GE

Grid Solutions

MiCOM P40 Agile Enhanced

P14D

Technical Manual
Feeder Management IED

Hardware Version: E
Software Version: 01
Publication Reference: P14DEnh-TM-EN-1.1
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 4
2.4 Compliance 5
3 Product Scope 6
3.1 Ordering Options 6
4 Features and Functions 7
4.1 Description of the P14D Feeder Protection System 7
4.2 Introduction to Logical Devices 7
4.3 Protection Functions 8
4.4 Control Functions 9
4.5 Measurement Functions 10
4.6 Communication Functions 11
4.7 System Functions 12
4.8 Main Menu 13
5 Logic Diagrams 14
6 Functional Overview 16

Chapter 2 Safety Information 17

1 Chapter Overview 19
2 Health and Safety 20
3 Symbols 21
4 Installation, Commissioning and Servicing 22
4.1 Lifting Hazards 22
4.2 Electrical Hazards 22
4.3 Fusing Requirements 23
4.4 Equipment Connections 23
4.5 Protection Class 1 Equipment Requirements 24
4.6 Pre-energisation Checklist 24
4.7 Peripheral Circuitry 25
4.8 Upgrading/Servicing 26
5 Decommissioning and Disposal 27
6 Regulatory Compliance 28
6.1 EMC Compliance: 2014/30/EU 28
6.2 LVD Compliance: 2014/35/EU 28
6.3 RoHS Compliance 2011/65/EU and (EU) 2015/863 28
6.4 Morocco Compliance 28

Chapter 3 Hardware Design 29

1 Chapter Overview 31
2 Hardware Architecture 32
2.1 Memory and Real Time Clock 32
3 Mechanical Implementation 34
3.1 Housing Variants 35
3.2 20TE Rear Panel 36
4 Terminal Connections 37
4.1 I/O Options 37
5 Front Panel 38
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5.1 20TE Front Panel 38

5.2 Keypad 39
5.3 Liquid Crystal Display 39
5.4 USB Port 39
5.5 Fixed Function LEDs 40
5.6 Programable LEDs 40

Chapter 4 Software Design 41

1 Chapter Overview 43
2 Software Design Overview 44
3 System Level Software 45
3.1 Real Time Operating System 45
3.2 System Services Software 45
3.3 Self-Diagnostic Software 45
3.4 Startup Self-Testing 45
3.4.1 System Boot 45
3.4.2 System Level Software Initialisation 45
3.4.3 Platform Software Initialisation and Monitoring 46
3.5 Continuous Self-Testing 46
4 Platform Software 47
4.1 Record Logging 47
4.2 Settings Database 47
4.3 Interfaces 47
5 Protection and Control Functions 48
5.1 Acquisition of Samples 48
5.2 Frequency Tracking 48
5.3 Fourier Signal Processing 48
5.4 Programmable Scheme Logic 49
5.5 Event Recording 49
5.6 Disturbance Recorder 49
5.7 Fault Locator 50

Chapter 5 Configuration 51
1 Chapter Overview 53
2 Settings Application Software 54
2.1 Setpoint Entry Methods 54
2.2 Common Setpoints 54
2.3 Setpoints Text Abbreviations 56
3 Using the HMI Panel 57
3.1 Navigating the HMI Panel 58
3.2 Getting Started 58
3.3 Default Display 59
3.4 Default Display Navigation 59
3.5 Password Entry 60
3.6 Processing Alarms and Records 60
3.7 Menu Structure 60
3.8 Changing the Settings 60
4 Device 62
4.1 Date and Time Configuration 62
4.1.1 Clock 63
4.1.2 SNTP Protocol 63
4.2 Security 63
4.3 Communications 63
4.4 Disturbance Recorder 64
4.5 Data Logger 64

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4.6 Event Data 64

4.7 Flex States 64
4.8 Front Panel 64
4.8.1 Display Properties 64
4.8.2 Default Screens 64
4.9 Resetting 64
4.10 Clear Records 65
5 System 66
5.1 CT Ratio 66
5.2 VT Ratio 67
5.3 Power System 68
5.4 CB Setup 68
5.5 User Curves 69

Chapter 6 Current Protection Functions 71

1 Chapter Overview 73
2 Overcurrent Protection Principles 74
2.1 IDMT Characteristics 74
2.1.1 IEC 60255 IDMT Curves 75
2.1.2 European Standards 77
2.1.3 North American Standards 79
2.1.4 IEC and IEEE Inverse Curves 81
2.1.5 ANSI Curves 82
2.1.6 IAC Curves 83
2.1.7 I2T Curves 83
2.1.8 I4T Curves 84
2.1.9 Differences Between the North american and European Standards 84
2.1.10 Programmable Curves 84
2.2 Principles of Implementation 84
2.2.1 Timer Hold Facility 85
3 Phase Overcurrent Protection 87
3.1 Phase Overcurrent Protection Implementation 87
3.2 Non-Directional Overcurrent Logic 88
3.3 Directional Element 88
3.4 Directional Overcurrent Logic 90
3.5 Application Notes 91
3.5.1 Parallel Feeders 91
3.5.2 Ring Main Arrangements 92
3.5.3 Setting Guidelines 92
3.5.4 Setting Guidelines (Directional Element) 93
4 Voltage Dependent Overcurrent Element 94
4.1 Voltage Dependent Overcurrent Protection Implementation 94
4.1.1 Voltage Controlled Overcurrent Protection 94
4.1.2 Voltage Restrained Overcurrent Protection 95
4.1.3 Voltage Dependent Overcurrent Logic 96
4.2 Application Notes 96
4.2.1 Setting Guidelines 96
5 Negative Sequence Overcurrent Protection 98
5.1 Negative Sequence Overcurrent Protection Implementation 98
5.2 Non-Directional Negative Sequence Overcurrent Logic 98
5.3 Directional Element 99
5.3.1 Directional Negative Sequence Overcurrent 99
5.3.2 Directional Negative Sequence Overcurrent Logic 100
5.4 Application Notes 101
5.4.1 Setting Guidelines (Current Threshold) 101
5.4.2 Setting Guidelines (Time Delay) 101
5.4.3 Setting Guidelines (Directional element) 101

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6 Earth Fault Protection 103

6.1 Earth Fault Protection Elements 103
6.2 Non-directional Earth Fault Logic 104
6.3 Directional Element 104
6.3.1 Residual Voltage Polarisation 106
6.4 Application Notes 107
6.4.1 Setting Guidelines (Directional Element) 107
6.4.2 Petersen Coil Earthed Systems 107
6.4.3 Setting Guidelines (Compensated networks) 111
7 Sensitive Earth Fault Protection 113
7.1 SEF Protection Implementation 113
7.2 Non-directional SEF Logic 113
7.3 Directional Element 114
7.3.1 Directional SEF Logic 114
7.4 Application Notes 117
7.4.1 Insulated Systems 117
7.4.2 Setting Guidelines (Insulated Systems) 118
8 Cold Load Pickup 120
8.1 Implementation 120
8.2 CLP Logic 121
8.3 Application Notes 121
8.3.1 CLP for Resistive Loads 121
8.3.2 CLP for Motor Feeders 121
8.3.3 CLP for Switch Onto Fault Conditions 122
9 Thermal Overload Protection 123
9.1 Single Time Constant Characteristic 123
9.2 Dual Time Constant Characteristic 123
9.3 Thermal Overload Protection Implementation 124
9.4 Thermal Overload Protection Logic 124
9.5 Application Notes 125
9.5.1 Setting Guidelines for Dual Time Constant Characteristic 125
9.5.2 Setting Guidelines for Single Time Constant Characteristic 126
10 Broken Conductor Protection 128
10.1 Broken Conductor Protection Implementation 128
10.2 Broken Conductor Protection Logic 128
10.3 Application Notes 128
10.3.1 Setting Guidelines 128
11 Blocked Overcurrent Protection 130
11.1 Blocked Overcurrent Implementation 130
11.2 Application Notes 130
11.2.1 Busbar Blocking Scheme 130
12 SOTF Protection 132
12.1 SOTF Implementationn 132
12.2 SOTF Logic 132
13 Undercurrent Protection 133
13.1 Undercurrent Implementation 133
13.2 Undercurrent Logic 133

Chapter 7 Restricted Earth Fault Protection 135

1 Chapter Overview 137
2 REF Protection Principles 138
2.1 Resistance-Earthed Star Windings 139
2.2 Solidly-Earthed Star Windings 139
2.3 Through Fault Stability 140
2.4 Restricted Earth Fault Types 140
2.4.1 Low Impedance REF Principle 141

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2.4.2 High Impedance REF Principle 142

3 Restricted Earth Fault Protection Implementation 144
3.1 Restricted Earth Fault Protection Settings 144
3.2 Low Impedance REF 144
3.2.1 Setting the Bias Characteristic 144
3.3 High Impedance REF 145
3.3.1 High Impedance REF Calculation Principles 146
4 Application Notes 147
4.1 Star Winding Resistance Earthed 147
4.2 Low Impedance REF Protection Application 148
4.2.1 Setting Guidelines for Biased Operation 148
4.2.2 Low Impedance REF Scaling Factor 148
4.2.3 Parameter Calculations 149
4.3 High Impedance REF Protection Application 149
4.3.1 High Impedance REF Operating Modes 149
4.3.2 Setting Guidelines for High Impedance Operation 151

Chapter 8 CB Fail Protection 155

1 Chapter Overview 157
2 Circuit Breaker Fail Protection 158
3 Circuit Breaker Fail Implementation 159
3.1 Circuit Breaker Failure Initiation 159
3.2 Circuit Breaker Failure Determination 159
3.3 Circuit Breaker Failure Outputs 160
4 Circuit Breaker Fail Logic 161
5 Circuit Breaker Mapping 162
6 Application Notes 163
6.1 Reset Mechanisms for CB Fail Timers 163
6.2 Setting Guidelines (CB fail Timer) 163

Chapter 9 Current Transformer Requirements 165

1 Chapter Overview 167
2 CT requirements 168
2.1 Phase Overcurrent Protection 168
2.1.1 Directional Elements 168
2.1.2 Non-directional Elements 169
2.2 Earth Fault Protection 169
2.2.1 Directional Elements 169
2.2.2 Non-directional Elements 169
2.3 SEF Protection (Residually Connected) 169
2.3.1 Directional Elements 169
2.3.2 Non-directional Elements 170
2.4 SEF Protection (Core-Balanced CT) 170
2.4.1 Directional Elements 170
2.4.2 Non-directional Elements 170
2.5 Low Impedance REF Protection 170
2.6 High Impedance REF Protection 171
2.7 High Impedance Busbar Protection 171
2.8 Use of Metrosil Non-linear Resistors 171
2.9 Use of ANSI C-class CTs 173

Chapter 10 Voltage Protection Functions 175

1 Chapter Overview 177
2 Undervoltage Protection 178
2.1 Undervoltage Protection Implementation 178

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2.2 Undervoltage Protection Logic 179

2.3 Application Notes 180
2.3.1 Undervoltage Setting Guidelines 180
3 Overvoltage Protection 181
3.1 Overvoltage Protection Implementation 181
3.2 Overvoltage Protection Logic 182
3.3 Application Notes 183
3.3.1 Overvoltage Setting Guidelines 183
4 Residual Overvoltage Protection 184
4.1 Residual Overvoltage Protection Implementation 184
4.2 Residual Overvoltage Logic 185
4.3 Application Notes 185
4.3.1 Calculation for Solidly Earthed Systems 185
4.3.2 Calculation for Impedance Earthed Systems 186
4.3.3 Setting Guidelines 187
5 Negative Sequence Overvoltage Protection 188
5.1 Negative Sequence Overvoltage Implementation 188
5.2 Negative Sequence Overvoltage Logic 188
5.3 Application Notes 188
5.3.1 Setting Guidelines 188
6 Positive Sequence Undervoltage Protection 190
6.1 Positive Sequence Undervoltage Implementation 190
6.2 Positive Sequence Undervoltage Logic 190
7 Positive Sequence Overvoltage Protection 191
7.1 Positive Sequence Overvoltage Implementation 191
7.2 Positive Sequence Overvoltage Logic 191

Chapter 11 Frequency Protection Functions 193

1 Chapter Overview 195
2 Frequency Protection Overview 196
2.1 Frequency Protection Implementation 196
3 Underfrequency Protection 197
3.1 Underfrequency Protection Implementation 197
3.2 Underfrequency Protection Logic 197
3.3 Application Notes 197
3.3.1 Setting Guidelines 197
4 Overfrequency Protection 199
4.1 Overfrequency Protection Implementation 199
4.2 Overfrequency Protection Logic 199
4.3 Application Notes 199
4.3.1 Setting Guidelines 199
5 Independent R.O.C.O.F Protection 201
5.1 Independent R.O.C.O.F Protection Implementation 201
5.2 Independent R.O.C.O.F Protection Logic 202
5.3 Application Notes 202
5.3.1 Setting Guidelines 202

Chapter 12 Power Protection Functions 205

1 Chapter Overview 207
2 Overpower Protection 208
2.1 Overpower Protection Implementation 208
2.2 Overpower Logic 208
2.3 Application Notes 209
2.3.1 Forward Overpower Setting Guidelines 209
2.3.2 Reverse Power Considerations 209

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2.3.3 Reverse Overpower Setting Guidelines 209

3 Underpower Protection 211
3.1 Underpower Protection Implementation 211
3.2 Underpower Logic 211
3.3 Application Notes 212
3.3.1 Low Forward Power Considerations 212
3.3.2 Low Forward Power Setting Guidelines 212

Chapter 13 Autoreclose 213

1 Chapter Overview 215
2 Introduction to 3-phase Autoreclose 216
3 Implementation 217
4 Autoreclose Function Inputs 218
4.1 CB Healthy 218
4.2 Block AR 218
4.3 Reset Lockout 218
4.4 AR Auto Mode 218
4.5 AR LiveLine Mode 218
4.6 Telecontrol Mode 218
4.7 Live/Dead Ccts OK (Live/Dead Circuits OK) 218
4.8 AR Sys Checks (AR System Checks) 218
4.9 Ext AR Prot Trip (External AR Protection Trip) 219
4.10 Ext AR Prot Start (External AR Protection Start) 219
4.11 DAR Complete (Delayed Autoreclose Complete) 219
4.12 CB in Service (Circuit Breaker in Service) 219
4.13 AR Restart 219
4.14 DT OK To Start (Dead Time OK to Start) 219
4.15 DeadTime Enabled 219
4.16 AR Init TripTest (Initiate Trip Test) 220
4.17 AR Skip Shot 1 220
4.18 Inh Reclaim Time (Inhibit Reclaim Time) 220
5 Autoreclose Function Outputs 221
5.1 AR In Progress 221
5.2 DAR In Progress 221
5.3 Sequence Counter Status signals 221
5.4 Successful Close 221
5.5 AR In Service 221
5.6 AR Blk Main Prot (Block Main Protection) 221
5.7 AR Blk SEF Prot (Block SEF Protection) 221
5.8 Reclose Checks 221
5.9 DeadTime In Prog 222
5.10 DT Complete (Dead Time Complete) 222
5.11 AR Sync Check (AR Synchronisation Check) 222
5.12 AR SysChecks OK (AR System Checks OK) 222
5.13 Auto Close 222
5.14 Protection Lockt (Protection Lockout) 222
5.15 Reset Lckout Alm (Reset Lockout Alarm) 222
5.16 Reclaim In Prog 222
5.17 Reclaim Complete 222
6 Autoreclose Function Alarms 223
6.1 AR No Sys Check 223
6.2 AR CB Unhealthy 223
6.3 AR Lockout 223
7 Autoreclose Operation 224
8 Operating Modes 225
8.1 Four-Position Selector Switch Implementation 225

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8.2 Operating Mode Selection Logic 227

8.3 Autoreclose Initiation 227
8.3.1 Start Signal Logic 228
8.3.2 Trip Signal Logic 229
8.3.3 Blocking Signal Logic 229
8.3.4 Shots Exceeded Logic 229
8.3.5 AR Initiation Logic 230
8.4 Blocking Instantaneous Protection for Selected Trips 230
8.5 Blocking Instantaneous Protection for Lockouts 231
8.6 Dead Time Control 233
8.6.1 AR CB Close Control 233
8.7 AR System Checks 234
8.8 Reclaim Timer Initiation 235
8.9 Autoreclose Inhibit 236
8.10 Autoreclose Lockout 237
8.11 Sequence Co-ordination 239
8.12 System Checks for First Reclose 240
9 Setting Guidelines 241
9.1 Number of Shots 241
9.2 Dead Timer Setting 241
9.2.1 Stability and Synchronism Requirements 241
9.2.2 Operational Convenience 241
9.2.3 Load Requirements 242
9.2.4 Circuit Breaker 242
9.2.5 Fault De-ionisation Time 242
9.2.6 Protection Reset Time 242
9.3 Reclaim Timer Setting 243

Chapter 14 Monitoring and Control 245

1 Chapter Overview 247
2 Event Records 248
2.1 Event Types 248
2.1.1 Opto-input Events 248
2.1.2 Contact Events 248
2.1.3 Alarm Events 249
2.1.4 Fault Record Events 249
2.1.5 Security Events 249
2.1.6 Protection Events 249
2.1.7 Platform Events 249
2.2 Flex States 249
2.2.1 Flex Elements 250
2.2.2 Event Data 252
2.3 Read Only Mode 252
2.4 Setpoint Group 253
3 Measurements 254
3.1 Measured Quantities 254
3.1.1 Measured and Calculated Currents 254
3.1.2 Measured and Calculated Voltages 254
3.1.3 Power and Energy Quantities 254
3.1.4 Demand Values 254
3.1.5 Frequency Measurements 255
3.1.6 Other Measurements 255
3.2 Fault Locator 255
3.3 Fault Locator Settings Example 255
3.4 Opto-input Time Stamping 256
4 CB Health Monitoring 257
4.1 Application Notes 257

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4.1.1 Setting the Thresholds for the Arc Energy 257

4.1.2 Setting the thresholds for the Number of Operations 257
4.1.3 Setting the thresholds for the Operating Time 257
4.1.4 Setting the Thresholds for Excesssive Fault Frequency 258
5 CB State Monitoring 259
5.1 CB State Monitoring Logic 260
6 Circuit Breaker Control 261
6.1 CB Control using the IED Menu 261
6.2 CB Control using the Hotkeys 262
6.3 CB Control using the Opto-inputs 262
6.4 Remote CB Control 263
6.5 Synchronisation Check 263
6.6 CB Healthy Check 263
6.7 CB Control Logic 264
6.8 CB Arcing Current 264
7 Pole Dead Function 266
7.1 Pole Dead Logic 266
8 Synchrocheck 267
9 Synchrocheck Implementation 268
9.1 VT Connections 268
9.2 Voltage Monitoring 268
9.3 Check Synchronisation 268
9.4 System Check Logic 269
10 System Check PSL 270
11 Switch Status and Control 271
11.1 Switch Status Logic 272
11.2 Switch Control Logic 273
12 Harmonic Detection 274
13 Pole Discrepancy 275

Chapter 15 Supervision 281

1 Chapter Overview 283
2 DC Supply Monitor 284
2.1 DC Supply Monitor Implementation 284
2.2 DC Supply Monitor Logic 285
3 Voltage Transformer Supervision 286
3.1 Loss of One or Two Phase Voltages 286
3.2 Loss of all Three Phase Voltages 286
3.3 VTS Implementation 286
3.4 VTS Logic 286
4 Current Transformer Supervision 288
4.1 CTS Implementation 288
4.2 CTS Logic 289
4.3 Application Notes 289
4.3.1 Setting Guidelines 289
5 Trip Circuit Supervision 290
5.1 Trip Circuit Supervision Scheme 1 290
5.1.1 Resistor Values 290
5.1.2 PSL for TCS Scheme 1 291
5.2 Trip Circuit Supervision Scheme 2 291
5.2.1 Resistor Values 292
5.2.2 PSL for TCS Scheme 2 292
5.3 Trip Circuit Supervision Scheme 3 292
5.3.1 Resistor Values 293
5.3.2 PSL for TCS Scheme 3 293
5.4 Trip Circuit Supervision Scheme 4 293

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5.4.1 Resistor Values 294

5.4.2 PSL for TCS Scheme 4 294

Chapter 16 Digital I/O and PSL Configuration 295

1 Chapter Overview 297
2 Configuring Digital Inputs and Outputs 298
3 Scheme Logic 299
3.1 PSL Editor 300
3.2 PSL Schemes 300
4 Configuring the Opto-Inputs 301
5 Fixed Function LEDs 302
6 Virtual Inputs 303
7 Outputs 304
7.1 Output Relays 304
7.2 Assigning the Output Relays 304
7.3 Virtual Outputs 305

Chapter 17 Communications 307

1 Chapter Overview 309
2 Communication Interfaces 310
3 Serial Communication 311
3.1 Modbus Protocol 311
3.1.1 EIA(RS)485 Biasing Requirements 311
3.2 EIA (RS 485 Bus 312
4 Ethernet Communication 314
4.1 USB 314
5 Data Protocols 315
5.1 IEC 60870-5-103 315
5.1.1 Physical Connection and Link Layer 316
5.1.2 Initialisation 316
5.1.3 Time Synchronisation 316
5.1.4 EC103 Interoperability 316
5.2 DNP 3.0 321
5.2.1 Physical Connection and Link Layer 321
5.2.2 Object 1 Binary Inputs 322
5.2.3 Object 10 Binary Outputs 323
5.2.4 Object 20 Binary Counters 323
5.2.5 Object 30 Analogue Input 324
5.2.6 DNP3 Device Profile 324
5.3 MODBUS 332
5.3.1 Physical Connection and Link Layer 332
5.3.2 Response Codes 333
5.3.3 IEC 61850 333
6 Time Synchronisation 338
6.1 Demodulated IRIG-B 338
6.1.1 Demodulated IRIG-B Implementation 339
6.2 SNTP 339
6.3 Time Synchronisation using the Communication Protocols 339

Chapter 18 Cyber-Security 341

1 Overview 343
2 The Need for Cyber-Security 344
3 Standards 345
3.1 NERC Compliance 345
3.1.1 CIP 002 346

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3.1.2 CIP 003 346

3.1.3 CIP 004 346
3.1.4 CIP 005 346
3.1.5 CIP 006 346
3.1.6 CIP 007 347
3.1.7 CIP 008 347
3.1.8 CIP 009 347
3.2 IEEE 1686-2013 347
3.3 IEC 62351 348
4 Cyber-Security Implementation 350
4.1 RBAC Functionality 350
4.2 Basic Security Implementation 351
4.2.1 Device/Local Authentication 351
4.2.2 Four-level Access 351
4.2.3 Bypass Access 352
4.2.4 Enhanced Password Security 352
4.2.5 Disabling Physical and Logical Ports 352
4.3 Advanced Cyber-Security Implementation 353
4.3.1 Server/Remote Authentication 353
4.3.2 Unique Configurable Usernames 354
4.3.3 Secure Encrypted Communication 354
4.3.4 Syslog 355
4.3.5 Increased Product Hardening 356
4.4 Additional Features 356
4.4.1 LostPassword 356
4.4.2 Loading Factory Configuration 356

Chapter 19 Installation 357

1 Chapter Overview 359
2 Product Identification 360
3 Handling the Goods 361
3.1 Receipt of the Goods 361
3.2 Unpacking the Goods 361
3.3 Storing the Goods 361
3.4 Dismantling the Goods 361
4 Mounting the Device 362
4.1 Flush Panel Mounting 362
4.1.1 Rack Mounting 362
4.1.2 Draw-out Unit Withdrawal and Insertion 363
4.2 Software Only 364
5 Cables and Connectors 365
5.1 Lug Orientation 365
5.2 Terminal Blocks 365
5.3 Power Supply Connections 366
5.4 Earth Connnection 366
5.5 Phase Sequence and Transformer Polarity 367
5.6 Current Transformers 367
5.7 Voltage Transformer Connections 368
5.8 Watchdog Connections 368
5.9 EIA(RS)485 Connections 368
5.10 IRIG-B Connection 368
5.11 Opto-input Connections 369
5.12 Output Relay Connections 370
5.13 Ethernet Metallic Connections 370
5.14 Ethernet Fibre Connections 370
5.15 USB Connection 370
6 Case Dimensions and Panel Cutout 371

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Chapter 20 Commissioning Instructions 373

1 Chapter Overview 375
2 General Guidelines 376
3 Commissioning Test Menu 377
3.1 Opto I/P Status Element (Opto-input Status) 377
3.2 Relay O/P Status Element (Relay Output Status) 377
3.3 Testing 377
3.4 Autoreclose Testing 378
4 Commissioning Equipment 380
4.1 Recommended Commissioning Equipment 380
4.2 Essential Commissioning Equipment 380
4.3 Advisory Test Equipment 381
5 Product Checks 382
5.1 Product Checks with the IED De-energised 382
5.1.1 Visual Inspection 382
5.1.2 Insulation 383
5.1.3 External Wiring 383
5.1.4 Watchdog Contacts 383
5.1.5 Power Supply 383
5.2 Product Checks with the IED Energised 383
5.2.1 Watchdog Contacts 384
5.2.2 Date and Time 384
5.2.3 Test LEDs 384
5.2.4 Test Opto-inputs 384
5.2.5 Test Relay Outputs 384
5.2.6 Test Serial Communication Port COM1 385
5.2.7 Test Ethernet Communication 385
5.2.8 Test Current Inputs 385
5.2.9 Test Voltage Inputs 386
6 Setting Checks 387
6.1 Apply Application-specific Settings 387
6.1.1 Transferring Settings from a Settings File 387
6.1.2 Entering settings using the HMI 387
7 Protection Timing Checks 389
7.1 Overcurrent Check 389
7.2 Connecting the Test Circuit 389
7.3 Performing the Test 389
7.4 Check the Operating Time 389
8 Onload Checks 390
8.1 Confirm Current Connections 390
8.2 Confirm Voltage Connections 390
8.3 On-load Directional Test 390
9 Final Checks 392

Chapter 21 Testing 393

1 Chapter Overview 395
2 Testing Features 396
3 Simulation 397
3.1 Pre-Fault 397
3.2 Fault 397
3.3 Post-Fault 398
4 Test LEDs 399
5 Output Relays 400
6 Autoreclose 401

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Chapter 22 Maintenance and Troubleshooting 403

1 Chapter Overview 405
2 Maintenance 406
2.1 Maintenance Checks 406
2.1.1 Targets and Alarms 406
2.1.2 Opto-isolators 406
2.1.3 Output Relays 406
2.1.4 Measurement Accuracy 407
2.1.5 External Damage 407
2.1.6 Records 407
2.1.7 Out-of-Service Maintenance 407
2.1.8 Unscheduled Maintenance (system interruption) 407
2.2 Replacing the Unit 407
2.3 Cleaning 408
3 Troubleshooting 409
3.1 Self-Diagnostic Software 409
3.2 Power-up Errors 409
3.3 Self-test Errors 409
3.4 Error Code during Operation 412
3.5 Mal-operation during testing 413
3.5.1 Failure of Output Contacts 413
3.5.2 Failure of Opto-inputs 413
3.5.3 Incorrect Analogue Signals 413
3.6 PSL Editor Troubleshooting 413
3.6.1 Diagram Reconstruction 414
3.6.2 PSL Version Check 414
3.7 Repair and Modification Procedure 414

Chapter 23 Technical Specifications 417

1 Chapter Overview 419
2 Interfaces 420
2.1 Rear Serial Port 1 420
2.2 IRIG-B Port (shared with rear serial port COM1) 420
2.3 Rear Ethernet Port Copper 420
2.4 Front USB Port 420
3 Performance of Current Protection Functions 421
3.1 Three-phase Overcurrent Protection (Directional/ Non-directional) 421
3.1.1 Three-phase Overcurrent Directional Parameters 421
3.2 Earth Fault Protection (Directional/ Non-directional) 421
3.2.1 Earth Fault Directional Parameters 422
3.3 Sensitive Earth Fault Protection (Directional/Non-directional) 422
3.3.1 SEF Directional Parameters 422
3.4 Restricted Earth Fault Protection 422
3.5 Negative Sequence Overcurrent Protection (Directional/Non-directional) 422
3.5.1 Directional Parameters 423
3.6 Circuit Breaker Fail 423
3.7 Broken Conductor Protection 423
3.8 Thermal Overload Protection 423
3.9 Cold Load Pickup Protection 423
3.10 Undercurrent 424
4 Performance of Voltage Protection Functions 425
4.1 Undervoltage Protection 425
4.2 Overvoltage Protection 425
4.3 Residual Overvoltage Protection 425
4.4 Positive Sequence Voltage Protection 425

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4.5 Negative Sequence Voltage Protection 426

5 Performance of Frequency Protection Functions 427
5.1 Overfrequency Protection 427
5.2 Underfrequency Protection 427
5.3 Frequency Rate of Change Protection 427
6 Power Protection Functions 428
6.1 Overpower / Underpower Protection 428
7 Performance of Monitoring and Control Functions 429
7.1 Voltage Transformer Supervision 429
7.2 Current Transformer Supervision 429
7.3 CB State and Condition Monitoring 429
7.4 PSL Timers 429
7.5 DC Supply Monitor 429
7.6 Pole Discrepancy 430
8 Measurements and Recording 431
8.1 Metering 431
8.2 Disturbance Records 431
8.3 Event and Fault Records 431
8.4 Fault Locator 431
9 Regulatory Compliance 432
9.1 EMC Compliance: 2014/30/EU 432
9.2 EMC Compliance: 2574-14 of ramadan 1436 432
9.3 LVD Compliance: 2014/35/EU 432
9.4 LVD Compliance: 2573-14 of ramadan 1436 432
9.5 RoHS Compliance 2011/65/EU and (EU) 2015/863 432
9.6 Morocco Compliance 432
9.7 Mechanical Specifications 433
9.7.1 Physical Parameters 433
9.7.2 Enclosure Protection 433
9.7.3 Mechanical Robustness 433
9.7.4 Transit Packaging Performance 433
10 Ratings 434
10.1 AC Measuring Inputs 434
10.2 Current Transformer Inputs 434
10.3 Voltage Transformer Inputs 434
11 Power Supply 435
11.1 Auxiliary Power Supply Voltage 435
11.2 Nominal Burden 435
12 Input / Output Connections 436
12.1 Isolated Digital Inputs 436
12.1.1 Nominal Pickup and Reset Thresholds 436
12.2 RL1, RL2, and RL3 Output Contacts 436
12.3 Auxiliary Output Contacts 437
12.4 Watchdog Contacts 437
13 Environmental Conditions 438
13.1 Ambient Temperature Range 438
13.2 Temperature Endurance Test 438
13.3 Ambient Humidity Range 438
14 Type Tests 439
14.1 Insulation 439
14.2 Creepage Distances and Clearances 439
14.3 High Voltage (Dielectric) Withstand 439
14.4 Impulse Voltage Withstand Test 439
15 Electromagnetic Compatibility 440
15.1 1 MHz Burst High Frequency Disturbance Test 440
15.2 Damped Oscillatory Test 440

xiv P14DEnh-TM-EN-1.1
P14D Contents

15.3 Immunity to Electrostatic Discharge 440

15.4 Electrical Fast Transient or Burst Requirements 440
15.5 Surge Withstand Capability 440
15.6 Surge Immunity Test 441
15.7 Immunity to Radiated Electromagnetic Energy 441
15.8 Radiated Immunity from Digital Communications 441
15.9 Immunity to Conducted Disturbances Induced by Radio Frequency Fields 441
15.10 Magnetic Field Immunity 442
15.11 Conducted Emissions 442
15.12 Radiated Emissions 442
15.13 Power Frequency 442

Chapter 24 EnerVista Flex 443

1 Chapter Overview 445
2 Install EnerVista Flex 446
3 Uninstall EnerVista Flex 447
4 Configure the USB Port 448
5 Access Management 449
5.1 Password Requirements 449
6 Login 450
7 User Settings 451
7.1 Edit My Profile 451
7.1.1 Information 451
7.2 Logout 452
8 Quick Connect 453
8.1 Device Monitor 454
8.2 User Configuration 454
9 Error List 455
10 Device Configuration 456
10.1 Profile Configuration 456
10.2 Device Setting 456
10.3 Error List 457
10.4 DisturbanceRecords 457
11 Create a New Project 458
12 Manage Projects 459
13 Project Configuration 460
13.1 Topology View 460
13.2 IEC1850 Configuration 460
13.3 Add a New Device 461
13.4 Edit a Device 462
13.5 Receive CID from Device 462
13.6 Edit Device Configuration Settings 463
13.7 Send CID to Device 463
13.8 Set Device Language 463
14 PSL Editor 464
14.1 Loading Schemes from Files 464
14.2 PSL Editor Toolbar 464
14.2.1 Logic Symbols 464
14.3 Logic Signal Properties 465
14.3.1 Link Properties 465
14.3.2 Input Signal Properties 466
14.3.3 Output Signal Properties 466
14.3.4 Counter Properties 466
14.3.5 Timer Properties 466
14.3.6 Gate Properties 466
14.3.7 SR Programmable Gate Properties 467

P14DEnh-TM-EN-1.1 xv
Contents P14D

Appendix A Ordering Options 469

Appendix B Settings and Signals 471

Appendix C Wiring Diagrams 473

xvi P14DEnh-TM-EN-1.1
Table of Figures
Figure 1: Main Menu Hierarchy 13
Figure 2: Key to logic diagrams 15
Figure 3: Functional Overview 16
Figure 4: Hardware design overview 32
Figure 5: Exploded view of IED 35
Figure 6: 20TE rear panel 36
Figure 7: Front panel (20TE) 38
Figure 8: LED Numbering 40
Figure 9: Typical LED Indicator Panel 40
Figure 10: Software structure 44
Figure 11: Main Setpoints Display Hierarchy 53
Figure 12: Navigating the HMI 58
Figure 13: Default display navigation 59
Figure 14: Device Display Hierarchy 62
Figure 15: System Menu Hierarchy 66
Figure 16: IEC 60255 IDMT curves 77
Figure 17: IEC standard and very inverse curves 81
Figure 18: IEC Extremely inverse and IEEE moderate inverse curves 81
Figure 19: IEEE very and extremely inverse curves 82
Figure 20: Principle of protection function implementation 85
Figure 21: Non-directional Overcurrent Logic diagram 88
Figure 22: Directional trip angles 89
Figure 23: Directional Overcurrent Logic diagram (Phase A shown only) 90
Figure 24: Typical distribution system using parallel transformers 91
Figure 25: Typical ring main with associated overcurrent protection 92
Figure 26: Modification of current pickup level for voltage controlled overcurrent protection 94
Figure 27: Modification of current pickup level for voltage restrained overcurrent protection 95
Figure 28: Voltage dependant overcurrent logic (Phase A to phase B) 96
Figure 29: Negative Sequence Overcurrent logic - non-directional operation 98
Figure 30: Negative Sequence Directional Characteristic 100
Figure 31: Negative Sequence Overcurrent logic - directional operation 101
Figure 32: Non-directional EF logic (single stage) 104
Figure 33: Directional voltage-polarized characteristics 105
Figure 34: Directional angles 106
Figure 35: Directional EF logic with neutral voltage polarization (single stage) 107
Figure 36: Current level (amps) at which transient faults are self-extinguishing 108
Figure 37: Earth fault in Petersen Coil earthed system 108
Figure 38: Distribution of currents during a Phase C fault 109
Table of Figures P14D

Figure 39: Phasors for a phase C earth fault in a Petersen Coil earthed system 109
Figure 40: Zero sequence network showing residual currents 110
Figure 41: Phase C earth fault in Petersen Coil earthed system: practical case with resistance 111
present
Figure 42: Non-directional SEF logic 113
Figure 43: Types of directional control 114
Figure 44: Sensitive ground directional voltage-polarized characteristics 116
Figure 45: Directional SEF with VN polarisation (single stage) 116
Figure 46: Current distribution in an insulated system with C phase fault 117
Figure 47: Phasor diagrams for insulated system with C phase fault 118
Figure 48: Positioning of core balance current transformers 119
Figure 49: Cold Load Pickup logic 121
Figure 50: Thermal overload protection logic diagram 124
Figure 51: Spreadsheet calculation for dual time constant thermal characteristic 125
Figure 52: Dual time constant thermal characteristic 126
Figure 53: Broken conductor logic 128
Figure 54: Simple busbar blocking scheme 130
Figure 55: Simple busbar blocking scheme characteristics 131
Figure 56: SOTF Logic diagram 132
Figure 57: Undercurrent Logic diagram 133
Figure 58: REF protection for delta side 138
Figure 59: REF protection for star side 138
Figure 60: REF Protection for resistance-earthed systems 139
Figure 61: REF Protection for solidly earthed system 139
Figure 62: Low Impedance REF Connection 141
Figure 63: Three-slope REF bias characteristic 141
Figure 64: High Impedance REF principle 142
Figure 65: High Impedance REF Connection 143
Figure 66: REF bias characteristic 145
Figure 67: Star winding, resistance earthed 147
Figure 68: Percentage of winding protected 148
Figure 69: Low Impedance REF Scaling Factor 148
Figure 70: Hi-Z REF protection for a grounded star winding 150
Figure 71: Hi-Z REF protection for a delta winding 150
Figure 72: Hi-Z REF Protection for autotransformer configuration 151
Figure 73: High Impedance REF for the LV winding 152
Figure 74: Circuit Breaker Fail logic 161
Figure 75: Circuit Breaker mapping 162
Figure 76: CB Fail timing 163
Figure 77: Undervoltage - single and three phase tripping mode (single stage) 179

xviii P14DEnh-TM-EN-1.1
P14D Table of Figures

Figure 78: Overvoltage - single and three phase tripping mode (single stage) 182
Figure 79: Residual Overvoltage logic 185
Figure 80: Residual voltage for a solidly earthed system 186
Figure 81: Residual voltage for an impedance earthed system 187
Figure 82: Negative Sequence Overvoltage logic 188
Figure 83: Positive Sequence Undervoltage logic 190
Figure 84: Positive Sequence Overvoltage logic 191
Figure 85: Underfrequency logic (single stage) 197
Figure 86: Overfrequency logic (single stage) 199
Figure 87: Power system segregation based upon frequency measurements 200
Figure 88: Independent rate of change of frequency logic (single stage) 202
Figure 89: Overpower logic 208
Figure 90: Underpower logic 211
Figure 91: Four-position selector switch implementation 226
Figure 92: Autoreclose mode select logic 227
Figure 93: Start signal logic 228
Figure 94: Trip signal logic 229
Figure 95: Blocking signal logic 229
Figure 96: Shots Exceeded logic 229
Figure 97: AR initiation logic 230
Figure 98: Blocking instantaneous protection for selected trips 231
Figure 99: Blocking instantaneous protection for lockouts 232
Figure 100: Dead Time Control logic 233
Figure 101: AR CB Close Control logic 234
Figure 102: AR System Check logic 235
Figure 103: Reclaim Time logic 236
Figure 104: AR Initiation inhibit 237
Figure 105: Overall Lockout logic 238
Figure 106: Lockout for protection trip when AR is not available 239
Figure 107: Fault recorder stop conditions 249
Figure 108: Flex Element logic diagram 251
Figure 109: CB State Monitoring logic 260
Figure 110: Hotkey menu navigation 262
Figure 111: Remote Control of Circuit Breaker 263
Figure 112: CB Control logic 264
Figure 113: CB Arcing current measurement 265
Figure 114: CB Arcing current Logic 265
Figure 115: Pole Dead logic 266
Figure 116: System Check logic 269
Figure 117: System Check PSL 270

P14DEnh-TM-EN-1.1 xix
Table of Figures P14D

Figure 118: Representation of typical feeder bay 271

Figure 119: Switch Status logic 272
Figure 120: Switch Control logic 273
Figure 121: Harmonic detection logic 274
Figure 122: Breaker contacts arrangement for detecting pole discrepancy externally 275
Figure 123: Breaker contacts wiring for pole discrepancy detected by the relay 276
Figure 124: Pole discrepancy detection--main logic 277
Figure 125: Auxiliary status based pole discrepancy detection logic 278
Figure 126: Current based pole discrepancy detection logic 279
Figure 127: Pole discrepancy: breaker pole failure signal logic 280
Figure 128: DC Supply Monitor zones 284
Figure 129: DC Supply Monitor logic 285
Figure 130: VTS logic 287
Figure 131: CTS logic diagram 289
Figure 132: TCS Scheme 1 290
Figure 133: PSL for TCS Scheme 1 291
Figure 134: TCS Scheme 2 291
Figure 135: PSL for TCS Scheme 2 292
Figure 136: TCS Scheme 3 292
Figure 137: PSL for TCS Scheme 3 293
Figure 138: TCS Scheme 4 293
Figure 139: PSL for TCS Scheme 4 294
Figure 140: Scheme Logic Interfaces 299
Figure 141: RS485 biasing circuit 312
Figure 142: Data model layers in IEC61850 334
Figure 143: GPS Satellite timing signal 338
Figure 144: RADIUS server/client communication 353
Figure 145: Rack mounting of products 363
Figure 146: IP20 cover with teeth removed, alone and installed 365
Figure 147: Terminal block with 3-pole jumper 366
Figure 148: Case dimensions 371
Figure 149: Cutout dimensions 371
Figure 150: COM1 physical connection 385
Figure 151: Minor error events and message generation 410
Figure 152: Major error events and message generation 410

xx P14DEnh-TM-EN-1.1
 CHAPTER 1

INTRODUCTION
Chapter 1 - Introduction P14D

2 P14DEnh-TM-EN-1.1
P14D 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 7
Logic Diagrams 14
Functional Overview 16

P14DEnh-TM-EN-1.1 3
Chapter 1 - Introduction P14D

2 FOREWORD
This technical manual provides a functional and technical description of General Electric's P14D, 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 General Electric'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:
contact.centre@ge.com

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 and follow all safety precautions. 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 text is
written in upper case italics
For example: The SYSTEM DATA
● If reference is made to the IED's internal settings and signals database, the value is written as follows:
The Language setting in the SYSTEM DATA heading contains the value English

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.

4 P14DEnh-TM-EN-1.1
P14D Chapter 1 - Introduction

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.

P14DEnh-TM-EN-1.1 5
Chapter 1 - Introduction P14D

3 PRODUCT SCOPE
The P14D feeder management IED is a microprocessor-based relay for primary and backup over-current
protection of medium and low voltage distribution feeders. The P14D provides integral directional and non-
directional overcurrent, overvoltage and earth-fault protection and is suitable for application on solidly earthed,
impedance earthed, Petersen coil earthed, and isolated systems.
In addition to the protection features, each relay provides protection, control, and monitoring functions with both
local and remote human interfaces. They also display the present trip/alarm conditions, and the available
measured system parameters. Recording of past trip, alarm or control events, maximum demand levels, and
energy consumption is also performed.
The P14D can be used in various applications, depending on the chosen firmware. There are two different models
according to which firmware is installed: P14DB, P14DL.
● The P14DB is the base device for general application
● The P14DL is for line protection

All models are available with a range of Input/Output options, which are described in the hardware design chapter
and summarised in the ordering options.
The small footprint and the withdrawable option make the P40 Agile Enhanced ideal for panel mounting on either
new or retrofit installations.
Programming can be accomplished with the front panel keys and display. Due to the numerous settings, this
manual method can be somewhat laborious. To simplify programming and provide a more intuitive interface,
setpoints can be entered with a PC running the EnerVista Flex software. Even with minimal computer knowledge,
this menu-driven software provides easy access to all front panel functions. Actual values and setpoints can be
displayed, altered, stored, and printed. If settings are stored in a setpoint file, they can be downloaded at any time
to the front panel program port of the relay via a computer cable connected to the serial port of any personal
computer

3.1 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:
contact.centre@ge.com
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.

6 P14DEnh-TM-EN-1.1
P14D Chapter 1 - Introduction

4 FEATURES AND FUNCTIONS

4.1 DESCRIPTION OF THE P14D FEEDER PROTECTION SYSTEM

CPU
Relay functions are controlled by a Texas Instruments AM5706 Sitara Processor, which measures all analog signals
and digital inputs, controls all output relays; and all the Ethernet communication protocols.

Analog Input and Waveform Capture

Magnetic transformers are used to scale-down the incoming analog signals from the source instrument
transformers. The analog signals are then passed through a low pass anti-aliasing filter. All signals are then
simultaneously captured by sample and hold buffers to ensure there are no phase shifts. The signals are converted
to digital values by a 16KHz 24-bit A/D converter before finally being passed on to the CPU for analysis. Both
current and voltage are sampled sixty-four times per power frequency cycle. These ‘raw’ samples are scaled in
software, then placed into the waveform capture buffer, thus emulating a fault recorder. The waveforms can be
retrieved from the relay via the EnerVista Flex software for display and diagnostics.

Frequency
Frequency measurement is accomplished by measuring the time between zero crossings of the composite signal
of three-phase bus voltages. The signals are passed through a low pass filter to prevent false zero crossings.
Frequency tracking utilizes the measured frequency to set the sampling rate for voltage which results in better
accuracy for the Discrete Fourier Transform (DFT) algorithm for offnominal frequencies.
The main frequency tracking source uses three-phase bus voltages. If a stable frequency signal is not available,
then the tracking frequency defaults to the nominal system frequency.

Phasors, Transients, and Harmonics

All waveforms are processed eight times every cycle.

Processing of AC Current Inputs

The DC Decaying Removal Filter is a short window digital filter, which removes the DC decaying component from
the asymmetrical current present at the moment a fault occurs. This is done for all current signals used for
overcurrent protection; voltage signals use the same DC Decaying Removal Filter. This filter ensures no overreach
of the overcurrent protection.
The Discrete Fourier Transform (DFT) uses exactly one cycle of samples to calculate a phasor quantity which
represents the signal at the fundamental frequency; all harmonic components are removed. All subsequent
calculations (e.g. power, etc.) are based upon the current and voltage phasors, such that the resulting values have
no harmonic components. RMS (root mean square) values are calculated from one cycle of samples prior to
filtering.

Protection Elements
Most of the voltage, current and frequency protection elements are processed eight times every cycle to
determine if a pickup has occurred or a timer has expired. The voltage and current protection elements use RMS
current/voltage, or the magnitude of the phasor.

4.2 INTRODUCTION TO LOGICAL DEVICES

Logical Device definitions

The P40 Agile Enhanced relay implements an IEC 61850 server that can contain one or more Logical Devices. Each
Logical Device contains a data model built from instances of specific Logical Nodes and must consist of at least an

P14DEnh-TM-EN-1.1 7
Chapter 1 - Introduction P14D

instance of the LPHD Logical Node (which is responsible for providing physical device information) and an instance
of the LLN0 Logical Node (for addressing common issues across the Logical Device).
The IEC 61850 data model is contained within the Logical Devices detailed in the table below. All P40 Agile
Enhanced devices will name the supported Logical Devices consistently to ensure that data model variables with
the same purpose will have the same name within each P40 Agile Enhanced server.
Logical Device Comment/Usage
Ctrl P40 Agile Enhanced Controls Domain
Meter P40 Agile Enhanced Measurements Domain
Prot P40 Agile Enhanced Protection Domain
Master P40 Agile Enhanced System Domain

IEC 61850 Logical Device data model

The IEC 61850 Logical Device top-level data model consists of instances of Logical Nodes. The data model name
for a Logical Node instance is constructed from an optional prefix (known as the wrapper), the Logical Node name,
and an instance ID (or suffix).
The data model in P40A Enhanced is in an alphabetically sorted order, rather than a logical order, because this is
the natural order of the data when presented by a native MMS browser. (Higher level browsers can of course
impart any ordering that they desire).

4.3 PROTECTION FUNCTIONS

The P14D models offer the following protection functions. The IEC 61850 Logical Device data model for the P40
Agile Enhanced Protection Domain (Prot) is listed in the following table along with the protection functions
description.
IEC 61850 P40Agile Enhanced Protection Domain (Prot) CORTEC
LD LN Instance LN Type IEC 61850 Description P14D ANSI PROTECTION DESCRIPTION STAGES
(Logical
Device)
Prot auxPTOV1 (to 4) AuxPTOV Auxiliary OV 1 (to 4) Yes 59X Auxiliary Overvoltage 4
Prot BrknCondGAPC1 GAPC Broken Conductor Yes 46BC Broken Conductor 1
Prot gndPIOC1 (to 4) GndPIOC EF1 IOC 1 (to 4) Yes 50G Ground (EF1 Measured) 4
Instantaneous Overcurrent
Prot gndPTOC1 (to 2) PTOC_2 EF1 TOC 1 (to 2) Yes 51G Ground (EF1 Measured) 2
Time Overcurrent
Prot gndRDIR1 (to 4) GndRDIR EF1 Dir OC 1 (to 4) Yes 67G Ground (EF1 Measured) 4
Directional Overcurrent
Prot hsePIOC1 (to 4) HsePIOC Sen Gnd IOC1 (to 4) Yes 50SG Sensitive Ground (SEF 4
(50SEF) Measured) Instantaneous
Overcurrent
Prot hsePTOC1 (to 2) HsePTOC Sen Gnd TOC1 (to 2) Yes 51SG Sensitive Ground (SEF 2
Measured) Time
Overcurrent
Prot hseRDIR1 (to 4) HseRDIR Sen Gnd Dir OC1 (to 4) Yes 67SG Sensitive Ground (SEF 4
Measured) Directional
Overcurrent
Prot LLN0 LLN0 Protection Logical Yes
Device
Prot LPHD LPHD_1 Physical Device Yes
Information

8 P14DEnh-TM-EN-1.1
P14D Chapter 1 - Introduction

Prot ndPIOC1 (to 4) NdPIOC EF2 IOC1 (to 4) Yes 50N Neutral (EF2 Derived) 4
Instantaneous Overcurrent
Prot ndPTOC1 (to 2) NdPTOC EF2 TOC1 (to 2) Yes 51N Neutral (EF2 Derived) Time 2
Overcurrent
Prot ndPTOV1 (to 4) NdPTOV Neutral OV 1 (to 4) Yes 59N Neutral Overvoltage 4
Prot ndRDIR1 (to 4) NdRDIR EF2 Dir OC 1 (to 4) Yes 67N Neutral (EF2 Derived) 4
Directional Overcurrent
Prot ngseqPIOC1 (to 4) NgSeqPIOC Neg Seq IOC1 (to 4) Yes 50_2 Negative Sequence 4
Instantaneous Overcurrent
Prot ngseqPTOC1 (to 4) NgSeqPTOC Neg Seq TOC1 (to 4) Yes of Negative Sequence Time 4
Overcurrent
Prot ngseqPTOV1 (to 2) NgSeqPTOV Neg Seq OV 1 (to 2) Yes 59_2 (47) Negative Sequence 2
Overvoltage
Prot ngseqRDIR1 (to 4) NgSeqRDIR Neg Seq Dir OC1 (to 4) Yes 67_2 Negative Sequence 4
Directional Overcurrent
Prot PDOP1 (to 2) PDOP_2 Overpower 1 (to 2) Yes 32OF Underpower 2
(P14DL)
Prot PDUP1 (to 2) PDUP Underpower 1 (to 2) Yes 32LF Overpower 2
(P14DL)
Prot PFRC1 (to 9) PFRC df/dt 1 (to 9) Yes 81R (81 Rate Of Change Of 9
(P14DL) df/dt) Frequency (ROCOF)
Prot phsPIOC1 (to 6) PhsPIOC Phase IOC 1 (to 6) Yes 50P (50) Phase Instantaneous 6
Overcurrent
Prot phsPTOC1 (to 3) PhsPTOC Phase TOC 1 (to 3) Yes 51P (51) / Phase Time Overcurrent / 3
51PV (51V) Phase time overcurrent
with voltage restraint
Prot phsPTOV1 (to 4) PhsPTOV Phase OV 1 (to 4) Yes 59P (59) Phase Overvoltage 4
Prot phsPTUV1 (to 4) PhsPTUV Phase UV 1 (to 4) Yes 27P (27) Phase Undervoltage 4
Prot phRDIR1 (to 6) PhsRDIR Ph Dir OC1 (to 6) Yes 67P (67) Phase Directional 6
Overcurrent
Prot PoleDeaGAPC1 PoleDeadGAP Pole Dead 1 Yes Pole Dead 1
C
Prot posseqPTOV1 (to PosSeqPTOV Pos Seq OV 1 (to 2) Yes 59_1 (59V) Positive Sequence 2
2) Overvoltage
Prot posseqPTUV1 (to PosSeqPTUV Pos Seq UV 1 (to 2) Yes 27_1 (27V) Positive Sequence 2
2) Undervoltage
Prot PTOF1 (to 9) PTOF Overfrequency 1 (to 9) Yes 81O Over Frequency 9
Prot PTUC1 PTUC_2 Undercurrent 1 Yes 37 Undercurrent 1
Prot PTUF1 (to 9) PTUF Underfrequency 1 (to 9) Yes 81U Under Frequency 9
Prot RGFPDIF1 RGFPDIF Restricted E/F 1 Yes 64N Restricted Earth Fault 1
Prot SwOntoFltGAPC1 GAPC SOTF 1 Yes 50 SOTF Switch On To Fault 1
Prot ThmOvlPTTR1 PTTR_5 Thermal Overload 1 Yes 49 Thermal Overload 1

4.4 CONTROL FUNCTIONS

The P14D models offer the following control functions:

Feature IEC 61850 ANSI

Power-up diagnostics and continuous self-monitoring

P14DEnh-TM-EN-1.1 9
Chapter 1 - Introduction P14D

Feature IEC 61850 ANSI

Alternative setting groups (4)
Programmable LEDs
Watchdog contacts

Cyber-security
Programmable allocation of digital inputs and outputs
Control inputs
Graphical programmable scheme logic (PSL)
Circuit breaker control, status & condition monitoring XCBR 52
Trip circuit and coil supervision TCS
CT supervision (only for products with CT inputs) CTSupervisionGAPC CTS
VT supervision (only for products with VT inputs) TVTR VTS (60)
Fault locator (only for products with VT inputs) RFLO 21FL
The IEC 61850 Logical Device data model for the P40 Agile Enhanced Controls Domain (Ctrl) is listed in the
following table along with the control functions description.
IEC 61850 P40 Agile Enhanced Controls Domain (Ctrl) CORTEC

LD LN Instance LN Type IEC 61850 P14D ANSI CONTROL DESCRIPTION STAGES

(Logical Description
Device)
Ctrl ColdLodGAPC1 GAPC Cold Load Pickup Yes CLP Cold Load Pickup 1
Ctrl CSW1 (to 8) CSWI_LOC SW1 Control (to 8) Yes 1 Switch Controller 8
Ctrl CTSupGAPC1 CTSupervisionGAPC_2 CT Supervision Yes CTS CT Supervision (for P14D 1
and P14N)
Ctrl HaDetPHAR1 (to 4) PHAR HarmDet1 (to 4) Yes Harmonic Detection 4
Ctrl LLN0 LLN0 Controls Logical Yes Controls Logical Device
Device
Ctrl LPHD LPHD_1 Physical Device Yes Physical Device
Information Information
Ctrl PoleDscGAPC1 PoleDiscordanceGAPC Pole Discordance Yes 52 Pole Discordance 1
Ctrl RBRF1 RBRF CB Fail & I< Yes 50BF Breaker Failure (CB Fail & 1
I<)
Ctrl RREC1 RREC Auto Reclose Yes 79 Autoreclose (3 phases) 1
(P14DL)
Ctrl SynChkRSYN1 RSYN Synchrocheck Yes 25 Synchrocheck (Check
(P14DL) Synchronising)
Ctrl TVTR1 TVTR VT Supervision Yes VTS (60) VT Supervision (for P94V) 1
Ctrl XCBR1 XCBR CB Control Yes 52 CB Control (Circuit 1
Breaker)
Ctrl XSWI1 (to 8) XSWI_0 SW1 Status (to 8) Yes 33 SW Control (Circuit 8
Switch status)

4.5 MEASUREMENT FUNCTIONS

The device offers the following measurement functions:

10 P14DEnh-TM-EN-1.1
P14D Chapter 1 - Introduction

Measurement Function Details

Measurements ● Measured currents and calculated sequence
(Exact range of measurements depend on the device model) and RMS currents
● Measured voltages and calculated sequence
and RMS voltages
● Power and energy quantities
● Peak, fixed and rolling demand values
● Frequency measurements
● Others measurements
Disturbance records (waveform capture, oscillography) 30 Seconds Disturbance record capacity at the highest
Channels / duration each or total / samples per cycle resolution of 64 samples/cycle
8/16/24/48/64 samples/cycle
Fault Reports 25
Event Records / Event logging 2048
Time Stamping of Opto-inputs Yes

The IEC 61850 Logical Device data model for the P40 Agile Enhanced Measurements Domain (Meter) is listed in the
following table.
IEC 61850 P40 Agile Enhanced Measurements Domain (Meter) CORTEC
LD LN Instance LN Type IEC 61850 Description P14D CONTROL / MASTER / METER /
(Logical PROTECTION DESCRIPTION
Device)
Meter HThdMHAI1 MHAI Harmonic Currents Metering Yes Harmonic Currents Metering
(Harmonics and Interharmonics)
Meter LLN0 LLN0 Meter Logical Device Yes Meter Logical Device
Meter LPHD LPHD_1 Physical Device Information Yes Physical Device Information (name
plate, health)
Meter MMTR1 MMTR_1 Energy Metering Yes Energy Metering for P14D (+Whr, -Whr,
+VARhr, -VARhr)
Meter MMXU1 MMXU_2_2 CT Bank-B Metering No CT Bank-B Metering for P14N
Meter MMXU1 MMXU_3 VT Bank-A, CT Bank-B, Frequency and Power Yes VT Bank-A, CT Bank-B, Frequency and
Metering Power Metering for P14D
Meter MMXU1 MMXU_4 VT Bank-A and Frequency Metering No VT Bank-A and Frequency Metering for
P94V
Meter MSQI1 MSQI_1 Sequence Metering Yes Sequence Currents and Voltages for
P14D
Meter MSQI1 MSQI_A Sequence Metering No Sequence Currents for P14N
Meter MSQI1 MSQI_V Sequence Metering No Sequence Voltages for P94V

4.6 COMMUNICATION FUNCTIONS

The device offers the following communication functions:
Communication Function Details
Local HMI Yes
Multi-language HMI Yes

Front port USB (Maintenance)

1st rear port RS485 or IRIG-B
2nd rear port Single channel Ethernet Engineering / SCADA port

P14DEnh-TM-EN-1.1 11
Chapter 1 - Introduction P14D

Communication Function Details

Serial Protocols available IEC 60870-5-103, MODBUS, RTU, DNP3
Ethernet Protocols available IEC 61850 Ed.2, MODBUS TCP, DNP3 over Ethernet
Virtual inputs 128
Cyber-security Yes
EnerVista Flex Yes

IEC 61850 P40 Agile Enhanced System Domain (Master) CORTEC

LD LN Instance LN Type IEC 61850 Description P14D ANSI MASTER DESCRIPTION STAGES
(Logical
Device)
Master GGIO1 GGIO_RO GGIO1 Indication 1 to 32 Status Yes GGIO1 Indication (1 to 32 32
Status)
Master GGIO2 GGIO_CI Opto Inputs Status Yes Opto Inputs Status (the Cortec
number of Opto inputs related
depends of the cortec IO
option selected)
Master GGIO3 GGIO_VI Virtual Inputs 1-128 Yes Virtual Inputs (1-128) 128
Master GGIO4 GGIO_VO Virtual Outputs 1-128 Yes Virtual Outputs (1-128) 128
Master GGIO5 GGIO_RI Remote Inputs 1-128 Yes Remote Inputs (1-128) 128
Master GGIO6 GGIO_CO Output Relays status Yes Output Relays status (the Cortec
number of relay outputs related
depends of the cortec IO
option selected)
Master LGOS1 (to 32) LGOS GOOSE 1 subscription Yes GOOSE Subscription (1 to 32) 32
monitoring (to GOOSE 32)
Master LLN0 LLN0_MOD Master Logical Device Yes Master Logical Device
Master LPHD LPHD Physical Device Information Yes Physical Device Information
Master RptRFLO1 (to 25) RFLO Fault Report 1 Yes 21FL Fault Report (Fault Locator) 25

4.7 SYSTEM FUNCTIONS

The P14D models offer the following generic system functions. The IEC 61850 Logical Device data model for the
P40 Agile Enhanced System Domain (Master) is listed in the following table along with the generic system functions
description.
IEC 61850 P40 Agile Enhanced System Domain (Master) CORTEC
LD LN Instance LN Type IEC 61850 Description P14D ANSI MASTER DESCRIPTION STAGES
(Logical
Device)
Master GGIO1 GGIO_RO GGIO1 Indication 1 to 32 Status Yes GGIO1 Indication (1 to 32 32
Status)
Master GGIO2 GGIO_CI Opto Inputs Status Yes Opto Inputs Status (the Cortec
number of Opto inputs related
depends of the cortec IO
option selected)
Master GGIO3 GGIO_VI Virtual Inputs 1-128 Yes Virtual Inputs (1-128) 128
Master GGIO4 GGIO_VO Virtual Outputs 1-128 Yes Virtual Outputs (1-128) 128

12 P14DEnh-TM-EN-1.1
P14D Chapter 1 - Introduction

Master GGIO5 GGIO_RI Remote Inputs 1-128 Yes Remote Inputs (1-128) 128
Master GGIO6 GGIO_CO Output Relays status Yes Output Relays status (the Cortec
number of relay outputs related
depends of the cortec IO
option selected)
Master LGOS1 (to 32) LGOS GOOSE 1 subscription Yes GOOSE Subscription (1 to 32) 32
monitoring (to GOOSE 32)
Master LLN0 LLN0_MOD Master Logical Device Yes Master Logical Device
Master LPHD LPHD Physical Device Information Yes Physical Device Information
Master RptRFLO1 (to 25) RFLO Fault Report 1 Yes 21FL Fault Report (Fault Locator) 25

4.8 MAIN MENU

Targets
Device Status Circuit Breaker
Information
Switch Control
Opto Inputs
Relay Output s
Setpoints Device
Virtual Inputs
System
Virtual Outputs
Inputs
Flex States
Communications Outputs

Device Status Protection

Clock
Monitoring
Autoreclose
Control

FlexLogic

Testing

Measurements CT Bank 1 -J1

Ph VT Bnk1-J2
4th VT1 Bank-A
Records Events
VT1 Frequency
CT1 Harmonics % Transients
CT1 Harm. Detec Data Logger
Check Sync 1
Fault Reports
Power 1
Energy Circuit Breakers
CT1 Demand
Digital Counters
Power Demand
Thermal State Clear Records
894335A1
DC Supply Supv.
FlexElements

Figure 1: Main Menu Hierarchy

P14DEnh-TM-EN-1.1 13
Chapter 1 - Introduction P14D

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.

14 P14DEnh-TM-EN-1.1
P14D Chapter 1 - Introduction

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

P14DEnh-TM-EN-1.1 15
Chapter 1 - Introduction P14D

6 FUNCTIONAL OVERVIEW

50
46 50 50BF 51
86 37 49 64N 68 79 CTS
46BC 50N 50SEF 51N
SOTF

Isen

81O
27 59 67 VTS
21FL 25 32 47 51V 81U 81df/dt
27V 59V 67N (60)
81V

Digital I/O Communication Measurements Disturbance

Opto- Relay Local records
IRIG-B Ethernet RS485 Fault records
inputs outputs USB

V06900

Figure 3: Functional Overview

16 P14DEnh-TM-EN-1.1
 CHAPTER 2

SAFETY INFORMATION
Chapter 2 - Safety Information P14D

18 P14DEnh-TM-EN-1.1
P14D 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 19
Health and Safety 20
Symbols 21
Installation, Commissioning and Servicing 22
Decommissioning and Disposal 27
Regulatory Compliance 28

P14DEnh-TM-EN-1.1 19
Chapter 2 - Safety Information P14D

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 Could cause irreversible damage to the
equipment and could lead to property damage, personal injury, and/or death.
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.

20 P14DEnh-TM-EN-1.1
P14D 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

Warning:
Risk of damage to eyesight

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'.

P14DEnh-TM-EN-1.1 21
Chapter 2 - Safety Information P14D

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.

22 P14DEnh-TM-EN-1.1
P14D Chapter 2 - Safety Information

Warning:
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 reducing 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 FUSING REQUIREMENTS

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).

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

4.4 EQUIPMENT CONNECTIONS

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

Caution:
Tighten M3.5 clamping screws of heavy duty terminal block connectors to a nominal
torque of 0.8 Nm.
Tighten captive screws of terminal blocks to a nominal torque value of 0.5 Nm.

P14DEnh-TM-EN-1.1 23
Chapter 2 - Safety Information P14D

Caution:
It is highly recommended that 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.

4.5 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.

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.

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.

4.6 PRE-ENERGISATION CHECKLIST

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

24 P14DEnh-TM-EN-1.1
P14D Chapter 2 - Safety Information

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.

4.7 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.

Note:
For this IED, the current transformers remain in the chassis is the unit is disassembled. Therefore external shorting of the CTs
may not be required.

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.

P14DEnh-TM-EN-1.1 25
Chapter 2 - Safety Information P14D

Warning:
Data communication cables with accessible screens and/or screen conductors,
(including optical fibre cables with metallic elements), may create an electric shock
hazard in a sub-station environment if both ends of the cable screen are not connected
to the same equipotential bonded earthing system.

To reduce the risk of electric shock due to transferred potential hazards:

i. The installation shall include all necessary protection measures to ensure that no
fault currents can flow in the connected cable screen conductor.

ii. The connected cable shall have its screen conductor connected to the protective
conductor terminal (PCT) of the connected equipment at both ends.

iii. The protective conductor terminal (PCT) of each piece of connected equipment shall
be connected directly to the same equipotential bonded earthing system.

iv. If, for any reason, both ends of the cable screen are not connected to the same
equipotential bonded earth system, precautions must be taken to ensure that such
screen connections are made safe before work is done to, or in proximity to, any such
cables.

v. No equipment shall be connected to any download or maintenance circuits or

connectors of this product except temporarily and for maintenance purposes only.

vi. Equipment temporarily connected to this product for maintenance purposes shall be
protectively earthed (if the temporary equipment is required to be protectively
earthed), directly to the same equipotential bonded earthing system as the product.

4.8 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.

26 P14DEnh-TM-EN-1.1
P14D Chapter 2 - Safety Information

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. This product cannot be disposed of as
unsorted municipal waste in the European Union. For proper recycling return this
product to your supplier or a designated collection point. For more information go to
www.recyclethis.info

Note:
Store the unit indoors in a cool, dry place. If possible, store in the original packaging. Follow the storage temperature range
outlined in the Specifications. To avoid deterioration of electrolytic capacitors, power up units that are stored in a deenergized
state once per year, for one hour continuously.

P14DEnh-TM-EN-1.1 27
Chapter 2 - Safety Information P14D

6 REGULATORY COMPLIANCE
Compliance with the European Commission Direction on EMC, LVD and RoHS is via the self certification route.

6.1 EMC COMPLIANCE: 2014/30/EU

The product specific Declaration of Conformity (DoC) lists the relevant harmonised standard(s) or conformity
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 ROHS COMPLIANCE 2011/65/EU AND (EU) 2015/863

The product complies with the directive of the Council of the European Communities on harmonization of the laws
of the Member States concerning restriction on usage of hazardous substances in electrical and electronic
equipment (RoHS Directive 2011/65/EU). This conformity has been proved by tests performed according to the
Council Directive in accordance with the standard EN 50581.

6.4 MOROCCO COMPLIANCE

If marked with this logo, the product is compliant with the requirements of the Morocco safety and EMC
regulations No.2573.14 and 2574.14.

28 P14DEnh-TM-EN-1.1
 CHAPTER 3

HARDWARE DESIGN
Chapter 3 - Hardware Design P14D

30 P14DEnh-TM-EN-1.1
P14D Chapter 3 - Hardware Design

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
Terminal Connections 37
Front Panel 38

P14DEnh-TM-EN-1.1 31
Chapter 3 - Hardware Design P14D

2 HARDWARE ARCHITECTURE
The main components comprising devices based on the P40Agile Enhanced 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)
● An I/O board consisting of output relay contacts and digital opto-inputs with optional redundant rear
communications
● Power supply with rear communication connectors

All 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 CAN bus for
conveying sampled data from the modules 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.

Figure 4: Hardware design overview

2.1 MEMORY AND REAL TIME CLOCK

The IED contains flash memory for storing the following operational information:
● Fault and Disturbance Records
● Events
● Alarms
● Measurement values
● Latched trips
● Latched contacts

32 P14DEnh-TM-EN-1.1
P14D Chapter 3 - Hardware Design

Flash memory is non-volatile and therefore no backup battery is required.

A dedicated Supercapacitor keeps the on board real time clock operational for up to seven days after power down.

P14DEnh-TM-EN-1.1 33
Chapter 3 - Hardware Design P14D

3 MECHANICAL IMPLEMENTATION
This equipment is Suitable for mounting on the flat surface of a Type 1 Enclosure. All products based on the
P40Agile Enhanced platform have common hardware architecture. The hardware comprises two main parts; the
cradle and the housing.
The cradle consists of the front panel which is attached to a carrier board into which all of the hardware boards
and modules are connected. The products have been designed such that all the boards and modules comprising
the product are fixed into the cradle and are not intended to be removed or inserted after the product has left the
factory.
The housing comprises the housing metalwork, magnetic module and connectors at the rear into which the
boards in the cradle plug into.

Note:
The magnetic module remains attached to the chassis to avoid opening the current transformers circuit.

34 P14DEnh-TM-EN-1.1
P14D Chapter 3 - Hardware Design

Figure 5: Exploded view of IED

3.1 HOUSING VARIANTS

The P40 Agile range of products are implemented in one case size. 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.

P14DEnh-TM-EN-1.1 35
Chapter 3 - Hardware Design P14D

The cases are pre-finished steel with a black covering of hybrid epoxi-polyester powder. 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. The case dimensions are as follows:
Case width (TE) Case width (mm)
20TE 102.4 mm (4 inches)

3.2 20TE REAR PANEL

The basic 20TE rear panel consists of one 16-pole terminal block connector and one 24-pole 45 degree connector.
An optional I/O module can be ordered with an additional 16-pole 45 degree connector.

Figure 6: 20TE rear panel

36 P14DEnh-TM-EN-1.1
P14D Chapter 3 - Hardware Design

4 TERMINAL CONNECTIONS

4.1 I/O OPTIONS

Component I/O option B I/O option D

Digital inputs 3 (1 group of 3) 9 (3 groups of 3)
Output relays 7 (NO) 11 (NO)

Note:
I/O options B & D have also two Trip Circuit Supervision (TCS) inputs.
For details of terminal connections, refer to the Wiring Diagrams Appendix.
All of the I/O options have a Relay Healthy NC output relay.

P14DEnh-TM-EN-1.1 37
Chapter 3 - Hardware Design P14D

5 FRONT PANEL

5.1 20TE FRONT PANEL

The relay front panel provides an interface with a liquid crystal display, LED status indicators, control keys, and a
USB program port. The display and status indicators show the relay information automatically. The control keys
are used to select the appropriate message for entering setpoints or displaying measured values. The USB
program port is also provided for connection with a computer

Figure 7: Front panel (20TE)

The figures show the front panels for the 20TE variant.

38 P14DEnh-TM-EN-1.1
P14D Chapter 3 - Hardware Design

It consists of:
● LCD display
● Keypad
● USB port
● 4 x fixed function tri-colour LEDs
● 4 x programmable tri-colour LEDs

5.2 KEYPAD
The keypad consists of the following keys:

Four arrow keys (Up, Down, Left, Right) to navigate the menus
(organised around the Enter key)

An Enter key for executing the chosen option

A Clear key for clearing the last enter key execution. If maintained it
will issue a Reset command.

A Read key for accessing Targets menu if the Alarm LED is on. And,
for accessing Last Trip data if the Trip LED is on.(arrow keys now used
for scrolling)

Two hot keys for accessing the Reset Command (Up) and CB Control
(Down). These are situated directly below the LCD display.

5.3 LIQUID CRYSTAL DISPLAY

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

5.4 USB PORT

The USB port is situated on the front panel in the bottom left hand corner, and is used to communicate with a
locally connected PC. It has two main purposes:
● To transfer settings information to/from the PC from/to the device.
● For downloading firmware updates and menu text editing.

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 MODBUS communication protocol only to
allow communication with a range of protection equipment, and between the device and the Windows-based
support software package.
You can connect the unit to a PC with a USB cable up to 5 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.

P14DEnh-TM-EN-1.1 39
Chapter 3 - Hardware Design P14D

Caution:
When not in use, always close the cover of the USB port to prevent contamination.

5.5 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.
● Alarm (Orange) flashes when the IED registers an alarm. This may be triggered by a fault, event or
maintenance record. For non-latched Alarms the LED flashes until the alarm conditions disappear, then it
switches OFF. For Latched Alarms the LED flashes until the alarm conditions disappear, then changes to
constantly ON. When the alarms are cleared, the LED switches OFF.
● Out of service (Red) 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 Out of service and
healthy LED is reflected by the watchdog contacts at the back of the unit.

5.6 PROGRAMABLE LEDS

The device has a number of programmable LEDs. All of the programmable LEDs on the unit are tri-colour and can
be set to RED, ORANGE or GREEN.
In the 20TE case, four programmable LEDs are available.

E06924

Figure 8: LED Numbering

E06923

Figure 9: Typical LED Indicator Panel

40 P14DEnh-TM-EN-1.1
 CHAPTER 4

SOFTWARE DESIGN
Chapter 4 - Software Design P14D

42 P14DEnh-TM-EN-1.1
P14D Chapter 4 - Software Design

1 CHAPTER OVERVIEW
This chapter describes the software design of the IED.
This chapter contains the following sections:
Chapter Overview 43
Software Design Overview 44
System Level Software 45
Platform Software 47
Protection and Control Functions 48

P14DEnh-TM-EN-1.1 43
Chapter 4 - Software Design P14D

2 SOFTWARE DESIGN OVERVIEW

The range of products based on the P40 Agile Enhanced platform can be conceptually categorised 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.

Protection and Control Software Layer

Protection Task

Programmable & Fourier signal Protection

fixed scheme logic processing algorithms Fault locator Disturbance
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

V00300

Figure 10: Software structure

The software 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 required.

44 P14DEnh-TM-EN-1.1
P14D Chapter 4 - Software Design

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.

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.
If a problem is detected by the self-monitoring functions, the device attempts to store a 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.

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 integrity of the non-volatile memory, which is used to store event, fault and disturbance records
● The operation of the LCD controller
● The watchdog operation

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At the conclusion of the initialization software the supervisor task begins the process of starting the platform
software.

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 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-isolated 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.
If the self-check detected is a minor error the IED continues in service and the cause of the error is displayed in the
IED records as well as in the Targets menu. If the self-check is a major error, the device takes itself permanently out
of service. In both cases the Alarm LED is active while the self-test error is active.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:
● Targets
● 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.
The sampling rate is adapted to the frequency of the electrical power system to provide a fixed sampling
acquisition rate of 64 samples/ cycle.
The sampling function waits until the reception of 8 consecutive samples, it calculates the DFT or RMS value of the
last 64 samples, -8 consecutive blocks of 8 sample each- and raises an interrupt to the rest of the system
indicating a new measurement has been acquired. Thus, the sampling rate of the protection system is executed 8
times per electrical power cycle.

5.2 FREQUENCY TRACKING

The device provides a frequency tracking algorithm so that there are always 64 samples per cycle irrespective of
frequency drift within a certain frequency range (see technical specifications). If the frequency falls outside this
range, the sample rate reverts to its default rate of 3200 samples for 50 Hz or 3840 samples for 60 Hz.
Frequency measurement is accomplished by measuring the time between zero crossings of the composite signal
of three-phase bus voltages. The signals are passed through a low pass filter to prevent false zero crossings.
Frequency tracking utilises the measured frequency to set the sampling rate for voltage which results in better
accuracy for the Discrete Fourier Transform (DFT) algorithm for offnominal frequencies. The main frequency
tracking source uses three-phase bus voltages. If a stable frequency signal is not available from all sources, then
the tracking frequency defaults to the nominal system frequency.
The frequency tracks off any voltage down to 10%Vn for voltage.
The frequency is limited to the range between 45 Hz and 65 Hz.

5.3 FOURIER SIGNAL PROCESSING

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 64 samples.
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.
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

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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 64 samples per cycle, this would be nominally 1600 Hz for a 50 Hz system, or 1920 Hz for a 60 Hz system.

5.4 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.
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 can be assigned to 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 design is achieved by means of a
PC support package called the PSL Editor. This is available as part of the settings application software Toolsuite.

5.5 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 (flash memory). The operation of the record logging to RAM 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.
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.

5.6 DISTURBANCE RECORDER

The disturbance recorder can record the waveforms of the calibrated analog channels, plus the values of the
digital signals. The number of records is user selectable up to 16 and the maximum time for one record at 128
samples/cycle is 30 seconds. The disturbance recorder is supplied with data by the protection and control task
once per cycle, and collates the received data into the required length disturbance record. The disturbance records
can be extracted using application software or the SCADA system, which can also store the data in COMTRADE
format, allowing the use of other packages to view the recorded data.
For more information, see the Monitoring and Control chapter.

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5.7 FAULT LOCATOR

The fault locator uses 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.

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CONFIGURATION
Chapter 5 - Configuration P14D

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1 CHAPTER OVERVIEW
The P40 Agile Enhanced has a considerable number of programmable setpoints, all of which make the relay
extremely flexible. These setpoints have been grouped into a variety of menus which are available from the paths
shown below. Each setpoints menu has sub-sections that describe in detail the setpoints found on that menu.

Setpoints Device
System
Inputs
Outputs
Protection
Monitoring
Control
FlexLogic
Testing
894347A1

Figure 11: Main Setpoints Display Hierarchy

Note:
Use the path provided to access the menus from the front panel and from the Toolsuite Setup software.

Note:
For certain named settings the user may configure custom names. The user should not create 13-character long names using
the largest width characters (i.e. WWWWWWWWWWWWW). Doing so can cause the last 3 characters to overlap the setting
name when viewed from the HMI or the PC program.

This chapter contains the following sections:

Chapter Overview 53
Settings Application Software 54
Using the HMI Panel 57
Device 62
System 66

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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 EnerVista Flex. 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 IEC 61850
communications.
If you do not already have a copy of the Settings Application Software, you can obtain it from General Electric at
www.gegridsolutions.com.
Refer to the Interface section for more information.

2.1 SETPOINT ENTRY METHODS

Before placing the relay in operation, setpoints defining system characteristics, inputs, relay outputs, and
protection settings must be entered, using one of the following methods:
● Front panel, using the keypad and the display.
● Front USB port, connected to a portable computer running the Enervista Flex Setup software.
● Rear Ethernet (copper port connected to portable computer running the EnerVista Flex software.
● Rear RS485 port and a SCADA system running user-written software.
Any of these methods can be used to enter the same information. A computer, however, makes entry much easier.
Files can be stored and downloaded for fast, error free entry when a computer is used. The relay leaves the factory
with setpoints programmed to default values, and it is these values that are shown in all the setpoint message
illustrations.
At a minimum, the SETPOINTS / SYSTEM setpoints must be entered for the system to function correctly. To
safeguard against the installation of a relay whose setpoints have not been entered, the Out-Of-Service self-test
warning is displayed. In addition, the Critical Failure relay is de-energized and the Healthy LED is OFF (red). Once
the relay has been programmed for the intended application, the SETPOINTS / DEVICE / INSTALLATION / Device In
Service setpoint should be changed from “Not Ready” (the default) to “Ready” and the Healthy LED will turn ON
(green). Before putting the relay in “Ready” state, each page of setpoint messages should be worked through to
ensure that proper device settings have been configured, entering values either by keypad or computer.

2.2 COMMON SETPOINTS

To make the application of this device as simple as possible, similar methods of operation and similar types of
setpoints are incorporated in various features. Rather than repeat operation descriptions for this class of setpoint

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throughout the manual, a general description is presented in this overview. Details that are specific to a particular
feature are included in the discussion of the feature. The form and nature of these setpoints is described below.
● FUNCTION setpoint: The <ELEMENT_NAME> FUNCTION setpoint determines the operational characteristic
of each feature. The range for this setpoint is: “Disabled”, “Trip”, “Alarm”, “Latched Alarm”, and “Configurable”.
If the FUNCTION setpoint is selected as “Disabled”, then the feature is not operational.
If the FUNCTION setpoint is selected as “Trip”, then the feature is operational. When the “Trip” function is
selected and the feature operates, the output relay “Trip” operates, and the LED “TRIP” is lit.
If the FUNCTION setpoint is selected as “Alarm” or “Latched Alarm”, then the feature is operational. When
this function is selected, and the feature operates, the LED “ALARM” is lit, and any assigned auxiliary output
relay operates. The “Trip” output relay does not operate, and the LED “TRIP” is not lit.
When Alarm function is selected and the feature operates, the LED “ALARM” flashes, and it self-resets when
the operating conditions are cleared.
When Latched Alarm function is selected, and the feature operates, the LED “ALARM” will flash during the
operating condition, and will be steady lit after the conditions are cleared. The LED “ALARM” can be reset by
issuing reset command.
If the FUNCTION setpoint is selected as “Configurable”, the feature is fully operational but outputs are not
driving any action, such as TRIP relay , Alarm LED or anything else. The User has to program operands from
this element to a desirable action which may be the auxiliary output relay from the list of available relays in
the element itself, Flexlogic, Trip Bus etc.

Note:
The FlexLogic operands generated by the operation of each feature are active, and available to assign to outputs, or use in
FlexLogic equations, regardless of the selected function, except when the function is set to “Disabled”.

● PICKUP: The setpoint selects the threshold equal to or above (for over elements) or equal to or below (for
under elements) which the measured parameter causes an output from the measuring element.
● TIME DELAY: The setpoint selects a fixed time interval to delay an input signal from appearing as an output.
● DROPOUT DELAY: The setpoint selects a fixed time interval to delay dropping out the output signal after
being generated.
● TDM: The setting provides a selection for Time Dial Multiplier which modifies the operating times per the
selected inverse curve. For example, if an IEEE Extremely Inverse curve is selected with TDM=2, and the fault
current is 5 times bigger than the PKP level, operation of the element can not occur before an elapsed time
of 2.59 s from Pickup.
● OUTPUT RELAYS: The <ELEMENT_NAME> RELAYS setpoint selects the relays required to operate when the
feature generates an output. The range is any combination of the Auxiliary output relays. The letter "X"
denotes the number of auxiliary output relays defined for the relay's order code.
● DIRECTION: The <ELEMENT_NAME> DIRECTION setpoint is available for overcurrent features which are
subject to control from a directional element. The range is “Non-Directional”, “Forward”, and “Reverse”. If set
to “Non-Directional”, the element is allowed to operate for current flow in any direction. There is no
supervision from the directional element. If set to “Forward”, the OC element is allowed to operate when the
fault is detected by the directional element in forward direction. In this mode, the OC element does not
operate for fault in reverse direction. If set to “Reverse”, the OC element is allowed to operate when the fault
is detected in reverse direction, and does not operate in forward direction.
● RESET: Selection of an Instantaneous DT or a Timed reset is provided by this setting. If Instantaneous reset is
selected, the element resets instantaneously providing the quantity drops below the percentage or absolute
value of the PKP level corresponding to each element before the time for operation is reached. More
information on the drop out levels for each element can be found in the Technical Specifications chapter. If
Timed reset is selected, the time to reset is calculated based on the reset equation for the selected inverse
curve.
● INHIBIT: The <ELEMENT_NAME> INHIBIT setpoint selects an operand from the list of FlexLogic operands,
which when active, blocks the feature from running.

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Caution:
To ensure the settings file inside the relay is updated, wait 30 seconds after a setpoint change before
cycling power.

2.3 SETPOINTS TEXT ABBREVIATIONS

The following abbreviations are used in the setpoints pages.
● A: amperes
● kA: kiloamperes
● V: volts
● kV: kilovolts
● kW: kilowatts
● kvar: kilovars
● kVA: kilo-volt-amperes
● AUX: auxiliary
● COM, Comms: communications
● CT: current transformer
● GND: ground (earth)
● Hz: Hertz
● MAX: maximum
● MIN: minimum
● SEC, s: seconds
● UV: undervoltage
● OV: overvoltage
● VT: voltage transformer
● Ctrl: control
● Hr & hr: hour
● O/L: overload
● CT1 IN2: EF2 Derived Current
● CT1 IN1: EF1 Measured Current
● ISEF: Sensitive Earth Fault Current or SEF Current

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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

Shortcuts for executing Reset command and enter CB

Hotkeys Control menu. Also, for confirming or not confirming
changes when navigating through settings

Cancel key To return to column header from any menu cell

Read key To read alarm messages and enter Last Trip data menu

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

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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 oth 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

The Cancel key

For the Cancel and UP key options,
goes to Default
Default Display #2 is shown:
Display Menu
Model Number, Database Date and
#2
Shortcuts

Column 00 Subsequent column headings Last Column

System data

Vertical cursor keys move

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

The Cancel key

returns to
column header
Subsequent rows Subsequent rows

V06918

Figure 12: 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
the default display menu.
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 that has the Ethernet port physically connected with a
copper cable. If this is the case, the orange Alarms LED will be flashing and the alarm can be read by pressing the
'Read' key.

TARGETS
Link Error Prim

If this is the case, you will first need to connect the device to an active Ethernet network to clear the alarm.
If there are other alarms present, these must also be cleared to set the Alarm LED OFF.

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3.3 DEFAULT DISPLAY

The HMI display provides Date, Time and Measurements for the system voltages, currents, power, and frequency,
depending on the device model.

Date and time, and Metering values

For example:

Ia 0.0 A Va 0.0 V
Ib 0.0 A Vb 0.0 V
Ic 0.0 A Vc 0.0 V
f 0.00 Hz DC 0.0 V

3.4 DEFAULT DISPLAY NAVIGATION

The following diagram is an example of the default display navigation. 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.

System Current
Currents, Voltages,
Frequency, DC supply
voltage and Date & Time

System Power
Measurements, Power
Factor and Date & Time

System Current & Voltage

Negative, Positive and
Zero sequence values
and Date & Time

System Total Harmonic

Distortion and Date & Time
V06929

Figure 13: Default display navigation

Note:
Whenever the IED has an uncleared alarm the default display iyou can enter the menu structure from the default display, even
if the display shows the Alarms/Faults present message.

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3.5 PASSWORD ENTRY

When configuring the default display (in addition to modification of other settings) you will be prompted for a Role
and a password before you can make any changes, as follows: The default Role is Viewer.

LOGIN
Viewer

LOGIN
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.
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 followed by an AUTH FAILED message is displayed. The display then reverts back to Enter
password. On entering a valid password, this Role 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. If the keypad is inactive for a number of minutes, the
password protection of the front panel user interface reverts to the default access level.

Note:
In the SECURITY CONFIG settings menu, you can set the maximum number of attempts, 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 Target Messages display and the orange 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.
2. Scroll through the pages of the latest fault record, using the cursor keys.

3.7 MENU STRUCTURE

IED display messages are organized into a Main Menu, Pages, and Sub-pages. The five Main Menu headers are
Targets, Device Status, Measurements, Setpoints and Records.
Pressing the Down key scrolls through the Main Menu.
Pressing the Enter key from the Main Menu headers displays the corresponding Page. Use the Up and Down keys
to scroll through the available Pages.

3.8 CHANGING THE SETTINGS

Starting at the default display, press the Down cursor key to show the first heading.
1. Use the Enter cursor key to select the required heading.
2. Use the vertical cursor keys (Right and Left) to view the setting data.

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3. To return to the header press the Cancel key for a second or so.
4. To return to the default display, press the Cancel key from any of the headings.
5. To change the value of a setting, go to the relevant Setpoint in the menu, then press the Enter key to
change the cell value. A marking cursor on the LCD shows that the value can be changed. You may be
prompted for a password first.
6. 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.
7. 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.
8. 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 heading level pressing the Clear
cursor key. Before returning to the default display, the following prompt appears.

Confirm Changes ?
NO YES

9. Press the relevant hotkey to accept or discard the new settings.

P14DEnh-TM-EN-1.1 61
Chapter 5 - Configuration P14D

4 DEVICE
The following diagram is an example of the Setpoints display navigation, so it may not apply in its entirety to all
models. The actual display options available are dependent on the exact model.

Custom Configuration
Modbus
Date And Time
Ethernet
Security Ethernet

Communications USB
Setpoints Device
DNP Protocol
System Disturb Recorder
DNP Point Lists

Inputs Data Logger IEC 60870-5-103

IEC103 Pt Lists
Outputs Fault Records
IEC103DistRecord
Protection Event Data
IEC61850 MMS
Monitoring Flex States GOOSE Analog

Control TFTP

FlexLogic

Testing Prog. LEDs

Front Panel
Display Property

Resetting
Default Screens
Installation
Default Screens
Clear Records
Default Screens

894325A1

Figure 14: Device Display Hierarchy

4.1 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 setting under the path SETPOINTS > DEVICE > DATE AND TIME.

62 P14DEnh-TM-EN-1.1
P14D Chapter 5 - Configuration

4.1.1 CLOCK
Path: SETPOINTS > DEVICE > CLOCK
The P14D is capable of receiving a time reference from several time sources in addition to its own internal clock for
the purpose of time-stamping events, transient recorders and other occurrences within the relay. The accuracy of
the time stamp is based on the time reference that is used. The P14D supports an internal clock, SNTP, IRIG-B, as
potential time references.
If two or more time sources are available, the time source with the higher priority shown in Time Sources table is
used where 1 is considered to be the highest priority.
The following table shows the priority of each time source.

Time Source Priority

IRIG-B 1*
SNTP 2

Note:
Synchronization by IEC103, DNP, Modbus is not going to be issued if there is a sync source from IRIG-B or SNTP .

4.1.2 SNTP PROTOCOL

Path: SETPOINTS > DEVICE > DATE AND TIME > SNTP
SNTP FUNCTION
Range: Disabled, Enabled
Default: Disabled
SERVER X IP ADDR
Range: Standard IP Address Format
Default: 0.0.0.0
SERVER X UDP PORT
Range: 0 to 65535 in steps of 1
Default: 123
Being X: 1, 2

4.2 SECURITY
The following security features are available:
● Basic Security – The basic security feature present in the default offering of the product.
● Advanced Cybersecurity – The feature refers to the advanced security options available as a software
option. When this option is purchased, it is automatically enabled and Basic Security is disabled.
Security settings are found under the path: Path: SETPOINTS > DEVICE > SECURITY.
Refer to the Cyber Security chapter for more information.

4.3 COMMUNICATIONS
Refer to the Communications chapter for more information.

P14DEnh-TM-EN-1.1 63
Chapter 5 - Configuration P14D

4.4 DISTURBANCE RECORDER

Refer to the Monitoring and Control chapter for more information.

4.5 DATA LOGGER

Refer to the Monitoring and Control chapter for more information.

4.6 EVENT DATA

The Event Data feature stores 64 FlexAnalog quantities each time an event occurs. The IED is able to capture a
maximum of 2048 Event records. The Event Data behaviour matches that of the Event Recorder.
There is no Enabling/Disabling of the feature. It is always ‘ON’.
When changes are made to the Event Data settings, the Event data is cleared and the Snapshot.txt file is deleted.
The Event Record remains as is and is not cleared.
Path: SETPOINTS > DEVICE > EVENT DATA

4.7 FLEX STATES

The Flex State feature provides a mechanism where any of 256 selected FlexLogic operand states or any inputs
can be used for efficient monitoring.
The feature allows user-customized access to the FlexLogic operand states in the relay.
Path: SETPOINTS > DEVICE > FLEX STATES

4.8 FRONT PANEL

4.8.1 DISPLAY PROPERTIES

To select the language of the device use the Front Panel Display Property setting. The options include English (UK),
English (US), Spanish and French.
Path: SETPOINTS > DEVICE > FRONT PANEL > DISPLAY PROPERTY

4.8.2 DEFAULT SCREENS

By Default, the first home screen is configured to show the metering values. The sequence of displaying the
screens starts after a time of inactivity, when no pushbutton (PB) has been pressed.
Path: SETPOINTS > DEVICE > FRONT PANEL > DEFAULT SCREENS

4.9 RESETTING
Some events can be programmed to latch the faceplate LED event indicators. Depending on the application some
auxiliary output relays can be programmed to latch after the triggering event is cleared. Once set, the latching
mechanism holds all the latched indicators, messages, and auxiliary output relays in the set state, after the
initiating condition has cleared, until a RESET command is received to return these latches (except the FlexLogic
latches) to the reset state.
The RESET command can be sent from the faceplate by pressing CLEAR key/Reset hotkey, a remote device via a
communication channel, or any programmed FlexLogic operand. Executing the RESET command from either
source creates a general FlexLogic operand RESET OP. Each individual source of a RESET command also creates
its individual operand RESET OP (PB), RESET (COMMS), and RESET OP (OPERAND) to identify the source of the
command.

64 P14DEnh-TM-EN-1.1
P14D Chapter 5 - Configuration

4.10 CLEAR RECORDS

The Clear Records command is accessible from the front panel and from the software.
Path: DEVICE > CLEAR RECORDS
Records can be cleared either by assigning “On” or a FlexLogic operand to the appropriate setting.

Note:
The Clear Records command is also available from Records > Clear Records, however there the allowable settings are only
“ON” and “OFF”. (FlexLogic operands cannot be used.)

P14DEnh-TM-EN-1.1 65
Chapter 5 - Configuration P14D

5 SYSTEM

CT Ratio
Setpoints Device
Data
VT Capture
Ratio
System
Power System
Inputs
CB Setup
Outputs
User Curves Data
Protection
894365A1

Monitoring

Control

FlexLogic
Testing
Figure 15: System Menu Hierarchy

5.1 CT RATIO
The CT RATIO menu provides the setup menu for the Current Transformers (CTs) connected to the P40 Enhanced
terminals. The setup of the three-phase CTs, the Earth CT, and the Sensitive Earth CT requires a selection of primary
and secondary CT ratings.
The P14D Feeder Management IED has three inputs for phase currents A, B, and C, and one input for earth/
residual current.
The CT ratio selection for the P14D is organized under Path: SETPOINTS > SYSTEM > CT RATIO> CT1 BANK
PHASE CT PRIMARY
Range: 1 A to 30000 in steps of 1 A
Default: 1 A
Enter the primary rating of the three-phase feeder CTs wired to the relay phase CT terminals. With the phase CTs
connected in wye (star), the calculated phasor sum of the three phase currents (Ia + Ib + Ic = Neutral Current = 3I0)
is used as the input for the neutral.

66 P14DEnh-TM-EN-1.1
P14D Chapter 5 - Configuration

PHASE CT Sec'y
Range: 1 A or 5 A
Default: 1 A
EARTH CT PRIMARY
Range: 1 A to 30000 in steps of 1 A
Default: 1 A
Enter the primary rating of the ground CT wired to the relay ground CT terminals. When the ground input is used
for measuring the residual 3I0 current, the primary current must be the same as the one selected for the phase
CTs.
SENSITIVE EARTH CT PRIMARY (displayed only if the Sensitive EARTH input is installed)
Range: 1 A to 30000 in steps of 1 A
Default: 1 A
Enter the primary rating of the sensitive ground CT wired to the relay sensitive ground CT terminals.
EARTH CT Sec'y
Range 1 A or 5 A
Default: 1 A

5.2 VT RATIO
The VT ratio menu provides the setup for all VTs (PTs) connected to the IED voltage terminals
Path: SETPOINTS > SYSTEM > VT RATIO > VT RATIO

Note:
The nominal PHASE VT SECONDARY and the 4th VT SECONDARY voltage settings are the voltages across the phase VT
terminals and the auxiliary VT terminals correspondingly when nominal voltage is applied.

For example, on a system of 13.8kV nominal primary voltage, and a 14400:120 volt VT in a Delta connection, the
secondary voltage would be 115V, i.e. (13800/14400)*120. For a Wye connection, the voltage value entered must
be the phase to neutral voltage which would be 115/√3 = 66.4 V.
On a 14.4 kV system with a Delta connection and a VT primary to secondary turns ratio of 14400:120, the voltage
value entered would be 120 V, i.e. 14400/120.

PH VT INPUT
Range: Wye, Delta
Default: Wye
Select the type of phase VT connection to match the VTs (PTs) connected to the relay.

MAIN VT PRIMARY
Range: 100 to 1000000 in steps of 1 V
Default: 110 V
Select the phase VT ratio to match the ratio of the VTs connected to the VT bank.

MAIN VT SEC'Y
Range: 10.0 to 240.0 V in steps of 0.1 V

P14DEnh-TM-EN-1.1 67
Chapter 5 - Configuration P14D

Default: 110.0 V
Select the output secondary voltage for phase VTs connected to the J2 bank.

4th VT INPUT
Range: Vab VT, Vbc VT, Vca VT, Van VT, Vbn VT, Vcn VT, Vn
Default: Vab VT
Select the voltage type corresponding to the one applied to the Aux VT relay terminals from bank VT. Select Vn
(neutral voltage), if the neutral voltage is applied to the relay auxiliary VT.

4th VT PRIMARY
Range: 100 to 1000000 in steps of 1 V
Default: 110 V
Select the phase VT ratio to match the ratio of the VT connected to the aux VT input from bank.

4TH VT SEC'Y
Range: 10.0 to 240.0 V in steps of 0.1 V
Default: 110.0 V
Select the output secondary voltage of the aux. VT connected to the aux. VT input from bank.

5.3 POWER SYSTEM

Path: SETPOINTS > SYSTEM > POWER SYSTEM
NOM. FREQUENCY
Range: 50 Hz, 60 Hz
Default: 50 Hz
The power system NOMINAL FREQUENCY is used as a default to set the digital sampling rate if the system
frequency cannot be measured from available AC signals. This may happen if the signals selected for frequency
tracking are not present, or a valid frequency is not detected. Before reverting to the nominal frequency, the
frequency tracking algorithm holds the last valid frequency measurement for a safe period of time while waiting
for the signals to reappear or for the distortions to decay.
PHASE SEQUENCE
Range: STANDAR ABC, REVERSE ACB
Default: STANDARD ABC

5.4 CB SETUP
Breaker detection ON is performed on the IED by monitoring the state/states of either one, or preferably two,
contact inputs. It is highly recommended to monitor the status of the feeder breaker using both breaker auxiliary
contacts 52a, and 52b. However using only one of them is also acceptable.
Path: Setpoints > System > CB Setup
CB STATUS INPUT
Range: None, 52A, 52B, Both 52A and 52B
Default: None
Select CB input configuration.
CB AUX 3PH (52A)

68 P14DEnh-TM-EN-1.1
P14D Chapter 5 - Configuration

Range: Off, Any FlexLogic operand

Default: Off
Selects the Contact Input connected to the breaker auxiliary contact 52a.
CB AUX 3PH (52B)
Range: Off, Any FlexLogic operand
Default: Off
Selects the Contact Input connected to the breaker auxiliary contact 52b.

5.5 USER CURVES

The relay incorporates four programmable User Curves - User Curve 1, 2, 3 and 4. The points for these curves are
defined in the Enervista Flex Setup software. User-defined curves can be used for Time Overcurrent protection in
the same way as IEEE, IAC, ANSI, and IEC curves. Each of the four User Curves 120-point settings for entering times
to reset and operate, 40 points for reset (from 0 to 0.98 times the Pickup value) and 80 for operate (from 1.03 to 20
times the Pickup). This data is converted into two continuous curves by linear interpolation between data points.
Path: Setpoints > System > User Curves

Note:
Use the Setup software program to select, design or modify any of the User Curves.

P14DEnh-TM-EN-1.1 69
Chapter 5 - Configuration P14D

70 P14DEnh-TM-EN-1.1
 CHAPTER 6

CURRENT PROTECTION FUNCTIONS

Chapter 6 - Current Protection Functions P14D

72 P14DEnh-TM-EN-1.1
P14D Chapter 6 - Current Protection Functions

1 CHAPTER OVERVIEW
The P14D provides a wide range of current 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 73
Overcurrent Protection Principles 74
Phase Overcurrent Protection 87
Voltage Dependent Overcurrent Element 94
Negative Sequence Overcurrent Protection 98
Earth Fault Protection 103
Sensitive Earth Fault Protection 113
Cold Load Pickup 120
Thermal Overload Protection 123
Broken Conductor Protection 128
Blocked Overcurrent Protection 130
SOTF Protection 132
Undercurrent Protection 133

P14DEnh-TM-EN-1.1 73
Chapter 6 - Current Protection Functions P14D

2 OVERCURRENT PROTECTION PRINCIPLES

Most electrical power system faults result in an overcurrent of one kind or another. It is the job of protection
devices, formerly known as 'relays' but now known as Intelligent Electronic Devices (IEDs) to protect the power
system from faults. The general principle is to isolate the faults as quickly as possible to limit the danger and
prevent fault currents flowing through systems, which can cause severe damage to equipment and systems. At
the same time, we wish to switch off only the parts of the power grid that are absolutely necessary, to prevent
unnecessary blackouts. The protection devices that control the tripping of the power grid's circuit breakers are
highly sophisticated electronic units, providing an array of functionality to cover the different fault scenarios for a
multitude of applications.
The described products offer a range of overcurrent protection functions including:
● Phase Overcurrent protection
● Earth Fault Overcurrent protection
● Negative Sequence Overcurrent protection
● Sensitive Earth Fault protection

To ensure that only the necessary circuit breakers are tripped and that these are tripped with the smallest possible
delay, the IEDs in the protection scheme need to co-ordinate with each other. Various methods are available to
achieve correct co-ordination between IEDs in a system. These are:
● By means of time alone
● By means of current alone
● By means of a combination of both time and current.
Grading by means of current alone is only possible where there is an appreciable difference in fault level between
the two locations where the devices are situated. Grading by time is used by some utilities but can often lead to
excessive fault clearance times at or near source substations where the fault level is highest.
For these reasons the most commonly applied characteristic in co-ordinating overcurrent devices is the IDMT
(Inverse Definite Minimum Time) type.

2.1 IDMT CHARACTERISTICS

There are two basic requirements to consider when designing protection schemes:
● All faults should be cleared as quickly as possible to minimise damage to equipment
● Fault clearance should result in minimum disruption to the electrical power grid.

The second requirement means that the protection scheme should be designed such that only the circuit
breaker(s) in the protection zone where the fault occurs, should trip.
These two criteria are actually in conflict with one another, because to satisfy (1), we increase the risk of shutting
off healthy parts of the grid, and to satisfy (2) we purposely introduce time delays, which increase the amount of
time a fault current will flow. With IDMT protection applied to radial feeders, this problem is exacerbated by the
nature of faults in that the protection devices nearest the source, where the fault currents are largest, actually
need the longest time delay.
IDMT characteristics are described by operating curves. Traditionally, these were defined by the performance of
electromechanical relays. In numerical protection, equations are used to replicate these characteristics so that
they can be used to grade with older equipment.
The old electromechanical relays countered this problem somewhat due to their natural operate time v. fault
current characteristic, whereby the higher the fault current, the quicker the operate time. The characteristic typical
of these electromechanical relays is called Inverse Definite Minimum Time or IDMT for short.

74 P14DEnh-TM-EN-1.1
P14D Chapter 6 - Current Protection Functions

2.1.1 IEC 60255 IDMT CURVES

There are seven well-known variants of this characteristic:
● Standard Inverse
● Very inverse
● Extremely inverse
● UK Long Time inverse
● Rectifier

● FR Short Time Inverse

● Standard Inverse (1.3s)

These equations and corresponding curves governing these characteristics are very well known in the power
industry.

Standard Inverse
This characteristic is commonly known as the 3/10 characteristic, i.e. at ten times setting current and TMS of 1 the
relay will operate in 3 seconds.
The characteristic curve can be defined by the mathematical expression:

0.14
top = T 0.02
 I 
  −1
 Is 
The standard inverse time characteristic is widely applied at all system voltages – as back up protection on EHV
systems and as the main protection on HV and MV distribution systems.
In general, the standard inverse characteristics are used when:
● There are no co-ordination requirements with other types of protective equipment further out on the
system, e.g. Fuses, thermal characteristics of transformers, motors etc.
● The fault levels at the near and far ends of the system do not vary significantly.
● There is minimal inrush on cold load pick up. Cold load inrush is that current which occurs when a feeder is
energised after a prolonged outage. In general the relay cannot be set above this value but the current
should decrease below the relay setting before the relay operates.

Very Inverse
This type of characteristic is normally used to obtain greater time selectivity when the limiting overall time factor is
very low, and the fault current at any point does not vary too widely with system conditions. It is particularly
suitable, if there is a substantial reduction of fault current as the distance from the power source increases. The
steeper inverse curve gives longer time grading intervals. Its operating time is approximately doubled for a
reduction in setting from 7 to 4 times the relay current setting. This permits the same time multiplier setting for
several relays in series.
The characteristic curve can be defined by the mathematical expression:

13.5
top = T
I 
  −1
 Is 

P14DEnh-TM-EN-1.1 75
Chapter 6 - Current Protection Functions P14D

Extremely Inverse
With this characteristic the operating time is approximately inversely proportional to the square of the current. The
long operating time of the relay at peak values of load current make the relay particularly suitable for grading with
fuses and also for protection of feeders which are subject to peak currents on switching in, such as feeders
supplying refrigerators, pumps, water heaters etc., which remain connected even after a prolonged interruption of
supply.
For cases where the generation is practically constant and discrimination with low tripping times is difficult to
obtain, because of the low impedance per line section, an extremely inverse relay can be very useful since only a
small difference of current is necessary to obtain an adequate time difference.
Another application for this relay is with auto reclosers in low voltage distribution circuits. As the majority of faults
are of a transient nature, the relay is set to operate before the normal operating time of the fuse, thus preventing
perhaps unnecessary blowing of the fuse.
Upon reclosure, if the fault persists, the recloser locks itself in the closed position and allows the fuse to blow to
clear the fault.
This characteristic is also widely used for protecting plant against overheating since overheating is usually an I2t
function.
This characteristic curve can be defined by the mathematical expression:

80
top = T 2
I 
  −1
 Is 

UK Long Time Inverse

This type of characteristic has a long time characteristic and may be used for protection of neutral earthing
resistors (which normally have a 30 second rating). The relay operating time at 5 times current setting is 30
seconds at a TMS of 1.
This can be defined by:

120
top = T
 I 
  −1
 Is 

Rectifier
This characteristic curve can be defined by the mathematical expression:

45900
t op = T 5.6
I 
I  −1
 S

FR Short Time Inverse

This characteristic curve can be defined by the mathematical expression:

0.05
t op = T 0.04
I 
I  −1
 S

76 P14DEnh-TM-EN-1.1
P14D Chapter 6 - Current Protection Functions

Standard Inverse (1.3S)

This characteristic curve can be defined by the mathematical expression:

0.00607
t op = T 0.02
I 
I  −1
 S
In the above equations:
• top is the operating time
• T is the time multiplier setting
• I is the measured current
● • Is is the current threshold setting.

The ratio I/Is is sometimes defined as ‘M’ or ‘PSM’ (Plug Setting Multiplier).
These curves are plotted as follows:
1000.00

100.00
Operating time (seconds)

Long Time Inverse (LTI)

10.00

Standard Inverse (SI)

1.00
Very Inverse (VI)

Extremely Inverse (EI)

0.10
1 10 100

E00600 Current (multiples of IS)

Figure 16: IEC 60255 IDMT curves

2.1.2 EUROPEAN STANDARDS

The IEC 60255 IDMT Operate equation is:

 β 
top = T  α + L+C
 M −1 
and the IEC 60255 IDMT Reset equation is:

P14DEnh-TM-EN-1.1 77
Chapter 6 - Current Protection Functions P14D

 β 
tr = T  α 
 1− M 
where:
● top is the operating time
● tr is the reset time
● T is the Time Multiplier setting
● M is the ratio of the measured current divided by the threshold current (I/Is)
● β is a constant, which can be chosen to satisfy the required curve characteristic
● α is a constant, which can be chosen to satisfy the required curve characteristic
● C is a constant for adding Definite Time (Definite Time adder)
● L is a constant (usually only used for ANSI/IEEE curves)

The constant values for the IEC IDMT curves are as follows:
Curve Description b constant a constant L constant
IEC Standard Inverse Operate 0.14 0.02 0
IEC Standard Inverse Reset 8.2 6.45 0
IEC Very Inverse Operate 13.5 1 0
IEC Very Inverse Reset 50.92 2.4 0
IEC Extremely Inverse Operate 80 2 0
IEC Extremely Inverse Reset 44.1 3.03 0
UK Long Time Inverse Operate* 120 1 0
Rectifier Operate* 45900 5.6 0
FR Short Time Inverse Operate* 0.05 0.04 0
Standard Inverse (1.3s) Operate 0.0607 0.02 0
Standard Inverse (1.3s) Reset 3.55 6.45 0

Note:
* When using UK Long Time Inverse, Rectifier or FR Short time Inverse for the Operate characteristic, DT (Definite Time) is
always used for the Reset characteristic.

Rapid Inverse (RI) characteristic

The RI operate curve is represented by the following equation:

 
 1 
top = K 
0.236 
 0.339 − 
 M 

78 P14DEnh-TM-EN-1.1
P14D Chapter 6 - Current Protection Functions

where:
● top is the operating time
● K is the Time Multiplier setting
● M is the ratio of the measured current divided by the threshold current (I/Is)

Note:
* When using RI for the Operate characteristic, DT (Definite Time) is always used for the Reset characteristic.

2.1.3 NORTH AMERICAN STANDARDS

The IEEE IDMT Operate equation is:

 β 
top = TD  α + L+C
 M −1 
and the IEEE IDMT Reset equation is:

 β 
tr = TD  α 
 1− M 
where:
● top is the operating time
● tr is the reset time
● TD is the Time Dial setting
● M is the ratio of the measured current divided by the threshold current (I/Is)
● b is a constant, which can be chosen to satisfy the required curve characteristic
● a is a constant, which can be chosen to satisfy the required curve characteristic
● C is a constant for adding Definite Time (Definite Time adder)
● L is a constant (usually only used for ANSI/IEEE curves)

The constant values for the IEEE curves are as follows:

Curve Description b constant a constant L constant
IEEE Moderately Inverse Operate 0.0515 0.02 0.114
IEEE Moderately Inverse Reset 4.85 2 0
IEEE Very Inverse Operate 19.61 2 0.491
IEEE Very Inverse Reset 21.6 2 0
IEEE Extremely Inverse Operate 28.2 2 0.1217
IEEE Extremely Inverse Reset 29.1 2 0
CO8 US Inverse Operate 5.95 2 0.18
CO8 US Inverse Reset 5.95 2 0
CO2 US Short Time Inverse Operate 0.16758 0.02 0.11858
CO2 US Short Time Inverse Reset 2.261 2 0
The ANSI Operate equation is:

P14DEnh-TM-EN-1.1 79
Chapter 6 - Current Protection Functions P14D

 
T = TD ×  A + 
B D E
+ +


( I / I pickup ) - C (( I / I pickup )-C) (
2 3
)
( I / I pickup ) - C 
 β 
tr = TD  α 
 1− M 
And the ANSI Reset equation is:

 
tr
TRESET = TD ×  
1 − ( I / I
pickup ) 
2


where:
● T = operate time (in seconds),
● TD = Time Dial setting,
I = measured current,
● Ipickup = threshold Current,
● A to E = constants,
● tr = characteristic constant, and
● TRESET = reset time in seconds
The constant values for the ANSI curves are as follows:

Curve Description A constant B constant C constant D constant E constant tr constant

ANSI Extremely Inverse 0.0399 0.2294 0.5000 3.0094 0.7222 5.67
ANSI Very Inverse 0.0615 0.7989 0.3400 -0.2840 4.0505 3.88
ANSI Normally Inverse 0.0274 2.2614 0.3000 -4.1899 9.1272 5.95

ANSI Moderately Inverse 0.1735 0.6791 0.8000 -0.0800 0.1271 1.08

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P14D Chapter 6 - Current Protection Functions

2.1.4 IEC AND IEEE INVERSE CURVES

IEC Standard Inverse Curve IEC Very Inverse Curve

1000 1000

100 TMS 100 TMS

0.025 0.025

0.075 0.075
10 10

Time in seconds
Time in seconds

0.100 0.100

0.300 0.300

1 1
0.500 0.500

0.700 0.700

0.900 0.900
0.1 0.1

1.000 1.000

1.200 1.200
0.01 0.01
0.5 5 50 0.5 5 50
Current in Multiples of Setting Current in Multiples of Setting

E00757

Figure 17: IEC standard and very inverse curves

IEC Extremely Inverse Curve

IEEE Moderate Inverse Curve
1000

1000

100 TMS
0.05
100
0.025
0.5
0.075
10
1
Time in seconds
Time in seconds

0.100 10

5
0.300

1 10
0.500 1

0.700 30

0.900 50
0.1 0.1

1.000
70

1.200
0.01 100
0.01
0.5 5 50 0.5 5 50
Current in Multiples of Setting Current in Multiples of Setting

E00758

Figure 18: IEC Extremely inverse and IEEE moderate inverse curves

P14DEnh-TM-EN-1.1 81
Chapter 6 - Current Protection Functions P14D

IEEE Very Inverse Curve IEEE Extremely Inverse Curve

10000 10000

TD TD

1000 0.05 1000 0.05

0.5 0.5

100 100
1 1

Time in seconds
Time in seconds

5 5
10 10

10 10

1 30 1 30

50 50
0.1 0.1
70 70

0.01 100 0.01 100

0.5 5 50 0.5 5 50

Current in Multiples of Setting Current in Multiples of Setting

E00759
Figure 19: IEEE very and extremely inverse curves

2.1.5 ANSI CURVES

The IAC Operate equation is:

 
T = TD ×  A + 
B D E
+ +


( I / I pickup ) − C (( I / I pickup )−C) (
2 3
( I / I pickup ) − C )
And the IAC Reset equation is:

 
tr
TRESET = TD ×  
1 − ( I / I
pickup ) 
2


where:
● T = operate time (in seconds),
● TD = Time Dial setting,
● I = measured current,
● Ipickup = threshold Current,
● A to E = constants,
● tr = characteristic constant, and
● TRESET = reset time in seconds
The constant values for the IAC curves are as follows:

Curve Description A constant B constant C constant D constant E constant tr constant

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ANSI Extremely Inverse 0.0399 0.2294 0.5000 3.0094 0.7222 5.67

ANSI Very Inverse 0.0615 0.7989 0.3400 -0.2840 4.0505 3.88

ANSI Normally Inverse 0.0274 2.2614 0.3000 -4.1899 9.1272 5.95

ANSI Moderately Inverse 0.1735 0.6791 0.8000 -0.0800 0.1271 1.08

2.1.6 IAC CURVES

The IAC Operate equation is:

 
T = TD ×  A + 
B D E
+ +


( I / I pickup ) − C (( I / I pickup )−C) (
2
)
3
( I / I pickup ) − C 
And the IAC Reset equation is:

 
 tr 
TRESET = TD ×
1 − ( I / I
pickup ) 
2


where:
● T = operate time (in seconds),
● TD = Time Dial setting,
● I = measured current,
● Ipickup = threshold Current,
● A to E = constants,
● tr = characteristic constant, and
● TRESET = reset time in seconds
The constant values for the IAC curves are as follows:

Curve Description A constant B constant C constant D constant E constant tr constant

IAC Extremely Inverse 0.0040 0.6379 0.6200 1.7872 0.2461 6.008

IAC Very Inverse 0.0900 0.7965 0.1000 -1.2885 7.9586 4.678

IAC Normally Inverse 0.2078 0.8630 0.8000 -0.4180 0.1947 0.990

IAC Moderately Inverse 0.0428 0.0609 0.6200 -0.0010 0.0221 0.222

2.1.7 I2T CURVES

The I2T Operate equation is:

 
 100 
T = TD ×
(I / I
pickup ) 
2


And the I2T Reset equation is:

 
 100 
TRESET = TD ×
(I / I
pickup ) 
−2



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Chapter 6 - Current Protection Functions P14D

where:
● T = operate time (in seconds),
● TD = Time Dial setting,
● I = measured current,
● Ipickup = threshold Current and
● TRESET = reset time in seconds

2.1.8 I4T CURVES

The I4T Operate equation is:

 
 100 
T = TD ×
(I / I
pickup ) 
4


And the I4T Reset equation is:

 
100
TRESET = TD ×  
(I / I
pickup ) 
−4


where:
● T = operate time (in seconds),
● TD = Time Dial setting,
● I = measured current,
● Ipickup = threshold Current and
● TRESET = reset time in seconds

2.1.9 DIFFERENCES BETWEEN THE NORTH AMERICAN AND EUROPEAN STANDARDS

The IEEE and US curves are set differently to the IEC/UK curves, with regard to the time setting. A time multiplier
setting (TMS) is used to adjust the operating time of the IEC curves, whereas a time dial setting is used for the
IEEE/US curves. The menu is arranged such that if an IEC/UK curve is selected, the I>1 Time Dial setting is not
visible and vice versa for the TMS setting. For both IEC and IEEE/US type curves, a definite time adder setting is
available, which will increase the operating time of the curves by the set value.

2.1.10 PROGRAMMABLE CURVES

In addition to the standard curves as defined by various countries and standardising bodies, it is possible to
program custom curves using FlexCurves, as described in the Settings Application Software chapter. This is a user-
friendly tool by which you can create curves either by formula or by entering data points. FlexCurves help you to
match more closely the withstand characteristics of the electrical equipment than standard curves.

2.2 PRINCIPLES OF IMPLEMENTATION

The range of protection products provides a very wide range of protection functionality. Despite the diverse range
of functionality provided, there is some commonality between the way many of the protection functions are
implemented. It is important to describe some of these basic principles before going deeper into the individual
protection functions.
A simple representation of protection functionality is shown in the following diagram:

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Energising quantity Start signal

IDMT /DT
Threshold
& & Trip Signal

Function inhibit

Timer
Settings

Voltage
Directional Check
Current

V06000

Figure 20: Principle of protection function implementation

An energising quantity is either a voltage input from a system voltage transformer, a current input from a system
current transformer or another quantity derived from one or both of these. The energising quantities are extracted
from the power system. The signals are converted to digital quantities where they can be processed by the IEDs
internal processor.
In general, an energising quantity, be it a current, voltage, power, frequency, or phase quantity, is compared with a
threshold value, which may be settable, or hard-coded depending on the function. If the quantity exceeds (for
overvalues) or falls short of (for undervalues) the threshold, a signal is produced, which when gated with the
various inhibit functions becomes the Start signal for that protection function. This Start signal is generally made
available to Programmable Scheme Logic (PSL) for further processing. It is also passed through a timer function to
produce the Trip signal. The timer function may be an IDMT curve, or a Definite Time delay, depending on the
function. The timer can be configured by a range of settings to define such parameters as the type of curve, The
Time Multiplier Setting, the IDMT constants, the Definite Time delay etc.
In General Electric products, there are usually several independent stages for each of the functions, and for three-
phase functions, there are usually independent stages for each of the three phases.
PTOC protection elements use an Inverse Definite Minimum time (IDMT) timer function, and a Definite Time timer
(DT) function. If the DT time delay is set to '0', then the function is known to be "instantaneous". In many instances,
the term 'instantaneous protection" is used loosely to describe Definite Time protection stages, even when the
stage may not theoretically be instantaneous.
Many protection functions require a direction-dependent decision. Such functions can only be implemented where
both current and voltage inputs are available. For such functions, a directional check is required, whose output can
block the Start signal should the direction of the fault be wrong.

Note:
In the logic diagrams and descriptive text, it is usually sufficient to show only the first stage, as the design principles for
subsequent stages are usually the same (or at least very similar). Where there are differences between the functionality of
different stages, this is clearly indicated.

2.2.1 TIMER HOLD FACILITY

The Timer Hold facility is available for stages with IDMT functionality , and is controlled by the timer reset settings
for the relevant stages (e.g. I>1 tReset, I>2 tReset ). These cells are not visible for the IEEE/US curves if an inverse
time reset characteristic has been selected, because in this case the reset time is determined by the time dial
setting (TDS).

P14DEnh-TM-EN-1.1 85
Chapter 6 - Current Protection Functions P14D

This feature may be useful in certain applications, such as when grading with upstream electromechanical
overcurrent relays, which have inherent reset time delays. If you set the hold timer to a value other than zero, the
resetting of the protection element timers will be delayed for this period. This allows the element to behave in a
similar way to an electromechanical relay. If you set the hold timer to zero, the overcurrent timer for that stage will
reset instantaneously as soon as the current falls below a specified percentage of the current setting (typically
95%).
Another situation where the timer hold facility may be used to reduce fault clearance times is for intermittent
faults. An example of this may occur in a plastic insulated cable. In this application it is possible that the fault
energy melts and reseals the cable insulation, thereby extinguishing the fault. This process repeats to give a
succession of fault current pulses, each of increasing duration with reducing intervals between the pulses, until the
fault becomes permanent.
When the reset time is instantaneous, the device will repeatedly reset and not be able to trip until the fault
becomes permanent. By using the Timer Hold facility the device will integrate the fault current pulses, thereby
reducing fault clearance time.

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3 PHASE OVERCURRENT PROTECTION

Phase current faults are faults where fault current flows between two or more phases of a power system. The fault
current may be between the phase conductors only or, between two or more phase conductors and earth.
Although not as common as earth faults (single phase to earth), phase faults are typically more severe.

3.1 PHASE OVERCURRENT PROTECTION IMPLEMENTATION

Phase Time Overcurrent Protection is configured under the path SETPOINTS\PROTECTION\GROUP [1-4]\CURRENT
PROT.\PHASE TOC
Phase Instantaneous Overcurrent Protection is configured under the path SETPOINTS\PROTECTION\GROUP
[1-4]\CURRENT PROT.\PHASE IOC
The product provides segregated 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.
Each stage of PTOC provides a choice of operate and reset characteristics, where you can select between:
● A range of IDMT (Inverse Definite Minimum Time) curves based on IEC, IEEE, ANSI and IAC standards
● A range of programmable user-defined curves
● DT (Definite Time) characteristic

For stage 1, this is achieved using the following settings:

● I>1 Function for the overcurrent operate characteristic
● I>1 Reset Char for the overcurrent reset characteristic
The setting names for other stages follow the same principles.

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3.2 NON-DIRECTIONAL OVERCURRENT LOGIC

PTOC I>1 Start A
IA

I>1 Current Set

& IDMT/DT PTOC I>1 Trip A

Timer Settings

PTOC I>1 Start B

IB

I>1 Current Set & IDMT/DT PTOC I>1 Trip B

Timer Settings

PTOC I>1 Start C

IC

I>1 Current Set

& IDMT/DT PTOC I>1 Trip C

Timer Settings 1 PTOC I>1 Start

1 PTOC I>1 Trip

AR Blk Main Prot Notes: This diagram does not show all stages. Other stages follow
& similar principles.
I> Blocking AR will block in DT elements, and raise the threshold in IDMT
AR Blocks I >3 elements
V06001

Figure 21: Non-directional Overcurrent Logic diagram

Phase Overcurrent Modules are level detectors that detect when the current magnitude exceeds a set threshold.
When this happens, a Start signal is generated unless it is inhibited by a blocking signal. This Start signal initiates
the timer module, which can be configured as an IDMT timer or DT timer, for PTOC or PIOC respectively. The Start
signal is also available for use in the PSL. For each stage, there are three Phase Overcurrent Modules, one for each
phase. The three Start signals from each of these phases are combined to form a 3-phase Start signal.
The timer can be configured with several settings depending on which type of timer is selected. Taking stage 1 as
an example:
The setting I>1 Time Delay sets the DT time delay
The setting I>1 TMS sets the Time Multiplier setting for IEC IDMT curves
The setting I>1 Time Dial sets the Time Multiplier setting for IEEE/US IDMT curves
The setting I>1 tRESET determines the reset time for the DT characteristic
The outputs of the timer modules are the single-phase trip signals. These trip signals are combined to form a 3-
phase Trip signal.

3.3 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.

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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
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 using the IED characteristic angle (RCA) setting. The RCA 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 characteristic angle can be set independently for each stage. For PTOC stage 1, for example, this would be the
setting I>1 Char Angle. It is possible to set characteristic angles anywhere in the range 0° to + 359°.

-90o

VAG(Unfaulted) Fault angle

set @60o Lag

VPol

VAG(Faulted) IA
ECA
set @30o

VBC

VBC
VCG VBG +90o

Phasors for Phase APolarization:

VPol = VBC*(1/_ECA) = polarizing voltage

IA = operating current
o
ECA= Element Characteristic Angle @30

V06029

Figure 22: Directional trip angles

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 polarisation feature that stores the pre-fault voltage information
and continues to apply this to the directional overcurrent elements for a period of 3 cycles. This ensures that either
instantaneous or time-delayed directional overcurrent elements will be allowed to operate, even with a three-
phase voltage collapse.

P14DEnh-TM-EN-1.1 89
Chapter 6 - Current Protection Functions P14D

3.4 DIRECTIONAL OVERCURRENT LOGIC

PTOC I>1 Start A
IA

I>1 Current Set & PTOC I>1 Trip A

IDMT/DT
&

Timer Settings

IA
VAB
I>1 Direction
Notes: This diagram does not show all stages. Other stages follow
Directional similar principles.
check AR will block in DT elements, and raise the threshold in IDMT
elements.

I>1 Char Angle

AR Blk Main Prot

&
I>Blocking
AR Blocks I >1

V06003

Figure 23: Directional Overcurrent Logic diagram (Phase A shown only)

90 P14DEnh-TM-EN-1.1
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3.5 APPLICATION NOTES

3.5.1 PARALLEL FEEDERS

33 kV

R1 R2
OC/EF OC/EF

SBEF
R3 R4
DOC/DEF DOC/DEF
OC/EF OC/EF

11 kV

R5
OC/EF

Loads
E00603

Figure 24: Typical distribution system using parallel transformers

In the application shown in the diagram, a fault at ‘F’ could result in the operation of both R3 and R4 resulting in
the loss of supply to the 11 kV busbar. Hence, with this system configuration, it is necessary to apply directional
protection devices at these locations set to 'look into' their respective transformers. These devices should co-
ordinate with the non-directional devices, R1 and R2, to ensure discriminative operation during such fault
conditions.
In such an application, R3 and R4 may commonly require non-directional overcurrent protection elements to
provide protection to the 11 kV busbar, in addition to providing a back-up function to the overcurrent devices on
the outgoing feeders (R5).
For this application, stage 1 of the R3 and R4 overcurrent protection would be set to non-directional and time
graded with R5, using an appropriate time delay characteristic. Stage 2 could then be set to directional (looking
back into the transformer) and also have a characteristic which provides correct co-ordination with R1 and R2.
Directionality for each of the applicable overcurrent stages can be set in the directionality cells (I>1 Direction).

Note:
The principles outlined for the parallel transformer application are equally applicable for plain feeders that are operating in
parallel.

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Chapter 6 - Current Protection Functions P14D

3.5.2 RING MAIN ARRANGEMENTS

Source

2.1s 2.1s

51 51
0.1s 0.1s
F Load B
67 67

Load
67
1.7s
Load 67
1.7s

Load 67
0.5s
67 Load 0.5s

1.3s 1.3s
E Load C
67 67

0.9s 0.9s

67 67

D
E00604

Figure 25: Typical ring main with associated overcurrent protection

In a ring main arrangement, current may flow in either direction through the various device locations, therefore
directional overcurrent devices are needed to achieve correct discrimination.
The normal grading procedure for overcurrent devices protecting a ring main circuit is to consider the ring open at
the supply point and to grade the devices first clockwise and then anti-clockwise. The arrows shown at the various
device locations depict the direction for forward operation of the respective devices (i.e. the directional devices are
set to look into the feeder that they are protecting).
The diagram shows typical time settings (assuming definite time co-ordination is used), from which it can be seen
that any faults on the interconnections between stations are cleared discriminatively by the devices at each end of
the feeder.
Any of the overcurrent stages may be configured to be directional and co-ordinated, but bear in mind that IDMT
characteristics are not selectable on all the stages.

3.5.3 SETTING GUIDELINES

Standard principles should be applied in calculating the necessary current and time settings. The example detailed
below shows a typical setting calculation and describes how the settings are applied.

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This example is for a device feeding a LV switchboard and makes the following assumptions:
● CT Ratio = 500/1
● Full load current of circuit = 450A
● Slowest downstream protection = 100A Fuse

The current setting on the device must account for both the maximum load current and the reset ratio, therefore:
I> must be greater than: 450/drop-off = 450/0.95 = 474A.
The required setting is 475A in terms of primary current.
A suitable time delayed characteristic will now need to be chosen. When co-ordinating with downstream fuses, the
applied characteristic should be closely matched to the fuse characteristic. Therefore, assuming IDMT co-
ordination is to be used, an Extremely Inverse (EI) characteristic would normally be chosen. This is found under the
I>1 Curve setting as IEC E Inverse.
Finally, a suitable time multiplier setting (TMS) must be calculated and entered in setting I>1 TMS.

3.5.4 SETTING GUIDELINES (DIRECTIONAL ELEMENT)

The applied current settings for directional overcurrent devices are dependent upon the application in question. In
a parallel feeder arrangement, load current is always flowing in the non-operate direction. Hence, the current
setting may be less than the full load rating of the circuit.
You need to observe some setting constraints when applying directional overcurrent protection at the receiving-
end of parallel feeders. These minimum safe settings are designed to ensure that there is no possibility of
undesired tripping during clearance of a source fault. For a linear system load, these settings are as follows:
We recommend the following settings to ensure that there is no possibility of malaoperation:
● Parallel plain feeders: Set to 50% pre-fault load current
● Parallel transformer feeders: Set to 87% pre-fault load current

In a ring main application, the load current can flow in either direction. The current setting must be above the
maximum load current.
The required characteristic angle settings for directional devices depend on the application. We recommend the
following settings:
● Plain feeders, or applications with an earthing point behind the device location, should use a +30° RCA
setting
● Transformer feeders, or applications with a zero sequence source in front of the device location, should use
a +45° RCA setting

Although it is possible to set the RCA to exactly match the system fault angle, we recommend that you adhere to
the above guidelines, as these settings provide satisfactory performance and stability under a wide range of
system conditions.

P14DEnh-TM-EN-1.1 93
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4 VOLTAGE DEPENDENT OVERCURRENT ELEMENT

An overcurrent protection scheme is co-ordinated throughout a system such that cascaded operation is achieved.
This means that if for some reason a downstream circuit breaker fails to trip for a fault condition, the next
upstream circuit breaker should trip.
However, where long feeders are protected by overcurrent protection, the detection of remote phase-to-phase
faults may prove difficult due to the fact that the current pick-up of phase overcurrent elements must be set above
the maximum load current, thereby limiting the minimum sensitivity.
If the current seen by a local device for a remote fault condition is below its overcurrent setting, a voltage
dependent element may be used to increase the sensitivity to such faults. As a reduction in system voltage will
occur during overcurrent conditions, this may be used to enhance the sensitivity of the overcurrent protection by
reducing the pick up level.
Voltage dependent overcurrent devices are often applied in generator protection applications in order to give
adequate sensitivity for close up fault conditions. The fault characteristic of this protection must then co-ordinate
with any of the downstream overcurrent devices that are responsive to the current decrement condition. It
therefore follows that if the device is to be applied to an outgoing feeder from a generator station, the use of
voltage dependent overcurrent protection in the feeder device may allow better co-ordination with the Voltage
Dependent device on the generator.

4.1 VOLTAGE DEPENDENT OVERCURRENT PROTECTION IMPLEMENTATION

Voltage Dependent Overcurrent Protection (VDep OC) is set in Phase TOC.
The function is available for each stage of PTOC. When I>1 VDep OC is enabled, the overcurrent threshold setting is
modified when the voltage falls below a set threshold.
If voltage dependant overcurrent operation is selected, the element can be set in one of two modes, voltage
controlled overcurrent or voltage restrained overcurrent.

4.1.1 VOLTAGE CONTROLLED OVERCURRENT PROTECTION

In Voltage Controlled Operation (VCO) mode of operation, the under voltage detector is used to produce a step
change in the current setting, when the voltage falls below the voltage setting V Dep OC V<1 Set. The operating
characteristic of the current setting when voltage controlled mode is selected is as follows:

Current
setting

Current pickup setting

K x Current pickup setting

Measured voltage
Voltage threshold setting
E00642

Figure 26: Modification of current pickup level for voltage controlled overcurrent protection

94 P14DEnh-TM-EN-1.1
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4.1.2 VOLTAGE RESTRAINED OVERCURRENT PROTECTION

In Voltage Restrained Operation (VRO) mode the effective operating current of the protection element is
continuously variable as the applied voltage varies between two voltage thresholds. This protection mode is
considered to be better suited to applications where the generator is connected to the system via a generator
transformer.
With indirect connection of the generator, a solid phase-phase fault on the local busbar will result in only a partial
phase-phase voltage collapse at the generator terminals.
The voltage-restrained current setting is related to measured voltage as follows:
● If V is greater than V<1, the current setting (Ιs) = Ι>
● If V is greater than V<2 but less than V<1, the current setting (Ιs) =

V −V < 2
KI > + ( I > − KI )
V < 1−V < 2
● If V is less than V<2, the current setting (Ιs) = K.Ι>
where:
● Ι> = Over current stage setting
● Ιs = Current setting at voltage V
● V = Voltage applied to relay element
● V<1 = V Dep OC V<1
● V<2 = V Dep OC V<2

Current
setting

V Dep OC I> Set

V Dep OC k Set

V Dep OC V<2 Set V Dep OC V<1 Set Measured voltage

E00643

Figure 27: Modification of current pickup level for voltage restrained overcurrent protection

P14DEnh-TM-EN-1.1 95
Chapter 6 - Current Protection Functions P14D

4.1.3 VOLTAGE DEPENDENT OVERCURRENT LOGIC

I>1 V Dep OC
VCO
&
VRO 1 Vdep OC Start AB

VAB
I>1 V Dep OC V<1

I>1 Current Set

Applied Current
× Threshold
I>1 V Dep OC k
1
VAB &

I>1 V Dep OC V<1

I>1 Current Set

VAB &
I>1 V Dep OC V<2

I>1 Current Set

×
I>1 V Dep OC k

VAB &

I>1 V Dep OC V<2 &

Note: This diagram does not show all stages.
VAB
Other stages follow similar principles.
I>1 V Dep OC V<1

I>1 V Dep OC k
Functional
I>1 Current Set
Operato r
VAB
V06004

Figure 28: Voltage dependant overcurrent logic (Phase A to phase B)

The current threshold setting for the Overcurrent function is determined by the voltage.
If the voltage is greater than I>1 V Dep OC V<1, the normal overcurrent setting I>1 current set is used. this applies
to both VCO and VRO modes.
If the voltage is less than I>1 V Dep OC V<1 AND it is in VCO mode, the overcurrent setting I>1 current set is
multiplied by the factor set by I>1 V Dep OC k.
If the voltage is less than I>1 V Dep OC V<2 AND it is in VRO mode, the overcurrent setting I>1 current set is
multiplied by the factor set by I>1 V Dep OC k.
If the voltage is between I>1 V Dep OC V<1 and I>1 V Dep OC V<2 AND it is in VRO mode, the overcurrent setting is
multiplied by a functional operator to determine the setting.

4.2 APPLICATION NOTES

4.2.1 SETTING GUIDELINES

The I>1 V Dep OC k setting should be set low enough to allow operation for remote phase-to-phase faults,
typically:

96 P14DEnh-TM-EN-1.1
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IF
k=
1.2 I >
where:
● IF = Minimum fault current expected for the remote fault
● I> = Phase current setting for the element to have VCO control

Example
If the overcurrent device has a setting of 160% In, but the minimum fault current for the remote fault condition is
only 80% In, then the required k factor is given by:

0.8
k= = 0.42
1.6 ×1.2
The voltage threshold, I>1 V Dep OC V<(n) setting would be set below the lowest system voltage that may occur
under normal system operating conditions, whilst ensuring correct detection of the remote fault.

P14DEnh-TM-EN-1.1 97
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5 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.

5.1 NEGATIVE SEQUENCE OVERCURRENT PROTECTION IMPLEMENTATION

Negative Sequence Overcurrent Protection is implemented under the path SETPOINTS\PROTECTION\GROUP
[1-4]\CURRENT PROT.\NEG SEQ TOC).
Negative Sequence Instantaneous Protection is configured under the path SETPOINTS\PROTECTION\GROUP
[1-4]\CURRENT PROT.\NEG SEQ IOC).
The product provides multiple stages of negative sequence overcurrent protection with independent time delay
characteristics.
Each NEG SEQ TOC stage provides a choice of operate and reset characteristics, where you can select between:
● A range of standard IDMT (Inverse Definite Minimum Time) curves
● A range of User-defined curves
● DT (Definite Time)

For stage 1, this is achieved using the following settings:

● I2>1 Curve for the overcurrent operate characteristic
● I2>1 Reset Char for the overcurrent reset characteristic
The setting names for other stages follow the same principles.

5.2 NON-DIRECTIONAL NEGATIVE SEQUENCE OVERCURRENT LOGIC

I2 I2>1 TOC Start
I2>1 Current Set &
IDMT/DT I2>1 TOC Trip
CTS Block

I2>1 Inhibit Timer Settings

Note: This diagram does not show all stages. Other stages follow
similar principles.
V06006

Figure 29: Negative Sequence Overcurrent logic - non-directional operation

98 P14DEnh-TM-EN-1.1
P14D Chapter 6 - Current Protection Functions

For Negative Phase Sequence Overcurrent Protection, the energising quantity I2 is compared with the threshold
voltage I2>1 Current Set. If the value exceeds this setting a Start signal is generated, provided there are no blocks.
The function can be blocked if a CTS condition is detected with inhibit signal.
The I2>1 (IOC, TOC) Start signal is fed into a timer to produce the I2>1 (IOC, TOC) Trip signal.
This diagram and description applies to each stage.

5.3 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>1 Direction setting for the relevant stage. It can be set to non-directional, directional
forward, or directional reverse.
A suitable characteristic angle setting (I2>1 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.

5.3.1 DIRECTIONAL NEGATIVE SEQUENCE OVERCURRENT

Mode Operating Current
Negative Sequence Iop = |I_2| - K x |I_1|

Direction Compared Phasors

Forward -V_2 I_2 x 1∠ECA
Reverse -V_2 -(I_2 x 1∠ECA)
Forward -V_2 I_2 x 1∠ECA
Reverse -V_2 -(I_2 x 1∠ECA)

P14DEnh-TM-EN-1.1 99
Chapter 6 - Current Protection Functions P14D

E06033

Figure 30: Negative Sequence Directional Characteristic

5.3.2 DIRECTIONAL NEGATIVE SEQUENCE OVERCURRENT LOGIC

Directionality is achieved by comparing the angle between the negative phase sequence voltage and the negative
phase sequence current. The element may be selected to operate in either the forward or reverse direction. A
suitable characteristic angle setting (I2>1 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.
For the negative phase sequence directional elements to operate, the device must detect a polarising voltage
above a minimum threshold, I2>1 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.
The P40 Agile Enhanced relay equipped with the Negative Sequence Directional Overcurrent protection element
provides both forward and reverse fault direction indications through its output operands Neg Seq Dir OC FWD
and Neg Seq Dir OC REV, respectively. The output operand is asserted if the magnitude of the operating current is
above a Pickup level (overcurrent unit) and the fault direction is seen as forward or reverse, respectively (directional
unit).

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I2 I2>1 TOC Start

I2>1 Current Set &
&
IDMT/DT I2>1 TOC Trip
CTS Block

I2>1 Inhibit Timer Settings

Note: This diagram does not show all stages. Other

I2>1 Direction stages follow similar principles.
V2

I2>1 V2pol Set

Directional
check

I2>1 Inhibit

I2>1 Char Angle

V06007
Figure 31: Negative Sequence Overcurrent logic - directional operation

5.4 APPLICATION NOTES

5.4.1 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.

5.4.2 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.

5.4.3 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

P14DEnh-TM-EN-1.1 101
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suitable relay characteristic angle setting (I2>1 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>1 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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6 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.

6.1 EARTH FAULT PROTECTION ELEMENTS

Earth fault Time Overcurrent protection is implemented under the SETPOINTS\PROTECTION\GROUP [1-4]\Current
Prot\(EF1 TOC, EF2 TOC).
Earth fault Instantaneous protection is implemented under the SETPOINTS\PROTECTION\GROUP [1-4]\Current Prot\
(EF1 IOC, EF2 IOC).
EARTH FAULT 1 (EF1) is used for earth fault current that is measured directly from the system (measured). EARTH
FAULT 2 (EF2) uses quantities derived internally from summing the three-phase currents.
The P14D provides Earth Fault protection with independent time delay characteristics.
Each stage provides a choice of operate and reset characteristics, where you can select between:
● A range of IDMT (Inverse Definite Minimum Time) curves
● A range of User-defined curves
● DT (Definite Time)

For the EF1 element, this is achieved using the settings:

● IN1>(n) Curve for the overcurrent operate characteristics
● IN1>(n) Reset Char for the overcurrent reset characteristic
For the EF2 element, this is achieved using the settings:
● IN2>(n) Curve for the overcurrent operate characteristics
● IN2>(n) Reset Char for the overcurrent reset characteristic
where (n) is the number of the stage.
The fact that both EF1 and EF2 elements may be enabled at the same time leads to a number of applications
advantages. For example, some applications may require directional earth fault protection for upstream
equipment and backup earth fault protection for downstream equipment. This can be achieved with a single IED,
rather than two.

P14DEnh-TM-EN-1.1 103
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6.2 NON-DIRECTIONAL EARTH FAULT LOGIC

IN2 IN2>1 TOC Start
IN2>1 Current &
IDMT IN2>1 TOC Trip

Timer Settings

IN2>1 Inhibit Note: This diagram shows the logic for IN 2 (derived earth fault). The logic
for IN1 (measured earth fault) follows the same principles, but with no CTS
blocking.
from PSL This diagram does not show all stages. Other stages follow similar
CTS Block principles.
AR blocking is only available for stages IN1/IN2 IOC .
Not applicable for I N1 For IN1 IOC, we have the following DDBs IN1>1 IOC Start and IN1>1 IOC
1
AR Blk Main Prot Trip

AR blocking available for IN1/IN2 IOC only

V06008

Note:
*1 If a CLP condition exists, the I>(n) Current Set threshold is taken from the COLD LOAD PICKUP settings
*2The CTS blocking is not applicable for IN1, however this can be achieved using the PSL

Figure 32: Non-directional EF logic (single stage)

The Earth Fault current is compared with a set threshold (IN1>(n) Current) for each stage. If it exceeds this
threshold, a Start signal is triggered, providing it is not blocked. This can be blocked by an Inhibit setting.
The autoreclose logic can be set to block the Earth Fault start and trip after a prescribed number of shots (set in
the AUTORECLOSE settings). This is achieved using the AR Blk Main Prot signal.
Earth Fault protection can follow the same IDMT characteristics as described in the Overcurrent Protection
Principles section. Please refer to that section for details of IDMT characteristics.
The diagram and description also applies to the Earth Fault 2 element (IN2).

6.3 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 earth fault protection, three options are available for polarisation; Residual voltage (zero sequence), polarising
current or both.
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.
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

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provided in the MEASUREMENTS may assist in determining the required threshold setting during the
commissioning stage, as this will indicate the level of standing residual voltage present.

DIRECTIONAL UNIT
OVERCURRENT UNIT
POLARIZING MODE DIRECTION COMPARED PHASORS
Forward –V_0 I_0 × 1∠ECA
Voltage
Reverse –V_0 –I_0 × 1∠ECA
Forward Ig I_0
Current
Reverse Ig –I_0 Iop = 3 × (|I_0| – K × |I_1|)
if |I_1| > 0.8 x CT
–V_0 I_0 × 1∠ECA
Forward or Iop = 3 × (|I_0|)
Ig I_0 if |I_1| ≤ 0.8 x CT
Dual
–V_0 –I_0 × 1∠ECA
Reverse or
Ig –I_0

V06034

Figure 33: Directional voltage-polarized characteristics

Some of the models derive the Residual Voltage quantity internally, from the 3-phase voltage input supplied from
either a 5-limb or three single-phase VTs.On models with 4th VT input, this feature can be used for Check Sync or
to measure the Residual Voltage VN. The 4th VT input can be configured for measured or derived voltage.

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Chapter 6 - Current Protection Functions P14D

6.3.1 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.
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 under MEASUREMENTS 1 in 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
(Ð VN + 180°) + RCA - 90° + (180° - tripping angle)/2 < Ð IN < (Ð VN +180°) + RCA +90° - (180° -
tripping angle)/2

Directional reverse
(Ð VN + 180°) + RCA - 90° - (180° - tripping angle)/2 > Ð IN > (Ð VN +180°) + RCA +90° + (180° -
tripping angle)/2
This can be best visualised with reference to the following diagram:

IN

VN VN

V00748

Figure 34: Directional angles

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P14D Chapter 6 - Current Protection Functions

Some of the models derive the Residual Voltage quantity internally, from the 3-phase voltage input supplied from
either a 5-limb or three single-phase VTs.On models with 4th VT input, this feature can be used for Check Sync or
to measure the Residual Voltage VN. The 4th VT input can be configured for measured or derived voltage.

6.3.1.1 DIRECTIONAL EARTH FAULT LOGIC WITH RESIDUAL VOLTAGE POLARISATION

IN1> DIRECTIONAL

VN

IN1> VNpo l S et

IN1

Lo w Curren t Th re shold Directional

To EF logic
check
IN1>1 Ch ar A ngle

IN1>1 Trip Ang le

VTS Slow Block Note: This diagram shows the log ic fo r IN1 (measure d earth fault). The logic for
IN1> Blo cking IN2 (derived earth f ault) follo ws simila r p rinciples.
& This diagram does no t show all st ages. Ot her stages f ollow simila r p rinciples.
VTS Blocks IN>1

V00744

Figure 35: Directional EF logic with neutral voltage polarization (single stage)

Voltage Transformer Supervision (VTS) selectively blocks the directional protection or causes it to revert to non-
directional operation. When selected to block the directional protection, VTS blocking is applied to the directional
checking which effectively blocks the Start outputs as well.

6.4 APPLICATION NOTES

6.4.1 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. Set this under I> Char Angle in the
relevant earth fault menu.
We recommend the following RCA settings:
● Resistance earthed systems: 0°
● Distribution systems (solidly earthed): -45°
● Transmission systems (solidly earthed): -60°

6.4.2 PETERSEN 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

P14DEnh-TM-EN-1.1 107
Chapter 6 - Current Protection Functions P14D

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 36: 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.

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 C jX C -I B
jX L
V AN
(=I L)  0 if  I B  IC (=-I B) (=-I C)
If jX L
VAC VAB

Petersen -jXC -jXC -jXC N

jXL
Coil C B

Current vectors for A phase fault

V00631

Figure 37: 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:

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P14D Chapter 6 - Current Protection Functions

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 38: Distribution of currents during a Phase C fault

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 39: 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°

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Chapter 6 - Current Protection Functions P14D

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 40: Zero sequence network showing residual currents

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

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P14D Chapter 6 - Current Protection Functions

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 41: 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.

6.4.3 SETTING GUIDELINES (COMPENSATED NETWORKS)

The directional setting should be such that the forward direction is looking down into the protected feeder (away
from the busbar), with a 0° RCA setting.
For a fully compensated system, the residual current detected by the relay on the faulted feeder is equal to the coil
current minus 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 steady state per phase value. Therefore, for a fully compensated system, the detected unbalanced
current is equal to three times the per phase charging current of the faulted circuit. 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 faulted circuit. In practise,
the exact settings may well be determined on site, where system faults can be applied and suitable settings can
be adopted based on practically obtained results.

P14DEnh-TM-EN-1.1 111
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In most situations, the system will not be fully compensated and consequently a small level of steady state fault
current will be allowed to flow. The residual current seen by the protection on the faulted feeder may therefore be
a larger value, which further emphasises the fact that the protection settings should be based upon practical
current levels, wherever possible.
The above also holds true for the RCA setting. As has been shown, a nominal RCA setting of 0º is required.
However, fine-tuning of this setting on-site may be necessary in order to obtain the optimum setting in accordance
with the levels of coil and feeder resistances present. The loading and performance of the CT will also have an
effect in this regard. The effect of CT magnetising current will be to create phase lead of current. Whilst this would
assist with operation of faulted feeder IEDs, it would reduce the stability margin of healthy feeder IEDs. A
compromise can therefore be reached through fine adjustment of the RCA. This is adjustable in 1° steps.

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7 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.

7.1 SEF PROTECTION IMPLEMENTATION

SEF Time Overcurrent Protection is configured under the path SETPOINTS\PROTECTION\GROUP [1-4]\CURRENT
PROT. \SEF TOC
SEF Instantaneous Overcurrent Protection is configured under the path SETPOINTS\PROTECTION\GROUP
[1-4]\CURRENT PROT. \SEF IOC
The product provides SEF TOC protection with independent time delay characteristics, where you can select
between:
● A range of IDMT (Inverse Definite Minimum Time) curves
● A range of User-defined curves
● DT (Definite Time)

This is achieved using the setpoints

● ISEF>(n) Curve for the overcurrent operate characteristic
● ISEF>(n) Reset Chr for the overcurrent reset characteristic
where (n) is the number of the stage.

7.2 NON-DIRECTIONAL SEF LOGIC

ISEF ISEF>1 TOC Start
ISEF>1 Current &
IDMT/DT ISEF>1 TOC Trip
ISEF>1 Direction
Non-directional
Timer Settings
ISEF>1 Inhibit
AR Blk SEF Prot

Note: This diagram does not show all stages. Other stages follow similar
principles.

The SEF IOC element has the following DDB signals: ISEF>1 IOC Start
and ISEF>1 IOC Trip
V06020

Figure 42: Non-directional SEF logic

The SEF current is compared with a set threshold (ISEF>(n) Current) for each stage. If it exceeds this threshold, a
Start signal is triggered, providing it is not blocked. This can be blocked by an Inhibit SEF DDB signal.
The autoreclose logic can be set to block the SEF trip after a prescribed number of shots (set in the AUTORECLOSE
settings). This is achieved using AR Blk SEF Prot through PSL.
SEF protection can follow the same IDMT characteristics as described in the Overcurrent Protection Principles
section. Please refer to this section for details of IDMT characteristics.

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7.3 DIRECTIONAL ELEMENT

Where current may flow in either direction, directional control should be used.
A directional element is available for all of the SEF overcurrent stages. This is found in the ISEF>(n) Direction cell for
the relevant stage. It can be set to non-directional, directional forward, or directional reverse.
Directionality is achieved by using different techniques depending on the application. With reference to the figure
below, you can see that directional SEF can be used for:
● Solidly earthed systems
● Unearthed systems (insulated systems)
● Compensated systems
● Resistance earthed systems

The following diagram shows which type of directional control can be used for which systems.

Unearthed Systems Compensated Systems

Solidly Earthed Systems Resistance-Earthed Systems
(insulated systems) (Petersen coil)

Directional SEF TEFD TEFD Directional SEF

Core-balanced Transient Transient INcos(j)

CT reactive power reactive power characteristic

Directional Transient active Transient active Core-balanced

Earth Fault power power CT

High Impedance Fault Directional SEF Directional

Directional SEF
(HIF) Earth Fault

INsin(j) INcos(j) High Impedance Fault

characteristic characteristic (HIF)

Wattmetric Wattmetric
VN x IN sin( j) VN x IN cos( j)
(reactive power) (active power)

Core-balanced
V00773 CT

Figure 43: Types of directional control

The device supports standard core-balanced directional control.

7.3.1 DIRECTIONAL SEF LOGIC

The P40 Agile Enhanced relay equipped with the Sensitive Earth Fault Directional Overcurrent protection element
provides both forward and reverse fault direction indications: the SEF Dir OC FWD and SEF Dir OC REV operands,
respectively. The output operands are asserted if the magnitude of the operating current is above a Pickup level
(overcurrent unit) and the fault direction is seen as forward or reverse, respectively (directional unit).
The overcurrent unit responds to the magnitude of a fundamental frequency phasor of the sensitive ground
current. There are separate Pickup settings for the forward-looking and reverse-looking functions.

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The directional unit uses the sensitive ground current (Isg) for fault direction discrimination and may be
programmed to use zero-sequence voltage (“Calculated V0” or “Measured VX”), for polarizing. The following tables
define the sensitive ground directional overcurrent element.
DIRECTIONAL UNIT OVERCURRENT UNIT
POLARIZING MODE DIRECTION COMPARED PHASORS
Forward V_0 Isg SENSITIVE GROUND CURRENT
Voltage (Isg)
Reverse –V_0 –lsg
Where: V_0 = 1/3 * (Vag + Vbg + Vcg) = zero sequence voltage
When POLARIZING VOLTAGE is set to “Measured VX”, one-third of this voltage is used in place of V_0. The following
figure explains the usage of the voltage polarized directional unit of the element.
The figure below shows the voltage-polarized phase angle comparator characteristics for a phase A to ground
fault, with:
● ECA = 90° (element characteristic angle = centerline of operating characteristic)
● FWD LA = 80° (forward limit angle = the ± angular limit with the ECA for operation)
● REV LA = 80° (reverse limit angle = the ± angular limit with the ECA for operation)

The element incorporates a current reversal logic: if the reverse direction is indicated for at least 1.25 of a power
system cycle, the prospective forward indication will be delayed by 1.5 of a power system cycle. The element is
designed to emulate an electromechanical directional device. Larger operating and polarizing signals will result in
faster directional discrimination bringing more security to the element operation.
The forward-looking function is designed to be more secure as compared to the reverse-looking function, and
therefore, should be used for the tripping direction. The reverse-looking function is designed to be faster as
compared to the forward-looking function and should be used for the blocking direction. This allows for better
protection coordination.
The above bias should be taken into account when using the sensitive ground directional overcurrent element to
directionalize other protection elements.

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E06035

Figure 44: Sensitive ground directional voltage-polarized characteristics

IS>1 Function

VN
Directional
check
To SEF element
IS>1 VNpol Set

IS>1 Inhibit
Off=0

ISEF>1 CharAngle

V06023

Figure 45: Directional SEF with VN polarisation (single stage)

116 P14DEnh-TM-EN-1.1
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7.4 APPLICATION NOTES

7.4.1 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 46: 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°.

P14DEnh-TM-EN-1.1 117
Chapter 6 - Current Protection Functions P14D

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 47: 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.

7.4.2 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:

118 P14DEnh-TM-EN-1.1
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Cable gland

Cable box

Cable gland/shealth
earth connection

“Incorrect”

No operation
SEF

“Correct”

Operation
SEF

E00614

Figure 48: 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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8 COLD LOAD PICKUP

When a feeder circuit breaker is closed in order to energise a load, the current levels that flow for a period of time
following energisation may be far greater than the normal load levels. Consequently, overcurrent settings that
have been applied to provide overcurrent protection may not be suitable during this period of energisation (cold
load), as they may initiate undesired tripping of the circuit breaker. This scenario can be prevented with Cold Load
Pickup (CLP) functionality.
The Cold Load Pick-Up (CLP) logic works by either:
● Blocking one or more stages of the overcurrent protection for a set duration
● Raising the overcurrent settings of selected stages, for the cold loading period.

The CLP logic therefore provides stability, whilst maintaining protection during the start-up.

8.1 IMPLEMENTATION
Cold Load Pickup Protection is configured under the path SETPOINTS\CONTROL\CLP [X].
This function acts upon the following protection functions:
● All overcurrent stages (both non-directional and directional if applicable)
● All Earth Fault 1 stages (both non-directional and directional if applicable)
● All Earth Fault 2 stages (both non-directional and directional if applicable)

● All negative sequence overcurrent stages

CLP operation occurs when the circuit breaker remains open for a time greater than tcold Time Delay and is
subsequently closed. CLP operation is applied after tcold Time Delay and remains for a set time delay of tclp Time
Delay following closure of the circuit breaker. Whilst CLP operation is in force, the CLP settings are enabled. After
the time delay tclp Time Delay has elapsed, the normal overcurrent settings are applied and the CLP settings are
disabled.
If desired, instead of applying different current setting thresholds for the cold load time, it is also possible to
completely block the overcurrrent operation during this time, for any of the overcurrent stages.
Voltage-dependent operation can also affect the overcurrent settings. If a Voltage Dependent condition arises, this
takes precedence over the CLP function. If the CLP condition prevails and the Voltage Dependent function resets,
the device will operate using the CLP settings. Time-delayed elements are reset to zero if they are disabled during
the transitions between normal settings and CLP settings.

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8.2 CLP LOGIC

IA < 0.05 x CT
tcold
IB < 0.05 x CT & & S
IC < 0.05 x CT Q CLP Operation
R
tcold Time Delay

tclp
&

tclp Time Delay

Cold Load Pickup

1
Enabled

Current threshold setting Applied Current

in CLP Threshold

Timer settings in CLP Applied Timer Settings

V06024

Figure 49: Cold Load Pickup logic

The CLP Operation signal indicates that CLP logic is in operation. This only happens when CLP is enabled AND CLP
is initiated from an undercurrent function after the tcold Time Delay period has elapsed. The CLP Operation
indicator goes low when CLP is disabled or when there is a CB closed condition.
tcold Time Delay and tclp Time Delay are initiated via the undercurrent signals generated within the device.

8.3 APPLICATION NOTES

8.3.1 CLP FOR RESISTIVE LOADS

A typical example of where CLP logic may be used is for resistive heating loads such as such as air conditioning
systems. Resistive loads typically offer less resistance when cold than when warm, hence the start-up current will
be higher.
The settings should be chosen in accordance with the expected load profile. Where it is not necessary to alter the
setting of a particular stage, the CLP settings should be set to zero, so that the same overcurrent setting applies
during CLP condition.
It may not be necessary to alter the protection settings following a short supply interruption. In this case a suitable
tcold timer setting can be used.

8.3.2 CLP FOR MOTOR FEEDERS

In general, a dedicated motor protection device would protect feeders supplying motor loads. However, if CLP logic
is available in a feeder device, this may be used to modify the overcurrent settings during start-up.
Depending on the magnitude and duration of the motor starting current, it may be sufficient to simply block
operation of instantaneous elements. If the start duration is long, the time-delayed protection settings may also
need to be raised. A combination of both blocking and raising of the overcurrent settings may be adopted. The CLP
overcurrent settings in this case must be chosen with regard to the motor starting characteristic.
This may be useful where instantaneous earth fault protection needs to be applied to the motor. During motor
start-up conditions, it is likely that incorrect operation of the earth fault element would occur due to asymmetric
CT saturation. This is due to the high level of starting current causing saturation of one or more of the line CTs
feeding the overcurrent/earth fault protection. The resultant transient imbalance in the secondary line current
quantities is therefore detected by the residually connected earth fault element. For this reason, it is normal to
either apply a nominal time delay to the element, or to use a series stabilising resistor.

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The CLP logic may be used to allow reduced operating times or current settings to be applied to the earth fault
element under normal running conditions. These settings could then be raised prior to motor starting, by means of
the logic.

8.3.3 CLP FOR SWITCH ONTO FAULT CONDITIONS

In some feeder applications, fast tripping may be required if a fault is already present on the feeder when it is
energised. Such faults may be due to a fault condition not having been removed from the feeder, or due to
earthing clamps having been left on following maintenance. In either case, it is desirable to clear the fault
condition quickly, rather than waiting for the time delay imposed by IDMT overcurrent protection.
The CLP logic can cater for this situation. Selected overcurrent/earth fault stages could be set to instantaneous
operation for a defined period following circuit breaker closure (typically 200 ms). Therefore, instantaneous fault
clearance would be achieved for a switch onto fault (SOTF) condition.

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9 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.

9.1 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:

where:
●

= time to trip, from thermal capacity from

to

following application of the overload current

●

= initial thermal capacity

●

= final thermal capacity, Thermal trip set to 100%

●

= heating and cooling time constant of the protected plant

●

= ratio of actual phase current and the pickup setting

● K
= overload factor, a constant, settable between 1 and 1.5

9.2 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 time 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.

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Chapter 6 - Current Protection Functions P14D

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:

where:
● t1 = heating and cooling time constant of the transformer windings
● t2 = heating and cooling time constant of the insulating oil

9.3 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 under the SETPOINTS\PROTECTION\GROUP [1-4]\CURRENT PROT.
\Thermal Overload\THERMAL O/L [X]
This contains the settings for the characteristic type, the alarm and trip thresholds and the time constants.

9.4 THERMAL OVERLOAD PROTECTION LOGIC

IA

Thermal State
IC

Thermal Trip
Thermal 1 Trip
Characteristic Thermal trip
Single
Thermal threshold
Dual Calculation

Heat Const TH1

Heat Const TH2

Cool Const TC1

Cool Const TC2

Thermal 1 Alm
Thermal Alarm

V06025

Figure 50: Thermal overload protection logic diagram

Three phase input currents are 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 can be reset under the clear records menu.

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9.5 APPLICATION NOTES

9.5.1 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 /
τ 1)
+ 0.6e( − t /τ 2) − 1

Figures based
on equation

E00728

Figure 51: Spreadsheet calculation for dual time constant thermal characteristic

P14DEnh-TM-EN-1.1 125
Chapter 6 - Current Protection Functions P14D

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 52: 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.

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.

9.5.2 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 

126 P14DEnh-TM-EN-1.1
P14D Chapter 6 - Current Protection Functions

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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Chapter 6 - Current Protection Functions P14D

10 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.

10.1 BROKEN CONDUCTOR PROTECTION IMPLEMENTATION

Broken Conductor protection is implemented under the SETPOINTS\PROTECTION\GROUP [1-4]\CURRENT PROT.
\BROKENCONDUCTOR1.
The BROKEN CONDUCTOR feature contains the settings to enable the function, for the pickup threshold and the
time delay.

10.2 BROKEN CONDUCTOR PROTECTION LOGIC

The ratio of I2/I1 is calculated and compared with the threshold setting. If the threshold is exceeded, current is
within a nominal range and phase current changes, the delay timer is initiated. The CTS block signal is used to
block the operation of the delay timer.

Bkn Line 1 Start

I2/I1
DT
I2/I1 Setting & Bkn Line1 Trip

I1

I1 Min

I1

I1 Max

I2/I1 Inhibit
CTS Block

V06027

Figure 53: Broken conductor logic

10.3 APPLICATION NOTES

10.3.1 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%.

128 P14DEnh-TM-EN-1.1
P14D Chapter 6 - Current Protection Functions

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.

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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Chapter 6 - Current Protection Functions P14D

11 BLOCKED OVERCURRENT PROTECTION

With Blocked Overcurrent schemes, you connect the start contacts from downstream IEDs to the timer blocking
inputs of upstream IEDs. This allows identical current and time settings to be used on each of the IEDs in the
scheme, as the device nearest to the fault does not receive a blocking signal and so trips discriminatively. This type
of scheme therefore reduces the number of required grading stages, and consequently fault clearance times.
The principle of Blocked Overcurrent protection may be extended by setting fast-acting overcurrent elements on
the incoming feeders to a substation, which are then arranged to be blocked by start contacts from the devices
protecting the outgoing feeders. The fast-acting element is thus allowed to trip for a fault condition on the busbar,
but is stable for external feeder faults due to the blocking signal.
This type of scheme provides much reduced fault clearance times for busbar faults than would be the case with
conventional time-graded overcurrent protection. The availability of multiple overcurrent and earth fault stages in
the General Electric IEDs allows additional time-graded overcurrent protection for back-up purposes.

11.1 BLOCKED OVERCURRENT IMPLEMENTATION

Blocked Overcurrent schemes are implemented using the PSL. The start outputs, available from each stage of the
overcurrent and earth fault elements (including the sensitive earth fault element) can be mapped to output relay
contacts. These outputs can then be connected to the relevant timer block inputs of the upstream IEDs via opto-
inputs.

11.2 APPLICATION NOTES

11.2.1 BUSBAR BLOCKING SCHEME

Incomer

IED Block highset element

CB fail backtrip

IED IED IED IED

O/P CB
from fail
start backtrip
contact

Feeder 1 Feeder 2 Feeder 3 Feeder 4

E00636

Figure 54: Simple busbar blocking scheme

130 P14DEnh-TM-EN-1.1
P14D Chapter 6 - Current Protection Functions

10.0

1.0
Time Incomer IDMT element
(secs) IDMT margin
Feeder IDMT element
0.1 Incomer high set element
0.08
Time to block
Feeder start contact
0.01
1.0 10.0 100.0
Current (kA)
E00637

Figure 55: Simple busbar blocking scheme characteristics

For further guidance on the use of blocked busbar schemes, refer to General Electric.

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Chapter 6 - Current Protection Functions P14D

12 SOTF PROTECTION
Switch on to fault protection (SOTF) is provided for high speed clearance of any detected fault immediately
following manual closure or closure after a long open time of the circuit breaker. Without SOTF, there is a risk that if
the breaker is closed onto close-in three-phase fault, the measured voltages may be too small for the impedance
zones or the directional overcurrent stages to operate reliably.

12.1 SOTF IMPLEMENTATIONN

SOTF Protection is configured under the path SETPOINTS\PROTECTION\GROUP [1-4]\CURRENT PROT\SOFT\SOTF[X].

12.2 SOTF LOGIC

Ia, Ib, Ic
SOTF 1 Alarm
Dead Line Vmax
DT
&
1 1 DT
Va, Vb, Vc
DT & SOTF 1 Trip

Dead Line Vmin Line Dead Window

T Delay Time Delay

BRK1 Open

Manual breaker closing command

Inhibit

Ext SOTF Trigger Voltage information -Directional models

Ia, Ib, Ic

V06027
Current Set
& 1
Va, Vb, Vc
V06031
Voltage Max

Figure 56: SOTF Logic diagram

132 P14DEnh-TM-EN-1.1
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13 UNDERCURRENT PROTECTION
The relay provides three Undercurrent element per protection group. The element responds to a per-phase
current. An alarm will occur if the magnitude of any phase current falls below the undercurrent alarm pickup level
for the time specified by the undercurrent alarm delay. Furthermore, a trip will occur if the magnitude of any phase
current falls below the undercurrent trip pickup level for the time specified by the undercurrent trip delay. The
alarm and trip pickup levels should be set lower than the lowest feeder loading during normal operations.
Undercurrent requires breaker ‘close’ status to active the element. In addition, the Undercurrent element can be
blocked upon the closing of the feeder breaker for a period of time defined by the setting Start Block Delay. This
block may be used in applications when load requires time to build up to a certain operating level before the
undercurrent element trips or alarms.

13.1 UNDERCURRENT IMPLEMENTATION

Undercurrent Protection is configured under the path SETPOINTS\PROTECTION\GROUP [1-4]\CURRENT PROT
\UNDERCURRENT\UNDERCURRENT [X].

13.2 UNDERCURRENT LOGIC

I<1 Alarm Delay
I<1 Alarm PKP
Ia

I<1 Alm Current tpkp

1 I<1 Alarm OP
&
Ib tRST

I<1 Alm Current

Ic

I<1 Alm Current

I<1 Alarm tRESET

I<1 A lm Inhibit
This diagram does not show all stages. Other stages follow similar principles.
DT Trip function follow similar principles
BKR1 Closed

V06032
I<1 Strt Blk Dly

Figure 57: Undercurrent Logic diagram

P14DEnh-TM-EN-1.1 133
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134 P14DEnh-TM-EN-1.1
 CHAPTER 7

RESTRICTED EARTH FAULT PROTECTION

Chapter 7 - Restricted Earth Fault Protection P14D

136 P14DEnh-TM-EN-1.1
P14D Chapter 7 - Restricted Earth Fault Protection

1 CHAPTER OVERVIEW
The device provides extensive Restricted Earth Fault functionality. This chapter describes the operation of this
function including the principles of operation, logic diagrams and applications.
This chapter contains the following sections:
Chapter Overview 137
REF Protection Principles 138
Restricted Earth Fault Protection Implementation 144
Application Notes 147

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Chapter 7 - Restricted Earth Fault Protection P14D

2 REF PROTECTION PRINCIPLES

Winding-to-core faults in a transformer can be caused by insulation breakdown. Such faults can have very low
fault currents, but they still need to be picked up. If such faults are not identified, this could result in extreme
damage to very expensive equipment.
Often the associated fault currents are lower than the nominal load current. Neither overcurrent nor percentage
differential protection is sufficiently sensitive in this case. We therefore require a different type of protection
arrangement. Not only should the protection arrangement be sensitive, but it must create a protection zone, which
is limited to each transformer winding. Restricted Earth Fault protection (REF) is the protection mechanism used to
protect individual transformer winding sets.
The following figure shows a REF protection arrangement for protecting the delta side of a delta-star transformer.

Load

REF
IED protection zone

V00620

Figure 58: REF protection for delta side

The current transformers measuring the currents in each phase are connected in parallel. The currents from all
three phases are summed to form a differential current, sometimes known as a spill current. Under normal
operating conditions the currents of the three phases add up to zero resulting in zero spill current. A fault on the
star side will also not result in a spill current, as the fault current would simply circulate in the delta windings.
However, if any of the three delta windings were to develop a fault, the impedance of the faulty winding would
change and that would result in a mismatch between the phase currents, resulting in a spill current. If the spill
current is large enough, it will trigger a trip command.
The following figure shows a REF protection arrangement for the star side of a delta-star transformer.

REF
protection zone

Load

IED

V00621

Figure 59: REF protection for star side

Here we have a similar arrangement of current transformers connected in parallel. The difference is that we need
to measure the zero sequence current in the neutral line as well. An external unbalanced fault causes zero
sequence current to flow through the neutral line, resulting in uneven currents in the phases, which could cause

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the protection to maloperate. By measuring this zero sequence current and placing it in parallel with the other
three, the currents are balanced, resulting in stable operation. Now only a fault inside the star winding can create
an imbalance sufficient to cause a trip.

2.1 RESISTANCE-EARTHED STAR WINDINGS

Most distribution systems use resistance-earthed systems to limit the fault current. Consider the diagram below,
which depicts an earth fault on the star winding of a resistance-earthed Dyn transformer (Dyn = Delta-Star with
star-point neutral connection).

87
1.0

IF IF
Source
IS Current p.u.
(x full load)
Pickup
IS
0.2
IF
64
20% 100%
Winding not protected

Fault position from neutral

V00669 (Impedance earthing)

Figure 60: REF Protection for resistance-earthed systems

The value of fault current (IF) depends on two factors:

● The value of earthing resistance (which makes the fault path impedance negligible)
● The fault point voltage (which is governed by the fault location).
Because the fault current (IF) is governed by the resistance, its value is directly proportional to the location of the
fault.
A restricted earth fault element is connected to measure IF directly. This provides very sensitive earth fault
protection. The overall differential protection is less sensitive, since it only measures the HV current IS. The value of
IS is limited by the number of faulty secondary turns in relation to the HV turns.

2.2 SOLIDLY-EARTHED STAR WINDINGS

Most transmission systems use solidly-earthed systems. Consider the diagram below, which depicts an earth fault
on the star winding of a solidly-earthed Dyn transformer.

87
10

IF 8 IF
Source Current p.u.
IS (x full load) 6

2 IS
IF
64 20% 40% 60% 80% 100%

Fault position from neutral

V00670 (Solid earthing)

Figure 61: REF Protection for solidly earthed system

P14DEnh-TM-EN-1.1 139
Chapter 7 - Restricted Earth Fault Protection P14D

In this case, the fault current IF is dependent on:

● The leakage reactance of the winding
● The impedance in the fault path
● The fault point voltage (which is governed by the fault location)

In this case, the value of fault current (IF) varies with the fault location in a complex manner.
A restricted earth fault element is connected to measure IF directly. This provides very sensitive earth fault
protection.
For solidly earthed systems, the operating current for the transformer differential protection is still significant for
faults over most of the winding. For this reason, independent REF protection may not have been previously
considered, especially where an additional device would have been needed. But with this product, it can be
applied without extra cost.

2.3 THROUGH FAULT STABILITY

In an ideal world, the CTs either side of a differentially protected system would be identical with identical
characteristics to avoid creating a differential current. However, in reality CTs can never be identical, therefore a
certain amount of differential current is inevitable. As the through-fault current in the primary increases, the
discrepancies introduced by imperfectly matched CTs is magnified, causing the differential current to build up.
Eventually, the value of the differential current reaches the pickup current threshold, causing the protection
element to trip. In such cases, the differential scheme is said to have lost stability. To specify a differential scheme’s
ability to restrain from tripping on external faults, we define a parameter called ‘through-fault stability limit’, which
is the maximum through-fault current a system can handle without losing stability.

2.4 RESTRICTED EARTH FAULT TYPES

There are two different types of Restricted Earth Fault; Low Impedance REF (also known as Biased REF) and High
Impedance REF. Each method compensates for the effect of through-fault errors in a different manner.
With Low Impedance REF, the through-fault current is measured and this is used to alter the sensitivity of the REF
element accordingly by applying a bias characteristic. So the higher the through fault current, the higher the
differential current must be for the device to issue a trip signal, Often a transient bias component is added to
improve stability during external faults.
Low impedance protection used to be considered less secure than high impedance protection. This is no longer
true as numerical IEDs apply sophisticated algorithms to match the performance of high-impedance schemes.
Some advantages of using Low Impedance REF are listed below:
● There is no need for dedicated CTs. As a result CT cost is substantially reduced.
● The wiring is simpler as it does not require an external resistor or Metrosil.
● Common phase current inputs can be used.
● It provides internal CT ratio mismatch compensation. It can match CT ratios up to 1:40 resulting flexibility in
substation design and reduced cost.
● Advanced algorithms make the protection secure.
With High Impedance REF, there is no bias characteristic, and the trip threshold is set to a constant level. However,
the High Impedance differential technique ensures that the impedance of the circuit is sufficiently high such that
the differential voltage under external fault conditions is lower than the voltage needed to drive differential current
through the device. This ensures stability against external fault conditions so the device will operate only for faults
occurring inside the protected zone.
High Impedance REF protection responds to a voltage across the differential junction points. During external faults,
even with severe saturation of some of the CTs, the voltage does not rise above certain level, because the other

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CTs will provide a lower-impedance path compared with the device input impedance. The principle has been used
for more than half a century. Some advantages of using High Impedance REF are listed below:
● It provides a simple proven algorithm, which is fast, robust and secure.
● It is less sensitive to CT saturation.

2.4.1 LOW IMPEDANCE REF PRINCIPLE

Low 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 is as follows:

Phase A
Phase A
Phase B
Phase B
Phase C
Phase C

I Phase A
I Phase A

I Phase B
I Phase B

I Phase C
I Phase C

I Neutral

IED IED

Connecting IED to star winding for Low Connecting IED to delta winding for Low
Impedance REF Impedance REF
V00679

Figure 62: Low Impedance REF Connection

2.4.1.1 LOW IMPEDANCE BIAS CHARACTERISTIC

Usually, a triple slope biased characteristic is used as follows:

Differential current

Higher
slope

Operate region

Lower slope

Restraint region
Minimum operating current

Bias current
First knee point Second knee point
V00677

Figure 63: Three-slope REF bias characteristic

The flat area of the characteristic is the minimum differential current required to cause a trip (operate current) at
low bias currents. From the first kneepoint onwards, the operate current increases linearly with bias current, as
shown by the lower slope on the characteristic. This lower slope provides sensitivity for internal faults. From the

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second knee point onwards, the operate current further increases linearly with bias current, but at a higher rate.
The second slope provides stability under through fault conditions.

Note:
In Restricted Earth Fault applications, Bias Current Compensation is also known as Low Impedance REF.

2.4.2 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 64: 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 65: High Impedance REF Connection

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3 RESTRICTED EARTH FAULT PROTECTION IMPLEMENTATION

3.1 RESTRICTED EARTH FAULT PROTECTION SETTINGS

Restricted Earth Fault Protection is implemented in the Restricted E/F menu of the relevant settings group. It is here
that the constants and bias currents are set.
The REF protection may be configured to operate as either a high impedance or biased element.

3.2 LOW IMPEDANCE REF

3.2.1 SETTING THE BIAS CHARACTERISTIC

Low impedance REF uses a bias charactersitic for increasing sensitivity and stabilising for through faults. The
current required to trip the differential IED is called the Operate current. This Operate current is a function of the
differential current and the bias current according to the bias characteristic.
The differential current is defined as follows:

I diff = I A + I B + I C + K I N
( )
The bias current is as follows:

I bias =
1
2
{
max  I A , I B , I C  + K I N }
where:
● K = Neutral CT ratio / Line CT ratio
● IN = current measured by the neutral CT

The allowable range for K is:

0.05 < K < 15 for standard CTs
0.05 < K < 20 for sensitive CTs
The operate current is calculated according to the following characteristic:

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I DIFF

Operate K2

Restrain

I S1 K1

I S2 I BIAS

E04021

Figure 66: REF bias characteristic

The following settings are provided to define this bias characteristic:

● IREF> Is1: sets the minimum trip threshold
● IREF> Is2: sets the bias current kneepoint whereby the required trip current starts increasing
● IREF> k1: defines the first slope (often set to 0%)
● IREF> k2: defines the second slope

Note:
Is1 and Is2 are relative to the line CT, which is always the reference CT.

3.3 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.

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3.3.1 HIGH IMPEDANCE REF CALCULATION PRINCIPLES

The primary operating current (Iop) is a function of the current transformer ratio, the device operate current
(IREF>Is), the number of current transformers in parallel with a REF element (n) and the magnetizing current of
each current transformer (Ie) at the stability voltage (Vs). This relationship can be expressed in three ways:
1. The maximum current transformer magnetizing current to achieve a specific primary operating current with
a particular operating current:

1  I op 
Ie <  − [ IREF > Is ] 
n  CT ratio 
2. The maximum current setting to achieve a specific primary operating current with a given current
transformer magnetizing current:

 I op 
[ IREF > Is ] <  − nI e 
 CT ratio 
3. The protection primary operating current for a particular operating current with a particular level of
magnetizing current:

I op = ( CT ratio ) ([ IREF > Is ] + nI e )

To achieve the required primary operating current with the current transformers that are used, you must select a
current setting for the high impedance element, as shown in item 2 above. You can calculate the value of the
stabilising resistor (RST) in the following manner.

Vs I ( R + 2 RL )
Rst = = F CT
[ IREF > Is ] [ IREF > Is ]
where:
● RCT = the resistance of the CT winding
● RL = the resistance of the lead from the CT to the IED.

Note:
The above formula assumes negligible relay burden.

We recommend a stabilizing resistor, which is continuously adjustable up to its maximum declared resistance.

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4 APPLICATION NOTES

4.1 STAR WINDING RESISTANCE EARTHED

Consider the following resistance earthed star winding below.

Primary Secondary

A a

V2 V1
B b

c
C

V00681

Figure 67: Star winding, resistance earthed

An earth fault on such a winding causes a current which is dependent on the value of earthing impedance. This
earth fault current is proportional to the distance of the fault from the neutral point since the fault voltage is
directly proportional to this distance.
The ratio of transformation between the primary winding and the short circuited turns also varies with the position
of the fault. Therefore the current that flows through the transformer terminals is proportional to the square of the
fraction of the winding which is short circuited.
The earthing resistor is rated to pass the full load current IFLC = V1/Ö3R
Assuming that V1 = V2 then T2 = Ö3T1
For a fault at x PU distance from the neutral, the fault current If = xV1/Ö3R

Therefore the secondary fault current referred to the primary is Iprimary = x2.IFLC/Ö3
If the fault is a single end fed fault, the primary current should be greater than 0.2 pu (Is1 default setting) for the
differential protection to operate. Therefore x2/Ö3 > 20%
The following diagram shows that 41% of the winding is protected by the differential element.

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Chapter 7 - Restricted Earth Fault Protection P14D

X in % Idiff in %
10 0.58
20 2.31
30 5.20
59% of unprotected winding
40 9.24
50 14.43
60 20.00
70 28.29
80 36.95 41% of protected winding
90 46.77
100 57.74

V00682

Figure 68: Percentage of winding protected

4.2 LOW IMPEDANCE REF PROTECTION APPLICATION

4.2.1 SETTING GUIDELINES FOR BIASED OPERATION

Two bias settings are provided in the REF characteristic. The K1 level of bias is applied up to through currents of
Is2, which is normally set to the rated current of the transformer. K1 is normally be set to 0% to give optimum
sensitivity for internal faults. However, if any CT mismatch is present under normal conditions, then K1 may be
increased accordingly, to compensate. We recommend a setting of 20% in this case.
K2 bias is applied for through currents above Is2 and would typically be set to 150%.
According to ESI 48-3 1977, typical settings for the Is1 thresholds are 10-60% of the winding rated current when
solidly earthed and 10-25% of the minimum earth fault current for a fault at the transformer terminals when
resistance earthed.

4.2.2 LOW IMPEDANCE REF SCALING FACTOR

The three line CTs are connected to the three-phase CTs, and the neutral CT is connected to the neutral CT input.
These currents are then used internally to derive both a bias and a differential current quantity for use by the low
impedance REF protection. The advantage of this mode of connection is that the line and neutral CTs are not
differentially connected, so the neutral CT can also be used to provide the measurement for the Standby Earth
Fault Protection. Also, no external components such as stabilizing resistors or Metrosils are required.

Line CTs 1000:1

Phase A

Phase B

Phase C

I Phase A

I Phase B

I Phase C
Neutral CT 200:1
I Neutral

IN IED

V00683

Figure 69: Low Impedance REF Scaling Factor

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Another advantage of Low Impedance REF protection is that you can use a neutral CT with a lower ratio than the
line CTs in order to provide better earth fault sensitivity. In the bias calculation, the device applies a scaling factor
to the neutral current. This scaling factor is as follows:
Scaling factor = K = Neutral CT ratio / Line CT ratio
This results in the following differential and bias current equations:

I diff = I A + I B + I C + K I N
( )
I bias =
1
2
{
max  I A , I B , I C  + K I N }
4.2.3 PARAMETER CALCULATIONS
Consider a solidly earthed 90 MVA 132 kV transformer with a REF-protected star winding. Assume line CTS with a
ratio of 400:1.
Is1 is set to 10% of the winding nominal current:

= (0.1 x 90 x 106) / (Ö3 x 132 x 103)

= 39 Amps primary
= 39/400 = 0.0975 Amps secondary (approx 0.1 A)
Is2 is set to the rated current of the transformer:

= 90 x 106 / (Ö3 x 132 x 103)

= 390 Amps primary
= 390/400 = 0.975 Amps secondary (approx 1 A)
Set K1 to 0% and K2 to 150%

4.3 HIGH IMPEDANCE REF PROTECTION APPLICATION

4.3.1 HIGH IMPEDANCE REF OPERATING MODES

In the examples below, the respective Line CTS and measurement CTs must have the same CT ratios and similar
magnetising characteristics.

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Chapter 7 - Restricted Earth Fault Protection P14D

CT1
A a

B b

c
C

TN1 CT
TN2 CT
TN3 CT

CTN Rst
Varistor

V00684

Figure 70: Hi-Z REF protection for a grounded star winding

CT1
A
a

B
b

C c

TN 1 CT
TN 2 CT
Varistor TN 3 CT
Rst

V00685

Figure 71: Hi-Z REF protection for a delta winding

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P14D Chapter 7 - Restricted Earth Fault Protection

CT2
a

CT1
A
b
CTN
B
c

TN1 CT
Varistor
Rst

V00686

Figure 72: Hi-Z REF Protection for autotransformer configuration

4.3.2 SETTING GUIDELINES FOR HIGH IMPEDANCE OPERATION

This scheme is very sensitive and can protect against low levels of fault current in resistance grounded systems. In
this application, the IREF>Is settings should be chosen to provide a primary operating current less than 10-25% of
the minimum earth fault level.
This scheme can also be used in a solidly grounded system. In this application, the IREF>Is settings should be
chosen to provide a primary operating current between 10% and 60 % of the winding rated current.
The following diagram shows the application of a high impedance REF element to protect the LV winding of a
power transformer.

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Chapter 7 - Restricted Earth Fault Protection P14D

A 400:1
a
RCT

B b

RL
c
C

RL

RL

Transformer: High Z
RCT
90 MVA REF
33/132 kV
Dyn11, X = 5% RL
Buderns:
RCT = 0.5 W
RL = 0.98 W

V00687

Figure 73: High Impedance REF for the LV winding

4.3.2.1 STABILITY VOLTAGE CALCULATION

The transformer full load current, IFLC, is:

IFLC = (90 x 106) / (132 x 103 x Ö3) = 394 A

To calculate the stability voltage the maximum through fault level should be considered. The maximum through
fault level, ignoring the source impedance, IF, is:

IF = IFLC / XTX = 394 / 0.05 = 7873 A

The required stability voltage, VS, and assuming one CT saturated is:
Vs = KIF(RCT + 2RL)
The following figure can be used to determine the K factor and the operating time. The K factor is valid when:
● 5 ≤ X/R ≤ 120
and
● 0.5In ≤ I f ≤ 40In
We recommend a value of VK/VS = 4.
With the transformer at full load current and percentage impedance voltage of 394A and 5% respectively, the
prospective fault current is 7873 A and the required stability voltage Vs (assuming that one CT is saturated) is:
Vs = 0.9 x 7873 x (0.5 + 2 x 0.98) / 400 = 45.5 V
The CTs knee point voltage should be at least 4 times Vs so that an average operating time of 40 ms is achieved.

4.3.2.2 PRIMARY CURRENT CALCULATION

The primary operating current should be between 10 and 60 % of the winding rated current. Assuming that the
relay effective setting or primary operating current is approximately 30% of the full load current, the calculation
below shows that a setting of less than 0.3 A is required.
Effective setting = 0.3IFLC / CT Ratio = 30.3 x 394 / 400 = approximately 0.3 A

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4.3.2.3 STABILISING RESISTOR CALCULATION

Assuming that a setting of 0.1A is selected the value of the stabilizing resistor, RST, required is

RST = Vs / (IREF> Is1 (HV)) = 45.5 / 0.1 = 455 ohms

To achieve an average operating time of 40 ms, Vk/Vs should be 3.5.
The Kneepoint voltage is:
VK = 4Vs = 4 x 45.5 = 182 V.
If the actual VK is greater than 4 times Vs, then the K factor increases. In this case, Vs should be recalculated.

Note:
K can reach a maximum value of approximately 1.

4.3.2.4 CURRENT TRANSFORMER CALCULATION

The effective primary operating current setting is:
IP = N(Is + nIe)
By re-arranging this equation, you can calculate the excitation current for each of the current transformers at the
stability voltage. This turns out to be:
Ie = (0.3 - 0.1) / 4 = 0.05 A
In summary, the current transformers used for this application must have a kneepoint voltage of 182 V or higher
(note that maximum Vk/Vs that may be considered is 16 and the maximum K factor is 1), with a secondary winding
resistance of 0.5 ohms or lower and a magnetizing current at 45.5 V of less than 0.05 A.
Assuming a CT kneepoint voltage of 200 V, the peak voltage can be estimated as:
VP = 2Ö2VK(VF-VK) = 2Ö2(200)(9004-200) = 3753 V
This value is above the peak voltage of 3000 V and therefore a non-linear resistor is required.

Note:
The kneepoint voltage value used in the above formula should be the actual voltage obtained from the CT magnetizing
characteristic and not a calculated value.

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154 P14DEnh-TM-EN-1.1
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CB FAIL PROTECTION
Chapter 8 - CB Fail Protection P14D

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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 157
Circuit Breaker Fail Protection 158
Circuit Breaker Fail Implementation 159
Circuit Breaker Fail Logic 161
Circuit Breaker Mapping 162
Application Notes 163

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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.

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3 CIRCUIT BREAKER FAIL IMPLEMENTATION

Circuit Breaker Failure Protection is implemented under the SETPOINTS\CONTROL\CB FAIL.
The circuit beaker failure element determines that a breaker signaled to tip has not cleared a fault within a definite
time. The circuit breaker failure scheme must Trip all breakers that can supply current to the faulted zone.
Operation of a circuit breaker failure element causes clearing of a larger section of the power system than the
initial Trip. Because circuit breaker failure can result in tripping a large number of breakers and this can affect
system safety and stability, a very high level of security is required.
The circuit breaker failure function monitors phase and neutral currents and/or status of the breaker while the
protection trip or external initiation command exists. If circuit breaker failure is declared, the function operates the
selected output relays, forces the autoreclose scheme to lockout and raises signals.
The operation of a circuit breaker failure element consists of three stages: initiation, determination of a failure
condition, and outputs.

3.1 CIRCUIT BREAKER FAILURE INITIATION

The protection signals initially sent to the breaker or external initiation (signal that initiates circuit breaker failure)
initiates the circuit breaker failure scheme.
When the scheme is initiated, it immediately sends a Trip signal to the circuit breaker initially signalled to trip (this
function is configured as Re-Trip and phase and neutral overcurrent condition is satisfied). This reduces the
possibility of widespread tripping that can result from a declaration of a failed circuit breaker.

3.2 CIRCUIT BREAKER FAILURE DETERMINATION

The schemes determine a circuit breaker failure condition supervised by one of the following:
● Current supervision only
● Circuit beaker status only
● Both (current and circuit breaker status)
Each type of supervision is equipped with a time delay, after which a failed circuit breaker is declared and trip
signals are sent to all breakers required to clear the zone. The delays are associated with breaker failure timers 1,
2, and 3.
Timer 1 logic is supervised by current level only. If fault current is detected after the delay interval, an output is
issued. The continued presence of current indicates that the breaker has failed to interrupt the circuit. This logic
detects a breaker that opens mechanically but fails to interrupt fault current.
Timer 2 logic is supervised by both current supervision and circuit breaker status. If the circuit breaker is still closed
(as indicated by the auxiliary contact) and fault current is detected after the delay interval, an output is issued.
Timer 3 logic is supervised by a circuit breaker auxiliary contact only. There is no current level check in this logic as
it is intended to detect low magnitude faults. External logic may be created to include the control switch contact
used to indicate that the circuit breaker is in out-of-service mode, disabling this logic when the circuit breaker is
out-of-service for maintenance.
Timer 1 and 2 logic provide two levels of current supervision - high-set and low-set - that allow the supervision
level to change (for example: from a current which flows before a circuit breaker inserts an opening resistor into
the faulted circuit to a lower level after resistor insertion). The high-set detector is enabled after the timeout of
timer 1 or 2, along with a timer low-set delay that enables the low-set detector after its delay interval. The delay
interval between high-set and low-set is the expected breaker opening time. Both current detectors provide a fast
operating time for currents at small multiples of the pickup value. The overcurrent detectors are required to
operate after the circuit breaker failure delay interval to eliminate the need for very fast resetting overcurrent
detectors.

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3.3 CIRCUIT BREAKER FAILURE OUTPUTS

The outputs from the circuit breaker failure schemes are:
● Re-trip of the protected breaker
● FlexLogic operand that reports on the operation of the portion of the scheme where high-set or low-set
current supervision is used
● FlexLogic operand that reports on the operation of the portion of the scheme where 52b status supervision
is used only
● FlexLogic operand that initiates tripping required to clear the faulted zone. The Breaker Failure output can
be sealed-in for an adjustable period

160 P14DEnh-TM-EN-1.1
P14D Chapter 8 - CB Fail Protection

4 CIRCUIT BREAKER FAIL LOGIC

Function
Re-Trip

Ia, Ib, Ic
1 & BF1 Retrip
Ph Retrip Set

IN

Neutral Retrip Set

Inhibit

BF Initiate
EXT Initiate
1
Int Initiate (1 to 15)

Ia, Ib, Ic

Ph Highset

1 & BF1 Highest Trip

IN

Ntrl Highset

Ia, Ib, Ic

Ph Lowset

1 & BF1 Lowest Trip

IN

Ntrl Lowset

T1 Time Delay
BF Supervision
DT
Current
52b & Current DT
52b T2 Time Delay 1
DT
& Lowset Delay

T3 Time Delay
DT
BF1 52b SupvTrip
&
Breaker Closed

V06300

Figure 74: Circuit Breaker Fail logic

P14DEnh-TM-EN-1.1 161
Chapter 8 - CB Fail Protection P14D

5 CIRCUIT BREAKER MAPPING

CB Closed 3 ph CB in Service

V02026

Figure 75: Circuit Breaker mapping

162 P14DEnh-TM-EN-1.1
P14D Chapter 8 - CB Fail Protection

6 APPLICATION NOTES

6.1 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.

6.2 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.

Fault occurs

CBF Safety
Protection Maximumbreaker reset margin
Normal operatingtime clearing time time time
operation
t

Protection Local Bks clearing

Breaker failure operatingtime CBFback-up trip time delay time
operation

Local 86 Remote CB
operating clearing time
time

Maximumfault clearing time

V06303 Fault occurs

Figure 76: CB Fail timing

The following examples consider direct tripping of a 2-cycle circuit breaker. Typical timer settings to use are as
follows:

P14DEnh-TM-EN-1.1 163
Chapter 8 - CB Fail Protection P14D

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

164 P14DEnh-TM-EN-1.1
 CHAPTER 9

CURRENT TRANSFORMER REQUIREMENTS

Chapter 9 - Current Transformer Requirements P14D

166 P14DEnh-TM-EN-1.1
P14D Chapter 9 - Current Transformer Requirements

1 CHAPTER OVERVIEW

This chapter contains the following sections:

Chapter Overview 167
CT requirements 168

P14DEnh-TM-EN-1.1 167
Chapter 9 - Current Transformer Requirements P14D

2 CT REQUIREMENTS
The current transformer requirements are based on a maximum fault current of 50 times the rated current (In) with
the device having an instantaneous overcurrent setting of 25 times the rated current. The current transformer
requirements are designed to provide operation of all protection elements.
Where the criteria for a specific application are in excess of this, or the lead resistance exceeds the limiting lead
resistance shown in the following table, the CT requirements may need to be modified according to the formulae in
the subsequent sections:
Nominal Accuracy Accuracy Limited Limiting Lead
Nominal Output
Rating Class Factor Resistance
1A 2.5 VA 10P 20 1.3 ohms
5A 7.5 VA 10P 20 0.11 ohms
The formula subscripts used in the subsequent sections are as follows:
K = A constant affected by the dynamic response of the relay
cn = Maximum prospective secondary earth fault current or 31 times > setting (whichever is lower) (amps)
cp = Maximum prospective secondary phase fault current or 31 times > setting (whichever is lower) (amps)
f = Maximum through-fault current level (amps)
Ιfn = Maximum prospective secondary earth fault current (amps)
Ιfp = Maximum prospective secondary phase fault current (amps)
n = Rated secondary current (amps)
s = Current setting of REF elements (amps)
Ιsn = Stage 2 & 3 earth fault setting (amps)
Ιsp = Stage 2 and 3 setting (amps)
Ιst = Motor start up current referred to CT secondary side (amps)
RCT = Resistance of current transformer secondary winding (ohms)
RL = Resistance of a single lead from relay to current transformer (ohms)
Rn = Impedance of the neutral current input at 30n (ohms)
Rp = Impedance of the phase current input at 30n (ohms)
Rst = Value of stabilising resistor for REF applications (ohms)
VK = Required CT knee-point voltage (volts)
VS = Required stability voltage

2.1 PHASE OVERCURRENT PROTECTION

2.1.1 DIRECTIONAL ELEMENTS

Time-delayed phase overcurrent elements

I cp
VK = ( RCT + RL + R p )
2

168 P14DEnh-TM-EN-1.1
P14D Chapter 9 - Current Transformer Requirements

Instantaneous phase overcurrent elements

I fp
VK = ( RCT + RL + R p )
2

2.1.2 NON-DIRECTIONAL ELEMENTS

Time-delayed phase overcurrent elements

I cp
VK = ( RCT + RL + R p )
2

Instantaneous phase overcurrent elements

VK = I sp ( RCT + RL + R p )

2.2 EARTH FAULT PROTECTION

2.2.1 DIRECTIONAL ELEMENTS

Instantaneous earth fault overcurrent elements

I fn
VK = ( RCT + 2 RL + R p + Rn)
2

2.2.2 NON-DIRECTIONAL ELEMENTS

Time-delayed earth fault overcurrent elements

I cn
VK = ( RCT + 2 RL + R p + Rn )
2

Instantaneous earth fault overcurrent elements

VK = I sn ( RCT + 2 RL + R p + Rn )

2.3 SEF PROTECTION (RESIDUALLY CONNECTED)

2.3.1 DIRECTIONAL ELEMENTS

Time delayed SEF protection

I cn
VK ≥ ( RCT + 2 RL + R p + Rn)
2

Instantaneous SEF protection

I
VK ≥ ( RCT + 2 RL + R p + Rn)
fn

P14DEnh-TM-EN-1.1 169
Chapter 9 - Current Transformer Requirements P14D

2.3.2 NON-DIRECTIONAL ELEMENTS

Time delayed SEF protection

I cn
VK ≥ ( RCT + 2 RL + R p + Rn)
2

Instantaneous SEF protection

I sn
VK ≥ ( RCT + 2 RL + R p + Rn)
2

2.4 SEF PROTECTION (CORE-BALANCED CT)

2.4.1 DIRECTIONAL ELEMENTS

Instantaneous element

I
VK ≥ ( RCT + 2 RL + Rn)
fn

Note:
Ensure that the phase error of the applied core balance current transformer is less than 90 minutes at 10% of rated current
and less than 150 minutes at 1% of rated current.

2.4.2 NON-DIRECTIONAL ELEMENTS

Time delayed element

I cn
VK ≥ ( RCT + 2 RL + Rn)
2

Instantaneous element

VK ≥ I sn ( RCT + 2 RL + Rn)

Note:
Ensure that the phase error of the applied core balance current transformer is less than 90 minutes at 10% of rated current
and less than 150 minutes at 1% of rated current.

2.5 LOW IMPEDANCE REF PROTECTION

For X/R < 40 and f < 15n

VK ≥ 24 I n ( RCT + 2 RL )

For 40 < X/R < 120 and 15n < If < 40n

VK ≥ 48 I n ( RCT + 2 RL )

170 P14DEnh-TM-EN-1.1
P14D Chapter 9 - Current Transformer Requirements

Note:
Class x or Class 5P CTs should be used for low impedance REF applications.

2.6 HIGH IMPEDANCE REF PROTECTION

The high impedance REF element will maintain stability for through-faults and operate in less than 40ms for
internal faults, provided the following equations are met:

I f ( RCT + 2 RL )
Rst =
Is

VK ≥ 4 I s Rst

Note:
Class x CTs should be used for high impedance REF applications.

2.7 HIGH IMPEDANCE BUSBAR PROTECTION

The high impedance bus bar protection element will maintain stability for through faults and operate for internal
faults. You should select Vk/Vs based on the X/R of the system. The equation is:
Vs=K*If*(RCT+RL)

For X/R <= 40

Vk/Vs >= 2
Typical operating time = 25 ms

For X/R > 40

Vk/Vs>=4
Typical operating time = 30 ms

Note:
K is a constant affected by the dynamic response of the device. K is always equal to 1.

2.8 USE OF METROSIL NON-LINEAR RESISTORS

Current transformers can develop high peak voltages under internal fault conditions. Metrosils are used to limit
these peak voltages to a value below the maximum withstand voltage (usually 3 kV).
You can use the following formulae to estimate the peak transient voltage that could be produced for an internal
fault. The peak voltage produced during an internal fault is a function of the current transformer kneepoint voltage
and the prospective voltage that would be produced for an internal fault if current transformer saturation did not
occur.
Vp = 2Ö(2VK(VF-VK))
Vf = I'f(RCT+2RL+RST)

P14DEnh-TM-EN-1.1 171
Chapter 9 - Current Transformer Requirements P14D

where:
● Vp = Peak voltage developed by the CT under internal fault conditions
● Vk = Current transformer kneepoint voltage
● Vf = Maximum voltage that would be produced if CT saturation did not occur
● I'f = Maximum internal secondary fault current
● RCT = Current transformer secondary winding resistance
● RL = Maximum lead burden from current transformer to relay
● RST = Relay stabilising resistor

You should always use Metrosils when the calculated values are greater than 3000 V. Metrosils are connected
across the circuit to shunt the secondary current output of the current transformer from the device to prevent very
high secondary voltages.
Metrosils are externally mounted and take the form of annular discs. Their operating characteristics follow the
expression:

V = CI0.25
where:
● V = Instantaneous voltage applied to the Metrosil
● C = Constant of the Metrosil
● I = Instantaneous current through the Metrosil

With a sinusoidal voltage applied across the Metrosil, the RMS current would be approximately 0.52 x the peak
current. This current value can be calculated as follows:
4
 2VS ( RMS ) 
I RMS = 0.52  
 C 
 
where:
● VS(RMS) = RMS value of the sinusoidal voltage applied across the metrosil.

This is due to the fact that the current waveform through the Metrosil is not sinusoidal but appreciably distorted.
The Metrosil characteristic should be such that it complies with the following requirements:
● The Metrosil current should be as low as possible, and no greater than 30 mA RMS for 1 A current
transformers or 100 mA RMS for 5 A current transformers.
● At the maximum secondary current, the Metrosil should limit the voltage to 1500 V RMS or 2120 V peak for
0.25 second. At higher device voltages it is not always possible to limit the fault voltage to 1500 V rms, so
higher fault voltages may have to be tolerated.
The following tables show the typical Metrosil types that will be required, depending on relay current rating, REF
voltage setting etc.

Metrosils for devices with a 1 Amp CT

The Metrosil units with 1 Amp CTs have been designed to comply with the following restrictions:
● The Metrosil current should be less than 30 mA rms.
● At the maximum secondary internal fault current the Metrosil should limit the voltage to 1500 V rms if
possible.

The Metrosil units normally recommended for use with 1Amp CTs are as shown in the following table:

172 P14DEnh-TM-EN-1.1
P14D Chapter 9 - Current Transformer Requirements

Nominal Characteristic Recommended Metrosil Type

Device Voltage Setting C b Single Pole Relay Triple Pole Relay
Up to 125 V RMS 450 0.25 600A/S1/S256 600A/S3/1/S802
125 to 300 V RMS 900 0.25 600A/S1/S1088 600A/S3/1/S1195

Note:
Single pole Metrosil units are normally supplied without mounting brackets unless otherwise specified by the customer.

Metrosils for devices with a 5 Amp CT

These Metrosil units have been designed to comply with the following requirements:
● The Metrosil current should be less than 100 mA rms (the actual maximum currents passed by the devices
shown below their type description.
● At the maximum secondary internal fault current the Metrosil should limit the voltage to 1500 V rms for
0.25secs. At the higher relay settings, it is not possible to limit the fault voltage to 1500 V rms so higher fault
voltages have to be tolerated.
The Metrosil units normally recommended for use with 5 Amp CTs and single pole relays are as shown in the
following table:
Secondary Internal Fault Current Recommended Metrosil types for various voltage settings
Amps RMS Up to 200 V RMS 250 V RMS 275 V RMS 300 V RMS
600A/S1/S1213 600A/S1/S1214 600A/S1/S1214 600A/S1/S1223
50A C = 540/640 C = 670/800 C =670/800 C = 740/870
35 mA RMS 40 mA RMS 50 mA RMS 50 mA RMS
600A/S2/P/
600A/S2/P/S1215 600A/S2/P/S1215 600A/S2/P/S1196
S1217
100A C = 570/670 C =570/670 C =620/740
C = 470/540
75 mA RMS 100 mA RMS 100 mA RMS
70 mA RMS
600A/S3/P/
600A/S3/P/S1220 600A/S3/P/S1221 600A/S3/P/S1222
S1219
150A C = 520/620 C = 570/670 C =620/740
C = 430/500
100 mA RMS 100 mA RMS 100 mA RMS
100 mA RMS

In some situations single disc assemblies may be acceptable, contact General Electric for detailed applications.

Note:
The Metrosils recommended for use with 5 Amp CTs can also be used with triple pole devices and consist of three single pole
units mounted on the same central stud but electrically insulated from each other. To order these units please specify "Triple
pole Metrosil type", followed by the single pole type reference. Metrosil for higher voltage settings and fault currents are
available if required.

2.9 USE OF ANSI C-CLASS CTS

Where American/IEEE standards are used to specify CTs, the C class voltage rating can be used to determine the
equivalent knee point voltage according to IEC. The equivalence formula is:

VK = 1.05(C rating in volts ) + 100 RCT

P14DEnh-TM-EN-1.1 173
Chapter 9 - Current Transformer Requirements P14D

174 P14DEnh-TM-EN-1.1
 CHAPTER 10

VOLTAGE PROTECTION FUNCTIONS

Chapter 10 - Voltage Protection Functions P14D

176 P14DEnh-TM-EN-1.1
P14D Chapter 10 - Voltage Protection Functions

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 177
Undervoltage Protection 178
Overvoltage Protection 181
Residual Overvoltage Protection 184
Negative Sequence Overvoltage Protection 188
Positive Sequence Undervoltage Protection 190
Positive Sequence Overvoltage Protection 191

P14DEnh-TM-EN-1.1 177
Chapter 10 - Voltage Protection Functions P14D

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 under the path SETPOINTS/PROTECTION/GROUP [1-4]/VOLTAGE PROT/
PHASE UV.
The product provides four stages of Undervoltage protection with independent time delay characteristics.
Each stage provides a choice of operate characteristics, where you can select between:
● An IDMT characteristic
● A range of user-defined curves
● DT (Definite Time)

You set this using the V<(n) Curve, depending on the stage.
The IDMT characteristic is defined by the following formula:
T= D/(1 – V / Vpkp)
where:
● T = Operating time in seconds
● D = Undervoltage Pickup Time Delay setpoint (for D = 0.00 operates instantaneously)
● V = Voltage as a fraction of the nominal VT Secondary Voltage
● Vpkp = Undervoltage Pickup Level

If FlexCurves are selected, the operating time is determined based on the following equation:
● T= Flexcurve(Vpkp / V)
The undervoltage stages can be configured either as phase-to-neutral or phase-to-phase voltages in the setting
V< [n] Meas Mode.

178 P14DEnh-TM-EN-1.1
P14D Chapter 10 - Voltage Protection Functions

Additional stages are included in order to provide multiple output types, such as alarm and trip stages.
Alternatively, different time settings may be required depending upon the severity of the voltage dip. For example,
motor loads will be able to cope with a small voltage dip for a longer time than a major one.
Outputs are available for single or three-phase conditions via the V< (n) Operate Mode setting for each stage.

2.2 UNDERVOLTAGE PROTECTION LOGIC

V<1 Min Voltage

V<1 Meas Mode

V<1 Start A/AB

V<1 Voltage Set & t

V<1 Trip A/AB
0
V<1 Time Delay

V<1 Meas Mode

V<1 Start B/BC

V<1 Voltage Set & t V<1 Trip B/BC

0
V<1 Time Delay

V<1 Meas Mode

V<1 Start C/CA

V<1 Voltage Set & t V<1 Trip C/CA

0
V<1 Time Delay
1
&
Inhibit
VTS Fast Block &
& 1 V<1 Start

&

& 1
&

&
V<1 Operate Mode
Any Phase
Any Two
Three Phase

1
&

&
& 1 V<1 Trip

&

&
& 1

&

V06100
Note: This diagram does not show all stages. Other stages follow similar principles.
VTS Fast Block only applies for directional models.

Figure 77: Undervoltage - single and three phase tripping mode (single stage)

P14DEnh-TM-EN-1.1 179
Chapter 10 - Voltage Protection Functions P14D

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 a V<(n) Min Voltage threshold setting. This Start signal is applied to the
timer module to produce the Trip signal. 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<(n) 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<(n)
Operate Mode setting.
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, a V<(n) Min Voltage threshold setting blocks the Start signal for each
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.

180 P14DEnh-TM-EN-1.1
P14D Chapter 10 - Voltage Protection Functions

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 under the path SETPOINTS/PROTECTION/GROUP [1-4]/VOLTAGE PROT/
PHASEOV.
The product provides overvoltage protection with independent time delay characteristics.
Each stage provides a choice of operate characteristics, where you can select between:
● An IDMT characteristic
● A range of user-defined curves
● DT (Definite Time)

You set this using the V>(n) Curve.

The IDMT characteristic is defined by the following formula:
The operating time is defined by the following formula:

D
T=
 V 
 − 1

 V pickup 
when V > Vpickup
Where:
● T = trip time in seconds
● D = Overvoltage Pickup Delay setpoint
● V = actual phase-phase voltage
● Vpickup = Overvoltage Pickup setpoint
The overvoltage stages can be configured either as phase-to-neutral or phase-to-phase voltages in the V>(n)
Meas mode cell.
Additional stages are included in order to provide multiple output types, such as alarm and trip stages.
Alternatively, different time settings may be required depending upon the severity of the voltage increase.
Outputs are available for single or three-phase conditions via the V>(n) Operate Mode setting for each stage.

P14DEnh-TM-EN-1.1 181
Chapter 10 - Voltage Protection Functions P14D

3.2 OVERVOLTAGE PROTECTION LOGIC

V>1 Meas Mode

V>1 Start A/AB

V>1 Voltage Set & t

V>1 Trip A/AB
0
V>1 Time Delay

V>1 Meas Mode

V>1 Start B/BC

V>1 Voltage Set & t V>1 Trip B/BC

0
V>1 Time Delay

V>1 Meas Mode

V>1 Start C/CA

V>1 Voltage Set & t V>1 Trip C/CA

0
V>1 Time Delay
1
&
Inhibit
&
& 1 V>1 Start

&

& 1
&

&
V>1 Operate Mode
Any Phase
Any Two
Three Phase

1
&

&
& 1 V>1 Trip

&

&
& 1

&
V06101

Note: This diagram does not show all stages. Other stages follow similar principles.
VTS Fast Block only applies for directional models.

Figure 78: 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 Inhibit signal. This start signal is applied to the timer module to produce the Trip signal. 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>(n) Operate Mode setting.

182 P14DEnh-TM-EN-1.1
P14D Chapter 10 - Voltage Protection Functions

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>(n)
Operate Mode setting.

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.

P14DEnh-TM-EN-1.1 183
Chapter 10 - Voltage Protection Functions P14D

4 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.

4.1 RESIDUAL OVERVOLTAGE PROTECTION IMPLEMENTATION

Residual Overvoltage Protection is implemented under the paths SETPOINTS/PROTECTION/GROUP [1-4]/VOLTAGE
PROT/RESIDUAL OV(M)--for measured values, and SETPOINTS/PROTECTION/GROUP [1-4]/VOLTAGE PROT/
RESIDUAL OV(D)--for derived values.
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 Residual Overvoltage protection with independent time delay characteristics.
Each stage provides a choice of operate characteristics, where you can select between:
● An IDMT characteristic
● A range of user-defined curves
● DT (Definite Time)

The operating time is given by:

D
T=
 V 
 − 1

 V pickup 
when V > Vpickup
Where:
● T = trip time in seconds
● D = overvoltage Pickup Delay setpoint
● V = measured or derived phase-phase voltage
● Vpickup = overvoltage Pickup setpoint
You set this using the VN>(n) Curve.
The residual voltage may be derived from the phase voltages (Vres = Va + Vb +Vc) or measured from the 4th VT
input.

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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.

4.2 RESIDUAL OVERVOLTAGE LOGIC

VN2>1 Start

VN

VN2>1 Voltage Set &

IDMT/DT VN2>1 Trip
Inhibit
VTS Fast Block

Note: This diagram shows the logic for VN2(Derived). The logic for
VN1(Measured) follows the same principles. V06102
The corresponding outputs will be VN1>1 Start and VN1>1 Trip
.

Figure 79: 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.

4.3 APPLICATION NOTES

4.3.1 CALCULATION FOR SOLIDLY EARTHED SYSTEMS

Consider a Phase-A to Earth fault on a simple radial system.

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Chapter 10 - Voltage Protection Functions P14D

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 80: 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.

4.3.2 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 81: 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.

4.3.3 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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5 NEGATIVE SEQUENCE OVERVOLTAGE PROTECTION

Where an incoming feeder is supplying rotating plant equipment such as an induction motor, correct phasing and
balance of the supply is essential. Incorrect phase rotation will result in connected motors rotating in the wrong
direction. For directionally sensitive applications, such as elevators and conveyor belts, it is unacceptable to allow
this to happen.
Imbalances on the incoming supply cause negative phase sequence voltage components. In the event of incorrect
phase rotation, the supply voltage would effectively consist of 100% negative phase sequence voltage only.

5.1 NEGATIVE SEQUENCE OVERVOLTAGE IMPLEMENTATION

Negative Sequence Overvoltage Protection is implemented under the path SETPOINTS\PROTECTION\GROUP
[1-4]\VOLTAGE PROT\NEG SEQ OV.
The device includes one Negative Phase Sequence Overvoltage element with multiple stages. Only Definite time is
possible.
This element monitors the input voltage rotation and magnitude (normally from a bus connected voltage
transformer) and may be interlocked with the motor contactor or circuit breaker to prevent the motor from being
energised whilst incorrect phase rotation exists.
The element is enabled using the V2>1 Function setting.

5.2 NEGATIVE SEQUENCE OVERVOLTAGE LOGIC

V2>1 Start

V2

V2>1 VoltageSet & & DT V2>1 Trip

V2>1 Inhibit
Note: This diagramdoesnot showall stages. Other stages followsimilar
principles.
V06103

Figure 82: Negative Sequence Overvoltage logic

The Negative Voltage Sequence Overvoltage module detects when the voltage magnitude exceeds a set
threshold. When this happens, the comparator output Overvoltage Module produces a Start signal (e.g. for stage
1: V2>1 Start), which signifies the "Start of protection". This can be blocked by a V2>1 Inhibit signal. This Start
signal is applied to the DT timer module. The output of the DT timer module is the trip signal which is used to drive
the tripping output relay.

5.3 APPLICATION NOTES

5.3.1 SETTING GUIDELINES

The primary concern is usually the detection of incorrect phase rotation (rather than small imbalances), therefore a
sensitive setting is not required. The setting must be higher than any standing NPS voltage, which may be present
due to imbalances in the measuring VT, device tolerances etc.
A setting of approximately 15% of rated voltage may be typical.

Note:
Standing levels of NPS voltage (V2) are displayed in the V2 Magnitude setting under MEASUREMENTS.

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The operation time of the element depends on the application, but a typical setting would be in the region of 5
seconds.

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6 POSITIVE SEQUENCE UNDERVOLTAGE PROTECTION

6.1 POSITIVE SEQUENCE UNDERVOLTAGE IMPLEMENTATION

Positive Sequence Undervoltage Protection is implemented under the path SETPOINTS\PROTECTION\GROUP [1-4]\
\VOLTAGE PROT\POS SEQ UV.
The product provides Positive Sequence Undervoltage protection with independent time delay characteristics.
Each stage provides a choice of operate characteristics, where you can select between:
● An IDMT characteristic
● DT (Definite Time)

You set this using the V1<1 Curve

The IDMT characteristic is defined by the following formula:
T= D/(1 – V / Vpkp)

where:
● T = Operating time in seconds
● D = Undervoltage Pickup Time Delay setpoint (for D = 0.00 operates instantaneously)
● V = Measured positive sequence voltage
● Vpkp = Undervoltage Pickup Level

Additional stages are included in order to provide multiple output types, such as alarm and trip stages.

6.2 POSITIVE SEQUENCE UNDERVOLTAGE LOGIC

V1<1 Start

V1<1 Voltage Set &

& V1<1 Trip

V1<1 Time Delay

V
V1<1 Min Voltage
Note: This diagram does not show all stages. Other stages follow similar principles.
VTS Fast Block only applies for directional models.
Inhibit
VTS Fast Block

V06104

Figure 83: Positive Sequence Undervoltage logic

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7 POSITIVE SEQUENCE OVERVOLTAGE PROTECTION

7.1 POSITIVE SEQUENCE OVERVOLTAGE IMPLEMENTATION

Positive Sequence Overvoltage Protection is implemented under the path SETPOINTS\PROTECTION\GROUP
[1-4]\VOLTAGE PROT\POS SEQ OV
The product provides Positive Sequence Overvoltage protection with independent time delay characteristics.
Each stage provides a choice of operate characteristics, where you can select between:
● An IDMT characteristic
● DT (Definite Time)

You set this using the V1>1 Curve setting.

The IDMT characteristic is defined by the following formula:

TMS
T=
 V 
 − 1

 V pickup 
where:
● T = operate time (in seconds)
● TMS = Time Multiplier setting
● V = measured positive sequence voltage
● Vpickup = Pickup Voltage setting
Multiple stages are included in order to provide multiple output types, such as alarm and trip stages.

7.2 POSITIVE SEQUENCE OVERVOLTAGE LOGIC

V1>1 Start

V1>1 Voltage Set &

& V1>1 Trip

V1>1 Time Delay

V>1 Inhibit Note: This diagram does not show all stages. Other stages follow similar principles.
Off=0

V06105

Figure 84: Positive Sequence Overvoltage logic

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192 P14DEnh-TM-EN-1.1
 CHAPTER 11

FREQUENCY PROTECTION FUNCTIONS

Chapter 11 - Frequency Protection Functions P14D

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P14D Chapter 11 - Frequency Protection Functions

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 195
Frequency Protection Overview 196
Underfrequency Protection 197
Overfrequency Protection 199
Independent R.O.C.O.F Protection 201

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2 FREQUENCY PROTECTION OVERVIEW

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.
Protection devices capable of detecting low frequency conditions are generally used to disconnect unimportant
loads in order to re-establish the generation-to-load balance. However, with such devices, the action is initiated
only after the event and this form of corrective action may not be effective enough to cope with sudden load
increases that cause large frequency decays in very short times. In such cases a device that can anticipate the
severity of frequency decay and act to disconnect loads before the frequency reaches dangerously low levels, are
very effective in containing damage. This is called instantaneous rate of change of frequency protection (ROCOF).

2.1 FREQUENCY PROTECTION IMPLEMENTATION

Frequency Protection is implemented under the path SETPOINTS\PROTECTION\GROUP [1-4]\FREQUENCY PROT.
The device includes multiple stages for the following frequency protection methods:
● Underfrequency Protection: abbreviated to F<(n)
● Overfrequency Protection: abbreviated to F>(n)
● Independent Rate of Change of Frequency Protection: abbreviated to df/dt>(n)
Each stage can be disabled or enabled with the Function setting. The frequency protection can also be blocked by
an undervoltage condition if required.

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3 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.

3.1 UNDERFREQUENCY PROTECTION IMPLEMENTATION

Under Frequency Protection is implemented under the path SETPOINTS\PROTECTION\GROUP [1-4]\FREQUENCY
PROT. \UNDER FREQUENCY
The following settings are relevant for underfrequency:
● F<(n) Function: determines whether the stage is underfrequency or disabled
● F<(n) Freq Set: defines the frequency pickup setting
● F<(n) Time Delay: sets the time delay

3.2 UNDERFREQUENCY PROTECTION LOGIC

F<1 Sta rt

DT
F<1 Freq Set & F<1 Trip
tRESET

F<Inhibit

F<1 Function
Disabled

F<1 Imin

F<1 Vmin

V06600 Note: This diagram does not show all stages. Other stages follow similar principles.

Figure 85: 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.

3.3 APPLICATION NOTES

3.3.1 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.

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Chapter 11 - Frequency Protection Functions P14D

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.
An example of a four-stage load shedding scheme for 50 Hz systems is shown below:
Stage Element Frequency Setting (Hz) Time Setting (Sec)
1 Stage 1(f+t) 49.0 20 s
2 Stage 2(f+t) 48.6 20 s
3 Stage 3(f+t) 48.2 10 s
4 Stage 4(f+t) 47.8 10 s

The relatively long time delays are intended to provide sufficient time for the system controls to respond. This will
work well in a situation where the decline of system frequency is slow. For situations where rapid decline of
frequency is expected, this load shedding scheme should be supplemented by rate of change of frequency
protection elements.

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4 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.

4.1 OVERFREQUENCY PROTECTION IMPLEMENTATION

Over Frequency Protection is implemented under the path SETPOINTS\PROTECTION\GROUP [1-4]\FREQUENCY
PROT. \OVER FREQUENCY
The following settings are relevant for overfrequency:
● F>(n) Function: determines whether the stage is overfrequency or disabled
● F>(n) Freq Set: defines the frequency pickup setting
● F>(n) Time Delay: sets the time delay

4.2 OVERFREQUENCY PROTECTION LOGIC

F>1 Sta rt

DT
F>1 Freq Set & F>1 Trip
tRESET
F>1 Inhibit

F>1 Function
Disabled

F>1 Vmin

V06601 Note: This diagram does not show all stages. Other stages follow similar principles.

Figure 86: 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.

4.3 APPLICATION NOTES

4.3.1 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.
An example of two-stage overfrequency protection is shown below using stages 5 and 6 of the f+t elements.
However, settings for a real system will depend on the maximum frequency that equipment can tolerate for a
given period of time.

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Chapter 11 - Frequency Protection Functions P14D

Stage Element Frequency Setting (Hz) Time Setting (Sec.)

1 Stage 5(f+t) 50.5 30
2 Stage 6(f+t) 51.0 20

The relatively long time delays are intended to provide time for the system controls to respond and will work well in
a situation where the increase of system frequency is slow.
For situations where rapid increase of frequency is expected, the protection scheme above could be supplemented
by rate of change of frequency protection elements.
In the system shown below, the generation in the MV bus is sized according to the loads on that bus, whereas the
generators linked to the HV bus produce energy for export to utility. If the links to the grid are lost, the generation
will cause the system frequency to rise. This rate of rise could be used to isolate the MV bus from the HV system.

To utility
IPP generation

HV bus

Load

MV bus

Local generation
Load

E00857

Figure 87: Power system segregation based upon frequency measurements

200 P14DEnh-TM-EN-1.1
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5 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.

5.1 INDEPENDENT R.O.C.O.F PROTECTION IMPLEMENTATION

Rate Of Change Of Frequency Protection is implemented under the path SETPOINTS\PROTECTION\GROUP
[1-4]\FREQUENCY PROT. \ROCOF
The device provides independent stages of protection. Each stage can respond to either rising or falling frequency
conditions. This depends on whether the df/dt>(n) Dir'n is set to negative or positive or Both. For example, if the
trend is set to positive, the rate of change of frequency setting is considered as positive and the element will
operate for rising frequency conditions. If the trend is set to negative, the element will operate for falling frequency
conditions.
The following settings are relevant for df/dt protection:
● df/dt>(n) Dir'n: determines whether the stage is for falling or rising frequency conditions
● df/dt>(n) Set: defines the rate of change of frequency pickup setting
● df/dt>(n) Delay: sets the time delay

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Chapter 11 - Frequency Protection Functions P14D

5.2 INDEPENDENT R.O.C.O.F PROTECTION LOGIC

V1

df/dt 1 Vmin

I1

df/dt 1 Imin &

f
&
df/dt 1 Fmin 1 df/dt 1 Trip

df/dt 1 Up Trip
&

df/dt 1 Fmax

df/dt 1 Function
Enabled & df/dt1 Dwn Trip

df/dt 1 Dir¶n
1
Positive
Both df/dt 1 Delay
Negative
df/dt1 Up Start
1
df/dt 1 Dwn Start
df/dt 1 Inhibit
1 df/dt 1 Start
df/dt

df/dt 1 Set

-df/dt

Note: This diagram does not show all stages. Other stages follow similar principles.
V06602

Figure 88: Independent rate of change of frequency logic (single stage)

5.3 APPLICATION NOTES

5.3.1 SETTING GUIDELINES

Considerable care should be taken when setting this element because it is not supervised by a frequency setting.
Setting of the time delay will improve stability but this is traded against reduced tripping times.
It is likely that this element would be used in conjunction with other frequency based protection elements to
provide a scheme that accounts for severe frequency fluctuations. An example scheme is shown below:
Rate of Change of Frequency
Stage
"df/dt [81R]" Elements
Rate of Change of Frequency Setting (Hz/Sec.) Time Setting (Sec.)
1 - -
2 - -
3 -3.0 0.5
4 -3.0 0.5
5 -3.0 0.1

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P14D Chapter 11 - Frequency Protection Functions

In this scheme, tripping of the last two stages is accelerated by using the independent rate of change of frequency
element. If the frequency starts falling at a high rate (> 3 Hz/s in this example), then stages 3 & 4 are shed at
around 48.5 Hz, with the objective of improving system stability. Stage 5 serves as an alarm and gives operators
advance warning that the situation is critical.

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204 P14DEnh-TM-EN-1.1
 CHAPTER 12

POWER PROTECTION FUNCTIONS

Chapter 12 - Power Protection Functions P14D

206 P14DEnh-TM-EN-1.1
P14D Chapter 12 - Power Protection Functions

1 CHAPTER OVERVIEW
Power protection is used for protecting generators. Although the main function of this device is for feeder
applications, it can also be used as a cost effective alternative for protecting small distributed generators, typically
less than 2 MW.
This chapter contains the following sections:
Chapter Overview 207
Overpower Protection 208
Underpower Protection 211

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Chapter 12 - Power Protection Functions P14D

2 OVERPOWER PROTECTION
With Overpower, we should consider two distinct conditions: Forward Overpower and Reverse Overpower.
A forward overpower condition occurs when the system load becomes excessive. A generator is rated to supply a
certain amount of power and if it attempts to supply power to the system greater than its rated capacity, it could
be damaged. Therefore overpower protection in the forward direction can be used as an overload indication. It can
also be used as back-up protection for failure of governor and control equipment. Generally the Overpower
protection element would be set above the maximum power rating of the machine.
A reverse overpower condition occurs if the generator prime mover fails. When this happens, the power system
may supply power to the generator, causing it to motor. This reversal of power flow due to loss of prime mover can
be very damaging and it is important to be able to detect this with a Reverse Overpower element.

2.1 OVERPOWER PROTECTION IMPLEMENTATION

Overpower Protection is implemented under the path SETPOINTS\PROTECTION\GROUP [1-4]\POWER
\OVERPOWER\OVERPOWER 1
The Overpower Protection element provides multiple stages of directional overpower for both active and reactive
power. The directional element can be configured as forward or reverse and can activate single-phase or three-
phase trips.
The elements use three-phase power and single phase power measurements as the energising quantities. A Start
condition occurs when measurements exceed the setting threshold. A trip condition occurs if the Start condition is
present for the set time delay. This can be inhibited by the VTS Slow Block and Pole Dead logic if desired.
The Start and Trip timer resets if the power falls below the drop-off level or if an inhibit condition occurs. The reset
mechanism is similar to the overcurrent functionality for a pecking fault condition, where the percentage of
elapsed time for the operate timer is memorised for a set reset time delay. If the Start condition returns before the
reset timer has timed out, the operate time initialises from the memorised travel value. Otherwise the memorised
value is reset to zero after the reset time times out.

2.2 OVERPOWER LOGIC

P>1 3PhStart

P(3 phase)
DT
P>1 3Ph Watt & 1 & P>1 3Ph Trip

P>1 3Ph VAR tRESET

P>1 Mode P>1TimeDelay

Active -1 X &
Reactive

P>1Direction
Forward
Reverse

P>1 Function
Enabled

P>1 Inhibit

V06700

Figure 89: Overpower logic

208 P14DEnh-TM-EN-1.1
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2.3 APPLICATION NOTES

2.3.1 FORWARD OVERPOWER SETTING GUIDELINES

The relevant power threshold settings should be set greater than the full load rated power.
The operating mode should be set to Forward.
A time delay setting (P>(n) TimeDelay) should be applied. This setting is dependant on the application. The delay on
the reset timer (P>(n) tRESET), would normally be set to zero.

2.3.2 REVERSE POWER CONSIDERATIONS

A generator is expected to supply power to the connected system in normal operation. If the generator prime
mover fails, it will begin to take motoring power from the power system (if the power system to which it is
connected has other generating sources). The consequences of this reversal of power and the level of power
drawn from the power system will be dependent on the type of prime mover.
Typical levels of motoring power and possible motoring damage that could occur for various types of generating
plant are given in the following table.
Prime mover Motoring power Possible damage (percentage rating)
Diesel Engine 5% - 25% Risk of fire or explosion from unburned fuel
Motoring level depends on compression ratio and cylinder bore stiffness. Rapid disconnection is required to limit power loss
and risk of damage.
10% - 15% (Split-shaft) With some gear-driven sets, damage may arise due
Gas Turbine
>50% (Single-shaft) to reverse torque on gear teeth.
Compressor load on single shaft machines leads to a high motoring power compared to split-shaft machines. Rapid
disconnection is required to limit power loss or damage.
0.2 - >2% (Blades out of water) Blade and runner damage may occur with a long
Hydraulic Turbines
>2.0% (Blades in water) period of motoring
Power is low when blades are above tail-race water level. Hydraulic flow detection devices are often the main means of
detecting loss of drive. Automatic disconnection is recommended for unattended operation.
Thermal stress damage may be inflicted on low-
0.5% - 3% (Condensing sets)
Steam Turbines pressure turbine blades when steam flow is not
3% - 6% (Non-condensing sets)
available to dissipate losses due to air resistance.
Damage may occur rapidly with non-condensing sets or when vacuum is lost with condensing sets. Reverse power
protection may be used as a secondary method of detection and might only be used to raise an alarm.

In some applications, the level of reverse power in the case of prime mover failure may fluctuate. This may be the
case for a failed diesel engine. To prevent cyclic initiation and reset of the main trip timer, an adjustable reset time
delay is provided. You will need to set this time delay longer than the period for which the reverse power could fall
below the power setting. This setting needs to be taken into account when setting the main trip time delay.

Note:
A delay in excess of half the period of any system power swings could result in operation of the reverse power protection
during swings.

2.3.3 REVERSE OVERPOWER SETTING GUIDELINES

Each stage of power protection can be selected to operate as a reverse power stage by setting P>(n) Direction to
Reverse.
The relevant power threshold settings should be set to less than 50% of the motoring power.
The operating mode should be set to Reverse.

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Chapter 12 - Power Protection Functions P14D

The reverse power protection function should be time-delayed to prevent false trips or alarms being given during
power system disturbances or following synchronisation.
A time delay setting, of approximately 5 s would be typically applied.
The delay on the reset timer, P>1 tRESET or P>2 tRESET, would normally be set to zero.
When settings of greater than zero are used for the reset time delay, the pick-up time delay setting may need to be
increased to ensure that false tripping does not result in the event of a stable power swinging event.
Reverse overpower protection can also be used for loss of mains applications. If the distributed generator is
connected to the grid but not allowed to export power to the grid, it is possible to use reverse power detection to
switch off the generator. In this case, the threshold setting should be set to a sensitive value, typically less than 2%
of the rated power. It should also be time-delayed to prevent false trips or alarms being given during power system
disturbances, or following synchronisation. A typical time delay is 5 seconds.

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3 UNDERPOWER PROTECTION
Although the Underpower protection is directional and can be configured as forward or reverse, the most common
application is for Low Forward Power protection.
When a machine is generating and the circuit breaker connecting the generator to the system is tripped, the
electrical load on the generator is cut off. This could lead to overspeeding of the generator if the mechanical input
power is not reduced quickly. Large turbo-alternators, with low-inertia rotor designs, do not have a high over
speed tolerance. Trapped steam in a turbine, downstream of a valve that has just closed, can rapidly lead to over
speed. To reduce the risk of over speed damage, it may be desirable to interlock tripping of the circuit breaker and
the mechanical input with a low forward power check. This ensures that the generator circuit breaker is opened
only after the mechanical input to the prime mover has been removed, and the output power has reduced enough
such that overspeeding is unlikely. This delay in tripping the circuit breaker may be acceptable for non-urgent
protection trips (e.g. stator earth fault protection for a high impedance earthed generator). For urgent trips
however (e.g. stator current differential protection), this Low Forward Power interlock should not be used.

3.1 UNDERPOWER PROTECTION IMPLEMENTATION

Underpower Protection is implemented under the path SETPOINTS\PROTECTION\GROUP [1-4]\POWER
\UNDEROWER\UNDERPOWER 1
The UNDERPOWER Protection element provides multiple stages of directional underpower for both active and
reactive power. The directional element can be configured as forward or reverse and can activate single-phase or
three-phase trips.
The elements use three-phase power and single phase power measurements as the energising quantity. A start
condition occurs when two consecutive measurements fall below the setting threshold. A trip condition occurs if
the start condition is present for the set trip time. This can be inhibited by the VTS slow block and pole dead logic if
desired.
The Start and Trip timer resets if the power exceeds the drop-off level or if an inhibit condition occurs. The reset
mechanism is similar to the overcurrent functionality for a pecking fault condition, where the percentage of
elapsed time for the operate timer is memorised for a set reset time delay. If the Start condition returns before the
reset timer has timed out, the operate time initialises from the memorised travel value. Otherwise the memorised
value is reset to zero after the reset time times out.

3.2 UNDERPOWER LOGIC

P<1 3PhStart
3 Phase Watts
3 Phase VA
P<1 3Ph Watt & DT
1 & P<1 3Ph Trip
P<1 3Ph VAR

P<1 Mode P<1TimeDelay

Active -1 X &
Reactive

P<1Direction
Forward
Reverse
Note: This diagram does not show all stages . Other stages follow similar principles.
P<1 Function
Enabled

P<1 Inhibit V06701

Figure 90: Underpower logic

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Chapter 12 - Power Protection Functions P14D

3.3 APPLICATION NOTES

3.3.1 LOW FORWARD POWER CONSIDERATIONS

The Low Forward Power protection can be arranged to interlock ‘non-urgent’ protection tripping using the
programmable scheme logic. It can also be arranged to provide a contact for external interlocking of manual
tripping. To prevent unwanted alarms and flags, a Low Forward Power protection element can be disabled when
the circuit breaker is opened via Pole Dead logic.
The Low Forward Power protection can also be used to provide loss of load protection when a machine is
motoring. It can be used for example to protect a machine which is pumping from becoming unprimed, or to stop
a motor in the event of a failure in the mechanical transmission.
A typical application would be for pump storage generators operating in the motoring mode, where there is a need
to prevent the machine becoming unprimed which can cause blade and runner damage. During motoring
conditions, it is typical for the protection to switch to another setting group with the low forward power enabled
and correctly set and the protection operating mode set to Reverse.
A low forward power element may also be used to detect a loss of mains or loss of grid condition for applications
where the distributed generator is not allowed to export power to the system.

3.3.2 LOW FORWARD POWER SETTING GUIDELINES

Each stage of power protection can be selected to operate as a forward power stage by setting P<(n) Direction to
Forward.
When required for interlocking of non-urgent tripping applications, the threshold setting of the low forward power
protection function should be less than 50% of the power level that could result in a dangerous overspeed
condition on loss of electrical loading.
When required for loss of load applications, the threshold setting of the low forward power protection function, is
system dependent, however, it is typically set to 10 - 20% below the minimum load. The operating mode should be
set to operate for the direction of the load current, which would typically be reverse for a pump storage machine
application where Forward is the Generating direction and Reverse is the motoring direction.
For interlocking non-urgent trip applications the time delay associated with the low forward power protection
function could be set to zero. However, some delay is desirable so that permission for a non-urgent electrical trip is
not given in the event of power fluctuations arising from sudden steam valve/throttle closure. A typical time delay
is 2 seconds.
For loss of load applications the pick-up time delay is application dependent but is normally set in excess of the
time between motor starting and the load being established. Where rated power cannot be reached during
starting (for example where the motor is started with no load connected) and the required protection operating
time is less than the time for load to be established then it will be necessary to inhibit the power protection during
this period. This can be done in the PSL using AND logic and a pulse timer triggered from the motor starting to
block the power protection for the required time.
When required for loss of mains or loss of grid applications where the distributed generator is not allowed to
export power to the system, the threshold setting of the reverse power protection function, should be set to a
sensitive value, typically <2% of the rated power.
The low forward power protection function should be time-delayed to prevent false trips or alarms being given
during power system disturbances or following synchronisation. A time delay setting, of 5 s should be applied
typically.
The delay on the reset timers would normally be set to zero.
To prevent unwanted alarms and flags, the protection element can be disabled when the circuit breaker is open
via Pole Dead logic.

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AUTORECLOSE
Chapter 13 - Autoreclose P14D

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P14D Chapter 13 - Autoreclose

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 215
Introduction to 3-phase Autoreclose 216
Implementation 217
Autoreclose Function Inputs 218
Autoreclose Function Outputs 221
Autoreclose Function Alarms 223
Autoreclose Operation 224
Operating Modes 225
Setting Guidelines 241

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2 INTRODUCTION TO 3-PHASE AUTORECLOSE

It is known that approximately 80 - 90% of faults are transient in nature. This means that most faults do not last
long and are self-clearing. 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.
A transient fault, such as an insulator flashover, is a self-clearing ‘non-damage’ fault. The flashover will cause one
or more circuit breakers to trip, but it may also have the effect of clearing the fault. If the fault clears itself, the fault
does not recur when the line is re-energised.
The remaining 10 – 20% of faults are either semi-permanent or permanent. A small tree branch falling on the line
could cause a semi-permanent fault. Here the cause of the fault would not be removed by the immediate tripping
of the circuit, but could 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 supply can be
restored.
In the majority of fault incidents, if the faulty line is immediately tripped out, and time is allowed for the fault arc to
deionise, reclosure of 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 HV/MV distribution networks, autoreclosing is applied mainly to radial feeders, where system stability problems
do not generally arise. The main advantages of using Autoreclose are:
● Minimal interruption in supply to the consumer
● Reduction of operating costs - fewer man hours in repairing fault damage and the possibility of running
unattended substations
● With Autoreclose, instantaneous protection can be used which means shorter fault durations. This in turn
means less fault damage and fewer permanent faults

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 autoreclosing, 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 auto-
reclosing 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 autoreclosing 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 IMPLEMENTATION
Autoreclose functionality is a software option, which is selected when ordering the device, so this description only
applies to models with this option.
Autoreclose works for phase overcurrent (POC) earth fault (EF) and sensitive earth fault (SEF) protection. It is
implemented in the under the path SETPOINTS\CONTROL\AUTORECLOSE
The Autoreclose function can be set to perform a single-shot, two-shot, three-shot or four-shot cycle. You select
this by the Number of Shots setting in the AR (n) Setup menu. You can also initiate a separate Autoreclose cycle for
the SEF protection, with a different number of shots, selected by the Number SEF Shots. Dead times for all shots
can be adjusted independently.
An Autoreclose cycle can be initiated internally by operation of a protection element, or externally by a separate
protection device.At the end of the relevant dead time, an Auto Close signal is given, providing it is safe for the
circuit breaker to close. This is determined by checking that certain system conditions are met as specified by the
System Checks functionality.
It is safe to close the circuit breaker providing that:
● only one side of the circuit breaker is live (either dead line / live bus, or live line / dead bus), or
● if both bus and line sides of the circuit breaker are live, the system voltages are synchronised.

In addition, the energy source powering the circuit breaker (for example the closing spring) must be fully charged.
This is indicated from the CB Healthy input.
When the CB has closed, the reclaim time starts. If the circuit breaker does not trip again, the Autoreclose function
resets at the end of the set reclaim time. If the protection operates during the reclaim time the device either
advances to the next shot in the Autoreclose cycle, or if all reclose attempts have been made, goes to lockout.
CB Status signals must also be available, so the default setting for CB Status Input should be modified according
to the application. The default PSL requires 52A, 52B and CB Healthy logic inputs, so a setting of both 52A and 52B
would be required for the CB Status Input if used with the default PSL.

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4 AUTORECLOSE FUNCTION INPUTS

The Autoreclose function has several logic inputs, which can be mapped to any of the opto-inputs or to one or
more of the output signals generated by the PSL. The functions of these inputs are described below.

4.1 CB HEALTHY
It is necessary to establish if there is sufficient energy in the circuit breaker (spring charged, gas pressure healthy,
etc.) before the CB can be closed. This CB Healthy input is used to ensure this before initiating a CB closed 3ph
command. If on completion of the dead time, the CB Healthy input is low, and remains low for a period given by
the CB Healthy Time timer, lockout will result and the circuit breaker will remain open.
The majority of circuit breakers are only capable of providing a single trip-close-trip cycle, in which case the CB
Healthy signal would stay low after one Autoreclose shot, resulting in lockout.
This check can be disable by setting CB Healthy to on, whereby the signal defaults to high state.

4.2 BLOCK AR
The Block AR input blocks the Autoreclose function and causes a lockout. It can be used when protection
operation without Autoreclose is required. A typical example is on a transformer feeder, where Autoreclose may be
initiated by the feeder protection but blocked by the transformer protection.

4.3 RESET LOCKOUT

The Reset Lockout input can be used to reset the Autoreclose function following lockout. It also resets any
Autoreclose alarms, provided that the signals that initiated the lockout have been removed.

4.4 AR AUTO MODE

The AR Auto Mode input is used to select the Auto operating mode. In this mode, the Autoreclose function is in
service.

4.5 AR LIVELINE MODE

The AR LiveLine Mode input is used to select the Live Line operating mode when Autoreclose is out of service and
all blocking of instantaneous protection by Autoreclose is disabled. This operating mode takes precedence over all
other operating modes for safety reasons, as it indicates that utility personnel are working near live equipment.

4.6 TELECONTROL MODE

The Telecontrol input is used to select the Telecontrol operating mode so that the Auto and Non-auto modes of
operation can be selected remotely.

4.7 LIVE/DEAD CCTS OK (LIVE/DEAD CIRCUITS OK)

The LiveDead Ccts OK signal is a signal indicating the status of the Live Line / Dead Bus or Live Bus / Dead Line
system conditions (High = OK, Low = Not OK). The logic required can be derived in the PSL from the Live Line, Dead
Line, Live Bus and Dead Bus signals in the System Check logic (if applicable), or it can come from an external
source depending on the application.

4.8 AR SYS CHECKS (AR SYSTEM CHECKS)

This signal can also be mapped to an opto-input, to allow the IED to receive a signal from an external system
monitoring device, indicating that the system conditions are suitable for CB closing. This should not normally be
necessary, since the IED has comprehensive built in system check functionality.

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4.9 EXT AR PROT TRIP (EXTERNAL AR PROTECTION TRIP)

The Ext AR Prot Trip signal allows Autoreclose initiation by a Trip from a separate protection device.

4.10 EXT AR PROT START (EXTERNAL AR PROTECTION START)

The Ext AR Prot Strt signal allows Autoreclose initiation by a Start from a separate protection device.

4.11 DAR COMPLETE (DELAYED AUTORECLOSE COMPLETE)

Some utilities require Delayed Autoreclose (DAR) functionality.
The DAR Complete signal can, if required, be mapped in PSL to provide a short pulse when a CB Close command is
given at the end of the dead time. If DAR Complete is activated during an Autoreclose cycle, the output signal DAR
in Progress resets, even though the reclaim time may still be running, and AR in Progress remains set until the end
of the reclaim time.
For most applications, DAR complete can be ignored (not mapped in PSL). In such cases, DAR in Progress operates
and resets in parallel with AR in Progress.

4.12 CB IN SERVICE (CIRCUIT BREAKER IN SERVICE)

The CB In Service signal must remain asserted when protection operates if autoreclose is to be initiated. For most
applications, it can be mapped to CB Closed 3ph. More complex PSL mapping can be programmed if required, for
example where it is necessary to confirm not only that the CB is closed but also that the line and/or bus VT is
actually live up to the instant of protection operation.

4.13 AR RESTART
In some applications, it is sometimes necessary to initiate an Autoreclose cycle by means of connecting an
external signal to an opto-input. This would be when the normal interlock conditions are not all satisfied, i.e. when
the CB is open and the associated feeder is dead. If the AR Restart input is mapped to an opto-input, activation of
that opto-input will initiate an Autoreclose cycle irrespective of the status of the CB in Service input, provided the
other interlock conditions, are still satisfied.

4.14 DT OK TO START (DEAD TIME OK TO START)

This is an optional extra interlock in the dead time initiation logic. In addition to the CB being open and the
protection reset, DT OK To Start has to be set high to allow the dead time function to be primed after an AR cycle
has started. Once the dead time function is primed, this signal has no further affect – the dead time function stays
primed even if the signal subsequently goes low. A typical PSL mapping for this input is from the Dead Line signal
from the System Check logic. This would enable dead time priming only when the feeder has gone dead after CB
tripping. If this extra dead time priming interlock is not required, DT OK To Start is set to On, and it will default to a
high state.

4.15 DEADTIME ENABLED

This is an optional interlock in the dead time logic. This signal has to be high to allow the dead time to run. If this
signal goes low, the dead time stops and resets, but stays primed, and will restart from zero when it goes high
again. A typical PSL mapping is from the CB Healthy input or from selected signals from the System Check logic. It
could also be mapped to an opto-input to provide a 'hold off' function for the follower CB in a 'master/follower'
application with 2 CBs. If this optional interlock is not required, DeadTime Enabled is set to On, and it will default to
a high state.

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4.16 AR INIT TRIPTEST (INITIATE TRIP TEST)

If AR Init TripTest is mapped to an opto-input, and that input is activated momentarily, the IED generates a CB trip
output via AR Trip Test. The default PSL then maps this to output to the trip output relay and initiates an
Autoreclose cycle.

4.17 AR SKIP SHOT 1

If AR Skip Shot 1 is mapped to an opto-input, and that input is activated momentarily, the IED logic will cause the
Autoreclose sequence counter to increment by 1. This will decrease the available number of reclose shots and will
lockout the re-closer.

4.18 INH RECLAIM TIME (INHIBIT RECLAIM TIME)

If Inh Reclaim Time is mapped to an opto-input, and that input is active at the start of the reclaim time, the IED
logic will cause the reclaim timers to be blocked.

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5 AUTORECLOSE FUNCTION OUTPUTS

The Autoreclose function has several logic outputs, which can be assigned to output relay contacts or the PSL. The
functions of these outputs are described below.

5.1 AR IN PROGRESS
This signal is present during the complete re-close cycle from the start of protection to the end of the reclaim time
or lockout.

5.2 DAR IN PROGRESS

This operates together with the AR In Progress signal at the start of Autoreclose. If DAR Complete does not
operate, DAR in Progress remains operated until AR In Progress resets at the end of the cycle. If DAR Complete
goes high during the Autoreclose cycle, DAR in Progress resets.

5.3 SEQUENCE COUNTER STATUS SIGNALS

During each Autoreclose cycle a sequence Counter increments by 1 after each fault trip and resets to zero at the
end of the cycle.
● AR SeqCounter 0 is set when the counter is at zero
● AR SeqCounter 1 is set when the counter is at 1
● AR SeqCounter 2 is set when the counter is at 2
● AR SeqCounter 3 is set when the counter is at 3
● AR SeqCounter 4 is set when the counter is at 4

5.4 SUCCESSFUL CLOSE

The Successful Close output indicates that an Autoreclose cycle has been successfully completed. A successful
Autoreclose signal is given after the protection has tripped the CB and it has reclosed successfully. The successful
Autoreclose output is reset at the next CB trip or from one of the reset lockout methods.

5.5 AR IN SERVICE
The AR In Service output indicates whether the Autoreclose is in or out of service. Autoreclose is In Service when
the device is in Auto mode and Out of Service when in the Non Auto and Live Line modes.

5.6 AR BLK MAIN PROT (BLOCK MAIN PROTECTION)

The AR Blk Main Prot signal blocks the DT-only stages (instantaneous stages) of the main current protection
elements. You block the instantaneous stages for each trip of the Autoreclose cycle using the Trip 1 Main, Trip 2
Main, Trip 3 Main, Trip 4 Main and Trip 5 Main settings.

5.7 AR BLK SEF PROT (BLOCK SEF PROTECTION)

The AR Blk SEF Prot signal blocks the DT-only stages (instantaneous stages) of the SEF protection elements. You
block the instantaneous SEF stages for each trip of the Autoreclose cycle using the Trip 1 SEF, Trip 2 SEF, Trip 3
SEF, Trip 4 SEF and Trip 5 SEF settings.

5.8 RECLOSE CHECKS

The Reclose Checks output indicates that the AR System Checks are in progress.

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5.9 DEADTIME IN PROG

The DeadTime in Prog output indicates that the dead time is in progress. This signal is set when Reclose Checks is
set AND input Dead TimeEnabled is high. This may be useful during commissioning to check the operation of the
Autoreclose cycle.

5.10 DT COMPLETE (DEAD TIME COMPLETE)

DT Complete (Dead time complete) operates at the end of the set dead time, and remains operated until either the
scheme resets at the end of the reclaim time or a further protection operation or Autoreclose initiation occurs. It
can be applied purely as an indication, or included in PSL mapping to logic input DAR Complete.

5.11 AR SYNC CHECK (AR SYNCHRONISATION CHECK)

AR Sync Check indicates that the Autoreclose Synchronism checks are satisfactory. This is when the
synchronisation check module confirms an In-Synchronism condition.

5.12 AR SYSCHECKS OK (AR SYSTEM CHECKS OK)

AR SysChecks OK indicates that the Autoreclose System checks are satisfactory. This is when any selected system
check condition (synchronism check, live bus/dead line etc.) is confirmed.

5.13 AUTO CLOSE

The Auto Close output indicates that the Autoreclose logic has issued a Close signal to the CB. This output feeds
a signal to the control close pulse timer and remains on until the CB has closed. This signal may be useful during
commissioning to check the operation of the Autoreclose cycle.

5.14 PROTECTION LOCKT (PROTECTION LOCKOUT)

Protection Lockt (Protection Lockout) operates if AR lockout is triggered by protection operation either during the
inhibit period following a manual CB close or when the device is in Non-auto or Live Line mode.

5.15 RESET LCKOUT ALM (RESET LOCKOUT ALARM)

Reset Lckout Alm operates when the device is in Non-auto mode, if the Reset Lockout setting is set to Select
Non Auto.

5.16 RECLAIM IN PROG

Reclaim in Prog output indicates that a reclaim timer is in progress and will drop-off once the reclaim timer resets.

5.17 RECLAIM COMPLETE

Reclaim Complete operates at the end of the set reclaim time and is a fast reset. To maintain the output indication
a dwell timer has to be implemented in PSL.

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6 AUTORECLOSE FUNCTION ALARMS

The following DDB signals will produce an alarm. These are described below.

6.1 AR NO SYS CHECK

The AR No Sys Check alarm indicates that the system voltages are not suitable for autoreclosing at the end of the
system check time (setting Sys Check Time), leading to a lockout condition. This alarm is latched and must be reset
manually.

6.2 AR CB UNHEALTHY
The AR CB Unhealthy alarm indicates that the CB Healthy input was not energised at the end of the CB Healthy
Time, leading to a lockout condition. This alarm is latched and must be reset manually.

6.3 AR LOCKOUT
The AR Lockout alarm indicates that the device is in a lockout status and that further re-close attempts will not be
made. This alarm can configured to reset automatically (self-reset) or manually as determined by the setting Reset
Lockout by.

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7 AUTORECLOSE OPERATION
The Autoreclose function is a complex function consisting of several modules interacting with one another. This is
described in terms of separate logic diagrams, which link together by means of Internal signals (depicted by the
pink-coloured boxes.

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8 OPERATING MODES
The Autoreclose function has three operating modes:
● Auto Mode: Autoreclose is in service
● Non-auto Mode: Autoreclose is out of service AND the chosen protection functions are blocked if setting AR
Deselected = Block Inst Prot.
● Live Line Mode: Autoreclose is out of service, but protection functions are NOT blocked, even if setting AR
Deselected = Block Inst Prot.

Note:
Live Line Mode provides extra security for live line working on the protected feeder.

You can select the Autoreclose operating mode according to application requirements. The basic method of mode
selection is determined by the setting AR Mode Select as summarised in the following table:
AR Mode Select Setting Description
Command Mode Auto or Non-auto mode selection is determined by the command setting Autoreclose Mode.
Auto or Non-auto mode selection is determined by an opto-input mapped to AR Auto Mode
Opto Set Mode If the AR Auto Mode input is high, Auto operating mode is selected. If the AR Auto Mode input is low, Non-
Auto operating mode is selected.
Auto or Non-auto mode selection is controlled by the Telecontrol Mode input. If the Telecontrol Mode input
User Set Mode is high, the setting Autoreclose Mode is used to select Auto or Non Auto operating mode. If the Telecontrol
Mode input is low, it behaves as for the Opto Set Mode setting.
Auto or Non-auto mode selection is determined by the falling edge of AR Auto Mode signal. If the
Telecontrol input is high, the operating mode is toggled between Auto and Non Auto Mode on the falling
Pulse Set Mode
edge of the AR Auto Mode signal as it goes low. The Auto Mode pulses are produced by the SCADA system.
If the Telecontrol input is low, it behaves as for the Opto Set Mode setting.

The Live Line Mode is controlled by AR LiveLine Mode. If this is high, the scheme is forced into Live Line Mode
irrespective of the other signals.

8.1 FOUR-POSITION SELECTOR SWITCH IMPLEMENTATION

It is quite common for some utilities to apply a four position selector switch to control the mode of operation. This
application can be implemented using the signals AR LiveLine Mode, AR Auto Mode and Telecontrol Mode. This is
demonstrated in the following diagram.

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MODE SETTINGS
4 POSITION SELECTOR SWITCH AUTO COMMAND MODE
OPTO SET MODE
USER SET MODE

NON AUTO PULSE SET MODE

OPERATING MODES

TELECONTROL NON AUTO

TELECONTROL
LOGIC INPUT

AUTO AUTO
AUTO
LOGIC INPUT

LIVE LINE LIVE LINE

LIVE LINE
LOGIC INPUT

IED

E00500

Figure 91: Four-position selector switch implementation

The required logic truth table for this arrangement is as follows:

Switch position AR Auto Mode Telecontrol Mode AR Live Line Mode
Non-auto 0 0 0
Telecontrol 0 or SCADA pulse 1 0
Auto 1 0 0
Live Line 0 0 1

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8.2 OPERATING MODE SELECTION LOGIC

Auto-Reclose
Disable Autoreclose disabled
Enable
& Live Line Mode (int)
AR LiveLine Mode

AR Mode Select
Opto Set Mode
&
&
User Set Mode Non Auto Mode
&
&
Pulse Set Mode
& &
&
Command Mode
& 1 &
1
S
Autoreclose Mode Q Auto Mode (int)
&
Auto R
No Operation 1
&
Non Auto

&

&

& Enable

Output pulse on
rising edge of µTele ¶

& Enable

Output pulse on &

AR Auto Mode falling edge of µAuto¶

&

Telecontrol Mode
V06200

Figure 92: Autoreclose mode select logic

The mode selection logic includes a 100 ms delay for Auto Mode, Telecontrol and Live Line logic inputs, to ensure
a predictable change of operating modes. This is of particular importance for the case when the four position
switch does not have 'make-before-break' contacts. The logic also ensures that when the switch is moved from
Auto or Non-Auto position to Telecontrol, the scheme remains in the previously selected mode (Auto or Non-Auto)
until a different mode is selected by remote control.
For applications where live line operating mode and remote selection of Auto/Non-auto modes are not required, a
simple two position switch can be arranged to activate Auto Mode input. In this case, the Live Line and
Telecontrol inputs would be unused.

8.3 AUTORECLOSE INITIATION

Autoreclose is usually initiated from the IED's internal protection function. Different stages of phase overcurrent
and earth fault protection can be programmed to initiate or block the main Autoreclose function. The stages of
sensitive earth fault protection can also be programmed to initiate or block both the Main Autoreclose function or
the SEF Autoreclose function.
The associated settings are found in the path (AUTORECLOSE\AR INITIATE.
For example:
If Phase IOC1 is set to Initiate Main AR, operation of the Phase IOC 1 protection stage will initiate
Autoreclose

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If ISEF IOC>1 AR is set to No Action, operation of the ISEF>1 protection stage will lead to a CB trip but no
reclose. Otherwise it can be used to initiate Main autoreclose or SEF autoreclose.

Note:
A selection must be made for each protection stage that is enabled.

A separate protection device may also initiate Autoreclose. The Autoreclose can be initiated from a protection Trip,
or when sequence coordination is required from a protection Start. If external triggering of Autoreclose is required,
the following DDB signals should be mapped to opto-inputs:
● Ext AR Prot Trip
● Ext AR Prot Strt (if applicable)

In addition, the setting Ext Prot should be set to Initiate Main AR.
Although a protection start and a protection trip can initiate an AR cycle, several checks still have to be performed
before the initialisation signal is given. Some of the checks are listed below:
● Auto Mode has been selected
● Live line mode is disabled
● The number of main protection and SEF shots have not been reached
● Sequence co-ordination is enabled (for protection start to initiate AR. This is not necessary if a protection
trip is doing the initiating)
● The CB in Service DDB signal is high

Note:
The relevant protection trip must be mapped to the Trip Command In DDB.

8.3.1 START SIGNAL LOGIC

Ext AR Prot Strt

Ext Prot &
Initiate Main AR

PIOC I>1 Start

Phase IOC1 &
Initiate Main AR

IN2>1 IOC Start

IN2>1 IOC 1 & 1 Main Protection Start
Initiate Main AR

IN>1 IOC Start Note: This diagram does not show all
IN1 IOC 1 & stages and TOC elements. Other
Initiate Main AR
stages and TOC elements follow
similar principles.
ISEF>1 IOC Start
ISEF IOC 1 &
Initiate Main AR
Initiate SEF AR SEF Protection Start

V06201

Figure 93: Start signal logic

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8.3.2 TRIP SIGNAL LOGIC

AR Init Trip Test
Test AutoReclose 1 AR Trip Test
AR Init Trip Test
3 pole Test
Note: This diagram does not
Ext AR Prot Trip show all stages and TOC. Other
Ext Prot & stages and TOC elements follow
Initiate Main A R similar principles.

Trip Command In

Phase IOC I>1 Trip

Phase IOC 1 &
Initiate Main A R

IN1>1 IOC Trip

IN1 IOC 1 & 1 & Main Protection Trip
Initiate Main A R

IN2 IOC 1
N2 IOC 1 &
Initiate Main A R

ISEF>1 IOC Trip

ISEF IOC 1 &
Initiate Main A R
Initiate SEF AR & SEF Protection Trip

V06202

Figure 94: Trip signal logic

8.3.3 BLOCKING SIGNAL LOGIC

CB Fail Alarm

Block AR

Trip Command In

PIOC I>1 Trip

Phase IOC 1 &
Block AR

IN1 IOC 1
IN1 IOC 1 &
Block AR

IN2>1 IOC Trip 1 & 1 Block AR

IN2 IOC 1 &

Block AR
Any Backup Protection
ISEF>1 IOC Trip
ISEF IOC 1 &
Block AR
V06214

Figure 95: Blocking signal logic

8.3.4 SHOTS EXCEEDED LOGIC

Main Protection Start

& S
SC Count >= Main Shots Q Main High Shots
R

SEF Protection Start

& S
SC Count >= SEF Shots Q SEF High Shots
R

V00504

Figure 96: Shots Exceeded logic

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8.3.5 AR INITIATION LOGIC

Auto Mode (int)
&
Lockout Alarm

Main Protection Trip

1
Main Protection Start
&
Main High Shots

SEF Protection Trip

1
SEF Protection Start
&
SEF High Shots

Sequence Co-ord
Enabled
Disabled
Autoreclose Start

& S
1
Q DAR in Progress
R
CB in Service Autoreclose Initiate
S
Autoreclose Inhibit Q AR in Progress
R
AR Restart Increment on falling AR SeqCounter 0
edge
DAR Complete AR SeqCounter 1
1
AR SeqCounter 2
Lockout Alarm
AR SeqCounter 3
SC Counter
Reclaim Complete AR SeqCounter 4
Non Auto Mode 1 Reset SC Count > 4
Number of Shots SC Count >= Main Shots
Autoreclose Disabled
Number SEF Shots SC Count >= SEF Shots
Live Line Mode

V06204

Figure 97: AR initiation logic

8.4 BLOCKING INSTANTANEOUS PROTECTION FOR SELECTED TRIPS

Instantaneous protection may be blocked or not blocked for each trip in an Autoreclose cycle. This is selected
using the Trip (n) Main and Trip (n) SEF settings, where n is the number of the trip in the autoreclose cycle. These
allow the instantaneous elements of phase, earth fault and SEF protection to be selectively blocked for a CB trip
sequence. For example, if Trip 1 Main is set to No Block and Trip 2 Main is set to Block Inst Prot, the
instantaneous elements of the phase and earth fault protection will be available for the first trip but blocked
afterwards for the second trip during the Autoreclose cycle. The logic for this is shown below.

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AR SeqCounter 0

Trip 1 Main &

Block Inst Prot
No Block

AR SeqCounter 1

Trip 2 Main &

Block Inst Prot
No Block

AR SeqCounter 2

Trip 3 Main
& 1 Block Main Prot Trips
Block Inst Prot
No Block

AR SeqCounter 3

Trip 4 Main &

Block Inst Prot
No Block

AR SeqCounter 4
1
SC Count > 4
&
Trip 5 Main
Block Inst Prot
No Block

AR SeqCounter 0

Trip 1 SEF &

Block Inst Prot
No Block

AR SeqCounter 1

Trip 2 SEF &

Block Inst Prot
No Block

AR SeqCounter 2

Trip 3 SEF & 1 Block SEF Prot Trips

Block Inst Prot
No Block

AR SeqCounter 3

Trip 4 SEF
&
Block Inst Prot
No Block

AR SeqCounter 4
1
SC Count > 4
&
Trip 5 Main
Block Inst Prot
No Block

V00506

Figure 98: Blocking instantaneous protection for selected trips

8.5 BLOCKING INSTANTANEOUS PROTECTION FOR LOCKOUTS

Instantaneous protection can also be blocked for certain lockout conditions:

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It is blocked when the CB maintenance lockout counter or excessive fault frequency lockout has reached its
penultimate value.
For example, if the setting No. CB Ops Lock in the \SETPOINTS\MONITORING\CIRCUIT BREAKER\ CB 1 MONITOR
\CB1 HEALTH\FUNCTION is set to 100, the instantaneous protection can be blocked to ensure that the last CB trip
before lockout will be due to discriminative protection operation. This is controlled using the EFF Maint Lock
setting (Excessive Fault Frequency maintenance lockout). If this is set to Block Inst Prot, the instantaneous
protection will be blocked for the last CB Trip before lockout occurs.
Instantaneous protection can also be blocked when the IED is locked out, using the AR Lockout setting. It can also
be blocked after a manual close using the Manual Close setting. When the IED is in the Non-auto mode it can be
blocked by using the AR Deselected setting. The logic for these features is shown below.

Autoreclose disabled

Lockout Alarm

Pre-Lockout
&
EFF Maint Lock
Block Inst Prot
No Block

Block Main Prot Trips

& & &

Main Protection Start S

Q 1 & AR Blk Main Prot
1 R

Live Line Mode (int)

Block SEF Prot Trips

& & &

SEF Protection Start S

Q 1 & AR Blk SEF Prot
1 R

Live Line Mode (int)

Lockout Alarm

AR Lockout &
Block Inst Prot 1
No Block

Non Auto Mode

AR Deselected
&
Block Inst Prot
No Block

AR In Progress

CB Closed 3 ph &
1
Auto Mode (int) &
20ms
Autoreclose inhibit

Manual Close
Block Inst Prot
No Block

V00507

Figure 99: Blocking instantaneous protection for lockouts

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8.6 DEAD TIME CONTROL

When the setting CS AR Immediate is enabled, immediate re-closure of the circuit breaker is allowed providing
that both sides of the circuit breaker are live and in synchronism at any time after the dead time has started. This
allows for quicker load restoration, as it is not necessary to wait for the full dead time to expire.
If CS AR Immediate is disabled, or neither Line nor Bus are live, the dead timer will continue to run, if the DeadTime
Enabled signal is high. The DeadTime Enabled function could be mapped to an opto-input to indicate that the
circuit breaker is healthy. Mapping the DeadTime Enabled function in PSL increases the flexibility by allowing it to
be triggered by other conditions such as Live Line/Dead Bus. If DeadTime Enabled is not mapped in PSL, it is set to
On, so the dead time can run.
The dead time control logic is shown below.

Scheme 2 (Voltage models only)

AR with ChkSyn
Enable
&
Disable

1 &
AR Sync Check

1
DeatTime Enabled

AR SeqCounter 1 &

AR SeqCounter 2 & 1 DT Complete

& DeadTime in Prog

AR SeqCounter 3 &

AR SeqCounter 4 &

CB Open 3 ph
1

DT OK To Start & S
Q Reclose Checks
R

Autoreclose Start &

1 1

Autoreclose Initiate

AR In Progress

Sequence Co -ord
Enable
&
Disable

Start Dead t On
&
Protection Reset
CB Trips

V06207

Figure 100: Dead Time Control logic

8.6.1 AR CB CLOSE CONTROL

Once the dead time is completed or a synchronism check is confirmed, the Auto Close signal is given, provided
both the CB Healthy and the System Checks are satisfied. The Auto Close signal triggers a CB Close command via
the CB Control functionality.

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The AR CB Close Control Logic is as follows:

Reset Total AR
Yes Total Shot Counter
No (Increment on +ve edge)

CB Cls Fail
& t Auto Close
CB Open 3 ph 0

& Hold Reclaim Output

& SD
Q
R

& SD
DT Complete Q
R
Autoreclose Start &

Lockout Alarm
& S
CB Healthy Time
Q
R

CB Closed 3 ph

& t AR CB Unhealthy
0
CB Healthy
&
& t AR No Sys Check
AR SysChecks OK 0

V06208
Sys Check Time

Figure 101: AR CB Close Control logic

8.7 AR SYSTEM CHECKS

The permission to initiate an Autoreclose depends on the following AR system check settings. These are found in
the path (AUTORECLOSE under AR SYS CHECKS).
The AR SYSTEM CHECKS are as follows:
● Live/Dead Ccts: When enabled this setting will give an AR Check OK signal when the LiveDead Ccts OK
signal is high. This logic input DDB would normally be mapped in PSL to appropriate combinations of Line
Live, Line Dead, Bus Live and Bus Dead signals.
● No System Checks: When enabled this setting completely disables system checks thus allowing
Autoreclose initiation under any system conditions.
● SysChk on Shot 1: Can be used to disable system checks on the first AR shot.
● AR with ChkSyn: Only allows Autoreclose when the system satisfies the Check Sync Stage 1 (CS1) settings in
the main SYSTEM CHECKS menu.
The AR System Check logic is as follows:

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AR Sys Checks
1 AR SysChecks OK
SysChk on Shot 1
Enabled
&
AR SeqCounter 1

No system Checks
Enabled
1 AR SysChecks OK

Live/Dead Ccts
Enabled
&
LiveDead Ccts OK

AR with ChkSyn
Enabled
& AR Sync Check
Check Sync 1 OK

Reclose Checks

V06215

Figure 102: AR System Check logic

8.8 RECLAIM TIMER INITIATION

The tReclaim Extend setting allows you to control whether the timer is suspended from the protection start
contacts or not. When a setting of No Operation is used, the reclaim timer operates from the instant the CB is
closed and will continue until the timer expires. The Reclaim Time must therefore be set in excess of the time-
delayed protection operating time, to ensure that the protection can operate before the Autoreclose function is
reset.
For certain applications it is advantageous to set tReclaim Extend to On Prot Start. This facility allows the
operation of the reclaim timer to be suspended after CB re-closure by a signal from the main protection start or
SEF protection start signals. This feature ensures that the reclaim time cannot time out and reset the Autoreclose
before the time delayed protection has operated.
Since the reclaim timer will be suspended, it is unnecessary to use a timer setting in excess of the protection
operating time, therefore a short reclaim time can be used. Short reclaim time settings can help to prevent
unnecessary lockout for a succession of transient faults in a short period, for example during a thunderstorm.

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Lockout Reset
Yes

HMI Clear 1
Reset Lockout
Reset
Lockout alarm t
& Lockout
CB Closed 3 ph 0

Reset Lockout by
CB Close
User Interface
Man Close RstDly
Reset Lckout Alm

CB Open 3 ph

& S
Auto close Q
1 & S
R
Q Successful close
CB Closed 3 ph R
&
AR In Progress
Reclaim In Prog
Inh Reclaim Time
tReclaim Extend t
&
On Prot Start 0 & Reclaim Complete
&
No Operation 1

Main Protection Start

1
SEF Protection Start

DT Complete
1
Autoreclose Start &
Sequence Co -ord Reclaim Time 3
Enabled

Hold Reclaim Output

AR SeqCounter 1
& nc Successful
Reset 1st shot Counter
AR SeqCounter 2
& nc Successful
Reset 2 nd shot Counter
AR SeqCounter 3
& nc Successful
Reset 3rd shot Counter
AR SeqCounter 4
& nc Successful
Reset 4 th shot Counter
CB Open 3 ph
& nc Persistant
AR Lockout
Reset Faults Counter

Reset Total AR
Yes

V06210

Figure 103: Reclaim Time logic

8.9 AUTORECLOSE INHIBIT

To ensure that autoreclosing is not initiated for a manual CB closure on to a pre-existing fault (switch on to fault),
the AR on Man Close setting can be set to Inhibited. With this setting, Autoreclose initiation is inhibited for a period
equal to setting AR Inhibit Time following a manual CB closure. The logic for AR Inhibit is as follows:

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AR Inhibit Time
CB Closed 3 ph Pulse to start inhibit timer
&
1 t
AR In Progress & Autoreclose inhibit
0
AR on Man Close
Inhibite d
Enabled
&
Main Protection St art
1
SEF Protection Start

Auto Mo de (int)

V00512

Figure 104: AR Initiation inhibit

If a protection operation occurs during the inhibit period, Autoreclose is not initiated. A further option is provided
by setting Man Close on Flt. If this is set to Lockout, Autoreclose is locked out (AR Lockout) for a fault during the
inhibit period following manual CB closure. If Man Close on Flt is set to No Lockout, the CB trips without
reclosure, but Autoreclose is not locked out.
You may need to block selected fast non-discriminating protection in order to obtain fully discriminative tripping
during the AR initiation inhibit period following CB manual close. You can do this by setting Manual Close to
Block Inst Prot. A No Block setting will enable all protection elements immediately on CB closure.
If setting AR on Man Close is set to Enabled, Autoreclose can be initiated immediately on CB closure, and settings
AR Inhibit Time, Man Close on Flt and Manual Close are irrelevant.

8.10 AUTORECLOSE LOCKOUT

If protection operates during the reclaim time following the final reclose attempt, the IED is driven to lockout and
the Autoreclose function is disabled until the lockout condition is reset. This produces the alarm, AR Lockout. The
Block AR input blocks Autoreclose and causes a lockout if Autoreclose is in progress.
Autoreclose lockout can also be caused by the CB failing to close due to an unhealthy circuit breaker (CB springs
not charged or low gas pressure) or if there is no synchronisation between the system voltages. These two
conditions are indicated by the alarms CB Unhealthy and AR No Sys Check This is shown in the AR Lockout logic
diagram as follows:

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Reclaim Complete
&
CB Open 3 ph

DT complete &

Autoreclose Start

AR in Progress
& S
Block Autoreclose Q
R

AR CB Unhealthy
1
CB State Unknown

CB Cls Fail

S
HMI Clear Q AR Lockout
1 R
Lockout Reset
Yes

Reset
Lockout
Reset Lockout

Lockout Alarm
&
CB Closed 3 ph

Reset Lockout by
User Interface
CB Close

Reset Lckout Alm

Main Protection Trip

Autoreclose Initiate &

Main High Shots

SEF Protection Trip

Autoreclose Initiate &

1
SEF High Shots

AR No Sys Check

Protection Lockt

V06212

Figure 105: Overall Lockout logic

AR lockout may also be due to a protection operation when the IED is in the Live Line or Non-auto modes when the
setting Trip AR Inactive is set to Lockout. Autoreclose lockout can also be caused by a protection operation after
manual closing during the AR Inhibit Time when the Man Close on Flt setting is set to Lockout. This is shown as
follows:

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Ext. Trip 3ph

Main Protection Trip 1

&
SEF Protection Trip 1 Protection Lockt

Autoreclose inhibit

Man Close on Flt

Lockout
No Lockout

Live Line Mode

Non Auto mode 1 &

Lockout Alarm

Trip AR Inactive
Lockout
No Lockout

V06213

Figure 106: Lockout for protection trip when AR is not available

The Reset Lockout input can be used to reset the Autoreclose function following lockout and reset any Autoreclose
alarms, provided that the signals that initiated the lockout have been removed. Lockout can also be reset from the
clear key or the command Lockout Reset.
The Reset Lockout by setting is used to enable or disable reset of lockout automatically from a manual close after
the manual close time Man Close RstDly or to enable/disable the resetting of lockout when the IED is in the Non-
auto operating mode. The reset lockout methods are summarised in the following table:
Reset Lockout Method When Available?
User Interface via the Clear key.
Always
Note: This will also reset all other protection flags
User interface via command Lockout Reset Always
Opto-input Reset lockout Always
Following a successful manual close if Reset Lockout by is set to CB Close Only when set
By selecting Non-Auto mode, provided Reset Lockout by is set to Select NonAuto Only when set

8.11 SEQUENCE CO-ORDINATION

The Sequence Co-ord setting in the AUTORECLOSE menu allows sequence co-ordination with other protection
devices, such as downstream pole-mounted reclosers.
The main protection start or SEF protection start signals indicate when fault current is present, advance the
sequence count by one and start the dead time, whether the CB is open or closed. When the dead time is
complete and the protection start inputs are low, the reclaim timer is initiated.
You should program both the upstream and downstream Autoreclose IEDs with the same number of shots to
lockout and number of instantaneous trips before instantaneous protection is blocked. This will ensure that for a
persistent downstream fault, both Autoreclose IEDs will be on the same sequence count and will block
instantaneous protection at the same time. When sequence co-ordination is disabled, the circuit breaker has to be
tripped to start the dead time, and the sequence count is advanced by one.
When using sequence co-ordination for some applications such as downstream pole-mounted reclosers, it may be
desirable to re-enable instantaneous protection when the recloser has locked out. When the downstream recloser
has locked out there is no need for discrimination. This allows you to have instantaneous, then IDMT, then
instantaneous trips again during an Autoreclose cycle. Instantaneous protection may be blocked or not blocked
for each trip in an Autoreclose cycle using the Trip (n) Main and Trip (n) SEF settings, where n is the number of the
trip in the autoreclose cycle.

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8.12 SYSTEM CHECKS FOR FIRST RECLOSE

The SysChk on Shot 1 setting in the SYSTEM CHECKS sub menu of the AUTORECLOSE menu is used to enable or
disable system checks for the first reclose attempt in an Autoreclose cycle. This may be preferred when high speed
Autoreclose is applied, to avoid the extra time for a synchronism check. Subsequent reclose attempts in a multi-
shot cycle will, however, still require a synchronism check.

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9 SETTING GUIDELINES

9.1 NUMBER OF SHOTS

There are no clear cut rules for defining the number of shots for a particular application. Generally medium voltage
systems use only two or three shot Autoreclose schemes. However, in certain countries, for specific applications, a
four-shot scheme is used. A four-shot scheme has the advantage that the final dead time can be set sufficiently
long to allow any thunderstorms to pass before reclosing for the final time. This arrangement prevents
unnecessary lockout for consecutive transient faults.
Typically, the first trip, and sometimes the second, will result from instantaneous protection. Since most faults are
transient, the subsequent trips will be time delayed, all with increasing dead times to clear semi-permanent faults.
An important consideration is the ability of the circuit breaker to perform several trip-close operations in quick
succession and the affect of these operations on the circuit maintenance period.
On EHV transmission circuits with high fault levels, only one re-closure is normally applied, because of the damage
that could be caused by multiple re-closures.

9.2 DEAD TIMER SETTING

The choice of dead time is dependent on the system. The main factors that can influence the choice of dead time
are:
● Stability and synchronism requirements
● Operational convenience
● Load
● The type of circuit breaker
● Fault deionising time
● The protection reset time

9.2.1 STABILITY AND SYNCHRONISM REQUIREMENTS

It may be that the power transfer level on a specific feeder is such that the systems at either end of the feeder
could quickly fall out of synchronism if the feeder is opened. If this is the case, it is usually necessary to reclose the
feeder as quickly as possible to prevent loss of synchronism. This is called high speed autoreclosing (HSAR). In this
situation, the dead time setting should be adjusted to the minimum time necessary. This time setting should
comply with the minimum dead time limitations imposed by the circuit breaker and associated protection, which
should be enough to allow complete deionisation of the fault path and restoration of the full voltage withstand
level. Typical HSAR dead time values are between 0.3 and 0.5 seconds.
On a closely interconnected transmission system, where alternative power transfer paths usually hold the overall
system in synchronism even when a specific feeder opens, or on a radial supply system where there are no
stability implications, it is often preferred to leave a feeder open for a few seconds after fault clearance. This allows
the system to stabilise, and reduces the shock to the system on re-closure. This is called slow or delayed auto-
reclosing (DAR). The dead time setting for DAR is usually selected for operational convenience.

9.2.2 OPERATIONAL CONVENIENCE

When HSAR is not required, the dead time chosen for the first re-closure following a fault trip is not critical. It
should be long enough to allow any resulting transients resulting to decay, but not so long as to cause major
inconvenience to consumers who are affected by the loss of the feeder. The setting chosen often depends on
service experience with the specific feeder.
Typical first shot dead time settings on 11 kV distribution systems are 5 to 10 seconds. In situations where two
parallel circuits from one substation are carried on the same towers, it is often arranged for the dead times on the

P14DEnh-TM-EN-1.1 241
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two circuits to be staggered, e.g. one at 5 seconds and the other at 10 seconds, so that the two circuit breakers do
not reclose simultaneously following a fault affecting both circuits.
For multi-shot Autoreclose cycles, the second shot and subsequent shot dead times are usually longer than the
first shot, to allow time for semi-permanent faults to burn clear, and for the CB to recharge. Typical second and
third shot dead time settings are 30 seconds and 60 seconds respectively.

9.2.3 LOAD REQUIREMENTS

Some types of electrical load might have specific requirements for minimum and/or maximum dead time, to
prevent damage and minimise disruption. For example, synchronous motors are only capable of tolerating
extremely short supply interruptions without losing synchronism. In practise it is desirable to disconnect the motor
from the supply in the event of a fault; the dead time would normally be sufficient to allow a controlled shutdown.
Induction motors, on the other hand, can withstand supply interruptions up to typically 0.5 seconds and re-
accelerate successfully.

9.2.4 CIRCUIT BREAKER

For HSAR, the minimum dead time of the power system will depend on the minimum time delays imposed by the
circuit breaker during a tripping and reclose operation.
After tripping, time must be allowed for the mechanism to reset before applying a closing pulse, otherwise the
circuit breaker might fail to close correctly. This resetting time will vary depending on the circuit breaker, but is
typically 0.1 seconds.
Once the mechanism has reset, a CB Close signal can be applied. The time interval between energising the closing
mechanism and making the contacts is called the closing time. A solenoid closing mechanism may take up to 0.3
seconds. A spring-operated breaker, on the other hand, can close in less than 0.1 seconds.
Where HSAR is required, for the majority of medium voltage applications, the circuit breaker mechanism reset time
itself dictates the minimum dead time. This would be the mechanism reset time plus the CB closing time. A
solenoid mechanism is not suitable for high speed Autoreclose as the closing time is generally too long.
For most circuit breakers, after one reclosure, it is necessary to recharge the closing mechanism energy source
before a further reclosure can take place. Therefore the dead time for second and subsequent shots in a multi-
shot sequence must be set longer than the spring or gas pressure recharge time.

9.2.5 FAULT DE-IONISATION TIME

For HSAR, the fault deionising time may be the most important factor when considering the dead time. This is the
time required for ionised air to disperse around the fault position so that the insulation level of the air is restored.
You cannot accurately predict this, but you can obtain an approximation from the following formula:
Deionising time = (10.5 + ((system voltage in kV)/34.5))/frequency
Examples:
At 66 kV 50 Hz, the deionising time is approximately 0.25 s
At 132 kV 60 Hz, the deionising time is approximately 0.29 s

9.2.6 PROTECTION RESET TIME

It is essential that any time-graded protection fully resets during the dead time, so that correct time discrimination
will be maintained after reclosing on to a fault. For HSAR, instantaneous reset of protection is required. However at
distribution level, where the protection is predominantly made up of overcurrent and earth fault devices, the
protection reset time may not be instantaneous. In the event that the circuit breaker recloses on to a fault and the
protection has not fully reset, discrimination may be lost with the downstream protection. To avoid this condition
the dead time must be set in excess of the slowest reset time of either the local device or any downstream
protection.
Typical 11/33 kV dead time settings are as follows:

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1st dead time = 5 - 10 seconds

2nd dead time = 30 seconds
3rd dead time = 60 - 180 seconds
4th dead time = 1 - 30 minutes

9.3 RECLAIM TIMER SETTING

A number of factors influence the choice of the reclaim timer:
● Supply continuity: Large reclaim times can result in unnecessary lockout for transient faults.
● Fault incidence/Past experience: Small reclaim times may be required where there is a high incidence of
lightning strikes to prevent unnecessary lockout for transient faults.
● Spring charging time: For HSAR the reclaim time may be set longer than the spring charging time to ensure
there is sufficient energy in the circuit breaker to perform a trip-close-trip cycle. For delayed Autoreclose
there is no need as the dead time can be extended by an extra CB healthy check window time if there is
insufficient energy in the CB. If there is insufficient energy after the check window time the IED will lockout.
● Switchgear maintenance: Excessive operation resulting from short reclaim times can mean shorter
maintenance periods. A minimum reclaim time of more than 5 seconds 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 circuit breaker's duty rating.

The reclaim time must be long enough to allow any time-delayed protection initiating Autoreclose to operate.
Failure to do so would result in premature resetting of the Autoreclose scheme and re-enabling of instantaneous
protection. If this condition arose, a permanent fault would effectively look like a number of transient faults,
resulting in continuous autoreclosing, unless additional measures are taken such as excessive fault frequency
lockout protection.
Sensitive earth fault protection is applied to detect high resistance earth faults and usually has a long time delay,
typically 10 - 15 seconds. This longer time may have to be taken into consideration, if autoreclosing from SEF
protection. High resistance earth faults are rarely transient and may be a danger to the public. It is therefore
common practise to block Autoreclose by operation of sensitive earth fault protection and lockout the circuit
breaker.
A typical 11/33 kV reclaim time is 5 - 10 seconds. This prevents unnecessary lockout during thunderstorms.
However, reclaim times of up to 60 - 180 seconds may be used elsewhere in the world.

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MONITORING AND CONTROL

Chapter 14 - Monitoring and Control P14D

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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 247
Event Records 248
Measurements 254
CB Health Monitoring 257
CB State Monitoring 259
Circuit Breaker Control 261
Pole Dead Function 266
Synchrocheck 267
Synchrocheck Implementation 268
System Check PSL 270
Switch Status and Control 271
Harmonic Detection 274
Pole Discrepancy 275

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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.
The event records are detailed in the RECORDS section. The first event shown 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 value) and
a short description relating to the event.
The device is capable of storing up to 1024 event records.
Events are available for view under the path RECORDS\EVENT RECORDS

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

Standard events are further sub-categorised internally to include different pieces of information. These are:
● Protection events (starts and trips)
● Platform events

Note:
The first event in the list 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 same information is also shown in the Opto I/P Status. 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.

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The same information is also shown in the Relay O/P Status. 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 same information is also shown in the Alarm Status. This information is updated continuously, whereas the
information in the event log is a snapshot at the time when the event was created.

2.1.4 FAULT RECORD EVENTS

An event record is created for every fault the IED detects. This is also known as a fault record.
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.
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

V06804

Figure 107: 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 SECURITY EVENTS

An event record is generated each time a setting that requires an access level is executed.

2.1.6 PROTECTION EVENTS

The IED logs protection starts and trips as individual events. Protection events are special types of standard events.
Not all DDB signals can generate an event. Those that can are listed in the RECORD menu. In this menu, you can
set which DDBs generate events.

2.1.7 PLATFORM EVENTS

Platform events are special types of standard events.

2.2 FLEX STATES

The Flex State feature provides a mechanism where any of 256 selected DDB states or any inputs can be used for
efficient monitoring.

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The feature allows user-customised access to the DDB states in the relay. The state bits are packed so that 16
states may be read out in a single Modbus register. The state bits can be configured so that all of the states which
are of interest are available in a minimum number of Modbus registers.
Path: Setpoints > Device > Flex States

2.2.1 FLEX ELEMENTS

There are 8 identical Flex Elements. A Flex Element is a universal comparator, that can be used to monitor any
analog actual value measured or calculated by the relay, or a net difference of any two analog actual values of the
same type. Depending on how the Flex Element is programmed, the effective operating signal could be either a
signed signal (“Signed” selected for Input Mode), or an absolute value (“Absolute” selected for Input Mode).
The element can be programmed to respond either to a signal level or to a rate-of-change (delta) over a pre-
defined period of time. The output DDB is asserted when the operating signal is higher than a threshold or lower
than a threshold as per user’s choice.
When programming a Flex Element, one shall keep in mind the following limitations:
1. The analog inputs for any Flex Element shall be from the same “gender”:
● current and current (in any combination, phase-symmetrical, phase-phase, kA-A, differential, restraint, etc.)
● voltage and voltage (as above)
● active power and active power (Watts and Watts)
● reactive power and reactive power (Vars and Vars)
● apparent power and apparent power (VA and VA)
● angle and angle (any, no matter what signal, for example angle of voltage and angle of current are a valid
pair)
● % and % (any, for example THD and harmonic content is a valid pair)
● V/Hz and V/Hz
● Flex Element actual and Flex Element actual

For all the other combinations, the element will display 0.000 or N/A and will not assert any output DDB. The relay
displays error message
2. The analog value associated with one Flex Element can be used as an input to another Flex Element
“Cascading”

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I/P Comp Mode

Operating Mode

Direction
Function
Pickup
Enabled = 1
Hysteresis:

& ROC T Unit (dt)

Inhibit
ROC T Set Pickup Delay

Dropout Delay
INPUT 1(+):
RUN
Actual Value tPKP
+
INPUT 2 (-): FE 1 OP
-
Actual Value tDPO
FE 1 PKP

V06813
FE 1 Op Signal

Figure 108: Flex Element logic diagram

Input 1 setting specifies the first input (non-inverted) to the Flex Element. Zero is assumed as the input if this
setting is set to “Off”. For proper operation of the element at least one input must be selected. Otherwise, the
element will not assert its output DDB. Input 2 setting specifies the second input (inverted) to the Flex Element.
Zero is assumed as the input if this setting is set to “Off”. For proper operation of the element at least one input
must be selected. Otherwise, the element will not assert its output DDB. This input should be used to invert the
signal if needed for convenience, or to make the element respond to a differential signal. A warning message is
displayed, and the element does not operate if the two input signals are of different types, for example if one tries
to use active power and phase angle to build the effective operating signal.
The element responds directly to the differential signal if this Operating Mode setting is set to “Signed”. The
element responds to the absolute value of the differential signal if this Operating Mode setting is set to “Absolute”.
Sample applications for the “Absolute” setting include monitoring the angular difference between two phasors
with a symmetrical limit angle in both directions; monitoring power regardless of its direction or monitoring a trend
regardless of whether the signal increases of decreases.
Pickup setting specifies the operating threshold for the effective operating signal of the element. If the “Over”
direction is set, the element picks up when the operating signal exceeds the PICKUP value. If the “Under” direction
is set, the element picks up when the operating signal falls below the PICKUP value. The HYSTERESIS setting
controls the element drop out. Note that both the operating signal and the pickup threshold can be negative when
facilitating applications such as reverse power alarms.
The Flex Element can be programmed to work with all analog values measured or computed by the relay. The
PICKUP setting is entered in pu values using the following definitions of the base units:

Definitions of the Base Unit for the Flex Element

Measured or calculated Base Unit
analog value related to:
VOLTAGE VBASE = maximum nominal primary RMS value of the Input 1 (+) and Input 2 (-) inputs
CURRENT IBASE = maximum nominal primary RMS value of the Input 1 (+) and Input 2 (-) inputs
POWER PBASE = maximum value of VBASE * IBASE for the Input 1 (+) and Input 2 (-) inputs
POWER FACTOR PFBASE = 1.00
PHASE ANGLE DegBASE = 360 deg
HARMONIC CONTENT HBASE = 100% of nominal

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THD THDBASE = 100%

FREQUENCY fBASE = nominal frequency as entered under the SYSTEM SETUP menu
VOLT/HZ BASE = 1.00
I2t (arcing Amps) BASE = 2000 kA2*cycle
ROC T Unit (dt) setting specifies the time base dt when programming the FlexElement as a rate of change element.
The setting is applicable only if the Operating Mode is set to “Delta”.
ROC T Set setting specifies the duration of the time interval for the rate of change mode of operation. The setting is
applicable only if the Operating Mode is set to “Delta”.

2.2.2 EVENT DATA

The Event Data feature stores 64 FlexAnalog quantities each time an event occurs. The relay is able to capture a
maximum of 2048 records. The Event Data behaviour matches that of the Event Recorder. This is a Platform
feature and a ‘Basic’ option so it has no dependencies.
There is no Enabling/Disabling of the feature. It is always ‘ON’.
When changes are made to the Event Data settings, the Event data is cleared and the Snapshot.txt file is deleted.
The Event Record remains as is and is not cleared.
Event Data Configuration Path: Setpoints > Device > Event Data

2.3 READ ONLY MODE

The Read Only Mode features allow customisation of the P40Agile configurations in such a way that the user
experience of the P40Agile platform is further enhanced.

Configuration Mode
P40Agile supports a multitude of functions and features which include: Protection and Control (P&C), Asset
Monitoring, PSL, Records and Reporting, Time Synchronisation, Testing/Simulation, etc. Taking into consideration
user experience, configuration mode controls how the “Settings” are presented by only displaying settings that are
typically used, or settings that are important to configure.
There are two configuration modes supported: Simplified, and Regular.
● In Simplified configuration mode, some of the advanced functions/features or a few settings under a
function are hidden or made read-only (greyed out).
● In Regular configuration mode, all function/features and settings of the device are editable and nothing is
hidden or greyed out.

Simplified configuration mode does not remove any functionality or setting from the device. It only controls the
view or display of the settings. All the settings made in Regular configuration mode are still applied during
simplified mode (they are either hidden or read-only). Therefore, simplified configuration mode can also be viewed
as locking advanced settings.
Configuration mode is applicable to the “Settings” items only and does not control view/presentation to other Main
menu items, such as Device Definition, Status, Metering, Records, Commands and Maintenance. The configuration
mode setting is available to be changed by the “Administrator” role. The configuration mode control is applicable
to device HMI and setup software, as well as online and offline setting files.
Configuration mode does not disable the device functionality or settings. It only controls the view or presentation
on the HMI and setup software screens. Therefore, settings which are hidden or Read-only are preserved and
applied within the device.

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2.4 SETPOINT GROUP

The IED provides four setpoint groups. All setpoints contained under the protection setpoints are reproduced in
four groups, identified as Setpoint Groups 1, 2, 3 and 4. These multiple settings provide the capability for both
automatic and manual switching to protection settings for different operating situations. Automatic (adaptive)
protection setting adjustment is available to change settings when the power system configuration is altered.
Automatic group selection can be initiated from the autoreclose, SETPOINT GROUPS and by use of a SET GROUP x
ACTIVE setpoint input. The group selection can be initiated by this input from any operands, inputs or
communications.
Group 1 is the default for the "Active Group" and is used unless another group is requested to become active. The
active group can be selected with the ACTIVE SETPOINT GROUP setpoint, by SET ACTIVE x GROUP input or inputs
from autoreclose, SETPOINT GROUPS. If there is a conflict in the selection of the active group, between a setpoint,
inputs and inputs from functions, the higher numbered group is made active. For example, if the inputs for Group
2, 3, and 4 are all asserted the relay uses Group 4. If the logic input for Group 4 then becomes de-asserted, the
relay uses Group 3. Some application conditions require that the relay does not change from the present active
group. This prevention of a setpoint group change can be applied by setting Change Inhibit inputs (1 to 16). If
needed, typically this change inhibit is done when any of the overcurrent (phase, neutral, ground, or negative
sequence), overvoltage, bus or line undervoltage, or underfrequency elements are picked-up.
Path: Setpoints > Control > Setpoint Groups

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3 MEASUREMENTS

3.1 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 window or with the Measurement Viewer in the settings
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

3.1.1 MEASURED AND CALCULATED CURRENTS

The device measures phase-to-phase and phase-to-neutral current values. The values are produced by sampling
the analogue input quantities, converting them to digital quantities to present the magnitude and phase values.
Sequence quantities are produced by processing the measured values. These are also displayed as magnitude and
phase angle values.
These measurements are contained in the MEASUREMENTS window in the CT BANK X tab .

3.1.2 MEASURED AND CALCULATED VOLTAGES

The device measures phase-to-phase and phase-to-neutral voltage values. The values are produced by sampling
the analogue input quantities, converting them to digital quantities to present the magnitude and phase values.
Sequence quantities are produced by processing the measured values. These are also displayed as magnitude and
phase angle values.
These measurements are contained in the MEASUREMENTS window in the PH VT BANK X or A-BANK VAUX tabs.

3.1.3 POWER AND ENERGY QUANTITIES

Using the measured voltages and currents the device calculates the apparent, real and reactive power quantities.
These are produced on a phase by phase basis together with three-phase values based on the sum of the three
individual phase values.The device also calculates the per-phase and three-phase power factors

3.1.4 DEMAND VALUES

The device produces fixed, rolling, and peak demand values. You reset these quantities using the Reset demand
command.
The fixed demand value is the average value of a quantity over the specified interval. Values are produced for
three phase currents and three phase real and reactive power. The fixed demand values displayed are those for
the previous interval. The values are updated at the end of the fixed demand period according to the Fix Dem
Period setting.
The rolling demand values are similar to the fixed demand values, but a sliding window is used. The rolling demand
window consists of a number of smaller sub-periods. The resolution of the sliding window is the sub-period length,
with the displayed values being updated at the end of each of the sub-periods according to the Roll Sub Period
setting.
Peak demand values are produced for each phase current and the real and reactive power quantities. These
display the maximum value of the measured quantity since the last reset of the demand values.

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3.1.5 FREQUENCY MEASUREMENTS

The device produces a range of frequency statistics and measurements relating to the Frequency Protection
function. These include Check synchronisation, Slip frequency and Rate of Change of Frequency measurements.
The device produces the slip frequency measurement by measuring the rate of change of phase angle between
the bus and line voltages, over a one-cycle period. The slip frequency measurement assumes the bus voltage to be
the reference phasor.

3.1.6 OTHER MEASUREMENTS

Depending on the model, the device produces a range of other measurements such as thermal measurements.

3.2 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 menu.
This setting will display the fault location in metres, miles ohms or percentage, depending on the chosen units in
the Fault Location setting.
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.

3.3 FAULT LOCATOR SETTINGS EXAMPLE

Assuming the following data for the protected line:
Parameter Value
CT Ratio 1200/5
VT Ratio 230000/115
Line Length 10 km
Positive sequence line impedance ZL1 (per km|) 0.089+j0.476 Ohms/km
Zero sequence line impedance ZL0 0.34+j1.03 ohms/km
Zero sequence mutual impedance ZM0 0.1068+j0.5712 Ohms/km

The line impedance magnitude and angle settings are calculated as follows:
● Ratio of secondary to primary impedance = CT ratio/VT ratio = 0.12
● Positive sequence line impedance ZL1 (total) = 0.12 x 10(0.484Ð79.4°) = 0.58 Ð79.4°
● Therefore set line length = 0.58
● Line angle = 79°

The residual impedance compensation magnitude and angle are calculated using the following formula:

ZL0 − ZL1 ( 0.34 + j1.03) − ( 0.089 + j 0.476 ) 0.6∠65.2°

KZn = = = = 0.41∠ − 14.2°
3ZL1 3 ( 0.484∠79.4° ) 1.45∠79.4°

Therefore the settings are:

● KZN Residual = 0.41
● KZN Res Angle = -14

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3.4 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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4 CB HEALTH 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. The circuit breaker condition monitoring counters
are incremented every time the device issues a trip command.
These statistics are available in the CB CONDITION menu. The menu items are counter values only, and cannot be
set directly. The counters may be reset, however, during maintenance. This is achieved with the Clear command

Note:
When in Commissioning test mode the CB condition monitoring counters are not updated.

4.1 APPLICATION NOTES

4.1.1 SETTING THE THRESHOLDS FOR THE ARC ENERGY

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
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 ARC ENERGY is calculated by the breaker arcing current element. If the breaker arcing current element is
disabled, the ACR ENERGY will not be calculated and this setting should not be used. The ARC ENERGY used here is
the individual value for each trip rather than the accumulated value recorded in the Breaker Arcing Current
element.

Note:
Any maintenance program must be fully compliant with the switchgear manufacturer’s instructions.

4.1.2 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.
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.

4.1.3 SETTING THE THRESHOLDS FOR THE OPERATING TIME

Slow CB operation indicates the need for mechanism maintenance. Lockout thresholds (Lockout Time) is provided
to enforce this. They can be set in the range of 0 to 600 ms. This time relates to the interrupting time of the circuit
breaker.

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4.1.4 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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5 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. 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 SYSTEM/CONTACTOR/CONTACTOR 1 setpoint there is a setting called CB Status Input that 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
Closed Closed State unknown Alarm raised if the condition persists
Open Open State unknown Alarm raised if the condition persists

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5.1 CB STATE MONITORING LOGIC

CB Status Input
None
52A
52B
Both 52A and 52B
&
CB Aux 3ph(52-A)

& 1 CB Closed 3 ph

&

&

& 1 CB Open 3 ph

&

30ms
& CB Status Unknown
X1 0s
CB Aux 3ph(52-B)

V06800

Figure 109: CB State Monitoring logic

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6 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 setting in the CB STATE MONITOR element must be set to the type of circuit breaker. If no CB auxiliary
contacts are available then this setting should be set to None, and no CB control will be possible.
For local control, the CB control by setting 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 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 opto-inputs (local control)
● SCADA communication (remote control)

6.1 CB CONTROL USING THE IED MENU

You can control manual trips and closes with the CB Trip/Close command in the CB CONTROL element. This can
be set to No Operation, Trip, or Close accordingly.
For this to work you have to set the CB control by setting to Local, Local + Remote, Opto+Local, or Opto
+Local+Remote in the CB CONTROL element.

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6.2 CB CONTROL USING THE HOTKEYS

The hotkeys allow you to manually trip and close the CB without the need to enter the CB CONTROL element. For
this to work you have to set the CB control by setting to Local, Local+Remote, Opto+Local, or Opto
+Local+Remote in the CB CONTROL element.
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
● 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 110: Hotkey menu navigation

6.3 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 setting to opto, Opto+Local, Opto+Remote, or Opto
+Local+Remote in the CB CONTROL menu.

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6.4 REMOTE CB CONTROL

Remote CB control can be achieved by setting the CB Trip/Close to trip or close by using a command over a
communication link.
For this to work, you have to set the CB control by setting to Remote,Local+Remote, Opto+remote, Opto
+Local+Remote in the CB CONTROL menu.
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.

Protection Trip

Trip
Remote
Control
Trip Close

Remote
Control
Close

Local

Remote

Trip Close

E01207

Figure 111: Remote Control of Circuit Breaker

6.5 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.

6.6 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.

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6.7 CB CONTROL LOGIC

CB Control
Disabled Opto
Local Opto+Local
1 Enable opto -initiated CB trip and close
Remote Opto+Remote
Local+Remote Opto+Rem+Local

HMI Trip Control Trip

1 Trip pulse
& & S
Init Trip CB Q
R & Man CB Trip Fail

&
Init close CB 1 Close in Prog

HMI Close Delayed control close time

& S
Control Close
Q
Close pulse
AR In Progress R &
1 S
Auto Close Q
Pulsed output latched in HMI
R
& CB Cls Fail
AR models only

Reset Close Dly

1

Trip Command In 1
1
Ext. Trip 3ph

Control Trip

CB Open 3 ph
1
CB Closed 3 ph
CB healthy window

& Man CB Unhealthy

CB Healthy

C/S window
Voltage models only
& Man No Checksync
Man Check Synch

V06803

Figure 112: CB Control logic

6.8 CB ARCING CURRENT

This Function calculates an estimate of the per-phase wear on the breaker contacts by measuring and integrating
the current squared passing through the breaker contacts as an arc. These per-phase values are added to
accumulated totals for each phase and compared to a programmed threshold value. When the threshold is
exceeded in any phase, the relay can set an output operand and set an alarm. The accumulated value for each
phase can be displayed as an actual value.
The same output operands that are selected to operate the Trip output relay that is used to trip the breaker
indicating a tripping sequence has begun, are used to initiate this feature. A time delay is introduced between
initiation and starting of integration to prevent integration of current flow through the breaker before the contacts
have parted. This interval includes the operating time of the output relay, any other auxiliary relays and the
breaker mechanism. For maximum measurement accuracy, the interval between the change-of-state of the
operand (from 0 to 1) and contact separation should be measured for the specific installation. Integration of the
measured current continues for 100 ms, which is expected to include the total arcing period.
Trip signals from internal protection functions can trigger the Breaker Arcing Scheme with INITIATION setting.

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E06810

Figure 113: CB Arcing current measurement

&
DT 100
ms
1
Initiation
& CB Arc Current
Inhibit Delay

IA2t
IA2 Cycle
IA Integrate
IB2t CB Arc Alarm
IB2 Cycle Max
IB Integrate
IC2t
IC2 Cycle
IC Integrate
Alarm level
Threshold Reset to o
Enabled V06811

Figure 114: CB Arcing current Logic

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7 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.

7.1 POLE DEAD LOGIC

IA

& 1 Pole Dead A

Current Set

VA

Voltage Set

IB

& 1 Pole Dead B

Current Set

VB

Voltage Set

IC

Current Set & 1 Pole Dead C

VC

1 Any Pole Dead

Voltage Set

VTS Slow Block

& All Poles Dead
CB Open 3 ph

V06801

Figure 115: Pole Dead logic

If both the line current and voltage fall below certain thresholds, the device will initiate a Pole Dead condition.
If one or more poles are dead, the device will indicate which phase is dead and will also assert the Any Pole Dead
DDB signal. If all phases are dead the Any Pole Dead signal would be accompanied by the All Poles Dead signal.
If a VT fails, a VTS signal is generated to block the Pole Dead indications that would be generated by the
undervoltage and undercurrent thresholds. However, the VTS logic will not block the Pole Dead indications if they
are initiated by a BRK Open signal. A BRK Open signal automatically initiates a Pole Dead condition regardless of
the current and voltage measurement.

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8 SYNCHROCHECK
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 Synchrocheck 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).

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9 SYNCHROCHECK IMPLEMENTATION
The Synchrocheck function provides Live/Dead Voltage Monitoring and Check Synchronisation.
The System Checks function is enabled or disabled under the path Setpoints\Control\Synchrocheck\Synchrocheck\
CS1 Function setting

9.1 VT CONNECTIONS
The device provides inputs for a three-phase "Main VT" and at least one single-phase VT for check synchronisation
or residual voltage. 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 4th 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, the Line VT I/P is provided
where you can define this. This is the main Bus VT I/P setting.
The Bus VT I/P setting is provided to define the Bus VT Location.

9.2 VOLTAGE MONITORING

The settings Bus Live V and Line Live V 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 Bus Dead V or Line Dead V setting, a DDB signal is generated (Dead Bus, or
Dead Line). If the measured voltage exceeds the Bus Live V or Line Live V setting, a signal is generated (Live Bus,
or Live Line).

9.3 CHECK SYNCHRONISATION

Synchrocheck verifies that the voltages (BUS and LINE) on the two sides of the supervised circuit breaker are within
set limits of magnitude, angle and frequency differences. The time that the two voltages remain within the
admissible angle difference is determined by the setting of the phase angle difference ΔΦ and the frequency
difference ΔF (slip frequency).
This can be defined as the time it would take the voltage phasor, BUS or LINE, to traverse an angle equal to 2 × ΔΦ
at a frequency equal to the frequency difference ΔF. This time can be calculated by:

1
T=
360°
× ∆F
2 × ∆Φ
where: ΔΦ = phase angle difference in degrees; ΔF = frequency difference in Hz.
Example: for the values of ΔΦ = 30° and ΔF = 0.1 Hz, the time while the angle between the two voltages will be less
than the set value is:

1
T= = 1.66 sec
360
× 0.1
2 × 30
Therefore the breaker closing time must be less than than this computed time, in terms to successfully close and
connect both energized sides.
If one or both sides of the synchronising breaker are de-energized, the synchrocheck programming can allow for
closing of the circuit breaker using undervoltage control to by-pass the synchrocheck measurements (dead source
function).

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9.4 SYSTEM CHECK LOGIC

Function
Disabled
Enabled

AND

BLOCK :
Off = 0

MAX VOLT DIFFERENCE:

Bus (Line) voltage MAX FREQ DIFFERENCE:

Associated setpoints from
MAX ANGLE DIFFERENCE:
System/Voltage Sensing/
Phase VT connection MAX FREQ HYSTERESES:
Magnitude Vbv DV <= MAX VOLTS DIFF
DV = |V3phv– V1phv|

AND
Frequency fbv Df = |f3phv– f1phfv| Df <= MAX FREQ DIFF Sync1 OK
Phase Fbv DF=|(F3phv – F1phv)|
DF <= MAX ANGLE DIFF

from Tie-Breaker Transfer scheme

AND
Sync1 Live Bus
Transfer Initiate

AND
Sync1 Live Line

Line (Bus) voltage

Associated setpoints from LIVE BUS VOLTS MIN:

AND
System/Voltage Sensing/ Aux Sync1 Dead Bus
Vbus >= LIVE BUS V MIN
VT connection

AND
Magnitude Vlv
LIVE LINE VOLTS MIN:
Frequency fl v

AND
Sync 1Dead Line
Phase Flv Vline >= LIVE LINE V MIN

AND
DEAD BUS VOLTS MAX:

AND
Vbus<=DEAD BUS V MAX Sync1 Dead Src OK

AND

OR
DEAD LINE VOLTS MAX:

AND
Sync1 Close Perm
Vline<=DEAD LINE V MAX
OR

AND

OR
AND

DEAD SOURCE PERM:

OUTPUT RELAYS 3 to 7
OR
AND

Disabled

AND
Do Not Operate, Operate
L BUS & D LINE

L LINE & D BUS

TO:
D LINE & D BUS Autoreclose
Undervoltage restoration
D LINE OR D BUS Underfrequency restoration
Manual local/remote closing
D LINE XOR D BUS
SYNCHCHECK BYPASS
V06802
Off = 0

Figure 116: System Check logic

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10 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 117: System Check PSL

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11 SWITCH STATUS AND CONTROL

All P40 Agile products support Switch Status and Control for up to 8 switchgear elements in an IEC61850
substation. The device is able to monitor the status of and control up to eight switches. The types of switch that
can be controlled are:
● Load Break switch
● Disconnector
● Earthing Switch
● High Speed Earthing Switch

Consider the following feeder bay:

XSWI1 XSWI2

XCBR

XSWI3 Legend:
XSWI4 XSWI1 = Disconnector 1
XSWI2 = Disconnector 2
XSWI3 = Disconnector 3
XSWI4 = Earthing Switch
XCBR = Circuit Breaker
V01241

Figure 118: Representation of typical feeder bay

This bay shows four switches of the type LN XSWI and one circuit breaker of type LN XCBR. In this example, the
switches XSWI1 – XSWI3 are disconnectors and XCSWI4 is an earthing switch.
For the device to be able to control the switches, the switches must provide auxiliary contacts to indicate the
switch status. For convenience, the device settings refer to the auxiliary contacts as 52A and 52B, even though
they are not circuit breakers.
There are eight sets of settings in the SWITCH CONTROL column, which allow you to set up the Switch control, one
set for each switch. These settings are as follows:
SWITCH1 Type
This setting defines the type of switch. It can be a load breaking switch, a disconnector, an earthing switch or a
high speed earthing switch.
SWI1 Status Inpt
This setting defines the type of auxiliary contacts that will be used for the control logic. For convenience, the device
settings refer to the auxiliary contacts as 52A and 52B, even though they are not circuit breakers. "A" contacts
match the status of the primary contacts, whilst "B" contacts are of the opposite polarity.
SWI1 Control by
This setting determines how the switch is to be controlled. This can be Local (using the device directly) remote
(using a communications link), or both.
SWI1 Trip/Close
This is a command to directly trip or close the switch.
SWI1 Trp Puls T and SWI1 Cls Puls T

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These settings allow you to control the width of the open and close pulses.
SWI1 Sta Alrm T
This setting allows you to define the duration of wait timer before the relay raises a status alarm.
SWI1 Trp Alrm T and SWI1 Cls Alrm T
These settings allow you to control the delay of the open and close alarms when the final switch status is not in
line with expected status.
SWI1 Operations
This is a data cell, which displays the number of switch operations that have taken place. It is an accumulator,
which you can reset using the Reset SWI1 Data setting
Reset SWI1 Data
This setting resets the switch monitoring data.

Note:
Settings for switch 1 are shown, but settings for all other switch elements are the same.

11.1 SWITCH STATUS LOGIC

SWI1 Aux (52-A)
&
1
SWI1 Aux (52-B) & SWI1 Status Cls

SWI1 Status Inpt &

52A
52B
&
52A + 52B
SWI1 Sta Alrm T
None

& t
1 SWI1 Input Alm
0

&

& & SWI1 Status Opn

1

&

&
V01286

Figure 119: Switch Status logic

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11.2 SWITCH CONTROL LOGIC

SWI1 Control by 1
&
Lo cal 1
Lo ca l+Re mote
1
Remot e &

Lo cal

Remot e

Blk Rmt SWI1 Ops

SWI1 Cls Puls T

& SWI1 Co ntrol Cls

SWI1 Statu s Opn
1
SWI1 Statu s Cls

SWI1 Statu s Inpt

1
None & SWI1 Co ntrol Trp

SWI1 Trip/Close
SWI1 Trp P uls T
Close
Trip

&
1 SWI1 Inpu t Alm

&
SWI1 Cls Alrm T

t
& SWI1 Cls Fail
SWI1 Status Cls 0

t
& SWI1 Trip Fail
SWI1 Status Opn 0

V01285 SWI1 Trp A lrm T

Note: This diagram doe s not show a ll switche s. Other switches f ollow simila r p rinciples.

Figure 120: Switch Control logic

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12 HARMONIC DETECTION
The Harmonic detection function monitors the 2nd harmonic, which is present in the phase currents. The relay
provides four identical Harmonic Detection elements.
During transformer energization or motor starts, the inrush current present in phase currents can impact some
sensitive elements, such as negative sequence overcurrent. Therefore, the ratio of the second harmonic to the
fundamental magnitude per phase is monitored, while exceeding the settable pickup level, an operand is asserted,
which can be used to block such sensitive elements. The harmonics are updated every protection pass.
This function defines the phases required for operation like ONE, TwO, THREE or AVERAGE. If set to AVERAGE, the
relay calculates the average level of the 2nd harmonic and compares this level against the pickup setting.
Averaging of the 2nd harmonic follows an adaptive algorithm depending on the fundamental current magnitude
per-phase. If the fundamental magnitude on any of the three phases goes below the current cut-off level, the 2nd
harmonic current from that phase is dropped (zeroed) from the equation for averaging, and the divider is
decreased from 3 to 2. The same happens if the magnitude of the fundamental magnitude on one of remaining
two phases drops below the cut-off level. In this case the 2nd harmonic on this phase is dropped from summation,
and the divider is decreased to 1.
Imin setting sets the minimum value of current required to allow the Harmonic Detection element to operate. If
OPERATE MODE is set to AVERAGE, the average of three-phase currents is used for supervision. A similar adaptive
average algorithm is applied to calculate the average of operation current magnitude.

Harm Det Start A

Harm Det Start B

Ia 2nd Harm Det Start C

Harm
&
Threshold Harm Det Start

Ib 2nd DT
Harm Mode Harm Det Trip
& Selection

Ic 2nd Time Delay

Harm
&

Operate Mode
V06812
Inhibit

Figure 121: Harmonic detection logic

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13 POLE DISCREPANCY
The P40Agile relay provides three Pole Discrepancy elements under Control menu. This element can be used for re-
tripping the breaker after pole Discrepancy detection or tripping upstream breaker in cases when the pole
Discrepancy still persists. The element detects if one or two of the breaker poles remain open following close
command, or if one or two of the poles remain closed following open command. The pole Discrepancy function
operates based on either information from auxiliary contacts associated with the open/close status of each pole
of the breaker, or by detecting the presence of phase currents above/below programmable current limit level upon
breaker close or open operation respectively. To detect pole Discrepancy using phase currents, the setting Current
Limit must be programmed. By monitoring each phase current with respect to the selected Current Limit threshold,
the relay detects whether the breaker pole is open or closed. If the phase current is detected below the current
limit, the pole will be declared open, and if the current is above that limit, the pole will be declared closed. The
implemented pole Discrepancy logic from P40Agile allows either detection of pole

IED
Ia Pole Discrepancy

Ib

Ic

Circuit Breaker

52a 52a 52a 52b 52b 52b

External Pole
Discrepancy

V06814

Figure 122: Breaker contacts arrangement for detecting pole discrepancy externally

Discrepancy externally using single contact input (see figure, bove), Aux Status Based based detection using 6
input contacts from 52a and 52b auxiliary breaker contacts per-phase (see figure, below), currents based
detection, any combination of the three detection methods, or all three methods enabled.
The pole Discrepancy scheme from P40Agile relay allows two types of breaker contacts wiring: The figure above
shows wiring of the breaker pole Discrepancy signal detected externally. In such schemes the three 52a contacts
are paralleled and connected in series with the three paralleled 52b contacts. If the External Pole Discrepancy
input turns ON, this would indicate either any of the 52b contacts did not open after breaker close command, or
any of the 52a contacts remained closed after breaker trip command.
The figure below shows the connection of breaker 52a and 52b auxiliary contacts per breaker pole, and their
wiring to the relay inputs. This wiring of the breaker contacts to the relay is used when the contacts based method
for pole Discrepancy detection is enabled on the relay

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IED
Ia

Ib
Ic

Block

CB Trip Trigger
Circuit Breaker Pole Discrepancy
CB Close Trigger

52a 52a 52a 52b 52b 52b

V06815

Figure 123: Breaker contacts wiring for pole discrepancy detected by the relay

CB Trip Trigger assigns the CB trip (open) initiation signal, CB Close Trigger assigns the breaker close initiation
signal. Ext Pole Discrp an operand (typically contact input) as an input from pole discrepancy detected externally
by arranging the breaker auxiliary contacts.
Time Delay provides the definite time pickup delay. If, during a breaker open action, all three poles are detected
open before the timer expires, the timer resets and no pole discrepancy is declared. If, however, one or two of the
poles remain closed after the timer expires, pole discrepancy is declared. The same logic applies when a close
command is send to the breaker, by monitoring the closed status of the breaker poles. Even though the minimum
Pickup Delay of 100 ms from the range serves most breakers with shorter operating times, make sure to check the
breaker operating times, and set the delay to be longer than these times.
Aux Status Based enables the PH A(B,C) OPEN and PH A(B,C) CLOSED settings associated with Aux Status Based PD
detection. PH A(B,C) Open setting provides selection of the operand per phase (pole) to detect the Open status of
the breaker phase (pole). Normally, selection of the contact input wired to the pole auxiliary contact 52b is
selected. This setting applies only if Aux Status Based is set to “Enabled”. PH A(B,C) Closed setting provides selection
of operand per phase (pole) to detect the Closed status of this breaker phase (pole). Normally, selection of the
contact input wired to the pole auxiliary contact 52a is selected. This setpoint applies only if Aux Status Based is
set to “Enabled”. To get proper functionality when using auxiliary contacts as detection criteria, the primary
contacts must be fully synchronized with the auxiliary contacts of the monitored switching element. This means
primary contacts and auxiliary contacts need to switch simultaneously.
Current Based enables the setting Current Limit, associated with current-based PD detection. Current Limit setting
sets the threshold for the measured phase currents per breaker pole, above which the pole is considered closed,
and below which the pole is detected.

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FUNCTION:
Disabled = 0

INHIBIT

&
Off = 0

&
Aux Status Based
Disable, Enable = 1 RUN

Ph A pole (52a contact)

Ph B pole (52a contact)

Ph C pole (52a contact)

Contact based
PD detection
Ph A pole (52b contact)
logic Contact PD[X] Trip

&
Ph B pole (52b contact)

Ph C pole (52b contact)

Ext PD[X] Trip

&
TIME DELAY

Ext Pole Discrp. t pkp

Pole Disc[X] Trip
&

1
Off=0

SETPOINT
Timer
CB Trip Trigger
Off=0 t = tpkp + 300ms

Timer
CB Close Trigger
t = tpkp + 300ms
Off=0

Currents Based RUN

&

Disable, Enabled

Current based

AND
Current PD[X] Trip
PD detection
logic

Phase A current
Phase B current
V06816-1
Phase C current

PhaseCurrents

Figure 124: Pole discrepancy detection--main logic

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From Pole Discrepancy

Detection - Main logic
(V06816 -1)

To Pole Discrepancy:
Breaker pole Failure
operands ( V06816 -4)

RUN

Bre a ke r a u xilia ry
co n ta ct o u tp u ts
C o n ta ct In p u ts

Ph A pole (52a) Ph A C lo se d

Ph B pole (52a) Ph B C lo se d

&

&
Ph C pole (52a) Ph C C lo se d
PD[X]-A Fail- Cls

1
Ph A C lo se d

Ph B C lo se d

&

&
Ph C C lo se d
PD[X]-B Fail -Cls

1
Ph A C lo se d

Ph B C lo se d

&

&
Ph C C lo se d
PD[X]-C Fail-Cls

1
Ph A C lo se d

Ph B C lo se d
&

&
Ph C C lo se d

Ph A C lo se d

Ph B C lo se d
&

&
Ph C C lo se d

Ph A C lo se d

Ph B C lo se d
&

Ph C C lo se d &
Pole Discrepancy operation From Pole Discrepancy
From Pole detection - main logic
(V06816 -1 )
Discordance Check for open
detection-main logic poles
1

(V06816 -1)
&

BR K C lo se Trig g e r
To Pole Discrepancy
Aux Status Based Based PD Pickup detection - main logic
(V06816 -1 )
1

BR K Trip Trig g e r
&

Check for closed

1

poles
Bre a ke r a u xilia ry
C o n ta ct In p u ts
co n ta ct o u tp u ts

Ph A pole (52b) Ph A Op e n
&

Ph B pole (52b) Ph B Op e n
&

PD[X]-A Fail-Open
1

Ph C pole (52b) Ph C Op e n

Ph A Op e n
&

Ph B Op e n
&

PD[X]-B Fail -Open

1

Ph C Op e n

Ph A Op e n
&

Ph B Op e n
&

Ph C Op e n
PD[X]-C Fail-Open
1

Ph A Op e n
&

Ph B Op e n
&

Ph C Op e n

Ph A Op e n
&

Ph B Op e n
&

Ph C Op e n
To Pole Discrepancy:
Breaker pole Failure
Ph A Op e n
operands ( V06816 -4)
&

Ph B Op e n
&

V06816-2 Ph C Op e n

Figure 125: Auxiliary status based pole discrepancy detection logic

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P14D Chapter 14 - Monitoring and Control

From Pole Discrepancy

Detection - Main logic
(V06816- 1)
To Pole Discrepancy :
Breaker pole Failure
operands ( V06816 -4)

RUN

Phase Currents PICKUP:

Ph A current Ia  Pickup

Ph B current Ib  Pickup

&

&
Ph C current Ic  Pickup
PD[X]-A Fail- Cls

1
Ia  Pickup

Ib  Pickup

&

&
Ic  Pickup
PD[X]-B Fail-Cls

1
Ia  Pickup

Ib  Pickup

&

&
Ic  Pickup
PD[X]- C Fail-Cls

1
Ia  Pickup

Ib  Pickup

&

&
Ic  Pickup

Ia  Pickup

Ib  Pickup
&

&
Ic  Pickup

Ia  Pickup

Ib  Pickup
&

&
Ic  Pickup

Pole Discrepancy operation From Pole Discrepancy

From Pole detection - main logic
Discrepancy Check for open ( V06816-1 )
OR

Detection - Main poles

logic ( V06816 -1) &

BRK Close Trigger

Current Based PD detection To Pole Discrepancy

1 detection - main logic
BRK Trip Trigger ( V06816- 1)
&

Check for closed

1

poles

PICKUP:

Ia < Pickup
&

Ib < Pickup
&

PD[X]-A Fail-Open

1
Ic < Pickup

Ia < Pickup
&

Ib < Pickup
&

PD[X]-B Fail-Open
1

Ic < Pickup

Ia < Pickup
&

Ib < Pickup
&

Ic < Pickup
PD[X]-C Fail-Open
1

Ia < Pickup
&

Ib < Pickup
&

Ic < Pickup

Ia < Pickup
&

Ib < Pickup
&

Ic < Pickup
To Pole Discrepancy:
Breaker pole Failure
Ia < Pickup
operands ( V06816- 4)
V06816-3
&

Ib < Pickup
&

Ic < Pickup

Figure 126: Current based pole discrepancy detection logic

P14DEnh-TM-EN-1.1 279
Chapter 14 - Monitoring and Control P14D

From contacts PD[X] -A Fail -Cls

1
based PD
detection logic
(V06816-2)
PD[X] -B Fail -Cls

1
PD[X] -C Fail -Cls

1
PD[X] -A Fail -Open

1
PD[X] -B Fail -Open

1
PD[X] -C Fail -Open

From currents 1
based PD
detection logic
(V06816-3) V06816-4

Figure 127: Pole discrepancy: breaker pole failure signal logic

280 P14DEnh-TM-EN-1.1
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SUPERVISION
Chapter 15 - Supervision P14D

282 P14DEnh-TM-EN-1.1
P14D Chapter 15 - Supervision

1 CHAPTER OVERVIEW
This chapter describes the supervison functions.
This chapter contains the following sections:
Chapter Overview 283
DC Supply Monitor 284
Voltage Transformer Supervision 286
Current Transformer Supervision 288
Trip Circuit Supervision 290

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Chapter 15 - Supervision P14D

2 DC SUPPLY MONITOR
This product can be powered using either a DC or AC supply. As a DC supply is normally used, a DC Supply
Monitoring feature is included to indicate the DC supply status. The nominal DC Station supply is 48 V DC, which is
provided by a bank of batteries. It is sometimes possible for this nominal supply to fall below or rise above
acceptable operational limits. If the voltage is too high, it may indicate overcharging. If the voltage is too low, it
may indicate a failing battery.
In such cases it is very useful to have DC supply monitoring functionality. The P40 Agile products provide such
functionality by measuring the auxiliary DC supply fed into the device and processing this information using
settings to define certain limits. In addition, the DC Auxiliary Supply value can be displayed on the front panel LCD
to a resolution of 0.1 V DC. The measuring range is from 19 V DC to 300 V DC.

2.1 DC SUPPLY MONITOR IMPLEMENTATION

The P40Agile products provide three DC supply monitoring zones; zone 1, zone 2, and zone 3. This allows you to
have multiple monitoring criteria. Each zone must be configured to correspond to either an overvoltage condition
or an undervoltage condition. A single zone cannot be configured to provide an alarm for both undervoltage and
overvoltage conditions. Typically, you would configure zones 1 and 2 for undervoltage conditions, whereby the
lowest limit is set very low, and zone 3 for an overvoltage condition whereby the upper limit is very high.
This is best illustrated diagrammatically:

Vdc3 upper limit

Zone 3 (overvoltage)
Vdc3 lower limit
Vdc nominal
Vdc1 upper limit

Zone 1 (undervoltage)

Vdc1 lower limit

Vdc2 upper limit
Zone 2 (undervoltage)

Vdc2 lower limit

V01221

Figure 128: DC Supply Monitor zones

It is possible to have overlapping zones whereby zone 2 upper limit is lower than zone 1 lower limit in the above
example.
The DC Supply Monitoring function is implemented using settings in the DC SUP. MONITOR column. There are three
sets of settings; one for each of the zones. The settings allow you to:
● Enable or disable the function for each zone
● Set a lower voltage limit for each zone
● Set an upper voltage limit for each zone
● Set a time delay for each zone

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2.2 DC SUPPLY MONITOR LOGIC

Vdc Vdc1 Start

Vdc1 Lower Limit 0

& Vdc1 Trip
t
Vdc

Vdc1 Upper Limit

Vdc1 Status
Enabled

Vdc1 Inhibit

Vdc1 Time Delay

V06407

Figure 129: DC Supply Monitor logic

The diagram above shows the DC supply monitoring logic for stage 1 only. Stages 2 and 3 are identical in principle.
The logic function will work when the Vdc1 status setting cell is Enabled and the DC Supply Monitoring inhibit
signal (Vdc Inhibit) is low.
If the auxiliary supply voltage (Vdc) exceeds the lower limit AND falls below the upper limit, the voltage is in the
healthy zone and a Start signal is generated.
The Vdc(n) Trip signals from all stages are OR'd together to produce an alarm signal DC Supply Fail.

Note:
The device's supercapacitor uses Vdc to provide charge and so may cause the voltage to dip below the Vdc lower limit (19.2 V)
during a system power-up sequence if fully discharged. This will trigger a lockout error. In this case, it will be necessary to
allow the supercapacitor to charge before attempting another power-up sequence. The supercapacitor may take several
minutes to become fully charged, depending on the AC/DC supply specification. With the supercapacitor charged, the next
relay power cycle will clear the lockout and the relay will boot and operate normally.

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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.
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

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.

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
currents. However, if this is not caused by a power system failure, there will be no change in any of the currents. So
if there is no measured voltage on any of the three phases and there is no change in any of the 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.

3.3 VTS IMPLEMENTATION

VTS is implemented in the SUPERVISION column of the relevant settings group.
The following settings are relevant for VT Supervision:
● VTS Function: determines whether the VTS Operate output will be a blocking output or an alarm indication
only
● VTS Time delay: determines the operating time delay
VTS is only enabled during a live line condition to prevent operation under dead system conditions.

3.4 VTS LOGIC

This logic will only be enabled during a live line conditionto prevent operation under dead system conditions.

286 P14DEnh-TM-EN-1.1
P14D Chapter 15 - Supervision

V2
&

Hardcodedthreshold
1 1 S
V1 Q
R
Hardcodedthreshold `&
`&
I1

Hardcodedthreshold

Hardcodedthreshold
`&
& VTS Fast Block

Hardcodedthreshold 1 S
Q VTS Slow Block
R

`&
&

&

& VTS Fuse V Loss

DeltaI1

Hardcodedthreshold
DeltaI2
1
Hardcodedthreshold
DeltaI0 V06400

Hardcodedthreshold

Figure 130: VTS logic

As can be seen from the diagram, the VTS function is inhibited if:
● A Negative Phase Sequence current exists
● If the phase current changes over the period of 1 cycle

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Chapter 15 - Supervision P14D

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.

4.1 CTS IMPLEMENTATION

The P14D relay provides a CT Supervision element that uses three distinct checks that can be enabled or disabled
individually once the overall function is enabled. These three checks are the sequence check, differential check,
and symmetry check.
The sequence check is the first check and should ideally be used for CT supervision. The sequence check uses zero
sequence current, zero sequence voltage, and ground current. This check may not be an option if the ground
current is not available, voltages are not available, or not connected in wye configuration to be able to calculate
zero sequence voltage. If voltages are not available or they are available but in delta configuration, the differential
check can be used.
The differential check uses calculated zero sequence current and ground current to calculate differential current. If
ground current is not available, the symmetry check can be used.
The symmetry check operates by calculating a quotient or a ratio of minimum current over maximum current and
comparing against a threshold. This function should be set appropriately considering possible minimum and
maximum load currents occurred in various scenarios.
To further enhance the security of these functions and not block overcurrent in case of fault events, an additional
maximum load current supervision is added where the maximum of the phase current magnitudes Imax must be
less than the maximum load current ILmax.

288 P14DEnh-TM-EN-1.1
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4.2 CTS LOGIC

Inhibit

Max(Ia, Ib, Ic)

Max Current Supv

3I0
1 CTS Block

Seq 3I0 Set

&
3V0

Seq 3V0 Set

1 CTS Time Delay

IN1

Seq IN1 Set

|3I0-IG|
(Diff Slope*Imax) & 1 CTS Alarm
+
Diff Current Set

Imin/Imax

Sym Quotient Set

&
Imax

Sym Min Current

V06401

Figure 131: CTS logic diagram

4.3 APPLICATION NOTES

4.3.1 SETTING GUIDELINES

Sequence Check: The ground current input for the sequence check must come from a core balance CT or a
transformer neutral point grounding CT. The residual ground input method should not be used for sequence check.
Differential Check: The CT Supervision element ground current input must come from a core balance CT.
Transformer neutral point grounding or the residual ground input method should not be used for the differential
check.

P14DEnh-TM-EN-1.1 289
Chapter 15 - Supervision P14D

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 132: 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 60 mA. The table below
shows the appropriate resistor value and voltage setting for this scheme.
Trip Circuit Voltage Resistor R1
24/27 620 Ohms at 2 Watts

290 P14DEnh-TM-EN-1.1
P14D Chapter 15 - Supervision

Trip Circuit Voltage Resistor R1

30/34 820 Ohms at 2 Watts
48/54 1.2 kOhms at 5 Watts
110/125 2.7 kOhms at 10 Watts
220/250 5.2 kOhms at 15 Watts

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. V06405

Figure 133: 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.

+ve

Trip Output Relay Trip coil

Trip path 52A

52B

R1 Opto-input 1
Circuit Breaker
-ve

R2 Opto-input 2
V01215

Figure 134: TCS Scheme 2

P14DEnh-TM-EN-1.1 291
Chapter 15 - Supervision P14D

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

As with scheme 1, 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 Resistor R1 and R2
24/27 620 Ohms at 2 Watts
30/34 820 Ohms at 2 Watts
48/54 1.2 kOhms at 5 Watts
110/125 2.7 kOhms at 10 Watts
220/250 5.2 kOhms at 15 Watts

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. V06406

Figure 135: 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.

+ve
R3
Output Relay Trip coil
Trip path 52A

R2
52B

Opto-input R1 Circuit Breaker

-ve
V01216

Figure 136: 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.

292 P14DEnh-TM-EN-1.1
P14D Chapter 15 - Supervision

5.3.1 RESISTOR VALUES

As with TCS schemes 1 and 2, 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 on 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.
Trip Circuit Voltage Resistor R1 and R2 Resistor R3
24/27 620 Ohms at 2 Watts 330 Ohms at 5 Watts
30/34 820 Ohms at 2 Watts 430 Ohms at 5 Watts
48/54 1.2 kOhms at 5 Watts 620 Ohms at 10 Watts
110/125 2.7 kOhms at 10 Watts 1.5 k Ohms at 15 Watts
220/250 5.2 kOhms at 15 Watts 2.7 k Ohms at 25 Watts

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. V06405

Figure 137: PSL for TCS Scheme 3

5.4 TRIP CIRCUIT SUPERVISION SCHEME 4

Scheme 4 is identical to that offered by MVAX31 (a Trip Circuit Supervision relay) and consequently is fully
compliant with ENA Specification H7. To achieve this compliance, there are eight settings in the OPTO CONFIG
column. Two of these settings must be set to TCS before the scheme can be used, with any remaining opto-input
set to Normal as required.
In the diagram below, Opto-input 1 and Opto-input 2 would correlate to one of the above-mentioned opto-inputs.

+ve

Trip Output Relay Trip coil

52A
Trip path

52B

R1 Opto A
Circuit Breaker
-ve

R2 Opto B
V01222

Figure 138: TCS Scheme 4

Under normal non-fault conditions, a current of 2 mA flows through one of the following paths:

P14DEnh-TM-EN-1.1 293
Chapter 15 - Supervision P14D

a) Post Close Supervision: When the CB is in a closed state, the current flows through R1, Opto A, Contact 52A and
the trip coil.
b) Pre-close Supervision: When the CB is in an open state, the current flows through R1, Opto A, Contact 52B, Opto
B and the trip coil.
c) Momentary Tripping with Self-reset Contact: When a self-reset trip contact is in a closed state, the current flows
through the trip contact, contact 52A and the trip coil.
d) Tripping with Latched Contact: When a latched trip contact is used and when it is in a closed state, the current
flows through the trip contact, Contact 52A, the trip coil, then changing to the path trip contact, R2, Contact 52B,
Opto B and the trip coil.
A current of 2 mA through the Trip Coil is insufficient to cause operation of the Trip Contact, but large enough to
energise the opto-inputs. Under this condition both of the opto-inputs will output logic 1, so the output relay (TCS
health) will be closed and the User Alarm will be off. If a break occurs in the trip circuit, the current ceases to flow,
resulting in both opto-inputs outputting logic 0. This will open the output relay and energise the user alarm.

5.4.1 RESISTOR VALUES

The TCS opto-inputs sink a constant current of 2 mA.The values of external resistors R1 and R2 are chosen to limit
the current to a maximum of 60 mA in the event that an opto-input becomes shorted. The values of these resistors
depend on the trip circuit voltage. To achieve compliance with ENA Specification H7, we have carried out extensive
testing and we recommended the following resistors values.
Trip Circuit Voltage Resistor R1 and R2 (ohms)
24/27 620 Ohms at 2 Watts
30/34 820 Ohms at 2 Watts
48/54 1.2 kOhms at 5 Watts
110/125 2.7 kOhms at 10 Watts
220/250 5.2 kOhms at 15 Watts

For the momentary tripping condition, none of the opto-inputs are energised. To tide over this normal CB
operation, a drop-off time delay of about 400 ms is added in the PSL.

5.4.2 PSL FOR TCS SCHEME 4

Opto A

Opto B Opto input 1

Opto input 2 0 0
1 dropoff straight *Output Relay
400 0

50
pickup Latching LED
0
User Alarm

*NC stands for Normally Closed. V06410

Figure 139: PSL for TCS Scheme 4

294 P14DEnh-TM-EN-1.1
 CHAPTER 16

DIGITAL I/O AND PSL CONFIGURATION

Chapter 16 - Digital I/O and PSL Configuration P14D

296 P14DEnh-TM-EN-1.1
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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 297
Configuring Digital Inputs and Outputs 298
Scheme Logic 299
Configuring the Opto-Inputs 301
Fixed Function LEDs 302
Virtual Inputs 303
Outputs 304

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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.
● 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.

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3 SCHEME LOGIC
The product is supplied with Programmable Scheme Logic (PSL).
The Scheme Logic is a functional module within the IED, through which all mapping of inputs to outputs is handled.
Programmable Scheme Logic (PSL) is built around a concept called the FlexLogic Operand. These FlexLogic
oeprands encompasses all of the digital signals which are used in the PSL. The FlexLogic operands included digital
inputs, outputs, and internal signals.
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

Output relays
Goose outputs
Control inputs

Goose inputs

Control input Ethernet

module processing module

V06928
Figure 140: 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.

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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 INPUTS menu there is a global nominal voltage setting. If all opto-inputs are going to be energised
from the same voltage range, select the appropriate value with this setting.
The Contact Inputs are either open or closed with a programmable debounce time to prevent false operation from
induced voltage. The debounce time is adjustable by the user per manufacturer specifications.
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.
By default the pick-up threshold is 80% of the minimum DC input value. You can change this to other available
thresholds if required. Other available thresholds are 50% - 70% and 75%. Drop-off is fixed at 20% of Nominal
Voltage.

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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.

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6 VIRTUAL INPUTS
The P40 relay is equipped with 128 Virtual Inputs that can be individually programmed to respond to input signals
from the keypad or from communications protocols. This has the following advantages over Contact Inputs only:
● The number of logic inputs can be increased without introducing additional hardware.
● Logic functions can be invoked from a remote location over a single communication channel.
● The same logic function can be invoked both locally via contact input or front panel keypad, and/or
remotely via communications.
● Panel switches can be replaced entirely by virtual switches to save cost and wiring.
All Virtual Input operands are defaulted to “Off” (logic 0) unless the appropriate input signal is received.
Path: SETPOINTS > INPUTS > VIRTUAL INPUTS > VIRTUAL INPUT
The following setting options are available:

FUNCTION
Range: Disabled, Enabled
Default: Disabled
If this setting is set to “Disabled,” the input will be forced to OFF (logic 0) regardless of any attempt to alter the
input. If set to “Enabled,” the input operates as shown on the logic
diagram below, and generates output FlexLogic operands in response to received input signals and the applied
settings.

NAME
Range: Up to 13 Alphanumeric Characters
Default: VI 1
An alphanumeric name may be assigned to a Virtual Input for diagnostic, setting, and event recording purposes.

TYPE
Range: Latched, Self-reset
Default: Latched
There are two types of operation: self-reset and latched. If VIRTUAL INPUT x TYPE is “SelfReset,” when the input
signal transits from OFF to ON the output operand will be set to ON for only one evaluation of the FlexLogic
equations, then return to OFF. If set to “Latched,” the virtual input sets the state of the output operand to the same
state as themost recent received input.

Note:
The self-reset operating mode generates the output operand for a single evaluation of the FlexLogic equations (i.e., a pulse of
one protection pass). If the operand is to be used anywhere other than internally in a FlexLogic equation, it will likely have to
be lengthened in time. A FlexLogic timer with a delayed reset time can perform this function.

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7 OUTPUTS
Remote inputs provide a means of exchanging digital state information between Ethernet networked devices
supporting IEC 61850. Remote inputs that create FlexLogic operands at the receiving relay are extracted from
GOOSE messages originating in remote devices. Remote input 1 must be programmed to replicate the logic state
of a specific signal from a specific remote device for local use. The programming is performed by the three settings
shown in the Virtual Inputs section.
Path: SETPOINTS\ INPUTS\ REMOTE INPUTS

7.1 OUTPUT RELAYS

The P40 Agile IED is equipped with a number of electromechanical output relays specified at the time of ordering.
The first output relay (Relay 1) in the IED is a Form A relay that can be used for Trip Coil monitoring, and is
designated for tripping the breaker. The relay is energized upon operation of any element with setpoint Function
set to Trip. The relay can be customized by changing the name and type, and adding triggers or blocking, as
shown in the Output Relay setpoint descriptions. OUTPUT RELAY 1 is programmed internally for tripping the
breaker, and it cannot be changed, disabled, or replaced by any other relay. Additional output relays can be
selected to operate as well from the menu of each protection, control, or monitoring element.
The output relays supports facility to modify the behaviour of output contact by choosing different operating Mode
including Pickup, Dropoff, Dwell, Pulse, Pickup/Dropoff, Straight-through, Latching.
Relay #1 Trip and selected Relay Path: Setpoints\ Outputs \ Output Relays\ Aux Relay X

7.2 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:

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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.

7.3 VIRTUAL OUTPUTS

There are 128 virtual outputs that may be assigned via Logic configuration. If not assigned, the output is forced to
OFF (Logic 0). An ID may be assigned to each virtual output. Virtual outputs are resolved in each pass through the
evaluation of the logic equations.
For example, if Virtual Output 1 is the trip signal from FlexLogic and the trip relay is used to signal events, the
settings would be programmed as follows:
VIRTUAL OUTPUT 1 NAME: Trip
VIRTUAL OUTPUT 1 Events: Enabled
Path: SETPOINTS > OUTPUTS > VIRTUAL OUTPUTS > VIRTUAL OUTPUTS 1 (32)

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COMMUNICATIONS
Chapter 17 - Communications P14D

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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 309
Communication Interfaces 310
Serial Communication 311
Ethernet Communication 314
Data Protocols 315
Time Synchronisation 338

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2 COMMUNICATION INTERFACES
The P40 Agile Enhanced 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

Local settings
Front Standard USB MODBUS
Firmware download
SCADA
Rear serial port 1 Standard RS485 Remote settings MODBUS, IEC 60870-5-103, DNP3.0
IRIG-B
SCADA
Rear Ethernet
Optional Ethernet/copper Remote settings MODBUS, DNP3.0, IEC 61850
port
Firmware update

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3 SERIAL COMMUNICATION
The physical layer standards that are used for serial communications for SCADA purposes.
RS485 is similar to RS232 but for longer distances and it allows daisy-chaining and multi-dropping of IEDs.
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.
A full description of the RS485 is available in the published standard.

3.1 MODBUS PROTOCOL

All Ethernet ports and serial communication ports support the Modbus protocol. The only exception is if the serial
port has been configured for DNP or IEC 60870-5-103 operation (see descriptions below). This allows the Toolsuite
Setup software (which is a Modbus master application) to communicate to the IED.
The P14D IED implements a subset of the Modicon Modbus RTU serial communication standard. The Modbus
protocol is hardware-independent. That is, the physical layer can be any of a variety of standard hardware
configurations. This includes USB, RS485, RJ45 etc. Modbus is a single master / multiple slave type of protocol
suitable for a multi-drop configuration.
The P14D is always a Modbus slave with a valid slave address range 1 to 254.

Data Frame Format and Data Rate

One data frame of an asynchronous transmission to or from an IED typically consists of 1 start bit, 8 data bits, and
1 stop bit. This produces a 10-bit data frame. This is important for transmission through modems at high bit rates.
Modbus protocol can be implemented at any standard communication speed. The IED supports operation at 9600,
19200, 38400, 57600, and 115200 bps baud rate. The USB interface supports ModBus TCP/IP.

Function Codes Supported

The following functions are supported by the P40 Agile Enhanced:
● FUNCTION CODE 03H - Read Setpoints
● FUNCTION CODE 04H - Read Actual Values
● FUNCTION CODE 05H - Execute Operation
● FUNCTION CODE 06H - Store Single Setpoint
● FUNCTION CODE 07H - Read Device Status
● FUNCTION CODE 08H - Loopback Test
● FUNCTION CODE 10H - Store Multiple Setpoints
When a ModBus master communicates to the IED over Ethernet, the IED slave address, TCP port number and the
IED IP address for the associated port must be configured and are also configured within the Master for this
device. The default ModBus TCP port number is 502.
Configurable ModBus parameters are found at the following path:
Path: SETPOINTS > DEVICE > COMMUNICATIONS > MODBUS PROTOCOL

Note:
Refer to MODBUS CHAPTER at Data protocols section for detailed specifications

3.1.1 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.

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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 141: 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.

3.2 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.
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.
On the rear card P40 enhanced Series relays are equipped with one serial communication port. The RS485 port
has settings for baud rate and parity. It is important that these parameters agree with the settings used on the

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computer or other equipment connected to this port. A maximum of 32 relays can be daisy-chained and
connected to a DCS, PLC or a PC using the RS485 port.
Path: SETPOINTS > DEVICE > COMMUNICATIONS > RS485

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4 ETHERNET COMMUNICATION
The Ethernet interface is required for either IEC 61850 and/or DNP3 over Ethernet (protocol must be selected at
time of order). With either of these protocols, the Ethernet interface also offers communication with ModBus TCP
for remote configuration and record extraction.
The device can also be connected to either a 10Base-T or a 100Base-TX Ethernet hub or switch using the RJ45
port. The port automatically senses which type of hub is connected.
The pins on the RJ45connector are 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

4.1 USB
The USB port is used for connecting computers locally for the purposes of transferring settings, measurements
and records to/from the computer to the IED and to download firmware updates from a local computer to the IED.
The USB parameters are as follows:
IP Address: 172.16.0.2
IP Mask: 255.255.255.0
IP Gateway: 172.16.0.1

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5 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
MODBUS RS485, Ethernet 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
Data Protocols MODBUS IEC 61850
DNP3.0 DNP3.0
Data Link Layer EIA(RS)485 Ethernet USB
Physical Layer Copper

5.1 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 P40 Agile Enhanced. 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 point map for
the IEC 60870-5-103 is different from the one shared by IEC 104 and DNP protocols.

Cause of Transmission
Cause of transmission is an unsigned integer and it shall take one of the values specified in the following tables:
In monitor direction
<1> Spontaneous
<2> Cyclic
<3> Reset frame count bit (FCB)
<4> Reset communication unit (CU)
<5> Start/restart
<6> Power on
<8> Time synchronization
<9> General interrogation
<10> Termination of general interrogation

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<20> Positive ack of command

<21> Nack of command

In control direction
<8> Time synchronization

<9> Initiation of general interogation

<20> General command

5.1.1 PHYSICAL CONNECTION AND LINK LAYER

There is just one option for IEC 60870-5-103:
● Rear serial port 1- for permanent SCADA connection via RS485

Note:
DNP, IEC 60870-5-103 and Modbus may not be enabled simultaneously on the RS485 serial port. But you may enable DNP on
Ethernet and IEC 60870-5-103 on serial RS485.

The IED address and baud rate can be selected using the front panel menu or by a suitable application such as
EnerVista Flex.

5.1.2 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.

5.1.3 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.

5.1.4 EC103 INTEROPERABILITY

Physical layer
Electrical interface
EIA RS-485
32 Number of loads for one protection equipment

Optical Interface

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Glass fibre
Plastic fibre
F-SMA type connector
BFOC/2,5 type connector
Transmission Speed
9600 bits/s
19200 bits/s
38400 bits/s
57600 bits/s
115200 bits/s

Link Layer
There are no choices for the link layer.

Application Layer
Transmission mode for application data
Mode 1 (least significant octet first), as defined in 4.10 of IEC 60870-5-4, is used exclusively in this companion
standard.
Common address of ASDU
One COMMON ADDRESS OF ASDU (identical with station address)
More than one COMMON ADDRESS OF ASDU
Selection of standard information numbers in monitor direction
System functions in monitor direction
INF Semantics
<0> End of general interrogation
<0> Time synchronization
<2> Reset FCB
<3> Reset CU
<4> Start/restart
<5> Power on
Status indications in monitor direction
INF Semantics
<16> Auto-recloser active
<17> Teleprotection active
<18> Protection active
<19> LED reset
<20> Monitor direction blocked
<21> Test mode
<22> Local parameter setting

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<23> Characteristic 1
<24> Characteristic 2
<25> Characteristic 3
<26> Characteristic 4
<27> Auxiliary input 1
<28> Auxiliary input 2
<29> Auxiliary input 3
<30> Auxiliary input 4
Supervision indications in monitor direction
INF Semantics
<32> Measurand supervision I
<33> Measurand supervision V
<35> Phase sequence supervision
<36> Trip circuit supervision
<37> I>> back-up operation
<38> VT fuse failure
<39> Teleprotection disturbed
<46> Group warning
<47> Group alarm
Earth fault indications in monitor direction
INF Semantics
<48> Earth fault L1
<49> Earth fault L2
<50> Earth fault L3
<51> Earth fault forward, i.e. line
<52> Earth fault reverse, i.e. busbar
Fault indications in monitor direction
INF Semantics
<64> Start / pick-up L1
<65> Start / pick-up L2
<66> Start / pick-up L3
<67> Start / pick-up N
<68> General trip
<69> Trip L1
<70> Trip L2
<71> Trip L3
<72> Trip I>> (back-up operation)
<73> Fault location X in ohms

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<74> Fault forward / line

<75> Fault reverse / busbar
<76> Teleprotection signal transmitted
<77> Teleprotection signal received
<78> Zone 1
<79> Zone 2
<80> Zone 3
<81> Zone 4
<82> Zone 5
<83> Zone 6
<84> General start / pick-up
<85> Breaker failure
<86> Trip measuring system L1
<87> Trip measuring system L2
<88> Trip measuring system L3
<89> Trip measuring system E
<90> Trip I>
<91> Trip I>>
<92> Trip IN>
<93> Trip IN>>
Auto-reclosure indications in monitor direction
INF Semantics
<128> CB ‘on’ by AR
<129> CB ‘on’ by long-time AR
<130> AR blocked
Measurands in monitor direction
INF Semantics
<144> Measurand I
<145> Measurands I, V
<146> Measurands I, V, P, Q
<147> Measurands In, Ven
<148> Measurands IL123, VL123, P, Q, f
Generic functions in monitor direction
INF Semantics
<240> Read headings of all defined groups
<241> Read values or attributes of all entries of one group
<243> Read directory of a single entry
<244> Read value or attribute of a single entry

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<245> End of general interrogation of generic data

<249> Write entry with confirmation
<250> Write entry with execution
<251> Write entry aborted
Selection of standard information numbers in control direction
System functions in control direction
INF Semantics
<0> Initiation of general interrogation
<0> Time synchronization
General commands in control direction
INF Semantics
<16> Auto-recloser on / off
<17> Teleprotection on / off
<18> Protection on / off
<19> LED reset
<23> Activate characteristic 1
<24> Activate characteristic 2
<25> Activate characteristic 3
<26> Activate characteristic 4
Generic functions in control direction
INF Semantics
<240> Read headings of all defined groups
<241> Read values or attributes of all entries of one group
<243> Read directory of a single entry
<244> Read value or attribute of a single entry
<245> General interrogation of generic data
<248> Write entry
<249> Write entry with confirmation
<250> Write entry with execution
<251> Write entry abort
Basic application functions
Test mode
Blocking of monitor direction
Disturbance data
Generic services
Private data
Miscellaneous
Measurand Max. MVAL = times rated value

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1,2 or 2,4
Current L1
Current L2
Current L3
Voltage L1-E
Voltage L2-E
Voltage L3-E
Active power P
Reactive power Q
Frequency f
Voltage L1-L2

5.2 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.
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).

5.2.1 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 serial port 1 - for permanent SCADA connection via RS485
● The rear Ethernet RJ45 port - for permanent SCADA Ethernet connection
With DNP3 Over Ethernet, a maximum of 2 Clients can be configured.
The IED address and baud rate can be selected using the front panel menu or by a suitable application.
When using a serial interface, the data format is: 1 start bit, 8 data bits, 1 stop bit and optional configurable parity
bit.

Binary input data

Binary input data is used to monitor two-state device operations such as the position of a breaker. The user can
configure up to 96 Binary inputs. All binary inputs are configured from PSL signals.

Binary output data

Binary output data is used to control two-state devices such as the opening and closing of a breaker. The SR8 can
be configured to support up to 32 Binary outputs. The client’s Binary outputs are mapped to a list of Virtual Inputs
and Coils. Please note that the number of Binary/ Control outputs is configurable. Of the total number of outputs
configured the user can configure a subset that supports dual point control.

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Analog input data

Analog input data is used to monitor analog signals such as voltages, currents, and power. The SR8 has 32 analog
points.

Analog output data

Not supported in SR8

Time stamps

Count input data

Count input data could represent a cumulative quantity such as kilowatt hours of energy. The SR8 has 16 Count
input data.
Supported Object Numbers
Object DNP Data Type SR8
1 Binary Input status User assigned Flexlogic Operands
2 Binary Input change since last read
10 Binary output status for monitoring User assigned Virtual Inputs and/or
Commands (client looks at status only)
12 Control Relay Output Block User assigned Virtual Inputs and/or
Commands (client can write to the user
specified number of control relay
outputs)
20 Counter value Digital counters 1 through 16,
21 Frozen counter value
22 Counter value change since last read
23 Frozen counter value change since last
read by client
30 User configured Analog input value
32 User configured Analog input value
changed since last time read by client.

5.2.2 OBJECT 1 BINARY INPUTS

The DNP binary input data points are configured under the path: DNP > POINT LISTS BINARY INPUT. When a freeze
function is performed on a binary counter point, the frozen value is available in the corresponding frozen counter
point.

Binary Input Points

Static (Steady-State) Object Number: 1
Change Event Object Number: 2
Request Function Codes supported: 1 (read), 22 (assign class)
Static Variation reported when variation 0 requested: 2 (Binary Input with status), Configurable
Change Event Variation reported when variation 0 requested: 2 (Binary Input Change with Time), Configurable
Change Event Scan Rate: 8 times per power system cycle
Change Event Buffer Size: 1024
Default Class for All Points: 1

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5.2.3 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).
Object Number: 10
Request Function Codes supported: 1 (read)
Default Variation reported when Variation 0 requested: 2 (Binary Output Status)

5.2.4 OBJECT 20 BINARY COUNTERS

The following details lists both Binary Counters (Object 20) and Frozen Counters (Object 21). When a freeze function
is performed on a Binary Counter point, the frozen value is available in the corresponding Frozen Counter point.
IED Digital Counter values are represented as 16 or 32-bit integers. The DNP 3.0 protocol defines counters to be
unsigned integers. Care should be taken when interpreting negative counter values.

Binary Counters
Static (Steady-State) Object Number: 20
Change Event Object Number: 22
Request Function Codes supported: 1 (read), 7 (freeze), 8 (freeze noack), 9 (freeze and clear), 10 (freeze and clear,
noack), 22 (assign class)
Static Variation reported when variation 0 requested: 1 (32-Bit Binary Counter with Flag)
Change Event Variation reported when variation 0 requested: 1 (32-Bit Counter
Change Event without time)
Change Event Buffer Size: 10
Default Class for all points: 3

Frozen Counters
Static (Steady-State) Object Number: 21
Change Event Object Number: 23
Request Function Codes supported: 1 (read)
Static Variation reported when variation 0 requested: 1 (32-Bit Frozen Counter with Flag)
Change Event Variation reported when variation 0 requested: 1 (32-Bit Counter Change Event without time)
Change Event Buffer Size: 10
Default Class for all points: 3

Binary and Frozen Counters Point Index Name/Description

0 Digital Counter 1
1 Digital Counter 2
2 Digital Counter 3
3 Digital Counter 4
4 Digital Counter 5
5 Digital Counter 6

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6 Digital Counter 7
7 Digital Counter 8
8 Digital Counter 9
9 Digital Counter 10
10 Digital Counter 11
11 Digital Counter 12
12 Digital Counter 13
13 Digital Counter 14
14 Digital Counter 15
15 Digital Counter 16

5.2.5 OBJECT 30 ANALOGUE INPUT

It is important to note that 16-bit and 32-bit variations of analog inputs are transmitted through DNP as signed
numbers. Even for analog input points that are not valid as negative values, the maximum positive representation
is 32767 for 16-bit values and 2147483647 for 32-bit values. This is a DNP requirement. The deadbands for all
Analog Input points are in the same units as the Analog Input quantity. For example, an Analog Input quantity
measured in volts has a corresponding deadband in units of volts. Relay settings are available to set default
deadband values according to data type. Deadbands for individual Analog Input Points can be set using DNP
Object 34.

Note:
1. A default variation refers to the variation response when variation 0 is requested and/or in class 0, 1, 2, or 3 scans. The
default variations for object types 1, 2, 20, 21, 22, 23, 30, and 32 are selected via relay settings. This optimizes the class 0 poll
data size.

Note:
2. For static (non-change-event) objects, qualifiers 17 or 28 are only responded when a request is sent with qualifiers 17 or 28,
respectively. Otherwise, static object requests sent with qualifiers 00, 01, 06, 07, or 08, are responded with qualifiers 00 or 01.
For change event objects, qualifiers 17 or 28 are always responded.

Note:
3. Cold restarts are implemented the same as warm restarts – the P40 Agile Enhanced is not restarted, but the DNP process is
restarted.

Note:
4. Only value changes of Binary or Analog Points are considered as events. Flag changes i.e. say a point becomes offline to
online with same value or Time stamp changes i.e. the time stamp of say frozen counter events changes without value
change are not considered as events and not reported to master as events.

5.2.6 DNP3 DEVICE PROFILE

This section describes the specific implementation of DNP version 3.0 within General Electric P40 Agile Enhanced
IEDs for both compact and modular ranges.

5.2.6.1 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

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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.

(Also see the IMPLEMENTATION TABLE in the following section)

Vendor Name: General Electric
Device Name: P40 Agile Enhanced
Highest DNP Level Supported:
For Requests: Level 2
For Responses: Level 2
Device Function:
¨ Master
þ Slave
Notable objects, functions, and/or qualifiers supported in addition to the Highest DNP Levels Supported (the complete
list is described in the attached table):
Binary Inputs (Object 1)
Binary Input Changes (Object 2)
Binary Outputs (Object 10)
Control Relay Output Block (Object 12)
Binary Counters (Object 20)
Frozen Counters (Object 21)
Counter Change Event (Object 22)
Frozen Counter Event (Object 23)
Analog Inputs (Object 30)
Analog Input Changes (Object 32)
Analog Deadbands (Object 34)
Time and Date (Object 50)
Time Delay Fine (Object 52)
Class Data (Object 60)
Internal Indications (Object 80)
Maximum Data Link Frame Size (octets): Maximum Application Fragment Size (octets):
Transmitted: 292 Transmitted: configurable up to 2048
Received: 292 Received: 2048
Maximum Data Link Re-tries: Maximum Application Layer Re-tries:
þ None þ None
¨ Fixed at 3 ¨ Configurable
¨ Configurable
Requires Data Link Layer Confirmation:
þ Never
¨ Always
¨ Sometimes
¨ Configurable
Requires Application Layer Confirmation:
¨ Never
¨ Always
þ When reporting Event Data
þ When sending multi-fragment responses
¨ Sometimes
¨ Configurable

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Timeouts while waiting for:

Data Link Confirm: þ None ¨ Fixed at ____ ¨ Variable ¨ Configurable
Complete Appl. Fragment: þ None ¨ Fixed at ____ ¨ Variable ¨ Configurable
Application Confirm: ¨ None þ Fixed at 10 s ¨ Variable ¨ Configurable
Complete Appl. Response: þ None ¨ Fixed at ____ ¨ Variable ¨ Configurable
Others:
Transmission Delay: No intentional delay
Need Time Interval: Configurable (default = 24 hrs.)
Select/Operate Arm Timeout: 10 s
Binary input change scanning period: 8 times per power system cycle
Analog input change scanning period: 500 ms
Counter change scanning period: 500 ms
Frozen counter event scanning period: 500 ms

Sends/Executes Control Operations:

WRITE Binary Outputs þ Never ¨ Always ¨ Sometimes ¨ Configurable
SELECT/OPERATE ¨ Never þ Always ¨ Sometimes ¨ Configurable
DIRECT OPERATE ¨ Never þ Always ¨ Sometimes ¨ Configurable
DIRECT OPERATE – NO ACK ¨ Never þ Always ¨ Sometimes ¨ Configurable
Count > 1 þ Never ¨ Always ¨ Sometimes ¨ Configurable
Pulse On ¨ Never ¨ Always þ Sometimes ¨ Configurable
Pulse Off ¨ Never ¨ Always þ Sometimes ¨ Configurable
Latch On ¨ Never ¨ Always þ Sometimes ¨ Configurable
Latch Off ¨ Never ¨ Always þ Sometimes ¨ Configurable
Queue þ Never ¨ Always ¨ Sometimes ¨ Configurable
Clear Queue þ Never ¨ Always ¨ Sometimes ¨ Configurable
Explanation of ‘Sometimes’: Object 12 points are mapped to Virtual Inputs and Commands(Force Coils). Both "Pulse On" and
"Latch On" operations perform the same function in the series8; that is, the appropriate Virtual Input or Coil is put into the "On"
state. The On/Off times and Count value are ignored. "Pulse Off" and "Latch Off" operations put the appropriate Virtual Input or
Coil into the "Off" state. "Trip" and "Close" operations both put the appropriate Virtual Input or coil into the "On" state if a paired
mapping is set., otherwise "Trip" will put into "Off" and "Close" will put into "On".

Reports Binary Input Change Events when no Reports time-tagged Binary Input Change Events when no
specific variation requested: specific variation requested:
¨ Never ¨ Never
þ Only time-tagged þ Binary Input Change With Time
¨ Only non-time-tagged ¨ Binary Input Change With Relative Time
¨ Configurable ¨ Configurable (attach explanation)
Sends Unsolicited Responses: Sends Static Data in Unsolicited Responses:
¨ Never þ Never
¨ Configurable ¨ When Device Restarts
¨ Only certain objects ¨ When Status Flags Change
þ Sometimes No other options are permitted.
þ ENABLE/DISABLE unsolicited Function codes supported

Explanation of ‘Sometimes’: It will be disabled for RS-485

applications, since there is no collision avoidance mechanism.
For ethernet communication it will be available and it can be
disabled or enabled with the proper function code.

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Default Counter Object/Variation: Counters Roll Over at:

¨ No Counters Reported ¨ No Counters Reported
¨ Configurable (attach explanation) ¨ Configurable (attach explanation)
þ Default Object: 20 þ 16 Bits
Default Variation: 1 ¨ 32 Bits
þ Point-by-point list attached ¨ Other Value: _____
þ Point-by-point list attached
Sends Multi-Fragment Responses:
þ Yes
¨ No

5.2.6.2 DNP3 IMPLEMENTATION TABLE

The implementation table provides a list of objects, variations and control codes supported by the device:

Object No. Variation Description Function Codes Qualifier Codes Function Codes Qualifier Codes
No. (DEC) (HEX) (DEC) (HEX)
1 0 Binary Input 1 (read) 00, 01 (start-stop)
(Variation 0 is used 22 (assign class) 06 (no range, or all)
to request 07, 08 (limited
default variation) quantity)
17, 28 (index)
1 Binary Input 1 (read) 00, 01 (start-stop) 129 (response) 00, 01 (start-stop)
22 (assign class) 06 (no range, or all) 17, 28 (index)
07, 08 (limited (see Note 2)
quantity)
17, 28 (index)
2 Binary Input with 1 (read) 00, 01 (start-stop) 129 (response) 00, 01 (start-stop)
Status 22 (assign class) 06 (no range, or all) 17, 28 (index)
07, 08 (limited (see Note 2)
quantity)
17, 28 (index)
2 0 Binary Input 1 (read) 06 (no range, or all)
Change (Variation 07, 08 (limited
0 is used to quantity)
request default
variation)
1 Binary Input 1 (read) 06 (no range, or all) 129 (response) 17, 28 (index)
Change without 07, 08 (limited 130 (unsol. resp.)
Time quantity)
2 Binary Input 1 (read) 06 (no range, or all) 129 (response 17, 28 (index)
Change with Time 07, 08 (limited 130 (unsol. resp.)
quantity)
3 Binary Input 1 (read) 06 (no range, or all)
Change with 07, 08 (limited
Relative Time quantity)

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10 0 Binary Output 1 (read) 00, 01(start-stop)

Status (Variation 0 06 (no range, or all)
is used to 07, 08 (limited
request default quantity)
variation) 17, 28 (index)
2 Binary Output 1 (read) 00, 01 (start-stop) 129 (response) 00, 01 (start-stop)
Status 06 (no range, or all) 17, 28 (index)
07, 08 (limited (see Note 2)
quantity)
17, 28 (index)
12 1 Control Relay 3 (select) 00, 01 (start-stop) 129 (response) echo of request
Output Block 4 (operate) 07, 08 (limited
5 (direct op) quantity)
6 (dir. op, noack) 17, 28 (index)
20 0 Binary Counter 1 (read) 00, 01(start-stop)
(Variation 0 is used 7 (freeze) 06(no range, or all)
to request default 8 (freeze noack) 07, 08(limited
variation) 9 (freeze clear) quantity)
10 (frz. cl. noack) 17, 28(index)
22 (assign class)
1 32-Bit Binary 1 (read) 00, 01 (start-stop) 129 (response) 00, 01 (start-stop)
Counter 7 (freeze) 06 (no range, or all) 17, 28 (index)
8 (freeze noack) 07, 08 (limited (see Note 2)
9 (freeze clear) quantity)
10 (frz. cl. noack) 17, 28 (index)
22 (assign class)
2 16-Bit Binary 1 (read) 00, 01 (start-stop) 129 (response) 00, 01 (start-stop)
Counter 7 (freeze) 06 (no range, or all) 17, 28 (index)
8 (freeze noack) 07, 08 (limited (see Note 2)
9 (freeze clear) quantity)
10 (frz. cl. noack) 17, 28 (index)
22 (assign class)
5 32-Bit Binary 1 (read) 00, 01 (start-stop) 129 (response) 00, 01 (start-stop)
Counter without 7 (freeze) 06 (no range, or all) 17, 28 (index)
Flag 8 (freeze noack) 07, 08 (limited (see Note 2)
9 (freeze clear) quantity)
10 (frz. cl. noack) 17, 28 (index)
22 (assign class)
6 16-Bit Binary 1 (read) 00, 01 (start-stop) 129 (response) 00, 01 (start-stop)
Counter without 7 (freeze) 06 (no range, or all) 17, 28 (index)
Flag 8 (freeze noack) 07, 08 (limited (see Note 2)
9 (freeze clear) quantity)
10 (frz. cl. noack) 17, 28 (index)
22 (assign class)

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21 0 Frozen Counter 1 (read) 00, 01 (start-stop)

(Variation 0 is used 22 (assign class) 06 (no range, or all)
to request default 07, 08 (limited
variation) quantity)
17, 28 (index)
1 32-Bit Frozen 1 (read) 00, 01 (start-stop) 129 (response) 00, 01 (start-stop)
Counter 22 (assign class) 06 (no range, or all) 17, 28 (index)
07, 08 (limited (see Note 2)
quantity)
17, 28 (index)
2 16-Bit Frozen 1 (read) 00, 01 (start-stop) 129 (response) 00, 01 (start-stop)
Counter 22 (assign class) 06 (no range, or all) 17, 28 (index)
07, 08 (limited (see Note 2)
quantity)
17, 28 (index)
9 32-Bit Frozen 1 (read) 00, 01 (start-stop) 129 (response) 00, 01 (start-stop)
Counter without 22 (assign class) 06 (no range, or all) 17, 28 (index)
Flag 07, 08 (limited (see Note 2)
quantity)
17, 28 (index)
10 16-Bit Frozen 1 (read) 00, 01 (start-stop) 129 (response) 00, 01 (start-stop)
Counter without 22 (assign class) 06 (no range, or all) 17, 28 (index)
Flag 07, 08 (limited (see Note 2)
quantity)
17, 28 (index)
22 0 Counter Change 1 (read) 06 (no range, or all)
Event (Variation 0 07, 08 (limited
is used to request quantity)
default variation)
1 32-Bit Counter 1 (read) 06 (no range, or all) 129 (response) 17, 28 (index)
Change Event 07, 08 (limited 130 (unsol. resp.)
quantity)
2 16-Bit Counter 1 (read) 06 (no range, or all) 129 (response) 17, 28 (index)
Change Event 07, 08 (limited 130 (unsol. resp.)
quantity)
5 32-Bit Counter 1 (read) 06 (no range, or all) 129 (response) 17, 28 (index)
Change Event with 07, 08 (limited 130 (unsol. resp.)
Time quantity)
6 16-Bit Counter 1 (read) 06 (no range, or all) 129 (response) 17, 28 (index)
Change Event with 07, 08 (limited 130 (unsol. resp.)
Time quantity)

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23 0 Frozen Counter 1 (read) 06 (no range, or all)

Event (Variation 0 07, 08 (limited
is used to request quantity)
default variation)
1 32-Bit Frozen 1 (read) 06 (no range, or all) 129 (response) 17, 28 (index)
Counter Event 07, 08 (limited 130 (unsol. resp.)
quantity)
2 16-Bit Frozen 1 (read) 06 (no range, or all) 129 (response) 17, 28 (index)
Counter Event 07, 08 (limited 130 (unsol. resp.)
quantity)
5 32-Bit Frozen 1 (read) 06 (no range, or all) 129 (response) 17, 28 (index)
Counter Event with 07, 08 (limited 130 (unsol. resp.)
Time quantity)
6 16-Bit Frozen 1 (read) 06 (no range, or all) 129 (response) 17, 28 (index)
Counter Event with 07, 08 (limited 130 (unsol. resp.)
Time quantity)
30 0 Analog Input 1 (read) 00, 01 (start-stop)
(Variation 0 is used 22 (assign class) 06 (no range, or all)
to request default 07, 08 (limited
variation) quantity)
17, 28 (index)
1 32-Bit Analog 1 (read) 00, 01 (start-stop) 129 (response) 00, 01 (start-stop)
Input 22 (assign class) 06 (no range, or all) 17, 28 (index)
07, 08 (limited (see Note 2)
quantity)
17, 28 (index)
2 16-Bit Analog 1 (read) 00, 01 (start-stop) 129 (response) 00, 01 (start-stop)
Input 22 (assign class) 06 (no range, or all) 17, 28 (index)
07, 08 (limited (see Note 2)
quantity)
17, 28 (index)
3 32-Bit Analog 1 (read) 00, 01 (start-stop) 129 (response) 00, 01 (start-stop)
Input without Flag 22 (assign class) 06 (no range, or all) 17, 28 (index)
07, 08 (limited (see Note 2)
quantity)
17, 28 (index)
4 16-Bit Analog 1 (read) 00, 01 (start-stop) 129 (response) 00, 01 (start-stop)
Input without Flag 22 (assign class) 06 (no range, or all) 17, 28 (index)
07, 08 (limited (see Note 2)
quantity)
17, 28 (index)
5 short floating point 1 (read) 00, 01 (start-stop) 129 (response) 00, 01 (start-stop)
22 (assign class) 06 (no range, or all) 17, 28 (index)
07, 08 (limited (see Note 2)
quantity)
17, 28 (index)

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32 0 Analog Change 1 (read) 06 (no range, or all)

Event (Variation 0 07, 08 (limited
is used to request quantity)
default variation)
1 32-Bit Analog 1 (read) 06 (no range, or all) 129 (response) 17, 28 (index)
Change Event 07, 08 (limited 130 (unsol. resp.)
without Time quantity)
2 16-Bit Analog 1 (read) 06 (no range, or all) 129 (response) 17, 28 (index)
Change Event 07, 08 (limited 130 (unsol. resp.)
without Time quantity)
3 32-Bit Analog 1 (read) 06 (no range, or all) 129 (response) 17, 28 (index)
Change Event with 07, 08 (limited 130 (unsol. resp.)
Time quantity)
4 16-Bit Analog 1 (read) 06 (no range, or all) 129 (response) 17, 28 (index)
Change Event with 07, 08 (limited 130 (unsol. resp.)
Time quantity)
5 short floating point 1 (read) 06 (no range, or all) 129 (response) 17, 28 (index)
Analog Change 07, 08 (limited 130 (unsol. resp.)
Event without Time quantity)
7 short floating point 1 (read) 06 (no range, or all) 129 (response) 17, 28 (index)
Analog Change 07, 08 (limited 130 (unsol. resp.)
Event with Time quantity)
34 0 Analog Input 1 (read) 00, 01 (start-stop)
Reporting 06 (no range, or all)
Deadband 07, 08 (limited
(Variation 0 is used quantity)
to request default 17, 28 (index)
variation)
1 16-bit Analog 1 (read) 00, 01 (start-stop) 129 (response) 00, 01 (start-stop)
Input Reporting 06 (no range, or all) 17, 28 (index)
Deadband 07, 08 (limited (see Note 2)
(default - see Note quantity)
1) 17, 28 (index)
2 (write) 00, 01 (start-stop)
07, 08 (limited
quantity)
17, 28 (index)
2 32-bit Analog 1 (read) 00, 01 (start-stop) 129 (response) 00, 01 (start-stop)
Input Reporting 06 (no range, or all) 17, 28 (index)
Deadband 07, 08 (limited (see Note 2)
quantity)
17, 28 (index)
2 (write) 00, 01 (start-stop)
07, 08 (limited
quantity)
17, 28 (index)
50 1 Time and Date 1 (read) 00, 01 (start-stop) 129 (response) 00, 01 (start-stop)
(default - see Note 2 (write) 06 (no range, or all) 17, 28 (index)
1) 07 (limited qty=1) (see Note 2)
08 (limited
quantity)
17, 28 (index)
52 2 Time Delay Fine 129 (response) 07 (limited
(quantity = 1) quantity)

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60 0 Class 0, 1, 2, and 3 1 (read) 06 (no range, or all)

Data – used for 20 (enable unsol)
changing the class 21 (disable unsol)
of objects and 22 (assign class)
enabling/disabling
unsolicited
responses.
1 Class 0 Data 1 (read) 06 (no range, or all)
22 (assign class)
2 Class 1 Data 1 (read) 06 (no range, or all)
20 (enable unsol) 07, 08 (limited
3 Class 2 Data 21 (disable unsol) quantity)
22 (assign class)
4 Class 3 Data
80 1 Internal indications 1 (read) 00, 01 (start-stop) 129 (response) 00, 01 (start-stop)
clearing (index =7)
2 (write) 00 (start-stop)
(see Note 3) (index =7)
No Object (function 13 (cold restart)
code only)
see Note 3
No Object (function 14 (warm restart)
code only)
No Object (function 23 (delay meas.)
code only)

Note:
1: A default variation refers to the variation responded when variation 0 is requested and/or in class 0, 1, 2, or 3 scans. The
default variations for object types 1, 2, 20, 21, 22, 23, 30, and 32 are selected via relay settings. This optimizes the class 0 poll
data size.

Note:
2: For static (non-change-event) objects, qualifiers 17 or 28 are only responded 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 with qualifiers 00 or
01 (for change event objects, qualifiers 17 or 28 are always responded.)

Note:
3: Cold restarts are implemented the same as warm restarts – the P40 Agile Enhanced is not restarted, but the DNP process is
restarted.

5.3 MODBUS
This section describes how the MODBUS 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
MODBUS standard.
The MODBUS protocol is a master/slave protocol, defined and administered by the MODBUS Organization For
further information on MODBUS and the protocol specifications, please see the Modbus web site
(www.modbus.org).

5.3.1 PHYSICAL CONNECTION AND LINK LAYER

DATA FRAME FORMAT AND DATA RATE

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One data frame of an asynchronous transmission to or from a P40 Agile Enhanced typically consists of 1 start bit,
8 data bits, and 1 stop bit. This produces a 10 bit data frame. This is important for transmission through modems
at high bit rates.
Modbus protocol can be implemented at any standard communication speed. The P40 Agile Enhanced supports
operation at 9600, 19200, 38400, 57600, and 115200 baud. The USB and Ethernet interfaces support ModBus
TCP/IP.

5.3.2 RESPONSE CODES

MCode MODBUS Description MiCOM Interpretation

01 Illegal Function The function code transmitted is not supported by the slave.
02 Illegal Data Address The data address in the request is not an allowable value.
03 Illegal Data Value A value referenced in the data field transmitted by the master is not within range.

5.3.3 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.
The P40 Agile Enhanced supports both the IEC61850 GOOSE and IEC 61850 MMS Server service as per IEC 61850
standard Ed. 2. The GOOSE messaging service provides the 8 Series relay unit the ability to Publish/Subscribe
Digital Input and other element statuses and its Quality and Timestamp to/from other IEDs with supporting GOOSE
messaging service. Server support allows remote control center, RTU/Gateway, local HMI or other client role
devices access to the relay for monitoring and control. The configuration of IEC61850 services is accomplished
using the Enervista Flex Setup software.

5.3.3.1 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)

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5.3.3.2 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.

5.3.3.3 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.

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 142: 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.

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5.3.3.4 IEC 61850 IN MICOM IEDS

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

The IEC 61850 compatible interface standard provides capability for the following:
● Read access to measurements
● Refresh of all measurements at a standard rate.
● Generation of non-buffered and 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 IEC 61850 MMS file transfer. The record is extracted as an ASCII format
COMTRADE file

● Controls (Direct and Select Before Operate)

5.3.3.5 IEC 61850 DATA MODEL IMPLEMENTATION

The data model is described in the Model Implementation Conformance Statement (MICS) document, which is
available as a separate document.

5.3.3.6 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.

5.3.3.7 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.

5.3.3.8 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

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● INT8
● UINT16
● UINT32
● UINT8

5.3.3.8.1 IEC 61850 GOOSE CONFIGURATION

All GOOSE configuration is performed using the software application.

5.3.3.9 ETHERNET DISCONNECTION

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.

5.3.3.10 LOSS OF POWER

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.

5.3.3.11 IEC 61850 CONFIGURATION

The EnerVista Flex 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.

5.3.3.11.1 IEC 61850 CONFIGURATION BANKS

There are two configuration banks:
● Active Configuration Bank
● Inactive Configuration Bank

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.

5.3.3.11.2 IEC 61850 NETWORK CONNECTIVITY

Configuration of the IP parameters is performed by the EnerVista Flex 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.

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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.

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6 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
● Using the SNTP time protocol
● By using the time synchronisation functionality inherent in the data protocols

6.1 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 satellite

GPS time signal

IRIG-B

Satellite dish Receiver IED IED IED

V01040

Figure 143: 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

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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).

6.1.1 DEMODULATED IRIG-B IMPLEMENTATION

All models have the option of accepting a demodulated IRIG-B input.
To set the device to use IRIG-B, use the setting IRIG-B Sync cell in the DATE AND TIME column. This can be set to
None (for no IRIG-B), RP1 (for the option where IRIG-B uses terminals 54 and 56) and RP2 (for the option where
IRIG-B uses terminals 82 and 84)
The IRIG-B status can be viewed in the IRIG-B Status cell in the DATE AND TIME column.

6.2 SNTP
SNTP is used to synchronise the clocks of computer systems over packet-switched, variable-latency data
networks, such as IP.
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 EnerVista Flex Setup Software.
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.
P40 Agile Enhanced SNTP synchronisation may take up to 1-2 minutes, as it needs to get many time values and
average them.

6.3 TIME SYNCHRONISATION USING THE COMMUNICATION PROTOCOLS

All communication protocols have in-built time synchronisation mechanisms. If an external time synchronisation
mechanism such as IRIG-B or SNTP 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.
The time synchronisation for each protocol is described in the relevant protocol description section.

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CYBER-SECURITY
Chapter 18 - Cyber-Security P14D

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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 343
The Need for Cyber-Security 344
Standards 345
Cyber-Security Implementation 350

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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 1686-2013

IEEE 1686-2013 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.

3.3 IEC 62351

EC 62351 is a standard developed for handling the security of IEC TC 57 series of protocols including IEC 60870-
5 series, IEC 60870-6 series, IEC 61850 series, IEC 61970 series & IEC 61968 series. The different security objectives
include authentication of data transfer through digital signatures, ensuring only authenticated access, prevention
of eavesdropping, prevention of playback and spoofing, and intrusion detection.
The Roles described in chapter 62351-8 apply. Below table shows predefined Roles assignment according to it:
SETTING
ROLE VIEW READ DATA SET REPORTING FILE READ FILE WRITE FILE MNGT CONTROL CONFIG SECURITY
GROUP

VIEWER x x

OPERATOR x x x x

ENGINEER x x x x x x x

INSTALLER x x x x x

SECADM x x x x x x x x x

SECAUD x x x x

RBACMNT x x x x x

ADMINISTRATOR x x x x x x x x x x x

User definition:
● VIEWER: can view what objects are present within a Logical-Device by presenting the type ID of those
objects.
● OPERATOR: An operator can view what objects and values are present within a Logical Device by presenting
the type ID of those objects as well as perform control actions.
● ENGINEER: An engineer can view what objects and values are present within a Logical Device by presenting
the type ID of those objects. Moreover, an engineer has full access to DateSets and Files and can configure
the server locally or remotely.
● INSTALLER: An installer can view what objects and values are present within a Logical Device by presenting
the type ID of those objects. Moreover, an installer can write files and can configure the server locally or
remotely.
● SECADM: Security administrator can change subject-to-role assignments (outside the device) and role-to-
right assignment (inside the device) and validity periods; change security setting such as certificates for
subject authentication and access token verification.
● SECAUD: Security auditor can view audit logs.
● RBACMNT: RBAC management can change role-to-right assignment.
● ADMINISTRATOR: Has All read/write access

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Rights definition:
● VIEW: Allows the subject/role to discover what objects are present within a Logical Device by presenting the
type ID of those objects.
● READ: Allows the subject/role to obtain all or some of the values in addition to the type and ID of objects
that are present within a Logical-Device
● DATASET: Allows the subject/role to have full management rights for both permanent and non-permanent
DataSets
● REPORTING: Allows a subject/role to use buffered reporting as well as un-buffered reporting
● FILEREAD: Allows the subject/role to have read rights for file objects
● FILEWRITE: Allows the subject/role to have write rights for file objects. This right includes the FILEREAD right
● FILEMNGT: Allows the role to transfer files to the Logical-Device, as well as delete existing files on the
Logical- Device
● CONTROL: Allows a subject to perform control operations
● CONFIG: Allows a subject to locally or remotely configure certain aspects of the server
● SETTINGGROUP: Allows a subject to remotely configure Settings Groups
● SECURITY: Allows a subject/role to perform security functions at both a Server/Service Access Point and
Logical-Device basis

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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. The bulk of the implementation consists of
RBAC (Role Based Access Control) Cyber-security mode, Centralised Authentication, Remote Logging and System
Hardening. The features are compliant with NERC-CIPv6 and IEEE 1686. This is valid for the release of platform
software to which this manual pertains.
Two levels of Cyber-security are available as ordering options for the P40 Agile Enhanced relays:
● Basic Cyber-security
● Advanced Cyber-security
Basic Cyber-security includes the following security features:
● Device / Local Authentication
● Four-level access: Fixed local users and roles (Administrator, Engineer, Operator, Viewer)
● ByPass Access
● Password complexity
● Disabling of unused physical and logical ports
● Flag for Failed authentication
● User lockout for configurable period
● Inactivity time out

Advanced security includes additional security features as follows:

● Remote /Server Authentication (supports RADIUS)
● Local authentication with unique configurable usernames
● Secure encrypted communication (Modbus/SSH, SFTP)
● Syslog
● Increased product hardening

4.1 RBAC FUNCTIONALITY

Role based access control, RBAC, is the core of session management. Every login attempt will connect to the RBAC
service and it will allow or deny the login of the user.
In Basic Security, default connection is done as Viewer, without password requirement.
In case of Advanced Security, a username and password will be required. If the login is successful, the access level
will correspond to the role defined to this user.
The user cannot change its own role. So, in case of more rights needed, another different user with the
corresponding role should be logged in.
The maximum number of concurrent sessions is only one for all roles, except of Viewer role, which has the limit of
5 sessions.
There is a session timeout adjustable by settings. This timeout means that open sessions are automatically closed
if they remain inactive till the timer elapses. This inactivity timer defines the period that IED waits in idleness before
a logged in user will be automatically logged out. This timeout is different for HMI interface and other interfaces
(serial, ethernet, etc).

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There is a lockout period adjustable by settings. For each account, when a maximum number of failed login
attempts is reached, it is locked during the specified period. It doesn’t matter the interface the login comes from.
The account will be unlocked at the first successful login passed the lockout period.
If the Authentication Method setting is changed, the logged in user will be forced to logout.

4.2 BASIC SECURITY IMPLEMENTATION

4.2.1 DEVICE/LOCAL AUTHENTICATION

In Device Authentication mode, IED provide local RBAC Server security. The IED supports unique device usernames,
and stores device passwords securely. For password encryption, PBKDF2 with SHA256 and a unique 64bits salt per
user is used.
Only Administrator can change other user’s passwords. All device users can change their own passwords. For
password reset/recovery procedure the Administrator role will be required.
Viewer access level has no password associated and is the default connection to the device.

4.2.2 FOUR-LEVEL ACCESS

Basic Security relay supports 4 fixed roles: Administrator, Engineer, Operator and Viewer. The fixed local usernames
match with these roles.
All the roles are password protected except the Viewer. A Viewer connection is directly logged in without entering a
password using front panel or any communication port.
The different features of each role or access level are shown in the table below:
Administrator Engineer Operator Viewer
Settings Security settings RW R R R
Change own PW (Basic security) Yes Yes Yes X
Change own PW (Advanced security) Yes Yes Yes Yes
Create New / Modify users, assign roles RW X X X
(advanced security OC)
Non-Security settings RW RW R R
FlexLogic RW RW R R
IEC61850 settings RW RW R R
Factory Settings X X X X
Commands Date change RW RW X X
BKR related RW RW RW X
Clear records RW X X X
Restore Defaults RW X X X
RESET W W W X
File Config File read R R R R
Config File write W W X X
Upload FW W X X X
Actual Values Status R R R R
Metering R R R R
Reports Events R R R R
Waveforms R R R R
Security Audit log R R X X

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4.2.3 BYPASS ACCESS

The 'Bypass Access' feature allows to bypass security authentication. Once this setting is other than 'Disabled”,
then user gets Administrator access rights on configured interface. For example, if user configures it as 'Local”
then no user authentication is needed for accessing over USB or HMI. Other possible option is to bypass
authentication for 'HMI only” where user can view and modify all the settings, view actual values or execute
commands. The bypass security feature provides an easier access, with no authentication and encryption.
Therefore, the use of this feature should be restricted only in commissioning phase or when it is considered safe.
Only the Administrator, can enable this feature.

4.2.4 ENHANCED PASSWORD SECURITY

When Password complexity setpoint is set to 'Enabled”, it allows user to configure password strings which adhere
to complexity rules defined below. When the setting is configured as 'Disabled” then user can change the
password to any string with max length of 20 characters.
Password complexity has the following features:
● Passwords cannot contain the user's account name or parts of the user's full name that exceed two
consecutive characters.
● Must be at least 8 characters in length. Max length can be 20 ASCII char
● Passwords must contain characters from all four categories:
○ English uppercase characters (A through Z).
○ English lowercase characters (a through z).
○ Numeric: Base 10 digits (0 through 9).
○ Special non-alphanumeric (such as @,!,#,{, but not limited to only those, etc.)
The IED supports encryption for passwords. The encryption algorithm used is PBKDF2 with SHA256 and a unique
64bits salt per user, where this salt is generated randomly.

4.2.5 DISABLING PHYSICAL AND LOGICAL PORTS

The IED supports the ability to turn off any of the following specific physical ports [CAT2-CYBER-6-001]:
● front USB serial port
● rear port RS485
● Ethernet port

The IED supports the ability to turn off any of the following specific communication protocols [CAT2-CYBER-6- 002]:
● IEC 61850 (MMS and GOOSE)
● Modbus
● DNP OE
● DNP serial
● IEC 104
● TFTP

Time synchronization protocols can be selectively enabled/disabled based on the configuration.

● IRIG-B
● SNTP

Services Port Numbers

Modbus / TCPSeices 502
IEC 61850 (ISO-TSAP) / TCP 102
TFTP / UDP 69

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DNP / TCP 20000

DNP / UDP 20000
IEC 60870-5-104 / TCP 2404
SNTP / UDP 123

4.3 ADVANCED CYBER-SECURITY IMPLEMENTATION

In addition to all the Basic security features, the Advanced security option provides the properties listed below.

4.3.1 SERVER/REMOTE AUTHENTICATION

In Server Authentication mode, IED authenticates the user using RADIUS server. RADIUS client resides in the
product and connects to the RADIUS server.
Customer can use any of the following RADIUS servers as their central authentication server
● FreeRADIUS server
● Microsoft NPS server
● RSA Authentication Manager

RADIUS users and passwords are created in the server (in the Active Directory). Each RADIUS user should have a
password (that meets the password policy of the Active Directory) and specific role assigned to in the Active
Directory.
P40 Agile Enhanced supports 2 servers in the configuration for redundancy. The IED will try each in sequence until
one respond. When the first RADIUS server is unavailable, the next server in the list is tried for RADIUS
Authentication.

Groups User
Access Request
User login RADIUS
IED Client
Access
Accept
(User Role)
User RADIUS Server Active Directory

V01100

Figure 144: RADIUS server/client communication

The IED will first try the server 1 up to the configured number of retries leaving request timeout between each
request. After this point, if it still does not have a valid answer from server 1, it switches to server 2 and repeats for
up to the number of configured retries again. If it maxes out on retries on the second server, it gives up entirely on
Server Authentication and fallback to device authentication (Only if Authentication Method Server and Device is
selected). A "RADIUS Server unavailable" security event is also logged under this condition.

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IED will authenticate and authorize RADIUS users using the following authentication stack:
● Primary Radius if enabled (stop on invalid credential failure, continue all other failures)
● Secondary Radius if enabled (stop on invalid credential failure, continue all other failures) The RADIUS
implementation supports the following authentication protocols:

● PEAPv0 with inner authentication method MS-CHAPv2 (To support Microsoft NPS server)
● EAP-TTLS with inner authentication method PAP (To support RSA AM)
● EAP with inner authentication method GTC (To support RSA AM)
● PAP (unsecured, to support any RADIUS server)

The RADIUS implementation will query the Role ID vendor attribute and establish the logged in user security
context with that role.
In case of Server Authentication mode but if the RADIUS server is not operational, IED will try Device
Authentication.

4.3.2 UNIQUE CONFIGURABLE USERNAMES

In Advanced Security relay, user can configure up to 20 configurable user accounts. As part of this, user can
configure a Username (length can be up to 20 ASCII char), Password for the username (in compliance with the
Password complexity) and assign a supported user role (range: Administrator, Engineer, Operator, Viewer).
'Administrator' is eligible to configure various accounts. He is eligible to modify passwords for all available
accounts. Non-Admin users can modify their own account password.
It is recommended to have more than one 'Administrator' account.

4.3.3 SECURE ENCRYPTED COMMUNICATION

4.3.3.1 MODBUS/SSH
Secure Shell (SSH) protocol provides a secure channel over an unsecured network by using a client-
server architecture. The SSH server reside in the IED. It securely encrypts the Modbus commands and data
between the Toolsuite and itself using port forwarding.
SSH architecture is described in RFC4251 and is composed of three components:
● The transport Layer protocol (SSH-TRANS) – RFC 4253
● The User Authentication Protocol (SSH-USERAUTH) – RFC 4252
● The Connection Protocol (SSH-CONNECT) – RFC 4254

The port forwarding feature is available only on TCP/IP frames. UDP is not supported. The SSH server on the
product runs on port 22.
It supports the Encryption Ciphers: RSA 2048, AES-128-CBC or AES-128-GCM, HMAC-SHA-256.
The SSH server has a timeout for authentication and disconnect if the authentication has not been accepted
within the timeout period.

4.3.3.2 SFTP
SFTP (SSH File Transfer Protocol) is the file transfer protocol used with SSHv2. Provides secure file access, file
transfer, and file management.
The SFTP commands will be limited for a given period of time to avoid DOS attacks and also implement role-based
access to the file.

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4.3.4 SYSLOG
The IED supports security event reporting through the Syslog protocol for supporting Security Information Event
Management (SIEM) systems for centralized cyber security Monitoring over UDP protocol [CAT2-CYBER-8-001].
2 Syslog servers are supported in the configuration for redundancy. The IED will try each in sequence until one
respond [CAT2-CYBER-8-002].
The IED logs to a remote syslog server:
● User log events, whether successful or unsuccessful
● Error log events
● Kernel error log events

Event Level Description MSGID

LOGIN, ORIGIN, TIMESTAMP: Notice (5) An event to indicate when a certain role logged in. 0
Origin: Username and IP:MAC
LOGIN_PWD_EXPIRED, ORIGIN, TIMESTAMP: Notice (5) An event to indicate when a certain role logged in with 1
an expired password. Origin: Username and IP:MAC
FAILED_AUTH, ORIGIN, TIMESTAMP Notice (5) A failed authentication with origin information 2
(username and IP:MAC address), a time stamp in UTC
time when it occurred.
USER_LOCKOUT, ORIGIN, TIMESTAMP: Error (3) The user lockout has occurred because of too many 3
failed authentication attempts. Origin: username and
IP:MAC address
LOGOUT, ORIGIN, TIMESTAMP: Notice (5) An event to indicate when a certain role logged out. 4
Origin: Username and IP:MAC
LOGOUT, ORIGIN, TIMESTAMP: Notice (5) An event to indicate when a certain role logged out by 5
idle timeout. Origin: Username and IP:MAC
FAILED_MAX_CONNS, ORIGIN, TIMESTAMP Notice (5) A failed authentication with origin information 6
(username and IP:MAC address) when max connections
is reached
SETTING_CHG, ORIGIN, TIMESTAMP: Notice (5) An event to indicate setting change(s). Origin: Username 7
and IP:MAC
PRIM_RADIUS_UNREACH, ORIGIN, Critical (2) RADIUS server is unreachable. Origin: RADIUS server IP 8
TIMESTAMP: address and port number
SEC_RADIUS_UNREACH, ORIGIN, Critical (2) RADIUS server is unreachable. Origin: RADIUS server IP 9
TIMESTAMP: address and port number
CLEAR_EVENT_RECORDS, ORIGIN, Notice (5) Clear event records command was issued. Origin: 10
TIMESTAMP: Username and IP:MAC
CLEAR_TRANSIENT_RECORDS, ORIGIN, Notice (5) Clear transient records command was issued. Origin: 11
TIMESTAMP: Username and IP:MAC
BYPASS ACCESS ACTIVATED Warning (4) Bypass access has been activated 12
BYPASS ACCESS DEACTIVATED Warning (4) Bypass access has been deactivated 13
PRIM_SYSLOG_UNREACHABLE Critical (2) SYSLOG server is unreachable. Origin: SYSLOG server IP 14
address and port number
SEC_SYSLOG_UNREACHABLE Critical (2) SYSLOG server is unreachable. Origin: SYSLOG server IP 15
address and port number
FW_UPLOAD_SUCCESSFULL Notice (5) [IEEE 1686] requires audit logging for firmware related 16
aspects. A software is generic that includes also
firmware.

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4.3.5 INCREASED PRODUCT HARDENING

In Advanced security, the IED supports the ability to turn off the added features in encrypted communication. SSH
and SFTP protocols on port 22 can be disabled.

4.4 ADDITIONAL FEATURES

In addition to all the Basic security features, the Advanced security option provides the properties listed below.

4.4.1 LOSTPASSWORD
P40 Agile Enhanced relay allows modification of all user account passwords by user with “Administrator”
privileges. Also, non-Admin users can update their own passwords.
For 'Advanced security', it is recommended to have more than one user with 'Administrator' role. This will help in
case 'Administrator' password is lost. Other local 'Administrator' account or Remote authentication user
'Administrator' can modify the password for the 'Administrator' whose password is lost.
If Remote authentication server is not configured or is unreachable, and if there is a single 'Administrator'
configured on IED for Local authentication, then the only way to reset 'Administrator' password is to execute
command from HMI. This action will default passwords for all accounts.
Access IED from HMI as another role. Go to Settings -> Product setup -> Install: Screen will have option to enter
'Service command'. User can enter the command to reset passwords for all accounts.
Please, contact GE customer support to get the code and perform this action.

4.4.2 LOADING FACTORY CONFIGURATION

User needs to login as ‘Administrator’. Go to Security screen and then ‘Restore Defaults’ can be set to ‘Yes’.

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INSTALLATION
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1 CHAPTER OVERVIEW
This section describes the mechanical installation of the system, including dimensions for mounting and
information on module withdrawal and insertion.
This chapter contains the following sections:
Chapter Overview 359
Product Identification 360
Handling the Goods 361
Mounting the Device 362
Cables and Connectors 365
Case Dimensions and Panel Cutout 371

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2 PRODUCT IDENTIFICATION
The product identification label is located on the side panel of the IED. This label indicates the product model, serial
number, and date of manufacture. However, when the IED is installed the label may not be visible. In this case, the
product my be identified using the model number printed on the front panel and the Cortec provided in the
Ordering Options Appendix.

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3 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.

3.1 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.

3.2 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.

3.3 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 –40º to +85ºC for unlimited periods (see technical specifications).
To avoid deterioration of electrolytic capacitors, power up units that are stored in a deenergized state once per
year, for one hour continuously.

3.4 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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4 MOUNTING THE DEVICE

The products are available in the following forms
● For flush panel and rack mounting
● Software only (for upgrades)

4.1 FLUSH PANEL MOUNTING

Caution:
To avoid the potential for personal injury due to fire hazards, ensure the unit is
mounted in a safe location and/or within an appropriate enclosure.

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.

Caution:
Do not fasten products with pop rivets because this makes them difficult to remove if
repair becomes necessary.

4.1.1 RACK MOUNTING

Panel-mounted variants can also be rack mounted using single-tier rack frames (our part number FX0021 001), 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.

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Figure 145: 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:

Case size summation Blanking plate part number

5TE GJ2028 001
10TE GJ2028 002
15TE GJ2028 003
20TE GJ2028 004
25TE GJ2028 005
30TE GJ2028 006
35TE GJ2028 007
40TE GJ2028 008

4.1.2 DRAW-OUT UNIT WITHDRAWAL AND INSERTION

Unit withdrawal and insertion may only be performed when control power has been removed from the unit.

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Note:
Turn off control power before drawing out or re-inserting the relay to prevent maloperation.

Follow the steps outlined below to withdraw the Draw-out unit.

● Remove the 4 M3x10 self taping screws that fix the front panel to the chasis
● Extract the draw-out unit.
Repeat the steps in the reverse order to insert the draw-out unit

4.2 SOFTWARE ONLY

It is possible to upgrade an existing device with advanced software functions by purchasing software only
(providing the device is already fitted with the requisite hardware).
There are two options for software-only products:
● Your device is sent back to the General Electric factory for upgrade.
● The software is downloaded or sent to you for upgrade. Please contact your local representative if you wish
to procure the services of a commissioning engineer to help you with your device upgrade.

Note:
Software-only products are licensed for use with devices with specific serial numbers.

Caution:
Do not attempt to upgrade an existing device if the software has not been licensed for
that specific device.

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5 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.
A broad range of applications are available for the IEDs. As such, it is not possible to present typical connections
for all possible schemes. The information in this section covers the important aspects of interconnections, in the
general areas of instrument transformer inputs, other inputs, outputs, communications and grounding.

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.

Copper wiring is suggested with a minimum temperature rating of 75ºC.

5.1 LUG ORIENTATION

Note:
When installing two lugs on one terminal, both lugs should be installed as per lug manufacturer instructions and engineering
best practise.

5.2 TERMINAL BLOCKS

The device uses terminal blocks as shown below.
The device uses terminal blocks, each consisting of up to 16 x M3.5 screw terminals. The wires can be terminated
with rings using ring terminals, with no more than two rings per terminal. If two rings are used, remove the teeth of
the IP20 cover, as shown.

Figure 146: IP20 cover with teeth removed, alone and installed

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The terminal block is supplied with a 3-pole jumper to create a star configuration with the current transformers
when one is needed (instead of wiring one externally), as shown.

Figure 147: Terminal block with 3-pole jumper

5.3 POWER SUPPLY CONNECTIONS

These should be wired with 1.5 mm PVC insulated multi-stranded copper wire terminated with/without M3.5 8 mm
maximum diameter ring terminals. Recommended ring terminals: TE B-106-1403 or Molex 193240012
The wire should have a minimum voltage rating of 300 V RMS.

Caution:
Control power supplied to the relay must match the installed power supply range. If the
applied voltage does not match, damage to the unit may occur. All earths MUST be
connected for normal operation regardless of control power supply type.

Caution:
Protect the auxiliary power supply wiring with a maximum 16 A high rupture capacity
(HRC) type NIT or TIA fuse.

5.4 EARTH CONNNECTION

Every device must be connected to the earth connection using the earth terminal.

Use the shortest practical path. A tinned copper, braided, shielding and bonding cable should be used. As a
minimum, 96 strands of number 34 AWG should be used.
The wire should have a minimum voltage rating of 300 V RMS.

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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.

5.5 PHASE SEQUENCE AND TRANSFORMER POLARITY

For correct operation of the relay features, follow the instrument transformer polarities, shown in the Typical
Wiring Diagram. Note the solid square markings that are shown with all instrument transformer connections.
When the connections adhere to the drawing, the arrow shows the direction of power flow for positive watts and
the positive direction of vars. The phase sequence is user programmable for either ABC or ACB rotation.
The P40 Agile Enhanced IED has four (4) current inputs. Three of them are used for connecting to the phase CT
phases A, B, and C. The fourth input is an earth input that can be connected to either a earth CT placed on the
neutral from a Wye connected transformer winding, or to a “donut” type CT measuring the zero sequence current
from a earthed system. The IED CTs are placed in a packet mounted to the chassis of the IED. There are no internal
earth connections on the current inputs.

Caution:
Verify that the relay’s nominal input current of 1 A or 5 A matches the secondary rating
of the connected CTs. Unmatched CTs may result in equipment damage or inadequate
protection.

5.6 CURRENT TRANSFORMERS

Current transformers would generally be wired with 2.5 mm2 PVC insulated multi-stranded copper wire terminated
with M3.5 8 mm maximum diameter ring terminals. Recommended ring terminals: TE B-106-1403 or Molex
193240012.

Due to physical limitations, the maximum wire size you can use is 4.0 mm2 using ring terminals. 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, ensure that the terminals into which the CTs connect are shorted before the CT module is removed.

Note:
For 5A CT secondaries, we recommend using 2 x 2.5 mm2 PVC insulated multi-stranded copper wire.

Note:
The terminal block is supplied with a 3-pole jumper to create a star configuration with the current transformers when one is
needed (instead of wiring one externally).

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5.7 VOLTAGE TRANSFORMER CONNECTIONS

Voltage transformers would generally be wired with 2.5 mm2 PVC insulated multi-stranded copper wire terminated
with M3.5 8 mm maximum diameter ring terminals. Recommended ring terminals: TE B-106-1403 or Molex
193240012.
The wire should have a minimum voltage rating of 300 V RMS.

5.8 WATCHDOG CONNECTIONS

These should be wired with at least 1mm PVC multi stranded copper wire with/without pin terminals up to 2.5mm.
The wire should have a minimum voltage rating of 300 V RMS.
The critical output relay is reserved as Relay_8 and it is omitted and is not programmable.

5.9 EIA(RS)485 CONNECTIONS

For connecting the EIA(RS485) ports, use 2-core screened cable with a maximum total length of 1000 m or 200 nF
total cable capacitance.
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

Up to 32 P14 Series IEDs can be daisy-chained together on a communication channel without exceeding the driver
capability. For larger systems, additional serial channels must be added. Commercially available repeaters can
also be used to add more than 32 relays on a single channel.

Caution:
To ensure that all devices in a daisy-chain are at the same potential, it is imperative
that the common terminals of each RS485 port are tied together and grounded only
once, at the master or at the IED. Failure to do so may result in intermittent or failed
communications.

The last device at each end of the daisy-chain should be terminated with a 120 ohm ¼ watt resistor in series with
a 1 nF capacitor across the positive and negative terminals. Some systems allow the shield (drain wire) to be used
as a common wire and to connect directly to the COM terminal; others function correctly only if the common wire
is connected to the COM terminal, but insulated from the shield.
Observing these guidelines ensure a reliable communication system immune to system transients.
To guarantee the performance specifications, you must ensure continuity of the screen, when daisy chaining the
connections.There is no electrical connection of the cable screen to the device. The link is provided purely to link
together the two cable screens.

5.10 IRIG-B CONNECTION

IRIG-B is a standard time code format that allows time stamping of events to be synchronized among connected
devices within 1 millisecond. The IRIG-B time code formats are serial, width-modulated codes DC level shift form.
Third party equipment is available for generating the IRIG-B signal; this equipment may use a GPS satellite system
to obtain the time reference so that devices at different geographic locations can also be synchronized.

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GPS SAT ELLIT E SYST EM

GP S C ON N E C TION
OP TION A L

IRIG-B GE MULTILIN
TIME CODE SH IELD ED C ABLE P40 AGILE SERIES
GENERATOR
+ D1 IRIG-B(+)

(DC SHIFT OR R EC EIVER

AMPLITUDE MODULATED
SIGNAL CAN BE USED)
– D2 IRIG-B(-)

E06925

TO OT H ER D EVIC ES

The optional IRIG-B input uses the same terminals as the EIA(RS)485 port COM1. It is therefore apparent that RS485
communications and IRIG-B input are mutually exclusive.
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

Irig-B positive wire should be connected to COM1 B(+) terminal

Irig-B neutral wire must be connected to COM1 GND terminal
The uncovered communications cable shield connected to the common terminal should not exceed 1” (2.5 cm) for
proper EMC shielding of the communications cable.

Note:
To use the IRIG-B connection, the IRIG-B setting under Date & Time should be set to Enabled.

5.11 OPTO-INPUT CONNECTIONS

Depending on the order code, the P40 Agile Enhanced IED has a different number of contact inputs which can be
used to operate a variety of logic functions for circuit switching device control, external trips, blocking of protection
elements, etc. The IED has ‘contact inputs’ and ‘virtual inputs’ that are combined in a form of programmable logic
to facilitate the implementation of various schemes.
These should be wired with at least 1mm PVC multi stranded copper wire with/wihout pin terminals up to 2.5mm.
Each opto-input has a debounce time setting. This makes the input immune to noise induced on the wiring. This
can, however slow down the response.

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Caution:
Protect the opto-inputs and their wiring with a maximum 16 A high rupture capacity
(HRC) type NIT or TIA fuse.

5.12 OUTPUT RELAY CONNECTIONS

These should be wired with at least 1mm PVC multi stranded copper wire with/wihout pin terminals up to 2.5mm.

5.13 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

5.14 ETHERNET FIBRE CONNECTIONS

We recommend the use of fibre-optic connections for permanent connections in a substation environment. The
100 Mbps fibre optic port is based on the 100BaseFX standard and uses type LC connectors. They are compatible
with 50/125 µm or 62.5/125 µm multimode fibres at 1300 nm wavelength.

5.15 USB CONNECTION

The IED has a type B USB socket on the front panel. A standard USB printer cable (type A one end, type B the other
end) can be used to connect a local PC to the IED. This cable is the same as that used for connecting a printer to a
PC.

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6 CASE DIMENSIONS AND PANEL CUTOUT

Figure 148: Case dimensions

Figure 149: Cutout dimensions

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COMMISSIONING INSTRUCTIONS
Chapter 20 - Commissioning Instructions P14D

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1 CHAPTER OVERVIEW
This chapter contains the following sections:
Chapter Overview 375
General Guidelines 376
Commissioning Test Menu 377
Commissioning Equipment 380
Product Checks 382
Setting Checks 387
Protection Timing Checks 389
Onload Checks 390
Final Checks 392

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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 EnerVista Flex settings 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:
Do not disassemble the device during commissioning.

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3 COMMISSIONING TEST MENU

The IED provides several test facilities under the SETPOINTS > TESTING menu heading in the HMI and under
MONITORING > TESTING in the Enervista Flex software. There are menu elements that allow you to monitor the
status of the opto-inputs, output relay contacts and user-programmable LEDs. This section describes these
commissioning test facilities.

3.1 OPTO I/P STATUS ELEMENT (OPTO-INPUT STATUS)

This element can be used to change the status of the opto-inputs without a suitable DC voltage. The element
changes the status of each opto input from OFF to ON without DC generator and checks any logic associated with
each input.

3.2 RELAY O/P STATUS ELEMENT (RELAY OUTPUT STATUS)

This element can be used to change the status of the relay outputs. The element is able to change the status of the
relay outputs from OFF to ON and vice versa without any logic or trip status.

3.3 TESTING
The P40 Agile Enhanced supports Testing Menu which facilitates relay testing during commissioning. The testing
Menu supports following functions: -
● Simulation
● Test LEDs
● Opto Inputs
● Relay Outputs
● Autoreclose

The P40 Agile Enhanced can simulate current and voltage inputs in this section. Other test operations are also
possible such as LED lamp test of each color, contact input states and testing of output relays.
Simulation
The Simulation feature is provided for testing the functionality of the P40 Agile Enhanced relays in response to
programmed conditions, without the need of external AC voltage and current inputs. First time users will find this
to be a valuable training tool. System parameters such as currents, voltages and phase angles are entered as
setpoints. When placed in test mode, the relay suspends reading actual AC inputs, generates samples to represent
the programmed phasors, and loads these samples into the memory to be processed by the relay. Normal (pre-
fault), fault, and post-fault conditions can simulate a wide variety of system disturbances, and exercise many P40
Agile Enhanced relays features.
Path: Setpoints\ Testing\ Simulation > Setup
Simulation state
Range: Disabled, Prefault State, Fault State, Postfault State
Programme the Simulation State to “Disabled” if actual system inputs are to be monitored. If programmed to any
other value, the relay is in test mode and actual system parameters are not monitored, including Current, Voltage,
and Contact Inputs. The system parameters simulated by the relay are those in the following section that
correspond to the programmed value of this setpoint. For example, if programmed to “Fault”, then the system
parameters are set to those defined by the Fault setpoint values.
When the Fault State is set as the Simulation State and a Trip occurs, the Simulation State automatically
transitions to the Postfault State.

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Caution:
All Simulation setpoints revert to default values at power-up.

Force Relays
When in test mode, and Force Relays is “Enabled”, relay states can be forced from the Setpoints\Testing\Relay
Outputs in HMI or in Monitoring\Testing\Relay Outputs menu in the EnerVsta Flex software, this overrides the
normal operation of the output contacts. When in test mode, and Force Relays is “Disabled”, the relay states
maintain their normal operation. Forcing of output relay states is not performed when the Simulation State is
“Disabled”.
Force LEDs
When in test mode, and Force LEDs is “Enabled”, LED states and colors can be forced from the Setpoints\Testing
\Test LEDs menu (in HMI or in Monitoring\Testing\Relay Outputs menu in Enervista Flex software), this will override
the normal operation of the LEDs. When in test mode, and Test LEDs is “Disabled”, the LED states and colors will
maintain their normal operation. Forcing of LEDs is not performed when the Simulation State is “Disabled”.
Test LEDs
The Test LEDs section is used to program the state and color of each LED when in test mode and Force LEDs is
“Enabled” All LEDs color from 2 till 8 can be set to off, Red, Green and Orange color. LED 1 can be set to off or red/
orange, green is not displayed.
Path: Setpoints\ Testing\ Test LEDs
NOTE: Test LEDs setpoints here (in test mode) will revert to default values at power-up.
Opto Inputs
The opto Inputs section is used to program the state of each opto input when in test mode. The number of opto
Inputs available is dependent on the installed Order Code options.
Path: Setpoints\ Testing\ Opto Inputs

Note:
Contact Inputs setpoints here (in test) will revert to default values at power-up.

Relay Outputs
The Relay Outputs section is used to program the state of each relay output when the device is in test mode and
Force Relays is “Enabled”.
Select “Off” to force the output relay to the de-energized state, or select “On” to force the output relay to the
energized state.
The number of Output Relays available is dependent on the installed Order Code options.
Path: Setpoints \ Testing\Relay Outputs
NOTE: Relay Outputs setpoints here (in test mode) will revert to default values at power-up.

3.4 AUTORECLOSE TESTING

This is for testing the sequence of circuit breaker trip and auto-reclose cycles when in test mode.
The 3 Pole Test command causes the device to perform the first three phases trip/reclose cycle so that associated
output contacts can be checked for operation at the correct times during the 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 auto-reclose cycles, you can repeat the 3 Pole test command.

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Note:
Simulation state should be Disabled.

PATH: Setpoints\Testing\Autoreclose

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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.
● Suitable electrical test leads.
● Electronic or brushless insulation tester with a DC output not exceeding 500 V
● Continuity tester
● Verified application-specific settings files

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)
● Timer
● Test switches
● Suitable electrical test leads
● Continuity tester

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4.3 ADVISORY TEST EQUIPMENT

Advisory test equipment may be required for extended commissioning procedures:
● Current clamp meter
● Multi-finger test plug:
● Electronic or brushless insulation tester with a DC output not exceeding 500 V
● EIA(RS)485 to EIA(RS)232/USB converter for testing EIA(RS)485 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

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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 test block is
provided, the required isolation can be achieved by inserting a test plug. 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.

5.1.1 VISUAL INSPECTION

Caution:
Check the rating information provided with the device. Check that the IED being
tested is correct for the line or circuit.

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.

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5.1.2 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.

5.1.3 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.

The auxiliary DC voltage supply uses terminals A1 (supply positive) and A2 (supply negative).

5.1.4 WATCHDOG CONTACTS

Using a continuity tester, check that the Watchdog contact is in the following state:
Terminals De-energised contact
D23 - D24 Closed

5.1.5 POWER SUPPLY

The IED can accept a nominal DC voltage from 24 V DC to 250 V DC, or a nominal AC voltage from 110 V AC to
240 V AC at 50 Hz or 60 Hz. Ensure that the power supply is within this operating range. The power supply must be
rated at 10 Watts or more.

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.

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5.2.1 WATCHDOG CONTACTS

Using a continuity tester, check that the Watchdog contact is in the following state:
Terminals Energised contact
D23 - D24 Open

5.2.2 DATE AND TIME

The date and time is stored in non-volatile memory. If the values are not already correct, set them to the correct
values. The method of setting will depend on whether accuracy is being maintained by the IRIG-B port or by the
IED's internal clock.
When using IRIG-B to maintain the clock, the IED must first be connected to the satellite clock equipment, which
should be energised and functioning.
1. Set the IRIG-B setting under path SETPOINT > DEVICE > DATE AND TIME to Enabled.
2. Ensure the IED is receiving the IRIG-B signal by checking that CLOCK Status at Device Status> CLOCK > RTC
SYNC SOURCE reads IRIB-B.
3. Once the IRIG-B signal is active, adjust the time offset of the universal 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 element. The IRIG-B signal does not
contain the current year so it will need to be set manually.
5. Reconnect the IRIG-B signal.
If the time and date is not being maintained by an IRIG-B signal, ensure that the IRIG-B setting in the DATE AND
TIME element is set to Disabled.
1. Set the date and time to the correct local time and date using Date/Time element or using the serial
protocol.

5.2.3 TEST LEDS

If any of the 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.
To test the LEDs, change the existing status of any LED at SETPOINT > TESTING > TEST LEDS.

5.2.4 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 the DEVICE STATUS > OPTO INPUTS element.
ON indicates an energised input and OFF indicates a de-energised input.
Opto inputs can be simulated at SETPOINTS > TESTING > OPTO INPUTS. It can be changed the existing status from
OFF to ON and vice versa. Take into account that it simulates the opto input, so any logic should be checked.

5.2.5 TEST RELAY OUTPUTS

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.
2. The output relays should be energised one at a time. To select output relay 1 for testing, set SETPOINTS >
TESTING > RELAY OUTPUTS > RELAY O/P 1
3. /P 1.

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4. Connect a continuity tester across the terminals corresponding to output relay 1 as shown in the external
connection diagram.
5. To operate the output relay change the Contact Test status.
6. Check the operation with the continuity tester.
7. Measure the resistance of the contacts in the closed state.
8. Reset the output relay by changing the Contact Test status.
9. Repeat the test for the remaining output relays.
10. Return the IED to service by setting the Test Mode to Disabled.

5.2.6 TEST SERIAL COMMUNICATION PORT COM1

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.

5.2.6.1 CHECK PHYSICAL CONNECTIVITY

The rear communication port COM1 is on the rear of the IED. Screened twisted pair cable is used to make a
connection to the port.
Figure 150: COM1 physical connection

EIA(RS)485 is polarity sensitive, so you must ensure the wires are connected the correct way round.
If RS485 is being used, an RS485-RS232/USB converter will have been installed. In the case where a protocol
converter is being used, a laptop PC running appropriate software can be connected to the incoming side of the
protocol converter. Most modern laptops have USB ports, so it is likely you will also require a RS232 to USB
converter too.

5.2.6.2 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. Check that communications can be established with this IED using the portable PC/Master Station.

5.2.7 TEST ETHERNET COMMUNICATION

For products that employ Ethernet communications, we recommend that testing be limited to a visual check that
the correct ports are working and that there is no sign of physical damage.

5.2.8 TEST CURRENT INPUTS

This test verifies that the current measurement inputs are configured correctly.
All devices leave the factory set for operation at a system frequency of 50 Hz. If operation at 60 Hz is required then
this must be set in the Frequency.
1. Apply current equal to the line current transformer secondary winding rating to each current transformer
input in turn.
2. Check its magnitude using a multi-meter or test set readout. The corresponding reading can then be
checked in the MEASUREMENTS >.CT1 BANK-B menu.
An additional allowance must be made for the accuracy of the test equipment being used.

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MONITOR > MEASUREMENT >CT1 BANK-B Measurement Corresponding CT ratio

menu (in CT AND VT RATIOS menu)
CT1 IA
CT1 IB Phase CT Primary / Phase CT Sec'y
CT1 IC
CT1 IN2 (Derived Current) E/F CT Primary / E/F CT Secondary
CT1 IN1 (EF Measured Current) E/F CT Primary / E/F CT Secondary
CT1 SEF (SEF measured current) SEF CT Primary / SEF CT Secondary

Note:
E/F or SEF current values are displayed for each device depending of the Cortec selected.

5.2.9 TEST VOLTAGE INPUTS

This test verifies that the voltage measurement inputs are configured correctly.
1. Apply rated voltage to each voltage transformer input in turn
2. Check its magnitude using a multimeter or test set readout. The corresponding reading can then be
checked in the MEASUREMENTS MONITOR > MEASUREMENT >PHASE VT1 BANK-A and 4th VT1 BANK-A
menus.

MEASUREMENTS MONITOR > MEASUREMENT >PHASE VT1 Corresponding VT ratio

BANK-A and 4th VT1 BANK-A menus (in CT AND VT RATIOS)
VT1 VAN
VT1 VBN Main VT Primary / Main VT Sec'y
VT1 VCN
4th VT1 Mag 4th VT Primary / 4th VT Sec'y

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6 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.

6.1 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 EnerVista Flex
● Enter the settings manually using the IED’s front panel HMI

6.1.1 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 EnerVista Flex Settings Application Software to the IED's USB front port, or the
rear Ethernet port.
2. Power on the IED
3. Create or open an existing project including the CID file for the IED and click in the appropriate device name
in the project and select Send CID from the top toolbox. Right-click the appropriate device name in the
System Explorer pane and select Send
4. Enter the IP address of the device related to the interface selected, USB or Ethernet
5. In the User Authentication dialog select the Username and Password and click Continue and then Finish

Note:
The device name may not already exist in the project. In this case, perform a Quick Connect to the IED, then manually add
the settings file to the device name in the project. Refer to the EnerVista Flex Settings Application Software help for details of
how to do this.

6.1.2 ENTERING SETTINGS USING THE HMI

1. Starting at the default display, press the Down cursor key to navigate through the HMI menus.
2. Use the vertical cursor keys to select the required Setpoint setting under SETPOINTS menu.
3. Press OK to access to the next menu and to view the setting data in the cselected menu.
4. To return to the previous header menu 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 Cancel key repeatedly from any of the menu headings until the
default display is reached.
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 steady 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.

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8. Press the Enter key to confirm the new setting value.

9. The changes must be confirmed before they are used. When all required changes have been entered, press
the Clear key. Before returning to the default display, the following prompt appears.

CONFIRM CHANGES?
NO YES

10. Press the YES right Up key key to accept the new settings or press the NO left Up key key to discard the new
settings.

Note:
It is not possible to change the PSL or IEC 61850 configuration using the IED’s front panel HMI.

Caution:
Where the installation needs application-specific PSL, the relevant .PSL logic, must
be transferred to the IED, taking into account that the logic should apply 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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7 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.

7.1 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 SETPOINTS MENu, 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.

7.2 CONNECTING THE TEST CIRCUIT

1. Use the PSL and device setpoints to determine which output relay will operate when an overcurrent trip
occurs.
2. Use the output relay 1 assigned to Trip.
3. Use the PSL and device setpoints to map the protection stage under test directly to an output relay.
4. Connect the output relay so that its operation will trip the test set and stop the timer.
5. Connect the current output of the test set to the A-phase current transformer input.
6. Ensure that the timer starts when the current is applied.

7.3 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 setpoint.
3. Note the time displayed when the timer stops.
4. Check that the red trip LED has illuminated.

7.4 CHECK THE OPERATING TIME

Check that the operating time recorded by the timer is within the range shown in the technical specification for
each function.
For all characteristics, allowance must be made for the accuracy of the test equipment being used.

Caution:
On completion of the tests, you must restore all settings to customer specifications.

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8 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.

8.1 CONFIRM CURRENT CONNECTIONS

1. Measure the current transformer secondary values for each input using a multimeter connected in series
with the corresponding current input.
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.
4. Compare the values of the secondary phase currents and phase angle with the measured values, which
can be found in the MONITOR > MEASUREMENTS menu.

8.2 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 values, which can be found in the
MONITOR > MEASUREMENT >PHASE VT1 BANK-A and 4th VT1 BANK-A menus.

MONITOR > MEASUREMENT >PHASE VT1 BANK-A and

Corresponding VT ratio in CT AND VT RATIOS column
4th VT1 BANK-A menus
VT1 VAN
VT1 VBN
VT1 VCN
Main VT Primary / Main VT Sec'y
VT1 VAB
VT1 VBC
VT1 VCA
4th VT1 Mag 4th VT Primary / 4th VT Sec'y

8.3 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

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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
setting in the MONITOR > MEASUREMENTS > POWER 1 menu should show positive power signing.
● For load current flowing in the Reverse direction (power import from the remote line end), the A Phase
Watts setting in the MONITOR > MEASUREMENTS > POWER 1 menu should show negative power signing.
In the event of any uncertainty, check the phase angle of the phase currents with respect to their phase voltage.

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9 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 SETTING tab and SETPOINTS
menus.
5. Ensure that the IED has been restored to service by checking that the Simulation State setting in the
TESTING >SIMULATION > SETUP menu 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 test block is installed, remove the test plug and replace all wiring 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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TESTING
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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 395
Testing Features 396
Simulation 397
Test LEDs 399
Output Relays 400
Autoreclose 401

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2 TESTING FEATURES
P40Agile can simulate current and voltage inputs when the Simulation feature is enabled. Other test operations
are also possible such as the LED lamp test of each color, contact input states, testing of output relays and testing
of autorecloser.
● Simulation
● Test LEDs
● Opto Inputs
● Output Relays
● Autoreclose

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3 SIMULATION
The Simulation feature is provided for testing the functionality of the IED in response to programmed conditions,
without the need of external AC voltage and current inputs. First time users will find this to be a valuable training
tool. System parameters such as currents, voltages and phase angles are entered as setpoints. When placed in
simulation mode, the relay suspends reading actual AC inputs, generates samples to represent the programmed
phasors, and loads these samples into the memory to be processed by the relay. Normal (pre-fault), fault and post-
fault conditions can be simulated to exercise a variety of relay features. There are three sets of input parameters
used during simulation, each provides a particular state of the system as follows.
Path: Setpoints > Testing > Simulation > Setup
● Simulation State
● Pre-Fault to Fault Trigger
● Force Relays
● Force LEDs

Program the Simulation State to “Disabled” if actual system inputs are to be monitored.
If programmed to any other value, the relay is in test mode and actual system parameters are not monitored,
including Current, Voltage, and Opto Inputs. The system parameters simulated by the relay are those in the
following section that correspond to the programmed value of this setpoint. For example, if programmed to
“Fault”, then the system parameters are set to those defined by the Fault setpoint values.
Note: While in test mode, Opto Input states are automatically forced to the values set in Setpoints > Testing > Opto
Inputs. When the Fault State is set as the Simulation State and a Trip occurs, the Simulation State automatically
transitions to the Postfault State.
When in test mode, and Force Relays is “Enabled”, relay states can be forced from the Setpoints > Testing > Output
Relays menu, this overrides the normal operation of the output contacts. When in test mode, and Force Relays is
“Disabled”, the relay states maintain their normal operation. Forcing of output relay states is not performed when
the Simulation State is “Disabled”.
When in test mode, and Force LEDs is “Enabled”, LED states and colors can be forced from the Setpoints > Testing
> Test LEDs menu, this will override the normal operation of the LEDs. When in test mode, and Test LEDs is
“Disabled”, the LED states and colors will maintain their normal operation. Forcing of LEDs is not performed when
the Simulation State is “Disabled”.

3.1 PRE-FAULT
This state is intended to simulate the normal operating condition of a system by replacing the normal input
parameters with programmed pre-fault values. For proper simulation, values entered here must be below the
minimum trip setting of any protection feature.
Voltage magnitudes and angles are entered as Wye values only. The voltage setpoints are not available if the
corresponding VT Bank PHASE VT CONNECTION setpoint is Delta. Voltages are set in secondary VT units.

3.2 FAULT
The Fault state is intended to simulate the faulted operating condition of a system by replacing the normal input
parameters with programmed fault values.
Voltage magnitudes and angles are entered as Wye values only. The voltage setpoints are not available if the
corresponding VT Bank PHASE VT CONNECTION setpoint is Delta. Voltages are set in secondary VT units.

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3.3 POST-FAULT
This state is intended to simulate the normal operating condition of a system by replacing the normal input
parameters with programmed pre-fault values. For proper simulation, values entered here must be below the
minimum trip setting of any protection feature.
Voltage magnitudes and angles are entered as Wye values only. The voltage setpoints are not available if the
corresponding VT Bank PHASE VT CONNECTION setpoint is Delta. Voltages are set in secondary VT units.

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4 TEST LEDS
The Test LEDs setting is used to program the state and color of each LED when in test mode and Force LEDs is
“Enabled”.
Test LEDs setpoints here (in test mode) will revert to default values at power-up.
Path: Setpoints > Testing > Test LEDs

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5 OUTPUT RELAYS
This is for testing the sequence of circuit breaker trip and auto-reclose cycles when in test mode.
The 3 Pole Test command causes the device to perform the first three phases trip/reclose cycle so that associated
output contacts can be checked for operation at the correct times during the 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 auto-reclose cycles, you can repeat the 3 Pole test command.

Note:
Simulation state should be Disabled.

PATH: Setpoints\Testing\Autoreclose.

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6 AUTORECLOSE
The Output Relays section is used to program the state of each output relay when the device is in test mode and
Force Relays is “Enabled”.
Select “Off” to force the output relay to the de-energized state, or select “On” to force the output relay to the
energized state.
The number of Output Relays available is dependent on the installed Order Code options.
Output Relays setpoints here (in test mode) will revert to default values at power-up.
Path: Setpoints > Testing > Output Relays

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MAINTENANCE AND TROUBLESHOOTING

Chapter 22 - Maintenance and Troubleshooting P14D

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1 CHAPTER OVERVIEW
The Maintenance and Troubleshooting chapter provides details of how to maintain and troubleshoot products
based on the P40Agile platform. 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 405
Maintenance 406
Troubleshooting 409

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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 when
the environment and electrical conditions are within stated specifications.
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 TARGETS AND ALARMS

Target messages are automatically displayed for any active condition on the relay such as pickups, trips, or alarms
or minor or major error. The relay displays the most recent event first, active target messages will be displayed
until the conditions clear.
Target and Alarm messages can be reviewed by accessing the Targets menu using the Up and Down keys in the
display, or using the Read key in case the Alarm LED is ON.
For Non-latched Alarms the alarm LED flashes until the alarm conditions disappears, then it switches OFF.
For Latched Alarms the LED flashes until the alarm condition disappears, then changes to constantly ON.
When the alarms are cleared, the LED switches OFF.

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.

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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.

2.1.5 EXTERNAL DAMAGE

Complete a visual inspection for any damage, corrosion, dust, or loose wires.

2.1.6 RECORDS
Check Event Recorder file downloads, with further events analysis.

2.1.7 OUT-OF-SERVICE MAINTENANCE

1. Check wiring connections for firmness.
2. Analog values (currents, voltages, RTDs, analog inputs) injection test and metering accuracy verification.
Calibrated test equipment is required.
3. Protection elements setting verification (analog values injection or visual verification of setting file entries
against relay settings schedule).
4. Contact inputs and outputs verification. This test can be conducted by direct change of state forcing or as
part of the system functional testing.
5. Visual inspection for any damage, corrosion, or dust.
6. Event recorder file download with further events analysis.

Note:
To avoid deterioration of electrolytic capacitors, power up units that are stored in a deenergized state once per year, for one
hour continuously.

2.1.8 UNSCHEDULED MAINTENANCE (SYSTEM INTERRUPTION)

View the event recorder and oscillography for correct operation of inputs, outputs,
and elements.

2.2 REPLACING THE UNIT

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 should normally
replace the cradle which slides easily out of the case. This can be done without disturbing the scheme wiring.
In the unlikely event that the problem lies with the wiring and/or terminals, then you must replace the complete
device, rewire and re-commission the device.

Caution:
If the repair is not performed by an approved service centre, the warranty will be
invalidated.

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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 unit, isolate all voltage and current supplying it.

To replace the cradle without disturbing the case and wiring:

1. Remove the faceplate.
2. Carefully withdraw the cradle from the front.
To reinstall the unit, follow the above instructions in reverse, ensuring that each connector is relocated in the
correct position and all connections are replaced. The terminal blocks are labelled alphabetically with ‘A’ on the
right hand side when viewed from the rear.
Once the unit has been reinstalled, it should be re-commissioned as set out in the Commissioning chapter.

2.3 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.
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 checks 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 voltage on terminals A2 and A1.
If the auxiliary voltage is correct, go to test 2. Otherwise check the wiring
1 Verify the voltage level and polarity against the
and fuses in the auxiliary supply.
rating label
If the LEDs and LCD backlight switch on, or the Watchdog contacts close
Check the LEDs and LCD backlight switch on at and no error code is displayed, the error is probably on the main processor
2 power-up. Also check the N/C (normally closed) board.
watchdog contact to see if it opens. If the LEDs and LCD backlight do not switch on and the N/C Watchdog
contact does not open, the fault is probably in the IED.

3.3 SELF-TEST ERRORS

The relay performs self diagnostics at initialisation (after power up), and continuously as a background task to
ensure that the hardware and software are functioning correctly.
There are two types of self-test warnings indicating either a minor or major problem. Minor problems indicate a
problem with the relay that does not compromise protection of the power system. Major errors indicate a problem
with the relay which takes it out of service.

Caution:
Self-Test Warnings may indicate a serious problem with the relay hardware.

Upon detection of a minor problem, the relay will:

● Display the detailed description of the error on the relay display as a target message
● Record the minor self-test error in the Event Recorder.
● Flash the "ALARM" LED.

Upon detection of a major problem, the relay will:

● De-energizes critical failure relay
● De-energizes all output relays
● Blocks protection and control elements
● Turns the "HEALTHY" LED to off

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● Turns the "OUT of Service" LED to ON

● Flashes the "ALARM" LED
● Displays “Major Self-test error” with the error code as a target message
● Records the major self-test failure in the Event Recorder

Note:
The Critical Failure Relay (Output Relay 8) is energised when the relay is in-service, and no major error is present.

Minor Error 1

Message & Event Recorder

Minor Error 2

. Message & Event Recorder

. ANY MINOR ERROR

OR
.
(See all minor errors listed
. in the table below)
.
.
Minor Error XX

Message & Event Recorder

E06926

Figure 151: Minor error events and message generation

Major Error 1

Message & Event Recorder

Major Error 2

. Message & Event Recorder

. ANY MAJOR ERROR

OR

.
(See all major errors listed
. in the table below)
.
.
Major Error XX

Message & Event Recorder

E06927

Figure 152: Major error events and message generation

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Minor self-test errors

Self-Test Error Message Description of the How often the test is What to do
problem performed
Hardware doesn’t
Order Code Error
match order code Every 2,5 seconds
CPU card doesn’t have
valid data to match the
CPU S/N Invalid order code. Every 2,5 seconds
IO card located in slot
'n' doesn’t have valid
data to match the order
Slot 'n' IO S/N Invalid code. Every 2,5 seconds
Power Supply Unit
doesn’t have valid data
to match the order
PSU S/N Invalid code. Every 2,5 seconds
The CPU cannot read If alert doesn’t self-reset,
RTC Error the time from the real then contact factory.
time clock Every 2,5 seconds
The product serial Otherwise monitor re-
Product Serial Invalid number doesn’t match occurrences as a
the product type Every 2,5 seconds momentary error was
Serial port errors when detected but recovered.
COMM Error #1 initializing or accessing
it. Every 2,5 seconds
The permanent storage
FLASH Error memory has been
corrupted Every 2,5 seconds
Communication error
between CPU and LEDs,
SPI Error
Keypad or peripheral
memory devices Every 2,5 seconds
MAC address is not in
Invalid MAC Address
the product range Every 2,5 seconds
Calibration Error Unit has default Boot-up and Every 2,5
calibration values seconds
Clock Not Set The clock has the Every 2,5 seconds Set clock to current time
default time
Link Error Primary Port 1 is not connected Every 2,5 seconds Ensure Ethernet cable is
connected, check cable
functionality (i.e. physical
damage or perform
continuity test) and ensure
master or peer device is
functioning. If none of these
apply, contact the factory.
Traffic Error Primary Abnormally high Every 2,5 seconds Contact site IT department
amount of Broadcast to check network for
and Uni-cast traffic on malfunctioning devices
port 1 or port 4
Ambient Temperature The ambient Every 2,5 seconds Inspect mounting
>80C temperature enclosure for unexpected
surrounding the heat sources (i.e loose
product has exceeded primary cables) and remove
80C accordingly

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IRIG-B Failure A bad IRIG-B input Every 2,5 seconds Ensure IRIG-B cable is
signal has been connected, check cable
detected functionality (i.e. physical
damage or perform
continuity test), ensure IRIG-
B receiver is functioning,
and check input signal level
(it may be less than
specification). If none of
these apply, contact the
factory.
STNP Failure Synchronization from a Every 2,5 seconds Ensure Ethernet connection,
SNTP server failed. check cable functionality
(i.e. physical damage) and
ensure SNTP server
configuration is correct. If
none of these apply,
contact the factory.
PTP Failure Synchronization from a Every 2,5 seconds Ensure Ethernet connection,
PTP master failed. check cable functionality
(i.e. physical damage) and
ensure PTP settings are
correct. If none of these
apply, contact the factory.
Version Mismatch CPU firmware revision Boot-up and Every 2,5 Ensure CPU was uploaded
must match with Order seconds during the upgrade process.
Code and CID. Ensure Order Code and CID
are correct.
SelfTestFWUpdate The updating of the Every 2,5 seconds Re-try uploading firmware.
firmware failed If the upload doesn’t work a
second time contact factory

Major self-test errors

Self-Test Error Description of the How often the test is What to do
Message problem performed
Relay Not Ready DEVICE INSTALLATION On power up and Program all required
DEVICE INSERVICE whenever the DEVICE settings and then set the
setting indicates relay is INSTALLATION DEVICE DEVICE INSTALLATION
not in a programmed INSERVICE setting is DEVICE INSERVICE setting to
state. altered. "Ready".
Major Self-Test (error Unit hardware failure Every 2,5 seconds Contact the factory and
code) detected supply the failure code as
noted on the display.
where 'n' is the slot ID (i.e. F, G, H etc.)
Under both conditions, the targets cannot be cleared if the error is still active.

3.4 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. A permanent problem (for example due to a hardware fault) is usually detected in the power-
up sequence. By examining the maintenance record logged, the nature of the detected fault can be determined.

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3.5 MAL-OPERATION DURING TESTING

3.5.1 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 output status in the Commissioning
2 If the contact output status are operated, go to test 4; if not, go to test 3.
or Testing section of the menu.
If the protection element does not operate, check the test is correctly
applied.
Examine the fault record or use the test port to check the
3 If the protection element operates, check the protection element
protection element is operating correctly.
settings to make sure the output contacts (Relay O/P) are correctly
selected and configured.
Using the Commissioning or Testing mode function, If the output relay operates, the problem must be in the external wiring
apply a test pattern to the relevant relay output to the relay. If the output relay does not operate the output relay
4 contacts. Consult the correct external connection contacts may have failed (the self-tests verify that the relay coil is being
diagram and use a continuity tester at the rear of the energized). Ensure the closed resistance is not too high for the continuity
relay to check the relay output contacts operate. tester to detect.

3.5.2 FAILURE OF OPTO-INPUTS

The opto-isolated inputs are mapped onto the IED's internal signals using the programmable scheme logic. If an
input is not recognized by the scheme logic, use the Opto I/P Status setting in the Commissioning or Testing menu
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 OPTO CONFIG. To do this:
1. Select the nominal battery voltage for all opto-inputs by selecting one of the five standard ratings in the
Global Nominal V cell.
2. 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).
If the signal is correctly applied, this indicates failure of an opto-input, in which case the complete cradle should be
replaced.

3.5.3 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. To check current and
voltages inject 2 times the nominal values.
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.

3.6 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
● Password in not valid

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● Communication set-up 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

3.6.1 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

3.6.2 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.

3.7 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:
contact.centre@ge.com
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

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3. Send the RMA form to your local contact

For a list of local service contacts worldwide, email us at:
contact.centre@ge.com
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
Chapter 23 - Technical Specifications P14D

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1 CHAPTER OVERVIEW
This chapter describes the technical specifications of the product.

Note:
To obtain the total operating time, i.e. from the presence of a trip condition to initiation of a trip, add 8 ms output relay time to
the operate times listed below.

This chapter contains the following sections:

Chapter Overview 419
Interfaces 420
Performance of Current Protection Functions 421
Performance of Voltage Protection Functions 425
Performance of Frequency Protection Functions 427
Power Protection Functions 428
Performance of Monitoring and Control Functions 429
Measurements and Recording 431
Regulatory Compliance 432
Ratings 434
Power Supply 435
Input / Output Connections 436
Environmental Conditions 438
Type Tests 439
Electromagnetic Compatibility 440

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2 INTERFACES

2.1 REAR SERIAL PORT 1

Rear serial port 1 (COM1)

Use For SCADA communications (multi-drop)
Standard EIA(RS)485, IRIG-B
Connector General purpose pluggable terminal block, 3.5 mm screws (3 wire)
Cable Screened twisted pair (STP)
Supported Protocols IEC-60870-5-103, DNP3.0, MODBUS
Isolation Isolation to PELV level
Constraints Maximum cable length 1000 m

2.2 IRIG-B PORT (SHARED WITH REAR SERIAL PORT COM1)

IRIG-B Interface (De-modulated)

Use External clock synchronization signal
Standard IRIG 200-98 format B00X
Connector Rear serial port 1
Cable type Screened twisted pair (STP)
Accuracy < +/- 1 s per day

2.3 REAR ETHERNET PORT COPPER

Rear Ethernet port using CAT 5/6/7 wiring

Main Use Substation Ethernet communications / Engineering port
Communication protocol 10BaseT/100BaseTX
Connector RJ45
Cable type Screened twisted pair (STP)
Isolation 1 kV
Supported Protocols* IEC61850 Ed-2, DNP3oE, Modbus TCP
Constraints Maximum cable length 100 m
*Not all models support all protocols - see ordering options.

2.4 FRONT USB PORT

Front USB port

Use For local connection to laptop for configuration purposes and firmware downloads
Connector USB type B
Isolation Isolation to PELV level
Constraints Maximum cable length 5 m

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3 PERFORMANCE OF CURRENT PROTECTION FUNCTIONS

3.1 THREE-PHASE OVERCURRENT PROTECTION (DIRECTIONAL/ NON-DIRECTIONAL)

Level accuracy for 0.1 to 2.0 x CT ±0.5% of reading or ±0.4% of rated, whichever is greater
Level accuracy for > 2.0 x CT ±1.5% of reading > 2.0 x CT rating
Drop-off (IDMT and DT) 97 to 98% of Pickup
Currents > 1.03 to 20 x pickup: ± 3% of operate time or ± 1 cycle
Curve timing accuracy
(whichever is greater) from pickup to operate

< 12 ms at 3 × pickup at 60 Hz
DT operate
< 15 ms at 3 × pickup at 50 Hz

DT timer accuracy ±2% of operate time or ± ¼ cycle (whichever is greater)

DT reset Setting ± 5%

3.1.1 THREE-PHASE OVERCURRENT DIRECTIONAL PARAMETERS

Directional boundary accuracy (RCA +/-90%) +/-2°

Note:
The directional element does not have any operands. These are included internally in the overcurrent protection

3.2 EARTH FAULT PROTECTION (DIRECTIONAL/ NON-DIRECTIONAL)

Measured and Derived

For 0.1 to 2.0 x CT, ±0.5% of reading or ±0.4% of rated (whichever is greater)
Level accuracy
For > 2.0 x CT, ±1.5% of reading > 2.0 x CT rating
Drop-off (IDMT and DT) for EF1 97 to 98% of pick-up
Drop-off (IDMT and DT) for EF2 97 to 98% of pick-up
Currents > 1.03 to 20 x pickup: ± 3% of operate time or ± 1 cycle (whichever is
IDMT operate
greater) from pickup to operate
< 12 ms at 3 × pickup at 60 Hz
DT operate (EF 1)
< 15 ms at 3 × pickup at 50 Hz
< 16 ms at 3 × pickup at 60 Hz
DT operate (EF 2)
< 19 ms at 3 × pickup at 50 Hz
DT reset Setting +/- 5%
EF1: DT timer accuracy ±2% of operate time or ± ¼ cycle (whichever is greater)
EF2: DT timer accuracy ±3% of operate time or ± ¼ cycle (whichever is greater)

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3.2.1 EARTH FAULT DIRECTIONAL PARAMETERS

Directional boundary pick-up (RCA +/- 90°) +/-2°

3.3 SENSITIVE EARTH FAULT PROTECTION (DIRECTIONAL/NON-DIRECTIONAL)

For 0.1 to 2.0 x CT ±0.5% of reading or ±0.4% of rated (whichever is greater)

Level accuracy
For > 2.0 x CT ±1.5% of reading > 2.0 x CT rating
Drop-off (IDMT + DT) 97 to 98% of Pickup
>1.03 to 20 x pickup: ± 3% of operate time or 1 cycle (whichever is greater) from pickup to
IDMT operate
operate
< 12 ms at 3 × pickup at 60 Hz
DT operate
<15 ms at 3 x pickup at 50 Hz
DT Reset Setting +/- 5%

3.3.1 SEF DIRECTIONAL PARAMETERS

Angle Accuracy +/- 2%

3.4 RESTRICTED EARTH FAULT PROTECTION

High/low Impedance Retricted Earth Fault (REF) accuracy

For 0.1 to 2.0 x CT: ±0.5% of reading or ±0.4% of rated (whichever is greater)
Pick-up
For > 2.0 x CT: ±1.5% of reading
Drop-off 97 to 98%
< 25 ms at 1.1 × slope x Imax at 60 Hz
Operating time
< 30 ms at 1.1 × slope x Imax at 50 Hz
High pick-up Setting +/- 5%
Timer accuracy ±3% of delay setting or ± ¼ cycle (whichever is greater) from pickup to operate

3.5 NEGATIVE SEQUENCE OVERCURRENT PROTECTION (DIRECTIONAL/NON-

DIRECTIONAL)

For 0.1 to 2.0 x CT, ±0.5% of reading or ±0.4% of rated, whichever

Level accuracy is greater
For > 2.0 x CT, ±1.5% of reading > 2.0 x CT rating
Drop-off (IDMT + DT) 97 to 98% of pick-up%
Currents > 1.03 to 20 x pickup: ± 3% of operate time or ± 1 cycle
IDMT operate
(whichever is greater) from pickup to operate
< 12 ms at 3 × pickup at 60 Hz
DT operate
< 15 ms at 3 × pickup at 50 Hz
DT Reset Setting +/- 5%
DT timer accuracy 2% of operate time or ± ¼ cycle (whichever is greater)

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3.5.1 DIRECTIONAL PARAMETERS

Directional boundary pick-up (RCA +/-90%) +/- 2°

3.6 CIRCUIT BREAKER FAIL

For 0.1 to 2.0 x CT: ±0.5% of reading or ±0.4% of rated (whichever

Pick-up is greater)
For > 2.0 x CT: ±1.5% of reading
I< Drop-off 97 to 98% of pick-up
Timers +/- 3% or 1 cycle, whichever is greater from pick-up to operate

3.7 BROKEN CONDUCTOR PROTECTION

For 0.1 to 2.0 x CT: ±0.5% of reading or ±0.4% of rated (whichever

Pick-up is greater)
For > 2.0 x CT: ±1.5% of reading
Drop-off 97 to 98 % of Pickup level
±3% of delay setting or ± ¾ cycle (whichever is greater) from
DT operate
pickup to operate

3.8 THERMAL OVERLOAD PROTECTION

For 0.1 to 2.0 x CT: ±0.5% of reading or ±0.4% of rated (whichever

Current level accuracy is greater)
For > 2.0 x CT: ±1.5% of readi
< 30 ms at 60Hz (from 0 to 120 x pickup)
Operate time
< 36 ms at 50Hz (from 0 to 120 x pickup)
Thermal alarm pick-up Calculated trip time +/- 10%
Thermal overload pick-up Calculated trip time +/- 10%
Cooling time accuracy +/- 15% of theoretical

3.9 COLD LOAD PICKUP PROTECTION

Pick-up 0.05 x CT fixed

Drop-off 0.05 x CT fixed
+/-3% of delay setting or +/- ¼ cycle (whichever is greater) from
DT operate
pickup to operate

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3.10 UNDERCURRENT

For 0.05 to 2.0 x CT: ±0.5% of reading or ±0.4% of rated,

Pick-up
whichever is greater
±3% of delay setting or ± 2 power cycles (whichever is greater)
IDMT operate
from pick-up to operate
<45 ms at 60 Hz
Operating Time
<50 ms at 50 Hz
Dropoff 102% to 103% of Pickup

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4 PERFORMANCE OF VOLTAGE PROTECTION FUNCTIONS

4.1 UNDERVOLTAGE PROTECTION

Pick-up (IDMT and DT) +/- 0.5 % of reading from 10 to 240 V

Drop-off (IDMT and DT) 102 to 103 % of Pickup
<0.9 x pickup: +/- 3.5% of operate time or +/- 1 cycle (whichever
IDMT operate
is greater) from pickup to operate
DT operate +/- 2% or 50 ms, whichever is greater

4.2 OVERVOLTAGE PROTECTION

IDMT pick-up +/- 0.5% of reading from 10 to 240 V

DT pick-up +/- 0.5% of reading from 10 to 240 V
Drop-off (IDMT and DT) 97-98% of pick-up
at >1.1 x PKP : +/- 3 % of operate time or 1 cycle (which ever is
IDMT operate
greater)
DT operate +/- 3% of operate time or 1 cycle (which ever is greater)
DT reset Setting +/- 5%

4.3 RESIDUAL OVERVOLTAGE PROTECTION

Pick-up ±0.5% of reading from 10 to 240 V

IDMT Pickup ±0.5% of reading from 10 to 240 V
Drop-off (IDMT and DT) 97 to 98% of pick-up
at >1.1 x pick-up: +/- 3 % of operate time or +/- ½cycle
IDMT operate
(whichever is greater) from pick-up to operate
DT operate ± 3% of operate time or ± 0.5cycle (whichever is greater)
DT reset Setting ±5%

4.4 POSITIVE SEQUENCE VOLTAGE PROTECTION

Accuracy
Pick-up ±0.5% of reading from 10 to 208 V
Drop-off 97 to 98% of pick-up
<25 ms at 1.1 x pickup at 60Hz
Operate time
<30 ms at 1.1 x pickup at 50Hz
± 3% of delay setting or ± 1 cycle (whichever is greater) from
Timer accuracy
pickup to operate

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4.5 NEGATIVE SEQUENCE VOLTAGE PROTECTION

Accuracy
Pick-up ±0.5% of reading from 10 to 208 V
Drop-off 97 to 98% of pick-up
<25 ms at 1.1 x pickup at 60Hz
DT operate (normal operation)
<30 ms at 1.1 x pickup at 50Hz
± 3% of delay setting or ± 1 cycle (whichever is greater) from
Timer accuracy
pickup to operate

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5 PERFORMANCE OF FREQUENCY PROTECTION FUNCTIONS

5.1 OVERFREQUENCY PROTECTION

Accuracy
Pick-up Setting ±0.01 Hz
Drop-off Pickup - 0.03 Hz
± 2% of delay setting or ± 50 ms(whichever is greater) from pick-
Operating timer
up to operate

Operating and Reset time

Operating time (0.1 Hz/s change) typically 4 cycles
Operating time (0.3 Hz/s change) typically 3.5 cycles
Operating time (0.5 Hz/s change) typically 3 cycles

Typical times are average operate times including variables such as frequency change instance, test method, etc.,
and may vary by ±0.5 cycles

5.2 UNDERFREQUENCY PROTECTION

Accuracy
Pick-up Setting ±0.01 Hz
Drop-off Pickup + 0.03 Hz
± 2% of delay setting or ± 50 ms (whichever is greater) from pick-
Operating timer
up to operate

Operating and Reset time

Operating time (0.1 Hz/s change) typically 4 cycles
Operating time (0.3 Hz/s change) typically 3.5 cycles
Operating time (0.5 Hz/s change) typically 3 cycles

5.3 FREQUENCY RATE OF CHANGE PROTECTION

Accuracy
Pick-up (df/dt) 10 mHz/s or 3.5%, whichever is greater
Drop-off 96% of pick-up level
Typically 6.5 cycles at 2 x pick-up
Operating timer Typically 5.5 cycles at 3 x pick-up
Typically 4.5 cycles at 5 x pick-up

Operating and Reset time

± 3% of delay setting or ± ¼ cycle (whichever is
Operating time
greater) from pickup to operate
Reset time <250 ms

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6 POWER PROTECTION FUNCTIONS

6.1 OVERPOWER / UNDERPOWER PROTECTION

Pick-up level accuracy ±1.5% or ±0.005 x Rated Power, whichever is greater

Hysteresis 2% or 0.001 x Rated Power, whichever is greater
Operating time ± 2% or 50ms, whichever is greater
tRESET ± 5%

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7 PERFORMANCE OF MONITORING AND CONTROL FUNCTIONS

7.1 VOLTAGE TRANSFORMER SUPERVISION

Fast block operation < 25 ms

Fast block reset < 40 ms
Time delay +/- 2% or 40 ms, whichever is greater

7.2 CURRENT TRANSFORMER SUPERVISION

For 0.1 to 2 x CT: +/-0.5% of reading or +/- 0.4% of rated

Level accuracy (whichever is greater)
For > 2 x CT: +/-1.5% of reading
<12 ms typical at 3 x pickup at 60 Hz
Operate time
<15 ms typical at 3 x pickup at 50 Hz
+/- 3 % delay setting or +/- ¼ cycle (whichever is greater) from
Timer accuracy
pickup to operate
CTS reset < 40 ms

7.3 CB STATE AND CONDITION MONITORING

Timers +/- 40 ms or 2%, whichever is greater

7.4 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

7.5 DC SUPPLY MONITOR

Measuring Range 19 V-300 V

Tolerance +/-2.5% or 1.5V whichever is greater
Pickup 100% of Setting ± Tolerance *
Dropoff Hysteresis 2%
102% of Setting ± Tolerance for the upper limit *
98% of Setting ± Tolerance for the lower limit *
Operate Time Setting ± (2% or 500 ms whichever is greater)

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Note:
* Tested at 21°C

7.6 POLE DISCREPANCY

Level Accuracy (Current) 0.1 < I < 2.0 x CT: ±0.5% of reading or ±0.4% of rated (whichever is
greater)
I > 2.0 x CT: ±1.5% of reading
Dropout level 97 to 98% of Current Limit
Timer Accuracy ±3% of operate time or ± 1 cycle (whichever is greater)

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8 MEASUREMENTS AND RECORDING

8.1 METERING

Parameter RANGE ABS TOLERANCE

% TOLERANCE
HIGH HIGH
0.05 x In 2 x In 0,50% 0.002 x In
Current Mag
2 x In 30 x In 1,00% ---
0.002 x In 0.2 x In 0,50% 0.001 x In
Sens Current Mag
0.2 x In 3 x In 1,00% ---
Voltage Mag 10 V 300 V 0,5% ---
Current Ang 0.05 x In 30 x In --- 1º
Voltage Ang 10 V 300 V --- 1º
Frequency 40 Hz 70 Hz --- 0.01Hz
Real Power (Watts) -0.8 < PF ≤ -1.0 and 0.8 < PF < 1.0 ± 1.5% of reading 0.005 * rated kW
Reactive Power (Vars) -0.2 < PF ≤ 0.2 ± 1.5% of reading 0.005 * rated kVAr

8.2 DISTURBANCE RECORDS

Disturbance Records Measurement Accuracy

Number of records 1 to 16
Sampling rate (Samples/cycle) 128 S/c, 64 S/c, 32 S/c, 16 S/c, 8 S/c
Magnitude and relative phases accuracy ±5% of applied quantities
Trigger position accuracy ±2%

8.3 EVENT AND FAULT RECORDS

Event & Fault Records

Record location Flash memory
Viewing method Front panel display or EnerVista Flex
Extraction method Extracted via the USB or Ethernet port
Number of Event records Up to 2048 time tagged event records
Number of Fault Records Up to 25

8.4 FAULT LOCATOR

Accuracy
+/- 3.5% of line length up to SIR 30
Fault Location
Reference conditions: solid fault applied on line
Method Single-ended

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9 REGULATORY COMPLIANCE
Compliance with the European Commission Direction on EMC, LVD and RoHS is via the self certification route.

9.1 EMC COMPLIANCE: 2014/30/EU

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

9.2 EMC COMPLIANCE: 2574-14 OF RAMADAN 1436

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

9.3 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.

9.4 LVD COMPLIANCE: 2573-14 OF RAMADAN 1436

The product specific Declaration of Conformity (DoC) lists the relevant harmonized standard(s) or conformity
assessment used to demonstrate compliance with the LVD directive

9.5 ROHS COMPLIANCE 2011/65/EU AND (EU) 2015/863

The product complies with the directive of the Council of the European Communities on harmonization of the laws
of the Member States concerning restriction on usage of hazardous substances in electrical and electronic
equipment (RoHS Directive 2011/65/EU). This conformity has been proved by tests performed according to the
Council Directive in accordance with the standard EN 50581.

9.6 MOROCCO COMPLIANCE

If marked with this logo, the product is compliant with the requirements of the Morocco safety and EMC
regulations No.2573.14 and 2574.14.

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9.7 MECHANICAL SPECIFICATIONS

9.7.1 PHYSICAL PARAMETERS

Physical Measurements

Case Types 20TE

Weight (20TE case) 1.5 kg –2 kg (depending on chosen options)

Dimensions in mm (w x h x l) (20TE case) W: 102.4mm H: 177.0mm D: 185.6mm
Mounting Panel, rack

9.7.2 ENCLOSURE PROTECTION

Against dust and dripping water (front face) IP52 as per IEC 60529:2013
Protection for rear of the case IP20 as per IEC 60529:2013
Noise 0 dB

Caution:
To maintain IP20 protection, the rear cover must be re-installed as per the provided instructions after
wiring is complete.

9.7.3 MECHANICAL ROBUSTNESS

Vibration test per EN 60255-21-1:1988 Response: class 2, Endurance: class2

Shock response: class 2, Shock withstand: class 1, Bump withstand:
Shock and bump immunity per EN 60255-21-2:1988
class 1
Seismic test per EN 60255-21-3: 1995 Class 2

9.7.4 TRANSIT PACKAGING PERFORMANCE

Primary packaging carton protection ISTA 1C

Compression test 1.4 x Calculated force
Vibration tests 4 Orientations, Random frequency, 22.45mm amplitude, 1.15 G
Shock test 10 drops from 760mm on multiple carton faces, edges and corners

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10 RATINGS

10.1 AC MEASURING INPUTS

AC Measuring Inputs
Nominal frequency 50 Hz or 60 Hz (settable)
Operating range 40 Hz to 70 Hz
Phase rotation ABC or CBA

10.2 CURRENT TRANSFORMER INPUTS

AC Current
Nominal current (In) 1A and 5A dual rated*
Nominal burden per phase < 0.05 VA at In
Continuous: 4 x In
10 s: 30 x In
AC current thermal withstand
1 s: 100 x In
Linear to 40 x In (non-offset ac current)

Note:
A single input is used for both 1A and 5A applications. 1 A or 5 A operation is determined by means of software in the
product’s database.

Note:
These specifications are applicable to all CTs.

10.3 VOLTAGE TRANSFORMER INPUTS

AC Voltage
Nominal voltage 100 V to 120 V
Nominal burden per phase < 0.1 VA at Vn
Thermal withstand Continuous: 4 x Vn, 10 s: 5 x Vn

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11 POWER SUPPLY

11.1 AUXILIARY POWER SUPPLY VOLTAGE

24-250 V DC +/-20%
Nominal operating range
110-240 V AC -20% + 10%
Maximum operating range 19 to 300 V DC
Frequency range for AC supply 45 – 65 Hz
Ripple <15% for a DC supply (compliant with IEC 60255-26:2013)

11.2 NOMINAL BURDEN

Quiescent burden 8 W max.

0.2 W per output relay for trip contacts
Additions for energised relay outputs
0.14 W per output relay for auxiliary contacts

Opto-input burden 2 mA DC per each input

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12 INPUT / OUTPUT CONNECTIONS

12.1 ISOLATED DIGITAL INPUTS

Opto-isolated digital inputs (opto-inputs)

Compliance ESI 48-4
Rated nominal voltage 24 to 250 V dc
Withstand 300 V dc
Recognition time without debounce time
< 1 ms
setting
Debounce time setting from 1 to 50 ms in steps of 1 ms

12.1.1 NOMINAL PICKUP AND RESET THRESHOLDS

Selectable threshold voltage (PU level) 24, 30, 48, 110, 220 VDC
DO level fixed -20% of PU level

Note:
Filter is required to make the opto-inputs immune to induced AC voltages.

12.2 RL1, RL2, AND RL3 OUTPUT CONTACTS

Compliance In accordance with IEC 60255-1:2009

Use General purpose relay outputs for tripping, opening and closing
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 a maximum load of 7500W))
4 A for 1.5 s, 10000 operations (subject to the above limit for make and break, dc
Make, carry and break, dc resistive
resistive load)
0.5 A for 1 s, 10000 operations (subject to the above limit for make and break, dc
Make, carry and break, dc inductive
inductive load)
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 10000 operations min.
Unloaded contact 100000 operations min.
Operate time < 5 ms
Reset time < 5 ms

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12.3 AUXILIARY OUTPUT CONTACTS

Compliance In accordance with IEC 60255-1:2009

Use General purpose relay outputs for signalling
Rated voltage 300 V
Maximum continuous current 5A
Short duration withstand carry 10 A for 3 s
Make and break, dc resistive 24 W
Make and carry, dc resistive 10 A for 3 s
Operate time < 5 ms
Reset time < 5 ms

12.4 WATCHDOG CONTACTS

Use Non-programmable contacts for relay healthy/relay fail indication

Breaking capacity, dc resistive 24 W

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13 ENVIRONMENTAL CONDITIONS

13.1 AMBIENT TEMPERATURE RANGE

Compliance IEC 60255-27: 2014

Test Method IEC 60068-2-1:2007 and IEC 60068-2-2 2007
Operating temperature range -25°C to +60°C (continuous)
Storage and transit temperature range -40°C to +85°C (continuous)
Altitude up to 2000 m

13.2 TEMPERATURE ENDURANCE TEST

Temperature Endurance Test

Test Method IEC 60068-2-1: 2007 and 60068-2-2: 2007
-25°C (96 hours)
Operating temperature range
+60°C (96 hours)

-40°C (96 hours)

Storage and transit temperature range
+85°C (96 hours)

13.3 AMBIENT HUMIDITY RANGE

Compliance IEC 60068-2-78: 2013 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

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14 TYPE TESTS

14.1 INSULATION

Compliance IEC 60255-27: 2014

Insulation resistance > 100 M ohm at 500 V DC (Using only electronic/brushless insulation tester)

14.2 CREEPAGE DISTANCES AND CLEARANCES

Compliance IEC 60255-27: 2014

Pollution degree 2
Overvoltage category lll
Impulse test voltage (not RJ45) 5 kV
Impulse test voltage (RJ45) 1 kV

14.3 HIGH VOLTAGE (DIELECTRIC) WITHSTAND

IEC Compliance IEC 60255-27: 2014

Between all independent circuits 2 kV ac rms for 1 minute
Across open watchdog contacts 1 kV ac rms for 1 minute
Between all RJ45 contacts and protective earth terminal 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

14.4 IMPULSE VOLTAGE WITHSTAND TEST

Compliance IEC 60255-27: 2014

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 Ethernet communications and protective
Front time: 1.2 µs, Time to half-value: 50 µs, Peak value: 1 kV
earth

Note:
Exceptions are communications ports and normally-open output contacts, where applicable.

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15 ELECTROMAGNETIC COMPATIBILITY

15.1 1 MHZ BURST HIGH FREQUENCY DISTURBANCE TEST

Compliance IEC 60255-26:2013

Common-mode test voltage (level 3) 2.5 kV
Differential test voltage (level 3) 1.0 kV

15.2 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

15.3 IMMUNITY TO ELECTROSTATIC DISCHARGE

Compliance IEC 60255-26:2013

Class 4 Condition 15 kV discharge in air to user interface, display, and communication port
Class 4Condition 8 kV discharge in contact to exposed metalwork and communication port.

15.4 ELECTRICAL FAST TRANSIENT OR BURST REQUIREMENTS

Compliance EN61000-4-4:2012. Test severity level lll and lV, IEC 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

15.5 SURGE WITHSTAND CAPABILITY

Compliance IEEE/ANSI C37.90.1: 2012

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 Ethernet
Condition 2
communications

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15.6 SURGE IMMUNITY TEST

Compliance61000-4-5:2014 IEC 61000-4-5:2014 Level 4, IEC60255-26:2013

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)

15.7 IMMUNITY TO RADIATED ELECTROMAGNETIC ENERGY

Compliance IEC 60255-26:2013

Frequency band 80 MHz to 1.0 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 80MHz, 160MHz, 450MHz, 900MHz and 900MHz
Waveform 1 kHz @ 80% am and pulse modulated
Field strength 35 V/m

15.8 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 2.7 GHz
Test field strength 10 V/m
Test using AM 1 kHz / 80%

15.9 IMMUNITY TO CONDUCTED DISTURBANCES INDUCED BY RADIO FREQUENCY

FIELDS

Compliance IEC 60255-26:2013, IEC 61000-4-6:2013 Level 3

Frequency bands 150 kHz to 80 MHz
Test disturbance voltage 10 V rms
Test using AM 1 kHz @ 80%
Spot tests 27 MHz and 68 MHz

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15.10 MAGNETIC FIELD IMMUNITY

IEC 61000-4-8:2010 Level 5

Compliance
IEC61000-4-9:2016 IEC61000-4-110:2017 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

15.11 CONDUCTED EMISSIONS

Compliance IEC 60255-26:2013, EN 55016-2-1:2014

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)

15.12 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 – 6 GHz, 76 dBµV/m at 10 m measurement distance

15.13 POWER FREQUENCY

Compliance IEC 60255-26:2013

300 V common-mode (Class A)
Opto-inputs
150 V differential mode (Class A)

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ENERVISTA FLEX
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1 CHAPTER OVERVIEW
The settings application software used in this range of IEDs is called EnerVista Flex. It is a collection of software
tools, which is used for managing all aspects of the IEDs. This chapter provides a brief description of each software
tool. Further information is available in the Help system.
This chapter contains the following sections:
Chapter Overview 445
Install EnerVista Flex 446
Uninstall EnerVista Flex 447
Configure the USB Port 448
Access Management 449
Login 450
User Settings 451
Quick Connect 453
Error List 455
Device Configuration 456
Create a New Project 458
Manage Projects 459
Project Configuration 460
PSL Editor 464

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2 INSTALL ENERVISTA FLEX

Installation of the EnerVista Flex software requires system administrator access to the computer.

Note:
If there is a previous version of the EnerVista Flex software installed on the computer, it must be uninstalled before installing a
new software version.

1. Download the EnerVista Flex installer from GE.

2. Launch the installer by right-clicking on the .exe and selecting the option to Run as administrator.
3. When the initial installer screen opens, click Next to continue.
4. Read and accept the terms in the license agreement by selecting the I accept the terms in the license
agreement radio button, click Next to continue.
5. Click Install to start the installation. To review any information in previous steps, click Back. To stop the
installation, click Cancel.
6. Wait for the installation to finish. Progress is indicated by the Status bar.
7. After installation, click Finish to close the window.
8. If prompted to install GE Energy Network adapters, click Install. Ensure that the trust GE software checkbox
is ticked.
The software installation process creates the following folder:
C:\Program Files (x86)\GE Power Management\EnerVista Flex

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3 UNINSTALL ENERVISTA FLEX

To uninstall the software:
1. Access the Control Panel in Windows® and click the Add or Remove Program option.
2. Select EnerVista Flex from the list of installed software and click Uninstall.
3. Confirm the uninstall, if necessary.
4. Wait for the software removal process to complete. This can take a few minutes.
5. Confirm the software has been removed by viewing the list of installed software in the Windows® Control
Panel.

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4 CONFIGURE THE USB PORT

The USB port uses IP network emulation to communicate with the device. A USB network driver is installed as part
of the EnerVista Flex distribution.
To enable communication, the network adapter associated with the USB connection must be configured to use the
same network IP range as the connected device. This can be configured by selecting, Control Panel>Network and
Internet>Network and Sharing Center, then click Change adapter settings. Double-click the GE RNDIS Device
Ethernet connection (associated with the USB driver), click the Properties button and select Internet Protocol
Version 4 (TCP/IP v4) from the list and click the Properties button.
The device’s USB IP and gateway addresses are given in the device HMI,
Setpoints>Device>Communications>USB.

Note:
The USB Ethernet device installed with EnerVista Flex will be named, GE RNDIS Device.

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5 ACCESS MANAGEMENT
User roles are used to control access to different modules within the EnerVista Flex software.
There are five default users provided within the EnerVista Flex software, one for each user role. The table below
describes the user roles, default usernames, and permission levels within the EnerVista Flex software. Use these
accounts as a starting point for your installation. Additional accounts can be created by logging in to the Admin or
UserAdmin account.
Default accounts for all but Guest have the initial password set to, Welcome123. Guest default password is.
Guest1234.

Note:
The names and email addresses associated with each account should be changed to reflect the actual user information, with
passwords changed on first login.

User Role Default Username* Permissible Actions

Administrator Admin All access, firmware upload.
Engineer Engg Everything except user management
Operator Oper Connect to online devices only
Guest Guest Project management, Open, Import, Download
Settings, Export
Device Records, All
IEC61850, open View
Cyber-Security UserAdmin User management only
User account information (other than the user password) can only be changed by users with Administrator or
Cyber-Security user roles.

Note:
Different account names and passwords are used to send/receive configuration files.

5.1 PASSWORD REQUIREMENTS

Passwords used for user authentication have the following requirements:
● 9 characters minimum
● Must include at least 3 of the following: uppercase, lowercase, numeric and special characters (@, !, #, {, etc).
● The password is encrypted and saved in the database

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6 LOGIN
The login screen of the EnerVista Flex software allows language selection of four languages: English, French,
German, and Spanish.
Select a language and enter a valid username and password to login.

Note:
Usernames and passwords, as well as user profiles are set by the system administrator. User Profile settings allow or block
access to different parts of the EnerVista Flex software.

After login, the Main Screen of EnerVista Flex opens

The main screen includes the following areas:
Software Name – GE EnerVista Flex
Welcome
This area can be used to create a new project or open an existing project. Previously viewed projects are listed so
they can be re-opened quickly, and sample projects which can be used and reamed are also included.
Modules
Used to Navigate to the Project View and to Quick connect a device.
Quick Connect
Used to quickly connect to a device.
User
This area includes software version information, user preferences, and user logout controls.
Details of each area on the main screen are in the following sections.

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7 USER SETTINGS
The User area on the main screen is described below:
From left to right, the options available are:
● Settings
● About
● User
● Window controls (minimize, maximize and close)

Settings

About

User

The Settings button provides access to the My Preferences Setting dialog box, with the following options:
● Login Settings
○ Keep logged in (ON/OFF)
● Appearance
○ Choose from the six colour scheme options
● Setting Preferences
○ Setting File Transfer--Edit communications settings for offline device
○ Poll Cycle Setting--Enable poll cycle

The About button shows the EnerVista Flex version and release dialog box.
The User button allows access to the Manage Role Based Access dialog box, with tools to configure, User
Accounts, User Groups and Roles.

7.1 EDIT MY PROFILE

Use the Edit My Profile menu to change your password, user profile picture, or the first and last name associated
with your account. Other changes to user accounts require Administrator or Cyber-Security access.
To change your password:
1. Click the edit icon to the right of the password field.
2. Enter a new password.
3. Confirm the new password by entering it in the second password field and click Save to save your changes.

Note:
Passwords must be a minimum of 9 characters including at least three of the following: uppercase, lowercase, numeric, and
special characters.

7.1.1 INFORMATION
Click the About button to determine the version of EnerVista Flex software currently in use. This information is
required should you need to contact GE customer support.
About

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7.2 LOGOUT
Click the Username/profile in the User area to access the logout controls.
If you have made any changes to the open project, you will be prompted to save your changes before logging out.
Click Yes to complete the logout process.
Once logged out, the EnerVista Flex login screen reopens.

Username/Profile

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8 QUICK CONNECT
Click the Quick Connect button to quickly connect to a device using USB or network connection—by entering and
selecting appropriate interface, network IP address. The model number and version info may be obtained from the
device by clicking the Read Model Number button.

Quick Connect

The Quick Connect dialog box:

Quick Connect x

Site Name IP Address

Device Name Slave Address

Description Port

Interface Model Number

Device Type Version Read Model Number

Cancel Connect
^ View Details
Time Detail
Once connected using Quick Connect, The Device name, model number, version and IP address are listed in the
Quick Connect pane. Mouseover the device entry in the Quick connect pane to update firmware and configure the
device.
The Firmware Update dialog box allows selection of a firmware file from a user defined file location accessible via
the PC running EnerVista Flex.
Clicking the configure device option, enter the device password for the appropriate role (this is not the Enervista
Flex role/password), and click the Connect button.
When connected, the following device specific second-level tab options are available:
● Profile
● Setting
● Logic
● Monitor
● Records
● IEC61850 Configuration
● User Configuration

For information about Profile, Setting, Logic and Records, refer to the Device Configuration section.

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8.1 DEVICE MONITOR

The device monitor menu ribbon contains the following items:
● Poll Status
● Commands

The poll status indicator shows a colour-coded device poll state.

The Commands button opens a Commands dialog box, allowing various commends to be sent to the device.
The Monitor Status pane may be docked and has five status category tabs at the bottom of the pane:
● Device Status
● Measurement
● Records
● Testing

● Virtual Inputs

Each of the Status pane tabs contains a filterable list of monitor items, with each selected item available as a tab
at the top of the main workspace pane, with the attributes for the currently selected item shown in the main
workspace. The path to the selected monitor item is shown at the bottom of the main workspace pane.

8.2 USER CONFIGURATION

The User Configuration pane allows device User type, Username, password and user rights to be modified and
saved to the connected device, as required.

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9 ERROR LIST
The error list button provides access to a filtered/searchable list of device errors. The Error List menu ribbon has
the following options:
● Error—Hides/unhides error items in the Error List workspace
● Warning—Hides/unhides warning items in the Error List workspace
● Info—Hides/unhides info items in the Error List workspace

The Error list may be pinned or minimised, as required.

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10 DEVICE CONFIGURATION
In order to configure a device using the EnerVista Flex software, a project must be created and opened with at
least one device added, or a device connected using Quick Connect.
Double-click the device icon in the Project Topology view to open the Device Profile.

Note:
It is good practice to download the CID file from the device and used as the base for configuration changes.

The top-level Device tab comprises second-level items:

● Profile
● Setting
● Logic
● Records
● IEC61850 Configuration

10.1 PROFILE CONFIGURATION

The Device profile tab provides device information and allows access to the device’s language setting.

10.2 DEVICE SETTING

The Device Setting tab provides access to set the device settings, with device setting menu ribbon items:
● Save
● Export

The Save button saves setting changes.

The Export button allows the setting data to be exported to XRIO, PDF, CSV and Excel file formats, with setting
group data selected/deselected as required.
In the Export Device Settings dialog box, the Copy Details button copies the file export process details to the PC’s
copy/paste buffer.

Note:
Hover over value fields for a menu tip showing the maximum, minimum and step values for each.

To alter device settings, navigate the Settings pane device tree to the desired setting name and double-click to
modify the required parameters in each case.
A tab for each selected setting allows access at the top of the setting parameter workspace.

Note:
The selected setting path is shown at the bottom of the parameter workspace area.

Send and Receive buttons are provided (bottom right of main workspace) to send and receive CID data to/from the
device.

Send

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Receive

10.3 ERROR LIST

An external PSL editor is opened when selecting the Device Logic tab. Logic may be created/edited and saved in
the tool as required.
Once closed, the main Logic workspace contains a list of the logic command lines in tabular form.
The Logic Editor may be reopened by selecting the Logic Editor item in the Logic menu ribbon.

Note:
For detailed instructions, refer to the PSL Editor section.

10.4 DISTURBANCERECORDS
The device disturbance records tab contains the following record menu ribbon items:
● Open
● Import
● Export
● Email (Share)
● Print (Share)
● Application Cache (Show Records)
○ show/hide application cache records
● Device Cache (Show Records)
○ show/hide device cache records
● Imported Files
○ show/hide imported cache records
● Delete
● Refresh

The main Records workspace contains a filtered list of available records, with any open records selectable as tabs
at the bottom of the workspace window.
Send and Receive buttons are provided (bottom right of main workspace) to send and receive CID data to/from the
device.

Send

Receive

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11 CREATE A NEW PROJECT

A project is needed in order to add devices (one or many) and begin configuring individual settings. In order to
create a project, do the following:
1. From the Main screen Welcome area (left side), click New Project.
2. Enter a Project Name and Description and click Create Project when done.
The Project window opens to the Topology View, which is empty until devices are added.
The Project management space can be used to configure an extended system, such as a substation or bay with
various substation elements and devices if desired.
Project View is selectable on the top row of tab items, this allows projects to be viewed.
Project Name is selectable on the top row. Is the user defined project name.
Topology View is selectable on the second row. This view is empty until devices are added to the workspace.
The next step is to add one or more devices to the project, by dragging and dropping a device into the workspace
—the central region of the screen.

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12 MANAGE PROJECTS
Select the Open Project, New Project, Recent Project or Sample item in the Welcome pane or the Project item in
the Modules pane to manage Projects. The project may also be managed at any time in the project views, by
selecting the top-level Project tab.

Project tab
The Project page comprises a menu ribbon with:
● My Computer
● Import
● Export
● Delete
● Copy to Server
● Configure
Projects may be created, opened and closed using the vertical menu ribbon on the left, and projects may be
sorted, filtered, searched, and selected via a project list in the main project management workspace.
Projects may be opened by double-clicking the desired project item listed.

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13 PROJECT CONFIGURATION

13.1 TOPOLOGY VIEW

The Topology View comprises a Toolbox window containing the substation elements and devices, and a Topology
window.
Toolbox window elements and devices may be dragged into the project workspace window (main screen area).
Right-clicking in the workspace window, or on selected substation elements or IEDs provides more options.
Topology window selections may be added, Imported, Exported, Edited and deleted as required, using the
appropriate buttons.
The Topology View menu ribbon has options to:
● Save
● Import (CID or SCD)
● Export (CID or SCD)
● Send
● Receive
● Connect
● Disconnect
● Sync
● Select Offline and Online modes
● Compare topology elements

The moveable (and dockable either left or right) Toolbox pane contains Substation and IED devices, which may be
dragged to the main Topology workspace as required.
The moveable (and dockable either left or right) Topology pane contains the project items in the main Topology
workspace in a hierarchical tree view. The Topology pane also has option to:
● Add Substation
● Add Voltage
● Add Bay
● Add Device
● Import (CID)
● Export (CID)
● Edit (project /device/element name and description)
● Delete (Substation, Voltage and Bay items)

Topology pane project items are colour coded to indicate device/element, with the colour code key at the bottom
of the Topology pane.

13.2 IEC1850 CONFIGURATION

The IEC61850 Configuration view comprises a Publisher pane, a Dataset pane a Control Block pane and a
Subscriber pane.
The IEC61850 Configuration menu ribbon has options to:
● Open
● Save
● Manage Data Model (connected device only)
● Measurement Setting (connected device only)

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● Control Setting (connected device only)

● Add Dataset
● Edit Dataset
● Delete Dataset
● Hide/Unhide Dataset
● Add GOOSE Control Block
● Edit GOOSE Control Block
● Delete GOOSE Control Block
● Hide/Unhide GOOSE Control Block
● Add Report Control Block
● Edit Report Control Block
● Delete Report Control Block
● Hide/Unhide Report Control Block
● Add Sample Value Block
● Edit Sample Value Block
● Delete Sample Value Block
● Hide/Unhide Sample Value Block
● Edit Subscribe Parameter
● Unmap (Subscribe)
● Unsubscribe All
● Graphical View (Summary View)
● Table View (Summary View)
● Hide/Unhide Connections
● User friendly name/EIC Name

Added Datasets appear as blocks within the Dataset pane—Publisher items may then be dragged and dropped
into the blocks as required. Added GOOSE, Report and Sample Value Control Blocks appear in the Control Block
pane—Publisher items from Dataset blocks may be connected to required GOOSE, Report and Sample Value blocks
as required.
Dataset connected Control Block items may be connected to appropriate Subscriber items.

Note:
Connected items are shown using arrowed lines, with control block to Subscriber lines selectable to Edit, Unmap and
Unsubscribe, and Publisher to Dataset lines selectable to Unsubscribe. Dataset items may be removed within Dataset blocks,
by selecting the  for each Publisher item.

13.3 ADD A NEW DEVICE

To add a new device to a project, follow these steps:
1. From the project topology view, click to expand the IED Devices menu in the toolbox on the left.
2. Drag and drop a device from the toolbox to project area (the central grid).
When the new device is dropped, an Add Device window opens.
3. Enter a Name and Description for the device.
4. Select Model Type corresponding to the device Cortec.
5. To select the required device Cortec, then select each element in turn and choose the required option for
each digit from the choices in the corresponding list. Ensure that this matches the order code of the actual
device.

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Elements added to the project appear in the right-hand Topology panel, in a tree structure. The next step is to
download the device CID file as a basis for configuring the device.

Note:
The device Name field only accepts alphanumeric characters. Do not use spaces or other special characters other than
underscore _.

13.4 EDIT A DEVICE

1. Right-click the corresponding device graphic in the Topology workspace, or the required device in the
Topology pane tree and select Edit or select Edit in the Topology Pane menu ribbon.
2. Edit the name and description for the device.
3. Select Model Type corresponding to the device Cortec.
To select the required device Cortec, then select each element in turn and choose the required option for each digit
from the choices in the corresponding list. Ensure that this matches the order code of the actual device.

Note:
The device Name field only accepts alphanumeric characters. Do not use spaces or other special characters.

13.5 RECEIVE CID FROM DEVICE

After creating a New Device within the EnerVista Flex software, you can download the CID file from the physical
device.
Only the Engineer and Administrator user roles can access the Send/Receive CID functionality in the EnerVista Flex
software.

Note:
Important: Ensure the Device Name is correct.

1. Double-click the device icon in the Project Topology view to open the Device Profile.
2. Click the Receive CID File button located in the bottom right corner of the Device Profile window.
3. Click Yes to confirm that that unsaved configuration changes made in the offline file can be overwritten.
4. In the Receive CID File – Device Information window, enter the Ethernet IP Address of the device and click
Continue.
5. In the Receive CID File – User Authentication window, enter the User ID and Password.
6. Once the status bar indicates the CID file transfer is complete, click Continue.
7. Next the Schema is validated. Click Finish to complete the CID file download process.
8. 8. Click OK to acknowledge the completed CID file transfer and return to the device view.

Note:
Only accounts with the Engineer or Administrator user roles can access the Send/Receive CID functionality in the EnerVista
Flex software.

Receive CID File

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13.6 EDIT DEVICE CONFIGURATION SETTINGS

Note:
It is good practice to download the CID file from the device and use it as the basis for configuration changes.

1. Double-click the Device button, in the Project Topology view to open the Device Profile.
2. Click Setting on the device menu bar.
The Setting tab opens showing the configuration options.

13.7 SEND CID TO DEVICE

Once configuration changes are complete, update the P40 ENHANCED configuration by sending the CID file back
to the device.

Note:
It is good practice to download the CID file from the device and use it as the basis for configuration changes.

1. Double-click the device icon in the Project Topology view to open the Device Profile.
2. Click the Send CID File button located in the bottom right corner of the Device Profile window.
3. Click Yes to confirm that that unsaved configuration changes made in the offline file can be overwritten.
4. In the Send CID File – Device Information window, enter the Ethernet IP Address of the device and click
Continue.
5. Next the Schema is validated. Click Continue to initiate the CID file upload process.
6. In the Send CID File – User Authentication window, enter the User ID and Password.
7. The status bar indicates when the file transfer is complete. Click Finish to acknowledge the completed CID
file transfer and return to the device view.
8. Once the CID file has been successfully sent, the updated configuration can be confirmed by checking the
Web Interface.

Note:
Your user account must have the appropriate user role assigned (Administrator or Engineer) in order to send and receive CID
files. Account settings can be changed by the Administrator.

13.8 SET DEVICE LANGUAGE

Select the language for the device HMI, using the Device Language drop-down in the Device>Profile tab.
The device language may also be modified shown? in the Device>Settings>Front Panel>Language

Note:
EnerVista Flex language is selectable at login. It may be different to the device language, as desired.

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14 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 internal logic. This is done by combining the IED's digital inputs with internally
generated digital signals using logic gates and timers, then mapping the resultant signals to the IED's digital
outputs and LEDs.
The Programmable Scheme Logic (PSL) Editor allows you to create and edit scheme logic diagrams to suit your
own particular application.

14.1 LOADING SCHEMES FROM FILES

The product is shipped with default scheme files. These can be used as a starting point for changes to a scheme.
To create a new blank scheme, select File then New then 'Blank scheme... to open the default file for the
appropriate IED. This deletes the diagram components from the default file to leave an empty diagram but with
the correct configuration information loaded.

14.2 PSL EDITOR TOOLBAR

There are a number of toolbars available to help with navigating and editing the PSL.

Toolbar Description
Standard tools: For file management and printing.

Alignment tools: To snap logic elements into horizontally or vertically

aligned groupings.

Drawing tools : To add text comments and other annotations, for

easier reading of PSL schemes.

Nudge tools: To move logic elements.

Rotation tools: Tools to spin, mirror and flip.

Structure tools: To change the stacking order of logic components.

Zoom and pan tools: For scaling the displayed screen size, viewing the
entire PSL, or zooming to a selection.

14.2.1 LOGIC SYMBOLS

The logic symbol toolbar provides icons to place each type of logic element into the scheme diagram. Not all
elements are available in all devices. Icons are only displayed for elements available in the selected device.
Symbol Function Explanation
Link Create a link between two logic symbols.

Input Signal Create an input signal.

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Symbol Function Explanation

Output Signal Create an output signal.

Contact Conditioner Create a contact conditioner.

Timer Create a timer.

AND Gate Create an AND Gate.

OR Gate Create an OR Gate.

Programmable Gate Create a programmable gate.

SR Latch Create an SR latch

14.3 LOGIC SIGNAL PROPERTIES

1. Use the logic toolbar to select logic signals. This is enabled by default but to hide or show it, select View
then Logic Toolbar.
2. Zoom in or out of a logic diagram using the toolbar icon or select View then Zoom Percent.
3. Right-click any logic signal and a context-sensitive menu appears.

Certain logic elements show the Properties option. If you select this, a Component Properties window appears.
The contents of this window and the signals listed will vary according to the logic symbol selected. The actual DDB
numbers are dependent on the model.

14.3.1 LINK PROPERTIES

Links form the logical link between the output of a signal, gate or condition and the input to any element. Any link
connected to the input of a gate can be inverted. To do this:
1. Right-click the input
2. Select Properties…. The Link Properties window appears.
3. Check the box to invert the link. Or uncheck for a non-inverted link
An inverted link is shown with a small circle on the input to a gate. A link must be connected to the input of a gate
to be inverted.
Links can only be started from the output of a signal, gate, or conditioner, and must end at an input to any
element.
Signals can only be an input or an output. To follow the convention for gates and conditioners, input signals are
connected from the left and output signals to the right. The Editor automatically enforces this convention.
A link is refused for the following reasons:
● There has been an attempt to connect to a signal that is already driven. The reason for the refusal may not
be obvious because the signal symbol may appear elsewhere in the diagram. In this case you can right-click
the link and select Highlight to find the other signal. Click anywhere on the diagram to disable the highlight.
● An attempt has been made to repeat a link between two symbols. The reason for the refusal may not be
obvious because the existing link may be represented elsewhere in the diagram.

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14.3.2 INPUT SIGNAL PROPERTIES

NIC Link Fail #
DDB #
E02031

IED logic functions provide logic output signals that can be used for programming in PSL. Depending on the IED
functionality, operation of an active IED function drives an associated DDB signal in PSL.

14.3.3 OUTPUT SIGNAL PROPERTIES

Inhibit VTS
DDB #
E02032

Logic functions provide logic input signals that can be used for programming in PSL. Depending on the
functionality of the output relay, when the output signal is activated, it drives an associated DDB signal in PSL. This
causes an associated response to the function of the output relay.

14.3.4 COUNTER PROPERTIES

Each PSL counter has an increment (+), a decrement (-) and Reset (R) input and a count output (Q) which goes high
when the count threshold value is exceeded.
To set counter properties,
1. From the Trigger Type tick list, choose either, Rising edge triggered or Falling edge triggered.
2. Set the Trigger threshold value, if required.
3. Set the Invert output tick box, if required.
4. From the Available counters list, choose the counter required. Note: The counter number will auto-
increment when adding counters.
5. Click OK.

14.3.5 TIMER PROPERTIES

Each timer can be selected for pick-up, drop-off, dwell, pulse or pick-up/drop-off operation.
To set timer properties,
1. From the Timer Mode tick list, choose the mode.
2. Set the Pick-up Value (in milliseconds), if required.
3. Set the Drop-off Value (in milliseconds), if required.
4. From the Available timers list (not in all products), choose the timer required. Note: The timer number will
auto-increment when adding timers.
5. Click OK.

14.3.6 GATE PROPERTIES

A gate can be an AND, OR, or programmable gate.
● An AND Gate requires that all inputs are TRUE for the output to be TRUE.
● An OR Gate requires that one or more input is TRUE for the output to be TRUE.
● A Programmable Gate requires that the number of inputs that are TRUE is equal to or greater than its
Inputs to Trigger setting for the output to be TRUE.

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To set gate properties,

1. Select the gate type: AND Gate, OR Gate, or Programmable Gate.
2. If you select Programmable Gate, set the number of Inputs to Trigger.
3. If you want the output of the gate to be inverted, check the Invert Output check box. An inverted output
appears as a "bubble" on the gate output.
4. Click OK.

14.3.7 SR PROGRAMMABLE GATE PROPERTIES

A Programmable SR gate can be selected to operate with the following three latch properties:
Q0 (Previous
Set Reset Q1 Set Dominant Q1 Reset Dominant Q1 No Dominance
Output State)
0 0 0 0 0 0
0 0 1 1 1 1
0 1 1 0 0 0
0 1 0 0 0 0
1 1 0 1 0 0
1 1 1 1 0 1
1 0 1 1 1 1
1 0 0 1 1 1

Q0 is the previous output state of the latch before the inputs change. Q1 is the output of the latch after the inputs
change.
The Set dominant latch ignores the Reset if the Set is on.
The Reset Dominant latch ignores the Set if the Reset is on.
When both Set and Reset are on, the output of the non-dominant latch depends on its previous output Q0.
Therefore if Set and Reset are energised simultaneously, the output state does not change.

Note:
Use a set or reset dominant latch. Do not use a non-dominant latch unless this type of operation is required.

SR latch properties
In the Component Properties dialog, you can select S-R latches as Standard (no input dominant), Set input
dominant or Reset input dominant.
If you want the output to be inverted, check the Invert Output check box. An inverted output appears as a
"bubble" on the gate output.

P14DEnh-TM-EN-1.1 467
Chapter 24 - EnerVista Flex P14D

468 P14DEnh-TM-EN-1.1
 APPENDIX A

ORDERING OPTIONS
Appendix A - Ordering Options P14D

P14DEnh-TM-EN-1.1
P14D Appendix A - Ordering Options

Variants Order Number

1 - 4 5 6 7 8 9 10 11 12-13 14 15
Model Type (P40 Agile Enhanced)
Feeder Management Protection - Directional P14D

Application Package
Base B
Base + Power prot. (32) + Autoreclose (79) + Check Sync (25) + Rate of change of freq. (df/dt) + Fault locator (21FL) L

Current / Voltage Types

Standard Earth CT 1
Sensitive Earth Fault CT 2

Hardware Options
EIA RS485 serial comms – with RJ45 Engineering Port (only) 20TE 2
EIA RS485 serial comms and station bus Ethernet - Single channel RJ45 Copper 20TE 5

Binary Input / Output Options Case

5 inputs (2 for Trip Circuit Supervision) + 7 outputs + 1 watchdog 20TE B
11 inputs (2 for Trip Circuit Supervision) + 11 outputs + 1 watchdog 20TE D

Communication protocol / Cybersecurity

DNP3.0 / Modbus / IEC 60870-5-103 2
IEC 61850 / DNP3.0 / Modbus / IEC 60870-5-103 3
IEC 61850 / DNP3.0 / Modbus / IEC 60870-5-103 with advanced cybersecurity Level 2 4

Case
20TE Flush (4 inch width) B
Software only 0

Language
(English (UK) / English (US) / French / Spanish) 0

Software Version
Initial release 01

Customisation / Regionalisation
Default 0
Customer specific A

Hardware design suffix

Enhanced model E

P14DEnh-TM-EN-1.1 A1
Appendix A - Ordering Options P14D

A2 P14DEnh-TM-EN-1.1
 APPENDIX B

SETTINGS AND SIGNALS

Appendix B - Settings and Signals P14D

Tables, containing a full list of settings for each model, are provided in a separate Excel file attached as an
embedded resource. To access the spreadsheet file, click on the button below.

Note:
An Open File dialogue box may open with a warning message about potential harm from programs , macros or viruses. The
file supplied does not contain any harmful content, and may be safely opened.

Settings & Signals

P14DEnh-TM-EN-1.1
 APPENDIX C

WIRING DIAGRAMS
Appendix C - Wiring Diagrams P14D

P14DEnh-TM-EN-1.1
 20 19 18 17 16 15 14 13 12 11
REVISION HISTORY
REV ITR ECO # DESCRIPTION DD/MM/YY APPROVED
0 T2019037684 FIRST ISSUE 14-03-19 J.A.
1 T2019047761 FIRST REVISION 08-04-19 J.A.
A 2 T2019098259 SECOND REVISION 01-10-19 J.A.
DIRECTION OF FORWARD CURRENT FLOW
3 T2019108337 THIRD REVISION 16-10-19 J.A.
P2 P1 A 2 T2019118511 FOURTH REVISION 21-11-19 A.Z.
A
FIG. 1 A 3 T2020048981 GENERAL REVISION 22-04-20 A.Z.
S2 S1
C B B
E PHASE ROTATION C E
A B C
C B A
A.C./D.C. SUPPLY

-/N +/L
N
A7 A2 A1
n 1 TX+
V CHECK 2 TX-
SYNC 3 RX+ ETH1 (RJ45)
c b a A8 4 10 BASE-T/
B1 5 100 BASE-TX
6 RX-
IA B2
N 7
B3 8
n
IB B4

a b c B5
IC B6
D B
D
B7 COM1
+
IN B8 A EIA RS485/IRIG-B
- COMMUNICATIONS
GND
VA A3

VB A4 P14D
VC A5
TCS +
A6
ETHERNET
OPTO 1 +
D1
D2
OPTO 2 + D9
OPTO ISOLATED
BINARY INPUTS D10 RL1
D3
OPTO 3 +
C D11 C
D4 RL2
OPTO 1,2,3 - D12
+ D13
D5
OPTO 4 D6 D14 RL3
OPTO ISOLATED -
TCS INPUTS + D15
D7 RELAY OUTPUT
OPTO 5 D16 RL4
D8 CONTACTS
- D17
D18 RL5

OPTO 6 + D19
C1 RL6
D20
C2
OPTO 7 + D21
D22 RL7
C3
OPTO 8 +
D23
C4
OPTIONAL OPTO 6,7,8 - D24 RELAY FAIL
B OPTO ISOLATED
B
OPTO 9 +
BINARY INPUTS C5
C6 C9
OPTO 10 +
C10 RL9
C7 C11
OPTO 11 +
C12 RL10 OPTIONAL
C8
OPTO 9,10,11 - C13 RELAY OUTPUT
RL11 CONTACTS
C14
C15
C16 RL12

UNLESS OTHERWISE SPECIFIED NAME DD/MM/YY

DIMENSIONS ARE (TBS) Grid Solutions
CASE EARTH DRAWN J.A. 14-03-19
INTERPRET DIM TOLERANCE
GE Power Management
A CONNECTION AV. PINOA 10, 48170 ZAMUDIO (SPAIN) A
PER ASME Y14.5/ISO BS8888 CHECKED

TOLERANCE MM: TOLERANCE INCH: APPROVED TITLE: STATUS:

P14D
1 PL +/- 1 PL +/- .X MATERIAL: DIRECTIONAL PHASE
2 PL +/- 2 PL +/- .XX OVERCURRENT AND EARTH APPROVED
ANGLE +/- 3 PL +/- .XXX FAULT WITH TCS & ETHERNET
GE PROPRIETARY AND CONFIDENTIAL INFORMATION ANGLE +/- 0.5 DEG FINISH: 20TE CASE
This document is the property of General Electric Company ("GE") and contains proprietary information of GE. This document is loaned on the express condition that neither it nor the information contained therein THIRD ANGLE CTQ (Critical to Quality) SIZE: DWG.NO. REV. ITR.
shall be disclosed to others without the express written consent of GE, and that the information shall be used by the recipient only as approved expressly by GE. This document shall be returned to GE upon its request. PROJECTION
This document may be subject to certain restrictions under U.S. export control laws and regulations. © General Electric Company, GE CONFIDENTIAL UNPUBLISHED WORK. MAJOR INSPECTION NEXT STAGE: 2 C C154201 A 3
TBD TBD
SCALE: PART NUMBER: C1542P1 SHEET 1

20 19 18 17 16 15 14 13 12 11
 20 19 18 17 16 15 14 13 12 11
REVISION HISTORY
REV ITR ECO # DESCRIPTION DD/MM/YY APPROVED
A 2 T2020048981 FIRST REVISION 22/04/20 A.Z.

A DIRECTION OF FORWARD CURRENT FLOW

P2 P1
A
FIG. 4 S2 S1
C B B
E PHASE ROTATION C E
C B A
A.C./D.C. SUPPLY

-/N +/L
N
A7 A2 A1
n 1 TX+
V CHECK 2 TX-
SYNC 3 RX+ ETH1 (RJ45)
c b a A8 4 10 BASE-T/
B1 5 100 BASE-TX
6 RX-
IA B2
7
B3 8
IB B4

B5
IC B6
D D
B7 B
+ COM1
IN B8 A EIA RS485/IRIG-B
- COMMUNICATIONS
GND
VA A3

VB A4 P14D
VC A5
TCS +
N A6
ETHERNET
OPTO 1 +
D1
D2
OPTO 2 + D9
OPTO ISOLATED
BINARY INPUTS D10 RL1
D3
OPTO 3 +
C D11 C
D4 RL2
OPTO 1,2,3 - D12
+ D13
D5
OPTO 4 D6 D14 RL3
OPTO ISOLATED -
TCS INPUTS + D15
D7 RELAY OUTPUT
OPTO 5 D16 RL4
D8 CONTACTS
- D17
D18 RL5

OPTO 6 + D19
C1 RL6
D20
C2
OPTO 7 + D21
D22 RL7
C3
OPTO 8 +
D23
C4
OPTIONAL OPTO 6,7,8 - D24 RELAY FAIL
B OPTO ISOLATED
B
OPTO 9 +
BINARY INPUTS C5
C6 C9
OPTO 10 +
C10 RL9
C7 C11
OPTO 11 +
C12 RL10 OPTIONAL
C8
OPTO 9,10,11 - C13 RELAY OUTPUT
RL11 CONTACTS
C14
C15
C16 RL12

UNLESS OTHERWISE SPECIFIED NAME DD/MM/YY

DIMENSIONS ARE (TBS) Grid Solutions
CASE EARTH DRAWN A.Z. 22/04/20
INTERPRET DIM TOLERANCE
GE Power Management
A CONNECTION AV. PINOA 10, 48170 ZAMUDIO (SPAIN) A
PER ASME Y14.5/ISO BS8888 CHECKED

TOLERANCE MM: TOLERANCE INCH: APPROVED TITLE: STATUS:

P14D
1 PL +/- 1 PL +/- .X MATERIAL: DIRECTIONAL PHASE
2 PL +/- 2 PL +/- .XX OVERCURRENT AND EARTH APPROVED
ANGLE +/- 3 PL +/- .XXX FAULT WITH TCS & ETHERNET
GE PROPRIETARY AND CONFIDENTIAL INFORMATION ANGLE +/- 0.5 DEG FINISH: 20TE CASE
This document is the property of General Electric Company ("GE") and contains proprietary information of GE. This document is loaned on the express condition that neither it nor the information contained therein THIRD ANGLE CTQ (Critical to Quality) SIZE: DWG.NO. REV. ITR.
shall be disclosed to others without the express written consent of GE, and that the information shall be used by the recipient only as approved expressly by GE. This document shall be returned to GE upon its request. PROJECTION
This document may be subject to certain restrictions under U.S. export control laws and regulations. © General Electric Company, GE CONFIDENTIAL UNPUBLISHED WORK. MAJOR INSPECTION NEXT STAGE: 5 C C154204 A 2
TBD TBD
SCALE: PART NUMBER: C1542P4 SHEET 4

20 19 18 17 16 15 14 13 12 11
Imagination at work

Grid Solutions
St Leonards Building
Redhill Business Park
Stafford, ST16 1WT, UK
+44 (0) 1785 250 070
contact.centre@ge.com

© 2020 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.

P14DEnh-TM-EN-1.1