GE Energy Connections

Grid Solutions

MiCOM P40 Agile

P543i/P545i

Technical Manual
Single Breaker Current Differential (with Distance)

Hardware Version: M
Software Version: 85
Publication Reference: P54x1i-TM-EN-1
Contents

Chapter 1 Introduction 1
1 Chapter Overview 3
2 Foreword 4
2.1 Target Audience 4
2.2 Typographical Conventions 4
2.3 Nomenclature 5
2.4 Compliance 5
3 Product Scope 6
3.1 Product Versions 6
3.1.1 Ordering Options 7
4 Features and Functions 8
4.1 Current Differential Protection Functions 8
4.2 Distance Protection Functions 8
4.3 Protection Functions 8
4.4 Control Functions 9
4.5 Measurement Functions 10
4.6 Communication Functions 10
5 Logic Diagrams 11
6 Functional Overview 13

Chapter 2 Safety Information 15

1 Chapter Overview 17
2 Health and Safety 18
3 Symbols 19
4 Installation, Commissioning and Servicing 20
4.1 Lifting Hazards 20
4.2 Electrical Hazards 20
4.3 UL/CSA/CUL Requirements 21
4.4 Fusing Requirements 21
4.5 Equipment Connections 22
4.6 Protection Class 1 Equipment Requirements 22
4.7 Pre-energisation Checklist 23
4.8 Peripheral Circuitry 23
4.9 Upgrading/Servicing 24
5 Decommissioning and Disposal 25
6 Regulatory Compliance 26
6.1 EMC Compliance: 2014/30/EU 26
6.2 LVD Compliance: 2014/35/EU 26
6.3 R&TTE Compliance: 2014/53/EU 26
6.4 UL/CUL Compliance 26
6.5 ATEX Compliance: 2014/34/EU 26

Chapter 3 Hardware Design 29

1 Chapter Overview 31
2 Hardware Architecture 32
2.1 Coprocessor Hardware Architecture 32
3 Mechanical Implementation 34
3.1 Housing Variants 34
3.2 List of Boards 35
4 Front Panel 37
4.1 Front Panel 37
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4.1.1 Front Panel Compartments 37

4.1.2 Keypad 38
4.1.3 Front Serial Port (SK1) 38
4.1.4 Front Parallel Port (SK2) 39
4.1.5 Fixed Function LEDs 39
4.1.6 Function Keys 39
4.1.7 Programable LEDs 40
5 Rear Panel 41
6 Boards and Modules 43
6.1 PCBs 43
6.2 Subassemblies 43
6.3 Main Processor Board 44
6.4 Power Supply Board 45
6.4.1 Watchdog 47
6.4.2 Rear Serial Port 48
6.5 Input Module - 1 Transformer Board 49
6.5.1 Input Module Circuit Description 50
6.5.2 Transformer Board 51
6.5.3 Input Board 52
6.6 Standard Output Relay Board 53
6.7 IRIG-B Board 54
6.8 Fibre Optic Board 55
6.9 Rear Communication Board 56
6.10 Ethernet Board 56
6.11 Redundant Ethernet Board 58
6.12 Coprocessor Board 60
6.12.1 Current Differential Inputs 60
6.12.2 Coprocessor board with 1PPS input 60

Chapter 4 Software Design 63

1 Chapter Overview 65
2 Sofware Design Overview 66
3 System Level Software 67
3.1 Real Time Operating System 67
3.2 System Services Software 67
3.3 Self-Diagnostic Software 67
3.4 Startup Self-Testing 67
3.4.1 System Boot 67
3.4.2 System Level Software Initialisation 68
3.4.3 Platform Software Initialisation and Monitoring 68
3.5 Continuous Self-Testing 68
4 Platform Software 70
4.1 Record Logging 70
4.2 Settings Database 70
4.3 Interfaces 70
5 Protection and Control Functions 71
5.1 Acquisition of Samples 71
5.2 Frequency Tracking 71
5.3 Direct Use of Sample Values 71
5.4 System Level Software Initialisation 71
5.5 Distance Protection 72
5.6 Fourier Signal Processing 72
5.7 Programmable Scheme Logic 73
5.8 Event Recording 74
5.9 Disturbance Recorder 74
5.10 Fault Locator 74

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5.11 Function Key Interface 74

Chapter 5 Configuration 75
1 Chapter Overview 77
2 Settings Application Software 78
3 Using the HMI Panel 79
3.1 Navigating the HMI Panel 80
3.2 Getting Started 80
3.3 Default Display 81
3.4 Default Display Navigation 82
3.5 Password Entry 83
3.6 Processing Alarms and Records 83
3.7 Menu Structure 84
3.8 Changing the Settings 85
3.9 Direct Access (The Hotkey menu) 86
3.9.1 Setting Group Selection Using Hotkeys 86
3.9.2 Control Inputs 86
3.9.3 Circuit Breaker Control 87
3.10 Function Keys 87
4 Line Parameters 89
4.1 Tripping Mode 89
4.1.1 CB Trip Conversion Logic Diagram 89
4.2 Residual Compensation 90
4.3 Mutual Compensation 90
5 Date and Time Configuration 92
5.1 Using an SNTP Signal 92
5.2 Using an IRIG-B Signal 92
5.3 Using an IEEE 1588 PTP Signal 92
5.4 Without a Timing Source Signal 93
5.5 Time Zone Compensation 93
5.6 Daylight Saving Time Compensation 94
6 Settings Group Selection 95

Chapter 6 Current Differential Protection 97

1 Chapter Overview 99
2 Current Differential Protection Principle 100
2.1 Numerical Current Differential Protection 100
3 Synchronisation of Current Signals 102
3.1 Time Alignment using Ping-Pong Technique 102
3.2 GPS Synchronisation 103
4 Phase Current Differential Protection 105
4.1 Phase Current Differential Tripping Criteria 106
4.2 Phase Current Differential Protection Logic 107
5 Neutral Current Differential Protection 108
6 Three-Terminal Schemes 109
6.1 Three-Terminal Scheme Reconfiguration on Energisation 110
7 Transient Bias 111
8 Capacitive Charging Current Compensation 112
9 CT Compensation 113
10 Feeders with In-Zone Transformers 114
10.1 CT Phase Correction 114
10.2 Zero Sequence Filtering 115
10.3 Magnetising Inrush Restraint 116
10.3.1 Second Harmonic Restraint 117
10.4 Overfluxing Restraint 119

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10.4.1 Fifth Harmonic Blocking 119

10.5 Logic for Feeders with In-Zone Transformers 120
10.6 Second Harmonic Blocking Logic 121
10.7 Fifth Harmonic Blocking Logic 122
11 Current Differential Intertripping 123
12 Stub Bus Differential Protection 124
13 Application Notes 125
13.1 Setting Up the Phase Differential Characteristic 125
13.2 Sensitivity Under Heavy Loads 126
13.3 Permissive Intertripping 127
13.4 CT Ratio Correction Setting Guidelines 127
13.5 Feeders with Small Tapped Loads 128
13.6 Setting a Two-Terminal Phase Current Differential Element 128
13.7 Setting a Three-Terminal Phase Current Differential Element 129

Chapter 7 Distance Protection 133

1 Chapter Overview 135
2 Introduction 136
2.1 Distance Protection Principle 136
2.2 Performance Influencing Factors 136
2.3 Impedance Calculation 137
2.4 Implementation with Comparators 137
2.5 Polarization of Distance Characteristics 137
3 Distance Measuring Zones Operating Principles 138
3.1 Mho Characteristics 139
3.1.1 Directional Mho Characteristic for Phase Faults 139
3.1.2 Offset Mho Characteristic for Phase Faults 139
3.1.3 Directional Self-Polarized Mho Characteristic for Earth Faults 140
3.1.4 Offset Mho Characteristic for Earth Faults 142
3.1.5 Memory Polarization of Mho Characteristics 144
3.1.6 Dynamic Mho Expansion and Contraction 144
3.1.7 Cross Polarization of Mho Characteristics 147
3.1.8 Implementation of Mho Polarization 148
3.2 Quadrilateral Characteristic 149
3.2.1 Directional Quadrilaterals 150
3.2.2 Earth Fault Quadrilateral Characteristics 154
3.3 Quadrilateral Characteristic for Phase Faults 162
3.3.1 Phase Fault Impedance Reach Line 163
3.3.2 Phase Fault Reverse Impedance Reach Line 163
3.3.3 Phase Fault Resistive Reach Line 164
3.3.4 Phase Fault Reverse Resistive Reach Line 166
3.3.5 Phase Fault Quadrilateral Characteristic Summary 166
4 Phase and Earth Fault Distance Protection Implementation 168
4.1 Phase Fault Characteristics 168
4.2 Earth Fault Characteristics 168
4.3 Distance Protection Tripping Decision 168
4.4 Distance Protection Phase Selection 169
4.4.1 Faulted Phase Selection 169
4.5 Biased Neutral Current Detector 170
4.6 Distance Element Zone Settings 171
4.6.1 Directionalizing the Distance Elements 171
4.6.2 Advanced Distance Zone Settings 172
4.6.3 Distance Zone Sensitivities 172
4.7 Capacitor VT Applications 173
4.7.1 CVTs with Passive Suppression of Ferroresonance 173
4.7.2 CVTs with Active Suppression of Ferroresonance 173
4.8 Load Blinding 174

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4.9 Cross Country Fault Protection 175

5 Delta Directional Element 176
5.1 Delta Directional Principle and Setup 176
5.2 Delta Directional Decision 177
6 Distance Isolated and Compensated Systems 179
6.1 Peterson Coil Earthed Systems 179
6.2 Earth Fault Distance Protection for Isolated and Compensated Systems 182
6.2.1 Single-phase to Earth Faults on Isolated or Compensated Systems 183
6.2.2 Cross-Country Faults on Isolated or Compensated Systems 183
6.3 Implementation of Distance Protection for Isolated and Compensated Networks 184
6.3.1 Network Earthing System Setting 184
6.3.2 First Earth FaultDetection 184
6.3.3 Fault Detection Logic 186
6.3.4 Phase Preferential Logic 187
7 Application Notes 193
7.1 Setting Mode Choice 193
7.2 Operating Characteristic Selection 193
7.2.1 Phase Characteristic 193
7.2.2 Earth Fault Characteristic 194
7.3 Zone Reach Setting Guidelines 194
7.3.1 Quadrilateral Resistive Reaches 195
7.4 Earth Fault Resistive Reaches and Tilting 195
7.4.1 Dynamic Tilting 196
7.4.2 Fixed Tilting 197
7.5 Phase Fault Zone Settings 197
7.6 Directional Element for Distance Protection 198
7.7 Filtering Setup 198
7.7.1 Distance Digital Filter 198
7.7.2 Setting up CVTs 198
7.8 Load Blinding Setup 199
7.9 Polarizing Setup 199
7.10 Delta Directional Element Setting Guidelines 200
7.10.1 Delta Thresholds 200
7.11 Distance Protection Worked Example 201
7.11.1 Line Impedance Calculation 202
7.11.2 Residual Compensation for Earth Fault Elements 202
7.11.3 Zone 1 Phase and Ground Reach Settings 202
7.11.4 Zone 2 Phase and Ground Reach Settings 203
7.11.5 Zone 3 Phase and Ground Reach Settings 203
7.11.6 Zone 3 Reverse Reach Settings 203
7.11.7 Zone 4 Reverse Reach Settings 203
7.11.8 Load Avoidance 204
7.11.9 Quadrilateral Resistive Reach Settings 204
7.12 Teed Feeder Applications 206

Chapter 8 Carrier Aided Schemes 207

1 Chapter Overview 209
2 Introduction 210
3 Carrier Aided Schemes Implementation 211
3.1 Carrier Aided Scheme Types 211
3.2 Default Carrier Aided Schemes 212
4 Aided Distance Scheme Logic 213
4.1 Permissive Underreach Scheme 213
4.2 Permissive Over-reach Scheme 214
4.2.1 Permissive Overreach Trip Reinforcement 216
4.2.2 Permissive Overreach Weak Infeed Features 217
4.3 Permissive Scheme Loss Of Guard 217

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4.4 Current Reversal Guard Logic 218

4.5 Aided Distance Blocking Schemes 219
4.6 Aided Distance Unblocking Schemes 220
4.7 Aided Distance Logic Diagrams 222
4.7.1 Aided Distance Send Logic 222
4.7.2 Carrier Aided Schemes Receive Logic 223
4.7.3 Aided Distance Tripping Logic 223
4.7.4 PUR Aided Tripping logic 224
4.7.5 POR Aided Tripping logic 225
4.7.6 Aided Scheme Blocking 1 Tripping logic 226
4.7.7 Aided Scheme Blocking 2 Tripping logic 226
5 Aided DEF Scheme Logic 227
5.1 Aided DEF Introduction 227
5.2 Implementation 227
5.3 Aided DEF Polarization 227
5.3.1 Zero Sequence Polarizing 228
5.3.2 Negative Sequence Polarizing 229
5.4 Aided DEF Setting Guidelines 230
5.5 Aided DEF POR Scheme 231
5.6 Aided DEF Blocking Scheme 232
5.7 Aided DEF Logic Diagrams 233
5.7.1 DEF Directional Signals 233
5.7.2 Aided DEF Send Logic 234
5.7.3 Carrier Aided Schemes Receive Logic 234
5.7.4 Aided DEF Tripping Logic 235
5.7.5 POR Aided Tripping logic 236
5.7.6 Aided Scheme Blocking 1 Tripping logic 237
5.7.7 Aided Scheme Blocking 2 Tripping logic 237
6 Aided Delta Scheme Logic 238
6.1 Aided Delta POR Scheme 238
6.2 Aided Delta Blocking Scheme 239
6.3 Aided Delta Logic Diagrams 241
6.3.1 Aided Delta Send Logic 241
6.3.2 Carrier Aided Schemes Receive Logic 241
6.3.3 Aided Delta Tripping Logic 242
6.3.4 POR Aided Tripping logic 243
6.3.5 Aided Scheme Blocking 1 Tripping logic 244
6.3.6 Aided Scheme Blocking 2 Tripping logic 244
7 Application Notes 245
7.1 Aided Distance PUR Scheme 245
7.2 Aided Distance POR Scheme 245
7.3 Aided Distance Blocking Scheme 245
7.4 Aided DEF POR Scheme 246
7.5 Aided DEF Blocking Scheme 246
7.6 Aided Delta POR Scheme 246
7.7 Aided Delta Blocking Scheme 246
7.8 Teed Feeder Applications 247
7.8.1 POR Schemes for Teed Feeders 248
7.8.2 PUR Schemes for Teed Feeders 248
7.8.3 Blocking Schemes for Teed Feeders 249

Chapter 9 Non-Aided Schemes 251

1 Chapter Overview 253
2 Non-Aided Schemes 254
3 Basic Schemes 255
3.1 Basic Scheme Modes 255
3.2 Basic Scheme Setting 258

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4 Trip On Close Schemes 259

4.1 Switch On To Fault (SOTF) 260
4.1.1 Switch Onto Fault Mode 260
4.1.2 SOTF Tripping 261
4.1.3 SOTF Tripping with CNV 261
4.2 Trip On Reclose (TOR) 261
4.2.1 Trip On Reclose Mode 262
4.2.2 TOR Tripping Logic for Appropriate Zones 262
4.2.3 TOR Tripping Logic with CNV 262
4.3 Polarisation during Circuit Engergisation 262
5 Zone1 Extension Scheme 264
6 Loss of Load Scheme 265

Chapter 10 Power Swing Functions 267

1 Chapter Overview 269
2 Introduction to Power Swing Blocking 270
3 Power Swing Blocking 272
3.1 Power Swing Detection 272
3.1.1 Settings-Free Power Swing Detection 272
3.1.2 Slow Power Swing Detection 275
3.2 Detection of a Fault During a Power Swing 276
3.3 Power Swing Blocking Configuration 276
3.4 Power Swing Load Blinding Boundary 277
3.5 Power Swing Blocking Logic 278
3.6 Power Swing Blocking Setting Guidelines 279
3.6.1 Setting the Resistive Limits 280
3.6.2 Setting the Reactive Limits 280
3.6.3 PSB Timer Setting Guidelines 281
4 Out of Step Protection 283
4.1 Out of Step Detection 283
4.2 Out of Step Protection Operataing Principle 284
4.3 Out of Step Logic Diagram 285
4.4 OST Application Notes 285
4.4.1 Setting the OST Mode 285

Chapter 11 Autoreclose 293

1 Chapter Overview 295
2 Introduction to Autoreclose 296
3 Autoreclose Implementation 297
3.1 Autoreclose Logic Inputs from External Sources 298
3.1.1 Circuit Breaker Healthy Input 298
3.1.2 Inhibit Autoreclose Input 298
3.1.3 Block Autoreclose Input 298
3.1.4 Reset Lockout Input 299
3.1.5 Pole Discrepancy Input 299
3.1.6 External Trip Indication 299
3.2 Autoreclose Logic Inputs 299
3.2.1 Trip Initiation Signals 299
3.2.2 Circuit Breaker Status Inputs 299
3.2.3 System Check Signals 299
3.3 Autoreclose Logic Outputs 299
3.4 Autoreclose Operating Sequence 300
3.4.1 AR Timing Sequence - Transient Fault 300
3.4.2 AR Timing Sequence - Evolving/Permanent Fault 300
3.4.3 AR Timing Sequence - Evolving/Permanent Fault Single-phase 301
4 Autoreclose System Map 302

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4.1 Autoreclose System Map Diagrams 304

4.2 Autoreclose Internal Signals 309
4.3 Autoreclose DDB Signals 311
5 Logic Modules 317
5.1 Circuit Breaker Status Monitor 317
5.1.1 CB State Monitor Logic diagram 318
5.2 Circuit Breaker Open Logic 319
5.2.1 Circuit Breaker Open Logic Diagram 319
5.3 Circuit Breaker in Service Logic 319
5.3.1 Circuit Breaker in Service Logic Diagram 319
5.3.2 Autoreclose OK Logic Diagram 320
5.4 Autoreclose Enable 320
5.4.1 Autoreclose Enable Logic Diagram 320
5.5 Autoreclose Modes 320
5.5.1 Single-Phase and Three-Phase Autoreclose 321
5.5.2 Autoreclose Modes Enable Logic Diagram 322
5.6 AR Force Three-Phase Trip Logic 322
5.6.1 AR Force Three-Phase Trip Logic Diagram 322
5.7 Autoreclose Initiation Logic 322
5.7.1 Autoreclose Initiation Logic Diagram 324
5.7.2 Autoreclose Trip Test Logic Diagram 324
5.7.3 AR External Trip Initiation Logic Diagram 325
5.7.4 Protection Reoperation and Evolving Fault Logic Diagram 326
5.7.5 Fault Memory Logic Diagram 326
5.8 Autoreclose In Progress 326
5.8.1 Autoreclose In Progress Logic Diagram 327
5.9 Sequence Counter 327
5.9.1 Autoreclose Sequence Counter Logic Diagram 328
5.10 Autoreclose Cycle Selection 328
5.10.1 Single-Phase Autoreclose Cycle Selection Logic Diagram 328
5.10.2 3-phase Autoreclose Cycle Selection 329
5.11 Dead Time Control 329
5.11.1 Dead Time Start Enable Logic Diagram 330
5.11.2 1-phase Dead Time Logic Diagram 331
5.11.3 3-phase Dead Time Logic Diagram 332
5.12 Circuit Breaker Autoclose 332
5.12.1 Circuit Breaker Autoclose Logic Diagram 333
5.13 Reclaim Time 333
5.13.1 Prepare Reclaim Initiation Logic Diagram 334
5.13.2 Reclaim Time Logic Diagram 334
5.13.3 Succesful Autoreclose Signals Logic Diagram 335
5.13.4 Autoreclose Reset Successful Indication Logic Diagram 335
5.14 CB Healthy and System Check Timers 335
5.14.1 CB Healthy and System Check Timers Logic Diagram 336
5.15 Autoreclose Shot Counters 336
5.15.1 Autoreclose Shot Counters Logic Diagram 337
5.16 Circuit Breaker Control 338
5.16.1 CB Control Logic Diagram 338
5.17 Circuit Breaker Trip Time Monitoring 339
5.17.1 CB Trip Time Monitoring Logic Diagram 339
5.18 Autoreclose Lockout 339
5.18.1 CB Lockout Logic Diagram 340
5.19 Reset Circuit Breaker Lockout 341
5.19.1 Reset CB Lockout Logic Diagram 341
5.20 Pole Discrepancy 342
5.20.1 Pole Discrepancy Logic Diagram 342
5.21 Circuit Breaker Trip Conversion 342
5.21.1 CB Trip Conversion Logic Diagram 343

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5.22 Monitor Checks for CB Closure 343

5.22.1 Check Synchronisation Monitor for CB Closure 344
5.22.2 Voltage Monitor for CB Closure 345
5.23 Synchronisation Checks for CB Closure 345
5.23.1 Three-phase Autoreclose System Check Logic Diagram 347
5.23.2 CB Manual Close System Check Logic Diagram 348
6 Setting Guidelines 349
6.1 De-ionising Time Guidance 349
6.2 Dead Timer Setting Guidelines 349
6.2.1 Example Dead Time Calculation 349
6.3 Reclaim Time Setting Guidelines 350

Chapter 12 CB Fail Protection 351

1 Chapter Overview 353
2 Circuit Breaker Fail Protection 354
3 Circuit Breaker Fail Implementation 355
3.1 Circuit Breaker Fail Timers 355
3.2 Zero Crossing Detection 355
4 Circuit Breaker Fail Logic 357
4.1 Circuit Breaker Fail Logic - Part 1 357
4.2 Circuit Breaker Fail Logic - Part 2 358
4.3 Circuit Breaker Fail Logic - Part 3 359
4.4 Circuit Breaker Fail Logic - Part 4 360
5 Application Notes 361
5.1 Reset Mechanisms for CB Fail Timers 361
5.2 Setting Guidelines (CB fail Timer) 361
5.3 Setting Guidelines (Undercurrent) 362

Chapter 13 Current Protection Functions 363

1 Chapter Overview 365
2 Phase Fault Overcurrent Protection 366
2.1 POC Implementation 366
2.2 Directional Element 366
2.3 POC Logic 368
3 Negative Sequence Overcurrent Protection 369
3.1 Negative Sequence Overcurrent Protection Implementation 369
3.2 Directional Element 369
3.3 NPSOC Logic 370
3.4 Application Notes 370
3.4.1 Setting Guidelines (Current Threshold) 370
3.4.2 Setting Guidelines (Time Delay) 370
3.4.3 Setting Guidelines (Directional element) 371
4 Earth Fault Protection 372
4.1 Earth Fault Protection Implementation 372
4.2 IDG Curve 372
4.3 Directional Element 373
4.3.1 Residual Voltage Polarisation 373
4.3.2 Negative Sequence Polarisation 374
4.4 Earth Fault Protection Logic 375
4.5 Application Notes 375
4.5.1 Residual Voltage Polarisation Setting Guidelines 375
4.5.2 Setting Guidelines (Directional Element) 375
5 Sensitive Earth Fault Protection 377
5.1 SEF Protection Implementation 377
5.2 EPATR B Curve 377

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5.3 Sensitive Earth Fault Protection Logic 378

5.4 Application Notes 379
5.4.1 Insulated Systems 379
5.4.2 Setting Guidelines (Insulated Systems) 380
6 High Impedance REF 382
6.1 High Impedance REF Principle 382
7 Thermal Overload Protection 384
7.1 Single Time Constant Characteristic 384
7.2 Dual Time Constant Characteristic 384
7.3 Thermal Overload Protection Implementation 385
7.4 Thermal Overload Protection Logic 385
7.5 Application Notes 385
7.5.1 Setting Guidelines for Dual Time Constant Characteristic 385
7.5.2 Setting Guidelines for Single Time Constant Characteristic 387
8 Broken Conductor Protection 389
8.1 Broken Conductor Protection Implementation 389
8.2 Broken Conductor Protection Logic 389
8.3 Application Notes 389
8.3.1 Setting Guidelines 389
9 Transient Earth Fault Detection 391
9.1 Transient Earth Fault Detection Implementation 392
9.2 Transient Earth Fault Detection Logic 393
9.2.1 Transient Earth Fault Detection Logic Overview 393
9.2.2 Fault Type Detector Logic 394
9.2.3 Direction Detector Logic - Standard Mode 394
9.2.4 Transient Earth Fault Detection Output Alarm Logic 394

Chapter 14 Voltage Protection Functions 395

1 Chapter Overview 397
2 Undervoltage Protection 398
2.1 Undervoltage Protection Implementation 398
2.2 Undervoltage Protection Logic 399
2.3 Application Notes 400
2.3.1 Undervoltage Setting Guidelines 400
3 Overvoltage Protection 401
3.1 Overvoltage Protection Implementation 401
3.2 Overvoltage Protection Logic 402
3.3 Application Notes 403
3.3.1 Overvoltage Setting Guidelines 403
4 Compensated Overvoltage 404
5 Residual Overvoltage Protection 405
5.1 Residual Overvoltage Protection Implementation 405
5.2 Residual Overvoltage Logic 406
5.3 Application Notes 406
5.3.1 Calculation for Solidly Earthed Systems 406
5.3.2 Calculation for Impedance Earthed Systems 407
5.3.3 Setting Guidelines 408

Chapter 15 Frequency Protection Functions 409

1 Chapter Overview 411
2 Frequency Protection 412
2.1 Underfrequency Protection 412
2.1.1 Underfrequency Protection Implementation 412
2.1.2 Underfrequency Protection logic 413
2.1.3 Application Notes 413

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2.2 Overfrequency Protection 413

2.2.1 Overfrequency Protection Implementation 413
2.2.2 Overfrequency Protection logic 414
2.2.3 Application Notes 414
3 Independent R.O.C.O.F Protection 415
3.1 Indepenent R.O.C.O.F Protection Implementation 415
3.2 Independent R.O.C.O.F Protection Logic 415

Chapter 16 Current Transformer Requirements 417

1 Chapter Overview 419
2 Recommended CT Classes 420
3 Current Differential Requirements 421
4 Distance Protection Requirements 422
5 Determining Vk for IEEE C-class CT 423
6 Worked Examples 424
6.1 Calculation of Primary X/R ratio 424
6.2 Calculation of Source Impedance 424
6.3 Calculation of Full Line Impedance 424
6.4 Calculation of Total Impedance up to Remote Busbar 425
6.5 Calculation of Through Fault X/R ratio 425
6.6 Calculation of Through Fault Current 425
6.7 Calculation of Line Impedance to Zone 1 Reach Point 425
6.8 Calculation of Total Impedance to Zone 1 Reach Point 425
6.9 Calculation of X/R to Zone 1 Reach Point 425
6.10 Calculation of Fault Current to Zone 1 Reach Point 425
6.11 Calculation of Vk for Current Differential Protection 425
6.12 Calculation of Vk for Distance Zone 1 Reach Point 425
6.13 Calculation of Vk for Distance Zone 1 Close-up Fault 426
6.14 Calculation of Vk for Distance Time Delayed Zones 426
6.15 Overcurrent Elements 426
6.16 Overcurrent Elements 426

Chapter 17 Monitoring and Control 427

1 Chapter Overview 429
2 Event Records 430
2.1 Event Types 430
2.1.1 Opto-input Events 431
2.1.2 Contact Events 431
2.1.3 Alarm Events 431
2.1.4 Fault Record Events 432
2.1.5 Maintenance Events 432
2.1.6 Protection Events 432
2.1.7 Security Events 433
2.1.8 Platform Events 433
3 Disturbance Recorder 434
4 Measurements 435
4.1 Measured Quantities 435
4.2 Measurement Setup 435
4.3 Fault Locator 435
4.4 Opto-input Time Stamping 435
5 CB Condition Monitoring 436
5.1 Broken Current Accumulator 437
5.2 CB Trip Counter 437
5.3 CB Operating Time Accumulator 438
5.4 Excessive Fault Frequency Counter 438

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5.5 Reset Lockout Alarm 439

5.6 CB Condition Monitoring Logic 440
5.7 Reset Circuit Breaker Lockout 440
5.7.1 Reset CB Lockout Logic Diagram 441
5.8 Application Notes 441
5.8.1 Setting the Thresholds for the Total Broken Current 441
5.8.2 Setting the thresholds for the Number of Operations 442
5.8.3 Setting the thresholds for the Operating Time 442
5.8.4 Setting the Thresholds for Excesssive Fault Frequency 442
6 CB State Monitoring 443
6.1 CB State Monitor Logic diagram 444
7 Circuit Breaker Control 445
7.1 CB Control using the IED Menu 445
7.2 CB Control using the Hotkeys 446
7.3 CB Control using the Function Keys 446
7.4 CB Control using the Opto-inputs 447
7.5 Remote CB Control 447
7.6 CB Healthy Check 448
7.7 Synchronisation Check 448
7.8 CB Control AR Implications 448
7.9 CB Control Logic Diagram 449
8 Pole Dead Function 450
8.1 Pole Dead Logic 450
9 System Checks 451
9.1 System Checks Implementation 451
9.1.1 VT Connections 451
9.1.2 Voltage Monitoring 452
9.1.3 Check Synchronisation 452
9.1.4 Check Syncronisation Vector Diagram 452
9.2 Voltage Monitor for CB Closure 454
9.3 Check Synchronisation Monitor for CB Closure 455
9.4 System Check PSL 456
9.5 Application Notes 456
9.5.1 Predictive Closure of Circuit Breaker 456
9.5.2 Voltage and Phase Angle Correction 456

Chapter 18 Supervision 459

1 Chapter Overview 461
2 Current Differential Supervision 462
2.1 Current Differential Starter Supervision 462
2.1.1 Current Differential Starter Supervision Logic 464
2.1.2 Current Differential Start Logic 465
2.2 Switched Communication Path Supervision 465
2.3 Communications Asymmetry Supervision 466
2.4 GPS Synchronisation Supervision 467
2.4.1 Propogation Delay Management 468
3 Voltage Transformer Supervision 470
3.1 Loss of One or Two Phase Voltages 470
3.2 Loss of all Three Phase Voltages 470
3.3 Absence of all Three Phase Voltages on Line Energisation 470
3.4 VTS Implementation 471
3.5 VTS Logic 472
4 Current Transformer Supervision 475
4.1 Differential CTS 475
4.2 Differential CTS Logic 476
4.3 CTS Implementation 476

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4.4 Standard CTS Logic 477

4.5 CTS Blocking 477
4.6 Application Notes 477
4.6.1 Setting Guidelines 477
4.6.2 Differential CTS Setting Guidelines 478
5 Trip Circuit Supervision 479
5.1 Trip Circuit Supervision Scheme 1 479
5.1.1 Resistor Values 479
5.1.2 PSL for TCS Scheme 1 480
5.2 Trip Circuit Supervision Scheme 2 480
5.2.1 Resistor Values 481
5.2.2 PSL for TCS Scheme 2 481
5.3 Trip Circuit Supervision Scheme 3 481
5.3.1 Resistor Values 482
5.3.2 PSL for TCS Scheme 3 482

Chapter 19 Digital I/O and PSL Configuration 483

1 Chapter Overview 485
2 Configuring Digital Inputs and Outputs 486
3 Scheme Logic 487
3.1 PSL Editor 488
3.2 PSL Schemes 488
3.3 PSL Scheme Version Control 488
4 Configuring the Opto-Inputs 489
5 Assigning the Output Relays 490
6 Fixed Function LEDs 491
6.1 Trip LED Logic 491
7 Configuring Programmable LEDs 492
8 Function Keys 494
9 Control Inputs 495

Chapter 20 Fibre Teleprotection 497

1 Chapter Overview 499
2 Protection Signalling Introduction 500
2.1 Unit Protection Schemes 500
2.2 Teleprotection Commands 500
2.3 Transmission Media and Interference 501
3 Fibre Teleprotection Implementation 502
3.1 Setting up the IM64 Scheme 502
3.1.1 Fibre Teleprotection Scheme Terminal Addressing 503
3.1.2 Setting up IM64 504
3.1.3 Two-Terminal IM64 Operation 504
3.1.4 Dual Redundant Two-Terminal IM64 Operation 504
3.1.5 Three-Terminal IM64 Operation 505
3.1.6 Physical Connection 506
3.2 Communications Supervision 509
4 IM64 Logic 511
5 Application Notes 513
5.1 Alarm Management 513
5.2 Alarm Logic 513
5.3 Two-ended Scheme Extended Supervision 514
5.4 Three-ended Scheme Extended Supervision 514

Chapter 21 Electrical Teleprotection 517

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1 Chapter Overview 519

2 Introduction 520
3 Teleprotection Scheme Principles 521
3.1 Direct Tripping 521
3.2 Permissive Tripping 521
4 Implementation 522
5 Configuration 523
6 Connecting to Electrical InterMiCOM 525
6.1 Short Distance 525
6.2 Long Distance 525
7 Application Notes 526

Chapter 22 Communications 529

1 Chapter Overview 531
2 Communication Interfaces 532
3 Serial Communication 533
3.1 EIA(RS)232 Bus 533
3.2 EIA(RS)485 Bus 533
3.2.1 EIA(RS)485 Biasing Requirements 534
3.3 K-Bus 534
4 Standard Ethernet Communication 536
4.1 Hot-Standby Ethernet Failover 536
5 Redundant Ethernet Communication 537
5.1 Supported Protocols 537
5.2 Parallel Redundancy Protocol 538
5.3 High-Availability Seamless Redundancy (HSR) 539
5.3.1 HSR Multicast Topology 539
5.3.2 HSR Unicast Topology 540
5.3.3 HSR Application in the Substation 540
5.4 Rapid Spanning Tree Protocol 541
5.5 Self Healing Protocol 542
5.6 Dual Homing Protocol 543
5.7 Configuring IP Addresses 545
5.7.1 Configuring the IED IP Address 546
5.7.2 Configuring the REB IP Address 546
5.8 PRP/HSR Configurator 549
5.8.1 Connecting the IED to a PC 549
5.8.2 Installing the Configurator 550
5.8.3 Starting the Configurator 550
5.8.4 PRP/HSR Device Identification 551
5.8.5 Selecting the Device Mode 551
5.8.6 PRP/HSR IP Address Configuration 551
5.8.7 SNTP IP Address Configuration 551
5.8.8 Check for Connected Equipment 551
5.8.9 PRP Configuration 551
5.8.10 HSR Configuration 552
5.8.11 Filtering Database 552
5.8.12 End of Session 553
5.9 RSTP Configurator 553
5.9.1 Connecting the IED to a PC 553
5.9.2 Installing the Configurator 554
5.9.3 Starting the Configurator 554
5.9.4 RSTP Device Identification 554
5.9.5 RSTP IP Address Configuration 555
5.9.6 SNTP IP Address Configuration 555
5.9.7 Check for Connected Equipment 555
5.9.8 RSTP Configuration 555

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5.9.9 End of Session 556

5.10 Switch Manager 556
5.10.1 Installation 557
5.10.2 Setup 558
5.10.3 Network Setup 558
5.10.4 Bandwidth Used 558
5.10.5 Reset Counters 558
5.10.6 Check for Connected Equipment 558
5.10.7 Mirroring Function 559
5.10.8 Ports On/Off 559
5.10.9 VLAN 559
5.10.10 End of Session 559
6 Simple Network Management Protocol (SNMP) 560
6.1 SNMP Management Information Bases 560
6.2 Main Processor MIBS Structure 560
6.3 Redundant Ethernet Board MIB Structure 561
6.4 Accessing the MIB 565
6.5 Main Processor SNMP Configuration 565
7 Data Protocols 567
7.1 Courier 567
7.1.1 Physical Connection and Link Layer 567
7.1.2 Courier Database 568
7.1.3 Settings Categories 568
7.1.4 Setting Changes 568
7.1.5 Event Extraction 568
7.1.6 Disturbance Record Extraction 570
7.1.7 Programmable Scheme Logic Settings 570
7.1.8 Time Synchronisation 570
7.1.9 Courier Configuration 571
7.2 IEC 60870-5-103 572
7.2.1 Physical Connection and Link Layer 572
7.2.2 Initialisation 573
7.2.3 Time Synchronisation 573
7.2.4 Spontaneous Events 573
7.2.5 General Interrogation (GI) 573
7.2.6 Cyclic Measurements 573
7.2.7 Commands 573
7.2.8 Test Mode 574
7.2.9 Disturbance Records 574
7.2.10 Command/Monitor Blocking 574
7.2.11 IEC 60870-5-103 Configuration 574
7.3 DNP 3.0 575
7.3.1 Physical Connection and Link Layer 576
7.3.2 Object 1 Binary Inputs 576
7.3.3 Object 10 Binary Outputs 576
7.3.4 Object 20 Binary Counters 577
7.3.5 Object 30 Analogue Input 577
7.3.6 Object 40 Analogue Output 578
7.3.7 Object 50 Time Synchronisation 578
7.3.8 DNP3 Device Profile 578
7.3.9 DNP3 Configuration 586
7.4 IEC 61850 587
7.4.1 Benefits of IEC 61850 588
7.4.2 IEC 61850 Interoperability 588
7.4.3 The IEC 61850 Data Model 588
7.4.4 IEC 61850 in MiCOM IEDs 589
7.4.5 IEC 61850 Data Model Implementation 590
7.4.6 IEC 61850 Communication Services Implementation 590
7.4.7 IEC 61850 Peer-to-peer (GOOSE) communications 590

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7.4.8 Mapping GOOSE Messages to Virtual Inputs 590

7.4.9 Ethernet Functionality 591
7.4.10 IEC 61850 Configuration 591
7.4.11 IEC 61850 Edition 2 592
8 Read Only Mode 596
8.1 IEC 60870-5-103 Protocol Blocking 596
8.2 Courier Protocol Blocking 596
8.3 IEC 61850 Protocol Blocking 597
8.4 Read-Only Settings 597
8.5 Read-Only DDB Signals 597
9 Time Synchronisation 598
9.1 Demodulated IRIG-B 598
9.1.1 IRIG-B Implementation 599
9.2 SNTP 599
9.2.1 Loss of SNTP Server Signal Alarm 599
9.3 IEEE 1588 Precision time Protocol 599
9.3.1 Accuracy and Delay Calculation 599
9.3.2 PTP Domains 600
9.4 Time Synchronsiation using the Communication Protocols 600

Chapter 23 Cyber-Security 601

1 Overview 603
2 The Need for Cyber-Security 604
3 Standards 605
3.1 NERC Compliance 605
3.1.1 CIP 002 606
3.1.2 CIP 003 606
3.1.3 CIP 004 606
3.1.4 CIP 005 606
3.1.5 CIP 006 606
3.1.6 CIP 007 607
3.1.7 CIP 008 607
3.1.8 CIP 009 607
3.2 IEEE 1686-2007 607
4 Cyber-Security Implementation 609
4.1 NERC-Compliant Display 609
4.2 Four-level Access 610
4.2.1 Blank Passwords 611
4.2.2 Password Rules 611
4.2.3 Access Level DDBs 612
4.3 Enhanced Password Security 612
4.3.1 Password Strengthening 612
4.3.2 Password Validation 612
4.3.3 Password Blocking 613
4.4 Password Recovery 614
4.4.1 Password Recovery 614
4.4.2 Password Encryption 615
4.5 Disabling Physical Ports 615
4.6 Disabling Logical Ports 615
4.7 Security Events Management 616
4.8 Logging Out 618

Chapter 24 Installation 619

1 Chapter Overview 621
2 Handling the Goods 622
2.1 Receipt of the Goods 622

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2.2 Unpacking the Goods 622

2.3 Storing the Goods 622
2.4 Dismantling the Goods 622
3 Mounting the Device 623
3.1 Flush Panel Mounting 623
3.2 Rack Mounting 624
4 Cables and Connectors 626
4.1 Terminal Blocks 626
4.2 Power Supply Connections 627
4.3 Earth Connnection 627
4.4 Current Transformers 627
4.5 Voltage Transformer Connections 628
4.6 Watchdog Connections 628
4.7 EIA(RS)485 and K-Bus Connections 628
4.8 IRIG-B Connection 628
4.9 Opto-input Connections 628
4.10 Output Relay Connections 628
4.11 Ethernet Metallic Connections 629
4.12 Ethernet Fibre Connections 629
4.13 RS232 connection 629
4.14 Download/Monitor Port 629
4.15 GPS Fibre Connection 629
4.16 Fibre Communication Connections 629
5 Case Dimensions 630
5.1 Case Dimensions 40TE 630
5.2 Case Dimensions 60TE 631
5.3 Case Dimensions 80TE 632

Chapter 25 Commissioning Instructions 633

1 Chapter Overview 635
2 General Guidelines 636
3 Commissioning Test Menu 637
3.1 Opto I/P Status Cell (Opto-input Status) 637
3.2 Relay O/P Status Cell (Relay Output Status) 637
3.3 Test Port Status Cell 637
3.4 Monitor Bit 1 to 8 Cells 637
3.5 Test Mode Cell 638
3.6 Test Pattern Cell 638
3.7 Contact Test Cell 638
3.8 Test LEDs Cell 638
3.9 Test Autoreclose Cell 638
3.10 Static Test Mode 639
3.11 Loopback Mode 639
3.12 IM64 Test Pattern 640
3.13 IM64 Test Mode 640
3.14 Red and Green LED Status Cells 640
3.15 Using a Monitor Port Test Box 640
4 Commissioning Equipment 641
4.1 Recommended Commissioning Equipment 641
4.2 Essential Commissioning Equipment 641
4.3 Advisory Test Equipment 642
5 Product Checks 643
5.1 Product Checks with the IED De-energised 643
5.1.1 Visual Inspection 644
5.1.2 Current Transformer Shorting Contacts 644
5.1.3 Insulation 644

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5.1.4 External Wiring 644

5.1.5 Watchdog Contacts 645
5.1.6 Power Supply 645
5.2 Product Checks with the IED Energised 645
5.2.1 Watchdog Contacts 645
5.2.2 Test LCD 646
5.2.3 Date and Time 646
5.2.4 Test LEDs 647
5.2.5 Test Alarm and Out-of-Service LEDs 647
5.2.6 Test Trip LED 647
5.2.7 Test User-programmable LEDs 647
5.2.8 Test Field Voltage Supply 647
5.2.9 Test Opto-inputs 647
5.2.10 Test Output Relays 648
5.2.11 Test Serial Communication Port RP1 648
5.2.12 Test Serial Communication Port RP2 649
5.2.13 Test Ethernet Communication 650
5.3 Secondary Injection Tests 650
5.3.1 Test Current Inputs 650
5.3.2 Test Voltage Inputs 651
6 Electrical Intermicom Communication Loopback 652
6.1 Setting up the Loopback 652
6.2 Loopback Test 652
6.2.1 InterMicom Command Bits 653
6.2.2 InterMicom Channel Diagnostics 653
6.2.3 Simulating a Channel Failure 653
7 Intermicom 64 Communication 654
7.1 Checking the Interface 654
7.2 Setting up the Loopback 655
7.3 Loopback Test 655
8 GPS Synchronisation 656
8.1 GPS Optical Signal Strength 656
8.2 Check Synchronisation signal at the IED 656
9 Setting Checks 657
9.1 Apply Application-specific Settings 657
9.1.1 Transferring Settings from a Settings File 657
9.1.2 Entering settings using the HMI 657
10 IEC 61850 Edition 2 Testing 659
10.1 Using IEC 61850 Edition 2 Test Modes 659
10.1.1 IED Test Mode Behaviour 659
10.1.2 Sampled Value Test Mode Behaviour 659
10.2 Simulated Input Behaviour 660
10.3 Testing Examples 660
10.3.1 Test Procedure for Real Values 661
10.3.2 Test Procedure for Simulated Values - No Plant 661
10.3.3 Test Procedure for Simulated Values - With Plant 662
10.3.4 Contact Test 663
11 Current Differential Protection 664
11.1 Current Differential Bias Characteristic 664
11.1.1 Lower Slope 664
11.1.2 Upper Slope 665
11.2 Current Differential Operation and Contact Assignment 665
12 Distance Protection 667
12.1 Dependency Conditions 667
12.2 Distance Protection Single-ended Testing 667
12.2.1 Preliminaries 667
12.2.2 Zone 1 Reach Check 668
12.2.3 Zone 2 Reach Check 668

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12.2.4 Zone 3 Reach Check 669

12.2.5 Zone 4 Reach Check 669
12.2.6 Zone P Reach Check 669
12.2.7 Zone Q Reach Check 669
12.2.8 Resistive Reach 669
12.2.9 Load Blinder 670
12.3 Operation and Contact Assignment 670
12.3.1 Phase A 670
12.3.2 Phase B 670
12.3.3 Phase C 670
12.3.4 Time Delay Settings 671
12.4 Scheme Testing 671
12.4.1 Scheme Trip Test for Zone 1 Extension 672
12.4.2 Scheme Trip Tests for Permissive Schemes 672
12.4.3 Scheme Trip Tests for Blocking Scheme 672
12.4.4 Signal Send Test for Permissive Schemes 673
12.4.5 Signal Send Test for Blocking Scheme 673
12.4.6 Scheme Timer Settings 673
13 Delta Directional Comparison 674
13.1 Single-ended Testing 674
13.1.1 Preliminaries 674
13.1.2 Single-ended Injection Test 674
13.1.3 Forward Fault Preparation 674
13.2 Operation and Contact Assignment 675
13.2.1 Phase A 675
13.2.2 Phase B 675
13.2.3 Phase C 675
13.3 Delta Protection Scheme Testing 676
13.3.1 Signal Send Test for Permissive Schemes 676
13.3.2 Signal Send Test for Blocking Schemes 676
14 DEF Aided Schemes 677
14.1 Dependency Conditions 677
14.2 Earth Current Pilot Scheme 677
14.2.1 Preliminaries 678
14.2.2 Perform the Test 678
14.2.3 Forward Fault Trip Test 678
14.3 Scheme Testing 679
14.3.1 Signal Send Test for Permissive Schemes 679
14.3.2 Signal Send Test for Blocking Schemes 679
15 Out of Step Protection 680
15.1 OST Setting 680
15.2 Predictive OST Setting 681
15.3 Predictive and OST Setting 681
15.4 OST Timer Test 681
16 Protection Timing Checks 682
16.1 Dependency Conditions 682
16.2 Overcurrent Check 682
16.3 Connecting the Test Circuit 682
16.4 Performing the Test 683
16.5 Check the Operating Time 683
17 System Check and Check Synchronism 684
17.1 Check Synchronism Pass 684
17.2 Check Synchronism Fail 684
18 Check Trip and Autoreclose Cycle 685
19 End-to-End Communication Tests 686
19.1 Remove Local Loopbacks 686
19.1.1 Restoring Direct Fibre Connections 686
19.1.2 Restoring C37.94 Fibre Connections 687

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19.1.3 Communications using P59x Interface Units 687

19.2 Remove Remote Loopbacks 687
19.3 Verify Communication between IEDs 687
20 End-to-End Scheme Tests 689
20.1 Aided Scheme 1 689
20.1.1 Preparation at Remote End 689
20.1.2 Performing the Test 689
20.1.3 Channel Check in the Opposite Direction 689
20.2 Aided Scheme 2 689
21 Onload Checks 691
21.1 Confirm Voltage Connections 691
21.2 Confirm Current Connections 691
21.3 Measure Capacitive Charging Current 692
21.4 Check Differential Current 692
21.5 Check Current Transformer Polarity 692
21.6 On-load Directional Test 692
22 Final Checks 693
23 Commmissioning the P59x 694
23.1 Visual Inspection 694
23.2 Insulation 694
23.3 External Wiring 694
23.4 P59x Auxiliary Supply 694
23.5 P59x LEDs 695
23.6 Received Optical Signal Level 695
23.7 Optical Transmitter Level 695
23.8 Loopback Test 696

Chapter 26 Maintenance and Troubleshooting 697

1 Chapter Overview 699
2 Maintenance 700
2.1 Maintenance Checks 700
2.1.1 Alarms 700
2.1.2 Opto-isolators 700
2.1.3 Output Relays 700
2.1.4 Measurement Accuracy 700
2.2 Replacing the Device 701
2.3 Repairing the Device 702
2.4 Removing the front panel 702
2.5 Replacing PCBs 703
2.5.1 Replacing the main processor board 703
2.5.2 Replacement of communications boards 704
2.5.3 Replacement of the input module 705
2.5.4 Replacement of the power supply board 705
2.5.5 Replacement of the I/O boards 706
2.6 Recalibration 706
2.7 Changing the battery 706
2.7.1 Post Modification Tests 707
2.7.2 Battery Disposal 707
2.8 Cleaning 707
3 Troubleshooting 708
3.1 Self-Diagnostic Software 708
3.2 Power-up Errors 708
3.3 Error Message or Code on Power-up 708
3.4 Out of Service LED on at power-up 709
3.5 Error Code during Operation 710
3.5.1 Backup Battery 710

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3.6 Mal-operation during testing 710

3.6.1 Failure of Output Contacts 710
3.6.2 Failure of Opto-inputs 710
3.6.3 Incorrect Analogue Signals 711
3.7 Coprocessor board failures 711
3.7.1 Signalling failure alarm (on its own) 711
3.7.2 C diff failure alarm (on its own) 711
3.7.3 Signalling failure and C diff failure alarms together 711
3.7.4 Incompatible IED 711
3.7.5 Comms changed 711
3.7.6 IEEE C37.94 fail 712
3.8 PSL Editor Troubleshooting 712
3.8.1 Diagram Reconstruction 712
3.8.2 PSL Version Check 712
3.9 Repair and Modification Procedure 712

Chapter 27 Technical Specifications 715

1 Chapter Overview 717
2 Interfaces 718
2.1 Front Serial Port 718
2.2 Download/Monitor Port 718
2.3 Rear Serial Port 1 718
2.4 Fibre Rear Serial Port 1 718
2.5 Rear Serial Port 2 719
2.6 Optional Rear Serial Port (SK5) 719
2.7 IRIG-B (Demodulated) 719
2.8 IRIG-B (Modulated) 719
2.9 Rear Ethernet Port Copper 720
2.10 Rear Ethernet Port Fibre 720
2.10.1 100 Base FX Receiver Characteristics 720
2.10.2 100 Base FX Transmitter Characteristics 721
2.11 1 PPS Port 721
2.12 Fibre Teleprotection Interface 721
3 Protection Functions 722
3.1 Phase Current Differential Protection 722
3.2 Neutral Current Differential Protection 722
3.3 Distance Protection 723
3.4 Power Swing Blocking 723
3.5 Out Of Step Protection 724
3.6 Fibre Teleprotection Transfer Times 724
3.7 Autoreclose and Check Synychronism 724
3.8 Phase Overcurrent Protection 724
3.8.1 Transient Overreach and Overshoot 725
3.8.2 Phase Overcurrent Directional Parameters 725
3.9 Earth Fault Protection 725
3.9.1 Earth Fault Directional Parameters 725
3.10 Sensitive Earth Fault Protection 726
3.10.1 Sensitive Earth Fault Protection Directional Element 726
3.11 High Impedance Restricted Earth Fault Protection 726
3.12 Negative Sequence Overcurrent Protection 726
3.12.1 NPSOC Directional Parameters 727
3.13 Circuit Breaker Fail and Undercurrent Protection 727
3.14 Broken Conductor Protection 727
3.15 Thermal Overload Protection 727
4 Monitoring, Control and Supervision 728
4.1 Voltage Transformer Supervision 728

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4.2 Standard Current Transformer Supervision 728

4.3 Differential Current Transformer Supervision 728
4.4 CB State and Condition Monitoring 728
4.5 PSL Timers 729
5 Measurements and Recording 730
5.1 General 730
5.2 Disturbance Records 730
5.3 Event, Fault and Maintenance Records 730
5.4 Fault Locator 730
6 Ratings 731
6.1 AC Measuring Inputs 731
6.2 Current Transformer Inputs 731
6.3 Voltage Transformer Inputs 731
6.4 Auxiliary Supply Voltage 731
6.5 Nominal Burden 732
6.6 Power Supply Interruption 732
6.7 Battery Backup 733
7 Input / Output Connections 734
7.1 Isolated Digital Inputs 734
7.1.1 Nominal Pickup and Reset Thresholds 734
7.2 Standard Output Contacts 734
7.3 High Break Output Contacts 735
7.4 Watchdog Contacts 735
8 Mechanical Specifications 736
8.1 Physical Parameters 736
8.2 Enclosure Protection 736
8.3 Mechanical Robustness 736
8.4 Transit Packaging Performance 736
9 Type Tests 737
9.1 Insulation 737
9.2 Creepage Distances and Clearances 737
9.3 High Voltage (Dielectric) Withstand 737
9.4 Impulse Voltage Withstand Test 737
10 Environmental Conditions 738
10.1 Ambient Temperature Range 738
10.2 Temperature Endurance Test 738
10.3 Ambient Humidity Range 738
10.4 Corrosive Environments 738
11 Electromagnetic Compatibility 739
11.1 1 MHz Burst High Frequency Disturbance Test 739
11.2 Damped Oscillatory Test 739
11.3 Immunity to Electrostatic Discharge 739
11.4 Electrical Fast Transient or Burst Requirements 739
11.5 Surge Withstand Capability 739
11.6 Surge Immunity Test 740
11.7 Immunity to Radiated Electromagnetic Energy 740
11.8 Radiated Immunity from Digital Communications 740
11.9 Radiated Immunity from Digital Radio Telephones 740
11.10 Immunity to Conducted Disturbances Induced by Radio Frequency Fields 740
11.11 Magnetic Field Immunity 741
11.12 Conducted Emissions 741
11.13 Radiated Emissions 741
11.14 Power Frequency 741
12 Regulatory Compliance 742
12.1 EMC Compliance: 2014/30/EU 742
12.2 LVD Compliance: 2014/35/EU 742

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12.3 R&TTE Compliance: 2014/53/EU 742

12.4 UL/CUL Compliance 742
12.5 ATEX Compliance: 2014/34/EU 742

Appendix A Ordering Options 745

Appendix B Settings and Signals 747

Appendix C Wiring Diagrams 749

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xxiv P54x1i-TM-EN-1
Table of Figures
Figure 1: P40L version M85 - version evolution 7
Figure 2: Key to logic diagrams 12
Figure 3: Functional Overview 13
Figure 4: Hardware architecture 32
Figure 5: Coprocessor hardware architecture 33
Figure 6: Exploded view of IED 34
Figure 7: Front panel (60TE) 37
Figure 8: Rear view of populated case 41
Figure 9: Terminal block types 42
Figure 10: Rear connection to terminal block 43
Figure 11: Main processor board 44
Figure 12: Power supply board 45
Figure 13: Power supply assembly 46
Figure 14: Power supply terminals 47
Figure 15: Watchdog contact terminals 48
Figure 16: Rear serial port terminals 49
Figure 17: Input module - 1 transformer board 49
Figure 18: Input module schematic 50
Figure 19: Transformer board 51
Figure 20: Input board 52
Figure 21: Standard output relay board - 8 contacts 53
Figure 22: IRIG-B board 54
Figure 23: Fibre optic board 55
Figure 24: Rear communication board 56
Figure 25: Ethernet board 56
Figure 26: Redundant Ethernet board 58
Figure 27: Fully populated Coprocessor board 60
Figure 28: Software Architecture 66
Figure 29: Frequency response of FIR filters 72
Figure 30: Frequency Response (indicative only) 73
Figure 31: Navigating the HMI 80
Figure 32: Default display navigation 82
Figure 33: Circuit Breaker Trip Conversion Logic Diagram (Module 63) 89
Figure 34: Ping-pong measurement for alignment of current signals 102
Figure 35: Asymmetric propogation delay times 104
Figure 36: Dual slope current differential bias characteristic 105
Figure 37: Phase Current Differential Protection logic 107
Figure 38: Capacitive charging current 112
Table of Figures P543i/P545i

Figure 39: CT Compensation 113

Figure 40: The need for zero-sequence current filtering 116
Figure 41: Magnetising inrush phenomenon 117
Figure 42: Typical overflux current waveform 119
Figure 43: Phase Current Differential Protection logic for feeders with in-zone transformers 120
Figure 44: Second Harmonic Blocking logic 121
Figure 45: Fifth Harmonic Blocking logic 122
Figure 46: Permissive Intertripping example 123
Figure 47: Stub Bus protection 124
Figure 48: Typical two-terminal plain feeder circuit 129
Figure 49: Typical three-terminal plain feeder circuit 130
Figure 50: System Impedance Ratio 136
Figure 51: Directional mho element construction 139
Figure 52: Offset Mho characteristic 140
Figure 53: Directional Mho element construction – impedance domain 141
Figure 54: Offset Mho characteristics – impedance domain 142
Figure 55: Offset mho characteristics – voltage domain 143
Figure 56: Simplified forward fault 144
Figure 57: Mho expansion – forward fault 145
Figure 58: Simplified Reverse Fault 146
Figure 59: Mho contraction – reverse fault 147
Figure 60: Simplified quadrilateral characteristics 149
Figure 61: General Quadrilateral Characteristic Limits 150
Figure 62: Directional Quadrilateral Characteristic 151
Figure 63: Quadrilateral Characteristic featuring 2 directional forward zones and 1 offset zone 152
Figure 64: Five-sided polygon formed by Quadrilateral characteristic with Directional-Line 153
intersection of Reverse Impedance Reach Line
Figure 65: Impedance Reach line in Z1 plane 156
Figure 66: Impedance Reach line in ZLP plane 157
Figure 67: General characteristic in ZLP plane 158
Figure 68: Phase relations between I2 and Iph for leading and lagging polarizing currents 159
Figure 69: General characteristic in Z1 plane 160
Figure 70: Simplified characteristic in Z1 plane 161
Figure 71: Impedance Reach line construction 163
Figure 72: Reverse impedance reach line construction 164
Figure 73: Resistive reach of phase elements 164
Figure 74: Resistive Reach line construction 165
Figure 75: Reverse resistive reach line construction 166
Figure 76: Phase Fault Quadrilateral characteristic summary 166
Figure 77: Phase to phase current changes for C phase-to-ground (CN) fault 170

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Figure 78: Biased Neutral Current Detector Characteristic 171

Figure 79: Load Blinder Characteristics 174
Figure 80: Sequence networks connection for an internal A-N fault 177
Figure 81: - DV Forward and Reverse tripping regions 178
Figure 82: Current level (amps) at which transient faults are self-extinguishing 179
Figure 83: Earth fault in Petersen Coil earthed system 180
Figure 84: Distribution of currents during a Phase C fault 180
Figure 85: Phasors for a phase C earth fault in a Petersen Coil earthed system 181
Figure 86: Zero sequence network showing residual currents 181
Figure 87: Phase C earth fault in Petersen Coil earthed system: practical case with resistance 182
present
Figure 88: Voltage distribution in an isolated system for a Phase-A-to-Earth fault 185
Figure 89: Biased Neutral Current Detector 185
Figure 90: First earth fault detection 186
Figure 91: Second earth fault detection logic 187
Figure 92: Priority setting enable logic 189
Figure 93: Zone starting logic 190
Figure 94: Zone timer logic 191
Figure 95: Zone trip logic 192
Figure 96: Settings required to apply a quadrilateral zone 193
Figure 97: Settings required to apply a mho zone 194
Figure 98: Over-tilting effect 196
Figure 99: Example power system 201
Figure 100: Apparent Impedances seen by Distance Protection on a Teed Feeder 206
Figure 101: Scheme Assignment 211
Figure 102: Aided Distance PUR scheme 214
Figure 103: Aided Distance POR scheme 216
Figure 104: Example of fault current reversal of direction 218
Figure 105: Aided Distance Blocking scheme (BOP) 220
Figure 106: Aided Distance Send logic 222
Figure 107: Carrier Aided Schemes Receive logic 223
Figure 108: Aided Distance Tripping logic 223
Figure 109: PUR Aided Tripping logic 224
Figure 110: POR Aided Tripping logic 225
Figure 111: Aided Scheme Blocking 1 Tripping logic 226
Figure 112: Aided Scheme Blocking 2 Tripping logic 226
Figure 113: Virtual Current Polarization 229
Figure 114: Directional criteria for residual voltage polarization 230
Figure 115: Aided DEF POR scheme 232
Figure 116: Aided DEF Blocking scheme 233

P54x1i-TM-EN-1 xxvii
Table of Figures P543i/P545i

Figure 117: DEF Directional Signals 233

Figure 118: Aided DEF Send logic 234
Figure 119: Carrier Aided Schemes Receive logic 234
Figure 120: Aided DEF Tripping logic 235
Figure 121: POR Aided Tripping logic 236
Figure 122: Aided Scheme Blocking 1 Tripping logic 237
Figure 123: Aided Scheme Blocking 2 Tripping logic 237
Figure 124: Aided Delta POR scheme 239
Figure 125: Aided Delta Blocking scheme 240
Figure 126: Aided Delta Send logic 241
Figure 127: Carrier Aided Schemes Receive logic 241
Figure 128: Aided Delta Tripping logic 242
Figure 129: POR Aided Tripping logic 243
Figure 130: Aided Scheme Blocking 1 Tripping logic 244
Figure 131: Aided Scheme Blocking 2 Tripping logic 244
Figure 132: Apparent Impedances seen by Distance Protection on a Teed Feeder 247
Figure 133: Problematic Fault Scenarios for PUR Scheme Application to Teed Feeders 249
Figure 134: Zone Starting Logic 256
Figure 135: Zone timer logic 257
Figure 136: Zone trip logic 257
Figure 137: Basic time stepped distance scheme 258
Figure 138: Trip On Close logic 259
Figure 139: Trip On Close based on CNV level detectors 260
Figure 140: SOTF Tripping 261
Figure 141: SOTF Tripping with CNV 261
Figure 142: TOR Tripping logic for appropriate zones 262
Figure 143: TOR Tripping logic with CNV 262
Figure 144: Zone 1 extension scheme 264
Figure 145: Zone 1 extension logic 264
Figure 146: Loss of load accelerated trip scheme 265
Figure 147: Loss of Load Logic 266
Figure 148: Power transfer related to angular difference between two generation sources 270
Figure 149: Phase selector timing for power swing condition 273
Figure 150: Phase selector timing for fault condition 274
Figure 151: Phase selector timing for fault during a power swing 274
Figure 152: Slow Power Swing detection characteristic 275
Figure 153: Load Blinder Boundary Conditions 278
Figure 154: Power swing blocking logic 279
Figure 155: Setting the resistive reaches 280
Figure 156: Reactive reach settings 281

xxviii P54x1i-TM-EN-1
P543i/P545i Table of Figures

Figure 157: PSB timer setting guidelines 282

Figure 158: Out of Step detection characteristic 283
Figure 159: Out of Step logic diagram 285
Figure 160: OST setting determination for the positive sequence resistive component OST R5 287
Figure 161: OST R6max determination 288
Figure 162: Example of timer reset due to MOVs operation 290
Figure 163: Autoreclose sequence for a Transient Fault 300
Figure 164: Autoreclose sequence for an evolving or permanent fault 301
Figure 165: Autoreclose sequence for an evolving or permanent fault - single-phase operation 301
Figure 166: Key to logic diagrams 303
Figure 167: Autoreclose System Map - part 1 304
Figure 168: Autoreclose System Map - part 2 305
Figure 169: Autoreclose System Map - part 3 306
Figure 170: Autoreclose System Map - part 4 307
Figure 171: Autoreclose System Map - part 5 308
Figure 172: CB State Monitor logic diagram (Module 1) 318
Figure 173: Circuit Breaker Open logic diagram (Module 3) 319
Figure 174: CB In Service logic diagram (Module 4) 319
Figure 175: Autoreclose OK logic diagram (Module 8) 320
Figure 176: Autoreclose Enable logic diagram (Module 5) 320
Figure 177: Autoreclose Modes Enable logic diagram (Module 9) 322
Figure 178: Force Three-phase Trip logic diagram (Module 10) 322
Figure 179: Autoreclose Initiation logic diagram (Module 11) 324
Figure 180: Autoreclose Trip Test logic diagram (Module 12) 324
Figure 181: Autoreclose initiation by external trip or evolving conditions (Module 13) 325
Figure 182: Protection Reoperation and Evolving Fault logic diagram (Module 20) 326
Figure 183: Fault Memory logic diagram (Module 15) 326
Figure 184: Autoreclose In Progress logic diagram (Module 16) 327
Figure 185: Autoreclose Sequence Counter logic diagram (Module 18) 328
Figure 186: Single-phase Autoreclose Cycle Selection logic diagram (Module 19) 328
Figure 187: Three-phase Autoreclose Cycle Selection logic diagram (Module 21) 329
Figure 188: Dead time Start Enable logic diagram (Module 22) 330
Figure 189: Single-phase Dead Time logic diagram (Module 24) 331
Figure 190: Three-phase Dead Time logic diagram (Module 25) 332
Figure 191: Circuit Breaker Autoclose Logic Diagram (Module 32) 333
Figure 192: Prepare Reclaim Initiation Logic Diagram (Module 34) 334
Figure 193: Reclaim Time logic diagram (Module 35) 334
Figure 194: Successful Autoreclose Signals logic diagram (Module 36) 335
Figure 195: Autoreclose Reset Successful Indication logic diagram (Module 37) 335
Figure 196: Circuit Breaker Healthy and System Check Timers Healthy logic diagram (Module 39) 336

P54x1i-TM-EN-1 xxix
Table of Figures P543i/P545i

Figure 197: Autoreclose Shot Counters logic diagram (Module 41) 337
Figure 198: CB Control logic diagram (Module 43) 338
Figure 199: Circuit Breaker Trip Time Monitoring logic diagram (Module 53) 339
Figure 200: AR Lockout Logic Diagram (Module 55) 340
Figure 201: Reset Circuit Breaker Lockout Logic Diagram (Module 57) 341
Figure 202: Pole Discrepancy Logic Diagram (Module 62) 342
Figure 203: Circuit Breaker Trip Conversion Logic Diagram (Module 63) 343
Figure 204: Check Synchronisation Monitor for CB closure (Module 60) 344
Figure 205: Voltage Monitor for CB Closure (Module 59) 345
Figure 206: Three-phase Autoreclose System Check Logic Diagram (Module 45) 347
Figure 207: CB Manual Close System Check Logic Diagram (Module 51) 348
Figure 208: Circuit Breaker Fail logic - part 1 357
Figure 209: Circuit Breaker Fail logic - part 2 358
Figure 210: Circuit Breaker Fail logic - part 3 359
Figure 211: Circuit Breaker Fail logic - part 4 360
Figure 212: CB Fail timing 362
Figure 213: Phase Overcurrent Protection logic diagram 368
Figure 214: Negative Phase Sequence Overcurrent Protection logic diagram 370
Figure 215: IDG Characteristic 373
Figure 216: Earth Fault Protection logic diagram 375
Figure 217: EPATR B characteristic shown for TMS = 1.0 378
Figure 218: Sensitive Earth Fault Protection logic diagram 378
Figure 219: Current distribution in an insulated system with C phase fault 379
Figure 220: Phasor diagrams for insulated system with C phase fault 380
Figure 221: Positioning of core balance current transformers 381
Figure 222: High Impedance REF principle 382
Figure 223: High Impedance REF Connection 383
Figure 224: Thermal overload protection logic diagram 385
Figure 225: Spreadsheet calculation for dual time constant thermal characteristic 386
Figure 226: Dual time constant thermal characteristic 386
Figure 227: Broken conductor logic 389
Figure 228: Transient Earth Fault Logic Overview 393
Figure 229: Fault Type Detector Logic 394
Figure 230: Direction Detector Logic - Standard Mode 394
Figure 231: TEFD output alarm logic 394
Figure 232: Undervoltage - single and three phase tripping mode (single stage) 399
Figure 233: Overvoltage - single and three phase tripping mode (single stage) 402
Figure 234: Residual Overvoltage logic 406
Figure 235: Residual voltage for a solidly earthed system 407
Figure 236: Residual voltage for an impedance earthed system 408

xxx P54x1i-TM-EN-1
P543i/P545i Table of Figures

Figure 237: Underfrequency logic (single stage) 413

Figure 238: Overfrequency logic (single stage) 414
Figure 239: Rate of change of frequency logic (single stage) 415
Figure 240: Fault recorder stop conditions 432
Figure 241: Broken Current Accumulator logic diagram 437
Figure 242: CB Trip Counter logic diagram 437
Figure 243: Operating Time Accumulator 438
Figure 244: Excessive Fault Frequency logic diagram 438
Figure 245: Reset Lockout Alarm logic diagram 439
Figure 246: CB Condition Monitoring logic diagram 440
Figure 247: Reset Circuit Breaker Lockout Logic Diagram (Module 57) 441
Figure 248: CB State Monitor logic diagram (Module 1) 444
Figure 249: Hotkey menu navigation 446
Figure 250: Default function key PSL 447
Figure 251: Remote Control of Circuit Breaker 448
Figure 252: CB Control logic diagram (Module 43) 449
Figure 253: Pole Dead logic 450
Figure 254: Check Synchronisation vector diagram 453
Figure 255: Voltage Monitor for CB Closure (Module 59) 454
Figure 256: Check Synchronisation Monitor for CB closure (Module 60) 455
Figure 257: System Check PSL 456
Figure 258: Current Differential Starter Supervision Logic 464
Figure 259: Current Differential function Start logic 465
Figure 260: Switched Communication Path supervision 466
Figure 261: Communication Asymmetry Supervision 467
Figure 262: VTS logic 474
Figure 263: Differential CTS 476
Figure 264: Standard CTS 477
Figure 265: TCS Scheme 1 479
Figure 266: PSL for TCS Scheme 1 480
Figure 267: TCS Scheme 2 481
Figure 268: PSL for TCS Scheme 2 481
Figure 269: TCS Scheme 3 482
Figure 270: PSL for TCS Scheme 3 482
Figure 271: Scheme Logic Interfaces 487
Figure 272: Trip LED logic 491
Figure 273: Fibre Teleprotection connections for a three-terminal Scheme 503
Figure 274: Interfacing to PCM multiplexers 508
Figure 275: IM64 channel fail and scheme fail logic 511
Figure 276: IM64 general alarm signals logic 511

P54x1i-TM-EN-1 xxxi
Table of Figures P543i/P545i

Figure 277: IM64 communications mode and IEEE C37.94 alarm signals 512
Figure 278: IM64 two-terminal scheme extended supervision 514
Figure 279: IM64 three-terminal scheme extended supervision 514
Figure 280: Example assignment of InterMiCOM signals within the PSL 524
Figure 281: Direct connection 525
Figure 282: Indirect connection using modems 525
Figure 283: RS485 biasing circuit 534
Figure 284: Remote communication using K-Bus 535
Figure 285: IED attached to separate LANs 538
Figure 286: HSR multicast topology 539
Figure 287: HSR unicast topology 540
Figure 288: HSR application in the substation 541
Figure 289: IED attached to redundant Ethernet star or ring circuit 541
Figure 290: IED, bay computer and Ethernet switch with self healing ring facilities 542
Figure 291: Redundant Ethernet ring architecture with IED, bay computer and Ethernet switches 542
Figure 292: Redundant Ethernet ring architecture with IED, bay computer and Ethernet switches 543
after failure
Figure 293: Dual homing mechanism 544
Figure 294: Application of Dual Homing Star at substation level 545
Figure 295: IED and REB IP address configuration 546
Figure 296: Connection using (a) an Ethernet switch and (b) a media converter 550
Figure 297: Connection using (a) an Ethernet switch and (b) a media converter 554
Figure 298: Control input behaviour 577
Figure 299: Data model layers in IEC61850 589
Figure 300: Edition 2 system - backward compatibility 593
Figure 301: Edition 1 system - forward compatibility issues 593
Figure 302: Example of Standby IED 594
Figure 303: Standby IED Activation Process 595
Figure 304: GPS Satellite timing signal 598
Figure 305: Timing error using ring or line topology 600
Figure 306: Default display navigation 610
Figure 307: Location of battery isolation strip 623
Figure 308: Rack mounting of products 624
Figure 309: Terminal block types 626
Figure 310: 40TE case dimensions 630
Figure 311: 60TE case dimensions 631
Figure 312: 80TE case dimensions 632
Figure 313: RP1 physical connection 648
Figure 314: Remote communication using K-bus 649
Figure 315: InterMicom loopback testing 652

xxxii P54x1i-TM-EN-1
P543i/P545i Table of Figures

Figure 316: Simulated input behaviour 660

Figure 317: Test example 1 661
Figure 318: Test example 2 662
Figure 319: Test example 3 663
Figure 320: Current Differential Bias Characteristics 664
Figure 321: State impedances 680
Figure 322: Possible terminal block types 702
Figure 323: Front panel assembly 704

P54x1i-TM-EN-1 xxxiii
Table of Figures P543i/P545i

xxxiv P54x1i-TM-EN-1
 CHAPTER 1

INTRODUCTION
Chapter 1 - Introduction P543i/P545i

2 P54x1i-TM-EN-1
P543i/P545i Chapter 1 - Introduction

1 CHAPTER OVERVIEW
This chapter provides some general information about the technical manual and an introduction to the device(s)
described in this technical manual.

This chapter contains the following sections:

Chapter Overview 3
Foreword 4
Product Scope 6
Features and Functions 8
Logic Diagrams 11
Functional Overview 13

P54x1i-TM-EN-1 3
Chapter 1 - Introduction P543i/P545i

2 FOREWORD
This technical manual provides a functional and technical description of General Electric's P543i/P545i, as well as a
comprehensive set of instructions for using the device. The level at which this manual is written assumes that you
are already familiar with protection engineering and have experience in this discipline. The description of principles
and theory is limited to that which is necessary to understand the product. For further details on general
protection engineering theory, we refer you to Alstom's publication NPAG, which is available online or from our
contact centre.
We have attempted to make this manual as accurate, comprehensive and user-friendly as possible. However we
cannot guarantee that it is free from errors. Nor can we state that it cannot be improved. We would therefore be
very pleased to hear from you if you discover any errors, or have any suggestions for improvement. Our policy is to
provide the information necessary to help you safely specify, engineer, install, commission, maintain, and
eventually dispose of this product. We consider that this manual provides the necessary information, but if you
consider that more details are needed, please contact us.
All feedback should be sent to our contact centre via the following URL:
www.gegridsolutions.com/contact

2.1 TARGET AUDIENCE

This manual is aimed towards all professionals charged with installing, commissioning, maintaining,
troubleshooting, or operating any of the products within the specified product range. This includes installation and
commissioning personnel as well as engineers who will be responsible for operating the product.
The level at which this manual is written assumes that installation and commissioning engineers have knowledge
of handling electronic equipment. Also, system and protection engineers have a thorough knowledge of protection
systems and associated equipment.

2.2 TYPOGRAPHICAL CONVENTIONS

The following typographical conventions are used throughout this manual.
● The names for special keys appear in capital letters.
For example: ENTER
● When describing software applications, menu items, buttons, labels etc as they appear on the screen are
written in bold type.
For example: Select Save from the file menu.
● Filenames and paths use the courier font
For example: Example\File.text
● Special terminology is written with leading capitals
For example: Sensitive Earth Fault
● If reference is made to the IED's internal settings and signals database, the menu group heading (column)
text is written in upper case italics
For example: The SYSTEM DATA column
● If reference is made to the IED's internal settings and signals database, the setting cells and DDB signals are
written in bold italics
For example: The Language cell in the SYSTEM DATA column
● If reference is made to the IED's internal settings and signals database, the value of a cell's content is
written in the Courier font
For example: The Language cell in the SYSTEM DATA column contains the value English

4 P54x1i-TM-EN-1
P543i/P545i Chapter 1 - Introduction

2.3 NOMENCLATURE
Due to the technical nature of this manual, many special terms, abbreviations and acronyms are used throughout
the manual. Some of these terms are well-known industry-specific terms while others may be special product-
specific terms used by General Electric. The first instance of any acronym or term used in a particular chapter is
explained. In addition, a separate glossary is available on the General Electric website, or from the General Electric
contact centre.
We would like to highlight the following changes of nomenclature however:
● The word 'relay' is no longer used to describe the device itself. Instead, the device is referred to as the 'IED'
(Intelligent Electronic Device), the 'device', or the 'product'. The word 'relay' is used purely to describe the
electromechanical components within the device, i.e. the output relays.
● British English is used throughout this manual.
● The British term 'Earth' is used in favour of the American term 'Ground'.

2.4 COMPLIANCE
The device has undergone a range of extensive testing and certification processes to ensure and prove
compatibility with all target markets. A detailed description of these criteria can be found in the Technical
Specifications chapter.

P54x1i-TM-EN-1 5
Chapter 1 - Introduction P543i/P545i

3 PRODUCT SCOPE
The P543 and P545 devices have been designed for current differential protection of overhead line and cable
applications. Version M85 of P543 and P545 have been designed for both solidly grounded systems and Petersen
Coil grounded systems. The products within this range interface readily with the longitudinal (end-end)
communications channel between line terminals. The P543 and P545 devices are for single circuit breaker
applications.
The devices include high-speed current differential unit protection with optional high performance sub-cycle
distance protection, including phase segregated aided directional earth fault protection as well as in-zone
transformer differential protection and 4-shot phase-segregated Autoreclose protection. The P545 provides more
I/O and is housed in a larger case than the P543. The differences between the model variants are summarised in
the table below:

Feature/Variant P543 model A P543 model S P545 model A P545 model N P545 model S
Number of CT Inputs 5 5 5 5 5
Number of VT inputs 4 4 4 4 4
Opto-coupled digital inputs 16 16 24 32 24
Standard relay output contacts 14 7 32 32 16
High speed high break output contacts 4 8
The M85 version of these devices provide additional functionality, which allow them to be used for cross-country
faults in Petersen Coil earthed systems. To supplement this requirement, in addition it provides transient earth
fault detection, a sixth protection zone, enhanced power swing detection functionality and a VT input for
measuring the neutral voltage.

3.1 PRODUCT VERSIONS

This product is a special version from the P40L family. This diagram shows from which version this product has
evolved.

6 P54x1i-TM-EN-1
P543i/P545i Chapter 1 - Introduction

P445: P46
P54x No Distance : M66
P841A: M66
Special
All other products: M76

· Current Diff Starters for P 54x P443: M78B

· Other improvements · Zone Q addition
· PSB changes
· VT input for Vn meas .
Non-distance products: M81 · Cross-country fault
Distance products : M82 enhancements

· IEC 61850 Edition 2

· IEEE 1588 support

Special
P443i, P543i, P545i: M85
· Zone Q addition for DE
· PSB changes for DE
·· German
VT input forthing
Vn meas . for DE
· Cross-country fault
enhancements for DE

V00062-M85
Figure 1: P40L version M85 - version evolution

3.1.1 ORDERING OPTIONS

All current models and variants for this product are defined in an interactive spreadsheet called the CORTEC. This is
available on the company website.
Alternatively, you can obtain it via the Contact Centre at the following URL:
www.gegridsolutions.com/contact
A copy of the CORTEC is also supplied as a static table in the Appendices of this document. However, it should only
be used for guidance as it provides a snapshot of the interactive data taken at the time of publication.

P54x1i-TM-EN-1 7
Chapter 1 - Introduction P543i/P545i

4 FEATURES AND FUNCTIONS

4.1 CURRENT DIFFERENTIAL PROTECTION FUNCTIONS

Feature IEC 61850 ANSI

Phase segregated current differential protection DifPDIF1 87L
Neutral current differential protection (optional) DifPDIF2 87N
2 and 3 terminal lines/cables
Feeders with in-zone transformers 87T
Suitable for use with SDH/SONET networks (using P594)
GPS time synchronization (optional)

4.2 DISTANCE PROTECTION FUNCTIONS

Feature IEC 61850 ANSI

Distance zones, full-scheme protection (6) DisPDIS 21/21N
Phase characteristic (Mho and quadrilateral)
Ground characteristic (Mho and quadrilateral)
CVT transient overreach elimination
Load blinder
Easy setting mode
Communication-aided schemes, PUTT, POTT, Blocking, Weak
DisPSCH 85
Infeed
Accelerated tripping – loss of load and Z1 extension
Switch on to fault and trip on reclose – elements for fast fault
SofPSOF/ TorPSOF 50SOTF/27SOTF
clearance on breaker closure

Power swing blocking PsbRPSB 68

Directional earth fault (DEF) unit protection 67N

Out of step OstRPSB 78

Delta directional comparison - fast channel schemes operating

78DCB/78DCUB
on fault generated superimposed quantities

Mutual compensation (for fault locator and distance zones)

Cross-country fault detection

InterMiCOM64 teleprotection for direct device-to-device

communication (optional)

4.3 PROTECTION FUNCTIONS

Feature IEC 61850 ANSI

Tripping Mode (1 & 3 pole) PTRC
ABC and ACB phase rotation

8 P54x1i-TM-EN-1
P543i/P545i Chapter 1 - Introduction

Feature IEC 61850 ANSI

Phase overcurrent , with optional directionality (4 stages) OcpPTOC/RDIR 50/51/67
Earth/Ground overcurrent stages, with optional directionality (4
EfdPTOC/RDIR 50N/51N/ 67N
stages)
Sensitive earth fault (SEF) (4 stages) SenPTOC/RDIR 50N/51N/67N
High impedance restricted earth fault (REF) SenRefPDIF 64
Transient Earth Fault Detection (TEFD) PTEF
Negative sequence overcurrent stages, with optional
NgcPTOC/RDIR 67/46
directionality (4 stages)
Broken conductor, used to detect open circuit faults 46
Thermal overload protection ThmPTTR 49
Undervoltage protection (2 stages) VtpPhsPTUV 27
Overvoltage protection (2 stages) VtpPhsPTOV 59
Remote overvoltage protection (2 stages) VtpCmpPTOV 59R
Residual voltage protection (2 stages) VtpResPTOV 59N
Underfrequency protection (4 stages) FrqPTUF 81
Overfrequency protection (2 stages) FrqPTOF 81
Rate of change of frequency protection (4 stages) DfpPFRC 81
High speed breaker fail suitable for re-tripping and back-
RBRF 50BF
tripping (2 stages)
Current Transformer supervision 46
Voltage transformer supervision 47/27
Auto-reclose (4 shots) RREC 79
Check synchronisation (2 stages) RSYN 25

4.4 CONTROL FUNCTIONS

Feature IEC 61850 ANSI

Watchdog contacts
Read-only mode
Function keys FnkGGIO
Programmable LEDs LedGGIO
Programmable hotkeys
Programmable allocation of digital inputs and outputs
Fully customizable menu texts
Circuit breaker control, status & condition monitoring XCBR 52
CT supervision
VT supervision
Trip circuit and coil supervision
Control inputs PloGGIO1
Power-up diagnostics and continuous self-monitoring
Dual rated 1A and 5A CT inputs
Alternative setting groups (4)
Graphical programmable scheme logic (PSL)

P54x1i-TM-EN-1 9
Chapter 1 - Introduction P543i/P545i

Feature IEC 61850 ANSI

Fault locator RFLO

4.5 MEASUREMENT FUNCTIONS

Measurement Function IEC 61850 ANSI

Measurement of all instantaneous & integrated values
MET
(Exact range of measurements depend on the device model)
Disturbance recorder for waveform capture – specified in samples per cycle RDRE DFR
Fault Records
Maintenance Records
Event Records / Event logging Event records
Time Stamping of Opto-inputs Yes Yes

4.6 COMMUNICATION FUNCTIONS

Feature ANSI
NERC compliant cyber-security
Front RS232 serial communication port for configuration 16S
Rear serial RS485 communication port for SCADA control 16S
2 Additional rear serial communication ports for SCADA control and
16S
teleprotection (fibre and copper) (optional)
Ethernet communication (optional) 16E
Redundant Ethernet communication (optional) 16E
Courier Protocol 16S
IEC 61850 edition 1 or edition 2 (optional) 16E
IEC 60870-5-103 (optional) 16S
DNP3.0 over serial link (optional) 16S
DNP3.0 over Ethernet (optional) 16E
SNMP 16E
IRIG-B time synchronisation (optional) CLK
IEEE 1588 PTP (Edition 2 devices only)

10 P54x1i-TM-EN-1
P543i/P545i Chapter 1 - Introduction

5 LOGIC DIAGRAMS
This technical manual contains many logic diagrams, which should help to explain the functionality of the device.
Although this manual has been designed to be as specific as possible to the chosen product, it may contain
diagrams, which have elements applicable to other products. If this is the case, a qualifying note will accompany
the relevant part.
The logic diagrams follow a convention for the elements used, using defined colours and shapes. A key to this
convention is provided below. We recommend viewing the logic diagrams in colour rather than in black and white.
The electronic version of the technical manual is in colour, but the printed version may not be. If you need coloured
diagrams, they can be provided on request by calling the contact centre and quoting the diagram number.

P54x1i-TM-EN-1 11
Chapter 1 - Introduction P543i/P545i

Key:
Energising Quantity AND gate &

Internal Signal OR gate 1

DDB Signal XOR gate XOR

Internal function NOT gate

Setting cell Logic 0 0

Setting value Timer

Hardcoded setting
Pulse / Latch

Measurement Cell S
SR Latch Q
R
Internal Calculation
S
SR Latch Q
Derived setting Reset Dominant RD

HMI key Latched on positive edge

Connection / Node Inverted logic input

1
Switch Soft switch 2

Switch Multiplier X

Bandpass filter
Comparator for detecting
undervalues

Comparator for detecting

V00063 overvalues

Figure 2: Key to logic diagrams

12 P54x1i-TM-EN-1
P543i/P545i Chapter 1 - Introduction

6 FUNCTIONAL OVERVIEW
This diagram is applicable to P543 and P545models.

BUS 1
IEC 2nd Remote Remote Local Fault records Disturbance
61850 comm. port comm. port Communication Record
Measurements
Self monitoring

X 50/27 50/51 50N/ 67N

87N 87P 21 67 78 67N I/ V TEFD* 64 67/46 68 49
51N SEF
V ref

V ref

LINE
I E sen

IM

Remote 50BF 46BC FL CTS VTS 27/59 59N 85 79 25 PSL LEDs

Neutral current
from parallel line
(if present)

conventional 1 stOptic 2ndOptic protection

signalling port port communication Always Optional P543
available P545
* 50Hz only

E00070

Figure 3: Functional Overview

P54x1i-TM-EN-1 13
Chapter 1 - Introduction P543i/P545i

14 P54x1i-TM-EN-1
 CHAPTER 2

SAFETY INFORMATION
Chapter 2 - Safety Information P543i/P545i

16 P54x1i-TM-EN-1
P543i/P545i Chapter 2 - Safety Information

1 CHAPTER OVERVIEW
This chapter provides information about the safe handling of the equipment. The equipment must be properly
installed and handled in order to maintain it in a safe condition and to keep personnel safe at all times. You must
be familiar with information contained in this chapter before unpacking, installing, commissioning, or servicing the
equipment.

This chapter contains the following sections:

Chapter Overview 17
Health and Safety 18
Symbols 19
Installation, Commissioning and Servicing 20
Decommissioning and Disposal 25
Regulatory Compliance 26

P54x1i-TM-EN-1 17
Chapter 2 - Safety Information P543i/P545i

2 HEALTH AND SAFETY

Personnel associated with the equipment must be familiar with the contents of this Safety Information.
When electrical equipment is in operation, dangerous voltages are present in certain parts of the equipment.
Improper use of the equipment and failure to observe warning notices will endanger personnel.
Only qualified personnel may work on or operate the equipment. Qualified personnel are individuals who are:
● familiar with the installation, commissioning, and operation of the equipment and the system to which it is
being connected.
● familiar with accepted safety engineering practises and are authorised to energise and de-energise
equipment in the correct manner.
● trained in the care and use of safety apparatus in accordance with safety engineering practises
● trained in emergency procedures (first aid).

The documentation provides instructions for installing, commissioning and operating the equipment. It cannot,
however cover all conceivable circumstances. In the event of questions or problems, do not take any action
without proper authorisation. Please contact your local sales office and request the necessary information.

18 P54x1i-TM-EN-1
P543i/P545i Chapter 2 - Safety Information

3 SYMBOLS
Throughout this manual you will come across the following symbols. You will also see these symbols on parts of
the equipment.

Caution:
Refer to equipment documentation. Failure to do so could result in damage to the
equipment

Warning:
Risk of electric shock

Earth terminal. Note: This symbol may also be used for a protective conductor (earth) terminal if that terminal
is part of a terminal block or sub-assembly.

Protective conductor (earth) terminal

Instructions on disposal requirements

Note:
The term 'Earth' used in this manual is the direct equivalent of the North American term 'Ground'.

P54x1i-TM-EN-1 19
Chapter 2 - Safety Information P543i/P545i

4 INSTALLATION, COMMISSIONING AND SERVICING

4.1 LIFTING HAZARDS

Many injuries are caused by:
● Lifting heavy objects
● Lifting things incorrectly
● Pushing or pulling heavy objects
● Using the same muscles repetitively

Plan carefully, identify any possible hazards and determine how best to move the product. Look at other ways of
moving the load to avoid manual handling. Use the correct lifting techniques and Personal Protective Equipment
(PPE) to reduce the risk of injury.

4.2 ELECTRICAL HAZARDS

Caution:
All personnel involved in installing, commissioning, or servicing this equipment must be
familiar with the correct working procedures.

Caution:
Consult the equipment documentation before installing, commissioning, or servicing
the equipment.

Caution:
Always use the equipment as specified. Failure to do so will jeopardise the protection
provided by the equipment.

Warning:
Removal of equipment panels or covers may expose hazardous live parts. Do not touch
until the electrical power is removed. Take care when there is unlocked access to the
rear of the equipment.

Warning:
Isolate the equipment before working on the terminal strips.

Warning:
Use a suitable protective barrier for areas with restricted space, where there is a risk of
electric shock due to exposed terminals.

Caution:
Disconnect power before disassembling. Disassembly of the equipment may expose
sensitive electronic circuitry. Take suitable precautions against electrostatic voltage
discharge (ESD) to avoid damage to the equipment.

20 P54x1i-TM-EN-1
P543i/P545i Chapter 2 - Safety Information

Caution:
NEVER look into optical fibres or optical output connections. Always use optical power
meters to determine operation or signal level.

Warning:
Testing may leave capacitors charged to dangerous voltage levels. Discharge
capacitors by rediucing test voltages to zero before disconnecting test leads.

Caution:
Operate the equipment within the specified electrical and environmental limits.

Caution:
Before cleaning the equipment, ensure that no connections are energised. Use a lint
free cloth dampened with clean water.

Note:
Contact fingers of test plugs are normally protected by petroleum jelly, which should not be removed.

4.3 UL/CSA/CUL REQUIREMENTS

The information in this section is applicable only to equipment carrying UL/CSA/CUL markings.

Caution:
Equipment intended for rack or panel mounting is for use on a flat surface of a Type 1
enclosure, as defined by Underwriters Laboratories (UL).

Caution:
To maintain compliance with UL and CSA/CUL, install the equipment using UL/CSA-
recognised parts for: cables, protective fuses, fuse holders and circuit breakers,
insulation crimp terminals, and replacement internal batteries.

4.4 FUSING REQUIREMENTS

Caution:
Where UL/CSA listing of the equipment is required for external fuse protection, a UL or
CSA Listed fuse must be used for the auxiliary supply. The listed protective fuse type is:
Class J time delay fuse, with a maximum current rating of 15 A and a minimum DC
rating of 250 V dc (for example type AJT15).

Caution:
Where UL/CSA listing of the equipment is not required, a high rupture capacity (HRC)
fuse type with a maximum current rating of 16 Amps and a minimum dc rating of 250 V
dc may be used for the auxiliary supply (for example Red Spot type NIT or TIA).
For P50 models, use a 1A maximum T-type fuse.
For P60 models, use a 4A maximum T-type fuse.

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Chapter 2 - Safety Information P543i/P545i

Caution:
Digital input circuits should be protected by a high rupture capacity NIT or TIA fuse with
maximum rating of 16 A. for safety reasons, current transformer circuits must never be
fused. Other circuits should be appropriately fused to protect the wire used.

Caution:
CTs must NOT be fused since open circuiting them may produce lethal hazardous
voltages

4.5 EQUIPMENT CONNECTIONS

Warning:
Terminals exposed during installation, commissioning and maintenance may present a
hazardous voltage unless the equipment is electrically isolated.

Caution:
Tighten M4 clamping screws of heavy duty terminal block connectors to a nominal
torque of 1.3 Nm.
Tighten captive screws of terminal blocks to 0.5 Nm minimum and 0.6 Nm maximum.

Caution:
Always use insulated crimp terminations for voltage and current connections.

Caution:
Always use the correct crimp terminal and tool according to the wire size.

Caution:
Watchdog (self-monitoring) contacts are provided to indicate the health of the device
on some products. We strongly recommend that you hard wire these contacts into the
substation's automation system, for alarm purposes.

4.6 PROTECTION CLASS 1 EQUIPMENT REQUIREMENTS

Caution:
Earth the equipment with the supplied PCT (Protective Conductor Terminal).

Caution:
Do not remove the PCT.

Caution:
The PCT is sometimes used to terminate cable screens. Always check the PCT’s integrity
after adding or removing such earth connections.

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P543i/P545i Chapter 2 - Safety Information

Caution:
Use a locknut or similar mechanism to ensure the integrity of stud-connected PCTs.

Caution:
The recommended minimum PCT wire size is 2.5 mm² for countries whose mains supply
is 230 V (e.g. Europe) and 3.3 mm² for countries whose mains supply is 110 V (e.g. North
America). This may be superseded by local or country wiring regulations.
For P60 products, the recommended minimum PCT wire size is 6 mm². See product
documentation for details.

Caution:
The PCT connection must have low-inductance and be as short as possible.

Caution:
All connections to the equipment must have a defined potential. Connections that are
pre-wired, but not used, should be earthed, or connected to a common grouped
potential.

4.7 PRE-ENERGISATION CHECKLIST

Caution:
Check voltage rating/polarity (rating label/equipment documentation).

Caution:
Check CT circuit rating (rating label) and integrity of connections.

Caution:
Check protective fuse or miniature circuit breaker (MCB) rating.

Caution:
Check integrity of the PCT connection.

Caution:
Check voltage and current rating of external wiring, ensuring it is appropriate for the
application.

4.8 PERIPHERAL CIRCUITRY

Warning:
Do not open the secondary circuit of a live CT since the high voltage produced may be
lethal to personnel and could damage insulation. Short the secondary of the line CT
before opening any connections to it.

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Chapter 2 - Safety Information P543i/P545i

Note:
For most Alstom equipment with ring-terminal connections, the threaded terminal block for current transformer termination
is automatically shorted if the module is removed. Therefore external shorting of the CTs may not be required. Check the
equipment documentation and wiring diagrams first to see if this applies.

Caution:
Where external components such as resistors or voltage dependent resistors (VDRs) are
used, these may present a risk of electric shock or burns if touched.

Warning:
Take extreme care when using external test blocks and test plugs such as the MMLG,
MMLB and P990, as hazardous voltages may be exposed. Ensure that CT shorting links
are in place before removing test plugs, to avoid potentially lethal voltages.

4.9 UPGRADING/SERVICING

Warning:
Do not insert or withdraw modules, PCBs or expansion boards from the equipment
while energised, as this may result in damage to the equipment. Hazardous live
voltages would also be exposed, endangering personnel.

Caution:
Internal modules and assemblies can be heavy and may have sharp edges. Take care
when inserting or removing modules into or out of the IED.

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5 DECOMMISSIONING AND DISPOSAL

Caution:
Before decommissioning, completely isolate the equipment power supplies (both poles
of any dc supply). The auxiliary supply input may have capacitors in parallel, which may
still be charged. To avoid electric shock, discharge the capacitors using the external
terminals before decommissioning.

Caution:
Avoid incineration or disposal to water courses. Dispose of the equipment in a safe,
responsible and environmentally friendly manner, and if applicable, in accordance with
country-specific regulations.

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6 REGULATORY COMPLIANCE
Compliance with the European Commission Directive on EMC and LVD is demonstrated using a technical file.

6.1 EMC COMPLIANCE: 2014/30/EU

The product specific Declaration of Conformity (DoC) lists the relevant harmonised standard(s) or conformit
assessment used to demonstrate compliance with the EMC directive.

6.2 LVD COMPLIANCE: 2014/35/EU

The product specific Declaration of Conformity (DoC) lists the relevant harmonized standard(s) or conformity
assessment used to demonstrate compliance with the LVD directive.
Safety related information, such as the installation I overvoltage category, pollution degree and operating
temperature ranges are specified in the Technical Data section of the relevant product documentation and/or on
the product labelling .
Unless otherwise stated in the Technical Data section of the relevant product documentation, the equipment is
intended for indoor use only. Where the equipment is required for use in an outdoor location, it must be mounted
in a specific cabinet or housing to provide the equipment with the appropriate level of protection from the
expected outdoor environment.

6.3 R&TTE COMPLIANCE: 2014/53/EU

Radio and Telecommunications Terminal Equipment (R&TTE) directive 2014/53/EU.
Conformity is demonstrated by compliance to both the EMC directive and the Low Voltage directive, to zero volts.

6.4 UL/CUL COMPLIANCE

If marked with this logo, the product is compliant with the requirements of the Canadian and USA Underwriters
Laboratories.
The relevant UL file number and ID is shown on the equipment.

6.5 ATEX COMPLIANCE: 2014/34/EU

Products marked with the 'explosion protection' Ex symbol (shown in the example, below) are compliant with the
ATEX directive. The product specific Declaration of Conformity (DoC) lists the Notified Body, Type Examination
Certificate, and relevant harmonized standard or conformity assessment used to demonstrate compliance with
the ATEX directive.
The ATEX Equipment Protection level, Equipment group, and Zone definition will be marked on the
product.
For example:

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Where:

'II' Equipment Group: Industrial.

'(2)G' High protection equipment category, for control of equipment in gas atmospheres in Zone 1 and 2.
This equipment (with parentheses marking around the zone number) is not itself suitable for operation
within a potentially explosive atmosphere.

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28 P54x1i-TM-EN-1
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HARDWARE DESIGN
Chapter 3 - Hardware Design P543i/P545i

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1 CHAPTER OVERVIEW
This chapter provides information about the product's hardware design.
This chapter contains the following sections:
Chapter Overview 31
Hardware Architecture 32
Mechanical Implementation 34
Front Panel 37
Rear Panel 41
Boards and Modules 43

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2 HARDWARE ARCHITECTURE
The main components comprising devices based on the Px4x platform are as follows:
● The housing, consisting of a front panel and connections at the rear
● The Main processor module consisting of the main CPU (Central Processing Unit), memory and an interface
to the front panel HMI (Human Machine Interface)
● A selection of plug-in boards and modules with presentation at the rear for the power supply,
communication functions, digital I/O, analogue inputs, and time synchronisation connectivity
All boards and modules are connected by a parallel data and address bus, which allows the processor module to
send and receive information to and from the other modules as required. There is also a separate serial data bus
for conveying sampled data from the input module to the CPU. These parallel and serial databuses are shown as a
single interconnection module in the following figure, which shows typical modules and the flow of data between
them.

Keypad
Output relay boards Output relay contacts
Processor module
Front panel HMI

LCD
Opto-input boards Digital inputs
LEDs
I/O
Front port
CTs Power system currents
Memory
Interconnection

Flash memory for settings VTs Power system voltages

Analogue Inputs
Battery-backed SRAM
for records

RS485 modules RS485 communication

Watchdog
contacts Watchdog module
IRIG-B module Time synchronisation
+ LED

Ethernet modules Ethernet communication

Auxiliary
PSU module
Supply Communications

Note: Not all modules are applicable to all products

V00233

Figure 4: Hardware architecture

2.1 COPROCESSOR HARDWARE ARCHITECTURE

Some products are equipped with a coprocessor board for extra computing power. There are several variants of
coprocessor board, depending on the required communication requirements. Some models do not need any
external communication inputs, some models need inputs for current differential functionality and some models
need an input for GPS time synchronisation.

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FPGA
Comms between main and
coprocessor board

Interconnection
CPU SRAM

Optional Ch1 for current differential input

comms GPS
interface Ch2 for current differential input
Optional coprocessor board

V00249

Figure 5: Coprocessor hardware architecture

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3 MECHANICAL IMPLEMENTATION
All products based on the Px4x platform have common hardware architecture. The hardware is modular and
consists of the following main parts:
● Case and terminal blocks
● Boards and modules
● Front panel
The case comprises the housing metalwork and terminal blocks at the rear. The boards fasten into the terminal
blocks and are connected together by a ribbon cable. This ribbon cable connects to the processor in the front
panel.
The following diagram shows an exploded view of a typical product. The diagram shown does not necessarily
represent exactly the product model described in this manual.

Figure 6: Exploded view of IED

3.1 HOUSING VARIANTS

The Px4x range of products are implemented in a range of case sizes. Case dimensions for industrial products
usually follow modular measurement units based on rack sizes. These are: U for height and TE for width, where:
● 1U = 1.75 inches = 44.45 mm
● 1TE = 0.2 inches = 5.08 mm

The products are available in panel-mount or standalone versions. All products are nominally 4U high. This equates
to 177.8 mm or 7 inches.
The cases are pre-finished steel with a conductive covering of aluminium and zinc. This provides good grounding
at all joints, providing a low resistance path to earth that is essential for performance in the presence of external
noise.
The case width depends on the product type and its hardware options. There are three different case widths for
the described range of products: 40TE, 60TE and 80TE. The case dimensions and compatibility criteria are as
follows:

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Case width (TE) Case width (mm) Case width (inches)

40TE 203.2 8
60TE 304.8 12
80TE 406.4 16

Note:
Not all case sizes are available for all models.

3.2 LIST OF BOARDS

The product's hardware consists of several modules drawn from a standard range. The exact specification and
number of hardware modules depends on the model number and variant. Depending on the exact model, the
product in question will use a selection of the following boards.
Board Use
Main Processor board - 40TE or smaller Main Processor board – without support for function keys
Main Processor board - 60TE or larger Main Processor board – with support for function keys
Power supply board - 24/54V DC Power supply input. Accepts DC voltage between 24V and 54V
Power supply board - 48/125V DC Power supply input. Accepts DC voltage between 48V and 125V
Power supply board - 110/250V DC Power supply input. Accepts DC voltage between 110V and 125V
Transformer board Contains the voltage and current transformers
Input board Contains the A/D conversion circuitry
Input board with opto-inputs Contains the A/D conversion circuitry + 8 digital opto-inputs
IRIG-B board - modulated input Interface board for modulated IRIG-B timing signal
IRIG-B board - demodulated input Interface board for demodulated IRIG-B timing signal
Fibre board Interface board for fibre-based RS485 connection
Fibre board + IRIG-B Interface board for fibre-based RS485 connection + demodulated IRIG-B
2nd rear communications board Interface board for RS232 / RS485 connections
2nd rear communications board with IRIG-B input Interface board for RS232 / RS485 + IRIG-B connections
100MhZ Ethernet board Standard 100MHz Ethernet board for LAN connection (fibre + copper)
100MhZ Ethernet board with modulated IRIG-B Standard 100MHz Ethernet board (fibre / copper) + modulated IRIG-B
100MhZ Ethernet board with demodulated IRIG-B Standard 100MHz Ethernet board (fibre / copper)+ demodulated IRIG-B
High-break output relay board Output relay board with high breaking capacity relays
Redundant Ethernet SHP+ modulated IRIG-B Redundant SHP Ethernet board (2 fibre ports) + modulated IRIG-B input
Redundant Ethernet SHP + demodulated IRIG-B Redundant SHP Ethernet board (2 fibre ports) + demodulated IRIG-B input
Redundant Ethernet RSTP + modulated IRIG-B Redundant RSTP Ethernet board (2 fibre ports) + modulated IRIG-B input
Redundant Ethernet RSTP+ demodulated IRIG-B Redundant RSTP Ethernet board (2 fibre ports) + demodulated IRIG-B input
Redundant Ethernet DHP+ modulated IRIG-B Redundant DHP Ethernet board (2 fibre ports) + modulated IRIG-B input
Redundant Ethernet DHP+ demodulated IRIG-B Redundant DHP Ethernet board (2 fibre ports) + demodulated IRIG-B input
Redundant Ethernet PRP+ modulated IRIG-B Redundant PRP Ethernet board (2 fibre ports) + modulated IRIG-B input
Redundant Ethernet PRP+ demodulated IRIG-B Redundant PRP Ethernet board (2 fibre ports) + demodulated IRIG-B input
Redundant Ethernet HSR + modulated IRIG-B Redundant HSR Ethernet board (2 fibre ports) + demodulated IRIG-B input
Redundant Ethernet HSR+ demodulated IRIG-B Redundant HSR Ethernet board (2 fibre ports) + demodulated IRIG-B input
Output relay output board Standard output relay board
Coprocessor board with dual fibre inputs Coprocessor board with fibre connections for current differential inputs

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Coprocessor board with fibre connections for current differential inputs + GPS
Coprocessor board with dual fibre inputs + GPS
input.

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4 FRONT PANEL

4.1 FRONT PANEL

Depending on the exact model and chosen options, the product will be housed in either a 40TE, 60TE or 80TE case.
By way of example, the following diagram shows the front panel of a typical 60TE unit. The front panels of the
products based on 40TE and 80TE cases have a lot of commonality and differ only in the number of hotkeys and
user-programmable LEDs. The hinged covers at the top and bottom of the front panel are shown open. An optional
transparent front cover physically protects the front panel.

Figure 7: Front panel (60TE)

The front panel consists of:

● Top and bottom compartments with hinged cover
● LCD display
● Keypad
● 9 pin D-type serial port
● 25 pin D-type parallel port
● Fixed function LEDs
● Function keys and LEDs (60TE and 80TE models)
● Programmable LEDs (60TE and 80TE models)

4.1.1 FRONT PANEL COMPARTMENTS

The top compartment contains labels for the:
● Serial number
● Current and voltage ratings.

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The bottom compartment contains:

● A compartment for a 1/2 AA size backup battery (used to back up the real time clock and event, fault, and
disturbance records).
● A 9-pin female D-type front port for an EIA(RS)232 serial connection to a PC.
● A 25-pin female D-type parallel port for monitoring internal signals and downloading software and
language text.

4.1.2 KEYPAD
The keypad consists of the following keys:

4 arrow keys to navigate the menus (organised around the Enter key)

An enter key for executing the chosen option

A clear key for clearing the last command

A read key for viewing larger blocks of text (arrow keys now used for
scrolling)

2 hot keys for scrolling through the default display and for control of
setting groups. These are situated directly below the LCD display.

4.1.2.1 LIQUID CRYSTAL DISPLAY

The LCD is a high resolution monochrome display with 16 characters by 3 lines and controllable back light.

4.1.3 FRONT SERIAL PORT (SK1)

The front serial port is a 9-pin female D-type connector, providing RS232 serial data communication. It is situated
under the bottom hinged cover, and is used to communicate with a locally connected PC. It is used to transfer
settings data between the PC and the IED.
The port is intended for temporary connection during testing, installation and commissioning. It is not intended to
be used for permanent SCADA communications. This port supports the Courier communication protocol only.
Courier is a proprietary communication protocol to allow communication with a range of protection equipment,
and between the device and the Windows-based support software package.
This port can be considered as a DCE (Data Communication Equipment) port, so you can connect this port device
to a PC with an EIA(RS)232 serial cable up to 15 m in length.
The inactivity timer for the front port is set to 15 minutes. This controls how long the unit maintains its level of
password access on the front port. If no messages are received on the front port for 15 minutes, any password
access level that has been enabled is cancelled.

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Note:
The front serial port does not support automatic extraction of event and disturbance records, although this data can be
accessed manually.

4.1.3.1 FRONT SERIAL PORT (SK1) CONNECTIONS

The port pin-out follows the standard for Data Communication Equipment (DCE) device with the following pin
connections on a 9-pin connector.
Pin number Description
2 Tx Transmit data
3 Rx Receive data
5 0 V Zero volts common

You must use the correct serial cable, or the communication will not work. A straight-through serial cable is
required, connecting pin 2 to pin 2, pin 3 to pin 3, and pin 5 to pin 5.
Once the physical connection from the unit to the PC is made, the PC’s communication settings must be set to
match those of the IED. The following table shows the unit’s communication settings for the front port.
Protocol Courier
Baud rate 19,200 bps
Courier address 1
Message format 11 bit - 1 start bit, 8 data bits, 1 parity bit (even parity), 1 stop bit

4.1.4 FRONT PARALLEL PORT (SK2)

The front parallel port uses a 25 pin D-type connector. It is used for commissioning, downloading firmware updates
and menu text editing.

4.1.5 FIXED FUNCTION LEDS

Four fixed-function LEDs on the left-hand side of the front panel indicate the following conditions.
● Trip (Red) switches ON when the IED issues a trip signal. It is reset when the associated fault record is
cleared from the front display. Also the trip LED can be configured as self-resetting.
● Alarm (Yellow) flashes when the IED registers an alarm. This may be triggered by a fault, event or
maintenance record. The LED flashes until the alarms have been accepted (read), then changes to
constantly ON. When the alarms are cleared, the LED switches OFF.
● Out of service (Yellow) is ON when the IED's functions are unavailable.
● Healthy (Green) is ON when the IED is in correct working order, and should be ON at all times. It goes OFF if
the unit’s self-tests show there is an error in the hardware or software. The state of the healthy LED is
reflected by the watchdog contacts at the back of the unit.

4.1.6 FUNCTION KEYS

The programmable function keys are available for custom use for some models.
Factory default settings associate specific functions to these keys, but by using programmable scheme logic, you
can change the default functions of these keys to fit specific needs. Adjacent to these function keys are
programmable LEDs, which are usually set to be associated with their respective function keys.

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4.1.7 PROGRAMABLE LEDS

The device has a number of programmable LEDs, which can be associated with PSL-generated signals. The
programmable LEDs for most models are tri-colour and can be set to RED, YELLOW or GREEN. However the
programmable LEDs for some models are single-colour (red) only. The single-colour LEDs can be recognised by
virtue of the fact they are large and slightly oval, whereas the tri-colour LEDs are small and round.

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5 REAR PANEL
The MiCOM Px40 series uses a modular construction. Most of the internal workings are on boards and modules
which fit into slots. Some of the boards plug into terminal blocks, which are bolted onto the rear of the unit.
However, some boards such as the communications boards have their own connectors. The rear panel consists of
these terminal blocks plus the rears of the communications boards.
The back panel cut-outs and slot allocations vary. This depends on the product, the type of boards and the
terminal blocks needed to populate the case. The following diagram shows a typical rear view of a case populated
with various boards.

Figure 8: Rear view of populated case

Note:
This diagram is just an example and may not show the exact product described in this manual. It also does not show the full
range of available boards, just a typical arrangement.

Not all slots are the same size. The slot width depends on the type of board or terminal block. For example, HD
(heavy duty) terminal blocks, as required for the analogue inputs, require a wider slot size than MD (medium duty)
terminal blocks. The board positions are not generally interchangeable. Each slot is designed to house a particular
type of board. Again this is model-dependent.
The device may use one or more of the terminal block types shown in the following diagram. The terminal blocks
are fastened to the rear panel with screws.
● Heavy duty (HD) terminal blocks for CT and VT circuits
● Medium duty (MD) terminal blocks for the power supply, opto-inputs, relay outputs and rear
communications port
● MiDOS terminal blocks for CT and VT circuits
● RTD/CLIO terminal block for connection to analogue transducers

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,
Figure 9: Terminal block types

Note:
Not all products use all types of terminal blocks. The product described in this manual may use one or more of the above
types.

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6 BOARDS AND MODULES

Each product comprises a selection of PCBs (Printed Circuit Boards) and subassemblies, depending on the chosen
configuration.

6.1 PCBS
A PCB typically consists of the components, a front connector for connecting into the main system parallel bus via
a ribbon cable, and an interface to the rear. This rear interface may be:
● Directly presented to the outside world (as is the case for communication boards such as Ethernet Boards)
● Presented to a connector, which in turn connects into a terminal block bolted onto the rear of the case (as is
the case for most of the other board types)

Figure 10: Rear connection to terminal block

6.2 SUBASSEMBLIES
A sub-assembly consists of two or more boards bolted together with spacers and connected with electrical
connectors. It may also have other special requirements such as being encased in a metal housing for shielding
against electromagnetic radiation.
Boards are designated by a part number beginning with ZN, whereas pre-assembled sub-assemblies are
designated with a part number beginning with GN. Sub-assemblies, which are put together at the production
stage, do not have a separate part number.

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The products in the Px40 series typically contain two sub-assemblies:

● The power supply assembly comprising:
○ A power supply board
○ An output relay board
● The input module comprising:
○ One or more transformer boards, which contains the voltage and current transformers (partially or
fully populated)
○ One or more input boards
○ Metal protective covers for EM (electromagnetic) shielding
The input module is pre-assembled and is therefore assigned a GN number, whereas the power supply module is
assembled at production stage and does not therefore have an individual part number.

6.3 MAIN PROCESSOR BOARD

Figure 11: Main processor board

The main processor board performs all calculations and controls the operation of all other modules in the IED,
including the data communication and user interfaces. This is the only board that does not fit into one of the slots.
It resides in the front panel and connects to the rest of the system using an internal ribbon cable.
The LCD and LEDs are mounted on the processor board along with the front panel communication ports.
The memory on the main processor board is split into two categories: volatile and non-volatile. The volatile
memory is fast access SRAM, used by the processor to run the software and store data during calculations. The
non-volatile memory is sub-divided into two groups:
● Flash memory to store software code, text and configuration data including the present setting values.
● Battery-backed SRAM to store disturbance, event, fault and maintenance record data.

There are two board types available depending on the size of the case:
● For models in 40TE cases
● For models in 60TE cases and larger

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6.4 POWER SUPPLY BOARD

Figure 12: Power supply board

The power supply board provides power to the unit. One of three different configurations of the power supply
board can be fitted to the unit. This is specified at the time of order and depends on the magnitude of the supply
voltage that will be connected to it.
There are three board types, which support the following voltage ranges:
● 24/54 V DC
● 48/125 V DC or 40-100V AC
● 110/250 V DC or 100-240V AC
The power supply board connector plugs into a medium duty terminal block. This terminal block is always
positioned on the right hand side of the unit looking from the rear.
The power supply board is usually assembled together with a relay output board to form a complete subassembly,
as shown in the following diagram.

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Figure 13: Power supply assembly

The power supply outputs are used to provide isolated power supply rails to the various modules within the unit.
Three voltage levels are used by the unit’s modules:
● 5.1 V for all of the digital circuits
● +/- 16 V for the analogue electronics such as on the input board
● 22 V for driving the output relay coils.
All power supply voltages, including the 0 V earth line, are distributed around the unit by the 64-way ribbon cable.
The power supply board incorporates inrush current limiting. This limits the peak inrush current to approximately
10 A.
Power is applied to pins 1 and 2 of the terminal block, where pin 1 is negative and pin 2 is positive. The pin
numbers are clearly marked on the terminal block as shown in the following diagram.

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Figure 14: Power supply terminals

6.4.1 WATCHDOG
The Watchdog contacts are also hosted on the power supply board. The Watchdog facility provides two output
relay contacts, one normally open and one normally closed. These are used to indicate the health of the device
and are driven by the main processor board, which continually monitors the hardware and software when the
device is in service.

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Figure 15: Watchdog contact terminals

6.4.2 REAR SERIAL PORT

The rear serial port (RP1) is housed on the power supply board. This is a three-terminal EIA(RS)485 serial
communications port and is intended for use with a permanently wired connection to a remote control centre for
SCADA communication. The interface supports half-duplex communication and provides optical isolation for the
serial data being transmitted and received.
The physical connectivity is achieved using three screw terminals; two for the signal connection, and the third for
the earth shield of the cable. These are located on pins 16, 17 and 18 of the power supply terminal block, which is
on the far right looking from the rear. The interface can be selected between RS485 and K-bus. When the K-Bus
option is selected, the two signal connections are not polarity conscious.
The polarity independent K-bus can only be used for the Courier data protocol. The polarity conscious MODBUS,
IEC 60870-5-103 and DNP3.0 protocols need RS485.
The following diagram shows the rear serial port. The pin assignments are as follows:
● Pin 16: Earth shield
● Pin 17: Negative signal
● Pin 18: Positive signal

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Figure 16: Rear serial port terminals

An additional serial port with D-type presentation is available as an optional board, if required.

6.5 INPUT MODULE - 1 TRANSFORMER BOARD

Figure 17: Input module - 1 transformer board

The input module consists of the main input board coupled together with an instrument transformer board. The
instrument transformer board contains the voltage and current transformers, which isolate and scale the
analogue input signals delivered by the system transformers. The input board contains the A/D conversion and
digital processing circuitry, as well as eight digital isolated inputs (opto-inputs).
The boards are connected together physically and electrically. The module is encased in a metal housing for
shielding against electromagnetic interference.

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6.5.1 INPUT MODULE CIRCUIT DESCRIPTION

Optical 8 digital inputs Optical

Isolator Isolator

Noise Noise
filter filter

Parallel Bus

Buffer

Transformer
board

VT
or
CT

Serial Serial Link

A/D Converter
interface

VT
or
CT

V00239

Figure 18: Input module schematic

A/D Conversion
The differential analogue inputs from the CT and VT transformers are presented to the main input board as shown.
Each differential input is first converted to a single input quantity referenced to the input board’s earth potential.
The analogue inputs are sampled and converted to digital, then filtered to remove unwanted properties. The
samples are then passed through a serial interface module which outputs data on the serial sample data bus.
The calibration coefficients are stored in non-volatile memory. These are used by the processor board to correct
for any amplitude or phase errors introduced by the transformers and analogue circuitry.

Opto-isolated inputs
The other function of the input board is to read in the state of the digital inputs. As with the analogue inputs, the
digital inputs must be electrically isolated from the power system. This is achieved by means of the 8 on-board
optical isolators for connection of up to 8 digital signals. The digital signals are passed through an optional noise
filter before being buffered and presented to the unit’s processing boards in the form of a parallel data bus.
This selectable filtering allows the use of a pre-set filter of ½ cycle which renders the input immune to induced
power-system noise on the wiring. Although this method is secure it can be slow, particularly for inter-tripping. This
can be improved by switching off the ½ cycle filter, in which case one of the following methods to reduce ac noise
should be considered.
● Use double pole switching on the input
● Use screened twisted cable on the input circuit

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The opto-isolated logic inputs can be configured for the nominal battery voltage of the circuit for which they are a
part, allowing different voltages for different circuits such as signalling and tripping.

Note:
The opto-input circuitry can be provided without the A/D circuitry as a separate board, which can provide supplementary
opto-inputs.

6.5.2 TRANSFORMER BOARD

Figure 19: Transformer board

The transformer board hosts the current and voltage transformers. These are used to step down the currents and
voltages originating from the power systems' current and voltage transformers to levels that can be used by the
devices' electronic circuitry. In addition to this, the on-board CT and VT transformers provide electrical isolation
between the unit and the power system.
The transformer board is connected physically and electrically to the input board to form a complete input module.
For terminal connections, please refer to the wiring diagrams.

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6.5.3 INPUT BOARD

Figure 20: Input board

The input board is used to convert the analogue signals delivered by the current and voltage transformers into
digital quantities used by the IED. This input board also has on-board opto-input circuitry, providing eight optically-
isolated digital inputs and associated noise filtering and buffering. These opto-inputs are presented to the user by
means of a MD terminal block, which sits adjacent to the analogue inputs HD terminal block.
The input board is connected physically and electrically to the transformer board to form a complete input module.
The terminal numbers of the opto-inputs are as follows:
Terminal Number Opto-input
Terminal 1 Opto 1 -ve
Terminal 2 Opto 1 +ve
Terminal 3 Opto 2 -ve
Terminal 4 Opto 2 +ve
Terminal 5 Opto 3 -ve
Terminal 6 Opto 3 +ve
Terminal 7 Opto 4 -ve
Terminal 8 Opto 4 +ve
Terminal 9 Opto 5 -ve
Terminal 10 Opto 5 +ve
Terminal 11 Opto 6 -ve
Terminal 12 Opto 6 +ve
Terminal 13 Opto 7 –ve
Terminal 14 Opto 7 +ve
Terminal 15 Opto 8 –ve
Terminal 16 Opto 8 +ve

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Terminal Number Opto-input

Terminal 17 Common
Terminal 18 Common

6.6 STANDARD OUTPUT RELAY BOARD

Figure 21: Standard output relay board - 8 contacts

This output relay board has 8 relays with 6 Normally Open contacts and 2 Changeover contacts.
The output relay board is provided together with the power supply board as a complete assembly, or
independently for the purposes of relay output expansion.
There are two cut-out locations in the board. These can be removed to allow power supply components to
protrude when coupling the output relay board to the power supply board. If the output relay board is to be used
independently, these cut-out locations remain intact.
The terminal numbers are as follows:
Terminal Number Output Relay
Terminal 1 Relay 1 NO
Terminal 2 Relay 1 NO
Terminal 3 Relay 2 NO
Terminal 4 Relay 2 NO
Terminal 5 Relay 3 NO
Terminal 6 Relay 3 NO
Terminal 7 Relay 4 NO
Terminal 8 Relay 4 NO
Terminal 9 Relay 5 NO
Terminal 10 Relay 5 NO

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Terminal Number Output Relay

Terminal 11 Relay 6 NO
Terminal 12 Relay 6 NO
Terminal 13 Relay 7 changeover
Terminal 14 Relay 7 changeover
Terminal 15 Relay 7 common
Terminal 16 Relay 8 changeover
Terminal 17 Relay 8 changeover
Terminal 18 Relay 8 common

6.7 IRIG-B BOARD

Figure 22: IRIG-B board

The IRIG-B board can be fitted to provide an accurate timing reference for the device. The IRIG-B signal is
connected to the board via a BNC connector. The timing information is used to synchronise the IED's internal real-
time clock to an accuracy of 1 ms. The internal clock is then used for time tagging events, fault, maintenance and
disturbance records.
IRIG-B interface is available in modulated or demodulated formats.
The IRIG-B facility is provided in combination with other functionality on a number of additional boards, such as:
● Fibre board with IRIG-B
● Second rear communications board with IRIG-B
● Ethernet board with IRIG-B
● Redundant Ethernet board with IRIG-B

There are two types of each of these boards; one type which accepts a modulated IRIG-B input and one type
which accepts a demodulated IRIG-B input.

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6.8 FIBRE OPTIC BOARD

Figure 23: Fibre optic board

This board provides an interface for communicating with a master station. This communication link can use all
compatible protocols (Courier, IEC 60870-5-103, MODBUS and DNP 3.0). It is a fibre-optic alternative to the metallic
RS485 port presented on the power supply terminal block. The metallic and fibre optic ports are mutually exclusive.
The fibre optic port uses BFOC 2.5 ST connectors.
The board comes in two varieties; one with an IRIG-B input and one without:

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6.9 REAR COMMUNICATION BOARD

Figure 24: Rear communication board

The optional communications board containing the secondary communication ports provide two serial interfaces
presented on 9 pin D-type connectors. These interfaces are known as SK4 and SK5. Both connectors are female
connectors, but are configured as DTE ports. This means pin 2 is used to transmit information and pin 3 to receive.
SK4 can be used with RS232, RS485 and K-bus. SK5 can only be used with RS232 and is used for electrical
teleprotection. The optional rear communications board and IRIG-B board are mutually exclusive since they use
the same hardware slot. However, the board comes in two varieties; one with an IRIG-B input and one without.

6.10 ETHERNET BOARD

Figure 25: Ethernet board

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This is a communications board that provides a standard 100-Base Ethernet interface. This board supports one
electrical copper connection and one fibre-pair connection.
There are several variants for this board as follows:
● 100 Mbps Ethernet board
● 100 Mbps Ethernet with on-board modulated IRIG-B input
● 100 Mbps Ethernet with on-board unmodulated IRIG-B input
Two of the variants provide an IRIG-B interface. IRIG-B provides a timing reference for the unit – one board for
modulated IRIG-B and one for demodulated. The IRIG B signal is connected to the board with a BNC connector.
The Ethernet and other connection details are described below:

IRIG-B Connector
● Centre connection: Signal
● Outer connection: Earth

LEDs
LED Function On Off Flashing
Green Link Link ok Link broken
Yellow Activity Traffic

Optical Fibre Connectors

Connector Function
Rx Receive
Tx Transmit

RJ45connector
Pin Signal name Signal definition
1 TXP Transmit (positive)
2 TXN Transmit (negative)
3 RXP Receive (positive)
4 - Not used
5 - Not used
6 RXN Receive (negative)
7 - Not used
8 - Not used

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6.11 REDUNDANT ETHERNET BOARD

IRIG-B

Link Fail
Pin3 connector
Pin 2

Pin 1
Link channel Link channel B
A (green LED) (green LED)
Activity channel Activity channel B
A (yellow LED) (yellow LED)
A
C

V01009

Figure 26: Redundant Ethernet board

This board provides dual redundant Ethernet (supported by two fibre pairs) together with an IRIG-B interface for
timing.
Different board variants are available, depending on the redundancy protocol and the type of IRIG-B signal
(unmodulated or modulated). The available redundancy protocols are:
● SHP (Self healing Protocol)
● RSTP (Rapid Spanning Tree Protocol)
● DHP (Dual Homing Protocol)
● PRP (Parallel Redundancy Protocol)

There are several variants for this board as follows:

● 100 Mbps redundant Ethernet running RSTP, with on-board modulated IRIG-B
● 100 Mbps redundant Ethernet running RSTP, with on-board unmodulated IRIG-B
● 100 Mbps redundant Ethernet running SHP, with on-board modulated IRIG-B
● 100 Mbps redundant Ethernet running SHP, with on-board unmodulated IRIG-B
● 100 Mbps redundant Ethernet running DHP, with on-board modulated IRIG-B
● 100 Mbps redundant Ethernet running DHP, with on-board unmodulated IRIG-B
● 100 Mbps redundant Ethernet running PRP, with on-board modulated IRIG-B
● 100 Mbps redundant Ethernet running PRP, with on-board demodulated IRIG-B
The Ethernet and other connection details are described below:

IRIG-B Connector
● Centre connection: Signal
● Outer connection: Earth

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Link Fail Connector (Ethernet Board Watchdog Relay)

Pin Closed Open
1-2 Link fail Channel 1 (A) Link ok Channel 1 (A)
2-3 Link fail Channel 2 (B) Link ok Channel 2 (B)

LEDs
LED Function On Off Flashing
Green Link Link ok Link broken
Yellow Activity SHP running PRP, RSTP or DHP traffic

Optical Fibre Connectors (ST)

Connector DHP RSTP SHP PRP
A RXA RX1 RS RXA
B TXA TX1 ES TXA
C RXB RX2 RP RXB
D TXB TX2 EP TXB

RJ45connector
Pin Signal name Signal definition
1 TXP Transmit (positive)
2 TXN Transmit (negative)
3 RXP Receive (positive)
4 - Not used
5 - Not used
6 RXN Receive (negative)
7 - Not used
8 - Not used

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6.12 COPROCESSOR BOARD

Figure 27: Fully populated Coprocessor board

Note:
The above figure shows a coprocessor complete with GPS input and 2 fibre-optic serial data interfaces, and is not necessarily
representative of the product and model described in this manual. These interfaces will not be present on boards that do not
require them.

Where applicable, a second processor board is used to process the special algorithms associated with the device.
This second processor board provides fast access (zero wait state) SRAM for use with both program and data
memory storage. This memory can be accessed by the main processor board via the parallel bus. This is how the
software is transferred from the flash memory on the main processor board to the coprocessor board on power
up. Further communication between the two processor boards is achieved via interrupts and the shared SRAM.
The serial bus carrying the sample data is also connected to the co-processor board, using the processor’s built-in
serial port, as on the main processor board.
There are several different variants of this board, which can be chosen depending on the exact device and model.
The variants are:
● Coprocessor board with current differential inputs and GPS input
● Coprocessor board with current differential inputs only
● Coprocessor board with GPS input only

6.12.1 CURRENT DIFFERENTIAL INPUTS

Where applicable, the coprocessor board can be equipped with up to two daughter boards, each containing a
fibre-optic interface for a serial data link. BFOC 2.5 ST connectors are used for this purpose. One or two channels
are provided, each channel comprising a fibre pair for transmitting and receiving (Rx Tx). These channels are
labelled Ch1 and Ch2. These serial data links are used to transfer information between two or three IEDs for
current differential applications.

6.12.2 COPROCESSOR BOARD WITH 1PPS INPUT

In some applications, where the communication links between two remote devices are provided by a third party
telecommunications partner, the transmit and receive paths associated with one channel may differ considerably
in length, resulting in very different transmission and receive times.

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If, for example, Device A is transmitting to Device B information about the value of its measured current, the
information Device A is receiving from Device B about the current measured at the same time, may reach device B
at a different time. This has to be compensated for. A 1pps GPS timing signal applied to both devices will help the
IEDs achieve this, because it is possible to measure the exact time taken for both transmission and receive paths.

Note:
The 1 pps signal is always supplied by a GPS receiver (such as a P594).

Note:
This signal is used to control the sampling process, and timing calculations and is not used for time stamping or real time
synchronisation.

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SOFTWARE DESIGN
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1 CHAPTER OVERVIEW
This chapter describes the software design of the IED.
This chapter contains the following sections:
Chapter Overview 65
Sofware Design Overview 66
System Level Software 67
Platform Software 70
Protection and Control Functions 71

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2 SOFWARE DESIGN OVERVIEW

The device software can be conceptually categorized into several elements as follows:
● The system level software
● The platform software
● The protection and control software

These elements are not distinguishable to the user, and the distinction is made purely for the purposes of
explanation. The following figure shows the software architecture.

Protection and Control Software Layer

Protection Task
Programmable & fixed Coprocessor protection
scheme logic algorithms
Fault locator Disturbance
Signal processing Protection algorithms task recorder task

Supervisor task

Records

and control
Protection

settings
Platform Software Layer

Event, fault,
Remote
disturbance,
Settings database communications
maintenance record
Sampling function interfaces
logging

Front panel Local

interface communications
(LCD + Keypad) interfaces

Sample data + digital Control of interfaces to keypad , LCD, LEDs,

logic inputs front & rear ports.
Control of output contacts
and programmable LEDs Self-checking maintenance records

System Level Software Layer

System services (e.g. device drivers) / Real time operating system / Self-diagnostic software

Hardware Device Layer

LEDs / LCD / Keypad / Memory / FPGA

V00307

Figure 28: Software Architecture

The software, which executes on the main processor, can be divided into a number of functions as illustrated
above. Each function is further broken down into a number of separate tasks. These tasks are then run according
to a scheduler. They are run at either a fixed rate or they are event driven. The tasks communicate with each other
as and when required.

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3 SYSTEM LEVEL SOFTWARE

3.1 REAL TIME OPERATING SYSTEM

The real-time operating system is used to schedule the processing of the various tasks. This ensures that they are
processed in the time available and in the desired order of priority. The operating system also plays a part in
controlling the communication between the software tasks, through the use of operating system messages.

3.2 SYSTEM SERVICES SOFTWARE

The system services software provides the layer between the hardware and the higher-level functionality of the
platform software and the protection and control software. For example, the system services software provides
drivers for items such as the LCD display, the keypad and the remote communication ports. It also controls things
like the booting of the processor and the downloading of the processor code into RAM at startup.

3.3 SELF-DIAGNOSTIC SOFTWARE

The device includes several self-monitoring functions to check the operation of its hardware and software while in
service. If there is a problem with the hardware or software, it should be able to detect and report the problem, and
attempt to resolve the problem by performing a reboot. In this case, the device would be out of service for a short
time, during which the ‘Healthy’ LED on the front of the device is switched OFF and the watchdog contact at the
rear is ON. If the restart fails to resolve the problem, the unit takes itself permanently out of service; the ‘Healthy’
LED stays OFF and watchdog contact stays ON.
If a problem is detected by the self-monitoring functions, the device attempts to store a maintenance record to
allow the nature of the problem to be communicated to the user.
The self-monitoring is implemented in two stages: firstly a thorough diagnostic check which is performed on boot-
up, and secondly a continuous self-checking operation, which checks the operation of the critical functions whilst
it is in service.

3.4 STARTUP SELF-TESTING

The self-testing takes a few seconds to complete, during which time the IED's measurement, recording, control,
and protection functions are unavailable. On a successful start-up and self-test, the ‘health-state’ LED on the front
of the unit is switched on. If a problem is detected during the start-up testing, the device remains out of service
until it is manually restored to working order.
The operations that are performed at start-up are:
1. System boot
2. System software initialisation
3. Platform software initialisation and monitoring

3.4.1 SYSTEM BOOT

The integrity of the Flash memory is verified using a checksum before the program code and stored data is loaded
into RAM for execution by the processor. When the loading has been completed, the data held in RAM is compared
to that held in the Flash memory to ensure that no errors have occurred in the data transfer and that the two are
the same. The entry point of the software code in RAM is then called. This is the IED's initialisation code.

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3.4.2 SYSTEM LEVEL SOFTWARE INITIALISATION

The initialization process initializes the processor registers and interrupts, starts the watchdog timers (used by the
hardware to determine whether the software is still running), starts the real-time operating system and creates
and starts the supervisor task. In the initialization process the device checks the following:
● The status of the backup battery
● The integrity of the battery-backed SRAM that is used to store event, fault and disturbance records
● The operation of the LCD controller
● The watchdog operation

At the conclusion of the initialization software the supervisor task begins the process of starting the platform
software. Coprocessor board checks are also made as follows:
● A check is made for the presence of the coprocessor board

● The RAM on the coprocessor board is checked with a test bit pattern before the coprocessor board is
transferred from flash memory

If any of these checks produces an error, the coprocessor board is left out of service. The other protection
functions provided by the main processor board are left in service.

3.4.3 PLATFORM SOFTWARE INITIALISATION AND MONITORING

When starting the platform software, the IED checks the following:
● The integrity of the data held in non-volatile memory (using a checksum)
● The operation of the real-time clock
● The optional IRIG-B function (if applicable)
● The presence and condition of the input board
● The analog data acquisition system (it does this by sampling the reference voltage)

At the successful conclusion of all of these tests the unit is entered into service and the application software is
started up.

3.5 CONTINUOUS SELF-TESTING

When the IED is in service, it continually checks the operation of the critical parts of its hardware and software. The
checking is carried out by the system services software and the results are reported to the platform software. The
functions that are checked are as follows:
● The Flash memory containing all program code and language text is verified by a checksum.
● The code and constant data held in system memory is checked against the corresponding data in Flash
memory to check for data corruption.
● The system memory containing all data other than the code and constant data is verified with a checksum.
● The integrity of the digital signal I/O data from the opto-inputs and the output relay coils is checked by the
data acquisition function every time it is executed.
● The operation of the analog data acquisition system is continuously checked by the acquisition function
every time it is executed. This is done by sampling the reference voltages.
● The operation of the optional Ethernet board is checked by the software on the main processor card. If the
Ethernet board fails to respond an alarm is raised and the card is reset in an attempt to resolve the problem.
● The operation of the optional IRIG-B function is checked by the software that reads the time and date from
the board.
In the event that one of the checks detects an error in any of the subsystems, the platform software is notified and
it attempts to log a maintenance record.

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If the problem is with the battery status or the IRIG-B board, the device continues in operation. For problems
detected in any other area, the device initiates a shutdown and re-boot, resulting in a period of up to 10 seconds
when the functionality is unavailable.
A restart should clear most problems that may occur. If, however, the diagnostic self-check detects the same
problem that caused the IED to restart, it is clear that the restart has not cleared the problem, and the device takes
itself permanently out of service. This is indicated by the ‘’health-state’ LED on the front of the device, which
switches OFF, and the watchdog contact which switches ON.

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4 PLATFORM SOFTWARE
The platform software has three main functions:
● To control the logging of records generated by the protection software, including alarms, events, faults, and
maintenance records
● To store and maintain a database of all of the settings in non-volatile memory
● To provide the internal interface between the settings database and the user interfaces, using the front
panel interface and the front and rear communication ports

4.1 RECORD LOGGING

The logging function is used to store all alarms, events, faults and maintenance records. The records are stored in
non-volatile memory to provide a log of what has happened. The IED maintains four types of log on a first in first
out basis (FIFO). These are:
● Alarms
● Event records
● Fault records
● Maintenance records

The logs are maintained such that the oldest record is overwritten with the newest record. The logging function
can be initiated from the protection software. The platform software is responsible for logging a maintenance
record in the event of an IED failure. This includes errors that have been detected by the platform software itself or
errors that are detected by either the system services or the protection software function. See the Monitoring and
Control chapter for further details on record logging.

4.2 SETTINGS DATABASE

The settings database contains all the settings and data, which are stored in non-volatile memory. The platform
software manages the settings database and ensures that only one user interface can modify the settings at any
one time. This is a necessary restriction to avoid conflict between different parts of the software during a setting
change.
Changes to protection settings and disturbance recorder settings, are first written to a temporary location SRAM
memory. This is sometimes called 'Scratchpad' memory. These settings are not written into non-volatile memory
immediately. This is because a batch of such changes should not be activated one by one, but as part of a
complete scheme. Once the complete scheme has been stored in SRAM, the batch of settings can be committed to
the non-volatile memory where they will become active.

4.3 INTERFACES
The settings and measurements database must be accessible from all of the interfaces to allow read and modify
operations. The platform software presents the data in the appropriate format for each of the interfaces (LCD
display, keypad and all the communications interfaces).

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5 PROTECTION AND CONTROL FUNCTIONS

The protection and control software processes all of the protection elements and measurement functions. To
achieve this it has to communicate with the system services software, the platform software as well as organise its
own operations.
The protection task software has the highest priority of any of the software tasks in the main processor board. This
ensures the fastest possible protection response.
The protection and control software provides a supervisory task, which controls the start-up of the task and deals
with the exchange of messages between the task and the platform software.

5.1 ACQUISITION OF SAMPLES

After initialization, the protection and control task waits until there are enough samples to process. The acquisition
of samples on the main processor board is controlled by a ‘sampling function’ which is called by the system
services software.
This sampling function takes samples from the input module and stores them in a two-cycle FIFO buffer. These
samples are also stored concurrently by the coprocessor. The sample rate is 48 samples per cycle. This results in a
nominal sample rate of 2,400 samples per second for a 50 hz system and 2,880 samples per second for a 60 Hz
system. However the sample rate is not fixed. It tracks the power system frequency as described in the next
section.
In normal operation, the protection task is executed 16 times per cycle.

5.2 FREQUENCY TRACKING

The device provides a frequency tracking algorithm so that there are always 48 samples per cycle irrespective of
frequency drift. The frequency range in which 48 samples per second are provided is between 45 Hz and 66 z. If
the frequency falls outside this range, the sample rate reverts to its default rate of 2,400 Hz for 50 Hz or 2,880 Hz
for 60 Hz.
The frequency tracking of the analog input signals is achieved by a recursive Fourier algorithm which is applied to
one of the input signals. It works by detecting a change in the signal’s measured phase angle. The calculated value
of the frequency is used to modify the sample rate being used by the input module, in order to achieve a constant
sample rate per cycle of the power waveform. The value of the tracked frequency is also stored for use by the
protection and control task.
The frequency tracks off any voltage or current in the order VA, VB, VC, IA, IB, IC, down to 10%Vn for voltage and
5%In for current.

5.3 DIRECT USE OF SAMPLE VALUES

Most of the IED’s protection functionality uses the Fourier components calculated by the device’s signal processing
software. However RMS measurements and some special protection algorithms available in some products use
the sampled values directly.
The disturbance recorder also uses the samples from the input module, in an unprocessed form. This is for
waveform recording and the calculation of true RMS values of current, voltage and power for metering purposes.
In the case of special protection algorithms, using the sampled values directly provides exceptionally fast response
because you do not have to wait for the signal processing task to calculate the fundamental. You can act on the
sampled values immediately.

5.4 SYSTEM LEVEL SOFTWARE INITIALISATION

The differential protection requires that the devices at the line ends exchange data messages four times per cycle.
To achieve this the coprocessor retrieves the frequency-tracked samples at 48 samples per cycle from the input

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board and converts these to 8 samples per cycle based on the nominal frequency. The coprocessor calculates the
Fourier transform of the fixed rate samples after every sample, using a one-cycle window. This generates current
measurements eight times per cycle which are used for the differential protection algorithm. These are transmitted
to the remote device(s) using the HDLC (high-level data link control) communication protocol.
The coprocessor is also responsible for managing intertripping commands via the communication link, as well as
re-configuration instigated from the remote device(s).
Data exchange between the coprocessor board and the main processor board is achieved through the use of
shared memory on the coprocessor board. When the main processor accesses this memory, the coprocessor is
temporarily halted. After the coprocessor code has been copied onto the board at initialization, the main traffic
between the two boards consists of setting change information, commands from the main processor, differential
protection measurements and output data.

5.5 DISTANCE PROTECTION

The current and voltage inputs are filtered using Finite Impulse Response (FIR) digital filters. This reduces the
effects of non-power frequency components in the input signals, such as DC offsets in current waveforms, and
capacitor voltage transformer (CVT) transients in the voltages. The device uses a combination of a 1/4 cycle filter
using 12 coefficients, a 1/2 cycle filter using 24 coefficients, and a single cycle filter using 48 coefficients. The
device automatically performs intelligent switching in the application of the filters, to select the best balance of
removal of transients with fast response. The protection elements themselves then perform additional filtering,
implemented for example, by the trip count strategy.
The following figure shows the frequency response of the 12, 24 and 48 coefficient filters, noting that all have a
gain of unity at the fundamental frequency:

Filter Response

2.5

2
Full
1.5
Gain Half
1
Quarter
0.5
0
0 3 6 9 12 15 18 21

Harmonic
E00308

Figure 29: Frequency response of FIR filters

5.6 FOURIER SIGNAL PROCESSING

All backup protection and measurement functions use single-cycle fourier digital filtering to extract the power
frequency component. This filtering is performed on the main processor board.
When the protection and control task is re-started by the sampling function, it calculates the Fourier components
for the analog signals. Although some protection algorithms use some Fourier-derived harmonics (e.g. second
harmonic for magnetizing inrush), most protection functions are based on the Fourier-derived fundamental
components of the measured analog signals. The Fourier components of the input current and voltage signals are
stored in memory so that they can be accessed by all of the protection elements’ algorithms.
The Fourier components are calculated using single-cycle Fourier algorithm. This Fourier algorithm always uses
the most recent 48 samples from the 2-cycle buffer.
Most protection algorithms use the fundamental component. In this case, the Fourier algorithm extracts the power
frequency fundamental component from the signal to produce its magnitude and phase angle. This can be
represented in either polar format or rectangular format, depending on the functions and algorithms using it.

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The Fourier function acts as a filter, with zero gain at DC and unity gain at the fundamental, but with good
harmonic rejection for all harmonic frequencies up to the nyquist frequency. Frequencies beyond this nyquist
frequency are known as alias frequencies, which are introduced when the sampling frequency becomes less than
twice the frequency component being sampled. However, the Alias frequencies are significantly attenuated by an
anti-aliasing filter (low pass filter), which acts on the analog signals before they are sampled. The ideal cut-off point
of an anti-aliasing low pass filter would be set at:
(samples per cycle) ´ (fundamental frequency)/2
At 48samples per cycle, this would be nominally 1200 Hz for a 50 Hz system, or 1440 Hz for a 60 Hz system.
The following figure shows the nominal frequency response of the anti-alias filter and the Fourier filter for a 48-
sample single cycle fourier algorithm acting on the fundamental component:

1
Ideal anti-alias filter response
0.8
Fourier Response
0.6 Real anti-alias filter without anti-alias filter
response
0.4
Fourier Response
0.2 with anti-alias filter

1 2 3... 24 Alias frequency

50 Hz 1200 Hz 2400 Hz
V00306

Figure 30: Frequency Response (indicative only)

5.7 PROGRAMMABLE SCHEME LOGIC

The purpose of the programmable scheme logic (PSL) is to allow you to configure your own protection schemes to
suit your particular application. This is done with programmable logic gates and delay timers. To allow greater
flexibility, different PSL is allowed for each of the four setting groups.
The input to the PSL is any combination of the status of the digital input signals from the opto-isolators on the
input board, the outputs of the protection elements such as protection starts and trips, and the outputs of the fixed
protection scheme logic (FSL). The fixed scheme logic provides the standard protection schemes. The PSL consists
of software logic gates and timers. The logic gates can be programmed to perform a range of different logic
functions and can accept any number of inputs. The timers are used either to create a programmable delay,
and/or to condition the logic outputs, such as to create a pulse of fixed duration on the output regardless of the
length of the pulse on the input. The outputs of the PSL are the LEDs on the front panel of the relay and the output
contacts at the rear.
The execution of the PSL logic is event driven. The logic is processed whenever any of its inputs change, for
example as a result of a change in one of the digital input signals or a trip output from a protection element. Also,
only the part of the PSL logic that is affected by the particular input change that has occurred is processed. This
reduces the amount of processing time that is used by the PSL. The protection & control software updates the logic
delay timers and checks for a change in the PSL input signals every time it runs.
The PSL can be configured to create very complex schemes. Because of this PSL desing is achieved by means of a
PC support package called the PSL Editor. This is available as part of the settings application software MiCOm S1
Agile, or as a standalone software module.

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5.8 EVENT RECORDING

A change in any digital input signal or protection element output signal is used to indicate that an event has taken
place. When this happens, the protection and control task sends a message to the supervisor task to indicate that
an event is available to be processed and writes the event data to a fast buffer controlled by the supervisor task.
When the supervisor task receives an event record, it instructs the platform software to create the appropriate log
in non-volatile memory (battery backed-up SRAM). The operation of the record logging to battery backed-up SRAM
is slower than the supervisor buffer. This means that the protection software is not delayed waiting for the records
to be logged by the platform software. However, in the rare case when a large number of records to be logged are
created in a short period of time, it is possible that some will be lost, if the supervisor buffer is full before the
platform software is able to create a new log in battery backed-up SRAM. If this occurs then an event is logged to
indicate this loss of information.
Maintenance records are created in a similar manner, with the supervisor task instructing the platform software to
log a record when it receives a maintenance record message. However, it is possible that a maintenance record
may be triggered by a fatal error in the relay in which case it may not be possible to successfully store a
maintenance record, depending on the nature of the problem.
For more information, see the Monitoring and Control chapter.

5.9 DISTURBANCE RECORDER

The disturbance recorder operates as a separate task from the protection and control task. It can record the
waveforms for up to 12 calibrated analog channels and the values of up to 32 digital signals. The recording time is
user selectable. Up to 50 seconds of data can be recorded. A minimum number of 5 records with a capacity of 10
seconds each, up to a maximum of 50 records with a capacity of 10 seconds each can be set. The disturbance
recorder is supplied with data by the protection and control task once per cycle. The disturbance recorder collates
the data that it receives into the required length disturbance record. The disturbance records can be extracted by
settings application software such as MiCOM S1 Agile, which can also store the data in COMTRADE format,
therefore allowing the use of other packages to view the recorded data.
For more information, see the Monitoring and Control chapter.

5.10 FAULT LOCATOR

The fault locator uses 12 cycles of the analog input signals to calculate the fault location. The result is returned to
the protection and control task, which includes it in the fault record. The pre-fault and post-fault voltages are also
presented in the fault record. When the fault record is complete, including the fault location, the protection and
control task sends a message to the supervisor task to log the fault record.
The Fault Locator is not available on all models.

5.11 FUNCTION KEY INTERFACE

The function keys interface directly into the PSL as digital input signals. A change of state is only recognized when
a key press is executed on average for longer than 200 ms. The time to register a change of state depends on
whether the function key press is executed at the start or the end of a protection task cycle, with the additional
hardware and software scan time included. A function key press can provide a latched (toggled mode) or output
on key press only (normal mode) depending on how it is programmed. It can be configured to individual protection
scheme requirements. The latched state signal for each function key is written to non-volatile memory and read
from non-volatile memory during relay power up thus allowing the function key state to be reinstated after power-
up, should power be inadvertently lost.

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CONFIGURATION
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1 CHAPTER OVERVIEW
Each product has different configuration parameters according to the functions it has been designed to perform.
There is, however, a common methodology used across the entire product series to set these parameters.
Some of the communications setup can only be carried out using the HMI, and cannot be carried out using
settings applications software. This chapter includes concise instructions of how to configure the device,
particularly with respect to the communications setup, as well as a description of the common methodology used
to configure the device in general.

This chapter contains the following sections:

Chapter Overview 77
Settings Application Software 78
Using the HMI Panel 79
Line Parameters 89
Date and Time Configuration 92
Settings Group Selection 95

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2 SETTINGS APPLICATION SOFTWARE

To configure this device you will need to use the Settings Application Software. The settings application software
used in this range of IEDs is called MiCOM S1 Agile. It is a collection of software tools, which is used for setting up
and managing the IEDs.
Although you can change many settings using the front panel HMI, some of the features cannot be configured
without the Settings Application Software; for example the programmable scheme logic, or IEC61850
communications.
If you do not already have a copy of the Settings Application Software, you can obtain it from General Electric
contact centre.
To configure your product, you will need a data model that matches your product. When you launch the Settings
Application Software, you will be presented with a panel that allows you to invoke the “Data Model Manager”. This
will close the other aspects of the software in order to allow an efficient import of the chosen data model. If you
don’t have, or can’t find, the data model relating to your product, please call the General Electric contact centre.
When you have loaded all the data models you need, you should restart the Settings Application Software and
start to create a model of your system using the “System Explorer” panel.
The software is designed to be intuitive, but help is available in an online help system and also the Settings
Application Software user guide P40-M&CR-SAS-UG-EN-n, where 'Language' is a 2 letter code designating the
language version of the user guide and 'n' is the latest version of the settings application software.

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3 USING THE HMI PANEL

Using the HMI, you can:
● Display and modify settings
● View the digital I/O signal status
● Display measurements
● Display fault records
● Reset fault and alarm indications

The keypad provides full access to the device functionality using a range of menu options. The information is
displayed on the LCD.
Keys Description Function

To change the menu level or change between settings in a

Up and down cursor keys
particular column, or changing values within a cell

To change default display, change between column

Left and right cursor keys
headings, or changing values within a cell

ENTER key For changing and executing settings

For executing commands and settings for which shortcuts

Hotkeys
have been defined

Cancel key To return to column header from any menu cell

Read key To read alarm messages

Function keys (not all models) For executing user programmable functions

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Note:
As the LCD display has a resolution of 16 characters by 3 lines, some of the information is in a condensed mnemonic form.

3.1 NAVIGATING THE HMI PANEL

The cursor keys are used to navigate the menus. These keys have an auto-repeat function if held down
continuously. This can be used to speed up both setting value changes and menu navigation. The longer the key is
held pressed, the faster the rate of change or movement.
The navigation map below shows how to navigate the menu items.

Default display Default display

option option

Alarm message

Default display options

C

Column 00 Subsequent column headings Last Column

System data

Vertical cursor keys move

Horizontal cursor
between setting rows
keys move
Row 01
Language C between values
within a cell
Row 01

The Cancel key

returns to
column header
Subsequent rows Subsequent rows

V00400

Figure 31: Navigating the HMI

3.2 GETTING STARTED

When you first start the IED, it will go through its power up procedure. After a few seconds it will settle down into
one of the top level menus. There are two menus at this level:
● The Alarms menu for when there are alarms present
● The default display menu for when there are no alarms present.

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If there are alarms present, the yellow Alarms LED will be flashing and the menu display will read as follows:

Alarms / Faults
Present
HOTKEY

Even though the device itself should be in full working order when you first start it, an alarm could still be present,
for example, if there is no network connection for a device fitted with a network card. If this is the case, you can
read the alarm by pressing the 'Read' key.

ALARMS
NIC Link Fail

If the device is fitted with an Ethernet card, you will first need to connect the device to an active Ethernet network
to clear the alarm and get the default display.
If there are other alarms present, these must also be cleared before you can get into the default display menu
options.

3.3 DEFAULT DISPLAY

The HMI contains a range of possible options that you can choose to be the default display. The options available
are:

NERC Compliant banner

If the device is a cyber-security model, it will provide a NERC-compliant default display. If the device does not
contain the cyber-security option, this display option is not available.

ACCESS ONLY FOR

AUTHORISED USERS
HOTKEY

Date and time

For example:

11:09:15
23 Nov 2011
HOTKEY

Description (user-defined)
For example:

Description
MiCOM P14NB
HOTKEY

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Plant reference (user-defined)

For example:

Plant Reference
MiCOM
HOTKEY

Access Level
For example:

Access Level
3
HOTKEY

In addition to the above, there are also displays for the system voltages, currents, power and frequency etc.,
depending on the device model.

3.4 DEFAULT DISPLAY NAVIGATION

The following diagram is an example of the default display navigation. In this example, we have used a cyber-
secure model. This is an example only and may not apply in its entirety to all models. The actual display options
available depend on the exact model.
Use the horizontal cursor keys to step through from one display to the next.

NERC compliant
banner

NERC Compliance NERC Compliance

Warning Warning

System Current
Access Level
Measurements

System Voltage
System Frequency
Measurements

System Power
Plant Reference
Measurements

Description Date & Time

V00403

Figure 32: Default display navigation

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If the device is cyber-secure but is not yet configured for NERC compliance (see Cyber-security chapter), a warning
will appear when moving from the "NERC compliant" banner. The warning message is as follows:

DISPLAY NOT NERC

COMPLIANT. OK?

You will have to confirm with the Enter button before you can go any further.

Note:
Whenever the IED has an uncleared alarm the default display is replaced by the text Alarms/ Faults present. You cannot
override this default display. However, you can enter the menu structure from the default display, even if the display shows
the Alarms/Faults present message.

3.5 PASSWORD ENTRY

Configuring the default display (in addition to modification of other settings) requires level 3 access. You will be
prompted for a password before you can make any changes, as follows. The default level 3 password is AAAA.

Enter Password

1. A flashing cursor shows which character field of the password can be changed. Press the up or down cursor
keys to change each character (tip: pressing the up arrow once will return an upper case "A" as required by
the default level 3 password).
2. Use the left and right cursor keys to move between the character fields of the password.
3. Press the Enter key to confirm the password. If you enter an incorrect password, an invalid password
message is displayed then the display reverts to Enter password. On entering a valid password a message
appears indicating that the password is correct and which level of access has been unlocked. If this level is
sufficient to edit the selected setting, the display returns to the setting page to allow the edit to continue. If
the correct level of password has not been entered, the password prompt page appears again.
4. To escape from this prompt press the Clear key. Alternatively, enter the password using the Password
setting in the SYSTEM DATA column. If the keypad is inactive for 15 minutes, the password protection of the
front panel user interface reverts to the default access level.
To manually reset the password protection to the default level, select Password, then press the CLEAR key instead
of entering a password.

Note:
In the SECURITY CONFIG column, you can set the maximum number of attemps, the time window in which the failed attempts
are counted and the time duration for which the user is blocked.

3.6 PROCESSING ALARMS AND RECORDS

If there are any alarm messages, they will appear on the default display and the yellow alarm LED flashes. The
alarm messages can either be self-resetting or latched. If they are latched, they must be cleared manually.
1. To view the alarm messages, press the Read key. When all alarms have been viewed but not cleared, the
alarm LED changes from flashing to constantly on, and the latest fault record appears (if there is one).
2. Scroll through the pages of the latest fault record, using the cursor keys. When all pages of the fault record
have been viewed, the following prompt appears.

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Press Clear To
Reset Alarms

3. To clear all alarm messages, press the Clear key. To return to the display showing alarms or faults present,
and leave the alarms uncleared, press the Read key.
4. Depending on the password configuration settings, you may need to enter a password before the alarm
messages can be cleared.
5. When all alarms are cleared, the yellow alarm LED switches off. If the red LED was on, this will also be
switched off.

Note:
To speed up the procedure, you can enter the alarm viewer using the Read key and subsequently pressing the Clear key. This
goes straight to the fault record display. Press the Clear key again to move straight to the alarm reset prompt, then press the
Clear key again to clear all alarms.

3.7 MENU STRUCTURE

Settings, commands, records and measurements are stored in a local database inside the IED. When using the
Human Machine Interface (HMI) it is convenient to visualise the menu navigation system as a table. Each item in
the menu is known as a cell, which is accessed by reference to a column and row address. Each column and row is
assigned a 2-digit hexadecimal numbers, resulting in a unique 4-digit cell address for every cell in the database.
The main menu groups are allocated columns and the items within the groups are allocated rows, meaning a
particular item within a particular group is a cell.
Each column contains all related items, for example all of the disturbance recorder settings and records are in the
same column.
There are three types of cell:
● Settings: this is for parameters that can be set to different values
● Commands: this is for commands to be executed
● Data: this is for measurements and records to be viewed, which are not settable

Note:
Sometimes the term "Setting" is used generically to describe all of the three types.

The table below, provides an example of the menu structure:

SYSTEM DATA (Col 00) VIEW RECORDS (Col 01) MEASUREMENTS 1 (Col 02) …
Language (Row 01) "Select Event [0...n]" (Row 01) IA Magnitude (Row 01) …
Password (Row 02) Menu Cell Ref (Row 02) IA Phase Angle (Row 02) …
Sys Fn Links (Row 03) Time & Date (Row 03) IB Magnitude (Row 03) …
… … … …

It is convenient to specify all the settings in a single column, detailing the complete Courier address for each
setting. The above table may therefore be represented as follows:
Setting Column Row Description
SYSTEM DATA 00 00 First Column definition
Language (Row 01) 00 01 First setting within first column
Password (Row 02) 00 02 Second setting within first column

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Setting Column Row Description

Sys Fn Links (Row 03) 00 03 Third setting within first column
… … …
VIEW RECORDS 01 00 Second Column definition
Select Event [0...n] 01 01 First setting within second column
Menu Cell Ref 01 02 Second setting within second column
Time & Date 01 03 Third setting within second column
… … …
MEASUREMENTS 1 02 00 Third Column definition
IA Magnitude 02 01 First setting within third column
IA Phase Angle 02 02 Second setting within third column
IB Magnitude 02 03 Third setting within third column
… … …

The first three column headers are common throughout much of the product ranges. However the rows within
each of these column headers may differ according to the product type. Many of the column headers are the
same for all products within the series. However, there is no guarantee that the addresses will be the same for a
particular column header. Therefore you should always refer to the product settings documentation and not make
any assumptions.

3.8 CHANGING THE SETTINGS

1. Starting at the default display, press the Down cursor key to show the first column heading.
2. Use the horizontal cursor keys to select the required column heading.
3. Use the vertical cursor keys to view the setting data in the column.
4. To return to the column header, either press the Up cursor key for a second or so, or press the Clear key
once. It is only possible to move across columns at the column heading level.
5. To return to the default display, press the Up cursor key or the Clear key from any of the column headings. If
you use the auto-repeat function of the Up cursor key, you cannot go straight to the default display from
one of the column cells because the auto-repeat stops at the column heading.
6. To change the value of a setting, go to the relevant cell in the menu, then press the Enter key to change the
cell value. A flashing cursor on the LCD shows that the value can be changed. You may be prompted for a
password first.
7. To change the setting value, press the Up and Down cursor keys. If the setting to be changed is a binary
value or a text string, select the required bit or character to be changed using the horizontal cursor keys.
8. Press the Enter key to confirm the new setting value or the Clear key to discard it. The new setting is
automatically discarded if it is not confirmed within 15 seconds.
9. For protection group settings and disturbance recorder settings, the changes must be confirmed before
they are used. When all required changes have been entered, return to the column heading level and press
the Down cursor key. Before returning to the default display, the following prompt appears.

Update settings?
ENTER or CLEAR

10. Press the Enter key to accept the new settings or press the Clear key to discard the new settings.

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Note:
For the protection group and disturbance recorder settings, if the menu time-out occurs before the changes have been
confirmed, the setting values are discarded. Control and support settings, howeverr, are updated immediately after they are
entered, without the Update settings? prompt.

3.9 DIRECT ACCESS (THE HOTKEY MENU)

For settings and commands that need to be executed quickly or on a regular basis, the IED provides a pair of keys
directly below the LCD display. These so called Hotkeys can be used to execute specified settings and commands
directly.
The functions available for direct access using these keys are:
● Setting group selection
● Control inputs
● Circuit Breaker (CB) control functions

The availability of these functions is controlled by the Direct Access cell in the CONFIGURATION column. There are
four options: Disabled, Enabled, CB Ctrl only and Hotkey only.
For the Setting Group selection and Control inputs, this cell must be set to either Enabled or Hotkey only. For
CB Control functions, the cell must be set to Enabled or CB Ctrl only.

3.9.1 SETTING GROUP SELECTION USING HOTKEYS

In some models you can use the hotkey menu to select the settings group. By default, only Setting group 1 is
enabled. Other setting groups will only be available if they are first enabled. To be able to select a different setting
group, you must first enable them in the CONFIGURATION column.
To access the hotkey menu from the default display, you press the key directly below the HOTKEY text on the LCD.
The following screen will appear.

¬User32 STG GP®

HOTKEY MENU
EXIT

Use the right cursor keys to enter the SETTING GROUP menu.

¬Menu User01®
SETTING GROUP 1
Nxt Grp Select

Select the setting group with Nxt Grp and confirm by pressing Select. If neither of the cursor keys is pressed within
20 seconds of entering a hotkey sub menu, the device reverts to the default display.

3.9.2 CONTROL INPUTS

The control inputs are user-assignable functions. You can use the CTRL I/P CONFIG column to configure the control
inputs for the hotkey menu. In order to do this, use the first setting Hotkey Enabled cell to enable or disable any of
the 32 control inputs. You can then set each control input to latched or pulsed and set its command to On/Off,
Set/Reset, In/Out, or Enabled/Disabled.
By default, the hotkey is enabled for all 32 control inputs and they are set to Set/Reset and are Latched.

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To access the hotkey menu from the default display, you press the key directly below the HOTKEY text on the LCD.
The following screen will appear.

¬User32 STG GP®

HOTKEY MENU
EXIT

Press the right cursor key twice to get to the first control input, or the left cursor key to get to the last control input.

¬STP GP User02®
Control Input 1
EXIT SET

Now you can execute the chosen function (Set/Reset in this case).
If neither of the cursor keys is pressed within 20 seconds of entering a hotkey sub menu, the device reverts to the
default display.

3.9.3 CIRCUIT BREAKER CONTROL

You can open and close the controlled circuit breaker with the hotkey to the right, if enabled as described above.
By default, hotkey access to the circuit breakers is disabled.
If hotkeyaccess to the circuit breakers has been enabled, the bottom right hand part of the display will read "Open
or Close" depending on whether the circuit breaker is closed or open respectively:
For example:

Plant Reference
MiCOM
HOTKEY CLOSE

To close the circuit breaker (in this case), press the key directly below CLOSE. You will be given an option to cancel
or confirm.

Execute
CB CLOSE
Cancel Confirm

More detailed information on this can be found in the Monitoring and Control chapter.

3.10 FUNCTION KEYS

Most products have a number of function keys for programming control functionality using the programmable
scheme logic (PSL).
Each function key has an associated programmable tri-colour LED that can be programmed to give the desired
indication on function key activation.
These function keys can be used to trigger any function that they are connected to as part of the PSL. The function
key commands are in the FUNCTION KEYS column.

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The first cell down in the FUNCTION KEYS column is the Fn Key Status cell. This contains a binary string, which
represents the function key commands. Their status can be read from this binary string.

FUNCTION KEYS
Fn Key Status
0000000000

The next cell down (Fn Key 1) allows you to activate or disable the first function key (1). The Lock setting allows a
function key to be locked. This allows function keys that are set to Toggled mode and their DDB signal active
‘high’, to be locked in their active state, preventing any further key presses from deactivating the associated
function. Locking a function key that is set to the Normal mode causes the associated DDB signals to be
permanently off. This safety feature prevents any inadvertent function key presses from activating or deactivating
critical functions.

FUNCTION KEYS
Fn Key 1
Unlocked

The next cell down (Fn Key 1 Mode) allows you to set the function key to Normal or Toggled. In the Toggle mode
the function key DDB signal output stays in the set state until a reset command is given, by activating the function
key on the next key press. In the Normal mode, the function key DDB signal stays energised for as long as the
function key is pressed then resets automatically. If required, a minimum pulse width can be programmed by
adding a minimum pulse timer to the function key DDB output signal.

FUNCTION KEYS
Fn Key 1 Mode
Toggled

The next cell down (Fn Key 1 Label) allows you to change the label assigned to the function. The default label is
Function key 1 in this case. To change the label you need to press the enter key and then change the text on
the bottom line, character by character. This text is displayed when a function key is accessed in the function key
menu, or it can be displayed in the PSL.

FUNCTION KEYS
Fn Key 1 Label
Function Key 1

Subsequent cells allow you to carry out the same procedure as above for the other function keys.
The status of the function keys is stored in non-volatile memory. If the auxiliary supply is interrupted, the status of
all the function keys is restored. The IED only recognises a single function key press at a time and a minimum key
press duration of approximately 200 ms is required before the key press is recognised. This feature avoids
accidental double presses.

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4 LINE PARAMETERS
This product requires information about the circuit to which it is applied. This includes line impedance, residual
compensation, and phase rotation sequence. For this reason circuit parameter information must be input using
the LINE PARAMETERS settings. These LINE PARAMETERS settings are used by protection elements as well as by the
fault locator.

4.1 TRIPPING MODE

The Tripping Mode setting selects whether the product should trip single-phase or three-phase when
instantaneous protection elements detect single-phase faults.
Selecting 1 and 3 Pole means that the product will only trip the affected phase for a single-phase fault. For
faults involving more than one phase the product will always trip all three phases.
Selecting 3 Pole means that the product will always trip all three phases.
For products controlling more than one circuit breaker, the tripping mode is independent for each circuit breaker.
The product features an autorecloser that can be used for single-phase autoreclose. In that case, if a single-phase
fault evolves into a multi-phase fault during the autoreclose cycle, the product will switch to three-phase tripping.

4.1.1 CB TRIP CONVERSION LOGIC DIAGRAM

530
Trip Inputs A
1 S
523
Q Trip Output A
R
531
Trip Inputs B
1 S
524
Q Trip Output B
R
532
Trip Inputs C
1 S
525
Q Trip Output C
R
Tripping Mode 1
&
3 Pole 1 S
526
Q Trip 3 ph
858 R
AR Force 3 pole 1
533
Force 3Pole Trip
529
Trip Inputs 3Ph

Dwell
522
1 Any Trip
530 100 ms
Trip Inputs A
531
Trip Inputs B
≥ S
Trip Inputs C 532 2 Q 527
2/3 Ph Fault
R
892
Pole Dead A &
1 S
528
Q 3 Ph Fault
R
893 & 1
Pole Dead B 1

&
894 1
Pole Dead C
&
V03386

Figure 33: Circuit Breaker Trip Conversion Logic Diagram (Module 63)

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Chapter 5 - Configuration P543i/P545i

4.2 RESIDUAL COMPENSATION

To improve accuracy of impedance measuring elements such as those used in distance protection and fault
locators, the total loop impedance calculation ZLP/IA can be calibrated by the positive sequence impedance
between the relaying point and the fault (ZF1) using the following equation:

VA
ZF1 =
I A + k ZN ⋅ I N
where:
● VA is the phase A voltage
● IA is the phase A current
● IN is the residual current, derived from the phase currents by the equation:

I N = I A + I B + IC

● kZN is the residual compensation coefficient given by the complex equation:

Z L 0 − Z L1
k ZN =
3Z L1
where:
● ZL0 is the total zero sequence impedance of the line (a complex value)
● ZL1 is the total positive sequence impedance of the protected line (a complex value)

The complex residual compensation coefficient is defined by two settings: kZN Res Comp (the absolute value) and
kZN Res Angle (the angle in degrees).

Caution:
The kZN Res Angle is different to that in LFZP, SHNB, and LFZR products: If importing
settings from these products, you must subtract angle ÐZL1

4.3 MUTUAL COMPENSATION

On parallel circuits, mutual flux coupling can alter the impedance seen by fault locators and distance zones. A
current input (the Mutual Compensation input) is provided to compensate.
If you want to use Mutual Compensation, the connection polarity must match that shown in the connection
diagram and the element must be Enabled in the settings.
Consider for example an A-phase to earth fault on one circuit of a parallel circuit. The positive sequence
impedance between the relaying point and the fault can be calculated using the following equation:

VA
Z F1 =
I A + kZN ⋅ I N + k Zm ⋅ I M

where:
● VA is the phase A voltage
● IA is the phase A current
● IN is the residual current of the protected line (derived from phase currents)

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P543i/P545i Chapter 5 - Configuration

● IM is the residual current of the parallel line (measured)

● kZN is the residual compensation coefficient
● kZm is the mutual compensation coefficient

In the above equation:

I N = I A + I B + IC

Z L 0 − Z L1
k ZN =
3Z L1

Zm0
k Zm =
3Z L1
where:
● ZL0 is the total zero sequence impedance of the line (a complex value)
● ZL1 is the total positive sequence impedance of the protected line (complex value)
● Zm0 is the zero sequence mutual impedance between the two circuits (complex value).

If used, you must set the mutual compensation feature kZm using the settings:
● kZm Mutual Set (the absolute value) and
● kZm Mutual Angle (the angle in degrees).

Note:
The following paragraph applies only to distance products and so may not be applicable to your model

In applications where the Mutual Compensation is used to reduce errors in the distance elements, a third setting,
Mutual Cut Off, is used for a fast dynamic control. The ratio IM/IN is compared with the Mutual Cut Off setting. If
the ratio is higher, mutual compensation is suppressed to prevent false-tripping for faults on the parallel line.
Typically a Mutual Cut Off factor of 1.5 is chosen to give a good margin of safety between the requirements of
correct mutual compensation for faults on the protected circuit whilst avoiding maloperations for faults on the
parallel circuit.

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Chapter 5 - Configuration P543i/P545i

5 DATE AND TIME CONFIGURATION

The date and time setting will normally be updated automatically by the chosen UTC (Universal Time Co-
ordination) time synchronisation mechanism when the device is in service. You can also set the date and time
manually using the Date/Time cell in the DATE AND TIME column.

5.1 USING AN SNTP SIGNAL

When using SNTP to maintain the clock, the IED must first be connected to the SNTP server, which should be
energized and functioning.
1. In the DATE AND TIME column, check that either the Primary Source or Secondary Source setting is set to
SNTP.
2. Ensure that the IED is receiving valid time synchronisation messages by checking that the SNTP Status cell
reads Server 1 OK or Server 2 OK.
3. Check that the Act. Time Source cell reads SNTP. This indicates that the IED is using PTP as the source for
its time. Note that If IRIG-B or PTP have been selected as the Primary Source, these must first be
disconnected before the device can switch to SNTP as the active source.
4. Once the IED is using SNTP as the active time source, adjust the time offset of the universal coordinated
time on the SNTP Server equipment, so that local time is displayed.
5. Check that the time, date and month are correct in the Date/Time cell.

5.2 USING AN IRIG-B SIGNAL

When using IRIG-B to maintain the clock, the IED must first be connected to the timing source equipment (usually a
P594), which should be energized and functioning.
1. In the DATE AND TIME column, check that either the Primary Source or Secondary Source setting is set to
IRIG-B.
2. Ensure the IED is receiving the IRIG-B signal by checking that IRIG-B Status cell reads Active
3. Check that the Act. Time Source cell reads IRIG-B. This indicates that the IED is using IRIG-B as the
source for its time. Note that If SNTP or PTP have been selected as the Primary Source, these must first be
disconnected before the device can switch to IRIG-B as the active source.
4. Once the IED is using IRIG-B as the active time source, adjust the time offset of the universal coordinated
time (satellite clock time) on the satellite clock equipment, so that local time is displayed.
5. Check that the time, date and month are correct in the Date/Time cell. The IRIG-B signal does not contain
the current year so this also needs to be set manually in this cell.
6. If the auxiliary supply fails, the time and date are maintained by the auxiliary battery. Therefore, when the
auxiliary supply is restored, you should not have to set the time and date again. To test this, remove the
IRIG-B signal, and then remove the auxiliary supply. Leave the device de-energized for approximately 30
seconds. On re-energization, the time should be correct.
7. Reconnect the IRIG-B signal.

5.3 USING AN IEEE 1588 PTP SIGNAL

When using IEEE 1588 PTP to maintain the clock, the IED must first be connected to the PTP Grandmaster, which
should be energized and functioning.
1. In the DATE AND TIME column, check that either the Primary Source or Secondary Source setting is set to
PTP.
2. Set the Domain Number setting. The domain defines which clocks the IED will use for synchronisation.
Therefore this number must match the domain used by the other clocks on the network.

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3. Ensure that the IED is receiving valid time synchronisation messages by checking that the PTP Status cell
reads Valid Master.
4. Check that Act. Time Source cell reads PTP. This indicates that the IED is using PTP as the source for its
time. Note that If IRIG-B or SNTP have been selected as the Primary Source, these must first be
disconnected before the device can switch to PTP as the active source.
5. Once the IED is using PTP as the active time source, adjust the time offset of the universal coordinated time
on the Master Clock equipment, so that local time is displayed.
6. Check that the time, date and month are correct in the Date/Time cell.

5.4 WITHOUT A TIMING SOURCE SIGNAL

If the time and date is not being maintained by an IRIG-B, PTP or SNTP signal, in the DATE AND TIME column, ensure
that both the Primary Source and Secondary Source are set to NONE.
1. Check that Act. Time Source cell reads Free Running.
2. Set the date and time to the correct local time and date using the Date/Time cell or the serial protocol.
3. If the auxiliary supply fails, the time and date are maintained by the auxiliary battery. Therefore, when the
auxiliary supply is restored, you should not have to set the time and date again. To test this, remove the
auxiliary supply. Leave the device de-energized for approximately 30 seconds. On re-energization, the time
should be correct.

5.5 TIME ZONE COMPENSATION

The UTC time standard uses Greenwich Mean Time as its standard. Without compensation, the date and time
would be displayed on the device irrespective of its location.
You may wish to display the local time corresponding to its geographical location. You can do this with the settings
LocalTime Enable and LocalTime Offset.
The LocalTime Enable has three setting options; Disabled, Fixed, and Flexible.
With Disabled, no local time zone is maintained. Time synchronisation from any interface will be used to directly
set the master clock. All times displayed on all interfaces will be based on the master clock with no adjustment.
With Fixed, a local time zone adjustment is defined using the LocalTime Offset setting and all non-IEC 61850
interfaces, which uses the Simple Network Time Protocol (SNTP), are compensated to display the local time.
With Flexible, a local time zone adjustment is defined using the LocalTime Offset setting. The non-local and
non-IEC 61850 interfaces can be set to either the UTC zone or the local time zone. The local interfaces are always
set to the local time zone and the Ethernet interface is always set to the UTC zone.
The interfaces where you can select between UTC and Local Time are the serial interfaces RP1, RP2, DNP over
Ethernet (if applicable) and Tunnelled Courier (if applicable). This is achieved by means of the following settings,
each of which can be set to UTC or Local.:
● RP1 Time Zone
● RP2 Time Zone
● DNPOE Time Zone
● Tunnel Time Zone

The LocalTime Offset setting allows you to enter the local time zone compensation from -12 to + 12 hours at 15
minute intervals.

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Chapter 5 - Configuration P543i/P545i

5.6 DAYLIGHT SAVING TIME COMPENSATION

It is possible to compensate for Daylight Saving time using the following settings
● DST Enable
● DST Offset
● DST Start
● DST Start Day
● DST Start Month
● DST Start Mins
● DST End
● DST End Day
● DST End Month
● DST End Mins

These settings are described in the DATE AND TIME settings table in the configuration chapter.

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6 SETTINGS GROUP SELECTION

You can select the setting group using opto inputs, a menu selection, and for some models the hotkey menu or
function keys. You choose which method using the Setting Group setting in the CONFIGURATION column. There are
two possibilities; Select via Menu, or Select via PSL. If you choose Select via Menu, you set the settings group using
the Active Settings setting or with the hotkeys. If you choose Select via PSL , you set the settings group with DDB
signals according to the following table:

SG Select 1X SG Select X1 Selected Setting Group

0 0 1
0 1 2
1 0 3
1 1 4

Each setting group has its own PSL. Once a PSL configuration has been designed it can be allocated to any one of
the 4 setting groups. When downloading or extracting a PSL configuration, you will be prompted to enter the
required setting group to which it will allocated.

P54x1i-TM-EN-1 95
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96 P54x1i-TM-EN-1
 CHAPTER 6

CURRENT DIFFERENTIAL PROTECTION

Chapter 6 - Current Differential Protection P543i/P545i

98 P54x1i-TM-EN-1
P543i/P545i Chapter 6 - Current Differential Protection

1 CHAPTER OVERVIEW
This product provides biased, phase-segregated, numerical Current Differential protection.
This chapter introduces the principles and theory behind Current Differential protection and describes how they
are implemented in this product. Guidance for applying this protection is also provided.
The current differential protection is enabled by default, but it can be disabled if you don’t want to use it. The
current differential protection needs digital communications links to exchange the values of current between the
terminals in the scheme.

This chapter contains the following sections:

Chapter Overview 99
Current Differential Protection Principle 100
Synchronisation of Current Signals 102
Phase Current Differential Protection 105
Neutral Current Differential Protection 108
Three-Terminal Schemes 109
Transient Bias 111
Capacitive Charging Current Compensation 112
CT Compensation 113
Feeders with In-Zone Transformers 114
Current Differential Intertripping 123
Stub Bus Differential Protection 124
Application Notes 125

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2 CURRENT DIFFERENTIAL PROTECTION PRINCIPLE

Current differential protection is based on Kirchoff’s Law. It generally uses the Merz-Price principle in which the
sum of the currents entering the protected zone should equal the sum of the currents leaving the protected zone.
A difference between these currents is known as differential current. If the differential current exceeds a threshold,
then a protection device may be required to trip. If the differential current is below the threshold then it is expected
to restrain.
Errors caused by mis-match of the current transformers at the different terminals, or saturation of the current
transformers during external faults could lead to false tripping under healthy conditions. For that reason a
restraining quantity is normally applied so that when the magnitude of the current in the system rises, so the level
of differential current necessary to cause a trip rises. The level of restraint applied is called a bias quantity and its
relationship to the operate quantity is called a Biased Differential characteristic.
Current differential protection does not need voltage transformer inputs, but they can be employed to enhance the
protection, control, automation, and supervision features of this product for certain applications.
To provide current differential protection of transmission lines and distribution feeders, it is normal practice to have
similar devices at each terminal with interconnecting communications links to exchange current signal
information between terminals.
When applying numerical current differential to protection of transmission lines and distribution feeders, as well as
communicating details of the local current measurements, the product also communicates timing, status, and
control data to remote terminals. The current, timing, status, and control data are encapsulated into messages
(sometimes referred to as telegrams) which are transmitted frequently and regularly. The timing data is used to
align local and remote current measurements. The control and status data is used for purposes such as
intertripping. Messages are secured by an address field as well as a cyclic redundancy check code (CRC code). The
use of the address field ensures that only the intended receiving device will respond to the message. Corruption of
the data in the messages could potentially cause the product to trip incorrectly. The use of the CRC code together
with other error checking prevents this.

2.1 NUMERICAL CURRENT DIFFERENTIAL PROTECTION

At each terminal in the scheme the power system current input quantities are acquired, converted into numerical
values, filtered, and compared with current input values from the other terminal(s) in the scheme.
For each phase, and at each terminal, the vector sum of the currents entering the protected zone is calculated.
This is known as the Differential current and provides an operating quantity. Also calculated is the scalar sum of
the same currents, of which a proportion is used as a restraining quantity. This is known as the bias current. To
determine whether tripping should occur, the Differential Current is compared with a percentage of the Bias
Current. If it is exceeded then a trip can be initiated.
The Differential and Bias currents are calculated on a per phase basis, and the tripping decision is made on a per
phase basis. However, the Bias current used in the calculation is the same for all three phases and is based on the
highest of the Bias currents calculated for each phase. This is called Maximum Bias and improves discrimination
for single phase faults.
Some products also perform differential protection on the neutral current. A similar biasing principle is applied, but
the characteristic is generally different.
Products are available to protect two-terminal and three-terminal lines and feeders. Models are therefore available
with one or two communications channels for the Current Differential protection function. Models with two
channels can be used to protect two-terminal or three-terminal feeders. In both of these cases, inherent
communications redundancy assures integrity of the protection in the event of a single communication link failure.
With a single communications channel, the application is restricted to the protection of two terminal lines and the
protection is compromised if the communication channel fails.
The tripping characteristics for two-terminal and three-terminal applications are similar, but two-terminal
applications use two current values for the evaluation of the Bias and Differential currents, whereas three-terminal

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P543i/P545i Chapter 6 - Current Differential Protection

applications use three current values (one from each terminal) for the evaluation of the Bias and Differential
currents.
Line differential protection requires the comparison of power system quantities taken at the different line
terminals. For a meaningful comparison, synchronisation of the current signals is needed so that they are related
to a common time reference. Different methods are used to achieve current signal synchronisation – some
requiring external time reference signals, and some using internal timing signals.

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3 SYNCHRONISATION OF CURRENT SIGNALS

To ensure accuracy of the calculation of the differential current, the locally derived current values and the values
derived from inputs at remote terminals must be aligned to a common time reference before the differential
calculations are made. This process is called ‘Time Alignment’ or ‘Synchronisation’
Synchronism could be achieved by using accurate time signals from sources such as atomic clocks or the Global
Positioning Satellite (GPS) system. This product can synchronise using a GPS input, and this is recommended for
schemes using communications that may be subject to switching. For many applications, however, this is not
necessary, and the product can self-synchronise using a technique known as “ping-pong”.

3.1 TIME ALIGNMENT USING PING-PONG TECHNIQUE

The following figure demonstrates the ping-pong technique for a two-terminal protection scheme. the two
terminals are referred to as “End A” and “End B”.

Protected line
X X
A B
Digital communications link
End A End B

Measure sampling time Propagation delay time

tB3* = (tA - tp2) tp1 = tp2 = 1/2 (tA* - tA1 - td)

Curren
tA1 t vecto tB1
rs
tp1 tA1
tA2
tB2
tB*
tA3
td
tB3* tB3
tA4 rs
t vecto
tp2 Curren tB4
tA5 1 td
tA* tB3 tA tB5

tA1, tA2 sampling instants of relay A

tB1, tB2 sampling instants of relay B
tp1 Propagation delay time from relay A to B
tp2 Propagation delay time from relay B to A
td time between the arrival of message tA1
tA* at relay B and despatch of message tB3
tB* arrival time of message tA1 at relay B
tB3* the measured sampling time of tB3 by relay A
E02606

Figure 34: Ping-pong measurement for alignment of current signals

The device at End A samples its current signals at times tA1, tA2, etc. The device at End B samples its current
signals at time tB1, tB2, etc. The sampling of the signals at the two ends are not synchronised, but both operate in
the same way. The filtering and processing of the current inputs produces current vectors together with timing
information, which are sent between devices as shown in the figure.

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P543i/P545i Chapter 6 - Current Differential Protection

At time tA1, End A sends a data message to End B. The message contains a time tag, tA1, plus other timing,
control, and status information as well as the calculated current values. The message arrives at End B after a
channel after a propogation delay time tp1. End B registers the arrival time of the message as tB*.
Since the devices at both terminals operate in the same way, End B also sends messages to End A. In the figure,
End B sends a message at tB3. The message contains the time tag tB3. It also returns the last received time tag
from End A (tA1) and the delay time, td, between the time of the the message was received, tB*, and the sampling
time, tB3, where td = (tB3 - tB*).
The message arrives at End A after a channel propagation delay time, tp2. The arrival time is registered by End A
as tA*. From the returned time tag, tA1, End A can measure an elapsed time as (tA* - tA1). This equals the sum of
the propagation delay times, tp1, and tp2, as well as the time between End B receiving the message and returning
it. So:
(tA* - tA1) = (td + tp1 + tp2)
The device assumes that the time to communicate data between two terminals is the same in each direction, and
on this basis tp1 and tp2 can be calculated as:
tp1 = tp2 = ½(tA* - tA1 - td)
The propagation delay time is measured for each received message. This is used to monitor changes on the
communication link and to manage the response of the protection. When the propagation delay time has been
calculated, the sampling instant of the received data from End B (tB3*) can also be calculated. As shown in the
figure, the sampling time tB3* is measured by End A as:
tB3* = (tA* - tp2)
In the figure, tB3* is between tA3 and tA4. To calculate the differential and bias currents, the values at each
terminal must correspond to the same point in time. So the values received at tB3* must be aligned with values
taken at sampling instants tA3 and tA4. This is achieved by rotating the received current vector by an angle
corresponding to the time difference between tB3* and tA3 (and tA4).
After this time-alignment process, the respective differential and bias currents can be calculated.

3.2 GPS SYNCHRONISATION

In schemes where protection communications operate over switched communication channels, there is a
possibility of asymmetry of communications channels between connected terminals. The term “asymmetry” is
used to describe an application in which the time taken to communicate information between a pair of connected
terminals is different in one direction to the other.
If the communication between devices is asymmetric, the ping-pong method of synchronisation may not work
correctly, so the products are equipped with features designed to provide stability for asymmetric
communications.
To overcome the shortcomings of the ping-pong technique, each device provides a GPS input, which can be used
together with an appropriate synchronising device (e.g. P594). GPS synchronisation works with asymmetric
communications paths.
The GPS synchronisation device produces a synchronisation signal that can be connected to the protection device
via optical fibre. If you have an application that needs GPS synchronisation, you must connect the GPS
synchronisation input on the protection, and you must enable the function using the GPS Sync setting in the PROT
COMMS/ IM64 column.
The figure below shows the different propagation delays and how compensation is applied. The GPS
synchronisation compensates for the different delays associated with the transmit and receive communication
paths.

P54x1i-TM-EN-1 103
Chapter 6 - Current Differential Protection P543i/P545i

ta

tA1 tB1

tA2 tp 1
tB2
tB*
tc
tA3 tB3
tB3* td

tA4 tB4
tp 2

tA5
tB5
tA*
tA6 tB6

Relay A Relay B
E02607

Figure 35: Asymmetric propogation delay times

The GPS synchronised values at terminal A (tA1, etc.) can be individually compared with those at terminal B (tB1,
etc.) to derive the bias and differential currents. The propagation delay times are not required for the derivation of
the bias and differential currents, but they can be calculated individually as tp1, and tp2, and they are stored for
potential use if GPS synchronisation fails.

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4 PHASE CURRENT DIFFERENTIAL PROTECTION

By appropriate model selection, current differential protection can be provided for two-terminal or three-terminal
feeders. Products that have two protection communications channels fitted can be applied to the protection of
three-terminal applications.
To uniquely identify the different terminals in a scheme, a naming convention is used in the product. It uses the
terms ‘Local’ and ‘Remote’. ‘Local’ is applied to the device being described. ‘Remote’ refers to a connected device.
For a two-terminal application, the remote device is referenced in the MEASUREMENTS 3 column, etc., as ‘Remote
1’. When a third terminal is included it is referenced as ‘Remote 2’, connected to the protection communication
channel 2.
So, for a three terminal scheme, the reference terminal is the Local terminal, and it connects to Remote 1 via
communications channel 1, and to Remote 2 via communications channel 2.
At each device in the scheme, the remote current measurements received through the communications links are
processed and compared with the local signals to derive the differential current and bias current values on a per-
phase basis.
Derivation of the differential and bias currents needs to use local and remote current measurements taken at the
same point in time, but the sampling of the current signals of these devices is not directly synchronised. If not
corrected, this would cause errors. Correction is also needed to compensate for the delays involved in
communicating measurements between terminals. This compensation process is called “time alignment”. The
time-alignment process transposes remote current measurements to align them to local ones. After time
alignment of the remote current measurements to the local current measurements the differential and bias
currents can be calculated as:
● Differential current (IDiff) = vector summation of all currents entering the protected zone
● Bias current (IBias) = half the scalar sum of the currents entering the protected zone.

The differential and bias currents are compared against a tripping criterion which is defined by a dual-slope
characteristic as shown below. The figure shows the tripping criteria for protection of a three-terminal feeder, but
the principle is similar for a two-terminal feeder.

I diff

Phase K2 slope For a three-terminal feeder where:

200% slope Operate I1 = Ilocal
I2 = Iremote1
I3 = Iremote2
I diff  I 1  I 2  I 3
Phase K1 Slope I1  I 2  I 3
I bias 
Restrain 2
Idiff min
Phase IS1

Phase IS2 Ibias

V02605

Figure 36: Dual slope current differential bias characteristic

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Chapter 6 - Current Differential Protection P543i/P545i

4.1 PHASE CURRENT DIFFERENTIAL TRIPPING CRITERIA

The phase current differential characteristic is defined by four settings:
● Phase Is1: The basic differential current setting which determines the minimum pick-up level of the
protection.
● Phase k1: The lower percentage bias setting used when the bias current is below the Phase Is2 setting. This
provides stability for small CT mismatches, while ensuring good sensitivity to resistive faults under heavy
load conditions.
● Phase Is2: A bias current threshold setting, above which the higher percentage bias setting Phase k2 is
used.
● Phase k2: The higher percentage bias setting used to improve protection stability under heavy through fault
current conditions.
The tripping criteria is defined by the bias characteristic graph. Basically if the differential current is above the line,
the protection will trip. If it is below, the protection will restrain.
When the phase-differential protection issues a trip command, it sends a per-phase ‘differential intertrip’ signal to
the remote terminals to instruct them to trip their circuit breakers. This is to ensure that all ends of the protected
line trip, even for marginal fault conditions.
For grading with other protection, the phase differential protection trip signal can be time delayed using either a
definite time, or an inverse time characteristic. By default, the delay characteristic is set to definite time with a zero
second delay, resulting in instantaneous tripping.
Since differential and bias current calculations are made on a per-phase basis, the values vary on a per-phase
basis. For optimum stability the highest value of the three-phase bias currents is used to restrain all three phases.

Minimum Trip Level

The minimum trip current level (Idiff min) is a function of Phase Is1 and Phase k1 as shown in the following
calculation (note: Phase Is1 and Phase k1 have been shortened to just Is1 and k1 for clarity).
Idiff = k1(Ibias) + Is1 ...
Idiff = (k1)(0.5Idiff) + Is1 ...
Is1 = Idiff - k1.0.5Idiff = Idiff(1 - 0.5k1) ...
Idiff = Is1/(1 - 0.5k1)
if k1 has a value of 30% for example, this means that the minimum trip current is 1.176Is1.

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4.2 PHASE CURRENT DIFFERENTIAL PROTECTION LOGIC

Permit Cdiff SD
582
Q 1 Diff Trip
1 R 738
IDiff>Start A
& t
Phase A Operate threshold 583
& Diff Trip A
reached
0
Send Diff Intertrip A

739
IDiff>Start B
& t
Phase B Operate threshold 584
& Diff Trip B
reached
0
Send Diff Intertrip B

740
IDiff>Start C
& t
Phase C Operate threshold 585
& Diff Trip C
reached
0
Send Diff Intertrip C
Receive Inhibit C Diff
1145
1
Inhibit C Diff
Send Inhibit C Diff

586
Phase Time Delay 1 Diff Intertrip
587
Receive Diff Intertrip A Diff Intertrip A

588
Receive Diff Intertrip B Diff Intertrip B

589
Receive Diff Intertrip C Diff Intertrip C

V02616

Figure 37: Phase Current Differential Protection logic

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Chapter 6 - Current Differential Protection P543i/P545i

5 NEUTRAL CURRENT DIFFERENTIAL PROTECTION

In products that feature distance back-up protection, Neutral Current Differential protection is provided to clear
high-resistive earth faults which may be below the Phase Current Differential sensitivity limit.
If you wish to use the Neutral Current Differential protection you must enable it using the In Diff setting under the
NEUTRAL DIFF subheading of the CURRENT DIFF column.
The Neutral Current Differential protection can be very sensitive. Before it is allowed to operate, certain criteria
must be met:
● The operation of the Neutral Current Differential is time delayed compared with the phase current
differential protection to provide discrimination. Operation can be delayed further by setting the In Diff Time
setting. With the In Diff Time cell set to 0 (instantaneous), the operating time for the Neutral Current
Differential element will be at its minimum and typically will range between one-and-a-half and two-and-a-
half cycles of power system frequency.
● Operation of the Neutral Current Differential protection is blocked or inhibited for the following cases
○ A Phase Current Differential element has started.
○ A Distance protection element has started.
○ A Current Differential CTS element has blocked.
○ A Second Harmonic blocking detector has picked up
○ The device has detected that one or more of the circuit breaker (or isolator) poles are open.
● An External Inhibit condition using an opto-isolator mapped by the PSL is asserted.

The characteristic is determined by three protection settings. You can change the settings, but we strongly
recommend retaining the default values, which are as follows:
● In Diff Is1 = 0.1 pu
● In Diff Is2 = 2.0 pu
● In Diff k1 = 10%
This provides stability for small CT mismatches, while ensuring good sensitivity to resistive faults under heavy load
conditions.

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6 THREE-TERMINAL SCHEMES
Products that have two protection communications channels fitted can be applied to the protection of three-
terminal applications.
By appropriate model selection, current differential protection can be provided for two-terminal or three-terminal
feeders. A naming convention is used featuring the terms ‘Local’ and ‘Remote’. ‘Local’ is applied to the device being
described. ‘Remote’ refers to a connected device. For a two-terminal application, the remote device is referenced
in the MEASUREMENTS 3 column as ‘Remote 1’. When a third terminal is included it is referenced as ‘Remote 2’.
Sometimes what is expected to be a three-terminal scheme may need to operate as a two-terminal scheme (this
may be due to a line end being taken out for maintenance, or it may be that the line end has still to be added). In
such a case, it is possible to reconfigure the protection devices to perform as a two-terminal application. The
device that has been configured-out can be removed from the system without any alarms being raised. This
reconfiguration can be done from any of the terminals in the protection scheme, but it is generally performed at
the terminal being configured out, as it requires an interlock that is associated with the isolator at that terminal. If
you intend to use this feature you might need to create and use customised PSL files and the product must be set
up for three-terminal operation.
To reconfigure a scheme from three-terminal to two-terminal you use the Re-Configuration setting in the PROT
COMMS/IM64 column. Before you can change a configuration, two interlocking criteria need to be satisfied: The
Inhibit C Diff and Recon Interlock DDB signals (455, 456 respectively) need to be asserted. The Inhibit C Diff DDB
signal is mapped by default to one of the opto-isolated inputs and is used to ensure stability during the
reconfiguration. According to the particular model being used, the Recon Interlock DDB signal might not be
mapped by default. To reconfigure a scheme from three-terminal to two-terminal, the DDB signal must be mapped
to an opto-isolated input using the PSL. This signal is intended to be connected to reflect the state of the
switchgear at the terminal that is being taken out of service (The rationale being that if the line is open, current
does not flow and so the scheme can be protected as a two-terminal line).

Note:
The line end to be ‘configured out’ must be open before issuing a reconfiguration command. If this is not done, any current
flowing in or out of the ‘configured out’ end will be seen as fault current and when the Inhibit C Diff’input is removed, it might
cause the other devices to operate.

Reconfiguration is only permitted if all three devices are energised and communicating correctly with each other.
Four values are available for the Re-Configuration setting:
● Three Ended (stay as three-ended)
● Two Ended(L&R1) (Local + Remote 1)
● Two Ended(L&R2) (Local + Remote 2)
● Two Ended(R1&R2) (Remote 1 + Remote 2)

If the reconfigured scheme incorporates the local device, the trip outputs of the differential protection will continue
to be inhibited until the Inhibit C Diff signal at the local device is cleared. If the new reconfiguration scheme only
incorporates the remote devices, the differential protection at the remote devices are not inhibited because they
will ignore all commands from the local device unless it is a command for reconfiguration.
Setting the Re-Configuration setting to Three Ended at any terminal will restore three-terminal operation
without regard to the status of the Inhibit C Diff DDB signal or the Recon Interlock DDB signal.
The operation of the change configuration logic is as follows:
● The reconfiguration setting is changed.
● The product detects the change in setting and attempts to implement the new setting.
If the current configuration is Two-Ended and the new setting is also Two-Ended, the device blocks the change and
issues a configuration error alarm.

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Chapter 6 - Current Differential Protection P543i/P545i

If the current configuration is Two-Ended and the new setting is Three-Ended, the device checks that all the
communications are healthy and sends out the restore command to the other devices. It then checks that the
scheme has stabilised as ‘Three-Ended’ after one second.
If any of the communications in the scheme were failed or if the scheme has not stabilised as Three-Ended, the
device returns to its original Two-Ended setting and issues a configuration error alarm.
If the scheme stabilises as Three-Ended, the Reconfiguration setting is updated.
If the device configuration is Three-Ended and the new setting is Two-Ended L & R1, the device first checks that the
two interlocks are energised. The differential tripping is blocked, but the backup protection can still operate the trip
outputs. The device then checks that the communication with Remote 1 is healthy and sends out the command to
the remote devices. It then checks that the scheme has stabilised as Two-Ended L & R1 after one second.
If the interlocks are not energised, or the communication with Remote 1 has failed, or the scheme does not
stabilise as Two-Ended L & R1, the device returns to Three-Ended and issues a configuration error alarm.
If the scheme stabilises as Two-Ended L & R1, the Reconfiguration setting is updated.
If the device configuration is Three-Ended and the new setting is Two-Ended L & R2, the device reacts similarly to a
Two-Ended L & R1 reconfiguration.
If the device configuration is Three-Ended and the new setting is Two-Ended R1&R2, the device reacts similarly to a
Two-Ended L & R1 reconfiguration.

6.1 THREE-TERMINAL SCHEME RECONFIGURATION ON ENERGISATION

This occurs when a device is energised and it tries to configure itself to be compatible with other devices in the
scheme. The scheme tries to maintain the configuration set by the user. However, there are certain conditions that
may prevent this from happening:
When powered on the device configuration depends on the following factors:
● The scheme currently configured on the remote devices
● The status of the communication links
● The configuration stored in non-volatile memory before power down

When the device is energised, the following events occur:

● The device checks whether any messages are being received. If so, then the configuration commands in the
first messages to arrive are used to configure the device. This is subject to certain conditions. If the device
receives a Two-Ended configuration instruction from one end and a Three-Ended configuration instruction
from the other end, it uses the Two-Ended instruction. If both incoming commands are Three-Ended, the
scheme stabilses as three-ended.
● If no messages arrive from either end, after one second the device assumes the configuration it had before
power down. Once messages begin to arrive again, the device checks them for validity against the current
scheme. If one device is Three-Ended and the other is Two-Ended, the configuration changes to Two-Ended.
If both are Three-Ended or both are the same Two-Ended scheme, that scheme becomes the configuration.
If two devices have different Two-Ended configurations, they are unable to determine which one to use and
each generates a configuration error alarm and each device remains in its current configuration. This
condition can be cleared by restoring the devices or by removing the supply to the device with the incorrect
configuration.
● If all the devices in a scheme are energised simultaneously, the configuration reverts to Three-Ended if all
the communication channels are healthy. This occurs because all the devices are waiting to be told their
configuration and all default to Three-Ended. This is a very unlikely event in normal use.
If a communication channel has only half failed (for example, the receive channel has failed but not the transmit
channel), there may be configuration errors on power up because the devices are not communicating correctly. If
the status is available from the third device and communications are healthy using its two channels, the scheme
stabilises correctly.

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7 TRANSIENT BIAS
Phase current differential protection stability for current transformers is assisted by a feature called Transient
Bias. This can be enabled or disabled with the transient Bias setting in the CURRENT DIFF column.
Saturation of current transformers (CTs) under heavy load or external fault conditions can cause the protection to
see differential current and could lead to tripping. Preventing CT saturation can impose high specifications and
high costs for the CTs. The Transient Bias feature allows the CT requirements to be relaxed – typically by 25%.
The Transient Bias feature recognises the changes in bias and differential currents under different conditions and
reacts as follows:
● For an internal fault, bias and differential currents start to increase together. For an external condition, bias
current will start to rise, but differential current will not. If CT saturation starts to occur for an external
condition, the differential current starts to increase after the bias current has increased.
● Detecting the relative changes in the bias and differential currents allows the device to detect whether the
differential current is due to an internal fault or due to an external condition causing CT saturation. For
external conditions, the biasing quantity is raised, transiently, to provide stability. For internal faults,
sensitivity is maintained.

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8 CAPACITIVE CHARGING CURRENT COMPENSATION

All electrical conductors, including feeders, are capacitively coupled to earth. When energised, a capacitive current
flows from the feeder to earth to charge the capacitance. The capacitance is distributed along the feeder, but for
analysis it can be modelled according with the following figure.

IL IR
ZL I L = Local end line current
I CHL ICHR I R = Remote end line current
VL VR VL = Local end voltage
VR = Remote end voltage
Z L = Line impedance
I CHL = Local end charging current
I CHR = Remote end charging current
V02608

Figure 38: Capacitive charging current

Both transient capacitive and steady-state capacitive charging currents exist. Transient inrush charging current
consists of predominately high-order harmonics, which are filtered out by the device. However, steady state AC
charging currents flow all the time that the feeder remains energised. This capacitive charging current appears as
a differential current. On long overhead lines, and on cable circuits, this capacitive charging current can be
sufficiently high to cause current differential elements to trip under healthy conditions and therefore needs to be
compensated.
To prevent maloperation due to capacitive charging currents, Phase Is1 would normally be set to at least 2.5 times
the charging current. This, however, reduces the sensitivity of the differential protection. If voltage input
connections are made, more effective compensation for capacitive charging current can be applied:
Using the voltage inputs and the line positive-sequence capacitive susceptance, the devices can calculate the
charging currents. These can then be taken into account before calculating the differential currents.
Referring to the figure above, we see that the line charging current at a particular location is equal to the voltage
at that location multiplied by the line positive sequence capacitive susceptance (Bs). The differential current is
therefore:
Idiff = IL + IR - (jVLBs/2) - (jVRBs/2) = {IL - (jVLBs/2)} + {IR - (jVRBs/2)}
The two terms in this equation represent one component that can be calculated at a local terminal and another
that can be calculated at a remote terminal. Using these values, rather than the actual phase current
measurements, will eliminate the effects caused by capacitive charging currents. So, for long line or cable
applications, if voltage transformers are connected, capacitive charging current compensation can be applied.
This is achieved by setting the Compensation setting in the CURRENT DIFF column to Cap Charging. This will
make visible a Susceptance setting into which the line positive sequence capacitive susceptance value can be
entereed.
When applied to a three-ended scheme with ends local (L), remote 1 (R1) and remote 2 (R2), the differential current
is calculated as:
Idiff = IL + IR1 + IR2 - (jVL Bs/3) - (jVR1Bs/3) - (jVR2Bs/3) = {IL - (jVLBs/3) } + {IR1 - (jVR1Bs/3) } + {IR2 -
(jVR2Bs/3)}
If the capacitive charging compensation is enabled, the current measurements in the MEASUREMENTS 3 column
display the compensated values.

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9 CT COMPENSATION
The primary and secondary ratios for the phase current transformers are set in the CT AND VT RATIOS column.
These settings are used to display the phase current quantities in the MEASUREMENTS 1 column. The device can
be set to display the input current either in primary values or in secondary values.
To ensure correct operation of the differential elements, it is important that under load and through fault
conditions, the currents into the differential elements of the devices balance. If the CTs have different ratios this will
not be the case. This product has CT ratio correction (magnitude compensation) to overcome this problem.
When calculating differential and bias currents, the devices use per-unit (p.u.) quantities. CT ratio compensation is
used to scale-up the current signals to match those of the remote terminals by setting an appropriate value in the
Ph CT Corr'tion setting in the CURRENT DIFF column. Because of dynamic limitations, this scaled-up value is
limited to 40 p.u. Values exceeding this are clipped at 40 p.u.
Similarly compensated per-unit values are used in the calculation of the differential and bias currents.
The per-unit compensated values of local and remote currents as well as the per-unit values of differential and
bias currents are scaled-down by the local CT ratio correction factor and displayed in the MEASUREMENTS 3
column.
The process is outlined in the figure below:

Transmission to
Secondary CT 40 p.u. clipping
correction

rating

Remote end
I ABC [Amps sec.] * 
I LOCAL [p.u.]
Vector

I LOCAL [p.u.]
* 1 / I CT rated CT_Correction

* CT_Ratio


I LOCAL [p.u.] 
calculations

I DIFF [p.u.]
Diff/Bias


I REMOTE 1 [p.u.]
Decision

 [p.u.]
I BIAS Trip, Intertrip
Measurements 1

Trip


I REMOTE 2 [p.u.]

Settings
* 1 / CT_Correction [Amps pri. or sec .] Settings [p.u.]
* 1 / ICT rated
Primary or Primary or
Secondary CT * ICT rated
Secondary CT
rating rating
Measurements 3
V02609

Figure 39: CT Compensation

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10 FEEDERS WITH IN-ZONE TRANSFORMERS

A transformer feeder comprises a transformer directly connected to a transmission circuit without the intervention
of switchgear. Although separate current transformer inputs may be available to allow separate overlapping zones
of protection for the transformer and the feeder this is not always the case and the transformer and the feeder
must be treated and protected as a single item of plant for protection. The integration of in-zone power
transformers into unit feeders causes further complications for current differential protection:
● Phase shift and possible imbalance of signals across the transformer
● Transfer of earth fault current by the transformer
● Magnetising Inrush current
● Overfluxing

This product therefore provides facilities to deal with the above issues by providing:
● CT compensation for phase shifts and imbalances across the transformer
● Zero sequence compensation.
● Magnetising Inrush detection and restraint
● Second harmonic blocking.
● Overfluxing detection and restraint
● Fifth harmonic blocking.

To make these available you need to enable the differential protection for an in-zone power transformer. This is
done on a per-setting group basis. The phase differential element (Phase Diff) for the setting group concerned
must be enabled.
To enable the transformer feeder protection you set the Compensation cell in the CURRENT DIFF settings to
Transformer.

10.1 CT PHASE CORRECTION

To compensate for any phase shift between two windings of a transformer, it is necessary to provide phase
correction. Phase correction is provided by specifying the vector group using the Vectorial comp setting in the
CURRENT DIFF column.
The phase compensation options are listed in the table below:
Setting Phase shift Action
Yy0 0 Do nothing
Ia = (IA - IC) / √3
Yd1 30 lag Ib = (IB - IA) / √3
Ic = (IC - IB) / √3
Ia = -IC
Yy2 60 lag Ib = -IA
Ic = -IB
Ia = (IB - IC) / √3
Yd3 90 lag Ib = (IC - IA) / √3
Ic = (IA - IB) / √3
Ia = IB
Yy4 120 lag Ib = IC
Ic = IA

Yd5 150 lag Yd11 and Invert

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Setting Phase shift Action

Yy6 180 lag Invert currents

Yd7 150 lead Yd1 and Invert

Ia = IC
Yy8 120 lead Ib = IA
Ic = IB

Yd9 90 lead Yd3 and Invert

Ia = -IB
Yy10 60 lead Ib = -IC
Ic = -IA
Ia = (IA - IB) / √3
Yd11 30 lead Ib = (IB - IC) / √3
Ic = (IC - IA) / √3
Ia = IA - (IA + IB + IC) / 3
Ydy0 0 Ib = IB - (IA + IB + IC) / 3
Ic = IC - (IA + IB + IC) / 3

Ydy6 180 lag Ydy0 and Invert

Where Ia, Ib, Ic are the uncorrected values and IA, IB, IC are the corrected values.

Note:
You must set Compensation to Transformer before the Vectorial Comp setting becomes visible.

10.2 ZERO SEQUENCE FILTERING

In addition to compensating for the phase shift of the protected transformer, it is also necessary to mimic the
distribution of primary zero sequence current in the protection scheme. The figure below shows the need for zero
sequence current filtering for differential protection across a transformer. The power transformer delta winding
acts as a ‘trap’ to zero sequence current. This current is only seen on the star connection side of the transformer
and therefore as differential current.

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Chapter 6 - Current Differential Protection P543i/P545i

I0

IR1 I0 IR2

IED1 IED2
Digital communication channel

IED1 IED2

IR1 = 0 IR2 = I0
IR2 = I0 Received IR1 = I0
Received
Idiff = I0 Idiff = I0
E02611

Figure 40: The need for zero-sequence current filtering

Where a transformer winding can pass zero sequence current to an external earth fault, it is essential that some
form of zero sequence current filtering is used. This would also be applicable where in zone earthing transformers
are used. In this product, zero sequence current filtering is automatically implemented in software when a delta
connection is set for the vector compensation.

10.3 MAGNETISING INRUSH RESTRAINT

Whenever there is an abrupt change of magnetising voltage (e.g. when a transformer is initially connected to a
source of AC voltage), there may be a substantial surge of current through the primary winding called inrush
current.
In an ideal transformer, the magnetizing current would rise to approximately twice its normal peak value as well,
generating the necessary MMF to create this higher-than-normal flux. However, most transformers are not
designed with enough of a margin between normal flux peaks and the saturation limits to avoid saturating in a
condition like this, and so the core will almost certainly saturate during this first half-cycle of voltage. During
saturation, disproportionate amounts of MMF are needed to generate magnetic flux. This means that winding
current, which creates the MMF to cause flux in the core, could rise to a value way in excess of its steady state
peak value. Furthermore, if the transformer happens to have some residual magnetism in its core at the moment
of connection to the source, the problem could be further exacerbated.
The following figure shows the magnetizing inrush phenomenon:

116 P54x1i-TM-EN-1
P543i/P545i Chapter 6 - Current Differential Protection

+Fm

Steady state

-Fm

2Fm

Switch on at voltage
zero – No residual flux

V = Voltage, F = Flux, Im = magnetising current, Fm = maximum flux

V03123

Figure 41: Magnetising inrush phenomenon

The main characteristics of magnetising inrush currents are:

● Higher magnitude than the transformer rated current magnitude
● Containing harmonics and DC offset
● Much longer time constant than that of the DC offset component of fault current

We can see that inrush current is a regularly occurring phenomenon and should not be considered a fault, as we
do not wish the protection device to issue a trip command whenever a transformer is switched on at an
inconvenient point during the input voltage cycle. This presents a problem to the protection device, because it
should always trip on an internal fault. The problem is that typical internal transformer faults may produce
overcurrents which are not necessarily greater than the inrush current. Furthermore, faults tend to manifest
themselves on switch on, due to the high inrush currents. For this reason, we need to find a mechanism that can
distinguish between fault current and inrush current. Fortunately, this is possible due to the different natures of the
respective currents. An inrush current waveform is rich in harmonics, especially 2nd harmonics, whereas an
internal fault current consists only of the fundamental. We can therefore develop a restraining method based on
the 2nd harmonic content of the inrush current. The mechanism by which this is achieved, is called second
harmonic blocking.

10.3.1 SECOND HARMONIC RESTRAINT

When set to protect feeders with in-zone transformers, this product measures the second harmonic components
of the input currents to detect magnetising inrush, which can be used to modify operation of the current
differential protection.

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Chapter 6 - Current Differential Protection P543i/P545i

Using the Inrush Restraint setting you can choose what will happen to differential characteristic in the presence of
second harmonic current:
● If set to Disabled, the characteristic will not be modified,
● If set to Restraint, the characteristic will be restrained if the second harmonic component is above a
user set threshold.
● If set to Blocking, the protection will be blocked
The Restraint and Blocking modes are qualified by other settings outlined below. In both cases an
unbiased high-set current differential element becomes visible.

Note:
You must set Compensation to Transformer before the Inrush Restraint setting becomes visible.

Note:
When used, the Inrush Restraint function must be enabled at all ends to avoid possible maloperation.

Note:
There is an Inrush Detection setting in the SUPERVISION column of the menu. The Inrush Detection setting is only visible if
the Inrush Blocking’in the CURRENT DIFF column is not being used. The function asserts the same DDB outputs as Inrush
Restraint and can be used to control other protection elements during magnetising inrush conditions. The output of Inrush
Detection does not, however, affect the Current Differential protection.

10.3.1.1 SECOND HARMONIC RESTRAINT

If the Inrush Restraint setting is set to Restraint, then a percentage of the second harmonic component of the
input signal is added to the bias quantity used in the current differential characteristic.
The amount of additional bias to be added into the calculation is defined by the following expression:
Additional bias = Ih(2) Multiplier * 1.414 * largest 2nd harmonic current
You can set Ih(2) Multiplier between 1 and 20 according to your application.

Note:
Where Inrush Restraint is used to restrain operation, it must be used at all terminals in the scheme to avoid possible
maloperation.

10.3.1.2 SECOND HARMONIC BLOCKING

If the Inrush Restraint setting is set to Blocking, then the operation of the current differential elements will be
blocked if magnetising inrush is detected.
Magnetising inrush is considered to be present if the level of phase current is above 5% In AND the ratio of
harmonic to fundamental in that phase exceeds the Ih(2) %> value which you set.
Detection of magnetising inrush forces a phase block signal to block local and remote ends.
You can choose whether to block just the affected phase, or to block all three phases using the Ih(2) CrossBlock
cell. If you disable Ih(2) CrossBlock, only the affected phase is blocked. If you enable Ih(2) CrossBlock, all phases
are blocked.

10.3.1.3 HIGH SET DIFFERENTIAL

It is possible for current transformers (CTs) to saturate under heavy internal fault conditions. CT saturation, like
magnetising inrush, is characterised by significant second harmonic components. The protection is required to

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remain stable for magnetising inrush conditions, but to operate for internal faults. To discriminate between the
two, an unrestrained high set differential protection is included. If Inrush Restraint is set either to Restraint or
to Blocking, an unrestrained high set differential protection becomes visible. It is provided to ensure rapid
clearance for heavy internal faults with saturated CTs. The element can be enabled or disabled according to the
HighSet Status setting in the CURRENT DIFF column. The pick-up value can be set between 4 In and 32 In (RMS
values) using the Id High Set cell.

Note:
The Id High Set cell should be set so that it is in excess of the anticipated inrush current after ratio correction has been
applied.

10.4 OVERFLUXING RESTRAINT

Sometimes the protected transformer is subject to overfluxing due to temporary overloading with a voltage in
excess of the nominal voltage, or a reduced voltage frequency. For example, when a load is suddenly
disconnected from a power transformer, the voltage at the input terminals of the transformer may rise by 10-20%
of the rated value. Since the voltage increases, the flux also increases. As a result, the transformer steady state
excitation current becomes higher. The resulting excitation current flows in one winding only and therefore
appears as differential current which may rise to a value high enough to operate the differential protection. A
typical differential current waveform during such a condition is as follows.

E03107

Figure 42: Typical overflux current waveform

Such waveforms have a significant 5th harmonic content. We can therefore develop a restraining method based
on the 5th harmonic content of the inrush current. The mechanism by which this is achieved, is called fifth
harmonic blocking.

10.4.1 FIFTH HARMONIC BLOCKING

A characteristic of overfluxing is that there is a strong fifth harmonic component associated.
When applied to the protection of transformer feeders, this product measures the fifth harmonic components of
the input currents to detect overfluxing. This detection can be used to block operation of the current differential
protection.
If the 5th Harmonic setting is enabled, then the operation of the current differential elements will be blocked if
overfluxing is detected.
Overfluxing blocking is implemented on a phase-by-phase basis. Blocking is prevented if the phase current is less
than 5% In. If the phase current exceeds 5% In, and the element is enabled, then if the ratio of fifth harmonic
current to the fundamental component exceeds the the Ih(5) %> setting, operation of the current differential is
blocked on that phase. Blocking of affected phases is applied both at local and at remote terminals.
You can choose whether to block just the affected phase, or to block all three phases using the Ih(5) CrossBlock
cell. If you disable Ih(5) CrossBlock, only the affected phase is blocked. If you enable Ih(5) CrossBlock, all phases
are blocked.

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10.5 LOGIC FOR FEEDERS WITH IN-ZONE TRANSFORMERS

Permit Cdiff
SD
Q
1 R

Phase A Operate LS &

& IDiff>Start A
threshold reached

Phase A Operate HS &

& IDiff>>Start A
threshold reached

Phase B Operate LS &

& IDiff>Start B
threshold reached

Phase B Operate HS &

& IDiff>>Start B
threshold reached

Phase C Operate LS &

& IDiff>Start C
threshold reached

Phase C Operate HS &

& IDiff>>Start C
threshold reached

Ih (2 ) Block A
1
Ih (5 ) Block A

Ih (2 ) Block B
1
Ih (5 ) Block B

Ih (2) Block C
1
Ih (5) Block C

Receive Inhibit C Diff

1
Inhibit C Diff
V 02617

Figure 43: Phase Current Differential Protection logic for feeders with in-zone transformers

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P543i/P545i Chapter 6 - Current Differential Protection

10.6 SECOND HARMONIC BLOCKING LOGIC

Phase A 2nd harmonic

threshold reached & Ih(2) Loc Blk A
Ih(2) Loc Blk A**
Phase B 2nd harmonic
threshold reached & Ih(2) Loc Blk B
Ih(2) Loc Blk B**
Phase C 2 nd harmonic
threshold reached & Ih(2) Loc Blk C
Ih(2) Loc Blk C**
Inrush Restraint
1
Blocking & Ih (2 ) Loc Cross Blk**

Ih(2) CrossBlock
1 Ih(2) Blk A
Enabled

1 Ih(2) Blk B

Ih (2) Rem1 Cross Blk* 1 Ih(2) Blk C

1
Ih(2) Rem2 Cross Blk*

Ih(2) Rem1 Blk A*

1 Ih(2) Rem Blk A
Ih(2) Rem2 Blk A*

Ih(2) Rem1 Blk B*

1 Ih(2) Rem Blk B
Ih(2) Rem2 Blk B*

Ih(2 ) Rem1 Blk C*

1 Ih(2) Rem Blk C
Ih(2 ) Rem2 Blk C*

* Internal signal sent in message

V02618 ** External signal sent in message

Figure 44: Second Harmonic Blocking logic

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Chapter 6 - Current Differential Protection P543i/P545i

10.7 FIFTH HARMONIC BLOCKING LOGIC

Phase A 5th harmonic

threshold reached & Ih(5) Loc Blk A
Ih(5) Loc Blk A**
Phase B 5th harmonic
threshold reached & Ih(5) Loc Blk B
Ih(2) Loc Blk B**
Phase C 5th harmonic
threshold reached & Ih(5) Loc Blk C
Ih(5) Loc Blk C**
Ih(5) Blocking
1
Enabled & Ih (5 ) Loc Cross Blk**

Ih(5) CrossBlock
1 Ih(5) Blk A
Enabled

1 Ih(5) Blk B

Ih (5) Rem1 Cross Blk* 1 Ih(5) Blk C

1
Ih(5) Rem2 Cross Blk*

Ih(5) Rem1 Blk A*

1 Ih(5) Rem Blk A
Ih(5) Rem2 Blk A*

Ih(5) Rem1 Blk B*

1 Ih(5) Rem Blk B
Ih(5) Rem2 Blk B*

Ih(5 ) Rem1 Blk C*

1 Ih(5) Rem Blk B
Ih(5 ) Rem2 Blk C*

* Internal signal sent in message

V02619 ** External signal sent in message

Figure 45: Fifth Harmonic Blocking logic

122 P54x1i-TM-EN-1
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11 CURRENT DIFFERENTIAL INTERTRIPPING

Eight freely assignable intertripping signals are provided by a facility called InterMICOM64, which is described in
the chapter on Fibre Teleprotection. In addition there are two intertripping functions associated directly with the
Current Differential protection. Both are operational when the phase current differential is enabled:
The first is a differential intertripping function whereby if one terminal sees a differential fault, as well as issuing a
local trip command it will also send a command to trip to remote terminals to ensure that the fault is isolated at all
terminals.
The second is a permissive intertripping function. A Permissive Intertripping function (PIT) is associated with the
current differential protection and is visible and active if the phase current differential protection is enabled.

Note:
The term “permissive intertripping” associated with this current differential protection is not the same as that commonly used
in teleprotection schemes. It is specific to this type of Current Differential protection implementation.

A device can be configured to send a permissive intertrip command over the protection communication channel.
To use this function you need to map the Perm Intertrip DDB signal to one of the opto-inputs using the PSL.

Protected line

Digital communication link Busbar

IED 1 IED 2
Permissive protection
Intertrip (PIT) 000 PIT = 1 000
Data message V02612

Figure 46: Permissive Intertripping example

Consider the above diagram. If a fault occurs as shown, it will be seen by the busbar protection which can trip its
local circuit breaker. The fault will not be seen by the differential protection, however, so the fault will continue to
be fed. An input signal from the busbar protection at the faulted end can be sent as a permissive intertrip (PIT)
command to a remote terminal to cause it to permissively trip the remote circuit breaker to clear the fault.
Tripping occurs if the current remains above the Phase Is1 setting of the phase current differential elements while
the PIT command is received. The condition must remain satisfied for a minimum time setting. The time is set in the
PIT Time setting in the CURRENT DIFF column. The permissive intertrip (PIT) timer can be set between 0 and 200
ms. This time should be set to provide discrimination with other protection devices. For example, if there is a
genuine busbar fault, the time delay should be set to allow busbar protection to clear the fault. A typical setting
may be 100 to 150 ms.
You can choose whether to use the local current value sent with the PIT command to make the decision at the
remote end, or whether to use the remote current value at the receiving end for the decision. This choice is made
using the PIT I selection setting in the CURRENT DIFF column.

Note:
The permissive intertripping function always trips three-phase.

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12 STUB BUS DIFFERENTIAL PROTECTION

This product can provide stub-bus protection associated with the differential protection.
If you wish to use this feature you must ensure that the current differential protection is enabled. You will need to
map one of the opto-isolated inputs to the DDB Stub Bus Enabled using the programmable scheme logic and you
will need to enable the feature by setting Ph Diff Stub Bus in the CURRENT DIFF column to Enabled.
When the stub bus protection is enabled and activated by energisation of the opto-isolated input, the differential
protection is disabled. No differential trip signals will be issued by the affected terminal. No differential intertrip
signals will be issued, or acted upon by the affected terminal. No permissive intertrip signals will be issued, or
acted upon by the affected terminal. Intertripping signals mapped via IM64 will be acted upon, and the affected
terminal remains active to protect the isolated stub bus.
For products having two sets of CT inputs, the stub bus protection takes the two sets of current inputs and uses
them as inputs to the phase differential current protection. The values are compared against the dual slope
characteristics to determine whether tripping should occur or not.
For products having a single set of CT inputs, an additional setting (Ph Is1 StubBus) is provided. In these
applications, if the stub-bus feature is enabled and activated, the protection will trip if the measured current
exceeds the Ph Is1 StubBus setting.
Tripping due to the operation of the stub-bus protection is always three-phase.
The principle is outlined in the figure below:

To busbar 1

Communication channel End Y

CTX1 P54x P543/5

CT Y
End X
Protected line

CTX2

To busbar 2 V02614

Figure 47: Stub Bus protection

Note:
Models having distance protection feature a phase segregated stub bus protection associated with the distance protection
elements. Where applicable these are described along with the distance elements.

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13 APPLICATION NOTES

13.1 SETTING UP THE PHASE DIFFERENTIAL CHARACTERISTIC

The biased phase current differential characteristic is defined by four protection settings. Each can be set
independently. This flexibility allows the characteristic to be set for particular sensitivity and current transformer
requirements. To simplify setting the protection, however, we strongly recommend three of the settings be fixed as:
● Phase Is2 = 2.0 pu
● Phase k1 = 30% (This provides stability for small CT mismatches, while ensuring good sensitivity to resistive
faults under heavy load conditions
● Phase k2 = 150% (For 2 terminal applications to provides stability under heavy through fault current
conditions)
● Phase k2 = 100% (For 3 terminal applications to provides stability under heavy through fault current
conditions)
These settings give a characteristic suitable for most applications so that only the Phase Is1 setting needs
changing from the default value.
Phase Is1 is the setting which determines the minimum pick-up of the phase current differential elements. This
value should be set to account for any mismatch between the current transformers at the different terminals, as
well the capacitive charging current if this is not compensated.
If voltage inputs are connected, the charging current can be compensated for. To do this you need to set the
Compensation setting in the CURRENT DIFF column to Cap Charging and then programme the line positive
sequence capacitive susceptance value into the Susceptance setting now apparent in the CURRENT DIFF column.
If Cap Charging is selected, Phase Is1 may be set below the value of line charging current. We recommend that
you choose Phase Is1 only sufficiently below the charging current to offer the required fault resistance coverage
as now described.
The table below shows some typical steady state charging currents for various lines and cables.
Voltage (kV) Core formation and spacing Conductor size in mm2 Charging current A/km
11 kV Cable Three-core 120 1.2
33 kV Cable Three-core 120 1.8
33 kV Cable Close-trefoil 300 2.5
66 kV Cable Flat, 127 mm 630 10
132 kV Overhead Line 175 0.22
132 kV Overhead Line 400 0.44
132 kV Cable Three-core 500 10
132 kV Cable Flat, 520 mm 600 20
275 kV Overhead Line 2 x 175 0.58
275 kV Overhead Line 2 x 400 0.58
275 kV Cable Flat, 205 mm 1150 19
275 kV Cable Flat, 260 mm 2000 24
400 kV Overhead Line 2 x 400 0.85
400 kV Overhead Line 4 x 400 0.98
400 kV Cable Flat, 145 mm 2000 28
400 kV Cable Tref., 585 mm 3000 33

If capacitive charging current compensation is not used, the setting of Phase Is1 must be set above 2.5 times the
steady state charging current. Where charging current is low or negligible, the recommended setting of 0.2 pu
(factory default) should be applied.

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If there is a mismatch between CTs at line ends, then the lowest primary CT rated current should be used as a
reference current for p.u. calculations (assuming that the load current cannot continuously exceed this value). This
means that the recommended settings Phase Is1 = 0.2 pu is equal to 0.2*(the lowest primary CT rated value). The
same consideration applies for other current settings such as Phase Is2.

13.2 SENSITIVITY UNDER HEAVY LOADS

The sensitivity of the phase current differential protection is governed by its settings and also the magnitude of
load current in the system. For a three-ended system, with devices LOCAL, REMOTE1, and REMOTE2, the following
applies:
|Idiff| = |(ĪLOCAL + ĪREMOTE1 + ĪREMOTE2)|
|Ibias|= 0.5 (|ILOCAL| + |IREMOTE1| + |IREMOTE2|)
Assume a load current of IL flowing from end LOCAL to REMOTE1 and REMOTE2. Assume also a high resistance
single-end fault of current IF, being fed from end LOCAL. In the worst case, we can also assume IF to be in phase
with IL:

ILOCAL = IL + IF
IREMOTE1 = -y*IL where 0<y<1
IREMOTE2 = - (1-y) IL
|Idiff|= |IF|
|Ibias| = |IL| + 0.5 |IF|

Phase current differential protection sensitivity when |Ibias| < Phase Is2:
The phase current differential protection would operate if |Idiff| > Phase k1 |Ibias| + Phase Is1
therefore:
|IF| > (Phase k1 |IL| + Phase Is1) / (1 - 0.5 Phase k1)
For Phase Is1 = 0.2 pu, Phase k1 = 30% and Phase Is2 =2.0 pu, then
● for |IL| = 1.0 pu, the phase current differential protection would operate if |IF| > 0.59 pu
● for |IL| = 1.59 pu, the phase current differential protection would operate if |IF| > 0.80 pu
If |IF| = 0.80 pu and |I| = 1.59 pu, then |Ibias| = 1.99 pu, which reaches the limit of the low percentage bias curve.

Phase current differential protection sensitivity when |bias| > Phase Is2:
The phase current differential protection would operate if |Idiff| > Phase k2 |Ibias| - (Phase k2 - Phase k1) Phase Is2 +
Phase Is1
therefore:
|IF| > (Phase k2 |IL| - (Phase k2 - Phase k1) Phase Is2 + Phase Is1) / (1 - 0.5 Phase k2)
For Phase Is1= 0.2 pu, Phase k1 = 30%, Phase Is2 = 2.0 pu and Phase k2 = 100%, then,
● for |IL| = 2.0 pu, the phase current differential protection would operate if |IF| > 1.6 pu
● for |IL| = 2.5 pu, the phase current differential protection would operate if |IF| > 2.6 pu

Fault resistance coverage

Assuming the fault resistance RF is much higher than the line impedance and source impedance, then for a 33 kV
system and 400/1 CT:

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P543i/P545i Chapter 6 - Current Differential Protection

|IF| = (Vph-n /RF)(1/CT ratio) pu = 47.63/RF pu

Based on the analysis above, the phase current differential protection detects a fault current in excess of 0.59 pu
with a load current of 1 pu flowing. The fault resistance is less than 47.63/0.59 = 81 ohms in this case.
With a short time overload current of 2.0 pu, the phase current differential protection can detect a fault resistance
of 47.63/1.6 = 30 ohms or lower.

13.3 PERMISSIVE INTERTRIPPING

The permissive intertrip (PIT) timer can be set between 0 and 200 ms. This time should be set to provide
discrimination with other protection devices. For example, if there is a genuine busbar fault, the time delay should
be set to allow busbar protection to clear the fault. A typical setting may be 100 to 150 ms.

13.4 CT RATIO CORRECTION SETTING GUIDELINES

If there is no mismatch between current transformers at line ends, Ph CT Corr’tion should be set to 1 in all devices

Note:
The following consideration includes references to currents used in Neutral Current Differential protection and protection of
feeders with In-zone transformers. If not applicable they may be ignored.

If the CTs at line ends have different primary ratings, then one of them is considered as a reference (the one with
the lowest primary rating). Ph CT Corr’tion should be set to 1 in the device connected to the reference CT. For all
other devices Ph CT Corr’tion is calculated as follows:
Ph CT Corr'tion IEDx = (Phase CT Primary IEDx) / (Phase CT Primary REFERENCE)
Settings Phase Is1, Phase Is2, Id High Set, Diff Is1, Diff Is2 must be calculated as pu of the reference primary
rating, then converted into local primary (secondary) values. For setting Phase Is1 in IEDX, the equations would be:
Phase Is1 [p.u.] = (Phase Is1 IABSOLUTE PRI [A]) / (Phase CT Primary REFERENCE [A])
Phase Is1 IEDx PRI. [A] = (Phase Is1 [p.u.]) (Phase CT Primary IEDx)
Phase Is1 IEDx SEC. [A] = (Phase Is1 [p.u.]) (Phase CT Sec'y IEDx)
The same considerations apply to settings Phase Is2, Id High Set, In Diff Is1, Diff Is2.

Example:
Assume that we have a three-ended application with line ends X, Y, Z (500/5, 800/5, 200/1) and Current Differential
settings in absolute primary values:
Phase Is1 ABSOLUTE PRI. = 100A
Phase Is2 ABSOLUTE PRI. = 1000A
Id High Set ABSOLUTE PRI. = 3000A
Diff Is1 ABSOLUTE PRI. = 50A
Diff Is2 ABSOLUTE PRI. = 1000A
Setting End X End Y End Z
Phase CT Primary 500A 800A 200A
Phase CT Sec’y 5A 5A 1A
Ph CT Corr’tion 500/200 = 2.5 800/200 = 4 1 (reference)
Phase Is1 [p.u.] 100/200 = 0.5 100/200 = 0.5 100/200 = 0.5

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Chapter 6 - Current Differential Protection P543i/P545i

Setting End X End Y End Z

Phase Is1 (Primary) 0.5*500 = 250A 0.5*800 = 400A 0.5*200 = 100A
Phase Is1 (Secondary) 0.5*5 = 2.5A 0.5*5 = 2.5A 0.5*1 = 0.5A
Phase Is2 [p.u.] 1000/200 = 5 1000/200 = 5 1000/200 = 5
Phase Is2 (Primary) 5*500 = 2500A 5*800 = 4000A 5*200 = 100A
Phase Is2 (Secondary) 5*5 = 25A 5*5 = 25A 5*1 = 5A
Id High Set [p.u.] 3000/200 = 15 3000/200 = 15 3000/200 = 15
Id High Set (Primary) 15*500 = 7500A 15*800 = 12000A 15*200 = 300A
Id High Set (Secondary) 15*5 = 75A 15*5 = 75A 15*1 = 15A
In Diff Is1 [p.u.] 50/200 = 0.25 50/200 = 0.25 50/200 = 0.25
In Diff Is1 (Primary) 0.25*500 = 125A 0.25*800 = 200A 0.25*200 = 50A
In Diff Is2 (Secondary) 0.25*5 = 0.75A 0.25*5 = 0.75A 0.25*1 = 0.25A
In Diff Is1 [p.u.] 1000/200 = 5 1000/200 = 5 1000/200 = 5
In Diff Is1 (Primary) 5*500 = 2500A 5*800 = 4000A 5*200 = 100A
In Diff Is2 (Secondary) 5*5 = 25A 5*5 = 25A 5*1 = 5A

13.5 FEEDERS WITH SMALL TAPPED LOADS

Where transformer loads are tapped off the protected line, it is not always necessary to install CTs at this location.
If the tee-off load is light, differential protection can be configured for the main line alone. The settings Phase
Char, Phase Time Delay and Phase TMS or Phase Time Dial allow the differential element to time grade with IDMT
overcurrent protection devices or fuses protecting the tap. This keeps stability of the differential protection for
external faults on the tee circuit.

13.6 SETTING A TWO-TERMINAL PHASE CURRENT DIFFERENTIAL ELEMENT

All four settings are user adjustable. This flexibility in settings allows the phase current differential characteristic to
be tailored to suit particular sensitivity and CT requirements. To simplify your task, we strongly recommend three of
the settings be fixed to:
Phase Is2 = 2.0 pu
Phase k1 = 30%
Phase k2 = 150%
These settings will give a characteristic suitable for most applications. It leaves only the Phase Is1 setting to be
decided by you. The value of this setting should be in excess of any mismatch between line ends. It should also
account for line charging current, where necessary.
By considering the circuit shown below, the settings for the phase current differential element can be established.

128 P54x1i-TM-EN-1
P543i/P545i Chapter 6 - Current Differential Protection

33 kV 400/1 400/1 33 kV
25 km
Protected line

Digital communication link

P54x P54x

Steady state charging current

= 2.5 A/km – cable
= 0.1 A/km – overhead line
V02621

Figure 48: Typical two-terminal plain feeder circuit

In the case that voltage inputs are not in place, no facility to account for line charging current is available. The
setting of Phase Is1 must therefore be set above 2.5 times the steady state charging current value. In this example,
assume a cable is used and there are not VT inputs connected to the device:
Phase Is1 > 2.5(Ich)
Phase Is1 > 2.5 (25 km x 2.5 A/km)
Phase Is1 > 156.25 A
The line CTs are rated at 400 amps primary. The setting of Phase Is1 must therefore exceed 156.25/400 = 0.391 pu.
Therefore select:
Phase Is1 = 0.4 pu
If VTs are connected, a facility exists to overcome the effects of the line charging current. To use this you need to
set the Compensation setting in the CURRENT DIFF column to Cap Charging and then programme the line
positive sequence capacitive susceptance value into the Susceptance setting now apparent in the CURRENT DIFF
column. This can be calculated from the line charging current as follows (assuming a VT ratio of 33 kV / 110 V):
Ich = 25 x 2.5 A = 62.5 A
Susceptance B = wC = Ich/V
B = 62.5 A/(33/Ö3 ) kV primary
B = 3.28 x 10-3 S primary
Therefore set:
B = 3.28 mS primary (= 2.46 mS secondary)
Phase Is1 may now be set below the value of line charging current if required, however we suggest that you
choose Phase Is1 only sufficiently below the charging current to offer the required fault resistance coverage.
Where charging current is low or negligible, the recommended factory default setting of 0.2xIn should be applied.

13.7 SETTING A THREE-TERMINAL PHASE CURRENT DIFFERENTIAL ELEMENT

All four settings are user adjustable. This flexibility in settings allows the phase current differential characteristic to
be tailored to suit particular sensitivity and CT requirements. To simplify your task, we strongly recommend three of
the settings be fixed to:
Phase Is2 = 2.0 pu
Phase k1 = 30%
Phase k2 = 100%

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Chapter 6 - Current Differential Protection P543i/P545i

These settings will give a characteristic suitable for most applications. It leaves only the Phase Is1 setting to be
decided by you. The value of this setting should be in excess of any mismatch between line ends. It should also
account for line charging current, where necessary.
By considering the circuit shown below, the settings for the phase current differential element can be established.

End A End B
275 kV 400/5 400/5 275 kV
Protected line
45 km 30 km

Ch 1 Digital communication link Ch 2

P54x P54x
10 km
Ch 2 Ch 1
End C 1200/5
275 kV
Digital communication link Digital communication link

P54x
Ch 1 Ch 2

Steady state charging current = 0.58 A/km - overhead line

V02620

Figure 49: Typical three-terminal plain feeder circuit

If there are no VT inputs connected, the setting Phase Is1 must be 2.5 times the steady state charging current
suitably corrected for the different CT ratios as presented below in the calculation of charging current
compensated values. For an overhead line circuit with a charging current of 0.58A/km the charging current will be:
Ich = 0.58 A ( 45 + 30 + 10 ) = 49.3 A
If VT inputs are connected, there is a facility to overcome the effect of charging current. To do this you need to
enter the positive sequence capacitive susceptance value.
Considering the charging current on the circuit shown in the figure above, the following calculation applies:
Ich = 0.58 A ( 45 + 30 + 10 ) = 49.3 A
Susceptance = wC = Ich/V
B = 49.3 A/( 275/ Ö3) kV primary
B = 0.31 x 10-3 S primary.
The CT ratios on the three ends are different, so it is necessary to apply a correction factor to ensure secondary
currents balance for all conditions:
To calculate the correction factor (CF), the same primary current must be used even if this current is not the
expected load transfer for every branch. This will ensure secondary current balance for all conditions.
CT ratio correction input data is shown in the table below:
Setting End A End B End C
Phase CT Primary 4000A 4000A 1200A
Ph CT Corr’tion 4000/1200 = 3.33 4000/1200 = 3.33 1 (reference)

We recommend the following settings:

Phase Is1 = 0.2 p.u. = 0.2*1200A = 240A

Phase Is2 = 2 p.u. = 2*1200A = 2400A

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P543i/P545i Chapter 6 - Current Differential Protection

Phase k1 = 30%
Phase k2 = 100%
Therefore, settings in primary/secondary values for each device can be calculated as follows:
Setting End A End B End C
Phase CT Primary 4000A 4000A 1200A
Phase CT Sec’y 5A 5A 5A
Phase Is1 [p.u.] 0.2 0.2 0.2
Phase Is1 (Primary) 0.2*4000 = 800A 0.2*4000 = 800A 0.2*1200 = 240A
Phase Is1 (Secondary) 0.2*5 = 1A 0.2*5 = 1A 0.2*5 = 1A
Phase Is2 [p.u.] 2 2 2
Phase Is2 (Primary) 2*4000 = 8000A 2*4000 = 8000A 2*1200 = 2400A
Phase Is2 (Secondary) 2*5 = 10A 2*5 = 10A 2*5 = 10A

Note:
Settings shown in primary values at ends A and B appear different compared with end C. This is not a problem as the currents
at ends A and B will be multiplied by the Correction Factor, when the differential calculation is done.

Susceptance settings for Ends A and B

With a VT ratio 275 kV/110 V and CT ratio 4000/5:
RCT = 800
RVT = 2500
B = 310 mS
Secondary susceptance = 310 mS(RVT/ RCT)= 968 mS

Susceptance settings for End C

With a VT ratio 275 kV/110 V and CT ratio 1200/5:
B = 310 mS
Secondary susceptance = 310 mS(RVT/ RCT)= 3.22 mS

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132 P54x1i-TM-EN-1
 CHAPTER 7

DISTANCE PROTECTION
Chapter 7 - Distance Protection P543i/P545i

134 P54x1i-TM-EN-1
P543i/P545i Chapter 7 - Distance Protection

1 CHAPTER OVERVIEW
This chapter introduces the principles and theory behind the protection and describes how it is implemented in this
product. Guidance for applying this protection is also provided.
This chapter contains the following sections:
Chapter Overview 135
Introduction 136
Distance Measuring Zones Operating Principles 138
Phase and Earth Fault Distance Protection Implementation 168
Delta Directional Element 176
Distance Isolated and Compensated Systems 179
Application Notes 193

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Chapter 7 - Distance Protection P543i/P545i

2 INTRODUCTION
Amongst protection engineers, the basic principles of Distance Protection are widely documented and understood.
If you are reading this chapter, we assume that you are familiar with the principles of distance protection and
associated components such as Aided Schemes. However, to help you choose suitable settings, some of the
principles of operation of the Distance Measuring Zones is included in this chapter.

2.1 DISTANCE PROTECTION PRINCIPLE

The principle behind Distance protection is based on using measured values of voltage and current to calculate
impedance seen from a relaying point. If the impedance calculated is an unexpected value, this may indicate a
fault.
The impedance of a transmission line is proportional to its length. If voltage and current signals are available at a
relaying point, they can be used to calculate the impedance value seen from the relaying point. Impedance values
looking forward into the line, as well as values looking in the reverse direction behind the relaying point can be
calculated. The calculated impedance is compared with so called 'Reach Points'. Reach Points are impedance
values, which are used to define zones of protection. The device contains settings by which you can configure
these Reach Points. The zones are usually numbered (for example: Zone 1, Zone 2, Zone 3). By comparing the
calculated impedance with the zone reach points, the device can determine whether a fault is present and if
necessary, trip the associated circuit breakers.

2.2 PERFORMANCE INFLUENCING FACTORS

As well as the accuracy of the signals presented by the input transducers, an important factor that influences the
performance of distance protection is the relationship between the source and line impedance. This is the System
Impedance Ratio (SIR), and is defined by ZS/ZL.
The following figure represents a fault condition on an electrical power system, and can be used to demonstrate
the relationship.

R
Source Line

VS IR VL=VR

ZL
V VR

V02753

Figure 50: System Impedance Ratio

The voltage V applied to the impedance loop is the open circuit voltage of the power system. Point R represents the
protection location; IR and VR are the current and voltage measured by the relay, respectively.
The impedances Zs and ZL are described as source and line impedances because of their position with respect to
the protection location. Source impedance Zs is a measure of the fault level at the relaying point. For faults
involving earth it is dependent on the method of system earthing behind the relaying point. Line impedance ZL is a
measure of the impedance of the protected section. The voltage VR applied to the relay is, therefore, IRZL. For a
fault at the reach point, this may be expressed in terms of the System Impedeance Ratio, using the following
expression:
VR = V/(SIR+1)

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P543i/P545i Chapter 7 - Distance Protection

where SIR = ZS/ZL

From the equation above, it can be seen that the measured voltage has a significant impact on the decision
making process.
The ability of distance protection to measure accurately for a given reach point fault, depends on the voltage at
the relaying location being above a minimum value at the time of the fault. If the voltage is above this minimum
value, it is generally used to polarize the distance protection and indicate the direction of the fault. This is called
self-polarization.
If the voltage collapses below the minimum threshold necessary to make a sensible decision, alternative methods
of polarization to determine the direction of the fault are needed. Two methods that are applied are cross-
polarization and memory polarization. If a fault doesn’t affect all phases, the voltage signals on the healthy phases
can be used for the directional decision. This is called cross-polarization. If the fault causes all phase voltages to
collapse, a stored record of the pre-fault voltage can be used to make the directional decision. This is called
memory polarization. Memory polarization, cross-polarization, and self-polarization can sometimes be used in
combination.

2.3 IMPEDANCE CALCULATION

Careful selection of the reach settings and tripping times for the various measurement zones enables correct
coordination between Distance protection devices. Basic Distance protection will comprise instantaneous
directional Zone 1 protection and one or more time delayed zones. A basic distance protection scheme is likely to
feature 3 zones of protection, but numerical distance protection devices may have several more zones, some set
to measure in the forward direction and some set to measure in the reverse direction.
Some numerical distance protection devices measure the fault voltage and current directly then calculate the
impedance, after which they determine whether operation is required according to impedance boundaries defined
on an R/X diagram. Many numerical IEDs emulate their traditional electro-mechanical counterparts. Rather than
calculating the absolute impedance, they compare the measured fault voltage with a replica voltage derived from
the fault current and the zone impedance setting to determine whether the fault is within zone or out-of-zone.
Typically, a comparator will compare either the relative amplitude or relative phase of input quantities to
determine impedance limits. Limits may be either straight line characteristics (quadrilaterals), or circular
characteristics (Mhos).

2.4 IMPLEMENTATION WITH COMPARATORS

The distance protection in this product uses measured values of voltage and current, together with setting values
such as line impedance, to determine whether fault conditions exist. The determination as to whether a fault
condition exists is performed by so-called ‘comparators’. These comparators use voltage and current inputs in
conjunction with impedance settings to decide whether a fault is in a particular zone. Multiple zones can provide
protection for the protected line as well as providing back-up protection for connected lines.
All distance zone calculations in this product are constructed using one or more comparators. Each comparator
uses two vector quantities which are generally referenced as S1 and S2. S1 and S2 comparators are used to
construct either circular (Mho) and/or Quadrilateral characteristics. In the case of Mho characteristics, a single
comparator is used to make a tripping decision. In the case of Quadrilateral characteristics, multiple comparators
are used to make a tripping decision.

2.5 POLARIZATION OF DISTANCE CHARACTERISTICS

The distance zone characteristics are polarized (directionalized) to reflect the characteristic angle of the line. Some
of the zones of the distance protection are forward looking, some are reverse looking, and some are of the offset
type. Polarization is generally achieved by directional self-polarization, but memory-polarization, or cross-
polarization, might be adopted for close-up zero-voltage faults.

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3 DISTANCE MEASURING ZONES OPERATING PRINCIPLES

All distance zone characteristics in this product are constructed with one or more comparators. The comparators
are used to construct either Mho, or Quadrilateral characteristics. This section outlines the principles behind the
construction of the characteristics in order to provide an understanding of how best to set them.
The following table details signal definitions used to construct the measuring zone characteristics.
Name Description
I Current
I Current used by the Distance protection measuring element
IM Residual current of parallel line (mutual current)
IN Neutral Current (derived)
Iph Faulted phase current (for example IA for A-N fault)
j The complex operator
kM Mutual compensation co-efficient
kZN Residual compensation co-efficient
Distance polarizing factor. A percentage of the memory voltage polarizing signal that is added to the self-
p
polarizing voltage signal to dictate the level of Mho expansion and help establish a directional decision.
R Resistance
R Forward Resistance Reach
R’ Reverse Resistance Reach
S A voltage vector value comprising one or more voltage components
S1 A voltage vector input to a comparator
S2 A second voltage vector input to a comparator
V Voltage
V Voltage used by the Distance protection measuring element
V/I Impedance measured by the Distance protection element
Vmem Voltage memory signal used for polarization
Vph Faulted phase voltage (for example VA for A-N fault)
Vph/Iph Loop impedance measurement
VS Source voltage
X Reactance
Z Impedance Reach setting
Z’ Reverse Impedance Reach setting
Z1 Positive sequence impedance
ZLP Loop impedance
Zreplica Forward replica reach in the loop impedance plane = Z(1+kZN.IN/Iph+kZM.IM/Iph)
Z’replica Reverse replica reach in the loop impedance plane = Z’(1+kZN.IN/Iph+kZM.IM/Iph)
ZS Source impedance
σ An angle (in degrees) usually associated with the tilt of a reactive line on a Quadrilateral characteristic
Ðσ A vectorial operator that rotates a vector quantity by an angle of σº (alternative representation ejσ)

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Note:
The faulted phase current (I) is generally used as the reference (0º) for the vector diagrams.

3.1 MHO CHARACTERISTICS

There are different types of Mho characteristic, but two specific ones are well suited to introducing the defining
principles. These are the directional Self-polarized Mho and the Offset Mho. Both types are used for both phase
faults and earth faults.
In practice, self-polarized Mhos are rarely used since voltage collapses for close-up faults render self-polarization
unreliable. Rather, memory-polarization components and/or cross-polarization components are usually used to
provide a polarizing reference. Directional Self-Polarized Mhos, however, are simpler to understand and are used
by way of introduction.

3.1.1 DIRECTIONAL MHO CHARACTERISTIC FOR PHASE FAULTS

The following diagram illustrates how the Directional Self-Polarized Mho characteristic for phase Distance
protection is created.

V IZ

IZ

V 90°

V02710
Figure 51: Directional mho element construction

The two signals provided to the comparator are:

S1 = V
S2 = V - I.Z
Operation occurs when the angle between the signals is greater than 90°

3.1.2 OFFSET MHO CHARACTERISTIC FOR PHASE FAULTS

The following diagram illustrates how the Offset Mho characteristic for phase Distance protection is created:

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Chapter 7 - Distance Protection P543i/P545i

V IZ

IZ
90°

V
V  I  Z
I
I  Z

V02711

Figure 52: Offset Mho characteristic

The two signals provided to the comparator are:

S1 = V - IZ'
S2 = V - IZ
Operation occurs when the angle between the signals is greater than 90°

3.1.3 DIRECTIONAL SELF-POLARIZED MHO CHARACTERISTIC FOR EARTH FAULTS

Characteristics of earth-fault elements can be represented in two different complex planes - the positive sequence
impedance plane (Z1 -plane) and the loop impedance plane (ZLP -plane). The reach impedance setting defines the
reach in positive sequence impedance terms. The characteristic in the ZLP -plane is generally dynamic because it
depends on fault currents. However, the ZLP–plane representation is often more convenient for reference,
especially if an injection test kit is used, which cannot apply the residual compensation to the impedance plot, or in
the case that the load blinders have to be verified.
The following diagram illustrates how a directional Mho characteristic for earth-faults is created.

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Z1 Plane ZLP Plane

jX Z  k ZN  I N I ph
 jX
V ph I ph  Z replica

V IZ
Z Z

Z replica

90°
90°

R R
V I V ph I ph
V02712

Figure 53: Directional Mho element construction – impedance domain

The two signals provided to the comparator are:

S1 = V
S2 = V - IZ
where (for an A-N fault for example) with residual compensation applied:
V = VA
I = IA + kZN.IN
where kZN = (Z0 - Z1) / 3Z1 and is defined by two settings: kZN Res Comp and KZN Res Angle.
and if mutual compensation is applied:
I = IA + kZN.IN + kZM.IM
where kZM = 3ZM / 3Z1 and is defined by two settings: kZm Mutual Set and kZm Mutual Angle.
Operation occurs when the angle between the signals is greater than 90°.
To obtain a ZLP-plane representation in the directional Mho element construction, V is replaced with Vph and I is
replaced with Iph + kZN.IN, where Vph and Iph are the faulty phase voltage and current respectively (assuming no
mutual current compensation).
The two signals provided to the comparator in this case are:
S1 = Vph
S2 = Vph - Iph.Z(1+kZN.IN/Iph)
We can define a replica impedance reach, Zreplica, as:

Zreplica = Z(1+kZN.IN/Iph)
or if mutual compensation is applied:

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Z(1+kZN.IN/Iph+kZM.IM/Iph)
Then if healthy phase currents are much less then the current of the faulty phase and the mutual compensation is
disabled:
IN @ Iph
so that
Zreplica @ Z(1 + kZN)
Thus the ZLP plane representation of the characteristic becomes static.

3.1.4 OFFSET MHO CHARACTERISTIC FOR EARTH FAULTS

The diagram below illustrates how the Offset Mho characteristic for earth-fault distance protection is created in
the impedance domain.

 jX Z1 -plane

V IZ
Z

90°
V I

V I  Z

R
Z

V02713
Figure 54: Offset Mho characteristics – impedance domain

The two signals provided to the comparator are:

S1 = V - I.Z'
S2 = V - I.Z
Operation occurs when the angle between the signals is greater than 90°.
The following diagram below how the Offset Mho characteristic for earth-fault distance protection translates to
the loop impedance domain.

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Z LP -plane

 jX Z  k ZN  I N I ph

V ph I ph  Z replica

Z Z replica
90°
h
h / Ip
Vp


Z replica R

Z


V ph I ph  Z replica
Z   k ZN  I N I ph
V02714
Figure 55: Offset mho characteristics – voltage domain

where: Zreplica is the replica forward reach and Z'replica is the replica reverse reach.
With mutual compensation applied:
Zreplica = Z(1+kZN.IN/Iph + kZM.IM/Iph)
Z'replica = Z'(1+kZN.IN/Iph + kZM.IM/Iph)
If the healthy phase currents are much less than the current of the faulty phase, then the neutral current is
approximately the same as the phase current, and the terms can be simplified as follows:
Zreplica = Z(1+kZN + kZM.IM/Iph)
Z'replica = Z'(1+kZN + kZM.IM/Iph)
If the healthy phase currents are much less than the current of the faulty phase, and mutual current compensation
is not applied, then these terms can be simplified as follows:
Zreplica @ Z(1+kZN)
Z'replica @ Z'(1+kZN)
So, as with the Directional Self-Polarized Mho characteristic for earth-faults, the ZLP plane representation of the
characteristic becomes static.

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3.1.5 MEMORY POLARIZATION OF MHO CHARACTERISTICS

Self-Polarized Directional Mho characteristics require sufficient polarizing voltage to detect the voltage angle.
Therefore such a characteristic is unable to operate for close-up faults where there would be insufficient polarizing
voltage. To ensure the correct Mho element response for zero-voltage faults, the protection algorithm adds a
percentage of voltage from the memory to the main polarizing voltage as a substitute phase reference.
This technique is called memory polarizing. Not only does it preserve the directional property of the Mho
characteristic, it actually enhances it by dynamically expanding or contracting the characteristic.

3.1.6 DYNAMIC MHO EXPANSION AND CONTRACTION

The signals provided to the Mho comparators for memory polarization are:
S1 = V + pVmem
S2 = V - IZ
where:
● V is the self-polarization voltage
● Vmem is the memory polarization voltage

Operation occurs when the angle between the signals is greater than 90°.
The memory voltage Vmem is the pre-fault voltage. Assuming the pre-fault current is close to zero at the relaying
point, he pre-fault voltage is equal to the source voltage. Therefore:
Vmem = VS

Dynamic Mho Expansion for Forward Faults

The contribution of additional polarizing input creates dynamic Mho expansion for forward faults and increases
the fault arc resistance coverage.
Referring to the diagram below:

IED
Dist
VS Bus I
Line
ZS ZF
V
V02715
Figure 56: Simplified forward fault

For a fault condition we can write the following equations:

VS = V + I.ZS

 p 
90° ≤ ∠  V I + ⋅ Z S  − ∠ ( V I − Z ) ≤ −90°
 1+ p 
The Mho expansion for a forward fault is illustrated in the following diagram:

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 jX
Self-polarised

V IZ
Z

V I 90°

R
p
  ZS
1 p p
V I  ZS
1 p
V02716
Figure 57: Mho expansion – forward fault

The Mho expansion associated with forward faults is as follows:

Mho Expansion = ZS.p/(1 +p)
where ZS is the impedance of the source behind the relaying point.
Using the source and line impedances is a simple way of representing the Mho expansion. The protection
algorithm does not calculate ZS internally, it only deals with the signals S1 and S2 provided to the Mho
comparators. In some cases the source and line impedances are different from their actual values used in various
power system studies. This is mainly due to pre-fault current and the residual compensation for phase-to-ground
loops. To plot an accurate impedance characteristic, calculate the values of ZS as follows:

ZS = (Vmem - V)/I

Dynamic Mho Contraction for Reverse Faults

The contribution of additional polarizing input creates dynamic Mho contraction for reverse faults and enhances
the directional decision
Referring to the following diagram:

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IED
Dist
Bus VS
I
Network
ZF ZL ZS
V
V02717
Figure 58: Simplified Reverse Fault

For a fault condition we can write the following equations:

VS = V - I(ZS + ZL)

 p 
90° ≤ ∠  V I − ⋅ ( Z S + Z L )  − ∠ ( V I − Z ) ≤ −90°
 1+ p 
The Mho contraction for a reverse fault is illustrated in the following diagram:

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p
V I  (ZS  ZL )
1 p
 jX
90°

V IZ

p
 (Z S  Z L )
1 p

V I

R

Self-polarised

V02718
Figure 59: Mho contraction – reverse fault

The Mho contraction associated with reverse faults is as follows:

Mho Contraction = (ZS + ZL).p/(1 + p)
where ZS + ZL is the impedance of the line and the source ahead of the relaying point.
Using the source and line impedances is a simple way of representing the Mho contraction. The protection does
not calculate ZS + ZL internally, it only deals with the signals S1 and S2 provided to the Mho comparators. In some
cases the source and line impedances are different from their actual values used in various power system studies.
This is mainly due to pre-fault current and the residual compensation for phase-to-ground loops. To plot an
accurate impedance characteristic, calculate the values of ZS + ZL as follows:

ZS + ZL = (V - Vmem)/I

3.1.7 CROSS POLARIZATION OF MHO CHARACTERISTICS

If the voltage collapses on a faulted phase, it may be possible to use healthy phase voltage components to derive
a polarizing signal to make the directional decision. This process is called cross-polarization.

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The cross-polarization voltage is generated using phase(s) not otherwise used for the particular distance or
directional measurement. While one pole is dead, and the memory is not available, the elements associated with
the remaining phases are polarized as shown in the following table:
Cross Polarizing Signal Cross Polarizing Signal Cross Polarizing Signal
Loop
(No poles dead) Lagging Pole Dead Leading Pole Dead
A-N 0.5(aVB + a2VC) αVB α2VC
B-N 0.5(aVC + a2VA) αVC α2VA
C-N 0.5(aVA + a2VB) αVA α2VB
A-B √3VC Ð -90º 0 0
B-C √3VA Ð -90º 0 0
C-A √3VB Ð -90º 0 0
where a is a mathematical operator which rotates a vector through 120° and a2 denotes a rotation of 240°.
The table shows polarizing signal contributions for each loop under the different operating conditions. The
proportion of cross-polarization voltage used is defined by the Dist. Polarizing (p) setting.

Note:
Cross polarization is used only when there is no memory polarization quantity available.

3.1.8 IMPLEMENTATION OF MHO POLARIZATION

This product does not allow the directional Mho characteristics to be purely self-polarized or purely memory-
polarized. The polarizing voltage always contains the directly measured self-polarized voltage, onto which a
percentage of the pre-fault memory voltage is added.

Note:
If no memory voltage is available then the cross-polarized quantity is used instead.

The setting Dist. Polarizing (p) defines the amount of memory polarization (or if need be, cross polarization
voltage), which should be added with respect to the existing self-polarizing voltage so that:
S1 = V + pVmem.
The value "p" can be set from 0.2 (20%) to 5 (500%).
This will have an affect on the characteristic where operation occurs when the fault impedance lies inside a circle
whose diameter is set by the points IZ and p/(1+p)IZsource
This means for example:
● If p = 1, the characteristic will have an expansion of 50% IZsource
● If p = 5, the characteristic will have an expansion of 83.3% IZsource

The memory algorithm works as follows:

1. Memory voltage is stored for two cycles after line energisation, whereafter the voltage signals are
considered valid and stored in the voltage memory buffers. The voltage memory used for polarizing is taken
from a buffer corresponding to a value taken two cycles previously, so the voltage memory can be used
after four cycles following line energisation.
2. Following fault inception, voltage signals buffered in the polarizing memory can be recycled and re-used for
a period set with the Mem Volt Dura setting. This can be set between 16 and 32 cycles.
3. If a power swing condition is detected, the voltage memory signal expires after a reduced period of 3.2
cycles.

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4. If the fault is cleared before the voltage memory signal expires, the memory algorithm resets and restarts
the two/four cycle validation process.
5. If there is no voltage memory available (either because the line has just been energised, or because the
memory voltage has expired), cross polarization is used instead. The contribution of cross polarizing signals
is only used when memory polarizing is invalid and is only valid for certain pole dead conditions.
6. If neither memory polarization voltage nor cross-polarization voltage is available (pole dead condition for
phase-to-phase element), then the phase-to-phase elements are self polarized. If the polarizing voltage is
less than 1V, only zone 1 is allowed to operate. In this case a Mho characteristic with a reverse offset of 25%
is applied. This ensures operation when closing on to a close-up three-phase fault (SOTF/ TOR condition).
One of the additional benefits of adding memory into the polarizing mix is that Mho characteristics offer dynamic
expansion if there is a forward fault, therefore covering greater fault arc resistance

3.2 QUADRILATERAL CHARACTERISTIC

A number of zones are provided to make up the Quadrilateral characteristics. The following diagram shows
examples of Directional Forward, Directional Reverse, and Offset zones:

Line Angle
+jX

Z3 (offset)

ZP (forward)

Z2

Z1
Forward

-R +R

Reverse

Z4

ZQ (reverse)
E02785

Figure 60: Simplified quadrilateral characteristics

Programmable zones (zone P and Q) are also available. Similar to Zone 3, the programmable zones can be
configured as Offset, Directional Forward, or Directional Reverse.
A combination of simple comparators, each using signals derived from measured currents and voltages,
determines whether measured impedance is within a tripping zone. A separate comparator is used for each line of
each Quadrilateral.
Each tripping zone is constructed from a Quadrilateral based on that depicted in the following diagram:

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Chapter 7 - Distance Protection P543i/P545i

jX Z Impedance Reach line

Reverse Resistive
Reach line Tripping
Region
Resistive
Reach line

R’ θ R +R

Z’

-jX Reverse Impedance Reach line

V02721

Figure 61: General Quadrilateral Characteristic Limits

In the figure, an Offset Quadrilateral characteristic is defined by its Impedance Reach, Z, (and Reverse Impedance
Reach, Z’), its Resistive Reach, R, (and Reverse Resistive Reach, R’), and the zone angle (θ).
The two near-horizontal lines (Impedance Reach Line and Reverse Impedance Reach Line) set the reactive
impedance limits of the tripping zone. The two near-vertical lines (Resistive Reach Line and Reverse Resistive
Reach Line) set the resistive impedance limits.
The Resistive Reach Lines (also called Resistive Blinders) are parallel and set at the angle of the zone’s
characteristic impedance.
The Impedance Reach Lines exhibit a characteristic tilt (slope). A line that tilts to reduce the reactive reach
(negative tilt/tilt down) encourages underreaching; A line that tilts to increase the reactive reach (positive tilt/tilt up)
encourages overreaching. The tilt can be used to reinforce the overreaching/underreaching requirements of the
zone. For example, for an underreaching Forward zone, a negative tilt will ensure that the measurement continues
to underreach, even with increasing fault resistance.
The Impedance Reach, Z, and the Resistive Reach, R, apply in the context of the direction of the protection. For a
Forward Zone, or an Offset Zone, Z and R look into the protected plant. For a Reverse Zone, Z and R look behind the
protected plant. Reactive Line tilts follow the same convention.

3.2.1 DIRECTIONAL QUADRILATERALS

A Directional Line overlaid onto an Offset characteristic is used to create a Directional one as shown in the
following figure:

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P543i/P545i Chapter 7 - Distance Protection

jX Z

Tripping
Region
Directional Line

R’ θ R +R

Z’ Forward direction
60°

-jX

V02720 Reverse direction

Figure 62: Directional Quadrilateral Characteristic

This product has a Delta Directional element that is normally used to directionalise the Distance protection.
By default, the Delta Directional element is enabled (Dir. Status in DELTADIRECTIONAL set to Enabled). In this
case, the Directional Line for the Quadrilateral is derived using superimposed fault-current (Delta I). When using the
Delta Directional element, the Directional Line angle has a default value of 60º, but you can change it with the Dir.
Char Angle setting.
If you want to use a conventional directional technique, then you can do this by disabling the Delta Directional
element. The protection will then use a conventional directional element with a fixed angle of 60º.
The following figure illustrates two Offset zones that have been converted into Directional Forward zones by the
overlay of a Directional Line. An Offset zone is also shown for reference.

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jX

Offset zone

Directional zone

Directional zone
Directional Line

-R +R

Forward direction

-jX

V02772 Reverse direction

Figure 63: Quadrilateral Characteristic featuring 2 directional forward zones and 1 offset zone

Directional Quadrilateral Limits

The implementation of Directional Quadrilaterals in this product produces Directional Zone characteristics that are
formed by the combination of five comparators. Each comparator produces a straight line on the complex
impedance plane. The lines produced are:
● Impedance Reach Line
● Reverse Impedance Reach Line
● Resistance Reach Line
● Reverse Resistance Reach Line
● Directional Line.

Each of the lines produced by the comparators defines a tripping limit: Impedance on one side of the line prevents
tripping whereas impedance on the other side of the line may, if the other comparators agree, allow tripping. For
example, impedance beyond the Impedance Reach Line will not allow tripping.
The combination of the comparator outputs produces a polygon shaped tripping region. The polygon may be
either 4-sided or 5-sided. The shape depends according to the settings that are applied by the five comparators
and how the Directional Line interacts with the reach lines (usually the Reverse Impedance Reach Line):
● The Directional Line may completely mask a reach line. If that is the case, the polygon will be 4-sided
(quadrilateral).
● If the Directional Line intersects a reach line, the polygon will be 5-sided.

Creation of a 5-sided polygon is illustrated in the following figure:

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jX

Directional Line

-R R

Forward direction
-jX

V02773 Reverse direction

Figure 64: Five-sided polygon formed by Quadrilateral characteristic with Directional-Line intersection of
Reverse Impedance Reach Line

The applied settings will determine the intersection point. When the settings have been chosen, the following
values will affect the line intersection point:
● Impedance Reach
● Reverse Impedance Reach
● Resistive Reach
● Reverse Resistive Reach
● Directional Line Angle
● Zone Characteristic Impedance Angle
● Tilt Angles of Impedance Reach Lines

The Impedance Reach, the Resistive Reach, and the Zone Characteristic Impedance Angle, can be freely assigned.
The Directional Line Angle is 60º by default but can be varied if the Delta Directional element is enabled. The Tilt
Angle of the impedance lines has a default setting of -3º, but some variation is allowed if the Advanced setting
option is chosen.
The Reverse Impedance Reach, and the Reverse Resistive Reach are applied as a fixed ratio of the Impedance
Reach and the Resistive Reach for Directional characteristics. The ratios used vary according to the zone type. The
following tables present the different values for phase-phase characteristics and phase-earth characteristics. For
completion, the reach limit values for Offset zones are also included (although the overlaid Directional line does not
apply and the Offset characteristics will always be quadrilateral).

Phase-to-phase Element Reaches

Reverse Impedance Reverse Resistive
Zone Type Impedance Reach Z Resistive Reach R
Reach Z’ Reach R’
1 Ph-Ph Forward Z1 Ph. Reach 0.25 Z ½*R1 Ph. Resistive 0.25 R
2 Ph-Ph Forward Z2 Ph. Reach 0.25 Z ½*R2 Ph. Resistive 0.25 R
3 Ph-Ph Forward Z3 Ph. Reach 0.25 Z ½*R3 Ph. Resistive 0.25 R
3 Ph-Ph Reverse Z3 Ph. Reach 0.25 Z ½*R3 Ph. Resistive 0.25 R

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Reverse Impedance Reverse Resistive

Zone Type Impedance Reach Z Resistive Reach R
Reach Z’ Reach R’
3 Ph-Ph Offset Z3 Ph. Reach Z3’ Ph Rev Reach ½*R3 Ph. Resistive ½*R3’ Ph Res. Rev.
4 Ph-Ph Reverse Z4 Ph. Reach Z ½*R4 Ph. Resistive 0.25 R
P Ph-Ph Forward ZP Ph. Reach Z ½*RP Ph Resistive 0.25 R
P Ph-Ph Reverse ZP Ph. Reach Z ½*RP Ph Resistive 0.25 R
P Ph-Ph Offset ZQ Ph. Reach ZP’ Ph Rev Reach ½*RP Ph Resistive ½*RP’ Ph. Res. Rev.
Q Ph-Ph Forward ZQ Ph. Reach Z ½*RQ Ph Resistive 0.25 R
Q Ph-Ph Reverse ZQ Ph. Reach Z ½*RQ Ph Resistive 0.25 R
Q Ph-Ph Offset ZQ Ph. Reach ZQ’ Ph Rev Reach ½*RQ Ph Resistive ½*RQ’ Ph. Res. Rev.

Phase-to-earth Element Reaches

Reverse Resistive
Zone Type Impedance Reach Z Reverse Impedance Reach Z’ Resistive Reach R
Reach R’
1 Ph-Earth Forward Z1 Gnd. Reach * (1 + kZN) 0.25 Z R1 Gnd Resistive 0.25 R
2 Ph-Earth Forward Z2 Gnd. Reach * (1 + kZN) 0.25 Z R2 Gnd Resistive 0.25 R
3 Ph-Earth Forward Z3 Gnd. Reach * (1 + kZN) 0.25 Z R3 Gnd Resistive 0.25 R
3 Ph-Earth Reverse Z3 Gnd. Reach * (1 + kZN) 0.25 Z R3 Gnd Resistive 0.25 R
3 Ph-Earth Offset Z3 Gnd. Reach * (1 + kZN) Z3’ Gnd Rev Rch * (1 + kZN) R3 Gnd Resistive R3’ Ph Res. Rev
4 Ph-Earth Reverse Z4 Gnd. Reach * (1 + kZN) Z R4 Gnd Resistive 0.25 R
P Ph-Earth Forward ZP Gnd. Reach * (1 + kZN) 0.25 Z RP Gnd Resistive 0.25 R
P Ph-Earth Reverse ZP Gnd. Reach * (1 + kZN) 0.25 Z RP Gnd Resistive 0.25 R
P Ph-Earth Offset ZQ Gnd. Reach * (1 + kZN) ZP’ Gnd Rev Rch * (1 + kZN) RP Gnd Resistive RP’ Gnd Res. Rev
Q Ph-Earth Forward ZQ Gnd. Reach * (1 + kZN) 0.25 Z RQ Gnd Resistive 0.25 R
Q Ph-Earth Reverse ZQ Gnd. Reach * (1 + kZN) 0.25 Z RQ Gnd Resistive 0.25 R
Q Ph-Earth Offset ZQ Gnd. Reach * (1 + kZN) ZQ’ Gnd Rev Rch * (1 + kZN) RQ Gnd Resistive RQ’ Gnd Res. Rev

where kZN = (Z0 - Z1) / 3Z1 and is defined by two settings: kZN Res Comp and KZN Res Angle.

Note:
Not all products feature all zones.

Note:
With default settings applied, Directional Zones 1, 2, and 4 should appear Quadrilateral.

3.2.2 EARTH FAULT QUADRILATERAL CHARACTERISTICS

Quadrilateral characteristics are available for earth-fault protection. A mix of Directional Forward, Directional
Reverse, and Offset characteristics is available. Zone 1 and Zone 2 are Directional Forward. Zone 4 is Directional
Reverse. Other zones can be set independently as Offset, Directional Forward, or Directional Reverse. Each zone is
independent and is defined by an Impedance Reach line, a Reverse Impedance Reach Line, and two resistive
blinders. The two resistive blinders (Resistive Reach Line and Reverse Resistive Reach Line) are parallel to the zone
characteristic impedance angle.
The two reactance lines of each Phase-Earth Quadrilateral exhibit a characteristic tilt. The tilts of the Impedance
Reach Line and the Reverse Impedance Reach Line are independent. The tilt of both may be fixed. Alternatively,

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the lines may be allowed to vary the tilt angle according to system conditions (dynamic tilting). If the tilt of the
Reverse Impedance Reach Line is fixed, the value is -3º. If the tilt of the Impedance Reach Line is fixed, the value is
fixed according to the setting, σ, -(user settable between +/- 30º). To use the dynamic tilting option you must
enable it. Enabling the dynamic tilt causes the slope of the reactance lines to deviate from the set values to
compensate, automatically, for angular difference between fault current and polarizing current.

3.2.2.1 EARTH FAULT REACTANCE LINES

Both forward and reverse reach reactance lines feature a fixed tilt. For the Impedance Reach line, the fixed tilt can
be set to reinforce underreaching or overreaching preferences for the zone. For the Reverse Impedance Reach line,
the fixed tilt is preset at -3º.
The tilting of the reactance lines can be set such that tilting will be affected by the choice of polarizing quantity. If
dynamic tilting is selected, the protection automatically chooses the best polarizing quantity from either the phase
current or negative sequence current. The choice depends on which line is being polarized and on the relationship
of measured currents I2 and Iph. When I2 is used as the polarizing quantity, the tilt can dynamically vary according
to the angle of I2. If Iph is used, the tilt remains fixed at the set angle.
Consider polarization of the reactance lines for the case of a phase-earth fault:
For a phase-earth fault:
V = Vph
and assuming that mutual compensation is not applied:
I = Iph + kZN.IN.
To avoid overreaching or underreaching due to the voltage drop in the arc resistance, the top line of the
characteristic should be ideally tilted by an angle:
Ð (Ifault / I)
So that the total angle of tilt should be:
Ð (Ifault / I) + σ
where Ifault is the fault current and σ is the fixed tilt of the reactance line (user setting for the Impedance Reach
line, fixed -3º preset for the Reverse Impedance Reach line.
If Z is the zone reach setting then the reactance line is formed by phase comparison between an operating signal
V – I Z (S1), and a polarizing quantity, IPOL (S2).
Ifault should be used to determine S2, but, because the Distance protection cannot measure the fault current
directly (due to the unknown infeed from the remote end), Ifault cannot be used as the polarizing current. Instead,
the angle of Ifault must be estimated. Two proven methods to estimate the angle of Ifault are:
1. The angle of Ifault can be assumed to be close to the angle of Iph
2. The angle of Ifault can be assumed to be close to the angle of the negative sequence current I2.
In case 1, the angle of Iph can be used to polarize the Quadrilateral characteristic and so the tilt of the reactance
line is fixed.
In case 2 the angle of I2 can be used to polarize the Quadrilateral characteristic. In this case, the reactance line tilt
varies dynamically according to the angle of I2.
The reactance line follows the fault resistance impedance and tilts up or down, starting from the set initial tilt angle
(σ) to avoid underreaching or overreaching.
For both fixed and dynamic tilting the validity of current polarization is controlled by the following condition:
|Ð I2 - Ð Iph | < 45º

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If this condition is not fulfilled, the assumptions that the angle of Ifault is close to the angle of Iph or close to the
angle of I2 cannot be considered valid. Under such conditions the Quadrilateral characteristic could significantly
overreach or underreach. To avoid this, the distance protection automatically switches from Quadrilateral to Mho
characteristics to provide stable operation.

3.2.2.2 EARTH FAULT FIXED REACTANCE LINE TILTING

Each zone has an independent setting to set the tilt angle (σ) of the Impedance Reach line of the quadrilateral
characteristic. If dynamic tilting is disabled, the characteristic uses this setting to apply a fixed tilt to the top line.
The tilting angle is with reference to the fault current I, and is defined by:
Tilt angle = setting (σ) = Ð Iph/I
The setting range is +/- 30°. A negative angle sets a downward tilt and a positive angle sets an upward tilt.
Operation occurs when the operating current I lags the polarizing current Iph.
The Impedance Reach line of the characteristic in the Z1 plane is shown in the following diagram:

Z 1-plane

 Iph j 
+jX Ð e 
 I 
V IZ

Z V I

+R

V02731

Figure 65: Impedance Reach line in Z1 plane

For all V/I vectors below the Impedance Reach line, the following condition is true:
Ð (V/I-Z) ≤ σ
or
Ð (V – I.Z) ≤ I + σ
If mutual compensation is not applied, for an earth-fault loop
V = Vph
and
I = Iph + kZN.IN
so the signals fed into comparator are:
S1 = Vph – Iph.Zreplica

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S2 = Iph Ð σ
where: Zreplica is the replica forward reach
The impedance below the Impedance Reach line is detected when the angle between the signals is less than 0°:
For products that have mutual compensation, if the mutual compensation is applied, then
Zreplica =Z(1+kZN.IN/Iph+kZM.IM/Iph).
The following figure shows the ZLP-plane representation of the characteristic:

Z LP -plane

+jX Z  k ZN  I N I ph V ph I ph  Z replica

Z replica
Z

V ph I ph

+R

V02732

Figure 66: Impedance Reach line in ZLP plane

The Impedance Reach line tilting angle in the ZLP plane is fixed at σ (Zx Tilt Top Line setting).
The Impedance Reach line tilting angle in the Z1 plane is defined as follows:
Tilt angle = Ð(Iph/I) + σ = Ð(Iph/(Iph + kZN.IN)) + σ
If the healthy phase currents are much less than the current of the faulty phase, then IN ≈ Iph. The tilting angle in
this case is fixed at the following value:
Tilt angle = Ð((1/(1 + kZN)) + σ
For products that have mutual compensation, if the mutual compensation is enabled, the tilting angle is:
Tilt angle = Ð(Iph/(Iph + kZN.IN+ kZM.IM)) + σ
The replica reach Zreplica depends on the ratio of IN/Iph. If IN ≈ Iph (and if mutual compensation is not applied)
then:
Zreplica =Z (1 + kZN)
So the characteristic is static.
The general characteristic in the ZLP plane is shown in the following figure:

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ZLP plane
+jX

Zreplica

Vph / Iph

R’ LP R LP
+R

3°
Z’ replica

V02733

Figure 67: General characteristic in ZLP plane

The comparators used for the reactance lines are as per the following table:
Zone Line S1 S2 Condition
Forward or Offset Impedance Reach Vph - Iph.Zreplica Iph∠σ ∠S1 -∠S2 < 0º
Forward or Offset Reverse Impedance Reach Vph - Iph.Z’replica Iph∠-3º ∠S1 -∠S2 > 0º
Reverse Impedance Reach Vph + Iph.Zreplica -Iph∠σ ∠S1 -∠S2 < 0º
Reverse Reverse Impedance Reach Vph + Iph.Z’replica -Iph ∠-3º ∠S1 -∠S2 > 0º

3.2.2.3 EARTH FAULT DYNAMIC REACTANCE LINE TILTING

If you enable dynamic tilting, the reactance lines of the earth-fault Distance Quadrilateral characteristic can
dynamically tilt on the positive sequence impedance (Z1) plane. If the line is polarized with negative sequence
current (I2), the total tilt is made up of the difference between the angle of I2 and the angle of the Distance
protection current (I), plus the user-settable fixed tilt angle σ:
Dynamic Tilt Angle = ∠(I2 / I) + σ
The default value of the fixed tilt is -3°. It is introduced to reduce the possibility of overreach caused by any small
differences between the negative sequence source impedances, and general CT/VT angle tolerances.
The tilting of Earth-Fault Quadrilateral characteristic reactance lines are constrained to prevent inappropriate
excessive tilting according to the following criteria:
● The Zone 1 Impedance Reach line dynamic tilt can only be applied to bring the Resistive Reach end of the
line towards the +R-axis. This ensures that Zone 1 does not overreach and maintains grading/selectivity
with downstream protection.
● For the other zones (including Zone 1X and Zone 4) the dynamic tilt of the Impedance Reach line can only
act in the sense to prevent underreaching. (This is particularly important for zones used to key channel-
aided distance schemes).
● For Forward operating zones (except Zone 1) the Impedance Reach line dynamic tilt is applied to tilt the
Resistive Reach end of the line away from the +R axis.

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● For Reverse operating zones the dynamically tilting line is in the opposite quadrant of the characteristic
compared with Forward/Offset Zones and the dynamic tilt moves the line away from the resistive axis.
● For Offset zones, the Impedance Reach lines tilt away from the R-axis, whilst the Reverse Impedance Reach
Lines tilt towards the +R axis. This avoids overreaching in the reverse direction.
● For products that feature single-phase tripping, when one circuit breaker pole is open during a single-pole
autoreclose sequence, dynamic tilting is automatically disabled. The fault current is used as the polarizing
signal and a fixed -7° tilt is applied. The additional tilt reduces the possibility of overreach caused by using
the faulted phase as the reference.

Note:
Zone 1X used in Zone 1 Extension Schemes uses the Zone 2 tilt settings to ensure that it does not underreach.

Dynamic tilting of reactance lines only occurs when the line is polarized with I2. If Iph is used as the polarizing
quantity the tilt of the Impedance Reach line is fixed. If fixed tilting is selected, Iph is always used. If dynamic tilting
is enabled, then the protection will decide whether to use I2 or Iph (and hence whether dynamic tilting will apply)
according to the angular relationship between I2 and Iph.
The following criteria are applied:
● If the angle between I2 and Iph is more than 45°, the Quadrilateral characteristics are disabled and Mho
characteristics are used instead.
● If the angle between I2 and Iph is less than 45°, Leading and lagging polarizing currents are allocated
according to the phase relations between I2 and Iph as presented in the diagram below:

I LEAD  I ph I ph I LEAD  I 2
I LAG  I 2 I LAG  I ph

I2
I ph
I2

V02728

Figure 68: Phase relations between I2 and Iph for leading and lagging polarizing currents

The comparators used for the reactance lines are allocated as per the following table:
Zone Line S1 S2 Condition

Zone 1 Vph - IphZreplica ILAG∠σ ∠S1 -∠S2 < 0º

Impedance Reach
Reverse Impedance
Zone 1 Vph - IphZ’replica ILAG∠-3º ∠S1 -∠S2 > 0º
Reach
Forward or Offset zones (except Zone
Impedance Reach Vph - IphZreplica ILEAD∠σ ∠S1 -∠S2 < 0º
1)
Forward or Offset zones (except Zone Reverse Impedance
Vph - IphZ’replica ILAG∠-3º ∠S1 -∠S2 > 0º
1) Reach
Reverse Impedance Reach Vph + IphZreplica -ILEAD∠σ ∠S1 -∠S2 < 0º
Reverse Impedance
Reverse Vph + Iph Z’replica -ILAG∠-3º ∠S1 -∠S2 > 0º
Reach

If ILEAD is I2 the lines are dynamically tilted up from the fixed angle.

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If ILEAD is Iph, the fixed tilt applies.

If ILAG is I2, the lines are dynamically tilted down from the fixed angle.
If ILAG is Iph, the fixed tilt applies.

3.2.2.4 EARTH FAULT RESISTIVE BLINDERS

The Resistive Reach settings are used to select the resistive limits of the Quadrilaterals.
The Earth Fault reach settings are set according to the positive sequence line impedance, so are generally identical
to the settings of the Phase Fault elements.
Since the Earth Fault reach settings are set according to the positive sequence line impedances, the relationship
between the positive sequence impedances and the earth-fault loop impedances needs to be understood.
Consider the general characteristic in the Z1 plane shown in the following figure:

+jX
Z1 plane
Ð (Iph / I) + 

V/I

R’
+R
Z’ R

Ð (I ph / I) – 3°
V02734

Figure 69: General characteristic in Z1 plane

R = RLP (Iph/I) and R’ = R’LP.(Iph/I)

I = Iph +kZN.IN
For products that have mutual compensation, if the mutual compensation is enabled, then
I = Iph +kZN.IN +kZM.IM
If the healthy phase currents are much less than the current of the faulty phase and the mutual compensation is
disabled, then IN ≈ Iph (the faulty phase current) and the characteristic in the Z1 plane is simplified:

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+jX Z 1 plane

 1 
Ð  
 1  k ZN 
Z
 1 
R 'LP   
 1  k ZN   1 
RLP   
 1  k ZN 
R’ reach Rreach
+R
Z’
 1 
Ð   3°
 1  k ZN 
V02735

Figure 70: Simplified characteristic in Z1 plane

Rreach = ((RLP./(1 + kZN)).sin( Z + a)),

R’reach = ((R’LP./(1 + kZN)).sin( Z + a)),
where: a is the angle of 1/(1 + kZN):

a = (1/(1 + kZN))
In typical cases the sine ratio coefficient term is close to unity so the simplified equations can be used:
Rreach = RLP / ǀ (1 + kZN) ǀ,
R’reach = R’LP / ǀ (1 + kZN) ǀ,
So in terms of replica impedances and loop resistances, the comparators used for the resistance lines are as per
the following table:
Zone Line S1 S2 Condition
Forward or Offset Resistive reach Vph - Iph.RLP Iph.Zreplica ∠S1 -∠S2 > 0º
Forward or Offset Reverse resistive reach Vph - Iph.R’LP Iph.Zreplica ∠S1 -∠S2 < 0º
Reverse Resistive reach Vph + Iph.RLP -Iph.Zreplica ∠S1 -∠S2 > 0º
Reverse Reverse resistive reach Vph + Iph.R’LP -Iph.Zreplica ∠S1 -∠S2 < 0º

The Resistive Impedance Reach side of the earth zone is controlled by the Resistive Reach setting applied (Rx Gnd
Resistive). This defines the fault arc resistance that can be detected for a single phase-earth fault. For such a fault,
the fault resistance appears in the total fault loop (out and return loop), in which the line impedance is Z1 x (1 +
kZN), if IN @ Iph.
Most injection test sets plot impedance characteristics in positive sequence terms, so that the right-hand intercept
appears less than the setting applied (Rn Gnd Resistive /(1+ kZN)). The left hand side is set by the Rn Gnd Res Rev
setting and acts similarly.

Note:
The resistive reach lines of earth-fault Quadrilateral characteristics are not affected by the type of tilting used by the reactive
lines (fixed or dynamic), nor by the angle values.

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3.2.2.5 EARTH FAULT QUADRILATERAL CHARACTERISTICS SUMMARY

The inputs to the comparators used for the earth-fault Quadrilaterals are summarised in the following table:
Zone Line S1 S2 Condition
Zone 1 Impedance Reach Vph - Iph.Zreplica ILAG ∠ σ ∠S1 -∠S2 < 0º
Zone 1 Reverse Impedance Reach Vph - Iph.Z’replica ILAG ∠-3º ∠S1 -∠S2 > 0º
Forward or Offset zones (except
Impedance Reach Vph - Iph.Zreplica ILEAD ∠ σ ∠S1 -∠S2 < 0º
Zone 1)
Forward or Offset zones (except
Reverse Impedance Reach Vph - Iph.Z’replica ILAG ∠-3º ∠S1 -∠S2 > 0º
Zone 1)
Reverse Impedance Reach Vph + Iph.Zreplica -ILEAD ∠ σ ∠S1 -∠S2 < 0º
Reverse Reverse Impedance Reach Vph + Iph.Z’replica -ILAG ∠-3º ∠S1 -∠S2 > 0º
Forward or Offset Resistive Reach Vph - Iph.RLP Iph.Zreplica ∠S1 -∠S2 > 0º
Forward or Offset Reverse Resistive Reach Vph - Iph.R’LP Iph.Zreplica ∠S1 -∠S2 < 0º
Reverse Resistive Reach Vph + Iph.RLP -Iph.Zreplica ∠S1 -∠S2 > 0º
Reverse Reverse Resistive Reach Vph + Iph.R’LP -Iph.Zreplica ∠S1 -∠S2 < 0º

If dynamic tilting is selected, then:

If ILEAD is I2 the lines are dynamically tilted up from the fixed angle (Forward sense)
● If ILEAD is Iph, the fixed tilt applies.
● If ILAG is I2, the lines are dynamically tilted down from the fixed angle (Forward sense)
● If ILAG is Iph, the fixed tilt applies.

If fixed tilting is selected, then he current input quantity for S2 is Iph in all cases.
The positive sequence reach settings used for the Earth-Fault Quadrilateral characteristics are summarised in the
table below:
Reverse Resistive
Zone Type Impedance Reach Z Reverse Impedance Reach Z’ Resistive Reach R
Reach R’
1 Ph-Earth Forward Z1 Gnd. Reach * (1 + kZN) 0.25 Z R1 Gnd Resistive 0.25 R
2 Ph-Earth Forward Z2 Gnd. Reach * (1 + kZN) 0.25 Z R2 Gnd Resistive 0.25 R
3 Ph-Earth Forward Z3 Gnd. Reach * (1 + kZN) 0.25 Z R3 Gnd Resistive 0.25 R
3 Ph-Earth Reverse Z3 Gnd. Reach * (1 + kZN) 0.25 Z R3 Gnd Resistive 0.25 R
3 Ph-Earth Offset Z3 Gnd. Reach * (1 + kZN) Z3’ Gnd Rev Rch * (1 + kZN) R3 Gnd Resistive R3’ Ph Res. Rev
4 Ph-Earth Reverse Z4 Gnd. Reach * (1 + kZN) Z R4 Gnd Resistive 0.25 R
P Ph-Earth Forward ZP Gnd. Reach * (1 + kZN) 0.25 Z RP Gnd Resistive 0.25 R
P Ph-Earth Reverse ZP Gnd. Reach * (1 + kZN) 0.25 Z RP Gnd Resistive 0.25 R
P Ph-Earth Offset ZQ Gnd. Reach * (1 + kZN) ZP’ Gnd Rev Rch * (1 + kZN) RP Gnd Resistive RP’ Gnd Res. Rev
Q Ph-Earth Forward ZQ Gnd. Reach * (1 + kZN) 0.25 Z RQ Gnd Resistive 0.25 R
Q Ph-Earth Reverse ZQ Gnd. Reach * (1 + kZN) 0.25 Z RQ Gnd Resistive 0.25 R
Q Ph-Earth Offset ZQ Gnd. Reach * (1 + kZN) ZQ’ Gnd Rev Rch * (1 + kZN) RQ Gnd Resistive RQ’ Gnd Res. Rev
where kZN = (Z0 - Z1) / 3Z1 and is defined by two settings: kZN Res Comp and KZN Res Angle.

3.3 QUADRILATERAL CHARACTERISTIC FOR PHASE FAULTS

Quadrilateral characteristics are available for phase fault protection. A mix of Directional Forward, Directional
Reverse, and Offset characteristics is available. Zone 1 and Zone 2 are Directional Forward. Zone 4 is Directional

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Reverse. Other zones can be set independently as Offset, Directional Forward, or Directional Reverse. Each zone is
independent and is defined by an Impedance Reach Line, a Reverse Impedance Reach Line, and two resistive
blinders. The two resistive blinders (Resistive Reach Line and Reverse Resistive Reach Line) are parallel to the zone
characteristic impedance angle. The two reactance lines of each Quadrilateral exhibit a characteristic tilt. In the
phase fault characteristics the tilt of the Reverse Impedance Reach Line is preset, whilst you can choose the tilt
angle for the Impedance Reach Line.

3.3.1 PHASE FAULT IMPEDANCE REACH LINE

The tilt of the top line can be set independently for each zone. It is defined by a reach setting, Z, and a tilt angle, σ,
as shown in the following diagram:

+jX
V IZ


Z V I

+R

V02722

Figure 71: Impedance Reach line construction

Referenced to the fault current I, the angle of tilt is equal to the setting σ. A negative angle sets a downward tilt
and a positive angle sets an upward tilt. Operation can occur when the operating signal lags the polarizing signal.
A negative angle sets a downward tilt and a positive angle sets an upward tilt.
For all V/I vectors below the Impedance Reach line, the following condition is true:
Ð (V/I - Z) £ σ
or
Ð (V - I.Z) £ Ð I.Ð σ
The resultant two signals provided to the comparator are:
S1 = V - I.Z
S2 = I.Ð σ
Impedance on the tripping side of the Impedance Reach line is detected when the angle between S1 and S2 is less
than 0°.

3.3.2 PHASE FAULT REVERSE IMPEDANCE REACH LINE

The Reverse Impedance Reach line of the phase quadrilateral elements has a tilt that is fixed at -3° as shown in the
following diagram:

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+jX

+R
+Z’ V/I

-3°
V / I - Z’
V02723

Figure 72: Reverse impedance reach line construction

For an Offset zone, Z’ is the settable reverse reach. For a directional zone Z’ is a fixed percentage (either 25% or
100%) of the forward reach (Z) in the opposite direction.
The signals provided to the comparator are:
S1 = V - I.Z’
S2 = I.Ð -3°
Impedance on the tripping side of the Reverse Impedance Reach line is detected when the angle between S1 and
S2 is greater than 0°.

3.3.3 PHASE FAULT RESISTIVE REACH LINE

Refer to the following figure:

IED
Dist V I  Half of the loop
Bus
A

ZF
R LP
B
Network Line

V02725

Figure 73: Resistive reach of phase elements

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The setting Rx Ph. Resistive defines the complete loop resistive reach RLP of the Distance Protection.
Since a phase-to-phase distance element measures half of the loop, the right-hand resistive reach R, of the
characteristic is equal to half of the setting value.
R = ½ Rx Ph. Resistive

+jX

V/I
V/I-R

R ÐZ +R

V02724

Figure 74: Resistive Reach line construction

For all V/I vectors which are on the left side of the right blinder the following condition is true:
Ð (V/I - R) £ Z
or
Ð (V - I.R) £ Ð I. Z
The two signals provided to the comparator are:
S1 = V - I.R
S2 = I.Z
The impedance on the left side of the right hand resistive line is detected when the angle between S1 and S2 is
greater than 0°.

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3.3.4 PHASE FAULT REVERSE RESISTIVE REACH LINE

+jX

ÐZ
V/I
V / I - R’ +R
R’

V02726

Figure 75: Reverse resistive reach line construction

For an offset zone, R’ is the settable reverse resistive reach (=½*Rx’ Ph Res. Rev.). . For a directional zone, R’ is fixed
at 25% of the Resistive Reach (=½*Rx Ph Res. Rev.), acting in the opposite direction.
The two signals provided to the comparator are:
S1 = V - I.R
S2 = I.Z
The impedance on the right side of the left hand resistive line is detected when the angle between S1 and S2 is less
than 0°.

3.3.5 PHASE FAULT QUADRILATERAL CHARACTERISTIC SUMMARY

The phase fault Quadrilateral characteristics are summarised in the following figure and tables:

+jX

V/I

R’ R +R
Z’
3°

V02727

Figure 76: Phase Fault Quadrilateral characteristic summary

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The comparators used for the Phase-Fault Quadrilateral zones are summarised in the following table:
Condition
Zone Line S1 S2
(∠S1 - ∠S2)
Forward/Offset Impedance Reach Line V – I.Z I.Ð σº <0º
Forward/Offset Reverse Impedance Reach Line V – I.Z’ I.Ð 3º >0º
Forward/Offset Resistive Reach Line V – I.R I.Z >0º
Forward/Offset Reverse Resistive Reach Line V – I.R’ I.Z <0º
Reverse Impedance Reach Line V + I.Z -I.Ð σº <0º
Reverse Reverse Impedance Reach Line V + I.Z’ -I.Ð 3º >0º
Reverse Resistive Reach Line V + I.R -I.Z >0º
Reverse Reverse Resistive Reach Line V + I.R’ -I.Z <0º

The positive sequence reach settings used for the Phase-Fault Quadrilateral characteristics are summarised in the
following table:
Reverse Impedance Reverse Resistive
Zone Type Impedance Reach Z Resistive Reach R
Reach Z’ Reach R’
1 Ph-Ph Forward Z1 Ph. Reach 0.25 Z ½*R1 Ph. Resistive 0.25 R
2 Ph-Ph Forward Z2 Ph. Reach 0.25 Z ½*R2 Ph. Resistive 0.25 R
3 Ph-Ph Forward Z3 Ph. Reach 0.25 Z ½*R3 Ph. Resistive 0.25 R
3 Ph-Ph Reverse Z3 Ph. Reach 0.25 Z ½*R3 Ph. Resistive 0.25 R
3 Ph-Ph Offset Z3 Ph. Reach Z3’ Ph Rev Reach ½*R3 Ph. Resistive ½*R3’ Ph Res. Rev.
4 Ph-Ph Reverse Z4 Ph. Reach Z ½*R4 Ph. Resistive 0.25 R
P Ph-Ph Forward ZP Ph. Reach Z ½*RP Ph Resistive 0.25 R
P Ph-Ph Reverse ZP Ph. Reach Z ½*RP Ph Resistive 0.25 R
P Ph-Ph Offset ZQ Ph. Reach ZP’ Ph Rev Reach ½*RP Ph Resistive ½*RP’ Ph. Res. Rev.
Q Ph-Ph Forward ZQ Ph. Reach Z ½*RQ Ph Resistive 0.25 R
Q Ph-Ph Reverse ZQ Ph. Reach Z ½*RQ Ph Resistive 0.25 R
Q Ph-Ph Offset ZQ Ph. Reach ZQ’ Ph Rev Reach ½*RQ Ph Resistive ½*RQ’ Ph. Res. Rev.

Note:
Not all zones feature in all product variations.

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4 PHASE AND EARTH FAULT DISTANCE PROTECTION IMPLEMENTATION

The Distance protection requires line data to be input to operate correctly. You must first input the data using the
settings in the LINE PARAMETERS column.
The Distance protection has a Setting Mode which is set to Simple by default. We recommend the default for
most applications. Instead of entering distance zone impedance reaches in ohms, zone settings are simply entered
in terms of percentage of the protected line data specified in the Line Impedance setting in the LINE PARAMETERS.
The setting assumes that the residual compensation factor is equal for all zones. The protection calculates the
required reach settings from the percentage settings. The calculated zone reaches are available for viewing but
you cannot change the values.
An Advanced Setting Mode allows individual distance ohmic reaches and residual compensation factors to be
entered for each zone. When advanced mode is selected, all 'percentage' settings associated with the Simple
setting mode are hidden and the Distance zone settings need to be entered for each zone in the DIST. ELEMENTS
column.

4.1 PHASE FAULT CHARACTERISTICS

Each phase zone can be Enabled or Disabled using the Zone Ph Status settings in the DISTANCE SETUP
column.
Characteristics can be either 'Quadrilateral' (polygon), or Mho (circular). The chosen characteristic applies to all
zones. All distance elements are directionalized and use residual compensation of the corresponding phase fault
reach.

4.2 EARTH FAULT CHARACTERISTICS

Each ground zone can be Enabled or Disabled using the Zone Gnd Status settings in the DISTANCE SETUP
column.
Characteristics can be either 'Quadrilateral' (polygon), or Mho (circular). The chosen characteristic applies to all
zones. All distance elements are directionalized and use residual compensation of the corresponding phase fault
reach.

4.3 DISTANCE PROTECTION TRIPPING DECISION

A fault is detected if the phase voltage drops below 70%, or if the phase selector picks up. When a fault is detected,
the protection stores values recorded over the two previous cycles. These are used to provide a reference for
memory polarization, etc, as the fault is processed.
For security, a number of criteria must be satisfied before the distance protection issues a trip command. These
are as follows:
● The phase selector needs to identify the faulted phases and ensure that only the correct distance
measuring zones can issue a trip. Possible phase selections are AN, BN, CN, AB, BC, CA, and ABC. For double
phase-earth faults, the selection is AB, BC or CA, with N (neutral) for indication only.
● For the selected phase-earth elements the phase and the neutral currents must exceed the minimum
sensitivity threshold. For the selected phase-to-phase elements the loop current must exceed the minimum
sensitivity threshold. By default, this sensitivity is 5%In for phase-earth faults and, for phase-to-phase faults
both of the faulted phases must exceed 5%In. You can raise this minimum sensitivity if necessary, but this is
not normally required.
● For an earth-fault distance element to operate, the corresponding biased neutral current detector must
have picked up.
● The faulted phase impedance must appear in a tripping (measuring) zone, corresponding to the phase
selection.

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● For directional zones, the directionality element must agree with the tripping zone. Zones 1, 2, and 4 are
always directional whereas other zones are only directional if set as directional. In directional zones the
directionality element must agree with the tripping zone. For example, Zone 1 is a Forward Directional zone
and must not trip for Reverse faults. Therefore a Zone 1 trip is only allowed if the directionality element
issues a Forward decision. Zone 4 is reverse-looking so needs a Reverse decision by the directionality
element.
● The set time delay for the measuring zone must expire, with the measured fault impedance remaining
inside the zone characteristic for the duration of the delay time. Typically, Zone 1 has no time delay
(instantaneous), whereas all other zones have time delays.
● Where channel-aided distance schemes are used, the time delay tZ2 for overreaching Zone 2 may be
bypassed for some of the schemes.

4.4 DISTANCE PROTECTION PHASE SELECTION

Phase selection allows the product to identify exactly which phases are involved in a fault and enables the correct
measuring zones to trip.
Operation of the distance elements is controlled by a Superimposed Current Phase Selector. For a period of two-
cycles after pick-up of the phase selector, only elements associated with the fault type selected by the phase
selector are allowed to operate. If these elements do not operate, all elements are enabled for the following five
cycles, before the phase selector returns to its quiescent state.
Operation of an enabled distance element during the two-cycle, or five-cycle period, causes the phase selector
state to be maintained until the element resets. An exception to this is when the phase selector changes decision
while an element is operated. In this case, the selected elements are reset and the two cycle period restarts with
the new selection.

Note:
Any existing trip decision is not reset under this condition. After the first cycle following a selection, the phase selector is only
permitted to change to a selection involving additional phases.

On double phase-to-earth faults, only the phase-to-phase elements are enabled. This is because they are
generally more accurate under these conditions than earth fault elements. A biased neutral current level detector
operates to indicate the involvement of earth in the fault.

4.4.1 FAULTED PHASE SELECTION

The faulted phase or phases are selected by comparing the magnitudes of the three phase-to-phase
superimposed currents. A single phase-to-earth fault produces the same superimposed current on two of these
signals and zero on the third. A phase-to-phase or double-phase-to-earth fault produces one signal which is larger
than the other two. A three phase fault produces three superimposed currents which are the same size. The figure
below shows how the change in current can be used to select the faulted phases for a C phase-to-ground (CN)
fault.

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AB

BC

CA

V02702

Figure 77: Phase to phase current changes for C phase-to-ground (CN) fault

As default, phase selection is made when any superimposed current exceeds 5% of nominal current (0.05 In).
Any superimposed current greater than 80% of the largest superimposed current is included in the phase selection
logic.
For applications which might experience high levels of sub-synchronous currents, the phase selector automatically
raises the threshold from the default 5% of In, in order to prevent sporadic operation whilst maintaining high
sensitivity to faults.

Note:
If you test the distance elements using test sets, which do not provide a dynamic model to generate true fault delta
conditions, you need to set Static Test Mode to Enabled in the COMMISSION TESTS column. This disables phase selector
control and forces the distance protection to use a conventional (non-delta) directional line.

The phase selector picks up on fault detection, and enables Distance protection on all elements which have been
selected by the pick-up. These elements are enabled for 2 cycles, and normally this will result in tripping. On double
ground-to-phase faults, only appropriate phase elements are enabled. This is because they are generally more
accurate than ground elements under these conditions. If, however, tripping is not initiated within the 2 cycles, for
the following 5 cycles all Distance elements (including all phase-earth elements) are enabled. During these five
cycles, this could lead to incorrect operation of earth-fault elements in case of an out-of-zone double-phase-earth
fault. This is because one of the phase-earth elements could demonstrate significant overreach, which may result
in maloperation. To help prevent this, a Biased Neutral Current Detector is incorporated.

4.5 BIASED NEUTRAL CURRENT DETECTOR

The Biased Neutral Current Detector permits the earth-fault elements to operate only if sufficient neutral current is
detected. The Biased Neutral Current Detector characteristic is illustrated in the following figure.

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I N  I A  I B  IC

Neutral current
K  10%

Bias current I BIAS  max  I A  I B , I B  I C , I C  I A 

V02777

Figure 78: Biased Neutral Current Detector Characteristic

The neutral current detector uses the maximum of the three phase current differences as a biasing value. The
slope of the characteristic is fixed at 10%.
Biasing the neutral current detector assures that the detector is sensitive enough to operate for any single-phase
fault, without the risk of picking up on neutral spill current during phase-to-phase faults. The neutral spill current
might arise from mismatched current transformers or current transformer saturation. The biasing also ensures
that the earth fault distance elements are generally disabled for double-phase-to-earth faults with high resistance
in the neutral. Such faults can occur in resistively earthed systems, or in solidly earthed systems due to high arc
resistance. Given that these conditions are very similar to pure phase-to-phase faults, the earth fault distance
elements can exhibit high measuring errors which the use of the neutral current detector overcomes.

4.6 DISTANCE ELEMENT ZONE SETTINGS

The settings for the Distance protection are contained in the DISTANCE SETUP and DIST. ELEMENTS columns of the
relevant settings group.
The Distance protection has a Setting Mode which is set to Simple by default. We recommend the default for
most applications.. Instead of entering distance zone impedance reaches in ohms, zone settings are simply
entered in terms of percentage of the protected line data specified with the Line Impedance setting in the LINE
PARAMETERS column. The setting assumes that the residual compensation factor is equal for all zones. The
protection calculates the required reach settings from the percentage settings. The calculated zone reaches are
available for viewing but you cannot change a value.
An ‘Advanced’ Setting Mode allows individual distance ohmic reaches and residual compensation factors to be
entered for each zone. When ‘Advanced’ mode is selected, all ‘percentage’ settings that are associated to ‘Simple’
setting mode in the DISTANCE SETUP column will be hidden and the Distance zone settings need to be entered for
each zone in the DIST. ELEMENTS column.
If you use the ‘Simple’ Settings Mode, the DISTANCE ELEMENTS column contains a list of what settings have been
automatically calculated and applied. This list is useful as a reference for commissioning and periodic injection
testing. If you use the ‘Advanced’ Setting Mode, however, you must enter all settings for each zone.

Note:
Distance zones are directionalized by a Delta Directional decision. The characteristic angle for this decision is set with the
Delta Directional configuration, in the DISTANCE SETUP column. The default setting is 60°.

4.6.1 DIRECTIONALIZING THE DISTANCE ELEMENTS

By default a Delta technique is used for directionalizing the Distance protection. It acts on step-changes (Deltas) of
current and voltage to determine whether potential fault conditions are in the forward or reverse direction. The
Delta voltage and current thresholds used in the Distance Directional decision are fixed for optimum performance.
The Directional characteristic angle, (also known as the relay characteristic angle – RCA) is set to 60° by default,
but you can change this to suit your application using the Dir. Char Angle setting in the DISTANCE SETUP column.

P54x1i-TM-EN-1 171
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The Delta Directional technique needs the changes in voltage and current to exceed the preset thresholds, in order
to determine forward and reverse decisions. If these thresholds are not exceeded, but a potential fault is detected,
the Distance protection reverts to a conventional directional technique with memory polarization of the voltage.
If you don’t want to use the Delta directional technique, set Dir. Status in the DISTANCE SETUP column to
Disabled in which case memory polarization is used.

4.6.2 ADVANCED DISTANCE ZONE SETTINGS

The Setting Mode is set in the DISTANCE SETUP column. There are two possible modes; simple and advanced.
If set to Simple, you need only to enter the line parameters such as length, impedances and residual
compensation found in the LINE PARAMETERS column. You set the reach in terms of percentage of the protected
line.
We recommend the Advanced setting for networks where the protected and adjacent lines are of dissimilar
construction, requiring independent zone characteristic angles and residual compensation. In this setting mode all
individual distance ohmic reach and residual compensation settings and operating current thresholds per each
zone are accessible.
If you use the advanced setting mode, you also need to set the minimum current sensitivity for each zone (Zn
Sensit. Iph>n, and Zn Sensit. Ignd>n).
The current sensitivity setting for each zone is used to set the minimum current that must flow in each of the
faulted phases before a trip can occur. For example, if a phase A-B line fault is present, the protection must
measure both currents Ia and Ib above the minimum set sensitivity.
The default setting is 7.5% In for Zones 1 and 2, and 5% In for other zones, ensuring that distance element
operation is not constrained, right through to an SIR ratio of 60.
When quadrilateral characteristics are used, you can set the tilt angle of the impedance reach lines.
In Advanced setting mode, the impedance reach lines of the quadrilateral characteristics are fixed, but not as
horizontal reactance lines. To account for phase angle tolerances in the current and voltage transformers, etc., the
lines are tilted downwards at a droop of -3°.
In Advanced setting mode, the tilt of the top lines can be changed from these values.

4.6.3 DISTANCE ZONE SENSITIVITIES

In the Simple Setting Mode a minimum current sensitivity applies but the value is automatically calculated and
applied based on the data entered in the ‘Simple’ settings fields. The criteria used to calculate the setting value are
needed for a minimum value of current flowing in the faulted loop and for the Zone reach point voltage. For Zones
other than 1 or 2, the minimum current must be greater than 5% of the rated current and the minimum voltage at
the Zone reach point must be 0.25V. The current equating to the reach point criteria can be expressed as 0.25/
Zone reach and the sensitivity can be expressed as:
Sensitivity = max (5%In, (0.25/Zone reach))
Zones 1 and 2 are set less sensitive than the reverse Zone 4. This ensures stability of the protection in either an
overreaching or a blocking scheme. For Zones 1 and 2, the same criteria are applied as for the other Zones. Also a
minimum sensitivity criterion is applied, depending on the Zone 4 sensitivity. The sensitivity must exceed 1.5 x Zone
4 sensitivity and can be expressed as:-
Sensitivity (Z1, Z2) = max (5%In, (0.25/Zone reach), (1.5 x Zone 4 sensitivity))
Or
Sensitivity (Z1, Z2) = max (5%In, (0.25/Zone reach), (1.5 x (0.25/Zone 4 reach)))
The dependency on the Zone 4 element always applies, even if Zone 4 is disabled.
The default reach setting for Zones 1, 2, and 4 are 80%, 120%, and 150% respectively. For these settings the zone-
dependent terms can be reduced to:

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0.25/Zone 1 reach = 0.25/(0.8 x line impedance)

0.25/Zone 2 reach = 0.25/(1.2 x line impedance)
1.5 x (0.25/Zone 4 reach) = 0.25/line impedance
In such cases, for Zone 1, the dominant Zone reach term is that of Zone 1 and the equation can be reduced to:
Sensitivity (Z1) = max (5%In, (0.25/(0.8 x line impedance)))
For lines with an impedance of less than 6.25 Ω the Zone 1 reach term dominates and the sensitivity is greater
than 5% In. Above this line impedance the sensitivity is 5% In.
Similarly, for Zone 2, the dominant Zone reach term is that of Zone 4 and the equation can be reduced to:
Sensitivity (Z2) = max (5%In, (0.25/line impedance))
For lines with an impedance of less than 5 Ω the Zone reach term dominates and the sensitivity is greater than 5%
In. Above this line impedance the sensitivity is 5% In.
In Advanced setting mode the same qualifications for distance zone minimum sensitivity as minimum sensitivity
should be applied to ensure distance element accuracy.

4.7 CAPACITOR VT APPLICATIONS

The device provides a setting for capacitor-coupled voltage transformer (CVT) applications. This setting is CVT
Filters and is found in the DISTANCE SETUP column. The default setting is Disabled which us used for
conventional wound voltage transformers. If CVTs are used you can set CVT Filters to either Passive, or Active
to reduce the effects of transient components caused by close up faults.

4.7.1 CVTS WITH PASSIVE SUPPRESSION OF FERRORESONANCE

Passive suppression to reduce the effects of transient components that could be caused by close up faults uses an
anti-resonance design and the resulting transient distortion is fairly small. Passively suppressed CVTs are
sometimes classed as type 2. In passive CVT applications, the effect on characteristic accuracy is generally
negligible for source to line impedance ratios of less than 30 (SIR < 30). However, with a high Source-to-Line
Impedance Ratio (SIR), it is advisable to set CVT Filters to Passive.
By setting CVT Filters to Passive, the protection can trip at sub-cycle speeds, unless the actual SIR is above that
which is set. If the SIR is estimated to be higher than the setting, the instantaneous operating time is increased by
about a quarter of a power frequency cycle. The protection estimates the SIR as the ratio of nominal rated voltage
Vn to the size of the comparator vector IZ (in volts):
SIR = Vn/IZ
where:
● Vn = Nominal phase to neutral voltage
● I = Fault current
● Z = Reach setting for the zone concerned

Therefore, for slower operation, I needs to be low, as restricted by a relatively weak infeed and Z needs to be small,
as for a short line.

4.7.2 CVTS WITH ACTIVE SUPPRESSION OF FERRORESONANCE

Active suppression to reduce the effects of transient components that could be caused by close up faults uses a
tuned L-C circuit in the CVT. The damping of transients is not as efficient as for passive suppression. Active
suppression CVTs are often called type 1 CVTs. In active CVT applications, to ensure reach point accuracy, the CVT
Filters setting should be set to Active. The protection varies according to the calculated source to line
impedance ratio SIR (= Vn / IZ).

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where:
● Vn = Nominal phase to neutral voltage
● I = Fault current
● Z = Reach setting for the zone concerned

Sub-cycle tripping is maintained for lower SIRs, up to a ratio of 2. The instantaneous operating time is increased by
about a quarter of a power frequency cycle at higher SIRs.
Transients caused by voltage dips, however severe, do not affect the protection’s directional measurement
because it uses voltage memory.

4.8 LOAD BLINDING

Load blinders are provided for both phase and earth fault distance elements, to prevent incorrect-tripping for
heavy load flow. A blinder envelope which surrounds the expected worst case load limits should be configured to
block tripping for any impedance measured in the blinded region. Only a fault impedance which is outside the area
bounded by the load blinders is allowed to cause a trip. The blinder characteristics are shown in the following
figure:

jX

Operate area

Blind area Blind area

β R

Operate area

V00645

Figure 79: Load Blinder Characteristics

● Z denotes the Load/B Impedance setting. This sets the radius of the under-impedance circle.
● ß denotes the Load/B Angle setting. This sets the angle of the two blinder boundary lines - the gradient of
the rise or fall with respect to the resistive axis.
The protection can allow the load blinder to be bypassed any time that the measured voltage for the phase in
question falls below an undervoltage setting. Under such circumstances, the low voltage could not be attributed to
normal voltage excursion tolerances on load. A fault must be present on the phase in question, so it is acceptable
to override the blinder action and allow the Distance protection to trip for an in-zone measurement. The
advantage of bypassing the load blinders is that the resistive coverage for faults near to the protection location
can be higher.

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To use the load blinders you must set the Load Blinders setting to Enabled. You then set appropriate values for
the blinder impedance using the Z< Blinder Imp setting, the b value using the Load/B Angle setting, and the
undervoltage threshold using the Load Blinder V< setting.

4.9 CROSS COUNTRY FAULT PROTECTION

"Cross country fault" is a term that has been adopted to cover a fault scenario where two separate single-phase
faults occur on a system together. For example, where single-pole tripping is employed, if a single phase-to-earth
fault occurs, the voltages on the other phases can rise above normal. This may cause a breakdown elsewhere on
the system and result in another fault involving a different phase to the one on which the original fault occurred.
The distance protection in this product features cross-country override logic, which is built into the phase selector.
The logic is dedicated to providing Cross-Country fault protection for solidly-earthed systems. It ensures correct
operation a fault in Zone 1 that may evolve to involve a different phase. For isolated or compensated earthing
systems a settable phase preferential logic will be used for cross-country faults instead.
The cross-country override logic:
● Prevents possible false operation of the phase-phase distance elements whilst allowing the appropriate
Zone1 phase-earth element to trip.
● Acts when the distance protection makes a multiple phase selection (where more than one phase is
involved in the fault), but only one Zone 1 phase-earth element picks up. Only "on-angle" operation of the
Zone 1 phase-earth element can activate the logic. this prevents incorrect operation due to impedance
encroachment.
● Allows only one Zone 1 phase-earth element to operate. The operation of that element must match the
phase pick-up indication of the phase selector. For example, if the original phase selection indicated
involvement of only B and C phases, the logic could allow a BN trip or a CN trip to override the phase-phase
selection, but override by the AN element is not allowed.
● Does not apply if more than one forward Zone 1 element picks up. In this case the fault is considered multi-
phase and the protection trips three-pole.

Note:
Load blinding can be applied for phase and earth characteristics. Residual compensation is not applied. Phase characteristics
use phase-to-phase voltage and phase-to-phase current. Earth fault characteristics use phase-to-neutral voltage and phase-
to-neutral current.

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5 DELTA DIRECTIONAL ELEMENT

Where Distance protection is being applied, a ‘Delta’ algorithm is provided to directionalize the distance elements.
If used in conjunction with aided schemes, this Delta algorithm can also provide additional protection in the form
of directional comparison protection.

5.1 DELTA DIRECTIONAL PRINCIPLE AND SETUP

Note:
The characteristic angle set in this section is also used by the Distance protection. This is because distance zones are
directionalized by the delta decision.

Delta directional comparison looks at the relative phase angle of the superimposed current DI (delta I) compared to
the superimposed voltage DV (delta V), at the instant of fault inception. The delta is only present when a fault
occurs and a step change from the pre-fault steady-state load is generated by the fault. The element issues a
forward or reverse decision which can be input into an aided channel unit protection scheme.
Under healthy network conditions the system voltage is close to Vn nominal and load current flows. Under such
steady-state conditions, if the voltage measured on each phase now is compared with a stored memory from
exactly two power-system cycles previously, the difference between them is zero. Zero voltage change (DV = 0) and
zero current change (DI = 0), except when there are changes in load current.
When a fault occurs on the system, the delta changes measured are:
DV = fault voltage (time “t”) - pre-fault healthy voltage (t-2 cycles)
DI = fault current (time “t”) - pre-fault load current (t-2 cycles)
The delta measurements are a vector difference, resulting in a delta magnitude and angle. Under healthy system
conditions the pre-fault values are those measured 2 cycles earlier. When a fault is detected the pre-fault values
are retained for the duration of the fault.
The changes in magnitude are used to detect the presence of the fault and the angles are used to determine
whether the fault is in the Forward or Reverse direction.
The following figure shows a single phase to earth fault.

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IF1

ZS1 I1 ZL1 ZR1

V1

IF/3
IF2

ZS2 I2 ZL2 ZR2

V2
voltage
generator
represents
voltage change
IF0 at fault location

ZS0 I0 ZL0 ZR0

V0

E02704

Figure 80: Sequence networks connection for an internal A-N fault

The fault is shown near to the busbar at end R of the line, and results in a connection of the positive, negative, and
zero sequence networks in series. The delta diagram shows that any fault is a generator of D, connected at the
location of the fault inception. The characteristics of the deltas are:
● The DI generated by the fault is equal to the total fault arc current.
● The DI splits into parallel paths, with part contribution from source “S” and part from remote end “R” of the
line. Therefore each element measures a lower proportion of DI.
● The DV generated by the fault is equal to the fault arc voltage minus the pre-fault voltage, so it is in anti-
phase with the pre-fault voltage.
● The DV measured by the protection is the voltage drop across the source impedance behind the protection
location. This is generally smaller than the DV measured at the fault location, because the voltage collapse
is smaller nearer to the source than at the fault.
● For fault detection, the measured DI and DV associated with the fault must be greater than the Dir I Fwd
and Dir V Fwd settings respectively.

5.2 DELTA DIRECTIONAL DECISION

Delta quantities are generated when a fault starts. The following criteria characterise the fault direction:

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For a forward fault:

DV is a decrease in voltage, so it is in the negative sense. DI is a forward current flow, so it is in the positive sense.
Where DI and DV are approximately in anti-phase, the fault is forward. The exact angle relationship for the forward
fault is:
DV / DI = - (Source impedance Zs)

For a reverse fault

DV is a decrease in voltage, so it is in the negative sense. DI is an outfeed flowing in the reverse direction, so it is in
the negative sense. Where DI and DV are approximately in phase, the fault is reverse. The exact angle relationship
for the reverse fault is:
DV / DI = (Remote Source impedance Zs’ + ZL)
where ZL is the protected line impedance and Zs’ source impedance behind the protection.
A directional characteristic angle (RCA) setting (Dir. Char Angle) allows you to set the centre of the directional
characteristic according to the amount by which the current nominally lags the reference DV. The characteristic
boundary is then +/- 90° either side of the set characteristic angle.

Note:
If Delta directional aided scheme are not used, Distance zone directionalizing uses fixed operating thresholds: DV=0.5V and
DI=5%In. If the fault DV is below the setting of 0.5V, a conventional distance line ensures correct forward/reverse polarizing.
For Delta directional aided schemes, sufficient DV must be present for tripping to occur.

The delta directional element will produce a forward decision when the angle between the delta volts and delta
current shifted by the Dir. Char Angle setting is greater than 90°. The Dir. Char Angle setting is the characteristic
angle of the source impedance, Zs.

Forward

Reverse
DI

Zs

RCA

RCA = Characteristic angle setting (Dir. Char Angle)

V02706

Figure 81: - DV Forward and Reverse tripping regions

To facilitate testing of the distance elements using test sets, which do not provide a dynamic model to generate
true fault delta conditions, set the Static Test Mode setting in the COMMISSIONING TESTS column to Enabled.
This disables phase selector control and forces the protection to use a conventional (non-delta) directional line.

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6 DISTANCE ISOLATED AND COMPENSATED SYSTEMS

6.1 PETERSON COIL EARTHED SYSTEMS

A Petersen Coil earthing system is used in compensated earthing systems, as well as being used in cases of high
impedance earthing. Petersen Coil earthed systems (also called compensated or resonant systems) are commonly
found in areas where the system consists mainly of rural overhead lines. They are particularly beneficial in
locations which are subject to a high incidence of transient faults. In a Petersen Coil earthed system, the network is
earthed via a reactor, whose reactance is tuned to be nominally equal to the total system capacitance to earth.
Similar to insulated systems, if a single-phase to earth fault is applied to a Petersen Coil earthed system, under
steady state conditions no earth fault current flows. The effectiveness of the method in reducing the current to
zero is dependent on the accuracy of the tuning of the reactance value and any changes in system capacitance
(for example due to system configuration changes) require changes to the coil reactance. In practice, perfect
matching of the coil reactance to the system capacitance is difficult to achieve, so that a small earth fault current
will flow.
In isolated and compensated earthed systems, if an earth fault current is below a certain level, then the fault will
self-extinguish due to the low current magnitude. It therefore appears as a transient phenomenon. The figure
below shows earth fault current levels, below which they self-extinguish on these types of system. Statistics
demonstrate that around 80% of earth faults in Petersen Coil earthed systems self-extinguish. This, in part,
explains their popularity.

Earth fault extinction current limits

as per DIN VDE 0228 Part 2
140

120

100
80

60

40
20

0
11kV 22kV 33kV 65kV 110kV
Residual fault current—compensated neutral
Capacitive fault current—isolated neutral
V00756

Figure 82: Current level (amps) at which transient faults are self-extinguishing

The following figure depicts a simple network earthed through a Petersen Coil reactance. It can be shown that if
the reactor is correctly tuned, theoretically no earth fault current will flow.

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Source

-I B -I C
-IC A IL

V AN V AB V ac
V AN I f  I B  I C   
jX L
jX L jX C jX C -I B
V
 0 i f AN  I B  I C (=-I B) (=-I C)
(=I L) If jX L
VAC VAB

Petersen -jXC -jXC -jXC N

jXL
Coil C B

Current vectors for A phase fault

V00631

Figure 83: Earth fault in Petersen Coil earthed system

Consider a radial distribution system earthed using a Petersen Coil with a phase to earth fault on phase C, shown
in the figure below:

I A1
IB1

I R1
-jXC1

I H1
IL IA2
IB2

jXL IR2
-jXC2

IH 2
I A3
IB3
I C3 = I F

I R3
-jXC3
IF

I H3 IH1 + I H2
I L = I F + I H1 + IH2 + I H3

V00632

Figure 84: Distribution of currents during a Phase C fault

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Assuming that no resistance is present in XL or XC, the resulting phasor diagrams will be as shown in the figure
below:

IL
I H3
IL A 3V0

IH2 -IH1
IR1 = IH1
Ib1
IH1 -IH2

IB1 IR3 IR3 = IF + IH3

= IL - IH1 - IH2
Ia1
I A1
N

C B
Vres = -3Vo Vres = -3Vo

a) Capacitive and inductive currents b) Unfaulted line c) Faulted line

V00633

Figure 85: Phasors for a phase C earth fault in a Petersen Coil earthed system

It can be seen that:

● The voltage in the faulty phase reduces to almost 0V
● The healthy phases raise their phase to earth voltages by a factor of Ö3
● The triangle of voltages remains balanced
● The charging currents lead the voltages by 90°

Using a core-balance current transformer (CBCT), the current imbalances on the healthy feeders can be measured.
They correspond to simple vector addition of IA1 and IB1, IA2 and IB2, IA3 and IB3, and they lag the residual voltage
by exactly 90º.
The magnitude of the residual current IR1 is equal to three times the steady-state charging current per phase. On
the faulted feeder, the residual current is equal to IL - IH1 - IH2 (C). This is shown in the zero sequence network
shown in the following figure:

I ROF IOF
Faulty feeder
I ROH
I ROF = Residual current on faulted feeder
I ROH = Residual current on healthy feeder
IROH Healthy feeders

IL I OF = I L – IH1 – I H2 – IH3
I ROF = IH3 + I OF

so:
IH 3 IH 2 IH 1 I ROF = IL – IH1 – I H2
3XL -V0
XCO

V00640

Figure 86: Zero sequence network showing residual currents

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In practical cases, however, resistance is present, resulting in the following phasor diagrams:

Resistive component
(IAH1 + I H2 + I H3)’ in feeder
Resistive component
A
in grounding coil I’ 3V0
L

C B

a) capacitive and inductive currents with resistive components

Restrain IL

Zero torque line for 0° RCA

Operate
I R1 = I H1
-IH 1 - IH2

IR 3
I R3 = I F + IH3 = IL - IH1- IH12

Restrain

Vres = -3V0 Vres = -3V0

Operate

Zero torque line for 0° RCA

b) Unfaulted line c) Faulted line

V00641

Figure 87: Phase C earth fault in Petersen Coil earthed system: practical case with resistance present

If the residual voltage is used as the polarising voltage, the residual current is phase shifted by an angle less than
90° on the faulted feeder, and greater than 90° on the healthy feeders. With an RCA of 0°, the healthy feeder
residual current will fall in the ‘restrain’ area of the characteristic while the faulted feeder residual current falls in
the ‘operate’ area.
Often, a resistance is deliberately inserted in parallel with the Petersen Coil to ensure a measurable earth fault
current and increase the angular difference between the residual signals to reinforce the directional decision.
Directionality is usually implemented using a Wattmetric function, or a transient earth fault detection function
(TEFD), rather than a simple directional function, since they are more sensitive. For further information about TEFD,
refer to Transient Earth Fault Detection in the Current Protection Functions chapter.

6.2 EARTH FAULT DISTANCE PROTECTION FOR ISOLATED AND COMPENSATED

SYSTEMS
There are four types of fault that need to be considered when providing distance protection for isolated or
compensation earthed systems. These are faults involving three phases, phase to phase faults, faults involving just
a single-phase to earth, and cross-country faults involving separate single phase to earth faults.

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Faults involving three phases and phase to phase faults do not require special attention; tripping is in accordance
with zone impedance limits, fault direction, and zone time delay.
Faults on isolated or compensated earthed systems involving single-phase to earth, or cross-country faults do
require special attention.

6.2.1 SINGLE-PHASE TO EARTH FAULTS ON ISOLATED OR COMPENSATED SYSTEMS

On isolated or compensated earthed systems, a single-phase to earth fault does not lead to a short circuit as only
a small capacitive or compensated current flows to earth. In most cases, the earth fault will self-extinguish. In the
remaining cases, the system can continue to operate with the earth fault present, until the fault is located and
removed by isolating the faulted feeder. Indication of the earth fault can be provided by Wattmetric function, or a
Transient Earth Fault Detection function (TEFD).
For a fault on a solidly earthed network, distance protection is required to trip as quickly as possible to isolate the
fault. This is for all fault types including a single-phase to earth fault. In isolated or compensation-earthed
systems, a single-phase to earth fault needs to be correctly identified for network control, but instantaneous
tripping should not happen since the system can be (at least for a certain period of time) remain connected - as
the magnitude of the fault current will not be very high - and/or the fault will in most cases self-extinguish.
Moreover, for a solid earth fault, the voltage on the faulted phase may be 0V across the whole of the galvanically
connected network. Using a collapsed voltage in conjunction with the load current would give measured
impedance values on the faulted phase of 0Ω across the network, causing incorrect, and uncontrolled, tripping.
Since distance protection should not operate for a single-phase to earth fault, pick up of fault detection elements
under single-phase to earth fault conditions must not lead to tripping. This can be a particular problem on large
isolated networks, where capacitance to earth is large. When a single-phase to earth fault occurs, the voltages on
the unfaulted phases increase relative to earth, and so too do the associated capacitive earth currents. During the
initial half cycle after fault inception, the arc-ignition earth current amplitude of the disturbance may be much
higher than nominal current, with a frequency close to the nominal system frequency. To prevent incorrect
detection during single-phase to earth faults, it is common practice to delay single-phase to earth fault detection
on isolated or compensation-earthed systems by a short delay. This delay is bypassed if the fault evolves into a
double earth fault.

6.2.2 CROSS-COUNTRY FAULTS ON ISOLATED OR COMPENSATED SYSTEMS

While a single-phase to earth fault is present on an isolated or compensation earthed system, the phase to earth
voltage on the healthy phases rises by a factor of √3. Due to this rise, double earth faults (or cross-country faults)
may result. The double earth fault is similar to a two-phase fault; however, for the double earth faults, the fault
path is from one earth-fault location to another, via earth. The second fault may be anywhere on the system,
depending on where the weakest point in the insulation is located.
The likelihood of a double earth fault increases as the size of the network increases. The protection strategy
usually applied for cross-country faults is to isolate one of the fault locations, with the expectation that the second
fault location will then self-extinguish similar to a single-phase to earth fault. The faulted line can then be tripped
manually once the fault location has been identified. Distance protection applied to isolated systems must have a
so-called double earth fault phase preference, which selects a predefined phase earth loop for measurement
across the entire galvanically connected network.
In the case of cross-country faults, measurements from the phase to phase loops between the two fault locations
do not produce useful results as the phase currents belong to different short circuit loops. For the second fault,
earth loops will measure the fault impedance more accurately. For a cross-country fault, all devices across the
network should follow either a so-called "cyclic" logic or an "acyclic" logic to select a phase preference for the
impedance measurement. This is used to determine which part of the system should be isolated by three-phase
tripping. Tripping will allow the rest of the network to continue to operate (single earth-fault present, but supply
maintained). Then, when the single phase-earth fault has been located, the faulted section can be tripped
manually.
The most commonly used phase preference logic is C(A) acyclic (that is C before A before B), but other preferences
can be used.

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6.3 IMPLEMENTATION OF DISTANCE PROTECTION FOR ISOLATED AND COMPENSATED

NETWORKS
When applying distance protection to compensated or isolated systems, the following key points must be taken
into account:
● Distance protection must not trip for a single-phase to earth fault
● In the case of cross-country faults, the protection methods are different from that of solidly earthed
systems. In this case either a cyclic or an acyclic logic should be used to select a phase preference for the
impedance measurement

6.3.1 NETWORK EARTHING SYSTEM SETTING

The setting Dist.Earth Mode in the DISTANCE SETUP column defines the behaviour of the distance protection
function according to the type of earthing system. The setting options are:
● Is/Comp Earthing for isolated or compensated systems
● Standard for directly earthed systems

If Is/Comp Earthing is selected:

● Distance protection is blocked for a single-phase to earth fault
● A earth fault is detected using the neutral current (IN) and/or the neutral voltage (VN)
● It has no influence on two-phase or three-phase fault performance
● In the case of cross-country faults, either a cyclic or an acyclic logic is invoked to select a phase preference
for the impedance measurement
● The DDB signal Is/Comp Enabled (1983) is asserted

6.3.2 FIRST EARTH FAULTDETECTION

In isolated or compensated mode, no trip should occur for a earth fault. Moreover its detection by means of an
impedance criteria would lead to false information as voltages around the galvanic network will be 0V for the
faulty phase. Instead, an earth fault is detected by comparing IN and/or VN with a settable threshold.
You can choose to use VN only, IN only, VN OR IN, or VN AND IN as your selection criteria. The mode is set by the
setting 1P Mode in the DISTANCE SETUP column. The single-phase to earth fault signal (IS/Comp EF) is then
produced after a time delay set by 1P Time delay.
IN> can be set from 0.05In to 1In in steps of 10 mA. VN can be set from 1V to 80V in steps of 1 V.
A pick-up timer, is available for the detection of the first earth fault. This can be set from 0 to 10 seconds in steps of
10 ms.
The mode selector decides whether the single-phase to earth fault is determined by VN> only, IN> only, VN> or IN>,
or VN> and IN>. The mode is set by the setting 1P Mode in the DISTANCE SETUP column. The single-phase to earth
fault signal (IS/Comp EF) is then produced after a time delay set by 1P Time delay.

6.3.2.1 NEUTRAL VOLTAGE CRITERIA

The influence of earth current in a fault can be determined by considering the changes in phase to phase and
neutral displacement voltages. During earth faults, a significant displacement of the neutral voltage is expected,
whilst no imbalance of the voltage triangle is to be expected. The following figure shows a Phase A to earth fault.

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VA VA=Ground

Ground

VC VB VC VB
All phases healthy Phase A ground fault
V02784

Figure 88: Voltage distribution in an isolated system for a Phase-A-to-Earth fault

Therefore, we can establish an earth fault by seeing if the neutral voltage VN exceeds a settable threshold VN>
Voltage Set, and checking whether the phase-phase voltages are still balanced.
0.8(max. Vph-ph) < (min. Vph-ph)
Neutral displacement is established by comparing the neutral voltage VN with a threshold set by the setting, VN>
Voltage Set

6.3.2.2 NEUTRAL CURRENT CRITERIA

The bias neutral level detector (LDBN), detailed in the Biased Neutral Current Detector section, is used to improve
stability and is complemented with an additional minimum threshold controlled by setting IN> Current set . A
negative sequence current check is also performed for long and heavily loaded lines.

I N  I A  I B  IC
Neutral current

K  10%

Bias current I BIAS  max  I A  I B , I B  I C , I C  I A 

V02777

Figure 89: Biased Neutral Current Detector

6.3.2.3 RELEVANT SETTINGS FOR FIRST EARTH FAULT DETECTION

The following settings are visible if the setting Dist.Earth Mode is set to Is/Comp Earthing.
IN> Current Set: Sets the threshold for the first fault earth fault overcurrent (default – 0.1In)
VN> Voltage Set: Sets the threshold for the first fault earth fault overvoltage (default – 12V)
1P Mode: Sets the first fault detection method (default – VN>)
1P Time Delay: Sets the first fault pickup delay (default – 50 ms)

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6.3.2.4 FIRST EARTH FAULT DETECTION

VN
VN> Start
VN> Voltage Set
1P Time Delay

1P Mode
VAB
Voltage equilibrium
VBC & Mode
342
analysis IS/Comp EF
VCA Selector

IN> Current Set

IN> Bias I2 check
IN Biased Neutral
IAB Level Detector
IBC ( LDBN ) 1335
ICA IN> Bias
I2
V02778

Figure 90: First earth fault detection

Detection of the first fault primes the detection of a second earth fault and blocks tripping of phase to phase
elements for zones 1,2,3,4 (zones P and Q do not get blocked). It also creates a DDB signal indicating a single-
phase earth fault (IS/Comp EF). Typically, with zones P and Q, the external starting zones will be used to detect if a
second earth loop converges into the impedance characteristic.
The VN> Start signal is established by comparing the neutral voltage VN with a threshold set by the setting VN>
Voltage Set. This signal is gated with another signal indicating whether the phase voltage triangle is balanced or
not and then fed into the mode selector. If the voltage triangle is balanced and there is an overvoltage condition,
then a single-phase fault is indicated.
The mode selector decides whether the single phase-to-earth fault is determined by VN> only, IN> only, VN> or
IN>, or VN> and IN>. The mode is set by the setting 1P Mode in the DISTANCE SETUP column. The single phase-to-
earth fault signal (IS/Comp EF) is then produced after a time delay set by 1P Time Delay.

6.3.3 FAULT DETECTION LOGIC

It is unlikely that a second fault would occur on the same phase, because the phase to neutral voltage on this
phase has collapsed to zero as a result of the first fault. However, a second fault is highly likely in one of the other
phases as the voltage has increased by a factor of Ö3 and the extra voltage will put more stress on the insulation,
increasing the likelihood of a fault further down the line.
A second earth fault (on a different phase) will cause an imbalance in the voltage triangle. This is used as part of
the second fault detection process. The criteria for the detection of a second fault is as follows:
A second earth fault is confirmed if a first earth fault has been detected AND the phase to phase voltage triangle is
unbalanced AND the neutral voltage has exceeded the set threshold AND the neutral current has exceeded the
level set by the threshold together with the bias neutral level detector (LDBN).

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VAB

VBC

1
VCA & V< Start

0.9*Vnom
890
All poles dead

First Fault
342
IS/Comp EF SD
Q Block Zones 1 - 4
R
Healthy Condition
VN> Start
&
V< Start
1
& Second Fault
Evolving 3-phase fault
1326
ZP AB Comp.
1327
ZP BC Comp. &
1328
ZP CA Comp.

1974
ZQ AB Comp.
1975
ZQ BC Comp. &
1976
ZQ CA Comp.

Evolving 2P Fault (No Neutral Current)

V< Start
50
VN> Start &
IN>Bias – I2 check

Second Fault
VN> Start

V< Start &

1335
IN> Bias
V02779

Figure 91: Second earth fault detection logic

A second fault is detected if additionally there is a neutral overvoltage, imbalance in the voltage triangle (phase
undervoltage) and there is enough neutral overcurrent (a minimum of 50 mA for correct device operation).

6.3.4 PHASE PREFERENTIAL LOGIC

With double earth faults (cross-country faults), the aim is to isolate one of the fault locations and expect that the
fault at the other location will self-extinguish, or will be tripped manually after successful detection. To achieve this
for isolated or compensated systems, the distance protection must have a preference as to which phase-to-earth
loop to measure.
There are two types of priority criteria; acyclic and cyclic.
Acyclic criteria are such that one of the phases is always the lowest priority. For example, A(B) Acyclic logic means:
phase A is higher priority than phase B, phase B is higher priority than phase C, and phase C is the lowest priority
and will never be selected, therefore C has the lowest priority. Acyclic criteria are most commonly used for
distribution systems.

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Cyclic criteria are such that the priorities of the phases are always compared cyclically. For example, C(A) Cyclic
logic means: phase C is higher priority than phase A, phase A is higher priority than phase B, but in this case phase
B priority is higher than phase C.
The definitions of all acyclic and cyclic combinations are listed in the following table:
Criterion Priority Convergent loops Selected phase
AN, BN AN
BN, CN BN
A(B) acyclic A before B, B before C
CN, AN AN
AN, BN, CN AN
AN, BN BN
BN, CN BN
B(A) acyclic B before A, A before C
CN, AN AN
AN, BN, CN BN
AN, BN AN
BN, CN CN
A(C) acyclic A before C, C before B
CN, AN AN
AN, BN, CN AN
AN, BN AN
BN, CN CN
C(A) acyclic C before A, A before B
CN, AN CN
AN, BN, CN CN
AN, BN BN
BN, CN BN
B(C) acyclic B before C, C before A
CN, AN CN
AN, BN, CN BN
AN, BN BN
BN, CN CN
C(B) acyclic C before B, B before A
CN, AN CN
AN, BN, CN CN
AN, BN BN
BN, CN CN
A(C) cyclic A before C, C before B, B before A
CN, AN AN
AN, BN, CN AN
AN, BN AN
BN, CN BN
C(A) cyclic C before A, A before B, B before C
CN, AN CN
AN, BN, CN CN
You can set the phase preference with the Phase prio. 2pG setting in the SCHEME LOGIC column.

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6.3.4.1 PRIORITY SETTING ENABLE LOGIC

1983
Is/Comp Enabled 1

Second Fault

1 PrioTripEna AN
1323
ZP AN Comparator &
1
1971
ZQ AN Comparator
1 PrioTripEna BN
ZP BN Comparator 1324 Phase &
1 Priority
1972
ZQ BN Comparator Selector
1 PrioTripEna CN
1325
ZP CN Comparator &
1
1973
ZQ CN Comparator
Phase prio. 2pG

V02780

Figure 92: Priority setting enable logic

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6.3.4.2 ZONE STARTING LOGIC

Zone 1 Tripping
Ground only
1
Phase And Ground &
384
Block Zone 1 Gnd

Dist. Earth Mode Logic = 1

&
Standard 1 & Zone 1 AN
Is/Comp Earthing
&
PrioTripEna AN
1983
Is/Comp Enabled
960 &
Zone1 AN Element 1

1305 &
Z1 AN Comparator
& 1 & Zone 1 BN
PrioTripEna BN

961 &
Zone1 BN Element 1

1306 &
Z1 BN Comparator
& 1 & Zone 1 CN
PrioTripEna CN
744
1 Zone 1 N Start
962 &
Zone1 CN Element 1 Zone 1 Start Gnd

Zone (n) Start Gnd

1307 & n = 2, 3, 4, P, or Q 1
1691
Any Dist Start
Z1 CN Comparator
Zone (n) Start Phs
Zone 1 Tripping
Phase only 1 Zone 1 Start Phs
1
Phase And Ground

385
Block Zone 1 Phs
1 &
Block Zones 1 - 4
963 & Zone 1 AB
Zone1 AB Element

964 & Zone 1 BC

Zone1 BC Element

965 & Zone 1 CA

Zone1 CA Element

Zone 1 AN 741
1 Zone 1 A Start

Zone 1 BN 742
1 Zone 1 B Start

Zone 1 CN 743
1 Zone 1 C Start
V02781

Figure 93: Zone starting logic

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6.3.4.3 ZONE TIMER LOGIC

Standard Mode
tZ1 Gnd. Delay
Basic Scheme Mode
Standard 0 1984
& Z1 G time elapse
t
Zone 1 Start Gnd
tZ1 Ph. Delay

0 1985
& Z1 P time elapse
Zone 1 Start Phs t

Alternative Mode

tZ1 Gnd. Delay

Basic Scheme Mode
Alternative 0 1984
& Z1 G time elapse
1691 t
Any Dist Start
tZ1 Ph. Delay

0 1985
Z1 P time elapse
t
V02782

Figure 94: Zone timer logic

Note:
Although the diagram above shows zone 1 logic only, the logic for all other zones follows the same principals.

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6.3.4.4 ZONE TRIP LOGIC

1984
Z1 G time elapse

Zone 1 AN
612
& Zone 1 N Trip
Zone 1 BN 1
608
Zone 1 CN 1 Zone 1 Trip
1985
Z1 P time elapse

Zone 1 AB
&
Zone 1 BC 1
Zone 1 CA
1984
Z1 G time elapse
& 609
Zone 1 AN 1 Zone 1 A Trip

1985
Z1 P time elapse

Zone 1 AB &
1
Zone 1 CA
1984
Z1 G time elapse
& 610
Zone 1 BN 1 Zone 1 B Trip

1985
Z1 P time elapse

Zone 1 AB &
1
Zone 1 BC

Z1 G time elapse
& 611
Zone 1 CN 1 Zone 1 C Trip

1985
Z1 P time elapse

Zone 1 BC &
1
Zone 1 CA
V02783

Figure 95: Zone trip logic

Note:
Although the diagram above shows zone 1 logic only, the logic for all other zones follows the same principals.

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7 APPLICATION NOTES

7.1 SETTING MODE CHOICE

This product has two setting modes for distance protection: Simple, or Advanced. In the majority of cases, we
recommend the Simple setting. Using the Simple mode, you need only enter the line parameters such as
length, impedances and residual compensation. You set the reach in terms of percentage of the protected line.
We recommend the Advanced setting mode for networks where the protected and adjacent lines are of
dissimilar construction, requiring independent zone characteristic angles and residual compensation. In
Advanced setting mode all individual distance ohmic reach and residual compensation settings and operating
current thresholds are accessible for every zone.

7.2 OPERATING CHARACTERISTIC SELECTION

In general, we recommend the following characteristics:
● For short line applications: Select Mho for phase fault zones and quadrilateral for earth fault zones.
● For open delta (vee-connected) voltage transformer applications: Set Mho for phase fault distance
protection. For Earth Fault protection, disable the Earth Fault Distance elements and use Directional Earth
Fault instead.
● For series compensated lines: Select Mho characteristics for both phase- and earth-faults.

7.2.1 PHASE CHARACTERISTIC

The phase characteristic selection is common to all zones, allowing Mho or quadrilateral selection. Generally, the
characteristic chosen matches utility practice. Generally we would recommend a Mho characteristic for line
protection and a quadrilateral characteristic for cable applications.
The following figure shows the basic settings needed to configure a forward-looking quadrilateral zone (blinder not
shown).

Zone Reach
Z

Tilt Angle

Time
Delay
t
Line
Angle
Resistive
Reach
R

E02746

Figure 96: Settings required to apply a quadrilateral zone

The following figure shows the basic settings needed to configure a forward-looking mho zone, assuming that the
load blinder is enabled.

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Variable mho
Zone Reach Z
expansion by
polarizing ratio

Time
Delay
t

Load
Line Blinder
Angle
Angle β

Blinder Radius

E02747

Figure 97: Settings required to apply a mho zone

7.2.2 EARTH FAULT CHARACTERISTIC

The earth fault characteristic selection is common to all zones, allowing Mho or quadrilateral selection. Generally,
the characteristic chosen matches utility practice. Generally we would recommend a Mho characteristic for line
protection and a quadrilateral characteristic for cable applications.
Quadrilateral earth-fault characteristics are also recommended for all lines shorter than 10miles (16km). This
ensures that the resistive fault arc coverage does not depend on Mho circle dynamic expansion and is a known set
value.

7.3 ZONE REACH SETTING GUIDELINES

The Zone 1 elements of a Distance protection should be set to cover as much of the protected line as possible,
allowing instantaneous tripping for as many faults as possible. In most applications the Zone 1 reach (Z1) should
not be able to respond to faults beyond the protected line. For an underreaching application the Zone 1 reach
must therefore be set to account for any possible overreaching errors. These errors come from measuring errors,
the current and voltage transformers, and inaccurate line impedance data. We therefore recommend that the
reach of the Zone 1 distance elements is restricted to 80% of the protected line impedance (positive phase
sequence line impedance), with Zone 2 elements set to cover the final 20% of the line.
The Zone 2 elements should be set to cover the 20% of the line not covered by Zone 1. Allowing for underreaching
errors, the Zone 2 reach (Z2) should be set in excess of 120% of the protected line impedance for all fault
conditions. Where aided tripping schemes are used, fast operation of the Zone 2 elements is required. It is
therefore beneficial to set Zone 2 to reach as far as possible, such that faults on the protected line are well within
reach. A constraining requirement is that, where possible, Zone 2 does not reach beyond the Zone 1 reach of
adjacent line protection. For this reason the Zone 2 reach should be set to cover up to 50% of the shortest
adjacent line impedance, if possible.
The Zone 3 elements would usually be used to provide overall back-up protection for adjacent circuits. The Zone 3
reach (Z3) is therefore set to approximately 120% of the combined impedance of the protected line plus the
longest adjacent line. A higher apparent impedance of the adjacent line may need to be allowed where fault
current can be fed from multiple sources or flow through parallel paths.
Zone 3 may also be programmed with a slight reverse (“rev”) offset, in which case its reach in the reverse direction
is set as a percentage of the protected line impedance too. This would typically provide back-up protection for the
local busbar, where the offset reach is set to 20% for short lines (<30km) or 10% for longer lines.

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Zone 3 may also be set as a reverse directional zone. The setting chosen for Zone 3, if used, depends on its
application. Typical applications include its use as an additional time delayed zone or as a reverse back-up
protection zone for busbars and transformers.
Programmable zone elements can be set with the same options as Zone 3 (Forward, Reverse or Offset). A
programmable zone can be used as an additional forward protection zone if custom and practice requires using
more than three forward zones of Distance protection.
The Zone 4 elements may also provide back-up protection for the local busbar. Where Zone 4 is used to provide
reverse directional decisions for Blocking or Permissive Overreach schemes, Zone 4 must reach further behind the
protection than Zone 2 for the remote end protection. In such cases the reverse reach should be:
● Mho: Z4 > Remote Zone 2 reach x 120%
● Quadrilateral: Z4 > (Remote Zone 2 reach x 120%) minus the protected line impedance

Note:
In the case of the Mho, the line impedance is not subtracted. This ensures that whatever the amount of dynamic expansion of
the circle, the reverse looking zone always detects all solid and resistive faults capable of detection by Zone 2 at the remote
line end.

7.3.1 QUADRILATERAL RESISTIVE REACHES

Two setting modes are possible for resistive reach coverage, which can be set by the Quad Resistance Setting:
Common: In this mode, all zones share one common fault resistive reach setting
Proportional: With this mode, the ratio of zone reach to resistive reach is the same for all zones. The Fault
Resistance setting defines a reference fault at the remote end of the line. The resistive reach is set at the same
percentage of the fault resistance as the Zone Reach setting. For example, if the Zone 1 reach is 80% of the
protected line, its resistive reach is 80% of the reference fault resistance.
The Proportional setting is used to avoid zones being excessively broad (width of the resistive reach compared
to the length of the impedance reach). In general, for easiest injection testing, the aspect ratio of any zone is best
within the 1 to 15 range:
1/15th <= Z reach / R reach setting <= 15
The resistive reach settings should be selected according to utility practice. If no such guidance exists, a starting
point for Zone 1 is:
● Cables: Resistive Reach = 3 x Zone 1 reach
● Overhead lines: Resistive Reach = [2.3 - 0.0045 x Line length (km)] x Zone 1 reach
● Lines longer than 400km: 0.5 x Zone 1 reach

Note:
Because the fault current for an earth fault may be limited by tower footing resistance, high soil resistivity, and weak
infeeding; any arcing resistance is often higher than for a corresponding phase fault at the same location. It maybe necessary
to set the Rn Gnd Resistive settings to be higher than the Rn Ph Resistive setting. A setting of Rn Gnd Resistive three times that
of Rn Ph Resistive is not uncommon.

7.4 EARTH FAULT RESISTIVE REACHES AND TILTING

The protection allows two different methods of tilting the Impedance Reach line.
● Automatic adjustment of the top reactance line angle (dynamic tilting)
● Fixed setting of the top line that overrides dynamic tilting (fixed tilting)

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7.4.1 DYNAMIC TILTING

The dynamic tilting requirements are different for long lines and short lines:

Long lines
In the case of medium and long line applications where quadrilateral distance earth-fault characteristics are used,
Zn Dynamic Tilt should be enabled and the starting tilt angle should be -3° (as per the default settings). This tilt
compensates for possible current and voltage transformer and line data errors.
For high resistive faults during power exporting, the underreaching Zone 1 is only allowed to tilt down by the angle
difference between the faulted phase and negative sequence current Ð(Iph-I2) starting from the –3° set angle. This
ensures stability of Zone 1 for high resistance faults beyond the Zone 1 reach even during heavy load conditions
(high load angle between two voltage sources) and sufficient sensitivity for high resistance internal faults. The tilt
angle for all other zones (that are by nature overreaching zones) remain at -3°.
In the case of power importing, Zone 1 remains at –3° while all other zones are allowed to tilt up by the Ð(Iph-I2)
angle difference, starting from –3°. This increases the Zone 2 and Zone 4 resistive reaches and secures correct
operation in permissive overreach and blocking type schemes.

Short lines
For very short lines, typically below 10Miles (16km), the ratio of resistive to reactance reach setting (R/X) could
easily exceed 10. For such applications the geometrical shape of the quadrilateral characteristic could be such
that the top reactance line is close or even crosses the resistive axis as presented in the following figure:

jX
High resistive internal fault
Total dynamic tilt starting from zero

Total dynamic tilt starting from -3°

Z1

-3 ° Iph -I 2
Line angle R

Iph -I 2

V02748

Figure 98: Over-tilting effect

In the case of high resistance external faults on a short line, particularly under heavy power exporting conditions,
Zone 1 remains stable due to dynamic downwards tilting of the impedance reach line. However, the detection of
high resistance internal faults especially towards the end of the line needs consideration. In such applications you
can choose to detect high resistance faults using highly sensitive Aided Directional Earth Fault scheme, or to clear
the fault with Distance ground protection. For the Distance to operate, it is necessary to eliminate over-tilting for
internal faults by reducing the initial -3° tilting angle to zero so that the overall impedance reach line tilt is equal to
Ð(Iph-I2) angle only.
As shown in the previous figure, the internal resistive fault then falls in the Zone 1 operating characteristic.
However, for short lines the load angle is relatively low when compared to long transmission lines for the same
transfer capacity and therefore the impedance reach line dynamic tilting may be moderate. Therefore it may be
necessary to reduce the Zone 1 reach to guarantee Zone 1 stability. This is particularly recommended if the
distance protection is operating in an aided scheme. To summarise, for very short lines with large R/X setting
ratios, we recommend settiing the initial tilt angle to zero and the Zone 1 reach to 70-75% of the line impedance.
The above discussion assumes homogenous networks where the angle of the negative sequence current derived
at relaying point is very close to the total fault current angle. If the network is non-homogenous, there is a

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difference in angle that causes inaccurate dynamic tilting. Therefore in such networks either quadrilateral with
fixed tilt angle or mho characteristic should be considered to avoid Zone 1 overreach.

Note:
You can also use Delta Directional schemes to detect high resistance faults.

7.4.2 FIXED TILTING

As an alternative to dynamic tilting, you can set a fixed tilt angle. This is used for applications where the power flow
direction is unidirectional.

Exporting End
To secure stability, the tilt angle of Zone 1 at the exporting end has to be set negative and above the maximum
angle difference between sources feeding the resistive faults. This data should be known from load flow study, but
if unavailable, the minimum recommended setting would be the angle difference between voltage and current
measured at local end during the heaviest load condition coupled with reduced Zone 1 reach of 70-75% of the line
impedance.

Note:
With a sharp fixed tilt angle, the effective resistive coverage would be significantly reduced. Therefore for short lines, dynamic
tilting (with variable tilt angle depending on fault resistance and location) is preferred. For all other overreaching zones, set the
tilting angle to zero.

Importing End
Set zone 1 tilt angle to zero and for all other zones the typical setting should be positive and between +5° and +10°.

Note:
The setting accuracy for overreaching zones is not crucial because it does not pose a risk for distance maloperation. The
purpose is to boost Zone 2 and Zone 4 reach and improve the performance of Aided Schemes.

7.5 PHASE FAULT ZONE SETTINGS

If you use the Advanced Setting Mode, in addition to the reach and compensation settings, you have additional
settings to enter.
Each zone has a minimum current sensitivity setting (Zn Sensit. Iph>) which sets the minimum current that must
be flowing in each of the faulted phases before a trip can occur. It is recommended to leave these settings at their
default. An exception is where the protection is made less sensitive to match with other protection existing on the
power system, or to grade with the pickup setting of any ground overcurrent protection for tee-off circuits.
When quadrilateral characteristics are used, the tilt angles of the impedance reach lines can be set.
By factory default, the impedance reach lines of the quadrilateral characteristics are not fixed as horizontal
reactance lines. To account for phase angle tolerances in the line transformers, etc., the lines are tilted downwards
at a droop of -3°. This tilt down helps to prevent Zone 1 overreach.
The fixed tilt setting on the phase elements may also be used to compensate for overreach effects when pre-fault
heavy load export is flowing. In such cases, fault arc resistance is phase shifted on the impedance polar plot, tilting
down towards the resistive axis and not appearing to be fully resistive in nature. For long lines with heavy power
flow, the zone 1 top line might be tilted downwards in the range –5° to –15°, mimicking the phase shift of the
resistance.

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Note:
A negative angle is used to set a downwards tilt gradient, and a positive angle to tilt upwards.

Note:
Mho characteristics have an inherent tendency to avoid unwanted overreaching, making them very desirable for long line
protection.

7.6 DIRECTIONAL ELEMENT FOR DISTANCE PROTECTION

Distance zones are directionalized by the Delta decision. For Delta directional decisions, the relay characteristic
angle (RCA) settings must be based on the average source + line impedance angle for a fault anywhere internal or
external to the line. Typically, the Dir Char Angle is set to 60°, as it is not essential for this setting to be precise.
When a fault occurs, the delta current is never close to the characteristic boundary, so an approximate setting is
good enough.
The 60° angle is associated with mainly inductive sources and suits most applications. However, in series
compensated line applications where the capacitor is physically located behind the line voltage transformer, the
Delta directional characteristic angle needs adjusting. In such applications the capacitor is included in the
equivalent source impedance. Then the overall source impedance seen by the protection becomes predominantly
capacitive if the inductance of the normally strong source is less than the capacitor value. In this case, the
calculated operating angle during an internal fault may not fall within the default 60° Delta directional line
operating boundary. This could lead to an incorrect (reverse) directional decision. A zero degree shift is most
suitable for such a fault. However, the constraining factor is the case of external faults for which the source is
always inductive regardless of the degree of compensation and for which the 60° shift is most appropriate. To
ensure correct, reliable and fast operation for both fault locations in the case of predominantly capacitive source,
we recommend a Dir Char Angle setting of 30°.

7.7 FILTERING SETUP

A number of filters and features are provided to help avoid false tripping during conditions that can be challenging
to distance protection.

7.7.1 DISTANCE DIGITAL FILTER

In most applications, we recommend setting the Digital Filter setting to Standard. This ensures that the
protection provides fast, sub-cycle tripping. In certain rare cases, such as where lines are immediately adjacent to
High Voltage DC (HVDC) transmission, the current and voltage inputs may be severely distorted under fault
conditions. The resulting non-fundamental harmonics could affect the reach point accuracy of the protection. To
prevent the protection being affected, you should select the Special Applics setting to enable the special
applications filter.

Note:
When using the Special Applications filter the instantaneous operating time is increased by about a quarter of a power
frequency cycle.

7.7.2 SETTING UP CVTS

CVTs with Passive Suppression of Ferroresonance

Set CVT Filters to Passive for any type 2 CVT (those with an anti-resonance design). You need to apply an SIR
cut-off setting, above which the protection operation is deliberately slowed by a quarter of a cycle. A typical SIR
setting is 30, below which the protection trips sub-cycle, and if the infeed is weak the CVT filter adapts to slow the
protection and prevent transient overreach.

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CVTs with Active Suppression of Ferroresonance

Set CVT Filters to Active for any type 1 CVT.

7.8 LOAD BLINDING SETUP

We strongly recommend enabling the load blinder, especially for lines above 150km (90miles) and for any networks
where power swings might be experienced. This will prevent non-harmonic low-frequency transients causing load
encroachment problems.
The impedance radius must be set lower than the worst-case loading, and this is often taken as 120% overloading
in one line, multiplied by two to account for increased loading during outages or fault clearance in an adjacent
parallel circuit. Then an additional allowance for measuring tolerances results in a recommended setting typically
between a quarter and one third of the rated full load current:
Z <= (Rated phase voltage Vn)/(IFLC x 3)
When the load is at the worst-case power factor, it should remain below the beta (b setting. So, if we assume a
typical worst case 0.85 power factor, then:

b >= Cos-1 (0.85) + 15° margin >= 47°

and to ensure that line faults are detected:
b <= (Line Angle -15°).
In practice, an angle half way between the worst-case leading load angle, and the protected line impedance
angle, is often used.
This product has a facility to allow the load blinder to be bypassed any time that the measured voltage for the
phase in question falls below an undervoltage (Load Blinder V<) setting. Under such circumstances, the low
voltage would not be explained by normal voltage excursion tolerances on-load. A fault must be present on the
phase in question, and it is acceptable to override the blinder action and allow the distance zones to trip according
to the entire zone shape. The benefit is that the resistive coverage for faults near to the protection location can be
higher.
The undervoltage setting must be lower than the lowest phase-neutral voltage under heavy load flow and
depressed system voltage conditions. The recommended Load Blinder V< setting is 70% Vn.

7.9 POLARIZING SETUP

You can choose how much memory polarization to mix with self-polarization using the Dist. Polarizing setting.
Some recommendations are:

Cable applications
Use 20% (0.2) memory. This results in minimum Mho expansion and keeps the protected line section well within the
expanded Mho, thereby ensuring better accuracies and faster operating times for close-up faults. This matches
the guidance previously provided for LFZP123 or LFZR applications for cable feeders

Series compensated lines

Use a mho with the maximum memory polarization (setting = 5). The large memory content ensures correct
operation even with the negative reactance effects of the compensation capacitors seen either within the zones,
or within the line impedance.

Short lines
For lines shorter than 10miles (16km), or with an SIR higher than 15, use the maximum memory polarization
(setting = 5). This ensures sufficient characteristic expansion to cover fault arc resistance.

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General line applications

Use any setting between 0.2 and 1.

7.10 DELTA DIRECTIONAL ELEMENT SETTING GUIDELINES

For the Delta directional element, the relay characteristic angle (RCA) settings must be based on the average
source + line impedance angle for a fault anywhere internal or external to the line. Typically, the Dir Char Angle is
set to 60°, as it is not essential for this setting to be precise. When a fault occurs, the delta current will never be
close to the characteristic boundary, so an approximate setting can be applied.

7.10.1 DELTA THRESHOLDS

For best performance, set the Dir. I Fwd current threshold at 10 to 20% In. This ensures detection of all fault types
if the fault current contribution to an earth fault at the remote end of the line generates at least this amount of
delta. To select the correct Delta V Forward setting, refer to the following table which compares SIR (Source to Line
impedance ratio) with recommended Delta V Forward setting (DV Fwd).
Lowest SIR ratio of the system Recommended DV Fwd (as a % of Vn)
>= 0.3 4%
>= 0.5 6%
>= 1 9%
>= 2 13%
>= 3 15%
>= 5 17%
>= 10 19%
25 – 60 21%

The reverse fault detectors must be set more sensitively, as they are used to invoke the blocking and current
reversal guard elements. We suggest that all reverse detectors are set at 66 to 80% of the setting of the forward
detector, typically:
● Dir. V Rev = Dir. V Fwd x 0.66
● Dir. I Rev = Dir. I Fwd x 0.66
Due to the implementation method, Deltas are present only for 2 cycles on fault inception. If any distance elements
are enabled, these will automatically allow the delta forward or reverse decisions to seal-in, until such time as the
fault is cleared from the system. Therefore as a minimum, some distance zone(s) must be enabled in the DISTANCE
SETUP column as fault detectors. It does not matter what time delay is applied for the zone(s). This can either be
the typical distance delay for that zone or set to ‘Disabled’ in the SCHEME LOGIC column, if no distance tripping is
required. As a minimum, Zone 3 must be enabled, with a reverse reach such as to allow seal-in of Dir. Rev, and a
forward reach to allow seal-in of Dir. Fwd.
The applicable reaches would be:
● Zone 3 Forward: Set at least as long as a conventional Zone 2 (120-150% of the protected line)
● Zone 3 Reverse: Set at least as long as a conventional Zone 4, or supplement by assigning Zone 4 if a large
reverse reach is not preferred for Zone 3.
We generally advise a Mho characteristic in such starter applications, although quadrilaterals are acceptable. As
the Mho starter is likely to have a large radius, we strongly advise applying the Load Blinder.

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7.11 DISTANCE PROTECTION WORKED EXAMPLE

This section presents a worked example of how to set the Distance protection. For this case study, we assume that
Zone 1 Extension is not used, and that only three zones are required for basic Distance protection (Zones 1 and 2
Forward Directional, and Zone 3 Forward Offset). The following settings are derived:
● Line Impedance
● Residual Compensation
● Zone 1 reach settings for phase-faults and earth-faults
● Zone 2 reach settings for phase-faults and earth-faults
● Zone 3 reach settings for phase-faults and earth-faults
● Zone 3 reverse reach settings
● Zone 4 reach settings (for use with Permissive Overreach or Blocking schemes if needed)
● Load avoidance

The settings are applicable whether the Distance protection characteristics are set to Mho, or Quadrilateral. If you
choose Quadrilateral however, you will need to consider the Resistive reaches of Quadrilaterals.
For this study, we wish to protect one line of a double 230kV, 100km line between a substation at Green Valley and
a substation at Blue river. There are generating sources at Tiger Bay, 80 km from Green Valley and at Rocky Bay, 60
km from Blue River.
The single-line diagram for the system is shown in the following figure:

Green Valley Blue River

Tiger Bay Rocky Bay

100 km
80 km 60 km

IED IED

E02705

Figure 99: Example power system

The system data is as follows:

● System Voltage: 230kV
● System earthing: Solid
● CT ratio: 1200 : 5
● VT ratio: 230 000 : 115
● Line length: 100km
● Positive sequence line impedance (Z1): 0.089 + j0.476 ohms/km = 0.484Ð79.4°
● Zero sequence line impedance (Z0): 0.426 + j1.576 ohms/km = 1.632Ð74.8°
● Z0/Z1: 3.372Ð4.6°
● Green Valley substation fault level: 2000 MVA to 5000 MVA
● Blue river substation fault level: 1000 MVA to 3000 MVA
● Circuit continuous rating: 400 MVA
● Worst case power factor of load: 0.85

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7.11.1 LINE IMPEDANCE CALCULATION

Ratio of secondary to primary impedance = (1200/5)/(230000/115) = 0.12
Total primary line impedance (for 100 km length) = 100 x 0.484Ð79.4° W
Total secondary impedance = (0.12 x 100 x 0.484)Ð79.4° = 5.81Ð79.4° W
Therefore set secondary values as follows:
Line Angle = 80°
Line Impedance = 5.81 W

7.11.2 RESIDUAL COMPENSATION FOR EARTH FAULT ELEMENTS

The residual compensation factor can be applied independently to certain zones if required. This is a useful feature
where line impedance characteristics change between sections or where hybrid circuits are used. In this example
this is not the case, so a common kZN factor can be applied to each zone. This is set as ratio kZN Res Comp, and
angle KZN Res Angle:
We know that
kZN = (Z0 - Z1)/3Z1
Now, performing the calculations iwht the given values ...
|Z0 - Z1| = 1.15
|3Z1| = 1.452
Ð(Z0-Z1) = 72.9°
Ð3Z1 = 79.4°
Thus ...
kZN = 0.79 Ð 6.5°

Therefore set:
kZN Res Comp = 0.79
KZN Res Angle = -6.5°

7.11.3 ZONE 1 PHASE AND GROUND REACH SETTINGS

For the protection at Green Valley:
The required Zone 1 reach is to be 80% of the line impedance between Green Valley and Blue River substations.
Using the Setting Mode Simple:
● Set Zone 1 Ph Status and Zone 1 Gnd Stat. to Enabled
● Set Zone 1 Ph Reach and Zone 1 Gnd Reach to 80%

From this the protection algorithm automatically calculates the required Ohmic reaches.
Alternatively, using the Setting Mode Advanced, the values can be calculated and entered manually as follows:
Required Zone 1 reach = 0.8 x 100 x 0.484Ð79.4° x 0.12 = 4.64Ð79.4° W secondary

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So:
● Set Z1 Ph. Reach and Z1 Gnd. Reach = 4.64 W
● Set Z1 Ph. Angle and Z1 Gnd. Angle = 80°

7.11.4 ZONE 2 PHASE AND GROUND REACH SETTINGS

For the protection at Green Valley:
In Advanced mode:
Required Zone 2 impedance = line impedance of Green Valley to Blue River + 50% line impedance
from Blue River to Rocky Bay
= (100+30) x 0.484Ð79.4° x 0.12
= 7.56 Ð79.4° W secondary
So:
● Set Z2 Ph. Reach and Z2 Gnd. Reach = 7.56 W
● Set Z2 Ph. Angle and Z2 Gnd. Angle = 80°

Alternatively, in Simple setting mode, this reach can be set as a percentage of the protected line. Typically a
figure of at least 120% of the line between Green Valley and Blue River is used.

7.11.5 ZONE 3 PHASE AND GROUND REACH SETTINGS

For the protection at Green Valley:
In Advanced mode:
Required Zone 3 impedance = 1.2(line impedance of Green Valley to Blue River) + line impedance
from Blue River to Rocky Bay
= 1.2*(100+60) x 0.484Ð79.4° x 0.12
= 11.15 Ð79.4° W secondary
So:
● Set Z3 Ph. Reach and Z2 Gnd. Reach = 11.15 W
● Set Z2 Ph. Angle and Z2 Gnd. Angle = 80°

Alternatively, in Simple setting mode, this reach can be set as a percentage of the protected line.

7.11.6 ZONE 3 REVERSE REACH SETTINGS

For the protection at Green Valley:
In the absence of special requirements, because the protected line length is more than 30km, Zone 3 can be given
a small reverse reach – say 10%.
Using Advanced mode, in the DISTANCE SETUP column, set:
● Z3' Ph Rev Reach and Z3' Gnd Rev Rch = 0.1*5.81 = 0.58 W

7.11.7 ZONE 4 REVERSE REACH SETTINGS

For the protection at Green Valley:
Where Zone 4 is used to provide reverse directional decisions for Blocking or Permissive Overreach schemes, Zone
4 must reach further behind the local protection than Zone 2 of the remote protection. This can be achieved by
setting Zone 4 ³ 1.2 x Remote Zone 2 reach, where mho characteristics are used.

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Remote Zone 2 Reach = line impedance of Green Valley to Blue River + 50% line impedance from
Green valley to Tiger Bay
= (100 + 40) x 0.484Ð79.4° x 0.12
= 8.13Ð79.4° W secondary
Zone 4 Reach ³ (8.13Ð79.4° x 120%) - 5.81Ð79.4°
= 3.95Ð79.4° W secondary
This is the minimum Zone 4 Reach setting, so:
● Set Z4 Ph. Reach and Z4 Gnd. Reach = 3.96 W
● Set Z4 Ph. Angle and Z4 Gnd. Angle = 80°

7.11.8 LOAD AVOIDANCE

The maximum full load current of the line can be determined from the calculation:
IFLC = [(Rated MVAFLC) / (Ö3 x Line kV)]
The settings must allow for a level of overloading, typically a maximum current of 120% IFLC prevailing on the
system transmission lines. Also, for a double circuit line, during the auto-reclose dead time of fault clearance on
the adjacent circuit, twice this level of current may flow on the healthy line for a short period of time. Therefore the
circuit current loading could be 2.4 x IFLC.
With such a heavy load flow, the system voltage may be depressed, typically with phase voltages down to 90% of
Vn nominal.
Allowing for a tolerance in the measuring circuit inputs (line CT error, VT error, protection accuracy, and safety
margin), this results in a load impedance which might be 3 times the expected rating.
To avoid the load, the blinder impedance needs to be set:
Z £ (Rated phase-ground voltage Vn) / (IFLC x 3)
= (115/√3) / (IFLC x 3)
Set the V< Blinder voltage threshold at the recommended 70% of Vn = 66.4 x 0.7 = 45 V.

7.11.9 QUADRILATERAL RESISTIVE REACH SETTINGS

If applying Quadrilateral characteristics, as well as the Impedance Reaches, the Resistive Reaches also need to be
considered. The Resistive reaches of the phase-fault elements must be set to cover the maximum expected phase-
to-phase fault resistance. The Resistive reaches of the earth-fault elements should take into account the arc-
resistance and the tower footing resistance.

Phase-Fault Elements
Ideally, the Resistive reach should be set greater than the maximum fault arc resistance for a phase-phase fault
(Ra), calculated in terms of the minimum expected phase-phase fault current, the maximum phase conductor
separation, according to the formula developed by (van) Warrington as:
Ra = (28710 x L)/If x 1.4
where:
● If = Minimum expected phase-phase fault current (A)
● L = Maximum phase conductor separation (m)

Typical figures for Ra are given, for different values of minimum expected phase fault currents, in the following
table:

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Conductor spacing Typical system Ra for Ra for Ra for

(m) voltage (kV) If = 1 kA If = 2 kA If = 3 kA
4 110 - 132 7.2 W (primary) 2.8 W (primary) 1.6 W (primary)
8 220 - 275 14.5 W (primary) 5.5 W (primary) 3.1 W (primary)
11 380 - 400 19.9 W (primary) 7.6 W (primary) 4.3 W (primary)

Note:
For circuits with infeed from more than one terminal, the fault resistance will appear greater. This is because the protection
cannot measure the current contribution from a remote terminal. The apparent fault resistance increase could be between 2
to 8 times the calculated resistance. For this reason, we recommended setting the zone Resistive reaches to 4 times the
calculated arc resistance.

In this example, the minimum phase fault level is 1000 MVA. This is equivalent to an effective short-circuit fault
feeding impedance of:

Z = kV2/MVA = 2302/1000 = 53 W (primary)

The lowest phase fault current level is equivalent to:
Ifault = (MVA x 1000)/(Ö3 x kV)
= (1000 x 1000)/(Ö3 x 230)
= 2.5 kA
Giving, according to the (van) Warrington formula, an arc resistance of:
Ra = 4 W
Iterative calculations could be performed to refine the expected fault current (which decreases as refined values of
Ra are included in the calculation), but as Ra is relatively small compared to the initially calculated value of Z, this
value is acceptable.
To compensate for remote infeed a small additional factor can be added to account for the expected fault current
being lower than that used in the calculation. So rather than set the zone Resistive reaches to 4 times the
calculated arc resistance, a factor of 5 could be used.
Using a factor of 5 gives a minimum setting of:
Phase Resistive Reach = 5 x Ra = 20 W (primary value)
The Phase Resistive Reach could be set higher than this (for example using the rule-of-thumb: [2.3 - 0.0045 x Line
length (km)] x Zone 1 reach), so typically it would be set higher than 20Ω but lower than the Load Avoidance
setting.

Earth-Fault Elements
Fault resistance would comprise arc-resistance and tower footing resistance. A typical resistive reach coverage
setting would be 40 W (primary).
For high resistance earth faults, the situation could arise where no distance elements would operate. In such
cases, supplementary earth fault protection (for example Aided DEF protection) should be applied. If
supplementary earth fault protection is used, large resistive reaches for Earth-Fault Distance protection do not
need to be used so that the Earth-Fault Resistive reach can be set according to the utility practice. In the absence
of specific guidance, a recommendation for setting Zone 1 is:
● Cables: Resistive Reach = 3 x Zone 1 reach
● Overhead lines: Choose Resistive Reach in the range [2.3 - 0.0045] x Line length(km) x Zone 1 Reach
● Lines longer than 400 km: Choose Resistive Reach = 0.5 x Zone 1 Reach

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7.12 TEED FEEDER APPLICATIONS

Distance protection can be applied to protect three terminal lines (teed feeders). Interconnecting three terminals,
however, affects the apparent impedances seen by the distance elements and creates certain problems.
Consider, as an example, the following figure which represents a teed feeder with terminals A, B, and C, with a fault
applied near to terminal B:

A B
Ia Ib

Zat
Zbt

Ic
Zct

Va
Va = Ia Zat + Ib Zbt C Impedance seen by relay A =
Ia
Ia = Ia + Ic

E03524

Figure 100: Apparent Impedances seen by Distance Protection on a Teed Feeder

The impedance seen by the distance elements at terminal A is given by:

Za = Zat + Zbt + [Zbt.(Ic/Ia)]
For faults beyond the Tee point, with infeed from terminals A and C, the distance elements at A (and C) will
underreach. If terminal C is a relatively strong source, the underreaching effect at A can be substantial. If Zone 2
was set to a typical value of 120% of line AB, the element may fail to operate for internal faults. To compensate,
the Zone 2 element must be set to further overreach by a factor which takes into account the effect of the infeed
from the tee-point.
So, if infeed is present on a teed circuit, all Zone 2 elements should be set to overreach both of their remote
terminals by a factor which takes into account the effect of the infeed from the tee-point.
Like overreaching of Zone 2 elements, underreaching of Zone 1 elements must also be assured. Zone 1 elements
at each terminal must be set to underreach the true impedance to their nearest terminal (limiting case = no infeed
to the tee-point - hence no overreach contribution).
Changing the reach requirements to match the infeed expectations is possible using the alternative setting group
feature. Tailoring setting group contents to the different conditions, coupled with appropriate setting group
switching, enables the changing reach requirements to be met.
Carrier aided schemes can also be used in conjunction with distance elements to protect teed feeders. Although
Permissive Overreaching and Permissive Underreaching schemes may be used, they suffer some limitations.
Blocking schemes are generally considered to be the most suitable.
For a full explanation of Teed Feeders applications in carrier aided schemes, please refer to the Carrier Aided
Schemes chapter.

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CARRIER AIDED SCHEMES

Chapter 8 - Carrier Aided Schemes P543i/P545i

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1 CHAPTER OVERVIEW
This chapter contains the following sections:
Chapter Overview 209
Introduction 210
Carrier Aided Schemes Implementation 211
Aided Distance Scheme Logic 213
Aided DEF Scheme Logic 227
Aided Delta Scheme Logic 238
Application Notes 245

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2 INTRODUCTION
The provision of communication channels between the terminals of a protected transmission line or distribution
feeder enables unit protection to be applied.
Protection devices located at different terminals can be configured to communicate with one another in order to
implement unit protection schemes. The exchange of simple ON/OFF command signals allows unit protection to
be achieved with Distance Protection schemes (Aided Distance), Directional Earth Fault schemes (Aided DEF) and if
applicable, Delta Directional Comparison Protection schemes (Aided Delta). Schemes where a communication
channel is used to send command signals between line ends are known as Carrier Aided Schemes.
The terms ‘simplex’ and ‘duplex’ are used to describe the type of communication channel used. Simplex
communication, also sometimes referred to as half-duplex, requires only a single communication channel
between line ends. Signals can be sent in both directions but not at the same time. Duplex communication requires
two communication channels between line ends (one in each direction). Duplex communication allows signals to
be sent and received at the same time.

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3 CARRIER AIDED SCHEMES IMPLEMENTATION

With Aided Distance protection, tripping schemes are used to connect similar devices at different terminals on the
protected line to provide fast clearance for faults anywhere along the line.
For distance protection It is typical to set Zone 1 distance protection elements to cover only 80% of a line from the
relaying point. Faults on the other 20% of the line would generally be cleared by a delayed Zone 2 element, which
could be hundreds of milliseconds after the fault inception. There is, however, a limit to the amount of arc reistance
and tower footing resistance that can be adequately covered by distance IEDs, since the coverage is limited by
their ohmic reach. If extremely high values of ground fault resistance are expected, then an optional directional
comparison earth fault scheme (Aided DEF) can be used to complement the distance schemes.
Aided distance schemes assure fast clearance for faults on the entire circuit by communicating command signals.
For the the communication between local and remote terminals InterMiCOM 64 (IM64) can be used.

3.1 CARRIER AIDED SCHEME TYPES

This product has two independent Carrier Aided Schemes (Aided Scheme 1 and Aided Scheme 2). The two schemes
are independent, but the design of both is the same. Each of the two Carrier Aided Schemes provides the following
options:
● Permissive Underreaching Schemes (PUR, PUTT)
● Permissive Overreaching Schemes (POR, POTT)
● Blocking Scheme (Block 1)
● Blocking Scheme (Block 2)
● Unblocking POR Scheme
● Unblocking PUR Schemes
● Programmable
● Programmable Unblocking

The underreaching options can be used to implement Carrier Aided Distance schemes. The other options can be
used with any Carrier Aided scheme application.
The following diagram shows how the schemes can be assigned.

Scheme Aided 1 Aided 2

Scheme Category Underreaching Overreaching

Scheme Mode PUR PUR Unblocking POR POR Unblocking Block 1 Block 2 Prog Unblock Prog

Scheme Function Aided Distance Aided Distance Aided DEF Aided Delta*

*Not P445
V03500

Figure 101: Scheme Assignment

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3.2 DEFAULT CARRIER AIDED SCHEMES

This product provides support for two Carrier Aided schemes, which can operate in parallel. The schemes are
referred to as ‘Aided Scheme 1’ and ‘Aided Scheme 2’. The schemes have been designed to operate independently
with a separate communication channel dedicated to each one, but they can share a single communication
channel if necessary. If both schemes are used and they share a common channel then, if one of the schemes
initiates transmission of a command signal, both schemes will receive the command and act upon it.
If you don’t want to use the Aided schemes, you should set the relevant Aid. 1 Selection and Aid.2 Selection
settings (in the SCHEME LOGIC column) to Disabled. If the setting(s) are enabled, you are provided with a choice
of schemes; standard transfer tripping schemes, blocking schemes, or custom programmable schemes.
You select the type of scheme you want to use, and then you choose whether to use it in conjunction with the
Distance protection, and/or the Aided DEF protection.
The scheme options are:
● Disabled: No scheme is implemented
● PUR: Permissive Underreach Transfer Tripping (PUPP, PUR, or PUTT) scheme
● PUR Unblocking: Perrmissive Underreach Unblocking scheme
● POR: Permissive Overreach Transfer Tripping (POP, POR, or POTT) scheme
● POR Unblocking: Permissive Overreach Unblocking scheme
● Blocking1: Current reversal guard signal is sent to qualify reverse looking Zone 4 elements
● Blocking2: Received current reversal guard signal qualifies reverse looking Zone 4 elements
● Prog. Unblocking: Allows you to define which elements are used to assert signals for Overreach
Unblocking.
● Programmable: Allows you to define which elements are used to assert signals for Overreach Transfer
Tripping, by using a custom send mask

Note:
The PUR schemes are only suitable for Distance protection. Therefore, if a PUR scheme is selected, the option to allocate to
other protection is not available.

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4 AIDED DISTANCE SCHEME LOGIC

When the Carrier Aided schemes are used in conjunction with the Distance protection, you can choose whether to
use them with the phase distance elements only, the earth-fault (ground) distance elements only, or for both
phase and earth fault elements.

4.1 PERMISSIVE UNDERREACH SCHEME

The simplest Carrier Aided scheme mode for use with distance-type applications is the Permissive Under-reach
Protection scheme, variously referred to as PUR, PUP, and PUTT. We normally use the term PUR.
To use this scheme, you need to set the relevant setting (Aid. 1 Selection or Aid. 2 Selection) in the SCHEME LOGIC
column to PUR.
The channel for a PUR scheme is keyed (that means that the aiding signal is asserted) if an under-reaching Zone 1
element operates. If the remote device detects a forward fault and this signal is received, then the remote
protection operates without further delay. Faults in the last 20% of the protected line are therefore cleared with
minimal time delay.

Note:
This assumes a 20% typical end-zone when Zone 1 is set to 80% of the protected line.

The following are some of the main features and requirements for a permissive under-reaching scheme.
● Only a simplex channel is required.
● Scheme security is high, because the signalling channel is only keyed for faults in the protected line.
● If the circuit breaker at the remote terminal is open, faults in the remote 20% of the line are cleared using
the Zone 2 time delay of the local protection.
● If there is a weak-infeed, or zero-infeed from the remote terminal, (current below the protection sensitivity),
faults in the remote 20% of the line are cleared using the Zone 2 time delay of the local protection.
● If the signalling channel fails, basic distance scheme tripping remains available.
The PUR logic is:
● Send logic: Assert signal if Zone 1 element operates
● Permissive trip logic: Trip if the Zone 2 element picks up AND the Carrier Aided signal is received

The figure below shows the simplified scheme logic:

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Zone 3
Zone 2
Zone 1
A B
Z

Z
Zone 1
Zone 2
Zone 3

CRx CRx
CTx CTx

& &

Z1 Z1
TZ1 TZ1
Trip A Trip B 1
1
Zp TZp Zp
TZp

Z2 TZ2 Z2
TZ2

Z3 TZ3 Z3
TZ3

Z4 TZ4 Z4
TZ4

Optional features of scheme

E03501

Figure 102: Aided Distance PUR scheme

4.2 PERMISSIVE OVER-REACH SCHEME

Permissive Over-reach schemes are variously referred to as POR, POP, POTT. We normally use the term POR.
In a Permissive Overreach scheme the channel is keyed (that means that the aiding signal is asserted) by the
pickup of an over-reaching Zone 2 element.
To use this scheme, you need to set the relevant setting (Aid. 1 Selection or Aid. 2 Selection) in the SCHEME LOGIC
column to POR.
If a remote protection element detects a forward fault and receives a POR signal, the protection operates without
further delay. Faults in the last 20% of the protected line are therefore cleared with minimal time delay.

Note:
This assumes a 20% typical end-zone when Zone 1 is set to 80% of the protected line.

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The following are some of the main features and requirements for a POR scheme:
● The scheme requires a duplex signalling channel to prevent possible maloperation if a carrier is keyed for an
external fault. Because the signalling channel can be keyed for faults external to the protected zone, it is
vital that they are only received by, and acted upon by, the intended recipient. A simplex channel cannot
assure this.
● A POR scheme may be more advantageous than a PUR scheme for the protection of short transmission
lines. This is because the resistive coverage of the Zone 2 elements may be greater than that of the Zone 1
elements (in the case of Mho elements)
● Current reversal guard logic prevents healthy-line protection maloperation for high speed current reversals
that can be experienced on double circuit line applications, which can be caused by sequential opening of
circuit breakers.
● If the signalling channel fails, basic distance scheme tripping remains available.

The POR logic is:

● Send logic: Assert signal if Zone 2 element picks up.
● Permissive trip logic: Trip if the Zone 2 element operates AND the Channel Aided signal is received.

The POR scheme also uses the reverse looking zone 4 as a reverse fault detector. This is used in the current
reversal logic and in the weak infeed echo feature, shown dotted in the figure below:

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Zone 4

Zone 3
Zone 2

Zone 1
Z B

Zone 1
Zone 2
Zone 3
Zone 4

CB Open & & CB Open

CRx CRx
Zone 4 & & Zone 4
CTx CTx
1 1

LD0V LD0V
& &

& &

Z1 Z1
TZ1 Trip A Trip B
TZ1
1 1

ZP TZP ZP
TZP

Z2 TZ2 TZ2 Z2

Z3 TZ3 TZ3 Z3

Z4 TZ4 TZ4 Z4

Selectable features
E03502

Figure 103: Aided Distance POR scheme

The POR scheme is enhanced by POR Trip Reinforcement, and POR Weak Infeed features.

4.2.1 PERMISSIVE OVERREACH TRIP REINFORCEMENT

The send logic in the POR scheme is arranged so that for any trip command at a local end, the local protection
sends a Channel Aided signal to the remote end(s). This facilitates fault isolation at each terminal as quickly as
possible. The send signal is generated by the Any Trip command, and it is sent on any channel that is being used.

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This feature is called permissive trip reinforcement. It is designed to ensure that synchronous tripping occurs at all
protected terminals.

4.2.2 PERMISSIVE OVERREACH WEAK INFEED FEATURES

Special weak infeed logic (WI) can be used with the POR schemes. The Weak Infeed setting can be found in the
SCHEME LOGIC column. Weak Infeed can be set to Echo, Echo and Trip, or Disabled.

Weak Infeed Echo

For a POR scheme, a signal is normally sent only if the appropriate signal associated with the pick up of the
sending zone detects a fault. However, under some circumstances, the fault current infeed at one line end may be
so low that it is insufficient to operate any of the distance zones. In another scenario, if a circuit breaker at one of
the terminals is in an open state, the current infeed will be zero. These scenarios are termed Weak Infeed (WI)
conditions. Without special attention they could result in slow fault clearance at the terminal that is feeding the
fault current (called the ‘strong infeed’ terminal). This would typically result in tripping after the Zone 2 time delay
(tZ2). To avoid Zone 2 delayed tripping, a device subject to Weak Infeed conditions can be set to echo signals
received on the Channel Aided link back to the initiating IED without delay. This allows the devices at points of
strong infeed to permissively trip instantaneously.
The Weak Infeed Echo Send logic is:
● No Distance Zone Operation has been detected, but a POR Aided signal has been received.

Weak Infeed Echo and Trip

The Weak infeed echo logic will produce an aided trip at a strong infeed terminal, but it does not produce a trip at
the weak infeed. Setting Weak Infeed to Echo and Trip allows tripping of the weak infeed circuit breaker of a
faulted line. Three undervoltage elements, Va<, Vb< and Vc< are used to detect the line fault at the weak infeed
terminal. This voltage check prevents tripping during spurious operations of the channel or during channel testing.
The Weak Infeed Echo and Trip logic is:
● No Distance Zone Operation has been detected, but a POR signal has been received, AND a V< condition
exists.
Weak infeed tripping is time delayed according to the value set in the WI Trip Delay settingin the SCHEME LOGIC
column. Due to the use of phase segregated undervoltage elements, single-phase tripping can be enabled for WI
trips if required. If single-phase tripping is disabled, under Weak Infeed conditions, three-phase tripping will occur
after the WI Trip Delay time has expired.

4.3 PERMISSIVE SCHEME LOSS OF GUARD

This scheme is intended for use with frequency shift keyed (FSK) power line carrier (PLC) communications.
When the protected line is healthy, a guard frequency is sent between line ends to verify the channel is in service.
However, when a line fault occurs and a permissive trip signal must be sent over the line, the power line carrier
frequency is shifted to a different (trip) frequency. Therefore the distance function should receive either the guard
frequency or the trip frequency, but not both together. For certain fault types, the line fault can attenuate the PLC
signals so the permissive signal is lost and not received at the other line end. To overcome this problem, when the
guard is lost and no trip frequency is received, the protection opens a window of time during which the permissive
scheme logic acts as though a trip signal had been received. Two opto-isolated inputs need to be assigned: One is
for Channel Receive; The second is designated Loss of Guard (the inverse function to guard received).
The Loss of Guard logic is described in the table below:
Permissive channel Permissive Alarm
System condition Loss of guard
received trip allowed generated
Healthy Line No No No No
Internal Line Fault Yes Yes Yes No

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Permissive channel Permissive Alarm

System condition Loss of guard
received trip allowed generated
Yes, during a 150 ms Yes, delayed on pickup by
Unblock No Yes
window 150 ms
Yes, delayed on pickup by
Signalling Anomaly Yes No No
150 ms

The window of time during which the unblocking logic is enabled starts 10ms after the guard signal is lost, and
continues for 150ms. The 10ms delay gives time for the signalling equipment to change frequency, as in normal
operation. For the duration of any alarm condition, Zone 1 extension logic is invoked if the Z1 Ext Scheme setting is
set to operate for channel failure.

4.4 CURRENT REVERSAL GUARD LOGIC

For double circuit lines, the fault current direction can change in one circuit when circuit breakers open
sequentially to clear the fault on the parallel circuit. The change in current direction causes the overreaching
distance elements to see the fault in the opposite direction to the direction in which the fault was initially detected
(settings of these elements exceed 150% of the line impedance at each terminal). The race between operation and
resetting of the overreaching distance elements at each line terminal can cause permissive overreach, and
blocking schemes to trip the healthy line. A system configuration that could result in current reversals is shown in
the figure below. For a fault on line L1 close to circuit breaker B, as circuit breaker B trips it causes the direction of
current flow in line L2 to reverse. Current reversal guard logic is incorporated in this product to prevent POR and
Blocking schemes from tripping incorrectly during current reversal conditions.

t2(C) t2(D)
Fault Fault
A L1 B A L1 B

Strong Weak
source C L2 D source C L2 D

Note how after circuit breaker B on line L1 opens

the direction of current flow in line L2 is reversed.
E03503

Figure 104: Example of fault current reversal of direction

The current reversal guard incorporated in the permissive overreach scheme logic is initiated when the reverse
looking Zone 4 elements operate on a healthy line.
Once the reverse looking Zone 4 elements have operated, the permissive trip logic and signal send logic are
inhibited at substation D. The reset of the current reversal guard timer is initiated when the reverse looking Zone 4
resets. A time delay tReversal Guard is required in case the overreaching trip element at end D operates before
the signal send from the protection at end C has reset. Otherwise this would cause the product at D to overreach.
Permissive tripping for the products at D and C substations is enabled again once the faulted line is isolated and
the current reversal guard time has expired.
The current reversal guard incorporated in the blocking scheme logic is initiated when a blocking element picks-up
to inhibit the channel-aided trip. When the current reverses and the reverse looking Zone 4 elements reset, the
blocking signal is maintained by the timer tReversal Guard. Therefore, the protections in the healthy line are
prevented from overreaching due to the sequential opening of the circuit breakers in the faulted line. After the
faulted line is isolated, the reverse-looking Zone 4 elements at substation C and the forward looking elements at
substation D reset.

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Two variants of Blocking scheme are available:

● Blocking 1 (Reversal Guard applied to the Signal Send)
● Blocking 2 (Reversal Guard applied to the Signal Receive)

4.5 AIDED DISTANCE BLOCKING SCHEMES

Two default Blocking schemes are provided:
● Blocking 1
● Blocking 2

The two schemes are similar. Both schemes feature current reversal guard signals used in conjunction with reverse
looking Zone 4 elements. In the Blocking 1 scheme, the current reversal guard signal applies to the send signal,
whereas in the Blocking 2 scheme, the current reversal guard signal applies to the receive signal.
The signalling channel is keyed from operation of the reverse-looking Zone 4 elements. If the remote zone 2
element picks up, it operates after the trip delay if no block is received. Listed below are some of the main features
and requirements for a Blocking scheme:
● Blocking schemes require only a simplex communication channel.
● Reverse-looking Zone 4 is used to send a blocking signal to the remote end to prevent unwanted tripping.
● When a simplex channel is used, a blocking scheme can easily be applied to a multi-terminal line provided
that outfeed does not occur for any internal faults.
● The blocking signal is transmitted over a healthy line, and so problems associated with power line carrier
signals failing are avoided.
● Blocking schemes provide similar resistive coverage to the permissive overreach schemes.
● Fast tripping occurs at a strong source line end, for faults along the protected line section, even if there is
weak- or zero- infeed at the other end of the protected line.
● If a line terminal is open, fast tripping still occurs for faults along the whole of the protected line length.
● If the signalling channel fails to send a blocking signal during a fault, fast tripping occurs for faults along the
whole of the protected line, but also for some faults in the next line section.
● If the signalling channel is taken out of service, the protection operates in the conventional basic mode.
● A current reversal guard timer is included in the logic to prevent unwanted tripping on healthy circuits
during current reversal situations on a parallel circuits.

The Blocking scheme logic is:

● Send logic: Assert carrier if Reverse Zone 4 element picks up
● Trip logic: Trip if the Zone 2 element picks up if no carrier is received, but only after the Aided Signal Delay
time out
The figure below shows the simplified scheme logic.

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Zone 4

Zone 3
Zone 2
Zone 1
A Z B

Z
Zone 1
Zone 2
Zone 3
Zone 4

CRx CRx
Fast Z4 Fast Z4
CTx CTx &
&

& &

Z1 Z1
TZ1 Trip B
TZ1
Trip A
1 1

ZP TZP ZP
TZP

Z2 TZ2 TZ2 Z2

Z3 TZ3 TZ3 Z3

Z4 Z4
TZ4 TZ4
Selectable features
E03504

Figure 105: Aided Distance Blocking scheme (BOP)

4.6 AIDED DISTANCE UNBLOCKING SCHEMES

The Unblocking schemes are specifically designed for use with Power Line Carrier (PLC) communications where
different frequencies are used to indicate that a guard (no-fault condition) or a trip (fault condition) signal should
be transmitted to the remote terminal(s). Normally, either a guard signal or a trip signal should be transmitted and
received. Under certain fault conditions however, the PLC signal can be heavily attenuated or even lost completely.
In such conditions, Permissive Overreach Unblocking schemes allow the permissive tripping to operate for a short
period after the carrier is lost. This ensures fast, selective fault clearance.
To use this scheme you need to assign two inputs. Generally, the inputs are mapped to opto-inputs in the default
PSL. The table below shows a default mapping for Aided Scheme 1.

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P543i/P545i Chapter 8 - Carrier Aided Schemes

DDB signal (Opto-input) DDB signal

Input L3 (DDB: 34) Aided 1 Scheme Rx (DDB: 493)
Input L4 (DDB: 35) Aided 1 COS/LGS (DDB: 492)

The Aided 1 Scheme RX signal corresponds to a 'channel-receive' signal for scheme 1. The Aided 1 COS/LGS signal
corresponds to a 'channel out of service' or 'loss of guard' signal ('Loss of guard' is the inverse signal to 'guard
received').
As well as the default mapping, it is possible to map the signals to other inputs if required.
The window during which the unblocking logic is enabled starts 10ms after the guard signal is lost and continues
for 150ms. The 10ms delay gives time for the signalling equipment to change frequency.

Note:
If the Z1 Ext Scheme setting is set to operate for channel failure, the Zone 1 extension logic will be invoked if a channel failure
is detected.

This scheme type also provides Loss of Guard logic as described below.
Permissive Permissive Alarm
System condition Loss of guard
channel received trip allowed generated
Healthy Line No No No No
Internal Line Fault Yes Yes Yes No
Unblock No Yes Yes, during a 150 ms window Yes, delayed on pickup by 150 ms
Signalling Anomaly Yes No No Yes, delayed on pickup by 150 ms

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4.7 AIDED DISTANCE LOGIC DIAGRAMS

4.7.1 AIDED DISTANCE SEND LOGIC

Aid 1 Distance
Scheme options *

Custom Send Mask

394
Masking options * Aid1 InhibitDist

960
Zone1 AN Element
961 &
Zone1 BN Element 1 1 &
1
962
Zone1 CN Element
963
Zone1 AB Element
964
&
Zone1 BC Element 1
965
Zone1 CA Element 1
&
966
Zone2 AN Element
967 &
Zone2 BN Element 1 1
968
Zone2 CN Element
969
Zone2 AB Element Signal Send
970 &
Zone2 BC Element 1 Echo Send
971
Zone2 CA Element 1
& 498
Zone4 AN Element 984 1
& Aided 1 Send
985
& tRG
Zone4 BN Element 1 1
986
Zone4 CN Element From Aided 1 DEF
987 From Aided 1 Delta
Zone4 AB Element
& (if applicable)
988
Zone4 BC Element 1
989 Blk Send
Zone4 CA Element
497
Aid1 Custom Send

496
Notes: Aid1 Block Send
This example assumes zone 2 distance phase and distance ground
elements are enabled .
Aided 1 scheme only shown .
Note: For the purpose of clarity , this diagram shows the first
relevant stage number for each signal and setting name .
V03505

Figure 106: Aided Distance Send logic

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4.7.2 CARRIER AIDED SCHEMES RECEIVE LOGIC

& 317
1 Aid 1 Chan Fail
&
t DR t DW
&
1
& 494
1 Aided 1 receive
1
& t PR

&
&
492
Aided 1 COS/LGS
&

493
Aided1 Scheme Rx
&
Aid. 1 Selection
PUR Unblocking
POR Unblocking 1
Prog. Unblocking V03508

Figure 107: Carrier Aided Schemes Receive logic

4.7.3 AIDED DISTANCE TRIPPING LOGIC

394
Aid1 InhibitDist

501
Aid1 Trip Enable
1
502
Aid1 Custom Trip tDST
1
503
1 Aid 1 Dist Trip
966
Zone2 AN Element
&
1 & 633
& 1 Aided 1 Trip A
967
Zone2 BN Element
&
1 & 634
& 1 Aided 1 Trip B
968
Zone2 CN Element
&
1 & 635
& 1 Aided 1 Trip C

Aid 1 Distance
1 1 & 636
Ground Only & 1 Aided 1 Trip N
Phase And Ground From Aided 1 Def Trip A
Phase Only 1 From Aided 1 Delta Trip A (if applicable)
From Aided 1 Def Trip B
From Aided 1 Delta Trip B (if applicable)
969
From Aided 1 Def Trip C
Zone2 AB Element From Aided 1 Delta Trip C (if applicable)
&
From Aided 1 Def Trip N
970
From Aided 1 Delta Trip N (if applicable )
Zone2 BC Element
& Notes:
Aided 1 scheme only shown.
971
Zone2 CA Element
&
V03509

Figure 108: Aided Distance Tripping logic

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4.7.4 PUR AIDED TRIPPING LOGIC

Aid. 1 Selection
PUR
501
& Aid1 Trip Enable
Aided 1 Receive 494 100 ms

V03512

Figure 109: PUR Aided Tripping logic

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4.7.5 POR AIDED TRIPPING LOGIC

Aided 1 Receive
&
Aid. 1 Selection & Aid1 Trip Enable

POR

Distance signal send

DEF signal send 1

Delta signal send tReversal Guard

Any Zone 4 element

Delta reverse element 1 & Blk Send

1 tRGD
DEF reverse element

Any Trip
&
Trip Inputs 3Ph &
1 Echo Send

Send on Trip
None
Any Trip
& &
Any Trip 1 100ms

Send on Trip
Aided / Z1
&
Aid 1 Distance
Disabled
&
Zone 1 Trip
1
Aid 1 Dist Trip
&
Aid 1 DEF Trip 1
250 ms 100 ms
Aided 1 Receive
&
Aid. 1 Selection
POR

CB Open 3 ph 10 ms

CB Open A ph

CB Open B ph 1 & WI Sngl Pole Trp

CB Open C ph Disabled
& Aid1 WI Trip 3Ph
Blk Send 60 ms

VTS Slow Block

Weak Infeed
Aid 1 WI Trip A
Echo
1 Week Infeed
Echo and Trip & Aid 1 WI Trip B
Snapshot Logic
S
Signal Send Q Aid 1 WI Trip C
100 ms R
&
1
Aided 1 WI V < A

Aided 1 WI V < B

Aided 1 WI V < C V03513

Figure 110: POR Aided Tripping logic

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4.7.6 AIDED SCHEME BLOCKING 1 TRIPPING LOGIC

498
Aided 1 Send
1
494 501
Aided 1 Receive 1 Aid1 Trip Enable

492
Aided 1 COS/LGS

V03516

Figure 111: Aided Scheme Blocking 1 Tripping logic

4.7.7 AIDED SCHEME BLOCKING 2 TRIPPING LOGIC

tReversal Guard

498
Aided 1 Send
1
Aided 1 Receive 494 tRGD 1 501
Aid1 Trip Enable

492
Aided 1 COS/LGS

V03517

Figure 112: Aided Scheme Blocking 2 Tripping logic

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5 AIDED DEF SCHEME LOGIC

5.1 AIDED DEF INTRODUCTION

High resistance faults may be difficult to detect using distance protection. A Directional Earth Fault DEF element is
sometimes used in conjunction with a communication scheme to provide protection against such faults. The use
of Aided-Trip logic in conjunction with the DEF element allows faster trip times, and can facilitate single-phase
tripping, if needed.
To use the Aided DEF protection you will need appropriate communication channels between terminals in the
scheme. The Programmable Scheme Logic (PSL) allows you to map signals for communication over the channels.
The signals you map may be signals to be sent to a remote terminal, or signals expected to be received from a
remote terminal. Two Aided DEF schemes are available.
With Aided DEF protection, the residual current (earth fault current) is compared with a threshold to determine the
presence of a fault, and a directionalising quantity to determine its direction. Directional measurements from
protecting terminals are then used in conjunction with teleprotection signals between the terminals, and aided
scheme logic to determine whether the fault is within the protected line (and hence trip), or outside the protected
line (and hence restrain).

5.2 IMPLEMENTATION
Aided DEF protection can be used with permissive over-reach schemes or blocking schemes.
The Aided DEF protection is enabled using the Directional E/F setting in the CONFIGURATION column. This makes
the settings in the AIDED DEF column visible.
The Aided DEF requires a polarizing quantity (selected in the DEF Polarizing setting) in conjunction with a
characteristic angle setting (DEF Char. Angle) to make the directional decision.
For all models a signal derived from the phase voltage inputs can be used for polarization. For certain models with
more VT inputs, a directly measured input can be used.
You have a choice between Zero Sequence Polarizing or Negative Sequence Polarizing for the Aided DEF element.
If you choose Zero Sequence Polarization, you have a choice to enable an innovative feature known as Virtual
Current Polarization to enhance the Aided DEF function.
Aided DEF protection is blocked if any of the following conditions are met:
● An Any Trip signal is asserted by one of the integrated protection functions
● The phase selector picks up on more than one phase
● Any of the signals Pole Dead A, Pole Dead B, or Pole Dead C are asserted

5.3 AIDED DEF POLARIZATION

There are essentially two ways of esablishing the direction of an earth fault:
● Zero sequence polarization
● Negative sequence polarization

Zero Sequence polarization normally uses the measurement of residual voltage (VN). This can only be achieved if a
5-limb VT or three single-phase VTs are used. A special form of zero sequence polarization called Virtual Current
Polarization is also possible with this device. Virtual Current Polarization allows directionalisation for low levels of
polarization voltage.

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5.3.1 ZERO SEQUENCE POLARIZING

Residual voltage is generated during earth faults. This zero-sequence quantity can be used to polarize the
directional decision of Aided DEF protection. This device can derive residual voltage if connected to a suitable
voltage transformer (VT) arrangement.
For the Aided DEF to use a derived voltage signal, the three phase voltage inputs must be supplied from a 5-limb
VT, or from three single-phase VTs having the primary star-point earthed. These VT arrangements allow the
passage of residual flux and hence allow the device to derive the required residual voltage. A 3-limb VT has no
path for residual flux and is therefore unsuitable for zero-sequence Polarization.
Small levels of residual voltage may be present under normal system conditions due to system imbalances, VT
inaccuracies and device tolerances. You can set a threshold (DEF VNPol Set) to provide stability against Aided DEF
operation under these conditions. Residual voltage (Vres) is nominally 180° out of phase with residual current so
Aided DEF elements are polarized from the -Vres quantity. This 180° phase shift is automatically compensated in
this device.

5.3.1.1 VIRTUAL CURRENT POLARIZING

A technique called Virtual Current Polarizing can allow the Aided DEF protection to operate even if the Polarizing
voltage is below the DEF VNPol Set threshold. If the superimposed current phase selector associated with the
Distance protection has identified a faulted phase, for example phase A, it removes that phase voltage from the
residual calculation Va + Vb + Vc, leaving only Vb + Vc. The resultant Polarizing voltage has a large magnitude and
is in the same direction as –Vres. This allows the protection to be applied even where very solid earthing behind
the protection prevents residual voltage from being developed.
This technique of subtracting the faulted phase is described as Virtual Current Polarizing because it removes the
need to use current Polarizing from a current transformer (CT) in a transformer star (wye)-earth connection behind
the device.
If you don’t want to use this feature you should set Virtual I Pol to Disabled so that removal of the faulted
phase voltage from the residual voltage calculation does not happen. The Aided DEF protection is then Polarized
by the residual voltage only.
The directional criteria with zero sequence (virtual current) Polarization are as follows:

Directional forward
90° < (angle(VNpol) +180°) - (angle(IN )- RCA) < 90°

Directional reverse
90° > (angle(VNpol) +180° - (angle(IN) - RCA) > 90°
This is represented in the following figure:

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IN angle -RCA

IN

For a forward direction, -VN hs to be in the shaded area

V03522 For a reverse direction, -VN has to be in unshaded area

Figure 113: Virtual Current Polarization

The Polarizing voltage (VNpol) is as per the table below and RCA is the relay characteristic angle defined by the
DEF Char. Angle setting.
Phase selector pickup VNpol
A Phase Fault VB + VC
B Phase Fault VA + VC
C Phase Fault VA + VB
No Selection VN = VA + VB + VC

5.3.2 NEGATIVE SEQUENCE POLARIZING

In certain applications, residual voltage polarization of Aided DEF may not be possible, or it may be problematic.
Example cases are:
● Where a 3-limb voltage transformer is fitted, which has no path for residual flux.
● Where the application features a parallel line and zero sequence mutual coupling may exist.

The problems in these applications can be alleviated using negative phase sequence (nps) voltage for polarization.
The nps voltage threshold must be set in the cell DEF V2pol Set.

Note:
The current quantity used for operation of the Aided DEF when it is nps Polarized is the residual current not the nps current.

The directional criteria with negative sequence polarization are as follows:

Directional forward
-90° < [(angle(V2) +180°) - (angle(I2) - RCA) ] < 90°

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Directional reverse
-90° > [ (angle(V2) +180°) - angle(I2) - RCA) ] > 90°
where RCA is the relay characteristic angle set in the DEF Char. Angle setting.
This is represented in the following figure:

I2 angle -RCA

I2

For a forward direction, -V2 hs to be in the shaded area

V03523 For a reverse direction, -V2 has to be in the unshaded area

Figure 114: Directional criteria for residual voltage polarization

5.4 AIDED DEF SETTING GUIDELINES

To use Aided DEF protection you need to set the polarization and the thresholds. Polarization can be achieved
using either zero sequence signals or negative sequence signals.
For zero sequence polarized Aided DEF, the typical zero sequence voltage on a healthy system can be as high as
1% (i.e.: 3% residual), and the voltage transformer (VT) error could be 1% per phase. A VNpol Set setting between
1% and 4%.Vn is typical, to avoid spurious detection on standing signals. The residual voltage measurement
provided in the MEASUREMENTS 1 column may assist in determining the required threshold setting during
commissioning, as this will indicate the level of standing residual voltage present. The Virtual Current Polarizing
feature will create a polarizing voltage, which is always large regardless of whether actual VN is present.
With Aided DEF, the residual current under fault conditions lies at an angle lagging the polarized voltage. Hence,
negative characteristic angle settings are required for Aided DEF applications. This is set in cell DEF Char. Angle in
the EARTH FAULT settings.
The following angle settings are recommended for a residual voltage polarized device:-
● Solidly earthed distribution systems: -45°
● Solidly earthed transmissions systems: -60°

If Virtual I Pol is set to ‘Disabled’ it prevents checking of the faulted phase and subsequent removal of the faulted
phase voltage. The aided DEF protection is then polarized by the residual voltage only.
For negative sequence polarization, the relay characteristic angle settings (DEF Char. Angle) must be based on the
angle of the upstream negative phase sequence source impedance. A typical setting is -60°.

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The Aided DEF Forward setting determines the current sensitivity (trip sensitivity) of the aided DEF aided scheme.
This setting must be set higher than any standing residual current unbalance. A typical setting will be between
10% and 20% In.
The Aided DEF Reverse setting determines the current sensitivity for the reverse earth fault. The setting must
always be below the aided DEF forward threshold for correct operation of blocking schemes and to provide
stability for current reversal in parallel line applications. The recommended setting is 2/3 of the Aided DEF forward
setting.

Note:
The Aided DEF Reverse setting has to be above the maximum steady state residual current imbalance.

5.5 AIDED DEF POR SCHEME

The scheme has the same features and requirements as the corresponding Distance scheme and provides
sensitive protection for high resistance earth faults.
The signalling channel is keyed from operation of the forward DEF Fwd Set element. If the remote device has also
detected a forward fault, it operates with no additional delay when it receives this signal.
The logic is:
● Send logic: Key channel if DEF Fwd Set picks up
● Permissive trip logic: Trip if DEF Fwd Set picks up AND the channel key is received
The figure below shows the element reaches, and the simplified scheme logic of the Aided DEF POR scheme.

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DEF Forward

ZL
A B

DEF Forward

CB Open & & CB Open

CRx CRx
DEF-Reverse & CTx CTx
& DEF-Reverse
1 1

LD0V & LD0V

&

DEF-Forward & & DEF-Forward

Trip Trip
DEF Inst DEF Inst
1 A B
1

DEF Bu1 t
Bu1 t
Bu1 DEF Bu1

DEF Bu2 t DEF Bu2

t
Bu2 Bu2

DEF IDMT t DEF IDMT

t
IDMT IDMT

E03518 Selectable features

Figure 115: Aided DEF POR scheme

5.6 AIDED DEF BLOCKING SCHEME

The scheme has the same features/requirements as the corresponding Distance scheme and provides sensitive
protection for high resistance earth faults.
The signalling channel is keyed from operation of the reverse Aided DEF element (DEF REV Set). If the remote
device’s forward Aided DEF element (DEF FWD Set) has picked up, it operates after the Aid. 1 DEF Dly. expires if no
block is received.
Where ‘t’ is shown in the diagram this signifies the time delay associated with an element. To allow time for a
blocking signal to arrive, a short time delay on aided tripping must be used.
The logic is:
● Send logic: Key channel if DEF REV Set picks up
● Trip logic: Trip if DEF FWD Set AND Channel NOT Received, after Aid. 1 DEF Dly. expires.

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The figures below show the element reaches, and the simplified scheme logic of the Aided Directional Earth Fault
(Aided DEF) Blocking scheme.

DEF-Forward

DEF-Reverse
ZL
A B

DEF-Forward
DEF-Reverse

CRx CRx
DEF-Reverse Start Start DEF-Reverse
CTx CTx
Stop Stop

DEF-Forward & & DEF-Forward

DEF Inst Trip Trip DEF Inst

1 A B 1

DEF Bu1 t
Bu1 t
Bu1 DEF Bu1

DEF Bu2 t
Bu2 t
Bu2 DEF Bu2

DEF IDMT t
IDMT t
IDMT DEF IDMT

E03519

Figure 116: Aided DEF Blocking scheme

5.7 AIDED DEF LOGIC DIAGRAMS

5.7.1 DEF DIRECTIONAL SIGNALS

DEF Forward element

892 996
Pole Dead A & DEF Forward
893
Pole Dead B 1
894 997
Pole Dead C & DEF Reverse

DEF Reverse element

V03526

Figure 117: DEF Directional Signals

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5.7.2 AIDED DEF SEND LOGIC

From Aided 1 Distance

From Aided 1 Delta
Signal Send
Aid. 1 DEF
Enabled Echo Send
&
Custom Send Mask 1 1
& &
DEF Fwd. 1 498
& Aided 1 Send
996 tRG
DEF Forward
&
Custom Send Mask
DEF Rev.
997
DEF Reverse
395
Aid 1 Inhibit DEF
877
TOC Active

Blk Send
497
Aid1 Custom Send
496
Aid1 Block Send

Notes:
Aided 1 scheme only shown .
P445 does not provide an Aided Delta function .
V03506

Figure 118: Aided DEF Send logic

5.7.3 CARRIER AIDED SCHEMES RECEIVE LOGIC

& 317
1 Aid 1 Chan Fail
&
t DR t DW
&
1
& 494
1 Aided 1 receive
1
& t PR

&
&
492
Aided 1 COS/LGS
&

493
Aided1 Scheme Rx
&
Aid. 1 Selection
PUR Unblocking
POR Unblocking 1
Prog. Unblocking V03508

Figure 119: Carrier Aided Schemes Receive logic

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5.7.4 AIDED DEF TRIPPING LOGIC

395
Aid 1 DEF Trip
Aid1 Inhibit DEF
3 Pole
501 1
Aid1 Trip Enable 1 And 3 Pole
1
502
Aid1 Custom Trip
1 tDEF & 641
Aid1 DEF Trip3 Ph
DEF Status &
505
Enabled 1 Aid 1 DEF Trip
&
996
DEF Forward
& 633
& 1 Aided 1 Trip A
1010
Phase Select A
& 634
1011 & 1 Aided 1 Trip B
Phase Select B
& 635
& 1 Aided 1 Trip C
1012
Phase Select C
& 636
1013 & 1 Aided 1 Trip N
Phase Select N

&
1
From Aided 1 Distance Trip A
& From Aided 1 Delta Trip A (if applicable)
From Aided 1 Distance Trip B
From Aided 1 Delta Trip B (if applicable)
& From Aided 1 Distance Trip C
From Aided 1 Delta Trip C (if applicable )
1013
Phase Select N From Aided 1 Distance Trip N
From Aided 1 Delta Trip N (if applicable )
Notes:
Aided 1 scheme only shown .
V03510

Figure 120: Aided DEF Tripping logic

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5.7.5 POR AIDED TRIPPING LOGIC

Aided 1 Receive
&
Aid. 1 Selection & Aid1 Trip Enable

POR

Distance signal send

DEF signal send 1

Delta signal send tReversal Guard

Any Zone 4 element

Delta reverse element 1 & Blk Send

1 tRGD
DEF reverse element

Any Trip
&
Trip Inputs 3Ph &
1 Echo Send

Send on Trip
None
Any Trip
& &
Any Trip 1 100ms

Send on Trip
Aided / Z1
&
Aid 1 Distance
Disabled
&
Zone 1 Trip
1
Aid 1 Dist Trip
&
Aid 1 DEF Trip 1
250 ms 100 ms
Aided 1 Receive
&
Aid. 1 Selection
POR

CB Open 3 ph 10 ms

CB Open A ph

CB Open B ph 1 & WI Sngl Pole Trp

CB Open C ph Disabled
& Aid1 WI Trip 3Ph
Blk Send 60 ms

VTS Slow Block

Weak Infeed
Aid 1 WI Trip A
Echo
1 Week Infeed
Echo and Trip & Aid 1 WI Trip B
Snapshot Logic
S
Signal Send Q Aid 1 WI Trip C
100 ms R
&
1
Aided 1 WI V < A

Aided 1 WI V < B

Aided 1 WI V < C V03513

Figure 121: POR Aided Tripping logic

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5.7.6 AIDED SCHEME BLOCKING 1 TRIPPING LOGIC

498
Aided 1 Send
1
494 501
Aided 1 Receive 1 Aid1 Trip Enable

492
Aided 1 COS/LGS

V03516

Figure 122: Aided Scheme Blocking 1 Tripping logic

5.7.7 AIDED SCHEME BLOCKING 2 TRIPPING LOGIC

tReversal Guard

498
Aided 1 Send
1
Aided 1 Receive 494 tRGD 1 501
Aid1 Trip Enable

492
Aided 1 COS/LGS

V03517

Figure 123: Aided Scheme Blocking 2 Tripping logic

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6 AIDED DELTA SCHEME LOGIC

If either a Permissive Overreaching scheme or a Blocking schemes is selected, it can be used to implement
Directional Comparison(Aided Delta) protection.

Caution:
Aided Delta should not be used on a communications channel if that channel is being used to
implement an Aided Distance Scheme or an Aided DEF scheme. You should ensure that the Aided
Distance and Aided DEF elements are disabled if you want to apply the Aided Delta (Directional
Comparison Protection).

6.1 AIDED DELTA POR SCHEME

The channel for an Aided Delta POR scheme is keyed by operation of the overreaching Delta Forward elements. If
the remote device has also detected a forward fault upon receipt of this signal, the protection operates.
If the signalling channel fails, Basic distance scheme tripping is available.
The logic is:
● Send logic: Key channel if a Detla Fault Forward is detected
● Permissive trip logic: Trip if a Delta Fault Forward AND a keyed channel is received.

This scheme is shown in the figure below.

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DIR REV DIR FWD

Z (T)
H
G

R R

Z (T)

DIR FWD DIR REV

DIR FWD DIR FWD

1 CTX CTX 1

CRX CRX
CB CB
OPEN & Signalling Signalling & OPEN
Equipment Equipment

DIR FWD & & DIR FWD

Trip G Trip H
1 1

TZ (T) TZ (T)
END G END H t
Z t Z
0 0

E03520

Figure 124: Aided Delta POR scheme

6.2 AIDED DELTA BLOCKING SCHEME

The signalling channel is keyed from operation of the Delta Reverse elements. If the remote device has detected
Delta Forward, it operates after the trip delay if no block is received.
The logic is:
● Send logic: Key channel if a Delta Fault Reverse condition is detected
● Trip logic: Trip if a Delta Fault Forward condition is detected, AND a keyed channel signal is NOT received,
before the Aided Delta Delay timer expires.

This scheme is shown in the figure below.

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DIR REV DIR FWD

Z (T)
H
G

R R

Z (T)

DIR FWD DIR REV

DIR REV DIR REV

CTX CTX

CRX CRX
Signalling Signalling
Equipment Equipment

DIR FWD & & DIR FWD

Trip G Trip H
1 1

TZ (T) END G END G TZ (T)

Z t t Z
0 0

E03521

Figure 125: Aided Delta Blocking scheme

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6.3 AIDED DELTA LOGIC DIAGRAMS

6.3.1 AIDED DELTA SEND LOGIC

Aid. 1 Delta
Enabled

Custom Send Mask

Dir Comp Fwd. From Aided 1 Distance

998
From Aided 1 DEF
Delta Dir Fwd AN
Signal Send
999
Delta Dir Fwd BN
Echo Send
1000
Delta Dir Fwd CN &
1 1 1
Delta Dir Fwd AB 1001 & &
1 498
1002
& Aided 1 Send
Delta Dir Fwd BC tRG
1003
Delta Dir Fwd CA

Custom Send Mask

Dir Comp Rev.

Delta Dir Rev AN 1004 Blk Send

1005
Delta Dir Rev BN Aid1 Custom Send 497

1006
Delta Dir Rev CN &
1 Aid1 Block Send 496
Delta Dir Rev AB 1007

1008
Delta Dir Rev BC
Notes:
1009
Delta Dir Rev CA Aided 1 scheme only shown.
396
Aid1 Inhib Delta V03507

Figure 126: Aided Delta Send logic

6.3.2 CARRIER AIDED SCHEMES RECEIVE LOGIC

& 317
1 Aid 1 Chan Fail
&
t DR t DW
&
1
& 494
1 Aided 1 receive
1
& t PR

&
&
492
Aided 1 COS/LGS
&

493
Aided1 Scheme Rx
&
Aid. 1 Selection
PUR Unblocking
POR Unblocking 1
Prog. Unblocking V03508

Figure 127: Carrier Aided Schemes Receive logic

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6.3.3 AIDED DELTA TRIPPING LOGIC

396
Aid1 Inhib Delta
Aid. 1 DeltaTrip
501
Aid1 Trip Enable 3 Pole
1 1
502
1 And 3 Pole & 640
Aid1 Delta Tr3Ph
Aid1 Custom Trip

Aid. 1 Delta tDIR 504

1 1 Aid 1 Delta Trip
Enabled

& 633
Delta Dir FWD AN 998 & 1 Aided 1 Trip A
1
& 634
Delta Dir FWD BN 999 & 1 Aided 1 Trip B
1
& 635
Delta Dir FWD CN 1000 & 1 Aided 1 Trip C
1
1001
Delta Dir FWD AB & 636
& 1 Aided 1 Trip N
1002
Delta Dir FWD BC 1
From Aided 1 Def Trip A
1003
Delta Dir FWD CA From Aided 1 Distance Trip A
From Aided 1 Def Trip B
From Aided 1 Distance Trip B
Notes: From Aided 1 Def Trip C
Aided 1 scheme only shown . From Aided 1 Distance Trip C
From Aided 1 Def Trip N
V03511 From Aided 1 Distance Trip N

Figure 128: Aided Delta Tripping logic

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6.3.4 POR AIDED TRIPPING LOGIC

Aided 1 Receive
&
Aid. 1 Selection & Aid1 Trip Enable

POR

Distance signal send

DEF signal send 1

Delta signal send tReversal Guard

Any Zone 4 element

Delta reverse element 1 & Blk Send

1 tRGD
DEF reverse element

Any Trip
&
Trip Inputs 3Ph &
1 Echo Send

Send on Trip
None
Any Trip
& &
Any Trip 1 100ms

Send on Trip
Aided / Z1
&
Aid 1 Distance
Disabled
&
Zone 1 Trip
1
Aid 1 Dist Trip
&
Aid 1 DEF Trip 1
250 ms 100 ms
Aided 1 Receive
&
Aid. 1 Selection
POR

CB Open 3 ph 10 ms

CB Open A ph

CB Open B ph 1 & WI Sngl Pole Trp

CB Open C ph Disabled
& Aid1 WI Trip 3Ph
Blk Send 60 ms

VTS Slow Block

Weak Infeed
Aid 1 WI Trip A
Echo
1 Week Infeed
Echo and Trip & Aid 1 WI Trip B
Snapshot Logic
S
Signal Send Q Aid 1 WI Trip C
100 ms R
&
1
Aided 1 WI V < A

Aided 1 WI V < B

Aided 1 WI V < C V03513

Figure 129: POR Aided Tripping logic

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6.3.5 AIDED SCHEME BLOCKING 1 TRIPPING LOGIC

498
Aided 1 Send
1
494 501
Aided 1 Receive 1 Aid1 Trip Enable

492
Aided 1 COS/LGS

V03516

Figure 130: Aided Scheme Blocking 1 Tripping logic

6.3.6 AIDED SCHEME BLOCKING 2 TRIPPING LOGIC

tReversal Guard

498
Aided 1 Send
1
Aided 1 Receive 494 tRGD 1 501
Aid1 Trip Enable

492
Aided 1 COS/LGS

V03517

Figure 131: Aided Scheme Blocking 2 Tripping logic

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7 APPLICATION NOTES

7.1 AIDED DISTANCE PUR SCHEME

This scheme allows an instantaneous Zone 2 trip on receipt of the signal from the underreaching element of the
remote end protection.
The logic is:
● Send logic: Zone 1
● Permissive Trip logic: Zone 2 plus channel received

The time delay setting (Aid.1 Dist. Dly, Aid.2 Dist. Dly) should be set to 0 ms for fast fault clearance.

7.2 AIDED DISTANCE POR SCHEME

This scheme allows This scheme allows an instantaneous Zone 2 trip on receipt of the signal from the
overreaching element of the remote end protection.
The logic is
● Send logic: Zone 2
● Permissive Trip logic: Zone 2 plus channel received

The time delay setting (Aid.1 Dist. Dly, Aid.2 Dist. Dly) should be set to 0 ms for fast fault clearance.
The POR scheme also uses the reverse looking zone 4 IED as a reverse fault detector. This is used in the current
reversal logic and in the optional weak infeed echo feature.

Weak Infeed
Where weak infeed tripping is employed, a typical voltage setting is 70% of rated phase-neutral voltage. Weak
infeed tripping is time delayed according to the WI Trip Delay value, usually set at 60ms.

Current Reversal Guard

The recommended setting is:
● tReversal Guard = Maximum signalling channel reset time + 60 ms.

7.3 AIDED DISTANCE BLOCKING SCHEME

This scheme uses a reverse looking zone 4 element to block operation of a forward looking zone 2 element at the
remote end protection.
The logic is:
● Send logic: Reverse Zone 4
● Trip logic: Zone 2, plus Channel NOT Received

To allow time for a blocking signal to arrive, a short time delay must be allowed before tripping (Aid.1 Dist. Dly, Aid.
2 Dist. Dly). The recommended delay is as follows:
● Recommended setting = Maximum signalling channel operating time + one power frequency cycle.

Note:
Two variants of a Blocking scheme are provided, Blocking 1 and Blocking 2. Both schemes operate similarly, except that the
reversal guard timer location in the logic changes. Blocking 2 may sometimes allow faster unblocking when a fault evolves
from external to internal, and hence a faster trip.

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Current Reversal Guard

The recommended settings are as follows:
● Where Duplex signalling channels are used: Set tReversal Guard to the maximum signalling channel
operating time + 20ms.
● Where Simplex signalling channel is used: Set tReversal Guard to the combination of the maximum
signalling channel operating time, minus the minimum signalling channel reset time, and add 20ms.

7.4 AIDED DEF POR SCHEME

This scheme allows an instantaneous DEF trip of a local terminal if it sees a forward fault AND it receives a signal
from the remote end protection indicating that it is too has seen a forward fault.
The logic is:
● Send logic: DEF forward
● Permissive Trip logic: DEF forward plus channel received

The time delay would normally be set to 0 ms.

7.5 AIDED DEF BLOCKING SCHEME

This scheme prevents DEF tripping of a local terminal if it receives a signal from the remote end protection
indicating that the fault is in the reverse direction, and hence out of zone.
The logic is:
● Send logic: DEF reverse
● Trip logic: DEF forward plus channel NOT received, with a small set delay

To allow time for a blocking signal to arrive, a short time delay on aided tripping must be used. The recommended
delay time setting (Aid. 1 DEF Dly., Aid. 2 DEF Dly.) is the maximum signalling channel operating time +20 ms.

7.6 AIDED DELTA POR SCHEME

This scheme allows an instantaneous Delta trip of a local terminal if it sees a forward fault AND it receives a signal
from the remote end protection indicating that it is too has seen a forward fault.
● Send logic: Delta fault Forward
● Permissive Trip logic: Delta fault Forward plus channel received

The time delay (Aid. 1 Delta Dly, Aid. 2 Delta Dly) should be set to 0 ms for fast fault clearance.

Current Reversal Guard

Current reversals during fault clearances on adjacent parallel lines need to be treated with care.To prevent
maloperation, a current reversal guard timer must be set.
The recommended setting (tReversal Guard) is the maximum signalling channel reset time + 35 ms.

7.7 AIDED DELTA BLOCKING SCHEME

This scheme prevents Delta tripping of a local terminal if it receives a signal from the remote end protection
indicating that the fault is in the reverse direction, and hence out of zone.
● Send logic: Delta fault reverse
● Trip logic: Delta fault forward plus channel NOT received, delayed by Tp (a short time delay)

Recommended delay setting (Aid. 1 Delta Dly, Aid. 2 Delta Dly): Maximum signalling channel operating time
+ 6ms.

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Current Reversal Guard

Current reversals during fault clearances on adjacent parallel lines need to be treated with care.To prevent
maloperation, a current reversal guard timer must be set.
The recommended setting (tReversal Guard) is the maximum signalling channel reset time + 35 ms.

7.8 TEED FEEDER APPLICATIONS

Distance protection can be applied to protect three terminal lines (teed feeders). Interconnecting three terminals,
however, affects the apparent impedances seen by the distance elements and creates certain problems.
Consider, as an example, the following figure which represents a teed feeder with terminals A, B, and C, with a fault
applied near to terminal B:

A B
Ia Ib

Zat
Zbt

Ic
Zct

Va
Va = Ia Zat + Ib Zbt C Impedance seen by relay A =
Ia
Ia = Ia + Ic

E03524

Figure 132: Apparent Impedances seen by Distance Protection on a Teed Feeder

The impedance seen by the distance elements at terminal A is given by:

Za = Zat + Zbt + [Zbt.(Ic/Ia)]
For faults beyond the Tee point, with infeed from terminals A and C, the distance elements at A (and C) will
underreach. If terminal C is a relatively strong source, the underreaching effect at A can be substantial. If Zone 2
was set to a typical value of 120% of line AB, the element may fail to operate for internal faults. To compensate,
the Zone 2 element must be set to further overreach by a factor which takes into account the effect of the infeed
from the tee-point.
So, if infeed is present on a teed circuit, all Zone 2 elements should be set to overreach both of their remote
terminals by a factor which takes into account the effect of the infeed from the tee-point.
Like overreaching of Zone 2 elements, underreaching of Zone 1 elements must also be assured. Zone 1 elements
at each terminal must be set to underreach the true impedance to their nearest terminal (limiting case = no infeed
to the tee-point - hence no overreach contribution).
Changing the reach requirements to match the infeed expectations is possible using the alternative setting group
feature. Tailoring setting group contents to the different conditions, coupled with appropriate setting group
switching, enables the changing reach requirements to be met.

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Carrier aided schemes can also be used in conjunction with distance elements to protect teed feeders. Although
Permissive Overreaching and Permissive Underreaching schemes may be used, they suffer some limitations.
Blocking schemes are generally considered to be the most suitable.

7.8.1 POR SCHEMES FOR TEED FEEDERS

A Permissive Overreach (POR) scheme requires the use of two signalling channels between each pair of terminals.
On a teed feeder, a permissive trip is issued only if local Zone 2 operation is accompanied by receipt of signals from
both remote terminals. The 'AND' function of received signals can either be implemented using external logic, or
within the internal Programmable Scheme Logic (PSL).
To ensure operation for internal faults in a POR scheme, the protection at each of the three terminals should be
able to see a fault anywhere on the protected feeder. This may demand very large Zone 2 reach settings to
address the apparent impedances seen by the Distance elements.
Although POR schemes are feasible for teed feeders, the signalling requirements and the very large Zone 2
settings can make its use unattractive.

7.8.2 PUR SCHEMES FOR TEED FEEDERS

For a Permissive Underrreaching (PUR) scheme, the signalling channel is only keyed for internal faults. The channel
is keyed by Zone 1 operation. Aided tripping will occur at a receiving terminal if its overreaching Zone 2 setting
requirements have been met.
On teed feeder applications, a permissive trip is issued at a terminal if that terminal’s Zone 2 operation is
accompanied by receipt of a signal from EITHER remote terminal. This makes the signalling channel requirements
for a PUR scheme less demanding than for a Permissive Overreach (POR) scheme. Either a common power line
carrier (PLC) signalling channel or a triangulated signalling arrangement can be used, making a PUR scheme
generally more attractive than a POR scheme for protecting for a teed feeder.
It must be recognised, however, that there are cases where instantaneous tripping will not occur with PUR
schemes. The following figure illustrates three cases for which delayed tripping will occur:

248 P54x1i-TM-EN-1
P543i/P545i Chapter 8 - Carrier Aided Schemes

(i) A B

= area where no zone 1 overlap exists

Z1A Z1C

(ii) A C

Z1A Z1B

Fault Fault seen by A & B in zone 2

(iii) A C B
No infeed

Relay at C sees reverse fault until B opens

E03525

Figure 133: Problematic Fault Scenarios for PUR Scheme Application to Teed Feeders

● Scenario (i) shows a short tee connected to one nearby terminal and one distant terminal. In this case, Zone
1 elements set to 80% of the shortest connected feeder length don’t all overlap, resulting in a section not
covered by any Zone 1 element. Any fault in this section would rely on delayed Zone 2 tripping.
● Scenario (ii) shows an example where terminal C has no infeed. Distance elements at C may not operate for
faults close to the terminal. As the fault is outside the Zone 1 reaches of A and B, clearance will rely on
delayed Zone 2 tripping at A and B.
● Scenario (iii) shows an example where outfeed from terminal C feeds an internal fault via terminal B. In this
case, terminal C will not see the fault until the breaker at B has operated. The result would be sequential
(and hence delayed) tripping.

7.8.3 BLOCKING SCHEMES FOR TEED FEEDERS

With Blocking schemes, high speed operation can be achieved for circuits where there is no current infeed from
one or more terminals. This makes Blocking schemes particularly suitable for protection of teed feeders. The
scheme also has the advantage that the signalling requirement can be realised with one simplex channel.

Note:
Triangulated simplex channels could be used in place of a common simplex one if prefered.

As with Permissive Underreaching (PUR) schemes, a limitation of a Blocking scheme implementation is a scenario
where outfeed from one terminal feeds an internal fault via another terminal. The terminal with the outfeed sees a

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reverse fault condition. This results in a blocking signal being sent to the two remote terminals. Although the fault
will be cleared, tripping will be prevented until the Zone 2 time delay has expired.

250 P54x1i-TM-EN-1
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NON-AIDED SCHEMES
Chapter 9 - Non-Aided Schemes P543i/P545i

252 P54x1i-TM-EN-1
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1 CHAPTER OVERVIEW
This chapter describes the distance schemes that do not require communication between the ends (Non-Aided
Schemes).
This chapter contains the following sections:
Chapter Overview 253
Non-Aided Schemes 254
Basic Schemes 255
Trip On Close Schemes 259
Zone1 Extension Scheme 264
Loss of Load Scheme 265

P54x1i-TM-EN-1 253
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2 NON-AIDED SCHEMES
This product provides Distance protection. The Distance protection has been designed for use as a standalone
non-unit protection, or for use with communications systems to provide unit protection (Carrier Aided schemes).
Standalone operation provides basic scheme Distance protection (e.g. instantaneous Zone 1 operation, delayed
Zone 2 protection and further delayed Back-up protection, etc.). It also implements some special standalone
schemes that don’t require communications. These are known as Non-Aided Distance Schemes.
The non-aided schemes provided in this product can be divided into the following categories:
● Basic schemes
● Trip On Close schemes
● Zone 1 Extension scheme
● Loss of Load scheme

The settings for these Non-Aided Distance Schemes are located in the SCHEME LOGIC column.

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3 BASIC SCHEMES
Basic Scheme operation is always executed if distance elements are enabled. It is the process by which the
measured line impedance is compared against the Distance measuring zone configuration (reach settings and
timers). Instantaneous or time delayed tripping or blocking signals may be issued for a specific zone according to
its settings and the measured impedance values.
There are six basic scheme zones; Zone 1, Zone 2, Zone 3, Zone 4, Zone P and Zone Q.
The Basic Scheme settings include:
● A mode setting, which is common to all zones
● Zone Tripping settings for each zone
● Zone phase delay settings for each zone
● Zone ground delay settings for each zone

On a per-zone basis, phase and earth-fault elements may be set to have different time delays.
To supplement Basic Scheme operation, there are also standalone scheme designs (Non-Aided Distance Schemes)
that provide timely clearance for particular fault scenarios where carrier aided signalling is either not available, or
is unnecessary. These scenarios cover Trip on Closure (including Switch On to Fault, and Trip on Reclose), Loss of
Load, and Zone1 Extension.
The Basic Scheme is continually executed, regardless of any carrier-aided acceleration schemes which may be
enabled.

3.1 BASIC SCHEME MODES

The operation of distance zones according to their set time delays is called the basic scheme. The basic scheme
always runs, regardless of any channel-aided acceleration schemes which may be enabled.
The BasicScheme Mode setting defines how the timers associated with the different Distance zones in the Basic
Scheme are initiated by pick up (start) of zone elements.
In Standard mode, a zone timer starts only when the corresponding distance zone start occurs.
In Alternative mode, if a condition causes any of the enabled Distance elements to start, then the Any
Distance Start DDB signal is asserted. This starts the timers associated with all enabled zones (phase zone timers
and earth zone timers are started). The timers are reset if the Any Distance Start signal resets. If a Distance zone
measuring element is picked up when its associated zone timer times-out, a trip is issued for that zone element.
The Alternative mode is especially suitable for evolving faults, since all zone timers will be initiated at initial
fault inception, rather than waiting to start a timer as additional phases become faulted. This minimises the overall
fault clearance time as the fault develops.
The two modes are described by the following logic diagrams.

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Zone 1 Tripping
Ground only
1
Phase And Ground &
384
Block Zone 1 Gnd

Dist. Earth Mode Logic = 1

&
Standard 1 & Zone 1 AN
Is/Comp Earthing
&
PrioTripEna AN
1983
Is/Comp Enabled
960 &
Zone1 AN Element 1

1305 &
Z1 AN Comparator
& 1 & Zone 1 BN
PrioTripEna BN

961 &
Zone1 BN Element 1

1306 &
Z1 BN Comparator
& 1 & Zone 1 CN
PrioTripEna CN
744
1 Zone 1 N Start
962 &
Zone1 CN Element 1 Zone 1 Start Gnd

Zone (n) Start Gnd

1307 & n = 2, 3, 4, P, or Q 1
1691
Any Dist Start
Z1 CN Comparator
Zone (n) Start Phs
Zone 1 Tripping
Phase only 1 Zone 1 Start Phs
1
Phase And Ground

385
Block Zone 1 Phs
1 &
Block Zones 1 - 4
963 & Zone 1 AB
Zone1 AB Element

964 & Zone 1 BC

Zone1 BC Element

965 & Zone 1 CA

Zone1 CA Element

Zone 1 AN 741
1 Zone 1 A Start

Zone 1 BN 742
1 Zone 1 B Start

Zone 1 CN 743
1 Zone 1 C Start
V02781

Figure 134: Zone Starting Logic

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Standard Mode
tZ1 Gnd. Delay
Basic Scheme Mode
Standard 0 1984
& Z1 G time elapse
t
Zone 1 Start Gnd
tZ1 Ph. Delay

0 1985
& Z1 P time elapse
Zone 1 Start Phs t

Alternative Mode

tZ1 Gnd. Delay

Basic Scheme Mode
Alternative 0 1984
& Z1 G time elapse
1691 t
Any Dist Start
tZ1 Ph. Delay

0 1985
Z1 P time elapse
t
V02782

Figure 135: Zone timer logic

1984
Z1 G time elapse

Zone 1 AN
612
& Zone 1 N Trip
Zone 1 BN 1
608
Zone 1 CN 1 Zone 1 Trip
1985
Z1 P time elapse

Zone 1 AB
&
Zone 1 BC 1
Zone 1 CA
1984
Z1 G time elapse
& 609
Zone 1 AN 1 Zone 1 A Trip

1985
Z1 P time elapse

Zone 1 AB &
1
Zone 1 CA
1984
Z1 G time elapse
& 610
Zone 1 BN 1 Zone 1 B Trip

1985
Z1 P time elapse

Zone 1 AB &
1
Zone 1 BC

Z1 G time elapse
& 611
Zone 1 CN 1 Zone 1 C Trip

1985
Z1 P time elapse

Zone 1 BC &
1
Zone 1 CA
V02783

Figure 136: Zone trip logic

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3.2 BASIC SCHEME SETTING

The Zone 1 time delay (tZ1) is generally set to zero, giving instantaneous operation.
The Zone 2 time delay (tZ2) is set to co-ordinate with Zone 1 fault clearance time for adjacent lines. The total fault
clearance time consists of the downstream Zone 1 operating time plus the associated breaker operating time.
Allowance must also be made for the Zone 2 elements to reset following clearance of an adjacent line fault and
also for a safety margin. A typical minimum Zone 2 time delay is of the order of 200 ms.
The Zone 3 time delay (tZ3) is typically set with the same considerations made for the Zone 2 time delay, except
that the delay needs to co-ordinate with the downstream Zone 2 fault clearance. A typical minimum Zone 3
operating time would be in the region of 400 ms.
The Zone 4 time delay (tZ4) needs to coordinate with any protection for adjacent lines in the protection’s reverse
direction.
Separate time delays can be applied to both phase and ground fault zones, for example where ground fault delays
are set longer to time grade with external ground/earth overcurrent protection.
Any zone (#) which may reach through a power transformer reactance, and measure secondary side faults within
that impedance zone should have a small time delay applied. This is to avoid tripping on the inrush current when
energizing the transformer.
As a general rule, if the Zone Reach setting is greater than 50% of the transformer reactance, set the Zone delay to
be 100 ms or greater. Alternatively, the 2nd harmonic detector output (which is available in the Programmable
Scheme Logic) may be used to block zones that may be at risk of tripping on inrush current. Settings for the inrush
detector are found in the SUPERVISION column.
The figure below shows the typical application of the Basic scheme.

Zone 3
Zone 2
Zone 1
Z B

Z
Zone 1
Zone 2
Zone 3

Typical application

Relay A Relay B
Z1 TZ1 TZ1 Z1
Trip A Trip B
1 1
ZP TZP TZP ZP

Z2 TZ2 TZ2 Z2

Z3 TZ3 TZ3 Z3

Z4 Z4
TZ4 TZ4

Note: All timers can be set instantaneous

E02749

Figure 137: Basic time stepped distance scheme

258 P54x1i-TM-EN-1
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4 TRIP ON CLOSE SCHEMES

Logic is provided for situations where special tripping may be necessary following closure of the associated circuit
breaker. Two cases of Trip on Close (TOC) logic are catered for:
● Switch on to Fault (SOTF).
● Trip on Reclose (TOR)

SOTF provides instantaneous operation of selected elements if a fault is present when manual closure of the circuit
breaker is performed.
TOR provides instantaneous operation of selected elements if a persistent fault is present when the circuit breaker
attempts autoreclosure
The SOTF and TOR functions are known as Trip on Close logic. Both methods operate in parallel if mapped to the
SOTF and TOR Tripping matrix in the setting file.
The settings for Switch on to Fault (SOTF) and Trip on Reclose (TOR) are located in the TRIP ON CLOSE section of the
SCHEME LOGIC column.
SOTF and TOR are complemented by Current No Voltage level detectors (also known as CNV level detectors). These
CNV level detectors are set using the voltage and current settings located in the CB FAIL & P.DEAD column. The
same settings are used for pole dead logic detection. A 20ms time delay in the logic avoids a possible race
between very fast overvoltage and undercurrent level detectors.
The following figures show the Trip On Close function in relation to the Distance zones and the Trip On Close
function when driven by Current No Volt level detectors.

TOR Status
Enabled
878
Inhibit TOR 485 & TOR Active

891
Any Pole Dead S 877
Q TOC Active
R
TOC Delay

TOC Reset Delay &

486
Inhibit SOTF 1 879
SOTF Active
890
All Poles Dead
& S
Q
R
SOTF Delay

SOTF Pulse

SOTF Status
Enabled PoleDead 1
En Pdead + Pulse
Enabled ExtPulse 1
488 &
Set SOTF

V02742

Figure 138: Trip On Close logic

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559
Fast OV PHA
864
&
IA < Start

560 20 ms
Fast OV PHB 556
865 & 1 CNV ACTIVE
IB < Start 0

561
Fast OV PHC
866 &
IC< Start

TOR Tripping
Current No Volts

556 557
CNV ACTIVE & TOR Trip CNV

878
TOR Active

SOTF Tripping
Current No Volts

556 558
CNV ACTIVE & SOTF Trip CNV

879
SOTF Active
V02743

Figure 139: Trip On Close based on CNV level detectors

The Current No Volt (‘CNV’) level detectors can be set in the CB FAIL & P.DEAD column The same settings are used
for pole dead logic detection. A 20ms time delay in the logic avoids a possible race between very fast overvoltage
and undercurrent level detectors.

4.1 SWITCH ON TO FAULT (SOTF)

You can use the SOTF Status setting to activated SOTF in in three different ways. It can be:
● Enabled using the pole dead detection logic. If an ‘All Pole Dead’ condition is detected, the SOTF Delay timer
starts. Once this timer expires, SOTF is enabled and stays active for the period set in the TOC Reset Delay
setting.
● Enabled by an external pulse. SOTF is enabled after an external pulse linked to DDB Set SOTF is ON. The
external pulse could be a circuit breaker close command, for example. The function stays active for the
duration of the SOTF Pulse setting.
● Enabled using both pole dead detection logic and an external pulse.
Three pole instantaneous tripping (and auto-reclose blocking) occurs for any fault detected by the selected zones
or Current No Volt level detectors when in SOTF mode. Whether this feature is enabled or disabled, the normal time
delayed elements or aided channel scheme continues to function and can trip the circuit.
The SOTF Delay is a pick up time delay that starts after opening all three poles of a circuit breaker (CB). If the CB is
then closed after the set time delay has expired, SOTF protection is active. SOTF provides enhanced protection for
manual closure of the breaker (not for auto-reclosure). This setting is visible only if Enabled PoleDead or En
Pdead + Pulse are selected to enable SOTF.
While the Switch on to Fault Mode is active, the protection trips instantaneously for pick up of any zone selected in
these links. To operate for faults on the entire circuit length, you should select at least Zone 1 and Zone 2 using the
SOTF Tripping setting . If no elements are selected, the normal time delayed elements and aided scheme provide
the protection.
A user settable time window during which the SOTF protection is available through the SOTF Pulse setting This
setting is visible only if Enabled ExtPulse or En Pdead + Pulse are selected to enable SOTF.

4.1.1 SWITCH ONTO FAULT MODE

To ensure fast isolation of faults (for example a closed three phase earthing switch), on energisation enable this
feature with appropriate zones or Current No Volt (CNV) level detectors, depending on utility practices.

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P543i/P545i Chapter 9 - Non-Aided Schemes

When busbar voltage transformers are used, the Pole Dead’ signal is not produced. Connect circuit breaker
auxiliary contacts for correct operation. This is not necessary if the SOTF is activated by an external pulse.
● SOTF Delay: The time chosen should be longer than the slowest delayed-auto-reclose dead time, but
shorter than the time in which the system operator might re-energise a circuit once it had opened/tripped.
We recommend 110 seconds as a typical setting.
● SOTF Pulse: Typically this could be set to at 500ms. This time is enough to establish completely the voltage
memory of distance protection.
● TOC Reset Delay: We recommend 500ms as a typical setting (chosen to be in excess of the 16 cycles length
of memory polarizing, allowing full memory charging before normal protection resumes).

4.1.2 SOTF TRIPPING

SOTF Tripping
Zone 1 709
& SOTF Trip Zone 1
879
SOTF Active
960
Zone1 AN Element
961
Zone1 BN Element Note: This diagram shows Zone 1 only. The other zones follow the same
Zone1 CN Element 962 principles.
963 1
Zone1 AB Element
964
Zone1 BC Element
965
Zone1 CA Element V02756

Figure 140: SOTF Tripping

4.1.3 SOTF TRIPPING WITH CNV

559
Fast OV PHA
864
&
IA < Start

560 20 ms
Fast OV PHB 556
865 & 1 CNV ACTIVE
IB < Start 0

561
Fast OV PHC
866 & 558
IC< Start & SOTF Trip CNV

879
SOTF Active

SOTF Tripping
Current No Volts V02758

Figure 141: SOTF Tripping with CNV

4.2 TRIP ON RECLOSE (TOR)

Trip On Reclose (TOR) is special protection following auto-reclosure. The TOR status setting is used to enable or
disable TOR. When enabled, TOR is activated after the TOC Delay expires, ready for application when an auto-
reclose shot occurs.
When this feature is enabled, the protection operates in ‘Trip on Reclose mode’ for a period following circuit
breaker (CB) closure. Three-phase instantaneous tripping occurs for any fault detected by the selected zones or
CNV level detectors. Whether this feature is enabled or disabled, the normal time-delayed elements or aided
channel scheme continue to function and can trip the circuit.
The SOTF and TOR features stay in service for the duration of the TOC Reset Delay time, once the circuit is
energised. The delay timer starts on CB closure and is common for SOTF and TOR protection. Once this timer
expires after successful closure, all protection reverts to normal.

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Chapter 9 - Non-Aided Schemes P543i/P545i

A user settable time delay (TOC Delay) starts when the CB opens, after which TOR is enabled. The time delay must
not exceed the minimum Dead Time setting of the auto-reclose because both times start simultaneously and TOR
protection must be ready by the time the CB closes on potentially persistent faults.
While the Trip on Reclose Mode is active, the protection trips instantaneously for pick up of any selected Distance
zone. You select the zone with the TOR Tripping setting. For example, Zone 2 could operate without waiting for the
usual time delay if a fault is in Zone 2 on CB closure. Also Current No Volts can be mapped for fast fault clearance
on line reclosure on a permanent fault. To operate for faults on the entire circuit length, at least Zone 1 and Zone 2
should be selected. If no elements are selected, the normal time delayed elements and aided scheme provide the
protection. TOR tripping is three-phase and auto-reclose is blocked.

4.2.1 TRIP ON RECLOSE MODE

To ensure fast isolation of all persistent faults following the circuit breaker reclosure, enable this feature with
appropriate zones selected or Current No Volt (CNV) level detectors.
● TOC Delay: The Trip on Reclose (TOR) is activated after TOC Delay has expired. The setting must not exceed
the minimum autoreclose Dead Time setting to make sure that the TOR is active immediately on reclose
command.
● TOC Reset Delay: We recommend 500ms as a typical setting.

4.2.2 TOR TRIPPING LOGIC FOR APPROPRIATE ZONES

TOR Tripping
Zone 1 704
& TOR Trip Zone 1
878
TOR Active
960
Zone1 AN Element
961
Zone1 BN Element
962
Zone1 CN Element Note: This diagram shows Zone 1 only. The other zones follow the same
963 1
Zone1 AB Element principles.
964
Zone1 BC Element
965
Zone1 CA Element V02755

Figure 142: TOR Tripping logic for appropriate zones

4.2.3 TOR TRIPPING LOGIC WITH CNV

559
Fast OV PHA
864
&
IA < Start

560 20 ms
Fast OV PHB 556
865 & 1 CNV ACTIVE
IB < Start 0

561
Fast OV PHC
866 & 557
IC< Start & TOR Trip CNV

878
TOR Active

TOR Tripping
Current No Volts V02757

Figure 143: TOR Tripping logic with CNV

4.3 POLARISATION DURING CIRCUIT ENGERGISATION

While the Switch on to Fault (SOTF) and Trip on Reclose (TOR) modes are active, the directionalised distance
elements are partially cross polarised from other phases. The same proportion of healthy phase to faulted phase
voltage, as given by the Distance Polarizing setting in the DISTANCE SETUP menu, is used.

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Partial cross polarisation is therefore substituted for the normal memory polarising, for the duration of the TOC
Delay. If insufficient polarising voltage is available, a slight reverse offset (approximately 10% of the forward reach)
is included in the Zone 1 characteristic to enable fast clearance of close up three-phase faults.

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5 ZONE1 EXTENSION SCHEME

Auto-reclosure is widely used on radial overhead line circuits to re-establish supply following a transient fault. A
Zone 1 extension scheme may be applied to a radial overhead feeder to provide high speed protection for
transient faults along the whole of the protected line. The figure below shows the alternative reach selections for
zone 1: Z1 or the extended reach Z1X.

Z1 Extension (A)

ZL
A Z1A B

Z1 Extension (B)

E02739

Figure 144: Zone 1 extension scheme

In this scheme Zone 1X is enabled and set to overreach the protected line. A fault on the line, including one in the
end 20% not covered by Zone 1, results in instantaneous tripping followed by autoreclosure. Zone 1X has resistive
reaches and residual compensation similar to Zone 1. The autorecloser is used to inhibit tripping from Zone 1X so
that on reclosure the device operates with Basic scheme logic only, to co-ordinate with downstream protection for
permanent faults. Therefore transient faults on the line are cleared instantaneously, which reduces the probability
of a transient fault becoming permanent. However, the scheme can operate for some faults on an adjacent line,
although this is followed by autoreclosure with correct protection discrimination. Increased circuit breaker
operations would occur, together with transient loss of supply to a substation.
Fault trip Z1X time delay
First fault trip = tZ1
Fault trip for persistent fault on auto-reclose = tZ2
The Zone 1 extension scheme can be disabled, permanently enabled or just brought into service when the
communication channel fails and the aided scheme is inoperative. If used in conjunction with a channel-aided
scheme, Z1X can be set to be enabled when Ch1 or Ch2 fails, or when all channels fail, or when any channel fails.

490
Reset Zone 1 Ext 876
& Z1 X Active
Z1 Ext Scheme
Enabled
En. on Ch 1 Fail 1
&
En. on Ch 2 Fail
En. All Ch Fail
En. Any Ch Fail &

&

&
317
Aid 1 Chan Fail
318 1
Aid 2 Chan Fail
V02754

Figure 145: Zone 1 extension logic

264 P54x1i-TM-EN-1
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6 LOSS OF LOAD SCHEME

The Loss of Load Scheme provides fast unit protection performance for most fault types occurring on a double-
end fed line or feeder, but it does not need communications.
It is used on circuits that are designed for three-pole tripping, and provides protection for faults involving one or
two phases. It is not suitable for single-pole tripping applications, and it cannot protect against three-phase faults.
The scheme does not require communications, but it can be used alongside carrier aided schemes if
communications are available.
The Loss-of-Load scheme can be permanently enabled, permanently disabled, or enabled if communication failure
compromises channel-aided scheme operation. If used in conjunction with a channel-aided scheme, loss of load
can be set to be enabled if only Channel 1 fails, or if only Channel 2 fails, or if both channels fail, or if either channel
fails. Aided scheme communication failure is detected by permissive scheme unblocking logic, or the presence of a
Channel Out of Service (COS) input.

Zone 2 IED1
Zone 1 IED 1
Zone 1 IED 2

Zone 2 IED 2

IED 1 IED 2
V02740

Figure 146: Loss of load accelerated trip scheme

Any fault in the reach of Zone 1 results in fast tripping of the local circuit breaker. For an end zone fault for IED 1
(near IED 2) with remote infeed (from IED 2), the remote breaker is tripped in Zone 1 by the remote device at IED 2.
The local device (IED 1) can recognise this by detecting loss of load current in the healthy phases. This condition, in
conjunction with operation of a Zone 2 comparator at IED 1P, can be used to trip the local circuit breaker.
Before an accelerated trip can occur, load current must be detected before the fault. The loss of load current
opens a window during which time a trip occurs if a Zone 2 comparator operates. A typical setting for this window
is 40ms as shown in the figure below, although this can be altered in the LoL Window setting. The accelerated trip
is delayed by 18ms to prevent initiation of a loss of load trip due to circuit breaker pole discrepancy occurring for
clearance of an external fault. The local fault clearance time can be deduced as follows:
t = Z1d + 2CB + LDr + 18ms
where:
● Z1d = Maximum downstream zone 1 trip time
● CB = Breaker operating time
● LDr = Upstream level detector (LOL <1) reset time
For circuits with load tapped off the protected line, care must be taken in setting the loss of load feature to ensure
that the undercurrent level detector setting is above the tapped load current. When selected, the loss of load
feature operates with the main distance scheme that is selected. This provides high speed clearance for end zone
faults when the Basic scheme is selected or, with permissive signal aided tripping schemes, it provides high speed
back up clearance for end zone faults if the channel fails.

Note:
Loss of load tripping is only available where three pole tripping is used.

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Note:
Assertion of the Any Trip DDB signal or the Inhibit LOL DDB signal will prevent LOL tripping.

The detailed Loss of Load logic diagram is shown below:

LOL Scheme
Enabled
En. On Ch1 Fail 1
&
En. On Ch2 Fail
En. All Ch Fail
En. Any Ch Fail &

&

&
317
Aid 1 Chan Fail
318 1
Aid 2 Chan Fail

Tripping Mode
3 Pole
491 1 18 ms
Inhibit LoL & SD
654
Q Loss ofLoad Trip
Any trip 522 R

LOL Window
1365
I> LoL A
1366
I> LoL B &
1367
tLOL
I> LoL C

966 &
Zone2 AN Element

967 &
Zone2 BN Element

968 &
Zone2 CN Element
1

969 &
Zone2 AB Element

970 &
Zone2 BC Element

971 &
Zone2 CA Element V02741

Figure 147: Loss of Load Logic

266 P54x1i-TM-EN-1
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POWER SWING FUNCTIONS

Chapter 10 - Power Swing Functions P543i/P545i

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1 CHAPTER OVERVIEW
This chapter describes special blocking and protection functions, which use Power swing Analysis.
This chapter contains the following sections:
Chapter Overview 269
Introduction to Power Swing Blocking 270
Power Swing Blocking 272
Out of Step Protection 283

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2 INTRODUCTION TO POWER SWING BLOCKING

Power swings are variations in power flow that occur when the voltage phase angles at different points of
generation shift relative to each other. They can be caused by events such as fault occurrences and subsequent
clearance. Power swings may be classified as stable or unstable.
A stable power swing is one where, following a disturbance, all sources of generation return to a state where they
are all generating synchronous voltages. An unstable power swing is one where at least one source of generation
cannot restore operation that is synchronous with the rest of the system. In this case the poles of one source of
generation slip with respect to those of another. This condition is known as Pole Slipping.
A power swing may cause the impedance presented to Distance protection to move away from the normal load
area and into one or more of its tripping characteristics. Without attention this could lead to unwanted or
uncontrolled tripping.

Note:
Power swings do not involve earth, so only phase-phase impedances are affected.

For stable power swings, distance protection should not trip. To prevent tripping, a Power Swing Blocking (PSB)
function is usually provided to compliment Distance protection.
For unstable power swings, there may be a strategy for instigating a controlled system split. In this case, distance
protection should not trip during loss of stability. If unstable power swings or Pole-Slipping conditions might be
expected, certain points on the network may be designated as split points, where the network should be split if
unstable (or potentially unstable) conditions occur. Strategic splitting of the system can be achieved by means of
dedicated Out-of-Step Tripping protection (OOS or OST protection). Or it may be possible to achieve splitting by
strategically limiting the duration for which the operation of a specific distance protection is blocked during power
swing conditions.
A method often used to help understand power system stability and Pole Slipping is called Equal Area Criterion.
This is based on a number of operational curves as outlined in the figure below:

Power Curve 1

Area 2

F Area 1
A E G
Po
Out of step
D

Curve 2
Curve 3
C
B
θ
0º θ0 θ1 90º θ2 θ3 180º
Phase angle difference between two ends
V02762

Figure 148: Power transfer related to angular difference between two generation sources

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The figure describes the behaviour of a power system with parallel lines connecting two sources of generation.
● Curve 1 represents pre-fault system operation through parallel lines where the transmitted power is Po.
● Curve 2 represents transmitted power during a phase-phase-earth fault.
● Curve 3 represents a new power curve when the faulted line is tripped.

At fault inception, the operating point A moves to B, which is a reduced power transfer level. There is, therefore, a
surplus of power (A to B) at that sending end and a corresponding deficit of power at the receiving end. The
sending end generators start to speed up, and the receiving end generators start to slow down, so the phase
angle θ increases, and the operating point moves along curve 2 until the fault is cleared (point C). At this point, the
phase angle is θ1. The operating point now moves to point D on curve 3 which represents the power transfer curve
when just one line is in service. There is still a power surplus at the sending end and a deficit at the receiving end,
so the generators continue to lose synchronism and the operating point moves further along curve 3.
If, at some point between E and G (point F) the generators are rotating at the same speed, the phase angle will
stop increasing. According to the Equal Area Criterion, this occurs when Area 2 is equal to Area 1. The sending end
will now start to slow down and receiving end to speed up. Therefore, the phase angle starts to decrease and the
operating point moves back towards E. As the operating point passes E, the net sending end deficit again becomes
a surplus and the receiving end surplus becomes a deficit, so the sending end generators begin to speed up and
the receiving end generators begin to slow down. With no losses, the system operating point will oscillate around
point E on curve 3, but in practise the oscillation is damped, and the system eventually settles at operating point E.
So, if Area 1 is less than Area 2, the system will oscillate but will stay in synchronism. This swing is usually called a
recoverable, or stable, power swing. If, on the contrary, the system passes point G with a further increase in angle
difference between sending and receiving ends, the system loses synchronism and becomes unstable. This will
happen if the initial power transfer Po is so high that the Area 1 is greater than Area 2. This power swing is not
recoverable and is usually called an Out-of-Step condition or a Pole Slip condition. In such a case, only system
separation and subsequent re-synchronising of the generators can restore normal system operation.
The point G is shown at approximately 120°, but this can vary. If, for example, the pre-fault transmitted power (Po)
was high and the fault clearance was slow, Area 1 would be greater. For the system to recover from this case, the
angle θ would be closer to 90º. Similarly, if the pre-fault transmitted power Po was low and fault clearance fast,
Area 1 would be small, and the angle θ could go closer to 180º with the system remaining stable.

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3 POWER SWING BLOCKING

A power swing may cause the impedance presented to the distance function to move away from the normal load
area and into one or more of its tripping zones. Stable power swings should not cause the distance protection to
trip. Therefore, if the power swing is deemed to be stable, the distance protection function for the zone in question
is blocked. Unstable power swings should result in either tripping of the relevant protection element, or a system
split. Therefore, the distance protection element should also be blocked for unstable power swings if there is a
strategy for a controlled system split.

3.1 POWER SWING DETECTION

There are two power swing detection modes: Advanced and Conventional. You can set this with the Power
Swing Mode setting.
Advanced mode provides 'settings-free' operation. This uses a superimposed current technique (also known as a
delta technique). This technique is suitable for power swings in the normal to fast frequency range (>0.5Hz)
To detect slower power swings (<0.5Hz), a supplementary technique based on impedance characteristics is used.
This so called slow swing technique will invoke the power swing blocking function should the power swing be to
slow for the delta technique to operate. The impedance method uses zone 7 and zone 8 concentric quadrilateral
impedance characteristics. Power swing detection is achieved by measuring the time taken for the impedance
trajectory to cross through zone 8 into zone 7 (delta Z). In conventional mode, the impedance method is used
for all power swings.
Once a power swing is detected the following actions occur:
● Relevant distance elements are blocked (if blocking is enabled).
● All zones are switched to self-polarised mho characteristics with 10% offset reach for maximum stability
during the swing.

3.1.1 SETTINGS-FREE POWER SWING DETECTION

By "Settings-Free", we mean that there is no need to define any characteristic criteria. The only settings needed are
to define what to do in the event of a power swing (Allow trip, block, or unblock with a delay).
The settings-free power swing detection technique uses a superimposed current detector (DI), as used in the phase
selector. For each phase loop (A-B, B-C, C-A), the actual measured current is compared with the measured current
from exactly two cycles earlier (present in a 2-cycle FIFO buffer). If there is a difference between the two (DI), this
indicates that something is happening on that current loop.
The superimposed current (DI) is compared with a set threshold (set at 5%In) to produce a switching signal PH1.
This switching signal is used as an input to the power swing blocking function. It also triggers the current sample
values in the 2-cycle FIFO butter to be stored in memory for further current comparisons.
Superimposed currents appear during both fault conditions, and power swings. For fault conditions, superimposed
components will not normally extend beyond two cycles. Under power swing conditions however, superimposed
components persist beyond two cycles. We can use this fact to differentiate between faults and power swings.
During a power swing (in the absence of a fault), the phase selector will indicate a three-phase selection, or a
phase-phase selection if one pole is dead. So if superimposed components persist for three cycles, and a “faulted-
phase” indication of “three-phase with one pole dead” is present during those three cycles, a power swing has
been detected and the relevant signals are asserted.
After a power swing condition has been detected, the DI threshold used by the phase selector is increased and the
current values present in the two cycle buffer are stored. This provides coverage for faults that might occur whilst
a power swing is in progress.
For a fault condition, the superimposed current detector should reset after two cycles, because once the fault
current values enter the FIFO buffer, this will be compared with the present fault current and the superimposed
current will return to zero. This will allow the power swing detection function to reset.

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Configuring Settings-Free Power Swing Detection

The power swing detection based on superimposed current requires no system study. You just need to decide
whether a zone should be blocked or allowed to trip if a power swing is detected. You do this zone by zone using
the zone specific settings. For example the zone 1 setting is Zone 1 Ph. PSB. The available options are Blocking,
Allow Trip, or Delayed Unblock.

3.1.1.1 TIMING OF THE PHASE SELECTOR SIGNALS

Start of
power swing End of
power swing

i (t)

3 cycles

PH1

PH2
t1 t2 t3

t 1: D i exceeds threshold 1 (5%In), so PH1 and PH2 go high

t 2: Threshold 2 invoked. PH2 goes low on account of threshold being increased . PH1 remains high,
because there continues to be a D i

t 3: PH1 goes low as power swing has diminished and D i goes below threshold 1
V02769
Figure 149: Phase selector timing for power swing condition

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Fault inception Fault cleared

i (t)

PH1

PH2
t1 t2 t3

t1: D i exceeds threshold 1 (5%In), so PH1 and PH2 go high

t2: Fault current value appears in 2 cycle buffer . This equals present fault current value so D i is reduced to
zero. PH1 therefore goes low. PH2 remains high because value in PH 2 memory is a stored value .

t3: Fault is cleared so PH 2 goes low. PH1 stays low even though there is a new D I, because the absolute
current value is also taken into consideration .
V02770
Figure 150: Phase selector timing for fault condition

Start of
power swing

i (t)

3 cycles

PH1

PH2
t1 t2 t3 t4 t5

t1: D i exceeds threshold 1 (5%In), so PH1 and PH2 go high

t2: Threshold 2 invoked (10%In). PH2 goes low on account of threshold being increased (from 5%IN to 10%In).
PH1 remains high, because there continues to be a D i

t3: Fault inception. D i exceeds threshold 2 (10%In), so PH2 goes high

t4: 2 cycles after fault inception , PH1 goes low

t5: Fault cleared, so PH2 goes low

V02771
Figure 151: Phase selector timing for fault during a power swing

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3.1.2 SLOW POWER SWING DETECTION

For slow power swings (0.5Hz and below) where the superimposed current may remain below the minimum 5%In
threshold needed for the superimposed current (DI) detector, a different detection method is used. This method is
called Slow Swing detection. This method requires the Slow Swing setting to be enabled.

Note:
If the Slow Swing feature is not Enabled, very slow power swings (< 0.5 Hz) may not be detected.

The Slow Swing method is based on changing impedance measurements and uses a pair of configurable
concentric quadrilateral zones on the impedance plane (Zone 7 and Zone 8). Since power swings don’t involve
earth, the impedance measurements are based on positive sequence quantities and only phase-phase
measurements are necessary. The characteristic is shown in the following figure:

+jX
PSB Z8 Zone 8

PSB Z7 Zone 7

Dt
ZL
Z1 = V1/I1

PSB R8' PSB R7' PSB R7 α

Resistive reverse (R’) PSB R8 Resistive forward (+R)

PSB Z7'

PSB Z8'

V02744

Figure 152: Slow Power Swing detection characteristic

The elapsed time defines the rate of change of impedance. If the rate of change is high, the change is due to a
fault. If the rate of change is low, the protection indicates a slow power swing. So, if the time taken for the
impedance trajectory to pass through zone 8 into zone 7 is greater than the time defined by the PSB timer, a slow
power swing is deemed to be in progress. If the time taken for the impedance trajectory to pass through zone 8
into zone 7 is less than that defined by the PSB timer, it is deemed to be a fault.
In other words, a power swing is indicated if the following condition is true:
Dt > PSB Timer
Both Zone 7 and Zone 8 characteristics are based on the positive sequence impedance measurement; Z1 = V1/I1.
The minimum current (sensitivity) needed for Zone 7 and Zone 8 measurements is 5%In.

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Configuring Slow Swing Detection

Slow Swing power swing detection and blocking must first be enabled with the Slow Swing setting. After this, you
need to configure the resistive and impedance reach settings to define the concentric quadrilateral characteristics
for zones 7 and 8:
PSB R7: forward resistive reach for zone 7
PSB R7': reverse resistive reach for zone 7
PSB R8: forward resistive reach for zone 8
PSB R8': reverse resistive reach for zone 8
PSB Z7: forward impedance reach for zone 7
PSB Z7': reverse impedance reach for zone 7
PSB Z8: forward impedance reach for zone 8
PSB Z8': reverse impedance reach for zone 8
You also need to configure the impedance phase angle a. This is the same for zone 7 and zone 8. To do this you
need to set Alpha between 20° and 90°.
The PSB timer setting defines the minimum time that the impedance trajectory must take to cross through zone 8
into zone 7 (Dt) before a power swing is deemed to have taken place. A power swing is indicated if Dt > PSB Timer.

3.2 DETECTION OF A FAULT DURING A POWER SWING

Faults are characterised by step changes in superimposed current (ΔI) rather than more gradual transitions
symptomatic of a power swing.
When a power swing is in progress, the threshold for the phase selector is increased to a value twice that of the
maximum prevailing superimposed current caused by the swing. A fault will cause a ΔI greater than this raised
threshold, so the fault will be detected by the phase selector. Operation of the phase selector in this condition
unblocks the PSB function, to allow tripping of Distance elements.
To provide stability for external faults, the blocking signal is only removed from zones that start within two cycles
of the phase detector recognising the fault:
Any Distance element measuring an impedance inside its characteristic before the phase selector detects the fault
remains blocked. This prevents tripping for a swing impedance that may be coincidentally passing through a fast-
acting zone, and which could cause spurious tripping if all elements were unblocked without qualification.
Any Distance element that measures an impedance inside its characteristic after the two cycle ΔI window of the
phase selector has expired, remains blocked. This prevents tripping for a continued swing that may pass through a
fast acting zone which could cause spurious tripping if the element was allowed to unblock by an unqualified
phase selector reset.

3.3 POWER SWING BLOCKING CONFIGURATION

To use the Power Swing function, you must ensure that the PowerSwing Block setting in the CONFIGURATION
column is set to Enabled. You can set Power Swing Blocking to Indication (where alarms are raised but no
blocking is imposed), or to Blocking (where blocking actions are imposed).
To define what the action the PSB function should take, you need to set the distance zones. The available distance
zones are:
Zone 1 Ph. PSB: Zone 1 phase
Zone 2 Ph. PSB: Zone 2 phase
Zone 3 Ph. PSB: Zone 3 phase
Zone 4 Ph. PSB: Zone 4 phase

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Zone P Ph. PSB: Zone P phase

Zone Q Ph. PSB: Zone P phase
Zone 1 Gnd. PSB: Zone 1 ground
Zone 2 Gnd. PSB: Zone 2 ground
Zone 3 Gnd. PSB: Zone 3 ground
Zone 4 Gnd. PSB: Zone 4 ground
Zone P Gnd. PSB: Zone P ground
Zone Q Gnd. PSB: Zone P ground
The following options are available for each of the above zones:
Allow Trip: If a power swing locus stays in the Distance characteristic for a duration equal to the element time
delay, the trip is allowed.
Blocking: Prevents tripping for that element, even if a power swing locus enters the element’s characteristic.
Delayed Unblock: This maintains the block for a set duration after a power swing has been detected. To use it,
you must set PSB Unblocking to Enabled, and then set the desired PSB Unblock dly time for removing the block.

Note:
The PSB Unblock dly timer is common to all elements.

The PSB Unblock dly is used to time the duration for which the swing is present. The intention is to allow the
distinction between a stable and an unstable swing. If after the timeout period the swing has still not stabilised, the
block for selected zones can be released (unblocking), giving the opportunity to split the system. If no unblocking is
required, set to maximum (10 s).
There is a further timer associated with the PSB function. This is the PSB Reset Delay timer. This timer is provided to
maintain the power swing detection for a period after the superimposed current detection (ΔI) has reset. ΔI
naturally tends to zero twice during each power swing cycle (around the current maxima and minima in the swing
element). A short time delay ensures continued PSB pick-up during these ΔI minima.
The PSB Reset Delay is used to maintain the PSB status when DI naturally is low during the swing cycle (near the
current maxima and minima in the swing envelope). A typical setting of 0.2s is used to seal-in the detection until DI
has chance to appear again.
The WI Trip PSB setting determines what will happen if a power swing is detected whilst the Weak Infeed (WI)
tripping feature is being used and the WI condition is present for longer than the WI Trip Delay time. If Blocking
is selected, the weak infeed operation will be disabled for the duration of the swing. If Delayed Unblock is
chosen, the weak infeed element block will be removed after drop off timer PSB Unblock dly has expired, even if
the swing is still present. This allows system separation when swings fail to stabilise. In Allow trip mode, the
weak infeed element is unaffected by power swing detection.

3.4 POWER SWING LOAD BLINDING BOUNDARY

If the product has load blinding enabled, the following applies for phase-to-phase loops:
Impedance values, which are inside the load blinder boundaries and close to it for more than one cycle, are
indicative of a power swing. The power swing region is represented by the shaded area in the following diagram.

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jX

Zone x

Power Swing region

(shaded area)
Operate Region

-10°
Blind Region
Blind Region
20%

-R Load blinder boundary R

-jX
V02775

Figure 153: Load Blinder Boundary Conditions

The area is defined by lines created with angles fixed at 10° closer to the resistive axis than those created by the
load blinder angle setting (Load/B Angle - 10°) and a circular arc with a radius concentric with, and equivalent
to 20% greater than, the load blinder impedance setting (Z< Blinder Imp + 20%).
This is clearly indicated with reference to the diagram.

Note:
This power swing conditions are completely independent of the slow swing associated with Zone 7 and Zone 8.

3.5 POWER SWING BLOCKING LOGIC

The Power Swing function follows the logic diagram below:

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Power Swing
Blocking

PSB Reset Delay

1691
Any Dist Start 3 cycles
t 0 1014
& P Swing Detector
Ph1 0 t

t
1 & Block selected element
0 &

Fault detection 1015

PSB Fault
during power swing
Ph2
297
Power Swing
PSB Unblock Dly

PSB Unblocking
Enabled

Slow Swing Slow Swing PSB Detector

Enable
V Impedance
I Calculator
PSB Timer PSB Timer

PSB Z7
PSB Z8 607
Slow PSB
PSB Z 7' Detector
PSB Z 8' Module
Quad
PSB R7 characteristic
PSB R8 definition

PSB R7'
PSB R8'
Alpha

V02745

Figure 154: Power swing blocking logic

Note:
This is a simplified representation to highlight the outputs of the Power Swing Blocking function.

3.6 POWER SWING BLOCKING SETTING GUIDELINES

Power sing blocking (PSB) should normally only be enabled in transmission system applications. Power swings are
not expected to occur at distribution level.
The main power swing detection technique used in this product can detect power swings faster than 0.5Hz
without you having to set any parameters. This method relies on superimposed current (ΔI) component techniques
to automatically detect power swings. The threshold to detect a power swing is 5%In. During power oscillations
slower than 0.5Hz the continuous ∆I phase current integral to the detection technique may be less than the 5%In
threshold. So it may not operate. Slow swings usually occur following sudden load changes or single pole tripping
on weak systems where the displacement of initial power transfer is not severe. Generally, swings of up to 1Hz are
recoverable, but the swing impedance may stay longer inside the Distance characteristics than might be expected
before the oscillations are damped by the power system. Therefore, to guarantee system stability during very slow
swings, we recommend setting Slow Swing to Enabled to complement the automatic setting-free detection
algorithm.

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To configure the slow power swing function you need to set the resistive and reactive limits of the Zone 7 and Zone
8 quadrilaterals. You also need to set the PSB Timer which defines the critical time period of the transition between
the two zones and which is characteristic of the slow swing.
Whichever power swing detector is responsible for applying PSB, the removal of PSB is defined by two settings –
the PSB Reset Delay and (if an unblocking philosophy is employed) the PSB Unblock dly.

3.6.1 SETTING THE RESISTIVE LIMITS

The Zone 7 quadrilateral should encompass all distance elements to be blocked during a power swing condition.
The Zone 8 quadrilateral should be set smaller than the minimum possible load impedance. The security margin
for both conditions should be at least 20%, also a margin of at least 10% should be provided between Zone 7 and
Zone 8:
R8 > 1.1(R7)
We recommend setting the magnitudes of R7’ and R8’ equal to R7 and R8 respectively:
R7’ = -R7, R8’ = -R8.

Distance zones to be blocked

+jX (only phase-to-phase)
Zone 8
Zone 7

Maximum Load

½ Rx Ph. Resistive

Resistive reverse (R’) Resistive forward (+R)

V02750

Figure 155: Setting the resistive reaches

3.6.2 SETTING THE REACTIVE LIMITS

The inner Zone 7 should be set in excess of total impedance ZT , which include local source impedance ZS , line
impedance ZL and remote source impedance ZR. Only positive sequence impedances should be considered. The
security margin for this condition should be at least 20%. The recommended margin between Z7 and Z8 settings is
10%:
Z8 = 1.1(Z7)
We recommend setting the magnitudes of Z7’ and Z8’ equal to Z7 and Z8 respectively
Z7’ = -Z7, Z8’ = -Z8

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The angle Alpha should be set equal to the angle of the total impedance ZT:

a = ÐZT

+jX
Zone 8

Zone 7

ZR

ZL α = ÐZ T
ZT
Resistive reverse (R’) Resistive forward (+R)

ZS

V02751

Figure 156: Reactive reach settings

3.6.3 PSB TIMER SETTING GUIDELINES

The Setting PSB Time setting can be calculated as follows:

(θ1 − θ 2 ) ⋅ f nom
∆t =
f PS
where
● angles q1 and q2 are defined in the following figure
● fnom is the nominal frequency
● fPS is the maximum Power Swing frequency to be taken into account
Since any power swing with fPS >= 0.5Hz can be detected by the setting-free delta current algorithm, only power
swings with fPS < 0.5Hz Hz need to be considered for Slow Power Swing detection. We recommended setting fPS to
1Hz because this value provides sufficient security margin.

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ZR Zone 7 Zone 8

ZL

ZT
2 q1
q2
ZT

ZS

V02752

Figure 157: PSB timer setting guidelines

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4 OUT OF STEP PROTECTION

Out-of-Step detection is based on the speed and trajectory of measured positive sequence impedance passing
through a particular characteristic. During power system disturbances such as faults and power swings, measured
impedance moves away from normal load values. Power swings, where the system voltage angles change relative
to each other, can be either stable (recoverable) or unstable (non-recoverable). It is the unstable power swings that
result in an Out-of-Step condition.
For stable power swings the relative phase angles will oscillate, but these oscillations will fade and synchronism
between generating sources will be maintained. Detecting stable power swings is necessary to prevent unwanted
tripping of impedance measuring protection elements if the swing impedance transiently passes through the fault
impedance zone.
Unstable power swings (which can be destructive) result in sources of generation losing synchronism. This is called
pole slipping. Detecting unstable power swings allows controlled tripping to split the systems into stable areas so
that synchronism is maintained in each area. This is called Out-of-Step tripping (OOS or OST).
As well as tripping for Out-of-Step conditions, it is possible to predict OST conditions. This allows controlled tripping
and consequent splitting of the system to recover stable operation before pole slipping occurs. This is called
Predictive Out-of-Step tripping (Predictive OST).
Out-of-Step and Predictive Out-of-Step protection is based on changing impedance measurements, and uses a
pair of configurable quadrilateral characteristics in the impedance plane (Zone 5 and Zone 6).
Out of Step protection is used to split the power system into more stable areas of generation and load balance
during unstable power oscillations. The points at which the system should be split are determined by detailed
system stability studies.

4.1 OUT OF STEP DETECTION

The Out of Step detection is based on the well proven ∆Z/∆t principle associated with two concentric polygon
characteristic, as shown below:

+jX
OST Z6 Zone 6

OST Z5 Zone 5

Predictive OST trip

OST trip Recoverable swing

ZL

OST R6' OST R5' OST R5 α

Resistive reverse (R’) OST R6 Resistive forward (+R)

OST Z5'

OST Z6'

V02760

Figure 158: Out of Step detection characteristic

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The OST principle uses positive sequence impedances. The positive sequence impedance is calculated as Z1 =
V1/I1, where V1 and I1 are the positive sequence voltage and current quantities derived from the measured phase
quantities. The concentric quadrilaterals are designated Zone 5 and Zone 6. Zone 5 encompasses possible system
fault impedances and sits within Zone 6. Because OST and Predictive OST quadrilaterals are based on positive
sequence impedances, all OST conditions are covered by a single measurement. Both quadrilaterals are
independent and have independent reach settings.
All four resistive blinders are parallel, using the common angle setting (a) that corresponds to the angle of the total
system impedance (ZT = ZS + ZL + ZR), where ZS and ZR are equivalent positive sequence impedances at the
sending and receiving ends and ZL positive sequence line impedance. The reactance lines are also parallel as
neither reactance line tilting nor esidual compensation is implemented.
In the figure, the purple solid impedance trajectory represents the locus for the non-recoverable power sawing,
known as a pole slip or Out Of Step condition. The dotted green impedance trajectory represents a recoverable
power swing.

4.2 OUT OF STEP PROTECTION OPERATAING PRINCIPLE

The Out of Step function has four different setting options, which are only visible if the PowerSwing Block is
enabled in the CONFIGURATION column:
● Disabled: Disables the Out of Step function.
● Pred. OST: Splits the system in advance. It minimizes the angle shift between two ends and aids stability
in the split areas.
● OST: Splits the system when an out of step condition is detected, which is when a pole slip occurs.
● Pred. OST or OST: Splits the system in advance or when an out of step condition is detected.
The Out-of-Step detection algorithm is based on the speed of the positive sequence impedance passing through
the characteristic. When the positive sequence impedance enters the outer quadrilateral (Zone 6) a timer is
started. The timer is stopped after the positive sequence impedance passes through the inner quadrilateral (zone
5). Let us call this time the zone 6 to zone 5 transition time.
If this time is less than 25 ms, the protection considers this to be a power system fault, not an Out-of-Step
condition. This 25 ms time is fixed and cannot be set. During a power system fault, the speed of change from a
load impedance to a fault impedance is fast, but the protection may operate slower for marginal faults close to a
zone boundary. This is particularly the case for high resistive faults inside the zone operating characteristic and
close to the Zone 5 boundary. The fixed time of 25 ms is implemented to provide sufficient time for a distance
element to operate and therefore to distinguish between a fault and an extremely fast power swing.
If the zone 6 to zone 5 transition time takes more than 25 ms but less than the set delta T time, this is treated as a
very fast power swing and the protection will trip if either the Pred. OST Trip or the Pred. & OST Trip
options are selected and the Out-of-Step tripping time delay (Tost) has expired. The minimum delta T setting is 30
ms, allowing 5 ms margin with the fixed 25 ms timer.
If the zone 6 to zone 5 transition time takes longer than the set delta T time, it is considered as a slow power
swing. On entering Zone 5, the protection records the polarity of the resistive part of the positive sequence
impedance. From this state, two outcomes are possible:
● If the resistive part of the positive sequence impedance leaves Zone 5 with the same polarity as previously
recorded on entering Zone 5, it is considered to be a recoverable swing. In this case, the protection does not
trip.
● If, when exiting Zone 5, the resistive part of the positive sequence impedance has the opposite polarity to
that of the recorded polarity on entering Zone 5, an Out-of-Step condition is recognised. This is followed by
tripping if either Pred. OST Trip or Pred. & OST Trip is selected.

As the tripping mode for the detected Out-of-Step condition is always three-phase, the Pred. OST and OST DDB
signals are mapped to the three-phase tripping signal in the default programmable scheme logic.

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The Out-of-Step tripping time delay (Tost), delays the OST tripping command until the angle between internal
voltages between the two ends are at 240 degrees closing towards 360 degrees. This limits the voltage stress
across the circuit breaker. If a fault occurs during the swing condition, the Out-of-Step tripping function is blocked.
The Out-of-Step algorithm is completely independent from the distance elements and the power swing detection
function. The load blinder does not affect the OST characteristics. In common with other similar functions, a
minimum positive sequence current of 5%In is needed for Out-of-Step operation.

4.3 OUT OF STEP LOGIC DIAGRAM

554
Start Z5
& Fault detected
555
Start Z6 25ms
&
0
tost
t
0
& 551
& Pred. OST
delta T ≥ t
1 0

OST Mode
553
OST Disabled & OST
& Polarity Reversed?
Pred. OST Trip
1 & Polarity detector
Pred. & OST Trip Reset function
& Not reversed
OST Trip & ≥
1 1 &
555
Start Z6

Note : R1 is measured resistive component of positive sequence impedance Reset function

V02761

Figure 159: Out of Step logic diagram

4.4 OST APPLICATION NOTES

This product provides integrated Out-of-Step protection, which avoids the need for a separate stand alone Out-of-
Step device. This section provides guidance on how to configure Out of Step protection.
If you are going to use either of the predictive OST options (Pred. OST Trip or Pred. & OST Trip) you
must conduct detailed system studies to determine accurate settings. This is because high setting accuracy is
needed to avoid premature system splitting in the case of severe power oscillations that do not lead to pole slip
conditions.
Using the non-predictive OST Trip setting is simpler. You can can set it by knowing just the total system impedance,
ZT, and the system split points.

4.4.1 SETTING THE OST MODE

The OST Mode setting provides four options:
● OST Disabled
● Pred. OST Trip
● OST Trip
● Pred. & OST Trip

Setting OST Trip is the most commonly used approach when this protection is applied. OST Trip should be
used when Out-of-Step conditions are probable. If Out-of-Step conditions are detected, the OST command will be
issued to split the system at the pre-determined points. A disadvantage of the OST Trip option compared with

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the ‘Predictive’ options is that tripping will take a little longer so that the power oscillations may escalate further
after separation and the split parts may become separately unstable. An advantage, however, is that the decision
to split the system will always be valid even if the accurate system data and setting parameters cannot be
obtained.
The predictive setting options Pred. OST Trip and Pred. & OST Trip are recommended for systems
where Out-of-Step conditions could possibly occur, and where an early system split should minimise the phase
shift between generation sources. This should maximise the chances for the separated parts of the system to
stabilise as quickly as possible. Special care must be taken when these settings are used to ensure that the circuit
breakers at the different terminals do not open when the voltages at different ends are in anti-phase. This is
because most circuit breakers are not designed to break current at double the nominal voltage. Attempting to
break the current at double the nominal voltage could lead to flash-over and circuit breaker damage.
‘Predictive’ settings are designed to detect and trip for fast power oscillations. When predictive tripping is used
with a circuit breaker capable of operating in typically two-cycles, the two voltages angles may rapidly move in
opposite directions at the time of opening the circuit breaker. So, if you use the predictive settings you need to
apply settings that will ensure that the circuit breaker opening occurs well before the phase difference between
the different terminals approaches 180º. This means that accurate settings can only be determined by exhaustive
system studies.
The setting Pred. & OST Trip provides two stages of OST. If a power system oscillation is very fast, the
combination of ∆R (the difference between the Zone 5 and Zone 6 resistive reaches), and the Delta T settings, must
be set so that Pred. OST Trip operates. If the oscillation is slower, the condition for the predictive OST is not
met and so tripping is dictated by the OST condition being met. For the OST condition to be met, the resistive
component of the impedance must leave Zone 5 with opposite polarity compared with when it entered. If the
polarity is opposite when Zone 5 resets, OST will trip. If the polarity is the same when Zone 5 resets, OST will not
trip. This distinguishes between a slower non-recoverable oscillation and recoverable swings.
You should disable OST for applications on lines where unrecoverable power oscillations are not expected, or not
expected to be severe. This is likely to apply to strong interconnected systems operating with three-phase tripping.

4.4.1.1 DETERMINING THE LIMITS OF THE OST CHARACTERISTIC

The figure below shows the OST characteristic in conjunction with the system impedance, ZT, and particularly the
relationship with the resistive reach of the Zone 5 element.

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+jX
OST Z6 Zone 6

OST Z5 Zone 5

Predictive OST trip

ZT
ZR
OST trip
θ
ZL
OST R6' OST R5' α
Resistive reverse (R’) ZS OST R5 OST R6
Resistive forward (+R)

OST Z5'

OST Z6'

V02763

Figure 160: OST setting determination for the positive sequence resistive component OST R5

ZT is the total system positive sequence impedance equal to ZS + ZL + ZR, where ZS and ZR are the equivalent
positive sequence impedances at the sending and receiving ends and ZL is the positive sequence line impedance.
θ is the angular difference between the voltages at the sending and receiving ends beyond which no system
recovery is possible.
To determine the settings for OST, the minimum inner resistive reach of OST R5 (R5min) needs to be calculated.
The figure above shows that:
R5min = (ZT/2) / tan(θ/2
Next the maximum (limit value) for the outer resistive reach OST R6 (R6 max) needs to be calculated. Referring to
the figure below, point A must not overlap with the load area for the worst assumed power factor of 0.85 and the
lowest possible ZT angle α.

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+jX
OST Z6 Zone 6

ZT LOAD

OST R6' O 32° β α

Resistive reverse (R’) OST R6
Resistive forward (+R)

OST Z6'

V02764

Figure 161: OST R6max determination

β = 32 + 90 – α
Z load min = OA
Where:
● Z load min is the minimum load impedance radius
● 32º is the load angle that corresponds to the lower power factor of 0.85
● α is the load blinder angle (Blinder Angle) that matches the ZT angle
Therefore:
R6max < Z load min(Cos β)
Starting from the limit values R5min and R6max, the actual OST R5 and OST R6 reaches will be set in conjunction
with the Delta T setting.

Note:
The R6max reach must be greater than the maximum resistive reach of any distance zone to ensure correct initiation of the
25 ms and Delta T timers. However, the R5min reach could be set below the distance maximum resistive reach (inside the
distance characteristic) if an extensive resistive coverage is required, meaning that Out-of-Step protection does not pose a
restriction to the quadrilateral applications.

For each zone, we receommend setting the positive and negative limits to be the same so, OST R5’ = OST R5, OST
Z5’ = OST Z5, OST R6’ = OST R6, and OST Z6’ = OST Z6.

4.4.1.2 SETTING OST Z5 AND OST Z6

Setting of the reactance lines OST Z5 and OST Z6 depends on how far from the protection location the power
oscillations are to be detected. Normally, there is only one point for initial splitting of the system; and that point will
be determined by system studies. For that reason, the Out-of-Step protection must be enabled at that location and

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disabled on all others. To detect the Out-of-Step conditions, the OST Z5’, OST Z5, OST Z6’, and OST Z6 settings must
be set to comfortably encompass the total system impedance ZT. A typical setting could be:

OST Z5 = OST Z5’ = ZT

The OST Z6 and OST Z6’ settings are not of great importance and could be set to 1.1 x OST Z5.

4.4.1.3 SETTING OST R5, OST R6 AND DELTA T

The R5min and R6max settings determined above represent limit values. The actual OST R5 and OST R6 values
need to be determined in relation to the Delta T timer.

Predictive OST setting

For the Pred. OST Trip setting, it is important to:
● Set OST R6 equal to R6max
● Set OST R5 as close as practical to R6max
The aim of pushing the OST R5 setting to the right is to detect fast oscillations as soon as possible, in order to gain
sufficient time to operate the breaker before the two source voltages are in opposite directions. The only restriction
is the limitation of the Delta T minimum time delay of 30ms and the speed of oscillation.
You should set Delta T such that it does not expire after the positive sequence impedance has passed the OST R6
– OST R5 region.
For this setting, you need to know the rate-of-change of swing impedance when crossing the OST R6 – OST R5
region. This must therefore be based on system studies.

Note:
You cannot assume that the rate-of-change of positive sequence impedance while crossing the OST R6 – OST R5 region is the
same as the average rate-of-change of positive sequence impedance for the whole swing cycle. A false assumumption could
lead to incorrect predictive OST operation.

Note:
For a fault, the OST R6 – OST R5 region will be crossed faster than 25ms, therefore even very fast oscillations up to 7Hz will
not be mistaken as a fault condition and predictive OST will not operate.

OST setting
For the OST Trip setting option, such a precise setting of the blinders and Delta T is not necessary. This is
because for a wide ∆R region and a short Delta T setting, any oscillation will be successfully detected. However,
the fault impedance must pass through the ∆R region faster than the Delta T setting.
Therefore, for the OST Trip setting, assume that θ = 120° and set:
● OST R5 = OST R5’ = R5min = ZT/3.46
● OST R6 = OST R6’ = R6max
● Delta T = 30 ms
Delta T always expires. Therefore, the setting value given above will secure the detection of a wide range of
oscillations, starting from very slow oscillations (caused by recoverable swings) up to a fastest oscillation limit of
7Hz. Note that any fault impedance will pass the OST R6 – OST R5 region faster than the minimum settable Delta T
time of 30ms.

Predictive and OST setting

The recommendations for Pred. & OST Trip are the same as for Pred. OST Trip.

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4.4.1.4 SETTING THE OST TIME DELAY

For either of the predictive OST settings, the OST time delay setting (Tost) must be set zero.
For the OST Trip setting, Tost would normally be set to zero, but if you want to operate the breaker at an angle
closer to 360º (when voltages are in phase) you could apply a time delay.

4.4.1.5 BLINDER ANGLE SETTING

Set Blinder Angle, α, the same as the total system impedance angle, ZT.

4.4.1.6 OST FOR SERIES COMPENSATED LINES

The maximum phase currents during an Out-of-Step condition rarely exceed 2In, which corresponds to the
minimum swing impedance passing through Zone 1. Since the Metal-Oxide Varistors (MOV) bypass level is
normally set between 2-3In, they will not operate during the power oscillations and therefore in the majority of
applications they will not make any impact on Out-of-Step operation.
In the worst case, power oscillations are triggered on fault clearance on a parallel line. Approximately twice the
load current starts flowing through the remaining circuit. This increases further and eventually exceeds the MOV
threshold. The OST R6 - OST R5 region is usually set far from Zone 1, therefore it is unlikely that the positive
sequence impedance’s trajectory can traverse in and out of the set ∆R region due to the operation of MOVs. If
MOVs do operate in the ∆R region, a timer that has been initiated may reset and be reinitiated, or the impedance
may remain in the ∆R region for slightly longer. This is because resistive and capacitive components are added to
the measured impedance during MOV operation as shown in the figure below. This effect may have an impact on
the Delta T measurement if the Pred. OST Trip setting is used. If the recommendation to set R5min as close
as practically possible to R6max is followed, it is unlikely that the swing currents will exceed the MOV threshold in
the ∆R region. If a study shows that the MOVs could operate within the ∆R region, we recommend setting Pred.
& OST Trip operating mode to cover all eventualities.

+jX
OST Z6 Zone 6

OST Z5 Zone 5

DR

OST trip
MOVs operation
ZL
OST R6' OST R5'
Resistive reverse (R’) OST R5 OST R6
Resistive forward (+R)

OST Z5'

OST Z6'

V02765

Figure 162: Example of timer reset due to MOVs operation

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Note:
If the OST Trip setting is chosen, the timer when triggered, will eventually expire as the power oscillations progress, therefore
the MOV operation will not have any impact on Out-of-Step operation.

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AUTORECLOSE
Chapter 11 - Autoreclose P543i/P545i

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1 CHAPTER OVERVIEW
Selected models of this product provide sophisticated Autoreclose (AR) functionality. The purpose of this chapter is
to describe the operation of this functionality including the principles, logic diagrams and applications.
This chapter contains the following sections:
Chapter Overview 295
Introduction to Autoreclose 296
Autoreclose Implementation 297
Autoreclose System Map 302
Logic Modules 317
Setting Guidelines 349

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2 INTRODUCTION TO AUTORECLOSE
Approximately 80 - 90% of faults on transmission lines and distribution feeders are transient in nature. This means
that most faults do not last long, and are self-clearing if isolated. A common example of a transient fault is an
insulator flashover, which may be caused, for example, by lightning, clashing conductors, or wind-blown debris.
Protection functions detecting the flashover will cause one or more circuit breakers to trip and may also remove
the fault. If the source is removed, the fault does not recur if the line is re-energised.
The remaining 10 – 20% of faults are either semi-permanent or permanent. A small tree branch falling onto the
line for example, could cause a semi-permanent fault. Here the cause of the fault would not be removed by
immediate tripping of the circuit, but could possibly be burnt away during a time-delayed trip. Permanent faults
could be broken conductors, transformer faults, cable faults or machine faults, which must be located and
repaired before the power supply can be restored. In many fault incidents, if the faulty line is immediately tripped
out, and time is allowed for the fault arc to de-ionise, reclosing the circuit breakers will result in the line being
successfully re-energised.
Autoreclose schemes are used to automatically reclose a circuit breaker a set time after it has been opened due to
operation of a protection element. On EHV transmission networks, Autoreclose is usually characterised by high-
speed single-phase operation for the first attempt at reclosure. This is intended to help maintain system stability
during a transient fault condition. On HV/MV distribution networks, Autoreclose is applied mainly to radial feeders,
where system stability problems do not generally arise, and is generally characterised by delayed three-phase
operation with potentially multiple reclosure attempts.
Autoreclosing provides an important benefit on circuits using time-graded protection, in that it allows the use of
instantaneous protection to provide a high speed first trip. With fast tripping, the duration of the power arc
resulting from an overhead line fault is reduced to a minimum. This lessens the chance of damage to the line,
which might otherwise cause a transient fault to develop into a permanent fault. Using instantaneous protection
also prevents blowing of fuses in teed feeders, as well as reducing circuit breaker maintenance by eliminating pre-
arc heating. When instantaneous protection is used with Autoreclose, the scheme is normally arranged to block
the instantaneous protection after the first trip. Therefore, if the fault persists after re-closure, the time-graded
protection will provide discriminative tripping resulting in the isolation of the faulted section. However, for certain
applications, where the majority of the faults are likely to be transient, it is common practise to allow more than
one instantaneous trip before the instantaneous protection is blocked.
Some schemes allow a number of re-closures and time-graded trips after the first instantaneous trip, which may
result in the burning out and clearance of semi-permanent faults. Such a scheme may also be used to allow fuses
to operate in teed feeders where the fault current is low.
When considering feeders that are partly overhead line and partly underground cable, any decision to install
Autoreclose should be subject to analysis of the data (knowledge of the frequency of transient faults). This is
because this type of arrangement probably has a greater proportion of semi-permanent and permanent
faults than for purely overhead feeders. In this case, the advantages of Autoreclose are small. It can even be
disadvantageous because re-closing on to a faulty cable is likely to exacerbate the damage.

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3 AUTORECLOSE IMPLEMENTATION
Before describing this function it is first necessary to understand the following terminology:
● A Shot is an attempt to close a circuit breaker using the Autoreclose function.
● Multi-shot is where more than one Shot is attempted.
● Single-shot is where only one Shot is attempted.
● Dead Time denotes the time between initiation of the Autoreclose operation and the attempt to close the
circuit breaker.
● Reclaim time is the time following the initiation of the circuit breaker closing and the resetting of the
Autoreclose scheme should the Autoreclose attempt be successful and the protection does not detect a
subsequent fault condition.
● High-speed Autoreclose is generally regarded as an Autoreclose application where the Dead Time is less
than 1 second.
● Delayed Autoreclose is generally regarded as an Autoreclose application where the Dead Time is greater
than 1 second.

This product features a multiple-shot Autoreclose function, which is suitable for both High-speed Autoreclose and
Delayed Autoreclose.
The Autoreclose function can be set to perform a single-shot, two-shot, three-shot or four-shot cycle. Dead Times
for all shots can be adjusted independently.
If a circuit breaker closes successfully at the end of the Dead Time, a Reclaim Time starts. If the circuit breaker
does not trip again, the Autoreclose function resets at the end of the Reclaim Time. If the protection trips again
during the Reclaim Time, the sequence advances to the next shot in the programmed cycle. If all programmed
reclose attempts have been made and the circuit breaker does not remain closed, the Autoreclose function goes
into Lockout, whereupon manual intervention is required.
An Autoreclose cycle can be initiated by operation of an internal or external protection element provided it is
mapped correctly, and that the circuit breaker is closed when the protection operates.
You can choose to initiate the Dead Time on:
● Protection operation
● A protection reset
● A Line Dead condition
● Circuit breaker operation
At the end of the relevant Dead Time, provided system conditions are suitable, a circuit breaker close signal is
given. The system conditions to be met for closing are that:
● the system voltages are in synchronism
● or that the dead line/live bus or live line/dead bus conditions exist as indicated by the internal system check
synchronising element
● and that the circuit breaker closing spring, or other energy source, is fully charged as indicated by the circuit
breaker healthy input.
The circuit breaker close signal is removed when the circuit breaker closes.
If the protection trips and the circuit breaker opens during the Reclaim Time, the Autoreclose function either
advances to the next shot in the programmed cycle, or if all programmed reclose attempts have been made, goes
into Lockout. Each time a closure is attempted, a sequence counter is incremented by 1 and the Reclaim Time
starts again.
Autoreclose is configured in the AUTORECLOSE column of the relevant settings group. The function is disabled by
default. If you wish to use it you must enable it first in the CONFIGURATION column.

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The Autoreclose function is a logic controller implemented in software. It takes inputs and processes them
according to defined logic to generates appropriate outputs. The logic is controlled by user prescribed settings and
commands. The controlling logic is complex and so, in order to facilitate its design and understanding, it is
decomposed into smaller logic functions which, when combined together implement the complete scheme. This
section concludes with a summary of:
● the logic inputs to the Autoreclose function,
● the logic outputs from the Autoreclose function
● the Autoreclose operating sequence
● the high-level design of the system logic functionality

3.1 AUTORECLOSE LOGIC INPUTS FROM EXTERNAL SOURCES

Logic inputs control the operation of the Autoreclose function. The logic inputs are mapped using DDB signals in
the PSL.
Generally the inputs are from external equipment connected to opto-isolated inputs. They can also come from
communications inputs, and some are internally derived.
This section provides an overview of the logic inputs originating from external sources.

3.1.1 CIRCUIT BREAKER HEALTHY INPUT

For circuit breakers to close, it needs energy. This energy usually comes from a spring (spring-charged circuit
breakers) or from gas pressure (gas pressurised circuit breakers). After closing, it is necessary to re-establish
sufficient energy in the circuit breaker before it can be closed again.
DDB signal inputs to the Autoreclose function allow the health of circuit breakers to be mapped to the logic. when
asserted, these signals demonstrate that there is sufficient energy available to close and trip the circuit breaker
before initiating a circuit breaker close command. If the signal indicating the health of the circuit breaker is low,
and remains low for a defined period set in the circuit breaker healthy timer, the circuit breaker locks out and stays
open.
If the circuit breaker healthy signal is not mapped in the PSL, the DDB signal defaults to high so that Autoreclose
may proceed.

3.1.2 INHIBIT AUTORECLOSE INPUT

A logic input can be used to inhibit the Autoreclose function. The signal is mapped to the DDB signal Inhibit AR in
the PSL.
Energising the input inhibits any auto-switching of connected circuit breakers. Any Autoreclose in progress is reset
and inhibited but not locked out. This function ensures that auto-switching does not interfere with any manual
switching. A typical application is on a mesh-corner scheme where manual switching is being performed on the
mesh, for which any Autoreclose would cause interference.
For products that are capable of single-phase tripping and Autoreclose, if a single-phase Autoreclose cycle is in
progress and a single pole of the circuit breaker is tripped when the inhibit Autoreclose signal is raised, the circuit
breaker is instructed to trip all phases, ensuring that all poles are in the same state (and avoiding a pole stuck
condition) when subsequent closing of the circuit breaker is attempted.

3.1.3 BLOCK AUTORECLOSE INPUT

External inputs can be used to block the Autoreclose function. If Autoreclose is in progress when the signal is
asserted, it forces a lockout.
Typically this feature is used where Autoreclose may be required for some protections functions but not required
for others. An example is on a transformer feeder, where Autoreclose can be initiated from the feeder protection
but blocked from the transformer protection.

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It can also be used if an Autoreclose cycle is likely to fail for conditions associated with the protected circuit, such
as during the Dead Time, if a circuit breaker indicates that it is not healthy to switch.

3.1.4 RESET LOCKOUT INPUT

If a condition that forced a lockout has been removed, the lockout can be reset by energising a logic input
appropriately mapped in the PSL. Energising the input will also reset any Autoreclose alarms.

3.1.5 POLE DISCREPANCY INPUT

Circuit breakers with independent mechanisms for each pole (phase), normally incorporate a mechanism to cater
for cases where the phases are not together. This automatically trips all three phases if they are either not all open,
or not all closed.
During single-phase Autoreclosing a pole discrepancy condition is necessarily introduced, but the pole discrepancy
device should not operate for this condition. This can be achieved using a delayed action pole discrepancy device
with a delay longer than the single-pole Autoreclose Dead Time (SP AR Dead Time setting).
Alternatively, an input can be used for external devices to indicate a pole discrepancy condition. The pole
discrepancy input is activated by an external device to indicate that all three poles of a circuit breaker are not in
the same position. If mapped in the PSL, energising the input forces three-phase tripping (providing there is not a
single-phase Autoreclose in progress). Otherwise, a signal indicating single-phase Autoreclose in progress can be
used to inhibit the external pole discrepancy device.

3.1.6 EXTERNAL TRIP INDICATION

Protection operation from a different device can be used to initiate the Autoreclose function. By default these
external trip inputs are mapped to initiate Autoreclose and to initiate breaker failure protection (if the functions are
enabled). These inputs are not mapped to the trip outputs. With appropriate mapping in the PSL however, the
external device can use this product to trip connected circuit breakers.

3.2 AUTORECLOSE LOGIC INPUTS

This section provides an overview of the logic inputs, which are derived internally.

3.2.1 TRIP INITIATION SIGNALS

The phase A, phase B and phase C trip inputs are used to initiate single-phase and three-phase autoreclose. For
the Autoreclose to work, you must ensure that these Trip Input signals remain appropriately mapped in the PSL.

3.2.2 CIRCUIT BREAKER STATUS INPUTS

Circuit breaker status information must be available as logic input(s) for Autoreclose to work. You can select
whether to use CB open, CB closed, or both, as inputs. The settings are made in the CB CONTROL column of the
menu, and you need to ensure that the PSL mapping of the chosen input(s) is correct.

3.2.3 SYSTEM CHECK SIGNALS

System Check and Check Synchronization functions produce signals which are used by the Autoreclose logic
ensure that the Autoreclose function is applied only when the system is in a suitable condition.

3.3 AUTORECLOSE LOGIC OUTPUTS

Output signals are provided to provide indication of an Autoreclose in progress (ARIP). An ARIP signal is asserted
when an Autoreclose sequence starts. It remains high from initiation, either until lockout, or until successful
Autoreclose.
An Autoreclose lockout condition resets any ‘Autoreclose in progress’ and associated signals. Signals are available
to indicate that Autoreclose is in progress and that a circuit breakers has been successfully closed.

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3.4 AUTORECLOSE OPERATING SEQUENCE

The Autoreclose sequence is controlled by so-called Dead Timers. Dead Time Control settings are used to select
the conditions that initiate Dead Timers in the Autoreclose sequence (for example protection operate, protection
reset, CB open, etc.). This section describes typical AR operation sequences in which Dead Timers start when
protection operation resets.

Note:
In a multi-shot AR sequence, a number of Dead Timers are used (one for each shot). All Dead Timers are enabled when the
sequence is initiated, but each timer only starts when the particular shot with which it is associated is triggered.

3.4.1 AR TIMING SEQUENCE - TRANSIENT FAULT

The figure below describes the operating sequence for a single-shot Autorecloser for a transient fault that clears
when the faulted line is isolated.

Protection Trip

AR in Progress

CB Open

Dead Time

Auto -close

Reclaim Time

Successful Autoreclose

V03395

Figure 163: Autoreclose sequence for a Transient Fault

Following fault inception, the protection operates and issues a trip signal. At the same time the Autoreclose in
Progress signal is asserted. Shortly afterwards the circuit breaker will open as indicated by the CB Open signal.
Opening of the CB clears the fault and the protection resets. When this happens, the Dead Timer is started and the
output remains high until the Dead Time setting expires, whereupon it resets and the Autorecloser issues the Auto-
close command to close the circuit breaker. As the fault has been cleared, the circuit breaker closes and remains
closed. When the Auto-close pulse is removed, the Reclaim Timer starts. If no further fault is detected before the
Reclaim Timer expires, the Autoreclose is considered to be successful and this is indicated by the Successful
Autoreclose signal.

3.4.2 AR TIMING SEQUENCE - EVOLVING/PERMANENT FAULT

The figure below shows a single-shot AR operating sequence where the fault is not cleared by the first AR cycle.
The sequence starts in a similar way to that of a transient fault, but in this case the fault is not transient (it may be
permanent, or it may evolve into a fault involving more than one phase). This case shows an evolving fault
inception occurring before the Reclaim Time has expired. When the Autorecloser recognises that the protection
has tripped, the cycle is terminated. The Autorecloser goes into Lockout, and the Autoreclose in Progress signal is
reset.

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P543i/P545i Chapter 11 - Autoreclose

Protection Trip

AR in Progress

CB Open

Dead Time

Auto-close

Reclaim Time

Successful Autoreclose

Autoreclose Lockout

V03396

Figure 164: Autoreclose sequence for an evolving or permanent fault

3.4.3 AR TIMING SEQUENCE - EVOLVING/PERMANENT FAULT SINGLE-PHASE

If the Autorecloser is set for single-phase operation, then single phase operation is only allowed on the first shot.
Subsequent tripping will be three-phase only until the AR has been successful or until AR has locked out as shown
in the figure below.

Protection Trip 1-ph 3-ph

AR in Progress

CB Open

Dead Time

Auto -close

Reclaim Time

Successful Autoreclose

Autoreclose Lockout

V03397

Figure 165: Autoreclose sequence for an evolving or permanent fault - single-phase operation

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4 AUTORECLOSE SYSTEM MAP

The Autoreclose System Map describes the System Design of the Autoreclose Logic implemented in this product.
The Autoreclose is implemented in logical software modules. The logical software modules interact by exchanging
signals between themselves, and with other software processes in the product. Interchange between modules is
limited to digital signals which are realised as either DDB signals or so called “internal signals” (IntSigs). DDB signals
are available for mapping in the PSL. Internal signals are similar to DDBs but they are self-contained within the
device's functions and are not user-accessible.
The Autoreclose System Map shows the interconnection of the logic modules that are used in the Autoreclose
system.
The logic diagrams follow a convention for the elements used, using defined colours and shapes. A key to this
convention is provided below. We recommend viewing the logic diagrams in colour rather than in black and white.
The electronic version of the technical manual is in colour, but the printed version is not. However, coloured
diagrams can be provided on request.

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Key:
Energising Quantity AND gate &

Internal Signal OR gate 1

DDB Signal XOR gate XOR

Internal function NOT gate

Setting cell Logic 0 0

Setting value Timer

Hardcoded setting
Pulse / Latch

Measurement Cell S
SR Latch Q
R
Internal Calculation
S
SR Latch Q
Derived setting Reset Dominant RD

HMI key Latched on positive edge

Connection / Node Inverted logic input

1
Switch Soft switch 2

Switch Multiplier X

Bandpass filter
Comparator for detecting
undervalues

Comparator for detecting

V00063 overvalues

Figure 166: Key to logic diagrams

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4.1 AUTORECLOSE SYSTEM MAP DIAGRAMS

CB Status Time CB Closed 3 ph Protection function 1 Trip Prot AR Block
CB Status Input CB Open 3 ph Protection function n Trip INIT AR

CB Aux 3ph(52-A) CB Closed A ph

IA< Start
CB Aux 3ph(52-B) CB Open A ph
IB< Start
CB Closed B ph Module 11
CB Aux A(52-A) Module 1 IC< Start AR Initiation
CB Aux A(52-B) CB State Monitor CB Open B ph
AR Trip Test A
CB Aux B(52-A) CB Closed C ph
AR Trip Test B
CB Aux B(52-B) CB Open C ph
AR Trip Test C
CB Aux C(52-A) CB Status Alarm
Any Trip
CB Aux C(52-B)
Test Autoreclose AR Trip Test A (577)
CB Open Aph CB1Op1P AR Trip Test B (578)
Init APh AR Test
CB Open Bph Module 3 CB1OpAny Module 12 AR Trip Test C (579)
Init BPh AR Test Trip Test
CB Open Cph CB Open CB1Op2/3P
Init CPh AR Test AR Trip Test 3Ph (576)
CB Open 3ph
Init 3P AR Test
A/R Lockout CB In Service
Module 4 Trip Output A Trip AR MemA (1535)
CB Closed 3 ph CB1 CRLO
CB In Service External Trip A Trip AR MemB (1536)
CB ARIP
Trip Output B Trip AR MemC (1537)
Auto-Reclose AR In Service External Trip B TAR2/3PH
HMI Command AR DISABLED Trip Output C TARANY
External Trip C TARA
IEC 60870 Command
Module 5 External Trip3ph Module 13 TARB
AR On Pulse AR Enable ARIP 1-pole / 3-pole Trip TARC
AR OFF Pulse Trip AR MemA RESPRMEM
AR Enable Trip AR MemB TMEMANY
AR Enable CB Trip AR MemC TMEM1Ph
AR In Service CB NoAR Init AR TMEM2/3Ph
AR Enable CB CB1 AR OK AR Disabled TMEM3Ph
CB In Service Module 8 TARANY
AR OK
A/R Lockout
Trip Inputs A FLTMEM 2P
BAR CB1 Ext Fault Aph FLTMEM 3P

AR Mode CB1 LSPAROK Trip Inputs B

CB1L3 PAROK Ext Fault BPh Module 15

AR In Service
Trip Inputs C Fault Memory
AR Enable CB
Module 9 Ext Fault CPh
AR Mode 1P AR Modes Enable AR Start
AR Mode 3P
Seq Counter = 0 RESPRMEM

Seq Counter = 1

CB ARIP AR Force 3 pole

Seq Counter = 1
CB1 SPOK
Seq Counter = 2
Seq Counter = 3
Seq Counter = 4
A/R Lockout Module 10
Force 3-phase Trip
A/R CB Unhealthy
Inhibit AR

CB1 L SPAROK
AR DISABLED
TARANY
V03392-1

Figure 167: Autoreclose System Map - part 1

304 P54x1i-TM-EN-1
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External Trip A AR Start Evolve 3Ph CB1L3PAR

External Trip B AR Initiation CB1LARIP AR 3pole in prog
External Trip C CB ARIP CB1L3PAROK
External Trip3ph ARIP Module 21
TMEM3P 3-phase AR cycle selection
Inhibit AR CB1LARIP CB1OP2/3P
Lockout Alarm TMemAny
CB NoAR CB1LSPAROK
CB1 ARIP
AR Start DT Start by Prot DTOK All

Set CB Close 3PDTStart WhenLD DTOK CB 1P

Module 16
CB Closed 3 ph AR In Progress DTStart by CB Op DTOK CB 3P
AR 1pole in prog DeadLineLockout
InitAR
AR Start
TMEM2/3Ph
OK Time 3P Module 22
TMEM1Ph
ARIP Dead Time Start Enable
CB1OP2/3P
AR Initiation
CB1L3PAROK
Dead Line
CB1ARSucc
CB Open 3 ph
CBARCancel
CB1OPAny OKTimeSP

CB1AROK CB1OP1P

Single Pole Shot Seq Counter = 0 DT Start by Prot 1P DTime

Three Pole Shot Seq Counter = 1 1 Pole Dead Time OKTimeSP

AR Initiation Seq Counter = 2 DTOK CB 1P CB1SPDTComp

ARIP Seq Counter = 3 Seq Counter = 1 Module 24

Seq Counter = 4 DTOK All 1-phase AR Dead Time
AR Start Module 18
1P Dtime Sequence Counter Seq Counter > 4 AR Start

Seq Counter = 1 Seq Counter >Set CB1LSPAR

ProtRe_Op SCCountoveqShots CB1OP2/3P

SCIncrement
DT Start by Prot OK Time 3P
LastShot
3P AR DT Shot 1 3P DTime1
CB1LARIP AR 1pole in prog 3P AR DT Shot 2 3P DTime2
CB1LSPAROK Module 19 3P AR DT Shot 3 3P DTime3
1-phase AR Cycle CB1LSPAR
TMEM1PH Selection 3P AR DT Shot 4 3P DTime4
CB1L3PAR DTOK CB 3P 3P Dead Time IP
DTOK All 3P Dtime
Discrim Time Evolve 3Ph
Module 25 & 26
CB Failed AR AR Start 3PDTCOMP
1P Dtime 3-phase AR Dead Time
Seq Counter = 1 CB13PDTComp
Seq Counter = 1 ProtRe_Op
Seq Counter = 2
A/R Lockout EvolveLock
Seq Counter = 3
CB Closed 3 ph
Module 20 Seq Counter = 4
CB ARIP
Evolving Fault
CB1L3PAR
TMemAny
3PDTComp
TARAny
CB1L3PAR
ProtRe_Op
LastShot
SetCB1Cl

V03392-2

Figure 168: Autoreclose System Map - part 2

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Any Trip Set CB Close Res AROK by UI RESCB1 ARSUCC

A/R Lockout Auto Close Reset AROK Ind
CB Healthy CB Control Res AROK by NoAR
CB Open 3 ph Res AROK by Ext
CB SCOK Res AROK by Tdly
CB Fast SCOK AROK Reset Time Module 37
AR Reset Successful
OK Time 3P Ext Rst AROK
ARIP Module 32
CB Autoclose AR Start
CB ARIP CB1 OPANY
CB Closed 3ph AR DISABLED
CB1SPDTCOMP CB1 ARSUCC
CB1OP1P
CB Healthy Time AR CB Unhealthy
CB1L3PAR
Check Sync Time A/R No Checksync
CB13PDTCOMP
PROTREOP OK Time 3P
CB Fast SCOK
Set CB Close SETCB1SPCL CB Healthy
CB SCOK SETCB13PCL A/ R Lockout Module 39
CB Fast SCOK CB Healthy and System
Module 34 CB Closed 3Ph Check Timers
OK Time 3P Prepare Reclaim Initiation CB SCOK
CB1SPDTCOMP CB1L3PAR
CB13PDTCOMP CB1SPDTCOMP

SPAR ReclaimTime 1P Reclaim TComp CB13PDTCOMP

3PAR ReclaimTime 1P Reclaim Time CB13PDTCOMP

Close Pulse Time 3P Reclaim TComp Reset CB Shots CB Total Shots Counter
Auto Close 3P Reclaim Time
Set CB Close CB Successful SPAR Shot 1
1P Reclaim Time CBARCancel CB Succ 1P AR Counter
3P Reclaim Time CB Successful 3PAR
CB Succ 3P AR
Module 35 Shot 1 Counter
CB Closed 3 ph Seq Counter = 1
Reclaim Time CB Successful 3PAR
CB ARIP Module 41 Shot 2 Counter
Seq Counter = 2 AR Shot Counters
CB Successful 3PAR
SETCB1SPCL Seq Counter = 3 Shot 3 Counter
CB1LARIP Seq Counter = 4 CB Successful 3PAR
SETCB13PCL CB Arip Shot 4 Counter

CB1LARIP A/ R Lockout CB Failed Counter

Prot Re-op Ext Rst CB Shots

3P Reclaim TComp CB Succ 1P AR

1P Reclaim TComp CB Succ 3P AR
CB Closed 3Ph CB1ARSUCC
SETCB1SPCL Module 36
CB1OP1P Successful AR Signals

RESCB1ARSUCC
SETCB13PCL
CB1OP2/3P

V03392-3

Figure 169: Autoreclose System Map - part 3

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CB Control by Control Trip CBM SC CS1 CB Man SCOK

Trip Pulse Time CB Trip Fail CBM SC CS2
Man Close Delay Close in Prog CBM SC DLLB
Close Pulse Time Control Close CBM SC LLDB
CB Healthy Time CB Close Fail CBM SC DLDB
Check Sync Time Man CB Unhealthy CBM SC required

HMI Trip No C/S Man Close Check Sync 1 OK Module 51

HMI Close Check Sync 2 OK CB Manual Close System
Check
Init Trip CB Dead Line

Init close CB Live Bus

CB ARIP Live Line

Auto Close Dead Bus

Reset Close Dly Dead Line

Any Trip Dead Bus

Module 43
Control Trip Ext CS OK
CB Control
External Trip3Ph Trip Pulse Time CB Fail Pr Trip
External Trip A
CB Open 3Ph
External Trip B
CB Closed 3Ph
External Trip C
CB Open 3 ph TAR2/3Ph
Module 53
CB Open A ph TARA CB Trip Time Monitor
CB Open B ph TMEM2/3Ph

CB Open C ph TARB

CB Closed 3 ph TMEM2/3Ph

CB Closed A ph TARC

CB Closed B ph Multi Phase AR A /R Lockout

CB Closed C ph
AR In Service BARCB1
CB Healthy
CB Close Fail
CB Man SCOK
CB Fail Pr Trip
CB SC ClsNoDly CB Fast SCOK CB ARIP
CB SC CS1 CB SCOK Block CB AR
CB SC CS2 A/R CB Unhealthy
CB SC DLLB A/R No Checksync
CB SC LLDB Evolve 3Ph
CB SC DLDB CB In Service
CB SC Shot 1 Seq Counter >Set
CB SC all Module 45 CB1 Status Alm
Module 55
Check Sync 1 OK 3 Phase AR System Check RESCB1LO Autoreclose Lockout
Check Sync 2 OK FLTMEM3P
Dead Line FLTMEM2P
Live Bus CB1OpAny
Live Line PROTRE-OP
Dead Bus LastShot
Seq Counter = 1 EVOLVELOCK
Ext CS OK ProtARBlock
TMEM2/3Ph
CB1L3 PAROK
TMEM1Ph
CB1 LSPAROK
DeadLineLockout

V03392-4

Figure 170: Autoreclose System Map - part 4

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Res LO by CB IS RESCB1LO A/R Lockout Pole Discrepancy

Res LO by UI Lockout Alarm
Reset CB LO Pole Discrepancy
Module 62
Res LO by NoAR AR 1pole in prog
Pole Discrepancy
Num CBs CB Open A ph
Res LO by ExtDDB CB Open B ph
Module 57
Res LO by Tdelay Reset CB Lockout CB Open C ph
LO Reset Time
Tripping Mode Trip OutputA
Reset Lockout Trip OutputB
Trip Inputs A
A/R Lockout Trip OutputC
Trip Inputs B
CB1CRLO Trip Inputs C Trip 3ph
AR Disabled AR Force 3 pole Module 63 Any Trip

Force 3Pole Trip CB Trip Conversion 2/3 Ph Fault

System Checks Live Line
Trip Inputs 3Ph 3 Ph Fault
VAN Dead line
VBN Live Bus Pole Dead A
VCN Pole Dead B
Dead Bus
VAB
Pole Dead C
VBC
VCA Module 59
VBus System Checks Voltage
MCB/VTS Monitor
MCB/VTS CB1 CS
Inhibit LL
Inhibit DL
Inhibit LB 1
Inhibit DB 1

System Checks SysChks Inactive

CS1 Status CS1 SlipF>
CS2 Status CS1 SlipF<
VAN CS2 SlipF>
VBN CS2 SlipF<
VCN
CS VLine>
VAB
VBC CS VBus>
VCA CS VLine<
VBus CS VBus<
MCB/VTS CS1 VL>VB
MCB/VTS CB1 CS CS1 VL<VB
VTS Fast Block CS1 FL>FB
F out of Range Module 60
CS1 FL<FB
Check Sync Signals
CS1 Enabled CS1 AngHigh+
CS2 Enabled CS1 AngHigh-
CS2 FL>FB
CS2 FL<FB
CS2 AngHigh+
CS2 AngHigh-
CS AngRotACW
CS AngRotCW
CS2 VL>VB
CS2 VL<VB
Check Sync 1 OK
Check Sync 2 OK

V03392-5

Figure 171: Autoreclose System Map - part 5

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4.2 AUTORECLOSE INTERNAL SIGNALS

The following table lists all the internal signals used in the CB control and Autoreclose logic system:
Signal Name Source Module Destination Module Description
3PDTCOMP 3-phase AR Dead Time (25) 3-phase AR Dead Time (25) Three phase dead time complete
Force 3-phase Trip (10)
1-pole / 3-pole Trip (13)
AR DISABLED AR Enabled (5) Overall Autoreclosing disabled
AR Reset Successful (37)
Reset CB Lockout (57)
BAR CB1 Autoreclose Lockout (55) AR OK (8) Block Autoreclose
CB Autoclose (32)
Prepare Reclaim Initiation (34)
CB1 3PDTCOMP 3-phase AR Dead Time (25) Three-pole Autoreclose dead time is complete
CB Healthy and System Check
Timers (39)
CB1 AROK AR OK (8) AR In Progress (16) CB is OK for Autoreclose
AR In Progress (16)
CB1 ARSUCC Successful AR Signals (36) Autoreclose successful
AR Reset Successful (37)
1-phase AR Cycle Selection (19)
CB1 LARIP AR In Progress (16) 3-phase AR Cycle Selection (21) CB Autoreclose in progress
Reclaim Time (35)
Dead Time Start Enable (22)
CB1 Op1P CB Open (3) CB Autoclose (32) CB is open on 1 phase
Successful AR Signals (36)
AR In Progress (16)
3-phase AR Cycle Selection (21)
CB1 Op2/3P CB Open (3) CB is open on 2 or 3 phases
1-phase AR Dead Time (24)
Successful AR Signals (36)
AR In Progress (16)
CB1 OpAny CB Open (3) AR Reset Successful (37) CB is open on 1, 2 or 3 phases
Autoreclose Lockout (55)
CB1 SPOK Force 3-phase Trip (10) CB is OK for single-phase Autoreclose
CB1CRLO CB In Service (4) Reset CB Lockout (57) Reset CB lockout
1-phase AR Cycle Selection (19)
3-phase AR Cycle Selection
CB1L3PAR 3-phase AR Dead Time (25) Three-phase Autoreclose is active
(21)
CB Autoclose (32)
AR In Progress (16)
CB1L3PAROK AR Modes Enable (9) 3-phase AR Cycle Selection (21) CB is OK to perform three-phase Autoreclose
Autoreclose Lockout (55)
1-phase AR Dead Time (24)
1-phase AR Cycle Selection
CB1LSPAR CB Healthy and System Check Single-phase Autoreclose is in progress
(19)
Timers (39)
Force 3-phase Trip (10)
1-phase AR Cycle Selection (19)
CB1LSPAROK AR Modes Enable (9) CB is OK to perform single-phase Autoreclose
3-phase AR Cycle Selection (21)
Autoreclose Lockout (55)
CB Autoclose (32)
Prepare Reclaim Initiation (34)
CB1SPDTCOMP Dead Time Start Enable (22) CB single-phase dead time is complete
CB Healthy and System Check
Timers (39)
CBARCancel Reclaim Time (35) AR In Progress (16) Cancel CB Autoreclose

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Signal Name Source Module Destination Module Description

Signal to force the auto-reclose sequence to
DeadLineLockout Dead Time Start Enable (22) Autoreclose Lockout (55)
lockout
Lockout for 2nd trip after the "Discrim Time" has
EVOLVE LOCK Evolving Fault (20) Autoreclose Lockout (55)
expired
A signal to indicate that the initiating fault
FLTMEM 2P Fault Memory (15) Autoreclose Lockout (55)
involved 2 phases
A signal to indicate that the initiating fault
FLTMEM 3P Fault Memory (15) Autoreclose Lockout (55)
involved 3 phases
AR Initiation (11), 1-pole / 3-
Internally derived signal to initiate Autoreclose
INIT AR pole Trip (13), AR In Progress
(external triggers not included)
(16)
Evolving Fault (20) Idicates tha the Autoreclose sequence has
LastShot Sequence Counter (18)
Autoreclose Lockout (55) reached the last shot
OKTimeSP 1-phase AR Dead Time (24) Dead Time Start Enable (22) The dead time for single pole Autoreclose is OK
Signal to block Autoreclose for selected host
Prot AR Block AR Initiation (11) Autoreclose Lockout (55)
protection elements
Sequence Counter (18)
Evolving Fault (20)
Signal to indicate that further protection
Prot Re-op Evolving Fault (20) CB Autoclose (32)
operation has occurred during Autoreclose
Reclaim Time (35)
Autoreclose Lockout (55)
RESCB1ARSUCC AR Reset Successful (37) Successful AR Signals (36) Reset the indication of successful Autoreclose
RESCB1LO Reset CB Lockout (57) Autoreclose Lockout (55) Reset the indication of lockout
Reset the signal that indicates the faulted phases
RESPRMEM 1-pole / 3-pole Trip (13) Fault Memory (15)
that initiated the Autoreclose
Prepare Reclaim Initiation Reclaim Time (35)
SETCB13PCL Three-phase close command to CB
(34) Successful AR Signals (36)
Prepare Reclaim Initiation Reclaim Time (35)
SETCB1SPCL Single-phase close command to CB
(34) Successful AR Signals (36)
Set CB1 CL Evolving Fault (20) Set CB as closed
1-pole / 3-pole Trip (13) A 2-phase or 3-phase trip has initiated
TAR2/3Ph 1-pole / 3-pole Trip (13)
CB Trip Time Monitor (53) Autoreclose

1-pole / 3-pole trip (13)

TARA 1-pole / 3-pole Trip (13) An A-phase trip has initiated Autoreclose
CB Trip Time Monitor (53)

Force 3-phase Trip (10)

TARANY 1-pole / 3-pole Trip (13) 1-pole / 3-pole Trip (13) Any trip has initiated Autoreclose
Evolving Fault (20)

1-pole / 3-pole Trip (13)

TARB 1-pole / 3-pole Trip (13) A B-phase trip has initiated Autoreclose
CB Trip Time Monitor (53)

1-pole / 3-pole Trip (13)

TARC 1-pole / 3-pole Trip (13) A C-phase trip has initiated Autoreclose
CB Trip Time Monitor (53)

AR In Progress (16)
Signal to remember that Autoreclose was
TMEM1Ph 1-pole / 3-pole Trip (13) 1-phase AR Cycle Selection (19)
initiated by a single-phase fault
Autoreclose Lockout (55)
AR In Progress (16)
Signal to remember that Autoreclose was
TMEM2/3Ph 1-pole / 3-pole trip (13) CB Trip Time Monitor (53)
initiated by a 2-phase fault or a 3-phase fault
Autoreclose Lockout (55)

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Signal Name Source Module Destination Module Description

Signal to remember that Autoreclose was

TMEM3Ph 1-pole / 3-pole Trip (13) 3-phase AR Cycle Selection (21)
initiated by a 3-phase fault

Evolving Fault (20) Signal to remember that Autoreclose was

TMEMANY 1-pole / 3-pole Trip (13)
3-phase AR Cycle Selection (21) initiated by an AnyTrip

4.3 AUTORECLOSE DDB SIGNALS

The following table lists all the DDB signals used in the CB control and Autoreclose logic system:
DDB Signal DDB Signal
Source Module Destination Module
Name Number
Sequence Counter (18)
1P DTime 1554 1-phase AR Dead Time (24)
Evolving Fault (20)
1P Reclaim TComp 1568 Reclaim Time (35) Successful AR Signals
1P Reclaim Time 1567 Reclaim Time (35) Reclaim Time Logic
2/3 Ph Fault 527 CB Trip Conversion (63)
3 Ph Fault 528 CB Trip Conversion (63)
3P Dead Time IP 853 3-phase AR Dead Time (25)
3P Dtime 1560 3-phase AR Dead Time (25)
3P DTime1 1556 3-phase AR Dead Time (25)
3P DTime2 1557 3-phase AR Dead Time (25)
3P DTime3 1558 3-phase AR Dead Time (25)
3P DTime4 1559 3-phase AR Dead Time (25)
3P Reclaim TComp 1570 Reclaim Time (35) Successful AR Signals
3P Reclaim Time 1569 Reclaim Time (35) Reclaim Time Logic
Force 3-phase Trip
A/R CB Unhealthy 307 CB Healthy and System Check Timers (39)
Autoreclose Lockout
CB In Service
AR OK
Force 3-phase Trip
Evolving Fault
A/R Lockout 306 Autoreclose Lockout (55) CB Autoclose Logic
CB Healthy and System Check Timers Logic
AR Shot Counters
Reset CB Lockout
Pole Discrepancy
A/R No Checksync 308 CB Healthy and System Check Timers (39) Autoreclose Lockout
AR Initiation
Any Trip 522 CB Trip Conversion (63) CB Autoclose Logic
CB Control
1-phase AR Cycle Selection
AR 1pole in prog 845 Dead Time Start Enable
Pole Discrepancy
AR 3pole in prog 844 3-phase AR Cycle Selection
AR Enable 1384 AR Enable
AR Enable
AR Enable CB 1609 AR OK
AR Modes Enable

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DDB Signal DDB Signal

Source Module Destination Module
Name Number
AR Force 3 pole 858 Force 3-phase Trip (10) CB Trip Conversion
AR OK
AR In Service 1385 AR Enable (5) AR Modes Enable
Autoreclose Lockout
Sequence Counter
AR Initiation 1543 AR In Progress (16)
Dead Time Start Enable
AR Mode 1P 1497 AR Modes Enable
AR Mode 3P 1498 AR Modes Enable
AR OFF Pulse 1383 AR Enable
AR On Pulse 1382 AR Enable
Fault Memory
AR In Progress
Sequence Counter
AR Start 1541 AR In Progress (16) Dead Time Start Enable
1-phase AR Dead Time
3-phase AR Dead Time Enable
AR Reset Successful Logic
AR Trip Test 3ph 576 Trip Test (12)
AR Trip Test A 577 Trip Test (12) AR Initiation
AR Trip Test B 578 Trip Test (12) AR Initiation
AR Trip Test C 579 Trip Test (12) AR Initiation
1-pole / 3-pole trip
Sequence Counter
ARIP 1542 AR In Progress (16)
Dead Time Start Enable
CB Autoclose Logic
Reclaim Time
Auto Close 854 CB Autoclose (32)
CB Control
Block CB AR 448 Autoreclose Lockout
CB In Service
Force 3-phase Trip
Evolving Fault
CB Autoclose
CB ARIP 1544 AR In Progress (16) AR In Progress
Reclaim Time
AR Shot Counters
CB Control
Autoreclose Lockout
CB Aux 3ph(52-A) 420 CB State Monitor
CB Aux 3ph(52-B) 424 CB State Monitor
CB Aux A(52-A) 421 CB State Monitor
CB Aux A(52-B) 425 CB State Monitor
CB Aux B(52-A) 422 CB State Monitor
CB Aux B(52-B) 426 CB State Monitor
CB Aux C(52-A) 423 CB State Monitor
CB Aux C(52-B) 427 CB State Monitor
CB Close Fail 303 CB Control (43) Autoreclose Lockout

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DDB Signal DDB Signal

Source Module Destination Module
Name Number
CB In Service
CB Autoclose
AR In Progress
Evolving Fault
CB Closed 3 ph 907 CB State Monitor (1) Reclaim Time
Successful AR Signals
CB Healthy and System Check Timers
CB Control
CB Trip Time Monitor
CB Closed A ph 908 CB State Monitor (1) CB Control
CB Closed B ph 909 CB State Monitor (1) CB Control
CB Closed C ph 910 CB State Monitor (1) CB Control
CB Control 1566 CB Autoclose (32)
CB Fail Pr Trip 1575 CB Trip Time Monitor (53) Autoreclose Lockout
CB Failed AR 1550 Evolving Fault (20)
CB Autoclose
CB Fast SCOK 1572 3 Phase AR System Check (45) Prepare Reclaim Initiation
CB Healthy and System Check Timers
CB Autoclose
CB Healthy 436 CB Healthy and System Check Timers
CB Control
AR OK
CB In Service 1526 CB In Service (4)
Autoreclose Lockout
3 Phase AR System Check (45)
CB Man SCOK 1574 CB Control
CB Manual Close System Check (51)
CB NoAR 1528 AR OK (8) AR In Progress
CB Open
Dead Time Start Enable
CB Open 3 ph 903 CB State Monitor (1) CB Autoclose Logic
CB Control
CB Trip Time Monitor
CB Open
CB Open A ph 904 CB State Monitor (1) CB Control
Pole Discrepancy
CB Open
CB Open B ph 905 CB State Monitor (1) CB Control
Pole Discrepancy
CB Open
CB Open C ph 906 CB State Monitor (1) CB Control
Pole Discrepancy
CB Autoclose
CB SCOK 1573 3 Phase AR System Check (45) Prepare Reclaim Initiation Logic
CB Healthy and System Check Timers
CB Status Alarm 301 CB State Monitor (1)
CB Succ 1P AR 1571 Successful AR Signals (36) AR Shot Counters
CB Succ 3P AR 852 Successful AR Signals (36) AR Shot Counters
CB Trip Fail 302 CB Control (43)
3 Phase AR System Check
Check Sync 1 OK 883 Check Sync Signals (60)
CB Manual Close System Check

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DDB Signal DDB Signal

Source Module Destination Module
Name Number
3 Phase AR System Check
Check Sync 2 OK 884 Check Sync Signals (60)
CB Manual Close System Check
Close in Prog 842 CB Control (43)
Control Close 839 CB Control (43)
Control Trip 838 CB Control (43) CB Control
CS AngRotACW 1594 Check Sync Signals (60)
CS AngRotCW 1595 Check Sync Signals (60)
CS1 SlipF> 1578 Check Sync Signals (60)
CS1 SlipF< 1579 Check Sync Signals (60)
CS VBus< 1583 Check Sync Signals (60)
CS VBus> 1582 Check Sync Signals (60)
CS VLine< 1580 Check Sync Signals (60)
CS VLine> 1581 Check Sync Signals (60)
CS1 AngHigh- 1593 Check Sync Signals (60)
CS1 AngHigh+ 1592 Check Sync Signals (60)
CS1 FL<FB 1591 Check Sync Signals (60)
CS1 FL>FB 1590 Check Sync Signals (60)
CS1 VL<VB 1588 Check Sync Signals (60)
CS1 VL>VB 1586 Check Sync Signals (60)
CS2 AngHigh- 1496 Check Sync Signals (60)
CS2 AngHigh+ 1495 Check Sync Signals (60)
CS2 FL<FB 1494 Check Sync Signals (60)
CS2 FL>FB 1493 Check Sync Signals (60)
CS2 SlipF< 1465 Check Sync Signals (60)
CS2 VL<VB 1589 Check Sync Signals (60)
CS2 VL>VB 1587 Check Sync Signals (60)
3 Phase AR System Check
Dead Bus 887 System Checks Voltage Monitor (59)
CB Manual Close System Check
Dead Time Start Enable
Dead Line 889 System Checks Voltage Monitor (59) 3 Phase AR System Check
CB Manual Close System Check
1-phase AR Dead Time
DTOK All 1551 Dead Time Start Enable (22)
3-phase AR Dead Time Enable
DTOK CB 1P 1552 Dead Time Start Enable (22) 1-phase AR Dead Time
DTOK CB 3P 1553 Dead Time Start Enable (22) 3-phase AR Dead Time Enable
3-phase AR cycle selection
Evolve 3Ph 1547 Evolving Fault (20)
Autoreclose Lockout
3 Phase AR System Check
Ext CS OK 900
CB Manual Close System Check
Ext Fault Aph 1508 Fault Memory
Ext Fault BPh 1509 Fault Memory
Ext Fault CPh 1510 Fault Memory
Ext Rst AROK 1517 AR Reset Successful Logic
Ext Rst CB Shots 1518 AR Shot Counters

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DDB Signal DDB Signal

Source Module Destination Module
Name Number
External Trip A 535 1-pole / 3-pole trip, AR In Progress, CB Control
External Trip B 536 1-pole / 3-pole trip, AR In Progress, CB Control
External Trip C 537 1-pole / 3-pole trip, AR In Progress, CB Control
External Trip3ph 534 1-pole / 3-pole trip, AR In Progress, CB Control
F out of Range 319 Check Sync Signals
Force 3Pole Trip 533 CB Trip Conversion
IA< Start 864 AR Initiation
IB< Start 865 AR Initiation
IC< Start 866 AR Initiation
Inhibit AR 1420 AR In Progress, Force 3-phase Trip
Inhibit DB 1525 System Checks Voltage Monitor
Inhibit DL 1523 System Checks Voltage Monitor
Inhibit LB 1524 System Checks Voltage Monitor
Inhibit LL 1522 System Checks Voltage Monitor
Init 3P AR Test 1507 Trip Test
Init APh AR Test 1504 Trip Test
Init BPh AR Test 1505 Trip Test
Init Close CB 440 CB Control
Init CPh AR Test 1506 Trip Test
Init Trip CB 439 CB Control
3 Phase AR System Check
Live Bus 886 System Checks Voltage Monitor (59)
CB Manual Close System Check
3 Phase AR System Check
Live Line 888 System Checks Voltage Monitor (59)
CB Manual Close System Check
AR In Progress
Lockout Alarm 860
Pole Discrepancy
Man CB Unhealthy 304 CB Control (43)
MCB/VTS 438 System Checks Voltage Monitor
MCB/VTS CB CS 1521 System Checks Voltage Monitor
No C/S Man Close 305 CB Control (43)
Dead Time Start Enable
3-phase AR Dead Time
OK Time 3P 1555 3-phase AR Dead Time (25) CB Autoclose
Prepare Reclaim Initiation
CB Healthy and System Check Timers
Pole Dead A 892 CB Trip Conversion
Pole Dead B 893 CB Trip Conversion
Pole Dead C 894 CB Trip Conversion
Pole Discrepancy 699 Pole Discrepancy (62) Pole Discrepancy
Reset Close Dly 443 CB Control
Reset Lockout 446 Reset CB Lockout
Seq Counter = 0 846 Sequence Counter (18) AR Modes Enable

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DDB Signal DDB Signal

Source Module Destination Module
Name Number
AR Modes Enable
Force 3-phase Trip
Sequence Counter
Evolving Fault
Seq Counter = 1 847 Sequence Counter (18)
1-phase AR Dead Time
3-phase AR Dead Time Logic
AR Shot Counters
3 Phase AR System Check
Force 3-phase Trip
Seq Counter = 2 848 Sequence Counter (18) 3-phase AR Dead Time Logic
AR Shot Counters
Force 3-phase Trip
Seq Counter = 3 849 Sequence Counter (18) 3-phase AR Dead Time Logic
AR Shot Counters
Force 3-phase Trip
Seq Counter = 4 850 Sequence Counter (18) 3-phase AR Dead Time Logic
AR Shot Counters
Seq Counter > 4 851 Sequence Counter (18)
Force 3-phase Trip
Seq Counter>Set 1546 Sequence Counter (18)
Autoreclose Lockout
AR In Progress
Set CB Close 1565 CB Autoclose (32) Prepare Reclaim Initiation
AR Shot Counters
SysChks Inactive 880 Check Sync Signals (60)
Trip 3ph 526 CB Trip Conversion (63)
Trip AR MemA 1535 1-pole / 3-pole Trip (13) 1-pole / 3-pole trip
Trip AR MemB 1536 1-pole / 3-pole Trip (13) 1-pole / 3-pole trip
Trip AR MemC 1537 1-pole / 3-pole Trip (13) 1-pole / 3-pole trip
Trip Inputs 3Ph 529 CB Trip Conversion
Fault Memory
Trip Inputs A 530
CB Trip Conversion
Fault Memory
Trip Inputs B 531
CB Trip Conversion
Fault Memory
Trip Inputs C 532
CB Trip Conversion
Trip Output A 523 CB Trip Conversion (63) 1-pole / 3-pole trip
Trip Output B 524 CB Trip Conversion (63) 1-pole / 3-pole trip
Trip Output C 525 CB Trip Conversion (63) 1-pole / 3-pole trip
VTS Fast Block 832 Check Sync Signals

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5 LOGIC MODULES
This section contains a complete set of logic diagrams, which will help to explain the Autoreclose function. Most of
the logic diagrams shown are logic modules that comprise the overall Autoreclose system. Some of the diagrams
shown are not directly related to Autoreclose functionality, however, they may use some inputs are produce
outputs that are used by the Autoreclose system. These diagrams are shown in this section for the sake of
completeness.

5.1 CIRCUIT BREAKER STATUS MONITOR

The Circuit Breaker State Monitor logic is part of the Monitoring and Control functionality and is fully described in
that chapter. The logic diagram is repeated in this section because some of the outputs of this logic module are
used as inputs to some of the Autoreclose logic modules.

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5.1.1 CB STATE MONITOR LOGIC DIAGRAM

CB Aux 3ph(52- A)
&

CB Aux 3ph(52- B)
& 1
1 CB Closed 3 ph
XOR

&

CB Status Input
&
52A 3 pole
52B 3 pole
52A & 52B 3 pole & 1
1 CB Open 3 ph

&

&

CB Aux A(52-A)
&

CB Aux A(52-B) 1 CB Closed A ph

& 1
XOR
&
&

CB Status Input
&
52A 1 pole
52B 1 pole
1 CB Open A ph
52A & 52B 1 pole & 1

&
&

&

CB Aux B(52-A) 1 CB Closed B ph

CB Aux B(52-B)

Phase B 1 CB Open B ph
CB Status Input
(Same logic as phase A )
52A 1 pole
52B 1 pole
52A & 52B 1 pole

CB Aux C(52- A) 1 CB Closed C ph

CB Aux C(52- B)

Phase C 1 CB Open C ph
CB Status Input
(Same logic as phase A )
52A 1 pole
52B 1 pole
1 CB Status Alm
52A & 52B 1 pole

V01264 CB Status Time

Figure 172: CB State Monitor logic diagram (Module 1)

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5.2 CIRCUIT BREAKER OPEN LOGIC

The Circuit Breaker Open logic module produces internal signals indicating the open status of one or more phases.
These signals are used by some of the Autoreclose logic modules.

5.2.1 CIRCUIT BREAKER OPEN LOGIC DIAGRAM

CB Open A ph

CB Open B ph 1 CB1Op1P

CB Open C ph

1 CB1OpAny
CB Open 3 ph

1 CB1 Op2/3P
³2

V03389

Figure 173: Circuit Breaker Open logic diagram (Module 3)

5.3 CIRCUIT BREAKER IN SERVICE LOGIC

For Autoreclose to proceed, a circuit breaker has to be in service when the Autoreclose is initiated. A circuit breaker
is considered to be in service if it has been closed for more than the CB IS Time setting.
For applications with fast-acting circuit breaker auxiliary switches, a time delay setting CB IS Memory Time is
provided. This is used to ensure correct operation if a delay between the circuit breaker tripping and recognition by
the protection, is expected.
When an Autoreclose cycle starts, the “in service” signal for a circuit breaker stays set until the Autoreclose cycle
finishes.
The circuit breaker “in service” signal resets if the circuit breaker opens, or if the corresponding Autoreclose in
progress (ARIP) signal resets.

5.3.1 CIRCUIT BREAKER IN SERVICE LOGIC DIAGRAM

A/R Lockout CBIST

& CB1CRLO
0

CBIST
CB Closed 3 ph
CBISMT & S
Q CB In Service
R
Logic 1 1
CB ARIP

V03302

Figure 174: CB In Service logic diagram (Module 4)

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5.3.2 AUTORECLOSE OK LOGIC DIAGRAM

AR In Service
& CB NoAR
AR Enable CB

CB In Service
CB1 AR OK
A/R Lockout

BAR CB1

V03308

Figure 175: Autoreclose OK logic diagram (Module 8)

5.4 AUTORECLOSE ENABLE

The Autoreclose function must be enabled in the CONFIGURATION column before it can be brought into service. It
can be brought into service by:
● using an opto-input mapped to the AR Enable DDB signal
● pulsing the DDB signal AR Pulse On (use AR Pulse Off to bring it out of service)
● programming a function key on the HMI.
● if applicable, using IEC 60870-5-103 communications
A further validation signal is also required to switch on Autoreclose. This is the DDB signals AR Enable CB. Once
Autoreclose is in service, the AR In Service DDB signal is asserted and the AR Status cell in the CB CONTROL
column is set accordingly.

5.4.1 AUTORECLOSE ENABLE LOGIC DIAGRAM

Auto-Reclose
Enabled
& AR DISABLED
HMI Command

IEC 60870 Command Autoreclose AR In Service

Status
Default = ON 1
AR On Pulse

AR OFF Pulse

AR Enable

AR Enable CB *
*Defaults to High if not mapped in PSL
V03300

Figure 176: Autoreclose Enable logic diagram (Module 5)

5.5 AUTORECLOSE MODES

The device can provide Single-phase and/or Three-phase Autoreclose. The Autoreclose mode is configured by the
AR Mode setting in the AUTORECLOSE column. You can choose from:
● Single-phase (AR 1P)
● Three-phase (AR 3P)
● Single-phase and Three-phase (AR 1/3P)
● Controlled by commands from DDB signals that must be mapped to opto-isolated inputs in the PSL (AR
Opto).

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Single-phase Autoreclosing is permitted only for the first shot of an Autoreclose cycle. In a multi-shot Autoreclose
cycle the second and subsequent trips will always be three-phase.
For multi-phase faults, you can use the Multi Phase AR setting in the AUTORECLOSE column to configure the
following options:
● Allow Autoreclose for all fault types (Allow Autoclose)
● Block Autoreclose for 2-phase and 3-phase faults (BAR 2 and 3 ph)
● Block Autoreclose for 3-phase faults (BAR 3 Phase)

5.5.1 SINGLE-PHASE AND THREE-PHASE AUTORECLOSE

Single-phase Autoreclose Only

If single-phase Autoreclose is enabled, the logic allows only a single shot Autoreclose. For a single-phase fault, the
single phase dead timer SP AR Dead Time starts, and the DDB signal CB AR 1pole in prog is asserted, which
indicates that single-phase Autoreclose is in progress. In this case, for a multi-phase fault the logic triggers a
three-phase trip and goes to lockout.

Three-phase Autoreclose Only

During three-phase Autoreclose, for any fault, the three-phase dead timers: 3P AR DT Shot 1, 3P AR DT Shot 2, 3P
AR DT Shot 3 and 3P AR DT Shot 4 are started and the DDB signal CB AR 3pole in prog is asserted, which indicates
that three-phase Autoreclose is in progress.
If three-phase only Autoreclose is enabled, the logic forces a three-phase trip by setting the DDB signal AR Force 3
pole for any single-phase fault.

Single-phase and Three-phase Autoreclose

With single-phase and three-phase Autoreclose enabled then, if the first fault is a single-phase fault the single-
phase dead time SP AR Dead Time is started and the single-phase Autoreclose in progress signal is asserted. If the
first fault is a multi-phase fault the three phase dead timer 3P AR DT Shot 1 is started and the three-phase
Autoreclose in progress signal is asserted. If set to allow more than one reclose (AR Shots >’1’) then any
subsequent faults are converted to three-phase trips by setting the force three-pole tripping signal. The three-
phase dead times 3P AR DT Shot 2, 3P AR DT Shot 3 and 3P AR DT Shot 4 (Dead Times 2, 3, 4) are started for the
2nd, 3rd and 4th trips (shots) respectively. The DDB signal AR 3pole in prog is asserted. If a single-phase fault
evolves to a multi-phase fault during the single-phase dead time (SP AR Dead Time), single-phase Autoreclose is
stopped. The single-phase Autoreclose in progress signal is reset, the three-phase Autoreclose in progress signal is
set, and the three-phase dead timer 3P AR DT Shot 1 is started.

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5.5.2 AUTORECLOSE MODES ENABLE LOGIC DIAGRAM

AR In Service
&
AR Enable CB *

AR Mode
AR 1P
&
AR 1/3P 1 & CB1 LSPAROK
AR 3P
AR Opto
& CB1L3 PAROK
1
&
AR Mode 1P

&
AR Mode 3 P

Seq Counter = 0
1
Seq Counter = 1
* Defaults to High if not mapped in PSL
V03309

Figure 177: Autoreclose Modes Enable logic diagram (Module 9)

5.6 AR FORCE THREE-PHASE TRIP LOGIC

Following single-phase tripping, while the Autoreclose cycle is in progress, and upon resetting of the protection
elements, tripping switches to three-phase.
Any protection operations that occur for subsequent faults while the Autoreclose cycle remains in progress will be
tripped three-phase.

5.6.1 AR FORCE THREE-PHASE TRIP LOGIC DIAGRAM

CB1 L SPAROK CB1 L SPAROK

AR DISABLED

CB ARIP
&
TARANY

&
Seq Counter = 1
1 & AR Force 3 pole
Seq Counter = 2 & 1

Seq Counter = 3

Seq Counter = 4

AR Lockout

A/R CB Unhealthy

Inhibit AR

V03313

Figure 178: Force Three-phase Trip logic diagram (Module 10)

When a three-phase trip is forced, the DDB signal AR Force 3 pole is asserted.

5.7 AUTORECLOSE INITIATION LOGIC

Autoreclose initiation starts Autoreclose for a circuit breaker only if Autoreclose is enabled for the circuit breaker,
and the circuit breaker is in service. When an Autoreclose cycle is started, Autoreclose in progress (ARIP) is
indicated. The indication remains until the end of the cycle. The end of the cycle is signified by successful
Autoreclose, or by lockout.

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Autoreclose cycles can be initiated by:

● Protection functions internal to the product
● A Trip Test feature
● External protection equipment

● Evolving fault combinations

Internal Protection Functions

Many of the protection functions in the product can be programmed to initiate or block Autoreclose. The
associated settings are found in the Autoreclose column and the available options are No Action, Initiate
AR, or Block AR. If set to Block AR operation of the protection function blocks the Autoreclose function and
forces a lockout.

Trip Test Feature

The Test Autoreclose command cell in the COMMISSION TESTS column can be used to initiate an Autoreclose
cycle. Each option provides a 100 ms pulse output. There is also a ‘No Operation’ option to exit the command field
without initiating a test.

External Protection Equipment

Protection operation from a different device can be used to initiate Autoreclose via PSL. By default these external
trip input signals are mapped to initiate Autoreclose. These inputs are not mapped to the trip outputs. With
appropriate mapping in the PSL, however, the external device can use this product to trip connected circuit
breakers.

Evolving Fault Combinations

The Autoreclose function would normally be initiated by a single condition (such as a single-phase fault). If,
however, the system conditions evolve such that other conditions that could initiate Autoreclose, then the
dynamics of the Autoreclose logic need to adapt. For example, if a single-phase fault evolves into a multi-phase
fault, then the operation of the Autorecloser must consequently adapt. To achieve this signals are generated to
indicate conditions such as evolving faults, re-operation of protection, combinations of initiation by internal
protection, external protection, or test features, which control the Autoreclose sequencing.
Records of initiating conditions are stored and used to control the sequencing. Initiation can be from a protection
function integrated in the product, from external protection and internal sources such as the Autoreclose test
function. Initiation can be further qualified by the phases causing the initiation. These conditions are stored in
signals that generally feature “MEM”- memory, or “AR” – Autoreclose, in the signal name.

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5.7.1 AUTORECLOSE INITIATION LOGIC DIAGRAM

Protection function 1 Trip

Block AR
Initiate AR 1 Prot AR Block

Protection function n Trip

Block AR 1 S
Q
Initiate AR R 1 INIT AR

864
IA< Start &
1
865
IB< Start

866
IC< Start

577
AR Trip Test A
1
578 &
AR Trip Test B

579
AR Trip Test C

522
Any Trip

V03315

Figure 179: Autoreclose Initiation logic diagram (Module 11)

5.7.2 AUTORECLOSE TRIP TEST LOGIC DIAGRAM

1504
Init APh AR Test
1 577
1 AR Trip Test A

1505
Init BPh AR Test
1 578
1 AR Trip Test B

1506
Init CPh AR Test
1 579
1 AR Trip Test C

1507
Init 3P AR Test 576
1 AR Trip Test 3Ph

Test Autoreclose
No Operation
Trip Pole A
Trip Pole B
Trip Pole C
Trip 3 Pole

V03304

Figure 180: Autoreclose Trip Test logic diagram (Module 12)

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5.7.3 AR EXTERNAL TRIP INITIATION LOGIC DIAGRAM

≥
TAR2/ 3PH
2

1 TARANY
Init AR
&
Trip Output A 1 TARA

External Trip A S
Q Trip AR MemA
Init AR R
&
Trip Output B 1 TARB

External Trip B S
Q Trip AR MemB
Init AR R
&
Trip Output C 1 TARC

External Trip C S
Q Trip AR MemC
R
External Trip3ph
0.01
ARIP
0.1
&
1 RESPRMEM

1 0.2
AR Disabled & S
0 Q
R

1
TARANY

Trip AR MemA

Trip AR MemB 1 TMEMANY

Trip AR MemC

=
TMEM1Ph
1
≥
TMEM2 /3Ph
2

& TMEM3Ph
V03317

Figure 181: Autoreclose initiation by external trip or evolving conditions (Module 13)

Note:
The signals must be mapped as shown in the default PSL scheme.

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5.7.4 PROTECTION REOPERATION AND EVOLVING FAULT LOGIC DIAGRAM

TMEMANY 0
&
0.02 &
1 Prot ReOp

TARANY
&

Discrim Time
t
&
1P DTime 0
Prot ReOp & Evolve Lock

Seq Counter = 1
& Evolve 3Ph

0
LastShot & S
0.02 Q
R & CB Failed AR
A/ R Lockout

Set CB1 CL
0 1
CB Closed 3 ph &
0.02
CB ARIP

V03331

Figure 182: Protection Reoperation and Evolving Fault logic diagram (Module 20)

5.7.5 FAULT MEMORY LOGIC DIAGRAM

Trip Inputs A
1
Ext Fault APh & S
Q =
R FLTMEM 2P
Trip Inputs B 2
1
Ext Fault BPh & S
Q
R & FLTMEM 3P
Trip Inputs C
1
Ext Fault CPh & S
Q
R
AR Start

RESPRMEM

V03320

Figure 183: Fault Memory logic diagram (Module 15)

5.8 AUTORECLOSE IN PROGRESS

The AR In Progress module produces various signals to indicate to other modules and functions that an
Autoreclose operation is currently in progress.

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5.8.1 AUTORECLOSE IN PROGRESS LOGIC DIAGRAM

Init AR

External Trip A 1 AR Start

External Trip B

External Trip C

External Trip3 ph

TMEM2 /3Ph
1
TMEM1Ph &
& & AR Initiation
CB1 Op2/3P
S
CB1L3 PAROK Q CB ARIP
R
ARIP
Inhibit AR 1
CB1 LARIP
Lockout Alarm

CB NoAR

CB1 ARSUCC

CBARCancel
0.02
CB1 OpAny
0 &
CB ARIP 1

AR Start &
Set CB Close
&
CB Closed 3 ph

CB1 AR OK

V03321

Figure 184: Autoreclose In Progress logic diagram (Module 16)

5.9 SEQUENCE COUNTER

The Autoreclose logic includes a counter for counting the number of Autoreclose shots. This is referred to as the
sequence counter. The sequence counter has a value of zero if Autoreclose is not in progress. Following a trip, and
subsequent Autoreclose initiation, the sequence counter is incremented. The counter provides output signals
indicating how many initiation events have occurred in any Autoreclose cycle. These signals are available as user
indications and are used in the logic to select the appropriate dead times or, for a persistent fault, force a lockout.
It is possible to skip the first Autoreclose attempt by enabling the AR Skip Shot 1 setting. If this is set, the sequence
counter will skip the first Autoreclose attempt (Shot 1) and move to the second (Shot 2) immediately upon
Autoreclose initiation. Each time the protection trips the sequence counter is incremented by 1. The Autoreclose
logic compares the sequence counter value to the number of Autoreclose shots setting AR Shots. If the counter
value exceeds this setting then the Autoreclose is locked out. If Autoreclose is successful, the sequence counter
resets to zero.

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5.9.1 AUTORECLOSE SEQUENCE COUNTER LOGIC DIAGRAM

AR Initiation
&
1
ARIP &

AR Start
&

1P Dtime
&
Seq Counter = 1
Sequence Counter Seq Counter = 0

Increment on rising edge Seq Counter = 1

Reset on falling edge Seq Counter = 2

Single Pole Shot Seq Counter = 3

Three Pole Shot Seq Counter = 4

Seq Counter > 4

Seq Counter >Set

& S
Prot Re-op Q LastShot
R
V03326

Figure 185: Autoreclose Sequence Counter logic diagram (Module 18)

5.10 AUTORECLOSE CYCLE SELECTION

The Autoreclose cycle selection logic is responsible for determining whether the Autoreclose will start as single-
phase or three-phase.

5.10.1 SINGLE-PHASE AUTORECLOSE CYCLE SELECTION LOGIC DIAGRAM

CB1 L ARIP
& S
CB1 L SPAROK Q AR 1 pole in prog
R
TMEM1PH CB1 L SPAR
CB1 L ARIP
1
CB1 L 3 PAR

V03329

Figure 186: Single-phase Autoreclose Cycle Selection logic diagram (Module 19)

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5.10.2 3-PHASE AUTORECLOSE CYCLE SELECTION

CB1 L ARIP
&
S
CB1 L3 PAROK Q CB1L 3PAR
R
Evolve 3Ph
1 AR 3pole in prog
TMEM3P

CB1 OP2 /3P

TMEM ANY
&
CB1 L SPAROK

V03334

Figure 187: Three-phase Autoreclose Cycle Selection logic diagram (Module 21)

5.11 DEAD TIME CONTROL

Once an Autoreclose cycle has started, the conditions to enable the dead time to run are determined by the menu
settings, the circuit breaker status, the protection status, the nature of the AR cycle (single-phase or three-phase),
and the opto-isolated inputs from external sources.
Three settings are involved in controlling the dead time start:
● DT Start by Prot
● 3PDTStart WhenLD
● DTStart by CB Op

The DT Start by Prot determines how the protection action will initiate a dead time. The setting is always visible
and has three options Protection Reset, Protection Op (protection operation), and Disable which
should be selected if you don’t want protection action to start the dead time. These options set the basic
conditions for starting the dead time.
Selecting protection operation to start the dead time can, optionally, be qualified by a check that the line is dead.
Selecting protection reset to start the dead time can, optionally, be qualified by a check, that the circuit breaker is
open (DTStart by CB Op) before starting the dead time. For three-phase tripping applications, there is a further
option to check that the line is dead (3PDTStart WhenLD) before starting the dead time.
If DT Start by Prot is disabled, the circuit breaker must be open for the dead time to start. For three-phase tripping
applications, there is an option to check that the line is dead (3PDTStart WhenLD) before starting the dead time. To
check that the line is dead, set 3PDTStart WhenLD to enabled. To check that the circuit breaker is open, set
DTStart by CB Op to Enabled.

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5.11.1 DEAD TIME START ENABLE LOGIC DIAGRAM

DT Start by Prot
Disable
1
Protection Reset & DTOK All
&
Protection Op

AR Start
Dead Line Time
OKTimeSP &
S
Q
OK Time 3P 1 R
& S t
Q DeadLineLockout
ARIP R 0
0 1
AR Initiation
0.02
Dead Line
1
3 PDTStart WhenLD
&
Enabled
Disabled

DT Start by Prot
Protection Reset
1
Disable &
AR 1 pole in prog

&
DTStart by CB Op
Disabled
1
Enabled
1 DTOK CB 1P
&
CB1OP1P

1 DTOK CB 3P
&
CB Open 3 ph

V03337

Figure 188: Dead time Start Enable logic diagram (Module 22)

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5.11.2 1-PHASE DEAD TIME LOGIC DIAGRAM

CB1LSPAR
&
DTOK CB 1P & S
Q
R & OKTimeSP

Seq Counter = 1

DTOK All

AR Start
1

DT Start by Prot
&
Protection Reset

CB1LSPAR

CB1OP2/ 3P

Logic 1
&
CB1LSPAR 1

t
0
1 Pole Dead Time

CB1LSPAR & 1P DTime

& CB1SPDTCOMP
V03342

Figure 189: Single-phase Dead Time logic diagram (Module 24)

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5.11.3 3-PHASE DEAD TIME LOGIC DIAGRAM

CB1L 3PAR
&
DTOK CB1L 3P

DTOK All
& S
3PDTCOMP Q
R & OK Time 3P

DT Start by Prot
Protection Reset
&
1

AR Start
Logic 1
&
CB1L 3PAR

3P AR DT Shot 1

t 1 3PDTCOMP
&
Seq Counter = 1 0
& 3P DTime1

3P AR DT Shot 2

t
&
Seq Counter = 2 0
& 3P DTime2

3P AR DT Shot 3

t
&
Seq Counter = 3 0
& 3P DTime3

3P AR DT Shot 4

t
&
Seq Counter = 4 0
& 3P DTime4

1 3P Dead Time IP

3PDTCOMP

CB1L3PAR & 3P DTime

& CB13 PDTCOMP

V03340

Figure 190: Three-phase Dead Time logic diagram (Module 25)

5.12 CIRCUIT BREAKER AUTOCLOSE

Autoclose logic takes effect when dead times have expired.
The Autoclose logic checks that all necessary conditions are satisfied before issuing an Autoclose command to the
circuit breaker control scheme.
Before a circuit breaker can be closed, it must be healthy (sufficient energy to close, and if necessary re-trip) and it
must not be in a lockout condition.
For three-phase Autoreclose, the circuit breaker must be open on all three phases and the appropriate system
check conditions must be met. For single-phase Autoreclose, the circuit breaker must be open on that phase.
The Autoclose command is a pulse lasting 100 milliseconds. Another command (Set CB Close) to set the circuit
breaker to close is asserted as well as the Autoclose command. This signal will remain set either until the end of

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the Autoreclose cycle, or until the next protection operation. These commands are used to initiate the Reclaim
Time logic and the Autoreclose Shot Counter logic.

5.12.1 CIRCUIT BREAKER AUTOCLOSE LOGIC DIAGRAM

Any Trip

A/ R Lockout &
&
CB Healthy
Note: If the DDB signal CB1 Healthy is not mapped in PSL , it
CB1SPDTCOMP defaults to High.
CB1OP1P &
CB1L3PAR

CB Open 3 ph

CB13 PDTCOMP
&
CB SCOK 1
CB Fast SCOK
& 1
OK Time 3P

Set CB Close

A/ R Lockout & S
Logic 1 Q Auto Close
R
PROTREOP
0.1s
1
ARIP

CB ARIP
& CB Control
CB Closed 3 ph

V03349

Figure 191: Circuit Breaker Autoclose Logic Diagram (Module 32)

5.13 RECLAIM TIME

If the protection operates again before the reclaim time has expired, the corresponding sequence counter is
incremented. At the same time, any “dead time complete” (….DTCOMP) signals are reset and the logic is prepared
for the next dead time to start when conditions are suitable. The operation also resets the signal that would set the
circuit breaker to close, and stops and resets the reclaim timer. The reclaim time starts again if the signal to set a
circuit breaker to close goes high following completion of a dead time in a subsequent Autoreclose cycle.
If the circuit breaker is closed and has not tripped again when the reclaim time expires, signals are generated to
indicate successful Autoreclose. These signals increment the relevant circuit breaker successful Autoreclose shot
counters and reset the relevant Autoreclose in progress signal.
The “successful Autoreclose” signals generated from the logic can be reset by various commands and settings
options available under CB CONTROL menu settings as follows:
If Res AROK by UI is set to Enabled, all the signals can be reset by user interface command Reset AROK Ind from
the CB CONTROL menu.
If Res AROK by NoAR is set to Enabled, the signals for each circuit breaker can be reset by temporarily
generating an Autoreclose disabled signal according to the logic shown.
If Res AROK by Ext is set to Enabled, the signals can be reset by activation of an external input signal
appropriately mapped in the PSL.
If Res AROK by TDly is set to Enabled, the signals are automatically reset after a time delay set in AROK Reset
Time.

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5.13.1 PREPARE RECLAIM INITIATION LOGIC DIAGRAM

CB1SPDTCOMP
& S
Q SETCB1SPCL
Set CB Close R

CB13 PDTCOMP
&
CB SCOK
&
CB Fast SCOK 1 S
&
OK Time 3P Q SETCB13PCL
R
V03352

Figure 192: Prepare Reclaim Initiation Logic Diagram (Module 34)

5.13.2 RECLAIM TIME LOGIC DIAGRAM

SPAR ReclaimTime

SETCB1SPCL
& t
CB1 LARIP & 1P Reclaim TComp
Logic 1 0
Auto Close

& 1P Reclaim Time

3PAR ReclaimTime

SETCB13PCL
& t
CB1LARIP & 3P Reclaim TComp
Logic 1 0
Auto Close

Close Pulse Time & 3P Reclaim Time

1P Reclaim Time t
1
3P Reclaim Time 0
&
Prot Re-op & CBARCancel

CB Closed 3 ph
&
CB ARIP

V03355

Figure 193: Reclaim Time logic diagram (Module 35)

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5.13.3 SUCCESFUL AUTORECLOSE SIGNALS LOGIC DIAGRAM

3P Reclaim TComp
1
1P Reclaim TComp & S
Q CB Succ 1P AR
RD
SETCB1SPCL 0
&
CB1OP1P 0.02S
& S
CB Closed 3 Ph Q
R

RESCB1ARSUCC 1 CB1ARSUCC

3P Reclaim TComp
1
1P Reclaim TComp & S
Q CB Succ 3P AR
RD
SETCB13PCL 0
&
CB1OP2/ 3P 0.02S
& S
CB Closed 3 Ph Q
R

1
V03358

Figure 194: Successful Autoreclose Signals logic diagram (Module 36)

5.13.4 AUTORECLOSE RESET SUCCESSFUL INDICATION LOGIC DIAGRAM

CB1 OPANY
1
AR Start
1 RESCB1 ARSUCC
Res AROK by UI
Enabled
&
Reset AROK Ind
Yes

Res AROK by NoAR

Enabled
&
AR DISABLED

Ext Rst AROK

&
Res AROK by Ext
Enabled

Res AROK by TDly

Enabled
&
AROK Reset Time
t
CB1 ARSUCC
0
V03361

Figure 195: Autoreclose Reset Successful Indication logic diagram (Module 37)

5.14 CB HEALTHY AND SYSTEM CHECK TIMERS

This logic provides signals to cancel Autoreclose if the circuit breaker is not healthy (for example low gas pressure)
or system check conditions are not satisfied (for example required line & bus voltage conditions) when the scheme
is ready to close the circuit breaker.
At the completion of a dead time, the logic starts an Autoreclose healthy timer. If a circuit breaker healthy signal
becomes high before the Autoreclose healthy time is complete, the timer stops and, if all other relevant circuit
breaker closing conditions are satisfied, the scheme issues a circuit breaker Autoclose signal. If the circuit breaker

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healthy signal stays low, then, at the end of the Autoreclose healthy time, a circuit breaker unhealthy alarm is
raised. This forces the Autoreclose sequence to be cancelled.
Additionally, at the completion of any three-phase dead time, the logic starts an Autoreclose check synchronism
timer. If the circuit breaker synchronism-check OK signal goes high before the time is complete, the timer stops
and, if all other relevant circuit breaker closing conditions are satisfied, the scheme issues a circuit breaker
Autoclose signal. If the circuit breaker synchronism-check OK signal stays low, then when the Autoreclose check
synchronism timer expires, an alarm is set to inform that the check synchronism is not satisfied and cancels the
Autoreclose cycle.

5.14.1 CB HEALTHY AND SYSTEM CHECK TIMERS LOGIC DIAGRAM

CB Healthy Time

CB1L 3PAR
OK Time 3P 1
CB Fast SCOK

CB1SPDTCOMP 1
& S t
CB13PDTCOMP Q AR CB Unhealthy
RD 0

CB Healthy
A/ R Lockout 1
CB Closed 3 Ph

Check Sync Time

CB13PDTCOMP
1 S t
CB SCOK Q A/R No Checksync
RD 0

A/R Lockout
1
CB Closed 3 Ph

V03363

If the DDB signal CB 1 Healthy is not mapped in PSL , it defaults to High .

Figure 196: Circuit Breaker Healthy and System Check Timers Healthy logic diagram (Module 39)

5.15 AUTORECLOSE SHOT COUNTERS

A number of counters are provided to enable analysis of circuit breaker Autoreclose history. The counters are
stored in non-volatile memory, so that the data is maintained even in the event of a failure of the auxiliary supply.
The counter values are accessible through the CB CONTROL column. The counters can be reset manually, or by
activation of an input appropriately mapped in the PSL.
The logic provides the following summary information for each circuit breaker
● Overall total number of shots (Number of Autoreclose attempts)
● Number of successful 1st shot single-phase Autoreclose sequences
● Number of successful 1st shot three-phase Autoreclose sequences
● Number of successful 2nd shot three-phase Autoreclose sequences
● Number of successful 3rd shot three-phase Autoreclose sequences
● Number of successful 4th shot three-phase Autoreclose sequences
● Number of failed Autoreclose cycles which forced a circuit breaker to lockout

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5.15.1 AUTORECLOSE SHOT COUNTERS LOGIC DIAGRAM

Set CB Close Increment

CB Total Shots Counter
Reset

CB Succ 1P AR Increment
CB Successful SPAR Shot 1 Counter
CB Succ 3P AR Reset

& Increment
Seq Counter = 1 CB Successful 3PAR Shot 1 Counter
Reset

& Increment
Seq Counter = 2 CB Successful 3PAR Shot 2 Counter
Reset

& Increment
Seq Counter = 3 CB Successful 3PAR Shot 3 Counter
Reset

& Increment
Seq Counter = 4 CB Successful 3PAR Shot 4 Counter
Reset
0
CB Arip
0.02 & Increment
CB Failed AR Counter
Reset
A/ R Lockout

Ext Rst CB Shots

1
Reset CB Shots
Yes

V03366

Figure 197: Autoreclose Shot Counters logic diagram (Module 41)

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5.16 CIRCUIT BREAKER CONTROL

5.16.1 CB CONTROL LOGIC DIAGRAM

CB Control by
Opto Note: If the DDB signal CB Healthy is not mapped in PSL it defaults to High .
Opto+Local
1
Opto+Remote
Opto+Rem+Local
Trip Pulse Time
HMI Trip Control Trip
1
& S t
& Q
Init Trip CB RD 0 & CB Trip Fail

&
Init close CB Man Close Delay Close Pulse Time
1 Close in Prog
HMI Close
& S t
CB ARIP Q
RD 0 & Control Close
1 S t
Auto Close Q
RD 0
Reset Close Dly

Any Trip & CB Close Fail

1
Control Trip

External Trip3Ph 1
1
External Trip A

External Trip B

External Trip C
1 1
CB Open 3 ph

CB Open A ph

CB Open B ph &
CB Open C ph

CB Closed 3 ph
1
CB Closed A ph

CB Closed B ph 1 CB Healthy Time

CB Closed C ph
t
& Man CB Unhealthy
CB Healthy 0

Check Sync Time

t
& No C/S Man Close
CB Man SCOK 0

V03369

Figure 198: CB Control logic diagram (Module 43)

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5.17 CIRCUIT BREAKER TRIP TIME MONITORING

The circuit breaker trip time monitoring logic checks for correct circuit breaker tripping following the issue of a
protection trip signal. When the protection trip signal is issued, a timer controlled by the Trip Pulse Time setting in
the CB CONTROL column is started.
If the circuit breaker trips correctly the timer resets. If Autoreclose is enabled and the timer resets, the cycle
continues. If the circuit breaker fails to trip correctly within the set time, the Autoreclose cycle is forced to lock out
and a signal is issued indicating that the circuit breaker failed to trip in response to the protection operation.

5.17.1 CB TRIP TIME MONITORING LOGIC DIAGRAM

Trip Pulse Time

TAR2/3Ph S t
Q
RD 0 1 CB Fail Pr Trip
& S
CB Open 3 Ph Q
RD
CB Closed 3 Ph

Trip Pulse Time

TARA
& S
TMEM2/3Ph Q t
RD 1
0
& S
CB Open 3 Ph Q
RD
CB Closed 3 Ph 1

TARB
& S
TMEM2/3Ph Q
RD
& S
CB Open 3 Ph Q
RD
CB Closed 3 Ph 1

TARC
& S
TMEM2/3Ph Q
RD
& S
CB Open 3 Ph Q
RD
CB Closed 3 Ph 1

V03376

Figure 199: Circuit Breaker Trip Time Monitoring logic diagram (Module 53)

5.18 AUTORECLOSE LOCKOUT

A number of events will cause Autoreclose lockout. If this happens an Autoreclose lockout alarm is raised. In this
condition, Autoreclose cannot be initiated until the corresponding lockout has been reset.
The following events force Autoreclose lockout:
● Protection operation during reclaim time. Following the final Autoreclose attempt, if the protection operates
during the reclaim time, the AR cycle goes to AR lockout and the Autoreclose function is disabled until the
AR lockout condition is reset.
● Persistent fault. A fault is considered persistent if the protection re-operates after the last permitted shot.
● Block Autoreclose. If the block Autoreclose DDB is asserted whilst Autoreclose is in progress, the cycle goes
to lockout.
● Protection function selection. Setting ‘Block AR’ against a particular protection function in the AUTORECLOSE
column means that operation of the protection will block Autoreclose and force lockout.

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● Circuit breaker failure to close. If a circuit breaker fails to close Autoreclose is blocked and forced to lockout.
● Circuit breaker remains open at the end of the reclaim time. An Autoreclose lockout is forced if the circuit
breaker is open at the end of the reclaim time.
● Circuit breaker fails to close when the close command is issued.
● Circuit breaker fails to trip correctly.
● Three-phase dead time started by ‘line dead’ violation. If the line does not go dead within the Dead Line
Time setting, the logic forces the Autoreclose sequence to lockout. Determination of when to start the timer
is made in the 3PDTStart WhenLD setting.
● Multi-phase faults. The logic can be set to block Autoreclose either for two-phase or three-phase faults, or
to block Autoreclose for three-phase faults only. For this, the setting Multi Phase AR in the AUTORECLOSE
column applies.
● Single-phase evolving into multi-phase fault. A discriminating time (Discrim Time in the AUTORECLOSE
settings) is provided for this feature If, after expiry of the discriminating time, a single-phase fault evolves
into a two-phase or three-phase fault, the internal signal ‘Evolve Lock’ is asserted and the Autoreclose is
forced to lockout.

5.18.1 CB LOCKOUT LOGIC DIAGRAM

FLTMEM3P
&
Multi Phase AR
BAR 3 Phase
1
BAR 2 and 3 Ph
&
FLTMEM2P A/ R Lockout
CB Close Fail

CB Fail Pr Trip
AR In Service
CB1OpAny & S
Q
R
CB ARIP &
Block CB AR

A/R CB Unhealthy
RESCB1LO
A/R No Checksync &

Evolve 3Ph S
Q
PROTRE-OP R

LastShot &
CB ARIP
1 BARCB1
EVOLVELOCK &
ProtARBlock

CB In Service
&
TMEM2/3Ph
0
CB1L3 PAROK
0.02s

CB In Service
&
TMEM1Ph
0
CB1 LSPAROK
0.02s
Seq Counter >Set

CB1 Status Alm

DeadLineLockout

V03379

Figure 200: AR Lockout Logic Diagram (Module 55)

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5.19 RESET CIRCUIT BREAKER LOCKOUT

Lockout conditions caused by the circuit breaker condition monitoring functions can be reset according to the
condition of the Rst CB mon LO by setting found in the CB CONTROL column. There are two options; CB Close
and User interface.
If set to CB Close, a timer setting, CB mon LO RstDly, becomes visible. When the circuit breaker closes, the CB
mon LO RstDly time starts. The lockout is reset when the timer expires.
If set to User Interface then a command, CB mon LO reset, becomes visible. This command can be used to
reset the lockout from a user interface.
An Autoreclose lockout generates an Autoreclose lockout alarm. Autoreclose lockout conditions can be reset by
various commands and setting options found under the CB CONTROL column.
If Res LO by CB IS is set to Enabled, a lockout is reset if the circuit breaker is successfully closed manually. For
this, the circuit breaker must remain closed long enough so that it enters the “In Service” state.
If Res LO by UI is set to Enabled, the circuit breaker lockout can be reset from a user interface using the reset
circuit breaker lockout command in the CB CONTROL column.
If Res LO by NoAR is set to Enabled, the circuit breaker lockout can be reset by temporarily generating an AR
disabled signal.
If Res LO by TDelay is set to Enabled, the circuit breaker lockout is automatically reset after a time delay set in
the LO Reset Time setting.
If Res LO by ExtDDB is Enabled, the circuit breaker lockout can be reset by activation of an external input
mapped in the PSL to the relevant reset lockout DDB signal.

5.19.1 RESET CB LOCKOUT LOGIC DIAGRAM

Res LO by CB IS
Enabled
&
CB1CRLO

Res LO by UI
Enabled
&
Reset CB LO
Yes

Res LO by NoAR
Enabled
& 1 RESCB1LO
AR Disabled

Res LO by ExtDDB
Enabled
&
Reset Lockout

Res LO by TDelay
Enabled
&
LO Reset Time
t
A/ R Lockout
0

V03382

Figure 201: Reset Circuit Breaker Lockout Logic Diagram (Module 57)

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5.20 POLE DISCREPANCY

In a three-pole CB, certain combinations of poles open and closed are indicative of a problem. The Pole
Discrepancy Logic combines an indication of a Pole Discrepancy condition from the CB Monitoring logic with
signals from the internal Autoreclose logic to produce a combined Pole Discrepancy indication for the CB.

5.20.1 POLE DISCREPANCY LOGIC DIAGRAM

A/ R Lockout
1 0.04
Lockout Alarm & Pole Discrepancy
0
Pol Disc Ext
&
AR 1pole in prog

CB Open A ph
1
CB Open B ph

CB Open C ph
&
V03384

Figure 202: Pole Discrepancy Logic Diagram (Module 62)

5.21 CIRCUIT BREAKER TRIP CONVERSION

Circuit breakers should only trip single-pole or three-pole. The trip conversion logic ensures that the tripping is
either single-pole or three-pole. The trip conversion logic ensures that all conditions that should cause three-pole
tripping do so. Indication of the number of phases that caused tripping is provided.

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5.21.1 CB TRIP CONVERSION LOGIC DIAGRAM

530
Trip Inputs A
1 S
523
Q Trip Output A
R
531
Trip Inputs B
1 S
524
Q Trip Output B
R
532
Trip Inputs C
1 S
525
Q Trip Output C
R
Tripping Mode 1
&
3 Pole 1 S
526
Q Trip 3 ph
858 R
AR Force 3 pole 1
533
Force 3Pole Trip
529
Trip Inputs 3Ph

Dwell
522
1 Any Trip
530 100 ms
Trip Inputs A
531
Trip Inputs B
≥ S
Trip Inputs C 532 2 Q 527
2/3 Ph Fault
R
892
Pole Dead A &
1 S
528
Q 3 Ph Fault
R
893 & 1
Pole Dead B 1

&
894 1
Pole Dead C
&
V03386

Figure 203: Circuit Breaker Trip Conversion Logic Diagram (Module 63)

5.22 MONITOR CHECKS FOR CB CLOSURE

For single-phase Autoreclose neither voltage nor synchronisation checks are needed as synchronising power
should be flowing in the two healthy phases. For three-phase Autorelcose, for the first shot (and only the first shot),
you can choose to attempt reclosure without performing a synchronisation check. The setting to permit
Autoreclose without checking synchronising conditions is CB SC Shot 1.
Otherwise, synchronising checks on voltages, relative frequencies, and relative phase angles are needed to ensure
that sympathetic conditions exist before CB closure is attempted.
The following diagrams detail the Monitor Checks for CB closure.

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5.22.1 CHECK SYNCHRONISATION MONITOR FOR CB CLOSURE

System Checks
Disabled SysChks Inactive
Enabled

CS1 Criteria OK
VAN &
VBN CS2 Criteria OK
&
VCN
Select CS1 SlipF>
VAB & CS1 SlipF>

VBC CS1 SlipF<

& CS1 SlipF<
VCA CS2 SlipF>
& CS2 SlipF>
VBus
CS2 SlipF<
& CS2 SlipF<

CS Vline>
& CS Vline>

CS Vbus>
& CS Vbus>

CS Vline<
& CS Vline<
Check Synchronisation Function

CS Vbus<
& CS Vbus<

CS1 Vl>Vb
& CS1 Vl>Vb

CS1 Vl<Vb
& CS1 Vl<Vb

CS1 Fl>Fb
& CS1 Fl>Fb

CS1 Fl<Fb
& CS1 Fl<Fb

CS1 AngHigh+
& CS1 AngHigh+

CS1 AngHigh-
& CS1 AngHigh-

CS2 Fl>Fb
& CS2 Fl>Fb

CS2 Fl<Fb
& CS2 Fl<Fb

CS2 AngHigh+
& CS2 AngHigh+

CS2 AngHigh-
& CS2 AngHigh-

CS AngRotACW
MCB/VTS CB CS & CS AngRotACW

MCB/VTS CS AngRotCW
& CS AngRotCW
VTS Fast Block
1 CS2 Vl>Vb
F out of Range & CS2 Vl>Vb

CS2 Vl<Vb
& CS2 Vl<Vb
CS1 Status
Enabled
& Check Sync 1 OK
CS1 Enabled

CS2 Status
Enabled & Check Sync 2 OK

CS2 Enabled V01259

Figure 204: Check Synchronisation Monitor for CB closure (Module 60)

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5.22.2 VOLTAGE MONITOR FOR CB CLOSURE

System Checks
Enabled

VAN
Live Line & Live Line
VBN

VCN
Select Dead Line & Dead line
VAB

VBC
Live Bus & Live Bus
VCA

VBus Dead Bus & Dead Bus

Voltage Monitors

MCB/VTS

MCB/VTS CB CS

1
Inhibit LL

1
Inhibit DL

1
Inhibit LB

1
Inhibit DB

V 01257

Figure 205: Voltage Monitor for CB Closure (Module 59)

5.23 SYNCHRONISATION CHECKS FOR CB CLOSURE

Logical checking of the outputs from the CB closure monitors is performed to generate signals to indicate that it is
OK to close circuit breakers.
Signals are provided to indicate that manual CB closure conditions are OK (CB Man SCOK), as are signals to
indicate that automatic CB closure conditions are OK (CB SCOK and CB Fast SCOK). The CB Fast SCOK signal
allows CB autoreclosure without waiting for the Dead Time to expire.
For single-phase Autoreclose no voltage or synchronism check is required as synchronising power is flowing in the
two healthy phases. Three-phase Autoreclose can be performed without checking that voltages are in
synchronism for the first shot (and only the first shot). The settings to permit Autoreclose without checking voltage
synchronism on the first shot are:
● CB1L SC Shot 1 for circuit breaker 1 as a leader,
● CB1F SC Shot 1 for circuit breaker 1 as a follower,
● CB2L SC Shot 1 for circuit breaker 2 as a leader,
● CB2L SC Shot 1 for circuit breaker 2 as a follower.

When the circuit breaker has closed, the Autoreclose function asserts a DDB signal Set CB1 Close, which indicates
that an attempt has been made to close the circuit breaker. At this point, the Reclaim Time starts. If the circuit

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breaker remains closed after the reclaim timer expires, the Autoreclose cycle is complete, and signals are
generated to indicate that Autoreclose was successful. These are:
● CB1 Succ 1P AR (Single-phase Autoreclose CB1)
● CB2 Succ 1P AR (Single-phase Autoreclose CB2)
● CB1 Succ 3P AR (Three-phase Autoreclose CB1)
● CB2 Succ 3P AR (Three-phase Autoreclose CB2)

These signals increment the relevant circuit breaker successful Autoreclose shot counters, as well as resetting the
Autoreclose in progress signal.
The relevant circuit breaker successful Autoreclose shot counters are:
● CB1 SUCC SPAR (Single-phase Autoreclose CB1)
● CB1 SUCC 3PAR Shot1 (Three-phase Autoreclose CB1, Shot 1)
● CB1 SUCC 3PAR Shot2 (Three-phase Autoreclose CB1, Shot 2)
● CB1 SUCC 3PAR Shot3 (Three-phase Autoreclose CB1, Shot 3)
● CB1 SUCC 3PAR Shot4 (Three-phase Autoreclose CB1, Shot 4)
● CB2 SUCC SPAR (Single-phase Autoreclose CB2)
● CB2 SUCC 3PAR Shot1 (Three-phase Autoreclose CB2, Shot 1)
● CB2 SUCC 3PAR Shot2 (Three-phase Autoreclose CB2, Shot 2)
● CB2 SUCC 3PAR Shot3 (Three-phase Autoreclose CB2, Shot 3)
● CB1 SUCC 3PAR Shot4 (Three-phase Autoreclose CB2, Shot 4)

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5.23.1 THREE-PHASE AUTORECLOSE SYSTEM CHECK LOGIC DIAGRAM

CB SC ClsNoDly
Enabled
& CB Fast SCOK
CB SC CS1
Enabled 1
&
Check Sync 1 OK

CB SC CS2
Enabled
&
Check Sync 2 OK

CB SC DLLB
Enabled
&
Dead Line

Live Bus

CB SC LLDB
Enabled
& 1 CB SCOK
Live Line

Dead Bus

CB SC DLDB
Enabled
&
Dead Line

Dead Bus

CB SC Shot 1
Note: If the DDB signal Ext CS OK is not mapped in PSL , it defaults to High.
Disabled
&
Seq Counter = 1

CB SC all
Disabled
&
Ext CS OK

V03372

Figure 206: Three-phase Autoreclose System Check Logic Diagram (Module 45)

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5.23.2 CB MANUAL CLOSE SYSTEM CHECK LOGIC DIAGRAM

CBM SC CS1
Enabled
&
Check Sync 1 OK

CBM SC CS2
Enabled
&
Check Sync 2 OK

CBM SC DLLB
Enabled
&
Dead Line

Live Bus

CBM SC LLDB
Enabled
& 1 CB Man SCOK
Live Line

Dead Bus

CBM SC DLDB
Enabled
&
Dead Line

Dead Bus
Note: If the DDB signal CB Ext CS OK is not mapped in PSL , it
CBM SC required defaults to High .
Disabled
&
Ext CS OK

V03374

Figure 207: CB Manual Close System Check Logic Diagram (Module 51)

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6 SETTING GUIDELINES

6.1 DE-IONISING TIME GUIDANCE

The de-ionisation time of a fault arc depends on several factors such as circuit voltage, conductor spacing, fault
current and duration, atmospheric conditions, wind speed and capacitive coupling from adjacent conductors. For
this reason it is difficult to estimate the de-ionisation time. Circuit voltage is, generally the most significant factor
and experience tells us that typical minimum de-ionising times for a three-phase fault are as follows:
● 66 kV: 100 ms
● 110 kV: 150 ms
● 132 kV: 170 ms
● 220 kV: 280 ms
● 275 kV: 300 ms
● 400 kV: 500 ms
Where single-pole high speed Autoreclose is used, the capacitive current induced between the healthy phases and
the faulty phase tends to maintain the arc. This significantly increases the de-ionisation time and hence required
dead time.
Single-pole Autoreclose is generally only used at transmission voltages. A typical de-ionisation time at 220 kV may
be as high as 560 ms.

6.2 DEAD TIMER SETTING GUIDELINES

High speed Autoreclose may need to maintain stability on a network with two or more power sources. For high
speed Autoreclose the system disturbance time should be minimised by using fast protection (typically <30 ms)
and fast circuit breakers (typically <60 ms). For stability between two sources a system dead time of ≤300 ms may
typically be required.
The minimum system dead time (considering just the circuit breaker) is the trip mechanism reset time plus the
circuit breaker closing time.
The Autoreclose minimum dead time settings are governed primarily by two factors:
● Time taken for de-ionisation of the fault path
● Circuit breaker characteristics
It is essential that the protection fully resets during the dead time, so that correct time discrimination will be
maintained after Autoreclose onto a fault. For high speed Autoreclose instantaneous reset of protection is
required.
For highly interconnected systems synchronism is unlikely to be lost by the tripping out of a single line. Here the
best policy may be to adopt longer dead times, to allow time for power swings resulting from the fault to settle.

6.2.1 EXAMPLE DEAD TIME CALCULATION

The following circuit breaker and system characteristics can be used for the minimum dead time calculation:
● a) Circuit breaker Operating time (Trip coil energized to Arc interruption): 50 ms
● b) Circuit breaker Opening + Reset time (Trip coil energized to trip mechanism reset): 200 ms
● c) Protection reset time: < 80 ms
● d) Circuit breaker Closing time (Close command to Contacts make): 85 ms
● e) De-ionisation time (280 ms for 3-phase, or 560 ms for 1-phase)
Three-phase de-ionisation time for 220 kV line is typically 280 ms.
The minimum Autoreclose dead time setting is therefore the greater of:
(a) + (c) = 50 ms + 80 ms = 130 ms, to allow protection reset

P54x1i-TM-EN-1 349
Chapter 11 - Autoreclose P543i/P545i

(a) + (e) - (d) = 50 ms + 280 ms - 85 ms = 245 ms, to allow de-ionising

In practice a few additional cycles would be added to allow for tolerances, so Dead Time 1 could be set to 300 ms
or greater. The overall system dead time is found by adding (d) to the chosen settings then subtracting (a). This
gives 335 ms.
A typical de-ionising time value for single-phase trip on a 220 kV line is 560 ms, so the 1 Pole Dead Time could be
chosen as 600 ms or greater. The overall system dead time is found by adding (d) to the chosen settings then
subtracting (a). This gives 635 ms.

6.3 RECLAIM TIME SETTING GUIDELINES

Several factors influence the choice of the reclaim timer, such as:
● Fault incidence/Past experience: Small reclaim times may be required where there is a high incidence of
recurrent lightning strikes to prevent unnecessary lockout for transient faults.
● Spring charging time: For high speed Autoreclose the reclaim time may be set longer than the spring
charging time. A minimum reclaim time of more than 5s may be needed to allow the circuit breaker time to
recover after a trip and close before it can perform another trip-close-trip cycle. This time will depend on the
duty (rating) of the circuit breaker. For delayed Autoreclose this may not be needed as the dead time can be
extended by an extra circuit breaker healthy check / Autoreclose Inhibit Time window time if there is
insufficient energy in the circuit breaker.
● Switchgear Maintenance: Excessive operation resulting from short reclaim times can mean shorter
maintenance intervals.
When used in conjunction with distance protection, the Reclaim Time setting is generally set greater than the zone
2 delay.

350 P54x1i-TM-EN-1
 CHAPTER 12

CB FAIL PROTECTION
Chapter 12 - CB Fail Protection P543i/P545i

352 P54x1i-TM-EN-1
P543i/P545i Chapter 12 - CB Fail Protection

1 CHAPTER OVERVIEW
The device provides a Circuit Breaker Fail Protection function. This chapter describes the operation of this function
including the principles, logic diagrams and applications.
This chapter contains the following sections:
Chapter Overview 353
Circuit Breaker Fail Protection 354
Circuit Breaker Fail Implementation 355
Circuit Breaker Fail Logic 357
Application Notes 361

P54x1i-TM-EN-1 353
Chapter 12 - CB Fail Protection P543i/P545i

2 CIRCUIT BREAKER FAIL PROTECTION

When a fault occurs, one or more protection devices will operate and issue a trip command to the relevant circuit
breakers. Operation of the circuit breaker is essential to isolate the fault and prevent, or at least limit, damage to
the power system. For transmission and sub-transmission systems, slow fault clearance can also threaten system
stability.
For these reasons, it is common practice to install Circuit Breaker Failure protection (CBF). CBF protection monitors
the circuit breaker and establishes whether it has opened within a reasonable time. If the fault current has not
been interrupted following a set time delay from circuit breaker trip initiation, the CBF protection will operate,
whereby the upstream circuit breakers are back-tripped to ensure that the fault is isolated.
CBF operation can also reset all start output contacts, ensuring that any blocks asserted on upstream protection
are removed.

354 P54x1i-TM-EN-1
P543i/P545i Chapter 12 - CB Fail Protection

3 CIRCUIT BREAKER FAIL IMPLEMENTATION

Circuit Breaker Failure Protection is implemented in the CB FAIL & P.DEAD column of the relevant settings group.

3.1 CIRCUIT BREAKER FAIL TIMERS

The circuit breaker failure protection incorporates two timers, CB Fail 1 Timer and CB Fail 2 Timer, allowing
configuration for the following scenarios:
● Simple CBF, where only CB Fail 1 Timer is enabled. For any protection trip, the CB Fail 1 Timer is started, and
normally reset when the circuit breaker opens to isolate the fault. If breaker opening is not detected, the CB
Fail 1 Timer times out and closes an output contact assigned to breaker fail (using the programmable
scheme logic). This contact is used to back-trip upstream switchgear, generally tripping all infeeds
connected to the same busbar section.
● A retripping scheme, plus delayed back-tripping. Here, CB Fail 1 Timer is used to issue a trip command to a
second trip circuit of the same circuit breaker. This requires the circuit breaker to have duplicate circuit
breaker trip coils. This mechanism is known as retripping. If retripping fails to open the circuit breaker, a
back-trip may be issued following an additional time delay. The back-trip uses CB Fail 2 Timer, which was
also started at the instant of the initial protection element trip.

You can configure the CBF elements CB Fail 1 Timer and CBF Fail 2 Timer to operate for trips triggered by
protection elements within the device. Alternatively you can use an external protection trip by allocating one of the
opto-inputs to the External Trip DDB signal in the PSL.
You can reset the CBF from a breaker open indication (from the pole dead logic) or from a protection reset. In these
cases resetting is only allowed if the undercurrent elements have also been reset. The resetting mechanism is
determined by the settings Volt Prot Reset and Ext Prot Reset.
The resetting options are summarised in the following table:
Initiation (Menu Selectable) CB Fail Timer Reset Mechanism
The resetting mechanism is fixed (e.g. 50/51/46/21/87)
Current based protection
IA< operates AND IB< operates AND IC< operates AND IN< operates
The resetting mechanism is fixed.
Sensitive Earth Fault element
ISEF< Operates
Three options are available:
● All I< and IN< elements operate
Non-current based protection (e.g. 27/59/81/32L)
● Protection element reset AND all I< and IN< elements operate
● CB open (all 3 poles) AND all I< and IN< elements operate
Three options are available.
● All I< and IN< elements operate
External protection
● External trip reset AND all I< and IN< elements operate
● CB open (all 3 poles) AND all I< and IN< elements operate

3.2 ZERO CROSSING DETECTION

When there is a fault and the circuit breaker interrupts the CT primary current, the flux in the CT core decays to a
residual level. This decaying flux introduces a decaying DC current in the CT secondary circuit known as
subsidence current. The closer the CT is to its saturation point, the higher the subsidence current.
The time constant of this subsidence current depends on the CT secondary circuit time constant and it is generally
long. If the protection clears the fault, the CB Fail function should reset fast to avoid maloperation due to the
subsidence current. To compensate for this the device includes a zero-crossing detection algorithm, which ensures
that the CB Fail re-trip and back-trip signals are not asserted while subsidence current is flowing. If all the samples
within half a cycle are greater than or smaller than 0 A (10 mS for a 50 Hz system), then zero crossing detection is
asserted, thereby blocking the operation of the CB Fail function. The zero-crossing detection algorithm is used

P54x1i-TM-EN-1 355
Chapter 12 - CB Fail Protection P543i/P545i

after the circuit breaker in the primary system has opened ensuring that the only current flowing in the AC
secondary circuit is the subsidence current.

356 P54x1i-TM-EN-1
P543i/P545i Chapter 12 - CB Fail Protection

4 CIRCUIT BREAKER FAIL LOGIC

4.1 CIRCUIT BREAKER FAIL LOGIC - PART 1

WI Prot Reset
Enabled

ExtTrip Only Ini

Enabled
&
642
Aid1 WI Trip 3Ph &
1
652
Aid2 WI Trip 3Ph 1 WIINFEEDA
&
637
Aid 1 WI Trip A &
1
647
Aid 2 WI Trip A 1 WIINFEEDB
&
638
Aid 1 WI Trip B &
1
648
Aid 2 WI Trip B 1 WIINFEEDC
&
639
Aid 1 WI Trip C &
1
649
Aid 2 WI Trip C
Note: This part is not relevant for non -distance models

ExtTrip Only Ini

Enabled
& S
CurrentProtSEFTrip Q TripStateSEF
RD

ISEF<FastUndercurrent

ZCDStateA

ZCDStateB
ZCD function
ZCDStateC

ZCDStateSEF

V00729

Figure 208: Circuit Breaker Fail logic - part 1

P54x1i-TM-EN-1 357
Chapter 12 - CB Fail Protection P543i/P545i

4.2 CIRCUIT BREAKER FAIL LOGIC - PART 2

External Trip A S
4 Q TripStateExt A
1
RD

3
1
Ext Prot Reset
2 I< Only
&
CB Open & I<
Pole Dead A 1 Prot Reset & I<
&
Prot Reset OR I<
0 Rst OR CBOp & I<
IA<FastUndercurrent

4
Latch ATripResetIncomp
3

2
&

1
&

0
Logic 0

V00730

Figure 209: Circuit Breaker Fail logic - part 2

Note:
This diagram shows only phase-A for a single-CB device. The diagrams for phases B and C follow the same principle and are
not repeated here.

358 P54x1i-TM-EN-1
P543i/P545i Chapter 12 - CB Fail Protection

4.3 CIRCUIT BREAKER FAIL LOGIC - PART 3

WIINFEEDA

TripStateExtA 1 TripStateA

ExtTrip Only Ini

Enabled

& S
AnyTripPhaseA Q
RD
IA<FastUndercurrent

External Trip 3Ph S

4 Q
1 1
RD

3
1
Ext Prot Reset

2 I< Only
&
CB Open & I<
All Poles Dead
1 1 Prot Reset& I<
&
Pole Dead A Prot Reset OR I<

0 Rst OR CBOp & I<

Pole Dead B &
Pole Dead C

4
Latch3PhTripResetIncomp
3

2
&
IA<FastUndercurrent

IB<FastUndercurrent & 1
&
IC<FastUndercurrent
0
ExtTrip Only Ini 0
Enabled

& S
CBF Non I Trip
2 Q
&
RD
All Poles Dead
1 1
&
Pole Dead A Ext Prot Reset
0 I< Only
Pole Dead B &
CB Open & I<
Pole Dead C Prot Reset& I<
Prot Reset OR I<
IA<FastUndercurrent Rst OR CBOp & I<

IB<FastUndercurrent &
2
&
IC<FastUndercurrent LatchNonITripResetIncomp
1
&

0
Logic 0

V00731

Figure 210: Circuit Breaker Fail logic - part 3

P54x1i-TM-EN-1 359
Chapter 12 - CB Fail Protection P543i/P545i

4.4 CIRCUIT BREAKER FAIL LOGIC - PART 4

From phase B equivalent
LatchATripResetIncomp*1 From phase C equivalent
1 Bfail1 Trip 3ph
Latch3PhTripResetIncomp 1
1 CB Fail Alarm
LatchNonITripResetIncomp

1 Bfail2 Trip 3ph

CBZCDStateA

WIINFEEDA

1
TripStateA
& &
t 1 CB Fail1 Trip A
CB Fail 1 Status
0
Enabled

CB Fail 1 Timer
1
&
TripStateA t 1 CB Fail2 Trip A
&
0
CB Fail 2 Status
Enabled

CB Fail 2 Timer

ZCDStateSEF

1
TripStateSEF
& &
t
CB Fail 1 Status
0
Enabled

CB Fail 1 Timer
1
&
TripStateSEF t
&
0
CB Fail 2 Status
Enabled

CB Fail 2 Timer
*1: Not used in P445.
V00732

Figure 211: Circuit Breaker Fail logic - part 4

Note:
This diagram shows only phase-A for a single-CB device. The diagrams for phases B and C follow the same principle and are
not repeated here.

360 P54x1i-TM-EN-1
P543i/P545i Chapter 12 - CB Fail Protection

5 APPLICATION NOTES

5.1 RESET MECHANISMS FOR CB FAIL TIMERS

It is common practise to use low set undercurrent elements to indicate that circuit breaker poles have interrupted
the fault or load current. This covers the following situations:
● Where circuit breaker auxiliary contacts are defective, or cannot be relied on to definitely indicate that the
breaker has tripped.
● Where a circuit breaker has started to open but has become jammed. This may result in continued arcing at
the primary contacts, with an additional arcing resistance in the fault current path. Should this resistance
severely limit fault current, the initiating protection element may reset. Therefore, reset of the element may
not give a reliable indication that the circuit breaker has opened fully.

For any protection function requiring current to operate, the device uses operation of undercurrent elements to
detect that the necessary circuit breaker poles have tripped and reset the CB fail timers. However, the
undercurrent elements may not be reliable methods of resetting CBF in all applications. For example:
● Where non-current operated protection, such as under/overvoltage or under/overfrequency, derives
measurements from a line connected voltage transformer. Here, I< only gives a reliable reset method if the
protected circuit would always have load current flowing. In this case, detecting drop-off of the initiating
protection element might be a more reliable method.
● Where non-current operated protection, such as under/overvoltage or under/overfrequency, derives
measurements from a busbar connected voltage transformer. Again using I< would rely on the feeder
normally being loaded. Also, tripping the circuit breaker may not remove the initiating condition from the
busbar, and so drop-off of the protection element may not occur. In such cases, the position of the circuit
breaker auxiliary contacts may give the best reset method.

5.2 SETTING GUIDELINES (CB FAIL TIMER)

The following timing chart shows the CB Fail timing during normal and CB Fail operation. The maximum clearing
time should be less than the critical clearing time which is determined by a stability study. The CB Fail back-up trip
time delay considers the maximum CB clearing time, the CB Fail reset time plus a safety margin. Typical CB
clearing times are 1.5 or 3 cycles. The CB Fail reset time should be short enough to avoid CB Fail back-trip during
normal operation. Phase and ground undercurrent elements must be asserted for the CB Fail to reset. The
assertion of the undercurrent elements might be delayed due to the subsidence current that might be flowing
through the secondary AC circuit.

P54x1i-TM-EN-1 361
Chapter 12 - CB Fail Protection P543i/P545i

CBF resets:
1. Undercurrent element asserts
2. Undercurrent element asserts and the
breaker status indicates an open position
3. Protection resets and the undercurrent
Fault occurs element asserts

CBF Safety
Protection Maximum breaker reset margin
Normal operating time clearing time time time
operation
t

Protection Local Bks clearing

Breaker failure operating time CBF back-up trip time delay time
operation

Local 86 Remote CB
operating clearing time
time

Maximum fault clearing time

V00693 Fault occurs

Figure 212: CB Fail timing

The following examples consider direct tripping of a 2-cycle circuit breaker. Typical timer settings to use are as
follows:
Typical Delay For 2 Cycle Circuit
CB Fail Reset Mechanism tBF Time Delay
Breaker
CB interrupting time + element reset time (max.) + error in tBF
Initiating element reset 50 + 50 + 10 + 50 = 160 ms
timer + safety margin
CB auxiliary contacts opening/ closing time (max.) + error in tBF
CB open 50 + 10 + 50 = 110 ms
timer + safety margin
CB interrupting time + undercurrent element (max.) + safety
Undercurrent elements 50 + 25 + 50 = 125 ms
margin operating time

Note:
All CB Fail resetting involves the operation of the undercurrent elements. Where element resetting or CB open resetting is
used, the undercurrent time setting should still be used if this proves to be the worst case.
Where auxiliary tripping relays are used, an additional 10-15 ms must be added to allow for trip relay operation.

5.3 SETTING GUIDELINES (UNDERCURRENT)

The phase undercurrent settings (I<) must be set less than load current to ensure that I< operation correctly
indicates that the circuit breaker pole is open. A typical setting for overhead line or cable circuits is 20%In. Settings
of 5% of In are common for generator CB Fail.
The earth fault undercurrent elements must be set less than the respective trip. For example:
IN< = (IN> trip)/2

362 P54x1i-TM-EN-1
 CHAPTER 13

CURRENT PROTECTION FUNCTIONS

Chapter 13 - Current Protection Functions P543i/P545i

364 P54x1i-TM-EN-1
P543i/P545i Chapter 13 - Current Protection Functions

1 CHAPTER OVERVIEW
The primary purpose of this product is not overcurrent protection. It does however provide a range of current
protection functions to be used as backup protection. This chapter assumes you are familiar with overcurrent
protection principles and does not provide detailed information here. If you require further information about
general overcurrent protection principles, please refer either to General Electric's NPAG publication, earlier
incarnations of this technical manual, or one of our technical manuals from our P40 Agile Modular distribution
range of products such as the P14x.
This chapter contains the following sections:
Chapter Overview 365
Phase Fault Overcurrent Protection 366
Negative Sequence Overcurrent Protection 369
Earth Fault Protection 372
Sensitive Earth Fault Protection 377
High Impedance REF 382
Thermal Overload Protection 384
Broken Conductor Protection 389
Transient Earth Fault Detection 391

P54x1i-TM-EN-1 365
Chapter 13 - Current Protection Functions P543i/P545i

2 PHASE FAULT OVERCURRENT PROTECTION

Phase fault overcurrent protection is provided as a form of back-up protection that could be:
● Permanently disabled
● Permanently enabled
● Enabled only in case of VT fuse/MCB failure
● Enabled only in case of protection communication channel failure
● Enabled if VT fuse/MCB or protection communication channel fail
● Enabled if VT fuse/MCB and protection communication channel fail

In addition, each stage may be disabled by a DDB signal.

It should be noted that phase overcurrent protection is phase segregated, but the operation of any phase is
mapped to 3 phase tripping in the default PSL.
The VTS element of the IED can be selected to either block the directional element or simply remove the directional
control.

2.1 POC IMPLEMENTATION

Phase Overcurrent Protection is configured in the OVERCURRENT column of the relevant settings group.
The product provides four stages of three-phase overcurrent protection, each with independent time delay
characteristics. The settings are independent for each stage, but for each stage, the settings apply to all phases.
Stages 1 and 2 provide a choice of operate and reset characteristics, where you can select between:
● A range of IDMT (Inverse Definite Minimum Time) curves based on IEC and IEEE standards
● A range of programmable user-defined curves
● DT (Definite Time) characteristic

This is achieved using the cells:

● I>(n) Function for the overcurrent operate characteristic
● I>(n) Reset Char for the overcurrent reset characteristic
● I>(n) Usr Rst Char for the reset characteristic for user-defined curves

where (n) is the number of the stage.

The IDMT-equipped stages, (1 and 2) also provide a Timer Hold facility. This is configured using the cells I>(n)
tReset, where (n) is the number of the stage. This does not apply to IEEE curves.
Stages 3 and 4 have definite time characteristics only.

2.2 DIRECTIONAL ELEMENT

If fault current can flow in both directions through a protected location, you will need to use a directional
overcurrent element to determine the direction of the fault. Once the direction has been determined the device
can decide whether to allow tripping or to block tripping. To determine the direction of a phase overcurrent fault,
the device must compare the phase angle of the fault current with that of a known reference quantity. The phase
angle of this known reference quantity must be independent of the faulted phase. Typically this will be the line
voltage between the other two phases.
The phase fault elements of the IEDs are internally polarized by the quadrature phase-phase voltages, as shown in
the table below:
Phase of protection Operate current Polarizing voltage
A Phase IA VBC

366 P54x1i-TM-EN-1
P543i/P545i Chapter 13 - Current Protection Functions

Phase of protection Operate current Polarizing voltage

B Phase IB VCA
C Phase IC VAB

Under system fault conditions, the fault current vector lags its nominal phase voltage by an angle depending on
the system X/R ratio. The IED must therefore operate with maximum sensitivity for currents lying in this region. This
is achieved by using the IED characteristic angle (RCA). This is the is the angle by which the current applied to the
IED must be displaced from the voltage applied to the IED to obtain maximum sensitivity.
The device provides a setting I> Char Angle, which is set globally for all overcurrent stages. It is possible to set
characteristic angles anywhere in the range –95° to +95°.
A directional check is performed based on the following criteria:

Directional forward
-90° < (angle(I) - angle(V) - RCA) < 90°

Directional reverse
-90° > (angle(I) - angle(V) - RCA) > 90°
For close up three-phase faults, all three voltages will collapse to zero and no healthy phase voltages will be
present. For this reason, the device includes a synchronous polarisation feature that stores the pre-fault voltage
information and continues to apply this to the directional overcurrent elements for a time period of a few seconds.
This ensures that either instantaneous or time-delayed directional overcurrent elements will be allowed to operate,
even with a three-phase voltage collapse.

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Chapter 13 - Current Protection Functions P543i/P545i

2.3 POC LOGIC

762
IA I>1 Start A

I>1 Current Set 656

& & I>1 Trip A

VBC
I>1 Direction
Directional
VTS Fast Block 832 check Timer Settings
I> Blocking &
VTS Blocks I>1
763
I>1 Start B
IB

I>1 Current Set 657

& & I>1 Trip B

VCA
I>1 Direction
Directional
VTS Fast Block 832 check Timer Settings
I> Blocking &
VTS Blocks I>1
764
I>1 Start C
IC

I>1 Current Set 658

& & I >1 Trip C

VAB 761
I>1 Direction
Directional 1 I>1 Start

VTS Fast Block 832 check Timer Settings

655
I> Blocking &
1 I>1 Trip
VTS Blocks I>1

401
I>1 Timer Block
Note: For the purpose of clarity , this diagram shows the first
relevant stage number for each signal and setting name .
V00735

Figure 213: Phase Overcurrent Protection logic diagram

368 P54x1i-TM-EN-1
P543i/P545i Chapter 13 - Current Protection Functions

3 NEGATIVE SEQUENCE OVERCURRENT PROTECTION

When applying standard phase overcurrent protection, the overcurrent elements must be set significantly higher
than the maximum load current. This limits the element’s sensitivity. Most protection schemes also use an earth
fault element operating from residual current, which improves sensitivity for earth faults. However, certain faults
may arise which can remain undetected by such schemes. Negative Phase Sequence Overcurrent elements can
help in such cases.
Any unbalanced fault condition will produce a negative sequence current component. Therefore, a negative phase
sequence overcurrent element can be used for both phase-to-phase and phase-to-earth faults. Negative Phase
Sequence Overcurrent protection offers the following advantages:
● Negative phase sequence overcurrent elements are more sensitive to resistive phase-to-phase faults,
where phase overcurrent elements may not operate.
● In certain applications, residual current may not be detected by an earth fault element due to the system
configuration. For example, an earth fault element applied on the delta side of a delta-star transformer is
unable to detect earth faults on the star side. However, negative sequence current will be present on both
sides of the transformer for any fault condition, irrespective of the transformer configuration. Therefore, a
negative phase sequence overcurrent element may be used to provide time-delayed back-up protection for
any uncleared asymmetrical faults downstream.

3.1 NEGATIVE SEQUENCE OVERCURRENT PROTECTION IMPLEMENTATION

Negative Sequence Overcurrent Protection is implemented in the NEG SEQ O/C column of the relevant settings
group.
The product provides four stages of negative sequence overcurrent protection with independent time delay
characteristics.
Stages 1, 2 provide a choice of operate and reset characteristics, where you can select between:
● A range of standard IDMT (Inverse Definite Minimum Time) curves
● DT (Definite Time)

This is achieved using the cells

● I2>(n) Function for the overcurrent operate characteristic
● I2>(n) Reset Char for the overcurrent reset characteristic
where (n) is the number of the stage.
The IDMT-capable stages, (1 and 2) also provide a Timer Hold. This is configured using the cells I2>(n) tReset, where
(n) is the number of the stage. This is not applicable for curves based on the IEEE standard.
Stages 3 and 4 have definite time characteristics only.

3.2 DIRECTIONAL ELEMENT

Where negative phase sequence current may flow in either direction, directional control should be used.
Directionality is achieved by comparing the angle between the negative phase sequence voltage and the negative
phase sequence current. A directional element is available for all of the negative sequence overcurrent stages.
This is found in the I2> Direction cell for the relevant stage. It can be set to non-directional, directional forward, or
directional reverse.
A suitable characteristic angle setting (I2> Char Angle) is chosen to provide optimum performance. This setting
should be set equal to the phase angle of the negative sequence current with respect to the inverted negative
sequence voltage (–V2), in order to be at the centre of the directional characteristic.

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Chapter 13 - Current Protection Functions P543i/P545i

3.3 NPSOC LOGIC

567 I2>1 Start

I2

IDMT/DT
I2>1 Current Set 571
& & & I2>1 trip
928
CTS Block

562
I2 > Inhibit

I2 >1 Direction

V2

Directional
I2> V2pol Set
check

833
VTS Slow block
I 2> VTS Blocking &
VTS Blocks I2>1

563
I2>1 Tmr Blk
Note: For the purpose of clarity , this diagram shows the first
relevant stage number for each signal and setting name .
V 00736

Figure 214: Negative Phase Sequence Overcurrent Protection logic diagram

3.4 APPLICATION NOTES

3.4.1 SETTING GUIDELINES (CURRENT THRESHOLD)

A negative phase sequence element can be connected in the primary supply to the transformer and set as
sensitively as required to protect for secondary phase-to-earth or phase-to-phase faults. This function will also
provide better protection than the phase overcurrent function for internal transformer faults. The NPS overcurrent
protection should be set to coordinate with the low-side phase and earth elements for phase-to-earth and phase-
to-phase faults.
The current pick-up threshold must be set higher than the negative phase sequence current due to the maximum
normal load imbalance. This can be set practically at the commissioning stage, making use of the measurement
function to display the standing negative phase sequence current. The setting should be at least 20% above this
figure.
Where the negative phase sequence element needs to operate for specific uncleared asymmetric faults, a precise
threshold setting would have to be based on an individual fault analysis for that particular system due to the
complexities involved. However, to ensure operation of the protection, the current pick-up setting must be set
approximately 20% below the lowest calculated negative phase sequence fault current contribution to a specific
remote fault condition.

3.4.2 SETTING GUIDELINES (TIME DELAY)

Correct setting of the time delay for this function is vital. You should also be very aware that this element is applied
primarily to provide back-up protection to other protection devices or to provide an alarm. It would therefore
normally have a long time delay.
The time delay set must be greater than the operating time of any other protection device (at minimum fault level)
that may respond to unbalanced faults such as phase overcurrent elements and earth fault elements.

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3.4.3 SETTING GUIDELINES (DIRECTIONAL ELEMENT)

Where negative phase sequence current may flow in either direction through an IED location, such as parallel lines
or ring main systems, directional control of the element should be employed (VT models only).
Directionality is achieved by comparing the angle between the negative phase sequence voltage and the negative
phase sequence current and the element may be selected to operate in either the forward or reverse direction. A
suitable relay characteristic angle setting (I2> Char Angle) is chosen to provide optimum performance. This setting
should be set equal to the phase angle of the negative sequence current with respect to the inverted negative
sequence voltage (–V2), in order to be at the centre of the directional characteristic.
The angle that occurs between V2 and I2 under fault conditions is directly dependent on the negative sequence
source impedance of the system. However, typical settings for the element are as follows:
● For a transmission system the relay characteristic angle (RCA) should be set equal to –60°
● For a distribution system the relay characteristic angle (RCA) should be set equal to –45°

For the negative phase sequence directional elements to operate, the device must detect a polarising voltage
above a minimum threshold, I2> V2pol Set. This must be set in excess of any steady state negative phase
sequence voltage. This may be determined during the commissioning stage by viewing the negative phase
sequence measurements in the device.

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4 EARTH FAULT PROTECTION

Earth faults are overcurrent faults where the fault current flows to earth. Earth faults are the most common type of
fault.
Earth faults can be measured directly from the system by means of:
● A separate current Transformer (CT) located in a power system earth connection
● A separate Core Balance Current Transformer (CBCT), usually connected to the SEF transformer input
● A residual connection of the three line CTs, where the Earth faults can be derived mathematically by
summing the three measured phase currents.

Depending on the device model, it will provide one or more of the above means for Earth fault protection.

4.1 EARTH FAULT PROTECTION IMPLEMENTATION

Earth fault protection is implemented in the EARTH FAULT column of the relevant settings group. The element uses
quantities derived internally from summing the three-phase currents.
The product provides four stages of Earth Fault protection with independent time delay characteristics, for each
EARTH FAULT column.
Stages 1 and 2 provide a choice of operate and reset characteristics, where you can select between:
● A range of IDMT (Inverse Definite Minimum Time) curves
● DT (Definite Time)

This is achieved using the cells:

● IN>(n) Function for the overcurrent operate characteristics
● IN>(n) Reset Char for the overcurrent reset characteristic

where (n) is the number of the stage.

Stages 1 and 2 provide a Timer Hold facility. This is configured using the cells IN>(n) tReset
Stages 3 and 4 can have definite time characteristics only.
Earth fault Overcurrent IN> can be set to:
● Permanently disabled
● Permanently enabled
● Enabled only if VT fuse/MCB fails
● Enabled only if protection communication channel fails
● Enabled if VT fuse/MCB or protection communication channel fail
● Enabled if VT fuse/MCB and protection communication channel fail
Each stage can be individually inhibited with a DDB signal Inhibit IN>(n), where n is the stage number.

4.2 IDG CURVE

The IDG curve is commonly used for time delayed earth fault protection in the Swedish market. This curve is
available in stage 1 of the Earth Fault protection.
The IDG curve is represented by the following equation:

 I 
top = 5.8 − 1.35 log e  
 IN > Setting 
where:

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top is the operating time

I is the measured current
IN> Setting is an adjustable setting, which defines the start point of the characteristic

Note:
Although the start point of the characteristic is defined by the "ΙN>" setting, the actual current threshold is a different setting
called "IDG Ιs". The "IDG Ιs" setting is set as a multiple of "ΙN>".

Note:
When using an IDG Operate characteristic, DT is always used with a value of zero for the Rest characteristic.

An additional setting "IDG Time" is also used to set the minimum operating time at high levels of fault current.

10

8 IDGIsIsSetting
IDG SettingRange
Range
time (seconds)
(seconds)

6
Operating time

5
Operating

3
IDG Time
IDG Time Setting
Setting Range
Range
2

0
1 10 100
I/IN>

V00611

Figure 215: IDG Characteristic

4.3 DIRECTIONAL ELEMENT

If Earth fault current can flow in both directions through a protected location, you will need to use a directional
overcurrent element to determine the direction of the fault. Typical systems that require such protection are
parallel feeders and ring main systems.
A directional element is available for all of the Earth Fault stages. These are found in the direction setting cells for
the relevant stage. They can be set to non-directional, directional forward, or directional reverse.
Directional control can be blocked by the VTS element if required.
For standard earth fault protection, two options are available for polarisation; Residual Voltage (zero sequence) or
Negative Sequence.

4.3.1 RESIDUAL VOLTAGE POLARISATION

With earth fault protection, the polarising signal needs to be representative of the earth fault condition. As residual
voltage is generated during earth fault conditions, this quantity is commonly used to polarise directional earth
fault elements. This is known as Zero Sequence Voltage polarisation, Residual Voltage polarisation or Neutral
Displacement Voltage (NVD) polarisation.

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Small levels of residual voltage could be present under normal system conditions due to system imbalances, VT
inaccuracies, device tolerances etc. For this reason, the device includes a user settable threshold (IN> VNPol set),
which must be exceeded in order for the DEF function to become operational. The residual voltage measurement
provided in the MEASUREMENTS 1 column of the menu may assist in determining the required threshold setting
during the commissioning stage, as this will indicate the level of standing residual voltage present.

Note:
Residual voltage is nominally 180° out of phase with residual current. Consequently, the DEF elements are polarised from the
"-Vres" quantity. This 180° phase shift is automatically introduced within the device.

The directional criteria with residual voltage polarisation is given below:

● Directional forward: -90° < (angle(IN) - angle(VN + 180°) - RCA) < 90°
● Directional reverse : -90° > (angle(IN) - angle(VN + 180°) - RCA) > 90°

4.3.2 NEGATIVE SEQUENCE POLARISATION

In some applications, the use of residual voltage polarisation may be not possible to achieve, or at the very least,
problematic. For example, a suitable type of VT may be unavailable, or an HV/EHV parallel line application may
present problems with zero sequence mutual coupling.
In such situations, the problem may be solved by using Negative Phase Sequence (NPS) quantities for polarisation.
This method determines the fault direction by comparing the NPS voltage with the NPS current. The operating
quantity, however, is still residual current.
This can be used for both the derived and measured standard earth fault elements. It requires a suitable voltage
and current threshold to be set in cells IN> V2pol set and IN> I2pol set respectively.
Negative phase sequence polarising is not recommended for impedance earthed systems regardless of the type
of VT feeding the relay. This is due to the reduced earth fault current limiting the voltage drop across the negative
sequence source impedance to negligible levels. If this voltage is less than 0.5 volts the device will stop providing
directionalisation.
The directional criteria with negative sequence polarisation is given below:
● Directional forward: -90° < (angle(I2) - angle(V2 + 180°) - RCA) < 90°
● Directional reverse : -90° > (angle(I2) - angle(V2 + 180°) - RCA) > 90°

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4.4 EARTH FAULT PROTECTION LOGIC

777 IN>1 Start

IN

IDMT/ DT
IN>1 Current Set 671
& & & IN>1 Trip
CTS Block 928

467
Inhibit IN >1

IN>1 Directional

VN

IN> VNpol Set

IN Directional
check
Low Current

Residual voltage polarisation

833
VTS Slow Block
IN> Blocking &
VTS Blocks IN>1

405
IN>1 Timer Blk

V2

IN> V2pol Set

I2

IN> I2pol Set

Negative Sequence Polarisation

Note: For the purpose of clarity, this diagram shows the first
relevant stage number for each signal and setting name .
V00737

Figure 216: Earth Fault Protection logic diagram

4.5 APPLICATION NOTES

4.5.1 RESIDUAL VOLTAGE POLARISATION SETTING GUIDELINES

It is possible that small levels of residual voltage will be present under normal system conditions due to system
imbalances, VT inaccuracies, IED tolerances etc. Hence, the IED includes a user settable threshold (IN> VNPol Set)
which must be exceeded in order for the DEF function to be operational. In practice, the typical zero sequence
voltage on a healthy system can be as high as 1% (i.e. 3% residual), and the VT error could be 1% per phase. A
setting between 1% and 4% is therefore typical. The residual voltage measurement may assist in determining the
required threshold setting during commissioning, as this will indicate the level of standing residual voltage present.

4.5.2 SETTING GUIDELINES (DIRECTIONAL ELEMENT)

With directional earth faults, the residual current under fault conditions lies at an angle lagging the polarising
voltage. Hence, negative RCA settings are required for DEF applications. This is set in the cell I> Char Angle in the
relevant earth fault menu.

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We recommend the following RCA settings:

● Resistance earthed systems: 0°
● Distribution systems (solidly earthed): -45°
● Transmission systems (solidly earthed): -60°

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5 SENSITIVE EARTH FAULT PROTECTION

With some earth faults, the fault current flowing to earth is limited by either intentional resistance (as is the case
with some HV systems) or unintentional resistance (e.g. in very dry conditions and where the substrate is high
resistance, such as sand or rock).
To provide protection in such cases, it is necessary to provide an earth fault protection system with a setting that is
considerably lower than for normal line protection. Such sensitivity cannot be provided with conventional CTs,
therefore the SEF input would normally be fed from a core balance current transformer (CBCT) mounted around
the three phases of the feeder cable. The SEF transformer should be a special measurement class transformer.

5.1 SEF PROTECTION IMPLEMENTATION

The product provides four stages of SEF protection with independent time delay characteristics.
Stages 1, 2 provide a choice of operate and reset characteristics, where you can select between:
● A range of IDMT (Inverse Definite Minimum Time) curves
● DT (Definite Time)

This is achieved using the cells

● ISEF>(n) Function for the overcurrent operate characteristic
● ISEF>(n) Reset Chr for the overcurrent reset characteristic

where (n) is the number of the stage.

Stages 1 and 2 also provide a Timer Hold facility. This is configured using the cells ISEF>(n) tReset.
Stages 3 and 4 have definite time characteristics only.
Each stage can be individually inhibited with a DDB signal Inhibit ISEF>(n), where n is the stage number.

5.2 EPATR B CURVE

The EPATR B curve is commonly used for time-delayed Sensitive Earth Fault protection in certain markets. This
curve is only available in the Sensitive Earth Fault protection stages 1 and 2. It is based on primary current settings,
employing a SEF CT ratio of 100:1 A.
The EPATR_B curve has 3 separate segments defined in terms of the primary current. It is defined as follows:
Segment Primary Current Range Based on 100A:1A CT Ratio Current/Time Characteristic
1 ISEF = 0.5A to 6.0A t = 432 x TMS/ISEF 0.655 secs
2 ISEF = 6.0A to 200A t = 800 x TMS/ISEF secs
3 ISEF above 200A t = 4 x TMS secs

where TMS (time multiplier setting) is 0.025 - 1.2 in steps of 0.025.

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EPATR Curve

1000

100
Time in Secs

10

1
0.1 1 10 100 1000
Current in Primary A (CT Ratio 100A/1A)

V00616

Figure 217: EPATR B characteristic shown for TMS = 1.0

5.3 SENSITIVE EARTH FAULT PROTECTION LOGIC

777 IN>1 Start

IN

IDMT/ DT
ISEF>1 Current 671
& & & IN>1 Trip
CTS Block 928

1724
Inhibit ISEF>1

ISEF>1 Direction

VN

ISEF> VNpol Set

IN Directional
check
Low Current

Residual voltage polarisation

833
VTS Slow Block
ISEF> Blocking &
VTS Blocks IN>1

409
ISEF>1 Timer Blk

ISEF> Blocking
AR Blks ISEF>3 *

Note: For the purpose of clarity , this diagram shows the first
V00738 * Stages 3 and 4 only relevant stage number for each signal and setting name .

Figure 218: Sensitive Earth Fault Protection logic diagram

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5.4 APPLICATION NOTES

5.4.1 INSULATED SYSTEMS

When insulated systems are used, it is not possible to detect faults using standard earth fault protection. It is
possible to use a residual overvoltage device to achieve this, but even with this method full discrimination is not
possible. Fully discriminative earth fault protection on this type of system can only be achieved by using a SEF
(Sensitive Earth Fault) element. This type of protection detects the resultant imbalance in the system charging
currents that occurs under earth fault conditions. A core balanced CT must be used for this application. This
eliminates the possibility of spill current that may arise from slight mismatches between residually connected line
CTs. It also enables a much lower CT ratio to be applied, thereby allowing the required protection sensitivity to be
more easily achieved.
The following diagram shows an insulated system with a C-phase fault.

Ia1
Ib1

IR1
jXc1

IH1
Ia2
Ib2

IR2
jXc2

IH2

Ia3
Ib3
IH1 + IH2 + IH3

IR3
jXc3

IR3 = IH1 + IH2 + IH3 - IH3 IH3 IH1 + IH2

IR3 = IH1 + IH2

E00627

Figure 219: Current distribution in an insulated system with C phase fault

The protection elements on the healthy feeder see the charging current imbalance for their own feeder. The
protection element on the faulted feeder, however, sees the charging current from the rest of the system (IH1 and
IH2 in this case). Its own feeder's charging current (IH3) is cancelled out.
With reference to the associated vector diagram, it can be seen that the C-phase to earth fault causes the
voltages on the healthy phases to rise by a factor of √3. The A-phase charging current (Ia1), leads the resultant A
phase voltage by 90°. Likewise, the B-phase charging current leads the resultant Vb by 90°.

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Vaf
Restrain
Vapf
IR1
Ib1

Operate
Ia1
Vbf

Vcpf Vbpf

Vres
(= 3Vo)

An RCA setting of ±90º shifts the

“centre of the characteristic” to here IR3 = (IH1 + IH2)
E00628

Figure 220: Phasor diagrams for insulated system with C phase fault

The current imbalance detected by a core balanced current transformer on the healthy feeders is the vector
addition of Ia1 and Ib1. This gives a residual current which lags the polariing voltage (–3Vo) by 90°. As the healthy
phase voltages have risen by a factor of Ö3, the charging currents on these phases are also Ö3 times larger than
their steady state values. Therefore, the magnitude of the residual current IR1, is equal to 3 times the steady state
per phase charging current.
The phasor diagram indicates that the residual currents on the healthy and faulted feeders (IR1 and IR3
respectively) are in anti-phase. A directional element (if available) could therefore be used to provide discriminative
earth fault protection.
If the polarising is shifted through +90°, the residual current seen by the relay on the faulted feeder will lie within
the operate region of the directional characteristic and the current on the healthy feeders will fall within the
restrain region.
The required characteristic angle setting for the SEF element when applied to insulated systems, is +90°. This is for
the case when the protection is connected such that its direction of current flow for operation is from the source
busbar towards the feeder. If the forward direction for operation were set such that it is from the feeder into the
busbar, then a –90° RCA would be required.

Note:
Discrimination can be provided without the need for directional control. This can only be achieved, however, if it is possible to
set the IED in excess of the charging current of the protected feeder and below the charging current for the rest of the system.

5.4.2 SETTING GUIDELINES (INSULATED SYSTEMS)

The residual current on the faulted feeder is equal to the sum of the charging currents flowing from the rest of the
system. Further, the addition of the two healthy phase charging currents on each feeder gives a total charging
current which has a magnitude of three times the per phase value. Therefore, the total imbalance current is equal
to three times the per phase charging current of the rest of the system. A typical setting may therefore be in the
order of 30% of this value, i.e. equal to the per phase charging current of the remaining system. Practically though,
the required setting may well be determined on site, where suitable settings can be adopted based on practically
obtained results.
When using a core-balanced transformer, care must be taken in the positioning of the CT with respect to the
earthing of the cable sheath:

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Cable gland

Cable box

Cable gland/shealth
earth connection

“Incorrect”

No operation
SEF

“Correct”

Operation
SEF

E00614

Figure 221: Positioning of core balance current transformers

If the cable sheath is terminated at the cable gland and directly earthed at that point, a cable fault (from phase to
sheath) will not result in any unbalanced current in the core balance CT. Therefore, prior to earthing, the
connection must be brought back through the CBCT and earthed on the feeder side. This then ensures correct
relay operation during earth fault conditions.

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6 HIGH IMPEDANCE REF

The device provides a high impedance restricted earth fault protection function. An external resistor is required to
provide stability in the presence of saturated line current transformers. Current transformer supervision signals do
not block the high impedance REF protection. The appropriate logic must be configured in PSL to block the high
impedance REF when any of the above signals is asserted.

6.1 HIGH IMPEDANCE REF PRINCIPLE

This scheme is very sensitive and can protect against low levels of fault current, typical of winding faults.
High Impedance REF protection is based on the differential principle. It works on the circulating current principle as
shown in the following diagram.

Healthy CT Saturated CT
Protected
circuit

A-G
Zm1 Zm2
I = Is + IF
RCT1 RCT2

I IF

RL1 IS RL3

Vs RST

R
RL2 RL4

V00671

Figure 222: High Impedance REF principle

When subjected to heavy through faults the line current transformer may enter saturation unevenly, resulting in
imbalance. To ensure stability under these conditions a series connected external resistor is required, so that most
of the unbalanced current will flow through the saturated CT. As a result, the current flowing through the device
will be less than the setting, therefore maintaining stability during external faults.
Voltage across REF element Vs = IF (RCT2 + RL3 + RL4)
Stabilising resistor RST = Vs/Is –RR
where:
● IF = maximum secondary through fault current
● RR = device burden
● RCT = CT secondary winding resistance
● RL2 and RL3 = Resistances of leads from the device to the current transformer
● RST = Stabilising resistor

High Impedance REF can be used for either delta windings or star windings in both solidly grounded and
resistance grounded systems. The connection to a modern IED are as follows:

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Phase A
Phase A
Phase B
Phase B
Phase C
Phase C

I Phase A

I Phase B

I Phase C
RSTAB I Neutral

I Neutral RSTAB
IED IED

Connecting IED to star winding for High Connecting IED to delta winding for High
Impedance REF Impedance REF

V00680

Figure 223: High Impedance REF Connection

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7 THERMAL OVERLOAD PROTECTION

The heat generated within an item of plant is the resistive loss. The thermal time characteristic is therefore based
on the equation I2Rt. Over-temperature conditions occur when currents in excess of their maximum rating are
allowed to flow for a period of time.
Temperature changes during heating follow exponential time constants. The device provides two characteristics
for thermal overload protection; a single time constant characteristic and a dual time constant characteristic. You
select these according to the application.

7.1 SINGLE TIME CONSTANT CHARACTERISTIC

This characteristic is used to protect cables, dry type transformers and capacitor banks.
The single constant thermal characteristic is given by the equation:

 I 2 − ( KI FLC )2 
t = −τ log  
 I 2 − I p2 
e  
where:
● t = time to trip, following application of the overload current I
● t = heating and cooling time constant of the protected plant
● I = largest phase current
● IFLC full load current rating (the Thermal Trip setting)
● K = a constant with the value of 1.05
● Ip = steady state pre-loading before application of the overload

7.2 DUAL TIME CONSTANT CHARACTERISTIC

This characteristic is used to protect equipment such as oil-filled transformers with natural air cooling. The thermal
model is similar to that with the single time constant, except that two timer constants must be set.
For marginal overloading, heat will flow from the windings into the bulk of the insulating oil. Therefore, at low
current, the replica curve is dominated by the long time constant for the oil. This provides protection against a
general rise in oil temperature.
For severe overloading, heat accumulates in the transformer windings, with little opportunity for dissipation into
the surrounding insulating oil. Therefore at high current levels, the replica curve is dominated by the short time
constant for the windings. This provides protection against hot spots developing within the transformer windings.
Overall, the dual time constant characteristic serves to protect the winding insulation from ageing and to minimise
gas production by overheated oil. Note however that the thermal model does not compensate for the effects of
ambient temperature change.
The dual time constant thermal characteristic is given by the equation:

( − t / τ1 ) ( −t / τ 2 )
 I 2 − ( KI FLC )2 
0.4e + 0.6e = 2 2

 I − I p 

where:
● t1 = heating and cooling time constant of the transformer windings
● t2 = heating and cooling time constant of the insulating oil

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7.3 THERMAL OVERLOAD PROTECTION IMPLEMENTATION

The device incorporates a current-based thermal characteristic, using RMS load current to model heating and
cooling of the protected plant. The element can be set with both alarm and trip stages.
Thermal Overload Protection is implemented in the THERMAL OVERLOAD column of the relevant settings group.
This column contains the settings for the characteristic type, the alarm and trip thresholds and the time constants.

7.4 THERMAL OVERLOAD PROTECTION LOGIC

IA
IB Max RMS
Thermal State
IC

Thermal Trip
680
Thermal Trip
Characteristic Thermal trip
Disabled Thermal threshold
Single Calculation
Dual

Time Constant 1

Time Constant 2

445
Reset Thermal
785
Thermal Alarm
Thermal Alarm

V00630

Figure 224: Thermal overload protection logic diagram

The magnitudes of the three phase input currents are compared and the largest magnitude is taken as the input
to the thermal overload function. If this current exceeds the thermal trip threshold setting a start condition is
asserted.
The Start signal is applied to the chosen thermal characteristic module, which has three outputs signals; alarm trip
and thermal state measurement. The thermal state measurement is made available in one of the MEASUREMENTS
columns.
The thermal state can be reset by either an opto-input (if assigned to this function using the programmable
scheme logic) or the HMI panel menu.

7.5 APPLICATION NOTES

7.5.1 SETTING GUIDELINES FOR DUAL TIME CONSTANT CHARACTERISTIC

The easiest way of solving the dual time constant thermal equation is to express the current in terms of time and
to use a spreadsheet to calculate the current for a series of increasing operating times using the following
equation, then plotting a graph.

0.4 I p 2 .e( − t /τ 1) + 0.6 I p 2 .e( − t /τ 2) − k 2 .I FLC 2

I=
0.4e( − t / + 0.6e( − t /τ 2) − 1
τ 1)

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Figures based
on equation

E00728

Figure 225: Spreadsheet calculation for dual time constant thermal characteristic

100000

10000 Time constant 1 = 5 mins

Operating Time (seconds)

Time constant 2 = 120 mins

Pre-overload current = 0.9 pu
Thermal setting = 1 Amp
1000

100

10

1
1 10
Current as a Multiple of Thermal Setting

V00629

Figure 226: Dual time constant thermal characteristic

The current setting is calculated as:

Thermal Trip = Permissible continuous loading of the transformer item/CT ratio.
For an oil-filled transformer with rating 400 to 1600 kVA, the approximate time constants are:
● t1 = 5 minutes
● t2 = 120 minutes
An alarm can be raised on reaching a thermal state corresponding to a percentage of the trip threshold. A typical
setting might be "Thermal Alarm" = 70% of thermal capacity.

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Note:
The thermal time constants given in the above tables are typical only. Reference should always be made to the plant
manufacturer for accurate information.

7.5.2 SETTING GUIDELINES FOR SINGLE TIME CONSTANT CHARACTERISTIC

The time to trip varies depending on the load current carried before application of the overload, i.e. whether the
overload was applied from hot or cold.
The thermal time constant characteristic may be rewritten as:

θ − θ p 
e( − t / τ ) =  
e 
θ −1 

where:
● θ = thermal state = I2/K2IFLC2
● θp = pre-fault thermal state = Ip2/K2IFLC2

● Ip is the pre-fault thermal state

● IFLC is the full load current

Note:
A current of 105%Is (KIFLC) has to be applied for several time constants to cause a thermal state measurement of 100%.

The current setting is calculated as:

Thermal Trip = Permissible continuous loading of the plant item/CT ratio.
The following tables show the approximate time constant in minutes, for different cable rated voltages with
various conductor cross-sectional areas, and other plant equipment.

Area mm2 6 - 11 kV 22 kV 33 kV 66 kV
25 – 50 10 minutes 15 minutes 40 minutes –
70 – 120 15 minutes 25 minutes 40 minutes 60 minutes
150 25 minutes 40 minutes 40 minutes 60 minutes
185 25 minutes 40 minutes 60 minutes 60 minutes
240 40 minutes 40 minutes 60 minutes 60 minutes
300 40 minutes 60 minutes 60 minutes 90 minutes

Plant type Time Constant (Minutes)

Dry-type transformer <400 kVA 40
Dry-type transformers 400 – 800 kVA 60 - 90
Air-core Reactors 40
Capacitor Banks 10

Overhead Lines with cross section > 100 mm2 10

Overhead Lines 10
Busbars 60

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8 BROKEN CONDUCTOR PROTECTION

One type of unbalanced fault is the 'Series' or 'Open Circuit' fault. This type of fault can arise from, among other
things, broken conductors. Series faults do not cause an increase in phase current and so cannot be detected by
overcurrent protection. However, they do produce an imbalance, resulting in negative phase sequence current,
which can be detected.
It is possible to apply a negative phase sequence overcurrent element to detect broken conductors. However, on a
lightly loaded line, the negative sequence current resulting from a series fault condition may be very close to, or
less than, the full load steady state imbalance arising from CT errors and load imbalances, making it very difficult
to distinguish. A regular negative sequence element would therefore not work at low load levels. To overcome this,
the device incorporates a special Broken Conductor protection element.
The Broken Conductor element measures the ratio of negative to positive phase sequence current (I2/I1). This ratio
is approximately constant with variations in load current, therefore making it more sensitive to series faults than
standard negative sequence protection.

8.1 BROKEN CONDUCTOR PROTECTION IMPLEMENTATION

Broken Conductor protection is implemented in the BROKEN CONDUCTOR column of the relevant settings group.
This column contains the settings to enable the function, for the pickup threshold and the time delay.

8.2 BROKEN CONDUCTOR PROTECTION LOGIC

The ratio of I2/I1 is calculated and compared with the threshold setting. If the threshold is exceeded, the delay
timer is initiated. The CTS block signal is used to block the operation of the delay timer.

I2/I1

679
I 2/I1 Setting & Broken Wire Trip

I2

Low Current

928
CTS Block

V00739

Figure 227: Broken conductor logic

8.3 APPLICATION NOTES

8.3.1 SETTING GUIDELINES

For a broken conductor affecting a single point earthed power system, there will be little zero sequence current
flow and the ratio of I2/I1 that flows in the protected circuit will approach 100%. In the case of a multiple earthed
power system (assuming equal impedance’s in each sequence network), the ratio I2/I1 will be 50%.
In practise, the levels of standing negative phase sequence current present on the system govern this minimum
setting. This can be determined from a system study, or by making use of the measurement facilities at the
commissioning stage. If the latter method is adopted, it is important to take the measurements during maximum
system load conditions, to ensure that all single-phase loads are accounted for.

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Note:
A minimum value of 8% negative phase sequence current is required for successful operation.

Since sensitive settings have been employed, we can expect that the element will operate for any unbalanced
condition occurring on the system (for example, during a single pole autoreclose cycle). For this reason, a long time
delay is necessary to ensure co-ordination with other protection devices. A 60 second time delay setting may be
typical.
The following example was recorded by an IED during commissioning:
Ifull load = 500A
I2 = 50A
therefore the quiescent I2/I1 ratio = 0.1
To allow for tolerances and load variations a setting of 20% of this value may be typical: Therefore set:
I2/I1 = 0.2
In a double circuit (parallel line) application, using a 40% setting will ensure that the broken conductor protection
will operate only for the circuit that is affected. A setting of 0.4 results in no pick-up for the parallel healthy circuit.
Set I2/I1 Time Delay = 60 s to allow adequate time for short circuit fault clearance by time delayed protections.

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9 TRANSIENT EARTH FAULT DETECTION

Some distribution systems run completely insulated from earth. Such systems are called unearthed systems. The
advantage of an unearthed system is that a single phase to earth fault does not cause an earth fault current to
flow. This means the whole system remains operational and the supply is not interrupted. The system must be
designed to withstand high transient and steady state overvoltages, however, and so its use is generally restricted
to low and medium voltage distribution systems.
When there is an earth fault in an unearthed 3-phase system, the voltage of the faulted phase is reduced to the
earth potential. This causes the phase voltage in the other two phases to increase, which causes a significant
charging current between the phase-to-earth capacitances. This can cause arcing at the fault location. Many
systems use a Petersen coil to compensate for this, thus eliminating the arcing problem. Such systems are called
compensated networks. The network is earthed with an inductive reactor, where its reactance is made nominally
equal to the total system capacitance to earth. Under this condition, a single-phase earth fault does not result in
any steady state earth fault current.
The introduction of a Petersen coil introduces major difficulties when it comes to determining the direction of the
fault. This is because the faulted line current is the sum of the inductive current introduced by the Petersen coil
and the capacitive current of the line, which are in anti-phase with each other. If they are equal in magnitude, the
current in the faulted line is zero. If the inductive current is larger than capacitance current, the direction of the
faulted line current will appear to be in the same direction as that of the healthy line.
Standard directionalizing techniques used by conventional feeder protection devices are not adequate for this
scenario, therefore we need a different method for determining the direction of the fault. Two commonly used
methods are the First Half Wave method and the Residual Active Power method.

First Half Wave Method

The initial transient wave, generated at the fault point travels towards the bus along the faulted line, until it
reaches the healthy line. For forward faults the high frequency fault voltage and current components are in
opposite directions during the first half wave, whereas for reverse faults, they are in phase. This fact can be used to
determine the fault direction. This method, however, is subject to the following disadvantages:
● The time duration of the characteristic is very short, in most cases not more than 3 ms. Because of this, it
requires a high sampling frequency (3000Hz or even higher)
● It requires an analogue high pass filter, necessitating special hardware
● It is affected by the fault inception angle. For example, when the fault inception angle is 0°, there are no
initial travelling waves.

Residual Active Power Method

Residual Active power, which is sometimes used to detect the instance of a fault can also in some cases be used
for detecting the fault direction. Although the capacitive currents can be compensated by an inductive current
generated by a Petersen coil, the active (instantaneous) current can never be compensated for and this is still
opposite to that of the healthy line. This fact can also be used to directionalise the fault.
For a forward directional fault, the zero-sequence active power is the power loss of Petersen’s coil, which is
negative. For a reverse fault, the zero-sequence active power is the power loss of the transmission line, which is
positive. This method, however, is subject to the following disadvantages:
● The zero-sequence active power will be very small in magnitude for a reverse directional fault. Its value
depends on the power loss of transmission line.
● The zero-sequence active power may be too small in magnitude to be detected for a forward directional
fault. Its value depends on the power loss of Petersen coil.
● High resolution CTs are required
Due to the low magnitude of measured values, reliability is compromised

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This product does not use the above techniques for directionalisation. This product uses an innovative patented
technique called Transient Reactive Power protection to determine the fault direction of earth faults in
compensated networks.

9.1 TRANSIENT EARTH FAULT DETECTION IMPLEMENTATION

Transient Earth Fault Detection (TEFD) in this device comprises three modules:
● Transient Earth Fault Detection module (TEF)
● Fault Type Detector (FTD)
● Direction Detector (DD)

Note:
In this product, TEFD is implemented for 50Hz only.

9..1 TRANSIENT EARTH FAULT DETECTOR

To establish that there is some kind of earth fault on the system somewhere is straightforward. A simple residual
overvoltage comparison can determine this. Therefore a TEF> Start signal is produced by comparing the neutral
voltage with a threshold voltage set by TEF VN> Start in the TEF DETECTION column. The difficulty comes with
establishing the type of fault and its direction.

9..2 FAULT TYPE DETECTOR

The FTD uses a Fundamental analysis (FA) technique to establish whether the fault is an intermittent fault or a
steady state faults. For Transient Earth Fault Detection, the detector counts the Residual Voltage bursts within a
specified time window. With some clever signal processing the detector module creates pulses by comparing the
bursts with a settable threshold, then counts these pulses. If the number of pulses exceeds the number specified
by the FTD> Fault Count setting, within the time window specified by FTD> Time Window, the fault is deemed to
be intermittent and the TEF> Intermit DDB signal is asserted. If there are fewer pulses than this number, this
indicates either a disturbance or a permanent fault. To establish which, we need to look at the RMS value of the
residual voltage.
If there are fewer pulses than specified and the RMS value does not draw back within the specified time window,
the fault is deemed to be permanent. In this case the TEF> Steady DDB signal is asserted.
If there are fewer pulses than specified and the RMS value does draw back, this indicates that a disturbance has
been detected but it is not a fault. In this case, the TEF> Steady DDB signal is not asserted.
The inputs to this module are:
● The residual voltage
● FTD> VN (defines the threshold which converts the residual voltage burst into a pulse
● FTD> Time Window (defines the time window - default is 2 seconds)
● FTD> Fault Count (defines the fault count)

The FTD outputs two signals to indicate whether the fault is steady state or intermittent.

9..3 DIRECTION DETECTOR

The Direction Detector uses a patented technique based on Transient Reactive Power to establish the direction of
the fault. Unlike traditional methods, this TRP method does not require high resolution CTs or special analogue
filtering hardware and is therefore cheaper to implement.
It can be shown that the residual voltage and residual current components are largest at 220 Hz. Also, in the
forward direction, the residual voltage leads the residual current by 90°, and in the reverse direction the residual
voltage lags the residual current by 90°. These criteria can be used to directionalize the fault.

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The residual voltage (Vres) is passed through a bandpass filter tuned to 220 Hz, which also adds 90° to it. The
residual current (Ires) is also passed through a 220 Hz bandpass filter, but no phase shift is applied. The resulting
components which we shall call VH1 and IH2 are therefore in antiphase with each other for forward faults and in
phase if the forward line is not faulted.
The VH1 and IH2 components are passed through a sign filter and multiplied to create a reactive power
component in the range of -1 to +1. This is the transient reactive power Qtran. If Qtran > 0, then there forward line is
healthy. If Qtran < 0, then the forward line is faulty.
There are two modes of operation for the direction detector; Standard and Advanced. Standard mode is used in
most cases and is described here. Advanced mode is for special situations, and involves dynamically altering the
Qtran thresholds. For details of Advanced mode, please contact General Electric.
The inputs to this module are:
● The residual voltage
● The residual current
● Dir> Vnf Thresh (defines the threshold for the residual voltage sign filter).
● Dir> Inf Thresh (defines the threshold for the residual current sign filter

The DD outputs two signals to indicate a forward fault and a reverse fault
Sign Filter Thresholds
The Dir> Vnf Thresh setting is used to get the sign of instantaneous voltage value by sign filter. If the input value is
larger than Vnf, the output is +1. If the input value is less than -1*Vnf, the output is -1. Otherwise the output is 0.
The Dir> Inf Thresh setting is used to get the sign of instantaneous current value by sign filter. If the input value is
larger than Vnf, the output is +1. If the input value is less than -1*Vnf, the output is -1. Otherwise the output is 0.

9.2 TRANSIENT EARTH FAULT DETECTION LOGIC

9.2.1 TRANSIENT EARTH FAULT DETECTION LOGIC OVERVIEW

VN

TEF VN> Start & TEF> Start

TEF Detection
Enabled

TEF> Timer Block

VN Steady & TEF> Steady

FTD> VN
FA
FTD> Time Window Fault Type
Detector Module
FTD> Fault Count
Intermittent & TEF> Intermit
FTD> Status
Enabled

VN Forward & TEF>DIR FWD

IN
TRP
Dir>Vnf Thresh Direction
Detector Module
Dir>Inf Thresh
Reverse & TEF>DIR REV
TEF>Dir Status
Enabled
V00905

Figure 228: Transient Earth Fault Logic Overview

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9.2.2 FAULT TYPE DETECTOR LOGIC

VNRMS Average -
VN RMS low pass
filter
Ʃ Pulse
Permanent
Decision Intermittent
+ Counter
Disturbance

FTD> VN

FTD> Fault Count

FTD> Time Window

V00906

Figure 229: Fault Type Detector Logic

9.2.3 DIRECTION DETECTOR LOGIC - STANDARD MODE

220Hz VH1 Sign filter

Add 90°
VN phase shift -0.1
Forward (faulty)
Dir>Vnf Thresh

220Hz
I H2 Sign filter
X ò Qtran

IN Reverse (healthy)

0.04
Dir>Inf Thresh

Note: In standard mode , Qtran comparison threshold is fixed at -0. 1 for the
forward direction and +0 .04 for the reverse direction .
V00907

Figure 230: Direction Detector Logic - Standard Mode

9.2.4 TRANSIENT EARTH FAULT DETECTION OUTPUT ALARM LOGIC

TEF Alarm Logic

&
S
Q TEF Alarm Output
& R
t
TEF> Start
0 1
TEF> tRESET

Reset TEF V00909

Figure 231: TEFD output alarm logic

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VOLTAGE PROTECTION FUNCTIONS

Chapter 14 - Voltage Protection Functions P543i/P545i

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1 CHAPTER OVERVIEW
The device provides a wide range of voltage protection functions. This chapter describes the operation of these
functions including the principles, logic diagrams and applications.
This chapter contains the following sections:
Chapter Overview 397
Undervoltage Protection 398
Overvoltage Protection 401
Compensated Overvoltage 404
Residual Overvoltage Protection 405

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2 UNDERVOLTAGE PROTECTION
Undervoltage conditions may occur on a power system for a variety of reasons, some of which are outlined below:
● Undervoltage conditions can be related to increased loads, whereby the supply voltage will decrease in
magnitude. This situation would normally be rectified by voltage regulating equipment such as AVRs (Auto
Voltage Regulators) or On Load Tap Changers. However, failure of this equipment to bring the system
voltage back within permitted limits leaves the system with an undervoltage condition, which must be
cleared.
● If the regulating equipment is unsuccessful in restoring healthy system voltage, then tripping by means of
an undervoltage element is required.
● Faults occurring on the power system result in a reduction in voltage of the faulty phases. The proportion by
which the voltage decreases is dependent on the type of fault, method of system earthing and its location.
Consequently, co-ordination with other voltage and current-based protection devices is essential in order to
achieve correct discrimination.
● Complete loss of busbar voltage. This may occur due to fault conditions present on the incomer or busbar
itself, resulting in total isolation of the incoming power supply. For this condition, it may be necessary to
isolate each of the outgoing circuits, such that when supply voltage is restored, the load is not connected.
Therefore, the automatic tripping of a feeder on detection of complete loss of voltage may be required. This
can be achieved by a three-phase undervoltage element.
● Where outgoing feeders from a busbar are supplying induction motor loads, excessive dips in the supply
may cause the connected motors to stall, and should be tripped for voltage reductions that last longer than
a pre-determined time.

2.1 UNDERVOLTAGE PROTECTION IMPLEMENTATION

Undervoltage Protection is implemented in the VOLT PROTECTION column of the relevant settings group. The
Undervoltage parameters are contained within the sub-heading UNDERVOLTAGE.
The product provides two stages of Undervoltage protection with independent time delay characteristics.
Stage 1 provides a choice of operate characteristics, where you can select between:
● An IDMT characteristic
● DT (Definite Time)

You set this using the V<1 Function setting.

The IDMT characteristic is defined by the following formula:
t = K/( M-1)
where:
● K = Time multiplier setting
● t = Operating time in seconds
● M = Measured voltage / IED setting voltage (V<(n) Voltage Set)

The undervoltage stages can be configured either as phase-to-neutral or phase-to-phase voltages in the V<
Measur't Mode cell.
There is no Timer Hold facility for Undervoltage.
Stage 2 can have definite time characteristics only. This is set in the V<2 Status cell.
Outputs are available for single or three-phase conditions via the V< Operate Mode cell for each stage.

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2.2 UNDERVOLTAGE PROTECTION LOGIC

V< Measur't Mode
789
VA V<1 Start A/AB
VAB
V<1 Voltage Set & 684
& V <1 Trip A/AB

V<1 Time Delay

V< Measur't Mode

790
VB V<1 Start B/BC
VBC
V<1 Voltage Set & 685
& V<1 Trip B/BC

V<1 Time Delay

V< Measur't Mode

791
VC V<1 Start C/CA
VCA
V<1 Voltage Set & 686
& V<1 Trip C/CA

V<1 Time Delay

1
&
890
All Poles Dead 788
1 V<1 Start
V<1 Poledead Inh &
& &
Enabled

832
VTS Fast Block 1
&
414
V<1 Timer Block 1 683
V<1 Trip
&
V< Operate Mode &
Any Phase
Three Phase

Note: This diagram does not show all stages . Other stages follow similar principles.
VTS Fast Block only applies for directional models .
V00803

Figure 232: Undervoltage - single and three phase tripping mode (single stage)

The Undervoltage protection function detects when the voltage magnitude for a certain stage falls short of a set
threshold. If this happens a Start signal, signifying the "Start of protection", is produced. This Start signal can be
blocked by the VTS Fast Block signal and an All Poles Dead signal. This Start signal is applied to the timer module
to produce the Trip signal, which can be blocked by the undervoltage timer block signal (V<(n) Timer Block). For
each stage, there are three Phase undervoltage detection modules, one for each phase. The three Start signals
from each of these phases are OR'd together to create a 3-phase Start signal (V<(n) Start), which can be be
activated when any of the three phases start (Any Phase), or when all three phases start (Three Phase), depending
on the chosen V< Operate Mode setting.
The outputs of the timer modules are the trip signals which are used to drive the tripping output relay. These
tripping signals are also OR'd together to create a 3-phase Trip signal, which are also controlled by the V< Operate
Mode setting.
If any one of the above signals is low, or goes low before the timer has counted out, the timer module is inhibited
(effectively reset) until the blocking signal goes high.
In some cases, we do not want the undervoltage element to trip; for example, when the protected feeder is de-
energised, or the circuit breaker is opened, an undervoltage condition would obviously be detected, but we would
not want to start protection. To cater for this, an All Poles Dead signal blocks the Start signal for each phase. This
is controlled by the V<Poledead Inh cell, which is included for each of the stages. If the cell is enabled, the relevant
stage will be blocked by the integrated pole dead logic. This logic produces an output when it detects either an

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open circuit breaker via auxiliary contacts feeding the opto-inputs or it detects a combination of both
undercurrent and undervoltage on any one phase.

2.3 APPLICATION NOTES

2.3.1 UNDERVOLTAGE SETTING GUIDELINES

In most applications, undervoltage protection is not required to operate during system earth fault conditions. If this
is the case you should select phase-to-phase voltage measurement, as this quantity is less affected by single-
phase voltage dips due to earth faults.
The voltage threshold setting for the undervoltage protection should be set at some value below the voltage
excursions that may be expected under normal system operating conditions. This threshold is dependent on the
system in question but typical healthy system voltage excursions may be in the order of 10% of nominal value.
The same applies to the time setting. The required time delay is dependent on the time for which the system is able
to withstand a reduced voltage.
If motor loads are connected, then a typical time setting may be in the order of 0.5 seconds.

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3 OVERVOLTAGE PROTECTION
Overvoltage conditions are generally related to loss of load conditions, whereby the supply voltage increases in
magnitude. This situation would normally be rectified by voltage regulating equipment such as AVRs (Auto Voltage
Regulators) or On Load Tap Changers. However, failure of this equipment to bring the system voltage back within
permitted limits leaves the system with an overvoltage condition which must be cleared.

Note:
During earth fault conditions on a power system there may be an increase in the healthy phase voltages. Ideally, the system
should be designed to withstand such overvoltages for a defined period of time.

3.1 OVERVOLTAGE PROTECTION IMPLEMENTATION

Overvoltage Protection is implemented in the VOLT PROTECTION column of the relevant settings group. The
Overvoltage parameters are contained within the sub-heading OVERVOLTAGE.
The product provides two stages of overvoltage protection with independent time delay characteristics.
Stage 1 provides a choice of operate characteristics, where you can select between:
● An IDMT characteristic
● DT (Definite Time)

You set this using the V>1 Function setting.

The IDMT characteristic is defined by the following formula:
t = K/( M - 1)
where:
● K = Time multiplier setting
● t = Operating time in seconds
● M = Measured voltage setting voltage (V>(n) Voltage Set)

The overvoltage stages can be configured either as phase-to-neutral or phase-to-phase voltages in the V>
Measur't Mode cell.
There is no Timer Hold facility for Overvoltage.
Stage 2 can have definite time characteristics only. This is set in the V>2 Status cell.
Outputs are available for single or three-phase conditions via the V> Operate Mode cell for each stage.

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3.2 OVERVOLTAGE PROTECTION LOGIC

V> Measur't Mode
V>1 Start A/AB
VA
VAB
V>1 Voltage Set & V >1 Trip A/AB

V>1 Time Delay

V> Measur't Mode

V>1 Start B/BC
VB
VBC
V>1 Voltage Set & V>1 Trip B/BC

V>1 Time Delay

V> Measur't Mode

V>1 Start C/CA
VC
VCA
V>1 Voltage Set & V>1 Trip C/CA

V>1 Time Delay 1

&
1 V>1 Start
&
&

1
&
V>1 Timer Block 1 V>1 Trip
&
V> Operate mode &
Any Phase
Three Phase
Notes: This diagram does not show all stages . Other stages follow similar principles.
VTS Fast Block only applies for directional models .
V 00804

Figure 233: Overvoltage - single and three phase tripping mode (single stage)

The Overvoltage protection function detects when the voltage magnitude for a certain stage exceeds a set
threshold. If this happens a Start signal, signifying the "Start of protection", is produced. This Start signal can be
blocked by the VTS Fast Block signal. This start signal is applied to the timer module to produce the Trip signal,
which can be blocked by the overvoltage timer block signal (V>(n) Timer Block). For each stage, there are three
Phase overvoltage detection modules, one for each phase. The three Start signals from each of these phases are
OR'd together to create a 3-phase Start signal (V>(n) Start), which can then be activated when any of the three
phases start (Any Phase), or when all three phases start (Three Phase), depending on the chosen V> Operate Mode
setting.
The outputs of the timer modules are the trip signals which are used to drive the tripping output relay. These
tripping signals are also OR'd together to create a 3-phase Trip signal, which are also controlled by the V> Operate
Mode setting.
If any one of the above signals is low, or goes low before the timer has counted out, the timer module is inhibited
(effectively reset) until the blocking signal goes high.

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3.3 APPLICATION NOTES

3.3.1 OVERVOLTAGE SETTING GUIDELINES

The provision of multiple stages and their respective operating characteristics allows for a number of possible
applications:
● Definite Time can be used for both stages to provide the required alarm and trip stages.
● Use of the IDMT characteristic allows grading of the time delay according to the severity of the overvoltage.
As the voltage settings for both of the stages are independent, the second stage could then be set lower
than the first to provide a time-delayed alarm stage.
● If only one stage of overvoltage protection is required, or if the element is required to provide an alarm only,
the remaining stage may be disabled.

This type of protection must be co-ordinated with any other overvoltage devices at other locations on the system.

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4 COMPENSATED OVERVOLTAGE
The Compensated Overvoltage function calculates the positive sequence voltage at the remote terminal using the
positive sequence local current and voltage and the line impedance and susceptance. This can be used on long
transmission lines where Ferranti Overvoltages can develop under remote circuit breaker open conditions.
The Compensated overvoltage protection function can be set in the VOLT PROTECTION column under the sub
heading COMP OVERVOLTAGE. The remote voltage is calculated using line impedance settings and the line
charging admittance in the LINE PARAMETERS column.
The IED uses the [A,B,C,D] transmission line equivalent model given the following parameters:
● Total Impedance Z = zÐq ohms
● Total Susceptance Y = yÐ90°
● Line Length l

The remote voltage is calculated using the following equations:

Vr   D − C  Vs 
 = × 
Ir
   − BA   Is 
where
● Vr is the voltage at the receiving end
● Ir is the current at the receiving end
● Vs is the measured voltage at the sending end
● Is is the measured current at the sending end
● A= D = cosh(y.l)
● B = Zc.sinh(y.l)
● C = Yc.sinh(y.l)
● y.l = Ö(Z.Y)
● Zc = 1/Yc = Ö(Z/Y)
● Y = total line capacitive charging susceptance
● Zc = characteristic impedance of the line (surge impedance)

There are two stages to provide both alarm and trip stages where required. Both stages can be set independently.
Stage 1 can be set to IDMT, DT or Disabled, in the V1>1 Cmp Funct cell. Stage 2 is DT only and is enabled or
disabled in the V1>2 Cmp Status cell.
The IDMT characteristic on the first stage is defined by the following formula:
t = K/(M - 1)
where:
● K = Time multiplier setting
● t =Operating time in seconds
● M = Remote Calculated voltage / IED setting voltage

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5 RESIDUAL OVERVOLTAGE PROTECTION

On a healthy three-phase power system, the sum of the three-phase to earth voltages is nominally zero, as it is the
vector sum of three balanced vectors displaced from each other by 120°. However, when an earth fault occurs on
the primary system, this balance is upset and a residual voltage is produced. This condition causes a rise in the
neutral voltage with respect to earth. Consequently this type of protection is also commonly referred to as 'Neutral
Voltage Displacement' or NVD for short.
This residual voltage may be derived (from the phase voltages) or measured (from a measurement class open
delta VT). Derived values will normally only be used where the model does not support measured functionality (a
dedicated measurement class VT). If a measurement class VT is used to produce a measured Residual Voltage, it
cannot be used for other features such as Check Synchronisation.
This offers an alternative means of earth fault detection, which does not require any measurement of current. This
may be particularly advantageous in high impedance earthed or insulated systems, where the provision of core
balanced current transformers on each feeder may be either impractical, or uneconomic, or for providing earth
fault protection for devices with no current transformers.

5.1 RESIDUAL OVERVOLTAGE PROTECTION IMPLEMENTATION

Residual Overvoltage Protection is implemented in the RESIDUAL O/V NVD column of the relevant settings group.
Some applications require more than one stage. For example an insulated system may require an alarm stage and
a trip stage. It is common in such a case for the system to be designed to withstand the associated healthy phase
overvoltages for a number of hours following an earth fault. In such applications, an alarm is generated soon after
the condition is detected, which serves to indicate the presence of an earth fault on the system. This gives time for
system operators to locate and isolate the fault. The second stage of the protection can issue a trip signal if the
fault condition persists.
The product provides two stages of Residual Overvoltage protection with independent time delay characteristics.
Stage 1 provides a choice of operate characteristics, where you can select between:
● An IDMT characteristic
● DT (Definite Time)

The IDMT characteristic is defined by the following formula:

t = K/( M - 1)
where:
● K= Time multiplier setting
● t = Operating time in seconds
● M = Derived residual voltage setting voltage (VN> Voltage Set)

You set this using the VN>1 Function setting.

Stage 1 also provides a Timer Hold facility.
Stage 2 can have definite time characteristics only. This is set in the VN>2 status cell
The device derives the residual voltage internally from the three-phase voltage inputs supplied from either a 5-limb
VT or three single-phase VTs. These types of VT design provide a path for the residual flux and consequently permit
the device to derive the required residual voltage. In addition, the primary star point of the VT must be earthed.
Three-limb VTs have no path for residual flux and are therefore unsuitable for this type of protection.

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5.2 RESIDUAL OVERVOLTAGE LOGIC

804
VN>1 Start

VN
VN>1 Voltage Set & 700
& IDMT/DT VN>1 Trip
832
VTS Fast Block

418
VN>1 Timer Blk
V00802

Figure 234: Residual Overvoltage logic

The Residual Overvoltage module (VN>) is a level detector that detects when the voltage magnitude exceeds a set
threshold, for each stage. When this happens, the comparator output produces a Start signal (VN>(n) Start), which
signifies the "Start of protection". This can be blocked by a VTS Fast block signal. This Start signal is applied to the
timer module. The output of the timer module is the VN> (n) Trip signal which is used to drive the tripping output
relay.

5.3 APPLICATION NOTES

5.3.1 CALCULATION FOR SOLIDLY EARTHED SYSTEMS

Consider a Phase-A to Earth fault on a simple radial system.

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E S IED F
ZS ZL

VA
VA

VC VB VC VB VC VB

VA VRES
VRES
VA
VB VB VB

VC VC VC

VRES = ZS0
X3E
2ZS1 + ZS0 + 2ZL1 + ZL0

E00800

Figure 235: Residual voltage for a solidly earthed system

As can be seen from the above diagram, the residual voltage measured on a solidly earthed system is solely
dependent on the ratio of source impedance behind the protection to the line impedance in front of the protection,
up to the point of fault. For a remote fault far away, the ZS/ZL: ratio will be small, resulting in a correspondingly
small residual voltage. Therefore, the protection only operates for faults up to a certain distance along the system.
The maximum distance depends on the device setting.

5.3.2 CALCULATION FOR IMPEDANCE EARTHED SYSTEMS

Consider a Phase-A to Earth fault on a simple radial system.

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E S IED F
ZS ZL
N

ZE

VA - G
S R VA - G
G,F G,F
G,F

VC - G VC - G VC - G
VB - G VB - G VB - G

VRES VRES VRES

VB - G VB - G VB - G
VA - G VA - G
VC - G VC - G VC - G

ZS0 + 3ZE
VRES = X3E
2ZS1 + ZS0 + 2ZL1 + ZL0 + 3Z
E

E00801

Figure 236: Residual voltage for an impedance earthed system

An impedance earthed system will always generate a relatively large degree of residual voltage, as the zero
sequence source impedance now includes the earthing impedance. It follows then that the residual voltage
generated by an earth fault on an insulated system will be the highest possible value (3 x phase-neutral voltage),
as the zero sequence source impedance is infinite.

5.3.3 SETTING GUIDELINES

The voltage setting applied to the elements is dependent on the magnitude of residual voltage that is expected to
occur during the earth fault condition. This in turn is dependent on the method of system earthing employed.
Also, you must ensure that the protection setting is set above any standing level of residual voltage that is present
on the system.

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 CHAPTER 15

FREQUENCY PROTECTION FUNCTIONS

Chapter 15 - Frequency Protection Functions P543i/P545i

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1 CHAPTER OVERVIEW
The device provides a range of frequency protection functions. This chapter describes the operation of these
functions including the principles, logic diagrams and applications.
This chapter contains the following sections:
Chapter Overview 411
Frequency Protection 412
Independent R.O.C.O.F Protection 415

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2 FREQUENCY PROTECTION
Power generation and utilisation needs to be well balanced in any industrial, distribution or transmission network.
These electrical networks are dynamic entities, with continually varying loads and supplies, which are continually
affecting the system frequency. Increased loading reduces the system frequency and generation needs to be
increased to maintain the frequency of the supply. Conversely decreased loading increases the system frequency
and generation needs to be reduced. Sudden fluctuations in load can cause rapid changes in frequency, which
need to be dealt with quickly.
Unless corrective measures are taken at the appropriate time, frequency decay can go beyond the point of no
return and cause widespread network collapse, which has dire consequences.
Normally, generators are rated for a particular band of frequency. Operation outside this band can cause
mechanical damage to the turbine blades. Protection against such contingencies is required when frequency does
not improve even after load shedding steps have been taken. This type of protection can be used for operator
alarms or turbine trips in case of severe frequency decay.
Clearly a range of methods is required to ensure system frequency stability. The frequency protection in this device
provides both underfrequency and overfrequency protection.
Frequency Protection is implemented in the FREQ PROTECTION column of the relevant settings group.

2.1 UNDERFREQUENCY PROTECTION

A reduced system frequency implies that the net load is in excess of the available generation. Such a condition can
arise, when an interconnected system splits, and the load left connected to one of the subsystems is in excess of
the capacity of the generators in that particular subsystem. Industrial plants that are dependent on utilities to
supply part of their loads will experience underfrequency conditions when the incoming lines are lost.
Many types of industrial loads have limited tolerances on the operating frequency and running speeds (e.g.
synchronous motors). Sustained underfrequency has implications on the stability of the system, whereby any
subsequent disturbance may damage equipment and even lead to blackouts. It is therefore essential to provide
protection for underfrequency conditions.

2.1.1 UNDERFREQUENCY PROTECTION IMPLEMENTATION

Simple underfrequency Protection is configured in the FREQ PROTECTION column of the relevant settings group.
The device provides 4 stages of underfrequency protection. The function uses the following settings (shown for
stage 1 only - other stages follow the same principles).
● F<1 Status: enables or disables underfrequency protection for the relevant stage
● F<1 Setting: defines the frequency pickup setting
● F<1 Time Delay: sets the time delay

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2.1.2 UNDERFREQUENCY PROTECTION LOGIC

Freq 1155
Averaging F<1 Start
DT
1161
F<1 Setting & F<1 Trip

F<1 Status
Enabled

890
All Poles Dead
1
Freq Not Found 1370

1149
F<1 Timer Block
V00861

Figure 237: Underfrequency logic (single stage)

If the frequency is below the setting and not blocked the DT timer is started. If the frequency cannot be
determined, the function is blocked.

2.1.3 APPLICATION NOTES

2.1.3.1 SETTING GUIDELINES

In order to minimise the effects of underfrequency, a multi-stage load shedding scheme may be used with the
plant loads prioritised and grouped. During an underfrequency condition, the load groups are disconnected
sequentially, with the highest priority group being the last one to be disconnected.
The effectiveness of each load shedding stage depends on the proportion of power deficiency it represents. If the
load shedding stage is too small compared with the prevailing generation deficiency, then there may be no
improvement in the frequency. This should be taken into account when forming the load groups.
Time delays should be sufficient to override any transient dips in frequency, as well as to provide time for the
frequency controls in the system to respond. These should not be excessive as this could jeopardize system
stability. Time delay settings of 5 - 20 s are typical.
The protection function should be set so that declared frequency-time limits for the generating set are not
infringed. Typically, a 10% underfrequency condition should be continuously sustainable.

2.2 OVERFREQUENCY PROTECTION

An increased system frequency arises when the mechanical power input to a generator exceeds the electrical
power output. This could happen, for instance, when there is a sudden loss of load due to tripping of an outgoing
feeder from the plant to a load centre. Under such conditions, the governor would normally respond quickly to
obtain a balance between the mechanical input and electrical output, thereby restoring normal frequency.
Overfrequency protection is required as a backup to cater for cases where the reaction of the control equipment is
too slow.

2.2.1 OVERFREQUENCY PROTECTION IMPLEMENTATION

Simple overfrequency Protection is configured in the FREQ PROTECTION column of the relevant settings group.
The device provides 2 stages of overfrequency protection. The function uses the following settings (shown for
stage 1 only - other stages follow the same principles).
● F>1 Status: enables or disables underfrequency protection for the relevant stage
● F>1 Setting: defines the frequency pickup setting
● F>1 Time Delay: sets the time delay

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2.2.2 OVERFREQUENCY PROTECTION LOGIC

1159
Freq Averaging F>1 Start
DT
1165
F>1 Setting & F>1 Trip

F>1 Status
Enabled

890
All Poles Dead
1
Freq Not Found 1370

1153
F>1 Timer Block
V00862

Figure 238: Overfrequency logic (single stage)

If the frequency is above the setting and not blocked, the DT timer is started and after this has timed out, the trip is
produced. If the frequency cannot be determined, the function is blocked.

2.2.3 APPLICATION NOTES

2.2.3.1 SETTING GUIDELINES

Following changes on the network caused by faults or other operational requirements, it is possible that various
subsystems will be formed within the power network. It is likely that these subsystems will suffer from a
generation/load imbalance. The "islands" where generation exceeds the existing load will be subject to
overfrequency conditions. Severe over frequency conditions may be unacceptable to many industrial loads, since
running speeds of motors will be affected. The overfrequency element can be suitably set to sense this
contingency.

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3 INDEPENDENT R.O.C.O.F PROTECTION

Where there are very large loads, imbalances may occur that result in rapid decline in system frequency. The
situation could be so bad that shedding one or two stages of load is unlikely to stop this rapid frequency decline. In
such a situation, standard underfrequency protection will normally have to be supplemented with protection that
responds to the rate of change of frequency. An element is therefore required which identifies the high rate of
decline of frequency, and adapts the load shedding scheme accordingly.
Such protection can identify frequency variations occurring close to nominal frequency thereby providing early
warning of a developing frequency problem. The element can also be used as an alarm to warn operators of
unusually high system frequency variations.

3.1 INDEPENENT R.O.C.O.F PROTECTION IMPLEMENTATION

The device provides four independent stages of protection. Each stage can respond to either rising or falling
frequency conditions. This depends on whether the frequency threshold is set above or below the system nominal
frequency. For example, if the frequency threshold is set above nominal frequency, the rate of change of frequency
setting is considered as positive and the element will operate for rising frequency conditions. If the frequency
threshold is set below nominal frequency, the setting is considered as negative and the element will operate for
falling frequency conditions.
The function uses the following settings (shown for stage 1 only - other stages follow the same principles).
● df/dt Avg.Cycles calculates the rate of change of frequency over a fixed period of several cycles.
● df/dt>1 Status: determines whether the stage is for falling or rising frequency conditions
● df/dt>1 Setting: defines the rate of change of frequency pickup setting
● df/dt>1 Time: sets the time delay

● df/dt>1 Dir'n: sets the direction of change you wish to check (positive, negative, or both)

In addition, start, trip and timer block DDB signals are available for each stage, as well as an inhibit signal to inhibit
all four stages.

3.2 INDEPENDENT R.O.C.O.F PROTECTION LOGIC

df /dt>1 Status
Enabled

Frequency 597
V df/dt df/dt >1 Start
determination
& 601
df /dt Avg . Cycles 1 df /dt>1 Trip
-1

df /dt>1 Setting × & df/dt >1 Time

df /dt>1 Dir’n 1
Positive
Both
1
Negative

1370
Freq Not Found
1368
Freq High 1
Freq Low 1369
V00869

Figure 239: Rate of change of frequency logic (single stage)

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416 P54x1i-TM-EN-1
 CHAPTER 16

CURRENT TRANSFORMER REQUIREMENTS

Chapter 16 - Current Transformer Requirements P543i/P545i

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1 CHAPTER OVERVIEW

This chapter contains the following sections:

Chapter Overview 419
Recommended CT Classes 420
Current Differential Requirements 421
Distance Protection Requirements 422
Determining Vk for IEEE C-class CT 423
Worked Examples 424

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Chapter 16 - Current Transformer Requirements P543i/P545i

2 RECOMMENDED CT CLASSES
You can use Class X current transformers with a knee point voltage greater or equal to that calculated. You can
also use class 5P protection CT. These have a knee-point voltage equivalent, which can be approximated from the
following calculations:
Vk = (VA ´ ALF)/In + (RCT ´ ALF ´ In)
where:
● Vk = Knee-point voltage
● VA = Voltampere burden rating
● ALF = Accuracy limit factor
● In = CT nominal secondary current
● RCT = CT resistance

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3 CURRENT DIFFERENTIAL REQUIREMENTS

We strongly recommend class X or class 5P Current Transformers. The CT knee point voltage should comply with
the minimum requirements of the formulae shown below:
Vk ³ KIn(RCT + 2RL)
where:
● Vk = Required IEC knee point voltage
● K = Dimensioning factor
● In = CT nominal secondary current
● RCT = CT resistance
● RL = One-way lead impedance from CT to relay
● K is a constant depending on the maximum value of through fault current for stability (If), and the Primary
system X/R ratio

Determination of K with transient bias disabled

For IEDs with the settings: Is1 = 20%, Is2 = 2In, k1 = 30%, k2 = 150% and for (If ´ X/R) £ 1000 (2-end applications):
K must have the value 65 or as calculated by: K = 40 + (0.07(If ´ X/R)), whichever the highest.
For higher (If ´ X/R) up to 2600, K = 107

For IEDs with the settings: Is1 = 20%, Is2 = 2In, k1 = 30%, k2 = 100% and for (If ´ X/R) £ 600 (3-end applications):
K must have the value 65 or as calculated by: K = 40 + (0.35(If ´ X/R))
For higher (If ´ X/R) up to 2600, K = 256

Determination of K with transient bias enabled

For IEDs with the settings: Is1 = 20%, Is2 = 2 In, k1 = 30%, k2 = 150% (2-end applications):
K = (1.42If + 53.7)(6.06E-03 ´ X/R + 0.515)
For IEDs with the settings: Is1 = 20%, Is2 = 2 In, k1 = 30%, k2 = 100% (3-end applications):
K = (7.47 ´ If + 77.8)(8.19E-03 ´ X/R + 0.345)
This is valid for If £ 50 pu and X/R £ 80

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4 DISTANCE PROTECTION REQUIREMENTS

Zone 1 Reach Point Accuracy (RPA)
Vk ³ KRPA ´ IfZ1(1+ X/R)(RCT + RL)
where:
● Vk = Required CT knee point voltage (volts)
● KRPA = Fixed dimensioning factor = 0.6
● IfZ1 = Maximum secondary phase fault current at Zone 1 reach point (A)
● X/R = Primary system reactance/resistance ratio
● RCT = CT secondary winding resistance
● RL = Single lead resistance from CT to IED

Zone 1 Close-up Fault Operation

An additional calculation must be performed for all cables and lines where the source impedance ratio (SIR) may
be less than SIR = 2.
Vk ³ Kmax Ifmax ´ I(RCT + RL)
where:
Kmax = Fixed dimensioning factor = 1.4
Ifmax = Maximum secondary phase fault current
Then, the highest of the two calculated knee points must be used.

Note:
It is not necessary to repeat the calculation for earth faults, as the phase reach calculation is the worst-case for CT
dimensioning.

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5 DETERMINING VK FOR IEEE C-CLASS CT

Where IEEE standards are used to specify CTs, the C class voltage rating can be checked to determine the
equivalent Vk (knee point voltage according to IEC).
The equivalence formula is:
Vk = 1.05(C rating in volts) + 100RCT

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6 WORKED EXAMPLES
The power system and the line parameters used in these examples are as follows:
● Single circuit operation between Green Valley and Blue River
● System voltage = 230 kV
● System frequency = 50 Hz
● System grounding = solid
● CT ratio = 1200/1
● Line length = 100 km
● Line positive sequence impedance Z1 = 0.089 + j 0.476 ohm per km
● Bus fault level = 40 kA
● Primary time constant = 120 ms

Important notes to be considered

● For calculating the CT requirements, the bus bar short time symmetrical fault rating should be considered
as the bus fault level.
● If only indicative X/R ratios are available, the circuit breaker’s DC breaking capacity is used to derive the
primary time constant and therefore the primary system X/R. It is derived from the circuit breaker
manufacturer’s practical primary time constants. These vary between 50 ms (66 kV and 132 kV breakers)
and 120 ms (220 kV and 400 kV breakers). 150 ms is a practical figure for generator circuit breakers.
● Current differential: Both If and X/R are to be calculated for a through fault
● Distance Zone1 reach point case: Both If and X/R are to be calculated for a fault at Zone1 reach point

6.1 CALCULATION OF PRIMARY X/R RATIO

Primary X/R up to the Green Valley busbar:
= 2pf ´ primary time constant
= 2p ´ 50 ´ 0.12  37.7

6.2 CALCULATION OF SOURCE IMPEDANCE

Source impedance magnitude:

= 230 kV / (1.732 ´ 40 kA) = 3.32 ohms

Source angle:
= tan-1 (37.7) = 88.48°
Hence:
Zs = 0.088 + j3.317

6.3 CALCULATION OF FULL LINE IMPEDANCE

Z1:
= 0.089 + j0.476 ohms / km
ZL:

= 8.9 + j47.6 = 48.42 ohms angle 79.4°

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6.4 CALCULATION OF TOTAL IMPEDANCE UP TO REMOTE BUSBAR

ZT = ZS + ZL:

= 8.988+ j50.917 ohms =51.7 ohms angle 80°

6.5 CALCULATION OF THROUGH FAULT X/R RATIO

X/R through = 50.917 / 8.988 = 5.66

6.6 CALCULATION OF THROUGH FAULT CURRENT

If through = 230kV / (1.732 ´ 51.7) = 2568.5 A primary = 2.14 A secondary

6.7 CALCULATION OF LINE IMPEDANCE TO ZONE 1 REACH POINT

Zzone 1 = 0.8ZL = 7.12 + j 38.08 = 38.73 ohms angle 79.4°

6.8 CALCULATION OF TOTAL IMPEDANCE TO ZONE 1 REACH POINT

ZT zone 1 = ZS + Z zone 1 = 7.208 + j 41.397 = 42.019 ohms angle 80°

6.9 CALCULATION OF X/R TO ZONE 1 REACH POINT

X/R zone 1 = 41.397 / 7.208 = 5.74

6.10 CALCULATION OF FAULT CURRENT TO ZONE 1 REACH POINT

If zone 1 = 230kV / (1.732 ´ 42.019) = 3160.34 A primary = 2.63 A secondary

6.11 CALCULATION OF VK FOR CURRENT DIFFERENTIAL PROTECTION

Transient Bias Disabled, with k2 set to 150%

If through ´ X/R through = 2.14 ´ 5.66 = 12.11
As this is less than 1000, we use the highest of K = 65 or K = 40 + (0.07(If ´ X/R))
Hence in this example we use K = 65. Therefore:
We know that Vk ³ KIn(RCT + 2RL), therefore
Vk ³ 65(RCT + 2RL)

Transient Bias Enabled, with k2 set to 150%

K = (1.42 ´ 2.14 + 53.7)(6.06E-03 ´ 5.66 + 0.515) = 31.2, therefore
Vk ³ 31.2(RCT + 2RL)

6.12 CALCULATION OF VK FOR DISTANCE ZONE 1 REACH POINT

Using: Vk ³ KRPA ´ IfZ1(1+ X/R)(RCT + RL)
Vk > 0.6 ´ 2.63 ´ (1 + 5.74)(RCT + RL), therefore:
Vk > 10.65(RCT + RL)

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6.13 CALCULATION OF VK FOR DISTANCE ZONE 1 CLOSE-UP FAULT

SIR = Zs/Zzone1 =3.32/38.73, which is less than 2, so we need to calculate Vk.
Close-up fault current = 40kA primary, = 33.33A secondary
Vk ³ Kmax ´ Ifmax(RCT + RL)
Vk > 1.4 ´ 33.3 ´ (RCT + RL), therefore:
Vk > 46.67(RCT + RL)

6.14 CALCULATION OF VK FOR DISTANCE TIME DELAYED ZONES

Vk > If(RCT + RL)
Vk > Ifthrough ´ (RCT + RL), therefore:
Vk > 2.14(RCT + RL)

6.15 OVERCURRENT ELEMENTS

Phase Elements
VK ³ 0.5ICP (RCT + RL + Rrp)

Ground Elements
VK ³ 0.5ICN (RCT + 2RL + Rrp + Rrn)

6.16 OVERCURRENT ELEMENTS

VK ³ 0.5ICN (RCT + 2RL + Rrn)

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 CHAPTER 17

MONITORING AND CONTROL

Chapter 17 - Monitoring and Control P543i/P545i

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1 CHAPTER OVERVIEW
As well as providing a range of protection functions, the product includes comprehensive monitoring and control
functionality.
This chapter contains the following sections:
Chapter Overview 429
Event Records 430
Disturbance Recorder 434
Measurements 435
CB Condition Monitoring 436
CB State Monitoring 443
Circuit Breaker Control 445
Pole Dead Function 450
System Checks 451

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2 EVENT RECORDS
General Electric devices record events in an event log. This allows you to establish the sequence of events that led
up to a particular situation. For example, a change in a digital input signal or protection element output signal
would cause an event record to be created and stored in the event log. This could be used to analyse how a
particular power system condition was caused. These events are stored in the IED's non-volatile memory. Each
event is time tagged.
The event records can be displayed on an IED's front panel but it is easier to view them through the settings
application software. This can extract the events log from the device and store it as a single .evt file for analysis on
a PC.
The event records are detailed in the VIEW RECORDS column. The first event (0) is always the latest event. After
selecting the required event, you can scroll through the menus to obtain further details.
If viewing the event with the settings application software, simply open the extracted event file. All the events are
displayed chronologically. Each event is summarised with a time stamp (obtained from the Time & Date cell) and a
short description relating to the event (obtained from the Event Text cell. You can expand the details of the event
by clicking on the + icon to the left of the time stamp.
The following table shows the correlation between the fields in the setting application software's event viewer and
the cells in the menu database.
Field in Event Viewer Equivalent cell in menu DB Cell reference User settable?
Left hand column header VIEW RECORDS ® Time & Date 01 03 No
Right hand column header VIEW RECORDS ® Event Text 01 04 No
Description SYSTEM DATA ® Description 00 04 Yes
Plant reference SYSTEM DATA ® Plant Reference 00 05 Yes
Model number SYSTEM DATA ® Model Number 00 06 No
Address Displays the Courier address relating to the event N/A No
Event type VIEW RECORDS ® Menu Cell Ref 01 02 No
Event Value VIEW RECORDS ® Event Value 01 05 No
Evt Unique Id VIEW RECORDS ® Evt Unique ID 01 FE No

The device is capable of storing up to 1024 event records.

In addition to the event log, there are two logs which contain duplicates of the last 5 maintenance records and the
last 5 fault records. The purpose of this is to provide convenient access to the most recent fault and maintenance
events.

2.1 EVENT TYPES

There are several different types of event:
● Opto-input events (Change of state of opto-input)
● Contact events (Change of state of output relay contact)
● Alarm events
● Fault record events
● Standard events
● Security events

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Standard events are further sub-categorised internally to include different pieces of information. These are:
● Protection events (starts and trips)
● Maintenance record events
● Platform events

Note:
The first event in the list (event 0) is the most recent event to have occurred.

2.1.1 OPTO-INPUT EVENTS

If one or more of the opto-inputs has changed state since the last time the protection algorithm ran (which runs at
several times per cycle), a new event is created, which logs the logic states of all opto-inputs. You can tell which
opto-input has changed state by comparing the new event with the previous one.
The description of this event type, as shown in the Event Text cell is always Logic Inputs # where # is the
batch number of the opto-inputs. This is '1', for the first batch of opto-inputs and '2' for the second batch of opto-
inputs (if applicable).
The event value shown in the Event Value cell for this type of event is a binary string. This shows the logical states
of the opto-inputs, where the Least Significant Bit (LSB), on the right corresponds to the first opto-input Input L1.
The same information is also shown in the Opto I/P Status cell in the SYSTEM DATA column. This information is
updated continuously, whereas the information in the event log is a snapshot at the time when the event was
created.

2.1.2 CONTACT EVENTS

If one or more of the output relays (also known as output contacts) has changed state since the last time the
protection algorithm ran (which runs at several times per cycle), a new event is created, which logs the logic states
of all output relays. You can tell which output relay has changed state by comparing the new event with the
previous one.
The description of this event type, as shown in the Event Text cell is always Output Contacts # where # is the
batch number of the output relay contacts. This is '1', for the first batch of output contacts and '2' for the second
batch of output contacts (if applicable).
The event value shown in the Event Value cell for this type of event is a binary string. This shows the logical states
of the output relays, where the LSB (on the right) corresponds to the first output contact Output R1.
The same information is also shown in the Relay O/P Status cell in the SYSTEM DATA column. This information is
updated continuously, whereas the information in the event log is a snapshot at the time when the event was
created.

2.1.3 ALARM EVENTS

The IED monitors itself on power up and continually thereafter. If it notices any problems, it will register an alarm
event.
The description of this event type, as shown in the Event Text cell is cell dependent on the type of alarm and will be
one of those shown in the following tables, followed by OFF or ON.
The event value shown in the Event Value cell for this type of event is a 32 bit binary string. There are one or more
banks 32 bit registers, depending on the device model. These contain all the alarm types and their logic states (ON
or OFF).
The same information is also shown in the Alarm Status (n) cells in the SYSTEM DATA column. This information is
updated continuously, whereas the information in the event log is a snapshot at the time when the event was
created.

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2.1.4 FAULT RECORD EVENTS

An event record is created for every fault the IED detects. This is also known as a fault record.
The event type description shown in the Event Text cell for this type of event is always Fault Recorded.
The IED contains a separate register containing the latest fault records. This provides a convenient way of viewing
the latest fault records and saves searching through the event log. You access these fault records using the Select
Fault setting, where fault number 0 is the latest fault.
A fault record is triggered by the Fault REC TRIG signal DDB, which is assigned in the PSL. The fault recorder
records the values of all parameters associated with the fault for the duration of the fault. These parameters are
stored in separate Courier cells, which become visible depending on the type of fault.
The fault recorder stops recording only when:
The Start signal is reset AND the undercurrent is ON OR the Trip signal is reset, as shown below:

Start signal resets

& Fault recorder stops recording
Undercurrent is ON
1
Trip signal resets

Fault recorder trigger

V01234

Figure 240: Fault recorder stop conditions

The event is logged as soon as the fault recorder stops. The time stamp assigned to the fault corresponds to the
start of the fault. The timestamp assigned to the fault record event corresponds to the time when the fault
recorder stops.

Note:
We recommend that you do not set the triggering contact to latching. This is because if you use a latching contact, the fault
record would not be generated until the contact has been fully reset.

2.1.5 MAINTENANCE EVENTS

Internal failures detected by the self-test procedures are logged as maintenance records. Maintenance records are
special types of standard events.
The event type description shown in the Event Text cell for this type of event is always Maint Recorded.
The Event Value cell also provides a unique binary code.
The IED contains a separate register containing the latest maintenance records. This provides a convenient way of
viewing the latest maintenance records and saves searching through the event log. You access these fault records
using the Select Maint setting.
The maintenance record has a number of extra menu cells relating to the maintenance event. These parameters
are Maint Text, Maint Type and Maint Data. They contain details about the maintenance event selected with the
Select Maint cell.

2.1.6 PROTECTION EVENTS

The IED logs protection starts and trips as individual events. Protection events are special types of standard events.
The event type description shown in the Event Text cell for this type of event is dependent on the protection event
that occurred. Each time a protection event occurs, a DDB signal changes state. It is the name of this DDB signal
followed by 'ON' or 'OFF' that appears in the Event Text cell.

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The Event Value cell for this type of event is a 32 bit binary string representing the state of the relevant DDB
signals. These binary strings can also be viewed in the COMMISSION TESTS column in the relevant DDB batch cells.
Not all DDB signals can generate an event. Those that can are listed in the RECORD CONTROL column. In this
column, you can set which DDBs generate events.

2.1.7 SECURITY EVENTS

An event record is generated each time a setting that requires an access level is executed.
The event type description shown in the Event Text cell displays the type of change.

2.1.8 PLATFORM EVENTS

Platform events are special types of standard events.
The event type description shown in the Event Text cell displays the type of change.

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3 DISTURBANCE RECORDER
The disturbance recorder feature allows you to record selected current and voltage inputs to the protection
elements, together with selected digital signals. The digital signals may be inputs, outputs, or internal DDB signals.
The disturbance records can be extracted using the disturbance record viewer in the settings application software.
The disturbance record file can also be stored in the COMTRADE format. This allows the use of other packages to
view the recorded data.
The integral disturbance recorder has an area of memory specifically set aside for storing disturbance records. The
number of records that can be stored is dependent on the recording duration. The minimum duration is 0.1 s and
the maximum duration is 10.5 s.
When the available memory is exhausted, the oldest records are overwritten by the newest ones.
Each disturbance record consists of a number of analogue data channels and digital data channels. The relevant
CT and VT ratios for the analogue channels are also extracted to enable scaling to primary quantities.
The fault recording times are set by a combination of the Duration and Trigger Position cells. The Duration cell
sets the overall recording time and the Trigger Position cell sets the trigger point as a percentage of the duration.
For example, the default settings show that the overall recording time is set to 1.5 s with the trigger point being at
33.3% of this, giving 0.5 s pre-fault and 1 s post fault recording times.
With the Trigger Mode set to Single, if further triggers occurs whilst a recording is taking place, the recorder will
ignore the trigger. However, with the Trigger Mode set to Extended, the post trigger timer will be reset to zero,
extending the recording time.
You can select any of the IED's analogue inputs as analogue channels to be recorded. You can also map any of the
opto-inputs output contacts to the digital channels. In addition, you may also map a number of DDB signals such
as Starts and LEDs to digital channels.
You may choose any of the digital channels to trigger the disturbance recorder on either a low to high or a high to
low transition, via the Input Trigger cell. The default settings are such that any dedicated trip output contacts will
trigger the recorder.
It is not possible to view the disturbance records locally via the front panel LCD. You must extract these using
suitable setting application software such as MiCOM S1 Agile.

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4 MEASUREMENTS

4.1 MEASURED QUANTITIES

The device measures directly and calculates a number of system quantities, which are updated every second. You
can view these values in the relevant MEASUREMENT columns or with the Measurement Viewer in the settings
application software. Depending on the model, the device may measure and display some or more of the following
quantities:
● Measured and calculated analogue current and voltage values
● Power and energy quantities
● Peak, fixed and rolling demand values
● Frequency measurements
● Thermal measurements
● Teleprotection channel measurements

4.2 MEASUREMENT SETUP

You can define the way measurements are set up and displayed using the MEASURE'T SETUP column and the
measurements are shown in the relevant MEASUREMENTS tables.

4.3 FAULT LOCATOR

Some models provide fault location functionality. It is possible to identify the fault location by measuring the fault
voltage and current magnitude and phases and presenting this information to a Fault Locator function. The fault
locator is triggered whenever a fault record is generated, and the subsequent fault location data is included as
part of the fault record. This information is also displayed in the Fault Location cell in the VIEW RECORDS column.
This cell will display the fault location in metres, miles ohms or percentage, depending on the chosen units in the
Fault Location cell of the MEASURE'T SETUP column.
The Fault Locator uses pre-fault and post-fault analogue input signals to calculate the fault location. The result is
included it in the fault record. The pre-fault and post-fault voltages are also presented in the fault record.
When applied to parallel circuits, mutual flux coupling can alter the impedance seen by the fault locator. The
coupling contains positive, negative and zero sequence components. In practise the positive and negative
sequence coupling is insignificant. The effect on the fault locator of the zero sequence mutual coupling can be
eliminated using the mutual compensation feature provided.

4.4 OPTO-INPUT TIME STAMPING

Each opto-input sample is time stamped within a tolerance of +/- 1 ms with respect to the Real Time Clock. These
time stamps are used for the opto event logs and for the disturbance recording. The device needs to be
synchronised accurately to an external clock source such as an IRIG-B signal or a master clock signal provided in
the relevant data protocol.
For both the filtered and unfiltered opto-inputs, the time stamp of an opto-input change event is the sampling time
at which the change of state occurred. If multiple opto-inputs change state at the same sampling interval, these
state changes are reported as a single event.

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5 CB CONDITION MONITORING
The device records various statistics related to each circuit breaker trip operation, allowing an accurate
assessment of the circuit breaker condition to be determined. These statistics are available in the CB CONDITION
column. The menu cells are register values only and cannot be set directly. They may be reset, however, during
maintenance. The statistics monitored are:
● Total Current Broken: A register stores the total amount of current that the CB has broken is stored in an
accumulator, giving at any time a measure of the total amount of current that the CB has broken since the
value was last reset.
● Number of CB operations: A counter registers the number of CB trips that have been performed for each
phase, giving at any time the total number of trips that the CB has performed since the value was last reset.
● CB Operate Time: A register stores the total amount of time the CB has transitioned from closed to open is
stored in an accumulator, giving at any time a measure of the total time that the CB has spent tripping since
the values was last reset.

● Excessive Fault Frequency: A counter registers the number of CB trips that have been performed for all
phases, giving at any time the total number of trips performed since the value was last reset.

These statistics are available in the CB CONDITION column. The menu cells are register values only and cannot be
set directly. They may be reset, however, during maintenance.

Note:
When in Commissioning test mode the CB condition monitoring registers are not updated.

Circuit breaker lockout, can be caused by the following circuit breaker condition monitoring functions:
● Maintenance lockout
● Excessive fault frequency lockout
● Broken current lockout

If the circuit breaker is locked out, the logic generates a lockout alarm

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5.1 BROKEN CURRENT ACCUMULATOR

PhaseACurrent
Set Set Cumulative IA broken In
Reset

PhaseBCurrent
Set Set Cumulative IB broken In
Reset

PhaseCCurrent
Set Set Cumulative IC broken In
Trip 3ph t Reset
1
External Trip3ph 0
Note: Broken current totals not incremented when device is in test mode
Trip Output A t 1
1
External Trip A 0

Trip Output B t 1
1
External Trip B 0

Trip Output C t 1
1
External Trip C 0

Reset CB Data
1 Note: All timers have 1 cycle pickup delay
Reset CB Data V01272

Figure 241: Broken Current Accumulator logic diagram

5.2 CB TRIP COUNTER

Trip 3ph
1
External Trip3ph

Trip Output A 1 Increment

1
External Trip A Phase A Trip Counter
Reset

Trip Output B 1 Increment

1
External Trip B Phase B Trip Counter
Reset

Trip Output C 1 Increment

1
External Trip C Phase C Trip Counter
Reset
Reset CB Data
1
Reset CB Data

V01276

Figure 242: CB Trip Counter logic diagram

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5.3 CB OPERATING TIME ACCUMULATOR

Trip 3ph
1 Note: CB operating time not accumulated when device is in test mode
External Trip3ph

Trip Output A 1 Start

External Trip A CB operating time phase A Increment

Stop CBOpTimePhA Counter
IA < fixed threshold Reset
1
Pole Dead A

Trip Output B 1 Start

External Trip B CB operating time phase B Increment

Stop CBOpTimePhB Counter
IB < fixed threshold Reset
1
Pole Dead B

Trip Output C 1 Start

External Trip C CB operating time phase C Increment

Stop CBOpTimePhB Counter
IC < fixed threshold Reset
1
Pole Dead C

Reset CB Data
1
Reset CB Data

V01274

Figure 243: Operating Time Accumulator

5.4 EXCESSIVE FAULT FREQUENCY COUNTER

Trip 3ph
1
External Trip3ph 1 Increment
Trip Output A Excessive Fault Frequency Counter
1 Reset
External Trip A

Trip Output B
1 S t
External Trip B Q
R 0 1
Trip Output C
1
External Trip C

Lockout Alarm

Fault Freq Time

V01278

Figure 244: Excessive Fault Frequency logic diagram

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5.5 RESET LOCKOUT ALARM

CB mon LO reset
Yes
1 Reset Lockout Alarm
Clear Alarms

CB Failed to Trip S
Q
R t
&
CB Open 3 ph 0
Lockout Alarm
CB Closed 3 ph
1
CB Closed A ph
CB Closed B ph &

CB Closed C ph

Rst CB mon LO by
CB Close
CB mon LO RstDly

V01280

Figure 245: Reset Lockout Alarm logic diagram

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5.6 CB CONDITION MONITORING LOGIC

I^ Maintenance
Alarm Enabled
&
Greatest broken current total & CB I^ Maint

I^ Maintenance S
Q 1 CB Monitor Alarm
R
I^ Lockout
Alarm Enabled
& CB I^ Lockout

I^ Lockout

No. CB Ops Maint

Alarm Enabled
&
Max no . of CB operations & No. CB Ops Maint
S
No. CB Ops Maint Q
R
No. CB Ops Lock
Alarm Enabled
& No. CB Ops Lock

No. CB Ops Lock

&
1 Pre-Lockout
-1
Fault Freq Lock
Alarm Enabled
& S
Fault frequency count Q CB FaultFreqLock
R
Fault Freq Count

&
-1 1 CB Mon LO Alarm
CB Time Maint
Alarm Enabled
&
Greatest CB travel time & CB Time Maint
S
CB Time Maint Q
R
CB Time Lockout
Alarm Enabled
& CB Time Lockout

CB Time Lockout

Reset Indication 1
Yes

Reset CB Data
Yes 1

Reset CB Data
S
Q Lockout Alarm
Reset lockout Alarm R

Control CB Unhealthy

Control no Check Synch

CB failed to trip

CB failed to close V01282

Figure 246: CB Condition Monitoring logic diagram

5.7 RESET CIRCUIT BREAKER LOCKOUT

Lockout conditions caused by the circuit breaker condition monitoring functions can be reset according to the
condition of the Rst CB mon LO by setting found in the CB CONTROL column. There are two options; CB Close
and User interface.

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If set to CB Close, a timer setting, CB mon LO RstDly, becomes visible. When the circuit breaker closes, the CB
mon LO RstDly time starts. The lockout is reset when the timer expires.
If set to User Interface then a command, CB mon LO reset, becomes visible. This command can be used to
reset the lockout from a user interface.
An Autoreclose lockout generates an Autoreclose lockout alarm. Autoreclose lockout conditions can be reset by
various commands and setting options found under the CB CONTROL column.
If Res LO by CB IS is set to Enabled, a lockout is reset if the circuit breaker is successfully closed manually. For
this, the circuit breaker must remain closed long enough so that it enters the “In Service” state.
If Res LO by UI is set to Enabled, the circuit breaker lockout can be reset from a user interface using the reset
circuit breaker lockout command in the CB CONTROL column.
If Res LO by NoAR is set to Enabled, the circuit breaker lockout can be reset by temporarily generating an AR
disabled signal.
If Res LO by TDelay is set to Enabled, the circuit breaker lockout is automatically reset after a time delay set in
the LO Reset Time setting.
If Res LO by ExtDDB is Enabled, the circuit breaker lockout can be reset by activation of an external input
mapped in the PSL to the relevant reset lockout DDB signal.

5.7.1 RESET CB LOCKOUT LOGIC DIAGRAM

Res LO by CB IS
Enabled
&
CB1CRLO

Res LO by UI
Enabled
&
Reset CB LO
Yes

Res LO by NoAR
Enabled
& 1 RESCB1LO
AR Disabled

Res LO by ExtDDB
Enabled
&
Reset Lockout

Res LO by TDelay
Enabled
&
LO Reset Time
t
A/ R Lockout
0

V03382

Figure 247: Reset Circuit Breaker Lockout Logic Diagram (Module 57)

5.8 APPLICATION NOTES

5.8.1 SETTING THE THRESHOLDS FOR THE TOTAL BROKEN CURRENT

Where power lines use oil circuit breakers (OCBs), changing of the oil accounts for a significant proportion of the
switchgear maintenance costs. Often, oil changes are performed after a fixed number of CB fault operations.
However, this may result in premature maintenance where fault currents tend to be low, because oil degradation

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may be slower than would normally be expected. The Total Current Accumulator (I^ counter) cumulatively stores
the total value of the current broken by the circuit breaker providing a more accurate assessment of the circuit
breaker condition.

The dielectric withstand of the oil generally decreases as a function of I2t, where ‘I’ is the broken fault current and
‘t’ is the arcing time within the interrupter tank. The arcing time cannot be determined accurately, but is generally
dependent on the type of circuit breaker being used. Instead, you set a factor (Broken I^) with a value between 1
and 2, depending on the circuit breaker.
Most circuit breakers would have this value set to '2', but for some types of circuit breaker, especially those
operating on higher voltage systems, a value of 2 may be too high. In such applications Broken I^ may be set
lower, typically 1.4 or 1.5.
The setting range for Broken I^ is variable between 1.0 and 2.0 in 0.1 steps.

Note:
Any maintenance program must be fully compliant with the switchgear manufacturer’s instructions.

5.8.2 SETTING THE THRESHOLDS FOR THE NUMBER OF OPERATIONS

Every circuit breaker operation results in some degree of wear for its components. Therefore routine maintenance,
such as oiling of mechanisms, may be based on the number of operations. Suitable setting of the maintenance
threshold will allow an alarm to be raised, indicating when preventative maintenance is due. Should maintenance
not be carried out, the device can be set to lockout the autoreclose function on reaching a second operations
threshold (No. CB ops Lock). This prevents further reclosure when the circuit breaker has not been maintained to
the standard demanded by the switchgear manufacturer’s maintenance instructions.
Some circuit breakers, such as oil circuit breakers (OCBs) can only perform a certain number of fault interruptions
before requiring maintenance attention. This is because each fault interruption causes carbonising of the oil,
degrading its dielectric properties. The maintenance alarm threshold (setting No. CB Ops Maint) may be set to
indicate the requirement for oil dielectric testing, or for more comprehensive maintenance. Again, the lockout
threshold No. CB Ops Lock may be set to disable autoreclosure when repeated further fault interruptions could
not be guaranteed. This minimises the risk of oil fires or explosion.

5.8.3 SETTING THE THRESHOLDS FOR THE OPERATING TIME

Slow CB operation indicates the need for mechanism maintenance. Alarm and lockout thresholds (CB Time Maint
and CB Time Lockout) are provided to enforce this. They can be set in the range of 5 to 500 ms. This time relates to
the interrupting time of the circuit breaker.

5.8.4 SETTING THE THRESHOLDS FOR EXCESSSIVE FAULT FREQUENCY

Persistent faults will generally cause autoreclose lockout, with subsequent maintenance attention. Intermittent
faults such as clashing vegetation may repeat outside of any reclaim time, and the common cause might never be
investigated. For this reason it is possible to set a frequent operations counter, which allows the number of
operations Fault Freq Count over a set time period Fault Freq Time to be monitored. A separate alarm and lockout
threshold can be set.

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6 CB STATE MONITORING
CB State monitoring is used to verify the open or closed state of a circuit breaker. Most circuit breakers have
auxiliary contacts through which they transmit their status (open or closed) to control equipment such as IEDs.
These auxiliary contacts are known as:
● 52A for contacts that follow the state of the CB
● 52B for contacts that are in opposition to the state of the CB

This device can be set to monitor both of these types of circuit breaker state indication. If the state is unknown for
some reason, an alarm can be raised.
Some CBs provide both sets of contacts. If this is the case, these contacts will normally be in opposite states.
Should both sets of contacts be open, this would indicate one of the following conditions:
● Auxiliary contacts/wiring defective
● Circuit Breaker (CB) is defective
● CB is in isolated position

Should both sets of contacts be closed, only one of the following two conditions would apply:
● Auxiliary contacts/wiring defective
● Circuit Breaker (CB) is defective

If any of the above conditions exist, an alarm will be issued after a 5 s time delay. An output contact can be
assigned to this function via the programmable scheme logic (PSL). The time delay is set to avoid unwanted
operation during normal switching duties.
In the CB CONTROL column there is a setting called CB Status Input. This cell can be set at one of the following
four options:
● None
● 52A
● 52B
● Both 52A and 52B

Where None is selected no CB status is available. Where only 52A is used on its own then the device will assume a
52B signal opposite to the 52A signal. Circuit breaker status information will be available in this case but no
discrepancy alarm will be available. The above is also true where only a 52B is used. If both 52A and 52B are used
then status information will be available and in addition a discrepancy alarm will be possible, according to the
following table:
Auxiliary Contact Position CB State Detected Action
52A 52B
Open Closed Breaker open Circuit breaker healthy
Closed Open Breaker closed Circuit breaker healthy
Alarm raised if the condition persists for greater than
Closed Closed CB failure
5s
Alarm raised if the condition persists for greater than
Open Open State unknown
5s

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6.1 CB STATE MONITOR LOGIC DIAGRAM

CB Aux 3ph(52- A)
&

CB Aux 3ph(52- B)
& 1
1 CB Closed 3 ph
XOR

&

CB Status Input
&
52A 3 pole
52B 3 pole
52A & 52B 3 pole & 1
1 CB Open 3 ph

&

&

CB Aux A(52-A)
&

CB Aux A(52-B) 1 CB Closed A ph

& 1
XOR
&
&

CB Status Input
&
52A 1 pole
52B 1 pole
1 CB Open A ph
52A & 52B 1 pole & 1

&
&

&

CB Aux B(52-A) 1 CB Closed B ph

CB Aux B(52-B)

Phase B 1 CB Open B ph
CB Status Input
(Same logic as phase A )
52A 1 pole
52B 1 pole
52A & 52B 1 pole

CB Aux C(52- A) 1 CB Closed C ph

CB Aux C(52- B)

Phase C 1 CB Open C ph
CB Status Input
(Same logic as phase A )
52A 1 pole
52B 1 pole
1 CB Status Alm
52A & 52B 1 pole

V01264 CB Status Time

Figure 248: CB State Monitor logic diagram (Module 1)

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7 CIRCUIT BREAKER CONTROL

Although some circuit breakers do not provide auxiliary contacts, most provide auxiliary contacts to reflect the
state of the circuit breaker. These are:
● CBs with 52A contacts (where the auxiliary contact follows the state of the CB)
● CBs with 52B contacts (where the auxiliary contact is in the opposite state from the state of the CB)
● CBs with both 52A and 52B contacts

Circuit Breaker control is only possible if the circuit breaker in question provides auxiliary contacts. The CB Status
Input cell in the CB CONTROL column must be set to the type of circuit breaker. If no CB auxiliary contacts are
available then this cell should be set to None, and no CB control will be possible.
For local control, the CB control by cell should be set accordingly.
The output contact can be set to operate following a time delay defined by the setting Man Close Delay. One
reason for this delay is to give personnel time to safely move away from the circuit breaker following a CB close
command.
The control close cycle can be cancelled at any time before the output contact operates by any appropriate trip
signal, or by activating the Reset Close Dly DDB signal.
The length of the trip and close control pulses can be set via the Trip Pulse Time and Close Pulse Time settings
respectively. These should be set long enough to ensure the breaker has completed its open or close cycle before
the pulse has elapsed.
If an attempt to close the breaker is being made, and a protection trip signal is generated, the protection trip
command overrides the close command.
The Reset Lockout by setting is used to enable or disable the resetting of lockout automatically from a manual
close after the time set by Man Close RstDly.
If the CB fails to respond to the control command (indicated by no change in the state of CB Status inputs) an
alarm is generated after the relevant trip or close pulses have expired. These alarms can be viewed on the LCD
display, remotely, or can be assigned to output contacts using the programmable scheme logic (PSL).

Note:
The CB Healthy Time and Sys Check time set under this menu section are applicable to manual circuit breaker operations
only. These settings are duplicated in the AUTORECLOSE menu for autoreclose applications.

The Lockout Reset and Reset Lockout by settings are applicable to CB Lockouts associated with manual circuit
breaker closure, CB Condition monitoring (Number of circuit breaker operations, for example) and autoreclose
lockouts.
The device includes the following options for control of a single circuit breaker:
● The IED menu (local control)
● The Hotkeys (local control)
● The function keys (local control)
● The opto-inputs (local control)
● SCADA communication (remote control)

7.1 CB CONTROL USING THE IED MENU

You can control manual trips and closes with the CB Trip/Close command in the SYSTEM DATA column. This can be
set to No Operation, Trip, or Close accordingly.

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For this to work you have to set the CB control by cell to option 1 Local, option 3 Local + Remote, option 5
Opto+Local, or option 7 Opto+Local+Remote in the CB CONTROL column.

7.2 CB CONTROL USING THE HOTKEYS

The hotkeys allow you to manually trip and close the CB without the need to enter the SYSTEM DATA column. For
this to work you have to set the CB control by cell to option 1 Local, option 3 Local+Remote, option 5 Opto
+Local, or option 7 Opto+Local+Remote in the CB CONTROL column.
CB control using the hotkey is achieved by pressing the right-hand button directly below LCD screen. This button is
only enabled if:
● The CB Control by setting is set to one of the options where local control is possible (option 1,3,5, or 7)
● The CB Status Input is set to '52A', '52B', or 'Both 52A and 52B'

If the CB is currently closed, the command text on the bottom right of the LCD screen will read Trip. Conversely, if
the CB is currently open, the command text will read Close.
If you execute a Trip, a screen with the CB status will be displayed once the command has been completed. If
you execute a Close, a screen with a timing bar will appear while the command is being executed. This screen
also gives you the option to cancel or restart the close procedure. The time delay is determined by the Man Close
Delay setting in the CB CONTROL menu. When the command has been executed, a screen confirming the present
status of the circuit breaker is displayed. You are then prompted to select the next appropriate command or exit.
If no keys are pressed for a period of 5 seconds while waiting for the command confirmation, the device will revert
to showing the CB Status. If no key presses are made for a period of 25 seconds while displaying the CB status
screen, the device will revert to the default screen.
To avoid accidental operation of the trip and close functionality, the hotkey CB control commands are disabled for
10 seconds after exiting the hotkey menu.
The hotkey functionality is summarised graphically below:

Default Display

HOTKEY CB CTRL

Hotkey Menu

CB closed CB open

<CB STATUS> EXECUTE <CB STATUS> EXECUTE EXECUTE CLOSE

CLOSED CB TRIP OPEN CB CLOSE 30 secs

TRIP EXIT CONFIRM CANCEL EXIT CLOSE CANCEL CONFIRM CANCEL RESTART

E01209

Figure 249: Hotkey menu navigation

7.3 CB CONTROL USING THE FUNCTION KEYS

For most models, you can also use the function keys to allow direct control of the circuit breaker. This has the
advantage over hotkeys, that the LEDs associated with the function keys can indicate the status of the CB. The

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default PSL is set up such that Function key 2 initiates a trip and Function key 3 initiates a close. For this to work
you have to set the CB control by cell to option 5 Opto+Local, or option 7 Opto+Local+Remote in the CB
CONTROL column.
As shown below, function keys 2 and 3 have already been assigned to CB control in the default PSL.

Function Key 2 Init Trip CB

Non- FnKey LED2 Red

Latching FnKey LED2 Grn

Function Key 3 Init Close CB

1 Non- FnKey LED3 Red

Close in Prog
Latching FnKey LED3 Grn
V01245

Figure 250: Default function key PSL

The programmable function key LEDs have been mapped such that they will indicate yellow whilst the keys are
activated.

Note:
Not all models provide function keys.

7.4 CB CONTROL USING THE OPTO-INPUTS

Certain applications may require the use of push buttons or other external signals to control the various CB control
operations. It is possible to connect such push buttons and signals to opto-inputs and map these to the relevant
DDB signals.
For this to work, you have to set the CB control by cell to option 4 opto, option 5 Opto+Local, option 6 Opto
+Remote, or option 7 Opto+Local+Remote in the CB CONTROL column.

7.5 REMOTE CB CONTROL

Remote CB control can be achieved by setting the CB Trip/Close cell in the SYSTEM DATA column to trip or close by
using a command over a communication link.
For this to work, you have to set the CB control by cell to option 2 Remote, option 3 Local+Remote, option 6
Opto+remote, or option 7 Opto+Local+Remote in the CB CONTROL column.
We recommend that you allocate separate relay output contacts for remote CB control and protection tripping.
This allows you to select the control outputs using a simple local/remote selector switch as shown below. Where
this feature is not required the same output contact(s) can be used for both protection and remote tripping.

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Protection Trip

Trip
Remote
Control
Trip Close
Remote
Control
Close

Local

Remote

Trip Close

E01207

Figure 251: Remote Control of Circuit Breaker

7.6 CB HEALTHY CHECK

A CB Healthy check is available if required. This facility accepts an input to one of the opto-inputs to indicate that
the breaker is capable of closing (e.g. that it is fully charged). A time delay can be set with the setting CB Healthy
Time. If the CB does not indicate a healthy condition within the time period following a Close command, the device
will lockout and alarm.

7.7 SYNCHRONISATION CHECK

Where the check synchronism function is set, this can be enabled to supervise manual circuit breaker Close
commands. A circuit breaker Close command will only be issued if the Check Synchronisation criteria are satisfied.
A time delay can be set with the setting Sys Check time. If the Check Synchronisation criteria are not satisfied
within the time period following a Close command the device will lockout and alarm.

7.8 CB CONTROL AR IMPLICATIONS

An Auto Close CB signal from the Auto-close logic bypasses the Man Close Delay time, and the CB Close output
operates immediately to close the circuit breaker.
If Autoreclose is used it may be desirable to block its operation when performing a manual close. In general, the
majority of faults following a manual closure are permanent faults and it is undesirable to allow automatic
reclosure.
To ensure that Autoreclose is not initiated for a manual circuit breaker closure on to a pre-existing fault, the CB IS
Time (circuit breaker in service time) setting in the AUTORECLOSE menu should be set for the desired time window.
This setting ensures that Autoreclose initiation is inhibited for a period equal to setting CB IS Time following a
manual circuit breaker closure. If a protection operation occurs during the inhibit period, Autoreclose is not
initiated.

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Following manual circuit breaker closure, if either a single phase or a three phase fault occur, the circuit breaker is
tripped three phase, but Autoreclose is not locked out for this condition.

7.9 CB CONTROL LOGIC DIAGRAM

CB Control by
Opto Note: If the DDB signal CB Healthy is not mapped in PSL it defaults to High .
Opto+Local
1
Opto+Remote
Opto+Rem+Local
Trip Pulse Time
HMI Trip Control Trip
1
& S t
& Q
Init Trip CB RD 0 & CB Trip Fail

&
Init close CB Man Close Delay Close Pulse Time
1 Close in Prog
HMI Close
& S t
CB ARIP Q
RD 0 & Control Close
1 S t
Auto Close Q
RD 0
Reset Close Dly

Any Trip & CB Close Fail

1
Control Trip

External Trip3Ph 1
1
External Trip A

External Trip B

External Trip C
1 1
CB Open 3 ph

CB Open A ph

CB Open B ph &
CB Open C ph

CB Closed 3 ph
1
CB Closed A ph

CB Closed B ph 1 CB Healthy Time

CB Closed C ph
t
& Man CB Unhealthy
CB Healthy 0

Check Sync Time

t
& No C/S Man Close
CB Man SCOK 0

V03369

Figure 252: CB Control logic diagram (Module 43)

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8 POLE DEAD FUNCTION

The Pole Dead Logic is used to determine and indicate that one or more phases of the line are not energised. A
Pole Dead condition is determined either by measuring:
● the line currents and/or voltages, or
● by monitoring the status of the circuit breaker auxiliary contacts, as shown by dedicated DDB signals.

It can also be used to block operation of underfrequency and undervoltage elements where applicable.

8.1 POLE DEAD LOGIC

IA 20 ms

I< Current Set &

1 Pole Dead A
VA

V<

CB Open A ph

IB 20 ms

I< Current Set &

1 Pole Dead B
VB

V<

CB Open B ph

IC 20 ms

I< Current Set &

1 Pole Dead C
VC

1 Any Pole Dead

V<

VTS Slow Block

& All Poles Dead
CB Open C ph

CB Open 3 ph

V 01247

Figure 253: Pole Dead logic

If both the line current and voltage values fall below a certain threshold, or a CB Open condition is asserted from
the state control logic, the device initiates a Pole Dead condition. The current and voltage thresholds can be set
with the I< Current Set and the V< settings respectively, in the CBFAIL&P.DEAD column.
If one or more poles are dead, the device indicates which phase is dead and asserts the Any Pole Dead DDB
signal. If all phases are dead the Any Pole Dead signal is accompanied by the All Poles Dead signal.
If the VT fails, a VTS Slow Block signal is taken from the VTS logic to block the Pole Dead indications that would be
generated by the undervoltage and undercurrent thresholds.

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9 SYSTEM CHECKS
In some situations it is possible for both "bus" and "line" sides of a circuit breaker to be live when a circuit breaker is
open - for example at the ends of a feeder that has a power source at each end. Therefore, it is normally necessary
to check that the network conditions on both sides are suitable, before closing the circuit breaker. This applies to
both manual circuit breaker closing and autoreclosing. If a circuit breaker is closed when the line and bus voltages
are both live, with a large phase angle, frequency or magnitude difference between them, the system could be
subjected to an unacceptable shock, resulting in loss of stability, and possible damage to connected machines.
The System Checks functionality involves monitoring the voltages on both sides of a circuit breaker, and if both
sides are live, performing a synchronisation check to determine whether any differences in voltage magnitude,
phase angle or frequency are within permitted limits.
The pre-closing system conditions for a given circuit breaker depend on the system configuration, and for
autoreclosing, on the selected autoreclose program. For example, on a feeder with delayed autoreclosing, the
circuit breakers at the two line ends are normally arranged to close at different times. The first line end to close
usually has a live bus and a dead line immediately before reclosing. The second line end circuit breaker now sees a
live bus and a live line.
If there is a parallel connection between the ends of the tripped feeder the frequencies will be the same, but any
increased impedance could cause the phase angle between the two voltages to increase. Therefore just before
closing the second circuit breaker, it may be necessary to perform a synchronisation check, to ensure that the
phase angle between the two voltages has not increased to a level that would cause unacceptable shock to the
system when the circuit breaker closes.
If there are no parallel interconnections between the ends of the tripped feeder, the two systems could lose
synchronism altogether and the frequency at one end could "slip" relative to the other end. In this situation, the
second line end would require a synchronism check comprising both phase angle and slip frequency checks.
If the second line-end busbar has no power source other than the feeder that has tripped; the circuit breaker will
see a live line and dead bus assuming the first circuit breaker has re-closed. When the second line end circuit
breaker closes the bus will charge from the live line (dead bus charge).

9.1 SYSTEM CHECKS IMPLEMENTATION

The System Checks function provides Live/Dead Voltage Monitoring, two stages of Check Synchronisation and
System Split indication.
The System Checks function is enabled or disabled by the System Checks setting in the CONFIGURATION column. If
System Checks is disabled, the SYSTEM CHECKS menu becomes invisible, and a SysChks Inactive DDB signal is
set.
The System Checks functionality can also be enabled or disabled by the System Checks setting in the SYSTEM
CHECKS column. For the Systems Checks functionality to be enabled, both the System Checks setting in the
CONFIGURATION column AND the System Checks setting in the SYSTEM CHECKS column must be enabled. For the
System Checks functionality to be disabled, either the System Checks setting in the CONFIGURATION column OR
the System Checks setting in the SYSTEM CHECKS column must be be enabled. In the latter case, the SysChks
Inactive DDB signal is set.

9.1.1 VT CONNECTIONS
The device provides inputs for a three-phase "Main VT" and at least one single-phase VT for check synchronisation.
Depending on the primary system arrangement, the Main VT may be located on either the line-side of the busbar-
side of the circuit breaker, with the Check Sync VT on the other. Normally, the Main VT is located on the line-side (as
per the default setting), but this is not always the case. For this reason, a setting is provided where you can define
this. This is the Main VT Location setting, which is found in the CT AND VT RATIOS column.

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The Check Sync VT may be connected to one of the phase-to-phase voltages or phase-to-neutral voltages. This
needs to be defined using the CS Input setting in the CT AND VT RATIOS column. Options are, A-B, B-C, C-A, A-N, B-
N, or C-N.

9.1.2 VOLTAGE MONITORING

The settings in the VOLTAGE MONITORS sub-heading in the SYSTEM CHECKS column allow you to define the
threshold at which a voltage is considered live, and a threshold at which the voltage is considered dead. These
thresholds apply to both line and bus sides. If the measured voltage falls below the Dead Voltage setting, a DDB
signal is generated (Dead Bus, or Dead Line, depending on which side is being measured). If the measured voltage
exceeds the Live Voltage setting, a DDB signal is generated (Live Bus, or Live Line, depending on which side is
being measured).

9.1.3 CHECK SYNCHRONISATION

The device provides two stages of Check Synchronisation. The first stage (CS1) is intended for use in synchronous
systems. This means, where the frequencies and phase angles of both sides are compared and if the difference is
within set limits, the circuit breaker is allowed to close. The second stage (CS2) is similar to stage, but has an
additional adaptive setting. The second stage CS2 is intended for use in asynchronous systems, i.e. where the two
sides are out of synchronism and one frequency is slipping continuously with respect to another. If the closing time
of the circuit breaker is known, the CB Close command can be issued at a definite point in the cycle such that the
CB closes at the point when both sides are in phase.
In situations where it is possible for the voltages on either side of a circuit breaker to be either synchronous or
asynchronous, both CS1 and CS2 can be enabled to provide a CB Close signal if either set of permitted closing
conditions is satisfied.
Each stage can also be set to inhibit circuit breaker closing if selected blocking conditions such as overvoltage,
undervoltage or excessive voltage magnitude difference are detected. CS2 requires the phase angle difference to
be decreasing in magnitude before permitting the circuit breaker to close. CS2 has an optional “Adaptive” closing
feature, which issues the permissive close signal when the predicted phase angle difference immediately prior to
the instant of circuit breaker main contacts closing (i.e. after CB Close time) is as close as practicable to zero.
Slip frequency is the rate of change of phase between each side of the circuit breaker, which is measured by the
difference between the voltage signals on either side of the circuit breaker.
Having two system synchronism check stages available allows the circuit breaker closing to be enabled under
different system conditions (for example, low slip / moderate phase angle, or moderate slip / small phase angle).
The settings specific to Check Synchronisation are found under the sub-heading CHECK SYNC in the SYSTEM
CHECKS column. The only difference between the CS1 settings and the CS2 settings is that CS2 has a CS2 Adaptive
setting for predictive closure of CB.

9.1.4 CHECK SYNCRONISATION VECTOR DIAGRAM

The following vector diagram represents the conditions for the System Check functionality. The Dead Volts setting
is represented as a circle around the origin whose radius is equal to the maximum voltage magnitude, whereby
the voltage can be considered dead. The nominal line voltage magnitude is represented by a circle around the
origin whose radius is equal to the nominal line voltage magnitude. The minimum voltage magnitude at which the
system can be considered as Live, is the magnitude difference between the bus and line voltages.

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0º
Check Sync
Stage 2 Limits
Check Sync
Stage 1 Limits
V
BUS

Live Volts

Rotating
Vector
Nomical
Volts

V LINE

Dead Volts

±180º
System Split
E01204 Limits

Figure 254: Check Synchronisation vector diagram

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9.2 VOLTAGE MONITOR FOR CB CLOSURE

System Checks
Enabled

VAN
Live Line & Live Line
VBN

VCN
Select Dead Line & Dead line
VAB

VBC
Live Bus & Live Bus
VCA

VBus Dead Bus & Dead Bus

Voltage Monitors

MCB/VTS

MCB/VTS CB CS

1
Inhibit LL

1
Inhibit DL

1
Inhibit LB

1
Inhibit DB

V 01257

Figure 255: Voltage Monitor for CB Closure (Module 59)

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9.3 CHECK SYNCHRONISATION MONITOR FOR CB CLOSURE

System Checks
Disabled SysChks Inactive
Enabled

CS1 Criteria OK
VAN &
VBN CS2 Criteria OK
&
VCN
Select CS1 SlipF>
VAB & CS1 SlipF>

VBC CS1 SlipF<

& CS1 SlipF<
VCA CS2 SlipF>
& CS2 SlipF>
VBus
CS2 SlipF<
& CS2 SlipF<

CS Vline>
& CS Vline>

CS Vbus>
& CS Vbus>

CS Vline<
& CS Vline<
Check Synchronisation Function

CS Vbus<
& CS Vbus<

CS1 Vl>Vb
& CS1 Vl>Vb

CS1 Vl<Vb
& CS1 Vl<Vb

CS1 Fl>Fb
& CS1 Fl>Fb

CS1 Fl<Fb
& CS1 Fl<Fb

CS1 AngHigh+
& CS1 AngHigh+

CS1 AngHigh-
& CS1 AngHigh-

CS2 Fl>Fb
& CS2 Fl>Fb

CS2 Fl<Fb
& CS2 Fl<Fb

CS2 AngHigh+
& CS2 AngHigh+

CS2 AngHigh-
& CS2 AngHigh-

CS AngRotACW
MCB/VTS CB CS & CS AngRotACW

MCB/VTS CS AngRotCW
& CS AngRotCW
VTS Fast Block
1 CS2 Vl>Vb
F out of Range & CS2 Vl>Vb

CS2 Vl<Vb
& CS2 Vl<Vb
CS1 Status
Enabled
& Check Sync 1 OK
CS1 Enabled

CS2 Status
Enabled & Check Sync 2 OK

CS2 Enabled V01259

Figure 256: Check Synchronisation Monitor for CB closure (Module 60)

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9.4 SYSTEM CHECK PSL

SysChks Inactive

Check Sync 1 OK

Check Sync 2 OK

Live Line Man Check Synch

&
Dead Bus 1 AR Sys Checks

&
Dead Line

&
Live Bus
V02028

Figure 257: System Check PSL

9.5 APPLICATION NOTES

9.5.1 PREDICTIVE CLOSURE OF CIRCUIT BREAKER

The CS2 Adaptive setting compensates for the time taken to close the CB. When set to provide CB Close Time
compensation, a predictive approach is used to close the circuit breaker ensuring that closing occurs at close to 0º
therefore minimising the impact to the power system. The actual closing angle is subject to the constraints of the
existing product architecture, i.e. the protection task runs twice per power system cycle, based on frequency
tracking over the frequency range of 40 Hz to 70 Hz.

9.5.2 VOLTAGE AND PHASE ANGLE CORRECTION

For the Check Synchronisation function, the device needs to convert measured secondary voltages into primary
voltages. In some applications, VTs either side of the circuit breaker may have different VT Ratios. In such cases, a
magnitude correction factor is required.
There are some applications where the main VT is on the HV side of a transformer and the Check Sync VT is on the
LV side, or vice-versa. If the vector group of the transformer is not "0", the voltages are not in phase, so phase
correction is also necessary.
The correction factors are as follows and are located in the CT AND VT RATIOS column:
● C/S V kSM, where kSM is the voltage correction factor.
● C/S Phase kSA, where kSA is the angle correction factor.
Assuming C/S input setting is A-N, then:
The line and bus voltage magnitudes are matched if Va sec = Vcs sec x C/S V kSA
The line and bus voltage angles are matched if ÐVa sec = ÐVcs sec + C/S Phase kSA
The following application scenarios show where the voltage and angular correction factors are applied to match
different VT ratios:
Physical Ratios (ph-N Values) Setting Ratios CS Correction Factors
Main VT Ratio (ph-
Scenario Main VT Ratio CS VT Ratio CS VT Ratio
ph) Always kSM kSA
Pri (kV) Sec (V) Pri (kV) Sec (V) Pri (kV) Sec (V) Pri (kV) Sec (V)
1 220/√3 110/√3 132/√3 100/√3 220 110 132 100 1.1 30º

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2 220/√3 110/√3 220/√3 110 220 110 127 110 0.577 0º

3 220/√3 110/√3 220/√3 110/3 220 110 381 110 1.732 0º

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SUPERVISION
Chapter 18 - Supervision P543i/P545i

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1 CHAPTER OVERVIEW
This chapter describes the supervison functions.
This chapter contains the following sections:
Chapter Overview 461
Current Differential Supervision 462
Voltage Transformer Supervision 470
Current Transformer Supervision 475
Trip Circuit Supervision 479

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2 CURRENT DIFFERENTIAL SUPERVISION

Current Differential protection of transmission lines or distribution feeders requires communication of measured
values of currents between terminals so that a comparison of current entering and leaving the protected zone can
be made. To determine the health of the protected zone, the current values received from a remote terminal must
be synchronised to locally acquired values. One method of achieving this is the so called ‘Ping-Pong’ method. For
this method to work, there is a requirement that the time taken for signals communicated from one terminal to
another (the propagation delay time) is equal to the time taken for signals to be communicated between the same
devices in the opposite direction. This is an assumption that is valid for many applications and which has been
widely applied. In some applications however, the communications symmetry may be violated either temporarily
or permanently. If the requirement is violated, the Ping-Pong method cannot work correctly and maloperation may
occur. Some products in this range can use a Global Positioning Satellite (GPS) input signal to provide a precise
timing signal that can be used to synchronise the alignment of the current values. This allows the protection to
work in applications where the communications paths may not be symmetrical. If there is no GPS synchronisation
signal available or its performance becomes severely degraded, a technique based on the Ping-Pong method is
employed to maintain the Current Differential protection. Unfortunately, with this compromised GPS
synchronisation technique, as well as with the standard Ping-Pong technique, switching of communications paths
can lead to miscalculation of bias and differential currents which could lead to maloperation. To help prevent this a
number of supervision checks can be applied to Current Differential protection that is not GPS synchronised. These
are:
● Current Differential Starter Supervision (Permit Current Differential)
● Switched Communications Paths Supervision
● Communications Asymmetry Supervision.

2.1 CURRENT DIFFERENTIAL STARTER SUPERVISION

An unexpected communications asymmetry condition can cause an apparent rise in the differential current. This
causes a condition that could be interpreted as a three-phase (balanced) fault condition. Positive sequence current
components are apparent in normally operating systems. A balanced fault will increase the magnitude of these
positive sequence components. Any increase resulting from a communications asymmetry will be modest.
However, a real three-phase fault will generally cause the magnitude of the positive sequence components to
increase far more than an asymmetric communication condition would. The measurement of positive sequence
current components can therefore be used to supervise Current Differential protection for balanced fault
conditions.
Unbalanced faults always produce negative sequence current components. Negative sequence current
components can therefore be used to supervise Current Differential protection for unbalanced fault conditions.
The components that implement this supervision are called Starter Elements. Both positive-sequence current (I1)
and negative-sequence current (I2) are derived. For both I1 and I2, there are two types of starter element for each
sequence component; fixed threshold and rate-of-change threshold (delta). There are four Starter Elements in all:
● Start I1 low
● Delta I1 low
● Start I2 low
● Delta I2 low

Which starter elements are used and in which combination depend on the specific application and customer
requirements. The device provides complete flexibility, allowing you to use each of them individually or in
combination with one another using PSL.
The starter element settings are located in the CURRENT DIFF column. You can choose to enable, or disable them,
or select Idiff Permit (discussed later). They are disabled by default.

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If a starter element picks up, the associated DDB signal is asserted. These can be used to block the current
differential protection. These DDB signals are:
● I1 Lo Start (Positive phase-sequence fixed threshold start)
● Del I1 Lo Start (Rate-of-change of positive phase-sequence current)
● I2 Lo Start (Negative phase-sequence fixed threshold start)
● Del I2 Lo Start (Rate-of-change of negative phase-sequence current)

If elements are set to Disabled, then the DDB signals cannot be asserted.
If elements are set to Enabled, then the DDB signals will be asserted if appropriate conditions are met. This will
allow you to use PSL to customize supervision of Current Differential protection operation. These signals do not
directly affect the operation of the Current Differential function. In order to directly influence the operation of the
current differential function you need to set one or more of the starter elements to Idiff Permit.
If elements are set to Idiff Permit, then the DDB Start signals will also be asserted if the appropriate
conditions are met, so you can use the PSL to customise supervision of Current Differential protection operation. In
addition however, if any one or more elements are set to IDiff Permit, then fixed internal logic is employed to
produce an internal signal (Permit CDiff) that supervises the Current Differential protection by either inhibiting it or
permitting it.

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2.1.1 CURRENT DIFFERENTIAL STARTER SUPERVISION LOGIC

I1

& I1 Lo Start
Start I1 low

Start I1
Disabled
1/ 8 cycle
I1 Delta
PU
S
Q Del I1 Lo Start
Delta I1 low & R

1
Block Delta PU
Delta I1
Disabled
Reset Low Time
I2

& I2 Lo Start
Start I 2 Low

Start I2
Disabled
1/ 8 cycle
I2 Delta
PU
S
Q Del I2 Lo Start
Delta I2 low & R

Block Delta 1
PU
Block Start I2 1 Any Low Set Start
Delta I2 1
Reset Low Time
Disabled
1 Any Delta Start
Start I1
Idiff permit
1 Any Thresh Start
Delta I1
Start
Idiff I1
permit
&
Start I2
Idiff permit

Delta I2
Idiff permit

I1
&

Start I1 low

I1 Delta
&
1 Permit Cdiff
Delta I1 low

I2
&

Start I 2 Low

I2 Delta
&

Delta I2 low
V 02600

Figure 258: Current Differential Starter Supervision Logic

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2.1.2 CURRENT DIFFERENTIAL START LOGIC

The Permit Cdiff internal signal interacts with the Current Differential function to control the Current Differential
start signals. the following figure shows how this is achieved for the line differential currents. The same principle
applies to neutral differential current.

Permit Cdiff SD
Q
1 R

& IDiff>Start A
Phase A Current Differential threshold reached

& IDiff>Start B
Phase B Current Differential threshold reached

& IDiff>Start C
Phase C Current Differential threshold reached

V02601

Figure 259: Current Differential function Start logic

2.2 SWITCHED COMMUNICATION PATH SUPERVISION

A feature is included in this product to supervise the operation of the Current Differential protection in the event of
communications paths being switched. The Ping-Pong method of time alignment requires symmetry of
communications paths. The absolute value of propagation delay is not important, but the symmetry is. Many
telecommunication systems feature self-healing mechanisms so that if a particular link fails, the integrity of the
system can be maintained by re-routing of traffic via unaffected links. Careful system management can ensure
that the reconfiguration of the system to bypass the failed link can respect the communications symmetry
requirements. Whilst the reconfiguration is in progress, however, there may be a temporary violation of the
symmetry requirements. The Switched Communications Paths Supervision function protects against incorrect
tripping during the period of transient symmetry violation.
The settings for the Switched Communications Paths Supervision reside in the CURRENT DIFF column.
The Current Differential protection continually monitors the communications propagation delay time. With
reference to the following figure, if the differences between 2 successive calculated propagation times exceed the
Comm Delay Tol setting in the PROT COMMS/ IM64 column, then the operating characteristic is modified from the
blue line to the red line.

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Idiff Normal Tripping Characteristic

Supervised Tripping Characteristic

Operate
Region
K2 slope
Supervise
Region

Restrain
K1 Slope
Region

IS1

IS2 Ibias
V02603

Figure 260: Switched Communication Path supervision

The change to the characteristic is determined by two timers (Char Mod Time, and Char Mod RstTime) found in
the PROT COMMS/IM64 column. These timers start when the switched communication path condition is
recognised. These timers define how long the modification to the tripping characteristics is applied for. A
communications delay alarm (Comm Delay Alarm) is also raised at the same time.
When the Comm Delay Tol setting has been exceeded for two consecutive calculations, the K1 slope is increased
to 200%. When the 200% slope reaches the IS2 setting, the characteristic tracks a horizontal line until it meets
with the K2 slope which the characteristic then follows.
The characteristic normally returns to normal when the Char Mod Time expires, but a mechanism is provided to
accelerate the reset if system conditions permit by using an additional timer Char Mod RstTime which is set to a
value less than the Char Mod Time.
The Char Mod RstTime can be enabled or disabled. If it is enabled, then it starts when the Char Mod Time starts. If
the Char Mod RstTime has expired, but the Char Mod Time is still running, AND IF the bias current is above 5% In,
AND IF the differential current is below 10% of bias current on all phases, then the Char Mod Time is reset and the
characteristic returns to normal. If these conditions are not met, then the characteristic remains increased for the
duration of the Char Mod Time. The Char Mod RstTime should be set greater than the minimum switching delay
expected, and less than the Char Mod Time.
We don’t recommend it, but If you don’t want the tripping characteristic to be changed during communications
switching operations, you should set Char Mod Time to 0.

2.3 COMMUNICATIONS ASYMMETRY SUPERVISION

The settings for this function reside under the DIFF SUPERVISON sub-heading of the SUPERVISION column.
The Communications Asymmetry Supervision function is included to supervise the Current Differential protection
on applications where communications path switching is expected. It is particularly intended to identify a situation
where communications switching has occurred and the communications has been re-established onto paths
where the symmetry requirements are not fully respected, but where the arising apparent differential current is
insufficient to cause tripping. It is usually used to indicate that the telecommunications network is not configured
as expected. It can also be used to block operation of the Current Differential protection until the issue has been
resolved. If the communications paths between a pair of devices are running on different paths, the protection will
calculate an apparent differential current even though the currents entering and leaving the protected zone
balance. If this pseudo-differential current exceeds the criteria for tripping, maloperation will occur. If the level is
less, it can be assumed to be caused by asymmetric communications paths and the restraint characteristic can be

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changed to prevent tripping should the effect of increasing load current with communications asymmetry take the
apparent differential current above the operate threshold.
Referring to the Switched Communication Path Supervision feature, if communication switching takes place, the
Current Differential protection will detect a propagation delay change and invoke a temporary increase in the
tripping threshold for a period set in the Char Mod Time setting column. When the timer expires, the standard
characteristic is restored. Whilst the timer is active, the differential protection will be stable for asymmetric
communication paths but if the asymmetry persists when the characteristic switches back, the protection might
trip. Using the current differential supervision feature, the condition can be detected and maloperation can be
prevented.
The function superimposes a second dual slope characteristic (defined by the settings IDiff Isup1 and IDiff Isup2)
onto the standard operating characteristic as shown in the figure below:

Idiff

K2 slope

Operate
Supervise
(Block or Alarm)

K1 Slope
Restrain
IS1
Isup1

IS2 Isup2 Ibias

V02604

Figure 261: Communication Asymmetry Supervision

If you choose to use the function, we recommend that you set the pickup value of the differential supervision
function (IDiff Isup1) be set at 80% of the Is1 setting and the IDiff Isup2 setting to 200% of Is2. The delay between
the condition being recognised and the alarm being raised is determined by the Idiff Sup TDelay setting.

Note:
Idiff Sup TDelay must always be set greater than the value set in Char Mod time.

2.4 GPS SYNCHRONISATION SUPERVISION

You can enable or disable GPS syncrhonisation supervision using the GPS Sync setting in the PROT COMMS/ IM64
column. It is disabled by default. There are three options with which you can enable the GPS synchronisation. Each
provides a different approach to supervising the Current Differential protection should the GPS synchronisation
signal become corrupt or unavailable. The three options available are:
● GPS -> Standard
● GPS -> Inhibit
● GPS -> Restrain
If the GPS signal is available, terminals will be synchronised, and the communications paths propagation delay
times (tp1 and tp2) will be continuously calculated and retained by each terminal. Should there be a failure of the
GPS input, the synchronisation might be lost and the product will adapt its operation according to the chosen GPS
Sync setting as explained below.

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GPS Standard
If GPS -> Standard is selected, the time alignment of the current data is performed by using the values of
propagation delay times (tp1, tp2) that were calculated and stored prior to the GPS failure. Each terminal continues
to measure the overall propagation delay (tp1+tp2). If the overall propagation delay remains unchanged, the
differential protection will continue to use the stored values until the GPS synchronisation is restored.
A communications delay tolerance setting (Comm Delay Tol) is provided. If the overall propagation delay changes
but by an amount less than this setting, the differential protection will continue to use the stored values of tp1 and
tp2 until GPS synchronisation is restored. If the overall propagation delay changes by an amount more than this
setting, the differential protection will be blocked until GPS synchronisation is restored.

GPS Inhibit
With GPS -> Inhibit selected, if the propagation delay times are equal when the GPS synchronisation is lost,
the product reverts to the ping-pong method of time alignment. If the propagation delays are not equal when the
GPS signal is lost, the product performs in the same way as if GPS -> Standard had been selected, using the
stored propagation delay times.
If the propagation delay changes by more than the Comm Delay Tol setting, the differential protection is blocked
until GPS synchronisation is restored.

GPS Restrain
If GPS -> Restrain is selected in the GPS Sync setting, the supervision applied to the Current Differential
function is the same as that for Switched Communications Paths Supervision described previously, and based on
increasing the bias quantity if path switching is detected.
In this case, if GPS has failed, and if the difference between successive propagation delay time measurements
exceeds the user settable Comm Delay Tol value, the device asserts the Comm Delay Alarm DDB signal and
initiates the temporary change in the bias characteristic managed by the Char Mod Time and Char Mod RstTime
settings.

2.4.1 PROPOGATION DELAY MANAGEMENT

When GPS synchronisation is used, there are some settings that are provided to control the behaviour of the
product according to the propagation delay times between terminals. These are described, together with some
related settings in the table below:
Setting Description.
This applies if the device is using GPS synchronisation. If the GPS signal is lost and there is a switch in the
protection communications network, the differential protection is inhibited. When the GPS is restored, the
differential protection will return to service. Using this setting you can return the differential protection to
Prop Delay Equal service in the absence of the GPS signal. Before activating this setting you must be sure that the
communication receiver and transmitter path delays (go and return) are equal, otherwise false tripping may
occur.
The setting is invisible when GPS Sync is disabled.
This setting enables (activates) or disables (turns off) the alarms of Maximum propagation delay time described
Prop Delay Stats
by the MaxCh1 PropDelay and MaxCh2 PropDelay settings
When the protection communications are enabled, the overall propagation delay divided by 2 is calculated for
channel 1. The maximum value is determined and displayed in the MEASUREMENTS 4 column. The value is
MaxCh1 PropDelay
compared against the MaxCh1 PropDelay setting. If the setting is exceeded, an alarm MaxCh1 PropDelay DDB
is raised.
When the protection communications are enabled, and where used, the overall propagation delay divided by 2
is calculated for channel 2. The maximum value is determined and displayed in the MEASUREMENTS 4 column.
MaxCh2 PropDelay
The value is compared against the MaxCh2 PropDelay setting. If the setting is exceeded, an alarm MaxCh2
PropDelay DDB is raised.
This is used to enable (activate) or disable (turn off) the alarms of absolute difference between the
TxRx Delay Stats
Transmission and Reception propagation delay. This setting is not visible if GPS Sync is disabled.

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Setting Description.
When Current Diff is enabled and if GPS Sync is not disabled, the absolute difference between the Transmission
and Reception propagation delay on channel 1 is calculated. The maximum value is displayed in the
MaxCh1 Tx-RxTime
MEASUREMENTS 4 column. The value is compared against the MaxCh1 Tx-RxTime setting. If the setting is
exceeded, an alarm, MaxCh1 Tx-RxTime DDB is raised.
When Current Diff is enabled and if GPS Sync is not disabled, if channel 2 is used, the absolute difference
between the Transmission and Reception propagation delay is calculated. The maximum value is displayed in
MaxCh2 Tx-RxTime
the MEASUREMENTS 4 column. The value is compared against the MaxCh2 Tx-RxTime setting. If the setting is
exceeded, an alarm, MaxCh2 Tx-RxTime DDB is raised.
This sets the time delay after which the GPS Alarm signal is asserted following a loss of GPS signal or by
GPS Fail Timer
initiation by the GPS transient fail alarm function described by the setting GPS Trans Fail.
To enable (activate) or disable (turn off) the transient GPS Fail alarm function described by the GPS Trans Count
GPS Trans Fail
and GPS Trans Timer settings.
Sets the count for the number of failed GPS signals which must be exceeded in the GPS Trans Timer setting
GPS Trans Count
window after which the GPS Fail Timer is initiated.
Sets the rolling time window in which the GPS Trans Count must be exceeded after which the GPS Fail Timer is
GPS Trans Timer
initiated.

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3 VOLTAGE TRANSFORMER SUPERVISION

The Voltage Transformer Supervision (VTS) function is used to detect failure of the AC voltage inputs to the
protection. This may be caused by voltage transformer faults, overloading, or faults on the wiring, which usually
results in one or more of the voltage transformer fuses blowing.
If there is a failure of the AC voltage input, the IED could misinterpret this as a failure of the actual phase voltages
on the power system, which could result in unnecessary tripping of a circuit breaker.
The VTS logic is designed to prevent such a situation by detecting voltage input failures, which are NOT caused by
power system phase voltage failure, and automatically blocking associated voltage dependent protection
elements. A time-delayed alarm output is available to warn of a VTS condition.
The following scenarios are possible with respect to the failure of the VT inputs.
● Loss of one or two-phase voltages
● Loss of all three-phase voltages under load conditions
● Absence of three-phase voltages upon line energisation

3.1 LOSS OF ONE OR TWO PHASE VOLTAGES

If the power system voltages are healthy, no Negative Phase Sequence (NPS) current will be present. If however,
one or two of the AC voltage inputs are missing, there will be Negative Phase Sequence voltage present, even if the
actual power system phase voltages are healthy. VTS works by detecting Negative Phase Sequence (NPS) voltage
without the presence of Negative Phase Sequence current. So if there is NPS voltage present, but no NPS current,
it is certain that there is a problem with the voltage transformers and a VTS block should be applied to voltage
dependent protection functions to prevent maloperation. The use of negative sequence quantities ensures correct
operation even where three-limb or V-connected VTs are used.
The Negative Sequence VTS Element is blocked by the Any Pole Dead DDB signal during SP AR Dead Time. The
resetting of the blocking signal is delayed by 240 ms after an Any Pole Dead condition disappears.

3.2 LOSS OF ALL THREE PHASE VOLTAGES

If all three voltage inputs are lost, there will be no Negative Phase Sequence quantities present, but the device will
see that there is no voltage input. If this is caused by a power system failure, there will be a step change in the
phase currents. However, if this is not caused by a power system failure, there will be no change in any of the
phase currents. So if there is no measured voltage on any of the three phases and there is no change in any of the
phase currents, this indicates that there is a problem with the voltage transformers and a VTS block should be
applied to voltage dependent protection functions to prevent maloperation.
To avoid blocking VTS due to changing load condition, the superimposed current signal can only prevent operation
of the VTS during the time window of 40 ms following the voltage collapse.

3.3 ABSENCE OF ALL THREE PHASE VOLTAGES ON LINE ENERGISATION

On line energisation there should be a change in the phase currents as a result of loading or line charging current.
Under this condition we need an alternative method of detecting three-phase VT failure.
If there is no measured voltage on all three phases during line energisation, two conditions might apply:
● A three-phase VT failure
● A close-up three-phase fault.

The first condition would require VTS to block the voltage-dependent functions.
In the second condition, voltage dependent functions should not be blocked, as tripping is required.
To differentiate between these two conditions an overcurrent level detector is used (VTS I> Inhibit). This prevents a
VTS block from being issued in case of a genuine fault. This overcurrent level detector is only enabled for 240 ms

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following line energization (based on an All Poles Dead signal drop off). It must still be set in excess of any non-
fault based currents on line energisation (load, line charging current, transformer inrush current if applicable), but
below the level of current produced by a close-up three-phase fault.
If the line is closed where a three-phase VT failure is present, the overcurrent detector will not operate and a VTS
block will be applied. Closing onto a three-phase fault will result in operation of the overcurrent detector and
prevent a VTS block being applied.

3.4 VTS IMPLEMENTATION

VTS is implemented in the SUPERVISION column of the relevant settings group.
The following settings are relevant for VT Supervision:
● VTS Mode: determines the mode of operation (Measured + MCB, Measured Only, MCB Only)
● VTS Status: determines whether the VTS Operate output will be a blocking output or an alarm indication
only
● VTS Reset Mode: determines whether the Reset is to be manual or automatic
● VTS Time Delay: determines the operating time delay
● VTS I> Inhibit: inhibits VTS operation in the case of a phase overcurrent fault
● VTS I2> Inhibit: inhibits VTS operation in the case of a negative sequence overcurrent fault
For faults with I2 less than the setting VTS I2 Inhibit, VTS will be active and block the associated functions if
sufficient V2 is measured. VTS is only enabled during a live line condition (as indicated by the pole dead logic) to
prevent operation under dead system conditions.

Thresholds
The negative sequence thresholds used by the element are:
● V2 = 10 V (fixed)
● I2 = 0.05 to 0.5 In settable (default 0.05 In).

The phase voltage level detectors are:

● Drop off = 10 V (fixed)
● Pickup = 30 V (fixed)

The sensitivity of the superimposed current elements is fixed at 0.1 In.

Fuse Fail
The device includes a setting (VT Connected ) in the CT AND VT RATIOS column, which determines whether there
are voltage transformers connected to it. If set to Yes, this setting has no effect.
If set to No it causes the VTS logic to set the VTS Slow Block and VTS Fast Block DDBs, but not raise any alarms. It
also disables the VTS function. This prevents the pole dead logic working incorrectly if there is no voltage or
current. It also blocks the distance, under voltage and other voltage-dependant functions. However, it does not
affect the CB open part of the logic.
A VTS condition can be raised by a mini circuit breaker (MCB) status input, by internal logic using IED
measurement, or both. The setting VTS Mode is used to select the method of indicating VT failure.

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3.5 VTS LOGIC

All Poles Dead

IA

240ms
VTS I> Inhibit

IB &
1
VTS I> Inhibit

IC

VTS I> Inhibit

VA

VTS Time Delay

Hardcoded threshold
VB
1
Hardcoded threshold 1 & S
Q
VC R 1
& VTS Slow Block

Hardcoded threshold

Delta IA

& S 1 & VTS Fast Block

Hardcoded threshold Q
R
Delta IB
1
Hardcoded threshold 1
Delta IC

Hardcoded threshold
&
V2

Hardcoded threshold & & S

Q
I2
R

I2>1 Current Set &

Any Voltage dependent
function
VTS Reset Mode
Manual &
1
Auto

MCB/VTS

VTS Status
Indication
Blocking
1 S 1 VT Fail Alarm
Any Pole Dead & Q
240ms R
& 20ms
VTS Acc Ind

5
Cycle
1½
½ Cycle
Cycle
VT Fast Block 1 Block Distance

&
All Poles Dead ½
Cycle
V01261

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Figure 262: VTS logic

The IED may respond as follows, on operation of any VTS element:

● VTS set to provide alarm indication only
● Optional blocking of voltage-dependent protection elements
● Optional conversion of directional overcurrent elements to non-directional protection (by setting the
relevant current protection status cells to Enabled VTS. In this case, the directional setting cells are
automatically set to non-directional.)
The VTS I> Inhibit or VTS I2> Inhibit elements are used to override a VTS block if a fault occurs that could trigger
the VTS logic. However, once the VTS block is set, subsequent system faults must not override the block. Therefore
the VTS block is latched after a settable time delay (VTS Time Delay). Once the signal has latched, there are two
methods of resetting. The first is manually using the front panel HMI, or remote communications (if the VTS
condition has been removed). The second is in Auto mode, by restoring the 3 phase voltages above the phase level
detector settings mentioned previously.
VTS Status can be set to Disabled, Blocking or Indication. If VTS Status is set to Blocking, a VTS
condition will block operation of the relevant protection elements. In this case, a VTS indication is given after the
VTS Time Delay has expired. If it is set to Indication, their is a risk of maloperation because protection
elements are not blocked. In this case the VTS indication is given before the VTS Time Delay expires, if a trip signal
is given (in this case a signal from the VTS acceleration logic is used as an input).
This scheme also operates correctly under very low load or even no load conditions. To achieve this, it uses a
combination of time delayed signals derived from the DDB signals VTS Fast Block and All Poles Dead, to generate
the distance blocking DDB signal called VTS Blk Distance.

Note:
All non-distance voltage-dependent elements are blocked by the VTS Fast Block DDB.

If a miniature circuit breaker (MCB) is used to protect the voltage transformer output circuits, MCB auxiliary
contacts can be used to indicate a three-phase output disconnection. It is possible for the VTS logic to operate
correctly without this input, but this facility has been provided to maintain compatibility with some practises.
Energising an opto-isolated input assigned to the MCB/VTS provides the necessary block.
The VTS function is inhibited if:
● An All Poles Dead DDB signal is present
● Any phase overcurrent condition exists
● A Negative Phase Sequence current exists
● If the phase current changes over the period of 1 cycle

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4 CURRENT TRANSFORMER SUPERVISION

The Current Transformer Supervision function (CTS) is used to detect failure of the AC current inputs to the
protection. This may be caused by internal current transformer faults, overloading, or faults on the wiring. If there
is a failure of the AC current input, the protection could misinterpret this as a failure of the actual phase currents
on the power system, which could result in maloperation. Also, interruption in the AC current circuits can cause
dangerous CT secondary voltages to be generated.
The IED has two methods of providing Current Transformer Supervision (CTS); differential and standard. The
differential method uses the ratio between positive and negative sequence currents to determine CT failure. This
method is not voltage dependant and relies on channel communications to declare a CTS condition.
The standard method relies on local measurements of zero sequence currents and voltages. You select the
method according to the application. Both methods can be applied individually or in parallel.
The CTS Mode setting in the SUPERVISION column is used to set the method. The options are:
● Disabled
● Standard
● Idiff
● Idiff + Std
The CTS Reset Mode setting determines whether the CTS will reset automatically or will need manual intervention.

4.1 DIFFERENTIAL CTS

Differential CTS does not need any local voltage measurements to determine a CTS condition. It is based on
measurement of the ratio of negative sequence current to positive sequence current (I2/I1) at all line ends. When
this ratio is small (theoretically zero), one of four possible conditions apply:
● The system is unloaded (both I2 and I1 are zero)
● The system is loaded but balanced (I2 is zero)
● The system has a three phase fault present (I2 is zero)
● There is a genuine 3 phase CT problem (unlikely, but if this is the case it would probably develop from a
single or two phase condition)

If the ratio is non-zero, we can assume one of two conditions are present:
● The system has an unbalanced fault (both I2 and I1 are non-zero)
● There is a 1 or 2 phase CT problem (both I2 and I1 are non-zero)

Measurement at a single end cannot provide any more information than this. However, if the ratio is calculated at
all ends and compared, the device can make a decision based on the following criteria:
● If the ratio is non-zero at more than two ends, it is almost certainly a genuine fault condition and so the CT
supervision is prevented from operating.
● If the ratio is non-zero at one end, there is a chance of either a CT problem or a single-end fed fault
condition.
A second criterion looks to see whether the differential system is loaded or not. For this purpose the device looks
at the positive sequence current I1. If load current is detected at one-end only, the device assumes that this is an
internal fault condition and prevents CTS operation. However, if load current is detected at two or more ends, this
indicates CT failure, so CTS operation is allowed.
There are two modes of operation, Indication and Restrain. You determine the mode of operation with the
CTS Status setting. In Indication mode, a CTS alarm is raised but there is no effect on tripping. In Restrain
mode, the differential protection is blocked for 20 ms after CT failure detection, then the Current Differential
threshold setting is raised above the load current.
For correct operation of the scheme, Differential CTS must be enabled at each end of the protected zone.

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4.2 DIFFERENTIAL CTS LOGIC

Inhibit CTS
&
Any Trip

Disable CTS

CT1 L i1>
1
CT1 R1 i1>
>
=
2
CT1 R2 i1>

CT1 L i2/i1>>
CTS Status CTS Time Delay

Indication
CT1 R1 i2/i1> S
& Pickup
Q CT Fail Alarm
CT1 R2 i2/i1> & R

1
CTS Reset Mode CTS Status & CTS Block

Manual Restrain
CT1 R1 i2/i1 >>
CT1 L i2/i1>
Auto 1

&
CTS Status
CT1 R2 i2/i1>
Restrain

CTS Restrain

& Pickup
CTS Status 1 & CTS Block Diff
Indication

CTS Time Delay

1 Pickup S
Q Remote CT Alarm
& R
*
CT1 R2 i2 /i1 >>
CT1 L i2/i1>

& 1 *In indication mode , timer is set to 20ms

CT1 R1 i2/i1> CTS Reset Mode
Manual
Auto V01262

Figure 263: Differential CTS

4.3 CTS IMPLEMENTATION

If the power system currents are healthy, no zero sequence voltage are derived. However, if one or more of the AC
current inputs are missing, a zero sequence current would be derived, even if the actual power system phase
currents are healthy. Standard CTS works by detecting a derived zero sequence current where there is no
corresponding derived zero sequence voltage.
The voltage transformer connection used must be able to refer zero sequence voltages from the primary to the
secondary side. Therefore, this element should only be enabled where the VT is of a five-limb construction, or
comprises three single-phase units with the primary star point earthed.

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The CTS function is implemented in the SUPERVISION column of the relevant settings group, under the sub-heading
CT SUPERVISION.
The following settings are relevant for CT Supervision:
● CTS Status: to disable or enable CTS
● CTS VN< Inhibit: inhibits CTS if the zero sequence voltage exceeds this setting
● CTS IN> Set: determines the level of zero sequence current
● CTS Time Delay: determines the operating time delay

4.4 STANDARD CTS LOGIC

CTS Time Delay
IN2

& Pickup S
CTS IN> Set
Q CT Fail Alarm
VN * & R

CTS VN< Inhibit 1

& CTS Block
Inhibit CTS
1
Disable CTS

CTS Status 1
In indication mode , timer is set to 20ms
Indication
Restrain

CTS Reset Mode

Manual
Auto

V 01263

Figure 264: Standard CTS

4.5 CTS BLOCKING

Both the standard and differential CTS methods block protection elements operating from derived quantities, such
as Broken conductor, derived earth fault and negative sequence overcurrent. Measured quantities such as DEF
can be selectively blocked by designing an appropriate PSL scheme.
Differential CTS can be used to restrain the differential protection if required.

4.6 APPLICATION NOTES

4.6.1 SETTING GUIDELINES

The residual voltage setting, CTS VN< Inhibit and the residual current setting, CTS IN> Set, should be set to avoid
unwanted operation during healthy system conditions. For example:
● CTS VN< Inhibit should be set to 120% of the maximum steady state residual voltage.
● CTS IN> Set will typically be set below minimum load current.
● CTS Time Delay is generally set to 5 seconds.

Where the magnitude of residual voltage during an earth fault is unpredictable, the element can be disabled to
prevent protection elements being blocked during fault conditions.

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4.6.2 DIFFERENTIAL CTS SETTING GUIDELINES

The Phase Is1 CTS setting must be set above the phase current of the maximum load transfer expected, normally
at 1.2 In. This setting defines the minimum pick-up level of the current differential protection once the current
transformer supervision CTS is detected.
The CTS i1> setting, once exceeded, indicates that the circuit is loaded. A default setting of 0.1 In is considered
suitable for most applications, but could be lowered in case of oversized CTs.
The CTS i2/i1> setting should be in excess of the worst unbalanced load expected in the circuit under normal
operation. It is recommended to read out the values of i2 and i1 in the MEASUREMENTS 1 column and set the ratio
above 5% of the actual ratio.
The CTS i2/i1>> setting should be kept at the default setting (40% In). If the ratio i2/i1 exceeds the value of this
setting at only one end, the CT failure is declared.

Note:
The minimum generated i2/i1 ratio will be 50% (case of one CT secondary phase lead being lost), and therefore a setting of
40% is considered appropriate to guarantee sufficient operating speed.

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5 TRIP CIRCUIT SUPERVISION

In most protection schemes, the trip circuit extends beyond the IED enclosure and passes through components
such as links, relay contacts, auxiliary switches and other terminal boards. Such complex arrangements may
require dedicated schemes for their supervision.
There are two distinctly separate parts to the trip circuit; the trip path, and the trip coil. The trip path is the path
between the IED enclosure and the CB cubicle. This path contains ancillary components such as cables, fuses and
connectors. A break in this path is possible, so it is desirable to supervise this trip path and to raise an alarm if a
break should appear in this path.
The trip coil itself is also part of the overall trip circuit, and it is also possible for the trip coil to develop an open-
circuit fault.
This product supports a number of trip circuit supervision (TCS) schemes.

5.1 TRIP CIRCUIT SUPERVISION SCHEME 1

This scheme provides supervision of the trip coil with the CB open or closed, however, it does not provide
supervision of the trip path whilst the breaker is open. The CB status can be monitored when a self-reset trip
contact is used. However, this scheme is incompatible with latched trip contacts, as a latched contact will short out
the opto-input for a time exceeding the recommended Delayed Drop-off (DDO) timer setting of 400 ms, and
therefore does not support CB status monitoring. If you require CB status monitoring, further opto-inputs must be
used.

Note:
A 52a CB auxiliary contact follows the CB position. A 52b auxiliary contact is the opposite.

+ve

Trip Output Relay 52A Trip coil

Trip path

Blocking diode

52B

R1 Opto-input Circuit Breaker

V01214 -ve

Figure 265: TCS Scheme 1

When the CB is closed, supervision current passes through the opto-input, blocking diode and trip coil. When the
CB is open, supervision current flows through the opto-input and into the trip coil via the 52b auxiliary contact.
This means that Trip Coil supervision is provided when the CB is either closed or open, however Trip Path
supervision is only provided when the CB is closed. No supervision of the trip path is provided whilst the CB is open
(pre-closing supervision). Any fault in the trip path will only be detected on CB closing, after a 400 ms delay.

5.1.1 RESISTOR VALUES

The supervision current is a lot less than the current required by the trip coil to trip a CB. The opto-input limits this
supervision current to less than 10 mA. If the opto-input were to be short-circuited however, it could be possible for
the supervision current to reach a level that could trip the CB. For this reason, a resistor R1 is often used to limit the
current in the event of a short-circuited opto-input. This limits the current to less than 60mA. The table below
shows the appropriate resistor value and voltage setting for this scheme.
Trip Circuit Voltage Opto Voltage Setting with R1 Fitted Resistor R1 (ohms)
48/54 24/27 1.2k

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Trip Circuit Voltage Opto Voltage Setting with R1 Fitted Resistor R1 (ohms)
110/125 48/54 2.7k
220/250 110/125 5.2k

Warning:
This Scheme is not compatible with Trip Circuit voltages of less than 48 V.

5.1.2 PSL FOR TCS SCHEME 1

0 0
Opto Input dropoff Straight *Output Relay
400 0

50
& pickup Latching LED
0
User Alarm

*NC stands for Normally Closed. V01217

Figure 266: PSL for TCS Scheme 1

The opto-input can be used to drive a Normally Closed Output Relay, which in turn can be used to drive alarm
equipment. The signal can also be inverted to drive a latching programmable LED and a user alarm DDB signal.
The DDO timer operates as soon as the opto-input is energised, but will take 400 ms to drop off/reset in the event
of a trip circuit failure. The 400 ms delay prevents a false alarm due to voltage dips caused by faults in other
circuits or during normal tripping operation when the opto-input is shorted by a self-reset trip contact. When the
timer is operated the NC (normally closed) output relay opens and the LED and user alarms are reset.
The 50 ms delay on pick-up timer prevents false LED and user alarm indications during the power up time,
following a voltage supply interruption.

5.2 TRIP CIRCUIT SUPERVISION SCHEME 2

This scheme provides supervision of the trip coil with the breaker open or closed but does not provide pre-closing
supervision of the trip path. However, using two opto-inputs allows the IED to correctly monitor the circuit breaker
status since they are connected in series with the CB auxiliary contacts. This is achieved by assigning one opto-
input to the 52a contact and another opto-input to the 52b contact. Provided the CB Status setting in the CB
CONTROL column is set to Both 52A and 52B, the IED will correctly monitor the status of the breaker. This
scheme is also fully compatible with latched contacts as the supervision current will be maintained through the
52b contact when the trip contact is closed.

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+ve

Trip Output Relay Trip coil

Trip path 52A

52B

R1 Opto-input 1
Circuit Breaker
-ve

R2 Opto-input 2
V01215

Figure 267: TCS Scheme 2

When the breaker is closed, supervision current passes through opto input 1 and the trip coil. When the breaker is
open current flows through opto input 2 and the trip coil. No supervision of the trip path is provided whilst the
breaker is open. Any fault in the trip path will only be detected on CB closing, after a 400 ms delay.

5.2.1 RESISTOR VALUES

Optional resistors R1 and R2 can be added to prevent tripping of the CB if either opto-input is shorted. The table
below shows the appropriate resistor value and voltage setting for this scheme.
Trip Circuit Voltage Opto Voltage Setting with R1 Fitted Resistor R1 and R2 (ohms)
48/54 24/27 1.2k
110/125 48/54 2.7k
220/250 110/125 5.2k

Warning:
This Scheme is not compatible with Trip Circuit voltages of less than 48 V.

5.2.2 PSL FOR TCS SCHEME 2

Opto Input 1 CB Aux 3ph(52 -A)

0 0
1 dropoff straight *Output Relay
400 0

Opto Input 2 CB Aux 3ph(52 -B)

50
& pickup Latching LED
0
User Alarm

*NC stands for Normally Closed. V01218

Figure 268: PSL for TCS Scheme 2

In TCS scheme 2, both opto-inputs must be low before a trip circuit fail alarm is given.

5.3 TRIP CIRCUIT SUPERVISION SCHEME 3

TCS Scheme 3 is designed to provide supervision of the trip coil with the breaker open or closed. It provides pre-
closing supervision of the trip path. Since only one opto-input is used, this scheme is not compatible with latched
trip contacts. If you require CB status monitoring, further opto-inputs must be used.

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+ve
R3
Output Relay Trip coil
Trip path 52A

R2
52B

Opto-input R1 Circuit Breaker

-ve
V01216

Figure 269: TCS Scheme 3

When the CB is closed, supervision current passes through the opto-input, resistor R2 and the trip coil. When the
CB is open, current flows through the opto-input, resistors R1 and R2 (in parallel), resistor R3 and the trip coil. The
supervision current is maintained through the trip path with the breaker in either state, therefore providing pre-
closing supervision.

5.3.1 RESISTOR VALUES

Resistors R1 and R2 are used to prevent false tripping, if the opto-input is accidentally shorted. However, unlike the
other two schemes. This scheme is dependent upon the position and value of these resistors. Removing them
would result in incomplete trip circuit monitoring. The table below shows the resistor values and voltage settings
required for satisfactory operation.
Opto Voltage Setting with R1
Trip Circuit Voltage Resistor R1 & R2 (ohms) Resistor R3 (ohms)
Fitted
48/54 24/27 1.2k 600
110/250 48/54 2.7k 1.2k
220/250 110/125 5.0k 2.5k

Warning:
This Scheme is not compatible with Trip Circuit voltages of less than 48 V.

5.3.2 PSL FOR TCS SCHEME 3

0 0
Opto Input dropoff Straight *Output Relay
400 0

50
& pickup Latching LED
0
User Alarm

*NC stands for Normally Closed. V01217

Figure 270: PSL for TCS Scheme 3

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1 CHAPTER OVERVIEW
This chapter introduces the PSL (Programmable Scheme Logic) Editor, and describes the configuration of the digital
inputs and outputs. It provides an outline of scheme logic concepts and the PSL Editor. This is followed by details
about allocation of the digital inputs and outputs, which require the use of the PSL Editor. A separate "Settings
Application Software" document is available that gives a comprehensive description of the PSL, but enough
information is provided in this chapter to allow you to allocate the principal digital inputs and outputs.
This chapter contains the following sections:
Chapter Overview 485
Configuring Digital Inputs and Outputs 486
Scheme Logic 487
Configuring the Opto-Inputs 489
Assigning the Output Relays 490
Fixed Function LEDs 491
Configuring Programmable LEDs 492
Function Keys 494
Control Inputs 495

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2 CONFIGURING DIGITAL INPUTS AND OUTPUTS

Configuration of the digital inputs and outputs in this product is very flexible. You can use a combination of
settings and programmable logic to customise them to your application. You can access some of the settings
using the keypad on the front panel, but you will need a computer running the settings application software to fully
interrogate and configure the properties of the digital inputs and outputs.
The settings application software includes an application called the PSL Editor (Programmable Scheme Logic
Editor). The PSL Editor lets you allocate inputs and outputs according to your specific application. It also allows you
to apply attributes to some of the signals such as a drop-off delay for an output contact.
In this product, digital inputs and outputs that are configurable are:
● Optically isolated digital inputs (opto-inputs). These can be used to monitor the status of associated plant.
● Output relays. These can be used for purposes such as initiating the tripping of circuit breakers, providing
alarm signals, etc..
● Programmable LEDs. The number and colour of the programmable LEDs varies according to the particular
product being applied.
● Function keys and associated LED indications. These are not provided on all products, but where they are,
each function key has an associated tri-colour LED.
● IEC 61850 GOOSE inputs and outputs. These are only provided on products that have been specified for
connection to an IEC61850 system, and the details of the GOOSE are presented in the documentation on
IEC61850.
● InterMiCOM inputs and outputs. These are not used by all products. If your product is equipped with an
InterMiCOM feature, you will find details of allocation and configuration in the chapter dedicated to the
InterMiCOM function.

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3 SCHEME LOGIC
The product is supplied with pre-loaded Fixed Scheme Logic (FSL) and Programmable Scheme Logic (PSL).
The Scheme Logic is a functional module within the IED, through which all mapping of inputs to outputs is handled.
The scheme logic can be split into two parts; the Fixed Scheme Logic (FSL) and the Programmable Scheme Logic
(PSL). It is built around a concept called the digital data bus (DDB). The DDB encompasses all of the digital signals
(DDBs) which are used in the FSL and PSL. The DDBs included digital inputs, outputs, and internal signals.
The FSL is logic that has been hard-coded in the product. It is fundamental to correct interaction between various
protection and/or control elements. It is fixed and cannot be changed.
The PSL gives you a facility to develop custom schemes to suit your application if the factory-programmed default
PSL schemes do not meet your needs. Default PSL schemes are programmed before the product leaves the
factory. These default PSL schemes have been designed to suit typical applications and if these schemes suit your
requirements, you do not need to take any action. However, if you want to change the input-output mappings, or
to implement custom scheme logic, you can change these, or create new PSL schemes using the PSL editor.
The PSL consists of components such as logic gates and timers, which combine and condition DDB signals.
The logic gates can be programmed to perform a range of different logic functions. The number of inputs to a logic
gate are not limited. The timers can be used either to create a programmable delay or to condition the logic
outputs. Output contacts and programmable LEDs have dedicated conditioners.
The PSL logic is event driven. Only the part of the PSL logic that is affected by the particular input change that has
occurred is processed. This minimises the amount of processing time used by the PSL ensuring industry leading
performance.
The following diagram shows how the scheme logic interacts with the rest of the IED.

Energising quantities Protection functions Fixed LEDs

SL outputs
SL inputs

Opto-inputs Programmable LEDs

PSL and FSL

Function keys Output relays

Goose outputs
Control inputs

Goose inputs

Control input Ethernet

module processing module

V02011

Figure 271: Scheme Logic Interfaces

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3.1 PSL EDITOR

The Programmable Scheme Logic (PSL) is a module of programmable logic gates and timers in the IED, which can
be used to create customised logic to qualify how the product manages its response to system conditions. The
IED's digital inputs are combined with internally generated digital signals using logic gates, timers, and
conditioners. The resultant signals are then mapped to digital outputs signals including output relays and LEDs.
The PSL Editor is a tool in the settings application software that allows you to create and edit scheme logic
diagrams. You can use the default scheme logic which has been designed to suit most applications, but if it does
not suit your application you can change it. If you create a different scheme logic with the software, you need to
upload it to the device to apply it.

3.2 PSL SCHEMES

Your product is shipped with default scheme files. These can be used without modification for most applications, or
you can choose to use them as a starting point to design your own scheme. You can also create a new scheme
from scratch. To create a new scheme, or to modify an existing scheme, you will need to launch the settings
application software. You then need to open an existing PSL file, or create a new one, for the particular product
that you are using, and then open a PSL file. If you want to create a new PSL file, you should select File then New
then Blank scheme... This action opens a default file appropriate for the device in question, but deletes the
diagram components from the default file to leave an empty diagram with configuration information loaded. To
open an existing file, or a default file, simply double-click on it.

3.3 PSL SCHEME VERSION CONTROL

To help you keep track of the PSL loaded into products, a version control feature is included. The user interface
contains a PSL DATA column, which can be used to track PSL modifications. A total of 12 cells are contained in the
PSL DATA column; 3 for each setting group.
Grp(n) PSL Ref: When downloading a PSL scheme to an IED, you will be prompted to enter the relevant group
number and a reference identifier. The first 32 characters of the reference identifier are displayed in this cell. The
horizontal cursor keys can scroll through the 32 characters as the LCD display only displays 16 characters.

Example:

Grp(n) PSL Ref

Date/time: This cell displays the date and time when the PSL scheme was downloaded to the IED.

Example:

18 Nov 2002
08:59:32.047

Grp(n) PSL ID: This cell displays a unique ID number for the downloaded PSL scheme.

Example:

Grp(n) PSL ID
ID - 2062813232

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4 CONFIGURING THE OPTO-INPUTS

The number of optically isolated status inputs (opto-inputs) depends on the specific model supplied. The use of the
inputs will depend on the application, and their allocation is defined in the programmable scheme logic (PSL). In
addition to the PSL assignment, you also need to specify the expected input voltage. Generally, all opto-inputs will
share the same input voltage range, but if different voltage ranges are being used, this device can accommodate
them.
In the OPTO CONFIG column there is a global nominal voltage setting. If all opto-inputs are going to be energised
from the same voltage range, you select the appropriate value in the setting. If you select Custom in the setting,
then the cells Opto Input 1, Opto Input 2, etc. become visible. You use these cells to set the voltage ranges for
each individual opto-input.
Within the OPTO CONFIG column there are also settings to control the filtering applied to the inputs, as well as the
pick-up/drop-off characteristic.
The filter control setting provides a bit string with a bit associated with all opto-inputs. Setting the bit to ‘1’ means
that a half-cycle filter is applied to the inputs. This helps to prevent incorrect operation in the event of power
system frequency interference on the wiring. Setting the field to ‘0’ removes the filter and provides for faster
operation.
The Characteristic setting is a single setting that applies to all the opto-inputs. It is used to set the pick-up/drop-
off ratios of the input signals. As standard it is set to 80% pick-up and 60% drop-off, but you can change it to other
available thresholds if that suits your operational requirements.

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5 ASSIGNING THE OUTPUT RELAYS

Relay contact action is controlled using the PSL. DDB signals are mapped in the PSL and drive the output relays.
The driving of an output relay is controlled by means of a relay output conditioner. Several choices are available for
how output relay contacts are conditioned. For example, you can choose whether operation of an output relay
contact is latched, has delay on pick-up, or has a delay on drop-off. You make this choice in the Contact
Properties window associated with the output relay conditioner.
To map an output relay in the PSL you should use the Contact Conditioner button in the toolbar to import it. You
then condition it according to your needs. The output of the conditioner respects the attributes you have assigned.
The toolbar button for a Contact Conditioner looks like this:

The PSL contribution that it delivers looks like this:

Note:
Contact Conditioners are only available if they have not all been used. In some default PSL schemes, all Contact Conditioners
might have been used. If that is the case, and you want to use them for something else, you will need to re-assign them.

On the toolbar there is another button associated with the relay outputs. The button looks like this:

This is the "Contact Signal" button. It allows you to put replica instances of a conditioned output relay into the PSL,
preventing you having to make cross-page connections which might detract from the clarity of the scheme.

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6 FIXED FUNCTION LEDS

Four fixed-function LEDs on the left-hand side of the front panel indicate the following conditions.
● Trip (Red) switches ON when the IED issues a trip signal. It is reset when the associated fault record is
cleared from the front display. Also the trip LED can be configured as self-resetting.
● Alarm (Yellow) flashes when the IED registers an alarm. This may be triggered by a fault, event or
maintenance record. The LED flashes until the alarms have been accepted (read), then changes to
constantly ON. When the alarms are cleared, the LED switches OFF.
● Out of service (Yellow) is ON when the IED's functions are unavailable.
● Healthy (Green) is ON when the IED is in correct working order, and should be ON at all times. It goes OFF if
the unit’s self-tests show there is an error in the hardware or software. The state of the healthy LED is
reflected by the watchdog contacts at the back of the unit.

6.1 TRIP LED LOGIC

When a trip occurs, the trip LED is illuminated. It is possible to reset this with a number of ways:
● Directly with a reset command (by pressing the Clear Key)
● With a reset logic input
● With self-resetting logic

You enable the automatic self-resetting with the Sys Fn Links cell in the SYSTEM DATA column. A '0' disables self
resetting and a '1' enables self resetting.
The reset occurs when the circuit is reclosed and the Any Pole Dead signal has been reset for three seconds
providing the Any Start signal is inactive. The reset is prevented if the Any Start signal is active after the breaker
closes.
The Trip LED logic is as follows:

Any Trip S
Q Trip LED Trigger
Reset R
1
Reset Relays/LED

Sys Fn Links
Trip LED S/Reset
3s
&

Any Pole Dead

Any Start

V01211

Figure 272: Trip LED logic

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7 CONFIGURING PROGRAMMABLE LEDS

There are three types of programmable LED signals which vary according to the model being used. These are:
● Single-colour programmable LED. These are red when illuminated.
● Tri-colour programmable LED. These can be illuminated red, green, or amber.
● Tri-colour programmable LED associated with a Function Key. These can be illuminated red, green, or
amber.

DDB signals are mapped in the PSL and used to illuminate the LEDs. For single-coloured programmable LEDs there
is one DDB signal per LED. For tri-coloured LEDs there are two DDB signals associated with the LED. Asserting LED
# Grn will illuminate the LED green. Asserting LED # Red will illuminate the LED red. Asserting both DDB signals will
illuminate the LED amber.
The illumination of an LED is controlled by means of a conditioner. Using the conditioner, you can decide whether
the LEDs reflect the real-time state of the DDB signals, or whether illumination is latched pending user intervention.
To map an LED in the PSL you should use the LED Conditioner button in the toolbar to import it. You then condition
it according to your needs. The output(s) of the conditioner respect the attribute you have assigned.
The toolbar button for a tri-colour LED looks like this:

The PSL contribution that it delivers looks like this:

The toolbar button for a single-colour LED looks like this:

The PSL contribution that it delivers looks like this.

Note:
LED Conditioners are only available if they have not all been used up, and in some default PSL schemes they might be. If that
is the case and you want to use them for something else, you will need to re-assign them.

On the toolbar there is another button associated with the LEDs. For a tri-coloured LED the button looks like this:

For a single-colour LED it looks like this:

It is the "LED Signal" button. It allows you to put replica instances of a conditioned LED into the PSL, preventing you
having to make cross-page connections which might detract from the clarity of the scheme.

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Note:
All LED DDB signals are always shown in the PSL Editor. However, the actual number of LEDs depends on the device
hardware. For example, if a small 20TE device has only 4 programmable LEDs, LEDs 5-8 will not take effect even if they are
mapped in the PSL.

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8 FUNCTION KEYS
For most models, a number of programmable function keys are available. This allows you to assign function keys
to control functionality via the programmable scheme logic (PSL). Each function key is associated with a
programmable tri-colour LED, which you can program to give the desired indication on activation of the function
key.
These function keys can be used to trigger any function that they are connected to as part of the PSL. The function
key commands are found in the FUNCTION KEYS column.
Each function key is associated with a DDB signal as shown in the DDB table. You can map these DDB signals to
any function available in the PSL.
The Fn Key Status cell displays the status (energised or de-energised) of the function keys by means of a binary
string, where each bit represents a function key starting with bit 0 for function key 1.
Each function key has three settings associated with it, as shown:
● Fn Key (n), which enables or disables the function key
● Fn Key (n) Mode, which allows you to configure the key as toggled or normal
● Fn Key (n) label, which allows you to define the function key text that is displayed

The Fn Key (n) cell is used to enable (unlock) or disable (unlock) the function key signals in PSL. The Lock setting has
been provided to prevent further activation on subsequent key presses. This allows function keys that are set to
Toggled mode and their DDB signal active ‘high’, to be locked in their active state therefore preventing any
further key presses from deactivating the associated function. Locking a function key that is set to the “Normal”
mode causes the associated DDB signals to be permanently off. This safety feature prevents any inadvertent
function key presses from activating or deactivating critical functions.
When the Fn Key (n) Mode cell is set to Toggle, the function key DDB signal output will remain in the set state
until a reset command is given. In the Normal mode, the function key DDB signal will remain energised for as long
as the function key is pressed and will then reset automatically. In this mode, a minimum pulse duration can be
programmed by adding a minimum pulse timer to the function key DDB output signal.
The Fn Key Label cell makes it possible to change the text associated with each individual function key. This text
will be displayed when a function key is accessed in the function key menu, or it can be displayed in the PSL.
The status of all function keys are recorded in non-volatile memory. In case of auxiliary supply interruption their
status will be maintained.

Note:
All function key DDB signals are always shown in the PSL Editor. However, the actual number of function keys depends on the
device hardware. For example, if a small 20TE device has no function keys, the function key DDBs mapped in the PSL will not
take effect.

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9 CONTROL INPUTS
The control inputs are software switches, which can be set or reset locally or remotely. These inputs can be used to
trigger any PSL function to which they are connected. There are three setting columns associated with the control
inputs: CONTROL INPUTS, CTRL I/P CONFIG and CTRL I/P LABELS. These are listed in the Settings and Records
appendix at the end of this manual.

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FIBRE TELEPROTECTION
Chapter 20 - Fibre Teleprotection P543i/P545i

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1 CHAPTER OVERVIEW
This chapter provides information about the fibre-optic communication mechanism,which is used to provide unit
schemes and general-purpose teleprotection signalling for protection of transmission lines and distribution
feeders. The feature is called Fibre Teleprotection.
This chapter contains the following sections:
Chapter Overview 499
Protection Signalling Introduction 500
Fibre Teleprotection Implementation 502
IM64 Logic 511
Application Notes 513

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2 PROTECTION SIGNALLING INTRODUCTION

Unit protection schemes can be formed by several IEDs located remotely from each other and some distance
protection schemes. Such unit protection schemes need communication between each location to achieve a unit
protection function. This communication is known as protection signalling or teleprotection. Communications
facilities are also needed when remote circuit breakers need to be operated due to a local event. This
communication is known as intertripping.
The communication messages involved may be quite simple, involving instructions for the receiving device to take
some defined action (trip, block, etc.), or it may be the passing of measured data in some form from one device to
another (as in a unit protection scheme).
Various types of communication links are available for protection signalling, for example:
● Private pilot wires installed by the utility
● Pilot wires or channels rented from a communications company
● Carrier channels at high frequencies over the power lines
● Radio channels at very high or ultra high frequencies
● Optical fibres
Whether or not a particular link is used depends on factors such as the availability of an appropriate
communication network, the distance between protection relaying points, the terrain over which the power
network is constructed, as well as cost.
Protection signalling is used to implement unit protection schemes, provide teleprotection commands, or
implement intertripping between circuit breakers.

2.1 UNIT PROTECTION SCHEMES

Phase comparison and current differential schemes use signalling to convey information concerning the relaying
quantity - phase angle of current and phase and magnitude of current respectively - between local and remote
relaying points. Comparison of local and remote signals provides the basis for both fault detection and
discrimination of the schemes.

2.2 TELEPROTECTION COMMANDS

Some Protection schemes use signalling to convey commands between local and remote relaying points. Receipt
of the information is used to aid or speed up clearance of faults within a protected zone or to prevent tripping from
faults outside a protected zone.
Teleprotection systems are often referred to by their mode of operation, or the role of the teleprotection command
in the system.
Three types of teleprotection command are commonly encountered, direct tripping, permissive tripping and
blocking schemes.

Direct Tripping
In direct tripping applications (also known as intertripping), signals are sent directly to the master trip relay. Receipt
of the command causes circuit breaker operation. The method of communication must be reliable and secure
because any signal detected at the receiving end causes a trip of the circuit at that end. The communications
system must be designed so that interference on the communication circuit does not cause spurious trips. If a
spurious trip occurs, the primary system might be unnecessarily isolated.

Permissive Tripping
Permissive trip commands are always monitored by a protection relay. The circuit breaker is tripped when receipt
of the command coincides with a ‘start’ condition being detected by the protection relay at the receiving end
responding to a system fault. Requirements for the communications channel are less onerous than for direct

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tripping schemes, since receipt of an incorrect signal must coincide with a ‘start’ of the receiving end protection for
a trip operation to take place. The intention of these schemes is to speed up tripping for faults occurring within the
protected zone.

Blocking Scheme
Blocking commands are initiated by a protection element that detects faults external to the protected zone.
Detection of an external fault at the local end of a protected circuit results in a blocking signal being transmitted to
the remote end. At the remote end, receipt of the blocking signal prevents the remote end protection operating if it
had detected the external fault. Loss of the communications channel is less serious for this scheme than in others
as loss of the channel does not result in a failure to trip when required. However, the risk of a spurious trip is higher.

2.3 TRANSMISSION MEDIA AND INTERFERENCE

The transmission media that provide the communication links involved in protection signalling can be:
● Private pilots
● Rented pilots or channels
● Power line carrier
● Radio
● Optical fibres

Historically, pilot wires and channels (discontinuous pilot wires with isolation transformers or repeaters along the
route between signalling points) have been the most widely used due to their availability, followed by Power Line
Carrier Communications (PLCC) techniques and radio. In recent years, fibre-optic systems have become the usual
choice for new installations, primarily due to their complete immunity from electrical interference. The use of fibre-
optic cables also greatly increases the number of communication channels available for each physical fibre
connection and thus enables more comprehensive monitoring of the power system to be achieved by the
provision of a large number of communication channels.

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3 FIBRE TELEPROTECTION IMPLEMENTATION

The Fibre Teleprotection interface is an integral part of the Current Differential protection implementation for this
product. It provides the communications necessary for the Current Differential protection schemes as well as
intertripping command signalling which can be freely allocated to realise protection schemes such as Permissive
and Blocking schemes.
If Current Differential protection is enabled, Fibre Teleprotection is enabled automatically. If you choose to disable
the Current Differential protection, you can still use the Fibre Teleprotection feature for teleprotection command
signalling. To do this you must enable the InterMiCOM 64 setting in the CONFIGURATION column. This setting will
only be visible if Current Differential protection is disabled.
If you enable Fibre Teleprotection but have current differential protection disabled, the CURRENT DIFF column will
be invisible. To re-enable Current Differential protection you must first set the InterMiCOM 64 setting in the
CONFIGURATION column to disabled. Enabling Current Differential protection will then automatically enable Fibre
Teleprotection and the InterMiCOM 64 setting in the CONFIGURATION column will disappear.
Each product can have up to 2 fibre-optic communications channels for teleprotection signalling. A range of
different fibre-optic interfaces are available to provide:
● Direct fibre connections between devices with a number of options available to suit different requirements
● Indirect connections using the industry standard IEEE C37.94. Fibre-optic connections are made between
the product and telecommunications equipment that supports industry standard fibre-optic interfaces (IEEE
C37.94). The telecommunications equipment provides the end-to-end service.
● Fibre-optic connection in conjunction with proprietary auxiliary interface units to provide connection to
standard electrical telecommunications interfaces (G.703, V.35, X.21). With this indirect connection method,
the telecommunications equipment provides the end-to-end service.
Signals to be communicated between devices are constructed into packets (sometimes called telegrams). These
packets include addressing, timing, and error checking information as well as teleprotection commands and data,
and are transmitted between terminals at frequent regular intervals. Upon reception, they are checked for integrity
before the contents are used.
Allocation of teleprotection commands is realised with mappings between InterMiCOM 64 signals and internal DDB
logic signals using the product’s the Programmable Scheme Logic (PSL).

3.1 SETTING UP THE IM64 SCHEME

To use the fibre teleprotection features in this product, you will need to configure the protection signalling scheme.
The protection signalling scheme is defined by the number of connected terminals, together with the
communications links between them.
Products can have either 1 physical fibre teleprotection channel, or two. Products with 1 physical fibre
teleprotection channel can be used to connect two products together into a scheme. Products with 2 physical fibre
teleprotection channels can be used to connect three products together into a scheme, or they can be used to
connect two products together into a scheme with dual communications channels to provide communications
redundancy (hot standby) in the event of a single communications channel failure.
For products with 2 physical fibre teleprotection channels use the Scheme Setup setting in the PROT COMMS/IM64
column. The choices are 3 Terminal, 2 Terminal (only physical Ch1 is used), and Dual Redundant (two
terminals with two interconnecting channels).
The physical connections are labelled as Ch1 and Ch2.
In a two-terminal scheme, channel 1 of one device should always connect to channel 1 of the other device. For a
two-terminal scheme with dual redundant communications, it follows that channel 2 of one device should connect
to channel 2 of the other.
In a three terminal scheme, channel 1 of one device should always connect to channel 2 of another device as
shown in the figure below.

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Rx IED B Tx
Ch1 Ch2
Tx Rx

Remote 1

Tx Rx Tx Rx
Ch2 Ch1
Local Remote 2
IED A IED C
Ch1 Ch2
Rx Tx Rx Tx

V02500

Figure 273: Fibre Teleprotection connections for a three-terminal Scheme

3.1.1 FIBRE TELEPROTECTION SCHEME TERMINAL ADDRESSING

In Fibre Teleprotection schemes, commands are packaged together with other important data for transmission
over communications channels to the other devices. The packages of information are generally called ‘messages’.
These messages are created for a specific destination where they will be acted upon to realise the overall scheme
protection. It is critical that they are only used by the intended device. Making the correct channel connections
may not always ensure that the messages get to the correct destination; there may be a possibility that
communication paths may become cross-connected or looped back during telecommunications network
switching operations. To avoid incorrect scheme operation, extra security is needed to ensure that messages are
acted upon only by their intended recipient. This is achieved by means of an address field in the messages. The
address field is used to individually match connected devices. A transmitting device includes the address of the
intended recipient in the message. If the receiving device matches the address, the message will be used. If it does
not match, it is discarded.
The address field is an 8-bit field in the message. It can carry any 8-bit value, but certain values have been chosen
for maximum security. For convenience they have been arranged into 32 groups. All devices in a scheme must
share the same group. For addressing, the different devices are referenced as ‘A’, ‘B’, and ‘C’ for three-terminal
schemes. Their addresses should recognise the referencing.
So for a two-terminal scheme, if one device has the address set to ‘5-A’ the other should have the address to ‘5-B’.
Similarly, in a three-terminal scheme if one device has address ‘1-A’, the other devices would have addresses ‘1-B’
and ‘1-C’. The address is set using the address setting in the PROT COMMS/IM64 column.

Note:
A universal address (0-0) is used as default. If this is used all products use the same address ‘0-0’. This is primarily intended to
help test the product before it goes into service. We strongly recommend not to use 0-0 in service since any communications
switching or loopback condition will not be detected and may cause false tripping.

Note:
For a three-terminal scheme, the A, B, and C parts of the address group should match the figure shown earlier for a
triangulated scheme where device A has address A, device B has address B, and device C has address C.

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3.1.2 SETTING UP IM64

In this product, the feature that manages the fibre teleprotection command signals is called InterMiCOM 64 (or
IM64). IM64 is suitable for the exchange of all teleprotection command types.
Up to 2 banks of teleprotection command signals (IM64 signals) are provided. Each bank provides 8 duplex
command signals. That means that each bank assigns 8 bits for IM64 input signals and 8 bits for IM64 output
signals. Each bank is associated with a logical channel (referred to as Ch1 or Ch2 in the internal logic). Each logical
channel associates with a physical communications channel (labelled Ch1 or Ch2 at the physical connection point).
The association of logical channels to physical channels varies according to specific scheme configurations.
Action of each IM64 input signal is managed by attributes defined by three settings associated with it. These are
set in the PROT COMMS/IM64 column and are of the form:
● IM 1 Cmd Type (command type)
● IM 1 FallBackMode (fallback modes)
● IM 1 DefaultValue (default values)

The settings shown above are for bit 1 only

The IM64 command type settings set the teleprotection type. Permissive satisfies the security requirements of
a permissive application, as well as the speed needed for a blocking scheme. For direct tripping applications, set it
to Direct.
The IM64fallback settings determine the behaviour of an input under communications failure conditions. You can
choose either to latch the state of the last good command received, or to revert to a default state. If you set the
fallback mode to Default you will need to set the default state to your requirement (either 1 or 0).
The attributes assigned to bit n of an IM64 input apply to that bit in both logical channels. For example, if IM4
DefaultValue is chosen as 1 then the default value for bit 4 in logical channel 1 (IM64 Ch1 Input 4) will be the same
for bit 4 in logical channel 2 (IM64 Ch2 Input 4), and will take the value 1.

3.1.3 TWO-TERMINAL IM64 OPERATION

The protection signalling connection requirement for products operating as a Two Terminal scheme is that the
Physical Channels labelled as Ch1 should be connected together. That means that the local Ch1 Tx connects to the
remote Ch1 Rx, and the local Ch1 Rx connects to the remote Ch1 Tx. Physical Channel 2 (Ch2) connectors may be
fitted, but they are not used.

With Current Differential protection enabled

Only the 8 bits of Logical Channel 1 (Ch1) are used, and they are all assigned to Physical Channel 1, so 8 duplex
commands (IM64 Ch1 bits 1-8) can be communicated between terminals. The command bits are packaged with
the Current Differential signals and use Ch1 Physical Channels.

With Current Differential protection disabled

The 8 bits of both Logical Channels (Ch1 and Ch2) are used. The bits of both Logical Channels are all assigned to
Physical Channel 1, so 16 duplex commands (IM64 Ch1 bits 1-8 and IM64 Ch2 bits 1-8) can be communicated
between terminals in IM64 messages using Ch1 Physical Channels.

3.1.4 DUAL REDUNDANT TWO-TERMINAL IM64 OPERATION

The protection signalling connection requirement for products operating as a Dual Redundant (Hot Standby)
scheme is that the Physical Channels labelled as Ch1 should be connected together and the Physical Channels
labelled as Ch2 should be connected together. That means that the local Ch1 Tx connects to the remote Ch1 Rx,
the local Ch1 Rx connects to the remote Ch1 Tx, the local Ch2 Tx connects to the remote Ch2 Rx, and the local Ch2
Rx connects to the remote Ch2 Tx.

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With Current Differential protection enabled

The 8 bits of both Logical Channels (Ch1 and Ch2) are available, Logical Channel 1 is assigned to Physical Channel
1, and Logical Channel 2 is assigned to Physical Channel 2, so 16 duplex commands are potentially available.
To implement a true redundancy scheme, however, signals on Logical Channel 2 should be assigned identically to
those on Logical Channel 1. Upon reception, the matched bits should be logically ‘OR’ed when mapped in the PSL.
In this application the command bits are packaged with the Current Differential signals. Current Differential
protection and the IM64 signalling will be maintained in the event of a single communication channel failure.

With Current Differential protection disabled

The 8 bits of both Logical Channels (Ch1 and Ch2) are used. The bits of both Logical Channels are all assigned both
to Physical Channel 1 and to Physical Channel 2, so that 16 duplex commands (IM64 Ch1 bits 1-8 and IM64 Ch2
bits 1-8) can be communicated between terminals in IM64 messages with full redundancy of both Logical
Channels in the event of failure of either Physical Channel.

3.1.5 THREE-TERMINAL IM64 OPERATION

The protection signalling connection requirement for products operating as a Three Terminal scheme is that
Physical Channels labelled as Ch1 should be connected to Physical Channels labelled as Ch2 . That means that a
local Ch1 Tx connects to a remote Ch2 Rx, and the corresponding Ch1 Rx and Ch2 Tx are connected together as
shown in the earlier figure (Fibre Teleprotection Connections for a Three Terminal Scheme).

With Current Differential protection enabled

8 IM64 Fibre Teleprotection Commands can be transferred between pairs of terminals. Integrity of the Current
Differential protection and the IM64 schemes can be maintained in the event of a communications link failure by
reverting to a master-slave-slave configuration where the terminal with healthy communications with the other
terminals makes the tripping decision and sends intertrip commands to the other two. The master can also send 8
IM64 teleprotection commands to the remote terminals. The same commands are sent to both terminals .
In this IM64 application, the 8 bits of both Logical Channels (Ch1 and Ch2) are available, Logical Channel 1 is
assigned to Physical Channel 1, and Logical Channel 2 is assigned to Physical Channel 2. To implement a true
redundancy scheme that will work correctly, the same IM64 bit assignments should be made at all three terminals
and the signals on Logical Channel 2 should be assigned identically to those on Logical Channel 1. Upon reception,
the matched bits should be logically ‘OR’ed when mapped in the PSL.
In this application the command bits are packaged with the Current Differential signals. Current Differential
protection and the IM64 signalling will be maintained in the event of a single communication channel failure.

With Current Differential protection disabled

This Three Terminal scheme uses a triangulation approach and is designed to function if a communications link
between two terminals is not present or is degraded. 8 duplex teleprotection commands are available between
any pair of terminals even if one communication channel fails.
Logical Channel 1 is associated with Physical Channel 1, and Logical Channel 2 is associated with Physical Channel
2.
Consider a Three terminal scheme where the terminals are referenced as Local, Remote1, and Remote2. Remote 1
correlates to Ch1, and Remote 2 correlates to Ch2. The Local terminal will send the commands that it wants
Remote 1 to act on to both Remote 1 and Remote 2. Upon receipt, Remote 1 acts upon the commands that the
Local terminal wants it to use. Remote 1 also packages the commands that it wants Remote 2 to use, together
with a copy of the commands that Local wants Remote 2 to use, and also the commands it wants Local to use.
Remote 1 sends the message to Remote2. Remote 2 acts similarly. The same process occurs in the opposite
direction around the ring, so in the event of a single channel failure, and if all terminals have the same mappings
for the 8 IM64 bits integrity will be maintained for all 8 duplex commands between connected terminals.
In a triangulated scheme, at each terminal, Logical Channel 1 commands are assigned to Physical Channel 1, and
Logical Channel 2 commands are assigned to Physical Channel 2. At each terminal, the eight IM64 commands

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transmitted on Physical Channel 1 are intended for the device connected as its Remote 1, and the eight IM64
commands transmitted on Channel 2 are intended for the device connected as its Remote 2. So, eight full-duplex
commands are available between any two terminals. Each device transmits both channels of eight IM64
commands to the connected devices. At the Remote 1 device, the eight Channel 1 IM64 commands are used
directly by the receiving device which passes through the eight Channel 2 IM64 commands to the remote 2 device.
All three devices in the scheme perform similarly, ensuring that, so long as one device is able to communicate with
the other two, scheme integrity is maintained.
This Chain topology (normally invoked when a communication link fails) can be used to save cost in a three-
terminal scheme. This is because two legs are cheaper to install than full triangulation implementation. Also if a
suitable communication link is not available between two of the line ends, it may be the only option. If a Chain
topology is used, or one link in a fully triangulated scheme is lost, the operating delay of the teleprotection
commands increases by approximately 7 ms, plus the communications channel signalling delay, due to the
extended path length and additional processing.

3.1.6 PHYSICAL CONNECTION

The protection communications into and out of the products are fibre-optic. Connections are made using BFOC/2.5
connectors (BFOC/2.5 connectors are commonly referred to as “ST” connectors where “ST” is a registered
trademark of AT&T).
According to application, different fibre-optic interfaces are available described in the following table:
Wavelength of light (nm) Fibre type Maximum transmission distance (km)
850 Multi-mode 1
1300 Multi-mode 50
1300 Single-mode 100
1550 Single-mode 150

Connections are made using appropriate fibre-optic cables terminated with BFOC/2.5 connectors. The transmitter
of one device (for example Tx1) is connected to the receiver of another (Rx1 or Rx2 according to the scheme set-
up)
Products can be supplied with the following fibre-optic channel arrangements:
Ch 1 Ch2
850 nm 850 nm
1300 nm multi-mode Not fitted
1300 nm multi-mode 1300 nm multi-mode
1300 nm single-mode Not fitted
1300 nm single-mode 1300 nm single-mode
1550 nm single-mode Not fitted
1550 nm single-mode 1550 nm single-mode
850 nm 1300 nm multi-mode
850 nm 1300 nm single-mode
850 nm 1550 nm single-mode
1300 nm multi-mode 850 nm
1300 nm single-mode 850 nm
1550 nm single-mode 850 nm

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3.1.6.1 DIRECT CONNECTION

If you are using direct fibre connections you need to set the Scheme Setup settings and you are advised to change
the Address setting from the default. You find these settings in the PROT COMMS/IM64 columns. You should not
need to use any of the other settings that would be applicable if using shared links and/or interfacing units.

3.1.6.2 INDIRECT CONNECTION

For 850nm communications links where the connection is not direct fibre, a number of options are available to
interface with standard telecommunications equipment. These are:
● Fibre connection to telecommunications equipment supporting the IEEE C37.94 interface
● Connection to G.703, V.35 or X.21 electrical circuits using auxiliary P59x interface units
P59x interface units are housed in 10TE wide, 4U high cases. They provide optical-electrical conversion. The optical
characteristics match those of the 850nm interface on the protection device. When used, you need one unit for
each transmitter/receiver pair. That means one unit at each end of each communications channel as
demonstrated in the figure below.

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850 nm 850 nm 850 nm

multimode multimode multimode
optical fiber optical fiber optical fiber
P591 P592 P593
interface unit interface unit interface unit

G.703 V.35 X.21

Multiplexer or Multiplexer or
Multiplexer
xDSL modem xDSL modem

Multiplexer or Multiplexer or
Multiplexer
xDSL modem xDSL modem

G.703 V.35 X.21

P591 P592 P593

interface unit interface unit interface unit

850 nm 850 nm 850 nm

multimode multimode multimode
optical fiber optical fiber optical fiber

V02501

Figure 274: Interfacing to PCM multiplexers

Note:
P59x interface units should be mounted as close as possible to the telecommunications equipment to minimise interference
on the electrical connections.

3.1.6.2.1 INDIRECT CONNECTION - FIBRE (IEEE C37.94)

An 850 nm fibre-optic interface can connect directly to a multiplexer supporting the IEEE C37.94 standard. 850 nm
multi-mode optical fibres, either 50/125 mm or 62.5/125 mm are suitable. BFOC/2.5 type fibre optic connectors are
used.

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Note:
To use this configuration, you need to set Comms Mode to ‘IEEE C37.94’. You then need to remove the power supply from the
product and then re-apply the power. The setting is now effective. If ‘IEEE C37.94’ is used, it applies to both communication
channels.

The IEEE C37.94 standard defines an N*64 kbits/s selection, where N is a number between 1 and 12 and selects
the channel used in the multiplexer. The value of N is set on a per channel basis by setting Ch1 N*64kbits/s (and
Ch2 N*64kbits/s where applicable) to N (1 to 12). For convenience an auto-detect setting is provided. Setting to
Auto means that the device will automatically determine which multiplexer channel to use.

3.1.6.2.2 INDIRECT CONNECTION - ELECTRICAL CIRCUITS

P591, P592, P593 interface units are housed in 10TE wide, 4U high cases. They provide optical-electrical conversion
allowing the protection to be used with telecommunications equipment providing interfaces to the ITU-T
recommendations G,703, V.35 and X.21 respectively. The optical characteristics of the P59x devices match those of
the 850 nm interface on the protection device. When used, you need one unit for each transmitter/receiver pair.
That means one unit at each end of each communications channel. The P59x devices should be mounted as close
as possible to the telecommunications equipment to minimise interference on the electrical connections.
A detailed description of the devices can be found in the P59x Technical Manual.
The P59x range supports the following electrical connections:
● X.21: Connection at 64 kbps is supported.

● V.35: Connection at 64 kbps or 56 kbps is supported.

● G.703: The data rate (baud rate) is 64 kbps but connection can be made at either 64 kbps or 2 Mbps.

When P59x units are used in the communications channel of the protection scheme, the following must be set:
● Comms Mode
● Baud Rate Chn (n = 1 or 2)
● Clock Source Chn (n = 1 or 2)

You should set the Comms Mode setting to Standard, and you should match the Baud Rate to the channel data
rate.
For V.35, you should set the Clock Source to External for a multiplexer network which is supplying a master
clock signal, or to Internal for a multiplexer network recovering signal timing from the equipment (clock
recovery). For G.703 and X.21, you always set the clock source to External.

3.2 COMMUNICATIONS SUPERVISION

Since electrical power systems are generally required to operate continuously, it follows that the applied
protection must do the same. If the protection uses communications, it must supervise these communications to
take appropriate action should they become degraded or lost.
IM64 provides the necessary communications supervision.
There are seven settings associated with the IM64 protection signalling communications supervision which are
listed below and described in the settings table:
● Comm Fail Timer
● Comm Fail Mode
● Channel Timeout
● IM Msg Alarm Lvl

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● Prop Delay Stats

● MaxCh 1 PropDelay
● MaxCh 2 PropDelay

A communication alarm is raised if the message error rate exceeds the IM Msg Alarm Lvl setting and persists for
the period defined by the Comm Fail Timer setting. Using the default settings will raise an alarm for a persistent Bit
Error Rate (BER) of 1.5 x 10 –3.
The alarm will be apparent at the receiving device, which will reflect the alarm back to the transmitting device.

Note:
The Comm Fail Mode setting applies only to devices configured for dual redundant or three-terminal configuration. It defines
what combination of failures on the two communications channels is used to indicate an alarm.

Note:
The MaxCh1 PropDelay and MaxCh2 PropDelay settings for Channel 1 (and Channel 2 if fitted) are only visible if the Prop
Delay Stats setting is Enabled.

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4 IM64 LOGIC

Channel Timeout
t
No Received Messages Ch 1 Ch1 Timeout
0 t
1
Poor Channel Quality Ch 1 0 1 Signalling Fail

Ch1 Degraded
Channel Timeout

No Received Messages Ch 2 t Ch2 Timeout

0
t
1
Poor Channel Quality Ch 2 0
Ch2 Degraded

1
Scheme Setup &
3 terminal

& 1 IM64 SchemeFail

&
V02502

Figure 275: IM64 channel fail and scheme fail logic

Channel Timeout
3 terminal
1 Ch1 Timeout
3 terminal

Channel Timeout
3 terminal Signalling Fail

Channel 1 IM64 Bits

received from channel 2 & Ch1 Degraded

Channel Timeout
3 terminal
& Ch2 Timeout
Channel 2 IM64 Bits
received from channel 1

V02503

Figure 276: IM64 general alarm signals logic

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Channel 1 Communication Error in Receive

Message Evaluation
message (IEEE C37 .94) Ch1 Signal Lost
Message Info

Channel 1
Error in Transit
Ch1 Path Yellow
Message Info
Comms Mode
IEEE C37.94 Channel Mismatch Ch1 Mismatch RxN

1 IEEE C37 .94

Error in Receive
Message Evaluation
Ch2 Signal Lost
Message Info
Channel 1

Error in Transit
Ch2 Path Yellow
Message Info
Channel 2 Communication Channel Mismatch Ch2 Mismatch RxN
message (IEEE C37 .94 )

Comms Mode
Standard S
Q
IEEE C37.94 RD
& Comms Changed
S
Q
RD
Relay Power Up

Fixed Pulse
V02504

Figure 277: IM64 communications mode and IEEE C37.94 alarm signals

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5 APPLICATION NOTES
Effective communications are essential for the performance of teleprotection schemes. Disturbances on the
communications links need to be detected and reported so that appropriate actions can be taken to ensure that
the power system does not go unprotected.

5.1 ALARM MANAGEMENT

Due to the criticality of IM64 communications for correct scheme performance, there is an extensive regime to
monitor signal quality and integrity, generate and report alarms. For most applications, the alarm management
provided as standard will satisfy the needs of the scheme.
For some applications, it may be necessary customise the alarm management. You can do this with the
programmable scheme logic. This section provides a detailed explanation the communications alarm signals
integrated in this product.

5.2 ALARM LOGIC

The figures in the logic diagram section show the main alarm DDB signals associated with IM64. Some of the
signals are setting or hardware dependent. For example, Channel 2 alarms are not available on a simple two-
terminal single communications link application. This section explains the logic, allowing you to understand how
you might customise the alarm logic for your application.
The messages received on each channel are individually assessed for quality to ensure the IM64 signalling scheme
is available for use. If no messages are received for a period equal to the Channel Timeout setting or the signal
quality falls below a defined value, DDB signals are activated as shown in the IM64 channel fail and scheme fail
logic diagram.
Poor quality is indicated if the percentage of incomplete messages exceeds the IM Msg Alarm Lvl setting in a
100 ms period (rolling window), or if the communications propagation time of the IM64 message exceeds the Max
Ch PropDelay (assuming the Prop Delay Stats setting is Enabled), or if (in IEEE C37.94 configuration only, and not
shown on the diagram) the Ch Mux Clk flag has been raised to indicate an incorrect baud rate.
If either the Ch Timeout or the Ch Degraded signal persists in the alarmed state for more than the duration of the
Comm Fail Timer setting, according to the conditions set in the Comm Fail Mode setting, the Signalling Fail signal
is raised.
For two-ended schemes (including dual redundant schemes), the IM64 SchemeFail signal is generated at the same
time as the Signalling Fail signal. However, for three-terminal applications, the IM64 SchemeFail signal indicates
that the full set of signalling bits cannot be processed by the scheme. Due to the self-healing nature of the three-
terminal application, this occurs when both channels at any one terminal are not receiving valid signals. This
condition generates a flag in the IM64 message structure which is passed to both remote ends, as well as
generating the local IM64 SchemeFail signal. Using this method, in three-terminal applications the scheme fail
indication is raised at all three ends.
The scheme fail signalling is generated by the inability of a device to receive messages through communication
failure. The transmitting device only knows that communication to a remote device has failed if it receives
notification from the remote device. If a device in the scheme is put into test mode, the communication failure
information is not passed on to the remote ends. If the communications failure is bidirectional, there will be no
indication at the remote device. If this causes operational issues, it may be necessary to include other signals to
enable more precise indication of scheme failure.
In addition to the main IM64 channel fail and scheme fail conceptual logic, there are number of additional alarm
DDB signals associated with test modes, reconfiguration for 3-terminal schemes, and the communication mode
(‘Standard’ or ‘IEEE C37.94’) shown in the logic diagrams.
The majority of signals are associated with the ‘IEEE C37.94’ communications mode and are not activated if the
Standard communication mode is selected. The Comms Changed DDB logic is to show that switching between
the different communication modes requires a power cycle to be performed before the change is activated.

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5.3 TWO-ENDED SCHEME EXTENDED SUPERVISION

For two-terminal applications, the Signalling Fail and IM64 SchemeFail signals operate together. As such, the
basic indications available on each device should be considered as local-terminal indications only. If remote
indication is needed to assure scheme functionality, it is necessary to use additional signals to communicate the
status to the remote end. One method of performing this is shown below:

These inputs are user controls that indicate

when the signalling is locally switched out of
service

Opto 1

Control Input 1

1 IM64 Ch1 output 8

Test Loopback

Test IM64 IM64 Ch2 output 8

Non-
Signalling Fail & Latching
LED 8

IM64 Ch1 Input 8 Aided 1 COS/LGS

1
IM64 Ch2 Input 8

V02505

Figure 278: IM64 two-terminal scheme extended supervision

In this example scheme, several signals are used to permanently pass an IM64 signal to the remote terminal.
These signals take account of the local ability to receive IM64 messages, local test/loopback modes and any other
external methods of switching the signalling scheme out of service. If any of these driving signals are energised,
the IM64 message is reset (a “0” sent on IM64 bit 8). This causes both ends to raise an alarm (LED 8 in the example)
or switch the aided scheme out of service due to loss of channel.
This is intended only as an example. You may need to customise it for your application requirements.

5.4 THREE-ENDED SCHEME EXTENDED SUPERVISION

The example for an IM64 two-terminal scheme above can be used for three-terminal applications. However for
three-terminal applications, the IM64 SchemeFail signal that is automatically communicated to all ends of the
scheme is used rather than the Signalling Fail signal.

These inputs are user controls

that indicate when the signalling
is locally switched out of service

Opto 1

Control Input 1

1 IM64 Ch1 output 8

Test Loopback

Test IM64 IM64 Ch2 output 8

Non-
Signalling Fail & Latching
LED 8

IM64 Ch1 Input 8 Aided 1 COS/LGS

1
IM64 Ch2 Input 8

V02506

Figure 279: IM64 three-terminal scheme extended supervision

In this example if both channels at any one terminal fail to receive information, this is communicated to the other
terminals. An alarm is raised and the aided scheme is switched out of service. The example given above, also takes

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into account the test modes and local switching, so the scheme is signalled out of service at all terminals if one
terminal is locally disabled.
The logic presented above is intended only as an example. You may need to customise it for your application
requirements.

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ELECTRICAL TELEPROTECTION
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1 CHAPTER OVERVIEW
This chapter contains the following sections:
Chapter Overview 519
Introduction 520
Teleprotection Scheme Principles 521
Implementation 522
Configuration 523
Connecting to Electrical InterMiCOM 525
Application Notes 526

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2 INTRODUCTION
Electrical Teleprotection is an optional feature that uses communications links to create protection schemes. It can
be used to replace hard wiring between dedicated relay output contacts and digital input circuits. Two products
equipped with electrical teleprotection can connect and exchange commands using a communication link. It is
typically used to implement teleprotection schemes.
Using full duplex communications, eight binary command signals can be sent in each direction between
connected products. The communication connection complies with the EIA(RS)232 standard. Ports may be
connected directly, or using modems. Alternatively EIA(RS)232 converters can be used for connecting to other
media such as optical fibres.
Communications statistics and diagnostics enable you to monitor the integrity of the communications link, and a
loopback feature is available to help with testing.

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3 TELEPROTECTION SCHEME PRINCIPLES

Teleprotection schemes use signalling to convey a trip command to remote circuit breakers to isolate circuits.
Three types of teleprotection commands are commonly encountered:
● Direct Tripping
● Permissive Tripping
● Blocking Scheme

3.1 DIRECT TRIPPING

In direct tripping applications (often described by the generic term: “intertripping”), teleprotection signals are sent
directly to a master trip device. Receipt of a command causes circuit breaker operation without any further
qualification. Communication must be reliable and secure because any signal detected at the receiving end
causes a trip of the circuit at that end. The communications system must be designed so that interference on the
communication circuit does not cause spurious trips. If a spurious trip occurs, the primary system might be
unnecessarily isolated.

3.2 PERMISSIVE TRIPPING

Permissive trip commands are monitored by a protection device. The circuit breaker is tripped when receipt of the
command coincides with a ‘start’ condition being detected by the protection at the receiving. Requirements for the
communications channel are less onerous than for direct tripping schemes, since receipt of an incorrect signal
must coincide with a ‘start’ of the receiving end protection for a trip operation to take place. Permissive tripping is
used to speed up tripping for faults occurring within a protected zone.

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4 IMPLEMENTATION
Electrical InterMiCOM is configured using a combination of settings in the INTERMICOM COMMS column, settings in
the INTERMICOM CONF column, and the programmable scheme logic (PSL).
The eight command signals are mapped to DDB signals within the product using the PSL.
Signals being sent to a remote terminal are referenced in the PSL as IM Output 1 - IM Output 8. Signals received
from the remote terminal are referenced as IM Input 1 - IM Input 8.

Note:
As well as the optional Modem InterMiCOM, some products are available with a feature called InterMiCOM64 (IM64). The
functionality and assignment of commands in InterMiCOM and InterMiCOM64 are similar, but they act independently and are
configured independently.

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5 CONFIGURATION
Electrical Teleprotection is compliant with IEC 60834-1:1999. For your application, you can customise individual
command signals to the differing requirements of security, speed, and dependability as defined in this standard.
You customise the command signals using the IM# Cmd Type cell in the INTERMICOM CONF column.
Any command signal can be configured for:
● Direct intertripping by selecting ‘Direct’. (this is the most secure signalling but incurs a time delay to deliver
the security).
● Blocking applications by selecting ‘Blocking’. (this is the fastest signalling)
● Permissive intertripping applications by selecting ‘Permissive. (this is dependable signalling that balances
speed and security)

You can also select to ‘Disable’ the command.

Note:
When used in the context of a setting, ‘#’ specifies which command signal (1-8) bit is being configured.

To ensure that command signals are processed only by their intended recipient, the command signals are
packaged into a message (sometimes referred to as a telegram) which contains an address field. A sending device
sets a pattern in this field. A receiving device must be set to match this pattern in the address field before the
commands will be acted upon. 10 patterns have been carefully chosen for maximum security. You need to choose
which ones to use, and set them using the Source Address and Receive Address cells in the INTERMICOM COMMS
column.
The value set in the Source Address of the transmitting device should match that set in the Receive Address of the
receiving device. For example set Source Address to 1 at a local terminal and set Receive Address to 1 at the
remote terminal.
The Source Address and Receive Address settings in the device should be set to different values to avoid false
operation under inadvertent loopback conditions.
Where more than one pair of devices is likely to share a communication link, you should set each pair to use a
different pair of address values.
Electrical InterMiCOM has been designed to be resilient to noise on communications links, but during severe noise
conditions, the communication may fail. If this is the case, an alarm is raised and you can choose how the input
signals are managed using the IM# FallBackMode cell in the INTERMICOM CONF column:
• If you choose Latched, the last valid command to be received can be maintained until a new valid message is
received.
• If you choose Default, the signal will revert to a default value after the period defined in the IM#
FrameSyncTim setting has expired. You choose the default value using the IM# DefaultValue setting.
Subsequent receipt of a full valid message will reset the alarm, and the new command signals will be used.
As well as the settings described above, you will need to assign input and output signals in the Programmable
Scheme Logic (PSL). Use the ‘Integral Tripping’ buttons to create the logic you want to apply. A typical example is
shown below.

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E002521

Figure 280: Example assignment of InterMiCOM signals within the PSL

Note:
When an Electrical InterMiCOM signal is sent from a local terminal, only the remote terminal will react to the command. The
local terminal will only react to commands initiated at the remote terminal.

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6 CONNECTING TO ELECTRICAL INTERMICOM

Electrical InterMiCOM uses EIA(RS)232 communication presented on a 9-pin ‘D’ type connector. The connector is
labelled SK5 and is located at the bottom of the 2nd Rear communication board. The port is configured as
standard DTE (Data Terminating Equipment).

6.1 SHORT DISTANCE

EIA(RS)232 is suitable for short distance connections only - less than 15m. Where this limitation is not a problem,
direct connection between devices is possible. For this case, inter-device connections should be made as shown
below the figure below.

IED IED

DCD 1 1 DCD
RxD 2 2 RxD

TxD 3 3 TxD

DTR 4 4 DTR

GND 5 5 GND

6 6
RTS 7 7 RTS
8 8
9 9

E02522

Figure 281: Direct connection

For direct connection, the maximum baud rate can generally be used.

6.2 LONG DISTANCE

EIA(RS)232 is suitable for short distance connections only - less than 15m. Where this limitation is a problem, direct
connection between devices is not possible. For this case, inter-device connections should be made as shown
below the figure below.

IED Modem Modem IED

DCD 1 DCD DCD 1 DCD
RxD 2 RxD RxD 2 RxD
Communication
TxD 3 TxD TxD 3 TxD
Network
DTR 4 4 DTR
GND 5 GND GND 5 GND
6 6
RTS 7 7 RTS
8 8
9 9

E02523

Figure 282: Indirect connection using modems

This type of connection should be used when connecting to devices that have the ability to control the DCD line.
The baud rate should be chosen to be suitable for the communications network. If the Modem does not support
the DCD function, the DCD terminal on the IED should be connected to the DTR terminal.

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7 APPLICATION NOTES
Electrical InterMiCOM settings are contained within two columns; INTERMICOM COMMS and INTERMICOM CONF.
The INTERMICOM COMMS column contains all the settings needed to configure the communications, as well as the
channel statistics and diagnostic facilities. The INTERMICOM CONF column sets the mode of each command signal
and defines how they operate in case of signalling failure.
Short metallic direct connections and connections using fire-optic converters will generally be set to have the
highest signalling speed of 19200b/s. Due to this high signalling rate, the difference in operating time between the
direct, permissive, and blocking type signals is small. This means you can select the most secure signalling
command type (‘Direct’ intertrip) for all commands. You do this with the IM# Cmd Type settings. For these
applications you should set the IM# Fallback Mode to Default. You should also set a minimal intentional delay
by setting IM# FrameSyncTim to 10 msecs. This ensures that whenever two consecutive corrupt messages are
received, the command will immediately revert to the default value until a new valid message is received.
For applications that use Modem and/or multiplexed connections, the trade-off between speed, security, and
dependability is more critical. Choosing the fastest baud rate (data rate) to achieve maximum speed may appear
attractive, but this is likely to increase the cost of the telecommunications equipment. Also, telecommunication
services operating at high data rates are more prone to interference and suffer from longer re-synchronisation
times following periods of disruption. Taking into account these factors we recommend a maximum baud rate
setting of 9600 bps. As baud rates decrease, communications become more robust with fewer interruptions, but
overall signalling times increase.
At slower baud rates, the choice of signalling mode becomes significant. You should also consider what happens
during periods of noise when message structure and content can be lost.
● In ‘Blocking’ mode, the likelihood of receiving a command in a noisy environment is high. In this case, we
recommend you set IM# Fallback Mode to Default, with a reasonably long IM# FrameSyncTim setting.
Set IM# DefaultValue to ‘1’. This provides a substitute for a received blocking signal, applying a failsafe for
blocking schemes.
● In ‘Direct’ mode, the likelihood of receiving commands in a noisy environment is small. In this case, we
recommend you set IM# Fallback Mode to Default with a short IM# FrameSyncTim setting. Set IM#
DefaultValue to ‘0’. This means that if a corrupt message is received, InterMiCOM will use the default value.
This provides a substitute for the intertrip signal not being received, applying a failsafe for direct
intertripping schemes.
● In ‘Permissive’ mode, the likelihood of receiving a valid command under noisy communications conditions is
somwhere between that of the ‘Blocking’ mode and the ‘Direct’ intertrip mode. In this case, we
recommended you set IM# Fallback Mode to Latched.
The table below presents recommended IM# FrameSyncTim settings for the different signalling modes and baud
rates:
Minimum Recommended "IM# FrameSyncTim" Setting
Minimum Setting Maximum Setting
Baud Rate Direct Intertrip Mode Blocking Mode
(ms) (ms)
600 100 250 100 1500
1200 50 130 50 1500
2400 30 70 30 1500
4800 20 40 20 1500
9600 10 20 10 1500
19200 10 10 10 1500

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Note:
As we have recommended Latched operation, the table does not contain recommendations for ‘Permissive’ mode. However, if
you do select ‘Default’ mode, you should set IM# FrameSyncTim greater than those listed above. If you set IM#
FrameSyncTim lower than the minimum setting listed above, the device could interpret a valid change in a message as a
corrupted message.

We recommend a setting of 25% for the communications failure alarm.

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COMMUNICATIONS
Chapter 22 - Communications P543i/P545i

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1 CHAPTER OVERVIEW
This product supports Substation Automation System (SAS), and Supervisory Control and Data Acquisition (SCADA)
communication. The support embraces the evolution of communications technologies that have taken place since
microprocessor technologies were introduced into protection, control, and monitoring devices which are now
ubiquitously known as Intelligent Electronic Devices for the substation (IEDs).
As standard, all products support rugged serial communications for SCADA and SAS applications. By option, any
product can support Ethernet communications for more advanced SCADA and SAS applications.

This chapter contains the following sections:

Chapter Overview 531
Communication Interfaces 532
Serial Communication 533
Standard Ethernet Communication 536
Redundant Ethernet Communication 537
Simple Network Management Protocol (SNMP) 560
Data Protocols 567
Read Only Mode 596
Time Synchronisation 598

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2 COMMUNICATION INTERFACES
The products have a number of standard and optional communication interfaces. The standard and optional
hardware and protocols are summarised below:
Port Availability Physical layer Use Data Protocols
Front Standard RS232 Local settings Courier
Rear Port 1 RS232 / RS485 / K- SCADA Courier, MODBUS, IEC60870-5-103, DNP3.0
Standard
(RP1 copper) Bus Remote settings (order option)
Rear Port 1 SCADA Courier, MODBUS, IEC60870-5-103, DNP3.0
Optional Fibre
(RP1 fibre) Remote settings (order option)
Rear Port 2 RS232 / RS485 / K- SCADA SK4: Courier only
Optional
(RP2) Bus Remote settings SK5: InterMicom only
IEC 61850 or DNP3 IEC 61850, Courier (tunnelled) or DNP3.0
Ethernet Optional Ethernet
Remote settings (order option)

Note:
Optional communications boards are always fitted into slot A.

Note:
It is only possible to fit one optional communications board, therefore RP2 and Ethernet communications are mutually
exclusive.

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3 SERIAL COMMUNICATION
The physical layer standards that are used for serial communications for SCADA purposes are:
● EIA(RS)485 (often abbreviated to RS485)
● K-Bus (a proprietary customization of RS485)

EIA(RS)232 is used for local communication with the IED (for transferring settings and downloading firmware
updates).
RS485 is similar to RS232 but for longer distances and it allows daisy-chaining and multi-dropping of IEDs.
K-Bus is a proprietary protocol quite similar to RS485, but it cannot be mixed on the same link as RS485. Unlike
RS485, K-Bus signals applied across two terminals are not polarised.
It is important to note that these are not data protocols. They only describe the physical characteristics required
for two devices to communicate with each other.
For a description of the K-Bus standard see K-Bus (on page534) and General Electric's K-Bus interface guide
reference R6509.
A full description of the RS485 is available in the published standard.

3.1 EIA(RS)232 BUS

The EIA(RS)232 interface uses the IEC 60870-5 FT1.2 frame format.
The device supports an IEC 60870-5 FT1.2 connection on the front-port. This is intended for temporary local
connection and is not suitable for permanent connection. This interface uses a fixed baud rate of 19200 bps, 11-bit
frame (8 data bits, 1 start bit, 1 stop bit, even parity bit), and a fixed device address of '1'.
EIA(RS)232 interfaces are polarised.

3.2 EIA(RS)485 BUS

The RS485 two-wire connection provides a half-duplex, fully isolated serial connection to the IED. The connection is
polarized but there is no agreed definition of which terminal is which. If the master is unable to communicate with
the product, and the communication parameters match, then it is possible that the two-wire connection is
reversed.
The RS485 bus must be terminated at each end with 120 Ω 0.5 W terminating resistors between the signal wires.
The RS485 standard requires that each device be directly connected to the actual bus. Stubs and tees are
forbidden. Loop bus and Star topologies are not part of the RS485 standard and are also forbidden.
Two-core screened twisted pair cable should be used. The final cable specification is dependent on the application,
although a multi-strand 0.5 mm2 per core is normally adequate. The total cable length must not exceed 1000 m. It
is important to avoid circulating currents, which can cause noise and interference, especially when the cable runs
between buildings. For this reason, the screen should be continuous and connected to ground at one end only,
normally at the master connection point.
The RS485 signal is a differential signal and there is no signal ground connection. If a signal ground connection is
present in the bus cable then it must be ignored. At no stage should this be connected to the cable's screen or to
the product’s chassis. This is for both safety and noise reasons.
It may be necessary to bias the signal wires to prevent jabber. Jabber occurs when the signal level has an
indeterminate state because the bus is not being actively driven. This can occur when all the slaves are in receive
mode and the master is slow to turn from receive mode to transmit mode. This may be because the master is
waiting in receive mode, in a high impedance state, until it has something to transmit. Jabber causes the receiving
device(s) to miss the first bits of the first character in the packet, which results in the slave rejecting the message
and consequently not responding. Symptoms of this are; poor response times (due to retries), increasing message
error counts, erratic communications, and in the worst case, complete failure to communicate.

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3.2.1 EIA(RS)485 BIASING REQUIREMENTS

Biasing requires that the signal lines be weakly pulled to a defined voltage level of about 1 V. There should only be
one bias point on the bus, which is best situated at the master connection point. The DC source used for the bias
must be clean to prevent noise being injected.

Note:
Some devices may be able to provide the bus bias, in which case external components would not be required.

6 – 9 V DC
180 Ω bias

Master 120 Ω

180 Ω bias
0V 120 Ω

Slave Slave Slave

V01000

Figure 283: RS485 biasing circuit

Warning:
It is extremely important that the 120 Ω termination resistors are fitted. Otherwise
the bias voltage may be excessive and may damage the devices connected to the
bus.

3.3 K-BUS
K-Bus is a robust signalling method based on RS485 voltage levels. K-Bus incorporates message framing, based on
a 64 kbps synchronous HDLC protocol with FM0 modulation to increase speed and security.
The rear interface is used to provide a permanent connection for K-Bus, which allows multi-drop connection.
A K-Bus spur consists of up to 32 IEDs connected together in a multi-drop arrangement using twisted pair wiring.
The K-Bus twisted pair connection is non-polarised.
It is not possible to use a standard EIA(RS)232 to EIA(RS)485 converter to convert IEC 60870-5 FT1.2 frames to K-
Bus. A protocol converter, namely the KITZ101, KITZ102 or KITZ201, must be used for this purpose. Please consult
General Electric for information regarding the specification and supply of KITZ devices. The following figure
demonstrates a typical K-Bus connection.

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IED IED IED

RS232 K-Bus

Computer RS232-USB converter KITZ protocol converter

V01001

Figure 284: Remote communication using K-Bus

Note:
An RS232-USB converter is only needed if the local computer does not provide an RS232 port.

Further information about K-Bus is available in the publication R6509: K-Bus Interface Guide, which is available on
request.

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4 STANDARD ETHERNET COMMUNICATION

The type of Ethernet board depends on the chosen model. The available boards and their features are described in
the Hardware Design chapter of this manual.
The Ethernet interface is required for either IEC 61850 or DNP3 over Ethernet (protocol must be selected at time of
order). With either of these protocols, the Ethernet interface also offers communication with the settings
application software for remote configuration and record extraction.
Fibre optic connection is recommended for use in permanent connections in a substation environment, as it offers
advantages in terms of noise rejection. The fibre optic port provides 100 Mbps communication and uses type
BFOC 2.5 (ST) connectors. Fibres should be suitable for 1300 nm transmission and be multimode 50/125 µm or
62.5/125 µm.
Connection can also be made to a 10Base-T or a 100Base-TX Ethernet switch using the RJ45 port.

4.1 HOT-STANDBY ETHERNET FAILOVER

This is used for products which are fitted with a standard Ethernet board. The standard Ethernet board has one
fibre and one copper interface. If there is a fault on the fibre channel it can switch to the copper channel, or vice
versa.
When this function detects a link failure, it generates the NIC Fail Alarm. The failover timer then starts, which has a
settable timeout. During this time, the Hot Standby Failover function continues to check the status of the other
channel. If the link failure recovers before the failover timer times out, the channels are not swapped over. If there
is still a fail when the failover timer times out and the other channel status is ok, the channels are swapped over.
The Ethernet controller is then reconfigured and the link is renegotiated.
To set the function, use the IEC 61850 Configurator tool in the Settings Application Software.

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5 REDUNDANT ETHERNET COMMUNICATION

Redundancy is required where a single point of failure cannot be tolerated. It is required in critical applications
such as substation automation. Redundancy acts as an insurance policy, providing an alternative route if one
route fails.
Ethernet communication redundancy is available for most General Electric products, using a Redundant Ethernet
Board (REB). The REB is a Network Interface Card (NIC), which incorporates an integrated Ethernet switch. The
board provides two Ethernet transmitter/receiver pairs.
By ordering option, a number of different protocols are available to provide the redundancy according to particular
system requirements.
In addition to the two Ethernet transmitter/receiver pairs, the REB provides link activity indication in the form of
LEDs, link fail indication in the form of watchdog contacts, and a dedicated time synchronisation input.
The dedicated time synchronisation input is designed to connect to an IRIG-B signal. Both modulated and un-
modulated IRIG-B formats are supported according to the selected option. Simple Network Time Protocol (SNTP) is
supported over the Ethernet communications.

5.1 SUPPORTED PROTOCOLS

A range of Redundant Ethernet Boards are available to support different protocols for different requirements. One
of the key requirements of substation redundant communications is "bumpless" redundancy. This means the
ability to transfer from one communication path to another without noticeable consequences. Standard protocols
of the time could not meet the demanding requirements of network availability for substation automation
solutions. Switch-over times were unacceptably long. For this reason, companies developed proprietary protocols.
More recently, however, standard protocols, which support bumpless redundancy (namely PRP and HSR) have
been developed and ratified.
As well as supporting standard non-bumpless protocols such as RSTP, the REB was originally designed to support
bumpless redundancy, using proprietary protocols (SHP, DHP) before the standard protocols became available.
Since then, variants have been produced for the newer standard protocols.
REB variants for each of the following protocols are available:
● PRP (Parallel Redundancy Protocol)
● HSR (High-availability Seamless Redundancy)
● RSTP (Rapid Spanning Tree Protocol)
● SHP (Self-Healing Protocol)
● DHP (Dual Homing Protocol)

PRP and HSR are open standards, so their implementation is compatible with any standard PRP or HSR device
respectively. PRP provides "bumpless" redundancy. RSTP is also an open standard, so its implementation is
compatible with any standard RSTP devices. RSTP provides redundancy, however, it is not "bumpless".
SHP and DHP are proprietary protocols intended for use with specific General Electric products:
● SHP is compatible with the C264-SWR212 as well as H35x multimode switches.
● DHP is compatible with the C264-SWD212 as well as H36x multimode switches.

Both SHP and DHP provide "bumpless" redundancy.

Note:
The protocol you require must be selected at the time of ordering.

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5.2 PARALLEL REDUNDANCY PROTOCOL

PRP (Parallel Reundancy Protocol) is defined in IEC 62439-3. PRP provides bumpless redundancy and meets the
most demanding needs of substation automation. The PRP implementation of the REB is compatible with any
standard PRP device.
PRP uses two independent Ethernet networks operating in parallel. PRP systems are designed so that there should
be no common point of failure between the two networks, so the networks have independent power sources and
are not connected together directly.
Devices designed for PRP applications have two ports attached to two separate networks and are called Doubly
Attached Nodes (DAN). A DAN has two ports, one MAC address and one IP address.
The sending node replicates each frame and transmits them over both networks. The receiving node processes the
frame that arrives first and discards the duplicate. Therefore there is no distinction between the working and
backup path. The receiving node checks that all frames arrive in sequence and that frames are correctly received
on both ports.
Devices such as printers that have a single Ethernet port can be connected to either of the networks but will not
directly benefit from the PRP principles. Such devices are called Singly Attached Nodes (SAN). For devices with a
single Ethernet port that need to connect to both LANs, this can be achieved by employing Ethernet Redundancy
Boxes (sometimes abbreviated to RedBox). Devices with a single Ethernet port that connect to both LANs by
means of a RedBox are known as Virtual DAN (VDAN).
The figure below summarises DAN, SAN, VDAN, LAN, and RedBox connectivity.

DAN DAN

SAN DAN

LAN B

LAN A

REDUNDANCY
BOX

VDAN

VDAN SAN SAN

VDAN

E01028

Figure 285: IED attached to separate LANs

In a DAN, both ports share the same MAC address so it does not affect the way devices talk to each other in an
Ethernet network (Address Resolution Protocol at layer 2). Every data frame is seen by both ports.
When a DAN sends a frame of data, the frame is duplicated on both ports and therefore on both LAN segments.
This provides a redundant path for the data frame if one of the segments fails. Under normal conditions, both LAN
segments are working and each port receives identical frames.

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5.3 HIGH-AVAILABILITY SEAMLESS REDUNDANCY (HSR)

HSR is standardized in IEC 62439-3 (clause 5) for use in ring topology networks. Similar to PRP, HSR provides
bumpless redundancy and meets the most demanding needs of substation automation. HSR has become the
reference standard for ring-topology networks in the substation environment. The HSR implementation of the
redundancy Ethernet board (REB) is compatible with any standard HSR device.
HSR works on the premise that each device connected in the ring is a doubly attached node running HSR (referred
to as DANH). Similar to PRP, singly attached nodes such as printers are connected via Ethernet Redundancy Boxes
(RedBox).

5.3.1 HSR MULTICAST TOPOLOGY

When a DANH is sending a multicast frame, the frame (C frame) is duplicated (A frame and B frame), and each
duplicate frame A/B is tagged with the destination MAC address and the sequence number. The frames A and B
differ only in their sequence number, which is used to identify one frame from the other. Each frame is sent to the
network via a separate port. The destination DANH receives two identical frames, removes the HSR tag of the first
frame received and passes this (frame D) on for processing. The other duplicate frame is discarded. The nodes
forward frames from one port to the other unless it was the node that injected it into the ring.

Source

DANH DANH Redbox Switch

D frame C frame D frame

A frame B frame

Singly Attached
Nodes

D frame D frame D frame

DANH DANH DANH

V01030
Figure 286: HSR multicast topology

Only about half of the network bandwidth is available in HSR for multicast or broadcast frames because both
duplicate frames A & B circulate the full ring.

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5.3.2 HSR UNICAST TOPOLOGY

With unicast frames, there is just one destination and the frames are sent to that destination alone. All non-
recipient devices simply pass the frames on. They do not process them in any way. In other words, D frames are
produced only for the receiving DANH. This is illustrated below.

Source

DANH DANH Redbox Switch

C frame
A frame B frame

Singly Attached
Nodes

D frame

DANH DANH DANH

Destination V01031
Figure 287: HSR unicast topology

For unicast frames, the whole bandwidth is available as both frames A & B stop at the destination node.

5.3.3 HSR APPLICATION IN THE SUBSTATION

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T1000 switch

PC SCADA

DS Agile gateways

Px4x H49 H49 H49 Px4x

Px4x Px4x Px4x Px4x Px4x Px4x

Bay 1 Bay 2 Bay 3

E01066

Figure 288: HSR application in the substation

5.4 RAPID SPANNING TREE PROTOCOL

RSTP is a standard used to quickly reconnect a network fault by finding an alternative path. It stops network loops
whilst enabling redundancy. It can be used in star or ring connections as shown in the following figure.

Switch 1 Switch 2 Switch 1 Switch 2

IED 1 IED 2 IED 1 IED 2

Star connection with redundant ports Ring connection managed by RST P

managed by RSTP blocking function . blocking function on upper switches
and IEDs interconnected directly .
V01010

Figure 289: IED attached to redundant Ethernet star or ring circuit

The RSTP implementation in this product is compatible with any devices that use RSTP.
RSTP can recover network faults quickly, but the fault recovery time depends on the number of devices on the
network and the network topology. A typical figure for the fault recovery time is 300ms. Therefore, RSTP cannot
achieve the “bumpless” redundancy that some other protocols can.
Refer to IEEE 802.1D 2004 standard for detailed information about the opration of the protocol.

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5.5 SELF HEALING PROTOCOL

The Self-Healing Protocol (SHP) implemented in the REB is a proprietary protocol that responds to the constraints
of critical time applications such as the GOOSE messaging of IEC 61850.
It is designed, primarily, to be used on PACiS Substation Automation Systems that employ the C264-SWR212
and/or H35x switches.
SHP is applied to double-ring network topologies. If adjacent devices detect a break in the ring, then they re-route
communication traffic to restore communication as outlined in the figure below.

MiCOM MiCOM
H35 H35

C264 Px4x C264 Px4x

DS Agile Ethernet DS Agile Ethernet

IEC 61850 ring network IEC 61850 ring network
under normal conditions self healed

Px4x Px4x

E01011

Figure 290: IED, bay computer and Ethernet switch with self healing ring facilities

A Self-Healing Management function (SHM) manages the ring.

Under healthy conditions, frames are sent on the main ring (primary fibre) in one direction, with short check frames
being sent every 5 μs in the opposite direction on the back-up ring (secondary fibre).
If the main ring breaks, the SHMs at either side of the break start the network self-healing. On one side of the
break, received messages are no longer sent to the main ring, but are sent to the back-up ring instead. On the
other side of the break, messages received on the back-up ring are sent to the main ring and communications are
re-established. This takes place in less than 1 ms and can be described as “bumpless”.
The principle of SHP is outlined in the figures below.

Primary Fibre

1 2 3 1 2 3 1 2 3

Switch Rx (Ep) Tx (Ep) Switch Switch

A B C D E

Tx (Es) Rx (Rs)
Hx5x IED C264 IED Hx5x

Secondary Fibre
V01013

Figure 291: Redundant Ethernet ring architecture with IED, bay computer and Ethernet switches

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Primary Fibre

1 2 3 1 2 3 1 2 3

Switch Rx (Ep) Tx (Ep) Switch Switch

A B C D E

Tx (Es) Rx (Rs)
Hx5x IED C264 IED Hx5x

Secondary Fibre
V01014

Figure 292: Redundant Ethernet ring architecture with IED, bay computer and Ethernet switches after failure

5.6 DUAL HOMING PROTOCOL

The Dual Homing Protocol (DHP) implemented in the REB is a proprietary protocol. It is designed, primarily to be
used on PACiS systems that employ the C264-SWD212 and/or H36x multimode switches.
DHP addresses the constraints of critical time applications such as the GOOSE messaging of IEC 61850.
DHP is applied to double-star network topologies. If a connection between two devices is broken, the network
continues to operate correctly.
The Dual Homing Manager (DHM) handles topologies where a device is connected to two independent networks,
one being the "main" path, the other being the "backup" path. Both are active at the same time.
Internet frames from a sending device are sent by the DHM to both networks. Receiving devices apply a “duplicate
discard” principle. This means that when both networks are operational, the REB receives two copies of the same
Ethernet frame. If both links are healthy, frames are received on both, and the DHM uses the first frame received.
The second frame is discarded. If one link fails, frames received on the healthy link are used.
DHP delivers a typical recovery time of less than 1 ms. The mechanism is outlined in the figures below.

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Network 1 Network 2

Optical star Optical star

Alstom Alstom
H63x H63x

Dual homing Dual homing Dual homing

SWD21x SWD21x SWD21x

IED IED IED IED IED IED IED IED

Modified frames from network 1

Modified frames from network 2
No modified frames
V01015

Figure 293: Dual homing mechanism

The H36x is a repeater with a standard 802.3 Ethernet switch, plus the DHM.

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MiCOM H382

SCADA or PACiS OI

DS Agile gateways

H600 switch H600 switch

Ethernet
Up to
6 links C264 *

C264 H368 Px4x **

Ethernet
Up to
4 links

RS485

Bay level Bay level Bay level

Type 1 Type 2 Type 3

TX copper link
FX optical fibre Ethernet
E01017 RS485, RS422
* For PRP this is SRP, for DHP this is SWD
** For PRP this is PRP REB, for DHP this is DHP REB

Figure 294: Application of Dual Homing Star at substation level

5.7 CONFIGURING IP ADDRESSES

An IP address is a logical address assigned to devices in a computer network that uses the Internet Protocol (IP) for
communication between nodes. IP addresses are stored as binary numbers but they are represented using
Decimal Dot Notation, where four sets of decimal numbers are separated by dots as follows:
XXX.XXX.XXX.XXX
For example:
10.86.254.85
An IP address in a network is usually associated with a subnet mask. The subnet mask defines which network the
device belongs to. A subnet mask has the same form as an IP address.
For example:
255.255.255.0
Both the IED and the REB each have their own IP address. The following diagram shows the IED as IP1 and the REB
as IP2.

Note:
IP1 and IP2 are different but use the same subnet mask.

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The switch IP address must be configured through the Ethernet network.

Set by IED Configurator

IED (IP1) AAA.BBB.CCC.DDD

REB (IP2) WWW.XXX.YYY.ZZZ

Set by Hardware Dip Switch SW 2 for SHP, DHP, or RSTP

Set by Switch Manager for SHP and DHP Set by PRP/HSR Configurator for PRP or HSR
Set by RSTP Configurator for RSTP
Set by PRP /HSR Configurator for PRP or HSR Fixed at 254 for SHP, DHP, or RSTP
Set by PRP /HSR Configurator for PRP or HSR
V01018

Figure 295: IED and REB IP address configuration

5.7.1 CONFIGURING THE IED IP ADDRESS

If you are using IEC 61850, set the IED IP address using the IEC 61850 Configurator software. In the IEC 61850
Configurator, set Media to Single Copper or Redundant Fibre.
If you are using DNP3 over Ethernet, set the IED IP address by editing the DNP3 file, using the DNP3 Configurator
software. In the DNP3 Configurator, set Ethernet Media to Copper, even though the redundant Ethernet network
uses fibre optic cables.

5.7.2 CONFIGURING THE REB IP ADDRESS

The board IP address must be configured before connecting the IED to the network to avoid an IP address conflict.
The way you configure the IP address depends on the redundancy protocol you have chosen.

PRP/HSR
If using PRP or HSR, you configure the REB IP address using the PRP/HSR Configurator software.

RSTP
If using RSTP, the first two octets are set by the RSTP configurator or an SNMP MIB browser. The third octet is fixed
at 254 (FE hex, 11111110 binary), and the fourth octet is set by the on-board dip switch.

SHP or DHP
If using SHP or DHP the first two octets are set by the Switch Manager software or an SNMP MIB browser. The third
octet is fixed at 254 (FE hex, 11111110 binary), and the fourth octet is set by the on-board dip switch.

Note:
An H35 (SHP) or H36 (DHP) network device is needed in the network to configure the REB IP address if you are using SNMP.

5.7.2.1 CONFIGURING THE LAST OCTET (SHP, DHP, RSTP)

If using SHP, DHP or RSTP, the last octet is configured using board address switch SW2 on the board. Remove the
IED front cover to gain access to the board address switch.

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Warning:
Configure the hardware settings before the device is installed.

1. Refer to the safety section of the IED.

2. Switch off the IED. Disconnect the power and all connections.
3. Before removing the front cover, take precautions to prevent electrostatic discharge damage according to
the ANSI/ESD-20.20 -2007 standard.
4. Wear a 1 MΩ earth strap and connect it to the earth (ground) point on the back of the IED.

E01019

5. Lift the upper and lower flaps. Remove the six screws securing the front panel and pull the front panel
outwards.

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E01020

6. Press the levers either side of the connector to disconnect the ribbon cable from the front panel.

E01021

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7. Remove the redundant Ethernet board. Set the last octet of IP address using the DIP switches. The available
range is 1 to 127.

1 Example address 1 + 4 + 16 + 64 = 85
2 decimal 85
4
8
16
32
64
Unused
ON
V01022 SW2 Top view

8. Once you have set the IP address, reassemble the IED, following theses instructions in the reverse order.

Warning:
Take care not to damage the pins of the ribbon cable connector on the front panel when reinserting
the ribbon cable.

5.8 PRP/HSR CONFIGURATOR

The PRP/HSR Configurator tool is intended for MiCOM Px4x IEDs with redundant Ethernet using PRP (Parallel
Redundancy Protocol), or HSR (High-availability Seamless Redundancy). This tool is used to identify IEDs, switch
between PRP and HSR or configure their parameters, configure the redundancy IP address, or configure the SNTP
IP address.

5.8.1 CONNECTING THE IED TO A PC

Connect the IED to the PC on which the Configurator tool is used. This connection is done through an Ethernet
switch or through a media converter.

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RJ45

Ethernet switch
Media
Converter
TXA RXA TXB RXB

TX RX

RXA TXA RXB TXB RXA TXA RXB TXB

IED IED

(a) (b)
V01806

Figure 296: Connection using (a) an Ethernet switch and (b) a media converter

5.8.2 INSTALLING THE CONFIGURATOR

To install the configurator:
1. Double click the WinPcap installer.
2. Double click the Configurator installer.
3. Click Next and follow the on-screen instructions.

5.8.3 STARTING THE CONFIGURATOR

To start the configurator:
1. Select the Configurator from the Windows Programs menu.
2. The Login screen appears. For user mode login, enter the Login name as User and click OK with no
password.
3. If the login screen does not appear, check all network connections.
4. The main window appears. In the bottom right-hand corner of the main window, click the Language button
to select the language.
5. The Network Board drop-down list shows the Network Board, IP Address and MAC Address of the PC in
which the Configurator is running.

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5.8.4 PRP/HSR DEVICE IDENTIFICATION

To configure the redundant Ethernet board, go to the main window and click the Identify Device button. A list of
devices are shown with the following details:
● Device address
● MAC address
● Version number of the firmware
● SNTP IP address
● Date & time of the real-time clock, from the board.

Select the device you wish to configure. The MAC address of the selected device is highlighted.

5.8.5 SELECTING THE DEVICE MODE

You must now select the device mode that you wish to use. This will be either PRP or HSR. To do this, select the
appropriate radio button then click the Update button. You will be asked to confirm a device reboot. Click OK to
confirm.

5.8.6 PRP/HSR IP ADDRESS CONFIGURATION

To change the network address component of the IP address:
1. From the main window click the IP Config button. The Device setup screen appears.
2. Enter the required board IP address and click OK. This is the redundancy network address, not the IEC 61850
IP address.
3. The board network address is updated and displayed in the main window.

5.8.7 SNTP IP ADDRESS CONFIGURATION

To Configure the SNTP server IP address:
1. From the main window click the SNTP Config button. The Device setup screen appears.
2. Enter the required MAC SNTP address and server IP SNTP Address. Click OK.
3. The updated MAC and IP SNTP addresses appear in the main screen.

5.8.8 CHECK FOR CONNECTED EQUIPMENT

To check what devices are connected to the device being monitored:
1. From the main window, select the device.
2. Click the Equipment button.
3. At the bottom of the main window, a box shows the ports where devices are connected and their MAC
addresses.

5.8.9 PRP CONFIGURATION

To view or configure the PRP Parameters:
1. Ensure that you have set the device mode to PRP.
2. Click the PRP/HSR Config button. The PRP Config screen appears.
3. To view the available parameters, click the Get PRP Parameters button.
4. To change the parameters, click the Set Parameters button and modify their values.
If you need to restore the default values of the parameters, click the Restore Defaults button.

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The configurable parameters are as follows:

● Multicast Address: Use this field to configure the multicast destination address. All DANPs in the network
must be configured to operate with the same multicast address for the purpose of network supervision.
● Node Forget Time: This is the time after which a node entry is cleared in the nodes table.
● Life Check Interval: This defines how often a node sends a PRP_Supervision frame. All DANPs shall be
configured with the same Life Check Interval.

5.8.10 HSR CONFIGURATION

To view or configure the HSR Parameters:
1. Click the PRP/HSR Config button. The HSR Config screen appears.
2. To view the available parameters in the board that is connected, click the Retrieve HSR Parameters from
IED button.
3. To change the parameters, click the Set Parameters button and modify their values.
If you need to restore the default values of the parameters, click the Restore Defaults button.
The configurable parameters are as follows:
● Multicast Address: Use this field to configure the multicast destination address. All DANPs in the network
must be configured to operate with the same multicast address for the purpose of network supervision.
● Node Forget Time: This is the time after which a node entry is cleared in the nodes table.
● Life Check Interval: This defines how often a node sends a PRP_Supervision frame. All DANPs must be
configured with the same Life Check Interval.
● Proxy Node Table Forget Time: This is the time after which a node entry is cleared in the ProxyTable
● Proxy Node Table Max Entries: This is the maximum number of entries in the ProxyTable
● Entry Forget Time: This is the time after which an entry is removed from the duplicates
● Node Reboot Interval: This is the minimum time during which a node that reboots remains silent

5.8.11 FILTERING DATABASE

The Filtering Database is used to determine how frames are forwarded or filtered across the on-board Ethernet
switch. Filtering information specifies the set of ports to which frames received from a specific port are forwarded.
The Ethernet switch examines each received frame to see if the frame's destination address matches a source
address listed in the Filtering Database. If there is a match, the device uses the filtering/forwarding information for
that source address to determine how to forward or filter the frame. Otherwise the frame is forwarded to all the
ports in the Ethernet switch (broadcast).

General tab
The Filtering Database contains two types of entry; static and dynamic. The Static Entries are the source addresses
entered by an administrator. The Dynamic Entries are the source addresses learnt by the switch process. The
Dynamic Entries are removed from the Filtering Database after the Ageing Time. The Database holds a maximum
of 1024 entries.
1. To access the forwarding database functions, if required, click the Filtering Database button in the main
window.
2. To view the Forwarding Database Size, Number of Static Entries and Number of Dynamic Entries, click Read
Database Info.
3. To set the Aging Time, enter the number of seconds in the text box and click the Set button.

Filtering Entries tab

The Filtering Database configuration pages are used to view, add or delete entries from the Filtering Database. This
feature is available only for the administrator. This Filtering Database is mainly used during the testing to verify the

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PRP/HSR functionality. To add an entry in the forwarding database, click the Filtering Entries tab. Configure as
follows:
1. Select the Port Number and MAC Address
2. Set the Entry type (Dynamic or Static)
3. Set the cast type (Unicast or Multicast)
4. Set theMGMT and Rate Limit
5. Click the Create button. The new entry appears in the forwarding database.
To delete an entry from the forwarding database, select the entry and click the Delete Entry button.

Goose Filtering tab

This page configures the source MACs from which GOOSE messages will be allowed or blocked. The filtering can be
configured by either the MAC address range boxes or by selecting or unselecting the individual MAC addresses in
the MAC table. After you have defined the addresses to be allowed or blocked you need to update the table and
apply the filter:
● Update Table: This updates the MAC table according to the filtering range entered in the MAC address
range boxes.
● Apply Filter: This applies the filtering configuration in the MAC table to the HSR/PRP board.

5.8.12 END OF SESSION

To finish the session:
1. In the main window, click the Quit button, a new screen appears.
2. If a database backup is required, click Yes, a new screen appears.
3. Click the ... button to browse the path. Enter the name in the text box.

5.9 RSTP CONFIGURATOR

The RSTP Configurator tool is intended for MiCOM Px4x IEDs with redundant Ethernet using RSTP (Rapid Spanning
Tree Protocol). This tool is used to identify IEDs, configure the redundancy IP address, configure the SNTP IP
address and configure the RSTP parameters.

5.9.1 CONNECTING THE IED TO A PC

Connect the IED to the PC on which the Configurator tool is used. This connection is done through an Ethernet
switch or through a media converter.

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RJ45

Ethernet switch
Media
Converter
TX1 RX1 TX2 RX2

TX RX

RX1 TX1 RX2 TX2 RX1 TX1 RX2 TX2

IED IED

(a) (b)
V01803

Figure 297: Connection using (a) an Ethernet switch and (b) a media converter

5.9.2 INSTALLING THE CONFIGURATOR

To install the configurator:
1. Double click the WinPcap installer.
2. Double click the Configurator installer.
3. Click Next and follow the on-screen instructions.

5.9.3 STARTING THE CONFIGURATOR

To start the configurator:
1. Select the Configurator from the Windows Programs menu.
2. The Login screen appears. For user mode login, enter the Login name as User and click OK with no
password.
3. If the login screen does not appear, check all network connections.
4. The main window appears. In the bottom right-hand corner of the main window, click the Language button
to select the language.
5. The Network Board drop-down list shows the Network Board, IP Address and MAC Address of the PC in
which the Configurator is running.

5.9.4 RSTP DEVICE IDENTIFICATION

To configure the redundant Ethernet board, go to the main window and click Identify Device.

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Note:
Due to the time needed to establish the RSTP protocol, wait 25 seconds between connecting the PC to the IED and clicking the
Identify Device button.

The redundant Ethernet board connected to the PC is identified and its details are listed.
● Device address
● MAC address
● Version number of the firmware
● SNTP IP address
● Date & time of the real-time clock, from the board.

5.9.5 RSTP IP ADDRESS CONFIGURATION

To change the network address component of the IP address,
1. From the main window click the IP Config button.
2. The Device Setup screen appears showing the IP Base Address. This is the board redundancy network
address, not the IEC 61850 IP address.
3. Enter the required board IP address. The first two octets can be configured. The third octet is always 254.
The last octet is set using the DIP switches (SW2) on the redundant Ethernet board, next to the ribbon
connector.
4. Click OK. The board network address is updated and displayed in the main window.

5.9.6 SNTP IP ADDRESS CONFIGURATION

To Configure the SNTP server IP address:
1. From the main window click the SNTP Config button. The Device setup screen appears.
2. Enter the required MAC SNTP address and server IP SNTP Address. Click OK.
3. The updated MAC and IP SNTP addresses appear in the main screen.

5.9.7 CHECK FOR CONNECTED EQUIPMENT

To check what devices are connected to the device being monitored:
1. From the main window, select the device.
2. Click the Equipment button.
3. At the bottom of the main window, a box shows the ports where devices are connected and their MAC
addresses.

5.9.8 RSTP CONFIGURATION

1. To view or configure the RSTP Bridge Parameters, from the main window, click the device address to select
the device. The selected device MAC address appears highlighted.
2. Click the RSTP Config button. The RSTP Config screen appears.
3. To view the available parameters in the board that is connected, click the Get RSTP Parameters button.
4. To set the configurable parameters such as Bridge Max Age, Bridge Hello Time, Bridge Forward Delay, and
Bridge Priority, modify the parameter values according to the following table and click Set RSTP
Parameters.

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Maximum value
S.No Parameter Default value (second) Minimum value (second)
(second)
1 Bridge Max Age 20 6 40
2 Bridge Hello Time 2 1 10
3 Bridge Forward Delay 15 4 30
4 Bridge Priority 32768 0 61440

5.9.8.1 BRIDGE PARAMETERS

To read the RSTP bridge parameters from the board,
1. From the main window click the device address to select the device. The RSTP Config window appears and
the default tab is Bridge Parameters.
2. Click the Get RSTP Parameters button. This displays all the RSTP bridge parameters from the Ethernet
board.
3. To modify the RSTP parameters, enter the values and click Set RSTP Parameters.
4. To restore the default values, click Restore Default and click Set RSTP Parameters.
The grayed parameters are read-only and cannot be modified.

Note:
When assigning the bridge priority, make sure the root of the network is the Ethernet switch, not the IEDs. This reduces the
number of hops to reach all devices in the network. Also make sure the priority values for all IEDs are higher than that of the
switch.

5.9.8.2 PORT PARAMETERS

This function is useful if you need to view the parameters of each port.
1. From the main window, click the device address to select the device. The RSTP Config window appears.
2. Select the Port Parameters tab, then click Get Parameters to read the port parameters. Alternatively, select
the port numbers to read the parameters.

5.9.8.3 PORT STATES

This is used to see which ports of the board are enabled or disabled.
1. From the main window, click the device address to select the device. The RSTP Config window appears.
2. Select the Port States tab then click the Get Port States button. This lists the ports of the Ethernet board. A
tick shows they are enabled.

5.9.9 END OF SESSION

To finish the session:
1. In the main window, click the Quit button, a new screen appears.
2. If a database backup is required, click Yes, a new screen appears.
3. Click the ... button to browse the path. Enter the name in the text box.

5.10 SWITCH MANAGER

Switch Manager is used to manage Ethernet ring networks and MiCOM H35x-V2 and H36x-V2 SNMP facilities. It is
a set of tools used to manage, optimize, diagnose and supervise your network. It also handles the version software
of the switch.

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The Switch Manager tool is also intended for MiCOM Px4x IEDs with redundant Ethernet using Self Healing Protocol
(SHP) and Dual Homing Protocol (DHP). This tool is used to identify IEDs and Alstom Switches, and to configure the
redundancy IP address for the Alstom proprietary Self Healing Protocol and Dual Homing Protocol.

Switch hardware
Alstom switches are stand-alone devices (H3xx, H6x families) or embedded in a computer device rack, for example
MiCOM C264 (SWDxxx, SWRxxx, SWUxxx Ethernet boards) or PC board (MiCOM H14x, MiCOM H15x, MiCOM H16x).

Switch range
There are 3 types of Alstom switches:
● Standard switches: SWU (in C264), H14x (PCI), H34x, H6x
● Redundant Ring switches: SWR (in C264), H15x (PCI), H35x,
● Redundant Dual Homing switches: SWD (in C264), H16x (PCI), H36x

Switch Manager allows you to allocate an IP addresses for Alstom switches. Switches can then be synchronized
using the Simple Network Time Protocol (SNTP) or they can be administrated using the Simple Network
Management Protocol (SNMP).
All switches have a single 6-byte MAC address.

Redundancy Management
Standard Ethernet does not support a loop at the OSI link layer (layer 2 of the 7 layer model). A mesh topology
cannot be created using a standard Hub and switch. Redundancy needs separate networks using hardware in
routers or software in dedicated switches using STP (Spanning Tree Protocol). However, this redundancy
mechanism is too slow for one link failure in electrical automation networks.
Alstom has developed its own Redundancy ring and star mechanisms using two specific Ethernet ports of the
redundant switches. This redundancy works between Alstom switches of the same type. The two redundant
Ethernet connections between Alstom switches create one private redundant Ethernet LAN.
The Ethernet ports dedicated to the redundancy are optical Ethernet ports. The Alstom redundancy mechanism
uses a single specific address for each Ethernet switch of the private LAN. This address is set using DIP switches or
jumpers.
Switch Manager monitors the redundant address of the switches and the link topology between switches.

5.10.1 INSTALLATION

Switch Manager requirements

● PC with Windows XP or later
● Ethernet port
● 200 MB hard disk space
● PC IP address configured in Windows in same IP range as switch

Network IP address
IP addressing is needed for time synchronization of Alstom switches and for SNMP management.
Switch Manager is used to define IP addresses of Alstom switches. These addresses must be in the range of the
system IP, depending on the IP mask of the engineering PC for substation maintenance.
Alstom switches have a default multicast so the 3rd word of the IP address is always 254.

Installation procedure
Run Setup.exe and follow the on-screen instructions.

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5.10.2 SETUP
1. Make sure the PC has one Ethernet port connected to the Alstom switch.
2. Configure the PC's Ethernet port on the same subnet as the Alstom switch.
3. Select User or Admin mode. In User mode enter the user name as User, leave the password blank and click
OK. In Admin mode you can not upload the firmware on the Ethernet repeaters.
4. In Admin mode enter the user name as Admin, enter the password and click OK. All functions are available
including Expert Maintenance facilities.
5. Click the Language button in the bottom right of the screen and select your language.
6. If several Ethernet interfaces are used, in the Network board drop-down box, select the PC Network board
connected to the Alstom switch. The IP and MAC addresses are displayed below the drop-down box.
7. Periodically click the Ring Topology button (top left) to display or refresh the list of Alstom switches that are
connected.

5.10.3 NETWORK SETUP

To configure the network options:
1. From the main window click the Settings button. The Network Setup screen appears.
2. Enter the required board IP address. The first two octets can be configured. The third octet is always 254.
The last octet is set using the DIP switches (SW2) on the redundant Ethernet board, next to the ribbon
connector.
3. Click OK. The board network address is updated and displayed in the main window.
4. From the main window click the SNTP Config button. The Device setup screen appears.
5. Enter the required MAC SNTP Address and server IP SNTP Address. Click OK.
6. The updated MAC and IP SNTP addresses appear in the main screen.
7. Click the Saturation button. A new screen appears.
8. Set the saturation level and click OK. The default value is 300.

5.10.4 BANDWIDTH USED

To show how much bandwidth is used in the ring,
Click the Ring% button, at the bottom of the main window. The percentage of bandwidth used in the ring is
displayed.

5.10.5 RESET COUNTERS

To reset the switch counters,
1. Click Switch Counter Reset.
2. Click OK.

5.10.6 CHECK FOR CONNECTED EQUIPMENT

To check what devices are connected to the device being monitored:
1. From the main window, select the device.
2. Click the Equipment button.
3. At the bottom of the main window, a box shows the ports where devices are connected and their MAC
addresses.

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5.10.7 MIRRORING FUNCTION

Port mirroring is a method of monitoring network traffic that forwards a copy of each incoming and outgoing
packet from one port of the repeater to another port where the data can be studied. Port mirroring is managed
locally and a network administrator uses it as a diagnostic tool.
To set up port mirroring:
1. Select the address of the device in the main window.
2. Click the Mirroring button, a new screen appears.
3. Click the checkbox to assign a a mirror port. A mirror port copies the incoming and outgoing traffic of the
port.

5.10.8 PORTS ON/OFF

To enable or disable ports:
1. Select the address of the device in the main window.
2. Click Ports On/Off, a new screen appears.
3. Click the checkbox to enable or disable a port. A disabled port has an empty checkbox.

5.10.9 VLAN
The Virtual Local Area Network (VLAN) is a technique used to split an interconnected physical network into several
networks. This technique can be used at all ISO/OSI levels. The VLAN switch is mainly at OSI level 1 (physical VLAN)
which allows communication only between some Ethernet physical ports.
Ports on the switch can be grouped into Physical VLANs to limit traffic flooding. This is because it is limited to ports
belonging to that VLAN and not to other ports.
Port-based VLANs are VLANs where the packet forwarding decision is based on the destination MAC address and
its associated port. You must define outgoing ports allowed for each port when using port-based VLANs. The VLAN
only governs the outgoing traffic so is unidirectional. Therefore, if you wish to allow two subscriber ports to talk to
each other, you must define the egress port for both ports. An egress port is an outgoing port, through which a
data packet leaves.
To assign a physical VLAN to a set of ports:
1. Select the address of the device in the main window.
2. Click the VLAN button, a new screen appears.
3. Use the checkboxes to select which ports will be in the same VLAN. By default all the ports share the same
VLAN.

5.10.10 END OF SESSION

To finish the session:
1. In the main window, click the Quit button, a new screen appears.
2. If a database backup is required, click Yes, a new screen appears.
3. Click the ... button to browse the path. Enter the name in the text box.

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6 SIMPLE NETWORK MANAGEMENT PROTOCOL (SNMP)

Simple Network Management Protocol (SNMP) is a network protocol designed to manage devices in an IP network.
The MiCOM P40 Modular products can provide up to two SNMP interfaces on Ethernet models; one to the IED’s
Main Processor for device level status information, and another directly to the redundant Ethernet board (where
applicable) for specific Ethernet network level information.
Two versions of SNMP are supported: Version 2c, and a secure implementation of version 3 that includes cyber-
security. Only the Main Processor SNMP interface supports Version 3.

6.1 SNMP MANAGEMENT INFORMATION BASES

SNMP uses a Management Information Base (MIB), which contains information about parameters to supervise. The
MIB format is a tree structure, with each node in the tree identified by a numerical Object Identifier (OID). Each OID
identifies a variable that can be read using SNMP with the appropriate software. The information in the MIB is
standardized.
Each device in a network (workstation, server, router, bridge, etc.) maintains a MIB that reflects the status of the
managed resources on that system, such as the version of the software running on the device, the IP address
assigned to a port or interface, the amount of free hard drive space, or the number of open files. The MIB does not
contain static data, but is instead an object-oriented, dynamic database that provides a logical collection of
managed object definitions. The MIB defines the data type of each managed object and describes the object.

6.2 MAIN PROCESSOR MIBS STRUCTURE

The Main Processor MIB uses a private OID with a specific Alstom Grid number assigned by the IANA. Some items
in this MIB also support SNMP traps (where indicated). These are items that can automatically notify a host without
being read.
Address Name Trigger Trap?
0 ROOT NODE
1 ISO
3 Org
6 DOD
1 Internet
4 Private
1 Enterprise
43534 Alstom Grid (IANA No)
1 Px4x
1 System Data
1 Description YES
2 Plant Reference YES
3 Model Number NO
4 Serial Number NO
5 Frequency NO
6 Plant Status YES
7 Active Group YES
8 Software Ref.1 NO
9 Software Ref.2 NO
10 Access Level (UI) YES
2 Date and Time

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Address Name Trigger Trap?

1 Date Time NO
2 IRIG-B Status YES
3 Battery Status YES
4 Active Sync source YES
5 SNTP Server 1 NO
6 SNTP Server 2 NO
7 SNTP Status YES
8 PTP Status YES
3 System Alarms
1 Invalid Message Format YES
2 Main Protection Fail YES
3 Comms Changed YES
4 Max Prop. Alarm YES
5 9-2 Sample Alarm YES
6 9-2LE Cfg Alarm YES
7 Battery Fail YES
8 Rear Communication Fail YES
9 GOOSE IED Missing YES
10 Intermicom loopback YES
11 Intermicom message fail YES
12 Intermicom data CD fail YES
13 Intermicom Channel fail YES
14 Backup setting fail YES
15 User Curve commit to flash failure YES
16 SNTP time Sync fail YES
17 PTP failure alarm YES
4 Device Mode
1 IED Mod/Beh YES
2 Simulation Mode of Subscription YES

6.3 REDUNDANT ETHERNET BOARD MIB STRUCTURE

The Redundant Ethernet board MIB uses three types of OID:
● sysDescr
● sysUpTime
● sysName

MIB structure for RSTP, DHP and SHP

Address Name
0 CCITT
1 ISO
3 Org
6 DOD
1 Internet

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Address Name
2 mgmt
1 Mib-2
1 sys
1 sysDescr
3 sysUpTime
4 sysName
Remote Monitoring
16 RMON
1 statistics
1 etherstat
1 etherStatsEntry
9 etherStatsUndersizePkts
10 etherStatsOversizePkts
12 etherStatsJabbers
13 etherStatsCollisions
14 etherStatsPkts64Octets
15 etherStatsPkts65to127Octets
16 etherStatsPkts128to255Octets
17 etherStatsPkts256to511Octets
18 etherStatsPkts512to1023Octets

MIB structure for PRP/HSR

Address Name
0 ITU
1 ISO
0 Standard
62439 IECHighavailibility
3 PRP
1 linkRedundancyEntityObjects
0 lreConfiguration
0 lreConfigurationGeneralGroup
1 lreManufacturerName
2 lreInterfaceCount
1 lreConfigurationInterfaceGroup
0 lreConfigurationInterfaces
1 lreInterfaceConfigTable
1 lreInterfaceConfigEntry
1 lreInterfaceConfigIndex
2 lreRowStatus
3 lreNodeType
4 lreNodeName
5 lreVersionName
6 lreMacAddressA

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Address Name
7 lreMacAddressB
8 lreAdapterAdminStateA
9 lreAdapterAdminStateB
10 lreLinkStatusA
11 lreLinkStatusB
12 lreDuplicateDiscard
13 lreTransparentReception
14 lreHsrLREMode
15 lreSwitchingEndNode
16 lreRedBoxIdentity
17 lreSanA
18 lreSanB
19 lreEvaluateSupervision
20 lreNodesTableClear
21 lreProxyNodeTableClear
1 lreStatistics
1 lreStatisticsInterfaceGroup
0 lreStatisticsInterfaces
1 lreInterfaceStatsTable
1 lreInterfaceStatsIndex
2 lreCntTotalSentA
3 lreCntTotalSentB
4 lreCntErrWrongLANA
5 lreCntErrWrongLANB
6 lreCntReceivedA
7 lreCntReceivedB
8 lreCntErrorsA
9 lreCntErrorsB
10 lreCntNodes
11 IreOwnRxCntA
12 IreOwnRxCntB
3 lreProxyNodeTable
1 lreProxyNodeEntry
1 reProxyNodeIndex
2 reProxyNodeMacAddress
3 Org
6 Dod
1 Internet
2 mgmt
1 mib-2
1 System
1 sysDescr
3 sysUpTime

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Address Name
5 sysName
7 sysServices
2 interfaces
2 ifTable
1 ifEntry
1 ifIndex
2 ifDescr
3 ifType
4 ifMtu
5 ifSpeed
6 ifPhysAddress
7 ifAdminStatus
8 ifOpenStatus
9 ifLastChange
10 ifInOctets
11 ifInUcastPkts
12 ifInNUcastPkts
13 ifInDiscards
14 ifInErrors
15 ifInUnknownProtos
16 ifOutOctets
17 ifOutUcastPkts
18 ifOutNUcastPkts
19 ifOutDiscards
20 ifOutErrors
21 ifOutQLen
22 ifSpecific
16 rmon
1 statistics
1 etherStatsTable
1 etherStatsEntry
1 etherStatsIndex
2 etherStatsDataSource
3 etherStatsDropEvents
4 etherStatsOctets
5 etherStatsPkts
6 etherStatsBroadcastPkts
7 etherStatsMulticastPkts
8 etherStatsCRCAlignErrors
9 etherStatsUndersizePkts
10 etherStatsOversizePkts
11 etherStatsFragments
12 etherStatsJabbers

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Address Name
13 etherStatsCollisions
14 etherStatsPkts64Octets
15 etherStatsPkts65to127Octets
16 etherStatsPkts128to255Octets
17 etherStatsPkts256to511Octets
18 etherStatsPkts512to1023Octets
19 etherStatsPkts1024to1518Octets
20 etherStatsOwner
21 etherStatsStatus

6.4 ACCESSING THE MIB

Various SNMP client software tools can be used. We recommend using an SNMP MIB browser, which can perform
the basic SNMP operations such as GET, GETNEXT and RESPONSE.

Note:
There are two IP addresses visible when communicating with the Redundant Ethernet Card via the fibre optic ports: Use the
one for the IED itself to the Main Processor SNMP interface, and use the one for the on-board Ethernet switch to access the
Redundant Ethernet Board SNMP interface. See the configuration chapter for more information.

6.5 MAIN PROCESSOR SNMP CONFIGURATION

You configure the main processor SNMP interface using the HMI panel. Two different versions are available;
SNMPv2c and SNMPv3:
To enable the main processor SNMP interface:
1. Select the COMMUNICATIONS column and scroll to the SNMP PARAMETERS heading
2. You can select either v2C, V3 or both. Selecting None will disable the main processor SNMP interface.

SNMP Trap Configuration

SNMP traps allow for unsolicited reporting between the IED and up to two SNMP managers with unique IP
addresses. The device MIB details what information can be reported using Traps. To configure the SNMP Traps:
1. Move down to the cell Trap Dest. IP 1 and enter the IP address of the first destination SNMP manager.
Setting this cell to 0.0.0.0 disables the first Trap interface.
2. Move down to the cell Trap Dest. IP 2 and enter the IP address of the second destination SNMP manager.
Setting this cell to 0.0.0.0 disables the Second Trap interface.

SNMP V3 Security Configuration

SNMPv3 provides a higher level of security via authentication and privacy protocols. The IED adopts a secure
SNMPv3 implementation with a user-based security model (USM).

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Authentication is used to check the identity of users, privacy allows for encryption of SNMP messages. Both are
optional, however you must enable authentication in order to enable privacy. To configure these security options:
1. If SNMPv3 has been enabled, set the Security Level setting. There are three levels; without authentication
and without privacy (noAuthNoPriv), with authentication but without privacy (authNoPriv), and with
authentication and with privacy (authPriv).
2. If Authentication is enabled, use the Auth Protocol setting to select the authentication type. There are two
options: HMAC-MD5-96 or HMAC-SHA-96.
3. Using the Auth Password setting, enter the 8-character password to be used by the IED for authentication.
4. If privacy is enabled, use the Encrypt Protocol setting to set the 8-character password that will be used by
the IED for encryption.

SNMP V2C Security Configuration

SNMPv2c implements authentication between the master and agent using a parameter called the Community
Name. This is effectively the password but it is not encrypted during transmission (this makes it inappropriate for
some scenarios in which case version 3 should be used instead). To configure the SNMP 2c security:
1. If SNMPv2c has been enabled, use the Community Name setting to set the password that will be used by
the IED and SNMP manager for authentication. This may be between one and 8 characters.

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7 DATA PROTOCOLS
The products supports a wide range of protocols to make them applicable to many industries and applications.
The exact data protocols supported by a particular product depend on its chosen application, but the following
table gives a list of the data protocols that are typically available.

SCADA data protocols

Data Protocol Layer 1 protocol Description
Courier K-Bus, RS232, RS485, Ethernet Standard for SCADA communications developed by General Electric.
MODBUS RS485 Standard for SCADA communications developed by Modicon.
IEC 60870-5-103 RS485 IEC standard for SCADA communications
Standard for SCADA communications developed by Harris. Used mainly in
DNP 3.0 RS485, Ethernet
North America.
IEC 61850 Ethernet IEC standard for substation automation. Facilitates interoperability.

The relationship of these protocols to the lower level physical layer protocols are as follows:
IEC 60870-5-103
MODBUS IEC 61850
Data Protocols
DNP3.0 DNP3.0
Courier Courier Courier Courier
Data Link Layer EIA(RS)485 Ethernet EIA(RS)232 K-Bus
Physical Layer Copper or Optical Fibre

7.1 COURIER
This section should provide sufficient detail to enable understanding of the Courier protocol at a level required by
most users. For situations where the level of information contained in this manual is insufficient, further
publications (R6511 and R6512) containing in-depth details about the protocol and its use, are available on
request.
Courier is an General Electric proprietary communication protocol. Courier uses a standard set of commands to
access a database of settings and data in the IED. This allows a master to communicate with a number of slave
devices. The application-specific elements are contained in the database rather than in the commands used to
interrogate it, meaning that the master station does not need to be preconfigured. Courier also provides a
sequence of event (SOE) and disturbance record extraction mechanism.

7.1.1 PHYSICAL CONNECTION AND LINK LAYER

Courier can be used with three physical layer protocols: K-Bus, EIA(RS)232 or EIA(RS)485.
Several connection options are available for Courier
● The front serial RS232 port (for connection to Settings application software on, for example, a laptop
● Rear Port 1 (RP1) - for permanent SCADA connection via RS485 or K-Bus
● Optional fibre port (RP1 in slot A) - for permanent SCADA connection via optical fibre
● Optional Rear Port 2 (RP2) - for permanent SCADA connection via RS485, K-Bus, or RS232

For either of the rear ports, both the IED address and baud rate can be selected using the front panel menu or by
the settings application software.

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7.1.2 COURIER DATABASE

The Courier database is two-dimensional and resembles a table. Each cell in the database is referenced by a row
and column address. Both the column and the row can take a range from 0 to 255 (0000 to FFFF Hexadecimal.
Addresses in the database are specified as hexadecimal values, for example, 0A02 is column 0A row 02.
Associated settings or data are part of the same column. Row zero of the column has a text string to identify the
contents of the column and to act as a column heading.
The product-specific menu databases contain the complete database definition.

7.1.3 SETTINGS CATEGORIES

There are two main categories of settings in protection IEDs:
● Control and support settings
● Protection settings

With the exception of the Disturbance Recorder settings, changes made to the control and support settings are
implemented immediately and stored in non-volatile memory. Changes made to the Protection settings and the
Disturbance Recorder settings are stored in ‘scratchpad’ memory and are not immediately implemented. These
need to be committed by writing to the Save Changes cell in the CONFIGURATION column.

7.1.4 SETTING CHANGES

Courier provides two mechanisms for making setting changes. Either method can be used for editing any of the
settings in the database.

Method 1
This uses a combination of three commands to perform a settings change:
First, enter Setting mode: This checks that the cell is settable and returns the limits.
1. Preload Setting: This places a new value into the cell. This value is echoed to ensure that setting corruption
has not taken place. The validity of the setting is not checked by this action.
2. Execute Setting: This confirms the setting change. If the change is valid, a positive response is returned. If
the setting change fails, an error response is returned.
3. Abort Setting: This command can be used to abandon the setting change.
This is the most secure method. It is ideally suited to on-line editors because the setting limits are extracted before
the setting change is made. However, this method can be slow if many settings are being changed because three
commands are required for each change.

Method 2
The Set Value command can be used to change a setting directly. The response to this command is either a
positive confirm or an error code to indicate the nature of a failure. This command can be used to implement a
setting more rapidly than the previous method, however the limits are not extracted. This method is therefore most
suitable for off-line setting editors such as MiCOM S1 Agile, or for issuing preconfigured control commands.

7.1.5 EVENT EXTRACTION

You can extract events either automatically (rear serial port only) or manually (either serial port). For automatic
extraction, all events are extracted in sequential order using the Courier event mechanism. This includes fault and
maintenance data if appropriate. The manual approach allows you to select events, faults, or maintenance data
as desired.

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7.1.5.1 AUTOMATIC EVENT RECORD EXTRACTION

This method is intended for continuous extraction of event and fault information as it is produced. It is only
supported through the rear Courier port.
When new event information is created, the Event bit is set in the Status byte. This indicates to the Master device
that event information is available. The oldest, non-extracted event can be extracted from the IED using the Send
Event command. The IED responds with the event data.
Once an event has been extracted, the Accept Event command can be used to confirm that the event has been
successfully extracted. When all events have been extracted, the Event bit is reset. If there are more events still to
be extracted, the next event can be accessed using the Send Event command as before.

7.1.5.2 MANUAL EVENT RECORD EXTRACTION

The VIEW RECORDS column (location 01) is used for manual viewing of event, fault, and maintenance records. The
contents of this column depend on the nature of the record selected. You can select events by event number and
directly select a fault or maintenance record by number.

Event Record Selection ('Select Event' cell: 0101)

This cell can be set the number of stored events. For simple event records (Type 0), cells 0102 to 0105 contain the
event details. A single cell is used to represent each of the event fields. If the event selected is a fault or
maintenance record (Type 3), the remainder of the column contains the additional information.

Fault Record Selection ('Select Fault' cell: 0105)

This cell can be used to select a fault record directly, using a value between 0 and 4 to select one of up to five
stored fault records. (0 is the most recent fault and 4 is the oldest). The column then contains the details of the fault
record selected.

Maintenance Record Selection ('Select Maint' cell: 01F0)

This cell can be used to select a maintenance record using a value between 0 and 4. This cell operates in a similar
way to the fault record selection.
If this column is used to extract event information, the number associated with a particular record changes when
a new event or fault occurs.

Event Types
The IED generates events under certain circumstances such as:
● Change of state of output contact
● Change of state of opto-input
● Protection element operation
● Alarm condition
● Setting change
● Password entered/timed-out

Event Record Format

The IED returns the following fields when the Send Event command is invoked:
● Cell reference
● Time stamp
● Cell text
● Cell value

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The Menu Database contains tables of possible events, and shows how the contents of the above fields are
interpreted. Fault and Maintenance records return a Courier Type 3 event, which contains the above fields plus two
additional fields:
● Event extraction column
● Event number

These events contain additional information, which is extracted from the IED using column B4. Row 01 contains a
Select Record setting that allows the fault or maintenance record to be selected. This setting should be set to the
event number value returned in the record. The extended data can be extracted from the IED by uploading the text
and data from the column.

7.1.6 DISTURBANCE RECORD EXTRACTION

The stored disturbance records are accessible through the Courier interface. The records are extracted using
column (B4).
The Select Record cell can be used to select the record to be extracted. Record 0 is the oldest non-extracted
record. Older records which have been already been extracted are assigned positive values, while younger records
are assigned negative values. To help automatic extraction through the rear port, the IED sets the Disturbance bit
of the Status byte, whenever there are non-extracted disturbance records.
Once a record has been selected, using the above cell, the time and date of the record can be read from the
Trigger Time cell (B402). The disturbance record can be extracted using the block transfer mechanism from cell
B40B and saved in the COMTRADE format. The settings application software software automatically does this.

7.1.7 PROGRAMMABLE SCHEME LOGIC SETTINGS

The programmable scheme logic (PSL) settings can be uploaded from and downloaded to the IED using the block
transfer mechanism.
The following cells are used to perform the extraction:
● Domain cell (B204): Used to select either PSL settings (upload or download) or PSL configuration data
(upload only)
● Sub-Domain cell (B208): Used to select the Protection Setting Group to be uploaded or downloaded.
● Version cell (B20C): Used on a download to check the compatibility of the file to be downloaded.
● Transfer Mode cell (B21C): Used to set up the transfer process.
● Data Transfer cell (B120): Used to perform upload or download.

The PSL settings can be uploaded and downloaded to and from the IED using this mechanism. The settings
application software must be used to edit the settings. It also performs checks on the validity of the settings before
they are transferred to the IED.

7.1.8 TIME SYNCHRONISATION

The time and date can be set using the time synchronization feature of the Courier protocol. The device will correct
for the transmission delay. The time synchronization message may be sent as either a global command or to any
individual IED address. If the time synchronization message is sent to an individual address, then the device will
respond with a confirm message. If sent as a global command, the (same) command must be sent twice. A time
synchronization Courier event will be generated/produced whether the time-synchronization message is sent as a
global command or to any individual IED address.
If the clock is being synchronized using the IRIG-B input then it will not be possible to set the device time using the
Courier interface. An attempt to set the time using the interface will cause the device to create an event with the
current date and time taken from the IRIG-B synchronized internal clock.

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7.1.9 COURIER CONFIGURATION

To configure the device:
1. Select the CONFIGURATION column and check that the Comms settings cell is set to Visible.
2. Select the COMMUNICATIONS column.
3. Move to the first cell down (RP1 protocol). This is a non-settable cell, which shows the chosen
communication protocol – in this case Courier.

COMMUNICATIONS
RP1 Protocol
Courier

4. Move down to the next cell (RP1 Address). This cell controls the address of the RP1 port on thje device. Up to
32 IEDs can be connected to one spur. It is therefore necessary for each IED to have a unique address so
that messages from the master control station are accepted by one IED only. Courier uses an integer
number between 1 and 254 for the Relay Address. It is set to 255 by default, which has to be changed. It is
important that no two IEDs share the same address.

COMMUNICATIONS
RP1 Address
100

5. Move down to the next cell (RP1 InactivTimer). This cell controls the inactivity timer. The inactivity timer
controls how long the IED waits without receiving any messages on the rear port before revoking any
password access that was enabled and discarding any changes. For the rear port this can be set between 1
and 30 minutes.

COMMUNICATIONS
RP1 Inactivtimer
10.00 mins.

6. If the optional fibre optic connectors are fitted, the RP1 PhysicalLink cell is visible. This cell controls the
physical media used for the communication (Copper or Fibre optic).

COMMUNICATIONS
RP1 PhysicalLink
Copper

7. Move down to the next cell (RP1 Card Status). This cell is not settable. It displays the status of the chosen
physical layer protocol for RP1.

COMMUNICATIONS
RP1 Card Status
K-Bus OK

8. Move down to the next cell (RP1 Port Config). This cell controls the type of serial connection. Select between
K-Bus or RS485.

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COMMUNICATIONS
RP1 Port Config
K-Bus

9. If using EIA(RS)485, the next cell (RP1 Comms Mode) selects the communication mode. The choice is either
IEC 60870 FT1.2 for normal operation with 11-bit modems, or 10-bit no parity. If using K-Bus this cell will not
appear.

COMMUNICATIONS
RP1 Comms Mode
IEC 60870 FT1.2

10. If using EIA(RS)485, the next cell down controls the baud rate. Three baud rates are supported; 9600, 19200
and 38400. If using K-Bus this cell will not appear as the baud rate is fixed at 64 kbps.

COMMUNICATIONS
RP1 Baud rate
19200

7.2 IEC 60870-5-103

The specification IEC 60870-5-103 (Telecontrol Equipment and Systems Part 5 Section 103: Transmission
Protocols), defines the use of standards IEC 60870-5-1 to IEC 60870-5-5, which were designed for communication
with protection equipment
This section describes how the IEC 60870-5-103 standard is applied to the Px40 platform. It is not a description of
the standard itself. The level at which this section is written assumes that the reader is already familiar with the
IEC 60870-5-103 standard.
This section should provide sufficient detail to enable understanding of the standard at a level required by most
users.
The IEC 60870-5-103 interface is a master/slave interface with the device as the slave device. The device conforms
to compatibility level 2, as defined in the IEC 60870-5-103.standard.
The following IEC 60870-5-103 facilities are supported by this interface:
● Initialization (reset)
● Time synchronization
● Event record extraction
● General interrogation
● Cyclic measurements
● General commands
● Disturbance record extraction
● Private codes

7.2.1 PHYSICAL CONNECTION AND LINK LAYER

Two connection options are available for IEC 60870-5-103:
● Rear Port 1 (RP1) - for permanent SCADA connection via RS485
● Optional fibre port (RP1 in slot A) - for permanent SCADA connection via optical fibre

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If the optional fibre optic port is fitted, a menu item appears in which the active port can be selected. However the
selection is only effective following the next power up.
The IED address and baud rate can be selected using the front panel menu or by the settings application software.

7.2.2 INITIALISATION
Whenever the device has been powered up, or if the communication parameters have been changed a reset
command is required to initialize the communications. The device will respond to either of the two reset
commands; Reset CU or Reset FCB (Communication Unit or Frame Count Bit). The difference between the two
commands is that the Reset CU command will clear any unsent messages in the transmit buffer, whereas the
Reset FCB command does not delete any messages.
The device will respond to the reset command with an identification message ASDU 5. The Cause of Transmission
(COT) of this response will be either Reset CU or Reset FCB depending on the nature of the reset command. The
content of ASDU 5 is described in the IEC 60870-5-103 section of the Menu Database, available from General
Electric separately if required.
In addition to the above identification message, it will also produce a power up event.

7.2.3 TIME SYNCHRONISATION

The time and date can be set using the time synchronization feature of the IEC 60870-5-103 protocol. The device
will correct for the transmission delay as specified in IEC 60870-5-103. If the time synchronization message is sent
as a send/confirm message then the device will respond with a confirm message. A time synchronization Class 1
event will be generated/produced whether the time-synchronization message is sent as a send confirm or a
broadcast (send/no reply) message.
If the clock is being synchronized using the IRIG-B input then it will not be possible to set the device time using the
IEC 60870-5-103 interface. An attempt to set the time via the interface will cause the device to create an event
with the current date and time taken from the IRIG-B synchronized internal clock.

7.2.4 SPONTANEOUS EVENTS

Events are categorized using the following information:
● Function type
● Information Number

The IEC 60870-5-103 profile in the Menu Database contains a complete listing of all events produced by the
device.

7.2.5 GENERAL INTERROGATION (GI)

The GI request can be used to read the status of the device, the function numbers, and information numbers that
will be returned during the GI cycle. These are shown in the IEC 60870-5-103 profile in the Menu Database.

7.2.6 CYCLIC MEASUREMENTS

The device will produce measured values using ASDU 9 on a cyclical basis, this can be read from the device using a
Class 2 poll (note ADSU 3 is not used). The rate at which the device produces new measured values can be
controlled using the measurement period setting. This setting can be edited from the front panel menu or using
MiCOM S1 Agile. It is active immediately following a change.
The device transmits its measurands at 2.4 times the rated value of the analogue value.

7.2.7 COMMANDS
A list of the supported commands is contained in the Menu Database. The device will respond to other commands
with an ASDU 1, with a cause of transmission (COT) indicating ‘negative acknowledgement’.

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7.2.8 TEST MODE

It is possible to disable the device output contacts to allow secondary injection testing to be performed using
either the front panel menu or the front serial port. The IEC 60870-5-103 standard interprets this as ‘test mode’. An
event will be produced to indicate both entry to and exit from test mode. Spontaneous events and cyclic measured
data transmitted whilst the device is in test mode will have a COT of ‘test mode’.

7.2.9 DISTURBANCE RECORDS

The disturbance records are stored in uncompressed format and can be extracted using the standard
mechanisms described in IEC 60870-5-103.

Note:
IEC 60870-5-103 only supports up to 8 records.

7.2.10 COMMAND/MONITOR BLOCKING

The device supports a facility to block messages in the monitor direction (data from the device) and also in the
command direction (data to the device). Messages can be blocked in the monitor and command directions using
one of the two following methods
● The menu command RP1 CS103Blcking in the COMMUNICATIONS column
● The DDB signals Monitor Blocked and Command Blocked

7.2.11 IEC 60870-5-103 CONFIGURATION

To configure the device:
1. Select the CONFIGURATION column and check that the Comms settings cell is set to Visible.
2. Select the COMMUNICATIONS column.
3. Move to the first cell down (RP1 protocol). This is a non-settable cell, which shows the chosen
communication protocol – in this case IEC 60870-5-103.

COMMUNICATIONS
RP1 Protocol
IEC 60870-5-103

4. Move down to the next cell (RP1 Address). This cell controls the IEC 60870-5-103 address of the IED. Up to 32
IEDs can be connected to one spur. It is therefore necessary for each IED to have a unique address so that
messages from the master control station are accepted by one IED only. IEC 60870-5-103 uses an integer
number between 0 and 254 for the address. It is important that no two IEDs have the same IEC 60870 5 103
address. The IEC 60870-5-103 address is then used by the master station to communicate with the IED.

COMMUNICATIONS
RP1 address
162

5. Move down to the next cell (RP1 Baud Rate). This cell controls the baud rate to be used. Two baud rates are
supported by the IED, 9600 bits/s and 19200 bits/s. Make sure that the baud rate selected on the
IED is the same as that set on the master station.

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COMMUNICATIONS
RP1 Baud rate
9600 bits/s

6. Move down to the next cell (RP1 Meas Period). The next cell down controls the period between
IEC 60870-5-103 measurements. The IEC 60870-5-103 protocol allows the IED to supply measurements at
regular intervals. The interval between measurements is controlled by this cell, and can be set between 1
and 60 seconds.

COMMUNICATIONS
RP1 Meas Period
30.00 s

7. If the optional fibre optic connectors are fitted, the RP1 PhysicalLink cell is visible. This cell controls the
physical media used for the communication (Copper or Fibre optic).

COMMUNICATIONS
RP1 PhysicalLink
Copper

8. The next cell down (RP1 CS103Blcking) can be used for monitor or command blocking.

COMMUNICATIONS
RP1 CS103Blcking
Disabled

9. There are three settings associated with this cell; these are:

Setting: Description:
Disabled No blocking selected.
When the monitor blocking DDB Signal is active high, either by energising an opto input or control input,
Monitor Blocking reading of the status information and disturbance records is not permitted. When in this mode the device
returns a "Termination of general interrogation" message to the master station.
When the command blocking DDB signal is active high, either by energising an opto input or control input,
Command Blocking all remote commands will be ignored (i.e. CB Trip/Close, change setting group etc.). When in this mode the
device returns a "negative acknowledgement of command" message to the master station.

7.3 DNP 3.0

This section describes how the DNP 3.0 standard is applied in the product. It is not a description of the standard
itself. The level at which this section is written assumes that the reader is already familiar with the DNP 3.0
standard.
The descriptions given here are intended to accompany the device profile document that is included in the Menu
Database document. The DNP 3.0 protocol is not described here, please refer to the documentation available from
the user group. The device profile document specifies the full details of the DNP 3.0 implementation. This is the
standard format DNP 3.0 document that specifies which objects; variations and qualifiers are supported. The
device profile document also specifies what data is available from the device using DNP 3.0. The IED operates as a
DNP 3.0 slave and supports subset level 2, as described in the DNP 3.0 standard, plus some of the features from
level 3.

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The DNP 3.0 protocol is defined and administered by the DNP Users Group. For further information on DNP 3.0 and
the protocol specifications, please see the DNP website (www.dnp.org).

7.3.1 PHYSICAL CONNECTION AND LINK LAYER

DNP 3.0 can be used with two physical layer protocols: EIA(RS)485, or Ethernet.
Several connection options are available for DNP 3.0
● Rear Port 1 (RP1) - for permanent SCADA connection via RS485
● Optional fibre port (RP1 in slot A) - for permanent SCADA connection via optical fibre
● An RJ45 connection on an optional Ethernet board - for permanent SCADA Ethernet connection
● A fibre connection on an optional Ethernet board - for permanent SCADA Ethernet connection

The IED address and baud rate can be selected using the front panel menu or by the settings application software.
When using a serial interface, the data format is: 1 start bit, 8 data bits, 1 stop bit and optional configurable parity
bit.

7.3.2 OBJECT 1 BINARY INPUTS

Object 1, binary inputs, contains information describing the state of signals in the IED, which mostly form part of
the digital data bus (DDB). In general these include the state of the output contacts and opto-inputs, alarm signals,
and protection start and trip signals. The ‘DDB number’ column in the device profile document provides the DDB
numbers for the DNP 3.0 point data. These can be used to cross-reference to the DDB definition list. See the
relevant Menu Database document. The binary input points can also be read as change events using Object 2 and
Object 60 for class 1-3 event data.

7.3.3 OBJECT 10 BINARY OUTPUTS

Object 10, binary outputs, contains commands that can be operated using DNP 3.0. Therefore the points accept
commands of type pulse on (null, trip, close) and latch on/off as detailed in the device profile in the relevant Menu
Database document, and execute the command once for either command. The other fields are ignored (queue,
clear, trip/close, in time and off time).
There is an additional image of the Control Inputs. Described as Alias Control Inputs, they reflect the state of the
Control Input, but with a dynamic nature.
● If the Control Input DDB signal is already SET and a new DNP SET command is sent to the Control Input, the
Control Input DDB signal goes momentarily to RESET and then back to SET.
● If the Control Input DDB signal is already RESET and a new DNP RESET command is sent to the Control
Input, the Control Input DDB signal goes momentarily to SET and then back to RESET.

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DNP Latch DNP Latch DNP Latch DNP Latch

ON ON OFF OFF

Control Input
(Latched)

Aliased Control
Input
(Latched)

Control Input
(Pulsed )

Aliased Control
Input
(Pulsed )
The pulse width is equal to the duration of one protection iteration
V01002

Figure 298: Control input behaviour

Many of the IED’s functions are configurable so some of the Object 10 commands described in the following
sections may not be available. A read from Object 10 reports the point as off-line and an operate command to
Object 12 generates an error response.
Examples of Object 10 points that maybe reported as off-line are:
● Activate setting groups: Ensure setting groups are enabled
● CB trip/close: Ensure remote CB control is enabled
● Reset NPS thermal: Ensure NPS thermal protection is enabled
● Reset thermal O/L: Ensure thermal overload protection is enabled
● Reset RTD flags: Ensure RTD Inputs is enabled
● Control inputs: Ensure control inputs are enabled

7.3.4 OBJECT 20 BINARY COUNTERS

Object 20, binary counters, contains cumulative counters and measurements. The binary counters can be read as
their present ‘running’ value from Object 20, or as a ‘frozen’ value from Object 21. The running counters of object
20 accept the read, freeze and clear functions. The freeze function takes the current value of the object 20 running
counter and stores it in the corresponding Object 21 frozen counter. The freeze and clear function resets the Object
20 running counter to zero after freezing its value.
Binary counter and frozen counter change event values are available for reporting from Object 22 and Object 23
respectively. Counter change events (Object 22) only report the most recent change, so the maximum number of
events supported is the same as the total number of counters. Frozen counter change events (Object 23) are
generated whenever a freeze operation is performed and a change has occurred since the previous freeze
command. The frozen counter event queues store the points for up to two freeze operations.

7.3.5 OBJECT 30 ANALOGUE INPUT

Object 30, analogue inputs, contains information from the IED’s measurements columns in the menu. All object 30
points can be reported as 16 or 32-bit integer values with flag, 16 or 32-bit integer values without flag, as well as
short floating point values.

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Analogue values can be reported to the master station as primary, secondary or normalized values (which takes
into account the IED’s CT and VT ratios), and this is settable in the COMMUNICATIONS column in the IED.
Corresponding deadband settings can be displayed in terms of a primary, secondary or normalized value.
Deadband point values can be reported and written using Object 34 variations.
The deadband is the setting used to determine whether a change event should be generated for each point. The
change events can be read using Object 32 or Object 60. These events are generated for any point which has a
value changed by more than the deadband setting since the last time the data value was reported.
Any analogue measurement that is unavailable when it is read is reported as offline. For example, the frequency
would be offline if the current and voltage frequency is outside the tracking range of the IED. All Object 30 points
are reported as secondary values in DNP 3.0 (with respect to CT and VT ratios).

7.3.6 OBJECT 40 ANALOGUE OUTPUT

The conversion to fixed-point format requires the use of a scaling factor, which is configurable for the various
types of data within the IED such as current, voltage, and phase angle. All Object 40 points report the integer
scaling values and Object 41 is available to configure integer scaling quantities.

7.3.7 OBJECT 50 TIME SYNCHRONISATION

Function codes 1 (read) and 2 (write) are supported for Object 50 (time and date) variation 1. The DNP Need Time
function (the duration of time waited before requesting another time sync from the master) is supported, and is
configurable in the range 1 - 30 minutes.
If the clock is being synchronized using the IRIG-B input then it will not be possible to set the device time using the
Courier interface. An attempt to set the time using the interface will cause the device to create an event with the
current date and time taken from the IRIG-B synchronized internal clock.

7.3.8 DNP3 DEVICE PROFILE

This section describes the specific implementation of DNP version 3.0 within General Electric MiCOM P40 Agile IEDs
for both compact and modular ranges.
The devices use the DNP 3.0 Slave Source Code Library version 3 from Triangle MicroWorks Inc.
This document, in conjunction with the DNP 3.0 Basic 4 Document Set, and the DNP Subset Definitions Document,
provides complete information on how to communicate with the devices using the DNP 3.0 protocol.
This implementation of DNP 3.0 is fully compliant with DNP 3.0 Subset Definition Level 2. It also contains many
Subset Level 3 and above features.

7.3.8.1 DNP3 DEVICE PROFILE TABLE

The following table provides the device profile in a similar format to that defined in the DNP 3.0 Subset Definitions
Document. While it is referred to in the DNP 3.0 Subset Definitions as a “Document”, it is just one component of a
total interoperability guide. This table, in combination with the subsequent Implementation and Points List tables
should provide a complete interoperability/configuration guide for the device.
The following table provides the device profile in a similar format to that defined in the DNP 3.0 Subset Definitions
Document. While it is referred to in the DNP 3.0 Subset Definitions as a "Document", it is just one component of a
total interoperability guide. This table, in combination with the subsequent Implementation and Points List tables
should provide a complete interoperability/configuration guide for the device.

DNP 3.0
Device Profile Document
Vendor Name: ALSTOM GRID
Device Name: MiCOM P40Agile Protection Relays – compact and modular range

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DNP 3.0
Device Profile Document
Models Covered: All models
Highest DNP Level Supported*: For Requests: Level 2
*This is the highest DNP level FULLY supported. Parts of level 3 are For Responses: Level 2
also supported
Device Function: Slave
Notable objects, functions, and/or qualifiers supported in addition to the highest DNP levels supported (the complete list is described in the
DNP 3.0 Implementation Table):
For static (non-change event) object requests, request qualifier codes 00 and 01 (start-stop), 07 and 08 (limited quantity), and 17 and 28 (index)
are supported in addition to the request qualifier code 06 (no range (all points))
Static object requests sent with qualifiers 00, 01, 06, 07, or 08 will be responded with qualifiers 00 or 01
Static object requests sent with qualifiers 17 or 28 will be responded with qualifiers 17 or 28
For change-event object requests, qualifiers 17 or 28 are always responded
16-bit and 32-bit analogue change events with time may be requested
The read function code for Object 50 (time and date) variation 1 is supported
Analogue Input Deadbands, Object 34, variations 1 through 3, are supported
Floating Point Analogue Output Status and Output Block Objects 40 and 41 are supported
Sequential file transfer, Object 70, variations 2 through 7, are supported
Device Attribute Object 0 is supported
Maximum Data Link Frame Size (octets): Transmitted: 292
Received: 292
Maximum Application Fragment Size (octets) Transmitted: Configurable (100 to 2048). Default 2048
Received: 249
Maximum Data Link Retries: Fixed at 2
Maximum Application Layer Retries: None
Requires Data Link Layer Confirmation: Configurable to Never or Always
Requires Application Layer Confirmation: When reporting event data (Slave devices only)
When sending multi-fragment responses (Slave devices only)
Timeouts while waiting for:
Data Link Confirm: Configurable
Complete Application Fragment: None
Application Confirm: Configurable
Complete Application Response: None
Others:
Data Link Confirm Timeout: Configurable from 0 (Disabled) to 120s, default 10s.
Application Confirm Timeout: Configurable from 1 to 120s, default 2s.
Select/Operate Arm Timeout: Configurable from 1 to 10s, default 10s.
Need Time Interval (Set IIN1-4): Configurable from 1 to 30, default 10min.
Application File Timeout 60 s
Analog Change Event Scan Period: Fixed at 0.5s
Counter Change Event Scan Period Fixed at 0.5s
Frozen Counter Change Event Scan Period Fixed at 1s
Maximum Delay Measurement Error: 2.5 ms
Time Base Drift Over a 10-minute Interval: 7 ms
Sends/Executes Control Operations:
Write Binary Outputs: Never
Select/Operate: Always

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DNP 3.0
Device Profile Document
Direct Operate: Always
Direct Operate - No Ack: Always
Count > 1 Never
Pulse On Always
Pulse Off Sometimes
Latch On Always
Latch Off Always
Queue Never
Clear Queue Never
Note: Paired Control points will accept Pulse On/Trip and Pulse On/Close, but only single point will accept the Pulse Off control command.
Reports Binary Input Change Events when no specific variation Configurable to send one or the other
requested:
Reports time-tagged Binary Input Change Events when no specific Binary input change with time
variation requested:
Sends Unsolicited Responses: Never
Sends Static Data in Unsolicited Responses: Never
No other options are permitted
Default Counter Object/Variation: Configurable, Point-by-point list attached
Default object: 20
Default variation: 1
Counters Roll Over at: 32 bits
Sends multi-fragment responses: Yes
Sequential File Transfer Support:
Append File Mode No
Custom Status Code Strings No
Permissions Field Yes
File Events Assigned to Class No
File Events Send Immediately Yes
Multiple Blocks in a Fragment No
Max Number of Files Open 1

7.3.8.2 DNP3 IMPLEMENTATION TABLE

The implementation table provides a list of objects, variations and control codes supported by the device:
Request Response
Object
(Library will parse) (Library will respond with)
Object Variation Function Codes (dec) Qualifier Codes Function Codes Qualifier Codes (hex)
Description (dec)
Number Number (hex)
1 0 Binary Input (Variation 0 is used to 1 (read) 00, 01 (start-stop)
request default variation) 22 (assign class) 06 (no range, or all)
07, 08 (limited qty)
17, 27, 28 (index)
1 1 Binary Input 1 (read) 00, 01 (start-stop) 129 response 00, 01 (start-stop)
(default - see 06 (no range, or all) 17, 28 (index - see note 2)
note 1) 07, 08 (limited qty)
17, 27, 28 (index)
1 2 Binary Input with Flag 1 (read) 00, 01 (start-stop) 129 response 00, 01 (start-stop)
06 (no range, or all) 17, 28 (index - see note 2)
07, 08 (limited qty)
17, 28 (index)

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Request Response
Object
(Library will parse) (Library will respond with)
Object Variation Function Codes (dec) Qualifier Codes Function Codes Qualifier Codes (hex)
Description (dec)
Number Number (hex)
2 0 Binary Input Change - Any 1 (read) 06 (no range, or all)
Variation 07, 08 (limited qty)
2 1 Binary Input Change without Time 1 (read) 06 (no range, or all) 129 response 17, 28 (index)
07, 08 (limited qty)
2 2 Binary Input Change with Time 1 (read) 06 (no range, or all) 129 response 17, 28 (index)
07, 08 (limited qty)
10 0 Binary Output Status - Any 1 (read) 00, 01 (start-stop)
Variation 06 (no range, or all)
07, 08 (limited qty)
17, 27, 28 (index)
10 2 Binary Output Status 1 (read) 00, 01 (start-stop) 129 response 00, 01 (start-stop)
(default - see 06 (no range, or all) 17, 28 (index - see note 2)
note 1) 07, 08 (limited qty)
17, 28 (index)
12 1 Control Relay Output Block 3 (select) 17, 28 (index) 129 response echo of request
4 (operate)
5 (direct op)
6 (dir. op, noack)
20 0 Binary Counter - Any Variation 1 (read) 00, 01 (start-stop)
22 (assign class) 06 (no range, or all)
07, 08 (limited qty)
17, 27, 28 (index)
7 (freeze) 00, 01 (start-stop)
8 (freeze noack) 06 (no range, or all)
9 (freeze clear) 07, 08 (limited qty)
10 (frz. cl. Noack)
20 1 32-Bit Binary Counter with Flag 1 (read) 00, 01 (start-stop) 129 response 00, 01 (start-stop)
06 (no range, or all) 17, 28 (index - see note 2)
07, 08 (limited qty)
17, 27, 28 (index)
20 2 16-Bit Binary Counter with Flag 1 (read) 00, 01 (start-stop) 129 response 00, 01 (start-stop)
06 (no range, or all) 17, 28 (index - see note 2)
07, 08 (limited qty)
17, 27, 28 (index)
20 5 32-Bit Binary Counter without Flag 1 (read) 00, 01 (start-stop) 129 response 00, 01 (start-stop)
(default - see 06 (no range, or all) 17, 28 (index - see note 2)
note 1) 07, 08 (limited qty)
17, 27, 28 (index)
20 6 16-Bit Binary Counter without Flag 1 (read) 00, 01 (start-stop) 129 response 00, 01 (start-stop)
06 (no range, or all) 17, 28 (index - see note 2)
07, 08 (limited qty)
17, 27, 28 (index)
21 0 Frozen Counter - Any Variation 1 (read) 00, 01 (start-stop)
06 (no range, or all)
07, 08 (limited qty)
17, 27, 28 (index)
21 1 32-Bit Frozen Counter with Flag 1 (read) 00, 01 (start-stop) 129 response 00, 01 (start-stop)
06 (no range, or all) 17, 28 (index - see note 2)
07, 08 (limited qty)
17, 27, 28 (index)
21 2 16-Bit Frozen Counter with Flag 1 (read) 00, 01 (start-stop) 129 response 00, 01 (start-stop)
06 (no range, or all) 17, 28 (index - see note 2)
07, 08 (limited qty)
17, 27, 28 (index)
21 5 32-Bit Frozen Counter with Time of 1 (read) 00, 01 (start-stop) 129 response 00, 01 (start-stop)
Freeze 06 (no range, or all) 17, 28 (index - see note 1)
07, 08 (limited qty)
17, 27, 28 (index)
21 6 16-Bit Frozen Counter with Time of 1 (read) 00, 01 (start-stop) 129 response 00, 01 (start-stop)
Freeze 06 (no range, or all) 17, 28 17, 28 (index - see note 1)
07, 08 (limited qty)
17, 27, 28 (index)
21 9 32-Bit Frozen Counter without Flag 1 (read) 00, 01 (start-stop) 129 response 00, 01 (start-stop)
(default - see 06 (no range, or all) 17, 28 (index - see note 2)
note 1) 07, 08 (limited qty)
17, 27, 28 (index)

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Request Response
Object
(Library will parse) (Library will respond with)
Object Variation Function Codes (dec) Qualifier Codes Function Codes Qualifier Codes (hex)
Description (dec)
Number Number (hex)
21 10 16-Bit Frozen Counter without Flag 1 (read) 00, 01 (start-stop) 129 response 00, 01 (start-stop)
06 (no range, or all) 17, 28 (index - see note 2)
07, 08 (limited qty)
17, 27, 28 (index)
`22 0 Counter Change Event - Any 1 (read) 06 (no range, or all)
Variation 07, 08 (limited qty)
22 1 32-Bit Counter Change Event 1 (read) 06 (no range, or all) 129 response 17, 28 (index)
(default - see without Time 07, 08 (limited qty)
note 1)
22 2 16-Bit Counter Change Event 1 (read) 06 (no range, or all) 129 response 17, 28 (index)
without Time 07, 08 (limited qty)
22 5 32-Bit Counter Change Event with 1 (read) 06 (no range, or all) 129 response 17, 28 (index)
Time 07, 08 (limited qty)
22 6 16-Bit Counter Change Event with 1 (read) 06 (no range, or all) 129 response 17, 28 (index)
Time 07, 08 (limited qty)
23 0 Frozen Counter Event (Variation 0 1 (read) 06 (no range, or all)
is used to request default 07, 08 (limited qty)
variation)
23 1 32-Bit Frozen Counter Event 1 (read) 06 (no range, or all) 129 response 17, 28 (index)
(default - see 07, 08 (limited qty)
note 1)
23 2 16-Bit Frozen Counter Event 1 (read) 06 (no range, or all) 129 response 17, 28 (index)
07, 08 (limited qty)
23 5 32-Bit Frozen Counter Event with 1 (read) 06 (no range, or all) 129 response 17, 28 (index)
Time 07, 08 (limited qty)
23 6 16-Bit Frozen Counter Event with 1 (read) 06 (no range, or all) 129 response 17, 28 (index)
Time 07, 08 (limited qty)
30 0 Analog Input - Any Variation 1 (read) 00, 01 (start-stop)
22 (assign class) 06 (no range, or all)
07, 08 (limited qty)
17, 27, 28 (index)
30 1 32-Bit Analog Input 1 (read) 00, 01 (start-stop) 129 response 00, 01 (start-stop)
06 (no range, or all) 17, 28 (index - see note 2)
07, 08 (limited qty)
17, 27, 28 (index)
30 2 16-Bit Analog Input 1 (read) 00, 01 (start-stop) 129 response 00, 01 (start-stop)
06 (no range, or all) 17, 28 (index - see note 2)
07, 08 (limited qty)
17, 27, 28 (index)
30 3 32-Bit Analog Input without Flag 1 (read) 00, 01 (start-stop) 129 response 00, 01 (start-stop)
(default - see 06 (no range, or all) 17, 28 (index - see note 2)
note 1) 07, 08 (limited qty)
17, 27, 28 (index)
30 4 16-Bit Analog Input without Flag 1 (read) 00, 01 (start-stop) 129 response 00, 01 (start-stop)
06 (no range, or all) 17, 28 (index - see note 2)
07, 08 (limited qty)
17, 27, 28 (index)
30 5 Short floating point 1 (read) 00, 01 (start-stop) 129 response 00, 01 (start-stop)
06 (no range, or all) 17, 28 (index - see note 2)
07, 08 (limited qty)
17, 27, 28 (index)
32 0 Analog Change Event - Any 1 (read) 06 (no range, or all)
Variation 07, 08 (limited qty)
32 1 32-Bit Analog Change Event 1 (read) 06 (no range, or all) 129 response 17, 28 (index)
(default - see without Time 07, 08 (limited qty)
note 1)
32 2 16-Bit Analog Change Event 1 (read) 06 (no range, or all) 129 response 17, 28 (index)
without Time 07, 08 (limited qty)
32 3 32-Bit Analog Change Event with 1 (read) 06 (no range, or all) 129 response 17, 28 (index)
Time 07, 08 (limited qty)
32 4 16-Bit Analog Change Event with 1 (read) 06 (no range, or all) 129 response 17, 28 (index)
Time 07, 08 (limited qty)
32 5 Short floating point Analog 1 (read) 06 (no range, or all) 129 response 17, 28 (index)
Change Event without Time 07, 08 (limited qty)
32 7 Short floating point Analog 1 (read) 06 (no range, or all) 129 response 17, 28 (index)
Change Event with Time 07, 08 (limited qty)

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Request Response
Object
(Library will parse) (Library will respond with)
Object Variation Function Codes (dec) Qualifier Codes Function Codes Qualifier Codes (hex)
Description (dec)
Number Number (hex)
34 0 Analog Input Deadband (Variation 1 (read) 00, 01 (start-stop)
0 is used to request default 06 (no range, or all)
variation) 07, 08 (limited qty)
17, 27, 28 (index)
34 1 16 Bit Analog Input Deadband 1 (read) 00, 01 (start-stop) 129 response 00, 01 (start-stop)
06 (no range, or all) 17, 28 (index - see note 2)
07, 08 (limited qty)
17, 27, 28 (index)
2 (write) 00, 01 (start-stop)
07, 08 (limited qty)
17, 27, 28 (index)
34 2 32 Bit Analog Input Deadband 1 (read) 00, 01 (start-stop) 129 response 00, 01 (start-stop)
(default - see 06 (no range, or all) 17, 28 (index - see note 2)
note 1) 07, 08 (limited qty)
17, 27, 28 (index)
2 (write) 00, 01 (start-stop)
07, 08 (limited qty)
17, 27, 28 (index)
34 3 Short Floating Point Analog Input 1 (read) 00, 01 (start-stop) 129 response 00, 01 (start-stop)
Deadband 06 (no range, or all) 17, 28 (index - see note 2)
07, 08 (limited qty)
17, 27, 28 (index)
2 (write) 00, 01 (start-stop)
07, 08 (limited qty)
17, 27, 28 (index)
40 0 Analog Output Status (Variation 0 1 (read) 00, 01 (start-stop)
is used to request default 06 (no range, or all)
variation) 07, 08 (limited qty)
17, 27, 28 (index)
40 1 32-Bit Analog Output Status 1 (read) 00, 01 (start-stop) 129 response 00, 01 (start-stop)
(default - see 06 (no range, or all) 17, 28 (index - see note 2)
note 1) 07, 08 (limited qty)
17, 27, 28 (index)
40 2 16-Bit Analog Output Status 1 (read) 00, 01 (start-stop) 129 response 00, 01 (start-stop)
06 (no range, or all) 17, 28 (index - see note 2)
07, 08 (limited qty)
17, 27, 28 (index)
40 3 Short Floating Point Analog 1 (read) 00, 01 (start-stop) 129 response 00, 01 (start-stop)
Output Status 06 (no range, or all) 17, 28 (index - see note 2)
07, 08 (limited qty)
17, 27, 28 (index)
41 1 32-Bit Analog Output Block 3 (select) 17, 28 (index) 129 response echo of request
4 (operate) 27 (index)
5 (direct op)
6 (dir. op, noack)
41 2 16-Bit Analog Output Block 3 (select) 17, 28 (index) 129 response echo of request
4 (operate) 27 (index)
5 (direct op)
6 (dir. op, noack)
41 3 Short Floating Point Analog 3 (select) 17, 27, 28 (index) 129 response echo of request
Output Block 4 (operate)
5 (direct op)
6 (dir. op, noack)
1 1 (read) 07 (limited qty = 1) 129 response 07 (limited qty = 1)
50 (default - see Time and Date
note 1)
2 (write) 07 (limited qty = 1)
60 0 Not defined
60 1 Class 0 Data 1 (read) 06 (no range, or all)
60 2 Class 1 Data 1 (read) 06 (no range, or all)
07, 08 (limited qty)
22 (assign class) 06 (no range, or all)
60 3 Class 2 Data 1 (read) 06 (no range, or all)
07, 08 (limited qty)
22 (assign class) 06 (no range, or all)
60 4 Class 3 Data 1 (read) 06 (no range, or all)
07, 08 (limited qty)

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Request Response
Object
(Library will parse) (Library will respond with)
Object Variation Function Codes (dec) Qualifier Codes Function Codes Qualifier Codes (hex)
Description (dec)
Number Number (hex)
22 (assign class) 06 (no range, or all)
70 0 File Event - Any Variation 1 (read) 06 (no range, or all)
07, 08 (limited qty)
22 (assign class) 06 (no range, or all)
70 2 File Authentication 29 (authenticate) 5b (free-format) 129 response 5B (free-format)
70 3 File Command 25 (open) 5b (free-format)
27 (delete)
70 4 File Command Status 26 (close) 5b (free-format) 129 response 5B (free-format)
30 (abort)
70 5 File Transfer 1 (read) 5b (free-format) 129 response 5B (free-format)
70 6 File Transfer Status 129 response 5B (free-format)
70 7 File Descriptor 28 (get file info) 5b (free-format) 129 response 5B (free-format)

80 1 Internal Indications 1 (read) 00, 01 (start-stop) 129 response 00, 01 (start-stop)

No Object (function code only) 13 (cold restart)

No Object (function code only) 14 (warm restart)

No Object (function code only) 23 (delay meas.)

Note:
A Default variation refers to the variation responded to when variation 0 is requested and/or in class 0, 1, 2, or 3 scans.

Note:
For static (non-change-event) objects, qualifiers 17 or 28 are only responded to when a request is sent with qualifiers 17 or
28, respectively. Otherwise, static object requests sent with qualifiers 00, 01, 06, 07, or 08, will be responded to with qualifiers
00 or 01. For change-event objects, qualifiers 17 or 28 are always responded to.

7.3.8.3 DNP3 INTERNAL INDICATIONS

The following table lists the DNP3.0 Internal Indications (IIN) and identifies those that are supported by the device.
The IIN form an information element used to convey the internal states and diagnostic results of a device. This
information can be used by a receiving station to perform error recovery or other suitable functions. The IIN is a
two-octet field that follows the function code in all responses from the device. When a request cannot be
processed due to formatting errors or the requested data is not available, the IIN is always returned with the
appropriate bits set.
Bit Indication Description Supported
Octet 1
Set when a request is received with the destination address of the all stations
address (6553510). It is cleared after the next response (even if a response to a
0 All stations message received global request is required). Yes
This IIN is used to let the master station know that a "broadcast" message was
received by the relay.

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Bit Indication Description Supported

Set when data that has been configured as Class 1 data is ready to be sent to
the master.
1 Class 1 data available Yes
The master station should request this class data from the relay when this bit
is set in a response.
Set when data that has been configured as Class 2 data is ready to be sent to
the master.
2 Class 2 data available Yes
The master station should request this class data from the relay when this bit
is set in a response.
Set when data that has been configured as Class 3 data is ready to be sent to
the master.
3 Class 3 data available Yes
The master station should request this class data from the relay when this bit
is set in a response.
The relay requires time synchronization from the master station (using the
Time and Date object).
4 Time-synchronization required Yes
This IIN is cleared once the time has been synchronized. It can also be cleared
by explicitly writing a 0 into this bit of the Internal Indication object.
Set when some or all of the relays digital output points (Object 10/12) are in the
Local state. That is, the relays control outputs are NOT accessible through the
5 Local DNP protocol. No
This IIN is clear when the relay is in the Remote state. That is, the relays control
outputs are fully accessible through the DNP protocol.
Set when an abnormal condition exists in the relay. This IIN is only used when
6 Device in trouble the state cannot be described by a combination of one or more of the other IIN No
bits.
Set when the device software application restarts. This IIN is cleared when the
7 Device restart master station explicitly writes a 0 into this bit of the Internal Indications Yes
object.
Octet 2
0 Function code not implemented The received function code is not implemented within the relay. Yes
The relay does not have the specified objects or there are no objects assigned
to the requested class.
1 Requested object(s) unknown Yes
This IIN should be used for debugging purposes and usually indicates a
mismatch in device profiles or configuration problems.
Parameters in the qualifier, range or data fields are not valid or out of range.
This is a 'catch-all' for application request formatting errors. It should only be
2 Out of range Yes
used for debugging purposes. This IIN usually indicates configuration
problems.
Event buffer(s), or other application buffers, have overflowed. The master
station should attempt to recover as much data as possible and indicate to the
3 Buffer overflow Yes
user that there may be lost data. The appropriate error recovery procedures
should be initiated by the user.
The received request was understood but the requested operation is already
4 Already executing
executing.
Set to indicate that the current configuration in the relay is corrupt. The
5 Bad configuration Yes
master station may download another configuration to the relay.
6 Reserved Always returned as zero.
7 Reserved Always returned as zero.

7.3.8.4 DNP3 RESPONSE STATUS CODES

When the device processes Control Relay Output Block (Object 12) requests, it returns a set of status codes; one for
each point contained within the original request. The complete list of codes appears in the following table:

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Code Number Identifier Name Description

0 Success The received request has been accepted, initiated, or queued.
The request has not been accepted because the ‘operate’ message was received after the
1 Timeout arm timer (Select Before Operate) timed out.
The arm timer was started when the select operation for the same point was received.
The request has not been accepted because no previous matching ‘select’ request exists. (An
2 No select ‘operate’ message was sent to activate an output that was not previously armed with a
matching ‘select’ message).
The request has not been accepted because there were formatting errors in the control
3 Format error
request (‘select’, ‘operate’, or ‘direct operate’).
The request has not been accepted because a control operation is not supported for this
4 Not supported
point.
The request has not been accepted because the control queue is full or the point is already
5 Already active
active.
6 Hardware error The request has not been accepted because of control hardware problems.
7 Local The request has not been accepted because local access is in progress.
8 Too many operations The request has not been accepted because too many operations have been requested.
9 Not authorized The request has not been accepted because of insufficient authorization.
127 Undefined The request not been accepted because of some other undefined reason.

Note:
Code numbers 10 through to 126 are reserved for future use.

7.3.9 DNP3 CONFIGURATION

To configure the device:
1. Select the CONFIGURATION column and check that the Comms settings cell is set to Visible.
2. Select the COMMUNICATIONS column.
3. Move to the first cell down (RP1 protocol). This is a non-settable cell, which shows the chosen
communication protocol – in this case DNP3.0.

COMMUNICATIONS
RP1 Protocol
DNP3.0

4. Move down to the next cell (RP1 Address). This cell controls the DNP3.0 address of the IED. Up to 32 IEDs can
be connected to one spur, therefore it is necessary for each IED to have a unique address so that messages
from the master control station are accepted by only one IED. DNP3.0 uses a decimal number between 1
and 65519 for the Relay Address. It is important that no two IEDs have the same address.

COMMUNICATIONS
RP1 Address
1

5. Move down to the next cell (RP1 Baud Rate). This cell controls the baud rate to be used. Six baud rates are
supported by the IED 1200 bps, 2400 bps, 4800 bps, 9600 bps, 19200 bps and 38400 bps. Make sure that
the baud rate selected on the IED is the same as that set on the master station.

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COMMUNICATIONS
RP1 Baud rate
9600 bits/s

6. Move down to the next cell (RP1 Parity). This cell controls the parity format used in the data frames. The
parity can be set to be one of None, Odd or Even. Make sure that the parity format selected on the IED is
the same as that set on the master station.

COMMUNICATIONS
RP1 Parity
None

7. If the optional fibre optic connectors are fitted, the RP1 PhysicalLink cell is visible. This cell controls the
physical media used for the communication (Copper or Fibre optic).

COMMUNICATIONS
RP1 PhysicalLink
Copper

8. Move down to the next cell (RP1 Time Sync). This cell affects the time synchronisation request from the
master by the IED. It can be set to enabled or disabled. If enabled it allows the DNP3.0 master to
synchronise the time on the IED.

COMMUNICATIONS
RP1 Time Sync
Enabled

7.3.9.1 DNP3 CONFIGURATOR

A PC support package for DNP3.0 is available as part of the supplied settings application software (MiCOM S1 Agile)
to allow configuration of the device's DNP3.0 response. The configuration data is uploaded from the device to the
PC in a block of compressed format data and downloaded in a similar manner after modification. The new DNP3.0
configuration takes effect after the download is complete. To restore the default configuration at any time, from
the CONFIGURATION column, select the Restore Defaults cell then select All Settings.
In MiCOM S1 Agile, the DNP3.0 data is shown in three main folders, one folder each for the point configuration,
integer scaling and default variation (data format). The point configuration also includes screens for binary inputs,
binary outputs, counters and analogue input configuration.
If the device supports DNP Over Ethernet, the configuration related settings are done in the folder DNP Over
Ethernet.

7.4 IEC 61850

This section describes how the IEC 61850 standard is applied to General Electric products. It is not a description of
the standard itself. The level at which this section is written assumes that the reader is already familiar with the
IEC 61850 standard.
IEC 61850 is the international standard for Ethernet-based communication in substations. It enables integration of
all protection, control, measurement and monitoring functions within a substation, and additionally provides the
means for interlocking and inter-tripping. It combines the convenience of Ethernet with the security that is so
essential in substations today.

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There are two editions of IEC 61850; IEC 61850 edition 1 and IEC 61850 edition 2. The edition which this product
supports depends on your exact model.

7.4.1 BENEFITS OF IEC 61850

The standard provides:
● Standardised models for IEDs and other equipment within the substation
● Standardised communication services (the methods used to access and exchange data)
● Standardised formats for configuration files
● Peer-to-peer communication

The standard adheres to the requirements laid out by the ISO OSI model and therefore provides complete vendor
interoperability and flexibility on the transmission types and protocols used. This includes mapping of data onto
Ethernet, which is becoming more and more widely used in substations, in favour of RS485. Using Ethernet in the
substation offers many advantages, most significantly including:
● Ethernet allows high-speed data rates (currently 100 Mbps, rather than tens of kbps or less used by most
serial protocols)
● Ethernet provides the possibility to have multiple clients
● Ethernet is an open standard in every-day use
● There is a wide range of Ethernet-compatible products that may be used to supplement the LAN installation
(hubs, bridges, switches)

7.4.2 IEC 61850 INTEROPERABILITY

A major benefit of IEC 61850 is interoperability. IEC 61850 standardizes the data model of substation IEDs, which
allows interoperability between products from multiple vendors.
An IEC 61850-compliant device may be interoperable, but this does not mean it is interchangeable. You cannot
simply replace a product from one vendor with that of another without reconfiguration. However the terminology
is pre-defined and anyone with prior knowledge of IEC 61850 should be able to integrate a new device very quickly
without having to map all of the new data. IEC 61850 brings improved substation communications and
interoperability to the end user, at a lower cost.

7.4.3 THE IEC 61850 DATA MODEL

The data model of any IEC 61850 IED can be viewed as a hierarchy of information, whose nomenclature and
categorization is defined and standardized in the IEC 61850 specification.

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Data Attributes
stVal q t PhA PhB PhC

Data Objects
Pos A

Logical Nodes : 1 to n
LN1: XCBR LN2: MMXU

Logical Device : IEDs 1 to n

Physical Device (network address)

V01008

Figure 299: Data model layers in IEC 61850

The levels of this hierarchy can be described as follows:

Data Frame format

Layer Description
Identifies the actual IED within a system. Typically the device’s name or IP address can be used (for
Physical Device
example Feeder_1 or 10.0.0.2.
Identifies groups of related Logical Nodes within the Physical Device. For the MiCOM IEDs, 5 Logical
Logical Device
Devices exist: Control, Measurements, Protection, Records, System.
Identifies the major functional areas within the IEC 61850 data model. Either 3 or 6 characters are
used as a prefix to define the functional group (wrapper) while the actual functionality is identified by
Wrapper/Logical Node Instance a 4 character Logical Node name suffixed by an instance number.
For example, XCBR1 (circuit breaker), MMXU1 (measurements), FrqPTOF2 (overfrequency protection,
stage 2).
This next layer is used to identify the type of data you will be presented with. For example, Pos
Data Object
(position) of Logical Node type XCBR.
This is the actual data (measurement value, status, description, etc.). For example, stVal (status value)
Data Attribute
indicating actual position of circuit breaker for Data Object type Pos of Logical Node type XCBR.

7.4.4 IEC 61850 IN MICOM IEDS

IEC 61850 is implemented by use of a separate Ethernet card. This Ethernet card manages the majority of the
IEC 61850 implementation and data transfer to avoid any impact on the performance of the protection functions.
To communicate with an IEC 61850 IED on Ethernet, it is necessary only to know its IP address. This can then be
configured into either:
● An IEC 61850 client (or master), for example a bay computer (MiCOM C264)
● An HMI
● An MMS browser, with which the full data model can be retrieved from the IED, without any prior knowledge
of the IED

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The IEC 61850 compatible interface standard provides capability for the following:
● Read access to measurements
● Refresh of all measurements at the rate of once per second.
● Generation of non-buffered reports on change of status or measurement
● SNTP time synchronization over an Ethernet link. (This is used to synchronize the IED's internal real time
clock.
● GOOSE peer-to-peer communication
● Disturbance record extraction by file transfer. The record is extracted as an ASCII format COMTRADE file

● Controls (Direct and Select Before Operate)

Note:
Setting changes are not supported in the current IEC 61850 implementation. Currently these setting changes are carried out
using the settings application software.

7.4.5 IEC 61850 DATA MODEL IMPLEMENTATION

The data model naming adopted in the IEDs has been standardised for consistency. Therefore the Logical Nodes
are allocated to one of the five Logical Devices, as appropriate.
The data model is described in the Model Implementation Conformance Statement (MICS) document, which is
available as a separate document.

7.4.6 IEC 61850 COMMUNICATION SERVICES IMPLEMENTATION

The IEC 61850 communication services which are implemented in the IEDs are described in the Protocol
Implementation Conformance Statement (PICS) document, which is available as a separate document.

7.4.7 IEC 61850 PEER-TO-PEER (GOOSE) COMMUNICATIONS

The implementation of IEC 61850 Generic Object Oriented Substation Event (GOOSE) enables faster
communication between IEDs offering the possibility for a fast and reliable system-wide distribution of input and
output data values. The GOOSE model uses multicast services to deliver event information. Multicast messaging
means that messages are sent to selected devices on the network. The receiving devices can specifically accept
frames from certain devices and discard frames from the other devices. It is also known as a publisher-subscriber
system. When a device detects a change in one of its monitored status points it publishes a new message. Any
device that is interested in the information subscribes to the data it contains.

7.4.8 MAPPING GOOSE MESSAGES TO VIRTUAL INPUTS

Each GOOSE signal contained in a subscribed GOOSE message can be mapped to any of the virtual inputs within
the PSL. The virtual inputs allow the mapping to internal logic functions for protection control, directly to output
contacts or LEDs for monitoring.
An IED can subscribe to all GOOSE messages but only the following data types can be decoded and mapped to a
virtual input:
● BOOLEAN
● BSTR2
● INT16
● INT32
● INT8

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● UINT16
● UINT32
● UINT8

7.4.8.1 IEC 61850 GOOSE CONFIGURATION

All GOOSE configuration is performed using the IEC 61850 Configurator tool available in the MiCOM S1 Agile
software application.
All GOOSE publishing configuration can be found under the GOOSE Publishing tab in the configuration editor
window. All GOOSE subscription configuration parameters are under the External Binding tab in the configuration
editor window.
Settings to enable GOOSE signalling and to apply Test Mode are available using the HMI.

7.4.9 ETHERNET FUNCTIONALITY

IEC 61850 Associations are unique and made between the client and server. If Ethernet connectivity is lost for any
reason, the associations are lost, and will need to be re-established by the client. The IED has a TCP_KEEPALIVE
function to monitor each association, and terminate any which are no longer active.
The IED allows the re-establishment of associations without disruption of its operation, even after its power has
been removed. As the IED acts as a server in this process, the client must request the association. Uncommitted
settings are cancelled when power is lost, and reports requested by connected clients are reset. The client must
re-enable these when it next creates the new association to the IED.

7.4.10 IEC 61850 CONFIGURATION

You cannot configure the device for IEC 61850 edition 1 using the HMI panel on the product. For this you must use
the IEC 61850 Configurator, which is part of the settings application software. If the device is compatible with
edition 2, however, you can configure it with the HMI. To configure IEC61850 edition 2 using the HMI, you must first
enable the IP From HMI setting, after which you can set the media (copper or fibre), IP address, subnet mask and
gateway address.
IEC 61850 allows IEDs to be directly configured from a configuration file. The IED’s system configuration
capabilities are determined from an IED Capability Description file (ICD), supplied with the product. By using ICD
files from the products to be installed, you can design, configure and test (using simulation tools), a substation’s
entire protection scheme before the products are installed into the substation.
To help with this process, the settings application software provides an IEC 61850 Configurator tool, which allows
the pre-configured IEC 61850 configuration file to be imported and transferred to the IED. As well as this, you can
manually create configuration files for all products, based on their original IED capability description (ICD file).
Other features include:
● The extraction of configuration data for viewing and editing.
● A sophisticated error checking sequence to validate the configuration data before sending to the IED.

Note:
Some configuration data is available in the IEC61850 CONFIG. column, allowing read-only access to basic configuration data.

7.4.10.1 IEC 61850 CONFIGURATION BANKS

There are two configuration banks:
● Active Configuration Bank
● Inactive Configuration Bank

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Any new configuration sent to the IED is automatically stored in the inactive configuration bank, therefore not
immediately affecting the current configuration.
Following an upgrade, the IEC 61850 Configurator tool can be used to transmit a command, which authorises
activation of the new configuration contained in the inactive configuration bank. This is done by switching the
active and inactive configuration banks. The capability of switching the configuration banks is also available using
the IEC61850 CONFIG. column of the HMI.
The SCL Name and Revision attributes of both configuration banks are available in the IEC61850 CONFIG. column
of the HMI.

7.4.10.2 IEC 61850 NETWORK CONNECTIVITY

Configuration of the IP parameters and SNTP (Simple Network Time Protocol) time synchronisation parameters is
performed by the IEC 61850 Configurator tool. If these parameters are not available using an SCL (Substation
Configuration Language) file, they must be configured manually.
Every IP address on the Local Area Network must be unique. Duplicate IP addresses result in conflict and must be
avoided. Most IEDs check for a conflict on every IP configuration change and at power up and they raise an alarm
if an IP conflict is detected.
The IED can be configured to accept data from other networks using the Gateway setting. If multiple networks are
used, the IP addresses must be unique across networks.

7.4.11 IEC 61850 EDITION 2

Many parts of the IEC 61850 standard have now been released as the second edition. This offers some significant
enhancements including:
● Improved interoperability
● Many new logical nodes
● Better defined testing; it is now possible to perform off-line testing and simulation of functions

Edition 2 implementation requires use of version 3.2 of the IEC 61850 configurator, which is installed with version
1.2 of MiCOM S1 Agile.

7.4.11.1 BACKWARD COMPATIBILITY

IEC61850 System - Backward compatibility

An Edition 1 IED can operate with an Edition 2 IEC 61850 system, provided that the Edition 1 IEDs do not subscribe
to GOOSE messages with data objects or data attributes which are only available in Edition 2.
The following figure explains this concept:

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V01056

Figure 300: Edition 2 system - backward compatibility

An Edition 2 IED cannot normally operate within an Edition 1 IEC 61850 system. An Edition 2 IED can work for
GOOSE messaging in a mixed system, providing the client is compatible with Edition 2.

V01057

Figure 301: Edition 1 system - forward compatibility issues

7.4.11.2 EDITION-2 COMMON DATA CLASSES

The following common data classes (CDCs) are new to Edition 2 and therefore should not be used in GOOSE control
blocks in mixed Edition 1 and Edition 2 systems
● Histogram (HST)
● Visible string status (VSS)
● Object reference setting (ORG)
● Controllable enumerated status (ENC)
● Controllable analogue process value (APC)
● Binary controlled analogue process value (BAC)
● Enumerated status setting (ENG)
● Time setting group (TSG)

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● Currency setting group (CUG)

● Visible string setting (VSG)
● Curve shape setting (CSG)

Of these, only ENS and ENC types are available from a MiCOM P40 IED when publishing GOOSE messages, so Data
Objects using these Common Data Classes should not be published in mixed Edition 1 and Edition 2 systems.
For compatibility between Edition 1 and Edition 2 IEDs, SCL files using SCL schema version 2.1 must be used. For a
purely Edition 2 system, use the schema version 3.1.

7.4.11.3 STANDBY PROTECTION REDUNDANCY

With digital substation architectures, measurements can be shared freely on the process bus across the
substation and between different devices without any additional wiring. This is because there are no longer any
electrical connections to instruments transformers that restrict the location of IEDs.
The new IEC 61850 Edition 2 test modes enable the introduction of standby protection IEDs at any location within
the substation, which has access to both station and process buses. In the case of failure, these devices can
temporarily replace the protection functions inside other IEDs.

V01059

Figure 302: Example of Standby IED

See the example below. If a failure occurs in the Bay 1 protection IED (MP2), we could disable this device and
activate a standby protection IED to replace its functionality.

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V01060

Figure 303: Standby IED Activation Process

The following sequence would occur under this scenario:

1. During the installation phase, a spare standby IED is installed in the substation. This can remain inactive,
until it is needed to replace functions in one of several bays. The device is connected to the process bus, but
does not have any subscriptions enabled.
2. If a failure occurs (in this example, bay 1), first isolate the faulty device by disabling its process bus and
station bus interfaces. You do this by turning off the attached network interfaces.
3. Retrieve the configuration that the faulty device normally uses, and load this into the standby redundant
IED.
4. Place the IED into the "Test Blocked" mode, as defined in IEC 61850-7-4 Edition Two. This allows test signals
to be injected into the network, which will check that the configuration is correct. GOOSE signals issued by
the device will be flagged as "test" so that subscribing switchgear controllers know not to trip during this
testing. In this way the protection can be tested all the way up to the switchgear control merging units
without having to operate primary circuit breakers, or by carrying out any secondary injection.
5. Take the standby IED out of "Test-Blocked" mode and activate it so that it now replaces the protection
functions that were disabled from the initial device failure.
The standby IED reduces downtime in the case of device failure, as protection functions can be restored quickly
before the faulted device is replaced.

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8 READ ONLY MODE

With IEC 61850 and Ethernet/Internet communication capabilities, security has become an important issue. For
this reason, all relevant General Electric IEDs have been adapted to comply with the latest cyber-security
standards.
In addition to this, a facility is provided which allows you to enable or disable the communication interfaces. This
feature is available for products using Courier, IEC 60870-5-103, or IEC 61850.

8.1 IEC 60870-5-103 PROTOCOL BLOCKING

If Read-Only Mode is enabled for RP1 or RP2 with IEC 60870-5-103, the following commands are blocked at the
interface:
● Write parameters (=change setting) (private ASDUs)
● General Commands (ASDU20), namely:
○ INF16 auto-recloser on/off
○ INF19 LED reset
○ Private INFs (for example: CB open/close, Control Inputs)
The following commands are still allowed:
● Poll Class 1 (Read spontaneous events)
● Poll Class 2 (Read measurands)
● GI sequence (ASDU7 'Start GI', Poll Class 1)
● Transmission of Disturbance Records sequence (ASDU24, ASDU25, Poll Class 1)
● Time Synchronisation (ASDU6)
● General Commands (ASDU20), namely:
○ INF23 activate characteristic 1
○ INF24 activate characteristic 2
○ INF25 activate characteristic 3
○ INF26 activate characteristic 4

Note:
For IEC 60870-5-103, Read Only Mode function is different from the existing Command block feature.

8.2 COURIER PROTOCOL BLOCKING

If Read-Only Mode is enabled for RP1 or RP2 with Courier, the following commands are blocked at the interface:
● Write settings
● All controls, including:Reset Indication (Trip LED)
○ Operate Control Inputs
○ CB operations
○ Auto-reclose operations
○ Reset demands
○ Clear event/fault/maintenance/disturbance records
○ Test LEDs & contacts

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The following commands are still allowed:

● Read settings, statuses, measurands
● Read records (event, fault, disturbance)
● Time Synchronisation
● Change active setting group

8.3 IEC 61850 PROTOCOL BLOCKING

If Read-Only Mode is enabled for the Ethernet interfacing with IEC 61850, the following commands are blocked at
the interface:
● All controls, including:
○ Enable/disable protection
○ Operate Control Inputs
○ CB operations (Close/Trip, Lock)
○ Reset LEDs
The following commands are still allowed:
● Read statuses, measurands
● Generate reports
● Extract disturbance records
● Time synchronisation
● Change active setting group

8.4 READ-ONLY SETTINGS

The following settings are available for enabling or disabling Read Only Mode.
● RP1 Read Only
● RP2 Read Only (only for products that have RP2)
● NIC Read Only (where Ethernet is available)

8.5 READ-ONLY DDB SIGNALS

The remote read only mode is also available in the PSL using three dedicated DDB signals:
● RP1 Read Only
● RP2 Read Only (only for products that have RP2)
● NIC Read Only (where Ethernet is available)

Using the PSL, these signals can be activated by opto-inputs, Control Inputs and function keys if required.

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9 TIME SYNCHRONISATION
In modern protection schemes it is necessary to synchronise the IED's real time clock so that events from different
devices can be time stamped and placed in chronological order. This is achieved in various ways depending on the
chosen options and communication protocols.
● Using the IRIG-B input (if fitted)
● Using the SNTP time protocol (for Ethernet IEC 61850 versions + DNP3 OE)
● By using the time synchronisation functionality inherent in the data protocols

9.1 DEMODULATED IRIG-B

IRIG stands for Inter Range Instrumentation Group, which is a standards body responsible for standardising
different time code formats. There are several different formats starting with IRIG-A, followed by IRIG-B and so on.
The letter after the "IRIG" specifies the resolution of the time signal in pulses per second (PPS). IRIG-B, the one which
we use has a resolution of 100 PPS. IRIG-B is used when accurate time-stamping is required.
The following diagram shows a typical GPS time-synchronised substation application. The satellite RF signal is
picked up by a satellite dish and passed on to receiver. The receiver receives the signal and converts it into time
signal suitable for the substation network. IEDs in the substation use this signal to govern their internal clocks and
event recorders.

GPS time signal GPS satellite

IRIG-B

Satellite dish Receiver IED IED IED

V01040

Figure 304: GPS Satellite timing signal

The IRIG-B time code signal is a sequence of one second time frames. Each frame is split up into ten 100 mS slots
as follows:
● Time-slot 1: Seconds
● Time-slot 2: Minutes
● Time-slot 3: Hours
● Time-slot 4: Days
● Time-slot 5 and 6: Control functions
● Time-slots 7 to 10: Straight binary time of day

The first four time-slots define the time in BCD (Binary Coded Decimal). Time-slots 5 and 6 are used for control
functions, which control deletion commands and allow different data groupings within the synchronisation strings.
Time-slots 7-10 define the time in SBS (Straight Binary Second of day).

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9.1.1 IRIG-B IMPLEMENTATION

Depending on the chosen hardware options, the product can be equipped with an IRIG-B input for time
synchronisation purposes. The IRIG-B interface is implemented either on a dedicated card, or together with other
communication functionality such as Ethernet. The IRIG-B connection is presented by a connector is a BNC
connector. IRIG-B signals are usually presented as an RF-modulated signal. There are two types of input to our
IRIG-B boards: demodulated or modulated. A board that accepts a demodulated input is used where the IRIG-B
signal has already been demodulated by another device before being fed to the IED. A board that accepts a
modulated input has an on-board demodulator.
To set the device to use IRIG-B, use the setting IRIG-B Sync cell in the DATE AND TIME column.
The IRIG-B status can be viewed in the IRIG-B Status cell in the DATE AND TIME column.

9.2 SNTP
SNTP is used to synchronise the clocks of computer systems over packet-switched, variable-latency data
networks, such as IP. SNTP can be used as the time synchronisation method for models using IEC 61850 over
Ethernet.
The device is synchronised by the main SNTP server. This is achieved by entering the IP address of the SNTP server
into the IED using the IEC 61850 Configurator software described in the settings application software manual. A
second server is also configured with a different IP address for backup purposes.
This function issues an alarm when there is a loss of time synchronisation on the SNTP server. This could be
because there is no response or no valid clock signal.
The HMI menu does not contain any configurable settings relating to SNTP, as the only way to configure it is using
the IEC 61850 Configurator. However it is possible to view some parameters in the COMMUNICATIONS column
under the sub-heading SNTP parameters. Here you can view the SNTP server addresses and the SNTP poll rate in
the cells SNTP Server 1, SNTP Server 2 and SNTP Poll rate respectively.
The SNTP time synchronisation status is displayed in the SNTP Status cell in the DATE AND TIME column.

9.2.1 LOSS OF SNTP SERVER SIGNAL ALARM

This function issues an alarm when there is a loss of time synchronization on the SNTP server. It is issued when the
SNTP sever has not detected a valid time synchronisation response within its 5 second window. This is because
there is no response or no valid clock. The alarm is mapped to IEC 61850.

9.3 IEEE 1588 PRECISION TIME PROTOCOL

The MiCOM P40 modular products support the IEEE C37.238 (Power Profile) of IEEE 1588 Precision Time Protocol
(PTP) as a slave-only clock. This can be used to replace or supplement IRIG-B and SNTP time synchronisation so
that the IED can be synchronised using Ethernet messages from the substation LAN without any additional
physical connections being required.
A dedicated DDB signal (PTP Failure) his provided to indicate failure of failure of PTP.

9.3.1 ACCURACY AND DELAY CALCULATION

A time synchronisation accuracy of within 5 ms is possible. Both peer-to-peer or end-to-end mode delay
measurement can be used.
In peer-to-peer mode, delays are measured between each link in the network and are compensated for. This
provides greater accuracy, but requires that every device between the Grand Master and Slaves supports the
peer-to-peer delay measurement.
In end-to-end mode, delays are only measured between each Grand Master and Slave. The advantage of this
mode is that the requirements for the switches on the network are lower; they do not need to independently

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calculate delays. The main disadvantage is that more inaccuracy is introduced, because the method assumes that
forward and reverse delays are always the same, which may not always be correct.
When using end-to-end mode, the IED can be connected in a ring or line topology using RSTP or Self Healing
Protocol without any additional Transparent Clocks. But because the IED is a slave-only device, additional
inaccuracy is introduced. The additional error will be less than 1ms for a network of eight devices.

V01061

Figure 305: Timing error using ring or line topology

9.3.2 PTP DOMAINS

PTP traffic can be segregated into different domains using Boundary Clocks. These allow different PTP clocks to
share the same network while maintaining independent synchronisation within each grouped set.

9.4 TIME SYNCHRONSIATION USING THE COMMUNICATION PROTOCOLS

All communication protocols have in-built time synchronisation mechanisms. If an external time synchronisation
mechanism such as IRIG-B, SNTP, or IEEE 1588 PTP is not used to synchronise the devices, the time synchronisation
mechanism within the relevant serial protocol is used. The real time is usually defined in the master station and
communicated to the relevant IEDs via one of the rear serial ports using the chosen protocol. It is also possible to
define the time locally using settings in the DATE AND TIME column.
The time synchronisation for each protocol is described in the relevant protocol description section.

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1 OVERVIEW
In the past, substation networks were traditionally isolated and the protocols and data formats used to transfer
information between devices were often proprietary.
For these reasons, the substation environment was very secure against cyber-attacks. The terms used for this
inherent type of security are:
● Security by isolation (if the substation network is not connected to the outside world, it cannot be accessed
from the outside world).
● Security by obscurity (if the formats and protocols are proprietary, it is very difficult to interpret them).

The increasing sophistication of protection schemes, coupled with the advancement of technology and the desire
for vendor interoperability, has resulted in standardisation of networks and data interchange within substations.
Today, devices within substations use standardised protocols for communication. Furthermore, substations can be
interconnected with open networks, such as the internet or corporate-wide networks, which use standardised
protocols for communication. This introduces a major security risk making the grid vulnerable to cyber-attacks,
which could in turn lead to major electrical outages.
Clearly, there is now a need to secure communication and equipment within substation environments. This
chapter describes the security measures that have been put in place for our range of Intelligent Electronic Devices
(IEDs).

Note:
Cyber-security compatible devices do not enforce NERC compliance, they merely facilitate it. It is the responsibility of the user
to ensure that compliance is adhered to as and when necessary.

This chapter contains the following sections:

Overview 603
The Need for Cyber-Security 604
Standards 605
Cyber-Security Implementation 609

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2 THE NEED FOR CYBER-SECURITY

Cyber-security provides protection against unauthorised disclosure, transfer, modification, or destruction of
information or information systems, whether accidental or intentional. To achieve this, there are several security
requirements:
● Confidentiality (preventing unauthorised access to information)
● Integrity (preventing unauthorised modification)
● Availability / Authentication (preventing the denial of service and assuring authorised access to information)
● Non-repudiation (preventing the denial of an action that took place)
● Traceability / Detection (monitoring and logging of activity to detect intrusion and analyse incidents)

The threats to cyber-security may be unintentional (e.g. natural disasters, human error), or intentional (e.g. cyber-
attacks by hackers).
Good cyber-security can be achieved with a range of measures, such as closing down vulnerability loopholes,
implementing adequate security processes and procedures and providing technology to help achieve this.
Examples of vulnerabilities are:
● Indiscretions by personnel (users keep passwords on their computer)
● Bad practice (users do not change default passwords, or everyone uses the same password to access all
substation equipment)
● Bypassing of controls (users turn off security measures)
● Inadequate technology (substation is not firewalled)

Examples of availability issues are:

● Equipment overload, resulting in reduced or no performance
● Expiry of a certificate preventing access to equipment

To help tackle these issues, standards organisations have produced various standards. Compliance with these
standards significantly reduces the threats associated with lack of cyber-security.

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3 STANDARDS
There are several standards, which apply to substation cyber-security. The standards currently applicable to
General Electric IEDs are NERC and IEEE1686.
Standard Country Description
NERC CIP (North American Electric Reliability
USA Framework for the protection of the grid critical Cyber Assets
Corporation)
BDEW (German Association of Energy and Water Requirements for Secure Control and Telecommunication
Germany
Industries) Systems
ICS oriented then Relevant for EPU completing existing standard
ANSI ISA 99 USA
and identifying new topics such as patch management
International Standard for substation IED cyber-security
IEEE 1686 International
capabilities
IEC 62351 International Power system data and Comm. protocol
ISO/IEC 27002 International Framework for the protection of the grid critical Cyber Assets
NIST SP800-53 (National Institute of Standards and
USA Complete framework for SCADA SP800-82and ICS cyber-security
Technology)
CPNI Guidelines (Centre for the Protection of National Clear and valuable good practices for Process Control and SCADA
UK
Infrastructure) security

3.1 NERC COMPLIANCE

The North American Electric Reliability Corporation (NERC) created a set of standards for the protection of critical
infrastructure. These are known as the CIP standards (Critical Infrastructure Protection). These were introduced to
ensure the protection of 'Critical Cyber Assets', which control or have an influence on the reliability of North
America’s electricity generation and distribution systems.
These standards have been compulsory in the USA for several years now. Compliance auditing started in June
2007, and utilities face extremely heavy fines for non-compliance.

NERC CIP standards

CIP standard Description
CIP-002-1 Critical Cyber Assets Define and document the Critical Assets and the Critical Cyber Assets
Define and document the Security Management Controls required to protect the
CIP-003-1 Security Management Controls
Critical Cyber Assets
Define and Document Personnel handling and training required protecting Critical
CIP-004-1 Personnel and Training
Cyber Assets
Define and document logical security perimeters where Critical Cyber Assets reside.
CIP-005-1 Electronic Security Define and document measures to control access points and monitor electronic
access
Define and document Physical Security Perimeters within which Critical Cyber Assets
CIP-006-1 Physical Security
reside
Define and document system test procedures, account and password management,
CIP-007-1 Systems Security Management security patch management, system vulnerability, system logging, change control
and configuration required for all Critical Cyber Assets
Define and document procedures necessary when Cyber-security Incidents relating
CIP-008-1 Incident Reporting and Response Planning
to Critical Cyber Assets are identified
CIP-009-1 Recovery Plans Define and document Recovery plans for Critical Cyber Assets

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3.1.1 CIP 002

CIP 002 concerns itself with the identification of:
● Critical assets, such as overhead lines and transformers
● Critical cyber assets, such as IEDs that use routable protocols to communicate outside or inside the
Electronic Security Perimeter; or are accessible by dial-up

Power utility responsibilities: General Electric's contribution:

We can help the power utilities to create this asset register automatically.
Create the list of the assets
We can provide audits to list the Cyber assets

3.1.2 CIP 003

CIP 003 requires the implementation of a cyber-security policy, with associated documentation, which
demonstrates the management’s commitment and ability to secure its Critical Cyber Assets.
The standard also requires change control practices whereby all entity or vendor-related changes to hardware
and software components are documented and maintained.

Power utility responsibilities: General Electric's contribution:

We can help the power utilities to have access control to its critical assets by
providing centralized Access control.
To create a Cyber-security Policy
We can help the customer with its change control by providing a section in the
documentation where it describes changes affecting the hardware and software.

3.1.3 CIP 004

CIP 004 requires that personnel with authorized cyber access or authorized physical access to Critical Cyber
Assets, (including contractors and service vendors), have an appropriate level of training.

Power utility responsibilities: General Electric's contribution:

To provide appropriate training of its personnel We can provide cyber-security training

3.1.4 CIP 005

CIP 005 requires the establishment of an Electronic Security Perimeter (ESP), which provides:
● The disabling of ports and services that are not required
● Permanent monitoring and access to logs (24x7x365)
● Vulnerability Assessments (yearly at a minimum)
● Documentation of Network Changes

Power utility responsibilities: General Electric's contribution:

To monitor access to the ESP
To disable all ports not used in the IED
To perform the vulnerability assessments
To monitor and record all access to the IED
To document network changes

3.1.5 CIP 006

CIP 006 states that Physical Security controls, providing perimeter monitoring and logging along with robust
access controls, must be implemented and documented. All cyber assets used for Physical Security are considered
critical and should be treated as such:

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Power utility responsibilities: General Electric's contribution:

Provide physical security controls and perimeter
monitoring.
General Electric cannot provide additional help with this aspect.
Ensure that people who have access to critical cyber
assets don’t have criminal records.

3.1.6 CIP 007

CIP 007 covers the following points:
● Test procedures
● Ports and services
● Security patch management
● Antivirus
● Account management
● Monitoring
● An annual vulnerability assessment should be performed

Power utility responsibilities: General Electric's contribution:

Test procedures, we can provide advice and help on testing.
Ports and services, our devices can disable unused ports and services
To provide an incident response team and have Security patch management, we can provide assistance
appropriate processes in place Antivirus, we can provide advise and assistance
Account management, we can provide advice and assistance
Monitoring, our equipment monitors and logs access

3.1.7 CIP 008

CIP 008 requires that an incident response plan be developed, including the definition of an incident response
team, their responsibilities and associated procedures.

Power utility responsibilities: General Electric's contribution:

To provide an incident response team and have
General Electric cannot provide additional help with this aspect.
appropriate processes in place.

3.1.8 CIP 009

CIP 009 states that a disaster recovery plan should be created and tested with annual drills.

Power utility responsibilities: General Electric's contribution:

To provide guidelines on recovery plans and backup/restore
To implement a recovery plan
documentation

3.2 IEEE 1686-2007

IEEE 1686-2007 is an IEEE Standard for substation IEDs' cyber-security capabilities. It proposes practical and
achievable mechanisms to achieve secure operations.
The following features described in this standard apply:
● Passwords are 8 characters long and can contain upper-case, lower-case, numeric and special characters.
● Passwords are never displayed or transmitted to a user.

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● IED functions and features are assigned to different password levels. The assignment is fixed.
● The audit trail is recorded, listing events in the order in which they occur, held in a circular buffer.
● Records contain all defined fields from the standard and record all defined function event types where the
function is supported.
● No password defeat mechanism exists. Instead a secure recovery password scheme is implemented.
● Unused ports (physical and logical) may be disabled.

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4 CYBER-SECURITY IMPLEMENTATION
The General Electric IEDs have always been and will continue to be equipped with state-of-the-art security
measures. Due to the ever-evolving communication technology and new threats to security, this requirement is
not static. Hardware and software security measures are continuously being developed and implemented to
mitigate the associated threats and risks.
This section describes the current implementation of cyber-security. This is valid for the release of platform
software to which this manual pertains. This current cyber-security implementation is known as Cyber-security
Phase 1.
At the IED level, these cyber-security measures have been implemented:
● NERC-compliant default display
● Four-level access
● Enhanced password security
● Password recovery procedure
● Disabling of unused physical and logical ports
● Inactivity timer
● Security events management

External to the IEDs, the following cyber-security measures have been implemented:
● Antivirus
● Security patch management

4.1 NERC-COMPLIANT DISPLAY

For the device to be NERC-compliant, it must provide the option for a NERC-compliant default display. The default
display that is implemented in our cyber-security concept contains a warning that the IED can be accessed by
authorised users. You can change this if required with the User Banner setting in the SECURITY CONFIG column.

ACCESS ONLY FOR

AUTHORISED USERS
HOTKEY

If you try to change the default display from the NERC-compliant one, a further warning is displayed:

DISPLAY NOT NERC

COMPLIANT OK?

The default display navigation map shows how NERC-compliance is achieved with the product's default display
concept.

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NERC compliant
banner

NERC Compliance NERC Compliance

Warning Warning

System Current
Access Level
Measurements

System Voltage
System Frequency
Measurements

System Power
Plant Reference
Measurements

Description Date & Time

V00403

Figure 306: Default display navigation

4.2 FOUR-LEVEL ACCESS

The menu structure contains four levels of access, three of which are password protected.

Password levels
Level Meaning Read Operation Write Operation
SYSTEM DATA column:
Description
Plant Reference
Model Number
Serial Number
S/W Ref.
Access Level Password Entry
Read Some
0 Security Feature LCD Contrast (UI only)
Write Minimal
SECURITY CONFIG column:
User Banner
Attempts Remain
Blk Time Remain
Fallback PW level
Security Code (UI only)
All items writeable at level 0.
Level 1 Password setting
Read All All data and settings are readable.
1 Extract Disturbance Record
Write Few Poll Measurements
Select Event, Main and Fault (upload)
Extract Events (e.g. via MiCOM S1 Studio)

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Level Meaning Read Operation Write Operation

All items writeable at level 1.
Setting Cells that change visibility (Visible/Invisible).
Setting Values (Primary/Secondary) selector
Commands:
Read All All data and settings are readable.
2 Reset Indication
Write Some Poll Measurements
Reset Demand
Reset Statistics
Reset CB Data / counters
Level 2 Password setting
All items writeable at level 2.
Change all Setting cells
Operations:
Extract and download Setting file.
Extract and download PSL
Extract and download MCL61850 (IEC61850 CONFIG)
Auto-extraction of Disturbance Recorder
Courier/Modbus Accept Event (auto event extraction, e.g. via
Read All All data and settings are readable.
3 A2R)
Write All Poll Measurements
Commands:
Change Active Group setting
Close / Open CB
Change Comms device address.
Set Date & Time
Switch MCL banks / Switch Conf. Bank in UI (IEC61850 CONFIG)
Enable / Disable Device ports (in SECURITY CONFIG column)
Level 3 password setting

4.2.1 BLANK PASSWORDS

A blank password is effectively a zero-length password. Through the front panel it is entered by confirming the
password entry without actually entering any password characters. Through a communications port the Courier
and Modbus protocols each have a means of writing a blank password to the IED. A blank password disables the
need for a password at the level that this password is applied.
Blank passwords have a slightly different validation procedure. If a blank password is entered through the front
panel, the following text is displayed, after which the procedure is the same as already described:

BLANK PASSWORD
ENTERED CONFIRM

Blank passwords cannot be configured if the lower level password is not blank.
Blank passwords affect the fall back level after inactivity timeout or logout.
The ‘fallback level’ is the password level adopted by the IED after an inactivity timeout, or after the user logs out.
This will be either the level of the highest-level password that is blank, or level 0 if no passwords are blank.

4.2.2 PASSWORD RULES

● Default passwords are blank for Level 1 and are AAAA for Levels 2 and 3
● Passwords may be any length between 0 and 8 characters long

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● Passwords may or may not be NERC compliant

● Passwords may contain any ASCII character in the range ASCII code 33 (21 Hex) to ASCII code 122 (7A Hex)
inclusive
● Only one password is required for all the IED interfaces

4.2.3 ACCESS LEVEL DDBS

The 'Access level' cell is in the 'System data' column (address 00D0). Also the current level of access for each
interface is available for use in the Programming Scheme Logic (PSL) by mapping to these Digital Data Bus (DDB)
signals:
● HMI Access Lvl 1
● HMI Access Lvl 2
● FPort AccessLvl1
● FPort AccessLvl2
● RPrt1 AccessLvl1
● RPrt1 AccessLvl2
● RPrt2 AccessLvl1
● RPrt2 AccessLvl2

Each pair of DDB signals indicates the access level as follows:

● Level 1 off, Level 2 off = 0
● Level 1 on, Level 2 off = 1
● Level 1 off, Level 2 on = 2
● Level 1 on, Level 2 on = 3

Key:
HMI = Human Machine Interface
FPort = Front Port
RPrt = Rear Port
Lvl = Level

4.3 ENHANCED PASSWORD SECURITY

Cyber-security requires strong passwords and validation for NERC compliance.

4.3.1 PASSWORD STRENGTHENING

NERC compliant passwords have the following requirements:
● At least one upper-case alpha character
● At least one lower-case alpha character
● At least one numeric character
● At least one special character (%,$...)
● At least six characters long

4.3.2 PASSWORD VALIDATION

The IED checks for NERC compliance. If the password is entered through the front panel, this is briefly displayed on
the LCD.

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If the entered password is NERC compliant, the following text is displayed.

NERC COMPLIANT
P/WORD WAS SAVED

If the password entered is not NERC-compliant, the user is required to actively confirm this, in which case the non-
compliance is logged.
If the entered password is not NERC compliant, the following text is displayed:

NERC COMPLIANCE
NOT MET CONFIRM?

On confirmation, the non-compliant password is stored and the following acknowledgement message is displayed
for 2 seconds.

NON-NERC P/WORD
SAVED OK

If the action is cancelled, the password is rejected and the following message is displayed for 2 seconds.

NON-NERC P/WORD
NOT SAVE

If the password is entered through a communications port using Courier or Modbus protocols, the device will store
the password, irrespective of whether it is NERC-compliant or not. It then uses appropriate response codes to
inform the client of the NERC-compliancy status. You can then choose to enter a new NERC-compliant password
or accept the non-NERC compliant password just entered.

4.3.3 PASSWORD BLOCKING

You are locked out temporarily, after a defined number of failed password entry attempts. Each invalid password
entry attempt decrements the 'Attempts Remain' data cell by 1. When the maximum number of attempts has been
reached, access is blocked. If the attempts timer expires, or the correct password is entered before the 'attempt
count' reaches the maximum number, then the 'attempts count' is reset to 0.
An attempt is only counted if the attempted password uses only characters in the valid range, but the attempted
password is not correct (does not match the corresponding password in the IED). Any attempt where one or more
characters of the attempted password are not in the valid range will not be counted.
Once the password entry is blocked, a 'blocking timer' is started. Attempts to access the interface while the
'blocking timer' is running results in an error message, irrespective of whether the correct password is entered or
not. Once the 'blocking timer' has expired, access to the interface is unblocked and the attempts counter is reset to
zero.
If you try to enter the password while the interface is blocked, the following message is displayed for 2 seconds.

NOT ACCEPTED
ENTRY IS BLOCKED

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A similar response occurs if you try to enter the password through a communications port.
The parameters can then be configured using the Attempts Limit, Attempts Timer and Blocking Timer settings in
the SECURITY CONFIG column.

Password blocking configuration

Cell
Setting Units Default Setting Available Setting
col row
Attempts Limit 25 02 3 0 to 3 step 1
Attempts Timer 25 03 Minutes 2 1 to 3 step 1
Blocking Timer 25 04 Minutes 5 1 to 30 step 1

4.4 PASSWORD RECOVERY

If you mislay a device's password, they can be recovered. To obtain the recovery password you must contact the
Contact Centre and supply the Serial Number and its Security Code. The Contact Centre will use these items to
generate a Recovery Password.
The security code is a 16-character string of upper case characters. It is a read-only parameter. The device
generates its own security code randomly. A new code is generated under the following conditions:
● On power up
● Whenever settings are set back to default
● On expiry of validity timer (see below)
● When the recovery password is entered

As soon as the security code is displayed on the LCD, a validity timer is started. This validity timer is set to 72 hours
and is not configurable. This provides enough time for the contact centre to manually generate and send a
recovery password. The Service Level Agreement (SLA) for recovery password generation is one working day, so 72
hours is sufficient time, even allowing for closure of the contact centre over weekends and bank holidays.
To prevent accidental reading of the IED security code, the cell will initially display a warning message:

PRESS ENTER TO
READ SEC. CODE

The security code is displayed on confirmation. The validity timer is then started. The security code can only be
read from the front panel.

4.4.1 PASSWORD RECOVERY

The recovery password is intended for recovery only. It is not a replacement password that can be used
continually. It can only be used once – for password recovery.
Entry of the recovery password causes the IED to reset all passwords back to default. This is all it is designed to do.
After the passwords have been set back to default, it is up to the user to enter new passwords. Each password
should be appropriate for its intended function, ensuring NERC compliance, if required.
On this action, the following message is displayed:

PASSWORDS HAVE
BEEN SET TO
DEFAULT

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The recovery password can be applied through any interface, local or remote. It will achieve the same result
irrespective of which interface it is applied through.

4.4.2 PASSWORD ENCRYPTION

The IED supports encryption for passwords entered remotely. The encryption key can be read from the IED through
a specific cell available only through communication interfaces, not the front panel. Each time the key is read the
IED generates a new key that is valid only for the next password encryption write. Once used, the key is invalidated
and a new key must be read for the next encrypted password write. The encryption mechanism is otherwise
transparent to the user.

4.5 DISABLING PHYSICAL PORTS

It is possible to disable unused physical ports. A level 3 password is needed to perform this action.
To prevent accidental disabling of a port, a warning message is displayed according to whichever port is required
to be disabled. For example if rear port 1 is to be disabled, the following message appears:

REAR PORT 1 TO BE
DISABLED.CONFIRM

The following ports can be disabled, depending on the model.

● Front port (Front Port setting)
● Rear port 1 (Rear Port 1 setting)
● Rear port 2 (Rear Port 2 setting)
● Ethernet port (Ethernet setting)

Note:
It is not possible to disable a port from which the disabling port command originates.

Note:
We do not generally advise disabling the physical Ethernet port.

4.6 DISABLING LOGICAL PORTS

It is possible to disable unused logical ports. A level 3 password is needed to perform this action.

Note:
The port disabling setting cells are not provided in the settings file. It is only possible to do this using the HMI front panel.

The following protocols can be disabled:

● IEC 61850 (IEC61850 setting)
● DNP3 Over Ethernet (DNP3 OE setting)
● Courier Tunnelling (Courier Tunnel setting)

Note:
If any of these protocols are enabled or disabled, the Ethernet card will reboot.

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4.7 SECURITY EVENTS MANAGEMENT

To implement NERC-compliant cyber-security, a range of Event records need to be generated. These log security
issues such as the entry of a non-NERC-compliant password, or the selection of a non-NERC-compliant default
display.

Security event values

Event Value Display
USER LOGGED IN
PASSWORD LEVEL UNLOCKED
ON {int} LEVEL {n}
USER LOGGED OUT
PASSWORD LEVEL RESET
ON {int} LEVEL {n}
P/WORD SET BLANK
PASSWORD SET BLANK
BY {int} LEVEL {p}
P/WORD NOT-NERC
PASSWORD SET NON-COMPLIANT
BY {int} LEVEL {p}
PASSWORD CHANGED
PASSWORD MODIFIED
BY {int} LEVEL {p}
PASSWORD BLOCKED
PASSWORD ENTRY BLOCKED
ON {int}
P/WORD UNBLOCKED
PASSWORD ENTRY UNBLOCKED
ON {int}
INV P/W ENTERED
INVALID PASSWORD ENTERED
ON <int}
P/WORD EXPIRED
PASSWORD EXPIRED
ON {int}
P/W ENT WHEN BLK
PASSWORD ENTERED WHILE BLOCKED
ON {int}
RCVY P/W ENTERED
RECOVERY PASSWORD ENTERED
ON {int}
IED SEC CODE RD
IED SECURITY CODE READ
ON {int}
IED SEC CODE EXP
IED SECURITY CODE TIMER EXPIRED
-
PORT DISABLED
PORT DISABLED
BY {int} PORT {prt}
PORT ENABLED
PORT ENABLED
BY {int} PORT {prt}
DEF. DISPLAY NOT NERC COMPLIANT DEF DSP NOT-NERC
PSL STNG D/LOAD
PSL SETTINGS DOWNLOADED
BY {int} GROUP {grp}
DNP STNG D/LOAD
DNP SETTINGS DOWNLOADED
BY {int}
TRACE DAT D/LOAD
TRACE DATA DOWNLOADED
BY {int}
IED CONFG D/LOAD
IEC61850 CONFIG DOWNLOADED
BY {int}
USER CRV D/LOAD
USER CURVES DOWNLOADED
BY {int} GROUP {crv}

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Event Value Display

PSL CONFG D/LOAD
PSL CONFIG DOWNLOADED
BY {int} GROUP {grp}
SETTINGS D/LOAD
SETTINGS DOWNLOADED
BY {int} GROUP {grp}
PSL STNG UPLOAD
PSL SETTINGS UPLOADED
BY {int} GROUP {grp}
DNP STNG UPLOAD
DNP SETTINGS UPLOADED
BY {int}
TRACE DAT UPLOAD
TRACE DATA UPLOADED
BY {int}
IED CONFG UPLOAD
IEC61850 CONFIG UPLOADED
BY {int}
USER CRV UPLOAD
USER CURVES UPLOADED
BY {int} GROUP {crv}
PSL CONFG UPLOAD
PSL CONFIG UPLOADED
BY {int} GROUP {grp}
SETTINGS UPLOAD
SETTINGS UPLOADED
BY {int} GROUP {grp}
EVENTS EXTRACTED
EVENTS HAVE BEEN EXTRACTED
BY {int} {nov} EVNTS
ACTIVE GRP CHNGE
ACTIVE GROUP CHANGED
BY {int} GROUP {grp}
C & S CHANGED
CS SETTINGS CHANGED
BY {int}
DR CHANGED
DR SETTINGS CHANGED
BY {int}
SETTINGS CHANGED
SETTING GROUP CHANGED
BY {int} GROUP {grp}
POWER ON
POWER ON
-
S/W DOWNLOADED
SOFTWARE_DOWNLOADED
-

where:
● int is the interface definition (UI, FP, RP1, RP2, TNL, TCP)
● prt is the port ID (FP, RP1, RP2, TNL, DNP3, IEC, ETHR)
● grp is the group number (1, 2, 3, 4)
● crv is the Curve group number (1, 2, 3, 4)
● n is the new access level (0, 1, 2, 3)
● p is the password level (1, 2, 3)
● nov is the number of events (1 – nnn)

Each new event has an incremented unique number, therefore missing events appear as ‘gap’ in the sequence.
The unique identifier forms part of the event record that is read or uploaded from the IED.

Note:
It is no longer possible to clear Event, Fault, Maintenance, and Disturbance Records.

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4.8 LOGGING OUT

If you have been configuring the IED, you should 'log out'. Do this by going up to the top of the menu tree. When
you are at the Column Heading level and you press the Up button, you may be prompted to log out with the
following display:

DO YOU WANT TO
LOG OUT?

You will only be asked this question if your password level is higher than the fallback level.
If you confirm, the following message is displayed for 2 seconds:

LOGGED OUT
Access Level #

Where # is the current fallback level.

If you decide not to log out, the following message is displayed for 2 seconds.

LOGOUT CANCELLED
Access Level #

where # is the current access level.

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INSTALLATION
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1 CHAPTER OVERVIEW
This chapter provides information about installing the product.
This chapter contains the following sections:
Chapter Overview 621
Handling the Goods 622
Mounting the Device 623
Cables and Connectors 626
Case Dimensions 630

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2 HANDLING THE GOODS

Our products are of robust construction but require careful treatment before installation on site. This section
discusses the requirements for receiving and unpacking the goods, as well as associated considerations regarding
product care and personal safety.

Caution:
Before lifting or moving the equipment you should be familiar with the Safety
Information chapter of this manual.

2.1 RECEIPT OF THE GOODS

On receipt, ensure the correct product has been delivered. Unpack the product immediately to ensure there has
been no external damage in transit. If the product has been damaged, make a claim to the transport contractor
and notify us promptly.
For products not intended for immediate installation, repack them in their original delivery packaging.

2.2 UNPACKING THE GOODS

When unpacking and installing the product, take care not to damage any of the parts and make sure that
additional components are not accidentally left in the packing or lost. Do not discard any CDROMs or technical
documentation. These should accompany the unit to its destination substation and put in a dedicated place.
The site should be well lit to aid inspection, clean, dry and reasonably free from dust and excessive vibration. This
particularly applies where installation is being carried out at the same time as construction work.

2.3 STORING THE GOODS

If the unit is not installed immediately, store it in a place free from dust and moisture in its original packaging. Keep
any de-humidifier bags included in the packing. The de-humidifier crystals lose their efficiency if the bag is
exposed to ambient conditions. Restore the crystals before replacing it in the carton. Ideally regeneration should
be carried out in a ventilating, circulating oven at about 115°C. Bags should be placed on flat racks and spaced to
allow circulation around them. The time taken for regeneration will depend on the size of the bag. If a ventilating,
circulating oven is not available, when using an ordinary oven, open the door on a regular basis to let out the
steam given off by the regenerating silica gel.
On subsequent unpacking, make sure that any dust on the carton does not fall inside. Avoid storing in locations of
high humidity. In locations of high humidity the packaging may become impregnated with moisture and the de-
humidifier crystals will lose their efficiency.
The device can be stored between –25º to +70ºC for unlimited periods or between -40°C to + 85°C for up to 96
hours (see technical specifications).

2.4 DISMANTLING THE GOODS

If you need to dismantle the device, always observe standard ESD (Electrostatic Discharge) precautions. The
minimum precautions to be followed are as follows:
● Use an antistatic wrist band earthed to a suitable earthing point.
● Avoid touching the electronic components and PCBs.

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3 MOUNTING THE DEVICE

The products are dispatched either individually or as part of a panel or rack assembly.
Individual products are normally supplied with an outline diagram showing the dimensions for panel cut-outs and
hole centres.
The products are designed so the fixing holes in the mounting flanges are only accessible when the access covers
are open.
If you use a P991 or MMLG test block with the product, when viewed from the front, position the test block on the
right-hand side of the associated product. This minimises the wiring between the product and test block, and
allows the correct test block to be easily identified during commissioning and maintenance tests.
If you need to test the product for correct operation during installation, open the lower access cover, hold the
battery in place and pull the red tab to remove the battery isolation strip.

V01412

Figure 307: Location of battery isolation strip

3.1 FLUSH PANEL MOUNTING

Panel-mounted devices are flush mounted into panels using M4 SEMS Taptite self-tapping screws with captive
3 mm thick washers (also known as a SEMS unit).

Caution:
Do not use conventional self-tapping screws, because they have larger heads and could
damage the faceplate.

Alternatively, you can use tapped holes if the panel has a minimum thickness of 2.5 mm.
For applications where the product needs to be semi-projection or projection mounted, a range of collars are
available.
If several products are mounted in a single cut-out in the panel, mechanically group them horizontally or vertically
into rigid assemblies before mounting in the panel.

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Caution:
Do not fasten products with pop rivets because this makes them difficult to remove if
repair becomes necessary.

3.2 RACK MOUNTING

Panel-mounted variants can also be rack mounted using single-tier rack frames (our part number FX0021 101), as
shown in the figure below. These frames are designed with dimensions in accordance with IEC 60297 and are
supplied pre-assembled ready to use. On a standard 483 mm (19 inch) rack this enables combinations of case
widths up to a total equivalent of size 80TE to be mounted side by side.
The two horizontal rails of the rack frame have holes drilled at approximately 26 mm intervals. Attach the products
by their mounting flanges using M4 Taptite self-tapping screws with captive 3 mm thick washers (also known as a
SEMS unit).

Caution:
Risk of damage to the front cover molding. Do not use conventional self-tapping
screws, including those supplied for mounting MiDOS products because they have
slightly larger heads.

Once the tier is complete, the frames are fastened into the racks using mounting angles at each end of the tier.

Figure 308: Rack mounting of products

Products can be mechanically grouped into single tier (4U) or multi-tier arrangements using the rack frame. This
enables schemes using products from different product ranges to be pre-wired together before mounting.
Use blanking plates to fill any empty spaces. The spaces may be used for installing future products or because the
total size is less than 80TE on any tier. Blanking plates can also be used to mount ancillary components. The part
numbers are as follows:

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Case size summation Blanking plate part number

5TE GJ2028 101

10TE GJ2028 102

15TE GJ2028 103

20TE GJ2028 104

25TE GJ2028 105

30TE GJ2028 106

35TE GJ2028 107

40TE GJ2028 108

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4 CABLES AND CONNECTORS

This section describes the type of wiring and connections that should be used when installing the device. For pin-
out details please refer to the Hardware Design chapter or the wiring diagrams.

Caution:
Before carrying out any work on the equipment you should be familiar with the Safety
Section and the ratings on the equipment’s rating label.

4.1 TERMINAL BLOCKS

The device may use one or more of the terminal block types shown in the following diagram. The terminal blocks
are fastened to the rear panel with screws.
● Heavy duty (HD) terminal blocks for CT and VT circuits
● Medium duty (MD) terminal blocks for the power supply, relay outputs and rear communications port
● MiDOS terminal blocks for CT and VT circuits
● RTD/CLIO terminal block for connection to analogue transducers

Figure 309: Terminal block types

MiCOM products are supplied with sufficient M4 screws for making connections to the rear mounted terminal
blocks using ring terminals, with a recommended maximum of two ring terminals per terminal.
If required, M4 90° crimp ring terminals can be supplied in three different sizes depending on wire size. Each type is
available in bags of 100.
Part number Wire size Insulation color
ZB9124 901 0.25 - 1.65 mm2 (22 – 16 AWG) Red
ZB9124 900 1.04 - 2.63 mm2 (16 – 14 AWG) Blue

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4.2 POWER SUPPLY CONNECTIONS

These should be wired with 1.5 mm PVC insulated multi-stranded copper wire terminated with M4 ring terminals.
The wire should have a minimum voltage rating of 300 V RMS.

Caution:
Protect the auxiliary power supply wiring with a maximum 16 A high rupture capacity
(HRC) type NIT or TIA fuse.

4.3 EARTH CONNNECTION

Every device must be connected to the cubicle earthing bar using the M4 earth terminal.

Use a wire size of at least 2.5 mm2 terminated with a ring terminal.

Due to the physical limitations of the ring terminal, the maximum wire size you can use is 6.0 mm2 using ring
terminals that are not pre-insulated. If using pre insulated ring terminals, the maximum wire size is reduced to 2.63
mm2 per ring terminal. If you need a greater cross-sectional area, use two wires in parallel, each terminated in a
separate ring terminal.
The wire should have a minimum voltage rating of 300 V RMS.

Note:
To prevent any possibility of electrolytic action between brass or copper ground conductors and the rear panel of the product,
precautions should be taken to isolate them from one another. This could be achieved in several ways, including placing a
nickel-plated or insulating washer between the conductor and the product case, or using tinned ring terminals.

4.4 CURRENT TRANSFORMERS

Current transformers would generally be wired with 2.5 mm2 PVC insulated multi-stranded copper wire terminated
with M4 ring terminals.

Due to the physical limitations of the ring terminal, the maximum wire size you can use is 6.0 mm2 using ring
terminals that are not pre-insulated. If using pre insulated ring terminals, the maximum wire size is reduced to 2.63
mm2 per ring terminal. If you need a greater cross-sectional area, use two wires in parallel, each terminated in a
separate ring terminal.
The wire should have a minimum voltage rating of 300 V RMS.

Caution:
Current transformer circuits must never be fused.

Note:
If there are CTs present, spring-loaded shorting contacts ensure that the terminals into which the CTs connect are shorted
before the CT contacts are broken.

Note:
For 5A CT secondaries, we recommend using 2 x 2.5 mm2 PVC insulated multi-stranded copper wire.

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4.5 VOLTAGE TRANSFORMER CONNECTIONS

Voltage transformers should be wired with 2.5 mm2 PVC insulated multi-stranded copper wire terminated with M4
ring terminals.
The wire should have a minimum voltage rating of 300 V RMS.

4.6 WATCHDOG CONNECTIONS

These should be wired with 1 mm PVC insulated multi-stranded copper wire terminated with M4 ring terminals.
The wire should have a minimum voltage rating of 300 V RMS.

4.7 EIA(RS)485 AND K-BUS CONNECTIONS

For connecting the EIA(RS485) / K-Bus ports, use 2-core screened cable with a maximum total length of 1000 m or
200 nF total cable capacitance.
To guarantee the performance specifications, you must ensure continuity of the screen, when daisy chaining the
connections.
Two-core screened twisted pair cable should be used. It is important to avoid circulating currents, which can cause
noise and interference, especially when the cable runs between buildings. For this reason, the screen should be
continuous and connected to ground at one end only, normally at the master connection point.
The K-Bus signal is a differential signal and there is no signal ground connection. If a signal ground connection is
present in the bus cable then it must be ignored. At no stage should this be connected to the cable's screen or to
the product’s chassis. This is for both safety and noise reasons.
A typical cable specification would be:
● Each core: 16/0.2 mm2 copper conductors, PVC insulated
● Nominal conductor area: 0.5 mm2 per core
● Screen: Overall braid, PVC sheathed

4.8 IRIG-B CONNECTION

The IRIG-B input and BNC connector have a characteristic impedance of 50 ohms. We recommend that
connections between the IRIG-B equipment and the product are made using coaxial cable of type RG59LSF with a
halogen free, fire retardant sheath.

4.9 OPTO-INPUT CONNECTIONS

These should be wired with 1 mm2 PVC insulated multi-stranded copper wire terminated with M4 ring terminals.
Each opto-input has a selectable preset ½ cycle filter. This makes the input immune to noise induced on the wiring.
This can, however slow down the response. If you need to switch off the ½ cycle filter, either use double pole
switching on the input, or screened twisted cable on the input circuit.

Caution:
Protect the opto-inputs and their wiring with a maximum 16 A high rupture capacity
(HRC) type NIT or TIA fuse.

4.10 OUTPUT RELAY CONNECTIONS

These should be wired with 1 mm PVC insulated multi-stranded copper wire terminated with M4 ring terminals.

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4.11 ETHERNET METALLIC CONNECTIONS

If the device has a metallic Ethernet connection, it can be connected to either a 10Base-T or a 100Base-TX
Ethernet hub. Due to noise sensitivity, we recommend this type of connection only for short distance connections,
ideally where the products and hubs are in the same cubicle. For increased noise immunity, CAT 6 (category 6) STP
(shielded twisted pair) cable and connectors can be used.
The connector for the Ethernet port is a shielded RJ-45. The pin-out is as follows:
Pin Signal name Signal definition
1 TXP Transmit (positive)
2 TXN Transmit (negative)
3 RXP Receive (positive)
4 - Not used
5 - Not used
6 RXN Receive (negative)
7 - Not used
8 - Not used

4.12 ETHERNET FIBRE CONNECTIONS

We recommend the use of fibre-optic connections for permanent connections in a substation environment. The
100 Mbps fibre optic port uses type ST connectors (one for Tx and one for Rx), compatible with 50/125 µm or
62.5/125 µm multimode fibres at 1300 nm wavelength.

Note:
For models equipped with redundant Ethernet connections the product must be partially dismantled to set the fourth octet of
the second IP address. This ideally, should be done before installation.

4.13 RS232 CONNECTION

Short term connections to the EIA(RS)232 port, located behind the bottom access cover, can be made using a
screened multi-core communication cable up to 15 m long, or a total capacitance of 2500 pF. The cable should be
terminated at the product end with a standard 9-pin D-type male connector.

4.14 DOWNLOAD/MONITOR PORT

Short term connections to the download/monitor port, located behind the bottom access cover, can be made
using a screened 25-core communication cable up to 4 m long. The cable should be terminated at the product end
with a 25-pin D-type male connector.

4.15 GPS FIBRE CONNECTION

Some products use a GPS 1 PPS timing signal. If applicable, this is connected to a fibre-optic port on the
coprocessor board in slot B. The fibre-optic port uses an ST type connector, compatible with fibre multimode
50/125 µm or 62.5/125 µm – 850 nm.

4.16 FIBRE COMMUNICATION CONNECTIONS

The fibre optic port consists of one or two channels using ST type connectors (one for Tx and one for Rx). The type
of fibre used depends on the option selected.
850 nm and 1300 nm multimode systems use 50/125 µm or 62.5/125 µm multimode fibres. 1300 nm and 1550 nm
single mode systems use 9/125 µm single mode fibres.

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5 CASE DIMENSIONS
Not all products are available in all case sizes.

5.1 CASE DIMENSIONS 40TE

Sealing
155.40 8 off holes Dia. 3.4 strip
23.30

AB BA

168.00 177.0
159.00 (4U)

AB BA

10.35 181.30 483 (19” rack)

202.00

A = Clearance holes Flush mouting panel

Panel cut-out details
B = Mouting holes

200.00
Note: If mouting plate is required
use flush mounting cut out
dimentions

All dimensons in mm

Secondary cover (when fitted)

240.00
Front view Incl. wiring
177.00

157.5
max.

Side view
206.00 30.00

E01411

Figure 310: 40TE case dimensions

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5.2 CASE DIMENSIONS 60TE

E01409

Figure 311: 60TE case dimensions

P54x1i-TM-EN-1 631
 74.95 116.55 142.45 12 OFF HOLES 3.40

632
5.3

E01410
FLUSH MOUNTING PANEL
CUT-OUT DETAIL

159.00 168.00
Chapter 24 - Installation

62.00 155.40 129.50

4.50

Figure 312: 80TE case dimensions

408.90

407.10
CASE DIMENSIONS 80TE

MOUNTING SCREW : M4 X 12 SEM UNIT STEEL THREAD

FORMING SCREW.

TERMINAL SCREWS : M4 X 7 BRASS CHEESE HEAD SCREWS WITH

222.00 LOCK WASHERS PROVIDED.

SECONDARY COVER
(WHEN FITTED)

240.00 INCL. WIRING

177.00 157.50 MAX

413.2
30.00
FRONT VIEW SIDE VIEW

P54x1i-TM-EN-1
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 CHAPTER 25

COMMISSIONING INSTRUCTIONS
Chapter 25 - Commissioning Instructions P543i/P545i

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1 CHAPTER OVERVIEW
This chapter contains the following sections:
Chapter Overview 635
General Guidelines 636
Commissioning Test Menu 637
Commissioning Equipment 641
Product Checks 643
Electrical Intermicom Communication Loopback 652
Intermicom 64 Communication 654
GPS Synchronisation 656
Setting Checks 657
IEC 61850 Edition 2 Testing 659
Current Differential Protection 664
Distance Protection 667
Delta Directional Comparison 674
DEF Aided Schemes 677
Out of Step Protection 680
Protection Timing Checks 682
System Check and Check Synchronism 684
Check Trip and Autoreclose Cycle 685
End-to-End Communication Tests 686
End-to-End Scheme Tests 689
Onload Checks 691
Final Checks 693
Commmissioning the P59x 694

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2 GENERAL GUIDELINES
General Electric IEDs are self-checking devices and will raise an alarm in the unlikely event of a failure. This is why
the commissioning tests are less extensive than those for non-numeric electronic devices or electro-mechanical
relays.
To commission the devices, you (the commissioning engineer) do not need to test every function. You need only
verify that the hardware is functioning correctly and that the application-specific software settings have been
applied. You can check the settings by extracting them using the settings application software, or by means of the
front panel interface (HMI panel).
The menu language is user-selectable, so you can change it for commissioning purposes if required.

Note:
Remember to restore the language setting to the customer’s preferred language on completion.

Caution:
Before carrying out any work on the equipment you should be familiar with the
contents of the Safety Section or Safety Guide SFTY/4LM as well as the ratings on the
equipment’s rating label.

Warning:
With the exception of the CT shorting contacts check, do not disassemble the device
during commissioning.

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3 COMMISSIONING TEST MENU

The IED provides several test facilities under the COMMISSION TESTS menu heading. There are menu cells that
allow you to monitor the status of the opto-inputs, output relay contacts, internal Digital Data Bus (DDB) signals
and user-programmable LEDs. This section describes these commissioning test facilities.

3.1 OPTO I/P STATUS CELL (OPTO-INPUT STATUS)

This cell can be used to monitor the status of the opto-inputs while they are sequentially energised with a suitable
DC voltage. The cell is a binary string that displays the status of the opto-inputs where '1' means energised and '0'
means de-energised. If you move the cursor along the binary numbers, the corresponding label text is displayed
for each logic input.

3.2 RELAY O/P STATUS CELL (RELAY OUTPUT STATUS)

This cell can be used to monitor the status of the relay outputs. The cell is a binary string that displays the status of
the relay outputs where '1' means energised and '0' means de-energised. If you move the cursor along the binary
numbers, the corresponding label text is displayed for each relay output.
The cell indicates the status of the output relays when the IED is in service. You can check for relay damage by
comparing the status of the output contacts with their associated bits.

Note:
When the Test Mode cell is set to Contacts Blocked, the relay output status indicates which contacts would operate if
the IED was in-service. It does not show the actual status of the output relays, as they are blocked.

3.3 TEST PORT STATUS CELL

This cell displays the status of the DDB signals that have been allocated in the Monitor Bit cells. If you move the
cursor along the binary numbers, the corresponding DDB signal text string is displayed for each monitor bit.
By using this cell with suitable monitor bit settings, the state of the DDB signals can be displayed as various
operating conditions or sequences are applied to the IED. This allows you to test the Programmable Scheme Logic
(PSL).

3.4 MONITOR BIT 1 TO 8 CELLS

The eight Monitor Bit cells allows you to select eight DDB signals that can be observed in the Test Port Status cell or
downloaded via the front port.
Each Monitor Bit cell can be assigned to a particular DDB signal. You set it by entering the required DDB signal
number from the list of available DDB signals.
The pins of the monitor/download port used for monitor bits are as follows:
Monitor Bit 1 2 3 4 5 6 7 8
Monitor/Download Port Pin 11 12 15 13 20 21 23 24

The signal ground is available on pins 18, 19, 22 and 25.

Caution:
The monitor/download port is not electrically isolated against induced voltages on
the communications channel. It should therefore only be used for local
communications.

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3.5 TEST MODE CELL

This cell allows you to perform secondary injection testing. It also lets you test the output contacts directly by
applying menu-controlled test signals.
To go into test mode, select the Test Mode option in the Test Mode cell. This takes the IED out of service causing
an alarm condition to be recorded and the Out of Service LED to illuminate. This also freezes any information
stored in the CB CONDITION column. In IEC 60870-5-103 versions, it changes the Cause of Transmission (COT) to
Test Mode.
In Test Mode, the output contacts are still active. To disable the output contacts you must select the Contacts
Blocked option.
Once testing is complete, return the device back into service by setting the Test Mode Cell back to Disabled.

Caution:
When the cell is in Test Mode, the Scheme Logic still drives the output relays, which
could result in tripping of circuit breakers. To avoid this, set the Test Mode cell to
Contacts Blocked.

Note:
Test mode and Contacts Blocked mode can also be selected by energising an opto-input mapped to the Test Mode
signal, and the Contact Block signal respectively.

3.6 TEST PATTERN CELL

The Test Pattern cell is used to select the output relay contacts to be tested when the Contact Test cell is set to
Apply Test. The cell has a binary string with one bit for each user-configurable output contact, which can be
set to '1' to operate the output and '0' to not operate it.

3.7 CONTACT TEST CELL

When the Apply Test command in this cell is issued, the contacts set for operation change state. Once the test
has been applied, the command text on the LCD will change to No Operation and the contacts will remain in the
Test state until reset by issuing the Remove Test command. The command text on the LCD will show No
Operation after the Remove Test command has been issued.

Note:
When the Test Mode cell is set to Contacts Blocked the Relay O/P Status cell does not show the current status of the
output relays and therefore cannot be used to confirm operation of the output relays. Therefore it will be necessary to monitor
the state of each contact in turn.

3.8 TEST LEDS CELL

When the Apply Test command in this cell is issued, the user-programmable LEDs illuminate for approximately
2 seconds before switching off, and the command text on the LCD reverts to No Operation.

3.9 TEST AUTORECLOSE CELL

Where the IED provides an auto-reclose function, this cell will be available for testing the sequence of circuit
breaker trip and auto-reclose cycles.
The Trip 3 Pole option in the Test Autoreclose cell causes the device to perform the first three phase trip/
reclose cycle so that associated output contacts can be checked for operation at the correct times during the

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cycle. Once the trip output has operated the command text will revert to No Operation whilst the rest of the
auto-reclose cycle is performed. To test subsequent three-phase autoreclose cycles, you repeat the Trip 3
Pole command. You can also test the single phases with Trip Pole A , Trip Pole B and Trip Pole B.

Note:
The default settings for the programmable scheme logic has the AR Trip Test signals mapped to the Trip Input
signals. If the programmable scheme logic has been changed, it is essential that these signals retain this mapping for the
Test Autoreclose facility to work.

3.10 STATIC TEST MODE

Static Test Mode can be set to Enabled or Disabled. When the Static Test mode is enabled it allows injection
test that don't support dynamic switching to be used to commission and test the device.
Dynamic secondary injection test sets are able to accurately mimic real power system faults. The test sets mimic
an instantaneous fault “shot”, with the real rate of rise of current, and the decaying DC exponential component.
Dynamic injection test sets are available, which cater for all three phases, providing a six signal set of analogue
inputs: Va, Vb, Vc, Ia, Ib, Ic. Such injection test sets can be used with the device, with no special testing limitations.
Static test sets, also known as Static Simulators, may not properly provide or simulate:
● A healthy pre-fault voltage
● A real fault shot (instead a gradually varying current or voltage would be used)
● The rate of rise of current and DC components
● A complete set of three-phase analogue inputs
● Real dynamic step changes in current and voltage.
Some of the protection in this product is based on delta techniques which recognise step changes in actual power
system quantities. Because these may not be produced by static test sets,, certain functions are can be disabled or
bypassed to allow injection testing with static test sets. Enabling the Static Test Mode option does this..
For the tests, the delta directional line is replaced by a conventional distance directional line. Extra filtering of
distance comparators is used so the filtering slows to use a fixed one cycle window. Memory polarising is replaced
by cross-polarising from unfaulted phases.

Note:
Trip times may be up to ½ cycle longer when tested in the static mode, due to the nature of the test voltage and current, and
the slower filtering. This is normal, and perfectly acceptable.

3.11 LOOPBACK MODE

Loopback Mode can be used to test InterMiCOM64 signalling.

Note:
If the cell is set to Internal, only the IED software is checked. If the cell is set to External, both the software and hardware
are checked.

When the device is switched into Loopback Mode, it automatically uses generic addresses 0-0. It responds as if it is
connected to a remote device. The sent and received IM64 signals continue to be routed to and from the signals
defined in the programmable logic.

Note:
Loopback mode can also be selected by energising an opto-input mapped to the Loopback signal.

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3.12 IM64 TEST PATTERN

This cell is used with the IM64 Test Mode cell to set a 16-bit pattern (8 bits per channel), which is transmitted
whenever the IM64 Test Mode cell is set to Enabled. The IM64 TestPattern cell has a binary string with one bit for
each user-defined Inter-MiCOM command. These can be set to '1' to operate the IM64 output under test conditions
and '0' for no operation.

3.13 IM64 TEST MODE

When the Enable command in this cell is issued, the InterMiCOM64 commands change to reflect the state of the
values set in the IM64 TestPattern cell. If the cell is set to Disabled, the InterMiCOM64 commands reflect the state
of the signals generated by the protection and control functions.

3.14 RED AND GREEN LED STATUS CELLS

These cells contain binary strings that indicate which of the user-programmable red and green LEDs are
illuminated when accessing from a remote location. A '1' indicates that a particular LED is illuminated.

Note:
When the status in both Red LED Status and Green LED Status cells is ‘1’, this indicates the LEDs illumination is yellow.

3.15 USING A MONITOR PORT TEST BOX

A test box containing eight LEDs and a switchable audible indicator is available. It is housed in a small plastic box
with a 25-pin male D-connector that plugs directly into the monitor/download port. There is also a 25-pin female
D-connector which allows other connections to be made to the monitor/download port while the monitor/
download port test box is in place.
Each LED corresponds to one of the monitor bit pins on the monitor/download port. Monitor Bit 1 is on the left-
hand side when viewed from the front of the IED. The audible indicator can be selected to sound if a voltage
appears on any of the eight monitor pins. Alternatively it can be set to remain silent, using only the LEDs.

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4 COMMISSIONING EQUIPMENT
Specialist test equipment is required to commission this product. We recognise three classes of equipment for
commissioning :
● Recommended
● Essential
● Advisory

Recommended equipment constitutes equipment that is both necessary, and sufficient, to verify correct
performance of the principal protection functions.
Essential equipment represents the minimum necessary to check that the product includes the basic expected
protection functions and that they operate within limits.
Advisory equipment represents equipment that is needed to verify satisfactory operation of features that may be
unused, or supplementary, or which may, for example, be integral to a distributed control/automation scheme.
Operation of such features may, perhaps, be more appropriately verified as part of a customer defined
commissioning requirement, or as part of a system-level commissioning regime.

4.1 RECOMMENDED COMMISSIONING EQUIPMENT

The minimum recommended equipment is a multifunctional three-phase AC current and voltage injection test set
featuring :
● Controlled three-phase AC current and voltage sources,
● Transient (dynamic) switching between pre-fault and post-fault conditions (to generate delta conditions),
● Dynamic impedance state sequencer (capable of sequencing through 4 impedance states),
● Integrated or separate variable DC supply (0 - 250 V)
● Integrated or separate AC and DC measurement capabilities (0-440V AC, 0-250V DC)
● Integrated and/or separate timer,
● Integrated and/or separate test switches.

In addition, you will need :

● A portable computer, installed with appropriate software to liaise with the equipment under test (EUT).
Typically this software will be proprietary to the product’s manufacturer (for example MiCOM S1 Agile).
● Suitable electrical test leads.
● Electronic or brushless insulation tester with a DC output not exceeding 500 V
● Continuity tester
● Verified application-specific settings files
For products that use fibre-optic communications to implement unit protection schemes :
● Fibre optic test leads (minimum 2). 10m minimum length, multimode 50/125 µm or 62.5µm, OR single mode
(according to the model variant) terminated with connectors as required by the product.
● Fibre-optic power meter
● P59x commissioning instructions

4.2 ESSENTIAL COMMISSIONING EQUIPMENT

As an absolute minimum, the following equipment is required:
● AC current source coupled with AC voltage source
● Variable DC supply (0 - 250V)
● Multimeter capable of measuring AC and DC current and voltage (0-440V AC, 0-250V DC)

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● Timer
● Test switches
● Suitable electrical test leads
● Continuity tester
For products that use fibre-optic communications to implement unit protection schemes :
● Fibre optic test leads (minimum 2). 10m minimum length, multimode 50/125 µm or 62.5µm, OR single mode
(according to the model variant) terminated with connectors as required by the product.
● Fibre-optic power meter
Note that if the AC test source that you are using is not capable of dynamic fault simulation (cannot dynamically
switch from load to fault conditions) you must use the product’s static test mode feature
To do this, in COMMISSIONING TESTS, set Static Test Mode to Enabled.

4.3 ADVISORY TEST EQUIPMENT

Advisory test equipment may be required for extended commissioning procedures:
● Current clamp meter
● Multi-finger test plug:
○ P992 for test block type P991
○ MMLB for test block type MMLG blocks
● Electronic or brushless insulation tester with a DC output not exceeding 500 V
● KITZ K-Bus - EIA(RS)232 protocol converter for testing EIA(RS)485 K-Bus port
● EIA(RS)485 to EIA(RS)232 converter for testing EIA(RS)485 Courier/MODBUS/IEC60870-5-103/DNP3 port
● A portable printer (for printing a setting record from the portable PC) and or writeable, detachable memory
device.
● Phase angle meter
● Phase rotation meter
● Fibre-optic power meter.
● Fibre optic test leads (minimum 2). 10m minimum length, multimode 50/125 µm or 62.5µm terminated with
BFOC (ST) 2.5 connectors for testing the fibre-optic RP1 port.

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5 PRODUCT CHECKS
These product checks are designed to ensure that the device has not been physically damaged prior to
commissioning, is functioning correctly and that all input quantity measurements are within the stated tolerances.
If the application-specific settings have been applied to the IED prior to commissioning, you should make a copy of
the settings. This will allow you to restore them at a later date if necessary. This can be done by:
● Obtaining a setting file from the customer.
● Extracting the settings from the IED itself, using a portable PC with appropriate setting software.

If the customer has changed the password that prevents unauthorised changes to some of the settings, either the
revised password should be provided, or the original password restored before testing.

Note:
If the password has been lost, a recovery password can be obtained from General Electric.

5.1 PRODUCT CHECKS WITH THE IED DE-ENERGISED

Warning:
The following group of tests should be carried out without the auxiliary supply being
applied to the IED and, if applicable, with the trip circuit isolated.

The current and voltage transformer connections must be isolated from the IED for these checks. If a P991 test
block is provided, the required isolation can be achieved by inserting test plug type P992. This open circuits all
wiring routed through the test block.
Before inserting the test plug, you should check the scheme diagram to ensure that this will not cause damage or
a safety hazard (the test block may, for example, be associated with protection current transformer circuits). The
sockets in the test plug, which correspond to the current transformer secondary windings, must be linked before
the test plug is inserted into the test block.

Warning:
Never open-circuit the secondary circuit of a current transformer since the high
voltage produced may be lethal and could damage insulation.

If a test block is not provided, the voltage transformer supply to the IED should be isolated by means of the panel
links or connecting blocks. The line current transformers should be short-circuited and disconnected from the IED
terminals. Where means of isolating the auxiliary supply and trip circuit (for example isolation links, fuses and MCB)
are provided, these should be used. If this is not possible, the wiring to these circuits must be disconnected and the
exposed ends suitably terminated to prevent them from being a safety hazard.

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5.1.1 VISUAL INSPECTION

Warning:
Check the rating information under the top access cover on the front of the IED.

Warning:
Check that the IED being tested is correct for the line or circuit.

Warning:
Record the circuit reference and system details.

Warning:
Check the CT secondary current rating and record the CT tap which is in use.

Carefully examine the IED to see that no physical damage has occurred since installation.
Ensure that the case earthing connections (bottom left-hand corner at the rear of the IED case) are used to
connect the IED to a local earth bar using an adequate conductor.

5.1.2 CURRENT TRANSFORMER SHORTING CONTACTS

Check the current transformer shorting contacts to ensure that they close when the heavy-duty terminal block is
disconnected from the current input board.
The heavy-duty terminal blocks are fastened to the rear panel using four crosshead screws. These are located two
at the top and two at the bottom.

Note:
Use a magnetic bladed screwdriver to minimise the risk of the screws being left in the terminal block or lost.

Pull the terminal block away from the rear of the case and check with a continuity tester that all the shorting
switches being used are closed.

5.1.3 INSULATION
Insulation resistance tests are only necessary during commissioning if explicitly requested.
Isolate all wiring from the earth and test the insulation with an electronic or brushless insulation tester at a DC
voltage not exceeding 500 V. Terminals of the same circuits should be temporarily connected together.
The insulation resistance should be greater than 100 MW at 500 V.
On completion of the insulation resistance tests, ensure all external wiring is correctly reconnected to the IED.

5.1.4 EXTERNAL WIRING

Caution:
Check that the external wiring is correct according to the relevant IED and scheme
diagrams. Ensure that phasing/phase rotation appears to be as expected.

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5.1.5 WATCHDOG CONTACTS

Using a continuity tester, check that the Watchdog contacts are in the following states:
Terminals Contact state with product de-energised
11 - 12 on power supply board Closed
13 - 14 on power supply board Open

5.1.6 POWER SUPPLY

Depending on its nominal supply rating, the IED can be operated from either a DC only or an AC/DC auxiliary
supply. The incoming voltage must be within the operating range specified below.
Without energising the IED measure the auxiliary supply to ensure it is within the operating range.
Nominal supply rating Nominal supply rating
DC operating range AC operating range
DC AC RMS
24 - 54 V N/A 19 to 65 V N/A
48 - 125 V 30 - 100 V 37 to 150 V 24 - 110 V
110 - 250 V 100 - 240 V 87 to 300 V 80 to 265 V

Note:
The IED can withstand an AC ripple of up to 12% of the upper rated voltage on the DC auxiliary supply.

Warning:
Do not energise the IED or interface unit using the battery charger with the battery
disconnected as this can irreparably damage the power supply circuitry.

Caution:
Energise the IED only if the auxiliary supply is within the specified operating ranges.
If a test block is provided, it may be necessary to link across the front of the test plug
to connect the auxiliary supply to the IED.

5.2 PRODUCT CHECKS WITH THE IED ENERGISED

Warning:
The current and voltage transformer connections must remain isolated from the IED
for these checks. The trip circuit should also remain isolated to prevent accidental
operation of the associated circuit breaker.

The following group of tests verifies that the IED hardware and software is functioning correctly and should be
carried out with the supply applied to the IED.

5.2.1 WATCHDOG CONTACTS

Using a continuity tester, check that the Watchdog contacts are in the following states when energised and
healthy.
Terminals Contact state with product energised
11 - 12 on power supply board Open

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Terminals Contact state with product energised

13 - 14 on power supply board Closed

5.2.2 TEST LCD

The Liquid Crystal Display (LCD) is designed to operate in a wide range of substation ambient temperatures. For
this purpose, the IEDs have an LCD Contrast setting. The contrast is factory pre-set, but it may be necessary to
adjust the contrast to give the best in-service display.
To change the contrast, you can increment or decrement the LCD Contrast cell in the CONFIGURATION column.

Caution:
Before applying a contrast setting, make sure that it will not make the display so
light or dark such that menu text becomes unreadable. It is possible to restore the
visibility of a display by downloading a setting file, with the LCD Contrast set within
the typical range of 7 - 11.

5.2.3 DATE AND TIME

The date and time is stored in memory, which is backed up by an auxiliary battery situated at the front of the
device behind the lower access cover. When delivered, this battery is isolated to prevent battery drain during
transportation and storage.
Before setting the date and time, ensure that the isolation strip has been removed. With the lower access cover
open, the battery isolation strip can be identified by a red tab protruding from the positive side of the battery
compartment. Pull the red tab to remove the isolation strip.
The method for setting the date and time depends on whether an IRIG-B signal is being used or not. The IRIG-B
signal will override the time, day and month settings, but not the initial year setting. For this reason, you must
ensure you set the correct year, even if the device is using IRIG-B to maintain the internal clock.
You set the Date and Time by one of the following methods:
● Using the front panel to set the Date and Time cells respectively
● By sending a courier command to the Date/Time cell (Courier reference 0801)

Note:
If the auxiliary supply fails, the time and date will be maintained by the auxiliary battery. Therefore, when the auxiliary supply
is restored, you should not have to set the time and date again. To test this, remove the IRIG-B signal, and then remove the
auxiliary supply. Leave the device de-energised for approximately 30 seconds. On re energisation, the time should be correct.

When using IRIG-B to maintain the clock, the IED must first be connected to the satellite clock equipment (usually a
P594), which should be energised and functioning.
1. Set the IRIG-B Sync cell in the DATE AND TIME column to Enabled.
2. Ensure the IED is receiving the IRIG-B signal by checking that cell IRIG-B Status reads Active.
3. Once the IRIG-B signal is active, adjust the time offset of the universal co coordinated time (satellite clock
time) on the satellite clock equipment so that local time is displayed.
4. Check that the time, date and month are correct in the Date/Time cell. The IRIG-B signal does not contain
the current year so it will need to be set manually in this cell.
5. Reconnect the IRIG-B signal.

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If the time and date is not being maintained by an IRIG-B signal, ensure that the IRIG-B Sync cell in the DATE AND
TIME column is set to Disabled.
1. Set the date and time to the correct local time and date using Date/Time cell or using the serial protocol.

5.2.4 TEST LEDS

On power-up, all LEDs should first flash yellow. Following this, the green "Healthy" LED should illuminate indicating
that the device is healthy.
The IED's non-volatile memory stores the states of the alarm, the trip, and the user-programmable LED indicators
(if configured to latch). These indicators may also illuminate when the auxiliary supply is applied.
If any of these LEDs are ON then they should be reset before proceeding with further testing. If the LEDs
successfully reset (the LED goes off), no testing is needed for that LED because it is obviously operational.

5.2.5 TEST ALARM AND OUT-OF-SERVICE LEDS

The alarm and out of service LEDs can be tested using the COMMISSION TESTS menu column.
1. Set the Test Mode cell to Contacts Blocked.
2. Check that the out of service LED illuminates continuously and the alarm LED flashes.
It is not necessary to return the Test Mode cell to Disabled at this stage because the test mode will be required
for later tests.

5.2.6 TEST TRIP LED

The trip LED can be tested by initiating a manual circuit breaker trip. However, the trip LED will operate during the
setting checks performed later. Therefore no further testing of the trip LED is required at this stage.

5.2.7 TEST USER-PROGRAMMABLE LEDS

To test these LEDs, set the Test LEDs cell to Apply Test. Check that all user-programmable LEDs illuminate.

5.2.8 TEST FIELD VOLTAGE SUPPLY

The IED generates a field voltage of nominally 48 V that can be used to energise the opto-inputs (alternatively the
substation battery may be used).
1. Measure the field voltage across the terminals 7 and 9 of the power supply terminal block
2. Check that the field voltage is within the range 40 V to 60 V when no load is connected and that the polarity
is correct.
3. Repeat for terminals 8 and 10.

5.2.9 TEST OPTO-INPUTS

This test checks that all the opto-inputs on the IED are functioning correctly.
The opto-inputs should be energised one at a time. For terminal numbers, please see the external connection
diagrams in the "Wiring Diagrams" chapter. Ensuring correct polarity, connect the supply voltage to the
appropriate terminals for the input being tested.
The status of each opto-input can be viewed using either the Opto I/P Status cell in the SYSTEM DATA column, or
the Opto I/P Status cell in the COMMISSION TESTS column.
A '1' indicates an energised input and a '0' indicates a de-energised input. When each opto-input is energised, one
of the characters on the bottom line of the display changes to indicate the new state of the input.

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5.2.10 TEST OUTPUT RELAYS

This test checks that all the output relays are functioning correctly.
1. Ensure that the IED is still in test mode by viewing the Test Mode cell in the COMMISSION TESTS column.
Ensure that it is set to Contacts Blocked.
2. The output relays should be energised one at a time. To select output relay 1 for testing, set the Test Pattern
cell as appropriate.
3. Connect a continuity tester across the terminals corresponding to output relay 1 as shown in the external
connection diagram.
4. To operate the output relay set the Contact Test cell to Apply Test.
5. Check the operation with the continuity tester.
6. Measure the resistance of the contacts in the closed state.
7. Reset the output relay by setting the Contact Test cell to Remove Test.
8. Repeat the test for the remaining output relays.
9. Return the IED to service by setting the Test Mode cell in the COMMISSION TESTS menu to Disabled.

5.2.11 TEST SERIAL COMMUNICATION PORT RP1

You need only perform this test if the IED is to be accessed from a remote location with a permanent serial
connection to the communications port. The scope of this test does not extend to verifying operation with
connected equipment beyond any suppied protocol converter. It verifies operation of the rear communication port
(and if applicable the protocol converter) and varies according to the protocol fitted.

5.2.11.1 CHECK PHYSICAL CONNECTIVITY

The rear communication port RP1 is presented on terminals 16, 17 and 18 of the power supply terminal block.
Screened twisted pair cable is used to make a connection to the port. The cable screen should be connected to pin
16 and pins 17 and 18 are for the communication signal:

Figure 313: RP1 physical connection

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For K-Bus applications, pins 17 and 18 are not polarity sensitive and it does not matter which way round the wires
are connected. EIA(RS)485 is polarity sensitive, so you must ensure the wires are connected the correct way round
(pin 18 is positive, pin 17 is negative).
If K-Bus is being used, a Kitz protocol converter (KITZ101, KITZ102 OR KITZ201) will have been installed to convert
the K-Bus signals into RS232. Likewise, if RS485 is being used, an RS485-RS232 converter will have been installed.
In the case where a protocol converter is being used, a laptop PC running appropriate software (such as MiCOM S1
Agile) can be connected to the incoming side of the protocol converter. An example for K-bus to RS232 conversion
is shown below. RS485 to RS232 would follow the same principle, only using a RS485-RS232 converter. Most
modern laptops have USB ports, so it is likely you will also require a RS232 to USB converter too.

IED IED IED

RS232 K-Bus

Computer RS232-USB converter KITZ protocol converter

V01001

Figure 314: Remote communication using K-bus

Fibre Connection
Some models have an optional fibre optic communications port fitted (on a separate communications board). The
communications port to be used is selected by setting the Physical Link cell in the COMMUNICATIONS column, the
values being Copper or K-Bus for the RS485/K-bus port and Fibre Optic for the fibre optic port.

5.2.11.2 CHECK LOGICAL CONNECTIVITY

The logical connectivity depends on the chosen data protocol, but the principles of testing remain the same for all
protocol variants:
1. Ensure that the communications baud rate and parity settings in the application software are set the same
as those on the protocol converter.
2. For Courier models, ensure that you have set the correct RP1 address
3. Check that communications can be established with this IED using the portable PC/Master Station.

5.2.12 TEST SERIAL COMMUNICATION PORT RP2

RP2 is an optional second serial port board providing additional serial connectivity. It provides two 9-pin D-type
serial port connectors SK4 and SK5. Both ports are configured as DTE (Date Terminal Equipment) ports. That means
they can be connected to communications equipment such as a modem with a straight-through cable.
SK4 can be configured as an EIA(RS232), EIA(RS485), or K-Bus connection for Courier protocol only, whilst SK5 is
fixed to EIA(RS)232 for InterMiCOM signalling only.
It is not the intention of this test to verify the operation of the complete communication link between the IED and
the remote location, just the IED's rear communication port and, if applicable, the protocol converter.

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The only checks that need to be made are as follows:

1. Set the RP2 Port Config cell in the COMMUNICATIONS column to the required physical protocol; (K-Bus,
EIA(RS)485, or EIA(RS)232.
2. Set the IED's Courier address to the correct value (it must be between 1 and 254).

5.2.13 TEST ETHERNET COMMUNICATION

For products that employ Ethernet communications, we recommend that testing be limited to a visual check that
the correct ports are fitted and that there is no sign of physical damage.
If there is no board fitted or the board is faulty, a NIC link alarm will be raised (providing this option has been set in
the NIC Link Report cell in the COMMUNICATIONS column).

5.3 SECONDARY INJECTION TESTS

Secondary injection testing is carried out to verify the integrity of the VT and CT readings. All devices leave the
factory set for operation at a system frequency of 50 Hz. If operation at 60 Hz is required, you must set this in the
Frequency cell in the SYSTEM DATA column.
The PMU must be installed and connected to a 1pps fibre optic synchronising signal and a demodulated IRIG-B
signal, provided by a device such as a P594 or a REASON RT430.
Connect the current and voltage outputs of the test set to the appropriate terminals of the first voltage and current
channel and apply nominal voltage and current with the current lagging the voltage by 90 degrees.

5.3.1 TEST CURRENT INPUTS

This test verifies that the current measurement inputs are configured correctly.
1. Using secondary injection test equipment such as an Omicron, apply and measure nominal rated current to
each CT in turn.
2. Check its magnitude using a multi-meter or test set readout. Check this value against the value displayed
on the HMI panel (usually in MEASUREMENTS 1 column).
3. Record the displayed value. The measured current values will either be in primary or secondary Amperes. If
the Local Values cell in the MEASURE’T SETUP column is set to Primary, the values displayed should be
equal to the applied current multiplied by the corresponding current transformer ratio (set in the CT AND VT
RATIOS column). If the Local Values cell is set to Secondary, the value displayed should be equal to the
applied current.

Note:
If a PC connected to the IED using the rear communications port is being used to display the measured current, the process
will be similar. However, the setting of the Remote Values cell in the MEASURE’T SETUP column will determine whether the
displayed values are in primary or secondary Amperes.

The measurement accuracy of the IED is +/- 1%. However, an additional allowance must be made for the accuracy
of the test equipment being used.

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5.3.2 TEST VOLTAGE INPUTS

This test verifies that the voltage measurement inputs are configured correctly.
1. Using secondary injection test equipment, apply and measure the rated voltage to each voltage
transformer input in turn.
2. Check its magnitude using a multimeter or test set readout. Check this value against the value displayed on
the HMI panel (usually in MEASUREMENTS 1 column).
3. Record the value displayed. The measured voltage values will either be in primary or secondary Volts. If the
Local Values cell in the MEASURE’T SETUP column is set to Primary, the values displayed should be equal
to the applied voltage multiplied by the corresponding voltage transformer ratio (set in the CT AND VT
RATIOS column). If the Local Values cell is set to Secondary, the value displayed should be equal to the
applied voltage.

Note:
If a PC connected to the IED using the rear communications port is being used to display the measured current, the process
will be similar. However, the setting of the Remote Values cell in the MEASURE’T SETUP column will determine whether the
displayed values are in primary or secondary Amperes.

The measurement accuracy of the IED is +/- 1%. However, an additional allowance must be made for the accuracy
of the test equipment being used.

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6 ELECTRICAL INTERMICOM COMMUNICATION LOOPBACK

If the IED is used in a scheme with standard InterMiCOM communication (Electrical Teleprotection), you need to
configure a loopback for testing purposes.

6.1 SETTING UP THE LOOPBACK

The communication path may include various connectors and signal converters before leaving the substation. We
therefore advise making the loopback as close as possible to where the communication link leaves the substation.
This way, as much of the wiring as possible and all associated communication signal converters are included in
the test.
1. Set CONFIGURATION > InterMiCOM to Enabled.
2. Set INTERMICOM COMMS > Ch Statistics and Ch Diagnostics to Visible.
3. Check that INTERMICOM COMMS > IM H/W Status displays OK. This means the InterMiCOM hardware is
fitted and initialised.

6.2 LOOPBACK TEST

INTERMICOM COMMS > Loopback Mode allows you to test the InterMiCOM channel. In normal service it must be
disabled. INTERMICOM COMMS > Loopback Status shows the status of the InterMiCOM loopback mode.

Note:
If INTERMICOM COMMS > Loopback Mode is set to Internal, only the internal software of the device is checked. This is
useful for testing functionality if no communications connections are made. Use the 'External' setting during commissioning
because it checks both the software and hardware. When the IED is switched into either Internal or External Loopback Mode it
automatically inhibits InterMiCOM messages to the PSL by setting all eight InterMiCOM message command states to zero.

Set INTERMICOM COMMS > Loopback Mode to External and form a communications loopback by connecting
the transmit signal (pin 2) to the receive signal (pin 3).

Note:
The DCD signal must be held high (by connecting pin 1 to pin 4) if the connected equipment does not support DCD.

DCD 1
RxD 2
TxD 3
DTR 4
GND 5
6
RTS 7
8
9
E01450

Figure 315: InterMicom loopback testing

The loopback mode is shown on the front panel by an Alarm LED and the message IM Loopback on the LCD.
Check that all connections are correct and the software is working correctly.
Check that INTERMICOM COMMS > Loopback Status shows OK.

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6.2.1 INTERMICOM COMMAND BITS

To test the InterMiCOM command bits, go to the INTERMICOM COMMS column and do the following:
1. Enter any test pattern in the Test Pattern cell in the by scrolling through and changing selected bits
between 1 and 0. The entered pattern is transmitted through the loopback.
2. Check that the IM Output Status cell matches the applied Test Pattern.
3. Check that all 8 bits in the IM Input Status cell are zero.

6.2.2 INTERMICOM CHANNEL DIAGNOSTICS

Check that the following cells in the INTERMICOM COMMS column all read OK.
● Data CD Status
● FrameSync Status
● Message Status
● Channel Status

6.2.3 SIMULATING A CHANNEL FAILURE

1. Simulate a failure of the communications link by breaking a connection and checking that some of these
cells show Fail.
2. Restore the communications loopback and ensure that the four diagnostic cells display OK.

Note:
Some or all of these cells show Fail depending on the communications configuration and the way the link has failed.

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7 INTERMICOM 64 COMMUNICATION

If the IED is used in a scheme with InterMiCOM64 communication, you need to configure a loopback for testing
purposes.
IM64 is fibre-based. Several different fibre-optic interfaces are available. In general, 1550 nm single-mode fibres, or
1300 nm single-mode or multimode fibres are used for direct connection. 850 nm multimode fibres are generally
used with multiplexing telecommunications equipment.

Note:
It is important that fibres used for testing are correct for the specified interface(s).

Optical fibres should be terminated with BFOC2.5 (ST2.5) connectors. For multimode applications use 50/125 µm
core fibre. Make sure fibre test leads used for measurements are long enough for mode stripping (a method of
reducing loss within the core). We recommend a minimum length of 10 m (30ft) for this.
If IEDs communicate using multiplexed electrical communication channels, a bidirectional optical-to-electrical
signal converter, such as a P59x, is used. The P59x range consists of three devices: P591 for G703, P592 for V.35
and P593 for X.21.
The P59x is situated near the multiplexer, between the fibre from the IED and the electrical interface of the
multiplexer. Apply the loopback either at the P59x or the multiplexer to ensure as much of the circuit as possible is
tested. If the IED is connected to a multiplexer, the loopback testing is exactly the same whether connected directly
or via a multiplexer. The P59x interface units require additional tests (see P59x documentation).
If Current Differential protection is used, set CONFIGURATION > Current Diff to Enable.
If Current Differential protection is not used, set CONFIGURATION > InterMiCOM64 to Enable.

Warning:
NEVER look directly into the transmit port or the end of an optical fibre, as this could
severely damage your eyes.

7.1 CHECKING THE INTERFACE

Before carrying out the loopback test, you need to check that the interface is transmitting a suitable signal. To
check this ...
1. Set COMMISSIONING TEST > Loopback Mode to External.
2. Using an appropriate fibre-optic cable, connect the Channel 1 transmitter (TX1) to an optical power meter.
Check that the average power transmitted is within the range given in the following table.
3. Record the transmit power level.
4. Repeat for Channel 2 if applicable.

850 nm 1300 nm 1300/1550 nm

Power
multi-mode multi-mode single-mode
Maximum transmitter power (average value) -19.8 dBm -3 dBm -3 dBm
Minimum transmitter power (average value) -22.8 dBm -9 dBm -9 dBm

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Note:
If CONFIGURATION > InterMiCOM64 is set to Enable, the signals normally sent and received by and from the
communications interface are routed to and from the signals defined in the Programmable Scheme Logic. If, however,
COMMISSION TESTS > IM64 Test Mode is set to Enabled, an IM64 test pattern is transmitted instead.

7.2 SETTING UP THE LOOPBACK

Set up a communications loopback for each of the two channels.
Where direct fibre connections are used (or where multiplexer channels conforming to the IEEE C37.94 standard
are used), connect an appropriate fibre-optic cable from the channel transmitter to the channel receiver port on
the rear of the device.
If the communications use P59x interface devices, connect the appropriate optical fibre(s) between the channel
transmitter(s) on the IED used to make connection to the P59x optical receiver(s). Then commission the relevant
P59x devices.

7.3 LOOPBACK TEST

1. Set COMMISSION TESTS > IM64 Test Mode to Enabled, and use COMMISSION TESTS > Test Pattern to set a
bit pattern sent using the InterMiCOM64 loopback.
2. Check that MEASUREMENTS 4 > IM64 Rx Status matches the test pattern set. The communication statistics
show the number of valid and erroneous messages received.

Note:
The propagation delay measurement is not valid in this mode of operation. The IED responds as if it is connected to a remote
IED. It indicates a loopback alarm which can only be cleared by setting COMMISSION TESTS > Loopback Mode to Disabled.

Note:
In loopback mode the signals sent and received through the protection communications interface continue to be routed to
and from the signals defined in the programmable logic.

Note:
A test pattern can also be sent to the remote end to test the whole InterMiCOM communication path. To do this, set
COMMISSION TESTS >IM64 Test Mode to Enable and connect two ends. Take special care because the test pattern is
executed using PSL at the remote end.

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8 GPS SYNCHRONISATION
The IED uses GPS timing information to align the local and remote current vectors in the current differential
algorithm. A P594 GPS synchronising unit is used to decode GPS signals and provide the synchronising signal.
If the IED uses GPS synchronisation, the associated P594 unit needs to be commissioned according to the
instructions in the P594 Technical Manual.

8.1 GPS OPTICAL SIGNAL STRENGTH

Using the optical fibre connected to the P594 optical transmitter:
1. Put the P594 in Test Cycle Mode as described in the P594 documentation
2. With an optical cable connected to the P594 optical transmitter, disconnect the other end of the cable from
the IED.
3. Measure the received signal strength at the IED end. The value should be in the range -16.8 dBm to -25.4
dBm.
4. Record the value.
5. Restore the optical fibre connection to the IED

Warning:
NEVER look directly into the transmit port or the end of an optical fibre, as this could
severely damage your eyes.

8.2 CHECK SYNCHRONISATION SIGNAL AT THE IED

1. Disable the P594 Test Cycle Mode
2. Connect the fibre from the P594 to the IED's GPS port.
3. Set PROT COMMS/IM64 > GPS Sync Enabled to Enable. This enables GPS synchronisation.
4. In MEASUREMENTS 4 > Channel Status, if the GPS synchronisation signal is being received, the display reads
**11******** (where * is a ‘don’t care’ state for this test). This means both the Local GPS and Remote GPS
are being received.
5. Check GPS failure condition by disconnecting the fibre from the P594 and check that the display reverts to
**00********.
6. Restore the GPS by reconnecting the fibre and check again that the display reads **11********.

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9 SETTING CHECKS
The setting checks ensure that all of the application-specific settings (both the IED’s function and programmable
scheme logic settings) have been correctly applied.

Note:
If applicable, the trip circuit should remain isolated during these checks to prevent accidental operation of the associated
circuit breaker.

9.1 APPLY APPLICATION-SPECIFIC SETTINGS

There are two different methods of applying the settings to the IED
● Transferring settings to the IED from a pre-prepared setting file using MiCOM S1 Agile
● Enter the settings manually using the IED’s front panel HMI

9.1.1 TRANSFERRING SETTINGS FROM A SETTINGS FILE

This is the preferred method for transferring function settings. It is much faster and there is a lower margin for
error.
1. Connect a PC running the Settings Application Software to the IED's front port, or a rear Ethernet port.
Alternatively connect to the rear Courier communications port, using a KITZ protocol converter if necessary.
2. Power on the IED
3. Enter the IP address of the device if it is Ethernet enabled
4. Right-click the appropriate device name in the System Explorer pane and select Send
5. In the Send to dialog select the setting files and click Send

Note:
The device name may not already exist in the system shown in System Explorer. In this case, perform a Quick Connect to the
IED, then manually add the settings file to the device name in the system. Refer to the Settings Application Software help for
details of how to do this.

9.1.2 ENTERING SETTINGS USING THE HMI

1. Starting at the default display, press the Down cursor key to show the first column heading.
2. Use the horizontal cursor keys to select the required column heading.
3. Use the vertical cursor keys to view the setting data in the column.
4. To return to the column header, either press the Up cursor key for a second or so, or press the Cancel key
once. It is only possible to move across columns at the column heading level.
5. To return to the default display, press the Up cursor key or the Cancel key from any of the column headings.
If you use the auto-repeat function of the Up cursor key, you cannot go straight to the default display from
one of the column cells because the auto-repeat stops at the column heading.
6. To change the value of a setting, go to the relevant cell in the menu, then press the Enter key to change the
cell value. A flashing cursor on the LCD shows that the value can be changed. You may be prompted for a
password first.
7. To change the setting value, press the vertical cursor keys. If the setting to be changed is a binary value or a
text string, select the required bit or character to be changed using the left and right cursor keys.
8. Press the Enter key to confirm the new setting value or the Clear key to discard it. The new setting is
automatically discarded if it is not confirmed within 15 seconds.

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9. For protection group settings and disturbance recorder settings, the changes must be confirmed before
they are used. When all required changes have been entered, return to the column heading level and press
the down cursor key. Before returning to the default display, the following prompt appears.

Update settings?
ENTER or CLEAR

10. Press the Enter key to accept the new settings or press the Clear key to discard the new settings.

Note:
If the menu time-out occurs before the setting changes have been confirmed, the setting values are also discarded.
Control and support settings are updated immediately after they are entered, without the Update settings prompt.
It is not possible to change the PSL using the IED’s front panel HMI.

Caution:
Where the installation needs application-specific PSL, the relevant .psl files, must be
transferred to the IED, for each and every setting group that will be used. If you do
not do this, the factory default PSL will still be resident. This may have severe
operational and safety consequences.

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10 IEC 61850 EDITION 2 TESTING

10.1 USING IEC 61850 EDITION 2 TEST MODES

In a conventional substation, functionality typically resides in a single device. It is usually easy to physically isolate
these functions, as the hardwired connects can simply be removed. Within a digital substation architecture
however, functions may be distributed across many devices. This makes isolation of these functions difficult,
because there are no physical wires that can be disconnected on a Ethernet network. Logical isolation of the
various functions is therefore necessary.
With devices that support IEC 61850 Edition 2, it is possible to use a test mode to conduct online testing, which
helps with the situation. The advantages of this are as follows:
● The device can be placed into a test mode, which can disable the relay outputs when testing the device
with test input signals.
● Specific protection and control functions can be logically isolated.
● GOOSE messages can be tagged so that receiving devices can recognise they are test signals.
● An IED receiving simulated GOOSE or Sampled Value messages from test devices can differentiate these
from normal process messages, and be configured to respond appropriately.

10.1.1 IED TEST MODE BEHAVIOUR

Test modes define how the device responds to test messages, and whether the relay outputs are activated or not.
You can select the mode of operation by:
● Using the front panel HMI, with the setting IED Test Mode under the COMMISSION TESTS column.
● Using an IEC 61850 control service to System/LLN0.Mod
● Using an opto-input via PSL with the signal Block Contacts

The following table summarises the IED behaviour under the different modes:
IED Test Mode Setting Result
Disabled ● Normal IED behaviour
● Protection remains enabled
● Output from the device is still active
Test ● IEC 61850 message output has the 'quality' parameter set to 'test'
● The device only responds to IEC61850 MMS messages from the client with the
'test' flag set
● Protection remains enabled
● Output from the device is disabled
Contacts Blocked ● IEC 61850 message output has quality set to ‘test’
● The device only responds to IEC 61850 MMS messages from the client with the
'test' flag set

Setting the Test or Contacts Blocked mode puts the whole IED into test mode. The IEC 61850 data object Beh in all
Logical Nodes (except LPHD and any protection Logical Nodes that have Beh = 5 (off) due to the function being
disabled) will be set to 3 (test) or 4 (test/blocked) as applicable.

10.1.2 SAMPLED VALUE TEST MODE BEHAVIOUR

The SV Test Mode defines how the device responds to test sampled value messages. You can select the mode of
operation by using the front panel HMI, with the setting SV Test Mode under the IEC 61850-9.2LE column.
The following table summarises the behaviour for sampled values under the different modes:

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SV Test Mode Setting Result

● Normal IED behaviour
● All sampled value data frames received with an IEC 61850 Test quality bit set
Disabled are treated as invalid
● The IED will display the measurement values for sampled values with the
Simulated flag set but the protection elements within the IED will be blocked
● All sampled value data frames received are treated as good, no matter if they
Enabled
have an IEC 61850-9-2 Simulated flag set or not

10.2 SIMULATED INPUT BEHAVIOUR

Simulated GOOSE messages and sampled value streams can be used during testing.
The Subscriber Sim setting in the COMMISSION TESTS column controls whether a device listens to simulated
signals or to real ones. An IEC 61850 control service to System/LPHD.Sim can also be used to change this value.
The device may be presented with both real signals and test signals. An internal state machine is used to control
how the device switches between signals:
● The IED will continue subscribing to the ‘real’ GOOSE1 (in green) until it receives the first simulated GOOSE 1
(in red). This will initiate subscription changeover.
● After changeover to this new state, the IED will continue to subscribe to the simulated GOOSE 1 message (in
red). Even if this simulated GOOSE 1 message disappears, the real GOOSE 1 message (in green) will still not
be processed. This means all Virtual Inputs derived from the GOOSE 1 message will go to their default state.
● The only way to bring the IED out of this state is to set the Subscriber Sim setting back to False. The IED will
then immediately stop processing the simulated messages and start processing real messages again.
● During above steps, IED1 will continuously process the real GOOSE 2 and GOOSE 3 messages as normal
because it has not received any simulated messages for these that would initiate a changeover.
The process is represented in the following figure:

LPHD1

Sim stVal=true Beh stVal=on

Simulated GOOSE 1 messages
Simulation bit goes TRUE

Real GOOSE 1 messages

Simulation bit was FALSE

Incoming data
processed
Real GOOSE 2 messages

Real GOOSE 3 messages

Reception buffer

V01058

Figure 316: Simulated input behaviour

10.3 TESTING EXAMPLES

These examples show how you test the IED with and without simulated values. Depending on the IED Test Mode, it
may respond by operating plant (for example by tripping the circuit breaker) or it may not operate plant.

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10.3.1 TEST PROCEDURE FOR REAL VALUES

This procedure is for testing with real values without operating plant.
1. Set device into 'Contacts Blocked' Mode
Select COMMISSION TESTS ® IED Test Mode ® Contacts Blocked
2. Confirm new behaviour has been enabled
View COMMISSION TESTS ® IED Mod/Beh, and check that it shows Test-blocked
3. Set device into Simulation Listening Mode
Select COMMISSION TESTS ® Subscriber Sim = Disabled
4. If using sampled values set the sampled values test mode
Select IEC 61850-9.2LE ® SV Test Mode ® Disabled
5. Inject real signals using a test device connected to the merging units. The device will continue to listen to
‘real’ GOOSE messages and ignore simulated messages received.
6. Verify function based on test signal outputs
Binary outputs (e.g. CB trips) will not operate. All transmitted GOOSE and MMS data items will be tagged with
the 'quality' parameter set to 'test', so that the receiver understands that they have been issued by a device
under test and can respond accordingly. This is summarised in the following diagram

V01062

Figure 317: Test example 1

10.3.2 TEST PROCEDURE FOR SIMULATED VALUES - NO PLANT

This procedure is for testing with simulated values without operating plant.
1. Set device into 'Contacts Blocked' Mode
Select COMMISSION TESTS ® IED Test Mode ® Contacts Blocked
2. Confirm new behaviour has been enabled
View COMMISSION TESTS ® IED Mod/Beh, and check that it shows test-blocked

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3. Set device into Simulation Listening Mode

Select COMMISSION TESTS ® Subscriber Sim = Enabled
4. If using sampled values set the sampled values test mode
Select IEC 61850-9.2LE ® SV Test Mode ® Enabled
5. Inject simulated signals using a test device connected to the Ethernet network. The device will continue to
listen to ‘real’ GOOSE messages until a simulated message is received. Once the simulated messages are
received, the corresponding ‘real’ messages are ignored until the device is taken out of test mode. Each
message is treated separately, but sampled values are considered as a single message.
6. Verify function based on test signal outputs
Binary outputs (e.g. CB trips) will not operate. All transmitted GOOSE and MMS data items will be tagged with
the 'quality' parameter set to 'test', so that the receiver understands that they have been issued by a device
under test and can respond accordingly. This is summarised in the following diagram

V01063

Figure 318: Test example 2

10.3.3 TEST PROCEDURE FOR SIMULATED VALUES - WITH PLANT

This procedure is for testing with simulated values with operating plant.
1. Set device into 'Contacts Blocked' Mode
Select COMMISSION TESTS ® IED Test Mode ® Test
2. Confirm new behaviour has been enabled
View COMMISSION TESTS ® IED Mod/Beh, and check that it shows Test
3. Set device into Simulation Listening Mode
Select COMMISSION TESTS ® Subscriber Sim = Enabled
4. If using sampled values set the sampled values test mode
Select IEC 61850-9.2LE ® SV Test Mode ® Enabled
5. Inject simulated signals using a test device connected to the Ethernet network.

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The device will continue to listen to ‘real’ GOOSE messages until a simulated message is received. Once the
simulated messages are received, the corresponding ‘real’ messages are ignored until the device is taken
out of IED test mode. Each message is treated separately, but sampled values are considered as a single
message.
6. Verify function based on test signal outputs.
Binary outputs (e.g. CB trips) will operate as normal. All transmitted GOOSE and MMS data items will be
tagged with the 'quality' parameter set to 'test', so that the receiver understands that they have been issued
by a device under test and can respond accordingly. This is summarised in the following diagram:

V01064

Figure 319: Test example 3

10.3.4 CONTACT TEST

The Apply Test command in this cell is used to change the state of the contacts set for operation.
If the device has been put into 'Contact Blocked' mode using an input signal (via the Block Contacts DDB signal)
then the Apply Test command will not execute. This is to prevent a device that has been blocked by an external
process having its contacts operated by a local operator using the HMI.
If the Block Contacts DDB is not set and the Apply Test command in this cell is issued, contacts change state and
the command text on the LCD changes to No Operation. The contacts remain in the Test state until reset by
issuing the Remove Test command. The command text on the LCD shows No Operation after the Remove Test
command has been issued.

Note:
When the IED Test Mode cell is set to Contacts Blocked, the Relay O/P Status cell does not show the current status of the
output relays so cannot be used to confirm operation of the output relays. Therefore it is necessary to monitor the state of
each contact in turn.

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11 CURRENT DIFFERENTIAL PROTECTION

11.1 CURRENT DIFFERENTIAL BIAS CHARACTERISTIC

1. In the CONFIGURATION column, disable all protection elements other than the one being tested.
2. Make a note of which elements need to be re-enabled after testing.
3. Set the device to loopback mode, isolating it from the remote end.
4. Connect the test circuit shown below. Alternatively, use an injection test set to supply Ia and Ib

P54x IED Ia
Ra
L A
Ph a
Ib
Rb
A
Ph b

V01452

Figure 320: Current Differential Bias Characteristics

11.1.1 LOWER SLOPE

If three LEDs have been assigned to provide phase segregated trip information (Trip A, Trip B and Trip C), these may
be used to indicate correct operation per-phase. If LEDs are not used, use monitor options, as follows.
1. Go to COMMISSION TESTS > Monitor Bit. Change cells 1, 2 and 3 to the values 523, 524 and 525 respectively.
The Test Port Status cell then displays the status of Trip Output A (DDB 523), Trip Output B (DDB 524) and
Trip Output C (DDB 525), with the rightmost bit representing Phase A Trip. From now on monitor the Test
Port Status cell.
2. Make sure that the IED is in loopback mode by setting the Loopback Mode cell to External and applying a
loop-back, either by direct fibre or using a P59x. Alternatively you can set the Test Loopback cell to
Internal.
3. Adjust the variac and the resistor to give a bias current of 1pu in the A-phase (1A into terminals 3-2 for 1A
applications, or 5A into terminals 1-2 for 5A applications).
The device trips, contacts associated with the A-phase operate, and bit 1 (rightmost) of the Test Port Status
cell is set to 1. Some LEDs, including the yellow alarm LED, switch OFF, but ignore these for the moment.
4. When the current in the A Phase is established, close the switch and slowly increase the current in the B
phase from zero until Phase B trips (bit 2 of the Test Port Status cell is set to 1).
For the initial conditions where the magnitude of the bias current in phase A = 1 pu, record the phase B current
magnitude and check that it corresponds to the following.
Connection type Magnitude of differential current in phase B
2-terminal & dual redundant 0.25 pu +/-10%
3-terminal 0.216 pu +/-10%
Assumption: Is1 = 0.2 pu, k1 = 30%, Is2 = 2.0 pu
For other differential settings or current injected into A phase (Ia), the following formula can be used (enter slope in
pu form, which is. percentage/100):

Connection type Magnitude of differential current in phase B

2-terminal & dual redundant 0.5 x (Is1 + (Ia x k1)) pu +/- 10%

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Connection type Magnitude of differential current in phase B

3-terminal 0.333 x (Is1 + (1.5 x Ia x k1)) pu +/- 10
Assumption: Ia < Is2
Switch OFF the AC supply, read and clear all alarms.

11.1.2 UPPER SLOPE

1. Repeat the lower slope test but with the bias current set in the A-phase to 3 pu.
2. When the current in the A Phase is established, close the switch and slowly increase the current in the B
phase from zero until phase B trips (bit 2 of the Test Port Status cell is set to 1).
For the initial conditions where the magnitude of the bias current in phase A = 3 pu, record the phase B current
magnitude and check that it corresponds to the information below.
Connection type k2 Magnitude of differential current in phase B
2-terminal & dual redundant 150% 1.15 pu +/- 10%
2-terminal & dual redundant 100% 0.9 pu +/- 10%
3-terminal 150% 1.51 pu +/- 10%
3-terminal 100% 1.1 pu +/- 10%
Assumption: Is1 = 0.2 pu, k1 = 30%, Is2 = 2.0 pu, k2 as above
For other differential settings or current injected into A phase (Ia), the formula below can be used (enter slopes in
pu form, which is percentage/100):
Connection type Magnitude of differential current in phase B
2-terminal & dual redundant 0.5 x [(Ia x k2) – {(k2 – k1) x Is2\- } + Is1] pu +/- 20%
3-terminal 0.333 x [(1.5 x Ia x k2) – {(k2 – k1) x Is2\- } + Is1] pu +/- 20%
Assumption: Ia > IS2
Switch OFF the ac supply and reset the alarms.

Note:
For 5 A applications, keep the duration of current injections short to avoid overheating of the variac or injection test set

11.2 CURRENT DIFFERENTIAL OPERATION AND CONTACT ASSIGNMENT

Phase A
1. Retaining the same test circuit as before, prepare for an instantaneous injection of 3 pu current in the A
phase, with no current in the B phase (B phase switch open).
2. Set a timer to start when the fault injection is applied, and to stop when the trip occurs.
3. To verify the correct output contact mapping, use the trip contacts that would be expected to trip the circuit
breaker(s), as shown below. For two breaker applications, stop the timer once both CB1 and CB2 trip
contacts have closed. This can be achieved by connecting the contacts in series to stop the timer.
Single breaker Two circuit breakers
Three Pole Tripping Any Trip Any Trip (CB1) and Any Trip (CB2)
Single Pole Tripping Trip A Trip A (CB1) and Trip A (CB2)

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Phase B
1. Reconfigure the test equipment to inject fault current into the B phase.
2. Repeat the test, this time ensuring that the breaker trip contacts relative to B phase operation close
correctly.
3. Record the B phase trip time.
4. Switch OFF the ac supply and reset the alarms

Phase C
1. Repeat the above procedure for the C phase.
2. Switch OFF the ac supply and reset the alarms.
The average of the recorded operating times for the three phases should be less than 40 ms for 50 Hz, and less
than 35 ms for 60 Hz when set for instantaneous operation.

Note:
For applications using magnetising inrush current restraint, use a test current higher than the Inrush High setting to obtain
fast operating times. A setting of at least twice the Inrush High setting is recommended.

The expected operating time is typically within +/- 5% (for IDMT) or +/-2% (for DT) of that for the curve equation
plus the “instantaneous” delay quoted above.
When the tests are completed, restore the original settings of any elements which were disabled for testing
purposes. Use the CONFIGURATION column.

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12 DISTANCE PROTECTION

12.1 DEPENDENCY CONDITIONS

Some protection elements can be set to have dependencies on the availability of the protection communication
channel(s) and on the status of the voltage transformer supervision function (VTS).
If you are testing a distance model, the distance protection can be permanently enabled, or it can be set so that it
is only enabled in the event of a failure of the protection communications channel(s).
The overcurrent and earth faults elements can be permanently enabled, or can be set so that they are only
enabled:
● in the event of a failure of the protection communications channel(s)
● in the event of a VTS alarm
● according to a logical combination of both conditions.

If these elements are enabled with a dependency upon the above conditions, it is necessary to simulate the
condition to test the correct operation of the protection function.
A communications failure can be simulated by setting the Test Loopback cell to Disabled and checking that the IED
raises a Comms Fail alarm.
At the end of the test, clear the communications alarms and reset the statistics.
A VTS alarm can be raised by applying a 3-phase voltage to the VT inputs and then removing one phase voltage
for a duration exceeding the VTS Time Delay setting.
At the end of the tests, clear the VTS alarm.

12.2 DISTANCE PROTECTION SINGLE-ENDED TESTING

If the distance protection function is being used, test the reaches and time delays.
1. Check for any possible dependency conditions and simulate as appropriate.
2. In the CONFIGURATION column, disable all protection elements other than the one being tested.
3. Disable the current differential function, directly or indirectly:
a. If the distance element is enabled without dependency, disable the current differential element
Current Diff.
b. If the distance protection is enabled with dependency on communication channel failure, the current
differential element Current Diff should remain enabled and the communication should be disrupted
to cause a suitable failure of the current differential protection
4. Make a note of which elements need to be re-enabled after testing

12.2.1 PRELIMINARIES
You should now connect the IED to equipment able to supply phase-phase and phase-neutral volts with current in
the correct phase relation for a particular type of fault on the selected characteristic angle. The facility for altering
the loop impedance (phase-to-ground fault or phase-phase) presented to the IED is essential.

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Use a three-phase digital/electronic injection test set to make the commissioning procedure easier.
1. If testing the distance elements using using test sets that do not provide a dynamic model to generate true
fault delta conditions, set COMMISSIONING TESTS > Static Test Mode to Enabled. When set, this disables
phase selector control and forces the device to use a conventional (non-delta) directional line.
2. For lower specification test equipment that cannot apply a full three phase set of healthy simulated pre-
fault voltages, the VT supervision may need to be disabled to avoid spurious pickup. Set CONFIGURATION >
Supervision to Disabled.
3. Connect the test equipment to the device using the test block(s), taking care not to open-circuit any CT
secondary windings. If using MMLG type test blocks, the live side of the test plug must be provided with
shorting links before it is inserted into the test block.
4. When the test is complete, make sure COMMISSIONING TESTS > Static Test Mode is set back to Disabled.

12.2.2 ZONE 1 REACH CHECK

The zone 1 element is set to be directional forward.
1. Apply a dynamic A-phase-to-neutral fault, slightly in excess of the expected reach. The duration of the
injection should be in excess of the tZ1 timer setting, but less than tZ2. These settings are in the DISTANCE
column. No trip should occur, and the red Trip LED should remain OFF.
2. Reduce the impedance and reapply the simulated fault.
3. Repeat this procedure until a trip occurs. When this happens, the display shows Alarms/Faults present and
the Alarm and Trip LEDs switch ON.
4. To view the alarm message, keep pressing the read key until the yellow alarm LED changes from flashing to
being steadily on.
5. At the prompt Press clear to reset alarms, press the C key. This clears the fault record from the display.
6. Record the impedance at which the device trips. The measured impedance should be within +/- 10% of the
expected reach.
7. Read and reset the alarms
Modern injection test sets usually calculate the expected fault loop impedance from the device settings. For those
that do not, check the reach for phase-phase and confirm the operation of the contacts. The appropriate loop
impedance is given by the vector sum:
Z1 + Z1 residual = Z1 + (Z1.kZN Res Comp ÐkZN Angle) Ω

12.2.3 ZONE 2 REACH CHECK

The zone 2 element is set to be directional forward.
1. Apply a dynamic B-C fault, slightly in excess of the expected reach. The duration of the injection should be
in excess of the tZ2 timer setting, but less than tZ3. These settings are in the DISTANCE column. No trip
should occur, and the red Trip LED should remain OFF.
2. Repeat the test described above to find the zone reach.
3. Record the impedance at which the device trips. The measured impedance should be within +/- 10% of the
expected reach.
4. Read and reset the alarms.
Modern injection test sets usually calculate the expected fault loop impedance from the device settings. For those
that do not, check the reach for phase-phase and confirm the operation of the appropriate contacts. The
appropriate loop impedance is now given by:
2 x Z2 Ω

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12.2.4 ZONE 3 REACH CHECK

1. The zone 3 element is set to forward, reverse or offset. The current injected must be in the appropriate
direction to match the setting in the DISTANCE SETUP column.
2. Apply a dynamic C-A fault, slightly in excess of the expected reach. The duration of the injection should be
in excess of the tZ3 timer setting (typically tZ3 + 100 ms).
3. Repeat the test described above to find the zone reach.
4. Record the impedance at which the device trips. The measured impedance should be within +/- 10% of the
expected reach.
5. Read and reset the alarms.
6. Check that the correct reverse offset (Z3’) has been applied. The setting is in the Z3’ Ph Rev Reach and Z3’
Gnd Rev Reach cells.

12.2.5 ZONE 4 REACH CHECK

The zone 4 element is set to be directional reverse.
1. Apply a dynamic B-N fault, slightly in excess of the expected reach. The duration of the injection should be
in excess of the tZ4 timer setting (typically tZ4 + 100 ms).
2. Repeat the test described above to find the zone reach.
3. Record the impedance at which the device trips. The measured impedance should be within +/- 10% of the
expected reach.
4. Read and reset the alarms.

12.2.6 ZONE P REACH CHECK

The zone P element can be set to forward or reverse directional or offset. The current injected must be in the
correct direction to match the setting in the DISTANCE SETUP column.
1. Apply a dynamic C-N fault, slightly in excess of the expected reach. The duration of the injection should be
in excess of the tZP timer setting (typically tZP + 100 ms).
2. Repeat the test described above to find the zone reach.
3. Record the impedance at which the relay trips. The measured impedance should be within +/-10% of the
expected reach.
4. Read and reset the alarms.

12.2.7 ZONE Q REACH CHECK

The zone Q element can be set to forward or reverse directional or offset. The current injected must be in the
correct direction to match the setting in the DISTANCE SETUP column.
1. Apply a dynamic C-N fault, slightly in excess of the expected reach. The duration of the injection should be
in excess of the tZQ timer setting (typically tZQ + 100 ms).
2. Repeat the test described above to find the zone reach.
3. Record the impedance at which the relay trips. The measured impedance should be within +/-10% of the
expected reach.
4. Read and reset the alarms.

12.2.8 RESISTIVE REACH

This is for quadrilateral characteristics only.

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Check that the correct settings for phase and ground element resistive reaches have been applied. The relevant
settings are:
● R1Ph, R2Ph, R3Ph, R3Ph reverse, R4Ph and RP Ph for phase fault zones.
● R1Gnd, R2Gnd, R3Gnd, R3Gnd reverse, R4Gnd and RP Gnd for ground fault zones.

Note:
Zone 3 has an independent setting for the forward resistance reach (right-hand resistive reach line), and the reverse resistance
reach (left-hand resistive reach line).

12.2.9 LOAD BLINDER

1. Check that the correct settings for the load blinder have been applied. The settings are at the end of the
DISTANCE SETUP column.
2. Verify that the Load B/Angle cell is set at least 10 degrees less than the Line Angle setting in the LINE
PARAMETERS column.

12.3 OPERATION AND CONTACT ASSIGNMENT

You should inject a fault at half Z1 reach with the intention of causing a distance protection trip.

12.3.1 PHASE A
1. Prepare a dynamic A-phase-to-neutral fault, as detailed above.
2. Set a timer to start when the fault injection is applied and to stop when the trip occurs.
3. To verify correct output contact mapping use the trip contacts that would be expected to trip the circuit
breaker(s) (Any Trip for 3-pole tripping, Trip A for single pole tripping).
4. For two breaker applications, stop the timer when CB1 and CB2 trip contacts have both closed. Monitor by
connecting the contacts in series to stop the timer if necessary.
5. Record the phase A trip time.
6. Switch OFF the AC supply and reset the alarms.

12.3.2 PHASE B
1. Reconfigure to test a B phase fault.
2. Repeat the test, this time ensuring that the breaker trip contacts relative to B phase operation close
correctly.
3. Record the phase B trip time.
4. Switch OFF the AC supply and reset the alarms.

12.3.3 PHASE C
1. Reconfigure to test a C phase fault.
2. Repeat the test, this time ensuring that the breaker trip contacts relative to C phase operation close
correctly.
3. Record the phase C trip time.
4. Switch OFF the AC supply and reset the alarms.

The average of the recorded operating times for the three phases should typically be less than 20 ms for 50 Hz,
and less than 16.7 ms for 60 Hz when set for instantaneous operation.

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Note:
Where a non-zero time delay is set in the DISTANCE menu column, the expected operating time is typically within +/- 5% of
the delay setting plus the “instantaneous” delay.

12.3.4 TIME DELAY SETTINGS

Check that the correct time delay settings have been applied. The relevant settings are in the SCHEME LOGIC
column and are as follows:
● tZ1 Ph Time Delay and tZ1 Gnd Time Delay
● tZ2 Ph Time Delay and tZ2 Gnd Time Delay
● tZ3 Ph Time Delay and tZ3 Gnd Time Delay
● tZP Ph Time Delay and tZP Gnd Time Delay
● tZ4 Ph Time Delay and tZ4 Gnd Time Delay

Note:
The device allows separate time delay settings for phase (“Ph”) and ground (“Gnd”) fault elements. BOTH must be checked to
ensure that they have been set correctly.

12.4 SCHEME TESTING

The device is tested for its response to internal and external fault simulations but the response depends on the
aided channel (pilot) scheme selected. The response to the 'Reset Z1 Extension' opto-input is shown in the case of a
Zone 1 Extension scheme.
We assume a conventional signalling scheme implementation.

If an InterMiCOM64 scheme is used to provide the signalling, the scheme logic may not use opto-inputs for the
aided scheme implementation. In this case, internal DDB signals need to be set or reset to test the operation of the
protection scheme.
Use the IM64 Test Mode with the IM64 Test Pattern to assert or monitor the relevant signals.
Ensure that the injection test set timer is still connected to measure the time taken for the device to trip. A series of
fault injections are applied, with a Zone 1, end-of-line, or Zone 4 fault simulated. At this stage, note the method in
which each fault is applied, but do not inject yet:
● Zone 1 fault: A dynamic forward A-B fault at half the Zone 1 reach is simulated.
● End of line fault: A dynamic forward A-B fault at the remote end of the line is simulated. The fault
impedance simulated should match the LINE PARAMETERS > Line Impedance setting.
● Zone 4 fault: A dynamic reverse A-B fault at half the Zone 4 reach is simulated.

The following table indicates the expected response for various test situations for a conventional signalling
scheme.
IED RESPONSE
Forward fault in Forward fault at end of line
Fault type simulated Reverse fault in zone 4
zone 1 (within Z1X/Z2)
Signal receive opto ON OFF ON OFF ON OFF
Zone 1 extension Trip Trip No Trip Trip No Trip No Trip
Trip, Trip, No Trip, No Signal Trip, No Trip, Signal No Trip, Signal
Blocking scheme
No Signal Send No Signal Send Send No Signal Send Send Send
Permissive Scheme Trip, No Trip, No Signal No Trip, No Signal No Trip, No Signal
Trip, Signal Send Trip, Signal Send
(PUR/PUTT) No Signal Send Send Send Send

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IED RESPONSE
Forward fault in Forward fault at end of line
Fault type simulated Reverse fault in zone 4
zone 1 (within Z1X/Z2)
Permissive Scheme No Trip, Signal No Trip, No Signal No Trip, No Signal
Trip, Signal Send Trip, Signal Send Trip, Signal Send
(POR/POTT) Send Send Send

12.4.1 SCHEME TRIP TEST FOR ZONE 1 EXTENSION

1. Energise the Reset Z1X (Reset Zone 1 Extension) opto-input. This is done by applying a continuous DC
voltage onto the required opto-input, either from the test set, or station battery.
2. Inject an end of line fault. The duration of injection should be set to 100 ms. No trip should occur.
3. De-energise the Reset Z1X opto-input
4. Repeat the test injection and record the operating time. This should typically be less than 20 ms for 50 Hz,
and less than 16.7 ms for 60 Hz when set for instantaneous operation.
5. Switch OFF the AC supply and reset the alarms.

Note:
Here a non-zero tZ1 Ph or tZ1 Gnd time delay is set in the DISTANCE column, the expected operating time is typically within
+/- 5% of the tZ1 setting plus the “instantaneous” delay quoted above.

12.4.2 SCHEME TRIP TESTS FOR PERMISSIVE SCHEMES

This test applies to both Permissive Underreach, and Permissive Overreach aided scheme applications.
1. Energise the Signal Receive opto-input. This is done by applying a continuous DC voltage onto the required
opto-input from the test set, or station battery.
2. Inject an end of line fault, and record the operating time. The measured operating time should typically be
less than 20 ms for 50 Hz, and less than 16.7 ms for 60 Hz when set for instantaneous operation.
3. Switch OFF the AC supply and reset the alarms.
4. De-energise the Signal Receive opto-input (remove the temporary energisation link, to turn it OFF).

Note:
Where a non-zero Aided Distance Dly time delay is set in the DISTANCE menu column, the expected operating time is typically
within +/- 5% of the tZ1 setting plus the “instantaneous” delay quoted above.

12.4.3 SCHEME TRIP TESTS FOR BLOCKING SCHEME

1. Energise the Signal Receive opto-input. This is done by applying a continuous DC voltage onto the required
opto-input, either from the test set, or station battery.
2. Inject an end of line fault. The duration of injection should be set to 100 ms. No trip should occur.
3. De-energise the channel received opto-input.
4. Repeat the test injection, and record the operating time.
5. Switch OFF the AC supply and reset the alarms.

Note:
For blocking schemes, a non-zero Aided Distance Dly time delay is set, so the expected operating time is typically within +/-
5% of the delay setting plus the “instantaneous” operating delay. The trip time should thus be less than 20 ms for 50 Hz, and
less than 16.7 ms for 60 Hz, plus 1.05 x Delay setting.

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12.4.4 SIGNAL SEND TEST FOR PERMISSIVE SCHEMES

This test applies to both Permissive Underreach, and Permissive Overreach scheme applications.
1. Reconnect the test set so that the timer is no longer stopped by the Trip contact, but is now stopped by the
Signal Send contact. This is the contact that would normally be connected to the pilot/signalling channel.
2. Inject a Zone 1 fault, and record the Signal Send contact operating time. The measured operating time
should typically be less than 20 ms for 50 Hz, and less than 16.7 ms for 60 Hz applications.
3. Switch OFF the AC supply and reset the alarms.

12.4.5 SIGNAL SEND TEST FOR BLOCKING SCHEME

1. Reconnect the test set so that the timer is no longer stopped by the Trip contact, but is now stopped by the
Signal Send contact. This is the contact that would normally be connected to the pilot/signalling channel.
2. Inject a Zone 4 fault, and record the signal send contact operating time. The measured operating time
should typically be less than 20 ms for 50 Hz, and less than 16.7 ms for 60 Hz applications.
3. Switch OFF the ACsupply and reset the alarms.

12.4.6 SCHEME TIMER SETTINGS

1. Check that the correct time delay settings have been applied. The relevant settings in the AIDED SCHEMES
column are:
a. tRev. Guard (if applicable/visible)
b. Unblocking Delay (if applicable/visible)
c. WI Trip Delay (if applicable/visible)
2. When the tests are completed, restore all settings that were disabled for testing purposes.
3. Set the Static Test Mode to Disabled.
4. Remove any wires or leads temporarily fitted to energise the channel receive opto-input

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13 DELTA DIRECTIONAL COMPARISON

13.1 SINGLE-ENDED TESTING

If the delta directional comparison aided scheme is being used, test the operation
1. In the CONFIGURATION column, disable all protection elements other than the one being tested.
2. Make a note of which elements need to be re-enabled after testing

13.1.1 PRELIMINARIES
Use a three-phase digital/electronic injection test set to make the commissioning procedure easier.
Connect the test equipment to the device using the test block(s) taking care not to open-circuit any CT secondary.
If MMLG type test blocks are used, the live side of the test plug must be provided with shorting links before it is
inserted into the test block.

13.1.2 SINGLE-ENDED INJECTION TEST

This set of injection tests aims to determine correct operation of a single IED at one end of the scheme. The device
is tested in isolation, with the communications channel to the remote line terminal disconnected.
First verify that the device cannot send or receive channel scheme signals to or from the remote line end.
The device is tested for its response to forward and reverse fault injections, but the response depends on the aided
channel (pilot) scheme that is selected. The table below shows the expected response for various test situations for
a conventional signalling scheme.
We assume a conventional signalling scheme implementation.

If an InterMiCOM64 scheme is used to provide the signalling, the scheme logic may not use opto-inputs for the
aided scheme implementation. In this case, internal DDB signals need to be set or reset to test the operation of the
protection scheme.
Use the IM64 Test Mode with the IM64 Test Pattern to assert or monitor the relevant signals.
IED RESPONSE
Direction of fault test
Forward fault Reverse fault
injection
Signal receive opto ON OFF ON OFF
No Trip, Trip, No Trip, No Trip,
Blocking scheme
No Signal Send No Signal Send Signal Send Signal Send
Permissive scheme (POR/ Trip, No Trip, No Trip, No Trip,
POTT) Signal Send Signal Send No Signal Send No Signal Send

13.1.3 FORWARD FAULT PREPARATION

Configure the test set to inject a dynamic sequence of injection, as follows:
1. Simulate a healthy three-phase set of balanced voltages, each of magnitude Vn. No load current should be
simulated. The duration of injection should be set to 1 second. Step 1 therefore mimics a healthy unloaded
line before the onset of a fault.
2. Simulate a forward fault on the A-phase. The A-phase voltage must be simulated to drop by 3 times the Dir.
V Fwd setting,
Va = Vn – 3 (Dir. V Fwd)
The fault current on the A-phase should be set to 3 times the Dir. I Fwd setting, lagging Va by a phase angle equal
to the line angle,

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Ia = 3 (Dir. I Fwd)Ð-θ Line

Phases B and C should retain their healthy pre-fault voltage, and no current. The duration of injection should be
set to 100 ms longer than the Aid. 1 Delta Dly, Aid. 2 Delta Dly time setting.

13.2 OPERATION AND CONTACT ASSIGNMENT

You should inject a forward fault with the intention of causing a scheme trip. For a Permissive scheme, the Signal
Receive opto-input needs to be energized. This is done by applying a continuous DC voltage onto the required
opto-input, either from the test set, or station battery.
For a Blocking scheme, the opto-input should remain de-energised.

13.2.1 PHASE A
1. Prepare a dynamic A-phase-to-neutral fault, as detailed above.
2. Set a timer to start when the fault injection is applied and to stop when the trip occurs.
3. To verify correct output contact mapping use the trip contacts that would be expected to trip the circuit
breaker(s) (Any Trip for 3-pole tripping, Trip A for single pole tripping).
4. For two breaker applications, stop the timer when CB1 and CB2 trip contacts have both closed. Monitor by
connecting the contacts in series to stop the timer if necessary.
5. Record the phase A trip time.
6. Switch OFF the AC supply and reset the alarms.

13.2.2 PHASE B
1. Reconfigure to test a B phase fault.
2. Repeat the test, this time ensuring that the breaker trip contacts relative to B phase operation close
correctly.
3. Record the phase B trip time.
4. Switch OFF the AC supply and reset the alarms.

13.2.3 PHASE C
1. Reconfigure to test a C phase fault.
2. Repeat the test, this time ensuring that the breaker trip contacts relative to C phase operation close
correctly.
3. Record the phase C trip time.
4. Switch OFF the AC supply and reset the alarms.

The average of the recorded operating times for the three phases should typically be less than 20 ms for 50 Hz,
and less than 16.7 ms for 60 Hz when set for instantaneous operation.

Note:
Where a non-zero time delay is set in the DISTANCE menu column, the expected operating time is typically within +/- 5% of
the delay setting plus the “instantaneous” delay.

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13.3 DELTA PROTECTION SCHEME TESTING

13.3.1 SIGNAL SEND TEST FOR PERMISSIVE SCHEMES

1. Reconnect the test set so that the timer is no longer stopped by the Trip contact, but is now stopped by the
Signal Send contact. This is the contact that would normally be connected to the pilot/signalling channel.
2. Repeat the forward fault injection, and record the Signal Send contact operating time. The measured
operating time should typically be less than 20 ms for 50 Hz, and less than 16.7 ms for 60 Hz applications.
3. Switch OFF the AC supply and reset the alarms.

13.3.2 SIGNAL SEND TEST FOR BLOCKING SCHEMES

Configure the test set to inject a dynamic sequence of injection, as follows:
1. Simulate a healthy three-phase set of balanced voltages, each of magnitude Vn. No load current should be
simulated. The duration of injection should be set to 1 second. Step 1 therefore mimics a healthy unloaded
line, prior to the onset of a fault.
2. Simulate a reverse fault on the A-phase. The A-phase voltage must be simulated to drop by 3 times the Dir.
V Rev setting; Va = Vn – 3(Dir. V Rev)
3. The fault current on the A-phase should be set to 3 times the DI Rev setting, and in antiphase to the forward
injections; Ia = 3 (Dir. I Rev) Ð180°-θ Line
4. Prepare the dynamic A phase reverse fault, as detailed above. Ensure that the test set is simulating Steps 1
and 2 as one continuous transition.
5. Set a timer to start when the fault injection is applied, and to stop when the Delta scheme Signal Send
contact closes.
6. Apply the test, and record the signal send contact response time. The recorded operating time should
typically be less than 20 ms for 50 Hz, and less than 16.7 ms for 60 Hz applications.
7. Switch OFF the AC supply and reset the alarms.

Caution:
When the tests are completed, restore all settings that were disabled for testing
purposes.

Caution:
Remove any wires or leads temporarily fitted to energise the channel receive opto-
input.

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14 DEF AIDED SCHEMES

14.1 DEPENDENCY CONDITIONS

Some protection elements can be set to have dependencies on the availability of the protection communication
channel(s) and on the status of the voltage transformer supervision function (VTS).
If you are testing a distance model, the distance protection can be permanently enabled, or it can be set so that it
is only enabled in the event of a failure of the protection communications channel(s).
The overcurrent and earth faults elements can be permanently enabled, or can be set so that they are only
enabled:
● in the event of a failure of the protection communications channel(s)
● in the event of a VTS alarm
● according to a logical combination of both conditions.

If these elements are enabled with a dependency upon the above conditions, it is necessary to simulate the
condition to test the correct operation of the protection function.
A communications failure can be simulated by setting the Test Loopback cell to Disabled and checking that the IED
raises a Comms Fail alarm.
At the end of the test, clear the communications alarms and reset the statistics.
A VTS alarm can be raised by applying a 3-phase voltage to the VT inputs and then removing one phase voltage
for a duration exceeding the VTS Time Delay setting.
At the end of the tests, clear the VTS alarm.

14.2 EARTH CURRENT PILOT SCHEME

1. Check for any possible dependency conditions and simulate as appropriate.
2. In the CONFIGURATION column, disable all protection elements other than the one being tested.
3. Disable the current differential function, directly or indirectly:
a. If the distance element is enabled without dependency, disable the current differential element
Current Diff.
b. If the distance protection is enabled with dependency on communication channel failure, the current
differential element Current Diff should remain enabled and the communication should be disrupted
to cause a suitable failure of the current differential protection
4. Make a note of which elements need to be re-enabled after testing
We assume a conventional signalling scheme implementation.

If an InterMiCOM64 scheme is used to provide the signalling, the scheme logic may not use opto-inputs for the
aided scheme implementation. In this case, internal logic signals (DDBs) need to be set or reset to test the
operation of the protection scheme.
The IM64 Test Mode in conjunction with the IM64 Test Pattern should be used to assert or monitor the relevant
signals.
This set of injection tests aims to determine that a single device, at one end of the scheme is performing correctly.

Note:
The device must be tested in isolation, with the communications channel to the remote line terminal disconnected.

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14.2.1 PRELIMINARIES
1. Determine which output relays have been selected to operate when a DEF trip occurs, by viewing the
programmable scheme logic. If the trip outputs are phase segregated (a different output relay allocated for
each phase), the output relay assigned for tripping on ‘A’ phase faults should be used.
2. Connect the output relay so that its operation will trip the test set and stop the timer.
3. Connect the current output of the test set to the ‘A’ phase current transformer input
4. Connect, all three phase voltages Va, Vb, and Vc.
5. Depending on the test equipment used, make sure the timer is set to start when the current is applied.

14.2.2 PERFORM THE TEST

1. Ensure that the timer is reset and prepare the following test shot.
2. Simulate a forward fault on the A-phase. The A-phase voltage must be simulated to drop by 4 times the DEF
VNpol Set setting; Va = Vn - 4 (DEF Vpol)
3. Set the fault current on the A-phase should to 2 times the DEF Threshold setting, and in the forward
direction. For a forward fault, the current Ia should lag the voltage Va by the DEF Char Angle setting; Ia = 2
(IN DEF Threshold Ð q DEF)
4. Phases B and C should retain their healthy pref-ault voltage, and no current. The duration of the injection
should be in excess of the DEF Delay setting (typically Aid. 1 DEF Dly. and Aid. 2 DEF Dly. + 100 ms).
IED RESPONSE
Direction of fault
Forward fault Reverse fault
test injection
Signal Receive Opto ON OFF ON OFF
No Trip, Trip, No Trip, No Trip,
Blocking Scheme
No Signal Send No Signal Send Signal Send Signal Send
Permissive Scheme Trip, No Trip, No Trip, No Trip,
(POR/POTT) Signal Send Signal Send No Signal Send No Signal Send

14.2.3 FORWARD FAULT TRIP TEST

A forward fault is now injected as described, with the intention to cause a scheme trip.
For a permissive scheme, the Signal Receive opto-input should be energised. This is done by applying a
continuous DC voltage onto the required opto-input, either from the test set, station battery, or IED field voltage.
The commissioning engineer decides on the best method.
For a blocking scheme, the opto-input should remain de-energised (“OFF”).
1. Apply the fault and record the (phase A) trip time.
2. Switch OFF the AC supply and reset the alarms.
The aided earth fault (DEF) scheme trip time for POR schemes (permissive overreach) POR schemes should be less
than 40 ms.
For blocking schemes, where a non-zero DEF Dly time delay is set, the expected operating time is typically within
+/- 5% of the delay setting plus the “instantaneous” (40 ms) delay quoted above.
There is no need to repeat the test for phases B and C, as these trip assignments have already been proven by the
distance/delta trip tests.

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14.3 SCHEME TESTING

14.3.1 SIGNAL SEND TEST FOR PERMISSIVE SCHEMES

1. Reconnect the test set so that the timer is no longer stopped by the Trip contact, but is now stopped by the
Signal Send contact (the contact that would normally be connected to the pilot/signalling channel).
2. Repeat the forward fault injection, and record the Signal Send contact operating time. The measured
operating time should typically be less than 40 ms.
3. Switch OFF the AC supply and reset the alarms.

14.3.2 SIGNAL SEND TEST FOR BLOCKING SCHEMES

1. Reconnect the test set so that the timer is no longer stopped by the Trip contact, but is now stopped by the
Signal Send contact. This is the contact that would normally be connected to the pilot/signalling channel.
2. Reverse the current flow direction on the A phase to simulate a reverse fault.
3. Perform the reverse fault injection and record the signal send contact operating time. The measured
operating time should typically be less than 40 ms.
4. Switch OFF the AC supply and reset the alarms.

Caution:
When the tests are completed, restore all settings that were disabled for testing
purposes.

Caution:
Remove any wires or leads temporarily fitted to energise the channel receive opto-
input.

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15 OUT OF STEP PROTECTION

For this test, an injection set with a state sequencer function is required, as dynamic impedance conditions are
going to be tested. The four states impedances that applied during the Out of Step commissioning process are
shown below:

+jX

Z6
Z5

State 4

State 3

State 2

State 1
R

R6' R5' R5 R6

∆R

Z5'
Z6'

V01451

Figure 321: State impedances

Depending on the Out of Step (OST) settings, use one of the following setting options.
● OST setting
● Predictive OST setting
● Predictive and OST setting

15.1 OST SETTING

1. Clear all alarms.
2. Set the OST timer to zero.
3. To test OST, a 4-state test sequence is required. Based on healthy voltages (VA = VB = VC = 57.8 V) calculate
the currents to generate the impedances as below.
State 1 State 2 State 3 State 4
Applied current
57.8/(1.1R6) 57.8/(R5+0.5(R6-R5)) 57.8/(0.95R5) 57.8/(1.1R5')
(all 3 phases)
Angle 0° 0° 0° 180°
Duration 500 ms Longer than ‘Delta t’ set time 100 ms 500 ms

Now apply the 4-state sequence, check that all 3-phases have tripped and that an OST alarm is displayed on the
local LCD.

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Note:
The angle in the table above is the angle between voltages and their respective currents. In state 4 the currents are displaced
180° from their respective voltages.

15.2 PREDICTIVE OST SETTING

1. Clear all alarms.
2. Set the OST timer to zero.
3. To test OST, a 3-state test sequence is required. Based on healthy voltages (VA = VB = VC = 57.8 V) calculate
the currents to generate the impedances as below
State 1 State 2 State 3
Applied current
57.8/(1.1R6) 57.8/(R5+0.5(R6-R5)) 57.8/(0.95R5)
(all 3 phases)
Angle 0° 0° 0°
Longer than 25 ms but shorter than
Duration 500 ms 500 ms
‘Delta t’ set time

Now apply the 3-state sequence, check that all 3-phases have tripped and that an OST alarm is displayed on the
local LCD.

15.3 PREDICTIVE AND OST SETTING

As per Predictive OST

15.4 OST TIMER TEST

1. Repeat the test as for ‘predictive OST’ and observe that the 3-phase tripping comes up after the ‘Tost’ set
delay.
2. Record the operating time in the commissioning record sheet.

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16 PROTECTION TIMING CHECKS

There is no need to check every protection function. Only one protection function needs to be checked as the
purpose is to verify the timing on the processor is functioning correctly.

16.1 DEPENDENCY CONDITIONS

Some protection elements can be set to have dependencies on the availability of the protection communication
channel(s) and on the status of the voltage transformer supervision function (VTS).
If you are testing a distance model, the distance protection can be permanently enabled, or it can be set so that it
is only enabled in the event of a failure of the protection communications channel(s).
The overcurrent and earth faults elements can be permanently enabled, or can be set so that they are only
enabled:
● in the event of a failure of the protection communications channel(s)
● in the event of a VTS alarm
● according to a logical combination of both conditions.

If these elements are enabled with a dependency upon the above conditions, it is necessary to simulate the
condition to test the correct operation of the protection function.
A communications failure can be simulated by setting the Test Loopback cell to Disabled and checking that the IED
raises a Comms Fail alarm.
At the end of the test, clear the communications alarms and reset the statistics.
A VTS alarm can be raised by applying a 3-phase voltage to the VT inputs and then removing one phase voltage
for a duration exceeding the VTS Time Delay setting.
At the end of the tests, clear the VTS alarm.

16.2 OVERCURRENT CHECK

If the overcurrent protection function is being used, test the overcurrent protection for stage 1.
1. Check for any possible dependency conditions and simulate as appropriate.
2. In the CONFIGURATION column, disable all protection elements other than the one being tested.
3. Make a note of which elements need to be re-enabled after testing.
4. Connect the test circuit.
5. Perform the test.
6. Check the operating time.

16.3 CONNECTING THE TEST CIRCUIT

1. Use the PSL to determine which output relay will operate when an overcurrent trip occurs.
2. Use the output relay assigned to Trip Output A.
3. Use the PSL to map the protection stage under test directly to an output relay.

Note:
If using the default PSL, use output relay 3 as this is already mapped to the DDB signal Trip Command Out.

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Note:
If the timer does not stop when the current is applied and stage 1 has been set for directional operation, the connections may
be incorrect for the direction of operation set. Try again with the current connections reversed.

16.4 PERFORMING THE TEST

1. Ensure that the timer is reset.
2. Apply a current of twice the setting shown in the I>1 Current Set cell in the OVERCURRENT column.
3. Note the time displayed when the timer stops.
4. Check that the red trip LED has illuminated.

16.5 CHECK THE OPERATING TIME

Check that the operating time recorded by the timer is within the range shown below.
For all characteristics, allowance must be made for the accuracy of the test equipment being used.
Operating time at twice current setting and time multiplier/
Characteristic
time dial setting of 1.0
Nominal (seconds) Range (seconds)
DT I>1 Time Delay setting Setting ±2%
IEC S Inverse 10.03 9.53 - 10.53
IEC V Inverse 13.50 12.83 - 14.18
IEC E Inverse 26.67 24.67 - 28.67
UK LT Inverse 120.00 114.00 - 126.00
IEEE M Inverse 3.8 3.61 - 4.0
IEEE V Inverse 7.03 6.68 - 7.38
IEEE E Inverse 9.50 9.02 - 9.97
US Inverse 2.16 2.05 - 2.27
US ST Inverse 12.12 11.51 - 12.73

Note:
With the exception of the definite time characteristic, the operating times given are for a Time Multiplier Setting (TMS) or Time
Dial Setting (TDS) of 1. For other values of TMS or TDS, the values need to be modified accordingly.

Note:
For definite time and inverse characteristics there is an additional delay of up to 0.02 second and 0.08 second respectively.
You may need to add this the IED's acceptable range of operating times.

Caution:
On completion of the tests, you must restore all settings to customer specifications.

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17 SYSTEM CHECK AND CHECK SYNCHRONISM

This function performs a comparison between the line voltage and the bus voltage.
There are two voltage inputs to compare:
● one from the voltage transformer input from the line side of the circuit breaker (Main VT)
● one from the VT on the bus side of the circuit breaker (CS VT).

In most cases the line VT input is three phase, whereas the bus VTs are single phase.
The bus VT inputs are normally single phase so the system voltage checks are made on single phases and the VT
may be connected to either a phase-to-phase or phase to neutral voltage.
For these reasons, the IED has to be programmed with the appropriate connection. The CS Input setting in the CT
AND VT RATIOS column can be set to A-N, B-N, C-N, A-B, B-C or C-A according to the application.
The single-phase bus VT inputs each have associated phase shift and voltage magnitude compensation settings
to compensate for healthy voltage angle and magnitude differences between the check sync VT input and the
selected main VT reference phase. These are:
● CS VT Ph Shift and CS VT Mag
Any voltage measurements or comparisons using bus VT inputs are made using the compensated values.
Each circuit breaker controlled can have two stages of check synchronism enabled according to the settings:
● System Checks, CS1 Status and CS2 Status
When the system voltage check conditions are satisfied, the relevant DDB signals are asserted high as follows:
● DDB (883): Check Sync 1 OK
● DDB (884): Check Sync 2 OK

These DDB signals should be mapped to the monitor/download port and used to indicate that the system check
synchronism condition has been satisfied.

17.1 CHECK SYNCHRONISM PASS

1. Taking note of the check synchronism settings, identify the appropriate VT input terminals and inject voltage
signals that should satisfy the system voltage check synchronism criteria.
2. Check that the DDB signals are asserted high.

17.2 CHECK SYNCHRONISM FAIL

1. Change the voltage signals so that the criteria are not satisfied
2. Check that the appropriate DDB signals are driven low

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18 CHECK TRIP AND AUTORECLOSE CYCLE

If the auto-reclose function is being used, the circuit breaker trip and auto reclose cycle can be tested
automatically by using the application-specific settings.
To test the trip and close operation without operating the breaker, the following conditions must be satisfied:
● The CB Healthy DDB signal should either not be mapped, or if it is mapped it must be asserted high.
● The CB status inputs (52A, etc.) should either not be mapped, or if they are mapped they should be activated
to mimic the circuit breaker operation.
● Some models can be configured for single-pole tripping. If configured for single pole tripping, either set
CT/VT RATIO > VT Connected to No, or apply appropriate voltage signals to prevent the pole dead logic from
converting to 3-pole tripping.

1. To test the first three-phase auto-reclose cycle, set COMMISSION TESTS > Test Autoreclose to Trip 3
Pole. The IED performs a trip/reclose cycle.
2. Repeat this operation to test the subsequent three-phase auto-reclose cycles.
3. Check all output relays (used for such as circuit breaker tripping and closing, or blocking other devices)
operate at the correct times during the trip/close cycle.
Check the auto-reclose cycles for single phase trip conditions one at a time by sequentially setting COMMISSION
TESTS > Test Autoreclose to Trip Pole A, Trip Pole B and Trip Pole C.

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19 END-TO-END COMMUNICATION TESTS

If the IED is being used in a scheme with InterMiCOM64 communications you must perform end-to-end testing of
the protection communications channels.
In this section all loopbacks are removed and satisfactory communications between line ends of the IEDs in the
scheme are confirmed.

Note:
End-to-end communication requires a working telecommunication channel between line ends (which may be a multiplexed
link or may be a direct connection). If the telecommunication channel is not available, it is not possible to establish end-to end
communication. Unless otherwise directed by local operational practise, follow the instructions in this section so the scheme
is ready for full operation when the telecommunications channels become available.

Note:
The trip circuit should remain isolated during these checks to prevent accidental operation of the associated circuit breaker.

19.1 REMOVE LOCAL LOOPBACKS

As well as removing the loopback, this section checks that all wiring and optical fibre are reconnected. If P592 or
P593 interface units are installed the application-specific settings are also applied.
1. Check the alarm records to ensure that no communications failure alarms have occurred while the
loopback test was in progress. If it was necessary to ‘fail’ the communications while testing the non-current
differential elements, observe the communications behaviour for a few minutes before removing the
loopbacks.
2. After you are satisfied with the communications behaviour in loopback, set COMMISSION TESTS > Test Mode
and Test Loopback to Disabled.

Note:
Most of the required optical signal power levels have already been measured and recorded. If all signalling uses P59x
interface units, no further measurements are required. If, however, direct fibre or C37.94 communications are used, further
measurements are needed.

19.1.1 RESTORING DIRECT FIBRE CONNECTIONS

When restoring direct fibre connections, check the optical power level received from the remote IED(s).
1. Remove the loopback test fibres and at both ends of each channel used, reconnect the fibre optic cables for
communications between IEDs.
2. For each channel fitted, remove the fibre connecting to the optical receiver (RX).
3. Using an optical power meter measure the strength of the signal received from the remote IED. The
measurements should be within -25.4 dBm and -16.8 dBm for 850 nm fibre connections and between
-37 dBm and -7 dBm for 1300 nm fibre connections
4. Record the received power level(s).
5. Reconnect the fibre(s) to the IED receiver(s).

Warning:
NEVER look directly into the transmit port or the end of an optical fibre, as this could
severely damage your eyes.

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19.1.2 RESTORING C37.94 FIBRE CONNECTIONS

When restoring C37.94 fibre connections, check the optical power level received from both the IED and the C37.94
multiplexer.
1. Remove the loopback test fibres and at both ends of each channel used.
2. Reconnect the fibre optic cables for communications between IEDs and the C37.94 compatible multiplexer.
3. Check that the value received from the IED at the C37.94 multiplexer, as well as that received by the IED
from the C37.94 multiplexer are between -25.4 dBm (min) and -16.8 dBm (max).
4. Record the received power level(s).
5. Reconnect the fibre(s) to the IED receiver(s).

Warning:
NEVER look directly into the transmit port or the end of an optical fibre, as this could
severely damage your eyes.

19.1.3 COMMUNICATIONS USING P59X INTERFACE UNITS

If external wiring has been removed to facilitate testing, ensure that it is replaced in accordance with the relevant
connection diagram or scheme diagram.

For the P591:

1. Check that all the cabling is correct.
2. Verify that the Healthy LED is on.

For the P592:

1. Set the V.35 LOOPBACK switch to the 0 position.
2. Set the CLOCK SWITCH, DSR, CTS and DATA RATE switches on each unit to the positions required for the
specific application.
3. Ensure the OPTO LOOPBACK switch is in the 0 position.
4. If applicable, replace the secondary front cover.

For the P593:

1. Set the X.21 LOOPBACK switch to the OFF position.
2. Ensure the OPTO LOOPBACK switch is also in the OFF position.
3. If applicable, replace the secondary front cover.

19.2 REMOVE REMOTE LOOPBACKS

Remove loopbacks at remote terminal connected to channel 1 and channel 2 by repeating the instructions for
local loopback removal.

19.3 VERIFY COMMUNICATION BETWEEN IEDS

Communications statistics and status – non GPS synchronised.

1. Reset any alarm indications and check that no further communications failure alarms are raised.
2. Check channel status and propagation delays in MEASUREMENTS 4 column for channel 1 (and channel 2
where fitted).
3. Check that the first two bits in ‘Channel Status’ (Rx and Tx) are displaying ‘1’ (11************ where *
indicates a ‘don’t care’ state).

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4. Clear the statistics and record the number of valid messages and the number of errored messages after a
minimum period of 1 hour.
5. Check that the ratio of errored/good messages is better than 10-4.
6. Record the measured message propagation delays for channel 1, and channel 2 (if fitted).

Communications statistics and status – GPS synchronised with P594

1. Reset any alarm indications and check that no further communications failure alarms are raised.
2. Check channel status and propagation delays in the MEASUREMENTS 4 column for channel 1 (and channel
2 where fitted).
3. Check that the first four bits in ‘Channel Status’ (Rx, Tx, Local GPS, and remote GPS) are displaying ‘1’
(1111********** where * indicates a ‘don’t care’ state).
4. Clear the statistics and record the number of valid messages and the number of errored messages after a
minimum period of 1 hour.
5. Check that the ratio of errored/good messages is better than 10-4. Record the measured message
propagation delays for channel 1, and channel 2 (if fitted).

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20 END-TO-END SCHEME TESTS

This section aims to check that the signalling channel is able to transmit the ON/OFF signals used in aided
schemes between the remote line ends.
Before testing, check that the channel is healthy. For example, if a power line carrier link is being used, it may not
be possible to perform the tests until the protected circuit is in service.

20.1 AIDED SCHEME 1

Aided Scheme 1 can be tested by operating output contacts to mimic the transmission of an aided channel signal.
For these tests, an engineer needs to be present at both ends of the line - at the local end to send aided signals,
and at the remote end to observe that the signals are received. A telephone link between the two commissioning
engineers is also necessary, to allow conversation.
1. Put the IED in test mode by setting COMMISSION TESTS > Test Mode to Blocked.
2. Record which contact is assigned as the Signal Send 1 output
3. Select this output contact as the one to test and advise the engineer at the remote end that the contact is
about to be tested.

20.1.1 PREPARATION AT REMOTE END

At the remote end, the engineer must confirm the assignment of the Monitor Bits in the COMMISSION TESTS
column in the menu, to be able to see the aided channel on arrival.
Scroll down and ensure that the Monitor Bit 1 cell is set to DDB493 and that the Monitor Bit 5 cell is set to
DDB507. The Test Port Status cell appropriately sets or resets the bits that now represent Aided 1 Scheme Receive
(DDB493), and Aided 2 Scheme Receive (DDB507), with the rightmost bit representing Aided Channel 1. From now
on the engineer at the remote end should monitor the indication of the Test Port Status cell.

20.1.2 PERFORMING THE TEST

1. At the local end, set the COMMISSION TESTS > Contact Test to Apply Test.
2. Reset the output relay by setting COMMISSION TESTS > Contact Test to Remove Test.
3. Check with the engineer at the remote end that the Aided Channel 1 signal did change state as expected.
The Test Port Status cell should have responded as in the table below
DDB No. 507 493
Monitor Bit 8 7 6 5 4 3 2 1
Contact Test OFF X X X X X X X 0
Contact Test Applied (ON) X X X X X X X 1
Test OFF X X X X X X X 0
X = Don't Care
Now return the IED to service by setting COMMISSION TESTS > Test Mode to Disabled.

20.1.3 CHANNEL CHECK IN THE OPPOSITE DIRECTION

Repeat the aided scheme 1 test procedure, but this time to check that the channel responds correctly when keyed
from the remote end. The remote end commissioning engineer should perform the contact test, with the Monitor
Option observed at the local end.

20.2 AIDED SCHEME 2

1. If applicable, repeat the test for Aided Channel 2.

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2. Return the device to service by setting COMMISSION TESTS > Test Mode to Disabled.

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21 ONLOAD CHECKS

Warning:
Onload checks are potentially very dangerous and may only be carried out by
qualified and authorised personnel.

Onload checks can only be carried out if there are no restrictions preventing the energisation of the plant, and the
other devices in the group have already been commissioned.
Remove all test leads and temporary shorting links, then replace any external wiring that has been removed to
allow testing.

Warning:
If any external wiring has been disconnected for the commissioning process, replace
it in accordance with the relevant external connection or scheme diagram.

21.1 CONFIRM VOLTAGE CONNECTIONS

1. Using a multimeter, measure the voltage transformer secondary voltages to ensure they are correctly rated.
2. Check that the system phase rotation is correct using a phase rotation meter.
3. Compare the values of the secondary phase voltages with the measured voltage magnitude values, which
can be found in the MEASUREMENTS 1 menu column.

Cell in MEASUREMENTS 1 Column Corresponding VT ratio in CT/VT RATIOS column

VAB MAGNITUDE
VBC MAGNITUDE
VCA MAGNITUDE Main VT Primary / Main VT Sec'y
VAN MAGNITUDE
VBN MAGNITUDE
VCN MAGNITUDE
C/S Voltage Mag CS VT Primary / CS VT Secondary

If the Local Values cell is set to Secondary, the values displayed should be equal to the applied secondary
voltage. The values should be within 1% of the applied secondary voltages. However, an additional allowance must
be made for the accuracy of the test equipment being used.
If the Local Values cell is set to Primary, the values displayed should be equal to the applied secondary voltage
multiplied the corresponding voltage transformer ratio set in the CT & VT RATIOS column. The values should be
within 1% of the expected values, plus an additional allowance for the accuracy of the test equipment being used.

21.2 CONFIRM CURRENT CONNECTIONS

1. Measure the current transformer secondary values for each input either by:
a. reading from the device's HMI panel (providing it has first been verified by a secondary injection test)
b. using a current clamp meter
2. Check that the current transformer polarities are correct by measuring the phase angle between the
current and voltage, either against a phase meter already installed on site and known to be correct or by
determining the direction of power flow by contacting the system control centre.
3. Ensure the current flowing in the neutral circuit of the current transformers is negligible.

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If the Local Values cell is set to Secondary, the values displayed should be equal to the applied secondary
voltage. The values should be within 1% of the applied secondary voltages. However, an additional allowance must
be made for the accuracy of the test equipment being used.
If the Local Values cell is set to Primary, the values displayed should be equal to the applied secondary voltage
multiplied the corresponding voltage transformer ratio set in the CT & VT RATIOS column. The values should be
within 1% of the expected values, plus an additional allowance for the accuracy of the test equipment being used.

21.3 MEASURE CAPACITIVE CHARGING CURRENT

1. With the feeder energised from one end only, compare the local and remote measured currents in the
MEASUREMENTS 3 column to confirm that the feeder capacitive charging current is similar to that expected
on all three phases.
2. Check that GROUP 1 CURRENT DIFF > Phase Is1 is set higher than 2.5 times the capacitive charging current.
If this is not the case, notify those concerned of the setting required to ensure stability under normal
operating conditions.

21.4 CHECK DIFFERENTIAL CURRENT

With the feeder supplying load current, check that the measurements in the MEASUREMENTS 3 column are as
expected and that the differential current is similar to the value of capacitive charging current previously
measured for all.

21.5 CHECK CURRENT TRANSFORMER POLARITY

The load current should be high enough to be certain that the main current transformers are connected with the
same polarity to each device in the group. On cable circuits with high line capacitance, it is possible that the load
current could be masked by the capacitive charging current.
1. If necessary reverse the connections to the main current transformers and check that the ‘A’ current
differential in MEASUREMENTS 3 > IA Differential cell is significantly higher than for the normal connection.
If the differential current falls with the connection reversed, the main current transformers may not be
correct and should be thoroughly checked.
2. Repeat the test for phases B and C using the IB Differential and IC Differential cells respectively.

21.6 ON-LOAD DIRECTIONAL TEST

This test ensures that directional overcurrent and fault locator functions have the correct forward/reverse
response to fault and load conditions. For this test you must first know the actual direction of power flow on the
system. If you do not already know this you must determine it using adjacent instrumentation or protection
already in-service.
● For load current flowing in the Forward direction (power export to the remote line end), the A Phase Watts
cell in the MEASUREMENTS 2 column should show positive power signing.
● For load current flowing in the Reverse direction (power import from the remote line end), the A Phase
Watts cell in the MEASUREMENTS 2 column should show negative power signing.

Note:
This check applies only for Measurement Modes 0 (default), and 2. This should be checked in the MEASURE’T SETUP column
(Measurement Mode = 0 or 2). If measurement modes 1 or 3 are used, the expected power flow signing would be opposite to
that shown above.

In the event of any uncertainty, check the phase angle of the phase currents with respect to their phase voltage.

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22 FINAL CHECKS
1. Remove all test leads and temporary shorting leads.
2. If you have had to disconnect any of the external wiring in order to perform the wiring verification tests,
replace all wiring, fuses and links in accordance with the relevant external connection or scheme diagram.
3. The settings applied should be carefully checked against the required application-specific settings to ensure
that they are correct, and have not been mistakenly altered during testing.
4. Ensure that all protection elements required have been set to Enabled in the CONFIGURATION column.
5. Ensure that the IED has been restored to service by checking that the Test Mode cell in the COMMISSION
TESTS column is set to Disabled.
6. If the IED is in a new installation or the circuit breaker has just been maintained, the circuit breaker
maintenance and current counters should be zero. These counters can be reset using the Reset All Values
cell. If the required access level is not active, the device will prompt for a password to be entered so that the
setting change can be made.
7. If the menu language has been changed to allow accurate testing it should be restored to the customer’s
preferred language.
8. If a P991/MMLG test block is installed, remove the P992/MMLB test plug and replace the cover so that the
protection is put into service.
9. Ensure that all event records, fault records, disturbance records, alarms and LEDs and communications
statistics have been reset.

Note:
Remember to restore the language setting to the customer’s preferred language on completion.

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23 COMMMISSIONING THE P59X

If you are setting up a scheme, which involves a P59x device, you will need to commission the P59x too. The
following instructions describe the commissioning procedure for a P59x.

23.1 VISUAL INSPECTION

Warning:
Check the rating information under the top access cover on the front of the IED.

Warning:
Check that the IED being tested is correct for the line or circuit.

Warning:
Record the circuit reference and system details.

Warning:
Check the CT secondary current rating and record the CT tap which is in use.

Carefully examine the IED to see that no physical damage has occurred since installation.
Ensure that the case earthing connections (bottom left-hand corner at the rear of the IED case) are used to
connect the IED to a local earth bar using an adequate conductor.

23.2 INSULATION
Insulation resistance tests are only necessary during commissioning if explicitly requested.
Isolate all wiring from the earth and test the insulation with an electronic or brushless insulation tester at a DC
voltage not exceeding 500 V. Terminals of the same circuits should be temporarily connected together.
The insulation resistance should be greater than 100 MW at 500 V.
On completion of the insulation resistance tests, ensure all external wiring is correctly reconnected to the IED.

Note:
The V.35 circuits and the X.21 circuits of the P592 and P593 respectively are isolated from all other circuits but are electrically
connected to the outer case. The circuits must therefore not be insulation or impulse tested to the case.

23.3 EXTERNAL WIRING

Caution:
Check that the external wiring is correct according to the relevant IED and scheme
diagrams. Ensure that phasing/phase rotation appears to be as expected.

23.4 P59X AUXILIARY SUPPLY

P591 devices operate from a DC auxiliary supply within the range of 19 V to 65 V for a 24 - 48 V version and 87.5 V
to 300 V for a 110 - 250 V version.

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P592 and P593 units operate from a DC auxiliary supply within the range of 19 V to 300 V.
Without energizing the device, measure the auxiliary supply to ensure it is within the operating range.
The devices are designed to withstand an AC ripple component of up to 12% of the normal DC auxiliary supply.
However, in all cases the peak value of the DC supply must not exceed the maximum specified operating limit.

Warning:
Do not energise the device or interface unit using the battery charger with the
battery disconnected as this can irreparably damage the power supply circuitry.

23.5 P59X LEDS

On power up the green ‘SUPPLY HEALTHY’ LED should be permanently illuminated, indicating that the device is
healthy.

P592 only
The four red LEDs can be tested by appropriate setting of the DIL switches on the front plate. Set the data rate
switch according to the communication channel bandwidth available. Set all other switches to 0. To illuminate the
‘DSR OFF’ and ‘CTS OFF’ LED’s, disconnect the V.35 connector from the rear of the P592 and set the ‘DSR’ and ‘CTS’
switches to ‘0’. The ‘OPTO LOOPBACK’ and ‘V.35 LOOPBACK’ LEDs can be illuminated by setting their corresponding
switches to ‘1’.
Once operation of the LEDs has been established set all DIL switches, except for the ‘OPTO LOOPBACK’ switch, to ‘0’
and reconnect the V.35 connector.

P593 only
Set the ‘X.21 LOOPBACK’ switch to ‘ON’. The green ‘CLOCK’ and red ‘X.21 LOOPBACK’ LED’s should illuminate. Reset
the ‘X.21 LOOPBACK’ switch to the ‘OFF’ position.
Set the ‘OPTO LOOPBACK’ switch to ‘ON’. The red ‘OPTO LOOPBACK’ LED should illuminate. Do not reset the “OPTO
LOOPBACK’ switch as it is required in this position for the next test.

23.6 RECEIVED OPTICAL SIGNAL LEVEL

1. With an optical cable connected to the P54x optical transmitter, disconnect the other end of the cable from
the P59x receiver (Rx) and use an optical power meter to measure the received signal strength. The value
should be in the range -16.8 dBm to -25.4 dBm.
2. Record the measured value and replace the connector to the P59x receiver.

Warning:
NEVER look directly into the transmit port or the end of an optical fibre, as this could
severely damage your eyes.

23.7 OPTICAL TRANSMITTER LEVEL

1. Using an appropriate fibre-optic cable, connect the optical transmitter (Tx) to an optical power meter.
2. Check that the average power transmitted is within the range -16.8 dBm to -22.8 dBm.
3. Record the transmit power level.
4. Connect the appropriate optical fibre to connect the P591 transmitter to the IED's optical receiver
5. Return to the IED

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23.8 LOOPBACK TEST

P591
It is necessary to loop the transmitted electrical G.703 signal presented on terminals 3 and 4 of the P591 to the
received signal presented on terminals 7 and 8.
If test links have been designed into the scheme to facilitate this they should be used. Alternatively, remove any
external wiring from terminals 3, 4, 7 and 8 at the rear of each P591 unit. Loopback the G.703 signals on each
device by connecting a wire link between terminals 3 and 7, and a second wire between terminals 4 and 8.

P592
With the ‘OPTO LOOPBACK’ switch in the ‘1’ position, the receive and transmit optical ports are connected together.
This allows the optical fibre communications between the IED and the P592 to be tested, but not the internal
circuitry of the P592 itself.

P593
Set the ‘OPTO LOOPBACK’ switch to ‘OFF’ and ‘X.21 LOOPBACK’ switch to ‘ON’ respectively. With the ‘X.21
LOOPBACK’ switch in this position the ‘Receive Data’ and ‘Transmit Data’ lines of the X.21 communication interface
are connected together. This allows the optical fibre communications between the IED and the P593, and the
internal circuitry of the P593 itself to be tested.

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MAINTENANCE AND TROUBLESHOOTING

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1 CHAPTER OVERVIEW
The Maintenance and Troubleshooting chapter provides details of how to maintain and troubleshoot products
based on the Px4x and P40Agile platforms. Always follow the warning signs in this chapter. Failure to do so may
result injury or defective equipment.

Caution:
Before carrying out any work on the equipment you should be familiar with the
contents of the Safety Section or the Safety Guide SFTY/4LM and the ratings on the
equipment’s rating label.

The troubleshooting part of the chapter allows an error condition on the IED to be identified so that appropriate
corrective action can be taken.
If the device develops a fault, it is usually possible to identify which module needs replacing. It is not possible to
perform an on-site repair to a faulty module.
If you return a faulty unit or module to the manufacturer or one of their approved service centres, you should
include a completed copy of the Repair or Modification Return Authorization (RMA) form.
This chapter contains the following sections:
Chapter Overview 699
Maintenance 700
Troubleshooting 708

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2 MAINTENANCE

2.1 MAINTENANCE CHECKS

In view of the critical nature of the application, General Electric products should be checked at regular intervals to
confirm they are operating correctly. General Electric products are designed for a life in excess of 20 years.
The devices are self-supervising and so require less maintenance than earlier designs of protection devices. Most
problems will result in an alarm, indicating that remedial action should be taken. However, some periodic tests
should be carried out to ensure that they are functioning correctly and that the external wiring is intact. It is the
responsibility of the customer to define the interval between maintenance periods. If your organisation has a
Preventative Maintenance Policy, the recommended product checks should be included in the regular program.
Maintenance periods depend on many factors, such as:
● The operating environment
● The accessibility of the site
● The amount of available manpower
● The importance of the installation in the power system
● The consequences of failure

Although some functionality checks can be performed from a remote location, these are predominantly restricted
to checking that the unit is measuring the applied currents and voltages accurately, and checking the circuit
breaker maintenance counters. For this reason, maintenance checks should also be performed locally at the
substation.

Caution:
Before carrying out any work on the equipment you should be familiar with the
contents of the Safety Section or the Safety Guide SFTY/4LM and the ratings on the
equipment’s rating label.

2.1.1 ALARMS
First check the alarm status LED to see if any alarm conditions exist. If so, press the Read key repeatedly to step
through the alarms.
After dealing with any problems, clear the alarms. This will clear the relevant LEDs.

2.1.2 OPTO-ISOLATORS
Check the opto-inputs by repeating the commissioning test detailed in the Commissioning chapter.

2.1.3 OUTPUT RELAYS

Check the output relays by repeating the commissioning test detailed in the Commissioning chapter.

2.1.4 MEASUREMENT ACCURACY

If the power system is energised, the measured values can be compared with known system values to check that
they are in the expected range. If they are within a set range, this indicates that the A/D conversion and the
calculations are being performed correctly. Suitable test methods can be found in Commissioning chapter.
Alternatively, the measured values can be checked against known values injected into the device using the test
block, (if fitted) or injected directly into the device's terminals. Suitable test methods can be found in the
Commissioning chapter. These tests will prove the calibration accuracy is being maintained.

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2.2 REPLACING THE DEVICE

If your product should develop a fault while in service, depending on the nature of the fault, the watchdog
contacts will change state and an alarm condition will be flagged. In the case of a fault, you can replace either the
complete device or just the faulty PCB, identified by the in-built diagnostic software.
If possible you should replace the complete device, as this reduces the chance of damage due to electrostatic
discharge and also eliminates the risk of fitting an incompatible replacement PCB. However, we understand it may
be difficult to remove an installed product and you may be forced to replace the faulty PCB on-site. The case and
rear terminal blocks are designed to allow removal of the complete device, without disconnecting the scheme
wiring.

Caution:
Replacing PCBs requires the correct on-site environment (clean and dry) as well as
suitably trained personnel.

Caution:
If the repair is not performed by an approved service centre, the warranty will be
invalidated.

Caution:
Before carrying out any work on the equipment, you should be familiar with the
contents of the Safety Information section of this guide or the Safety Guide SFTY/4LM,
as well as the ratings on the equipment’s rating label. This should ensure that no
damage is caused by incorrect handling of the electronic components.

Warning:
Before working at the rear of the device, isolate all voltage and current supplying it.

Note:
The current transformer inputs are equipped with integral shorting switches which will close for safety reasons, when the
terminal block is removed.

To replace the complete device:

1. Carefully disconnect the cables not connected to the terminal blocks (e.g. IRIG-B, fibre optic cables, earth),
as appropriate, from the rear of the device.
2. Remove the terminal block screws using a magnetic screwdriver to minimise the risk of losing the screws or
leaving them in the terminal block.
3. Without exerting excessive force or damaging the scheme wiring, pull the terminal blocks away from their
internal connectors.
4. Remove the terminal block screws that fasten the device to the panel and rack. These are the screws with
the larger diameter heads that are accessible when the access covers are fitted and open.
5. Withdraw the device from the panel and rack. Take care, as the device will be heavy due to the internal
transformers.
6. To reinstall the device, follow the above instructions in reverse, ensuring that each terminal block is
relocated in the correct position and the chassis ground, IRIG-B and fibre optic connections are replaced.
The terminal blocks are labelled alphabetically with ‘A’ on the left hand side when viewed from the rear.
Once the device has been reinstalled, it should be re-commissioned as set out in the Commissioning chapter.

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Caution:
If the top and bottom access covers have been removed, some more screws with
smaller diameter heads are made accessible. Do NOT remove these screws, as they
secure the front panel to the device.

Note:
There are four possible types of terminal block: RTD/CLIO input, heavy duty, medium duty, and MiDOS. The terminal blocks are
fastened to the rear panel with slotted or cross-head screws depending on the type of terminal block. Not all terminal block
types are present on all products.

Figure 322: Possible terminal block types

2.3 REPAIRING THE DEVICE

If your product should develop a fault while in service, depending on the nature of the fault, the watchdog
contacts will change state and an alarm condition will be flagged. In the case of a fault, either the complete unit or
just the faulty PCB, identified by the in-built diagnostic software, should be replaced.
Replacement of printed circuit boards and other internal components must be undertaken by approved Service
Centres. Failure to obtain the authorization of after-sales engineers prior to commencing work may invalidate the
product warranty.
We recommend that you entrust any repairs to Automation Support teams, which are available world-wide.

2.4 REMOVING THE FRONT PANEL

Warning:
Before removing the front panel to replace a PCB, you must first remove the auxiliary
power supply and wait 5 seconds for the internal capacitors to discharge. You should
also isolate voltage and current transformer connections and trip circuit.

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Caution:
Before removing the front panel, you should be familiar with the contents of the Safety
Information section of this guide or the Safety Guide SFTY/4LM, as well as the ratings
on the equipment’s rating label.

To remove the front panel:

1. Open the top and bottom access covers. You must open the hinged access covers by more than 90° before
they can be removed.
2. If fitted, remove the transparent secondary front cover.
3. Apply outward pressure to the middle of the access covers to bow them and disengage the hinge lug, so the
access cover can be removed. The screws that fasten the front panel to the case are now accessible.
4. Undo and remove the screws. The 40TE case has four cross-head screws fastening the front panel to the
case, one in each corner, in recessed holes. The 60TE/80TE cases have an additional two screws, one
midway along each of the top and bottom edges of the front plate.
5. When the screws have been removed, pull the complete front panel forward to separate it from the metal
case. The front panel is connected to the rest of the circuitry by a 64-way ribbon cable.
6. The ribbon cable is fastened to the front panel using an IDC connector; a socket on the cable and a plug
with locking latches on the front panel. Gently push the two locking latches outwards which eject the
connector socket slightly. Remove the socket from the plug to disconnect the front panel.

Caution:
Do not remove the screws with the larger diameter heads which are accessible when
the access covers are fitted and open. These screws hold the relay in its mounting
(panel or cubicle).

Caution:
The internal circuitry is now exposed and is not protected against electrostatic
discharge and dust ingress. Therefore ESD precautions and clean working conditions
must be maintained at all times.

2.5 REPLACING PCBS

1. To replace any of the PCBs, first remove the front panel.
2. Once the front panel has been removed, the PCBs are accessible. The numbers above the case outline
identify the guide slot reference for each printed circuit board. Each printed circuit board has a label stating
the corresponding guide slot number to ensure correct relocation after removal. To serve as a reminder of
the slot numbering there is a label on the rear of the front panel metallic screen.
3. Remove the 64-way ribbon cable from the PCB that needs replacing
4. Remove the PCB in accordance with the board-specific instructions detailed later in this section.

Note:
To ensure compatibility, always replace a faulty PCB with one of an identical part number.

2.5.1 REPLACING THE MAIN PROCESSOR BOARD

The main processor board is situated in the front panel. This board contains application-specific settings in its non-
volatile memory. You may wish to take a backup copy of these settings. This could save time in the re-
commissioning process.

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To replace the main processor board:

1. Remove front panel.
2. Place the front panel with the user interface face down and remove the six screws from the metallic screen,
as shown in the figure below. Remove the metal plate.
3. Remove the two screws either side of the rear of the battery compartment recess. These are the screws
that hold the main processor board in position.
4. Carefully disconnect the ribbon cable. Take care as this could easily be damaged by excessive twisting.
5. Replace the main processor board
6. Reassemble the front panel using the reverse procedure. Make sure the ribbon cable is reconnected to the
main processor board and that all eight screws are refitted.
7. Refit the front panel.
8. Refit and close the access covers then press the hinge assistance T-pieces so they click back into the front
panel moulding.
9. Once the unit has been reassembled, carry out the standard commissioning procedure as defined in the
Commissioning chapter.

Note:
After replacing the main processor board, all the settings required for the application need to be re-entered. This may be done
either manually or by downloading a settings file.

V01601

Figure 323: Front panel assembly

2.5.2 REPLACEMENT OF COMMUNICATIONS BOARDS

Most products will have at least one communications board of some sort fitted. There are several different boards
available offering various functionality, depending on the application. Some products may even be fitted two
boards of different types.
To replace a faulty communications board:
1. Remove front panel.
2. Disconnect all connections at the rear.
3. The board is secured in the relay case by two screws, one at the top and another at the bottom. Remove
these screws carefully as they are not captive in the rear panel.
4. Gently pull the communications board forward and out of the case.

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5. Before fitting the replacement PCB check that the number on the round label next to the front edge of the
PCB matches the slot number into which it will be fitted. If the slot number is missing or incorrect, write the
correct slot number on the label.
6. Fit the replacement PCB carefully into the correct slot. Make sure it is pushed fully back and that the
securing screws are refitted.
7. Reconnect all connections at the rear.
8. Refit the front panel.
9. Refit and close the access covers then press the hinge assistance T-pieces so they click back into the front
panel moulding.
10. Once the unit has been reassembled, commission it according to the Commissioning chapter.

2.5.3 REPLACEMENT OF THE INPUT MODULE

Depending on the product, the input module consists of two or three boards fastened together and is contained
within a metal housing. One board contains the transformers and one contains the analogue to digital conversion
and processing electronics. Some devices have an additional auxiliary transformer contained on a third board.
To replace an input module:
1. Remove front panel.
2. The module is secured in the case by two screws on its right-hand side, accessible from the front, as shown
below. Move these screws carefully as they are not captive in the front plate of the module.
3. On the right-hand side of the module there is a small metal tab which brings out a handle (on some
modules there is also a tab on the left). Grasp the handle(s) and pull the module firmly forward, away from
the rear terminal blocks. A reasonable amount of force is needed due to the friction between the contacts of
the terminal blocks.
4. Remove the module from the case. The module may be heavy, because it contains the input voltage and
current transformers.
5. Slot in the replacement module and push it fully back onto the rear terminal blocks. To check that the
module is fully inserted, make sure the v-shaped cut-out in the bottom plate of the case is fully visible.
6. Refit the securing screws.
7. Refit the front panel.
8. Refit and close the access covers then press the hinge assistance T-pieces so they click back into the front
panel moulding.
9. Once the unit has been reassembled, commission it according to the Commissioning chapter.

Caution:
With non-mounted IEDs, the case needs to be held firmly while the module is
withdrawn. Withdraw the input module with care as it suddenly comes loose once the
friction of the terminal blocks is overcome.

Note:
If individual boards within the input module are replaced, recalibration will be necessary. We therefore recommend
replacement of the complete module to avoid on-site recalibration.

2.5.4 REPLACEMENT OF THE POWER SUPPLY BOARD

Caution:
Before removing the front panel, you should be familiar with the contents of the Safety
Information section of this guide or the Safety Guide SFTY/4LM, as well as the ratings
on the equipment’s rating label.

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The power supply board is fastened to an output relay board with push fit nylon pillars. This doubled-up board is
secured on the extreme left hand side, looking from the front of the unit.
1. Remove front panel.
2. Pull the power supply module forward, away from the rear terminal blocks and out of the case. A
reasonable amount of force is needed due to the friction between the contacts of the terminal blocks.
3. Separate the boards by pulling them apart carefully. The power supply board is the one with two large
electrolytic capacitors.
4. Before reassembling the module, check that the number on the round label next to the front edge of the
PCB matches the slot number into which it will be fitted. If the slot number is missing or incorrect, write the
correct slot number on the label
5. Reassemble the module with a replacement PCB. Push the inter-board connectors firmly together. Fit the
four push fit nylon pillars securely in their respective holes in each PCB.
6. Slot the power supply module back into the housing. Push it fully back onto the rear terminal blocks.
7. Refit the front panel.
8. Refit and close the access covers then press the hinge assistance T-pieces so they click back into the front
panel moulding.
9. Once the unit has been reassembled, commission it according to the Commissioning chapter.

2.5.5 REPLACEMENT OF THE I/O BOARDS

There are several different types of I/O boards, which can be used, depending on the product and application.
Some boards have opto-inputs, some have relay outputs and others have a mixture of both.
1. Remove front panel.
2. Gently pull the board forward and out of the case
3. If replacing the I/O board, make sure the setting of the link above IDC connector on the replacement board
is the same as the one being replaced.
4. Before fitting the replacement board check the number on the round label next to the front edge of the
board matches the slot number into which it will be fitted. If the slot number is missing or incorrect, write
the correct slot number on the label.
5. Carefully slide the replacement board into the appropriate slot, ensuring that it is pushed fully back onto the
rear terminal blocks.
6. Refit the front panel.
7. Refit and close the access covers then press at the hinge assistance T-pieces so they click back into the
front panel moulding.
8. Once the unit has been reassembled, commission it according to the Commissioning chapter.

2.6 RECALIBRATION
Recalibration is not needed when a PCB is replaced, unless it is one of the boards in the input module. If any of the
boards in the input module is replaced, the unit must be recalibrated.
Although recalibration is needed when a board inside the input module is replaced, it is not needed if the input
module is replaced in its entirety.
Although it is possible to carry out recalibration on site, this requires special test equipment and software. We
therefore recommend that the work be carried out by the manufacturer, or entrusted to an approved service
centre.

2.7 CHANGING THE BATTERY

Each IED has a battery to maintain status data and the correct time when the auxiliary supply voltage fails. The
data maintained includes event, fault and disturbance records and the thermal state at the time of failure.

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As part of the product's continuous self-monitoring, an alarm is given if the battery condition becomes poor.
Nevertheless, you should change the battery periodically to ensure reliability.
To replace the battery:
1. Open the bottom access cover on the front of the relay.
2. Gently remove the battery. If necessary, use a small insulated screwdriver.
3. Make sure the metal terminals in the battery socket are free from corrosion, grease and dust.
4. Remove the replacement battery from its packaging and insert it in the battery holder, ensuring correct
polarity.
5. Ensure that the battery is held securely in its socket and that the battery terminals make good contact with
the socket terminals.
6. Close the bottom access cover.

Caution:
Only use a type ½AA Lithium battery with a nominal voltage of 3.6 V and safety
approvals such as UL (Underwriters Laboratory), CSA (Canadian Standards Association)
or VDE (Vereinigung Deutscher Elektrizitätswerke).

Note:
Events, disturbance and maintenance records will be lost if the battery is replaced whilst the IED is de-energised.

2.7.1 POST MODIFICATION TESTS

To ensure that the replacement battery maintains the time and status data if the auxiliary supply fails, scroll across
to the DATE AND TIME cell, then scroll down to Battery Status which should read Healthy.

2.7.2 BATTERY DISPOSAL

Dispose of the removed battery according to the disposal procedure for Lithium batteries in the country in which
the relay is installed.

2.8 CLEANING

Warning:
Before cleaning the device, ensure that all AC and DC supplies and transformer
connections are isolated, to prevent any chance of an electric shock while cleaning.

Only clean the equipment with a lint-free cloth dampened with clean water. Do not use detergents, solvents or
abrasive cleaners as they may damage the product's surfaces and leave a conductive residue.

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3 TROUBLESHOOTING

3.1 SELF-DIAGNOSTIC SOFTWARE

The device includes several self-monitoring functions to check the operation of its hardware and software while in
service. If there is a problem with the hardware or software, it should be able to detect and report the problem, and
attempt to resolve the problem by performing a reboot. In this case, the device would be out of service for a short
time, during which the ‘Healthy’ LED on the front of the device is switched OFF and the watchdog contact at the
rear is ON. If the restart fails to resolve the problem, the unit takes itself permanently out of service; the ‘Healthy’
LED stays OFF and watchdog contact stays ON.
If a problem is detected by the self-monitoring functions, the device attempts to store a maintenance record to
allow the nature of the problem to be communicated to the user.
The self-monitoring is implemented in two stages: firstly a thorough diagnostic check which is performed on boot-
up, and secondly a continuous self-checking operation, which checks the operation of the critical functions whilst
it is in service.

3.2 POWER-UP ERRORS

If the IED does not appear to power up, use the following to determine whether the fault is in the external wiring,
auxiliary fuse, IED power supply module or IED front panel.
Test Check Action
Measure the auxiliary voltage on terminals 1 and 2.
Verify the voltage level and polarity against the rating If the auxiliary voltage is correct, go to test 2. Otherwise check the wiring
1
label on the front. and fuses in the auxiliary supply.
Terminal 1 is –dc, 2 is +dc
If the LEDs and LCD backlight switch on, or the contact closes and no error
Check the LEDs and LCD backlight switch on at code is displayed, the error is probably on the main processor board in the
2 power-up. Also check the N/O (normally open) front panel.
watchdog contact for closing. If the LEDs and LCD backlight do not switch on and the contact does not
close, go to test 3.
If there is no field voltage, the fault is probably in the IED power supply
3 Check the output (nominally 48 V DC)
module.

3.3 ERROR MESSAGE OR CODE ON POWER-UP

The IED performs a self-test during power-up. If it detects an error, a message appears on the LCD and the power-
up sequence stops. If the error occurs when the IED application software is running, a maintenance record is
created and the device reboots.
Test Check Action
If the IED locks up and displays an error code permanently, go to test 2.
Is an error message or code permanently displayed
1 If the IED prompts for user input, go to test 4.
during power up?
If the IED reboots automatically, go to test 5.
Record whether the same error code is displayed when the IED is
Record displayed error, and then remove and re-apply rebooted. If no error code is displayed, contact the local service centre
2
IED auxiliary supply. stating the error code and IED information. If the same code is
displayed, go to test 3.

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Test Check Action

Error Code Identification
The following text messages (in English) are displayed if a These messages indicate that a problem has been detected on the IED’s
fundamental problem is detected, preventing the system main processor board in the front panel.
from booting:
Bus Fail – address lines
3 SRAM Fail – data lines
FLASH Fail format error
FLASH Fail checksum
Code Verify Fail
The following hex error codes relate to errors detected in
specific IED modules:
3.1 0c140005/0c0d0000 Input Module (including opto-isolated inputs)
3.2 0c140006/0c0e0000 Output IED Cards
Other error codes relate to hardware or software problems on the main
3.3 The last four digits provide details on the actual error.
processor board. Contact with details of the problem for a full analysis.
The IED displays a message for corrupt settings and The power-up tests have detected corrupted IED settings. Restore the
4 prompts for the default values to be restored for the default settings to allow the power-up to complete, and then reapply
affected settings. the application-specific settings.
Error 0x0E080000, programmable scheme logic error due to excessive
execution time. Restore the default settings by powering up with both
horizontal cursor keys pressed, then confirm restoration of defaults at
The IED resets when the power-up is complete. A record
5 the prompt using the Enter key. If the IED powers up successfully, check
error code is displayed
the programmable logic for feedback paths.
Other error codes relate to software errors on the main processor
board.

3.4 OUT OF SERVICE LED ON AT POWER-UP

Test Check Action

Using the IED menu, confirm the Commission Test or Test If the setting is Enabled, disable the test mode and make sure the Out of
1
Mode setting is Enabled. If it is not Enabled, go to test 2. Service LED is OFF.
Check for the H/W Verify Fail maintenance record. This indicates a
discrepancy between the IED model number and the hardware. Examine
Select the VIEW RECORDS column then view the last
2 the Maint Data; cell. This indicates the causes of the failure using bit
maintenance record from the menu.
fields:
Bit Meaning
The application type field in the model number does not
0
match the software ID
The application field in the model number does not match
1
the software ID
The variant 1 field in the model number does not match the
2
software ID
The variant 2 field in the model number does not match the
3
software ID
The protocol field in the model number does not match the
4
software ID
The language field in the model number does not match the
5
software ID
The VT type field in the model number is incorrect (110 V VTs
6
fitted)
The VT type field in the model number is incorrect (440 V VTs
7
fitted)

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Test Check Action

The VT type field in the model number is incorrect (no VTs
8
fitted)

3.5 ERROR CODE DURING OPERATION

The IED performs continuous self-checking. If the IED detects an error it displays an error message, logs a
maintenance record and after a short delay resets itself. A permanent problem (for example due to a hardware
fault) is usually detected in the power-up sequence. In this case the IED displays an error code and halts. If the
problem was transient, the IED reboots correctly and continues operation. By examining the maintenance record
logged, the nature of the detected fault can be determined.

3.5.1 BACKUP BATTERY

If the IED’s self-check detects a failure of the lithium battery, the IED displays an alarm message and logs a
maintenance record but the IED does not reset.
To prevent the IED from issuing an alarm when there is a battery failure, select DATE AND TIME then Battery Alarm
then Disabled. The IED can then be used without a battery and no battery alarm message appears.

3.6 MAL-OPERATION DURING TESTING

3.6.1 FAILURE OF OUTPUT CONTACTS

An apparent failure of the relay output contacts can be caused by the configuration. Perform the following tests to
identify the real cause of the failure. The self-tests verify that the coils of the output relay contacts have been
energized. An error is displayed if there is a fault in the output relay board.
Test Check Action
If this LED is ON, the relay may be in test mode or the protection has
1 Is the Out of Service LED ON?
been disabled due to a hardware verify error.
Examine the Contact status in the Commissioning If the relevant bits of the contact status are operated, go to test 4; if not,
2
section of the menu. go to test 3.
If the protection element does not operate, check the test is correctly
Examine the fault record or use the test port to check the applied.
3
protection element is operating correctly. If the protection element operates, check the programmable logic to
make sure the protection element is correctly mapped to the contacts.
Using the Commissioning or Test mode function, apply a If the output relay operates, the problem must be in the external wiring
test pattern to the relevant relay output contacts. to the relay. If the output relay does not operate the output relay
4 Consult the correct external connection diagram and use contacts may have failed (the self-tests verify that the relay coil is being
a continuity tester at the rear of the relay to check the energized). Ensure the closed resistance is not too high for the continuity
relay output contacts operate. tester to detect.

3.6.2 FAILURE OF OPTO-INPUTS

The opto-isolated inputs are mapped onto the IED's internal DDB signals using the programmable scheme logic. If
an input is not recognised by the scheme logic, use the Opto I/P Status cell in the COMMISSION TESTS column to
check whether the problem is in the opto-input itself, or the mapping of its signal to the scheme logic functions.
If the device does not correctly read the opto-input state, test the applied signal. Verify the connections to the
opto-input using the wiring diagram and the nominal voltage settings in the OPTO CONFIG column. To do this:
1. Select the nominal voltage for all opto-inputs by selecting one of the five standard ratings in the Global
Nominal V cell.
2. Select Custom to set each opto-input individually to a nominal voltage.
3. Using a voltmeter, check that the voltage on its input terminals is greater than the minimum pick-up level
(See the Technical Specifications chapter for opto pick-up levels).

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If the signal is correctly applied, this indicates failure of an opto-input, which may be situated on standalone opto-
input board, or on an opto-input board that is part of the input module. Separate opto-input boards can simply be
replaced. If, however, the faulty opto-input board is part of the input module, the complete input module should be
replaced. This is because the analogue input module cannot be individually replaced without dismantling the
module and recalibration of the IED.

3.6.3 INCORRECT ANALOGUE SIGNALS

If the measured analogue quantities do not seem correct, use the measurement function to determine the type of
problem. The measurements can be configured in primary or secondary terms.
1. Compare the displayed measured values with the actual magnitudes at the terminals.
2. Check the correct terminals are used.
3. Check the CT and VT ratios set are correct.
4. Check the phase displacement to confirm the inputs are correctly connected.

3.7 COPROCESSOR BOARD FAILURES

If a coprocessor board is used, this may cause the IED to report one or more of the following alarms:
● Signalling failure alarm (on its own)
● C diff failure (on its own)
● Signalling failure and C diff failure together
● Incompatible IED
● Comms changed
● IEEE C37.94 fail

3.7.1 SIGNALLING FAILURE ALARM (ON ITS OWN)

This indicates that there is a problem with one of the fibre-optic signalling channels. This alarm can occur in dual
redundant or three terminal schemes. The fibre may have been disconnected, the device may have been
incorrectly configured at one of the ends, or there is a problem with the communications equipment. Further
information about the status of the signalling channels can be found in MEASUREMENTS 4 column.

3.7.2 C DIFF FAILURE ALARM (ON ITS OWN)

This indicates there is a problem with the Coprocessor board. As a result the current differential/distance
protection is not available and backup protection will operate, if configured to do so. Further information can be
found in the maintenance records.

3.7.3 SIGNALLING FAILURE AND C DIFF FAILURE ALARMS TOGETHER

This indicates that there is a problem with one or both fibre-optic signalling channels. The fibre may have been
disconnected, the device may have been incorrectly configured at one of the ends, or there is a problem with the
communications equipment. As a result the current differential protection is not available and backup protection
will operate, if configured to do so. Further information about the status of the signalling channels can be found in
MEASUREMENTS 4 column.

3.7.4 INCOMPATIBLE IED

This occurs if the IEDs trying to communicate with each other are of incompatible types.

3.7.5 COMMS CHANGED

This indicates that the Comms Mode setting has been changed without a subsequent power off and on.

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3.7.6 IEEE C37.94 FAIL

This indicates a Signal Lost, a Path Yellow (indicating a fault on the communications channel) or a mismatch in the
number of N*64 channels used on either channel 1 or channel 2. Further information can be found in the
MEASUREMENTS 4 column.

3.8 PSL EDITOR TROUBLESHOOTING

A failure to open a connection could be due to one or more of the following:
● The IED address is not valid (this address is always 1 for the front port)
● Password in not valid
● Communication set-up (COM port, Baud rate, or Framing) is not correct
● Transaction values are not suitable for the IED or the type of connection
● The connection cable is not wired correctly or broken
● The option switches on any protocol converter used may be incorrectly set

3.8.1 DIAGRAM RECONSTRUCTION

Although a scheme can be extracted from an IED, a facility is provided to recover a scheme if the original file is
unobtainable.
A recovered scheme is logically correct but much of the original graphical information is lost. Many signals are
drawn in a vertical line down the left side of the canvas. Links are drawn orthogonally using the shortest path from
A to B. Any annotation added to the original diagram such as titles and notes are lost.
Sometimes a gate type does not appear as expected. For example, a single-input AND gate in the original scheme
appears as an OR gate when uploaded. Programmable gates with an inputs-to-trigger value of 1 also appear as
OR gates

3.8.2 PSL VERSION CHECK

The PSL is saved with a version reference, time stamp and CRC check (Cyclic Redundancy Check). This gives a
visual check whether the default PSL is in place or whether a new application has been downloaded.

3.9 REPAIR AND MODIFICATION PROCEDURE

Please follow these steps to return an Automation product to us:
1. Get the Repair and Modification Return Authorization (RMA) form
An electronic version of the RMA form is available from the following web page:
www.gegridsolutions.com/contact
2. Fill in the RMA form
Fill in only the white part of the form.
Please ensure that all fields marked (M) are completed such as:
○ Equipment model
○ Model No. and Serial No.
○ Description of failure or modification required (please be specific)
○ Value for customs (in case the product requires export)
○ Delivery and invoice addresses
○ Contact details
3. Send the RMA form to your local contact
For a list of local service contacts worldwide,visit the following web page:
www.gegridsolutions.com/contact

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4. The local service contact provides the shipping information

Your local service contact provides you with all the information needed to ship the product:
○ Pricing details
○ RMA number
○ Repair centre address
If required, an acceptance of the quote must be delivered before going to the next stage.
5. Send the product to the repair centre
○ Address the shipment to the repair centre specified by your local contact
○ Make sure all items are packaged in an anti-static bag and foam protection
○ Make sure a copy of the import invoice is attached with the returned unit
○ Make sure a copy of the RMA form is attached with the returned unit
○ E-mail or fax a copy of the import invoice and airway bill document to your local contact.

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TECHNICAL SPECIFICATIONS
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1 CHAPTER OVERVIEW
This chapter describes the technical specifications of the product.
This chapter contains the following sections:
Chapter Overview 717
Interfaces 718
Protection Functions 722
Monitoring, Control and Supervision 728
Measurements and Recording 730
Ratings 731
Input / Output Connections 734
Mechanical Specifications 736
Type Tests 737
Environmental Conditions 738
Electromagnetic Compatibility 739
Regulatory Compliance 742

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2 INTERFACES

2.1 FRONT SERIAL PORT

Front serial port (SK1)

Use For local connection to laptop for configuration purposes
Standard EIA(RS)232
Designation SK1
Connector 9 pin D-type female connector
Isolation Isolation to ELV level
Protocol Courier
Constraints Maximum cable length 15 m

2.2 DOWNLOAD/MONITOR PORT

Front download port (SK2)

Use For firmware downloads or monitor connection
Standard Compatible with IEEE1284-A
Designation SK2
Connector 25 pin D-type female connector
Isolation Isolation to ELV level
Protocol Proprietary
Constraints Maximum cable length 3 m

2.3 REAR SERIAL PORT 1

Rear serial port 1 (RP1)

Use For SCADA communications (multi-drop)
Standard EIA(RS)485, K-bus
Connector General purpose block, M4 screws (2 wire)
Cable Screened twisted pair (STP)
Supported Protocols * Courier, IEC-60870-5-103, DNP3.0, MODBUS
Isolation Isolation to SELV level
Constraints Maximum cable length 1000 m
* Not all models support all protocols - see ordering options

2.4 FIBRE REAR SERIAL PORT 1

Optional fibre rear serial port (RP1)

Main Use Serial SCADA communications over fibre
Connector IEC 874-10 BFOC 2.5 –(ST®) (1 each for Tx and Rx)
Fibre type Multimode 50/125 µm or 62.5/125 µm
Supported Protocols Courier, IEC870-5-103, DNP 3.0, MODBUS
Wavelength 850 nm

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2.5 REAR SERIAL PORT 2

Optional rear serial port (RP2)

Use For SCADA communications (multi-drop)
Standard EIA(RS)485, K-bus, EIA(RS)232
Designation SK4
Connector 9 pin D-type female connector
Cable Screened twisted pair (STP)
Supported Protocols Courier
Isolation Isolation to SELV level
Constraints Maximum cable length 1000 m for RS485 and K-bus, 15 m for RS232

2.6 OPTIONAL REAR SERIAL PORT (SK5)

Optional rear serial port for teleprotection

Use For teleprotection in distance products
Standard EIA(RS)232
Designation SK5
Connector 9 pin D-type female connector
Cable Screened twisted pair (STP)
Supported Protocols InterMiCOM (IM)
Isolation Isolation to SELV level
Constraints Maximum cable length 15 m

2.7 IRIG-B (DEMODULATED)

IRIG-B Interface (Demodulated)

Use External clock synchronisation signal
Standard IRIG 200-98 format B00X
Connector BNC
Cable type 50 ohm coaxial
Isolation Isolation to SELV level
Constraints Maximum cable length 10 m
Input signal TTL level
Input impedance 10 k ohm at dc
Accuracy < +/- 1 s per day

2.8 IRIG-B (MODULATED)

IRIG-B Interface (Modulated)

Use External clock synchronisation signal
Standard IRIG 200-98 format B12X
Connector BNC
Cable type 50 ohm coaxial

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IRIG-B Interface (Modulated)

Isolation Isolation to SELV level
Constraints Maximum cable length 10 m
Input signal peak to peak, 200 mV to 20 mV
Input impedance 6 k ohm at 1000 Hz
Accuracy < +/- 1 s per day

2.9 REAR ETHERNET PORT COPPER

Rear Ethernet port using CAT 5/6/7 wiring

Main Use Substation Ethernet communications
Standard IEEE 802.3 10BaseT/100BaseTX
Connector RJ45
Cable type Screened twisted pair (STP)
Isolation 1.5 kV
Supported Protocols IEC 61850, DNP3.0 OE
Constraints Maximum cable length 100 m

2.10 REAR ETHERNET PORT FIBRE

Rear Ethernet port using fibre-optic cabling

Main Use Substation Ethernet communications
Connector IEC 874-10 BFOC 2.5 –(ST®) (1 each for Tx and Rx)
Standard IEEE 802.3 100 BaseFX
Fibre type Multimode 50/125 µm or 62.5/125 µm
Supported Protocols IEC 61850, DNP3.0
Rapid spanning tree protocol (RSTP)
Self-healing protocol (SHP)
Optional Redundancy Protocols Supported
Dual homing protocol (DHP)
Parallel Redundancy Protocol (PRP)
Wavelength 1300 nm

2.10.1 100 BASE FX RECEIVER CHARACTERISTICS

Parameter Sym Min. Typ. Max. Unit

Input Optical Power Minimum at
PIN Min. (W) -33.5 –31 dBm avg.
Window Edge
Input Optical Power Minimum at
PIN Min. (C) -34.5 -31.8 Bm avg.
Eye Center
Input Optical Power Maximum PIN Max. -14 -11.8 dBm avg.
Conditions: TA = 0°C to 70°C

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2.10.2 100 BASE FX TRANSMITTER CHARACTERISTICS

Parameter Sym Min. Typ. Max. Unit

Output Optical Power BOL 62.5/125 µm -19
PO -16.8 -14 dBm avg.
NA = 0.275 Fibre EOL -20
Output Optical Power BOL 50/125 µm -22.5
PO -20.3 -14 dBm avg.
NA = 0.20 Fibre EOL -23.5
10 %
Optical Extinction Ratio
-10 dB
Output Optical Power at Logic "0" State PO -45 dBm avg.
Conditions: TA = 0°C to 70°C

2.11 1 PPS PORT

1 PPS port (fibre)

Main Use GPS accuracy clock reference
Connector BFOC 2.5 –(ST®)
Standard IEC 874-10
Fibre type Multimode 50/125 µm or 62.5/125 µm
Wavelength 850 nm
Minimum reception level -28 dBm
Better than +/- 50 ns for maximum absolute error between
Accuracy
actual GPS time and rising edge of 1 PPS signal.

2.12 FIBRE TELEPROTECTION INTERFACE

Fibre Teleprotection Interface

Main Use Teleprotection communications
Connectors (2) BFOC 2.5 –(ST®)
Standard IEC 874-10
Protocol InterMicom 64
Fibre type Multimode 50/125 µm or 62.5/125 µm or single-mode 9/125 µm
Wavelength 850 nm or 1300 nm (multimode), 1300 nm or 1500 nm (single mode)
Minimum reception level -28 dBm
Better than +/- 50 ns for maximum absolute error between actual GPS time and
Accuracy
rising edge of 1 PPS signal.

Optical budget
850nm MM 1300 nm MM 1300 nm SM 1550 nm SM
Minimum transmit output level (average power) -19.8 dBm -6 dBm -6 dBm -6 dBm
Receiver sensitivity (average power) -25.4 dBm -49 dBm -49 dBm -49 dBm
Optical budget 5.6 dB 43 dB 43 dB 43 dB
Less safety margin (3 dB) 2.6 dB 40 dB 40 dB 40 dB
Typical cable loss 2.6 dB/km 0.8 dB/km 0.4 dB/km 0.3 dB/km
Maximum transmission distance 1 km 50 km 100 km 130 km

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3 PROTECTION FUNCTIONS

3.1 PHASE CURRENT DIFFERENTIAL PROTECTION

Accuracy
Pick-up Formula +/- 10%
Drop-off 0.75 x Formula +/- 10%
IDMT characteristic shape +/- 5% or 40 ms, whichever is greater
DT operation +/- 2% or 20 ms, whichever is greater
Typical instantaneous operation with default settings,
back-to-back propagation delay included
50 Hz, 1 p.u. ≤ relay current < 2 p.u. <35 ms
60 Hz, 1 p.u. ≤ relay current < 2 p.u. <30 ms
50 Hz, relay current ≥ 2 p.u. <30 ms
60 Hz, relay current ≥ 2 p.u. <25 ms
Reset time <60 ms
Repeatability +/- 2.5%
UK curves IEC 60255-3 – 1998
Characteristic
US curves IEEE C37.112 – 1996
Vector compensation No affect on accuracy
Current transformer ratio compensation No affect on accuracy
High set characteristic setting No affect on accuracy
Three ended scheme operation No affect on accuracy

3.2 NEUTRAL CURRENT DIFFERENTIAL PROTECTION

Accuracy
Pick-up Formula +/- 10%
Drop-off 0.75 x Formula +/- 10%
DT operation +/- 2% or 40 ms, whichever is greater
Typical instantaneous operation with default settings
and IN Differential > 50% above threshold
50 Hz 30-50 ms
60 Hz 25-42 ms
Repeatability +/- 2.5%
Current transformer ratio compensation No affect on accuracy
Three ended scheme operation No affect on accuracy

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3.3 DISTANCE PROTECTION

Tripping characteristics

Operating time versus reach percentage, for faults close to line

angle.

50 Hz, SIR = 5

All quoted operating times include closure of the trip output

contact

Operating time versus reach percentage, for faults close to line

angle.

60 Hz, SIR = 5

All quoted operating times include closure of the trip output

contact

Operating time for resistive faults > 20% inside the 50 Hz, up to SIR = 30 < 30 ms
characteristic 60 Hz, up to SIR = 30 < 25 ms

Accuracy
+/- 5% for on-angle fault (on the set line angle)
+/- 10% for off-angle fault
Characteristic shape, up to SIR = 30
Example: For a 70 degree set line angle, injection testing at 40 degrees
would be referred to as "off-angle".
Zone time delay deviations +/- 20 ms or 2%, whichever is greater

3.4 POWER SWING BLOCKING

Accuracy
Accuracy of zones and timers As per Distance

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3.5 OUT OF STEP PROTECTION

Accuracy
Accuracy of zones and timers As per Distance
Operating range Up to 7 Hz

3.6 FIBRE TELEPROTECTION TRANSFER TIMES

The table below shows the minimum and maximum transfer time for InterMiCOM64 (IM64). The times are
measured from opto initialization (with no opto filtering) to relay standard output and include a small propagation
delay for back-back test (2.7 ms for 64 kbits/s and 3.2 ms for 56 kbits/s).
IDiff IM64 indicates InterMiCOM64 signals working in conjunction with the differential protection fibre optic
communications channel. IM64 indicates InterMiCOM64 signals working as a standalone feature.
Configuration Permissive op times (ms) Direct op times (ms)
IM64 at 64 k 13 - 18 17 - 20
IM64 at 56 k 15 - 20 19 - 22
IDiff IM64 at 64 k 22 - 24 23 - 25
IDiff IM64 at 56 k 24 - 26 25 - 27

3.7 AUTORECLOSE AND CHECK SYNYCHRONISM

Accuracy
Timers +/- 20 ms or 2%, whichever is greater

3.8 PHASE OVERCURRENT PROTECTION

Accuracy
IDMT pick-up 1.05 x Setting +/-5%
DT pick-up Setting +/-5%
Drop-off (IDMT and DT) 0.98 x setting +/-5%
IDMT operate +/-5% of expected operating time or 40 ms, whichever is greater*
IEEE reset +/-5% or 40 ms, whichever is greater
DT operate +/-2% of setting or 40 ms, whichever is greater
DT reset Setting +/-5%
Repeatability <5%
Characteristic UK IEC 60255-3 1998
Characteristic US IEEE C37.112 1996

Note:
*Reference conditions: TMS = 1, TD = 7, I> = 1A, operating range = 2-20In

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3.8.1 TRANSIENT OVERREACH AND OVERSHOOT

Additional tolerance due to increasing X/R ratios +/-5% over the X/R ratio of 1 to 90
Overshoot of overcurrent elements < 30 ms

3.8.2 PHASE OVERCURRENT DIRECTIONAL PARAMETERS

Accuracy
Directional boundary pickup (RCA +/-90%) +/-2°
Directional boundary hysteresis < 2°
Directional boundary repeatability <2%

3.9 EARTH FAULT PROTECTION

Accuracy
IDMT pick-up 1.05 x Setting +/-5%
DT pick-up Setting +/-5%, or 20 mA, whichever is greater
Drop-off (IDMT and DT) 0.95 x setting +/-5%
IDMT Operate +/-5% or 40 ms, whichever is greater*
IEEE reset +/-10% or 40 ms, whichever is greater
Repeatability < 5%
DT operate +/-2% or 50 ms, whichever is greater
DT reset +/- 5% or 50 ms, whichever is greater

Note:
Reference conditions: TMS = 1, TD = 1, IN> = 1A, operating range = 2-20In.

3.9.1 EARTH FAULT DIRECTIONAL PARAMETERS

Zero Sequence Polarising accuracy

Directional boundary pick-up (RCA +/- 90°) +/-2°
Hysteresis <3°
VN> pick-up Setting+/-10%
VN> drop-off 0.9 x Setting +/-10%

Negative Sequence Polarising accuracy

Directional boundary pick-up (RCA +/- 90°) +/-2°
Hysteresis <3°
VN2> pick-up Setting+/-10%
VN2> drop-off 0.9 x Setting +/-10%
IN2> pick-up Setting+/-10%
IN2> drop-off 0.9 x Setting +/-10%

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3.10 SENSITIVE EARTH FAULT PROTECTION

IDMT pick-up 1.05 x Setting +/-5%

DT Pick-up Setting +/- 5%
Drop-off (IDMT + DT) 0.95 x Setting +/-5%
IDMT operate +/- 5% or 40 ms, whichever is greater*
DT operate +/- 2% or 50 ms, whichever is greater
DT reset Setting +/- 5% or 50 ms, whichever is greater
Repeatability < 5%

Note:
Reference conditions: TMS = 1, TD = 1, IN> setting = 100 mA with operating range of 2-20Is.

3.10.1 SENSITIVE EARTH FAULT PROTECTION DIRECTIONAL ELEMENT

Wattmetric SEF
Pick-up P = 0 W ISEF > +/-5% or 5 mA
Pick-up P > 0 W P > +/-5%
Drop-off P = 0 W 0.95 x ISEF> +/- 5% or 5 mA
Drop-off P > 0 W 0.9 x P> +/- 5% or 5 mA
Boundary accuracy +/-5% with hysteresis < 1°
Repeatability < 1%

3.11 HIGH IMPEDANCE RESTRICTED EARTH FAULT PROTECTION

High Impedance and Low Impedance

Pick-up Setting formula +/- 5%
Drop-off 0.8 x Setting formula +/-5%
Operating time < 60 ms
High set pick-up Setting +/- 10%
High set operating time < 30 ms
Repeatability < 5%

3.12 NEGATIVE SEQUENCE OVERCURRENT PROTECTION

IDMT pick-up 1.05 x Setting +/-5%

DT pick-up Setting +/- 5%
Drop-off (IDMT and DT) 0.95 x Setting +/-5%
IDMT operate +/- 5% or 40 ms, whichever is greater
DT operate +/- 2% or 60 ms, whichever is greater
DT Reset Setting +/- 5%

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3.12.1 NPSOC DIRECTIONAL PARAMETERS

Directional boundary pick-up (RCA +/-90%) +/-2°

Directional boundary hysteresis < 1°
Directional boundary repeatability < 1%

3.13 CIRCUIT BREAKER FAIL AND UNDERCURRENT PROTECTION

I< Pick-up Setting +/- 10% or 0.025 In, whichever is greater

I< Drop-off Setting +/- 5% or 20 mA, whichever is greater
Operate time < 12 ms
Timers +/- 2% or 20 ms, whichever is greater
Reset time < 15 ms

3.14 BROKEN CONDUCTOR PROTECTION

Pick-up Setting +/- 2.5%

Drop-off 0.95 x Setting +/- 2.5%
DT operate +/- 2% or 40 ms, whichever is greater
Reset time <25 ms

3.15 THERMAL OVERLOAD PROTECTION

Thermal alarm pick-up Calculated trip time +/- 10%

Thermal overload pick-up Calculated trip time +/- 10%
Cooling time accuracy +/- 15% of theoretical
Repeatability <5%

Note:
Operating time measured with applied current of 20% above thermal setting.

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4 MONITORING, CONTROL AND SUPERVISION

4.1 VOLTAGE TRANSFORMER SUPERVISION

Fast block operation < 1 cycle

Fast block reset < 1.5 cycles
Time delay +/- 2% or 20 ms, whichever is greater

4.2 STANDARD CURRENT TRANSFORMER SUPERVISION

IN> Pick-up Setting +/- 5%

VN< Pick-up Setting +/- 5%
IN> Drop-off 0.9 x setting +/- 5%
VN< Drop-off 1.05 x setting +/-5% or 1 V, whichever is greater
Time delay operation Setting +/-2% or 20 ms, whichever is greater
CTS block operation < 1 cycle
CTS reset < 35 ms

4.3 DIFFERENTIAL CURRENT TRANSFORMER SUPERVISION

Accuracy
I1> Pick-up Setting +/- 5%
I1> Drop-off 0.9 x setting +/- 5%
I2/I1> Pick-up Setting +/- 5%
I2/I1> Drop-off 0.9 x setting +/-5%
I2/I1>> Pick-up Setting +/- 5%
I2/I1 >> Drop-off 0.9 x setting +/-5%
Time delay operation Setting +/-2% or 20 ms, whichever is greater
CTS block diff operation < 1 cycle
CTS reset < 35 ms

4.4 CB STATE AND CONDITION MONITORING

Accuracy
Timers +/- 40 ms or 2%, whichever is greater
Broken current accuracy +/- 5%
Reset time < 30 ms

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4.5 PSL TIMERS

Output conditioner timer Setting +/- 2% or 50 ms, whichever is greater

Dwell conditioner timer Setting +/- 2% or 50 ms, whichever is greater
Pulse conditioner timer Setting +/- 2% or 50 ms, whichever is greater

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5 MEASUREMENTS AND RECORDING

5.1 GENERAL

General Measurement Accuracy

General measurement accuracy Typically +/- 1%, but +/- 0.5% between 0.2 - 2 In/Vn
Phase 0° to 360° +/- 0.5%
Current (0.05 to 3 In) +/- 1.0% of reading, or 4mA (1A input), or 20mA (5A input)
Voltage (0.05 to 2 Vn) +/- 1.0% of reading
Frequency (45 to 65 Hz) +/- 0.025 Hz
Power (W) (0.2 to 2 Vn and 0.05 to 3 In) +/- 5.0% of reading at unity power factor
Reactive power (Vars) (0.2 to 2 Vn and 0.05 to 3 In) +/- 5.0% of reading at zero power factor
Apparent power (VA) (0.2 to 2 Vn and 0.05 to 3 In) +/- 5.0% of reading
Energy (Wh) (0.2 to 2 Vn and 0.2 to 3 In) +/- 5.0% of reading at unity power factor
Energy (Varh) (0.2 to 2 Vn and 0.2 to 3In) +/- 5.0% of reading at zero power factor

5.2 DISTURBANCE RECORDS

Disturbance Records Measurement Accuracy

Minimum record duration 0.1 s
Maximum record duration 10.5 s
Minimum number of records at 10.5 seconds 8
Magnitude and relative phases accuracy +/- 5% of applied quantities
Duration accuracy +/- 2%
Trigger position accuracy +/- 2% (minimum Trigger 100 ms)

5.3 EVENT, FAULT AND MAINTENANCE RECORDS

Event, Fault & Maintenance Records

Record location Battery-backed memory
Viewing method Front panel display or Settings Application Software
Extraction method Extracted via the front serial port
Number of Event records Up to 1024 time tagged event records (newest overwrites oldest)
Number of Fault Records Up to 15
Number of Maintenance Records Up to 10
Event time stamp resolution 1 ms

5.4 FAULT LOCATOR

Accuracy
+/- 2% of line length
Fault Location
Reference conditions: solid fault applied on line

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6 RATINGS

6.1 AC MEASURING INPUTS

AC Measuring Inputs
Nominal frequency 50 Hz or 60 Hz (settable)
Operating range 45 to 65 Hz
Phase rotation ABC or CBA

6.2 CURRENT TRANSFORMER INPUTS

AC Current Inputs
Nominal current (In) 1A or 5A
Nominal burden per phase < 0.2 VA at In
20 A (continuous operation)
AC current thermal withstand (5A input) 150 A (for 10 s)
500 A (for 1 s)
4 A (continuous operation)
AC current thermal withstand (1A input) 30 A (for 10 s)
100 A (for 1 s)
Linearity Linear up to 64 × In (non-offset)

6.3 VOLTAGE TRANSFORMER INPUTS

AC Voltage Inputs
Nominal voltage 100 V to 120 V
Nominal burden per phase < 0.1 VA at Vn
2 x Vn (continuous operation)
Thermal withstand
2.6 x Vn (for 10 seconds)
Linear up to 200 V (100/120 V supply)
Linearity
Linear up to 800 V (380/400 V supply)

6.4 AUXILIARY SUPPLY VOLTAGE

Cortec option (DC only)

24 to 48 V DC
Cortec option (rated for AC or DC operation)
48 to 110 V DC
Nominal operating range
40 to 100 V AC rms
Cortec option (rated for AC or DC operation)
110 to 250 V DC
100 to 240 V AC rms

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Cortec option (DC only)

19 to 65 V DC
Cortec option (rated for AC or DC operation)
37 to 150 V DC
Maximum operating range
32 to 110 V AC rms
Cortec option (rated for AC or DC operation)
87 to 300 V DC
80 to 265 V AC rms
Frequency range for AC supply 45 to 65 Hz
Ripple <15% for a DC supply (compliant with IEC 60255-11:2013)
Power up time < 11 seconds

6.5 NOMINAL BURDEN

Quiescent burden 11 W
2nd rear communications port 1.25 W
Each relay output burden 0.13 W per output relay
Each opto-input burden (24 – 27 V) 0.065 W max
Each opto-input burden (30 – 34 V) 0.065 W max
Each opto-input burden (48 – 54 V) 0.125 W max
Each opto-input burden (110 – 125 V) 0.36 W max
Each opto-input burden (220 – 250 V) 0.9 W max

6.6 POWER SUPPLY INTERRUPTION

Standard IEC 60255-26:2013 (DC and AC)

20 ms at 24 V (half and full load)
24-48V DC SUPPLY
50 ms at 36 V (half and full load)
100% interruption without de-energising
100 ms at 48 V (half and full load)
20 ms at 37V (half and full load)
50 ms at 60 V (half and full load)
48-110V DC SUPPLY
100 ms at 72 V (half load)
100% interruption without de-energising
100 ms at 85 V (full load)
200 ms at 110 V (half and full load)
20 ms at 87 V (half load)
50 ms at 110 V (half load)
50 ms at 98 V (full load)
110-250V DC SUPPLY
100 ms at 160 V (half load)
100% interruption without de-energising
100 ms at 135 V (full load)
200 ms at 210 V (half load)
200 ms at 174 V (full load)
40-100V AC SUPPLY 50 ms at 32 V (half load)
100% voltage dip without de-energising 10 ms at 32 V (full load)
100-240V AC SUPPLY
50 ms at 80 V (full and half load)
100% voltage dip without de-energising

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Note:
Maximum loading = all inputs/outputs energised.

Note:
Quiescent or 1/2 loading = 1/2 of all inputs/outputs energised.

6.7 BATTERY BACKUP

Location Front panel

Type 1/2 AA, 3.6V Lithium Thionyly Chloride
Battery reference LS14250
Lifetime > 10 years (IED energised for 90% of the time)

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7 INPUT / OUTPUT CONNECTIONS

7.1 ISOLATED DIGITAL INPUTS

Opto-isolated digital inputs (opto-inputs)

Compliance ESI 48-4
Rated nominal voltage 24 to 250 V dc
Operating range 19 to 265 V dc
Withstand 300 V dc
Recognition time with half-cycle ac
< 2 ms
immunity filter removed
Recognition time with filter on < 12 ms

7.1.1 NOMINAL PICKUP AND RESET THRESHOLDS

Nominal battery
Logic levels: 60-80% DO/PU Logic Levels: 50-70% DO/PU
voltage
24/27 V Logic 0 < 16.2V, Logic 1 > 19.2V Logic 0 <12V, Logic 1 > 16.8V
30/34 Logic 0 < 20.4V, Logic 1 > 24V Logic 0 < 15V, Logic 1 > 21V
48/54 Logic 0 < 32.4V, Logic 1 > 38.4V Logic 0 < 24V, Logic 1 > 33.6V
110/125 Logic 0 < 75V, Logic 1 > 88V Logic 0 < 55.V, Logic 1 > 77V
220/250 Logic 0 < 150V, Logic 1 > 176V Logic 0 < 110V, Logic 1 > 154V

Note:
Filter is required to make the opto-inputs immune to induced AC voltages.

In addition to the above thresholds, some models of this product provide the following threshold levels for FSK
applications:
● For 220/250 voltage inputs: Logic 0 < 145V, Logic 1 > 165V

7.2 STANDARD OUTPUT CONTACTS

Compliance In accordance with IEC 60255-1:2009

Use General purpose relay outputs for signalling, tripping and alarming
Rated voltage 300 V
Maximum continuous current 10 A
30 A for 3 s
Short duration withstand carry
250 A for 30 ms
Make and break, dc resistive 50 W
Make and break, dc inductive 62.5 W (L/R = 50 ms)
Make and break, ac resistive 2500 VA resistive (cos phi = unity)
Make and break, ac inductive 2500 VA inductive (cos phi = 0.7)
Make and carry, dc resistive 30 A for 3 s, 10000 operations (subject to the above limits)
Make, carry and break, dc resistive 4 A for 1.5 s, 10000 operations (subject to the above limits)

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Make, carry and break, dc inductive 0.5 A for 1 s, 10000 operations (subject to the above limits)
Make, carry and break ac resistive 30 A for 200 ms, 2000 operations (subject to the above limits)
Make, carry and break ac inductive 10 A for 1.5 s, 10000 operations (subject to the above limits)
Loaded contact 1000 operations min.
Unloaded contact 10000 operations min.
Operate time < 5 ms
Reset time < 10 ms

7.3 HIGH BREAK OUTPUT CONTACTS

Compliance In accordance with IEC 60255-1:2009

Use For applciations requiring high rupture capacity
Rated voltage 300 V
Maximum continuous current 10 A DC
30 A DC for 3 s
Short duration withstand carry
250 A for 30 ms
Make and break, dc resistive 7500 W
Make and break, dc inductive 2500 W (L/R = 50 ms)
Make and carry, dc resistive 30 A for 3 s, 10000 operations (subject to the above limits)
30 A for 3 s, 5000 operations (subject to the above limits)
Make, carry and break, dc resistive
30 A for 200 ms, 10000 operations (subject to the above limits)
10 A for 40 ms, 10000 operations (subject to the above limits)
Make, carry and break, dc inductive
10 a for 20 ms (250V, 4 shots per second)
Loaded contact 10,000 operations minimum.
Unloaded contact 100,000 operations minimum.
Operate time < 0.2 ms
Reset time < 8 ms
MOV Protection Maximum voltage 330 V DC

7.4 WATCHDOG CONTACTS

Use Non-programmable contacts for relay healthy/relay fail indication

Breaking capacity, dc resistive 30 W
Breaking capacity, dc inductive 15 W (L/R = 40 ms)
Breaking capacity, ac inductive 375 VA inductive (cos phi = 0.7)

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8 MECHANICAL SPECIFICATIONS

8.1 PHYSICAL PARAMETERS

40TE
Case Types* 60TE
80TE
Weight (40TE case) 7 kg – 8 kg (depending on chosen options)
Weight (60TE case) 9 kg – 12 kg (depending on chosen options)
Weight (80TE case) 13 kg - 16 kg (depending on chosen options)
Dimensions in mm (w x h x l) (40TE case) W: 206.0 mm H: 177.0 mm D: 243.1 mm
Dimensions in mm (w x h x l) (60TE case) W: 309.6 mm H: 177.0 mm D: 243.1 mm
Dimensions in mm (w x h x l) (80TE case) W 413.2 mm H 177.0 mm D 243.1 mm
Mounting Panel, rack, or retrofit

Note:
*Case size is product dependent.

8.2 ENCLOSURE PROTECTION

Against dust and dripping water (front face) IP52 as per IEC 60529:2002
Protection against dust (whole case) IP50 as per IEC 60529:2002
Protection for sides of the case (safety) IP30 as per IEC 60529:2002
Protection for rear of the case (safety) IP10 as per IEC 60529:2002

8.3 MECHANICAL ROBUSTNESS

Vibration test per EN 60255-21-1:1996 Response: class 2, Endurance: class 2

Shock response: class 2, Shock withstand: class 1, Bump withstand:
Shock and bump immunity per EN 60255-21-2:1995
class 1
Seismic test per EN 60255-21-3: 1995 Class 2

8.4 TRANSIT PACKAGING PERFORMANCE

Primary packaging carton protection ISTA 1C

Vibration tests 3 orientations, 7 Hz, amplitude 5.3 mm, acceleration 1.05g
10 drops from 610 mm height on multiple carton faces, edges and
Drop tests
corners

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9 TYPE TESTS

9.1 INSULATION

Compliance IEC 60255-27: 2005

Insulation resistance > 100 M ohm at 500 V DC (Using only electronic/brushless insulation tester)

9.2 CREEPAGE DISTANCES AND CLEARANCES

Compliance IEC 60255-27: 2005

Pollution degree 3
Overvoltage category lll
Impulse test voltage (not RJ45) 5 kV
Impulse test voltage (RJ45) 1 kV

9.3 HIGH VOLTAGE (DIELECTRIC) WITHSTAND

IEC Compliance IEC 60255-27: 2005

Between all independent circuits 2 kV ac rms for 1 minute
Between independent circuits and protective earth conductor terminal 2 kV ac rms for 1 minute
Between all case terminals and the case earth 2 kV ac rms for 1 minute
Across open watchdog contacts 1 kV ac rms for 1 minute
Across open contacts of changeover output relays 1 kV ac rms for 1 minute
Between all RJ45 contacts and protective earth 1 kV ac rms for 1 minute
Between all screw-type EIA(RS)485 contacts and protective earth 1 kV ac rms for 1 minute
ANSI/IEEE Compliance ANSI/IEEE C37.90-2005
Across open contacts of normally open output relays 1.5 kV ac rms for 1 minute
Across open contacts of normally open changeover output relays 1 kV ac rms for 1 minute
Across open watchdog contacts 1 kV ac rms for 1 minute

9.4 IMPULSE VOLTAGE WITHSTAND TEST

Compliance IEC 60255-27: 2005

Between all independent circuits Front time: 1.2 µs, Time to half-value: 50 µs, Peak value: 5 kV, 0.5 J
Between terminals of all independent circuits Front time: 1.2 µs, Time to half-value: 50 µs, Peak value: 5 kV, 0.5 J
Between all independent circuits and protective
Front time: 1.2 µs, Time to half-value: 50 µs, Peak value: 5 kV, 0.5 J
earth conductor terminal

Note:
Exceptions are communications ports and normally-open output contacts, where applicable.

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Chapter 27 - Technical Specifications P543i/P545i

10 ENVIRONMENTAL CONDITIONS

10.1 AMBIENT TEMPERATURE RANGE

Compliance IEC 60255-27: 2005

Test Method IEC 60068-2-1:2007 and IEC 60068-2-2 2007
Operating temperature range -25°C to +55°C (continuous)
Storage and transit temperature range -25°C to +70°C (continuous)

10.2 TEMPERATURE ENDURANCE TEST

Temperature Endurance Test

Test Method IEC 60068-2-1: 1993 and 60068-2-2: 2007
-40°C (96 hours)
Operating temperature range
+70°C (96 hours)
-40°C (96 hours)
Storage and transit temperature range
+70°C (96 hours)

10.3 AMBIENT HUMIDITY RANGE

Compliance IEC 60068-2-78: 2001 and IEC 60068-2-30: 2005

Durability 56 days at 93% relative humidity and +40°C
Damp heat cyclic six (12 + 12) hour cycles, 93% RH, +25 to +55°C

10.4 CORROSIVE ENVIRONMENTS

Compliance IEC 60068-2-42: 2003, IEC 60068-2-43: 2003

Industrial corrosive environment/poor environmental 21 days exposure to elevated concentrations (25ppm) of SO2 at
control, Sulphur Dioxide 75% relative humidity and +25°C
Industrial corrosive environment/poor environmental 21 days exposure to elevated concentrations (10ppm) of H2S at
control, Hydrogen Sulphide 75% relative humidity and +25°C
Salt mist IEC 60068-2-52: 1996 KB severity 3

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11 ELECTROMAGNETIC COMPATIBILITY

11.1 1 MHZ BURST HIGH FREQUENCY DISTURBANCE TEST

Compliance IEC 60255-22-1: 2008, Class III, IEC 60255-26:2013

Common-mode test voltage (level 3) 2.5 kV
Differential test voltage (level 3) 1.0 kV

11.2 DAMPED OSCILLATORY TEST

EN61000-4-18: 2011: Level 3, 100 kHz and 1 MHz. Level 4: 3 MHz,

Compliance
10 MHz and 30 MHz, IEC 60255-26:2013
Common-mode test voltage (level 3) 2.5 kV
Common-mode test voltage (level 4) 4.0 kV
Differential mode test voltage 1.0 kV

11.3 IMMUNITY TO ELECTROSTATIC DISCHARGE

Compliance IEC 60255-22-2: 2009 Class 3 and Class 4, IEC 60255-26:2013

Class 4 Condition 15 kV discharge in air to user interface, display, and exposed metalwork
Class 3 Condition 8 kV discharge in air to all communication ports

11.4 ELECTRICAL FAST TRANSIENT OR BURST REQUIREMENTS

IEC 60255-22-4: 2008 and EN61000-4-4:2004. Test severity level lll and lV, IEC
Compliance
60255-26:2013
Applied to communication inputs Amplitude: 2 kV, burst frequency 5 kHz and 100 KHz (level 4)
Applied to power supply and all other inputs
Amplitude: 4 kV, burst frequency 5 kHz and 100 KHz (level 4)
except for communication inputs

11.5 SURGE WITHSTAND CAPABILITY

Compliance IEEE/ANSI C37.90.1: 2002

4 kV fast transient and 2.5 kV oscillatory applied common mode and differential
Condition 1
mode to opto inputs, output relays, CTs, VTs, power supply
4 kV fast transient and 2.5 kV oscillatory applied common mode to communications,
Condition 2
IRIG-B

P54x1i-TM-EN-1 739
Chapter 27 - Technical Specifications P543i/P545i

11.6 SURGE IMMUNITY TEST

Compliance IEC 61000-4-5: 2005 Level 4, IEC 60255-26:2013

Pulse duration Time to half-value: 1.2/50 µs
Between all groups and protective earth conductor terminal Amplitude 4 kV
Between terminals of each group (excluding communications ports,
Amplitude 2 kV
where applicable)

11.7 IMMUNITY TO RADIATED ELECTROMAGNETIC ENERGY

Compliance IEC 60255-22-3: 2007, Class III, IEC 60255-26:2013

Frequency band 80 MHz to 3.0 GHz
Spot tests at 80, 160, 380, 450, 900, 1850, 2150 MHz
Test field strength 10 V/m
Test using AM 1 kHz @ 80%
Compliance IEEE/ANSI C37.90.2: 2004
Frequency band 80 MHz to 1 GHz
Spot tests at 80, 160, 380, 450 MHz
Waveform 1 kHz @ 80% am and pulse modulated
Field strength 35 V/m

11.8 RADIATED IMMUNITY FROM DIGITAL COMMUNICATIONS

Compliance IEC 61000-4-3: 2006, Level 4, IEC 60255-26:2013

Frequency bands 800 to 960 MHz, 1.4 to 2.0 GHz
Test field strength 30 V/m
Test using AM 1 kHz / 80%

11.9 RADIATED IMMUNITY FROM DIGITAL RADIO TELEPHONES

Compliance IEC 61000-4-3: 2006, IEC 60255-26:2013

Frequency bands 900 MHz and 1.89 GHz
Test field strength 10 V/m

11.10 IMMUNITY TO CONDUCTED DISTURBANCES INDUCED BY RADIO FREQUENCY

FIELDS

Compliance IEC 61000-4-6: 2008, Level 3, IEC 60255-26:2013

Frequency bands 150 kHz to 80 MHz

740 P54x1i-TM-EN-1
P543i/P545i Chapter 27 - Technical Specifications

Test disturbance voltage 10 V rms

Test using AM 1 kHz @ 80%
Spot tests 27 MHz and 68 MHz

11.11 MAGNETIC FIELD IMMUNITY

IEC 61000-4-8: 2009 Level 5

Compliance
IEC 61000-4-9/10: 2001 Level 5
IEC 61000-4-8 test 100 A/m applied continuously, 1000 A/m applied for 3 s
IEC 61000-4-9 test 1000 A/m applied in all planes
100 A/m applied in all planes at 100 kHz/1 MHz with a burst duration of 2
IEC 61000-4-10 test
seconds

11.12 CONDUCTED EMISSIONS

Compliance EN 55022: 2010, IEC 60255-26:2013

Power supply test 1 0.15 - 0.5 MHz, 79 dBµV (quasi peak) 66 dBµV (average)
Power supply test 2 0.5 – 30 MHz, 73 dBµV (quasi peak) 60 dBµV (average)
RJ45 test 1 (where applicable) 0.15 - 0.5 MHz, 97 dBµV (quasi peak) 84 dBµV (average)
RJ45 test 2 (where applicable) 0.5 – 30 MHz, 87 dBµV (quasi peak) 74 dBµV (average)

11.13 RADIATED EMISSIONS

Compliance EN 55022: 2010, IEC 60255-26:2013

Test 1 30 – 230 MHz, 40 dBµV/m at 10 m measurement distance
Test 2 230 – 1 GHz, 47 dBµV/m at 10 m measurement distance
Test 3 1 – 2 GHz, 76 dBµV/m at 10 m measurement distance

11.14 POWER FREQUENCY

Compliance IEC 60255-22-7:2003, IEC 60255-26:2013

Opto-inputs (Compliance is achieved using the opto-input 300 V common-mode (Class A)
filter) 150 V differential mode (Class A)

Note:
Compliance is achieved using the opto-input filter.

P54x1i-TM-EN-1 741
Chapter 27 - Technical Specifications P543i/P545i

12 REGULATORY COMPLIANCE
Compliance with the European Commission Directive on EMC and LVD is demonstrated using a technical file.

12.1 EMC COMPLIANCE: 2014/30/EU

The product specific Declaration of Conformity (DoC) lists the relevant harmonised standard(s) or conformit
assessment used to demonstrate compliance with the EMC directive.

12.2 LVD COMPLIANCE: 2014/35/EU

The product specific Declaration of Conformity (DoC) lists the relevant harmonized standard(s) or conformity
assessment used to demonstrate compliance with the LVD directive.
Safety related information, such as the installation I overvoltage category, pollution degree and operating
temperature ranges are specified in the Technical Data section of the relevant product documentation and/or on
the product labelling .
Unless otherwise stated in the Technical Data section of the relevant product documentation, the equipment is
intended for indoor use only. Where the equipment is required for use in an outdoor location, it must be mounted
in a specific cabinet or housing to provide the equipment with the appropriate level of protection from the
expected outdoor environment.

12.3 R&TTE COMPLIANCE: 2014/53/EU

Radio and Telecommunications Terminal Equipment (R&TTE) directive 2014/53/EU.
Conformity is demonstrated by compliance to both the EMC directive and the Low Voltage directive, to zero volts.

12.4 UL/CUL COMPLIANCE

If marked with this logo, the product is compliant with the requirements of the Canadian and USA Underwriters
Laboratories.
The relevant UL file number and ID is shown on the equipment.

12.5 ATEX COMPLIANCE: 2014/34/EU

Products marked with the 'explosion protection' Ex symbol (shown in the example, below) are compliant with the
ATEX directive. The product specific Declaration of Conformity (DoC) lists the Notified Body, Type Examination
Certificate, and relevant harmonized standard or conformity assessment used to demonstrate compliance with
the ATEX directive.
The ATEX Equipment Protection level, Equipment group, and Zone definition will be marked on the
product.
For example:

742 P54x1i-TM-EN-1
P543i/P545i Chapter 27 - Technical Specifications

Where:

'II' Equipment Group: Industrial.

'(2)G' High protection equipment category, for control of equipment in gas atmospheres in Zone 1 and 2.
This equipment (with parentheses marking around the zone number) is not itself suitable for operation
within a potentially explosive atmosphere.

P54x1i-TM-EN-1 743
Chapter 27 - Technical Specifications P543i/P545i

744 P54x1i-TM-EN-1
 APPENDIX A

ORDERING OPTIONS
Appendix A - Ordering Options P543i/P545i

P54x1i-TM-EN-1
P543i/P545i Appendix A - Ordering Options

Variants Order No.

Current differential - With distance backup, 1/3 pole autoreclose and check synchronising P543 **
Nominal auxiliary voltage
24-54 Vdc 7
48-125 Vdc (40-100 Vac) 8
110-250 Vdc (100-240 Vac) 9

In/Vn rating
In = 1A/5A ; Vn = 100-120Vac 1

Hardware options Protocol Compatibilty

Standard - None 1, 2, 3 & 4 1
IRIG-B Only (Modulated) 1, 2, 3 & 4 2
Fibre Optic Converter Only 1, 2, 3 & 4 3
IRIG-B (Modulated) & Fibre Optic Converter 1, 2, 3 & 4 4
Ethernet (10Mbit/s) * 5 5
Ethernet (100Mbit/s) 5, 6, 7 & 8 6
Second Rear Comms 1, 2, 3 & 4 7
IRIG-B (Modulated) + Second Rear Comms 1, 2, 3 & 4 8
Ethernet (100Mbit/s) plus IRIG-B (Modulated) ** 6, 7 & 8 A
Ethernet (100Mbit/s) plus IRIG-B (Un-modulated) ** 6, 7 & 8 B
IRIG-B (Un-modulated) ** 1, 2, 3 & 4 C
InterMiCOM + Courier Rear Port **** 1, 2, 3 & 4 E
InterMiCOM + Courier Rear Port + IRIG-B modulated **** 1, 2, 3 & 4 F
Redundant Ethernet Self-Healing Ring, 2 multi-mode fibre ports + Modulated IRIG-B *** 6, 7 & 8 G
Redundant Ethernet Self-Healing Ring, 2 multi-mode fibre ports + Un-modulated IRIG-B *** 6, 7 & 8 H
Redundant Ethernet RSTP, 2 multi-mode fibre ports + Modulated IRIG-B *** 6, 7 & 8 J
Redundant Ethernet RSTP, 2 multi-mode fibre ports + Un-modulated IRIG-B *** 6, 7 & 8 K
Redundant Ethernet Dual-Homing Star, 2 multi-mode fibre ports + Modulated IRIG-B *** 6, 7 & 8 L
Redundant Ethernet Dual-Homing Star, 2 multi-mode fibre ports + Un-modulated IRIG-B *** 6, 7 & 8 M
Redundant Ethernet PRP, 2 multi-mode fibre ports + Modulated IRIG-B *** 6, 7 & 8 N
Redundant Ethernet PRP, 2 multi-mode fibre ports + Un-modulated IRIG-B *** 6, 7 & 8 P

* Only on Suffix G or J Relays

** Only on Suffix K or M relays
*** Only on Suffix K or M relays with 45/55 Software and later
**** Only on Suffix K or M relays with 47/57 Software, replaces hardware options '7' & '8'

Product Options
Ch1=850nm multi-mode, Ch2=850nm multi-mode A
Ch1=1300nm single-mode, Ch2=not fitted (2 Terminal only) B
Ch1=1300nm single-mode, Ch2=1300nm single-mode C
Ch1=1300nm multi-mode, Ch2=not fitted (2 Terminal only) D
Ch1=1300nm multi-mode, Ch2=1300nm multi-mode E
Ch1=1550nm single-mode, Ch2=not fitted (2 Terminal only) F
Ch1=1550nm single-mode, Ch2=1550nm single-mode G
Ch1=850nm multi-mode, Ch2=1300nm single-mode * H
Ch1=850nm multi-mode, Ch2=1300nm multi-mode * J
Ch1=850nm multi-mode, Ch2=1550nm single-mode * K
Ch1=1300nm single-mode, Ch2=850nm multi-mode * L
Ch1=1300nm multi-mode, Ch2=850nm multi-mode * M
Reserved for future single channel N
Reserved for future single channel P
Ch1 1550nm single-mode, Ch2 850nm multi-mode * R
Ch1=850nm multi-mode, Ch2=850nm multi-mode + High Break** S
Ch1=1300nm single-mode, Ch2=not fitted (2 Terminal only) + High Break** T
Ch1=1300nm single-mode , Ch2=1300nm single-mode + High Break ** U
Ch1=1300nm multi-mode, Ch2=not fitted (2 Terminal only) + High Break** V
Ch1=1300nm multi-mode, Ch2=1300nm multi-mode + High Break** W
Ch1=1550nm single-mode, Ch2=not fitted (2 Terminal only) + High Break** X
Reserved - was used for RWE special Y
Ch1=1550nm single-mode, Ch2=1550nm single-mode + High Break ** Z
Ch1=850nm multi-mode, Ch2=1300nm single-mode + High Break** 0
Ch1=850nm multi-mode, Ch2=1300nm multi-mode + High Break** 1
Ch1=850nm multi-mode, Ch2=1550nm single-mode + High Break** 2
Ch1=1300nm single-mode, Ch2=850nm multi-mode + High Break** 3
Ch1=1300nm multi-mode, Ch2=850nm multi-mode + High Break** 4
Ch1 1550nm single-mode, Ch2 850nm multi-mode + High Break** 5
Reserved for future single channel 6
Reserved for future single channel 7

* Design Suffix G, J, K & M only

** Design Suffix K & M only

Protocol options Hardware Compatibilty

K-Bus 1, 2, 3, 4, C, E & F 1
Modbus * 1, 2, 3, 4, 2
IEC60870-5-103 (VDEW) 1, 2, 3, 4, C, E & F 3
DNP3.0 1, 2, 3, 4, C, E & F 4
UCA2 ** 5&6 5
IEC61850 + Courier via rear RS485 port *** 6, A, B,G, H, J, K, L, M, N, P 6
IEC61850 + IEC60870-5-103 via rear RS485 port *** 6, A, B,G, H, J, K, L, M, N, P 7
DNP3.0 Over Ethernet with Courier rear port K-Bus/RS485 protocol **** 6, A, B,G, H, J, K, L, M, N, P 8

* Only on Suffix B, G or J Relays

** Only on Suffix G Relays
*** Only On Suffix K or M Relays
**** Only available On Suffix K or M relays with software versions 44/54 & later

Mounting
Flush/Panel Mounting with Harsh Environment Coating M
Flush/Panel mounting with harsh environment coating P

P54x1i-TM-EN-1 A1
Appendix A - Ordering Options P543i/P545i

Variants Order No.

Current differential - With distance backup, 1/3 pole autoreclose and check synchronising P543 **
Language
English, French, German, Spanish 0
English, French, German, Italian (Not yet available!) 4
English, French, German, Russian * 5
English, Italian, Polish and Portuguese *** 7
Chinese, English or French via HMI, with English or French only via Communications port ** C

* Design Suffix G, J, K & M only

** Design Suffix K and M with 42/52 software and later only
*** Design Suffx M with 65/66/75/76 software

Software version
Without Distance 4*/6*
With Distance 5/7/8*

Customer specific options

Standard version 0
Customer version A

Hardware version
Phase 2 Enhanced Coprocessor, wide range opto B
Enhanced Main Processor (CPU2) with hotkeys G
As G plus dual characteristic optos J
Extended main processor (XCPU2) With Function Keys & Tri-colour LEDs K
As K plus increased main processor memory (XCPU3), Cyber Security M

A2 P54x1i-TM-EN-1
P543i/P545i Appendix A - Ordering Options

Variants Order No.

Current differential - With distance backup, P545 **
1/3 pole autoreclose and check synchronising, with 24 or 32 inputs, 32 outputs, GPS input.
Nominal auxiliary voltage
24-54 Vdc 7
48-125 Vdc (40-100 Vac) 8
110-250 Vdc (100-240 Vac) 9

In/Vn rating
In = 1A/5A ; Vn = 100-120Vac 1

Hardware options Protocol Compatibilty

Standard - None 1, 2, 3 & 4 1
IRIG-B Only (Modulated) 1, 2, 3 & 4 2
Fibre Optic Converter Only 1, 2, 3 & 4 3
IRIG-B (Modulated) & Fibre Optic Converter 1, 2, 3 & 4 4
Ethernet (10Mbit/s) * 5 5
Ethernet (100Mbit/s) 5, 6, 7 & 8 6
Second Rear Comms 1, 2, 3 & 4 7
IRIG-B (Modulated) + Second Rear Comms 1, 2, 3 & 4 8
Ethernet (100Mbit/s) plus IRIG-B (Modulated) ** 6, 7 & 8 A
Ethernet (100Mbit/s) plus IRIG-B (Un-modulated) ** 6, 7 & 8 B
IRIG-B (Un-modulated) ** 1, 2, 3 & 4 C
InterMiCOM + Courier Rear Port **** 1, 2, 3 & 4 E
InterMiCOM + Courier Rear Port + IRIG-B modulated **** 1, 2, 3 & 4 F
Redundant Ethernet Self-Healing Ring, 2 multi-mode fibre ports + Modulated IRIG-B *** 6, 7 & 8 G
Redundant Ethernet Self-Healing Ring, 2 multi-mode fibre ports + Un-modulated IRIG-B *** 6, 7 & 8 H
Redundant Ethernet RSTP, 2 multi-mode fibre ports + Modulated IRIG-B *** 6, 7 & 8 J
Redundant Ethernet RSTP, 2 multi-mode fibre ports + Un-modulated IRIG-B *** 6, 7 & 8 K
Redundant Ethernet Dual-Homing Star, 2 multi-mode fibre ports + Modulated IRIG-B *** 6, 7 & 8 L
Redundant Ethernet Dual-Homing Star, 2 multi-mode fibre ports + Un-modulated IRIG-B *** 6, 7 & 8 M
Redundant Ethernet PRP, 2 multi-mode fibre ports + Modulated IRIG-B *** 6, 7 & 8 N
Redundant Ethernet PRP, 2 multi-mode fibre ports + Un-modulated IRIG-B *** 6, 7 & 8 P

* Only on Suffix G or J Relays

** Only on Suffix K or M relays
*** Only on Suffix K or M relays with software versions 45/55 and later
**** Only on Suffix K or M relays with 47/57 Software, replaces hardware options '7' & '8'

Product Options: Basic Configuration of

Ch1=850nm multi-mode, Ch2=850nm multi-mode A
Ch1=1300nm single-mode, Ch2=not fitted (2 Terminal only) B
Ch1=1300nm single-mode, Ch2=1300nm single-mode C
Ch1=1300nm multi-mode, Ch2=not fitted (2 Terminal only) D
Ch1=1300nm multi-mode, Ch2=1300nm multi-mode E
Ch1=1550nm single-mode, Ch2=not fitted (2 Terminal only) F
Ch1=1550nm single-mode, Ch2=1550nm single-mode G
Ch1=850nm multi-mode, Ch2=1300nm single-mode * H
Ch1=850nm multi-mode, Ch2=850nm multi-mode + 32 Inputs *** I
Ch1=850nm multi-mode, Ch2=1300nm multi-mode * J
Ch1=850nm multi-mode, Ch2=1550nm single-mode * K
Ch1=1300nm single-mode, Ch2=850nm multi-mode * L
Ch1=1300nm multi-mode, Ch2=850nm multi-mode * M
Ch1=1300nm single-mode, Ch2=not fitted (2 Terminal only) + 32 Inputs *** N
Ch1=1300nm single-mode, Ch2=1300nm single-mode + 32 Inputs *** O
Ch1=1300nm multi-mode, Ch2=not fitted (2 Terminal only) + 32 Inputs *** P
Ch1=1300nm multi-mode, Ch2=1300nm multi-mode + 32 Inputs *** Q
Ch 1 1550nm single-mode, Ch 2 850nm multi-mode * R
Ch1=850nm multi-mode, Ch2=850nm multi-mode + High Break ** S
Ch1=1300nm single-mode, Ch2=not fitted (2 Terminal only) + High Break ** T
Ch1=1300nm single-mode, Ch2=1300nm single-mode + High Break ** U
Ch1=1300nm multi-mode, Ch2=not fitted (2 Terminal only) + High Break ** V
Ch1=1300nm multi-mode, Ch2=1300nm multi-mode + High Break ** W
Ch1=1550nm single-mode, Ch2=not fitted (2 Terminal only) + High Break ** X
Reserved - was used for RWE special Y
Ch1=1550nm single-mode, Ch2=1550nm single-mode + High Break ** Z
Ch1=850nm multi-mode, Ch2=1300nm single-mode + High Break ** 0
Ch1=850nm multi-mode, Ch2=1300nm multi-mode + High Break ** 1
Ch1=850nm multi-mode, Ch2=1550nm single-mode + High Break ** 2
Ch1=1300nm single-mode, Ch2=850nm multi-mode + High Break ** 3
Ch1=1300nm multi-mode, Ch2=850nm multi-mode + High Break ** 4
Ch 1 1550nm single-mode, Ch 2 850nm multi-mode + High Break ** 5
Reserved for future single channel 6
Reserved for future single channel 7
Ch1=1550nm single-mode, Ch2=not fitted (2 Terminal only) + 32 Inputs *** 8
Ch1=1550nm single-mode, Ch2=1550nm single-mode + 32 Inputs *** 9

* Design Suffix G, J, K or M only

** Design Suffix K & M only
*** Design Suffix K or M and software versions 44/54 and later

Protocol options Hardware Compatibilty

K-Bus 1, 2, 3, 4, C, E & F 1
Modbus * 1, 2, 3, 4, 2
IEC60870-5-103 (VDEW) 1, 2, 3, 4, C, E & F 3
DNP3.0 1, 2, 3, 4, C, E & F 4
UCA2 ** 5&6 5
IEC61850 + Courier via rear RS485 port *** 6, A, B,G, H, J, K, L, M, N, P 6
IEC61850 + IEC60870-5-103 via rear RS485 port *** 6, A, B,G, H, J, K, L, M, N, P 7
DNP3.0 Over Ethernet with Courier rear port K-Bus/RS485 protocol **** 6, A, B,G, H, J, K, L, M, N, P 8

* Only on Suffix B, G or J Relays

** Only on Suffix G Relays
*** Only On Suffix K or M Relays
**** Only available On Suffix K or M relays with software versions 44/54 and later

P54x1i-TM-EN-1 A3
Appendix A - Ordering Options P543i/P545i

Variants Order No.

Current differential - With distance backup, P545 **
Mounting
Flush/Panel Mounting with Harsh Environment Coating M
Rack Mounting with Harsh Environmental Coating N
Flush/panel mounting with harsh environment coating P
Rack mounting with harsh environmental coating Q

Language
English, French, German, Spanish 0
English, French, German, Russian * 5
English, Italian, Polish and Portuguese *** 7
Chinese, English or French via HMI, with English or French only via Communications port ** C

* Design Suffix G, J, K & M only

** Design Suffix K or M & 42/52 software and later only
*** Design Suffx M with 65/66/75/76/81/83 software

Software version
Without Distance 4/6/8*
With Distance 5/7/8*

Customer specific options

Standard version 0
Customer version A

Hardware version
Phase 2 Enhanced Coprocessor, wide range opto B
Enhanced Main Processor (CPU2) with hotkeys G
As G plus dual characteristic optos J
Extended main processor (XCPU2) With Function Keys & Tri-colour LEDs K
As K plus increased main processor memory (XCPU3), Cyber Security M

A4 P54x1i-TM-EN-1
 APPENDIX B

SETTINGS AND SIGNALS

Appendix B - Settings and Signals P543i/P545i

Tables, containing a full list of settings, measurement data and DDB signals for each product model, are provided
in a separate interactive PDF file attached as an embedded resource.
Tables are organized into a simple menu system allowing selection by language (where available), model and table
type, and may be viewed and/or printed using an up-to-date version of Adobe Reader.

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P54x1i-TM-EN-1
 APPENDIX C

WIRING DIAGRAMS
Appendix C - Wiring Diagrams P543i/P545i

P54x1i-TM-EN-1
P543i/P545i Appendix C – Wiring Diagrams

MOD CORTEC DRAWING-

EXTERNAL CONNECTION DIAGRAM TITLE ISSUE
EL OPTION* SHEET

Px4x - COMMS OPTIONS MICOM Px40 PLATFORM 10Px4001-1 J

A to R CURRENT DIFF. RELAY (60TE) DISTANCE, 1 OR 3 POLE TRIPPING, AUTO-RECLOSE & CHK SYNCH 10P54302-1 E

A to R CURRENT DIFF. RELAY (60TE) DISTANCE, 1 OR 3 POLE TRIPPING, AUTO-RECLOSE & CHK SYNCH 10P54302-2 E

P543 CURRENT DIFF. RELAY (60TE) 1 OR 3 POLE TRIPPING, AUTO-RECLOSE, CHK SYNCH & HIGH BREAK
S to Z 10P54303-1 E
RELAYS

CURRENT DIFF. RELAY (60TE) 1 OR 3 POLE TRIPPING, AUTO-RECLOSE, CHK SYNCH & HIGH BREAK
S to Z 10P54303-2 D
RELAYS

CURRENT DIFFERENTIAL RELAY (80TE) WITH DISTANCE, 1 OR 3 POLE TRIPPING, AUTO-RECLOSE &
A to R 10P54501-1 H
CHECK SYNCH

CURRENT DIFFERENTIAL RELAY (80TE) WITH DISTANCE, 1 OR 3 POLE TRIPPING, AUTO-RECLOSE &
A to R 10P54501-2 E
CHECK SYNCH
P545
CURRENT DIFF. (80TE) DISTANCE, 1 OR 3 POLE TRIPPING, AUTO-RECLOSE, CHK SYNC & HI BREAK
S to Z 10P54503-1 D
RELAYS

CURRENT DIFF. (80TE) DISTANCE, 1 OR 3 POLE TRIPPING, AUTO-RECLOSE, CHK SYNC & HI BREAK
S to Z 10P54503-2 C
RELAYS
* When selecting the applicable wiring diagram(s), refer to appropriate model’s CORTEC.

NOTE:
V BUSBAR inputs can be used for check sychronisation or measured VN (broken delta).

P54x1i-TM-EN-1 C1
Issue: Revision: Title:
DRAWING OUTLINE UPDATED. CID BLIN-8BHLDT EXTERNAL CONNECTION DIAGRAM: COMMS OPTIONS
J MICOM Px40 PLATFORM
Drg
Date: 30/11/2010 Name: W.LINTERN CAD DATA 1:1 DIMENSIONS: mm ALSTOM GRID UK LTD Sht: 1
Date: Chkd: DO NOT SCALE
Substation Automation Solutions
(STAFFORD)
No:
10Px4001 Next
Sht:
-
 A
DIRECTION OF FORWARD CURRENT FLOW (NOTE 8)
P2 P1
A
S2 S1
B
C B
C PHASE ROTATION
NOTE 6

MiCOM P543 (PART) MiCOM P543 (PART)

C1 5A J11
D1 WATCHDOG
- J12 CONTACT
A D2 OPTO 1
+ J13
A B C WATCHDOG
D3 J14 CONTACT
NOTE 5. C3 1A - J17
D4 OPTO 2 H1
-
C4 5A + H2 RELAY 1
EIA485/
N D5 KBUS NOTE 7
B - H3
D6 OPTO 3 PORT J18 RELAY 2
n + + H4
1A D7 J16 H5
C6 - SCN RELAY 3
D8 OPTO 4 H6
a b c C7 5A
+ H7
C D9
- J1 * H8 RELAY 4
D10 OPTO 5 AC OR DC - H9
+ x J2
C9 1A D11 + H10
- H11
C10 5A D12 OPTO 6 RELAY 5
+ H12
M D13
- H13
NOTE 4 OPTO 7
D14 H14
1A + RELAY 6
C12 H15
D15
C13 5A - H16
N D16 OPTO 8
SENSITIVE + H17 RELAY 7
P2 P1 A
D17 H18
A NOTE 2. TX1
COMMON
S2 S1 1A D18 CONNECTION G1
B C15
F1 RX1 G2 RELAY 8
C B FIBRE OPTIC
C -
F2 OPTO 9 COMMUNICATION G3
A + CURR DIFF G4 RELAY 9
C19 TX2
PARALLEL LINE F3
- G5
PROTECTION
F4 OPTO 10 RX2 G6 RELAY 10
+
F5 G7
- G8
F6 OPTO 11 RELAY 11
B C20 + G9
CONNECT TO P594 GPS
F7 G10
-
F8 OPTO 12 G11
+ RELAY 12
F9 G12
- G13
C C21 F10 OPTO 13
+ G14 RELAY 13
F11 G15
-
F12 OPTO 14 G16
N +
C22 G17
F13 RELAY 14
- G18
C23 OPTO 15
F14
+
V BUSBAR F15
-
(SEE NOTE 3.) OPTO 16
F16 * POWER SUPPLY VERSION 24-48V (NOMINAL) D.C. ONLY
C24 +
F17
COMMON
NOTES 1. F18 CONNECTION
(a) C.T. SHORTING LINKS

(b) PIN TERMINAL (P.C.B. TYPE)

2. USED FOR SEF PROTECTION. SENSITIVE
N SHOULD BE 5. C.T. CONNECTIONS ARE SHOWN 1A CONNECTED AND ARE TYPICAL ONLY.
DRIVEN FROM A CORE BALANCE CT WHEN SENSITIVE
50 OHM BNC CONNECTOR SETTINGS ARE USED. 6. REVERSE PHASE ROTATION IS ALSO SUPPORTED

3. V BUSBAR ONLY REQUIRED IF CHECK SYNCHRONISM FUNCTION ENABLED.

9-WAY & 25-WAY FEMALE D-TYPE SOCKET 7. FOR COMMS OPTIONS SEE DRAWING 10Px4001.
4. MUTUAL CURRENT INPUT ONLY REQUIRED IF ENABLED
IN LINE PARAMETERS. 8. WITH C.T. POLARITY SETTING 'STANDARD'.

Issue: Revision: Title:

FIELD VOLTAGE OUTPUT REMOVED. CID HONG-98JC6A. EXTERNAL CONNECTION DIAGRAM:CURRENT DIFF. RELAY (60TE)
E DISTANCE, 1 OR 3 POLE TRIPPING,AUTO-RECLOSE & CHK SYNCH
Drg
Date: 28/06/2013 Name: N.JOHNSON CAD DATA 1:1 DIMENSIONS: mm ALSTOM GRID UK LTD Sht: 1
Date: Chkd: DO NOT SCALE
Substation Automation Solutions
(STAFFORD)
No:
10P54302 Next
Sht: 2
Issue: Revision: Title:
DRAWING OUTLINE UPDATED. CID BLIN-8BHLDT EXTERNAL CONNECTION DIAG: CURRENT DIFF. RELAY (60TE)
E DISTANCE,1 OR 3 POLE TRIPPING, AUTO-RECLOSE & CHK SYNCH
Drg
Date: 29/11/2010 Name: W.LINTERN CAD DATA 1:1 DIMENSIONS: mm ALSTOM GRID UK LTD Sht: 2
Date: Chkd: DO NOT SCALE
Substation Automation Solutions
(STAFFORD)
No:
10P54302 Next
Sht:
-
 A
DIRECTION OF FORWARD CURRENT FLOW (NOTE 8)
P2 P1
A
S2 S1
B
C B
C PHASE ROTATION
NOTE 6

MiCOM P543 (PART) MiCOM P543 (PART)

C1 5A J11
D1 WATCHDOG
- J12 CONTACT
A D2 OPTO 1
+ J13
A B C WATCHDOG
D3 J14 CONTACT
NOTE 5. 1A - J17
C3 OPTO 2 H1
D4 -
C4 5A + H2 RELAY 1
EIA485/
N D5 KBUS NOTE 7
B - H3
D6 OPTO 3 PORT J18 RELAY 2
n + + H4
1A D7 J16 H5
C6 - SCN RELAY 3
OPTO 4 H6
C7 5A D8
a b c + H7
C D9
- J1 * H8 RELAY 4
D10 OPTO 5 - H9
AC OR DC
+ x J2
1A D11 + H10
C9
-
C10 5A OPTO 6 H11 RELAY 5
D12
+ H12
M D13
- H13
NOTE 4 OPTO 7
D14 H14
1A + RELAY 6
C12 H15
D15
C13 5A - H16
N D16 OPTO 8
SENSITIVE + H17 RELAY 7
A
P2 P1 D17 H18
A NOTE 2. TX1
COMMON
S2 S1 1A D18 CONNECTION G3
B C15
F1 RX1
C C B - FIBRE OPTIC RELAY 8
OPTO 9 COMMUNICATION G4
F2
A + CURR DIFF
C19 TX2 G7
PARALLEL LINE F3
PROTECTION -
F4 OPTO 10 RX2 RELAY 9
+ G8
F5 HIGH BREAK
- G11 CONTACTS
F6 OPTO 11
B C20 + CONNECT TO P594 GPS RELAY 10
F7 G12
-
F8 OPTO 12 G15
+
F9 RELAY 11
- G16
C C21 F10 OPTO 13
+
F11
-
F12 OPTO 14
N +
C22
F13
-
C23 OPTO 15
F14
+
V BUSBAR F15
-
(SEE NOTE 3.) OPTO 16
F16 * POWER SUPPLY VERSION 24-48V (NOMINAL) D.C. ONLY
C24 +
F17
COMMON
NOTES 1. F18 CONNECTION
(a) C.T. SHORTING LINKS

(b) PIN TERMINAL (P.C.B. TYPE)

2. USED FOR SEF PROTECTION. SENSITIVE
N SHOULD BE 5. C.T. CONNECTIONS ARE SHOWN 1A CONNECTED AND ARE TYPICAL ONLY.
DRIVEN FROM A CORE BALANCE CT WHEN SENSITIVE
50 OHM BNC CONNECTOR SETTINGS ARE USED. 6. REVERSE PHASE ROTATION IS ALSO SUPPORTED
3. V BUSBAR ONLY REQUIRED IF CHECK SYNCHRONISM FUNCTION ENABLED.
9-WAY & 25-WAY FEMALE D-TYPE SOCKET 7. FOR COMMS OPTIONS SEE DRAWING 10Px4001.
4. MUTUAL CURRENT INPUT ONLY REQUIRED IF ENABLED
IN LINE PARAMETERS. 8. WITH C.T. POLARITY SETTING 'STANDARD'.

Issue: Revision: Title:

FIELD VOLTAGE OUTPUT REMOVED. CID HONG-98JC6A. EXTERNAL CONN DIAG:CURRENT DIFF.RELAY(60TE) 1 OR 3 POLE
E TRIPPING,AUTO-RECLOSE,CHK SYNCH & HIGH BREAK RELAYS
Drg
Date: 28/06/2013 Name: N.JOHNSON CAD DATA 1:1 DIMENSIONS: mm ALSTOM GRID UK LTD Sht: 1
Date: Chkd: DO NOT SCALE
Substation Automation Solutions
(STAFFORD)
No:
10P54303 Next
Sht: 2
Issue: Revision: Title:
DRAWING OUTLINE UPDATED. CID BLIN-8BHLDT EXTERNAL CONN DIAG:CURRENT DIFF.RELAY (60TE)1 OR 3 POLE
D TRIPPING, AUTO-RECLOSE,CHK SYNCH & HIGH BREAK RELAYS
Drg
Date: 29/11/2010 Name: W.LINTERN CAD DATA 1:1 DIMENSIONS: mm ALSTOM GRID UK LTD Sht: 2
Date: Chkd: DO NOT SCALE
Substation Automation Solutions
(STAFFORD)
No:
10P54303 Next
Sht:
-
 DIRECTION OF FORWARD CURRENT FLOW

MiCOM P545 (PART) MiCOM P545 (PART)

D1 5A M11
E1 WATCHDOG
- M12 CONTACT
A E2 OPTO 1
+ M13
NOTE 7 WATCHDOG
E3 M14 CONTACT
NOTE 5. D3 1A -
E4 OPTO 2 H1 L1
D4 5A + RELAY 25 H2 L2 RELAY 1
E5
B - H3 L3
E6 OPTO 3 RELAY 26 H4 L4 RELAY 2
n +
1A E7 H5 L5
D6 - RELAY 27 RELAY 3 ANY TRIP
OPTO 4 H6 L6
D7 5A E8 NOTE 6.
a b c + H7 L7
C E9 RELAY 28 RELAY 4
- H8 L8
E10 OPTO 5 H9 L9
+
1A E11 RELAY 29 H10 L10 RELAY 5
D9
- H11 L11
D10 5A E12 OPTO 6
+ RELAY 30 H12 L12 RELAY 6
M E13
- H13 L13
NOTE OPTO 7
E14 H14 L14
4. 1A + RELAY 31 RELAY 7
D12 H15 L15
E15
D13 5A - H16 L16
N E16 OPTO 8
SENSITIVE + H17 L17
RELAY 32 RELAY 8
E17 H18 L18
NOTE 2.
COMMON
1A E18 CONNECTION K1
D15
C1 K2 RELAY 9
-
OPTO 9 K3
C2
A + K4 RELAY 10
D19
C3
- K5
C4 OPTO 10 K6 RELAY 11
+
C5 K7
- K8 RELAY 12
B C6 OPTO 11
D20 + M17 K9
C7 - RELAY 13
- EIA485/ SEE DRAWING
K10
C8 OPTO 12 KBUS 10Px4001 K11
+ PORT M18 RELAY 14
C9 + K12
- K13
C OPTO 13 M16
D21 C10 SCN
+ K14 RELAY 15
C11 K15
-
C12 OPTO 14 K16
N +
D22 K17
C13 RELAY 16
- K18
D23 C14 OPTO 15
+ J1
V BUSBAR C15 RELAY 17
- J2
(SEE NOTE 3.) OPTO 16
C16 J3
D24 +
J4 RELAY 18
C17
COMMON J5
C18 CONNECTION J6 RELAY 19
G1 J7
-
G2 OPTO 17 J8 RELAY 20
+
G3 J9
- J10 RELAY 21
G4 OPTO 18
+ J11
G5 J12 RELAY 22
-
2. USED FOR SEF PROTECTION. SENSITIVE
N SHOULD BE OPTO 19
G6 J13
DRIVEN FROM A CORE BALANCE CT WHEN SENSITIVE +
SETTINGS ARE USED. G7 J14 RELAY 23
- M1 * J15
G8 OPTO 20 -
3. V BUSBAR ONLY REQUIRED IF CHECK SYNCHRONISM FUNCTION ENABLED. AC OR DC J16
+ x M2
G9 + J17
4. MUTUAL CURRENT INPUT ONLY REQUIRED IF ENABLED - RELAY 24
G10 OPTO 21 J18
IN FAULT LOCATOR. +
G11
5. C.T. CONNECTIONS ARE SHOWN 1A CONNECTED AND ARE TYPICAL ONLY. - TX1
G12 OPTO 22
+
6. THIS RELAY SHOULD BE ASSIGNED TO ANY TRIP RX1 FIBRE OPTIC
G13
TO ENSURE CORRECT OPERATION OF THE PROTECTIVE RELAY. - COMMUNICATION
G14 OPTO 23 CURR DIFF
7. OPTO INPUTS 1 & 2 MUST BE USED FOR SETTING GROUP + TX2
IF THIS OPTION IS SELECTED IN THE RELAY MENU. G15
-
G16 OPTO 24 RX2
8. FOR COMMS OPTIONS SEE DRAWING 10Px4001. +
G17
COMMON RX1 CONNECT TO P594
G18 CONNECTION

* POWER SUPPLY VERSION 24-48V (NOMINAL) D.C. ONLY

Issue: Revision: Title:

FIELD VOLTAGE OUTPUT REMOVED. CID HONG-98JC6A. EXTERNAL CONNECTION DIAGRAM: CURRENT DIFFERENTIAL RELAY (80TE)
H WITH DISTANCE, 1 OR 3 POLE TRIPPING, AUTO-RECLOSE & CHECK SYNCH
Drg
Date: 28/06/2013 Name: N.JOHNSON CAD DATA 1:1 DIMENSIONS: mm ALSTOM GRID UK LTD Sht: 1
Date: Chkd: B.KIRBY DO NOT SCALE
Substation Automation Solutions
(STAFFORD)
No:
10P54501 Next
Sht: 2
Issue: Revision: Title:
DRAWING OUTLINE UPDATED. CID BLIN-8BHLDT EXT CONN DIAG: CURRENT DIFFERENTIAL RELAY (80TE) WITH DISTANCE,
E 1 OR 3 POLE TRIPPING, AUTO-RECLOSE & CHECK SYNCH
Drg
Date: 30/11/2010 Name: W.LINTERN CAD DATA 1:1 DIMENSIONS: mm ALSTOM GRID UK LTD Sht: 2
Date: Chkd: DO NOT SCALE
Substation Automation Solutions
(STAFFORD)
No:
10P54501 Next
Sht:
-
 A
DIRECTION OF FORWARD CURRENT FLOW (SEE NOTE 8)
P2 P1 MiCOM P545 (PART)
A
M11
S2 S1 WATCHDOG
B M12 CONTACT
C B
C PHASE ROTATION M13
WATCHDOG
SEE NOTE 6 M14 CONTACT
L1
MiCOM P545 (PART) RELAY 1
L2
D1 5A E1 L3
- RELAY 2
A E2 OPTO 1 L4
+ L5
A B C
E3 RELAY 3
1A - L6
NOTE 5. D3
E4 OPTO 2 L7
D4 5A +
N E5 L8 RELAY 4
B -
OPTO 3 L9
E6
n + L10 RELAY 5
1A E7
D6 - L11
D7 5A E8 OPTO 4 L12 RELAY 6
a b c +
E9 L13
C - L14 RELAY 7
E10 OPTO 5
+ L15
1A E11
D9 L16
-
D10 5A E12 OPTO 6 L17
+ RELAY 8
M E13 L18
NOTE 4. -
E14 OPTO 7 K1
1A + RELAY 9
D12 K2
E15
A D13 5A - K3
P2 P1 N E16 OPTO 8 RELAY 10
A + K4
SENSITIVE
S2 S1 E17 K5
B NOTE 2.
COMMON K6 RELAY 11
1A E18 CONNECTION
C C B D15 K7
C1 RELAY 12
- K8
PARALLEL LINE C2 OPTO 9 M17 K9
PROTECTION A + -
D19 K10 RELAY 13
C3 EIA485/ NOTE 7
- KBUS K11
C4 OPTO 10 M18
+ PORT RELAY 14
+ K12
C5 K13
- M16
C6 OPTO 11 SCN K14
B D20 + RELAY 15
C7 K15
- K16
C8 OPTO 12
+ K17 RELAY 16
C9 K18
-
C D21 C10 OPTO 13 J3
+
C11 RELAY 17
- J4
C12 OPTO 14
N + J7
D22
C13
- RELAY 18
D23 OPTO 15
C14 J8
+
NOTES 1. HIGH BREAK
V BUSBAR C15 J11 CONTACTS
C.T. SHORTING LINKS -
(a) (SEE NOTE 3.) OPTO 16
C16 RELAY 19
D24 + J12
C17
COMMON J15
(b) PIN TERMINAL (P.C.B. TYPE) C18 CONNECTION
RELAY 20
G1 J16
-
50 OHM BNC CONNECTOR G2 OPTO 17
+ H3
G3 M1 * RELAY 21
- - H4
9-WAY & 25-WAY FEMALE D-TYPE SOCKET G4 OPTO 18 AC OR DC
+
x M2
+ H7
G5
-
2. USED FOR SEF PROTECTION. SENSITIVE
N SHOULD BE OPTO 19 RELAY 22
G6 H8
DRIVEN FROM A CORE BALANCE CT WHEN SENSITIVE +
SETTINGS ARE USED. G7 HIGH BREAK
- H11 CONTACTS
G8 OPTO 20
3. V BUSBAR ONLY REQUIRED IF CHECK SYNCHRONISM FUNCTION ENABLED. + RELAY 23
G9 H12
4. MUTUAL CURRENT INPUT ONLY REQUIRED IF ENABLED -
G10 OPTO 21 H15
IN LINE PARAMETERS. +
G11 RELAY 24
5. C.T. CONNECTIONS ARE SHOWN 1A CONNECTED AND ARE TYPICAL ONLY. - H16
G12 OPTO 22
+
6. REVERSE PHASE ROTATION IS ALSO SUPPORTED. G13 TX1
-
7. FOR COMMS OPTIONS SEE DRAWING 10Px4001. G14 OPTO 23
+ RX1 FIBRE OPTIC
G15 COMMUNICATION
8. WITH C.T. POLARITY SETTING 'STANDARD'. - CURR DIFF
G16 OPTO 24 TX2
+
G17
RX2
COMMON
G18 CONNECTION
RX1 CONNECT TO P594

* POWER SUPPLY VERSION 24-48V (NOMINAL) D.C. ONLY

Issue: Revision: Title:

FIELD VOLTAGE OUTPUT REMOVED. CID HONG-98JC6A. EXTERNAL CONN DIAG.:CURRENT DIFF. (80TE)DISTANCE,1 OR 3
D POLE TRIPPING, AUTO-RECLOSE,CHK SYNC & HI BREAK RELAYS
Drg
Date: 28/06/2013 Name: N.JOHNSON CAD DATA 1:1 DIMENSIONS: mm ALSTOM GRID UK LTD Sht: 1
Date: Chkd: DO NOT SCALE
Substation Automation Solutions
(STAFFORD)
No:
10P54503 Next
Sht: 2
 DEFAULT SETTING E1
-
E2 M11
+ WATCHDOG
E3 M12 CONTACT
- M13
E4 WATCHDOG
+ M14 CONTACT DEFAULT SETTING
E5
- L1
E6 SEE NOTE 1 SEE NOTE 1 L2 RELAY 1
+
E7 L3
-
SEE NOTE 1 L4 RELAY 2
E8
+ L5
E9
- L6 RELAY 3
E10
+ L7
E11 RELAY 4
- L8
E12 L9
+
E13 L10 RELAY 5
-
E14 L11
+ L12 RELAY 6
E15
- L13
E16
+ L14 RELAY 7
E17
L15
E18 L16

-
C1 (PART) L17
RELAY 8
C2 L18
+
C3 K1
-
K2 RELAY 9
C4
+ K3
C5
- K4 RELAY 10
C6
+ K5
C7 RELAY 11
- K6
C8 K7
+
C9 K8 RELAY 12
-
C10 K9
+ RELAY 13
C11 K10
- K11
C12 RELAY 14
+ K12
C13
- K13
C14 K14
+ RELAY 15
C15 K15
-
C16 K16
+ K17
C17 RELAY 16
K18
C18
J3

G1 RELAY 17
- J4
G2
+ J7
G3
- RELAY 18
G4 J8
+ HIGH BREAK
G5 J11 CONTACTS
-
G6 RELAY 19
+ J12
G7
- J15
G8
+ RELAY 20
G9 J16
-
G10 H3
+
G11 RELAY 21
- H4
G12
+ H7
G13
- RELAY 22
G14 H8
+ HIGH BREAK
G15 H11 CONTACTS
-
G16 RELAY 23
+ H12
G17
COMMON H15
CONNECTION G18
RELAY 24
H16

NOTE1:
ONLY FOR RELAYS WITH DISTANCE PROTECTION OPTION.

Issue: Revision: Title:

DRAWING SHEET OUTLINE UPDATED. (NO DRAWING CHANGES). CID: TBEA-8ALFN6 EXTERNAL CONN DIAG.:CURRENT DIFF. (80TE)DISTANCE,1 OR 3
C POLE TRIPPING, AUTO-RECLOSE,CHK SYNC & HI BREAK RELAYS
Drg
Date: 27/10/2010 Name: T.BEACHAM CAD DATA 1:1 DIMENSIONS: mm ALSTOM GRID UK LTD Sht: 2
Date: Chkd: DO NOT SCALE
Substation Automation Solutions
(STAFFORD)
No:
10P54503 Next
Sht:
-
Imagination at work

Grid Solutions
St Leonards Building
Redhill Business Park
Stafford, ST16 1WT, UK
+44 (0) 1785 250 070
www.gegridsolutions.com/contact

© 2017 General Electric. All rights reserved. Information contained in this document is indicative only. No representation or warranty is given or
should be relied on that it is complete or correct or will apply to any particular project. This will depend on the technical and commercial
circumstances. It is provided without liability and is subject to change without notice. Reproduction, use or disclosure to third parties, without
express written authority, is strictly prohibited.

P54x1i-TM-EN-1