overcurrent protection coordination case study: …...ahmed hatim abdelbari elniema ahmed omer...

OVERCURRENT PROTECTION COORDINATION

CASE STUDY: BALEELA OIL-FIELD NETWORK

By

AHMED HATIM ABDELBARI ELNIEMA

AHMED OMER MOHAMED BABIKER

MOHAMED ALI MOHAMED IBRAHIM

Supervisor

Dr. Kamal Ramadan

A REPORT SUBMITTED TO

University Of Khartoum

In partial fulfillment for the degree of

B.Sc. (HONS) Electrical and Electronics Engineering

(POWER ENGINEERING)

Faculty of Engineering

Department of Electrical and Electronics Engineering

October 2017

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DECLARATION OF ORGINALITY

I declare this report entitled “OVERCURRENT PROTECTION COORDINATION

CASE STUDY: BALEELA OIL-FIELD NETWORK” is my own work except as cited in

references. The report has been not accepted for any degree and it is not being submitted

currently in candidature for any degree or other reward.

Signature: ____________________

Name: _______________________

Date: ________________________

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Acknowledgement

All the thanks, praises and glorifying is due to Almighty ALLAH.

To my mother and father, who grew me up, fed me and guided me through life.

I owe my deepest gratitude to my advisor Dr.Kamal Ramadan. First for accepting me as a

student, then for the support and help he has given me throughout the project.

Special thanks to my project partners for their hard work, support and cooperation. Besides, I

also want to thank Eng Abdallah Abdelmonem, and Eng Babikir Elnouman for their

significant assistance and help.

Many thanks to my colleagues and all the staff at the Department of Electrical and

Electronics Engineering for the pleasant working atmosphere and your friendship.

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Abstract

Continuous and reliable power supply is the main goal and target for power system networks.

In this regard, many methods have been developed to enhance the performance of power

supply systems.

The present research is initiated to investigate Baleela power network, because this network

is faced by blackouts several times per year during last couple of years, this led to severe lack

of production during blackout times beside the maintenance and operation cost impact.

Using ETAP software as analysis tool, the network was drawn. The data for each component

in the network was collected from a site visit to Baleela. After running the simulator,

different fault scenarios were created to examine the existing protection system schemes and

different miss-operations results were obtained as a response of protection system to the

abnormal conditions. After studying this network, it is noticed that one of the main reasons

for blackouts is the relay setting miss-coordination caused by the use of only (DMT)

characteristics.

An optimum characteristic (IDMT) for the relays was chosen, and a completely new

coordination scheme is designed which starts first by coordinating the phase over-current

elements, for different paths from furthest downstream up to the generators. Next the earth

fault relays are coordinated for the same paths and finally the instantaneous element as a

backup protection was applied successfully.

The new relay setting coordination has been applied to all relays in the five main substations

as a result from this study. The sequence of operation is well improved and as a result the

total blackouts frequency is significantly decreased. Valuable recommendations were

suggested.

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المستخلص

لذلن تم إبتكار أنظمة وطرق , يعتبر إمداد الطالة بشكل مستمر وموثوق أحد أهم أهداف شبكات إمداد الطاله الكهربائية

. من أجل تحسن أداء هذه الشبكات ألمداد الطالة بالصورة المطلوبة

تم إختيار هذه الشبكة بالتحديد نسبة لتكرر اإلنمطاع التام للتيار , تم عمل هذا البحث لدراسة الشبكة الكهربائية لحمل بليلة

وذلن لألعوام المليلة الماضية مما أثر سلبا على اإلنتاج في الحمول بجانب تأثير التكاليف , الكهربائي خالل العام الواحد

. الحالية للصيانة وإعادة التشغيل

تم رسم وتمثيل شبكة بليلــــة ثم جمع البيانات الخاصة لجميع , كأداة للدراسة والتحليل(ETAP) بزَبيــج بإستخدام

(. ETAP)ثم تم إدخال هذه البيانات في برنامج المحاكاة , عناصر الشبكة عن طريك زيـــارة المولع

تى إختببر أَظًة انحًبية انحبنية انخبصة بشبكة بهـــــيهة ػٍ طزيق ػًم سيُبريىهبت ألػطبل كهزببئية فتى انحصىل ػهى

بؼذ دراسة وتحهيم انشبكة نىحظ أٌ أحذ أسببة إَقطبع إيذاد , بؼض اإلستجبببت انخبطئة يٍ َظبو انحًبية نهذِ األػطبل

(. DMT)انكهزببء هى فقذاٌ تُسيق وضبط يزحالت انحًبية َتيجة إلستخذاو طزيقة

هذا النظام , ثم ُصمم نظام تنسيك جديد للمرحالت, المناسبة لمرحالت الحماية (IDMT)كبذيم نهطزيقة انسببقة تى إختيبر

يبدأ بتنسيك عناصر مرالبة التيار في الطور الواحد وذلن لعدة مسارات في الشبكة إبتداًء من أبعد نمطة في الشبكة وصوالً

. إلى المولدت وذلن كمرحلة أولى

وأخيراً تم , في المرحلة الثانية تم تنسيك مرحالت حمياة األعطال للخطأ األرضي وذلن لنفس المسارات السابمة للشبكة

. تنسيك العناصر اللحظية كعناصر إحتياطية للحماية

. انسببق نجًيغ يزحالت انحًبية في انخًس يحطبت في انشبكة كُتيجة نهذراسة انسببقة (IDMT)تم تطبيك نظام

كنتيجة لذالن إنخفضت مرات إنمطاع اإلمداد الكهربائي , عمل المرحالت لد تحسن بصورة كبيرةنىحظ أٌ تسهسم

. بصورة ملحوظة

.تم إلتراح توصيات مهمة في آخر البحث

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Table of Contents

DECLARATION OF ORGINALITY ................................................................................ ii

Acknowledgement ............................................................................................................. iii

Abstract .............................................................................................................................. iv

v.................................................................................................................................المستخلص

Table of Contents ............................................................................................................... vi

List of Figures .................................................................................................................... xi

List of Tables ................................................................................................................... xiii

CHAPTER ONE ................................................................................................................. 1

Introduction ................................................................................................................. 1

1.1 Overview .................................................................................................................... 1

1.2 Problem Statement ..................................................................................................... 1

1.3 Project background ..................................................................................................... 1

1.4 Objectives ................................................................................................................... 2

1.5 Thesis outline ............................................................................................................. 2

CHAPTER TWO ................................................................................................................ 3

2 Literature Review........................................................................................................ 3

2.1 Introduction ................................................................................................................ 3

2.2 Overview of electrical faults .................................................................................... 4

2.3 Protection Definitions ................................................................................................ 6

2.3.1 Protection System ............................................................................................... 6

2.3.2 Protection Equipment.......................................................................................... 6

2.3.3 Protection Scheme .......................................................................................... 6

2.4 Protection quality ....................................................................................................... 7

2.4.1 Overview ............................................................................................................. 7

2.5 Basic requirements of protection................................................................................ 8

2.5.1 Unit Protection (selectivity) ................................................................................ 8

2.5.2 Stability ............................................................................................................. 11

2.5.3 Reliability .......................................................................................................... 11

2.5.4 Speed of operation ............................................................................................ 11

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2.5.5 Sensitivity ......................................................................................................... 11

2.6 Protection components ............................................................................................. 11

2.6.1 Voltage transformers ......................................................................................... 11

2.6.2 Current transformers ......................................................................................... 12

2.6.3 Fuses ................................................................................................................. 12

2.6.4 Relays ................................................................................................................ 13

2.6.4.1 Electromechanical Relays .......................................................................... 13

2.6.4.2 Static Relays .............................................................................................. 14

2.6.4.3 Digital Relays ........................................................................................... 14

2.6.4.4 Numerical Relays ...................................................................................... 14

2.6.5 Circuit breakers ................................................................................................. 15

2.6.5.1 Purpose of circuit breakers ........................................................................ 15

2.6.5.2 Types of Circuit Breakers .......................................................................... 16

2.7 Over-current Protection ............................................................................................ 19

2.7.1 Co-ordination Procedure ................................................................................... 19

2.7.2 Principles of Time/Current Grading ................................................................. 19

2.7.2.1 Discrimination by Time ............................................................................. 20

2.7.2.2 Discrimination by Current ......................................................................... 20

2.7.2.3 Discrimination by both Time and Current ................................................. 20

2.7.3 Standard I.D.M.T. Overcurrent Relays ............................................................. 21

2.7.4 Combined IDMT and High Instantaneous Over-current Relays ................... 21

2.8 Generator protection ................................................................................................. 21

2.9 Feeder protection ...................................................................................................... 22

2.10 Transformer protection ............................................................................................. 22

2.11 Bus-bar protection .................................................................................................... 22

2.12 Primary and Back-up Protection .............................................................................. 23

2.13 Trip Circuit Supervision ........................................................................................... 24

CHAPTER THREE .......................................................................................................... 25

Case Study: Baleela Oil-Field Network ................................................ ............ 25

3.1 Introduction ................................................................................................................. 25

3.2 Overview .................................................................................................................. 25

3.3 Baleela oil-field network description ....................................................................... 26

3.3.1 CPF station ........................................................................................................ 26

3.3.2 KEYI Substation ............................................................................................... 27

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3.3.3 FNE Substation ................................................................................................. 27

3.3.4 Moga Substation ............................................................................................... 28

3.3.5 JAKE Substation ............................................................................................... 28

3.4 Network Implementation and Simulation ................................................................ 29

3.5 Simulation Scenarios (Old settings) ......................................................................... 30

3.5.1 Overview ........................................................................................................... 30

3.5.2 Three-Phase Fault Scenarios (phase) ................................................................ 30

3.5.2.1 A three phase fault on JAKE 11kV feeder ................................................ 30

3.5.2.2 A three phase fault at the transmission line ............................................... 32

3.5.2.3 A three phase fault at CPF 33kV bus-bar .................................................. 33

3.5.3 Line-To-Ground Fault Scenarios (earth fault) .................................................. 35

3.5.3.1 Line -To-Ground fault on KEYI 11kV feeder (feeder TR-6802) .............. 35

3.5.3.2 Line -To-Ground fault at transmission line between CPF and KEYI ....... 36

3.6 Concept of DMT and I.D.M.T ................................................................................. 37

3.6.1 Definite Time Relay .......................................................................................... 37

3.6.2 Inverse Time Relays ......................................................................................... 38

CHAPTER FOUR ............................................................................................................. 40

Implementation and Results ...................................................................................... 40

4.1 Introduction .............................................................................................................. 40

4.2 Analysis Conditions ................................................................................................. 40

4.3 Protection Settings Coordination Results ................................................................. 40

4.4 New Relay Settings Coordination ............................................................................ 41

4.4.1 Over-current Settings ........................................................................................ 41

4.4.1.1 JAKE –MOGA .......................................................................................... 41

4.4.1.2 MOGA – CPF ............................................................................................ 42

4.4.1.3 FNE - CPF ................................................................................................ 43

4.4.1.4 KEYI - CPF ............................................................................................... 44

4.4.2 Earth Fault Settings ........................................................................................... 45

4.4.2.1 Settings for JAKE up to the secondary of its transformer ......................... 45

4.4.2.2 Settings from JAKE primary of the transformer up to CPF ...................... 46

4.4.2.3 Settings for MOGA up to the secondary of its transformer ..................... 47

4.4.2.4 Settings from MOGA primary of the transformer up to CPF .................... 48

4.4.2.5 Settings for FNE up to Secondary of its transformer ................................ 49

4.4.2.6 Settings from FNE primary of the transformer up to CPF ........................ 50

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4.4.2.7 Settings for KEYI up to secondary of its transformer ............................... 51

4.4.2.8 Settings from KEYI primary of the transformer up to CPF ...................... 52

4.4.2.9 Settings from CPF primary of its transformer up to 11kV bus section ... 53

4.5 Simulation Scenarios (new settings) ........................................................................ 54

4.5.1 Overview ........................................................................................................... 54

4.5.2 Three-Phase Fault Scenarios ............................................................................. 54

4.5.2.1 A three phase fault on JAKE 11kV feeder ................................................ 54

4.5.2.2 A three phase fault at the transmission line ............................................... 55

4.5.2.3 A three phase fault at CPF 33kV bus-bar .................................................. 57

4.5.3 Line-To-Ground Fault Scenarios (earth fault) .................................................. 58

4.5.3.1 Line -To-Ground fault on KEYI 11kV feeder (feeder TR-6802) .............. 58

4.5.3.2 Line -To-Ground fault at transmission line between CPF and KEYI ....... 61

4.6 Summery .................................................................................................................. 63

CHAPTER FIVE .............................................................................................................. 65

Conclusion ................................................................................................................ 65

5.1 Protection Settings Coordination ............................................................................. 65

5.2 Objectives Achieved ................................................................................................ 65

5.3 Recommendations .................................................................................................... 66

References ......................................................................................................................... 67

Appendix A ....................................................................................................................... 68

A.1 Transformer Data ........................................................................................................ 68

A.2 X/R Ratio for each transformer ................................................................................... 69

A.3 Transmission Lines Data .............................................................................................. 69

A.4 The generators dynamic data ....................................................................................... 70

Appendix B ....................................................................................................................... 71

OLD SETTINGS ...................................................................................................... 71

B.1 OLD SETTINGS – FNE SUBSTATION .................................................................... 71

B.2 OLD SETTINGS – MOGASUBSTATION ................................................................. 75

B.3 OLD SETTINGS – JAKE SUBSTATION ................................................................ 80

B.4 OLD SETTINGS – KEYI SUBSTATION .................................................................. 85

B.5 OLD SETTINGS – CPF SUBSTATION .................................................................... 90

Appendix C ....................................................................................................................... 97

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NEW SETTING ........................................................................................................ 97

C.1 NEW RELAY COORDINATION SETTINGS – FNE SUBSTATION ...................... 97

C.2 NEW RELAY COORDINATION SETTINGS – JAKE SUBSTATION.................. 101

C.3 NEW SETTINGS – KEYI SUBSTATION ................................................................ 105

C.4 NEW RELAY COORDINATION SETTINGS – MOGA SUBSTATION ............... 109

C.5 NEW RELAY COORDINATION SETTINGS – CPF STATION ............................ 113

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List of Figures

Figure ‎2.1 Types of faults on a three-phase system: (A) Phase-to-earth fault; (B) Phase-to-

phase fault; (C) Phase-to phase- to-earth fault; (D) Three-phase fault; (E) Three-phase-to-

earth fault .............................................................................................................................5 Figure ‎2.2 Zones of protection............................................................................................ 7 Figure ‎2.3 Overlapping of zones ........................................................................................ 8

Figure ‎2.4 Application of principle of grading.................................................................. 10 Figure ‎2.5 Over current time grading ................................................................................ 10 Figure ‎2.6 Arc control circuit-breaker ............................................................................... 16

Figure ‎2.7 Oil circuit-breaker ............................................................................................ 17 Figure ‎2.8 Air break switchgear ......................................................................................... 18 Figure ‎3.1 Geographic description of BALEELA network ............................................... 26 Figure ‎3.2 Baleela Oil-Field Network Single Line Diagram ............................................ 29

Figure ‎3.3 Three phase fault on JAKE (CH05 TR7802A) feeder ..................................... 30 Figure ‎3.4 sequence of operation for JAKE 11kV feeder ................................................. 31

Figure ‎3.5 Three phase fault at MOGA-JAKE transmission line ..................................... 32 Figure ‎3.6 sequence of operation for fault at MOGA-JAKE transmission line ................ 32

Figure ‎3.7 Three phase fault at CPF 33kV bus-bar (B) ..................................................... 33 Figure ‎3.8 sequence of operation for a fault on CPF 33kV bus-bar (B) ........................... 34 Figure ‎3.9 Line-to-Ground fault on KEYI 11kV feeder ................................................... 35

Figure ‎3.10 The sequence of operation for Line-to-Ground fault on KEYI 11kV feeder .. 35

Figure ‎3.11 Line -To-Ground fault at transmission line between CPF and KEYI ............ 36 Figure ‎3.12 Sequence of operation for Line-to-Ground fault at CPF-KEYI transmission

line .......................................................................................................................36

Figure ‎3.13 Definite time relay curve ................................................................................ 38 Figure ‎3.14 Inverse time relay curve ................................................................................. 38 Figure ‎4.1 The new phase [O/C] settings for JAKE-MOGA path relays ......................... 41

Figure ‎4.2 The new phase [O/C] settings for MOGA-CPF path relays ........................... 42 Figure ‎4.3 The new phase [O/C] settings for FNE-CPF path relays ............................... 43

Figure ‎4.4 The new phase [O/C] settings for KEYI-CPF path relays .............................. 44

Figure ‎4.5 New earth fault settings for JAKE up to the secondary of its transformer .... 45

Figure ‎4.6 New earth fault settings from JAKE primary of the transformer up to CPF . 46

Figure ‎4.7 New earth fault settings For MOGA up to secondary of its transformer ...... 47 Figure ‎4.8 New earth fault settings from MOGA primary of the transformer up to CPF

...........................................................................................................................48 Figure ‎4.9 New earth fault settings for FNE up to secondary of its transformer ........... 49 Figure ‎4.10 New earth fault settings from FNE primary of the transformer up to CPF ... 50

Figure ‎4.11 New earth fault settings from KEYI up to secondary of its transformer ...... 51 Figure ‎4.12 New earth fault settings from KEYI primary of the transformer up to CPF . 52 Figure ‎4.13 New earth fault settings for CPF primary of its transformer up to 11kV bus

section .......................................................................................................................53 Figure ‎4.14 Three phase fault on JAKE 11kV (CH05 TR7802A) feeder ........................ 54

Figure ‎4.15 sequence of operation for a three phase fault on JAKE 11kV feeder ........... 55 Figure ‎4.16 Three phase fault at MOGA-JAKE transmission line ................................... 56

Figure ‎4.17 sequence of operation for a three phase fault at MOGA-JAKE line ............ 56

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Figure ‎4.18 Three phase fault at CPF 33kV bus-bar (B) .................................................. 57 Figure ‎4.19 sequence of operation for three phase fault at CPF 33kV bus-bar (B) ......... 58 Figure ‎4.20 Line-to-Ground fault on KEYI 11kV feeder ................................................. 59 Figure ‎4.21 The sequence of operation for Line-to-Ground fault on KEYI 11kV feeder 60

Figure ‎4.22 Line -To-Ground fault at transmission line between CPF and KEYI ........... 61 Figure ‎4.23 sequence of operation for Line-to-Ground fault on CPF- KEYI transmission

line .......................................................................................................................62

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List of Tables Table ‎2.1 Fault Statistics With Reference to Type of Fault ..................................................... 5 Table ‎2.2 Fault Statistics With Reference to Power System Elements .................................... 6 Table ‎3.1: Real and reactive power for CPF loads at busbar A ............................................. 27 Table ‎3.2: Real and reactive power for CPF loads at busbar (B) ........................................... 27 Table ‎3.3: Real and reactive power for KEIY loads at busbar (A & B) ................................ 27

Table ‎3.4: Real and reactive power for FNE loads at busbar A & B ..................................... 28 Table ‎3.5: Real and reactive power for MOGA loads at busbar (A & B) ............................. 28 Table ‎3.6: real and reactive power for JAKE loads at busbar (A & B) ................................. 28 Table ‎3.7: Parameters for different types of inverse characteristic ........................................ 39

Table ‎4.1 Coordination status for each scenario .................................................................... 64 Table A.1 Power Transformers Technical Data ..................................................................... 68 Table A. 2 X/R ratio for each transformer using the transformer rated MVA and copper

losses ....................................................................................................................................... 69 Table A. 3 Transmission Lines Data ...................................................................................... 70 Table A. 4 The generators dynamic data ................................................................................ 70 Table B. 1 11kV Feeders on 1

stBusbar ................................................................................... 71

Table B. 2 11kV Feeders on 2nd

Busbar .................................................................................. 72 Table B. 3 11kV Incomers ..................................................................................................... 72

Table B.4 33kV Transformer Feeders .................................................................................... 73 Table B. 5 33kV Bus coupler ................................................................................................. 73

Table B. 6 33kV Incomers ..................................................................................................... 74 Table B. 7 11kV Bus-section & 11kV two Incomers Directional Protection ........................ 74 Table B. 8 11 kV Feeders on 1

st Busbar ................................................................................. 75

Table B. 9 11kV Feeders on 2nd Busbar ............................................................................... 75 Table B. 10 11kv Incomers .................................................................................................... 76

Table B. 11 11kV Bus-section & 11kV two incomers Directional Protection [the directional

Element is disabled = non-directional] ................................................................................... 77 Table B.‎712 33 kV Transformer Feeders ............................................................................... 77

Table B.13 33kV Bus coupler ................................................................................................ 78 Table B. 14 33kV incomers.................................................................................................... 79

Table B.15 33 kV Outgoings (to Jake Substation) ................................................................. 79

Table B. 16 11kV Feeders on 1st

Busbar ................................................................................ 80

Table B.17 11kV Feeders on 2nd

Busbar ................................................................................ 81 Table B. 18 11kV Incomers ................................................................................................... 82 Table B. 19 33kV Transformer Feeders ................................................................................. 82 Table B. 20 33kV Bus coupler ............................................................................................... 83 Table B. 21 33kV Incomers ................................................................................................... 83

Table B. 22 11 kV Bus-section & 11kV Two Incomers Directional Protection [the

directional Element is disabled = non-directional] ................................................................. 84 Table B. 23 11kV Feeders on 1

st Busbar ................................................................................ 85


Busbar ............................................................................... 86

Table B. 25 11kV Incomers ................................................................................................... 87

Table B. 26 33kV Transformer Feeders ................................................................................. 87 Table B. 27 33kV Bus coupler ............................................................................................... 88 Table B. 28 33kV Incomers ................................................................................................... 88

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Table B. 29 11kV Bus-section & 11kV Two Incomers Directional Protection [the directional

Element is disabled = non-directional] ................................................................................... 89 Table B. 30 11kV Substation Feeders ................................................................................... 90 Table B. 31 11Kv Substation New Added Feeders ............................................................... 92

Table B. 32 11 kV Bus-section & 11 kV Transformer feeders .............................................. 94 Table B. 33 33 kV Transformer Feeders ................................................................................ 94 Table B. 34 11 kV Bus-section & 11 kV Transformer feeders .............................................. 95 Table B. 35 33 kV Transformer Feeders ................................................................................ 95 Table B. 36 33kVBustie ......................................................................................................... 96

Table B. 37 33 kV outgoings ................................................................................................. 96 Table C.1 11kV FEEDERS on 1

st Busbar.............................................................................. 97

Table C.2 11kV FEEDERS on 2nd

Busbar ............................................................................. 98 Table C.3 11kV incomers ...................................................................................................... 98 Table C.4 33kV Transformer Feeders.................................................................................... 99 Table C.5 33kV Bus coupler .................................................................................................. 99

Table C.6 33kV incomers ...................................................................................................... 99 Table C.7 11kV Bus-section & 11kV two incomers Directional Protection ....................... 100

Table C. 8 11kV FEEDERS on 1st Busbar .......................................................................... 101 Table C. 9 11kV FEEDERS on 2nd Busbar ........................................................................ 102 Table C.10 11kV incomers .................................................................................................. 103

Table C.11 33kV Transformer Feeders................................................................................ 103

Table C. 12 33kV Bus coupler ............................................................................................. 104 Table C. 13 33kV Incomers ................................................................................................. 104 Table C.14 11kV Bus-section & 11kV two incomers Directional Protection ..................... 104

Table C. 15 11kV FEEDERS on 1st Busbar ........................................................................ 105 Table C.16 11kV FEEDERS on 2nd Busbar ....................................................................... 106

Table C.17 11kV Incomers .................................................................................................. 106 table C. 18 33kV Transformer Feeders ................................................................................ 107 Table C. 19 33kV Bus coupler ............................................................................................. 107

Table C.20 33kV Incomers .................................................................................................. 107 Table C.21 11kV Bus-section & 11 kV two incomers Directional Protection .................... 108

Table C.22 11kV FEEDERS on 1st Busbar ........................................................................ 109

Table C.23 11kV FEEDERS on 2nd Busbar ....................................................................... 110 Table C. 24 11kV Incomers ................................................................................................. 110 Table C. 25 33kV Transformer Feeders............................................................................... 111

Table C.26 33kV Bus coupler .............................................................................................. 111 Table C. 27 11kV Bus-section & 11kV two incomers Directional Protection [the directional

Element is disabled = non-directional] ................................................................................. 112 Table C.28 NEW 11KV SUBSTATION FEEDERS .......................................................... 114 Table C.29 11kV Bus-section & 11kV Transformer feeders ............................................... 116

Table C.30 33kV Transformer Feeders................................................................................ 116 Table C.31 33kV outgoings ................................................................................................. 117

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List of ABBREVIATIONS

IEEE Institute of Electrical and Electronic Engineering

SLD Single Line Diagram

KVA Kilo Volt Ampere

KW Kilo Watt

KV Kilo Volt

DMT Definite Minimum Time

IDMT Inverse Definite Minimum Time

OC Over Current

CT Current Transformer

VT Voltage Transformer

CB Circuit Breaker

IEC International Electro-technical Commission

SI Standard Inverse

VI Very Inverse

ETAP Electrical Transient Analysis Program

TMS Time Multiplier Setting

OHTL Over Head Transmission Line

MVA Mega Volt Ampere

MW Mega Watt

Chapter 1 [Introduction]

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CHAPTER ONE

1 Introduction

1.1 Overview

This chapter is intended to give the reader an idea about the project‟s problem, background,

objectives. In addition, an overview of the report layout is given.

1.2 Problem Statement

In Sudan , Oil and Gas operating companies have its own power network containing

generation, transmission, distribution, protection, etc. systems. One of the most challenges

facing these companies is the power protection systems, because the production fields

located at areas countered unstable security situations, for example local people normally

cutting power cables, transmission lines earth wires, steel bars, etc., another frequent

problems are the lightning strikes hitting the OHTL during rainy seasons as a result of that

power disturbance is frequently take place.[5]

1.3 Project background

The protection for an electrical system should not only be safe under all service conditions

but, to ensure continuity of service, it should be selectively coordinated as well. A

coordinated system is one in which only the faulted circuit is isolated without disturbing any

other part of the system.

Over current protection devices should also provide short-circuit as well as overload

protection for system components, such as bus, cables, motor controllers, ...etc.

To obtain reliable, coordinated operation and assure that system components are

protected from damage, it is necessary to first calculate the available fault current at various

critical points in the electrical system. Once the fault levels are determined, the

Chapter 1 [Introduction]

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electrical design professional can specify proper interrupting rating requirements, selectively

coordinate the system, and provide component protection.[6]

1.4 Objectives

The objectives of the project can be summarized as follows:

Simulate Baleela Oil-Field power Network using ETAP software.

Analyze Baleela Oil-Field power Network from the protection point of view

Point out the disadvantages of the currently used relay settings at Baleela power

Network.

Perform over-current phase (O/C) and earth fault protections on this network and

obtain its relays settings and co-ordination.

Apply instantaneous protection as a back-up protection.

1.5 Thesis Layout

Chapter two gives a detailed discussion of all the concepts and theories which are used in

protection co-ordination analysis.

Chapter three Baleela oil-field power network had been taken as case study, detailed

description about the system and different faults scenarios on the network had been

conducted.

Chapter four explains how to change the protection philosophy by using the more flexible

IDMT principle for over-current and earth fault. Different scenarios of faults on this network

had been conducted to assure that the protection scheme is operating adequately.

Chapter five provides conclusion of results, discussion and recommendations.

Appendix A presents the electrical system data for all substations.

Appendix B contains the old protection relay settings as recorded directly from the

instruments interface.

Appendix C contains the new relay coordination settings for each substation.

Chapter 2 [LITERATURE REVIEW]

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CHAPTER TWO

2 Literature Review

2.1 Introduction

An electric power system is a network deployed to supply, transfer, and use electric power

with both reliability and economy .A power system is not only capable to meet the present

load but also has the flexibility to meet the future demands on a continuous basis.[1]

To ensure the maximum return on the large investment in the equipment, which goes to make

up the power system and to keep the users satisfied with reliable service, the whole system

must be kept in operation continuously without major breakdowns . This can be achieved in

two ways :

The first way is to implement a system adopting components, which should not fail and

requires the least or nil maintenance to maintain the continuity of service. By common

sense, implementing such a system is neither economical nor feasible, except for small

systems.

The second option is to foresee any possible effects or failures that may cause long-term

shutdown of a system.

The main idea is to restrict the disturbances during such failures to a limited area and

continue power distribution in the balance areas. Special equipment is normally installed to

detect such kind of failures (also called „faults‟) that can possibly happen in various sections

of a system, and to isolate faulty sections so that the interruption is limited to a localized area

in the total system covering various areas. The special equipment adopted to detect such

possible faults is referred to as „protective equipment or protective relay‟ and the system that

uses such equipment is termed as „protection system‟.[2]


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A protective relay is the device, which gives instruction to disconnect a faulty part of the

system. This action ensures that the remaining system is still fed with power, and protects the

system from further damage due to the fault. Hence, use of protective apparatus is very

necessary in the electrical systems, which are expected to generate, transmit and distribute

power with least interruptions and restoration time. It can be well recognized that use of

protective equipment are very vital to minimize the effects of faults, which otherwise can kill

the whole system.[1]

2.2 Overview of electrical faults

Electrical faults usually occur due to breakdown of the insulating media between live

conductors or between a live conductor and earth. This breakdown may be caused by anyone

or more of several factors for example mechanical damage, overheating, voltage surges

(caused by lightning or switching), ingress of a conducting medium, ionization of air, or

misuse of equipment.

Fault currents release an enormous amount of thermal energy, and if not cleared quickly may

cause fire hazards, extensive damage to equipment and risk to human life. Faults are

classified into two major groups: symmetrical and unbalanced (asymmetrical).Symmetrical

faults involve all three phases and cause extremely severe fault currents and system

disturbances. Unbalanced faults include phase-to-phase, phase-to-ground, and phase-to-

phase-to-ground faults. They are not as severe as symmetrical faults because not all three

phases are involved. The least severe fault condition is a single phase-to-ground fault with

the transformer neutral earthed through a resistor or reactor. However, if not cleared quickly,

unbalanced faults will usually develop into symmetrical faults. Switchgear need to be rated to

withstand and break the worst possible fault current ,which is a solid three-phase short-circuit

close to the switchgear.[4]


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Power systems have been in operation for over a hundred years now. Accumulated

experience shows that all faults are not equally likely. Single line to ground faults (L-G)are

the most likely. Whereas the fault due to simultaneous short circuit between all the three

lines, known as the three-phase fault(L-L-L), is the least likely. This is depicted in Table

2.1[7] .

Table ‎2.1 Fault Statistics With Reference to Type of Fault

Fault Probability of occurrence (%) Severity

Line-to-Ground 85 Least severe

Line-to-line 8

Line-to-line-to-Ground 5

Line-to-line-to-line 2 Most severe

The probabilities of faults on different elements of the power system are different. The

transmission lines which are exposed to the vagaries of the atmosphere are the most likely to

Figure ‎2.1 Types of faults on a three-phase system: (A) Phase-to-earth

fault; (B) Phase-to-phase fault; (C) Phase-to phase- to-earth fault; (D) Three-

phase fault; (E) Three-phase-to-earth fault


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be subjected to faults. Indoor equipment is least likely to be subjected to faults. The fault

statistics is shown in Table 2.2.

Table ‎2.2 Fault Statistics With Reference to Power System Elements

Power system element Probability of faults (%)

Overhead lines 50

Underground cables 9

Transformers 10

Generators 7

Switchgear 12

CT, PT relays, control equipment, etc 12

The severity of the fault can be expressed in terms of the magnitude of the fault current and

hence its potential for causing damage. In the power system, the three-phase fault is the most

severe whereas the single line-to-ground fault is the least severe. [7]

2.3 Protection Definitions

The definitions that follow are generally used in relation to power system protection.

2.3.1 Protection System

A complete arrangement of protection equipment and other devices required to achieve a

specified function based on a protection principal.

2.3.2 Protection Equipment

A collection of protection devices (relays, fuses, etc.). Excluded are devices such as CT‟s,

CB‟s, Contactors, etc.

2.3.3 Protection Scheme

a collection of protection equipment providing a defined function and including all

equipment required to make the scheme work (i.e. relays, CT‟s, CB‟s, batteries, etc.) In

order to fulfill the requirements of protection with the optimum speed for the many different

configurations, operating conditions and construction features of power systems, it has been


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necessary to develop many types of relay that respond to various functions of the power

system quantities.

2.4 Protection quality

2.4.1 Overview

The basic function of electrical protection is to detect system faults and to clear them as soon

as possible. For any one particular application, there are many ways to do this function, with

varying degrees of effectiveness. The choice is influenced by the overall protection

philosophy of the plant, and the importance of the equipment or portion of the network to be

protected, weighing cost against performance. The general philosophy of applying protection

in a power network is to divide the network into protective zones, such that the power system

can be adequately protected with the minimum part of the network being disconnected during

fault conditions. The zones can either be very clearly defined, with the protection operating

exclusively for that zone only as in differential protection, illustrated in Figure 2.2 or less

clearly defined ,with overlapping of the protection function between zones for example, over-

current protection, as illustrated in Figure 2.3.

Figure ‎2.2 Zones of protection


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Figure ‎2.3 Overlapping of zones

2.5 Basic requirements of protection

A protection apparatus has three main functions/duties

i Safeguard the entire system to maintain continuity of supply .

ii Minimize damage and repair costs where it senses fault .

iii Ensure safety of personnel.

These requirements are necessary, firstly for early detection and localization of faults, and

secondly for prompt removal of faulty equipment from service. In order to carry out the

above duties, protection must have the following qualities.

2.5.1 Unit Protection (selectivity)

selectivity or Discrimination is the ability of the protection to isolate only the faulted part of

the system, minimizing the impact of the fault on the power network. Absolute

discrimination is only obtained when the protection operates exclusively within a clearly

defined zone. This type of protection is known as „unit protection‟, as only one unit is

exclusively protected for example, a transformer, or a specific feeder cable.

Unit protection can only be achieved when the following essentials are satisfied :

Sensing or measuring devices must be installed at each (electrical) end of the

protected equipment.

There has to be a means of communication between the devices at each end, in order

to compare electrical conditions and detect a fault when present.


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The most common form of unit protection is current differential protection, whereby current

values at each end of the protected equipment is measured and compared, and a trip signal is

issued when the difference in measured values is more than a predefined threshold value.

Advantages of unit protection

i. Only the faulted equipment or part of the network is disconnected, with minimum

disruption to the power network.

ii. Unit protection operates very fast, limiting damages to equipment and danger to

human life. Fast operation is possible because the presence or absence of a fault is a

very clear-cut case.

iii. Unit protection is very stable

iv. Unit protection is very reliable (provided the communication path is intact).

v. Unit protection is very sensitive.

Disadvantages of unit protection

i. It is very expensive.

ii. It relies on communication between the relays installed at either end.

iii. It can be maintenance-intensive to keep the communication medium intact,

depending on the application and environment.

The discrimination qualities of non-unit protection are not absolute, as the relay functions

independently and will generally operate whenever it sees a fault, no matter where the fault is

located. Therefore, to achieve proper discrimination for non-unit protection schemes, the

principle of grading is applied. Consider the example, as illustrated in figure 2.4 where the

protection consists of only over-current relays. If the relays in figure 2.4 were all of the

same type, and no lower or upper restrictions were placed on the grading, it would be quite

simple, and the time–current would look something like the graph in figure 2.5 .


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Figure ‎2.4 Application of principle of grading

Figure ‎2.5 Over current time grading


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2.5.2 Stability

Stability, also called security, is the ability of the protection to remain inoperative for normal

load conditions (including normal transients like motor starting).Most stability problems

arise from incorrect application of relays and lack of maintenance.

2.5.3 Reliability

Reliability, or dependability, is the ability of the protection to operate correctly in case of a

fault . Reliability is probably the most important quality of a protection system.

2.5.4 Speed of operation

The longer the fault current is allowed to flow, the greater the damage to equipment and the

higher the risk to personnel. Therefore, protection equipment has to operate as fast as

possible, without compromising on stability. The best way to achieve this is by applying unit

protection schemes. However, unit protection is expensive, hence the importance and cost of

the equipment to be protected, and the consequences of an electrical fault, must be

considered and weighed against the cost of very fast protection schemes.

2.5.5 Sensitivity

The term sensitivity refers to the magnitude of fault current at which protection operation

occurs. A protection relay is said to be sensitive when the primary operating current is very

low. Therefore, the term sensitivity is normally used in the context of electrical protection for

expensive electronic equipment, or sensitive earth leakage equipment.

2.6 Protection components

2.6.1 Voltage transformers

Two types of voltage transformers used for protection equipment

i. Electromagnetic type.

ii. Capacitor type.


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The accuracy of voltage transformers shall be capable to produce secondary voltages.

Voltage transformers for protection are required to maintain reasonably good accuracy over a

large range of voltage from 0 to 173% of normal Connection of voltage transformers.

Electromagnetic voltage transformers may be connected inter phase or between phase and

earth. However, capacitor voltage transformers can only be connected phase-to-earth.[1]

Voltage transformers are commonly used in three-phase groups, generally in star–star

configuration.The Instrument transformers secondary voltages provide a complete replica of

the primary voltages, and any voltage (phase to-phase or phase to-earth) may be selected for

monitoring at the secondary .

To prevent secondary circuits from reaching dangerous potential, the circuits should be

earthed. Earthing should be made at only one point of a VT secondary circuit or galvanically

interconnected circuits. A VT with the primary connected phase-to-earth shall have the

secondary earthed at terminal n. A VT with the primary winding connected across two-

phases, shall have that secondary terminal earthed which has a voltage lagging the other

terminal by 120°. Windings not under use shall also be earthed .

2.6.2 Current transformers

There are two types of current transformers

i. Wound primary type.

ii. Bar primary type .

The wound primary is used for the smaller currents, but it can only be applied on low fault

level installations due to thermal limitations as well as structural requirements due to high

magnetic forces. For currents greater than 100 A, the bar primary type is used. If the

secondary winding is evenly distributed around the complete iron core, its leakage reactance

eliminated .[1]

2.6.3 Fuses

Fuse is the most common and widely used protective device in electrical circuits


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Rewire able type as the name indicates the fuse can be replaced or „rewired‟ once it fails.

Fusible wire used to be contained in an asbestos tube to prevent splashing of volatile metal.

Advantages

i. Correct rating and characteristic fuse always fitted to a circuit-not open to abuse as

rewire able type.

ii. Arc and fault energy contained within insulating tube-prevents damage.

iii. Normally sealed therefore not affected by atmosphere hence gives more stable

characteristic-reliable grading.

iv. Can operate considerably faster, suitable for higher short-circuit duty (Cartridge type

can handle 100 000 A & Semi-open type can handle 4000 A).

Disadvantages

i Open to abuse due to incorrect rating of replacement elements hence affording

incorrect protection

ii Deterioration of element as it is open to the atmosphere..

2.6.4 Relays

Types of relays

2.6.4.1 Electromechanical Relays

These relays were the earliest forms of relay used for the protection of power systems ,The

mechanical force is generated through current flow in one or more windings on a magnetic

core or cores, hence the term electromechanical relay. The principle advantage of such relays

is that they provide galvanic isolation between the inputs and outputs in a simple, cheap and

reliable form. Therefore for simple on/off switching functions where the output contacts have

to carry substantial currents, they are still used .Electromechanical relays can be classified

into several different types as follows.[3]

i attracted armature

ii moving coil

iii induction

iv thermal


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v motor operated

vi mechanical

2.6.4.2 Static Relays

The term „static‟ implies that the relay has no moving parts .Their design is based on the use

of analogue electronic devices instead of coils and magnets to create the relay characteristic.

While basic circuits may be common to a number of relays, the packaging was still

essentially restricted to a single protection function per case, while complex functions

required several cases of hardware suitably interconnected .They therefore can be viewed in

simple terms as an analogue electronic replacement for electromechanical relays, with some

additional flexibility in settings and some saving in space requirements. In some cases, relay

burden is reduced, making for reduced CT/VT output requirements . A number of design

problems had to be solved with static relays. In particular, the relays generally require a

reliable source of d.c .power and measures to prevent damage to vulnerable electronic

circuits had to be devised.[3]

2.6.4.3 Digital Relays

Digital protection relays introduced a step change in technology. Microprocessors and

microcontrollers replaced analogue circuits used in static relays to implement relay functions.

Compared to static relays, digital relays introduce A/D conversion of all measured analogue

quantities and use a microprocessor to implement the protection algorithm. The

microprocessor may use some kind of counting technique, or use the Discrete Fourier

Transform (DFT) to implement the algorithm .The limited power of the microprocessors

used in digital relays restricts the number of samples of the waveform that can be measured

per cycle. This, in turn, limits the speed of operation of the relay in certain applications.

Therefore, a digital relay for a particular protection function may have a longer operation

time than the static relay equivalent. However, the extra time is not significant in terms of

overall tripping time and possible effects of power system stability.[3]

2.6.4.4 Numerical Relays

The distinction between digital and numerical relay rests on points of fine technical detail,

and is rarely found in areas other than Protection. They can be viewed as natural


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developments of digital relays as a result of advances in technology. Typically, they use a

specialized digital signal processor (DSP) as the computational hardware, together with the

associated software tools.

The input analogue signals are converted into a digital representation and processed

according to the appropriate mathematical algorithm. Processing is carried out using a

specialized microprocessor that is optimized for signal processing applications, known as a

digital signal processor or DSP for short. Digital processing of signals in real time requires a

very high power microprocessor. In addition, the continuing reduction in the cost of

microprocessors and related digital devices (memory, I/O, etc.) naturally leads to an

approach where a single item of hardware is used to provide a range of functions („one-box

solution‟ approach). By using multiple microprocessors to provide the necessary

computational performance, a large number of functions previously implemented in separate

items of hardware can now be included within a single item.[3]

2.6.5 Circuit breakers

Where fuses are unsuitable or inadequate, protective relays and circuit breakers are used in

combination to detect and isolate faults. Circuit breakers are the main making and breaking

devices in an electrical circuit to allow or disallow flow of power from source to the load.

These carry the load currents continuously and are expected to be switched ON with loads

(making capacity).

These should also be capable of breaking a live circuit under normal switching OFF

conditions as well as under fault conditions carrying the expected fault current until

completely isolating the fault side (rupturing/breaking capacity) Under fault conditions, the

breakers should be able to open by instructions from monitoring devices like relays. The

relay contacts are used in the making and breaking control circuits of a circuit breaker, to

prevent breakers getting closed or to trip breaker under fault conditions as well as for some

other interlocks .[1]

2.6.5.1 Purpose of circuit breakers

The main purpose of a circuit breaker is to :


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i Switch load currents.

ii Break normal and fault currents.

iii Carry fault current without blowing itself.

The important characteristics from a protection point of view are

i The speed with which the main current is opened after a tripping impulse is

received.

ii The capacity of the circuit that the main contacts are capable of interrupting.

2.6.5.2 Types of Circuit Breakers

The types of breakers basically refer to the medium in which the breaker opens and closes.

The medium could be oil, air, vacuum or SF6 .[1]

Arc Control Device

A breaker consists of moving and fixed contact, and during the breaker operation, the

contactse broken and the arc created during such separation needs to be controlled. The

breaker is shown in figure 2.6.

Figure ‎2.6 Arc control circuit-breaker


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Oil Circuit Breakers

In modern installations, oil circuit breakers, which are becoming obsolete, are being replaced

by vacuum and SF6 breakers. Oil circuit breaker is shown in figure 2.7.

Advantages

i Ability of cool oil to flow into the space after current zero and arc goes out.

ii Cooling surface presented by oil.

iii Absorption of energy by decomposition of oil.

iv Action of oil as an insulator lending to more compact design of switchgear.

Disadvantages

i Inflammability (especially if there is any air near hydrogen).

ii Maintenance (changing and purifying).

Figure ‎2.7 Oil circuit-breaker

In the initial stages, the use of high-volume (bulk) oil circuit breakers was more common, In

this type, the whole breaker unit is immersed in the oil. This type had the disadvantage of

production of higher hydrogen quantities during arcing and higher maintenance

requirements. Subsequently these were replaced with low oil (minimum oil) types, where the

arc and the bubble are confined into a smaller chamber, minimizing the size of the unit.[1]


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Air Break Switchgear

Interrupting contacts situated in air instead of any other artificial medium as shown in figure

2.8. Arc is chopped into a number of small arcs by the Arc-shut as it rises due to heat and

magnetic forces. The air circuit breakers are normally employed for 380~480 V distribution.

Figure ‎2.8 Air break switchgear

SF6 Circuit Breakers

Sulphur-hexaflouride (SF6) is an inert insulating gas, which is becoming increasingly

popular in modern switchgear designs both as an insulating as well as an arc-quenching

medium.[1]

Vacuum Circuit Breakers and Contactors

A circuit breaker is designed for high through-fault and interrupting capacity and as a result

has a low mechanical life. On the other hand, a contactor is designed to provide large number

of operations at typical rated loads of 200/400/600 A at voltages of 1500/3300/6600/11000

V.[1]


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2.7 Over-current Protection

Over current protection was naturally the earliest protection system to evolve , it is a

discriminative fault protection.

2.7.1 Co-ordination Procedure

Correct over-current relay application requires knowledge of the fault current that can flow in

each part of the network. The data required for a relay setting study are :

i. A one-line diagram of the power system involved, showing the type and rating of the

protection devices and their associated current transformers .

ii. The impedances in ohms, per cent or per unit, of all power transformers, rotating

machine and feeder circuits .

iii. The maximum and minimum values of short circuit currents that are expected to flow

through each protection device .

iv. The maximum load current through protection devices .

v. The starting current requirements of motors and the starting and locked rotor/stalling

times of induction motors .

vi. The transformer inrush, thermal withstand anddamage characteristics .

vii. Decrement curves showing the rate of decay of the fault current supplied by the

generators.

viii. Performance curves of the current transformers .

The relay settings are first determined to give the shortest operating times at maximum fault

levels and then checked to see if operation will also be satisfactory at the minimum fault

current expected .[3]

2.7.2 Principles of Time/Current Grading

Among the various possible methods used to achieve correct relay co-ordination are those

using either time or overcurrent, or a combination of both. The common aim of all three

methods is to give correct discrimination.


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2.7.2.1 Discrimination by Time

In this method, an appropriate time setting is given to each of the relays controlling the

circuit breakers in a power system to ensure that the breaker nearest to the fault opens first.

Each protection unit comprises a definite-time delay overcurrent relay in which the operation

of the current sensitive element simply initiates the time delay element. each relay time

setting must be long enough to ensure that the upstream relays do not operate before the

circuit breaker at the fault location has tripped and cleared the fault. The main disadvantage

of this method of discrimination is that the longest fault clearance time occurs for faults in

the section closest to the power source, where the fault level (MVA) is highest.[3]

2.7.2.2 Discrimination by Current

The relays controlling the various circuit breakers are set to operate at suitably tapered values

of current such that only the relay nearest to the fault trips its breaker.

There are two important practical points that affect this method of co-ordination:

i. it is not practical to distinguish between a fault at F1 and a fault at F2, since the

distance between these points may be only a few meters, corresponding to a change in

fault current of approximately 0.1% .

ii. in practice, there would be variations in the source fault level .

Discrimination by current is therefore not a practical proposition for correct grading between

the circuit breakers at two points. [3]

2.7.2.3 Discrimination by both Time and Current

Because of the limitations imposed by the independent use of either time or current co-

ordination that the inverse time over-current relay characteristic has evolved. With this

characteristic, the time of operation is inversely proportional to the fault current level .

Illustrates the characteristics of two relays given different current/time settings. For a large

variation in fault current between the two ends of the feeder, faster operating times can be

achieved by the relays nearest to the source, where the fault level is the highest. The

disadvantages of grading by time or current alone are overcome .[3]


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2.7.3 Standard I.D.M.T. Overcurrent Relays

The current/time tripping characteristics of IDMT relays may need to be varied according to

the tripping time required and the characteristics of other protection devices used in the

network. For these purposes, IEC 60255 defines a number of standard characteristics as

follows:

Standard Inverse (SI)

Very Inverse (VI)

Extremely Inverse (EI)

Definite Time (DT)

2.7.4 Combined IDMT and High Instantaneous Over-current Relays

A high-set instantaneous element can be used where the source impedance is small in

comparison with the protected circuit impedance. This makes a reduction in the tripping time

at high fault levels possible. It also improves the overall system grading by allowing the

'discriminating curves' behind the high set instantaneous elements to be lowered.[3]

One of the advantages of the high set instantaneous elements is to reduce the operating time

of the circuit protection by the shaded area below the 'discriminating curves'. If the source

impedance remains constant, it is then possible to achieve highspeed protection over a large

section of the protected circuit. The rapid fault clearance time achieved helps to minimize

damage at the fault location. a further important advantage gained by the use of high set

instantaneous elements. Grading with the relay immediately behind the relay that has the

instantaneous elements enabled is carried out at the current setting of the instantaneous

elements and not at the maximum fault level.[3]

2.8 Generator protection

Most leading manufacturers of relay equipment today have a multi-function generator relay

on the market, offering a host of functions. The relay has to be configured to meet the

customer‟s requirements and according to the equipment specifications. All of the functions

available need not be required and hence will not be configured. Configuration of complex


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multi-function relays like a generator protection relay is quite involved and is usually done

by the relay supplier, preferably on a factory test-set before installation.[4]

2.9 Feeder protection

Feeder protection can be applied in two form feeder differential protection or the traditional

over-current and earth fault functions, which are undoubtedly the most commonly used form

of protection.

An over-current and earth fault relay will generally be installed on each feeder cubicle in a

distribution substation, often supporting or as a backup for other specific types of protection,

like differential protection or transformer protection.

The feeder protection relay functions independently and in a very straightforward manner. It

is this characteristic, together with the fact that it is so commonly used, that made this relay.

The ideal candidate to be developed into a versatile, flexible intelligent relay, with powerful

control functions and advanced communications capabilities.[4]

2.10 Transformer protection

The functions of transformer protection relays are less complex than those of generator

protection, and the configuration of the relays is more standard, depending mostly on the

equipment specifications. Generally, differential protection will be applied, with over-current

and earth fault functions as a backup. Larger transformers may also have frequency

protection.

Supplementary protection devices will usually be interfaced to the transformer, e.g. Buchholz

protection, oil temperature,... etc. [4]

2.11 Bus-bar protection

The sole function of busbar protection is to protect the bus-bars of a switchgear panel against

internal faults, that is, faults within the clearly defined bus-bar zone. Bus-bar faults are by

nature quite severe, with high fault currents flowing. The damage to the switchgear panel,


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which is normally a very expensive piece of equipment as well as a crucial part of the

distribution network, can be extensive if the fault is not cleared quickly. Therefore, bus-bar

protection needs to operate very fast and reliably.[4]

2.12 Primary and Back-up Protection

In the event of failure or non-availability of the primary protection some other means of

ensuring that the faulty sections isolated must be provided. These secondary systems are

referred to as „back-up protection‟.

Back-up protection may be considered as either being „local‟ or „remote‟. Local back-up

protection is achieved by protection which detects an un-cleared primary system fault at its

own location and which then trips its own circuit breakers, e.g. time graded over-current

relays.

Remote back-up protection is provided by protection that detects an un-cleared primary

system fault at a remote location and then issues a local trip command, e.g. the second or

third zones of a distance relay. In both cases the main and back-up protection systems detect

a fault simultaneously, operation of the back-up protection being delayed to ensure that the

primary protection clears the fault if possible. Normally being unit protection, operation of

the primary protection will be fast and will result in the minimum amount of the power

system being disconnected. Operation of the back-up protection will be, of necessity, slower

and will result in a greater proportion of the primary system being lost.[3]

The extent and type of back-up protection applied will naturally be related to the failure risks

and relative economic importance of the system. For distribution systems where fault

clearance times are not critical, time delayed remote back-up protection may be adequate.

For EHV systems, where system stability is at risk unless a fault is cleared quickly, multiple

primary protection systems, operating in parallel and possibly of different types (e.g. distance

and unit protection), will be used to ensure fast and reliable tripping.


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Back-up over-current protection may then optionally be applied to ensure that two separate

protection systems are available during maintenance of one of the primary protection

systems.

Back-up protection systems should, ideally, be completely separate from the primary

systems.[3]

2.13 Trip Circuit Supervision

The trip circuit includes the protection relay and other components, such as fuses, links, relay

contacts, auxiliary switch contacts, etc., and in some cases through a considerable amount of

circuit wiring with intermediate terminal boards. [3]

These interconnections, coupled with the importance of the circuit, result in a requirement in

many cases to monitor the integrity of the circuit. This is known as trip circuit supervision.

The simplest arrangement contains a healthy trip lamp. The resistance in series with the lamp

prevents the breaker being tripped by an internal short circuit caused by failure of the lamp.

This provides supervision while the circuit breaker is closed, a simple extension gives pre-

closing supervision.

Schemes using a lamp to indicate continuity are suitable for locally controlled installations,

but when control is exercised from a distance it is necessary to use a relay system.[3]

Chapter 3 [Case Study: Baleela Oil-Field Network]

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CHAPTER THREE

3 Case Study: Baleela Oil-Field Network

3.1 Introduction

In power systems, the analysis of the network is an important step to determine the

performance, both under normal operation and during faults conditions.

Fault levels at different parts of the network, as well as protection coordination are some of

the many important parameters that define the performance of the network. Calculating these

measures and simulation of the system is invaluable in terms of identifying network

problems and suggesting modifications.

3.2 Overview

A site visit was conducted to Baleela Oil-Field network in order to collect the data of the

existing network, collect the uploaded settings of the protection system and investigate the

defects of the existing settings.

The following data was collected:

i. Details of 33kV and 11kV substations in the network.

ii. Single line diagram of the Baleela Power system network.

iii. Impedances of all transmission lines and transformers.

iv. Reactance and MW rating of all generators connected to the network.

v. Load details (MVAr and MW) of the existing network.

vi. Length and type of transmission lines from one substation to another.

The collected data old settings is shown in appendix A and B respectivly.


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3.3 Baleela oil-field network description

Baleela network have its own power station located at CPF with installed capacity of 34.78

MW to supply power to FULA, FNE, JAKE, MOGA and KEYI fields as described in the

following sections.

Figure ‎3.1 Geographic description of BALEELA network

3.3.1 CPF station

This station consists of four Rolls Royce gas engine units of 5.1 MVA, two Wartsila gas

engine units of 7.588 MVA, three Wartsila diesel engine units of 2.5 MVA , 11kV/33kV

substation and three feeders, 33kV to KEYI, 33kV to FNE and 33kV to MOGA .

Table 3.1 shows real and reactive power for CPF loads at busbar (A).


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Table ‎3.1: Real and reactive power for CPF loads at busbar A

Table 3.2 shows real and reactive power for CPF loads at busbar (B).

Table ‎3.2: Real and reactive power for CPF loads at busbar (B)

3.3.2 KEYI Substation

This substation is of single busbar type with two bus couplers. It is composed of two power

transformers 33/11kV linking the 33 and 11 kV busbars with rated power 2 MVA .

Table 3.3 shows real and reactive power for KEIY loads at busbar (A & B)

Table ‎3.3: Real and reactive power for KEIY loads at busbar (A & B)

3.3.3 FNE Substation

This substation is of single busbar type with two bus couplers, one section CB and two

section isolators and it is composed of two power transformers 33/11kV linking the 33 and

11 kV busbars with rated power 3.5 MVA .

Table 3.4 shows real and reactive power for FNE loads at busbar (A & B)


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Table ‎3.4: Real and reactive power for FNE loads at busbar A & B

3.3.4 Moga Substation

This substation is of a single busbar type with two bus couplers. It is composed of two power

transformers 33/11 kV linking the 33 and 11 kV busbars with rated Power 2 MVA. MOGA

substation has two outgoing 33kv transmission lines feeding JAKE substation .

Table 3.5 shows real and reactive power for MOGA loads at busbar (A & B)

Table ‎3.5: Real and reactive power for MOGA loads at busbar (A & B)

3.3.5 JAKE Substation

This substation is of single busbar type with two bus couplers. It is composed of two power

transformers 33/11 kV linking the 33 and 11 kV busbars with rated power 2.5 MVA .

Table 3.6 shows real and reactive power for JAKE loads at busbar (A & B)

Table ‎3.6: real and reactive power for JAKE loads at busbar (A & B)


29 | P a g e

3.4 Network Implementation and Simulation

The simulation program used in this study is ETAP 12.6 (Electrical Transient and Analysis

Program). The circuit was constructed using all the required data and parameters as shown in

the single line diagram in figure 3.2.

Figure ‎3.2 Baleela Oil-Field Network Single Line Diagram

The single-line diagram includes all substations with the load of each feeder in each

substation, power transformers (rating, winding connection and grounding means), Incoming

and outgoing lines.

The ETAP Single-Line Diagram is used to create and visually manage the electrical

schematics and electrical drawings of Baleela network. It will also be used to perform

multiple simultaneous scenario simulations.


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3.5 Simulation Scenarios (Old settings)

3.5.1 Overview

All outgoing transmission lines relays setting was DMT with time delay (0.1 or 0.2 sec )

which will lead to trip of the outgoing transmission line for any fault that occurs at any

substation‟s feeder. Hence the protection scheme is miss-coordinated.

3.5.2 Three-Phase Fault Scenarios (phase)

To demonstrate this, JAKE substation was taken as a case study. Its existing protection

settings are uploaded in ETAP software. Tables in appendix (B) show existing settings of

JAKE substation.

The reason behind taking CPF-JAKE line as a case study is that it is the longest line, and

gives many faulty operations of relays.

3.5.2.1 A three phase fault on JAKE 11kV feeder

A three phase fault was simulated at (CH05 TR7802A) feeder as shown in figure 3.3

Figure ‎3.3 Three phase fault on JAKE (CH05 TR7802A) feeder


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The sequence of operation for three phase fault on JAKE 11kV feeder is shown in figure 3.4.

Figure ‎3.4 sequence of operation for JAKE 11kV feeder

From figure 3.4, it's clear that the bus section relay (relay 32) and the two relays at the

primary side of the two transformers (relay 44 and relay 45) tripped at the same time as the

faulted feeder relay (relay 47),which means that the whole substation is out for a single three

phase fault at the downstream feeder.

Also the two relays of the two feeders (relay 46 and relay 56) tripped at the same time (300

milliseconds) due to the high reverse currents of the motors.

The correct sequence of operation is that the feeder relay (relay 47) must trip first followed

by the bus section relay (relay 32) delayed by at least 150 millisecond then the two 11 kv

incomers (relay 33 & 43) also delayed by at least 150 millisecond, then the two relays of the

primary side of the transformer.


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3.5.2.2 A three phase fault at the transmission line

A three phase fault was simulated at MOGA-JAKE transmission line as shown in figure 3.5.

Figure ‎3.5 Three phase fault at MOGA-JAKE transmission line

The sequence of operation for three phase fault at MOGA-JAKE line is shown in figure 3.6

Figure ‎3.6 sequence of operation for fault at MOGA-JAKE transmission line


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From figure 3.6, it's clear that the two relays of the two parallel transmission lines going from

CPF to MOGA (relay 217 and relay 230) tripped instantaneously at zero second. Hence

MOGA substation will totally blackout for any fault that occur at the transmission line

going to Jake substation .hence protection scheme is miss-coordinated.

The correct sequence of operation is that the sending end of the two transmission line (going

to JAKE) relay (relay 250( must trip first followed by the bus section relay (relay 57) delayed

by at least 150 millisecond then the receiving end of the transmission line (coming from

CPF) relay (relay 249) also delayed by 150 millisecond.

3.5.2.3 A three phase fault at CPF 33kV bus-bar

A three phase fault at CPF 33kV bus-bar (B) was simulated as shown in figure 3.7

Figure ‎3.7 Three phase fault at CPF 33kV bus-bar (B)


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The sequence of operation for three phase fault at CPF 33kV bus-bar B is shown in figure

3.8.

Figure ‎3.8 sequence of operation for a fault on CPF 33kV bus-bar (B)

From the figure 3.8, is clear that all relays of the feeders in CPF (bus-bar A & B 11kV)

tripped due to the reverse current before the bus section.

Also the tripping of the bus section was delayed (after 500 millisecond), also 33kv incomer

relay did not trip. Hence protection scheme is miss-coordinated.

The correct sequence of operation is that the bus section relay (relay 171) must trip first then

the two 33kv incomers of CPF relays delayed by at least 150 millisecond then the two relays

of the primary side of the transformer.


35 | P a g e

3.5.3 Line-To-Ground Fault Scenarios (earth fault)

3.5.3.1 Line -To-Ground fault on KEYI 11kV feeder (feeder TR-6802)

Line -To-Ground fault is simulated on KEYI 11kV feeder (feeder TR-6802) as shown in

figure 3.9

Figure ‎3.9 Line-to-Ground fault on KEYI 11kV feeder

Figure 3.10 shows the sequence of operation for Line-to-Ground fault on KEYI 11kV feeder

Figure ‎3.10 The sequence of operation for Line-to-Ground fault on KEYI 11kV feeder


36 | P a g e

From figure 3.10, it is clear that the bus-section relay (relay 98) is disabled which means that

the two 11kv bus-bars will be lost if the feeder relay failed to operate .also the earth fault

element of the two 11kv incomers is delayed by 600 milliseconds.

3.5.3.2 Line -To-Ground fault at transmission line between CPF and KEYI

Line -To-Ground fault was simulated at transmission line between CPF and KEYI as shown

in figure 3.11

Figure ‎3.11 Line -To-Ground fault at transmission line between CPF and KEYI

Figure 3.12 shows the sequence of operation for Line -To-Ground fault at CPF- KEYI line

Figure ‎3.12 Sequence of operation for Line-to-Ground fault at CPF-KEYI transmission

line


37 | P a g e

From figure 3.12, the earth fault of the sending end relay of the transmission line (Relay 178)

operates instantaneously at Zero millisecond. However, it is clear that the earth fault element

of the bus-coupler relay is disabled and this will cause both transformers to be tripped when

the transmission line relay didn‟t operate. In addition, the earth fault element of the two 33kV

incomers was delayed by 1500 millisecond. This delay at fault current of 1260A will damage

the electrical equipments.

After investigation of the above fault scenarios, we found that the major cause of miss

coordination behavior of the relays was due to the use of the definite minimum time

philosophy.

3.6 Concept of DMT and I.D.M.T

3.6.1 Definite Time Relay

In this type of relay the setting may be changed to deal with different levels of current by

using different operating times.

The operation rules for definite-time-delayed over current relays can be expressed in the

following equation:

𝑇 =2𝑇𝑠

1+𝑠𝑔𝑛 (𝐼−𝐼𝑆) 3.1

Where T: relay operation time

Is: current setting threshold

I: current detected by relay (after relay filtering)

Ts: relay delay setting

Sgn: sign function (sign taken from the result, value being 1)

Equation (3.1) above means that:

𝑻 = ∞ 𝑰 < 𝑰𝑺𝑻𝑺 𝑰 > 𝑰𝑺


38 | P a g e

The characteristic curve of a definite time relay is shown in figure 3.13

Figure ‎3.13 Definite time relay curve

Definite time protection is more selective as the operating time can be set in fixed steps.

However, faults close to the source, which results in higher currents may be cleared in a

relatively long time.

To enhance the protection scheme performance we must use a more flexible philosophy of

the current- time characteristic such as inverse definite minimum time philosophy.

3.6.2 Inverse Time Relays

These relays operate in a time that is inversely proportional to the fault current. Inverse time

relays have the advantage of that shorter tripping times can be achieved without risking the

protection selectivity. These relays are classified based on their characteristic curves, which

define the speed of operation as inverse, very inverse or extremely inverse. Their defining

curve shape is shown in Figure 3.14.

Figure ‎3.14 Inverse time relay curve

https://www.google.com/url?sa=i&rct=j&q=&esrc=s&source=images&cd=&cad=rja&uact=8&ved=0CAcQjRw&url=https://electricalnotes.wordpress.com/2013/01/01/types-of-over-current-relay/&ei=BeHtVLiWIurlsATHo4HYAQ&bvm=bv.86956481,d.d24&psig=AFQjCNHcQUnth-Eb_DqlnOv_bfFqGOxc-Q&ust=1424961806598537

http://www.google.com/url?sa=i&rct=j&q=&esrc=s&source=images&cd=&cad=rja&uact=8&ved=0CAcQjRw&url=http://electrical-engineering-portal.com/types-and-applications-of-overcurrent-relay-1&ei=q-HtVNuhNOjasATVg4DwAw&bvm=bv.86956481,d.cWc&psig=AFQjCNHIFTKqpB1wwnK7etjtKq2UC8_Nzg&ust=1424962331333844


39 | P a g e

According to IEC and IEEE standards, the characteristic of inverse-time over current relays

can be depicted by the following expression:

𝑻 =𝑪

𝑰

𝑰𝑺 𝜶

−𝟏 3.2

Where:

T: relay operation time

C: constant for relay characteristic, proportional to the time multiplier setting

Is: current setting threshold

I: current detected by relay (after relay filtering), I>Is

α: constant representing inverse-time type, α>0

By assigning different values to α and C, there are different types of inverse characteristics.

Table 3.7 shows the definitions of various types by IEC and IEEE respectively.

Table ‎3.7: Parameters for different types of inverse characteristic

Curve Type

α C

IEC IEEE IEC IEEE

Standard Inverse (SI) 0.02 0.02 0.14 0.0515

Very Inverse (VI) 1 2 13.5 19.61

Extreme Inverse (EI) 2 2 80 28.2

Long Inverse (LI) 1 - 120 -

Chapter 4 [Implementation and Results]

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CHAPTER FOUR

4 Implementation and Results

4.1 Introduction

This chapter introduces the results obtained from Relay coordination study. and the new

settings will be used to obtain a well coordinated network.

4.2 Analysis Conditions

The analysis was performed under the normal conditions of generators ( two Rolls Royce gas

engine units of 5.1 MVA and two Wartsilla (gas) units of 7.588 MVA), operating according

to the site visit. The loads are the lumped loads and they were modeled exponentially.

4.3 Protection Settings Coordination Results

A completely new coordinated scheme was designed. It discriminated the network in

different zones. It starts first by coordinating the over-current elements, for different paths

from furthest downstream up to the generators. Next the Earth Fault relays were coordinated

for the same paths and finally the instantaneous elements.

The entire definite-minimum-time (DMT) scheme was replaced with the more flexible

inverse-definite-minimum-time (IDMT) scheme philosophy for first stage of both over-

current and earth fault.

The result is that the new philosophy and settings provide a backup over current and earth

fault system that is streamlined and does not result in some gross miss-operations such as

loss of 33kV feeders in CPF due to a fault on the 11kV bus of JAKE. For all substations, the

pickup settings for earth fault were coordinated by taking thirty percent of the normal full

load current.


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4.4 New Relay Settings Coordination

4.4.1 Over-current Settings

4.4.1.1 JAKE –MOGA

The coordination started from far downstream at 11kV feeder of JAKE substation until

MOGA 33kV bus-bar (MOGA 33kV outgoing relay), this coordination by both current and

time to ensure adequate fault isolation. The coordination is shown in next figures .

The new coordination is shown in figure 4.1

Figure ‎4.1 The new phase [O/C] settings for JAKE-MOGA path relays


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4.4.1.2 MOGA – CPF

The coordination is shown in figure 4.2

Figure ‎4.2 The new phase [O/C] settings for MOGA-CPF path relays


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4.4.1.3 FNE - CPF


Figure ‎4.3 The new phase [O/C] settings for FNE-CPF path relays


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4.4.1.4 KEYI - CPF


Figure ‎4.4 The new phase [O/C] settings for KEYI-CPF path relays


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4.4.2 Earth Fault Settings

4.4.2.1 Settings for JAKE up to the secondary of its transformer


Figure ‎4.5 New earth fault settings for JAKE up to the secondary of its transformer


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4.4.2.2 Settings from JAKE primary of the transformer up to CPF


Figure ‎4.6 New earth fault settings from JAKE primary of the transformer up to CPF


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4.4.2.3 Settings for MOGA up to the secondary of its transformer


Figure ‎4.7 New earth fault settings For MOGA up to secondary of its transformer


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4.4.2.4 Settings from MOGA primary of the transformer up to CPF


Figure ‎4.8 New earth fault settings from MOGA primary of the transformer up to CPF


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4.4.2.5 Settings for FNE up to Secondary of its transformer


Figure ‎4.9 New earth fault settings for FNE up to secondary of its transformer


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4.4.2.6 Settings from FNE primary of the transformer up to CPF


Figure ‎4.10 New earth fault settings from FNE primary of the transformer up to CPF


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4.4.2.7 Settings for KEYI up to secondary of its transformer


Figure ‎4.11 New earth fault settings from KEYI up to secondary of its transformer


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4.4.2.8 Settings from KEYI primary of the transformer up to CPF


Figure ‎4.12 New earth fault settings from KEYI primary of the transformer up to CPF


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4.4.2.9 Settings from CPF primary of its transformer up to 11kV bus section


Figure ‎4.13 New earth fault settings for CPF primary of its transformer up to 11kV bus

section


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4.5 Simulation Scenarios (new settings)

4.5.1 Overview

Now when applying the new settings mentioned in above section into ETAP to simulate the

sequence of operations for the same type of faults as mentioned in Chapter three, the results

showed that almost all the problems associated with the old settings has been resolved and

the network is well coordinated.

4.5.2 Three-Phase Fault Scenarios

4.5.2.1 A three phase fault on JAKE 11kV feeder

A three phase fault was simulated on JAKE 11kV feeder as shown in figure 4.14

Figure ‎4.14 Three phase fault on JAKE 11kV (CH05 TR7802A) feeder


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The sequence of operation for three phase fault on JAKE 11kV feeder is shown in figure 4.15

Figure ‎4.15 sequence of operation for a three phase fault on JAKE 11kV feeder

from figure 4.15 it is clearly that the feeder relay (relay 47) was tripped first at Zero second

by instantaneous element followed by the bus section relay (relay 32) delayed after 170

millisecond then the two 11kV incomers (relay 33 & 43) after 370 millisecond. After that the

two relays of the primary side of the transformers (relay 44 & 45) were tripped. Now this is

the correct sequence of operation, also grading margin between relays is maintained above

150 millisecond. Hence, miss-coordination will not occur as demonstrated in section

(3.5.2.1).

From above sequence of operation, the discrimination was conducted correctly which was

not achieved at the old setting as shown in section (3.5.2.1).

4.5.2.2 A three phase fault at the transmission line

A three phase fault was simulated at MOGA-JAKE transmission line as shown in figure 4.16


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Figure ‎4.16 Three phase fault at MOGA-JAKE transmission line

The sequence of operation for three phase fault at MOGA-JAKE transmission line is shown

in figure 4.17

Figure ‎4.17 sequence of operation for a three phase fault at MOGA-JAKE line


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Comparing figure 4.17 with that of chapter three (figure 3.6), it's clearly that the correct

sequence of operation is now achieved. Also, the grading margin between relays is

maintained above 150 millisecond.

Another point to shed the light on here, is the benefits of using the instantaneous current at

the beginning of the line (or on the transformer primary) to isolate the faults on the line as

quickly as possible. In this case, the instantaneous element enabled relay 250 to trip the line

at Zero seconds.

4.5.2.3 A three phase fault at CPF 33kV bus-bar

A three phase fault was simulated at CPF 33kV bus-bar (B) as shown in figure 4.18.

Figure ‎4.18 Three phase fault at CPF 33kV bus-bar (B)


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The sequence of operation for three phase fault at CPF 33kV bus-bar (B) is shown in figure

4.19

Figure ‎4.19 sequence of operation for three phase fault at CPF 33kV bus-bar (B)

Comparing this sequence of operation , for three phase fault on CPF 33kV bus-bar (B), with

the old setting, it's obvious that the correct sequence of operation is now achieved. However,

the bus coupler relay (Relay 171) had operated after a long period of time (1.185s) and this is

a situation that needs improving.

One possible and necessary solution is to install bus-bar differential protection on CPF 33kV

bus-bars to isolate this type of fault quickly.

4.5.3 Line-To-Ground Fault Scenarios (earth fault)

4.5.3.1 Line -To-Ground fault on KEYI 11kV feeder (feeder TR-6802)

Line -To-Ground fault is simulated on KEYI 11kV feeder (feeder TR-6802) is shown in

figure 4.20


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Figure ‎4.20 Line-to-Ground fault on KEYI 11kV feeder

Figure 4.21 shows the sequence of operation for earth fault on KEYI 11kV feeder


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Figure ‎4.21 The sequence of operation for Line-to-Ground fault on KEYI 11kV feeder

From figure 4.21 it is clear that the feeder relay (relay 102) tripped instantanously at zero

millisecond followed by the bus-section relay (relay 98) at 170 millisecond then the two 11kv

incomers (relay 97 and relay 107 ) tripped at 340 millisecond.


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4.5.3.2 Line -To-Ground fault at transmission line between CPF and KEYI

Line -To-Ground fault was simulated at transmission line between CPF and KEYI is shown

in figure 4.22

Figure ‎4.22 Line -To-Ground fault at transmission line between CPF and KEYI


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Figure 3.12 shows the sequence of operation for fault at transmission line between CPF and

KEYI

Figure ‎4.23 sequence of operation for Line-to-Ground fault on CPF- KEYI transmission

line

From figure 4.2 it is clear that the feeder relay (relay 178) tripped instantanously at zero

millisecond followed by the buscoupler relay (relay 171) at 821 millisecond then the two

33kv incomers (relay 8and relay 10 ) tripped after 1 second.


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4.6 Summery

Now and after this study for all substations the coordination has been achieved as follows:

The coordination of the over current settings starts at far downstream of the JAKE 11

kV feeder relay with IDMT delay curve and minimum time multiplier setting (TMS)

= 0.025.

The next relay is the bus section relay which was coordinated using pickup above the

rated current passing through the secondary side of the transformer, with a TMS=

0.05 , in order to isolate the healthy load from the faulty side.

Then 11 kV incomer relay with pickup above the rated current on low voltage side of

33/11 kV main transformer with a TMS = 0.1. Also 33 kV transformer feeders were

coordinated with a slightly higher pickup than the low voltage side of 33/11 kV main

transformer, but with the same TMS to ensure that the two relays will operate at the

same time in order to completely isolate the main transformer (i.e. reacts as a

differential protection).

Also, instantaneous element was implemented on the high voltage side of 33/11 kV

main transformer as a back-up protection to ensure fast adequate operation of the

relay.

The bus coupler on normal operation is opened, but for worst case scenario it‟s

coordinated with a pickup = 0.4 and TMS = 0.15.

The 33 kV incomer is coordinated with pickup = 0.75 and TMS = 0.2.

Then the sending end of the transmission line is coordinated with a pickup slightly

higher than the receiving end but with the same TMS = 0.2 to isolate both ends of the

line in almost the same time.

An instantaneous element was implemented at the sending end of the transmission

line as a back-up protection to ensure fast adequate operation of the relay.

Then the bus coupler of the 33kv bus bar of MOGA is coordinated with TMS = 0.72.

Then the outgoing is coordinated with pickup = 0.9 for the receiving end and 1.15 for

the sending end with the same TMS= 0.3.


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The earth fault settings were coordinated in the same way as for over-current in TMS

setting, furthermore the pickup settings were coordinated by taking thirty percent

from over-current pickup settings.

This coordination was performed to all substations (KEYI, FNE, MOGA, and JAKE)

except the feeders of the CPF main station because these feeders are directly

connected to the generation side.

In all 11 kV feeders of the CPF main station the pickup was raised up to avoid the

inrush current of the big motors, and the proposed settings is given in Appendix C.

Table 4.1 shows each scenario with its coordination status.

Table ‎4.1 Coordination status for each scenario

Scenario No Scenario description Uploaded settings Status of

coordination

4.5.2.1

Three phase fault on

JAKE 11kV feeder

(CH05 TR7802A)

Old settings

Miss coordinated

New settings Well coordinated

4.5.2.2


outgoing

transmission line

from MOGA to

Old settings

Miss coordinated


4.5.2.3


CPF 33kV bus-bar B

Old settings

Miss coordinated

New settings

Well coordinated

4.5.3.1

Line-To-Ground

fault on KEYI 11kV

feeder (TR6802

feeder)

Old settings

Will coordinated (but

with a large time

delay)


4.5.3.2

Line-To-Ground

fault on transmission

line between CPF

and KEYI

Old settings

Will coordinated (but

with a large time

delay)


Chapter 5 [Conclusion and Recommendations]

65 | P a g e

CHAPTER FIVE

5 Conclusion

5.1 Protection Settings Coordination The over-current protection settings coordination has been achieved successfully, and the

sequence of tripping starts at far downstream of the JAKE 11 KV feeder relay with IDMT

curve, then the 11 kV bus section relay, 11 kV incomer and 33 KV transformer feeders, Then

the 33 kV bus coupler, and finally the 33 kV incomer at 33 kV bus-bar on MOGA substation

and the outgoing transmission lines at the CPF main station. For the remaining substations,

the phase and earth fault settings were coordinated in the same way as for JAKE to CPF path.

Furthermore, the pickup settings for earth fault were coordinated by taking thirty percent of

the normal full load current. Also, an instantaneous element was performed successfully as a

back-up protection

5.2 Objectives Achieved

Baleela Oil-Field power Network has been simulated and analyzed using ETAP

software.

From simulating the currently-used relay settings, the disadvantages have been

observed.

Then, the optimum characteristics, which is IDMT, is chosen and performed for both

phase and earth fault protections on this network.

Instantaneous element is installed as a back-up protection.

With the use of the new settings, Baleela Network has been well coordinated.

Chapter 5 [Conclusion and Recommendations]

66 | P a g e

5.3 Recommendations

It‟s recommended to replace the currently installed DMT settings with the new

IDMT settings for both overcurrent and earth faults into all relays at Baleela network.

It‟s recommended to install busbar differential protection at CPF and MOGA 33KV

busbars to isolate the faults on them as quickly as possible. Because both the new and

old settings showed a high operating time for such faults.

Relay Settings coordination for both phase and earth faults in all substations should be re-

assessed on regular basis, because the nature of loads are dynamically changed.

It's recommended that all transformers and transmission lines relays to trip the two

breakers in order to entirely isolate the faulty transformer or transmission line.

It‟s recommended to re-calculate all the spare feeders‟ normal current before they are

connected to any load.

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References

[1]L.G.Hewitson, Mark Brown, Ramesh Balakrishnan, “Practical Power Systems Protection“

[2]J. Lewis Blackburn and Thomas J. Domain, “Protective Relaying Principles and

Applications”, Third Edition 2007.

[3] Areva, “Network Protection and Automation Guide”, First edition july 2002.

[4] Cobus strauss."Practical Electrical Network Automation and Communication Systems".

[5]Petro Energy Company E&P Co., Ltd., “Draft Report”

[6] Robert B. Hicke, “Electrical Engineer's Portable Handbook”.

[7]Y.G. Paithanka & S.R. Bhide, “Fundamentals of Power System Protection”.

Visvesvaraya National Institute of Technology Nagpur, 2003.

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6 Appendix A

A.1 Transformer Data

Table A.1 shows a power transformers technical data.

Table A.1 Power Transformers Technical Data

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A.2 X/R Ratio for each transformer

Table A.1 shows X/R ratio for each transformer using the transformer rated MVA and

copper losses.

Table A. 2 X/R ratio for each transformer using the transformer rated MVA and copper

losses

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A.3 Transmission Lines Data

Table A.3 shows transmission lines data

Table A. 3 Transmission Lines Data

A.4 The generators dynamic data

Table A.4 shows The generators dynamic data

Table A. 4 The generators dynamic data

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Appendix B

7 OLD SETTINGS

B.1 OLD SETTINGS – FNE SUBSTATION

Table B. 1 11kV Feeders on 1stBusbar

Feeder

Overcurrent protection [50/51] Earth protection [50N/51N] Relay

Type

C.T.

ratio

De

lay

cur

ve

typ

e

Current

setting

Time

settin

g

Instantaneous

protection

(DMT)

Ti

m

e

C.

T.

rat

io

De

lay

cur

ve

typ

e

Curre

nt

settin

g

Tim

e

setti

ng

Instantaneous

protection

(DMT)

Tim

e

BH01: Spare

Feeder

50/1 D

M

T

I

>0.48𝐼𝑛

2 I >>0.55𝐼𝑛

I >>>5.38𝐼𝑛

0.

5s

0 s

50

/1

D

M

T

I >

0.2𝐼𝑒

0.5 I >>0.4 𝐼𝑒 0 s

Tamco

Micom

P123

BH02: Spare

Feeder

50/1 D

M

T

I

>0.48𝐼𝑛

2 I >>0.55𝐼𝑛

I >>>5.38𝐼𝑛

0.

5s

0 s

50

/1

D

M

T

I >

0.2𝐼𝑒

0.5 I >>0.4 𝐼𝑒 0 s

Tamco

Micom

P123

BH03: Spare

Feeder

50/1 D

M

T

I

>0.48𝐼𝑛

2 I >>0.55𝐼𝑛

I >>>5.38𝐼𝑛

0.

5s

0 s

50

/1

D

M

T

I >

0.2𝐼𝑒

0.5 I >>0.4 𝐼𝑒 0 s

Tamco

Micom

P123

BH04:

1#RMUFeed

er

150/1 D

M

T

I > 0.5

𝐼𝑛

0.02 I >>0.5𝐼𝑛

I >>>0.6𝐼𝑛

0 s

0 s

50

/1

D

M

T

SI

I >

0.1𝐼𝑒

0.05 I >> 0.2 𝐼𝑒

I>>0.2 𝐼𝑒

0 s

0 s

Tamco

MicomP

123

72 | P a g e

BH05: TR-

8802A

100/1 D

M

T

I >

0.76𝐼𝑛

2 I >>0.98 𝐼𝑛

I >>>3.01 𝐼𝑛

0.

3s

0 s

50

/1

ID

M

T

SI

I >

0.2𝐼𝑒

0.5 I > 0.4 𝐼𝑒 0 s Tamco

Micom

P123


Busbar

Feeder


Type

C.T.

ratio

Dela

y curv

e

type

Current

setting

Time

setting

Instantaneous

protection (DMT)

Time C.T.

ratio

Dela

y curve

type

Curren

t setting

Time

setting

Instantaneo

us protection

(DMT)

Tim

e

BH12: TR-8802B 100/1

DMT

I >

0.76 𝐼𝑛

0.02 I >>0.98𝐼𝑛

I >>>3.01𝐼𝑛

0.3 s

0 s

50/1 DMT I >

0.2𝐼𝑒

0.5 I > 0.4 𝐼𝑒 0 s Tamco Micom

P123

BH13: Spare Feeder

100/1

DMT

I >

0.75𝐼𝑛

0.025 I >>1.08𝐼𝑛

I >>>16.41𝐼𝑛

0 s

0 s

50/1 DMT I >

0.2𝐼𝑒


P123

BH14: Spare

Feeder

40/1 DM

T

I >

0.75 𝐼𝑛

0.025 I >>1.08𝐼𝑛

I >>>16.40𝐼𝑛

0 s

0 s

50/1 DMT I >

0.2𝐼𝑒

0.025 I > 0.4 𝐼𝑒 0 s Tamco

Micom P123

BH15: 1# RMU

Feeder

150/

1

DM

T

I > 0.4

𝐼𝑛

0.025 I >>0.6𝐼𝑛

I >>>0.9𝐼𝑛

0 s

0 s

50/1 DMT I >

0.2𝐼𝑒

0.025 I > 0.4 𝐼𝑒 0 s Tamco

Micom P123

BH16: Spare

Feeder

100/

1

DM

T

I >

0.75 𝐼𝑛

0.025 I >>4.43𝐼𝑛

I >>5.01𝐼𝑛

0 s

0 s

50/1 DMT I >

0.2𝐼𝑒

0.025 I > 0.4 𝐼𝑒 0 s Tamco

Micom P123

Table B. 3 11kV Incomers

Incomer Overcurrent protection [50/51] Earth protection [50N/51N] Relay

Type

C.T.

ratio

Delay

curve

type

Current

setting

Time

setting

Instantaneous

protection

(DMT)

Time C.T.

ratio

Delay

curve

type

Current

setting

Time

setting

Instantaneous

protection

(DMT)

Time

73 | P a g e

BH07: 1#

Incomer

200/1 DMT I >

0.8 𝐼𝑛

2 I >>1.5𝐼𝑛

I >>>2.5𝐼𝑛

0.5 s

0.1s

200/1 DMT I >

0.1𝐼𝑒

0.1 s. I >> 0.15 𝐼𝑒

I >>> 0.4 𝐼𝑒

0.6 s

0.1 s

Tamco

Micom P121

BH10: 2#

Incomer

200/1 DMT I >

0.8 𝐼𝑛

2 I >>1.5𝐼𝑛

I >>>2.5𝐼𝑛

0.5 s

0.1s

200/1 DMT Disabled Tamco

Micom P121

Table B.4 33kV Transformer Feeders

Transformer

feeders


Type C.

T.

rati

o

Dela

y

curv

e

type

Curren

t

setting

Time

settin

g

Instantaneo

us

protection

(DMT)

Tim

e

C.T.

ratio

Delay

curve

type

Current

setting

Time

setting

Instantaneo

us

protection

(DMT)

Time

2#

Transformer-A

75/

1

DM

T

I

>0.8𝐼𝑛

0.1 Disabled 50/1 DMT I >

0.6𝐼𝑒

0.025 Disabled Schneider

P142

9#

Transformer-B

75/

1

DM

T

I

>0.8𝐼𝑛


0.6𝐼𝑒


P142

Table B. 5 33kV Bus coupler

Bus

Coupler


Type C.T.

ratio

Delay

curve

type

Current

setting

Time

setting

Instantaneous

protection

(DMT)

Time C.T.

ratio

Delay

curve

type

Current

setting

Time

setting

Instantaneous

protection

(DMT)

Time

6# Bus

coupler

150/1 DMT

I >

0.4𝐼𝑛

0.125 Disabled 150/1 Disabled Disabled Schneider

P143

74 | P a g e


Incomer Overcurrent protection [50/51] Earth protection [50N/51N] Relay Type

C.T.

ratio

Delay

curve

type

Current

setting

Time

setting

Instantaneous

protection

(DMT)

Time C.T.

ratio

Delay

curve

type

Current

setting

Time

setting

Instantaneous

protection

(DMT)

Time

4# Incoming

1

150/1 DMT I >

0.5𝐼𝑛


1.14𝐼𝑒

0.15 Disabled Schneider P143

7#

Incoming 2

150/1 DMT I >

0.5𝐼𝑛


1.14𝐼𝑒


P143

Table B. 7 11kV Bus-section & 11kV two Incomers Directional Protection

Incomer Overcurrent protection [67] Earth protection [67N] Relay

Type

C.T. ratio

Delay curve

type

Current setting

Time

sett

ing

Instantaneous

protection

(DMT)

Time

C.T. ratio

Delay curve

type

Current setting

Time setting

Instantaneous protection

(DMT)

Time

BH07: 1#

Incomer

200/

1

DMT I

>0.85𝐼𝑛

0.0

75

Disabled 40/1 DMT I >

0.8𝐼𝑒

0.1 Disabled Tamco

P127

BH10: 2#

Incomer

200/

1

DMT I >

0.85𝐼𝑛

0.0

75

Disabled 40/1 DMT I >

0.8 𝐼𝑒

0.1 Disabled Tamco

P127

BH08: Bus

section

200/

1

DMT I >

0.6𝐼𝑛

0.0

5

Disabled 200/

1

Disabled Tamco

P127

75 | P a g e

B.2 OLD SETTINGS – MOGASUBSTATION

Table B. 8 11 kV Feeders on 1st

Busbar

Feeder


Type

C.T.

ratio

Delay

curve

type

Current

setting

Time

setting

Instantaneou

s protection

(DMT)

Time C.T.

ratio

Delay

curve

type

Current

setting

Time

settin

g

Instantaneou

s protection

(DMT)

Time

AH11: TR-2820B Feeder

100/1

DMT I > 0.5

𝐼𝑛

2 I >>1𝐼𝑛 0.3 s 50/1 DMT I > 0.2

𝐼𝑒


P123

AH12: RMU-2830B 100/

1

DMT I >

0.6𝐼𝑛

0.5 I >>0.6 𝐼𝑛

I >>>0.6 𝐼𝑛

0 s

0 s

50/1 DMT I > 0.2

𝐼𝑒

0.025 I > 0.4 𝐼𝑒 0 s Tamco

Micom P123

Table B. 9 11kV Feeders on 2nd Busbar

76 | P a g e

Feeder

Overcurrent protection [50/51] Earth protection [50N/51N] Relay Type

C.T.

ratio

Delay

curve

type

Current

setting

Time

settin

g

Instantaneou

s protection

(DMT)

Ti

me

C.T

.

ratio

Delay

curve

type

Current

setting

Time

setting

Instantaneous

protection

(DMT)

Tim

e

AH01: Spare Feeder 40/1 DMT I > 0.5𝐼𝑛 2 I >>0.65 𝐼𝑛

I >>>6.25 𝐼𝑛

0.3

s

0 s

50/

1

DMT I > 0.2

𝐼𝑒

0.2 I > 0.4 𝐼𝑒 0 s Tamco

Micom

P123

AH02: RMU-2830A 100/1

DMT I > 0.4𝐼𝑛 0.2 I >>0.5 𝐼𝑛

I >>>0.6 𝐼𝑛

0s

0 s

50/1

DMT I > 0.1

𝐼𝑒

0.05 I > 0.2 𝐼𝑒 0 s Tamco

Micom P123

AH03: Spare Feeder

40/1 DMT I > 0.5𝐼𝑛 2 I >>0.65 𝐼𝑛

I >>>6.25 𝐼𝑛

0.3s

0 s

50/1

DMT I > 0.2

𝐼𝑒

0.2 I > 0.4 𝐼𝑒 0 s Tamco

Micom P123

AH04: TR-2820A

Feeder

100/

1

DMT I >

0.5 𝐼𝑛

2 I >>1 𝐼𝑛 0.3

s

50/

1

DMT I > 0.2

𝐼𝑒

0.2 I >> 0.4 𝐼𝑒 0 s Tamco

Micom

P123

Table B. 10 11kv Incomers


Type

C.T.

ratio

Delay

curve

type

Current

setting

Time

setting

Instantaneous

protection

(DMT)

Time C.T.

ratio

Delay

curve

type

Current

setting

Time

setting

Instantaneous

protection

(DMT)

Time

AH06:

1#

Incomer

150/1 Disabled 150/1 Disabled Tamco

Micom

P121

AH09:

2#

Incomer


Micom

P121

77 | P a g e

Table B. 11 11kV Bus-section & 11kV two incomers Directional Protection [the directional Element is disabled =

non-directional]


Type

C.T.

ratio

Delay

curve

type

Current

setting

Time

setting

Instantaneous

protection

(DMT)

Time C.T.

ratio

Delay

curve

type

Current

setting

Time

setting

Instantaneous

protection

(DMT)

Time

AH06:

1#

Incomer

150/1 DMT I

>0.9𝐼𝑛


1.0 𝐼𝑒

0.1 Disabled Tamco

P127

AH09:

2#

Incomer

150/1 DMT I

>0.9 𝐼𝑛


1.0𝐼𝑒

0.1 Disabled Tamco

P127

CH08:

Bus

section

150/1 DMT I >0.7

𝐼𝑛

0.05 Disabled 1/1 Disabled Tamco

P127

Table B.‎712 33 kV Transformer Feeders

78 | P a g e

Transformer

feeders


Type C.T.

ratio

Delay

curve

type

Current

setting

Time

setting

Instantaneous

protection

(DMT)

Time C.T.

ratio

Delay

curve

type

Current

setting

Time

setting

Instantaneous

protection

(DMT)

Time

3#

Transformer

(TR 7801A)

75/1 DMT I >

0.6𝐼𝑛


0.4𝐼𝑒


P142

10#

Transformer

(TR 7801B)

75/1 DMT I >

0.6𝐼𝑛


0.4𝐼𝑒


P142

Table B.13 33kV Bus coupler

Bus

Coupler


Type C.T.

ratio

Delay

curve

type

Current

setting

Time

setting

Instantaneous

protection

(DMT)

Time C.T.

ratio

Delay

curve

type

Current

setting

Time

setting

Instantaneous

protection

(DMT)

Time

6# Bus

coupler

150/1 DMT I

>0.4𝐼𝑛

0.125 Disabled

150/1 Disabled Schneider

P143

79 | P a g e

Table B. 14 33kV incomers


Type

C.T.

ratio

Delay

curve

type

Current

setting

Time

setting

Instantaneous

protection

(DMT)

Time C.T.

ratio

Delay

curve

type

Current

setting

Time

setting

Instantaneous

protection

(DMT)

Time

5#

Incoming

100/1 DMT I >

0.75𝐼𝑛


1.32𝐼𝑒


P143

8#

Incoming

100/1 DMT I >

0.75𝐼𝑛


1.32𝐼𝑒


P143

Table B.15 33 kV Outgoings (to Jake Substation)


Type

C.T

.

rati

o

Del

ay

curv

e

type

Current

setting

Time

settin

g

Instantane

ous

protection

(DMT)

Ti

me

C.T.

ratio

Delay

curve

type

Current

setting

Time

setting

Instantaneous

protection

(DMT)

Time

2# JAKE 1 100

/1

DM

T

I >

0.75𝐼𝑛


1.14𝐼𝑒


P123

11# JAKE 2 100

/1

DM

T

I >

0.75 𝐼𝑛


1.14𝐼𝑒


P123

80 | P a g e

B.3 OLD SETTINGS – JAKE SUBSTATION


Busbar

Feeder


C.T.

ratio

Delay

curve

type

Current

setting

Time

setting

Instantaneous

protection

(DMT)

Time C.T.

ratio

Delay

curve

type

Current

setting

Time

setting

Instantaneous

protection

(DMT)

Time

CH01:

Spare

Feeder

(OGM2)

50/1 DMT I >0.8

𝐼𝑛

0.200 I >>1 𝐼𝑛

I >>>1.2 𝐼𝑛

0 s

0 s

50/1 DMT I > 0.1

𝐼𝑒

0.050 I>> 0.2 𝐼𝑒

I>>> 2 𝐼𝑒

0 s Tamco

Micom

P123

CH02:

Spare

Feeder

(Camp)

100/1 DMT I >

0.4𝐼𝑛

0.200 I >>0.5 𝐼𝑛

I >>>0.6 𝐼𝑛

0s

0 s

50/1 DMT I > 0.1

𝐼𝑒

0.050 I>> 0.2 𝐼𝑒

I>>> 0.2 𝐼𝑒

0 s Tamco

Micom

P123

CH03:

P-

7603C

Feeder

Water

Injection

Pump C

40/1 DMT I > 2 𝐼𝑛 2 I >>3𝐼𝑛

I >>>7𝐼𝑛

0.3 s

0 s

50/1 DMT I > 0.2

𝐼𝑒

0.500 I >> 0.4 𝐼𝑒 0 s Tamco

Micom

P123

CH04:

P-

7603B

Feeder

Water

Injection

Pump B

40/1 DMT I > 2𝐼𝑛 2 I >>3𝐼𝑛

I >>>7 𝐼𝑛

0.3 s

0

s

50/1 DMT I > 0.2

𝐼𝑒

0.500 I > 0.4 𝐼𝑒 0 s Tamco

MicomP123

CH05:

TR-

7802A

100/1 DMT I > 0.8

𝐼𝑛

0.025 I >>1.3𝐼𝑛

I >>>3𝐼𝑛

0.1 s

0 s

50/1 DMT I > 0.2

𝐼𝑒

0.025 I > 0.4 𝐼𝑒 0 s Tamco

Micom

P123

81 | P a g e

Table B.17 11kV Feeders on 2nd

Busbar

Feeder


Type

C.T

.

rati

o

Dela

y

curve

type

Curren

t

setting

Tim

e

setti

ng

Instantane

ous

protection

(DMT)

Tim

e

C.T

.

rati

o

Dela

y

curve

type

Curre

nt

setting

Tim

e

setti

ng

Instantane

ous

protection

(DMT)

Tim

e

CH12: TR-

7802B

100

/1

DMT I > 0.8

𝐼𝑛

0.02

5 I >>1.3 𝐼𝑛

I >>>3 𝐼𝑛

0.1 s

0 s

50/

1

DMT I > 0.2

𝐼𝑒

0.02

5 I > 0.4 𝐼𝑒 0 s Tamco

Micom

P123

CH13: P-7603A

Feeder Water

Injection Pump

A

40/

1

DMT I > 2𝐼𝑛 2 I >>3 𝐼𝑛

I >>>7 𝐼𝑛

0.3s

0 s

50/

1

DMT I > 0.2

𝐼𝑒

0.50

0 I >> 0.4 𝐼𝑒 0 s Tamco

Micom

P123

CH14: Spare

Feeder

40/

1

DMT I >

1.2𝐼𝑛

0.02

5 I >>3 𝐼𝑛

I >>>5 𝐼𝑛

0.1 s

0 s

50/

1

DMT I >

0.2𝐼𝑒

0.02


Micom

P123

CH15: Spare

Feeder

40/

1

DMT I >

1.2𝐼𝑛

0.02

5 I >>3 𝐼𝑛

I >>>5 𝐼𝑛

0.1 s

0 s

50/

1

DMT I >

0.2𝐼𝑒

0.02


Micom

P123

CH16: Spare

Feeder

40/

1

DMT I >

1.2𝐼𝑛

0.02

5 I >>3 𝐼𝑛

I >>>5 𝐼𝑛

0.1 s

0 s

50/

1

DMT I >

0.2𝐼𝑒

0.02


Micom

P123

CH17: Spare

Feeder

(OGM1)

40/

1

DMT I >

0.8𝐼𝑛

0.02

5 I >>2 𝐼𝑛

I >>>3 𝐼𝑛

0.1 s

0 s

50/

1

DMT I > 0.1

𝐼𝑒

0.05

0 I >> 0.2 𝐼𝑒

I >>>

0.2 𝐼𝑒

0 s Tamco

Micom

P123

82 | P a g e


Type

C.T.

ratio

Delay

curve

type

Current

setting

Time

setting

Instantaneous

protection

(DMT)

Time C.T.

ratio

Delay

curve

type

Current

setting

Time

setting

Instantaneous

protection

(DMT)

Time

CH07:

1#

Incomer


Micom

P121

CH07:

2#

Incomer


Micom

P121


Table B. 19 33kV Transformer Feeders

Transformer

feeders


Type C.T.

ratio

Delay

curve

type

Current

setting

Time

setting

Instantaneous

protection

(DMT)

Time C.T.

ratio

Delay

curve

type

Current

setting

Time

setting

Instantaneous

protection

(DMT)

Time

2#

Transformer

(TR 7801A)

75/1 DMT I >

0.6𝐼𝑛


0.4𝐼𝑒


P142

2#

Transformer

(TR 7801B)

75/1 DMT I >

0.6𝐼𝑛

0.1 Disabled 50/1 DMT I > 0.4

𝐼𝑒


P142

83 | P a g e


Bus

Coupler


Type C.T.

ratio

Delay

curve

type

Current

setting

Time

setting

Instantaneous

protection

(DMT)

Time C.T.

ratio

Delay

curve

type

Current

setting

Time

setting

Instantaneous

protection

(DMT)

Time

Bus

coupler

150/1 DMT I >

0.4 𝐼𝑛

0.125 Disabled 150/1 Disabled Disabled Schneider

P143



Type

C.T.

ratio

Delay

curve type

Current

setting

Time

setting

Instantaneous

protection (DMT)

Time C.T.

ratio

Delay

curve type

Current

setting

Time

setting

Instantaneous

protection (DMT)

Time

CH07: 1#

Incomer

100/1 DMT I >

0.75𝐼𝑛


1.14𝐼𝑒


P143

CH07: 2# Incomer

100/1 DMT I >

0.75𝐼𝑛

0.15 Disabled 50/1 DMT I

>1.14𝐼𝑒


84 | P a g e

Table B. 22 11 kV Bus-section & 11kV Two Incomers Directional Protection [the directional

Element is disabled = non-directional]


Type

C.T.

ratio

Delay

curve

type

Current

setting

Time

setting

Instantaneous

protection

(DMT)

Time C.T.

ratio

Delay

curve

type

Current

setting

Time

setting

Instantaneous

protection

(DMT)

Time

CH07:

1#

Incomer

150/1 DMT I

>0.9𝐼𝑛

0.075 Disabled 30/1 DMT I

>1.0𝐼𝑒

0.1 Disabled Tamco

P127

CH10:

2#

Incomer

150/1 DMT I

>0.9𝐼𝑛


1.0 𝐼𝑒

0.1 Disabled Tamco

P127

CH08:

Bus

section

200/1 DMT I

>0.5𝐼𝑛


P127

85 | P a g e

B.4 OLD SETTINGS – KEYI SUBSTATION


Busbar

Feeder


C.T.

ratio

Delay

curve

type

Current

setting

Time

setting

Instantaneous

protection

(DMT)

Time C.T.

ratio

Delay

curve

type

Current

setting

Time

setting

Instantaneous

protection

(DMT)

Time

DH01: K13

RMU

40/1 DMT I >

0.5𝐼𝑛

0.200 I >>0.9𝐼𝑛

I >>>1.2𝐼𝑛

0 s

0 s

50/1 DMT I > 0.1

𝐼𝑒

0.05 I >>0.2 𝐼𝑒 0 s

Tamco

Micom P123

DH02:

OGM1 +

CAMP + Unloading

Pumps

100/1 DMT I >

0.3𝐼𝑛

0.200 I >>0.5 𝐼𝑛

I >>>0.5 𝐼𝑛

0 s

0 s

50/1 DMT I > 0.1

𝐼𝑒

0 I >>0.2 𝐼𝑒

0 s Tamco

Micom

P123

DH03: P-

6603C Feeder

Water

injection

Pump C

40/1 DMT I >

1.2𝐼𝑛

0.200 I >>2.1 𝐼𝑛

I >>>3 𝐼𝑛

0.1 s

0 s

50/1 IDMT

SI

I > 0.2

𝐼𝑒

0.500 I >> 0.4 𝐼𝑒 0 s Tamco

Micom P123

DH04: P-

7603B Feeder

Water

injection Pump B

40/1 DMT I >1.2

𝐼𝑛

0.200 I >>2.1 𝐼𝑛

I >>>3 𝐼𝑛

0 s

0 s

50/1 DMT I > 0.2

𝐼𝑒

0.500 I >> 0.4 𝐼𝑒

0 s Tamco

Micom P123

DH05: TR-7802A

100/1 DMT I >

0.5 𝐼𝑛

0.200 I>>0.79 𝐼𝑛

I>>>4.49 𝐼𝑛

0.3 s

0 s

50/1 DMT I >

0.2 𝐼𝑒

0.500 I >> 0.4 𝐼𝑒 0 s Tamco Micom

P123

86 | P a g e


Busbar

Feeder


Type

C.T.

ratio

Dela

y

curv

e

type

Curren

t

setting

Tim

e

setti

ng

Instanta

neous

protecti

on

(DMT)

Time C

.

T

.

ra

ti

o

Dela

y

curve

type

Curren

t

setting

Tim

e

setti

ng

Instanta

neous

protectio

n

(DMT)

Tim

e

DH12: TR-6802B 100/

1

DM

T

I >

0.5𝐼𝑛

0.2 I>>0.84 𝐼𝑛

I>>>4.49 𝐼𝑛

3 s

0 s

5

0/

1

DMT I >

0.2𝐼𝑒

0.50

0

I >>

0.4 𝐼𝑒

0 s Tamco

Micom

P123

DH13: P-6603A

Feeder Water

injection Pump A

40/1 DM

T

I

>1.2𝐼𝑛

0.02

5 I>>2. 1 𝐼𝑛

I>>>3 𝐼𝑛

0.1 s

0 s

5

0/

1

DMT I > 0.2

𝐼𝑒

0.02

5

I >>

0.4 𝐼𝑒

0 s Tamco

Micom

P123

DH14: Fire Fighter

Pump

40/1 DM

T

I >

1.2 𝐼𝑛

4 I>>5 𝐼𝑛

I>>>7 𝐼𝑛

0.

3

s

5

0/

1

DMT I >

0.2 𝐼𝑒

0.50

0

I >>

0.4 𝐼𝑒

0 s Tamco

Micom

P123

DH15: OGM 2-3-

4-5

100/

1

DM

T

I

>0.3 𝐼𝑛

0.2 I>>0.5 𝐼𝑛

I>>>0.5 𝐼𝑛

0 s

0 s

5

0/

1

DMT I >

0.1 𝐼𝑒

0.05 I >>

0.2 𝐼𝑒

0 s Tamco

Micom

P123

DH16: Spare

Feeder (Perkins)

40/1 DM

T

I

>1.24

𝐼𝑛

0.02

5 I>>2 𝐼𝑛

I>>>3 𝐼𝑛

0.1 s

0 s

5

0/

1

DMT I >

0.2𝐼𝑒

0.02

5

I >

0.4 𝐼𝑒

0 s Tamco

Micom

P123

87 | P a g e


Type

C.T.

rati

o

Delay

curve

type

Curre

nt

settin

g

Tim

e

setti

ng

Instantaneo

us

protection

(DMT)

Tim

e

C.T.

rati

o

Delay

curve

type

Current

setting

Tim

e

setti

ng

Instantaneous

protection

(DMT)

Time

DH07: 1#

Incomer

150/

1

DMT I>1.0

0𝐼𝑛

2 I>>2. 𝐼𝑛

I>>>3.5 𝐼𝑛

600

ms

0

ms

150/

1

DMT I >

0.15 𝐼𝑒

1.15 I >> 0.2 𝐼𝑒

0.6 s

Tamco

Micom

P121

DH11: 2#

Incomer

150/

1

DMT I>1.0

0𝐼𝑛

2 I>>2. 𝐼𝑛

I>>>3.5 𝐼𝑛

600

ms

0

ms

150/

1

DMT I >

0.15 𝐼𝑒

1.15 I >> 0.2 𝐼𝑒

0.6 s

Tamco

Micom

P121


Table B. 26 33kV Transformer Feeders

Transformer

feeders


Type C.T.

ratio

Delay

curve

type

Current

setting

Time

setting

Instantaneous

protection

(DMT)

Time C.T.

ratio

Delay

curve

type

Current

setting

Time

setting

Instantaneous

protection

(DMT)

Time

2#

Transformer

(TR-6801A)

75/1 DMT I >

0.6 𝐼𝑛


0.3 𝐼𝑒


P142

9#

Transformer

(TR-6801B)

75/1 DMT I >

0.6𝐼𝑛


0.3 𝐼𝑒


P142

88 | P a g e


Bus

Coupler


Type C.T.

ratio

Delay

curve

type

Current

setting

Time

setting

Instantaneous

protection

(DMT)

Time C.T.

ratio

Delay

curve

type

Current

setting

Time

setting

Instantaneous

protection

(DMT)

Time

6# Bus

coupler

150/1 DMT I

>0.4𝐼𝑛


0.1 𝐼𝑒

0.02 s Disabled Schneider

P143



Type

C.T.

ratio

Delay

curve

type

Curren

t

setting

Time

settin

g

Instantane

ous

protection

(DMT)

Tim

e

C.T.

ratio

Delay

curve

type

Curren

t

setting

Time

setting

Instantaneous

protection

(DMT)

Time

4# Incoming

1

150/

1

DMT I >

0.5𝐼𝑛


0.9𝐼𝑒


P143

7# Incoming

2

150/

1

DMT I >

0.5 𝐼𝑛


0.9𝐼𝑒


P143

89 | P a g e


Type

C.T.

ratio

Dela

y

curv

e

type

Curren

t

setting

Tim

e

setti

ng

Instantane

ous

protection

(DMT)

Tim

e

C.T.

ratio

Delay

curve

type

Current

setting

Time

setting

Instantaneous

protection

(DMT)

Time

DH07: 1#

Incomer

150/

1

Disabled

Tamco

P127

DH10: 2#

Incomer

150/

1

Disabled

Tamco

P127

DH08: Bus

coupler

A/B

150/

1

DM

T

I

>0.9 𝐼𝑛

0.20 Disabled

Tamco

P127

Table B. 29 11kV Bus-section & 11kV Two Incomers Directional Protection [the

directional Element is disabled = non-directional]

90 | P a g e

B.5 OLD SETTINGS – CPF SUBSTATION

Table B. 30 11kV Substation Feeders

Feeder


Type

C.T.

ratio

Delay

curve

type

Current

setting

Tim

e

setti

ng

Instantaneou

s protection

(DMT)

Ti

me

C.T.

ratio

Delay

curve

type

Current

setting

Time

setti

ng

Instantane

ous

protection

(DMT)

Ti

me

01: TR-1803A 100/

5

DMT I >

0.85𝐼𝑛

0.50

0 I >>2𝐼𝑛

I >>> 3.8 𝐼𝑛

0.1

s

0s

50/5 DMT I

>0.25𝐼𝑒

0.1 s I >>0.5𝐼𝑒

I >>> 1 𝐼𝑒

0.1

s

0s

Alstom

Micom

P123

04: TR-1805A 100/

5

DMT I > 1 𝐼𝑛 0.50

0 I >> 2 𝐼𝑛

I >>> 4 𝐼𝑛

0.1

s

0s

100/

5

DMT I >

0.125𝐼𝑒

0.50

0 I >>0.25𝐼𝑒

I >>> 0.5

𝐼𝑒

0.1

s

0s

Alstom

Micom

P122

10: TR-1801B 100/

5

DMT I > 1 𝐼𝑛 0.50

0 I >> 2 𝐼𝑛

I >>> 4 𝐼𝑛

0.1

s

0s

100/

5

DMT I >

0.125 𝐼𝑒

0.50

0

I

>>0.25 𝐼𝑒

I >>> 0.5

𝐼𝑒

0.1

s

0s

Alstom

Micom

P122

13: TR-1801C 100/

5

DMT I >1.5

𝐼𝑛

0.3 I >> 3 𝐼𝑛

I >>> 6 𝐼𝑛

0.1

s

0s

50/5 DMT I >.4𝐼𝑒 0.07

5 I >>0.6𝐼𝑒

I >>> 1.2

𝐼𝑒

0.1

s

0s

AREVA

MicomP

122

13: TR-1803B 100/

5

DMT I >1𝐼𝑛 0.50

0 I >> 2 𝐼𝑛

I >>> 4 𝐼𝑛

0.1

s

0s

50/5 DMT I

>0.25𝐼𝑒

0.50

0 I >>0.5𝐼𝑒

I >>> 1 𝐼𝑒

0.1

s

0s

Alstom

Micom

P123

15: Initial

substation -2

100/

5

DMT I > 3𝐼𝑛 0.510 I >> 6 𝐼𝑛

I >>> NO

0.1

s

0s

50/5

DMT

I

>0.67

𝐼𝑒

0.075 I>>1.3

𝐼𝑒

I >>>

NO

0.1s

Alstom

Micom

P122

16: RMU-2 200/ DMT I > 0.8 1.00 I >> 1.25 𝐼𝑛 0.3 200/ DMT I > 0.30 I >>0.2𝐼𝑒 0.1 Alstom

Micom

91 | P a g e

5 𝐼𝑛 I >>> 2 𝐼𝑛 s

0s

5 0.1𝐼𝑒 0 I >>> 0.3

𝐼𝑒

s

0s

P123

18: FULA

CENTRE -1-1

& 1-2

200/

5

DMT

I > 0.8

𝐼𝑛

2.00 I >> 1.25 𝐼𝑛

I >>>2 𝐼𝑛

0.1

s

0.1

s

50/5 DMT I > 0.25

𝐼𝑒

0.30

0 I >> 0.4𝐼𝑒

I

>>>0.8𝐼𝑒

0.1

s

0s

Alstom

Micom

P123

19: RMU-1 200/

5

DMT I > 0.8

𝐼𝑛

1.00 I >> 1.25 𝐼𝑛

I >>> 2 𝐼𝑛

0.3

s

0s

200/

5

DMT I >

0.1𝐼𝑒

0.30

0 I >>0.2 𝐼𝑒

I >>> 0. 𝐼𝑒

0.1

s

0s

Alstom

Micom

P123

19: TR-1801E 100/

5

DMT I > 0.8

𝐼𝑛

0.07

5 I >> 2 𝐼𝑛

I >>>4 In

I >>> 4 𝐼𝑛

0.1

s

0s

50/5 DMT I > 0.25

𝐼𝑒

0.07

5 I >>0.5𝐼𝑒

I >>> 1 𝐼𝑒

0.1

s

0s

AREVA

MicomP

122

15: Initial

substation -2

The relay is not working and the switchgear is OFF

TR-1801F 100/

1

DMT I > 0.8

𝐼𝑛

0.07

5 I >> 2 𝐼𝑛

I >>> 4 𝐼𝑛

0.1

s

0s

50/1 DMT I >

0.25𝐼𝑒

0.07

5 I >>0.5𝐼𝑒

I >>> 1 𝐼𝑒

0.1

s

0s

AREVA

Micom

P122

TR-1801D 100/

1

DMT I > 1.5

𝐼𝑛

0.3 I >> 3 𝐼𝑛

I >>> 6 𝐼𝑛

0.1

s

0s

50/1 DMT I > 0.4 𝐼𝑒 0.07

5 I >>0.6𝐼𝑒

I >>> 1.2

𝐼𝑒

0.1

s

0s

AREVA

Micom

P122

92 | P a g e

Table B. 31 11Kv Substation New Added Feeders

Feeder


Type

C.T

.

rati

o

Del

ay

cur

ve

type

Current

setting

Tim

e

setti

ng

Instantaneo

us

protection

(DMT)

Ti

me

C.T.

rati

o

Dela

y

curv

e

type

Current

setting

Tim

e

setti

ng

Instantane

ous

protection

(DMT)

Ti

me

01: Spare Feeder 200

/1

DM

T

I

>0.73

𝐼𝑛

0.07

5 I >>1.5𝐼𝑛

0.1

s

50/1 DM

T

I >0.25

𝐼𝑒

0.07

5 I >>0.8𝐼𝑒 0.1

s

Tamco

Micom

P141


/1

DM

T

I > 0.73

𝐼𝑛

0.07

5 I >> 1.2 𝐼𝑛

I >>> 7.4 𝐼𝑛

0.1

s

0.1

s

50/1 DM

T

I > 0.25

𝐼𝑒

0.07

5 I >> 0.5 𝐼𝑒 0.1

s

Tamco

Micom

P142

04: TR-1807A

(AGR)

150

/1

DM

T

I >0.65

𝐼𝑛

0.07

5 I >>2𝐼𝑛

0.1

s

50/1 DM

T

I > 0.25

𝐼𝑒

0.07

5 I >>0.5 𝐼𝑒 0.1

s

Tamco

Micom

P142


/1

DM

T

I > 0.73

𝐼𝑛

0.07

5 I >> 1 𝐼𝑛

0.1

s

50/1 DM

T

I > 0.25

𝐼𝑒

0.07

5 I >> 0.5 𝐼𝑒 0.1

s

Tamco

Micom

P142

06: WIP Pump

1605A

75/

1

DM

T

I

>2.5𝐼𝑛

0.07

5 I >>4𝐼𝑛

0.1

s

50/1 DM

T

I >0.25

𝐼𝑒

0.07

5 I >>0.5 𝐼𝑒 0.1

s

Tamco

Micom

P142

07: WIP Pump

1605B

75/

1

DM

T

I

>2.5𝐼𝑛

0.07

5 I >>4𝐼𝑛

0.1

s

50/1 DM

T

I >0.25

𝐼𝑒

0.07

5

I >> 0.5 𝐼𝑒 0.1

s

Tamco

Micom

P142


/1

DM

T

I > 0.5

𝐼𝑛

0.07

5 I >>1 𝐼𝑛

0.1

s

50/1 DM

T

I > 0.25

𝐼𝑒

0.07

5 I >> 0.5 𝐼𝑒 0 s Tamco

Micom

P141

09: Spare Feeder

(PSI-2 Incoming

Line)

400

/1

DM

T

I >1.25

𝐼𝑛

0.07

5 I >> 1.4 𝐼𝑛

I >>> 1.6 𝐼𝑛

0.1

s

0s

50/1 DM

T

I > 0.25

𝐼𝑒

0.07

5

I >> 0.5 𝐼𝑒 0 s Tamco

Micom

P142


/1

DM

T

I > 0.73

𝐼𝑛

0.07

5 I >> 1.5𝐼𝑛

0.1

s

50/1 DM

T

I > 0.25

𝐼𝑒

0.07

5 I >> 0.5 𝐼𝑒 0 s Tamco

Micom

P142

93 | P a g e


/1

DM

T

I > 0.73

𝐼𝑛

0.07

5 I >> 1 𝐼𝑛 50/1 DM

T

I > 0.25

𝐼𝑒

0.07

5 I >> 0.5 𝐼𝑒 0.1

s

Tamco

Micom

P141

19: TR-1807B 150

/1

DM

T

I > 0.65

𝐼𝑛

0.07

5 I >> 2 𝐼𝑛

0.1

s

50/1 DM

T

I > 0.25

𝐼𝑒

0.07

5 I >>0.5 𝐼𝑒 0.1

s

Tamco

Micom

P142


/1

DM

T

I > 0.73

𝐼𝑛

0.07

5 I >> 1.08𝐼𝑛

0.1

s

50/1 DM

T

I > 0.25

𝐼𝑒

0.07

5 I >> 0.5 𝐼𝑒 0 s Tamco

Micom

P142


/1

DM

T

I > 0.73

𝐼𝑛

0.07

5 I >> 1.5𝐼𝑛

0.1

s

50/1 DM

T

I > 0.25

𝐼𝑒

0.07

5 I >> 0.5 𝐼𝑒 0s Tamco

Micom

P141

22: WIP Pump

1605C

75/

1

DM

T

I

>2.5𝐼𝑛

0.07

5 I >> 4𝐼𝑛

0.1

s

50/1 DM

T

I >0.25

𝐼𝑒

0.07

5 I >> 0.5 𝐼𝑒 0.1

s

Tamco

Micom

P142


/1

DM

T

I > 0.73

𝐼𝑛

0.07

5 I >> 1.08𝐼𝑛

0.1

s

50/1 DM

T

I > 0.25

𝐼𝑒

0.07

5

I >> 0.5 𝐼𝑒 0.1

s

Tamco

Micom

P142

24: Spare Feeder

(PSI-1 Incoming

Line)

400

/1

DM

T

I > 1.25

𝐼𝑛

0.07

5 I >> 1.4 𝐼𝑛

I >>> 1.6 𝐼𝑛

0.1

s

0s

50/1 DM

T

I > 0.25

𝐼𝑒

0.07

5 I >> 0.5 𝐼𝑒 0.1

s

Tamco

Micom

P142

94 | P a g e

Table B. 32 11 kV Bus-section & 11 kV Transformer feeders


Type

C.T.

ratio

Delay

curve

type

Current

setting

Time

setting

Instantaneous

protection

(DMT)

Time C.T.

ratio

Delay

curve

type

Current

setting

Time

setting

Instantaneous

protection

(DMT)

Time

03:

Transformer

(TR-1806A)

800/1 DMT I >

0.66𝐼𝑛

0.275 Disabled 50/1 DMT I >1 𝐼𝑒 0.025 Disabled Tamco

Micom

P142

18:

Transformer

(TR-1806A)

800/1 DMT I >

0.66𝐼𝑛

0.275 Disabled 50/1 DMT I > 1 𝐼𝑒 0.025 Disabled Tamco

Micom

P142

DH08: Bus

section

1500/1 DMT I >

0.36𝐼𝑛


Micom

P143

Table B. 33 33 kV Transformer

Feeders

Transformer

feeders


Type

C.T.

ratio

Delay

curve

type

Current

setting

Time

setting

Instantaneous

protection

(DMT)

Time C.T.

ratio

Delay

curve

type

Current

setting

Time

setting

Instantaneous

protection

(DMT)

Time

H8: Transformer

(TR-1806A)

250/1 Disabled 75/1 Disabled AREVA

P121

250/1 DMT I

>0.7𝐼𝑛


0.31𝐼𝑒

0.275 Disabled AREVA

P142

H11:Transformer

( TR-1806B )


P121

250/1 DMT I

>0.7 𝐼𝑛

0.25 Disabled 250/1 DMT I > 0.31

𝐼𝑒


P142

95 | P a g e

Table B. 34 11 kV Bus-section & 11 kV Transformer

feeders


Type

C.T.

ratio

Delay

curve

type

Current

setting

Time

setting

Instantaneous

protection

(DMT)

Time C.T.

ratio

Delay

curve

type

Current

setting

Time

setting

Instantaneous

protection

(DMT)

Time

03:

Transformer

(TR-1806A)

800/1 DMT I >

0.66𝐼𝑛

0.275 Disabled 50/1 DMT I >1 𝐼𝑒 0.025 Disabled Tamco

Micom

P142

18:

Transformer

(TR-1806A)

800/1 DMT I >

0.66𝐼𝑛

0.275 Disabled 50/1 DMT I > 1 𝐼𝑒 0.025 Disabled Tamco

Micom

P142

DH08: Bus

section

1500/1 DMT I >

0.36𝐼𝑛


Micom

P143

Table B. 35 33 kV Transformer

Feeders

Transformer

feeders


Type

C.T.

ratio

Delay

curve

type

Current

setting

Time

setting

Instantaneous

protection

(DMT)

Time C.T.

ratio

Delay

curve

type

Current

setting

Time

setting

Instantaneous

protection

(DMT)

Time

H8: Transformer

(TR-1806A)


P121

250/1 DMT I

>0.7𝐼𝑛


0.31𝐼𝑒


P142

H11:Transformer

( TR-1806B )


P121

250/1 DMT I

>0.7 𝐼𝑛

0.25 Disabled 250/1 DMT I > 0.31

𝐼𝑒


P142

96 | P a g e

Table B. 36 33kVBustie

Item Overcurrent protection [50/51] Earth protection [50N/51N] Relay

Type C.T.

ratio

Delay

curve

type

Current

setting

Time

setting

Instantaneous

protection

(DMT)

Time C.T.

ratio

Delay

curve

type

Current

setting

Time

setting

Instantaneous

protection

(DMT)

Time

H9:

Bus

coupler

200/1 DMT I >

0.85𝐼𝑛

0.225 Disabled 200/1 Disabled Disabled AREVA

P143

Table B. 37 33 kV outgoings


Type

C.T.

ratio

Dela

y

curve

type

Current

setting

Tim

e

setti

ng

Instantane

ous

protection

(DMT)

Tim

e

C.T.

ratio

Delay

curve

type

Current

setting

Time

settin

g

Instantaneous

protection

(DMT)

Time

H1: FNE 1 150/

1

DMT I >

0.5𝐼𝑛

0.17

5 I >> 4𝐼𝑛 0 s 50/1 DMT I >

1.14𝐼𝑒

0.175 Disabled Areva

P123

H3: KEYI 1 100/

1

DMT I > 0.75

𝐼𝑛

0.17

5 I >> 4𝐼𝑛 0 s 50/1 DMT I > 0.2𝐼𝑒 0.1 I > 0.25𝐼𝑒 0 s Areva

P123

H5: MOGA

1

150/

1

DMT I > 0.5

𝐼𝑛

0.22

5 I >> 4𝐼𝑛 0 s 50/1 DMT I >

1.32𝐼𝑒


P123

H15: KEYI

2

100/

1

DMT I > 0.75

𝐼𝑛

0.17

5 I >> 4𝐼𝑛 0 s 50/1 DMT I > 0.2𝐼𝑒 0.1 I > 0.25𝐼𝑒 0 s Areva

P123

H13:

MOGA 2

150/

1

DMT I > 0.5

𝐼𝑛

0.22

5 I >> 4𝐼𝑛 0 s 50/1 DMT I >

1.32𝐼𝑒


P123

H17: FNE 2 150/

1

DMT I > 0.5

𝐼𝑛

0.17

5 I >> 4𝐼𝑛 0 s 50/1 DMT I >

1.14𝐼𝑒


P123

97 | P a g e

8 Appendix C

9 NEW SETTING

C.1 NEW RELAY COORDINATION SETTINGS – FNE

SUBSTATION

Feeder


Type

C.T.

ratio

Delay

curve

type

Current

setting

Time

setting

Instantaneous

protection

(DMT)

Time C.T.

ratio

Delay

curve

type

Current

setting

Time

setting

Instantaneous

protection

(DMT)

Time

BH01: Spare Feeder 40/1 IDMT

SI

Disabled 50/1 IDMT

SI

Disabled Tamco

Micom

P123


SI

Disabled 50/1 IDMT

SI

Disabled Tamco

Micom

P123


SI

Disabled 50/1 IDMT

SI

Disabled Tamco

Micom

P123

BH04: 1# RMUFeeder

150/1 IDMT SI

I >0.5𝐼𝑛 0.025 I >>1𝐼𝑛

0s

50/1 IDMT SI

I > 0.1

𝐼𝑒

0.025 I >> 0.2 𝐼𝑒 0s Tamco

Micom

P123

BH05: TR-8802A 100/1 IDMT

SI

I > 0.2

𝐼𝑛

0.025 I >>0.5𝐼𝑛

0s

50/1 IDMT

SI

I >

0.4𝐼𝑒

0.025 I >>0.8𝐼𝑒 0s Tamco

Micom

P123

Table C.1 11kV FEEDERS on 1st Busbar

98 | P a g e

Feeder


C.T.

ratio

Dela

y curv

e

type

Current

setting

Time

setting

Instantaneous

protection (DMT)

Time C.T.

ratio

Delay

curve type

Current

setting

Time

setting

Instantaneou

s protection (DMT)

Tim

e

BH12: TR-8802B 100/1

IDMT SI

I > 2.5

𝐼𝑛

0.025 I >> 5 𝐼𝑛 0s 50/1 IDMT SI

I >

0.35𝐼𝑒

0.025 I >>0.7𝐼𝑒 0s Tamco Micom

P123

BH13: Spare Feeder 100/

1

IDM

TSI

Disabled 50/1 IDM

T SI

Disabled Tamco

Micom P123

BH14: Spare Feeder 40/1 IDM SI

Disabled 50/1 IDMT SI

Disabled Tamco Micom

P123

BH15: 1# RMU

Feeder

150/

1

IDM

TSI

Disabled 50/1 IDM

T SI

Disabled Tamco

Micom

P123

BH16: Spare Feeder 100/

1

IDM

TSI

Disabled 50/1 IDM

T SI

Disabled Tamco

Micom

P123

Table C.2 11kV FEEDERS on 2nd

Busbar


Type

C.T. ratio

Delay curve

type

Current setting

Time setting


(DMT)

Time C.T. ratio

Delay curve

type

Current setting

Time setting


(DMT)

Time

BH07: 1# Incomer

200/1 IDMT SI

I >

1.65𝐼𝑛

0.075 Disabled 200/1 IDMT SI

I > 0.3𝐼𝑒 0.15 Disabled Tamco Micom

P121

BH10: 2#

Incomer

200/1 IDMT

SI

I >

1.65𝐼𝑛

0.075 Disabled 200/1 IDMT

SI I > 0.3𝐼𝑒 0.15 Disabled Tamco

Micom P121

Table C.3 11kV incomers

99 | P a g e

Table C.4 33kV Transformer Feeders

Transformer

feeders


C.T. ratio

Delay curve

type

Current setting

Time setting


(DMT)

Time C.T. ratio

Delay curve

type

Current setting

Time setting


(DMT)

Time

2# TR-A 75/1 IDMT

SI

I >

1.6𝐼𝑛

0.075 I >> 9 𝐼𝑛 0s 50/1 IDMT

SI

I >

0.35𝐼𝑒

0.025 I >> 1.05𝐼𝑛 0 Schneider

P142

9# TR-B 75/1 IDMT

SI

I >

1.6𝐼𝑛

0.075 I >> 9 𝐼𝑛 0s 50/1 IDMT

SI

I >

0.35𝐼𝑒

0.075 I >> 1.05𝐼𝑛 0 Schneider

P142

Table C.5 33kV Bus coupler

Bus Coupler Overcurrent protection [50/51] Earth protection [50N/51N] Relay Type

C.T. ratio

Delay curve

type

Current setting

Time setting


(DMT)

Time C.T. ratio

Delay curve

type

Current setting

Time setting


(DMT)

Time

6# Bus

coupler

150/1 IDMT

SI

I >

0.95𝐼𝑛


SI

I >

0.15𝐼𝑛


P143



Type C.T. ratio

Delay curve

type

Current setting

Time setting


(DMT)

Time C.T. ratio

Delay curve

type

Current setting

Time setting


(DMT)

Time

4# Incoming

1

150/1 IDMT

SI I >1 𝐼𝑛 0.15 Disabled 50/1 IDMT

SI

I >

0.5𝐼𝑒


P143

7# Incoming

2

150/1 IDMT

SI I >1 𝐼𝑛 0.15 Disabled 50/1 IDMT

SI

I >

0.5𝐼𝑒


P143

100 | P a g e

Table C.7 11kV Bus-section & 11kV two incomers Directional Protection


Type C.T.

ratio

Delay

curve

type

Current

setting

Time

setting

Instantaneous

protection

(DMT)

Time C.T.

ratio

Delay

curve

type

Current

setting

Time

setting

Instantaneous

protection

(DMT)

Time

BH07:

1#

Incomer

200/1 IDMT SI


Disabled Tamco

P127

BH10:

2#

Incomer

200/1 IDMT

SI

Disabled 40/1 IDMT

SI

Disabled Tamco

P127

BH08:

Bus

section

200/1 IDMT SI

I > 1.25

𝐼𝑛

0.05 Disabled 200/1 IDMT SI

I >

0.25𝐼𝑒

0.075 Disabled Tamco

P127

101 | P a g e

C.2 NEW RELAY COORDINATION SETTINGS – JAKE

SUBSTATION

Feeder


C.T.

ratio

Delay

curve

type

Current

setting

Time

setting

Instantaneous

protection

(DMT)

Time C.T.

ratio

Delay

curve

type

Current

setting

Time

setting

Instantaneous

protection

(DMT)

Time

CH01:

Spare Feeder

(OGM2)

40/1 IDMT

SI I >2.3𝐼𝑛 0.025 I >> 4 𝐼𝑛

0s

50/1 IDMT

SI

I > 0.2

𝐼𝑒

0.025 I >> 0.4 𝐼𝑒 0s Tamco

Micom P123

CH02:

Spare

Feeder (Camp)

100/1 IDMT

SI

I > 0.5

𝐼𝑛

0.025 I >> 1 𝐼𝑛 0s

50/1 IDMT

SI

I > 0.2

𝐼𝑒

0.025 I >> 0.4 𝐼𝑒 0s Tamco

Micom

P123

CH03: P-

7603C

Feeder

(Water Injection

Pump C)

40/1 IDMT

SI

I > 3.3

𝐼𝑛

0.025 I >> 5 𝐼𝑛

0s

50/1 IDMT

SI

I > 0.16

𝐼𝑒

0.025 I >> 0.32 𝐼𝑒 0s Tamco

Micom

P123

CH04: P-

7603B Feeder

(Water

Injection

Pump B)

40/1 IDMT

SI

50/1 IDMT

SI

Tamco

Micom P123

Table C. 8 11kV FEEDERS on 1st Busbar

102 | P a g e

Table C. 9 11kV FEEDERS on 2nd Busbar

Feeder


Type

C.T.

ratio

Dela

y curv

e

type

Current

setting

Time

setting

Instantaneous

protection (DMT)

Time C.T.

ratio

Delay

curve type

Current

setting

Time

setting

Instantaneou

s protection (DMT)

Time

CH05: TR-7802B 100/1

IDMT SI

I > 1 𝐼𝑛 0.025 I >> 2 𝐼𝑛 0s 0s

50/1 IDMT SI

I > 0.2

𝐼𝑒

Tamco

Micom

P123

CH04: P-7603A

Feeder (Water Injection Pump A)

CH14: Spare Feeder 40/1 IDM SI

I > 1.24

𝐼𝑛

0.025 I >> 20.21 𝐼𝑛 I

>>> 34.2 𝐼𝑛

0s 0s

50/1 IDMT SI

I > 0.8

𝐼𝑒

0.025 I >> 0.16 𝐼𝑒 0s Tamco

Micom

P123

CH15: Spare Feeder 40/1 IDMTSI

I > 1.24

𝐼𝑛

0.025 I >> 20.21 𝐼𝑛 I

>>> 34.2 𝐼𝑛

0s

0s

50/1 IDMT SI

I > 0.8

𝐼𝑒

0.025 I >> 0.16 𝐼𝑒 0s Tamco

Micom

P123

CH16: Spare Feeder 40/1 IDMTSI

I > 1.24

𝐼𝑛

0.025 I >> 20.21 𝐼𝑛

I >>> 34.2 𝐼𝑛

0s

0s

50/1 IDMT SI

I > 0.8

𝐼𝑒

0.025 I >> 0.16 𝐼𝑒 0s Tamco

Micom

P123

CH17: Spare Feeder

(OGM1)

40/1 IDM

T SI I >1.6𝐼𝑛 0.025 I >> 2.5 𝐼𝑛

0s

50/1 IDM

T SI I > 𝐼𝑒 0.025 I >> 0.4 𝐼𝑒 0s Tamco

Micom

P123

103 | P a g e



Type C.T.

ratio

Delay

curve

type

Current

setting

Time

setting

Instantaneous

protection

(DMT)

Time C.T.

ratio

Delay

curve

type

Current

setting

Time

setting

Instantaneous

protection

(DMT)

Time

CH07: 1#

Incomer

150/1 IDMT SI

I > 1 𝐼𝑛 0.1 Disabled 150/1 IDMT SI

I >

0.17𝐼𝑒

0.05 Disabled

Micom

P121

CH07: 2#

Incomer

150/1 IDMT SI

I > 1 𝐼𝑛 0.1 Disabled 150/1 IDMT SI

I >

0.17𝐼𝑒

0.05 Disabled Tamco

Micom

P121


Transformer

feeders


Type

C.T.

ratio

Delay

curve

type

Current

setting

Time

setting

Instantaneous

protection

(DMT)

Time C.T.

ratio

Delay

curve

type

Current

setting

Time

setting

Instantaneous

protection

(DMT)

Time

2#

Transformer

(TR 7801A)

75/1 IDMT

SI

I >

0.8𝐼𝑛

0.8 s I >> 8𝐼𝑛 0s 50/1 IDMT

SI

I > 0.2

𝐼𝑒

0.075 I >> 0.4 𝐼𝑒

0.05s Schneider

P142

2#

Transformer

(TR 7801B)

75/1 IDMT

SI

I >

0.8𝐼𝑛

0.8 s I >> 8 𝐼𝑛 0s 50/1 IDMT

SI

I > 0.2

𝐼𝑒

0.075 I >> 0.4 𝐼𝑒 0.05s Schneider

P142

104 | P a g e

Table C. 12 33kV Bus coupler

Bus

Coupler


Type

C.T.

ratio

Delay

curve

type

Current

setting

Time

setting

Instantaneous

protection

(DMT)

Time C.T.

ratio

Delay

curve

type

Current

setting

Time

setting

Instantaneous

protection

(DMT)

Time

Bus

coupler

150/1 IDMT

SI

I > 0.4

𝐼𝑛

0.15 Disabled Disabled Disabled Schneider

P143

Table C. 13 33kV Incomers


Type

C.T. ratio

Delay curve

type

Current setting

Time setting


(DMT)

Time C.T. ratio

Delay curve

type

Current setting

Time setting


(DMT)

Time

CH07: 1#

Incomer

100/1 IDMT

SI

I > 0.75

𝐼𝑛


SI

I > 0.6

𝐼𝑒

0.125 I >>1𝐼𝑒 0.1s Schneider

P143

CH07: 2#

Incomer

100/1 IDMT

SI

I > 0.75

𝐼𝑛


SI

I > 0.6

𝐼𝑒

0.125 I >> 1 𝐼𝑒 0.1s Schneider

P143

Table C.14 11kV Bus-section & 11kV two incomers Directional Protection


Type

C.T.

ratio

Delay

curve type

Current

setting

Time

setting

Instantaneous

protection (DMT)

Time C.T.

ratio

Delay

curve type

Current

setting

Time

setting

Instantaneous

protection (DMT)

Time

CH07: 1#

Incomer

150/1 SI Disabled 30/1 IDMT

SI

I > 1.6

𝐼𝑒

0.05 Disabled Tamco

P127

105 | P a g e

C.3 NEW SETTINGS – KEYI SUBSTATION

CH10: 2#

Incomer

150/1 IDMT

SI

Disabled 30/1 IDMT

SI

I > 1.1

𝐼𝑒

0.05 Disabled Tamco

P127

CH08: Bus

section

200/1 IDMT

SI

I > 0.75

𝐼𝑛


P127

Table C. 15 11kV FEEDERS on 1st Busbar

Feeder


Type

C.T.

ratio

Delay

curve type

Current

setting

Time

setting

Instantaneous

protection (DMT)

Time C.T.

ratio

Delay

curve type

Current

setting

Time

setting

Instantaneous

protection(DMT)

Time

DH01: Spare

Feeder (RMU)

40/1 IDMT

SI

I

>4.9𝐼𝑛

0.025 I >>9.8𝐼𝑛 0s

50/1 IDMT

SI

I >

0.25 𝐼𝑒

0.025 I >> 0.5 𝐼𝑒 0s Tamco

Micom P123

DH02: Spare

Feeder (OGM1 +

CAMP +

Unloading pumps)

100/1 IDMT

SI

I >

0.1𝐼𝑛

0.025 I >> 0.5𝐼𝑛 0s

50/1 IDMT

SI

I >

0.03 𝐼𝑒

0.025 I >> 0.06 𝐼𝑒 0s Tamco

Micom P123

DH03: P-

6603C

Feeder(Water injection

Pump C)

Disabled Disabled Tamco

Micom

P123

DH04: P-

7603B

Feeder(Water injection

Pump B)

disabled disabled Tamco

Micom

P123

DH05: TR-

7802A

100/1 IDMT

SI

I >

0.6𝐼𝑛

0.025 I >>1.2𝐼𝑛 0s

50/1 IDMT

SI

I >

0.08𝐼𝑒

0.025 I >>0.16𝐼𝑒 0s Tamco

Micom P123

106 | P a g e

Table C.16 11kV FEEDERS on 2nd Busbar

Feeder


Type

C.T. ratio

Delay

curv

e type

Current setting

Time

setti

ng


(DMT)

Time

C.T. ratio

Delay curve

type

Current setting

Time settin

g


(DMT)

Time

DH12: TR-6802B 100/1 IDM

T SI I > 0.35𝐼𝑛 0.02

5 I >>0.7𝐼𝑛

0s

50/1 IDM

T SI

I >

0.05 𝐼𝑒

0.025 I >>0.1𝐼𝑒 0s Tamcos

Micom

P123

DH13: P-6603A Feeder

(Water injection Pump A)

40/1 IDM

TSI

Disabled 50/1 IDM

T SI

Disabled Tamco

Micom P123

DH14: Spare Feeder

(Fire Fighter)

40/1 IDM

SI

Disabled 50/1 IDM

T SI

Disabled Tamco

Micom

P123

DH15: Spare Feeder

(OGM)

100/1 IDM

TSI I >0.45𝐼𝑛 0.02

5 I >>0.9𝐼𝑛 0s

50/1 IDM

T SI

I >

0.1𝐼𝑒

0.025 I >> 0.2𝐼𝑒 0s Tamco

Micom

P123

DH16: Spare Feeder

(Perkins)

40/1 IDM

TSI

Disabled 50/1 IDM

T SI

Disabled Tamco

Micom

P123

Table C.17 11kV Incomers


Type

C.T. ratio

Delay curve

type

Current setting

Time setting


(DMT)

Time C.T. ratio

Delay curve

type

Current setting

Time setting


(DMT)

Time

DH07: 1#

Incomer

150/1 IDMT

SI I > 1.7𝐼𝑛 0.075 Disabled 150/1 IDMT

SI

I >

0.25𝐼𝑒


Micom P121

DH11: 2#

Incomer

150/1 IDMT


SI

I >

0.25𝐼𝑒


Micom

P121

107 | P a g e

Transformer feeders


C.T.

ratio

Delay

curve

type

Current

setting

Time

setting

Instantaneous

protection

(DMT)

Time C.T.

ratio

Delay

curve

type

Current

setting

Time

setting

Instantaneous

protection

(DMT)

Time

2#

Transformer

(TR-6801A)

75/1 IDMT

SI I > 1.2𝐼𝑛 0.075 I >>7𝐼𝑛 0s 50/1 IDMT

SI

I >

0.22𝐼𝑒

0.025 I >> 0.66𝐼𝑛 0s Schneider

P142

9#

Transformer

(TR-6801B)

75/1 IDMT

SI I > 1.2𝐼𝑛 0.075 I >>7𝐼𝑛 0s 50/1 IDMT

SI

I >

0.22𝐼𝑒

0.025 I >> 0.66𝐼𝑛 0s Schneider

P142

table C. 18 33kV Transformer Feeders

Table C. 19 33kV Bus coupler

Bus Coupler Overcurrent protection [50/51] Earth protection [50N/51N] Relay Type

C.T. ratio

Delay curve

type

Current setting

Time setting


(DMT)

Time C.T. ratio

Delay curve

type

Current setting

Time setting


(DMT)

Time

6# Bus

coupler

150/1 IDMT

SI

I >

0.7𝐼𝑛

0.1 I >> 2 𝐼𝑛 0.07s 150/1 IDMT

SI I > 0.1𝐼𝑒 0.075s Disabled Schneider

P143

Table C.20 33kV Incomers


C.T.

ratio

Delay

curve type

Current

setting

Time

setting

Instantaneous

protection (DMT)

Time C.T.

ratio

Delay

curve type

Current

setting

Time

setting

Instantaneous

protection (DMT)

Time

4# Incoming

1

150/1 IDMT

SI I >0.77𝐼𝑛 0.15 Disabled 50/1 IDMT

SI

I >

0.4𝐼𝑒

0.15 Disabled

Schneider

P143

7# Incoming 2

150/1 IDMT SI

I >0.77𝐼𝑛 0.15 Disabled 50/1 IDMT SI

I >

0.4𝐼𝑒


108 | P a g e

Table C.21 11kV Bus-section & 11 kV two incomers Directional Protection


Type

C.T.

ratio

Delay

curve type

Current

setting

Time

setting

Instantaneous

protection (DMT)

Time C.T.

ratio

Delay

curve type

Current

setting

Time

setting

Instantaneous

protection (DMT)

Time

DH07: 1#

Incomer

150/1 IDMT

SI

Disabled 40/1 IDMT

SI

Disabled Tamco

P127

DH10: 2#

Incomer

150/1 IDMT

SI

Disabled 40/1 IDMT

SI

Disabled Tamco

P127

DH08: Bus

section

150/1 IDMT


SI

I >

0.2𝐼𝑒


P127

109 | P a g e

C.4 NEW RELAY COORDINATION SETTINGS – MOGA

SUBSTATION

Feeder


Type

C.T.

ratio

Delay

curve type

Current

setting

Time

setting

Instantaneous

protection

(DMT)

Time C.T.

ratio

Delay

curve type

Current

setting

Time

setting

Instantaneous

protection

(DMT)

Time

AH01: Spare Feeder Disabled

50/1 IDMT SI

I > 0.2

𝐼𝑒

0.025 I >> 0.4 𝐼𝑒 0s Tamco Micom

P123

AH02: RMU-2830A 100/

1

IDMT

SI I > 0.7𝐼𝑛 0.025 I >>1.4𝐼𝑛

0s

50/1 IDMT

SI

I > 0.2

𝐼𝑒

0.025 I >> 0.4 𝐼𝑒 0s Tamco

Micom P123

AH03: Spare Feeder


I > 0.2

𝐼𝑒


P123

AH04: TR-2820A Feeder

disable 50/1 IDMT SI

I > 0.2

𝐼𝑒


P123

Table C.22 11kV FEEDERS on 1st Busbar

110 | P a g e

Table C.23 11kV FEEDERS on 2nd Busbar

Feeder


Type

C.T. ratio

Delay

curv

e type

Current setting

Time settin

g


(DMT)

Time C.T. ratio

Delay curve

type

Current setting

Time settin

g


(DMT)

Time

AH11: TR-2820A

Feeder

100/

1

IDM

T SI

disable 50/1 IDM

T SI

I > 0.2

𝐼𝑒

0.025 I >> 0.4 𝐼𝑒 0s Tamco

Micom

P123

AH12: RMU-2830B 100/

1

IDM

T SI

disable

50/1 IDM

T SI

I > 0.2

𝐼𝑒

0.025 I >> 0.4 𝐼𝑒 0s Tamco

Micom

P123


C.T.

ratio

Delay

curve

type

Current

setting

Time

setting

Instantaneous

protection

(DMT)

Time C.T.

ratio

Delay

curve

type

Current

setting

Time

setting

Instantaneous

protection

(DMT)

Time

AH07: 1#

Incomer

150/1 IDMT

SI

I > 1.4𝐼𝑛 0.1 Disabled 150/1 IDMT

SI

I > 0.2

𝐼𝑒

0.05 Disabled Tamco

Micom P121

AH09: 2#

Incomer

150/1 IDMT

SI

I > 1.4𝐼𝑛 0.1 Disabled 150/1 IDMT

SI

I > 0.2

𝐼𝑒

0.05 Disabled Tamco

Micom P121

Table C. 24 11kV Incomers

111 | P a g e

Table C. 25 33kV Transformer Feeders

Transformer

feeders


C.T. ratio

Delay curve

type

Current setting

Time setting


(DMT)

Time C.T. ratio

Delay curve

type

Current setting

Time setting


(DMT)

Time

3#

Transformer

75/1 IDMT

SI

I >

1.1𝐼𝑛

0.1 I >> 8 𝐼𝑛 0 s 50/1 IDMT

SI

I >

0.65𝐼𝑒

0.05 I >> 0.8𝐼𝑒 0.05s Schneider

P142

8#

Transformer

(TR 7801B)

75/1 IDMT

SI

I >

1.1𝐼𝑛

0.1 I >> 8 𝐼𝑛 0 s 50/1 IDMT

SI

I >

0.65𝐼𝑒

0.05 I >> 0.8𝐼𝑒 0.05s Schneider

P142

Table C.26 33kV Bus coupler

Bus Coupler Overcurrent protection [50/51] Earth protection [50N/51N] Relay

Type

C.T.

ratio

Delay

curve type

Current

setting

Time

setting

Instantaneous

protection (DMT)

Time C.T.

ratio

Delay

curve type

Current

setting

Time

setting

Instantaneous

protection (DMT)

Time

6# Bus

coupler

150/1 IDMT

SI

I > 0.75

𝐼𝑛

0.25 disabled Disabled Schneider

P143

112 | P a g e

Table C. 27 11kV Bus-section & 11kV two incomers Directional Protection [the directional

Element is disabled = non-directional]


Type

C.T.

ratio

Delay

curve type

Current

setting

Time

setting

Instantaneous

protection (DMT)

Time C.T.

ratio

Delay

curve type

Current

setting

Time

setting

Instantaneous

protection (DMT)

Time

AH07: 1#

Incomer

150/1 IDMT

SI

Disabled 30/1 IDMT

SI

I > 0.8

𝐼𝑒

0.05 Disabled Tamco

P127

AH09: 2# Incomer

150/1 IDMT SI


I > 0.8

𝐼𝑒

0.05 Disabled Tamco P127

CH08: Bus

section

150/1 IDMT

SI

I > 1.5

𝐼𝑛


P127

113 | P a g e

C.5 NEW RELAY COORDINATION SETTINGS – CPF

SUBSTATION

Table C.28 OLD 11kV SUBSTATIONFEEDERS

Feeder


C.T. rati

o

Delay

curv

e type

Current setting

Time settin

g


(DMT)

Time

C.T. ratio

Delay curve

type

Current setting

Time settin

g

Instantaneous

protection

(DMT)

Time

01: TR-1803A Disabled

Disabled Alstom

Micom P123

04: TR-1805A 100/

5

IDM

T SI I >1.2 𝐼𝑛 0.02

5 I >>2.4𝐼𝑛

0s

100/

5

IDM

T SI I > 0.07𝐼𝑒 0.025 I >>0.14 𝐼𝑒 0 s Alstom

Micom

P122

10: TR-1801B Disabled

Disabled Alstom

Micom P122

13: TR-1801C Disabled Disabled AREVA

Micom P122

13: TR-1803B 100/

5

IDM

T SI

I > 0.9

𝐼𝑛

0.02

5 I >>1.8𝐼𝑛

0 s

50/5 IDM

T SI I >0.1𝐼𝑒 0.025 I >>0.2 𝐼𝑒 0 s Alstom

Micom

P123

15: Initial substation -2 The relay is not working and the switchgear is OFF

16: RMU-2 200/

5

IDM

T SI I > 1 𝐼𝑛 0.02

5 I >> 2 𝐼𝑛

0s

200/

5

IDM

T SI

I > 0.06

𝐼𝑒

0.025 I >> 0.12𝐼𝑒 0 s Alstom

Micom

P123

18: FULA CENTRE 1-1

& 1-2

200/

5

IDM

T SI

I > 1.1

𝐼𝑛

0.02

5 I >> 2.2 𝐼𝑛

0 s

50/5 IDM

T SI

I > 0.25

𝐼𝑒

0.025 0 s Alstom

Micom P123

19: RMU-1 Disabled

Disabled Alstom Micom

P123

19: TR-1801E 100/5

IDMT SI

I > 2.1

𝐼𝑛

0.025

I >> 4.2 𝐼𝑛 0s 50/5 IDMT SI

I > 0.22

𝐼𝑒

0.025 I >> 0.44𝐼𝑒 0 s AREVA Micom

114 | P a g e

P122

15: Initial substation -2 Disabled

Disabled

Alstom

Micom

P123

TR-1801F 100/

1

IDM

T SI

I > 0.8

𝐼𝑛

0.02

5 I >> 1.6 𝐼𝑛

0 s

50/5 IDM

T SI I > 0.1 𝐼𝑒 0.025 I >> 0.2 𝐼𝑒 0 s AREVA

Micom

P122

TR-1801D 100/

1

IDM

T SI

I > 1.3

𝐼𝑛

0.02

5 I >> 2.6 𝐼𝑛

0 s

50/5 IDM

T SI

I > 0.15

𝐼𝑒

0.075 I >> 0.3 𝐼𝑒 0 s AREVA

Micom

P122

Table C.28 NEW 11KV SUBSTATION FEEDERS

Feeder


C.T.

rati

o

Delay

curv

e type

Current setting

Time

setti

ng


(DMT)

Time

C.T. ratio

Delay curve

type

Current setting

Time settin

g

Instantaneous

protection

(DMT)

Time

01: Spare Feeder Disabled

Disabled Tamco

Micom P123


Disabled Tamco

Micom

P142

04: TR-1807A (AGR) Disabled Disabled Tamco Micom

P142

05: Spare Feeder Disabled Disabled Tamco

Micom P142

06: WIP Pump 1605A 75/

1

IDM

T

SI

I

>1.35𝐼𝑛

0.02

5 I >>2.7𝐼𝑛

0 s

50/1 IDM

T SI I >0.12 𝐼𝑒 0.025 I >>0.24 𝐼𝑒 0 s Tamco

Micom

P142

07: WIP Pump 1605B Disabled

Disabled

Tamco

Micom P142

08: Spare Feeder Disabled Disabled Tamco

Micom P141

115 | P a g e

09: Spare Feeder

(PSI-2 Incoming Line)

400

/1

IDM

T

SI

I > 0.75

𝐼𝑛

0.02

5 I >>1.5 𝐼𝑛

0 s

50/1 IDM

T SI

I > 0.32

𝐼𝑒

0.075 I >> 0.64 𝐼𝑒 0 s Tamco

Micom

P142


Disabled Tamco

Micom P142


Disabled Tamco

Micom

P141

19: TR-1807B 150

/5

IDM

T

SI

I > 0.6

𝐼𝑛

0.02

5 I >> 1.2 𝐼𝑛

0s

100/

5

IDM

T SI I > 0.1 𝐼𝑒 0.025 I >> 0.2 𝐼𝑒 0 s Tamco

Micom

P142


Disabled Tamco

Micom P142


Disabled Tamco

Micom P141

22: WIP Pump 1605C Disabled

Disabled

Tamco

Micom

P142

23: Spare Feeder Disabled Disabled Tamco Micom

P142

24: Spare Feeder

(PSI-1 Incoming Line)

400

/1

IDM

T SI

I > 0.5

𝐼𝑛

0.02

5 I >>1 𝐼𝑛

0s

50/1 IDM

T SI

I > 0.25

𝐼𝑒

0.025 I >> 0.5 𝐼𝑒 0 s Tamco

Micom P142

116 | P a g e

Incomer Overcurrent protection [67] Earth protection [67N] Relay Type

C.T.

ratio

Delay

curve

type

Current

setting

Time

setting

Instantaneous

protection

(DMT)

Time C.T.

ratio

Delay

curve

type

Current

setting

Time

setting

Instantaneous

protection

(DMT)

Time

03: Transformer

(TR-1806A)

800/1 IDMT SI

I > 0.7𝐼𝑛 0.35 Disabled 50/1 IDMT SI

I

>3.2𝐼𝑒

0.025 I > >10𝐼𝑒 0 s Tamco Micom

P142

18:

Transformer (TR-1806A)

800/1 IDMT

SI

I > 0.7

𝐼𝑛


SI

I > 3.2

𝐼𝑒

0.025 I > >10𝐼𝑒 0 s Tamco

Micom P142

DH08: Bus

section

1500/1 IDMT

SI

I >

0.41𝐼𝑛


SI

I > 3.4

𝐼𝑒


Micom

P143

Table C.29 11kV Bus-section & 11kV Transformer feeders


Transformer

feeders


Type

C.T. ratio

Delay curve

type

Current setting

Time setting


(DMT)

Time C.T. ratio

Delay curve

type

Current setting

Time setting


(DMT)

Time

H8: Transformer

(TR-1806A)

250/1 IDMT

SI

I > 1.4

𝐼𝑛


SI

I > 0.3

𝐼𝑒

0.25 Disabled AREVA

P121

250/1 IDMT

SI

I > 1.4

𝐼𝑛


SI

I > 0.1

𝐼𝑒

0.25 Disabled AREVA

P142

H11:Transformer

( TR-1806B )

250/1 IDMT

SI

I > 1.4

𝐼𝑛


SI

I > 0.3

𝐼𝑒

0.25 Disabled AREVA

P121

250/1 IDMT

SI

I > 1.4

𝐼𝑛


SI

I > 0.1

𝐼𝑒

0.25 Disabled AREVA

P142

117 | P a g e

Table C.31 33kV outgoings


C.T.

ratio

Delay

curve

type

Current

setting

Time

setting

Instantaneous

protection

(DMT)

Time C.T.

ratio

Delay

curve

type

Current

setting

Time

setting

Instantaneous

protection

(DMT)

Time

H1: FNE 1

150/1 IDMT SI

I >1.2𝐼𝑛 0.15 I >>11.5𝐼𝑛 0 s 50/1 IDMT SI

I >

0.6𝐼𝑒

0.15 I >> 34𝐼𝑒 0 s Areva P123

H3: KEYI 1

100/1 IDMT SI

I >

1.3𝐼𝑛

0.15 I >> 14 𝐼𝑛 0 s 50/1 IDMT SI

I > 0.45

𝐼𝑒

0.15 I >> 24 𝐼𝑒 0s Areva P123

H5:

MOGA 1

150/1 IDMT

SI

I > 0.9

𝐼𝑛

0.3 I >> 11.2 𝐼𝑛 0 s 50/1 IDMT

SI I > 1 𝐼𝑒 0.3 I >> 28 𝐼𝑒 0 s Areva

P123

H15:

KEYI 2

100/1 IDMT

SI

I > 1.3

𝐼𝑛

0.15 I >>14 𝐼𝑛 0s 50/1 IDMT

SI

I > 0.45

𝐼𝑒

0.15 I >> 24 𝐼𝑒 0 s Areva

P123

H13: MOGA

2

150/1 IDMT SI

I > 0.9

𝐼𝑛

0.3 I >> 11.2𝐼𝑛 0s 50/1 IDMT SI

I > 1𝐼𝑒 0.3 I >> 28 𝐼𝑒 0 s Areva P123

H17:

FNE 2

150/1 IDMT

SI

I > 1.2

𝐼𝑛

0.15 I >> 11.5 𝐼𝑛 0 s 50/1 IDMT

SI

I > 0.6

𝐼𝑒

0.15 I >> 34 𝐼𝑒 0 s Areva

P123

overcurrent protection coordination case study: …...ahmed hatim abdelbari elniema ahmed omer...

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