Substation Project

Design and Installation of 220/22 kV Gas Insulated

Substation (GIS)

Under the Supervision of

Prof. Dr. Mousa Abdullah

By

Abdelrahman Mohamed Mohamed Elsaeed Abdelrhman Gomaa Eisea Gomaa

Youssef Tarek Ibrahim Abdul-Dayem Youssef Nasser Sedky Ahmed
Hoda Elsayed Mohamed Ibrahim Nada Nader Nazeef Farahat
Youssef Abdelkhalek Abdelmonem Mariam Hossam El-dein Mohamed
Seif El-dien Mostafa Mohamed Shady Joseph Riad Aziz

Graduation Project
2023
 Acknowledgments
First of all, we deeply thank Allah for helping us accomplish this Project
and we devote it to our families, thanks to their encouragement, patience,
and assistance over the years.

We would like to thank many personnel for his support for the completion
of this work. Specially, our supervisor Prof. Dr. Mousa Abdallah.

Special thanks to Eng. Ahmed Metwally & Eng. Omar Saad & Eng.
Walid Fawzy Mohamed & Eng. Omar Hassan Taha & Eng. Ahmed
Moustafa Ahmed & Eng. Ahmed Dewidar & Eng. Seham Hamdy from
ELSEWEDY ELECTRIC T&D for their guidance along the technical
sessions.

Also, we would like to express our gratitude Smart Power Service (SPS)
for their continuous guidance and support specially Dr. Amr Kasem, Eng.
Mohamed Khaled, and Eng. Mahmoud Magdy.
 ABSTRACT
This project aims to design a transformation substation meeting all the
required specifications and quality standards for safe and reliable
operation.
An electrical substation is a subsidiary station of an electricity generation,
transmission, and distribution system where voltage is transformed from
high to low or the reverse using transformers.
Electric power may flow through several substations between generating
plant and consumer and may be changed in voltage in several steps.
A substation receives electrical power from generating station via
incoming transmission lines and delivers electrical power via outgoing
transmission lines. Substations generally have switching, protection,
control equipment and transformers.
Our case study on Zahraa EL-Mokattam 220/22 KV GIS Substation
which includes the primary and secondary design of all the equipment
associated with this substation.
 Table of Contents
CHAPTER 1 INTRODUCTION ............................................................................................... 18
1.1 Introduction ...................................................................................................................... 19
1.2 Sulfur Hexafluoride (SF6) ............................................................................................... 20
1.2.1 Introduction to Sulfur Hexafluoride ........................................................................... 20
1.2.2 Physical Properties ................................................................................................... 21
1.3 Classification of Substation ............................................................................................. 23
1.3.1 Classification based on voltage levels: .................................................................... 23
1.3.2 Classification based on Short Circuit level: ........................................................... 23
1.3.3 Classification based on Insulating Medium: .......................................................... 24
1.3.3.1 Air-insulated switchgear (AIS) ........................................................................ 24
1.3.3.2 Gas insulated switchgear (GIS) .......................................................................... 26
1.3.4 Classification based on Configuration .................................................................... 29
1.3.4.1 Single bus ........................................................................................................... 30
1.3.4.2 Double bus single breaker. ............................................................................... 30
1.3.4.3 Double bus double breaker. ............................................................................. 31
1.3.4.4 Ring bus ............................................................................................................. 32
1.3.4.5 Breaker and half breaker ................................................................................. 33
1.4 Project description ........................................................................................................... 34
CHAPTER 2 SLD & GLO ......................................................................................................... 35
2.1 SLD .................................................................................................................................... 36
2.1.1 Introduction SLD...................................................................................................... 36
2.1.2 Advantages of single line diagram .......................................................................... 36
2.1.3 Some of the standard symbols used to represent SLD .......................................... 36
2.1.3.1 Bus-bar: ............................................................................................................... 37
2.1.3.2 Power transformers: ............................................................................................ 37
2.1.3.3 Circuit breaker: ................................................................................................... 37
2.1.3.4 Isolators or Isolating switches:............................................................................ 38
2.1.3.5 Earth switch: ....................................................................................................... 38
2.1.3.6 Current transformers (CT): ................................................................................. 38
2.1.3.7 Potential transformers (PT): ................................................................................ 38
2.1.3.8 Lightning arresters(LA): ..................................................................................... 38
2.1.3.9 Coupling capacitor: ............................................................................................. 38
2.1.3.10 Wave trap: ......................................................................................................... 38
2.1.4 The project data ........................................................................................................ 39
2.1.5 Scope single line diagram ......................................................................................... 39
2.1.5.1 220 kV GIS Switchgear and Equipment: ............................................................ 39
2.1.5.2 220kV outdoor equipment: ................................................................................. 40
2.1.5.3 Supply, install and connect for 220k winding neutral point equipment of the
three phase power transformer: ....................................................................................... 41
 2.1.5.4 Supply, install and connect for 22KV winding neutral point equipment of the
three phase power transformer: ....................................................................................... 41
2.1.5.5 22 kV switchgear: ............................................................................................... 41
2.1.6 Single Line diagram for 220/22 KV Substation ..................................................... 43
2.2 General Layout (GLO) .................................................................................................... 44
2.2.1 Introduction ................................................................................................................ 45
2.2.2 Substation Layout Arrangement ................................................................................. 45
2.2.3 Important parameters and considerations for substation design ................................. 46
2.2.3.1 Environmental Conditions .................................................................................. 46
2.2.4 Minimum Clearance ................................................................................................... 47
2.2.5 Factor of safety ........................................................................................................... 47
2.2.6 General Layout Design ............................................................................................... 48
2.2.6.1 Gantry Area ......................................................................................................... 48
2.2.6.2 GIS Building ....................................................................................................... 48
2.2.6.3 Transformer Area ................................................................................................ 49
2.2.6.4 Main Road ........................................................................................................... 49
2.2.6.5 Capacitor Bank Area ........................................................................................... 50
2.2.6.6 Control Building ................................................................................................. 50
2.2.6.6.1 Switchgear Room .................................................................................... 51
2.2.6.7 Control Room...................................................................................................... 51
2.2.7 General Layout ........................................................................................................... 52
2.2.8 First Layout................................................................................................................. 52
CHAPTER 3 SHORT CIRCUIT CALCULATIONS ............................................................. 53
3.1 Introduction ...................................................................................................................... 54
3.1.1 Causes of Short Circuit ............................................................................................... 54
3.1.2 Effects of Short Circuit ............................................................................................... 55
3.1.3 Important of Short-Circuit Calculations ..................................................................... 56
3.2 Definitions ......................................................................................................................... 57
3.2.1 Terms and Definitions ................................................................................................ 57
3.2.1.1 Symmetrical short circuit current (𝐼𝑘) ................................................................ 57
3.2.1.2 Initial symmetrical short circuit current (𝐼𝑘′′) .................................................... 57
3.2.1.3 Initial symmetrical short-circuit apparent power (𝑆′′𝐾) ..................................... 57
3.2.1.4 Peak short-circuit current (𝑖𝑝) ............................................................................. 57
3.2.1.5 Decaying Component Direct current aperiodic component (𝐼𝑑𝑐) .................... 57
3.2.1.6 Steady-state short-circuit current (𝐼𝑘)................................................................. 57
3.2.1.7 Symmetrical breaking current (𝐼𝑏) ..................................................................... 58
3.2.1.8 Nominal system voltage (𝑈𝑛) ............................................................................. 58
3.2.1.9 Equivalent voltage source (𝑐𝑈𝑛/3) .................................................................... 58
3.2.1.10 Voltage factor (c) .............................................................................................. 58
3.2.1.11 Far-from-generator short circuit ....................................................................... 58
3.3 Short-Circuit Current Analysis ...................................................................................... 59
 3.3.1 Short-Circuit Path in the Positive-Sequence System .................................................. 60
3.4 Classification of Short-Circuit Types ............................................................................. 62
3.4.1 Symmetrical Fault....................................................................................................... 63
3.4.2 Unsymmetrical Fault .................................................................................................. 63
3.5 Methods of Short-Circuit Calculation ............................................................................ 64
3.5.1 Equivalent Voltage Source ......................................................................................... 65
3.6 Calculation Equations According (IEC 60909) ............................................................. 67
3.6.1 Impedance Equation ................................................................................................... 67
3.6.1.1 Network Feeder ................................................................................................... 67
3.6.1.2 Transformer Impedance ...................................................................................... 68
3.6.2 Short Circuit Current Equation ................................................................................... 69
3.6.2.1 Initial symmetrical short circuit current (𝐼𝑘′′) .................................................... 69
3.6.2.2 Peak short-circuit current (𝑖𝑝) ............................................................................. 69
3.6.2.3 Decaying Component Direct current aperiodic component (𝐼𝑑𝑐) .................... 70
3.6.2.4 Steady-state short-circuit current (𝐼𝑘)................................................................. 70
3.6.3 Symmetrical breaking current (𝐼𝑏) ............................................................................. 70
3.7 Short Circuit Calculation 220/22 kV GIS Substation ................................................... 71
3.7.1 Short Circuit Calculation Using MATLAB................................................................ 71
3.7.1.1 Substation Configuration (SLD) ......................................................................... 71
3.7.1.2 MATLAB Code .................................................................................................. 72
3.7.1.3 Input Data............................................................................................................ 74
3.7.1.4 Output Data From MATLAB (SC Calculation) ................................................. 75
3.7.2 Short Circuit Calculation Using ETAP ...................................................................... 78
3.7.2.1 Power Grid .......................................................................................................... 78
3.7.2.2 Transmission Line ............................................................................................... 79
3.8 Transformer...................................................................................................................... 80
3.9 Cable .................................................................................................................................. 81
3.10 RUN SC According IEC 60909 ..................................................................................... 82
3.10.1 Report from ETAP.................................................................................................... 82
CHAPTER 4 EARTHING SYSTEM ........................................................................................ 83
4.1 Earthing system:............................................................................................................... 84
4.2 Definitions: ........................................................................................................................ 85
4.3 Importance:....................................................................................................................... 87
4.4 Designing steps: ................................................................................................................ 88
4.4.1 Measurements of Soil Resistivity ............................................................................... 88
4.4.2 Determine the Surface Layer Derating Factor ............................................................ 89
4.4.3 Conductor sizing ......................................................................................................... 91
4.4.4 Calculation of tolerable step voltage and touch voltage: ............................................ 94
 4.4.5 Calculation of the number of conductors and the way to implement them: ............... 95
4.4.6 Calculation of the Earthing Grid Resistance: ............................................................. 96
4.4.7 Calculation of Maximum Grid Current: ..................................................................... 97
4.4.8 Calculation of Ground Potential Rise (GPR): ............................................................ 98
4.4.9 Calculating Maximum Step voltage and Touch voltage: ........................................... 99
4.4.10 Comparing: ............................................................................................................. 100
4.5 Designing of Substation Grounding Grid (Case study) .............................................. 101
4.5.1 Soil Resistivity:......................................................................................................... 101
4.5.2 Surface Layer Derating Factor: ................................................................................ 101
4.5.3 Cross Sectional Area of Conductors:........................................................................ 101
4.5.4 Safe Limits of Step Voltage and Touch Voltage: ..................................................... 102
4.5.5 Number of Conductors: ............................................................................................ 102
4.5.6 Grid Resistance: ........................................................................................................ 103
4.5.7 Maximum Grid Current: ........................................................................................... 103
4.5.8 Ground Potential Rise (GPR): .................................................................................. 103
4.5.9 Calculate Actual Mesh and Step Voltages by using Etap ........................................ 104
4.6 Designing of Substation Grounding Grid Using ETAP ............................................. 104
4.7 Secondary earthing ........................................................................................................ 109
CHAPTER 5 Raceway .............................................................................................................. 113
5.1 Raceway: ......................................................................................................................... 114
5.1.1 Cable Trench: ........................................................................................................... 114
5.1.1.1 Cable trays and Classification:.......................................................................... 115
5.1.1.2 Ladder trays: ..................................................................................................... 116
5.1.1.3 Perforated Cable Tray ....................................................................................... 116
5.1.1.4 Solid Bottom Cable Tray (Duct) ....................................................................... 117
5.1.1.5 Basket-type Cable Tray (Wire Mesh): .............................................................. 118
5.1.2 Filling Ratio .............................................................................................................. 119
5.1.2.1 Conduit size for cable: ...................................................................................... 119
5.1.2.2 Conduit material: .............................................................................................. 120
5.1.2.3 Calculation the filling ratio of all cables inside conduit: .................................. 120
5.1.3 Duct Bank ................................................................................................................. 122
5.1.4 Spacing between conductor ...................................................................................... 123
CHAPTER 6 Overvoltage Protection ..................................................................................... 126
6.1 Introduction .................................................................................................................... 127
6.2 Causes of Overvoltage .................................................................................................... 128
6.2.1 Internal faults ............................................................................................................ 128
6.2.2 External faults ........................................................................................................... 128
6.3 Lightning Protection System (LPS) .............................................................................. 129
6.3.1 LPS Components ...................................................................................................... 129
 6.3.2 LPS Design Methods ................................................................................................ 131
6.3.2.1 Fixed Angles Method ........................................................................................ 132
6.3.2.2 Empirical Curves Method ................................................................................. 133
6.3.2.3 Rolling sphere method ...................................................................................... 134
6.3.3 LPS Calculations ...................................................................................................... 137
6.4 Metal Oxide Surge Arrester (MOSA) .......................................................................... 139
6.4.1 Introduction .............................................................................................................. 139
6.4.2 Construction.............................................................................................................. 139
6.4.3 Operation .................................................................................................................. 141
6.4.4 ZnO Surge Arrester .................................................................................................. 143
CHAPTER 7 Switching devices ............................................................................................... 145
7.1 Puffer Type SF6 Circuit Breaker: ................................................................................ 146
7.1.1 Construction.............................................................................................................. 146
7.1.2 Working Principle..................................................................................................... 148
7.1.2.1 Normal Condition ............................................................................................. 148
7.1.2.2 Circuit Breaker Opening Operation .................................................................. 148
7.1.2.3 Circuit Breaker Closing Operation ................................................................... 150
7.1.3 Advantages of SF6 puffer type circuit breakers ....................................................... 150
7.1.4 Disadvantages of SF6 puffer type circuit breakers ................................................... 151
7.1.5 Nameplate Details of SF6 Circuit Breaker ............................................................... 151
7.1.5.1 Mandatory Parameters ...................................................................................... 153
7.1.5.1.1 Rated voltage ......................................................................................... 154
7.1.5.1.2 Rated frequency ..................................................................................... 154
7.1.5.1.3 Rated normal current ............................................................................. 154
7.1.5.1.4 Short circuit breaking current ................................................................ 155
7.1.5.1.5 Rated duration of short circuit ............................................................... 155
7.1.5.1.6 Rated peak withstand current or Rated making current ........................ 155
7.1.5.1.7 Rated short duration power frequency withstand voltage ..................... 156
7.1.5.1.8 Rated lighting impulse withstand voltage ............................................. 157
7.1.5.1.9 First pole to clear factor ......................................................................... 157
7.1.5.1.10 Rated operating sequence ...................................................................... 158
7.1.5.1.11 Switching duty: ...................................................................................... 160
7.1.5.1.12 Rated pressure of SF6 gas ..................................................................... 160
7.1.5.1.13 Total weight of SF6 gas ......................................................................... 160
7.1.5.1.14 Total weight of CB ................................................................................ 161
7.1.5.1.15 Rated control voltage ............................................................................. 161
7.1.5.2 Condition based parameters .............................................................................. 161
7.1.5.2.1 Rated switching impulse withstand voltage .......................................... 161
7.1.5.2.2 DC component of short circuit current .................................................. 162
7.1.5.2.3 Rated line charging current.................................................................... 162
7.1.5.2.4 Classification ......................................................................................... 162
7.1.5.3 Optional Parameters .......................................................................................... 163
 7.1.5.3.1 Rated out of phase current ..................................................................... 163
7.1.5.3.2 Rated cable Charging............................................................................. 164
7.1.5.3.3 Rated single capacitor bank breaking current ........................................ 164
7.1.5.3.4 Rated back-to-back capacitor bank breaking current ............................ 164
7.1.6 Mechanical Operating Mechanism of Circuit Breaker ............................................. 165
7.1.6.1 The hydromechanical mechanism..................................................................... 165
7.1.6.2 Spring Operating Mechanism ........................................................................... 166
7.2 Disconnecting Switch ..................................................................................................... 168
7.2.1 Disconnecting Switch Function ................................................................................ 168
7.2.2 Disconnect Switch Status ......................................................................................... 170
7.3 Earth Switch ................................................................................................................... 171
7.3.1 Earth Switch Function .............................................................................................. 171
7.3.2 Earth Switch Construction ........................................................................................ 172
7.3.3 Earth Switch Status ................................................................................................... 172
7.4 High Speed Earth Switch ............................................................................................... 172
7.5 The sequence of operation ............................................................................................. 174
CHAPTER 8 Auxiliary power supply and transformer ....................................................... 175
8.1 Introduction .................................................................................................................... 176
8.2 Substation main low voltage load ................................................................................. 177
8.2.1 Lighting: ................................................................................................................... 177
8.2.2 Sockets ...................................................................................................................... 179
8.3 Complete load estimation of 220/22 KV substation .................................................... 182
8.4 Auxiliary Transformer .................................................................................................. 184
8.4.1 Auxiliary transformer sizing ..................................................................................... 184
8.4.2 Auxiliary transformer and its specs: ......................................................................... 184
8.4.3 The requirements of the auxiliary transformer: ........................................................ 186
8.4.3.1 General: ............................................................................................................. 186
8.4.3.2 Transformation ratio and connection: ............................................................... 186
8.4.3.3 Voltage control: ................................................................................................ 186
8.4.3.4 Tapping and Tap changing: .............................................................................. 186
8.4.3.5 Overload capacity: ............................................................................................ 187
8.4.3.6 Limits of Temperature Rise: ............................................................................. 187
8.4.3.7 Bushing: ............................................................................................................ 188
8.4.3.8 Accessories and Fittings: .................................................................................. 188
8.4.3.9 Transformer room: ............................................................................................ 189
8.4.4 Operation of substation auxiliary transformer .......................................................... 189
8.5 Circuit Breaker: ............................................................................................................. 190
8.5.1 Type of circuit breaker: ............................................................................................ 190
8.5.1.1 Miniature circuit breakers (MCB): ................................................................... 190
 8.5.1.2 Molded-case circuit breaker (MCCB): ............................................................. 190
8.5.1.3 Air Circuit Breaker (ACB)................................................................................ 191
8.5.2 Circuit breaker selection: .......................................................................................... 191
8.6 Cables: ............................................................................................................................. 193
8.6.1 Cables and conductor types ...................................................................................... 193
8.6.1.1 Single core cable ............................................................................................... 193
8.6.1.2 Multi core cables: .............................................................................................. 193
8.6.2 Feeding cables requirements .................................................................................... 194
8.6.3 Cable Sizing Calculations ......................................................................................... 194
8.6.3.1 Ampacity: .......................................................................................................... 195
8.6.3.2 Derating factors ................................................................................................. 195
8.7 Voltage drop.................................................................................................................... 196
8.8 Short circuit: ................................................................................................................... 197
CHAPTER 9 DC AUXILARY SYSTEM ............................................................................... 198
9.1 Introduction .................................................................................................................... 199
9.2 Function of DC system:.................................................................................................. 200
9.3 Battery Types: ................................................................................................................ 201
9.3.1 Lead-acid batteries:................................................................................................... 201
9.3.2 Nickel-cadmium batteries: ........................................................................................ 202
9.4 DC system configuration: .............................................................................................. 203
9.4.1 Single 100% battery Low capital cost No standby DC and 100% charger System . 203
9.4.2 Semi-duplicate 2*50% batteries and 2 *100% chargers: ......................................... 204
9.4.3 Fully duplicate 2 * 100% batteries and 2 * 100% chargers: .................................... 204
9.5 DC system Voltage in substations:................................................................................ 205
9.6 DC Parameters: .............................................................................................................. 206
9.7 Design Factors: ............................................................................................................... 206
9.7.1 Temperature derating factor (Tt): ............................................................................. 206
9.7.2 Design margin factor: ............................................................................................... 207
9.7.3 Ageing factor: ........................................................................................................... 207
9.7.4 Capacity rating factor (Kt) ........................................................................................ 208
9.8 Load classifications: ....................................................................................................... 208
9.8.1 Continuous loads: ..................................................................................................... 208
9.8.2 Non-Continuous loads: ............................................................................................. 209
9.8.3 Momentary Loads: .................................................................................................... 210
9.9 Duty cycle diagram: ....................................................................................................... 211
9.10 Battery sizing Calculation "according to (IEEE-1115)": ......................................... 211
9.10.1 Number of cells calculation: ................................................................................... 213
 9.10.2 Batteries Sizing methodology:................................................................................ 214
9.10.3 Ampere-hour sizing ................................................................................................ 216
9.11 Battery Charger............................................................................................................ 218
9.11.1 Definition ................................................................................................................ 218
9.11.2 Battery charger rating "according to (EUS-E16)": ................................................. 218
9.11.3 Battery charger calculation ..................................................................................... 219
CHAPTER 10 INSTRUMENT TRANSFORMERS ............................................................. 220
10.1 Introduction .................................................................................................................. 221
10.2 CURRENT TRANSFORMERS (CTs) ....................................................................... 222
10.2.1 Magnetization curve ............................................................................................... 223
10.2.2 Knee-point voltage ................................................................................................. 224
10.2.3 Difference Between Measuring and Protective CTs .............................................. 224
10.2.4 Core Material of CTs .............................................................................................. 225
10.2.5 CT Burden .............................................................................................................. 226
10.2.6 Technical Terms of CTs ......................................................................................... 228
10.2.7 Theory of Current Transformers............................................................................. 231
10.2.8 CT Errors ................................................................................................................ 232
10.2.9 Open-circuiting of the Secondary Circuit of a CT ................................................. 234
10.2.10 Class X current transformers ................................................................................ 235
10.3 VOLTAGE TRANSFORMERS (VTs) ...................................................................... 235
10.3.1 VT Errors ................................................................................................................ 236
10.3.2 Limits of VT Errors for Protection ......................................................................... 236
10.3.3 Type of VTs ............................................................................................................ 237
10.3.3.1 Electromagnetic Type VTs ............................................................................. 237
10.3.3.2 Coupling Capacitor Voltage Transformers (CCVTs) ..................................... 238
CHAPTER 11 Protection Systems and Schemes ................................................................... 240
11.1 Introduction .................................................................................................................. 241
11.1.1 Classification of Relays and Basic requirements ............................................... 242
11.1.2 Zones of protection ............................................................................................... 243
11.1.3 Main and backup protection ............................................................................... 244
11.1.4 Tripping circuits ................................................................................................... 245
11.1.5 Trip circuit supervision ........................................................................................ 245
11.2 Feeder Protection ......................................................................................................... 247
11.2.1 Distance Relay ....................................................................................................... 247
11.2.1.1 Step Distance protection ............................................................................... 248
11.2.1.2 Problems facing distance protection ........................................................... 249
11.2.2 Line Current Differential Relay .......................................................................... 251
11.2.3 Common communication schemes ...................................................................... 252
11.2.4 Relay and Metering of feeder bay ....................................................................... 253
 11.3 Transformer Protection ............................................................................................... 254
11.3.1 Purpose of transformer protection ..................................................................... 254
11.3.2 Types of Faults Encountered in Transformers .................................................. 254
11.3.2.1 External Faults .............................................................................................. 254
11.3.2.2 Internal Faults ............................................................................................... 255
11.3.3 Considerations for selecting protection system.................................................. 256
11.3.4 Types of Transformer Protection ........................................................................ 257
11.3.4.1 Differential protection – ANSI 87T ............................................................. 257
11.3.4.2 Restricted earth fault protection ................................................................. 260
11.3.4.3 Overcurrent protection ................................................................................ 261
11.3.4.4 Over flux protection ...................................................................................... 263
11.3.4.5 Mechanical protection .................................................................................. 264
11.3.5 Relay and Metering of Transformer 220/22 KV................................................ 269
11.4 Busbar protection ......................................................................................................... 271
11.4.1 Bus-bar protection requirements ........................................................................ 271
11.4.2 Busbar protection types ....................................................................................... 271
11.4.2.1 Busbar differential protection ..................................................................... 272
11.4.2.1.1 Low impedance differential protection.................................................. 272
11.4.2.1.2 High impedance differential protection ................................................. 273
CHAPTER 12 Relay coordination study ................................................................................ 275
12.1 Over current protection ............................................................................................... 276
12.2 Purpose of OC protection: ........................................................................................... 277
12.3 Principles of time/current grading.............................................................................. 277
12.4 Standard IDMT overcurrent relay ............................................................................. 278
12.5 Overcurrent sitting ....................................................................................................... 280
12.5.1 ETAP program ..................................................................................................... 282
12.5.2 Time coordination Curve (TCC) ......................................................................... 289
12.5.3 calculation pickup Currents using EXCEL sheet.............................................. 290
CHAPTER 13 Substation Control & Monitoring ................................................................. 291
13.1 Introduction .................................................................................................................. 292
13.2 Basic Control System ................................................................................................... 292
13.3 Details of Conventional HMI ...................................................................................... 294
13.4 Details of Computer-Based HMI ................................................................................ 295
13.5 Local Control Cabinet ................................................................................................. 297
13.6 Bay Controller .............................................................................................................. 301
References .................................................................................................................................. 303
 List of figures
Figure 1.1 Power System Elements .............................................................................................. 19
Figure 1.2 Molecular structure of sulfur hexafluoride SF6 .......................................................... 21
Figure 1.3 Arc current of SF6, with SF6 gas-to-air gas mixture and air ...................................... 22
Figure 1.4 Physical Properties of Sulphur Hexafluoride – SF 6 ................................................... 23
Figure 1.5 Gas insulated switchgear ............................................................................................. 26
Figure 1.6 Comparison between GIS & AIS Substations ............................................................. 29
Figure 1.7 Single Bus arrangement ............................................................................................... 30
Figure 1.8 Double bus–single breaker arrangement. .................................................................... 30
Figure 1.9 Double breaker–double bus arrangement .................................................................... 31
Figure 1.10 Ring Bus arrangement ............................................................................................... 32
Figure 1.11 Breaker-and-a-half arrangement ................................................................................ 33
Figure 2.1 single line diagram of 220/22KV substation ............................................................. 43
Figure 2.2 Gantry Area ................................................................................................................. 48
Figure 2.3 GIS Building ................................................................................................................ 49
Figure 2.4 Transformer Area ........................................................................................................ 49
Figure 2.5 Capacitor Banks Area .................................................................................................. 50
Figure 2.6 Control Building 1 ....................................................................................................... 50
Figure 2.7 Switchgear Room ....................................................................................................... 51
Figure 2.8 Control Room .............................................................................................................. 51
Figure 2.9 General Layout ............................................................................................................ 52
Figure 2.10 First Layout ............................................................................................................... 52
Figure 3.1 time behavior of the short-circuit current .................................................................... 59
Figure 3.2 Equivalent circuit of the short-circuit current path in the positive-sequence system .. 60
Figure 3.3 Switching processes of the short circuit ...................................................................... 62
Figure 3.4 Short Circuit types ....................................................................................................... 64
Figure 3.5 Equivalent Voltage Source method ............................................................................. 65
Figure 3.6 short circuit is fed from a network without Transformer. .......................................... 67
Figure 3.7 short circuit is fed from a network with Transformer. ................................................ 68
Figure 3.8 X/R Ratio ..................................................................................................................... 70
Figure 3.9 SLD.............................................................................................................................. 71
Figure 3.10 Input data (MATLAB) .............................................................................................. 74
Figure 3.11 Power Grid Data (ETAP) .......................................................................................... 78
Figure 3.12 Transmission Line Data (ETAP) ............................................................................... 79
Figure 3.13 Transformer Data (ETAP) ......................................................................................... 80
Figure 3.14 Cable Data From Elseewdy catalogue ....................................................................... 81
Figure 3.15 Cable Data (ETAP).................................................................................................... 81
Figure 3.16 Short Circuit Results (ETAP) .................................................................................... 82
Figure 3.17 Short Circuit Report (ETAP) ..................................................................................... 82
Figure 4.1 (Wenner method) ........................................................................................................ 89
Figure 4.2 (Maximum Grid Current) ........................................................................................... 97
Figure 5.1 Cable Trench ............................................................................................................. 115
Figure 5.2 Ladder tray................................................................................................................. 116
Figure 5.3 Perforated Cable Tray................................................................................................ 117
Figure 5.4 solid bottom cable tray .............................................................................................. 118
Figure 5.5 Basket type Cable Tray ............................................................................................. 118
Figure 5.6 filled by multiple cables. ........................................................................................... 119
Figure 5.7 specifications ............................................................................................................. 120
Figure 5.8 calculations of Filling ratio ........................................................................................ 122
Figure 5.9 filling ratio specifications .......................................................................................... 122
Figure 5.10 Duct Bank ................................................................................................................ 123
Figure 5.11 Spacing between conductor ..................................................................................... 124
Figure 5.12 Diameter of 630Sq.mm Cable ................................................................................. 124
Figure 5.13 Cable Trench ........................................................................................................... 125
Figure 6.1 Fixed angles for masts (IEEE-998) ........................................................................... 132
Figure 6.2 Fixed angles curve for masts (IEEE-998) ................................................................. 133
Figure 6.3 Empirical curve for masts and objects (IEEE-998) ................................................... 134
Figure 6.4 Principle of Rolling Sphere Method (IEEE-998) ...................................................... 135
Figure 6.5 Rolling Sphere Over an Object (NFPA-780) ............................................................ 135
Figure 6.6 Manual Calculations of GIS Building ....................................................................... 137
Figure 6.7 Protected GIS Building.............................................................................................. 138
Figure 6.8 Zoomed-in Protected GIS Building ........................................................................... 138
Figure 6.9 Construction of metal oxide surge arrester (MOSA) ................................................ 140
Figure 6.10 Metal oxide resistor disks ........................................................................................ 140
Figure 6.11 Microstructure of MOSA disk element (ZnO, Bi2O3) ........................................... 143
Figure 6.12 Equivalent circuit of MOSA element ...................................................................... 144
Figure 7.1. Construction of Puffer Type CB Interrupter. ........................................................... 147
Figure 7.2 SF6 CB Construction. ................................................................................................ 147
Figure 7.3. Operation of a Puffer Type SF6 Circuit Breaker. ..................................................... 149
Figure 7.4. Current and Voltage during Fault Clearing. ............................................................. 149
Figure 7.5 Short Circuit Making Current Waveform.................................................................. 156
Figure 7.6. Auto Reclosing System. ........................................................................................... 159
Figure 7.7 Main Technical Parameters of CB. ........................................................................... 160
Figure 7.8 Hydromechanical operation mechanism. .................................................................. 165
Figure 7.9 Section view of Hydromechanical operation mechanism. ........................................ 166
Figure 7.10 Closed position (Closing spring Charged ) ............................................................. 167
Figure 7.11 Open position (Closing spring Charged ) ................................................................ 167
Figure 7.12 Closed position (Closing spring Charged ) ............................................................. 168
Figure 7.13. Cross-section of an isolated-phase GIS disconnector. ........................................... 169
Figure 8.1 32 A rated voltage 380 V........................................................................................... 181
Figure 8.2 16 A rated voltage 380 V........................................................................................... 182
Figure 8.3 Load estimation of 220/22 KV substation ................................................................. 183
Figure 8.4 Auxiliary transformers parameters ............................................................................ 185
Figure 8.5 Miniature circuit breaker ........................................................................................... 190
Figure 8.6 Molded-case circuit breaker ...................................................................................... 191
Figure 8.7 Air circuit breaker...................................................................................................... 191
Figure 8.8 Ratings of circuit breaker .......................................................................................... 192
Figure 8.9 Single core cable........................................................................................................ 193
Figure 8.10 Multi core cable ....................................................................................................... 194
Figure 9.1 DC auxiliary system .................................................................................................. 200
Figure 9.2 Lead acid batteries ..................................................................................................... 201
Figure 9.3 Nickel-Cadmium Battery........................................................................................... 202
Figure 9.4 Single battery single charger ..................................................................................... 203
Figure 9.5 one battery two charges ............................................................................................. 204
Figure 9.6 Two batteries tow charges system ............................................................................. 205
Figure 9.7 Duty cycle .................................................................................................................. 211
Figure 9.8 Generalized duty cycle .............................................................................................. 214
Figure 9.9 DC load summary ...................................................................................................... 216
Figure 9.10 Duty cycle diagram.................................................................................................. 217
Figure 9.11Total AH of battery .................................................................................................. 217
Figure 10.1 Typical CT magnetization curve ............................................................................. 223
Figure 10.2 Magnetization characteristics of CT cores .............................................................. 226
Figure 10.3 Equivalent circuit of CT as viewed from secondary side ........................................ 231
Figure 10.4 Capacitance voltage divider .................................................................................... 238
Figure 11.1 Division of power systems into protection zones .................................................... 243
Figure 11.2 Typical relay tripping circuits ................................................................................. 245
Figure 11.3 Trip circuit supervision circuit ................................................................................ 246
Figure 11.4 Typical basic protection for sub-transmission feeder .............................................. 247
Figure 11.5 Distance protection Zones ....................................................................................... 248
Figure 11.6 Load Encroachment ................................................................................................. 249
Figure 11.7 Power Swing ............................................................................................................ 250
Figure 11.8 Line Current Differential Relay-Scheme................................................................. 251
Figure 11.9 RMOLD of feeder bay............................................................................................. 253
Figure 11.10 Transformer fault statistics .................................................................................... 255
Figure 11.11 Percentage differential protection for Y - ∆ connected ........................................ 257
Figure 11.12 Operating characteristic of percentage differential relay ...................................... 259
Figure 11.13 Bias setting of percentage differential relay .......................................................... 259
Figure 11.14 Earth fault protection of a power transformer ....................................................... 260
Figure 11.15 Connection of overcurrent protection devices on both sides of a power transformer
..................................................................................................................................................... 262
Figure 11.16 Coordination between HV & LV sides of Transformer ........................................ 262
Figure 11.17 characteristics of over flux protection ................................................................... 263
Figure 11.18 Buchholz Relay mounting arrangement ................................................................ 264
Figure 11.19 Sudden Pressure Rise Relay .................................................................................. 266
Figure 11.20 Oil Pressure Relief Relay ...................................................................................... 267
Figure 11.21Winding Thermometer ........................................................................................... 268
Figure 11.22 RMOLD of transformer bay ................................................................................. 270
Figure 11.23 The Differential protection for a bus-bar............................................................... 272
Figure 11.24 Low Impedance bus Differential Protection diagram ........................................... 273
Figure 11.25 High Impedance bus Differential Protection diagram ........................................... 274
Figure 12.1 Relay characteristics ................................................................................................ 279
Figure 12.2 ETAP MODEL ........................................................................................................ 282
Figure 12.3 Time Coordination Curve (TCC) ............................................................................ 289
Figure 13.1 an example of human machine interface locations................................................. 293
Figure 13.2 Indoor local control cabinet ..................................................................................... 297
Figure 13.3 Outdoor local control cabinet .................................................................................. 298
Figure 13.4 Mimic diagram ........................................................................................................ 299
 List of Table
Table 2.1 220KV equipment's legend and symbols ...................................................................... 36
Table 2.2 22KV equipment’s and legend symbols ..................................................................... 37
Table 2.3 Environmental Conditions ............................................................................................ 46
Table 2.4 Minimum Clearance ..................................................................................................... 47
Table 2.5 Factor of safety ............................................................................................................. 47
Table 3.1 Voltage factor c, according to IEC 60909 .................................................................... 66
Table 3.2 Typical values of impedance voltage drop of three-phase transformer. ....................... 69
Table 3.3 Output Data (MATLAB) for HV Busbar ..................................................................... 76
Table 3.4 Output Data (MATLAB) for LV Busbar ...................................................................... 77
Table 4.1 Basic range of soil resistivity ........................................................................................ 88
Table 4.2 typical surface material resistivity ................................................................................ 91
Table 4.3: material constants ........................................................................................................ 93
Table 6.1 Maximum values of rolling sphere radius (IEC-62305-3).......................................... 136
Table 6.2 Final results of the manual calculations for all protection zones ................................ 138
Table 7.1 Nameplate of SF6 Circuit Breaker.............................................................................. 152
Table 10.1 CTR Errors ................................................................................................................ 233
Table 10.2 VTR Errors ............................................................................................................... 236
Table 11.1 Transformer categories Rating.................................................................................. 256
Table 11.2 Types of Mechanical Protection ............................................................................... 264
Table 11.3 RMOLD .................................................................................................................... 269
Table 12.1 Definitions of standard relay characteristics ............................................................ 279
CHAPTER 1 INTRODUCTION

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1.1 Introduction
Generally, the power system consists of three main elements which are
generation, transmission and distribution Substation: is part of power system in
which the voltage is transformed from level to level for transmission, distribution,
transformation and switching. The electric power is produced at the power stations
which are located at favorable places, generally quite away from the consumers.

Figure 1.1 Power System Elements

It is delivered to the consumers through a large network of transmission and

distribution. At many places in the line of the power system, it may be desirable and
necessary to change Voltage level for many reasons such as distribution or to connect
various regions through one electrical utility grid. This is accomplished by suitable
apparatus called substation. The electrical substation is the part of a power system
in which the voltage is transformed from high to low or from low to high for
transmission, distribution, transformation and switching. We need various voltage

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level in the grid to perform various tasks for example we transmit electrical power
at high voltage (220 KV, 132 KV, 66 KV) and sometimes extra high voltage (400
KV, 500 KV, 765 KV) and ultra-high voltage (more than 765 KV according to IEC
standard). Using high voltage for power transmission provides many benefits such
as decrease ohmic losses, decrease cross section area of conductors, increase power
transfer capability moreover transfer power for long distance. Addition benefit of
substation it is the core of unified utility electrical grid as the substation connect the
generation station from all over country through the transmission grid. The
substation provides the high reliability of the grid as through the substation we can
switch off the faulty sections of the grid and maintain the stability. The electrical
national grid through substations provides a very economic power system as we can
generate power in a place and transmit power to a distant place. The substations help
in the control of the electrical national grid as in case of increasing the loads in peak
times operators of the grid start of switching off less importance distribution
substations and decrease the current load to be suitable with the generation power
which maintain stability and prevent blackouts. Another strategy in case of high load
in peak times we can transfer electrical power in our national grid from substations
which is connected with other substations in different countries.

1.2 Sulfur Hexafluoride (SF6)

1.2.1 Introduction to Sulfur Hexafluoride

Sulfur hexafluoride (SF6) is a colorless, odorless, nontoxic, and nonflammable

gas. It is five times heavier than air and has an extremely stable molecular
construction (see Figure 1.2). The gas provides high dielectric strength and excellent
arc-quenching properties. However, the high heat. The main applications in electric
power equipment utilizing SF6 are defined by the current IEEE Standards C37.122,

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IEC 60480, 62271-203 for HV GIS, 62271-100 for circuit breakers and 62271-102
for disconnectors.

Figure 1.2 Molecular structure of sulfur hexafluoride SF6

1.2.2 Physical Properties

The main characteristic of SF6 useful for the design of high-voltage equipment
is the high dielectric withstand capability, which is about 3 times the dielectric
withstands of air. Used in high voltage equipment with gas pressures of up to 8 bar,
the size of equipment using SF6 can be reduced by up to ten times as compared to
equivalent air-insulated installations. SF6 gas also effectively quenches arcs in
circuit breakers, disconnectors, and ground switches. Pure SF6 increases strongly
the arc-quenching capability with increasing pressure, as shown in Figure 1.3. This
is the reason why the gas pressure in breaker compartments of a GIS has the highest
gas pressure compared to the bus bar gas compartment or to gas compartments of
disconnectors and ground/earth switches. If the SF6 gas is mixed with air, the
resulting arc-quenching capability is strongly reduced. The SF6 related arc currents
of air are much lower, as shown in Figure 1.3. The metal encapsulation of GIS makes

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the equipment very safe to operate because all high voltage parts are contained and
properly insulated and the metallic enclosure is grounded and can be normally
touched without injury. The SF6 insulation gas inside the GIS does not show any
aging effects and is protected by the metal enclosure from ambient influences such
as humidity, dust, salt air, and others. Therefore, the maintenance required is very
low. Today’s state-of-the-art GIS have recommended maintenance cycles of 25
years. The main physical properties of SF6 to be used in high-voltage equipment are
shown in figure 1.4.

Figure 1.3 Arc current of SF6, with SF6 gas-to-air gas mixture and air

The data in Figure 1.4. is taken from different sources and in some cases the results
are found to be conflicting, possibly due to the variation in the chemical purity of
the gas tested. SF6 gas resembles C02 in many physical properties. Both these gases
are sublime and melt under a pressure of several atmospheres. Up to -50.8 C (melting
point). The SF6 gas is in equilibrium with the solid phase and liquid SF6 is
metastable. On the other hand, liquid SF6 cannot exist above 45.6 0 C, the critical
temperature.

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Figure 1.4 Physical Properties of Sulphur Hexafluoride – SF 6

1.3 Classification of Substation

The substations can be classified in several ways including the following:

1.3.1 Classification based on voltage levels:

• LV (up to 1000V).
• MV (1000V to 33kV).
• HV (33 KV and 220 kV).
• EHV (above 220KV).
• HVDC Substation

1.3.2 Classification based on Short Circuit level:

• 25 KA
• 31.5 KA
• 40 KA
• 50 KA

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• 63 KA

1.3.3 Classification based on Insulating Medium:

• AIS
• GIS

1.3.3.1 Air-insulated switchgear (AIS)

The AIS uses air as the primary dielectric from phase to phase, and phase to
ground insulation. They have been in use for years before the introduction of GIS.
In Air Insulated Substation, air between phase-ground and phase-phase is used as
insulator. In spite of poor dielectric and statutory clearness of air more space is
required, and in urban populated area resources of area is very limited. Change in
ambient temperature such as humidity level, rain, pollutants in air cause the
insulation to deteriorate. Due to all these factors it’s required more space for
insulation of AIS in order to meet the specified requirements. The physical
infrastructure is venerable to continuous degradation due to atmospheric condition.
Any seismic instability can adversely affect the whole infrastructure. Because of all
above stated problems Air Insulated Substation require complex planning and more
execution time which increases its capital cost moreover its operational cost is also
high due to higher frequency of maintenance Undertaking all these facts an
insulation material is needed to decreases the size of substation. Using Gas Insulated
Substation is a solution to that. All equipment is enclosed in a gas filled chamber
which provides effective insulation in much less space as compared to Air Insulation
Substation. Special gas is used as insulation material whose properties are further
described in this paper. This gas is enclosed along with electric components such as
Bus-Bars, circuit breakers, switchgears… etc., in a chamber Using GIS not only

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decreases our size but it also has many advantages in the form of cost and
maintenance.

Advantages

1. The primary choice for areas with extensive space

2. With quality design, the system is viable due to the low construction costs and
cost of switchgear.
3. Less construction time, thereby more suited for expedited installations.
4. Easy maintenance as all the equipment is within view. It is easy to notice and
attend to faults.

Disadvantages

1. More space is required compared to GIS.

2. Vulnerable to faults since the equipment are exposed to the external elements
such as human intrusion, pollution, deposition of saline particles, lightning
strikes and extreme weather conditions.
3. More maintenance requirements, thus leading to high costs.

The poor dielectric properties of air, as well as secondary factors such as humidity,
pollutants, moisture means that more space is required for efficacy.

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1.3.3.2 Gas insulated switchgear (GIS)

Figure 1.5 Gas insulated switchgear

Gas Insulated Substation is an electric power substation in which all live equipment
and bus bars are housed in grounded metal which is sealed and placed in a chamber
filled with gas. Isolated gas station by using sulfur hexafluoride (SF6), which has
superior dielectric properties used to moderate pressure to the phase to phase and the
ground insulation. In gas-insulated high voltage conductors, circuit breakers,
switches, current transformers, voltage transformers and surge protectors are
encapsulated in SF6 cans to the ground. Isolation in the gas is used when space is to
provide a high position in the big cities or permissions in normal positions between
phase to phase and phase to ground are very large. For this reason, a large space is
required for the sub-station or in normal air insulation (AIS). But the dielectric
strength of SF6 gas is higher relative to the air, necessary for phase to phase and
ground clearance for all equipment are much lower. Therefore, the overall size of
each team and the whole substation is reduced to about 10 % of the conventional air
insulation substations. Gas Insulated Substation (GIS) SF6 contains the same
compartments in conventional outdoor substations. All live parts are enclosed in
metal boxes filled with SF6 gas. The active parts are supported on insulators molten
resin. Some of these bushes are designed as barriers between adjacent modules such

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that the gas does not pass through them. The entire system is divided into
compartments which are relative to the other gas-tight. Thus, the gas detection
system in each compartment can be independent and simpler. The housings are of
nonmagnetic materials such as aluminum or stainless steel and are connected to
ground. The gas seal is provided with 'O' static seal positioned between the machined
flanges. The “O – rings” are placed in the slots such that, after assembly, the “O-
ring” to shrink 20%. The quality of materials, the dimensions of grooves and “O –
rings” are important to ensure sealing performance of the gas-insulated gas station.
Gas Insulated station has a gas detection system. The gas inside of each compartment
should have a pressure in the range of the density of the gas in each compartment is
controlled 3kg/cm2 .The. If the pressure drops slightly, the gas is trapped
automatically. With new gas leaks, low pressure alarm is triggered or automatic or
shutdown.

Advantages of GIS

1. The earthed metal enclosure makes for a safe working environment for the
attending personnel.
2. Compartmentalized enclosure of the live parts makes for a very reliable
system due to reduced disruption of the insulation system.
3. By reducing the distance between active and non-active switchgear parts, less
space is required than in the normal AIS system: this comes in handy in
densely populated areas and unfavorable terrain (minimum requirements for
an AIS is about 47,000m2 , while GIS with the same power properties will
require approx.. 523m2 ). For the AIS, the highest element is approximately
28m, whereas for GIS you have 11m at the highest point for a 400kV
substation.

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4. Low maintenance requirements due to expedient design and protection against

external elements.
5. Under scheduled maintenance, SF6 neither ages nor depletes. There is no need
to top up the gas levels throughout the equipment lifetime (approx. 40 years).
6. Quick assembly due to extensive pre-assembly.

Disadvantages of GIS

1. High installation costs compared to AIS systems.

2. Procurement and supply of SF6 gas can be a problem especially in rough
terrain and off site locations. This further increases the costs.
3. High level of maintenance is required. This requires highly skilled personnel.
4. Internal faults tend to be very costly and severe when they occur. They often
lead to long outage periods. For example, the use of impure gas, as well as
leakage due to ‘O’ ring failure, as well as presence of dust can lead to
flashovers and explosions.
5. Though the gas is quite inert, flash problems can break it down into harmful
by products such as metal fluoride powders. This poses a health hazard such
as physical asphyxiation and other respiratory problems.

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Comparison between GIS & AIS Substations

Figure 1.6 Comparison between GIS & AIS Substations

1.3.4 Classification based on Configuration

Various factors affect the reliability of an electrical substation or switchyard

facility, one of which is the arrangement of switching devices and buses. The
following are the Five types of arrangements commonly used:

1. Single bus.
2. Double bus single breaker.
3. Double bus double breaker.
4. Ring bus
5. Breaker and half breaker.

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1.3.4.1 Single bus

Figure 1.7 Single Bus arrangement

This is the simplest bus arrangement, a single bus and all connections directly to one
bus (Figure 1.7). Reliability of the single bus configuration is low: even with proper
relay protection, a single bus failure on the main bus or between the main bus and
circuit breakers will cause an outage of the entire facility. With respect to
maintenance of switching devices, an outage of the line they are connected to is
required. Furthermore, for a bus outage the entire facility must be de-energized. This
requires standby generation or switching loads to adjacent substations, if available,
to minimize outages of loads supplied from this type of facility. Cost of a single bus
arrangement is relatively low, but also is the operational flexibility; for example,
transfer of loads from one circuit to another would require additional switching
devices outside the substation.

1.3.4.2 Double bus single breaker.

Figure 1.8 Double bus–single breaker arrangement.

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The double bus-single breaker arrangement connects each circuit to two buses, and
there is a tie breaker between the buses. With the tie breaker operated normally
closed, it allows each circuit to be supplied from either bus via its switches. Thus
providing increased operating flexibility and improved reliability. For example, a
fault on one bus will not impact the other bus. Operating the bus tie breaker normally
open eliminates the advantages of the system and changes the configuration to a two
single bus arrangement (Figure 1.8). The double bus–single breaker arrangement
with two buses and a tie breaker provides for some ease in maintenance, especially
for bus maintenance, but maintenance of the line circuit breakers would still require
switching and outages as described above for the single bus arrangement circuits.

1.3.4.3 Double bus double breaker.

Figure 1.9 Double breaker–double bus arrangement

The double bus–double breaker arrangement involves two breakers and two buses
for each circuit (Figure 1.9). With two breakers and two buses per circuit, a single
bus failure can be isolated without interrupting any circuits or loads. Furthermore, a
circuit failure of one circuit will not interrupt other circuits or buses. Therefore,

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CHAPTER 1 Introduction

reliability of this arrangement is extremely high. Maintenance of switching devices

in this arrangement is very easy, since switching devices can be taken out-of-service
as needed and circuits can continue to operate with partial line relay protection and
some line switching devices in-service, i.e., one of the two circuit breakers.

1.3.4.4 Ring bus

Figure 1.10 Ring Bus arrangement

As the name implies, all breakers are arranged in a ring with circuits connected
between two breakers. This arrangement affords increased reliability to the circuits,
since with properly operating relay protection, a fault on one bus section will only
interrupt the circuit on that bus section and a fault on a circuit will not affect any
other device (Figure 1.10). Protective relaying for a ring bus will involve more
complicated design and, potentially, more relays to protect a single circuit. Keep in
mind that bus and switching devices in a ring bus must all have the same ampacity,
since current flow will change depending on the switching device’s operating
position. From a maintenance point of view, the ring bus provides good flexibility.
A breaker can be maintained without transferring or dropping load, since one of the
two breakers can remain in-service and provide line protection while the other is
being maintained. Similarly, operating a ring bus facility gives the operator good

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flexibility since one circuit or bus section can be isolated without impacting the loads
on another circuit. Cost of the ring bus arrangement can be more expensive than a
single bus, main bus and transfer, and the double bus–single breaker schemes since
two breakers are required for each circuit, even though one is shared. he ring bus
arrangement is applicable to loads where reliability and availability of the circuit is
a high priority.

1.3.4.5 Breaker and half breaker

Figure 1.11 Breaker-and-a-half arrangement

The breaker-and-a-half scheme is configured with a circuit between two

breakers in a three-breaker line-up with two buses; thus, one-and-a-half breakers per
circuit. In many cases, this is the next development stage of a ring bus arrangement
(Figure 5). Similar to the ring bus, this configuration provides good reliability; with
proper operating relay protection, a single circuit failure will not interrupt any other
circuits. Furthermore, a bus section fault, unlike the ring bus, will not interrupt any
circuit loads. Maintenance as well is facilitated by this arrangement, since an entire
bus and adjacent breakers can be maintained without transferring or dropping loads.

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Relay protection is similar to the ring bus, and due to the additional devices, is more
complex and costly than most of the previously reviewed arrangements.

1.4 Project description

The Substation will be 220/22kV, 2×75 MVA Outdoor transformers, indoor
GIS type, expandable by a third similar transformer. The substation will be
connected to the unified 220kV network through opening one circuit of the existing
220k double circuit single conductor overhead transmission lines 220kV S/S / Cairo
East 220kV S/S. 220 kV GIS Switchgear and Equipment: The 220 kV switchgear
shall be SF6 Gas insulated (GIS) indoor type, double busbars with rated current
2000A, single breaker configuration and symmetrical short circuit current 50 k for
one second, lightning impulse withstand voltage 1050 KV peak and maximum rated
voltage 245 kV rms. Double three single phase enclosure bus-bar GIS type with rated
2000A to accommodate five (5) bays, plus space for one transformer bay and two
underground cables bays. The 22 kV switchgear single busbar with rated current
2500 A. one breaker configuration shall be metal clad of indoor type with
symmetrical short circuit current of 31.5 kA for three seconds, withstand lightning
impulse voltage 125 kV

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CHAPTER 2 SLD & GLO

CHAPTER 2 SLD & GLO

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2.1 SLD
2.1.1 Introduction SLD
A single line diagram also called the one-line diagram is a symbolic or
graphical representation of a three-phase power system. It has a diagrammatic
representation of all the equipment and connections. The electrical elements such
as circuit breakers, transformers, bus bars, and conductors, are represented using
standardized schematic symbols so that they can be read and understood easily. In
a single line diagram, instead of representing each of three phases with separate
lines, only a single conductor is represented using a single line. A single line
diagram makes it easy to understand an electrical system, particularly in the case of
complicated systems in substations. It helps in a detailed study and evaluation of
the system and its efficiency.
2.1.2 Advantages of single line diagram
• Helpful to identify when to perform troubleshooting and simplifies the
troubleshooting process.
• Meets compliance with applicable regulations and standards.
• Ensure a safer and more reliable operation of the facility
• Gives an overall understanding of the system and eases evaluation
• Accurate single line diagram will further ensure the safety of personnel
work.
2.1.3 Some of the standard symbols used to represent SLD

Table 2.1 220KV equipment's legend and symbols

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Table 2.2 22KV equipment’s and legend symbols

2.1.3.1 Bus-bar:
When number of lines operating at the same voltage levels needs to be
connected electrically, bus-bars are used. Bus-bars are conductors made of copper
or aluminum, with very low impedance and high current carrying capacity.
2.1.3.2 Power transformers:
Power transformers are used generation and transmission network for
stepping-up the voltage at generating station and stepping-down the voltage for
distribution. Auxiliary transformers supply power to auxiliary equipment’s at the
substations.
2.1.3.3 Circuit breaker:
A circuit breaker is a circuit component that can open or close a circuit under
normal and fault conditions. It is designed such that it can be operated manually
under normal conditions and automatically under fault conditions. It is a special
type of switching device which can be operated safely under huge current carrying
conditions. It is used for timely disconnecting and reconnecting different parts of
the power system for protection and control.

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2.1.3.4 Isolators or Isolating switches:

Isolators are employed in substations to isolate a part of the system for
general maintenance. Isolator switches are operated only under no load condition.
They are provided on each side of every circuit breaker.
2.1.3.5 Earth switch:
It is a switch normally kept open and connected between earth and
conductor. If the switch is closed it discharges the electric charge to ground,
available on the uncharged line.
2.1.3.6 Current transformers (CT):
The lines in substations carry currents in the order of thousands of amperes.
The measuring instruments are designed for low value of currents. Current
transformers are connected in lines to supply measuring instruments and protective
relays.
2.1.3.7 Potential transformers (PT):
The lines in substations operate at high voltages. The measuring instruments
are designed for low value of voltages. Potential transformers are connected in
lines to supply measuring instruments and protective relays. These transformers
make the low voltage instruments suitable for measurement of high voltages.
2.1.3.8 Lightning arresters(LA):
Lightning arresters are the protective devices used for protection of
equipment from lightning strokes. They are located at the starting of the substation
and also provided near the transformer terminals.
2.1.3.9 Coupling capacitor:
A coupling capacitor is used in substations where communication is done by
AC power line. It offers very low impedance to high frequency carrier signal and
allows them to enter the line matching unit and blocks the low frequency signal.
2.1.3.10 Wave trap:
This equipment is installed in the substation for trapping the high frequency
communication signals sent on the line from remote substation and diverting them
to the telecom panel in the substation control room.
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2.1.4 The project data

This project shall include but not limited to execute Uptown Cairo 220/22 KV
GIS Substation, located in Zahra El-Mokattam.
2.1.5 Scope single line diagram
2.1.5.1 220 kV GIS Switchgear and Equipment:
The 220 kV switchgear shall be SF6 Gas insulated (GIS) indoor type, double
busbars with rated current 2000A, single breaker configuration and symmetrical
short circuit current 50 kA for one second, lightning impulse withstand voltage
1050 kVpeak and maximum rated voltage 245 KVrms.
It includes but not limited to the followings and according to the attached single
line diagram: -
• Double three single phase enclosure bus-bar GIS type with rated 2000A
to accommodate five (5) bays, plus space for one transformer bay and two
underground cables bays.

• Each bus-bar section shall include:

- One (1) three single phase maintenance GIS earthing switch.
- One (1) three single phase GIS inductive potential transformer
complete with its GIS disconnecting link and earthing switch.
- One (1) three single phase GIS longitudinal bus bar disconnecting
switch with rated current 2000 A to be used for bus-bar sectionalizes.
- One (1) three single phase GIS longitudinal disconnecting rated
current 2000 A with earthing switches for extension.

• One complete bay for bus coupler with rated current 2000A contains but not
limited to:
- One (1) three single phase GIS circuit breaker 2000A.
- Two (2) three single phase GIS disconnecting switches.
- Two (2) three single phase GIS maintenance earthing switches.
- Two (2) three single phase GIS current transformers.
- Local control panels.

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• Two complete transformer bays with rated current 1600A, each bay contains
but not limited to:
- One (1) three single phase GIS circuit breakers 1600A.
- Two (2) three single phase GIS disconnecting switches.
- Two (2) three single phase GIS maintenance earthing switches.
- One (1) three single phase GIS current transformers.
- One (1) three single phase bus ducts up to 220kV SF6 to air bushing
outside the GIS building.
- One (1) three single phase SF6 to air bushing at the end of the GIS
bus ducts.
- Local control panel.
• Two complete OHTL bays with rated current 1600A each bay contains but
not limited to:
- One (1) three single phase GIS circuit breaker, 1600A.
- Three (3) three single phase GIS disconnecting switches.
- Two (2) three single phase GIS maintenance earthing switches.
- One (1) three single phase GIS current transformers.
- One (1) three single phase high speed GIS earthing switches.
- One (1) three single phase bus ducts up to 220kV SF6 to air bushing
outside the GIS building.
- One (1) three single phase SF6 to air bushing at the end of the GIS
bus ducts.
- Local control panel.
2.1.5.2 220kV outdoor equipment:
• For OHTL bays, each bay shall contain:
- One (1) three single phase outdoor surge arrester.
- One (1) three single phase outdoor voltage transformers (1 coupling
capacitive voltage transformer + 2 capacitive voltage transformer), the
CCVT shall be erected on middle phase and shall be suitable for line
trap erection.
- One (1) line trap suitable to be erected on CCVT.

• For the main transformer bays, each bay shall contain:

- One (1) three single phase outdoor surge arrester.

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2.1.5.3 Supply, install and connect for 220k winding neutral point
equipment of the three phase power transformer:
- One (1) single phase outdoor current transformer.
- One (1) single phase108kV outdoor surge arrester.
- One (1) single phase 123kV outdoor disconnector switch.

2.1.5.4 Supply, install and connect for 22KV winding neutral point
equipment of the three phase power transformer:
- One (1) single phase outdoor current transformer.
- One (1) single phase 15kV outdoor surge arrester.
- One (1) single phase 22kV outdoor disconnector switch.
- One (1) resistance 650A, 20 ohm, 30 sec.
2.1.5.5 22 kV switchgear:
The 22 kV switchgear single busbar with rated current 2500 A. one breaker
configuration shall be metal clad of indoor type with symmetrical short circuit
current of 31.5 kA for three seconds, withstand lightning impulse voltage 125
kVpeak, rated voltage 24 kVms and include but not limited to the followings as
specified herein and according to the attached single line diagram:
• Three (3) sections single phase bus bars of rated current 2500 A.
• Three (3) bus tie cells 2500 A each equipped with SF6 or vacuum circuit
breakers of rated current 2500 A as specified.
• Three (3) bus rise cells 2500 A each equipped with SF6 or vacuum circuit
breaker of rated 2500 A as specified interlocked with related bus tie circuit
Breaker.
• Three (3) incoming feeder cells 2500 A each equipped with SF6 or vacuum
circuit breaker of rated current 2500 A.
• Thirty-three (33) outgoing feeder cells 800 A each equipped with SF6 or
vacuum circuit breaker of rated current 800 A.
• Two (2) auxiliary transformer cells 800 A each equipped with SF6 or
vacuum circuit breaker of rated current 800 A.
• Three (3) for capacitor bank cells 1250 A each equipped with SF6 circuit
breaker of rated 1250 A as specified in the relevant sections in addition to
capacitor bank section.
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• Three (3) measuring cell each one contains three single phase voltage
transformer provided with H.R.C fuses.
• Nine (9) single phase lightning arresters of 24 kV, 2.5 kJ/kV for the three
sections (three for each section)
• All required AC and DC cable connections.
• All control, measuring and low voltage cables between the 22kV switchgear
and the control room panels.
• Control, measuring metering and protection equipment as specified in
relevant sections and SLD.
• 22 kV measuring transducers
• All other materials, equipment, switches, steel structure, cables and works
that may be required for completion and proper commercial operation of 22
kV switchgear.

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2.1.6 Single Line diagram for 220/22 KV Substation

Figure 2.1 single line diagram of 220/22KV substation

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2.2 General Layout (GLO)

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2.2.1 Introduction
General Layout of substations is the most important design considerations as
a every primary design drawing and some secondary drawings depends on the
layout and the included rooms in the substation. This chapter presents
studying the different substation rooms and shows every room function and
its importance.
2.2.2 Substation Layout Arrangement
1- Outdoor Switchyard
• Incoming Lines
• Outgoing Lines
• Busbars
• Transformers
• Insulators
• Capacitor banks
• Circuit-breakers, isolators,
• Earthing switches, surge arresters, CTs,
• VTs, neutral grounding equipment.
• Station cars parking

2- Control Building
• Low voltage AC Switchgear.
• Medium voltage switchgear.
• AC/ DC Room
• SCADA panel’s location
• Control Panels, Protection Panel

3- Battery Room
• D.C. Batteries system
• Washing latrine

4- Mechanical, Electrical and Other Auxiliaries

• Auxiliary Transformers

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2.2.3 Important parameters and considerations for substation design

2.2.3.1 Environmental Conditions
NO. DESCRIPTION CAIRO
1 Pressure mb -annual mean 1013
2 Atmospheric temperature °𝐶
Max. mean daily 47
Min mean daily -5
Yearly mean 30
Ambient temperature 47
3 Relative humidity %
Average relative humidity 75
Daily mean 95
Max 100
Min 20
4 Rain fall max. mm/day 65
5 Wind Velocity (m/s)-max recorded 35
6 Wind pressure N/𝑚2 766
7 Soli Temperature at depth 1.5m 25
Table 2.3 Environmental Conditions

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2.2.4 Minimum Clearance

Table 2.4 Minimum Clearance

2.2.5 Factor of safety

Table 2.5 Factor of safety

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2.2.6 General Layout Design

2.2.6.1 Gantry Area

Figure 2.2 Gantry Area

2.2.6.2 GIS Building

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Figure 2.3 GIS Building

2.2.6.3 Transformer Area

Figure 2.4 Transformer Area

2.2.6.4 Main Road

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2.2.6.5 Capacitor Bank Area

Figure 2.5 Capacitor Banks Area

2.2.6.6 Control Building

Figure 2.6 Control Building 1

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2.2.6.6.1 Switchgear Room

Figure 2.7 Switchgear Room

2.2.6.7 Control Room

Figure 2.8 Control Room

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2.2.7 General Layout

Figure 2.9 General Layout

2.2.8 First Layout

Figure 2.10 First Layout

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CHAPTER 3 SHORT CIRCUIT CALCULATIONS

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3.1 Introduction
Short-Circuit Currents are currents that introduce large amounts of destructive
energy in the forms of heat and magnetic force into a power system. A short circuit
is sometimes called a fault. It is a specific kind of current that introduces a large
amount of energy into a power system. It can be in the form of heat or in the form
of magnetic force. Basically, it is a low-resistance path of energy that skips part of
a circuit and causes the bypassed part of the circuit to stop working. The reliability
and safety of electric power distribution systems depend on accurate and thorough
knowledge of short-circuit fault currents that can be present, and on the ability of
protective devices to satisfactorily interrupt these currents. Knowledge of the
computational methods of power system analysis is essential to engineers
responsible for planning, design, operation, and troubleshooting of distribution
systems. Short circuit currents impose the most serious general hazard to power
distribution system components and are the prime concerns in developing and
applying protection systems. Fortunately, short circuit currents are relatively easy
to calculate. The application of three or four fundamental concepts of circuit
analysis will derive the basic nature of short circuit currents. These concepts will
be stated and utilized in a step-by step development. The three-phase bolted short
circuit currents are the basic reference quantities in a system study. In all cases,
knowledge of the three-phase bolted fault value is wanted and needs to be singled
out for independent treatment. This will set the pattern to be used in other cases.

3.1.1 Causes of Short Circuit

• Overtemperatures due to excessively high overcurrents
• Disruptive discharges due to overvoltages
• Arcing due to moisture together with impure air, especially on insulators.

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• A fault with the insulation- if the circuit wire insulation is faulty, the current can
then pass to neutral wire, causing a surge in electricity and a short circuit. circuit
wire insulation can be negatively affected by age and use, as well as SC and nails,
and animals like rats.
• A fault with the appliance- when you plug an appliance into the circuit, it
becomes a circuit extension. And if the wiring is faulty, this can short the whole
circuit in your property
• A fault with the connections- a circuit needs strong connectors to keep the current
flowing. If the connector is loose, electricity will be able to pass to either neutral
wire, or a grounded part of the circuit, causing a short circuit.

3.1.2 Effects of Short Circuit

The consequences are variable depending on the type and the duration of the
fault, the point in the installation where the fault occurs and the short-circuit
power, Consequences include.

1- At the Fault Location

▪ Damage to insulation.
▪ Welding of conductors.
▪ Fire and danger to life

2- On the Faulty circuit

▪ Electrodynamic forces, resulting in deformation of the bus
bars, disconnection of cables.
▪ Excessive temperature rises due to an increase in Joule
losses, with the risk of damage to insulation.

3- On Other Circuits in the Network or Nearby

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▪ Voltage dips during the time required to clear the fault,

ranging from a few milliseconds to a few hundred
milliseconds.
▪ Shutdown of a part of the network, the extent of that part
depending on the design of the network and the
discrimination levels offered by the protection devices.
▪ Dynamic instability and/or the loss of machine
synchronization.

3.1.3 Important of Short-Circuit Calculations

Most of the failures on the power system leads to short-circuit fault and cause
heavy currents to flow in the system. The calculations of these short-circuit
currents are important for the following reasons.

a) A short-circuit on the power system is cleared by a Circuit Breaker

or a fuse. It is necessary, therefore, to know the maximum possible
values of short-circuit current so That switchgear of suitable rating
may be installed to interrupt them.
b) The magnitude of short-circuit current determines the setting and
sometimes the types and location of protective system.
c) The magnitude of short-circuit current determines the size of the
protective reactors which must be inserted in the system so that the
circuit breaker is able to withstand the fault current.
d) The calculation of short-circuit currents enables us to make proper
selection of the associated apparatus (e.g., bus bars, current
transformers etc.) so that they can withstand the forces that arise
due to the occurrence of short-circuits.

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3.2 Definitions

3.2.1 Terms and Definitions

3.2.1.1 Symmetrical short circuit current (𝐼𝑘 )

The r.m.s. value of the symmetrical alternating current (A.C) component of a

prospective short circuit current, taking no account of the direct current (D.C)
component.

3.2.1.2 Initial symmetrical short circuit current (𝐼𝑘 ′′)

The effective value (RMS) of the symmetrical short-circuit current at the

moment at which the short circuit arises, when the short-circuit impedance has its
value from the time zero.

3.2.1.3 Initial symmetrical short-circuit apparent power (𝑆′′𝐾 )

The short-circuit power represents a fictitious parameter. During the planning

of networks, the short-circuit power is a suitable characteristic number.

𝑆′′𝐾 = 𝐼𝑘′′ ∗ √3𝑈𝑛

3.2.1.4 Peak short-circuit current (𝑖𝑝 )

The largest possible momentary value of the short circuit occurring.

3.2.1.5 Decaying Component Direct current aperiodic component (𝐼𝑑𝑐 )

Average value of the upper and lower envelope curve of the short-circuit
current, which slowly decays to zero.

3.2.1.6 Steady-state short-circuit current (𝐼𝑘 )

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Effective value (r.m.s) of the initial symmetrical short-circuit current

remaining after the decay of all transient phenomena.

3.2.1.7 Symmetrical breaking current (𝐼𝑏 )

The effective value of the short-circuit current that flows through the contact
switch at the time of the first contact separation.

3.2.1.8 Nominal system voltage (𝑈𝑛 )

The (line-to-line) voltage by which a system is specified and to which certain

operating characteristics are referred.

3.2.1.9 Equivalent voltage source (𝑐𝑈𝑛 /√3)

The voltage at the position of the short circuit, which is transferred to the
positive-sequence system as the only effective voltage and is used for the
calculation of the short-circuit currents.

3.2.1.10 Voltage factor (c)

Ratio between the equivalent voltage source and the network voltage, Un,
divided by √ 3.

3.2.1.11 Far-from-generator short circuit

The value of the symmetrical alternating current (a.c.) periodic component

remains essentially constant.

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3.3 Short-Circuit Current Analysis

Figure (3.1) shows the time behavior of the short-circuit current for the
occurrence of far-from-generator (a) and near-to-generator (b) short circuits. The
DC. aperiodic component depends on the point in time at which the short circuit
occurs. For a near-to-generator short circuit, the sub transient and the transient
behaviors of the synchronous machines are important. Following the decay of all
transient phenomena, the steady state sets in.

Figure 3.1 time behavior of the short-circuit current

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3.3.1 Short-Circuit Path in the Positive-Sequence System

For the same external conductor voltages, a three-phase short circuit allows
three currents of the same magnitude to develop among the three conductors.
Therefore, it is only necessary to consider one conductor in further calculations.
Depending on the distance from the position of the short circuit from the generator,
it is necessary to consider near-to-generator and far-from-generator short circuits
separately. For far-from-generator and near-to-generator short circuits, the short-
circuit path can be represented by a mesh diagram with an AC. voltage source,
reactances X, and resistances R (Figure 3.2). Here, X and R replace all components
such as cables, conductors, transformers, generators, and motors

Figure 3.2 Equivalent circuit of the short-circuit current path in the positive-sequence system

The following differential equation can be used to describe the short-circuit

process.

𝑑𝑖𝑘
𝑖𝑘 . 𝑅𝑘 + 𝐿𝑘 = 𝑢̂ sin( 𝜔𝑡 + 𝜓)
𝑑𝑡

where 𝜓 is the phase angle at the point in time of the short circuit. The
inhomogeneous first-order differential equation can be solved by determining the
homogeneous solution 𝑖𝑘 and a particular solution 𝐼′′ 𝑘 .

𝑖𝑘 = 𝑖′′𝑘 + 𝑖𝑘−

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𝑳
The homogeneous solution, with the time constant 𝛕𝒈 = , yields the
𝑹
following.

−𝑢 𝑡⁄ sin( 𝜔𝑡−∅ )
τ𝑔 𝑘
𝑖𝑘 = 𝑒
√(𝑅2 + 𝑋 2)

For the particular solution, we obtain the following:

−𝑢 𝑡⁄ sin( 𝜔𝑡+𝜓−∅ )
τ𝑔 𝑘
𝑖′′𝑘 = 𝑒
√(𝑅2 + 𝑋 2 )

The total short-circuit current is composed of both components.

−𝑢 𝑡⁄ sin( 𝜔𝑡−∅ )
τ𝑔 𝑘
𝑖𝑘 = [sin( 𝜔𝑡 + 𝜓−∅𝑘 ) − 𝑒
√(𝑅2 + 𝑋 2 )

The phase angle of the short-circuit current (short-circuit angle) is then, in

accordance with the above equation,

𝑋 𝑋
∅𝑘 = arctan ( ) = tan−1
𝑅 𝑅
Figure 3.3 shows the switching processes of the short circuit. For the far-from-
generator short circuit, the short-circuit current is, therefore, made up of a constant
a.c. periodic component and the decaying d.c. aperiodic component. From the
simplified calculations, we can now reach the following conclusions.

I. The short-circuit current always has a decaying d.c. aperiodic component in

addition to the stationary a.c. periodic component.

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II. The magnitude of the short-circuit current depends on the operating angle of
the current. It reaches a maximum at 𝛾 =90∘ (purely inductive load).This
case serves as the basis for further calculations.
III. The short-circuit current is always inductive.

Figure 3.3 Switching processes of the short circuit

3.4 Classification of Short-Circuit Types

For a three-phase short circuit, three voltages at the position of the short
circuit are zero. The conductors are loaded symmetrically. Therefore, it is
sufficient to calculate only in the positive-sequence system. The two-phase short-
circuit current is less than that of the three-phase short circuit, but largely close to
synchronous machines. The single-phase short-circuit current occurs most
frequently in low-voltage (LV) networks with solid grounding. The double ground
connection occurs in networks with a free neutral point or with a ground fault
neutralizer grounded system.

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short circuits classified into two main types:

3.4.1 Symmetrical Fault

Symmetrical faults are relatively simple to analyze; however, they account for
very few actual faults. Only about 5% of faults are symmetrical. Asymmetrical
faults are more difficult to analyze, but they are the more common type of fault.

1. Three-Phase Fault
• connection of all conductors with or without simultaneous
contact to ground
• symmetrical loading of the three external conductors
• calculation only according to single phase.
2. Three-Phase to ground Fault.

3.4.2 Unsymmetrical Fault

1. Single Line to ground Fault (1L-G)

• very frequent occurrence in LV networks
2. Double Line to ground Fault (2L-G)
• in networks with an insulated neutral point or with a
suppression coil grounded system 𝐼′′𝑘𝐸𝐸 < 𝐼′′𝑘2𝐸 ..
3. Line to Line Fault (L-L)
• unsymmetrical loading
• all voltages are nonzero.
• coupling between external conductors
• I′′ k2 > I′′ k3

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Figure 3.4 Short Circuit types

3.5 Methods of Short-Circuit Calculation

The measurement or calculation of short-circuit current in LV networks on
final circuits is very simple. In meshed and extensive power plants, the calculation
is more difficult because of the short-circuit current of several partial short-circuit
currents in conductors and earth return.

The short-circuit currents in three-phase systems can be determined by three

different calculation procedures:

1- superposition method for a defined load flow case

𝑐.𝑈𝑛
2- calculating with the equivalent voltage source at the fault location
√2

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3- transient calculation.

3.5.1 Equivalent Voltage Source

Figure 3.5 Equivalent Voltage Source method

Figure 3.5 shows an example of the equivalent voltage source at the short-
circuit location F as the only active voltage of the system fed by a transformer with
or without an on-load tap changer. All other active voltages in the system are short-
circuited. Thus, the network feeder is represented by its internal impedance, 𝑍𝑄𝑡
transferred to the LV side of the transformer and the transformer by its impedance
referred to the LV side. The shunt admittances of the line, the transformer, and the
nonrotating loads are not considered. The impedances of the network feeder and
the transformer are converted to the LV side. The transformer is corrected with 𝐾𝑇 ,
which will be explained later. The voltage factor c (Table 2.1) will be described
briefly as follows: If there are no national standards, it seems adequate to choose a

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voltage factor c, according to Table 3.1, considering that the highest voltage in a
normal

Table 3.1 Voltage factor c, according to IEC 60909

(undisturbed) system does not differ on average, by more than

approximately +5% (some LV systems) or+10% (some high-voltage, HV, systems)
from the nominal system voltage 𝑈𝑛 .

1) The different voltage values depending on time and position.

2) The step changes of the transformer switch
3) The loads and capacitances in the calculation of the equivalent voltage
source can be neglected.
4) The sub transient behavior of generators and motors must be
considered.

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This method assumes the following conditions:

1) The passive loads and conductor capacitances can be neglected.

2) The step setting of the transformers need not be considered.
3) The excitation of the generators need not be considered.
4) The time and position dependence of the previous load (loading state)
of the network need not be considered.

3.6 Calculation Equations According (IEC 60909)

3.6.1 Impedance Equation

3.6.1.1 Network Feeder

In Figure (3.6) short circuit is fed from a network in which only the initial
symmetrical short-circuit current at the feeder connection point Q is known, then
the equivalent impedance 𝑍𝐾𝑛𝑒𝑡 of the network (positive sequence short-circuit
impedance) at the feeder connection point q should be determined by :

𝑐 ∗ 𝑈𝑛 𝑐 ∗ 𝑈𝑛 2
𝑍𝐾𝑛𝑒𝑡 = 𝐼𝑓 𝑆′′𝑛 𝑖𝑠 𝐾𝑛𝑜𝑤𝑛 → 𝑍𝐾𝑛𝑒𝑡 =
√3 ∗ 𝐼𝐾𝑛𝑒𝑡 𝑆′′𝑛

Figure 3.6 short circuit is fed from a network without Transformer.

If a Short Circuit according Figure (3.7) a short circuit is fed by a

transformer from a medium or high voltage network in which only the initial
symmetrical short-circuit current at the feeder connection point Q is known, then

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the positive-sequence equivalent short-circuits impedance 𝑍𝐾𝑛𝑒𝑡 referred to the

low-voltage side of the transformer is to be determined by:

𝑐 ∗ 𝑈𝑛 2 𝑈𝑛−𝐿𝑉 2
𝑍𝐾𝑛𝑒𝑡 = ∗( )
𝑆′′𝑛 𝑈𝑛−𝐻𝑉

Figure 3.7 short circuit is fed from a network with Transformer.

In the case of high-voltage feeders with nominal voltages above 35 KV fed

by overhead lines if no accurate value is known for the resistance 𝑅𝐾𝑛𝑒𝑡 of network
feeders, one may substitute:

𝑅𝐾𝑛𝑒𝑡 = 0.1 ∗ 𝑋𝐾𝑛𝑒𝑡

𝑋𝐾𝑛𝑒𝑡 = 0.955 ∗ 𝑍𝐾𝑛𝑒𝑡

3.6.1.2 Transformer Impedance

The impedance of the machine can be calculated with the nominal parameters
of the machine itself (rated voltage 𝑈𝑟𝑇 ; apparent power 𝑆𝑟𝑇 ; percentage voltage
drops 𝑈𝑘 ) by using the following formula:

𝑈𝑘 𝑈𝑟𝑇 2
𝑍𝑇𝑅 = ∗
100% 𝑆𝑟𝑇

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Rated
primary
5…20 30 60 110 220 400
voltage
in KV

𝑈𝑘 in % 3.5…8 6…9 7…10 9…12 10…14 10…16

Table 3.2 Typical values of impedance voltage drop of three-phase transformer.

3.6.2 Short Circuit Current Equation

3.6.2.1 Initial symmetrical short circuit current (𝐼𝑘 ′′)

𝑐 ∗ 𝑈𝑛
𝐼′′𝐾 =
√3 𝑍 𝐾

3.6.2.2 Peak short-circuit current (𝑖𝑝 )

𝑖𝑝 = 𝐾 ∗ √2 𝐼′′𝐾

Where K is a factor depending on the R / X and can be calculated

approximately using the following equation Figure (2-8)
𝑅
𝐾 = 1.02 + 0.98𝑒 −3𝑋

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Figure 3.8 X/R Ratio

3.6.2.3 Decaying Component Direct current aperiodic component (𝐼𝑑𝑐 )

𝑅
−2𝜋𝑓𝑡 𝑘
𝑖𝐷𝐶 = √2 ∗ 𝐼 ′′ 𝐾 ∗ 𝑒 𝑋𝑘

3.6.2.4 Steady-state short-circuit current (𝐼𝑘 )

𝐼𝐾 = 𝐼′′𝐾

3.6.3 Symmetrical breaking current (𝐼𝑏 )

𝐼𝑏 = 𝐼′′𝐾

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3.7 Short Circuit Calculation 220/22 kV GIS Substation

3.7.1 Short Circuit Calculation Using MATLAB

3.7.1.1 Substation Configuration (SLD)

Figure 3.9 SLD

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3.7.1.2 MATLAB Code

% Short Circuit Calculation According IEC 90609

clear all
close all
clc
Un=input('Un=...kV ') ; % Un Nominal System
Voltage(kV)
Sn=input('Sn=...MVASC ') ; % Initial Symmetrical Short
Circuit (MVA)
STr = input ('STr=...MVA '); % Rated Apparent Power
of Transformer (MVA)
UHV = input ('UHV=...kV '); % Rated High Voltage Side
(kV)
ULV = input ('ULV=...kV ') ;% Rated Low Voltage Side
(kV)
Uk= input ('Uk=...% '); %Typical values of impedance
voltage drop of three phase transformers From Tables.
URr = 0.05; %For transformers with ratings over 31.5
MVA, < 0.5 %.
t= input('t=... sec ');
Cmax= 1.1; Cmin= 1 ; % Voltage Factor
L = 20 % (km) ; %Transmission Line Length
rL= 0.04; %(Ohm/km)
x=0.3; %(ohm/km)
RL=rL*L ; X=x*L ;
ZTL= sqrt(RL^2 + X^2)
ZKnet= (Cmax * (Un)^2 )/Sn
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Xknet= 0.995*ZKnet
Rknet = 0.1*Xknet
ZTR= (Uk*ULV^2)/(100*STr) % Transformer Impedance
RTr= (URr*ULV^2)/(100*STr) % Transformer Res
XTr= sqrt(ZTR^2-RTr^2) % Transformer Reactance
%------------------------------------------------------
Zsc=(ZKnet+ZTL)/4
XR_Ratio=Xknet/Rknet
K=1.02+0.98*exp(-3*(1/XR_Ratio))
%------------------------------------------------------
Ik_cmax= (Cmax*Un)/(sqrt(3)*Zsc)
Ik_cmin= (Cmin*Un)/(sqrt(3)*Zsc)
%------------------------------------------------------
ip= sqrt(2)*K*Ik_cmax
iDc= sqrt(2)*Ik_cmax*exp(-2*pi*50*t*(1/XR_Ratio))
%------------------------------------------------------
% MVSG Short Circuit
Rcable = 0.0414; %(Ohm/km)
Lcable = 0.3295; %(mH/km)
Lenghtcable = 20; %(m)
XL_cable = 2*pi*50*Lcable*0.02/4;
R_cable = Rcable*0.02/4;
Zcable=sqrt((R_cable^2 +XL_cable^2))
ZscM= (ZKnet* (ULV/UHV)^2 )+ (ZTR+ Zcable)/3
Ik_MVSG_cmax= (Cmax*ULV)/(sqrt(3)*ZscM)
Ik_MVSG_cmin= (Cmin*ULV)/(sqrt(3)*ZscM)

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3.7.1.3 Input Data

Un=...kV 220

Sn=...MVASC 8000

STr=...MVA 75

UHV=...kV 220

ULV=...kV 22

Uk=...% 13

t=... sec 0.01

Figure 3.10 Input data (MATLAB)

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3.7.1.4 Output Data From MATLAB (SC Calculation)

L = 20

ZTL =6.0531

ZKnet =6.6550

Xknet =6.6217

Rknet =0.6622

ZTR =0.8389

RTr =0.0032

XTr =0.8389

Zsc =3.1770

XR_Ratio =10

K = 1.7460

Ik_cmax =43.9779

Ik_cmin =39.9799

ip =108.5910

iDc =45.4267

Zcable =0.5100

ZscM =0.5162

Ik_MVSG_cmax = 27.0671

Ik_MVSG_cmin =24.6064

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Quantity Equation Value Unit

ZTL √𝑅𝐿 2 + 𝑋 2 Ω
6.0531

𝑐 ∗ 𝑈𝑛 2
𝑍𝑘𝑛𝑒𝑡 𝑍𝐾𝑛𝑒𝑡 = Ω
𝑆′′𝑛 6.655

Ω
𝑋𝑘𝑛𝑒𝑡 𝑋𝐾𝑛𝑒𝑡 = 0.955 ∗ 𝑍𝐾𝑛𝑒𝑡 6.6217

𝑅𝑘𝑛𝑒𝑡 𝑅𝐾𝑛𝑒𝑡 = 0.1 ∗ 𝑋𝐾𝑛𝑒𝑡 0.6622 Ω

𝑅
K 1.02 + 0.98𝑒 −3𝑋 1.746
HV Busbar 220
𝑋𝑅_𝑅𝑎𝑡𝑖𝑜 - 10 -
(kV)

𝑰𝒌𝑪𝒎𝒂𝒙 𝒄 ∗ 𝑼𝒏 kA
𝑰′′𝑲 =
√ 𝟑 𝒁𝑲 43.978

𝐼𝑘𝐶𝑚𝑖𝑛 𝑐 ∗ 𝑈𝑛 kA
𝐼′′𝐾 =
√3 𝑍𝐾 39.98

𝑖𝑝 kA
𝐾 ∗ √2 𝐼′′𝐾 108.59

𝐼𝐷𝐶 𝑅 kA
′′ −2𝜋𝑓𝑡 𝑘
√2 ∗ 𝐼 ∗ 𝑒 𝑋𝑘 45.427
𝐾

Table 3.3 Output Data (MATLAB) for HV Busbar

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Quantity Equation Value Unit

𝑍𝐶𝑎𝑏𝑙𝑒 0.5176 Ω

𝑍𝑘𝑛𝑒𝑡 0.5187 Ω

𝑰𝒌𝑪𝒎𝒂𝒙 𝒄 ∗ 𝑼𝒏 kA
𝑰′′𝑲 =
√ 𝟑 𝒁𝑲 26.9353

LV Busbar 22 (kV)
𝐼𝑘𝐶𝑚𝑖𝑛 𝑐 ∗ 𝑈𝑛 kA
𝐼′′𝐾 =
√3 𝑍𝐾 24.4866

𝑖𝑝 kA
𝐾 ∗ √2 𝐼′′𝐾 108.59

𝐼𝐷𝐶 𝑅 kA
′′ −2𝜋𝑓𝑡 𝑘
√2 ∗ 𝐼 ∗ 𝑒 𝑋 𝑘 45.427
𝐾

Table 3.4 Output Data (MATLAB) for LV Busbar

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3.7.2 Short Circuit Calculation Using ETAP

3.7.2.1 Power Grid

Figure 3.11 Power Grid Data (ETAP)

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3.7.2.2 Transmission Line

Figure 3.12 Transmission Line Data (ETAP)

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3.8 Transformer

Figure 3.13 Transformer Data (ETAP)

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3.9 Cable

Figure 3.14 Cable Data From Elseewdy catalogue

Figure 3.15 Cable Data (ETAP)

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3.10 RUN SC According IEC 60909

Figure 3.16 Short Circuit Results (ETAP)

3.10.1 Report from ETAP

Figure 3.17 Short Circuit Report (ETAP)

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CHAPTER 4 EARTHING SYSTEM

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CHAPTER 4 Earthing System

4.1 Earthing system:

An earthing system is an important safety measure used in electrical substations
to protect people and equipment from electrical hazards so when it comes to work
in electrical places such as power plants, transmission lines, substations, distribution
network, etc. man is always in hazard way or at risk of getting shocked during a fault
of any kind (short circuit, insulation failure, overload, 3-phase fault, etc.) which
would cause damage to the equipment and most likely to cause death to the workers.

In a substation, the earthing system consists of a network of conductors and

electrodes that are designed to provide a low-resistance path to the earth thereby
preventing dangerous voltage buildup that could cause electric shock, equipment
damage, or fire. This is typically achieved by installing a grounding grid, which is a
network of interconnected copper or steel rods buried in the ground. The grounding
grid is connected to all metallic parts of the substation, including the equipment and
structures, using bonding conductors.

The earthing system also includes other components such as surge

arresters, lightning arresters, and neutral grounding resistors, which are designed to
protect the substation against lightning strikes and other transient overvoltage.

The design of an earthing system for a substation is critical to ensure the safety of
personnel and equipment. It must be designed to handle fault currents and lightning
strikes, and it must be installed and maintained in accordance with local codes and
standards which is IEEE. Regular testing and maintenance of the earthing system is
also essential to ensure its continued effectiveness.

So, it is required to make these work spaces less risky and as safer as possible to
allow the worker to do their job safely. Thus, there are number of things to apply to
ensure the safety of the workers such as:
_ Wearing safety gear (Helmet, Goggles, Gloves, and Boots).
_ Using better insulation materials. _ Earthing system.
_ Using high sensitivity protection devices.
In this chapter we will discuss earthing systems in substations, talk about its
importance, important measurements, and steps and show a study case.

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4.2 Definitions:
We have to keep in mind some important definitions to understand this chapter
which are:
• Earthing system: is circuitry which connects parts of the electric circuit with the
ground. It affects the magnitude and distribution of short circuit currents through
the system, and the effects it creates on equipment and people in the proximity of
the circuit.
• Grounding system: Comprises all interconnected grounding facilities in a
specific area.
• Ground: A conducting connection, whether intentional or accidental, by which
an electric circuit or equipment is connected to the earth or to some conducting
body of relatively large extent that serves in place of the earth.
• Grounded: A system, circuit, or apparatus provided with a ground(s) for the
purposes of establishing a ground return circuit and for maintaining its potential
at approximately the potential of earth.
• Ground current: A current flowing into or out of the earth or its equivalent
serving as a ground.
• Ground electrode: A conductor imbedded in the earth and used for collecting
ground current from or dissipating ground current into the earth.
• Ground mat: A solid metallic plate or a system of closely spaced bare
conductors that are connected to and often placed in shallow depths above a
ground grid or elsewhere at the earth’s surface, in order to obtain an extra
protective measure minimizing the danger of the exposure to high step or touch
voltages in a critical operating area or places that are frequently used by people.
• ground return circuit: A circuit in which the earth or an equivalent conducting
body is utilized to complete the circuit and allow current circulation from or to
its current source
• Ground potential rise (GPR): The maximum electrical potential that a
substation grounding grid may attain relative to a distant grounding point
assumed to be at the potential of remote earth. This voltage, GPR, is equal to the
maximum grid current times the grid resistance.
• Grounding grid: A system of horizontal ground electrodes that consists of a
number of interconnected, bare conductors buried in the earth, providing a
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common ground for electrical devices or metallic structures, usually in one

specific location.
• Grounding system: Comprises all interconnected grounding facilities in a
specific area.
• Mesh voltage: The maximum touch voltage within a mesh of a ground grid.
• Step voltage: The difference in surface potential experienced by a person
bridging a distance of 1 m with the feet without contacting any grounded object.
• Touch voltage: The potential difference between the ground potential rise (GPR)
and the surface potential at the point where a person is standing while at the same
time having a hand in contact with a grounded structure.
• Transferred voltage: A special case of the touch voltage where a voltage is
transferred into or out of the substation from or to a remote point external to the
substation site.
• Surface material: A material installed over the soil consisting of, but not limited
to, rock or crushed stone, asphalt, or man-made materials. The surfacing material,
depending on the resistivity of the material, may significantly impact the body
current for touch and step voltages involving the person’s feet.
• X/R ratio: Ratio of the system reactance to resistance. It is indicative of the rate
of decay of any dc offset. A large X/R ratio corresponds to a large time constant
and a slow rate of decay.

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4.3 Importance:
Earthing a substation is crucial for several reasons, including:

• Safety: The primary purpose of earthing a substation is to protect people and

equipment from electrical hazards. It provides a low-impedance path for fault
currents to flow to the earth, thereby preventing dangerous voltage buildup that
could cause electric shock, equipment damage, or fire.
• Operational reliability: Proper earthing of a substation ensures that equipment
operates safely and reliably. It helps to minimize the risk of equipment failure
due to electrical faults and reduces the likelihood of power outages caused by
faults or lightning strikes.
• Lightning protection: Earthing is an essential component of lightning
protection for a substation. A well-designed earthing system can help to mitigate
the effects of lightning strikes, which can cause significant damage to equipment
and disrupt power supply.
• Compliance with regulations: Earthing a substation is often required by local
electrical codes and regulations. Failure to comply with these regulations can
result in fines or legal action.
• Cost savings: Proper earthing of a substation can also result in cost savings in
the long run. It helps to prevent damage to equipment, which can be costly to
repair or replace. It also reduces the likelihood of power outages, which can result
in lost revenue for businesses and inconvenience for consumers.

_In case you are wondering why earthing of all things is what is used in
substations and in many fields too; Earthing is one of the main factors in electrical
systems to protect the humans from getting electric shock. Earthing is used in
almost every equipment.
And when designing a grounding system there are two main objectives:
• To provide means to carry electric currents into the earth under normal and
fault conditions without exceeding any operating and equipment limits or
adversely affecting continuity of service.
• To assure that a person in the vicinity of grounded facilities is not exposed to
the danger of critical electric shock.

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4.4 Designing steps:

The design is made according to IEEE 80(2000) and its title name is (Guide for
Safety in AC substation grounding).
The steps are:
1. Measurements Of Soil Resistivity
2. Determine The Surface Layer Derating Factor
3. Determine Minimum Earthing Conductor Size.
4. Calculate Tolerable Step and Touch Potential
5. Determine The Number of horizontal conductors and Their Design.
6. Determine The Resistance of The Grounding System
7. Determine Maximum Grid Current
8. Determine GPR. If Less Than Tolerable Touch Voltage, Done.
9. Otherwise: Calculate Actual Mesh and Step Voltages.
10. If Mesh and Step Voltage Are Below Tolerable Values, Done
The objective of designing: Make sure that step voltage and touch voltage are
within the safe range.
4.4.1 Measurements of Soil Resistivity
Soil resistivity is an important parameter that affects the performance of the AC
grounding system in a substation. The soil resistivity determines the earth
resistance of the grounding system, which in turn affects the touch and step
voltages during a fault condition. Therefore, measuring the soil resistivity at the
substation site is important to ensure that the grounding system is designed and
installed correctly.

Table 4.1 Basic range of soil resistivity

The soil resistivity is subject to variation, due to moisture, temperature, and

chemical content.
There are several methods for measuring soil resistivity in AC grounding
substations, including:
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• The Wenner method

The Wenner method is one of the most widely used methods for measuring
soil resistivity. It involves inserting four equally spaced electrodes into the
ground in a straight line and applying a small AC current to the outer
electrodes. The voltage drop between the inner electrodes is then measured
and used to calculate the soil resistivity.

Figure 4.1 (Wenner method)

Its equation:

where
ρa is the apparent resistivity of the soil in Ω·m
R is the measured resistance in Ω
a is the distance between adjacent electrodes in m
b is the depth of the electrodes in m

If b is small compared to a, as is the case of probes penetrating the ground only a

short distance, Equation can be reduced to
ρa = 2πaR
4.4.2 Determine the Surface Layer Derating Factor

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The use of a thin layer of high-resistivity material, such as gravel, on the

earth's surface above the ground grid is a common practice in electrical substations
to increase the contact resistance between the soil and the feet of persons in the
substation. This layer of material is often referred to as a "thin layer material" or
"surface material."
When the underlying soil has a lower resistivity than the surface material, the
addition of the surface material can significantly reduce the current through the body
by increasing the contact resistance between the earth and the feet. This reduction
effect for surface material resistivity greater than soil resistivity can be represented
by a factor Cs, which is less than 1.0.
The thickness of the layer of material is typically between 0.08 m to 0.15 m (3 to 6
inches), and the material used should have higher resistivity than the underlying soil.
Gravel is a common choice for this purpose, as it is readily available and has a
relatively high resistivity.
We will use this factor later when calculating the Touch and Step Voltage. The
correction factor Cs is equal to one if there is no layer on the surface, and it
becomes less than one in the presence of this thin layer.
This layer has many advantages, as it is considered a resistive conductor in series
with the human body, which means that the current through the body will decrease
and may become one-tenth of its value. This is the main advantage of this layer. It
also impedes the evaporation of water from the original soil, thus maintaining a low
value of soil resistance.
Its mathematical equation:

Where
ρs: the soil resistivity, in Ω-m
ρ: the thin layer material resistivity, in Ω-m
h s:the thin layer material thickness

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Table 4.2 typical surface material resistivity

4.4.3 Conductor sizing

One of the main objectives of the design process is to calculate the
appropriate cross-sectional area for each earthing electrode, as well as the number
of electrodes required. In this step, we will calculate the appropriate cross-sectional
area.
As is well known, the cross-sectional area of the conductor depends primarily on the
value of the short-circuit current and the natural current.
However, unlike ordinary cables, whose current-carrying capacity depends on the
insulation's ability to withstand the high temperature generated by the short circuit
before melting occurs, earthing electrodes do not have this limitation.
In summary, the maximum current-carrying capacity of earthing conductors is
determined by their ability to withstand heat, and the calculation of the conductor's
cross-sectional area is an essential step in the earthing design process. It is important
to consider the operating time of the protection devices to ensure the safe and reliable
operation of the earthing system.

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Its equation:

Where
I = the r.m.s. current in kA
Amm² = the conductor cross-section in mm2
K0 =1/ɑ0 or (1/ɑr)
Tm = the maximum allowable temperature in °C
Ta = the ambient temperature in °C
Tr = the reference temperature for material constants in °C
α0 = the thermal coefficient of resistivity at 0 °C in 1/°C
αr = the thermal coefficient of resistivity at reference temperature Tr in 1/°C
ρr = the resistivity of the ground conductor at reference temperature Tr in µΩ cm
tc = the duration of current in s
TCAP = the thermal capacity per unit volume from Table 1, in J/ (cm3°C)

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Table 4.3: material constants

Practical tests:
• The interruption time should not be less than half a second for safety.
• In some designs, the insulation melting temperature is considered, especially
when there are insulated parts in the earthing system, such as green and yellow
insulated wires. In this case, the temperature is not the melting temperature of
the earthing conductor, which can reach 1000 degrees Celsius, but it is
calculated as 200 degrees Celsius only. It is important to first confirm the
presence or absence of insulated conductors in the earthing system, as this can
affect the cross-sectional area of the conductor.

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4.4.4 Calculation of tolerable step voltage and touch voltage:

When an electrical fault occurs and the current cannot complete its circuit except
by returning through the ground, there is a risk of Ground Potential Rises (GPR)
which can cause an increase in the voltage of the ground in the area of the fault. This
means that anyone standing on the ground is at risk of electric shock due to the
voltage difference between their feet (Step Voltage) or between their body and the
ground (Touch Volt). The goal of designing an appropriate grounding network is to
dissipate the fault current deep into the ground, thereby avoiding GPR on the surface
and ensuring that the Step Voltage and Touch Volt remain within safe limits at the
substation.
The following equations provide approximate values for Step Voltage and Touch
Volt (note that they depend on the weight of the person, the type of soil and surface
layer, and the duration of the fault current before protection devices isolate it). It is
important to have a fast protection system to reduce these voltages to safe limits.
The values obtained from these equations ensure that the actual current flowing
through the human body remains within safe limits.
The equation of step voltage:
_For body weight of 50 kg…..
0.116
Estep50 = (1000 + 6 Cs * ρs)
√𝑡𝑠
_For body weight of 70 kg…..
0.157
Estep70 = (1000 + 6 Cs * ρs)
√𝑡𝑠

The equations of touch voltage:

_For body weight of 50 kg…..
0.116
Estep50 = (1000 + 1.5 Cs * ρs)
√𝑡𝑠
_For body weight of 70 kg…..
0.157
Estep70 = (1000 + 1.5 Cs * ρs)
√𝑡𝑠
Where; Estep is the step voltage in (V)
Etouch is the touch voltage in (V)
ρ
0.09(1− )
ρ𝑠
Cs is is the surface layer derating factor 𝐶𝑠 =
2ℎ𝑠 +0.09

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Rs is the resistivity of the surface material in (Ω·m)

ts is the duration of shock current in seconds.

Figure 4.2 (Touch potential and step potential)

The previous equations for step and touch voltages can be also written as:
𝑅𝑓
Etouch = (RB + ). IB , Estep = (RB + 2Rf). IB
2
And the 1000 in the previous equations represent the resistance of the human body.

4.4.5 Calculation of the number of conductors and the way to implement

them:
The distribution of voltage on the surface of the ground resulting from the flow
of fault current through the earth electrodes is called Surface Potential Distribution.
This distribution is better in a network consisting of several horizontal conductors,
including vertically buried electrodes.

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In the case of horizontal conductors (or the network), the voltage value that arises
on the surface of the ground between two points in the area near the grounded body
due to the flow of fault current is small.
Therefore, you will always find in substations that we use a
grounding network consisting of horizontal conductors in the
form of squares with a side length ranging from 3-6 meters,
while the side length in grounding transmission and generation
stations ranges from 10 to 20 meters. This network is placed
under the ground of the substation to ensure a low value of Step

Figure 4.3 (grounding grid)

Voltage and Touch Volt, as shown in the diagram. Note that all
of these conductors are buried horizontally under the ground surface by
approximately one or half a meter. Then, we add vertical electrodes either at the
intersection points on the perimeter of the shape or at all intersection points.

4.4.6 Calculation of the Earthing Grid Resistance:

We can calculate the grid resistance of the grid in Figure 4.2 using this equation:
1 1 1
Rg = ρ ( + (1 + ))
𝐿𝑇 √ 20𝐴 1+ℎ√20/𝐴

Where;
Rg is the earthing grid resistance with respect to remote earth (Ω)
ρ is the soil resistivity (Ω.m)
𝐿 𝑇 is the total length of buried conductors (m)
A is the total area occupied by earthing grid (m2)
h is the depth of earthing grid (m)

From the previous equation, the value of resistance depends on:

1. The total lengths of the horizontal conductors used in the network of squares
(previous step).
2. The total depth of the vertical electrodes (previous step).
3. The depth of burial.
4. The area covered by the Earthing network (known information).
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5. The specific resistance of the soil (step 4.4.1).

4.4.7 Calculation of Maximum Grid Current:

It’s the maximum current from the short circuit calculations, where the 3-ph
short circuit calculated from:
1.1∗ 𝑈𝑛
I3-ph =
√3∗ |𝑍1 |
But for single phase:
√3∗1.1∗ 𝑈𝑛 3∗ 𝐼3−𝑝ℎ
I1-ph = |𝑍1 +𝑍2 +𝑍3 |
=
2+ |𝑍0 /𝑍1 |
Note that:
The fault current can experience a decrease due to what is called a Surface factor
(Sf) or an increase due to a Distance factor (Df). Sf represents the current that may
not return through the earth network but instead returns partly through cable sheaths
or other means. Assuming Sf equals one is safer, but more expensive since it requires
more electrodes.
Figure 15-13 illustrates the concept of fault current distribution and how it returns
to its source, with some current returning through the towers and some through the
earth. The original fault current at the fault point was 2720 A, and it returned to
the neutral point through two paths:
• The first through tower grounding, where some current leaks and returns
through the overhead earth line, with a total current of 875 A (or it may return
through the Cable Sheath if the transmission is through underground cables).
This current does not cause GPR, and therefore, it is not considered in touch
and step voltage calculations.
• The second path for returning the fault current is through the earth directly
and then to the earthing electrodes at the station and from there to the neutral
point, with a current of 1121 A, as shown in the figure.

Figure 4.2 (Maximum Grid Current)

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And this one is the one that matters where it causes GPR:

GPR = IG RG

On the other hand, there is an additional part that can increase the current value due
to magnetic coupling, as well as the possibility of the presence of a DC component in
the fault, whose value depends on the Time Constant of the network and the location
of the fault, and this requires an approximation in its calculation. Generally, the ratio
of this addition is called the Decrement factor, Df, which is calculated from the
following equations:
IG = Ig Df
−2 𝑡𝑓
𝑇𝑎
Df = √1 + (1 − 𝑒 𝑇𝑎 )
𝑡𝑓

𝑋 1
Ta =
𝑅 2𝜋𝑓

Where;
IG represents only the second part of the fault current.
Ta is the dc time offset constant.
𝑡𝑓 is the duration of fault.

Note: for simplification we can assume Df = 1.25

4.4.8 Calculation of Ground Potential Rise (GPR):

When an electrical fault happens and the current flows into the ground. In such cases,
the ground potential around the fault area increases, and anyone standing on the
ground may be exposed to electric shock due to the voltage difference between their
feet or between their body and the ground. The goal of designing an appropriate
grounding network is to dissipate the fault current deep into the ground, thereby
avoiding GPR on the surface and ensuring that the Step Voltage and Touch
Volt remain within safe limits at the substation.

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GPR = IG Rg

Where;

Ig is maximum grid current (step 4.4.7)

Rg is the earthing grid resistance (step 4.4.6)
Note:
• If 4-GPR < Vstep, then the design is correct, and we have reached the end of
the design steps.
• However, if 4-GPR > Vstep, the design may be correct or incorrect, and the
final judgment depends on the detailed values of Step Voltage and Touch
Volt that we will calculate in the next step. Therefore, in some cases, we may
calculate the detailed values and find out that they are lower than the allowed
limits, even though we did not change anything in the design. This confirms
that a high GPR does not necessarily mean a design error.

4.4.9 Calculating Maximum Step voltage and Touch voltage:

The values calculated in the previous step represented safe values, while the
values calculated here represent the values resulting from the grounding network
that was designed in the previous steps. Of course, the values in the ninth step must
be lower than the values in the fourth step to ensure that the design is safe. Achieving
safe values for these voltages is the ultimate goal of designing the grounding
network, as we mentioned in the introduction.

_First the maximum touch voltage: (mesh voltage)

ρ𝑠 𝐾𝑚 𝐾𝑖 𝐼𝑔
Em =
𝐿𝑀
Where;
L M = L C + LR
ρ𝑠 is the soil resistivity (Ω.m)
Ig is the maximum grid current (A)
Km is the geometric spacing factor
Ki is the irregularity factor

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LM is the effective buried length of the grid (m).

LC is the total length of the conductor in the horizontal grid (m)
LR is the total length of all ground rods (m)

_Second the maximum step voltage:

ρ𝑠 𝐾𝑠 𝐾𝑖 𝐼𝑔
Es =
𝐿𝑆
Where;
LS = 0.75LC +0.85 LR
ρ𝑠 is the soil resistivity (Ω.m)
Ig is the maximum grid current (A)
Km is the geometric spacing factor
Ki is the irregularity factor
LM is the effective buried length of the grid (m)

The calculations here take into account, in addition to the fault current value, the
spacing between the horizontal conductors, the depth of the vertical electrodes, the
total lengths of the horizontally buried conductors, and the total lengths of the
vertical electrodes. The original reference can be consulted for more details on these
constants.
4.4.10 Comparing:
To make sure that the system is secured and safe the values calculated in step
4.4.8 must be less than values calculated in step 4.4.4 where:

Em < Etouch

Es < Estep

And if any error were to be discovered we can check the design with some new
adjustments:

1. Reducing the earth resistance by increasing the number of electrodes or by

increasing the cross-section area.
2. Reducing the fault current using the current limiter.
3. Improving the soil Resistivity using chemicals.
4. Improving the resistivity of the surface material.
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4.5 Designing of Substation Grounding Grid (Case study)

The substation given parameters needed to design the substation:

➢ The area of the grid is 109*63

➢ The short circuit current is 50kA
➢ Short current duration is 1 sec
➢ Fault duration is 1sec
➢ The soil resistivity is 60 Ω.m.
➢ Surface material resistivity is 8534.4 Ω.m.
Then we design with the following steps:

4.5.1 Soil Resistivity:

the soil resistivity is equal 60 Ω.m.

4.5.2 Surface Layer Derating Factor:

_ According to the giving the soil resistivity is 60 Ω.m. and the surface material
resistivity is 8534.4 Ω.m. the:
ρ
0.09(1− )
ρ𝑠
Cs = 1 -
2ℎ𝑠 +0.09

60
0.09(1− )
8534.4
Cs = 1 - = 0.918
2 ∗0.5 +0.09

4.5.3 Cross Sectional Area of Conductors:

𝑡𝑐 ∗𝑎𝑟∗ρ𝑟 ∗104
𝑇𝐶𝐴𝑃
Amin = 𝐼𝑓 √ 𝑇 −𝑇
ln(1+ 𝑚 𝑎 )
𝑘0 + 𝑇𝑎

Where;
𝑇𝑚 = 1083 °C
αr = 0.00393 °C-1

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ρ𝑟 = 1.72 µΩ.cm.
TCAP =3.422 jcm-3°C-1
tc = 1 sec
K0 = 234
Ta =40 °C
Then;
1∗𝑜.𝑜𝑜393∗1.72∗104
3√ 3.422
A = 50 ∗ 10 1083− 4𝑜 =177.4 mm2
ln(1+ )
234+40

4.5.4 Safe Limits of Step Voltage and Touch Voltage:

__For 70 Kg person:
0.157
Estep,70 =(1000 + 6 . Cs . ρ𝑠 )
√𝑡 𝑠
0.157
Etouch,70 = (1000 + 1.5 . Cs . ρ𝑠 )
√𝑡 𝑠

Where;
Cs = 0.918
ρ𝑠 =8534.4 Ω.m.(gravel)
tc = 1 sec
Then.

0.157
Estep,70 =(1000 + 6 *0.918*8534.4 ) = 7537.17 V
√1
0.157
Etouch,70 = (1000 + 1.5 *0.918 * 8534.4) = 2002.04 V
√1

4.5.5 Number of Conductors:

The number of conductor can be assumed depending of the area of the grid
which 109 * 63 m so the number of conductors in rows is…20… conductor and
in columns ….20. conductors.

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4.5.6 Grid Resistance:

1 1 1
Rg = ρ ( + (1 + ))
𝐿𝑡 √20𝐴 1+ℎ√20/𝐴

Where;
ρ = 60 Ω.m.
𝐿𝑡 = (20*109+20*63+20*10) =3640
h = 0.5 m
A = 109*63=6867 m2
Then;
1 1 1
Rg = 60( + (1 + )) = 0.336 Ω
3640 √20∗6867 1+0.5√20/6867

4.5.7 Maximum Grid Current:

Assuming the value of X/R ratio is 10 and the fault duration is 1 sec then
calculating the decrement factor:
𝑋 1 1
𝑇𝐴 = ∗ = 10* = 0.03
𝑅 2𝜋𝑓 2𝜋∗50

−2𝑡𝑓
−2∗1
𝑇𝐴 0.03
Df = √1 +
𝑡𝑓
(1 − 𝑒 𝑇𝐴
) = √1 + 1
(1 − 𝑒 10 ) = 1.016

We can calculate the IG from it:

IG = Ig Df = 50*1.016=50.8 KA
4.5.8 Ground Potential Rise (GPR):
GPR = IG * Rg = 50.8*103*0.336 = 17068.8 V

Therefore, GPR > Vstep, the design may be correct or incorrect, and the final
judgment depends on the detailed values of Step Voltage and Touch Volt that we
will calculate in the next step

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4.5.9 Calculate Actual Mesh and Step Voltages by using Etap

• Mesh voltage = 1408.2 v

• Tolerable Touch =2002.1 v

• Calculated Step Voltage =1832.8 v

• Tolerable Step voltage = 7537.3 v

Therefore , Tolerable Touch> Mesh voltage

And Tolerable Step voltage > Calculated Step Voltage

Then the design is correct

4.6 Designing of Substation Grounding Grid Using ETAP

❖ First the soil data is entered to the software as shown below:

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❖ Then inputs concerning the conductor, grid and the rod size:

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❖ Case study

❖ Result (summary and Alert)

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4.7 Secondary earthing

Secondary earthing means that all the equipment and metal parts in the
substation shall be earthed.

The grounding connection provided to substation equipment and structures

are classified into two categories:

• Safety grounding: for equipment grounding.

• System grounding: for neutral grounding.

Equipment requiring safety grounds.

1. steel structures and switch racks

To ensure safety in electrical systems, switch racks and steel structures

supporting equipment must be grounded using a bolted connection at two
diagonally opposite legs. Equipment mounted on the steel structure must also
have a separate grounding conductor to ensure proper grounding and safe flow
of fault currents to the earth. It's important to follow local regulations and design
requirements, and consulting with a qualified professional is recommended.

2. Fences and gates

If there is enough space, a perimeter ground conductor should be installed along

the fence line of the substation. The conductor should be placed 0.5 - 1.5 meters
beyond the fence and should be bonded to the fence at corner posts, gate posts,
and every alternate line post. Gates should also be bonded to the gate posts using
a flexible copper cable or braid.

3. Cables
Metallic cable sheath shall be effectively grounded to drain any induced
voltages to the ground
4. Control cables
The shield of control cables must be grounded at both ends to the grounding
grid. In certain situations, a separate conductor should be installed alongside
the control cable and connected to the two sheath ground points.

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5. Power Cables
Sheaths of single conductor power cables within a substation should be
grounded at one end, preferably at the source end, to reduce sheath current.
For longer cables, the sheath should be grounded at both ends and at each
splice. Power cable potheads should be case grounded via a mounting bolt,
and the grounding of sheaths for ring type CTs should not affect CT secondary
current.

6. Instrument Cables
instrument cables carrying milliamps, analog, or digital signals should have
their metallic screening grounded at one point using a PVC insulated
grounding wire. The grounding wire should be connected to a separate
instrument ground bar that is insulated from the cubicle ground.

7. signal Cables
All signal cables used in telemetering and communications shall have their
shield grounded at one end only to reduce interference from stray sources.
.
8. Cable Tray System
Cable tray system shall be grounded with bare copper conductor of
50 mm2 size at both ends and shall be bonded across gaps including
expansions gaps.

9. Control Building
The control building in a substation must be grounded using the same safety
criteria as the substation and should be encircled by a grounding conductor.

10.Control Cabinets, Operating Mechanism Housing, Box

All the metallic enclosures and bodies shall be grounded.

11.Metallic Conduits
All metallic conduits should be connected to grid at each manhole or at its
terminals using 50mm2 conductor.

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12.circuit Breakers and Disconnect Switches

All circuit breakers and disconnectors shall be grounded at two diagonally
opposed corners from two different points from the grid.

13.Operating Handles for Outdoor Switches

Large percentage of fatal accidents occur from voltage gradient associated
with manual operating handles.

14.Terminal Transmission Tower Grounding

The terminal transmission line towers at incoming entrance of the substation
shall be grounded from two diagonally opposed points.

15.Oil Tanks and Oil/Water Piping

All oil tanks shall be grounded at two points with bolted cable connections
from two different points to the grounding grid. Oil piping shall be grounded
at intervals of 12 m. Runs shorter than 12 m shall be grounded at least at two
points. Water piping shall be connected to the grounding system at all service
points. In addition, a copper conductor of adequate size, shall be connected to
the main water pipe from two separate points of the grounding grid.
16.Grounding of Lighting Equipment
Grounding of the lighting fixtures, lamp holders, lamps, receptacles and metal
poles supporting lighting fixtures shall be per IEC standard.

Equipment requiring both safety and system grounds.

1. Power Transformer Tanks

Power transformer tanks shall be safety grounded at two points diagonally
opposite to each other. These connections shall be made from two different
points of the grounding grid. A separate system ground shall be provided for
the neutral of the transformer by means of two stranded copper wires as the
ground grid conductor size.
The neutral grounding wires shall be insulated from the transformer tank by
support insulators mounted on the tank wall and shall be connected to the
grounding grid directly. Independently mounted radiator bank and XLPE
cable termination boxes shall be separately grounded at two diagonally
opposite locations.
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2. Instrument Transformers
Potential and current transformers shall be grounded at the grounding
terminals of CT & PT. The neutral point of the secondary connection of
CT&PT shall be grounded to the ground grid in the control/relay room to
reduce the transient over-voltages.

3. Surge Arrestor
surge arrestor with operation counter, the insulated lower end of the lightning
arrestor shall be connected to the operation counter with an insulated coated
copper conductor with cross section area not less than 50 mm2. The surge
arrestor ground terminal shall be connected to the ground grid via two
stranded copper conductors.
4. Shunt Capacitors and Reactors
Shunt capacitors and reactors are grounded when mounted on a metal
structure that is connected to the grounding grid.

5. Station Auxiliary Transformer

Auxiliary transformer tank shall be safety grounded at two different locations.

One system ground shall be directly connected to the neutral bushing of wye
connected windings that are to be solidly grounded.

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CHAPTER 5 Raceway

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5.1 Raceway:
Raceways are an important component in the design. A raceway (sometimes
referred to as a raceway system) is an enclosed conduit that forms a physical pathway
for electrical wiring. Raceways protect wires and cables from heat, humidity,
corrosion and general physical threats. The cable tracks located in the station is
starting from the GIS building, which contains the control and Protection cables and
the low voltage cables that should be transferred to the control rooms and AC/ DC
room, the path of these cables should be created, taking into consideration the cost
not to increase, the losses of information in communication cables and the length to
avoid the voltage drop, The medium voltage path must be created to enter in
MVSWGR in the control building , so we must know what are the methods used and
how to calculate them taking into account some considerations in mind.

5.1.1 Cable Trench:

Prior to the cable being laid, the cable trench must be dug and prepared
properly. This means that the trench must be of adequate size to allow for the cables
and ducting required. The trench width and depth also depend on the where the cable
trench is being dug. For instance, a cable being laid underneath a public footway will
not be laid as deep as one under arable land that is to be ploughed. When a trench is
to be dug, it should be sufficient to allow the installer to install the cables and ducting
at the correct depth for the cable being used. The cable should be installed within the
specified pulling dimensions and without damaging the cable sheaths. Cable trays
shall be fabricated from hot dip galvanized steel. Tray shall not sag more than 50
mm at midpoint between supports when loaded with cables. Space between supports
shall be according to the cable weight but not more than 2 meters.

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Figure 5.1 Cable Trench

5.1.1.1 Cable trays and Classification:

Cable Tray System. A unit or assembly of units or sections and associated

fittings forming a structural system used to securely fasten or support cables and
raceways. The cable tray is a wonderfully efficient tool used to manage all these
wires. With a grounded metal barrier along the centerline to separate power wiring
and data/communication cabling, a single, large cable tray installation is capable of
routing a large amount of wiring. It heads off the possibility of a disorganized mass
of conductors that are difficult to trace when changes must be made or faults located.
Classification of cable trays Cable trays are available in a wide variety of sizes,
styles. (including ladder, ventilated trough, ventilated channel, solid bottom and
similar structures) and materials, metallic or non-metallic. If made of conductive
material, the cable tray is one of the permitted types of equipment grounding
conductors.

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5.1.1.2 Ladder trays:

Ladder trays generally get used where there are larger bundles or heavier
cables. The ladder cable tray has two side rails connected by cross members, or
rungs. The rungs provide convenient anchors for tying down the cables.

Figure 5.2 Ladder tray

5.1.1.3 Perforated Cable Tray

A perforated cable tray consists of a bottom that has openings, and 60% of the
flat area is used to support the cables, placed inside the longitudinal side rails. These
trays are used for instrumentation and power cables. They are perfect for organizing
large volumes of industrial power cables. Perforated cable trays can be installed on
any surface and improve the cables’ useful life. Cable trays such as these provide
greater security since they isolate cables completely. With a perforated cable tray,
there is no buckling or hanging. Additionally, the perforated design of the tray
ensures adequate ventilation for the cables, so one can maintain adequate
temperatures in a closed environment space.

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Figure 5.3 Perforated Cable Tray

5.1.1.4 Solid Bottom Cable Tray (Duct)

A solid or smooth background tray consists of a background that has no

opening, placed within the longitudinal side rails. Designed to protect and support
cables, of all types, the carrier tray provides maximum protection. As a result, all
kinds of buckles and hangings can be avoided. In addition, they are mostly used in
pipes with small-capacity cables. These trays are designed to completely isolate
cables through a hermetic closure system, which helps to prevent the building up of
heat. Additionally, the characteristics of the solid-background carriers allow them to
function as electromagnetic shields, making them ideal for protecting control and
data cables from RFI interference. It is important to note that these trays accumulate
moisture. It is a problem that can be solved by performing perforations that allow
continuous draining, as long as the trays are not used as a shield.

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Figure 5.4 solid bottom cable tray

5.1.1.5 Basket-type Cable Tray (Wire Mesh):

The basket-type trays are welded wire structures that serve to support electrical
cables in an orderly way especially systems with cables of control and data. They
provide ideal support for data communication cables (coaxial and braided pairs).
These trays have the advantage of being versatile and can be used in many different
situations. Due to this, it is possible to work with accessories that vary horizontally
and vertically by cutting them as needed. They have other advantages, such as a light
structure and more open spaces. It provides better cooling, improves electrical
efficiency, and is fire-resistant. It can be used as a shield for cables.

Figure 5.5 Basket type Cable Tray

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5.1.2 Filling Ratio

Conduit Fill or Raceway fill is the percent of area inside the conduit taken up
by the cable. Another definition is the amount of a conduit's cross-sectional area
occupied, or filled, by a cable or multiple cables. Figure clear the definition. The fill
is based on the cable outside diameter (O.D.) and the conduit inside diameter (I.D.).

Figure 5.6 filled by multiple cables.

5.1.2.1 Conduit size for cable:

Conduits can be used for cable routing in floors, along walls, and for cable
entrance into the control house. Conduits are available in plastic, aluminum, and
steel. Each of these types may be used in control houses for wire containment to
convenience outlets, lighting fixtures, and other control house auxiliary power
equipment. A word before starting need to consider some factors when doing the
calculations:

• Number of cables in conduit

• Cross-section area of cables

• Number of bends in conduit

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• In many specifications asking the designer to enforcement special requirement such

in figure

Figure 5.7 specifications

5.1.2.2 Conduit material:

This depends on supplier company which material manufacturing according to

NFC or if have to do a specific type require in specification so can asking about it.

• Plastic conduit: is easily installed and is available in a variety of sizes. Take

adequate physical and thermal precautions when using plastic conduit to ensure
safe operation.
• Metallic conduits: of aluminum and steel are widely used as control house
cableways. Intermediate- and heavy-walled steel conduit provides excellent
physical protection.

To Find the conduit’s minimum space available according to NEC specifications:

• One wire: maximum fill is 53% of the space inside a conduit

• Two wires: maximum fill is 31%
• Three wires: maximum fill is 40% of the conduit’s total available space.
• More than three: maximum as three wires and that standard at Egypt.

5.1.2.3 Calculation the filling ratio of all cables inside conduit:

First of all, the calculation of conduit depends on supplier materials so at designing

should coordinate with one supplier which has good reputation in work labor. From
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supplier data can get each cable Nominal External diameter of cable and conduit
diameter. So, to calculate everything in the following:

• Get all cable size required for GIS panels which that coordinate with protection
engineer or the supplier of GIS can send excel sheets for all panels requirement,
but this is not recommended because maybe specification require special requests
for the substation.
• Calculate total area for conduit and cable to use it in filling equation.
• According to NEC should have 25% as spare in conduit and the conduit filling
don’t exceeds 40%.
• After that calculate total use sleeves required increase some sleeves as spare for
any reason lead to damage any conduit.

Area of cable = Filling ratio ∗ area of conduit

πD2 cable πD2 conduit

= Filling ratio ∗
4 4

D2 cable
Filling ratio = 2
D conduit

The following table includes the calculations of Filling ratio for GIS building
opening sleeves.

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Figure 5.8 calculations of Filling ratio

And for cable trays filling ratio we have the same method of conduit sizing but in
many specifications have a special require in the project technical as in figure

Figure 5.9 filling ratio specifications

5.1.3 Duct Bank

Duct banks are groups of conduits designed to protect and consolidate cabling
to and from buildings. In a duct bank, data and electrical cables are laid out within
PVC conduits that are bundled together; these groupings of conduit are protected by
concrete and metal casings. Duct banks are often buried, allowing contractors to
consolidate the wiring for a building into centralized underground paths.

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Figure 5.10 Duct Bank

This construction method is designed to protect the cabling outside of the building
and consolidate it in one area, but not only protect the enclosed cables from damage
they also consolidate and conceal the building's series of wires. Bundling cables with
a duct bank also streamlines future construction projects because the cables are
consolidated and bundled to create a clear passageway. This consolidation allows
property owners to upgrade or repair existing wiring without undergoing lengthy
excavation projects. Duct banks are also useful for installing cabling underneath
roads, parking lots and other areas with existing structures. Duct banks also allow
property owners to replace, upgrade or repair existing underground wiring without
excavating the entire length of the lines.

5.1.4 Spacing between conductor

Values given are averages for the cable types and range of conductor sizes
considered. Single conductor cables can be installed in a cable tray cabled together,
Where the cables are installed according to Elsewedy Electric.

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Figure 5.11 Spacing between conductor

Diameter of 630Sq.mm Cable is equal to 60 mm2

Figure 5.12 Diameter of 630Sq.mm Cable

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Figure 5.13 Cable Trench

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CHAPTER 6 Overvoltage Protection

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6.1 Introduction
Overvoltage protection is a critical aspect of substation design and operation.
Substations are key components of electrical power systems, where they serve as
points of connection between different parts of the power grid, including
transmission lines, distribution networks, and customer facilities.

Overvoltage events can occur in substations due to a variety of factors, including

lightning strikes, switching operations, resonance and equipment failures. These
events can result in voltage spikes that exceed the normal operating range of the
power system, which can damage equipment and cause disruptions to the power
supply.

To prevent overvoltage events from damaging substation equipment and causing

power outages, various types of overvoltage protection devices are typically
installed in substations. These devices may include surge arresters, circuit breakers,
and other protective devices that are designed to detect and limit the effects of
overvoltage events.

Effective overvoltage protection requires careful planning and design, as well as

ongoing maintenance and testing to ensure that protective devices are functioning
properly. Substation engineers and operators must also be trained to recognize and
respond to overvoltage events to minimize the risk of equipment damage and power
disruptions.

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6.2 Causes of Overvoltage

Overvoltage events can occur in substations due to internal or external faults.
6.2.1 Internal faults
• Faults
• Switching operations

Switching operations can involve the opening or closing of circuit breakers,

disconnect switches, and other devices that control the flow of electrical energy. It
can have significant impacts on the power system, overvoltage and other
disturbances that can affect the operation of equipment and cause damage to it.

• Resonance

Resonance can occur when there is an inductor and capacitor in parallel, which
creates a resonant circuit. When an AC voltage is applied to this circuit, the inductor
and capacitor store energy and release it back and forth. If the frequency of
the applied voltage matches the natural frequency of the circuit, the energy stored in
the circuit builds up and can cause the voltage in the circuit to increase beyond the
expected or rated voltage.

6.2.2 External faults

• Lightning

Lightning is a natural phenomenon that occurs when there is a large buildup of

electric charge within a cloud or between a cloud and the ground or a cloud to cloud.
This buildup of electric charge can result from the separation of positive and negative
charges within the cloud, as well as the movement of these charges due to the strong
updrafts and downdrafts within the cloud.

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When the electric charge within the cloud or between the cloud and the ground
becomes large enough, it can create an electric discharge which causes damage to
buildings, starting fires, and injuring or killing people.

6.3 Lightning Protection System (LPS)

A lightning protection system is a collection of devices and equipment designed
to protect living beings, buildings, structures, and major equipments from the
damaging effects of lightning strikes. Lightning protection systems are designed to
intercept, conduct, and discharge lightning strikes safely to the ground, preventing
damage to the structure and its occupants. Also, (LPS) is developed to improve the
reliability of the system.

6.3.1 LPS Components

• Surge arrestor
• Lightning mast

A lightning mast, also known as a lightning rod or air terminal, is a tall, pointed
metal rod or object mounted on the roof or other high points of a building or structure
as part of a lightning protection system. The lightning mast is designed to attract
lightning strikes and provide a low-resistance path for the lightning current to flow
to the ground, thereby protecting the building or structure and its occupants from the
damaging effects of lightning strikes.

Lightning masts are typically made of conductive metals such as copper, aluminum,
or steel, and are designed to be taller than the surrounding objects to increase their
effectiveness in attracting lightning strikes. They are installed at regular intervals
around the perimeter of the building or structure, and are connected to a network of
conductors and grounding electrodes that provide a low-resistance path for the
lightning current to flow safely to the ground.

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• Copper wire

Copper wire is often used as the main conductor to connect the lightning rods or
air terminals to the grounding system. The wire is typically sized based on the
expected lightning current and voltage levels, and is installed in a straight path with
minimal bends or loops to minimize the resistance and voltage drop along the
conductor.

• Square wire clamp

Square wire clamps are typically made of corrosion-resistant materials such as

copper, brass, or stainless steel, and are designed to provide a secure and reliable
connection between the conductors. They are available in a range of sizes and
configurations to accommodate different conductor sizes and shapes. They can be
designed for use with both solid and stranded conductors.

• Down conductors

A down conductor, also known as a down lead or a lightning conductor cable, is

an essential component of a lightning protection system that provides a low-
resistance path for the lightning current to flow safely from the lightning rod or air
terminal to the grounding system. The down conductor is typically a heavy gauge
copper wire or cable that is installed vertically down the side of the building or
structure and connected to the lightning rod or air terminal at the top and the
grounding system at the bottom. It is designed to withstand the high current and
voltage levels of a lightning strike without overheating or breaking.

The size and length of the down conductor is determined by the expected lightning
current and voltage levels, the height of the building or structure, and the distance to
the grounding system. The down conductor must be installed in a straight path with

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minimal bends or loops to minimize the resistance and voltage drop along the
conductor.

• Disconnecting link
A disconnecting link, also known as a disconnect switch or isolator, is a device
used in a lightning protection system to isolate a section of the system from the rest
of the system for maintenance, repair, or replacement. The disconnecting link is
typically installed in the down conductor or other conductors of the lightning
protection system, and is designed to provide a safe and reliable means of
disconnecting the lightning protection system from the power supply.

The disconnecting link is often used in conjunction with other components of the
lightning protection system, such as surge protectors and grounding electrodes, to
provide a comprehensive system for protecting the building or structure from
lightning strikes. When maintenance or repairs are required, the disconnecting link
can be opened to isolate the lightning protection system from the power supply,
allowing work to be performed safely and without risk of electrical shock or damage
to equipment. It can be manual or automatic, and can be operated either locally or
remotely.

6.3.2 LPS Design Methods

There are several design methods that can be used in a lightning protection
system. Here are three main methods:

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6.3.2.1 Fixed Angles Method

This design method is used to determine the placement of air terminals
or lightning rods on a structure. The method is based on the concept that lightning
will strike the highest point in a given area. A protective angle (∝) is calculated based
on the height of the structure and the distance between air terminals or masts.

• Steps for calculation

1. Get the mast height (h)
2. Intersect it with the class-level curve
3. Get the protective angle (∝)

Figure 6.1 Fixed angles for masts (IEEE-998)

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Figure 6.2 Fixed angles curve for masts (IEEE-998)

Class of lightning protection system is obtained from risk assessment, usually taken
class three in Egypt.

The perfect protective angle is 45 degree.

6.3.2.2 Empirical Curves Method

• Steps for calculation
1. Get the mast height (h)
2. Get the height of the object to be protected (d)
3. Subtract the height of the object to be protected from the mast’s height (y)
4. Intersect (y) with the class-level curve
5. Get the max distance to be protected (x)

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Figure 6.3 Empirical curve for masts and objects (IEEE-998)

6.3.2.3 Rolling sphere method

The concept of this design method is that an imaginary sphere is being rolled
over the building, masts, or wires with radius (S) which is equal 46 meters. Any
object under the curve of sphere is being protected safely, if the object touches the
sphere or goes inside it that means that the object is in the risk of being struck by
lightning. The figures shown illustrates this concept,z

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Figure 6.4 Principle of Rolling Sphere Method (IEEE-998)

Figure 6.5 Rolling Sphere Over an Object (NFPA-780)

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The following table shows the maximum value of rolling sphere radius
according to the class-level,

Class of LPS Rolling sphere radius (m)

I 20
II 30
III 45
IV 60
Table 6.1 Maximum values of rolling sphere radius (IEC-62305-3)

To calculate the radius of protection and overlapping protection zone this equations
are being used,

• Radius of protection zone

𝑟 = √𝑆 2 − (𝑆 − ℎ𝑚 )2 − √𝑆 2 − (𝑆 − ℎ𝑒 )2 (ℎ𝑚 < 𝑆)

𝑟 = √𝑆 2 − √𝑆 2 − (𝑆 − ℎ𝑒 )2 (ℎ𝑚 ≥ 𝑆)

Where,

𝑟 : Radius of protection zone

𝑆 : Sphere radius

ℎ𝑚 : Height of lightning rod from ground level

ℎ𝑒 : Height of object to be protected from ground level

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• Radius of overlapping protection zone

𝑟 = √𝑆 2 − (𝑆 − ℎ𝑒 )2

𝑟 : Radius of protection zone

𝑆 : Sphere radius

ℎ𝑒 : Height of object to be protected from ground level

6.3.3 LPS Calculations

Rolling sphere method is used to design the lightning protection system for this
substation project and this figures is a cut sheet from sample of the manual
calculations and appliance on the substation building using AUTOCAD.

Figure 6.6 Manual Calculations of GIS Building

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Figure 6.7 Protected GIS Building

Figure 6.8 Zoomed-in Protected GIS Building

Name Radius of protection (m) Radius of overlapping (m)

Zone 1 220KV GIS Building 1.59 30.05
Zone 2 220KV Gantry 11.47 24.53
Zone 3 Firewall 1.76 28.28
Zone 4 Transformer 11.4 18.635
Control Building and
Zone 5 4.02 24.87
SWG Room
Zone 6 Capacitor Bank 12.73 16.15
Zone 7 Guard Room 3.4 16.41
Table 6.2 Final results of the manual calculations for all protection zones

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6.4 Metal Oxide Surge Arrester (MOSA)

6.4.1 Introduction

Surge arresters are installed in substations and in transmission lines with the
purpose of limiting both lightning and switching induced overvoltages to a specified
protection level, which is, in principle, below the withstand voltage of the equipment
in order to protect it from excessive overvoltages. The ideal surge arrester would
have a nonlinear voltage and current characteristic that starts to conduct at a specified
voltage level (switch-on), keeping a certain margin above its rated voltage, holds the
specified voltage level without variation for the duration of the overvoltage for
expected lifetime, and then ceases to conduct as soon as the voltage across the surge
arrester returns to a value below the specified voltage level (switch-off). Therefore,
surge arresters are fundamentally required to absorb the energy that is associated
with the overvoltages. We will talk about the metal oxide surge arrester (MOSA).
MOSA is often placed at the terminals of power transformers, at both ends of the
bus terminals, and at both ends of transmission lines to mitigate the overvoltage
levels imposed on equipment

6.4.2 Construction

Figure 6.9 shows the cross section of the design of a porcelain-housed unit of a
MOSA. The MO resister column and its supporting construction form the active part
of the arrester. The column consists of individually stacked MO resistors, almost
always cylindrical in shape as shown in Fig. 6.10. The resistor diameter determines
the energy absorption and current carrying capability. Diameters vary from
approximately 30 mm for distribution up to 100 mm and more for higher voltages.

When a MOSA has a length from 1.5 m to 2 m and higher, a grading ring is

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required. This is essential in controlling the voltage distribution from the top to the

bottom. This is unfavorably influenced by the earth capacitances that affect the

arrester. If the grading ring is not in place, the top, or high-voltage end, would be

stressed considerably more than the earthed end of the arrester.

Figure 6.9 Construction of metal oxide surge arrester (MOSA)

Figure 6.10 Metal oxide resistor disks

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6.4.3 Operation
Surge arresters are generally connected in parallel with the protected equipment
and are subjected to the system voltage under normal operating conditions.
The voltage and current (V-I) characteristic of a typical metal oxide surge arrester
(MOSA) shows three distinctive regions: (I) MOSA can leak a small capacitive
current at continuous operating voltage levels up to the rated voltage; (II) MOSA
starts to conduct and the current increases rapidly with a slight voltage increase
showing a flat V-I characteristic in the breakdown region; (III) then the MOSA
increases voltage for large currents.

A metal oxide surge arrester is composed of many microscopic junctions of metal

oxide grains that turn on and off in microseconds to create a current path from the
top terminal to the earth terminal of the arrester. It can be regarded as a very fast-
acting electronic switch, which is opened at operating voltages and closed at
switching and lightning overvoltages. An important parameter of surge arresters is
the switching impulse protection level (SIPL), defined as the maximum permissible
peak voltage on the terminals of a surge arrester subjected to switching impulses
under specific conditions.

In order to reduce the power consumed by a metal oxide arrester during nominal
operation at system voltage, the continuous operating voltage of the arrester has to
be chosen such that the peak value of the resistive-current component is well below
1 mA and the capacitive-current component is dominant. This means that the voltage
distribution at operating voltage is capacitive and is thus influenced by stray
capacitance. The voltage-current characteristic of the metal oxide material offers the
nonlinearity necessary to fulfill the mutually contradicting requirements of an
adequate protection level at overvoltages and low current, i.e., low energy

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dissipation, at the system operating voltage. Metal oxide surge arresters are suitable
for protection against switching overvoltages at all operating voltages.

Porcelain-housed metal oxide surge arresters were used for performance satisfaction,
it is important that the units are hermetically sealed for the lifetime of the arrester
disks. The sealing arrangement at each end of the arrester consists of a stainless steel
plate with a rubber gasket. This plate exerts continuous pressure on the gasket,
against the surface of the insulator. It also serves to fix the column of the metal oxide
disks in place by springs. The sealing plate is designed to act as an overpressure
relief system. Should the arrester be stressed in excess of its design capability, an
internal arc is established. The ionized gases cause a rapid increase of the internal
pressure, which in turn causes the sealing plate to open and the gases to flow out
through venting ducts. Since the ducts are directed toward each other, it results in an
external arc, thus relieving the internal pressure and preventing a violent shattering
of the insulator.

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6.4.4 ZnO Surge Arrester

The microstructure of the metal oxide material consists of a mixture of ZnO
grains with granular layers of additives, the combination which is pressed into a disk
shape which has low resistivity, thus making it more conductive. The voltage-current
characteristic of the resistive component of the microstructure is purely dependent
on the electric field distribution across the disk. The voltage drop across the resistive
component of the ZnO grains in the structure is much higher under high electric field
scenarios than in the low electric field scenarios. Figure 6.11

Figure 6.11 Microstructure of MOSA disk element (ZnO, Bi2O3)

The choice of material by the arrester manufacturer is very important as it has a

direct impact on the energy dissipation in the MOSA. This peak value of the resistive
component of the current is usually low due to high resistance and that the small
capacitive component is predominant. Figure 6-12

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Figure 6.12 Equivalent circuit of MOSA element

When the current through the metal oxide varistor remains capacitive, the voltage
across the varistor elements is determined by their capacitance and thus influenced
by stray capacitances. Stray capacitances to earth cause a deviation from the linear
axial voltage distribution with higher voltage stress of the upper elements in the
arresters. This deviation is influenced by the physical parameter of the arrester such
as height, number, and length of arrester units and grading rings. With increasing
varistor temperature, the ohmic current component of the varistor contributes to a
more linear voltage distribution in the arrester. Insertion of grading rings as a passive
measure to improve the voltage distribution is the most effective.

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CHAPTER 7 Switching devices

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7.1 Puffer Type SF6 Circuit Breaker:

In power systems, circuit breakers are used to switch electrical equipment and
networks under normal and fault conditions. The primary function of a circuit
breaker is to interrupt the flow of current (load or short circuit) by opening its
contacts and thereby isolating the switched parts of the system. The design and
working of a circuit breaker depend on its application and voltage rating. SF6 circuit
breakers are normally used for high voltage systems (> 72 kV).

7.1.1 Construction
Such SF6 circuit breaker has a fixed contact and moving contact. The moving
contact is hollow from inside having a cylinder that stores compressed SF6 gas as
shown in figure (7.1). The tip of the moving contact is designed in such a way to
form a nozzle that increases the speed of the gas when it passes through it. The fixed
contact is designed in such a way when it is in the closed position, it blocks the flow
of SF6 gas. When the contacts separate, the path for gas flow is opened which
releases a blast of SF6 gas. It has the same working operation as an air blast circuit
breaker except the gas is recombined, compressed and stored in the gas cylinder
again. Which makes it very complex and quite expensive gas system is required for
operation.

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Figure 7.1. Construction of Puffer Type CB Interrupter.

From FUJI Catalogue:

Figure 7.2 SF6 CB Construction.

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7.1.2 Working Principle

7.1.2.1 Normal Condition
In the normal condition, the circuit breaker contacts are closed and current
flows from one contact carrier to the other via the main contacts and the
sliding puffer cylinder.

7.1.2.2 Circuit Breaker Opening Operation

When the circuit breaker control panel receives an opening command (to clear
a fault or disconnect part of a network), it sends a signal to the trip coil of the
mechanical operating mechanism, which in turn releases the latch holding the
charged opening spring. As the opening spring discharges, it pulls the drive
rod (connected to the interrupter) in a linear direction, which causes the moving
contacts and puffer cylinder to move downwards.

The movement of the puffer cylinder against the stationary piston leads to a decrease
in the puffer cylinder’s internal volume, which causes compression of the SF6 gas
inside the cylinder. Due to contact overlap, gas compression starts before any
contacts open. As the downward movement continues, the main contacts separate
and the current commutates to the arcing contacts which are still in the closed
position (due to their physically longer construction). During the course of further
opening, the arcing contacts start to separate and an arc is established between them.

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Figure 7.3. Operation of a Puffer Type SF6 Circuit Breaker.

As the arc flows it blocks the flow of SF 6 gas through the nozzle to some extent.
Thus, the gas pressure in the puffer cylinder continues to increase. When the
sinusoidal current waveform approaches zero, the arc becomes relatively weak and
the pressurized SF6 gas inside the puffer cylinder flows axially (through nozzle) over
the arc length. This blast of SF6 gas removes the thermal energy in the contact gap
and reduces the degree of ionization (electrical conductivity) such that the arc is
extinguished.

Figure 7.4. Current and Voltage during Fault Clearing.

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When the arc is interrupted, transient recovery voltage (TRV) starts to appear across
the contacts as shown in figure above the opening speed of the circuit breaker
contacts should be fast enough to create an adequate contact separation distance to
withstand this voltage stress. In case the contact gap’s dielectric strength is lower
than TRV stress, the arc will be re-established in a phenomenon which is commonly
called circuit breaker re-ignition or re-strike.

7.1.2.3 Circuit Breaker Closing Operation

During the circuit breaker closing sequence, the closing coil releases the energy
of the closing spring which causes the contacts to move towards each other,
ultimately bringing them to their normal closed position. At the same time, SF6 gas
is redrawn into the puffer cylinder making the circuit breaker ready for the next
operation.

Whilst closing, a circuit breaker can sometimes experience an event known as pre-
strike. As the contacts move towards each other during closing, the contact gap’s
dielectric strength decreases. At some point, the voltage stress across the contact gap
exceeds its dielectric strength, thus producing a ‘pre-strike ‘arc which bridges the
contacts.

7.1.3 Advantages of SF6 puffer type circuit breakers

The advantages of SF6 puffer type circuit breakers in GIS are:
• Compact design - SF6 is an ideal gas for GIS as it has high dielectric strength,
which allows for compact designs.
• High reliability - SF6 puffer type circuit breakers are highly reliable as they
have a self-aligning nozzle system, which ensures consistent performance.
• Low maintenance - The SF6 gas used in the circuit breaker is self-
regenerating, which means that it does not need to be refilled.

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7.1.4 Disadvantages of SF6 puffer type circuit breakers

The disadvantages of SF6 puffer type circuit breakers in GIS are:
• The SF6 gas is identified as a greenhouse gas.
• SF6 is an expensive gas so these circuit breakers are costly.
• It requires special transportation and maintaining the quality of gas.
• Recombination and reconditioning of the SF6 gas require additional
equipment.

7.1.5 Nameplate Details of SF6 Circuit Breaker

In most of the countries high & extra high voltage circuit breakers are
manufactured based on the IEC standard, i.e., IEC 62271-100. Parameters
mentioned on the nameplate of circuit breaker are also in line with the IEC 62271-
100. As per IEC, few parameters are mandatory, some are condition based, and some
of them are completely optional. In this chapter, we’ll look at the all parameters
mentioned on nameplate of SF6 circuit breaker which is shown in table below.

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SIEMENS
Year of Manufacturing/ No.
Type 3AP1FI
2006/IND/07/2610
Rated voltage U 245KV

Rated lightning impulse withstand voltage Uimp 1.2/50 1050𝐾𝑉𝑃

Rated power frequency withstand voltage Ud 460KV

Rated frequency f 50HZ

Rated normal current In 1600A

Rated short circuit breaking current Isc 50KA

Rated short circuit duration t 1sec

First pole to clear factor 1.3

Rated operating sequence O-0.3s-CO-3min-CO

Rated pressure of SF6 at +20˚c (gauge) 6 bar

Weight of SF6 filling Approx 22 kg

Weight including SF6 (Excluding structure) Approx 3000 kg

Nominal supply voltage of auxiliary circuits

a) Control voltage DC 220 V

b) Operating mechanism voltage AC 240 V

In line with IEC 62271-100

MADE IN INDIA

Table 7.1 Nameplate of SF6 Circuit Breaker.

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7.1.5.1 Mandatory Parameters

• Manufacturer – Name of the manufacturer.

• Type designation and serial number – Type of CB and its serial number.
• Year of manufacture – year in which the breaker is manufactured.
• Relevant standard – standard as per the breaker is manufactured.
• Rated Voltage.
• Rated Frequency.
• Rated normal current.
• Rated short circuit breaking current.
• Rated duration of short circuit.
• Rated peak withstand current or rated making current
• Rated short duration power frequency withstand voltage (kV) & Rated
lighting impulse withstand voltage (kVp).
• Rated operating sequence
• Rated pressure of SF6 gas
• Total weight of SF6 gas
• Total weight of CB
• Rated control voltage

As the name suggest, these parameters are mandatory. All the manufacturer
producing circuit breakers must mention these parameters on the nameplate of
SF6 circuit breaker. But of course, some of these parameters may be skipped, if
it is mutually agreed between manufacturer and customer.

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7.1.5.1.1 Rated voltage

Rated voltage is the “Highest system voltage” for which breaker is designed.
This voltage is mentioned in kV rms and refers to phase to phase voltage of 3
phase system. Most of the time people gets confused between rated voltage and
normal voltage. Rated voltage is the highest voltage of a system for which the
system is designed. Whereas, normal voltage is the voltage which will remain in
the system normally. So, in this case, 420kV is the rated voltage and 400kV is
normal voltage. Similarly, for 245kV voltage level, rated voltage is 245kV and
the normal voltage is 220kV. For 145kV, rated voltage is 145kv and normal
voltage is 132kV.

Unit: kV RMS

7.1.5.1.2 Rated frequency

It is the power frequency on which electricity is generated, transmitted and
distributed. In some countries it is 50Hz and in some it is 60Hz. Unit: Hz

7.1.5.1.3 Rated normal current

It is the rms value of rated current which circuit breaker can carry
continuously. Or simply, we can say that, this is the normal current of the
system. Following are some of the standard values of rated normal current:

• 400 A
• 630 A
• 800 A
• 1250 A
• 1600 A
• 2000 A
• 3150 A

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• 4000 A

Unit: Ampere

7.1.5.1.4 Short circuit breaking current

It is the highest rms value of short circuit current, which circuit breaker is
capable of breaking. Rated short circuit current sometimes also called as
symmetrical breaking current. On some nameplates, you’ll find that short circuit
current is given as symmetrical and asymmetrical current. The difference is that,
Symmetrical current is the AC component of short circuit current which is equal
to rated short circuit current. Whereas, asymmetrical current is the combination
of AC and DC components of short circuit current.

Unit: kA RMS

7.1.5.1.5 Rated duration of short circuit

It is the time in seconds for which the breaker can withstand/tested the short
circuit current. As per standard it can be 3 sec or 1 sec.

Unit: Seconds

7.1.5.1.6 Rated peak withstand current or Rated making current

If the circuit breaker closes during the existing fault, current may increase to a
very high value during the first cycle. Therefore, the breaker must withstand this
high current and the mechanical forces caused by this current. This current is
called as “short circuit making current”. Or it is also called as rated peak
withstand current.

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Figure 7.5 Short Circuit Making Current Waveform.

It is generally 2.5 times the rated short circuit current. It is referred in kA peak,
as it remains for very short time.

Unit: kA Peak

7.1.5.1.7 Rated short duration power frequency withstand voltage

This is one of the highest system voltages use to check the insulation properties
of the equipment. It can also be called as insulation levels, if we combine rated
lighting impulse voltage and switching impulse voltage (which is a condition-based
parameter).

Power frequency withstand voltage can be caused by these reasons:

• Phase to earth faults

• Load rejection
• Ferro resonance
• Ferranti effect

And hence, breaker shall withstand power frequency voltage caused by these
reasons. IEC has defined the level of power frequency voltage that can appear across

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breaker contact. So, for example, for 420kV CB the power frequency voltage defined
by IEC is 610kV rms. Circuit breaker has to undergo power frequency withstand
test, in which power frequency voltage is applied to the circuit breaker for 1 min.

Unit: kV RMS

7.1.5.1.8 Rated lighting impulse withstand voltage

Lighting impulse voltage is generally generated due to lighting strokes. And of
course, breaker has to withstand these voltages too. Based on the experience and
system studies, IEC has defined the values for this also. For 420kV voltage level,
lighting impulse voltage defined by IEC is 1425 kV peak. Breaker has to undergo
test for this also.

Unit : kV Peak

7.1.5.1.9 First pole to clear factor

In SF6 circuit breaker, arc extinguishes during current zero. As in 3 phase AC
circuit, currents are out of phase by 120°, current interruption in breaker is not
simultaneous. Contact of one pole will open before the other two. And hence, the
power frequency recovery voltage across the first pole to open is more than the other
two. And this is called as first pole to clear factor. It is given as times the normal
system voltage.

So, on the nameplate we’ll find it is mentioned as 1.3 (or 1.5). This means, first pole
to open will have 1.3 times the normal system voltage across it, and the pole can
sustain that.

Unit: N/A

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7.1.5.1.10 Rated operating sequence

This is one of the important parameters of the breaker, it is also known as “Auto
reclosing duty”.

Operating sequence denotes the opening & closing operation breaker is capable of
performing under specified conditions.

As per IEC 62271-1 there are two alternatives for operating sequence:

O – t – CO – t’ – CO

CO – t’’ – CO

where,

O = Opening operation

C = closing operation

t,t’,t’’ = time intervals between successive operations

so auto reclosing works as follow: 90% of the faults (like) on the system are transient
in nature. Which remain in the system for a very short time and then the system goes
back to normal. In such cases, it is beneficial to put the system live again, and here
the auto reclosing system comes into picture.

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Figure 7.6. Auto Reclosing System.

We’ll consider the auto reclosing duty which is mentioned on our nameplate i.e. O-
0.3 SEC-CO-3 MIN-CO. So, let’s say there is fault on the system the breaker will
open then it will remain open for 0.3 sec. After 0.3 sec, it will close and if the fault
is cleared it will remain close. But, if the fault is still there then the breaker will open
immediately. Now breaker will remain in open condition for 3 mins. After 3 mins
the breaker will close again, and if the fault is cleared it will remain close. But if, the
fault is still there then the breaker will open immediately, and now breaker will
remain open until it is closed manually.

Unit: N/A

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7.1.5.1.11 Switching duty:

During the course of its service life, the circuit breaker should be able to
successfully undertake a variety of switching (interruption) duties that most notably
include: terminal and short line faults, transformer and reactor switching,
and capacitive current interruption. In terms of demands on the circuit breaker, these
different types of switching duties vary the magnitude of current and TRV that a
circuit breaker is required to withstand.

From CHINT Catalogue:

Figure 7.7 Main Technical Parameters of CB.

7.1.5.1.12 Rated pressure of SF6 gas

This is the rated pressure of the SF6 gas in the breaker. This will vary
manufacturer to manufacturer.

Unit: Bar or mega pascals or kg/ sq. cm.

7.1.5.1.13 Total weight of SF6 gas

This shows the total weight of SF6 gas in the breaker. Again, this will vary
manufacturer to manufacturer.

Unit: kg

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7.1.5.1.14 Total weight of CB

This shows the total weight of SF6 gas in the breaker. Again, this will vary
manufacturer to manufacturer.

Unit: kg

7.1.5.1.15 Rated control voltage

This is the DC voltage on which closing and tripping coil works. It can be 110V
DC or 220V DC.

Unit: Volts

These were the mandatory parameters as per IEC. These parameters we’ll generally
find on every nameplate of high & extra high voltage SF6 circuit breaker.

7.1.5.2 Condition based parameters

• Rated switching impulse withstand voltage

• DC component of short circuit current
• Rated line charging current
• Classification

condition-based parameters depend upon some specific condition, which is also

given below. If that condition is satisfied, then these parameters have to be on
nameplate of SF6 circuit breaker.

7.1.5.2.1 Rated switching impulse withstand voltage

Condition: Applicable only for circuit breakers including & above 300kV
Switching surges are generally occurs above 245kV voltage level. And hence
you’ll only find this parameter on the circuit breaker above 245kV level.

It becomes important to test the breaker above 245kV voltage level for switching
surges. Switching surges are generally caused by energization of lines or switching
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of transformers, etc. For 420kV voltage level, switching voltage is specified as

1050kV peak.

Unit: kV Peak

7.1.5.2.2 DC component of short circuit current

Condition: It has to be on nameplate if it is more than 20%

DC component is a DC component of short circuit current. And if it is more than

20% at the time of contact separation of CB, then it has to be on name plate.

Unit: %

7.1.5.2.3 Rated line charging current

Condition: Applicable only for circuit breakers including & above 72.5kV

This is the highest amount of line charging current a circuit breaker is capable of
breaking. This type of current is generated because of the switching of loaded or
unloaded overhead lines. So, for 420kV CB IEC has defined the rating equal to
600A.

Unit: Ampere

7.1.5.2.4 Classification
Condition: If class in not E1 & M1

If circuit breakers mechanical endurance class and electrical endurance class is

different from M1 and E1, then it has to be on nameplate. Let me tell you what is
mechanical endurance class and electrical endurance class.

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7.1.5.2.4.1 Mechanical Endurance Class

• M1 Class

If the breaker is of M1 class which is also called as normal mechanical endurance

class, then the breaker has to withstand 2000 no load operations.

• M2 Class

If the breaker is of M2 class which is also called as Extended mechanical endurance

class, then the breaker has to withstand 10,000 no load operation.

7.1.5.2.4.2 Electrical Endurance Class

E1 stands for Electrical endurance. Generally, most of the breaker nowadays
are of E1 class. E2 class is an extended electrical endurance class which indicate
that, the interrupting parts of the breaker does not require maintenance during its
expected operating life.

So, this was about the condition-based parameters.

7.1.5.3 Optional Parameters

• Rated out of phase current

• Rated cable changing
• Rated single capacitor bank breaking current
• Rated back-to-back capacitor bank breaking current

These parameters are completely optional as per the IEC standard. And hence, it
can be or cannot be on the nameplate, depends upon the manufacturer.

7.1.5.3.1 Rated out of phase current

If the breaker is used for synchronizing two different system, it may happen
that the breaker has to open when the systems are in synchronism procedure. And
the current generated during this condition is called as out of phase current.
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This current gives the highest amount of transient recovery voltage across the
breaker contacts and hence it is one of the critical duties to break. Generally, out of
phase breaking current is 25% of rated short circuit breaking current. On the
nameplate you can see the out of phase current is 12.5kA which is 25% of rated short
circuit breaking current I.e., 50kA.

Unit: kV

7.1.5.3.2 Rated cable Charging

This is the highest amount of cable charging current a breaker is able to break.
Cable charging current can occur while switching the unloaded cables.

Don’t get confused between line charging and cable charging both are different. Line
charging refers to overhead lines whereas, cable charging refers to underground
cables.

Unit: Ampere

7.1.5.3.3 Rated single capacitor bank breaking current

This is the highest amount of a single capacitor bank current a breaker is
capable of breaking. Switching of capacitive and inductive current is a bit difficult
task for the breaker. Because, voltage and current in capacitive and inductive circuit
is not in phase with each other.

Unit: Ampere

7.1.5.3.4 Rated back-to-back capacitor bank breaking current

Back-to-back capacitor bank switching is a special application, and not all the
breakers are intended for this. While switching back-to-back capacitor banks, inrush
current is very high and hence there is a high possibility that the arc will restrike. So,

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if the breaker is made for back to back capacitor bank switching, then you’ll find
this parameter on the nameplate of SF6 circuit breaker.

Unit: Ampere

So, these are the optional parameters we can find on the name plate of HV or EHV
circuit breaker.

7.1.6 Mechanical Operating Mechanism of Circuit Breaker

7.1.6.1 The hydromechanical mechanism
The hydromechanical mechanism has a modular design that allows for easy
maintenance. Disc springs are used to store the energy for operating the breaker. The
mechanism has two independent control valves for opening to ensure reliable
operation. The direct connection to the interrupter provides a one-to-one travel
distance between the interrupter and the mechanism. This mechanism can be
operated either in single phase or in three phases electrically, and can be gang-
operated in three phases mechanically.

Figure 7.8 Hydromechanical operation mechanism.

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Figure 7.9 Section view of Hydromechanical operation mechanism.

7.1.6.2 Spring Operating Mechanism

The design of the spring-operated mechanism provides the high performance
required for reliable operation. The lever engaged with the locking device, which is
released when the trip coil is energized, is rotated counterclockwise by the trip spring
as shown in (Fig.7.9).

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Figure 7.10 Closed position (Closing spring Charged )

The cam and the ratchet wheel engaged with the locking device, which is released
when the closing coil is energized, are rotated counterclockwise by the closing
spring. The lever is rotated clockwise, compressing the trip spring by torque from
the cam (Fig.7.10).

Figure 7.11 Open position (Closing spring Charged )

As soon as the closing sequence is completed, the closing spring is charged by the
ratchet linked to the motor (Fig.7.11).

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Figure 7.12 Closed position (Closing spring Charged )

7.2 Disconnecting Switch

Disconnectors (or disconnect switches) are placed in series with the circuit
breaker to provide additional protection and physical isolation. In a circuit, two
disconnectors are generally used, one on the line side and the other on the feeder
side. Disconnect switches are designed for the interruption of small currents,
induced or capacitively coupled.

7.2.1 Disconnecting Switch Function

Disconnect switches in a GIS installation are used for the same function as
those in an air insulated substation (AIS). They are applied to isolate different
elements of the substation, such as circuit breakers, transmission lines, transformer
banks, buses, and voltage transformers. Typically, they do not have big interrupting
capability except for small quantities of charging current associated with short pieces
of bus. Charging currents are in the range of 0.5 A to 2.0 A.

Disconnect switch operating systems involve:

• Only manual hand crank operation

• Motor operated with manual hand crank override

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• Single-phase operation or three-phase group service

Disconnect switches can be motorized or driven manually. In GIS systems,

motorized isolators are preferred. A pair of fixed contacts and a moving contact form
the active parts of disconnect switch. The fixed contacts are separated by an isolating
gas gap.

During the closing operation, this gap is bridged by the moving contact. The moving
contact is attached to a suitable drive, which imparts the desired linear displacement
to the moving contact at a pre-determined design speed.

A firm contact is established between the two contacts with the help of spring-loaded
fingers or the multi-lam contacts. The isolation gap is designed for the voltage class
of the isolator and the safe dielectric strength of the gas.

Figure shows a cross-section of an isolated-phase GIS disconnector.

Figure 7.13. Cross-section of an isolated-phase GIS disconnector.

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An insulator is used to drive the moving contact and to isolate the drive from the
high voltage components of the disconnector. The shape and size of the insulator are
controlled by the electrical and mechanical requirements of the isolator. In three-
phase ac systems, the individual phase isolators are ganged together to operate
simultaneously.

Leak-tight rotary seals are used in gas insulated isolators for transferring motion
from external drive to the gas. Disconnectors in high voltage GIS operate at SF6
pressures of 0.38 MPa to 0.45 MPa.

The operating speed of the disconnector moving contact ranges from 0.1 to 0.3
m/sec. The design of electrostatic shields on two fixed contacts and the earth side of
the drive insulator plays an important role in ensuring the satisfactory performance
of a gas insulated disconnector.

7.2.2 Disconnect Switch Status

The disconnect switch status, open or closed, may be discovered by one or more of
the following:

• An indicating element, such as red and green lights or semaphores, in the

LCC.
• A mechanical semaphore in the switch operating mechanism cabinet.
• The physical status of the linkages that drive the switch blade.

Direct/camera view of the status of the switch blade through a viewport in the
earthed metallic enclosure. Where motorized disconnect or earthing switches are
installed, some utilities and end users, demand a knife switch to make sure the motor
mechanism is deenergized during maintenance. Also, the motor mechanism may

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demand decoupling from disconnect operating arm. This has to be considered in the
initial design stages.

Commonly, during the initial design stages, a utility or new GIS end user will meet
with the GIS manufacturer to review their operating routines and functions.

7.3 Earth Switch

Fast earth switch and maintenance earth switch are the two types of earth
switches used for gas insulated substation systems. The maintenance earth switch is
a slow device used to ground the high voltage conductors during maintenance
schedules, in order to ensure the safety of the maintenance staff.

7.3.1 Earth Switch Function

earthing switches in a GIS installation are used for the same staff protection
purpose as those in an air insulated substation (AIS) similar to a portable personnel
earthing connection made with a hook stick. They are used to earth different de-
energized substation elements, such as circuit breakers and voltage transformers.
Typically, these earthing switches do not have fault-closing or induced current
interrupting ability, but are capable of conducting fault current when in the closed
position and a small quantity of continuous current for the purpose of testing circuit
breakers and current transformers that are out of service.

The fast earth switch, on the other hand, is used to protect the circuit-connected
instrument voltage transformer from core saturation caused by direct current flowing
through its primary as a consequence of remnant charge (stored online during
isolation/switching off of the line).

In such a situation, the use of a fast earth switch provides a parallel (low resistance)
path to drain the residual static charge quickly, thereby protecting the instrument

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voltage transformer from the damages that may otherwise be caused. The basic
construction of these earth switches is identical.

7.3.2 Earth Switch Construction

The earth switch is the smallest module of a gas insulated substation system. The
module is made up of two parts:

1. Fixed contact, which is located at the live bus conductor and which forms a
part of the main gas insulated system;

2. Moving contact system mounted on the enclosure of the main module and
aligned to the fixed contact.

7.3.3 Earth Switch Status

Earthing switches have the same type of operating mechanisms and method of
discovering switch status as disconnect switches. External, removable links in the
earthing switches are required to disconnect a earthing switch blade from the
external ground. In the closed position, the removable links allow electrical access
to the center conductor and allow timing tests on circuit breakers, conductivity tests,
and current transformer measurements. To help with operator identification the outer
housing of earthing switches may be painted a green, red or similar color to
distinguish from the gray or aluminum color of the GIS elements.

7.4 High Speed Earth Switch

These switches’ primary purpose is the same as grounding switches in air
insulated substations and non-fault-initiating grounding switches in GIS.

HSGS have the additional capability of closing an energized conductor, creating a

short circuit without receiving significant damage to the switch or the enclosure.
HSGS are used to ground various active elements of the substation, such as
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transmission lines, transformer banks, and main buses. In some GIS facilities high
speed ground switches are used to initiate protective relay functions. They are,
typically, not used to ground circuit breakers or voltage transformers. HSGS are also
designed and tested to interrupt electrostatically induced capacitive currents and
electromagnetically induced inductive currents occurring in de-energized
transmission lines in parallel and close proximity to energized transmission lines.
They can also remove DC trapped charges on a transmission line.

HSGS typically have motor operating mechanisms with spring assists for rapid
opening and closing of the switchblade. They typically use the same methods for
determining the switch position as disconnect switches. Figure show a HSGS
connected to a bus.

Normally, high speed earthing switches have motor operating mechanisms with
spring assists for quick opening and closing of the switch blade. Normally, they use
the same procedure for discovering the switch status as disconnect switches.

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Dependent on the design and customers maintenance procedures, external

removable links in the earthing switches may be required to disconnect an earthing
switch blade from the external ground. These removable links are needed to facilitate
timing tests on circuit breakers, conductivity tests, and current transformer
measurements.

7.5 The sequence of operation

While we are opening a circuit this sequence should be followed

1- Open the circuit breaker.

2- Open the disconnecting switch.
3- Close the earthing switch.

While we are closing a circuit this sequence should be followed

1- Open the earthing switch.

2- Close the disconnecting switch.
3- Close the circuit breaker.

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8.1 Introduction
Substation Auxiliary AC system is very important and critical in high voltage
substation. It is typically used to supply all low voltage loads.
Auxiliary power supply system shall be according to EUS-E16 specifications
comprise both AC and DC systems necessary for the substation to fed but not
limited to the following:

• Indoor and outdoor lighting.

• Motors and emergency lighting.
• Power transformer cooling equipment.
• Control equipment.
• Protective relays equipment.
• Indications and alarms.
• Fire protection
• HVAC system
• Power facilities

The AC auxiliary system can be also doubled. The doubled system would utilize
two separate auxiliary transformers, each supplying their own section in the main
distribution switchgear. The doubled system can be also constructed so that the
second supply is coming from an external source, often the surrounding low
voltage network using Automatic transfer switch.

The purpose of auxiliary power supply systems is to cater for the necessary energy
for the operation of primary and secondary devices at the substation. The auxiliary
power systems are normally divided in the main design requirements for typical

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AC auxiliary system in a power substation and electrical equipment used for

implementing.

The auxiliary transformer is a transformer that convert medium voltage level (22
KV or 11 KV) to low voltage level 0.4 KV. The medium voltage may be from
medium voltage switchgear outgoing or in sometimes it may be come from power
transformer tertiary winding.
The main aims of AC auxiliary system design is to size the rating of auxiliary
transformer to be able to meet all low voltage loads in the substation. Not only the
current loads but also the future loads due to expansion in station.

8.2 Substation main low voltage load

8.2.1 Lighting:
1- Control Building and Switchgear Building:
• The lighting installation shall be designed to give the illumination levels for
the respective areas.
• Luminaries shall be selected for ease lamp changing, cleaning and
durability.
• LED tube lamps shall be self-ballast.
• Light fittings selected for control room shall be low brightness type.
• LED tube lamps shall generally be (9.18 watts).
• Lights for Control room and 22KV hall (220KV switchgear corridors)
should be switchable from all entry points.

2- Guard Room & Dormitory Building:

• The minimum illumination level shall not be less than 100 lux.

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• LED tube lamps shall be installed in all parts of the building except on
outside wall of the building where high-pressure Sodium lamps shall be
used.
3- Other Buildings and Areas:
• Rather than those items mentioned herein, the whole substation
structures illumination and all electrification works are a part of the
contractor's works. Such as residential building, parking area, ... etc.
4- Emergency lighting:

Emergency lighting shall be supplied from the DC distribution board in case of

AC supply failure.

➢ Emergency lighting system shall be automatically supplied in the event of:

• AC supply failure of substation's main AC.
• AC supply failure of main Lighting board.
• Lighting's miniature circuit breaker failure for any one of the lighting circuits.
➢ Emergency lighting should be installed in all the substation rooms,
switchyard, main roads, access roads, guard room and main gate and
operated as follows:
➢ Emergency outdoor lighting system shall be manually operated.
➢ Emergency indoor lighting system shall be:
1- Directly operated automatically in the following mentioned areas:
• Control room.
• AC/DC rooms.
• Corridors and entrance
• Telecommunication room

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• 220KV switchgear buildings

• 22KV hall
2- Manually operated by means of DC switches which shall be
installed in the following places:
• Offices
• Workshop/store
• Kitchen/toilets
• Auxiliaries transformers rooms
• Battery room
• Firefighting room
• Rectifier room

Emergency lighting shall be designed to give lux level not less than 5% of the
normal lighting lux level with minimum level of 10 lux.

Only incandescent lamps with porcelain holders are allowed to be used.

Emergency exit signs are required at all exits and along escape routes.

Portable emergency lanterns which will be automatically light a pilot lamp in case
of AC supply failure shall be supplied.

8.2.2 Sockets

In General

• The various types of sockets should be provided with a switch and signal
lamp.
• All sockets shall be mounted at 0.4 m above floor level except in the kitchen
and the toilet which should be mounted at 1.2 m above floor level.

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• Sockets with rated current higher than 16A - 380V should be provided with
a locking device to prevent insertion or removal of the plug if there is a
tension (voltage) on its terminals.

Each socket should be provided with its plug with the following ratings:

• All sockets shall be provided with separate earthing pins connected to the
yellow/green part in the feeder's cable.
• Sockets for l0A and with rated voltage not exceeding 250V shall be in
accordance with IEC 83 group C, international standard.
• Sockets for 16A with a rated voltage not exceeding 750V shall be in
accordance with IEC 309-1-2-309A.
• Sockets for 125A with a rated voltage not exceeding 750V, shall be in
accordance with IEC 309-1-2-309A.
• Sockets for 250A rated voltage not exceeding 750V, shall be in accordance
with IEC 309-1-2-309A.

Sockets in substation shall be and located as follows:

1- Switchyard and transformer area:

• Sockets for 250A, rated voltage 380V shall be installed to each power
transformer to supply power to oil treatment plant.
• One socket 32A rated voltage 380V shall be installed outside each
marshalling box.

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Figure 8.1 32 A rated voltage 380 V

2- Control building and switchgear building:

• One power socket for 32A, rated voltage 380V, shall be installed for every
three bays at least (for indoor S/S).
• A minimum of three sockets- single phase shall be installed in each room
except in control room, 22KV hall and corridor of 220KV switch gear
building for indoor where a single-phase socket shall be installed every 15
m along their perimeters.

3- Other rooms:
• Sockets for 16A with rated voltage not exceed 250V shall be installed in
all rooms. Distance between sockets should not be more than 8 m, at least
two sockets in each room.
• Sockets for 16A with a rated voltage not exceeding 750V shall be each 4
meters, at least one socket in each room close to distribution boards, relay
boards and control boards.
• Sockets for 16A with a rated voltage 380V shall be installed close the AC
boards.

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Figure 8.2 16 A rated voltage 380 V

4- Basement

• Sockets for 63A, rated voltage not exceeding 750V one socket every 25 m at
least.

8.3 Complete load estimation of 220/22 KV substation

The substation has various loads so we must study all loads and make
calculations for demand and diversity factors. Suppliers of substation components
have a main role to provide data about loads power and their ratings. The following
table include a complete estimation and calculation for 220/22 KV substation.

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Figure 8.3 Load estimation of 220/22 KV substation

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8.4 Auxiliary Transformer

8.4.1 Auxiliary transformer sizing

Σ total loads in table1 = 365.88 KVA
Applying a diversity factor of "0.9"
Total load = 0.9 *411.615= 329.292 KVA
The transformer should be loaded with 80 % of its full load
Transformer should be not less than 329.292/.8=411.615 KVA
The available transformer rating is 500 KVA

According to technical specification of the substation and EUS the contractor

should provide two auxiliary transformers. Each transformer of them can withstand
all substation auxiliary loads.
The two transformers are connected to separated section or bus-bar and there is a
ATS (Automatic transfer switch) between the two sections.
So, in this substation we have 2 transformers 500 KVA

8.4.2 Auxiliary transformer and its specs:

An auxiliary transformer is the transformer used in the AC system to feed the
low voltage AC loads with the necessary current at 400 V.
The following table includes auxiliary transformer parameters and specification
from EUS (E15):

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Figure 8.4 Auxiliary transformers parameters

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8.4.3 The requirements of the auxiliary transformer:

8.4.3.1 General:

• The auxiliary transformers shall comply with IEC 60067 standard and will
be 3 phase unit transformers oil immersed ONAN type which suitable for
indoor installation.
• The auxiliary transformers shall be connected by power cables to medium
and low voltage switchgears.
• The Transformer shall be designed with cable entry boxes for direct
connection of cables on the high and low voltage sides. Oil or compound
filled cable boxes are not permitted..
• The continuous rating of each transformer shall not be less than 500KVA

8.4.3.2 Transformation ratio and connection:

The power supply of the substation will fed from two auxiliary transformers have a
transformation ratio of 22/0.4 KV and the connection will be DELTA/STAR
(DYN11) with earthed low voltage neutral.

8.4.3.3 Voltage control:

The transformer shall be equipped with an off-load tap-changer installed on the

high voltage side for± 5% transformation ratio adjusted in 2x2.5% equal steps.

8.4.3.4 Tapping and Tap changing:

• Tapping shall be provided on the high voltage winding to give the no load
voltage variation specification in schedule of requirements.

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• Tap changing shall be carried out with the transformer off-circuit by means
of an externally operated self-positioning tapping switch
• All phases of the tapping switch shall be operated by one hand wheel, which
shall be positively located and lockable at each tapping switch position
• Indication plates shall be fitted to show clearly the tap position number at
which the transformer is operating, switch position number one will
correspond to the maximum plus tapping.

8.4.3.5 Overload capacity:

The transformer shall be capable of withstanding an overload capacity of 10%

of its maximum continuous rating for a period two hours following continuous
running at full load without injury and without exceeding the specified temperature
rise value.

8.4.3.6 Limits of Temperature Rise:

The transformer shall be able to deliver its maximum continuous ratings with the
tap changer set at the middle tapping of the primary winding, without exceeding
the temperature rise limits:

• Ambient temperature 55 °C
• Oil temperature at top level 45 °C
• Winding temperature by resistance method 50 °C
• Hot spot 60 °C

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8.4.3.7 Bushing:

• The 22kV and 0.4kV sides shall be completely insulated. All bushings shall
be designed that there will be no excessive stressing of any parts due to
temperature changes and adequate means shall be provided to accommodate
conductor expansion.
• The bushings on both sides shall be of the outdoor type and have a leakage
path not less than 2 cm/kV at 22kV.
• MV and LV bushings shall be replaceable without difficulty. Cemented in
bushings are not acceptable. Replacement shall not require removal of the
top cover.
• Sufficiently robust to withstand transports risks.
• The LV bushings shall be located on the top of the transformer tank, on the
side opposite the MV bushings. The LV phase and neutral bushings shall be
provided.
• The MV bushings shall be labeled (U, V, W) and L V bushings (u, v, w, n)
The marking of phase identification by adhesive stickers or painting is not
acceptable.

8.4.3.8 Accessories and Fittings:

The Auxiliary transformers shall be supplied with all the necessary accessories
and fittings including but not limited to the following:

• Off load tap changer for external operation with clearly marked position
indication.
• Expanding vessel.

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• Oil level indicator.

• Runners.
• Eye bolt, nut and two eyelets.
• Gas protection device (Buchholz relay) with two stage signals, one for alarm
and the other for isolating the transformer.
• One indicating top-oil thermometer with two adjustable contacts for alarm
and tripping.The thermometer shall have red marking indicating the
maximum permissible temperature.
• Cable clamp (suitable area for earthing wire).

8.4.3.9 Transformer room:

• The transformer shall be installed in a room.

• The bays of the connecting devices and the transformer shall be separated.
• The transformer bay shall be equipped with an oil tray.
• The foundation shall be equipped with holes for LV and MV cables.
• All metal parts shall be equipped with cable clamps for connection to earth
ground network (l85mm2) earthing wire.
• The room shall be equipped with indoor lighting and sockets.

8.4.4 Operation of substation auxiliary transformer

So, in this substation we have 2 transformers 500 KVA, used in the AC system to
feed the low voltage AC loads with the necessary current at 400 V.
• Normal operation:

One of the two auxiliary transformer will feed the main distribution board.
• Abnormal operation:

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If a fault arises on any transformer, the transition system shall connect the loads to
the other transformer.
8.5 Circuit Breaker:
It’s a device used to switch all currents up to the rated current during normal
operation and to interrupt the fault current when a short-circuit occurs.

8.5.1 Type of circuit breaker:

8.5.1.1 Miniature circuit breakers (MCB):
Circuit breakers which operate with thermal and magnetic characteristics with
suitable rating. It can be classified to single phase C.B , two poles C.B, three phase
C.B and three phase with neutral C.B.
We can classify C.B according of minimum tripping current to three types B, C and
D.

Figure 8.5 Miniature circuit breaker

8.5.1.2 Molded-case circuit breaker (MCCB):

A molded case circuit breaker (MCCB) is a type of electrical protection
device that is used to protect the electrical circuit from excessive current, which

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can cause overload or short circuit. With a current rating of up to 2500A, MCCBs
can be used for a wide range of voltages and frequencies with adjustable trip
settings.

Figure 8.6 Molded-case circuit breaker

8.5.1.3 Air Circuit Breaker (ACB)

Is an electrical device used to provide Overcurrent and short-circuit
protection for electric circuits over 800 Amps to 10K Amps. These are usually
used in low voltage applications below 450V.

Figure 8.7 Air circuit breaker

8.5.2 Circuit breaker selection:

In order to properly protect the equipment and coordinate the fault clearing,
circuit breakers should be properly selected. There are three important aspects to

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the proper selection of circuit breakers. They are the rated maximum voltage, rated
continuous current, and the short-circuit current rating.

The voltage rating of the circuit breaker should be not less than the maximum 1
operating voltage of the AC system. Typical low voltage AC circuit breaker
voltage ratings are 120, 120/240, 208Y/120, 240, 277, 347, 480Y/277, 480,
600Y/347, and 600 volts.

The short-circuit current rating is the maximum short circuit current that a circuit
breaker can successfully interrupt. The circuit breakers for an AC system should
have a current interrupting rating equal to or higher than the actual AC system
maximum fault current. Typical low voltage AC circuit breaker current
interrupting ratings are 7.5 kA, 10 kA, 14 kA, 18 kA, 20 kA, 22 kA, 25 kA, 35 kA,
42 kA, 50 kA, 65 kA, 85 kA, 100 kA, 125 kA, 150 kA, and 200 kA.
The circuit breaker rated continuous current should be not less than the maximum
circuit normal operation current. Typically, the rated circuit breaker current should
be 1 to 1.25 of calculated load current with 10% design margin.

Available ratings of C.B:

Figure 8.8 Ratings of circuit breaker

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In some cases, thermal trip units or electronic trip units should be selected based on
equipment protection requirements or the arc flash energy limitation requirements.
The trip unit setting should be clearly identified in the circuit breaker order and
design document.

So, The AC switchboard shall include one outgoing feeders with circuit breaker of
rated current not less than 150 A for feeding outdoor fence

The main AC board shall contain but not limited to the following circuit breakers:

• 400 A MCCB for buildings lighting services

• 400 A MCCB for substation HVAC system
• 250 A MCCB for other requirements
• 25% spare for each type with a minimum of 1.

8.6 Cables:
8.6.1 Cables and conductor types
8.6.1.1 Single core cable
It is used for lighting circuits. Insulation may be XLPE or PVC.

Figure 8.9 Single core cable

8.6.1.2 Multi core cables:

It may be two cores (for single phase loads) or four cores (for three phase loads).
The outer and inner insulation may be PVC or XLPE. The cable may be armored
or may not. The conductor may be copper or Aluminum.

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Figure 8.10 Multi core cable

8.6.2 Feeding cables requirements

• All cables shall be copper conductors PVC insulated 0.6/1.2 kv

• General light circuits shall be wired in not less than 3 mm2 cables.
• General power circuits shall be wired in not less than 4 mm2 cables.
• General power circuits (three phase) shall be wired in not less than 6 mm2
cables.
• Different circuits for power sockets in the same room shall be fed from the
same phase for safety provision
➢ The cabling shall be made as follows: -
• Indoor installation: -
PVC insulated cables laid into tubes (conduits).
The percentage conduit fill shall not exceed 40% of the conduit cross section area.
• Outdoor installation: -
Armored cables lay on cable trays and in case crossing road steel pipes shall be
use.

8.6.3 Cable Sizing Calculations

The following factors should be considered when selecting the cable size:
1- Rated Voltage
2- Ampacity (Current carrying capacity)

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3- Operating Conditions (Derating)

4- Voltage Drop
5- Short Circuit

8.6.3.1 Ampacity:
All conductors should be initially sized based on the ampacity of the load(s)
they are supplying.
For single Phase Loads:
𝑃 𝑆
𝐼= =
𝑉 ∗ (cos ∅) 𝑉
For 3 Phase Loads:
𝑃
𝐼= = 𝑆/(√3 ∗ 𝑉)
√3 ∗ 𝑉 ∗ cos ∅
Where:
I: load current capacity
P: rated power (w)
V: system voltage
S: apparent power (VA)
Cos (ɸ): power factor
8.6.3.2 Derating factors
Are the factors which makes a cable current carrying capacity less than the
designed value. For example, ambient air temperature, soil temperature and laying
method of the cable.
For accurate design of cables and accurate specify capacity of cables we must
receive information about derating factors from cables suppliers so that we can
specify the cross-section area of cables more accurate.

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Generally, The cable must have a current capacity more than the rated of the circuit
breaker connected to it because if the cable current capacity is less than the rated of
circuit breaker then an moderate overload may be happen and C.B doesn’t sense it
but this overload may damage the cable (we can say that circuit breaker is a
protection for cable).

8.7 Voltage drop

Ohm's Law is a very basic law for calculating voltage drop:
Voltage drop = 𝐼 ∗ 𝑅
Where:
I: the current through the wire, measured in amperes.
R: the resistance of the wires, measured in ohms.
The resistance of the wires is often measured and given as length-specific
resistance, normally in the unit of ohms per kilometer or ohms per 1000 feet. Also,
the wire is round-tripped. Therefore, the formula for a single-phase or direct
current circuit becomes:
Voltage drop = 2 ∗ 𝐼 ∗ 𝑅 ∗ 𝐿
The formula for a three-phase circuit becomes:
Voltage drop = √3 ∗ 𝐼 ∗ 𝑅 ∗ 𝐿
Note: voltage drop must not exceed 5%.

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8.8 Short circuit:

Short circuit ratings must be calculated using adiabatic methods described in
(IEC 60949).The general form of the adiabatic temperature rise formula which is
applicable to any initial temperature is

2
𝜃𝑓 + 𝛽
𝐼𝑎𝑑 𝑡 = 𝐾 2 𝑆 2 ln
𝜃𝑖 + 𝛽
𝐼𝑎𝑑 : Short circuit current calculated on adiabatic basis (amp).
K: constant depends on material of the current carrying component.
S: cross sectional area of conductor (𝑚𝑚2).
T: duration of short circuit (1 second).
ɵ𝑓: Final temperature = 2500𝑐
ɵ𝑖: Initial temperature = 900𝑐
𝛽: Temperature coefficient of resistance of the current carrying component.

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CHAPTER 9 DC AUXILARY SYSTEM

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9.1 Introduction
A DC system is the total assembly of components that is required to supply
direct current within preset limits of terminal voltage for a specified time. What is
the necessity of the DC system in a substation?
The function of the DC system is to supply auxiliary and operating power to
equipment designed for a DC supply, such as:

• Protection circuits
• Control circuits
• Emergency lighting

• Annunciation, alarms
• Communication panels
The typical system is normally supplied by an AC system and consists of a battery
and a battery charger. Voltage-dropping devices may also be installed between the
system output terminals and the load to be supplied
Generally, DC supply is preferred because it is a reliable source obtained from a
battery bank.

In case of power failure, we can determined the status of the breakers, like which
breaker is in on position or which one is in off and check the fault status of the
relay.

But in this case the AC supply cannot be use to check the status of the fault that is
why DC system is preferred to use.

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9.2 Function of DC system:

The function of the DC system is to supply auxiliary and operating power to
equipment designed for a DC supply.
DC is normally supplied from the AC system across rectifiers, but if the AC supply
is lost, the batteries take over the power supply without any interruption for
operation and control of the substation equipment as well as to supply substation
emergency lighting.

Figure 9.1 DC auxiliary system

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9.3 Battery Types:

9.3.1 Lead-acid batteries:
The lead-acid battery is one of the oldest rechargeable (secondary) battery
technologies in existence. A number of designs have evolved to meet specific
design objectives and applications.

Figure 9.2 Lead acid batteries

• Components: Lead-acid batteries have an acidic electrolyte solution of

sulfuric acid (H2SO4). The active plate materials are lead dioxide (PbO2)
for the positive electrode and sponge lead (Pb) for the negative. The
active materials for both the positive and negative electrodes are
incorporated in a plate structure composed of lead or a lead alloy.

• Voltage: The fully charged lead-acid cell has an open circuit voltage of
approximately 2.10 V, which varies as a function of cell specific gravity
and temperature. Open circuit voltage increases with specific gravity and
decreases with temperature, and may range from 2.06 to 2.15 V/cell.
Float voltages range from 2.15 to 2.40 V/cell, depending on their
individual cell design, temperature, and manufacture recommendation

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9.3.2 Nickel-cadmium batteries:

Nickel-cadmium batteries use an alkaline electrolyte (potassium hydroxide).
The active materials are nickel hydroxide in the positive plate and cadmium
hydroxide in the negative plate.
The electrolyte in the nickel-cadmium battery does not take part in the overall cell
reaction, so the specific gravity does not change during charge and discharge.
The electrolyte retains its ability to transfer ions between the cell plates and also
acts as a preservative of steel components in the cell mechanical structure.

Figure 9.3 Nickel-Cadmium Battery

• Voltage: The nickel-cadmium cell has an open circuit voltage of

approximately 1.30 V and a nominal discharge voltage of 1.20 V. The
manufacturer’s recommendations indicate a range of float voltages of 1.38-
1.47 V/cell and equalizing voltages of 1.47-1.65 V/cell, depending on their
individual designs. Nickel-cadmium cells can tolerate very high charge rates
without damage, and may be left off charge for years with no life loss.

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• Capacity: The cell can tolerate complete discharge with almost no

permanent deterioration of capacity or life. Depending on the number of
cells used, the typical end-of-discharge voltage in this application may vary
from 1.00 to 1.10 V/cell. It is advisable to use the lowest end-of-discharge

voltage and the largest possible number of cells that will satisfy the
manufacturers charging recommendations.

9.4 DC system configuration:

9.4.1 Single 100% battery Low capital cost No standby DC and 100%
charger System

Figure 9.4 Single battery single charger

➢ Advantages:
• Low capital cost.

➢ Disadvantages:
• No standby DC System outage for maintenance Need to isolate battery/
charger combination from load under boost charge conditions in order
to prevent high boost voltages appearing on DC distribution system

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9.4.2 Semi-duplicate 2*50% batteries and 2 *100% chargers:

Figure 9.5 one battery two charges

➢ Advantages:
• Medium capital cost.
• Standby DC provided which is 100% capacity on loss of one charger.
• Each battery or charger can be maintained in turn.
• Each battery can be isolated, and boost charged in turn without
affecting DC output voltage.
➢ Disadvantages:
• 50% capacity on loss of one battery during AC source failure.
9.4.3 Fully duplicate 2 * 100% batteries and 2 * 100% chargers:

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Figure 9.6 Two batteries tow charges system

➢ Advantages:
• Full 100% standby DC capacity provided under all AC source conditions
and single component (charger or battery) failure
➢ Disadvantages:
• High capital cost
• Greater space requirement Increased maintenance cost
9.5 DC system Voltage in substations:
• 220/110-volt DC 2-wire ungrounded system for control, protection,
emergency lighting, tripping coils, operating coils, contactors, relays,
Auxiliary relays indications and protection.
• 48 volt for communications system and SAS system

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9.6 DC Parameters:
Generally, the following parameters for DC systems as specified in "EUS-E16"
are:
• Nominal DC system voltage: 220 V
• Allowable minimum DC system voltage: 198 V
• Allowable maximum DC system voltage: 242 V.
• Rated discharge time hour: 5H
• Number of batteries for 220 V: 2 batteries
• Number of chargers for 220 V: 2 chargers

Note: we will use 2 chargers and 1 charger as spare "according to PTS"

9.7 Design Factors:

9.7.1 Temperature derating factor (Tt):

The available capacity of a cell is affected by its operating temperature. The

standard temperature for stating cell capacity is 25 °C. If the lowest expected
electrolyte temperature is below standard, select a cell large enough to have the
required capacity available at the lowest expected temperature. The battery
manufacturer should be consulted for capacity derating factors for various
discharge times and temperatures. If the lowest expected electrolyte temperature is
above 25°C, generally there is no noticeable increase in the available capacity.

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9.7.2 Design margin factor:

It is prudent design practice to provide a capacity margin to allow for

unforeseen additions to the dc system, and less than optimum operating conditions
of the battery due to improper maintenance, recent discharge, ambient
temperatures lower than anticipated, or a combination of these factors. A method
of providing this design margin is to add a percentage factor to the cell size
determined by calculations. If the various loads are expected to grow at different
rates, it may be more accurate to apply the expected growth rate to each load for a
given time and to develop a duty cycle from the results.

9.7.3 Ageing factor:

Capacity decreases gradually during the life of the battery, with no sudden
capacity loss being encountered under normal operating conditions. Since the rate
of capacity loss is dependent upon such factors as operating temperature,
electrolyte specific gravity, depth, and frequency of discharge, an ageing factor
should be chosen based on the required service life. The choice of the ageing factor
is, therefore, essentially an economic consideration. An ageing factor of 1.25 is
used, meaning that the battery is sized to carry the loads until its capacity has
decreased to 80% of its rated capacity. For an application involving continuous
high temperatures and/or frequent deep discharges, it may be desirable to use a
factor of, say, 1.43, and replace the battery when its capacity falls to 70% of its
rated capacity.

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9.7.4 Capacity rating factor (Kt)

The capacity rating factor, Kt, is the ratio of rated ampere-hour capacity (at a
standard time rate, at 25 °C, and to a standard end-of-discharge voltage) of a cell,
to the amperes that can be supplied by that cell for t minutes at 25 °C and to a
given end of- discharge voltage. Kt factors are available from the battery
manufacturer or may be calculated from other published.
Published discharge data for nickel-cadmium cells are most commonly available in
tabular form, in which the current available from each cell type is stated for a given
discharge time and end-of-discharge voltage. For intermediate times and voltages,
it is necessary to interpolate between the known:

(𝐾𝑡2 − 𝐾𝑡1 ) × (𝑡2 − 𝑡1 )

𝐾𝑡 = 𝐾𝑡2 −
(𝑡2 − 𝑡1 )

9.8 Load classifications:

It’s important that we make a load classification to be aware for the batteries
duty cycle. The individual dc loads supplied by the battery during the duty cycle
may be classified as:
9.8.1 Continuous loads:
Continuous loads are energized throughout the duty cycle. These loads are those
normally carried by the battery charger and those initiated at the inception of the
duty cycle.

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➢ Typical continuous loads are:

• Lighting
• Continuously operating motors
• Converters (e.g., inverters)
• Indicating lights
• Continuously energized coils
• Annunciator loads
• Communication systems
9.8.2 Non-Continuous loads:
Non-continuous loads are energized only during a portion of the duty cycle.
These loads may switch on at any time within the duty cycle and may be on for a
set length of time, be removed automatically or by operator action, or continue
to the end of the duty cycle. When several loads occur simultaneously within the
same short period of time and a discrete sequence cannot be established, the load
should be assumed to be the sum of all loads occurring within that period. If a
discrete sequence can be established, the load for the period should be assumed
to be the maximum load at any instant. If a load lasts for less than one second, it
is normally considered to last for a full second.

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➢ Typical non continuous loads are:

• Emergency pump motors
• Critical ventilation system motors
• Fire protection systems
• Switchgear operations
• Motor-driven valve operations
• Isolating switch operations
• Field flashing of generators
• Motor starting currents
• Inrush current
9.8.3 Momentary Loads:
Momentary loads can occur when several loads occur simultaneously within
the same short period of time and a discrete sequence cannot be established, the
load should be assumed to be the sum of all loads occurring within that period. If a
discrete sequence can be established, the load for the period should be assumed to
be the maximum load at any instant. If a load lasts for less than one second, it is
normally considered to last for a full second.
Typical momentary loads are:
• Motor-driven valve operations
• Isolating switch operations
• Field flashing of generators
• Motor starting currents
• Inrush currents

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9.9 Duty cycle diagram:

A duty cycle diagram showing total load at any time during the cycle is an aid
in the analysis of the duty cycle. To prepare such a diagram, all loads, expressed as
either power or current expected during the cycle, are tabulated along with their
anticipated inception and shutdown times. The total time span of the duty cycle is
determined by the requirements of the installation.

Figure 9.7 Duty cycle

9.10 Battery sizing Calculation "according to (IEEE-1115)":

Several basic factors govern the size (number of cells and rated capacity) of
the battery. Included are the maximum system voltage, the minimum system
voltage, the duty cycle, correction factors, and design margin. Since a battery
string is usually composed of a number of identical cells connected in series,
the voltage of the battery is the voltage of a cell multiplied by the number of
cells in series. The ampere-hour capacity of a battery string is the same as the
ampere-hour capacity of a single cell.
If cells of sufficiently large capacity are not available, then two or more strings,
of equal number of series connected cells, may be connected in parallel to
obtain the necessary capacity. The ampere hour capacity of such a battery is the
sum of the ampere-hour capacities of the strings.

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Operating conditions can change the available capacity of the battery. For
example:
a) Available capacity decreases as its temperature decreases.
b) Available capacity decreases as the discharge rate increases.
c) The minimum specified cell voltage at any time during the battery discharge
cycle limits the available capacity.
d) The charging method can affect the available capacity.
The battery capacity is determined by the drawings up a load profile, which
specifies the current load on the battery as a function of time. The necessary
battery rating is determined by means of the load profile plus 25% for future use by
Owner.
The factors specified below shall be taken into account in determining the rating of
the battery:
• Load profile as approved by Owner.
• Time during which the AC supply is not available (5 hours).
• Highest and lowest permissible pole voltage.
• Factor of safety to allow for ageing of the battery and incomplete charging.
• Battery type.
• Ambient temperature

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9.10.1 Number of cells calculation:

When the battery voltage is not allowed to exceed a given maximum system
voltage, the number of cells will be limited by the manufacturer’s recommended
cell voltage required for satisfactory charging.
𝑀𝑎𝑥𝑖𝑚𝑢𝑚 𝑎𝑙𝑙𝑜𝑤𝑎𝑏𝑙𝑒 𝑠𝑦𝑠𝑡𝑒𝑚 𝑣𝑜𝑙𝑡𝑎𝑔𝑒
= 𝑁𝑢𝑚𝑏𝑒𝑟 𝑜𝑓 𝑐𝑒𝑙𝑙𝑠
𝐶𝑒𝑙𝑙 𝑣𝑜𝑙𝑡𝑎𝑔𝑒 𝑟𝑒𝑞𝑢𝑖𝑟𝑒𝑑 𝑓𝑜𝑟 𝑠𝑎𝑡𝑖𝑠𝑓𝑎𝑐𝑡𝑜𝑟𝑦 𝑐ℎ𝑎𝑟𝑔𝑖𝑛𝑔

The minimum battery voltage equals the minimum system voltage plus any voltage
drop between the battery terminals and the load. The minimum battery voltage is
then used to calculate the allowable minimum cell voltage.
𝑀𝑖𝑛𝑖𝑚𝑢𝑚 𝑏𝑎𝑡𝑡𝑒𝑟𝑦 𝑣𝑜𝑙𝑡𝑎𝑔𝑒
= 𝑀𝑖𝑛𝑖𝑚𝑢𝑚 𝑐𝑒𝑙𝑙 𝑣𝑜𝑙𝑡𝑎𝑔𝑒
𝑁𝑢𝑚𝑏𝑒𝑟 𝑜𝑓 𝑐𝑒𝑙𝑙𝑠

Nominal voltage (V) = 220

• Minimum allowable system voltage percentage = 0.9
• Maximum allowable system voltage percentage = 1.1
• Minimum allowable system voltage = 220 x 0.9 = 198 V
• Maximum allowable system voltage = 220 x 1.10 = 242 V
• End cell voltage = 1.076 V
• Number of cells = 184 cell

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9.10.2 Batteries Sizing methodology:

The cell selected for a specific duty cycle must have enough capacity to carry
the combined loads during the duty cycle. To determine the required cell size, it is
necessary to calculate, from an analysis of each section of the duty cycle, the
maximum capacity required by the combined load demands (current versus time)
of the various sections. The first section analyzed is the first period of the duty
cycle.

Figure 9.8 Generalized duty cycle

Using the capacity rating factor for the given cell range and the applicable
temperature derating factor Tt, a cell size is calculated that will supply the required
current for the duration of the first period. For the second section, the capacity is
calculated assuming that the current A1 required for the first period is continued
through the second period; this capacity is then adjusted for the change in current
(A2 - A1) during the second period. In the same manner, the capacity is calculated
for each subsequent section of the duty cycle. This iterative process is continued

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until all sections of the duty cycle have been considered. The calculation of the
capacity FS required by each section S, where S can be any integer from 1 to N,
can be expressed mathematically as follows:

𝑃=𝑆

𝐹𝑆 = ∑[𝐴𝑃 − 𝐴(𝑃−1) ]𝐾𝑡 𝑇𝑡

𝑃=1

Where:

• S :is the section of the duty cycle being analyzed. Section S contains the first
S periods of the duty cycle (for example, section S5 contains periods 1
through 5)
• N: is the number of periods in the duty cycle
• P: is the period being analyzed.
• Ap: is the amperes required for period P.
• t: is the time in minutes from the beginning of period P through the end of
section S
• Kt: is the capacity rating factor for a given cell type, at the t minute
discharge rate, at 25 °C, to a definite end-of-discharge voltage.
• Tt: is the temperature derating factor at t minutes, based on electrolyte
temperature at the start of the duty cycle.
• Fs: is the capacity required by each section S

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9.10.3 Ampere-hour sizing

Figure 9.9 DC load summary

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Figure 9.10 Duty cycle diagram

Figure 9.11Total AH of battery

So, The total ampere-hour= 419.371AH

The recommended battery size according to EUS specifications is 500 AH

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9.11 Battery Charger

9.11.1 Definition
A solid-state rectifier device, including power transformer, rectifying
elements, filter elements, regulating and control elements capable of providing
charging power to a storage battery, or of supplying charging power to a storage
battery and, at the same time, supplying power to a connected DC load.
The battery charger shall be designed as part of a DC supply system consisting of
charger, battery, and load, connected in parallel.

9.11.2 Battery charger rating "according to (EUS-E16)":

The output current rating of the charger in DC amperes shall be determined by the
following formula:

𝑘𝐶
𝐴= + 𝐿𝑐
𝐻
Where:
A: Output rating of the charger in amperes.
K: Efficiency factor to return 100 percent of ampere-hours removed. Use 1.4 for
nickel-cadmium batteries.
C: Calculated number of ampere-hours discharged from the battery (calculated
based on duty cycle).
H: Recharge time to approximately 95 percent of capacity in hours. A recharge
time of 8 to 12 hours is usually recommended.

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9.11.3 Battery charger calculation

K = 1.4
C = 500
H = 10
Lc = 27
A = ((1.4 * 500)/ 10) + 27 = 97

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CHAPTER 10 INSTRUMENT TRANSFORMERS

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10.1 Introduction
Current and voltage transformers (CTs and VTs) are collectively known as
transducers or instrument transformers. They are used to transform the power system
currents and voltages to lower magnitudes and to provide isolation between the high
voltage power system and the relays and other measuring instruments (meters)
connected to the secondary windings of the transducers. In order to achieve a degree
of interchangeability among different manufacturers of relays and meters, the ratings
of the secondary windings of the transducers are standardized. The standard current
ratings of the secondary windings of the current transformers (CTs) are 5 or 1
ampere. The secondary windings of the voltage transformers (VTs) are rated at 110
V line to line. The current and voltage ratings of the protective relays and meters are
same as the current and voltage ratings of the secondary windings of the CTs and
VTs respectively. The transducers should be able to provide current and voltage
signals to the relays and meters which are faithful reproductions of the corresponding
primary quantities. Although in most of the cases the modern transducers are
expected to do so, but they can’t be ideal and free from the errors of transformation.
Hence the errors of transformation introduced by the transducers must be taken into
account, so that the performance of the relays can be assessed in the presence of such
errors.

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10.2 CURRENT TRANSFORMERS (CTs)

Current transformers are used to perform two tasks. Firstly, they step down the
heavy power system currents to low values that are suitable for the operation of the
relays and other measuring instruments (meters) connected to their secondary
windings. Secondly, they isolate the relays and meters circuits from the high voltages
of the power system. The standard current ratings of the secondary windings of the
CTs used in practice are 5A or 1A. Since the current ratings of CT secondary
windings are standardized, current ratings for relays and meters are also
standardized, so that a degree of interchangeability among different manufacturers
of relays and meters can be achieved. A conventional CT of electromagnetic type is
similar to a power transformer to some extent since both depend on the same
fundamental principle of electromagnetic induction but there are considerable
differences in their design and operation. A power transformer is a shunt-operated
device while a CT is a series operated device. Current transformers are connected
with their primaries in series with the power system (protected circuit) and, because
the primary currents are so large, the primary winding has very few turns. The VA
rating of current transformers is small as compared with that of a power transformer.
Though the nominal (Continuous) current ratings of the secondary windings of the
CTs are 5A or 1A but they must be designed to tolerate higher values for short time
of few seconds under abnormal system conditions, e.g., fault conditions. Since the
fault currents may be as high as 50 times full-load current, current transformers are
designed to withstand these high currents for a few seconds. Protective relays require
reasonably accurate reproduction of the normal and abnormal conditions in the
power system for correct sensing and operation. Hence, the current transformers
should be able to provide current signals to the relays and meters which are faithful
reproductions of the primary currents. The measure of a current transformer

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performance is its ability to accurately reproduce the primary current in secondary

amperes. Ideally, the current transformer should faithfully transform the current
without any error. But, in practice, there is always some error. The error is both in
magnitude and in phase angle. These errors are known as ratio error and phase angle
error. The exciting current is the main source of these errors of a CT. Depending on
application, CTs are broadly classified into two categories: (1) measuring CTs, and
(2) protective CTs. CTs used in conjunction with measuring instruments (meters)
are popularly termed as measuring (metering) CTs’ and those used in conjunction
with protective devices are termed as protective CTs.

10.2.1 Magnetization curve

This curve is the best method of determining a CTs performance. It is a graph

of the amount of magnetizing current required to generate an open-circuit voltage
at the terminals of the unit. Due to the non-linearity of the core iron, it follows the
B-H loop characteristic and comprises three regions, namely the initial region,
unsaturated region and saturated region (see Figure 10.1).

Figure 10.1 Typical CT magnetization curve

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10.2.2 Knee-point voltage

The transition from the unsaturated to the saturated region of the open-circuit
excitation characteristic is a rather gradual process in most core materials. This
transition characteristic makes a CT not to produce equivalent primary current
beyond certain point. This transition is defined by ‘knee-point’ voltage in a CT,
which decides its accurate working range. It is generally defined as the voltage at
which a further 10% increase in volts at the secondary side of the CT requires more
than 50% increase in excitation current. For most applications, it means that current
transformers can be considered as approximately linear up to this point.

10.2.3 Difference Between Measuring and Protective CTs

CTs which are used to step down the primary currents to low values suitable
for the operation of measuring instruments (meters) are called measuring or metering
CTs. Secondary of the measuring CTs are connected to the current coils of ammeters,
wattmeters, energy meters, etc. Since the measurements of electrical quantities are
performed under normal conditions and not under fault conditions, the performance
of measuring CTs is of interest during normal loading conditions. Measuring CTs
are required to give high accuracy for all load currents up to 125% of the rated
current. These CTs may have very significant errors during fault conditions, when
the currents may be several times their normal value for a short time. This is not
significant because metering functions are not required during faults. The measuring
CTs should get saturated at about 1.25 times the full-load current so as not to
reproduce the fault current on the secondary side, to avoid damage to the measuring
instruments. CTs used in association with protective devices i.e., relays, trip coils,
pilot wires etc. are called protective CTs. Protective CTs are designed to have small
errors during fault conditions so that they can correctly reproduce the fault currents
for satisfactory operation of the protective relays. The performance of protective

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relays during normal conditions, when the relays are not required to operate, may
not be as accurate. When a fault occurs on a power system, the current tends to
increase and current and voltage tends to collapse. The fault current is abnormal and
may be 20 to 50 times the full-load current. It may have dc offset in addition to ac
component. The fault current for a CT secondary of 5A rating could be 100 to 250
A. Therefore, the CT secondary having a continuous current rating of 5A should
have short-time current rating of 100 to 250 A, so that the same is not damaged.
Since the ac component in the fault current is of paramount importance for the relays,
the protective CT should correctly reproduce it on the secondary side in spite of the
dc offset in the primary winding. Hence the dc offset should also be considered while
designing the protective CT. The protective CT should not saturate up to 20 to 50
times full-load current.

10.2.4 Core Material of CTs

Figure 10.2 shows the magnetization Characteristics of (a) cold-rolled grain-

oriented silicon steel (3%), (b) hot-rolled silicon steel (4%) and (c) nickel-iron (77%
Ni, 14% Fe). It is seen that the nickel-iron core has the qualities of highest
permeability, low exciting current, low errors and saturation at a relatively low flux
density. Measuring CTs are required to give a high accuracy for all load currents up
to 125% of the rated current. Nickel-iron gives a good accuracy up to 5 times the
rated current and hence, it is quite a suitable core material for CTs used for meters
and instruments. The excessive currents being fed to instruments and meters are
prevented during faults on power system due to almost absolute saturation at
relatively low flux density. Cold-rolled grain-oriented silicon steel (3%), which has
a high permeability, high saturation level, reasonably small exciting current and low
errors is used for the core of the CTs used for protective relays. Such core material
has reasonably good accuracy up to 10-15 times the rated current, but when we

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consider currents that are five times under the rated current, the core material made
from nickel-iron alloy fares batter.

Figure 10.2 Magnetization characteristics of CT cores

Hot-rolled silicon steel has the lowest permeability. So, it is not suitable for CTs. In
order to achieve the desired characteristics, composite cores made of laminations of
two or more materials are also used in CTs.

10.2.5 CT Burden

The CT burden is defined as the load connected across its secondary, which is
usually expressed in volt amperes (VA). It can also be expressed in terms of
impedance at the rated secondary current at a given power factor, usually 0.7
lagging. From the given impedance at rated secondary current, the burden in VA can
be calculated. Suppose the burden is 0.5 Ω at 5 𝐴 secondary current. Its volt amperes
will be equal to 𝐼 2 𝑅 = 52 × 0.5 = 12.5 𝑉𝐴. The total burden on the CT is that of
the relays, meters, connecting leads and the burden due to the resistance of the

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secondary winding of the CT. The relay burden is defined as the power required to
operate the relay. The burden of relays and meters is given by the manufactures or it
can be calculated from the manufacturer’s specifications as the burden depends on
their type and design. The burden of leads depends on their resistance and the
secondary current. Lead resistance is appreciable if long wires run from the
switchyard to the relay panels placed in the control room. Lead burden can also be
reduced using low secondary currents. Usually, secondary currents of 5 A are used,
but current of 2 A or even 1 A can be used to reduce the lead burden. Suppose, the
lead resistance is 5 Ω. Then lead burden at 5 𝐴 will be 52 × 5 = 125 𝑉𝐴. The burden
at 1 A is only 12 × 5 = 5 𝑉𝐴. The economy in CT cost and space requirement
demands shorter lead runs and sensitive relays. The rating of a large CT is 15 VA.
For a 5 A secondary current, the corresponding burden is 0.6 Ω, and for a 1 A
secondary current it is 15 Ω. If rated burden be PVA at rated secondary current 𝐼𝑆
amperes, the ohmic impedance of the burden Zb can be calculated as follows:

𝑃
𝑍𝑏 = 𝑜ℎ𝑚𝑠
𝐼𝑠2

If burden power factor is 𝑐𝑜𝑠 𝜙 , the values of resistance and reactance of the burden
can be calculated as follows:

𝑅𝑏 = 𝑍𝑏 𝑐𝑜𝑠 𝜙

𝑋𝑏 = √𝑍𝑏2 – 𝑅𝑏2

The impedance of the relay coil changes with current setting. The values of power
consumption of relays, trip coil etc. are given by their manufacturers. The CT of
suitable burden can be selected after calculating the total burden on the CT. When

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the relay is set to operate at current different from the rated secondary current of the
CT, the effective burden of the relay can be calculated as follows:

𝐼𝑠 2
𝑃𝑒 = 𝑃𝑟 ( )
𝐼𝑟

where, 𝑃𝑒 = Effective VA burden of the relay on CT

𝑃𝑟 = VA burden of relay at given current setting Ir

𝐼𝑠 = Rated secondary current of CT

𝐼𝑟 = Current setting of the relay

The rated VA output of the CT selected should be the higher standard value
nearest to the calculated value. If the VA rating of the CT selected is very
much in excess of the burden, it makes the choice uneconomical and the CT
becomes unduly large.

10.2.6 Technical Terms of CTs

The following are some of the commonly used terms for current transformers (CTs)

i. Rated primary current: The value of the primary current which is marked on
the rating plate of the transformer and on which the performance of the CT is
specified by the manufacturer.
ii. Rated secondary current: The value of the secondary current which is
marked on the rating plate of the transformer and on which the performance
of the CT is specified by the manufacturer.
iii. Rated transformation ratio: The ration of the rated primary current to rated
secondary current. It is also called nominal transformation ratio.

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iv. Actual transformation ratio: The ratio of the actual primary current to the
actual secondary current.
v. Burden: The value of the load connected across the secondary of CT,
expressed in VA or ohms at rated secondary current.
vi. Rated burden: The value of the load to be connected across the secondary of
CT including connecting lead resistance expressed in VA or ohms on which
accuracy requirement is based.
vii. Rated short-time current: The r.m.s value of the a.c. component of the
current which the CT is capable of carrying for the rated time without being
damaged by thermal or dynamic effects.
viii. Rated short-time factor: The ratio of rated short-time current to the rated
current.
ix. Rated accuracy limit primary current: The highest value of primary current
assigned by the CT manufacturer, up to which the limits of composit error are
complied with.
x. Rated accuracy limit factor: The ratio of rated accuracy limit primary
current to the rated primary current.
xi. Composit error: The r.m.s. value of the difference (𝑁 𝑖𝑠 – 𝑖𝑝 ), given by

100 1 𝑇
𝐶𝑜𝑚𝑝𝑜𝑠𝑖𝑡 𝑒𝑟𝑟𝑜𝑟 = √ ∫ (𝑁𝑖𝑠 – 𝑖𝑝 )
𝐼𝑝 𝑇 0

Where 𝑁 = Rated transformation ratio

𝐼𝑝 = r.m.s value of the primary current
𝑖𝑝 = Instantaneous values of the primary current
𝑖𝑠 = Instantaneous values of the secondary current
𝑇 = Time period of one cycle in seconds

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xii. Knee-point voltage: The sinusoidal voltage of rated frequency (system

frequency) applied to the secondary terminals of CT, with all other winding
being open-circuited, which when increased by 10 percent, causes the
exciting current to increase by 50 percent. Minimum knee point voltage is
specified by the following expression.
𝑉𝑘 = 𝐾𝐼 (𝑅𝐶𝑇 + 𝑍𝑠 )
Where;
𝐾 = A parameter to be specified by the purchaser depending on the system
fault level and the characteristic of the relay intended to be used.
𝐼 = Rated relay current (1 A or 5 A)
𝑅𝐶𝑇 = Resistance of CT secondary winding corrected to 75° C
𝑍𝑠 = Impedance of the secondary circuit (to be specified by the purchaser)

xiii. Rated short-circuit current: The r.m.s. value of primary current which the
CT will withstand for a rated time with its secondary winding short-circuited
without suffering harmful effects.
xiv. Rated primary saturation current: The maximum value of primary
current at which the required accuracy is maintained
xv. Rated saturation factor: the ratio of rated primary saturation current to
rated primary current

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10.2.7 Theory of Current Transformers

Conventional electromagnetic current transformers (CTs) are single primary
and single secondary magnetically coupled transformers. Hence, their performance
can be analyzed from the equivalent circuit commonly used in the analysis of
transformers. The equivalent circuit of CT as viewed from secondary side is shown
in Fig. 10.3. It is convenient to put the exiting shunt circuit on the secondary side
and to refer all quantities to that side, so that I′p denotes the primary current referred
to the secondary side. The exciting current I0 is deducted from I′p to excite the core
and induce voltage Es which circulates current Is.

Figure 10.3 Equivalent circuit of CT as viewed from secondary side

An ideal (perfect) transformer shown in Fig.10.3 is to provide the necessary ratio

change, it has no loss or impedance. All the quantities are referred to the secondary
side. In an ideal CT, the primary ampere-turns (AT) is exactly equal in magnitude to
the secondary AT and is in precise phase opposition to it. But in practical (actual)
CTs errors are introduced both in magnitude and in phase angle. These errors are
known as ratio error and phase angle error. The exciting current I0 is the main source
of these errors. Practical CTs do not reproduce the primary currents exactly in
magnitude and phase due to these errors.

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10.2.8 CT Errors
In an ideal (perfect) CT, the secondary current is given by

𝐼𝑝
𝐼𝑠 =
𝑁

But in a practical (actual) CT, it is

𝐼𝑝
𝐼𝑠 = – 𝐼0
𝑁

Thus, the actual CT does not reproduce the primary current exactly in secondary side
both in magnitude and phase due to exciting current I0. The exciting current I0 is the
main source of errors in both measuring and Protective CTs. The error in magnitude
is due to error in CT ratio which is called “ratio error” and the error in phase is
called “phase-angle error.”

3.2.7 Accuracy Class of CTs

The accuracy of any CT is determined essentially by how accurately the CT

reproduces the primary current in the secondary. Accuracy class is assigned to the
CT with the specified limits of ratio error and phase angle error. The accuracy of a
current transformer is expressed in terms of the departure of its ratio from its true
ratio. This is called the ratio error, and is expressed as:

𝑁𝐼𝑠 – 𝐼𝑝
𝑃𝑒𝑟𝑐𝑒𝑛𝑡 𝑒𝑟𝑟𝑜𝑟 = × 100
𝐼𝑝

rated primary current

N = Nominal ratio =
rated secondary current

Is = Secondary current

Ip = Primary current

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The ratio error of a CT depends on its exciting current. When the primary current
increases, the CT tries to produce the corresponding secondary current, and this
needs a greater secondary emf, core flux density and exciting current. A stage comes
when any further increase in primary current is almost wholly absorbed in an
increased exciting current, and thereby the secondary current hardly increases at all.
At this stage, the CT becomes saturated. Thus, the ratio error depends on saturation.
An accuracy of about 2% to 3% of the CT is desirable for distance and differential
relays, whereas for many other relays, a higher percentage can be tolerated.
According to standards followed in U.K., protective CTs are classified as S, T and
U type. The errors of these types of CT s are shown in Table 10.1

Table 10.1 CTR Errors

When the primary current increases, at a certain value the core commences to
saturate and the error increases. The value of the primary current at which the error
reaches a specified limit is known as its accuracy limit primary current or
saturation current. The maximum value of the primary current for a given accuracy
limit is specified by the manufacturer. The CT will maintain the accuracy at the
specified maximum primary current at the rated burden. This current is expressed as
a multiple of the rated current. The ratio of accuracy limit primary current and rated
primary current is known as the rated accuracy limit factor or saturation factor, the
standard values of which are 5, 10, 15, 20 and 30. The performance of a CT is given

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at certain multiples of the rated current. According to BSS 3938, rated primary
currents of CTs are up to 75 kA and secondary currents 5 A or 1 A

10.2.9 Open-circuiting of the Secondary Circuit of a CT

If a current transformer has its secondary circuit opened when current is
flowing in its primary circuit, there is no secondary mmf (ampere-turns) to oppose
that due to the primary current and all the primary mmf acts on the core as a
magnetizing quantity. The unopposed primary mmf produces a very high flux
density in the core. This high-flux density results in a greatly increased induced
voltage in the secondary winding. With rated primary current flowing this induced
voltage may be few hundred volts for a small CT but may be many kilovolts for a
large high ratio protective CT. With system fault current flowing, the voltage would
be raised in nearly direct proportion to the current value. Such high voltages are
dangerous not only to the insulation of the CT and connected apparatus but more
important, to the life of the operator. Hence, the secondary circuit of a CT should
never be opened while current is flowing in its primary circuit. If the secondary
circuit has to be disconnected while primary current is flowing, it is essential first to
short-circuit the secondary terminals of the CT. The conductor used for this purpose
must be securely connected and of adequate rating to carry the secondary current,
including what would flow if a fault occurs in the primary system. Most of the
current transformers have a short circuit link or a switch at secondary terminals for
short-circuiting purpose.

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10.2.10 Class X current transformers

These are normally specified for special purpose applications such as busbar
protection, where it is important that CTs have matching characteristics. For this
type of CT an exact point on the magnetization curve is specified, e.g.

1. Rated primary current

2. Turns ratio

3. Rated knee-point emf at maximum secondary turns

4. Maximum exciting current at rated knee-point emf

5. Maximum resistance of secondary winding.

In addition, the error in the turns ratio shall not exceed ±0.25%.

10.3 VOLTAGE TRANSFORMERS (VTs)

Voltage transformers (VTs) were previously known as potential transformers
(PTs). They are used to reduce the power system voltages to standard lower values
and to physically isolate the relays and other instruments (meters) from the high
voltages of the power system. The voltage ratings of the secondary windings of the
VTs have been standardized, so that a degree of interchangeability among relays and
meters of different manufacturers can be achieved. The standard voltage rating of
the secondary windings of the VTs used in practice is 110 V line to line or 110/√3
volts line to neutral. Therefore, the voltage ratings of the voltage (pressure) coils of
protective relays and measuring instrument (meters) are also 110 V line to line or
110/√3 line to neutral. The voltage transformers should be able to provide voltage
signals to the relays and meters which are faithful reproductions of the primary
voltages. The accuracy of voltage transformers is expressed in terms of the departure
of its ratio from its true ration.

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10.3.1 VT Errors
The errors introduced by the use of voltage transformers are, in general, less
serious than those introduced by current transformers. like current transformers,
voltage transformers introduce an error, both in magnitude and in phase, in the
measured value of the voltage. The voltage applied to the primary circuit of the VT
cannot be obtained correctly simply by multiplying the voltage across the secondary
by the turns ratio K of the transformer. The divergence of the actual (true) ratio 𝑉𝑝 /𝑉𝑠
from nominal (rated) ratio K depends upon the resistance and reactance of the
transformer windings as well as upon the value of the exciting current of the
transformer.

10.3.2 Limits of VT Errors for Protection

The accuracy of VTs used for meters and instruments is only important at
normal system voltages, whereas VTs used for protection require errors to be limited
over a wide range of voltages under fault conditions. This may be about 5% to 150%
of nominal voltage. The ratio error and phase angle error for VTs required for
protection according to ISS: 3156 (Part III) 1966 are given in Table 10.2

Table 10.2 VTR Errors

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10.3.3 Type of VTs

Following are two types of voltage transformers.

i. Electromagnetic type VTs

ii. Coupling Capacitor Voltage Transformers (CCVTs)

10.3.3.1 Electromagnetic Type VTs

This type of a VTs is conveniently used up to 132 kV. It is similar to a
conventional wound type transformer with additional features to minimize errors.
As its output is low, it differs from power transformers in physical size and cooling
techniques. In the UK, a 3-phase construction with 5 limbs is used. While in the
USA single phase construction is more common. The voltage rating of a VT governs
its construction. For lower voltages, up to 3.3 kV, dry type transformers with varnish
impregnated and taped windings are quite satisfactory. For higher voltages, oil
immersed VTs are used. Recently VTs with windings impregnated and encapsulated
in synthetic resins have been developed for higher voltages. This technique has made
it possible to use dry type VTs for system voltages up to 66 kV. For voltages above
132 kV, if electromagnetic type VTs to be used, several VTs are connected in
cascade. In cascade connection, the primary windings of CTs are connected in series,
though each primary is on a separate core. Coupling coils are provided along with
each primary to keep the effective leakage inductance to a low value. They also
distribute the voltage equally. Such an arrangement is conveniently placed in a
porcelain enclosure. Electromagnetic type VTs are used at all power system voltages
and are usually connected to the bus. However, coupling capacitor voltage
transformers (CCVTs) are more economical at higher system voltages. As the
voltage decreases, the accuracy of electromagnetic type VTs decreases but is
acceptable down to 1% of normal voltage

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10.3.3.2 Coupling Capacitor Voltage Transformers (CCVTs)

At higher voltages, electromagnetic type VTs become very expensive and
hence it is a common practice to use a capacitance voltage divider as shown in
Fig.10.4. V2 may be only about 10% or less of the system voltage. This arrangement
is called a coupling capacitor voltage transformer (CCVT) or a capacitor type VT
and is used at 132 KV and above. CCVT is one of the most common voltage sources
for relaying at higher voltages. The reactor L is included to tune the capacitor VT to
reduce the ratio and phase angle errors with the variation of VA burden, frequency,
etc. The reactor is adjusted to such a value that at system frequency it resonates with
the capacitors. Capacitor VTs are more economical than electromagnetic type in this
range of system voltage, particularly where high voltage capacitors are used for
carrier-current coupling.

Figure 10.4 Capacitance voltage divider

The transient performance of a capacitor type VT is inferior to that of an

electromagnetic type. A capacitor type VT has the tendency of introducing
harmonics in the secondary voltage. High voltage capacitors are enclosed in a

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porcelain housing. The performance of the voltage divider type capacitor VT is not
as good as that of the electromagnetic type. The performance of high-speed distance
relays is less reliable with capacitor type VTs. Hence, the decision regarding the
choice of a VT will depend whether economy in VT cost or relay performance is
more important for a particular power line. Errors of capacitor type VTs can be
reduced by reducing its burden. It is due to the fact that the series connected
capacitors perform the function of a potential divider if the current drawn by the
burden is negligible compared to the current flowing through the capacitors
connected in series. An electronic amplifier having high input impedance and VA
output high enough to supply the VA burden can be included in the capacitor type
VT arrangement. Such an arrangement gives a good transient response. Finally, it
can be concluded that the secondary voltage supply seldom creates any problem but
problems with secondary current supply arise frequently.

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CHAPTER 11 Protection Systems and Schemes

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11.1 Introduction
The purpose of an electrical power system is to generate and supply electrical
energy to consumers. The system should be designed to deliver this energy both
reliably and economically. Frequent or prolonged power outages result in severe
disruption to the normal routine of modern society, which is demanding ever-
increasing reliability and security of supply. As the requirements of reliability and
economy are largely opposed, power system design is inevitably a compromise.

Many items of equipment are very expensive, and so the complete power system
represents a very large capital investment. To maximise the return on this outlay, the
system must be utilised as much as possible within the applicable constraints of
security and reliability of supply. More fundamental, however, is that the power
system should operate in a safe manner at all times.

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

• Protection System: a complete arrangement of protection equipment and other

devices required to achieve a specified function based on a protection
principle (IEC 60255-20).
• Protection Equipment: a collection of protection devices (relays, fuses, etc.).
Excluded are devices such as Current Transformers (CTs), Circuit Breakers
(CBs) and contactors
• Protection Scheme: a collection of protection equipment providing a defined
function and including all equipment required to make the scheme work (i.e.
relays, CTs, CBs, batteries, etc.)

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11.1.1 Classification of Relays and Basic requirements

▪ Relays can be divided into six functional categories:
1. Protective relays: Detect defective lines, defective apparatus, or other
dangerous or intolerable conditions. These relays generally trip one or more
circuit breakers, but may also be used to sound an alarm.
2. Monitoring relays: Verify conditions on the power system or in the
protection system. These relays include fault detectors, alarm units, channel-
monitoring relays, synchronism verification, and network phasing. Power
system conditions that do not involve opening circuit breakers during faults
can be monitored by verification relays.
3. Reclosing relays: Establish a closing sequence for a circuit breaker following
tripping by protective relays.
4. Regulating relays: Are activated when an operating parameter deviates from
predetermined limits. Regulating relays function through supplementary
equipment to restore the quantity to the prescribed limits.
5. Auxiliary relays: Operate in response to the opening or closing of the
operating circuit to supplement another relay or device. These include timers,
contact-multiplier relays, sealing units, isolating relays, lock-out relays,
closing relays, and trip relays.
6. Synchronizing (or synchronism check) relays: Assure that proper
conditions exist for interconnecting two sections of a power system.

▪ Relays may be classified according to the technology used:

1. Electromechanical Relays: Based on magnetic attraction, magnetic
induction, and thermal units.
2. Static Relays: Using state devices and logic gates.

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3. Numerical Relays: are those in which the measured ac quantities are

sequentially sampled and converted into numeric data form. A microprocessor
performs mathematical and or logical operations on the data to make trip
decisions.

▪ Basic Requirements of a Protective Relay:

1. Speed 2. Selectivity and Discrimination
3. Sensitivity and Stability 4. Reliability
5. Simplicity 6. Economy and adequateness

11.1.2 Zones of protection

Figure 11.1 Division of power systems into protection zones

• The boundaries of the protective zone are decided by the locations of the
transducers or the CT’s.
• In order to cover all power equipment by their protection systems, the zones of
protection must meet these requirements:
i) All power system elements must be covered by at least one zone.
ii) Zones of protection must overlap to prevent any system element from
being unprotected.

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• A zone of protection may be closed or open.

• When the zone is closed, all power elements inside the zone are protected. All
the circuit breakers inside the zone must trip.
• For open zones such as in long TL or distribution systems, time or magnitude
coordination must apply.

11.1.3 Main and backup protection

The reliability of a power system has been discussed earlier, including the use
of more than one primary (or ‘main’) protection system operating in parallel. In the
event of failure or non-availability of the primary protection some other means of
ensuring that the fault is isolated must be provided. These secondary systems are
referred to as ‘back-up protection schemes’.

Back-up protection may be considered as either being ‘local’ or ‘remote’. Local

back-up protection is achieved by protection that detects an un-cleared primary
system fault at its own location, which then trips its own circuit breakers; e.g. time
graded overcurrent 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 trip
command to the relevant relay; 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. 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

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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. Back-up overcurrent 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. For example, a circuit protected by a current differential relay may also
have time graded overcurrent and earth fault relays added to provide circuit breaker
tripping in the event of failure of the main primary unit protection. Ideally, to
maintain complete redundancy, all system components would be duplicated. This
ideal is rarely attained in practice.

11.1.4 Tripping circuits

There are three main circuits in use for circuit

breaker tripping:

• series sealing
• shunt reinforcing
• shunt reinforcement with sealing

Figure 11.2 Typical relay tripping circuits

11.1.5 Trip circuit supervision

The simplest arrangement contains a healthy trip lamp or LED, as shown in Figure
11.3(a).

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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.

Figure 11.3(b) shows how, the addition of a

normally closed auxiliary switch and a
resistance unit can provide supervision
while the breaker is both open and closed.

Schemes using a lamp to indicate continuity

are suitable for locally controlled
installations, but when control is exercised
Figure 11.3 Trip circuit supervision circuit
from a distance it is necessary to use a relay
system. Figure 11.3(c) illustrates such a scheme, which is applicable wherever a
remote signal is required.

With the circuit healthy either or both of relays A and B are operated and energise
relay C. Both A and B must reset to allow C to drop-off. Relays A, B and C are time
delayed to prevent spurious alarms during tripping or closing operations. The
resistors are mounted separately from the relays and their values are chosen such
that if any one component is inadvertently short-circuited, tripping will not take
place.

The alarm supply should be independent of the tripping supply so that indication
will be obtained in case of failure of the tripping supply.

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11.2 Feeder Protection

Other than for lower voltage distribution feeders, where an overcurrent relay
may be applied, generally differential and/or distance protection is applied as the
main (fast-acting) protection.

Figure 11.4 Typical basic protection for sub-transmission feeder

11.2.1 Distance Relay

Since the impedance of a transmission line is proportional to its length, for

distance measurement it is appropriate to use a relay capable of measuring the
impedance of a line up to a predetermined point (the reach point). The basic principle
of distance protection involves the division of the voltage at the relaying point by
the measured current. The apparent impedance so calculated is compared with the
reach point impedance. If the measured impedance is less than the reach point
impedance, it is assumed that a fault exists on the line between the relay and the
reach point.

• The most common distance relay characteristics include:

1. Impedance Characteristic.
2. Directional Impedance Characteristic.
3. Self-Polarized Mho (Admittance) Characteristic.
4. Offset Mho Characteristic.

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5. Quadrilateral Characteristic.
6. Reactance Type Characteristic.
7. Lenticular Characteristic.

11.2.1.1 Step Distance protection

Figure 11.5 Distance protection Zones

1. Zone 1:
• Trips with no intentional time delay.
• Under reaches to avoid unnecessary operation for faults beyond remote
terminal.
• Typical reach setting range 80-90% of ZL.
2. Zone 2:
• Set to protect remainder of line.
• Overreaches into adjacent line/equipment.
• Minimum reach setting 120% of ZL.
• Typically, time delayed by 15-30 cycles.
3. Zone 3:
• Remote backup for relay/station failures at remote terminal.
• Reaches beyond Z2, may covers the whole adjacent line.

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11.2.1.2 Problems facing distance protection

1. Over Reach
• The protection device can see the far fault as if it is close if the fault is
negative, meaning that it sees the measured impedance as less than the real
one, and in this case, we say that it has got over reach.
2. Parallel Lines
• This problem is considered a type of over-reach, but when there are two
parallel lines.
3. Under Reach
• This problem is the opposite of the first problem that we mentioned, and here
the protection device can see the near fault as if it is far if the error is positive,
meaning that it sees the measured impedance is greater than the real, and in
this case, we say that it got under rich.
4. Load Encroachment
• While Loads increasing, Z decreasing Which may consider a fault for load
increasing
𝑉
• Z load min should be calculated = 0.9
𝐼𝑀𝐴𝑋

• After calculating Zmin , it should be cut from curve .

Figure 11.6 Load Encroachment

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5. Zero Sequence Compensation

• For Single phase fault, Current passing through the faulty phase = 𝐼1 + 𝐼0
while in healthy phases =𝐼0
• Current passing through the neutral = 3𝐼0
• The impedance calculated by the relay = V/(I1+I0), While it should be 𝑣⁄𝐼1
• So, Zero Sequence compensation factor should be calculated
𝑘0 = (𝑧0 − 𝑧1 )/3 𝑧1
6. Power Swing
• It occurs due to a change in the values of the angles and the voltages of the
generators, and thus the value of the delta changes between Vs and Vr.
• And therefore, the protection device will see that the impedance enters and
exits from the protection zone because it increases and decreases, and in the
event of a fault, it will see that the impedance goes out only, there will be a
change in the impedance, so they will totally be blocked.

Figure 11.7 Power Swing

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11.2.2 Line Current Differential Relay

Line current differential relays operate on a difference in current into the line
compared to the current out of the line. This is called current differential method.
The differential current can be measured in different ways:

• Magnitude comparison
• Phase comparison
• Phasor or Directional comparison (magnitude and angle)

• Working of Line Current Differential Relay

Line differential relays basically operate on a difference in current into the line,
compared to the current out of the line. For an internal fault, the current will flow
into the line from both line terminals, with the polarity of the current transformers
as shown in Figure

Figure 11.8 Line Current Differential Relay-Scheme

The above figure shows this for a line with two ends. Each device measures the local
current and sends the information of measured currents and phase relation to the
opposite end.

𝐼𝑂𝑝𝑒𝑟𝑎𝑡𝑒 = 𝐼 𝐿𝑜𝑐𝑎𝑙 – 𝐼𝑅𝑒𝑚𝑜𝑡𝑒

𝐼 𝑅𝑒𝑠𝑡𝑟𝑎𝑖𝑛𝑡 = ( 𝐼 𝐿𝑜𝑐𝑎𝑙 + 𝐼𝑅𝑒𝑚𝑜𝑡𝑒 )/2

%𝑆𝑙𝑜𝑝𝑒 = (𝐼𝑂𝑝𝑒𝑟𝑎𝑡𝑒 / 𝐼 𝑅𝑒𝑠𝑡𝑟𝑎𝑖𝑛𝑡 ) ∗ 100

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Two relays at each end of the cable separated by some distance with the
communication path between the two relays so that they exchange information
together.

• These relays operate on a current differential method.

• These relays connected using fiber to transit digital information.
• The digital information contains the current magnitudes and other diagnostic
parameters and is transmitted continuously between connected stations.
• Tripping is initiated when differential relay exceeds the relays restraint
characteristic.
• Failure of the fiber communication path will automatically block the scheme and
initiate an alarm.
• There is a chance to break the communication medium due to any reason, so
distance relay function used as back up to the line current differential relays

11.2.3 Common communication schemes

• Direct transfer trip (DTT)

• Permissive under-reach transfer trip (PUTT) scheme
• Permissive overreach transfer tripping (POTT) scheme
• Blocking scheme

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11.2.4 Relay and Metering of feeder bay

Figure 11.9 RMOLD of feeder bay

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11.3 Transformer Protection

11.3.1 Purpose of transformer protection

The main purpose of power transformer protection can be summarized as

follows:

• Protecting the transformer from external faults such as: various short circuits,
voltage surges, and overload.
• Protection of the electrical network connected to the transformer.
• Protecting the parts surrounding the transformer at the time of fault
• Observing and monitoring the operation of transformers in order to reduce
risks as much as possible at the time of fault occurrence.

11.3.2 Types of Faults Encountered in Transformers

The faults encountered in transformer can be placed in two main groups:

a) External faults (or through faults)

b) Internal faults

11.3.2.1 External Faults

In case of external faults, the transformer must be disconnected if other
protective devices meant to operate for such faults, fail to operate within a
predetermined time. For external faults, time graded overcurrent relays are employed
as back-up protection. Also, in case of sustained overload conditions, the transformer
should not be allowed to operate for long duration. Thermal relays are used to detect
overload conditions and give an alarm.

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11.3.2.2 Internal Faults

The primary protection of transformers is meant for internal faults. Internal faults
are classified into two groups.

(i) Short circuits in the transformer winding and connections These are
electrical faults of serious nature and are likely to cause immediate
damage. Such faults are detectable at the winding terminals by unbalances
in voltage or current. This type of faults include line to ground or line to
line and interturn faults on H.V. and L.V. windings.

(ii) Incipient faults Initially, such faults are of minor nature but slowly might
develop into major faults. Such faults are not detectable at the winding
terminals by unbalance in voltage or current and hence, the protective
devices meant to operate under short circuit conditions are not capable of
detecting this type of faults. Such faults include poor electrical
connections, core faults, failure of the coolant, regulator faults and bad
load sharing between transformers.

Winding and Terminal Core Tank and Accessories OLTC

Figure 11.10 Transformer fault statistics

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11.3.3 Considerations for selecting protection system

The protection methods used in transformers vary according to the power level
of each transformer. Transformers are usually categorized according to their ratings
as follows:

Category Single phase (kVA) Three phase (KVA)

I 5 to 500 15 to500
II 501 to 1667 501 to 5000
III 1668 to 10000 5001 to 30000
IV Above 10000 Above 30000
Table 11.1 Transformer categories Rating

Small transformers may only use the fuse as their main protection, while the levels
of protection vary to more than five types in large transformers, including
differential protection, overcurrent protection, restricted earth fault protection and
others.

Therefore, the transformer used in the Zahraa Al-Mokattam 220/22KV GIS

Substation, with a rated 75 MVA, is under category IV.

The types of protection devices to be installed on a 75 MVA transformer can be

summarized:

• Differential protection.
• Restricted earth fault protection.
• Overcurrent protection.
• Over flux protection.
• Mechanical protection.

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11.3.4 Types of Transformer Protection

11.3.4.1 Differential protection – ANSI 87T

- The following are the various types of differential protection:

• Simple (basic) differential protection.
• Percentage (biased) differential protection.
• Balanced (opposed) voltage differential protection.

▪ Percentage (biased) differential protection

Percentage differential protection is used for the protection of large power

transformers having ratings of 5 MVA and above. This scheme is employed for the
protection of transformers against internal short circuits. It is not capable of detecting
incipient faults. Figure 6.10 shows the schematic diagram of percentage differential
protection for a Y – D transformer. The direction of current and the polarity of the
CT voltage shown in the figure are for a particular instant. The convention for
marking the polarity for upper and lower CTs is the same. The current entering end
has been marked as positive. The end at which current is leaving has been marked
negative.

Figure 11.11 Percentage differential protection for Y - ∆ connected

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O and R are the operating and restraining coils of the relay, respectively. The
connections are made in such a way that under normal conditions or in case of
external faults the current flowing in the operating coil of the relay due to CTs of the
primary side is in opposition to the current flowing due to the CTs of the secondary
side. Consequently, the relay does not operate under such conditions. If a fault occurs
on the winding, the polarity of the induced voltage of the CT of the secondary side
is reversed. Now the currents in the operating coil from CTs of both primary and
secondary side are in the same direction and cause the operation of the relay. To
supply the matching current in the operating winding of the relay, the CT which are
on the star side of the transformer are connected in delta. The CTs which are on the
delta side of the transformer are connected in star. In case of Y – ∆ connected
transformer there is a phase shift of 30° in line currents. Also the above mentioned
CTs connections also correct this phase shift. Moreover, zero sequence current
flowing on the star side of the transformers does not produce current outside the
delta on the other side. Therefore, the zero sequence current should be eliminated
from the star side. This condition is also fulfilled by CTs connection in delta on the
star side of the transformer.

In case of star/star connected transformer CTs on both sides should be connected in

delta. In case of star/star connected transformer, if star point is not earthed, CTs may
be connected in star on both sides. If the star point is earthed and CTs are connected
in star, the relay will also operated for external faults. Therefore, it is better to follow
the rule that CTs associated with star-connected transformer windings should be
connected in delta and those associated with delta windings in star.

The relay settings for transformer protection are kept higher than those for
alternators. The typical value of alternator is 10% for operating coil and 5% for bias.

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The corresponding values for transformer may be 40% and 10% respectively. The
reasons for a higher setting in the case of transformer protection are.

(i) A transformer is provided with on-load tap changing gear. The CT ratio
cannot be changed with varying transformation ratio of the power
transformer. The CT ratio is fixed and it is kept to suit the nominal ratio of
the power transformer. Therefore, for taps other than nominal, an out of
balance current flows through the operating coil of the relay during load
and external fault conditions.
(ii) When a transformer is on no-load, there is no-load current in the relay.
Therefore, its setting should be greater than no-load current.

Figure 11.12 Operating characteristic of percentage differential relay

Figure 11.13 Bias setting of percentage differential relay

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11.3.4.2 Restricted earth fault protection

A simple overcurrent and earth fault relay does not provide good protection for
a star connected winding, particularly when the neutral point is earthed through an
impedance. Restricted earth fault protection, as shown in Fig. 11.14 provides better
protection. This scheme is used for the winding of the transformer connected in star
where the neutral point is either solidly earthed or earthed through an impedance.
The relay used is of high impedance type to make the scheme stable for external
faults.

Figure 11.14 Earth fault protection of a power transformer

For delta connection or ungrounded star winding of the transformer, residual

overcurrent relay as shown in Fig. 11.14 is employed. The relay operates only for a
ground fault in the transformer.

The differential protection of the transformer is supplemented by restricted earth

fault protection in case of a transformer with its neutral grounded through resistance.
For such a case only about 40% of the winding is protected with a differential relay
pick-up setting as low as 20% of the CT rating.

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11.3.4.3 Overcurrent protection

The overcurrent protection device is installed as the main protection to protect

the transformer against types of short circuits for transformers whose capacity ranges
from 511 kVA to 5 MVA, where the installation of a differential protection device
for power transformers higher than 5 MVA is costly, while it is sufficient in the case
of transformers Less power than 511 kVA using fuses with large cutting capacity
installed on the high voltage side of the transformer.

The overcurrent protection device, in addition to the restricted earth fault protection
device, is a backup protection against faults that occur outside the protection area in
the case of transformers with a capacity higher than 5 MVA.

The importance of using this protection appears in two cases:

1. When the transformer is exposed to external faults, causing a large current to

pass through the transformer, which causes the transformer to heat up and is
negatively affected by this temperature.
2. When the transformer is exposed to an overload above its rated load.

And this protection is installed on the high voltage and low voltage sides of the
transformer. They are considered as backup protection for the differential protection
on the transformer. And it is necessary to make a time coordination between them
to ensure the speed of separation from the low voltage side first. And overcurrent
relays contain special high set (instantaneous) element with high standards that are
useful in cases of severe short circuits.

It is also necessary to ensure that this protection does not operate when an inrush
current passes. Fig. 11.15 shows the connection of overcurrent protection devices on
both sides of the high voltage and low voltage from the power transformer.

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Figure 11.15 Connection of overcurrent protection devices on both sides of a power transformer

It also shows the time coordination between them by choosing the appropriate time
curve for the protection devices on both sides of the power transformer, as shown in
Figure No. (). When a fault occurs that causes the passage of a current of a value,
the time taken to disconnect the secondary side breaker must be faster (less) than the
time taken to disconnect the breaker of the primary side.

Figure 11.16 Coordination between HV & LV sides of Transformer

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11.3.4.4 Over flux protection

The magnetic flux increases when voltage increases. This results in increased
iron loss and magnetising current. The core and core bolts get heated and the
lamination insulation is affected. Protection against over fluxing is required where
overfluxing due to sustained overvoltage can occur. The reduction in frequency also
increases the flux density and consequently, it has similar effects as those due to
overvoltage. The expression of flux in a transformer is given by:

𝐸
∅=𝐾
𝑓

where, ∅ = flux, f = frequency, E = applied voltage and K = constant.

Therefore, to control flux, the ratio E/f is controlled. When E/f exceeds unity, it has
𝐸
to be detected. Electronic circuits with suitable relays are available to measure the
𝑓
𝐸
ratio. Usually 10% of overfluxing can be allowed without damage. If exceeds 1.1,
𝑓

overfluxing protections operates. Overfluxing does not requires high speed tripping
and hence instantaneous operation is undesirable when momentary disturbances
occur. But the transformer should be isolated in one or two minutes at the most if
overfluxing persists.

Figure 11.17 characteristics of over flux protection

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11.3.4.5 Mechanical protection

Mechanical protection of transformer does not depend directly on the electrical

quantities such as voltage or current. rather, it depends on some mechanical
parameters such as pressure and temperature.

In general, the mechanical protection is divided to:

Pressure devices Temperature devices:

Buchholz relay. Oil temperature.
Sudden pressure relay. Winding temperature.
Pressure relief device.
Table 11.2 Types of Mechanical Protection

Buchholz relay

Buchholz protection is normally provided on all transformers fitted with a

conservator. The Buchholz relay is contained in a cast housing which is connected
in the pipe to the conservator, as in Figure 11.18 .

Figure 11.18 Buchholz Relay mounting arrangement

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A typical Buchholz relay will have two sets of contacts. One is arranged to operate
for slow accumulations of gas, the other for bulk displacement of oil in the event of
a heavy internal fault. An alarm is generated for the former, but the latter is usually
direct-wired to the CB trip relay. The device will therefore give an alarm for the
following fault conditions, all of which are of a low order of urgency.

• hot spots on the core due to short circuit of lamination insulation.

• core bolt insulation failure.
• faulty joints.
• interturn faults or other winding faults involving only lower power infeeds.
• loss of oil due to leakage.

When a major winding fault occurs, this causes a surge of oil, which displaces the
lower float and thus causes isolation of the transformer. This action will take place
for:

• all severe winding faults, either to earth or interphase

• loss of oil if allowed to continue to a dangerous degree

An inspection window is usually provided on either side of the gas collection space.
Visible white or yellow gas indicates that insulation has been burnt, while black or
grey gas indicates the presence of, dissociated oil. In these cases, the gas will
probably be inflammable, whereas released air will not. A vent valve is provided on
the top of the housing for the gas to be released or collected for analysis.
Transformers with forced oil circulation may experience oil flow to/from the
conservator on starting/stopping of the pumps. The Buchholz relay must not operate
in this circumstance. Cleaning operations may cause aeration of the oil. Under such
conditions, tripping of the transformer due to Buchholz operation should be inhibited
for a suitable period. Because of its universal response to faults within the

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transformer, some of which are difficult to detect by other means, the Buchholz relay
is invaluable, whether regarded as a main protection or as a supplement to other
protection schemes. Tests carried out by striking a high voltage arc in a transformer
tank filled with oil, have shown that operation times of 0.05s-0.1s are possible.
Electrical protection is generally used as well, either to obtain faster operation for
heavy faults, or because Buchholz relays have to be prevented from tripping during
oil maintenance periods. Conservators are fitted to oil-cooled transformers above
1000kVA rating, except those to North American design practice that use a different
technique.

Sudden Pressure Rise Relay

Figure 11.19 Sudden Pressure Rise Relay

This device detects rapid rise of pressure rather than absolute pressure and
thereby can respond even quicker than the pressure relief valve to sudden abnormally
high pressures. Sensitivities as low as 0.07bar/s are attainable, but when fitted to
forced-cooled transformers the operating speed of the device may have to be slowed
deliberately to avoid spurious tripping during circulation pump starts. Alternatively,
sudden pressure rise relays may have their output supervised by instantaneous high-
set overcurrent elements.

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Oil Pressure Relief Devices

Figure 11.20 Oil Pressure Relief Relay

The simplest form of pressure relief device is the widely used ‘frangible disc’ that is
normally located at the end of an oil relief pipe protruding from the top of the
transformer tank. The surge of oil caused by a serious fault bursts the disc, so
allowing the oil to discharge rapidly. Relieving and limiting the pressure rise avoids
explosive rupture of the tank and consequent fire risk. Outdoor oil-immersed
transformers are usually mounted in a catchment pit to collect and contain spilt oil
(from whatever cause), thereby minimising the possibility of pollution. A drawback
of the frangible disc is that the oil remaining in the tank is left exposed to the
atmosphere after rupture. This is avoided in a more effective device, the sudden
pressure relief valve, which opens to allow discharge of oil if the pressure exceeds a
set level, but closes automatically as soon as the internal pressure falls below this
level. If the abnormal pressure is relatively high, the valve can operate within a few
milliseconds, and provide fast tripping when suitable contacts are fitted. The device
is commonly fitted to power transformers rated at 2MVA or higher, but may be
applied to distribution transformers rated as low as 200kVA, particularly those in
hazardous areas.

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Winding Thermometer

The winding thermometer, responds to both the top-oil temperature and the
heating effect of the load current. The winding thermometer creates an image of the
hottest part of the winding. However, the top-oil temperature can be measured, the
top-oil temperature may be considerably lower than the winding temperature,
especially shortly after a sudden load increase. This means that the top-oil
thermometer is not an effective overheating protection. Accordingly, the
measurement is further expanded with a current signal proportional to the loading
current in the winding. This current signal is taken from a current transformer located
inside the bushing of that particular winding.

Figure 11.21Winding Thermometer

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11.3.5 Relay and Metering of Transformer 220/22 KV

Control & Busbar

Panels Protection panel
Metering panel protection panel

Bay control unite

Differential Relay (87T)
(BCU)

Overcurrent (51) Fault annunciator

Main 1 Directional overcurrent Panel
Breaker Failure
relay (67) Accessories +
(BF)
Mimic With
Thermal relay (49)
Control Switches
Differential Relay (87T) Multi-meter

Overcurrent (51) AVR

Content of Main 2 Directional overcurrent Winding
each panel
relay (67) tempreture
Thermal relay (49) indicator (WTI)

Separate restricted earth fault Relay

(87G) on HV side Oil tempreture
Separate restricted earth fault Relay indicator (OTI) Centralized BBP

(87G) on LV side
Separate over flux Relay (24)
Tap Position
Trip circuit supervision Relay
indicator (TPI)
Lockout Relay (86)

Table 11.3 RMOLD

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Relay and Metering (RMOLD)

Figure 11.22 RMOLD of transformer bay

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11.4 Busbar protection

The Busbar is considered one of the least components of the electrical power
system that are subject to faults, however, it is considered the most dangerous one if
a fault happens on it because if a fault happens on it then all incoming or outgoing
loads connected to busbar will be out of service. Therefore, Busbar protection is
considered the most important protection that should be done correctly because of
its consequences if it fails like losing important loads or maybe could lead to station
combustion.

11.4.1 Bus-bar protection requirements

The successful protection can be achieved subject to compliance with the following:

1. Stability 2. Selectivity
• Not to operate for faults outside • Trip only the faulted equipment
the zone • Important for busbars divided
• Most important for busbars into zones
3. Speed
• Limit damage at fault point
• Limit effect on fault stability

11.4.2 Busbar protection types

• Frame leakage protection

• High-impedance differential protection
• Low-impedance biased differential protection
• Busbar blocking

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11.4.2.1 Busbar differential protection

The differential protection principal for high and low impedance differential
protection is based on the Kirchhoff’s Law, that all currents measured around a
protected element (line, transformer, generator, motor, bus) must under normal (non-
fault) condition sum up to zero.

Figure 11.23 The Differential protection for a bus-bar

A current sum unequal to zero would indicate a fault in the protected element. The
simplest way to obtain this current summation on a bus is by paralleling all current
transformer surrounding the bus zone. To be able to do this, all current transformers
need to have the same transformation ratio. As shown in figure 6.17, the sum of all
current can be measured and an overcurrent element would be sufficient to detect an
internal bus fault. On all external faults the measured current would be zero under
ideal measurement conditions. Basically, all differential protection algorithms are
based on this principle. However, the required “ideal measurement conditions” are
hard to achieve with inductive current transformer.

11.4.2.1.1 Low impedance differential protection

Low impedance differential protection scheme does not require dedicated CTs.
This scheme has capabilities to tolerate substantial CT saturation during external
faults. It also provides relatively high tripping speed. Microprocessor based relays

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makes this scheme to become attractive to most protection engineers because of its
advance algorithms for percent differential protection functions. Re-configuration of
bus-bar protection became less complex. Possibilities of replacing Data Acquisition
Units (DAU) in bays by utilizing distribution architectures have become
implementable.

Figure 11.24 Low Impedance bus Differential Protection diagram

11.4.2.1.2 High impedance differential protection

A High-impedance bus differential relay includes high impedance to the flow
of CT secondary current. The basic concept of this type of relaying involves taking
the paralleled output of all CTs in the system and connecting them to a common bus
which is then wired to the high-impedance bus differential relay as shown in Figure
11.25 . Ideally, the paralleled CTs must have the same full ratio, have their secondary
wound on a toroidal core with the winding fully distributed about the core (bushing
type CTs), and have the same accuracy class. Proper polarity connection is also
required to ensure that the secondary current outputs vector-sum to zero the same
way the primary currents in the bus do under normal through-load conditions. The
summation point for the CTs is frequently made in a junction box located in a
switchyard with equal distance from each breaker to minimize the effect of unequal
lead resistance. The summation point of each phase is then brought to the control

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house and connected to the relay. The relay operates based on the rising voltage
which appears at the summing point when differential current flows through the high
impedance operate circuit.

Figure 11.25 High Impedance bus Differential Protection diagram

The high-impedance input of the relay generally has an internal impedance of 1000
ohms or higher, depending on manufacturer, that is typically resistive. For non-fault
conditions, the currents are balanced sufficiently so that the voltage across the relay's
impedance is near zero. The weakest CT, fully saturated for an external fault, with
all other CTs operating normally should be calculated to establish the starting point
for the internal fault trip setting. This process is followed to prevent unwanted
operation for an external fault. For an internal fault, all CTs try to force the
differential current through the high-impedance input, creating the voltage drop used
to trip for the internal fault condition. At this point, the voltage which appears across
the relay is essentially the open-circuit voltage of the CTs. The resultant high voltage
is the signature for fault detection. High-impedance differential relays typically have
a means to control this high voltage to prevent CT, cable, and relay insulation
breakdown. The two main methods for controlling this high voltage are non-linear
impedances such as a Metal-Oxide Varistor (MOV), paralleling with stabilizing
resistance, and a static switching device such as a Silicon Controlled Rectifier
(SCR).

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CHAPTER 12 Relay coordination study

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12.1 Over current protection

Correct overcurrent relay application requires knowledge of the fault current that
can flow in each part of the network. Since large-scale tests are normally
impracticable, system analysis must be used Correct overcurrent relay application
requires knowledge of the fault current that can flow in each part of the network.
Since large-scale tests are normally impracticable, system analysis must be used The
data required for a relay setting study are:

• a one-line diagram of the power system involved, showing the type and rating
of the protection devices and their associated current transformers
• the impedances in ohms, per cent or per unit, of all power transformers,
rotating machine and feeder circuits
• the maximum and minimum values of short circuit
• currents that are expected to flow through each protection device
• the maximum load current through protection devices
• the starting current requirements of motors and the starting and locked
rotor/stalling times of induction motors
• the transformer inrush, thermal withstand and damage characteristics
• decrement curves showing the rate of decay of the fault current supplied by
the generators
• 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. It is always advisable to plot the curves of
relays and other protection devices, such as fuses, that are to operate in series, on a
common scale. It is usually more convenient to use a scale corresponding to the

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current expected at the lowest voltage base, or to use the predominant voltage base.
The alternatives are a common MVA base or a separate current scale for each system
voltage.

The basic rules for correct relay co-ordination can generally be stated as follows:

• whenever possible, use relays with the same operating characteristic in series
with each other.
• make sure that the relay farthest from the source has current settings equal to
or less than the relays behind it, that is, that the primary current required to
operate the relay in front is always equal to or less than the primary current
required to operate the relay behind it.

12.2 Purpose of OC protection:

• Detect abnormal conditions.

• Isolate faulty part of the system.
• Speed fast operation to minimize damage and danger.
• Discrimination isolate only the faulty section.
• Dependability / Reliability.
• Security / Stability.

12.3 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. That is to say, each one

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must isolate only the faulty section of the power system network, leaving the rest of
the system undisturbed.

1. Discrimination by Time
2. Discrimination by Current
3. Discrimination by both Time and Current

12.4 Standard IDMT overcurrent relay

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)

The mathematical descriptions of the curves are given in Table 12.1, and the curves
based on a common setting current and time multiplier setting of 1 second are shown
in Figure 12.1.

The tripping characteristics for different TMS settings using the SI curve are shown
in Figure 12.1.

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Figure 12.1 Relay characteristics

Relay Characteristic Equation (IEC 60255)

0.14
Standard Inverse (SI) 𝑡 = 𝑇𝑀𝑆 𝑥 0.2
𝐼𝑟 −1
13.5
Very Inverse (VI) 𝑡 = 𝑇𝑀𝑆 𝑥
𝐼𝑟 − 1
80
Extremely Inverse (EI) 𝑡 = 𝑇𝑀𝑆 𝑥
𝐼𝑟 2 − 1
120
Long time standby earth fault 𝑡 = 𝑇𝑀𝑆 𝑥
𝐼𝑟 − 1
Table 12.1 Definitions of standard relay characteristics

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12.5 Overcurrent sitting

Steps to set the sitting of OC Relay:

1. Calculate the pickup current

2. Select inverse time curve
3. choose value of instantaneous trip

The pickup values for:

1. load bay
• The cable cross- sectional area for outgoing cell from specs (630𝑚𝑚2 )
• The current rating of 630𝑚𝑚2 cable is equal = 741 A
• The Derated current of cable is equal = 741 x 0.5 = 370.5A =𝐼𝑟𝑎𝑡𝑒𝑑

1.25∗370.5∗1
• Phase (overcurrent) → 𝐼𝑝𝑖𝑐𝑘𝑢𝑝 = = 1.1578125 𝐴
400
8∗370.5∗1
• Phase (Instantaneous) → 𝐼𝑝𝑖𝑐𝑘𝑢𝑝 = = 7.41 𝐴
400
0.1∗370.5∗1
• Ground (overcurrent) → 𝐼𝑝𝑖𝑐𝑘𝑢𝑝 = = 0.092625 𝐴
400
0.5∗370.5∗1
• Ground (Instantaneous) → 𝐼𝑝𝑖𝑐𝑘𝑢𝑝 = = 0.463125𝐴
400

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2. Auxiliary transformer bay

500 𝑥 103
• 𝐼𝑟𝑎𝑡𝑒𝑑 = = 13.121597 𝐴
√3 𝑥 22 𝑥 103
1.25∗13.121
• Phase (overcurrent) → 𝐼𝑝𝑖𝑐𝑘𝑢𝑝 = = 0.32803 𝐴
50
8∗13.1215∗1
• Phase (Instantaneous) → 𝐼𝑝𝑖𝑐𝑘𝑢𝑝 = = 2.309401 𝐴
50
0.1∗13.121∗1
• Ground (overcurrent) → 𝐼𝑝𝑖𝑐𝑘𝑢𝑝 = = 0.026243 𝐴
50
0.5∗13.121∗1
• Ground (Instantaneous) → 𝐼𝑝𝑖𝑐𝑘𝑢𝑝 = = 0.131259𝐴
50

3. Bus coupler bay

75 𝑥 106
• 𝐼𝑟𝑎𝑡𝑒𝑑 = = 1968.2395 𝐴
√3 𝑥 22 𝑥 103
1.25∗1968.2395
• Phase (overcurrent) → 𝐼𝑝𝑖𝑐𝑘𝑢𝑝 = = 0.98411 𝐴
2500
0.1∗1968.23∗1
• Ground (overcurrent) → 𝐼𝑝𝑖𝑐𝑘𝑢𝑝 = = 0.07872 𝐴
2500

4. LV 75MVA TR bay
75 𝑥 106
• 𝐼𝑟𝑎𝑡𝑒𝑑 = = 1968.2395 𝐴
√3 𝑥 22 𝑥 103
1.25∗1968.2395
• Phase (overcurrent) → 𝐼𝑝𝑖𝑐𝑘𝑢𝑝 = = 0.98411 𝐴
2500
0.1∗1968.23∗1
• Ground (overcurrent) → 𝐼𝑝𝑖𝑐𝑘𝑢𝑝 = = 0.07872 𝐴
2500

5. HV 75MVA TR bay
75 𝑥 106
• 𝐼𝑟𝑎𝑡𝑒𝑑 = = 196.82395 𝐴
√3 𝑥 220 𝑥 103
1.25∗196.82395
• Phase (overcurrent) → 𝐼𝑝𝑖𝑐𝑘𝑢𝑝 = = 0.61507 𝐴
400
8∗196.82395 ∗1.1
• Phase (Instantaneous) → 𝐼𝑝𝑖𝑐𝑘𝑢𝑝 = = 4.3301 𝐴
400
0.1∗196.823∗1
• Ground (overcurrent) → 𝐼𝑝𝑖𝑐𝑘𝑢𝑝 = = 0.04920 𝐴
400
0.5∗196.82395∗1
• Ground (Instantaneous) → 𝐼𝑝𝑖𝑐𝑘𝑢𝑝 = = 0.2460𝐴
400

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Use Standard Inverse (SI):

0.14 𝐼𝑓𝑜𝑢𝑙𝑡
𝑡 = 𝑇𝑀𝑆 𝑥 , 𝐼𝑟 =
𝐼𝑟 0.2 − 1 𝐼𝑝𝑖𝑐𝑘𝑢𝑝

12.5.1 ETAP program

SLD

Figure 12.2 ETAP MODEL

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Input Data to Relay

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CASE_1 at Normal operation (the CB in bus coupler is open)

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Fault @load Bay : Fault @ Aux. Tr bay

Fault @ 22kv Busbar

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CASE_2 at abnormal operation (the CB in bus coupler is closed)

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Foult @ load bay

Foult @ bus coupler bay

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Foult @ LV TR Side

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12.5.2 Time coordination Curve (TCC)

Figure 12.3 Time Coordination Curve (TCC)

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12.5.3 calculation pickup Currents using EXCEL sheet

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CHAPTER 13 Control & Monitoring

CHAPTER 13 SUBSTATION CONTROL &

MONITORING

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CHAPTER 13 Control & Monitoring

13.1 Introduction
In order to operate the substation effectively, a control system which indicates
the status of all plant including alarms and indications of secondary system
equipment; shows analogue values for the key parameters such as voltage, current,
megawatts, and megavars; as well as provides digital outputs to close and open
switchgear, raise and lower taps on transformers, etc. is required. In addition to the
basic indications and controls, other functions such as synchronizing, voltage and/or
reactive control, interlocking for both safety and operational reasons, load control to
avoid frequency collapse, etc. may also be applied. Other functions such as
automatic closing or reclosing to optimize the performance of the network may be
needed, and in some instances-controlled switching, i.e., point on wave control of
closing or opening, may be used to reduce switching transients on the network.

13.2 Basic Control System

In most cases the substation control and monitoring system allows for three levels
of supervision and control (or points of human machine interface HMI). However,
the number of levels employed will be dependent on local practice and may be
restricted to the first two levels of control.

• In the switchyard/switchgear buildings (bay control)

• At the substation control room (station control)
• From a central network control center (network control, remote control center,
regional control center)

At any moment, only one control point shall be in service, and the rules to switch
control points (control arbitration) are user-definable, but usually selection between
bay or station control will be from the bay control point and may be on an individual

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equipment basis. Selection between station or network control will be from the
station control point and may be on a per-circuit basis. The facilities at each point
will vary in terms of the equipment being controlled, the indications, and the alarms
available. Alarms may be grouped for station and network control points to suit
individual requirements. Generally, alarms and indications necessary for the safe
and satisfactory operation of the substation should be provided at each control point.
Special facilities, such as synchronizing, may be available at the station or bay
control point. Reference should be made to Fig. 13.1 which illustrates the type of
equipment at the human machine interfaces. With the continued increase in the use
of equipment using digital technology, there is now a clear distinction between the
conventional and the computer-based human machine interfaces. Computer-based
HMI is commonly found at network control level but is becoming increasingly more
common in station control rooms. However, there are still some conventional HMIs
at the station level. HMI at bay level is often direct wire control and therefore
conventional.

Figure 13.1 an example of human machine interface locations

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13.3 Details of Conventional HMI

HMI at bay level will comprise control switches, indicator lamps, and meters
mounted on the equipment or in adjacent local control cubicles. Generally, these
facilities are used during maintenance of the controlled plant or as backup for use in
the event of failure of the station level or central network control center. At the
station level, control panels should be located in the main control room. The HMI
equipment should be grouped on a per-circuit basis, and open and close switches
should only control equipment on the same section of the substation as the control
panel represents. A mimic diagram representing the substation layout, usually in
single-line diagram form, should be provided. The mimic board is intended to give
operating personnel an overall view of the switchgear state. It may be made up from
the individual circuit control panels mounted side by side. The arrangement should
correspond to the primary equipment layout. Alarm annunciation equipment should
be mounted adjacent to the mimic diagram or form an integral part of the control
panel. Operation of an alarm should cause the appropriate window to flash and sound
an audible warning. Operation of an accept button will silence the audible warning,
steady the flashing window, and prepare the annunciation to respond to subsequent
initiation. A reset button should be provided to extinguish alarms which have reset.
A lamp test button is necessary which will initiate steady-state illumination of all
alarm windows. Trip or protection initiated alarms should have windows distinct
from others (e.g., red display instead of white or amber). Control and selector
switches should be of approved types complying with accepted standards such as
IEC 60337. Control switches will require two independent motions or two handed
operation to effect operation. Indicating instruments should be of approved types
complying with accepted standards such as IEC 60051.

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13.4 Details of Computer-Based HMI

Computer-based human machine interfaces function through computer systems
using distributed architectures. Such systems were commonly found at network level
but only since the 1990s at substation control level. Remote terminal units (RTUs)
form the interface with equipment and communicate information to the central
system(s). RTUs will collect analogue and digital data and issue control commands.
The human machine interface may make use of the following items in varying
quantities depending on the degree of redundancy required:

• Visual display unit (VDU)

• Alphanumeric keyboard
• Printer
• Plotter
• Trackball
• Joystick
• Special function panel
• Mouse

A mimic display either in the form of a board for large substations or VDU “pages”
should be available. Operator consoles capable of operating the substation (at
substation level), or power system (network level), should be comprised of the
required components from the above list. The console should be capable of operating
in online, maintenance, training, and programming mode. Special software
interlocks should prohibit two or more consoles working “online” simultaneously.
VDUs should be of the full graphic, multicolor type designed for 24 h a day
continuous operation. The following information should be displayed:

• Static (fixed) information (e.g., substation single-line diagram)

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• Operating parameters which may be changed

• Dynamic (real-time) variables

An operator’s keyboard, which contains special function keys, should be provided

at each console; this will allow execution of commands. The system keyboard is for
data entry and general operation of the computer system and substation(s). In
addition, an alphanumeric keyboard may also be required for system purposes.
When the substation is only manned occasionally, consideration should be given to
the provision of a touch screen VDU or special function panel to simplify the task
of the operator in controlling and monitoring the plant. The special function panel
would only have a small number of dedicated push buttons and switches for plant
control, selection of VDU pages, and acknowledgment of alarms. Two stage control
(select-check-execute) is normally required for all the control commands to effect
the operation from an HMI

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13.5 Local Control Cabinet

Each circuit breaker of the gas insulated substation (GIS) is provided with a
control cabinet for local control and monitoring of the respective bay and is generally
placed in front or adjacent to their GIS bays depending on the voltage level (see
Figure 13.2 for an indoor cabinet and Figure 13.3 for an outdoor cabinet).

Figure 13.2 Indoor local control cabinet

The control cabinet is metal enclosed, free standing, made of sheet steel, and
provided with a lockable hinged door and door operated lights. The local control
cabinet has all necessary control switches, local/off/remote lockable selector
switches, close and open switches, measuring instruments, all position indicators for
circuit breakers, disconnect switches and grounding switches, alarms, mimic
diagram, AC and DC supply terminals, control and auxiliary relays, and so on. The
cabinet is fully designed as per IEC 60 439 or IEEE C37.123. The control cabinet is
designed in such a way as to facilitate full and independent control and monitoring
of the GIS locally.

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Figure 13.3 Outdoor local control cabinet

All electronic components inside the bay control cabinet are designed to work
satisfactorily for the specified project requirement. At least 20% of each spare
contacts (NO (normally open) and NC (normally closed)) are provided with an
auxiliary relay for future use. All CT secondary taps should be wired to the local
control cabinet. The CT terminal block is such that it will provide isolation and
testing facilities of CT secondaries at the cabinet. For multiratio CTs the terminal
block is provided on the LCC as per IEEE C57.13 to facilitate connection of various
taps. Facility is provided in the LCC for shorting and grounding of secondary
terminals. Potential transformer (PT) secondary windings are terminated at the local
control cabinet through a terminal box. For PT wiring in the LCC, each phase of
each circuit is provided with a miniature knife switch and a high rupturing capacity
(HRC) fuse/supervised mini circuit breaker (MCB). Knife switches are located on
the PT side of fuses. Separate terminals are provided for PT fuse supervision. The

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control cabinet is equipped with a mimic diagram on the front of the cabinet showing
(see Figure 13.4):

a) A mimic diagram showing the arrangement of electrical equipment in the

bay including bus bar isolating links.
b) Control switches and local/off/remote changeover (lockable) for operation of
all circuit breakers, disconnect switches, and grounding switches.
c) Position indicators showing the position of all circuit breakers, disconnect
switches and grounding switches.
d) Overriding interlock switch between disconnects and grounding switches
associated with circuit breakers (depending on the user’s requirements).
e) SF6 gas zones.
f) The color of the mimic bus should be according to the user’s requirements.

Figure 13.4 Mimic diagram

The cabinet is equipped with a thermostatically controlled anticondensation space

heater along with a cabinet light, door switch, safety shrouds, and receptacle. The
arrangement of equipment within cubicles is such that access for maintenance or
removal of any item should be possible with minimum disturbance of an associated

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apparatus. All control power circuits are protected by miniature circuit breakers in
each cabinet. Other circuits supplying loads, such as heaters, receptacles, or lights,
have separate overload protection. The cabinet is grounded with a suitable copper
bus and the hinged door of the cabinet is grounded by a flexible grounding
connection. Alarm/annunciators are of the window type as per IEC 60 255 or IEEE
C37.1, with a minimum of 20% spare windows for use. The alarm/annunciator
system is designed for continuous operation of all alarms independently and
simultaneously.

The following minimum alarm is provided as a local alarm in the LCC:

• SF6 gas pressure Low–Low, Stage 1 alarm for each gas zone/section (in the
case of a single phase, an alarm is provided for each phase)
• SF6 gas pressure Low–Low, Stage 2 alarm for each gas zone/section (in case
of a single phase, the alarm is grouped for all phases)
• Excess run time of the motor for the circuit breaker, disconnecting switch, and
ground switch
• Spring overcharged for the circuit breaker mechanism
• Loss of DC for the trip and close circuit
• Circuit breaker trip
• VT supply fail (VT MCB trip)
• Loss of AC supply
• Circuit breaker mechanism failure
• Local/remote switch
• Pole discrepancy operated (for single-phase breaker)
• Trip circuit failure
• Loss of DC supply to circuit breaker motor

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13.6 Bay Controller

The bay controller unit is installed in the local control cabinet (LCC). There is
hard wiring from the GIS to the LCC/bay control unit including CT and VT
wiring. The high voltage equipment within the GIS is operated from different
places with a predetermined hierarchy:

• Local control panel with mimic

• Bay control unit (control IED)
• Station human–machine interface (HMI) (micro SCADA)
• SCADA master station

Bay level functions include data acquisition and data collection functionality in
bay control intelligent electronic devices (IEDs). The following basic functions
are included in the control unit:

• Control mode selection

• Interlocking and blocking
• Double command blocking
• Auto reclosing
• Synchrocheck and voltage selection
• Motor excessive run
• Monitoring pole discrepancy and trip function
• Measurement display
• Display of interlocking and blocking
• Device position indication (circuit breaker, disconnect switch, ground
switch)
• Transformer tap change control and indication
• Data storage Interface to the station level

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• Bay control unit (BCU) interlocking and blocking

Software/GOOSE (generic object orientated substation event) interlocking

control is through bay control IEDs. In the case where an “interlock override”
feature is provided as part of the “GOOSE” scheme, privileged users can only
access it using a strong password and other security features.

Double operation interlocking is made in a GOOSE design where separately

dedicated IP address/subnets are allocated for each voltage level in each
substation.

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 References

REFERENCES
[1] MEHTA, V. K.; MEHTA, Rohit. Principles of Power System: Including
Generation, Transmission, Distribution, Switchgear and Protection: for BE/B.
Tech., AMIE and Other Engineering Examinations. S. Chand Publishing, 2005.
[2] MCDONALD, John D. Electric power substations engineering. CRC press,
2016.
[3]RANDOLPH, John. Electric Power Substations Engineering [Book Reviews].
IEEE Power and Energy Magazine, 2013,
[4] GUIDE, SF6 Recycling. International Council on Large Electric Systems
(CIGRE). Task Force, 2010, 23.01.
[5] Power system studies book for Dr/Mahmoud El-Gilany.
[6] IEEE Std 80-2013.
[7] Egyptian Code for earthing E27.
[8] IEEE Std. 998-1996. IEEE Guide for Direct Lightning Stoke Shielding of
Substations.
[9] Greenwood, A. Electrical Transients in Power Systems.
[10] Abdel-Salam, M., et al. High Voltage Engineering - Theory and Practice.
[11] Zipse, D. Lightning Protection Systems: Advantages and Disadvantages.
IEEE Transactions on Industry Applications, Vol. 30, No. 5, September/October
1994.
[12] AS/NZS 1768:2007 Lightning Protection.
[13] IEC 62305-1:2010 Protection Against Lightning.
[14] Anderson and A.J. Eriksson, Lightning Parameters for Engineering
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[15] IEEE Std 80-2000

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[16] IEEE Std 141TM [B11]: [17] IEEE Std C57.12.00TM [B4]. [18] IEC 60949
[19] IEC 60076 [20] IEC 309-1-2-309A [21] IEEE 1115-2000 (Batteries for
Stationary Applications).
[22] IEEE 1184-1994 (Battery for UPS) .
[23] Electricity utilities specifications (EUS -E16).
[24] Transmission and Distribution Electrical Engineering, Third edition, Dr C. R.
Bayliss CEng FIET and B. J. Hardy ACGI CEng.
[25] IEEE Std 242-2001 IEEE Recommended Practice for Protection and.
Coordination of Industrial and Commercial Power Systems.
[26] IEEE Std C37.113-1999 IEEE Guide for Protective Relay Applications to
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[27] IEEE Standard C57.12.00-2015 categorizes the power transformers based on
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[28] IEEE Std C37.234-2009 IEEE Guide for Protection Relay Applications to
Power System Buses.
[29] Network Protection & Automation Guide by Alstom.
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