SECTIONALIZING STUDY OF 132/33 KV GRID SUB STATION

DISSERTATION Submitted in partial fulfilment of the requirements of

Master of Engineering in Electrical Power Engineering

Md. Siddique Hossain

Department of Electrical and Electronics Engineering

School of Engineering

Kathmandu University

December 2005

SECTIONALIZING STUDY OF 132/33 KV GRID SUB STATION

DISSERTATION Submitted in partial fulfilment of the requirements of

Master of Engineering in Electrical Power Engineering

By:

Md. Siddique Hossain

Under supervision of: Mr. Roshan Bhattarai

Assistant Professor Department of Electrical and Electronics Engineering

School of Engineering Kathmandu University

Department of Electrical and Electronics Engineering School of Engineering

Kathmandu University

December 2005

ACKNOWLEDGEMENTS

The end of writing a thesis is the beginning of expressing gratitude to those who have

contributed to it.

First of all I would like to express my deepest thanks to the three people who contributed

most to the thesis. They are Prof. Arne T Holen of NTNU, Asst. Prof. Roshan Bhattarai

and Asst. Prof. Gautam Bajracharya of Kathmandu University. Prof. Holen, taught me

about power system analysis, besides suggested and answered all the questions I posed.

I am very grateful to my supervisor Mr. Roshan Bhattarai, Assistant Professor,

Kathmandu University for his guidance, encouragement and assistance. I also express my

indebted gratitude to Dr. Bhupendra Bimal Chhetri, Course Coordinator of Master of

Electrical Power Engineering and Head of the Department of Electrical and Electronics

Engineering, Kathmandu University for his kind cooperation and continuing support at

any situation over the study periods. I would like to express my thanks to Mr. Morten

Husom, Powel ASA, Norway for giving me suggestions even when he was busy with his

work. Besides, I also thank Mr. Egil Hagen who put the primary idea of collecting data

and making a thesis into my head.

I am grateful to Mr. Faizul Kabir, Deputy Manager, PGCB and Mr. Abaidullah, Asst.

Manager, PGCB, Bangladesh for providing the data and relay guide manuals that I

needed for my project. Apart from this I heartily thank Mr. Arup Kumar Bishwas, Asst.

Engr., REB who has given lot of constructive comments for my dissertation work.

I wish to express my gratitude to the Norwegian Agency for Development Cooperation

(NORAD) for providing me opportunity to take part in this course and financial support

during my Masters period. I would like to express my heartily thanks to my organization

LP Gas Limited, especially Mr. A. Wadud Khan, Ex M.D. and Mr. Md. Fazlur Rahman

Khan, AGM for granting me permission in this course. I wish to convey warmest thanks

to my parents and my wife who gave me endless support and inspiration to continue with

this study at abroad.

Finally, I am thankful to all of my friends and all the staffs of Kathmandu University for

their kind cooperation shown toward me.

ABSTRACT

Since the effects of an unreliable power system transmission can be widespread and affect

millions of people, as well as damage to life and equipment, therefore one of the most

important requirements of electric power system operation is to isolate and disconnect

faulted parts of the system selectively and quickly. This purpose can be achieved by

proper coordination of protective devices. One aim of the research was to make a general

guideline from which proper coordination of transmission system can be developed in

Bangladesh.

This thesis proposes a review of coordination of distance relays for transmission lines of a

real network that is selected for study. The equipment has been upgraded in the network

due to growing demand of power where in most cases it was not planned with protective

device coordination in mind. Another problem is single shoot auto reclosing is used in the

network where the both end breaker will not trip simultaneously if any fault occurs

beyond the zone 1 reach at either end. The report developed in this thesis takes into

account the effect of following issues: load flow, short circuit analysis, protection system

and coordination.

The present load flow and fault currents of the network were calculated by using Net Bas

program and from these results the proper ratings of the protective devices and conductor

are observed. The basic principle of zone settings (Zone1, Zone2 and Zone3) of distance

relays are followed for primary and back-up protection of transmission lines and

coordination curves were made from which proper selectivity between zones of back-up

protection are observed. It has found that some feeders have coordination problem (e.g.

Kulshi – Baraulia 1 feeder, Baraulia – Kulshi 1 feeder, Sikalbaha2 – Madunaghat feeder)

with zones of back-up protection on adjacent feeder which may cause mal-operation

during the fault. After reviewing of coordination, the proposed zone and time settings

were tabulated for this network. The justifications of the proposed settings were discussed

and it is recommended to implement the proposed settings in this network. The pilot

relaying schemes are proposed to get high speed relaying which are imperative for

transmission line considering a bulk power supply rather than cost. The pilot relaying

schemes are also need for successful auto reclosing during transient faults. On the basis of

the results, some recommendations for improving the transmission grid stability in terms

of coordination analysis were made.

TABLE OF CONTENTS

LIST OF TABLES .................................................................................................................i

LIST OF FIGURES ..............................................................................................................ii

GLOSSARY OF ABBREVIATIONS ................................................................................iii

INTRODUCTION.................................................................................................................1

1.1 Background and Motivation ........................................................................................ 1 1.2 Objectives of the Project.............................................................................................. 3 1.3 Scope of the Project ..................................................................................................... 3 1.4 Review of Coordination............................................................................................... 3 1.5 Research Method.......................................................................................................... 4

1.5.1 Data Collection ..................................................................................................... 4 1.5.2 Procedure and Outcome ........................................................................................ 4

1.6 Limitation..................................................................................................................... 4 1.7 Outline of the Thesis .................................................................................................... 5

PROBLEM DEFINITION ...................................................................................................6

2.1 Problem Definition....................................................................................................... 6 2.2 Information for Applying Protection ........................................................................... 7

DESCRIPTION OF NETWORK UNDER STUDY..........................................................8

3.1 Introduction.................................................................................................................. 8 3.2 Grid Sub-Station Description....................................................................................... 8 3.3 Transmission Line and Conductor Information........................................................... 9 3.4 Conductor Impedance ................................................................................................ 10 3.5 Protective Devices...................................................................................................... 10

3.5.1 Distance Relay, Current Transformer and Voltage Transformer........................ 11 3.5.3 Other Protective Relays ...................................................................................... 12

STUDY ASPECT ................................................................................................................13

4.1 Load Flow Studies ..................................................................................................... 13 4.2 Short Circuit Study .................................................................................................... 14 4.3 Coordination Study.................................................................................................... 14

4.3.1 Primary and Back-up Protection......................................................................... 15 4.3.2 System Impedance .............................................................................................. 16 4.3.3 Relay Response ................................................................................................... 17

4.4 Output Data ................................................................................................................ 17 RELAY CHARACTERISTICS.........................................................................................18

5.1 Introduction................................................................................................................ 18 5.2 Types of Distance Relay............................................................................................ 18

5.2.1 MHO Characteristic ............................................................................................ 19 5.2.2 Offset MHO characteristic .................................................................................. 20 5.2.3 Quadrilateral Characteristic ................................................................................ 21

5.3 Effect of Arc Resistance ............................................................................................ 22 5.4 Power Swing .............................................................................................................. 22

5.4.1 Effect of Power Swings on the Performance of Distance Relays ....................... 23 5.5 Compensation for Correct Distance Measurement .................................................... 24

5.6 Carrier Aided Protection............................................................................................ 25 METHODOLOGY OF PROTECTION AND COORDINATION ................................26

6.1 Protection with Distance Relays ................................................................................ 26 6.1.1 Relationship between Primary and Secondary Impedances ............................... 26 6.1.2 Choice of Zone 1 Impedance Reach................................................................... 27 6.1.3 Choice of Zone 2 Impedance Reach................................................................... 27 6.1.4 Choice of Zone 3 Impedance Reach................................................................... 28 6.1.5 Choice of Zone 3 Reverse Impedance Reach: .................................................... 29 6.1.6 Choice of Relay Characteristic Angle................................................................. 29 6.1.7 Choice of Resistive Reach of Quadrilateral Characteristic ................................. 29 6.1.8 Co-ordination Criteria ......................................................................................... 29 6.1.9 Time Settings ...................................................................................................... 29 6.1.10 Zone-2 timer setting (TZ2) and Coordination.................................................... 30 6.1.11 Zone-3 Timer Setting (TZ3) and Coordination.................................................. 30 6.1.12 Summary of the Philosophy of Three-Stepped Distance Protection ................ 31 6.1.13 Ground Fault Compensation Setting................................................................. 31 6.1.14 Choice of Zone Setting for Ground Faults........................................................ 32 6.1.15 Mutual Compensation for Parallel Circuit ........................................................ 32 6.1.16 Calculations of Minimum Relay Voltage for a Fault at the Zone 1 Reach....... 32 6.1.17 Practical Applications for Phase and Earth Fault Connection.......................... 33

6.2 Maximum Source Impedance at Madunaghat and ..................................................... 33 Sikalbaha2 (for real case)................................................................................................. 33

DISCUSSION ON PROTECTION AND COORDINATION STUDY..........................34

7.1 Introduction................................................................................................................ 34 7.2 Discussion on Load flow and Short Circuit Analysis ................................................ 34 7.3 Discussion on Coordination Study............................................................................. 35

7.3.1 Existing Relay Setting......................................................................................... 36 7.3.2 Calculated/Proposed Impedance Value for Zone Setting ................................... 37 7.3.3 Madunaghat – Hathazari Feeders........................................................................ 38 7.3.4 Madunaghat – Kulshi 1 Feeder ........................................................................... 38 7.3.5 Madunaghat – Kulshi 2 Feeder ........................................................................... 39 7.3.6 Hathazari – Madunaghat Feeders........................................................................ 39 7.3.7 Madunaghat – Sikalbaha2 Feeders ..................................................................... 41 7.3.8 Baraulia - Hathazari Feeders............................................................................... 41 7.3.9 Hathazari - Baraulia Feeders............................................................................... 42 7.3.10 Kulshi – Madunaghat 1 Feeder ......................................................................... 43 7.3.11 Kulshi – Madunaghat 2 Feeder ......................................................................... 43 7.3.12 Halishahar – Sikalbaha2 Feeder........................................................................ 44 7.3.13 Kulshi – Baraulia 1 Feeder ............................................................................... 44 7.3.14 Kulshi – Baraulia 2 Feeder ............................................................................... 44 7.3.15 Kulshi – Halishahar Feeder............................................................................... 45 7.3.16 Baraulia – Kulshi 1 Feeder ............................................................................... 45 7.3.17 Halishahar – Kulshi Feeder............................................................................... 45 7.3.18 Baraulia – Kulshi 2 Feeder ............................................................................... 46 7.3.19 Sikalbaha2 – Halishahar Feeder........................................................................ 46 7.3.20 Sikalbaha2 – Madunaghat Feeder..................................................................... 47 7.3.21 Minimum Relay Voltages for a Fault at the Zone 1 Reach Point ..................... 48 7.3.22 Proposed Time Settings .................................................................................... 49

7.4 Auto Recloser and DEF ............................................................................................. 50

CONCLUSION AND RECOMMENDATIONS..............................................................51

BIBLIOGRAPHY...............................................................................................................54

APPENDIX A......................................................................................................................56

Single Line Diagram.................................................................................................... 56 A.6 Some important protection terminology ............................................................... 59

APPENDIX B ......................................................................................................................60

Short Circuit Analysis Results ..................................................................................... 60 APPENDIX C......................................................................................................................65

Power Flow Analysis Results ...................................................................................... 65 APPENDIX D......................................................................................................................67

D.1 Zone Setting Results ............................................................................................. 67 D.2 Calculation of Maximum Source Impedance at.................................................... 92 Madunaghat and Sikalbaha2 (for real case) ................................................................. 92

APPENDIX E ......................................................................................................................93

E.1ROUTINE TEST RECORD................................................................................... 93

i

LIST OF TABLES Table No. Caption Page 3.1 Maximum Load and Transformer Capacity 8 3.2 Conductor name and Line length of existing network 9 3.3 Impedance and current capacity of conductor 10 3.4 Relay type, CT ratio and P.T ratio of the existing network 11 3.5 Types and settings of other protective relay 12 5.1 Presence of sequence components 25 7.1 Zone and time setting of the network 35 7.2 Calculated positive sequence impedance for zone setting 37 7.3 Minimum relay voltage requirements for measurement of faults 48 7.4 The proposed time settings of distance relays

for existing network 49

ii

LIST OF FIGURES Figure No. Caption Page

4.1 Primary and back-up protection 15 5.1 MHO Impedance Characteristics 19 5.1.a MHO characteristic via a phase comparator 19 5.1.b MHO characteristic via a phase comparator 20 5.2 Offset MHO Characteristic 21 5.3 Three step quadrilateral characteristic 21 5.4 Effect of arc resistance on MHO relay 22 5.5 Effect of power surges on distance relays 23 6.1 Impedance measured by distance relay 26 7.1 Coordination curves of Madunaghat to Baraulia

and Kulshi section 38 7.2 Coordination curves of Madunaghat to Baraulia and Madunaghat – Sikalbaha2 section 39 7.3 Coordination curves of Madunaghat –Kulshi -Baraulia and Kulshi - Halishahar section 40 7.4 Coordination curves of Madunaghat-Sikalbaha,

Madunaghat –Kulshi-Baraulia and Halishahar section 40 7.5 Coordination curves of Madunaghat-Sikalbaha–Halishahar, Madunaghat–Kulshi section. 41 7.6 Coordination curves of Madunaghat - Sikalbaha - Halishahar and Kulshi – Halishahar – Sikalbaha2 section 42 7.7 Coordination curves of Hathazari - Baraulia - Kulshi section 43 7.8 Coordination curves of Kulshi –Baraulia and Madunaghat, and Halishahar-Kulshi section 44 7.9 Coordination curves of Madunaghat – Kulshi – Halishahar, Baraulia – Kulshi 1 and Sikalbaha2 – Halishahar section 46 7.10 Coordination curves of Sikalbaha2 – Madunaghat – Hathazari

and Kulshi 46 7.11 Coordination curves of Kulshi – Baraulia –

Hathazari – Madunaghat after time grading 47

iii

GLOSSARY OF ABBREVIATIONS

Abbreviation Full-Form First in page

BPDB Bangladesh Power Development Board 1 PGCB Power Grid Company of Bangladesh Limited 1 REB Rural Electrification Board 1 PSMP Power System Master Plan 1 EPZ Export Processing Zone 1 KV Kilo Volt 3 AAAC All Aluminium Alloy Conductor 6 MW Mega Watt 8 MVA Mega Volt Ampere 8 S/S Sub-Station 8 MCM Million Circular Mils 9 CB Circuit Breaker 10 O / km Ohm per Kilo Meter 10 0 C Degrees Centigrade 10 PTR Potential Transformer Ratio 12 CTR Current Transformer Ratio 11 C.T. Current Transformer 11 P.T./V.T. Potential/Voltage Transformer 11 O/C Over Current Relay 12 DEF Directional Earth Fault Relay 12 Tr Transformer 12 EHV Extra High Voltage 18 L-L Line to Line Fault 25 L-G Line to Ground Fault 25 L-L-G Double line to Ground Fault 25 L-L-L Three Phase Fault 25 PSB Power Swing Blocking 28 TZ Zone Time Setting 49 KA Kilo Ampere 58

1

Chapter 1 INTRODUCTION

1.1 Background and Motivation

Access to sustainable energy is identified as an important factor in alleviating poverty.

Major portion of the total population in Bangladesh do not have access to electricity. The

per capita electricity conjugation reflects the development of a country. At present only

20% of the population is served with electricity and per capita electricity consumption is

only 95 units (2000-2001). So, to provide reliable and quality electricity to the people is a

big challenge for our government.

From the beginning, Bangladesh Power Development Board (BPDB) was engaged with

Generation, Transmission and Distribution of electricity. Now there are other two

organizations named 1) Rural Electrification Board (REB) 2) Dhaka Electric Supply

Authority (DESA) are also involved to dis tribute the electricity. In 1996, Power Grid

Company of Bangladesh (An enterprise of BPDB) has formed to transmit the reliable and

quality bulk power through transmission line from one end to other end of the country.

With power demand growing rapidly (10% annually from 1974-1994; 7% annually from

2002-2003), Bangladesh's Power System Master Plan (PSMP) projects a required

doubling of electric generating capacity by 2010 and government committed to provide

affordable and reliable electricity to all citizens by 2020. In addition to, Chittagong is the

port city and a famous trade centre in Bangladesh. Most of the big industries and EPZ are

situated in the Chittagong city. In these circumstances, the uninterrupted power supply is

imperative for this city. Due to growing demand of power the load has been increased in

the grid system through distribution line. However, most electrical power transmission

and distribution systems are not planned with protective device coordination in mind. A

supply system can be designed for minimum losses and minimum upfront investment and

yet fail miserably in the proper coordination of the protective devices. As a result

equipment failures within the system can easily result in the shutdown of the entire plant

or substation. The objective of this collaborative project is to develop a maximum

protection of equipment, transmission lines and a consistence statistical framework for

2

evaluating year-to-year variation of transmission service quality and stability performance

indicators.

The power systems are usually large, complex and, in many ways, nonlinear systems. The

post-fault phenomena in a power system are dynamic in nature and dependent on the grid

connection and load flows in different parts of the grid. Thus the fault analysis and

protection coordination of a power system is a difficult task.

Transmission line protection has a central role in power system protection because

transmission lines are vital elements of a network which connects the generating plants to

the load centres. Since the consequence of power outage of a high voltage line is far more

serious than that of a distribution or sub transmission line, the protection of the bulk

power transmission line is generally more elaborate, with greater redundancy, and is also

more expensive [1]. The transmission system operators try to keep the security of the grid

at as high a level as possible. The resources for that are always limited. Most benefit from

the existing resources can be received if the decisions in investments, maintenance and

operation prove to be correct.

One of the most important requirements of electric power system operation is to isolate

and disconnect faulted parts of the system selectively and quickly. As a side benefit of a

coordination study the interrupting ratings of all protective equipment, conductors, and

switches are checked for adequacy. Inadequate equipment ratings can result in either

extensive damage to the equipment during faults and system operation and may introduce

hazards to plant operating personnel.

The main idea of the study is to obtain short circuit and load flow data for the existing

ring network sub-station and to acquire skill necessary for protective device coordination,

proposed the best protection and coordination through a case study. This report is about a

project conducted as part of the fulfilment of the requirements for the course in Master of

Electrical Power Engineering (MEPE) conducted by the department of School of

Engineering, Kathmandu University, Nepal and collaboration with Norwegian University

of Science and Technology, NTNU, Norway.

This project report is a small work out based on the requirement, the power system

analysis and protective device coordination for the safe and reliable power supply of the

3

Power Grid Company of Bangladesh Limited (PGCB), Bangladesh who are solely

responsible for transmission of electric power in Bangladesh at voltage levels 230 KV,

132 KV and 66 KV. In Bangladesh, the generating stations are located at different parts

of the country, which are interconnected by grid networks. In fact, this project work is not

sufficient to coordinate all protective devices for whole interconnected network. This

project deals with a portion of national grid networks which is supplying power in

Chittagong zone of Bangladesh.

1.2 Objectives of the Project

A sectionalizing study analyzes the impacts of short circuits and equipment failures

within a facility and determines the effects on the facility operation. Informed decisions

can then be made as to the changes necessary for the system. The main goal of this

project is to make general guidelines for protection coordination from which the

transmission protection system will be improved in Bangladesh.

The main objectives are fault calculation, recommendation for protection coordination

proposal, coordination of existing systems, coordination of proposed systems,

coordination curves, justification of protective devices proposed for line, tabulation of

fault analysis, tabulation of Coordination results and Analysis and recommendations.

1.3 Scope of the Project

The scope of the project involves with: Maximizes power system selectivity by isolating

faults to the nearest protective devices, Identification of maximum and minimum

momentary short-circuit current, Identification of ground fault current at major buses,

Identification of existing coordination problem of the system, Identification of optimum

coordination and protection of the system, Identification of proper ratings of the

protective devices.

1.4 Review of Coordination

In power system, small changes in loading conditions occur continually. The power

system must adjust to these changing conditions and continue to operate. Therefore,

4

sometimes it has to upgrade the equipment and system protective devices. A new or

revised coordina tion study should be made when the available short circuit current from

the power supply is increased, new large loads are added or existing equipment is

replaced with larger equipment, a fault shuts down a large part of the system and

protective devices are upgrade.

1.5 Research Method

1.5.1 Data Collection The initial phase included data collection of the network that is selected for a case study.

All data collected from PGCB Ltd. of Bangladesh.

1.5.2 Procedure and Outcome

The load flow study and short circuit analysis has carried out with the help of Net Bas

program. The coordination study and analysis has done manually. The coordination

curves were prepared by Microsoft Excel and illustrated adequate clearing times between

series devices. Zone 1, Zone 2 and Zone 3 are the computational methods for distance

relay used in this project. Manufacturer’s guidelines also followed for distance relay

settings.

The outcome of the project has tabulated and written in the form of report.

Recommendations were made for the best protection of the grid network in Bangladesh.

A general report provided to improve the protection system as well as to review of the

coordination of the system by implementing this information.

1.6 Limitation

1. Due to software constraint, the coordination study has done manually. Therefore,

the coordination curves were made by Microsoft Excel where the time in y axis is

given as a negative value to make the curve for both end relay of the protected

line. In practice it will be positive value. It is not possible to calculate the earth

fault current by using Net Bas program, that is why, existing earth fault current

5

were tabulated. In addition to, the phase fault current calculated by Net Bas are at

different busbar locations. It is not possible to calculate the fault current in

between of the protected line section. Therefore, artificial node has created

between the protected line sections to find out the fault current at a particular

distance which has given post- fault voltage zero at node point. In practice, this

post-fault voltage is not zero.

2. Due to time constraint and insufficient data (number of power interruptions,

duration of interruptions and affected consumer etc and data was not organized.),

the reliability analysis are skipped of the existing network. In addition to,

transformer protection is reviewed only for Kulshi grid sub-station due to same

cause, but the basic principle is same for transformer protection of another grid

sub-station. The network that is selected for case study is modified slightly for

insufficient data.

1.7 Outline of the Thesis

After the introduction, Chapter 2 describes the problem definition of the existing network

for which the sectionalizing study needs to be done. Chapter 3 presents the existing

network protection system and those details that are needed for this study. Some aspects

of the transmission system protection are presented in Chapter 4.

Chapter 5 describes the relay characteristics that are used in the existing network. Chapter

6 discusses about the methodology of the protection coordination where all factors are

included that is important for coordination. Based on this methodology the zone settings,

minimum relay voltage during the fault and compensation factor are calculated.

The discussion on load flow analysis, short circuit analysis and coordination is presented

in Chapter 7. In this Chapter the justifications of proposed settings are also described.

Conclusion and Recommendations are presented in Chapter 8.

6

Chapter 2 PROBLEM DEFINITION

2.1 Problem Definition

In Bangladesh, the national transmission grid voltage levels are 230KV, 132KV and 66

KV. The single line diagram of the network is shown in appendix (A), where all grid sub-

stations are at voltage levels 132 KV except Hathazari grid sub-station at voltage levels

230 KV and 132 KV. The transmission lines are overhead lines with Grosbeak and

AAAC conductors and are supported on steel tower. All power transformers and

equipment are out door type. Each of sub-station is contain with main and auxiliary bus

bar. The system mainly protected with distance relay, directional earth fault relay,

percentage differential relay, over current relay, circuit breakers, etc.

With such a network, the problem is how to maintain a safe, reliable and efficient energy

supply by ensuring that transmission line and equipment are well protected in the event of

fault. Protection system must recognize the existence of a fault and initiate circuit breaker

operation to disconnect faulted facilities of the system selectively and quickly. The

actions required assure minimum disruption of electrical services and limit damage in the

faulted equipment. This can only be achieved if the protective devices are well

coordinated. Although, the existing network was coordinated when it was installing but it

should be reviewed of coordination as causes described in chapter 1. [Ref. article 1.4]

The equipment has been upgraded in the network due to growing demand of power where

in most cases it was not planned with protective device coordination in mind. Therefore,

there is loss of selectivity between upstream and downstream protective devices.

Another problem is single shoot auto reclosing is used in the network where the both end

breaker will not trip simultaneously if any fault occurs beyond the zone 1 reach at either

end . Therefore, there is chance to jeopardize of the successful recloser of the existing

system which may reduce the power stability and may start generator from drifting apart

of the network. In this circumstance this study needs to be done for proper coordination.

7

2.2 Information for Applying Protection

One of the most difficult aspects of applying protection is often an accurate statement of

protection requirements or problem. The following checklist of information is required

for application of protection.

A single line diagram for applications documenting the system to be studied are

necessary, Appendix (A) showing the location of grid sub-stations, maximum load,

voltage and current level of the network. System grounding and arc fault resistance are

also necessary for studying ground fault protection. Impedance and connection of power

equipment, system frequency, voltage and currents are important for study that are

documented in chapter 3 and Appendix (A). Existing protection problems of the network

which is highlighted under chapter 2 and 7. Operating procedures and practices are

illustrated in chapter 5 and 6 for coordination study. System fault study is important for

power system protection applications. For phase fault protection, a three-phase fault study

is required while for ground fault protection, a single line to ground fault study is

required. System fault study is covered in chapter 7 and Appendix B. The required data

on system under study that are transformer ratings and impedance data, protective devices

ratings including momentary and interrupting duty as applicable, characteristics curves

for protective device, CT ratios, excitation curve and winding resistance, P.T ratios of the

system, conductor sizes and length and sequence impedance of the conductor and source.

These are documented in chapter 3.

The following information shall be included in the tabulation:

a. Bus identification.

b. Location identification.

c. Voltage

d. Manufacturer and type of equipment.

e. Device rating.

These are also documented in chapter 3 and Appendix A.

8

Chapter 3 DESCRIPTION OF NETWORK UNDER STUDY

3.1 Introduction

The transmission network that is selected for study of 132/33 KV grid sub-stations

protection in Chittagong zone of Bangladesh under Power grid company of Bangladesh

Limited (An enterprise of BPDB). This network is a mesh connected network which

consists with Madunaghat, Hathazari, Kulshi, Baraulia, Halishahar and Sikalbaha grid

sub-stations. This network is delivering power in Chittagong zone and national grid as

well. There are two generating power plants of total capacity 460 MW are feeding power

at Madunaghat and Sikalbaha sub-station.

The single line diagram of the network is shown in appendix (A).

3.2 Grid Sub-Station Description

The maximum load, transformer capacity, source information and load flow of each sub-

station are given below:

Table 3.1 Maximum Load and Transformer capacity.

Name of Grid S/S

Maximum Load, MW

Transformer Capacity, MVA

Source (From)

Remarks

Madunaghat 55 1 × 25/41.7 1 × 25/41

Generating Station

Hathazari 50 2 × 44.1/63 Madunaghat Supplying power to national Grid

Kulshi 98 2 × 44.1/63 Madunaghat Baraulia 135 1 × 28/40

1 × 25/41.7 Hathazari, Kulshi

Supplying power to national Grid

Sikalbaha2 5 2 × 25/41.7 Generating Station

Halishahar 100 2 × 44.1/63 1 × 25/41.7

Sikalbaha2, Kulshi

The load flow of the network is shown in appendix (A) and (C).

9

3.3 Transmission Line and Conductor Information

The conductor name and size, circuit and line length of the network are given in table

below.

Table 3.2 Conductor name and Line length of existing network.

Name of Grid S/S Name of Feeder Conductor Name & Size Line

Length, km

Circuit

Hathazari – 1 Grosbeak, 636 MCM 9

Hathazari – 2 Grosbeak, 636 MCM 9

Double

Kulshi – 1 Grosbeak, 636 MCM 12.7

Kulshi – 2 Grosbeak, 636 MCM 12.7

Double

Sikalbaha2 – 1 Grosbeak, 636 MCM 16.1

Madunaghat

Sikalbaha 2– 2 Grosbeak, 636 MCM 16.1

Double

Baraulia – 1 Grosbeak, 636 MCM 12.9

Baraulia – 2 Grosbeak, 636 MCM 12.9

Double

Halishahar Grosbeak, 636 MCM 13.5 Single

Madunaghat – 1 Grosbeak, 636 MCM 12.7

Kulshi

Madunaghat - 2 Grosbeak, 636 MCM 12.7

Double

Madunaghat – 1 Grosbeak, 636 MCM 9

Madunaghat – 2 Grosbeak, 636 MCM 9

Double

Baraulia – 1 Grosbeak, 636 MCM 12

Hathazari

Baraulia – 2 Grosbeak, 636 MCM 12

Double

Kulshi – 1 Grosbeak, 636 MCM 12.9

Kulshi – 2 Grosbeak, 636 MCM 12.9

Double

Hathazari – 1 Grosbeak, 636 MCM 12

Baraulia

Hathazari – 2 Grosbeak, 636 MCM 12

Double

Kulshi Grosbeak, 636 MCM 13.5 Single Halishahar

Sikalbaha2 AAAC 12.9 Single

Madunaghat – 1 Grosbeak, 636 MCM 16.1

Madunaghat - 2 Grosbeak, 636 MCM 16.1

Double Sikalbaha2

Halishahar AAAC 12.9 Single

10

3.4 Conductor Impedance

The positive and zero sequence impedance of conductors are very necessary for distance

protection of transmission lines.

The impedances of conductor which used in the existing network are given below:

Table 3.3 Impedance and current capacity of conductor

Positive & Negative

sequence Impedance,

Zero sequence

Impedance

Name &

Size of

Conductor

Current

Capacity, A

Stranding

r1 = r2, at

50 0 C

O / km

x1 = x2,

O / km

ro

O/ km

xo

O/km

Grosbeak,

322 mm2

790 26/7 0.099 0.385 0.24 0.98

AAAC,

804 mm2

777 61/4 0.0534 0.43 0.106 0.8

Where, r1 is the positive sequence resistance, r2 is the negative sequence resistance, x1 is

the positive sequence re4actance, x2 is the negative sequence reactance, ro is the zero

sequence resistance and xo is the zero sequence reactance. The ambient temperature is

normally 35 0 C in Bangladesh.

3.5 Protective Devices

Speedy elimination of a fault by the protection system requires correct operation of a

number of subsystems of the protection system. The protection system can be subdivided

into three subsystems. They are Circuit Breakers (CB), Transducers (T) and Relays (R).

The specification and type of these subsystems of the existing network are given below.

The manufacturer and specifications of CB is tabulated in Appendix (A).

11

3.5.1 Distance Relay, Current Transformer and Voltage Transformer

Table 3.4 Relay type, CT ratio and P.T ratio of the existing network

Line Parameter

(Primary ohm)

Relay Information

Positive

sequence

Zero Sequence

Name of

Grid S/S

Name of

Feeder

Z1 Angle0 Z0 Angle0

Relay

type

CTR

(A)

PTR, V

Hathazari – 1

3.57 69.5 9.12 76.3 SHPM101 800/5 132000/110

Hathazari – 2 3.57 69.5 9.12 76.3 SHPM101 800/5 132000/110

Kulshi – 1 5.384 76.1 12.86 76.3 SHPM101 400/5 132000/110 Kulshi – 2 5.384 76.1 12.44 76.3 SHPM101 800/5 132000/110 Sikalbaha2 – 1 6.384 75.5 13.26 76.1 SHPM101 400/5 132000/110

Madunaghat

End

Sikalbaha 2– 2 6.384 75.5 16.32 76.1 SHPM101 400/5 132000/110 Madunaghat-1 5.384 76.1 12.44 75.8 LZ32 400/5 132000/110 Madunaghat-2 5.384 76.1 12.44 75.8 LZ41a 800/5 132000/110 Baraulia – 1 5.135 75.3 10.63 76.1 REL

316*4

800/5 132000/110

Baraulia – 2 5.135 75.3 10.63 76.1 SHPM101 800/5 132000/110

Kulshi End

Halishahar 5.722 75.3 9.89 76.1 LZ41a 800/5 132000/110 Madunaghat-1 3.57 69.5 9.12 76.3 SHPM101 600/1 132000/110 Madunaghat-2 3.57 69.5 9.12 76.3 SHPM101 600/1 132000/110 Baraulia – 1 4.776 75.2 9.89 70.1 SHPM101 600/1 132000/110

Hathazari

End

Baraulia – 2 4.776 75.2 9.89 70.1 SHPM101 600/1 132000/110 Kulshi – 1 5.135 75.3 10.63 76.1 REL

316*4

800/5 132000/110

Kulshi – 2 5.135 75.3 10.63 76.1 SHPM101 800/5 132000/110 Hathazari – 1 4.776 75.2 9.89 70.1 SHPM101 800/5 132000/110

Baraulia

End

Hathazari – 2 4.776 75.2 9.89 70.1 SHPM101 800/5 132000/110 Kulshi 5.722 75.3 9.89 76.1 LZ41a 800/5 132000/110 Halishahar

End Sikalbaha2 5.58 82.9 10.41 82.4 SHPM101 800/5 132000/110 Madunaghat-1 6.384 75.5 13.26 76.1 SHPM101 400/5 132000/110 Madunaghat-2 6.384 75.5 13.26 76.1 SHPM101 400/5 132000/110

Sikalbaha2

End

Halishahar 5.58 82.9 10.41 82.4 SHPM101 800/5 132000/110 Sikalbaha 1 Source 6.2 85

Madunaghat Source 12.8 85

12

3.5.3 Other Protective Relays

Other protective relays are also used to protect the existing network properly. Some of

important relays are summarized in Table 3.6.

Table 3.5 Types and settings of other protective relays

Name of Grid S/S

Relay used Relay Setting

Madunaghat End

E/F relay (67G), GEC, USA. Auto reclosing relay (79R1) , NTJ-20, Japan Voltage relay, CV-5-D, Japan Synchronizing relay (same for all feeders)

Inst. 0.45s, P.S-1.0, D.S-0.2

P.S -120, D.S -10

Kulshi End E/F relay (67G), GEC, USA. Auto reclosing (79R1), NTJ-20, Japan Voltage relay, CV-5-D, Japan (For all feeders) Auto reclosing relay, PR5iq, BBC (for Kulshi - Madunaghat 1)

Inst. 0.45s, P.S-1.0, D.S-0.2

P.S -120, D.S -10

Inst. 0.15s, P.S-1.0, D.S-0.2

P.S -120, D.S -10 (E/F relay time setting for Kulshi –

Baraulia 2) Hathazari End

E/F relay (67G), GEC, USA. Auto reclosing (79R1) , NTJ-20, Japan Voltage relay, CV-5-D, Japan (For all feeders)

Inst. 0.45s, P.S-1.0, D.S-0.2

P.S -120, D.S -10

Baraulia End E/F relay (67G), GEC, USA. Auto reclosing (79R1) , NTJ-20, Japan Voltage relay, CV-5-D, Japan (For all feeders) Auto reclosing (79R1) , PR5iq, BBC (for Baraulia - Madunaghat 1)

Inst. 0.45s, P.S-1.0, D.S-0.2

P.S -120, D.S -10

Halishahar End

E/F relay (67G), GEC, USA. Auto reclosing (79R1) , NTJ-20, Japan Voltage relay, CV-5-D, Japan (For all feeders)

Inst. 0.45s, P.S-1.0, D.S-0.2

P.S -120, D.S -10

Sikalbaha2 End

E/F relay (67G), GEC, USA. Auto reclosing (79R1) , NTJ-20, Japan Voltage relay, CV-5-D, Japan (For all feeders)

Inst. 0.45s, P.S-1.0, D.S-0.2

P.S -120, D.S -10

Tr 1 (Primary)

O/C (51& 51G), Japan Differential relay (87), Japan

Inst. 0.3 s, P.S - 3.75, D.S -5 % =35

Tr 1 (Secondary)

O/C relay(51& 51G), Japan P.S - 5, D.S – 3.75

Tr 2 (Primary)

O/C relay (51& 51G), Japan Differential relay (87), Japan

Inst. 0.3 s, P.S - 3.75, D.S -5 % =35

Kulshi Grid

Tr 2 (Secondary)

O/C relay(51& 51G), Japan P.S - 5, D.S – 3.75

13

Chapter 4 STUDY ASPECT

4.1 Load Flow Studies

Load flow study is the determination of voltage, current, active and reactive power at

different locations of a network. By using a computer program, starting with system

operating under normal condition, the flow in all branches can be quickly computed for

compression with all other cases, present and future. Some changes that can be introduced

individually or in combination, to determine the effect on the system are: To take any line

or transformer out of service, Addition of new load to any branches or any buses,

Addition of new lines, Removal, adding or shifting of generation to any buses, Changes

of conductor size, Changes of transformer size and Upgrade of protective devices.

So, load flow studies are essential in planning the future expansion, best operation of the

system, and security of the system. In this project work, load flow analysis has been

carried out with the help of Net Bas program.

Load flow can have an adverse effect on relay performance, but most probably the

majority of applications are made and settings calculated where load flow is either

assumed to be zero or considered in a cursory manner. However, there are certain relays

and schemes where load flow must be comprehensively analyzed to permit a viable

application. In other cases load flow may be neglected and the relay system will perform

properly until a contingency situation arise that causes an incorrect relay operation

attributable to the effects of load flow.

An ideal distance relay sees an apparent impedance equal to the positive sequence

impedance from the relay location to the fault location. There are many factors that

conspire against a realization of such an ideal distance relay. Load flow coupled with

fault arc resistance / ground fault impedance can result in overreach for line-end faults

and incorrect directional action for close- in reverse faults [2].

14

4.2 Short Circuit Study

There are two types of short circuit studies of interest to the power engineer. The first

determines the first –cycle (momentary) and contact-parting (interrupting) short circuit

current duties (i.e. asymmetrical rms or peak currents) at the buses of the power system,

which are used to select the short circuit withstand and interrupting capabilities of

switchgear. The second type of study determines the subtransient and transient short

circuit currents that an overcurrent protective device will sense in order to initiate the

prompt removal of the affected portion of the power system by its circuit interrupter.

These short circuit currents are necessary to properly select the instantaneous and time

delay settings of the overcurrent protective scheme [3].

Although, virtually distance relay is independent of fault current, but fault current is

necessary for measuring the fault distance from the relaying point.

In this study, short circuit calculations that have been carried out with the help of Net Bas

program. But it is not possible to calculate the ground fault current by using the present

version of Net Bas program.

4.3 Coordination Study

The basic role of the protection scheme is to sense faults and isolate these faults by

opening all incoming current paths. However, the protection scheme must be selective so

that only faulted element is removed i.e. isolated. Therefore, a coordination study

maximizes power system selectivity by isolating faults to the nearest protective device, as

well as helping to avoid nuisance operations. One of the main topics of concern

protection engineers is the proper coordination behaviour of different relay units so as to

avoid relay mal-operation. Before arriving at proper relay coordination and relay settings,

several factors have to be taken into account and several consequences are to be

considered which are described in chapter 6. In fact, for proper coordination, it is better to

follow the relay manual guides which are provided by manufacturers.

15

4.3.1 Primary and Back-up Protection

A power system is divided into various zones for its protection. There is a suitable

protective scheme for each zone; it is the duty of the primary relays of that zone to isolate

the faulty element. The primary protection is the first line to defence. If the primary

protection fails to operate, there is a back-up protective scheme to clear the fault as a

second line to defence.

The causes of failures of primary protection could be due to failure of the CT/VT or relay,

or failure of the circuit breaker. The back-up protection should also preferably be located

at a place different from where the primary protection is located. Further, the back-up

protection must wait for the primary protection to operate, before using the trip command

to its associated circuit breakers. In other words, the operating time of the back-up

protection must be delayed by an appropriate amount over that of the primary protection.

Thus the operating time of the back-up protection should be equal to the operating time of

primary protection plus the operating time of the primary circuit breaker.

Consider the radial transmission system shown in figure in below. Relay B, provides

primary protection to the line section B-C. Relay A with circuit breaker CBA provides

back-up protection to the section B-C.

Consider a fault in section B-C as shown in figure. When a fault occurs, both the primary

relay RB and the back-up relay RA, start operating simultaneously. In case the primary

protection operates successfully, the line B-C gets de-energized but the loads on buses A

and B remain unaffected. Therefore, the back-up protection resets without issuing trip

Relay A operating time

C STI

CBB

TA

TB

Fault CBA

A Time

Figure 4.1 Primary and back-up protection

B

16

command. However, in case the primary protection fails to operate, the back-up relay

which is monitoring the fault, waits for the time in which the primary would have cleared

the fault and the issues the trip command to its allied circuit breakers.

Therefore, back-up relaying time > primary fault clearing time.

TA > TB + CBB (breaker operating time)

In general, there are three types of back-up relays.

a) Remote back-up

b) Relay back-up

c) Breaker back-up

Remote back-up:

When back-up relays are located at a neighbouring station, they backup the entire primary

protective scheme which includes the relay, circuit breaker, PT, CT and other elements, in

case of the primary protective scheme. It is the cheapest and simplest form of back-up

protection and is widely used back-up protection for transmission line.

Relay back-up:

This is kind of a local back-up in which an additional relay is provided for back-up

protection. It trips the same circuit breaker if the primary relay fails and this operation

takes place without delay. Though such a back-up is costly, it can be used where remote

back-up is not possible.

Breaker back-up:

This is also kind of a local back-up is necessary for a bus bar system where a number of

circuit breakers are connected to it. When a protective relay operates in response to a fault

but the circuit breaker fails to trip, the fault is treated as a bus bar fault. In such a

situation, it becomes necessary that all other circuit breakers on that bus bar should trip.

4.3.2 System Impedance The impedance of the power system may be divided into two parts. Firstly, the impedance

behind the relaying point, including the generators, feeders, transformers, etc., forms the

source impedance. The second part is the impedance to the fault in front of the relaying

point, which is governed by the geometrical arrangement, size, shape, spacing and

material of the conductors. Generally, this impedance data are provided by manufacturers.

Both of this impedance must be known to determine the faults levels and setting of the

relays.

17

4.3.3 Relay Response

To find the reaction of a relay to a system disturbance the voltages and currents at the

relaying point must be determined. This may be done practically, using a network

analyzer or theoretically. In this study, the fault currents and post-fault voltages at

different buses have been determined by Net Bas Program where minimum relay voltage

at the fault point calculated by hand calculation due to unavailable of software program.

4.4 Output Data

Results are calculated for each sub-stations relay and tabulated with appropriate station

names. The tables and appendix display the following:

1. Pre fault voltages, system nominal voltages are used in this study.

2. Minimum relay voltage

3. Total three phase bus fault current

4. Phase to phase fault currents.

5. Line current contribution for each bus fault for three phase faults.

6. Relay zone and time settings.

7. Short circuit results

8. Summary of load flow

9. Ground faults compensation factor.

18

Chapter 5 RELAY CHARACTERISTICS

5.1 Introduction

The reach and operating time of the over-current relay depend upon the magnitude of

fault current and the fault current at a particular location depends upon the type of fault

and the source impedance. Since neither the type of fault nor the source impedance is

predictable, the reach of the over current relay keeps on changing depending upon the

source conditions and the type of fault. Thus even though the relays are set with great

care, since their reach is subject to variations, they are likely to suffer from loss of

selectivity. Such a loss of selectivity can be tolerated to some extent in the low voltage

distribution system. However in high voltage or EHV interconnected system, loss of

selectivity can lead to danger to the stability of the power system, in addition to large

disruptions to loads. Therefore, over-current relay can not provide adequate protection in

high voltage systems. Distance relay is not bound by the same limitations as overcurrent

protection.

5.2 Types of Distance Relay

The most important and versatile family of relays is the distance relay group. It includes

the following major types-

1) Impedance relays

2) Reactance relays

3) MHO relays

4) Angle impedance relays

5) Quadrilateral relays etc.

The network that is selected for a case study of 132/33 KV grid sub-stations, where

MHO and Quadrilateral types of distance relays are being used as a primary and back-up

protection of transmission lines and busbars. Therefore, the characteristics of MHO relay

and Quadrilateral relay are discussed only in this study. Besides that, E/F over current

relay and Differential relay characteristics are also included in brief.

19

5.2.1 MHO Characteristic

The MHO characteristic, as seen on the impedance polar diagram, is a circle whose

diameter is the relay impedance setting vector, such that the characteristic passes through

the origin of the impedance diagram, as shown in Figure 5.1. The MHO relay is therefore

directional.

The MHO characteristic is commonly generated via a phase comparator which compares

the phase of S1 and S2 as illustrated in Figure 5.1.a.

Voltage to Relay = V

Current to Relay = I

Replica Impedance = Zr

Trip condition: ∠ S1 – S2 = θ < 900

Where, S2 = IZr - V

S1 = V

R

JX

Figure 5.1 MHO Impedance Characteristics

T1

T2

T3

S1

V3

IZr

IR

JIX

S2 Trip

V1 Stable

Figure 5.1.a MHO characteristic via a phase comparator

P

θ

20

If the point P lies within the circle, the phase angle between S1 and S2 is less than 900

(900 > ∠ S1 – S2). If P lies outside the circle, the phase angle is greater than 900 (900 < ∠

S1 – S2).

If we divide all vectors in above figure by I, the resulting vector diagram will be as shown

in Figure 5.1.b

V = IZ

S2 ∝ IZr – V ∝ Zr - Z

S1 ∝ V ∝ Z.

Angle between (Zr – Z3) and Z3 < 900 or > - 900 Trip

Angle between (Zr – Z1) and Z1 > 900 or < - 900 Restrain

MHO characteristic relays are very popular due to their simplicity. Compared with

directionalised impedance characteristic distance relay, a MHO characteristic relay is less

sensitive to operation due to power swing and load encroachment but it has lower

resistive coverage in the impedance plane.

5.2.2 Offset MHO characteristic

Where it is required that a distance relay element has some ability to see faults on the

busbar behind the relaying point, to provide local back-up protection for uncleared busbar

faults or to allow tripping for 3-phase faults close to the relaying point during line

energisation, then offset MHO characteristic is commonly used for distance relay Zone 3

elements.

R

JX

S1

S2 Trip

Zr

Z3

Z1 Stable

Figure 5.1.b MHO characteristic via a phase comparator

θ

21

An offset MHO characteristic can be produced via phase comparator as depicted in

Figure 5.2. With an offset MHO characteristic, the forward and reverse reach can be set

independently.

Trip Condition, ∠ S1 – S2 = θ < 900 .

5.2.3 Quadrilateral Characteristic

A quadrilateral relay is suitable for long as well as short lines. This relay characteristics

would allow the ground fault resistive reach to be increased or decreased independently

of the forward reach and source impedance behind relay so that the required ground fault

resistive coverage can be achieved.

Figure 5.2 Offset MHO Characteristic

S1

S2 R

X

Z

-Z

R

X

Zone 1

Zone 2

Zone 3

Figure 5.3 Three step quadrilateral characteristic

22

5.3 Effect of Arc Resistance

If a flashover from phase to phase or phase to ground occurs, an arc resistance is

introduced into the fault path which is appreciable at higher voltages. The arc resistance is

added to the impedance of the line and hence, the resultant impedance which is seen by

distance relays is increased. In case of ground faults, the earth resistance is also

introduced into the fault path.

The arc resistance is treated as pure resistance in series with the line impedance, where

reactive component is negligible.

Figure 5.4 shows the effect of arc resistance on a MHO relay. The characteristics angle of

the relay is the same as the characteristic angle f of the line. For a fault at the point F, the

actual line impedance up to fault is Zf but the impedance measure the by the relay is (Zf +

R). That is why, this shows that arc resistance causes underreach and relay fails to

operate.

5.4 Power Swing

In an interconnected power system, under steady state condition, all the generators run in

synchronism. There is a balance between the load and generation. This state is

characterized by constant rotor angles. However, when there is a disturbance in the

system, say, shedding of a large chunk of load, changes in direction of power flow or

sudden removal of faults, the system has to adjust to the new operating conditions. In

X

Figure 5.4 Effect of arc resistance on MHO relay

ZF+R

F R

Zl

R

Zf + R

F

f

Zf

23

order to balance the generation with the load, the rotors need to take on new angular

positions. Because of the inertia of the rotating system and their dynamics, the rotors

slowly reach their new angular positions in an oscillatory manner and which occurs, in a

rather slow oscillatory manner, subsequent to some large disturbance is known as power

swing. During rotor swings, the rotor angle changes and the current flowing through the

line also changes which currents are heavy.

5.4.1 Effect of Power Swings on the Performance of Distance Relays

During power swings, the current ‘seen’ by the relay is also changing. Therefore, the

impedance measured by the relay also varies on that period. Thus, a power surge ‘seen’

by the relay appears like a fault which is changing its distance from the relay location. In

the case of a transient power swing it is obviously important that the distance relay should

not trip.

The characteristic of some important distance relay and power surge are shown on the R-

X diagram, Figure 5.5. It is evident from the figure that the relay characteristic occupying

greater area on the R-X diagram remains under the influence of the power surge for a

greater period and hence, it is more affected by power surges.

Figure 5.5 Effect of power surges on distance relays

MHO Relay

Reactance Relay

R

Power Surges

Impedance Relay

X

24

The MHO relay having the least area on the R-X diagram is least affected. The

impedance relay characteristic has more area than the MHO relay but lesser area than a

reactance relay.

5.5 Compensation for Correct Distance Measurement

Although the same relays are employed for both phase to phase and three phase faults,

they do not measure the same impedance between the fault point and the relay location

for each type of fault unless proper compensation provided. If a distance relay is

energized by line to line voltage and line current, the impedance seen by the relay will be

2Z1 for a phase to phase fault and v3Z1∠300 for a three phase fault. If the relay is fed with

phase voltage and phase current, the impedance seen is (Z1 + Z2 + Z3)/3 for a line to

ground fault. But it depends on the number of sources and the number of earthed neutral

available at the time. To measure the same impedance for phase to phase and three phase

faults, the measuring unit is energized by line to line voltage and the difference between

the currents in the corresponding two phases as given below:

Relay Voltage Current

a-b phase pair Vab Ia – Ib

b-c phase pair Vbc Ib – Ic

c-a phase pair Vca Ic – Ia.

For phase faults to ground faults, the measuring units are energized by phase to neutral

voltage and corresponding phase current, plus a fraction of the residual current.

Relay Voltage Current

a - Phase Va Ia + 1/3 (K-1)Ires

b - Phase Vb Ib + 1/3 (K-1)Ires

c - Phase Vc Ic + 1/3 (K-1)Ires

Where = Z0/Z1 and Ires = Ia + Ib + Ic = 3I0.

The following table shows presence of sequence components in various faults

25

Table 5.1 presence of sequence components

Fault Positive sequence Negative sequence Zero sequence

L-G Yes Yes Yes

L-L Yes Yes No

L-L-G Yes Yes Yes

L-L-L Yes No No

From the above table it can be seen that positive sequence component is the only

component which is present during all faults.

5.6 Carrier Aided Protection

The carrier current protection capable of providing high speed protection for the whole

length as well as it initiates circuit breakers to trip simultaneously at both ends. In a

carrier scheme, the carrier signal can be used to prevent the operation of the relay which

is called carrier blocking scheme. When the carrier signal is employed to initiate tripping,

the scheme is called a carrier inter tripping or transfer tripping scheme.

There are two important operating techniques employed for carrier current protection

namely the phase comparison technique and directional comparison technique.

26

Chapter 6 METHODOLOGY OF PROTECTION AND COORDINATION

6.1 Protection with Distance Relays

The conventional distance relay uses three distance measuring units. The protected zone

of the first unit is called the first zone of protection. It is high speed unit and is used for

the primary protection of the protected line. Its operation is instantaneous, about 1 to 2

cycles. The protected zone of second unit is called the second zone of protection. The

setting of the second unit is so adjusted that it operates the relay even for arching faults at

the end of the line. The third zone of protection is provided for full back-up protection of

the adjoining line.

6.1.1 Relationship between Primary and Secondary Impedances

Relays are calibrated in secondary ohms of the sequence impedance of the line.

Figure 6.1 Impedance measured by distance relay

ZR = R

R

VI

=

2FP

1

2FP

1

VV ×

VI

I ×I

= FP

FP

VI

×

1

2

1

2

IIVV

= Zp × C.T.ratioV.T.ratio

= ZS

IR

VR

I1/I2

V1/V2

Zp

27

Where, ZR is the relay impedance, VFP is the fault voltage at the fault point, IFP is the fault

current at the fault point, Zp is the positive sequence impedance of the line and ZS is the

secondary positive sequence impedance of the line.

Relay calibration, characteristics and setting calculations are in terms of secondary

impedance.

6.1.2 Choice of Zone 1 Impedance Reach

Although in most applications the reach accuracy of the relay distance comparators is ±

5%, greater errors can occur as a result of voltage and current transformer errors and

inaccuracies in line data from which the relay settings are calculated. To prevent the

possibility of relays tripping instantaneously for faults in the next line, it is usual to set the

zone 1 reach of the relay to 80% - 90% of the protected line section and relay on zone 2 to

cover the remaining 20% of the line. With a signal aided distance protection scheme

arrangement, the zone 2 distance comparators could provide fast tripping at both ends of

the line for end-zone faults. If the zone 1 extension scheme is used, it is usual practice to

set the zone 1 extension to 150% of the normal zone 1 reach.

6.1.3 Choice of Zone 2 Impedance Reach

The principle purpose of the second zone unit of a distance relay is to provide protection

(able to cover bus faults also) for the rest of the line beyond the reach of the first zone

unit. As a general rule, the Zone 2 impedance reach is set to cover the protected line plus

50% of the shortest adjacent line. The reasoning behind the value of 50% is that Zone 2

should cover at lest 20% of the adjacent line, even in the presence of typical additional

infeed at the remote terminal of the protected line. One case of additional infeed at the

remote line terminal occurs when the protected line is paralleled by another line. When a

fault occurs in the adjacent line, approximately equal currents will flow in each of the

parallel lines. The relay on the protected line looking towards the fault will see impedance

which will be the sum of the protected line impedance plus twice the impedance of the

adjacent line to the fault. If the Zone 2 reach is set to cover 50% of the adjacent line

impedance, then in this parallel infeed case, Zone2 will effectively cover 25% of the

adjacent line.

28

In most situations, if the relay reaches at lest 20% into the adjacent line, then faults at the

remote terminal of the protected line will be well within Zone 2 reach and so fast

operation of the Zone 2 comparators will be achieved. This is important if signal aided

tripping schemes are used.

In some situations where the protected line is long and the adjacent line is short, then a

50% reach into the adjacent line will only be a very small overreach of the protected line.

If the protected line is paralleled by another line, then it may be that the zero sequence

mutual coupling between the two lines will be sufficient to prevent the zone 2

comparators from seeing a ground fault at the remote terminal of the line until the remote

circuit breaker trips, preventing ground fault current flowing in the healthy parallel

circuit. In such a case the Zone 2 setting may need to be increased slightly to avoid

sequential or time delayed clearance of the fault at the terminal remote from the fault.

In a parallel line situation, a fault on one line which is cleared sequentially can cause a

fault current reversal in the healthy line. If the Zone 2 settings are greater than 150% of

the protected line impedance and the Permissive Overreach or blocking scheme is being

used, then a fault current reversal in the healthy circuit could cause that circuit to be

incorrectly tripped unless special steps are taken. The Permissive Overreach and Blocking

schemes both have current reversal guards incorporated to prevent such mal-operations.

6.1.4 Choice of Zone 3 Impedance Reach

The Zone 3 forward reach should normally be set to cover the protected line section, plus

the longest adjacent section, plus 25% of a third section, to provide an overall time

delayed back-up protection (able to cover bus faults also at the bus between the two

lines). The reverse Zone 3 offset provides back-up protection for the bus bars behind the

relay and would typically be set to 25% of the Zone 1 setting. The forward Zone 3 reach

should be set to minimum unless the Power Swing Blocking facility (PSB) is also being

used [4].

The choice of zone impedance reach is summarized in a Table below.

29

6.1.5 Choice of Zone 3 Reverse Impedance Reach:

The principle purpose of the zone 3 reverse setting is to provide protection on the busbar

behind the relaying point. The zone 3 reverse reach should normally be set to cover 20% -

25% of the protected line behind the relay.

6.1.6 Choice of Relay Characteristic Angle

Maximum accuracy and sensitivity is obtained by setting the relay angle θPH equal to or to

the nearest setting above the line positive sequence angle ∠Z1, and θN equal to or to the

nearest value above ∠KNZ1 where KN is the neutral compensation factor.

6.1.7 Choice of Resistive Reach of Quadrilateral Characteristic

The resistive reach should be set (if necessary) to cover the desired level of ground fault

resistance, which would comprise arc resistance and tower footing resistance. In addition

to ensure Zone 1 reach accuracy the resistive reach should not be set greater than 15 times

the Zone 1 ground loop reach.

6.1.8 Co-ordination Criteria

Three broad categories for coordination criteria are defined as follows,

Desired design criteria: These are the existing criteria which will result in desired

operation of the relay system.

Minimum Criteria: These are the criteria adopted when the desired criteria can not be

achieved. This is achieved through back-up relay operating time being relaxed i.e. allow

back-up relay not to operate for some low fault currents.

Enhanced criteria: These are the criteria designed to produce optimum results. It might

include consideration of additional fault at mid-line for the purpose of relay coordination.

6.1.9 Time Settings

A fully coordinated result for distance relays should indicate the impedance setting values

for all the three zones in terms of various impedance taps available on the relays and also

the timer setting associated with second and third zone relays. The definite-distance

30

method of time grading are used of the existing network which has the advantage of high

speed fault clearance compared to distance/time method.

In ideal situation Zone time coordination is given below:

Zone 1: TZ1 = Instantaneous.

Zone 2: TZ2 = TZ1 (down) + CB (down) + Z2 (reset) + Margin

(In general, selective time interval is 0.25s – 0.5s)

Zone 3: TZ3 = TZ2 (down) + CB (down) + Z3 (reset) + Margin

(In general, selective time delay is 0.4s – 1s)

Where upper and lower zones overlap e.g. zone 2 up sees beyond zone 1 down, the upper

and lower zone time delays will need to be coordinated e.g. TZ2 (up) to exceed TZ2 (down)

[5].

Zone 3 reverse: The time setting is same as zone 3 time delay.

6.1.10 Zone-2 timer setting (TZ2) and Coordination

The coordination issue here is that, the second zones of all primary/back-up pairs either

never interact or if they do, the time delay of back-up relay exceed that of the primary

relay by a coordination time interval (MCI).

The coordination is completed at the end of the first round of determining timer setting

values if none of the relays have second zone delays greater than minimum coordination

interval defined for distance relays. If any of the relays has an increased second zone time

delay, we compute second time and modify the delays accordingly to achieve system

coordination.

6.1.11 Zone-3 Timer Setting (TZ3) and Coordination

The Zone-3 timers of all back-up pairs should coordinate among themselves.

The zone-3 timer (T-3) is set equal to T-2 plus minimum coordination interval. Each

back-up pair is taken and checked for coordination, if it does not coordinate, then either

31

Zone -3 timer setting is modified or little coordination interval is sacrificed. If still it does

not coordinate, then relay parameters are changed or it is replaced with another one.

6.1.12 Summary of the Philosophy of Three-Stepped Distance Protection

Step Purpose Reach Operating time Remarks First step

Primary protection

80 to 90 % of line section

Instantaneous i.e. no intentional time delay

Avoids loss of selectivity with protection with next zone in case of maximum overreach.

Second

step

Primary

protection of

remaining 20

to 10 % and

back-up

protection of

some portion

of adjacent

line.

100 % of line under

consideration + 50 %

of shortest adjoining

line

Tins + Selective time

interval = T2

* Provides primary

protection to part of line left

out of first step and provides

some back-up protection to

the bus and the next line.

* Shortest adjoining line is

to be considered.

* If the longest adjoining

line is considered, then it

causes loss of selectivity.

Third

step

Back-up

protection

100 % of line under

consideration + 100

% of longest line +

10 to 20% extra.

T2 + Selective time

interval = T3

* Idea to provide full back-

up to the adjoining line,

even in case of maximum

underreach.

* Longest adjoining line has

to be considered. If shortest

adjoining line is considered

then the longer adjoining

line will not get back-up

protection.

6.1.13 Ground Fault Compensation Setting

Ground loop impedance of line ZLE = (1 + KN) ZL1 Eq. 1

Where, KN (residual compensation factor) = L0 L1

L1

Z - Z3Z

= L1 L02Z + Z3

. Eq. 2

Compensation Setting ZN = KN × Zph Eq. 3

Where, Zph is the relay coarse reach.

32

[Also there are some attenuator factors (K factor) in some supplier relay manuals

to set ZN]

With this compensation the relay will measure ZL1 (positive sequence impedance of the

line) irrespective of the number and position of system earthing points.

6.1.14 Choice of Zone Setting for Ground Faults The ground impedance reach is typically set the same as the phase reach unless there is a

grounding transformer on the protected line, significant mutual impedance with a parallel

line, or other special application needs [6].

6.1.15 Mutual Compensation for Parallel Circuit

If the overhead line circuits are supported on the same tower there is mutual inductive

coupling between the two circuits. The positive and negative sequence coupling between

the two feeders are negligible. The zero sequence coupling on the other hand can be

strong and its effect can not be ignored because it will cause a distance relay to

underreach or overreach depending on the zero sequence current flow in the parallel

circuit. . Mutual impedance ZM causes relay to underreach by a factor HO

GO

II

. M

L1 L0

Z2Z + Z

.

Where, IHO is the mutual zero sequence current and IGO is the fault current in the faulted

circuit.

A distance relay can be mutually compensated by measuring the zero sequence current

flowing in the parallel circuit.

Mutual compensation factor KM = 0

1

m

L

ZZ

Eq. 4

6.1.16 Calculations of Minimum Relay Voltage for a Fault at the Zone 1 Reach

Relay voltage for a phase fault

= Impedance to zone 1 reach point×Secondary voltage of VT

Overallsourcetofaultimpedance Eq. 5

Relay voltage for a ground fault

= Ground loop impedance to zone 1 reach point Secondary voltage of VT

Overall source to fault ground loop impedance 1.732

×

× Eq. 6

33

6.1.17 Practical Applications for Phase and Earth Fault Connection

The set of three phase fault measuring elements, energized with phase-phase current from

the delta connected secondary windings of auxiliary C.T’s and with phase voltage,

measure positive-sequence impedance for all phase faults. The set of three earth-fault

measuring elements, energized with phase currents and phase-neutral voltages and with

residual compensation, measure positive-sequence impedance for all earth faults [7].

6.2 Maximum Source Impedance at Madunaghat and Sikalbaha2 (for real case)

1) Maximum source impedance at Madunaghat grid is when 400 MW source at

Madunaghat is switched out, only one 30 MW source at Sikalbaha2 is switched in and

only one of the parallel line between Madunaghat and Sikalbaha is switched in.

Maximum Madunaghat positive sequence impedance = 18.72 ∠81.8 [Ref. Appendix D.2]

2) Maximum source impedance at Sikalbaha2 grid is when both 30 MW sources at

Sikalbaha2 are switched out, 400 MW source at Madunaghat is switched in and only one

of the parallel line between Madunaghat and Sikalbaha is switched in.

Maximum Sikalbaha2 positive sequence impedance = 2.705 + j18.94 [Ref. Appendix

D.2]

34

Chapter 7 DISCUSSION ON PROTECTION AND COORDINATION STUDY

7.1 Introduction The load flow and short circuit study has performed mainly for coordination study of the

existing network, in addition to calculate the present load flow and fault levels. Therefore,

in this project work, the main discussion has done about coordination analysis of distance

relays.

7.2 Discussion on Load flow and Short Circuit Analysis

Load flow and short circuit analysis help to select proper ratings of the equipment and the

protective devices. From the load flow analysis which is shown in appendix (C), the

existing line conductors are sufficient to carry the maximum load current. In case of

Kulshi grid S/S, the capacity of both of the transformers is 41/63 MVA. The transformer

T1 and T2 of this grid are loaded 90 % during the peak load with cooling system (ONAF)

running condition. So, it is not problem for present situation but in the near future the

capacity of this transformer should be upgraded if the growing demand of load is consider

(annually growth 7%). From present load flow study, it can be seen that, the heaviest line

is Kulshi - Madunaghat line where each of the circuits is carrying current 391 Amperes.

Therefore, if any one of the line of Madunaghat-Kulshi feeder trips, healthy circuit will

may overloaded, but in this case partial load can share via Hathazari – Baraulia lines.

During the overload condition the distance relays will not be tripped. During normal load

condition of the network the impedance seen by a distance relay is outside the tripping

zone (Zone 3). It will not be affected for short length of lines i.e. for existing network.

But, on a very long line where the length of the line in miles exceeds the system KV, the

impedance characteristic may have to be made so large as to involve the normal load

point.

35

The existing maximum three phase faults at different locations are nearly same to

calculated fault current. Therefore the ratings of the protective devices and equipment are

sufficient of the network.

When a fault occurs in between of the protected line section, there is a contribution of the

fault current from another Bus Bar or from healthy circuit in case of parallel line which

may trip unaffected breaker. In general, parallel circuits do not affect the operation of

main zones of distance protection, although they may alter considerably the back-up

performance which can be seen in coordination curves.

Since MHO relays inherently a directional and all other E/F relays are used of this

network are directional, they will not see the fault behind of the relays except zone 3

reverse setting of distance relay. But it has to be considered that unaffected relay will

cause tripping during fault current contribution from adjacent feeder. It has found that,

there is no mal-operation of the relays when their feeder contributes the fault current

during the fault on adjacent feeder. The contribution of the fault currents to the affected

feeder are given in Appendix (B).

7.3 Discussion on Coordination Study From the existing zone settings and calculated zone settings of distance relays are shown

in table below, we found that, the impedances setting for zone 1, zone 2, zone 3 and zone

3 (reverse) are nearly same except Hathazari – Baraulia 1 and Hathazari – Baraulia 2

feeders. There are some variations between existing and proposed impedance settings

because in some cases the existing value of relay settings calculated as 85% of the

protected line for zone 1 which is also correct. The relay type, CT and VT ratio are given

in Table 3.5 in chapter 3. The zone 3 (reverse) settings are same as calculated reverse

zone 3 settings. The detail discussion and justification of existing and proposed settings

are given below in feeder basis.

36

7.3.1 Existing Relay Setting Table 7.1 Zone and time setting of the network

Zone Setting Time Step Setting Name of

Grid S/S

Name of

Feeder Zone 1

Imp, O

Secondary

Zone2

Imp, O

Secondary

Zone3

Imp, O

Secondary

Zone3

(Rev)

Imp, O

Secondary

TZ1

In

Second

TZ2

In

Second

TZ3

In

Second

Hathazari – 1 0.3744 0.72 1.1520 0.09 0 0.4 0.8 Madunaghat

End Hathazari – 2 0.3744 0.72 1.1520 0.09 0 0.4 0.8

Zone Setting Time Step Setting Name of

Grid S/S

Name of

Feeder Zone 1

Imp, O

Secondary

Zone2

Imp, O

Secondary

Zone3

Imp, O

Secondary

Zone3

(Rev)

Imp, O

Secondary

TZ1

In

Second

TZ2

In

Second

TZ3

In

Second

Kulshi – 1 0.285 0.5 0.77 0.06 0 0.4 0.8 Kulshi – 2 0.5405 0.98 1.51 0.13 0 0.4 0.8 Sikalbaha2-1 0.341 0.58 0.872 0.08 0 0.4 0.8

Madunaghat End

Sikalbaha 2-2 0.341 0.58 0.872 0.08 0 0.4 0.8 Madunaghat-1 0.2857 0.4762 1.6 0.1 0.6 1.2 Madunaghat-2 0.5405 0.9091 1.6 0.1 0.6 1.2 Baraulia – 1 0.58 0.97 1.5 0.03 0.3 0.6 Baraulia – 2 0.5824 0.9520 1.512 0.14 0 0.4 0.8

Kulshi End

Halishahar 0.6061 1.0526 1.6 0.1 0.6 1.2 Madunaghat-1 1.512 3.08 4.9 0.3850 0 0.4 0.8 Madunaghat-2 1.512 3.08 4.9 0.3850 0 0.4 0.8 Baraulia – 1 1.512 3.08 5.04 0.399 0 0.4 0.8

Hathazari End

Baraulia – 2 1.512 3.08 5.04 0.399 0 0.4 0.8 Kulshi – 1 0.58 0.98 1.6 0.03 0.3 0.6 Kulshi – 2 0.5824 0.9520 1.512 0.14 0 0.4 0.8 Hathazari – 1 0.45 0.76 1.0 0.1 0 0.4 0.8

Baraulia End

Hathazari – 2 0.45 0.76 1.0 0.1 0 0.4 0.8 Kulshi 0.6061 1.0526 1.6 0.1 0.6 1.2 Halishahar

End Sikalbaha2 0.62 1.175 1.8 0.14 0 0.4 0.8 Madunaghat-1 0.34 0.55 0.7 0.08 0 0.4 0.8 Madunaghat-2 0.34 0.55 0.7 0.08 0 0.4 0.8

Sikalbaha2 End

Halishahar 0.6 1.0 1.622 0.15 0 0.4 0.8

Where, TZ1 is the time setting for zone 1, TZ2 is the time setting for zone 2, and TZ3 is the

time setting for zone3.

37

7.3.2 Calculated/Proposed Impedance Value for Zone Setting

Table 7.2 Calculated positive sequence impedance for zone setting

Zone Setting

Name of

Grid S/S

Name of

Feeder

Zone 1

Imp, O

Secondary

Zone2

Imp, O

Secondary

Zone3

Imp, O

Secondary

Zone3 (Rev)

Imp, O

Secondary

Angle

Hathazari – 1 0.374 0.792 1.26 0.09 70

Hathazari – 2 0.374 0.792 1.26 0.09 70

Kulshi – 1 0.27 0.504 0.768 0.06 80

Kulshi – 2 0.53 0.988 1.508 0.13 80

Sikalbaha2-1 0.339 0.576 0.864 0.08 80

Madunaghat

End

Sikalbaha 2-2 0.339 0.576 0.864 0.08 80

Madunaghat-1 0.27 0.456 0.85 76

Madunaghat-2 0.538 0.91 1.69 76

Baraulia – 1 0.547 1.0 1.48 76

Baraulia – 2 0.541 0.988 1.508 0.13 75

Kulshi End

Halishahar 0.57 1.08 1.64 76

Madunaghat-1 1.428 3.08 5.04 0.350 70

Madunaghat-2 1.428 3.08 5.04 0.350 70

Baraulia – 1 1.872 3.6 5.58 0.45 75

Hathazari

End

Baraulia – 2 1.872 3.6 5.58 0.45 75

Kulshi – 1 0.547 1.02 1.58 76

Kulshi – 2 0.541 1.04 1.508 0.13 75

Hathazari – 1 0.499 0.816 1.2 0.12 75

Baraulia

End

Hathazari – 2 0.499 0.816 1.2 0.12 75

Kulshi 0.572 1.052 1.55 76 Halishahar

End Sikalbaha2 0.594 1.176 1.792 0.14 85

Madunaghat-1 0.339 0.544 0.736 0.08 80

Madunaghat-2 0.339 0.544 0.736 0.08 80

Sikalbaha2

End

Halishahar 0.6 1.02 1.62 0.15 85

38

7.3.3 Madunaghat – Hathazari Feeders

The existing zone settings of the relays for both Madunaghat – Hathazari 1 and 2 feeders

are accurate. Although, from the calculated zone settings [Ref. Table 7.2], it is evident

that, the zone 3 setting can be set to reach up to 1.26 ohm to provide complete back-up

protection and cover underreach which may arise due to arc fault resistance or transducers

errors.

Considering the zone and time settings depicted in the coordination curve, Figures 7.1

and 7.2, the discrimination between the zones of back-up protection with relays on

adjacent feeders, Hathazari -Baraulia (1 & 2) are sufficient. There is no possibility of mal-

operation during the fault.

Coordination Curve

-1-0.8-0.6-0.4-0.2

00.20.40.60.8

1

Distance

Tim

e

Madu-Hat 1 Hat-Madu1Hat - Bar 1 Bar - Hat1Madu-Kul 1

Figure 7.1 Coordination curves of Madunaghat to Baraulia and Kulshi section

7.3.4 Madunaghat – Kulshi 1 Feeder

From the calculated zone setting [Ref. Table 7.2], it can be seen that, the existing zone

settings of the relay at Madunaghat end are accurate. It provides back-up protection on

adjacent feeders, Kulshi – Baraulia (1 & 2) and Kulshi - Halishahar without the risk of

mal-discrimination.

In case of Kulshi – Halishahar feeder there is unnecessarily higher time grading at Kulshi

end relay between zone 1, zone 2 and zone 3. The time interval between zone 1, zone 2

and zone 3 may keep lower than existing setting (0.1 s, 0.4 s and 0.8 s for zone1, zone 2

and zone 3 respectively).

39

From the line length of the existing network and coordination curve [Ref. Table 3.2 and

Figure 7.3], it is evident that, Madunaghat – Kulshi and Kulshi – Baraulia feeder length is

12.7 km and 12.9 km respectively and both of this lines are almost equal i.e. adjacent line

is not short. Therefore, according to article 6.1.3, Zone 2 setting may not need to be

increased slightly, to avoid sequential or time delayed clearance of the fault at the

terminal remote from the fault. In this case, Kulshi end relay (Kulshi – Baraulia 1) time

setting can be set as same as Madunaghat end relay (Madunaghat – Kulshi1).

Coordination Curve

-1.2

-0.8

-0.4

0

0.4

0.8

1.2

Distance

Tim

e

Madu-Hat 2 Hat - Bar 2Hat-Madu 2 Bar - Hat 2Madu-Sikal2

Figure 7.2 Coordination curves of Madunaghat to Baraulia

and Madunaghat – Sikalbaha2 section.

7.3.5 Madunaghat – Kulshi 2 Feeder

From the calculated zone setting and coordination curve [Ref. Table 7.2 and Figure 7.4

respectively], it is clear that, the existing zone settings of the relay at Madunaghat end are

accurate. There is proper discrimination between zones of back-up protection on adjacent

feeders. For, Kulshi – Halishahar feeder and Kulshi – Baraulia feeder the relay can be set

as described above [Ref. section 7.3.4, line

7.3.6 Hathazari – Madunaghat Feeders

Since the CT’s and P.T’s ratio are same for both feeders, the zone settings of both relays

are same. From Table 7.1 and 7.2, it is evident that, the zone settings of both feeders are

accurate. But in case of zone 3 setting, it can be extend up to 5.04 ohm to provide full

back-up on adjacent feeders and to cover maximum underreach during the fault.

40

From the coordination curves [Ref. Figures 7.1 and 7.2], the selectivity between zones of

protection with relays on adjacent feeders is sufficient. So, there is no possibility of mal-

operation during the fault on adjacent feeders.

Coordination Curve

-1.5

-1.2

-0.9

-0.6

-0.3

0

0.3

0.6

0.9

1.2

1.5

Distance

Tim

e

Madu-Kul 1 Kul-Bar 1

Kul-Madu1 Bar-Kul 1

Kul - Hal Madu-Hat

Figure 7.3 Coordination curves of Madunaghat –Kulshi -Baraulia

and Kulshi – Halishahar section

Coordination Curve

-1.5-1.2-0.9-0.6-0.3

00.30.60.91.21.5

Distance

Tim

e

Madu-Kul 2 Kul-Bar 2Kul-Madu 2 Bar-Kul 2Kul - Hal Madu-Sikal2

Figure 7.4 Coordination curves of Madunaghat-Sikalbaha, Madunaghat –

Kulshi – Baraulia and Halishahar section

41

7.3.7 Madunaghat – Sikalbaha2 Feeders

Since the CT’s and P.T’s ratio are same for both circuits, the zone settings of both relays

are same. From Table 7.2, it is evident that, the zone settings for both feeders are

accurate.

Considering the time settings depicted in the coordination curves [Ref. Figures 7.5 and

7.6], the selectivity between the zones of back-up protection on adjacent feeder,

Sikalbaha2 - Halishahar is sufficient. There is no possibility of mal-operation during the

fault on Sikalbaha2 – Halishahar line.

Coordination Curve

-1.5

-1.2

-0.9

-0.6

-0.3

0

0.3

0.6

0.9

Distance

Tim

e

Madu-Sikal2-1 Sikal2- HalSikal2 - Madu1 Hal-Sikal2Kul - Hal

Figure 7.5 Coordination curves of Madunaghat-Sikalbaha–Halishahar,

Madunaghat – Kulshi section.

7.3.8 Baraulia - Hathazari Feeders

The zone settings for both feeders (Baraulia – Hathazari 1 & 2) are same due to same

CT’s, P.T’s ratios and distance. From the existing and calculated tables [Ref. Table 7.1

and Table 7.2], it is clear that, the existing zone settings are accurate.

From the coordination curves [Ref. Figures 7.1 and 7.2], the time delay between the zones

of back-up protection with relays on adjacent feeder (Hathazari –Madunaghat) are same.

If the adjoining line is so short, it is better an increase in the time setting of zone 2 on the

longer feeder to discriminate with zone 2 on the shorter feeder to avoid encroaches on the

zone 2 relays on the shorter feeder. Since, the adjoining feeder (Hathazari – Madunaghat)

is not so short, there is no loss of selectivity with zone 2 on the shorter feeder. But for

42

safe side, the operating time of zone 2 and zone 3 settings at Baraulia end relays can be

adjusted with some additional time for selectivity (say, 0.5 s for zone 2 and 0.9 s for zone

3).

Coordination Curve

-1.5-1.2-0.9-0.6-0.3

00.30.60.9

Distance

Tim

e

Madu-Sikal2-2 Sikal2- HalSikal2 - Madu2 Hal-Sikal2Kul - Hal

Figure 7.6 Coordination curves of Madunaghat - Sikalbaha - Halishahar

and Kulshi – Halishahar – Sikalbaha2 section.

7.3.9 Hathazari - Baraulia Feeders

From the existing settings and calculated settings [Ref. Table 7.1 and 7.2], it is clear that,

the zone settings of Hathazari – Baraulia feeder is completely wrong. The line length

between Hathazari and Madunaghat sub-station is 9 km where Hathazari to Baraulia is 12

km. But the data of zone settings provided by PGCB are same for all feeders i.e.

Hathazari – Madunaghat and Hathazari – Baraulia which are not correct (It may be data

error or settings error). From calculated zone settings [Ref. Table 7.2], zone 1, zone 2 and

zone 3 can be set to reach 1.872, 3.6 and 5.58 respectively. Therefore, it is recommended

that, the zone settings impedance of Hathazari – Baraulia feeder i.e. relay reach should be

set as same as proposed zone settings [Ref. Table 7.2].

Considering the time settings depicted in the coordination curves, Figure 7.7, it is clear

that, there is discrimination between zones of back-up protection on adjacent feeder

(Baraulia – Kulshi 1 & 2).

43

7.3.10 Kulshi – Madunaghat 1 Feeder

Considering the time settings [Ref. Figures 7.3 and 7.4], it is evident that, there is

selectivity to provide back-up protection on adjacent feeders. Since, the adjacent feeder

(Madunaghat – Hathazari) line length is short; there is an increase in the time setting of

zone 2 with zone 2 on the shorter feeder to avoid mal-discrimination.

Coordination Curve

-0.9

-0.6

-0.3

0

0.3

0.6

0.9

Distance

Tim

e

Hat - Bar Bar - Kul 1

Bar - Kul 2 Bar - Hat

Kul-Bar 1 Kul-Bar 2

Figure 7.7 Coordination curves of Hathazari - Baraulia - Kulshi section

A C.T. ratio 400/5 is used for this feeder while it is 800/5 for Kulshi – Madunaghat 2

feeder. From the existing data, zone 3 setting of the relay at Kulshi end is 1.6 ohm which

is same as zone 3 setting of Kulshi – Madunaghat 2 feeder. Therefore, the zone 3 existing

setting is not correct for this feeder, since the CT ratios are different (May be it was data

error or setting error as collected from PGCB). Therefore, it is recommended that, the

zone 3 setting can be set to reach 0.85 ohm. Zone1 and zone 2 relay settings are accurate

of this feeder.

7.3.11 Kulshi – Madunaghat 2 Feeder

The existing zone settings of this feeder are accurate. From the coordination curves [Ref.

Figures 7.3 and 7.4], it is evident that, there is discrimination between zones of protection

on adjacent feeders.

44

7.3.12 Halishahar – Sikalbaha2 Feeder Considering the coordination curves [Ref. Figures 7.5 and 7.6], it can be seen that, there

is proper selectivity between zones of back-up protection on adjacent feeders.

From Table 7.2, it can be also seen that, the existing zone settings are properly

maintained. There is no possibility of mal-operation during the fault on Sikalbaha2 –

Hathazari line.

7.3.13 Kulshi – Baraulia 1 Feeder From the coordination curve [Ref. Figure 7.7], the zone 2(up) back-up protection from

Kulshi end of circuit 1 relay has time delay only 0.15 second from zone 1(down) time

setting i.e. with adjacent feeder Baraulia - Hathazari. But for zone 2, the operating time

has to be delayed so as to be selective with zone 1(down) as described in chapter 6.

Therefore, due to loss of selectivity, there is possibility to trip Kulshi circuit 1 end relay

unnecessarily, if any fault occurs on Baraulia to Hathazari line. So, it is recommended

that, the zone 2 time setting at Kulshi end relay set to time delay 0.4 s. The existing zone

settings are accurate.

Coordination Curve

-1.5-1.2-0.9-0.6-0.3

00.30.60.91.21.5

Distance

Tim

e

Kul-Madu Hal - Kul

Kul-Bar 1 Kul-Bar 2

Hal - Kul

Figure 7.8 Coordination curves of Kulshi –Baraulia and Madunaghat,

and Halishahar - Kulshi section.

7.3.14 Kulshi – Baraulia 2 Feeder From the calculated zone setting table and coordination curve [Ref. Table 7.2 and Figure

7.7], it is clear that, there is proper discrimination between zones of back-up protection on

adjacent feeders.

45

7.3.15 Kulshi – Halishahar Feeder

From the calculated zone settings [Ref. Table 7.2], the zone settings of this feeder are

accurate. From the coordination curve [Ref. Figure 7.6], it can be seen that, there is

selectivity between zone 2 of Kulshi end relay and Halishahar end (Halishahar –

Sikalbaha2) relay. But there is unnecessarily, additional time delay for the zone 2 of this

feeder. The time interval of the zone 2 can be set 0.4 s.

7.3.16 Baraulia – Kulshi 1 Feeder

If the relay at Kulshi end does not operate properly during the fault between the

Madunaghat to Kulshi section, the zone 2(up) back-up protection from Halishahar end

will operate properly (Figure 7.8).

From the coordination curve [Ref. Figure 7.3], the zone 2(up) back-up protection from

Baraulia end of circuit 1 relay has time delay only 0.15 second from zone 1(down) time

setting. But for zone 2, the operating time has to be delayed so as to be selective with

zone 1(down) as described in section 6.1.9. Therefore, due to loss of selectivity, there is

possibility to trip Baraulia circuit 1 end breaker unnecessarily, if any fault occurs on

Kulshi to Madunaghat line. So, it is recommended that, the zone 2 time setting of

Baraulia circuit 1 end relay should be set to time delay 0.4s -0.6s. In addition to, there is

overlapping between zone 3 and zone 2 of Kulshi – Madunaghat feeders. Therefore, there

is loss selectivity with zone 2 of Kulshi - Madunaghat lines i.e. any fault occurs within

zone 2 reach of Kulshi – Madunaghat lines thereby it may trip Baraulia end breaker

unnecessarily. There is loss of selectivity with zone 2 of Kulshi – Halishahar feeder

which is depicted in coordination curve [Ref. Figure 7.9]. So, the zone 3 delay time

should be made long enough to be selective with the zone 2 of adjoining line sections. A

0.8s s interval is recommended.

7.3.17 Halishahar – Kulshi Feeder

The existing zone settings are accurate of this feeder. From Coordination curve [Ref.

Figure 7.8], it is evident that, there is discrimination between zones of back-up protection

on adjacent feeders. If the relay at Kulshi end does not operate properly during the fault

46

between the Madunaghat to Kulshi section and Kulshi to Baraulia section, the zone 2(up)

back-up protection from Halishahar end will operate properly (Figure 7.8).

Coordination Curve

-1.5-1.2

-0.9-0.6-0.3

00.30.6

0.91.21.5

Distance

Tim

e

Madu-Kul Kul - Hal

Bar-Kul 1 Sikal2- Hal

Hal - Kul

Figure 7.9 Coordination curves of Madunaghat – Kulshi – Halishahar,

Baraulia – Kulshi 1 and Sikalbaha2 – Halishahar section

7.3.18 Baraulia – Kulshi 2 Feeder

The existing zone settings are accurate of this feeder. From coordination curve [Ref.

Figure 7.4], it is evident that, there is discrimination between zones of back-up protection

on adjacent feeders.

Coordination Curve

0

0.2

0.4

0.6

0.8

1

Distance

Tim

e

Sikal2 - MaduMadu-Hat

Madu-Kul

Figure 7.10 Coordination curves of Sikalbaha2 – Madunaghat – Hathazari and Kulshi

7.3.19 Sikalbaha2 – Halishahar Feeder

47

From calculated zone settings [Ref. Table 7.2], it is evident that, the existing settings are

accurate of this feeder. From Coordination curve [Ref. Figure 7.9], there is selectivity

with zone 2 and zone 3 of adjacent feeder (Halishahar – Kulshi).

Coordination Curve

0

0.2

0.4

0.6

0.8

1

Distance

Tim

e

Bar - Hat Hat - Mad

Kul - Bar

Figure 7.11 Coordination curves of Kulshi – Baraulia – Hathazari – Madunaghat

after time grading

7.3.20 Sikalbaha2 – Madunaghat Feeder

From calculated zone settings [Ref. Table 7.2], it can be seen that, the existing settings

are accurate for both feeders.

Considering time setting depicted in the coordination curve, Figure 7.10, it is evident that,

there is overlapping with zone 3 of Madunaghat – Hathazari feeder. Since, the adjacent

line (Madunaghat – Hathazari) is short, zone 3 delay time should be made long enough to

be selective with the zone 3 of adjoining line section to avoid sequential or time delayed

clearance of the fault at the terminal remote from the fault. Although, it seems there is

discrimination between zones 2 of back-up protection on adjacent feeder, but according to

article 6.1.3, it may need to be increased slightly. A 0.5s interval is recommended for

zone 2 and 1.0s for zone 3.

48

7.3.21 Minimum Relay Voltages for a Fault at the Zone 1 Reach Point

Table7.3 Minimum relay voltage requirements for measurement of faults

Name of Grid

S/S Name of Feeder Minimum relay voltage

for a phase fault, V (Zone 1 reach point)

Minimum relay voltage for a ground fault, V (Zone 1 reach point)

Hathazari – 1 14.38 10.366 Hathazari – 2 14.38 10.366

Kulshi – 1 19.51 13.79 Kulshi – 2 19.27 13.39

Sikalbaha2 – 1 23.51 16.505

Madunaghat

Sikalbaha 2– 2 23.51 16.505 Baraulia – 1 17.07 11.247 Baraulia – 2 16.07 10.97 Halishahar 17.73 11.679

Madunaghat – 1 12.31 8.01

Kulshi

Madunaghat - 2 12.32 8.013 Madunaghat – 1 8.63 5.63 Madunaghat - 2 8.63 5.63

Baraulia – 1 15.85 10.98

Hathazari

Baraulia – 2 15.85 10.98 Kulshi – 1 15.16 9.87 Kulshi – 2 17.36 9.618

Hathazari – 1 12.63 8.436

Baraulia

Hathazari – 2 12.63 8.436 Kulshi 17.18 11.7 Halishahar

Sikalbaha2 14.62 9.13 Madunaghat – 1 23.11 16.28 Madunaghat - 2 23.11 16.28

Sikalbaha2

Halishahar 20.96 10.344

For all distance relays that are used for a network is required minimum relay voltages to

measure phase faults and ground faults. SHPM 101 (GEC, England), REL 316*4 (ABB,

Switzerland) and LZ type distance relays are used of the network that is selected for case

study. For ±5 % reach accuracy with the zone 1 multiplier setting set to unity

QUADRAMHO (SHPM) requires at least 2.05 volts for ground fault measurement or at

least 3.55 volts for phase fault measurement. In case of REL 316*4 the minimum voltage

requires at least 2.8 volts for ground fault measurement and 4 volts for phase fault

measurement. The maximum zone 1 multiplier is 1.122 in case of Madunaghat – Kulshi

circuit 1 for this network. Thus the required voltages for ±5 % reach accuracy are:

1.122 × 2.05 = 2.5 volts for ground faults (for SHPM 101 relay)

49

1.122 × 3.55 = 4.33 volts for phase faults (In case of SHPM 101)

Both voltage requirements are met in this network [Ref. Table 7.3]

7.3.22 Proposed Time Settings

Table7.4 The proposed time settings of distance relays for existing network

Time Setting (TZ) Name of Grid S/S Name of Feeder

TZ1 In

Second

TZ2 In

Second

TZ3 In

Second

Hathazari – 1 0 0.4 0.8

Hathazari – 2 0 0.4 0.8

Kulshi – 1 0 0.4 0.8

Kulshi – 2 0 0.4 0.8

Sikalbaha2-1 0 0.4 0.8

Madunaghat End

Sikalbaha 2-2 0 0.4 0.8

Madunaghat-1 0.1 0.6 1.2

Madunaghat-2 0.1 0.6 1.2

Baraulia – 1 0.03 0.4 0.8

Baraulia – 2 0 0.4 0.8

Kulshi End

Halishahar 0.1 0.4 0.8

Madunaghat-1 0 0.4 0.8

Madunaghat-2 0 0.4 0.8

Baraulia – 1 0 0.4 0.8

Hathazari

End

Baraulia – 2 0 0.4 0.8

Kulshi – 1 0.03 0.4 0.8

Kulshi – 2 0 0.4 0.8

Hathazari – 1 0 0.5 0.9

Baraulia End

Hathazari – 2 0 0.5 0.9

Kulshi 0.1 0.6 1.2 Halishahar End

Sikalbaha2 0 0.4 0.8

Madunaghat-1 0 0.5 1.0

Madunaghat-2 0 0.5 1.0

Sikalbaha2 End

Halishahar 0 0.4 0.8

50

7.4 Auto Recloser and DEF

About 80-85% of faults on overhead transmission lines are transient in nature. These

faults disappear if the line CB’s are tripped momentarily to isolate the line and permits

the arc to extinguish. Therefore, single shot Auto Reclosing are used to increase the

stability and prevents the generators from drifting apart of the network. But if we see the

coordination curves (reach characteristics) at both the ends of the protected line, it can be

easily seen that only 60% of the line gets high speed distance protection (In case of 85 %

of protected line setting, 70 % gets high speed). The remainder 40% - 30 % of the line

length falls in the zone 2 region which is delayed one. If there is a fault on existing

system beyond the zone 1 reach of protected line, the line CB’s at both ends will not be

tripped and reclosed simultaneously. Therefore, there will be an effective reduction in the

dead time which may jeopardize the chances of a successful reclosure. So, a carrier based

distance schemes or a temporary extension of zone 1 can be employed for simultaneous

tripping of CB’s at both ends. Pilot relaying with carrier signal is widely used for the

protection of transmission line. In case of pilot relaying, the carrier transmitter injects the

carrier information into the line at approximately the speed of light.

Apparently, the time settings of DEF (67G) relay of the existing network are correct

which used for relay back up during grounds faults. Although the time setting of E/F relay

is instantaneous but the time interval is made long enough [Ref. Table 3.6], therefore it

will response if the zone 2 of distance relay fails to trip. Due to time constraint, it was not

possible to review of coordination of DEF’s which are used at different locations. It also

needs to review of coordination of O/C relays between 33 KV (downstream) sides and

132 KV (upstream) sides.

51

Chapter 8 CONCLUSION AND RECOMMENDATIONS

The coordination was made for a real 132/33 KV grid transmission network, besides the

load flow and short circuit analysis are both taken into account.

The coordination curves were made for this network from which the loss of selectivity

between adjacent feeders can be observed. Where long feeders are followed by short

feeders, it has taken care to ensure discrimination between the zones of back-up

protection on adjacent feeders. The operating time settings of zone 2 and zone 3 are made

long enough to be selective with zone 2 and zone 3 of adjacent line section and basic

principle are considered to ensure selectivity for proper coordination. The minimum relay

voltage at the zone 1 reach point of this network which is require for proper measurement

of phase and ground faults are measured.

The proposed zone settings and time settings are tabulated in chapter 7 for this network.

The justification of proposed settings for this network are discussed in chapter 7.After

scrutinizing, it is recommended that, existing relay settings should be set according to

proposed settings thereby it would be possible to get optimum protection by using the

existing relay.

In case of REL 316*4 and LZ relays, there are no offset MHO facilities. Therefore some

buses are not getting zone back up protection behind the relaying point and proper power

swing blocking.

This study proposes the proper coordination of relay thereby relay mal-operation will not

be happened during the fault. It will be increased the availability of power in terms of

reliability of the network. Carrier aided pilot relaying schemes are proposed for the

successful reclosing of the network during the transient fault. It will be increased the

power stability and prevent the generators from drifting apart.

52

The reliability analysis of a transmission network and the effect of power swing on relay

performance are further scopes of this study.

After going through the above analysis it is recommended to do the following for existing

network:

1. In case of Madunaghat – Hathazari (1 & 2) feeders, the zone 3 setting can be set to

reach up to 1.26 ohm to provide complete back-up protection on adjacent feeders

and cover underreach which may arise due to arc fault resistance or transducers

errors.

2. In case of zone 3 setting of Hathazari – Madunaghat (1 & 2) feeders, it can be

extending up to 5.04 ohm.

3. The existing zone settings of Hathazari – Baraulia (1 & 2) feeders should be

adjusted in accordance with proposed zone settings.

4. The operating time of zone 2 and zone 3 settings at Baraulia end relays (Baraulia

– Hathazari feeder) can be adjusted with some additional time for selectivity. A

0.5 s for zone 2 and 0.9 s for zone 3 is recommended.

5. The existing zone 3 setting of Kulshi – Madunaghat 1 feeder should be set to

reach 0.85 ohm.

6. The zone 2 time setting at Kulshi end relay of Kulshi – Baraulia 1 circuit should

be set to time delay 0.4 s. A 0.8 s time interval is recommended for zone 3.

7. A 0.5s time interval is recommended for zone 2 and 1.0s for zone 3 settings of

Sikalbaha2 – Madunaghat feeders.

8. The zone 2 and zone 3 time settings of Baraulia circuit 1 end relay of Baraulia –

Kulshi 1 feeder should be set to time delay 0.4s and 0.8 s respectively to avoid

unnecessary tripping when fault occurs on Kulshi- Madunaghat or Kulshi –

Halishahar feeder.

9. There is unnecessarily additional time delay for the zone 2 of Kulshi – Halishahar

feeder. The time interval of the zone 2 and zone 3 can be set 0.4 s and 0.8 s

respectively.

10. Since there is no facility of reverse zone 3 setting in LZ32 and LZ411 type of

distance relays, it should be replaced by modern distance relays to get optimum

protection.

53

11. For perfect auto reclosing of the network, The CB’s of both ends should trip

simultaneously. In this case, carrier aided pilot relaying schemes should be

provided.

12. Since the main aim is to provide optimum protection of the network and thereby

increases the stability and reliability of the system, it is highly recommended to

afford pilot relaying schemes to achieve high speed protection.

13. As far my knowledge, PGCB was not preparing the coordination curves of the

existing network, therefore it is recommended that, the coordination curve should

be prepared from which it would be possible to see whether there is proper

selectivity between zones of protection on adjacent feeder or not.

14. For successful application of protection devices, a standard test sheets should be

prepared for all routine test, a suggested record sheet for routine test of distance

relay is given in appendix (E).

54

BIBLIOGRAPHY

1) William D. Stevenson, Jr., Elements of Power System Analysis, McGraw-Hill

Book Company, Fourth Edition, 1982.

2) G.E. Alexander, J.G. Andrichak, W.Z. Tyska and S.B. Wilkinson, Effects of Load

Flow on Relay Performance, GEC, 39th Annual Texas A&M Relay Conference,

April 14-16, 1986.

3) Herbert A. Fleck and Frank J. Mercede, Using Short-Circuit Currents to perform

a Protective Device Coordination Study, IEEE Industry Application Magazine,

2000.

4) Instruction Manual of QUADRAMHO relay, SHPM 101 types, GEC

Measurements, England.

5) J.B Royle, Analysis and Protection of Power System Course, T & D, Energy

Automation & Information, England.

6) Instruction Manual of REL 316*4, REL 512, ABB Application Note, Switzerland.

7) F E Wellman in collaboration with H.G. Bell and J.W. Hodgkiss, The Protective

Gear Handbook, Sir Isaac Pitman and Sons Ltd, London, 1968.

8) Badri Ram and D N Vishwakarma, Power System Protection and Switchgear,

Tata McGraw-Hill Publishing Company Limited, New Delhi, 1995.

9) B Ravindranath and M Chander, Power System Protection and Switchgear, New

Age International (P) Limited, New Delhi, 2003.

10) Y.G. Paithankar and S.R. Bhide, Fundamentals of Power System Protection,

Prentice-Hall of India Private Limited, New Delhi, 2003.

11) M V Deshpande, Switchgear and Protection, Tata McGraw-Hill Publishing

Company Limited, New Delhi, 1991.

55

12) L.P Singh, Digital Protection, New Age International (P) Limited, New Delhi,

Second Edition, 1997.

13) Arne T Holen, Power System Analysis, Norwegian University of Science and

Technology, Spring 2005.

14) Edward Wilson Kimbark, Power System Stability, Volume II, IEEE Press Power

Systems Engineering Series, John Wiley & Sons Inc., Publication, 2004.

15) Bharat Heavy Electricals Limited, Handbook of Switchgear, Tata McGraw-Hill

Publishing Company Limited, New Delhi, 2005.

16) V.K. Mehta, Principles of Power System, S. Chand & Company, Ltd, New

Delhi,1995

17) Gunter G. Seip, Electrical Installations Handbook, Part 1, Siemens, Germany.

18) G.E Alexander and J.G. Andrichak, Application of Phase and Ground Distance

Relays to Three Terminal Lines, MULTILIN, GE Protection & Control.

19) Demetrios A. Tziouvaras and Daqing Hou, Out-of-Steps Protection Fundamentals

and Advancements, Schweitzer Engineering Laboratories, Inc. USA.

20) http://www.geindustrial.com/multilin/notes/artsci/art14.pdf, Line Protection with

Distance Relays, Chapter 14.

21) http://www.adb.org/AnnualMeeting/2002/Seminars/presentations/iqbal_presentati

on.pdf

22) http://www.bpdb.gov.bd/xmission_line.htm

23) http://www.eng-tips.com/viewthread.cfm?qid=133396&page=1

24) http://www.aeso.ca/files/AIES_Protection_Standard_Revision_0_2004-12-01.pdf

25) www.selinc.com/transpg.htm

26) http://xnet.rrc.mb.ca/janaj/differential_protection.htm

56

APPENDIX A

Single Line Diagram

MADUNAGHAT

KULSHI

HATHAZARI

BARAULIA

SIKALBAHA 2

HALISHAHAR

33 KV BUS

SIKALBAHA 1

Figure A.1 Single line diagram of the existing Network

MADUNAGHAT 132.000 kV 184.146 mvar 1.000 pu

KULSHI 129.842 kV 0.000 mvar 0.984 pu

HATHAZARI 130.560 kV 0.000 mvar 0.989 pu

BARAULIA 129.296 kV 0.000 mvar 0.980 pu

SIKALBAHA 2 131.605 kV 0.000 mvar 0.997 pu

HALISHAHAR 129.453 kV 0.000 mvar 0.981 pu

33 KV BUS 31.553 kV 0.000 mvar 0.956 pu

SIKALBAHA 1 11.264 kV 35.000 mvar 1.024 pu

Figure A.2 Single line diagram with voltage level

57

A.3 Busbar Configuration of Grid S/S

MADUNAGHAT

KULSHI

HATHAZARI

BARAULIA

SIKALBAHA 2

HALISHAHAR

33 KV BUS

SIKALBAHA 1

A.4 Single line diagram with current level of different line sections

362 A

242 A 242 A

391 A 391 A

362 A

382 A

55 A

55 A

110 A 92 A

81%

90%

92 A

58

A.5 Manufacturer and specification of Existing Circuit Breaker

Breaker Specification Name of Grid S/S

Name of Feeder Manufacturer & Type of CB Rated

Voltage, KV

Normal Current,

A

S/C Breaking Current, KA

Hathazari – 1 Siemens, Germany, 3AQ1 EG, (SF6)

145 3150 31.5

Hathazari – 2 Fuji electric, Japan, BAP 514, (SF6)

145 1200 31.5

Kulshi – 1 Siemens, Germany, 3AQ1 EG, (SF6)

145 3150 31.5

Kulshi – 2 Siemens, Germany, 3AQ1 EG, (SF6)

145 3150 31.5

Sikalbaha2 – 1 S & S, Switzerland, HGF 112/1, (SF6)

145 2500 31.5

Madunaghat End

Sikalbaha 2– 2 BBC, Switzerland, ELF SF2-1, (SF6)

145 2000 31.5

Madunaghat – 1 BBC, Switzerland, ELF SF2-1, (SF6)

145 2000 31.5

Madunaghat - 2 S & S, Switzerland, HGF 112/1, (SF6)

145 2500 31.5

Baraulia – 1 Fuji electric, Japan, BAP 514, (SF6)

145 1200 31.5

Baraulia – 2 S & S, Switzerland, HGF 112/1, (SF6)

145 2500 31.5

Kulshi End

Halishahar S & S, Switzerland, HGF 112/1, (SF6)

145 2500 31.5

Madunaghat – 1 BBC, Switzerland, ELF SF2-1, (SF6)

145 2000 31.5

Madunaghat - 2 Siemens, Germany, 3AQ1 EG, (SF6)

145 3150 31.5

Baraulia – 1 Fuji electric, Japan, BAP 514, (SF6)

145 1200 31.5

Hathazari End

Baraulia – 2 Fuji electric, Japan, BAP 514, (SF6)

145 1200 31.5

Kulshi – 1 Siemens, Germany, 3AQ1 EG, (SF6)

145 3150 31.5

Kulshi – 2 S & S, Switzerland, HGF 112/1, (SF6)

145 2500 31.5

Hathazari – 1 S & S, Switzerland, HGF 112/1, (SF6)

145 2500 31.5

Baraulia End

Hathazari – 2 S & S, Switzerland, HGF 112/1, (SF6)

145 2500 31.5

Kulshi Siemens, Germany, 3AQ1 EG, (SF6)

145 3150 31.5 Halishahar End

Sikalbaha2 Siemens, Germany, 3AQ1 EG, (SF6)

145 3150 31.5

Madunaghat – 1 Fuji electric, Japan, BAP 514, (SF6)

145 1200 31.5 Sikalbaha2 End

Madunaghat - 2 Fuji electric, Japan, BAP 514, (SF6)

145 1200 31.5

Halishahar Siemens, Germany, 3AQ1 EG, (SF6)

145 3150 31.5

59

A.6 Some important protection terminology

Discrimination or Selectivity: Discrimination or selectivity is the attribute of protective

gear whereby only the faulty part of the electrical system is disconnected [7].

Sensitivity: Sensitivity is a function of the volt ampere input to protective device to cause

operation, or in other words a measure of the burden of the device at its setting; the lower

the burden the higher is the sensitivity [7].

Stability: Stability is the attribute of a protective device whereby it remains passive under

all conditions, whether of fault or otherwise, except those that specially call for its

operation [7].

Setting: The value of the actuating quantity (current, voltage, power, etc.) at which the

relay set to operate.

Operating time: It is the time which elapses from the instant at which the actuating

quantity exceeds the relays pick-up value to the instant at which the relay closes its

contacts [8].

Reset time: It is the time which elapses from the moment the actuating quantity falls

below its reset value to the instant when the relay comes back to its normal position.

Overshot time: The time during which stored operating energy is dissipated after the

characteristic quantity has been suddenly restored from a specified value to the value

which it had at the initial position of the relay [9].

Reach: This term is mostly used in connection with distance relays. The reach of a relay

is the maximum distance a fault can be from the relay to cause operation [7]. In other

words it is the maximum length of the line up to which the relay can protect.

Overreach: Sometimes a relay may operate even when a fault point is beyond its present

reach (i.e. protected length). This phenomenon is called overreach.

Underreach: Sometimes a relay may fail to operate even when the fault point is within

its reach, but it is at the far end of the protected line. This phenomenon is called

underreach.

60

APPENDIX B

Short Circuit Analysis Results

B.1 Summary of fault current level:

Data set: MADUNAGHAT. Year of calculation 2005.

---------------------------------------------------------------

Largest short-circuit current.

Node Voltage 3-phase 2-phase Capacity Cosphi

Un(kV) Ieff(kA) Ieff(kA) Sk(MVA)

----------------------------------------------------------------------------------------------------------

33 KV BUS 33.000 24.521 21.236 1401.562 0.130

BARAULIA 132.000 11.542 9.995 2638.758 0.077

HALISHAHAR 132.000 9.747 8.441 2228.447 0.088

HATHAZARI 132.000 12.859 11.137 2940.040 0.057

KULSHI 132.000 12.594 10.907 2879.397 0.059

MADUNAGHAT 132.000 16.301 14.117 3726.816 0.004

SIKALBAHA 1 11.000 75.571 65.447 1439.826 0.102

SIKALBAHA 2 132.000 11.815 10.232 2701.311 0.069

--------------------------------------------------------------------------------------------------------- Max 75.571* 65.447 3726.816

Min 9.747 8.441* 1401.562

B.2 Contribution of fault current during fault at Kulshi Grid: Data set: MADUNAGHAT. Year of calculation 2005.

-------------------------------------------------------------

Largest short-circuit current.

Short-circuit in : KULSHI

Voltage prior to fault: 129.820 kV

Power to Short-circuit

Node Voltage (kV) fault location capacity

Node name Pre Fault Fault kA MVA

---------------------------------------------------------------------------------------------------

Fault location: 129.820 0.000 12.594 2879.40

MADUNAGHAT 132.000 31.360 3.586

MADUNAGHAT 132.000 31.360 3.586

BARAULIA 129.282 11.934 1.344

61

BARAULIA 129.282 11.934 1.344 HALISHAHAR 129.438 13.146 1.591 ---------------------------------------------------------------------------------------------------- Sum 11.451 B.3 Contribution of fault current during fault at Madunaghat Grid:

Data set: MADUNAGHAT. Year of calculation 2005.

---------------------------------------------------------------

Largest short-circuit current.

Short-circuit in : MADUNAGHAT

Voltage prior to fault : 132.000 kV

Power to Short-circuit

Node Voltage (kV) fault location capacity

Node name Pre Fault Fault kA MVA

--------------------------------------------------------------------------------------

Fault location: 132.000 0.000 16.301 3726.82

Generator: 132.000 132.000 14.871

KULSHI 129.820 0.862 0.099

KULSHI 129.820 0.862 0.099

HATHAZARI 130.554 0.229 0.037

HATHAZARI 130.554 0.229 0.037

SIKALBAHA 2 131.600 5.710 0.515

SIKALBAHA 2 131.600 5.710 0.515

----------------------------------------------------------------------------------------

B.4 Contribution of fault current during fault at Sikalbaha2 Grid:

Data set: MADUNAGHAT. Year of calculation 2005.

----------------------------------------------------------------

Largest short-circuit current.

Short-circuit in : SIKALBAHA 2

Voltage prior to fault : 131.600 kV

Power to Short-circuit

Node Voltage (kV) fault location capacity

Node name Pre Fault Fault kA MVA

---------------------------------------------------------------------------------------------

Fault location: 131.600 0.000 11.815 2701.31

MADUNAGHAT 132.000 41.193 3.716

62

HALISHAHAR 129.438 18.917 1.954

MADUNAGHAT 132.000 41.193 3.716

SIKALBAHA 1 11.264 2.089 0.679

SIKALBAHA 1 11.264 2.089 0.679

------------------------------------------------------------------------------------------------- Sum 10.745

B.5 Contribution of fault current during fault at Hathazari Grid:

Data set: MADUNAGHAT. Year of calculation 2005.

-----------------------------------------------------------------

Largest short-circuit current.

Short-circuit in : HATHAZARI

Voltage prior to fault : 130.554 kV

Power to Short-circuit

Node Voltage (kV) fault location capacity

Node name Pre Fault Fault kA MVA

-------------------------------------------------------------------------------------------------

Fault location: 130.554 0.000 12.859 2940.04

MADUNAGHAT 132.000 28.729 4.636

BARAULIA 129.282 9.989 1.209

BARAULIA 129.282 9.989 1.209

MADUNAGHAT 132.000 28.729 4.636

--------------------------------------------------------------------------------------------------- Sum 11.690

B.6 Contribution of fault current during fault at Baraulia Grid:

Data set: MADUNAGHAT. Year of calculation 2005.

-------------------------------------------------------------

Largest short-circuit current.

Short-circuit in : BARAULIA

Voltage prior to fault : 129.282 kV

Power to Short-circuit

Node Voltage (kV) fault location capacity

Node name Pre Fault Fault kA MVA

-----------------------------------------------------------------------------------------

Fault location: 129.282 0.000 11.542 2638.76

HATHAZARI 130.554 22.714 2.749

KULSHI 129.820 22.179 2.497

63

KULSHI 129.820 22.179 2.497

HATHAZARI 130.554 22.714 2.749

----------------------------------------------------------------------------------------------- Sum 10.492 B.7 Contribution of fault current during fault at Halishahar Grid:

Data set: MADUNAGHAT. Year of calculation 2005.

-------------------------------------------------------------

Largest short-circuit current.

Short-circuit in : HALISHAHAR

Voltage prior to fault: 129.438 kV

Power to Short-circuit

Node Voltage (kV) fault location capacity

Node name Pre Fault Fault kA MVA

-----------------------------------------------------------------------------------------------

Fault location: 129.438 0.000 9.747 2228.45

SIKALBAHA 2 131.600 38.816 4.010

KULSHI 129.820 40.150 4.859

------------------------------------------------------------------------------------------------ Sum 8.869

B.8 Contribution of fault current during fault at 33 KV Bas :

Data set: MADUNAGHAT. Year of calculation 2005.

----------------------------------------------------------------

Largest short-circuit current.

Short-circuit in : 33 KV BUS

Voltage prior to fault : 27.236 kV

Power to Short-circuit

Node Voltage (kV) fault location capacity

Node name Pre Fault Fault kA MVA

----------------------------------------------------------------------------------------

Fault location: 27.236 0.000 24.521 1401.56

KULSHI 129.820 68.063 11.146

KULSHI 129.820 68.063 11.146

---------------------------------------------------------------------------------------- Sum 22.292

64

B.9 FAULT LEVEL OF DIFFERENT GRID SUBSTATIONS

Name of Grid

S/S

Pre Fault

Voltage, KV

Existing

Three Phase

Current, KA

Calculated

Three Phase

Current, KA

Existing Earth

Current, KA

MADUNAGHAT 132 13.6 16.30 12.2

HATHAZARI 132 15.3 12.86 15

SIKALBAHA 2 132 10.6 11.815 9.4

KULSHI 132 13 12.59 10.2

BARAULIA 132 13.5 11.54 11

HALISHAHAR 132 9.9 9.747 6.7

65

APPENDIX C

Power Flow Analysis Results

C.1 Power flow in line sections

Node Node Loadflow Power loss Curr. Load

From To MW MVAr kW kVAr A (%)

--------------------------------------------------------------------------------------------------------

MADUNAGHAT - KULSHI 80.653 37.823 574.86 1431.29 389 50

MADUNAGHAT - KULSHI 80.653 37.823 574.86 1431.29 389 50

MADUNAGHAT - HATHAZARI 74.573 35.829 351.08 792.25 361 46

MADUNAGHAT - HATHAZARI 74.573 35.829 351.08 792.25 361 46

MADUNAGHAT - SIKALBAHA 2 10.905 5.103 13.77 -979.76 52 7

MADUNAGHAT - SIKALBAHA 2 10.905 5.103 13.77 -979.76 52 7

SIKALBAHA 2 - HALISHAHAR 76.232 41.985 300.67 1445.03 381 49

HATHAZARI - BARAULIA 49.222 22.928 206.71 55.44 240 31

HATHAZARI - BARAULIA 49.222 22.928 206.71 55.44 240 31

KULSHI - BARAULIA 18.518 9.147 32.88 -672.24 91 12

KULSHI - BARAULIA 18.518 9.147 32.88 -672.24 91 12

KULSHI - HALISHAHAR 24.112 4.442 42.60 -579.52 109 14

---------------------------------------------------------------------------------------------------------

C.2 Power flow in two-winding transformers

Node Node Loadflow Power loss No-ld.l TD. Load

From Til MW MVAr kW kVAr kW (%) (%)

----------------------------------------------------------------------------------------------------------------

SIKALBAHA 1 - SIKALBAHA 2 30.000 17.500 275.85 1379.23 0 0.0 81

SIKALBAHA 1 - SIKALBAHA 2 30.000 17.500 275.85 1379.23 0 0.0 81

KULSHI - 33 KV BUS 49.505 25.024 504.77 2523.84 0 0.0 90

KULSHI - 33 KV BUS 49.505 25.024 504.77 2523.84 0 0.0 90

----------------------------------------------------------------------------------------------------------------

66

Summary 8 node : MW Mvar

--------------------------------------------------------------

Total generation : 447.263 219.146

Total voltage ind. load : 443.000 209.220

Total voltage dep. load : 0.000 0.000

-------------------------------------------------------------

Total transmission losses: 4.263 9.926

Losses in percent of load: 0.962

----------------------------------------------------------------------------------------

Total loss in 16 sect. : 4.263 9.926 0.000 (No-load losses)

Total loss in 12 LK : 2.702 2.119

Total loss in 4 T2 : 1.561 7.806 0.000

----------------------------------------------------------------------------------------

Data set : MADUNAGHAT. Year of calculation 2005.

-------------------------------------------------------------

C.3 Summary :

MW Mvar

Generation MADUNAGHAT : 387.883 187.229

Total generation : 447.263 219.146

Total voltage ind. load : 443.000 209.220

Total voltage dep. load : 0.000 0.000

Total losses in line sections : 2.702 2.119

Total losses in T2 : 1.561 7.806 0.000

Total electrical losses : 4.263 9.926 0.000 (No-load losses)

Max. voltage drop : 33 KV BUS : 4.39 %

Heaviest loaded line : KULSHI - MADUNAGHAT : 49.51 %

Heaviest loaded T2 : KULSHI - 33 KV BUS : 89.51 %

67

APPENDIX D

D.1 Zone Setting Results

Madunaghat - Sikalbaha2, Circuit 1

For phase to Phase Faults Selecting Zone 1 Setting Ohms Angle0 1 Required zone 1 reach: Secondary 0.341 76.1 2 The relay coarse reach: Zph 0.32 80 3 required Zone 1 multiplier setting: 1.067 4 Actual Zone 1

Setting 0.339 80

Selecting Zone 2 Setting 1 Required zone 2 reach : Secondary 0.598 2 required Zone 2 multiplier setting: 1.867 3 Actual zone 2

setting: 0.576 80

Selecting Zone 3 Setting 1 Required zone 3 reach: Secondary 0.854 (forward) 2 required Zone 3 multiplier setting: 2.669 3 Actual zone 3

forward setting: 0.864 80

4 Required zone 3 reach: Secondary 0.085 (reverse) 5 required Zone 3 multiplier setting: 0.265 6 Actual zone 3

reverse setting: 0.08 80

68

Madunaghat - Sikalbaha2, Circuit 2

For phase to Phase Faults

Selecting Zone 1 Setting Ohms Angle0 1 Required zone 1 reach: Secondary 0.341 76.1 2 The relay coarse reach: Zph 0.32 80 3 required Zone 1 multiplier setting: 1.067 4 Actual Zone 1

Setting 0.339 80

Selecting Zone 2 Setting 1 Required zone 2 reach: Secondary 0.598 2 required Zone 2 multiplier setting: 1.867 3 Actual zone 2

setting: 0.576 80

Selecting Zone 3 Setting 1 Required zone 3 reach: Secondary 0.854 (forward) 2 required Zone 3 multiplier setting: 2.669 3 Actual zone 3

forward se tting: 0.864 80

4 Required zone 3 reach: Secondary 0.085 (reverse) 5 required Zone 3 multiplier setting: 0.265 6 Actual zone 3

reverse setting: 0.08 80

69

Madunaghat – Hathazari, Circuit 1

For phase to Phase Faults Selecting Zone 1 Setting Ohms Angle0 1 Required zone 1 reach: 0.382 69.5 2 The relay coarse reach: Zph 0.36 70 3 required Zone 1 multiplier setting: 1.060 4 Actual Zone 1

Setting 0.374 70

Selecting Zone 2 Setting 1 Required zone 2 reach: Secondary 0.795 2 required Zone 2 multiplier setting: 2.208 3 Actual zone 2

setting: 0.792 70

Selecting Zone 3 Setting 1 Required zone 3 reach: Secondary 1.272 (forward) 2 required Zone 3 multiplier setting: 3.533 3 Actual zone 3

forward setting: 1.260 70

4 Required zone 3 reach: Secondary 0.094 (reverse) 5 required Zone 3 multiplier setting: 0.260

6 Actual zone 3

reverse setting: 0.09 70

70

Madunaghat – Hathazari, Circuit 2

For phase to Phase Faults Selecting Zone 1 Setting Ohms Angle0 1 Required zone 1 reach: 0.382 69.5 2 The relay coarse reach: Zph 0.36 70 3 required Zone 1 multiplier setting: 1.060 4 Actual Zone 1

Setting 0.374 70

Selecting Zone 2 Setting 1 Required zone 2 reach: Secondary 0.795 2 required Zone 2 multiplier setting: 2.208 3 Actual zone 2

setting: 0.792 70

Selecting Zone 3 Setting 1 Required zone 3 reach: Secondary 1.272 (forward) 2 required Zone 3 multiplier setting: 3.533 3 Actual zone 3

forward setting: 1.260 70

4 Required zone 3 reach: Secondary 0.094 (reverse) 5 required Zone 3 multiplier setting: 0.260

6 Actual zone 3

reverse setting: 0.09 70

71

Madunaghat – Kulshi, Circuit 1

For phase to Phase Faults Selecting Zone 1 Setting Ohms Angle0 1 Required zone 1 reach: Secondary 0.269 76.1 2 The relay coarse reach: Zph 0.24 80 3 required Zone 1 multiplier setting: 1.122 4 Actual Zone 1

Setting 0.269 80

Selecting Zone 2 Setting 1 Required zone 2 reach: Secondary 0.507 2 required Zone 2 multiplier setting: 2.114 3 Actual zone 2

setting: 0.504 80

Selecting Zone 3 Setting 1 Required zone 3 reach:Secondary 0.764 (forward) 2 required Zone 3 multiplier setting: 3.183 3 Actual zone 3

forward setting: 0.768 80

4 Required zone 3 reach:Secondary 0.067 (reverse) 5 required Zone 3 multiplier setting: 0.280 6 Actual zone 3

reverse setting: 0.06 80

72

Madunaghat – Kulshi, Circuit 2

For phase to Phase Faults Selecting Zone 1 Setting Ohms Angle0 1 Required zone 1 reach: 0.538 76.1 2 The relay coarse reach: Zph 0.52 80 3 required Zone 1 multiplier setting: 1.036 4 Actual Zone 1

Setting 0.530 80

Selecting Zone 2 Setting 1 Required zone 2 reach: Secondary 1.015 2 required Zone 2 multiplier setting: 1.952 3 Actual zone 2

setting: 0.988 80

Selecting Zone 3 Setting 1 Required zone 3 reach: Secondary 1.528 (forward) 2 required Zone 3 multiplier setting: 2.938 3 Actual zone 3

forward setting: 1.508 80

4 Required zone 3 reach: Secondary 0.133 (reverse) 5 required Zone 3 multiplier setting: 0.255 6 Actual zone 3

reverse setting: 0.13 80

73

Hathazari - Baraulia, Circuit 1

For phase to Phase Faults Selecting Zone 1 Setting Ohms Angle0 1 Required zone 1 reach: Secondary 1.908 75.2 2 The relay coarse reach: Zph 1.8 75 3 required Zone 1 multiplier setting: 1.060 4 Actual Zone 1

Setting 1.872 75

Selecting Zone 2 Setting 1 Required zone 2 reach: Secondary 3.667 2 required Zone 2 multiplier setting: 2.037 3 Actual zone 2

setting: 3.600 75

Selecting Zone 3 Setting 1 Required zone 3 reach: Secondary 5.590 (forward) 2 required Zone 3 multiplier setting: 3.105 3 Actual zone 3

forward setting: 5.580 75

4 Required zone 3 reach: Secondary 0.468 (reverse) 5 required Zone 3 multiplier setting: 0.260 6 Actual zone 3

reverse setting: 0.45 75

74

Hathazari - Baraulia, Circuit 2

For phase to Phase Faults Selecting Zone 1 Setting Ohms Angle0 1 Required zone 1 reach: Secondary 1.908 75.2 2 The relay coarse reach: Zph 1.8 75 3 required Zone 1 multiplier setting: 1.060 4 Actual Zone 1

Setting 1.872 75

Selecting Zone 2 Setting 1 Required zone 2 reach: Secondary 3.667 2 required Zone 2 multiplier setting: 2.037 3 Actual zone 2

setting: 3.600 75

Selecting Zone 3 Setting 1 Required zone 3 reach: Secondary 5.590 (forward) 2 required Zone 3 multiplier setting: 3.105 3 Actual zone 3

forward setting: 5.580 75

4 Required zone 3 reach: Secondary 0.468 (reverse) 5 required Zone 3 multiplier setting: 0.260 6 Actual zone 3

reverse setting: 0.45 75

75

Hathazari - Madunaghat, Circuit 1

For phase to Phase Faults Selecting Zone 1 Setting Ohms Angle0 1 Required zone 1 reach: Secondary 1.431 69.5 2 The relay coarse reach: Zph 1.4 70 3 required Zone 1 multiplier setting: 1.022 4 Actual Zone 1

Setting 1.428 70

Selecting Zone 2 Setting 1 Required zone 2 reach: Secondary 3.051 2 required Zone 2 multiplier setting: 2.179 3 Actual zone 2

setting: 3.080 70

Selecting Zone 3 Setting 1 Required zone 3 reach: Secondary 4.944 (forward) 2 required Zone 3 multiplier setting: 3.531 3 Actual zone 3

forward setting: 5.040 70

4 Required zone 3 reach: Secondary 0.357 (reverse) 5 required Zone 3 multiplier setting: 0.255 6 Actual zone 3

reverse setting: 0.35 70

76

Hathazari - Madunaghat, Circuit 2

For phase to Phase Faults Selecting Zone 1 Setting Ohms Angle0 1 Required zone 1 reach: Secondary 1.431 69.5 2 The relay coarse reach: Zph 1.4 70 3 required Zone 1 multiplier setting: 1.022 4 Actual Zone 1

Setting 1.428 70

Selecting Zone 2 Setting 1 Required zone 2 reach: Secondary 3.051 2 required Zone 2 multiplier setting: 2.179 3 Actual zone 2

setting: 3.080 70

Selecting Zone 3 Setting 1 Required zone 3 reach: Secondary 4.944 (forward) 2 required Zone 3 multiplier setting: 3.531 3 Actual zone 3

forward setting: 5.040 70

4 Required zone 3 reach: Secondary 0.357 (reverse) 5 required Zone 3 multiplier setting: 0.255 6 Actual zone 3

reverse setting: 0.35 70

77

Baraulia - Hathazari, Circuit 1

For phase to Phase Faults Selecting Zone 1 Setting Ohms Angle0 1 Required zone 1 reach: Secondary 0.509 75.2 2 The relay coarse reach: Zph 0.48 75 3 required Zone 1 multiplier setting: 1.060 4 Actual Zone 1

Setting 0.499 75

Selecting Zone 2 Setting 1 Required zone 2 reach: Secondary 0.875 2 required Zone 2 multiplier setting: 1.822 3 Actual zone 2

setting: 0.816 75

Selecting Zone 3 Setting 1 Required zone 3 reach: Secondary 1.232 (forward) 2 required Zone 3 multiplier setting: 2.567 3 Actual zone 3

forward setting: 1.200 75

4 Required zone 3 reach: Secondary 0.125 (reverse) 5 required Zone 3 multiplier setting: 0.260 6 Actual zone 3

reverse setting: 0.12 75

78

Baraulia - Hathazari, Circuit 2

For phase to Phase Faults Selecting Zone 1 Setting Ohms Angle0 1 Required zone 1 reach: Secondary 0.509 75.2 2 The relay coarse reach: Zph 0.48 75 3 required Zone 1 multiplier setting: 1.060 4 Actual Zone 1

Setting 0.499 75

Selecting Zone 2 Setting 1 Required zone 2 reach: Secondary 0.875 2 required Zone 2 multiplier setting: 1.822 3 Actual zone 2

setting: 0.816 75

Selecting Zone 3 Setting 1 Required zone 3 reach: Secondary 1.232 (forward) 2 required Zone 3 multiplier setting: 2.567 3 Actual zone 3

forward setting: 1.200 75

4 Required zone 3 reach: Secondary 0.125 (reverse) 5 required Zone 3 multiplier setting: 0.260 6 Actual zone 3

reverse setting: 0.12 75

79

Baraulia - Kulshi, Circuit 2

For phase to Phase Faults Selecting Zone 1 Setting Ohms Angle0 1 Required zone 1 reach: Secondary 0.547 75.3 2 The relay coarse reach: Zph 0.52 75 3 required Zone 1 multiplier setting: 1.052 4 Actual Zone 1

Setting 0.541 75

Selecting Zone 2 Setting 1 Required zone 2 reach: Secondary 1.020 2 required Zone 2 multiplier setting: 1.962 3 Actual zone 2

setting: 1.040 75

Selecting Zone 3 Setting 1 Required zone 3 reach: Secondary 1.525 (forward) 2 required Zone 3 multiplier setting: 2.933 3 Actual zone 3

forward setting: 1.508 75

4 Required zone 3 reach: Secondary 0.135 (reverse) 5 required Zone 3 multiplier setting: 0.260 6 Actual zone 3

reverse setting: 0.13 75

80

Kulshi - Baraulia, Circuit 2

For phase to Phase Faults Selecting Zone 1 Setting Ohms Angle0 1 Required zone 1 reach: Secondary 0.547 75.3 2 The relay coarse reach: Zph 0.52 75 3 required Zone 1 multiplier setting: 1.052 4 Actual Zone 1

Setting 0.541 75

Selecting Zone 2 Setting 1 Required zone 2 reach: Secondary 1.002 2 required Zone 2 multiplier setting: 1.926 3 Actual zone 2

setting: 0.988 75

Selecting Zone 3 Setting 1 Required zone 3 reach: Secondary 1.479 (forward) 2 required Zone 3 multiplier setting: 2.844 3 Actual zone 3

forward setting: 1.508 75

4 Required zone 3 reach: Secondary 0.135 (reverse) 5 required Zone 3 multiplier setting: 0.260 6 Actual zone 3

reverse setting: 0.13 75

81

Sikalbaha2 - Halishahar, Circuit

For phase to Phase Faults Selecting Zone 1 Setting Ohms Angle0 1 Required zone 1 reach: Secondary 0.596 82.4 2 The relay coarse reach: Zph 0.6 85 3 required Zone 1 multiplier setting: 0.993 4 Actual Zone 1

Setting 0.600 85

Selecting Zone 2 Setting 1 Required zone 2 reach: Secondary 1.041 2 required Zone 2 multiplier setting: 1.736 3 Actual zone 2

setting: 1.020 85

Selecting Zone 3 Setting 1 Required zone 3 reach: Secondary 1.578 (forward) 2 required Zone 3 multiplier setting: 2.630 3 Actual zone 3

forward setting: 1.620 85

4 Required zone 3 reach: Secondary 0.150 (reverse) 5 required Zone 3 multiplier setting: 0.250 6 Actual zone 3

reverse setting: 0.15 85

82

Halishahar - Sikalbaha2

For phase to Phase Faults Selecting Zone 1 Setting Ohms Angle0 1 Required zone 1 reach: Secondary 0.596 82.9 2 The relay coarse reach: Zph 0.56 85 3 required Zone 1 multiplier setting: 1.064 4 Actual Zone 1

Setting 0.594 85

Selecting Zone 2 Setting 1 Required zone 2 reach: Secondary 1.110 2 required Zone 2 multiplier setting: 1.983 3 Actual zone 2

setting: 1.176 85

Selecting Zone 3 Setting 1 Required zone 3 reach: Secondary 1.750 (forward) 2 required Zone 3 multiplier setting: 3.126 3 Actual zone 3

forward setting: 1.792 85

4 Required zone 3 reach: Secondary 0.148 (reverse) 5 required Zone 3 multiplier setting: 0.265 6 Actual zone 3

reverse setting: 0.14 85

83

Kulshi - Madunaghat, Circuit 1

For phase to Phase Faults Selecting Zone 1 Setting Ohms Angle0 1 Required zone 1 reach: Secondary 0.27 76.1 2 Actual Zone 1

Setting: Z1PH 0.27 76 Selecting Zone 2 Setting

1 Required zone 2 reach: Secondary 0.456 3 Actual zone 2

setting: Z2PH 0.456 76 Selecting Zone 3 Setting

1 Required zone 3 reach: Secondary 0.85 (forward)

3 Actual zone 3

forward setting: 0.85 76

Kulshi - Madunaghat, Circuit 2

For phase to Phase Faults Selecting Zone 1 Setting Ohms Angle0 1 Required zone 1 reach: Secondary 0.538 76.1 2 Actual Zone 1

Setting: Z1PH 0.538 76 Selecting Zone 2 Setting

1 Required zone 2 reach: Secondary 0.91 3 Actual zone 2

setting: Z2PH 0.91 76 Selecting Zone 3 Setting

1 Required zone 3 reach: Secondary 1.69 (forward) 3 Actual zone 3

forward setting: 1.69 76

84

Kulshi – Halishahar

For phase to Phase Faults Selecting Zone 1 Setting Ohms Angle0 1 Required zone 1 reach: Secondary 0.608 76.3 2 Actual Zone 1

Setting: Z1PH 0.57 76 Selecting Zone 2 Setting

1 Required zone 2 reach: Secondary 1.037 3 Actual zone 2

setting: Z2PH 1.08 76 Selecting Zone 3 Setting

1 Required zone 3 reach: Secondary 1.679 (forward) 3 Actual zone 3

forward setting: 1.64 76

Halishahar – Kulshi

For phase to Phase Faults Selecting Zone 1 Setting Ohms Angle0 1 Required zone 1 reach: Secondary 0.608 76.3 2 Actual Zone 1

Setting: Z1PH 0.572 76 Selecting Zone 2 Setting

1 Required zone 2 reach: Secondary 1.03 3 Actual zone 2

setting: Z2PH 1.052 76 Selecting Zone 3 Setting

1 Required zone 3 reach: Secondary 1.67 (forward) 3 Actual zone 3

forward setting: 1.55 76

85

Kulshi - Baraulia, Circuit 1

For phase to Phase Faults Selecting Zone 1 Setting Ohms Angle0 1 Required zone 1 reach: Secondary 0.547 75.3 2 Actual Zone 1

Setting: Z1PH 0.547 75 Selecting Zone 2 Setting

1 Required zone 2 reach: Secondary 1.0 3 Actual zone 2

setting: Z2PH 1.0 75 Selecting Zone 3 Setting

1 Required zone 3 reach: Secondary 1.48 (forward) 3 Actual zone 3

forward setting: 1.48 75

Baraulia - Kulshi, Circuit 1

For phase to Phase Faults Selecting Zone 1 Setting Ohms Angle0 1 Required zone 1 reach: Secondary 0.547 75.3 2 Actual Zone 1

Setting: Z1PH 0.547 75 Selecting Zone 2 Setting

1 Required zone 2 reach: Secondary 1.02 3 Actual zone 2

setting: Z2PH 1.02 75 Selecting Zone 3 Setting

1 Required zone 3 reach: Secondary 1.58 (forward) 3 Actual zone 3

forward setting: 1.58 75

86

Sikalbaha2 - Madunaghat, Circuit1

For phase to Phase Faults Selecting Zone 1 Setting Ohms Angle0 1 Required zone 1 reach: Secondary 0.341 75.5 2 The relay coarse reach: Zph 0.32 80 3 required Zone 1 multiplier setting: 1.067 4 Actual Zone 1

Setting 0.339 80

Selecting Zone 2 Setting 1 Required zone 2 reach: Secondary 0.546 2 required Zone 2 multiplier setting: 1.706 3 Actual zone 2

setting: 0.544 80

Selecting Zone 3 Setting 1 Required zone 3 reach: Secondary 0.725 (forward) 2 required Zone 3 multiplier setting: 2.265 3 Actual zone 3

forward setting: 0.736 80

4 Required zone 3 reach: Secondary 0.085 (reverse) 5 required Zone 3 multiplier setting: 0.265 6 Actual zone 3

reverse setting: 0.08 80

87

Sikalbaha2 - Madunaghat, Circuit2

For phase to Phase Faults Selecting Zone 1 Setting Ohms Angle0 1 Required zone 1 reach: Secondary 0.341 75.5 2 The relay coarse reach: Zph 0.32 80 3 required Zone 1 multiplier setting: 1.067 4 Actual Zone 1

Setting 0.339 80

Selecting Zone 2 Setting 1 Required zone 2 reach: Secondary 0.546 2 required Zone 2 multiplier setting: 1.706 3 Actual zone 2

setting: 0.544 80

Selecting Zone 3 Setting 1 Required zone 3 reach: Secondary 0.725 (forward) 2 required Zone 3 multiplier setting: 2.265 3 Actual zone 3

forward setting: 0.736 80

4 Required zone 3 reach: Secondary 0.085 (reverse) 5 required Zone 3 multiplier setting: 0.265 6 Actual zone 3

reverse setting: 0.08 80

88

Ground Fault Compensation Setting:

Magnitude Angle

Kn = 0.517 1.3

(51%

compensation) 1 Madunaghat - Hathazari 1

Ground loop impedance: 0.603 75.98 Actual Compensation setting Zn 0.2 75 Coarse Ground loop setting: 0.572 71.7

2 Madunaghat - Hathazari 2 Ground loop impedance: 0.603 75.98 Actual Compensation setting Zn 0.2 75 Coarse Ground loop setting: 0.572 71.7

3 Madunaghat – Sikalbaha2 - 1 Ground loop impedance: 0.603 75.98 Actual Compensation setting Zn 0.116 85 Coarse Ground loop setting: 0.454 81.26

4 Madunaghat - Sikalbaha2 - 2 Ground loop impedance: 0.603 75.98 Actual Compensation setting Zn 0.116 85 Coarse Ground loop setting: 0.454 81.26

5 Madunaghat – Kulshi 1 Ground loop impedance: 0.603 75.98 Actual Compensation setting Zn 0.108 85 Coarse Ground loop setting: 0.376 81.4

6 Madunaghat - Kulshi 2 Ground loop impedance: 0.603 75.98 Actual Compensation setting Zn 0.216 85 Coarse Ground loop setting: 0.744 81.4

89

Ground Fault Compensation Setting: Magnitude Angle Kn = 0.517 1.3

(51%

compensation) 1 Hathazari – Baraulia 1

Ground loop impedance: 0.603 75.98 Actual Compensation setting Zn 0.912 80 Coarse Ground loop setting: 2.77 76.6

2 Hathazari – Baraulia 2 Ground loop impedance: 0.603 75.98 Actual Compensation setting Zn 0.912 80 Coarse Ground loop setting: 2.77 76.6

3 Hathazari - Madunaghat 1 Ground loop impedance: 0.603 75.98 Actual Compensation setting Zn 0.708 75 Coarse Ground loop setting: 2.13 71.65

4 Hathazari - Madunaghat 2 Ground loop impedance: 0.603 75.92 Actual Compensation setting Zn 0.708 75 Coarse Ground loop setting: 2.13 71.65

5 Kulshi – Madunaghat 1 Ground loop impedance: 0.603 75.98 Actual Compensation setting Zn 0.108 85 Coarse Ground loop setting: 0.376 81.4

6 Kulshi - Madunaghat 2 Ground loop impedance: 0.603 75.98 Actual Compensation setting Zn 0.216 85 Coarse Ground loop setting: 0.744 81.4

90

Ground Fault Compensation Setting: Magnitude Angle Kn = 0.517 1.3

(51%

compensation) 1 Baraulia - Hathazari 1

Ground loop impedance: 0.603 75.98 Actual Compensation setting Zn 0.212 80 Coarse Ground loop setting: 0.709 76.48

2 Baraulia - Hathazari 2 Ground loop impedance: 0.603 75.98 Actual Compensation setting Zn 0.212 80 Coarse Ground loop setting: 0.709 76.48

3 Baraulia - Kulshi1 Ground loop impedance: 0.603 75.98 Actual Compensation setting Zn 0.3 80 Coarse Ground loop setting: 0.88 76.72

4 Baraulia – Kulshi 2 Ground loop impedance: 0.603 75.98 Actual Compensation setting Zn 0.216 80 Coarse Ground loop setting: 0.755 76.4

5 Kulshi – Baraulia 1 Ground loop impedance: 0.603 75.98 Actual Compensation setting Zn 0.3 80 Coarse Ground loop setting: 0.88 76.72

6 Kulshi - Baraulia 2 Ground loop impedance: 0.603 75.98 Actual Compensation setting Zn 0.216 80 Coarse Ground loop setting: 0.755 76.4

91

Ground Fault Compensation Setting: Magnitude Angle Kn = 0.517 1.3

(51%

compensation) 1 Sikalbaha2 – Madunaghat 1

Ground loop impedance: 0.603 75.98 Actual Compensation setting Zn 0.116 85 Coarse Ground loop setting: 0.454 81.27

2 Sikalbaha2 - Madunaghat 2 Ground loop impedance: 0.603 75.98 Actual Compensation setting Zn 0.116 85 Coarse Ground loop setting: 0.454 81.27

3 Kulshi – Halishahar Ground loop impedance: 0.603 75.98 Actual Compensation setting Zn 0.304 80 Coarse Ground loop setting: 0.912 77.35

4 Halishahar – Kulshi Ground loop impedance: 0.603 75.98 Actual Compensation setting Zn 0.304 80 Coarse Ground loop setting: 0.912 77.35

5 Sikalbaha2 – Halishahar Ground loop impedance: 0.603 75.98 Actual Compensation setting Zn 0.3 90 Coarse Ground loop setting: 0.9 86.68

6 Halishahar - Sikalbaha2 Ground loop impedance: 0.603 75.98 Actual Compensation setting Zn 0.3 90 Coarse Ground loop setting: 0.892 86.6

92

D.2 Calculation of Maximum Source Impedance at Madunaghat and Sikalbaha2 (for real case)

1) Maximum source impedance at Madunaghat grid is when 400 MW source at

Madunaghat is switched out, only one 30 MW source at Sikalbaha2 is switched in and

only one of the parallel line between Madunaghat and Sikalbaha is switched in.

Maximum Madunaghat positive sequence impedance

= 2 × (0.54 + j6.17) + 16.1 ×(0. 0992 + j0.385)

= 1.08 + j12.34 + 1.59 + j6.198

= 2.67 + j 18.53 = 18.72 ∠81.8

2) Maximum source impedance at Sikalbaha2 grid is when both 30 MW sources at

Sikalbaha2 are switched out, 400 MW source at Madunaghat is switched in and only one

of the parallel line between Madunaghat and Sikalbaha is switched in.

Maximum Sikalbaha2 positive sequence impedance;

= 1.115 + j12.75 + 1.59 + j6.198

= 2.705 + j18.94

3) Maximum Madunaghat zero sequence impedance;

= 1.08 + j12.34 + 16.1× (0.24 + j0.985)

= 4.94 + j28.19

4) Maximum Sikalbaha2 zero sequence impedance;

= 1.115 + j12.75 + 16.1× (0.24 + j0.985)

= 4.97 + j28.6

93

APPENDIX E

E.1ROUTINE TEST RECORD

DISTANCE RELAYS

RELAY PATTERN………………. SERIAL NO……………… MAKER………………... INSTALLED ON…………………….. CIRCUIT AT………………….. SUBSTATION SETTINGS:

Secondary Impedance Rheostats Date Zone 1 Zone 2 Zone 3

Curve No.

Terminal Nos. A B C

Set by

RESULTS OF TESTS:

Zone 1 Zone 2 Zone 3 Date Test Engineer Volts Amp. Volts Amp. Volts Amp.

Notes

Notes:

Suggested record sheet for routine tests [4].