HVDC Transmission

7,485 353 26MB

English Pages [393] Year 2011

Report DMCA / Copyright


Polecaj historie

HVDC Transmission

Table of contents :
Chapter One HVDC Transmission: Developments
1.1 Introduction
1.2 Historical Development
1.3 Equipment required for HVDC Systems
1.4 Comparison of AC and DC Transmission
1.5 Limitations of HVDC Transmission Lines
1.6 Reliability of HVDC Systems
1.7 Standard Rated Voltages of HVDC and EHVAC Systems
1.8 Choice of EHVAC and UHVAC Lines and Substation
1.9 Comparison of HVDC Link with EHVAC Link
1.10 HVDC-VSC Transmission Systems
Worked Examples
Multiple Choice Questions
Chapter Two HVDC Converters
2.1 Introduction
2.2 Thyristors and their Characteristics
2.3 Silicon Controlled Rectifi er (SCR)
2.4 Insulated Gate Bipolar Transistors (IGBTs)
2.5 HVDC Converter Valves and Valve Assembly
2.6 HVDC-Voltage Source Converters: Principle and Operation
2.7 3-phase 6-pulse Converters using SCRs or Thyristors
2.8 12-pulse Bridge Converters
Worked Examples
Multiple Choice Questions
Chapter Three 6-pulse Converter Operation and Analysis
3.1 Introduction
3.2 Conduction Sequence in 6-pulse Converter Confi guration 3
3.3 The Ideal Commutation Process without Gate Control
3.4 DC Output Voltage
3.5 Gate Control (Phase Control) of Valves
3.6 Analysis of Voltage Waveforms with Overlap Angle (m)
3.7 Voltage Drop in Per Unit Quantities
3.8 Complete Characteristics of Converter as Rectifi er/Inverter
3.9 Analysis of 12-pulse Converter
3.10 Power Flow in HVDC Links
3.11 Operation and Analysis of VSC Converters
Worked Examples
Multiple Choice Questions
Chapter Four Control of HVDC Converter and Systems
4.1 Introduction
4.2 Mechanism of AC Power Transmission
4.3 Principles of Control
4.4 Necessity of Control in case of a DC Link
4.5 Rectifi er Control
4.6 Compounding of Rectifi ers
4.7 Power Reversal in a DC Link
4.8 Voltage Dependent Current Order Limit (VDCOL)— Characteristics of the Converter
4.9 System Control Hierarchy and Basic Philosophy
4.10 Inverter Extinction Angle Control (EAG)
4.11 Pulse Phase Control
4.12 Starting and Stopping of a DC Link
4.13 Constant Power Control
4.14 Control Systems for HVDC Converters
4.15 Inverter Operation Problems
4.16 Control of VSC Converters
Worked Examples
Multiple Choice Questions
Chapter Five Harmonics in HVDC Systems
5.1 Introduction
5.2 Importance of Harmonic Study
5.3 Generation of Harmonics by Converters
5.4 Characteristic Harmonics on the DC Side
5.5 Characteristic Current Harmonics
5.6 Characteristic Variation of Harmonic Currents with Variation of a and m
5.7 Effect of Control Modes on Harmonics
5.8 Noncharacteristic Harmonics
5.9 Harmonics in VSC Converters
Worked Examples
Multiple Choice Questions
Chapter Six Harmonic Suppression in HVDC System—Filters
6.1 Introduction
6.2 Harmonic Model and Equivalent Circuit
6.3 Use of Filters
6.4 Filter Confi guration
6.5 Design of a Band-Pass Filter
6.6 Minimum Cost of Tuned AC Filters
6.7 Design of High-Pass Filters
6.8 Protection of Filters
6.9 Reactive Power Considerations
6.10 DC Filters
6.11 Power Line Communication and RI Noise
6.12 Active Filters and their Applications
6.13 Filters with Voltage Source Converter (VSC) HVDC Schemes
6.14 Other Methods of Harmonic Elimination
Worked Example
Multiple Choice Questions
Chapter Seven Grounding and Ground Electrodes for HVDC Systems
7.1 Introduction
7.2 Advantages and Problems with Ground Return
7.3 High Voltage Direct Current Systems—Grounding
7.4 The Current Field in the Earth near an Electrode
7.5 Resistance of Electrodes—Electric Current Field
7.6 Distribution of Current Field between the Electrodes
7.7 Natural Current Field due to the Earth’s Magnetic Field
7.8 Effect of Ground Return on Buried Objects
7.9 Requirements of Electrodes
7.10 Basic Parameters of Design of Ground Electrodes
7.11 Design of Land Electrodes
Worked Examples
Multiple Choice Questions
Chapter Eight Faults and Protection Schemes in HVDC Systems
8.1 Introduction
8.2 Nature and Types of Faults
8.3 Faults on AC side of Converter Stations
8.4 Converter Faults
8.5 Faults on DC side of the System
8.6 Protection against Overcurrents/Overvoltages
8.7 Protection of Filter Units
Multiple Choice Questions
Chapter Nine Overvoltages and Insulation Co-ordination for HVDC Systems
9.1 Introduction
9.2 Insulators for HVDC Overhead Lines
9.3 Lightning Overvoltages
9.4 Fast Transient Overvoltages produced by Converters
9.5 Overvoltages due to Faults or Disturbances from AC side
9.6 Protection against Overvoltages
9.7 Insulation Design of DC Lines and Air Clearances
9.8 Insulation Co-ordination for Converter Stations and DC Systems
Worked Examples
Multiple Choice Questions
Chapter Ten Multiterminal HVDC Systems
10.1 Introduction
10.2 Types of Multiterminal (MTDC) Systems
10.3 Parallel Operation Aspects of MTDC
10.4 Paralleling (Disconnecting) of Units or Converter
10.5 Control of Power in MTDC
10.6 VSC—Multilevel DC Systems
Multiple Choice Questions
Chapter Eleven Parallel AC and DC Systems
11.1 Introduction
11.2 Power Transfer Capabilities
11.3 Reliability Conditions
11.4 Power Loss Considerations and Other Technical Aspects
11.5 Environmental Characteristics Considerations for DC Transmission
11.6 Power Upgrading and Conversion of AC Lines (Systems) into DC Lines
11.7 DC and AC System Interaction
11.8 Parallel AC/DC Systems
11.9 FACTS and FACT Converters/HVDC
11.10 Modelling of HVDC Systems
Multiple Choice Questions
Appendix Some HVDC Projects implemented in India
Author Index
Subject Index

Citation preview

About the Authors S Kamakshaiah S Kamakshaiah is former professor of electrical engineering and head, Department of Electrical Engineering, College of Engineering, Jawaharlal Nehru Technological University, Hyderabad (A.P.). He completed BE with honors from Government College of Engineering, Ananathapur in 1962, and obtained ME and PhD from Indian Institute of Science, Bangalore, in High Voltage Engineering in 1965 and 1977, respectively. Dr Kamakshaiah has done extensive research in the area of triggered vacuum gaps and has a teaching and research experience spanning more than 45 years. He has supervised more than 25 MTech and six PhD theses. To his credit are 25 research papers, published in national and international journals. Among his many accolades are a Best Theses award for his PhD work and recognition as Best Teacher by the Government of Andhra Pradesh in 1997. Dr Kamakshaiah has also authored several books in the field of electrical engineering.

V Kamaraju V Kamaraju is former professor of electrical engineering and principal, College of Engineering, Jawaharlal Nehru Technological University, Kakinada (A.P.). He completed BE with honors in 1963 from the same college, and ME and PhD in High Voltage Engineering from Indian Institute of Science, Bangalore in 1965 and 1978, respectively. Dr Kamaraju has more than 45 years of teaching and research experience. He has supervised 25 MTech and two PhD theses and to his credit are more than 20 papers published in national and international journals. He has also been a visiting professor at Middle East Technical University, Turkey. Dr Kamaraju has erected and commissioned a medium-sized high voltage laboratory at Jawaharlal Nehru Technological University, College of Engineering, Kakinada. He has been honored as Best Teacher by the Government of Andhra Pradesh in 2001. He has also authored books on electrical engineering in the past, including High Voltage Engineering with the late Prof. M S Naidu and Electrical Power Distribution Systems; both published by Tata McGraw-Hill.

S Kamakshaiah Formerly Professor and Head of Department Department of Electrical Engineering College of Engineering Jawaharlal Nehru Technological University Hyderabad, Andhra Pradesh

V Kamaraju Formerly Professor of Electrical Engineering and Principal College of Engineering Jawaharlal Nehru Technological University Kakinada, Andhra Pradesh

Tata McGraw Hill Education Private Limited NEW DELHI McGraw-Hill Offices New Delhi New York St Louis San Francisco Auckland Bogotá Caracas Kuala Lumpur Lisbon London Madrid Mexico City Milan Montreal San Juan Santiago Singapore Sydney Tokyo Toronto

Tata McGraw-Hill Published by the Tata McGraw Hill Education Private Limited, 7 West Patel Nagar, New Delhi 110 008. HVDC Transmission Copyright © 2011, by Tata McGraw Hill Education Private Limited. No part of this publication may be reproduced or distributed in any form or by any means, electronic, mechanical, photocopying, recording, or otherwise or stored in a database or retrieval system without the prior written permission of the publishers. The program listings (if any) may be entered, stored and executed in a computer system, but they may not be reproduced for publication. This edition can be exported from India only by the publishers, Tata McGraw Hill Education Private Limited ISBN-13: 978-0-07-10-7253-3 ISBN-10: 0-07-10-7253-5 Vice President and Managing Director—McGraw-Hill Education, Asia-Pacific Region: Ajay Shukla Head—Higher Education Publishing and Marketing: Vibha Mahajan Manager: Sponsoring—SEM & Tech. Ed.: Shalini Jha Assoc. Sponsoring Editor: Suman Sen Editorial Researcher: Koyel Ghosh Sr Copy Editor: Nimisha Kapoor Jr Production Manager: Anjali Razdan Dy Marketing Manager: SEM & Tech. Ed.: Biju Ganesan Sr Product Specialist: SEM & Tech. Ed.: John Mathews General Manager—Production: Rajender P Ghansela Asst General Manager—Production: B L Dogra Information contained in this work has been obtained by Tata McGraw-Hill, from sources believed to be reliable. However, neither Tata McGraw-Hill nor its authors guarantee the accuracy or completeness of any information published herein, and neither Tata McGraw-Hill nor its authors shall be responsible for any errors, omissions, or damages arising out of use of this information. This work is published with the understanding that Tata McGraw-Hill and its authors are supplying information but are not attempting to render engineering or other professional services. If such services are required, the assistance of an appropriate professional should be sought. Typeset at The Composers, 260, C.A. Apt., Paschim Vihar, New Delhi 110 063 and printed at AP Offset Pvt. Ltd., 25/487, Zulfe Bengal, Dilshad Garden, New Delhi-110095 Cover Printer: AP Offset RALQCRXCDRRZC

Dedicated to my Almighty S Kamakshaiah Dedicated to my Family V S Rao (son), V Radhika (daughter), V Rajiv (grandson) and VVSN Jagadeeswari (daughter-in-law) whose encouragement, patience and help made this book possible. V Kamaraju

Contents Foreword Preface List of Symbols Abbreviations Inside

xi xiii xvii xix xx

Chapter One 1.1 1.2 1.3 1.4 1.5 1.6 1.7 1.8 1.9 1.10

HVDC Transmission: Developments Introduction 1 Historical Development 1 Equipment required for HVDC Systems 13 Comparison of AC and DC Transmission 17 Limitations of HVDC Transmission Lines 28 Reliability of HVDC Systems 28 Standard Rated Voltages of HVDC and EHVAC Systems 29 Choice of EHVAC and UHVAC Lines and Substation 30 Comparison of HVDC Link with EHVAC Link 31 HVDC-VSC Transmission Systems 31 References 35 Worked Examples 35 Questions 37 Problems 38 Multiple Choice Questions 38


Chapter Two 2.1 2.2 2.3 2.4 2.5 2.6 2.7 2.8

HVDC Converters Introduction 40 Thyristors and their Characteristics 40 Silicon Controlled Rectifier (SCR) 42 Insulated Gate Bipolar Transistors (IGBTs) 53 HVDC Converter Valves and Valve Assembly 57 HVDC-Voltage Source Converters: Principle and Operation 58 3-phase 6-pulse Converters using SCRs or Thyristors 62 12-pulse Bridge Converters 63 References 65 Worked Examples 65 Questions 66 Multiple Choice Questions 66


Chapter Three 3.1 3.2 3.3 3.4 3.5 3.6

6-pulse Converter Operation and Analysis Introduction 68 Conduction Sequence in 6-pulse Converter Configuration 3 68 The Ideal Commutation Process without Gate Control 70 DC Output Voltage 71 Gate Control (Phase Control) of Valves 75 Analysis of Voltage Waveforms with Overlap Angle (m) 81




3.7 3.8 3.9 3.10 3.11

Chapter Four 4.1 4.2 4.3 4.4 4.5 4.6 4.7 4.8 4.9 4.10 4.11 4.12 4.13 4.14 4.15 4.16

Chapter Five 5.1 5.2 5.3 5.4 5.5 5.6 5.7 5.8 5.9

Voltage Drop in Per Unit Quantities 92 Complete Characteristics of Converter as Rectifier/Inverter 94 Analysis of 12-pulse Converter 100 Power Flow in HVDC Links 103 Operation and Analysis of VSC Converters 106 References 112 Worked Examples 112 Questions 123 Problems 125 Multiple Choice Questions 126 Control of HVDC Converter and Systems Introduction 129 Mechanism of AC Power Transmission 129 Principles of Control 130 Necessity of Control in case of a DC Link 130 Rectifier Control 131 Compounding of Rectifiers 135 Power Reversal in a DC Link 139 Voltage Dependent Current Order Limit (VDCOL)— Characteristics of the Converter 140 System Control Hierarchy and Basic Philosophy 142 Inverter Extinction Angle Control (EAG) 152 Pulse Phase Control 153 Starting and Stopping of a DC Link 154 Constant Power Control 156 Control Systems for HVDC Converters 156 Inverter Operation Problems 159 Control of VSC Converters 162 References 166 Worked Examples 166 Questions 170 Problems 171 Multiple Choice Questions 172


Harmonics in HVDC Systems Introduction 174 Importance of Harmonic Study 174 Generation of Harmonics by Converters 174 Characteristic Harmonics on the DC Side 178 Characteristic Current Harmonics 181 Characteristic Variation of Harmonic Currents with Variation of a and m Effect of Control Modes on Harmonics 188 Noncharacteristic Harmonics 189 Harmonics in VSC Converters 190 References 192 Worked Examples 192 Questions 195





Problems 195 Multiple Choice Questions 195 Chapter Six 6.1 6.2 6.3 6.4 6.5 6.6 6.7 6.8 6.9 6.10 6.11 6.12 6.13 6.14

Harmonic Suppression in HVDC System—Filters Introduction 197 Harmonic Model and Equivalent Circuit 197 Use of Filters 200 Filter Configuration 202 Design of a Band-Pass Filter 204 Minimum Cost of Tuned AC Filters 208 Design of High-Pass Filters 209 Protection of Filters 209 Reactive Power Considerations 210 DC Filters 212 Power Line Communication and RI Noise 213 Active Filters and their Applications 213 Filters with Voltage Source Converter (VSC) HVDC Schemes 215 Other Methods of Harmonic Elimination 217 References 218 Worked Example 219 Questions 220 Multiple Choice Questions 221


Chapter Seven 7.1 7.2 7.3 7.4 7.5 7.6 7.7 7.8 7.9 7.10 7.11

Grounding and Ground Electrodes for HVDC Systems Introduction 223 Advantages and Problems with Ground Return 223 High Voltage Direct Current Systems—Grounding 225 The Current Field in the Earth near an Electrode 225 Resistance of Electrodes—Electric Current Field 227 Distribution of Current Field between the Electrodes 237 Natural Current Field due to the Earth’s Magnetic Field 238 Effect of Ground Return on Buried Objects 238 Requirements of Electrodes 239 Basic Parameters of Design of Ground Electrodes 240 Design of Land Electrodes 248 References 255 Worked Examples 255 Questions 258 Problems 259 Multiple Choice Questions 259


Chapter Eight 8.1 8.2 8.3 8.4 8.5 8.6

Faults and Protection Schemes in HVDC Systems Introduction 262 Nature and Types of Faults 262 Faults on AC side of Converter Stations 263 Converter Faults 265 Faults on DC side of the System 273 Protection against Overcurrents/Overvoltages 279





Chapter Nine 9.1 9.2 9.3 9.4 9.5 9.6 9.7 9.8

Protection of Filter Units 280 References 280 Questions 281 Multiple Choice Questions 281 Overvoltages and Insulation Co-ordination for HVDC Systems Introduction 283 Insulators for HVDC Overhead Lines 284 Lightning Overvoltages 287 Fast Transient Overvoltages produced by Converters 289 Overvoltages due to Faults or Disturbances from AC side 290 Protection against Overvoltages 291 Insulation Design of DC Lines and Air Clearances 296 Insulation Co-ordination for Converter Stations and DC Systems 297 References 299 Worked Examples 299 Questions 303 Multiple Choice Questions 303


Multiterminal HVDC Systems Introduction 305 Types of Multiterminal (MTDC) Systems 306 Parallel Operation Aspects of MTDC 307 Paralleling (Disconnecting) of Units or Converter 309 Control of Power in MTDC 309 VSC—Multilevel DC Systems 311 References 314 Questions 314 Multiple Choice Questions 314


Chapter Eleven 11.1 11.2 11.3 11.4 11.5 11.6 11.7 11.8 11.9 11.10

Parallel AC and DC Systems Introduction 316 Power Transfer Capabilities 316 Reliability Conditions 317 Power Loss Considerations and Other Technical Aspects 317 Environmental Characteristics Considerations for DC Transmission 319 Power Upgrading and Conversion of AC Lines (Systems) into DC Lines 324 DC and AC System Interaction 327 Parallel AC/DC Systems 333 FACTS and FACT Converters/HVDC 338 Modelling of HVDC Systems 349 References 354 Questions 355 Multiple Choice Questions 356


Appendix Author Index Subject Index

Some HVDC Projects implemented in India

358 365 367

Chapter Ten 10.1 10.2 10.3 10.4 10.5 10.6

Foreword The power sector in India is growing at a very rapid rate. From the present installed capacity of about 160,000 MW meeting a peak demand of about 100,000 MW, it is anticipated that by 2020 the installed generation capacity will be more than 450,000 MW to satisfy the anticipated peak demand of about 350,000 MW. This is to ensure that our present per capita electricity consumption of 500 units will reach 1000 units by 2020. Also the objective of the National Electricity Policy to provide ‘power for all’ will be reasonably fulfilled. The reforms, restructuring of the power sector, and private participation, which are the outcomes of the Electricity Act 2003, are likely to lead to improved quality and reliability of power supply and satisfy the ever-increasing demand for electrical energy consumption. To achieve these objectives all the available energy resources have to be developed and efficiently utilised, including, the adoption of renewable sources like solar, wind, tidal, geothermal and biomass. Many times the conventional energy sources are far away from the load centres demanding large power transfer over long distances. The Power Grid Corporation of India which handles the National Grid has already proposed many 765 KV AC Lines and 800 KV DC lines for bulk power transmission. These are in addition to the existing 400 KV AC lines, 500 KV DC lines and back-to-back DC ties, which form the major inter-regional ties for the National Power Grid. It is necessary to plan the growth of the transmission system properly, since in the years to come, the power evacuation from ultra-mega projects and far away hydro plants will pose a problem due to difficulties in procuring safe right of way. Here comes the need for HVDC lines, which require less space and are more suitable for long distance bulk power transmission compared to EHVAC systems. Because of the large geographical distances involved in India, there will be occasions when power regions in the country may have to operate in isolation with no AC inter-regional ties. Under these conditions, the DC lines are able to function as asynchronous links for inter-regional power transfer. Thus for operating modern power systems, a good knowledge of the characteristics, operation and control of HVDC systems is imperative for electrical utility engineers. I am happy to know that this topic is included as an elective course for final year electrical engineering students in almost all engineering colleges and also as a course in post-graduate studies in many universities. Therefore, a comprehensive text book on HVDC transmission giving all details of characteristics, operation, control, modelling, and simulation is very much needed. This need is fully met by the text book on HVDC authored by very experienced teachers Prof. S Kamakshaiah and Prof. V Kamaraju. All the necessary details required by students are covered in 11 chapters with several worked out examples which will help them understand the theory sections better. This book also provides a historical account of development of HVDC technology and details of HVDC systems presently operating in India. New developments in HVDC systems utilising voltage source converters with IGBT devices have also been included to enhance the general knowledge of students about future HVDC systems. I am very much indebted to the authors for giving me an opportunity to go through this excellent book on HVDC transmission. I congratulate the authors for bringing out a very useful text book on this topic which will be of great help to students of electrical engineering. M Ramamoorty Former Director General Central Power Research Institute Bangalore

Preface This book introduces the subject HVDC Transmission at a basic undergraduate level and covers all the topics associated with DC transmission as well. The book can be used for one semester, omitting a few chapters or as a complete reading material for two semesters of a course. It will be especially useful for final year undergraduate students of Electrical or Electrical and Electronics Engineering. The text is also meant for post-graduate students of Electrical or Electrical and Electronics Engineering, who have opted for a course on HVDC Transmission, also known as HVDC Engineering. High Voltage Direct Current Transmission was first developed in the 1950s, when 3-phase AC power transmission over long distances and through cables (undersea to islands) became difficult. DC transmission, at that time, seemed to be a viable alternative solution. The first commercial projects launched in this field were the Moscow–Kashira project of 30 MW over a distance of 100 km in 1951, and the Sweden–Gotland island project of 20 MW, spread over a distance of 98 km. Subsequent developments in high power electronic static devices made power conversion uncomplicated and cost effective. Of late several HVDC schemes and projects have come up all over the world where there is a need to transmit power over long distances (>500 km), interconnect two different frequency AC systems (asynchronous tie), provide cable transmission over long distances or connect nonconventional power sources like wind power and solar power to the main grid supply. In India, a few back-to-back interconnected systems and long distance transmission systems have been introduced in the last two decades. This has helped immensely in exposing power engineers to the basics of DC transmission technology. However, very few books are available on this subject. The first book written by Hingorani and Adamson that appeared in the late 1950s provided a brief outline of the subject. Kimbark’s book on DC transmission (Vol. 1, 1970) is an exhaustive read but it focuses solely on mercury arc valve technology. In the last two decades few more books, but of an advanced level have been published. Recognising the growing interest of students in this field, and a need for a comprehensive yet basic level text, we have authored this book to aid in-depth academic study. The book discusses state of the art in HVDC transmission systems and provides coverage of modern trends in HVDC transmission in ample detail. VSC converters which have been recently developed to interconnect nonconventional energy sources like wind power to the grid are included and presented in a lucid manner. Topics on interaction of AC and DC systems, multiterminal HVDC systems and FACTS controllers are included to give a complete overview of trends in this field. The content has been written after careful perusal of curriculum in various engineering colleges and hence can be used by students of all universities. This book can also be used as a reference reading or a refresher course guide by field engineers and professionals connected with HVDC systems. The content is written in simple and pedagogical manner and aims to provide a holistic understanding to a reader interested in studying inception, working principles, advantages and disadvantages of HVDC transmission and transmission systems. A few highlights of the book are listed below. Includes modern trends and list of HVDC projects in India and abroad. An informative coverage of some HVDC projects implemented in India, including the longest bipolar HVDC transmission line from Thalcher (Orissa) to Kolar (Bangalore) has been included towards the



end of the book. Technical details of three long distance transmission schemes and one back-to-back scheme (inter-state/inter-regional grid interconnectors) under the control of Power Grid Corporation of India Ltd. (PGCIL) has been presented with photographs from the site. A dedicated chapter on Grounding and Ground Electrodes has been provided to highlight the ability of HVDC transmission systems to transmit power by using the ground as return conductor. The importance and methodology of grounding has been presented in ample detail. The book begins with an elucidation of the need for HVDC along with information on its historical background and past developments. Further, it is organised in the following manner. The first chapter introduces the subject with a comparison of AC and DC systems, highlighting the merits of DC as a better alternative under specific conditions. HVDC projects executed around the world in the last fifty years have also been listed with relevant details in this chapter. Solid state devices (thyristors and IGBTs), their characteristics, use, operation, methods of triggering, along with high voltage valve technology is explained in Chapter 2. Chapter 3 deals with HVDC 6-pulse and 12-pulse converters. Their operation, power flow, losses and its control mechanisms have been analysed in this chapter. Chapter 4 is devoted to the operation and control of thyristor valves. Harmonics, their suppression through filters, filter arrangements and other suppression methods are discussed in Chapters 5 and 6. Necessity of grounding or earthing, layout and location of ground electrodes, and computation of ground resistance is discussed in Chapter 7. Chapter 8 is devoted to faults and protection schemes in HVDC systems. In Chapter 9, transient and overvoltages that occur in HVDC converters and lines are discussed along with possible protection measures against these. An introduction to insulation co-ordination is also given. Multiterminal schemes which are fast becoming important in HVDC transmission are discussed in Chapter 10. Topics like (i) Parallel AC–DC systems and their interaction, (ii) High electric and magnetic fields and their effect on the environment, (iii) Land usage and ecological health effects, etc., have been discussed in Chapter 11. The book concludes with an introduction to FACTS and FACTS controllers. The book has strong pedagogical features inclusive of worked examples, questions, problems and multiple choice questions. A student will find a good mix of theoretical questions and numerical problems. A list of important references to aid further study has also been provided at the end of every chapter. Numerous tables, illustrations and photographs have been included in the text to support visualisation of content. The book is also supplemented with an interesting online learning center for both instructors and students, which can be accessed at http://www.mhhe.com/Kamakshaiah/hvdct1

Acknowledgements We gratefully acknowledge the excellent foreword, critical review and suggestions given by Dr M Ramamoorty, former director general, CPRI, Bangalore. We would also like to thank Dr Adapa Rambabu of EPRI, USA, and Dr Vasudeva of CPRI, Bangalore, for contributing valuable and informative technical material during the preparation of this book. We also wish to express sincere thanks to all the reviewers listed below, who have spared precious time to offer constructive criticism and suggestions on the manuscript. Saikat Chakrabarti

Indian Institute of Technology Kanpur, Uttar Pradesh

P K Kalra

Indian Institute of Technology Kanpur, Uttar Pradesh


Bimal Kumar

Amritsar College of Engineering and Technology, Amritsar, Punjab

N K Kishore

Indian Institute of Technology Kharagpur, West Bengal

A M Kulkarni

Indian Institute of Technology Bombay, Maharashtra

M H Dhend

All India Shri Shivaji Memorial Society’s COE, Pune, Maharashtra

S Krishna

Indian Institute of Technology Madras, Tamil Nadu

A S Kandasamy

Paavai Engineering College, Namakkal Dist., Tamil Nadu

R Suresh Kumar

Anna University, Coimbatore, Tamil Nadu

K Purushottam Prasad

Sri Padmavati Mahila Visvavidyalayam, Tirupati, Andhra Pradesh

T Vamsee Kiran

Jawaharlal Nehru Technological University, Kakinada, Andhra Pradesh

Paul Clee

Padmasri Dr BV Raju Institute of Technology, Andhra Pradesh

G R Gurumurthy

BNM Institute of Technology, Bangalore, Karnataka


Further, any critical review or suggestions from the readers, academicians or engineers is welcome and will be incorporated in future editions of this book. S Kamakshaiah V Kamaraju

Publisher’s Note: Have something to tell us? Write to us with your comments at [email protected]. Please mention the title and author name as the subject.

List of Symbols a b g d e j m m q r w wn wr D a, b, c d DC e f g h i j k l m n o p p.u. q r s t u,v v x y z

Firing angle of rectifier Firing angle of inverter (p-a), Angle of advance Control angle of inverter (Extinction angle) Phase angle between V and I in power circle diagram Relative permittivity Magnetic flux, Power factor angle Overlap angle / Commutation angle in convertors Micro Phase angle between voltage and current phasors, Power factor angle Resistivity of material or conductor Angular frequency Tuned angular frequency for nth harmonic Resonant angular frequency Delta (mesh) connection in 3-phase systems Phase sequence; as a suffix refer to instantaneous or phase quantity Diameter, Distance between two members Direct current Electron charge Frequency Conductance Harmonic order, Height Instantaneous current Current density Harmonic number Length, Length of a conductor Maximum value Harmonic number At no-load (as suffix) Pulse number, Primary side (line side) of converter transformer Per unit Charge Radius Secondary (valve side) of converter transformer Time, Temperature DC Voltage, Converter voltage on DC side Instantaneous voltage Reactance, Line reactance per unit length Admittance, Admittance per unit length Impedance, Impedance per unit length


List of Symbols

A A, B, C, AC B C D DC E H HVDC I Id Idn IG Ip IR, IY, IB, IS J L Ld M P Pac Pd Q Qc QL R R, Y, B, S T U Vd Vdo Vido VdN VPL VP VR, VY, VB VSL X, XC, XL Y Z

Ampere, Area AC phase sequence Alternating current Suseptance, Breadth Capacitance Diameter, Diameter of a ring Direct Current Elec. field intensity Height, Spacing between conductors High Voltage Direct Current Current (DC) Direct current average value Rated DC current Gate current RMS current of line side of converter transformer AC 3-phase currents RMS current on secondary or valve side of converter transformer Current density Inductance Smoothing reactor (Inductance) Mutual inductance Pulse number, Power through converter Power in AC system DC power transmitted Reactive VA Capacitive VA Inductive Resistance Phase sequence 3-phase AC system Apparent power (VA) Time interval, Time, Temperature Convertor DC Voltage Voltage (DC) No-load DC voltage Ideal no-load direct voltage Rated direct voltage Rated RMS AC voltage line side of transformer Phase voltage, Peak voltage of AC AC 3-phase voltages Rated RMS voltage (line) on valve or secondary side of transformer Line reactance, Capacitive reactance , Inductive reactance (respectively) Suseptance Impedance


Circuit Breaker Constant Current Control Constant Extinction Angle (g ) control Constant Ignition Angle Control Current Source Converter Control Extinction Angle Control Equidistant Pulse Control Flexible AC Transmission System Gate Turn-off Thyristor Insulated Gate Bipolar Thyristor Integrated Gate Commuted Thyristor Individual Phase Control Metalic Return Transfer Breaker Multiterminal DC System Pulse Frequency Control Silicon Controlled Rectifier Silicon Carbide Base Thyristor Static Series Synchronous Compensator Static VAR Compensator Telephonic Harmonic Factor Telephone Influence Factor Thyristor Switch Capacitor/Reactor Voltage Dependant Current Order Limit Voltage Source Convertor

INSIDE... is a comprehensive literature on “HVDC Transmission” - the following section provides a sneak-peek into the highlights of the content, its layout and its presentation.

Location and history of HVDC projects around the world

Vishakhapatnam 500 MW

Important HVDC projects implemented in India including the longest bipolar HVDC transmission line from Thalcher (Orissa) to Kolar (Bangalore)

Grounding and Ground Electrodes for HVDC Systems 7.1

Dedicated chapter on Grounding and Ground Electrodes


It was indicated in the first chapter that HVDC transmission is a viable alternative to long distance AC transmission because of its relative advantages. One advantage is its ability to transmit power by using ground as return conductor. Most DC transmission systems use ground or sea water as return path for current either continuously or for short times in emergency and such return paths are known as ground return, even if the sea constitutes all or part of the path. A bipolar transmission system using ground return mode is more reliable in transmitting power with less losses, even when one of the poles is faulty, than an AC transmission line. Here a comprehensive review of the general subject of ground electrodes, which is an essential part in ground return operation of HVDC transmission systems is presented. Type of ground electrodes explained in this chapter are unique HVDC transmission systems. The following sections present a brief technical background of theory and practice of DC power transmission through the earth as return conductor and also the techniques which can be applied to the selection of sites for ground electrodes. A methodology of design of various types of ground electrodes is also included.



There are certain advantages of use of ground return. 1. The ground path has a very low resistance and consequently low power loss in comparison with a metallic return conductor of economical size and equal length, provided ground electrodes are properly designed. The resistance of the ground path of DC currents is low because the DC current under steady state spreads over a very large cross-sectional area in both depth and width, and does not follow closely the route of the metallic conductor unlike transient AC current. The resistance of this path is independent of the length of the line as the resistance of the ground is negligible and mostly comprises ground electrodes at each end. 2. A bipolar line is more economical than a monopolar line with ground return. A bipolar line has twice as many conductors and can carry twice as much power at slightly higher efficiency than the monopolar line. Its cost is surely less than twice that of a monopolar line with overhead conductors.

QUESTIONS 1. What are the causes for overvoltages in DC systems? Discuss their characteristics and effects. 2. How are insulators for DC different from that for DC? What are their requirements? 3. Discuss the equivalent circuit of DC insulator string and explain the significance of different components. How is the voltage distribution across the sting? 4. Discuss the nature and characteristics of short duration and lightning impulses in DC systems. 5. What are the different kinds of switching surges that occur in DC systems? Give their characteristics and effects. 6. Give the constructional features of metal oxide arresters. What are their characteristics and features? 7. What is insulation co-ordination in DC system? Explain the choice of different insulation levels. 8. Explain how the insulation co-ordination is affected different types of overvoltages. Work out the insulation levels for a converter station with a suitable example. 9. What are the methods adopted for limiting overvoltages in DC systems?

MULTIPLE CHOICE QUESTIONS 1. Valve house and converter station is mostly subjected to the following overvoltages (a) Lightning (b) Short switching impulse (c) DC overvoltages (d) Power frequency overvoltages 2. Equivalent circuit of a string insulator for DC is (a) Capacitance network (b) R–C network (c) Resistance network with variable resistance (d) None of the above 3. Variable resistance part of equivalent circuit for DC insulator string is (a) ionic current (b) surface resistance (c) volume resistance (d) both ionic current and surface resistance 4. Typical creepage length for DC voltages under pollution conditions is (a) 40 to 50 mm/kV (b) 10 to 15 mm/kV (c) above 70 mm/kV (d) 20 to 25 mm/kV 5. Long rod composite insulators are most suitable for DC applications under (a) wet conditions (b) low temperatures (c) pollution condition (d) all the above 6. In earlier HVDC schemes insulators used were (a) RTV and HTV insulator (b) Silicone composite insulators (c) Porcelain and high resistance glass insulators

Content presented with attractive pedagogy

HVDC Transmission: Developments 1.1


The demand for large amount of electric power, today, necessitates transmission at increasingly high voltages. Until 1960, electrical power was transported through AC 3-phase system only. Voltage transformation from one level to another level is quite easy with AC through a suitable transformer. Also, power generation by large size generators (of 500 MVA capacity) is feasible with AC only. However, transport of bulk power and over long distances (500 km and above) gives rise to considerable problems like variation of voltage profiles, decrease in power transfer and generation of reactive power. As such, viability of power transfer using an alternate means is thought of. At this juncture, DC power transmission is considered, and in the last fifty years, it has been developed for (i) (ii) (iii) (iv)

Power transfer over long distances from point to point Underwater (sea) transmission Interconnection of two AC systems with two different frequencies Better power system stability as a parallel link with existing AC system



Electrical science and its applications gained momentum with the discovery of direct current. Originally, electric power generation and transmission was through direct current. In 1882, the first electric central station in the world was built by Thomas A. Edison in New York and was supplying direct current at 110 V through underground tubular mains to an area of about 1.6 km radius. This station had Edison bipolar DC generators driven by steam engines. In case of high voltages, the size of commutator increases which restricts the peripheral speed of the machine. Hence, low speed DC machines were found to be costlier. Due to limitations of cost and size of DC machines on one hand and the advent of transformers, polyphase circuits and induction motors (between 1880–1890) on the other hand, alternating current (AC) power transmission system gained supremacy and began to play a dominant role in the phenomenal growth of power transmission systems. When the length of the line is more than 500 km, reactive power generated by the AC line is more than its power transmitting capacity as shown in Fig. 1.l.


HVDC Transmission

Fig. 1.1 Reactive power requirements of long AC and DC transmission lines

Among DC power transmission systems, the Thury system of HVDC transmission as designed by a French engineer was the first one to be put into operation in Europe, when AC system was in its infancy. It had a number of series-wound DC machines connected at the both ends of the transmission line and was operated at constant current. The first commercially successful DC system rated 100 kV, 20 kW was commissioned by the Gotland scheme in Sweden in 1954. Since then interest in HVDC power transmission has been increasing and many HVDC projects have been executed throughout the world (Table 1.1 to Table 1.5). Up to 1970, only mercury-valves were being used in HVDC projects in rectifier and inverter stations. Subsequently, thyristors and lately IGBTs have been developed and are being used extensively in bridge converters of HVDC systems. Locations of a few HVDC projects around the world are depicted in Fig. 1.2. The rapid advance in DC transmission technology has taken place because it has numerous advantages over EHVAC transmission in transporting bulk power through long-distance transmission lines. It reaps definite economic benefits when the transmission line length exceeds 500 km. Some advantages of HVDC transmission are listed below: (a) (b) (c) (d) (e) (f)

Interconnection of systems using long length of cables in particular while crossing sea water. Interconnection of systems operating at different frequencies (as asynchronous tie). Reduced transmission losses. Rigid control over the magnitude and direction of power flow with easy reversibility of power flow. Limiting the transfer of fault current. Damping out oscillations and improving the stability margins when embedded in weak AC systems of low short circuit ratio (SCR). The strength of AC systems connected to the terminals of DC links is measured in terms of short circuit ratio (SCR). [SCR is defined as the AC power transfer under short circuit at the converter bus or rated DC power. If SCR is less than 3, then AC system is said to be weak.] (g) HVDC transmission is most useful in areas requiring crossing of long waterways like crossing a sea to feed an island through submarine cables. The first major DC transmission line was established in 1960 in USSR for transmitting power of 750 MW at ±400 kV, over a distance of 500 km. In USA, a DC line of 1360 km length operating at ±400 kV for transmission of bulk power of l440 MW was established in 1970.

Several innovations in the development of DC conversion technology have enabled HVDC schemes look more attractive than AC systems when considering transfer of bulk power over long distances. The replacement of mercury valves with thyristors valves has reduced large requirements of land and civil engineering costs of convertor stations with attendant economic benefits.


Elbe Project

Moscow– Kashira

Gotland 1

HVDC CrossChannel

Konti–Skan 1

HVDC Volgograd– Donbass

HVDC InterIsland

HVDC Back-to-back Station, Sakuma









Haywards, New Zealand

Sakuma, Japan

Sakuma, Japan

Mikhailovskaya, Russia

Stenkullen, Sweden

Lydd, UK

Ygne, Sweden

Kashira, Russia

Berlin– Marienfelde, Germany

Converter Station 2

Benmore Dam, New Zealand

Volzhskaya, Russia

Vester Hassing, Denmark

Echingen, France

Vaestervik, Sweden

Moscow, Russia

Dessau, Germany

Converter Station 1

40 km

87 km

64 km

98 km

100 km

100 km

570 km

475 km

89 km

Length of Length Overhead Line of Cable

Realised HVDC systems that use (or used) mercury arc rectifiers

S. No.

Table 1.1

HVDC Projects from Around the World

±125 kV

+270 kV –350 kV

±400 kV

250 kV

±100 kV

200 kV

200 kV

±200 kV

Transmission Voltage

300 MW

1200 MW

750 MW

250 MW

160 MW

20 MW

30 MW

60 MW

Transmission Power









Inauguration Remarks


Replaced in 1993 by new converter using light-triggered thyristors

Upgraded in 1991. Pole 1 of this system still uses mercury arc rectifiers, one of the last such systems in the world to continue with this technology. Pole 2 is thyristor bridge.

Replaced in August 2006 by modern converters using thyristors

Shut down in 1984

Shut down in February 1986

Built of parts of HVDC Elbe-Project, shut down

Never placed in service, dismantled

HVDC Transmission: Developments




Table 1.1


HVDC Vancouver Island 1

Pacific DC Intertie

Nelson River Bipole 1

HVDC Kingsnorth

S. No.






Kingsnorth, UK

Gillam, Canada

Celilo, Oregon

Delta, British Columbia

Suvereto, Italia

Converter Station 1

London– Beddington, UK; London– Willesden, UK

Rosser, Manitoba

Sylmar, California

North Cowichan, British Columbia

Lucciana, Corse; Codrongianos, Sardinia

Converter Station 2

895 km

85 km

1,362 km

33 km

42 km

118 km

304 km

Length of Length Overhead of Cable Line

±266 kV

±450 kV

±500 kV

260 kV

200 kV

Transmission Voltage

640 MW

1620 MW

3100 MW

312 MW

200 MW

Transmission Power






Inauguration Remarks

Shut down

Used the largest mercury arc rectifiers ever built. Poles converted to thyristors in 1993, 2004

Transmission voltage until 1984 ±400 kV maximum transmission power until 1982 1440 MW, from 1982 to 1984 1600 MW, from 1984 to 1989 2000 MW; mercury arc rectifiers replaced in 2004 by photothyristors

Replaced in 1986 by thyristors, multiterminal scheme

4 HVDC Transmission


HVDC Back-to-back Station Eel, River

HVDC Vancouver Island 2

Square Butte


Cabora Bassa


HVDC Gotland 2

HVDC Itaipu 1

Nelson River Bipole 2

HVDC CrossChannel (new)











Les Mandarins, France

Sundance, Canada

Foz do Iguaçu, Paraná

Västervik, Sweden

Kolwezi, Zaire

Songo, Mozambique

Coal Creek, North Dakota

Center, North Dakota

Delta, British Columbia

New Brunswick, Canada

Converter Station 1

Sellindge, UK

Rosser, Canada

São Roque, São Paulo

Yigne, Sweden

Inga, Zaire

Apollo, South Africa

Dickinson, Minnesota

Arrowhead, Minnesota

North Cowichan, British Columbia

New Brunswick, Canada

Converter Station 2

72 km

92.9 km

33 km

Length of Cable

Some systems that used thyristors from first power-on

S. No.

Table 1.2

937 km

785 km 805 km

6.6 km

1700 km

1420 km

710 km

749 km

42 km

Length of Overhead Line

±270 kV

±500 kV

±600 kV

150 kV


±533 kV

±400 kV

±250 kV

280 kV

80 kV


2000 MW

1800 MW

3150 MW

130 MW

560 MW

1920 MW

1000 MW

500 MW

370 MW

320 MW

Transmission Power













2 bipolar systems

Two schemes each 3150 MW


HVDC Transmission: Developments




HVDC Sileru — Barsoor


HVDC Gezhouba — Shanghai

Quebec—New England Transmission

HVDC Rihand— Delhi


HVDC Inter-Island 2

Cross-Skagerrak 3













S. No.

Table 1.2

Stärnö, Sweden

Tjele, Denmark

Benmore Dam, New Zealand

Suvereto, Italia

Slupsk, Poland

Kristiansand, Norway

Haywards, New Zealand

Lucciana, France; Codrongianos, Italy

Dadri, India

Via Nicolet, Des canton Quebec

Ridson Quebec, Canada

Rihand, India

Nan Qiao, China

Rauma, Finland

Barsoor, India

Adelanto, California

Converter Station 2

Gezhouba, China

Dannebo, Sweden

Sileru, India

Intermountain, Utah

Converter Station 1

245 km

130 km

100 km

570 km

304 km

118 km

40 km

814 km

1100 km

1046 km

33 km

196 km

785 km

Length of Overhead Line

200 km

Length of Cable

450 kV

350 kV

350 kV

200 kV

±500 kV

450 kV

±500 kV

400 kV

±200 kV

±500 kV


600 MW

500 MW

640 MW

300 MW

1500 MW

2000 MW

1200 MW

500 MW

400 MW

1920 MW

Transmission Power













Multiterminal scheme

Multiterminal 3 terminals


6 HVDC Transmission


HVDC Italy—Greece

HVDC Three Gorges–Changzhou

HVDC Three Gorges— Guangdong




Xianjiba, Shanghai

Yannan, Guangdong










S. No.

Table 1.2

Guangdong, China

Xianjiba, China

Feda, Norway

Latina, Italy

Loy Yang, Australia

Jingzhou, China

Longquan, China

Galatina, Italy

Converter Station 1

Yunnan, China

Shanghai, China

Eemshaven, Netherlands

Fiume Santo, Sardinia

George Town, Australia

IIuizhou, China

Zhengping, China

Arachthos, Greece

Converter Station 2

580 km

435 km

298.3 km

200 km

Length of Cable

1400 km

2071 km

71.8 km

940 km

890 km

110 km

Length of Overhead Line

±800 kV

800 kV

±450 kV

±500 kV

400 kV

±500 kV

±500 kV

400 kV


5000 MW

6400 MW

700 MW

1000 MW

600 MW

3000 MW

3000 MW

500 MW

Transmission Power











HVDC Transmission: Developments



New Haven, Connecticut

Berri, Australia

Kollsnes, Norway

Espoo, Finland

Lista, Norway

Germany Diele

East Bay Okland, US


4 Cross Sound Cable

5 Murraylink

6 HVDC Troll

7 Estlink

8 HVDC Valhall

9 Nord EONI

10 Transbay San Francisco, US

11 Caprivi Link

*Source: Wikipedia: List of HVDC projects

Bungalora, Australia

Mullumbimby, Australia

3 Directlink

Namibia Zambari

San Francisco, US

Germany Borkum

Valhall, Offshore platform

Harku, Estonia

Offshore Platform Troll A

Red Cliffs, Australia

Shoreham, Long Island

Eagle Pass, Texas, USA

Tjæreborg, Denmark

Converter Station 2

2 HVDC Back-to-back Eagle Pass, Texas, Station, Eagle Pass, USA Texas

Tjæreborg, Denmark

Converter Station 1

Systems that used IGBTs from first power-on

1 HVDC Tjæreborg

S. No.

Table 1.3

970 km

88 km

203 km

292 km

105 km

70 km

177 km

40 km

59 km

4.3 km

Length of Length of Cable Overhead Line

500 kV

200 kV

150 kV

150 kV

±150 kV

±60 kV

±150 kV

±150 kV

±80 kV

±15.9 kV

±9 kV


300 MW

400 MW

400 MW

78 MW

350 MW

84 MW

220 MW

330 MW

180 MW

36 MW

7,2 MW

Transmission Power













Power supply for offshore gas compressor

Land cable

Buried underwater cable

Land cable

Interconnection to wind power generating stations


8 HVDC Transmission

HVDC Rihand— Delhi

Chandrapur–Padghe Chandrapur (Maharashtra)


East South-2









Barsoor (Chattisgarh)

Converter Station 2

*Source: Wikipedia: List of HVDC projects

Biswanath (Assam)

Ballia (U.P.)

Talcher (Orissa)

Gajuwaka (A.P.)

Rihand (U.P.)

Agra (U.P.)

Bhiwadi (Rajasthan)

Kolar (Karnataka)

Gajuwaka (A.P.)

Padghe (Maharashtra)

Dadri (U.P.)

Vindhyachal (U.P.) Vindhyachal (U.P.)

Vindhyachal Back-to-back


Sileru (A.P.)

Converter Station 1

HVDC Sileru— Barsoor


HVDC Schemes in India


S. No.

Table 1.4

1875 km

780 km

1450 km

900 km

814 km

196 km

Length Length of of Cable Overhead Line


±800 kV 6000 MW

±500 kV 2500 MW

±500 kV 2000 MW

176 kV 500 MW

±500 kV 1500 MW

±500 kV 1500 MW

±176 kV 500 MW

±200 kV 400 MW


To be completed in 2012

Under construction (2009)

2002 Interstate

2005 Back-to-back Eastern grid and Southern grid

1997 Interstate

1992 Interstate

1989 Interstate

1989 Experimental line


HVDC Transmission: Developments



HVDC Transmission

Table 1.5

HVDC back-to-back schemes

S. No.



HVDC Back-to-back, Shin Shinano






Shin–Shinano, Japan

±125 kV

600 MW 1977


Acaray, Paraguay

26.5 kV

50 MW 1981



Vyborg, Russia

±85 kV

1065 MW 1982



Durnrohar, Austria

145 kV

550 MW 1983



Chateauguay Saint Constant

140 kV

1000 MW 1984


Virginia Smith

US–Sidney Nebraska

150 kV

200 MW 1988



Etzenritch, Germany

160 kV

600 MW 1993


Minami Fukumitsu

Minami– Fukumitsu, Japan

125 kV

300 MW 1999



Sharyland, Texas, USA


Al Fadhili

Al Fadhili, Saudi Arabia

21 kV 150 MW 1800 MW 2008

Remarks Interconnection 50Hz/60Hz

Shut down in 1995 —

2007 —

The thyristor valves offer the following advantages. (a) They are free from arc backs which are frequent in mercury arc valves. (b) Have low power loss and offer wide flexibility of design which helps arrive at an economical design for a particular project. (c) Low maintenance requirements. The progressive increase in voltage and current ratings of thyristors and 12-pulse mode of operation has brought economy in filter requirements. Fairly good advances in this technology have taken place around the world. Advanced methods of cooling using Freon to keep the junction temperatures of SCRs at low values in order to enhance the power handling capabilities in thyristors have been developed. Gate turn-off thyristors and fiber optic triggering have also been developed in addition to improved control philosophies with microprocessor applications which have contributed to the development of reliable convertors and other power apparatus in HVDC systems. Nowadays IGBT Technology has induced further development of new HVDC projects. Several HVDC schemes projects that have come up in India have been listed in Table 1.4. An experimental DC line between upper Sileru in Andhra Pradesh and Barsoor in Chattisgarh with 400 MW at ±200 kV was commissioned in 1989. At present it is operating at –200 kV and 200 MW only.

Vishakhapatnam 500 MW

HVDC Transmission: Developments

Fig. 1.2

Location of some HVDC projects around the world*

*Rudervall Roberto et al., HVDC Transmission Systems Technology (Review Paper), ABB Power Systems, Sweden. www.abb.com.in



HVDC Transmission

1.2.1 Types of HVDC Systems There are mainly three types of HVDC links that are in use as shown in Fig. 1.3.

Fig. 1.3 Types of DC links

(a) Monopolar Link A monopolar system has only one conductor with ground as return conductor, and it is usually of a negative polarity. It is suitable in submarine systems where sea water can be used as a return conductor.

(b) Bipolar Link (Unbalanced Operation) A bipolar system has two conductors, one of positive and other of negative polarity. The mutual or ground point is maintained at the mid-potential. Each terminal of a bipolar system has two converters of equal voltage ratings connected in series. If both neutrals are grounded then two poles operate at equal current and there is no ground current. In the event of fault in one conductor, the other conductor with ground return can be used up to half the rated load or power with the rated current of the pole.

(c) Homopolar Link Homopolar system has two or more conductors with the same polarity, usually negative, and they always operate with ground return. In the event of fault in one conductor, the whole

HVDC Transmission: Developments


converter can be connected to a healthy pole and can carry more than half the power (2-pole) by overloading but at the expense of increased line loss. However, this is not possible in a bipolar system due to the use of graded insulation for negative and positive poles. When continuous ground currents are inevitable, homopolar system is preferable. The additional advantage is lower corona loss and radio interference due to negative polarity on the lines.



Sources and generation of power is usually in AC mode. An essential requirement of a DC system is conversion of AC to DC at one end and inversion back to AC at the other end. This naturally demands rectifiers and inverters of high power ratings. The advent of power thyristors have made this job easier. Nowadays all HVDC schemes prefer to employ 12-pulse conversion because of less ripple and reduction in harmonics. A typical layout of HVDC transmission system is shown in Fig. 1.4.

Fig. 1.4 A typical HVDC transmission scheme

Essential requirements of HVDC system are (a) 6/12–pulse converters (b) Converter transformer with suitable ratio and tap changing (c) Filters both on the AC side and on the DC side to take care of the harmonic generation at the converters and to reduce the harmonics (d) A smoothing reactor in the DC side to reduce the harmonic currents in the DC line and possible transient overcurrents


HVDC Transmission

(e) Shunt capacitors to complement the reactive power generated by the converters as they operate on lagging power factor and take lagging current (f) DC transmission line or DC cables for power transmission

(a) Converters In all HVDC schemes that evolved after 1970, only thyristor valves are being used in converters. New techniques using Freon for cooling the junction of thyistors, to enable the temperature of the junctions of the valves to go as low as possible have been developed. This has increased the power handling capacity of the devices. New developments like gate turn-off thyristor, (GTO, 8 kV, 4000 A), IGBTs (6.5 kV, 1000 A) and light triggered thyristors with reliable cesium-mercury flash lamp for high power light sources have made control schemes not only more reliable but also appear to have reduced 2000 electronic components per valve according to Jack L. Tink, Manager of HVDC Marketing at General Electric. Thyristors are now available in the market with blocking voltage ratings of 6 kV which is six times the ratings of the first thyristors used in converter stations in the early 1970s. This means only one–sixth of the valves need to be used now, saving considerable space and cost. Today, HVDC valves have entered a new phase with the development of IGBT valves. From a basic ‘chip’ with a PIV rating of 4 to 6 kV and around 1000 A, a module is made with a few thyristors or IGBTs connected in series parallel combination for 10 to 15 kV voltage rating and required current rating (1 kA to 3 kA) giving suitable redundancy. A valve is built with such modules in series up to 500 kV. With IGBTs, which are self commuted (unlike thyristors) the modules are arranged into stak-paks, with which the IGBT stack valves are built. In Fig. 1.5 HVDC converter arrangement using thyristor valves as well as IGBTs is shown. The developments in HVDC valves are pictorially shown in Fig. 1.6. Nowadays, IGBT valves are used mainly in underwater cable and cable schemes in the power range 100 to 500 MW with voltage rating up to 200 kV.

(b) Converter Transformers The transformers used in HVDC systems before rectification of AC are termed as converter transformers. They differ in their design as compared to one used in AC systems because of superimposed DC voltages. The insulation system of a converter transformer has to withstand AC voltages, short time overvoltages and also superimposed DC voltages with polarity reversals. An understanding of the breakdown of solid interfaces in liquids is needed in the design of transformers. The tolerance on the impedance of converter transformers is more stringent since any variation in impedance has more effect on the cost of the associated DC terminal equipment. The content of harmonics in a converter transformer is much higher than conventional AC transformer. These harmonics cause additional leakage flux resulting formation of local hot-spots in the windings. Suitable magnetic shunts, directed oil flow for effective cooling along with additional cooling arrangements would be necessary to avoid such hot spots. (c) Filters Harmonics are generated in HVDC transmission lines due to repetitive firing of thyristors. These are transmitted to the AC network in which a DC link is embedded. This may cause overheating of the equipment and interference with communication systems. In addition to this, noncharacteristic harmonics are also generated due to an unbalance in converter transformer reactance, AC supply voltage and errors in the firing angle of the phases. It is necessary to regulate the harmonics through filtering techniques.

(d) Reactive Compensation (Shunt Capacitors) Reactive volt-amperes are generated in the process of conversion, due to delay in the firing angle of the converter stations. As DC system does not generate or require reactive volt-amperes, this must be suitably compensated by connecting shunt capacitors

HVDC Transmission: Developments

Fig. 1.5

Fig. 1.6

HVDC converter arrangements

Development of HVDC valves



HVDC Transmission

at the both ends of the system. The compensation of static vars depends upon short circuit ratio (SCR) of AC systems. For weak AC systems (low SCR) which are common in India, proper choice of reactive power compensation must be seriously considered.

(e) DC Transmission Line or DC Cable It requires only two conductors as compared to three conductors in a 3-phase AC system. Consequently losses are also less. The size of the structure of the towers is also less in DC transmission. There is no skin effect in the conductors because there is no variation of current in time (zero frequency). For the same power handling capacity, the size of the conductors required in DC transmission is small. Typical HVDC cables used in NorNed cable project are shown in Fig. 1.7.

Fig. 1.7

HVDC cables

HVDC Transmission: Developments




The relative merits of the two modes of transmission of AC and DC should be compared based on the following facts to assess the suitability: (1) Economics of transmission (2) Technical performance (3) Reliability

1.4.1 Economics of Power Transmission DC transmission of bulk power over long distances has certain distinct advantages over conventional AC power transmission such as the following: (1) In DC transmission, inductance and capacitance of the line has no effect on the power transfer capability of the line and the line drop. Also, there is no leakage or charging current of the line under steady conditions. DC has more decided advantages when power is transmitted through cables as there is no charging current in the cable. (2) For long distance power transmission over 500 km, the saving in cost is substantial as shown in Fig. l.8(a). A DC line requires only 2 conductors whereas an AC line requires 3 conductors in 3-phase AC systems. The cost of the terminal equipment is more in DC lines than in AC line. Break-even distance is one at which the cost of the two systems is the same. It is understood from Fig. 1.8(a) that a DC line is economical for long distances which are greater than the break-even distance. The break-even distance also varies with the power transmitted over the line as shown in Fig. 1.8(b). Table l.6 below shows the comparative capability of HVDC systems for power transfer over various distances with that of an EHVAC system at different voltages. *Table 1.6

Power transfer capability of HVDC and HVAC lines

Distance in km 500 700 900 1100

Capability in MW for HVDC

Capability of EHVAC Transmission in MW

±400 kV

±800 kV

400 kV

750 kV

1000 kV

1200 kV

2250 1690 1460 1360

9000 7000 6000 5000

405 313 261 219

1660 1250 1080 900

3680 2770 2400 1987

5790 4340 3770 3125

*The above figures refer to fair weather conditions.

Table 1.7 Gives typical line loading figures for di erent voltages with alternating current and with direct current Alternating Current Highest System Voltage (kV) 360 420 550 800 1200

Direct Current

Typical Load (MW) 300–1000 400–1200 800–2000 2000–4000 4000–8000

Highest System Voltage (kV) Typical Load bipole (MW) ± 250 ± 300 ± 400 ± 600 ± 800

200–500* 400–1000 800–1600 2000–4000 4000–8000


HVDC Transmission

(3) The choice of DC transmission voltage for a given power has a direct impact on the total installation cost. The cost of losses is very important in the evaluation of energy losses cost and the time horizon for utilisation of the DC system. Hence, to estimate costs of an HVDC system, a life cycle cost analysis is done. Here a comparison between (i) EHVAC system and Thyristor valve DC system, and (ii) EHV AC system and VSC (IGBT) valves with cable is carried out. For the first one (i), the capital costs for HVDC converter are higher than that of EHVAC substations. On the other hand, the cost of transmission for lines, cables land cost, etc., are lower for a DC system. In Fig. 1.8 (c) and (d), the break-even distance arrived at is larger (>500 km). The break-even distance depends on several factors such as line or cable, cost of materials, labour costs, etc. Similar comparison is made for VSC based

Fig. 1.8(a)

Relative costs of AC and DC transmission lines vs distance

Fig. 1.8(b) Variation of break-even distance with power transmitted

HVDC Transmission: Developments


Fig. 1.8(c) Break-even distance for thyristor HVDC schemes

Fig. 1.8(d)

Break-even distance for total cost of AC and DC schemes

HVDC and AC systems for smaller power transport (50 to 200 MW) and for shorter distances few tens of km to about 200 km (Fig. 1.9). The subdivision of costs for HVDC schemes for 2000 MW is given in Fig. 1.10.

1.4.2 Technical Performance DC transmission has some positive features which are not present in AC transmission, but are mainly due to the fast controllability of power in DC lines through converter control. Following are some technical advantages: (1) Full control over power transmitted in either direction.


HVDC Transmission

Fig. 1.9

Fig. 1.10

Break-even distance for VSC (IGBT schemes)

Cost subdivision for a typical 2000 MW HVDC scheme

(2) The ability to improve the transient and dynamic stability of AC system when embedded with DC link. (3) Fast control to limit fault currents in DC lines. (4) A DC link can be used as an asynchronous tie which can tie down the small variations in system frequency of different AC systems. (5) Two large AC systems when interconnected by AC link may sustain instability. But DC link may dampen the system oscillations due to its inherent short over load capacity. (6) The choice of high voltage DC transmission system mainly depends on the economic suitability for a particular application. Primarily economy lies in the fact that DC transmission requires only two conductors per circuit (bipolar) rather than three conductors required for an AC system. Consequently, the towers carry less conductor weight in DC system and are smaller in size and hence are less costly.

Comparison of Single-Phase AC Line and Monopolar DC Line While comparing the performance of monopolar DC line with single-phase AC line, it is presumed that the size of the conductor is same in both the systems. The maximum system voltage to ground is also same. Let Ip be the rms AC current of single-phase system.

HVDC Transmission: Developments


Let Id be the direct current of the monopolar DC system. Id = Ip


Since the system maximum voltage is same in both cases, Vd =


2 Vp

where Vd is the DC voltage of the pole w.r.t. ground. where Vp is the r.m.s line to ground voltage of AC system. The power transmitted through DC line = Pd = Vd Id The power transmitted through AC line = PAC = Vp Ip cos f The ratio of DC power/AC power =

Pd Vd I d = PAC V p I p cos f

(l .3)

Assuming the power factor cos f = 0.945 Pd = 2 0.945 = 1.5 PAC


It means a monopolar DC line can transmit 1.5 times the power an AC line can transmit for the same conductor size and system maximum voltage.

1.4.3(a) Comparison of Bipolar DC Line with 3-phase AC Line for Power Transfer Capability (For same current and power level) It is presumed in the comparison that the insulation levels are the same, i.e., the maximum system voltage in both the cases is the same and the size of the conductor also the same with the above conditions. Id = I p Vd =

2 Vp

where Vd is the DC voltage of the pole w.r.t. ground The DC power transmitted by a bipolar line is Pd = 2 Vd Id AC power transmitted by a 3-phase system = PAC = 3Vp Ip cos f The ratio of =

p power transmitted by bipolar DC line = d power transmitted by 3-phase AC line pAC

2 Vd I d 3V p I p cos f


2 Ê Vd I d ˆ 2 Ê 2 V p I p ˆ ¥Á ˜ ˜= Á 3 Ë V p I p cos f ¯ 3 ÁË V p I p cos f ˜¯


22 with

HVDC Transmission

cos f = 0.945 pd pac


2 2 ¥ =1 3 0.945

It means that the power transmitted by a bipolar line is the same as that of a 3-phase AC line.

1.4.3(b) Comparison of a Bipolar DC System with 3-phase AC System for Same Insulation Levels (For same power transmitted and equal losses) A comparison of a bipolar DC system with that of a 3-phase AC system transmitting the same amount of power with same percentage of losses and with the same size of the conductor is given below. From this, the insulation strength of DC and AC systems can be compared. Let

Vp = Phase voltage of a 3-phase AC system Ip = Phase current of a 3-phase AC system Id = Conductor current of a DC system Vd = Voltage of one pole w.r.t. ground R = Resistance of each conductor

Assuming the power factor to be unity in the AC system, we have PAC = Total AC power = 3 Vp Ip PDC = Total DC power = 2 Vd Id

(1.6) (1.7)

For equal losses it follows that 3I 2p R = 2 ¥ I d2 R I p = 2/3 ¥ I d


Since power transmitted is the same in both the cases, we have (1.9)

3V p I p = 2Vd I d 3V p 2 3 ¥ I d = 2Vd I d Vd =

6 V = 2 p

3 V = 1.5 V p 2 p

If we compare the insulation in both the cases, the breakdown of the system insulation depends upon the maximum voltage, then DC insulation level = AC insulation level = 0.866

Vd 2 ¥ Vp


3 2 ¥ Vp 2 ¥ Vp


3 2


HVDC Transmission: Developments


An important conclusion that can be derived from the above is that the DC insulation level required is only 86.66% of that required in an AC system. It means that the number of insulators required in DC system is 86.6% that of 3-phase AC system. This results in lower cost of transmission.

1.4.3(c) Comparison of Bipolar DC with 3-phase AC System (For same power transmitted and same insulation level) Another basis of comparison is to assume equal power transmission with equal peak voltage in both AC and DC systems. The conductor size is assumed to be the same. The power losses can be compared in both the systems. When power transmitted is the same in both the cases Power transmitted in AC = PAC = 3Vp Ip Power transmitted in DC = PDC = 2Vd Id Since the peak voltage is same in both the systems Vmax = The maximum conductor to ground voltage = Vd Assuming the same maximum voltage from line to neutral in AC V p = Vmax Vd =

2 = Vd


2 Vp

(1.11) (1.12)

Given the total power transmitted in both the cases is same. We have



3V p I p = 2Vd I d = 2 2 V p I d I d = 1.06 I p Hence, 2 power loss in AC system 3I p R = 2 = 1.33 power loss in DC system 2 I d R


It follows from Eq. 1.14 that the power loss in an AC system is 33% more than a DC system.

1.4.3(d) Comparison of 3-phase Double Circuit AC Line with 3 Circuit DC Homopolar Line with Same Power Loss Let (a) Insulation levels be the same in both the systems, and (b) Percentage line losses be the same. Hence, the peak voltage from line to ground in both the systems is the same.


HVDC Transmission

2 V p = Vd (from Equation 1.12) i.e.

Vd = 2 V p PAC = 6V p I p PDC = 6Vd I d

Percentage losses in DC (due to bundling) 6 I d2 R 6 Vd I d = I d R

2 Vp

Percentage losses in AC = 6 I 2p R 6 V p I p = I p R V p

(1.15) (1.16)

Equating the percentage losses in both the systems, we have Id = 2 I p power transmitted in 3-circuit bundle line (DC) = 6Vd I d 6V p I p = 2 ¥ 2 = 2 power transmitted in double circuit 3f AC line

(1.17) (1.18)

The power that can be transmitted by a double circuit 3-phase AC line is one half of the power transmitted by 3-circuit DC line.

1.4.3(e) Other Factors in Favour of HVDC Transmission System These are as follows: 1. Overvoltages—Switching surges levels in EHVAC system are of the order of 2.5 p.u., whereas for DC it is less than 2.0 p.u. Earlier, DC lines were designed for a switching overvoltage of 1.7 p.u. 2. Reliability—The reliability of power supply is more in a DC line compared to AC. A single conductor to ground fault on bipolar DC line enables it to supply at least 50% power. But in 3-phase AC system more than 50% capacity is lost. 3. Stability of Power System—The power transfer capacity of a DC system is limited only by thermal conditions and current carrying capacity of the conductor and it is a function of difference of voltages at the two ends of the line. However in AC system, power transmitted depends on the sending end voltage VS, receiving end voltage VR, line reactance X and phase angle difference between VS and VR, (i.e.) P = VsVr sin d /X and is reduced with increase in line length due to increase in reactance (X). It is necessary to provide shunt reactors and series capacitors to compensate this. Stability limits: The power transfer capability vs distance is shown in Fig. 1.11. The power transfer capability of an AC line is a function of distance and it decreases with increase of the inductance, whereas DC line is not affected because it is governed by DC resistance of the line (conductors), thermal conditions and current carrying capability of the conductor. 4. Corona and Radio Interference and Skin Effects—Corona loss and radio interference are lower in DC systems. Further, there is no skin effect in the conductors of a DC system, whereas it increases the effective resistance of the AC system. 5. Towers and Tower Sizes—As shown, the DC insulation level is lower than AC insulation for a given power transmission. Therefore, the size of the towers and the corresponding right-of-way are also less.

HVDC Transmission: Developments

Fig. 1.11


Power transfer capabilities vs distance

6. Cable for Underground or Undersea Transmission—In a steady state operation there is no charging current or reactive KVA taken by the cable unlike in AC systems. Consequently there is no dielectric loss in DC cables. In DC cables electric fields are unidirectional and ionic motion is absent. Therefore, a working stress of 400 kV/cm can be used in DC cables as against 100 kV/cm in AC conditions. Thus, thinner insulation can be used for a given voltage and cooling conditions are superior in DC cables. Further, DC cables are subjected to less overcurrent stresses. The effective power transmitted by a cable with DC is about 2.5 times that with AC. 7. Voltage Profile—The voltage profile along the AC line is complicated by line charging and inductive voltage drops. When the lagging volt-amperes produced by the line (I2XL) is equal to the leading voltamperes produced by the line (V2/XC) for a particular load. Such a load is called surge impedance loading or natural loading on the line. Under these conditions V 2 XC = I 2 X L 2 XL L ÊV ˆ = ÁË ˜¯ = I XC C

Surge impedance Z n =

V L = I C

The surge impedance loading of the line is given by Pn =

V2 Zn


and Table 1.8 gives surge impedance loading for AC lines at 50 Hz operating frequency. Table 1.8

Surge Impedance Loading

Rated Voltage of the Line (kV) Surge Impedance Loading (MW)










HVDC Transmission

When load is equal to the surge impedance loading on the line, the voltage profile in an AC line is relatively flat and p.f. on the line is same throughout the line; and is equal to unity when conductor resistance and insulation leakage conductance of the line are neglected. When the sending end and receiving end voltages are held constant, the voltage at the middle of the line changes with the line loading as shown in Fig. 1.12.

Fig. 1.12

Variation of voltage along the line with load

Voltage in the middle of the line rises when the load is less than the surge impedance loading of the line, whereas the voltage at the middle of the line decreases, when the load on the line is more than Pn. In order to maintain constant voltages at the two ends, reactive power compensation is required. When the load P > Pn, shunt compensation is required with external capacitors to be connected across the line to nullify the lagging volt-amperes. On the other hand, under light load conditions (P < Pn), inductive compensation is required and can be done by switching on external series inductances along the line. Although DC converter stations require reactive power depending on the line loadings, the line itself does not require reactive power. The steady state charging currents in AC system pose serious problems in cables. This reduces the break-even distance of cable-transmission to around 40 km. 8. Line Compensation—For reasons stated in the previous section, AC lines require shunt and series compensation in long distance AC transmission to overcome the problems of line charging and stability limitation. Series capacitors and shunt inductors are used for this purpose. The other method of improving the stability and voltage regulation is by means of static var compensation (SVC). 9. Reactive Power Compensation—The line length can be expressed in electrical degrees as = l L C where


l is the length of the line in metres L is the series inductance of the line in henries/ph/metre C is the shunt capacitance of line in Farads/ph/metre

If the voltage along the line is to be regulated within ±5% throughout the line for all loads (light/heavy) compensation of reactive power becomes essential. The power transferred through the line can be expressed as

HVDC Transmission: Developments

P = Pn sec q



where Pn is the natural loading on the line and q is given by (1.20) as q = l LC In order to maintain constant voltage along the line as shown by Curve 2 in Fig. 1.12, lagging reactive power should be supplied during light loads by switching shunt reactors, and leading reactive power should be supplied during heavy loads by switching shunt capacitors. The reactive power requirement increases with the increase of line length. The variation of reactive power requirements with line loading is shown in Fig. 1.13. By means of controllable series/shunt compensations and static VAR systems, reactive power compensation can be optimised.

Fig. 1.13

Variation of reactive power with line loading

For long lines, the permissible transmission line loading, based on thermal ratings of conductor is much higher than P = 1.5 Pn. But the increased requirements of compensation and voltage regulation problems set a limit of power transfer to about 1.3 Pn. This difficulty is likely to be overcome by controllable series compensation and SVC. 10. AC Interconnection Problem—When two power systems are interconnected through an AC line, the automatic generation control of both the systems has to be co-ordinated using the line power and frequency signals. The operation of an AC tie may pose problem even with co-ordinated control of inter-connected systems because of the following reasons: (a) Presence of large power oscillations that lead to frequent tripping (b) Increase in fault level (c) Transmission of disturbance from one system to the other The power control through a DC line eliminates all of the above problems. An asynchronous DC tie does not demand co-ordinated control. It is clear that two systems which have different nominal frequencies cannot be interconnected directly but through a DC link only.


HVDC Transmission



1. Due to generation of harmonics in converter operation, nonsinusoidal currents will flow in converter transformers on the AC side, causing audio frequency telephone interference. Therefore, huge filters are required on both AC and DC sides to suppress the harmonics. 2. Static var compensation is essential since a DC system cannot generate reactive power when the converters operate with gate control. Reactive power is to be supplied from AC side at both ends. 3. Reliable multiterminal DC systems are yet to be established because of lack of HVDC circuit breakers. At present gate control is used to block DC under fault conditions. However, recent developments indicate that this can be achieved in near future. Canada (Quebec)—Massachusetts HVDC system is operating as a 3-terminal system and was put into service in 1991 (see Table 1.2). 4. Complexity of control. 5. High cost of conversion equipment. 6. Inability to use transformers to change voltage levels. Over the years, there have been significant advances in DC transmission, which have tried to overcome the disadvantages listed above. These are 1. 2. 3. 4. 5. 6.

Development of DC breakers Modular construction of thyristor valves Increase in ratings of thyristor cells that make up a valve Twelve pulse operation of converters Use of metal oxide gapless arresters Application of fiber optics and digital electronics in the control of converters



A study of the existing HVDC links in the world indicates that the reliability of DC transmission system is quite good and comparable to that of AC systems. The performance of thyristor valves is much more reliable than mercury arc valves. Further, developments like direct light triggered thyristor (LTT) and new techniques of control and protection have improved reliability levels. Transient Reliability: This is a factor specifying the performance of HVDC systems during recordable faults on the associated AC systems. The transient reliability can be defined as the ratio of =

No. of times HVDC systems performed as designed No. of recordable AC faults

Recordable AC system faults are defined as those faults which cause one or more AC bus phase voltages to drop below 90% of the voltage prior to the fault. It is assumed that the short circuit level after the fault is not below the minimum specified for satisfactory converter operation.

HVDC Transmission: Developments


Both the factors namely energy availability and transient reliability of existing DC systems with thyristor valves is 95% or more. The average failure rate of thyristors in a valve is less than 0.6% per operating year. It is common practice to provide redundant thyristors in the series string comprising an HVDC valve, so that in the event of failure of a thyristor, a redundant element can be replaced during scheduled maintenance once or twice a year. Maintenance of thyristor valves is also much simpler than mercury valves. Outage statistics of HVDC systems is given in the Table 1.9 indicating mean time to failure (MTTF) and mean time to repair (MTTR). Table 1.9

Outage statistics of HVDC systems

S. No.


1 2 3 4 5 6 7 8 9

MTTF (years)

Thyristor valve Converter transformer Smoothing reactor DC filter AC filter Master control Pole control Pole of the transmission DC line switch

MTTR (hours)

13.7 16.1 76.8 19.7 12.6 25.0 9.0 1.25/100 km 147.2

6.1 1700.0 1700.0 7.9 9.3 6.9 8.6 1.5 7.8

While comparing the reliability of various alternatives, it must be remembered that the bipolar DC line can be as reliable as a double circuit AC line with the same power capability. This is because of the fact that in the event of failure of one pole of DC system, the other pole can supply at least 50% energy with ground return.



Standard rated voltages of HVDC and EHVAC systems are given in the Table 1.10 and 1.11. The choice of voltage for new lines is preferred from the nearest system voltage. The commonly used HVDC voltages can be read from Tables 1.1 to 1.5. Table 1.10

Standard voltages for HVDC overhead lines Description

Bipolar line—pole voltage to ground Voltage between the poles

Rated Voltage in kV ±100














New transmission voltage level is decided only after surveying technical and economic aspects and acceptance feasibility reports of the line. Always, transmission systems are planned along with the planning of generation.


HVDC Transmission

Table 1.11

Standard Voltages as per (IEC) for 3-phase AC overhead lines Description

HV kV (rms)

EHV kV (rms)

UHV kV (rms)

Nominal rated voltage—phase to phase

132 220

345, 400, 500

750, 1000, 1100

Highest voltage—phase to phase

145 345

362, 420, 525

765, 1050, 1200



The power transmission capability of a single EHVAC line depends on the surge impedance loading and compensation and is denoted as Pn. Usually 3-phase lines are double circuit lines to ensure reliability of power supply, in case one of the 3-phase lines is out of order due to faults. Intermediate substations are required at an interval of 250 to 400 km for providing compensation of reactive power. If P is the total power to be transmitted through EHVAC/UHVAC line over a distance of 1000 km, the number of 3-phase circuit is given by n= where

P ¥2 Pn


n = Number of 3-phase circuits P = Total power to be transmitted Pn = Surge impedance loading of one line 2 = Factor for double circuit Number of AC line conductors = 3n Number of intermediate substations is given by È Length of the line in km ˘ Ê L ˆ S=Í - 1˙ = Á - 1˜ Ë 300 300 ¯ Î ˚


where L is the length of the line in km. For transmission of bulkpower over long distances, an HVDC bipolar line can be used up to 2500 MW but for EHVAC lines, the number of conductors changes with the distance as well as power. The Table 1.12 gives the number of conductors of EHVAC line for various power levels and line lengths. Table 1.12

EHVAC lines for di erent powers and line lengths

Length of the Line (km)

Power (MW)

Number of 3-phase AC Lines(n)

System Voltage (kV)

Total Number of Line Conductors

250 500 800 1000 1000 1000 1000 1000

1000 1000 1000 1000 1000 2500 2500 3000

2¥2 2¥2 3¥2 4¥2 2¥2 4¥2 2¥2 2¥2

400 400 400 400 750 400 750 750

12 12 18 24 12 24 12 12

HVDC Transmission: Developments


At present, several HVDC links have been installed in the world and by the year 2011 about 150 links are expected to be installed with a total power transfer capability of 100,000 MW.



HVDC links technically are superior to EHVAC links and are preferred for interconnection between two individually controlled AC systems. Tab1e 1.13 shows the superiority of DC link to AC link. Table 1.13 Comparison between DC and AC interconnection S. No.




Criterion for Preference


Power transfer ability

High, limited by temperature rise

Lower, limited by power angle and the reactance

HVDC Link for higher power


Control of power flow

Fast, accurate and bi-directional

Slow and difficult

HVDC is preferred


Frequency disturbance


Communicated between the system

HVDC is preferred


System support

Excellent, power flow is quickly modulated for damping oscillation

Poor, oscillations continue HVDC is better for long time


Transient performance



HVDC is preferred


Fault levels

Remains unchanged after interconnection

Get added after the interconnection

HVDC is better


Power swings

Damped quickly

Continue for long time

HVDC is better





HVDC is preferred


Frequency conversion


Not possible

HVDC is preferred


Cascade tripping of AC systems



HVDC is preferred


Spinning reserves of AC Network


Not much reduced

HVDC is preferred


Transient stability limit

Very high, limited, by thermal capacity of the equipment

Less than half of the thermal limit of line conductor

HVDC is preferred

1.10 HVDC-VSC TRANSMISSION SYSTEMS HVDC-VSC systems have been developed as a new technology in the last few years using IGBT valves. This technology was introduced in the mid 1990s using semiconductor chips that both rectify and control power. These chips are called the Insulated Gate Bipolar Transistors (IGBTs). The technology employs voltage source converters which transform DC voltage into AC or an AC signal into DC. This has the capability to keep both voltage and frequency stable, and hence, better stability over the grid. The important features and advantages are as follows:


HVDC Transmission

(i) Most suitable for underground and underwater schemes and transmission mode is Cable. DC cables contain solid insulation and hence are superior to the oil pregnated HV paper cables. The risk of damage to the cables is much less. (ii) Since this does not use overhead lines, and the cable is either two core or two single core cables bunched together, it does not produce an external magnetic field. The static magnetic field is largely cancelled since current flows in the opposite direction in the two conductors. (iii) It has independent control for active and reactive power. (iv) It can feed power into passive networks without any source or generation. (v) It has modular compact design and can be fabricated and delivered in short time. (vi) It has the advantage of remote control and unmanned operation. (vii) It is robust against grid alterations. (viii) Very low acoustic noise is produced, and noise within the converter station is mitigated through total enclosure of the equipment in a container. Further, the converter station is much more environment friendly and its impact is less, when compared to a thyristor converter station. Advantages and Benefits to AC system side are as follows: (i) Conventional converter station consumes reactive power depending on the firing angles of rectifier or inverter and this cannot be controlled independently. In HVDC-VSC systems both the active and reactive power flow within the operating range and can be controlled independently. (ii) Increased power transfer capability in the existing system can be obtained. Higher voltage levels at which the converter allows a transmission system to operate allows more power transfer to AC lines. (iii) Faster restoration after a block or block out—The converter and systems can recover faster since it has fast time response.

1.10.1 HVDC-VSC System: Description and Components The system consists of voltage source converter (VSC) with series connected IGBT valves controlled by pulse width modulation (PWM). The switching frequencies are usually around 1 to 2 kHz depending on AC system frequency and converter topology.

Fig. 1.14(a) Typical HVDC-VSC transmission system

HVDC Transmission: Developments

The basic units on DC side are (i) (ii) (iii) (iv) (v)

High voltage valve with series connected IGBTs (voltage range 50 to 150 kV) Compact HVDC capacitors of dry type (to act as voltage sources) A control unit HVDC cables for power transmission Normally no smoothing inductors or DC harmonic filters are used

On AC side as in the conversional system the equipment consists of (i) Converter transformer (no special type is needed) (ii) Harmonic filters (iii) Switch gear and control units

Fig. 1.14 (b) Typical IGBT assemblies

Typical converter station and system along with an IGBT module is shown in Fig. 1.14 and Fig. 1.15.

Fig. 1.15

An HVDC-VSC station



HVDC Transmission

1.10.2 Control of Active and Reactive Power Since the technique used in the operation of the IGBT is based on pulse width modulation technique, the control makes it possible to create any phase angle and amplitude instantaneously. Hence, the possibility of independent control of active and reactive power is obtained. No reactive power compensation is needed on AC side and only AC high frequency filters are to be installed. The converter is normally rated for a given voltage and current and so reactive power needs can be met or traded against the active power delivery. The combined active and reactive power capabilities for given power and voltage can be met as seen from P–Q diagram given in Fig. 1.16.

Fig. 1.16 An HVDC-VSC P–Q diagram

1.10.3 Application of HVDC-VSC Systems Their major usefulness and applications are as follows: (i) Multiterminal DC grid operation. The polarity of operation of converter does not change with power flow direction. Hence, the system can be built into blocks of multiterminals of HVDC system. Any number of HVDC-VSC converters can be connected to a DC bus with fixed polarity. Hence, a mesh DC system can be built similar to an AC system. (ii) Highly suitable for cable transmission of electric power. The break-even distance with cable transmission is much less (ª50 km) as seen from Fig. 1.9.

HVDC Transmission: Developments


(iii) Is a better choice compared to thyristor converter station. The power and voltage ranges of classical and HVDC-VSC systems are shown in Fig. 1.15. (iv) For interconnecting nonconventional sources like wind power, etc., to the main grid. Some of the HVDC-VSC light projects that are under operation or installation are given in Table 1.3.

Fig. 1.17

Power ranges HVDC classic and HVDC-VSC

REFERENCES Kimbark E.W., Direct Current Transmission, Wiley InterScience (New York), 1971. Arillaga J., High Voltage Direct Current Transmission, (London) Peter Peregrinus, 1983. Harraway L., Electrical Power Systems, Chapter 7, (London), Peter Peregrinus, 1985. Uhlmann. E., Power Transmission by Direct Current, (Berlin) Springer-Verlag, 1975. Wikipedia, List of HVDC Projects 2009, http://en.wikipedia.org. HVDC Light Technical Background Sea Breeze Olympic Converters LP, Web source. Weimers Lars., HVDC Light – The Transmission Technology of the Future, (Sweden) ABB Systems, Ludrika. 8. ABB Systems. http://www.abb.com.in

1. 2. 3. 4. 5. 6. 7.

WORKED EXAMPLES 1.1 A single-phase overhead AC line has inductance/km as 2 mH and a capacitance of 0.125 ¥ 10–7 F/km. Estimate the surge impedance loading of the line when the system voltage is 400 kV. Solution: Z n = Surge impedance =

L = C

2 ¥ 10-3 0.125 ¥ 10-7


HVDC Transmission

= 16 ¥ 104 = 400 W Surge impedance loading =

V 2 4002 = Zn 400

= 400 MW 1.2 Estimate the steady state stability of a 1-phase AC line with sending end and receiving end voltages maintained at 132 kV by a synchronous modifier, and when the sending end voltage is loading by 90° electrical degrees, given the reactance of the line is 10 W. Solution: Steady state power limit

VS VR sin d X

Given VS = VR = 132 kV d =p2 X = 10 W 1322 sin p 2¢ ¥ 106 10 1322 = = 1742.4 MW 10


1.3 An existing 3-phase AC line of 132 kV is converted into bipolar DC line with maximum system voltage in both the cases being the same. Estimate the DC voltage/pole and the number of standard 10 ≤ suspension insulators required. Solution: DC voltage pole = Vd =

132 3

¥ 2 kV = 108 kV

Taking 10 kV for disc No. of insulator units required in AC line =



1 = 8 (approx) 10

3 (Usually 9 discs are used) No. of insulator units required in DC line = 0.866 ¥ 9 = 8 Nos.

1.4 An existing 400 kV 3 f—AC line transmitting a power of 100 MW is converted into bipolar DC line. Estimate the DC voltage/pole and DC line losses, if the resistance of each conductor is 0.01 W. Assume p.f. = 0.90. Solution: The insulation strengths are the same since same line is converted into DC line.

HVDC Transmission: Developments

Therefore the DC voltage/pole = Vd = 400 ¥ AC current/ph. =


2 = 326 kV 3

1000 ¥ 106 3 ¥ 400 ¥ 103 ¥ 0.9

= 1.6 ¥ 103 A DC power = 2 I d Vd = 1000 ¥ 106 Id = =

1000 ¥ 106 2 ¥ 326 ¥ 103 500 ¥ 103 326

= 1.533 ¥ 103 A DC line losses = 2 ¥ I d2 R = 2 ¥ 2.35 ¥ 106 ¥ 0.01 = 5.7 ¥ 104 = 57 kW

QUESTIONS 1. 2. 3. 4. 5. 6.

State the advantages of HVDC transmission over EHVAC transmission for bulk power transmission. Give a neat sketch of different HVDC links. Why is bipolar line more commonly used? What are the advantages and disadvantages of homopolar HVDC links over other types of links. Discuss the different factors that favour DC transmission. Explain in detail the superiority of technical performance of HVDC lines to that of EHVAC lines. A ±400 kV DC transmission line to be compared with a 750 kV 3-phase EHV system for equal power transmission. Estimate the insulation levels and the ratio of line losses in both the systems. Ans: DC voltage/pole = 33%

AC line loss = 33% DC line loss

7. Explain clearly what do you understand by surge impedance loading? What is its importance? Explain how a voltage profile of AC line is governed by load and the length of the line. 8. With a neat schematic diagram, state the various apparatus required for HVDC station and explain the purpose of each. 9. What are the limitations of a DC line? How have these limitations been surmounted in modern HVDC lines? 10. Define the terms ‘transient reliability’ and ‘short circuit ratio’ as applied to transmission lines. Discuss the effect of these factors on the performance of a DC link. 11. Compare the performance of EHVAC link with HVDC link for (i) equal voltage (insulation level) and (ii) equal power losses. 12. What is an HVDC-VSC system? Give the single line diagram of the system? 13. What are the advantages of voltage source controlled IGBT HVDC schemes?


HVDC Transmission

PROBLEMS 1. A 400 kV, 3-phase AC line of 800 km length transmitting 1000 MW is converted into a DC line. If the surge impedance of the line is 320 W, estimate (i) The number of conductors required and surge impedance loading as 3-phase AC system. (ii) Voltage per pole as DC line power losses, as percentage of AC power losses. Take 0.9 lag for an AC system. Ans: (i) 12 conductors, 500 MW (ii) 326 kV, 75% upf, 50% upf, 0.9 pf 40% 2. In Problem 1 above, if the AC line is converted into a homopolar DC line with 3 circuits, estimate DC line losses. Ans: ª 50% of AC (upf) 3. A 220 kV double circuit line rated for 250 MVA, at 0.8 p.f. is converted into a DC line. There are 14 std. disk insulators on the line and are rated 10 kV (rms) or 14 kV peak. Estimate: (i) The voltage rating of the DC line with same insulators. (ii) Maximum DC power transfer capability. Ans: (i) ±200 kV (ii) 1000 A, 400 MW

MULTIPLE CHOICE QUESTIONS 1. HVDC transmission commercially began in the year (a) 1950 (b) 1954 (c) 1970 (d) 1935 2. The initial HVDC valves were (a) IGATS (b) Thyristors (c) Mercury arc rectifiers (d) None of the above 3. Thyristor valves came into operation in the year (a) 1950 (b) 1954 (c) 1972 (d) 2000 4. Systems using IGBT valves came into operation in (a) 1972 (b) 1954 (c) 1993 (d) 2000 5. HVDC systems are mainly used with large power rating for (a) interconnection of two systems with different frequencies (b) bulk power transmission over long distances (c) underwater or submarine cable transmission (d) for connecting nonconventional power sources like wind power etc. to the grid 6. A quadruple valve consists of (a) four units in series for 12-pulse operation (b) four units connected for operation as bridge rectifier (c) two double valves (d) twelve valves for 3-phase connection 7. A DC cable used for HVDC transmission is (a) mass impregnated oil-filled cable (b) dry caused polymeric insulated cable with metallic screen and outer covering

HVDC Transmission: Developments









(c) oil or liquid impregnated paper cable (d) any one of the above The break-even distance is the distance beyond which (a) DC transmission is economical (b) AC transmission is economical (c) cost of both systems are the same (d) both (b) and (c) In a bipolar system (a) both conductors are positive (b) both conductors are negative (c) one conductor is positive and the other negative (d) one conductor is positive or negative and other is at ground potential In a monopolar system usually the pole is (a) positive (b) negative (c) positive and negative (d) alternately positive and negative Modern HVDC systems are all (a) 3-pulse converters (b) 6-pulse converters (c) 24-pulse converters (d) 12-pulse converters Short circuit ratio of an HVDC grid is (a) DC power flow/kVA (b) AC MVA/DC MW (c) voltage/current at the short circuit point (d) short circuit MVA at converter bus rated DC power MW The first HVDC scheme in India is (a) Vidhyachal back-to-back system (b) Chandrapur–Padghe scheme (c) Delhi–Rihand 500 kV system (d) Sileru–Barsoor system HVDC-VSC scheme employs (a) IGBT valves (b) light or optically triggered thyristor valves (c) mercury arc valves (d) MOSFETs and GTO valves The main advantage of HVDC-VSC schemes is (a) both active and reactive powers can be controlled (b) does not require DC filters (c) can be used for very high power more than 1500 MW (d) all of the above

ANSWERS 1. (b) 9. (c)

2. (c) 10. (b)

3. (c) 11. (d)



4. (d) 12. (d)

5. (b) 13. (d)

6. (a) 14. (a)

7. (b) 15. (a)

8. (a)


HVDC Converters



The first HVDC transmission facility was established in 1954, between the Swedish mainland and the Island of Gotland at a voltage of 100 kV, 20 MW. Till 1970, mercury arc valves [see Fig. 2.24(a)] were used in converter stations. With the advent of high power semiconductor devices, mercury valves have been replaced by thyristor valves in HVDC converters. The largest device (SCR) rating now available is in the range of 5 kV, 3000 A. The highest DC transmission voltage has reached ±800 kV. Lately, many power electronic devices like LASCRs, GTOs and IGBTs have come into successful operation for power conversion and control of motor drives. Among these IGBTs used in voltage source converters (VSC) have become highly suitable for HVDC application and today many of the HVDC schemes are using IGBTs in power converter valves. Before we study HVDC transmission systems, it is necessary to have the basic knowledge of semiconductor devices, their characteristics and methods of control. In this section, static and dynamic characteristics, methods of triggering, series-parallel control of SCRs and IGBTs are discussed. Elementary ideas of rectification and commutation of converters have also been reviewed.



Power semiconductor devices are operated in switching mode to handle high voltages and currents. A wide variety of these are presently available covering a power spectrum ranging from 1 kW to 100 MW. Following are some of the currently available power devices with their typical maximum ratings as shown in Table 2.1 and in Fig. 2.1. The term ‘thyristor’ is the general name given to all controllable four layer pnpn devices like SCR, Triac, LASCR, GTO and other derivatives. Among these, SCRs have dominated converter applications for more than 40 years. Over the years, their power capacity has increased from a few kilowatts to a few megawatt. As a result of advanced technology, they have proved to be the most economical. Thyristors with special structures like symmetrical SCR (ACSR), reverse conducting thyristor (RCT), gate assisted turn-off thyristor (GATT) have been introduced with reduced turn-off times for inverter applications. Newly developed ASCR

HVDC Converters

Table 2.1 Device

Maximum Voltage (V)

Single Unit Current (A)

Maximum Current (A) (peak)

Typical Max. Frequency (kHz)

Switching Junction Temperature (°C)





–40° to 125°

Thyristor (SCR)


600 to 800



–40° to 115°





>2 kHz

–40° to 115°




>2 kHz

–40° to 115°











–40° to 115°






–40° to 125°






–20° to 150°

*Source: M/s Siemens Ltd, ABB websites

Fig. 2.1

Fig. 2.1

(a) Press-pack high power devices

(b) Advanced power devices reduce losses and raise switching frequency



HVDC Transmission

can block up to 4000 V forward voltage. High power LASCRs have been developed mainly for HVDC and static VAR compensation (SVC) applications, where a large number of devices is connected in series with light triggering, which provides gate circuit isolation and simultaneous triggering of all devices in a string. GTO is gate turn-off thyristor. Recent developments in high power GTO (5 kV, 3000 A) have led to the elimination of commutating circuits. Consequentially, they are replacing other thyristors used in high power converter/inverter applications.



Silicon controlled rectifier (SCR) is a type of a thyristor and is often simply referred to as a thyristor. A thyristor is a three terminal, four layer semiconductor device. Its diagrammatical representation and circuit symbol are shown in Fig. 2.2. The terminal connected to end P region is called anode, the terminal connected to end N region is called cathode and the terminal connected to P region adjacent to cathode is called the gate. When the anode is made positive with respect to the cathode, the SCR is said to be forward biased. When the anode is negative with respect to the cathode, the SCR is said to be reverse biased. The SCR conducts only in one direction, i.e. from anode to cathode. Symbolic representation of an SCR is shown in Fig. 2.2 (b) and (c). When the SCR is forward biased, it comes to an on state only when the gate trigger pulse is given. Note, it acts as a closed switch. When the SCR is reverse biased, then it is turned off and it does not allow the current to flow in the opposite direction and acts as an open switch. Thus, the SCR is a unidirectional controlled switch. With fast switching action, small size, high current and high voltage ratings, the SCR can be adapted to many switching applications.

2.3.1 Static V–I Characteristic of SCR The static V–I characteristic of SCR is shown in Fig. 2.2(d). At first, it is nonconducting in both forward and reverse directions. As the voltage is increased in the forward direction, the leakage current does not increase appreciably until a point is reached where an avalanche multiplication begins. A slight increase of voltage would cause breakdown and the SCR comes to an on state. After the SCR has been switched to on state, a certain minimum value of anode current called holding current is required to maintain the thyristor in this low impedance state. If the anode current is reduced below this critical holding current, the thyristor reverts to an off state. The SCR has the following three modes of operation:

(i) Reverse Blocking: Mode-1 The SCR is said to be reverse blocking when the cathode is made positive with respect to the anode. Then junctions J1 and J3 are reverse biased while J2 is forward biased. The device behaves in similar manner as two diodes connected in series with reverse voltage applied across them. A small reverse leakage current of the order of few hundred micro-amperes flows through it. This is the reverse blocking mode (off state) of the SCR. A small reverse current is produced as the reverse voltage is increased till the reverse avalanche region is reached. Here, the reverse current increases rapidly at the reverse breakdown voltage (VRBO). The presence of high current in conjunction with a high voltage gives rise to a large dissipation of power. If the junction temperature crosses the permissible value, it can damage the SCR.

HVDC Converters

(a) Representation

(b) Circuit symbol


(c) Switch

(d) Static V–I characteristic of SCR

Fig. 2.2 Thyristor and its representation

(ii) Forward Blocking: Mode-2 A thyristor is said to be forward biased when the anode is positive with respect to the cathode. Under these conditions, junctions J1 and J3 are forward biased while junction J2 is reverse biased. The reverse bias on junction J2 limits the forward current to the value of forward leakage


HVDC Transmission

current in order of milliamps. The thyristor is then said to be in a forward blocking state (off state). Application of a small positive gate current causes a slight increase of forward leakage current. If a large gate current is given, the SCR comes to an on state.

(iii) Forward Conduction: Mode-3 With forward bias voltage, a thyristor can be made to come to a conduction state (on state) using any one of the four techniques mentioned below: (a) Exceeding forward break-over voltage (b) Gate current or gate triggering dv (c) Exceeding —– rating of the SCR dt (d) Irradiation of gate-cathode junction

(a) Exceeding forward break-over voltage Any increase in the anode voltage in the absence of a gate signal causes avalanche breakdown of junction J2 at a voltage called forward break-over voltage (VFBO). At this voltage, the thyristor changes its state from a high voltage across it with a low leakage current (off state) to a low voltage across it with a large forward current whose value is limited mainly by the load impedance. This is the on state of the thyristor.

(b) Gate triggering This is the most common method of triggering a thyristor. When a thyristor is desired to be turned on, a suitable positive voltage is applied at the gate cathode terminal. The layer at the gate is flooded by electrons from the cathode and it loses its identity as a layer. Accordingly the thyristor becomes equivalent to a conducting diode. As shown in Fig. 2.2, a positive gate to cathode current reduces the forward break-over voltage. For a given forward voltage there is a minimum gate current at which the thyristor turns on. Once the thyristor is on, the gate current is no longer required by the device to remain in conduction and hence, a gate pulse is enough to turn on the SCR. However, if the gate current is reduced to zero before the anode current reaches a value called the latching current, the thyristor will turn off again. Once the latching current is exceeded, the gate terminal loses its control. A thyristor cannot be turned off unless the gate signal is removed and the forward current falls below the ‘holding current’ value. The latching current is much higher (10 times) than the holding current, and can be assumed to be three times the holding current when not specified in the thyristor data sheet. dv (c) —– turn-on A thyristor may be triggered on by a rapid rate of increase of forward anode to cathode dt voltage in the presence or absence of gate signal. This can be explained in terms of anode to gate, and gate to cathode capacitance. A rapidly rising anode voltage produces transient gate current sufficient to turn on the SCR. This type of turn-on is not used. An unwanted turn-on may however occur due to spurious spikes of dv voltages emanating from other equipment. It can be avoided by ensuring that —– across the thyristor is less dt than the value at which it may turn on.

(d) Irradiation of gate-cathode junction A beam of light directed at the gate to the cathode junction can turn on the thyristor. This method of turn-on is used in LASCR.

2.3.2 The Two-Transistor Model of SCR The two transistor analogy demonstrates the positive feedback action that results when a pnpn device is switched on. The SCR can be considered as an npn and pnp transistor, connected with the collector of one

HVDC Converters


transistor, attached to the base of the other and vice versa as shown in Fig. 2.3. It is evident from the figure that the collector of pnp transistor Q1 is connected to the base of npn transistor Q2. Let a1 and a2 be the current transfer functions of Q1 and Q2 respectively.

(a) Two transistor model

(b) Circuit representation

Fig. 2.3 Two transistor equivalent of SCR

In any transistor the collector current IC = aIE + ICBO where


IC = Collector current IE = Emitter current ICBO = Leakage current Considering Q1, IC1 = a1IA + ICBO1 Considering Q2, IC2 = a2IK + ICBO2 Considering as Thyristor, IK = IA + IG


IA = IC1 + IC2 = a1IA + a2IK + ICBO1 + ICBO2 = a1IA + a2(IA + IG) + ICBO1 + ICBO2


IA = a 2 I G + I COB1 + I CBO2 (1 - [a 1 + a 2 ])

For any transistor a increases with emitter current IE as shown in Fig. 2.4.



HVDC Transmission

For very small values of IE, a will be very small. When the gate current is zero IA =

I CBO1 + I CBO2 1 - (a1 + a 2 )


the equivalent transistors Q1 and Q2 will have very small forward bias of the emitter base junction; the values of a1 and a2 are very small; and IA = ICBO1 + ICBO2. If positive gate current is given, the base current of Q2 increases resulting in an increase of IC2 the collector current of Q2. But IC2 is the base current of Q1. Thus, the Fig. 2.4 Variation of a with IE collector current IC1 of Q1 is increased, which in turn increases ICBO2 causing further increase in IC2. Thus, regeneration starts, and a1 and a2 increase as the emitter currents of two transistors increase. When the sum of a1 and a2 approaches unity, the two transistors are driven to saturation and the anode current IA of SCR reaches a value determined by the external load circuit. From the above discussion, it can be seen that a small positive amplitude signal applied between gate and cathode when the SCR is forward biased, will ensure turn-on of SCR. Once SCR is latched into conduction, the gate signal serves no useful purpose and may be removed.

2.3.3 Dynamic Characteristics of SCR (a) Dynamic characteristic during turn-on The time td is called delay time and it is the duration between the front of the gate pulse and the beginning of rapid rate of increase of anode current. tr is the rise time and it is the duration between 10% and 90% of the final value of anode current. Spread time tp is the

Fig. 2.5

Turn-on characteristic of SCR

HVDC Converters


time taken for the conduction to spread over the entire cross section of the thyristor. Turn-on time of the SCR is the sum of td, tr and tp. Thus tON = td + tr + tp


tON is the order of 1 to 3 microseconds. During the initial part of turn-on only a smal1 area near the gate terminal conducts anode current. If the anode current is allowed to increase at a faster rate, a large current will flow through a comparatively narrow di channel, resulting in local heating which may damage the thyristor. Hence, a maximum is specified for dt a given thyristor.

(b) Dynamic characteristic during turn-off Thyristor turn-off means that the thyristor has regained forward voltage blocking capability after forward conduction. A thyristor can be turned off by reducing the forward current to a value less than the holding current and maintaining a reverse bias at least for a specific period. The dynamic characteristic during turn-off is given in Fig. 2.6.

Fig. 2.6

Turn-o characteristic of SCR

The thyristor is turned off by applying a negative voltage to SCR. Let the negative voltage applied to SCR at t = 0. Then the current IA starts decreasing. The current becomes zero, and later a small reverse current flows. The thyristor continues to conduct current because of the stored charge and acts as a short circuit with a small +ve voltage across it, even after its current has reversed. Till such a time when about sixty percent of stored change gets recovered, the thyristor acts as a short circuit and the reverse current reaches a peak value. Beyond this point, the thyristor develops reverse blocking capability. The reverse recovery time trr is shown in the figure. Thyristor turn-off is not complete at the end of reverse recovery time. The junctions J1 and J3 have recovered during trr but the junction J2 has trapped charge. The thyristor blocks the forward


HVDC Transmission

voltage only when the excess carriers at junction J2 have recombined. The time required for recombination of these carriers is tgr, the gate recovery time. The reverse voltage across SCR has to be maintained during gate recovery time also. The turn-off time tq is equal to the sum of trr and tgr.

2.3.4 Gate Triggering or Firing Circuits of SCR Among the different methods of turn-on, gate pulse control is by far the most commonly employed method. The gate control circuits are called firing or triggering circuits. These are generally low power electronic circuits. Any practical power circuit configuration consists of several thyristors. The gate control circuit must fulfill two general functions: 1. It is required to produce voltage pulses to each SCR at the appropriate instant of time in a periodic manner and with a particular sequence depending upon the type of power circuits. 2. Pulse produced by the control circuit are usually at low power level. If fed directly, they may not be able to trigger the thyristors into conduction. The pulses are therefore, coupled with the gate cathode terminals of a thyristor through a ‘driver’ circuit which consists of a pulse amplifier and a pulse transformer. Figure 2.7 shows the general layout of the firing circuit and Fig. 2.8 illustrates typical output waveforms of the pulse generator. The electronic pulse generator is usually placed separate and away from the assembly of thyristors. A separate regulated DC power supply is provided for it. The pulses generated are passed through the pulse amplifier module. The output of the pulse amplifier goes through the pulse transformer and damping network before the pulses are coupled to the gate and cathode terminals of a thyristor through shielded cables. The function of the pulse transformer is to isolate the control circuit from the high voltage anode circuit.

Fig. 2.7

General layout of the firing circuit

HVDC Converters

Fig. 2.8


Typical pulse generator outputs (a) Single pulse (b) and (c) HF pulse train

2.3.5 Series and Parallel Operation of Thyristor Several thyristors are connected in series or in parallel when circuit applications require voltage or current ratings in excess of those provided by a single thyristor. Certain precautions must be taken to ensure satisfactory operation and proper utilisation of individual thyristor ratings. Due to dissimilar characteristics of thyristors of same ratings and specifications, distribution of voltage in series connection and distribution of current in parallel connection are not equal. External equalising circuits are then used to ensure proper sharing.

(a) Series Connection When thyristors are connected in series, variation of forward and reverse blocking characteristics cause unequal distribution of voltage in steady state. Figure 2.9 shows how two thyristors of same ratings and specifications share the voltage when they are connected in series. Thyristor T2 is supporting higher voltage. T2 is on the point of breakdown. T1 is supporting only a small voltage. The maximum voltage that the string can block is only (V1 + V2) and not 2V2. Full forward blocking voltage capabilities of each thyristor can only be realised by equal distribution of forward blocking voltages.

Fig. 2.9

Distribution of voltage in series connection of thyristors

A nearly equal distribution of voltage is obtained by connecting equal resistance across each thyristor as shown in Fig. 2.10. This is called static voltage equalisation. Unequal voltage distribution among thyristors in series also occurs during transient conditions of turn-off or turn-on. If one thyristor in the string has short reverse

Fig. 2.10

Static equalisation of voltage


HVDC Transmission

recovery time, it will solely support string reverse voltage. A thyristor which has the highest turn-on time in the string will have to momentarily support the full string voltage. One method that can be used to minimise turn-on time differences is to use gate pulses with fast rise time and magnitude as large as the rating allows. Capacitors connected in parallel to each thyristor forces equal sharing during transient conditions. Since the shunt capacitor discharges through the thyristor during turn-on, a resistor Rc is provided to limit the magnitude and the rate of change of current. A diode D is placed across the resistor Rc to bypass it for forward voltages. The circuit is called dynamic equalising circuit and is shown in Fig. 2.11.

Fig. 2.11

Dynamic equalising circuit

(b) Parallel Connection of SCRs The V-I characteristic of a thyristor during forward conduction is such that a small change in voltage results in large variation in current. Thyristors connected in parallel will have equal voltage drops. A slight mismatch in characteristics will reduce the current handling capability of the unit by a large amount. Figure 2.12 shows the sharing of current between two parallel connected thyristors T1 and T2 of the same type. Due to mismatch in characteristics, when T1 is carrying rated current I1, thyristor T2 is carrying current I2, which is much less than its rated value. Total rated current of the parallel unit is only I1 + I2 instead of 2I1.

Fig. 2.12

Distribution of current in parallel connection of thyristors

If one of the thyristors has large turn-on time, the forward voltage across it drops to a very low value when other thyristors in parallel have already turned on. If the forward voltage is less than the finger voltage, the thyristor will fail to turn-on. The thyristors already on will now be required to share the complete load current and may get damaged due to overloading. The parallel thyristors are usually mounted on the same heat sink to maintain equal junction temperatures. This minimises current unbalance resulting from thermal differences

HVDC Converters


between thyristors. Unequal inductive effect on current carrying conductors may also cause uneven current distribution. This effect can be minimised by locating the thyristors symmetrically on the heat sink. To meet the different triggering requirements of thyristors connected in parallel, it is advisable to use gate signals with fast rise time and magnitude as large as the rating allows.

2.3.6 Triggering Series Operated SCRs The following two primary methods are commonly used for triggering SCRs: 1. Simultaneous triggering 2. Slave triggering Simultaneous triggering of all SCR gates is a preferred method. Slave triggering produces some time delay between the master and slave operation.

(a) Simultaneous Triggering via Pulse Transformer This method of triggering is indicated in Fig. 2.13. The pulse is transmitted through the pulse transformer secondaries to all the SCRs simultaneously. The insulation between the windings of the pulse transformer must be able to support at least the peak of the supply voltage. As the system voltage becomes higher, the design of pulse transformer will become very difficult.

Fig. 2.13

Simultaneous triggering of series connected SCRs via pulse transformers

(b) Simultaneous Triggering by Means of Light Figure 2.14 shows an approach whereby simultaneous triggering of series connected SCRs is achieved by triggering LASCRs in the gate circuit of each SCR. This method of triggering provides the required gate isolation along with simultaneous turn-on, when a single light source is used to turn on all LASCRs. The series combination of R1 and R2 is made equal to the required shunt resistance Rs (for static equalisation), R2 is made fairly small compared to R1 so that low voltage LASCRs can be employed.


HVDC Transmission

Fig. 2.14

Use of LASCRs to trigger series connected SCRs

2.3.7 Mounting and Cooling of Power Semiconductor Successful application of SCRs depends to a great extent on adequate cooling of these devices. If junction temperature of an SCR rises to a high value, permanent damage may occur in its characteristics and the device may fail by thermal runaway and melting. Circuits may fail before thermal runaway due to melting in the SCR. This can occur due to insufficient cooling which may reduce the forward break-over voltage, increase turn-off time, etc. Variation in these and other SCR characteristics outside specifications sufficiently induce circuit malfunction. For these reasons, all SCRs and rectifier diodes are designed with same type of

HVDC Converters


heat transfer mechanism to dissipate internal heat losses. Mounting surfaces are generally an integral part of an SCR’s heat transfer path. Proper mounting is always needed for successful SCR cooling. Thus, cooling and mounting the SCR must be treated together. For small lead-mounted SCRs, cooling is maintained by radiation and convection from the surface of the case and by thermal conduction down the leads. Medium current rating SCRs are either press fit type or stud type. These two types are mounted on heat sinks. Large current rating SCRs are available in flat base package. Special mounting arrangements are available and forced cooling is adopted for dissipation of heat. In very high power applications forced liquid cooling is preferred.

2.3.8 Line Commuted Converters It has been mentioned in the previous section that the gate in a conventional thyristor has no control after it has been triggered into conduction. The device can be brought back to the blocking mode either by reducing the forward current below the holding current level or by applying a large reverse voltage across it. This must be achieved by external means and the turn-off process is called commutation. There are various methods of commutations and only line commutated converters are discussed in this section. In the line commutated converters, the available line voltage is used for commutation and no external commutating circuits are required. Line commutated converters are used either for converting AC to DC or DC to AC. When they are converting AC to DC they are called rectifiers and when converting DC to AC they are called inverters. During rectifying action, a variable DC voltage can be obtained from a fixed AC source and during inversion variable DC can be converted to a constant AC (fixed) and can feed power into AC mains only when connected to external mains.



During the late 1980s, combining the good features of both bipolar transistors and MOSFETs, a totally new device known as insulated gate bipolar transistor or IGBT was created. These devices have the high input impedance of the MOSFET and low on-state voltage drop that varies slightly with junction temperature. The turn-off time of an IGBT is greater than that of a MOSFET. IGBT is a voltage controlled device with low switching and conduction losses.

2.4.1 IGBT: Structure, Operation and Equivalent Circuit The cross section of an IGBT along with its symbol and equivalent circuit are given in Fig. 2.15(a) to (c). The structure is similar to that of a MOSFET except that N+ substrate is replaced by the P+ collector region which has epitaxial ‘n’ layer with large minority carriers during forward conduction. The device has three terminals, viz. gate, collector and emitter instead of gate, drain and source of a MOSFET. Current flow cannot occur when a negative voltage is applied to the collector with respect to the emitter, as the lower junction J3 will be reverse biased. This provides the device with reverse blocking capability as shown in Fig. 2.15 (c).


HVDC Transmission

Fig. 2.15 IGBT representation and characteristic

HVDC Converters


The output characteristic of an IGBT is shown in Fig. 2.15(d). The parasitic P-N-P-N thyristor structure between collector and emitter may be seen from Fig. 2.15(a). Some of the features and characteristics of High Voltage IGBTs are

(a) Reverse Blocking Capability When a negative voltage is applied to the collector terminal, reverse blocking is provided by junction J3. Junction J3 becomes reverse biased for negative collector voltage. When blocking voltage requirement increases. N-base width is correspondingly increased (typically 0.1 to 0.2 mm). Devices with reverse blocking up to 4500 V are available now.

(b) Forward Blocking Capability This is provided by p-base—n-base junction J2 during operation with positive collector voltage. For forward blocking mode, the gate is shorted to the emitter. (c) Forward Conduction Mode The gate voltage given must be sufficiently large above the threshold level to make channel resistance small during current flow. Hence, the injected carrier density is typically 100 to 1000 times greater than N-base doing level which reduces the series resistance to a small value. Hence, IGBT can operate at high current density. The equivalent circuit model is given in Fig. 2.15(c), which shows the main current path.

(d) Switching Characteristic The IGBT design is such that turn-on and turn-off times are controlled by gate-emitter source impedance. Turn-on is achieved by applying positive voltage between gate and emitter such that VGE >> VGE (threshold). Turn-off is controlled from the external circuitry. Usually turn-on and turn-off times are of the order of 2 to 3 ms. (e) Conduction and Switching Losses in IGBTs The power loss in IGBT will be (i) drive losses, (ii) conduction loss, (iii) off-state losses, and (iv) switching losses. Of these, drive losses and switching losses are more; and switching losses depend on the duty cycle and pulse width.

(f ) Gate Drive Gate drive is usually given either through a pulse transformer and pulse generator or a pulse generator connected through a diode. IGBT turn-off through a snubber circuit is shown in Fig. 2.16.

Fig. 2.16

IGBT turn-o with and without polarised snubber


HVDC Transmission

2.4.2 IGBT Component Assembly Technology IGBT valves in HVDC application are quite different from that of thyristor technology. The IGBT pack is formed with a series parallel combination of individual IGBTs. A typical pack may contain 4 to 6 individual pieces and is typically rated for 4000 to 6000 V and up to 800 A. Such units are connected in series for the given voltage application. In Fig. 2.17(a) an individual IGBT element 4.5 kV, 750 A (DC)/800 A r.m.s. (AC) is shown; and series connected elements along with reverse biased diodes, voltage grading circuits and gate drive unit are shown in Fig. 2.17(b).

Fig. 2.17 (a) Switching frequency 750 Hz (1000 Hz)

Fig. 2.17

(b) Series connection of IGBT

HVDC Converters


The turn-on and turn-off series connected IGBT shown in Fig. 2.18 clearly indicates that a current of 1200 A at an individual 1500 V voltage level, switches on or off in about 6 ms, when compared to thyristors which take around 100 ms to turn-off under line commutation.

Fig. 2.18

(a) Turn-on waveform of series connected IGBTs

Fig. 2.18

(b) Turn-o waveform of series connected IGBTs

Unlike the thyristor valves, the operation of rectifier and inverter is VSC (Voltage Source Control). Pulse width modulation technique is used in inverter and hence the valve can feed a passive load also (which is not possible with thyristor valves).



Solid state power electronic components are commercially available with maximum ratings of around 5000 V and 80 to 300 A. These are usually made as packs or modules for voltage rating 4 to 6 kV and up to 3000 A, by


HVDC Transmission

proper series parallel connection along with gate firing circuits, protection and redundered component by giving a factor of safety of 2 to 3. In order to build up a valve for high voltage rating of several hundred kilovolts (100 to 300 kV) individual valve group series connection of the packs or modules is done. Proper cooling is provided with forced air or gas and liquid cooling, so that the component junction temperatures are within limits.

2.5.1 Thyristor Valve Assembly Thyristor valves are made individually (single valve) or as double valves (for 6-pulse units) and as quadruple valves for 12-pulse operation (Ref. Fig. 1.5). The advantage with double or quadruple valves is that a permanent series connection is made between individual valve elements and only two terminals (one AC and one DC for double valves) and 4 terminals (two AC and two DC) for quadruple valves are brought out which considerably save bushing cost as well as terminal arrangements and mounting.

2.5.2 IGBT Valve Assembly Since voltage source converters and PWM inverter is employed in case of IGBT valves, in many applications the sending end mainly operates as rectifier and at the receiving end, inverter mode operation is done. (Ref. Fig. 1.5). Valve stack is assembled as a single unit for each phase of the 3-phase supply and for each DC pole. Usually cooling is forced air or water cooling.



This is a new transmission technology based on voltage source converters, wherein the valves are built using IGBTs and PWM technique to create the desired waveform. With PWM, it is possible to create any waveform within the limit set by the switching frequency, the magnitude and phase angle of the fundamental component which is made sinusoidal. The VSC is a controllable voltage source. HVDC-VSC acts like a synchronous source that can control both active and reactive power. HVDC-VSC schematic diagram is shown in Fig. 1.14(a). The converter can be built either for back-to-back or cable transmission scheme (cable 1.14a built will add for the capacitance at the DC output end). The AC side arrangement is same as that of a thyristor scheme. Since high frequencies are generated in this scheme, the AC side reactors are needed, and no reactor is needed on the DC side. Here, there is no need for reactive power compensation and only harmonic filters are needed on the AC side (Ref. Section 2.6.2, 3.11). Large size capacitors are needed on the DC side to reduce voltage ripple and to provide low inductive path for turn-off current.

2.6.1 HVDC Converters The converters so far employed in actual transmission applications are composed of a number of elementary converters, that is, of three-phase, two-level, six-pulse bridges or three-phase, three-level, 12-pulse bridges, as shown in Fig. 2.19 (a) and (b). The two-level bridge is the most simple circuit configuration that can be used for building a three-phase forced commutated VSC bridge. It has been widely used in many applications at a wide range of power levels. As shown in Fig. 2.19(a), the two-level converter is capable of generating the two voltage levels –0.5 UdcN and +0.5 UdcN.

HVDC Converters

(a) Two-level


(b) Three-level

Fig. 2.19

Voltage Source Converters

The two-level bridge consists of six valves and each valve consists of an IGBT and an anti-parallel diode. In order to use the two-level bridge in high power applications, series connection of devices may be necessary and then each valve will be built of n number of series connected turn-off devices and anti-parallel diodes. The number of devices required is determined by rated power of the bridge and power handling capacity of the devices. At present IGBTs of voltage rating 4.5 kV are available and can be switched on/off at about 2 kHz or less, and the valve can block voltages up to 150 kV. A ‘VSC’ rated for 800 A r.m.s., ±150 kV and power ratings up to 200 MW is in operation. Individual two-level and three-level converter phase modules are shown Fig. 2.20 (a) and (b). The phase module acts like a switch and generates a positive voltage and negative voltage (square pulses from the AC

Fig. 2.20 (a) Voltage source converter two-level phase module


HVDC Transmission

for each phase). In case of 3-level converter module, the pulse generated by an individual phase member is V of a shorter duration [Fig. 2.20(b)]. The positive pulse d from each leg is added in time to get a continuous 2 voltage at the capacitor terminals and the capacitor maintains a constant voltage for the load connected across it. In case of operation as an inverter, the DC voltage applied to the converter is given pulse width modulation (PWM) at a high frequency (1 to 2 kHz) for generating 50 or 60 Hz AC. As such, the harmonics generated are of very high order and the filters required on the AC side are of less capacity and of much less MVA capacity. No reactive power compensation is needed as the PWM converter can generate the required reactive power on its own. The voltage waveform of one phase of the inverter output is shown in Fig. 2.20(c).

Fig. 2.20 (b) Voltage source converter three-level phase module (12-pulse mode)

Fig. 2.20 (c) Pulse width modulation (PWM) pattern and the fundamental frequency voltage in a voltage source converter (VSC)—one phase

Advantages of IGBT-based Voltage Source Converters The replacement of thyristors by IGBTs permits self-commutation of the converter with the following advantages: The commutation does not fail when system voltage is decreased or distorted. The low-order harmonics are greatly reduced and therefore the harmonic filters can be small. No local reactive-power supply is required, even when it is used with low short-circuit level power systems. The active power supplied through the DC line and the reactive-power output from each terminal are independently controlled. The response is faster owing to the increased switching frequency pulse width modulation (PWM) process.

HVDC Converters


Fig. 2.20 (d) Circuit arrangement of an IGBT chain module

2.6.2 Components of VSC Converter The voltage converter is a very strong capacitive network on the DC side and hence is voltage stiff. Thus, a large capacitor is needed on the DC side which in turn stabilises the voltage. This also reduces the DC voltage ripple. By increasing the switching frequencies, the size of the capacitor is reduced, and if the stations are connected by an underground cable, cable capacitance itself may serve the purpose. Hence, in addition to the usual components used in the thyristor valve stations, VSC stations will have the following components:

(a) DC Capacitor On the DC side of the converter, one or two capacitors in series with centre point grounded is connected across the converter to maintain constant voltage (see Fig 1.15, Chapter 1). The capacitors are dry and may be few microfarads. In case a long DC cable is connected, no separate capacitor will be needed. A disadvantage of the capacitor is that it contributes for a large fault current when a pole-toground or pole-to-pole fault occurs.

(b) Coupling Reactor (Inductor) A coupling reactor (Inductor) on the AC side, between the transformer and converter terminals, is needed (i) to reduce the fault current, stabilise the AC current from the source, and reduce the harmonic current


HVDC Transmission

(ii) to enable the control of active and reactive power from the VSC. The inductors are designed for high frequency and high voltage stresses. (iii) in inverter operation mode with pulse width modulator (PWM), the converter generates higher harmonics related to switching frequency. The harmonics are blocked by the inductor.

(c) High Voltage Valve Due to limited voltage rating of individual switching devices (IGBTs 5kV), a series connected high voltage valve with voltage balance across each component, and a parallel connection for increased current rating, is essential for valve reliability. The difference in turn-on and turn-off times of individual devices in series chain and leakage current difference of the component, causes voltage unbalance among individual members under transient and steady state operation. Hence, to get voltage sharing properly, snubber circuits are placed in parallel or an active gate control is used during switching. Such an arrangement is shown in Fig. 2.20(d). The gate electronics control the gate voltage turn on and off process. All the IGBTs must be turned on and off at exactly the same moment to achieve even distribution of voltage across the valve under transient condition.

(d) Anti-parallel Diodes The diode connected across the converter elements in VSC constitutes an uncontrolled bridge rectifier. Hence, the diodes conduct and stresses are produced under short circuit conditions when the DC short circuit fault current flows through them. The fault current is cleared only by the ‘CB’ on the AC side, which takes few cycles of time. The overcurrent is limited by external components. This feature and these components do not occur in thyristor valves. (e) High Frequency Filters In voltage source converters, the high switching frequency for valve switching generates high frequency (HF noise) in audio range and is significantly higher than that generated for the conventional thyristor converters. To prevent this noise from entering into power grids, shielding of the valve housing, ensuring proper HF grounding, and if further needed, HF filters are used.



Schematic diagram of a 3-phase 6-pulse converter scheme is shown in Fig. 2.21(a) and its equivalent circuit arrangement in 2.21(b). This circuit arrangement is known as the Graetz circuit and uses six thyristor valves. Each valve consists of a number of thyristors modules put in series (Ref. Fig. 1.5) for the required output voltages. Usually, the input voltage to the bridge is derived through a converter transformer, either a 3-phase Y/D connected unit or 3 single-phase transformers connected in Y/D or Y/Y. In case of a Y/Y connection, a 3rd winding is also used for circulating currents of 3rd and 3n harmonics. The converter is triggered by gate triggering circuitry. If the Fig. 2.21 (a) 6-pulse Graetz’s bridge firing or triggering angle a is less than 90°, the converter converter operates as a rectifier; and if a > 90°, negative voltage is generated, which means the converter becomes an inverter as pointed out in Section 3.5.2. Inverter action cannot be obtained for isolated loads and it has to be connected to an external AC system for power flow

HVDC Converters

Fig. 2.21


(b) 6-pulse bridge converter equivalent circuit

from rectifier to inverter. The valve module, valve layer and typical thyristor with control unit is shown in Fig. 2.22.

Fig. 2.22


Thyristor valves


The circuit diagram of a 12-pulse bridge converter is shown in Fig. 2.23. It consists of two 6-pulse converters which are connected in series. The input voltage to these two converters is derived from two Y/Y, Y/D connected transformers. There is a phase difference of 60° between the voltages on the secondary side. This results in a phase difference of 30° between the voltages driving the SCRs in a sequential manner. The resultant output voltage (DC) is the sum of the individual converter output voltages. Since each converter gives a 6-pulse output, the resultant voltage is a 12-pulse output. By virtue of series connection of the


HVDC Transmission

Fig. 2.23 Cascade of two 3-phase bridge rectifiers—12-pulse bridge converter

converters, the same load current flows through the converters. The primary of the supply transformer may be star connected or delta connected. If we assume constant load current with negligible ripple and source impedance, the distortion factor of the line current does not change, as the firing angle a is varied, since the wave shape remains unchanged but shifts in phase. The displacement angle or fundamental power factor angle does vary as the firing angle is varied. Hence, the power factor deteriorates as a approaches 90°, since the firing angle is the same as the fundamental phase angle for a fully controlled converter with a constant load current. Quadruple valves are used as converters and are shown in Fig. 2.24.

(a) Mercury arc valve Fig. 2.24

(b) Thyristor valve

Typical valves used in HVDC transmission

*Source: Wikipedia, the free source encyclopedia, 2009 (Minitoba Hydro, Canada).

HVDC Converters


REFERENCES 1. Arillaga J., High Voltage Direct Current Transmission, (London) Peter Peregrinus, 1983. 2. Harraway L., Electrical Power Systems, Chapter 7, (London) Peter Peregrinus, 1985. 3. Singh M.D. and Khanchandani K.B., Power Electronics, (New Delhi) Tata McGraw Hill Education, 2007. 4. Padiyar K.R., HVDC Power Transmission Systems, Wiley Eastern Ltd, 1992. 5. HVDC Light Converter Development, ABB Power Systems. http://www.abb.com.in. 6. HVDC Technical Background Sea Breeze Olympic Converter LP., (Stak-pack HVDC modules), Web source. 7. Asplund et al., DC Transmission based on Voltage Source Converters, (France) Cigre Conference, Paris, 1998. 8. Asplund et al., DC Transmission based on Voltage Source Converters, Cigre SC 14 Colloquium on HVDC and Facts, (South Africa), 1997. 9. CuiQing Du., The Control of VSC-HVDC and Its Use for Large Industrial Drives, (Sweden) Chalmers University of Technology, Götenberg, 2003. 10. Wenakijillan, Modular back-to-back HVDC Converter with Capacitor Commuted Converters, Suceava Conference, Cigre, 2001. 11. Schattler F. and Huang H., HVDC Transmission System Using Voltage Source Converters Design and Applications, IEEE Power Engg. Society, Summer Meeting, 2000. 12. Siemens’ VSC Technology Power Transmission and Distribution EVH2 01 98 Powerlink Universal System, Siemens, Web source. 13. Gunner Asplund, DC Transmission based on Voltage Source Converters, Cigre, 1998.

WORKED EXAMPLES 2.1 If Vg Ig characteristic of an SCR is assumed to be a straight line passing through the origin, with a gradient of 3 ¥ 10+3. Calculate the required gate source resistance, given that Eg = 10 V and allowable gate power dissipation is (Pg) 0.012 W. Solution: The gate voltage and gate current relation is Vg = Eg

Rg Ig

where Vg is the gate voltage and Rg is the gate resistance. Given Vg = 3 ¥ 103 Ig, Pg = Vg Ig = 0.012 W Eliminating Vg, 3 ¥ 103 Ig ¥ Ig = 0.012 Ig2 = 0.012/3 ¥ 103 Ig = 2 ¥ 10 3 A Vg = 3 ¥ 103 ¥ 2 ¥ 10 3 = 6 V Eg - Vg 10 - 6 = = 2 kW Rg = Ig 2 ¥ 10-3


HVDC Transmission

QUESTIONS 1. Why are thyristors (SCRs) used as converter elements in HVDC valves? Explain. 2. What are the advantages of using IGBTs over SCRs for HVDC converters? 3. Explain how SCRs are connected in series and parallel arrangements for a desired voltage and current. How is triggering of SCRs achieved? 4. Explain the typical valve arrangements in HVDC converters using thyristors? How is (i) triggering, (ii) protection, and (iii) voltage equalisation during switching achieved? 5. Give the typical valve arrangement with IGBTs. How is the turn-on and turn-off function achieved? 6. Give the triggering, protection scheme and voltage equalisation schemes for IGBT valves. 7. How are 6-pulse/12-pulse arrangements achieved in case of (i) thyristor valves and (ii) IGBT valves? 8. Explain the turn-on/turn-off mechanism with series connected IGBTs. Give the typical on/off voltage and current waveforms.

MULTIPLE CHOICE QUESTIONS 1. A thyristor valve conducts when (a) anode is positive (b) anode is negative (c) anode is positive with positive gate pulse (d) anode is positive with negative gate pulse 2. A thyristor valve is fabricated using (a) SCRs connected in series (all) (b) SCRs connected in parallel (all) (c) SCRs connected in series and parallel as modules (a) all of the above 3. 12-pulse converters are used in modern converters because of (a) reduced current (b) reduced ripple (c) increased voltage and reduced harmonics (d) both (b) and (c) 4. In 12-pulse connections, transformers are connected (a) Delta/Delta (both) (b) Star/Star (both) (c) Star/Delta (both) (d) One Star/Star and other Star/Delta 5. IGBT converters operate on the principle of (a) voltage source converter (b) current source converter (c) power source converter (d) either (a) or (b) 6. IGBT requires (a) large current for triggering (b) large voltage pulse for triggering (c) sine wave voltage for triggering (d) any one (a), (b) or (c) 7. Compared to SCRs, IGBT have (a) more turn-on, turn-off time (b) less turn-on, turn-off time (c) both have some characteristics (d) turn-on, turn-off times can be more or less depending on the circuit

HVDC Converters

8. A pack in an IGBT valve comprises (a) triggering gate pulse circuit (b) parallel connect IGBTs (c) series and parallel connected IGBTs with projection (d) none of the above 9. Coolant used in thyristor/IGBT valves is (a) Air (b) SF6 (c) Freon (d) Oxygen 10. A 12-pulse converter consists of (a) two 6-pulse converters in series (b) two 6-pulse converters in parallel (c) (a) or (b) (d) (a) and (b)

ANSWERS 1. (c) 9. (a)

2. (c) 10. (a)

3. (d)

4. (d)

5. (a)

6. (b)

7. (b)

8. (c)


6-pulse Converter Operation and Analysis 3.1


In the previous chapter, a discussion on the type of DC converters used in HV transmission system had been presented; including different circuit configurations such as 6-pulse and 12-pulse converters. Thyristor valve bridges are basically voltage controlled (constant current) rectifiers and their output is varied by varying the firing angle of the converter (a variation). As a varies, the waveforms of voltage and current change drastically and by incorporating suitable filters, DC voltage with certain amount of ripple is obtained. In this chapter, operation and analysis of 6-pulse and 12-pulse thyristor (SCR) converters is presented. The configuration and operation of a 3-phase fully controlled 6-pulse bridge converter (Graetz’s circuit) is described in this section. The converter has two types of circuits. The main circuit comprises converter transformers, thyristors valves, bus bars and series reactor and DC load. High power flows through this circuit. The second is a control and protection circuit which is a low power circuit. It is used for firing the valves in the desired sequence, monitoring, etc. Each thyristor valve consists of several thyristors connected in seriesparallel combination to meet system voltage and current requirements.



All modern HVDC systems use either 6-pulse or 12-pulse converters. The 3-phase bridge shown in Fig. 3.1 is the only configuration used in HVDC transmission. The bridge configuration provides better utilisation of converter transformer and a lower peak inverse voltage across the converter valves when compared with other possible alternatives. In Fig. 3.1 conducting valves are indicated by thick lines. The bridge indicates that two valves are connected to each phase (for example, 1, 4 with phase R). In the upper part of the bridge, the anodes of the valves 1, 3, 5 are connected to the phase R, Y, B respectively. Similarly in the lower half of the bridge, the cathodes of valves 4, 6, 2 are connected to the phases R, Y, B respectively. The figure indicates that at any time two valves will be conducting in series (6, 1; 1, 2; 2, 3; 3, 4; 4, 5; 5, 6) simultaneously when the source inductance of

6-pulse Converter Operation and Analysis


the transformer is neglected. This is not considered a drawback in high voltage applications, particularly with solid state converter, because it is necessary to connect many thyristor units in series to withstand the voltage levels being used.

Fig. 3.1 Sequence of conduction of valve of 3-phase fully controlled 6-pulse bridge converter (Graetz’s circuit)


HVDC Transmission



Before we understand the operation of a bridge converter it is assumed that the bridge is connected to an infinite bus of zero source impedance. This eliminates any overlap in the conduction of the valves and simplifies the operation. With zero source impedance, the transfer of current (commutation) between the valves on the same side of the bridge takes place instantaneously. The switching sequence and rectified voltage waveforms are illustrated in Fig. 3.2(a) and (b) for an uncontrolled bridge rectifier (i.e. on diode operation) with delay angle a = 0. The valves are numbered according to the sequence of operation. Performance of the 3-phase bridge circuit or Graetz’s circuit under balanced sinusoidal 3-phase operation is considered with the following assumptions to simplify the analysis.

Fig. 3.2 Voltage and current waveforms of 6-pulse bridge converter with a = 0

6-pulse Converter Operation and Analysis


(1) The DC current is constant and ripple free. (2) The valves can be modelled as ideal switches with zero forward impedance when conducting and infinite backward impedance when not conducting. (3) Ignition of the valves is carried out in sequence at equal intervals. (4) The AC voltages at the converter bus are sinusoidal and remain constant. The operation of the converter as rectifier can be explained as follows. Considering Fig. 3.2(a), at the instant P, the phase voltage R is more positive with respective to other phases and therefore the valve 1 conducts. Similarly, phase voltage Y is more negative w.r.t other phases and therefore the valve 6 conducts. This state of operation continues up to the point Q, after which the valve 2 is forward biased since the phase voltage B becomes more negative. The anode of 2, which is directly connected to the anode of 6 becomes more positive, as it is connected to the phase B. Therefore, at the point Q, the current commutates naturally from the valve 6 to valve 2. The above discussion indicates that the anode of the valve which is driven more positive and the cathode of the valve which is driven more negative will be conducting simultaneously. Therefore, in the region PQ, the valves 1, 6 and in the region QR, the valves 1, 2 conduct. At the point R, the anode of the valve 3 connected to the phase Y will begin to be driven more positive than the anode of the valve 1 connected to the phase R, and the current commutation will take place from the valve 1 to valve 3. This will be followed by commutation of the valve 2 to valve 4 at the point S and the valve 3 to valve 5 at the point T. Similarly, commutation of the valve 4 to valve 6 at U, and the valve 5 to valve 1 at V takes place. This completes the switching cycle sequence. In the region RS, the valves 2, 3 conduct; and in the region ST, the valves 3, 4 conduct; and so on. The order and the pair of valves conducting at different periods are also indicated in the figure. Further analysing the converters, conduction occurs during the period when anode is positive with respect to the cathode, and line-to-line voltage is applied between two mid-points of the series connected valves 1, 4 or 3, 6 or 5, 2. The voltage at any instant is assumed as Vo (t ) = 3Vm cos w t , where Vm is the peak value of the phase voltage with zero reference to the y-axis passing through the peak of Vo(t).



The output waveform given in Fig. 3.2(a) indicates voltage variation of the positive (common cathode) and negative (common anode) poles with respect to the transformer neutral (n) on the secondary side. Figure 3.2(b) shows the output voltage Vo(t) between the positive and negative poles, which is indicated by thick lines. The output voltage Vo(t) contains ripples of harmonic frequency, which is six times that of the main frequency because the Vo(t) contains six pulses in the cycle of the main voltage. When the valves 1, 2 conduct, the output voltage is VRB, i.e. line-to-line voltages of the phases R and B (neglecting the drop across the valves). Similarly, UYB is the voltage on the output side when the valves 2, 3 conduct. It can be deduced from Fig. 3.2(b) that the output voltage is the combination of line-to-line voltages. The no-load DC output voltage across the load without phase control is the average of Vo(t) and is given by p /6

Vdo =

p /6

1 3 Vo (t ) d (w t ) = 3Vm cos w t d (w t ) Ú p / 3 -p / 6 p -pÚ/ 6


where Vo(t) = VRB(t) in the region QR when 1, 2 conduct. By considering X–X as y-axis and x as origin in Fig. 3.2(b), when VRB is passing through maximum value, Vo(t) can be represented as


HVDC Transmission

Vo (t ) = 3Vm cos w t , as stated earlier where Vm = Peak voltage between phase and neutral on the secondary side of the converter transformer 3Vm = Peak voltage between any two phases (lines) on the secondary (valve) side of the converter transformer Vdo =

3 3Vm 3 3Vm [sin w t ]+-pp // 66 = p p


If VsL rms is the voltage the on the secondary side between two phases of the converter transformer, then 3Vm = Vdo = 1.35 VsL =

2VsL 2VsL ¥

3 p

3 3Vm p

(3.3) (3.4)

The phase current IR is also shown in Fig. 3.2(c). When the valve 1 conducts, the current in the phase R enters into the bridge circuit through the valve V1, Ld, RL and back to the point n as shown in Figs. 3.1(a) and (b). This current is treated as positive and IR = Id. But when the valve 4 conducts, the current in the phase R of the secondary is reversed as shown in Fig. 3.2(c) and flows from the bridge into the secondary windings of the phase R and is therefore reckoned as negative. The phase current remains constant and is equal to Id because of large inductance Ld. The valve currents I1, I3, I5 are also shown in Fig. 3.2(d). The valve voltage drop is shown in Fig. 3.2(e). During the period when V1 conducts, the voltage across the valve 1 is zero in the interval C1C3. When V1 is not conducting in the period RT, the line voltage VRY appears across V1 due to conduction of the valve 3. Similarly in the period TV, line voltage URB appears across V1 due to conduction of the valve 5. The valve voltage in the conducting and nonconducting periods is indicated in thick lines in the interval PV. Maximum voltage across the valve is the maximum of VRY (maximum of lineto-line voltage) and is equal to 3Vm .

3.4.1 Peak Inverse Voltage (PIV) The peak inverse voltage is the maximum voltage that appears across the valve when the valve is not conducting. From the valve voltage waveforms the PIV is the maximum line-to-line voltage across any two phases (maximum of VRY or VRB). Therefore, the peak inverse voltage is PIV =

3Vm = 2VsL


Peak inverse voltage in terms of DC voltage is p 3 = 1.047 Vdo

= Vdo ¥


6-pulse Converter Operation and Analysis


3.4.2 Peak-to-Peak Ripple Voltage (PPR) Peak-to-peak ripple voltage is the difference in the voltage at wt = 0 and wt = p/6; by taking X reference axis (w t = 0).

X as the

ÎÈVo (t )wt =0 - Vo (t )wt =p / 6 ˚˘ = ÎÈVRBwt =0 - VRBwt =p /6 ˚˘ PPR = 3Vm (cos 0 - cos p /6) = 3Vm (1 - 0.866) = 0.134 ¥ 3 Vm = 0.134 ¥ 1.047 Vdo = 0.1403 Vdo


3.4.3 Valve Current Relations The load current in any one phase is carried by two valves in series. One from the upper-half bridge (valves 1, 3, 5) and the other from the lower-half bridge (valves 2, 4, 6). From Figs. 3.2(c) and (d), each valve conducts during two-third of a half cycle. Assuming that valve current is a rectangular pulse of value Id and lasts for a duration of 2p/3 and considering the first cycle of the voltage of the phase R: 0 £ wt £ p/6 p/6 £ wt £ 5p/6 5p/6 £ wt £ p p £ wt £ 2 p

The value current i1 = 0 = Id =0 =0 The average valve current I av1 =

1 2p

1 = 2p I I av1 = d 3


Ú i1 d (w t ) 0

2p È ˘ ÍÎ0 ¥ p 6 + I d ¥ 3 + 0 ¥ p 6˙˚ (3.8)

The rms current through the valve 1 is 2 I rms =

1 2p



Ú i12dq = 2p (0 ¥ p 0

6 + I d2 ¥

2p + 0 ¥ p 6) 3

I2 = d 3 This can be verified since the current lasts for 1/3 of the time and the square of the average cut is I 2d /3 I rms =

Id 3



HVDC Transmission

3.4.4 Transformer Current on the Secondary Side The current in each phase of the secondary winding of a star connected transformer is shown in Fig. 3.2(c). The current in the phase R is positive when the valve 1 conducts and is given by 0< wt < p/6 p/6 £ wt £ 5p/6 5 p/6 £ wt £ p

iR(t) = 0 = Id =0

and the phase current iR is negative, when V4 conducts and is given by p £ wt £ 7 p/6 7p/6 £ wt £ 11 p/6 11p/6 £ wt £ 2p

iR(t) = 0 = –Id =0

The rms value of the phase current iR is I R2 rms = I R2 rms =

1 2p 1 2p =


Ú iR2 (w t ) 0

2p 2p È ˘ 2 2 Íp 6 ¥ 0 + I d ¥ 3 + p 6 ¥ 0 + p 6 ¥ 0 + I d ¥ 3 + p 6 ¥ 0˙ Î ˚

I d2 2p

I R (rms) = I s =


4p 2 2 = Id 3 3 2 I 3 d


where Is is the rms current on the secondary (valve) side of the converter transformer.

3.4.5 Transformer Volt-Ampere Rating The conventional volt-ampere rating T of a 3-phase converter transformer feeding secondary current Is at line-to-line secondary voltage VsL to a six-pulse bridge converter is given by T = 3VsL ¥ I s ¥ 10-3 kVA But we know Vsl = Is =

p 3 2

Vdo from (3.3)

2 I from (3.10) 3 d

Substituting the values for VsL and Is in (3.11)


6-pulse Converter Operation and Analysis

T= 3¥ =

p 3 2

Vdo ¥


2 I ¥ 10-3 kVA 3 d

p V I ¥ 10-3 kVA 3 do d

The transformer kVA rating of a 3-phase bridge converter is T = 1.047 Vdo Id ¥ 10 3 kVA where


Vdo = No-load DC output voltage of a 6-pulse converter with zero phase control (a = 0) Id = DC output current of a 6-pulse converter

If Pd is the direct power output of a 6-pulse converter with zero phase control, then Pd = Vdo Id The transformer kVA rating in terms of Pd is T = 1.047 Pd ¥ 10



3.4.6 Volt-Ampere Rating of Valve The volt-ampere rating of each valve is the product of the average current through the valve and the peak inverse voltage of the valve, and is given by Id ¥ 1.047 Vdo = 0.349 Vdo I d 3 I Volt-ampere rating of all the valves = 6 ¥ d ¥ 1.047 Vdo = 2.094 Pd 3 =




In the previous section, natural commutation of SCRs without gate control has been described. In this process, the transfer of current between the valves takes place at the instant of crossing of phase voltage (C1, C2, C3, C4, C5, C6, etc., as shown in Fig. 3.3). By delaying the firing instants of the valves with respect to the voltage crossings, natural commutation can be delayed by a definite time interval a and the process is known as phase control. a is called the firing angle, as indicated in Fig. 3.3(a). The effect of phase control on DC voltage waveforms is illustrated in Figs. 3.3(a) and (b), where a = 30°. It should be noted, that the voltage area under the curve shown in Fig. 3.3(b) decreases with increase in the firing angle a and therefore the mean direct voltage also decreases with increase in a.


HVDC Transmission

Fig. 3.3 Voltage and current waveforms of 6-pulse bridge converter with a = 30°

3.5.1 DC Output Voltage with Phase Control As shown in Fig. 3.3(b), the output voltage Vo(t) is the combination of line-to-line voltages. The DC output voltage, which is the average of Vo(t) is given by p +a

1 6 Vd = V (t )d (w t ) p / 3 -pÚ o 6


6-pulse Converter Operation and Analysis


+p +a 6



3Vm cos w t d (w t )

- p +a 6

3 È Êp ˆ Êp ˆ˘ 3Vm Ísin Á + a ˜ + sin Á - a ˜ ˙ Ë ¯ Ë ¯˚ p 6 6 Î 3 p È ˘ = 3Vm Í2sin cos a ˙ p 6 Î ˚ 3 3Vm 3 2VsL = cos a = cos a p p Vd = Vdo cos a =


where Vd is the no-load DC voltage of 6-pulse unit with delay angle a and Vdo is the no-load direct voltage without phase control (a = 0). The mean DC voltage with phase control can also be obtained as explained in Section 3.3 and is given by the expression

Vd =


1 p /3

3 p

3p +a 6


(VR - VY ) d (w t )

p +a 6

3p +a 6


p +a 6

3Vm cos (w t - p /6) d (w t ) =

3 3Vm cos a p

(3.16) (see footnote)

The controlled direct voltage at the output side is maximum when a = 0 and decreases with increase in the p p firing angle a and becomes zero at a = . The mean DC voltage becomes negative when a > . In Figs. 2 2 3.3(c) and (d), the phase current IR and the voltage across the valve V1 are shown. The phase current IR is shifted by an angle a with respect to the phase current IR as shown in Fig. 3.2(c) without phase control. The valve V1 conducts during the period PR and does not conduct during the period RV. The valve V4 conducts during the period SU. The valve voltage Vv1 as shown in Fig. 3.3(d) is zero during the conducting period PR of the valve V1 and the nonconducting period RV and it is characterised by line-to-line voltages VRY and VRB in the periods RT and TV respectively. Footnote: Phase voltages are taken as VnR = Vm sin w t. VnY = Vm sin (w t - 120∞). VnB = Vm sin (w t + 120∞). Line-to-line voltage = VRY = VR – VY pˆ 3 Ê VRY = Vm (sin[(w t – 120°)) = 2Vm cos (wt – 60°) sin (60°)] = 2Vm cos Á w t - ˜ ¥ Ë 3¯ 2 pˆ Ê 3 Vm cos Á w t - ˜ . Ë 3¯


HVDC Transmission

For delay angles above 60°, some negative voltage periods begin to appear. If the output of the bridge were connected to a pure resistance, the bridge’s unidirectional current conduction property would not prevent reverse current flow during these negative voltage periods, and the operation would then be intermittent with no continuous current flow. However, with the provision of the large smoothing reactor (Ld), a positive current flow during the negative periods is maintained, and energy is transferred from reactor magnetic field to the AC system. The voltage waveforms for delay angle a = 90° are illustrated in Figs. 3.4(a) and (b). P, Q, R, S, T are the instants when the valves 1, 2, 3, 4, 5, 6 are fired. The valve 1 conducts during the period PR and the valve 2 conducts during RF, and so on. The output DC voltage Vo(t) contains equal positive and

Fig. 3.4 Voltage and current waveforms of 6-pulse bridge converter with a = 90°

6-pulse Converter Operation and Analysis


negative regions (indicated by the shaded areas) and the mean direct voltage Vd is zero. The phase current IR and valve voltage drops Vv1 are also shown in Figs. 3.4(c) and (d) respectively.

3.5.2 Inverter Operation For firing angles ‘a’ greater than 90°, output voltage waveforms, phase current IR and valve voltage drops are illustrated in Fig. 3.5. The bridge operation can only be maintained in the presence of a DC power supply in place of the DC load. This supply must be connected such that positive polarity to the common anodes and negative polarity to the common cathodes so that it overcomes negative voltage and forces the current to

Fig. 3.5 Voltage and current waveforms of 6-pulse bridge converter with a = 120°


HVDC Transmission

conduct in the same direction in opposition to the induced emf in the converter transformer. This suggests that power is being supplied from the DC to the AC system. The converter is operating as an inverter. In Fig. 3.5, P1, P2, P3, etc., correspond to the instant when valves 1, 2, 3, etc., are fired. S1, S2, S3 are the instant when valves 1, 2, 3, etc., stop conduction respectively. In the rectifier operation, valves 1, 3, 5 will conduct when their anodes are driven more positive and valves 4, 6, 2 will conduct when their anodes are driven more negative. However, in the inverter operation, valves 1, 3, 5 will conduct when their cathodes are driven more negative and valves 4, 6, 2 will conduct when their anodes are driven more positive with respect to others in the same group. Figures 3.6(a) and (b) illustrate the voltage waveforms on full inversion with a = 180°.

Fig. 3.6 Voltage and current waveforms of 6-pulse bridge converter with a = 180°

6-pulse Converter Operation and Analysis


The conduction period of valves 1, 3, 5 is shifted by 180° when compared to the voltage waveforms shown in Fig. 3.2. Valve voltage drop Vv1 is positive on full version and is negative with zero phase control. Three conditions required for power flow from the DC side to an AC source during inversion are (1) An active AC voltage source which provides commutating voltage waveforms (2) Provision of firing angle control to delay commutations beyond a = 90° (3) A DC power supply in place of the DC load, as indicated in the Fig. 3.7(a)

Fig. 3.7 (a) 6-pulse bridge connection—inverter operation



As discussed in the previous section, in practice, an AC source with source impedance, which can produce voltage and current waveforms as discussed in the previous section does not exist. Even if the AC system impedance were negligible, there is considerable transformer leakage reactance between the converter and the AC system. However, converter transformers are used for controlling DC power by on-load tap-changing. The main effect of AC system reactance is to reduce the rate of current which increases commutation time. During commutation, the magnetic energy stored in the reactance of the previously conducting phase has to be transferred to the reactance of the incoming phase. The energy in the reactance depends upon the direct current level and inductance per phase. The speed of the commutation process is also affected by the supply voltage and delay in firing angle (a). Before analysing the commutation process, it is essential to know the terms ‘commutating voltage’ and ‘commutation reactance’.

3.6.1 Commutating Voltage Commutating voltage can be defined as the voltage appearing on the DC line during periods when no commutation is taking place. In this operating region, only direct current flows through the AC system impedance and therefore, the voltage waveform is sinusoidal. Commutating voltage is responsible for circulating commutating current when the two valves of the same row (1, 3, 5, etc.) are conducting simultaneously. Before commutation, this voltage appears across the valve which is to be fired. Commutating voltage is that which


HVDC Transmission

appears between successive phases, i.e. the phase to which the conducting valve is connected and the phase to which the next valve is to be fired in a specific order. In practice, however, phase shifting and filtering are provided with every HVDC converter station and the voltage waveform at the filter bus-bar is reasonably sinusoidal under steady and normal operating conditions. Such voltage can therefore be used as commutating voltage.

3.6.2 Commutation Reactance Commutation reactance can be defined as the reactance between the AC bus and the converter valves as shown in Fig. 3.8.

3.6.3 Rectifier Operation with Overlap Angle (m) In this section, the effect of source reactance on the commutation of 6-pulse fully controlled converter is discussed. The source reactance introduces overlap of currents due to simultaneous conduction of SCRs to be commutated during the commutation period m. The schematic diagram of a 6-pulse bridge converter with source reactance is shown in Fig. 3.8. The effect of source reactance on the output voltage and current waveforms is shown in Fig. 3.9 with delay angle a and overlap angle m. During the commutation period, a pair of commutating valves V1, V3; V3, V5; V5, V1 conduct together in the positive group of the converter and V2, V4; V4, V6; V6, V2 conduct simultaneously in the negative group. In Fig. 3.9, P indicates the firing instant. For example P1, is the firing instant of the valve 1. S indicates the end of a commutation and at S5 the valve 5 stops conducting. C indicates the instant of crossing of phase voltages. C1 indicates positive crossing of B and R phases. At the instant P1, when the valve V1 is fired, current in the valve 1 slowly increases and current in the valve 5 slowly decreases because of inductance of the source. Valves 1 and 5 will be conducting simultaneously in the positive group in addition to the valve 6 in the negative group. During the commutation process, voltage of the cathode w.r.t. the transformer neutral is the average of the corresponding phase voltages of the conducting valves, i.e. (VnR + VnB)/2, which is shown in the dotted line (P1S5). Figure 3.9(a) illustrates positive potentials of the cathode (1, 3, 5) and negative potentials of the anodes (2, 4, 6) with respect to the transformer neutral. Figure 3.9(b) shows the direct voltage (Vo(t)) output waveform, which is a combination of the corresponding line-to-line voltages appearing on the output side of the bridge. The mean direct voltage is the average of Vo(t).

Fig. 3.8 Schematic diagram of a 6-pulse bridge converter

6-pulse Converter Operation and Analysis


Fig. 3.9 6-pulse bridge converter with overlap

The potential across valve 1 is shown in Fig. 3.9(b). When valve 1 completes a commutation to valve 3 at S1, the voltage across it follows the line-to-line voltage (VRY) between the red and yellow phases from S1, until P4 is reached. Between P4 and S2, the commutation from valve 2 to valve 4 (see Fig. 3.9(a)) reduces the negative potential of R phase and causes the first voltage dent in the valve voltage by following the average voltage -3 curve of (VnB + VnR ) 2 - Vr = Vy . 2 The firing of valve 5 at P5 increases the potential of the common cathode to the average voltage of phases Y and B. This causes a second commutation dent, at the end of which (at S3) the common cathode follows the potential of B due to conduction of valve 5 and voltage across the valve 1 will follow VRB. Finally commutation from valve 4 to valve 6 (P6 to S4) increases the negative potential of the anode of valve 1 and produces another voltage dent. Figure 3.9(c) indicates the AC line current in phase R. Figures 3.9(d) and (e) give valve currents from 1 to 6.


HVDC Transmission

For obtaining steady state equations, it is presumed that only two or three valves conduct simultaneously in addition to the number of approximations stated earlier.

3.6.4 Analysis of the Commutating Circuits Considering the commutation process between valves 5 and 1 of the bridge converter, the source (commutation) reactance per phase is taken as wLS with negligible resistance. The equivalent circuit of the commutation process is shown in Fig. 3.10(a). Commutation from the valve 5 to the valve 1 starts at P1 and ends at S5.

Fig. 3.10

Commutation process in a 6-pulse bridge converter

6-pulse Converter Operation and Analysis


Let VnB and VnR be the phase voltages of the blue and red phases w.r.t. to the neutral of the secondary of the transformer, and are expressed as ¸ Ô Ô = Vy = Vm sin (w t - 120∞) ˝ Ô = VB = Vm sin (w t + 120∞) Ô˛

VnR = VR = Vm sin w t VnY VnB


Êp ˆ Êp ˆ VR - VY = 3Vm cos (w t - p 3) in the period Á + a ˜ £ w t < Á + a + m ˜ Ë6 ¯ Ë6 ¯ VnR - VnB 2




pˆ Ê Êp ˆ Êp ˆ cos Á w t - 2 ˜ when Á + a ˜ £ w t < Á + a + m ˜ Ë Ë6 ¯ Ë6 ¯ 3¯

During the commutation period, the load voltage Vo(t) is the average of the two conducting phases p Ê VnR + VnB ˆ - VnY . From Fig. 3.10(b) it is understood that when w t ≥ , the voltage VnR is greater than VnB ÁË ˜ ¯ 6 2 so the current in the valve 1 (i1) increases and the current in the valve 5 decreases, such that at all times in the Êp ˆ Êp ˆ period Á + a ˜ £ w t £ Á + a + m ˜ Ë6 ¯ Ë6 ¯ i1 + i5 = Id


From the waveforms given in Fig. 3.10(b), the average load voltage is less than the value given by the È DV ˘ expression (3.15) without overlap by an amount Í p ˙ , where DV is the area hatched between the curves VnR ÍÎ 3 ˙˚ Ê V + VB ˆ Êp ˆ Êp ˆ and Á R in the interval Á + a ˜ £ w t £ Á + a + m ˜ as indicated in the Fig. 3.10(b ). Ë Ë6 ¯ Ë6 ¯ 2 ˜¯ The average DC voltage Vd is given by È 3p + a + m ˘ ˙ 1 Í6 Vd = Í Ú (VR - VY ) dq - DV ˙ p /3 Í p ˙ +a ÎÍ 6 ˚˙


where DV is given by the area Êp ˆ ÁË + a + m ˜¯ 6

DV =


Êp ˆ ÁË + a ˜¯ 6

È Ê VR + VB ˆ ˘ ÍVR - ÁË ˙ dq = 2 ˜¯ ˚ Î

Êp ˆ ÁË + a + m ˜¯ 6


Êp ˆ ÁË + a ˜¯ 6

Ê VR - VB ˆ dq ÁË 2 ˜¯


HVDC Transmission


3 V 2 m

Êp ˆ ÁË +a + m ˜¯ 6


Êp ˆ ÁË +a ˜¯ 6

2p ˆ 3 Ê dq = V [cos a - cos (a + m ) ] cos Á w t ˜ Ë 3¯ 2 m


From the expression (2.23) Ê 3p ˆ +a ˜ ËÁ 6 ¯


Ê 3p ˆ +a ˜ ËÁ 6 ¯

(VR - VY ) dq =

Êp ˆ ÁË +a ˜¯ 6


3Vm cos (w t - 60) = 3Vm cos a

Êp ˆ ÁË +a ˜¯ 6

Substituting these values in the expression (3.18)

Vd =

˘ 3Vm 3È {cos a - cos (a + m )}˙ Í 3Vm cos a p ÎÍ 2 ˚˙

Vd =

3 3Vm V [cos a + cos (a + m )]= 2do [cos a + cos (a + m )] 2p


During commutation of valves 5 and 1, phases B and R are short circuited through the conducting valves 1 and 5, resulting circulating current is(t). The corresponding circuit equation is 2 Ls

dis = (VR - VB ) = 3Vm cos (w t - 2p /3) dt

is = I d


d (is ) =

is = 0

3Vm 2w Ls

p +a + m 6


cos (w t -

p +a 6

2p ) d (w t ) 3


The circuit conditions are p +a 6 p is = i1 = id at wt = + a + m 6 3Vm Id = [cos a - cos (a + m )] 2w Ls is = i1 = 0 at wt =

Eliminating cos (a + m) from the expression (3.20) Vd =

3 3Vm È 2I w L ˘ Í2 cos a - d s ˙ 2p ÎÍ 3Vm ˚˙


6-pulse Converter Operation and Analysis


3 3Vm p

[cos a ] -

Vd = Vdo cos a -

I d 3w Ls p

3w Ls I d



3w Ls I d ˘ È Vd = ÍVdo cos (a + m ) + p ˙˚ Î




The expression (3.22) can be expressed as Vd = [Vdo cos a – Rc1 Id] where


3 3Vm = No-load DC voltage with a = 0 p 3w Ls Rc = = Equivalent resistance of the rectifier with overlap p

Vdo = 1

3.6.5 Equivalent Circuit of the Rectifier Equation 3.24 suggests that the rectifier can be represented by a DC equivalent circuit as shown in Fig. 3.11.

3.6.6 AC Current on the Secondary Side of the Transformer The rms value of the rectangular current waveform as shown in Fig. 3.9(c) is often used to define converter transformer MVA and is given by the expression (3.10) as IR(rms) = I d

2 = 0.816 I d 3


Fig. 3.11 Equivalent circuit of the rectifier with overlap

With the use of harmonic filters at converter terminals, the current flowing in the AC system contains only fundamental component and its rms magnitude (from Fourier analysis of current waveform IR). I1 = I d

6 p


Using the equations 3.21(a) and 3.21(b) instantaneous commutating is(t) can be expressed as =

3Vm È Êp ˆ˘ cos a - cos Á - w t ˜ ˙ Í Ë ¯˚ 2w Ls Î 6

È Êp ˆ˘ Ícos a - cos ÁË 6 - w t ˜¯ ˙ Î ˚ for Ê p + a ˆ < w t < Ê p + a + m ˆ is (t) = I d ÁË ˜¯ ÁË ˜¯ + cos a cos ( a m ) 6 6 { }



HVDC Transmission

2p ˆ Êp ˆ Êp = I d for Á + a + m ˜ < w t < Á + a + ˜ Ë6 ¯ Ë6 3¯ Ï 2p ˆ ¸ Êp Ìcos a - cos ÁË - w t + ˜˝ 6 3 ¯˛ 2p ˆ Êp Ê 5p ˆ Ó for Á + a + + a + m˜ = Id - Id ˜ < w t < ÁË Ë6 ¯ 3¯ 6 {cos a - cos (a + m )}



The fundamental component of the current waveform as defined by the equations (3.26) to (3.28) is

6 I I1 = p d

È{cos 2a - cos 2 (a + m )}2 + {2 m + sin 2a - sin 2 (a + m )}2 ˘ Î ˚ 4 {cos a - cos (a + m )}


3.6.7 Inverter Operation with Overlap The conditions for inverter operation have been described in Section 3.5.2 under ideal conditions without commutation reactance. In practice, full inversion (a = 180°) cannot be achieved and the delay angle must be less than 180°. The inverter operation with overlap angle m and delay angle a > 120° is shown in Fig. 3.12. The voltage across the valve 1 and valve currents i1, i2, i3 and AC line current in the phase R are shown in Fig. 3.13. The commutation from the valve 5 to the valve 1 starts at P1 and it is possible only when the voltage of the phase R is more positive than the voltage of the phase B. Further, the commutation must not only be completed

Fig. 3.12

Inverter operation

6-pulse Converter Operation and Analysis

a = Delay angle > 120º b = Angle of advance = (p −a) = (m +g ) g = Extinction angle = (b −m) (a) Positive and negative voltages with respect to transformer neutral (b) Voltage across the valve 1 and direct bridge voltage Vo(t) (c) AC line current of the phase R (d) and (e) Valve current C1 to C6

Fig. 3.13 6-pulse inverter operation



HVDC Transmission

before C4, but some extinction angle g1 (g1 > g0) must be left for the valve 5 which has just stopped conducting to re-establish its blocking ability. This imposes a limit to the maximum angle of firing a = p (m + g0) for successful inverter operation. If this limit were exceeded, the valve 5 would pick up the current again causing commutation failure. There is a fundamental difference between rectifier and inverter operations which prevent optimal firing conditions in the later case. In the rectifier operation, the delay angle a can be chosen accurately to satisfy a particular control constraint, but the same is not possible with respect to angle g because of the uncertainty of the overlap angle m. This is because events taking place after the instant of firing are unpredictable. Therefore a minimum extinction angle g0 must have a margin of safety to cope with reasonable uncertainties. The value of g0 usually lies between 15° and 20°. An analysis of inverter operation is not different from that of rectification. But when a is more than 90°, it is more convenient to define angle of advance b such that b=p–a


The angle of extinction g for the inverter operation is defined as g =b–m


where m is the angle of overlap for the rectifier. The operating equations of the inverter are often expressed in terms of b and g. The voltage and current equations for the inverter operation can be obtained by substituting a = (p b) and m = (b g) in the expressions for the rectifier (3.20) and (3.21). Vdo [cos a + cos (a + m )] 2 V For inverter Vd = do [cos (p - b ) + cos (p - g ) ] 2

For rectifiers Vd =

- Vd = +

Vdo [cos b + cos g ] 2


Using (3.23) for the rectifier 3w Ls I d p 3w Ls I d For inverter Vd = Vdo cos (p - g ) + p Vd = Vdo cos (a + m ) +

3w Ls I d ˘ È -Vd = ÍVdo cos g p ˙˚ Î 3w Ls I d ˘ È -Vd = ÍVdo cos b + p ˙˚ Î

(3.33(a)) (3.33(b))

6-pulse Converter Operation and Analysis


The expression for direct current as rectifier is

Id =

3Vm 2 Lsw

[cos a - cos (a + m )]


and for inverter operation a = (p – b); a + m = p – g

Id =


3Vm 2 Lsw 2VsL 2w Ls

(cos g - cos b )

[cos g


- cos b ] =

VsL 2w Ls

[cos g

- cos b ]


In Table 3.1, a comparison between inverter and rectifier equations is presented. Table 3.1 Inverter


–Vd = Vdo cos b — no-load voltage - Vd =

Vdo 3w Ls I d (cos b + cos g ) or - Vd = Vdo cos g 2 p

-Vd = Vdo cos b + Id =

Vd = Vdo cos a

VsL 2w Ls

[cos g

Vd =

Vdo [cos a + cos (a + m )] 2

I d 3w Ls p

Vd = Vdo cos a -

- cos b ]

Id =

VsL 2w Ls

I d 3w Ls p

[cos a - cos (a + m )]

b Angle of advance (p – a)

a Delay angle


m Overlap angle

Extinction angle

(b – m)

3.6.8 Equivalent Circuit of the Inverter Equivalent circuit of the inverter based on the expression –Vd = Vdo cos g – –Vd = Vdo cos b +

3w Ls I d p 3w Ls I d p

(3.33(a)) and (3.33(b))

Omitting the negative sign of voltage of the inverter Vd = Vdo cos g + Rc2Id where Rc2 = The equivalent circuit of the inverter is given in Fig. 3.14.

-3w Ls p



HVDC Transmission

Fig. 3.14 Equivalent circuit of the inverter

3.6.9 Complete Equivalent Circuit of HVDC Link Combining the equivalent circuit of the rectifier and inverter, the total equivalent circuit of HVDC link is shown in Fig. 3.15.

Equivalent circuit of an HVDC link

Fig. 3.15

The expression for the direct current Id can be obtained from the figure above as Id = (Vd - Vd ) R 1

or Id =


Vdo cos a - Vdo cos b 1


Rc + R + Rc 1




Rc = Equivalent resistance of the rectifier Rc = Equivalent resistance of the Inverter R = Resistance of the transmission line 1




The DC voltage drop can be expressed in per unit values similar to AC quantities. The base impedance on AC side Zb =

Base Voltage ph VsL 3 = Base current Is

6-pulse Converter Operation and Analysis


substituting for VsL and Is in terms of DC quantities Zb = Base impedance Zb = X s in per unit =

Vdon 3 6

p 2 I dn = ¥ 3 3 6


3 Vdo -n 2 I d -n

p Vdo -n 6 I d -n


Vdo -n X s (in ohms) = Xs .p 6 I d -n Zb

Rc = Equivalent resistance of the rectifier on the DC side 1


3w Ls p

Base resistance on the DC side = Rb =


3X s p

Vdo - n


Id -n

Ê 3X ˆ p.u. reactance on the AC side = X s p.u. = 2 Á s ˜ Ë p ¯ = where Rc = 1

2 Rc



Vdo -n 6 X s = Rb p I d -n

= 2 Rc



per unit value



X s p.u. = 2 Rc (p.u.)



Rc = 1

1 X 2 s


The DC output voltage Vd = Vdo cos a – Rc1 Id Dividing both sides with Vdon Vd Vdon

= =

Vdo Vdon Vdo Vdon

cos a - Rc


cos a - Rc

= Vdo cos a -





Id Vdon Id I dn


Id Vdon


Vd = Vdo cos a - Rc I d 1

= V do cos a - 0.5 X s I d



HVDC Transmission

where Vd = Per unit voltage on the DC side Vdo = Per unit voltage on no load Rc = Per unit equivalent resistance of the converter r

I d = Per unit DC current



[Vd – Id characteristic (0 < m < 60°)] The complete characteristics of converter working as a rectifier/inverter can be obtained by modifying equations derived earlier. For a rectifier, the direct current can be expressed as



[cos a - cos (a + m )] w Xs Id = [cos a - (a + m )] = Is

Id =


where Is line-to-line maximum short circuit current =

3Vm 2Xs

The output DC voltage = Vd = Vd =

Vd Vdo





VsL 2Xs

[cos a + cos (a + m )]

[cos a + cos (a + m )] 2

We know (a + m) = p – g Expressing I d and Vd in terms of extinction angle I d = (cos a + cos g) Vd = (cos a – cos g)/2 Eliminating cos g in the above expressions, we get I d + 2Vd = 2cos a - I d + 2Vd = – 2cos g



6-pulse Converter Operation and Analysis


Rearranging the terms 1 I 2 d 1 Vd = - cos g - I d 2 Vd = cos a -

(3.44(a)) (3.44(b))

If V d and I d are plotted on the x-y plane, the expression (3.44(a)) represents a straight line, where a is constant for rectifier/inverter action as shown in Fig. 3.16. The slope of the above lines is –1/2 and the intercept on the y-axis is cos a. These are family of parallel lines for different values of a ranging from 0 –180°. Since the angle of advance b = (p a), the locus of constant a is also the locus of constant b.

Fig. 3.16 Locus of constant a for m < 60°

In a similar way, the expression (3.44(b)) can be plotted with V d on the y-axis and I d on the x-axis. It also represents a straight line with a positive slope of ½ and with an intercept of cos g on the y-axis. By varying g from 0–180° a family of parallel lines can be generated as shown in Fig. 3.17.

Fig. 3.17 Locus of constant g for m < 60°.

3.8.1 Locus of Constant m The angle of overlap = m = (b – g) We also know I d = cos a – cos(a + m)


HVDC Transmission

mˆ m Ê = 2 sin Á a + ˜ sin Ë ¯ 2 2 Id

mˆ Ê m = sin ÁË a + 2 ˜¯ 2 sin 2


From the expression (3.43) Vd = Vd m cos 2

1 m m [cos a + cos (a + m )] = cos ÊÁË a + 2 ˆ˜¯ cos 2 2

mˆ Ê = cos ÁË a + ˜¯ 2


Combining the expressions (3.45) and (3.46) as shown below g

Ê ˆ Ê ˆ Á Vd ˜ Á Id ˜ +Á Á m˜ m˜ ÁË cos ˜¯ ÁË 2 sin ˜¯ 2 2




The locus given by the equation 3.27 with V d on the y-axis and I d on the x-axis is shown in Fig. 3.18. It represents an ellipse with semi-major axis equal to 2 sin m/2 and semi-minor axis equal to cos m/2. The locus of constant a lines, the locus of constant g lines and the locus of constant m are plotted in Fig. 3.18. When a = 45° and g = 120°; the value of m = p a g = 180 120 45 = 15°. The ellipse m = 15° will pass through the intersection point between a = 45° line and g = 120° line at P. P is the operating point which determines the DC voltage V d and the DC current I d . The boundary of rectifier operation is shown by the points A, B, C, D and the point E corresponds to the maximum power output of the converter. The operating points on the boundary are tabulated in Table 3.2. Table 3.2

Boundary points of rectifier characteristic Point














0.75 3 4 0




3 2











1 2 1.0

3 2 2 0

6-pulse Converter Operation and Analysis


Fig. 3.18 Loci of constant angle m in the I d , V d plane for u < 60°

The normal range of operation of HVDC is in the 2–3 valve region. For example, in the case of a converter with x s , the normal region of operation is bound on the right-hand side of the vertical dashed line as shown in Fig. 3.19.

3.8.2 Power Factor and Reactive Power of Converters The converter current in any phase is always larger than the phase voltage, as shown in Fig. 3.20, due to firing angle delay and commutation delay. Therefore, the rectifier absorbs lagging VA.


HVDC Transmission

Fig. 3.19 Modes of operation of a converter

(a) Phasor diagram for current 0 £ fR £ 90° for rectifier operation 90° £ fi £ 180° for inverter operation Suffix R indicates for rectification Suffix i indicates for inverter (b) Phasor diagram for current P—Active Power Q—Reactive Power VsL—Phase-to-phase voltage on the secondary side of the converter transformer Is—Line current on the secondary side

Fig. 3.20

Phasor diagram

6-pulse Converter Operation and Analysis


With filter circuits no distortion current can flow beyond the filtering point when the filtering process is perfect. Under these conditions, the power factor can be approximated by the displacement factor (cos f), where f is the phase difference between the fundamental frequency voltage and fundamental current component. In ideal conditions with losses neglected, the active fundamental AC power (PAC) is same as the DC power (Pd), i.e. PAC =

3VsL I1 cos f = Vd I d


where I1 is the fundamental component of the current on the secondary side of the converter transformer and Vd I d (3.49) cos f = 3VsL I1 Substituting Vd and I1 from equations (3.20) and (3.25), the expression reduces to V= I1 = cos f =


Vdo [cos a + cos (a + m )] 2 6 I p d

(3.20) (3.25)

Vdo 2 [cos a + cos (a + m ) ] ¥ I d ÈV p ¥ 1 ˘ I d 6 3 Í do ˙ Î 3 2 ˚ p cos a + cos (a + m ) 2


Reactive power is often expressed in terms of active power as Q = PAC tan f


where tan f [derived from the expression (3.29) and (3.50)] is expressed as tan f =

sin (2a + 2 m ) - sin (2a - 2 m ) cos 2a - cos (2a + 2 m )


The power factor for the inverter operation can be approximated from the expression (3.50) as cos f =

1 (cos g + cos b ) 2


From AC voltage and valve current waveforms shown in Figs. 3.13(a) and (c), it is clear that the current supplied by the inverter to the AC system lags the positive half of the corresponding phase voltage waveform by more than 90° or in other words leads the negative half of the same vo1tage by less than 90°. It can be stated that the inverter absorbs the lagging current or provides leading current. Both the concepts indicate that the inverter, like the rectifier, acts like a sink of reactive power. This point is expressed in a graphical form in the phasor diagram in Fig. 3.20.


HVDC Transmission

Expressions (3.48) to (3.53) show that the active and reactive powers of a controlled rectifier vary with cosine and sine of the control angle respectively. Thus, when operating at constant current, the reactive power demand at low p.f. can be very high. However, such operational conditions are prevented in HVDC converters by the addition of on-load transformer tap-changes, which try to reduce the steady state control angle a (and extinction angle g) to the minimum specified. Under such controlled conditions, Fig. 3.21 illustrates the typical variation of the reactive power demand versus active power of an HVDC converter. The reactive power demand is shown to be approximately 60% of the power transmitted at full load and it is about 28% at half the full load as marked in the diagram.


Fig. 3.21 Variation of reactive power with active power


Let Vm be maximum phase voltage applied to the bridge, Vd and Vd as output DC voltages of upper and lower bridge circuits as shown in Fig. 3.22. 1

Fig. 3.22


12-pulse converter

The AC voltage of the lower bridge lags that of the upper by 30° (electrical). For the top bridge, we have

6-pulse Converter Operation and Analysis

Vd (t ) = 1

pˆ Ê 3Vm cos Á w t - ˜ Ë 6¯


pˆ Ê ÁË 0 £ w t £ ˜¯ 3


pˆ Êp ÁË £ w t £ ˜¯ 6 2


With a 30° shift, the bottom bridge’s output unfiltered voltage is Vd (t ) = 2

pˆ Ê 3Vm cos Á w t - ˜ Ë 3¯

The output voltage of the combination is thus Vd(t) =

È Ê pˆ p ˆ˘ Ê 3Vm Ícos Á w t - ˜ ± cos Á w t - ˜ ˙ Ë ¯ Ë 6 3¯˚ Î

pˆ Ê = 1.9319 3Vm cos Á w t - ˜ Ë 4¯

pˆ Êp ÁË £ w t £ ˜¯ 6 3


The DC voltage Vd is thus Ï Èp 3 pˆ ˘ Ô Ê Vd = 1.9319 3Em Ì Í Ú cos Á q - ˜ dq ˙ Ë 4¯ ˙ ÔÓ ÍÎp 6 ˚ =

¸ pÔ ˝ 6Ô ˛

(6)(1.9319 3) Em Êpˆ 2 sin Á ˜ = 3.3042 Vm Ë 12 ¯ p

This can also be obtained from the DC value of one bridge Vd1 as È3 3 ˘ Vd = 2Vd = 2 Í (Vm ) ˙ Î p ˚



The transformer secondary voltage is given by the inverse relation Vm =

1 V 3.3042 d

or Vm = 0.3026 Vd


The peak inverse voltage and average current in a valve are given by the same expressions used for a single bridge. Id =


3 = 0.333 Id

p (V ) 3 d p ÊV ˆ = Á d˜ 3Ë 2 ¯

Peak inverse voltage = PIV =


HVDC Transmission

Thus, PIV = 0.5236 Vd


The peak-to-peak ripple is Êpˆ Êpˆ PPR = Vd ÁË ˜¯ - Vd ÁË ˜¯ 4 3 pˆ Ê = 1.9319 3 Vm Á1 - cos ˜ Ë 12 ¯ = 0.114Em In terms of the DC voltage, we thus have PPR = (0.114) (0.3026Vd) or PPR = 0.0345Vd


Thus, it can be seen that ripple is less than 3.5% of the DC output voltage. The maximum secondary voltage V of the transformer is about 30% of the DC output voltage. Hence, the rms value of the line voltage = 3 m 2 is 37% of the DC output voltage. Since two valves conduct at the same time in each bridge, there will be 4 valves conducting at a time in a 12-pulse bridge converter. The output of the bridge is maximum, when a = 0 and becomes zero when a = 90°. In case of a six-pulse converter, since the phase difference between successive SCRs is 60°, maximum overlap angle can go up to 60° (m £ 60º), whereas in a 12-pulse converter, the phase difference is 30° only. Hence, commutation or overlap angle should be less than 30°. In order to maintain stable operation of rectifier, it is preferable to have both a and m in the range 0 £ a, m £ 30°, in which case 4 or 5 valve conduction exists and with 30° £ m £ 60°, 5 and 6 valve conduction mode takes place, for 60° £ m £ 90° 6 and 7 valve conduction takes place.

3.9.1 Current Waveform in 12-pulse Converters The equivalent circuit of the twelve-pulse converter is the series combination of equivalent circuits for the two bridges. This is because the two bridges are connected in series on the DC side and in parallel on the AC side. The current waveform (neglecting overlap) in the primary winding of the star/star connected transformer is shown in Fig. 3.23(a). The current waveform in the primary side of the star/delta connected transformer is shown in Fig. 3.23(b). The waveform of the line current injected into the converter bus is shown in Fig. 3.23(c). It can be shown that the 5th, 7th, 17th, l9th harmonics (in general, when h π 12n + 1) produced by the two bridges cancel each other. Thus, the lowest AC harmonic present in a 12-pulse converter is of order 11. Complete analysis of a 12-pulse converter, similar to a 6-pulse converter, is not presented here because a 12-pulse converter is the combination of two 6-pulse converters. The Vd Id characteristic is similar, as given in Fig. 3.19, except that 4–5 valve conduction, 5, 6 valve and 6, 7 valve conduction occurs as m charges from 0 to 30° to 60° to 90°.

6-pulse Converter Operation and Analysis


Fig. 3.23 AC current waveform in a 12-pulse converter

3.10 POWER FLOW IN HVDC LINKS A group of valves which can be connected in various ways constitute a converter. In all modern HVDC systems 12-pulse converter circuits are used. The basic properties of converter circuits have been discussed in previous sections. For economic and useful design of HVDC systems, it is essential to know certain terms associated with them. Terms and definitions related to HVDC transmission— (1) Two terminal HVDC system—A high voltage direct current (HVDC) transmission system consists of two substations which are interconnected by a DC transmission line. (2) Multiterminal HVDC systems (MTDC)—An HVDC transmission system consisting of more than two transmission substations and an interconnecting DC transmission line. (3) HVDC coupling system—An HVDC system which transfers energy between two AC buses at the same location, but operating at different frequencies, is generally known as back-to-back HVDC substation. (4) HVDC transmission line—A part of HVDC transmission system consisting of overhead lines or underground cables connected to HVDC substations known as rectifier/inverter stations.


HVDC Transmission

(5) HVDC substation—It is a part of an HVDC system which consists of one or more converter units installed in a single location together with buildings, reactors, filters, reactive power controls and protective equipment. (6) HVDC system pole—It is known as the pole of HVDC systems, and consists of all equipments in the HVDC substation and interconnecting transmission lines (if any), which during normal conditions exhibit a common direct polarity with respect to the earth. (7) Peak Inverse Voltage (PIV)—The maximum voltage that appears across the terminals of a valve during the nonconduction period. (8) Peak-to-peak ripple—This is defined as the difference between the highest and the lowest values of the output waveform for a given circuit configuration. (9) Volt-ampere rating of a valve—This is defined as the product of the average current and the peak inverse voltage. This is also sometimes expressed as a fraction of DC power delivered. (10) Volt-ampere rating of a transformer—This is the product of the rms value of voltage and the rms value of current. As the current waveform is nonsinusoidal, VA rating differs from the normal value of power transformer used in AC power transmission. (11) Pulse number—The number of cycles of ripple or pulses of a DC voltage for each cycle of the AC voltage. For example, for a single-phase full wave rectifier there will be two pulses of voltage in the rectified DC voltage. In HVDC systems only 6-pulse and 12-pulse converters are used and therefore their analysis is limited to these circuits only.

3.10.1 Fundamental Equations of HVDC Power Flow An HVDC system consists of a rectifier station, DC transmission line and inverter station as shown in Fig. 1.4. AC power is first rectified by the first converter and transported by the DC overhead line or cable, inverted by the 2nd converter into AC at the other terminal. Any converter can either act as rectifier or inverter with proper control so that power can flow in either direction.

3.10.2 Power Flow and Current Control The power flow and current through an HVDC line can be controlled by either controlling the DC voltage at the inverter end or rectifier end. Current through the DC line is expressed as Id =

Vd - Vd 1




where Vd is the DC voltage on the rectifier end and Vd is the DC voltage on the inverter end and R is the 1 2 resistance of the DC line per pole. Vd = DC voltage in the middle of the DC line 3


Vd + Vd 1




The DC power through the line is Fdc = Vd Id


6-pulse Converter Operation and Analysis


The values of Vd and Vd can be changed in two ways— 1


(1) With the use of tap-changer control, which is slow and may take 8 to 10 seconds. (2) Fast variation of DC voltages can be achieved through gate control, by varying the delay angle for a few milliseconds. The value of PDC can be controlled quickly because of a small value of R. The DC side voltages Vd and Vd at both ends of the DC line have definite relations to the corresponding 1 2 AC voltages, which depend upon the position of top-changer control and delay in firing angle of the converters. Usually Vd is held at a certain value by voltage control of the inverter terminal and the 2 current Id is controlled by the rectifier terminal. The following equation must be satisfied for power flow from the rectifier end to the inverter end as Vd = Vd + Id 1




The current through the rectifier and inverter must be same as Id = Id = Id. 1 2 Power at the rectifier end (Pd ) 1 The DC power at the rectifier end is given by Pd = Vd Id 1



(Vd - Vd )

= Vd










Vd Vd 1




The power at the rectifier end can be controlled by controlling the difference (Vd – Vd ), while holding 1 2 Vd at a fixed value. 1 Power at the inverter end (Pd ) 2 The DC power at the inverter end is given by Pd = Vd Id 2



Using the expression (13.1) for Id Pd = 2

Vd (Vd - Vd ) 2



R Vd2 Vd Vd + = R R 2



Vd2 2



Vd Vd 1





The negative sign of the first term indicates that the power is received by the inverter end.

3.10.3 Power Loss in the DC System Power loss in the DC circuit (line) between the rectifier and the inverter is PL = Pd – Pd 1


= (Vd Id – Vd Id) Id = (Vd – Vd ) Id 1

PL =


(Vd - Vd ) 2

The DC line loss increases with DC power flow.





= I d2 R




HVDC Transmission

3.10.4 Power in the Middle of the DC Line (Pdm) The power in the middle of the line is given by Pdm = (Pd + Pd )/2 1







Vd Vd





ÏÔ Vd2 Vd Vd + Ì+ R R ÓÔ 2



¸Ô˘ ˝˙ ˛Ô˙˚

ÈVd2 - Vd2 ˘ Vd2 - Vd2 ˙= = Í 2R ÍÎ 2 R ˙˚ 1





Vd2 - Vd2 1




The power at the rectifier end can be expressed as Pd = Pdm + ½PL 1


Similarly, power at the inverter end can be expressed as Pd = Pdm – ½ PL 2


3.10.5 Relation between Power Flow on AC and DC Sides The power on the AC side is PL = 3 VsLIs cos f where cos f is the p.f. on the AC side and power on the DC side is Pd = Vd Id Neglecting the conversion losses 3 VsL Is cos f = Vd Id Vd = where Kc is called current ratio factor =


Is cos f VsL = K cVsL Id

3I s Id

(3.73) (3.74) (3.75)

3.11 OPERATION AND ANALYSIS OF VSC CONVERTERS The simplified diagram (one line) of a typical VSC converter is shown in Fig. 3.24. In the Fig. 3.24, the 6-pulse converter bridge along with AC side reactors is shown with IGBT valves as switches. For a 12-pulse connection, two 6-pulse converters, one with Y connected transformer secondary and another with D connected transformer secondary will be feeding similar bridge circuits, and the two bridges will be connected in series. The single line diagram of the VSC connection is shown in Fig. 3.24(b).

6-pulse Converter Operation and Analysis


Fig. 3.24(a) Voltage source converter (6-pulse)

Fig. 3.24(b) Single-line diagram representation of VSC

During rectifier operation, the converter operates as an uncontrolled bridge rectifier with the six diodes charging the capacitor to Vm (AC side peak voltage). When the rectifier is connected to a load (or an inverter), the bridge supplies the load current IL and also the charging current for the capacitor. Hence, the voltage at the capacitor reduces due to the ripple. The AC current is maintained constant by the inductors L on the AC side, whereas DC capacitor C maintains the voltage Vd constant on the DC side. The DC voltage is controlled by tap changer of the converter transformer. The polarity of the DC bus is always the same and a power reversal is obtained by reversing the current (as in the case with DC machines). If a converter feeds current into the DC bus, it acts as a rectifier, and if it receives current from the DC bus, it acts as an inverter. In addition to this, PWM control is also used to control the DC voltage (current) to monitor active power flow.

3.11.1 Inverter Operation DC voltage can be converted into a pulse voltage using Chopper technique, i.e. during a period T, if the voltage is on for a period t1, and off for a period t2, given (t1 + t2 = T), the output becomes a pulse of voltage V and duration t1. Instead, if a DC voltage Vd with mid-point earthed (i.e. +Vd /2 and –Vd /2) is chopped, as described above, a square wave is generated.


HVDC Transmission

Fig. 3.25 Two-level single-pluse voltage source converter

During blanking periods, i.e. when both S1 and S2 are switched off, the AC terminal voltage depends on the current direction in which the switch pair is turned off, and the AC side reactor maintains the current. To generate AC voltage waveform, a repeated switching sequence is used in a time interval T with n number of switching actions with intervals t1, t2, t3……….tn as a sequence from starting time t0 in a given pattern. The parameter T controls the AC (output voltage) frequency. The n switching times (t1, t2, t3… tn) control the amplitude (peak value) of AC output voltage (fundamental value). The above principle is called power width modulation technique (PWM). The frequency (f0), amplitude (Vm) and phase angle (q) are controlled by the switching gate control.

3.11.2 PWM or Pulse Width Modulation In case of simple switching technique, there is only one pulse in every fundamental half cycle. In the 2-level VSC discussed here, fundamental switching cannot control the magnitude of the fundamental component. The magnitude of fundamental component control can be achieved by regulating the DC voltage with a margin. With DC voltage sufficiently high, the PWM firing pattern can control all the three parameters Vm, f0 and q. A critical factor in the choice of the modulation principle is the ratio of carrier or modulation frequency to that of the fundamental frequency (P), given by P = fp /f (Eq. 3.76). This also determines the harmonic spectrum. However, a high frequency ratio causes high losses. The achievable volt-time area gets reduced with a high P and thus the magnitude of fundamental component at full voltage gets reduced. Other two factors that govern the performance are M, K as defined below M = V1/V1 (um)


It is the ratio of fundamental component modulated to unmodulated waveforms. K = V1 (max) /V1 (um)


It is called utilisation ratio and it gives a measure of how modulation can best utilise the maximum available volt-time area. Switching-pattern start time (or the phase angle related to reference signal) is an important controllable variable for active power control.

6-pulse Converter Operation and Analysis


This is illustrated in Fig. 3.25. The DC side capacitor used C is shown as two capacitors 2C connected in series but charged to Vd /2 only. When S1 is closed and S2 is open, + Vd /2 appears and with S1 open and S2 closed, –Vd /2 appears at the output terminals. Since conduction with solid state (IGBT) elements is unidirectional, anti-parallel diodes D1, D2 are needed to form the switching pair, so that the bridge voltage only has one polarity, while current can flow in either direction. With switches S1 and S2 (IGBT valves) blocked, the anti-parallel diodes form the uncontrolled bridge rectifier. The AC voltage charges the capacitor C (2C+2C) for the peak value of AC as explained in the previous section (3.11). The main switches S1 and S2 can be blocked or switched on in any desired pattern but should never be made on simultaneously, as it will form short circuit on the DC side. Even if both switches (IGBTs) are blocked for a short duration, the current path will continue through the freewheeling diodes. A single line diagram of VSC inverter is shown in Fig. 3.26.

Fig. 3.26 Simplified representation of VSC inverter connected to AC grid

Basically, the VSC converter generates a square wave only. To understand the inverter operation, let the upper switch S1 (Valve 1) be turned on and the AC terminal is now connected to + of a DC, i.e. capacitor terminal via switch S1 and diode D1. Current can flow in either direction, i.e. through S1 (current from AC terminal) or through D1 (current from DC terminal to the capacitor). When S1 is turned off, the reactance on the AC side (see Fig. 3.24(b)) maintains the current through the anti-parallel diode. The current path is maintained through the lower freewheeling diode D2 but polarity is maintained at +Vd /2 only. Similarly, when S2 is turned on, the polarity reverses and the above sequence continues. Schematic diagram of complete HVDC link is shown in Fig. 3.27.

Fig. 3.27 Basic VSC transmission system

If the inverter is connected to an active AC system, i.e. another AC system, the frequency of the firing pattern is synchronous with that of the AC power system. If the inverter is connected to a passive load (like in motor controls or independent power supply system), the frequency has to be controlled independently. In 3-phase systems, all the three

Fig. 3.28

Phasor diagram of VSC and direction of power flow


HVDC Transmission

phases are taken as a whole and given symmetrical waveforms. Since VSC systems are self-commuted, they form an electrical power system controlled in real time and the control firing pattern parameters (P, M, q) have to be changed in real time to control both real power P and reactive power Q.

3.11.3 Carrier-based PWM In the classical method of PWM techniques with voltage source converters, (or inverters), a low frequency output AC wave is generated with controllable magnitude and frequency by suitable programming of high frequency pulses. Out of different methods available, carrier based PWM is preferred due to low harmonic distortion and well defined switching frequency and implementation simplicity. The triangular intersection technique is usually employed where a sinusoidal PWM is used. The reference modulation wave (sine wave) is compared with a triangular carrier wave and the intersections define the switching instants.

Fig. 3.29(a) Single-phase sine PWM signal

This is shown in Fig. 3.29. Switching signals for the single-phase (Fig. 3.29(a)), and three-phase system (3.29(b)) are shown along with PWM patterns in respective figures. A similar modulation technique is used for all the three phases of gate signals to trigger the six valves in a 6-pulse converter. Since 3-phase AC systems do not have a neutral in 3-wire systems, any zero sequence signal can get inserted in the reference modulation signal and may cause distortion or improper switching of the valves. However, a properly selected zero sequence signal can extend the sinusoidal PWM linearity range. The scheme is simple for 2-level converters. But for multilevel (3 or more) converters, digital or space vector PWM is preferred, as it does not involve sector identification and works well with overmodulation also.

6-pulse Converter Operation and Analysis


Fig. 3.29(b) Three-phase SPWM generating principle

3.11.4 Power Flow in VSC-DC Transmission The basic VSC transmission system is shown in Fig. 3.27 and the phasor diagram on the AC side of the converter station in Fig. 3.28. The two AC systems are interconnected by the DC link. Let the AC voltage on the valve side of the converters transformers be VL with a DC load current Id. Power converter is P = Pd = Vd Id = (VLVV /XL) sin d


where XL is reactance of the inductor L and d is the phase difference between the two voltages. The reactive power Q = VL (VL – VV cos d) / XL


Neglecting the resistance of inductor of transformer windings, thus P = (VLVV /XL) sin d and (Q – VL2 / XL.) = (VL. VV /XL) cos d


Since converter’s terminal voltage Vv = kVd or proportional to the valve side DC voltage, the power input to the converter can be controlled by changing Vv or Vd and by changing d, the reactive power can be controlled. It may be noted that the locus of P, Q is a circle, and thus for a given MVA rating of the system, P and Q can be independently controlled. Typical P-Q diagram is shown in Fig. 1.16 (Chapter 1, Section 1.10.2). Usually both converter stations can act either as a rectifier or an inverter. In thyristor or current source (CSE) system, the direction of current is constant and the voltage polarity is changed. In VSC systems, polarity is constant and power reversal is obtained by reversing the current. Thus, if the station 1 has a higher DC voltage (say, 1.05 p.u.) power flows from 1 to 2 and vice versa.


HVDC Transmission

3.11.5 Comparison between CSC (Classical HVDC) and HVDC-VSC Systems Due to limitations on HVDC-VSC valve voltage ratings, VSC systems are at present used with less than ± 200 kV and 500 MW system. Whereas classical CSC systems are being used for voltages above 300 kV and over 1 GW. The high controllability of HVDC-VSC leads to independent control of active and reactive power, and possibility of controlling short circuit conditions. Table 3.3 gives comparative characteristics of both the systems. Table 3.3 Comparison between HVDC-CSC and HVDC-VSC systems S.No.




Acts as a constant current source on DC side

Constant voltage source on DC side


Current on DC side is unidirectional

Polarity on DC side is unidirectional


Polarity on DC side changes with power flow

Direction of current changes with the power flow


DC reactor maintains constant current

DC capacitor maintains constant voltage


DC filter capacitance is used on line side of smoothing reactor

DC smoothing reactor is used on the line side of DC filter capacitor


Line commuted or forced commuted



PWM control is very rarely applied

PWM control is usually applied


CSC and VSC are dual systems

CSC and VSC are dual systems


For given power rating, costs are less

Overall costs are more


Cannot feed reactive power into AC system

Reactive power control is possible

REFERENCES 1. Kimbark E.W., Direct Current Transmission, Wiley InterScience (New York), 1971. 2. Arillaga J., High Voltage Direct Current Transmission, IEE Power Engg. Series, (London) Peter Peregrinus, 1983; 2nd edition, 1998. 3. Padiyar K.R., High Voltage DC Power Transmission System, Wiley Eastern Ltd., (New Delhi), 1992. 4. Kimbark E.W., (Charts showing the relation between electrical quantities on the AC and DC sides of a converter), IEEE, Tr. PAS, Vol. 82, December 1963. 5. Sood Vijay K., et al., High voltage DC Transmission and FACTS, CRC Press, (USA), 2004.

WORKED EXAMPLES 3.1 A transformer secondary line voltage to a 3-phase bridge rectifier is 345 kV. Calculate the DC voltage output with m = 15°, when a = (a) 0°, (b) 15°, and (c) 30°.

6-pulse Converter Operation and Analysis


Solution: Given m = 15∞ and VL = 345 kV 3 2 V = 466 kV p L V But Vd = do [cos a + cos (a + m )] 2 For a = 0∞, Vd = 233[1 + cos 15∞] = 458 kV Vdo =

a = 15∞, Vd = 233[cos 15∞ + cos (15 + 15)∞] = 426.8 kV a = 30∞; Vd = 233[cos 30∞ + cos (30 + 15∞)] = 366.5 kV 3.2 Calculate the secondary line voltage of the transformer for 3-phase bridge rectifier to provide a DC voltage of 120 kV. Assume a = 30°, m = 15°. What is the effective reactance XL, if the rectifier gives 800 A of DC output current? Solution: Vd =


2 Vdo

[cos a + cos (a + m )]

[cos 30∞ + cos (30 + 15)∞] 2 3 2 Vdo = V = 152.6 kV p L V ¥p = 113 kV VL = do 3 2 Vd = Vdo cos a - I d Rd

120 =



i.e. 120 kV = 152.6 cos 30∞ - 800 Rd ¥ 10-3 kV \

Rd = 15.15 W =


XL =

Rd ¥ p 3

3 XL p

= 15.9 W

3.3 An HVDC link has the following parameters—AC line voltage at rectifier terminals 320 kV when delivering load of 500 MW at 335 kV. The inverter operator with m = 21.5°, Xrect = 58 W, Xinv = 57 W, Rline = 3 W. Calculate (a) a, (b) AC line ct and p.f. at the rectifier, and (c) AC line current, voltage, p.f. at the inverter end. Solution: DC current I d at rectifier =

500 ¥ 103 = 1493 A 335


HVDC Transmission


335 =

3 XL 3 2 VL cos a I p p d

3 2 3 ¥ 58 ¥ 320 cos a ¥ 1493 ¥ 10-3 kV p p Solving a = 14.9∞ =

AC line current is given by IL =

6 I = 1164 A p d

AC power = 3VL I L cos q 500 ¥ 103 = 3 ¥ 320 ¥ (1163 ¥ 10-3 ) cos q \

cos q = 0.775 Voltage drop I d R = Vrect - Vinv


Vinv = Vrect - I d R = 335 - (1493 ¥ 10-3 ) = 330.5 kV


Vdi =

3 2 3 V cos g - I d X i p L p i

3 2 3 VL cos (21.5∞) - ¥ (1493 ¥ 10-3 ) ¥ 57 p p from which VL = 327.7 kV 330.5 =



Inverter Power = Vdi I d = 330.5 ¥ 1493 ¥ 10-3 = 493.1 MW \ p.f. at inverter terminals is 493.1

cos q i =

3 ¥ 327.7 ¥ 1164

= 0.747

3.4 The AC line voltage is 330 kV with a load of 500 MW and p.f. = 0.78 at the inverter end. Calculate the AC line voltage, current and p.f. at the rectifier end with m = 15°. Solution: 500 ¥ 106

At the inverter end I L =

3 ¥ 330 ¥ 0.78 ¥ 10-3 = 1121.5 A


Id = Vdi =

p 6 Pdi Id

I L = 1438 A =

500 ¥ 103 = 347.6 kV 1439

6-pulse Converter Operation and Analysis

Rectifier end voltage


Vdr = Vdi + I d R = 347.6 + (1439 ¥ 10-3 ) ¥ 3 = 352 kV Vdr =


3 2 3 VL cos a - ( I d X r ) p p

3 2 3 V cos 15∞ - ¥ 1493 ¥ 10-3 ¥ 58 p L p VL = 331 kV

352 =

Power output at the rectifier is (352 ¥ 1439 ¥ 10-3 ) = 506.2 MW Since voltage (VL ) is almost same, I L is same i.e.

= 1121.5 A PAC = PDC


506.2 = 3(331 ¥ 1121.5 ¥ 10-3 ) ¥ cos q cos q = p.f. at rectifier end = 0.787


3.5 Determine the output DC voltage, peak-to-peak ripple and peak inverse voltage of 12-pulse converter given that the secondary side voltage of converter transformer (line-to-line) is 200 kV (rms). Solution: Peak value of phase voltage is \

200 ¥ 2 = 163.2 kV 3 Vd = 3.304 Vm = 539 kV PPR = 0.0345 Vd = 18.6 kV

PIV of valve = 0.5236 Vd = 282 kV 3.6 A 3-phase fully-controlled bridge converter is connected to a 400 V, 50 Hz supply having a source reactance of 0.3 W/ph. The converter is operating as a rectifier at a firing angle of 60°. Determine the average load voltage and the overlap angle when the converter is supplying a steady current 100 A. Solution: From the expression (3.22), the average load voltage is Vd =

3 3 Vm p

=3 3¥

cos a -

3w Ls p


400 ¥ 2 3 ¥ 0.3 cos 60∞ ¥ 100 p p

= 270 - 28.5 = 241.5 V


HVDC Transmission

From the expression (3.23), Vd = 241.5 =

3 3Vm

[cos (a + m )] +

p 3 3Vm



cos[(a + m )] + 28.5


213 ¥ p

cos (a + m ) =

3w Ls


3¥ 3 ¥

400 ¥ 2


213 ¥ p 3 2 ¥ 400


= 0.394 a + m = 66.8∞ Overlap angle = m = 66.8 - 60 = 6.8∞ 3.7 A bipolar two terminal HVDC link is delivering 1000 MW at ± 500 kV at the receiving end. The total losses in the DC circuit are 50 MW. Calculate the following: (a) Sending end power (b) Sending end voltage (c) Power in the middle of the line (d) Voltage in the middle of the line (e) Tota1 resistance of the DC circuit Solution: (a) Sending power = Receiving end power + Losses = 1000 + 50 = 1050 MW (b) Sending end voltage = Vd



Vd ¥ I d = 1050 MW 1

Vd =

1050 ¥ 106 Id

Id =

1000 ¥ 106 = 1000 A 2 ¥ 500 ¥ 103



Vd = sending voltage = 1

1050 ¥ 106 = 1050 kV 1000

between the poles, i.e. ± 525 kV/pole (c) Power in the middle of the line = Power at the receiving end + 1/2 Losses = 1000 + 25 = 1025 MW

6-pulse Converter Operation and Analysis

(d) Voltage in the middle of the line =


Power in the middle of the line Id

1025 ¥ 106 = 1025 kV 1000 = ± 512.5 kV =


(e) Total resistance of the DC circuit PL = I d2 R R=

50 ¥ 106 = 50 W 106

3.8 A bipolar DC line of ±100 kV is delivering 100 MW on the DC side. The power factor on the AC side of line is 0.9. Estimate the AC side voltage (3-phase) and the corresponding current ratio. Assume the insulation levels are the same. Solution: Since insulation levels are the same, the AC side line voltage (VsL) on the converter side can be related as VsL 3

¥ 2 = Vd

The AC line-to-line voltage on the converter side of the transformer VsL = 100 ¥ 1.5 = 122.5 kV I s = AC current = AC line current =


¥ 106

3VsL 0.9


100 ¥ 106 3VsL ¥ 0.9 100 ¥ 106 3 ¥ 122.5 ¥ 103

= 523.6 A DC current = I d = 109 2 ¥ 105 = 500 A Current ratio factor = K c =

3 ¥ Is Id

¥ cos f

3 ¥ 523.6 ¥ 0.9 500.0 = 1.813 =

3.9 The AC line voltage of a 3-phase bridge rectifier is 150 kV when delivering a DC power of 300 MW. Assuming a delay angle of 30º and commutating reactance of 10 W, find the value of the DC current in the circuit and the DC voltage on load.


HVDC Transmission

Solution: The AC side line voltage on the converter side = VsL = 150 kV If Vm is the peak voltage/ph. on the AC side, then 3 Vm = 2VsL = 150 ¥ 2 = 212.13 kV Vdo =

3 3Vm

= No-load DC voltage = p = 202.57 kV

3 ¥ 212.13 p

Vd = Vdo cos a - I d Rc


= 202.57 ¥ cos 30 ¥ 103 - I d ¥ 10 = 175.43 ¥ 103 - I d ¥ 10 Vd I d = 175.43 ¥ 103 I d - I d2 ¥ 10 10 I d2 - 175.43 ¥ 103 I d + 300 ¥ 106 = 0 I d2 - 175.43 ¥ 102 I d + 300 ¥ 105 = 0 I d = 1.9 kA Vd = 175.43 - 1.9 ¥ 10 = 175.43 - 19 = 156 kV on load 3.10 The DC voltage and current at the sending end of a rectifier station are 200 kV and 1000 A respectively. The commutating reactance of the rectifier is 10 W and the resistance of the line is 10 W. Calculate the extinction angle g, if the DC voltage is 190 kV at the terminal of the inverter. Assume the no-load voltage of the inverter as 200 kV at g = 0. Solution: Id =

Vdo cos a - Vdo cos g 1


Rc + R - Rc 1


Given R = 10 W, Rc = 10 W and I d = 1000 A 1

Id =

200 ¥ 103 - 190 ¥ 103 Rc + R - Rc 1


(20 - Rc )103 = 10 ¥ 103 2

Rc = (20 - 10) = 10 W 2

For the inverter operation, -Vd = Vdo cos g - Rc I d 2


Vdo cos g = - Vd + Rc I d 2


6-pulse Converter Operation and Analysis


= -190 + 10 ¥ 103 = -180 kV 180 180 cos g = = = 0.9 200 Vdo 2

= 25.84∞ 3.11 An HVDC link delivers DC power with the AC line voltage to the rectifier being 180 kV and that at the inverter being 165 kV. Taking a = 15º and g = 20º, Rc and R = 10 W and R = 5 W. Calculate the DC 1 voltage at both the ends and the current in the DC link. Solution: Vdo = No-load DC voltage at the rectifier end =

3 2VsL





3 2 ¥ 180 ¥ 103 = 243 kV p

Vdo = No-load DC voltage at the inverter end =

3 2VsL




3 2 ¥ 165 ¥ 103 = 222.8 kV p Vd = Vdo cos a = 242 ¥ 103 ¥ cos 15∞ = 243 ¥ 103 ¥ 0.9659 =



= 234.7 kV Vd = Vdo cos g = 222.8 ¥ cos 20∞ ¥ 103 = 209.36 kV 2


I d = (234.7 - 209.36) / 20 = 1.265 kA 3.12 The per unit values of the converters acting as a rectifier are Vd = 0.98, Vdo = 1.0, Rc = 0.10 and I d = 0.9. Compute the delay in firing of the rectifier. 1

Solution: The characteristic equation of the rectifier in p.u. is Vd = Vdo cos a - Rc I d 1


V1 = 0.98; Vdo = 1.0; Rc = 0.1 and I d = 0.9 1

Substituting the above values 0.98 = cos a – 0.1 ¥ 0.9 cos a = 0.89 a = 27.12º 3.13 An HVDC converter rated 100 MW at 100 kV on the DC side has a commutation reactance of 0.2 p.u. The delay is varied between 5º and 20º. Determine the converter transformer rating and percentage of


HVDC Transmission

tap-changing required. Determine the rating of the condenser to make the p.f. on the primary side of the converter 1.0. Solution: Given Vd = 100 kV, Pd = 100 MW, X c = 0.2 (p.u.) Id =

100 ¥ 103 = 1000 A 100

The rms value of AC current in the transformer secondary I s = 2 / 3I d I s = 0.816 ¥ 1000 = 816 A Vd = Vdo [cos a - Rc p.u.] 1

But we know Rc = xc = 0.1 p.u. 1

100 = Vdo [cos a - 0.1] Vdo = 3 2VsL p

100 cos a - 0.1

= 100 /(cos a - 0.1)

VsL =

100 ¥ p 3 2(cos a - 0.1)

in kV

For a = 5º VsL = 81.9 kV = 82.60 a = 20º VsL = 87.40 kV = 88.21 Transformer rating = 3 ¥ VsL ¥ I s ¥ 10-3 kVA = 3 ¥ 87.40 ¥ 816 = 123.52 MVA = 124.67 kVA Percentage tap changing required 87.40 - 81.9 88.21 - 82.60 = = 81.9 82.60 5.5 5.61 = 100 ¥ = 0.06715 ¥ 100 = = 6.79% 81.9 82.60 = 6.715% Power factor on the AC side = cos f = cos a cos f = cos a - Rc p.u. 1

= cos 20∞ - 0.1

Rc I d 1


6-pulse Converter Operation and Analysis


= 0.94 - 0.1 = 0.84 f = cos -1 0.84 = 32.85 sin f = 0.5425 Rating of the condenser = 3VsL I s sin f = 3 ¥ 87.40 ¥ 0.5425 ¥ 816 = 67 MVA 3.14 An HVDV bipolar link using a 6-pulse converter is supplying power of 500 MW at ±100 kV. The rectifier station is working at a delay angle a = 15º. Estimate (a) No-load DC voltage, (b) AC voltage on the converter side of the transformer, (c) Transformer secondary rating, (d) Peak inverse voltage, (e) Peak-to-peak ripple, and (f) Current on the secondary side of the converter transformer. Solution: (a)

Vd = Vdo cos a 1

Vdo = 1

Vdo = 1

Vd cos a


200 ¥ 103 cos 15∞

200 ¥ 103 = 207 kV 0.9659

(b) The AC voltage on the converter side of the transformer VsL =





207 = 153.4 kV 1.35

(c) AC current on the secondary side I s = 2 / 3 I d Id =

500 ¥ 106 = 2500 A 200 ¥ 103

I s = 0.666 ¥ 2500 = 2040 A (d) Transformer secondary rating = T = 1.047 ¥ Pd ¥ 10–3 1.047 ¥ 500 ¥ 10–3 = 523.5 kVA (e) Peak inverse voltage =

2VsL = 1.047 Vdo


= 1.047 ¥ 207 = 216.73 kV (f) Peak-to-peak ripple = (PPR) = 0.1403Vdo 1 = 29 kV 3.15 Find the maximum permissible commutating reactance in p.u. to allow commutation to be completed in an overlap angle of 60º at rated voltage and at 1.5 times the rated current.


HVDC Transmission

Solution: Vd (p.u.) = 1/ 2[cos a + cos(a + m )] a = 0, m = 60∞


Vd = 1/ 2 ¥ (1 + 1/ 2) = 3 / 4 (p.u.) Vd =


= 3/ 4


Vdo = 4 / 3 Vd Vdo =


= 4 / 3 (p.u.)


But we know Vd = Vdo cos a - Rc I d 1

a =0


Vd = Vdo - Rc ¥ 1.5 1

Ê4 ˆ Rc ¥ 1.5 = Vdo - Vd = Á - 1˜ = (1 - 3 / 4)V do Ë3 ¯ 1

= 1/ 3p.u. = 1/ 4 p.u.(V do = 1) Rc = 2 / 9 = 1

1 ¥ 3 / 2 = -1/ 6 (p.u.) 4

xc = 2 Rc = 4 / 9 p.u. = 0.444 (p.u.) = 1


2 ¥1 = 1/ 3 = 0.33p.u. 6

3.16 Find the ratio of the kVA rating of the converter transformer bank for a 3-phase, 6-pulse converter to the rated DC power, for a = 15º and xc = 0.15p.u. 1

Solution: Vd = Vdo cos a - Rc ¥ I d 1


Vd = 1 p.u. xc = 0.15 p.u. I d = 1.0 p.u. and a = 15∞ 1

Rc = xc / 2 = 0.075 p.u. 1


1 = Vdo cos15∞ - 0.075 ¥ 1 Vdo = =

(1 + 0.075) 1.075 = cos15∞ cos15∞ 1.075 = 1.114 p.u. 0.965

T = The transformer kVA rating = 1.047 Vdo Id ¥ 10–3 kVA

6-pulse Converter Operation and Analysis


Pd = Vd ¥ I d = 1 ¥ 1 = 1 p.u. T = Transformer kVA rating in (p.u.) = 1.047 Vdo I d (p.u.) T = 1.047 ¥ 1.114 ¥ 1 = 1.1664 p.u. T Pd

= 1.1664

3.17 Show that in a 3-phase bridge rectifier operating with no delay and with 60º overlap, the direct current is one-half of the crest value of line-to-line short circuit on the secondary side of the transformer bank. Solution: The expression for direct current is Id =

VsL 2w Ls

[cos a - cos(a + m )]

When a = 0 and m= 60º Id =

VsL 2Xs

= 1/ 2 ¥

(1 - 1/ 2) =

VsL 2 2Xs

2 Ê VsL ˆ 2 Á 2 X ˜ = 1/ 2 ¥ 1 ( I sc ) 2Ë s¯

= 1/ 2( I sc max ) where


VsL = Short circuit current between the lines (rms) 2X s

Isc max = Maximum short circuit current between the lines \ DC current is half the maximum short circuit current

QUESTIONS 3.1 Give the schematic diagram of an HVDC link. What are the important components? 3.2 Mention various methods of controlling the output voltage of a converter. 3.3 Obtain the expressions for PIV, peak-to-peak ripple and valve volt-ampere rating in a 6-pulse Graetz’s converter circuit. 3.4 Obtain the relation between the DC output voltage and the AC line voltage (rms) and rating of the converter transformer with Graetz’s converter circuit.


HVDC Transmission

3.5 Explain the gate control scheme adopted for thyristor valves. How is both the rectifier and inverter operation obtained with suitable controls? 3.6 Sketch the waveforms of the output voltage and the transformer secondary current in the case of 3-phase, 6-pulse bridge circuit (Graetz’s circuit). 3.7 Explain the terms— (i) Firing angle delay (ii) Commutation delay as applied to HVDC converters Sketch the voltage and current waveforms for Graetz’s circuit when (i) a = 30° (ii) a = 120° (iii) g = 15° (neglect overlap) 3.8 Develop the equivalent circuit of a converter working as rectifier with an overlap angle m and delay angle a. Hence, show that the equivalent resistance of the converter is 3wLs /p, where w is the angular frequency and LS is the effective series inductance associated with converter per phase. 3.9 Obtain the expressions for the output voltage and direct current of a converter working as a rectifier with delay angle a and commutation angle m. 3.10 What do you understand by the terms— (a) Commutating Voltage and (b) Commutation Reactance Discuss the effect of the later term on the output voltage of the converter. 3.11 Distinguish between delay in firing angle (a) and extinction angle (g) of an HVDC converter. Explain the operation of a converter when working as an inverter, and state the necessary conditions required for inverter operation. 3.12 Develop the complete equivalent circuit of an HVDC link and obtain an expression for the current in the DC link as Id =

Vdo cos a - Vdo cos g 1


Rc + R - Rc 1


3.13 Obtain the output DC voltage of HVDC converter in per unit quantities and hence show that 2 Rc = X s , where Rc is the p.u. equivalent resistance of the converter and X s is the p.u. series reactance / phase of the converter. 3.14 Show that the expression for the power factor of an HVDC converter is ½ (cos a + cos (a + m)). 3.15 Explain how would you proceed to construct the universal diagram of an HVDC converter? Illustrate how complete characteristics of converters as rectifier/inverter can be obtained from it? 3.16 Give the schematic diagram of a 12-pulse converter. What are the different conduction modes? 3.17 Derive expressions for PIV, PPR (peak-to-peak ripple), valve volt-ampere rating for a 12-pulse converter. 3.18 Sketch the current waveform of the transformer secondary line current of a 12-pulse converter and show that harmonics generated are 11th and above. 3.19 Derive the equations for power flow in an HVDC link. How are the losses estimated? 3.20 Define and explain the following terms— (a) Two terminal HVDC system (b) HVDC pole (c) Multiterminal system (d) Converter substation 1


6-pulse Converter Operation and Analysis


PROBLEMS 3.1 Derive an expression for current ratio of an HVDC link. Also compute its value for a bipolar DC line of ± 400 kV, transmitting a power of 1000 MW, when power factor on the AC side voltage of the converter transformer is = 0.9, assuming that the insulation levels are the same. Also compute current on the AC and DC side. Ans: VsL = 419.9 kV. Ratio = 0.907 3.2 A bipolar HVDC link is delivering 1000 MW at ±400 kV at the receiving end. Calculate the losses in the line, assuming the resistance per conductor as 1 W. Also estimate the sending end power, sending end voltage, power in the middle of the line, and line losses. Ans: = PLosses = 3.75 MW, Ps = 1003.75 MW, Vd1 = 401.25 kV, Pdm = 1001.562 MW 3.3 A 3-phase fully controlled 6-pulse converter has a source reactance of 0.3 W/ph. and operating from 400 V 3-phase 50 Hz supply. The converter is operating as rectifier with fixing angle 60°. Determine the load voltage and overlap angle when load current is 100 A. Determine m and load voltage if a is reduced to 30° and load changed to 30 A. 3.4 For a 3-phase bridge circuit, the secondary voltage on transformer side is 400 kV rms with reactance X = 40 W. Find the DC output voltage, overlap angle if output current is 2000 A and firing angle a = 15°. Ans: Vd = 445 kV, m = 32° 3.5 The AC side line voltage of a 3-phase bridge inverter is 160 kV with g = 20° and m = 20°. What is the DC side voltage? What is the new extinction angle if DC side voltages change to 180 kV, with m and AC side voltage remaining the same? Ans: Vd = 184.3, Extinction angle = 22.02° 3.6 An HVDC link has the following parameters: line resistance 3.0 W, commutating reactance at rectifier end = 60 W, inverter end = 57 W, line voltage at rectifier end (AC) = 320 kV, and power delivered at 333 kV = 500 MW. Determine (i) a, (ii) AC line current and p.f. at rectifier end, and (iii) line current (AC) p.f. at inverter end extinction angle g = 20° Ans: (i) a = 14.2° (ii) 1170 A, p.f. = 0.77 (iii) 1170 A, p.f. = 0.755 3.7 A 3-terminal DC system is shown in Fig. 3.30. Calculate the AC line voltage and current at inverter end. Ans: Vac = 296 kV IL = 1984 A p.f. = 0.79 3.8 The AC line voltage of a 3-phase bridge rectifier is 400 kV when delivering a DC power of 500 MW. Assuming a delay angle of 15° and commutation reactance of 10 W, find the current in the DC link. Fig. 3.30 Ans: 0.75 kA


HVDC Transmission

3.9 Find the ratio of the kVA rating of the converter transformer bank for a 3-phase, 6-pulse converter to the rated DC power for a = 10° and X c = 0.15 p.u. Ans: 1.1428 3.10 Find the maximum permissible commutating reactance in p.u. to allow commutation to be completed in an overlap angle of 30° at rated voltage and current. Ans: 0.278 p.u. 3.11 An HVDC bipolar link using 6-phase converter is supplying 1000 MW at ±400 kV. The rectifier station is working at a delay angle of a = 10°. Estimate (a) No-load DC voltage, (b) AC voltage on the converter side of the transformer, (c) Current on the secondary side of the transformer, (d) Transformer secondary rating, and (e) Peak-to-peak ripple. Ans: 812 kV; 601.7 kV(AC); 1020 A: 1047 MVA; 113.92 kV 3.12 The DC voltage and current at the receiving end of an inverter station is 400 kV and l000 A respectively. The commutation reactance of the inverter is 10 W and that of the rectifier is 15 W. The resistance of the DC line is 20 W. Calculate the delay angle of the rectifier given that no-load DC voltage at the sending end with a = 0 is 450 kV. Also compute the DC voltage at the sending end. Ans: a = 19.2°; 410 kV 3.13 Find the commutating reactance (i.e. p.u.) of a rectifier when working with a = 0 and m = 30°. Also find the ratio of DC voltage on-load/DC voltage on no-load. V Ans: xs (p.u.) = 0.134; d = 0.933 Vdo 3.14 A ± 500 kV, 2000 MW HVDC converter operates as a 12-pulse unit. Assuming full conduction and no losses, calculate (i) Transformer secondary line to line voltage (rms), (ii) Peak to peak ripple, (iii) PIV of the valves, and (iv) Transformer line current. Ans: Vrms = 247.5 kV PPR = 34.8 kV ITr = 666.7 A PIV = 523.6 kV 3.15 In Problem 3.14, the HVDC converter is supplied from a 400 kV, 3-phase AC system and the secondary side transfer line to voltage is 230 kV. Determine (i) DC voltage, (ii) Peak-to-peak ripple, (iii) DC line current, (iv) DC line current, and (v) Transformer line current. Power transmitted may be taken as 2000 MW. 1

MULTIPLE CHOICE QUESTIONS 1. Pulse number means (a) number of valves (b) number of pulses in the output voltage per cycle (c) number of DC poles (d) both (a) and (b) 2. The output voltage of a converter is changed by varying (a) a (b) m (c) g (d) anyone a, m or g 3. In HVDC converter ratio reactive power needed for proportional active power transmission at full-load will be about (a) 1.0 (b) 0.9 (c) 0.6 (d) 0.25 4. Power transmitted through the DC system depends on (a) rectifier end voltage (b) inverter end voltage (c) rectifier end current (d) rectifier end voltage and current

6-pulse Converter Operation and Analysis


5. With increase in delay angle a (a) active power transmitted decreases (b) reactive KVAR needed increases (c) DC output voltage decreases (d) all of the above (a), (b) and (c) 6. During commutation in a converter (a) voltage is exchanged (b) current is transformed from one valve to the other (c) DC voltage is blocked (d) none of the above 7. If Vm is the peak voltage/phase on the AC side for a given a and m, the reduction in output DC voltage 3Vm with an overlap is ¥ 2 (a) cos a – cos(a + m) (b) cos a + cos(a + m) 2 (cos a - cos (a + m ) (d) 2 (cos a + cos (a + m ) 8. Equivalent resistance of a converter with source reactance Xs /ph. for a 6-pulse converter bridge is 3X s Xs (c) (d) 3p Xs (a) 3Xs (b) p p 9. Power factor of rectifier with firing angle a and commutation overlap m is (a) cos a + cos(a + m) (b) cos a + cos(a – m) 1 1 (d) (c) [cos a - cos (a + m )] [cos a + cos (a - m )] 2 2 10. If angle of advance is 30° and overlap angle 12°, the extinction angle g will be (c)

(a) 42°

Ê 30 ˆ (b) ÁË ˜¯ 2

(c) 18°

(d) 21°

11. If base resistance on the DC side is 120 W, the base impedance on AC side will be 120 (a) 20 ¥ p (b) 10 ¥ p (c) 30 ¥ p (d) p 12. If the percent reactance of converter transformer is 20/ph., the percentage DC resistance will be (a) 20 (b) 10 (c) 5 (d) 4 13. Mid-point power in HVDC link is given by (Pd rectifier end power; Pd inverter end power; and PL line 1 2 losses) P P P P (a) Pd - L 2 (b) Pd + L 2 (c) Pd - L 2 (d) Pd ± L 2 14. Peak inverse voltage in a 12-pulse converter is 6 3 p Vd p Vm V (b) (c) (a) (d) 1.932 Vm 2 2 p m 3 3 15. Peak-to-peak ripple in a 12-pulse converter is (a) 0.5236 Vd (b) 0.114 Vd (c) 0.3206 Vd (d) 0.0345 Vd 16. A ± 200 kV, 400 MW HVDC unit has rectifier end voltage ± 195 kV and an inverter end voltage ± 187 kV, when transmitting 1000 A current. The power loss in the system is (a) 8 MW (b) 5 MW (c) 13 MW (d) 16 MW 17. For inversion the system to be stable and successful, g should be such that (g /w) is (a) less than recovery time of valve that is just turned off (b) more than recovery time of valve that is just turned off (c) much less than recovery time of valve that is turned off (d) any of the above three (a), (b) or (c) 1





HVDC Transmission

18. The relation between Vdo and peak value of phase voltage on the secondary side of AC system is, Vdo = p 3 3 Vm p 3 Vm (a) Vm (b) Vm (d) (c) 3 3 p 3 p 19. For constant m, the relation between Vd and Id is (in Vd Id plane) (a) straight line (b) straight line with negative slope (c) circle (d) ellipse 20. In a 6-pulse circuit, a DC voltage with a = 30° is 120 kV when overlap angle is 15°. What will be the no-load output voltage with a = 0°? (a) 120 kV (b) 135 kV (c) 153 kV (d) 113 kV

ANSWERS 1. (d) 9. (c) 17. (b)

2. (a) 10. (c) 18. (b)

3. (c) 11. (a) 19. (d)

4. (d) 12. (b) 20. (c)

5. (d) 13. (a)

6. (b) 14. (a)

7. (d) 15. (d)

8. (b) 16. (d)

Control of HVDC Converter and Systems 4.1


One of the most significant advantages of DC transmission is the inherent ability of a DC link to control the power flow. In AC systems, the power transfer from one system to the other depends entirely on the system conditions on both sides. However in DC, the power transmitted can be varied by changing the voltage across a converter valve bridge at a fast pace. The controllability of DC power can be utilised for different purposes, such as (i) stabilisation of connected AC network, (ii) control of frequency of sending and receiving end network, (iii) control of reactive power and AC voltage, etc.



In AC systems, the power transfer from one system to another depends entirely on the conditions of both the systems. The active power transmission through an AC link is given by the expression PAC = where

VSVR sin d X


VS is the sending end voltage VR is the receiving end voltage X is the reactance of the AC link d is the phase angle between the voltages VS and VR

Similarly, the expression for reactive power transmitted from the sending end is Qs =

VS (VS – VR cos) d X

and reactive power at the receiving end is



HVDC Transmission

QR =

VR (VR − VS cos d ) X


From the above expressions, it is understood that the active power transmitted depends upon the angle d. As d is related to the demand for transmitted power via the rotating machines (rotors) of both the ends, the AC system adapts automatically. It means that the angle d increases with an increase in load on the AC system as the rotor gets retarded w.r.t. to the synchronously revolving magnetic field produced by the stator. The reactive power is only slightly influenced by the angle d but it depends a lot upon the magnitude of the voltages.



The typical HVDC systems of Fig. 1.4 can be conveniently represented by an equivalent circuit (derived in Chapter 3) as shown in Fig. 3.15. As the mid-point of each terminal station is at earth potential and the upper and lower halves of the system are symmetrical, therefore only one-half of the circuit needs to be considered for analysis. The equivalent circuit representation shown in Fig. 3.15 is sufficient for steady-state analysis of power transfer. The station on the left-hand side is a rectifier and on the right-hand side is an inverter. Both stations are assumed to operate at constant delay angles a and b or g respectively. The direct current through the line is given by the equation (3.36) as

Id =

Vdo cos a − Vdo cos (b or g ) 1


Rc + R ± Rc 1



A change of current and therefore power transfer can be achieved by altering any one of the four possible parameters — (a) (b) (c) (d)

The control angle of the rectifier a The control angle of the invertor b or g The rectifier-transformer secondary winding voltage by the tap-changer The inverter-transformer secondary winding voltage by the tap-changer

The cases (c) and (d) can be effected by employing tap-changing of the converter transformer to change the AC voltage.



From the expression for current through a DC link it can be observed that the denominator has only resistances which are small when compared with the reactance of an AC system. Hence, current is sensitive to change in voltage resulting in large fluctuations, which can damage the thyristors. Thus, control of current and hence power, in case of a DC system is a must. The advantages of using control are

Control of HVDC Converter and Systems


1. Current order setting can be quickly and reliably changed depending on the requirement 2. Power reversal can be done easily and quickly 3. Fault current levels are limited to rated values Thus, the basic philosophy of control of an HVDC converter is the proper timing of firing pulses to the thyristor valves to ensure optimum performance.



Figure 4.1 illustrates the phase voltages and one-phase current of a rectifier for firing angles a = 0 and a = 30°, assuming no commutation reactance. It is clear that when a = 0, the displacement angle f between the phase voltage (VR) and the fundamental of the corresponding current waveform (IR ) is zero. However, the displacement angle increases as a increases. It may be concluded that a must be kept as near to zero as possible for minimum rectifier VAR demand. In fact, even at ‘a = 0’, there is a displacement angle present due to the finite value of the commutating reactance. Any long-term control of the rectifier voltage must be changed by tap-changing, allowing a to meet any required fast change of angle of voltage of the rectifier [Vd ]. In practice, under normal condition a is kept near 15° for two reasons. First, to ensure that all valves of 1 the bridge are fired at the same instant of time. Secondly, to allow a small voltage margin for an immediate small power increase if it is dictated by the gate control regulator.

Fig. 4.1 Rectifier operation with large smoothing inductors

4.5.1 Inverter Control Figure 4.2 shows the phase voltages and currents for an inverter operation at two control angles (a) b = 0, m = 0°; (b) b = 60° and m > 0. Similar to the operation of the rectifier, the minimum inverter reactive volt-ampere


HVDC Transmission

Fig. 4.2 Inverter operation

demand will take place with b = 0°. For b > 0°, the current leads the negative voltage by an angle u and consumes lagging reactive volt-amperes. It is important to realise that the range over which inversion can be achieved is limited by the instant C6 as shown in Fig. 4.2. Later than the instant C6, the current cannot be made to commutate from the valve 1 to the valve 3 as the commutating voltage VYR (VY – VR) changes sign, as illustrated in Fig. 4.2. The phase difference between voltage VR and I1 cannot be made equal to zero. An extinction angle g must be introduced at least equal to g0 corresponding to the recovery time of the valve 1 so that the commutation of the valve 1 is finished in advance (g0/w sec) before the instant C6 is reached. A

Control of HVDC Converter and Systems


portion of the voltage across the valve 1 when the bridge is inverting is shown in Fig. 4.2(d). After that instant C6, the cathode to anode voltage of the valve 1 becomes positive and if the gate of the valve 3 has not fired by that instant, the valve 1 will not conduct. A new angle g occupies a relatively small interval during which the cathode–anode voltage is negative. An extinction angle smaller than g0 will result in commutation failure, because enough time should be allowed for the valve 1 to regain its blocking property. An extinction angle larger than g0 will result in unnecessary reactive volt-ampere demand. From this it is implied that the most desirable inverter operating condition is the safest and involves constant extinction angle control.

4.5.2 Constant


Let Vd represent the voltage at the inverter terminals of Fig. 3.14 (Vd = Vd). Then from the rectifier current2 voltage characteristic, Vd is given by Vd = Vdo1 cos a – (RC1 + R) Id


And for constant b inverter operation, the current-voltage characteristic is given by Vd = Vdo2 cos b + (RC2) Id


Fig. 4.3 Operation diagram when rectifier and inverter stations are not compounded

The above factors can be explained with reference to Fig. 4.4. It is assumed that normal current is flowing and b is adjusted so that g > g0 as shown in Fig. 4.4(a). If there is a sudden symmetrical reduction in 3-phase supply voltage as shown in Fig. 4.4(b) and the current remains more or less same, the same current is to be commutated at reduced voltage. The shaded areas in the two figures have to be equal. As a result, g of


HVDC Transmission

Fig. 4.4 Symmetrical reduction of system voltage and commutation

Fig. 4.4(b) is less than g0 with subsequent commutation failure. But if b is kept at very large value in anticipation of voltage reduction, the inverter VAR demand would be much more, which is undesirable.

4.5.3 Constant


The control operation can be explained by studying the expression (3.35) which describes the control under steady state as Id =

VsL (cos g - cos b ) 2w Ls


For a particular value of direct current Id and valve side phase-to-phase voltage VsL, the expression will yield the correct b so that there is still an angle g remaining after the completion of the commutation. If commutation is continuously performed as per the estimated value of b from the expression (3.35), and the valves are fired accordingly, there will still be a substantial risk of commutation failure for the following reasons. 1. The computation is based on the reduction of 3-phase symmetrical voltage. But vast majority of faults are asymmetrical. A line-to-line fault will not only reduce the commutating voltage but also increase or decrease the available commutation angle as shown in Fig. 4.5 when the phase voltage of R is reduced. 2. In spite of the use of a large smoothing inductor, the rate of change of direct current may be appreciable after the reduction of an AC system voltage, which increases m.

Control of HVDC Converter and Systems


Fig. 4.5 Asymmetrical reduction of AC system voltage of the phase R

3. Even with ideal controllers, commutation failure can occur if the voltage reduction takes place just before the computed instant of firing or after firing of a valve. It has been shown by Posse in his work, that this commutation failure is not of a serious nature and the inverter will revert to normal operation as long as the firing of the next valve is initiated at the correct instant. The constant extinction angle controller is a device that consists of a separate analogue/digital computer for each group of valves connected to the same phase. Catering to each group separately is necessary because complete balance between the phase voltages must not be taken for granted after asymmetrical fault conditions. Each computer continuously calculates and provides an output pulse when the correct instant for firing a valve has approached, for safe commutation. During the commutation process, a computer must take into account the various items listed below. 1. 2. 3. 4.

The amplitude of the commutating voltage The phase of the commutating voltage The magnitude of the direct current The rate of change of the direct current

Commutating voltage has already been defined in the previous section. The voltage is circulating the commutating current when the two valves of the same row (1, 3 or 3, 5, etc.) are conducting simultaneously. Before commutation this voltage appears across the valve which is to be fired. In other words, the commutating voltage is the voltage between two successive phases, namely the phase to which the conducting valve is connected and the other phase to which the next valve is to be fired, in an order of the same group. The above control is known as ‘consecutive control’ which was used in Gotland and Cross channel schemes.



DC system characteristics with constant a and constant g controls are shown in Fig. 4.6. The two characteristics have a negative slope and the intersection point of the two characteristics determines the operating point P (Vd, Id). When the AC system voltage decreases at the inverter end, the DC voltage falls and the inverter characteristic will shift downwards parallel to it. The operating point will move to Q, resulting larger current (Id > Id ). This is undesirable since the valves may be overloaded. Although, the automatic constant g 2 1 controller may prevent commutation failure, it is important that the valves should be operated strictly within their current rating. This suggests that constant current regulation on the rectifier side is clearly desirable.


HVDC Transmission

Fig. 4.6 Operation with constant g of inverter

The rectifier is generally compounded with constant current controller in addition to natural constant firing angle control [Constant Ignition Angle control (C.I.A.)] as shown in Fig. 4.7. The current setting of the rectifier controller can be adjusted for any desirable current setting Id , Id , etc., and therefore, for any power 1 2 transfer.

Fig. 4.7 Operation with rectifier with constant a and constant current control and inverter with constant g control

The rectifier regulator consists of a summing amplifier which compares the actual current with a set value of current. If the actual current is less than the set value, there is no signal output and the rectifier operates on the constant a characteristic. If the current is more than the set value, a signal is sent to the pulsing units, so that a is changed until the difference of currents is reduced to a small value. The gain of the amplifier determines the slope of the constant current portion of the characteristic. This slope must be less than a certain

Control of HVDC Converter and Systems


value otherwise due to the negative resistance of the compounded inverter hunting during change of the DC voltage will take place. When the system voltage on the inverter side falls to DD from CC (Fig. 4.7), the operating point P changes to Q with constant current controller employed with the rectifier, but no untoward change take place since the current remains more or less at the same value when the operating point P is changed to Q. But if the rectifier system voltage drops, the rectifier constant a characteristic will be displaced from AA to BB as shown in Fig. 4.7 and the system will then run down since the inverter voltage (Vdo cos g) is greater 2 than (Vdo cos a) the rectifier voltage. The continuity of power cannot be maintained unless inverter current 1 compounding is also introduced.

4.6.1 Current Compounding of Inverter As stated in the previous section, if the continuity of power supply is to be retained, a constant current regulator in the inverter station must be incorporated. The operation of a DC system when both the stations are compounded for constant current is shown in Fig. 4.8. P is the operating point under normal conditions, but when the rectifier voltage falls, the operating point shifts to Q, and then CC control of the inverter is incorporated. And if the voltage of the inverter falls, the characteristic shifts down from DD to EE and the new operating point is R. In all these cases the current does not change enormously beyond a certain value. When the inverter characteristic is higher than the rectifier characteristic, as at the point Q, the inverter works at constant current and the rectifier at constant voltage. When the rectifier characteristic is higher than the inverter, the rectifier works at constant current with inverter at constant g control (constant voltage). The system will not run down due to changes in the AC voltage or blocking of one of the bridges on either side.

Fig. 4.8 Both stations compounded for constant current control

Under normal conditions, the rectifier can be considered as a source of direct current and hence controls the current (Id) of the DC systems. The inverter acts as a load and therefore controls the DC voltage (Vd).


HVDC Transmission

The difference between the current controller settings of the two stations is called current margin (Idm). In order to avoid conflict between the two current controllers at both the ends, the rectifier current controller is provided with a higher current order such that Idi = Idr – Idm where


Idi is the current order of the inverter Idr is the current order of the rectifier

Idm is the current margin usually about 10 to 15% of the rated value and is essential to avoid simultaneous operation of the current regulators (controls), thus avoiding instability. For reduction of load, both current regulators must be set at a lower current setting with original margin maintained. This demands a high speed communication link between the two stations. When the operating point P falls to R as shown in Fig. 4.8, cos a is decreased and VAR demand on the rectifier side AC system is increased. Under these circumstances a can be restored to the original value by the use of a tap-changer and thereby improving the p.f. The signal to the transformer tap-changer can be obtained either from a firing-angle measuring unit or from a power-factor measuring relay on the AC side. Usually the station with a higher current margin will act as a rectifier and the other as an inverter as shown in the Fig. 4.9. In Fig. 4.9(a), the station 1 has higher voltage characteristic and current margin, and therefore acts as a rectifier. In Fig. 4.9(b), the station 2 has higher voltage characteristic and the operating point A is on the current control characteristic of the inverter.

Fig. 4.9 Steady state characteristic and operating point

With incorporation of constant current controllers in both the stations, the system becomes hybrid control. The power delivered from the inverter to the AC system is approximately proportional to the current. The change in the inverter control angle from no-load to full-load is small, and therefore the change in the inverter back-voltage is small.

Control of HVDC Converter and Systems


It can be understood that when the receiving end voltage is kept constant, the power delivered is controlled by the level of current transmitted, and this current setting is kept constant whatever the circumstances, until a change in power flow is ordered. A great advantage of constant current control compounding is the increase in stability of operation of both the stations under disturbed system conditions. A short circuit in the DC line will have no adverse effects. This is very important in the absence of a reliable DC circuit breaker; yet to be developed. The three basic modes of converter control are (a) Constant ignition angle characteristic or natural voltage characteristic (i.e. a = 0°) (CIA) (b) Constant current characteristic of rectifier/inverter (CCC) (c) Constant extinction angle characteristic (CEA control) of the inverter The voltage ceilings, i.e. a = 0 characteristics and g = gmin characteristics can be varied by changing the tap-setting of the converter transformer provided at both the ends.



Power reversal can be carried out by changing a and g over their entire range so that the rectifier (Station 1) operates at a close to 180° and the inverter (Station 2) operates at g close to 0°.

Fig. 4.10

Additional control

4.7.1 Power Reversal Characteristics The sign of the output voltage of the converter changes depending upon the value of a, and the firing angle I. The same station can work as a rectifier when a < 90° and as an inverter when a > 90°.


HVDC Transmission

The combined characteristics of the converter stations at both ends are shown in Fig. 4.10. To have the line voltage Vd as positive, the characteristic of the inverter is to be turned around Id - axis as shown in the figure. The station with higher current margin will act as a rectifier as shown in Fig. 4.10(a). The operating point A decides whether the station 1 acts as rectifier and the station 2 as inverter, since current flows from the station 1 to the station 2. The direction of power transmission can be changed by manipulating current margin with a change of polarity of transmission voltage. In Fig. 4.10(b), the current margin of the station 1 is less than the station 2. The operating point A lies in the 4th quadrant with reversal of the polarity of Vd. It means that the station 2 acts as rectifier and the station 1 as inverter. A precaution to be considered here, is that although the rectifier is allowed to become an inverter at certain times (for example, to clear DC line faults), an inverter is not generally allowed to become a rectifier without permission. Hence, additional controls are provided (indicated by broken lines), which cut-off the control at a particular value a or g.

4.7.2 Correction to Inverter Characteristics Consider the typical Vd – Vd characteristics illustrated in the Fig. 4.11(a). If the rectifier natural characteristic (a = 0°) decreases, then the operating point B will be poorly defined and this will cause power fluctuations. To overcome this, the inverter characteristics (position of transition from current control to voltage control) is given a positive slope, i.e. constant a characteristic instead of constant g characteristic, as shown in Fig. 4.11(b).

Fig. 4.11


Modified inverter characteristic


Mainly due to faults in the AC system on the rectifier or inverter side, the voltage on the DC link is reduced. Low AC voltage due to faults on the inverter side can result in persistent commutation failure because of an

Control of HVDC Converter and Systems


increase in the overlap angle. In such cases, it is necessary to reduce the DC current in the link to a level that leads to reduced DC voltage at the rectifier end. Reduction of current also relieves the valves in the inverter which are overstressed due to continuous overcurrent flow in them. If the low voltage is due to faults on the rectifier side of the AC system, the inverter has to operate at larger value of g, at very low power factor demanding excessive consumption of VAR which is undesirable. Thus, it becomes useful to modify the control characteristics to include voltage dependent current order limits (VDCOL). This is illustrated in Fig. 4.12 which also shows current error characteristics to stabilise the mode when operating with DC current in the limits Id and Id . 1


Fig. 4.12 VDCOL characteristics of the converter

The characteristic CD and DH show the limitation of current due to the reduction in voltage. When the system voltage drops considerably, the DC current is reduced from Id to Id¢ linearly and maintained at Id¢ below the 1 1 l voltage Vd . The inverter characteristic also follows the rectifier characteristic to maintain the current margin 2 except for K ¢ K, which is due to the lower limit imposed on the delay angle of the inverter. VDCOL contains control unit to reduce the current order.

4.8.1 Summary of Control Mechanisms Let us summarise the various control schemes associated with a DC link. As mentioned in the beginning, it is desirable to control current and regulate voltage simultaneously in the link. The question is which terminal should be assigned the task of current control and which should control the DC voltage? Under normal conditions, it is desirable to have current control at the rectifier station because of the following considerations. (a) By reducing a, the power in the DC link can be increased, which also improves the power factor at the rectifier at higher loadings and minimises the reactive volt-ampere demand. (b) The demand of VAR at the inverter station can be kept low by working at minimum g. It should be remembered that current control at the inverter worsens the power factor at higher loadings as g has to be increased with load. Higher values of g imply higher losses in the valve-snubber circuits.


HVDC Transmission

(c) For better voltage regulation it is necessary to adopt current control at the rectifier, and minimum extinction angle control at the inverter end, than operating with minimum delay angle at the rectifier and current control at the inverter end. (d) The current during DC line faults is automatically limited with rectifier station in current control mode. It is economical to operate the inverter at a constant extinction angle (CEA) which is slightly above the absolute minimum required for the commutation margin, but there is a need to maintain a minimum extinction angle of the inverter to avoid commutation failure. This results in reduced converter losses, reduced cost of the inverter station and reactive power consumption. However, the main drawback of CEA control is the negative resistance characteristic of the converter, which makes it difficult to operate stably when the AC system is weak (with low short circuit ratio). Constant DC voltage (CDCV) control or constant AC voltage (CACV) control are the alternatives that could be used at the inverter. Under normal conditions, the rectifier operates at constant current (CC) control and inverter at CEA control. But during the conditions of reduced AC voltage at the rectifier, it is necessary to shift the current control to the inverter to avoid run down of the DC link when the rectifier control hits the minimum limit. This implies that current controller must also be provided at the inverter in addition to CEA controllers as stated in previous sections. A smooth transition from CEA to CC takes place whenever the link current starts falling. To avoid a clash of two current controllers at both the stations, the current order at the inverter is kept below that of the rectifier by an amount called current margin which is generally about 10% of the rated current. The power reversal in the link can take place by reversal of the DC link voltage. This can be achieved easily by increasing the delay angle a at the station originally operating as rectifier, while reducing the delay angle at the station initially working as inverter. Thus, it is necessary to provide both CEA and CC controllers at both the terminals. The purpose of on-load tap-changer control at the inverter is to maintain constant DC voltage (when the inverter is in CEA control). The tap-changer at the rectifier station is designed to maintain a within 10° to 20° in order to maintain a certain voltage margin around 3% for the purpose of current control. The feedback control power in the DC link is not desirable because of the following reasons. (a) At low DC voltages, the current required is excessive to maintain the required level of power. This is undesirable because of excessive requirements of reactive power which further reduce the voltage level. (b) The constant power characteristic results in negative damping and degrades dynamic stability.



It has been mentioned in previous sections that control of HVDC converters is essential. An ideal control system for an HVDC link must satisfy the following requirements. 1. Symmetrical firing of the valves under steady state conditions. 2. Instant of firing of the valves to be decided with regard to permissible valves of commutation voltage for the rectifier and commutation margin for the inverter.

Control of HVDC Converter and Systems


3. The consumption of reactive power must be minimised in converters and subjected to the condition that it is achieved without an unacceptable risk of commutation failure. 4. The controls must take care of normal variation in voltage and frequency of AC supply network which may disturb the DC link. 5. Some degree of prediction of the optimum instant of firing of inverters, based on the actual network voltage and direct current, without involving the risk of commutation failure is essential. 6. Current control devices must have sufficient speed and stability margin to cope with changing reference values and disturbances. 7. Must have facilities for continuous operation ranging from full rectification to full inversion. The theory presented in Chapter 3 is based on perfectly symmetrical and sinusoidal waveforms with firing angles (a > C) occurring at exactly equal intervals in the appropriate cyclic sequence. Deviations from such ideal conditions give rise to two basically different control methods which are discussed in this section.

4.9.1 Control Hierarchy Control functions required for an HVDC link are carried using the hierarchical control scheme shown in Fig. 4.13. The master controller for bipole is situated at one of the terminals and is provided with the power order from the system controller. It also has other information regarding AC voltage at the converter bus, DC voltage, etc. The master controller transmits the current order to the pole-control units, which, in turn, provide a firing angle order to the individual converters. Converter control also oversees valve monitoring and firing logic through optical interface. It also contains bypass pair selection logic, tap-changing control, commutation failure protection, converter start/stop sequences, margin switching, and valve protection circuits.

Fig. 4.13 Hierarchical control scheme for a DC link


HVDC Transmission

Pole control includes pole protection, DC line protection and optional converter paralleling and deparalleling sequences. The master controller which oversees the complete bipole includes the function of frequency control, power modulation, AC voltage and reactive power control, and torsional frequency damping control; in addition to overseeing of pole paralleling sequences and transient pole current control, which increases when there is outage of a pole, balancing of pole currents and communication of the power/current order to the remote terminal. The pole and converter control block diagram is shown in Fig. 4.14. This illustrates the basic control functions. The extinction angle or current controller generates a control signal Vc, which is related to the firing angle required. The gate pulses are generated by the firing angle controller in response to the control signal Vc. The selector picks up the smaller of the a determined by the current and CEA controllers.

Fig. 4.14 Block diagram of pole and converter controllers

4.9.2 Firing Angle Control The operation of CC and CEA controllers is closely linked with the method of generating gate pulses for valves in a converter. Following are the two basic requirements for generating firing pulses for HVDC valves. There are two types of firing controls: (i) Individual Phase Control (IPC) (ii) Equidistant Pulse Control (EPC) IPC was used in the past and has now been replaced by EPC for reasons explained below.

4.9.3 Individual Phase Control (IPC) This scheme was used in early HVDC stations. In this scheme, firing instant is determined individually for each valve so that a constant delay or extinction angle is maintained for all the valves in steady state with

Control of HVDC Converter and Systems


respect to the instant of crossing of voltages. In other words, the phase position of the control pulses is determined separately for each valve and is directly synchronised to commutation voltages by relating the firing to zero crossing of the commutation voltages. This principle was used in most mercury arc valves around the world. As this scheme is characterised by a separate control of phase delay angle a for each valve, it requires six parallel delay circuits. There are two basic approaches to individual phase control system: (i) Cosine control of phase delay (ii) Linear control of phase delay

4.9.4 Cosine Control of Phase Delay There are several versions of this method. In this scheme, a control voltage common (Vc) to all delay circuits generates pulses at the crossing point of the control voltage and the appropriate AC line voltage. This is illustrated in Fig. 4.15(a). The phase delay angle a is given by a = cos–1 (Vc/Vm)

Fig. 4.15 Individual phase control waveforms



HVDC Transmission

The output voltage of the converter is given by Vd = Vdo cos a =

Vdo Vm


◊ Vc = kVc

Therefore, the cosine control system results in a linear transfer characteristic. Besides, the output voltage is independent of changes in the input AC voltage and thus, has a self-regulating feature. However, as the firing angle a approaches zero, Vc approaches the peak value Vm and a becomes very sensitive to both Vc and Vm and a small error in either leads to high inaccuracy.

4.9.5 Linear Control of Phase Delay In this scheme, a control voltage (Vc) common to all delay circuits, generates pulses at equal time delays from zero crossing of AC voltages. This is illustrated in Fig. 4.15(b). The firing angle is proportional to the control voltage. a = k1Vc Vd = Vdo cos (k1Vc)

(4.10 )

This makes the transfer characteristic nonlinear. However, accuracies of the order of ±l° in the firing angle are normally possible. In this scheme as shown in Fig. 4.15(c), six timing (commutation) voltages are derived from the converter AC bus via voltage transformer. The six gate pulses are generated at a nominally identical delay time, subsequent to the respective zero crossing of the voltages. The instant of zero crossing of a particular commutation voltage corresponds to a = 0 of that valve. The delays are produced by independent delay circuits and controlled by a common control voltage Vc derived from the current controllers.

Fig. 4.15(c)

Control voltage ‘Vc’ is derived from the current controller

A major drawback of the IPC scheme is that the firing delay angle for each thyristor is dependent on the corresponding line voltage. Therefore, asymmetry or distortion in the AC voltages will result in different phase delay angles for different valves, and hence the firing intervals will differ from 60°. Consequently, an

Control of HVDC Converter and Systems


unintentional feedback loop is established from distortions in AC voltage through the control system, delay angle and phase current fluctuations, and back to the AC voltages. This inaccurate pulse spacing will produce abnormal noncharacteristic harmonics in the AC line current apart from normal harmonics. It is expensive to filter out lower order harmonics. In a weak AC system (high impedance) this may lead to harmonic instability. This is also one reason for not using individual phase control in modern HVDC schemes for which the AC networks are often considered weak. The problem is aggravated at frequencies for which filter impedance and system impedance are parallel. But the main advantage of this scheme under protective CEA control is its ability to provide highest DC voltage possible under asymmetrical or distorted supply waveforms.

4.9.6 Equidistant Pulse Control (EPC) In this scheme, no direct synchronisation of the control pulse to the AC voltage is applied and is used in all modern HVDC stations. It is primarily useful for successful operation of a weak AC system. The basic principle is the production of a single pulse spacing at equal intervals of (1/pf) through a ring counter, where p is the pulse number and f is the system fundamental frequency. This method was suggested by Ainsworth using a phase locked oscillator to generate the firing pulses. There are two methods of the EPC scheme: (i) Pulse Frequency Control (PFC) (ii) Pulse Phase Control (PPC) Pulse Frequency Control (PFC) In this method, the frequency of a voltage controlled oscillator (VCO) shown in Figs. 4.16(a) and 4.17(a) is determined by the control voltage Vc which is related to the error in quantities like current, extinction angle (g) or DC voltage being regulated. Under steady state, the frequency is equal to the product of the pulse number and nominal supply frequency of the AC system (pf ). The input to the oscillator is (at six times the supply AC frequency) T/6 and an error voltage (Vc) is obtained from the difference between the reference voltage Vr and a feedback quantity to be controlled, such as DC current, etc. A constant slope ramp function generator is controlled from the output of the oscillator starting

Fig. 4.16(a) Voltage controlled oscillator


HVDC Transmission

from zero voltage at each firing instant. This ramp voltage is compared to the difference between the voltage T/6 and the control voltage V in a level detector and a pulse is generated at each instant of equality. When Vc = 0, the distance between consecutive pulses is exactly 60° (electrical), corresponding to steady state condition. The pulse train form VCO is checked for necessary conditions like Vmin -condition before a triggering pulse is generated. The triggering pulse train is decoded using a ring counter to channelise them for different valves 1 to 6. These channelised control pulses are processed in pulse logic unit before firing the valves. The pulse logic unit gives the operational freedom for pulse blocking/deblocking and for bypass pair selection. Figure 4.16(b) shows how an increase in the control signal Vc will result in delaying the triggering pulse to meet the new value of a ordered. As the control voltage changes, the error signal changes the frequency. Thus, control of the pulse is an integral characteristic. When the ordered change is obtained, Vc becomes zero and the delay angle remains at the new position.

Fig. 4.16(b) Generation of control pulses

The simplified block diagram of the PFC system is shown in Fig. 4.17(a). The voltage controlled oscillator (VCO) consists of an integrator, comparator and pulse generator. The ring counter is driven by the output of the pulse generator. The pulse generator is also useful for resetting the integrator. The instant (tn) of generation of firing angle is determined from the following equation: tn

Ú k1 (Vc + V1 ) dt = V3

tn - 1

Fig. 4 .17(a) Block diagram of a PFC system


Control of HVDC Converter and Systems


where V1 is the bias voltage, V3 is proportional to the system period, Vc is the control voltage and k1 is the gain of the integrator; under steady condition Vc = 0 and from the expression (4.11) it can be shown that k1V1 (tn – tn – 1) = V3


We know that (tn – tn – 1) = 1/pf


and in the steady state, the gain of the integrator is chosen as k1 = pf

V3 V1


A drawback of the circuit shown in Fig. 4.l7(a) is that it does not carry frequency correction control when the system frequency changes from f. Ainsworth introduced frequency correction control as shown in Fig. 4.17(b) and according to him, V3 can be derived from Fig. 4.17(b) as V3 = V2 /(1 + ST1) V2 = k1V1 (tn – 1 – tn – 2)


(4.15) (4.16)

Fig. 4 17(b) Ainsworth correction for PFC

Working of the circuit as designed by Ainsworth is similar to PFC but for the method of handling the control voltage Vc. The structure of the controller is the same as in Fig. 4.16(a). However, Vc is now summed up with V3 instead of V1. Therefore, the instant tn of the pulse generation is given by tn

Ú k1V1dt

= V3 + Vc


k1V1 (tn – tn – 1) = V3 + Vc


tn - 1

It can be shown from (4.17) that ÊT ˆ with Vc = 0, the interval between consecutive pulses in steady state is equal to 1/ pf Á ˜ . Ë 6¯ The pulse frequency can be controlled as shown in Fig. 4.16(b) by an exponential decaying Vc which changes the delay angle by decreasing the pulse frequency in between the period t1 and t2. Frequency correction in the scheme is obtained by either updating V1 in response to the variation in system frequency or including another integrator in the CC or CEA controller.


HVDC Transmission Pulse Phase Control and Principle of Phase Locked Oscillator The alternative control philosophy to (IPC) is given in Fig. 4.18 which is a voltage control oscillator that delivers a train of pulses at a frequency directly proportional to DC control voltage Vc.

Fig. 4.18 Pulse phase control and voltage control oscillator

The train of pulses is fed to a six-stage ring counter. In this only one stage is on at a time. The on stage is stepped sequentially from position 1 to 6 by the oscillator pulses. Each ring counter produces a sharp output pulse when it is in on stage, once in a cycle. Under steady state conditions, the complete set of six pulses normally occurs at successive intervals of 60°. The stop pulses are also obtained from the ring counter but two stages later. For example, the start pulse of the valve 1 is from the stage 1 and the stop pulse for the valve 1 is from the stage 3 after 120° electrical degrees. Control hardware consists of one oscillator and one ring counter per bridge. Various control modes are in operation but they differ only in the type of control loop which provides the oscillator control voltage Vc. The phase of the firing pulses generated by the ring counter with respect to the AC system voltage is arbitrary. But the value of a is the same for each valve when the AC system fundamental voltage is balanced.

Control of HVDC Converter and Systems


In practice if a simple independent oscillator is used, there will be a drift in frequency and phase relative to the AC system voltage. Therefore, some method of phase locking the oscillator to the AC system is required. This is obtained by connecting Vc as shown in Fig. 4.18 in a conventional negative feedback loop for constant current or constant extinction angle as explained below.

4.9.7 Constant Current Control In the constant current control system, the feedback signal is only Vc. This signal is derived from the amplified difference (error) between the current reference and the measured DC line current, which forms a simple negative feedback control loop tending to hold the current at a fixed value very close to the reference value. To understand the operation of the loop, imagine that the current is nearly equal to the reference value so that the amplified error (Vc) is precisely such a value that is required to give an oscillator frequency equal to six times the frequency of the AC supply. The valve gate pulses from the ring counter will have certain phase difference with respect to AC supply voltage. Suppose that this phase difference is identical to the delay in firing angle a and is able to give correct converter DC output voltage to overcome the back emf of the DC link resulting correct DC current. This corresponds to steady state operation. The current loop is self-correcting against disturbances of any source. For example, a drop in the back emf in the DC system causes temporary increase in current which reduces Vc. This effect slows down the oscillator, thus retarding its phase and finally increasing a. This tends to decrease the current again and the system is forced to settle down at the same current, with the same Vc and oscillator frequency but for a different (phase) a. 1. Voltage control oscillator consists of 1. Integrator 2. Comparator 3. Pulse generator 2. Ring counter decodes the pulses to channelise the control pulses for different valves. 3. EPC (Principle of phase locked oscillator current) D-CC-T (Direct current transducer) EPC—Equidistance pulse phase control 4. A—Under steady state condition Vc2 = negative feedback voltage B—Under transient conditions Vc3 = the addition feedback control voltage when g < g min The control system will also follow system frequency variations, in which case the frequency of the oscillator changes, and this results in a different f and therefore current, but the current error is made small by using high gain amplification. The constant current control scheme explained above is the main mode of operation during rectification under normal conditions and it is also used during inverter operation under asymmetrical fault conditions. The response of the control system is fast but its effect will be reduced by the DC line due to the presence of inductance, capacitance and smoothing reactance.


HVDC Transmission

4.10 INVERTER EXTINCTION ANGLE CONTROL (EAG) The extinction angle control mode of the inverter carried by the negative feedback loop is very similar to the current loop illustrated in Fig. 4.18. The difference between g-setting and measured g is amplified and the amplified signal provides Vc as before. However, it differs as g is a sampled quantity rather than a continuous quantity. For each valve, the extinction angle g is defined as the time difference between the instant of current zero and the instant when the anode voltage next crosses zero and goes positive. Typical waveforms of g-measuring techniques are shown in Fig. 4.19.

Fig. 4.19 Waveforms of g-control circuit

For each bridge there are 6 values of g to be measured, which under symmetrical steady state operation are identical. However, under unbalanced conditions, the valve with greatest risk of commutation failure is the one having the smallest g. Thus, smallest measured g produces the most negative output and causes its diode to conduct due to signal A. This produces negative feedback voltage Vc . During steady state operation and full 2 inversion Vc controls the oscillator, holding the smallest g at a predetermined value by closed loops control. 2

Under the conditions explained above Vc is zero, because the inverter current control setting is less than 1 the DC line current setting of the rectifier CC control. Therefore, the inverter CC loop tries to decrease a by making Vc as low as possible. The minimum Vc is clamped to zero volts and thus during normal inverter 1 1 operation the CC control loop is ineffective. But during transient conditions (asymmetrical faults) the component B is an additional feedback voltage (Vc ) 3 applied when g < gmin. A sudden impulse is then applied to the VCO, which has an integrating characteristic and can thus suddenly shift the phase (a ) by an appropriate amount.

4.10.1 Transition from Extinction Angle to Constant Current Control Under normal conditions, the current setting for the inverter operation is less than that of the rectifier at the sending end. Under these conditions Vc in Fig. 4.18 is zero, the current control amplifier is saturated and the 1 converter operates at constant EAG (g ) control at full inversion.

Control of HVDC Converter and Systems


But in the event of sudden system disturbance due to either rise in the AC system voltage at the inverter end or a dip in the voltage of the DC link, the current in the link decreases; consequently the current amplifier comes out of saturation and Vc becomes positive. This additional input to VCO causes advances of the phase 1 of the gate firing pulses which increases g and the converter takes over constant current control.

4.11 PULSE PHASE CONTROL In this system as illustrated in Fig. 4.20, the frequency of the pulse train depends on charging and discharging voltage of a capacitor. This is maintained between a fixed limit ± DV around the control voltage Vc. The charging of the capacitor is achieved through a voltage controlled current source which makes the slope of the ramp voltage across the capacitor constant. Therefore, change of the control voltage Vc causes a proportional change in the control angle a as can be seen from Fig. 4.21. The response of this system is fast because it does not have an integral characteristic. However, to achieve a unique relationship between Vc and a, and to ensure a synchronisation of control pulses with the AC system, an auxiliary control loop for the converter control angle a is required.

Fig. 4.20 Pulse phase control block diagram

Fig. 4.21

Equidistant pulse control waveforms: pulse phase control (PPC)


HVDC Transmission

4.11.1 Disadvantages of EPC Scheme Even though EPC scheme is less complex than IPC and generation of abnormal harmonics are avoided, it has certain drawbacks. The first drawback is that EPC results in less DC voltage as compared to IPC under unbalanced voltage conditions, which may arise due to single line-to-ground fault in the AC system and may persist for 10 cycles due to stuck breakers. Under these conditions it is desirable to increase DC power in the link to the maximum possible by reverting to IPC control. The transition from EPC to IPC under fault conditions should be carried out carefully. EPC scheme also results in higher negative damping contribution to torsional oscillations when HVDC is the major transmission link from a thermal station.

4.12 STARTING AND STOPPING OF A DC LINK 4.12.1 Energisation and De-energisation of a Bridge Consider a converter station with s series connected bridges. It is possible to take one bridge out of service only by blocking the bridge and bypassing the bridge. This is because of the fact that just blocking the pulses does not extinguish the current in the pair of valves that are left conducting at the time of blocking. The continued conduction of the pair injects AC voltage into the link, which can give rise to current and voltage oscillations due to lightly damped oscillatory circuit in the link, formed by smoothing reactor and line capacitance. The transformer feeding the bridge is also subjected to DC magnetisation when DC current continues to flow through secondary windings. The bypassing of the bridge can be done by providing a separate bypass valve or by activating a bypass pair in the bridge. The bypass valve is used with mercury arc valves where the occurrence of arc makes it impractical to use bypass pairs. As a practice, bypass pair is used with thyristor valves as it saves the cost of an extra valve. The process of de-energisation of a bridge is given with reference to Fig. 4.22. It is assumed that valves 2 and 3 are conducting initially when the blocking Fig. 4.22 A converter bridge with isolators command is given. With the selection of bypass pairs 1 and 4, the commutation from valves 2 to 4 is the usual manner, but the commutation from valves 3 to 5 is prevented. In case of a predetermined choice of the bypass path, the time lapse between the blocking command and the current transfer to bypass path can vary from 60° to 180° for a rectifier bridge. This time can be reduced from 60° to 120° if the bypass pair is chosen such that the valve with the lower valve number carrying current at the instant of blocking is included in the bypass pair. In the inverter, there is no time lag involved in the activation of the bypass pair. The voltage waveforms for the rectifier and the Fig. 4.23 Voltage waveforms during inverter are shown in Fig. 4.23 respectively, without taking the de-energisation effect of overlap.

Control of HVDC Converter and Systems


By closing the switch S1 (mechanical), the current from the bypass pair is diverted. Now the bridge can be isolated with the help of isolators S. The switch S1 and the isolator pair S are interlocked such that one or both are always closed. The energisation of a blocked bridge is carried in two ways. The current is first diverted from S1 to the bypass pair. This is possible only when S1 generates the required arc voltage and to minimise this arc voltage the circuit inductance must be small. In case the bypass pair fails to take over the current, S1 must close automatically if the current in that does not become zero after predetermined time interval. Sometimes switch S1 will be AC breakers with sufficient arc voltage but with induced breaking capacity. In the second stage of energisation, the current is diverted from the bypass pair. This can take place instantaneously for a rectifier when there is no overlap. However, for the inverter, the transition requires some time lag. The voltage waveforms during energisation are shown in Fig. 4.24. To avoid operation at high delay or extinction angles, the de-energisation of a bridge at the rectifier/inverter station is accompanied by the de-energisation of the bridge at the inverter/rectifier station.

Fig. 4.24 Voltage waveforms during energisation

4.12.2 Start-up of a DC Link There are two start-up methods depending upon the duration of gate pulse (short/long). The long gate pulses’ lost for 120°. Start-up with Long Gate Pulse Firing In this case, the extinction of current during start-up is not difficult. The sequence of starting as follows: 1. Deblock inverter at about g = 90°. 2. Deblock rectifier at a = 85° to force low direct current. 3. Ramp-up voltage by inverter control and the current by rectifier control. Start-up with Short Gate Pulse Firing In this case, the current extinction during start-up is a problem as the valve with forward bias is not put into conduction when the transient current in that falls below the holding current. The sequence of starting is as follows: (a) (b) (c) (d) (e) (f)

Open bypass switch at one terminal Deblock the terminal and load to minimum current in the rectifier mode Open bypass switch at the second terminal and commutate current to the bypass pair Start the second terminal also in the rectifier mode The inverter terminal is put into the inversion mode Ramp-up voltage and current


HVDC Transmission

Before raising current through the link, the voltage of the system is raised. This procedure enables a check on the insulation of the system before pumping power. The gradual increase of power eliminates stresses on the generator shaft. This also reduces switching surges in the line. Depending upon the short circuit ratio (SCR) of the system, the rate of increase of power is determined. Weaker section with low SCR requires fast restoration of DC power for maintaining transient stability. But, high ramping rates of power in such cases can give rise to large voltage drops due to a requirement of reactive power at the converter. Such voltage drops may lead to failure of commutation at the inverter. The permissible rate of increase of power through the link lies in the range 2 to 10 p.u./second which requires start-up time of more than 100 to 500 ms.

4.13 CONSTANT POWER CONTROL When current control is switched over from rectifier to inverter, there is loss in power transfer corresponding to the current margin, since the current order of the inverter is smaller. There is a change in voltage drop in the DC link. If it is desired to maintain DC power, then current is to be increased as illustrated in Fig. 4.25. When rectifier is on CC control, P1 is the original operating point. When the CC control is changed to inverter, P2 is the operating point and there is reduction in power in the DC link. In order to restore the power level in the DC link, first the current order of the rectifier must be increased and then the inverter, so that the new operating point is P3 on the original power order. But if the current order of the inverter is increased first, then the new operating point will be P4 as shown in Fig. 4.26 and the DC power is reduced instead of increasing, and the voltage is also reduced.

Fig. 4.25 Reduction in DC power when the current order is changed to inverter

Fig. 4.26 Current order of inverter is increased first

4.14 CONTROL SYSTEMS FOR HVDC CONVERTERS The basic control system employed for HVDC converters is shown in Fig. 4.27. The tap changer control (TCC) system used for rectifier, controls the firing angle a so as to keep it at 10–15° as far as possible, but the TCC control at the inverter end controls the DC voltage for it to be maintained at rated value.

Control of HVDC Converter and Systems


Fig. 4.27 Basic control system for HVDC converters

When the AC voltage at the rectifier end changes, the current in the link changes and the current system responds by changing a which is faster than TCC control in order to keep Vdo1 cos a as constant. Then TCC system compares the a response with the reference value and orders TCC to vary the taps in order to change Vdo1. The correction for the change in AC voltage at the inverter end is somewhat complex in nature. Since the TCC control is slow, the first action is momentarily initiated by change in a. But before the TCC of the rectifier comes into operation, TCC of the inverter completes the correction action and the value of a is brought back to the rated value to maintain the current. In point-to-point transmission, one station acts as lead station where current order is computed and the other station acts as trail station. The various controls employed in a lead station is shown in Fig. 4.28 and in a trail station is shown in Fig. 4.29.

4.14.1 Selection of Lead and Trail Station It is preferable to have the lead station as one whose AC quantity is to be controlled so that the fast response of the DC link will not be affected by any delay in communication or in the worst case failure of communication, resulting loss of control. In case the current control is with trail station, on failure of telecommunication link, the current control has to be shifted to the lead station either by temporarily increasing the limit of amin if the lead station is an inverter or by changing the limit of gmin if the lead station is a rectifier. Power Order Setting Power ramping speed and power order are set from either the responses obtained from the local station or from the remote station where the load dispatch centre is located or from the other station and are fed to the stepping logic function device. An enter signal is given to the stepping logic function when a change of power is to be ordered. This initiates the ramp power order. To this power order P0 thus obtained, additional contribution (D P0) generated from the frequency changes in one or both networks can be as shown in Fig. 4.28.


HVDC Transmission

Fig. 4.28 Control system for a lead station

Fig. 4.29 Control system for a trail station

Control of HVDC Converter and Systems

159 Calculation of Current Order The current order is obtained by dividing the total power order by the direct voltage response obtained from a voltage divider. Overload Control The overload capacity of the converter is sensed by temperature rise and a current order limiter based on the higher temperature rise measured in the two stations and the corresponding control is provided at the lead station. Current Order Transmission The current order obtained in the lead station is transmitted to the trail station through a communication link and in return gets acknowledged. If the acknowledgement is missed due to communication troubles, the current order is locked and with sophisticated control system, it is possible to vary the current order in steps by accepting the current order of the station determining the voltage to the DC current, set by the current controlling station.

4.15 INVERTER OPERATION PROBLEMS An HVDC converter normally has a basic control system that enables it to be operated in the following modes: 1. Constant current control which may be at rectifier or at inverter. 2. Operation on minimum alpha at rectifier. 3. Operation on minimum extinction angle at inverter.

4.15.1 Constant Current versus Constant Voltage Operation Two alternative ways of operating a DC transmission system while permitting control of transmitted power are 1. Current held constant while voltage varies as does power 2. Voltage held nearly constant while current varies as does power The main differences raise the following concerns: 1. The limitation of variation of current caused by variation of alternating voltage when there are faults in the DC line or in the converters. 2. Energy losses and efficiency. It is well known that short-circuit currents on a constant-voltage AC system can be very great although limited by system impedance, of which reactance is the major component. On a constant-voltage DC system, fault currents could conceivably be much greater being limited only by circuit resistance. On a constant-current system, however, short-circuit currents are ideally limited to the value of the load current and in practice to about twice the rated current. Accidental open circuits could give rise to high voltages, but in practice opencircuit faults are more rare than short-circuit faults. In a constant-voltage system I2R loss in the conductors is proportional to the square of the power transmitted. In a constant-current system, this loss always has its full-load value. If the system transmits less than the rated power for some time, as is true in nearly all transmission systems, the daily or annual energy loss is much


HVDC Transmission

less in a constant voltage system than in a constant current system. The opposite is true of those losses which depend on voltage such as corona loss and losses in insulation leakage. In practice, however, the voltage dependent losses are always much less than current dependent losses. Thus, consideration of losses favour the constant-voltage system but limitation of fault current favour the constant current system. In modern HVDC installations mostly constant current control is adopted and hence our discussion centres around this direct-current–direct-voltage characteristic. To illustrate the cooperation between the rectifier and the inverter under normal as well as disturbed network conditions and to understand the different modes of operation mentioned above, the direct-current–directvoltage characteristic is illustrated in Fig. 4.30. The curves A and B represent the different operation modes for the rectifier and the inverter respectively. The inverter has a lower current order than the rectifier, and the comparison requires the inverter voltage to be compensated for the DC line voltage drop. A stable operation point is obtained at 5. Between 1 and 2 the converter is in the rectifier mode with control on minimum delay angle. For 2 to 3 we have constant current control with the rectifier. The inverter has constant current operation from 6 to 7, and at the later point from 5 to 4 it is in minimum extinction angle control. Fig. 4.30 Direct current–direct voltage The line 5 to 6 has often a larger slope than the part 1 to characteristic 2 of the rectifier. This means that if the feeding voltage of the rectifier is reduced (as shown in dotted line) it is possible to obtain an unstable operation point 5. This is avoided by modifying the inverter characteristic as indicated by the line part 5 to 6. For the control system described, the modification is easily done by adding a current-dependent term to the gamma reference in extinction angle control. The additional contribution is zero when the direct current is equal to, or probably larger than, the reference value. Its signal is such that the extinction angle is increased.

Normally, the rectifier operates on constant current control and the inverter operates on minimum extinction angle control, which gives smallest consumption of reactive power in the inverter. However, it must be noted that current control in the inverter is exactly same as current control in the rectifier. The requirement of speed of response is mainly valid for current control. The requirement for safe inverter operation without communication failures mainly refers to the operation on minimum extinction angle. This latter requirement is most difficult to fulfill and has resulted in the most complicated part of the control system. Current control, which is simpler to understand is described first. The description of operation on constant extinction angle control follows subsequently.

Control of HVDC Converter and Systems


4.15.2 Constant Current Control The rectifier normally controls the direct current. Figure 4.31 shows a simplified block diagram for a current control system of a converter. A control voltage Vc is derived from the difference between current reference and current response in a control amplifier. This voltage Vc controls the phase position of the firing pulses as explained in EPC or IPC schemes.

Fig. 4.31 Current control system

The control amplifier should have a high enough gain to attain agreement between current order and current response and suitable dynamics to make the current control system stable and fast. The gain and time constant of the current control system in rectifier and inverter operation have to be turned to meet the dynamic behaviour of the HVDC system.

4.15.3 Constant Extinction Angle Control Since current reference in the inverter is reduced by a fixed amount called current margin Idm, the direct current determined by the rectifier in the other end of the line will be more than the current reference at the inverter. This gives a constant error which forces the current controller to go to saturation at the inverter, and leave the inverter with constant extinction angle control. This is the usual mode of operation for an inverter. The current and g control systems are shown in Fig. 4.32. In constant extinction angle control, the extinction angle (gamma) of the thyristors is controlled in a closed loop. The actual value of gamma is evaluated from the time interval between the valve current extinguishing point to zero crossover point of the communicating voltage. The controller must act fast in the direction of the enlarging gamma. Dynamic stabilisation is needed to improve recovery from commutation failures.


HVDC Transmission

Fig. 4.32 Current and constant extinction angle (g) control system

4.15.4 Inverter Operation at AC Network Disturbances It is an important task for the inverter control system to reduce the number of commutation failures resulting from network disturbances. This refers to disturbances as well as the number of commutation failures that occur during the fault interval and starting-up of a DC link after restoration of normal conditions in ensuring AC supply to the networks. Commutation failures at disturbances in the AC system should as far as possible be avoided. The cases with a small ratio between short-circuit capacity and transmitted power on the HVDC link is of special interest. The measure available to prevent commutation failure in this case is to advance firing for the next valve and to fire after the occurrence of the fault. However, it should be noticed that advance firing results in a transient increase in current for the corresponding phase and a further decrease of the supply voltage, which in turn reduces the extinction angle. This problem is more difficult to solve when the AC network impedance is high, i.e. the short circuit capacity is low. Thus, even if the fault is rapidly detected in the control system, it is an intricate problem to determine the optimal advancement of the control pulses.

4.16 CONTROL OF VSC CONVERTERS The main aim of control in HVDC-VSC systems is to have a precise and accurate control of (i) active power, (ii) reactive power, and (iii) output frequency of the inverter. Further, the controls may often be used to improve the stability and dynamics of the connected AC grids. There are two types of basic controls, viz. voltage control and current control schemes. The voltage control scheme allows for direct control of (i) active and reactive power, and (ii) phase angle and output voltage of inverters.

Control of HVDC Converter and Systems


The current control scheme makes it possible to work the converter as a current source wherein the injected current follows the current phasors. Thus, the advantage of current control scheme are (i) better power quality as converter is less effected by harmonics and grid disturbances, (ii) active and reactive power can be independently controlled, (iii) gives protection against overcurrents (faults), and (iv) can be used to compensate for line (grid) harmonics.

4.16.1 The Direct Control Scheme The schematic diagram of direct control scheme is shown in Fig. 4.33.

Fig. 4.33 Direct control principle of HVDC-VSC

The active power P and reactive power Q are controlled directly by modifying d and modulation index M (Ref. Sec. 3.11.2). Hence, the converter voltage magnitude is varied. The actual power angle d is calculated from the terminal voltage and current quantities and compared with desired power angle. The error is processed by the angle controller to generate the reference phase angle. In a similar manner the error between the actual and reference reactive power Q is also processed by reactive power controller to generate the magnitude of the modulating signal. Phase locked loop (PLL) will perform the synchronising of control output voltage to the grid. Since both P and Q are functions of phase angle d, converter voltage Vd will be changed. Hence P and Q cannot be independently controlled in this scheme.

4.16.2 Vector Control Scheme for VSC Converters In order to overcome the difficulties mentioned in the direct control schemes for HVDC-VSC systems, current control or vector control schemes are employed. Both converters of VSC have identical control schemes.


HVDC Transmission

Unlike the CSC (Thyristor) classical HVDC schemes, the two controllers are independent with no communication between them (sometimes it may be employed). Each converter has two degrees of freedom, i.e. Rectifier (Station 1) controls P and Q. Inverter (Station 2) controls Vd and Q. The block diagram of the controller is shown in Fig. 4.34.

Fig. 4.34 Vector control of HVDC-VSC system

The phase locked PLL is used to synchronise the converter control with the line voltage and also to compute the transformation angle used in d–q transformation. The three-phase quantities of the a-b-c system under steady state are transformed into the two-phase a, b (Clarke transformation parameters) which again are transformed into d–q two axis block. The PLL block measures the system frequency and phase angle u.

Control of HVDC Converter and Systems


In steady state, sin u is in phase with positive sequence component a and phase A of the common voltage Va,b,c. The outer active and reactive power block controls the active power P, reactive power Q and the voltage in the loop. The active power and hence the DC voltage is controlled by controlling phase angle d (refer Fig. 4.34) and the reactive power is controlled by controlling the modulating index M. The instantaneous active and reactive power of the inverter on the valve side are given by P = 3/2 [Vfd ivd + Vfq ivq]


Q = 3/2 [–Vfd ivd + Vfq ivq]


where Vfd and Vfq are direct and quadrature axis voltages in transformed d-q frame and ivd and ivq are the corresponding currents. Hence, it is possible to control DC power (active power) and AC bus voltage (reactive power) by the control of the currents ivd and ivq. The input to inner current loop is fed from the calculated Id, Iq. The inner current loop which controls the SPWM that controls the switching operations of the valve voltage and current operates depending upon the dynamic conditions. The voltage drop across the reactor on the AC side (line side) is governed by dV = Vf – Vv = L (d iv / dt) + R iv


This after transformation from the 3-phase AC system frame to a, b frame to the d-q frame yields the equations Vvdp = Vfdp – R ivdq + wL ivqp – L (d ivdp /dt) Vvqp = Vfqp – R ivqp + wL ivdq – L (d ivqp/dt)

(4.22) (4.23)

Vvdn = Vfdn – R ivdn + wL ivqn – L (d ivdn/dt)


Vvqn = Vfdn – R ivqn + wL ivdn – L (d ivqn/dt)


where suffixes d, q refer to direct and quadrature axis quantities and p, n refer to positive and negative sequence components in a, b frame and v and f refer to voltage position at filter and valve. The above quantities are computed at every instant in steps over a sampling time period. The control is based on the computed values of the above voltages at the instances of sampling and controlled to the desired values. The difference between the DC side voltages are controlled to keep the DC pole voltages balanced (+Vd = –Vd). Thus, the vector control method has more versatile control over all the parameters. With this type of controller, active power adjustments can be done in less than 4 cycles and AC voltage control adjustments are done in 4 to 5 cycles. 3-phase short circuits can be cleared in about 0.2 s (4 cycles). Apart from the two typical schemes described, there are several schemes proposed as modifications to the vector control scheme depending on the specific HVDC link or scheme.


HVDC Transmission

REFERENCES 1. Arrillaga J., Direct Current Transmission, IEE Press, (England) Peter Peregrinus Ltd., 1983; 2nd edition, 1998. 2. Kimbark E.W., Direct Current Transmission, Wiley International (New York), 1971. 3. Ainsworth J. D., Development of Phase Locked Oscillator Control System for HVDC, IEE Conference Publication - 255, September 1985. 4. Ainsworth J. D., Phase Locked Oscillator, IEEE Tr. PAS, Vol. 87, No. 3, March 1968. 5. Hingorani N. G., A new constant extinction angle control for HVDC converters, IEEE Tr. PAS, Vol. 87, No. 3, 1968. 6. Uhlmann E., Power Transmission by Direct Current, Springer Verlag (Berlin), 1975. 7. Arrilaga J. et al., Direct Digital Control of DC converters, IEEE Tr. PAS, Vol. 89, No. 8, 1970. 8. Ahmet M. Hava et al., Simple Analytical and Graphical Methods for Carrier based PWM-VSC drives, IEEE Transactions on Power Electronics, Vol. 14, No.1, Jan. 1999. 9. Schetter F. et al., HVDC Transmission Systems Using VSC: Design and Applications, SM -260, 2000. 10. Woldeyesus Tamiru Shire, M.Sc. Thesis, Delft University of Technology, (TuDelft), May 2009. 11. Mohammed Khatir et al., Performance Analysis of VSC-based HVDC Systems, Leonardo Journal of Sciences, No. 15, July–December 2009.

WORKED EXAMPLES 4.1 The constants of a 3-phase line are A = 0.9 2° and B = 0.9 70° W /ph . The line delivers 60 MVA at 132 kV and 0.8 p.f. lag. Find the sending end voltage and the maximum receiving end power when VS and VR are held constant. If the above line is converted into a DC line, find the receiving end power of the line. Solution: VS = AVR + BIR Power/ph. =

60 = 20MVA 3

Receiving end voltage/ph. = VR = 132/ 3 = 76.2 kV Receiving end current/ph. = VR =

20 ¥ 106 = 262A 76.2 ¥ 103

VS = Sending end voltage / ph. = AVR + BIR = 0.9 2∞ 3 76.2 0∞ + 140 70∞ 3 262 –36.8∞ = 99.22 + j 22.47 = 101.7 0.22 red. = 101.7 12.6∞ kV

Control of HVDC Converter and Systems

Maximum receiving end power/ph. = PR max =


VsVR AVR2 cos (b - a ) B B

b = 78° and a = 2°



101.7 ¥ 76.2 0.9 ¥ 76.22 cos 68∞ 140 140

= 55.35 – 13.99 = 41.35 MW Total maximum 3-phase power that can be delivered = 3 3 41.35 = 124 MW Assuming B as z = 140 70∞ (i.e.) 140(cos 70° + j sin 70°) z = 140(0.342 + j 0.9396):(47.85 + j 131.55) The DC resistance of the line/conductor =

47.88 = 38.304 W 1.25

È132 ¥ 2 ˘ DC voltage between the lines (pole-to-pole) = 2 Í ˙ 3 ˚ Î = 216 kV Id = DC current = IP = 262 A DC power delivered at the receiving end = 0.262 3 216 MW = 56.70 MW AC power delivered at the receiving end = 60 3 0.8 = 48 MW 4.2 An HVDC link delivers DC power with AC line voltage to the rectifier being 400 kV and that at the inverter being 392 kV. Taking a = 10°, g =15° and the DC resistance of the line as 20 W; calculate (i) the DC voltage at both the ends, (ii) the current in the DC link, (iii) the power delivered, and losses in the link. Solution: Vdo = No-load DC voltage at the rectifier end 1

= =

3 2VsL


p 3 2 ¥ 400 = 1.35 ¥ 400 = 540 kV p


HVDC Transmission

Vdo = No-load DC voltage at the inverter end 2


3 2VsL



= 1.35 3 392 = 529 kV. Vd = Vdo cos a = 540 3 cos 10° = 531.8 kV 1


Vd = Vdo cos g = 529 3 cos 15° = 511.00 kV 2


Vd - Vd

(531.8 - 511) = ¥ 103 A R 20 20.8 = ¥ 103 = 1.04 ¥ 103 = 1040A 20

Current in the DC link Id =



The DC power delivered to the inverter = 511 3 1.040 MW = 531.44 MW Losses in the DC link = 2 3 1040 3 20 = 43.3 MW 2

4.3 An HVDC link delivers DC power with AC line voltage to the rectifier being 220 kV. Taking a = 10°, g = 15°, Rc1 = 20 W and Rc2 = 10 W; calculate the current in the DC link. Also estimate the current in the DC link if the supply voltage on the inverter side is reduced by 5%. Solution: Vdo1 = No-load DC voltage at the rectifier end =

3 2 ¥ VsL p



= 1.35 3 220 3 10 = 297 kV Vdo2 = No-load DC voltage at the inverter end =

3 2 ¥ VsL p



= 1.35 3 220 3 10 = 270 kV Vd1 = Vdo1 cos a = 297 3 cos 10° = 292.5 kV Vd2 = Vdo2 cos g = 270 3 cos 15° kV = 260 kV In Fig. 4.35 the straight line indicates the expression Vdo1 cos a – Id Rc1 = Vd1. The expression Vdo2 cos a – Id Rc2 = Vd2 is given by the straight line B. The intersection point P gives the current in the DC link as 1200 A. If the voltage on the inverter side falls by 5%, then Vd = 0.95 3 260 = 247.75 kV. A parallel line to the 2 line (B) is drawn through the point (247.75, 0) which meets the straight line A at P2. The current in the DC link increases to 2200 A when the voltage on the inverter end is reduced by 5%. 4.4 An HVDC link delivers DC power with AC line voltage to the rectifier being 230 kV and that at the inverter being 220 kV. The current order of the rectifier is 1000 A and that of the inverter is 900 A. Estimate the delay/extinction angle of the rectifier/inverter when the DC voltage at the inverter end is 250 kV. Assume the DC resistance of the line as 20 W.

Control of HVDC Converter and Systems

Fig. 4.35 Calculation of current in DC link in Problem 4.3

Solution: Vdo1 = No-load DC voltage at the rectifier end =

3 2 ¥ VsL p


= 1.35 3 230 = 310.5 kV Vdo2 = No-load DC voltage at the inverter end =

3 2 ¥ VsL p


= 1.35 3 220 = 297 kV Line drop in the DC line = 20 3 1000 = 20 kV DC voltage at the rectifier end = DC voltage at the inverter + line drop Vdl = 250 + 20 = 270 kV Vd1 = Vdo1 cos a = 270 cos a =

270 = 0.8695 310.5

Delay angle of the rectifier = a = 29.59° Vd2 = Vdo2 cos g = 250 cosg =

250 = 0.842 297

Extinction angle of the inverter = g = 32.67°.



HVDC Transmission

4.5 An HVDC link delivers DC power at 500 kV at the inverter end with constant current controller at rectifier end set at 1000 A. The equivalent resistances of the rectifier and inverter station are 15 W and the18 W respectively. The DC resistance of the line is 20 W. If the AC voltage at the rectifier is 400 kV, find the percentage of tap changer required to maintain the current constant in the DC link without gate control. Also find the value of delay angle of the rectifier to maintain the above current in the absence of a tap changer. Solution: DC voltage at the inverter end = 500 kV DC line drop = 20 3 1000 = 20 kV Drop in the rectifier station = 15 3 1000 = 15 kV Vdo1 = The no-load DC voltage at the rectifier end = 500 + 20 + 15 = 535 kV. Vsl = The AC voltage required with load =

535 = 396.3kV 1.35

400 - 396.3 ¥ 100 400 3.7 = ¥ 100 = 0.925% 400

The percentage of tap changer required =

In the absence of a tap changer, the delay angle required for the rectifier is given by 520 = 535 a 520 cos a = 535 a = 13.60°

QUESTIONS 1. State the differences in power control in HVDC and HVAC systems and explain the necessity of power control in an HVDC link. 2. State the important circuit parameters which control power in an HVDC link. State the advantages and disadvantages of control of power using each parameter. 3. Explain the necessity of compounding both rectifier and inverter stations with constant current control. 4. What do you understand by constant extinction angle control? What are the parameters that should be taken into account while designing the above controller? 5. What do you understand by current margin between two stations in an HVDC link? How is it assigned to the stations? Why is it advantageous to operate the inverter as constant voltage controller under normal conditions? 6. State the important basic controls required for the operation of HVDC systems and explain how they work and maintain system stability under abnormal conditions. 7. Explain the necessity of VDCOL control used in HVDC systems. 8. State the different firing control schemes adopted for HVDC systems with neat sketches. Explain the difference in operation of each method. Also state their merits and demerits.

Control of HVDC Converter and Systems


9. Explain the operation of pulse frequency control and state why it is preferred in modern HVDC systems? 10. Explain the purpose of a smoothing reactor in a DC line. Show that if Vd is the DC voltage and Id is the DC current, then the value of DC reactor required to prevent commutation failure is given by DVd Dt. Ld = DI d 11. Explain the limitations of constant b control of inverter operation when there is sudden symmetrical or asymmetrical reduction in the system voltage. 12. State the advantages and disadvantages of IPC scheme used for firing angle control of converters. Explain the operation of cosine control of phase delay used in the above scheme. 13. Explain how linear control of phase delay is achieved in IPC scheme of firing angle control of HVDC converters. 14. Give a neat diagram of the basic control system for HVDC converters and explain various controls incorporated in the system. 15. Explain the role of phase locked oscillator used in pulse phase control. Why is EPC scheme used in modern HVDC stations? 16. In the design of phase locked oscillator, explain clearly how feedback control voltage takes into account variations in system conditions. 17. What do you understand by extinction angle control? What are its limitations under asymmetrical fault? 18. Explain why an inverter should be compounded with constant current control in addition to CEA control. 19. Mention the basic requirements of control philosophy adopted in HVDC systems. Explain the use of phase locked oscillator in pulse phase control scheme. 20. With relevant diagrams explain the operation of IPC and EPC schemes employed in control schemes of firing circuits of HVDC stations. State the relative merits and demerits of each scheme. 21. Mention the various modes of operation of HVDC converters and explain the necessity of each mode in operating an HVDC link. 22. Explain the relative merits and demerits of constant current and constant voltage operation of an HVDC link. 23. With the help of a neat block diagram, explain the operation of constant current system and mention various requirements for the same. 24. What are the different control schemes employed for VSC converters? Explain the vector control scheme and how active and reactive can be controlled independently.

PROBLEMS 1. An HVDC link delivers DC power at 250 kV at the inverter when the AC line voltage to the rectifier is 220 kV and that at the inverter is 210 kV. The current order of the rectifier is 1000 A and that of the inverter is 950 A. Estimate the delay/extinction angle of the rectifier/inverter. Assume the DC resistance of the line as 20 W. Ans: a = 24.6° and g = 28° 2. An HVDC link delivers DC power at 500 kV at the rectifier end with constant current controller at the rectifier set at 1000 A. The equivalent resistances of the rectifier and inverter stations are 20 W and


HVDC Transmission

10 W and that of the DC line is 20 W. If AC voltage at the inverter end is 350 kV, find the percentage tap changer required to maintain the current in the link with extinction angle g = 10°. Ans: Rectifier end 3.31%; Inverter end 1% 3. An HVDC system operates at 200 kV no-load voltage and full current of 1000 A. Equivalent resistance of rectifier 8 W, line 3 V and inverter resistance 6.5 V of the current margin set is 100 A and slope for constant current operating is 100 kV/20 A, for both the rectifier and the inverter. (i) Determine the inverter end voltage with sending end voltage 200 kV and load 1000 A. (ii) Rectifier operating with a = 10° and inverter operating at g = 20°, determine operating point for load of 1000 A. (iii) What will be the new operating point, if Vdo is reduced to 195 kV due to AC voltage dip?

MULTIPLE CHOICE QUESTIONS 1. Power transfer through AC systems depends on (a) sending and receiving end voltages (b) phase angle difference between sending end and receiving end voltages (c) reactance of the line (d) all of the above 2. Power transfer in DC line depends on (a) sending and receiving end voltages (b) number of pulses in the rectifier (c) line resistance (d) none of the above 3. Advantage of DC link for power transfer is (a) easy controllability of power (b) more economical (c) it is an asynchronous tie (d) less insulation requirement 4. Control of DC power in a DC link is done by (a) a control (b) g control (c) transformer tap changing (d) all of the above 5. Control of power in DC link is necessary because (a) current order setting needs to be done (b) power can be reversed (c) current sensitive to voltage changes and may damage the converters (d) all of the above 6. With increase in delay angle a (a) p.f. is reduced (b) DC voltage decreases (c) both (a) and (b) (d) kVAR requirement decreases 7. For inversion or inverter operation (a) a £ 90° (b) a > 90° (c) 90° < a < 180° (d) 180° < a < 270° 8. Extinction angle g is optimised so that (a) DC current is kept minimum (b) kVAR requirement is minimum (c) DC output voltage is minimum (d) all of the above 9. For stable operation of DC systems (a) CC and CEA control is adopted (b) a control, CC and CEA is adopted (c) only CEA control is adopted (d) only CC control is adopted

Control of HVDC Converter and Systems


10. Characteristic of a converter is the relation between (a) AC voltage and Id (b) DC output voltage and Id (c) DC power and Id (d) a and Id 11. The common control done in converters is (a) rectifier as both voltage and current controller (b) inverter as both voltage and current controller (c) inverter as current controller (d) rectifier as voltage controller and inverter as current controller 12. VDCOL controlling is done and is necessary when (a) low voltage due to faults (b) to regulate DC current depending on DC voltage due to fault on AC side (c) to regulate DC current when DC voltage dips (d) to regulate AC current under faults 13. Power reversal in DC link is done (a) operating rectifier (a) close to 180° and inverter g close to zero (b) operating both a and g near 90° (c) operating a at 90° and g close to zero (d) operating g close to 90° and a near zero 14. In case of IPC cosine control, DC output voltage is proportional to (a) control voltage (b) DC current (c) cos–1 of phase angle on AC side (d) overlap angle m 15. Main drawback of CEA control is (a) it cannot offer stable operation in weak AC links (b) more reactive kVAR are needed (c) control is uneconomical (d) generates harmonics 16. Firing angle control in modern HV converters is (a) IFC (b) EPC (c) IPC (d) both (a) and (b) 17. In HVDC link with CC control (a) power loss is more (b) short circuit current is limited (c) both (a) and (b) (d) none of the above 18. Commutation failure usually occurs in (a) rectifiers (b) inverters (c) both inverters and rectifiers (d) controllers 19. A rectifier station is set at a current level of 900 A and inverter station at 800 A. The current margin is (a) 100 A (b) 50 A (c) 200 A (d) – 100 A 20. In order bring the voltage of operation to the normal voltage level as the power varies, control done is (a) a control (b) transformer tap changing (c) g control (d) both a and g control

ANSWERS 1. (d) 9. (b) 17. (c)

2. (a) 10. (b) 18. (a)

3. (a) 11. (d) 19. (a)

4. (d) 12. (b) 20. (b)

5. (c) 13. (a)

6. (c) 14. (a)

7. (c) 15. (a)

8. (b) 16. (d)

Harmonics in HVDC Systems 5.1


Electrical energy transmitted through AC transmission or DC transmission is to be delivered at the consumer’s terminals at specified voltage level of constant magnitude without deviation from the ideal waveform. Deviation from the perfect sinusoidal waveform is generally expressed in terms of harmonic components. The term harmonic is derived from acoustics, and is defined as the content of the electrical signal whose frequency is an integral multiple of fundamental or system frequency produced by generators. In the previous chapters, it has been be observed that waveforms of current in the transformer windings are not sinusoidal. This causes both the current waveform and voltage waveform to be distorted. Further, the switching operations also cause distortion of waveforms on the AC side. Further, on the DC side also, the output voltage is not perfectly constant and contains ripples which generate harmonic voltages on the DC side.



An HVDC transmission system generates harmonic currents on the AC side and harmonic voltages on the DC side during operation. The harmonic currents generated at the AC bus of the converter get transmitted to the AC network and cause the following adverse effects— (a) Heating of the equipments connected (b) Instability of converter control (c) Generates telephone and radio interference in adjacent communication lines, thereby inducing harmonic noise (d) Harmonics can lead to generation of overvoltages due to resonance when filter circuits are employed



An HVDC transmission system consists of a rectifier and an inverter whose operation generates harmonics on AC and DC side of the converter. The three distinct sources of harmonics in HVDC systems are

Harmonics in HVDC Systems


(i) Transformer (ii) AC generator (iii) Converter along with its control devices

5.3.1 Transformer as Source of Harmonics Transformers can be considered as sources of harmonic voltages, which arise from magnetic distortion and magnetic saturation due to the presence of a DC component in its secondary. The magnitude of these harmonics depends upon the operating flux density. Converter transformers are usually operated at high flux densities than conventional 3-phase transformers, and therefore the possibility of generation of harmonics is more in the former than in the later. Although the waveform is usually good, an AC generator may be regarded as a source of balanced harmonic voltages because of non-uniform distribution of flux on the armature windings. The converter which forms the basic unit in HVDC transmission imposes cyclic changes of impedances in the circuit and therefore regarded as harmonic current generators. Considering the emf equation of a transformer, the voltage on the primary side is V1 = – emf = N1

dw dt

f = fm sin w t


(5.1) (5.2)

The emf induced in the primary winding is dw dt e1 = – N1w cos w t e1 = – N1

The supply voltage on the primary side is V1 = – e1 = + N1 w cos w t


From the expressions (5.2) and (5.2(a)), it is clear that the sinusoidal flux produces sinusoidal voltage at no load. But the primary magnetising current will not be sinusoidal because of the nonlinear nature of the B–H curve of the core material used for the transformer. The wave shapes of the magnetising current im neglecting the core-loss component is shown in Fig. 5.l(b) which is projected from Fig. 5.1(a). The flux waveform is sinusoidal to balance the primary voltage. The magnetising current is plotted against time for each value of flux and the resulting waveform of current is far from sinusoidal. When the hysteresis effect is considered, then the nonsinusoidal magnetising current waveform is no longer symmetrical about its maximum value. The distortion shown in Fig. 5.2(a) and (b) is mainly caused by triple n harmonics and particularly the third harmonic. Thus, in order to maintain a reasonable sinusoidal voltage supply, it is necessary to provide a path for the triple n harmonics. This is normally achieved by the use of delta-connected windings which provide a path for third harmonic currents. Therefore, a transformer excited by a sinusoidal voltage produces a symmetrical excitation current that contains only odd harmonics.


HVDC Transmission

Fig. 5.1 Transformer magnetisation (without hysteresis) (a) Magnetisation curve (b) Flux and magnetisation current waveforms

Fig. 5.2

Transformer magnetisation (including hysteresis) (a) Magnetisation curve (b) Flux and magnetisation waveforms

If a linear or nonlinear load is connected to the transformer, the excitation current will again contain only odd harmonics provided the load current does not contain a DC component. If magnetic imbalance is introduced for any reason, then B–H curve (f – i) and the excitation current will no longer have the same shape as under no-load conditions, but will be as shown in Fig. 5.3(a) and 5.3(b). Due to this unbalance, the average value of flux will not be zero. This means that the AC flux component can be offset by a value equal to fdc. This is possible only when the excitation current contains a DC component. Any unbalanced loading on the secondary side of a converter transformer due to unbalanced firing of the valves results in DC component of current in addition to the sinusoidal terms. Under balanced operating conditions, the converter is supposed to produce only fundamental and normal harmonics of the orders 5, 7, 11, 13, etc. In general, the normal current harmonics produced on the AC

Harmonics in HVDC Systems


Fig. 5.3 Excitation characteristic under asymmetrical magnetisation

side are of the order (pk ± 1), where p is the pulse number and k is any positive integer. The fundamental component is the desired component and the remaining harmonics merely represent an interference source. The above mentioned normal harmonics are called characteristic harmonics.

5.3.2 Harmonics due to Converters Figure 5.4 shows a 12-pulse connection which essentially consists of two 6-pulse groups. One group having Y-Y connected converter transformer with 1 : 1 turns ratio and the other group having Y-D converter

Fig. 5.4 12-pulse bridge connection


HVDC Transmission

transformer bank with 1: 3 turns ratio between the lines of 3-phase banks. A series connection of the two 6-pulse groups constitute a 12-pulse connection.



The order of characteristic harmonics is related to the pulse number of the converter configuration and is defined as the number of nonsimultaneous commutations per cycle of fundamental frequency. A converter with pulse number p generates characteristic voltage harmonics of the order pk on the DC side, where k is any integer. The following assumptions are made while analysing characteristic harmonics. 1. The AC supply voltage is a perfectly balanced system of voltages and contains only fundamental components. 2. Direct current is of constant magnitude (Ld S `). 3. Valves conduct sequentially at equal intervals of time. 4. The commutation reactance of each phase is same. Consider the 6-phase bridge converter as shown in the Fig. 3.1; current and voltage waveforms are shown in Fig. 3.9 for delay angle a and commutation angle m. The output DC voltage is illustrated in Fig. 3.9(b). Taking time reference at the crossing of the voltage waveforms (C1), the output DC voltage can be expressed as 2p ˆ Ê 2VSL cos Á w t + ˜ for 0 < w t < a Ë 6¯

V0(t) =

V0(t) =

6VSL (VR + VB ) – Vy = sin w t for a < w t < a + m 2 2 p 2p ˆ Ê 2VSL cos Á w t ˜¯ for a + m < w t < Ë 6 3

V0(t) =


Using Fourier equations 1 A0 = p

An =

Bn =

1 p 1 p

s + 2p


f (θ) d θ


f (θ) cos nθ d θ


f (θ) sin nθ d θ



s + 2p



s + 2p



Harmonics in HVDC Systems


where s is any angle. The general trigonometric form of Fourier series is F(q) =

A0 2


 [ An cos nθ + Bn sin nθ]


n =1

A where q = wt and w is the basic repetition frequency in rad/s; 0 is the average value of the function f(q) and and Bn are the rectangular components of the nth harmonic. 2 n The peak value of the nth harmonic and its continuous form are An2 + Bn2 and Cn fn = An - iBn ¸Ô ˝ fn = tan -1 (- Bn An ) Ô˛ Cn =


Using the above equations (5.4) to (5.6), the rms value of the hth harmonic voltage is given by Vh =

È m¸ m¸ 2 2Ï 2 2Ï Í (h - 1) cos Ì(h + 1) 2 ˝ + (h + 1) cos Ì(h - 1) 2 ˝ 2(h - 1) Î Ó ˛ Ó ˛ Vdo 2


m¸ m¸ ˘ Ï Ï - 2(h - 1)(h + 1) cos Ì(h + 1) ˝ cos Ì(h - 1) ˝ cos (2a + m ) ˙ 2˛ 2˛ Ó Ó ˚ Some interesting facts can be seen from the above equation when reduces to Vho = 2 Vdo (h 2 - 1) Vho = 2 (h 2 - 1) Vdo

= 0 and

(5.9) = 0 and the expression (5.9)

(5.10) 2 h2


The zero suffix in Vho indicate that the commutation angle is zero. The rms values of 6th, 12th and 18th harmonics can be computed from the expression (5.11) and their values are 4.04, 0.99 and 0.44 percent respectively, when a = 0. Generally the harmonic content increases with a and when a=

p and m = 0 2

Vho = 2h (h 2 - 1) = 2 h Vdo


ASEA, Sweden have provided a set of curves for harmonic voltages (Vh) as a percentage of Vdo against the angle m for different values of a as shown in Figs. 5.5 to 5.7 for 6th, 12th and 18th harmonic respectively. It may be seen from the curves (see Figs. 5.5 to 5.7) that for small values of the angle m, the harmonic magnitudes increase with an increase in a and the higher order harmonics increase more rapidly. For a constant


HVDC Transmission

delay angle a, the harmonics decrease and reach first minimum at approximately m = p/h; but for m = p/(h + 1), and m = p/(h – 1), the harmonics are constant for any angle and attain maximum at m = 2p/h and there is further minimum at m = 3p/h. Comparison of the expressions (5.11) and (5.12) indicates that the harmonic content at ~ = p/2 is h times the harmonic content corresponding at a = 0. This suggests higher order harmonics increase with a and the maximum value of these harmonics is given by the expression (5.12). If the converter is formed with two bridges one with star–star connected transformer and the other with star–delta transformer, then their voltage on the

Fig. 5.5

Fig. 5.6 Variation of 12th harmonic voltage in relation to angle of delay and overlap

Variation of 6th harmonic voltage in relation to angle of delay and overlap

Harmonics in HVDC Systems


Fig. 5.7 Variation of 18th harmonic voltage in relation to angle of delay and overlap

secondary side differ in phase by 30°; therefore harmonics also differ in phase. A phase difference of 30° for fundamental voltage of the two bridges induce a phase difference of 180° (30 3 6) for the 6th harmonic and a phase difference of 2p (30 3 12) for the 12th harmonic and so on.



Figure 5.8 shows the wave shapes of primary current when a = 0; IA, IB and IC are the primary currents for Y-Y connected converter and I A¢ , I B¢ , and IC¢ for Y–D connected converter. The wave shapes of these currents are primarily responsible for generation of current harmonics. The secondary side currents of Y–Y converter are IR, IY and IB. Since the turns ratio of Y–Y, 3-phase bank is 1 : 1, the line currents on the primary side of the Y–Y bank are also the same (i.e. IA = IR; IB = IY and IC = IB). The secondary side line currents on Y–D transformer bank are I R¢ , IY¢ , and I B¢ and the corresponding phase currents of D bank are I1, I2 and I3 whose values in terms of line currents are given by I1 = ( I R¢ – IY¢ ) / 3 I 2 = ( IY¢ – I B¢ ) / 3 I 3 = ( I B¢ – I R¢ ) / 3



HVDC Transmission

Fig. 5.8 Primary side current—12-pulse operation, a = 0

The corresponding line currents on the primary side of a Y–D transformer bank are I A¢ , I B¢ , and IC¢ , and are related to the phase currents on the D side as I B = 3I1 = ( I R¢ – IY¢ ) / 3 I C = 3I 2 = ( IY¢ – I B¢ ) / 3 I A = 3I 3 = ( I B¢ – I R¢ ) / 3


Harmonics in HVDC Systems

The peak value of these currents of stepped waveform is on the Y–Y side.

2Id 3


, where Id is the peak value of the phase current

The above currents are also shown in Fig. 5.9 with firing angle a. Comparison of waveforms in Fig. 5.8 and Fig. 5.9 indicates that the wave shape of I A¢ , I B¢ , and IC¢ remains the same even with gate control but their position is shifted w.r.t. the corresponding phase voltage.

Fig. 5.9 Primary side currents—12-pulse operation, a π 0

The primary currents of Y–Y and Y–D bank connection of the converter which are in phase are shown separately in Fig. 5.10. Figure 5.10(a) indicates the current waveform of a star–star converter transformer neglecting the commutation reactance. Taking the origin symmetrical with the waveform, the waveform can be defined as


HVDC Transmission

i = Id for –p/3 £ wt £ p/3 = 0 for p/3 £ wt £ 2p/3 and –p/3 £ wt £ –2p/3 = –Id for –2p/3 £ wt £ + p and 2p/3 £ wt £ p

Fig. 5.10 Waveforms of phase currents on the primary side (a) Star–Star transformer connection (b) Star–Delta transformer connection

The Fourier series for the above waveform is i=

2 3I d p

1 1 1 È ÍÎcos w t - 5 cos 5 w t + 7 cos 7w t - 11 cos 11 w t +

˘ •˙ ˚


The order of the characteristic harmonics determined from the expression is h = pk ± 1 or (6k ± 1)


where k is the integer and p is the pulse number. The rms value of the fundamental current is given by I1 = 6 I d p


and the rms value of the hth harmonic is Ih =

6Id = I1 h ph


Harmonics in HVDC Systems


The primary current waveform of star–delta or delta–star connected transformer is shown in Fig. 5.10(b) and is defined as follows. i = 2Id = Id

3 0 £ w t £ p 6 and - p 6 £ w t £ 0 3 p 6 £ w t £ p 2 and - p 2 £ w t £ - p 6

= - Id = - 2Id

3 p 2 £ w t £ 5p 6 and - p 2 £ w L £ - 5p 6 3 5p 6 £ w t £ p and - 5p 6 £ w t £ - p

The Fourier analysis of the above waveform is given by i=

2 3I d p

1 1 1 È ˘ ÍÎ cos w t + 5 cos 5w t - 7 cos 7w t - 11 cos 11w t + º• ˙˚


The expressions (5.15) and (5.19) are identical except for the negative q for certain harmonics.

5.5.1 Harmonic Generation in 12-pulse Converters If the two 6-pulse bridges with transformer connections Y–Y and Y–D are connected in series as shown in Fig. 5.4 for 12-pulse operation, then the only harmonics corresponding to h = 12k ± 1, will enter into the AC system. The net current at the AC bus on the primary side is (IYA + IDA) and the Fourier components of the above current is obtained by adding the expressions (5.15) and (5.19) as ia =

4 3I d È 1 1 1 1 ˘ cos w t - cos 11 w t + cos 13 w t = cos 23 w t + cos 25 w t º• ˙ Í p Î 11 13 23 25 ˚


Assuming the DC voltage on each 6-pulse converter is one-half of the DC voltage of 12-pulse converter and the primary line current of each 6-pulse converter transformer is equal to half the total line current of 12-pulse converter bridge, then the line current of a 12-pulse converter bridge is given by ia =

2 3I d È cos 11 w t cos 13 w t cos 23 w t cos 25 w t ˘ cos w t + + º •˙ Í p Î 11 13 23 25 ˚


The order of the characteristic harmonics with an AC line on the primary side of a 12-pulse converter is given in the equation (5.16) and the primary current contains fundamental and harmonics of the order 11,13, 23, 25, etc. But it is observed that AC secondary side line currents of 12-pulse bridge operation contains apart from fundamental, current harmonics of the order, 5th, 7th, 11th, 13th, etc. As stated earlier, a 12-pulse converter bridge is formed by connecting two 6-pulse bridges in series as shown in Fig. 5.4. The required phase difference between the line currents and voltages of the two 6-pulse bridges is obtained as explained below by connecting one converter transformer in star–star and the other in star–delta. The consecutive pulses of DC voltages waveform of a 6-pulse converter are displaced by 2p/6 radians. Similarly, the consecutive pulses of DC voltage waveform of a 12-pulse converter are displaced by 2p/12


HVDC Transmission

radians (i.e. 30° electrical). To achieve this phase difference between the pulse voltages of the first and second 3-phase transformers, one is connected in star–star and the other is star–delta. The fundamental voltages on the secondary side (valve) terminals of two 3-phase converter transformers feeding 12-pulse converter are mutually displaced by 30°. The delay angle a is the same for every phase of the two 6-pulse converters. Assuming equal commutating reactance, the fundamental waveform of secondary line current of the two 6-pulse converter bridges have the same phase difference as that of the respective phase voltages (30° electrical). For the star–delta connection indicated in Fig. 5.4, the phase voltage on the delta side lags the phase voltage on the star side by 30°. The phase current I1 on the secondary side of Y–D transformer leads the phase current IR on the secondary side of Y–Y transformer by 30° as illustrated in Fig. 5.8(d). But the phase current I A¢ on the primary side of Y/D transformer bank leads in phase by 30° electrical w.r.t secondary current, and therefore in phase with IA of the phase current on Y–Y transformer, as shown in Fig. 5.8(e). The resultant AC bus current on the primary side for 12-pulse operation is obtained by adding the in-phase currents IA and I A¢ [see Fig. 5.10(a) and (b)] and Fig. 5.11. The Fourier expansion of the above waveform is given in the expression 5.21.

Fig. 5.11 Idealised phase current waveform with 12-pulse operation

The above expression can also be expressed in terms of no-load DC voltage and line voltage on AC side as Ia =

I d Vdo È cos 11q cos 13q cos 23q cos 25q ˘ + + º• ˙ cos q Í 11 13 23 25 Î ˚ 3VSL


From the above, the maximum value of the fundamental and harmonic currents will be Ê 6Id ˆ I10 = 2 3I d Á rms˜ Ë π ¯ Iho = I10/h

(5.23) (5.24)

The first suffix in the above expression indicates the order of the harmonic and the second suffix 0 indicates that m is assumed to be zero.

5.5.2 AC Harmonic Currents with Firing Angle and Overlap Figure 5.9 shows the current waveforms with overlap which is a better approximate to a sine wave than the current wave shapes without overlap. The analysis of the above waveforms can be carried with Fourier series. The amplitude of these harmonics increases due to an increase in the firing angle. The amplitude of these harmonics with delay angle a and overlap angle m can be computed and can be expressed as Ih = Kh Iho



Harmonics in HVDC Systems


Kh =

( K12 + K 22 - 2 K1 K 2 cos(2α + μ))1 2 (cos α - cos(α + μ))


K1 =

sin(h + 1) μ 2 sin(h - 1) μ 2 and K 2 = h -1 h +1


The above expression is valid for m £ 60°. The values Kh are indicated in Table 5.1 for different values of a and commutation reactance Xs. The magnitude of the characteristic harmonics as a function of Id is also shown in Fig. 5.12. Table 5.1

Value of kh as a function of

and Xs


a =15° Xs = 0.08

Xs = 0.1

Xs = 0.08

a =20° Xs = 0.1

Xs = 0.08

a =30° Xs = 0.1

11 13 23 25

0.47 0.32 0.21 0.21

0.37 0.19 0.19 0.15

0.56 0.42 0.16 0.20

0.46 0.26 0.21 0.20

0.69 0.57 0.07 0.06

0.57 0.44 0.14 0.13

The table indicates that the maximum value of harmonic currents is less dependent on the firing angle and more dependent on overlap angle and direct current. It should be noted that the converter behaves like a current source for the fundamental and harmonics. The harmonics decrease with increase in commutation reactance or commutation angle (m) and the rate of decrease is greater for higher harmonics. Harmonics tend to attain minimum value at about m = 2p/h and then increase slightly. It should be noted that during abnormal conditions (disturbances) a is nearly 90° and m is comparatively small, and the harmonics approach their maximum in contrast to normal operating conditions.


Fig. 5.12

Harmonic magnitudes with variation in DC current


Several studies have been undertaken to study the effect of variation of firing angle a and overlap angle m on the magnitude of harmonic currents. The following conclusions were drawn from these analysis. 1. As m increases, the magnitude of the harmonics decreases but higher order harmonics decreases more rapidly than the lower order ones. 2. The rate of reduction of harmonics increase as m increases up to a certain limit. 3. Each harmonic decreases to a minimum at an angle m = 2p/h and then rises slightly thereafter. 4. When m is held constant, changes in the various harmonics for different values of a is small.


HVDC Transmission

5. For a given current, when angle a is increased, and angle m is decreased, the harmonics tend to increase and approach the highest values at m = 0. In no case, however, the harmonics exceed the values given ( 6Id ) 1 . p h



For a 12-pulse converter having an overlap angle m < p/6, the relative DC side voltage harmonics and AC side current harmonics are given by expressions (5.19) and (5.21). It may be seen from these two equations that the relative harmonic magnitude depends on a and m, which in turn depends upon the modes of converter control. A study was carried by the authors Sahu et al., for computing the relative harmonic contents for different modes of control and the results are plotted in Figs. 5.13 and 5.14.

Fig. 5.13

12th and 24th harmonic voltages for di erent control modes

Fig. 5.14 11th and 13th currents for di erent control modes

Harmonics in HVDC Systems


(a) Constant Ignition Angle Control (CIA) This mode is taken as reference for comparison between relative harmonics generated under different control modes when a is held constant at values determined by a steady-state power flow in the DC line. The relative voltage and current harmonic magnitudes are computed for this mode and typical results for a = 20° are plotted.

(b) Constant Current Mode (CC) For this mode, a is set at a value so as to maintain Id constant. The relative voltages and current harmonic magnitudes are computed for Id equal to 1 p.u. and the results are plotted. (c) Constant Power Control (CP) a is controlled in this mode so that Pdc(VdId) is kept constant at a set value. The relative voltage and current harmonics are computed for Pdc equal to 1 p.u.

(d) Constant Power Factor Control (CPF) Nishimura et al., suggested that the inverter commutation failure is reduced in this mode and the relative magnitude of voltage and current are computed for a power factor of 0.95 lag. (e) Constant Extinction Angle Control (CEA) For this mode of operation, the curves are similar to those under CIA mode and therefore later curves are used. From Figs. 5.13 and 5.14, it is clear that the magnitude of harmonics differ for different modes of converter control. The difference being more predominant for higher order harmonics.



The converter not only generates characteristic harmonics as stated in the previous sections but also contributes in generating noncharacteristic harmonics of the order 2, 3, 4, 6, 8, ..., etc. The magnitude of these harmonics depends upon— 1. 2. 3. 4.

Imbalance in the converter transformer reactance Imbalance in the operation of two bridges forming the 12-pulse converter Imbalance in the AC supply voltage Firing angle errors in phases

An unbalanced operation generates odd harmonics while the errors in the firing angle of the converter generate even harmonics. Today, firing schemes use phase locked voltage oscillator with feedback control loop which results in variation of firing angle of few tenth of a degree.

5.8.1 Effect of Firing Angle Errors The error in the firing angles can be due to the jitter in the firing or the nature of the control system. The equidistant pulse control scheme is better than IPC as it has no inherent errors except due to jitter. A major error in the firing angle in the modern converter stations is due to the ripple in the current feedback signal and not due to the equipment. The allowable tolerance in the delay of the firing pulses is ±0.2°. In 12-pulse converters, residual harmonics resulting due to unbalanced operation of the two 6-pulse bridges forming the operation of 12-pulse converter can be eliminated by adopting an equidistant pulse control scheme. Even and triple n harmonics will be generated due to firing angle errors and their relative magnitudes are shown in Table 5.2. The harmonic order is given by h = 6n + m. The table indicates that in one group the magnitude increases with n while in the other group it decreases with n.


HVDC Transmission

Table 5.2 n 0 1 2 3 4

Noncharacteristic harmonics due to errors in firing angle (m = 0) m 1






101.4 15.7 8.60 5.70 3.90

1.10 1.40 1.70 1.90 1.90

4.00 3.90 3.70 3.40 3.10

0.75 0.35 0.07 0.48 0.85

17.60 6.30 2.80 1.10 0.10

2.00 1.80 1.60 1.30 1.00

5.8.2 Effect of Unbalanced System of Voltages The presence of negative sequence component of AC voltages shifts the zero-crossing of the commutation voltages. In the IPC scheme, noncharacteristic harmonics are generated because of asymmetry in the firing angle of individual valves, even if the DC current is assumed to be constant and overlap angle is neglected, 5% third harmonic currents will be generated when there is 5% negative sequence voltage. With an EPC scheme, the above mentioned trouble can be avoided. However, when the smoothing reactor has finite inductance, there will be DC current harmonics of 2nd order which, in turn, will generate AC harmonics of 3rd order.



Voltage source converters are usually operated with different control schemes that use PWM to control AC fundamental frequency. From the converter side of the reactor, the voltage-to-ground is a square wave and thus requires AC filters to remove harmonics. The line side reactor usually removes the high frequency component in current wave and the DC capacitor high frequency voltage ripples on the DC side. Still depending on type of converter (6-pulse or 12-pulse), voltage harmonics of 6n ± 1 or 12n ± 1(n harmonic number) are generated in the rectifier side of the converter. Further with PWM and high dv/dt switching, high frequency voltage and noise are generated, the starting harmonic being pf0, where f0 fundamental frequency, p = ratio of modulation frequency to fundamental AC frequency. With p = 9, the harmonics generated will be 9, 17, 19, etc. The amplitude spectrum of typical harmonics with p = 9 and M = 0.5 (Ref. Sec. 3.11.2) of PWM inverter is shown in Fig. 5.15. In a study carried out on a actual system with a long cable, the effect of switching frequency had larger effect when it is equal to one of the harmonic frequencies. The current harmonic has the largest magnitude. With p = 9, 11, 13, etc., ..., the predominant harmonics were 9, 11 and 13. The capacitance of the cable and that of the capacitor bank provided reduces the THD (total harmonic distortion) significantly. Further with an increase in capacitance value, the resonances that occur become damped because the interaction produced by DC harmonic currents gets reduced. The studies at a VSC-based HVDC link in Australia (Terranora-Mullunbiby) showed that total harmonic distortion THD was about 1.5% and TIF 40% respectively (Ref. Sec. 6.3). The high level of 5th harmonic was not due to converters, as it was present even when converters were re-energised. Some harmonics are present around once and twice the switching frequency. The 9th harmonic was present on the DC side due to cable resonance and was filtered off with the 9th harmonic filter. To

Harmonics in HVDC Systems

Fig. 5.15


Harmonics with sinusoidal PWM P = 9 and M = 0.5

conclude, most harmonics that are present in the VSC system are either due to switching or due to resonance between capacitor and reactances present. A typical harmonic spectrum is shown in Fig. 5.16.

Fig. 5.16

Typical spectra for the AC side voltage and the DC side current


HVDC Transmission

REFERENCES 1. Keimbark E.W., Direct Current Transmission, Wiley InterScience, Vol. 1, Chapter 8, 1971. 2. Arillaga J., HVDC Transmission, (London) Peter Peregrinus, IEEE Series, 1983. 3. Pintsov A.M., Calculation of Harmonic Audio Frequency Currents in DC Power Lines, Direct Current, Vol. 4, June 1958. 4. Bornitz E. et al., Harmonics in Electrical Systems and their Reduction through Filter, Cigre, 304, 1958. 5. Reeve J. and Krishnayya PCS, Unsual Harmonic Currents arising from High Voltage DC Transmission, IEEE Tr. PAS, Vol. 87, 1968. 6. Reeve J. and Rao Subba T., Harmonics caused by imbalanced transformer impedances and imperfect twelve pulse operation of HVDC conversion, IEEE Trans. PAS, Vol. 95, No. 5, September/October 1976. 7. Mathur R. M. and Sharaf A.M., Harmonics on DC side in HVDC conversion, IEEE Tr. PAS, Vol. 96, No. 5, 1997. 8. Railing B.D. et al., The direct linked VSC based project, Cigre 14–108, Session, 2002 9. Chang Hsin Chien, Analysis of harmonics in subsea power transmission cables used in VSC-HVDC Tr. Systems, IEEE Tr. (Power Delivery), Vol. 22, No. 4, October 2007. 10. Brahman Micheal P., Standard Handbook of Electrical Engg. Direct Current Power Transmission (sec. 15), Digital Engineering Library, McGraw-Hill Co., USA.

WORKED EXAMPLES 5.1 The AC system voltage at the rectifier end is 220 kV. Estimate the sixth harmonic voltage of a 6-pulse converter when (a) a = 0 and m = 0 (b) a = p/2 and m = 0 Solution: Case (a) a = 0 and m = 0 The AC system voltage between two-phase = USL = 220 kV The no-load DC voltage = Vdo = 1.35 USL = 1.35 3 220 = 297 kV Harmonic voltage Vho =

2 ¥ 297 = 11.66 kV 36 V = 0.0399, i.e. 60 = 39% Vdo

For sixth harmonic V60 = V60 Vdo

2 ¥ Vdo h2

Harmonics in HVDC Systems


Case (b) a = p/2 and m = 0 Harmonic voltage = The sixth harmonic voltage = V6 =

Vh 2 = 2h h 2 - 1 ª Vdo h V6 2 = 6 Vdo 2 ¥ 297 = 69.89 kV 6

5.2 Obtain relative magnitude of sixth harmonic voltage of a 6-pulse converter when a = 10° and m = 10°. Solution: The harmonic voltage of hth order is given by Vdo

Vh =

2(h 2 - 1)

[(h - 1) 2 cos 2 {(h + 1) m 2} + (h + 1) 2 cos 2 {(h - 1) m 2} - 2(h - 1)(h + 1) cos (h + 1) m/2 cos(h - 1) m/2 cos (2a + m )]1 2

When a = 10° and m = 0° V6 = Vdo

1 [52 cos 2 35 + 7 2 cos 2 25 - 2 ¥ 5 ¥ 7 cos35cos 25cos30]1 2 2(36 - 1)


1 [25 ¥ 0.06698 + 49 ¥ 0.08214 - 70 ¥ 0.2588 ¥ 0.9063 ¥ 0.86]1 2 2 ¥ 35


1 1 [1.6745 + 40.248 - 14.22]1 2 = [27.7025]1 2 2 ¥ 35 2 ¥ 35


5.26 = 0.1065 2 ¥ 35

V6 = 10.65% Vdo 5.3 A 12-pulse operation is obtained with star–star bank of 1:1 turns ratio and star-delta bank of 1 : 3 turns ratio. Estimate the peak value of current in the secondary side of delta winding when current in the DC link is 1000 A and 11th harmonic current. Assume a = 0 and m = 0. Solution: From the waveforms shown in Fig. 5.8, the peak value of current in the delta winding on the secondary side is 2Id 3


2 ¥ 1000 = 666.6 A 3


HVDC Transmission

i11 = Eleventh harmonic (peak) current =

4 3I d p ¥ 11

4 3 1000 ¥ = 0.20048 ¥ 103 A (peak) p 11 = 141.98 A (rms) =

5.4 An HVDC link is supplying DC power of 1000 MW at ±500 kV at the inverter end. Estimate the value of the eleventh harmonic current when a = 10° and m = 20°. Solution: Id = DC current in the link =

1000 ¥ 106 = 1000A 1000 ¥ 103

Fundamental component of current when a = 0 and m = 0 is

I10 =

6Id p

(rms) =

6 ¥ 1000 = 0.7797 ¥ 103 A p

Eleventh harmonic (rms current) I11 = I ho =


11 = 70.88 A


0.7797 ¥ 103 11

When a = 10° and a = 20° Ih = Kh Iho where

K h = [ K12 + K 22 - 2 K1 K 2 cos (2a + m )]1 2 /[cos a - cos (a + m )]


K1 =

sin (h + 1) m /2 sin (h - 1) m /2 and K 2 = (h - 1) (h + 1) 12 10 K1 = sin ¥ 10 and K1 = sin ¥ 10 10 12 = 0.2079 and K2 = 0.1449

K11 =

[0.20792 + 0.14492 - 2 ¥ 0.2079 ¥ 0.1449cos 40∞]1 2 [cos10∞ - cos30∞]

= 0.0432 + 0.020996 – 0.06025 3 0.7660 =

(0.0432 + 0.020996 - 0.0462)1 2 = (0.019996)1/ 2 /0.1188 0.9848 - 0.8660


0.134 = 1.1292 0.1188

Harmonics in HVDC Systems


rms value of eleventh harmonic current = Ih = K11I110 = 70.88 3 1.1292 = 80.04 A

QUESTIONS 1. Identify the various sources for generation of harmonics in HVDC systems and mention the various adverse effects caused due to the presence of harmonics. 2. With neat sketches, explain how a converter transformer is responsible for generation of harmonics and suggest various methods for minimising them. 3. What do you understand by characteristic harmonics in HVDC systems? Using Fourier analysis, obtain an expression for nth harmonic voltage on the DC side of the converter system. Discuss the effect of variation of a and m on the magnitude of the above harmonics. 4. With the help of a schematic diagram of a 12-pulse converter, obtain the wave shape of currents of the primary side of star–star and star–delta of 3-phase banks of converter transformers, and hence obtain an expression for current on the primary side in terms of harmonics. 5. Obtain an expression for primary current of Y–Y and Y–D banks of a 12-pulse converter transformer in terms of x, m and harmonic components, and discuss the effect of x and m on the magnitude of these harmonics currents. 6. What are noncharacteristic harmonics in HVDC systems? How are they generated? 7. State the various sources of harmonics generation in HVDC-VSC systems and mention the adverse effects caused by these harmonics. 8. Show that current harmonics generated for 12-pulse operation is given by the expression pk ± 1. 9. How does an AC harmonic current vary with (a) a or (b) m? Illustrate with the characteristic curves. 10. What is the effect of different control modes on harmonics and their relative magnitudes?

PROBLEMS 1. Estimate the magnitude of 6th and 12th harmonic voltages in a 6-pulse converter operating at Vdo= 200 kV with (a) a = 10°, m = 0; (b) a = 10°, m = 15°. 2. A 12-pulse converter is supplied from two Y–Y and Y–Delta transformers with 1:1 and 1: 3 ratio. What is the peak AC current on the secondary side Y and D of the transformer with DC link current 1200 A with (a) a = 0, m = 0; (b) a = 15°, m = 15°. 3. If the above link Q2 is operating at ±500 kV at the inverter end, estimate the 11th harmonic and 13th harmonic currents for a = 10°, m = 15°.

MULTIPLE CHOICE QUESTIONS 1. Converter transformer act as a source of generation of harmonics because of (a) magnetostiction (b) nonlinear nature of B–H curve of iron core (c) magnetising current (d) none of the above 2. In a 12-pulse converter, the two 6-pulse converter groups are fed from transformers connected as (a) Y–Y and Y–D (b) Y–Y and Y–Y (c) D/D and D–Y (d) Y–Y and D–D


HVDC Transmission

3. In a 12-pulse bridge, if one transfer Y–Y has turns ratio 1:1, the other transformer Y–D will have turns ratio (a) 1:1 (b) 1: 3 (c) 3 :1 (d) 1: 2 4. If pulse number = p, and k is an integer, voltage harmonic generated on the DC side is (a) pk + 1 (b) pk – 1 (c) 2pk (d) pk 5. If pulse number is = p and k is an integer, the voltage harmonic generated on the AC side is (a) pk (b) 2pk (c) pk ± 1 (d) 2pk ± 1 6. In a 12-pulse converter, the phase difference between the two 6-pulse bridges is (a) 0° (b) 60° (c) 30° (d) 15° 7. The lowest current harmonic produced in 12-pulse converters is (a) 11 (b) 13 (c) 23 (d) 25 8. Increase in pulse number has the effect of (a) increasing harmonics (b) decreasing the harmonic number (c) increasing the lowest harmonic number (d) no effect 9. Effect of increasing overlap angle is to (a) decrease amplitude of harmonic voltage (b) increase the amplitude of harmonic voltage (c) no effect on magnitude (d) depends on the relative values of a 10. With CC or CIA control as overlap angle m increases, the amplitude of harmonic current (a) increases (b) no effect (c) decreases for some harmonics and increases for some harmonics (d) decreases

ANSWERS 1. (a) 9. (a)

2. (a) 10. (d)

3. (b)

4. (d)

5. (a)

6. (c)

7. (a)

8. (c)

Harmonic Suppression in HVDC System—Filters 6.1


As has been discussed in Chapter 5, harmonic voltages and currents are produced on either side (both AC and DC sides) of HVDC systems. Harmonic voltages generated on the AC side distort the supply nature (sinusoidal) and give rise to various problems that reduce the power quality. Hence, they must be eliminated completely and reduced to a minimum level that will not disturb the power system. The easiest and the most convenient way to eliminate or reduce them is to connect a passive filter which comprises an L-C resonant circuit that offers a low or zero impedance and bypasses the harmonic voltages to a level specified in the technical specifications. This chapter deals with the details of filter configurations, special features of AC and DC filters, active filters, and other methods of suppression of harmonics in HVDC systems.



In order to have an understanding of the process by which harmonic currents are bypassed, a simplified circuit is shown in Fig. 6.1. Ih: Harmonic current to filter In: Current into other AC networks One line diagram of an HVDC station with filter equipment is shown in Fig. 6.2(a) and its equivalent circuit in Fig. 6.2(b).

Fig. 6.1

Circuit for harmonic source with filter

The converter acts as a source of harmonic currents whose amplitude and frequencies may be constant as described earlier. These harmonics travel into the AC network and AC filters, and produce voltage drops of respective harmonic frequencies. The harmonic currents of the order h generated are divided into two components. (a) Harmonic currents in filter branch ( I hf ) =

Vh I Z = hc ha Z hf Z ha + Z hf


HVDC Transmission

Fig. 6.2 An HVDC system with filter network

(b) Harmonic currents in the AC network ( I ha ) =

I hc Z hf Vh = Z ha Z hf + Z ha

and satisfies the condition Ihc = Ihf + Iha


The AC filter requirements change with power transfer through the HVDC system and the requirement depends upon the AC network conditions and their interaction with HVDC systems. The harmonic filter bank is capacitive at low frequencies and the AC system impedance may be inductive. As shown in Fig. 6.2, at some frequencies there may be resonance between the two. The net impedance Ê Z hf ¥ Z ha ˆ Á ˜ may be very high under these conditions and is resistive in nature. The harmonic current Ë Z hf + Z ha ¯

Harmonic Suppression in HVDC System—Filters


produces high harmonic voltage drops when it flows through the large impedance. The impedance for different harmonic orders is also plotted in Fig. 6.3. h indicates the order of the harmonic. The harmonic currents are filtered out using AC filters at the converter buses. It is not possible to filter the entire harmonic currents and therefore, flow of harmonic current into the AC system results in an unbalance in the AC system.

Fig. 6.3 Typical harmonic impedance diagram (Impedances are in p.u. on a 100 MVA base. h denotes harmonic order)

Harmonic Elimination There are two principal means of reducing harmonics— (1) Increasing the pulse number (2) Use of filters Increasing the Pulse Number From the analysis of converters, it is clear that the harmonics entering the AC system can be greatly reduced by increasing the number of phases at which the converter operates. Though theoretically, it is possible to increase the pulse number from 6 to 108, the method demands a more expensive transformer. Therefore, a 12-pulse normal operation is usually the most suitable arrangement.


HVDC Transmission



Any reduction in harmonic output of the converter beyond that achieved by an increase of pulse number must be done by the use of harmonic filters. From an economical point of view, it is a common practice to use a 12-pulse converter with filters. A filter is a network that responds more vigorously at some frequencies than others and reduces the amplitude of one or more fixed frequency currents or voltages. They normally consist of one or more L-C turned circuits with a fairly high Q (40), and can also comprise a high pass filter. However, damping circuit is used to reduce either the overshoot or rate of rise of a transient current or voltage with unusually low Q (=1 or less).

Design of AC Filters AC filters are designed to reduce telephone interference. This can be measured by any one of the following performance indices. Telephone Interface Normally the voice transmission on the telephone lines is from 200 to 3500 Hz. This falls into the range of harmonic currents generated by the converters and can lead to distortion in voice transmission. Electric and magnetic coupling present between telephone lines and power lines results in induced voltages in the communication lines. The magnitude of these induced voltages depends upon the configuration and nearness between the lines. These induced voltages distort communication sent through the telephone lines. The magnitude of these distortions can be calculated and the filters can be designed based on the following values. (a) (b) (c) (d)

Harmonic Distortion Telephone Influence Factor (TIF) Telephone Harmonic Form Factor (THFF) IT Product

(a) Harmonic Distortion This is measured in two ways. The harmonic distortion is defined as D = Sm h= 2 where

Ih Zh ¥ 100 V1


Ih is the harmonic current Zh is the harmonic impedance of the system V1 is the fundamental component of line to neutral voltage m is the highest harmonic considered

A second definition is 1

ÈÎÂ ( I h Z h ) 2 ˘˚ 2 DRSS = V1


Harmonic Suppression in HVDC System—Filters


Often the upper limit for any harmonic voltage is about 1% of the fundamental voltage. In some cases, the harmonic distortion can be defined individually for a single harmonic as Dh = (Ih · Zh /V1) ¥ 100 This definition is now modified as Dn =


En ¥ 100 E ph

where En and Eph are respective harmonic phase voltages to ground for individual harmonic distortion, and total harmonic distortion is defined as

Deff =

50 Ê


En ˆ Á ˜ Ë E ph ¯



(b) Telephone Influence Factor (TIF) This is an index of possible telephone interference and is defined as 1

ÈÎÂ ( I h Z h Fh ) 2 ˘˚ 2 TIF = V1


F1 = 5hf1 ph



and Ph is the C message weighing used by Bell Telephone Systems (BTS) and Edison Electric Institute (EEI) in USA as per the publication 60–63; Sept. 1960* and is shown in Fig. 6.4. This weighing reflects the frequency dependent sensitivity of the human ear and has a maximum value at a frequency of 1000 Hz. (c) Telephone Harmonic Form Factor (THFF) This is analogous to TIF except that Fh =

hf1 ¥ Wh 800


where Wh is psophometric weight in the harmonic order h, as defined by the Consultative Commission on Telephone and Telegraph Systems (CCTTS). The factor TIF is used in USA and THFF is commonly used in Europe. The telephonic harmonic factor is now computed as Fig. 6.4 Telephone Influence Factor 2


˘ 50 È E Â1 Í E n K n Pn ˙ ¥ 100 ÎÍ ph ˚˙

*See references 4 and 6.



HVDC Transmission

(d) IT Product BTS–EEI system has defined another index known as IT product and is given by 1

IT = ÈÎÂ ( I h Fh ) 2 ˘˚ 2


and KIT product is defined as KIT = IT/1000


From past experience of telephone companies, an IT product of about 10,000 is acceptable. Even though there are no specific standards on the performance requirements, the following are the suggested values of the above indices, as given in Table 6.1. Table 6.1 Typical Values of Indices Index

Suggested values


25 to 50



25 to 100


2 to 5






1 rd


1.25% 3 & 5 , 1.0% odd, 0.5% even harmonic






It is mentioned above that the converter station generates characteristic harmonics of the order 11, 13, 23, 25, etc., in case of 12-pulse bridges. Filters are used to drain these harmonics. The present practice is to provide tuned band-pass filter for 11th and 13th harmonics and damped high-pass filters for higher harmonics. Filters used in HVDC stations not only absorb harmonics but also provide VAR support for the converters. Due to this reason, a co-ordinated design between filter performance and reactive power balance is essential. Following are the various types of AC filters that can be used— (a) Single tuned filters (b) Double tuned filters (c) High-pass filters (i) Second order filters (ii) C-type filters The configuration of these filters and their impedance characteristics as a function of frequency is shown in Figs. 6.5(a) to (e). Single tuned filters are designed to filter out characteristic harmonics of single frequency. Double tuned filters are used to filter out two discrete frequencies, instead of using two single

Harmonic Suppression in HVDC System—Filters


Fig. 6.5 Filter configurations and impedance characteristics

tuned filters. The main advantages are (i) only one inductor is subjected to full line impulse voltage and (ii) power loss at the fundamental frequency is considerably reduced.


HVDC Transmission

High-pass filters of second order are designed to filter out the higher harmonics and the tuning of these filters is not critical. C-type filters can be used to minimise losses at fundamental frequency as the leg containing C2 in series with L offers low impedance to fundamental frequency. The advantages of high-pass filters are (i) no sharp tuning is required, (ii) it tolerates relatively large steady state frequency variation, and (iii) it reduces transient voltage due to large resistance. However, it has higher losses. In Figs. 6.6(a) and (b), an arrangement in a 1000 MVA/1000 MW HVDC station is shown.

Fig. 6.6(a) AC filters and switchyard Arrangement of filter bank in 1000 MVA station shown in Fig. 6.6(b)



It consists of capacitor (C) and reactor (L) in series with a resistance (R) and is turned to a specific harmonic frequency. The filter impedance is given by Zf = R + j(wL – 1/wC)


At resonance frequency, the impedance is the lowest and is equal to pure resistance R. The band-pass filter is commonly tuned to such a frequency at which its reactance is equal to the resistance. Its impedance is given as Zf =

2 R 45∞

If the filter is turned to an angular frequency of wn rad/s


Harmonic Suppression in HVDC System—Filters

Fig. 6.6(b) 3-phase harmonic filters arrangement in a typical HVDC station of 1000 MVA/MW



HVDC Transmission

1 LC


wn =


wn = 2pfn Xn = w n L = Xn =



1 w nC



The quality factor Q is given by Q=

Xn R


Detuning A vital factor in the design of band-pass filter is the difference between filter resonant frequency and the frequency of the harmonic current to be absorbed. This disparity can arise by variation in system frequency or by change in L and C of the filter circuit due to ageing and temperature rise. The frequency deviation is defined as = where

w - wn wn


w = Actual resonant frequency wn = Tuned frequency dwn = w – wn w = wn (1 + d)


¸ Ô Ô ˝ 1 1 Ô C= = w n X n w n RQ Ô˛


At tuned frequency L=

X n RQ = wn wn

substituting the values of , L and C in Zf in (6.18) w n RQ w n RQ ¸Ô ÏÔ Zf = R + j Ì(1 + d ) ˝ wn w n (1 + d ) ˛Ô ÓÔ Ï Ï {Q(1 + d ) 2 - 1} ¸ (d + 2)Q ¸ = R Ì1 + j ˝ = R Ì1 + j ˝ (1 + d ) (1 + d ) ˛ Ó Ó ˛

Harmonic Suppression in HVDC System—Filters


Ï1 (d + 2) ¸ = RQ Ì + j ˝ (1 + d ) ˛ ÓQ Ï1 (d + 2) ¸ = X n Ì + jd ˝ (1 + d ) ˛ ÓQ = Xnk


Ê1 ˆ = Á + j (2 + d )/(1 + d )˜ ËQ ¯


The quantity k can be calculated for different values of Q as a function d. The variation of k with detuning factor d is shown in Fig. 6.7. Using the curves, the absolute value of the band-pass filter impedance will be Zf = Xn | k |

Fig. 6.7 Factor[k] vs detuning (Zf = filter impedance ∫ Xn k where k = 1 + j(2 + d)/(1 + d)) Q



HVDC Transmission

The detuning contribution due to change in frequency would be dF =

± Df f


The detuning due to change in capacitance can be estimated from dC = a0(T – T0)2


where T0 is the temperature at which capacitance is defined (tuned) and T is the temperature at which the detuning has to be calculated and a0 is the temperature coefficient of capacitance. The detuning is d = dF + dC


From Fig. 6.2 the harmonic current in the filter branch is Ihf =

I hc ¥ Z ha Z ha + Z hf


The harmonic voltage at the converter bus is Vhf = Ihf ¥ Zhf




AC filters are used for filtering and reactive power compensation. The capital cost of AC filters varies between 5 to 12% of the capital cost of the HVDC terminal substation equipment. The total reactive power generated by AC harmonics filters is normally 10 to 40% of the active power transfer of an HVDC link. The remaining reactive power demand of the terminal substation is fulfilled by AC shunt capacitors/synchronous condensers. Synchronous condensers are used on the AC side of an HVDC link when short circuit level at the AC bus due to the AC network is less than required. The total capital cost of an AC harmonic filter includes the following components— (a) Cost of AC filter capacitors which is directly proportional to the MVAR size of the AC filter branch. (b) Cost of AC filter reactors which varies inversely with the MVAR size of an AC filter branch. (c) Cost of the related circuit breakers, CTS, resistors, busbars, etc., which is fixed. The total cost is expressed as K = AS + B/S + C


where A, B and C are constants and S is the reactive MVAR supplied by the filter. For the minimum cost of the filter dK B = 0= A- 2 +0 dS S S = B/A

(6.29) (6.30)

Harmonic Suppression in HVDC System—Filters


The minimum cost of the filter is given by Kmin = A B/A + B A/B + C = 2 AB + C




High-pass second order filter is usually provided for eliminating harmonics of order greater than 17. Using the following parameters Z0 =

L/C ; s = R/Z 0 and h0 = 1



The following values can be chosen as 0.5 < s < 2 h0 £


2 hmin

where hmin is the smallest of h to be handled by the filter, the choice of h0 given above implies that the impedance of the filter at hmin = R. The filter impedance is given by Zhf =

Z 0 ÈÎs + j (h0 + h){s 2 - 1 - (s h0 /h) 2 }˘˚ 1 + (s h0 /h) 2


The reactive power supplied by the filter is U12 2 S = ÈÎh0 /(h0 - 1) ˘˚ ¥ Z0


It can be shown that the filtering is improved if S is increased and higher value of h0 can be chosen. Therefore, it is advantageous to design it for a 12-pulse operation.



The filters connected to the system will be subjected to overvoltages during switching operations and the magnitude of the overvoltage depends on the short circuit ratio (SCR) and saturation level of the B–H curve of the core of converter transformers. During switching operations, the current through the filters at filter frequencies can be as high as 20 to 100 times the normal harmonic current under steady state. The lower values of current for band-pass filters which are tuned for higher values are applicable for high-pass filters. These overcurrents must be taken into account while designing the reactor coils as they produce extra-electromagnetic forces between the turns of the coil. When the filters are disconnected, their capacitors carry residual charges corresponding to the instant of


HVDC Transmission

switching. The residual DC voltage may also appear on busbars. To avoid these residual voltages, capacitors are crow-bared to discharge the residual charges. AC filters will be subjected to higher currents and losses when there is deviation in system frequency and sometimes it is necessary to disconnect them such as when the current exceeds its limit.



The main objective of AC filters is to create a low impedance path for the harmonics generated and VAR compensation for the converters. This dual function of the filters is satisfactory at high DC loads, but at low loads, levels leading reactive power generated by the filters may be more than the lagging VARs generated by the converters, which may result in overvoltages. In order to avoid adverse effects, reactive power balance study is co-ordinated with filter design. The reactive power absorption of the DC link with variation of DC current is shown in Fig. 6.8.

Fig. 6.8 Converter VAR requirement

The filter banks at fundamental frequency behave like pure capacitance and the VAR generation is approximately equal to VAR rating of the capacitors in the filter bank. This is not much affected by the presence of reactors. The problem in the design of filters is that the VAR generation from filters and shunt capacitors must match the requirements of the system over the entire range of load without sacrificing the filtering performance specified. Figure 6.9 shows the VAR generation of a typical filter bank superimposed on the requirements of reactive power consumption of DC links. At the time of switching of filter banks, there will be surplus reactive power generated from the banks and at this stage, the AC system has to accept the surplus reactive power. The switching of filter banks normally takes place at points to minimise VAR flow to or from the AC system, as shown in Fig. 6.10. At each

Harmonic Suppression in HVDC System—Filters

Fig. 6.9 Co-ordination of VAR consumption and generation

Fig. 6.10

VAR flow to or from the AC system



HVDC Transmission

switching operation filter performance criteria has to be maintained. Filter design and cost are influenced by the limits of VAR flow to or from the AC system. Narrow limits will reduce individual bank size and demand several switching points which may make filters and banks unnecessarily costly.

6.10 DC FILTERS The DC voltage on the converter side contains both characteristic and noncharacteristic harmonics. These harmonics result in current harmonics in the DC line and produce noise in telephone circuits. The harmonic currents generated, depend on the source of harmonic voltage, smoothing reactor, the DC filter and line parameters. The harmonic current varies from point to point along the line from the converter station, as it is dependent on distance. Effectiveness of the DC filter is judged by one of the following conditions— (a) Maximum TIF value on the DC high voltage bus. (b) Maximum included noise voltage (INV) in millivolts/km in a parallel test line situated one kilometre away from the HVDC line. (c) Maximum permissible noise to ground in dB on telephone lines close to HVDC lines. The second condition stated above is widely used, which also involves the commutation of harmonic currents and the mutual impedance, which depends on the following factors— (1) Resistivity of the earth (2) Method of operation (monopolar/bipolar) (3) Nature of ground return (metallic, etc.) Figure 6.11 illustrates the variation of C message weighed induced noise voltage (INV) for the three cases (1) Monopolar mode, (2) Bipolar mode, and (3) Monopolar with earth return as a function of distance measured from the converter station.

Fig. 6.11

Variation of INV with distance of DC link

Harmonic Suppression in HVDC System—Filters


Induced noise voltage of 18–20 mV/km is allowed for monopolar operation. The DC filter used may be single-tuned or double-tuned type to filter out 6th or 12th harmonic voltages and high-pass filters are used to filter out higher order harmonics. Overvoltages due to DC line resonance and faults in the DC line are affected by the installation of DC filters. The smoothing reactor and surge capacitor play a role in increasing the wavefront of the surge voltages in the order indicated. From an analysis of travelling waves it is found that DC filters help in limiting the magnitude of overvoltages and elongating the front time in case of monopolar lines. DC filters are designed only to eliminate DC harmonic voltages and there is no need for the filters to supply reactive VARs as in case of AC filters. The designers must take into account that they are subjected to stresses due to DC voltages, in addition to harmonics.

6.11 POWER LINE COMMUNICATION AND RI NOISE HVDC converter stations produce high levels of electrical noise whose frequencies range in the carrier frequency band from 22 kHz to 500 kHz. They also generate radio inference (RI) noise of frequencies in the mega hertz range. However, converters are usually located in buildings which act as a shield to electromagnetic radiation and, therefore, valves in the HVDC station do not contribute to direct radiation of noise. The radiation from the DC switch yard is considerable when compared to DC lines. Therefore, power line communication and radio interference (PLC-RI) filters are used to minimise interference with power line carrier communication system. Typical PLC-RI filter is shown in Fig. 6.12.

Fig. 6.12

Configuration of PLC-RI filter

The attenuation requirements of such filters are shown in Fig. 6.13. The required attenuation of noise by the filters must be above the values indicated by the curve. The arrangement of filters and damping circuits on HVDC converters is shown in Fig. 6.14.

Fig. 6.13 Attenuation requirements of PLC-RI filter

6.12 ACTIVE FILTERS AND THEIR APPLICATIONS In high voltage applications, harmonic filters will be of huge size costing several millions of rupees with passive elements such as inductors and capacitors only. Further, they are not exactly tunable due to nonlinearities in the elements, viz. inductors. Therefore, in order to minimise cost and also get variation of tuning


HVDC Transmission

Fig. 6.14 Arrangement of filters and damping circuits on HVDC converters B: Damper circuit, D: Damper across line reactor, E: Harmonic filter

depending on the magnitude of the harmonics, active filters and hybrid filters have been developed in recent times. Active filters can be connected in series, or in parallel with loads, or through a coupling connection. The principle employed in the active filter is that it generates harmonic current and injects it into the circuit in an opposite direction. The equivalent circuit representation of harmonic source (the converters) together with active filter is shown in Fig. 6.15.

Fig. 6.15

Equivalent circuit of harmonic source and active filter

VS is the harmonic source which produces a voltage and drives a current IS. The active filter through the tuned circuit Lr, Cr injects a current Ir in the opposite direction, so that the net harmonic current is reduced to a minimum into the network Zh (load). The active filter thus suppresses the harmonic currents produced.

Harmonic Suppression in HVDC System—Filters


The first commercial active filter was installed in Skagerrak-3 HVDC scheme (Denmark) and was commissioned in 1993. The reduction in harmonic currents with and without active filters are shown in Table 6.2. Table 6.2

Reduction in harmonic current with active filter

Harmonic number

‘f’ (Hz)

Without active filter (Arms)

With active filter





















The primary function of active filter is to counteract the harmonics. Either a current source or voltage source converter is chosen for an active filter function. However, VSC converters are most common. The cost of a passive filter is more as the harmonic current reduces but the cost of an active filter remains the same. As such, a simple passive filter in series with the active part is used (Fig. 6.16). Schematic arrangement of active filter in series with a passive filer is shown in Fig. 6.17 (a) and (b).

Fig. 6.16 Relation between harmonic current and firing angle a for the two filters

The active filter is connected in series or parallel depending on (i) harmonic source, (ii) measurement points, (iii) regulation aspect from circuit point, and (iv) integration of the filter into the system. Advantages and benefits of active AC and DC filters— (i) (ii) (iii) (iv)

They can track system frequency and can filter several harmonics at the same time. Excellent performance even in case of detuning of passive filter. Easy adoption to existing passive filters. Less resonance frequencies due to interaction with network impedance and other filter capacitors and reactors. (v) They meet the highest harmonic performance which is needed for environmental issues in metros and mega cities.

6.13 FILTERS WITH VOLTAGE SOURCE CONVERTER (VSC) HVDC SCHEMES Since VSC schemes operate on PWM converter principle, the switching frequency is high, typically 1 to 2 kHz. Hence, the typical lowest harmonic frequency generated will be 20th harmonic or more on the DC side


HVDC Transmission

Fig. 6.17(a) Topology of an active DC filter

Fig. 6.17 (b) Advanced active filter for AC side

Harmonic Suppression in HVDC System—Filters


and 19th, 21st and higher harmonics on the AC side. Therefore, no tuned filter is used but only high-pass filters are used. Typical filter used with an HVDC-VSC scheme is shown in Fig. 6.17(b) along with a conventional high frequency (high-pass) filter in series with active filters as described earlier.

6.14 OTHER METHODS OF HARMONIC ELIMINATION Due to the substantial cost of filter circuits coupled with complexity of design, other methods have been suggested to achieve the control of harmonics. They are (a) Elimination by magnetic flux compensation (b) Elimination by harmonic injection (c) Elimination by DC ripple reinjection

6.14.1 Magnetic Flux Compensation This method of harmonics elimination is shown in Fig. 6.18. A current transformer is used to detect the harmonics coming from the nonlinear load. These currents are fed to the tertiary winding of a transformer through an amplifier in such a manner as to cause cancellation of the harmonic currents concerned. The main difficulty in this arrangement is the coupling between the tertiary and the output of the amplifier, so that the fundamental current flow does not damage the amplifier. This is reduced to some extent by providing a quaternary winding and the filter as indicated in Fig. 6.18.

Fig. 6.18

Magnetic flux compensation for harmonic elimination

The main advantage of this scheme is its ability to remove uncharacteristic harmonics of the order 3rd and 9th. A disadvantage is its inability to eliminate lower order characteristic harmonics of large magnitude.

6.14.2 Harmonic Injection The converter rectangular current waveform is modified by adding current harmonics from an external source as shown in Fig. 6.19. A triplen harmonic from the current source (S) is injected in the conducting transformer


HVDC Transmission

phases. The advantage of this scheme over filtering technique is that the system impedance has no effect on the design criteria. The main disadvantages of this system are as follows: (a) It requires a separate current source of triplen harmonics and it must be synchronised with the system source. (b) For each operating condition, the magnitude and phase of the injection current should be varied and this is not a simple job. (c) It can eliminate only one harmonic order at any operating point. (d) Poor efficiency due to extra losses because of triplen harmonics. (e) It is suitable for rectifier operation with a = 0.

Fig. 6.19 Method of harmonic injection

6.14.3 DC Ripple Injection In this method, triple frequency current wave is generated such that the magnitude is a function of the magnitude of DC current and wave shape. This current is injected into the neutral of the main transformer secondary and flows through the conducting transformer winding. The modified currents in the transformer phases will then contain only 12-pulse related current harmonics.

REFERENCES 1. Kimbark E.W., DC Transmission, Vol. 1, Wiley InterScience (New York), 1971. 2. Arillaga J., HVDC Transmission, Peter Peregrinus Ltd. (London), IEE, 1983.

Harmonic Suppression in HVDC System—Filters


3. Padiyar K.R., HVDC Transmission Systems, Wiley Eastern Ltd. (New Delhi), 1992. 4. Clarke C.D. et al., Application of self tuned harmonic filters to HVDC converters, IEE Conference on HVDC, Publication 22, 1966. 5. Stanley C.H., Price C.J. et al., Design and performance of AC filters for 12-pulse HVDC schemes, IEE Conference Publication 154, 1977. 6. AC Harmonic Filters and Reactive Power Compensation, Cigre WG 14.03, Brochure 65, June 1990. 7. Active filters in HVDC applications tech., Cigre WG 14.28, Brochure 223, April 2003. 8. Zhang et al., Active DC filter for HVDC applications, IEEE Computer Applications in Power, Vol. 7, No. 1, 1994. 9. Gunnerson Stephen et al., Active filters for HVDC Applications, ABB Power System Ltd. AB, Ludvika (Sweden), ABB website, 2003.

WORKED EXAMPLE 1. Determine the cost of a 5th harmonic filter for a bipolar 4-bridge 12-pulse converter rated 1000 A, ± 300 kV. The filter is connected to 400 kV, 3-ph. 50 Hz supply. Filter is to be designed for operation with one bridge out of service. Cost: Capacitors 20 lakhs/MVAR Inductors 45 lakhs/MVAR Take a = 15°, p.f. = 0.866 and network impedance angle limited to 75°. Solution: Rated power = 600 kV ¥ 1.0 kA = 600 MW 600 = 1.0 kA Ifull on the AC side = 3 ¥ 400 kV ¥ 0.866 I(fifth) =

1000 = 50 A 5¥4

Correct overlap angle is to be taken. Since it is not given Ififth is taken as 10% more I5 = 50 ¥ 1.1 = 55 A V 45,00,000 A = VC + L2 = 20,00,000 + Rs/MVAR h 25 = Rs. 38,00,000/MVAR 2

Ê 400 ˆ ¥ 552 ¥ 10 –6 ¥ 65,00,000 V12 I h2 (VC + VL ) ÁË 3 ˜¯ = B= 5 n = Rs. 20,97,00,000


HVDC Transmission


Smin =

B = 7.43 MVA/ph. A

K min =

AB = 2,85,00,000 Rs/ph.

285 ˆ Ê Cost factor K = Á 38 + ˜ = 95 lakhs/ph. Ë 5 ¯ C=

Smin = w12V12


1 106 = = 0.877 H C (nw1) 2 0.455(5 ¥ 100 p ) 2


X w L 100p ¥ 0.877 = = ª9W Q Q 30

7.43 Ê 400 ˆ (100 p ) 2 ¥ Á Ë 3 ˜¯


= 0.455 m F

Taking Q = 30 and d = 0.02

V5 = 3.2 d X0I5 = 3.2 ¥ 0.02 ¥ 125 ¥ 55 = 4,400 or 4.4 kV Note: This is nearly 2% V1, fundamental voltage. Harmonic voltage should be kept around 1%. As such, filter size should be doubled.

QUESTIONS 1. Mention the various sources of harmonic generation in HVDC systems and suggest methods to eliminate them. 2. Define Telephone Interference Factor and explain how it varies with the harmonic order. 3. Explain the working of band-pass and high-pass filters used in HVDC systems. Explain the term detuning and state its importance in the design of filters for HVDC systems. 4. Explain the need to employ filter circuit in HVDC systems. Derive an expression for minimum cost of tuned AC filters used in HVDC systems. 5. What are the different types of filters used on the AC side of an HVDC system? How are they located and arranged? 6. Give the schematic diagram and layout of harmonic filters on the AC side of an HVDC system. 7. How is a filter designed? How is cost optimisation obtained in choosing L and C of a filter? Illustrate with examples. 8. Why are filters not needed on the DC side with HVDC voltage source converter schemes? 9. What are the order of harmonics present on the AC side of the VSC converter DC systems? 10. What are the other methods of eliminating or suppressing harmonics with HVDC system? Give a comparison using passive filter network.

Harmonic Suppression in HVDC System—Filters


MULTIPLE CHOICE QUESTIONS 1. Filters used in 12-pulse converters usually on the AC side are (a) 5th, 7th and high-pass (b) 11th, 13th and high-pass th th (c) 6 , 12 and high-pass (d) Only high-pass filter 2. For power frequency, the harmonic filter acts as a (a) leading p.f. load supplying leading kVA (b) lagging p.f. load supplying lagging kVA (c) (a) or (b) depending on the p.f. of the system (d) leading p.f. at rectifier end and lagging p.f. at inverter end 3. The maximum value of the harmonic current depends on (a) firing angle (b) overlap angle (c) DC current (d) both firing angle and overlap angle 4. TIF factor usually lies between (a) 10 to 25 (b) 20 to 30 (c) 25 to 50 (d) 50 to 100 5. DSS product defined for harmonic distortion is given by m

1/ 2

(a) Â ÈÎ( I n Fn ) 2 ˘˚ n= 2

1/ 2

Èm ˘ (b) Í Â ( I n Fn ) 2 ˙ Î n= 2 ˚

1/ 2

1/ 2

Èm ˘ (c) Í Â ( I n Z n Fn ) 2 ˙ Î n= 2 ˚

Èm ˘ 2 Í Â (In Zn ) ˙ ˚ (d) Î n= 2 E1

¥ 100

In harmonic current, Zn = harmonic impedance, Fn = weighing factor, m = max. harmonic considered 6. Network impedance characteristic is given as (a) Locus of Z in R, X plane for each harmonic (b) Network impedance in R, X plane for a given harmonic (c) Variation of harmonic current with the magnitude of harmonic voltage (d) All of the above 7. Harmonic filters are protected by (a) overcurrent relays (b) lightning arresters (c) spark gaps (d) none of the above 8. In HVDC-VSC schemes filters are used (a) only on the AC side (b) only on the DC side (c) both AC and DC side (d) no filter is needed 9. Size of an AC filter and its MVAR capacity is much less in VSC schemes as (a) no harmonics are generated (b) harmonics generated are of much higher order (c) filter need not supply RKVA at power frequency and harmonics generated are at switching frequency and higher (d) none of the above


HVDC Transmission

10. In a 2nd order or 3rd order filter, which of the components R, L or C are to be rated to full AC power frequency voltage? (a) Inductor (b) Capacitors (c) Resistors (d) Both inductors and capacitors

ANSWERS 1. (b) 9. (c)

2. (a) 10. (b)

3. (d)

4. (c)

5. (d)

6. (a)

7. (b)

8. (a)

Grounding and Ground Electrodes for HVDC Systems 7.1


It was indicated in the first chapter that HVDC transmission is a viable alternative to long distance AC transmission because of its relative advantages. One advantage is its ability to transmit power by using ground as return conductor. Most DC transmission systems use ground or sea water as return path for current either continuously or for short times in emergency and such return paths are known as ground return, even if the sea constitutes all or part of the path. A bipolar transmission system using ground return mode is more reliable in transmitting power with less losses, even when one of the poles is faulty, than an AC transmission line. Here a comprehensive review of the general subject of ground electrodes, which is an essential part in ground return operation of HVDC transmission systems is presented. Type of ground electrodes explained in this chapter are unique for HVDC transmission systems. The following sections present a brief technical background of theory and practice of DC power transmission through the earth as return conductor and also the techniques which can be applied to the selection of sites for ground electrodes. A methodology of design of various types of ground electrodes is also included.



The following are certain advantages of use of ground return. 1. The ground path has a very low resistance and consequently low power loss in comparison with a metallic return conductor of economical size and equal length, provided ground electrodes are properly designed. The resistance of the ground path of DC currents is low because the DC current under steady state spreads over a very large cross-sectional area in both depth and width, and does not follow closely the route of the metallic conductor unlike transient AC current. The resistance of this path is independent of the length of the line as the resistance of the ground is negligible and mostly comprises ground electrodes at each end. 2. A bipolar line is more economical than a monopolar line with ground return. A bipolar line has twice as many conductors and can carry twice as much power at slightly higher efficiency than the monopolar line. Its cost is surely less than twice that of a monopolar line with overhead conductors. Apart from this, a bipolar line can be built in two stages if the power demand on the line at the initial stages is


HVDC Transmission

less. It can operate in the first stage as a monopolar line with ground return and in the second stage as a bipolar line without ground current. This saves initial capital investment except the cost of ground electrodes, which are required for monopolar operation at the first stage. 3. A bipolar line in the second stage can supply almost 50% of its rated power in the event of fault on one of the poles. Therefore, the reliability of a bipolar DC line is almost equal to that of a double circuit 3-phase AC line, even though it has only two conductors instead of six. Monopolar, homopolar and unbalanced HVDC system must have ground electrodes rated for continuous operation. HVDC transmission systems may have time restrictions during which ground transmission may be used or on the total number of ampere-hours per year. In case of an outage of a converter pole, the ground electrodes will automatically carry the load current of the healthy pole, but if there is a restriction in time or current for ground return, the system may be designed to eliminate ground current by using the conductor of the faulted pole as the return path. This operation can be accomplished without interruption of supply by the use of a scheme known as the metallic return as shown in Fig. 7.1. A metallic return transfer breaker (MRTB) is used.

Fig. 7.1 Switching arrangement for operating a bipolar system in metallic return mode

7.2.1 Disadvantages of Ground Return Ground return has some disadvantages too. They are as follows: (a) Design of ground electrodes with low resistance with low cost of installation and maintenance. (b) The location and screening of the electrodes must be properly carried so that the electrolytic corrosion of buried metallic structures, step and touch voltages are within permissible limits due to the presence of ground currents.

Grounding and Ground Electrodes for HVDC Systems


(c) The interference of ground currents with nearby AC power transmission, railway signals and ship compasses should be minimised.



All the three modes of operation of HVDC systems, viz. monopolar, bipolar and homopolar systems, which are described in Chapter 1, can employ ground return currents. A monopolar system as shown in Fig. 1.3(a) operates with only one high voltage pole and uses the earth as a return conductor so that its ground current is equal to the current in the insulated conductor, but of an opposite polarity. A grounded bipolar system operates with poles having their centre point connected to the ground as shown in Fig. 1.3(b). Under practical operating conditions, the current through the electrodes is not zero. Id1 ~ Id2 because small deviations between equipment parameters such as the impedance of the converter transformer and firing angle cause an imbalance between the pole currents. This current is usually of the order of 1 to 3% of the line current and flows through the ground electrodes, and can be of either polarity. The homopolar system utilises more than one pole of the same polarity preferably negative as shown in Fig. 1.3(c). The ground current in this system is equal to the sum of line currents and is continuous. Before designing the ground electrodes, knowledge of the distribution of ground currents in the vicinity of an electrode is essential. Field around ground electrode is presented in the next section.



The current field at any point in the earth is described in terms of two vector quantities, viz. the current density – – J and electric field intensity E and the scalar electric potential Ve of the electrode with respect to remote earth. The current field depends upon variation of these parameters around the vicinity of the electrode or near the surface of the earth.

7.4.1 Resistivity of the Earth The earth has different layers with different resistivities as shown in Fig. 7.2. It is non-uniform and has a core radius of 3500 km (55 per cent of the radius of the earth). It consists of hot molten magma of low resistivity. It is surrounded by a mantle 2860 km thick made of hot solid material of medium resistivity. The mantle is covered by a crest of rocks 40 km thick of high resistivity. This crest is thin or absent under the oceans. The surface layers of land over the rocks contain many local irregularities of different resistivity such as rivers, marshes, deserts, etc. Approximate resistivities of some materials encountered by ground currents are listed in Table 7.1.


HVDC Transmission

Fig. 7.2 Cross section of the earth Table 7.1

Resistivities of materials encountered by ground currents Material

Typical Resistivity (ohm-m)


1.72 ¥ 10


At 20°C, increase with temperature

1 ¥ 10


Varies with composition

3. Steel

1 to 7 ¥ 10–7

Varies with composition

4. Lead

1. Copper 2. Iron

2.2 ¥ 10


3 ¥ 10


5. Carbon 6. Granulated coke


7. Sea water


Varies with salinity and temperature

8. Fresh water 9. Soils

5 to 300

Varies with temperature and impurities

10 to 1000

Varies with temperature and impurities

10. Average land surface


Varies with temperature and impurities

11. Rocks

103 to 108

Depending upon the minerals

The site for an electrode must be selected carefully such that the location has ample supply of ground water and the resistivity of the earth at the location must be low. The electrode is buried in the earth at a depth of 1.2 m to 8 m. The electrode at which the direct current enters from the HVDC system is termed as anode. The current returns to the HVDC system through the electrode at the other end and is known as cathode. The earth acts as a conducting mass having non-uniform resisitivity. However, for the purpose of simplicity of analysis, the earth is considered as a mass of uniform resistivity with the following assumptions. 1. Surface of the earth is a horizontal plane.

Grounding and Ground Electrodes for HVDC Systems


2. The electrode is hemispherical in shape with centre at the surface of the earth with radius of a meters as shown in Fig. 7.3.

Fig. 7.3 Current flow lines from hemispherical electrode in the surface of uniform earth and equipotential surfaces



Due to symmetry of geometry, the current flow lines are radial and current density is uniform over the surface – of a hemispherical electrode as shown in Fig. 7.3. The current density J at any radius r is given by – Id = Id J = S 2p r 2


Id = DC current entering the ground electrode r = Radius of the hemisphere in metres S = Surface area of the hemisphere 2pr2 (m2) a = Radius of the hemispherical electrode in metres – – The electric field intensity E and the current density J are related as r ¥ Id – E = rJ = 2p r 2


where r is the resistivity of the earth in ohm-meters. The electric potential at any point in the earth with respect to zero potential at infinite is r


V = – Ú E ◊ dl = - Ú E ◊ d r •

= –

rId 2p



Ú r2 =

rId È1 ˘ volts 2p ÍÎ r ˙˚



HVDC Transmission

The electric potential is maximum at the surface of the electrode and is given by Ve =

rId 2p a


– – and it decreases inversely as the distance of the point from the electrode, whereas the J and E vary inversely as the square of the distance as shown in Fig. 7.4.

– – Fig. 7.4 Variation of J , E and V in uniform earth around the hemispherical electrode

7.5.1 Resistance of the Electrode in Uniform Earth The resistance of the hemispherical electrode can be obtained from the expression (7.4) as Potential of the electrode w.r.t remote earth Current through the electrode Ve r = Re = I d 2p a

Re =


The resistance of the earth between r = a and r = 2a is given by Rea =

r r È r ˘ – =Í 2p a 4p a Î 4p a ˙˚


It is found from the expression (7.6) that Rea = ½ Re


It is understood from the expression (7.6(a)) that half the resistance of the electrode is due to the earth between the electrode and the hemisphere having twice the radius of the electrode. Low ground resistance is required

Grounding and Ground Electrodes for HVDC Systems


for HVDC transmission which can be obtained by locating large electrodes in wet soil. For practical reasons, the electrodes used are not hemispherical, but expression (7.5) is still valid because distances involved are several times the dimensions of the electrodes and much smaller than the distance to the other electrode.

7.5.2 Resistance of the Electrodes in Non-uniform Earth The expression (7.5) suggests that low earth resistivity reduces the resistance of the ground electrode. A more reasonable approach would be to locate the electrode in soil with lower resistivity (r1) which is much lower than the resistivity (r2) of the rest of the soil, as shown in Fig. 7.5.

Fig. 7.5 Hemispherical electrode of radius a immersed in a soil of resistivity r1 (r2 > r1)

The current flow lines are still radial because of symmetry. The electric field intensity is given by – r2 I d ( r > b) E= 2p r 2 =

r1 I d 2p r 2

( a £ r £ b)

The electric potential of the electrode is given by È b r2 I d dr a r1 I d dr ˘ +Ú ˙ Ve = – Í Ú 2 2p r 2 ˚˙ b ÎÍ• 2p r a I d È È 1 ˘b È1 ˘ ˘ r + r Í = 1Í ˙ ˙ 2p Î 2 ÍÎ r ˙˚ • Î r ˚b ˚


I d È r2 Ï 1 1 ¸˘ + r1 Ì - ˝˙ 2p ÍÎ b Ó a b ˛˚


Id È 1 r ˘ ( r2 – r1 ) + 1 ˙ Í a˚ 2p Î b



HVDC Transmission

The resistance of the earth electrode in non-uniform earth is

Re =


Ve Id


1 È ( r2 – r1 ) r1 ˘ + ˙ b a˚ 2p ÍÎ

r2 Ê r ˆa Êr ˆ 1– 1˜ +Á 1˜ Á 2p a Ë r2 ¯ b Ë r2 ¯



The resistance of the earth electrode of radius a and immersed in a soil of resistivity r2 according to (7.5) is Re =

r2 2p a


The ratio of Resistance of the electrode with non-uniform earth Resistance of the electrode with uniform earth


Re¢ ÈÊ r ˆa r ˘ = Í 1– 1˜ + 1˙ Re ÎÁË r2 ¯ b r2 ˚


Taking b = 10 a and r2 = 10 r1 Re¢

reduces to 0.19 and consequently the electrode potential will be reduced in the same ratio. Re The above method of embedding the hemispherical electrode in a volume of low-resistivity material is not practicable. But the electrode resistance can be lowered by locating the electrodes in marshy soil or in a trench-back filled with coke. The effect of the above method is purely local and has no effect at points beyond the area of low resistivity material. However, the method not only reduces ground resistance and potential of the electrodes but also limits power loss, heating of the earth and step voltage near the electrode. The ratio of

7.5.3 Resistance of the Buried Electrodes (a) Spherical Electrode Consider a spherical electrode of radius a buried in uniform earth or immersed in liquid of resistivity r. The centre of the electrode is at a depth h metres below the horizontal surface as shown in Fig. 7.6. The current is fed to the electrode through a small insulated wire from a source above the surface. The above problem can be solved using the method of images which satisfies the boundary conditions at the surface of the earth. An image conductor of same size as the buried conductor is considered but situated at h metres above the ground, carrying same current as the buried electrode. It is also assumed that the medium above the ground is replaced by a medium of same resistivity as that of the earth below the ground.

Grounding and Ground Electrodes for HVDC Systems


Fig. 7.6 Buried spherical electrode in uniform earth of resistivity r

The current density at Q is due to the combined effect of the buried electrode and its image electrode is given by 2Id 2I x I x – ¥ cos q = d 3 = d 3 J= 2 4p r 4p r 2p r


rId x rId x – = E = rJ = 3 2p r 2p ( x 2 + h 2 )3/ 2


The electric field is zero at P, at x = 0 and for x >> h rId rId – = (x ª r) E= 2 2p x 2p r 2


– Considering the expressions (7.13) and (7.14), one can conclude that E increases with x up to some value and dE – = 0. then decreases and therefore E attains a maximum value when dx i.e.

rId È x.3 / 2.2 x ˘ 1 – 2 =0 Í 2 2 3/ 2 2p Î ( x + h ) ( x + h 2 )5/ 2 ˙˚ 1–

3x 2 = 0; ( x2 + h2 ) 2x2 = h2; x = h/ 2 x = h/ 2



HVDC Transmission

The maximum value of Emax is Emax =

rId 3 3p h



0.0614 r I d h2

V /m


The maximum field intensity of hemispherical electrode situated at the surface of the earth occurs at its surface and is given by the expression (7.2) when r = a as Emax = The ratio of



2p a 2

Emax of a buried electrode Emax of a surface electrode =

rId 3 3p h


rId 2 ( a/h ) 2 = 2 2p a 3 3

= 0.385 (a/h)2


For a case a/h = 0.1, the maximum field intensity is reduced in the ratio 0.385 ¥ 10–2. The buried electrode also reduces hazardous step potential to a safe value. The step voltage is the potential difference between two feet of 1 m separation of a person or animal on the surface of the earth near the electrode. The variation of – E at the surface of the earth due to a buried spherical electrode is shown in Fig. 7.7(a).

Fig. 7.7(a) Electric field intensity at the surface of the earth due to a buried electrode

The potential of the buried electrode is obtained by the addition of the potential due to its own current field in an infinite medium and the potential due to its image electrode and is expressed as

Grounding and Ground Electrodes for HVDC Systems

Ve =

rId 4p a


rId 4p (2h)


rId Ê 1 1 ˆ Á + ˜ 4p Ë a 2h ¯

233 (7.19)

The resistance of the buried electrode to remote earth is Re =

Ve Id


r Ê1 1 ˆ Á + ˜ 4p Ë a 2h ¯


(b) Cylindrical Electrode The cylindrical electrode of diameter d and length l can be buried underground at a depth h similar to spherical electrodes as shown in Fig. 7.7(b).

Fig. 7.7(b) Buried cylindrical electrode

The current density at the point Q due to the combined effect of buried electrode and its image electrode is 2Id I x – cos q = d 2 J= 2p rl p lr Id x = p l ( x2 + h2 ) rId x – V/m E= p l ( x2 + h2 )

(7.21) (7.22)

The maximum value of E occurs at x = h and its value is given as Ê rId ˆ Emax = ÁË ˜ V/m 2p lh ¯



HVDC Transmission

The ratio of

Emax of a buried electrode Emax of the surface electrode =

rId p lh

rId Ê a2 ˆ = Á ˜ 2p a 2 Ë lh 2 ¯


This method of calculation is accurate enough for electrodes of finite length much greater than the diameter and for square or rectangular cross section, as well as round. It can also be applied for star or ring layouts. But the surface gradient near the ends of a cylinder of finite length or near the ends of the arms of a star, however, are somewhat greater than the value given by the expression (7.23).

7.5.4 Resistance of Electrodes on Shore Consider an electrode situated on shore as shown in Fig. 7.9. Let the resistivity of the land mass and the earth at sea bottom have the same value r2 and that of water Fig. 7.8 Surface gradients due to a long cylinbe of much lower resistivity r1. Consider sphere of drical electrode buried in the ground radius r centered around the electrode. The water inside the sphere is a spherical wedge. The land and sea bottom constitute a hemisphere. The current flow lines are radial and no current crosses the plane boundary between any two of the three media, viz. air, water and land. The current densities in water and earth are inversely proportional to their respective resistivities. The crosssectional areas of water and earth on the spherical shell of radius r are given below.

Fig. 7.9 Electrode at shore

S1 = 2ar2 and S2 = 2pr2


Grounding and Ground Electrodes for HVDC Systems


If J1 and J2 are the current densities in water and earth and the total current passing from the electrode is Id = J1S1 + J2S2 = 2r2 (J1 a + J2 p)


If E1 and E2 are the radial electric field intensities in water and earth, applying the boundary condition that the – tangential components of E are equal at the boundary between water and land, then E1 = E2 r1J1 = r2J2 J1r1 J2 = r2

(7.27) (7.28) (7.29)

Using the expression (7.27) and eliminating J2 pr1 ˆ Ê Id = 2r 2 J1 Á a + r2 ˜¯ Ë


pr ˆ Ê J1 = I d 2 r 2 Á a + 1 ˜ r2 ¯ Ë


and J2 =

Id Ê ar ˆ 2r 2 Á p + 2 ˜ r1 ¯ Ë


The electric field intensities in water and ground are p ˆ – – Êa E1 = E2 = r1 J1 = r2 J 2 = I d 2r 2 Á + ˜ Ë r1 r2 ¯


The potential at a distance r from the electrode w.r.t remote earth is r

I d dr p ˆ Êa • 2r 2 ÁË r + r ˜¯ 1 2

= –Ú


Id p ˆ Êa 2r Á + ˜ Ë r1 r2 ¯


The potential of the electrode w.r.t remote earth is Ve =

Id p ˆ Êa 2a Á + ˜ r r Ë 1 2¯



HVDC Transmission

The resistance of the electrode to remote ground is R¢e =

Ve Id


1 p ˆ Êa 2a Á + ˜ Ë r1 r2 ¯


In comparison with the corresponding resistance in earth of uniform resistivity r2 (Eq. 7.4) is h = Efficiency of shore electrode =




1 p ˆ Êa 2a Á + ˜ Ë r1 r2 ¯

Re¢ Re

r2 2p a

p p ˆ Êa r2 Á + ˜ Ë r1 r2 ¯ 1 1 = a r2 ˆ Ê a r2 ˆ Ê ÁË p r + 1˜¯ ÁË1 + p r ˜¯ 1 1


The potential and potential gradient at any point on the land are reduced by the same ratio given by (7.37). The efficiency of the shore electrode in comparison with land electrode is given in Table 7.2, with resistivity of land (r2) = 100 ohm-m and resistivity of sea (r1) = 0.2 ohm-m.

Table 7.2

E ciency (h) of shore electrode in comparison with land electrode for di erent values of a and (r2/r1) r2/r1

Slope Angle a (rad) d Æ 0.01





























Êr ˆ The table indicates that a shore electrode situated at salt water Á 1 ˜ = 500 has a very low resistance of Ë r2 ¯ 0.3859 ¥ times that of the land electrode for a = 0.01 rad.

Grounding and Ground Electrodes for HVDC Systems


7.5.5 Resistance of Electrodes in Anisotropic Earth In certain places the earth contains numerous thin horizontal strata having different resistivities. If several kinds of such strata occur in a cyclic order, then the electrical properties of such strata in bulk can be described approximately in terms of two resistivities, i.e. longitudinal parallel to the beds (r1) and the other transverse across the beds (rt). The coefficient of anisotropy is defined as Ê rt ˆ Ka = Á ˜ Ë r1 ¯

1/ 2

(rt > r1)


According to Keller and Frischknecht, the equipotential surfaces around an electrode in anisotropic earth are ellipsoids of revaluation instead of spherical shells as in isotropic uniform earth. The vertical semi-axis of these ellipsoids is shorter than the horizontal one resulting in an increase in electric field intensity at the surface of the earth by a factor Ka than that of the value of uniform earth of resistivity r2.



The distribution of current field between electrodes depends upon the nature of the current AC or DC. The return current through ground in case of AC follows the route of the metallic conductors, whether they are overhead or underground cables. AC current takes a regular path without short circuits. It spreads out in the ground both downwards and sideways through a distance depending upon the frequencies of current, resistivity and the magnetic properties of the ground. At audio and power frequencies the current penetrates through a distance of several hundred metres depending upon the skin depth which is given by Ê r ˆ d= Á Ë p f m ˜¯ where

1/ 2



f = Frequency of current in Hz m = Permeability of the ground H/m r = Resistivity of the ground (ohm-metre)

For nonmagnetic earth it becomes = 503(r/f)1/2 metres


At power frequencies, the resistance of the ground-return path is independent of resistivity and is directly proportional to frequency, and is given by Rg = 2.96 ¥ 106 f ohm/metres


The current flow lines are parallel to one another and to the metallic conductor except at the ends of the transmission line. The end effects adds additional resistance to the electrodes. As can be seen from the expression, the current spread further below and to the sides as the frequency decreases. The end effects ranging from


HVDC Transmission

2d to 3d metres occupy a major part of the line. But for zero frequency corresponding to DC currents, only the end effects are predominating. The resistance of the ground return is merely the sum of the resistances associated with each electrode. The current flow lines confine to the path independent of the route of the metallic conductors. As the current leaves the electrode in all directions, the impedance of ground return path is negligible either for AC or DC except for the resistance of the electrodes at the ends. In DC transmission, the current consists of DC component and also harmonics, the former widely dispersed and the latter following closely the route of the transmission line. When the electrodes in DC transmission are far apart compared to their size, then the field intensity at any point between the electrodes is mostly due to the nearer electrode only.



The variation of the earth’s magnetic field causes telluric currents in the earth. It is believed that the variations in the emission of charged particles from the sun are responsible for the variation of the earth’s magnetic field. The magnetic field of the earth gets deflected eastwards or westwards depending upon the nature of charged particles, whether positive or negative. Due to these charged particles, the ring of currents around the earth is formed in elliptical orbits which vary with time and depend upon the number of charged particles intercepted by the earth. In addition to this, a magnetic field is also set up by natural currents inside the earth. One method of assessing possible adverse effects of ground-return currents from DC transmission is to compare the voltage gradients at or near the surface of the earth. Due to the transmission currents at various distances from the ground electrode, the voltage gradients caused by DC transmission must be less than the gradients caused by natural currents.



Ground return of DC line can adversely affect the neighbouring services of public utilities like gas pipes, water pipes, rail roads, AC power systems, and telephone lines. Investigations have shown that the detrimental effects of ground current can be eliminated or reduced by locating the ground electrodes at sufficient distances (8 to 50 km) from public utility services. The most serious problem posed by direct ground current is the electrolytic corrosion of buried metal objects pertaining to public utility services. Even without ground return currents, corrosion of metal objects occurs because of local ground currents due to thermo-emfs which are a result of contact of different metals. The superimposed DC current sometimes may aggravate corrosion depending upon the direction of current. A typical reaction between an iron anode and the soil is Fe++ + 2OH– Æ Fe(OH)2


These metal ions move in the direction of current in the electrolyte. The formation of doubly ionized ions releases two electrons which may traverse along the pipe and combine with positive ions at the point where the current enters, which results in the release of hydrogen given by the reaction 2e– + 2H+ Æ H2


Grounding and Ground Electrodes for HVDC Systems


This reaction coats the pipe with a layer of hydrogen that protects it from oxidation and other corrosion. In the electrolyte, the current leaves the metallic anode and enters at the cathode. The metallic anodes are corroded and most cathodes are protected from corrosion. However, corrosion does not take place between two metallic contacts due to conduction by electrons. AC currents of commercial power frequency cause only about 1% corrosion of that of DC current of equal rms value.



Electrodes are classified depending upon their location as land and shore electrodes. But there are some common requirements for both types of electrodes, as listed below. 1. 2. 3. 4. 5. 6.

Low resistance Sufficient current carrying capacity Low maintenance Easy accessibility Minimum damage to other services Safety for persons, livestock and fish

7.9.1 Low Resistance Low resistance of the electrodes reduces power loss and can be obtained by using large surface area of electrodes while locating them in soil or water of low resistivity. The resistance must remain low during the entire life of the electrode.

7.9.2 Sufficient Current Carrying Capacity The current carrying capacity of the electrode can be increased by using large surface area at low current density to avoid overheating and drying of adjacent soil or boiling of adjacent water during the operation.

7.9.3 Low Maintenance Cost It is stated above that usually anodes get corroded in the ground electrodes of HVDC transmission. Replacement of anodes due to corrosion is necessary. The cost of replacement must be low. Anodes are preferably made of cheap nonmetallic materials like coke in schemes in which the current is never reversed as in a monopolar link. A cheaper material can be used for cathodes as they do not pose corrosion problems. But in bipolar links, sometimes current can be reversed, and in such cases both electrodes must be designed as anodes.

7.9.4 Accessibility of Electrodes Electrodes must be located in such a way that they are easily accessible for maintenance. Electrodes are made of several parts and each part can be replaced independently whenever necessary. Shore electrodes sometimes have their elements suspended in tubular wells to facilitate easy inspection by pulling them out.


HVDC Transmission

7.9.5 Location of Electrodes Electrodes are generally located 8 to 50 km far away from the terminal DC substation to avoid electrolytic corrosion on buried metal structures. It also reduces the saturation in transformers. Electrodes are connected to converters through lightly insulated electrode lines. The electrode lines can be run on the same towers carrying pole-conductors, which may also serve as shield wires. The tower footings can be insulated from the ground to avoid corrosion or wooden poles can also be used.

7.9.6 Safety The maximum potential difference between two feet, separated by 1 m, of a person walking on the ground is known as step voltage and this should not exceed 6.5 V/m. The maximum surface gradient near a land electrode should be limited to about 5 V/m in order to avoid annoying electric shocks to a person walking on the ground nearby an electrode. Attention should also be paid to the touch voltage which is defined as the potential difference between a point where the person is standing while his hands are in contact with a grounded structure and the ground. The maximum touch voltage within grounded grid is known as mesh voltage. Fences can be located to follow equipotential lines approximately and they can be sectionalised by insulators. In the vicinity of sea or shore electrodes, areas of high voltage gradient must be screened to avoid fish and unauthorised persons experiencing shocks. It is easy to limit the voltage gradients near electrodes with DC currents, since the short circuit current at the most is twice the full-load value in the DC system. DC ground electrodes can be designed in three ways, viz. for continuous rating, intermittent duty and without any load current. The design requirements are different in each case.

7.10 BASIC PARAMETERS OF DESIGN OF GROUND ELECTRODES The important parameters to be considered in the design of ground electrodes while determining the size are listed below. (a) (b) (c) (d) (e) (f) (g)

Choice of site Electrode material Layout of the electrode (electrode shape) and electrode resistance Current carrying capacity Voltage rise of the electrode Surface potential gradient near the electrode Time constant

7.10.1 Choice of Site The location of electrode should be selected where there is sufficient area of land/space of low resisitivity and sufficient distance (8 to 50 km) from converter station and other substations and should also be away from densely populated areas, buried pipe lines and rail tracks.

Grounding and Ground Electrodes for HVDC Systems


7.10.2 Anode Material The material used for anode must be cheap and should not suffer from excessive corrosion loss. Even though iron is cheap, the loss of material/annum carrying 1000 A may range from 1800 to 12,500 kg. But on the other hand if iron is immersed in coke as shown in Fig. 7.10, the loss may be reduced to 140 kg at 1000 A. The reduction in loss is due to conduction of current by electrons instead of ions. However, if the moisture reaches the iron part, a small part of conduction may be ionic. The corrosion loss was found to be lowest when the ground was frozen and highest when the soil was wettest. It has been observed from experiments that safe current density at the surface of iron for minimum loss of iron material ranges from 15 to 25 A/m2.

Fig. 7.10 Cross section of land electrode with backfill of granulated coke in the bottom of trench

The coke used must be free from sulphur content. In the arrangement shown in Fig. 7.10, coke becomes the true electrode and the role of iron is to distribute the current to the coke. Use of carbon or graphite rods as anodes will almost eliminate the anode loss by electrolysis. In the method of construction of an electrode, a trench is dug as shown in Fig. 7.10 to fill with coke to half the final depth. On this layer of coke, the distributing conductors are placed and the remaining half of the trench is filled with coke. At each stage, the coke or back fill should be compacted by tamping.

7.10.3 Electrode Shape and Resistance Various types of electrodes in plan view are illustrated in Fig. 7.11. The ring form gives the most uniform current into the ground/unit length of the trench, if located in uniform soil and thus uses the materials to best advantage. However, it requires a large area of land with uniform soil. Linear electrodes and star electrodes have current densities from coke to the soil at higher values at the ends of the arms. The length and the shape of the arms can be varied depending upon the local conditions. In star shaped electrodes, the electrode-to-ground conductance decreases with increase of number of arms. A branched star appears to use the area of site efficiently.


HVDC Transmission

Fig. 7.11 Plan views of several forms of land electrode: (a) Straight, (b) Ring, (c) Six-pointed star and (d) Branched star

The resistance of the electrodes w.r.t remote earth which are buried at uniform depth in a soil of uniform resistivity is given for different configurations, where Re = Electrode-resistance w.r.t remote earth (W) r = Ground resistivity (W-m) l = Length of the electrode in (m) D = Diameter of the ring (m) d = Diameter of the conductor (m) h = Depth of burial of the centre conductor (m) b=


(a) For straight cylindrical rod (linear electrode) (horizontally buried) Re =

r Ê 2l ˆ ÁË ln – 1˜¯ b pl

when h r1). Assume that the upper layer of lower resistivity extends to a radius b. Take the radius of the hemisphere to be a and at a depth = d.

Grounding and Ground Electrodes for HVDC Systems


3. Obtain an expression for the efficiency of a shore electrode. State the assumptions made. Also obtain an expression for potential of the shore electrode w.r.t. remote earth. 4. Bring out the differences in the distribution of current field between buried electrodes when AC and DC currents are used. 5. What are the effects of ground return currents on the buried objects? Suggest remedies to minimise them. 6. Mention the essential requirements of ground electrodes in HVDC systems and explain the necessity of each item briefly. 7. State the basic parameters to be considered in the design of ground electrodes. Give a neat sketch of an electrode trench for land electrode and explain how it is executed. 8. Give the various shapes of ground electrodes and mention the advantages of each. 9. Derive an expression for the voltage rise of a land electrode. Explain how a land electrode is designed for large currents of the order of 1000 A. 10. Explain the importance of surface potential gradients near a HVDC station. What is step potential and its importance? Suggest the methods to minimise the step potential. 11. Define thermal time constant of an electrode in HVDC systems and obtain an expression for the same. 12. Explain how a pole of the converter is connected to the ground or earth electrode. What are the precautions to be taken while running ground electrodes?

PROBLEMS 1. Determine the resistance of hemispherical electrode situated in a non-uniform field each of resistivities r1 = 10 W-m and r2 = 10r1. With Id = 10 A. Also estimate the potential of the earth electrode w.r.t remote earth. Assume upper layer of lower resisitivity is up to radius 10 m. Ans: 3.024 W, 30.24 V 2. What is the potential rise of a land electrode with r of soil 100 W-m, thermal conductivity of soil 3 watt/m-°C and allowable temperature rise 60°C. Ans: 189.7 V 3. Compare the efficiency of a bipolar line with resistance 18 W per conductor and current 1.8 kA per conductor with a monopolar line with ground return. Take resistance of ground electrode 0.05 W. Assume voltage to ground of DC line as 400 kV at sending end. Ans: 91.9% and 91.8%

MULTIPLE CHOICE QUESTIONS 1. Advantage of ground return in HV-bipolar DC system is (a) less power loss (b) can be built in stages (c) in the event of fault, 50% power is available (d) all of the above (e) none of the above


HVDC Transmission

2. The ground currents in HVDC system flow through (a) small area (b) small area along the line (c) very large area and does not confine to route of the line (d) very large area along the route of the line 3. The order of ground currents and polarity in bipolar system is (a) 1 to 3% either polarity (b) 1 to 3% negative polarity (c) 1 to 3% positive polarity (d) 5 to 10% either polarity 4. The resistivity of average land surface is of the order (W-m) (a) 1 to 1000 (b) 50 to 200 (c) 1000 (d) 1000–10,000 5. Electrical field intensity of a hemispherical electrode at its surface (radius = r) is proportional to 1 1 1 (a) (b) 2 (c) 3 (d) r r r r 6. Resistance of hemispherical electrode of r = 1 m in a soil of r = 100 W-m is in ohms 50 5 100 10 (a) (b) (c) (d) p p p p 7. If the electrodes are immersed in a trench filled with coke or betonite, the electrode resistance (a) does not change (b) increases (c) reduces (d) becomes zero 8. If a spherical electrode of r = 1 m is buried at a depth of 2 m, the electric field due to current is maximum at a distance along the surface from the electrode 1 1 1 m (a) m (b) 2 m (c) 2 m (d) 2 2 2 9. The efficiency of shore electrode in comparison with land electrode, with soil r = 1000 W-m and sea water r = 0.2 W-m with sector a = 0.1 radians. (a) 1.0 (b) 0.5 (c) 0.76 (d) 0.95 10. The depth of penetration of AC currents of frequency f through nonmagnetic soil of resistivity r is 1/ 2

11. 12.

13. 14. 15. 16.

1/ 2

1/ 2 1/ 2 Èr˘ Èr˘ r r (b) 500 Í ˙ (c) 1000 ÈÍ ˘˙ (d) 50 Í ˙ (a) 100 ÈÍ ˘˙ Îf˚ Îf˚ Îf˚ Îf˚ The resistance of good ground return excluding electrodes is taken as (a) negligible (b) 1 W (c) 10 W (d) 100 W Corrosion of buried metal objects occur due to ground return of a DC line only when the object acts as (a) cathode (b) cathode under moist condition (c) when not painted (d) anode Value of step potential should be limited (for 1 m step) (a) 10 V (b) 6.5 V (c) 5 V (d) 3 V Corrosion due to AC 50/60 Hz frequency currents compared to DC currents of equal magnitude is (a) 1% (b) 5% (c) 10% (d) 25% Annoying body currents due to grounding of DC lines is about (a) 15 mA (b) 1 mA (c) 5 mA (d) 0.5 mA The voltage rise of the earth electrode w.r.t remote earth depends on (a) resistivity of the soil (b) heat conductivity of the soil (c) temperature rise of the soil (d) all three (a), (b) and (c)

Grounding and Ground Electrodes for HVDC Systems


17. The earth electrode in the ground return DC line is located from the converter station at a distance of (a) 1 km (b) 3 to 5 km (c) 10 km (d) 8 to 20 km 18. The design of land electrode connected to the earth electrode depends on (a) current and operating time (b) heat dissipation and safety (c) current, operating time, life time, polarity, and safety (d) soil resistivity, thermal conductivity, safety, reliability, and electrode current 19. Which of the following soils have low resistivity? (a) rock (b) sandy soil with loam (c) soil with granite layer (d) none of the above 20. As per IEEE standards, human body resistance is taken as (a) 500 to 5000 W (b) 5000 to 10,000 W (c) less than 500 W (d) 10 kW to 50 kW

ANSWERS 1. (d) 9. (c) 17. (d)

2. (c) 10. (b) 18. (c)

3. (a) 11. (a) 19. (b)

4. (b) 12. (d) 20. (a)

5. (b) 13. (b)

6. (a) 14. (a)

7. (c) 15. (c)

8. (d) 16. (d)

Faults and Protection Schemes in HVDC Systems 8.1


Any power system, however best it is designed, is subjected to disturbances and short circuits. In case of HVDC systems, faults or short circuits can occur either on the AC side or on the DC side. Further, faults can be caused by failure of insulation due to overvoltages such as lightning, switching, etc. The malfunctioning of control mechanisms, failure of commutation in valves, overloading, etc., will also lead to faults or short circuits. In case of AC systems, short circuits and abnormal currents are detected by relays, etc., and the protective devices such as circuit breakers open and remove the fault. With DC normally there will be no circuit breakers and faults or short circuits are cleared through valve blocking only. An analysis and previous experience with DC systems indicate some typical faults and their occurrence, as given in Table 8.1. Table 8.1

Types of faults and their occurrence Type of Fault


Converter and Internal Faults Rare DC Line Faults


Commutation Failure

Very frequent


Fault Current


10 p.u. Valves are rated for small duration of fault occurrence 2 to 3 p.u. Forced retardation of firing/dynamic VOCL. AC breaker tripped after a delay 1.5 to 2.5 p.u. Single-self clearing, multiple-b angle advance, static VOCL


Most of the short circuit type faults that occur in HVDC systems are from AC source through DC link to the other AC system and may be summarised as (i) AC network faults like line-to-ground or line-to-line short circuits. Converter transformer or AC bus faults or short circuits in filter and other equipment. These may be temporary and if so, they are cleared by tripping the AC side breakers. The system suffers power loss till the faults are cleared and supply is restored.

Faults and Protection Schemes in HVDC Systems


(ii) AC line faults on the inverter side. For this type of faults, commutation failure occurs in general but power is restored in a very short time clearing the faults. (iii) DC line or cable faults. The pole-to-ground or line-to-ground fault is the usual fault, but rarely poleto-pole short circuit can also occur. The fault is cleared by turning the rectifier into an inverter, so that fault energy is dissipated in a short time of 80 to 100 ms. Sometimes faults due to a lightning stroke can cause a temporary short circuit. Such faults are cleared in about 200 ms and the system is restored. (iv) DC cable damages and short circuits are rare. They occur where an underground cable link is used between the sending end and receiving end. In such cases the rectifier is blocked, the stored energy is pumped back to the AC system and power is disconnected till the fault is isolated and cleared. (v) DC converter station faults. These are totally different from 3-phase AC system faults. They are only of one type, i.e. line-to-ground fault. Normally there are no CBs in DC systems and the protection system takes care of fault clearing by blocking the rectifier and dissipating the stored energy. DC fault clearing is very fast and is done in about 100 ms restoring the supply in about 200 ms for temporary faults. Other faults that usually occur are (a) valve misfire, (b) commutation failure, and (c) maloperation of control and protection circuits, etc.



The usual faults on an AC side of the converter stations are the symmetrical three-phase faults or asymmetrical line-to-ground or line-to-line and double line-to-ground faults. Following a fault, the voltage at the converter terminal is reduced very much, so that the DC link power is reduced or completely becomes zero. DC current and power cannot be brought back to the original value because of large time constants involved in DC control units. Further, the fault alters the reactive power requirements of the converter and hence its voltage.

8.3.1 3-phase Symmetrical Faults A 3-phase symmetrical fault or short circuit is not that severe when compared with an all AC system, as the DC link does not feed any additional current into the fault. If the fault is on the rectifier’s side, the protective relays sense it and the AC breaker isolates it. After the fault is cleared, the system is restored. However, a short circuit on the inverter’s side close to it causes commutation failures and gives rises to large DC current peaks. These are controlled by quickly reducing the firing angles of the valves. Usually the fault is cleared in about 100 ms (5 cycles time). Typical simulated current waveforms at the rectifier and inverter end are shown in Fig. 8.1 along with the AC voltage waveform at the rectifier end (Fig. 8.2). The peak fault current can reach 2.5 p.u. The fault is simulated at 0.5 s, cleared at 0.62 s and the normalcy is restored at 0.75 s.

8.3.2 3-phase Asymmetrical Faults In case of symmetrical faults like L-G or L-L fault, usually sufficient commuting voltage will be available and the DC link may be operated with a very reduced power level. But the valve firing circuitry which takes signal from the valve windings of the transformer, suffer from improper gate signals and hence, the system is usually cut from operation. The fault clearing and re-establishment of link is done in the same manner as that of 3-phase symmetrical faults. The voltage and current waveforms for an L-G fault at the inverter end along with variation of a and g to clear the fault are shown in Figs. 8.3 and 8.4. Voltage and current waveforms


HVDC Transmission

Fig. 8.1 3-phase fault at the inverter end (the DC side current)

Fig. 8.2 3-phase fault at the inverter end (rectifier AC voltage)

on the AC side of the inverter end are shown in Fig. 8.5. The fault occurs at time t = 0.7 s and cleared at 0.82 s. A similar L-G fault at the inverter end of MTDC systems (Chapter 10) is shown in Fig. 8.6 for 2-Rectifier 2-Inverter Scheme.

8.3.3 Other Disturbances on AC Side and Fault Sensing The initiation and clearing of faults, which are switching actions cause switching surges up to 1.6 p.u. The energisation of converter transformer also causes overvoltages because of heavy magnetisation currents. The voltage and current get distorted causing even harmonic voltage and currents. Other phenomena leading to overvoltages are discussed in the next chapter. The fault sensing is done through either overcurrent relays or through differential relays. The factors that are to be taken into account are (i) selectivity, (ii) sensitivity and (iii) backup. The converter station and valve house are disconnected within 5 cycles time for AC faults.

Faults and Protection Schemes in HVDC Systems


Fig. 8.3 Voltages and currents of inverter for an AC line fault on the inverter side (L-G fault)



Internal faults usually referred to as converter faults are a common feature but are quickly rectified or quenched and generally do not cause interruptions of power flow. Based on the nature of the disturbance, the converter malfunction is classified as (i) Malfunction of valves and valve controls resulting in (a) arc through or fire through, (b) arc back, (c) misfire, and (d) current extinction. (ii) Commutation failure — most common with inverter operation (iii) Short circuits inside the converter units


HVDC Transmission

Fig. 8.4 AC line-to-ground fault at inverter side (L-G fault)

8.4.1 Misfire and Arc Through Misfire is failure of the valve during conduction period, i.e. it does not conduct when firing pulse are given and arc through or fix through is failure of the valve to block the conduction. These are mainly caused by an improper or malfunction of control circuits and firing circuits. These are serious at the inverter end. On rectifier side, the voltage and current oscillation over the DC output will usually result in malfunction in gate pulse circuit or a spurious pulse introduced into the gating circuit will make the inverter conduct. Most of the time the inverter will have valve voltage positive and the unwanted pulse results in through conduction. Typical fire through in valve V1 at instant B is shown in Fig. 8.7. The valve can fire through at any time after instant A although it is scheduled to firing at F. The waveforms shown are ideal, but in actual case both voltage and current waveforms will be highly iratic. Usually single arc through is self-clearing. But arc through may recur and protection against this taken care by converter differential protection schemes. Misfire results in spurious pulse entering in gating circuits and fire the valve at an undesired instant and the next valve does not fire properly. This is very rare. Misfire can be either at the rectifier or inverter end. At inverter point, misfire will result in the bridge average voltage becoming small or even going to zero. This will result in large voltage and current oscillations as AC

Faults and Protection Schemes in HVDC Systems


Fig. 8.5 Variation of voltage and current on AC side at the inverter end for an L-G fault (Note that one-phase voltage is absent in voltage waveform)

voltage is injected into the DC side. The DC current may extinguish and a large overvoltage may develop. Typical voltage and current waveforms due to misfire are shown in Fig. 8.8.

8.4.2 Commutation Failure Normally, the incoming valve has to take over the conduction current before the commutating voltage reverses. The failure of such event results in the fault or commutation failure. Strictly commutation failure is due to varying conditions of the inverter extinction angle due to either variations in DC or AC circuit conditions. A low AC voltage or a high DC current can cause incomplete commutation process in time for safe commutation. The DC current is shifted back to the previously conducting valve. Usually this often occurs at the inverter’s end. Since, g = (p a m) and m is a function of commutating voltage and direct current, either reduction of AC voltage or increase in current will cause m to increase and g < g min. Hence, commutation


HVDC Transmission

Fig. 8.6 Voltages and currents in the MTDC system for SLG fault at inverter-2

failure occurs. Typical commutation failure from valve V1 to valve V3 of a six-pulse converter is shown in Fig. 8.9(b). Commutation failure occurs at point t2, i.e. the point of voltage crossing. Commutation reverses and valve V1 of V2 will continue to carry current. Consequently the voltage continues to fall as Vca of point t3,V4 turns on to take over from V2 at which time Vca is shorted and DC voltage falls to zero. Assuming that commutation from valve V2 to Va is successful, the direct current effectively passes through the leg of 1 and 4, and valve 5 does not have chance to take over because its voltage is reverse biased. The DC short ends at t4 when valve 6 takes over from valve 4. DC voltage slightly goes negative and converter continues to conduct and comes back to normal. This type of fault is a single failure. But sometimes multiple failures can also occur. These type of faults are normally corrected after one complete cycle of operation by the control circuits.

8.4.3 Internal Short Circuits These are very rare faults. Internal short circuits can occur at (i) ground fault at the coverter terminals, (ii) valve terminals, (iii) DC bus, (iv) junction point of two valves, and (v) short circuit across a nonconducting valve, etc. These are mainly due to a flashover on the bushing or insulator supports. Most of these at the rectifier side of the converter will reflect as a 3-phase fault while shorting or flashover across a nonconducting valve is phase-to-phase short circuit. The worst case is when a is zero or near to zero. The peak short circuit current is equal to 12 {I do + 3I s }, where I s = 2VLL 2 xc; VLL is the true voltage on the AC side and xc is equivalent transformer impedance and ido the DC current at the instant of firing of the valve. The peak fault currents

Faults and Protection Schemes in HVDC Systems


Fig. 8.7 Single firethrough of valve V1 in typical inverter

can be as high as 10 times the rated current and the valves (thyristors) must have such instantaneous short circuit capability. This fault is usually cleared by blocking of the valves. If the valve blocking is not done, the


HVDC Transmission

Fig. 8.8 DC voltage and current for persistent misfire

backup is given by tripping the circuit breakers on the AC side. The short circuit current is only limited by transformer short circuit impedance and the source impedance.

Faults and Protection Schemes in HVDC Systems

Fig. 8.9(a) Single commutation failure from valve V1 to valve V3



HVDC Transmission

Fig. 8.9(b) Commutation failure in a thyristor-based line-commutated converter: (a) 6-pulse thyristor converter (b) Inverter voltage during a single commutation failure (c) Inverter voltage during double commutation failure

Faults and Protection Schemes in HVDC Systems


8.4.4 Bridge Bypass and Fault Clearing Action Many temporary faults that occur in valve bridges are stated in Sections 8.4.1 to 8.4.4 can be cleared in about one cycle time by valve bypass action. In older mercury arc rectifier schemes, a bypass valve was used to divert the short circuit current. This bypass valve was across the main converter bridge and kept blocked in normal operation. To make the main bridge unit nonconducting and divert current, the bypass valve was fired and other valves were blocked. The bypass valve can be blocked after first interrupting its current, so that the grid gains its control. When the normal bridge valves are restarted after fault clearing, the bypass valve cathode becomes positive with respect to anode and hence is automatically blocked. In case of thyristor bridges, no separate bypass valve is needed and a normal or healthy pair of valves in series of one leg of 6-pulse bridge can be used for this purpose (as shown in Fig. 8.10). Blocking the converter using one leg is same as described earlier. The selection of blocking sequence to the bypass pair of valves is important to give the faulty valve the best possible time and chance to recover. The selection of the most suitable bypass pair for blocking depends on cause and type of fault. Fault detectors should be provided with good and sufficient discrimination. Restoration of normal operation requires the restoration of firing pulses and suppression of blocking pulses. Inverter deblocking by these means is also much simpler.

Fig. 8.10 Bypass pair (1, 4) two series switches and a bypass switch for bypass action



Usual faults that occur on the DC side of the system are (i) pole-to-ground fault, (ii) pole-to-pole short circuit, or (iii) a ground fault at the DC bus, smoothing reactor or failure of insulation resulting in a ground fault. There may be a temporary short circuit due to a lightning stroke on one of the DC overlines which is usually self-clearing after a few milliseconds. The fault current cannot be extinguished by itself until the current is brought down to zero and the arc is deionised. As soon as the fault occurs, DC voltage reduces and becomes zero; the rectifier current tends to rise and the inverter current tends to fall to zero. As such the rectifier is blocked and the inverter phase is advanced beyond 90° to rectifier action to maintain sufficient voltage. Normal converter controls will not be adequate to reduce the fault current to zero and special control is employed to drive both converters into the inverter mode. Thus, the energy stored in inductor and capacitors is cleared quickly. This is done speedily by sensing the fault and making the rectifier go into the inverter mode. After fault clearing, both converters are brought to the normal mode.


HVDC Transmission

Typical simulated voltage and current waveforms for a DC line-to-ground fault at the rectifier side are shown in Fig. 8.11(a) and (b). The fault was initiated at time t = 0.7 s and valve blocking started at 0.72 s. Normalcy was restored by 1.1 s, i.e. total time taken was about 0.4 second. The fault current was 2.2 p.u. The minimum reference current is shown in Fig. 8.11(b) and the control of firing angle a to clear the fault and restore the normalcy is indicated in Fig. 8.11(c). Current and commutation voltage across valve 1 is shown in Fig. 8.11(b), (c) and (d) respectively at the inverter end, along with the variation of g for fault initiation at 0.669 sec.

Fig. 8.11

DC Line fault on the Rectifier Side: Rectifier voltage and current waveforms

Faults and Protection Schemes in HVDC Systems

Fig. 8.11(Contd)


Current and commutation voltage of valve 1 for DC line fault

8.5.1 Fault Sensing Most of the fault sensing is by overcurrent detection and under or overvoltage sensing. In overhead lines or cables, the voltage and current changes (i.e.) dv/dt and di/dt set up travelling waves and provide basis for detection as well as discrimination. The polarity of the travelling wave with respect to line voltage will give necessary information to identify the fault in both bipolar and monopolar systems. In case of line fault, the rate at which the voltage falls ( dv/dt) at the rectifier end or terminal is higher than that at the inverter terminal; and the voltage magnitude and other characteristics decide the fault sensing and location. For DC line fault discrimination, the weighted sum of Vd and Id, i.e. S = k1Vd + k2Id, which is directly related to the travelling wave initiated by the fault gives complete information regarding the type of fault and its location. The sensitivity of detection depends on length and actual line parameters.

8.5.2 Fault Clearing Usually after a fault is detected, the rectifier firing angle is delayed into inverter operation region, i.e. a is delayed to about 120° or more, so that the rectifier current is reduced or collapsed. It is kept in that condition till all the energy stored in the inductances is exhausted and the deionisation and arc extinction takes place. Similarly, to ensure that line voltage is maintained, inverter end firing angle b is also advanced to less than 80°. But with long cable transmission systems and large smoothing reactors in the lines large voltage oscillations and polarity swings can occur in the DC lines. After complete deionisation, the restart procedure is done to restore normal voltage and pre-fault power conditions. Normal current controls are modified by the emergency control unit during fault clearing procedure.


HVDC Transmission

8.5.3 Direct Current Circuit Breakers and Their Application Normally in DC back-to-back schemes or in point-to-point DC links, no circuit breaker is needed or used. However, in multiterminal schemes (MTDC—see Chapter 10) and some large schemes direct current circuit breakers are being used. The main problem with DC arcs compared to AC arcs is that there is no instant at which the current passes through a zero magnitude. Hence, lack of current zero in DC poses a difficulty in arc extinction and opening of DC circuits. One method that is envisaged is to bring the fault current to a reasonably low value so that CB requirement is not very severe. But the system suffers with low voltage condition during that period. The modern approach suggested and adopted is to superimpose an alternating or oscillating (AC) current on the DC arc and forcing the current to zero at which time the arc is extinguished. Typical circuit breaker arrangement using the former principle is shown in Fig. 8.12. The DC breaker arrangement consists of CS, the commuting switch, an isolating switch IS and a commutation circuit. The commutation circuit consists of a capacitor C in parallel with discharge resistor Rc, a spark gap Gc and a surge diverter A. When the commutation switch CS opens, an arc with high arc voltage is formed. The arc voltage causes the spark gap Gc to spark over, charging the capacitor C because of spark gap current. The rate at which voltage rises is limited by the arrester A which takes over the large current of the DC arc in the CS. The surge diverter dissipates the energy and the voltage across the unit starts reducing as the current starts reducing to zero. At this stage the isolator switch IS is opened so that the current becomes zero and the entire circuit is opened.

Fig. 8.12

DC Breakers

The second type or superimposed AC current oscillation on DC arc breakers have been introduced recently and the schematic arrangement is shown in Fig. 8.13. In this arrangement, a resonant circuit consisting of capacitor C1 and inductor L is connected in parallel with the CB, S1 along with the previous arrangement of R-C2 circuit and the surge arrester A. No other isolator switch is used. The capacitor C1 is pre-charged from a DC source. The CB S1 is usually a vacuum or SF6 CB as it interrupts high frequency currents and recovers the dielectric strength quickly.

Faults and Protection Schemes in HVDC Systems

Fig. 8.13

Fig. 8.13(a)


DC Breaker with L-C oscillation circuit for forced current zero

Oscillogram of current interruption and recovery voltage on a 70 kV CB

When the CB, S1 contacts start separating, the arc is low, and as the contacts separate, the switch S2 is closed. C1 produces an oscillating current through L of frequency 250 to 500 Hz of sufficient magnitude which forces a current zero and thus S1 quenches the arc formed. After that the surge diverter takes over the current oscillation and absorbs the energy of the L-C circuit. Typical current interruption and the recovery voltage oscillogram during a test are shown in Fig. 8.13(a).


HVDC Transmission

8.5.4 Metallic Return Transfer Breaker (MRTB) In some schemes in which DC system is operated temporarily with ground return as monopolar mode, an MRTB is required to eliminate corrosion in metallic elements close to the DC line. This is schematically shown in Fig. 8.14 and connects or isolates the far-off grounding point.

Fig. 8.14 Configuration using an MRTB circuit breaker

The duty of the circuit breaker is heavy as it has to handle the energy stored in the ground loop. The CB is closed only when earth return is used, otherwise it is opened. The energy capabilities are as high as 10 MJ or more. Requirements for Switchgear Normally, even though circuit breakers may not be needed, isolator switches are required to open or close the DC lines and other equipment. As such, various switches or breakers have to be installed in converter stations on the DC side. During normal operation, the current in the lines and parallel groups can be controlled to a value before the switch or CB is operated. However, in case of parallel lines or multiterminal schemes, this is not true and requirements are quite heavy. Usually most of the faults on the converters are temporary and are cleared by converter controls. Only pole or line-to-ground faults and line-to-line faults are the worst situations of the station. If line breaker opens immediately, say in 2 to 3 ms after the fault detection, the breaking voltage across the arc or breaker is sufficient in excess of internal feed voltage and will be effective in breaking or quenching the current in the CB. But such a breaker action produces very high transients and overvoltages in the system. Further, in DC links, the energy to be dissipated is less whereas in MTDC systems or ring systems much larger energy is to be dissipated or handled. Since energy to be dissipated is proportional to I 2, it is important to establish full breaking voltage in the shortest possible time as this limits the current through fault. Using proper current limiters, it is better that operating times are put around 20 to 40 ms. The main advantages with breaker operating after a current limiting action is that there is no risk of overloading at the inverter end and the current order controls can be changed through the communication networks. This will result in larger interruption time and disrupt the power transmission.

Faults and Protection Schemes in HVDC Systems


Hence, the requirements can be summed up as follows: Limit: (i) The overvoltages produced and their duration by proper operating time selected, (ii) Maximum energy dissipating capacity and magnitude of breaking voltage and (iii) Time for tripping order to full breaking voltage and time to current extinction to full withstand capacity

8.5.5 Simulation Studies on Faults and Other Disturbances Nowadays, exhaustive studies on HVDC systems are being done by simulating the system on computers, so that normal operations as well as abnormal conditions like faults and system disturbances can be studied, and clearing times and restoration can be precisely obtained. Simulation studies can be on (i) DC physical model simulators on a DC network analyser or on digital computer using software developed for this purpose such as MATLAB-simulink packages, etc. For computer studies, the computer requirements, calculating time, etc., were some constraints faced earlier. However today, with high speed computers with large memory, there is no restriction and any type of complex study can be done on an HVDC simulator. The important factor in these studies is the correct representation of HVDC system components and the dynamic behaviour of the AC system connected. All faults and disturbances mentioned in the earlier sections are simulated and system studies are now done on the simulators using physical or mathematical models.



Protection schemes used in DC systems are similar to that of AC schemes, but are usually faster. The important factors to be considered are (i) sensitivity, (ii) selectivity, (iii) backup, and (iv) reliability of the schemes. Some faults can give rise to fault currents of the order of 10 p.u. which drastically effect the converter transformers and hence tripping of AC side breakers is contemplated. Usually the overcurrent protection setting is decided with reference to short time overload capacity of thyristor valves and their heat dissipation capabilities. The converter faults are provided with valve group protection so that particular valve or bridge can be isolated. The protection scheme is usually differential protection, in which the valve current is compared with transformer current and fault detection is made.

8.6.1 DC Line Overcurrent Protection Most common faults are DC line-to-ground and pole-to-pole short circuits and one of their causes is either lightning or insulator failure. Usually the smoothing reactor limits the current to less than 3 p.u. The detection dv dI of fault is done by comparing after some time lag of 2 to 3 ms. Sometimes rate of change of current dt dt dv dv is also taken. This is set to exclude lightning voltage strikes which have very high and are not cloud dt dt to line-to-ground strokes. This sensing is sufficiently sensitive and fast, and signal is sent to block the rectifier and also trip the CB if included. As a backup, an under-voltage unit is used to detect high resistance faults in dv which may be too slow or less. Current control limits the current to a small value. The current is forced dt to zero by delaying the firing angle, forcing it to the inverter mode.


HVDC Transmission

8.6.2 Valve and Bridge Group Protection Internal faults in valves, valve groups or in the bridge circuit as a whole are almost dead short circuits, as not much resistance is involved in the fault. The peak fault currents can be 10 p.u. Usually if the valve blocking is not or cannot be done faster, AC side CBs are tripped. Here valve group differential protection is employed and rectified as current of the secondary of the transformer is compared with DC current for unit protection. If the indication shows DC current is greater, it may be a commutation failure which is corrected. On the other hand if AC current is greater, the fault may be a backfire or a short circuit in the valve group. The backup protection is done using a non-overcurrent protection scheme with higher or delayed tripping. Ground faults are detected and protected using differential protection which has higher selectivity. The protection scheme is to (i) first block the valves, (ii) de-energise the line or pole or valve group, and (iii) if necessary trip the AC side breaker and isolate the valve group or bridge.



Harmonic filter units are provided both on AC and DC side. The filter banks are subjected to (i) overvoltages, and (ii) internal faults or short circuits. Usually capacitor banks are made up of series connected capacitor racks, a few of them connected in parallel to make up for required KVAR. Each rack is protected by an HRC fuse unit. Further, the filter arms are equipped with overcurrent relays which respond to both power frequency and also the harmonic voltage. The entire unit is connected through suitable CBS. The capacitors as well as inductors are provided with their own surge arresters which protect them against overvoltages when a fault occurs or is cleared, as well as against lightning and switching impulses. Usually if a persistent short circuit or overcurrent occurs, the banks are switched off and put into service manually after fault clearing.

REFERENCES 1. Arillaga J., High Voltage Direct Current Transmission, IEE Power Engg. Series, 2nd Edition, 1998. 2. Padiyar K.R., HVDC Transmission Systems, Wiley Eastern Ltd. (New Delhi), 1992. 3. Hingorani N. G. and Gyugyi Laszlo, Understanding FACTS, (New Delhi) IEEE Press, Standard Publishing Distributor, Indian Edition 2001. 4. Khatir M. et al., Analysis of the recovery from commutation failure in HVDC inverter, Acta Electrotechnician, Vol. 8, No. l, 2008. 5. Khatir M. et al., Effect of DC control on recovery from commutation failures in HVDC inverters, Turk Journal of Electrical Engineering, Vol. 58, No. 4, 2007. 6. Faried S.O., Upadhay S., Serafi AM El., Impact of HVDC commutation failure on turbine-generator shaft torsional torques, Web source - http://www.itee.uq.edu.au/ 7. Kauferle J. and Pohvd, Concepts of over-voltage and overcurrent protection of HVDC converters, Cigre, Paper 14–08, Paris, 1978. 8. Baoiang Sheng, Synthetic test circuit for current switching tests of HVDC circuit breakers, ABB, AB HVDC, Ludivika (Sweden), IEEE, 2008.

Faults and Protection Schemes in HVDC Systems


9. Manohar Premila and Chandrasekhariah H. S., Application of ZnO varistors protection to artificially commuted inverter MTDC systems, IEEE PAS, Vol. 6, No. l, 1991. 10. Mohammad Khatir et al., Comparison of HVDC line models in PSB/Simulink based study state and transient considerations, Acta Electro-technician Information, Vol. 8, No. 2, 2008. 11. Zangeneth B. Zohouri and Shoulaic A. A., New simulator for HVDC/HV-AC systems, Part I and Part II, Turk Journal of Electrical Engg., Vol. 2, No. 3, 2003.

QUESTIONS 1. What are the different types of faults that can occur is HVDC systems? Discuss their nature and occurrence. 2. Explain briefly the faults on the AC side of HVDC systems. Discuss their impact on the inverter giving suitable examples with waveforms. 3. What are the main types of faults in converters and converter stations? 4. Explain the occurrence of commutation failure in inverters. Discuss its effects giving the voltage and current waveforms. 5. What is the importance of bridge bypass action and how does it help in clearing converter faults? 6. Discuss the nature and type of faults on the DC side of converter stations. How are the faults sensed and cleared? 7. Give the principle of different types of DC circuit breaker schemes. Why is a surge diverter needed across the DC CB. 8. What is the importance of simulation studies for modern DC systems and links? 9. Give the protection schemes for the following types of faults (a) DC line overcurrent protection (b) Valve and bridge group protection (c) Filter bank protection.

MULTIPLE CHOICE QUESTIONS 1. Most frequent type of fault in DC systems is (a) converter internal fault (b) DC line fault (c) commutation failure (d) arc back and arc through 2. Fault current level is highest in the following types of faults (a) converter internal fault (b) DC line fault (c) commutation failure (d) lightning stroke on lines 3. Which of the following fault is self-clearing (a) DC line fault (b) single commutation failure (c) multiple commutation failure (d) arc back and arc through 4. Usual time taken for fault clearing after the fault is sensed is (a) less than 2 ms (b) 10 ms (c) 1 to 2 s (d) 100 ms


HVDC Transmission

5. Converter faults are cleared by (a) tripping of AC side CBS (b) blocking the rectifier and inverter (c) opening the ground or neutral CB (d) using backup protection schemes 6. In worst case, for a phase-to-phase short circuit at nonconducting valve terminals, the peak short circuit current is (a) 2Ido (b) 3Is (c) Ido + 3Is (d) 12 (Ido + 3Is) 7. Bypass valve is mainly used to clear (a) temporary faults that occur is valve bridges (b) pole-to-pole fault at converter terminals (c) arc back and arc through in valves (d) faults on DC side of the converters 8. Fault sensing is done by comparing (a) Vd and Id (b)

- dv dt

dv dI and which set up travelling waves dt dt (d) none of the above (c)

9. A surge diverter is used across the DC CB to (a) limit recovery voltage (b) limit fault current (c) absorb the arc energy (d) all of the above 10. The principle of DC CB is (a) forcing a current zero and extinguishing the arc (b) limit the arc voltage and absorb arc energy (c) lengthening the arc and quenching it (d) diverting the arc into another circuit 11. Metallic return transfer breaker MRTB is needed for (a) isolate ground return (b) switch off ground connection during line-to-ground fault (c) isolate ground loop (d) eliminate metallic element corrosion close to DC line in monopolar operation 12. Valve group protection is done using (a) overcurrent comparison (b) differential protection (c) current control limiter (d) HRC fuses in each group

ANSWERS 1. (c) 9. (c)

2. (a) 10. (a)

3. (b) 11. (d)

4. (d) 12. (b)

5. (b)

6. (d)

7. (a)

8. (c)

Overvoltages and Insulation Co-ordination for HVDC Systems 9.1


Overhead lines, cables and other components like converters, transformers, etc., are subjected to overvoltages. The external cause for overvoltages is lightning and only power lines and outdoor equipment is subjected to it. However, other requirement can have induced and transmitted voltage. But this is limited by the protective devices. Other transient voltages to which the system is subjected are (i) faults and fault clearing, (ii) converter operation, i.e. switching and blocking in converters and sudden interruption of large currents, and (iii) the commutation in the converter devices. The overvoltages that occur in the DC system, mainly at the converter station are (i) (ii) (iii) (iv)

The lightning and switching transient voltages which are external to the station Fast transients produced in the converters Overvoltages due to faults, faults clearing, etc., originating from DC side Overvoltages due to disturbances on AC side

Since all these overvoltages affect the insulation structure and the insulators used in the overhead transmission line, a review of the insulator application on HVDC lines is presented.

9.1.1 Requirements for DC Insulators Insulators for HVDC applications are required to endure specific electrical stresses compared to insulators used in AC applications. This is due to unidirectional flow of electric current and highly non-uniform electric field distribution along the insulator string. This will further worsen under polluted conditions. If the stress is not tackled properly in DC insulator design, it can lead to electrical and thermal stresses that cause rapid material degradation, failure due to puncture, corrosion damage to metal parts, and frequent flashovers due to contamination. The improvements to be made for each type of specific DC stresses are with respect to 1. Dielectric material 2. Shape of material shell of insulator material, i.e. toughened glass, porcelain, or polymeric material 3. Corrosion resistance of metal parts end fittings


HVDC Transmission

Insulator’s dielectric shells, made of any one of the materials mentioned above, have some form of ionic conductivity. Alkali ions within the materials migrate through its internal network. Hence, high resistivity materials such as toughened glass or EPDM is preferred for DC insulators. Since the contamination aging is much larger with DC than AC, it should be ensured that adequate mechanical and electrical strength is provided. Further, the DC leakage currents on the surface of a wetted and contaminated shell cause electrolytic action at pin surface close to the cementing line. Corrosion, which is much severe results in shell cracking in the head area. Therefore, an optimised insulator design is needed.



Insulator requirements for HVDC are quite different from AC application. Insulator capacitance is not important here as it does not contribute to any capacitive current which is absent in DC. Since the electric field and DC stress are unidirectional, the factors that affect the performance are (i) (ii) (iii) (iv)

Ionic current Ion or charge accumulation on insulators Non-uniform voltage distribution due to non-uniform electric field Electrostatic attraction of dust and other particles.

The above factors contribute to (a) More suspect-ability to pollution and settlement of the particles on the insulator surface (b) Discharges of larger magnitude; and these are stable and propagate easily The requirement of total number of insulators is more compared to AC (c) Initiation of thermal runaway condition (d) Unit flashover which is high (e) Contamination accumulation is larger The requirement of creepage length with DC is much high As per the accepted norms and recommendations given by IEC, IEEE standards, etc., the requirement of minimum creepage length is shown in Table 9.1. Table 9.1 Creepage length recommended under polluting conditions Creepage Length Pollution Level

AC (mm/kV)

DC (mm/kV)

Light, (Agricultural land, area without industries)



Medium (Industrial but not producing smoke)



Heavy (high density industrial area, heavy smoke heating plants, etc.)


ª 50

Very heavy (Coastal, marine pollution chemical industries, desert area with no rain, etc.)


ª 70

Overvoltages and Insulation Co-ordination for HVDC Systems


The air insulation-gap length requirements for typical AC and DC systems are given in Table 9.2. Table 9.2 Air gap length under polluting conditions Air Gap Length

275 kV DC

500 kV DC

275 kV AC


2.1 m

3.8 m


Light pollution

2.2 m

4.1 m


Medium pollution

3.1 m

5.8 m

Heat pollution

4.4 m

8.2 m

The equivalent circuit of a string insulator for AC and DC application is shown in Fig. 9.1.

Fig. 9.1

Equivalent circuit of a string of insulators

From the equivalent circuit it is evident that in both cases of AC and DC the voltage distribution along the string is non-uniform and line end insulators will have larger voltages impressed upon them. The surface resistance and resistance equivalent to ionic currents are shown as variable, as they depend on surface conditions, weather conditions and pollution levels.

9.2.1 Types of Insulators for DC Applications The type of insulators used with DC systems are (i) Porcelain insulators both disc type as well as long rod insulators (ii) High resistance toughened glass (HRTG) (iii) Composite insulators, silicone rubber insulators with fibre rods


HVDC Transmission

The pollution performance of porcelain insulators is not satisfactory and results in heavy leakage currents. Hence, the insulator surfaces are usually treated with either RTV or silicone grease coating. It has been reported that under light rain conditions of 0.2 mm/min precipitation, a 150 kV rated insulator string resulted in a leakage current of 0.7 mA, whereas with RTV coating the leakage current was 0.02 mA and with silicone grease coating it was only 0.001 mA or 1 mA. The same string with a rain of 20 mm/min for 10 min failed in giving a flashover. The respective coatings of RTV and silicone grease resulted in 12 mA and 0.21 mA of leakage current. The high resistance HRTG have better performance and are reported satisfactory with better shed profile and increased booster sheds. They have proved to be very good with DC lines for the last 30 years. Porcelain insulators for high voltage applications are made as long rod units of length up to 1 m. Depending on the voltage application 1 to 5 units or more are used. They proved to have good long term satisfactory experience and good mechanical strength, puncture proof and self-cleaning property. However, a disadvantage is that the string is heavy, inflexible and has greater failure rate due to vandalism and heavy breeze conditions. Composite long rod insulators with polymeric and silicone rubber material which have been introduced during the last 15 to 20 years have less weight and are made as single unit up to 400 kV. They are punctureproof, have good RIV and corona performance, and are also competitively priced. The field experience with composite insulators is very less and they have less tracking resistance. The greatest advantage with silicone composite insulators is excellent pollution performance. The hydrofobacity property of repelling water droplets on the surface makes them better suited for polluted areas. Since fault induced overvoltages are usually less with DC lines and lightning performance of insulators is of less importance in EHV and UHV lines, the switching surge levels are less (about 1.7 p.u.). As such, pollution performance is given more importance in the selection of insulators. A comparative study shows that for a 400 kV line, 31 discs weighing 332 kg with a string length of 5.27 m is needed. Whereas a long rod porcelain insulator will have 4 units weighing 200 kg with total length 5.41 m. A polymeric composite insulator has only one unit weighing 28 kg and is 4.45 m in length. This shows the advantages of using polymeric long rod insulators. The insulator application for ±500 kV lines is given in Table 9.3. Table 9.3 Insulator applications of di erent 500 kV HVDC lines DC Line Pacific Inter Tie

Type of Insulators Porcelain

Creepage Length (mm/kV)

No. of Insulators in a String



(do) polluted

22 to 28

24 to 30


Toughened glass (HRTG)

28 to 32

32 to 36

Rihand–Dadri (India)







40 to 44

Silicone Rubber (Heavy polluted areas)

Single unit length

Overvoltages and Insulation Co-ordination for HVDC Systems




Lightning strokes cause steep fronted surges on overhead lines, with front times ranging from 0.5 to 5 ms and tail times of the order of 20 to 100 ms. Lightning causes travelling waves on the lines which travel in both directions and the surges are slowed down by the characteristic impedance of the line, and are attenuated by the resistance. The wave that enters a converter station is further modified by the smoothing reactor and DC capacitors. Lightning stroke currents on the EHV and UHV DC lines may be typically 5 to 10 kA or even less. Further, ground wire provided over the overhead line also diverts and reduces the rise time as well as the magnitude of the surge voltages. Lightning stroke surges that propagate from the AC side are reduced or suppressed by the AC filters and the converter transformer. The converter station experiences only long duration surges when it comes through the transformer. Further, the incident surge currents that come from the DC line side can sometimes cause sharp oscillating overvoltages. Typical effect of such oscillations as their rise time t is varied is shown in Fig. 9.2.

Fig. 9.2

Lightning surge I0 = 5 kA propagating into the converter station (Ref. 1)


HVDC Transmission

9.3.1 Switching Type Overvoltages Switching on or switching off the DC line on load due to earth fault on one pole can give rise to surge voltages on the other pole due to inductive and capacitive coupling between the two pole conductors. The surges have longer front and tail times and may have a magnitude of the order of 1.8 p.u. or more depending on line length. For converters in their normal conducting mode, the distribution of the switching surge is governed by the inductance that exists between concerned points and the ground. Switching surges of long duration and high energy content may cause currents of sufficient magnitude to produce current extinction. Since the smoothing reactors (inductors) have large inductance, the switching surge does not have much effect on conducting valves in a bridge. But the incoming surge can cause extinction of valve current and this will cause overvoltage across the converter bridge as shown in Fig. 9.3.

Fig. 9.3 DC line switching-surge causing valve current extinction

Overvoltages and Insulation Co-ordination for HVDC Systems




Internal converter faults like misfire or commutation failure in a valve give rise to fundamental frequency voltage on DC lines. Typical overvoltages that occurred during early operation of Cabora–Bassa DC line are shown in Fig. 9.4. They had a peak value of 3. p.u. and these overvoltages can continue for several cycles. If the converter has proper current control system and is effective, the DC voltage is checked reducing the overvoltage and oscillations. In modern controls they are limited to 1.5 p.u. Some other situations which may give rise to overvoltages are (i) A short circuit in one pole of the DC converter induces an overvoltage in a healthy pole. The overvoltage can be of the order of 2 p.u. or more but will be limited to less than 2 p.u. by the control mechanism.

Fig. 9.4 Line current and voltage recorded at the inverter during missing pulse condition in a rectifier bridge (© 1980 CIGRE)

(ii) Deblocking or re-energisation of converter bridges also causes transient voltages. The extra voltage that is developed on the DC line when a rectifier is deblocked with full voltage and when the inverter end is open is shown in Fig. 9.5(b). Usually the rectifier voltage gradually rises in about 0.25 s or more but a snag or fault in the control unit will give rise to the transient voltage as shown in Fig. 9.5. (iii) Voltage oscillations across a valve can occur in case of an earth fault on valve side of the DC reactor, Ê dv ˆ or its bushing. In Fig. 9.6, the rate at which such voltage rise occurs across the valve Á ˜ is shown. Ë dt ¯ However, this type of transient voltage does not effect line insulation.


HVDC Transmission

Fig. 9.5 Deblocking with full rectifier voltage against an open inverter end

Fig. 9.6 Calculated maximum rate of rise of earth fault overvoltages across the valves with faults inside the converter station (© 1974 IEEE)



Transient voltages of longer duration but less magnitude that propagate into the converter station or DC lines are (a) Harmonic overvoltages due to AC side disturbances (b) Unbalanced AC faults. Usually switching, lightning or other types of overvoltages are limited or blocked on the AC side itself by the protective devices and the converter transformers. Usually filters present capacitive reactance at the fundamental frequency. If the other side of AC system is inductive, which is the usual case, a parallel resonance occurs between the filter capacitance and system

Overvoltages and Insulation Co-ordination for HVDC Systems


inductance at 2nd, 3rd or 4th harmonic. In case of the 5th harmonic filter, the capacitor bank is put for reactive power compensation. Further, the magnitude of the harmonic voltage generated will be more with an unbalanced fault occurring on the AC side. These harmonic voltages drive the converter transformer to saturation. A large magnitude of harmonic voltage is superimposed on the fundamental voltage. The impedance angle of the system greatly affects the overvoltage. Typical harmonic voltage distortion is shown in Fig. 9.7. Figure 9.8 indicates how short circuit ratio and impedance angle influence the overvoltages generated. Typical simulated overvoltages for different fault conditions at the rectifier terminals are shown in Fig. 9.9. Faults occurred at time t = 0.51 s and cleared at 0.60 s.

Fig. 9.7 Harmonic voltage distortion following an AC fault

Fig. 9.8 Statistical overvoltages on transformer energisation as a function of system impedance and impedance angle (© 1980 IEEE)



Since all equipment in any system has to experience a certain amount of overvoltages in normal operation, the insulation design of all the equipment like converter insulation, the insulators used for their mounting, the reactors, filters, line conductors, etc., will be designed to withstand the basic impulse level (BIL) for transient and lightning voltages. Further, insulation is also designed to withstand about 2 p.u. transient switching and


HVDC Transmission

Fig. 9.9 Voltage and currents at DC rectifier terminal under 3 di erent fault conditions

Overvoltages and Insulation Co-ordination for HVDC Systems


other types of extra voltage over and above this level. Spark gaps and surge arresters (lightning arresters) are used and coordinated for minimum number of units and minimum cost.

9.6.1 Rod Gaps The simplest and effective protection device is a rod–rod gap consisting of either square or circular cross section rods, fixed on all insulators either vertically or horizontally, and separated by a distance. The sparkover voltage depends on atmospheric conditions. However, it does not meet complete requirements of a protective device. The sparkover characteristic of a rod gap is shown in Fig. 9.10. Since there is no current limiting device, a series resistance of nonlinear type is often used in series with it. The dispersion of sparkover voltage is high (ª15%). The sudden collapse of voltage to zero, when the gap sparks, creates a steep step voltage which sometimes proves dangerous. Spark gaps are usually used to protect bushings of reactors, transformers and other such apparatus.

Fig. 9.10

Sparkover voltage characteristic of rod gaps

9.6.2 Surge Arresters Surge arresters or lightning arresters are devices with nonlinear resistance (like silicone carbide, zinc oxide (ZnO) or such metal oxide) and gap. ZnO arresters are usually gapless. They are designed for 5, 10 or 20 kA surge current. The sparkover voltage of the arrester is normally far less than any other equipment or Ê1 ˆ apparatus to be protected. They are capable of discharging 100 to 250 kA of short duration ÁË m sec˜¯ surge 2 currents also, and will absorb or dissipate energy of few tens of kilojoules.


HVDC Transmission

The main task and requirements of surge arresters is (i) To protect the equipment from overvoltages (ii) It should not have any effect on the power system during normal operation (iii) It should be capable of withstanding surges and dissipate energy without incurring any damage. The requirements are (a) Offer low resistance during surges so that overvoltage is limited to a low level (b) Very high resistance during normal operation to avoid power loss and energy loss (c) They must operate satisfactorily under earthquakes, polluted atmospheres, under high and low temperature conditions, etc. Figure 9.11 shows a cross-sectional view of a typical ZnO arrester housed in a polymeric housing for application in HVDC systems. The assembly consists of a number of ZnO discs piled one over the other and compressed by a suitable spring. A pressure relief valve is provided so that any gases or decomposed products released are sent out. The volt-ampere characteristic of a single disc of metal oxide element is shown in Fig. 9.12 and voltage-current oscillogram for positive and negative impulses of 20 kA arrester unit is shown in Fig. 9.13. The volt ampere characteristic is extremely flat and has power law V = IKn, n ª 0.05 to 0.2.

Fig. 9.11

Metal oxide (ZnO) surge arresters

Overvoltages and Insulation Co-ordination for HVDC Systems

Fig. 9.12

Current/voltage characteristics of a nonlinear MO arrester

Fig. 9.13 Typical voltage and current oscillograms obtained for the positive-negative impulse test on a surge arrester



HVDC Transmission

Surge arrester application in DC is quite different from that of AC. The arrester has to suppress direct current in a highly inductive circuit, as a large valve (few mH) smoothing reactor exists on the DC side. Hence, current suppression needs to be done in a controlled manner. Earlier arresters with series gaps and silicon carbide valve elements were used. The present metal oxide arresters have high discharge capability and lack of spark gaps avoids sparkover transients which is an added advantage. The voltage of the arrester will not rise much even with a large current of several kilo amperes. In case of switching surges, all arresters connected to a bus will share the current and limit the voltage to a low valve. Further, they contribute for damping the transients. An overvoltage limiter can be used in parallel with the arrester by connecting thyristors in anti-parallel mode across them. In general, a surge diverter must be set in such a way that (i) it discharges an overvoltage greater than the normal operating voltage and (ii) lower than the breakdown or sparkover voltage of the insulation of the equipment or system.

9.6.3 Limitation and Control of Overvoltages Various types of overvoltages that have been discussed in previous sections are usually limited or controlled by methods mentioned below: (i) (ii) (iii) (iv) (v)

Properly designing the HVDC control Avoiding resonances at low order harmonics Making use of damping circuits such as pre-insertion and opening resistors in CBs Installing controlled reactive power compensation on AC side Using proper surge arresters

To limit overvoltages further, the HVDC control system should be optimised to achieve (i) Optimum recovery from AC and DC faults so that temporary overvoltages on both sides are damped (ii) Limiting the oscillations of DC system caused by malfunctioning of bridges (iii) Multiple commutation failures due to voltage dip on AC side of the inverter to be avoided Further, DC filters and smoothing reactors are designed to avoid power frequency and low order harmonic resonances.



The insulation design of DC lines, creepage length chosen on insulators and air gap clearances allowed are to be chosen and designed based on (a) lightning, (b) switching, and (c) temporary overvoltages. Selection of the insulator is mainly based on the creepage length of the insulator system. The design of this external insulation is very critical from the point of reliability of the line. The risk factor should be economically chosen to withstand the location severity and pollution levels. The knowledge of field data and co-relation with laboratory test results is a necessity while selecting the design of the insulator. The specific creepage distances (mm\kV) given in Tables 9.1 and 9.2 are to be carefully selected so that flashovers and outages do not occur. It is reported that creepage distances of 80 mm/kV have flashed over many a time in certain systems, whereas those with 20 mm/ kV have not flashed. Usually while selecting an insulator the voltage is taken as 1.1 times. Fog condition is taken as 35 to 55 mm/kV for natural pollution levels of 0.12 mg/cm. Larger values have to be adopted for heavy pollution.

Overvoltages and Insulation Co-ordination for HVDC Systems


Air Clearances Normally insulators provide adequate leakage distance to minimise leakage currents and also maintain adequate conductor-to-tower clearance even under adverse wind and weather conditions. However, the presence of insulators degrade the air gap characteristics. The air gap stresses due to continuous presence of DC voltage. Superimposed lightning and switching overvoltages must be considered. Adequate clearance between conductors and conductor-to-ground (tower body) has to be chosen to keep line reliability at an optimum value. Usually the rod/plane gap withstand and flash over characteristic data with positive polarity. DC voltage is used for line clearance design since most of the DC Lines that are now coming up are in the EHV or UHV range. Here, the switching impulse flashover criteria is considered as the governing factor. The DC voltage superimposed by switching impulse voltage characteristic (50% flashover voltage, forms the basis for choosing the proper conductor-to-ground clearance.



The converter station, its component parts and equipment have to be protected against different types of overvoltages such that the number of failures are as less as possible. At the same time, the cost involved in design, installation, operation and maintenance should not be high. Hence, a gradation of system insulation and protective devices chosen is to be followed, keeping in view the importance of the equipment involved. The converter station has on AC side substation transformers, switchgear, filters and reactive power compensators like capacitors, ‘STATCOM’, metering equipment and bus bars. On DC side the converter valve group, line reactors, filters, metering and switchgear, DC bus, etc., are located. All these equipment have to be protected against internal insulation failures, sparkovers, etc. For selfrestoring insulation like string insulators, bushings or post insulators a flashover outside, i.e. in the air can be allowed. But these flashovers must be minimum or negligible. For systems of ±300 kV or below, switching surges of external nature may not be of importance, but fast transients generated inside and lightning impulse are to be considered. For lightning and fast transients, the withstand level known as basic impulse level is established from system nominal voltage of operation. For system voltages of ±300 kV and above, switching surges and long duration transients are of importance and SIL or switching impulse level similar to BIL is established. The sparkover or flashover voltage of a protective device is chosen such that it will not operate for normal DC or/and other harmonic voltages. But if a long duration overvoltage due to harmonic voltages or faults occur, it may have to operate and hence must have thermal overload capacity. In EHV and UHV systems, the protective device has to limit the overvoltages due to switching, internal transients and lightning overvoltages. Hence, suitable margin between BIL and SIL is to be given. The ideal requirements are (a) It should not flash over for power frequency or DC voltages (b) The volt-time characteristic of the device must lie below the withstand voltage of the equipment insulation (to be protected) and adequate margin must be given to account for change in characteristics atmospheric conditions, pollution, etc. (c) Should be capable of discharging high energies and recover the insulation quickly (d) It should not allow DC or power frequency follow-on currents and should seal off


HVDC Transmission

The steps to be followed are (i) Insulation levels of system components to be determined and a scheme for protecting equipment for that insulation level is to be drawn (ii) The maximum steady state, temporary and transient voltage levels are to be established for various equipment (iii) Required voltage withstand capabilities are to be chosen (iv) The volt-time and other characteristics of protective devices are to be determined (v) The equipment to be protected should not be subjected to excess voltage (vi) The number and location of protective devices and requirement of each protective device (arrester) is to be established It should be noted that energy storing elements and VAR sources of large magnitude like capacitors, filter units, etc., affect the co-ordination. The protective devices, i.e., surge arresters are to be located at (i) AC yard with AC bus arrester (ii) Valve house with converter group and also each valve arrester (iii) DC yard with DC bus arrester The arrester voltage rating, current rating and arrester location are generally decided by (i) Calculation of reference voltage (ii) Maximum continuous operating voltage The selection of surge arrester is based on (a) Calculating the current rating for lightning and switching surges (b) Fixing the BIL and SIL (c) Arriving at the protective margin The BIL and SIL usually adopted in converter stations are given in Table 9.4. Table 9.4 BIL and SIL adopted in converter stations Location/System AC side

Base Voltage (p.u.)




2.8 to 4.0 p.u.

2.4 to 3.5

2.8 to 4.0 p.u.

2.4 to 3.5

3 2VL Converter Transformer AC side


Converter Transformer DC side

p Vdo 3 p Vdo 3

2.8 to 4.0

2.4 to 3.5

1.8 to 2.2

1.8 to 2.2

DC bus




Mid-point of bus




DC line





Overvoltages and Insulation Co-ordination for HVDC Systems


REFERENCES 1. Arrillaga J., High Voltage Direct Current Transmission, Peter Pereginnus Ltd., IEEE, 1983, 1st edition; 1998, 2nd edition. 2. Khalifa M.E., High Voltage Engineering Theory and Practice: Marcel Dekker, (New York) 2000. 3. Naidu M.S., Kamaraju V., High Voltage Engineering, 4th edition, (New Delhi), Tata McGraw-Hill, 2008. 4. Elahi H. et al., Insulation co-ordination process for HVDC converter station, IEEE Tr. (power delivery), Vol. 4, No. 2, 1989. 5. Tanabe S. et al., Study of overvoltage protection on HVDC LTT Valve, IEEE Tr. (power delivery), Vol. 15, No. 2, 2000. 6. Results of salt fog ageing test under DC stress on cap and pin: Glass and porcelain insulators, ISH-93/1993 N 41-04. 7. Choice of Insulators for DC Tr. Lines, IEEE, PES Conference, (Madras, India), February, 1986. 8. Sediver, HRTG Insulators for HVDC Application DC, 1999. 9. Insulator maintenance, International workshop on HVDC, (New Delhi), February 25–26, 2008. 10. Friedrich Kiessling et al., Overhead Power Lines, Springer -Verlag (Berlin), 2003. 11. Kuffel E., Zaengl. W., High Voltage Engineering, Pergamon Press, Oxford (England) 1984; 2nd edition, Butterworth-Heinemann, (England) 2000. 12. Haddad A. et al., Double impulse testing of ZnO surge arresters, EE Division School of Engineering, University of Wales (UK), 2004. 13. Mohd. Muhrid-za-bin Yacob, Behavior of metal oxide varistors under multiple lightning strokes, PhD Thesis, University of Technology (Malaysia), 2005. 14. Seiman, Power Engineering Guide Transmission and Distribution, 4th edition. 15. Shang L., Herold G. et al., High speed fault identification and protection for HVDC lines using wavelet technique: proto-power tech, (Porto Portugal), Sept. 2001. 16. Peixoto CAO, Flashover performance of HVDC converter station insulators under polluted conditions, Cigre, SC 33 Colloquium, (Edinburg, UK), Jan. 1983. 17. Naito K., The performance of insulators subjected to DC voltage under polluted conditions, Cigre, SC 33.81, Section III, Artificial Pollution Tests. 18. Kimoto T. et al., Performance of insulators—HVDC transmission under polluted conditions, IEEE PAS 92, 1973. 19. Ramamoorty M. (edited), HVDC Transmission Handbook, CPRI (Bangalore), January, 1993.

WORKED EXAMPLES 9.1 Typically for an HVDC system rated for 150 kV, the insulation levels chosen are (150 kV = 1 p.u.). For Thyristor valves negative polarity: Fast transients For Thyristor valves negative polarity: Switching transients

Ê1 ˆ ÁË m sec ˜¯ 4 to 4.5 p.u. 5 3.25 to 3.5 p.u.


HVDC Transmission

Solution Maximum permissible dynamic AC voltage Peak commutation transient Protective device sparkover voltages: Maximum sparkover Max power frequency sparkover and Switch surge sparkover Minimum impulse and switching surge sparkover Rated resealing voltage

2 to 2.2 p.u. (a = 90°) ª 1.8 p.u. ª 2.5 p.u. ª 2.35 to 2.40 p.u. ª 2.2 p.u. ª 1.6 p.u.

9.2 The insulation levels chosen for a ±250 kV (500 kV) system are Steep fronted impulse (0.5/5 msec) +600 kV and Lightning impulse withstand voltage and Switching impulse withstand voltage +575 kV and Protective level chosen 524 kV Surge arrester sparkover voltage (for both lightning and switching) 499 kV Peak direct overvoltage impulse (a = 0°) 467 kV Peak direct overvoltage impulse (a = 90°) 458 kV Peak AC line-to-line voltage VLL 305 kV Temporary overvoltage level 1.3 p.u.

600 kV 575 kV

Solution The above tabulations give the chosen voltage withstand levels and protective margins adopted. The arrangement of different types of arresters and their location in a converter station is shown in Fig. 9.14 and Table 9.5.

Fig. 9.14 Location of surge arresters in a converter station

Overvoltages and Insulation Co-ordination for HVDC Systems


Table 9.5 Arrester location and purpose in converter stations Location


AC bus arrester A

Arrester Type

The ZnO arrester will be installed close to the converter transformer line side bushing

Limit the overvoltages on the primary and secondary side of the converter transformer.

AC filter bus arrester Aa

The ZnO arrester will be installed Protect the AC filters busbar against lightning surges. at the busbar of the AC filter banks

Valve arrester V

3-pulse commutation group

The main events to be considered with respect to arrester discharge currents and energies are (a) Switching surges from the AC system through converter transformer (b) Ground fault between valve and HV bushing of converter transformer during rectifier operation

Converter group arrester C

12-pulse converter group

Protection against overvoltages from the AC and DC side.

DC bus arrester D

At the HV smoothing reactor and at the DC line

They will protect the smoothing reactor and the converter station (e.g. DC switchyard) against overvoltages coming from the DC side.

Neutral DC bus arrester E

Neutral DC bus

The neutral bus arresters protect the LV terminal of the l2-pulse group and the neutral bus equipment.

AC filter arrester FAC

AC filter

The operating voltage for the AC filter arresters consists of low fundamental frequency and harmonic voltages. Overvoltages can occur transiently during faults.

AC filter arrester FDC

AC filter

The operating voltage for the DC filter arresters consists of low DC component and harmonic voltages. Overstresses may occur transiently during DC bus fault to ground.

9.3 Insulation co-ordination suggested for an 800 kV UHV station. Basic Impulse Level Chosen (ª 2.5 p.u.) = 1950 kV Switching Impulse Level Chosen (ª 2.0 p.u.) = 1550 kV Solution (a) 800 kV DC bus side for 12-pulse converter after reactor to the line side. Lightning protective level = 1625 kV The DC line has ground wire shielding and overhead line arcing horns. The allowable margin is

1950 – 1625 ¥ 100 = 20% 1625

Switching impulse sparkover (protective level) = 1345 kV Margin

1625 – 1345 280 = ¥ 100 ª 16% (> 15%) 1625 1625


HVDC Transmission

Ground fault overvoltage expected ª 1040 kV Overvoltage due to disconnection of AC line on inverter side expected ª 1215 kV (The insulation on the line side and reactor side can withstand this voltage) (b) 800 kV DC bus and valve hall BIL chosen 1800 kV SIL chosen 1520 kV Lightning (fast transient) protection level = 1500 kV Switching surge protection level = 1320 kV Margin for Lightning impulse

1800 – 1500 ¥ 100 = 20% 1500

Margin for Switching impulse

1520 – 1320 ¥ 100 = 14% 1520

(c) Thyristor valve insulation Since there will be 4 valves in series in a 12-pulse converter quadruple valve. For each valve Lightning withstand level (BIL) = 425 kV Switching surge withstand level (SIL) = 450 kV (Switching impulses are severe with valves and are fast transient). Hence, Lightning sparkover voltage ª 385 kV Switching sparkover voltage = 405 kV. 425 – 385 Margin Lightning = ¥ 100 = 9% 385 445 – 405 Switching = ¥ 100 = 9% 440 It may be noted that valves will have much high insulation level and a 10% margin is quite enough in UHV systems. (d) Smoothing reactor: Lightning impulse level = 2160 kV Lightning sparkover voltage = 1800 kV 2160 – 1800 360 Margin = = 20% 1800 1800 (Two arresters of 900 kV sparkover in series are suggested for reactor protection.) (e) Y–Y transformer secondary side (converter transformer) protection BIL or Lightning withstand voltage = 1750 kV Switching impulse withstand voltage = 1520 kV Lightning impulse protection level (sparkover) = 1450 kV Switching impulse protection level (sparkover) = 1320 kV

Overvoltages and Insulation Co-ordination for HVDC Systems


1750 – 1450 ¥ 100% = 20% 1450 1520 – 1320 ¥ 100% = 13.2% Margin for Switching = 1520 AC bus switching surge level =1130 kV Inverter blocking with respect to bypass valve pair = 1100 kV Both these overvoltages can be withstood by the valve insulation. There are many other considerations to be met and worked out before the protective level score is arrived. It can be inferred from the discussions that choosing proper insulation level for the equipment and protective levels (surge diverters) for overvoltages are crucial for EHV and UHV DC systems. Margin for Lightning =

QUESTIONS 1. What are the causes for overvoltages in DC systems? Discuss their characteristics and effects. 2. How are insulators for DC different from that for AC? What are their requirements? 3. Discuss the equivalent circuit of DC insulator string and explain the significance of different components. How is the voltage distribution across the sting? 4. Discuss the nature and characteristics of short duration and lightning impulses in DC systems. 5. What are the different kinds of switching surges that occur in DC systems? Give their characteristics and effects. 6. Give the constructional features of metal oxide arresters. What are their characteristics and features? 7. What is insulation co-ordination in DC system? Explain the choice of different insulation levels. 8. Explain how the insulation co-ordination is affected by different types of overvoltages. Work out the insulation levels for a converter station with a suitable example. 9. What are the methods adopted for limiting overvoltages in DC systems?

MULTIPLE CHOICE QUESTIONS 1. Valve house and converter station is mostly subjected to the following overvoltages: (a) Lightning (b) Short switching impulse (c) DC overvoltages (d) Power frequency overvoltages 2. Equivalent circuit of a string insulator for DC is (a) capacitance network (b) R–C network (c) resistance network with variable resistance (d) none of the above 3. Variable resistance part of equivalent circuit for DC insulator string is (a) ionic current (b) surface resistance (c) volume resistance (d) both ionic current and surface resistance


HVDC Transmission

4. Typical creepage length for DC voltages under pollution conditions is (a) 40 to 50 mm/kV (b) 10 to 15 mm/kV (c) above 70 mm/kV (d) 20 to 25 mm/kV 5. Long rod composite insulators are most suitable for DC applications under (a) wet conditions (b) low temperatures (c) pollution condition (d) all the above 6. In earlier HVDC schemes insulators used were (a) RTV and HTV insulator (b) Silicone composite insulators (c) Porcelain and high resistance glass insulators (d) All of the above 7. Material used for surge arresters for DC applications is (a) ZnO (b) SiC (c) Graphite (d) Magnesium–aluminium oxide 8. The volt-ampere characteristic of a gapless nonlinear element in surge arresters is (a) V = KIn(n > 2.0) (b) V = K1In + K2I–n (n ≥ 2) –n (c) V = KI (n > 2.0) (d) V = KIn(n < 0.3) 9. The equivalent circuits of a surge arrester for DC is (a) capacitance (b) nonlinear variable resistance (c) inductor (d) R C network 10. BIL chosen for HVDC bus is usually (a) 3.5 Vd (b) 1.7 Vd (c) 4 to 4.5 Vd. (d) 2.7 to 2.9 Vd 11. The purpose of insulation co-ordination is (a) to limit overvoltages (b) to grade the insulation level of different apparatus so that the most important one is best protected (c) to protect all apparatus equally against surges (d) surge arresters are used to minimum extent 12. Rod gap protection is not normally done because (a) protection for fast transients is doubtful and introduces steep fronted transient when sparkover occurs (b) becomes short circuit on sparkover (c) sparkover depends on atmospheric conditions (d) none of the above

ANSWERS 1. (b) 9. (b)

2. (c) 10. (d)

3. (d) 11. (b)

4. (a) 12. (a)

5. (c)

6. (c)

7. (a)

8. (d)

Multiterminal HVDC Systems 10.1 INTRODUCTION HVDC systems were earlier developed as point-to-point connections transmitting power from one end to the other or as back-to-back networks. As such they were feeding only one load point or exchanging power from one end to the other. Recently, with larger systems of one gigawatt or more and interconnecting nonconventional energy source points like off-shore wind generators, oil rig platforms, etc., there is a need to connect more than one of them through a DC link. Further parallel operation of converters and connection of more than one unit to a common bus also becomes a multiterminal operation. Multiterminal HVDC transmission (MTDC) is best suited to provide facilities for power exchange between large power grids such as home grids or inter-country transmission systems. MTDC is cost effective and requires less space for spreading transmission lines for the same power exchange compared to AC systems. This facilitates the operation and administration of power flow control in large systems. Many HVDC systems are now point-to-point connections. Contrary to this, a MTDC allows all partners (such as regional power operators) to connect within the reach of transmission line routing. A few MTDC schemes have been implemented in Europe, USA and Canada. The experience gained from those schemes has proved that energy availability and reliability is of the same order as that of point-to-point DC schemes. The major additions for MTDC would be 1. More DC switch gear is needed 2. Balancing of order between different stations so that the sum of the rectifier station currents is always equal to the sum of currents of inverter stations 3. Ramping of DC power between stations on demand 4. Control of voltage profile on DC system 5. Managing of overload for different converters 6. Relocating of power between stations and terminals after a forced outage Experience with existing HVDC links has proven that the contribution of control and protection to forced outages and non-availability of energy is very small. From previous studies#, it is concluded that a meshed #

Micheal Häuster, Multiterminal HVDC in Europe, CEPEX 99, (Poznan, Poland) 1999.


HVDC Transmission

DC grid for bulk power transmission offers increased energy availability, and the technique to operate the same is now available. This feature can be used to practically eliminate the influence of HVDC lines on energy availability.

10.2 TYPES OF MULTITERMINAL (MTDC) SYSTEMS MTDC systems can be series, parallel or ring type networks as shown in Fig. 10.1.

Fig. 10.1

MTDC systems

10.2.1 Series MTDC System A series connected system is shown in Fig. 10.1(a). All the converters are connected in series and carry the same amount of current. 1 and 2 are acting as rectifiers while 3 and 4 are inverters. Out of the full supply voltage, part of the voltage may be dropped across the inverter 4 (20 to 30%) and 20 to 30% of the power is only tapped at the point 4. Usually this type of arrangement is suitable for monopolar operation. The system is grounded only at one point. Usually the entire system is designed for full voltage insulation. Sometimes other terminals are grounded through capacitors to improve insulation co-ordination. The current is usually set by one station the main rectifier unit and all other stations operate at constant g to keep the reactive power requirement to a minimum. Voltage adjustment is done through tap changing of transformers. Switching in or out of a bridge (converter) is done by blocking the particular converter and bypassing it before it is disconnected; and the process is done mechanically. Satisfactory operation of the converters require central control to adjust current setting and local control of power is done through transformer tap changing out.

10.2.2 Parallel MTDC Systems The principle of parallel connected AC systems is extended to DC systems as well, in this method. The sending end converter acts as a rectifier and more than one converter (load) is connected to the line. All converters operate almost at constant voltage. Current in all the converter stations except at the sending

Multiterminal HVDC Systems


end can be adjusted according to their load requirements. All the receiving converter stations usually act as inverter stations only, as shown in Fig. 10.1(b).

10.2.3 MTDC Ring System The parallel system may be extended as a loop system [Fig. 10.1(c)]. Each one of the inverter stations will have an alternate feed and form a closed loop. The loop may be closed or operated in radial mode with the loop opened at a convenient point. The operation of multiterminal systems is hampered because of (i) lack of application targets, (ii) complex requirement for control system and (iii) reliable DC circuit breakers. But nowadays DC breaker is replaced by a control and protection system in which the disturbance is seen in the entire system and the converters are suitably blocked or bypassed.

10.3 PARALLEL OPERATION ASPECTS OF MTDC All converters in parallel MTDC systems are connected to the same bus or line, and hence operate at the same voltage. Only voltage drop in the DC line or cable gives the voltage difference between the terminals and is true at all conditions, i.e. both transient and steady state. Schematic diagram of a typical system is shown in Fig. 10.2. Usual practice is that the largest sized inverter controls the DC voltage while the other converters control their own currents.

Fig. 10.2

Multiterminal HVDC system (two-rectifier two-inverter system)

10.3.1 Steady State Operation The V-I characteristic of two-rectifier two-inverter MTDC in a simplified manner is shown in Fig. 10.3. Inverter I2 controls the voltage Vd, while other converters control their load (current) independently. For control of current at inverter I1, it must have some margin between its voltage limit due minimum g and DC voltages Vd . As indicated in the figure I1 can dynamically increase its voltage by temporary reduction of the 1 margin for g below its steady state limit. This is possible by keeping a sum of current orders in inverters lower than that in the rectifiers. This is indicated as Im in Fig. 10.3. The size of the current margin is of the order of 10 to 12% of the rated current of the inverter, and this is important for current disturbances. For a certain temporary reduction of AC voltage of AC network fed by the inverter (I1) the V-I characteristic a is reduced to b. As a consequence the DC voltage is reduced to Vd 2 controlled by inverter I1. The new operating points go to the line Vd . The current control in rectifiers R1, R2 2 and inverter I1 will limit the current in inverter I1.


HVDC Transmission

Fig. 10.3

V-I Characteristics of converters MTDC 2-Inverter, 2-Rectifier system and their V-I characteristics

10.3.2 Operation and Control of Multiterminal Systems Even though series operation is possible and simple because of constant current, most of the MTDC systems that are now in operation are in parallel mode and operate at constant voltage. The difficulties and differences in the operation as compared to normal HVDC links are as follows. (a) Each terminal has to be operated at a different current and hence, power level. This needs that the terminal has to operate at extremes of DC voltage limited by minimum firing angle (rectifier) and minimum extinction angle (inverter). Hence, without getting overloaded at any terminal, the current settings are co-ordinated via a system current balancer. (b) Transient disturbances at one terminal like commutation failure will temporarily reduce the system voltage, and may disturb and affect the power distribution at other terminals. This has to be properly taken care of. (c) Current diversion may be affected at a faulted inverter but this will cause disparity at other terminals and hence valve design and their overloading capacity has to be properly taken care of. (d) A sustained pole to ground fault at one location (inverter), can resume service and power supply at a modified power level, with correct isolating switch opened within the de-energisation limit. This requires a fast co-ordinated blocking of the pole and disconnector switches.

10.3.3 Operation of MTDC Schemes Since DC circuit breakers are now available, the operation strategy compared to earlier schemes is modified as follows: (i) Improvement in switching time for power restoration after a fault (ii) Inverters to be operated at a higher extinction angle to take care of the dip in AC voltage under faulted conditions and is weighed against additional reactive power requirements (iii) To take into account the possibility of increased load or expansion of the system (iv) Strategy requirements for accommodating balance currents due to pole outage as stated earlier The operation strategies include (a) paralleling sequence of the terminals, and (b) disconnection or deparalleling.

Multiterminal HVDC Systems


10.4 PARALLELING (DISCONNECTING) OF UNITS OR CONVERTER Connecting a converter or disconnecting it from the line or bus is somewhat different from paralleling or connecting an AC or DC generator to the bus or disconnecting it from the bus in a station. Here it is the automatic process initiated from the power control depending on the pole line current order. The more complex procedures are the paralleling sequence for taking a converter into operation after an outage or starting up; and the corresponding deparalleling for taking the converter out of operation. The sequential procedure followed is given below: (i) (ii) (iii) (iv) (v) (vi) (vii) (viii)

The converter is first connected to the neutral or ground bus as the case may be. It is energised and connected to DC line. Tap changer of the transformer is brought to about same position of the already existing converter. The converter to be connected is always started in current control mode regardless of mode of operation (rectifier or inverter). When the current is about two times the minimum current for the pole, it is automatically paralleled. This means it is first put as inverter. Next converter is blocked, followed by deblocking of the valves. The current control now brings the parallel converter into normal operation and master control adjusts the load. The total time of operation takes about 0.3 s.

10.4.1 Deparalleling or Disconnection In order to avoid loss of power during disconnection of any of the terminals, normally, manual operation is preferred and done as follows (i) During disconnection operation the total current order of the line pole is reduced to less than 0.5 of minimum current of one converter. (ii) The DC voltage setting is lowered at the rectifier that is to stay in operation, such that its voltage controller takes it out of current control. Hence, all other stations go into current control. (iii) The firing angles are forced to retard at the pole to be deparalleled to eliminate station currents. This makes current zero before disconnection. (iv) The rectifier/inverter of the pole to be disconnected are isolated from the line. (v) The rectifier voltage controller in the running pole is reset to allow it to regain current control. The total time of operation is about 0.3 s.

10.5 CONTROL OF POWER IN MTDC In MTDC systems the control of power (current) is normally done from the central control station with remote telemetry even though individual converter stations have control mechanisms available. The different techniques used are (i) Current control (ii) Voltage limit control (iii) Automatic current regulator control


HVDC Transmission

10.5.1 Basic Control Even though several types of control procedures are suggested in real installations, only current control is adopted. This is an extension of current margin control principle used for two terminal links. This means that one station controls the voltage and the other operates in current control mode. Under dynamic or transient conditions, the roles of the two stations may be exchanged. In a multiterminal system, more than one converter controls the current simultaneously. Hence, a central master controller function is needed which determines and distributes the current order to each converter, so that SId = 0, where Id represents the sum total of all the rectifier and inverter currents. This is accomplished by the schematic control block shown in Fig. 10.4.

Fig. 10.4 Block diagram of 4-terminal current order system

Here one of the converter stations will be operating with minimum g (or a) determined by the DC voltage. All others will be operating as current controllers. The current controllers operate with voltage margin which may become negative also through zero. It is imperative that current flow and power distribution in the system does not alter except for minor changes during a disturbance. The converter with lowest voltage ceiling acts as the voltage setting terminal which will usually be the rectifier terminal. The magnitude of current margin is critical for converters of lower rating as they may become overloaded. A central controller usually regulates all the terminals and is called current reference balancer.

10.5.2 Power Control or Power Modulation HVDC transmission is mainly preferred for its unique feature, i.e. power which can be controlled very accurately at all times. Hence, it is used to modulate power and stabilise it in that part and the surrounding AC network. Same power modulation technique can be used for control in multiterminal networks. The current order control technique described earlier can facilitate power modulation provided the inverter terminals have sufficient current capability.

10.5.3 Faults and Protection of MTDC Since VDCOL control (Ref. Sec. 4.8) is widely used in the control of HVDC systems, faults in the converters are handled by the master or central control unit with appropiate deparalleling and disconnection of the

Multiterminal HVDC Systems


converter under fault. If the telecommunication link fails, fault clearance has to be attended locally. If a ground fault occurs in the DC line, differential voltage level and derivative control detectors are used for fault clearing. All terminals are equipped with DC line protection and can detect fault currents. When a fault is detected, rectifiers at all terminals are retarded to bring the current to zero and inverters will de-energise the line. After fault clearance, all rectifiers are first started with an alternate possible reconfiguration decided by the master controller. The most significant aspect in MTDC is increased transient and temporary overcurrent at inverter terminals for all types of disturbances or faults, as all parallel converters feed into the fault. If the faults are cleared by DC circuit breakers, switching overvoltages are induced into the DC system of higher magnitudes.

10.6 VSC—MULTILEVEL DC SYSTEMS With the advent of new energy sources like wind power, solar power or tidal power, transport of energy by conventional AC systems has become very difficult due to the following reasons: (i) Varying voltage and power at different times during a day (ii) Interconnection of coast or island power to mainland Hence, the generated power is converted into DC mode for transmission. Further, remote islands oil rig platforms in sea, etc., also pose difficulty for AC power transmission and DC mode is preferred. For such cases, DC local grids and multilevel DC systems have been developed. Typical multilevel and multiterminal DC systems are shown in Figs. 10.5 and 10.6. A multilevel DC network can be used to transport electrical energy from the transmission system to the drives. At the final load end, an AC voltage of controllable frequency and magnitude is obtained through the inverter. The system shown in Fig. 10.6(a) supplies three very large IM drives of 1 to 5 MVA. The induction motor voltage ratings may be typically 13.8 kV, 11 kV and 6.6 kV at 60, 50 and 25 Hz with power 6, 5 and 2 MVA. The DC voltage levels at Bus 1 and 2 are typically 160 kV and 30 kV. Simulation studies indicated that with motors started at 0.2, 3.2 and 5.0 seconds, the largest rated motor

Fig. 10.5

Multilevel DC systems


HVDC Transmission

Fig. 10.6

MTDC grid using VSC technology

(6 MVA) is started first and the lowest rated motor at the end. The output waveforms indicated that voltage dip was of the order of less than 10% and current fluctuation was about 30%. The time taken for the transients to die was 2 to 3 seconds. The DC/AC converter connected to induction motor is a variable frequency inverter operating in the frequency range 25 to 60 Hz with v/f controller and voltage range of 6 to 15 kV, 3-phase AC. The other DC/DC converter uses a DC voltage controller. The power ratings of both the converters is set to be 21 MVA for getting satisfactory operation from the drive. This type of multilevel systems are under study and have not been reported for commercial operation as yet.

10.6.1 Multiterminal Networks for Wind Power and Other Nonconventional Power Sources One of the important features of HVDC-VSC converters is that the polarity does not change when the power flow changes. Instead, the current direction changes. This makes it easy to use the converter in a multiterminal system. Hence, VSC converters can easily be expanded by adding new units. Wind power units and wind farms are often expanded in steps in few years or joined to the adjacent locations or units. In these cases, direct connection of wind power units to AC system is very difficult as either constant voltage or constant frequency maintenance is extremely difficult. Further, interconnection to grid requires at least a short circuit ratio of 10 which is not possible for satisfactory operation. With VSC converters this is not a restriction and short circuit ratio of 3 is acceptable. Wind power generators absorb reactive power. Most wind generators are induction generators that operate at leading p.f. taking magnetisation current from the AC mains. VSC controlled DC systems can supply reactive power to wind generators. Typical multiterminal grid using VSC technology is shown in Fig. 10.6, wherein the units shown inside the circle in Fig. 10.6(c) are wind generators and the units shown outside are the units connected to the AC grid. When wind power generation is absent, power from the grid goes to the area in which wind power feeds the local area, and when sufficient generation is achieved, power from wind generators is fed to the grid.

Multiterminal HVDC Systems


A typical wind farm connected to the AC mains grid is shown in Fig. 10.7. The studies needed at this juncture are (i) Simulation of combined performance of respective power flows and identification of operation limit (ii) Component ratings (iii) Paradigms for operation without STATCOM

Fig. 10.7 Wind farm connected to AC grid through DC VSC

The advantages with VSC controlled converters are (i) (ii) (iii) (iv)

Full control of active and reactive power Sending end and receiving end frequencies are completely decoupled Reduced cable requirements and long distance cable transmission Less transmission cable losses

A typical multiterminal wind power farm is shown in Fig. 10.8. The farm consists of 4 groups of 40 MW wind turbine units. Each unit is a 20 MW variable speed wind turbine driven induction generator. Studies are being done to improve fault-ride utilising capabilities of a wind farm with HVDC links.

Fig. 10.8

Typical multiterminal wind farm with VSC-HVDC system


HVDC Transmission

REFERENCES 1. Padiyar K. R., HVDC Power Transmission, Wiley Eastern Ltd. (New Delhi), 1992. 2. Lescale Victor F., Kewar Abhay et al., Challenges with Multiterminal UHVDC Transmission Power, Conference 2008, IEEE Power India Conference, (New Delhi), October, 2008. 3. Flong W., Reeve J. et al., Application Aspects of Multiterminal DC Power Transmission, IEEE Trans. (power delivery), Vol. 5, No. 4, November, 1990. 4. Reeve J., Multiterminal HVDC Power System, IEEE Trans. PAS, Vol. 99, No. 2, March/April, 1980. 5. Nozari F. et al., Current order co-ordination in multiterminal HVDC systems, IEEE Trans. PAS, Vol. 100, No. 11, November, 1981. 6. Allard Y. et al., Multiterminal Operation Experience of Hydro Quebec, NEPOOL Phase II. 7. HVDC Network, International Colloquium on HVDC and FACTS, (Montreal, Canada), September 18–19, 1995. 8. Weimars Lars, HVDC Light Technology of the Future, ABB Power Systems, (Sweden) Ludwika, Rokuping, 2001. 9. HVDC Light, Sea Breeze Olympic Converters LP, Internet free downloads, 2009. 10. Livani Hanif et al., Improvement of fault-ride through capabilities of wind farm using VSC–HVDC, European Journal of Scientific Research, Vol. 28, No. 3, 2009.

QUESTIONS 1. 2. 3. 4. 5. 6. 7.

Why are multiterminal DC systems needed? What are the different types of MTDC systems used? What are the different aspects to be considered for a parallel operation of converters? Explain. With respect to a 3- or 4-terminal MTDC, explain converter operation and control. How is (a) paralleling, (b) deparalleling and (c) control of power done in MTDC systems? How is current order control done in MTDC systems? How is power sharing and power control achieved in an MTDC system? Explain how a VSC multiterminal system is more useful for interconnection of nonconventional power systems like wind power, remote hydel stations of small power, etc. 8. What is a multilevel VSC DC system? Discuss with respect to smaller level systems giving examples.

MULTIPLE CHOICE QUESTIONS 1. Multiterminal systems are (a) series connected (b) parallel connected (c) ring connected (d) all of the above 2. Most of the MTDC systems that are in operation and feasible are (a) series connected (b) parallel connected (c) ring connected (d) all of the above 3. Multiterminal systems are controlled through (a) voltage control (b) current order control (c) firing angle control (d) all of the above

Multiterminal HVDC Systems

4. Normal time of operation for paralleling or disconnection of a converter or pole is (a) 0.3 s (b) 3 s (c) less than 20 ms (d) 1 minute 5. For paralleling a converter to the pole, the converter is started in (a) current control mode (b) a control mode (c) g control (d) power control mode 6. Under steady state operation, voltage control is done by (a) rectifier (b) inverter (c) both rectifier and inverter (d) either rectifier or inverter 7. Basic control philosophy in MTDC systems is (a) Total rectifier current is constant (b) Total inverter current is constant (c) Total current, both rectifier and inverter = 0 (d) None of the above 8. VSC DC systems are best suited for (a) point-to-point interconnection (b) large power interconnection (c) interconnection of low short circuit ratio AC systems (d) interconnection of remote unconventional systems and also long distance cable transmission

ANSWERS 1. (d)

2. (b)

3. (c)

4. (a)

5. (a)

6. (b)

7. (c)

8. (d)


Parallel AC and DC Systems 11.1 INTRODUCTION In Chapter 1, the advantages and economics of DC transmission have been discussed. Due to easy voltage transformation from one level to the other, AC systems have taken over DC systems. Since a rotating armature is required in DC generators, large size DC generators (more than 5 MW) at high voltages are not possible. Hence, generation and voltage transformation to a higher level for transformation of power is done through AC only. When bulk energy transfer over a long distance (>500 km) or through cables (>100 km) is required, and in special situations like connecting a wind farm generation, oil platforms or rigs, etc., DC transmission alterative is used. In case of DC transmission, power equipment costing twice the power being handled (the ‘rectifier’ and ‘inverter’ for that rating) is needed at its cost and economics, against the conversional AC transmission is to be worked out for every project. Further, the energy losses that occur in the converter stations are also a major consideration. HVDC transmission is used for dual purposes in a system network when (i) Bulk power or energy transfer is needed and that too over long distances (ii) Systems interconnection for improvement of stability and flexible transmission or power modulation, i.e. controlling both active power and reactive power independently.

11.2 POWER TRANSFER CAPABILITIES In AC systems, if Vs, VR are the sending end and receiving end voltages of a transmission line, X the line reactance and d the phase angle difference between the two, the power transmitted is given by P=

VSVR sin d X


As the line length increases, X increases limiting the power that can be transferred. Further line X absorbs reactive power and this has to be compensated either from the generators or through VAR compensators.

Parallel AC and DC Systems


If cable transmission is necessary, as in case of undersea cables to islands, oil platforms, etc., the cable charging current will be quite high (about 5 to 10 times that of overhead lines), and inductive reactance is to be introduced at every 25 to 30 km of cable length. AC transmission uses 3-phase system and requires 3 conductors. Hence, the tower size and right-of-way required is much higher. For a given transfer of power, losses also will be higher. A few other considerations for an alternative option for power transmission are (i) Operational reliability, flexibility and performance during disturbances (ii) Maximum loading capacity, continuous and short time overloads (iii) Transmission system development and possibility of upgradation and extension in future In case of DC power transmission, the receiving end voltage must always be less than sending end and the power transfer does not depend on the line resistance. The power at sending end is given by PS = VdRIR and at receiving end PR = VdiIR


where VdR and Vdi are respective sending end and receiving end voltages and IR is the load current. Usually the receiving end voltage is kept constant and sending end voltage VdR which is a function of firing angle a is varied to alter the power transmitted. Further, there is no reactive power requirement on the DC side. But converters consume reactive power proportional to sin a, a being the firing angle. With current source converters, i.e. thyristor bridges, the converter usually requires about 50 to 80% of the total DC power transmitted as reactive power. On the other hand if voltage source converter with GTOS or IGBT valves is used, no additional reactive power from the AC side or grid is needed and the converter itself can generate its own required reactive power (Ref. Chapter 1.2).

11.3 RELIABILITY CONDITIONS When an alternative to 3-phase AC power transmission is contemplated, it is essential that a reliability study is made between the AC and DC systems. In a case if fault like L-G or L-L occurs, and the line is out in entire AC system or line cannot transfer power, usually power is fed via another route or line. In case of a double circuit line, the 2nd line which is healthy may transmit 50% power. The reliability of a 2-pole bipolar line is often better for an L-G fault, ground return with normal pole can be used to transmit 50% power or a little overloading also. However, in case of a lower fault, both AC and DC systems are dead. The usual reliability studies include probability of a fault occurrence in the two systems and their associated transmission loss. Some studies made in the 1990s indicate that DC transmission alternative is unfavourable, but compares well and can be favourable if sufficient spares like a spare converter transformer, reactor, etc., are available (Ref. Chapter 1.5).

11.4 POWER LOSS CONSIDERATIONS AND OTHER TECHNICAL ASPECTS In AC transmission systems, power losses in transmission lines will be (a) conductor power losses (I2R), (b) dielectric losses (in cable transmission) and (c) power loss in conductor due to skin effect. In DC systems,


HVDC Transmission

only I 2R loss will be present. Hence, for a given power level, power transmission through cables is more compact, safe, invisible, and distance effect is absent or much reduced; and requires less maintenance and is environmental friendly (Ref. Section 11.5). With AC transmission through cables the losses encountered are (i) (ii) (iii) (iv) (v) (vi)

Ohmic losses in conducter Induced losses (skin effect) Sheath current losses Dielectric losses in insulation medium Induced losses in nearby cables Large charging current due to longer lengths

In DC cables, only ohmic losses exist and all other losses mentioned above are absent. As such DC cables are designed for higher dielectric stress and hence, are less in size (dia) as compared to AC cables of same voltage level. Figure11.1 gives the working stress for AC and DC cables. In DC transmission system, the additional losses that occur are (i) increased power losses in converter transformer, and (ii) power losses in converter values and converter plant including additional filter units. But these are compensated by the reduction in line losses over long distances. For cable transmission, transmission line length is not a constraint and in Sweden DC cables are used and exist for nearly 1500 km route length. In Table 11.1, a comparison of transmission system along with its power transfer capabilities is shown. Table 11.1

Fig. 11.1

Working stress for AC and DC cables

Comparison of transmission systems Voltage level kV


HVDC other type cables

Overhead line

220/250 kV

200 to 500 MVA

100–300 MW

300–500 MVA

400 kV

400 to 1600 MVA

300–1000 MW (300 kV)

500–2000 MVA

Width of effected land

1 to 2 m

0.5 to 1 m

40 to 60 m

MVA/m (220–400 kV systems)

200–500 MVA/m

200–1000 MVA/m

7.5 to 30 MVA/m

In Table 11.2, a comparison of power losses in AC and upgraded and converted to DC systems is shown as a function of current density in the conductor. Substantial power upgradation of existing AC lines to DC lines using same conductors, towers and tower bodies with a little change in tower head and insulator assemblies, if necessary can be done.

Parallel AC and DC Systems

Table 11.2


Comparison of losses in AC and converted DC systems (132 kV double circuit line converted into bipolar DC Line 0.7A/mm2

Conductor Current Density S Voltage

Power (MW)

132 kV AC Converted 250 kV (264 kV) DC

1.0 A/mm2

% Losses J/100 km

Power (MW)






% Losses J/100 km

Power (MW)

% Losses J/100 km









Various issues and aspects to be considered for DC transmission are (i) (ii) (iii) (iv) (v) (vi) (vii) (viii)

Capital cost of the station including land and installation Capital cost of land of overhead/cable route Cost of consultants, legal aspects, etc. Cost of delays in execution Power losses and impacts on existing networks Reliability and availability Maintenance and operation Auxiliary service benefits and losses

The technical issues regarding AC line enhancement are (i) Increasing network capability by addition of parallel HVDC link (ii) Conversion of existing AC lines into DC lines, usually power limit is thermal capability limit (a) Full and fast control of power (b) Power oscillation and creeping capability increased (c) DC does not contribute to short circuit level (d) AC voltage control is smooth with voltage source converters Some of the above aspects and issues are discussed in the following sections of this chapter.

11.5 ENVIRONMENTAL CHARACTERISTICS CONSIDERATIONS FOR DC TRANSMISSION There are several possible influences on the environment caused by EHV and UHV transmission systems, mostly as overhead lines are routed through forest area, deserts and similar areas and away from the cities and busy areas. Underground cables may be routed along road sides, highways, etc., for easy access for maintenance and location. Both overhead lines as well as cables give rise to certain adverse effects which include (i) (ii) (iii) (iv) (v)

The effects of high electric fields The effects of magnetic fields Radio and TV interference Audible noise due to corona and other factors Ground currents and corrosion effects


HVDC Transmission

(vi) Land acquisition for transmission lines and substations (vii) Visual and ecological effects and impacts

11.5.1 Electric Fields Effects High voltage overhead lines create high electric fields underneath them as well as in their neighbourhoods. The electric fields produced are due to (a) electrostatic field due to lines, (b) space charge fields, and (c) charge produced by the line corona. The presence of charge between the line conductor and ground influences the total static field produced by the line. It was pointed out in investigations done by HVDC Power Transmission Research Institute at St. Petersberg, Russia that under HVDC lines, a person does not feel discomfort, contrary to the discomfort experienced under EHVAC power lines. The typical discomfort experienced is due to spark discharges from humans to bushes, grass, and other such vegetation. The discharges are quite infrequent unlike those caused by EHVAC lines which can be 100 per second at 50 Hz frequency. The investigations with typical experimental ±1000 kV DC lines and 1150 kV AC lines indicated that ionic current in DC lines is much less and was of the order of 1% compared to AC line capacitive currents (about 2 to 3 mA for HVDC line and about 0.2 mA for HVAC line). Experimental studies in Canada indicated that ionic current densities are around 120 nA/m2 with DC fields of 50 kV/m. Further, under high humidity condition and rain ion concentration in air can increase up to 105 to 106/cm3 and is detrimental to health. But this does not have any adverse effects as nobody will be under charged lines during rain conditions. All the extensive experimental results suggested that electric fields below and around HVDC transmission lines are not hazardous as to necessitate safety measures. The following table (Table 11.3) prescribes the limits to time of exposure to DC fields for the safety of personnel working under DC lines. Table 11.3

Safe exposure time to DC fields DC field conditions E

£ 15 kV/m, J


15 to 20 kV/m, J

E Em

Time of exposure (Max. in hrs) 8


20 nA/m


25 nA/m2

20 to 60 kV/m, J > 25 nA/m2 60 kV/m

Em > 60 kV/m

Em2 ( E + b )2

, b=

0.25 KV/m , (nA)

1 not recommended

Underground cables are usually shielded cables and electric fields are confined only to the inside of the cable.

11.5.2 Magnetic Field Effects The environmental impact of transmission line magnetic fields on human beings is much less. Earth’s magnetic field is 30 to 60 mT at different parts and heights in the world. The magnetic field produced by either DC cables in the neighbourhood (>2 m) or under the overhead lines below them is 5 to 10 mT and is much less than the earth’s magnetic field. Usually, the earth’s magnetic field is superimposed over the DC cable or the

Parallel AC and DC Systems


line field. Hence, the magnetic fields associated with DC lines produce no perceivable effects. Hence, there are practically no guidelines relating to DC lines in relation to magnetic fields.

11.5.3 Radio and TV Interference The radio and TV interference is mainly due to corona discharges around the line conductors. Normally only positive corona occurs with DC lines, i.e. on positive pole conductor only. Whereas in AC lines, corona occurs on all the three conductors. Under rainy conditions, with AC lines the radio interference increases, with DC lines RI levels decrease. As such, surface voltage gradients of up to 25 kV/cm is acceptable with DC lines, whereas the limit is only 15 kV/cm with AC lines. It has been established that RI level of HVDC lines is typically lower by 6 to 8 dB than that of HVAC lines.

11.5.4 Audible Noise This is a serious factor in the design of substations and overhead lines. In substations, the main source of noise is converter transformer and a solution is to adequately surround the transformer with screens. Noise form DC transmission lines is a broadband noise and is most prevalent in fair weather. As a rule, the audible noise from lines should exceed 50 dB during day and 40 dB during night in residential areas.

11.5.5 Ground Currents and Corrosion Effects In order to utilise the capability of HVDC transmission for power transfer through one pole, ground return circuit is provided. Several possible, designs are used for ground return current which have been discussed in Chapter 7. For cable monopole system, current return is performed through ground. In several cases a special additional conductor is used, which normally serves as ground wire for lightning. In all these cases, the conductor has a thermal limit greater than the current it has to carry. In Fig. 11.2 typical ground return cases are illustrated. The current path between grounding installations of HVDC converter stations lies through the whole global space and the environmental impact on the surface is limited to only a moderate area near the grounding installation. On the other hand, if there is any conductor, like a pipe line, etc., the current return occurs through such a conductor. This latter path of current return poses a danger to buried metal infrastructure (like footings of towers pipe lines) by way of electro-corrosion. The damage depends on the quantity of charge, i.e. Ah (Ampere hours) which is the integral of current passing through it (Ref. Fig. 11.3). Most HVDC lines are bipolar. Such lines or systems are operated as monopolar lines usually for a very small duration or transitory purposes and some operation as monopolar system cannot be avoided. Also because of asymmetry in the system even in bipolar operation some nominal amount of current, about 2 to 3% of rated value will exist in the ground. Usually ground electrodes are situated 1 to 2 km away from the main converter stations and are designed to exclude all possibilities of corrosion of substation underground components, nearby piping, structural foundations, etc. Electrodes are also made with special materials and are highly corrosion resistant. Both anodic and cathodic protection is given to resist corrosion. But with all due measures taken, it is still recommended that additional cathodic protection to objects such as water piping be given to prevent rapid corrosion.


HVDC Transmission

Fig. 11.2

Basic variants of return current circuit organisation for monopole operation (a) Via permanent grounding installation (b) With emergency pole’s conductor usage (c) With lightning rope or special conductor usage (d) Quadrapolar transmission line overloading possibility

Fig. 11.3 Current return via grounding installations

Parallel AC and DC Systems


11.5.6 Land Usage and Ecological Changes due to Transmission Lines and Substations Land requirements for converter stations (EHV and UHV) are quite large. Further, the transmission lines through country side, forest and desert places as well as near urban areas require a corridor of width 40 to 60 m. Grounding installations also require considerable area. Compared to EHVAC substations, the additional land requirement is for converter units and filter banks, which is not too large. However, the total area required for towers and the right-of-way is quite less for DC lines. The area of land use, as a major ecological index of transmission system, depends on system reliability requirements. Further, the land requirements depend on type of converters like monopole, bipole, quadrapole, the number units (valves) in series or in parallel, whether all of these are located in the same place or elsewhere, etc., decides the land per MW (or for 100 MW). It is reported that a ±500 kV, 2000 MW bipolar transmission system requires about 90 3 103 m2 area for a substation and converter units and almost the same area (90 to 100 3 103 m2) per km of line length. But compared to a UHVAC system (with 525 kV, 3f AC) this land requirement for same power transmission is about 65 to 70% only. But definitely land requirements will not be more than 90% of AC system.

11.5.7 Visual Effects and Impact of Landscape Nowadays, with increased population and growing cities and towns, there is a general dislike amid public regarding transmission lines going around or crossing populated areas, national parks, resorts, places of historical importance, world heritage sites, etc. Conservation of natural landscape is being prioritised. Hence, certain demands and restrictions are put forth for line dimensions. Further, forest conservation laws may not allow power lines to pass through them. Special demands are also placed on aesthetics of design of lines and towers. In such cases, an alternative is to go for underground cables, but this increases the cost of transmission lines substantially. HVDC systems in such cases are the best solution. DC overhead lines offer several advantages from the point of visual impact as compared to AC lines. Bipolar DC lines have only two conductors and require much shorter heights in comparison to AC lines for the same power and voltage levels. The tower design is quite simple with only one or two cross arms. Typical towers for a ±500 kV system with two circuits per pole are shown in Fig. 11.4 (±500 kV quadrapolar HVDC towers). Sometimes part of the

Fig. 11.4

Schematic of two variants for construction of ±500 kV quadrapolar HVDC transmission line towers, with one (flat tower) or two cross arms


HVDC Transmission

line may be overhead line with cables and is used where landscaping and ecology is to be maintained. No capacitive compensation is needed in a DC system as against an AC system. In all the cases, structurally simple HVDC lines or cables offer definite advantages for HVDC.

11.5.8 Health Effects Unlike AC transmission, DC transmission systems do not produce low frequency magnetic fields and the field strength is much less than the earth’s magnetic field (Ref. Sec. 11.5.2). Therefore, there are no health hazards and no adverse reports have been reported. The impact of particulate condensation and negative corona generate more ozone. Usually generation of ozone is further at the down-wind side of power lines. This may lead to creation of potential health problems. Not much information is available in this respect. But negative corona is very rare and usually corona is seen in positive pole of the bipolar lines, which reduces the ozone formation and ozone impacts. Overhead lines routed through thick jungles and green belts give rise to loss of trees. As such CO2 intake and conversion of CO2 to oxygen by trees is highly affected and the estimated loss is about 42 tons/km length as converted O2 and deposits in trees as stored carbon in woods. This results in increased CO2 levels and decreased O2 levels in the atmosphere which can result in health problems as well. Further, studies on a group of about 40 personnel working under 400 kV AC lines under a field 4 kV/m and less than 6 mT showed that there is no variation in heart rate, blood pressure and other cardiac parameters. Comparatively, in DC fields it is still less. Hence, no health effects were found or observed. To conclude, combination of several specific physical characteristics and technical aspects related to lines and substations, their design, construction, operation and maintenance, HVDC offers definite advantages. Environmental effects are much less and DC systems are also more economical (lower cost by 30% or more) for long distance and high power ( 500 MW) transmission.

11.6 POWER UPGRADING AND CONVERSION OF AC LINES (SYSTEMS) INTO DC LINES Due to the problems associated with construction of new overhead lines, nowadays it has become important to examine the possible option of increasing the capacity of power lines and substations and making maximum possible usage of the existing ones. Wherever possible, upgrading is an attractive alternative as the costs become less and much time is saved rather than going for a new line or substation. Different constraints limit the power transmission capacity of the system. These are (i) (ii) (iii) (iv)

Switchgear characteristics and capacities Environmental effects Voltage regulation and power losses System stability

When an AC line is to be upgraded to handle higher transfer of power, the following are the constraints with the voltage increased: (i) loading capacity, (ii) thermal conditions, (iii) minimum safe conditions and insulator requirements, (iv) system short circuit limits, and (v) power angle and phase angle displacements. Reactive power compensation is to be met with suitable compensators. An easy and better solution in many cases is to go for conversion of AC line system into a DC line or link.

Parallel AC and DC Systems


In case of long overhead lines, the problem lies with line inductance and short capacitance. In order to balance the line reactive power needed, i.e. QL = wLI 2 and Qc = wCV 2; the surge impedance loading, i.e. for QL = QC = Zs is given as ¸ L Ô C ˝ 2 Pc = VI = V / Z s Ô˛

V /I =


Hence, the power carried by an AC line for different operating system voltages are given in Chapter 1, Table 1.8. If the loading on the line goes above PC, reactive power compensation has to be given. Since no such limit exists and no reactive power is needed in case of DC lines, HVDC lines have the following advantages, viz. (i) (ii) (iii) (iv) (v) (vi)

Greater power per conductor Less number of conductors and simple line construction Operation of each conductor/pole independently No charging current, skin effect, no reactive power for lines, less corona, and RIV Nonsynchronous operation and no distance limitations Low short circuit current and this does not contribute to short circuit current of AC system.

Some disadvantages are high converter cost, reactive power is needed for converter operation, requirement of harmonic filters and multiterminal operation is difficult.

11.6.1 Conversion of AC Lines to DC Lines In Chapter 1 (Ref. 1.3.3 b to d), it has been shown that when a 3-phase double circuit AC line is converted into DC with same tower and insulator configuration, power transmitted can be doubled (Eq. 1.18). By defining a few factors (Ks) as K1 =

DC with stand voltage for continuation of line insulation RMS AC with stand voltage

K2 =

AC insulation level Rated AC voltage of line (peak value V p )

K3 =

DC insulation level Rated DC voltage of line (Vd )

with same or equal current in both AC and DC line operation. Vd =

K 1 K2 V K3 p


and power ratio PDC K1 K 2 = PAC K3



HVDC Transmission

Usually K2 = 2.5 and K3 = 1.7 and K1 = 2 the power ratio becomes 2 as stated earlier. When line conversion or upgradation of power lines is taken up, the following parameters should be considered. (i) Temperature: Highest temperature that occurred or is likely to occur along the line Wind Speed: Lowest wind speed to be taken and the angle between conductor and wind flow Altitude: Height over the sea level Solar Radiation: A factor that determines the thermal loading of conductors as the same are heated by sun radiation Snowfall and Snow Reflection: Sometimes this may cause high value of solar radiation (ii) Conductor Parameters: Type of conductor already used like ACSR, ACSS, ZT ACIR (Zirconium alloy of aluminium), GT ACSR (Gap type heat resistant), CRAC (Composite reinforced aluminium), etc. Preload and time for short duration maximum currents, continuous maximum current, etc. (iii) Statistical and Pollution Performance: The pollution performance of line insulation for different types of duration is to be carefully assessed. The lightning characteristics shielding failure, back flashovers lightning current distribution and their amplitudes should be considered as they are different for AC and DC insulation. The shielding failure rate is calculated for DC lines based on electro-geometrical models. Outages on DC lines are generally due to monopolar ground faults caused by either insulator flashovers due to lightning, pollution, etc. This may cause an overvoltage on healthy pole and a certain risk exits for bipolar fault. Switching surge overvoltage profile has to be calculated along the line. To conclude, when conversion of an AC to a DC line is done, the parameters that decide the ultimate capacity of DC line as (i) weather conditions, (ii) conductor parameters, (iii) pollution performance, and (iv) the line insulation that decide the voltage of operation and maximum power that can be transmitted with least possible cost and modifications. This is illustrated in the following example: Example 1: Conversion of a 220 kV, 200 MVA double circuit 3-phase line into bipolar ±200 kV, 400 MW HVDC line. The 220 kV double circuit line has 14 standard insulator (10 discs) string and uses conductor of a current carrying capacity of 450 A. Tower is 35 m in height, spacing between cross arms is 7 m, the details of which are shown in Fig. 11.5. Average span is 270 m. Current per circuit in AC I =

100 ¥ 103 ª 280 A 3 ¥ 220

Maximum voltage-to-ground =

220 2 ª 180 kV 3

Fig. 11.5

220 kV double circuit tower

Parallel AC and DC Systems


Total creepage distance: 5.5 to 5.8 m Lightning impulse flashover voltage < 1050 kV Switching impulse flashover voltage: 850 kV The insulator string can withstand ±450 kV DC Hence, the line can be converted into ±220 kV allowing a factor of 2.2 line for a maximum power rating of 400 MW with 3 conductors bundled together. Current in each conductor is

400 ¥ 103 = 333A (< the current carrying capacity). (200 ¥ 2) ¥ 3

Taking 30 mm/kV creepage length in DC with average pollution. Creepage distance required for 200 kV is (200 3 30 mm) = 6000 mm = 6 m. Hence, the insulator string is sufficient otherwise one more insulator may be added. Power loss per km in the line (AC) is 2 3 2802 3 0.35 = 54.88 kW per phase or total 164 kW (AC resistance at 50°C is 0.35 W/km) Power loss in DC (DC resistance 0.24 W at 50°C) is 6¥

1000 ¥ 0.24 = 144 kW 3

Taking the line to be about 200 km. % power loss in AC

200 ¥ 164 ¥ 10 - 3 ¥ 100 = 1.64% (200)MVA

% power loss in DC

200 ¥ 144 ¥ 10 - 3 ¥ 100 = 0.7% 400

(By conversion of the line doubles the amount of power is transmitted with loss reduced to less than 50%). Other losses are not considered here. The example taken is similar to the lower Sileru (A.P.)–Barsoor Line (M.P.) (220 kV, 200 MVA DC line 196 km), one circuit of which is converted into +200 kV monopolar line with 200 MW capacity and metallic return. The conversion costed about Rs 100 crore in 1989. In future it will be converted into a ±200 kV bipolar line.

11.7 DC AND AC SYSTEM INTERACTION All HVDC systems form a part of large size AC systems and act as nonsynchronous tie between different sections. This DC part has quite a complex interaction with the main AC system. Some of the effects can be studied using the short circuit ratio of the system. The effects and interactions are basically


HVDC Transmission

(i) (ii) (iii) (iv) (v)

The value of short circuit ratio and its influence on AC system Disturbance in AC system due to variation of control angles in inverter/rectifier Maximum power availability and AC terminal voltage variations Converter transformer saturation due to harmonics produced and their consequential effects Effects on source generators and vibrations produced in electro-mechanical system (turbine-generator units) (vi) HVDC and facts devices used in AC system

11.7.1 Short Circuit Ratio (SCR) and Its Effects Short circuit ratio of AC system is defined as SCR =

Short circuit level of AC system (MVA) DC power Pd (MW)

The short circuit level of a AC system is 2 /Z SCL = VAC AC

where VAC = AC system voltage and ZAC = Short circuit impedance ZAC includes the series reactance of the source, the shunt reactances of lines, any capacitors used for reactive power compensation, Zl = Load impedance, etc. Short circuit ratio (SCR) can be expressed in terms of AC, SCL and DC power as SCR =

2 2 VAC VAC Z Z = ◊ base = base Pd ◊ Z AC Pd ◊ Z base Z AC Z AC


2 VAC V2 will be equal to one as maximum Pd will be equal to AC . Pd ◊ Z base Z base SCR is a complex number as it includes reactance of the AC system as well as the resistance. ZAC varies with frequency. AC systems are classified as

where Zbase is base impedance of AC and

(i) Weak system if SCR £ 3 (ii) Strong system if SCR > 5 In weak systems, the dynamic overvoltage that occurs (voltage rises) will be very high if SCR is less than 3 and will need special alteration to reduce these overvoltages. Typical transient overvoltage that occur can be as high as 1.4 p.u. or more with very weak AC system as shown in Fig. 11.6. Usually the disturbances like sudden load changes, temporary faults, misfire of valves, etc., which last for 150 to 300 ms will cause the above overvoltages. This necessitates the modification or rearrangement of system components so that resonances at system frequency and its harmonics (particularly 3rd and 5th) is avoided and sufficient dumping is provided. Sometimes effective SCR (ESCR) is more frequently referred, given by

Parallel AC and DC Systems


SCL - Qc Z base = Pd Ze

329 (11.7)

is used to describe the system.

Fig. 11.6

Overvoltages of the AC system due to the phase and magnitude of the SCR

2 Y Y Qc is the equivalent compensations loading given VAC ( =

1 1 + ; Z = the effective impendance for Z f Zc f

the frequency under reference and Zc the converter impedance). With this effective SCR, the overvoltages that can appear can be as high as 2.0 at the AC load for the minimum g at the inverter end.

Maximum Power Curves and AC Terminal Voltage Effects In current source converter schemes with SCR firing angle control, DC power variation is by means of control angle. For given gmin at the inverter end, the maximum DC power transfer depends on Id and without any AC side voltage control, within the control duration of about 300 ms the power entirely depends on the current Id. A similar situation prevails for the amin at the rectifier end. Now, maximum power available is reduced as the Id is increased beyond its set level, unless the reactive power consumed is compensated or AC side voltage is increased at the inverter end. The maximum power available is a function of commuting reactance Xc, gmin, and the shunt capacitor compensation at the converter station. For high SCR systems, an HVDC link does not pose any problem, whereas with system SCR less than 3, the temporary voltage rises with a load rejection (Id = 0) and gives rise to high overvoltages and hence requires additional control features. The rise of voltage on AC side is illustrated in Fig. 11.7. The solid line curves represent the DC maximum power curves for constant g and the dotted curves represent the corresponding AC voltage at the inverter end as a function of SCR. The lower the SCR value, higher will be the AC voltage as the DC load current is reduced or load is rejected (Id = 0). Hence, when lower SCR systems are to operate satisfactorily without causing high transient or temporary overvoltages at the inverter end, suitable synchronous compensators are to be designed and located. This can be done by (i) fast acting static var compensators or STATCOM (Ref. Section. 11.9.3) or by variable g operation and suitable tap-changing employed with inverter transformer to keep the overvoltage within a permissible limit (1.05 to 1.10 p.u.).


HVDC Transmission

Fig. 11.7

Variations of inverter AC voltage and DC power with DC current

11.7.2 Converter Transformer Core Saturation and Resonance Phenomenon AC and DC transmission systems have capacitances and inductance elements that can form resonant circuits producing large overvoltages. Usually the resonant frequencies are high enough and do not cause problem. But with converter transformers, subjected to nonsinusoidal voltages, converter transformer core saturation occurs and presents variable inductance. Sometimes harmonics generated at sending end AC system are transferred to receiving end AC system via a DC link. This is known as cross modulation and gives rise to very complex interactions. A small amount of 2nd harmonic voltage distortion exists on the AC side of the converter, the fundamental voltage distortion appears on the DC side. This will result in flow of DC current on the AC side of the transformer which will saturate the core. As the core saturates, the magnetising reactance of the transformer becomes variable which along with filter capacitors and other capacitances gives rise to resonance and high voltages. The resources can lead to high voltage and current stresses on equipment and sometimes cause instability in the system. The amount of damping (resistance component in the resonant circuits) decides the harmonic current in resultant waveforms. In case a fault occurs in the system, the resultant zero sequence currents in fault path depend on X0/X1 and R0/R1 (X0, R0 zero sequence components and X1, R1 positive sequence components). With converter transformer of Y/D connection and parallel AC filters, the resonant frequencies will be usually in the range of 2nd to 3rd harmonic frequencies and resonant frequency in zero sequence system Mˆ Ê SCL fr ª Á + Qc Ë Z 0 / Z1 X t ˜¯ SCL : Short circuit level of AC system Z0, Z1 : Zero and positive sequence impendances of AC network


Parallel AC and DC Systems


M : Converter Tr. MVA rating Xt : Converter Tr. leakage reactance Qc : Total capacitive shunt compensation Resonant frequency, if close to 2nd or 3rd harmonic frequency, high overvoltage will result in a line-to-ground fault and its fault clearing sequence.

Ferro-Resonance Phenomenon The equivalent (simplified) circuit for ferro-resonance of converter transformer is shown in Fig. 11.8, wherein the magnetising reactance along with core losses equivalent resistance are shown as variable L along with R. The source voltage (AC) is shown as es and c is the capacitance of AC bus, grading rings, etc. The resonant frequency and overvoltage produced VL depends on the values of L and C. C can be the capacitance of circuit breakers (open) corrected between the main bus and transformer bus. It was reported that the overvoltage produced caused damages to station potential transformers. The location of series capacitors, filters, etc., that inject capacitive Q (RKVA) into the system are shown in Fig. 11.8(b).

Fig. 11.8(a)

Equivalent model for simulating ferroresonance of a transformer

11.7.3 HVDC Systems and Synchronous Generators In many HVDC systems and links, sources or AC generators are connected to HVDC links that run over several kilometres in length. Since most of the high power systems are thyristor controlled current source converters (CSC), a few adverse interactions have Fig. 11.8(b) Locating a series capacitor between the been reported in some literature. One of the important AC system and the DC inverter where QAC, reactions is the low frequency subsynchronous QDC and QF are the reactive powers torsional vibrations involving turbine-generator rotors at lower frequencies (10 to 50 Hz). This was reported in 1977 during the commissioning of Square Butte HVDC scheme in USA. This phenomenon is mainly related to the DC current regulation which was maintained constant irrespective of the network voltage or power flow. Usually mechanical resonant frequencies, i.e. shaft natural oscillations are in the range 5 Hz to 30 Hz or more and this is in the subharmonic frequency range of 50 or 60 Hz. The turbine-generator unit is schematically shown in Fig. 11.9 and the rotor is slightly perturbed corresponding to the synchronous speed of f0. The increase in speed changes generated voltage V, which in turn changes HVDC commuting bus voltage. The AC voltage component contains frequencies of f0 ± ft, where ft is the vibration frequency. With constant current mode operation current component corresponding to ft appears as an error and the feedback loop changes a, the firing angle; and hence AC current at that frequency.


HVDC Transmission

Fig. 11.9

Turbine-generator rotor torsional interaction with DC system current control

This tries to affect the generator current and hence the electric torque. If the change in torque is opposite to that of mechanical torque, damping occurs and the vibrations are subsided. But if the torque is in the same direction, vibrations increase because of negative damping effect. The increase in speed vibrations cause torsional stresses and fatigue in the shaft. This must be subsided using proper control mechanism. In a similar manner harmonics (2nd and 3rd) are also produced in the rotors due to the harmonic currents present in the stator currents, which may induce negative phase sequence harmonic currents in the generator grids leading to unnecessary heating. Some of the adverse effects that result are (i) Vibrations are produced in both steam turbine and hydro-turbine units by harmonics in air gap torques of the generators. Harmonic torques which may have the same resonant frequencies as that of mechanical system can result in large vibrations. (ii) Excitation systems can also misoperate due to harmonics. The self-excitation systems using controlled rectifiers are sensitive to these and the feedback and sensing systems are highly effected. The same effect is also felt in the relay and protective systems using static relays which are sensitive to harmonic currents. Suitable filters may have to be inserted to eliminate harmonic currents.

Self-excitation Systems Salient pole generators with self-excitation systems go into self-excitation in d or direct axis when xc < xd and quadrature axis self-excitation when xc < xq, where xc is the capacitive reactance seen from generator terminals. xd and xq are direct and quadrature axes reactances. Self-excitation comes in when field flux changes and becomes negative. If td and tq are the time constants in the two axes and td 0 and tq0 the steady state time constants td = td0

X c - X d¢ Xc - Xd

and t q = t q 0

X c - X q¢ Xc - Xq


where (‘9’) quantities are the transient reactances. When sudden change in the field flux occurs, these time constants can become negative. Typical self-excitation system of a salient pole generator using self-excitation is shown in Fig. 11.10. The system comprises a six-pulse converter feeding the field system from its own terminal voltage. The terminal voltage developed, change in field current, change in speed (frequency) and field voltage developed during a sudden load switch off is shown in Fig. 11.10(b).

Parallel AC and DC Systems

Fig. 11.10


Self-excitation of a generator at 100% load rejection

To conclude, there are several other interactions like electromagnetic transients induced, small signal control oscillations, subsynchronous resonances developed, etc., for which the reader can refer to titles 12 and 13 given in references.

11.8 PARALLEL AC/DC SYSTEMS In many power transmission systems, an HVDC line with converters is used in parallel with an AC transmission line. In such cases, a flexibility in power transfer exists and reactive power can also be controlled. Figure 11.11 gives a simple parallel AC/DC system operation.


HVDC Transmission

From Eq. (11.1), the AC power transmitted is given by PAC =

VS VL sin d XL


and the total power to the load is PL = PDC + PAC = PDC +

VS VL sin d XL


Fig. 11.11

In terms of Ic and VL, the power through DC line and the reactive power needed for converter is PDC = VL IC sin d QDC = VL IC cos d If the reactive power at receiving end, i.e. load QL is to be zero, cos d =



Substituting for cos d in Eq. (11.11) VL (VS + I C X L ) 2 - VL2 XL


VL (VS + I C X L ) dPL = dI c [(VS + I C X L ) r - VLr ]1/ 2


PL = and

With voltage source converters (VSC) or HVDC VSC schemes, it is possible to control the loadability of the line as well as QL. Allowing about 10% voltage drop, i.e. making Vs =1.0 p.u. and VL = 0.9 p.u, power transfer capability increases by 50%. The power transfer circle (P V) diagrams of a typical DC line is shown in Fig. 11.12(b). The maximum loadability increases as the load voltage increases. The different operating modes are shown in the figure. Mixed control, i.e. both P and Q control the maximum loading of the line can be increased to 1.0 p.u. or a little more. In case of rotor angle oscillations, they can be suppressed with active power variation and hence can improve voltage stability. An analysis on a model line with the above controls showed that without a parallel DC line, the line loading is 89% and with parallel DC line 1.011, showing an increase of 11%. When VSC controlled HVDC is connected as shown in Fig. 11.11, it is usually aimed to transfer as much active power as possible over the parallel combination without causing a high voltage drop. But active power transfer will restrict the amount of reactive power that can be injected into the bus. For this purpose the sending end and receiving end power circles are shown in Fig. 11.13. The maximum current through the DC line Ib and hence loadabillity is given by the equations P = VdIb sin d

and Q = ±VdIb cos d

Parallel AC and DC Systems

Fig. 11.12(a)


PV curves for di erent control modes

Fig. 11.13 Sending end and receiving end power circle diagrams ‘B’—Capacitive susceptance ‘XL’—Line reactance VS, VL—sending and receiving end voltages

Fig. 11.12(b)

Active power flow with parallel DC cable

The sign of the reactive power is chosen so that it is injected into the bus. The maximum DC voltage limit and the operating point for maximum power transferability are optimised to get the best solution but are functions voltage. The best solution is obtained from the circle diagrams (Ref. Fig. 11.13) as follows: (i) (ii) (iii) (iv) (v)

The sending end and receiving end power circles are drawn The power flow through DC line is (short line inside small circle) Pd The solid lines are the power through DC link for highest power factor on converters A low power factor on DC link is more effective to improve P transfer capability of the system Maximum loadability of the line is the optimal solution


HVDC Transmission

(vi) Maximum DC voltage levels further restrict and put constraints. These are checked graphically by introducing limiting arcs.

11.8.1 Voltage Stability and Power Modulation In a hybrid or parallel AC DC transmission system, damping control of power swings by HVDC power is called power modulation. This is used for stabilisation of AC systems. For reliable service, the bulk of the power system must remain intact and capable of withstanding wide varieties of disturbances. It should not result in uncontrolled, widespread and cascaded power interruptions. Normally transmission system operation is that the system does not transfer more power than possible when a failure of a single component, equipment or loss of a single transmission line occurs. A less common method is to change the operation of another component or parameter in the system after failure or loss, to maintain the system stability. VSC schemes that have been developed recently have the advantage of almost instantaneous change of either P (power) or Q (reactive power), so that it is flexible and can meet the demand and requirements. DC transmission devices do not offer damping of AC power system when they are operated in constant power mode. But the power flow settings can be controlled to increase the transient stability. Some of the strategies that can be adopted are (i) power flow in the DC line is modulated based on rotor speeds of the generators at both rectifier and inverter end, (ii) modulation is done based on the phase angle difference between the sending end and receiving end AC voltages of the link, and (iii) modulation is based on the rate at which the power change/power flow between the two control areas at which the HVDC link exists. This first control is based on modulated power. PDC is changed according to the error is e= where

d {w D - w i Di } dt r r


wrDr — rotor speed of generator connected to rectifier end wiDi — rotor speed of generator connected to inverter side

The 2nd control is done using the error signal. e=

d {d Dr - d Di } dt


where dDr and dDi are phase angles of AC voltage at the rectifier and inverter ends. Another control that may d be used is based on e = [ Pi ] , where Pi is the power flow through AC line in interconnected areas. With dt the above schemes tested on a IEEE 24 bus system with HVDC links (2 nos.) showed that the rotor swings which went beyond 100° without control for a 3-phase fault were effectively reduced to within 50° as shown in Fig. 11.14. The damping control studies done on Brazilian Temascal—TCL 400 kV system showed that if HVDC power modulation is used, the oscillations are damped out quickly. The controlled input signal was limited to local rotor speed control and AC line power control. HVDC link addition and its power modulation quickly dampens the oscillations without the control for a fault at substation and loss of 400 kV line resulted in severe post fault voltage swings and loss of synchronisation. With HVDC power modulation control and voltage

Parallel AC and DC Systems

Fig. 11.14

Power flow through the HVDC link with and without control



HVDC Transmission

support, power flow was stabilised within five seconds and voltage was maintained within few cycles. The results are shown in Fig. 11.15.

Fig. 11.15

Comparison of 400 kV bus voltage response with and without HVDC power modulation

The bus voltage response of a typical 400 kV system with and without HVDC power modulation is shown in Fig. 11.15. Simulation studies for a 3-phase bolted short circuit applied at t = 20 ms and cleared after five cycles is shown in Fig. 11.16. The simulated results indicated that co-ordinated HVDC and SVC support allows for a more damped system response. It may be concluded that HVDC power modulation technique will significantly improve the transient stability of the system. But all these techniques have to be listed on a real time actual system for different eventualities and faults before a conclusion is arrived at and its adaptability to the real systems.

11.9 FACTS AND FACT CONVERTERS/HVDC Many generating stations usually are located away from the load centres. Sometimes power is to be transmitted over a long distance (>600 km). Also many a times nonconventional energy conversion systems like wind power, mini-hydroplants, etc., are to be connected to the main supply grids through long transmission lines.

Parallel AC and DC Systems

Fig. 11.16


Comparison of Temascal SVC response with and without HVDC modulation

Further isolated loads like islands, remote forest or hill towns are to be supplied power from the main grid. If such sources or loads are connected to the main supply grid, the cost of electricity will be less. In such cases, existing alternatives are either HVDC-Voltage source converter system or HVAC with FACTS controllers. FACTS, i.e. Flexible AC Transmission Systems is incorporating power electronic based static controllers to control the needed active and reactive power, and increase power transfer capability of the lines. This can control one line or more number of AC lines in parallel. FACTS concept is illustrated in the following example. Let Bus 1 and Bus 2 shown in Fig. 11.17 represent two AC systems wherein power is to be transmitted from 1 to 2 through a line of impedance r + jx. Neglecting the resistance r ({ x > r), the power transmitted is given by Fig. 11.17


HVDC Transmission

P12 =

V1V2 sin d x


where d is phase angles of V2 with respect to a reference (i.e.) V1. Q12 =

V12 V1V2 cosd (the reactive power) x x


By changing the effective value of x, the power transmitted can be increased or decreased. Further, it modifies the reactive power needed. By connecting either a shunt controller or a series controller reactive power needed is also controlled. The maximum power that can be transmitted with fixed V1 and V2 amplitudes, is obtained when d = 90°. Increasing d beyond 90° will reduce the power that can be transmitted. Increase and decrease of x will change the Pmax value, i.e. the peak of the sin d curve as shown in Fig. 11.18. Hence, power flow in a line can be regulated with (i) either increase or decrease of x and (ii) for a given power flow P, the phase angle between V1 and V2 can be controlled Fig. 11.18 Power angle curves for power/current flow control using the control of either V1 or di erent x V2, which is another method of controlling the power flow. Usually with changing magnitude of V1, V1 V2 does not change much but the phase angle changes as shown in Fig. 11.19. Therefore, regulating V1 or V2 by suitably injecting a voltage will have more influence on the reactive power flow. This is illustrated in Fig. 11.19(b).

Fig. 11.19

(a) Phaser diagram showing send and receiving end voltage and currents (b) Injecting a voltage phaser in series with line voltage to change reactive power

The reactive power at the receiving end is given by Q2 =

V2 (V2 - V1 cos d ) x

which is similar to the equation (11.18)


Parallel AC and DC Systems


In flexible or controllable AC systems, the controllable parameters are (a) Control of line reactance x (b) Control of phase angle d when it is not large which controls the active power flow (c) Injecting voltage in series with the line and at 90° phase with line current, i.e. injection of reactive power in series. This will control active power flow. (d) Injecting voltage in series with line but at variable phase angle. This will control both active and reactive power flow. (e) Controlling the magnitude of either V1 or V2 (f) Controlling or variation of line reactance with a series controller and regulating the voltage with a shunt controller. This can control both active and reactive power. The above control is usually done by means of FACTS controllers which are basically static thyristor or other type. They are mainly (i) Series controllers (ii) Shunt controllers (iii) Series–Shunt or Series–Series controllers

11.9.1 Flexible AC Transmission (FACTS) Controllers Different types of FACTS controllers are schematically shown in Fig. 11.20.

Fig. 11.20

A series controller is usually a variable impedance like a capacitor, an inductor, etc., or a power electronic switched device of variable source with either mains frequency or subharmonic frequency. This injects a voltage in series with the line. If the voltage injected is in phase with the line and current in quadrature, the series controller either supplies or consumes reactive power.


HVDC Transmission

A shunt controller can be either a variable impedance, i.e. capacitor inductor or variable source or a combination of both. Shunt controllers inject current into the line. If the current injected is in quadrature with the line voltage, it either supplies or absorbs the reactive power. A combine series–shunt controller is a combination of both types and is a co-ordinated or unified unit (called UPFC). They inject both voltage in series with line and current into the line. There can be a real power exchange from series to shunt controller or vice versa and hence can control real power also. The different FACTS controllers are (a) static var compensator (SVC), (b) thyristor controlled reactor (TCR), (c) thyristor switched capacitor (TSC), (d) thyristor controlled series capacitor (TCSC), and (e) voltage source converter based units like static compensators (STATCOM) and unified power flow fact controller (UPFC).

11.9.2 The Series Controllers (a) Thyristor Controlled Series Capacitor The series controllers are used to compensate for the line inductive reactance so that effective X of the line is reduced and power transfer capacity is increased. The schematic arrangement is shown in Fig. 11.21. A series capacitor bank is used in parallel with a parallel thyristor controlled reactor to get smooth variation of the capacitive reactance. The net reactance of the line becomes (X XC) and the Pmax that can be transmitted increases to P=

V1V2 sin d (X - XC )

(11.20) Fig. 11.21

V1V2 sin d . Hence, the transient stability X limit also increases and power oscillations produced during fault clearing, etc., are also damped out as shown in Fig. 11.22. which is larger than

Fig. 11.22

Capacitive reactance compensator: (a) Arrangement with SCRs (b) Equivalent circuit

SSSC arrangement

(b) Static Series Synchronous Compensator (SSSC) SSSC is a device capable of interchanging both active and reactive power in an AC link between two systems. For controlling only reactive power, the size of SSSC can be reduced. The injected voltage into the line is controlled by controlling the magnitude of the voltage phasor injected, which is at 90º to the current flowing in the line (either lead or lag). The operation is

Parallel AC and DC Systems


similar to the series capacitor compensator and a controllable series reactor compensator. The basic difference is that the magnitude of voltage injected is not related to the line current and is independently controlled. Hence, this is effective for both high and low line loading. Schematic arrangement of SSSC is shown in Fig. 11.22. SSSC is introduced into the line at a suitable location or at load end. It requires a source, usually from the load end tapping with a rectifier and voltage source converter to inject the required voltage at 90º phase with respect to the line current. SSSC has a wide application, namely for (a) power flow control, (b) load end voltage control, and (c) phase angle (load) for stability enhancement. The fact that this can inject both lagging and leading voltage into the line makes it useful over a wide range of operation. It gives better possibility of damping the oscillations. The disadvantage is that a high voltage (rated to the line voltage) inter-phasing transformer is required and the cost of the scheme is higher compared to TSC. SSSC can raise or lower the line current, but cannot alter real power P or reactive power Q independently. A single series connected converter installation is generally cost effective for application where a power flow control is sufficient. In Big Sandy line, it is reported that SSSC was operated to control the magnitude and polarity of the injected voltage in steps so that the power flow was controlled from 100 MW, 180 MW, 250 MW to 200 MW finally (in steps). Continuous variation of power is difficult. The advantages of SSSC over other series compensators can be summarised as follows: (i) It is capable of generating a controllable compensating voltage over an identical capacitive and inductive range independently of the line current magnitude. (ii) With an external DC source connected it can provide compensation for line resistance and inject P (real power) into the line. (iii) It increases the effectiveness of the power oscillation damping by modulating the series reactance suitably. The variable reactance (impedance) of the compensator can damper transient power oscillations. The compensating characteristics and range of operation are shown in Fig. 11.23.

Fig. 11.23

V I characteristics, power losses and phaser diagram of SSSC

11.9.3 The Shunt Controllers (a) The Switched Capacitors/Reactors (TSC/TSR) In Fig. 11.24 the basic arrangement of thyristor controlled capacitors arrangement is shown. The capacitor C may be a capacitor bank split into smaller value capacitors which can be switched on/off in smaller steps. The reactor L is to limit the switching transient


HVDC Transmission

current. Thyristor is switched on when the network instant voltage is equal to the capacitor voltage. This has the advantage of step-wise control, average delay of one-half cycle to one cycle, and no generation of harmonics, since the transient currents are damped out. The disadvantage is that compensation is not continuous. Each capacitor requires separate thyristors and the system resonant frequency w r = 1/ LC should be far higher than the operating frequency of AC supply. An improvement for this basic scheme (which was first adopted in 1971) is to go for a more continuous scheme with one SCR (S1) replaced by a diode as shown in Fig. 11.25. For switching on, firing of the thyristor is done when supply voltage 3p . The current starts from 0 value is at negative peak, i.e. 270º or 2

Fig. 11.24

(a) Thyristor-diode switched capacitor configuration

(b) Experimental compensating phase currents of switched capacitors (a) Current through B1’, (b) current through B2, (c) Current through B3, (d) Current through B4, and (e) Total system compensating current

Fig. 11.25

Binary switched capacitor configuration

Thyristor switched capacitors current

Parallel AC and DC Systems


without distortion. With this neither harmonics nor magnetic inrush current in transformer exist. The starting current at switching time dV d = CVm (- cos wt ) dt dt = CVm sin wt0 =c


which gradually increases as shown in Fig. 11.25(b). This scheme of TSC is more economical and more number of compensating levels can be obtained.

(b) Thyristor Controlled Reactor A switched (or thyristor controlled) reactor in parallel with a fixed capacitor gives more flexible and better reactive power compensation. The schematic circuit arrangement along with voltage—R-KVA characteristic is shown in Fig. 11.26. The compensator also includes a filter in parallel to filter harmonics generated. When phase angle control is used to switch the reactor, continuous variation of reactive power is obtained but odd harmonic current is generated during the control process. Full conduction is obtained for control angle a = p/2 or 90º and partial conduction is obtained for between p/2 and p as shown in Fig. 11.27. As the firing angle is increased, the fundamental component of current is decreased, since the thyristor is line commutated adjustment of currents and compensation can be obtained only once per half cycle. The main disadvantage of the scheme is lower order harmonics and power losses in reactor. The amplitude of Kth harmonic current is given by the equation (11.22). Ik =

4Vr.m.s. È sin(k + 1)a sin(k - 1)a sin (ka ) ˘ + - cos(a ) ˙ p X L ÍÎ 2(k + 1) 2(k - 1) k ˚

Fig. 11.26

Fig. 11.27


Voltage-reactive power characteristic of a FC-TCR

Voltage and current waveforms in TCR for di erent a

The main characteristic of VAR compensators is the amount of reactive power exchanged with the system. The Q V characteristic is shown in Fig. 11.26 as a function of a and applied voltage. At rated voltage the


HVDC Transmission

fixed capacitor TCR has almost linear characteristic which is only limited by the ratings of L and C.

(c) Static Synchronous Compensators (STATCOM) Due to the developments in power electronics and digital control schemes, reactive power compensators using self-commuted converters are developed which are not only used to compensate reactive power but also voltage regulation, power flicker, harmonics, real and reactive power, line impedance, and phase angle control. All these are achieved to get final effect of power system performance and improve stability. One of such high performance controller is static synchronous compensator or STATCOM. This is based on a solid-state VSC with an inverter and the connected in parallel-to-power system through a reactor. STATCOM generates three balanced sets of sinusoidals at the line or system frequency with controllable voltage magnitude and phase angle; the schematic diagram of which is shown in Fig. 11.28.

Fig. 11.28

Static synchronous compensator—STATCOM

The grid sees STATCOM as a synchronous machine without inertia and offers subcycle response. Each phase is independently controlled and gives optimum voltage support especially during system disturbances. The advantages are (i) It does not require large reactive components, i.e. shunt reactor or capacitor to provide reactive power. (ii) Operating range is much wider than classical SVC with (a) higher reactive output at lower system voltages, and (b) significantly improved voltage control under contingencies and gives good recovery support under system disturbances. (iii) It has high dynamic response than classical SVC. The V-I characteristic of self-commuted VAR compensated (STATCOM) and thyristor controlled SVC is shown in Fig. 11.29 which indicates the advantages mentioned above. The damping ability of SVC in power oscillations is given in Fig. 11.29(c).

Parallel AC and DC Systems

Fig. 11.29 V-I Characteristics of shunt VAR compensators



HVDC Transmission

11.9.4 The Series–Shunt Controller Unified Power Flow Controller (UPFC) The unified power flow controller (UPFC), shown in Fig. 11.30, consists of two switching converters operated from a common DC link provided by a DC storage capacitor, one connected in series with the line, and the other in parallel. This arrangement functions as an ideal AC to AC power converter in which the real power can freely flow in either direction between the AC terminals of the two inverters and each inverter can independently generate (or absorb) reactive power at its own AC output terminal. The series converter of the UPFC injects via series transformer an AC voltage with controllable magnitude and phase angle in series with the transmission line. The shunt converter supplies or absorbs the real power demanded by the series converter through the common DC link. The inverter connected in series provides the main function of the UPFC by injecting an AC voltage Vpq with controllable magnitude (0 £ Vpq £ Vpq max) and phase angle q (0 £ q £ 2p), at the power frequency, in series with the line via a transformer. The transmission line current flows through the series voltage source resulting in real and reactive power exchange between it and the AC system. The real power exchanged at the AC terminal, that is the terminal of the coupling transformer, is converted by the inverter into DC power which appears at the DC link as positive or negative real power demand. The reactive power exchanged at the AC terminal is generated internally by the inverter.

Fig. 11.30 UPFC power circuit and configuration

The basic function of the inverter connected in parallel (Inverter 1) is to supply or absorb the real power demanded by the inverter connected in series to the AC system (Inverter 2), at the common DC link. Inverter 1 can also generate or absorb controllable reactive power, if it is desired, and thereby it can provide independent shunt reactive compensation for the line. It is important to note that there is a closed direct path for the real power negotiated by the action of series voltage injection through the inverter 1 and back to the line, the corresponding reactive power exchanged is supplied or absorbed locally by the inverter 2 and therefore, it does not flow through the line. Thus, the inverter 1 can be operated at a unity power factor or be controlled to have a reactive power exchange with the line independently of the reactive power exchanged by the inverter 2. This means that there is no continuous reactive power flow through the UPFC.

Parallel AC and DC Systems


11.9.5 Conclusions on FACT Controllers An overview of the different power electronic FACT controllers is briefly presented in this section. They use both line commuted CSC converters (thyristor controlled) as well as self-commuted VSC based (using IGBTs and IGCTs) and there is a dramatic improvement in the performance of VAR compensators. They have faster dynamic behaviour and can control more parameters and variables. The introduction of new selfcommuted topologies at high voltage levels and larger power ratings (few hundreds of MVAR/MVA rating) makes increasingly larger power transfer (in GW range possible). These will be used on much wider scale in future along with HVDC transmission.

11.10 MODELLING OF HVDC SYSTEMS 11.10.1 Introduction An HVDC system is not an independent system but an integral part of a large electrical power system. Hence, the design and operation requires detailed understanding of the different phenomenon that are additionally added to the larger power networks. The converter controls and power sharing by DC links have to be properly incorporated in modelling and analysis of power system when model studies are carried out. System performance studies are normally carried out using analogue or digital methods, i.e. either analog, computer or digital computer studies. These are used for AC power systems for analysis and simulation and can be augmented to include the HVDC system or link. The HVDC simulator and transient network analyser are analog methods. Studies on a digital computer are digital tool modelling of different components or parts in an AC/DC system that are needed for (i) simulation studies for both steady state and transient conditions, (ii) modelling for study of harmonics, and (iii) transients in converters under switching conditions which are important for complete system studies.

11.10.2 Converter Model (a) Steady State A simplified network model of an HVDC converter along with the transformer is shown in Fig. 11.31. Here, Ed = Vdo cos a Vdo = aVAC a= Rc = where

(11.23) (11.24)

3 Ên ˆ 2 Á s ˜ a0 p Ë np ¯


3 x p c


VAC = Line-to-line voltage on primary side of transformer Rc = Commutation resistance Xc = Leakage reactance of the transformer ns/np = Converter transformer nominal turns ratio

Fig. 11.31

Simplified Network model of HVDC converter with transformer


HVDC Transmission

The transformer winding equivalent resistance and valve voltage drop may also be taken similar to the reactance Xc or leakage inductance Lc. In the above model or equivalent circuit (i) Harmonics in DC voltage is not considered (ii) AC voltages are taken balanced and nonlinearities in converter transformer are neglected

(b) Converter Model for Transient Analysis When a converter model is to be taken for the normal operation of a six-pulse converter, only two valves go into conduction, and under commutation process, 3 valves go into conduction. In case of a 12-pulse converter, the normal mode of conduction is 4/5 valves and if m exceeds 30°, it will be 5/6 valve conduction. To take this fact into account the inductance and resistances represented in figure have to be changed as 2Rc 4 xc 3 xc for mc < 30° and 2Rc and and for 30° £ mc £ w0 w0 60° for a 12-pulse converter. The switching on action of the valves is represented either as (i) ideal switch, turned on at the instant of firing, and (ii) turned off with turn-off time represented as equal to the closing of switch till a forward voltage appears. The equivalent circuit for transient condition studies is shown in Fig. 11.32.

Fig. 11.32

Equivalent circuit for transient condition

11.10.3 Model for DC Network The DC transmission line along with smoothing reactor and DC filters are usually represented as lumped parameter elements. The equivalent circuit representation for a two-terminal DC link is shown in Fig. 11.33. The DC line is represented by an equivalent p or T network (here T network is shown).

Fig. 11.33

Equivalent circuit

L, C and R—The DC line total inductance, capacitance and resistance Rcr, Lcr— Rectifier equivalent resistance and inductance Ldr— Filter and reactor inductance on rectifier side Ldi— Filter and reactor inductance on inverter side Rci, Lci— Inverter equivalent resistance and inductance

Parallel AC and DC Systems


Even though the resistance of the smoothing reactors is not shown, they can be included suitably along with resistance of lines. The inductances and resistances shown can be clubbed into single unit for analysis as Ldr = Rectifier side inductance = Lcr + Ldr + L/2 Ldi = Inverter side inductance = Lci + Ldi + L/2 Rdr = Rectifier side resistance = Rdr + R/2 Rdi = Inverter side resistance = Rdi + R/2 And the simplified T network becomes as shown in Fig. 11.34.

Fig. 11.34 Simplified T network of DC system

The network equations are didr + Rd idr dt di (Vc – Edi ) = Ldi di + Ri idi dt 1 dVc (idr – idi ) = C dt ( Edr – VC ) = Ldr

(11.27) (11.28) (11.29)

The above equations are re-arranged as follows to get into state variable form didr R = – dr idr + (Vdr – Vc ) dt Ldr


didi R = – di idi + (Vc – Vdi ) dt Ldi


dVc 1 = {idr – idi } dt C È – Rdr 0 Í L dr Í x È 1˘ – Rdi Íx ˙ = Í 0 Í 2˙ Í Ldi ÍÎ x3 ˙˚ Í Í 1 –1 Í ÍÎ c c

(11.32) –1 ˘ È 1 ˘ Í ˙ Ldr ˙ ˙ È x ˘ Í Ldr ˙ ÈV ˘ 1 dr –1 ˙ Í ˙ Í –1 ˙ Í ˙ V ˙ Í x2 ˙ + Í ˙ Ldi ˙ L Í di ˙ ÍÎ x3 ˙˚ Í di ˙ ÍÎ 0 ˙˚ ˙ ÍÎ 0 ˙˚ 0 ˙ ˙˚



HVDC Transmission

Representing the currents as state variables x1 = idr; x2 = idi ; x3 = Vc. The state-variable representation for DC networks is given in equation (11.33) and the solution for idr, idi, Vdr, Vdi is obtained. Modelling of the associated network is done in the same manner as it is done for power flow or stability analysis in AC power system studies. For accounting for the DC current in the AC network, the equivalent fundamental component of AC current I1 is taken as Ê 6ˆ I1 = ± Á nI Ë p ˜¯ b d where


nb = Number of bridges connected, and Id = DC current in the bridge. ‘+’ is taken for inverter and ‘–’ is taken for rectifier.

The AC injected current leads the voltage by an angle f since the converter consumes reactive power lagging. The angle f is defined as ÊV ˆ ÊV ˆ f = cos –1 Á d ˜ for rectifier and f = cos –1 Á d ˜ + p for inverter Ë aV ¯ Ë aV ¯ where Vd is the average DC voltage at the converter. Modelling of synchronous generator is usually done by transforming the time-varying 3-phase systems into time invariant form using Park’s transformations. Multimachine systems need more complex transformations and are not discussed here.

11.10.4 Modelling of DC Links Since a DC link network consists of converters, reactors and the lines (Ref. 11.10.3) it is viewed as a resistive network excited by voltage or current sources for steady state modelling (neglecting the inductances and capacitances). For converters connected in series or parallel an additional loop resistance or nodal conductance matrix may be added. The converters are to be represented as controlled sources with the controller characteristics. The elements of DC network can be separated into tree branches and link branches after forming the graph of the network. All the resistances in the network in general can be assumed to form a subset of tree branches. The converters can be divided so that they go into either tree branches or links. The solution for DC network can be obtained by forming either the loop or nodal equations and solving for vg and ig, the voltage and current vectors corresponding to the conductances. For these values, the converter voltages and currents and hence the solution for power flow is obtained.

11.10.5 Per Unit System for DC Quantities In AC system analysis, it is customary to use per unit quantities to get the solution. The per unit voltage is usually taken as equal to the phase voltage of 3-phase system and a base unit power or VA is taken. In a similar manner, for DC quantities also, independent base voltage and current can be chosen. Usual base quantities adopted are

Parallel AC and DC Systems


DC base voltage VDC (p.u.) = Nominal or rated value of DC voltage per converter DC base current IDC (p.u.) = Nominal or rated value of the current If all the converters are not identical then a common base value is to be chosen which may be the largest V converter value. With the above choice, base resistance is defined as Rbase = dc . The voltage equation for I dc converter will become Vd = k where

Ed cos a – Rd I d T


Ed = Transformer side nominal voltage T = Transformer tap position k=

3 2 N s Vb p N p Vdb


Ns, Np—Turns of converter transformer Vb—Base voltage (AC) at converter bus Vdb—Base voltage (DC) of the converter Parallel AC–DC system, power flow interaction with generators and DC power modulation aspects have been discussed in Sections 11.6 and 11.7. Performance of the DC system can be studied on DC simulator using the modelling discussed in this section. A brief outline of a HVDC simulator—The studies that are done on a simulator can be performed on a digital computer as well, but they require a large capacity and consist of very long calculations.

11.10.6 HVDC Simulator An HVDC simulator usually consists of a large number of cubicles (20 to 50) for representing different components of a DC system along with the associated AC system. Simulators usually have the capacity to model either (i) a bipolar system, or (ii) a monopolar with ground return and the cubicles can be interconnected as desired. Present-day advanced simulators have the provision to go for multiterminal systems also. Usually the simulators will have the following components— (i) (ii) (iii) (iv) (v) (vi) (vii) (viii) (ix) (x)

12-pulse converters Bipolar overhead DC lines Synchronous machine models Static VAR compensator models AC filter banks consisting of 3rd , 5th, 7th, 11th, 13th and high pass banks Reactors to represent AC network AC breaker models Complete set of control and protection subsystems, for both converter and pole levels Recording equipment Other auxiliary units


HVDC Transmission

The simulators can have a nominal voltage rating of about 50 V per converter, current rating of 100 to 250 mA, and AC 3-phase voltage (10 to 20) * 3 V, with corresponding power ratings of 5 to 12 watts per converter. With such low power ratings, it is possible to eliminate voltage drops in valves and reduce the losses in filters, converter transformers, etc. The different cubicles will consist of (i) DC lines connected as p or T network (ii) 12-pulse converters (iii) Converter transformers, with 3-winding transformer, tap changer, shunt reactor, commutation reactor, loss compensator, and compensator for saturation effects. (iv) The thyristor units with very less voltage drop (about 5%) may be large compared to real valves with about 0.2% forward voltage drop. (v) Smoothing reactor (vi) AC filter banks with high Q filters (vii) Synchronous machine model units that include basic parameters, excitation system, power stabiliser, speed governor turbine and inertia model, measurement system, etc. (viii) The model can be operated with variable frequency mode up to 100 Hz. (ix) Converter control unit consisting of (a) Firing angle control (b) Delay angle control (c) Commutation margin (d) Supervisory control unit (x) Pole control units may include (a) DC line protection (b) Pole differential protection (c) Overvoltage protection and (d) Harmonic protections Usual studies that are performed are (i) (ii) (iii) (iv) (v)

DC main circuit design Development of control and protection schemes Dynamic interaction between HVDC and AC systems System testing on control equipment Support for HVDC schemes in operation and for further schemes

An HVDC simulator with most of the above features described is located at CPRI, Bangalore and is engaged to cater to needs in planning, design and operational studies on HDVC transmission in India.

REFERENCES 1. Koshcheev L. A., Environmental Characteristics of HVDC Overhead Lines, Third Workshop on Power Grid Interconnection in North East Asia, (Vladivostok, Russia), Sept. 30 to Oct. 3, 2003 (St. Petersburg), HVDC Power Tr. Research Institute.

Parallel AC and DC Systems


2. Zhang X. P., HVDC Power Transmission Systems, Widly International, (USA). 3. Larruskain D. M. et al., Tr. and Distribution Networks AC and DC, Dept. of E.E., University of Basque Country, (Bilbar, Spain). 4. Korpinen Leena, Cardiovascular effects of short term exposure to electric and magnetic fields of electrical power transmission, PhD Thesis, Temere University of Technology (Helsingin), December, 2007. 5. Maruvada P. S., R. D. Dallaire et al., Environmental effects of Nelson River HVDC Tr. lines RN, AN, electric field induced voltage and ion current distribution tests, IEEE, PAS, Vol. 101, No. 4, April 1982. 6. Schmidt Gerhard et al., HVDC Transmission and the Environment, Power Engineering Journal, October, 1996. 7. Clerici A, Paris L., Donfors P., HVDC conversion of HVAC lines to provide substantial power upgrading, IEEE Tr. (Power Delivery), Vol. 6, No. 1, January, 1991. 8. Mazon A. J., Zamora I. et al., Analysis of traditional suspension strings with GT ACSR conductors, Tr. IEEE (Power Delivery), Vol. 19, July, 2004. 9. Larruskain D. M., Power Transmission Capacity Upgrade of Overhead Lines, Dept. of EEE, E.U.I.T.I. University of Rasque, (County Bilbo, Spain). 10. HVDC, Transmission Reference book EPRI, (Polo Alto, California), February, 2008. 11. Jovcic, D., Pahalawaththa N. et al., Small signal analysis of HVDC HV-AC interactions, IEEE Tr. (Power Delivery), Vol. 14, No. 2, 1999. 12. Faried, S. O. and El-Serafi A. M., Effect of HVDC converter station faults on turbine generator shaft torsional torques, IEEE Tr. Power Systems, Vol. 12, No. 2, 1997. 13. Arrillaga J. et al., Direct Connection of Series Self-excited Generators and HVDC Converters, IEEE Tr. Power Delivery, Vol. 8, No. 4, 1993. 14. Sood Vijay K. et al., HVDC Power Transmission and FACTS controllers, (USA), Kulwer Academic Publishers, CRC Press, 2004. 15. Sood Vijay K., HVDC Power Transmission, John Wiley and Sons, Asia Pvt. Ltd., 2009. 16. Hingorani Narian G., Gyugyi Laszlo, Understanding FACTS, (New Delhi), IEEE Press, Standard Publishers and Distributors, 2001. 17. Zhang Lindon et al., Power system reliability and transfer capability, security and reliability of elec. power systems, Cigre, June 18 20, (Tallinn, Estonia), ABB Power Technology, (Sweden). 18. Hazra J., Phulpin Y., Ernst D., HVDC control strategies to improve transient stability of interconnected systems, Power Tech. 2009, June/July (Bucharest, Rumania), 2009. 19. Messina A. B. et al, Damping of low frequency inter-area oscillations using HVDC power modulation, Elec. Power Components of Systems, Vol. 31, pp. 389 402, 2003. 20. Hua Song Yong, Johns Allan T., Flexible AC Transmission Systems (FACTS), Inst. of Electrical Engineers, (London, UK), 1999. 21. Mathur R. Mohan, Verma Rajiv K., Thyristor based FACTS Controllers for Electrical Transmission Systems, IEEE, Wiley Series (New York), John Wiley and Sons, 2002. 22. Sen Kalyan, K., Sen Mey Ling, Introduction to FACTS Controllers, IEEE, Wiley Series, September, 2009. 23. Dixon Jaun, Moran Luis et al., Reactive Power Compensation Technologies, State of the art Review, (Invited Paper), Elec. Engg. Dept., Pontificiat University, (Santiago, Chile).

QUESTIONS 1. Discuss the different aspects and limitations pertaining to (a) using an AC system and (b) DC system for power transfer.


HVDC Transmission

2. What are the different losses in HVDC system and how do they compare with AC systems? 3. What are the different possible affects and influences on nature and environment regarding overhead transmission lines. How are these minimised with DC systems? 4. Discuss the different advantages and limitations regarding conversion of AC lines into DC lines. 5. Enumerate the possible interaction of DC systems with AC. How does SCR affect the terminal voltage and transients that occur at inverter ends? 6. What are the resonant phenomena that occur in AC/DC systems and how are the overvoltages produced controlled? 7. What are the different subharmonic oscillations that occur due to disturbances in DC systems? Explain. 8. How are the power transfer capabilities of AC lines improved by using parallel HVDC–VSC system (using DC cable transmission)? 9. What are the different FACTS devices that are commonly used? Explain briefly the difference between series and shunt controllers. 10. Explain briefly how voltage control and reactive power control can be achieved using a TCSC/TCR. 11. Give the principle of SSSC and explain how this controls reactive VARS and dampen oscillation? 12. What is STATCOM? Compare its characteristics with that of other shunt connected devices. 13. Explain unified power flow controller and discuss how it is more versatile than other FACTS devices?

MULTIPLE CHOICE QUESTIONS 1. HVDC transmission is opted when (a) bulk power transfer is needed (b) improvement of stability (c) long distance and cable transmission is required (d) all of the above 2. DC cables are more effective and less bulky because (a) voltage stress used is much higher in the insulation (b) no dielectric losses with DC (c) no charging current with DC (d) both (a) and (b) (e) both (b) and (c) 3. The power transfer capability of DC cables compared to AC cables is (a) same (b) 1.5 to 2 times (c) 0.5 to 1.5 times (d) cannot be asserted 4. An HVAC line using same current density in conductors as that of DC will have conductor losses (a) about 3 times (b) 1.5 times (c) same as that of DC (d) cannot be asserted 5. Safe and permissible electric field and ionic current density is about (a) 60 kV/m and 30 nA/m2 (b) 20 kV/m and 25 nA/m2 2 (c) less than 20 kV/m and 15 nA/m (d) 5 kV/m and 10 mA/m2 6. Compared to AC overhead lines, towers and substations, the land requirement in DC is (a) same as that of AC (b) 65% for substations and 50% for lines (c) 90% for both substations and lines (d) cannot be predicted

Parallel AC and DC Systems


7. At ground level, direct current power lines produce magnetic field of (a) 10 m T (b) 30 m T (c) same as the earth’s magnetic fields (d) more than 100 m T 8. Short circuit ratio of a system is PDC Short circuit level of AC system (a) P (b) Short circuit level of DC system AC (c)

Short circuit level of AC system DC power Pd


2 VAC Pd

9. A system is said to be weak if SCR is (a) less than 3 (b) less than 1 (c) more than 5 (d) 3 to 5 10. Converter transformer core saturation will lead to (a) harmonic oscillations (b) ferro resonance (c) subharmonic oscillations (0 5 Hz) (d) torsional oscillations in turbine-generator unit 11. When a 3-phase double circuit AC line is converted into DC line, the power transfer will be increased (a) no change (b) 1.5 times (c) 3 times (d) 2 times 12. Which of the following is a series connected FACTS device? (a) UPFC (b) STATCOM (c) TCSC (d) TCPST

ANSWERS 1. (d) 9. (a)

2. (d) 10. (b)

3. (b) 11. (d)

4. (a) 12. (c)

5. (c)

6. (b)

7. (a)

8. (c)

Some HVDC Projects implemented in India In the last two decades, few HVDC schemes have been designed, executed and brought into operation. They are mainly long distance bulk power transmission systems or back-to-back schemes. Reasons for choice of HVDC are (a) better overall economy, (b) long distance network stability, (c) right-of-way requirement is less (about 50%) and (d) low transmission losses and better stability. The reason for back-to-back schemes is to overcome frequency deviation in different regions and to have an asynchronous connection. The technical details of three long distance schemes and one back-to-back scheme are mentioned here. The transmission systems under the control of Power Grid Corporation of India Ltd. (PGCIL), a central government organisation and all their schemes are either inter-state or inter-regional grid interconnectors.

(A) RIHAND–DADRI (U.P.) (50 KM FROM DELHI) HVDC LINK This is the first commercial project being operated at ±500kV DC and was commissioned in August 1992 as an NTPC project. The project is implemented by ABB. (a) Length of Line (b) Power Rating

(c) Convertor (d) Converter Transformer Single Phase, 3 Winding Taps Percentage Impedance Short Circuit Ratio

814 km 1500 MW (Dadri) 1568 MW (Rihand) 1659 MW 2 hours 2000 MW 5 s 12-pulse with quadruple suspend valves 400 kV/213 kV, 315 MVA (Rihand) 400 kV/206 kV, 305 MVA (Dadri) –10 to +14% in 1.25% steps 19.3 5.0 (Dadri) 3.5 (Rihand), 2.5 (Rihand, minimum)

Some HVDC Projects implemented in India

(e) AC Filters (Double-tuned) Double-tuned High Pass (f) Insulation Level (HV) Low Voltage (Star) Low Voltage ( ) (g) Input/Output AC DC (h) Line Data Conductors Spacing between Poles Height of Pole Conductor maximum sag Ground Wires Spacing between Ground Wires Shielding Angle (i) Electrode Line Spacing Height of Conductor (j) DC Filter Single–tuned 12 Double–tuned 12/24

(k) DC Reactors (l) HVDC Valves (m) Insulators used



3/36 40. 1 MVAR 11/13 39.0 MVAR 5/27 70.5 MVAR HP/24 38.8 MVAR 1300 kV Lightning 1080 kV Switching 1550 kV Lightning 1290 kV Switching 1175 kV Lightning 980 kV Switching 400 kV 50 Hz 12-pulse ±500 kV (nominal) ±400 kV (reduced) Quad, ACSR 45.7 cm spacing 12.4 m 28 m 9m 2 9.5 m 10° 2 ACSR conductors 1.5 m 1.5 m C=1.2 F, l=58.6 mH 2 numbers C=1.2 F, L = 42 mH 2 numbers C = 1.6 F, L=15.4 mH, R=552 0.36 H (Close to valve) 0.18 H Quadruple suspended, 12-pulse 16 modules in series, 6 thyristors/module 38 discs with 41 mm/kV creepage length, V string


This line or scheme is meant to interconnect the eastern region grid to the southern region grid and transport 2000 MW of power from Talcher (Orissa–NTPC) thermal station to Karnataka (Bangalore). The project is proposed by NTPC and the line is controlled and operated by the Power Grid Corporation of India (PGCIL). The line goes through the states of Orissa, Andhra Pradesh and Karnataka. There is a proposal to have another terminal at Mysore (Karnataka ). The project costed Rs. 2700 crore and the line costed about Rs. 3365 crore. This is called the East-South Interconnector II. (a) Line Length

1400 km


HVDC Transmission

(b) Power Rating

(c) Convertor Transformer Single phase, 3 winding (d) AC Filters (Double-tuned) (East Orissa)(Double-tuned) Shunt Capacitor Bank Shunt Reactors (South Kolar)(Double-tuned) Shunt Capacitor Bank (e) Input/Output AC DC

(f) (g) (h) (i) (j)

Thyristors Insulators used Type Conductors Height above Ground

2000 MW (nominal) 1.15 p.u 2 hrs 1.30 p.u 30 min 1.47 p.u 5 min 400 kV, 400 MVA, 300 tons each 12/24 6 numbers 3/36 3 numbers 1 number 2 numbers 12/24 6 numbers 3/36 3 numbers 5 numbers 400 kV 3-phase 50 Hz ±500 kV (nominal) ±400 kV (reduced) (Charged and operated at 400 kV in October 2002) 100 mm, 7.5 kV, 1550 A, TC=60˚ 41 discs, Creepage length 45 mm/kV V string 35.05 mm ¥ 4 (quad) ASCR Bundle 12.75 m

One full tower configuration

Fig. A-1 Typical HVDC towers used in Talcher–Kolar system

Some HVDC Projects implemented in India


Fig. A-2 Tower head showing V String and quad conductors

(C) BALLIA (U.P.) — BHIWANDI (RAJASTAN) HVDC LINK This project is envisaged to interconnect the northern grid with the western grid and is an inter-state link expected to be commissioned during 2010. (a) Length of the Line (b) Power Rating

(c) Converter Transformer (Single phase) Reactance Tapings (d) AC Filters 12/24

(e) Filter Requirement

780 km 2500 MW 1.1 p.u. 2 hours I, 155 p.u. 30 min Bipole 1.2 p.u. 30 min Monopole 500/3 MVA, 16 Nos., (One spare) 400/ 3(Y) \ 211.1/ 3(Y) \ 211.1( ) 17 % –6.6 to 19.8 % in steps of 0.825% 120 MVAR 3 Nos. 12/36 97 MVAR 2 Nos. 12 150 MVAR 2 Nos. 24 15 MVAR 3 Nos. Shunt Capacitor 150 MVAR 4 Nos. Shunt Reactor 72 MVAR 2 Nos. Induced Harmonic Distortion < 1% Total Harmonic Distortion < 4 %





(j) (k) (l) (m)

HVDC Transmission

Total Effective Distortion < 3 % Generator Harmonic Current < 1 % 5th and 7th Harmonic currents in any generator < 0.6% Insulation Levels 400 kV AC Side Lightning 1300 kV Switching 1080 kV Valve Side (Star) Lightning 1550 kV Switching 1290 kV Valve Side ( ) Lightning 1050 kV Switching 950 kV Input-Output AC/DC 400 kV, 3-ph. AC DC Operating Voltage ±500 kV down to 350 kV At 80% Voltage 2250 A At 70% Voltage 2150 A Operating Ambient Temperature 25˚C DC Reactor Inductance 250 mH Rated Voltage 512 kV, 2500 A, DC Insulation Level 1425 kV to ground and 850 kV terminal to terminal DC Breaker Metallic Return (MRTB) and Ground Return (GRTB) In DC Yard, DC Current 1.2 p.u Reactive Power Requirement 2054 MVAR at 400 kV, 3-phase Insulators Composite Long Rod 210 kN Features 1. Prevents self-excitation of generators 2. Overvoltage limiting control 3. It is directly connected to the Singrowly thermal station

(D) VISAKHAPATNAM BACK-TO-BACK HVDC INTERCONNETION PROJECT This project was envisaged to connect the eastern region grid to the southern region grid at Visakhapatnam (Gazuwaka) and is split as Vizag I and II for power exchange of 1000 MW; each unit rated for 500 MW. Since, the eastern region maintains frequency of 50 Hz and above and the southern region frequency is always less than 50 Hz (49.2 to < 50) it was necessary to have an asynchronous link. Hence, a back-to-back DC scheme was implemented for interconnection. Details of Vizag II, which was commissioned in March 2005 are given below. The station is controlled and operated by PGCIL. The single line diagram of the Vizag back-to-back station is shown in Fig. A-3. (a) Power Rating (b) Operating Voltage AC DC (c) Transformers Single Phase, 3 winding (6 numbers)

500 MW 550 MW (1.1p.u) 2 hrs 400 kV, 3-phase 88 kV, Line-to-ground 176 kV Line-to-neutral (Across 12-pulse Bridge Unit) 400/ 3(Y) \74.5/ 3(Y) \74.5 kV( ) 201 MVA each

Some HVDC Projects implemented in India

(d) Filters H.P. (e) DC Reactor (f) Control either from

(g) Valve details (Thyristors)


330 MVAR (i.e. 110 MVAR each, 3 nos.) 12/24 and 12/36 30 mH each, 2 numbers (1) Vizag 1 unit (2) Eastern region load dispatch center (3) Southern region load dispatch center through optical fiber network YST 90(50) 6 thyristors per module, 6 modules in series Total number of thyristors 864 Maximum voltage per thyristor 7.2 kV Arrangement 12-pulse bridge

This scheme has frequency control and is stable between 47.5 Hz to 51.5 Hz with dead band of 0.05 Hz at its specific preset frequency. The converter protection schemes employed are (a) 1. 2. 3. 4. 5.

Voltage-stress Transformer Tap Changer Linked Control High angle supervision DC overload control Low voltage detection Thyristor monitoring

Fig. A-3 Single line diagram of Vizag back-to-back HVDC Link


HVDC Transmission

6. Valve monitoring 7. Cooling water temperature supervision (b) DC Pole Control 1. DC over and undervoltage protection 2. DC Harmonic protection 3. DC differential protection 4. Smoothing reactor earth fault protection

Author Index

Ainsworth J. D. 166 Allard Y. 314 Arrillaga J. 35, 355

Hingorani Narian G. 166, 355 Herold G. 299 Hua Song Yong 355

Baoiang Sheng 280 Bornitz E. 192 Brahman Micheal P. 192

Jack L. Tink 14 Johns Allan T. 355 Jovcic 355

Chandrasekhariah H. S. 281 Chang Hsin Chien 192 Clarke C.D. 219 Clerici A. 355

Kamaraju V. 299 Keller 237 Kewar Abhay 314 Khanchandani K.B. 65 Kamaraju V. 299 Kauferle J. 280 Khatir M. 280 Kimbark E.W. 35 Kimoto T. 299 Korpinen Leena 355 Koshcheev L. A. 354 Krishnayya PCS 192 Kuffel E. 299

Dallaire R. D. 355 Dixon Jaun 355 Donfors P. 355 Elahi H. 299 El Serafi A. M. El-Serafi 355 Ernst D. 355


Faried S. O. 280 Flong W. 314 Friedrich Kiessling Frischknecht 237


Gunner Asplund 65 Gunnerson Stephen et al. 219 Gyugyi Laszlo 280, 355 Haddad A. 299 Harraway L. 35 Hazra J. 355

Larruskain D. 355 Larruskain D.M. 355 Lescale Victor F. 314 Livani Hanif 314 Manohar Premila 281 Maruvada P. S. 355 Mathur R. M. 192, 355 Mazon A. J. 355 Messina A. B. 355 Micheal Häuster 305


Author Index

Mohammad Khatir 166, 281 Mohd. Muhrid-za-bin Yacob 299 Moran Luis 355 Naidu M.S. 299 Naito K. 299 Nozari F. 314 Padiyar K.R. 65 Pahalawaththa N. 355 Paris L. 355 Pintsov A.M. 192 Phulpin Y. 355 Railing B.D. 192 Ramamoorty M. 299 Rao Subba T. 192 R. D. Dallaire 355 Reeve J. 192, 228, 234, 237, 314 Rudervall Roberto 11 Schattler F. 65 Schetter F. 166 Schmidt Gerhard 355 Sediver 299 Seiman 299 Sen Kalyan 355 Sen Mey Ling 355

Serafi AM El. 280 Shang L. 299 Sharaf A.M. 192 Shoulaic A. A. 281 Singh M.D. 65 Sood Vijay 112 Sood Vijay K. 355 Stanley C.H. 219 Tanabe S. 299 Thomas A. Edison


Uhlmann E. 35, 166 Upadhay S. 280 Verma Rajiv K.


Weimars Lars 35, 314 Wenakijillan 65 Woldeyesus Tamiru Shire Zaengl W. 299 Zamora I 355 Zangeneth B. 281 Zhang et al. 219 Zhang Lindon 355 Zhang X. P. 355 ZnO arrester 294 Zohouri 281


Subject Index

3-phase AC 30 3-phase Symmetrical Faults 263 6-Pulse Converters 62 12-Pulse 63 12-pulse bridges 58 12-pulse conversion 13 12-Pulse Converter 100, 102 (ACSR) 40 (FACTS) Controllers 341 (GATT) 40 (IGBTs) 53 (STATCOM) 346 (TSC/TSR) 343 AC filter 198 Harmonic Currents 186 Interconnection Problem 27 Lines 324 Power Transmission 129 Active DC filter 216 Active filters 213 Advanced active filter 216 Advanced silicon devices 41 Advantages of HVDC 2 Ainsworth 149 Analysis 100 Analysis of VSC Converters 106 Angle of advance b 90 Angle of extinction g 90 Anisotropic Earth 237 Anode material 241 Arc Through 266

Arrangement of filters 214 Asplund 65 Asymmetrical Faults 263 Audiable noise 321 Back-to-back schemes 10 Barsoor 10 B–H curve 176 BIL and SIL 298 Binary Switches Capacitors 344 Body current 245 Bridge Bypass 273 Binary switched capacitor 344 Bipolar Link 12 Break-even distance 17 Bridge Bypass 273 Buried Earth Electrode 246 Carrier-based PWM 110 CCC 139 CEA 139 Choice of site 240 CIA 139 Commutating circuits 84 voltage 81 Commutation failure 267 process 70 reactance 82 Compounding 135 Conduction sequence 68 Considerations 319


Subject Index

Constant Control 133, 134 Constant current characteristic 139 Constant 95 current control 151, 143 extinction angle characteristic 139 extinction angle control 161 ignition angle characteristic 139 power control 156 Contact resistances 245 Control 162 hierarchy 142 of Active 34 Control of multiterminal systems 308 Conversion of AC lines 324 Converter 14, 262 faults 265 model 349 Converter units Paralleling 309 Deparalleling 309 Disconnection 309 Converter stations 298 Converter transformer core saturation 330 Converter transformers 14 Cooling of power semiconductor 52 Core Saturation converter transformer 330 Cosine control 145 Cost subdivision 20 Coupling Reactor (Inductor) 61 Creepage length 284 C-type filters 202 CuiQing Du. 65 Current compounding 137 Current field 227 harmonics 181 waveform 102 Cylindrical electrode 233 Damping control 336 DC and AC System Interaction DC applications 285 breakers 276 cable 16 capacitor 61


filters 212 insulators 283 lines 296 link 154 network 350 network model 350 output voltage 71 ripple injection 218 side 178 system 105 Deparalleling 309 Design 209 Design of a Band-Pass Filter 204 Design of AC Filters 200 Detuning 206 Direct control 163 Direct current (DC) Breaker 276 Insulators 283, 285 Direct current circuit breakers 276 Disconnection 309 Double tuned filters 202 Dynamic characteristics 46 Dynamic equalising circuit 50 Earth 225 electrodes 252 Earth electrode—underwater 252 Ecological changes 323 Economics 17 Effect of control modes 188 Effect of ground return 238 Efficiency (h) of shore electrode 236 Electric fields effects 320 Electrodes 227, 243 location 240 requirement 239 resistance 241 shape 241 Electrode voltage rise 243 Electrodes on shore 234 Environmental 319 Equidistant pulse control 147 Equipment 13 Equivalent circuit 87, 285 Equivalent circuit string insulator 285

Subject Index

Excitation characteristic 177 current 176 Extinction Angle Control (EAG)


Fact converters 338 Facts 338 controllers 338, 341 series controller 341, 342 shunt controllers 343 SSSC 342 TCR 345 TSC/TSR 343 UPFC 348 with HVDC 339 Fariedy 355 Fast transient Over Voltages 289 Faults 3-Ph. asymmetrical 263 Faults 3-Ph. symmetrical 263 Faults clearing 273, 275 converter 262, 265 Line 262 on DC Side 273 sensing 264, 274 Faults 262 Faults on DC side 273 Ferro-resonance 331 Ferro-Resonance Phenomenon 331 Fibrillation current 245 Field effects Electric 320 Magnetic 320 Filter configuration 202, 203 Filters 13, 215 Filter units 280 Firing angle 75 Firing angle control 144 Firing circuits 48 Forward blocking 43 conduction 44 Frischknecht 237 Gate control 75 Gate drive 55

Gate triggering 44, 48 Ground current 224, 321 electrode 223, 224 return 223, 224, 238 path 223 current 224, 321 Grounding 225 Group protection 280 GTO 14 Harmonic 185 currents 13, 187, 198 distortion 200 elimination 199 filter 198 injection 217 model 197 Harmonics 13, 31, 174, 31 Harmonics due to converters 177 Health effects 324 High-Pass Filters 209 High Voltage Valve 62 Homopolar link 12 Horizontal electrode 249, 253 Horizontal Land Electrode 253 HRTG 286 HVAC with FACTS 339 HVDC 13, 349 classic 15 link 92 projects 3, 9 schemes 215 schemes in India 2 simulator 353 transmission 15 HVDC-VSC 32 IGBT 8, 53 assemblies 33 chain module 61 schemes 20 Impedance diagram 199 Individual Phase Control (IPC) Insulation Co-ordination 297




Subject Index

Insulation design 296 levels 22 Insulators 285 Interference Radio 321 TV 321 Internal short circuits Inverter 91 control 131 operation 79 IT product 200


KIT product 202 Land electrode 236, 248, 253 Land usage 323 LASCRs 40 Lescale Victor F. 314 Lightning MTDC 305 MTDC control 308 MTDC faults 310 MTDC ring 307 MTDC operation 308 MTDC parallel operation 307 MTDC protection 310 overvoltage 287 stroke current 287 Lightning overvoltages 287 Lightning stroke currents 287 Limitations 28 Line compensation 26 Line faults 262 Location of electrodes 240 Locus 95 Long rod insulator 286 Long rod porcelain insulator 286 Magnetic field effects 320 Magnetic flux compensation 217 Maximum Power curves 329 Mean time to failure (MTTF) 29 Mechanical resonant frequency 331 Mercury arc rectifiers 3 Mercury arc valve 64 Mercury-valves 2

Metallic Return Transfer Breaker (MRTB) Minimum Cost 208 Misfire 266 Model 350 Modelling 349 Modelling HVDC 349 Monopolar Link 12 MRTB 278 MTDC 305 MTDC Ring 307 Multilevel DC 311 DC systems 311 for wind power 312 networks 312 VSC 311 Multiterminal HVDC 305 networks 312 Natural Current Field 238 Noncharacteristic Harmonics


Operation and analysis 68 Operation of MTDC 308 Overcurrent protection 279 Overlap 88, 90 Overlap Angle (m) 81, 88 Overvoltages 283, 288, 291 Overvoltages control 296 due to faults 290 fast transient 289 lightning 279 protection 291 switching 288 Parallel AC/DC Systems 333 Parallel Connection of SCRs 50 Paralleling 309 Parallel operation 307 Peak inverse voltage 72 Peak-to-peak ripple voltage 73 Peixoto CAO 299 Per unit quantities 92 Per unit system 352 PFC system 148 Phase control 75 Power angle curves 340


Subject Index

Power factor 97 flow 103 flow in VSC 111 law 294 loss 105, 317 loss considerations 317 modulation 310, 336 Power order setting 157 Power reversal 139 Power transfer 316 Power transfer capabilities 21, 25 P–Q diagram 34 Price C.J. 219 Protection filter units 280 overcurrent 279 overvoltages 279, 283 valve 280 Protection of filters 209 Pulse frequency control 147 Pulse number 199 Pulse phase control 150 Pulse width modulation 108 PWM 108 PWM converter 60 Quality factor Q 206 Radio and TV Interference 321 Rating of Valve 75 Reactive Compensation (Shunt capacitors) 14 Reactive power 34 Reactive power absorption 210 Reactive power compensation 26 Rectifier 87 Rectifier control 131 Reliability 28, 317 Requirements 239 Resistance electrodes 227 uniform earth 228 non-uniform earth 229 buried electrode 230, 233 spherical electrode 230 cylindrical electrode 233

electrode on shore 234 anitropic earth 237 contact 245 neutral 238 Resistivity earth 225 Resistance of the buried electrode 230, 233 Resistance of the Electrodes in Non-uniform Earth 229 Reverse blocking 42 RI noise 213 Rod gap 293 Surge arrester 297 Surge Zno 294 Volt-ampere characteristic 294 Power Law 294 Insulation design 296 Insulation Co-ordination 297 BIL 298 SIL 298 Safely 240 SCL 330 SCRs 51 Sea/Underwater 252 Second order filters 202 Self-excitation systems 332 Series connection 49 Series connection of IGBT 56 Series controllers 341, 342 Shore electrode efficiency 236 Short circuit (SCR) Level 330 Short circuit level 330 Short Circuit Ratio (SCR) 2, 328 Shunt controllers 343 Single tuned filters 202 Six-pulse bridges 58 S. O. 355 Source of harmonics 175 Spherical electrode 230 Standard voltages 30 Standard voltages for HVDC 29 Starting 154 Start-up 155 STATCOM 346



Subject Index

Static Series Synchronous Compensator (SSSC) 342 Step potential 245, 246 String insulator 285 Submarine electrode 253 Surface gradient 234, 244 Surface potential gradients 244 Surge arresters 293 Surge impedance loading 25 Switching 288 overvoltage 288 System Interaction AC and DC 327, 333 Telephone Harmonic Form Factor (THFF) 201 Telephone Influence Factor (TIF) 201 Telephone interface 200 THFF 200 Thermal time constant 247 Three-level 58 Thury 2 Thyristor controlled reactor 345 Thyristors 5, 40 Thyristors valves 2, 64 TIF 200 Tolerable step voltage 246 Topology 216 Torsional vibrations 331 Touch potential 247 Transformer current 74

Transformer magnetisation 176 Transformer Volt-Ampere rating 74 Triggering 51 Turn-on 44 Two-level 58 Two-Transistor Model 44 Types of faults 262 Unified Power Flow Controller (UPFC) Uniform Earth 228 Upper Sileru 10 Valve 280 current 73 Valves and valve assembly 57 VDCOL 140 Vector Control 163 Vertical land electrode 253 Visual effects 323 Voltage dependent current order limits Voltage rise 243 Voltage stability 336 Volt ampere characteristic 294 VSC 215 VSC converters 162 Wind power 312 With variation of a and m World 11