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EMTP-RV Investigation of a Mho Relay Model for Protection of 500 kV Series Compensated Transmission Lines Abhaykumar Babulal Shah A Thesis In The Department of Electrical and Computer Engineering Presented in Partial Fulfillment of the Requirements For the Degree of Master of Applied Science at Concordia University Montreal, Quebec, Canada April 2009 © Abhaykumar Babulal Shah, 2009

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Page 1: EMTP-RV Investigation of a Mho Relay Model for … EMTP-RV Investigation of a Mho Relay Model for Protection of 500 kV Series Compensated Transmission Lines Abhaykumar Shah Extra High

EMTP-RV Investigation of a Mho Relay Model for Protection

of 500 kV Series Compensated Transmission Lines

Abhaykumar Babulal Shah

A Thesis

In

The Department

of

Electrical and Computer Engineering

Presented in Partial Fulfillment of the Requirements For the Degree of Master of Applied Science at

Concordia University Montreal, Quebec, Canada

April 2009

© Abhaykumar Babulal Shah, 2009

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1*1 Library and Archives Canada

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Bibliotheque et Archives Canada

Direction du Patrimoine de I'edition

395, rue Wellington OttawaONK1A0N4 Canada

Your file Votre reference ISBN: 978-0-494-63316-8 Our file Notre reference ISBN: 978-0-494-63316-8

NOTICE: AVIS:

The author has granted a non­exclusive license allowing Library and Archives Canada to reproduce, publish, archive, preserve, conserve, communicate to the public by telecommunication or on the Internet, loan, distribute and sell theses worldwide, for commercial or non­commercial purposes, in microform, paper, electronic and/or any other formats.

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The author retains copyright ownership and moral rights in this thesis. Neither the thesis nor substantial extracts from it may be printed or otherwise reproduced without the author's permission.

L'auteur conserve la propriete du droit d'auteur et des droits moraux qui protege cette these. Ni la these ni des extraits substantiels de celle-ci ne doivent etre imprimes ou autrement reproduits sans son autorisation.

In compliance with the Canadian Privacy Act some supporting forms may have been removed from this thesis.

Conformement a la loi canadienne sur la protection de la vie privee, quelques formulaires secondaires ont ete enleves de cette these.

While these forms may be included in the document page count, their removal does not represent any loss of content from the thesis.

Bien que ces formulaires aient inclus dans la pagination, il n'y aura aucun contenu manquant.

1+1

Canada

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ABSTRACT

EMTP-RV Investigation of a Mho Relay Model for Protection of 500 kV Series Compensated Transmission Lines

Abhaykumar Shah

Extra High Voltage (EHV) transmission lines are designed to transfer large

amounts of electrical power from one place to another. The lines being left open to the

environment (wind and bad weather) constitute a major reason for incidence of faults on

the lines. The stability of the entire power system is influenced by the occurrence of

faults on the high voltage transmission lines. Once a fault occurs on such a system, a

delay in clearing the fault is usually not allowable; therefore, protective relays are

installed to protect the lines. On the other hand, many methods have been investigated to

increase the power transfer capability of existing transmission line systems. Due to the

cost and environmental concerns, a number of series compensated lines and parallel lines

are being employed in power system. Series compensation has been widely used for

upgrading existing power systems to compensate for the inductive reactance of long

transmission lines. Adding series capacitors makes sense because they are relatively

inexpensive, simple and could be installed for 20% to 30% of the total cost of the

installation of a new transmission line. They can also provide the advantages of better

voltage regulation, increased system capability and reduced system losses.

This thesis presents the detailed development of a Mho distance relay model and

the residual current compensation in EMTP-RV. The Mho distance relay model is tested

iii

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for the protection of two parallel 500 kV, 280 km long transmission lines which are 40%

compensated by fixed series capacitors installed at their remote end. A current

compensation technique is used to compensate for the error and detects correct fault

location under earth fault conditions. The relay model detects faults by measuring and

comparing phase angles between two input (voltage and current) signals through a phase

comparator, using four specially shaped characteristics (three forward zones and one

reverse zone) and applying appropriate logic functions. This thesis presents the

simulation results of improving the measuring accuracy of distance protection under

various fault types, fault locations, fault resistances (Rf) and MOV reference voltages

(Vref). The proposed techniques provide protection at high speed and discriminate

between internal and external faults. The fault location based Mho distance relay works

satisfactorily in most cases.

Index terms: Series compensated line, distance algorithm, transmission line protection,

EMTP-RV, simulation, current compensation

IV

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ACKNOWLEDGEMENTS

First of all, I would like to express my gratitude and deep appreciation for Dr.

Vijay K. Sood for the supervision of this work. His intellectual advice and

encouragement, extraordinary experience and knowledge, freedom of work, patience and

financial assistance in the preparation of this thesis is thankfully acknowledged.

For being a wonderful supervisor, I would like to thank Dr. Venkat

Ramachandran for his comments and financial support throughout this research.

I would also wish to thank Dr. Donald McGillis for providing helpful comments

and guidance for the completion of this manuscript. My hearty thanks to Omar Saad,

Lewis Vaughan, Venkatraman Sundharesan and Jacobson David for their useful

suggestions. Kind acknowledgments are conveyed to my closest and dearest friend

Nikunj Shah for his moral support, unselfish friendship and helpful suggestions and

discussions when needed.

I am greatly indebted to my wife Rupal Shah and children Parshva Shah and

Dhiya Shah for their continued loving support, inspiration, patience and encouragement

to compete this research project. Special thanks to my parents, my in-law and all other

family members and friends who helped in making this project.

v

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With honour and love, dedicated to

my beautiful wife Rupal Shah,

my dear children Parshva Shah and Dhiya Shah and my family.

You are the inspiration of my life.

VI

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TABLE OF CONTENTS

LIST OF FIGURES xi

LIST OF TABLES xv

LIST OF ACRONYMS xvi

CHAPTER-1 INTRODUCTION 1

1.1 THE NECESSITY FOR PROTECTION [1-4] 1

1.2 OBJECTIVE OF THE THESIS 2

1.3 METHODOLOGY 3

1.4 EMTP-RV: OVERVIEW [5-6] 3

1.5 LITERATURE REVIEW 4

1.6 OUTLINE OF THE THESIS 7

1.7 SUMMARY 9

CHAPTER - 2 POWER SYSTEM PROTECTION 10

2.1 INTRODUCTION 10

2.2 BASIC PROTECTION REQUIREMENTS [26] 12

2.3 TRANSMISSION LINE FAULTS 13

2.3.1 Causes of Faults [2, 4] 15

2.3.2 Effects of Faults [2, 3, 4] 16

2.4 THE IMPORTANCE OF A PROTECTION RELAY 16

2.4.1 Connection of Protective Relay 17

2.4.2 Tripping Arrangement 19

2.5 CLASSIFICATION OF PROTECTIVE RELAYS 19

2.5.1 Over Current Relay [2, 3, 27] 19

2.5.2 Differential Relay [3, 4, 27] 20 vii

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2.5.3 Distance Relay [1 - 4, 27] 20

2.5.4 Directional Relays [4] 25

2.6 AUTO-RECLOSING [2, 31] 26

2.6.1 Single-phase Auto-reclosing 26

2.6.2 Three-phase Auto-reclosing 27

2.6.3 Single-shot Auto-reclosing 27

2.6.4 Multi-shot Auto-reclosing 27

2.7 SUMMARY 28

CHAPTER-3 SERIES COMPENSATION 29

3.1. INTRODUCTION 29

3.2 THE PURPOSE OF SERIES COMPENSATION 30

3.3 THE COMPENSATION DEGREE AND LOCATION 31

3.4 TRANSMISSION LINE WITH SERIES COMPENSATION 32

3.5 PROTECTION SCHEMES FOR THE SERIES CAPACITORS 33

3.5.1 Single-Gap Protection Scheme Device 34

3.5.2 Dual-Gap Scheme Device 35

3.5.3 Zno Scheme Device 36

3.6 RELAYING PROTECTION PROBLEMS ASSOCIATED WITH SERIES CAPACITORS COMPENSATION [1,26, 32] 38

3.6.1 Voltage Reversal (Voltage Inversion) 39

3.6.2 Current Reversal (Current Inversion) 41

3.6.3 Other Protection Problems 41

3.7 SUMMARY 43

CHAPTER-4 MODELING OF MHO RELAY 44

4.1 INTRODUCTION 44

viii

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4.2 CONVENTIONAL MHO RELAY MODELING 45

4.3 FAULT DETECTION (BLOCK A) 48

4.3.1 Data Acquisition 48

4.3.2 Calculation 50

4.3.3 Detection Circuit 52

4.4 ZONE AND FAULTY PHASE DETECTION (BLOCK B) 56

4.4.1 Zone Detection 57

4.4.2 Faulty Phases Detection 59

4.4.3 Time Delay 62

4.4.4 Zone Representation 64

4.5 LOGIC CIRCUIT (BLOCK C) 67

4.5.1 Logic Sequence 67

4.5.2 Reclosing 69

4.6 POWER SYSTEM TEST MODEL 71

4.7 SUMMARY 72

CHAPTER - 5 SIMULATION RESULTS 73

5.1 INTRODUCTION 73

5.2 SIMULATION STUDIES 74

5.2.1 Assessment of Relay under Permanent Fault 75

5.2.2 Assessment of Relay under Temporary Fault 115

5.3 SIMULATION RESULTS ANALYSIS 126

5.3.1 Permanent Faults 127

5.3.2 Temporary Faults 130

5.3.3 Capacitor and MOV Operation 131

ix

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5.3.4 Ground Faults for Different Fault Resistances 132

5.4 SUMMARY 133

CHAPTER-6 CONCLUSION 135

6.1 SUMMARY AND CONCLUSION 135

6.2 SUGGESTIONS FOR FUTURE RESEARCH 137

REFERENCES 139

APPENDIX-A MHO RELAY DATA 144

APPENDIX - B TRANSMISSION LINE DATA 146

APPENDIX-C RELEVANT DEFINITIONS [2, 4, 26] 147

APPENDIX - D LIST OF PUBLICATIONS 150

x

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LIST OF FIGURES

Figure 2.1: Zones of protection 11

Figure 2.2: Symmetrical faults (a) Three phase fault (b) Three phase-to-ground fault... 13

Figure 2.3: Unsymmetrical faults (a) Phase-to-Phase fault (b) One phase-to-ground fault (c) Two phase-to-ground fault (d) Single open conductor (e) Two open conductors 15

Figure 2.4: Basic connections of a protective relay 17

Figure 2.5: Tripping arrangement 19

Figure 2.6: Operating principle of the distance relay 21

Figure 2.7: Characteristic of impedance relay 22

Figure 2.8: Characteristic of reactance relay 22

Figure 2. 9: Characteristic of Mho relay 22

Figure 2.10: Stepped time-distance characteristics for three zone protection 24

Figure 3.1: Single-line diagram of a series compensated transmission line 32

Figure 3.2: Single-line diagram of aparallel transmission line 33

Figure 3.3: Single-gap scheme device model 35

Figure 3.4: Dual-gap scheme device model 35

Figure 3.5: Zno scheme device 36

Figure 3.6: Typical MOV voltage-ampere characteristic 37

Figure 3.7: Mid-compensated line with fault 39

Figure 3.8: Series compensated transmission line with line side measurement 40

Figure 3.9: Series compensated transmission line with source side measurement 41

Figure 3.10: (a) Line with 50% series compensation (b) Apparent impedance versus position of fault on line 41

xi

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Figure 4.1: Block diagram of conventional Mho relay model 45

Figure 4.2: Capacitor voltage transformer 46

Figure 4.3: Block diagram for fault detection model 48

Figure 4.4: Block diagram of data acquisition model 49

Figure 4.5: Magnitude transfer function v/s frequency for a band-pass filter 49

Figure 4.6: Single line diagram for voltage and current measurement 50

Figure 4.7: Block diagram for voltages and currents detection model 52

Figure 4.8: Compensation model 55

Figure 4.9: Polar multiplication 56

Figure 4.10: Zone and faulty phase detection model 57

Figure 4.11: Zone detection model 58

Figure 4.12: Faulty phase detection model 59

Figure 4.13: Block diagram to obtain the impedance trajectory for each phase 60

Figure 4.14: Phase comparator 61

Figure 4.15: Block diagram for time delay model 63

Figure 4.16: Timeout model 64

Figure 4.17: Zone representation 65

Figure 4.18: Zone characteristic 66

Figure 4.19: Block diagram for the logic circuit model 67

Figure 4.20: Logic sequence 68

Figure 4.21: Logic diagram for the reclosing model 69

Figure 4.22: Mho relay model 70

Figure 4.23: Power system model 71

xii

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Figure 5.1: Simulation power system model 73

Figure 5.2: Single phase-to-ground (a-g) fault (a) Trip signals for phases a, b and c (b) 3-phase currents in Line LI (c) 3-phase voltages in Line LI (d) Impedance (R-X) diagram (e) 3-phase currents in Line L2 (f) 3-phase voltages in Line 2 80

Figure 5.3: Two phase-to-ground (a-b-g) fault (a) Trip signals for phases a, b and c (b) 3-phase currents in Line LI (c) 3-phase voltages in Line LI (d) Impedance (R-X) diagram 83

Figure 5.4: Three phase-to-ground (a-b-c-g) fault (a) Trip signals for phases a, b and c (b) 3-phase currents in Line LI (c) 3-phase voltages in Line LI (d) Impedance (R-X) diagram 86

Figure 5.5: Single phase-to-ground (a-g) fault (a) Trip signals for phases a, b and c (b) 3-phase currents in Line LI (c) 3-phase voltages in Line LI (d) Impedance (R-X) diagram 89

Figure 5.6: Two phase-to-ground (a-b-g) fault (a) Trip signals for phases a, b and c (b) 3-phase currents in Line LI (c) 3-phase voltages in Line LI (d) Impedance (R-X) diagram 92

Figure 5.7: Three phase-to-ground (a-b-c-g) fault (a) Trip signals for phases a, b and c (b) 3-phase currents in Line LI (c) 3-phase voltages in Line LI (d) Impedance (R-X) diagram 95

Figure 5.8: Single phase-to-ground (a-g) fault (a) Trip signals for phases a, b and c (b) 3-phase currents in Line LI (c) 3-phase voltages in Line LI (d) Impedance (R-X) diagram 98

Figure 5.9: Two phase-to-ground (a-b-g) fault (a) Trip signals for phases a, b and c (b) 3-phase currents in Line LI (c) 3-phase voltages in Line LI (d) Impedance (R-X) diagram 101

Figure 5.10: Three phase-to-ground (a-b-c-g) fault (a) Trip signals for phases a, b and c (b) 3-phase currents in Line LI (c) 3-phase voltages in Line LI (d) Impedance (R-X) diagram 104

Figure 5.11: Single phase-to-ground (a-g) fault (a) Trip signals for phases a, b and c (b) 3-phase currents in Line LI (c) 3-phase voltages in Line LI (d) Impedance (R-X) diagram 118

Figure 5.12: Three phase-to-ground (a-b-c-g) fault (a) Trip signals for phases a, b and c

XIII

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(b) 3-phase currents in Line LI (c) 3-phase voltages in Line LI (d) Impedance (R-X) diagram 121

Figure 5.13: Single phase-to-ground (a-g) fault (a) Trip signals for phases a, b and c (b) 3-phase currents in Line LI (c) 3-phase voltages in Line LI (d) Impedance (R-X) diagram 124

Figure 5.14: Capacitor voltage (top), capacitor current (middle) and the MOV current (bottom) for phase a 131

Figure 5.15: Impedance diagram for single phase-to-ground (a-g) fault after capacitor with different fault resistance 132

XIV

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LIST OF TABLES

Table 4.1: Equations for phase-to-phase and phase-to-ground voltage and current measurements 51

Table 5.1: Permanent fault cases for relay assessment 76

Table 5.2: Analysis of the relay operation for permanent fault, fault resistance (Rf) = 20 Q and MOV reference voltage (Vref) = 200 kV 105

Table 5.3: Analysis of the relay operation for permanent fault, fault resistance (Rf) = 10 Q and MOV reference voltage (Vref) = 200 kV 106

Table 5.4: Analysis of the relay operation for permanent fault, fault resistance (Rf) = 5 Q. and MOV reference voltage (Vref) = 200 kV 107

Table 5.5: Analysis of the relay operation for permanent fault, fault resistance (Rf) = 0 Q, and MOV reference voltage (Vref) = 200 kV 108

Table 5.6: Analysis of the relay operation for permanent fault, fault resistance (Rf) = 10 D, and MOV reference voltage (Vref) = 100 kV 109

Table 5.7: Analysis of the relay operation for permanent fault, fault resistance (Rf) = 10 Q and MOV reference voltage (Vref) = 75 kV 110

Table 5.8: Analysis of the relay operation for permanent fault, fault resistance (Rf) = 10 Q and MOV reference voltage (Vref) = 5 kV HI

Table 5.9: Analysis of the relay operation for permanent fault, fault resistance (Rf) = 10 Q and different MOV reference voltages 112

Table 5.10: Analysis of the relay operation for permanent fault, MOV reference voltage (Vref) = 200 kV and different fault resistances (Rf) 113

Table 5.11: Analysis of the permanent fault for secure, unsecure and missing operation of the relay 114

Table 5.12: Analysis of the relay operation for temporary fault, fault resistance (Rf) = 10 Q, and MOV reference voltage (Vref) = 200 kV 125

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LIST OF ACRONYMS

HV

MV

EHV

UHV

EMTP-RV

BPA

IEEE

PR

CB

TCSC

GCSC

OC

OV

pu

PLC

CT

CVT

kV

kA

Hz

ms

High Voltage

Medium Voltage

Extra High Voltage

Ultra High Voltage

Electro Magnetic Transient Program-Restructure Version

Bonneville Power Administration

Institute of Electrical and Electronics Engineers

Protective Relay

Circuit Breaker

Thyristor Controlled Series Capacitor

Gate Controlled Series Capacitor

Over Current

Undervoltage

Per Unit

Power Line Carrier

Current Transformer

Capacitor Voltage Transformer

Kilovolts

Kiloamperes

Hertz

Millisecond

MOV Metal Oxide Varistor

XVI

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FACTS Flexible AC Transmission System

RO Zero Sequence Resistance of the Protected Line

Rl Positive Sequence Resistance of the Protected Line

LO Zero Sequence Inductance of the Protected Line

LI Positive Sequence Inductance of the Protected Line

Ictp, ^ Primary and Secondary Current Respectively of the CT

Primary and Secondary Voltage Respectively of the CVT

Impedance of the Line

Angle of the Line Impedance

Zone Delay Time

Compensation Current

Phase Current

Residual Current (Zero sequence current)

Conventional Average Compensation Factor,

Magnitude Compensation,

Angle Compensation

Resistance in Fault Path

Single Line-to-Ground (Single Phase-to-Ground)

Two Line-to-Ground (Two Phase-to-Ground)

Three Line-to-Ground (Three Phase-to-Ground)

ZR11, ZR12, ZR13 Reach Impedances of Zones 1, 2 and 3 Respectively

ZR1, ZR2, ZRla, kj, k2, ai , 012, 61, 02 Comparator Design Constants

» cvtp> »cvts

•Wangle

tzone

Icomp

tpn

Io

kc

K-mag

Krad

Rf

SLG

2LG

3LG

XVII

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C H A P T E R - l

INTRODUCTION

This thesis is concerned with power system protection. Protection is a key to the

successful operation of a power system which can be affectuated by the detection of

abnormal conditions and the initiation of appropriate remedial actions.

1.1 T H E NECESSITY FOR PROTECTION [i-4]

An electrical power system consists of generators, transformers, transmission

lines and substations. The purpose of the electric power system is to provide electricity in

a secure, reliable and economical manner. Electric power systems are one of the largest

and most complex systems ever built. Short circuit and other abnormal conditions

frequently occur on a power system causing the large short circuit currents that have the

possibility to damage equipment if suitable protective devices (protective relays, circuit

breakers) are not provided for the protection of each component of the power system.

In order to generate electric power and transmit it to customers, a huge amount of

money must be spent on equipment to develop the system and, therefore, it is essential to

protect it against accidents and abnormal conditions. Unfortunately, certain kinds of

faults are inevitable due to insulation deterioration or unforeseen events, such as lightning

strikes, entry of birds into the equipment and external bodies falling on the lines.

Protection systems are sets of equipment, schemes and policies dedicated to detect

faults on the protected elements of the power system. Protection systems minimize the

damage by locating the fault, isolating the faulty circuit and re-establishing the service.

1

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Protection systems must provide various equipment and schemes to detect and react to

most fault scenarios.

In general, protective systems monitor conditions, such as power in and out of a

bus or transformer bank, current flow, current unbalance, current at the both ends of the

line and frequency. If any abnormal condition occurs, the relay will sense such

abnormality and send a tripping signal to isolate the affected line or equipment.

In connection with the relay monitoring, there exists and is available a simulator

that can monitor the relay reading of current, voltage, power and frequency and convert

them into system parameters as time-dependent variables, such as di/dt, dv/dt, dp/dt and

df/dt.

The purpose of monitoring the system parameters is to provide an early-warning

system that indicates the development of a stressful condition in the vicinity of the relay

location and leads to the possibility of remedial action.

1.2 OBJECTIVE OF THE THESIS

Following are the major objectives of the work reported in this thesis:

1 To propose a generalized approach for the protection of a series compensated

transmission line by monitoring the variation in system parameters, such as

bus voltage and line current at the relay located at the beginning of the

transmission line.

2 To determine the zone of protection and location of a fault on the protected

transmission line from the information contained in the voltage and current

readings.

2

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3 To design a Mho relay and an appropriate algorithm for detecting and locating

transmission line faults.

4 To validate the dynamic performance of the proposed protective Mho relay

and algorithm with a typical system composed of two parallel 500 kV

transmission lines, compensated by fixed series capacitors installed at the

remote end of the lines, using the simulation package Electro Magnetic

Transients Program-Restructured Version (EMTP-RV).

1.3 METHODOLOGY

It is intended to use the EMTP-RV program to carry out the following functions:

1) To model the series-compensated two parallel transmission line installation,

2) To simulate the required performance,

3) To verify the required characteristics, and

4) To prepare a specification of the protection system

The expected results of the EMTP-RV simulations will be used to prepare a

general electrical specification of the protection system for tendering purposes.

1.4 EMTP-RV: OVERVIEW [5-6]

EMTP-RV was originally developed by the Bonneville Power Administration

(BPA), Portland, Oregon. This present version was developed at IREQ, Hydro-Quebec

under the agreement with the Direct Coordination Group (DCG). This program is widely

used in power utilities and research institutes for transients simulation studies around the

world, and is a circuit-based power system simulator. It will be used here for the study of

the protection of a series compensated transmission line and associated relay

3

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characteristics in this thesis. The EMTP-RV is the enhanced computational engine and

EMTPWorks is its new Graphical User Interface (GUI).

Power system networks can be modeled using EMTP-RV to represent practical

systems and large numbers of models are available in EMTP-RV for this purpose. These

models can be used for the steady state and transient state phenomenon simulation in

power networks. The power network can be modeled using voltage or current sources,

machines, multiphase circuits, distributed or lumped parameter line models and switches.

The simulated model can be used to represent a specified power system. There are

different subroutines in EMTP-RV that solve the mathematical equations and provide

solutions to such models. Another advantage of the EMTP-RV is that it can handle very

large and complex power system networks. Its uses include switching and lightning surge

analysis, insulation coordination and power electronic applications in power systems.

Further information about EMTP-RV can be obtained from the website www.emtp.com.

1.5 LITERATURE REVIEW

In order to acquire background knowledge of distance relaying, especially as it

relates to the protection of a series compensated transmission line, number of texts were

consulted. A brief discussion of some of the well known papers on this topic and other

related topics are presented below.

In 1990, F. Andersson and W. A. Almore presented a paper on the protection of a

series compensated line which covers a number of important topics in the study of this

complex problem. First, they checked the basic problems related to the capacitor-

compensated schemes. These problems included spark-gap flashover, distortion of the

apparent line impedance seen at the relay location, Metal Oxide Varistor (MOV)

4

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operation, voltage reversal, current reversal, power reversal in case of parallel lines, and

delayed impedance swing due to a low-frequency transient component. They provided a

graph which showed the apparent impedance of a single line with a fault at the far end

and also suggested using a band-pass filter to eliminate the high-frequency components

and low-frequency oscillations [7].

Several books and papers [8-11] have been published mentioning the overvoltage

protection of series capacitors used for the protection of series compensated transmission

lines. This overvoltage protection of the series capacitor consists of Metal oxide varistors,

spark gap etc. generally called a ZNO protection system. A. T. Johns and Q. Y. Xuan

presented a thyristor control series capacitor (TCSC) compensated EHV transmission

system [10]. E. H. Watanabe, L. F. W. de Souza, F. D. de Jesus, J. E. R. Alves and A.

Bianco developed a gate controlled series capacitor (GCSC): a new facts device for the

series compensated transmission lines [11].

In 2001, P. G. McLaren, K. Mustaphi, G. Benmouyal, S. Chano, A. Girgis, C.

Henville, M. Kezunvoic, L. Kojovic, R. Marttila, M. Meisinger, G. Michel, M. S.

Sachdev, V. Skendzic, T. S. Sidhu and D. Tziouvaras (working group CI of the Systems

Protection Sub-committee of the Institute of Electrical and Electronics Engineers (IEEE)

Power System Relay Committee (PSRC)) presented software models for relays. This

paper reviewed past and present uses of relay models and discussed the different types of

relay models, model validation processes and the information required to build such relay

models. It also provided the examples of present and possible future use of software

models [12].

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In 1981, R. J. Marttila proposed a new method of analysis of directional

characteristics of Mho distance relays using two-input comparators and tested with

different types of faults in 1981 [13, 14]. In 1997, he also presented the evaluation and

testing of distance protection for series compensated and adjacent lines with the use of a

fundamental frequency phasor model of the relays [22].

In 1985, Z. Peng, M. S. Li, C. Y. Wu, T. C. Cheng and T. S. Ning developed a

dynamic state space model of a Mho distance relay. Relay analysis is entirely based on

instantaneous values of the variables involved, thus becoming a general transient analysis

method [15].

In 1987, R. K. Aggrawal, A. T. Johns and D. S. Tripp proposed a high-speed

numerical method for series compensated transmission systems, based on the directional

comparison principle. In this method, communication channels extracted voltage and

current waveform information from both ends of the protected lines. The algorithm

evaluates this information and determines the location of the fault [16].

In 1987, M. S. Abou-El-Ela, F. Ghassemi and A. T. Johns implemented the phase

modified Fourier transform principle to estimate the impedance of the series compensated

transmission lines. The effect of resonance phenomena and series capacitor flashover was

investigated on the performance of distance relay [17]. In 1990, F. Ghassemi and A. T.

Johns modified the topology suggested in [17] and proposed a technique for eliminating

the source of error in measurement of phase-to-ground fault due to a residual

compensation factor [20].

In 1988, W. O. Kennedy, B. J. Gruell, C. H. Sinh and L. Yee proposed a new

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method of field testing cross and quadrature polarized Mho distance relays with three

different case studies [18, 19].

In 1992, D. W. Thomas and C. Christopolos developed an algorithm for series

compensated transmission systems based on travelling wave techniques. The algorithm

uses correlation techniques to identify transient components, which leave from the

relaying points and return to that point later after a direct reflection from the fault. The

location of the fault can be found from the departure and arrival timing of these signals at

the relaying point [21].

In 2004, A. Y. Abdelaziz, A. M. Ibrahim, M. M. Mansour and H. E. Talaat

proposed two approaches based on travelling waves and artificial neural networks (ANN)

for fault type classification and faulted phase selection of series compensated

transmission lines [23].

In 2006, D. McGillis, K. El-Arroudi, R. Brearley and G. Joos presented a new

approach to the process of system collapse based on areas of vulnerability. The relation

between the states of a system and the contingencies has been covered widely in this

paper. Three concepts, namely abnormal contingency, areas of vulnerability and systems

on the verge of collapse are combined to represent the process of system collapse [24].

In 2007, K. M. Silva, W. L. A. Neves and B. A. Souza presented the use of

distance relay EMTP model to evaluate the performance of distance protection schemes

applied to a three-terminal line of a 230 kV three-bus power network [25].

1.6 OUTLINE OF THE THESIS

This thesis is organized into six chapters and four appendices. A brief summary of

these six chapters and four appendices is given in this section.

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The first chapter (Introduction) provides information about the necessity of the

protection system, the objectives of this thesis, the methodology adopted and the

expected results, an overview of the simulation tool EMTP-RV and a literature review.

The second chapter (Power System Protection) summarizes present day power-

system protection philosophies. It begins with the basic requirements of the protection

system, various types of faults which occur in transmission lines, causes of the faults and

the effects of such faults. The importance of the protective relay in terms of protection

and different types of protective relays with their operating characteristics are also

explained in this chapter. Most of the faults in transmission lines are transient; therefore

the chapter describes various types of auto-reclosing schemes utilized in the protection of

transmission lines.

The third chapter (Series Compensation) deals with series compensation as part of

the new control technology of transmission systems (e.g. Flexible AC Transmission

System (FACTS)). This chapter explains the purpose of series compensation in

transmission lines, examples of transmission lines with series compensation and the

protection schemes for series capacitors. Relaying protection problems due to series

compensation at various locations are also explained in this chapter.

The fourth chapter (Modeling of Mho Relay) presents the design of the Mho relay

used in this project. The Mho relay model comprises three fundamental blocks and each

block is further divided into sub-blocks. The internal calculations and logic circuits for

associated blocks and sub-blocks are described for detecting and locating faults on a

transmission line. The residual current compensation algorithm for eliminating the source

of error for various earth faults is also explained in this chapter. This chapter also

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presents the 500 kV series compensated transmission line test system, modeled in EMTP-

RV to generate data for evaluating the performance of the proposed Mho relay and

algorithm.

A total of 294 simulation tests are carried out in the fifth chapter (Simulation

Results); to validate the operation of the Mho relay with 500 kV two parallel series

compensated transmission lines. Simulation tests are run in EMTP-RV by varying the

different parameters, such as fault types, fault locations, fault resistances and MOV

reference voltages. Results of some cases, achieved by processing the data in the

proposed Mho relay, are also discussed.

Finally, conclusions drawn from the work reported in the thesis along with the

future direction of the research is provided in chapter six.

Appendices A and B list the data for the relay and series compensated

transmission line model, respectively, to test the performance of the relay. Appendix C

presents the relevant definitions and Appendix D presents the list of publications.

1.7 SUMMARY

This chapter covers the following topics:

• A brief explanation of the necessity of protection for power systems to obtain

high efficiency under different abnormal conditions.

• An overview of the objectives of this thesis.

• A discussion about the methodology to carry out various functions with an

overview of the EMTP-RV is provided.

• A literature review and a summary of the outline of the thesis.

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CHAPTER - 2

POWER SYSTEM PROTECTION

This chapter deals with the basic characteristics of a reliable protection system

that responds to the disturbances that occur in the power system.

2.1 INTRODUCTION

The main goal of the power system is to generate, transmit and distribute

electrical energy to the different kinds of customers without obstruction, in an efficient,

economical and safe manner. To obtain these goals, power systems are divided into four

subsystems.

Generation: Convert different forms of energy such as nuclear, thermal etc. to electrical

energy.

Transformation: Convert the generated voltage to a convenient high voltage level for

transmitting and distributing electrical energy.

Transmission: Transmit electrical energy from the generation station to distant load

centres.

Distribution: Distribute electrical energy to the customers at a convenient voltage level.

Huge investments are involved in the modern electrical power system, therefore,

proper operation and protection of all subsystems is very important to reduce the

consequences of disturbances.

Each element of the power system requires a separate protection arrangement [2,

26], such as generator protection, transformer protection, transmission line protection,

distribution line protection, bus bar protection, etc. Fig. 2.1 shows the protection zones of 10

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a simple power system. The entire power system is divided into a number of zones of

protection, where each zone covers a single element of the power system. Adjacent

protective zones must overlap each other, so the entire power system is covered, and no

unprotected spots are left. Without overlap, no circuit breaker would trip if the fault

occurs at a boundary of the zone; thus overlap between adjacent zones cannot be avoided.

Generator Protection

Circuit Breaker

Transformer

— H.V. Switchgear Protection

Transformer Protection

*— EHV Switchgear Protection

Transmission Line Protection

EHV Switchgear Protection

Figure 2.1: Zones of protection.

Most of the time, the power system operates in a steady state, but temporary and

permanent faults occur occasionally in power systems due to human errors, aging and

natural calamities. An incident of a fault in the power system can cause loss of

synchronism, severe reduction in voltage, very high current flow and eventually loss of

revenue due to interruption of service; therefore, it is essential to protect the power

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system equipment to avoid such collapse and its related results. This is obtained by

protective devices, installed at various locations in the power system to detect faults and

initiate operation of the associated circuit breaker to isolate the faulted element from the

remaining system. Such protective devices are known as protective relays. In this thesis,

the focus is on the protection of series compensated transmission lines.

2.2 B A S I C PROTECTION REQUIREMENTS [26]

1. Selectivity or discrimination: Selectivity is the ability of a protective device to

isolate only the faulty section of the protection system. In other words, it is the

duty of the protective device to discriminate between faulty and normal

conditions.

2. Reliability: Reliability is the ability of the protective device to work properly

during the time it is in service. The protective device must operate reliably when a

fault occurs in its zone of protection. Reliability can be defined as:

(a) Dependability: This is the ability of the protective scheme to work correctly

if an internal fault (fault within the protected system) occurs, i.e. to remove

fault selectively.

(b) Security: This refers to the ability of the protection relay not to send a

tripping signal, if there is no internal fault.

3. Sensitivity: Sensitivity is the ability of the protection device to react correctly to

small disturbances.

4. Availability: Availability is defined as the protection device working properly

according to its service time. A high degree of availability is obtained by periodic

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maintenance, use of high quality electromechanical devices for the relays, self-

checking capability of modern protection relays etc.

5. Speed: As mentioned earlier, fast fault clearing is very important. The time

period from the fault inception to the protection relay sends a tripping signal to its

corresponding circuit breaker is the fault detection time, while the time period

between fault inception and fault clearing is referred to as fault clearing time.

Fault clearing time includes the tripping time and the time needed for the circuit

breaker to open. Modern circuit breakers open within approximately two to three

periods of the power frequency after receiving a tripping signal and high speed

breakers require only one and a half cycles of the fundamental frequency.

2.3 TRANSMISSION LINE FAULTS

Transmission line faults can be split into:

(a) Symmetrical faults

(b) Unsymmetrical faults

Symmetrical faults: Fig. 2.2 shows the symmetrical faults. A three-phase (3-0) fault is

called a symmetrical fault. Fig. 2.2(a) shows all three phases short circuited without

ground and Fig. 2.2(b) shows all three phases short circuited with ground.

a Fault

b (

c

9

1

i

i

— b

— c

9

Fault

f

«

(

-i

• i

i

(a) (b)

Figure 2.2: Symmetrical faults (a) Three phase fault (b) Three phase-to-ground fault.

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Unsymmetrical faults: Phase-to-phase (L-L) fault, single phase-to-ground (L-G), two

phase-to-ground (L-L-G) and single or two phase open circuits are unsymmetrical faults.

Fig. 2.3 shows different unsymmetrical faults.

Phase-to-phase (L-L) short circuit fault (Fig. 2.3(a)): A short circuit that occurs

between any two phases is called a phase-to-phase or line-to-line fault.

Single phase-to-ground (L-G or SLG) fault (Fig. 2.3(b)): A short circuit between any

one phase and earth is called a single phase-to-ground fault. It may be due to any line

conductor breaking and falling to the ground or failure of insulation between a phase

conductor and the earth.

Two phase-to-ground (L-L-G or 2LG) fault (Fig. 2.3(c)): A short circuit between any

two phases and the earth is called a two phase-to-ground or a double line-to-ground fault.

Single or two phase open circuit fault (Fig. 2.3(d) and (e)): Such faults occur when

one or two phase conductors break, cable or overhead line joints fail, the circuit breaker

or the isolator opens the phases but fails to close one or two phases, which means

breaking the conducting path. Unbalanced current flows into the system due to the

opening of one or two phases. Protective schemes must be used to deal with such

abnormal conditions.

Multiple or Simultaneous faults: Two or more (same or different type) faults that may

occur at the same or different points on a system simultaneously are known as multiple or

simultaneous faults.

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a

b -

c —

g - -

g

b —

g - -

Fault

~~1 (a)

Fault

a —

b -

c g -

b -

g -

Fault •— _4

(b)

Fault

3 Fault b *

c

g (c)

(d) (e)

Figure 2.3: Unsymmetrical faults (a) Phase-to-phase fault (b) One phase-to-ground fault (c) Two phase-to-ground fault (d) Single open conductor (e) Two open conductors.

2.3.1 Causes of Faults [2, 4]

Generally, faults are caused by conduction path failures due to a broken conductor

or by insulation failures that result in short circuits, which is dangerous because it may

damage power system equipment. The opening of one or more lines makes the system

unbalanced and it is generally not allowed in the power system operation. In transmission

and distribution lines, most of the faults occur due to lightning surges, power swings or

external bodies falling on the line, which create overvoltages. Such overvoltages cause

the short circuit by flashovers on the surface of insulators.

Short circuits also occur by tree branches or other conduction paths falling on the

overhead transmission lines. If the bodies of birds touch one of the phases and the

ground, then this also causes faults. Other reasons for faults on overhead lines are: ice

and snow loading, storms, earthquakes, abnormal loading, lightning strokes, etc.

Some faults occur due to faulty design or lower quality of components.

Sometimes circuit breakers may trip due to wrong connections, testing or maintenance

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work, defects in protective devices, etc. Hence, such faults can be minimized by using

higher quality components, improving system design and the proper operation and

maintenance of equipments.

2.3.2 Effects of Faults [2, 3, 4]

Short circuits are the most dangerous types of fault and if they are not cleared,

may have the following effects on a power system:

1. Heating of rotating machines due to unbalancing the supply current and voltage.

2. Loss of industrial loads due to reduction in the healthy feeder supply voltage.

3. A heavy short circuit current may damage equipment or other system components

due to overheating and high mechanical force.

4. Fire hazards may occur due to the arcs associated with short circuits. If a fault is

not cleared quickly, then there is a chance of fire extending to other system

components.

5. There is a chance of loss of system stability; individual generators may lose

synchronism resulting in a complete power system shutdown.

6. Loss of revenue due to the interruption of consumers supply occurred by above

faults.

Good quality, high speed and reliable protective devices are necessary in the

power system to reduce the effects of faults and other abnormal conditions.

2.4 THE IMPORTANCE OF A PROTECTION RELAY

The most important equipment used for the protection of power systems are

protective relays. These are the most economic, well-known and flexible devices that

provide fast, reliable and inexpensive protection. Reliability, sensitivity, high speed

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operation and selectivity are the most desirable qualities of a protective relay. A

protective relay is a device which responds to abnormal conditions on an electrical power

system to control a circuit breaker, so as to isolate the faulty section of the power system

with minimum interruption to the existing service. To achieve this function, the relay

must be able to decide promptly which circuit breakers are to trip in order to isolate only

the faulted section.

Protective relays recognize and locate faults by constantly measuring electrical

quantities, such as current, voltage, frequency and phase angle from the power system at

the relay location. These quantities will change between normal and abnormal conditions.

It is necessary to provide relays responding to more than one of these quantities, because

the fault current with minimum generation may be less than the load current during

maximum generation and the power factor may be as low during a power swing as a

fault.

2.4.1 Connection of Protective Relay

b •

c •

Tripping direction

Circuit Breaker \ \ \

II o

Protected Circuit

Station bus

Trip Coil

Relay

1 ?T to m

J

Figure 2.4: Basic connections of a protective relay.

17

v-O L * J <AJ 3 g on on on | |

CD —

Secondary potential bus

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Basic connections of the protective relay are shown in Fig. 2.4. During normal

conditions the relay contacts are open. Whenever a fault occurs, the protective relay

contacts become closed and the relay controls the power supply to the protected circuit by

providing the signal to the trip coil of the circuit breaker. Due to a fault, when the

protective relay contacts are closed, the high L/R ratio of the circuit breaker trip coil

delays to the build-up of current, therefore, the circuit breaker is tripped quickly before

the current reaches its steady value. Due to only a few cycles duration of the circuit

breaker trip coil current, the relay contacts need a small continuous rating, such as only 5

amperes, and still operates a higher rating around 30 amperes circuit breaker trip coil

many times without maintenance [4].

Immediately after the circuit breaker has tripped by getting the signal from the

protective relay, its auxiliary switch "a" opens the highly inductive trip coil circuit. The

relay can be reset by opening of the circuit breaker. Relay contacts will be burned in a

bad way if the relay contacts are chattering when the current is flowing through it. For

proper operation, it is essential that the relay contacts do not chatter. This is obtained

either by seal-in-relay or by bounce-free designs. The reliability of protective relays

depends on their contact performance. Low contact resistance, freedom from corrosion,

high contact pressure, bounce-free, dust-proof, self-cleaning action and freedom from

sparking are the essential requirements of good contacts.

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2.4.2 Tripping Arrangement

Current Transformer

r Circuit J Breaker (c

^ Voltage j Transformer

Distance Protection

i '

Measuring Unit

i >

Trip Re lay

*'

Fault Detector

Reach Adjustment

Time Delay

0.4 Sec. i

Figure 2.5: Tripping arrangement.

Fig. 2.5 shows the basic tripping arrangement [1]. When a fault occurs in Zone 1,

the measuring unit and fault detector operate and tripping takes place without time delay.

For a fault beyond Zone 1 but within Zone 2, fault detector operates first and triggers the

time delay unit. After 0.4 sec. delay, the measuring unit is extended to Zone 2 values to

reach the fault location and provide tripping signal for Zone 2. If the fault is beyond Zone

2 but within Zone 3, the relay provides a tripping signal after 0.8 sec.

2.5 CLASSIFICATION OF PROTECTIVE RELAYS

There are different types of protective relays, but the most important relays are

classified here depending upon the operation they are required to execute, under the

headings of over current relay, directional relay, distance relay and differential relay.

2.5.1 Over Current Relay [2, 3, 27]

The protective relay, which operates when the load current exceeds a preset or

pick-up value is called an over current relay. Such a relay is used for less important

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circuits, such as distribution lines and large motors, where the cheapest relay is justified.

In such cases, only the local current magnitude is checked, so the relay is simple and

cheap. This method is possible in most low voltage distribution networks because the

short circuit current is large compared with the full-load current. These relays are also

used for back-up protection of transmission lines.

2.5.2 Differential Relay [3, 4, 27]

The basic principle for the operation of a differential relay is the circulating

current principle. Mostly these relays are used for the protection of generators,

transformers, bus zones and large size motors. This relay makes the direct comparison of

phase angle and magnitude for a current entering the machine and leaving it. To achieve

this, Current Transformer's (CT's) with suitable ratios are placed at both ends of the

protected equipment. Under normal conditions or external fault conditions, the current

entering and leaving the equipment is equal but during a fault condition it is not equal.

2.5.3 Distance Relay [1 - 4, 27]

The most important types of distance relay include impedance relay, reactance

relay, Mho relay, angle impedance relay, quadrilateral relay, elliptical and other conic

section relays.

In this thesis, Mho distance relay is used for the protection of a series

compensated transmission line.

Distance relay compares the local current with the local voltage in the

corresponding phase. Since impedance is equal to the ratio of voltage to current (Z=V/I),

the relay is known as an impedance relay. Distance relays measure the impedance or

some components of the impedance at the relay location. The measured quantity is

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proportional to the line length between the relay location and where the fault has

occurred. Since the impedance of the line is proportional to the distance along the line

length, it is called a distance relay.

The operating principle of the distance relay is shown in Fig. 2.6, It shows how a

relay is set for line impedance (Ziine). When a fault occurred in the transmission line, the

local voltage of the relay will be the IZ drop of the line [27]. The relay will not trip if the

fault is beyond the protected line section because V/I>Zune and if the fault is within the

protected line section, then it will trip because V/I < Ziine.

Source Impedance (Zs)

Line

mpedance (Znne)

Block Region

Trip Regioon

nternal Relay External fault setting fault

Figure 2.6: Operating principle of the distance relay.

A more useful way to draw the impedance relay characteristic is the R-X diagram,

which is shown in Fig. 2.7 [3]. As the relay characteristic is a circle, the relay operation is

independent of the phase angle between voltage (V) and current (I), but depends on the

magnitude of impedance (Z). The zone within the circle is the tripping zone of the relay

and the region outside the circle is a blocking zone.

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i X

Block /

_R 1 Tripping r* zone

-X,

i

J R

Figure 2.7: Characteristic of impedance relay.

X

/ Operating

Characteristic

"R -X

Block t

1 Trip

R

Figure 2.8: Characteristic of reactance relay.

Figure 2.9: Characteristic of Mho relay.

Instead of comparing local current I with local voltage V, sometimes it is

necessary to compare local current I with the component of V or V with the component

of I. For instance, one kind of distance relay operates when I>Vsin0, where 0 is the

phase angle between voltage (V) and current (I). Here ratio Vsin0/I = X (reactance) so, 22

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the relay measures the reactance of the line at the relay location and therefore distance

measurement is not affected by the fault resistance. Its characteristic in the R-X diagram

is a straight line and parallel to the R-axis as shown in Fig. 2.8. Such a relay is used for

ground faults and very short lines.

For long lines, the relay is more suitable when comparing V with a component of

I. In these cases, the relay measures the ratio V/Icos(0-6), where 0 is the phase angle

between V and I and 0 is the value of 0 for maximum sensitivity and hence the angle of

impedance circle relative to the R axis. This is called a Mho relay. Its characteristic in the

R-X diagram is a circle passing through the origin. It measures a component of

admittance |Y|Z0. It detects a fault only in one direction (forward direction); therefore,

Mho relay is inherently a directional relay. It is also called an admittance or angle

admittance relay. It is very selective between internal faults and any other conditions. Fig.

2,9 shows the characteristic of the Mho relay.

2.5.3.1 Three Zone Protection

Selectivity in a distance relay is provided by using different impedance reaches in

conjunction with different time delays associated with these settings. The combination of

an impedance reach and its associated time delay is known as a protection zone. The

incident of a fault within a protection zone of a distance relay must initiate and complete

the relay operation.

For three zone protection, usually three distance measuring units are required at a

particular location [1]. The setting value of each unit is expressed as a percentage of the

line length. Generally, the first unit is set to cover up to 80% to 90% of the protected line

length. This is known as the first zone protection. Its operation is high speed, about 1 to 2

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cycles and instantaneous, which means Zone 1 relay trips without any intentional time

delay and therefore used for the primary protection. This unit is not set to cover 100 % of

the entire protected line length to avoid undesirable tripping due to overreach which

means, it is normal to keep a margin for the relay of 10-15% to avoid overreach situation

and it is acceptable. Overreach may occur due to transients during fault conditions. Fig.

2.10 shows the stepped time-distance characteristics for three zone protection.

1 0)

E H-D) C

* — » CO CD O O v

A

7nnp ^ _ 1 , + 1 T <-d

Zone 2 = Li + C ).5L2

+ 0 95! Q

Zone 1 = 0.85 Li *

Li

Distance

L

T2 = 0.3 sec '

- •

<f

B

i

L 2

, T3 = 0.8 sec

r

c

*

L3

Figure 2.10: Stepped time-distance characteristics for three zone protection.

The second zone unit is to protect the rest of the protected line length which is not

covered by the first unit and also provide back-up to the adjacent line section which is up

to about 50% of its line length. The second unit should be adjusted in such a way that it

initiates the relay even for an arcing fault at the end of the protected line section. The

second unit has more time delay than the first unit and it is operated after a certain time

delay; the operating time is about 0.2 sec. to 0.5 sec.

The main objective of the third zone unit is to provide back-up protection for

faults in the adjoining line. It covers the protected line, plus the second line, plus 25% of

the third line. It is operated after a further time delay and the operating time is about 0.4

sec. to 1 sec. Zone 2 and Zone 3 have some intentional time delays added to coordinate

24

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with the relays at the remote bus, before providing an output. Time delays may vary

depending on the circumstances.

2.5.3.2 Comparators for Distance Protection

The phase angle between voltage and current as well as an amplitude of current

and voltage may alter during fault conditions; therefore, these quantities are not similar

during normal and fault conditions. The relay circuitry is developed to detect such

changes and discriminate between normal and faulty conditions. The section of the circuit

which compares two actuating quantities either in phase angle or amplitude is known as a

comparator. There are two types of comparators:

Phase comparator: A phase comparator compares the phase angle of two input

quantities, regardless of their amplitude, and the output appears when the phase angle

between them is lying within specified limits (< 90°). Examples are directional relays,

distance relays excluding impedance type relay and other phase comparison relays.

Amplitude comparator: One of the input quantities is an operating quantity and the

other is a restraining quantity. The amplitude comparator compares the amplitude of two

input quantities, regardless of the phase angle between them. The relay sends a tripping

signal when the operating quantity exceeds the restraining quantity. The function is

represented by a circle in the complex plane with its centre at the origin, which defines

the boundary of the operation. Examples are biased relays and impedance type distance

relays.

2.5.4 Directional Relays [4]

Impedance relay and over current relay are responses to the disturbance in either

forward or reverse direction. These relays are monitored by directional relay to prevent

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undesired tripping of unfaulted line. Directional relays respond only in one direction with

the current flowing from the bus to the line. Therefore, directional relays are used to

obtain directional sensitivity of the above mentioned relays. Directional relays are not

used for protection on their own but only increase the performance of the above

mentioned relays.

2.6 AUTO-RECLOSING [2, 31]

Continuity of service cannot be maintained by quickly eliminating the faulted

circuit from the remaining power system if faults are transient in nature. According to

statistical evidence, about 80% to 90% of faults on overhead transmission and

distribution lines are transient in nature and creates arcs. These arcs disappear if the

circuit breakers are tripped momentarily to achieve disconnection of the line. The

isolation of the line by opening the circuit breaker for a short time permits the arc to be

extinguished. Immediately after this, the line is re-energized again by reclosing the circuit

breakers automatically to minimize the service interruption and restore the power supply.

Reclosing the circuit breakers automatically is known as auto-reclosing.

2.6.1 Single-phase auto-reclosing

In a single-phase auto-reclosing, only the faulty phase pole of the circuit breaker

is tripped and reclosed, but at the same time, synchronizing power still flows through the

healthy phases. For any multi-phase fault, all the three-phases are tripped and reclosed

simultaneously. In this scheme, each phase of the circuit breaker is separated and

provided with its own tripping and closing mechanism. As compared to the three-phase

auto-reclosing scheme, this scheme is more costly and complicated because it requires a

more complex relaying scheme to detect and choose the faulty phase. The main drawback

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of this scheme is a longer de-ionization time of the arc; on the other hand, improvement

in transient state stability, system reliability and availability, and reduction of switching

overvoltages are the benefits of the single-phase auto-reclosing scheme.

2.6.2 Three-phase Auto-reclosing

In a three-phase auto-reclosing, all the three phases are tripped and reclosed

simultaneously for any types of fault. This scheme requires less de-ionizing time of the

arc; therefore, its relaying scheme is faster, easier and cheaper when compared to the

single-phase auto-reclosing.

2.6.3 Single-shot Auto-reclosing

Most of the faults on EHV lines are due to lightning or external objects (i.e. tree

branches, birds etc.) falling on the line. Due to the height of EHV lines, tree branches are

not expected to cause faults. If any objects are dropped by birds on EHV lines, they are

vaporized immediately because of the large amount of power in the arc. EHV lines need

only one reclosure. The reclosure should be made as fast as possible to avoid any

noticeable variation in phase angle between the open line voltages of the two ends. In a

single-shot auto-reclosing scheme, only one reclosure is made.

2.6.4 Multi-shot Auto-reclosing

For lines up to 33 kV, the disturbances might be caused by external objects, such

as tree branches falling on the line due to pole heights. External objects may not be burnt

at the first reclosure and may need additional reclosures. Three reclosures at 15 to 120

second intervals, are often made to clear the fault. According to statistical data, about

80% of faults are cleared after first reclosure, 10% of faults are cleared after second

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reclosure and less than 2% of faults require a third reclosure. If a fault is not cleared after

three reclosures, then this scheme indicates the fault is permanent in nature.

2.7 SUMMARY

The following points have been explained in this chapter:

• A discussion about the number of zones of protection to protect the each element

of the power system. These zones are overlapped to avoid any unprotected spots.

• The basic protection requirements, such as selectivity, sensitivity, speed etc. for

the protection of transmission line are discussed together with their definitions.

• Different types of symmetrical and unsymmetrical faults in transmission line are

presented. Reasons for causes of the faults and its effects in the power system are

also discussed.

• A brief overview about the importance of the protective relay, including its

connection strategy and tripping arrangement. This chapter also includes a

classification of various kinds of protective relays, depending upon the operation

they have to execute for the protection of power system including transmission

line. Operating characteristics of each relay are also presented.

• Necessity of auto-reclosing for transmission lines with different types of auto-

reclosing scheme is also described in this chapter.

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CHAPTER - 3

SERIES COMPENSATION

3.1. INTRODUCTION

In recent decades, series compensation has been widely used on power systems to

compensate the inductive reactance of a long transmission line. Adding series

compensation is one of the simplest ways of increasing transmission line capacity, power

transfer capability, system stability, lowering losses and improving voltage regulation. It

can maximize the usage of a transmission system by optimizing the sharing of real power

between alternative paths connected to the same busbars [17].

The advantages of series capacitors for the power system are well recognized and

difficulties for their protection are also well identified. Nowadays, utility companies have

difficulties in obtaining approval for new generation power plants and transmission lines

due to environmental concerns and the huge cost involved. Therefore, they must better

utilize their existing systems and provide better power quality at lower cost to the

consumer. To achieve these goals, the series compensation technique is being

increasingly used to compensate for the inductive reactance of long transmission lines. It

is evident that with the growing power system, more and more series compensated lines

will be put into the system. Finally, series compensation reduces the financial burden of a

utility company by not installing a costly additional transmission line.

Series capacitors are usually placed either at the middle or end of the transmission

lines. The range of series compensation is from 20 to 70 percent referred to the inductive

reactance of the transmission line. Today's technology on series compensation has been

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improved and there has also been improvement in capacitors and auxiliary equipment,

such as protective devices and signaling linkages. The recent or latest technology on

series compensation using capacitors involves MOV which improves the reliability of the

system and also shortens the time period needed for reinsertion of the capacitor into the

system after clearing the fault.

3.2 THE PURPOSE OF SERIES COMPENSATION

A literature review has shown wide spread application of series capacitors over

the past many years, mostly in the long-distance, high-voltage lines, such as the 500 kV

peace river development of British Columbia Hydro and 735 kV lines of Hydro-Quebec.

Capacitive reactance of the series capacitors compensates the inductive reactance of the

transmission line.

Series compensation reduces the number of required transmission lines for power

system development and also minimizes the cost by increasing the existing transmission

line capacity and power transfer capability. A particular case has been made for the use of

series capacitors in asymmetric operation where the series capacitors can be used in

single-phase operation of transmission line.

With respect to the 735 kV system of Hydro Quebec, series capacitors have

allowed the shunt reactors to remain in the system at all times since the reactive power is

supplied by the series capacitors, thus controlling the level of the temporary overvoltages.

This represents a novel application of series capacitors since it permits the transmission

system to cope with a three phase fault at any location.

As already noted, series compensation has been very effective in improving the

performance of power systems, especially for high-voltage systems. These applications

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have all used conventional fixed capacitor. For this purpose, varying capacitance is now

being introduced, as a FACTS device to increase the capacity of a power system without

limiting its security. The introduction of series compensation as a FACTS controller

basically involves varying the impedance of the static compensation to response to the

requirements of the power system usually for power flow control.

FACTS devices provide maximum advantage from their stabilized voltage

support when placed at the middle of the transmission line. In case of reactive power

control, the mid-point location is also most effective. When compared to the

uncompensated transmission line, the power transfer capability is increased to double for

the series compensated transmission line [33].

3.3 THE COMPENSATION DEGREE AND LOCATION

The ratio of the effective series capacitive reactance (Xc) to the series line

reactance (XL) is called the compensation degree [28].

Degree of series compensation = Xc / XL (3.1)

If the ratio is less than one then it is said to be undercompensated; if the ratio is

greater than one then it is said to be overcompensated, while if the ratio is unity then it is

completely compensated. Series capacitors are usually placed either at the middle or end

of the transmission lines. In power systems, usually the compensation degree is less than

70% as referred to the inductive reactance of the transmission line. For the line-end

arrangement, either located at one end or both ends, the compensation degree for each

end is usually 35% or less. For extra-high-voltage (EHV) systems, series capacitors are

basically used in the range of 100 to 1000 MVAr in size [29].

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3.4 TRANSMISSION LINE WITH SERIES COMPENSATION

As discussed earlier, series capacitors can increase the system stability, power

transfer capability and can also optimize the sharing of real power between parallel lines.

The series capacitors compensate the inductive reactance of the line so as to maximize

the power transfer capability in a long transmission line. A single-line diagram of a series

compensated transmission line is shown in Fig. 3.1.

Busbar A

Busbar A voltage Vi

Busbar B

XL Xc

Ps-

Qs-

Busbar B voltage V2

PR-

QR-

Figure 3.1: Single-line diagram of a series compensated transmission line.

The real power flowing towards busbar B without series compensation is [29]

PR = (VI * V2 / XL) * Sine (3.2)

and the real power flowing towards busbar B with series compensation is

PR = (VI * V2 / (XL - Xc)) * SinG (3.3)

Here, 6 is the phase angle difference between two busbar voltages V] and V2. It is

apparent that series capacitors can increase the real power transfer in a transmission line

by compensating the line inductance. The difference in phase angle between two busbar

voltages Vi and V2 can be reduced by keeping the real power transferred fixed. This will

increase the transient stability of the transmission line.

Fig. 3.2 shows the single-line diagram of a parallel transmission line system with

only one line using series compensation. In such a system, the flow of power is separated

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according to the impedance of the different transmission lines. The sharing of the power

flow in a transmission line is set by the impedance or length of each line section. In Fig.

3.2, Line CD] is longer than Line CD2, the difference in length between Line CDi and

Line CD2 has determined the condition of the power flow. If a series capacitor is placed

in Line CDi the power flow strategy (even if the line is longer) can be set by the

economic point of view.

Busbar C Busbar D

XLi Xc LineCDI rY~Y~Y~^\ I I

(With compensation) XL2

Line CD2 O ^ V ^ O (Without Compensation)

Figure 3.2: Single-line diagram of a parallel transmission line.

Finally when the line with the lowest power transfer capability reaches its limit,

the flow of power cannot be increased on other unsaturated lines, which leads to a waste

of money and power. Therefore, the power transfer capability of the complete system can

be increased with the help of series capacitors by rearranging the line impedance

distribution. With series compensation and neglecting line charging, the net transfer

impedance of the line is XL-Xc, where XL is the series line reactance and Xc is the

effective series capacitive reactance [28]. System losses can be reduced by the proper

distribution of current between the parallel transmission lines.

3.5 PROTECTION SCHEMES FOR THE SERIES CAPACITORS

Since series capacitors are established on a transmission line, they have to work in

harmony with other parts of the power system. In order to obtain this goal and protect the

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capacitors against damages, suitable protective devices as well as protection schemes are

required to ensure that the capacitors are bypassed effectively during fault conditions. On

the other hand, after clearing the fault, protection schemes have to reinsert the capacitors

into the system instantaneously. Three types of protective schemes, such as single-gap,

dual-gap and Zno have been developed for the protection of series capacitors.

3.5.1 Single-Gap Protection Scheme Device

The single-gap protection scheme device model is shown in Fig. 3.3. The

capacitor bank, airgap and bypass breaker are connected in parallel. The capacitor bank is

comprised of a number of capacitor modules which are in series or parallel. The capacitor

bank is designed for a certain voltage, which is usually 2 to 3 times the rated voltage or

current for a short duration. The rated capacitor current is usually chosen as the

maximum load current passing through the capacitor and the rated capacitor voltage is

the voltage across the capacitor when the maximum load current is passing through it. In

most cases, the fault current is three times greater than the load current. During a fault,

when the voltage across the capacitor bank reaches a particular level, the airgap Gl will

ignite. The airgap itself cannot usually take the fault current for a long time. This will

close the bypass breaker SI, which operates more slowly than the airgap so as to

extinguish the airgap consequently. When the voltage across the capacitor reaches to a

preset level, the bypass breaker will open and the capacitor will operate at the pre-fault

voltage level. After clearing the fault, a single-gap scheme takes 0.2 to 0.4 second to

reinsert the capacitors into the system. This delay is because of the airgap, which has to

cool down before reinsertion of the capacitor. Airgap and bypass breaker serve as a back-

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up protection. A damping circuit (inductor) between the airgap and the capacitor limits

the current flowing through the airgap when it fires.

CAPACITOR (C)

INDUCTOR AIRGAP

BYPASS BREAKER S1

Figure 3.3: Single-gap scheme device model.

3.5.2 Dual-Gap Scheme Device

CAPACITOR (C)

INDUCTOR AIRGAP

S2 - • 9-

AIRGAP

BYPASS BREAKER S1

Figure 3.4: Dual-gap scheme device model.

Dual-gap scheme model, shown in Fig. 3.4, uses an extra lower setting airgap G2

which can be isolated by opening a bypass breaker S2. The bypass breaker S2 is closed

during normal condition. Higher setting airgap Gl works as a back-up protection after the

capacitor insertion. When a fault occurs in the system, the voltage across the capacitor

will ignite the lower setting airgap G2, then bypass breaker SI will close before the

bypass breaker S2 opens. After the fault is cleared, bypass breaker SI will open and most

significantly, the lower setting airgap G2 has enough time to cool down. Operation does

not affected by the cooling of the airgap G2; therefore, reinsertion time of the capacitor

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can be effectively decreased. In dual-gap scheme, reinsertion of capacitors takes

approximately 60 milliseconds.

3.5.3 Zno Scheme Device

Zno scheme model is shown in Fig. 3.5, which is also known as Metal Oxide

Varistor (MOV), is placed directly parallel with the capacitor. The airgap, bypass breaker

and MOV provide total protection scheme for the capacitor. MOV is a nonlinear resistor

[18] and provides the main protection.

CAPACITOR (C)

a: O h-o z> Q

MOV

AIRGAP

BYPASS BREAKER S1

Figure 3.5: ZnO scheme device.

A typical voltage-ampere characteristic of the MOV is shown in Fig. 3.6 and it is

an important property of the MOV scheme. The voltage-ampere characteristic for the

MOV (Fig. 3.6) is approximated by equation 3.4 [30].

IMOV= P*[v /V R E F ] q (3.4)

Where, iMov and v = MOVs current and voltage, respectively

P = Reference current

VREF = Reference Voltage

q = Exponent of the characteristic

P and VREF are coordinates of the knee-point.

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V / V R £ F *

in pu 1 Q

iMov/P P u

Figure 3.6: Typical MOV voltage-ampere characteristic.

When a fault occurs and line current surges significantly higher than normal, then

there is a chance of damaging the capacitor. When the voltage across MOV is below a

threshold level then the MOV resistance appears to be very high. However, when the

voltage exceeds a certain level set for the device, the MOV resistance drops very rapidly

and acts to short the capacitor terminal to protect the capacitor. The resistance of the

MOV varies as the voltage on the capacitor terminals varies, thus the MOV operates with

respect to the type of fault and fault current level.

During a fault condition, the voltage across the capacitor will build up and a fault

current will pass through the MOV instead of capacitor, therefore, the capacitor will not

be damaged by high voltage and still will be working as a part of the system. The MOV

has a thermal limit and cannot withstand heavy currents for a long duration. During fault

condition, the energy absorbed by the MOV will be monitored and if it exceeds a certain

thermal limit, the airgap will ignite. The airgap protects the MOV when exceeding its

energy capacity. Again, if the duration of the fault current in the airgap reaches a certain

level, the bypass breaker SI will operate.

When the line fault is cleared, the capacitor reinsertion takes place without time

delay, which improves the system stability. The main benefit of the MOV is reinsertion

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time of the capacitor, which is nearly zero because the capacitor stays within the system

during most fault conditions.

3.6 RELAYING PROTECTION PROBLEMS ASSOCIATED WITH SERIES

CAPACITORS COMPENSATION [1, 26, 32]

As modern transmission systems become heavily loaded, the advantage of series

compensation for many transmission lines becomes more apparent. Capacitors with their

own protection are mostly used for series compensation, but they can reduce or weaken

the effectiveness of many of the protection schemes used for long distance transmission

lines. In order to determine the distance to the fault from the relaying point, the relay will

measure the ratio of voltage to current and decide whether the fault is either inside or

outside its zone of protection.

Placing the capacitance in series with line reactance adds a certain complexity to

the necessary application of impedance based distance relays. When it is known that the

capacitor is going to be a part of the fault circuit, then it is necessary to correct the relay

setting, but this is not always known. Relay settings are based on no capacitor in the fault

circuit, but when a capacitor is switched into the transmission line, it cancels some of the

line inductive reactance. Thus, series compensation can make the remote forward faults

appear in zone one of the relay and cause the relay to 'overreach'. Under these situations,

close-in faults can appear to be reverse faults. Since series compensation was introduced,

different protection problems on series compensated transmission lines have arisen.

These include voltage inversion, current inversion, self-excitation, negative damping,

sub-synchronous resonance, positive determination of whether the capacitor is involved

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in a fault loop or not, and successful calculation of the compensated line current for

phase-to-ground faults.

3.6.1 Voltage Reversal (Voltage Inversion)

If the effective reactance (impedance) from the relay location to the fault location

is capacitive rather than inductive, the fault current will lead the measured voltage. This

phenomenon is called "voltage reversal". In such a situation, the source voltage leads the

fault current. As a result, the voltage applied to the relay will be 180° out-of-phase, which

would be considered the "normal" position. Basically, distance relays are designed to

work on inductive systems. Distance relays are most affected by the voltage reversal

because they can lose their direction in steady state. The direction function can be

designed with compensating features to overcome the effect of voltage reversal. Voltage

reversal can have an adverse effect on the relay performance. To overcome the voltage

reversal problem, it is possible to reinforce the design of the capacitor application, such

that the net effective reactance from the relay location to the fault location is inductive

rather than capacitive.

3.6.1.1 Mid-Compensated Line

Fault F

I „ M X F

jXs ->—€ -

CM v

jXL1 *\ -jXc h jXL2 A

Figure 3.7: Mid-compensated line with fault.

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Fig. 3.7 shows the mid-compensated transmission line. An inductive impedance

will only be measured for a fault at point F where XLI+XF>XC, otherwise the relay will

see the fault as a reverse fault. In such a scheme, it is important to make sure that Xu and

XL2 are greater than Xc.

3.6.1.2 End-Compensated Line

The impedance measurement can be done on either the line side or the source side

of the series capacitor. It is very important to consider the choice of voltage and current

signals location for impedance measurement.

jXs l V H—i

-jXc JXi

Fault F

Figure 3.8: Series compensated transmission line with line side measurement.

When a measurement is taken from the line side of the capacitor, it does not

cause any problem for a forward fault on the line. But for the reverse fault shown in Fig.

3.8, just beyond the busbar, the impedance measure by the relay is inductive, which

means reverse fault will appear as a forward direction to the relay.

For the second case, when a measurement is taken from the source end of the

capacitor shown in Fig. 3.9, the impedance measurement is capacitive if Xc is greater

than XF, and inductive if Xc is less than XF. In the case of a fault point where Xc = XF,

the relay will see any fault to the left side of point F in a reverse direction because the net

reactance is negative.

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jXs

I V JXP Fault F

-jXc JXL

Figure 3.9: Series compensated transmission line with source side measurement.

3.6.2 Current Reversal (Current Inversion)

If the source reactance is lower than the compensation system capacitance, the

fault current will lead to the source voltage, which means the fault current will flow

towards the bus in case of internal fault and refuse to clear the internal fault. This

phenomenon is called "current inversion". From a protection point of view, it is

preferable for the series capacitor location and size to be selected such that the source

reactance is always larger than the capacitive reactance. When series capacitor is located

some distance away from the line terminal; it will reduce the chances of the source

reactance being lower than the capacitive reactance.

3.6.3 Other Protection Problems

Figure 3.10: (a) Line with 50% series compensation (b) Apparent impedance versus position of fault on line.

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Fig. 3.10(a) shows a line with 50% series compensation; in such a case, line

inductive reactance is jX and capacitive reactance is -j(0.5*X). Fig. 3.10(b) shows a

graph for apparent impedance versus position of fault on the line from the relay.

According to the graph, it is clear that when the relay has been set without series

compensation, then the relay will see many of the faults as reverse faults and will not

operate. In such a situation, a fault occurring at 125% of the line will appear as a Zone 1

fault. It must be necessary to look at another scheme to protect this line.

One approach is to slow down the operation of the relay so that the capacitor

overvoltage protection system in use, which consists of MOV, airgap and a bypass circuit

breaker will have time to operate and isolate the capacitor (or short circuit its terminal)

from the service. The Mho relay will function properly in such cases. Basically,

increasing the fault clearing time may lead to creating instability in the system.

A successful way to protect the series compensated line is by the use of phase

comparison relaying [38]. A phase comparison scheme compares the phase angle of the

current entering at one end with the phase angle of the current leaving at the other end of

the protected transmission line section and decide whether the fault is in the protected

line section or not. A communication channel compares the phase angles of the currents

between the protected line sections. A carrier signal is employed as a blocking pilot (the

carrier signal is used to prevent the relay operation). If the carrier signals from both ends

are 180 degrees or close to 180 degrees, this means no fault in the particular line section,

but if the carrier signal from both ends are in-phase, this means a fault occurs in the

particular protected line section. Communication links are basically costly to install and

also provide a weak link in a protection system.

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Out of these problems, voltage reversal has been a major problem for distance

protection due to the inductive current flowing through the capacitive impedance. From a

relaying point of view, the maximum magnitude of voltage reversal happens at a

measuring location directly adjacent to a capacitor installation.

3.7 SUMMARY

The following points have been explained in this chapter:

• Advantages of the series compensation using capacitors for power system

planning and operation to increase the power transfer capability of the

transmission lines.

• Different schemes for the protection of series capacitors against overvoltage,

which includes single-gap protection scheme, dual-gap protection scheme and

most importantly, Zno protection scheme or MOV scheme.

• A brief description about the location of series capacitors in the transmission line

and the degree of compensation obtained due to series capacitors.

• A brief explanation about various problems in the relaying protection due to the

installation of series capacitors for compensation in the transmission line.

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CHAPTER - 4

MODELING OF MHO RELAY

4.1 INTRODUCTION

A conventional Mho relay is modeled in EMTP-RV to investigate its behaviour

under different fault conditions at various locations in the 500 kV, 280 km long series

compensated two parallel transmission lines. The model of a conventional Mho relay is

comprised of three fundamental blocks: a Fault Detection Block, a Zone and Faulty Phase

Detection Block and a Logic Circuit. Each block has various sub-blocks. Distance relays

are basically used to protect high voltage, long transmission lines by detecting short

circuit faults on the protected line and thereafter initiating the remedial action by tripping

the circuit breakers related to the particular section of the line covered by the relay.

According to statistical evidence, a single phase-to-ground fault is the most

common fault experienced on a transmission line. Different algorithms and models have

been put forward to protect the transmission lines [34]-[48]. The Mho relay has a circular

operating characteristic with directionality, correct phase selection and easy criterion. The

coverage of the fault resistance is small, especially when the setting impedance of the

Mho relay is small. On the other hand, basically for heavy load and long line, the relay

has less stability, when the setting impedance is high. Whenever the earth resistance

increases, the Mho relay decreases its sensitivity and in the worst cases, refuses to trip.

Therefore, to overcome the earth resistance effect, it is an essential necessity to improve

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the sensitivity of the Mho relay. The stability (ability of the protection relay not to send a

tripping signal, if there is no internal fault) is also essential at the same time [49].

A transmission line demonstrates predictable impedance, which increases with the

length of the line. A distance relay has a pre-established impedance setting, which

determines the size of the relay's impedance characteristic, which is typically in the form

of a circle in the impedance (R-X) diagram and matched to the length of the line to be

protected by the relay. The distance relay is capable of detecting faults rapidly on the

transmission line; this means that the relay is capable of detecting faults when the

impedance of the line is inside the impedance (R-X) characteristic of the relay.

In this thesis, a Mho relay model based on the residual current compensation

algorithm is proposed. The operation boundary of the Mho relay can be adjusted to

provide consistent zone coverage over the area of interest.

4.2 CONVENTIONAL MHO RELAY MODELING

Input to the relay

From CVT 115V

# treset # # treclose #

Fault Detection Zone and Faulty Phase Block Detection Block

Logic Circuit Block

Amont_a Amont_b Amont_c

Zonel Zone2 Zone3 decl_a

decl b Phase_a Phase_b Phase c

decl c

Presencejr treset treclose

Output from the relay

Dec

Figure 4.1: Block diagram of conventional Mho relay model.

The block diagram of a conventional Mho relay model for a series compensated

transmission line is shown in Fig. 4.1. The Mho relay has two 3-phase inputs, (1) the 45

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three phase voltages from the capacitor voltage transformers (CVT's) and (2) the three

line currents from the current transformers (CT's), and provides one logical output which

gives a trip indication to the protection system.

(1) Capacitor Voltage Transformer: CVT's are used to step-down extra high voltage

signals and provide low voltage signals to operate a protective relay. A simplified

diagram of the CVT is shown in Fig. 4.2

High Voltage lerminal •

Cl =

C2 =

Ground _ Terminal

= L Transformer

" )

c Secondary C_ Terminals

Figure 4.2: Capacitor voltage transformer.

The CVT consists of three parts:

(a) Two capacitors (capacitive divider) which divide the voltage signal.

(b) A compensation coil L (inductive element) used to tune the device to the supply

frequency.

(c) An intermediate transformer used to isolate and further step-down the voltage for

the protective relay.

CVT's are single-phase devices used for measuring voltages in excess of one

hundred kilovolts where the use of ordinary voltage transformers would be expensive;

therefore, from a cost point of view, CVT's are more implemented in EHV lines [50]. In

practice, the first capacitor (CI) is often replaced by a stack of capacitors connected in

series, resulting in a large voltage drop across the stack of capacitors that replaces the

46

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first capacitor, and a comparatively smaller voltage drop across the second capacitor (C2)

and hence the secondary terminals.

The CVT has at least four terminals, a high voltage (HV) terminal for connection

to the high voltage signal, a ground terminal and one set (two) of secondary terminals for

connection to the protective relay.

(2) Current transformers: CT's are used to reduce the large current flowing in the

power system to a value low enough to suit the operation of the protective relay.

Reset time (treset): Most of the faults in the transmission line are transient, therefore,

after the reset time; the relay will check the status of the fault. If the fault is still there,

then the relay will trip the circuit breaker. If the fault has disappeared during that period,

then the relay will restore the line or service.

Reclose time (treclose): Most faults on EHV lines are caused by lightning, which means

the faults are transient in nature. Overvoltage caused by the lightning exists for a short

duration so, after the reclose time, the relay is used to reconnect the system to the normal

operation.

The Mho relay model is comprised of three principal blocks:

• Block A - Fault Detection Block,

• Block B - Zone and Faulty Phase Detection Block, and

• Block C - Logic Circuit Block.

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4.3 FAULT DETECTION (BLOCK A)

Calculation Detection circuit

Van Vbn Vcn

Ian Ibn Icn

Presence Ir

Figure 4.3: Block diagram for fault detection model.

Fig. 4.3 shows the block diagram for the fault detection, which has inputs from

the CVT and CT. Internal computations within this block provide both phase-to-phase or

phase-to-ground voltages and currents as outputs. The fault detection block has three sub-

blocks:

• Data Acquisition Sub-Block,

• Calculation Sub-Block, and

• Detection Circuit Sub-Block.

4.3.1 Data Acquisition

The basic block diagram of the data acquisition model is shown in Fig. 4.4. Input

voltages (Va, Vb and Vc) and input currents (la, lb and Ic) are filtered with a second

order band-pass filter to remove harmonics from the three phase voltages and currents.

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Band-pass filter: A band-pass filter passes frequencies within a certain range and

attenuates (rejects) frequencies outside that range, allowing signals between two specific

frequencies to pass through.

Va Vb Vc la lb Ic

f(u) K .

(1/3)*(u[1]+u[2]+u[3])

Va Vaf Vb Vbf Vc Vcf

laf Ibf Icf

lo lof

Band Pass Filter

Vaf Vbf Vcf laf Ibf Icf

K > iof

Figure 4.4: Block diagram of data acquisition model.

Fig. 4.5 illustrates the magnitude v/s frequency graph of a band-pass filter. The

lower and upper cutoff frequencies, fl and f2, are the frequencies at which the output

signal falls to 0.707 of the peak value. The range of frequencies between fl and fl is

called the filter pass band.

3

Bandwidth ,

Peak value

0.707 of the peak or gain-0.3 dB

fl = lower cutoff frequency £2 = upper cutoff frequency

fl fn a

Frequency

Figure 4.5: Magnitude transfer function v/s frequency for a band-pass filter. 49

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In this relay, the band pass filter has the following data:

Initial values: fn = 60 Hz and Zeta = 0.707

fn = Resonance (Tuned) frequency in Hz

Zeta = Damping ratio

Wn = 2*7t*fn

w„ = Resonance frequency in radians

If la, lb and Ic are the input currents, then the fraction of residual current (Io) is derived

as:

I0 = (l/3)*(Ia+Ib+Ic) (4.1)

The residual current, which is obtained from the above equation, is used to

compensate the phase current for the correct distance measurement.

4.3.2 Calculation

Inputs

Va Vb Vc

la lb Ic

~Wi

-EHi

u[1] - u[2]

f(u)

flu)

flu) >-

• ^ L f(u)

flu) >-

-3a f(u)

Outputs

- K > V a b

H X > Vbc

• — K > V c a

Van Vbn Vcn

K> lab

K> Ibc

K > lea

-£C> Ibn I en

Figure 4.6: Single line diagram for voltage and current measurement. 50

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The single line diagram of phase-to-phase and phase-to-ground voltage and

current measurements is shown in Fig. 4.6. Since a fault may or may not involve the

ground connection, input voltages and currents, after being filtered, are converted into

phase-to-phase and phase-to-ground values by the calculation sub-block. Since this sub-

block receives only phase-to-ground values, phase-to-phase values are obtained by

subtracting two voltages or two currents. Fig. 4.6, f(u) shows that the output is a function

of inputs; thus the output is the difference of the two input values (u[l] - u[2]). Table 4.1

provides the equations for phase-to-phase and phase-to-ground voltage and current

measurements.

Table 4.1: Equations for phase-to-phase and phase-to-ground voltage and current measurements.

Phase-to-phase

voltages

Vab = Va-Vb

Vbc = Vb-Vc

Vca = Vc-Va

Phase-to-ground

voltages

Van = Va-Vn

Vbn = Vb-Vn

Vcn = Vc-Vn

Phase-to-phase

currents

lab = la-lb

Ibc = Ib-Ic

lea = Ic-Ia

Phase-to-ground

currents

Ian = Ia-In

Ibn = Ib-In

Icn = Ic-In

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4.3.3 Detection Circuit

V a b [ Van

V b c l Vbn

VcaF Vcn

lab[ Ian [

IbcE Ibn

lca[ Icn

1° Ey

-tP ABS(u[1])>#seuil_lr#*#ln#

2 SUM D>—Min out> 1 &|l f(u) > -

EH in ou t^ -rms

—0)in oul"t>-rms

—EH in outt>-

f(u) b>

1 LJL.

f(u) b>

f(u) b>

rms (ABS(u[1]>1e-6)*(u[1]) u[2]>=u[1]

- C S >

SUM

~W2 Hin out>-

inst to phasor

-^ p ^j in out^——

instto phasor

1 ^2 h~7 iHi '1 °"'l>

Q Van

<IVbn

Q Vcn instto phasor

1 > Nin QUI): frini out)>—•{X]lan

inst to phasor

- ^ >——C?j in out ^"*"

instto phasor

- « i

1 out|>

inst to phasor

Select a

o Logic AND

Select b C o m p a

Comp_b

- Select_c Comp_e

- i - lo

•t>in2 phasoradd

•&firvi outb—^2lbn

phasoradd

•E>Trvi out[>—fXllcn PH> in2

phasoradd

> Presence Ir

Compensation

Figure 4.7: Block diagram for voltages and currents detection model.

Depending on the type of fault, this sub-block provides either phase-to-phase

voltages and currents or phase-to-ground voltages and currents as outputs. The block

diagram for voltages and currents detection is shown in Fig. 4.7. The selection is carried

out based on the current flowing through the circuit. During a fault condition, current in

each phase varies depending on the type of fault. The selection of the output is achieved

through an input selector control device.

Input selector: output = selected input. Selection is determined by the control signal

"select". The value of "select device" is trimmed to the (1, n), n being the number of

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inputs, in our case n=2. This control device selects one of the inputs (Vab or Van, Vbc or

Vbn, Vca or Vcn, lab or Ian, Ibc or Ibn, lea or Icn) as an output. A total of six outputs are

determined by the value of the selection control signal.

To get a control signal for ground faults, the sum of the three input currents are

carried out (Ian+Ibn+Icn) and the output value is fed to the RMS meter which calculates

the RMS value over a sliding time window of period (T=l/f). When the ABS (Absolute

value (output value = |w/?w?|)) of RMS meter current is greater than the product of seuil_ir

(reference current) and In (neutral current) then output is obtained from the function f(u).

Summation of the absolute value of the RMS output with constant value (1) is carried out

to get the signal "2" for "select device"; otherwise, "select device" will provide only

constant " 1 " as an output signal during normal condition.

The output voltage and the current of the input selectors are instantaneous values.

The instantaneous-to-phasor device converts the first harmonic of the instantaneous value

of a signal to a phasor representation. The phasor representation is a 2-signal bundle of

the polar coordinates (magnitude and angle) of the phasor. To obtain the actual distance

measurement for the series compensated line, in this thesis, the residual current

compensation algorithm is used. The complete process of the compensation algorithm is

explained in the next section.

4.3.3.1 Compensation

The impedance seen by the relay is given by the ratio V/I (=Z). An important

feature of designing a distance protection scheme is to select appropriate values of bus

voltage (V) and line current (I) signal, so that the impedance measurement and

computation by the relay during a fault condition is the positive phase sequence (p.p.s.)

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impedance from the relay location to the fault location [1]. The values of phase voltage

(V) and line current (I) are different with/without series capacitor in the transmission line.

Compensation methods are utilized to permit the relay to measure the p.p.s. impedance

from the relaying location to the fault location. The impedance measure by the relay is

influenced by the fault type and also by a number of power system parameters, such as

MOV rating, series capacitance etc. In this thesis, an algorithm called "residual current

compensation" is employed, where the compensation current (Icomp) is added to the phase

currents (Ipn) to derive corrected impedance measurements and finally, the distance from

the relay location to the fault location.

The basic circuit diagram for the compensation is shown in Fig. 4.8. After

compensation, the current seen by the relay for impedance measurement is given by:

Here, Icomp = kc*Io and Conventional average compensation factor (kc)= k ^ Zk d

2 2 Magnitude compensation (kmag) =

( R Q ~ R 1 ) + ( L 0 ~ L 1 ) (4.3) \ (R1)2+(L1)2

Angle compensation (krad) = tan"' f ( L 0 ~ L 1 ) | - tan"'(—) (4.4) ^R0-R1)J {RlJ

The residual current compensation algorithm uses a composite relay current signal

made up of faulted phase and compensation currents at the relay location. An

instantaneous residual current is converted into a polar representation (magnitude and

angle) by means of an instantaneous-to-polar conversion device. The parameters RO, LO,

Rl and LI are the zero and positive sequence resistance and inductance, respectively of

the protected line.

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Compensation_a

Select_a

10

Select b

kmag I c krad Lsl

Select c

Select

10 kmag krad

I0_comp' ( Comp_a

Compensation^

Select

10 kmag krad

I0_comp' I Comp_b

Compensations

Comp_c

Select K >

Compensation

10 K > <H i n m*>9 rad>

inst to polar

kmag [ krad [

n1_mag out_mag >— n1_rad out_radp— n2_mag n2 rad

—ti*

polar multiply

n_mag out >* IWH* t^| n rad

polar to phasor IO_Comp

Figure 4.8: Compensation model.

The output magnitude and angle from the residual current phasor and the kmag and

krad are obtained with the help of a polar multiplication device. Fig. 4.9 shows the single

line diagram for the polar multiplication. With this device, the output magnitude is

obtained by the product of two input magnitudes and the output angle is obtained by the

sum of two input angles.

out_mag = in 1 mag * in2_mag

out_rad = inljrad + in2_rad

If Zl and Z2 are the magnitudes and 01 and 92 are the angles, then:

Output magnitude = (zi|Z6l)*(Z2|Z02) = (zi|*|Z2|)zei+e2

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in1_mag in1 rad

in2_mag in2 rad

- E > 1 "C>2

PROD t> out_mag

-|X> out_rad

Figure 4.9: Polar multiplication.

Finally, this polar representation is converted into a phasor through a polar-to-

phasor conversion device and provides the compensation current for the faulted phase(s).

As shown in equation (2) that such compensation current is add with the phase current

and provide the appropriate current value, which is used to find the correct zone, faulty

phase(s) and finally distance to the fault.

Polar to phasor conversion: outmag = inmag

out_rad = in_rad

4.4 ZONE AND FAULTY PHASE DETECTION (BLOCK B)

After computations on the inputs received from Block A, the output from this

block provides information about the faulted phase(s) and the zone where the fault has

occurred. The block diagram for the zone and faulty phase detection model is shown in

Fig. 4.10. A total of nine outputs are obtained from this block: one each for Zones 1, 2

and 3, one each for the phases a, b and c, and three for reverse zone with respect to the

three phases a, b and c. Block B has four sub-blocks:

• Zone detection sub-block,

• Faulty phases detection sub-block,

• Time delay sub-block, and

• Zone representation sub-block. 56

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Zone Detection

Van Vbn Vcn[

Ian Ibn len

treset treclose

Van Vbn Vcn

Ian Ibn len

Amont_a Amont_b Amont_c

Zone1_a Zone2_a

Zone1_b Zone2_b

Zonelc Zone2 c

Van Vbn Vcn

Ian Ibn len

Ordrea Ordre_b Ordre c

Faulty Phase Detection

Time Delay Amont_a Amont_b Amont_c

Zone1_a Zone2_a

Zone1_b Zone2_b

Zone1_c Zone2 c

Ordre_a Ordre_b Ordre_c

treset treclose

Amonta Amontb Amontc

Zonel Zone2 Zone3

Phase_a Phase_b Phase c

Zone Representation

Amont_a Amont_b Amont_c

Zonel Zone2 Zone3

Phase_a Phase_b Phase c

Figure 4.10: Zone and faulty phase detection model.

4.4.1 Zone Detection

Phase comparators are employed for the zone detection. The 3-phase input

voltages and currents are fed to the phase comparators to detect the zone. Fig. 4.11 shows

the basic diagram for the zone detection sub-block. We know that V/I = Z and the

impedance of the line is proportional to the length of the line to be protected. During fault

condition, the impedance measured by the relay is given by:

z = • V.

pn

I p „ + k c * I „ (4.5)

The role of equation (4.5) is to keep Zr invariant with the types of faults, such as

Single Line-to-Ground (SLG), Two Line-to-Ground (2LG), Three Line-to-Ground (3LG)

etc. During a fault condition, the voltage and current values will change and, therefore,

57

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impedance will be affected. In this model, the faulty zone detection is carried out based

upon the difference in phase angles between two input quantities (Current and voltage)

through the phase comparator.

Van

VcnE

IcnR

Detection_Phase a

Detection Phase C

V Zonel . Zone2

Amont

Zone1_b Zone2_b Amont b

> Zbne1_c > Zone2_c ' Amont c

IE

Phase Comparator

Sequence

Phase Comparator

4v Sequence

Phase Comparator

Sequence!

Zonel

- |E> Zone2

-£g> Amont

Figure 4.11: Zone detection model.

Zone 1 primary impedance magnitude = Zonel *Zijne and

Zone 1 primary impedance angle, Zangie = tan"'(Ll/Rl)

Here, Zonel = 0.85 (85% of the protected line length), and

Zii„e = Length* V(R1)2+(L1)2 * — ^ CtS'

(Vcvtp/Vcvts)

I t and I . = Primary and secondary current, respectively of the CT, and

V + and V t = Primary and secondary voltage, respectively of the CVT

58

(4.6)

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The setting value of each zone is expressed as a percentage of the line length.

Normally, the first zone covers only up to 80% to 90% of the protected line length. The

second zone covers the remainder of the line left unprotected by the Zone 1 setting, plus

50% of the adjacent line section. The third zone is used for back-up protection and covers

the first and second line sections, plus 20% to 25% of the adjacent line. The output

signals are based on the each phase and zone such as Zonel_a, Zonel_b, Zone2_a etc.

For instance, if the fault occurs on phase a and Zone 2, then Zone2_a gives the output

signal for further processing and the other output signals provide a zero signal. During

this process, the relay can detect the zone where the fault has occurred.

4.4.2 Faulty Phases Detection

Impedance Trajectory

Van

lan[Xh

-i>Zxa

-l>Zya

Phase Comparator

Sequence_ Sequence

Impedance Trajectory

Vbn[

Ibn [

• M M | I

-E>Zxb

H>Zyb

Phase Comparator

Sequence_b Sequence

Impedance Trajectory

V c n ^ -

Icn g j -

Zx

zy

-£>ZXC

-OZyc

Phase Comparator

Sequence Sequence_c

Figure 4.12: Faulty phase detection model.

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The block diagram for the faulty phase detection model is shown in Fig. 4.12.

Phase comparators are employed for the faulted phase detection. The output of this sub-

block provides the sequence of phases a, b or c through the phase comparators and the

impedance trajectory of each phase in the impedance (R-X) diagram.

4.4.2.1 Impedance Trajectory

Fig. 4.13 shows the block diagram to obtain the impedance trajectory for each

phase in the impedance (R-X) diagram.

(t<=#period#)*#Zr_init_mag# +(t>#period#)*u[1] ^-f(t)

in1_mag out_mag in1_rad out_rad|> in2_mag in2 rad

polar divide

>-f(t)

ABS(u[1]) >= 5*#zline#

(t<=#period#)*#Zr_init_ang# +(t>#period#)*u[1]

-o\i m t>—

1± Hold

-Nmag x S -

-C>|rad yp~ polar to xy

Output value: is reset to reset value (rv) when reset control (rc)>0 else is held to output (t-deltat) when hold control (hc>0) else is value of input

Figure 4.13: Block diagram to obtain the impedance trajectory for each phase.

Three phase input voltages and currents from the previous block (Block A) are

fed to this sub-block, which converts a polar (magnitude and angle) representation of a

phasor or vector (voltage and current) to its (x, y) coordinates. Polar coordinates

(magnitude and angle) of the voltage and current (phases a, b and c) are fed to the polar

division device. This device divides two vectors or phasors represented by their polar

coordinates. The output of the polar division device is calculated as follows:

outmag = inl_mag/in2_mag

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out rad = inl rad - in2 rad

The output of the polar division device affects the mathematical operation f(u),

which gives an output as a function of its inputs, and that value passes through the hold

component. Here, if the hold control he is greater than 0, then the output maintains its

previous value and if the reset control re is greater than 0, then regardless of he, the

output takes the reset value rv. Finally, these polar representations convert into its (x, y)

coordinates through the polar-to-(x, y) conversion. This sub-block provides the

location/trajectory of each phase in the impedance (R-X) diagram. The necessary

conditions which need to be satisfied for the operation are shown in fig. 4.13.

4.4.2.2 Phase Comparator

Comparator* I c >

{(u[1]>-tialf_pi) AND

halfji))*(t>2,#pefiod#)

Output

Sequence

polar multiply

Figure 4.14: Phase comparator.

The block diagram for the phase comparator is shown in Fig. 4.14. A phase

comparator compares the two input quantities in phase angle and operates if the phase

angle between them is less than or equal to 90° [2]. If current is an operating quantity and

voltage is a restraining quantity, then the relay sends a trip signal when the operating

quantity exceeds the restraining quantity. It is important to determine the zone as well as 61

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the phase(s) for the protection line where the fault has occurred. The magnitude and angle

of the voltage and current are different during fault and normal conditions.

In this sub-block, the angle of two electrical quantities (current and voltage) is

compared to find out whether a fault has occurred in a particular phase. The necessary

conditions which need to be satisfied for the operation are shown in Fig. 4.14. The same

sub-block is used for two different purposes: one, to find the zone and the second, to find

the faulted phases. Typical values for the phase comparator design constant parameters

i.e. ki, k2, cii, (X2, 0i, 62, ZR1 and ZR2 are shown in the Appendix A.

4.4.3 Time Delay

Fig. 4.15 shows the block diagram for the time delay model. When signals about

the different zones and the different phases are received from the zone detection and

faulty phase detection block, they pass through a logical OR function to determine the

zone where the fault has occurred. This sub-block receives signals like Zonel_a, which

means Zone 1 of phase a; Zonel_b, which means Zone 1 of phase b; Zone2_a, which

means Zone 2 of phase a, etc. The zone involved in the fault is received through the

logical OR function, and the output signal is used for further processing.

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Zone2_a f Zone2_b < zone2 c )

Sequence, Sequence. Sequence,

Q> [delay | £ Detect

#tzone1#

-Ml

Timeout

#tzone2#

Ml O . , "o H Detect delay |

Timeout

Q> [delay | #tzone3#

In y £ Detect

Outputs

{>£> Amonta

{g> Amontb

Amontc

-K>Zone1

>Zone2

>Zone3

-£g>Phase_a

-{g>Phase_b

-)>?> Phase c

Figure 4.15: Block diagram for time delay model.

After the detection of the faulted zone, it is necessary to add the delay time before

getting the final signal. For Zone 1, the relay trips instantaneously. However, Zone 2 and

Zone 3 have some intentional time delays added to coordinate with the relays at the

remote bus, before providing an output. Zone 3 has more time delay than Zone 2. Most of

the faults in transmission lines are transient, so after a zone time delay, it is necessary to

provide the reset and reclose time to see the condition of the fault. This will allow the

relay to trip the circuit breakers or put the line back into service.

If reclose time is greater than the reset time, then the relay trips the circuit

breakers after the reset time, but if the reclose time is lesser than the reset time, then the

relay does not provide the trip signal after the reset plus the reclose time.

63

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4.4.3.1 Timeout

Inf Delay —W2

Output = time integral of input signal Output is limited dynamically (no windup) to low and high limits (see limits) Output is reset to reset value (rv) when reset control (re) is > 0.

treset F trecloset

— E > 1 — i > 2

— i > 3

((u[2]+u[3]>0)* (u[1]>(u[2]+u[3]»

—i>D E> CLK

—!>set —1> dear —!> toggle —t>hold

Q notQ

D flip-flop

Detect

Figure 4.16: Timeout model.

The block diagram for the timeout function is shown in Fig. 4.16. When the zone

and the faulty phases are decided, then it is necessary to determine whether the fault is

temporary or permanent before tripping the circuit breakers. This sub-block adds the time

delay based on the selection of zone, where the fault has occurred. After the zone time

delay and the reset time, the relay again checks the status of the fault (whether the fault is

still in the line or not). If the fault is not found then the relay puts the line back into

service but if the fault is found then the relay sends a signal to trip the three phase circuit

breakers and isolate the protected line.

4.4.4 Zone Representation

The zone representation function, which draws a distance relay characteristic on

an impedance (R-X) diagram. With internal mathematical calculations, this sub-block

decides the centers and radii of the circles on an impedance (R-X) diagram for different

zones (Zone 1, Zone 2, Zone 3 and Zone a) according to the data chosen for the system.

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Selected values for the different parameters are shown in the Appendix A. The basic

block diagram for the zone representation is shown in Fig. 4.17.

Inputs

#ZR11# #k1#

#theta1#

#ZR21# #k2#

#theta2#

#ZR12#

#ZR22#

#ZR13#

#ZR23#

#ZR1a#

#theta1a#

#ZR2a#

#theta2a#

c c c

c c c

c

^ c

c

c

c

c

c

c

v

Zonel Characteristic

ZR1

thetay

V " ) c. _y C*

k2 Cy theta2

Comparator

Zone2 Characteristic

ZR1

thetaV'

\ ^ * _ ^ c" k2 Cy theta2

Comparator

Zone3 Characteristic

ZR1

thetay

V c __J Cx k2 Cy theta2

Comparator

Zonea Characteristic

ZR1

thetay

\i ^ c _ y CA

ZR2 k2 Cy theta2

Outputs

Cx1

Cy1

Cx2

Cy2

Cx

Cy

Cxa

Cya

Figure 4.17: Zone representation.

4.4.4.1 Zone Characteristic

With selected input data, this sub-block provides the centers and radii of the

circles for different zones. Internal mathematical equations for Zone 1 are shown in Fig.

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4.18, which is identical for other zones. These circles pass through the origin and have

different radii for different zones. Each circle denotes a particular length of the line.

u[l]/(l*u[2]==0)+u[2])

ZR1 k1

thetal

ZR2 k2

theta2

~{>2 f(u)

- j>1 ~J>2

—&H -* f(u> (>-

mag x >-rad y >-

polar to xy

mag x b -l—Eslrad yp>-

polar to xy

{> mag x > {> rad y >

polar to xy

Circle Centre 0.5*u[1] Comparator in1_x out_x >-in1_y out_y >-

1^ in2_x i>| in2_y

W1 f(u)

OhJinL

xy add

Circle Radius -t>i -£>2 -t>3 -04

f(u) b-

0.5*SQRT((u[1]-u[3])A2 + (u[2]-u[4]r2)

u[l]+ C0S(64*pi*t)*u[2]

n«) >~K>Cx

SIN(64*pi*t)*u[2]

f(u) k-K>Cy

Figure 4.18: Zone characteristic.

The diameters of the circle are proportional to the impedance of the line or

indirectly the length of the line to be coved by each zone. The setting value of each zone

is expressed as a percentage of the total line length. For instance, if the length of the line

is 280 km and if Zonel=0.9 is selected, it means that circle 1 will cover 90% of the

protected line length. When a fault occurs within that area, this can be located within

Zone 1 circle in the R-X diagram.

After such a process, this device converts a polar (magnitude, angle)

representation of a vector or phasor to its (x, y) coordinates,

x = magnitude * cos(angle) and

y = magnitude * sin(angle).

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4.5 LOGIC CIRCUIT (BLOCK C)

Inputs

Amont_a Amont_b Amont_c

Zonel Zone2 Zone3

Phase_a Phase_b Phase_c

Presence ir

treset treclose

Logic Sequence Amont_a Amont_b Amont_c

Zonel Zone2 Zone3

Phase_a Phase_b Phase_c

Presencejr treset

Fire_a Fire_b Fire c

Reclosing

fire a decl a fire_b ~ g decl_b fire_c <g $ decl_c

Outputs

7S decl_a <S decl_b <*> decl c

Figure 4.19: Block diagram for the logic circuit model.

The output of this block determines the final decision of the relay for tripping a

circuit breaker based on the input data received from the previous block about different

zones and phases. If the fault is temporary and can be isolated within the reset time of the

relay, then this block will not send a trip signal. However, if the fault is permanent, then

it will send a trip signal for the circuit breaker. The block diagram for the logic circuit

model is shown in Fig. 4.19. The logic circuit has two sub-blocks:

• Logic sequence sub-block, and

• Reclosing sub-block

4.5.1 Logic Sequence

Fig. 4.20 shows the block diagram for the logic sequence. The signals of Zones 1,

2 and 3 from the previous block pass through a logical OR function, the output gives the

final zone decision and identify where the fault has occurred. Now, as information about

the zone and the faulty phase(s) are available, a logical AND function provides an output

based on the combination of faulted zone with faulted phase. 67

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Inputs

Zonel Zone2

Zone3

Amont_aE Phase a [

Amont_bR Phase bO

Amont_cD Phase cC

:E^=T>

11£J

Logic OR

Logic AND

Logic OR

& ^ > Logic AND

Logic OR

to Logic AND

Presence_lr [>0—

jgic NOT r ~ ~ = T "

Logic AND

-WD Q p -H> CLK 1 notQp—

—|> set i> clear

D flip-flop

WCLK .;' nolQ

—D* clear —W toggle

D flip-flop

— N D Q

NCLK f notQ

clear toggle hoW

D flip-flop

time step

Logic NOT Outputs

> Fire_a

Logic NOT

—[>-HE>

Logic NOT

^—P>—K>

Fire b

Fire c

Logic NOT

1 sc re rv

Sampler

u[1]>u[2]

d

Figure 4.20: Logic sequence.

Flip-flop: This device is an implementation of a D flip-flop with a rising-edge clock and

full override controls. The initial value of Q must be defined if the device is possibly

holding or toggling at t=0. When the device operates in clearing or setting mode at t=0,

the initial value is ignored. The three outputs from the flip-flop are entered into the

logical OR function and the output is used to obtain the control signal for the select

device, as well as to send a signal back to the flip-flop after the processing of the sampler

and if the condition (u[l]>u[2]) is satisfied. The logic sequence for the select device

operation is shown in Fig. 4.20. After getting the "select" control signal, the circuit

breaker receives the firing signal. Before firing, it is necessary to know whether the fault

is still present in the line or not. After the next sub-block, the final decision has been

taken by the relay. For "sampler", output value:

• Is reset to reset value (rv) when reset control (re) >0,

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• Else is selected sampling when sample control (sc) >0,

• Else is held to output(t-At)

4.5.2 Reclosing

(reset K > — ' — — — — —

trecloseE£>—

lire a g > -

Logic NOT \

Sampler

Sampler

Sampler

u(1]==0 OR u[]1>u[2]

u(1]==0OR u[]1>u[2]

\ V do« l i yb—

1 Logic NOT

D Q CLK ,. notQ

—N toggle

D flip-flop

time step

Logic NOT

^Sampler

u|2J>u[1]

U3>w

^Sampler

H'"' t^

(Ml2l/u[3))>u[1]>*1

p »h «.i p-

iLh—«—K

°EH

u[1)+u[2]+u[3]>=2

Logic NOT

Logic NOT

HP-

u(1]"0 OR u[)1>u[2l

Logic NOT

H>

Logic NOR

l T \ K > decl_a

Logk: NOR

Z ^ D * K>decl_b

Loge NOR

h j ^ » — K> *cl_c

Figure 4.21: Logic diagram for the reclosing model.

A single-phase auto-reclosing scheme is employed to detect the permanent or

temporary fault and its logic diagram is shown in Fig. 4.21. In a single-phase auto-

reclosing scheme, for single phase-to-ground fault, only the faulted phase pole of the

circuit breaker is tripped and reclosed. At the same time, synchronizing power still flows

through the healthy phases. For a multi-phase fault, all the three phases are tripped and

reclosed simultaneously. When the zone and faulted phase(s) are decided, then it is

necessary to determine whether the fault is temporary or permanent in nature before

tripping the three phase circuit breakers. Whenever this block receives the information

about zone and faulted phase(s) where the fault has occurred, the relay sends a trip signal

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for the faulted phase(s). The relay checks the status of the fault again after a reset time.

Depending upon the permanent or temporary fault, either the relay sends a trip signal for

the three phase circuit breakers or restores the line after reset time, respectively. The logic

sequence and mathematical equations for different devices are shown in Fig. 4.21. For the

relay operation, it is essential to satisfy all necessary conditions.

Fig. 4.22 shows the Mho relay model with three blocks and their sub-blocks.

CVT

i CT input to the

IE: relay

Data Acquisition Vpn I I Ipn

Calculation

Vppj vPn j jfoP jlpn Detection and Compensation

Vpp or Vpn

S Zone

Detection

Ipp or Ipn

Faulty Phase Detection

Zone Phase

Time delay and Zone representation

Zone with delay Phase selection

Logic Sequence

j Fire

Reclosing

Trip Signal

o o CO

00

o _o CO

o XL o a

CO

Figure 4.22: Mho relay model.

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4.6 POWER SYSTEM TEST MODEL

Numerous simulation tests were carried out in the power system test model as

shown in Fig. 4.23. The test system, modeled in the simulation package EMTP-RV [51],

is comprised of two 500 kV parallel transmission lines LI and L2. The line lengths are

indicated in the figure. The two lines are paralleled at Buses A, B and C. Series

compensation capacitors are located just ahead of the Bus B.

Ralay f Fault I

Figure 4.23: Power system model.

The series capacitors are protected by a parallel MOV, airgap and breaker. The

transmission lines are 40% compensated. Transmission Line LI of the power system is

protected with the Mho distance relay, which is placed at the beginning of Line LI, next

to Bus A. In order to evaluate the relay performance during different faults, in this thesis,

the EMTP-RV program is used to replay events and analyze problems. The relay

monitors the phase voltage and phase current through a CVT and CT, respectively.

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4.7 SUMMARY

The following points have been explained in this chapter:

• The conventional Mho relay is modeled in the EMTP-RV with three fundamental

blocks and sub-blocks to investigate its behavior under different fault conditions

at various locations.

• The residual current compensation algorithm is proposed to obtain the actual

distance from the relay location to the fault location.

• The description of the faulty phase detection and zone detection with its internal

calculations and basic block diagrams are included in this chapter.

• The single-phase auto-reclosure scheme is modeled with its internal calculations

to investigate the temporary and permanent faults.

• The zone representation and its characteristics, time delay circuit for different

zones and logic circuit to obtain the final decision for the tripping signal are also

explained in this chapter.

• The test circuit of the two 500 kV parallel transmission lines with 40% series

compensation located at the remote end of the protected line is modeled in the

EMTP-RV to investigate the behavior of the above mentioned relay.

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CHAPTER- 5

SIMULATION RESULTS

5.1 INTRODUCTION

In order to evaluate the performance of protective systems, the use of EMTP-RV

simulation provides a good understanding of both relay performance and power system

dynamics during transient conditions. The test system, comprising conventional Mho

relay model and 500 kV, 280 km parallel line, explained in the preceding chapter is

simulated to investigate the operating behaviour of the Mho relay model and distance

protection algorithm under different fault conditions at various locations on the protected

line. The simulated power network is depicted in Fig. 5.1 and its parameters are

summarized in Appendices A and B.

RELAY

C V TL

500 kV

CT

BUS A

F3

Line L1 . ,_.. _r

MOVj-c^z5-AIRGAPT-

BREAKER ~no/ LineL2 ' 4 0 %

Damping Circuit

280 km

s BUSB BUSC

220 km

Figure 5.1: Simulation power system model.

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Series capacitors are located at the end of the protected lines or just ahead of the

Bus B. The series capacitors, whose capacitive reactance Xc, equals approximately -39.2

Q, compensate for approximately 40% of the transmission line inductive reactance. The

Mho distance relay is placed at the beginning of Line LI, next to Bus A, and protects the

Line LI. The distance relay monitors the line current and phase voltage through a CT's

and CVT's, respectively. The relay operation and algorithm are checked for permanent

and temporary fault conditions with different cases, such as types of faults, fault

locations, fault resistances (Rf) and MOV reference voltages (Vref). Different

specifications of the faults are considered in the study. Although many simulations were

done, only a few representative results are shown next.

5.2 SIMULATION STUDIES

Using the developed EMTP-RV model, a number of fault cases have been

studied. A vast variety of the cases was obtained by changing the status of the fault

(permanent or temporary), type of fault, fault location, fault resistance (Rf) and MOV

reference voltage (Vref). A total of 294 fault cases were studied for parallel line operation.

The following changes were created in the power system model to investigate the

performance of the relay:

(a) Status of fault

(1) Permanent or (2) Temporary

(b) Type of fault

(1) Single phase-to-ground fault,

(2) Two phase-to-ground fault, and

(3) Three phase-to-ground fault.

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(c) Fault Location

Fault locations are shown in fig. 4.22, in which,

(1) Fault Fl is generated at the remote end after the capacitor bank,

(2) Fault F2 is created at the remote end but before the capacitor bank, and

(3) Fault F3 is created at the beginning of the protected line,

d) Fault Resistance (Rf)

(1)20Q (2) 10 Q (3)5Q (4) 0 Q,

(d) MOV Reference Voltage (Vref)

( l )200kV (2)100kV (3) 75 kV (4) 5 kV

In order to investigate the performance of the Mho relay model, a simulation of

the power system model (Fig. 4.22) is carried out with above mentioned changes. The

simulation study is divided into two parts: with either permanent fault or temporary fault.

5.2.1 Assessment of Relay under Permanent Fault

In this section, the distance relay performance for permanent fault is assessed

interactively under various fault types, fault locations, fault resistances (Rf) and MOV

reference voltages (Vref). The representation for operating time of the relay, trajectories of

impedances and 3-phase voltage and current waveforms are shown under different cases.

The fault occurs at time=0.06s, and the simulation is run for a total time period of 0.7s.

Table 5.1 shows that a variety of fault cases have been generated and used in testing the

behaviour of the relay and distance protection algorithm.

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Table 5.1: Permanent fault cases for relay assessment.

Fault type

SLG, 2LG and 3LG

SLG, 2LG and 3LG

SLG, 2LG and 3LG

SLG, 2LG and 3LG

SLG, 2LG and 3LG

SLG, 2LG and 3LG

SLG, 2LG and 3LG

Fault location

Fl,F2andF3

Fl,F2andF3

Fl,F2andF3

Fl,F2andF3

Fl,F2andF3

Fl,F2andF3

Fl,F2andF3

Fault resistance RfOhms

20

10

5

0

10

10

10

MOV VrefkV

200

200

200

200

100

75

5

The new distance protection algorithm was tested with the above test cases and

the following results were obtained for the relay. Figures 5.2 to 5.10 show the

representation of the three different types of faults at three various locations. Tables 5.2

to 5.5 show the analysis of the relay operation for 20 Q., 10 Q, 5 Q and 0 Q. fault

resistances, respectively, with 200 kV MOV reference voltage (Vref). Tables 5.6 to 5.8

show the analysis of the relay operation for 10 Q. fault resistance with 100 kV, 75 kV and

5 kV MOV reference voltages (Vref), respectively. The above mentioned tables include

different fault locations, fault types, operating time of the relay with delay, operating time

of the relay with delay and reset period and number of operating cycles with delay.

(1) Single phase-to-ground (a-g) fault at location Fl (280 km after capacitor)

Fig. 5.2 shows results from a permanent single phase-to-ground (a-g) fault placed

at 280 km from the relay, after the capacitor (at location Fl) with fault resistance (Rf) =

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10 Q and MOV reference voltage (Vref) = 200 kV. The fault occurs at time=0.06s, and the

simulation is run for a total time period of 0.7s.

Fig. 5.2(a) shows the trip signals for phases a, b and c. For phase "a" the trip

signal is generated after 0.3952s (including 0.3s Zone 2 delay). The relay checks the

status of the fault after 0.18s (reset time) and due to it being a permanent fault, all three

phase circuit breakers are tripped after 0.5928s.

Fig. 5.2(b) and (c) show the Line LI, 3-phase current and voltage waveforms,

respectively, measured at the relay location. When the fault occurs at 0.06s, the current

for phase "a" increases and at the same time voltage decreases. The relay trips the phase

"a" breaker at 0.3952s, therefore, no current passes through the phase "a". Due to a

permanent fault, after 0.18s (reset time), the relay trips the three phase circuit breakers at

0.5928s and the protected line is completely disconnected from the service.

The impedance (R-X) diagram (Fig. 5.2(d)) shows the 3 circles covering Zones 1,

2 and 3 and another smaller circle covering reverse zone operation. The impedance

trajectories for phases a, b and c are also shown. The trajectory of phase "a" indicates that

the fault involved phase "a" and is depicted by the Zone 2 circle.

Fig. 5.2(e) and (f) show the Line L2, 3-phase current and voltage waveforms,

respectively, measured at the beginning of the Line L2 near bus A. When the fault occurs

at Line LI, phase "a" current in Line L2 increases and the voltage decreases. High

current passes through the Line L2 after the Line LI is disconnected from the service.

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1.2

•a 0.6

t

Operating time of the relay - Phase a-to-ground fault

o.i

1 1 — . — i

Phase b Phase c

0.3952s I 1 i

t

i 0.5752s X

i

i

i ; 1; ii 1

i i i ;

ii ii

/ T ~~"_ __" 0.5928s

0.2 0.3 0.4

Time (Second) 0.5 0.6

(a)

0.7

(1) Phase a current

L z 1 ? 1 1

mwmm i \i«

0.5752s

f\ 0.06$ 0.3952s 0.5928s

0.1 0.2 0.3 0.4 0.5

(2) Phase b current

0.2 0.3 0.4 0.5

(3) Phase c current

0.6 0.7

0.6 0.7

J^ 0.06s

N. £!L

0.5928s-|

0.1 0.3 0.4 0.5

Time (Second) >•

(b)

0.6 0.7

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, l p u (1) Phase a voltage

'WW -2 L 0.06s

0.3952s

V V V V V V V V 0.5928s ,

D.l 0.2 0.3 0.4 0.5

(2) Phase b voltage

0.1 0.2 0.3 0.4 0.5

(3) Phase c voltage 0.6

0.3 0.4 Time (Second)

(C)

0.7

30 r

Impedance diagram

25 V

20

S 15 a O •S io

&

1 5 ^ 8 o

-5 -

-10

Zone 3 Zone 2

Phase a Impedance Trajectory

Zone 1

v Phase c Impedance Trajectory

Reverse Zone Phase b Impedance Trajectory

-15 L -10 5 10 15

Resistance (R) in Ohms

(d)

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Three phases current waveform for unfaulted line

0.3 0.4 Time (Second)

(e)

Three phases voltage waveform for unfaulted line

-Phase a -Phase b Phase c

0.2 0.3 0.4 Time (Second)

Figure 5.2: Single phase-to-ground (a-g) fault (a) Trip signals for phases a, b and c (b) 3-phase currents in Line LI (c) 3-phase voltages in Line LI (d) Impedance (R-X) diagram (e) 3-phase currents in Line L2 (f) 3-phase voltages in Line L2.

(2) Two phase-to-ground (a-b-g) fault at location Fl (280 km after capacitor)

Fig. 5.3 shows results from a permanent two phase-to-ground (a-b-g) fault placed

at 280 km from the relay, after the capacitor (at location Fl) with fault resistance (Rf) =

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10 Q and MOV reference voltage (Vref) = 200 kV. The fault occurs at time=0.06s, and the

simulation is run for a total time period of 0.7s.

Fig. 5.3(a) shows the trip signals for phases a, b and c. The trip signal for phase

"b" is generated after 0.0822s and for phases "a" and "c" is generated after 0.0852s. For

any two phase-to-ground faults, all three phases are tripped together and the relay does

not check the status of the fault after reset time, which means that faults of this kind

permanently trip the three phase circuit breakers once the relay senses the fault with this

relay model. The relay operates in Zone 1 instead of Zone 2 (overreach) due to the

capacitor and measured impedance at the relay location.

Fig. 5.3(b) and (c) show the Line LI, 3-phase current and voltage waveforms,

respectively, measured at the relay location. When the fault occurs at 0.06s, the current

for phase "a" and "b" increases and at the same time voltage decreases. The relay trips

the phase "b" breaker at 0.0822s and phases "a" and "c" breakers at 0.0852s, and the

protected line is completely disconnected from the service.

The impedance (R-X) diagram (Fig. 5.3(d)) shows the 3 circles covering Zones 1,

2 and 3 and another smaller circle covering reverse zone operation. The impedance

trajectories for phases a, b and c are also shown. The trajectory of the phases "a" and "b"

indicates that the fault involved phases "a" and "b" and is depicted by the Zone 1 circle.

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1.2 Operating tune of the relay - Phases a and b-to-ground fault

o.s

2 0.6

5 °-4

0.2

0.3 0.4

Time (Second)

1 - 1 i !

f : 1! 1 - u 11 :

m

Phase 1 i

3

Phase c

• 'f' ;

!! ;

i ; I !

f : o.iissis

o.0822s : ; i i i i !

(a)

(1) Phase a current

0.2 0.3 0.4 0.5

(2) Phase b current

0.2 0.3 0.4 0.5

(3) Phase c current

0.3 0.4

Tune(Second)

(b)

0.6

0.6

0.7

0.7

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(1) Phase a voltage

0.2 0.3 0.4 0.5 (2) Phase b voltage

0.06s 0.pS22s o.i 0.2 0.3 0.4 0.5 0.6

(3) Phase c voltage

0.3 0.4 Time (Second)

( C )

0.7

30

25

20

« 15 h

s a O io =

& 5

| 0

«

« -5

-10

-15

Impedance diagram

-20

Zone 2

Zone 1

Reverse Zone

Zone 3

^ P h a s e a \j^^ Impedance

Trajectory

Phase b Impedance Trajectory

Phase c Impedance Trajectory

-10 0 5 10 15 20 25

Resistance (R) in Ohms >• 30

(d)

Figure 5.3: Two phase-to-ground (a-b-g) fault (a) Trip signals for phases a, b and c (b) 3-phase currents in Line LI (c) 3-phase voltages in Line LI (d) Impedance (R-X) diagram.

83

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(3) Three phase-to-ground (a-b-c-g) fault at location Fl (280 km after capacitor)

Fig. 5.4 shows results from a permanent three phases-to-ground (a-b-c-g) fault

placed at 280 km from the relay, after the capacitor (at location Fl) with fault resistance

(Rf) = 10 D. and MOV reference voltage (Vref) = 200 kV. The fault occurs at time=0.06s,

and the simulation is run for a total time period of 0.7s.

Fig. 5.4(a) shows the trip signals for phases a, b and c. The trip signals for three

phases are generated after 0.0832s. The relay checks the status of the fault after 0.18s

(reset time) and due to the permanent fault, all three phase circuit breakers are tripped

after 0.2766s. The relay operates in Zone 1 instead of Zone 2 (overreach) due to the

capacitor and measured impedance at the relay location.

Fig. 5.4(b) and (c) show the Line LI, 3-phase current and voltage waveforms,

respectively, measured at the relay location. When the fault occurs at 0.06s, the current

for three phases are increased and at the same time voltage decreases. The relay trips the

three phase's circuit breakers at 0.0832s; therefore, no current passes through the

protected line. Due to a permanent fault, after 0.18s (reset time), the relay trips the three

phase's circuit breakers at 0.2766s and the protected line completely disconnects from the

service.

The impedance (R-X) diagram (Fig. 5.4(d)) shows the 3 circles covering Zones 1,

2 and 3 and another smaller circle covering reverse zone operation. The impedance

trajectories for phases a, b and c are also shown. The trajectory of the three phases

indicates that the fault involved phases "a", "b" and "c" and is depicted by the Zone 1

circle.

84

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1.2

0.8

o.a

0.4

0.2

Operating time of the relay - Three phase-to-ground fault

-0.2

! j

1 1 I

!

1

i ! I S

/ 0.0832s

0.2631

i

[T'l i \ •

i i : 1 ! i I :

! ^ •

1 1

;s j | 0.2766s

i

- r»i -

l'nase Phase Phase

i

a b c

0.1 0.2 0.3 0.4 Time (Second)

(a)

0.5 0.6 0.7

(1) Phase a current 1 pu

-2

0.0832s

IAA 0.06s 0.2632s 0.2766s , 0.1 0.2 0.3 0.4 0.5

(2) Phase b current

0.1 0.2 0.3 0.4 0.5

(3) Phase c current

2 -

S. °

0.1 0.2 0.3 0.4

Time (Second) 0.5

(b)

0.6

0.6

0.6

0.7

2

0

-2

t /1 \nl\l\ .

0.06s

0.2632s 1

^

,0.0832s

0.2766s

J ^ "

i i i i

0.7

0.06s

X pu

0.0832s

0.2632s

, 0.2766s

Y '• i i i i

0.7

85

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(1) Phase a voltage

a a.

0.0832

O.Q6s ":0.2766s 0.1 0.2 0.3 0.4

(2) Phase b voltage 0.6

S. °

0 .06s i 0 . 0 8 3 2 s , 0.2766s , 0.1 0.2 0.3 0.4

(3) Phase c voltage 0.5

0.06s 0.2766s

0.6 0.7

1

5 o

0 . 0 8 3 2 s 0.2 0.3 0.4

Time (Second)

(C)

0.6 0.7

Impedance diagram

Phase b Impedance Trajectory

0 5 10 15 20

Resistance (R) in Ohms >

(d)

Figure 5.4: Three phase-to-ground (a-b-c-g) fault (a) Trip signals for phases a, b and c (b) 3-phase currents in Line LI (c) 3-phase voltages in Line LI (d) Impedance (R-X) diagram.

86

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(4) Single phase-to-ground (a-g) fault at location F2 (280 km before capacitor)

Fig. 5.5 shows results from a permanent single phase-to-ground (a-g) fault placed

at 280 km from the relay, before the capacitor (at location F2) with fault resistance (Rf) =

\0 Q, and MOV reference voltage (Vref) = 200 kV. The fault occurs at time=0.06s, and the

simulation is run for a total time period of 0.7s.

Fig. 5.5(a) shows the trip signals for phases a, b and c. The faulted phase current

u[2] compared with the addition of input currents u[l], and the condition u[2]>=u[l] is

not satisfied, therefore, the relay fails to operate for single phase-to-ground fault. With

minor changes in the existing equation for the above comparison (u[2]>=0.8*u[l]), the

relay operates for all fault cases except higher fault resistance (20 £T).

Fig. 5.5(b) and (c) show the Line LI, 3-phase current and voltage waveforms,

respectively, measured at the relay location. When the fault occurs at 0.06s, the current

for phase "a" increases and at the same time voltage decreases. Higher current passes

through the protected line after the fault occurred at 0.06s.

The impedance (R-X) diagram (Fig. 5.5(d)) shows the 3 circles covering Zones 1,

2 and 3 and another smaller circle covering reverse zone operation. The impedance

trajectories for phases a, b and c are also shown. The trajectory of phase "a" indicates that

the fault involved phase "a" and is not depicted by any of the zone circle, which means

the relay fails to operate.

87

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1.2 Operating time of the relay - Phase a to ground fault

.S-e 0.4 ^

0.2

0.1 0.3 0.4

Time (Second) —

(a) (1) Phase a current

0.5

0.2 0.3 0.4 0.5 (3) Phase c current

0.3 0.4

Time (Second)

!' - • • 1 1

Relay fails

i i

to operate

- P h a s e a Phase b Phase c

(b)

88

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(1) Phase a voltage

/wwvwwwvwwwyvwwwvw 0.1 0.3 0.4

(2) Phase b voltage 0.5

0.3 0.4

Time (Second)

(C)

0.6

30

25

20

E 15 a O •S io

a 5

tf

-10

-15

Impedance diagram -i r

, Phase a Impedance Trajectory

Zone 3 / " N=,

Zone 2

Zone 1 \ ....

Phase c Impedance Trajectory

) , / " \

a v_ A

J

Reverse Zone Phase b,

Impedance Trajectory

_l l_

20 25 30 -10 -5 0 5 10 15

Resistance (R) in Ohms >

(d)

Figure 5.5: Single phase-to-ground (a-g) fault (a) Trip signals for phases a, b and c (b) 3-phase currents in Line LI (c) 3-phase voltages in Line LI (d) Impedance (R-X) diagram.

89

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(5) Two phase-to-ground (a-b-g) fault at location F2 (280 km before capacitor)

Fig. 5.6 shows results from a permanent two phase-to-ground (a-b-g) fault placed

at 280 km from the relay, before the capacitor (at location F2) with fault resistance (Rf) =

10 Q and MOV reference voltage (Vref) = 200 kV. The fault occurs at time=0.06s, and the

simulation is run for a total time period of 0.7s.

Fig. 5.6(a) shows the trip signals for phases a, b and c. The trip signals for three

phases are generated after 0.4476s (including 0.3s Zone 2 delay). For any two phase-to-

ground faults, all three phases are tripped together and the relay does not check the status

of the fault after reset time, which means that faults of this kind permanently trip the

three phase circuit breakers once the relay senses the fault with this relay model.

Fig. 5.6(b) and (c) show the Line LI, 3-phase current and voltage waveforms,

respectively, measured at the relay location. When the fault occurs at 0.06s, the current

for phases "a" and "b" increases and at the same time voltage decreases. The relay trips

the three phases circuit breakers at 0.4476s and the protected line is completely

disconnected from the service.

The impedance (R-X) diagram (Fig. 5.6(d)) shows the 3 circles covering Zones 1,

2 and 3 and another smaller circle covering reverse zone operation. The impedance

trajectories for phases a, b and c are also shown. The trajectory of the phases "a" and "b"

indicates that the fault involved phases "a" and "b" and is depicted by the Zone 2 circle.

90

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1.2

1

| O.S

C 0.4

0.2

0

Operating time of the relay - Phases a and b-to-ground F

i

i i i ; i

i i

| \ 0.4476s

|/1

I

fault

0.1 0.2 0.3 0.4

Time (Second) 0.5 0.6

(a)

0.7

(1) Phase a current

2

S o ^mimimi \\t\USL 0.4476s

P.06s 0.1 0.2 0.3 0.4 0.5

(2) Phase b current

0.6

0.2 0.3 0.4 0.5

(3) Phase c current

0.3 0.4 0.5 Time (Second) >

0.7

0.7

0.7

(b)

91

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(1) Phase a voltage

0.4476s

m \mmmwywM^f^mMh% p.06s

0.2 0.3 0.4 0.5

(2) Phase b voltage

0.3 0.4 Time (Second)

(C)

0.6 0.7

30

25

20

te 15

s a O io .5

J o « « -5

Impedance diagram

-10

-15

-20 -15

Zones ^<^L^\ l-j,.

Zone 2 ^ %/M' •" ^ ''•-

Zone 1 ^ / p **'•*

Phase b Impedance-Trajectory

Phase a " Impedance Trajectory

Reverse Zone

Phase c Impedance Trajectory

-10 0 5 10 15 20

Resistance (R) in Ohms > 25 30

(d)

Figure 5.6: Two phases-to-ground (a-b-g) fault (a) Trip signals for phases a, b and c (b) 3-phase currents in Line LI (c) 3-phase voltages in Line LI (d) Impedance (R-X) diagram.

92

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(6) Three phase-to-ground (a-b-c-g) fault at location F2 (280 km before capacitor)

Fig. 5.7 shows results from a permanent three phase-to-ground (a-b-c-g) fault

placed at 280 km from the relay, before the capacitor (at location F2) with fault resistance

(Rf) = 10 Q, and MOV reference voltage (Vref) = 200 kV. The fault occurs at time=0.06s,

and the simulation is run for a total time period of 0.7s.

Fig. 5.7(a) shows the trip signals for phases a, b and c. The trip signals for three

phases are generated after 0.2508s. The relay checks the status of the fault after 0.18s

(reset time) and due to the permanent fault, all three phase circuit breakers are tripped

after 0.4454s. The relay operates in Zone 1 instead of Zone 2 (overreach) due to fault

resistance, measured impedance at the relay location and parallel line operation. The

relay has a longer operating time due to the fault being detected near the boundary of the

characteristic.

Fig. 5.7(b) and (c) show the Line LI, 3-phase current and voltage waveforms,

respectively, measured at the relay location. When the fault occurs at 0.06s, the current

for three phases are increased and at the same time voltage decreases. The relay trips the

three phase's circuit breakers at 0.2508s; therefore, no current passes through the

protected line. Due to a permanent fault, after 0.18s (reset time), the relay trips the three

phase's circuit breakers at 0.4454s and the protected line completely disconnects from the

service.

The impedance (R-X) diagram (Fig. 5.7(d)) shows the 3 circles covering Zones 1,

2 and 3 and another smaller circle covering reverse zone operation. The impedance

trajectories for phases a, b and c are also shown. The trajectory of the three phases

93

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indicates that the fault involved phases "a", "b" and "c" and is depicted by the Zone 1

circle.

1.2

0.8

2 0.6 -

C 0.4

0.2

-0.2

Operating time of the relay - Three phase-to-ground fault

i 1 1 I

:' 1 i ; 1

1 : 1

j ; 0.4308s

i : \ : i

A : .

0.2508s

""1 | i j . . i i i

Phase b Phase c

• ' I " :

i ! ;

i ! :

j I | | | 0.4454s :

. i i / \ 1 \ / :

0.1 0.2 0.3 0.4

Time (Second) 0.5 0.6

(a)

0.7

(1) Phase a current

/ PUft s ' 0.2508s

M^m¥-—-x 0.06s , t 0.4398s

0.4454s

0.2 0.3 0.4

(2) Phase b current 0.5 0.6 0.7

1 pu

0.06s\,

0.4308s

kr- 1 2 ^ 0.2508s 0.4454s

0 0.1 0.3 0.4 0.5 (3) Phase c current

0.6 0.7

0.06s

pu

0.4308s 0.4454s

• * -

0.2508s 0.1 0.3 0.4

Time (Second)

(b)

94

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(1) Phase a voltage

0.2508s 0.4454s

ft(l(yV^AA/vAW^ 0.06s

0.1 0.3 0.4

(2) Phase b voltage 0.5

0.2 0.3 0.4 (3) Phase c voltage

0.5

0.3 0.4

Time (Second)

(C)

0.6

wiiw .OTW

0.06s ,

0.2508s

AAAAAAA/mlA A

^

0.4308s

AAAAAAA/VAAAAAAAAAAAA ;VVv VvvvvwvvvVVV\/\/lj\

0.4454s

1 1 1 11 1 i \l n

0.7

30 Impedance diagram

Phase b Impedance Trajectory

Phase c Impedance Trajectory

0 5 10 15

Resistance (X) in Ohms 30

(d)

Figure 5.7: Three phase-to-ground (a-b-c-g) fault (a) Trip signals for phases a, b and c (b) 3-phase currents in Line LI (c) 3-phase voltages in Line LI (d) Impedance (R-X) diagram.

95

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(7) Single phase-to-ground (a-g) fault at location F3 (Beginning of the protected

line)

Fig. 5.8 shows results from a permanent single phase-to-ground (a-g) fault placed

at the beginning of the protected line (at location F3) with fault resistance (Rf) = 10 Q,

and MOV reference voltage (Vref) = 200 kV. The fault occurs at time=0.06s, and the

simulation is run for a total time period of 0.7s.

Fig. 5.8(a) shows the trip signals for phases a, b and c. For phase "a" the trip

signal is generated after 0.0750s. The relay checks the status of the fault after 0.18s (reset

time) and due to it being a permanent fault, all three phase circuit breakers are tripped

after 0.2601s.

Fig. 5.8(b) and (c) show the Line LI, 3-phase current and voltage waveforms,

respectively, measured at the relay location. When the fault occurs at 0.06s, the current

for phase "a" increases and at the same time voltage decreases. The relay trips the phase

"a" breaker at 0.0750s, therefore, no current passes through the phase "a". Due to a

permanent fault, after 0.18s (reset time), the relay trips the three phase circuit breakers at

0.2601s and the protected line is completely disconnected from the service.

The impedance (R-X) diagram (Fig. 5.8(d)) shows the 3 circles covering Zones 1,

2 and 3 and another smaller circle covering reverse zone operation. The impedance

trajectories for phases a, b and c are also shown. The trajectory of phase "a" indicates that

the fault involved phase "a" and is depicted by the Zone 1 circle.

96

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1.2

O.S

a 0.6

38

= 0.4

0.2 -

Operating time of the relay - Phase a to ground fault

-0.2

! 1

- - ; - • • - - • • ; - -

0.2550s!

'• * .

0.0750s

\ i i

! |

I

I

i

V

1 1 !

__ Phas Phas

0.2601s!

/ ;

i i

e a e b e c

-

0.1 0.2 0.3 0.4

Time (Second) 0.5 0.6 0.7

(a)

(1) Phase a current lPuf\ 0.0750s

0.06s 0.2550s Ps ' 0.2601s 0.1 0.2 0.3 0.4 0.5

(2) Phase b current

0.2 0.3 0.4 0.5

(3) Phase c current

0.3 0.4

Time (Second)

(b)

0.6

0.6

0.7

s a.

10

0

-10

/ 1 P U

. 0.06s i

' • \

0.2601s 0.7

97

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(1) Phase a voltage 0.06s

0.3 0.4 0.5 (2) Phase b voltage

0.3 0.4 Time (Second)

(C )

0.7

30

25

20

15

Impedance diagram

0 io =

& 5

£ 0 « « -5

-10

-15

-20

Phase a Impedance Trajectory

Impedance / , - - ,r"y> /

Trajectory / / ' -i#

Reverse Zone Phase b' Impedance Trajectory

v xx \ V f/'|:;

::::..^'3>

-10 5 10 15

Resistance (R) hi Ohms 20 25 30

(d)

Figure 5.8: Single phase-to-ground (a-g) fault (a) Trip signals for phases a, b and c (b) 3-phase currents in Line LI (c) 3-phase voltages in Line LI (d) Impedance (R-X) diagram.

98

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(8) Two phase-to-ground (a-b-g) fault at location F3 (Beginning of the protected

line)

Fig. 5.9 shows results from a permanent two phase-to-ground (a-b-g) fault placed

at the beginning of the protected line (at location Fl) with fault resistance (Rf) = 10 Q.

and MOV reference voltage (Vref) = 200 kV. The fault occurs at time=0.06s, and the

simulation is run for a total time period of 0.7s.

Fig. 5.9(a) shows the trip signals for phases a, b and c. The trip signals for three

phases are generated after 0.0728s. For any two phase-to-ground faults, all three phases

are tripped together and the relay does not check the status of the fault after reset time,

which means that faults of this kind permanently trip the three phase circuit breakers once

the relay senses the fault with this relay model.

Fig. 5.9(b) and (c) show the Line LI, 3-phase current and voltage waveforms,

respectively, measured at the relay location. When the fault occurs at 0.06s, the current

for phases "a" and "b" increases and at the same time voltage decreases. The relay trips

the three phases circuit breakers at 0.0728s and the protected line is completely

disconnected from the service.

The impedance (R-X) diagram (Fig. 5.9(d)) shows the 3 circles covering Zones 1,

2 and 3 and another smaller circle covering reverse zone operation. The impedance

trajectories for phases a, b and c are also shown. The trajectory of the phases "a" and "b"

indicates that the fault involved phases "a" and "b" and is depicted by the Zone 1 circle.

99

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1.2

1

0.8

0.4

0.2

0

Operating time of the relay - Phases a and b-to ground !

! i !

" I " " - : I i

i i

" t " " : 1 |

1 /

0.0728s

_ . Phas

fault

e a eb

;

0.3 0.4

Time (Second) 0.6 0.7

(a)

(1) Phase a current

o.i 0.2 0.3 0.4 0.5

(2) Phase b current

0.6 0.7

/ p u . 0.0728s

-0.06s4 0.1 0.2 0.3 0.4 0.5

(3) Phase c current

0.3 0.4

Time (Second)

(b)

100

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(1) Phase a voltage

§,»

^.'0.0728s

S M» 0X.06s

1 '

in 1 L.

'

Will ,

H i >

1 -

0

-1 -

-2 0

0.2 0.3 0.4 (2) Phase b voltage

0.5

,4.06s

0.07,28s

0.3 0.4 0.5 (3) Phase c voltage

0.6 0.7

0.7

0.3 0.4

Time (Second)

(C)

0.5 0.7

25

20

15

Impedance diagram

M 10

S A O 5

a & o

tf -10 I

-15

-20

-25 -30 -20

Phase b Impedance^ Trajectory

Z o n e S ^ X ^ N

Zone 2 - — L ' / / T ' r .-• i A * / '

Zonel—\>i Xtf'"' -J/

Reverse Zone

Phase a Impedance Trajectory

Phase c' Impedance i Trajectory '

-10 0 10 Resistance (R) in Ohms

20 30

(d)

F igure 5.9: Two phases-to-ground (a-b-g) fault (a) Trip signals for phases a, b and c (b) 3-phase currents in Line LI (c) 3-phase voltages in Line LI (d) Impedance (R-X) diagram.

101

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(9) Three phase-to-ground (a-b-c-g) fault at F3 location (Beginning of the protected

line)

Fig. 5.10 shows results from a permanent three phase-to-ground (a-b-c-g) fault

placed at the beginning of the protected line (at location F3) with fault resistance (Rf) =

10 Q. and MOV reference voltage (Vref) = 200 kV. The fault occurs at time=0.06s, and the

simulation is run for a total time period of 0.7s.

Fig. 5.10(a) shows the trip signals for phases a, b and c. The trip signals for three

phases are generated after 0.0727s. The relay checks the status of the fault after 0.18s

(reset time) and due to the permanent fault, all three phase circuit breakers are tripped

after 0.2597s.

Fig. 5.10(b) and (c) show the Line LI, 3-phase current and voltage waveforms,

respectively, measured at the relay location. When the fault occurs at 0.06s, the current

for three phases are increased and at the same time voltage decreases. The relay trips the

three phase's circuit breakers at 0.0727s; therefore, no current passes through the

protected line. Due to a permanent fault, after 0.18s (reset time), the relay trips the three

phase's circuit breakers at 0.2597s and the protected line completely disconnects from the

service.

The impedance (R-X) diagram (Fig. 5.10(d)) shows the 3 circles covering Zones

1, 2 and 3 and another smaller circle covering reverse zone operation. The impedance

trajectories for phases a, b and c are also shown. The trajectory of the three phases

indicates that the fault involved phases "a", "b" and "c" and is depicted by the Zone 1

circle.

Tables 5.2 to 5.11 show the analysis of the relay operation for different cases of faults.

102

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1.2 Operating time of the relay - Three phase-to-ground fault

33

•s-

0.6

0.4

-0.2 0.1 0.2 0.3 0.4

Time (Second)

(a)

! 1 1

1 ': U '• 1 : !i : ! . . . . . . . Ij ,:

1 'l ' : l i

" '"": !f ! : Ij

j : 0.2524s | i 0.2597s

0.0727s '•• i i i

-Phase a Phase b Phase c

0.5 0.6 0.7

(1) Phase a current

oy

-10

7Uft 0.0727s

0.06s 0.2,524s

10

0.1 0.2 0.3 0.4 0.5

(2) Phase b current

/ 0 W

1 pu

-10

0.0727s 0.2597s

0.06s 0.2524s 0 0.1 0.2 0.3 0.4 0.5

(3) Phase c current

0.6 0.7

-10

0.06s

V \ 1 pu

\

0.2524s 0.2597s

0,.0727s

...W. ......... 0.3 0.4

Time (Second) 0.5

(b)

0.6 0.7

103

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(1) P h a s e a vol tage

0.Q6S 0 . 2 5 9 7 s 0.3 0.4

(2) P h a s e b vo l tage

0.06s

0.0727s.

0.3 0.4

(3) Phase c voltage 0.2597s"

0.7

-IF •• -M » .' •••

0.2524s 0.1 0.2 0.3 0.4

Time (Second)

(C)

0.5 0.6 0.7

Impedance diagram

-:o

Phase b Impedance Trajectory

, Phase c s^ Impedance

>•"- "•• Trajectory

_ l L_

-20 -15 -10 -5 0 5 10 15 20

Resis tance (R) in Ohms >> 25 30

(d)

Figure 5.10: Three phase-to-ground (a-b-c-g) fault (a) Trip signals for phases a, b and c (b) 3-phase currents in Line LI (c) 3-phase voltages in Line LI (d) Impedance (R-X) diagram.

104

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Table 5.2: Analysis of the relay operation for permanent fault, fault resistance (Rf) = 20 n and MOV reference voltage (Vref) = 200 kV.

Fault location

Fl

F2

F3

Fault type

a-g

b-g

c-g

a-b-g

b-c-g

c-a-g

a-b-c-g

a-g

b-g

c-g

a-b-g

b-c-g

c-a-g

a-b-c-g

a-g

b-g

c-g

a-b-g

b-c-g

c-a-g

a-b-c-g

Zone

2

2

2

1

1

1

1

2

2

2

2

2

2

2

Relay operating time with delay (s)

0.3247

0.3224

0.3210

0.0252

0.0276

0.0273

0.258

Fail to operate

Fail to operate

Fail to operate

0.356

0.391

0.3885

0.3346

0.0158

0.0122

0.0153

0.0141

0.0135

0.0158

0.014

Relay operating time with delay and reset (s)

0.5182

0.5165

0.5188

No reset time

No reset time

No reset time

0.4505

No reset time

No reset time

0.5691

0.5283

0.2004

0.1973

0.2031

No reset time

No reset time

No reset time

0.2028

No. of cycles with delay time

< 19 (1/2)

< 19 (1/2)

< 19 (1/2)

1 (1/2)

> 1 (1/2)

> 1 (1/2)

15 (1/2)

a 21 (1/2)

a 23 (1/2)

a 23 (1/4)

20

<1

<1

<1

<1

<1

<1

<1

Remarks

Zone 2 delay

0.3s & reset

time 0.18s

105

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Table 5.3: Analysis of the relay operation for permanent fault, fault resistance (Rf) = 10 a and MOV reference voltage (Vref) = 200 kV.

Fault location

Fl

F2

F3

Fault type

a-g

b-g

c-g

a-b-g

b-c-g

c-a-g

a-b-c-g

a-g

b-g

c-g

a-b-g

b-c-g

c-a-g

a-b-c-g

a-g

b-g

c-g

a-b-g

b-c-g

c-a-g

a-b-c-g

Zone

2

2

2

1

1

1

1

2

2

2

2

2

2

Relay operating time with delay (s)

0.3352

0.3332

0.3177

0.0252

0.0231

0.0236

0.0232

Fail to operate

Fail to operate

Fail to operate

0.3876

0.3843

0.3836

0.1908

0.0150

0.0126

0.0131

0.0128

0.0125

0.0146

0.0127

Relay operating time with delay and reset (s)

0.5328

0.5311

0.5118

No reset time

0.2034

0.2041

0.2166

No reset time

No reset time

No reset time

0.3854

0.2001

0.1972

0.2014

No reset time

No reset time

No reset time

0.1997

No. of cycles with delay time

- 2 0

20

~19

1 (1/2)

< 1 (1/2)

< 1 (1/2)

< 1 (1/2)

~23

= 23

= 23

11 (1/2)

<1

<1

<1

<1

<1

<1

<1

Remarks

Zone 2 delay

0.3s & reset

time 0.18s

Relay can

operate with

minor changes

106

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Table 5.4: Analysis of the relay operation for permanent fault, fault resistance (Rf) = 5 Q and MOV reference voltage (Vref) = 200 kV.

Fault location

Fl

F2

F3

Fault type

a-g

b-g

c-g

a-b-g

b-c-g

c-a-g

a-b-c-g

a-g

b-g

c-g

a-b-g

b-c-g

c-a-g

a-b-c-g

a-g

b-g

c-g

a-b-g

b-c-g

c-a-g

a-b-c-g

Zone

1

1

2

1

1

1

1

2

2

2

2

2

2

2

Relay operating time with delay (s)

0.03

0.0266

0.3170

0.0215

0.0231

0.0228

0.0212

Fail to operate

Fail to operate

Fail to operate

0.3475

0.3487

0.3492

0.3385

0.0141

0.0119

0.0129

0.0123

0.0118

0.0129

0.0121

Relay operating time with delay and reset (s)

0.2256

0.2229

0.5113

0.2019

No reset time

No reset time

0.2142

No reset time

No reset time

No reset time

0.5322

0.1997

0.1969

0.2018

No reset time

No reset time

0.1931

0.1989

No. of cycles with delay time

<2

= 1 (1/2)

19

< 1 (1/2)

< 1 (1/2)

< 1 (1/2)

< 1 (1/2)

- 2 1

- 2 1

= 21

< 20 (1/2)

<1

<1

<1

<1

<1

<1

<1

Remarks

Relay can

operate with

minor changes

107

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Table 5.5: Analysis of the relay operation for permanent fault, fault resistance (Rf) = 0 ft and MOV reference voltage (Vref) = 200 kV.

Fault location

Fl

F2

F3

Fault type

a-g

b-g

c-g

a-b-g

b-c-g

c-a-g

a-b-c-g

a-g

b-g

c-g

a-b-g

b-c-g

c-a-g

a-b-c-g

a-g

b-g

c-g

a-b-g

b-c-g

c-a-g

a-b-c-g

Zone

2

2

2

1

1

1

1

2

2

2

2

1

2

2

Relay operating time with delay (s)

0.4136

0.4111

0.3651

0.0215

0.0209

0.0186

0.0192

Fail to operate

Fail to operate

Fail to operate

0.3477

0.0207

0.3741

0.3159

0.0128

0.0111

0.0127

0.009

0.0112

0.0132

0.0114

Relay operating time with delay and reset (s)

0.6085

0.6057

0.5611

0.2019

No reset time

No reset time

0.2120

No reset time

0.2124

0.5705

0.5097

0.1995

0.1968

0.2014

No reset time

0.1917

No reset time

0.1971

No. of cycles with delay time

<25

~ 24 (1/2)

-22

< 1 (1/2)

< 1 (1/2)

~1

= 1

- 2 1

< 1 (1/2)

22 (1/2)

- 1 9

<1

<1

<1

= (1/2)

<1

<1

<1

Remarks

Zone 2 delay

0.3s & reset

time 0.18s

Relay can

operate with

minor changes

108

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Table 5.6: Analysis of the relay operation for permanent fault, fault resistance (Rf) = 10 £2 and MOV reference voltage (Vref) = 100 kV.

Fault location

Fl

F2

F3

Fault type

a-g

b-g

c-g

a-b-g

b-c-g

c-a-g

a-b-c-g

a-g

b-g

c-g

a-b-g

b-c-g

c-a-g

a-b-c-g

a-g

b-g

c-g

a-b-g

b-c-g

c-a-g

a-b-c-g

Zone

2

2

2

1

1

1

1

2

2

2

2

2

2

Relay operating time with delay (s)

0.3217

0.3193

0.318

0.0237

0.0237

0.0258

0.0293

Fail to operate

Fail to operate

Fail to operate

0.3641

0.3620

0.3665

0.2092

0.0156

0.0126

0.0132

0.0129

0.0125

0.0130

0.0127

Relay operating time with delay and reset (s)

0.5175

0.5147

0.5121

No reset time

No reset time

No reset time

0.2237

No reset time

No reset time

No reset time

0.4032

0.2012

0.1983

0.2014

No reset time

0.1931

No reset time

0.1995

No. of cycles with delay time

< 19 (1/2)

~19

19

< 1 (1/2)

< 1 (1/2)

= 1 (1/2)

<2

- 2 2

<22

~22

12(1/2)

<1

<1

<1

<1

<1

<1

<1

Remarks

Zone 2 delay

0.3s & reset

time 0.18s

Relay can

operate with

minor changes

109

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Table 5.7: Analysis of the relay operation for permanent fault, fault resistance (Rf) = 10 ft and MOV reference voltage (Vref) = 75 kV.

Fault location

Fl

F2

F3

Fault type

a-g

b-g

c-g

a-b-g

b-c-g

c-a-g

a-b-c-g

a-g

b-g

c-g

a-b-g

b-c-g

c-a-g

a-b-c-g

a-g

b-g

c-g

a-b-g

b-c-g

c-a-g

a-b-c-g

Zone

2

2

2

1

1

1

1

2

2

2

2

2

2

Relay operating time with delay (s)

0.3219

0.3195

0.3195

0.0250

0.0265

0.0269

0.0776

Fail to operate

Fail to operate

Fail to operate

0.3772

0.3763

0.3803

0.2309

0.0155

0.0121

0.0133

0.0129

0.0125

0.0131

0.0128

Relay operating time with delay and reset (s)

0.5166

0.5149

0.5146

0.2055

0.2062

No reset time

0.2719

No reset time

No reset time

No reset time

0.4244

0.2011

0.1972

0.2016

0.1930

0.1927

No reset time

0.1996

No. of cycles with delay time

- 1 9

- 1 9

= 19

1(1/2)

-1(1/2)

-1(1/2)

- 4(1/2)

-22(1/2)

-22(1/2)

- 2 3

- 1 4

<1

<1

<1

<1

<1

<1

<1

Remarks

Zone 2 delay

0.3s & reset

time 0.18s

Relay can

operate with

minor changes

110

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Table 5.8: Analysis of the relay operation for permanent fault, fault resistance (Rf) = 10 Q and MOV reference voltage (Vref) = 5 kV.

Fault location

Fl

F2

F3

Fault type

a-g

b-g

c-g

a-b-g

b-c-g

c-a-g

a-b-c-g

a-g

b-g

c-g

a-b-g

b-c-g

c-a-g

a-b-c-g

a-g

b-g

c-g

a-b-g

b-c-g

c-a-g

a-b-c-g

Zone

2

2

2

2

2

2

1

2

2

2

2

2

2

Relay operating time with delay (s)

0.3219

0.3192

0.3202

0.3186

0.3180

0.3195

0.1838

0.3362

0.3341

0.3201

0.3186

0.3178

0.3195

0.1812

0.0151

0.0123

0.0134

0.0127

0.0123

0.0131

0.0126

Relay operating time with delay and reset (s)

0.5167

0.514

0.5181

No reset time

No reset time

No reset time

0.3775

0.5333

0.5306

0.5178

0.4989

No reset time

No reset time

0.3749

0.1997

0.1969

0.2017

No reset time

No reset time

No reset time

0.1990

No. of cycles with delay time

< 19 (1/2)

= 19

< 19 (1/2)

~19

= 19

= 19

11

= 20

20

< 19 (1/2)

= 19

19

= 19

<11

<1

<1

<1

<1

<1

<1

<1

Remarks

Zone 2 delay

0.3s & reset

time 0.18s

111

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Table 5.9: Analysis of the relay operation for permanent fault, fault resistance (Rf) = 10 II and different MOV reference voltages.

Fault

type

SLG

2LG

3LG

MOV

V ref(kV)

5

75

100

200

5

75

100

200

5

75

100

200

Fl

Zone of

operation

2

2

2

2

2

No. of

cycle

19(1/2)

19

19(1/2)

20

19

1(1/2)

1(1/2)

1(1/2)

11

4(1/2)

< 2

< 1(1/2)

F2

Zone of

operation

2

No. of

cycle

20

Fail to operate

Fail to operate

Fail to operate

2

2

2

2

1

1

1

1

19

22(1/2)

22

23

11

14

12(1/2)

11(1/2)

F3

Zone of

operation

No. of

cycle

<1

<1

<1

<1

<1

<1

<1

<1

<1

<1

<1

<1

112

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Table 5.10: Analysis of the relay operation for permanent fault, MOV reference voltage (Vref) = 200 kV and different fault resistances (Rf).

Fault

type

SLG

2LG

3LG

Rf ohms

0

5

10

20

0

5

10

20

0

5

10

20

Fl

Zone of

operation

2

1

2

2

No. of

cycle

24

<2

20

19(1/2)

1(1/2)

<l(l/2)

1(1/2)

1(1/2)

1

<l(l/2)

1(1/2)

15(1/2)

F2

Zone of

operation

No. of

cycle

Fail to operate

Fail to operate

Fail to operate

Fail to operate

2

2

2

2

2

2

1

2

21

21

23

23(1/2)

19

20(1/2)

11(1/2)

20

F3

Zone of

operation

No. of

cycle

<1

<1

<1

<1

< 1

<1

<1

<1

<1

<1

<1

<1

113

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Table 5.11: Analysis of the permanent fault for secure, insecure and missing operation of the relay.

Fault type

1 Phase-G

2 Phase-G

3 Phase-G

Total

1 Phase-G

2 Phase-G

3 Phase-G

Total

1 Phase-G

2 Phase-G

3 Phase-G

Total

1 Phase-G

2 Phase-G

3 Phase-G

Total

1 Phase-G

2 Phase-G

3 Phase-G

Total

1 Phase-G

2 Phase-G

3 Phase-G

Total

1 Phase-G

2 Phase-G

3 Phase-G

Total

Fault

resistance

20

20

20

10

10

10

5

5

5

0

0

0

10

10

10

10

10

10

10

10

10

MOV reference

voltage (Vref)

200

200

200

200

200

200

200

200

200

200

200

200

100

100

100

75

75

75

5

5

5

Out of 147 faults

Total percentage

Secure

operation

6

6

2

14

6

6

1

13

4

6

2

12

6

5

2

13

6

6

1

13

6

6

1

13

9

9

1

19

97

6 6 %

Insecure

operation

0

3

1

4

0

3

2

5

2

3

1

6

0

4

1

5

0

3

2

5

0

3

2

5

0

0

2

2

32

21.76 %

Missing

operation

3

0

0

3

3

0

0

3

3

0

0

3

3

0

0

3

3

0

0

3

3

0

0

3

0

0

0

0

18

12.24 %

114

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5.2.2 Assessment of Relay under Temporary Fault

In this section, the distance relay performance for temporary fault is assessed

under various fault types, fault locations, 10 Q fault resistance (Rf) and 200 kV MOV

reference voltage (Vref). The representation for operating time of the relay, trajectories of

impedances and three phase voltage and current waveforms are shown under different

cases. The fault occurs at time=0.06s, and the simulation is run for a total time period of

0.7s. The following varieties of fault cases have been generated and used in testing the

behaviour of the relay, distance protection algorithm and auto-reclosure scheme.

(a) Three types of faults (SLG, 2LG and 3LG) at three distinct locations (Fl, F2 and

F3) with fault resistance (Rf) = 10 Q, and MOV reference voltage (Vref) = 200 kV.

The new distance protection algorithm was presented and the following results

have been obtained for the relay.

Figures 5.11 to 5.13 show the representation of the two different types of faults at

two locations with 10 £1 fault resistance (Rf) and 200 kV MOV reference voltage (Vref).

Table 5.12 shows the analysis of the relay operation for fault resistance (Rf) = 10 Q and

MOV reference voltage (Vref) = 200 kV. This table includes different fault locations, fault

types, operating time of the relay with delay, operating time of the relay with delay and

reset and finally auto-reclosure operation.

(1) Single phase-to-ground (a-g) fault at location Fl (280 km after capacitor)

Fig. 5.11 shows results from a temporary single phase-to-ground (a-g) fault

placed at 280 km from the relay, after the capacitor (at location Fl) with fault resistance

(Rf) = 10 Q and MOV reference voltage (Vref) = 200 kV. The fault occurs at time=0.06s,

and the simulation is run for a total time period of 0.7s.

115

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Fig. 5.11(a) shows the trip signals for phases a, b and c. For phase "a" the trip

signal is generated after 0.3952s (including 0.3s Zone 2 delay). The relay checks the

status of the fault after 0.18s (reset time) and due to the temporary fault; the phase "a"

circuit breaker closes after 0.5752s and the system returns to the service including the

faulted phase.

Fig. 5.11(b) and (c) show the Line LI, 3-phase current and voltage waveforms,

respectively, measured at the relay location. When the fault occurs at 0.06s, the current

for phase "a" increases and at the same time phase voltage decreases. The relay trips the

phase "a" breaker at 0.3952s, therefore, no current passes through the phase "a". Due to a

temporary fault, after 0.18s (reset time); the protected line completely returns to normal

service at 0.5752s.

The impedance (R-X) diagram (Fig. 5.11(d)) shows the 3 circles covering Zones

1, 2 and 3 and another smaller circle covering reverse zone operation. The impedance

trajectories for phases a, b and c are also shown. The trajectory of phase "a" indicates that

the fault involved phase "a" and is covered by the Zone 2 circle, but due to the fault being

temporary in nature, the impedance trajectories for three phases are returned to the initial

position.

116

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•a 0.6

5 °-4

-0.2

Operaring time or the relay - Phase a-to-ground fault

o.i

!

• ^ * »

Phase b Phase c

i

1

0.3952s i

Tempo rary Fault

:0.5752s

0.3 0.4

Time (Second)

(a)

0.7

(1) Phase a current 1 pu

w 0-PSs

0.5752s

0.3952s 0.1 0.2 0.3 0.4 0.5

(2) Phase b current

0.2 0.3 0.4 0.5

(3) Phase c current

o.i 0.2 0.3 0.4

Time (Second) 0.5

(b)

0.6

0.6

0.7

0.7

2

0

2

,0l06s . . .

0.7

117

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(1) Phase a voltage

IP 0.06s

mm w i

0.3952s, III

, Hi

" 0.1 0.2 0.3 0.4

(2) Phase b voltage 0.5

0.3 0.4 Time (Second)

( C )

0.6 0.7

30 Impedance diagram

A 20

S io a 0 s g o u

i v 8 -ID

-20

-30 -10

Zone

Phase b Impedance Trajectory

Reverse Zone

Phase a Impedance Trajectory

0 5 10 15 20 25

Resistance (R) in Ohms >

(d)

Figure 5.11: Single phase-to-ground (a-g) fault (a) Trip signals for phases a, b and c (b) 3-phase currents in Line LI (c) 3-phase voltages in Line LI (d) Impedance (R-X) diagram.

118

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(2) Three phase-to-ground (a-b-c-g) fault at location Fl (280 km after capacitor)

Fig. 5.12 shows results from a temporary three phase-to-ground (a-b-c-g) fault

placed at 280 km from the relay, after the capacitor (at location Fl) with fault resistance

(Rf) = 10 Q and MOV reference voltage (Vref) = 200 kV. The fault occurs at time=0.06s,

and the simulation is run for a total time period of 0.7s.

Fig. 5.12(a) shows the trip signals for phases a, b and c. The trip signals for three

phases are generated after 0.0832s. The relay checks the status of the fault after 0.18s

(reset time) and due to the temporary fault, all three phase circuit breakers closes after

0.2632s and the system returns to normal service.

Fig. 5.12(b) and (c) show the Line LI, 3-phase current and voltage waveforms,

respectively, measured at the relay location. When the fault occurs at 0.06s, the current

for three phases are increased and at the same time phase voltage decreases. The relay

trips the three phase's circuit breakers at 0.0832s; therefore, no current passes through the

protected line. Due to a temporary fault, after 0.18s (reset time); the protected line

completely returns to normal service at 0.2632s.

The impedance (R-X) diagram (Fig. 5.12(d)) shows the 3 circles covering Zones

1, 2 and 3 and another smaller circle covering reverse zone operation. The impedance

trajectories for phases a, b and c are also shown. The trajectory of the three phases

indicates that the fault involved phases "a", "b" and "c" and is covered by the Zone 1

circle, but due to the fault being temporary in nature the impedance trajectories for three

phases are returned to the initial position.

119

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1.2

0 . 8 -••

2 O.d -

g 0.4

0.2

Operating time of the relay - Three phase-to-ground fault

0.2 0.3 0.4

Time (Second)

(a)

1 1 r I

1 Temporary Fault ;

M i : i i !

i ; i : i i ' 1 : !

" r r : ! : 1 i : i :

M ! ; i ! : : ! ; i : !

i 0.0832s : ' ;

i K . _ i . i ! 1 0.2632s

i i i i ...

i

Phase a Phase b Phase c

0.5 0.7

(1) Phase a current Ipwj 0.0832s 2

-2 0.06s 0.2632s

A\Aw^mHmws-0.2 0.3 0.4 0.5

(2) Phase b current

0.2 0.3 0.4 0.5

(3) Phase c current ft-0<»s 0.0832s

^4 f, /

0.(5 0.7

2h

0B

-2h 1 pn' 0.2632s 0.1 0.2 0.3 0.4

Time (Second) 0.5

(b)

0.6 0.7

120

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(1) Phase a voltage 0.2632s 0.0832s

0.06s 0.1 0.2 0.3 0.4

(2) Phase b voltage 0.5 0.6 0.7

0.06s 0.0832s 0.0832s (

2

1

0

-1

) 0.1

0.06s . , ^ .

V • - 9'' 0.0832s

0.2

1

0.3 0.4 (3) Phase c voltage

0.0832s

I - '

0.5

'

0.6

'

0

-

0.2 0.3 0.4 0.5 Time (Second) *•

( C )

0.6 0.7

30

20

Impedance diagram

S io a 0 .5 S o

-10

-20

-30 -10

hase b Impedance Trajectory

Reverse Zone

Phase a Impedance Trajectory

Phase c Impedance Trajectory

0 5 10 15 20

Resistance (R) in Ohms > 25 30

(d)

Figure 5.12: Three phase-to-ground (a-b-c-g) fault (a) Trip signals for phases a, b and c (b) 3-phase currents in Line LI (c) 3-phase voltages in Line LI (d) Impedance (R-X) diagram.

121

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(3) Single phase-to-ground (a-g) fault at location F3 (Beginning of the protected line)

Fig. 5.13 shows results from a temporary single phase-to-ground (a-g) fault

placed at the beginning of the protected line (at location F3) with fault resistance (Rf) =

10 Q. and MOV reference voltage (Vref) = 200 kV. The fault occurs at time=0.06s, and the

simulation is run for a total time period of 0.7s.

Fig. 5.13(a) shows the trip signals for phases a, b and c. For phase "a" the trip

signal is generated after 0.0750s. The relay checks the status of the fault after 0.18s (reset

time) and due to the temporary fault; the phase "a" circuit breaker closes after 0.2550s and the

system returns to normal service including the faulty phase.

Fig. 5.13(b) and (c) show the Line LI, 3-phase current and voltage waveforms,

respectively, measured at the relay location. When the fault occurs at 0.06s, the current

for phase "a" increases and at the same time voltage decreases. The relay trips the phase

"a" breaker at 0.0750s, therefore, no current passes through the phase "a". Due to a

temporary fault, after 0.18s (reset time); the protected line completely returns to normal

service at 0.2550s.

The impedance (R-X) diagram (Fig. 5.13(d)) shows the 3 circles covering Zones

1, 2 and 3 and another smaller circle covering reverse zone operation. The impedance

trajectories for phases a, b and c are also shown. The trajectory of phase "a" indicates that

the fault involved phase "a" and is covered by the Zone 1 circle, but due to the fault being

temporary in nature, the impedance trajectories for three phases are returned to the initial

position.

Table 5.12 shows the analysis of the relay operation for different cases of faults.

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1.2 Operating time of the relay - Phase a-to-ground fault

•a

0.8

D.6

SI3

.& £ 0.4

-0.2

1 1

0.0750s;

i i i

; Temporary Fault i

0.2550s \ i i i

__ e a Phase b Phase c

0.1 0.2 0.3 0.4 Time (Second)

0.5 0.6

(a)

(1) Phase a current

10

a. °

-10

k/Vv\i

,0750s

0.06s, 0.2550s

$\j\rs\f'>sj\f^\j\r^r\f^.r^r\f*>rSsrs/x^r\/\'\A

0.1 0.2 0.3 0.4 0.5

(2) Phase b current o.s 0.7

0.2 0.3 0.4 0.5

(3) Phase c current

0.6 0.7

0.3 0.4 Time (Second)

(b)

123

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(1) Phase a voltage

0.2 0.3 0.4 (2) Phase b voltage

0.7

-1 0.0750s,

,0.2550s

0.2 0.3 0.4 0.5 (3) Phase c current

0.7

-1

0.0750s' * .

\ 0.255,0s

0.3 0.4 Time (Second)

(C)

0.5 0.6 0.7

30

-30

Impedance diagram

Phase a Impedance Trajectory

/ Trajectory

Phase c Impedance Trajectory

-10 5 10 15 Resistance (R) in Ohms

20 25 30

(d)

Figure 5.13: Single phase-to-ground (a-g) fault (a) Trip signals for phases a, b and c (b) 3-phase currents in Line LI (c) 3-phase voltages in Line LI (d) Impedance (R-X) diagram.

124

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Table 5.12: Analysis of the relay operation for temporary fault, fault resistance (Rf) = 10 Q and MOV reference voltage (Vref) = 200 kV.

Fault location

Fl

F2

F3

Fault type

a-g

b-g

c-g

a-b-g

b-c-g

c-a-g

a-b-c-g

a-g

b-g

c-g

a-b-g

b-c-g

c-a-g

a-b-c-g

a-g

b-g

c-g

a-b-g

b-c-g

c-a-g

a-b-c-g

Zone

2

2

2

1

1

1

1

2

2

2

2

2

2

Relay operating time with delay (s)

0.3352

0.3332

0.3177

0.0252

0.0231

0.0236

0.0232

Fail to operate

Fail to operate

Fail to operate

0.3641

0.3620

0.3665

0.2092

0.0150

0.0126

0.0131

0.0128

0.0125

0.0146

0.0127

Relay operating time with delay and reset (s)

0.5152

0.5132

0.4977

No reset time

No reset time

No reset time

0.2032

No reset time

No reset time

No reset time

0.3892

0.1950

0.1926

0.1931

No reset time

No reset time

No reset time

0.1927

Auto-reclosure operation

Yes

Yes

Yes

No

No

No

Yes

No

No

No

Yes

Yes

Yes

Yes

No

No

No

Yes

Remarks

Relay sense the

fault and trips 3-

phases breakers

Relay sense the

fault and trips 3-

phases breakers

Relay sense the

fault and trips 3-

phases breakers

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5.3 SIMULATION RESULTS ANALYSIS

A total of 294 results were obtained with the test system. Different faults were

considered in the study. The findings of these evaluations are summarized in Tables 5.2

to 5.12. The performance of the relay operation and the algorithm scheme with two

parallel, 500 kV series compensated lines were tested for SLG, 2LG and 3LG permanent

and temporary faults at three different locations Fl, F2 and F3 is shown in Tables 5.2 to

5.12. At Fl, the fault is located at the remote end, after the capacitor. At F2, the fault is

located at the remote end, before the capacitor. At F3, the fault is located at the beginning

of the protected line. The relay operation and algorithm are tested with different fault

resistances (20, 10, 5 and 0 Q) and different MOV reference voltages (200, 100, 75 and 5

kV).

Tables 5.2 to 5.8 and 5.12 provide analysis of the 21 faults with particular fault

resistances and reference voltages, respectively. Fault locations, type of faults, zone of

operation, relay operating time with delay and relay operating time including delay and

reset are listed in columns 1, 2, 3, 4 and 5, respectively, in Tables 5.2 to 5.8 and 5.12 for

each fault case. For permanent faults, the number of cycles with delay time is listed in

column 6 of Tables 5.2 to 5.8. For temporary faults, auto-reclosure operation is listed in

column 6 of Table 5.12. The Zone 1 covers 85% of the protected line, therefore, the fault

within this area has been taken care of by the first zone for secure operation of the relay

and the relay has to trip without any intentional time delay. Above 85% of the protected

line length covered by the second zone, which means any fault beyond 85% of the length

is taken care of by Zone 2 for secure operation of the relay. As expected, the trajectories

of the faulty phase impedances enter the tripping zone region of the relay and the healthy

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phase impedance trajectories are located outside this region depending upon the type of

the fault.

5.3.1 Permanent Faults

Table 5.2 shows results for permanent fault, fault resistance (Rf) = 20 Q. and MOV

reference voltage (Vref) = 200 kV. When the fault occurs at location Fl, the relay operates

in Zone 1 instead of Zone 2 (overreach) due to the capacitor, impedance measurement at

the relay location and parallel line operation for 2LG and 3LG faults. As mentioned

earlier, the series capacitor makes the electrical line look shorter. The operating time for

the SLG fault is less than 1.5 cycles excluding the Zone 2 time delay. For faults at

location F2, the relay fails to operate for SLG faults. The relay operation is satisfactory

for close-in faults. The relay operates securely and the operating time is less than 1 cycle

for close-in faults.

Table 5.3 shows results for permanent fault, fault resistance (Rf)= 10 Q. and MOV

reference voltage (Vref) = 200 kV. When the fault occurs at location Fl, the relay operates

in Zone 1 instead of Zone 2 (overreach) due to the capacitor, impedance measurement at

the relay location and parallel line operation for 2LG and 3LG faults. As mentioned

earlier, the series capacitor makes the electrical line look shorter. The operating time for

the SLG fault is around 2 cycles excluding the Zone 2 time delay. For faults at location

F2, the relay fails to operate for SLG faults and for the 3LG fault, the relay operates in

Zone 1 instead of Zone 2 (overreach) due to impedance measurement and parallel line

operation. The relay operation is satisfactory for close-in faults. The relay operates

securely and the operating time is less than 1 cycle for close-in faults.

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Table 5.4 shows results for permanent fault, fault resistance (Rf) = 5 Q and MOV

reference voltage (Vref) = 200 kV. When the fault occurs at location Fl, the relay operates

in Zone 1 instead of Zone 2 (overreach) for majority of the faults, due to parallel line

operation and the capacitor. As mentioned earlier, the series capacitor makes the

electrical line look shorter. The operating time is between 1.5 to 2 cycles for most of the

faults. For faults at location F2, the relay fails to operate for SLG faults, but for all other

faults, the relay operates securely and the operating time is around 3 cycles excluding the

Zone 2 time delay. The relay operation is satisfactory for close-in faults. The relay

operates securely and the operating time is less than 1 cycle for close-in faults.

Table 5.5 shows results for permanent fault, fault resistance (Rf) = 0 Q and MOV

reference voltage (Vref) = 200 kV. When the fault occurs at location Fl, the relay operates

in Zone 1 instead of Zone 2 (overreach) due to the capacitor, impedance measurement at

the relay location and parallel line operation for 2LG and 3LG faults. As mentioned

earlier, the series capacitor makes the electrical line look shorter. For faults at location

F2, the relay fails to operate for SLG faults, but for the majority of faults, the relay

operates securely. The relay operation is satisfactory for close-in faults. The relay

operates securely and the operating time is less than 1 cycle for close-in faults.

Tables 5.6 and 5.7 show results for permanent fault, fault resistance (Rf) = 10 Q

and MOV reference voltage (Vref) = 100 kV and 75 kV, respectively. When the fault

occurs at location Fl, the relay operates in Zone 1 instead of Zone 2 (overreach) due to

the capacitor, impedance measurement at the relay location and parallel line operation for

2LG and 3LG faults. As mentioned earlier, the series capacitor makes the electrical line

look shorter. The operating time for the SLG faults is less than 1.5 cycles excluding the

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Zone 2 time delay. For faults at location F2, the relay fails to operate for SLG faults and

for the 3LG fault, the relay operates in Zone 1 instead of Zone 2 (overreach). The relay

operation is satisfactory for close-in faults. The relay operates securely and the operating

time is less than 1 cycle for close-in faults.

Table 5.8 shows results for permanent fault, fault resistance (Rf) = 10 CI and MOV

reference voltage (Vref) = 5 kV. When the fault occurs at location Fl, the relay operates in

Zone 1 instead of Zone 2 (overreach) due to the capacitor, impedance measurement at the

relay location and parallel line operation for the 3LG fault. As mentioned earlier, the

series capacitor makes the electrical line look shorter. The operating time for SLG faults

is less than 1.5 cycles excluding the Zone 2 time delay. For faults at location F2, the relay

operates securely for SLG and 2LG faults, but for the 3LG fault, the relay operates in

Zone 1 instead of Zone 2. The relay operation is satisfactory for close-in faults. The relay

operates securely and the operating time is less than 1 cycle for close-in faults.

Table 5.9 shows the analysis of the relay operation for permanent faults, fault

resistance (Rf) = 10 Q. and different MOV reference voltage (Vref) (5, 75, 100 and 200

kV). The type of faults and different MOV Vref are listed in columns 1 and 2,

respectively. Columns 3, 4 and 5 show the three different fault locations, which include

the zone of operation and number of cycles for each fault case. The data shown in the

Table 5.9 indicates that the relay operates securely and correctly for all close-in faults

(F3). For close-in faults, the relay operates in Zone 1 and an average tripping time is less

than 1 cycle or 16.7 ms.

Table 5.10 shows the analysis of the relay operation for permanent faults, MOV

reference voltage (Vref) = 200 kV and different fault resistances (0, 5, 10 and 20 Q.). The

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type of faults and different fault resistance (Rf) in ohms are listed in columns 1 and 2,

respectively. Columns 3, 4 and 5 show the three different fault locations, which includes

the zone of operation and number of cycles for each fault case. The data shown in the

Table 5.10 indicates that the relay operates securely and correctly for all close-in faults

(F3). For close-in fault, the relay operates in Zone 1 and an average tripping time is less

than 1 cycle.

Table 5.11 shows the analysis of the permanent fault for secure, insecure and

missing operations of the relay. The types of faults, different fault resistance (Rf),

different MOV reference voltage (Vref), secure, insecure and missing operations are listed

in columns 1 to 6, respectively, for each fault case. The data shown in the table indicates

that the relay operates more securely operations with Rf = 10 Q. and MOV Vref= 5 kV.

In most cases, for faults at location F2, the relay fails to operate for SLG faults,

but with minor changes in the comparison equation (u[2]>=u[l]) inside the relay model,

the relay operates for most of the fault cases, except fault resistance 20 Q.

5.3.2 Temporary Faults

Table 5.12 shows the results for the temporary faults, fault resistance (Rf) = 10 Q.

and MOV reference voltage (Vref) = 200 kV. When the fault occurs at location Fl, the

relay operates in Zone 1 instead of Zone 2 (overreach) due to the capacitor, impedance

measurement at the relay location and parallel line operation for 2LG and 3LG faults.

Due to a temporary fault, after the reset time (0.18s), the protected line is completely

returned to the service for SLG and 3LG faults. For faults at location F2, the relay fails to

operate for SLG faults, but with minor changes mentioned in the previous section, the

relay operates for SLG faults. The auto-reclosure scheme also fails to operate for 2LG

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faults at all locations. In case of 2LG faults, the relay sends trip signals whenever it

senses a fault and does not check the status of the fault after reset time.

5.3.3 Capacitor and MOV Operation

In order to investigate the operation of the capacitor and MOV, single phase-to-

ground fault (a-g) is generated at the remote end, after the capacitor (at location Fl) with

10 Q. fault resistance (Rf) and 75 kV MOV reference voltage (Vref). Fig. 5.14 shows the

capacitor voltage (top trace), capacitor current (middle trace) and the MOV current

(bottom trace) for phase 'a". The results show that when the fault occurs at 0.06s, the

capacitor voltage and current increase. The voltage increase is enough to trigger the

MOV after a half cycle from the fault occurrence to conduct the MOV and protect the

capacitor against overvoltage. The capacitor and the MOV take turns conducting currents

till the line is disconnected from the service.

Voltage across capacitor for phase a

0.2 0.3 0.4 0.5 Capacitor current for phase a

,d.06s

1 pu 0.5627s' 0.5668s

0.1 0.2 0.3 0.4 0.5 MOV current for phase a

0.6 0.7

0.3808s

• A' 0.0677s

</

0.5668s i 0.5753s

0 0.1 0.2 0.3 0.4 Time (Second)

0.5 0.6 0.7

Figure 5.14: Capacitor voltage (top), capacitor current (middle) and the MOV current (bottom) for phase a.

131

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5.3.4 Ground Faults for Different Fault Resistances

Fig. 5.15 shows the fault trajectories of phase "a" for single phase-to-ground fault

generated at the remote end with different fault resistances and the effect of an increasing

fault resistance to the impedance measurement. The fault resistance (Rf) varies from 0 Q.

to 50 Q. The network data, the relay location and the fault location are the same for each

case. Clearly the error in the impedance measurement increases with increasing fault

resistance.

30

25

20

Impedance diagram for differnt fault resistance (a-g fault)

o .3 is

10

•8 as

5h

Rf = 10 ohms

-15 0 5 10 15 Resistance (R) in Ohms -

30

Figure 5.15: Impedance diagram for single phase-to-ground (a-g) fault after capacitor with different fault resistance.

The fault trajectory enters the trip area during the transition from pre-fault to post-

fault for a fault resistance of up to 30 Q,. Higher fault resistances cause the impedance

trajectories to settle inside the trip area, resulting in an insecure response of the relay.

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Since the Rf increases, the resistive part of the impedance measurement increases

too. Depending on the network and trip area setting, if the fault resistance becomes too

high, then the resistive part of the impedance measurement is greater than the trip area;

therefore, the impedance fault trajectory of an external high resistive ground fault will not

enter the trip area.

If the Rf is so high, then the fault trajectory does not enter the trip area for an

internal fault, therefore, the relay loses its dependability. The corrected fault trajectory

cannot improve the dependability in this case because the resistive parts of the fault

trajectories are too high.

The greater the impedance indicating a greater distance to the fault, the longer the

operating time. If the impedance falls below a specified value, the relay trips as quickly

as possible without any intentional time delay. The effect of the fault resistance is to

increase the magnitude of the impedance and make the fault appear more remote.

5.4 SUMMARY

The following points have been explained in this chapter:

(1) The analysis and test results, which have been obtained from computer

simulations with relay model and 500 kV series compensated parallel

transmission lines have been shown in this chapter.

(2) Assessment of the relay under permanent and temporary faults is also

presented in this chapter.

(3) The analysis and simulation results for single phase-to-ground, two phase-to-

ground and three phase-to-ground faults at three different locations are shown

in this chapter.

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(4) The relay performance is tested with different fault resistances (0, 5, 10 and

20 ohms) as well as different MOV reference voltages (5, 75, 100 and 200

kV).

(5) This chapter investigated the capacitor and MOV operation with simulation

results.

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CHAPTER - 6

CONCLUSION

6.1 SUMMARY AND CONCLUSION

Electric power systems experience faults due to aging of equipment and adverse

environmental conditions. A fault can cause excessive currents to flow resulting in

extensive damage in power system equipments and consequential interruption of power

supply to consumers. To maintain the continuity of the power supply, the power

equipment should be protected with protective relays and circuit breakers. When the fault

occurs, the protective relay plays a vital role to minimize the damage and keep the power

system safe.

This thesis describes the detailed design of the Mho relay model, logic operation

and the residual current compensation algorithm in EMTP-RV. The EMTP-RV is used to

evaluate the performance of a Mho relay model and algorithm for two parallel 500 kV,

280 km series compensated transmission system. An algorithm scheme based on the

residual current compensation is used to compensate the error. The phase comparators are

employed to detect faulted phase(s) and zone by measuring and comparing phase angle

between input voltage and current signals.

The assessment of a Mho relay model and its algorithm is carried out for

permanent and temporary faults. A total of 294 (147 permanent and 147 temporary) fault

cases were studied for parallel line operation. Out of 147 permanent faults, the relay has

• 97 (66 %) secure operations (i.e. the relay operated in the expected zone),

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• 32 (21.76 %) insecure operations (i.e. the relay operated in a different zone than

the expected zone), and

• 18 (12.24 %) missed operations (i.e. the relay failed to operate).

For temporary faults, numbers of secure, insecure and missing operations are the

same as permanent faults.

The simulation results show that the relay model detects the faults correctly and

generates trip signals with regards to the location of the fault in the majority of fault

cases. However, the relay may not be as secure on certain unbalanced fault types

generated at the remote end, behind the capacitor. The results show that the auto-closure

does not work for two phase-to-ground faults (the relay trips the protected line

completely when senses a fault) and the relay fails to operate for most SLG faults

generated at the remote end, before the capacitor. With minor changes in the

mathematical equations (u[2]>=0.8*u[l]) before compensation, for the comparison

between the summation of input currents and the individual phase current, the relay

operates for most SLG faults generated at the remote end, before the capacitor; therefore,

the number of missed operations can be minimized. Finally, for close-in faults,

satisfactorily relay performance was obtained and the average tripping time was less than

1 cycle.

The MOV protects the capacitor against overvoltage during fault conditions.

Furthermore, it is noted that the operating time of the relay is a function of the distance to

the fault. Extensive tests of the relay with different data selection have revealed that the

relay can be used in a wide variety of power systems to protect transmission lines. The

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tests were conducted to show that the relay performs satisfactorily for most faults

occurring in a power system.

The Mho relay proposed in this thesis can be successfully used in a variety of

power systems to protect transmission lines. It is found that an algorithm principle works

in most cases, but it would give a wrong zone operation for some remote end unbalanced

faults. The relay works satisfactorily with changing the relay setting and does not lose its

directionality.

Simulation results and analysis show that the relay model and the residual current

compensation scheme are well suited for the series compensated transmission line and

works well for the majority of fault conditions.

6.2 SUGGESTIONS FOR FUTURE RESEARCH

As a continuation of this work, future research could be suggested as follows:

1. The relay model and its algorithm were tested using EMTP-RV simulations. Their

validation should be tried by laboratory implementations and then followed by

field tests.

2. The effects of CT's such as CT burden, saturation of CT's and consequent

distortion of the secondary current etc. and also the effects of CVT on the

performance of the proposed algorithm have yet to be investigated.

3. The relay model and its algorithm need to be tested for

• Faults beyond the remote end and reverse faults.

• Capacitor and its overvoltage protection located at the middle and

beginning of the protected line.

• Multiple line networks.

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4. The proposed relay model and its algorithm have been tested for SLG, 2LG and

3LG faults. Its response to disturbances, such as power swings, line charging etc.

should also be included in future research.

5. Further investigation in the algorithm is necessary, because the relay fails to

operate after reset time in two phase-to-ground faults.

6. There should be a study of alternative logic control strategies or algorithms to

further improve the performance of the proposed relay model.

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APPENDIX - A

M H O RELAY DATA

Protected line length = 280 km

Ic tp=1074A

lets = 5 A

Vcvtp = 410kV

Vov t s=115V

Comparator = 1 (1 for Phase and 2 for Amplitude)

R0 = 0.06162 Q/km

L0= 1.05 ft/km

Rl = 0.0205 ft/km

LI = 0.35 Q/km

In (Neutral Current) = 5 A

Seuillr (Reference current) = 0.1

Zonel = 0.85 (85% of the protected line)

Zone2 = 1.5, Zone3 = 2

tzonel = 0.001 sec

tzone2 = 0.3 sec

tzone3 = 0.8 sec

tamont = 2.5 sec

treset (reset time to see the status of the fault, permanent or temporary) = 0.18 sec

treclose = 0.18 sec

k,=l,k2 = l

CXi = 71, (X2 = 0

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01 _ Zangle, 02 "~ 0> 01a ~ Zangle + 71, 02a ~ 0

ZR1 = Ziine, ZR2 = 0, ZRla = Ziine/2

Initial load (ohm)

Zr in i tmag = 200 Q,

Zr in i t ang = 0.1 rad/s

The initial impedance load (magnitude and angle) is provided only to avoid weird R-X

points during the first 0.03s, the time require by the phase transformation to translate

properly the 60 Hz sinusoidal waveform.

Frequency = 60 Hz

Rules

Reach of the relay for three zones

ZR11 = ZRl*Zonel=ZRl*Zline = 5.026 £2

ZR12 = ZRl*Zone2 = ZR1* Zhne = 8.869 £1

ZR13 = ZRl*Zone3 = ZR1* Z(ine = 11.825 Q

ZRla = (Ziine)/2 = 2.956 Q

ZR21 =ZR2*Zonel=0

ZR22 = ZR2*Zone2 = 0

ZR23 = ZR2*Zone3 = 0

ZR2a = 0

Ziine = Length* J (R1) 2 +(L1) 2 * Ctp CtS = 5.908 Q (Vctp /Vcts)

Zangle - t a n -ITLO

vRly

Period = 1/frequency

86.65° or 1.51229 rad

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APPENDIX - B

TRANSMISSION LINE DATA

Rated voltage = 500 kV

Rated Power = 1450 MW

Total line length = 500 km

Protected line length = 280 km

Number of parallel line = two

R0 = 0.06162 ft/km, L0 = 1.05 Q/km

Rl = 0.0205 ft/km, LI = 0.35 ft/km

Fault resistance (Rf) = 0 Q, 5 ft, 10 Q and 20 Q

Capacitor bank protection scheme = Zno

Zno reference voltage (Vref) = 5 kV, 75 kV, 100 kV and 200 kV

Series compensation = 40%

Series capacitance = 67.66 uF per phase

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APPENDIX - C

RELEVANT DEFINITIONS [2,4,26]

Relay: A relay is an automatic device, which opened or closed and makes changes in the

same or another electrical circuit.

Protective Relay: Like a relay, the protective relay is also an automatic device, which

detects an abnormal condition in the electrical circuits and makes a circuit breaker to

isolate the faulty element from the system. In some cases, it may give an alarm or the

visual indication to alert the operator.

Protective System: It is a combination of the protective equipments, such as protective

relays, P.T., C.T. and auxiliary equipment to secure the isolation of the faulty equipment

under predetermined conditions (abnormal and/or alarm signal).

Protective Scheme: Several protective systems are covered under the protective scheme.

It is designed to protect one or more power system elements.

Fault Detector or Starting Relay: This relay detects abnormal conditions and initiates

the operation of other protective scheme elements.

Coordination of Protection: The process of selecting protection devices setting or zone

time delay characteristics, such that operation of the devices will happen in a specified

order to minimize power system isolation and customer service interruption due to a

disturbance in the power system.

Setting: The relay is set to operate for a particular value of the actuating quantity.

Reach: It is the maximum line length up to which the relay can protect. This word is

commonly used in relation with distance relays. A distance relay begins its operation

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when the impedance or the component of the impedance seen by the relay is less than a

preset value. This preset value of the impedance or a component of the impedance or

corresponding distance is called the reach of the relay.

Overreach: Sometimes a relay may initiate its operation even when the fault occurred

beyond its protected length. This phenomenon is called overreach.

Underreach: Opposite to the overreach, sometimes a relay may fail to initiate its

operation even when the fault occurred within its protected length or reach, but it is at the

far end of the protected line. This phenomenon is called underreach.

Primary Protection: The primary protection acts as a first order defense. It is the duty of

the primary protection to clear the fault without any intentional time delay, if the fault

occurs within the protected line length. If it fails to operate, the back-up protection clears

the fault.

Back-up Protection: The back-up protection is designed to clear the fault if the primary

protection fails to operate. It is basically time delayed and removes more system elements

than required by the primary protection operation. It acts as a second order defense.

Distance Zones: In a power system, the reaches of the measuring elements of distance

protection is called distance zones.

Grading Time: The delay times setting of the back-up zones.

Step Distance: A non-pilot distance relay scheme using multiple zones with different

time delay to distinguish between the zones of protection.

Operating Time: It is the time interval between the moments at which the actuating

quantity exceeds the relays pick-up value and the relay closes its contacts.

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Reset Time: It is the time internal between the moments at which the actuating quantity

falls below its reset value and the relay return to its initial position.

Operating Torque or Force: A torque or force which tends to close the contacts of the

relay.

Restraining Torque or Force: A torque or force which opposes the operating

torque/force.

Dual Polarization: The polarization of the relay using voltage and current sources.

Distance Relay: A protective relay in which the response of the electrical input quantities

(voltage and current) is primarily a function of the distance between the relay location

and the fault location.

Ground Distance Relay: A distance relay designed to detect phase-to-ground faults

(SLG, 2LG and 3LG) is called ground distance relay.

Phase Distance Relay: A distance relay designed to detect phase-to-phase and three-

phase faults is called phase distance relay.

Mho Unit: A distance relay unit having a circular impedance characteristic that passes

through the origin in the R-X diagram.

Source Impedance: The Thevenin equivalent impedance of an electrical system at the

transmission line terminal. In network application, this impedance varies depending on

the fault location on the transmission line and the status of other terminals (opened or

closed) related with the transmission line.

Fault Impedance: An impedance, resistive or reactive, between the power system faulty

phase conductors or faulty phase conductor(s) and the ground.

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APPENDIX - D

LIST OF PUBLICATIONS

Conference papers

1. A.B. Shah, V.K. Sood and O. Saad, "Mho Relay for Protection of Series

Compensated Transmission Lines," IPST 2009 in Kyoto, Japan, June 3-6, 2009.

(Accepted)

2. A. B. Shah, V. K. Sood, O. Saad and V. Ramachandran, "Modeling Mho Relay

for Protection of Series Compensated Line," IEEE TIC-STH 2009, Toronto,

Canada, September 27-29, 2009. (manuscript under preparation)

150