Rec 670 руководство по эксплуатации

Relion 670 series

Bay control REC670 2.0 IEC Application manual

Document ID: 1MRK 511 310-UEN Issued: July 2016

Revision: B Product version: 2.0

Copyright 2014 ABB. All rights reserved

Copyright

This document and parts thereof must not be reproduced or copied without written permission from ABB, and the contents thereof must not be imparted to a third party, nor used for any unauthorized purpose.

The software and hardware described in this document is furnished under a license and may be used or disclosed only in accordance with the terms of such license.

This product includes software developed by the OpenSSL Project for use in the OpenSSL Toolkit. (http://www.openssl.org/)

This product includes cryptographic software written/developed by: Eric Young (eay@cryptsoft.com) and Tim Hudson (tjh@cryptsoft.com).

Trademarks ABB and Relion are registered trademarks of the ABB Group. All other brand or product names mentioned in this document may be trademarks or registered trademarks of their respective holders.

Warranty Please inquire about the terms of warranty from your nearest ABB representative.

Disclaimer

The data, examples and diagrams in this manual are included solely for the concept or product description and are not to be deemed as a statement of guaranteed properties. All persons responsible for applying the equipment addressed in this manual must satisfy themselves that each intended application is suitable and acceptable, including that any applicable safety or other operational requirements are complied with. In particular, any risks in applications where a system failure and/or product failure would create a risk for harm to property or persons (including but not limited to personal injuries or death) shall be the sole responsibility of the person or entity applying the equipment, and those so responsible are hereby requested to ensure that all measures are taken to exclude or mitigate such risks.

This document has been carefully checked by ABB but deviations cannot be completely ruled out. In case any errors are detected, the reader is kindly requested to notify the manufacturer. Other than under explicit contractual commitments, in no event shall ABB be responsible or liable for any loss or damage resulting from the use of this manual or the application of the equipment.

Conformity

This product complies with the directive of the Council of the European Communities on the approximation of the laws of the Member States relating to electromagnetic compatibility (EMC Directive 2004/108/EC) and concerning electrical equipment for use within specified voltage limits (Low-voltage directive 2006/95/EC). This conformity is the result of tests conducted by ABB in accordance with the product standard EN 60255-26 for the EMC directive, and with the product standards EN 60255-1 and EN 60255-27 for the low voltage directive. The product is designed in accordance with the international standards of the IEC 60255 series.

Table of contents

Section 1 Introduction……………………………………………………………19 This manual………………………………………………………………………….. 19 Intended audience…………………………………………………………………. 19 Product documentation……………………………………………………………20

Product documentation set………………………………………………….20 Dokumentennderungsverzeichnis……………………………………… 21 Related documents…………………………………………………………….22

Document symbols and conventions…………………………………………22 Symbols……………………………………………………………………………22 Document conventions……………………………………………………….23 IEC 61850 edition 1 / edition 2 mapping………………………………..24

Section 2 Application…………………………………………………………….33 General IED application…………………………………………………………..33 Main protection functions…………………………………………………………34 Back-up protection functions…………………………………………………… 34 Control and monitoring functions………………………………………………36 Communication………………………………………………………………………40 Basic IED functions……………………………………………………………….. 43

Section 3 Configuration…………………………………………………………45 Introduction……………………………………………………………………………45 Description of configuration REC670……………………………………….. 46

Introduction……………………………………………………………………….46 Description of configuration A30…………………………………….. 46 Description of configuration B30…………………………………….. 47 Description of configuration C30…………………………………….. 49

Section 4 Analog inputs…………………………………………………………53 Introduction……………………………………………………………………………53 Setting guidelines………………………………………………………………….. 53

Setting of the phase reference channel…………………………………53 Example……………………………………………………………………… 54

Setting of current channels………………………………………………….54 Example 1…………………………………………………………………… 55 Example 2…………………………………………………………………… 55 Example 3…………………………………………………………………… 56 Examples on how to connect, configure and set CT inputs for most commonly used CT connections………………………… 60

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Example on how to connect a star connected three-phase CT set to the IED…………………………………………………………..61 Example how to connect delta connected three-phase CT set to the IED………………………………………………………………..66 Example how to connect single-phase CT to the IED………… 69

Setting of voltage channels………………………………………………… 71 Example……………………………………………………………………… 71 Examples how to connect, configure and set VT inputs for most commonly used VT connections………………………………71 Examples on how to connect a three phase-to-earth connected VT to the IED……………………………………………….. 72 Example on how to connect a phase-to-phase connected VT to the IED………………………………………………………………..74 Example on how to connect an open delta VT to the IED for high impedance earthed or unearthed netwoeks………….. 76 Example how to connect the open delta VT to the IED for low impedance earthed or solidly earthed power systems…..79 Example on how to connect a neutral point VT to the IED…..80

Section 5 Local HMI…………………………………………………………….. 83 Display………………………………………………………………………………….84 LEDs…………………………………………………………………………………….86 Keypad………………………………………………………………………………… 86 Local HMI functionality…………………………………………………………… 88

Protection and alarm indication…………………………………………… 88 Parameter management …………………………………………………….89 Front communication………………………………………………………….90

Section 6 Differential protection…………………………………………….. 91 1Ph High impedance differential protection HZPDIF …………………..91

Identification…………………………………………………………………….. 91 Application………………………………………………………………………..91

The basics of the high impedance principle……………………… 93 Connection examples for high impedance differential protection………………………………………………………………………….99

Connections for three-phase high impedance differential protection……………………………………………………………………..99 Connections for 1Ph High impedance differential protection HZPDIF……………………………………………………….100

Setting guidelines……………………………………………………………. 101 Configuration……………………………………………………………… 101 Settings of protection function………………………………………. 102 T-feeder protection……………………………………………………… 102 Tertiary reactor protection……………………………………………. 105 Alarm level operation……………………………………………………108

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Section 7 Current protection…………………………………………………109 Instantaneous phase overcurrent protection 3-phase output PHPIOC ……………………………………………………………………………..109

Identification…………………………………………………………………… 109 Application………………………………………………………………………109 Setting guidelines……………………………………………………………. 110

Meshed network without parallel line…………………………….. 110 Meshed network with parallel line…………………………………. 112

Four step phase overcurrent protection 3-phase output OC4PTOC …………………………………………………………………………. 114

Identification…………………………………………………………………… 114 Application………………………………………………………………………114 Setting guidelines……………………………………………………………. 115

Settings for each step…………………………………………………..117 2nd harmonic restrain…………………………………………………..120

Instantaneous residual overcurrent protection EFPIOC ……………. 126 Identification…………………………………………………………………… 126 Application………………………………………………………………………126 Setting guidelines……………………………………………………………. 126

Four step residual overcurrent protection, (Zero sequence or negative sequence directionality) EF4PTOC ……………………………129

Identification…………………………………………………………………… 129 Application………………………………………………………………………129 Setting guidelines……………………………………………………………. 131

Settings for each step (x = 1, 2, 3 and 4)……………………….. 131 Common settings for all steps………………………………………. 133 2nd harmonic restrain…………………………………………………..135 Parallel transformer inrush current logic………………………….135 Switch onto fault logic…………………………………………………..136 Line application example………………………………………………137

Four step directional negative phase sequence overcurrent protection NS4PTOC ……………………………………………………………142

Identification…………………………………………………………………… 143 Application………………………………………………………………………143 Setting guidelines……………………………………………………………. 144

Settings for each step ………………………………………………….145 Common settings for all steps………………………………………. 148

Sensitive directional residual overcurrent and power protection SDEPSDE …………………………………………………………………………. 149

Identification…………………………………………………………………… 150 Application………………………………………………………………………150 Setting guidelines……………………………………………………………. 151

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Thermal overload protection, one time constant, Celsius/ Fahrenheit LCPTTR/LFPTTR…………………………………………………159

Identification…………………………………………………………………… 160 Application………………………………………………………………………160 Setting guideline………………………………………………………………160

Thermal overload protection, two time constants TRPTTR ………..161 Identification…………………………………………………………………… 162 Application………………………………………………………………………162 Setting guideline………………………………………………………………163

Breaker failure protection 3-phase activation and output CCRBRF 165 Identification…………………………………………………………………… 165 Application………………………………………………………………………165 Setting guidelines……………………………………………………………. 166

Stub protection STBPTOC …………………………………………………… 169 Identification…………………………………………………………………… 169 Application………………………………………………………………………169 Setting guidelines……………………………………………………………. 170

Pole discordance protection CCPDSC……………………………………. 171 Identification…………………………………………………………………… 171 Application………………………………………………………………………171 Setting guidelines……………………………………………………………. 171

Directional underpower protection GUPPDUP…………………………. 172 Identification…………………………………………………………………… 172 Application………………………………………………………………………172 Setting guidelines……………………………………………………………. 174

Directional overpower protection GOPPDOP …………………………..178 Identification…………………………………………………………………… 178 Application………………………………………………………………………178 Setting guidelines……………………………………………………………. 180

Broken conductor check BRCPTOC ……………………………………… 184 Identification…………………………………………………………………… 184 Application………………………………………………………………………184 Setting guidelines……………………………………………………………. 184

Capacitor bank protection CBPGAPC…………………………………….. 185 Identification…………………………………………………………………… 185 Application………………………………………………………………………185

SCB protection…………………………………………………………… 187 Setting guidelines……………………………………………………………. 189

Restrike detection………………………………………………………..191 Voltage-restrained time overcurrent protection VRPVOC………….. 191

Identification…………………………………………………………………… 191 Application………………………………………………………………………192

Base quantities……………………………………………………………192

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Application possibilities……………………………………………….. 193 Undervoltage seal-in…………………………………………………… 193

Setting guidelines……………………………………………………………. 194 Explanation of the setting parameters…………………………….194 Voltage-restrained overcurrent protection for generator and step-up transformer………………………………………………. 195 Overcurrent protection with undervoltage seal-in……………..195

Section 8 Voltage protection……………………………………………….. 197 Two step undervoltage protection UV2PTUV …………………………..197

Identification…………………………………………………………………… 197 Application………………………………………………………………………197 Setting guidelines……………………………………………………………. 198

Equipment protection, such as for motors and generators…198 Disconnected equipment detection……………………………….. 198 Power supply quality ………………………………………………….. 198 Voltage instability mitigation…………………………………………. 198 Backup protection for power system faults………………………198 Settings for Two step undervoltage protection………………… 199

Two step overvoltage protection OV2PTOV …………………………….201 Identification…………………………………………………………………… 201 Application………………………………………………………………………201 Setting guidelines……………………………………………………………. 202

Equipment protection, such as for motors, generators, reactors and transformers……………………………………………. 202 Equipment protection, capacitors………………………………….. 202 Power supply quality…………………………………………………… 202 High impedance earthed systems…………………………………. 203 The following settings can be done for the two step overvoltage protection…………………………………………………. 203

Two step residual overvoltage protection ROV2PTOV …………….. 205 Identification…………………………………………………………………… 205 Application………………………………………………………………………205 Setting guidelines……………………………………………………………. 205

Equipment protection, such as for motors, generators, reactors and transformers……………………………………………. 206 Equipment protection, capacitors………………………………….. 206 Power supply quality…………………………………………………… 206 High impedance earthed systems…………………………………. 206 Direct earthed system…………………………………………………. 207 Settings for Two step residual overvoltage protection……….208

Voltage differential protection VDCPTOV ………………………………..210 Identification…………………………………………………………………… 210 Application………………………………………………………………………210

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Setting guidelines……………………………………………………………. 212 Loss of voltage check LOVPTUV ………………………………………….. 213

Identification…………………………………………………………………… 213 Application………………………………………………………………………214 Setting guidelines……………………………………………………………. 214

Advanced users settings……………………………………………… 214

Section 9 Frequency protection…………………………………………….215 Underfrequency protection SAPTUF ……………………………………… 215

Identification…………………………………………………………………… 215 Application………………………………………………………………………215 Setting guidelines……………………………………………………………. 215

Overfrequency protection SAPTOF ………………………………………..216 Identification…………………………………………………………………… 216 Application………………………………………………………………………217 Setting guidelines……………………………………………………………. 217

Rate-of-change frequency protection SAPFRC ………………………..218 Identification…………………………………………………………………… 218 Application………………………………………………………………………218 Setting guidelines……………………………………………………………. 218

Frequency time accumulation protection function FTAQFVR…….. 219 Identification…………………………………………………………………… 219 Application………………………………………………………………………219 Setting guidelines……………………………………………………………. 221

Section 10 Multipurpose protection…………………………………………223 General current and voltage protection CVGAPC…………………….. 223

Identification…………………………………………………………………… 223 Application………………………………………………………………………223

Current and voltage selection for CVGAPC function…………224 Base quantities for CVGAPC function…………………………….226 Application possibilities……………………………………………….. 227 Inadvertent generator energization……………………………….. 228

Setting guidelines……………………………………………………………. 229 Directional negative sequence overcurrent protection……… 229 Negative sequence overcurrent protection………………………231 Generator stator overload protection in accordance with IEC or ANSI standards………………………………………………… 233 Open phase protection for transformer, lines or generators and circuit breaker head flashover protection for generators…………………………………………………………….. 235 Voltage restrained overcurrent protection for generator and step-up transformer………………………………………………. 236 Loss of excitation protection for a generator…………………… 237

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Section 11 System protection and control………………………………..239 Multipurpose filter SMAIHPAC………………………………………………. 239

Identification…………………………………………………………………… 239 Application………………………………………………………………………239 Setting guidelines……………………………………………………………. 240

Setting example…………………………………………………………..240

Section 12 Secondary system supervision……………………………….245 Current circuit supervision CCSSPVC……………………………………..245

Identification…………………………………………………………………… 245 Application………………………………………………………………………245 Setting guidelines……………………………………………………………. 246

Fuse failure supervision FUFSPVC…………………………………………246 Identification…………………………………………………………………… 246 Application………………………………………………………………………246 Setting guidelines……………………………………………………………. 247

General………………………………………………………………………247 Setting of common parameters…………………………………….. 247 Negative sequence based…………………………………………….248 Zero sequence based…………………………………………………..249 Delta U and delta I ………………………………………………………249 Dead line detection………………………………………………………250

Fuse failure supervision VDSPVC…………………………………………..250 Identification…………………………………………………………………… 250 Application………………………………………………………………………251 Setting guidelines……………………………………………………………. 252

Section 13 Control………………………………………………………………..253 Synchrocheck, energizing check, and synchronizing SESRSYN…253

Identification…………………………………………………………………… 253 Application………………………………………………………………………253

Synchronizing……………………………………………………………..253 Synchrocheck……………………………………………………………..254 Energizing check………………………………………………………… 256 Voltage selection………………………………………………………… 257 External fuse failure……………………………………………………..258

Application examples………………………………………………………..259 Single circuit breaker with single busbar………………………… 260 Single circuit breaker with double busbar, external voltage selection……………………………………………………………………. 260 Single circuit breaker with double busbar, internal voltage selection……………………………………………………………………. 261 Double circuit breaker…………………………………………………. 262

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1 1/2 circuit breaker……………………………………………………..262 Setting guidelines……………………………………………………………. 265

Autorecloser for 1 phase, 2 phase and/or 3 phase operation SMBRREC ………………………………………………………………………….270

Identification…………………………………………………………………… 270 Application………………………………………………………………………270

Auto-reclosing operation OFF and ON……………………………274 Start auto-reclosing and conditions for start of a reclosing cycle…………………………………………………………………………. 274 Start auto-reclosing from CB open information……………….. 274 Blocking of the autorecloser…………………………………………. 275 Control of the auto-reclosing open time for shot 1…………… 275 Long trip signal…………………………………………………………… 275 Maximum number of reclosing shots………………………………276 ARMode=3ph, (normal setting for a single 3 phase shot)…. 276 ARMode=1/2/3ph……………………………………………………….. 276 ARMode=1/2ph, 1-phase or 2-phase reclosing in the first shot……………………………………………………………………………277 ARMode=1ph + 1*2ph, 1-phase or 2-phase reclosing in the first shot………………………………………………………………..277 ARMode=1/2ph + 1*3ph, 1-phase, 2-phase or 3-phase reclosing in the first shot……………………………………………….277 ARMode=1ph + 1*2/3ph, 1-phase, 2-phase or 3-phase reclosing in the first shot……………………………………………….277 External selection of auto-reclose mode………………………… 278 Reclosing reclaim timer……………………………………………….. 279 Pulsing of the CB closing command and Counter…………….279 Transient fault……………………………………………………………..279 Permanent fault and reclosing unsuccessful signal…………. 279 Lock-out initiation……………………………………………………….. 280 Evolving fault……………………………………………………………… 281 Automatic continuation of the reclosing sequence ………….. 281 Thermal overload protection holding the auto-reclosing function back …………………………………………………………….. 282

Setting guidelines……………………………………………………………. 282 Configuration……………………………………………………………… 282 Auto-recloser parameter settings………………………………….. 289

Apparatus control APC…………………………………………………………. 292 Application………………………………………………………………………292

Bay control (QCBAY)………………………………………………….. 295 Switch controller (SCSWI)…………………………………………….296 Switches (SXCBR/SXSWI)……………………………………………297 Reservation function (QCRSV and RESIN)……………………. 298

Interaction between modules……………………………………………..300

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Setting guidelines……………………………………………………………. 302 Bay control (QCBAY)………………………………………………….. 302 Switch controller (SCSWI)…………………………………………….302 Switch (SXCBR/SXSWI)……………………………………………… 303 Bay Reserve (QCRSV)…………………………………………………304 Reservation input (RESIN)…………………………………………… 304

Voltage control……………………………………………………………………..304 Identification…………………………………………………………………… 304 Application………………………………………………………………………304 Setting guidelines……………………………………………………………. 337

TR1ATCC or TR8ATCC general settings………………………..337 TR1ATCC or TR8ATCC Setting group …………………………..338 TCMYLTC and TCLYLTC general settings…………………….. 346

Logic rotating switch for function selection and LHMI presentation SLGAPC………………………………………………………….. 347

Identification…………………………………………………………………… 347 Application………………………………………………………………………348 Setting guidelines……………………………………………………………. 348

Selector mini switch VSGAPC………………………………………………..348 Identification…………………………………………………………………… 349 Application………………………………………………………………………349 Setting guidelines……………………………………………………………. 349

Generic communication function for Double Point indication DPGAPC……………………………………………………………………………. 350

Identification…………………………………………………………………… 350 Application………………………………………………………………………350 Setting guidelines……………………………………………………………. 350

Single point generic control 8 signals SPC8GAPC…………………… 350 Identification…………………………………………………………………… 350 Application………………………………………………………………………350 Setting guidelines……………………………………………………………. 351

AutomationBits, command function for DNP3.0 AUTOBITS………. 351 Identification…………………………………………………………………… 351 Application………………………………………………………………………351 Setting guidelines……………………………………………………………. 352

Single command, 16 signals SINGLECMD……………………………… 352 Identification…………………………………………………………………… 352 Application………………………………………………………………………352 Setting guidelines……………………………………………………………. 354

Interlocking ………………………………………………………………………… 354 Configuration guidelines……………………………………………………356 Interlocking for line bay ABC_LINE …………………………………… 356

Application………………………………………………………………….356 Signals from bypass busbar…………………………………………. 357

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Signals from bus-coupler………………………………………………357 Configuration setting…………………………………………………… 360

Interlocking for bus-coupler bay ABC_BC ………………………….. 361 Application………………………………………………………………….362 Configuration……………………………………………………………… 362 Signals from all feeders………………………………………………..362 Signals from bus-coupler………………………………………………364 Configuration setting…………………………………………………… 366

Interlocking for transformer bay AB_TRAFO ………………………. 367 Application………………………………………………………………….367 Signals from bus-coupler………………………………………………368 Configuration setting…………………………………………………… 368

Interlocking for bus-section breaker A1A2_BS……………………..369 Application………………………………………………………………….369 Signals from all feeders………………………………………………..369 Configuration setting…………………………………………………… 372

Interlocking for bus-section disconnector A1A2_DC ……………. 373 Application………………………………………………………………….373 Signals in single breaker arrangement……………………………373 Signals in double-breaker arrangement…………………………. 376 Signals in 1 1/2 breaker arrangement……………………………. 379

Interlocking for busbar earthing switch BB_ES …………………….380 Application………………………………………………………………….380 Signals in single breaker arrangement……………………………380 Signals in double-breaker arrangement…………………………. 384 Signals in 1 1/2 breaker arrangement……………………………. 385

Interlocking for double CB bay DB ……………………………………. 386 Application………………………………………………………………….386 Configuration setting…………………………………………………… 387

Interlocking for 1 1/2 CB BH ……………………………………………..388 Application………………………………………………………………….388 Configuration setting…………………………………………………… 389

Section 14 Scheme communication………………………………………..391 Scheme communication logic for distance or overcurrent protection ZCPSCH……………………………………………………………… 391

Identification…………………………………………………………………… 391 Application………………………………………………………………………391

Blocking schemes………………………………………………………. 392 Delta blocking scheme………………………………………………… 393 Permissive schemes…………………………………………………… 394 Intertrip scheme…………………………………………………………..397

Setting guidelines……………………………………………………………. 397 Blocking scheme………………………………………………………… 397

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Delta blocking scheme………………………………………………… 398 Permissive underreaching scheme……………………………….. 398 Permissive overreaching scheme…………………………………. 398 Unblocking scheme…………………………………………………….. 398 Intertrip scheme…………………………………………………………..399

Current reversal and Weak-end infeed logic for distance protection 3-phase ZCRWPSCH …………………………………………… 399

Identification…………………………………………………………………… 399 Application………………………………………………………………………399

Current reversal logic………………………………………………….. 399 Weak-end infeed logic………………………………………………….400

Setting guidelines……………………………………………………………. 401 Current reversal logic………………………………………………….. 401 Weak-end infeed logic………………………………………………….402

Local acceleration logic ZCLCPSCH……………………………………….402 Identification…………………………………………………………………… 402 Application………………………………………………………………………402 Setting guidelines……………………………………………………………. 403

Scheme communication logic for residual overcurrent protection ECPSCH …………………………………………………………………………….404

Identification…………………………………………………………………… 404 Application………………………………………………………………………404 Setting guidelines……………………………………………………………. 405

Current reversal and weak-end infeed logic for residual overcurrent protection ECRWPSCH………………………………………..405

Identification…………………………………………………………………… 405 Application………………………………………………………………………405

Fault current reversal logic…………………………………………… 405 Weak-end infeed logic………………………………………………….406

Setting guidelines……………………………………………………………. 407 Current reversal…………………………………………………………..407 Weak-end infeed………………………………………………………… 408

Section 15 Logic…………………………………………………………………..409 Tripping logic common 3-phase output SMPPTRC …………………..409

Identification…………………………………………………………………… 409 Application………………………………………………………………………409

Three-phase tripping ………………………………………………….. 410 Single- and/or three-phase tripping……………………………….. 411 Single-, two- or three-phase tripping……………………………… 412 Lock-out……………………………………………………………………..413 Blocking of the function block………………………………………..413

Setting guidelines……………………………………………………………. 413 Trip matrix logic TMAGAPC………………………………………………….. 414

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Identification…………………………………………………………………… 414 Application………………………………………………………………………414 Setting guidelines……………………………………………………………. 414

Logic for group alarm ALMCALH…………………………………………….415 Identification…………………………………………………………………… 415 Application………………………………………………………………………415 Setting guidelines……………………………………………………………. 415

Logic for group alarm WRNCALH………………………………………….. 415 Identification…………………………………………………………………… 415

Application………………………………………………………………….415 Setting guidelines……………………………………………………….. 415

Logic for group indication INDCALH………………………………………..416 Identification…………………………………………………………………… 416

Application………………………………………………………………….416 Setting guidelines……………………………………………………….. 416

Configurable logic blocks……………………………………………………….416 Application………………………………………………………………………416 Setting guidelines……………………………………………………………. 417

Configuration……………………………………………………………… 417 Fixed signal function block FXDSIGN…………………………………….. 418

Identification…………………………………………………………………… 418 Application………………………………………………………………………418

Boolean 16 to Integer conversion B16I…………………………………… 419 Identification…………………………………………………………………… 419 Application………………………………………………………………………419

Boolean 16 to Integer conversion with logic node representation BTIGAPC…………………………………………………………………………….420

Identification…………………………………………………………………… 420 Application………………………………………………………………………420

Integer to Boolean 16 conversion IB16…………………………………… 421 Identification…………………………………………………………………… 422 Application………………………………………………………………………422

Integer to Boolean 16 conversion with logic node representation ITBGAPC…………………………………………………………………………….423

Identification…………………………………………………………………… 423 Application………………………………………………………………………423

Elapsed time integrator with limit transgression and overflow supervision TEIGAPC……………………………………………………………424

Identification…………………………………………………………………… 424 Application………………………………………………………………………424 Setting guidelines……………………………………………………………. 424

Section 16 Monitoring……………………………………………………………427 Measurement……………………………………………………………………….427

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Identification…………………………………………………………………… 427 Application………………………………………………………………………427 Zero clamping………………………………………………………………….429 Setting guidelines……………………………………………………………. 430

Setting examples…………………………………………………………433 Gas medium supervision SSIMG…………………………………………… 440

Identification…………………………………………………………………… 440 Application………………………………………………………………………440 Setting guidelines……………………………………………………………. 440

Liquid medium supervision SSIML…………………………………………. 441 Identification…………………………………………………………………… 441 Application………………………………………………………………………441 Setting guidelines……………………………………………………………. 441

Breaker monitoring SSCBR……………………………………………………442 Identification…………………………………………………………………… 442 Application………………………………………………………………………442 Setting guidelines……………………………………………………………. 444

Setting procedure on the IED……………………………………….. 445 Event function EVENT…………………………………………………………..446

Identification…………………………………………………………………… 446 Application………………………………………………………………………446 Setting guidelines……………………………………………………………. 446

Disturbance report DRPRDRE………………………………………………. 447 Identification…………………………………………………………………… 447 Application………………………………………………………………………447 Setting guidelines……………………………………………………………. 448

Recording times…………………………………………………………. 451 Binary input signals…………………………………………………….. 451 Analog input signals……………………………………………………. 452 Sub-function parameters……………………………………………… 452 Consideration…………………………………………………………….. 453

Logical signal status report BINSTATREP………………………………. 454 Identification…………………………………………………………………… 454 Application………………………………………………………………………454 Setting guidelines……………………………………………………………. 454

Fault locator LMBRFLO…………………………………………………………455 Identification…………………………………………………………………… 455 Application………………………………………………………………………455 Setting guidelines……………………………………………………………. 455

Connection of analog currents……………………………………… 457 Limit counter L4UFCNT…………………………………………………………457

Identification…………………………………………………………………… 457 Application………………………………………………………………………458

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Setting guidelines……………………………………………………………. 458

Section 17 Metering…………………………………………………………….. 459 Pulse-counter logic PCFCNT………………………………………………… 459

Identification…………………………………………………………………… 459 Application………………………………………………………………………459 Setting guidelines……………………………………………………………. 459

Function for energy calculation and demand handling ETPMMTR 460 Identification…………………………………………………………………… 460 Application………………………………………………………………………460 Setting guidelines……………………………………………………………. 461

Section 18 Station communication………………………………………….463 670 series protocols…………………………………………………………….. 463 IEC 61850-8-1 communication protocol………………………………….. 463

Application IEC 61850-8-1…………………………………………………463 Horizontal communication via GOOSE for interlocking GOOSEINTLKRCV…………………………………………………………..465 Setting guidelines……………………………………………………………. 465 Generic communication function for Single Point indication SPGAPC, SP16GAPC………………………………………………………465

Application………………………………………………………………….465 Setting guidelines……………………………………………………….. 465

Generic communication function for Measured Value MVGAPC………………………………………………………………………..465

Application………………………………………………………………….465 Setting guidelines……………………………………………………….. 466

IEC 61850-8-1 redundant station bus communication………….. 466 Identification………………………………………………………………. 466 Application………………………………………………………………….466 Setting guidelines……………………………………………………….. 467

IEC 61850-9-2LE communication protocol……………………………….468 Introduction……………………………………………………………………..468 Setting guidelines……………………………………………………………. 470

Specific settings related to the IEC 61850-9-2LE communication…………………………………………………………… 471 Loss of communication…………………………………………………471 Setting examples for IEC 61850-9-2LE and time synchronization………………………………………………………….. 475

LON communication protocol………………………………………………… 480 Application………………………………………………………………………480 MULTICMDRCV and MULTICMDSND………………………………. 481

Identification………………………………………………………………. 482 Application………………………………………………………………….482 Setting guidelines……………………………………………………….. 482

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SPA communication protocol………………………………………………… 482 Application………………………………………………………………………482 Setting guidelines……………………………………………………………. 483

IEC 60870-5-103 communication protocol………………………………. 485 Application………………………………………………………………………485

DNP3 Communication protocol……………………………………………… 492 Application………………………………………………………………………492

Section 19 Remote communication…………………………………………493 Binary signal transfer…………………………………………………………….493

Identification…………………………………………………………………… 493 Application………………………………………………………………………493

Communication hardware solutions………………………………. 493 Setting guidelines……………………………………………………………. 494

Section 20 Basic IED functions……………………………………………… 499 Authority status ATHSTAT……………………………………………………. 499

Application………………………………………………………………………499 Change lock CHNGLCK……………………………………………………….. 499

Application………………………………………………………………………499 Denial of service DOS………………………………………………………….. 500

Application………………………………………………………………………500 Setting guidelines……………………………………………………………. 500

IED identifiers TERMINALID…………………………………………………. 501 Application………………………………………………………………………501

Product information PRODINF………………………………………………. 501 Application………………………………………………………………………501 Factory defined settings…………………………………………………… 501

Measured value expander block RANGE_XP………………………….. 502 Identification…………………………………………………………………… 502 Application………………………………………………………………………502 Setting guidelines……………………………………………………………. 503

Parameter setting groups……………………………………………………… 503 Application………………………………………………………………………503 Setting guidelines……………………………………………………………. 503

Rated system frequency PRIMVAL………………………………………… 503 Identification…………………………………………………………………… 504 Application………………………………………………………………………504 Setting guidelines……………………………………………………………. 504

Summation block 3 phase 3PHSUM………………………………………. 504 Application………………………………………………………………………504 Setting guidelines……………………………………………………………. 504

Global base values GBASVAL………………………………………………. 505 Identification…………………………………………………………………… 505

Table of contents

15 Application manual

Application………………………………………………………………………505 Setting guidelines……………………………………………………………. 505

Signal matrix for binary inputs SMBI………………………………………. 505 Application………………………………………………………………………505 Setting guidelines……………………………………………………………. 506

Signal matrix for binary outputs SMBO ………………………………….. 506 Application………………………………………………………………………506 Setting guidelines……………………………………………………………. 506

Signal matrix for mA inputs SMMI………………………………………….. 506 Application………………………………………………………………………506 Setting guidelines……………………………………………………………. 506

Signal matrix for analog inputs SMAI……………………………………… 506 Application………………………………………………………………………507 Frequency values……………………………………………………………. 507 Setting guidelines……………………………………………………………. 508

Test mode functionality TESTMODE……………………………………….513 Application………………………………………………………………………513

IEC 61850 protocol test mode……………………………………….513 Setting guidelines……………………………………………………………. 514

Self supervision with internal event list INTERRSIG…………………. 514 Application………………………………………………………………………514

Time synchronization TIMESYNCHGEN………………………………….515 Application………………………………………………………………………515 Setting guidelines……………………………………………………………. 516

System time………………………………………………………………..516 Synchronization…………………………………………………………..516 Process bus IEC 61850-9-2LE synchronization……………….518

Section 21 Requirements………………………………………………………519 Current transformer requirements………………………………………….. 519

Current transformer classification……………………………………….519 Conditions……………………………………………………………………….520 Fault current…………………………………………………………………… 520 Secondary wire resistance and additional load……………………. 521 General current transformer requirements………………………….. 521 Rated equivalent secondary e.m.f. requirements………………….522

Breaker failure protection…………………………………………….. 522 Non-directional instantaneous and definitive time, phase and residual overcurrent protection………………………………..522 Non-directional inverse time delayed phase and residual overcurrent protection…………………………………………………. 523 Directional phase and residual overcurrent protection……… 524

Current transformer requirements for CTs according to other standards………………………………………………………………………..524

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16 Application manual

Current transformers according to IEC 61869-2, class P, PR525 Current transformers according to IEC 61869-2, class PX, PXR (and old IEC 60044-6, class TPS and old British Standard, class X)…………………………………. 525 Current transformers according to ANSI/IEEE………………… 525

Voltage transformer requirements………………………………………….. 526 SNTP server requirements……………………………………………………. 527 Sample specification of communication requirements for the protection and control terminals in digital telecommunication networks…………………………………………………………………………….. 527 IEC 61850-9-2LE Merging unit requirements ………………………….. 528

Section 22 Glossary…………………………………………………………….. 531

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17 Application manual

Section 1 Introduction

1.1 This manual

The application manual contains application descriptions and setting guidelines sorted per function. The manual can be used to find out when and for what purpose a typical protection function can be used. The manual can also provide assistance for calculating settings.

1.2 Intended audience

This manual addresses the protection and control engineer responsible for planning, pre-engineering and engineering.

The protection and control engineer must be experienced in electrical power engineering and have knowledge of related technology, such as protection schemes and communication principles.

1MRK 511 310-UEN B Section 1 Introduction

19 Application manual

1.3 Product documentation

1.3.1 Product documentation set

IEC07000220-4-en.vsd

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Application manual

Operation manual

Installation manual

Engineering manual

Communication protocol manual

Cyber security deployment guideline

Technical manual

Commissioning manual

IEC07000220 V4 EN

Figure 1: The intended use of manuals throughout the product lifecycle

The engineering manual contains instructions on how to engineer the IEDs using the various tools available within the PCM600 software. The manual provides instructions on how to set up a PCM600 project and insert IEDs to the project structure. The manual also recommends a sequence for the engineering of protection and control functions, LHMI functions as well as communication engineering for IEC 60870-5-103, IEC 61850 and DNP3.

The installation manual contains instructions on how to install the IED. The manual provides procedures for mechanical and electrical installation. The chapters are organized in the chronological order in which the IED should be installed.

The commissioning manual contains instructions on how to commission the IED. The manual can also be used by system engineers and maintenance personnel for assistance during the testing phase. The manual provides procedures for the checking of external circuitry and energizing the IED, parameter setting and configuration as

Section 1 1MRK 511 310-UEN B Introduction

20 Application manual

well as verifying settings by secondary injection. The manual describes the process of testing an IED in a substation which is not in service. The chapters are organized in the chronological order in which the IED should be commissioned. The relevant procedures may be followed also during the service and maintenance activities.

The operation manual contains instructions on how to operate the IED once it has been commissioned. The manual provides instructions for the monitoring, controlling and setting of the IED. The manual also describes how to identify disturbances and how to view calculated and measured power grid data to determine the cause of a fault.

The application manual contains application descriptions and setting guidelines sorted per function. The manual can be used to find out when and for what purpose a typical protection function can be used. The manual can also provide assistance for calculating settings.

The technical manual contains application and functionality descriptions and lists function blocks, logic diagrams, input and output signals, setting parameters and technical data, sorted per function. The manual can be used as a technical reference during the engineering phase, installation and commissioning phase, and during normal service.

The communication protocol manual describes the communication protocols supported by the IED. The manual concentrates on the vendor-specific implementations.

The point list manual describes the outlook and properties of the data points specific to the IED. The manual should be used in conjunction with the corresponding communication protocol manual.

The cyber security deployment guideline describes the process for handling cyber security when communicating with the IED. Certification, Authorization with role based access control, and product engineering for cyber security related events are described and sorted by function. The guideline can be used as a technical reference during the engineering phase, installation and commissioning phase, and during normal service.

1.3.2 Dokumentennderungsverzeichnis Dokument gendert / am Historie -/Juli 2016 Erste bersetzung von 1MRK 511 310-UEN

Version —

1MRK 511 310-UEN B Section 1 Introduction

21 Application manual

1.3.3 Related documents Documents related to REC670 Identify number Application manual 1MRK 511 310-UEN

Commissioning manual 1MRK 511 312-UEN

Product guide 1MRK 511 313-BEN

Technical manual 1MRK 511 311-UEN

Type test certificate 1MRK 511 313-TEN

670 series manuals Identify number Operation manual 1MRK 500 118-UEN

Engineering manual 1MRK 511 308-UEN

Installation manual 1MRK 514 019-UEN

Communication protocol manual, IEC 60870-5-103

1MRK 511 304-UEN

Communication protocol manual, IEC 61850 Edition 1

1MRK 511 302-UEN

Communication protocol manual, IEC 61850 Edition 2

1MRK 511 303-UEN

Communication protocol manual, LON 1MRK 511 305-UEN

Communication protocol manual, SPA 1MRK 511 306-UEN

Accessories guide 1MRK 514 012-BEN

Cyber security deployment guideline 1MRK 511 309-UEN

Connection and Installation components 1MRK 513 003-BEN

Test system, COMBITEST 1MRK 512 001-BEN

1.4 Document symbols and conventions

1.4.1 Symbols

The electrical warning icon indicates the presence of a hazard which could result in electrical shock.

The warning icon indicates the presence of a hazard which could result in personal injury.

The caution hot surface icon indicates important information or warning about the temperature of product surfaces.

Section 1 1MRK 511 310-UEN B Introduction

22 Application manual

The caution icon indicates important information or warning related to the concept discussed in the text. It might indicate the presence of a hazard which could result in corruption of software or damage to equipment or property.

The information icon alerts the reader of important facts and conditions.

The tip icon indicates advice on, for example, how to design your project or how to use a certain function.

Although warning hazards are related to personal injury, it is necessary to understand that under certain operational conditions, operation of damaged equipment may result in degraded process performance leading to personal injury or death. It is important that the user fully complies with all warning and cautionary notices.

1.4.2 Document conventions

Abbreviations and acronyms in this manual are spelled out in the glossary. The glossary also contains definitions of important terms.

Push button navigation in the LHMI menu structure is presented by using the push button icons. For example, to navigate between the options, use and .

HMI menu paths are presented in bold. For example, select Main menu/Settings.

LHMI messages are shown in Courier font. For example, to save the changes in non-volatile memory, select Yes and press

. Parameter names are shown in italics.

For example, the function can be enabled and disabled with the Operation setting. Each function block symbol shows the available input/output signal.

the character ^ in front of an input/output signal name indicates that the signal name may be customized using the PCM600 software.

the character * after an input signal name indicates that the signal must be connected to another function block in the application configuration to achieve a valid application configuration.

Logic diagrams describe the signal logic inside the function block and are bordered by dashed lines.

1MRK 511 310-UEN B Section 1 Introduction

23 Application manual

Signals in frames with a shaded area on their right hand side represent setting parameter signals that are only settable via the PST or LHMI.

If an internal signal path cannot be drawn with a continuous line, the suffix -int is added to the signal name to indicate where the signal starts and continues.

Signal paths that extend beyond the logic diagram and continue in another diagram have the suffix -cont.

Illustrations are used as an example and might show other products than the one the manual describes. The example that is illustrated is still valid.

1.4.3 IEC 61850 edition 1 / edition 2 mapping Table 1: IEC 61850 edition 1 / edition 2 mapping

Function block name Edition 1 logical nodes Edition 2 logical nodes AEGPVOC AEGGAPC AEGPVOC

AGSAL AGSAL SECLLN0

AGSAL

ALMCALH ALMCALH ALMCALH

ALTIM — ALTIM

ALTMS — ALTMS

ALTRK — ALTRK

BCZSPDIF BCZSPDIF BCZSPDIF

BCZTPDIF BCZTPDIF BCZTPDIF

BDCGAPC SWSGGIO BBCSWI BDCGAPC

BRCPTOC BRCPTOC BRCPTOC

BRPTOC BRPTOC BRPTOC

BTIGAPC B16IFCVI BTIGAPC

BUSPTRC_B1 BUSPTRC BBSPLLN0

BUSPTRC

BUSPTRC_B2 BUSPTRC BUSPTRC

BUSPTRC_B3 BUSPTRC BUSPTRC

BUSPTRC_B4 BUSPTRC BUSPTRC

BUSPTRC_B5 BUSPTRC BUSPTRC

BUSPTRC_B6 BUSPTRC BUSPTRC

BUSPTRC_B7 BUSPTRC BUSPTRC

BUSPTRC_B8 BUSPTRC BUSPTRC

BUSPTRC_B9 BUSPTRC BUSPTRC

BUSPTRC_B10 BUSPTRC BUSPTRC

Table continues on next page

Section 1 1MRK 511 310-UEN B Introduction

24 Application manual

Function block name Edition 1 logical nodes Edition 2 logical nodes BUSPTRC_B11 BUSPTRC BUSPTRC

BUSPTRC_B12 BUSPTRC BUSPTRC

BUSPTRC_B13 BUSPTRC BUSPTRC

BUSPTRC_B14 BUSPTRC BUSPTRC

BUSPTRC_B15 BUSPTRC BUSPTRC

BUSPTRC_B16 BUSPTRC BUSPTRC

BUSPTRC_B17 BUSPTRC BUSPTRC

BUSPTRC_B18 BUSPTRC BUSPTRC

BUSPTRC_B19 BUSPTRC BUSPTRC

BUSPTRC_B20 BUSPTRC BUSPTRC

BUSPTRC_B21 BUSPTRC BUSPTRC

BUSPTRC_B22 BUSPTRC BUSPTRC

BUSPTRC_B23 BUSPTRC BUSPTRC

BUSPTRC_B24 BUSPTRC BUSPTRC

BUTPTRC_B1 BUTPTRC BBTPLLN0

BUTPTRC

BUTPTRC_B2 BUTPTRC BUTPTRC

BUTPTRC_B3 BUTPTRC BUTPTRC

BUTPTRC_B4 BUTPTRC BUTPTRC

BUTPTRC_B5 BUTPTRC BUTPTRC

BUTPTRC_B6 BUTPTRC BUTPTRC

BUTPTRC_B7 BUTPTRC BUTPTRC

BUTPTRC_B8 BUTPTRC BUTPTRC

BZISGGIO BZISGGIO BZISGAPC

BZITGGIO BZITGGIO BZITGAPC

BZNSPDIF_A BZNSPDIF BZASGAPC BZASPDIF BZNSGAPC BZNSPDIF

BZNSPDIF_B BZNSPDIF BZBSGAPC BZBSPDIF BZNSGAPC BZNSPDIF

BZNTPDIF_A BZNTPDIF BZATGAPC BZATPDIF BZNTGAPC BZNTPDIF

BZNTPDIF_B BZNTPDIF BZBTGAPC BZBTPDIF BZNTGAPC BZNTPDIF

Table continues on next page

1MRK 511 310-UEN B Section 1 Introduction

25 Application manual

Function block name Edition 1 logical nodes Edition 2 logical nodes CBPGAPC CBPLLN0

CBPMMXU CBPPTRC HOLPTOV HPH1PTOV PH3PTUC PH3PTOC RP3PDOP

CBPMMXU CBPPTRC HOLPTOV HPH1PTOV PH3PTOC PH3PTUC RP3PDOP

CCPDSC CCRPLD CCPDSC

CCRBRF CCRBRF CCRBRF

CCRWRBRF CCRWRBRF CCRWRBRF

CCSRBRF CCSRBRF CCSRBRF

CCSSPVC CCSRDIF CCSSPVC

CMMXU CMMXU CMMXU

CMSQI CMSQI CMSQI

COUVGAPC COUVLLN0 COUVPTOV COUVPTUV

COUVPTOV COUVPTUV

CVGAPC GF2LLN0 GF2MMXN GF2PHAR GF2PTOV GF2PTUC GF2PTUV GF2PVOC PH1PTRC

GF2MMXN GF2PHAR GF2PTOV GF2PTUC GF2PTUV GF2PVOC PH1PTRC

CVMMXN CVMMXN CVMMXN

D2PTOC D2LLN0 D2PTOC PH1PTRC

D2PTOC PH1PTRC

DPGAPC DPGGIO DPGAPC

DRPRDRE DRPRDRE DRPRDRE

ECPSCH ECPSCH ECPSCH

ECRWPSCH ECRWPSCH ECRWPSCH

EF2PTOC EF2LLN0 EF2PTRC EF2RDIR GEN2PHAR PH1PTOC

EF2PTRC EF2RDIR GEN2PHAR PH1PTOC

EF4PTOC EF4LLN0 EF4PTRC EF4RDIR GEN4PHAR PH1PTOC

EF4PTRC EF4RDIR GEN4PHAR PH1PTOC

EFPIOC EFPIOC EFPIOC

EFRWPIOC EFRWPIOC EFRWPIOC

ETPMMTR ETPMMTR ETPMMTR

FDPSPDIS FDPSPDIS FDPSPDIS

FMPSPDIS FMPSPDIS FMPSPDIS

FRPSPDIS FPSRPDIS FPSRPDIS

Table continues on next page

Section 1 1MRK 511 310-UEN B Introduction

26 Application manual

Function block name Edition 1 logical nodes Edition 2 logical nodes FTAQFVR FTAQFVR FTAQFVR

FUFSPVC SDDRFUF FUFSPVC SDDSPVC

GENPDIF GENPDIF GENGAPC GENPDIF GENPHAR GENPTRC

GOOSEBINRCV BINGREC —

GOOSEDPRCV DPGREC —

GOOSEINTLKRCV INTGREC —

GOOSEINTRCV INTSGREC —

GOOSEMVRCV MVGREC —

GOOSESPRCV BINSGREC —

GOOSEVCTRRCV VCTRGREC —

GOPPDOP GOPPDOP GOPPDOP PH1PTRC

GRPTTR GRPTTR GRPTTR

GSPTTR GSPTTR GSPTTR

GUPPDUP GUPPDUP GUPPDUP PH1PTRC

HZPDIF HZPDIF HZPDIF

INDCALCH INDCALH INDCALH

ITBGAPC IB16FCVB ITBGAPC

L3CPDIF L3CPDIF L3CGAPC L3CPDIF L3CPHAR L3CPTRC

L4UFCNT L4UFCNT L4UFCNT

L6CPDIF L6CPDIF L6CGAPC L6CPDIF L6CPHAR L6CPTRC

LAPPGAPC LAPPLLN0 LAPPPDUP LAPPPUPF

LAPPPDUP LAPPPUPF

LCCRPTRC LCCRPTRC LCCRPTRC

LCNSPTOC LCNSPTOC LCNSPTOC

LCNSPTOV LCNSPTOV LCNSPTOV

LCP3PTOC LCP3PTOC LCP3PTOC

LCP3PTUC LCP3PTUC LCP3PTUC

LCPTTR LCPTTR LCPTTR

LCZSPTOC LCZSPTOC LCZSPTOC

LCZSPTOV LCZSPTOV LCZSPTOV

LD0LLN0 LLN0 —

LDLPSCH LDLPDIF LDLPSCH

Table continues on next page

1MRK 511 310-UEN B Section 1 Introduction

27 Application manual

Function block name Edition 1 logical nodes Edition 2 logical nodes LDRGFC STSGGIO LDRGFC

LEXPDIS LEXPDIS LEXPDIS LEXPTRC

LFPTTR LFPTTR LFPTTR

LMBRFLO LMBRFLO LMBRFLO

LOVPTUV LOVPTUV LOVPTUV

LPHD LPHD

LPTTR LPTTR LPTTR

LT3CPDIF LT3CPDIF LT3CGAPC LT3CPDIF LT3CPHAR LT3CPTRC

LT6CPDIF LT6CPDIF LT6CGAPC LT6CPDIF LT6CPHAR LT6CPTRC

MVGAPC MVGGIO MVGAPC

NS2PTOC NS2LLN0 NS2PTOC NS2PTRC

NS2PTOC NS2PTRC

NS4PTOC EF4LLN0 EF4PTRC EF4RDIR GEN4PHAR PH1PTOC

EF4PTRC EF4RDIR PH1PTOC

O2RWPTOV GEN2LLN0 O2RWPTOV PH1PTRC

O2RWPTOV PH1PTRC

OC4PTOC OC4LLN0 GEN4PHAR PH3PTOC PH3PTRC

GEN4PHAR PH3PTOC PH3PTRC

OEXPVPH OEXPVPH OEXPVPH

OOSPPAM OOSPPAM OOSPPAM OOSPTRC

OV2PTOV GEN2LLN0 OV2PTOV PH1PTRC

OV2PTOV PH1PTRC

PAPGAPC PAPGAPC PAPGAPC

PCFCNT PCGGIO PCFCNT

PH4SPTOC GEN4PHAR OCNDLLN0 PH1BPTOC PH1PTRC

GEN4PHAR PH1BPTOC PH1PTRC

PHPIOC PHPIOC PHPIOC

PRPSTATUS RCHLCCH RCHLCCH SCHLCCH

PSLPSCH ZMRPSL PSLPSCH

PSPPPAM PSPPPAM PSPPPAM PSPPTRC

Table continues on next page

Section 1 1MRK 511 310-UEN B Introduction

28 Application manual

Function block name Edition 1 logical nodes Edition 2 logical nodes QCBAY QCBAY

QCRSV QCRSV QCRSV

REFPDIF REFPDIF REFPDIF

ROTIPHIZ ROTIPHIZ ROTIPHIZ ROTIPTRC

ROV2PTOV GEN2LLN0 PH1PTRC ROV2PTOV

PH1PTRC ROV2PTOV

SAPFRC SAPFRC SAPFRC

SAPTOF SAPTOF SAPTOF

SAPTUF SAPTUF SAPTUF

SCCVPTOC SCCVPTOC SCCVPTOC

SCILO SCILO SCILO

SCSWI SCSWI SCSWI

SDEPSDE SDEPSDE SDEPSDE SDEPTOC SDEPTOV SDEPTRC

SESRSYN RSY1LLN0 AUT1RSYN MAN1RSYN SYNRSYN

AUT1RSYN MAN1RSYN SYNRSYN

SINGLELCCH SCHLCCH

SLGAPC SLGGIO SLGAPC

SMBRREC SMBRREC SMBRREC

SMPPTRC SMPPTRC SMPPTRC

SP16GAPC SP16GGIO SP16GAPC

SPC8GAPC SPC8GGIO SPC8GAPC

SPGAPC SPGGIO SPGAPC

SSCBR SSCBR SSCBR

SSIMG SSIMG SSIMG

SSIML SSIML SSIML

STBPTOC STBPTOC BBPMSS STBPTOC

STEFPHIZ STEFPHIZ STEFPHIZ

STTIPHIZ STTIPHIZ STTIPHIZ

SXCBR SXCBR SXCBR

SXSWI SXSWI SXSWI

T2WPDIF T2WPDIF T2WGAPC T2WPDIF T2WPHAR T2WPTRC

T3WPDIF T3WPDIF T3WGAPC T3WPDIF T3WPHAR T3WPTRC

Table continues on next page

1MRK 511 310-UEN B Section 1 Introduction

29 Application manual

Function block name Edition 1 logical nodes Edition 2 logical nodes TCLYLTC TCLYLTC TCLYLTC

TCSLTC

TCMYLTC TCMYLTC TCMYLTC

TEIGAPC TEIGGIO TEIGAPC TEIGGIO

TEILGAPC TEILGGIO TEILGAPC

TMAGAPC TMAGGIO TMAGAPC

TPPIOC TPPIOC TPPIOC

TR1ATCC TR1ATCC TR1ATCC

TR8ATCC TR8ATCC TR8ATCC

TRPTTR TRPTTR TRPTTR

U2RWPTUV GEN2LLN0 PH1PTRC U2RWPTUV

PH1PTRC U2RWPTUV

UV2PTUV GEN2LLN0 PH1PTRC UV2PTUV

PH1PTRC UV2PTUV

VDCPTOV VDCPTOV VDCPTOV

VDSPVC VDRFUF VDSPVC

VMMXU VMMXU VMMXU

VMSQI VMSQI VMSQI

VNMMXU VNMMXU VNMMXU

VRPVOC VRLLN0 PH1PTRC PH1PTUV VRPVOC

PH1PTRC PH1PTUV VRPVOC

VSGAPC VSGGIO VSGAPC

WRNCALH WRNCALH WRNCALH

ZC1PPSCH ZPCPSCH ZPCPSCH

ZC1WPSCH ZPCWPSCH ZPCWPSCH

ZCLCPSCH ZCLCPLAL ZCLCPSCH

ZCPSCH ZCPSCH ZCPSCH

ZCRWPSCH ZCRWPSCH ZCRWPSCH

ZCVPSOF ZCVPSOF ZCVPSOF

ZGVPDIS ZGVLLN0 PH1PTRC ZGVPDIS ZGVPTUV

PH1PTRC ZGVPDIS ZGVPTUV

ZMCAPDIS ZMCAPDIS ZMCAPDIS

ZMCPDIS ZMCPDIS ZMCPDIS

ZMFCPDIS ZMFCLLN0 PSFPDIS ZMFPDIS ZMFPTRC ZMMMXU

PSFPDIS ZMFPDIS ZMFPTRC ZMMMXU

Table continues on next page

Section 1 1MRK 511 310-UEN B Introduction

30 Application manual

Function block name Edition 1 logical nodes Edition 2 logical nodes ZMFPDIS ZMFLLN0

PSFPDIS ZMFPDIS ZMFPTRC ZMMMXU

PSFPDIS PSFPDIS ZMFPDIS ZMFPTRC ZMMMXU

ZMHPDIS ZMHPDIS ZMHPDIS

ZMMAPDIS ZMMAPDIS ZMMAPDIS

ZMMPDIS ZMMPDIS ZMMPDIS

ZMQAPDIS ZMQAPDIS ZMQAPDIS

ZMQPDIS ZMQPDIS ZMQPDIS

ZMRAPDIS ZMRAPDIS ZMRAPDIS

ZMRPDIS ZMRPDIS ZMRPDIS

ZMRPSB ZMRPSB ZMRPSB

ZSMGAPC ZSMGAPC ZSMGAPC

1MRK 511 310-UEN B Section 1 Introduction

31 Application manual

Section 2 Application

2.1 General IED application

REC670 is used for the control, protection and monitoring of different types of bays in power networks. The IED is especially suitable for applications in control systems where the IEC 6185081 Ed 1 or Ed 2 station bus features of the REC670 can be fully utilized. It is used for station-wide interlocking via GOOSE messages and vertical client-server MMS communication to a local station or remote SCADA operator workplace. This supports the architecture with distributed control IEDs in all bays with high demands on reliability. Redundant communication is obtained through the built-in PRP feature which can be used in star or ringbus architectures. REC670 can be used on all voltage levels. It is suitable for the control of all apparatuses in any type of switchgear arrangement.

The control is performed from remote (SCADA/Station) through the IEC 618508 1 Ed1 or Ed2 station communication or from the built-in multi-display local HMI. Cyber security measures are implemented to secure safe autonomous operation of the protection and control functions even if simultaneous cyber attacks occur. For all common types of switchgear arrangements, there are different pre-configurations for control and interlocking. One REC670 control IED can be used for single bay or multi-bay applications. The control operation is based on the select-before-execute principle to give highest possible security. There are synchrocheck functions available to assist optimal breaker closing at the right instance in synchronous as well as asynchronous networks.

A number of protection functions are available for flexibility in use for different station types and busbar arrangements. To fulfil the user’s application requirements, the REC670 features, for example, up to six instantaneous phase and earth overcurrent functions, 4step directional or non-directional delayed-phase and earth overcurrent functions, thermal overload and frequency functions, two instances of 2step under- and overvoltage functions, autorecloser functions and several different measuring functions. This, together with the multi-display local HMI that can show one or more pages per feeder allows using the REC670 for protection and control for up to six bays in a substation.

The auto-reclose for single-, two-, and/or three-phase reclose includes priority circuits for multi-breaker arrangements. It co-operates with the synchrocheck function with high-speed or delayed reclosing. Several breaker failure functions are available to provide a breaker failure function independent from the protection IEDs, also for a complete one- and a half breaker diameter.

Disturbance recording and fault locator are available to allow independent post-fault analysis after primary disturbances in case of a failure in the protection system.

1MRK 511 310-UEN B Section 2 Application

33 Application manual

Duplex communication channels for transfer of up to 192 intertrip and binary signals are available on each remote-end data communication card (LDCM). Typical applications are the communication between 670series IEDs inside the station or with 670series in a remote station as remote I/O.

REC670 can be used in applications with the IEC 61850-9-2LE process bus with up to six Merging Units (MU).

Logic is prepared with a graphical tool. The advanced logic capability allows special applications such as automatic opening of disconnectors in multi-breaker arrangements, closing of breaker rings, load transfer logics and so on. The graphical configuration tool ensures simple and fast testing and commissioning.

2.2 Main protection functions

2 = number of basic instances 0-3 = option quantities 3-A03 = optional function included in packages A03 (refer to ordering details)

IEC 61850 ANSI Function description Bay control

REC670

R EC

67 0

(A 30

)

R EC

67 0

(A 31

)

R EC

67 0

(B 30

)

R EC

67 0

(C 30

)

Differential protection

HZPDIF 87 1Ph high impedance differential protection

0-6 3-A02 3-A02 3-A02 6-A07

2.3 Back-up protection functions

IEC 61850 ANSI Function description Bay control

REC670

R EC

67 0

(A 30

)

R EC

67 0

(A 31

)

R EC

67 0

(B 30

)

R EC

67 0

(C 30

)

Current protection

PHPIOC 50 Instantaneous phase overcurrent protection

0-6 1-C51 1-C51 2-C52 2-C53

OC4PTOC 51_671) Four step phase overcurrent protection

0-6 1-C51 1-C51 2-C52 2-C53

EFPIOC 50N Instantaneous residual overcurrent protection

0-6 1-C51 1-C51 2-C52 2-C53

Table continues on next page

Section 2 1MRK 511 310-UEN B Application

34 Application manual

IEC 61850 ANSI Function description Bay control

REC670

R EC

67 0

(A 30

)

R EC

67 0

(A 31

)

R EC

67 0

(B 30

)

R EC

67 0

(C 30

)

EF4PTOC 51N 67N2)

Four step residual overcurrent protection

0-6 1-C51 1-C51 2-C52 2-C53

NS4PTOC 46I2 Four step directional negative phase sequence overcurrent protection

0-6 1-C51 1-C51 2-C52 2-C53

SDEPSDE 67N Sensitive directional residual overcurrent and power protection

0-6 1-C16 1C16 1-C16 1-C16

LCPTTR 26 Thermal overload protection, one time constant, Celsius

06 1-C51 1-C51 1-C52 1-C53

LFPTTR 26 Thermal overload protection, one time constant, Fahrenheit

06 1-C51 1-C51 1-C52 1-C53

TRPTTR 49 Thermal overload protection, two time constant

0-6 1-C51 1-C51 1-C52 1-C53

CCRBRF 50BF Breaker failure protection

0-6 1-C51 1-C51 1-C52 1-C53

STBPTOC 50STB Stub protection 0-3

CCPDSC 52PD Pole discordance protection

0-6 1 1 2 3

GUPPDUP 37 Directional underpower protection

0-2 1-C17 1-C17 1-C17 1-C17

GOPPDOP 32 Directional overpower protection

0-2 1-C17 1-C17 1-C17 1-C17

BRCPTOC 46 Broken conductor check

0-1 1 1 1 1

CBPGAPC Capacitor bank protection

0-3

VRPVOC 51V Voltage restrained overcurrent protection

0-3

Voltage protection

UV2PTUV 27 Two step undervoltage protection

0-2 2-D02 2-D02 2-D02 2-D02

OV2PTOV 59 Two step overvoltage protection

0-2 2-D02 2-D02 2-D02 2-D02

ROV2PTOV 59N Two step residual overvoltage protection

0-2 2-D02 2-D02 2-D02 2-D02

VDCPTOV 60 Voltage differential protection

0-6 2 2 2 2

LOVPTUV 27 Loss of voltage check 0-2 1 1 1 2

Frequency protection

Table continues on next page

1MRK 511 310-UEN B Section 2 Application

35 Application manual

IEC 61850 ANSI Function description Bay control

REC670

R EC

67 0

(A 30

)

R EC

67 0

(A 31

)

R EC

67 0

(B 30

)

R EC

67 0

(C 30

)

SAPTUF 81 Underfrequency protection

0-6 6-E01 6-E01 6-E01 6-E01

SAPTOF 81 Overfrequency protection

0-6 6-E01 6-E01 6-E01 6-E01

SAPFRC 81 Rate-of-change frequency protection

0-6 6-E01 6-E01 6-E01 6-E01

FTAQFVR 81A Frequency time accumulation protection

0-12

Multipurpose protection

CVGAPC General current and voltage protection

0-9 4-F01 4-F01 4-F01 4-F01

General calculation

SMAIHPAC Multipurpose filter 0-6

1) 67 requires voltage 2) 67N requires voltage

2.4 Control and monitoring functions

IEC 61850 ANSI Function description Bay control

REC670

R EC

67 0

(A 30

)

R EC

67 0

(A 31

)

R EC

67 0

(B 30

)

R EC

67 0

(C 30

)

Control

SESRSYN 25 Synchrocheck, energizing check and synchronizing

0-6, 0-2 1 1 2 3

SMBRREC 79 Autorecloser 0-6, 0-4 1-H04 1-H04 2-H05 3-H06

APC8 3 Apparatus control for single bay, max 8 apparatuses (1CB) incl. interlocking

1 1 1

APC15 3 Apparatus control for single bay, max 15 apparatuses (2CBs) incl. interlocking

1 1

APC30 3 Apparatus control for up to 6 bays, max 30 apparatuses (6CBs) incl. interlocking

1 1

QCBAY Apparatus control 1+5/APC30 1 1 1 1+5/ APC3

0

Table continues on next page

Section 2 1MRK 511 310-UEN B Application

36 Application manual

IEC 61850 ANSI Function description Bay control

REC670

R EC

67 0

(A 30

)

R EC

67 0

(A 31

)

R EC

67 0

(B 30

)

R EC

67 0

(C 30

)

LOCREM Handling of LRswitch positions 1+5/APC30 1 1 1 1+5/ APC3

0

LOCREMCTRL LHMI control of PSTO 1+5/APC30 1 1 1 1+5/ APC3

0

TR1ATCC 90 Automatic voltage control for tap changer, single control

0-4 1-H11 1-H11 1-H11 2-H16

TR8ATCC 90 Automatic voltage control for tap changer, parallel control

0-4 1-H15 1-H15 1-H15 2-H18

TCMYLTC 84 Tap changer control and supervision, 6 binary inputs

0-4 4 4 4 4

TCLYLTC 84 Tap changer control and supervision, 32 binary inputs

0-4 4 4 4 4

SLGAPC Logic rotating switch for function selection and LHMI presentation

15 15 15 15 15

VSGAPC Selector mini switch 20 20 20 20 20

DPGAPC Generic communication function for Double Point indication

16 16 16 16 16

SPC8GAPC Single point generic control 8 signals

5 5 5 5 5

AUTOBITS AutomationBits, command function for DNP3.0

3 3 3 3 3

SINGLECMD Single command, 16 signals 4 4 4 4 4

VCTRSEND Horizontal communication via GOOSE for VCTR

1 1 1 1 1

GOOSEVCTRRC V

Horizontal communication via GOOSE for VCTR

7 7 7 7 7

I103CMD Function commands for IEC 60870-5-103

1 1 1 1 1

I103GENCMD Function commands generic for IEC 60870-5-103

50 50 50 50 50

I103POSCMD IED commands with position and select for IEC 60870-5-103

50 50 50 50 50

I103IEDCMD IED commands for IEC 60870-5-103

1 1 1 1 1

I103USRCMD Function commands user defined for IEC 60870-5-103

1 1 1 1 1

Secondary system supervision

CCSSPVC 87 Current circuit supervision 0-5 1 1 2 3

FUFSPVC Fuse failure supervision 0-4 3 3 3 3

VDSPVC 60 Fuse failure supervision based on voltage difference

0-4 1-G03 1-G03 1-G03 1-G03

Logic

Table continues on next page

1MRK 511 310-UEN B Section 2 Application

37 Application manual

IEC 61850 ANSI Function description Bay control

REC670

R EC

67 0

(A 30

)

R EC

67 0

(A 31

)

R EC

67 0

(B 30

)

R EC

67 0

(C 30

)

SMPPTRC 94 Tripping logic 1-6 6 6 6 6

TMAGAPC Trip matrix logic 12 12 12 12 12

ALMCALH Logic for group alarm 5 5 5 5 5

WRNCALH Logic for group warning 5 5 5 5 5

INDCALH Logic for group indication 5 5 5 5 5

AND, OR, INV, PULSETIMER, GATE, TIMERSET, XOR, LLD, SRMEMORY, RSMEMORY

Configurable logic blocks 40-280 40-28 0

40-28 0

40-28 0

40-28 0

ANDQT, ORQT, INVERTERQT, XORQT, SRMEMORYQT, RSMEMORYQT, TIMERSETQT, PULSETIMERQT , INVALIDQT, INDCOMBSPQT, INDEXTSPQT

Configurable logic blocks Q/T 0-1

SLGAPC, VSGAPC, AND, OR, PULSETIMER, GATE, TIMERSET, XOR, LLD, SRMEMORY, INV

Extension logic package 0-1

FXDSIGN Fixed signal function block 1 1 1 1 1

B16I Boolean 16 to Integer conversion 18 18 18 18 18

BTIGAPC Boolean 16 to Integer conversion with Logic Node representation

16 16 16 16 16

IB16 Integer to Boolean 16 conversion 18 18 18 18 18

ITBGAPC Integer to Boolean 16 conversion with Logic Node representation

16 16 16 16 16

TEIGAPC Elapsed time integrator with limit transgression and overflow supervision

12 12 12 12 12

Monitoring

CVMMXN, CMMXU, VMMXU, CMSQI, VMSQI, VNMMXU

Measurements 6 6 6 6 6

Table continues on next page

Section 2 1MRK 511 310-UEN B Application

38 Application manual

IEC 61850 ANSI Function description Bay control

REC670

R EC

67 0

(A 30

)

R EC

67 0

(A 31

)

R EC

67 0

(B 30

)

R EC

67 0

(C 30

)

AISVBAS Function block for service value presentation of secondary analog inputs

1 1 1 1 1

EVENT Event function 20 20 20 20 20

DRPRDRE, A1RADR, A2RADR, A3RADR, A4RADR, B1RBDR, B2RBDR, B3RBDR, B4RBDR, B5RBDR, B6RBDR

Disturbance report 1 1 1 1 1

SPGAPC Generic communication function for Single Point indication

64 64 64 64 64

SP16GAPC Generic communication function for Single Point indication 16 inputs

16 16 16 16 16

MVGAPC Generic communication function for Measured Value

24 24 24 24 24

BINSTATREP Logical signal status report 3 3 3 3 3

RANGE_XP Measured value expander block 66 66 66 66 66

SSIMG 63 Gas medium supervision 21 21 21 21 21

SSIML 71 Liquid medium supervision 3 3 3 3 3

SSCBR Circuit breaker monitoring 0-18 3-M13 3-M13 6-M15 9-M17

LMBRFLO Fault locator 0-1 1-M01 1-M01 1-M01 1-M01

I103MEAS Measurands for IEC 60870-5-103 1 1 1 1 1

I103MEASUSR Measurands user defined signals for IEC 60870-5-103

3 3 3 3 3

I103AR Function status auto-recloser for IEC 60870-5-103

1 1 1 1 1

I103EF Function status earth-fault for IEC 60870-5-103

1 1 1 1 1

I103FLTPROT Function status fault protection for IEC 60870-5-103

1 1 1 1 1

I103IED IED status for IEC 60870-5-103 1 1 1 1 1

I103SUPERV Supervison status for IEC 60870-5-103

1 1 1 1 1

I103USRDEF Status for user defiend signals for IEC 60870-5-103

20 20 20 20 20

L4UFCNT Event counter with limit supervision 30 30 30 30 30

Table continues on next page

1MRK 511 310-UEN B Section 2 Application

39 Application manual

IEC 61850 ANSI Function description Bay control

REC670

R EC

67 0

(A 30

)

R EC

67 0

(A 31

)

R EC

67 0

(B 30

)

R EC

67 0

(C 30

)

Metering

PCFCNT Pulse-counter logic 16 16 16 16 16

ETPMMTR Function for energy calculation and demand handling

6 6 6 6 6

2.5 Communication

IEC 61850 ANSI Function description Bay control

REC670 R

EC 67

0 (A

30 )

R EC

67 0

(A 31

R EC

67 0

(B 30

)

R EC

67 0

(C 30

)

Station communication

LONSPA, SPA SPA communication protocol

1 1 1 1 1

ADE LON communication protocol

1 1 1 1 1

HORZCOMM Network variables via LON

1 1 1 1 1

PROTOCOL Operation selection between SPA and IEC 60870-5-103 for SLM

1 1 1 1 1

RS485PROT Operation selection for RS485

1 1 1 1 1

RS485GEN RS485 1 1 1 1 1

DNPGEN DNP3.0 communication general protocol

1 1 1 1 1

DNPGENTCP DNP3.0 communication general TCP protocol

1 1 1 1 1

CHSERRS485 DNP3.0 for EIA-485 communication protocol

1 1 1 1 1

CH1TCP, CH2TCP, CH3TCP, CH4TCP

DNP3.0 for TCP/IP communication protocol

1 1 1 1 1

CHSEROPT DNP3.0 for TCP/IP and EIA-485 communication protocol

1 1 1 1 1

Table continues on next page

Section 2 1MRK 511 310-UEN B Application

40 Application manual

IEC 61850 ANSI Function description Bay control

REC670

R EC

67 0

(A 30

)

R EC

67 0

(A 31

R EC

67 0

(B 30

)

R EC

67 0

(C 30

)

MST1TCP, MST2TCP, MST3TCP, MST4TCP

DNP3.0 for serial communication protocol

1 1 1 1 1

DNPFREC DNP3.0 fault records for TCP/IP and EIA-485 communication protocol

1 1 1 1 1

IEC61850-8-1 Parameter setting function for IEC 61850

1 1 1 1 1

GOOSEINTLKR CV

Horizontal communication via GOOSE for interlocking

59 59 59 59 59

GOOSEBINRCV Goose binary receive 16 16 16 16 16

GOOSEDPRCV GOOSE function block to receive a double point value

64 64 64 64 64

GOOSEINTRCV GOOSE function block to receive an integer value

32 32 32 32 32

GOOSEMVRCV GOOSE function block to receive a measurand value

60 60 60 60 60

GOOSESPRCV GOOSE function block to receive a single point value

64 64 64 64 64

GOOSEVCTRCO NF

GOOSE VCTR configuration for send and receive

1 1 1 1 1

VCTRSEND Horizontal communication via GOOSE for VCTR

1 1 1 1 1

GOOSEVCTRRC V

Horizontal communication via GOOSE for VCTR

7 7 7 7 7

MULTICMDRCV, MULTICMDSND

Multiple command and transmit

60/10 60/10 60/10 60/10 60/10

FRONT, LANABI, LANAB, LANCDI, LANCD

Ethernet configuration of links

1 1 1 1 1

GATEWAY Ethernet configuration of link one

1 1 1 1 1

OPTICAL103 IEC 60870-5-103 Optical serial communication

1 1 1 1 1

RS485103 IEC 60870-5-103 serial communication for RS485

1 1 1 1 1

Table continues on next page

1MRK 511 310-UEN B Section 2 Application

41 Application manual

IEC 61850 ANSI Function description Bay control

REC670

R EC

67 0

(A 30

)

R EC

67 0

(A 31

R EC

67 0

(B 30

)

R EC

67 0

(C 30

)

AGSAL Generic security application component

1 1 1 1 1

LD0LLN0 IEC 61850 LD0 LLN0 1 1 1 1 1

SYSLLN0 IEC 61850 SYS LLN0 1 1 1 1 1

LPHD Physical device information

1 1 1 1 1

PCMACCS IED Configuration Protocol

1 1 1 1 1

SECALARM Component for mapping security events on protocols such as DNP3 and IEC103

1 1 1 1 1

FSTACCS Field service tool access via SPA protocol over ethernet communication

1 1 1 1 1

ACTIVLOG Activity logging parameters

1 1 1 1 1

ALTRK Service Tracking 1 1 1 1 1

SINGLELCCH Single ethernet port link status

1 1 1 1 1

PRPSTATUS Dual ethernet port link status

1 1 1 1 1

Process bus communication IEC 61850-9-2 1)

PRP IEC 62439-3 parallel redundancy protocol (only in F00)

0-1 1-P03 1-P03 1-P03 1-P03

Remote communication

Binary signal transfer receive/transmit

6/36 6/36 6/36 6/36 6/36

Transmission of analog data from LDCM

1 1 1 1 1

Receive binary status from remote LDCM

6/3/3 6/3/3 6/3/3 6/3/3 6/3/3

Scheme communication

ZCPSCH 85 Scheme communication logic for distance or overcurrent protection

0-1 1-K01 1-K01 1-K01 1-K01

ZCRWPSCH 85 Current reversal and weak-end infeed logic for distance protection

0-1 1-K01 1-K01 1-K01 1-K01

Table continues on next page

Section 2 1MRK 511 310-UEN B Application

42 Application manual

IEC 61850 ANSI Function description Bay control

REC670

R EC

67 0

(A 30

)

R EC

67 0

(A 31

R EC

67 0

(B 30

)

R EC

67 0

(C 30

)

ZCLCPSCH Local acceleration logic 0-1 1-K01 1-K01 1-K01 1-K01

ECPSCH 85 Scheme communication logic for residual overcurrent protection

0-1 1-C51 1-C51 1-C52 1-C53

ECRWPSCH 85 Current reversal and weak-end infeed logic for residual overcurrent protection

0-1 1-C51 1-C51 1-C52 1-C53

1) Only included for 9-2LE products

2.6 Basic IED functions

Table 2: Basic IED functions

IEC 61850 or function name

Description

INTERRSIG Self supervision with internal event list

SELFSUPEVLST Self supervision with internal event list

TIMESYNCHGEN Time synchronization module

SYNCHBIN, SYNCHCAN, SYNCHCMPPS, SYNCHLON, SYNCHPPH, SYNCHPPS, SYNCHSNTP, SYNCHSPA, SYNCHCMPPS

Time synchronization

TIMEZONE Time synchronization

DSTBEGIN, DSTENABLE, DSTEND

GPS time synchronization module

IRIG-B Time synchronization

SETGRPS Number of setting groups

ACTVGRP Parameter setting groups

TESTMODE Test mode functionality

CHNGLCK Change lock function

SMBI Signal matrix for binary inputs

SMBO Signal matrix for binary outputs

SMMI Signal matrix for mA inputs

SMAI1 — SMAI20 Signal matrix for analog inputs

3PHSUM Summation block 3 phase

Table continues on next page

1MRK 511 310-UEN B Section 2 Application

43 Application manual

IEC 61850 or function name

Description

ATHSTAT Authority status

ATHCHCK Authority check

AUTHMAN Authority management

FTPACCS FTP access with password

SPACOMMMAP SPA communication mapping

SPATD Date and time via SPA protocol

DOSFRNT Denial of service, frame rate control for front port

DOSLANAB Denial of service, frame rate control for OEM port AB

DOSLANCD Denial of service, frame rate control for OEM port CD

DOSSCKT Denial of service, socket flow control

GBASVAL Global base values for settings

PRIMVAL Primary system values

ALTMS Time master supervision

ALTIM Time management

ALTRK Service tracking

ACTIVLOG Activity logging parameters

FSTACCS Field service tool access via SPA protocol over ethernet communication

PCMACCS IED Configuration Protocol

SECALARM Component for mapping security events on protocols such as DNP3 and IEC103

DNPGEN DNP3.0 communication general protocol

DNPGENTCP DNP3.0 communication general TCP protocol

CHSEROPT DNP3.0 for TCP/IP and EIA-485 communication protocol

MSTSER DNP3.0 for serial communication protocol

OPTICAL103 IEC 60870-5-103 Optical serial communication

RS485103 IEC 60870-5-103 serial communication for RS485

IEC61850-8-1 Parameter setting function for IEC 61850

HORZCOMM Network variables via LON

LONSPA SPA communication protocol

LEDGEN General LED indication part for LHMI

Section 2 1MRK 511 310-UEN B Application

44 Application manual

Section 3 Configuration

3.1 Introduction

On request, ABB is available to support the re-configuration work, either directly or to do the design checking.

Hardware modules are configured with the hardware configuration tool in the PCM600 engineering platform.

The IED is available to be ordered in three different alternatives with the configuration suitable for the application. The control application will normally require adaptation of interlocking signals, mimic adaptation to the specific arrangements etc. as e.g. the availability of earthing switches varies.

The main protection functions are switched Off at delivery. Back-up functions that are not generally used are also set to Off.

The configurations are:

Single-breaker arrangement, single or double busbar. Double bus/double breaker arrangement. One-and-a-half breaker arrangement (one complete diameter).

The number of IO must be ordered to the application where more IO is foreseen to be required in the Double and One-and-a-half breaker arrangement.

The configuration is done for the complete control and measurement in the bays. Interlocking is provided and configured to be default done across bays with GOOSE messaging according to the IEC61850-8-1 standard.

Complete projects are provided with setting, signal matrix, mimic and the application configuration prepared and for single breaker arrangements multiple feeders and the bus coupler configurations are available and can simply be downloaded.

Synchronism check function is included for controlled closing of the circuit breakers.

Disconnectors and earthing switches are proposed and foreseen to be switched double pole to have highest possible security against unnecessary operations due to, for example a single- earth fault in the control circuit.

Protection functions are option and are not configured.

All IEDs can be reconfigured with help of the application configuration tool, being part of the PCM600 platform. This way the IED can be made suitable for special

1MRK 511 310-UEN B Section 3 Configuration

45 Application manual

applications and special logic can be developed i.e. logic for automatic opening of disconnectors and closing ring bays, automatic load transfer from one busbar to the other, and so on.

On request, ABB is available to support the re-configuration work, either directly or to do the design checking.

Optional functions and optional IO ordered will not be configured at delivery. It should be noted that the standard only includes one binary input and one binary output module and only the key functions such as tripping are connected to the outputs in the signal matrix tool. The required total IO must be calculated and specified at ordering.

Optional functions and optional IO ordered will not be configured at delivery. It should be noted that the standard only includes one binary input and one binary output module and only the key functions such as tripping are connected to the outputs. The required total IO must be calculated and specified at ordering.

The configurations are as far as found necessary provided with application comments to explain why the signals have been connected in the special way. This is of course for the special application features created, not for standard functionality.

3.2 Description of configuration REC670

3.2.1 Introduction

3.2.1.1 Description of configuration A30

The configuration of the IED is shown in Figure 2.

This configuration is used in single breaker arrangements with single or double busbar.

Control, measuring and interlocking is fully configured.

The following should be noted. The configuration is made with the binary input and binary output boards in the basic delivery. In many cases this is sufficient, in other cases, for example with full control of all apparatuses included, more IO cards are required. Our proposal for a full version with control is to use two binary input modules and one binary output module.

Section 3 1MRK 511 310-UEN B Configuration

46 Application manual

REC670 A30 Double busbar in single breaker arrangement 12AI (6I + 6U)

QB1

QA1

QB2

QB9

S CILO

3 Control

S CSWI

3 Control

S XSWI

3 Control

S CILO

3 Control

S CSWI

3 Control

S XSWI

3 Control

S CILO

3 Control

S CSWI

3 Control

S XSWI

3 Control

S CILO

3 Control

S CSWI

3 Control

S XSWI

3 Control

DRP RDRE

DFR/SER DR

CV MMXN

MET P/Q

VN MMXU

MET UN

ETP MMTR

MET W/Varh

QC9

SES RSYN

25 SC/VC

Q CBAY

3 Control

Q CRSV

3 Control

R ESIN

3 Control

BRC PTOC

46 Iub>

CC PDSC

52PD PD

Other Functions available from the function library

TCM YLTC

84

LOV PTUV

27 3U<

VDC PTOV

60 Ud>

CCS SPVC

87 INd/I

TCL YLTC

84

NS4 PTOC

46I2 4(I2>)

LC PTTR

26 >

Optional Functions

HZ PDIF

87 Id>

PH PIOC

50 3I>>

OC4 PTOC

51_67 4(3I>)

EF PIOC

50N IN>>

EF4 PTOC

51N_67N 4(IN>)

LF PTTR

26 >

SDE PSDE

67N IN>

UV2 PTUV

27 2(3U<)

SA PTOF

81 f>

OV2 PTOV

59 2(3U>)

GOP PDOP

32 P>

SA PFRC

81 df/dt<>

GUP PDUP

37 P<

TR PTTR

49 >

CV GAPC

2(I>/U<)

ZCRW PSCH

85

LMB RFLO

21FL FL

EC PSCH

85

ZC PSCH

85

TR8 ATCC

90 U

ECRW PSCH

85

TR1 ATCC

90 U

ZCLC PSCH

ROV2 PTOV

59N 2(U0>)

SA PTUF

81 f<

VD SPVC

60 Ud>

S SIMG

63

S SIML

71

SMP PTRC

94 1 0

CC RBRF

50BF 3I>BF

VN MMXU

MET UN

V MMXU

MET U

V MSQI

MET Usqi

C MMXU

MET I

C MSQI

MET Isqi

S CILO

3 Control

S CSWI

3 Control

S XCBR

3 Control

VN MMXU

MET UN

SMB RREC

79 0 1

WA1

WA2

WA2_VT

WA1_VT

LINE_CT

LINE_VT

S SCBR

FUF SPVC

U>/I<

IEC05000837 V3 EN

Figure 2: Configuration diagram for configuration A30

3.2.1.2 Description of configuration B30

The configuration of the IED is shown in Figure 3.

This configuration is used in double breaker arrangements.

1MRK 511 310-UEN B Section 3 Configuration

47 Application manual

Control, measuring and interlocking is fully configured, including communication with other bays such as other lines and the bus coupler over GOOSE.

The following should be noted. The configuration is made with the binary input and binary output boards in the basic IED delivery. In many cases this is sufficient, in other cases e.g. with full control of all apparatuses included more IO cards are required. Our proposal for a full version with control is to use two binary input modules and one or two binary output modules. For systems without Substation Automation a second binary output board might be required.

Section 3 1MRK 511 310-UEN B Configuration

48 Application manual

REC670 B30 — Double breaker arrangement 12AI (6I + 6U)

QB1

QA1

QB61

QB2

QA2

QB62

QB9

S CILO

3 Control

S CSWI

3 Control

S XCBR

3 Control

ETP MMTR

MET W/Varh

BRC PTOC

46 Iub>

CC PSDC

52PD PD

Other Functions available from the function library

TCM YLTC

84

LOV PTUV

27 3U<

VDC PTOV

60 Ud>

CCS RDIF

87 INd/I

TCL YLTC

84

NS4 PTOC

46I2 4(I2>)

Optional Functions

HZ PDIF

87 Id>

PH PIOC

50 3I>>

OC4 PTOC

51_67 4(3I>)

EF PIOC

50N IN>>

EF4 PTOC

51N_67N 4(IN>)

SDE PSDE

67N IN>

UV2 PTUV

27 2(3U<)

SA PTOF

81 f>

OV2 PTOV

59 2(3U>)

GOP PDOP

32 P>

SA PFRC

81 df/dt<>

GUP PDUP

37 P<

CV GAPC

2(I>/U<)

ZCRW PSCH

85

LMB RFLO

21FL FL

EC PSCHZC PSCH

85

TR8 ATCC

90 U

ECRW PSCHTR1 ATCC

90 U

ZCLC PSCH

ROV2 PTOV

59N 2(U0>)

SA PTUF

81 f<

QC9

3 Control

VD SPVC

60 Ud>

S SIMG

63

S SIML

71

CC RBRF

50BF 3I>BF

TR PTTR

49 >

SMB RREC

79 0 1

SMP PTRC

94 1 0

LF PTTR

26 >

LC PTTR

26 >

C MMXU

MET I

C MSQI

MET Isqi

FUF SPVC

U>/I<

WA1

WA2_VT

WA1_VT

WA2

LINE_VT

LINE_CT1

LINE_CT2

S CILO

3 Control

S CSWI

3 Control

S XSWI

3 Control

S CILO

3 Control

S CSWI

3 Control

S XSWI

3 Control

VN MMXU

MET UN

S CILO

3 Control

S CSWI

3 Control

S XCBR

3 Control

VN MMXU

MET UN

VN MMXU

MET UN

V MMXU

MET U

V MSQI

MET Usqi

DRP RDRE

DFR/SER DR

Q CBAY Q CRSV

3 Control

R ESIN

3 Control

S CILO

3 Control

S CSWI

3 Control

S XSWI

3 Control

S CILO

3 Control

S CSWI

3 Control

S XSWI

3 Control

S CILO

3 Control

S CSWI

3 Control

S XSWI

3 Control

S CILO

3 Control

S CSWI

3 Control

S XSWI

3 Control

S SCBR

SES RSYN

25 SC/VC

SES RSYN

25 SC/VC

CV MMXN

MET P/Q

IEC05000838 V3 EN

Figure 3: Configuration diagram for configuration B30

3.2.1.3 Description of configuration C30

The configuration of the IED is shown on Figure 4.

1MRK 511 310-UEN B Section 3 Configuration

49 Application manual

This configuration is used in one-and-a-half breaker arrangements for a full diameter. The configuration can also be used for a section of the diameter with utilization of a part of the apparatuses only.

Control, measuring and interlocking is fully configured, including communication with other bays such as other lines and the bus coupler over GOOSE.

The following should be noted. The configuration is made with the binary input and binary output boards in the basic IED delivery. In many cases this is sufficient, in other cases, for example with full control of all apparatuses included more IO cards are required. Our proposal for a full version with control is to use three binary input modules and two binary output modules. For systems without Substation Automation a second binary output board might be required.

Section 3 1MRK 511 310-UEN B Configuration

50 Application manual

S CILO

3 Control

S CSWI

3 Control

S XSWI

3 Control

S CILO

3 Control

S CSWI

3 Control

S XSWI

3 Control

S CILO

3 Control

S CSWI

3 Control

S XSWI

3 Control

S CILO

3 Control

S CSWI

3 Control

S XSWI

3 Control

S CILO

3 Control

S CSWI

3 Control

S XSWI

3 Control

S CILO

3 Control

S CSWI

3 Control

S XSWI

3 Control

S CILO

3 Control

S CSWI

3 Control

S XSWI

3 Control

S CILO

3 Control

S CSWI

3 Control

S XSWI

3 Control

S CILO

3 Control

S CSWI

3 Control

S XSWI

3 Control

S CILO

3 Control

S CSWI

3 Control

S XSWI

3 Control

DRP RDRE

DFR/SER DR

Q CBAY

3 Control

Q CRSV

03 Control

R ESIN

3 Control

S CILO

3 Control

S CSWI

3 Control

S XCBR

3 Control

S CILO

3 Control

S CSWI

3 Control

S XCBR

3 Control

S CILO

3 Control

S CSWI

3 Control

S XCBR

3 Control

ETP MMTR

MET W/Varh

V MMXU

MET U

REC670C30 Complete one-and a half breaker diameter arrangement 24AI (6I + 6U, 6I+6U)

V MMXU

MET U

BRC PTOC

46 Iub>

CC PDSC

52PD PD

Other Functions available from the function library

TCM YLTC

84

LOV PTUV

27 3U<

VDC PTOV

60 Ud>

CCS SPVC

87 INd/I

TCL YLTC

84

NS4 PTOC

46I2 4(I2>)

LC PTTR

26 >

Optional Functions

HZ PDIF

87 Id>

PH PIOC

50 3I>>

OC4 PTOC

51_67 4(3I>)

EF PIOC

50N IN>>

EF4 PTOC

51N_67N 4(IN>)

LF PTTR

26 >

SDE PSDE

67N IN>

UV2 PTUV

27 2(3U<)

SA PTOF

81 f>

OV2 PTOV

59 2(3U>)

GOP PDOP

32 P>

SA PFRC

81 df/dt<>

GUP PDUP

37 P<

ZCRW PSCH

85

LMB RFLO

21FL FL

EC PSCH

85

ZC PSCH

85

TR8 ATCC

90 U

ECRW PSCH

85

TR1 ATCC

90 U

ZCLC PSCH

ROV2 PTOV

59N 2(U0>)

SA PTUF

81 f<

SMP PTRC

94 1 0

Q CRSV

3 Control

C MMXU

MET I

C MSQI

MET Isqi

C MMXU

MET I

C MSQI

MET Isqi

WA1

WA2_VT

FUF SPVC

U>/I<

V MSQI

MET Usqi

V MSQI

MET Usqi

S SIMG

63

TR PTTR

49 >

CV GAPC

U

SMB RREC

79 0 1

S SIML

71

VD SPVC

60 Ud>

S SCBR

QB1

WA1_QA1

WA1_QB6

LINE1_QC9

QB61

TIE_QA1

QB62

LINE1_QB9

LINE2_QC9

WA2_QB6

LINE2_QB9

WA2_QA1

QB2

WA1_VT

WA1_CT

WA2_CT

LINE2_VT

TIE_CT

LINE1_VT

WA2

SES RSYN

25 SC

SES RSYN

25 SC

SES RSYN

25 SC/VC

VN MMXU

MET UN

ETP MMTR

MET W/Varh

CV MMXN

MET P/Q

FUF SPVC

U>/I<

CV MMXN

MET P/Q

VN MMXU

MET UN

VN MMXU

MET UN

VN MMXU

MET UN

CC RBRF

50BF 3I>BF

IEC05000839 V3 EN

Figure 4: Configuration diagram for configuration C30

1MRK 511 310-UEN B Section 3 Configuration

51 Application manual

Section 4 Analog inputs

4.1 Introduction

Analog input channels must be configured and set properly to get correct measurement results and correct protection operations. For power measuring and all directional and differential functions the directions of the input currents must be defined properly. Measuring and protection algorithms in the IED use primary system quantities. Setting values are in primary quantities as well and it is important to set the data about the connected current and voltage transformers properly.

A reference PhaseAngleRef can be defined to facilitate service values reading. This analog channels phase angle will always be fixed to zero degrees and all other angle information will be shown in relation to this analog input. During testing and commissioning of the IED the reference channel can be changed to facilitate testing and service values reading.

The IED has the ability to receive analog values from primary equipment, that are sampled by Merging units (MU) connected to a process bus, via the IEC 61850-9-2 LE protocol.

The availability of VT inputs depends on the ordered transformer input module (TRM) type.

4.2 Setting guidelines

The available setting parameters related to analog inputs are depending on the actual hardware (TRM) and the logic configuration made in PCM600.

4.2.1 Setting of the phase reference channel

All phase angles are calculated in relation to a defined reference. An appropriate analog input channel is selected and used as phase reference. The parameter PhaseAngleRef defines the analog channel that is used as phase angle reference.

1MRK 511 310-UEN B Section 4 Analog inputs

53 Application manual

4.2.1.1 Example

Usually the L1 phase-to-earth voltage connected to the first VT channel number of the transformer input module (TRM) is selected as the phase reference. The first VT channel number depends on the type of transformer input module.

For a TRM with 6 current and 6 voltage inputs the first VT channel is 7. The setting PhaseAngleRef=7 shall be used if the phase reference voltage is connected to that channel.

4.2.2 Setting of current channels

The direction of a current to the IED is depending on the connection of the CT. Unless indicated otherwise, the main CTs are supposed to be star connected and can be connected with the earthing point to the object or from the object. This information must be set in the IED. The convention of the directionality is defined as follows: A positive value of current, power, and so on means that the quantity has the direction into the object and a negative value means direction out from the object. For directional functions the direction into the object is defined as Forward and the direction out from the object is defined as Reverse. See figure 5

A positive value of current, power, and so on (forward) means that the quantity has a direction towards the object. — A negative value of current, power, and so on (reverse) means a direction away from the object. See figure 5.

Protected Object Line, transformer, etc

ForwardReverse

Definition of direction for directional functions

Measured quantity is positive when flowing

towards the object

e.g. P, Q, I

ReverseForward

Definition of direction for directional functions

e.g. P, Q, I Measured quantity is positive when flowing

towards the object

Set parameter CTStarPoint

Correct Setting is «ToObject»

Set parameter CTStarPoint

Correct Setting is «FromObject» en05000456.vsd

IEC05000456 V1 EN

Figure 5: Internal convention of the directionality in the IED

With correct setting of the primary CT direction, CTStarPoint set to FromObject or ToObject, a positive quantities always flowing towards the object and a direction defined as Forward always is looking towards the object. The following examples show the principle.

Section 4 1MRK 511 310-UEN B Analog inputs

54 Application manual

4.2.2.1 Example 1

Two IEDs used for protection of two objects.

Transformer

protection

Transformer

Line

Line

Setting of current input:

Set parameter

CTStarPoint with

Transformer as

reference object.

Correct setting is

«ToObject»

ForwardReverse

Definition of direction

for directional functions

Line protection

Setting of current input:

Set parameter

CTStarPoint with

Transformer as

reference object.

Correct setting is

«ToObject»

Setting of current input:

Set parameter

CTStarPoint with

Line as

reference object.

Correct setting is

«FromObject»

IEC05000753=IEC05

000753=1=en=Origin

al[1].vsd

IsIs

Ip Ip Ip

IED IED

IEC05000753 V2 EN

Figure 6: Example how to set CTStarPoint parameters in the IED

The figure 6 shows the normal case where the objects have their own CTs. The settings for CT direction shall be done according to the figure. To protect the line the direction of the directional functions of the line protection shall be set to Forward. This means that the protection is looking towards the line.

4.2.2.2 Example 2

Two IEDs used for protection of two objects and sharing a CT.

1MRK 511 310-UEN B Section 4 Analog inputs

55 Application manual

Transformer

protection

Transformer

Line

Setting of current input:

Set parameter

CTStarPoint with

Transformer as

reference object.

Correct setting is

«ToObject»

ForwardReverse

Definition of direction

for directional functions

Line protection

Setting of current input:

Set parameter

CTStarPoint with

Transformer as

reference object.

Correct setting is

«ToObject»

Setting of current input:

Set parameter

CTStarPoint with

Line as

reference object.

Correct setting is

«FromObject»

IED IED

IEC05000460 V2 EN

Figure 7: Example how to set CTStarPoint parameters in the IED

This example is similar to example 1, but here the transformer is feeding just one line and the line protection uses the same CT as the transformer protection does. The CT direction is set with different reference objects for the two IEDs though it is the same current from the same CT that is feeding the two IEDs. With these settings the directional functions of the line protection shall be set to Forward to look towards the line.

4.2.2.3 Example 3

One IED used to protect two objects.

Section 4 1MRK 511 310-UEN B Analog inputs

56 Application manual

Transformer and

Line protection

Transformer

Line

Setting of current input:

Set parameter

CTStarPoint with

Transformer as

reference object.

Correct setting is

«ToObject»

ReverseForward

Definition of direction

for directional

line functions

Setting of current input:

Set parameter

CTStarPoint with

Transformer as

reference object.

Correct setting is

«ToObject»

IED

IEC05000461 V2 EN

Figure 8: Example how to set CTStarPoint parameters in the IED

In this example one IED includes both transformer and line protection and the line protection uses the same CT as the transformer protection does. For both current input channels the CT direction is set with the transformer as reference object. This means that the direction Forward for the line protection is towards the transformer. To look towards the line the direction of the directional functions of the line protection must be set to Reverse. The direction Forward/Reverse is related to the reference object that is the transformer in this case.

When a function is set to Reverse and shall protect an object in reverse direction it shall be noted that some directional functions are not symmetrical regarding the reach in forward and reverse direction. It is in first hand the reach of the directional criteria that can differ. Normally it is not any limitation but it is advisable to have it in mind and check if it is acceptable for the application in question.

If the IED has a sufficient number of analog current inputs an alternative solution is shown in figure 9. The same currents are fed to two separate groups of inputs and the line and transformer protection functions are configured to the different inputs. The CT direction for the current channels to the line protection is set with the line as reference object and the directional functions of the line protection shall be set to Forward to protect the line.

1MRK 511 310-UEN B Section 4 Analog inputs

57 Application manual

Transformer and

Line protection

Transformer

Line

Setting of current input

for transformer functions:

Set parameter

CTStarPoint with

Transformer as

reference object.

Correct setting is

«ToObject»

ForwardReverse

Definition of direction

for directional

line functions

Setting of current input

for transformer functions:

Set parameter

CTStarPoint with

Transformer as

reference object.

Correct setting is

«ToObject»

Setting of current input

for line functions:

Set parameter

CTStarPoint with

Line as

reference object.

Correct setting is

«FromObject»

IED

IEC05000462 V2 EN

Figure 9: Example how to set CTStarPoint parameters in the IED

Section 4 1MRK 511 310-UEN B Analog inputs

58 Application manual

Busbar Protection

Busbar

1

2

2

1

en06000196.vsd

IED

IEC06000196 V2 EN

Figure 10: Example how to set CTStarPoint parameters in the IED

For busbar protection it is possible to set the CTStarPoint parameters in two ways.

The first solution will be to use busbar as a reference object. In that case for all CT inputs marked with 1 in figure 10, set CTStarPoint = ToObject, and for all CT inputs marked with 2 in figure 10, set CTStarPoint = FromObject.

The second solution will be to use all connected bays as reference objects. In that case for all CT inputs marked with 1 in figure 10, set CTStarPoint = FromObject, and for all CT inputs marked with 2 in figure 10, set CTStarPoint = ToObject.

Regardless which one of the above two options is selected busbar differential protection will behave correctly.

1MRK 511 310-UEN B Section 4 Analog inputs

59 Application manual

The main CT ratios must also be set. This is done by setting the two parameters CTsec and CTprim for each current channel. For a 1000/1 A CT the following setting shall be used:

CTprim = 1000 (value in A) CTsec =1 (value in A).

4.2.2.4 Examples on how to connect, configure and set CT inputs for most commonly used CT connections

Figure 11 defines the marking of current transformer terminals commonly used around the world:

In the SMAI function block, you have to set if the SMAI block is measuring current or voltage. This is done with the parameter: AnalogInputType: Current/voltage. The ConnectionType: phase — phase/phase-earth and GlobalBaseSel.

ISec

I P ri

S1 (X1)

P1 (H1)

P2 (H2)

S2 (X2)

P2 (H2)

P1 (H1)

x x

a) b) c)

en06000641.vsd

S2 (X2) S1 (X1)

IEC06000641 V1 EN

Figure 11: Commonly used markings of CT terminals

Where:

a) is symbol and terminal marking used in this document. Terminals marked with a square indicates the primary and secondary winding terminals with the same (that is, positive) polarity

b) and c) are equivalent symbols and terminal marking used by IEC (ANSI) standard for CTs. Note that for these two cases the CT polarity marking is correct!

It shall be noted that depending on national standard and utility practices, the rated secondary current of a CT has typically one of the following values:

1A 5A

Section 4 1MRK 511 310-UEN B Analog inputs

60 Application manual

However in some cases the following rated secondary currents are used as well:

2A 10A

The IED fully supports all of these rated secondary values.

It is recommended to:

use 1A rated CT input into the IED in order to connect CTs with 1A and 2A secondary rating

use 5A rated CT input into the IED in order to connect CTs with 5A and 10A secondary rating

4.2.2.5 Example on how to connect a star connected three-phase CT set to the IED

Figure 12 gives an example about the wiring of a star connected three-phase CT set to the IED. It gives also an overview of the actions which are needed to make this measurement available to the built-in protection and control functions within the IED as well.

For correct terminal designations, see the connection diagrams valid for the delivered IED.

1MRK 511 310-UEN B Section 4 Analog inputs

61 Application manual

L1 IL

1

IL 2

IL 3

L2 L3

Protected Object

CT 600/5 Star Connected

IL1

IL2

IL3

IED

IEC13000002-4-en.vsdx

1 2

3

4

SMAI2

BLOCK

REVROT

^GRP2L1

^GRP2L2

^GRP2L3

^GRP2N

AI3P

AI1

AI2

AI3

AI4

AIN

5

IN

IEC13000002 V4 EN

Figure 12: Star connected three-phase CT set with star point towards the protected object

Where:

1) The drawing shows how to connect three individual phase currents from a star connected three-phase CT set to the three CT inputs of the IED.

2) The current inputs are located in the TRM. It shall be noted that for all these current inputs the following setting values shall be entered for the example shown in Figure12. ‘

CTprim=600A CTsec=5A CTStarPoint=ToObject

Inside the IED only the ratio of the first two parameters is used. The third parameter (CTStarPoint=ToObject) as set in this example causes no change on the measured currents. In other words, currents are already measured towards the protected object.

Table continues on next page

Section 4 1MRK 511 310-UEN B Analog inputs

62 Application manual

3) These three connections are the links between the three current inputs and the three input channels of the preprocessing function block 4). Depending on the type of functions, which need this current information, more than one preprocessing block might be connected in parallel to the same three physical CT inputs.

4) The preprocessing block that has the task to digitally filter the connected analog inputs and calculate:

fundamental frequency phasors for all three input channels harmonic content for all three input channels positive, negative and zero sequence quantities by using the fundamental frequency

phasors for the first three input channels (channel one taken as reference for sequence quantities)

These calculated values are then available for all built-in protection and control functions within the IED, which are connected to this preprocessing function block. For this application most of the preprocessing settings can be left to the default values. If frequency tracking and compensation is required (this feature is typically required only for IEDs installed in power plants), then the setting parameters DFTReference shall be set accordingly. Section SMAI in this manual provides information on adaptive frequency tracking for the signal matrix for analogue inputs (SMAI).

5) AI3P in the SMAI function block is a grouped signal which contains all the data about the phases L1, L2, L3 and neutral quantity; in particular the data about fundamental frequency phasors, harmonic content and positive sequence, negative and zero sequence quantities are available. AI1, AI2, AI3, AI4 are the output signals from the SMAI function block which contain the fundamental frequency phasors and the harmonic content of the corresponding input channels of the preprocessing function block. AIN is the signal which contains the fundamental frequency phasors and the harmonic content of the neutral quantity. In this example GRP2N is not connected so this data is calculated by the preprocessing function block on the basis of the inputs GRPL1, GRPL2 and GRPL3. If GRP2N is connected, the data reflects the measured value of GRP2N.

Another alternative is to have the star point of the three-phase CT set as shown in the figure below:

1MRK 511 310-UEN B Section 4 Analog inputs

63 Application manual

L1 IL

1

IL 2

IL 3

L2 L3

Protected Object

CT 800/1 Star Connected

IL1

IL2

IL3

IED

IEC11000026-4-en.vsdx

4 1 2

3

SMAI2

BLOCK

REVROT

^GRP2L1

^GRP2L2

^GRP2L3

^GRP2N

AI3P

AI1

AI2

AI3

AI4

AIN

5

IN

IEC11000026 V4 EN

Figure 13: Star connected three-phase CT set with its star point away from the protected object

In the example in figure 13 case everything is done in a similar way as in the above described example (figure 12). The only difference is the setting of the parameter CTStarPoint of the used current inputs on the TRM (item 2 in the figure):

CTprim=600A CTsec=5A CTStarPoint=FromObject

Inside the IED only the ratio of the first two parameters is used. The third parameter as set in this example will negate the measured currents in order to ensure that the currents are measured towards the protected object within the IED.

A third alternative is to have the residual/neutral current from the three-phase CT set connected to the IED as shown in the figure below.

Section 4 1MRK 511 310-UEN B Analog inputs

64 Application manual

L1 IL

1

IL 2

IL 3

L2 L3

Protected Object

CT 800/1

Star Connected IL1

IL2

IL3

IN

IED

1

3

4

2

5

IEC06000644-4-en.vsdx

6

SMAI2

BLOCK

REVROT

^GRP2L1

^GRP2L2

^GRP2L3

^GRP2N

AI3P

AI1

AI2

AI3

AI4

AIN

IEC06000644 V4 EN

Figure 14: Star connected three-phase CT set with its star point away from the protected object and the residual/neutral current connected to the IED

Where:

1) The drawing shows how to connect three individual phase currents from a star connected three-phase CT set to the three CT inputs of the IED.

2) shows how to connect residual/neutral current from the three-phase CT set to the fourth inputs in the IED. It shall be noted that if this connection is not made, the IED will still calculate this current internally by vectorial summation of the three individual phase currents.

3) is the TRM where these current inputs are located. It shall be noted that for all these current inputs the following setting values shall be entered.

CTprim=800A CTsec=1A CTStarPoint=FromObject ConnectionType=Ph-N

Inside the IED only the ratio of the first two parameters is used. The third parameter as set in this example will have no influence on the measured currents (that is, currents are already measured towards the protected object).

4) are three connections made in the Signal Matrix tool (SMT), Application configuration tool (ACT), which connects these three current inputs to the first three input channels on the preprocessing function block 6). Depending on the type of functions, which need this current information, more than one preprocessing block might be connected in parallel to these three CT inputs.

Table continues on next page

1MRK 511 310-UEN B Section 4 Analog inputs

65 Application manual

5) is a connection made in the Signal Matrix tool (SMT), Application configuration tool (ACT), which connects the residual/neutral current input to the fourth input channel of the preprocessing function block 6). Note that this connection in SMT shall not be done if the residual/neutral current is not connected to the IED. In that case the pre-processing block will calculate it by vectorial summation of the three individual phase currents.

6) is a Preprocessing block that has the task to digitally filter the connected analog inputs and calculate:

fundamental frequency phasors for all four input channels harmonic content for all four input channels positive, negative and zero sequence quantities by using the fundamental frequency

phasors for the first three input channels (channel one taken as reference for sequence quantities)

These calculated values are then available for all built-in protection and control functions within the IED, which are connected to this preprocessing function block in the configuration tool. For this application most of the preprocessing settings can be left to the default values. If frequency tracking and compensation is required (this feature is typically required only for IEDs installed in the generating stations), then the setting parameters DFTReference shall be set accordingly.

4.2.2.6 Example how to connect delta connected three-phase CT set to the IED

Figure 15 gives an example how to connect a delta connected three-phase CT set to the IED. It gives an overview of the required actions by the user in order to make this measurement available to the built-in protection and control functions in the IED as well.

For correct terminal designations, see the connection diagrams valid for the delivered IED.

Section 4 1MRK 511 310-UEN B Analog inputs

66 Application manual

L1

IL 1

IL 2

IL 3

L2 L3

Protected Object

IED

C T 6

0 0 /5

in D

e lta

D A

B C

o nn

e c te

d

IL1-IL2

IL2-IL3

IL3-IL1

1 2

3 4

IEC11000027-3-en.vsdx

SMAI2

BLOCK

REVROT

^GRP2L1

^GRP2L2

^GRP2L3

^GRP2N

AI3P

AI1

AI2

AI3

AI4

AIN

IEC11000027 V3 EN

Figure 15: Delta DAB connected three-phase CT set

1MRK 511 310-UEN B Section 4 Analog inputs

67 Application manual

Where:

1) shows how to connect three individual phase currents from a delta connected three-phase CT set to three CT inputs of the IED.

2) is the TRM where these current inputs are located. It shall be noted that for all these current inputs the following setting values shall be entered. CTprim=600A CTsec=5A

CTStarPoint=ToObject ConnectionType=Ph-Ph

3) are three connections made in Signal Matrix Tool (SMT), Application configuration tool (ACT), which connect these three current inputs to first three input channels of the preprocessing function block 4). Depending on the type of functions which need this current information, more then one preprocessing block might be connected in parallel to these three CT inputs.

4) is a Preprocessing block that has the task to digitally filter the connected analog inputs and calculate:

fundamental frequency phasors for all three input channels harmonic content for all three input channels positive, negative and zero sequence quantities by using the fundamental frequency

phasors for the first three input channels (channel one taken as reference for sequence quantities)

These calculated values are then available for all built-in protection and control functions within the IED, which are connected to this preprocessing function block. For this application most of the preprocessing settings can be left to the default values. If frequency tracking and compensation is required (this feature is typically required only for IEDs installed in the generating stations) then the setting parameters DFTReference shall be set accordingly.

Another alternative is to have the delta connected CT set as shown in figure 16:

Section 4 1MRK 511 310-UEN B Analog inputs

68 Application manual

L1

IL 1

IL 2

IL 3

L2 L3

Protected Object

IED

C T 8

0 0 /1

in D

e lta

D A

C C

o n n e ct

e d

IL3-IL2

IL2-IL1

IL1-IL3

2

3

4

IEC11000028-3-en.vsdx

SMAI2

BLOCK

REVROT

^GRP2L1

^GRP2L2

^GRP2L3

^GRP2N

AI3P

AI1

AI2

AI3

AI4

AIN

1

IEC11000028 V3 EN

Figure 16: Delta DAC connected three-phase CT set

In this case, everything is done in a similar way as in the above described example, except that for all used current inputs on the TRM the following setting parameters shall be entered:

CTprim=800A

CTsec=1A

CTStarPoint=ToObject ConnectionType=Ph-Ph

It is important to notice the references in SMAI. As inputs at Ph-Ph are expected to be L1L2, L2L3 respectively L3L1 we need to tilt 180 by setting ToObject.

4.2.2.7 Example how to connect single-phase CT to the IED

Figure 17 gives an example how to connect the single-phase CT to the IED. It gives an overview of the required actions by the user in order to make this measurement available to the built-in protection and control functions within the IED as well.

For correct terminal designations, see the connection diagrams valid for the delivered IED.

1MRK 511 310-UEN B Section 4 Analog inputs

69 Application manual

Protected Object

L1 L2 L3

IED

IN P

INS

INS

2

IEC11000029-4-en.vsdx

4

3

C T

1 0

0 0

/1

a)

b)

(+)

(+)

(-)

(-) (+)

(-)

1 SMAI2

BLOCK

REVROT

^GRP2L1

^GRP2L2

^GRP2L3

^GRP2N

AI3P

AI1

AI2

AI3

AI4

AIN

IEC11000029 V4 EN

Figure 17: Connections for single-phase CT input

Where:

1) shows how to connect single-phase CT input in the IED.

2) is TRM where these current inputs are located. It shall be noted that for all these current inputs the following setting values shall be entered. For connection (a) shown in figure 17: CTprim = 1000 A CTsec = 1A CTStarPoint=ToObject For connection (b) shown in figure 17: CTprim = 1000 A CTsec = 1A CTStarPoint=FromObject

3) shows the connection made in SMT tool, which connect this CT input to the fourth input channel of the preprocessing function block 4).

4) is a Preprocessing block that has the task to digitally filter the connected analog inputs and calculate values. The calculated values are then available for all built-in protection and control functions within the IED, which are connected to this preprocessing function block. If frequency tracking and compensation is required (this feature is typically required only for IEDs installed in the power plants) then the setting parameters DFTReference shall be set accordingly.

Section 4 1MRK 511 310-UEN B Analog inputs

70 Application manual

4.2.3 Setting of voltage channels

As the IED uses primary system quantities the main VT ratios must be known to the IED. This is done by setting the two parameters VTsec and VTprim for each voltage channel. The phase-to-phase value can be used even if each channel is connected to a phase-to-earth voltage from the VT.

4.2.3.1 Example

Consider a VT with the following data:

132 110 3 3 kV V

EQUATION2016 V1 EN (Equation 1)

The following setting should be used: VTprim=132 (value in kV) VTsec=110 (value in V)

4.2.3.2 Examples how to connect, configure and set VT inputs for most commonly used VT connections

Figure 18 defines the marking of voltage transformer terminals commonly used around the world.

A (H1)

B (H2)

b (X2)

a (X1)

A (H1)

N (H2)

n (X2)

a (X1)

b) c)

A (H1)

N (H2)

dn (X2)

da (X1)

d)

UPri

+ + USec

a)

en06000591.vsd

IEC06000591 V1 EN

Figure 18: Commonly used markings of VT terminals

Where:

a) is the symbol and terminal marking used in this document. Terminals marked with a square indicate the primary and secondary winding terminals with the same (positive) polarity

b) is the equivalent symbol and terminal marking used by IEC (ANSI) standard for phase-to- earth connected VTs

c) is the equivalent symbol and terminal marking used by IEC (ANSI) standard for open delta connected VTs

d) is the equivalent symbol and terminal marking used by IEC (ANSI) standard for phase-to- phase connected VTs

1MRK 511 310-UEN B Section 4 Analog inputs

71 Application manual

It shall be noted that depending on national standard and utility practices the rated secondary voltage of a VT has typically one of the following values:

100 V 110 V 115 V 120 V 230 V

The IED fully supports all of these values and most of them will be shown in the following examples.

4.2.3.3 Examples on how to connect a three phase-to-earth connected VT to the IED

Figure 19 gives an example on how to connect a three phase-to-earth connected VT to the IED. It as well gives overview of required actions by the user in order to make this measurement available to the built-in protection and control functions within the IED.

For correct terminal designations, see the connection diagrams valid for the delivered IED.

Section 4 1MRK 511 310-UEN B Analog inputs

72 Application manual

L1

IED L2

L3

66

3 110

3

kV

V

1

3

2

66

3 110

3

kV

V

66

3 110

3

kV

V

.

#Not used

5

IEC06000599-4-en.vsdx

4

SMAI2

BLOCK

REVROT

^GRP2L1

^GRP2L2

^GRP2L3

^GRP2N

AI3P

AI1

AI2

AI3

AI4

AIN

IEC06000599 V4 EN

Figure 19: A Three phase-to-earth connected VT

Where:

1) shows how to connect three secondary phase-to-earth voltages to three VT inputs on the IED

2) is the TRM where these three voltage inputs are located. For these three voltage inputs, the following setting values shall be entered: VTprim =66 kV VTsec = 110 V Inside the IED, only the ratio of these two parameters is used. It shall be noted that the ratio of the entered values exactly corresponds to ratio of one individual VT.

66 66 3

110110 3

=

EQUATION1903 V1 EN (Equation 2)

Table continues on next page

1MRK 511 310-UEN B Section 4 Analog inputs

73 Application manual

3) are three connections made in Signal Matrix Tool (SMT), which connect these three voltage inputs to first three input channels of the preprocessing function block 5). Depending on the type of functions which need this voltage information, more then one preprocessing block might be connected in parallel to these three VT inputs.

4) shows that in this example the fourth (that is, residual) input channel of the preprocessing block is not connected in SMT tool. Thus the preprocessing block will automatically calculate 3Uo inside by vectorial sum from the three phase to earth voltages connected to the first three input channels of the same preprocessing block. Alternatively, the fourth input channel can be connected to open delta VT input, as shown in figure 21.

5) is a Preprocessing block that has the task to digitally filter the connected analog inputs and calculate:

fundamental frequency phasors for all four input channels harmonic content for all four input channels positive, negative and zero sequence quantities by using the fundamental frequency

phasors for the first three input channels (channel one taken as reference for sequence quantities)

These calculated values are then available for all built-in protection and control functions within the IED, which are connected to this preprocessing function block in the configuration tool. For this application most of the preprocessing settings can be left to the default values. However the following settings shall be set as shown here: UBase=66 kV (that is, rated Ph-Ph voltage) If frequency tracking and compensation is required (this feature is typically required only for IEDs installed in the generating stations) then the setting parameters DFTReference shall be set accordingly.

4.2.3.4 Example on how to connect a phase-to-phase connected VT to the IED

Figure 20 gives an example how to connect a phase-to-phase connected VT to the IED. It gives an overview of the required actions by the user in order to make this measurement available to the built-in protection and control functions within the IED as well. It shall be noted that this VT connection is only used on lower voltage levels (that is, rated primary voltage below 40 kV).

Section 4 1MRK 511 310-UEN B Analog inputs

74 Application manual

L1

IED

L2

L3

13.8 120

kV V

1

2

#Not Used

13.8 120

kV V

.

5

IEC06000600-5-en.vsdx

4

SMAI2

BLOCK

REVROT

^GRP2L1

^GRP2L2

^GRP2L3

^GRP2N

AI3P

AI1

AI2

AI3

AI4

AIN

3

IEC06000600 V5 EN

Figure 20: A Two phase-to-phase connected VT

Where:

1) shows how to connect the secondary side of a phase-to-phase VT to the VT inputs on the IED

2) is the TRM where these three voltage inputs are located. It shall be noted that for these three voltage inputs the following setting values shall be entered: VTprim=13.8 kV VTsec=120 V Please note that inside the IED only ratio of these two parameters is used.

Table continues on next page

1MRK 511 310-UEN B Section 4 Analog inputs

75 Application manual

3) are three connections made in the Signal Matrix tool (SMT), Application configuration tool (ACT), which connects these three voltage inputs to first three input channels of the preprocessing function block 5). Depending on the type of functions, which need this voltage information, more than one preprocessing block might be connected in parallel to these three VT inputs

4) shows that in this example the fourth (that is, residual) input channel of the preprocessing block is not connected in SMT. Note. If the parameters UL1, UL2, UL3, UN should be used the open delta must be connected here.

5) Preprocessing block has a task to digitally filter the connected analog inputs and calculate:

fundamental frequency phasors for all four input channels harmonic content for all four input channels positive, negative and zero sequence quantities by using the fundamental frequency

phasors for the first three input channels (channel one taken as reference for sequence quantities)

These calculated values are then available for all built-in protection and control functions within the IED, which are connected to this preprocessing function block in the configuration tool. For this application most of the preprocessing settings can be left to the default values. However the following settings shall be set as shown here: ConnectionType=Ph-Ph UBase=13.8 kV If frequency tracking and compensation is required (this feature is typically required only for IEDs installed in the generating stations) then the setting parameters DFTReference shall be set accordingly.

4.2.3.5 Example on how to connect an open delta VT to the IED for high impedance earthed or unearthed netwoeks

Figure 21 gives an example about the wiring of an open delta VT to the IED for high impedance earthed or unearthed power systems. It shall be noted that this type of VT connection presents a secondary voltage proportional to 3U0 to the IED.

In case of a solid earth fault close to the VT location the primary value of 3Uo will be equal to:

3 0 3 3Ph Ph Ph NU U U— -= = EQUATION1921 V3 EN (Equation 3)

The primary rated voltage of an open Delta VT is always equal to UPh-E. Three series connected VT secondary windings gives a secondary voltage equal to three times the individual VT secondary winding rating. Thus the secondary windings of open delta VTs quite often have a secondary rated voltage equal to one third of the rated phase- to-phase VT secondary voltage (110/3V in this particular example).

Figure 21 gives overview of required actions by the user in order to make this measurement available to the built-in protection and control functions within the IED as well.

Section 4 1MRK 511 310-UEN B Analog inputs

76 Application manual

L1

IED L2

L3

6.6

3 110

3

kV

V

+3Uo

6.6

3 110

3

kV

V

6.6

3 110

3

kV

V

1

2

4

3

# Not Used

5

IEC06000601-4-en.vsdx

# Not Used

# Not Used

SMAI2

BLOCK

REVROT

^GRP2L1

^GRP2L2

^GRP2L3

^GRP2N

AI3P

AI1

AI2

AI3

AI4

AIN

IEC06000601 V4 EN

Figure 21: Open delta connected VT in high impedance earthed power system

1MRK 511 310-UEN B Section 4 Analog inputs

77 Application manual

Where:

1) shows how to connect the secondary side of the open delta VT to one VT input on the IED.

+3U0 shall be connected to the IED

2) is the TRM where this voltage input is located. It shall be noted that for this voltage input the following setting values shall be entered:

3 6.6 11.43VTprim kV= =

EQUATION1923 V1 EN (Equation 4)

110 sec 3 110

3 VT V= =

EQUATION1924 V1 EN (Equation 5)

Inside the IED, only the ratio of these two parameters is used. It shall be noted that the ratio of the entered values exactly corresponds to ratio of one individual open delta VT.

6.6 3 6.6 3

110110 3

=

EQUATION1925 V1 EN (Equation 6)

3) shows that in this example the first three input channel of the preprocessing block is not connected in SMT tool or ACT tool.

4) shows the connection made in Signal Matrix Tool (SMT), Application configuration tool (ACT), which connect this voltage input to the fourth input channel of the preprocessing function block 5).

5) is a Preprocessing block that has the task to digitally filter the connected analog input and calculate:

fundamental frequency phasors for all four input channels harmonic content for all four input channels positive, negative and zero sequence quantities by using the fundamental frequency

phasors for the first three input channels (channel one taken as reference for sequence quantities)

These calculated values are then available for all built-in protection and control functions within the IED, which are connected to this preprocessing function block in the configuration tool. For this application most of the preprocessing settings can be left to the default values. If frequency tracking and compensation is required (this feature is typically required only for IEDs installed in the generating stations ) then the setting parameters DFTReference shall be set accordingly.

Section 4 1MRK 511 310-UEN B Analog inputs

78 Application manual

4.2.3.6 Example how to connect the open delta VT to the IED for low impedance earthed or solidly earthed power systems

Figure 22 gives an example about the connection of an open delta VT to the IED for low impedance earthed or solidly earthed power systems. It shall be noted that this type of VT connection presents secondary voltage proportional to 3U0 to the IED.

In case of a solid earth fault close to the VT location the primary value of 3Uo will be equal to:

3 3

Ph Ph Ph E

U Uo U—

-= =

EQUATION1926 V1 EN (Equation 7)

The primary rated voltage of such VT is always equal to UPh-E Therefore, three series connected VT secondary windings will give the secondary voltage equal only to one individual VT secondary winding rating. Thus the secondary windings of such open delta VTs quite often has a secondary rated voltage close to rated phase-to-phase VT secondary voltage, that is, 115V or 115/3V as in this particular example. Figure 22 gives an overview of the actions which are needed to make this measurement available to the built-in protection and control functions within the IED.

1

L1

IED L2

L3

138

3 115

3

kV

V

+3Uo

138

3 115

3

kV

V

138

3 115

3

kV

V

IEC06000602-4-en.vsdx

# Not Used

# Not Used

# Not Used

SMAI2

BLOCK

REVROT

^GRP2L1

^GRP2L2

^GRP2L3

^GRP2N

AI3P

AI1

AI2

AI3

AI4

AIN

2

3

4

5

IEC06000602 V4 EN

Figure 22: Open delta connected VT in low impedance or solidly earthed power system

1MRK 511 310-UEN B Section 4 Analog inputs

79 Application manual

Where:

1) shows how to connect the secondary side of open delta VT to one VT input in the IED.

+3Uo shall be connected to the IED.

2) is TRM where this voltage input is located. It shall be noted that for this voltage input the following setting values shall be entered:

138 3 138

3 VTprim kV= =

EQUATION1928 V1 EN (Equation

115 sec 3 115

3 VT V= =

EQUATION1929 V1 EN (Equation 9)

Inside the IED, only the ratio of these two parameters is used. It shall be noted that the ratio of the entered values exactly corresponds to ratio of one individual open delta VT.

138 138 3

115115 3

=

EQUATION1930 V1 EN (Equation 10)

3) shows that in this example the first three input channel of the preprocessing block is not connected in SMT tool.

4) shows the connection made in Signal Matrix Tool (SMT), which connect this voltage input to the fourth input channel of the preprocessing function block 4).

5) preprocessing block has a task to digitally filter the connected analog inputs and calculate:

fundamental frequency phasors for all four input channels harmonic content for all four input channels positive, negative and zero sequence quantities by using the fundamental

frequency phasors for the first three input channels (channel one taken as reference for sequence quantities)

These calculated values are then available for all built-in protection and control functions within the IED, which are connected to this preprocessing function block in the configuration tool. For this application most of the preprocessing settings can be left to the default values. If frequency tracking and compensation is required (this feature is typically required only for IEDs installed in the generating stations) then the setting parameters DFTReference shall be set accordingly.

4.2.3.7 Example on how to connect a neutral point VT to the IED

Figure 23 gives an example on how to connect a neutral point VT to the IED. This type of VT connection presents secondary voltage proportional to U0 to the IED.

Section 4 1MRK 511 310-UEN B Analog inputs

80 Application manual

In case of a solid earth fault in high impedance earthed or unearthed systems the primary value of Uo voltage will be equal to:

0 3

Ph Ph Ph E

UU U— -= =

EQUATION1931 V2 EN (Equation 11)

Figure 23 gives an overview of required actions by the user in order to make this measurement available to the built-in protection and control functions within the IED as well.

L1 L2 L3

IED

6.6

3 100

kV

V

R Uo

IEC06000603-4-en.vsdx

# Not Used

# Not Used

# Not Used

Protected Object

SMAI2

BLOCK

REVROT

^GRP2L1

^GRP2L2

^GRP2L3

^GRP2N

AI3P

AI1

AI2

AI3

AI4

AIN

1

2

3

4

5

IEC06000603 V4 EN

Figure 23: Neutral point connected VT

1MRK 511 310-UEN B Section 4 Analog inputs

81 Application manual

Where:

1) shows how to connect the secondary side of neutral point VT to one VT input in the IED.

U0 shall be connected to the IED.

2) is the TRM or AIM where this voltage input is located. For this voltage input the following setting values shall be entered:

6.6 3.81

3 VTprim kV= =

EQUATION1933 V1 EN (Equation 12)

sec 100VT V=

EQUATION1934 V1 EN (Equation 13)

Inside the IED, only the ratio of these two parameters is used. It shall be noted that the ratio of the entered values exactly corresponds to ratio of the neutral point VT.

3) shows that in this example the first three input channel of the preprocessing block is not connected in SMT tool or ACT tool.

4) shows the connection made in Signal Matrix Tool (SMT), Application configuration tool (ACT), which connects this voltage input to the fourth input channel of the preprocessing function block 5).

5) is a preprocessing block that has the task to digitally filter the connected analog inputs and calculate:

fundamental frequency phasors for all four input channels harmonic content for all four input channels positive, negative and zero sequence quantities by using the fundamental frequency

phasors for the first three input channels (channel one taken as reference for sequence quantities)

These calculated values are then available for all built-in protection and control functions within the IED, which are connected to this preprocessing function block in the configuration tool. For this application most of the preprocessing settings can be left to the default values. If frequency tracking and compensation is required (this feature is typically required only for IEDs installed in the generating stations) then the setting parameters DFTReference shall be set accordingly.

Section 4 1MRK 511 310-UEN B Analog inputs

82 Application manual

Section 5 Local HMI

IEC13000239-2-en.vsd

IEC13000239 V2 EN

Figure 24: Local human-machine interface

The LHMI of the IED contains the following elements:

1MRK 511 310-UEN B Section 5 Local HMI

83 Application manual

Keypad Display (LCD) LED indicators Communication port for PCM600

The LHMI is used for setting, monitoring and controlling.

5.1 Display

The LHMI includes a graphical monochrome display with a resolution of 320 x 240 pixels. The character size can vary. The amount of characters and rows fitting the view depends on the character size and the view that is shown.

The display view is divided into four basic areas.

IEC13000063-2-en.vsd

1

3 4

2

IEC13000063 V2 EN

Figure 25: Display layout

1 Path

2 Content

3 Status

4 Scroll bar (appears when needed)

Section 5 1MRK 511 310-UEN B Local HMI

84 Application manual

The function button panel shows on request what actions are possible with the function buttons. Each function button has a LED indication that can be used as a feedback signal for the function button control action. The LED is connected to the required signal with PCM600.

IEC13000281-1-en.vsd

GUID-C98D972D-D1D8-4734-B419-161DBC0DC97B V1 EN

Figure 26: Function button panel

The alarm LED panel shows on request the alarm text labels for the alarm LEDs. Three alarm LED pages are available.

IEC13000240-1-en.vsd

GUID-5157100F-E8C0-4FAB-B979-FD4A971475E3 V1 EN

Figure 27: Alarm LED panel

The function button and alarm LED panels are not visible at the same time. Each panel is shown by pressing one of the function buttons or the Multipage button. Pressing the ESC button clears the panel from the display. Both the panels have dynamic width that depends on the label string length that the panel contains.

1MRK 511 310-UEN B Section 5 Local HMI

85 Application manual

5.2 LEDs

The LHMI includes three protection status LEDs above the display: Ready, Start and Trip.

There are 15 programmable alarm LEDs on the front of the LHMI. Each LED can indicate three states with the colors: green, yellow and red. The alarm texts related to each three-color LED are divided into three pages.

5.3 Keypad

The LHMI keypad contains push-buttons which are used to navigate in different views or menus. The push-buttons are also used to acknowledge alarms, reset indications, provide help and switch between local and remote control mode.

The keypad also contains programmable push-buttons that can be configured either as menu shortcut or control buttons.

Section 5 1MRK 511 310-UEN B Local HMI

86 Application manual

1

18

19

7

6

5

4

3

2

8

20

21

22

17161514131211109

23

24

IEC15000157-2-en.vsd

IEC15000157 V2 EN

Figure 28: LHMI keypad with object control, navigation and command push- buttons and RJ-45 communication port

1…5 Function button

6 Close

7 Open

8 Escape

9 Left

10 Down

11 Up

12 Right

13 Key

14 Enter

15 Remote/Local

16 Uplink LED

17 Not in use

18 Multipage

1MRK 511 310-UEN B Section 5 Local HMI

87 Application manual

19 Menu

20 Clear

21 Help

22 Communication port

23 Programmable indication LEDs

24 IED status LEDs

5.4 Local HMI functionality

5.4.1 Protection and alarm indication

Protection indicators The protection indicator LEDs are Ready, Start and Trip.

The start and trip LEDs are configured via the disturbance recorder. The yellow and red status LEDs are configured in the disturbance recorder function, DRPRDRE, by connecting a start or trip signal from the actual function to a BxRBDR binary input function block using the PCM600 and configure the setting to Off, Start or Trip for that particular signal.

Table 3: Ready LED (green)

LED state Description Off Auxiliary supply voltage is disconnected.

On Normal operation.

Flashing Internal fault has occurred.

Table 4: Start LED (yellow)

LED state Description Off Normal operation.

On A protection function has started and an indication message is displayed. The start indication is latching and must be reset via communication, LHMI or binary input on the LEDGEN component. To open the reset menu on the LHMI, press .

Flashing The IED is in test mode and protection functions are blocked, or the IEC61850 protocol is blocking one or more functions. The indication disappears when the IED is no longer in test mode and blocking is removed. The blocking of functions through the IEC61850 protocol can be reset in Main menu/Test/Reset IEC61850 Mod. The yellow LED changes to either On or Off state depending on the state of operation.

Section 5 1MRK 511 310-UEN B Local HMI

88 Application manual

Table 5: Trip LED (red)

LED state Description Off Normal operation.

On A protection function has tripped. An indication message is displayed if the auto-indication feature is enabled in the local HMI. The trip indication is latching and must be reset via communication, LHMI or binary input on the LEDGEN component. To open the reset menu on the LHMI, press .

Flasing Configuration mode.

Alarm indicators The 15 programmable three-color LEDs are used for alarm indication. An individual alarm/status signal, connected to any of the LED function blocks, can be assigned to one of the three LED colors when configuring the IED.

Table 6: Alarm indications

LED state Description Off Normal operation. All activation signals are off.

On Follow-S sequence: The activation signal is on. LatchedColl-S sequence: The activation signal is on, or it is off but the indication

has not been acknowledged. LatchedAck-F-S sequence: The indication has been acknowledged, but the

activation signal is still on. LatchedAck-S-F sequence: The activation signal is on, or it is off but the indication

has not been acknowledged. LatchedReset-S sequence: The activation signal is on, or it is off but the indication

has not been acknowledged.

Flashing Follow-F sequence: The activation signal is on. LatchedAck-F-S sequence: The activation signal is on, or it is off but the indication

has not been acknowledged. LatchedAck-S-F sequence: The indication has been acknowledged, but the

activation signal is still on.

5.4.2 Parameter management

The LHMI is used to access the relay parameters. Three types of parameters can be read and written.

Numerical values String values Enumerated values

Numerical values are presented either in integer or in decimal format with minimum and maximum values. Character strings can be edited character by character. Enumerated values have a predefined set of selectable values.

1MRK 511 310-UEN B Section 5 Local HMI

89 Application manual

5.4.3 Front communication

The RJ-45 port in the LHMI enables front communication.

The green uplink LED on the left is lit when the cable is successfully connected to the port.

GUID-D71BA06D-3769-4ACB-8A32-5D02EA473326 V1 EN

Figure 29: RJ-45 communication port and green indicator LED

1 RJ-45 connector

2 Green indicator LED

Section 5 1MRK 511 310-UEN B Local HMI

90 Application manual

Section 6 Differential protection

6.1 1Ph High impedance differential protection HZPDIF

6.1.1 Identification

Function description IEC 61850 identification

IEC 60617 identification

ANSI/IEEE C37.2 device number

1Ph High impedance differential protection HZPDIF Id

SYMBOL-CC V2 EN

87

6.1.2 Application

The 1Ph High impedance differential protection function HZPDIF can be used as:

Generator differential protection Reactor differential protection Busbar differential protection Autotransformer differential protection (for common and serial windings only) T-feeder differential protection Capacitor differential protection Restricted earth fault protection for transformer, generator and shunt reactor

windings Restricted earth fault protection

The application is dependent on the primary system arrangements and location of breakers, available CT cores and so on.

1MRK 511 310-UEN B Section 6 Differential protection

91 Application manual

3Id

3IdId

3Id

3Id

G

3Id

IEC05000163-4-en.vsd

IEC05000163 V4 EN

Section 6 1MRK 511 310-UEN B Differential protection

92 Application manual

3Id

Z<

3Id

Z<

IEC05000738-3-en.vsd

IEC05000738 V3 EN

Figure 30: Different applications of a 1Ph High impedance differential protection HZPDIF function

6.1.2.1 The basics of the high impedance principle

The high impedance differential protection principle has been used for many years and is well documented in literature publicly available. Its operating principle provides very good sensitivity and high speed operation. One main benefit offered by the principle is an absolute stability (that is, no operation) for external faults even in the presence of heavy CT saturation. The principle is based on the CT secondary current circulating between involved current transformers and not through the IED due to high impedance in the measuring branch. This stabilizing resistance is in the range of hundreds of ohms and sometimes above one kilo Ohm. When an internal fault occurs the current cannot circulate and is forced through the measuring branch causing relay operation.

It should be remembered that the whole scheme, its built-in components and wiring must be adequately maintained throughout the lifetime of the equipment in order to be able to withstand the high voltage peaks (that is, pulses) which may appear during an internal fault. Otherwise any flash-over in CT secondary circuits or any other part of the scheme may prevent correct operation of the high impedance differential relay for an actual internal fault.

1MRK 511 310-UEN B Section 6 Differential protection

93 Application manual

Id

IEC05000164-2-en.vsd

R

Metrosil

IEC05000164 V3 EN

Figure 31: Example for the high impedance restricted earth fault protection application

For a through fault one current transformer might saturate when the other CTs still will feed current. For such a case a voltage will be developed across the measuring branch. The calculations are made with the worst situations in mind and a minimum operating voltage UR is calculated according to equation 14

( )maxUR IF Rct Rl> + EQUATION1531 V1 EN (Equation 14)

where:

IFmax is the maximum through fault current at the secondary side of the CT

Rct is the current transformer secondary winding resistance and

Rl is the maximum loop resistance of the circuit at any CT.

Section 6 1MRK 511 310-UEN B Differential protection

94 Application manual

The minimum operating voltage has to be calculated (all loops) and the IED function is set higher than the highest achieved value (setting U>Trip). As the loop resistance is the value to the connection point from each CT, it is advisable to do all the CT core summations in the switchgear to have shortest possible loops. This will give lower setting values and also a better balanced scheme. The connection in to the control room can then be from the most central bay.

For an internal fault, all involved CTs will try to feed current through the measuring branch. Depending on the size of current transformer, relatively high voltages will be developed across the series resistor. Note that very high peak voltages can appear. To prevent the risk of flashover in the circuit, a voltage limiter must be included. The voltage limiter is a voltage dependent resistor (Metrosil).

The external unit with stabilizing resistor has a value of either 6800 ohms or 1800 ohms (depending on ordered alternative) with a sliding link to allow adjustment to the required value. Select a suitable value of the resistor based on the UR voltage calculated. A higher resistance value will give a higher sensitivity and a lower value a lower sensitivity of the relay.

The function has a recommended operating current range 40 mA to 1.0A for 1 A inputs and 200 mA to 5A for 5A inputs. This, together with the selected and set value, is used to calculate the required value of current at the set U>Trip and SeriesResitor values.

The CT inputs used for 1Ph High impedance differential protection HZPDIF function, shall be set to have ratio 1:1. So the parameters CTsecx and CTprimx of the relevant channel x of TRM and/or AIM shall be set equal to 1 A by PST in PCM600; The parameter CTStarPointx may be set to ToObject.

The tables 7, 8 below show, the operating currents for different settings of operating voltages and selected resistances. Adjust as required based on tables 7, 8 or to values in between as required for the application.

Minimum ohms can be difficult to adjust due to the small value compared to the total value.

Normally the voltage can be increased to higher values than the calculated minimum U>Trip with a minor change of total operating values as long as this is done by adjusting the resistor to a higher value. Check the sensitivity calculation below for reference.

Table 7: 1 A channels: input with minimum operating down to 20 mA

Operating voltage U>Trip

Stabilizing resistor R ohms

Operating current level 1 A

Stabilizing resistor R ohms

Operating current level 1 A

Stabilizing resistor R ohms

Operating current level 1 A

20 V 1000 0.020 A — — — —

40 V 2000 0.020 A 1000 0.040 A — —

60 V 3000 0.020 A 1500 0.040 A 600 0.100 A

Table continues on next page

1MRK 511 310-UEN B Section 6 Differential protection

95 Application manual

Operating voltage U>Trip

Stabilizing resistor R ohms

Operating current level 1 A

Stabilizing resistor R ohms

Operating current level 1 A

Stabilizing resistor R ohms

Operating current level 1 A

80 V 4000 0.020 A 2000 0.040 A 800 0.100 A

100 V 5000 0.020 A 2500 0.040 A 1000 0.100 A

150 V 6000 0.020 A 3750 0.040 A 1500 0.100 A

200 V 6800 0.029 A 5000 0.040 A 2000 0.100 A

Table 8: 5 A channels: input with minimum operating down to 100 mA

Operating voltage U>Trip

Stabilizing resistor R1 ohms

Operating current level 5 A

Stabilizing resistor R1 ohms

Operating current level 5 A

Stabilizing resistor R1 ohms

Operating current level 5 A

20 V 200 0.100 A 100 0.200 A — —

40 V 400 0.100 A 200 0.200 A 100 0.400

60 V 600 0.100 A 300 0.200 A 150 0.400 A

80 V 800 0.100 A 400 0.200 A 200 0.400 A

100 V 1000 0.100 A 500 0.200 A 250 0.400 A

150 V 1500 0.100 A 750 0.200 A 375 0.400 A

200 V 2000 0.100 A 1000 0.200 A 500 0.400 A

The current transformer saturation voltage must be at least 2 U>Trip to have sufficient operating margin. This must be checked after calculation of U>Trip.

When the R value has been selected and the U>Trip value has been set, the sensitivity of the scheme IP can be calculated. The IED sensitivity is decided by the total current in the circuit according to equation 15.

( )IP n IR Ires lmag= + + EQUATION1747 V1 EN (Equation 15)

where:

n is the CT ratio

IP primary current at IED pickup,

IR IED pickup current (U>Trip/SeriesResistor)

Ires is the current through the voltage limiter and

Imag is the sum of the magnetizing currents from all CTs in the circuit (for example, 4 for restricted earth fault protection, 2 for reactor differential protection, 3-5 for autotransformer differential protection).

It should be remembered that the vectorial sum of the currents must be used (IEDs, Metrosil and resistor currents are resistive). The current measurement is insensitive to DC component in fault current to allow the use of only the AC components of the fault current in the above calculations.

Section 6 1MRK 511 310-UEN B Differential protection

96 Application manual

The voltage dependent resistor (Metrosil) characteristic is shown in Figure 37.

Series resistor thermal capacity The series resistor is dimensioned for 200 W. Preferable the U>Trip2/SeriesResistor should always be lower than 200 W to allow continuous activation during testing. If this value is exceeded, testing should be done with a transient faults.

1MRK 511 310-UEN B Section 6 Differential protection

97 Application manual

I>

R

Rres

Rl

Rct Rct

Rl

UR

a) Through load situation

b) Through fault situation

UR

UR

c) Internal faults

UR

Protected Object

IEC05000427-2-en.vsd

IEC05000427 V2 EN

Figure 32: The high impedance principle for one phase with two current transformer inputs

Section 6 1MRK 511 310-UEN B Differential protection

98 Application manual

6.1.3 Connection examples for high impedance differential protection

WARNING! USE EXTREME CAUTION! Dangerously high voltages might be present on this equipment, especially on the plate with resistors. De-energize the primary object protected with this equipment before connecting or disconnecting wiring or performing any maintenance. The plate with resistors should be provided with a protective cover, mounted in a separate box or in a locked cubicle. National law and standards shall be followed.

6.1.3.1 Connections for three-phase high impedance differential protection

Generator, reactor or busbar differential protection is a typical application for three- phase high impedance differential protection. Typical CT connections for three-phase high impedance differential protection scheme are shown in figure 33.

L1 (A)

L2 (B)

L3 (C)

Protected Object

CT 1200/1 Star/Wye

Connected

L1 (A)

L2 (B)

L3 (C)

CT 1200/1 Star/Wye

Connected

7

8

9 1 01 11 2

1

2

3

4

5

6

AI01 (I)

AI02 (I)

AI03 (I)

AI04 (I)

AI05 (I)

AI06 (I)

7

6

X1

R 4

R 5

R 6

1 2

1 2

1 2

11 12 13 14

U U U R 1

1 3

4

2

1 3

R 2

2

4

1 3

R 3

2

4

1 2 3 4 5 6 7

L1 (A)

L2 (B)

L3 (C) N

3-Ph Plate with Metrosils and Resistors

2

3

5

4

X X

L1 (A)

L2 (B)

L3 (C) N

1

IED

IEC07000193_4_en.vsd

AI3P

AI1

AI2

AI3

AI4

AIN

SMAI2

BLOCK

^GRP2L1

^GRP2L2

^GRP2L3

^GRP2N

TYPE

IEC07000193 V4 EN

Figure 33: CT connections for high impedance differential protection

1MRK 511 310-UEN B Section 6 Differential protection

99 Application manual

Pos Description

1 Scheme earthing point

It is important to insure that only one earthing point exist in this scheme.

2 Three-phase plate with setting resistors and metrosils. Protective earth is a separate 4 mm screw terminal on the plate.

3 Necessary connection for three-phase metrosil set.

4 Position of optional test switch for secondary injection into the high impedance differential IED.

5 Necessary connection for setting resistors.

6 Factory-made star point on a three-phase setting resistor set.

The star point connector must be removed for installations with 670 series IEDs. This star point is required for RADHA schemes only.

7 Connections of three individual phase currents for high impedance scheme to three CT inputs in the IED.

6.1.3.2 Connections for 1Ph High impedance differential protection HZPDIF

Restricted earth fault protection REFPDIF is a typical application for 1Ph High impedance differential protection HZPDIF. Typical CT connections for high impedance based REFPDIF protection scheme are shown in figure 34.

Section 6 1MRK 511 310-UEN B Differential protection

100 Application manual

L1 (A)

L2 (B)

L3 (C)

Protected Object

CT 1500/5 Star/Wye

Connected

7

8

9

10

11

12

1

2

3

4

5

6

AI01 (I)

AI02 (I)

AI03 (I)

AI04 (I)

AI05 (I)

AI06 (I)

6

X1

R 1

1 2

4 5

U R 2

1 3

4

2

1 2 3

N

1-Ph Plate with Metrosil and Resistor

2 3

5

4

N

L1 (A)

L2 (B)

L3 (C)

C T

15 00

/5 1

IEC07000194_4_en.vsd

AI3P

AI1

AI2

AI3

AI4

AIN

SMAI2

BLOCK

^GRP2L1

^GRP2L2

^GRP2L3

^GRP2N

TYPE

IEC07000194 V4 EN

Figure 34: CT connections for restricted earth fault protection

Pos Description

1 Scheme earthing point

Ensure that only one earthing point exists in this scheme.

2 One-phase plate with stabilizing resistor and metrosil. Protective earth is a separate 4 mm screw terminal on the plate.

3 Necessary connection for the metrosil.

4 Position of optional test switch for secondary injection into the high impedance differential IED.

5 Necessary connection for stabilizing resistor.

6 How to connect REFPDIF high impedance scheme to one CT input in IED.

6.1.4 Setting guidelines

The setting calculations are individual for each application. Refer to the different application descriptions below.

6.1.4.1 Configuration

The configuration is done in the Application Configuration tool.

1MRK 511 310-UEN B Section 6 Differential protection

101 Application manual

6.1.4.2 Settings of protection function

Operation: The operation of the high impedance differential function can be switched On or Off.

U>Alarm: Set the alarm level. The sensitivity can roughly be calculated as a certain percentage of the selected Trip level. A typical setting is 10% of U>Trip This alarm stage can be used for scheme CT supervision.

tAlarm: Set the time delay for the alarm. A typical setting is 2-3 seconds.

U>Trip: Set the trip level according to the calculations (see examples below for a guidance). The level is selected with margin to the calculated required voltage to achieve stability. Values can be within 20V — 400V range dependent on the application.

SeriesResistor: Set the value of the used stabilizing series resistor. Calculate the value according to the examples for each application. Adjust the resistor as close as possible to the calculated value. Measure the value achieved and set this value for this parameter.

The value shall always be high impedance. This means for example, for 1A circuits say bigger than 400 ohms (400 VA) and for 5 A circuits say bigger than 100 ohms (2500 VA). This ensures that the current will circulate and not go through the differential circuit at through faults.

That the settings of U>Alarm, U>Trip and SeriesResistor must be chosen such that both U>Alarm/SeriesResistor and U>Trip/ SeriesResistor are >4% of IRated of the used current input. Normally the settings shall also be such that U>Alarm/SeriesResistor and U>Trip/SeriesResistor both gives a value <4*IRated of the used current input. If not, the limitation in how long time the actual current is allowed to persist not to overload the current input must be considered especially during the secondary testing.

6.1.4.3 T-feeder protection

In many busbar arrangements such as one-and a half breaker, ring breaker, mesh corner, there will be a T-feeder from the current transformer at the breakers up to the current transformers in the feeder circuit (for example, in the transformer bushings). It is often required to separate the protection zones that the feeder is protected with one scheme while the T-zone is protected with a separate differential protection scheme. The 1Ph high impedance differential HZPDIF function in the IED allows this to be done efficiently, see Figure 35.

Section 6 1MRK 511 310-UEN B Differential protection

102 Application manual

3Id

IEC05000165-2-en.vsd

IEC05000165 V2 EN

3Id

IEC05000739-2-en.vsd

IEC05000739 V2 EN

Figure 35: The protection scheme utilizing the high impedance function for the T-feeder

1MRK 511 310-UEN B Section 6 Differential protection

103 Application manual

Normally this scheme is set to achieve a sensitivity of around 20 percent of the used CT primary rating so that a low ohmic value can be used for the series resistor.

It is strongly recommended to use the highest tap of the CT whenever high impedance protection is used. This helps in utilizing maximum CT capability, minimize the secondary fault current, thereby reducing the stability voltage limit. Another factor is that during internal faults, the voltage developed across the selected tap is limited by the non- linear resistor but in the unused taps, owing to auto-transformer action, voltages induced may be much higher than design limits.

Setting example Basic data: Current transformer ratio: 2000/1 A

CT Class: 20 VA 5P20

Secondary resistance: 6.2 ohms

Cable loop resistance: <100 m 2.5 mm2 (one way) gives 2 0.8 ohm at 75 C

Max fault current: Equal to switchgear rated fault current 40 kA

Calculation:

EQUATION1207 V2 EN (Equation 16)

Select a setting of U>Trip=200 V.

The current transformer saturation voltage must be at least twice the set operating voltage U>Trip.

( )5 20 6.2 20 524E P V> + =

EQUATION1208 V1 EN (Equation 17)

that is, bigger than 2 U>Trip

Check from the table of selected resistances the required series stabilizing resistor value to use. As this application requires to be so sensitive select SeriesResistor= 2000 ohm, which gives an IED operating current of 100 mA.

Calculate the primary sensitivity at operating voltage using the following equation.

Section 6 1MRK 511 310-UEN B Differential protection

104 Application manual

IP approx A= + + ( ) 2000

1 100 0 20 0 3 10 60 10 275

3

EQUATION1209 V2 EN (Equation 18)

where

100 mA is the current drawn by the IED circuit and

10 mA is the current drawn by each CT just at pickup

20 mA is current drawn by metrosil at pickup

The magnetizing current is taken from the magnetizing curve for the current transformer cores which should be available. The current value at U>Trip is taken. For the voltage dependent resistor current the peak value of voltage 200 2 is used. Then the RMS current is calculated by dividing obtained current value from the metrosil curve with2. Use the value from the maximum metrosil curve given in Figure 37

It can clearly be seen that the sensitivity is not so much influenced by the selected voltage level so a sufficient margin should be used. The selection of the stabilizing resistor and the level of the magnetizing current (mostly dependent of the number of turns) are the most important factors.

6.1.4.4 Tertiary reactor protection

Reactive power equipment (for example shunt reactors and/or shunt capacitors) can be connected to the tertiary winding of the power transformers. The 1Ph High impedance differential protection function HZPDIF can be used to protect the tertiary reactor for phase faults as well as earth faults if the power system of the tertiary winding is direct or low impedance earthed.

1MRK 511 310-UEN B Section 6 Differential protection

105 Application manual

3Id

IEC05000176-3-en.vsd

IEC05000176 V3 EN

Figure 36: Application of the1Ph High impedance differential protection HZPDIF function on a reactor

Setting example

It is strongly recommended to use the highest tap of the CT whenever high impedance protection is used. This helps in utilizing maximum CT capability, minimize the secondary fault, thereby reducing the stability voltage limit. Another factor is that during internal faults, the voltage developed across the selected tap is limited by the non-linear resistor but in the unused taps, owing to auto-transformer action, voltages much higher than design limits might be induced.

Section 6 1MRK 511 310-UEN B Differential protection

106 Application manual

Basic data: Current transformer ratio: 100/5 A (Note: Must be the same at all locations)

CT Class: 10 VA 5P20

Secondary resistance: 0.26 ohms

Cable loop resistance: <50 m 2.5mm2 (one way) gives 1 0.4 ohm at 75 C Note! Only one way as the tertiary power system earthing is limiting the earth-fault current. If high earth-fault current exists use two way cable length.

Max fault current: The maximum through fault current is limited by the reactor reactance and the inrush will be the worst for a reactor for example, 800 A.

Calculation:

UR > + = 800

100 5 0 26 0 4 26 4

/ ( . . ) ,

EQUATION1216 V2 EN (Equation 19)

Select a setting of U>Trip=30 V.

The current transformer saturation voltage must be at least, twice the set operating voltage U>Trip .

U CT Saturation V_ _ .> +

=

10

25 0 26 20 5 66

EQUATION1217 V2 EN (Equation 20)

that is, greater than 2 U>Trip.

Check from the table of selected resistances the required series stabilizing resistor value to use. Since this application requires good sensitivity, select SeriesResistor = 300 ohm, which gives an IED current of 100 mA.

To calculate the sensitivity at operating voltage, refer to equation 21, which gives an acceptable value. A little lower sensitivity could be selected by using a lower resistance value.

IP approx A= + + ( ) 100

5 100 0 5 0 2 100 60 10 5

3

EQUATION1218 V2 EN (Equation 21)

The magnetizing current is taken from the magnetizing curve of the current transformer cores, which should be available. The current value at U>Trip is taken. For the voltage dependent resistor current the peak value of voltage 30 2 is used. Then the RMS current is calculated by dividing obtained current value from the metrosil curve with 2. Use the maximum value from the metrosil curve given in Figure 37.

1MRK 511 310-UEN B Section 6 Differential protection

107 Application manual

6.1.4.5 Alarm level operation

The 1Ph High impedance differential protection HZPDIF function has a separate alarm level, which can be used to give alarm for problems with an involved current transformer circuit. The setting level is normally selected to be around 10% of the operating voltage U>Trip.

As seen in the setting examples above the sensitivity of HZPDIF function is normally high, which means that the function will in many cases operate also for short circuits or open current transformer secondary circuits. However the stabilizing resistor can be selected to achieve sensitivity higher than normal load current and/or separate criteria can be added to the operation, like a check zone. This can be either another IED, with the same HZPDIF function, or be a check about the fault condition, which is performed by an earth overcurrent function or neutral point voltage function.

For such cases where operation is not expected during normal service the alarm output should be used to activate an external shorting of the differential circuit avoiding continuous high voltage in the circuit. A time delay of a few seconds is used before the shorting and alarm are activated. Auxiliary relays with contacts that can withstand high voltage shall be used, like RXMVB types.

The metrosil operating characteristic is given in the following figure.

IEC05000749 V1 EN

Figure 37: Current voltage characteristics for the non-linear resistors, in the range 10-200 V, the average range of current is: 0.0110 mA

Section 6 1MRK 511 310-UEN B Differential protection

108 Application manual

Section 7 Current protection

7.1 Instantaneous phase overcurrent protection 3-phase output PHPIOC

7.1.1 Identification Function description IEC 61850

identification IEC 60617 identification

ANSI/IEEE C37.2 device number

Instantaneous phase overcurrent protection 3-phase output

PHPIOC

3I>>

SYMBOL-Z V1 EN

50

7.1.2 Application

Long transmission lines often transfer great quantities of electric power from production to consumption areas. The unbalance of the produced and consumed electric power at each end of the transmission line is very large. This means that a fault on the line can easily endanger the stability of a complete system.

The transient stability of a power system depends mostly on three parameters (at constant amount of transmitted electric power):

The type of the fault. Three-phase faults are the most dangerous, because no power can be transmitted through the fault point during fault conditions.

The magnitude of the fault current. A high fault current indicates that the decrease of transmitted power is high.

The total fault clearing time. The phase angles between the EMFs of the generators on both sides of the transmission line increase over the permitted stability limits if the total fault clearing time, which consists of the protection operating time and the breaker opening time, is too long.

The fault current on long transmission lines depends mostly on the fault position and decreases with the distance from the generation point. For this reason the protection must operate very quickly for faults very close to the generation (and relay) point, for which very high fault currents are characteristic.

The instantaneous phase overcurrent protection 3-phase output PHPIOC can operate in 10 ms for faults characterized by very high currents.

1MRK 511 310-UEN B Section 7 Current protection

109 Application manual

7.1.3 Setting guidelines

The parameters for instantaneous phase overcurrent protection 3-phase output PHPIOC are set via the local HMI or PCM600.

This protection function must operate only in a selective way. So check all system and transient conditions that could cause its unwanted operation.

Only detailed network studies can determine the operating conditions under which the highest possible fault current is expected on the line. In most cases, this current appears during three-phase fault conditions. But also examine single-phase-to-earth and two-phase-to-earth conditions.

Also study transients that could cause a high increase of the line current for short times. A typical example is a transmission line with a power transformer at the remote end, which can cause high inrush current when connected to the network and can thus also cause the operation of the built-in, instantaneous, overcurrent protection.

OpMode: This parameter can be set to 2 out of 3 or 1 out of 3. The setting controls the minimum number of phase currents that must be larger than the set operate current IP>> for operation. Normally this parameter is set to 1 out of 3and will thus detect all fault types. If the protection is to be used mainly for multi phase faults, 2 out of 3 should be chosen.

IP>>: Set operate current in % of IBase.

StValMult: The operate current can be changed by activation of the binary input ENMULT to the set factor StValMult.

7.1.3.1 Meshed network without parallel line

The following fault calculations have to be done for three-phase, single-phase-to- earth and two-phase-to-earth faults. With reference to figure 38, apply a fault in B and then calculate the current through-fault phase current IfB. The calculation should be done using the minimum source impedance values for ZA and the maximum source impedance values for ZB in order to get the maximum through fault current from A to B.

Section 7 1MRK 511 310-UEN B Current protection

110 Application manual

~ ~ ZA ZBZ L

A B

IED

I fB

Fault

IEC09000022-1-en.vsd

IEC09000022 V1 EN

Figure 38: Through fault current from A to B: IfB

Then a fault in A has to be applied and the through fault current IfA has to be calculated, figure 39. In order to get the maximum through fault current, the minimum value for ZB and the maximum value for ZA have to be considered.

IEC09000023-1-en.vsd

~ ~ ZA ZBZ L

A B

IED

I fA

Fault

IEC09000023 V1 EN

Figure 39: Through fault current from B to A: IfA

The IED must not trip for any of the two through-fault currents. Hence the minimum theoretical current setting (Imin) will be:

Imin MAX IfA IfB,( )

EQUATION78 V1 EN (Equation 22)

A safety margin of 5% for the maximum protection static inaccuracy and a safety margin of 5% for the maximum possible transient overreach have to be introduced. An additional 20% is suggested due to the inaccuracy of the instrument transformers under transient conditions and inaccuracy in the system data.

The minimum primary setting (Is) for the instantaneous phase overcurrent protection 3-phase output is then:

1MRK 511 310-UEN B Section 7 Current protection

111 Application manual

min1.3sI I

EQUATION79 V3 EN (Equation 23)

The protection function can be used for the specific application only if this setting value is equal to or less than the maximum fault current that the IED has to clear, IF in figure 40.

IEC09000024-1-en.vsd

~ ~ ZA ZBZ L

A B

IED

I F

Fault

IEC09000024 V1 EN

Figure 40: Fault current: IF

100 Is

IP IBase

>>=

EQUATION1147 V3 EN (Equation 24)

7.1.3.2 Meshed network with parallel line

In case of parallel lines, the influence of the induced current from the parallel line to the protected line has to be considered. One example is given in figure 41 where the two lines are connected to the same busbars. In this case the influence of the induced fault current from the faulty line (line 1) to the healthy line (line 2) is considered together with the two through fault currents IfA and IfB mentioned previously. The maximal influence from the parallel line for the IED in figure 41 will be with a fault at the C point with the C breaker open.

A fault in C has to be applied, and then the maximum current seen from the IED (IM ) on the healthy line (this applies for single-phase-to-earth and two-phase-to-earth faults) is calculated.

Section 7 1MRK 511 310-UEN B Current protection

112 Application manual

IEC09000025-1-en.vsd

~ ~ ZA ZB

ZL1 A B

I M

Fault

IED

ZL2

M

C Line 1

Line 2

IEC09000025 V1 EN

Figure 41: Two parallel lines. Influence from parallel line to the through fault current: IM

The minimum theoretical current setting for the overcurrent protection function (Imin) will be:

Imin MAX IfA IfB IM, ,( )

EQUATION82 V1 EN (Equation 25)

Where IfA and IfB have been described in the previous paragraph. Considering the safety margins mentioned previously, the minimum setting (Is) for the instantaneous phase overcurrent protection 3-phase output is then:

Is 1.3Imin EQUATION83 V2 EN (Equation 26)

The protection function can be used for the specific application only if this setting value is equal or less than the maximum phase fault current that the IED has to clear.

The IED setting value IP>> is given in percentage of the primary base current value, IBase. The value for IP>> is given from this formula:

100 Is

IP IBase

>>=

EQUATION1147 V3 EN (Equation 27)

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113 Application manual

7.2 Four step phase overcurrent protection 3-phase output OC4PTOC

7.2.1 Identification Function description IEC 61850

identification IEC 60617 identification

ANSI/IEEE C37.2 device number

Four step phase overcurrent protection 3-phase output

OC4PTOC

TOC-REVA V2 EN

51/67

7.2.2 Application

The Four step phase overcurrent protection 3-phase output OC4PTOC is used in several applications in the power system. Some applications are:

Short circuit protection of feeders in distribution and subtransmission systems. Normally these feeders have radial structure.

Back-up short circuit protection of transmission lines. Back-up short circuit protection of power transformers. Short circuit protection of different kinds of equipment connected to the power

system such as; shunt capacitor banks, shunt reactors, motors and others. Back-up short circuit protection of power generators.

If VT inputs are not available or not connected, setting parameter DirModex (x = step 1, 2, 3 or 4) shall be left to default value Non- directional.

In many applications several steps with different current pick up levels and time delays are needed. OC4PTOC can have up to four different, individual settable, steps. The flexibility of each step of OC4PTOC is great. The following options are possible:

Non-directional / Directional function: In most applications the non-directional functionality is used. This is mostly the case when no fault current can be fed from the protected object itself. In order to achieve both selectivity and fast fault clearance, the directional function can be necessary.

Choice of delay time characteristics: There are several types of delay time characteristics available such as definite time delay and different types of inverse time delay characteristics. The selectivity between different overcurrent protections is normally enabled by co-ordination between the function time delays of the different protections. To enable optimal co-ordination between all overcurrent protections, they should have the same time delay characteristic. Therefore a wide range of

Section 7 1MRK 511 310-UEN B Current protection

114 Application manual

standardized inverse time characteristics are available: IEC and ANSI. It is also possible to tailor make the inverse time characteristic.

Normally it is required that the phase overcurrent protection shall reset as fast as possible when the current level gets lower than the operation level. In some cases some sort of delayed reset is required. Therefore different kinds of reset characteristics can be used.

For some protection applications there can be a need to change the current pick-up level for some time. A typical case is when the protection will measure the current to a large motor. At the start up sequence of a motor the start current can be significantly larger than the rated current of the motor. Therefore there is a possibility to give a setting of a multiplication factor to the current pick-up level. This multiplication factor is activated from a binary input signal to the function.

Power transformers can have a large inrush current, when being energized. This phenomenon is due to saturation of the transformer magnetic core during parts of the period. There is a risk that inrush current will reach levels above the pick-up current of the phase overcurrent protection. The inrush current has a large 2nd harmonic content. This can be used to avoid unwanted operation of the protection. Therefore, OC4PTOC have a possibility of 2nd harmonic restrain if the level of this harmonic current reaches a value above a set percentage of the fundamental current.

The phase overcurrent protection is often used as protection for two and three phase short circuits. In some cases it is not wanted to detect single-phase earth faults by the phase overcurrent protection. This fault type is detected and cleared after operation of earth fault protection. Therefore it is possible to make a choice how many phases, at minimum, that have to have current above the pick-up level, to enable operation. If set 1 of 3 it is sufficient to have high current in one phase only. If set 2 of 3 or 3 of 3 single- phase earth faults are not detected.

7.2.3 Setting guidelines

When inverse time overcurrent characteristic is selected, the operate time of the stage will be the sum of the inverse time delay and the set definite time delay. Thus, if only the inverse time delay is required, it is important to set the definite time delay for that stage to zero.

In version 2.0, a typical starting time delay of 24ms is subtracted from the set trip time delay, so that the resulting trip time will take the internal IED start time into consideration.

The parameters for Four step phase overcurrent protection 3-phase output OC4PTOC are set via the local HMI or PCM600.

The following settings can be done for OC4PTOC.

1MRK 511 310-UEN B Section 7 Current protection

115 Application manual

MeasType: Selection of discrete Fourier filtered (DFT) or true RMS filtered (RMS) signals. RMS is used when the harmonic contents are to be considered, for example in applications with shunt capacitors.

Operation: The protection can be set to Off or On

AngleRCA: Protection characteristic angle set in degrees. If the angle of the fault loop current has the angle RCA the direction to fault is forward.

AngleROA: Angle value, given in degrees, to define the angle sector of the directional function, see figure 42.

IminOpPhSel: Minimum current for phase selection set in % of IBase. This setting should be less than the lowest step setting. Default setting is 7%.

StartPhSel: Number of phases, with high current, required for operation. The setting possibilities are: Not used,1 out of 3, 2 out of 3 and 3 out of 3. Default setting is 1 out of 3.

2ndHarmStab: Operate level of 2nd harmonic current restrain set in % of the fundamental current. The setting range is 5 — 100% in steps of 1%. Default setting is 20%.

Section 7 1MRK 511 310-UEN B Current protection

116 Application manual

Uref

Idir

IEC09000636_1_vsd

1

2

2

3

4

IEC09000636 V1 EN

Figure 42: Directional function characteristic

1. RCA = Relay characteristic angle 2. ROA = Relay operating angle 3. Reverse 4. Forward

7.2.3.1 Settings for each step

x means step 1, 2, 3 and 4.

DirModex: The directional mode of step x. Possible settings are Off/Non-directional/ Forward/Reverse.

Characteristx: Selection of time characteristic for step x. Definite time delay and different types of inverse time characteristics are available according to table 9.

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117 Application manual

Table 9: Inverse time characteristics

Curve name ANSI Extremely Inverse

ANSI Very Inverse

ANSI Normal Inverse

ANSI Moderately Inverse

ANSI/IEEE Definite time

ANSI Long Time Extremely Inverse

ANSI Long Time Very Inverse

ANSI Long Time Inverse

IEC Normal Inverse

IEC Very Inverse

IEC Inverse

IEC Extremely Inverse

IEC Short Time Inverse

IEC Long Time Inverse

IEC Definite Time

User Programmable

ASEA RI

RXIDG (logarithmic)

The different characteristics are described in Technical reference manual.

I1>MinEd2Set: Minimum settable operating phase current level for step 1 in % of IBase, for 61850 Ed.2 settings

I1>MaxEd2Set: Maximum settable operating phase current level for step 1 in % of IBase, for 61850 Ed.2 settings

I2>MinEd2Set: Minimum settable operating phase current level for step 2 in % of IBase, for 61850 Ed.2 settings

I2>MaxEd2Set: Maximum settable operating phase current level for step 2 in % of IBase, for 61850 Ed.2 settings

I3>MinEd2Set: Minimum settable operating phase current level for step 3 in % of IBase, for 61850 Ed.2 settings

I3>MaxEd2Set: Maximum settable operating phase current level for step 3 in % of IBase, for 61850 Ed.2 settings

I4>MinEd2Set: Minimum settable operating phase current level for step 4 in % of IBase, for 61850 Ed.2 settings

I4>MaxEd2Set: Maximum settable operating phase current level for step 4 in % of IBase, for 61850 Ed.2 settings

Section 7 1MRK 511 310-UEN B Current protection

118 Application manual

Ix>: Operate phase current level for step x given in % of IBase.

tx: Definite time delay for step x. The definite time tx is added to the inverse time when inverse time characteristic is selected.

kx: Time multiplier for inverse time delay for step x.

IMinx: Minimum operate current for step x in % of IBase. Set IMinx below Ix> for every step to achieve ANSI reset characteristic according to standard. If IMinx is set above Ix> for any step the ANSI reset works as if current is zero when current drops below IMinx.

IxMult: Multiplier for scaling of the current setting value. If a binary input signal (enableMultiplier) is activated the current operation level is increase by this setting constant. Setting range: 1.0-10.0

txMin: Minimum operate time for all inverse time characteristics. At high currents the inverse time characteristic might give a very short operation time. By setting this parameter the operation time of the step can never be shorter than the setting. Setting range: 0.000 — 60.000s in steps of 0.001s.

IMinx

Operate time

Current

tx

txMin

IEC10000058

IEC10000058 V2 EN

Figure 43: Minimum operate current and operation time for inverse time characteristics

In order to fully comply with curves definition setting parameter txMin shall be set to the value, which is equal to the operating time of the selected inverse curve for measured current of twenty times the set current pickup value. Note that the operating time value is dependent on the selected setting value for time multiplier kx.

ResetTypeCrvx: The reset of the delay timer can be made in different ways. By choosing setting the possibilities are according to table 10.

1MRK 511 310-UEN B Section 7 Current protection

119 Application manual

Table 10: Reset possibilities

Curve name Curve index no. Instantaneous 1

IEC Reset (constant time) 2

ANSI Reset (inverse time) 3

The delay characteristics are described in the technical reference manual. There are some restrictions regarding the choice of reset delay.

For the definite time delay characteristics the possible delay time settings are instantaneous (1) and IEC (2 = set constant time reset).

For ANSI inverse time characteristics all three types of reset time characteristics are available; instantaneous (1), IEC (2 = set constant time reset) and ANSI (3 = current dependent reset time).

For IEC inverse time characteristics the possible delay time settings are instantaneous (1) and IEC (2 = set constant time reset).

For the customer tailor made inverse time delay characteristics (type 17) all three types of reset time characteristics are available; instantaneous (1), IEC (2 = set constant time reset) and ANSI (3 = current dependent reset time). If the current dependent type is used settings pr, tr and cr must be given.

HarmRestrainx: Enable block of step x from the harmonic restrain function (2nd harmonic). This function should be used when there is a risk if power transformer inrush currents might cause unwanted trip. Can be set Off/On.

tPCrvx, tACrvx, tBCrvx, tCCrvx: Parameters for customer creation of inverse time characteristic curve (Curve type = 17). See equation 28 for the time characteristic equation.

[ ]

>

p

A t s B IxMult

i C

in

= +

—

EQUATION1261 V2 EN (Equation 28)

For more information, refer to the technical reference manual.

tPRCrvx, tTRCrvx, tCRCrvx: Parameters for customer creation of inverse reset time characteristic curve (Reset Curve type = 3). Further description can be found in the technical reference manual.

7.2.3.2 2nd harmonic restrain

Section 7 1MRK 511 310-UEN B Current protection

120 Application manual

If a power transformer is energized there is a risk that the transformer core will saturate during part of the period, resulting in an inrush transformer current. This will give a declining residual current in the network, as the inrush current is deviating between the phases. There is a risk that the phase overcurrent function will give an unwanted trip. The inrush current has a relatively large ratio of 2nd harmonic component. This component can be used to create a restrain signal to prevent this unwanted function.

The settings for the 2nd harmonic restrain are described below.

2ndHarmStab: The rate of 2nd harmonic current content for activation of the 2nd harmonic restrain signal, to block chosen steps. The setting is given in % of the fundamental frequency residual current. The setting range is 5 — 100% in steps of 1%. The default setting is 20% and can be used if a deeper investigation shows that no other value is needed..

HarmRestrainx: This parameter can be set Off/On, to disable or enable the 2nd harmonic restrain.

The four step phase overcurrent protection 3-phase output can be used in different ways, depending on the application where the protection is used. A general description is given below.

The operating current setting of the inverse time protection, or the lowest current step of the definite time protection, must be defined so that the highest possible load current does not cause protection operation. Here consideration also has to be taken to the protection reset current, so that a short peak of overcurrent does not cause operation of the protection even when the overcurrent has ceased. This phenomenon is described in figure 44.

1MRK 511 310-UEN B Section 7 Current protection

121 Application manual

Operate current

Current I

The IED does not reset

Line phase current

Time t

Reset current

IEC05000203-en-2.vsd IEC05000203 V3 EN

Figure 44: Operate and reset current for an overcurrent protection

The lowest setting value can be written according to equation 29.

ImaxIpu 1.2 k

EQUATION1262 V2 EN (Equation 29)

where:

1.2 is a safety factor

k is the resetting ratio of the protection

Imax is the maximum load current

From operation statistics the load current up to the present situation can be found. The current setting must be valid also for some years ahead. It is, in most cases, realistic that the setting values are updated not more often than once every five years. In many cases this time interval is still longer. Investigate the maximum load current that different equipment on the line can withstand. Study components such as line conductors, current transformers, circuit breakers, and disconnectors. The manufacturer of the equipment normally gives the maximum thermal load current of the equipment.

Section 7 1MRK 511 310-UEN B Current protection

122 Application manual

The maximum load current on the line has to be estimated. There is also a demand that all faults, within the zone that the protection shall cover, must be detected by the phase overcurrent protection. The minimum fault current Iscmin, to be detected by the protection, must be calculated. Taking this value as a base, the highest pick up current setting can be written according to equation 30.

Ipu 0.7 Iscmin EQUATION1263 V2 EN (Equation 30)

where:

0.7 is a safety factor

Iscmin is the smallest fault current to be detected by the overcurrent protection.

As a summary the operating current shall be chosen within the interval stated in equation 31.

Imax1.2 Ipu 0.7 Iscmin k

EQUATION1264 V2 EN (Equation 31)

The high current function of the overcurrent protection, which only has a short delay of the operation, must be given a current setting so that the protection is selective to other protection in the power system. It is desirable to have a rapid tripping of faults within as large portion as possible of the part of the power system to be protected by the protection (primary protected zone). A fault current calculation gives the largest current of faults, Iscmax, at the most remote part of the primary protected zone. Considerations have to be made to the risk of transient overreach, due to a possible DC component of the short circuit current. The lowest current setting of the most rapid stage, of the phase overcurrent protection, can be written according to

max1.2 t schighI k I

EQUATION1265 V1 EN (Equation 32)

where:

1.2 is a safety factor

kt is a factor that takes care of the transient overreach due to the DC component of the fault current and can be considered to be less than 1.05

Iscmax is the largest fault current at a fault at the most remote point of the primary protection zone.

The operate times of the phase overcurrent protection has to be chosen so that the fault time is so short that protected equipment will not be destroyed due to thermal overload, at the same time as selectivity is assured. For overcurrent protection, in a radial fed network, the time setting can be chosen in a graphical way. This is mostly used in the case of inverse time overcurrent protection. Figure 45 shows how the time-

1MRK 511 310-UEN B Section 7 Current protection

123 Application manual

versus-current curves are plotted in a diagram. The time setting is chosen to get the shortest fault time with maintained selectivity. Selectivity is assured if the time difference between the curves is larger than a critical time difference.

en05000204.wmf

IEC05000204 V1 EN

Figure 45: Fault time with maintained selectivity

The operation time can be set individually for each overcurrent protection.

To assure selectivity between different protections, in the radial network, there have to be a minimum time difference Dt between the time delays of two protections. The minimum time difference can be determined for different cases. To determine the shortest possible time difference, the operation time of protections, breaker opening time and protection resetting time must be known. These time delays can vary significantly between different protective equipment. The following time delays can be estimated:

Protection operation time:

15-60 ms

Protection resetting time: 15-60 ms

Breaker opening time: 20-120 ms

Section 7 1MRK 511 310-UEN B Current protection

124 Application manual

Example for time coordination Assume two substations A and B directly connected to each other via one line, as shown in the figure 46. Consider a fault located at another line from the station B. The fault current to the overcurrent protection of IED B1 has a magnitude so that the protection will have instantaneous function. The overcurrent protection of IED A1 must have a delayed function. The sequence of events during the fault can be described using a time axis, see figure 46.

I> I>

A1 B1 Feeder

Time axis

t=0 t=t1 t=t2 t=t3 The fault occurs

Protection B1 trips

Breaker at B1 opens

Protection A1 resets

en05000205.vsd

IEC05000205 V1 EN

Figure 46: Sequence of events during fault

where:

t=0 is when the fault occurs

t=t1 is when the trip signal from the overcurrent protection at IED B1 is sent to the circuit breaker. The operation time of this protection is t1

t=t2 is when the circuit breaker at IED B1 opens. The circuit breaker opening time is t2 — t1

t=t3 is when the overcurrent protection at IED A1 resets. The protection resetting time is t3 — t2.

To ensure that the overcurrent protection at IED A1, is selective to the overcurrent protection at IED B1, the minimum time difference must be larger than the time t3. There are uncertainties in the values of protection operation time, breaker opening time and protection resetting time. Therefore a safety margin has to be included. With normal values the needed time difference can be calculated according to equation 33.

1MRK 511 310-UEN B Section 7 Current protection

125 Application manual

40 100 40 40 220t ms ms ms ms msD + + + = EQUATION1266 V1 EN (Equation 33)

where it is considered that:

the operate time of overcurrent protection B1 is 40 ms

the breaker open time is 100 ms

the resetting time of protection A1 is 40 ms and

the additional margin is 40 ms

7.3 Instantaneous residual overcurrent protection EFPIOC

7.3.1 Identification Function description IEC 61850

identification IEC 60617 identification

ANSI/IEEE C37.2 device number

Instantaneous residual overcurrent protection

EFPIOC

IN>>

IEF V1 EN

50N

7.3.2 Application

In many applications, when fault current is limited to a defined value by the object impedance, an instantaneous earth-fault protection can provide fast and selective tripping.

The Instantaneous residual overcurrent EFPIOC, which can operate in 15 ms (50 Hz nominal system frequency) for faults characterized by very high currents, is included in the IED.

7.3.3 Setting guidelines

The parameters for the Instantaneous residual overcurrent protection EFPIOC are set via the local HMI or PCM600.

Some guidelines for the choice of setting parameter for EFPIOC is given.

The setting of the function is limited to the operate residual current to the protection (IN>>).

Section 7 1MRK 511 310-UEN B Current protection

126 Application manual

The basic requirement is to assure selectivity, that is EFPIOC shall not be allowed to operate for faults at other objects than the protected object (line).

For a normal line in a meshed system single phase-to-earth faults and phase-to-phase- to-earth faults shall be calculated as shown in figure 47 and figure 48. The residual currents (3I0) to the protection are calculated. For a fault at the remote line end this fault current is IfB. In this calculation the operational state with high source impedance ZA and low source impedance ZB should be used. For the fault at the home busbar this fault current is IfA. In this calculation the operational state with low source impedance ZA and high source impedance ZB should be used.

~ ~ ZA ZBZ L

A B

IED

I fB

Fault

IEC09000022-1-en.vsd

IEC09000022 V1 EN

Figure 47: Through fault current from A to B: IfB

IEC09000023-1-en.vsd

~ ~ ZA ZBZ L

A B

IED

I fA

Fault

IEC09000023 V1 EN

Figure 48: Through fault current from B to A: IfA

The function shall not operate for any of the calculated currents to the protection. The minimum theoretical current setting (Imin) will be:

Imin MAX IfA IfA,( )

EQUATION284 V1 EN (Equation 34)

A safety margin of 5% for the maximum static inaccuracy and a safety margin of 5% for maximum possible transient overreach have to be introduced. An additional 20%

1MRK 511 310-UEN B Section 7 Current protection

127 Application manual

is suggested due to inaccuracy of instrument transformers under transient conditions and inaccuracy in the system data.

The minimum primary current setting (Is) is:

Is = 1.3 Imin EQUATION285 V3 EN (Equation 35)

In case of parallel lines with zero sequence mutual coupling a fault on the parallel line, as shown in figure 49, should be calculated.

IEC09000025-1-en.vsd

~ ~ ZA ZB

ZL1 A B

I M

Fault

IED

ZL2

M

C Line 1

Line 2

IEC09000025 V1 EN

Figure 49: Two parallel lines. Influence from parallel line to the through fault current: IM

The minimum theoretical current setting (Imin) will in this case be:

I m in M AX IfA I fB IM, ,( )

EQUATION287 V1 EN (Equation 36)

Where:

IfA and IfB have been described for the single line case.

Considering the safety margins mentioned previously, the minimum setting (Is) is:

Is = 1.3 Imin EQUATION288 V3 EN (Equation 37)

Transformer inrush current shall be considered.

The setting of the protection is set as a percentage of the base current (IBase).

Operation: set the protection to On or Off.

Section 7 1MRK 511 310-UEN B Current protection

128 Application manual

IN>>: Set operate current in % of IBase.

StValMult: The operate current can be changed by activation of the binary input ENMULT to the set factor StValMult.

7.4 Four step residual overcurrent protection, (Zero sequence or negative sequence directionality) EF4PTOC

7.4.1 Identification Function description IEC 61850

identification IEC 60617 identification

ANSI/IEEE C37.2 device number

Four step residual overcurrent protection

EF4PTOC 4(IN>)

4 alt4

TEF-REVA V2 EN

51N/67N

7.4.2 Application

The four step residual overcurrent protection EF4PTOC is used in several applications in the power system. Some applications are:

Earth-fault protection of feeders in effectively earthed distribution and subtransmission systems. Normally these feeders have radial structure.

Back-up earth-fault protection of transmission lines. Sensitive earth-fault protection of transmission lines. EF4PTOC can have better

sensitivity to detect resistive phase-to-earth-faults compared to distance protection.

Back-up earth-fault protection of power transformers. Earth-fault protection of different kinds of equipment connected to the power

system such as shunt capacitor banks, shunt reactors and others.

In many applications several steps with different current operating levels and time delays are needed. EF4PTOC can have up to four, individual settable steps. The flexibility of each step of EF4PTOC is great. The following options are possible:

Non-directional/Directional function: In some applications the non-directional functionality is used. This is mostly the case when no fault current can be fed from the protected object itself. In order to achieve both selectivity and fast fault clearance, the directional function can be necessary. This can be the case for earth-fault protection in meshed and effectively earthed transmission systems. The directional residual overcurrent protection is also well suited to operate in teleprotection communication

1MRK 511 310-UEN B Section 7 Current protection

129 Application manual

schemes, which enables fast clearance of earth faults on transmission lines. The directional function uses the polarizing quantity as decided by setting. Voltage polarizing is most commonly used, but alternatively current polarizing where currents in transformer neutrals providing the neutral source (ZN) is used to polarize (IN ZN) the function. Dual polarizing where the sum of both voltage and current components is allowed to polarize can also be selected.

Choice of time characteristics: There are several types of time characteristics available such as definite time delay and different types of inverse time characteristics. The selectivity between different overcurrent protections is normally enabled by co-ordination between the operate time of the different protections. To enable optimal co-ordination all overcurrent protections, to be co-ordinated against each other, should have the same time characteristic. Therefore a wide range of standardized inverse time characteristics are available: IEC and ANSI.

Table 11: Time characteristics

Curve name ANSI Extremely Inverse

ANSI Very Inverse

ANSI Normal Inverse

ANSI Moderately Inverse

ANSI/IEEE Definite time

ANSI Long Time Extremely Inverse

ANSI Long Time Very Inverse

ANSI Long Time Inverse

IEC Normal Inverse

IEC Very Inverse

IEC Inverse

IEC Extremely Inverse

IEC Short Time Inverse

IEC Long Time Inverse

IEC Definite Time

User Programmable

ASEA RI

RXIDG (logarithmic)

It is also possible to tailor make the inverse time characteristic.

Normally it is required that EF4PTOC shall reset as fast as possible when the current level gets lower than the operation level. In some cases some sort of delayed reset is required. Therefore different kinds of reset characteristics can be used.

For some protection applications there can be a need to change the current operating level for some time. Therefore there is a possibility to give a setting of a multiplication

Section 7 1MRK 511 310-UEN B Current protection

130 Application manual

factor INxMult to the residual current pick-up level. This multiplication factor is activated from a binary input signal ENMULTx to the function.

Power transformers can have a large inrush current, when being energized. This inrush current can have residual current components. The phenomenon is due to saturation of the transformer magnetic core during parts of the cycle. There is a risk that inrush current will give a residual current that reaches level above the operating current of the residual overcurrent protection. The inrush current has a large second harmonic content. This can be used to avoid unwanted operation of the protection. Therefore, EF4PTOC has a possibility of second harmonic restrain 2ndHarmStab if the level of this harmonic current reaches a value above a set percentage of the fundamental current.

7.4.3 Setting guidelines

When inverse time overcurrent characteristic is selected, the operate time of the stage will be the sum of the inverse time delay and the set definite time delay. Thus, if only the inverse time delay is required, it is of utmost importance to set the definite time delay for that stage to zero.

In version 2.0, a typical starting time delay of 24ms is subtracted from the set trip time delay, so that the resulting trip time will take the internal IED start time into consideration.

The parameters for the four step residual overcurrent protection, zero or negative sequence direction EF4PTOC are set via the local HMI or PCM600.

The following settings can be done for the four step residual overcurrent protection.

Operation: Sets the protection to On or Off.

7.4.3.1 Settings for each step (x = 1, 2, 3 and 4)

DirModex: The directional mode of step x. Possible settings are Off/Non-directional/ Forward/Reverse.

Characteristx: Selection of time characteristic for step x. Definite time delay and different types of inverse time characteristics are available.

Inverse time characteristic enables fast fault clearance of high current faults at the same time as selectivity to other inverse time phase overcurrent protections can be assured. This is mainly used in radial fed networks but can also be used in meshed networks. In meshed networks the settings must be based on network fault calculations.

1MRK 511 310-UEN B Section 7 Current protection

131 Application manual

To assure selectivity between different protections, in the radial network, there have to be a minimum time difference Dt between the time delays of two protections. The minimum time difference can be determined for different cases. To determine the shortest possible time difference, the operation time of protections, breaker opening time and protection resetting time must be known. These time delays can vary significantly between different protective equipment. The following time delays can be estimated:

Protection operate time: 15-60 ms

Protection resetting time: 15-60 ms

Breaker opening time: 20-120 ms

The different characteristics are described in the technical reference manual.

INx>: Operate residual current level for step x given in % of IBase.

kx: Time multiplier for the dependent (inverse) characteristic for step x.

IMinx: Minimum operate current for step x in % of IBase. Set IMinx below Ix> for every step to achieve ANSI reset characteristic according to standard. If IMinx is set above Ix> for any step then signal will reset at current equals to zero.

INxMult: Multiplier for scaling of the current setting value. If a binary input signal (ENMULTx) is activated the current operation level is increased by this setting constant.

txMin: Minimum operating time for inverse time characteristics. At high currents the inverse time characteristic might give a very short operation time. By setting this parameter the operation time of the step can never be shorter than the setting.

IMinx

Operate time

Current

tx

txMin

IEC10000058

IEC10000058 V2 EN

Figure 50: Minimum operate current and operate time for inverse time characteristics

Section 7 1MRK 511 310-UEN B Current protection

132 Application manual

In order to fully comply with curves definition the setting parameter txMin shall be set to the value which is equal to the operate time of the selected IEC inverse curve for measured current of twenty times the set current pickup value. Note that the operate time value is dependent on the selected setting value for time multiplier kx.

ResetTypeCrvx: The reset of the delay timer can be made in different ways. The possibilities are described in the technical reference manual.

tPCrvx, tACrvx, tBCrvx, tCCrvx: Parameters for user programmable of inverse time characteristic curve. The time characteristic equation is according to equation 38:

[ ] = +

— >

p

A t s B k

i C

in EQUATION1189 V1 EN (Equation 38)

Further description can be found in the technical reference manual.

tPRCrvx, tTRCrvx, tCRCrvx: Parameters for user programmable of inverse reset time characteristic curve. Further description can be found in the technical reference manual.

7.4.3.2 Common settings for all steps

tx: Definite time delay for step x. Used if definite time characteristic is chosen.

AngleRCA: Relay characteristic angle given in degree. This angle is defined as shown in figure 51. The angle is defined positive when the residual current lags the reference voltage (Upol = 3U0 or U2)

1MRK 511 310-UEN B Section 7 Current protection

133 Application manual

Upol = 3U0 or U2

I>Dir

RCA

Operation

en 05000135-4-nsi.vsd

IEC05000135 V4 EN

Figure 51: Relay characteristic angle given in degree

In a normal transmission network a normal value of RCA is about 65. The setting range is -180 to +180.

polMethod: Defines if the directional polarization is from

Voltage (3U0 or U2) Current (3I0 ZNpol or 3I2 ZNpol where ZNpol is RNpol + jXNpol), or both currents and voltage, Dual (dual polarizing, (3U0 + 3I0 ZNpol) or (U2 + I2

ZNpol)).

Normally voltage polarizing from the internally calculated residual sum or an external open delta is used.

Current polarizing is useful when the local source is strong and a high sensitivity is required. In such cases the polarizing voltage (3U0) can be below 1% and it is then necessary to use current polarizing or dual polarizing. Multiply the required set current (primary) with the minimum impedance (ZNpol) and check that the percentage of the phase-to-earth voltage is definitely higher than 1% (minimum 3U0>UPolMin setting) as a verification.

RNPol, XNPol: The zero-sequence source is set in primary ohms as base for the current polarizing. The polarizing voltage is then achieved as 3I0 ZNpol. The ZNpol can be defined as (ZS1-ZS0)/3, that is the earth return impedance of the source behind the protection. The maximum earth-fault current at the local source can be used to calculate the value of ZN as U/(3 3I0) Typically, the minimum ZNPol (3 zero sequence source) is set. Setting is in primary ohms.

Section 7 1MRK 511 310-UEN B Current protection

134 Application manual

When the dual polarizing method is used it is important that the settingINx>or the product 3I0 ZNpol is not greater than 3U0. If so, there is a risk for incorrect operation for faults in the reverse direction.

IPolMin: is the minimum earth-fault current accepted for directional evaluation. For smaller currents than this value the operation will be blocked. Typical setting is 5-10% of IBase.

UPolMin: Minimum polarization (reference) polarizing voltage for the directional function, given in % of UBase/3.

I>Dir: Operate residual current release level in % of IBase for directional comparison scheme. The setting is given in % of IBase and must be set below the lowest INx> setting, set for the directional measurement. The output signals, STFW and STRV can be used in a teleprotection scheme. The appropriate signal should be configured to the communication scheme block.

7.4.3.3 2nd harmonic restrain

If a power transformer is energized there is a risk that the current transformer core will saturate during part of the period, resulting in a transformer inrush current. This will give a declining residual current in the network, as the inrush current is deviating between the phases. There is a risk that the residual overcurrent function will give an unwanted trip. The inrush current has a relatively large ratio of 2nd harmonic component. This component can be used to create a restrain signal to prevent this unwanted function.

At current transformer saturation a false residual current can be measured by the protection. Also here the 2nd harmonic restrain can prevent unwanted operation.

2ndHarmStab: The rate of 2nd harmonic current content for activation of the 2nd harmonic restrain signal. The setting is given in % of the fundamental frequency residual current.

HarmRestrainx: Enable block of step x from the harmonic restrain function.

7.4.3.4 Parallel transformer inrush current logic

In case of parallel transformers there is a risk of sympathetic inrush current. If one of the transformers is in operation, and the parallel transformer is switched in, the asymmetric inrush current of the switched in transformer will cause partial saturation of the transformer already in service. This is called transferred saturation. The 2nd

harmonic of the inrush currents of the two transformers will be in phase opposition. The summation of the two currents will thus give a small 2nd harmonic current. The residual fundamental current will however be significant. The inrush current of the transformer in service before the parallel transformer energizing, will be a little delayed compared to the first transformer. Therefore we will have high 2nd harmonic current initially. After a short period this current will however be small and the normal 2nd harmonic blocking will reset.

1MRK 511 310-UEN B Section 7 Current protection

135 Application manual

en05000136.vsd

Power System

IN>IN>

IEC05000136 V1 EN

Figure 52: Application for parallel transformer inrush current logic

If the BlkParTransf function is activated the 2nd harmonic restrain signal will latch as long as the residual current measured by the relay is larger than a selected step current level. Assume that step 4 is chosen to be the most sensitive step of the four step residual overcurrent protection function EF4PTOC. The harmonic restrain blocking is enabled for this step. Also the same current setting as this step is chosen for the blocking at parallel transformer energizing.

Below the settings for the parallel transformer logic are described.

UseStartValue: Gives which current level that should be used for activation of the blocking signal. This is given as one of the settings of the steps: Step 1/2/3/4. Normally the step having the lowest operation current level should be set.

BlkParTransf: This parameter can be set Off/On, the parallel transformer logic.

7.4.3.5 Switch onto fault logic

In case of energizing a faulty object there is a risk of having a long fault clearance time, if the fault current is too small to give fast operation of the protection. The switch on to fault function can be activated from auxiliary signals from the circuit breaker, either the close command or the open/close position (change of position).

This logic can be used to issue fast trip if one breaker pole does not close properly at a manual or automatic closing.

SOTF and Under Time are similar functions to achieve fast clearance at asymmetrical closing based on requirements from different utilities.

The function is divided into two parts. The SOTF function will give operation from step 2 or 3 during a set time after change in the position of the circuit breaker. The SOTF function has a set time delay. The Under Time function, which has 2nd

harmonic restrain blocking, will give operation from step 4. The 2nd harmonic restrain will prevent unwanted function in case of transformer inrush current. The Under Time function has a set time delay.

Below the settings for switch on to fault logics are described.

Section 7 1MRK 511 310-UEN B Current protection

136 Application manual

SOTF operation mode: This parameter can be set: Off/SOTF/Under Time/SOTF +Under Time.

ActivationSOTF: This setting will select the signal to activate SOTF function; CB position open/CB position closed/CB close command.

tSOTF: Time delay for operation of the SOTF function. The setting range is 0.000 — 60.000 s in step of 0.001 s. The default setting is 0.100 s

StepForSOTF: If this parameter is set on the step 3 start signal will be used as current set level. If set off step 2 start signal will be used as current set level.

t4U: Time interval when the SOTF function is active after breaker closing. The setting range is 0.000 — 60.000 s in step of 0.001 s. The default setting is 1.000 s.

ActUnderTime: Describes the mode to activate the sensitive undertime function. The function can be activated by Circuit breaker position (change) or Circuit breaker command.

tUnderTime: Time delay for operation of the sensitive undertime function. The setting range is 0.000 — 60.000 s in step of 0.001 s. The default setting is 0.300 s

7.4.3.6 Line application example

The Four step residual overcurrent protection EF4PTOC can be used in different ways. Below is described one application possibility to be used in meshed and effectively earthed systems.

The protection measures the residual current out on the protected line. The protection function has a directional function where the polarizing voltage (zero-sequence voltage) is the polarizing quantity.

The polarizing voltage and current can be internally generated when a three-phase set of voltage transformers and current transformers are used.

1MRK 511 310-UEN B Section 7 Current protection

137 Application manual

xx05000149.vsd

IN>

IEC05000149 V1 EN

Figure 53: Connection of polarizing voltage from an open delta

The different steps can be described as follows.

Step 1 This step has directional instantaneous function. The requirement is that overreaching of the protected line is not allowed.

IEC05000150-3-en.vsd

IN

3I0

One- or two-phase earth-fault or unsymmetric short circuit without earth connection

IEC05000150 V4 EN

Figure 54: Step 1, first calculation

Section 7 1MRK 511 310-UEN B Current protection

138 Application manual

The residual current out on the line is calculated at a fault on the remote busbar (one- or two-phase-to-earth fault). To assure selectivity it is required that step 1 shall not give a trip at this fault. The requirement can be formulated according to equation 39.

step1 0I 1.2 3I (remote busbar)

EQUATION1199 V3 EN (Equation 39)

As a consequence of the distribution of zero sequence current in the power system, the current to the protection might be larger if one line out from the remote busbar is taken out of service, see figure 55.

IEC05000151-en-2.vsd

IN >

One- or two-phase-earth-fault

3I0

IEC05000151 V2 EN

Figure 55: Step 1, second calculation. Remote busbar with, one line taken out of service

The requirement is now according to equation 40.

step1 0I 1.2 3I (remote busbar with one line out)

EQUATION1200 V3 EN (Equation 40)

A higher value of step 1 might be necessary if a big power transformer (Y0/D) at remote bus bar is disconnected.

A special case occurs at double circuit lines, with mutual zero-sequence impedance between the parallel lines, see figure 56.

1MRK 511 310-UEN B Section 7 Current protection

139 Application manual

IN >

One phase-to-earth fault

3I0

IEC05000152-en-2.vsd IEC05000152 V2 EN

Figure 56: Step 1, third calculation

In this case the residual current out on the line can be larger than in the case of earth fault on the remote busbar.

step1 0I 1.2 3I EQUATION1201 V3 EN (Equation 41)

The current setting for step 1 is chosen as the largest of the above calculated residual currents, measured by the protection.

Step 2 This step has directional function and a short time delay, often about 0.4 s. Step 2 shall securely detect all earth faults on the line, not detected by step 1.

IN >

One- or two-phase earth-fault

3I0

IEC05000154-en-2.vsd

IEC05000154 V2 EN

Figure 57: Step 2, check of reach calculation

Section 7 1MRK 511 310-UEN B Current protection

140 Application manual

The residual current, out on the line, is calculated at an operational case with minimal earth-fault current. The requirement that the whole line shall be covered by step 2 can be formulated according to equation 42.

step2 0I 0.7 3I (at remote busbar) EQUATION1202 V4 EN (Equation 42)

To assure selectivity the current setting must be chosen so that step 2 does not operate at step 2 for faults on the next line from the remote substation. Consider a fault as shown in Figure 58.

IN >

One phase-to-earth fault

3I0

IN >

3I01

IEC05000155-en-2.vsd

IEC05000155 V3 EN

Figure 58: Step 2, selectivity calculation

A second criterion for step 2 is according to equation 43.

1 1 0

step2 step1 0

3I I .2 I 3I

EQUATION1203 V4 EN (Equation 43)

where:

Istep1 is the current setting for step 1 on the faulted line.

Step 3 This step has directional function and a time delay slightly larger than step 2, often 0.8 s. Step 3 shall enable selective trip of earth faults having higher fault resistance to earth, compared to step 2. The requirement on step 3 is selectivity to other earth-fault protections in the network. One criterion for setting is shown in Figure 59.

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141 Application manual

IEC05000156-3-en.vsd

IN >

One phase-to- earth fault

3I0

IN >

3I02

IEC05000156 V3 EN

Figure 59: Step 3, Selectivity calculation

1 0 step3 step2

02

3I I .2 I 3I

EQUATION1204 V4 EN (Equation 44)

where:

Istep2 is the chosen current setting for step 2 on the faulted line.

Step 4 This step normally has non-directional function and a relatively long time delay. The task for step 4 is to detect and initiate trip for earth faults with large fault resistance, for example tree faults. Step 4 shall also detect series faults where one or two poles, of a breaker or other switching device, are open while the other poles are closed.

Both high resistance earth faults and series faults give zero-sequence current flow in the network. Such currents give disturbances on telecommunication systems and current to earth. It is important to clear such faults both concerning personal security as well as risk of fire.

The current setting for step 4 is often set down to about 100 A (primary 3I0). In many applications definite time delay in the range 1.2 — 2.0 s is used. In other applications a current dependent inverse time characteristic is used. This enables a higher degree of selectivity also for sensitive earth-fault current protection.

7.5 Four step directional negative phase sequence overcurrent protection NS4PTOC

Section 7 1MRK 511 310-UEN B Current protection

142 Application manual

7.5.1 Identification Function description IEC 61850

identification IEC 60617 identification ANSI/IEEE C37.2

device number Four step negative sequence overcurrent protection

NS4PTOC I2 4

4 alt

IEC10000053 V1 EN

46I2

7.5.2 Application

Four step negative sequence overcurrent protection NS4PTOC is used in several applications in the power system. Some applications are:

Earth-fault and phase-phase short circuit protection of feeders in effectively earthed distribution and subtransmission systems. Normally these feeders have radial structure.

Back-up earth-fault and phase-phase short circuit protection of transmission lines.

Sensitive earth-fault protection of transmission lines. NS4PTOC can have better sensitivity to detect resistive phase-to-earth-faults compared to distance protection.

Back-up earth-fault and phase-phase short circuit protection of power transformers.

Earth-fault and phase-phase short circuit protection of different kinds of equipment connected to the power system such as shunt capacitor banks, shunt reactors and others.

In many applications several steps with different current operating levels and time delays are needed. NS4PTOC can have up to four, individual settable steps. The flexibility of each step of NS4PTOC function is great. The following options are possible:

Non-directional/Directional function: In some applications the non-directional functionality is used. This is mostly the case when no fault current can be fed from the protected object itself. In order to achieve both selectivity and fast fault clearance, the directional function can be necessary. This can be the case for unsymmetrical fault protection in meshed and effectively earthed transmission systems. The directional negative sequence overcurrent protection is also well suited to operate in teleprotection communication schemes, which enables fast clearance of unsymmetrical faults on transmission lines. The directional function uses the voltage polarizing quantity.

Choice of time characteristics: There are several types of time characteristics available such as definite time delay and different types of inverse time characteristics. The selectivity between different overcurrent protections is normally enabled by co-ordination between the operating time of the different protections. To

1MRK 511 310-UEN B Section 7 Current protection

143 Application manual

enable optimal co-ordination all overcurrent relays, to be co-ordinated against each other, should have the same time characteristic. Therefore a wide range of standardized inverse time characteristics are available: IEC and ANSI.

Table 12: Inverse time characteristics

Curve name ANSI Extremely Inverse

ANSI Very Inverse

ANSI Normal Inverse

ANSI Moderately Inverse

ANSI/IEEE Definite time

ANSI Long Time Extremely Inverse

ANSI Long Time Very Inverse

ANSI Long Time Inverse

IEC Normal Inverse

IEC Very Inverse

IEC Inverse

IEC Extremely Inverse

IEC Short Time Inverse

IEC Long Time Inverse

IEC Definite Time

User Programmable

ASEA RI

RXIDG (logarithmic)

There is also a user programmable inverse time characteristic.

Normally it is required that the negative sequence overcurrent function shall reset as fast as possible when the current level gets lower than the operation level. In some cases some sort of delayed reset is required. Therefore different kinds of reset characteristics can be used.

For some protection applications there can be a need to change the current operating level for some time. Therefore there is a possibility to give a setting of a multiplication factor IxMult to the negative sequence current pick-up level. This multiplication factor is activated from a binary input signal ENMULTx to the function.

7.5.3 Setting guidelines

The parameters for Four step negative sequence overcurrent protection NS4PTOC are set via the local HMI or Protection and Control Manager (PCM600).

The following settings can be done for the four step negative sequence overcurrent protection:

Section 7 1MRK 511 310-UEN B Current protection

144 Application manual

Operation: Sets the protection to On or Off.

Common base IED values for primary current (IBase), primary voltage (UBase) and primary power (SBase) are set in Global base values for settings function GBASVAL. GlobalBaseSel: It is used to select a GBASVAL function for reference of base values.

When inverse time overcurrent characteristic is selected, the operate time of the stage will be the sum of the inverse time delay and the set definite time delay. Thus, if only the inverse time delay is required, it is of utmost importance to set the definite time delay for that stage to zero.

In version 2.0, a typical starting time delay of 24ms is subtracted from the set trip time delay, so that the resulting trip time will take the internal IED start time into consideration.

7.5.3.1 Settings for each step

x means step 1, 2, 3 and 4.

DirModeSelx: The directional mode of step x. Possible settings are off/nondirectional/ forward/reverse.

Characteristx: Selection of time characteristic for step x. Definite time delay and different types of inverse time characteristics are available.

Table 13: Inverse time characteristics

Curve name ANSI Extremely Inverse

ANSI Very Inverse

ANSI Normal Inverse

ANSI Moderately Inverse

ANSI/IEEE Definite time

ANSI Long Time Extremely Inverse

ANSI Long Time Very Inverse

ANSI Long Time Inverse

IEC Normal Inverse

IEC Very Inverse

IEC Inverse

IEC Extremely Inverse

IEC Short Time Inverse

Table continues on next page

1MRK 511 310-UEN B Section 7 Current protection

145 Application manual

Curve name IEC Long Time Inverse

IEC Definite Time

User Programmable

ASEA RI

RXIDG (logarithmic)

The different characteristics are described in the Technical Reference Manual (TRM).

Ix>: Operation negative sequence current level for step x given in % of IBase.

tx: Definite time delay for step x. The definite time tx is added to the inverse time when inverse time characteristic is selected. Note that the value set is the time between activation of the start and the trip outputs.

kx: Time multiplier for the dependent (inverse) characteristic.

IMinx: Minimum operate current for step x in % of IBase. Set IMinx below Ix> for every step to achieve ANSI reset characteristic according to standard. If IMinx is set above Ix> for any step the ANSI reset works as if current is zero when current drops below IMinx.

IxMult: Multiplier for scaling of the current setting value. If a binary input signal (ENMULTx) is activated the current operation level is multiplied by this setting constant.

txMin: Minimum operation time for inverse time characteristics. At high currents the inverse time characteristic might give a very short operation time. By setting this parameter the operation time of the step can never be shorter than the setting.

Section 7 1MRK 511 310-UEN B Current protection

146 Application manual

IMinx

Operate time

Current

tx

txMin

IEC10000058

IEC10000058 V2 EN

Figure 60: Minimum operate current and operation time for inverse time characteristics

ResetTypeCrvx: The reset of the delay timer can be made in different ways. By choosing setting there are the following possibilities:

Curve name Instantaneous

IEC Reset (constant time)

ANSI Reset (inverse time)

The different reset characteristics are described in the Technical Reference Manual (TRM). There are some restrictions regarding the choice of reset delay.

For the independent time delay characteristics the possible delay time settings are instantaneous (1) and IEC (2 = set constant time reset).

For ANSI inverse time delay characteristics all three types of reset time characteristics are available; instantaneous (1), IEC (2 = set constant time reset) and ANSI (3 = current dependent reset time).

For IEC inverse time delay characteristics the possible delay time settings are instantaneous (1) and IEC (2 = set constant time reset).

For the programmable inverse time delay characteristics all three types of reset time characteristics are available; instantaneous (1), IEC (2 = set constant time reset) and ANSI (3 = current dependent reset time). If the current dependent type is used settings pr, tr and cr must be given.

tPCrvx, tACrvx, tBCrvx, tCCrvx: Parameters for programmable inverse time characteristic curve. The time characteristic equation is according to equation 38:

1MRK 511 310-UEN B Section 7 Current protection

147 Application manual

[ ] = +

— >

p

A t s B k

i C

in EQUATION1189 V1 EN (Equation 45)

Further description can be found in the Technical reference manual (TRM).

tPRCrvx, tTRCrvx, tCRCrvx: Parameters for customer creation of inverse reset time characteristic curve. Further description can be found in the Technical Reference Manual.

7.5.3.2 Common settings for all steps

x means step 1, 2, 3 and 4.

AngleRCA: Relay characteristic angle given in degrees. This angle is defined as shown in figure 51. The angle is defined positive when the residual current lags the reference voltage (Upol = -U2)

Section 7 1MRK 511 310-UEN B Current protection

148 Application manual

AngleRCA

Forward Area

Iop = I2

Upol=-U2

Reverse Area

IEC10000031-1-en.vsd IEC10000031 V1 EN

Figure 61: Relay characteristic angle given in degree

In a transmission network a normal value of RCA is about 80.

UPolMin: Minimum polarization (reference) voltage % of UBase.

I>Dir: Operate residual current level for directional comparison scheme. The setting is given in % of IBase. The start forward or start reverse signals can be used in a communication scheme. The appropriate signal must be configured to the communication scheme block.

7.6 Sensitive directional residual overcurrent and power protection SDEPSDE

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149 Application manual

7.6.1 Identification Function description IEC 61850

identification IEC 60617 identification

ANSI/IEEE C37.2 device number

Sensitive directional residual over current and power protection

SDEPSDE — 67N

7.6.2 Application

In networks with high impedance earthing, the phase-to-earth fault current is significantly smaller than the short circuit currents. Another difficulty for earth fault protection is that the magnitude of the phase-to-earth fault current is almost independent of the fault location in the network.

Directional residual current can be used to detect and give selective trip of phase-to- earth faults in high impedance earthed networks. The protection uses the residual current component 3I0 cos , where is the angle between the residual current and the residual voltage (-3U0), compensated with a characteristic angle. Alternatively, the function can be set to strict 3I0 level with a check of angle .

Directional residual power can also be used to detect and give selective trip of phase- to-earth faults in high impedance earthed networks. The protection uses the residual power component 3I0 3U0 cos , where is the angle between the residual current and the reference residual voltage, compensated with a characteristic angle.

A normal non-directional residual current function can also be used with definite or inverse time delay.

A backup neutral point voltage function is also available for non-directional residual overvoltage protection.

In an isolated network, that is, the network is only coupled to earth via the capacitances between the phase conductors and earth, the residual current always has -90 phase shift compared to the residual voltage ( 3U0). The characteristic angle is chosen to -90 in such a network.

In resistance earthed networks or in Petersen coil earthed, with a parallel resistor, the active residual current component (in phase with the residual voltage) should be used for the earth fault detection. In such networks, the characteristic angle is chosen to 0.

As the amplitude of the residual current is independent of the fault location, the selectivity of the earth fault protection is achieved by time selectivity.

When should the sensitive directional residual overcurrent protection be used and when should the sensitive directional residual power protection be used? Consider the following:

Sensitive directional residual overcurrent protection gives possibility for better sensitivity. The setting possibilities of this function are down to 0.25 % of IBase,

Section 7 1MRK 511 310-UEN B Current protection

150 Application manual

1 A or 5 A. This sensitivity is in most cases sufficient in high impedance network applications, if the measuring CT ratio is not too high.

Sensitive directional residual power protection gives possibility to use inverse time characteristics. This is applicable in large high impedance earthed networks, with large capacitive earth fault currents. In such networks, the active fault current would be small and by using sensitive directional residual power protection, the operating quantity is elevated. Therefore, better possibility to detect earth faults. In addition, in low impedance earthed networks, the inverse time characteristic gives better time-selectivity in case of high zero-resistive fault currents.

Phase currents

Phase- ground

voltages

IN

UN

IEC13000013-1-en.vsd

IEC13000013 V1 EN

Figure 62: Connection of SDEPSDE to analog preprocessing function block

Overcurrent functionality uses true 3I0, i.e. sum of GRPxL1, GRPxL2 and GRPxL3. For 3I0 to be calculated, connection is needed to all three phase inputs.

Directional and power functionality uses IN and UN. If a connection is made to GRPxN this signal is used, else if connection is made to all inputs GRPxL1, GRPxL2 and GRPxL3 the internally calculated sum of these inputs (3I0 and 3U0) will be used.

7.6.3 Setting guidelines

The sensitive earth fault protection is intended to be used in high impedance earthed systems, or in systems with resistive earthing where the neutral point resistor gives an earth fault current larger than what normal high impedance gives but smaller than the phase-to-phase short circuit current.

In a high impedance system the fault current is assumed to be limited by the system zero sequence shunt impedance to earth and the fault resistance only. All the series impedances in the system are assumed to be zero.

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151 Application manual

In the setting of earth fault protection, in a high impedance earthed system, the neutral point voltage (zero sequence voltage) and the earth fault current will be calculated at the desired sensitivity (fault resistance). The complex neutral point voltage (zero sequence) can be calculated as:

phase

0 f

0

U U

3 R 1

Z

=

+

EQUATION1943 V1 EN (Equation 46)

Where

Uphase is the phase voltage in the fault point before the fault,

Rf is the resistance to earth in the fault point and

Z0 is the system zero sequence impedance to earth

The fault current, in the fault point, can be calculated as:

phase

j 0

0 f

3 U I 3I

Z 3 R

= =

+

EQUATION1944 V1 EN (Equation 47)

The impedance Z0 is dependent on the system earthing. In an isolated system (without neutral point apparatus) the impedance is equal to the capacitive coupling between the phase conductors and earth:

phase

0 c

j

3 U Z jX j

I

= — = —

EQUATION1945 V1 EN (Equation 48)

Where

Ij is the capacitive earth fault current at a non-resistive phase-to-earth fault

Xc is the capacitive reactance to earth

In a system with a neutral point resistor (resistance earthed system) the impedance Z0 can be calculated as:

Section 7 1MRK 511 310-UEN B Current protection

152 Application manual

c n 0

c n

jX 3R Z

jX 3R

— =

— +

EQUATION1946 V1 EN (Equation 49)

Where

Rn is the resistance of the neutral point resistor

In many systems there is also a neutral point reactor (Petersen coil) connected to one or more transformer neutral points. In such a system the impedance Z0 can be calculated as:

( ) n n c

0 c n n

n c n n c

9R X X Z jX // 3R // j3X

3X X j3R 3X X = — =

+ —

EQUATION1947 V1 EN (Equation 50)

Where

Xn is the reactance of the Petersen coil. If the Petersen coil is well tuned we have 3Xn = Xc In this case the impedance Z0 will be: Z0 = 3Rn

Now consider a system with an earthing via a resistor giving higher earth fault current than the high impedance earthing. The series impedances in the system can no longer be neglected. The system with a single phase to earth fault can be described as in Figure 63.

1MRK 511 310-UEN B Section 7 Current protection

153 Application manual

Substation A

Substation B

ZlineAB,1 (pos. seq) ZlineAB,0 (zero seq)

ZlineBC,1 (pos. seq) ZlineBC,0 (zero seq)

U0A

U0B

3I0

Phase to earth fault

RN ZT,1 (pos. seq) ZT,0 (zero seq)

Source impedance Zsc (pos. seq)

en06000654.vsd

IEC06000654 V1 EN

Figure 63: Equivalent of power system for calculation of setting

The residual fault current can be written:

phase

0

1 0 f

3U 3I

2 Z Z 3 R =

+ +

EQUATION1948 V1 EN (Equation 51)

Where

Uphase is the phase voltage in the fault point before the fault

Z1 is the total positive sequence impedance to the fault point. Z1 = Zsc+ZT,1+ZlineAB,1+ZlineBC,1

Z0 is the total zero sequence impedance to the fault point. Z0 = ZT,0+3RN+ZlineAB,0+ZlineBC,0

Rf is the fault resistance.

The residual voltages in stations A and B can be written:

( )0 A 0 T,0 NU 3I Z 3R= +

EQUATION1949 V1 EN (Equation 52)

OB 0 T,0 N lineAB,0U 3I (Z 3R Z )= + +

EQUATION1950 V1 EN (Equation 53)

Section 7 1MRK 511 310-UEN B Current protection

154 Application manual

The residual power, measured by the sensitive earth fault protections in A and B will be:

0 A 0A 0S 3U 3I=

EQUATION1951 V1 EN (Equation 54)

0 B 0B 0S 3U 3I=

EQUATION1952 V1 EN (Equation 55)

The residual power is a complex quantity. The protection will have a maximum sensitivity in the characteristic angle RCA. The apparent residual power component in the characteristic angle, measured by the protection, can be written:

0 A ,prot 0A 0 AS 3U 3I cosj=

EQUATION1953 V1 EN (Equation 56)

0 B,prot 0B 0 BS 3U 3I cosj=

EQUATION1954 V1 EN (Equation 57)

The angles A and B are the phase angles between the residual current and the residual voltage in the station compensated with the characteristic angle RCA.

The protection will use the power components in the characteristic angle direction for measurement, and as base for the inverse time delay.

The inverse time delay is defined as:

0 0 inv

0 0

kSN (3I 3U cos (reference))t 3I 3U cos (measured)

j =

j

EQUATION1942 V2 EN (Equation 58)

The function can be set On/Off with the setting of Operation.

Common base IED values for primary current (IBase), primary voltage (UBase) and primary power (SBase) are set in a Global base values for settings function GBASVAL.

GlobalBaseSel: It is used to select a GBASVAL function for reference of base values.

RotResU: It is a setting for rotating the polarizing quantity ( 3U0) by 0 or 180 degrees. This parameter is set to 180 degrees by default in order to inverse the residual voltage ( 3U0) to calculate the reference voltage (-3U0 e-jRCADir). Since the reference voltage is used as the polarizing quantity for directionality, it is important to set this parameter correctly.

With the setting OpMode the principle of directional function is chosen.

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155 Application manual

With OpMode set to 3I0cosfi the current component in the direction equal to the characteristic angleRCADir has the maximum sensitivity. The characteristic for RCADir is equal to 0 is shown in Figure 64.

= =o o0 , 90RCADir ROADir

03I

j = -0 refang(3I ) ang(3U )

— =0 ref3U U 03I cos j

IEC06000648-4-en.vsd

IEC06000648 V4 EN

Figure 64: Characteristic for RCADir equal to 0

The characteristic is for RCADir equal to -90 is shown in Figure 65.

IEC06000649_3_en.vsd

refU = = 90 , 90RCADir ROADir

03I

03 I cos

= 0(3 ) ( )refang I ang U

03U

IEC06000649 V3 EN

Figure 65: Characteristic for RCADir equal to -90

When OpMode is set to 3U03I0cosfi the apparent residual power component in the direction is measured.

When OpMode is set to 3I0 and fi the function will operate if the residual current is larger than the setting INDir> and the residual current angle is within the sector RCADir ROADir.

Section 7 1MRK 511 310-UEN B Current protection

156 Application manual

The characteristic for this OpMode when RCADir = 0 and ROADir = 80 is shown in figure 66.

-3U0

Operate area

3I0

RCADir = 0

ROADir = 80

IEC06000652-3-en.vsd IEC06000652 V3 EN

Figure 66: Characteristic for RCADir = 0 and ROADir = 80

DirMode is set Forward or Reverse to set the direction of the operation for the directional function selected by the OpMode.

All the directional protection modes have a residual current release level setting INRel> which is set in % of IBase. This setting should be chosen smaller than or equal to the lowest fault current to be detected.

All the directional protection modes have a residual voltage release level setting UNRel> which is set in % of UBase. This setting should be chosen smaller than or equal to the lowest fault residual voltage to be detected.

tDef is the definite time delay, given in s, for the directional residual current protection.

tReset is the time delay before the definite timer gets reset, given in s. With a tReset time of few cycles, there is an increased possibility to clear intermittent earth faults correctly. The setting shall be much shorter than the set trip delay. In case of intermittent earth faults, the fault current is intermittently dropping below the set value during consecutive cycles. Therefore the definite timer should continue for a certain time equal to tReset even though the fault current has dropped below the set value.

The characteristic angle of the directional functions RCADir is set in degrees. RCADir is normally set equal to 0 in a high impedance earthed network with a neutral point resistor as the active current component is appearing out on the faulted feeder only. RCADir is set equal to -90 in an isolated network as all currents are mainly capacitive.

1MRK 511 310-UEN B Section 7 Current protection

157 Application manual

ROADir is Relay Operating Angle. ROADir is identifying a window around the reference direction in order to detect directionality. ROADir is set in degrees. For angles differing more than ROADir from RCADir the function is blocked. The setting can be used to prevent unwanted operation for non-faulted feeders, with large capacitive earth fault current contributions, due to CT phase angle error.

INCosPhi> is the operate current level for the directional function when OpMode is set 3I0Cosfi. The setting is given in % of IBase. The setting should be based on calculation of the active or capacitive earth fault current at required sensitivity of the protection.

SN> is the operate power level for the directional function when OpMode is set 3I03U0Cosfi. The setting is given in % of SBase. The setting should be based on calculation of the active or capacitive earth fault residual power at required sensitivity of the protection.

The input transformer for the Sensitive directional residual over current and power protection function has the same short circuit capacity as the phase current transformers. Hence, there is no specific requirement for the external CT core, i.e. any CT core can be used.

If the time delay for residual power is chosen the delay time is dependent on two setting parameters. SRef is the reference residual power, given in % of SBase. kSN is the time multiplier. The time delay will follow the following expression:

inv 0 0

kSN Sref t

3I 3U cos (measured)j

=

EQUATION1957 V1 EN (Equation 59)

INDir> is the operate current level for the directional function when OpMode is set 3I0 and fi. The setting is given in % of IBase. The setting should be based on calculation of the earth fault current at required sensitivity of the protection.

OpINNonDir> is set On to activate the non-directional residual current protection.

INNonDir> is the operate current level for the non-directional function. The setting is given in % of IBase. This function can be used for detection and clearance of cross- country faults in a shorter time than for the directional function. The current setting should be larger than the maximum single-phase residual current on the protected line.

TimeChar is the selection of time delay characteristic for the non-directional residual current protection. Definite time delay and different types of inverse time characteristics are available:

Table 14: Inverse time characteristics

Curve name ANSI Extremely Inverse

ANSI Very Inverse

ANSI Normal Inverse

Table continues on next page

Section 7 1MRK 511 310-UEN B Current protection

158 Application manual

Curve name ANSI Moderately Inverse

ANSI/IEEE Definite time

ANSI Long Time Extremely Inverse

ANSI Long Time Very Inverse

ANSI Long Time Inverse

IEC Normal Inverse

IEC Very Inverse

IEC Inverse

IEC Extremely Inverse

IEC Short Time Inverse

IEC Long Time Inverse

IEC Definite Time

User Programmable

ASEA RI

RXIDG (logarithmic)

See chapter Inverse time characteristics in Technical Manual for the description of different characteristics

tPCrv, tACrv, tBCrv, tCCrv: Parameters for customer creation of inverse time characteristic curve (Curve type = 17). The time characteristic equation is:

[ ] = +

— >

p

A t s B InMult

i C

in EQUATION1958 V1 EN (Equation 60)

tINNonDir is the definite time delay for the non directional earth fault current protection, given in s.

OpUN> is set On to activate the trip function of the residual over voltage protection.

tUN is the definite time delay for the trip function of the residual voltage protection, given in s.

7.7 Thermal overload protection, one time constant, Celsius/Fahrenheit LCPTTR/LFPTTR

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159 Application manual

7.7.1 Identification Function description IEC 61850

identification IEC 60617 identification

ANSI/IEEE C37.2 device number

Thermal overload protection, one time constant, Celsius

LCPTTR 26

Thermal overload protection, one time constant, Fahrenheit

LFPTTR 26

7.7.2 Application

Lines and cables in the power system are designed for a certain maximum load current level. If the current exceeds this level the losses will be higher than expected. As a consequence the temperature of the conductors will increase. If the temperature of the lines and cables reaches too high values the equipment might be damaged:

The sag of overhead lines can reach unacceptable value. If the temperature of conductors, for example aluminium conductors, gets too

high the material will be destroyed. In cables the insulation can be damaged as a consequence of the overtemperature.

As a consequence of this phase to phase or phase to earth faults can occur.

In stressed situations in the power system it can be required to overload lines and cables for a limited time. This should be done while managing the risks safely.

The thermal overload protection provides information that makes a temporary overloading of cables and lines possible. The thermal overload protection estimates the conductor temperature continuously, in Celsius or Fahrenheit depending on whether LCPTTR or LFPTTR is chosen. This estimation is made by using a thermal model of the line/cable based on the current measurement.

If the temperature of the protected object reaches a set warning level AlarmTemp, a signal ALARM can be given to the operator. This enables actions in the power system to be taken before dangerous temperatures are reached. If the temperature continues to increase to the trip value TripTemp, the protection initiates trip of the protected line.

7.7.3 Setting guideline

The parameters for the Thermal overload protection, one time constant, Celsius/ Fahrenheit LCPTTR/LFPTTR are set via the local HMI or PCM600.

The following settings can be done for the thermal overload protection.

Operation: Off/On

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160 Application manual

GlobalBaseSel is used to select a GBASVAL function for reference of base values, primary current (IBase), primary voltage (UBase) and primary power (SBase).

Imult: Enter the number of lines in case the protection function is applied on multiple parallel lines sharing one CT.

IRef: Reference, steady state current, given in % of IBase that will give a steady state (end) temperature rise TRef. It is suggested to set this current to the maximum steady state current allowed for the line/cable under emergency operation (a few hours per year).

TRef: Reference temperature rise (end temperature) corresponding to the steady state current IRef. From cable manuals current values with corresponding conductor temperature are often given. These values are given for conditions such as earth temperature, ambient air temperature, way of laying of cable and earth thermal resistivity. From manuals for overhead conductor temperatures and corresponding current is given.

Tau: The thermal time constant of the protected circuit given in minutes. Please refer to manufacturers manuals for details.

TripTemp: Temperature value for trip of the protected circuit. For cables, a maximum allowed conductor temperature is often stated to be 90C (194F). For overhead lines, the critical temperature for aluminium conductor is about 90 — 100C (194-212F). For a copper conductor a normal figure is 70C (158F).

AlarmTemp: Temperature level for alarm of the protected circuit. ALARM signal can be used as a warning before the circuit is tripped. Therefore the setting shall be lower than the trip level. It shall at the same time be higher than the maximum conductor temperature at normal operation. For cables this level is often given to 65C (149F). Similar values are stated for overhead lines. A suitable setting can be about 15C (59F) below the trip value.

ReclTemp: Temperature where lockout signal LOCKOUT from the protection is released. When the thermal overload protection trips a lock-out signal is activated. This signal is intended to block switch in of the protected circuit as long as the conductor temperature is high. The signal is released when the estimated temperature is below the set value. This temperature value should be chosen below the alarm temperature.

7.8 Thermal overload protection, two time constants TRPTTR

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161 Application manual

7.8.1 Identification Function description IEC 61850

identification IEC 60617 identification

ANSI/IEEE C37.2 device number

Thermal overload protection, two time constants

TRPTTR

SYMBOL-A V1 EN

49

7.8.2 Application

Transformers in the power system are designed for a certain maximum load current (power) level. If the current exceeds this level the losses will be higher than expected. As a consequence the temperature of the transformer will increase. If the temperature of the transformer reaches too high a value, the equipment might be damaged;

The insulation within the transformer experiences forced ageing. As a consequence of this, the risk of internal phase-to-phase or phase-to-earth faults increases.

There might be hot spots within the transformer, which degrades the paper insulation. It might also cause bubbling in the transformer oil.

In stressed situations in the power system it can be required to overload transformers for a limited time. This should be done without the above mentioned risks. The thermal overload protection provides information and makes temporary overloading of transformers possible.

The permissible load level of a power transformer is highly dependent on the cooling system of the transformer. There are two main principles:

OA: The air is naturally circulated to the coolers without fans and the oil is naturally circulated without pumps.

FOA: The coolers have fans to force air for cooling and pumps to force the circulation of the transformer oil.

The protection can have two sets of parameters, one for non-forced cooling and one for forced cooling. Both the permissive steady state loading level as well as the thermal time constant is influenced by the cooling system of the transformer. The two parameters sets can be activated by the binary input signal COOLING. This can be used for transformers where forced cooling can be taken out of operation, for example at fan or pump faults.

The thermal overload protection estimates the internal heat content of the transformer (temperature) continuously. This estimation is made by using a thermal model of the transformer which is based on current measurement.

If the heat content of the protected transformer reaches a set alarm level a signal can be given to the operator. Two alarm levels are available. This enables preventive

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162 Application manual

actions in the power system to be taken before dangerous temperatures are reached. If the temperature continues to increase to the trip value, the protection initiates a trip of the protected transformer.

After tripping by the thermal overload protection, the transformer will cool down over time. There will be a time gap before the heat content (temperature) reaches such a level so that the transformer can be taken into service again. Therefore, the function will continue to estimate the heat content using a set cooling time constant. Energizing of the transformer can be blocked until the heat content has reached a set level.

7.8.3 Setting guideline

The parameters for the thermal overload protection, two time constants (TRPTTR) are set via the local HMI or Protection and Control IED Manager (PCM600).

The following settings can be done for the thermal overload protection:

Operation: Off/On

Operation: Sets the mode of operation. Off switches off the complete function.

GlobalBaseSel: Selects the global base value group used by the function to define (IBase), (UBase) and (SBase).

IRef: Reference level of the current given in % of IBase. When the current is equal to IRef the final (steady state) heat content is equal to 1. It is suggested to give a setting corresponding to the rated current of the transformer winding.

IRefMult: If a binary input ENMULT is activated the reference current value can be multiplied by the factor IRefMult. The activation could be used in case of deviating ambient temperature from the reference value. In the standard for loading of a transformer an ambient temperature of 20C is used. For lower ambient temperatures the load ability is increased and vice versa. IRefMult can be set within a range: 0.01 — 10.00.

IBase1: Base current for setting given as percentage of IBase. This setting shall be related to the status with no COOLING input. It is suggested to give a setting corresponding to the rated current of the transformer with natural cooling (OA).

IBase2: Base current for setting given as percentage of IBase. This setting shall be related to the status with activated COOLING input. It is suggested to give a setting corresponding to the rated current of the transformer with forced cooling (FOA). If the transformer has no forced cooling IBase2 can be set equal to IBase1.

Tau1: The thermal time constant of the protected transformer, related to IBase1 (no cooling) given in minutes.

Tau2: The thermal time constant of the protected transformer, related to IBase2 (with cooling) given in minutes.

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163 Application manual

The thermal time constant should be obtained from the transformer manufacturers manuals. The thermal time constant is dependent on the cooling and the amount of oil. Normal time constants for medium and large transformers (according to IEC 60076-7) are about 2.5 hours for naturally cooled transformers and 1.5 hours for forced cooled transformers.

The time constant can be estimated from measurements of the oil temperature during a cooling sequence (described in IEC 60076-7). It is assumed that the transformer is operated at a certain load level with a constant oil temperature (steady state operation). The oil temperature above the ambient temperature is DQo0. Then the transformer is disconnected from the grid (no load). After a time t of at least 30 minutes the temperature of the oil is measured again. Now the oil temperature above the ambient temperature is DQot. The thermal time constant can now be estimated as:

0ln lno ot

tt = DQ — DQ

EQUATION1180 V1 EN (Equation 61)

If the transformer has forced cooling (FOA) the measurement should be made both with and without the forced cooling in operation, giving Tau2 and Tau1.

The time constants can be changed if the current is higher than a set value or lower than a set value. If the current is high it is assumed that the forced cooling is activated while it is deactivated at low current. The setting of the parameters below enables automatic adjustment of the time constant.

Tau1High: Multiplication factor to adjust the time constant Tau1 if the current is higher than the set value IHighTau1. IHighTau1 is set in % of IBase1.

Tau1Low: Multiplication factor to adjust the time constant Tau1 if the current is lower than the set value ILowTau1. ILowTau1 is set in % of IBase1.

Tau2High: Multiplication factor to adjust the time constant Tau2 if the current is higher than the set value IHighTau2. IHighTau2 is set in % of IBase2.

Tau2Low: Multiplication factor to adjust the time constant Tau2 if the current is lower than the set value ILowTau2. ILowTau2 is set in % of IBase2.

The possibility to change time constant with the current value as the base can be useful in different applications. Below some examples are given:

In case a total interruption (low current) of the protected transformer all cooling possibilities will be inactive. This can result in a changed value of the time constant.

If other components (motors) are included in the thermal protection, there is a risk of overheating of that equipment in case of very high current. The thermal time constant is often smaller for a motor than for the transformer.

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164 Application manual

ITrip: The steady state current that the transformer can withstand. The setting is given in % of IBase1 or IBase2.

Alarm1: Heat content level for activation of the signal ALARM1. ALARM1 is set in % of the trip heat content level.

Alarm2: Heat content level for activation of the output signal ALARM2. ALARM2 is set in % of the trip heat content level.

ResLo: Lockout release level of heat content to release the lockout signal. When the thermal overload protection trips a lock-out signal is activated. This signal is intended to block switching on of the protected circuit transformer as long as the transformer temperature is high. The signal is released when the estimated heat content is below the set value. This temperature value should be chosen below the alarm temperature. ResLo is set in % of the trip heat content level.

ThetaInit: Heat content before activation of the function. This setting can be set a little below the alarm level. If the transformer is loaded before the activation of the protection function, its temperature can be higher than the ambient temperature. The start point given in the setting will prevent risk of no trip at overtemperature during the first moments after activation. ThetaInit: is set in % of the trip heat content level.

Warning: If the calculated time to trip factor is below the setting Warning a warning signal is activated. The setting is given in minutes.

7.9 Breaker failure protection 3-phase activation and output CCRBRF

7.9.1 Identification Function description IEC 61850

identification IEC 60617 identification

ANSI/IEEE C37.2 device number

Breaker failure protection, 3-phase activation and output

CCRBRF

3I>BF

SYMBOL-U V1 EN

50BF

7.9.2 Application

In the design of the fault clearance system the N-1 criterion is often used. This means that a fault needs to be cleared even if any component in the fault clearance system is faulty. One necessary component in the fault clearance system is the circuit breaker. It is from practical and economical reason not feasible to duplicate the circuit breaker for the protected component. Instead a breaker failure protection is used.

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Breaker failure protection, 3-phase activation and output (CCRBRF) will issue a back-up trip command to adjacent circuit breakers in case of failure to trip of the normal circuit breaker for the protected component. The detection of failure to break the current through the breaker is made by means of current measurement or as detection of remaining trip signal (unconditional).

CCRBRF can also give a re-trip. This means that a second trip signal is sent to the protected circuit breaker. The re-trip function can be used to increase the probability of operation of the breaker, or it can be used to avoid back-up trip of many breakers in case of mistakes during relay maintenance and test.

7.9.3 Setting guidelines

The parameters for Breaker failure protection 3-phase activation and output CCRBRF are set via the local HMI or PCM600.

The following settings can be done for the breaker failure protection.

Operation: Off/On

FunctionMode This parameter can be set Current or Contact. This states the way the detection of failure of the breaker is performed. In the mode current the current measurement is used for the detection. In the mode Contact the long duration of breaker position signal is used as indicator of failure of the breaker. The mode Current&Contact means that both ways of detections are activated. Contact mode can be usable in applications where the fault current through the circuit breaker is small. This can be the case for some generator protection application (for example reverse power protection) or in case of line ends with weak end infeed.

RetripMode: This setting states how the re-trip function shall operate. Retrip Off means that the re-trip function is not activated. CB Pos Check (circuit breaker position check) and Current means that a phase current must be larger than the operate level to allow re-trip. CB Pos Check (circuit breaker position check) and Contact means re-trip is done when circuit breaker is closed (breaker position is used). No CBPos Check means re-trip is done without check of breaker position.

Table 15: Dependencies between parameters RetripMode and FunctionMode

RetripMode FunctionMode Description Retrip Off N/A the re-trip function is not

activated

CB Pos Check Current a phase current must be larger than the operate level to allow re-trip

Contact re-trip is done when breaker position indicates that breaker is still closed after re-trip time has elapsed

Current&Contact both methods are used

Table continues on next page

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166 Application manual

RetripMode FunctionMode Description No CBPos Check Current re-trip is done without check of

breaker position

Contact re-trip is done without check of breaker position

Current&Contact both methods are used

BuTripMode: Back-up trip mode is given to state sufficient current criteria to detect failure to break. For Current operation 2 out of 4 means that at least two currents, of the three-phase currents and the residual current, shall be high to indicate breaker failure. 1 out of 3 means that at least one current of the three-phase currents shall be high to indicate breaker failure. 1 out of 4 means that at least one current of the three- phase currents or the residual current shall be high to indicate breaker failure. In most applications 1 out of 3 is sufficient. For Contact operation means back-up trip is done when circuit breaker is closed (breaker position is used).

IP>: Current level for detection of breaker failure, set in % of IBase. This parameter should be set so that faults with small fault current can be detected. The setting can be chosen in accordance with the most sensitive protection function to start the breaker failure protection. Typical setting is 10% of IBase.

I>BlkCont: If any contact based detection of breaker failure is used this function can be blocked if any phase current is larger than this setting level. If the FunctionMode is set Current&Contact breaker failure for high current faults are safely detected by the current measurement function. To increase security the contact based function should be disabled for high currents. The setting can be given within the range 5 200% of IBase.

IN>: Residual current level for detection of breaker failure set in % of IBase. In high impedance earthed systems the residual current at phase- to-earth faults are normally much smaller than the short circuit currents. In order to detect breaker failure at single- phase-earth faults in these systems it is necessary to measure the residual current separately. Also in effectively earthed systems the setting of the earth-fault current protection can be chosen to relatively low current level. The BuTripMode is set 1 out of 4. The current setting should be chosen in accordance to the setting of the sensitive earth-fault protection. The setting can be given within the range 2 200 % of IBase.

t1: Time delay of the re-trip. The setting can be given within the range 0 60s in steps of 0.001 s. Typical setting is 0 50ms.

t2: Time delay of the back-up trip. The choice of this setting is made as short as possible at the same time as unwanted operation must be avoided. Typical setting is 90 200ms (also dependent of re-trip timer).

The minimum time delay for the re-trip can be estimated as:

_2 1 + + +cbopen BFP reset margint t t t t EQUATION1430 V1 EN (Equation 62)

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167 Application manual

where:

tcbopen is the maximum opening time for the circuit breaker

tBFP_reset is the maximum time for breaker failure protection to detect correct breaker function (the current criteria reset)

tmargin is a safety margin

It is often required that the total fault clearance time shall be less than a given critical time. This time is often dependent of the ability to maintain transient stability in case of a fault close to a power plant.

Time

The fault occurs

Protection operate time

Trip and Start CCRBRF

Normal tcbopen

Margin

Retrip delay t1 tcbopen after re-trip

tBFPreset

Minimum back-up trip delay t2

Critical fault clearance time for stability

IEC05000479_2_en.vsd

IEC05000479 V2 EN

Figure 67: Time sequence

t2MPh: Time delay of the back-up trip at multi-phase start. The critical fault clearance time is often shorter in case of multi-phase faults, compared to single phase-to-earth faults. Therefore there is a possibility to reduce the back-up trip delay for multi-phase faults. Typical setting is 90 150 ms.

t3: Additional time delay to t2 for a second back-up trip TRBU2. In some applications there might be a requirement to have separated back-up trip functions, tripping different back-up circuit breakers.

tCBAlarm: Time delay for alarm in case of indication of faulty circuit breaker. There is a binary input CBFLT from the circuit breaker. This signal is activated when internal supervision in the circuit breaker detect that the circuit breaker is unable to clear fault. This could be the case when gas pressure is low in a SF6 circuit breaker, of others. After the set time an alarm is given, so that actions can be done to repair the

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168 Application manual

circuit breaker. The time delay for back-up trip is bypassed when the CBFLT is active. Typical setting is 2.0 seconds.

tPulse: Trip pulse duration. This setting must be larger than the critical impulse time of circuit breakers to be tripped from the breaker failure protection. Typical setting is 200 ms.

7.10 Stub protection STBPTOC

7.10.1 Identification Function description IEC 61850

identification IEC 60617 identification

ANSI/IEEE C37.2 device number

Stub protection STBPTOC

3I>STUB

SYMBOL-T V1 EN

50STB

7.10.2 Application

In a 1-breaker switchyard the line protection and the busbar protection normally have overlap when a connected object is in service. When an object is taken out of service it is normally required to keep the diagonal of the 1-breaker switchyard in operation. This is done by opening the disconnector to the protected object. This will, however, disable the normal object protection (for example the distance protection) of the energized part between the circuit breakers and the open disconnector.

Stub protection STBPTOC is a simple phase overcurrent protection, fed from the two current transformer groups feeding the object taken out of service. The stub protection is only activated when the disconnector of the object is open. STBPTOCenables fast fault clearance of faults at the section between the CTs and the open disconnector.

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169 Application manual

IEC05000465 V2 EN

Figure 68: Typical connection for STBPTOC in 1-breaker arrangement.

7.10.3 Setting guidelines

The parameters for Stub protection STBPTOC are set via the local HMI or PCM600.

The following settings can be done for the stub protection.

Operation: Off/On

ReleaseMode: This parameter can be set Release or Continuous. With theRelease setting the function is only active when a binary release signal RELEASE into the function is activated. This signal is normally taken from an auxiliary contact (normally closed) of the line disconnector and connected to a binary input RELEASE of the IED. With the settingContinuous the function is activated independent of presence of any external release signal.

I>: Current level for the Stub protection, set in % of IBase. This parameter should be set so that all faults on the stub can be detected. The setting should thus be based on fault calculations.

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170 Application manual

t: Time delay of the operation. Normally the function shall be instantaneous.

7.11 Pole discordance protection CCPDSC

7.11.1 Identification Function description IEC 61850

identification IEC 60617 identification

ANSI/IEEE C37.2 device number

Pole discordance protection CCPDSC

PD

SYMBOL-S V1 EN

52PD

7.11.2 Application

There is a risk that a circuit breaker will get discordance between the poles at circuit breaker operation: closing or opening. One pole can be open and the other two closed, or two poles can be open and one closed. Pole discordance of a circuit breaker will cause unsymmetrical currents in the power system. The consequence of this can be:

Negative sequence currents that will give stress on rotating machines Zero sequence currents that might give unwanted operation of sensitive earth-

fault protections in the power system.

It is therefore important to detect situations with pole discordance of circuit breakers. When this is detected the breaker should be tripped directly.

Pole discordance protection CCPDSC will detect situation with deviating positions of the poles of the protected circuit breaker. The protection has two different options to make this detection:

By connecting the auxiliary contacts in the circuit breaker so that logic is created, a signal can be sent to the protection, indicating pole discordance. This logic can also be realized within the protection itself, by using opened and close signals for each circuit breaker pole, connected to the protection.

Each phase current through the circuit breaker is measured. If the difference between the phase currents is larger than a CurrUnsymLevel this is an indication of pole discordance, and the protection will operate.

7.11.3 Setting guidelines

The parameters for the Pole discordance protection CCPDSC are set via the local HMI or PCM600.

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171 Application manual

The following settings can be done for the pole discordance protection.

Operation: Off or On

tTrip: Time delay of the operation.

ContSel: Operation of the contact based pole discordance protection. Can be set: Off/PD signal from CB. If PD signal from CB is chosen the logic to detect pole discordance is made in the vicinity to the breaker auxiliary contacts and only one signal is connected to the pole discordance function. If the Pole pos aux cont. alternative is chosen each open close signal is connected to the IED and the logic to detect pole discordance is realized within the function itself.

CurrSel: Operation of the current based pole discordance protection. Can be set: Off/CB oper monitor/Continuous monitor. In the alternative CB oper monitor the function is activated only directly in connection to breaker open or close command (during 200 ms). In the alternative Continuous monitor function is continuously activated.

CurrUnsymLevel: Unsymmetrical magnitude of lowest phase current compared to the highest, set in % of the highest phase current. Natural difference between phase currents in 1 1/2 breaker installations must be considered. For circuit breakers in 1 1/2 breaker configured switch yards there might be natural unbalance currents through the breaker. This is due to the existence of low impedance current paths in the switch yard. This phenomenon must be considered in the setting of the parameter.

CurrRelLevel: Current magnitude for release of the function in % of IBase.

7.12 Directional underpower protection GUPPDUP

7.12.1 Identification Function description IEC 61850

identification IEC 60617 identification

ANSI/IEEE C37.2 device number

Directional underpower protection GUPPDUP P <

2 SYMBOL-LL V2 EN

37

7.12.2 Application

The task of a generator in a power plant is to convert mechanical energy available as a torque on a rotating shaft to electric energy.

Sometimes, the mechanical power from a prime mover may decrease so much that it does not cover bearing losses and ventilation losses. Then, the synchronous generator

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172 Application manual

becomes a synchronous motor and starts to take electric power from the rest of the power system. This operating state, where individual synchronous machines operate as motors, implies no risk for the machine itself. If the generator under consideration is very large and if it consumes lots of electric power, it may be desirable to disconnect it to ease the task for the rest of the power system.

Often, the motoring condition may imply that the turbine is in a very dangerous state. The task of the reverse power protection is to protect the turbine and not to protect the generator itself.

Steam turbines easily become overheated if the steam flow becomes too low or if the steam ceases to flow through the turbine. Therefore, turbo-generators should have reverse power protection. There are several contingencies that may cause reverse power: break of a main steam pipe, damage to one or more blades in the steam turbine or inadvertent closing of the main stop valves. In the last case, it is highly desirable to have a reliable reverse power protection. It may prevent damage to an otherwise undamaged plant.

During the routine shutdown of many thermal power units, the reverse power protection gives the tripping impulse to the generator breaker (the unit breaker). By doing so, one prevents the disconnection of the unit before the mechanical power has become zero. Earlier disconnection would cause an acceleration of the turbine generator at all routine shutdowns. This should have caused overspeed and high centrifugal stresses.

When the steam ceases to flow through a turbine, the cooling of the turbine blades will disappear. Now, it is not possible to remove all heat generated by the windage losses. Instead, the heat will increase the temperature in the steam turbine and especially of the blades. When a steam turbine rotates without steam supply, the electric power consumption will be about 2% of rated power. Even if the turbine rotates in vacuum, it will soon become overheated and damaged. The turbine overheats within minutes if the turbine loses the vacuum.

The critical time to overheating a steam turbine varies from about 0.5 to 30 minutes depending on the type of turbine. A high-pressure turbine with small and thin blades will become overheated more easily than a low-pressure turbine with long and heavy blades. The conditions vary from turbine to turbine and it is necessary to ask the turbine manufacturer in each case.

Power to the power plant auxiliaries may come from a station service transformer connected to the secondary side of the step-up transformer. Power may also come from a start-up service transformer connected to the external network. One has to design the reverse power protection so that it can detect reverse power independent of the flow of power to the power plant auxiliaries.

Hydro turbines tolerate reverse power much better than steam turbines do. Only Kaplan turbine and bulb turbines may suffer from reverse power. There is a risk that the turbine runner moves axially and touches stationary parts. They are not always strong enough to withstand the associated stresses.

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173 Application manual

Ice and snow may block the intake when the outdoor temperature falls far below zero. Branches and leaves may also block the trash gates. A complete blockage of the intake may cause cavitations. The risk for damages to hydro turbines can justify reverse power protection in unattended plants.

A hydro turbine that rotates in water with closed wicket gates will draw electric power from the rest of the power system. This power will be about 10% of the rated power. If there is only air in the hydro turbine, the power demand will fall to about 3%.

Diesel engines should have reverse power protection. The generator will take about 15% of its rated power or more from the system. A stiff engine may require perhaps 25% of the rated power to motor it. An engine that is good run in might need no more than 5%. It is necessary to obtain information from the engine manufacturer and to measure the reverse power during commissioning.

Gas turbines usually do not require reverse power protection.

Figure 69 illustrates the reverse power protection with underpower protection and with overpower protection. The underpower protection gives a higher margin and should provide better dependability. On the other hand, the risk for unwanted operation immediately after synchronization may be higher. One should set the underpower protection (reference angle set to 0) to trip if the active power from the generator is less than about 2%. One should set the overpower protection (reference angle set to 180) to trip if the power flow from the network to the generator is higher than 1%.

Underpower protection Overpower protection

Q Q

P P

Operating point without turbine torque

Margin Margin

Operate Line

Operate Line

Operating point without turbine torque

IEC09000019-2-en.vsd

IEC09000019 V2 EN

Figure 69: Reverse power protection with underpower or overpower protection

7.12.3 Setting guidelines

Operation: With the parameter Operation the function can be set On/Off.

Mode: The voltage and current used for the power measurement. The setting possibilities are shown in table 16.

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174 Application manual

Table 16: Complex power calculation

Set value Mode Formula used for complex power calculation L1, L2, L3 * * *

1 1 2 2 3 3L L L L L LS U I U I U I= + +

EQUATION1697 V1 EN (Equation 64)

Arone * * 1 2 1 2 3 3L L L L L LS U I U I= —

EQUATION1698 V1 EN (Equation 65)

PosSeq *3 PosSeq PosSeqS U I=

EQUATION1699 V1 EN (Equation 66)

L1L2 * * 1 2 1 2( )L L L LS U I I= —

EQUATION1700 V1 EN (Equation 67)

L2L3 * * 2 3 2 3( )L L L LS U I I= —

EQUATION1701 V1 EN (Equation 68)

L3L1 * * 3 1 3 1( )L L L LS U I I= —

EQUATION1702 V1 EN (Equation 69)

L1 * 1 13 L LS U I=

EQUATION1703 V1 EN (Equation 70)

L2 * 2 23 L LS U I=

EQUATION1704 V1 EN (Equation 71)

L3 * 3 33 L LS U I=

EQUATION1705 V1 EN (Equation 72)

The function has two stages that can be set independently.

With the parameter OpMode1(2) the function can be set On/Off.

The function gives trip if the power component in the direction defined by the setting Angle1(2) is smaller than the set pick up power value Power1(2)

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175 Application manual

Operate

Angle1(2)

Power1(2)

P

Q

en06000441.vsd

IEC06000441 V1 EN

Figure 70: Underpower mode

The setting Power1(2) gives the power component pick up value in the Angle1(2) direction. The setting is given in p.u. of the generator rated power, see equation 73.

Minimum recommended setting is 0.2% of SN when metering class CT inputs into the IED are used.

3NS UBase IBase=

EQUATION1708 V1 EN (Equation 73)

The setting Angle1(2) gives the characteristic angle giving maximum sensitivity of the power protection function. The setting is given in degrees. For active power the set angle should be 0 or 180. 0 should be used for generator low forward active power protection.

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176 Application manual

Operate Angle1(2) = 0

Power1(2)

P

Q

en06000556.vsd IEC06000556 V1 EN

Figure 71: For low forward power the set angle should be 0 in the underpower function

TripDelay1(2) is set in seconds to give the time delay for trip of the stage after pick up.

Hysteresis1(2) is given in p.u. of generator rated power according to equation 74.

3NS UBase IBase=

EQUATION1708 V1 EN (Equation 74)

The drop out power will be Power1(2) + Hysteresis1(2).

The possibility to have low pass filtering of the measured power can be made as shown in the formula:

( )1Old CalculatedS k S k S= + —

EQUATION1893 V1 EN (Equation 75)

Where

S is a new measured value to be used for the protection function

Sold is the measured value given from the function in previous execution cycle

SCalculated is the new calculated value in the present execution cycle

k is settable parameter

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177 Application manual

The value of k=0.92 is recommended in generator applications as the trip delay is normally quite long.

The calibration factors for current and voltage measurement errors are set % of rated current/voltage:

IAmpComp5, IAmpComp30, IAmpComp100

UAmpComp5, UAmpComp30, UAmpComp100

IAngComp5, IAngComp30, IAngComp100

The angle compensation is given as difference between current and voltage angle errors.

The values are given for operating points 5, 30 and 100% of rated current/voltage. The values should be available from instrument transformer test protocols.

7.13 Directional overpower protection GOPPDOP

7.13.1 Identification Function description IEC 61850

identification IEC 60617 identification

ANSI/IEEE C37.2 device number

Directional overpower protection GOPPDOP P >

2 DOCUMENT172362-IMG158942

V2 EN

32

7.13.2 Application

The task of a generator in a power plant is to convert mechanical energy available as a torque on a rotating shaft to electric energy.

Sometimes, the mechanical power from a prime mover may decrease so much that it does not cover bearing losses and ventilation losses. Then, the synchronous generator becomes a synchronous motor and starts to take electric power from the rest of the power system. This operating state, where individual synchronous machines operate as motors, implies no risk for the machine itself. If the generator under consideration is very large and if it consumes lots of electric power, it may be desirable to disconnect it to ease the task for the rest of the power system.

Often, the motoring condition may imply that the turbine is in a very dangerous state. The task of the reverse power protection is to protect the turbine and not to protect the generator itself.

Section 7 1MRK 511 310-UEN B Current protection

178 Application manual

Steam turbines easily become overheated if the steam flow becomes too low or if the steam ceases to flow through the turbine. Therefore, turbo-generators should have reverse power protection. There are several contingencies that may cause reverse power: break of a main steam pipe, damage to one or more blades in the steam turbine or inadvertent closing of the main stop valves. In the last case, it is highly desirable to have a reliable reverse power protection. It may prevent damage to an otherwise undamaged plant.

During the routine shutdown of many thermal power units, the reverse power protection gives the tripping impulse to the generator breaker (the unit breaker). By doing so, one prevents the disconnection of the unit before the mechanical power has become zero. Earlier disconnection would cause an acceleration of the turbine generator at all routine shutdowns. This should have caused overspeed and high centrifugal stresses.

When the steam ceases to flow through a turbine, the cooling of the turbine blades will disappear. Now, it is not possible to remove all heat generated by the windage losses. Instead, the heat will increase the temperature in the steam turbine and especially of the blades. When a steam turbine rotates without steam supply, the electric power consumption will be about 2% of rated power. Even if the turbine rotates in vacuum, it will soon become overheated and damaged. The turbine overheats within minutes if the turbine loses the vacuum.

The critical time to overheating of a steam turbine varies from about 0.5 to 30 minutes depending on the type of turbine. A high-pressure turbine with small and thin blades will become overheated more easily than a low-pressure turbine with long and heavy blades. The conditions vary from turbine to turbine and it is necessary to ask the turbine manufacturer in each case.

Power to the power plant auxiliaries may come from a station service transformer connected to the primary side of the step-up transformer. Power may also come from a start-up service transformer connected to the external network. One has to design the reverse power protection so that it can detect reverse power independent of the flow of power to the power plant auxiliaries.

Hydro turbines tolerate reverse power much better than steam turbines do. Only Kaplan turbine and bulb turbines may suffer from reverse power. There is a risk that the turbine runner moves axially and touches stationary parts. They are not always strong enough to withstand the associated stresses.

Ice and snow may block the intake when the outdoor temperature falls far below zero. Branches and leaves may also block the trash gates. A complete blockage of the intake may cause cavitations. The risk for damages to hydro turbines can justify reverse power protection in unattended plants.

A hydro turbine that rotates in water with closed wicket gates will draw electric power from the rest of the power system. This power will be about 10% of the rated power. If there is only air in the hydro turbine, the power demand will fall to about 3%.

1MRK 511 310-UEN B Section 7 Current protection

179 Application manual

Diesel engines should have reverse power protection. The generator will take about 15% of its rated power or more from the system. A stiff engine may require perhaps 25% of the rated power to motor it. An engine that is well run in might need no more than 5%. It is necessary to obtain information from the engine manufacturer and to measure the reverse power during commissioning.

Gas turbines usually do not require reverse power protection.

Figure 72 illustrates the reverse power protection with underpower IED and with overpower IED. The underpower IED gives a higher margin and should provide better dependability. On the other hand, the risk for unwanted operation immediately after synchronization may be higher. One should set the underpower IED to trip if the active power from the generator is less than about 2%. One should set the overpower IED to trip if the power flow from the network to the generator is higher than 1%.

Underpower IED Overpower IED

Q Q

P P

Operating point without turbine torque

Margin Margin

Operate Line

Operate Line

Operating point without turbine torque

IEC06000315-2-en.vsd IEC06000315 V2 EN

Figure 72: Reverse power protection with underpower IED and overpower IED

7.13.3 Setting guidelines

Operation: With the parameter Operation the function can be set On/Off.

Mode: The voltage and current used for the power measurement. The setting possibilities are shown in table 17.

Table 17: Complex power calculation

Set value Mode Formula used for complex power calculation L1, L2, L3 * * *

1 1 2 2 3 3L L L L L LS U I U I U I= + +

EQUATION1697 V1 EN (Equation 77)

Arone * * 1 2 1 2 3 3L L L L L LS U I U I= —

EQUATION1698 V1 EN (Equation 78)

PosSeq *3 PosSeq PosSeqS U I=

EQUATION1699 V1 EN (Equation 79)

Table continues on next page

Section 7 1MRK 511 310-UEN B Current protection

180 Application manual

Set value Mode Formula used for complex power calculation L1L2 * *

1 2 1 2( )L L L LS U I I= —

EQUATION1700 V1 EN (Equation 80)

L2L3 * * 2 3 2 3( )L L L LS U I I= —

EQUATION1701 V1 EN (Equation 81)

L3L1 * * 3 1 3 1( )L L L LS U I I= —

EQUATION1702 V1 EN (Equation 82)

L1 * 1 13 L LS U I=

EQUATION1703 V1 EN (Equation 83)

L2 * 2 23 L LS U I=

EQUATION1704 V1 EN (Equation 84)

L3 * 3 33 L LS U I=

EQUATION1705 V1 EN (Equation 85)

The function has two stages that can be set independently.

With the parameter OpMode1(2) the function can be set On/Off.

The function gives trip if the power component in the direction defined by the setting Angle1(2) is larger than the set pick up power value Power1(2)

1MRK 511 310-UEN B Section 7 Current protection

181 Application manual

Operate

Angle1(2)

Power1(2)

P

Q

en06000440.vsd

IEC06000440 V1 EN

Figure 73: Overpower mode

The setting Power1(2) gives the power component pick up value in the Angle1(2) direction. The setting is given in p.u. of the generator rated power, see equation 86.

Minimum recommended setting is 0.2% of SN when metering class CT inputs into the IED are used.

3NS UBase IBase=

EQUATION1708 V1 EN (Equation 86)

The setting Angle1(2) gives the characteristic angle giving maximum sensitivity of the power protection function. The setting is given in degrees. For active power the set angle should be 0 or 180. 180 should be used for generator reverse power protection.

Section 7 1MRK 511 310-UEN B Current protection

182 Application manual

Operate Angle1(2 ) = 180 o

Power1(2)

P

Q

IEC06000557-2-en.vsd IEC06000557 V2 EN

Figure 74: For reverse power the set angle should be 180 in the overpower function

TripDelay1(2) is set in seconds to give the time delay for trip of the stage after pick up.

Hysteresis1(2) is given in p.u. of generator rated power according to equation 87.

3NS UBase IBase=

EQUATION1708 V1 EN (Equation 87)

The drop out power will be Power1(2) — Hysteresis1(2).

The possibility to have low pass filtering of the measured power can be made as shown in the formula:

( )1Old CalculatedS k S k S= + —

EQUATION1893 V1 EN (Equation 88)

Where

S is a new measured value to be used for the protection function

Sold is the measured value given from the function in previous execution cycle

SCalculated is the new calculated value in the present execution cycle

k is settable parameter

1MRK 511 310-UEN B Section 7 Current protection

183 Application manual

The value of k=0.92 is recommended in generator applications as the trip delay is normally quite long.

The calibration factors for current and voltage measurement errors are set % of rated current/voltage:

IAmpComp5, IAmpComp30, IAmpComp100

UAmpComp5, UAmpComp30, UAmpComp100

IAngComp5, IAngComp30, IAngComp100

The angle compensation is given as difference between current and voltage angle errors.

The values are given for operating points 5, 30 and 100% of rated current/voltage. The values should be available from instrument transformer test protocols.

7.14 Broken conductor check BRCPTOC

7.14.1 Identification Function description IEC 61850

identification IEC 60617 identification

ANSI/IEEE C37.2 device number

Broken conductor check BRCPTOC — 46

7.14.2 Application

Conventional protection functions can not detect the broken conductor condition. Broken conductor check (BRCPTOC) function, consisting of continuous current unsymmetrical check on the line where the IED connected will give alarm or trip at detecting broken conductors.

7.14.3 Setting guidelines

Broken conductor check BRCPTOC must be set to detect open phase/s (series faults) with different loads on the line. BRCPTOC must at the same time be set to not operate for maximum asymmetry which can exist due to, for example, not transposed power lines.

All settings are in primary values or percentage.

Set IBase (given in GlobalBaseSel) to power line rated current or CT rated current.

Set minimum operating level per phase IP> to typically 10-20% of rated current.

Section 7 1MRK 511 310-UEN B Current protection

184 Application manual

Set the unsymmetrical current, which is relation between the difference of the minimum and maximum phase currents to the maximum phase current to typical Iub> = 50%.

Note that it must be set to avoid problem with asymmetry under minimum operating conditions.

Set the time delay tOper = 5 — 60 seconds and reset time tReset = 0.010 — 60.000 seconds.

7.15 Capacitor bank protection CBPGAPC

7.15.1 Identification Function description IEC 61850

identification IEC 60617

identification ANSI/IEEE C37.2

device number Capacitor bank protection CBPGAPC — —

7.15.2 Application

Shunt capacitor banks (SCBs) are somewhat specific and different from other power system elements. These specific features of SCB are briefly summarized in this section.

A capacitor unit is the building block used for SCB construction. The capacitor unit is made up of individual capacitor elements, arranged in parallel or series connections. Capacitor elements normally consist of aluminum foil, paper, or film-insulated cells immersed in a biodegradable insulating fluid and are sealed in a metallic container. The internal discharge resistor is also integrated within the capacitor unit in order to reduce trapped residual voltage after disconnection of the SCB from the power system. Units are available in a variety of voltage ratings (240V to 25kV) and sizes (2.5kVAr to about 1000kVAr). Capacitor unit can be designed with one or two bushings.

The high-voltage SCB is normally constructed using individual capacitor units connected in series and/or parallel to obtain the required voltage and MVAr rating. Typically the neighboring capacitor units are mounted in racks. Each rack must be insulated from the other by insulators because the can casing within each rack are at a certain potential. Refer figure 75 for an example:

1MRK 511 310-UEN B Section 7 Current protection

185 Application manual

Capacitor Unit (Can)

Rack

IEC09000753_1_en.vsd

IEC09000753 V1 EN

Figure 75: Replacement of a faulty capacitor unit within SCB

There are four types of the capacitor unit fusing designs which are used for construction of SCBs:

Externally fused

where an individual fuse, externally mounted, protects each capacitor unit.

Internally fused

where each capacitor element is fused inside the capacitor unit

Fuseless where SCB is built from series connections of the individual capacitor units (that is, strings) and without any fuses

Unfused where, in contrary to the fuseless configuration, a series or parallel connection of the capacitor units is used to form SCB, still without any fuses

Which type of fusing is used may depend on can manufacturer or utility preference and previous experience.

Section 7 1MRK 511 310-UEN B Current protection

186 Application manual

Because the SCBs are built from the individual capacitor units the overall connections may vary. Typically used SCB configurations are:

1. Delta-connected banks (generally used only at distribution voltages) 2. Single wye-connected banks 3. Double wye-connected banks 4. H-configuration, where each phase is connected in a bridge

Additionally, the SCB star point, when available, can be either directly earthed , earthed via impedance or isolated from earth. Which type of SCB earthing is used depends on voltage level, used circuit breaker, utility preference and previous experience. Many utilities have standard system earthing principle to earth neutrals of SCB above 100 kV.

Switching of SCB will produce transients in power system. The transient inrush current during SCB energizing typically has high frequency components and can reach peak current values, which are multiples of SCB rating. Opening of capacitor bank circuit breaker may produce step recovery voltages across open CB contact, which can consequently cause restrikes upon the first interruption of capacitive current. In modern power system the synchronized CB closing/opening may be utilized in such a manner that transients caused by SCB switching are avoided.

7.15.2.1 SCB protection

IED protection of shunt capacitor banks requires an understanding of the capabilities and limitations of the individual capacitor units and associated electrical equipment. Different types of shunt capacitor bank fusing, configuration or earthing may affect the IED selection for the protection scheme. Availability and placement of CTs and VTs can be additional limiting factor during protection scheme design.

SCB protection schemes are provided in order to detect and clear faults within the capacitor bank itself or in the connected leads to the substation busbar. Bank protection may include items such as a means to disconnect a faulted capacitor unit or capacitor element(s), a means to initiate a shutdown of the bank in case of faults that may lead to a catastrophic failure and alarms to indicate unbalance within the bank.

Capacitor bank outages and failures are often caused by accidental contact by animals. Vermin, monkeys, birds, may use the SCB as a resting place or a landing site. When the animal touches the HV live parts this can result in a flash-over, can rapture or a cascading failures that might cause extensive damages, fire or even total destruction of the whole SCB, unless the bank is sufficiently fitted with protection IEDs.

In addition, to fault conditions SCB can be exposed to different types of abnormal operating conditions. In accordance with IEC and ANSI standards capacitors shall be capable of continuous operation under contingency system and bank conditions, provided the following limitations are not exceeded:

1. Capacitor units should be capable of continuous operation including harmonics, but excluding transients, to 110% of rated IED root-mean-square (RMS) voltage and a crest voltage not exceeding of rated RMS voltage. The capacitor should also

1MRK 511 310-UEN B Section 7 Current protection

187 Application manual

be able to carry 135% of nominal current. The voltage capability of any series element of a capacitor unit shall be considered to be its share of the total capacitor unit voltage capability.

2. Capacitor units should not give less than 100% nor more than 110% of rated reactive power at rated sinusoidal voltage and frequency, measured at a uniform case and internal temperature of 25C.

3. Capacitor units mounted in multiple rows and tiers should be designed for continuous operation for a 24h average temperature of 40 C during the hottest day, or 40 C during the coldest day expected at the location.

4. Capacitor units should be suitable for continuous operation at up to 135% of rated reactive power caused by the combined effects of: Voltage in excess of the nameplate rating at fundamental frequency, but not

over 110% of rated RMS voltage Harmonic voltages superimposed on the fundamental frequency Reactive power manufacturing tolerance of up to 115% of rated reactive

power 5. Capacitor units rated above 600 V shall have an internal discharge device to

reduce the residual voltage to 50 V or less in 5 or 10 minutes (depending on national standard).

Note that capacitor units designed for special applications can exceed these ratings.

Thus, as a general rule, the minimum number of capacitor units connected in parallel within a SCB is such that isolation of one capacitor unit in a group should not cause a voltage unbalance sufficient to place more than 110% of rated voltage on the remaining capacitors of that parallel group. Equally, the minimum number of series connected groups within a SCB is such that complete bypass of one group should not pause voltage higher than 110% of the rated voltage on the remaining capacitors of that serial group. The value of 110% is the maximum continuous overvoltage capability of capacitor units as per IEEE Std 18-1992.

The SCB typically requires the following types of IED protection:

1. Short circuit protection for SCB and connecting leads (can be provided by using PHPIOC, OC4PTOC, CVGAPC, T2WPDIF/T3WPDIF or HZPDIF functions)

2. Earth-fault protection for SCB and connecting leads (can be provided by using EFPIOC, EF4PTOC, CVGAPC, T2WPDIF/T3WPDIF or HZPDIF functions)

3. Current or Voltage based unbalance protection for SCB (can be provided by using EF4PTOC, OC4PTOC, CVGAPC or VDCPTOV functions)

4. Overload protection for SCB 5. Undercurrent protection for SCB 6. Reconnection inhibit protection for SCB 7. Restrike condition detection

CBPGAPC function can be used to provide the last four types of protection mentioned in the above list.

Section 7 1MRK 511 310-UEN B Current protection

188 Application manual

7.15.3 Setting guidelines

This setting example will be done for application as shown in figure 76:

Preprocessing Function Block

Capacitor bank protection function

400kV

CBPGAPCSMAI

200MVAr 400kV

500/1

IED

IEC09000754-1-en.vsd

IEC09000754 V1 EN

Figure 76: Single line diagram for the application example

From figure 76 it is possible to calculate the following rated fundamental frequency current for this SCB:

1000 200[ ] 289 3 400[ ]r

MVArI A kV

= =

IEC09000755 V1 EN (Equation 89)

or on the secondary CT side:

_ ec

289 0.578 500 1r S

AI A= =

IEC09000756 V1 EN (Equation 90)

Note that the SCB rated current on the secondary CT side is important for secondary injection of the function.

The parameters for the Capacitor bank protection function CBPGAPC are set via the local HMI or PCM600. The following settings are done for this function:

General Settings:

Operation =On; to enable the function

1MRK 511 310-UEN B Section 7 Current protection

189 Application manual

IBase =289A; Fundamental frequency SCB rated current in primary amperes. This value is used as a base value for pickup settings of all other features integrated in this function.

Reconnection inhibit feature:

OperationRecIn =On; to enable this feature

IRecnInhibit< =10% (of IBase); Current level under which function will detect that SCB is disconnected from the power system

tReconnInhibit =300s; Time period under which SCB shall discharge remaining residual voltage to less than 5%.

Overcurrent feature:

OperationOC =On; to enable this feature

IOC> =135% (of IBase); Current level for overcurrent pickup. Selected value gives pickup recommended by international standards.

tOC =30s; Time delay for overcurrent trip

Undercurrent feature:

OperationUC =On; to enable this feature

IUC< =70% (of IBase); Current level for undercurrent pickup

tUC =5s; Time delay for undercurrent trip

Undercurrent feature is blocked by operation of Reconnection inhibit feature.

Reactive power overload feature:

OperationQOL =On; to enable this feature

QOL> =130% (of SCB MVAr rating); Reactive power level required for pickup. Selected value gives pickup recommended by international standards.

tQOL =60s; Time delay for reactive power overload trip

Harmonic voltage overload feature:

OperationHOL =On; to enable this feature

Settings for definite time delay step

HOLDTU> =200% (of SCB voltage rating); Voltage level required for pickup

tHOLDT =10s; Definite time delay for harmonic overload trip

Section 7 1MRK 511 310-UEN B Current protection

190 Application manual

Settings for IDMT delay step

HOLIDMTU> =110% (of SCB voltage rating); Voltage level required for pickup of IDMT stage. Selected value gives pickup recommended by international standards.

kHOLIDMT =1.0; Time multiplier for IDMT stage. Selected value gives operate time in accordance with international standards

tMaxHOLIDMT =2000s; Maximum time delay for IDMT stage for very low level of harmonic overload

tMinHOLIDMT =0.1s; Minimum time delay for IDMT stage. Selected value gives operate time in accordance with international standards

7.15.3.1 Restrike detection

Opening of SCBs can be quite problematic for certain types of circuit breakers (CBs). Typically such problems are manifested as CB restrikes.

In simple words this means that the CB is not breaking the current at the first zero crossing after separation of the CB contacts. Instead current is re-ignited and only braked at consecutive current zero crossings. This condition is manifested as high current pulses at the moment of current re-ignition.

To detect this CB condition, the built in overcurrent feature can be used. Simply, any start of the overcurrent feature during breaker normal opening means a restrike. Therefore simple logic can be created in the Application Configuration tool to detect such CB behavior. Such CB condition can be just alarmed, and if required, the built in disturbance recorder can also be triggered.

To create this logic, a binary signal that the CB is going to be opened (but not trip command) shall be made available to the IED.

7.16 Voltage-restrained time overcurrent protection VRPVOC

7.16.1 Identification Function description IEC 61850

identification IEC 60617 identification

ANSI/IEEE C37.2 device number

Voltage-restrained time overcurrent protection

VRPVOC I>/U< 51V

1MRK 511 310-UEN B Section 7 Current protection

191 Application manual

7.16.2 Application

A breakdown of the insulation between phase conductors or a phase conductor and earth results in a short-circuit or an earth fault. Such faults can result in large fault currents and may cause severe damage to the power system primary equipment.

A typical application of the voltage-restrained time overcurrent protection is in the generator protection system, where it is used as backup protection. If a phase-to-phase fault affects a generator, the fault current amplitude is a function of time, and it depends on generator characteristic (reactances and time constants), its load conditions (immediately before the fault) and excitation system performance and characteristic. So the fault current amplitude may decay with time. A voltage- restrained overcurrent relay can be set in order to remain in the picked-up state in spite of the current decay, and perform a backup trip in case of failure of the main protection.

The IED can be provided with a voltage-restrained time overcurrent protection (VRPVOC). The VRPVOC function is always connected to three-phase current and three-phase voltage input in the configuration tool, but it will always measure the maximum phase current and the minimum phase-to-phase voltage.

VRPVOC function module has two independent protection each consisting of:

One overcurrent step with the following built-in features: Selectable definite time delay or Inverse Time IDMT characteristic Voltage restrained/controlled feature is available in order to modify the

start level of the overcurrent stage in proportion to the magnitude of the measured voltage

One undervoltage step with the following built-in feature: Definite time delay

The undervoltage function can be enabled or disabled. Sometimes in order to obtain the desired application functionality it is necessary to provide interaction between the two protection elements within the VRPVOC function by appropriate IED configuration (for example, overcurrent protection with under-voltage seal-in). Sometimes in order to obtain the desired application functionality it is necessary to provide interaction between the two protection elements within the D2PTOC function by appropriate IED configuration (for example, overcurrent protection with under- voltage seal-in).

7.16.2.1 Base quantities

GlobalBaseSel defines the particular Global Base Values Group where the base quantities of the function are set. In that Global Base Values Group:

IBase shall be entered as rated phase current of the protected object in primary amperes.

Section 7 1MRK 511 310-UEN B Current protection

192 Application manual

UBase shall be entered as rated phase-to-phase voltage of the protected object in primary kV.

7.16.2.2 Application possibilities

VRPVOC function can be used in one of the following three applications:

voltage controlled over-current voltage restrained over-current overcurrent protection with under-voltage seal-in.

7.16.2.3 Undervoltage seal-in

In the case of a generator with a static excitation system, which receives its power from the generator terminals, the magnitude of a sustained phase short-circuit current depends on the generator terminal voltage. In case of a nearby multi-phase fault, the generator terminal voltage may drop to quite low level, for example, less than 25%, and the generator fault current may consequently fall below the pickup level of the overcurrent protection. The short-circuit current may drop below the generator rated current after 0.5…1 s. Also, for generators with an excitation system not fed from the generator terminals, a fault can occur when the automatic voltage regulator is out of service. In such cases, to ensure tripping under such conditions, overcurrent protection with undervoltage seal-in can be used.

To apply the VRPVOC function, the configuration is done according to figure 77. As seen in the figure, the pickup of the overcurrent stage will enable the undervoltage stage. Once enabled, the undervoltage stage will start a timer, which causes function tripping, if the voltage does not recover above the set value. To ensure a proper reset, the function is blocked two seconds after the trip signal is issued.

Trip output

OR

OR t

IEC12000183-1-en.vsd

VRPVOC I3P*

U3P*

BLOCK

BLKOC

BLKUV

TRIP

TROC

TRUV

START

STOC

STUV

IEC12000183 V1 EN

Figure 77: Undervoltage seal-in of current start

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193 Application manual

7.16.3 Setting guidelines

7.16.3.1 Explanation of the setting parameters

In version 2.0, a typical starting time delay of 24ms is subtracted from the set trip time delay, so that the resulting trip time will take the internal IED start time into consideration.

Operation: Set to On in order to activate the function; set to Off to switch off the complete function.

StartCurr: Operation phase current level given in % of IBase.