ABB RELION 650 SERIES Applications Manual

Issued: March 2019 Revision: A Product version: 2.1 © Copyright 2016 ABB. All rights reserved

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 ([email protected]) and Tim Hudson ([email protected]). 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.

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.

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.

Section 1 Introduction.......................................................................................................11 1.1 This manual........................................................................................................................................11 1.2 Intended audience............................................................................................................................11 1.3 Product documentation..................................................................................................................12 1.3.1 Product documentation set.......................................................................................................12 1.3.2 Document revision history.........................................................................................................13 1.3.3 Related documents......................................................................................................................13 1.4 Document symbols and conventions...........................................................................................14 1.4.1 Symbols......................................................................................................................................... 14 1.4.2 Document conventions...............................................................................................................15 1.5 IEC 61850 edition 1 / edition 2 mapping..................................................................................... 15 Section 2 Application.........................................................................................................19 2.1 General IED application...................................................................................................................19 2.2 Main protection functions............................................................................................................. 20 2.3 Back-up protection functions....................................................................................................... 20 2.4 Control and monitoring functions................................................................................................21 2.5 Communication................................................................................................................................23 2.6 Basic IED functions..........................................................................................................................24 Section 3 Configuration.................................................................................................... 27 3.1 Description of configuration RET650.......................................................................................... 27 3.1.1 Introduction..................................................................................................................................27 3.1.1.1 Description of A05....................................................................................................................27 Section 4 Analog inputs.................................................................................................... 29 4.1 Introduction...................................................................................................................................... 29 4.2 Setting guidelines............................................................................................................................29 4.2.1 Setting of the phase reference channel..................................................................................29 4.2.1.1 Example......................................................................................................................................29 4.2.2 Setting of current channels.......................................................................................................30 4.2.2.1 Example 1...................................................................................................................................30 4.2.2.2 Example 2................................................................................................................................... 31 4.2.2.3 Example 3...................................................................................................................................32 4.2.2.4 Examples on how to connect, configure and set CT inputs for most commonly used CT connections............................................................................................................... 34 4.2.2.5 Example on how to connect a star connected three-phase CT set to the IED............ 35 4.2.2.6 Example how to connect delta connected three-phase CT set to the IED...................39 4.2.2.7 Example how to connect single-phase CT to the IED....................................................... 41 4.2.3 Relationships between setting parameter Base Current, CT rated primary current and minimum pickup of a protection IED................................................................ 42 4.2.4 Setting of voltage channels.......................................................................................................43 Table of contents 1 Application manual

used VT connections............................................................................................................... 43 4.2.4.3 Examples on how to connect a three phase-to-earth connected VT to the IED.........44 4.2.4.4 Example on how to connect a phase-to-phase connected VT to the IED.....................46 4.2.4.5 Example on how to connect an open delta VT to the IED for high impedance earthed or unearthed netwoeks........................................................................................... 48 4.2.4.6 Example how to connect the open delta VT to the IED for low impedance earthed or solidly earthed power systems......................................................................... 49 4.2.4.7 Example on how to connect a neutral point VT to the IED...............................................51 Section 5 Local HMI........................................................................................................... 55 5.1 Display................................................................................................................................................56 5.2 LEDs.................................................................................................................................................... 57 5.3 Keypad............................................................................................................................................... 58 5.4 Local HMI functionality...................................................................................................................60 5.4.1 Protection and alarm indication.............................................................................................. 60 5.4.2 Parameter management ........................................................................................................... 61 5.4.3 Front communication................................................................................................................. 61 Section 6 Differential protection.....................................................................................63 6.1 Transformer differential protection T3WPDIF ..........................................................................63 6.1.1 Application....................................................................................................................................63 6.1.2 Setting guidelines....................................................................................................................... 64 6.1.2.1 Restrained and unrestrained differential protection.......................................................64 6.1.2.2 Elimination of zero sequence currents................................................................................66 6.1.2.3 Inrush restraint methods........................................................................................................67 6.1.2.4 Overexcitation restraint method.......................................................................................... 67 6.1.2.5 Cross-blocking between phases...........................................................................................67 6.1.2.6 External/Internal fault discriminator...................................................................................68 6.1.2.7 Differential current alarm.......................................................................................................69 6.1.2.8 Open CT detection...................................................................................................................69 6.1.2.9 Switch onto fault feature........................................................................................................70 6.1.3 Setting example...........................................................................................................................70 6.1.3.1 Introduction.............................................................................................................................. 70 6.1.3.2 Typical main CT connections for transformer differential protection.......................... 71 6.1.3.3 Application Examples.............................................................................................................. 72 6.1.3.4 Summary and conclusions......................................................................................................76 6.2 Low impedance restricted earth fault protection REFPDIF ................................................... 78 6.2.1 Identification................................................................................................................................78 6.2.2 Application....................................................................................................................................78 6.2.2.1 Transformer winding, solidly earthed..................................................................................79 6.2.2.2 Transformer winding, earthed through zig-zag earthing transformer........................ 80 6.2.2.3 Autotransformer winding, solidly earthed..........................................................................81 6.2.2.4 Reactor winding, solidly earthed.......................................................................................... 82 6.2.2.5 CT earthing direction.............................................................................................................. 83 6.2.3 Setting guidelines....................................................................................................................... 83 Table of contents 2 Application manual

6.2.3.2 Settings......................................................................................................................................84 Section 7 Current protection........................................................................................... 85 7.1 Instantaneous phase overcurrent protection PHPIOC ............................................................85 7.1.1 Identification................................................................................................................................85 7.1.2 Application....................................................................................................................................85 7.1.3 Setting guidelines....................................................................................................................... 85 7.1.3.1 Meshed network without parallel line..................................................................................86 7.1.3.2 Meshed network with parallel line........................................................................................88 7.2 Four step phase overcurrent protection OC4PTOC................................................................. 89 7.2.1 Identification................................................................................................................................89 7.2.2 Application....................................................................................................................................89 7.2.3 Setting guidelines....................................................................................................................... 90 7.2.3.1 Settings for each step............................................................................................................. 91 7.2.3.2 2nd harmonic restrain.............................................................................................................94 7.3 Instantaneous residual overcurrent protection EFPIOC .........................................................98 7.3.1 Identification................................................................................................................................99 7.3.2 Application....................................................................................................................................99 7.3.3 Setting guidelines....................................................................................................................... 99 7.4 Four step residual overcurrent protection EF4PTOC ............................................................ 101 7.4.1 Identification.............................................................................................................................. 101 7.4.2 Application.................................................................................................................................. 101 7.4.3 Setting guidelines..................................................................................................................... 103 7.4.3.1 Settings for each step (x = 1, 2, 3 and 4)............................................................................103 7.4.3.2 Common settings for all steps............................................................................................105 7.4.3.3 2nd harmonic restrain...........................................................................................................106 7.4.3.4 Parallel transformer inrush current logic.......................................................................... 106 7.4.3.5 Switch onto fault logic.......................................................................................................... 107 7.4.3.6 Transformer application example...................................................................................... 108 7.5 Sensitive directional residual overcurrent and power protection SDEPSDE .....................111 7.5.1 Identification...............................................................................................................................111 7.5.2 Application...................................................................................................................................111 7.5.3 Setting guidelines...................................................................................................................... 113 7.6 Thermal overload protection, two time constants TRPTTR ................................................. 119 7.6.1 Identification..............................................................................................................................120 7.6.2 Application..................................................................................................................................120 7.6.3 Setting guideline........................................................................................................................ 121 7.7 Breaker failure protection CCRBRF.............................................................................................122 7.7.1 Identification.............................................................................................................................. 123 7.7.2 Application.................................................................................................................................. 123 7.7.3 Setting guidelines......................................................................................................................123 7.8 Directional underpower protection GUPPDUP........................................................................ 126 7.8.1 Identification.............................................................................................................................. 126 7.8.2 Application..................................................................................................................................126 7.8.3 Setting guidelines......................................................................................................................127 Table of contents 3 Application manual

7.9.1 Identification...............................................................................................................................131 7.9.2 Application...................................................................................................................................131 7.9.3 Setting guidelines......................................................................................................................133 7.10 Broken conductor check BRCPTOC ........................................................................................... 136 7.10.1 Identification.............................................................................................................................. 136 7.10.2 Application..................................................................................................................................136 7.10.3 Setting guidelines......................................................................................................................136 Section 8 Voltage protection..........................................................................................137 8.1 Loss of voltage check LOVPTUV .................................................................................................137 8.1.1 Identification.............................................................................................................................. 137 8.1.2 Application.................................................................................................................................. 137 8.1.3 Setting guidelines......................................................................................................................137 8.1.3.1 Advanced users settings.......................................................................................................137 Section 9 Multipurpose protection................................................................................139 9.1 General current and voltage protection CVGAPC....................................................................139 9.1.1 Identification.............................................................................................................................. 139 9.1.2 Application..................................................................................................................................139 9.1.2.1 Current and voltage selection for CVGAPC function...................................................... 140 9.1.2.2 Base quantities for CVGAPC function................................................................................ 142 9.1.2.3 Application possibilities....................................................................................................... 142 9.1.2.4 Inadvertent generator energization...................................................................................143 9.1.3 Setting guidelines..................................................................................................................... 144 9.1.3.1 Directional negative sequence overcurrent protection................................................. 144 9.1.3.2 Negative sequence overcurrent protection......................................................................145 9.1.3.3 Generator stator overload protection in accordance with IEC or ANSI standards...147 9.1.3.4 Open phase protection for transformer, lines or generators and circuit breaker head flashover protection for generators......................................................... 149 9.1.3.5 Voltage restrained overcurrent protection for generator and step-up transformer............................................................................................................................. 150 9.1.3.6 Loss of excitation protection for a generator..................................................................150 Section 10 Secondary system supervision..................................................................... 153 10.1 Fuse failure supervision FUFSPVC..............................................................................................153 10.1.1 Identification.............................................................................................................................. 153 10.1.2 Application.................................................................................................................................. 153 10.1.3 Setting guidelines..................................................................................................................... 154 10.1.3.1 General......................................................................................................................................154 10.1.3.2 Setting of common parameters..........................................................................................154 10.1.3.3 Negative sequence based.....................................................................................................154 10.1.3.4 Zero sequence based.............................................................................................................155 10.1.3.5 Delta U and delta I ................................................................................................................. 156 10.1.3.6 Dead line detection................................................................................................................156 Section 11 Control..............................................................................................................157 11.1 Synchrocheck, energizing check, and synchronizing SESRSYN............................................ 157 Table of contents 4 Application manual

11.1.2.2 Single circuit breaker with double busbar, internal voltage selection........................158 11.1.3 Setting guidelines......................................................................................................................159 11.2 Apparatus control APC..................................................................................................................163 11.2.1 Application..................................................................................................................................163 11.2.1.1 Bay control (QCBAY)..............................................................................................................166 11.2.1.2 Switch controller (SCSWI).....................................................................................................167 11.2.1.3 Switches (SXCBR/SXSWI).....................................................................................................168 11.2.1.4 Reservation function (QCRSV and RESIN).........................................................................168 11.2.2 Interaction between modules.................................................................................................170 11.2.3 Setting guidelines...................................................................................................................... 171 11.2.3.1 Bay control (QCBAY)...............................................................................................................171 11.2.3.2 Switch controller (SCSWI)..................................................................................................... 172 11.2.3.3 Switch (SXCBR/SXSWI)..........................................................................................................173 11.2.3.4 Bay Reserve (QCRSV)..............................................................................................................173 11.2.3.5 Reservation input (RESIN).....................................................................................................173 11.3 Logic rotating switch for function selection and LHMI presentation SLGAPC................. 173 11.3.1 Identification.............................................................................................................................. 173 11.3.2 Application.................................................................................................................................. 173 11.3.3 Setting guidelines......................................................................................................................174 11.4 Selector mini switch VSGAPC...................................................................................................... 174 11.4.1 Identification.............................................................................................................................. 174 11.4.2 Application.................................................................................................................................. 174 11.4.3 Setting guidelines......................................................................................................................175 11.5 Generic communication function for Double Point indication DPGAPC.............................175 11.5.1 Identification.............................................................................................................................. 175 11.5.2 Application.................................................................................................................................. 175 11.5.3 Setting guidelines......................................................................................................................176 11.6 Single point generic control 8 signals SPC8GAPC...................................................................176 11.6.1 Identification.............................................................................................................................. 176 11.6.2 Application.................................................................................................................................. 176 11.6.3 Setting guidelines......................................................................................................................177 11.7 AutomationBits, command function for DNP3.0 AUTOBITS................................................. 177 11.7.1 Identification...............................................................................................................................177 11.7.2 Application.................................................................................................................................. 177 11.7.3 Setting guidelines......................................................................................................................177 11.8 Single command, 16 signals SINGLECMD..................................................................................177 11.8.1 Identification.............................................................................................................................. 178 11.8.2 Application.................................................................................................................................. 178 11.8.3 Setting guidelines......................................................................................................................179 Section 12 Logic................................................................................................................. 181 12.1 Tripping logic SMPPTRC ...............................................................................................................181 12.1.1 Identification.............................................................................................................................. 181 Table of contents 5 Application manual

12.1.2.2 Single- and/or three-phase tripping.................................................................................. 182 12.1.2.3 Single-, two- or three-phase tripping.................................................................................183 12.1.2.4 Lock-out................................................................................................................................... 184 12.1.2.5 Blocking of the function block.............................................................................................184 12.1.3 Setting guidelines..................................................................................................................... 184 12.2 Trip matrix logic TMAGAPC..........................................................................................................184 12.2.1 Identification..............................................................................................................................185 12.2.2 Application..................................................................................................................................185 12.2.3 Setting guidelines......................................................................................................................185 12.3 Logic for group alarm ALMCALH................................................................................................ 185 12.3.1 Identification..............................................................................................................................185 12.3.2 Application..................................................................................................................................185 12.3.3 Setting guidelines..................................................................................................................... 186 12.4 Logic for group alarm WRNCALH................................................................................................186 12.4.1 Identification..............................................................................................................................186 12.4.1.1 Application...............................................................................................................................186 12.4.1.2 Setting guidelines.................................................................................................................. 186 12.5 Logic for group indication INDCALH......................................................................................... 186 12.5.1 Identification..............................................................................................................................186 12.5.1.1 Application...............................................................................................................................186 12.5.1.2 Setting guidelines.................................................................................................................. 186 12.6 Configurable logic blocks.............................................................................................................186 12.6.1 Application.................................................................................................................................. 187 12.6.2 Setting guidelines......................................................................................................................187 12.6.2.1 Configuration..........................................................................................................................187 12.7 Fixed signal function block FXDSIGN.........................................................................................188 12.7.1 Identification..............................................................................................................................188 12.7.2 Application..................................................................................................................................188 12.8 Boolean 16 to Integer conversion B16I.......................................................................................189 12.8.1 Identification..............................................................................................................................189 12.8.2 Application..................................................................................................................................189 12.9 Boolean to integer conversion with logical node representation, 16 bit BTIGAPC.......... 190 12.9.1 Identification..............................................................................................................................190 12.9.2 Application..................................................................................................................................190 12.10 Integer to Boolean 16 conversion IB16.......................................................................................191 12.10.1 Identification.............................................................................................................................. 191 12.10.2 Application.................................................................................................................................. 192 12.11 Integer to Boolean 16 conversion with logic node representation ITBGAPC.....................192 12.11.1 Identification.............................................................................................................................. 193 12.11.2 Application..................................................................................................................................193 12.12 Elapsed time integrator with limit transgression and overflow supervision TEIGAPC...194 12.12.1 Identification..............................................................................................................................194 12.12.2 Application..................................................................................................................................194 12.12.3 Setting guidelines..................................................................................................................... 194 Table of contents 6 Application manual

12.13.1 Identification..............................................................................................................................194 12.13.2 Application..................................................................................................................................195 12.13.3 Setting guidelines......................................................................................................................195 12.13.4 Setting example.........................................................................................................................195 12.14 Comparator for real inputs - REALCOMP..................................................................................196 12.14.1 Identification..............................................................................................................................196 12.14.2 Application..................................................................................................................................196 12.14.3 Setting guidelines..................................................................................................................... 196 12.14.4 Setting example.........................................................................................................................196 Section 13 Monitoring.......................................................................................................199 13.1 Measurement..................................................................................................................................199 13.1.1 Identification..............................................................................................................................199 13.1.2 Application..................................................................................................................................199 13.1.3 Zero clamping............................................................................................................................200 13.1.4 Setting guidelines......................................................................................................................201 13.1.4.1 Setting examples................................................................................................................... 203 13.2 Gas medium supervision SSIMG................................................................................................. 207 13.2.1 Identification..............................................................................................................................207 13.2.2 Application..................................................................................................................................207 13.2.3 Setting guidelines..................................................................................................................... 207 13.3 Liquid medium supervision SSIML.............................................................................................208 13.3.1 Identification..............................................................................................................................208 13.3.2 Application................................................................................................................................. 208 13.3.3 Setting guidelines.....................................................................................................................208 13.4 Breaker monitoring SSCBR..........................................................................................................208 13.4.1 Identification..............................................................................................................................208 13.4.2 Application................................................................................................................................. 209 13.4.3 Setting guidelines...................................................................................................................... 211 13.4.3.1 Setting procedure on the IED...............................................................................................211 13.5 Event function EVENT....................................................................................................................212 13.5.1 Identification.............................................................................................................................. 212 13.5.2 Application.................................................................................................................................. 212 13.5.3 Setting guidelines......................................................................................................................213 13.6 Disturbance report DRPRDRE...................................................................................................... 213 13.6.1 Identification.............................................................................................................................. 213 13.6.2 Application..................................................................................................................................214 13.6.3 Setting guidelines......................................................................................................................214 13.6.3.1 Recording times......................................................................................................................216 13.6.3.2 Binary input signals................................................................................................................217 13.6.3.3 Analog input signals...............................................................................................................217 13.6.3.4 Sub-function parameters......................................................................................................218 13.6.3.5 Consideration..........................................................................................................................218 13.7 Logical signal status report BINSTATREP.................................................................................219 13.7.1 Identification.............................................................................................................................. 219 Table of contents 7 Application manual

13.8.1 Identification..............................................................................................................................220 13.8.2 Application..................................................................................................................................220 13.8.3 Setting guidelines..................................................................................................................... 220 13.9 Running hour-meter TEILGAPC...................................................................................................220 13.9.1 Identification..............................................................................................................................220 13.9.2 Application..................................................................................................................................220 13.9.3 Setting guidelines..................................................................................................................... 220 Section 14 Metering...........................................................................................................223 14.1 Pulse-counter logic PCFCNT........................................................................................................ 223 14.1.1 Identification.............................................................................................................................. 223 14.1.2 Application..................................................................................................................................223 14.1.3 Setting guidelines......................................................................................................................223 14.2 Function for energy calculation and demand handling ETPMMTR......................................224 14.2.1 Identification..............................................................................................................................224 14.2.2 Application..................................................................................................................................224 14.2.3 Setting guidelines..................................................................................................................... 225 Section 15 Station communication................................................................................. 227 15.1 Communication protocols........................................................................................................... 227 15.2 IEC 61850-8-1 communication protocol.................................................................................... 227 15.2.1 Application IEC 61850-8-1........................................................................................................ 227 15.2.2 Horizontal communication via GOOSE for interlocking GOOSEINTLKRCV................... 229 15.2.3 Setting guidelines..................................................................................................................... 229 15.2.4 Generic communication function for Single Point indication SPGAPC, SP16GAPC..... 229 15.2.4.1 Application.............................................................................................................................. 229 15.2.4.2 Setting guidelines..................................................................................................................229 15.2.5 Generic communication function for Measured Value MVGAPC..................................... 229 15.2.5.1 Application.............................................................................................................................. 229 15.2.5.2 Setting guidelines..................................................................................................................229 15.2.6 IEC 61850-8-1 redundant station bus communication - PRP............................................230 15.2.6.1 Identification.......................................................................................................................... 230 15.2.6.2 Application.............................................................................................................................. 230 15.2.6.3 Setting guidelines...................................................................................................................231 15.3 LON communication protocol.....................................................................................................232 15.3.1 Application..................................................................................................................................232 15.3.2 MULTICMDRCV and MULTICMDSND......................................................................................233 15.3.2.1 Identification...........................................................................................................................233 15.3.2.2 Application...............................................................................................................................233 15.3.2.3 Setting guidelines..................................................................................................................234 15.4 SPA communication protocol......................................................................................................234 15.4.1 Application..................................................................................................................................234 15.4.2 Setting guidelines..................................................................................................................... 235 15.5 IEC 60870-5-103 communication protocol...............................................................................236 Table of contents 8 Application manual

15.6.1 Application..................................................................................................................................242 Section 16 Security............................................................................................................243 16.1 Authority status ATHSTAT...........................................................................................................243 16.1.1 Application..................................................................................................................................243 16.2 Self supervision with internal event list INTERRSIG................................................................243 16.2.1 Application..................................................................................................................................243 16.3 Change lock CHNGLCK................................................................................................................. 244 16.3.1 Application................................................................................................................................. 244 16.4 Denial of service DOS....................................................................................................................244 16.4.1 Application................................................................................................................................. 244 16.4.2 Setting guidelines..................................................................................................................... 245 Section 17 Basic IED functions.........................................................................................247 17.1 IED identifiers TERMINALID......................................................................................................... 247 17.1.1 Application..................................................................................................................................247 17.2 Product information PRODINF....................................................................................................247 17.2.1 Application..................................................................................................................................247 17.2.2 Factory defined settings..........................................................................................................247 17.3 Measured value expander block RANGE_XP.............................................................................248 17.3.1 Identification..............................................................................................................................248 17.3.2 Application..................................................................................................................................248 17.3.3 Setting guidelines..................................................................................................................... 248 17.4 Parameter setting groups........................................................................................................... 249 17.4.1 Application..................................................................................................................................249 17.4.2 Setting guidelines..................................................................................................................... 249 17.5 Rated system frequency PRIMVAL............................................................................................. 249 17.5.1 Identification..............................................................................................................................249 17.5.2 Application..................................................................................................................................249 17.5.3 Setting guidelines..................................................................................................................... 250 17.6 Summation block 3 phase 3PHSUM...........................................................................................250 17.6.1 Application..................................................................................................................................250 17.6.2 Setting guidelines..................................................................................................................... 250 17.7 Global base values GBASVAL.......................................................................................................250 17.7.1 Identification..............................................................................................................................250 17.7.2 Application.................................................................................................................................. 251 17.7.3 Setting guidelines......................................................................................................................251 17.8 Signal matrix for binary inputs SMBI..........................................................................................251 17.8.1 Application.................................................................................................................................. 251 17.8.2 Setting guidelines......................................................................................................................251 17.9 Signal matrix for binary outputs SMBO ....................................................................................251 17.9.1 Application.................................................................................................................................. 251 17.9.2 Setting guidelines..................................................................................................................... 252 17.10 Signal matrix for mA inputs SMMI..............................................................................................252 17.10.1 Application..................................................................................................................................252 Table of contents 9 Application manual

17.11 Signal matrix for analog inputs SMAI........................................................................................ 252 17.11.1 Application..................................................................................................................................252 17.11.2 Frequency values....................................................................................................................... 252 17.11.3 Setting guidelines..................................................................................................................... 253 17.12 Test mode functionality TESTMODE..........................................................................................257 17.12.1 Application..................................................................................................................................257 17.12.1.1 IEC 61850 protocol test mode.............................................................................................258 17.12.2 Setting guidelines..................................................................................................................... 259 17.13 Time synchronization TIMESYNCHGEN.................................................................................... 259 17.13.1 Application..................................................................................................................................259 17.13.2 Setting guidelines.....................................................................................................................260 17.13.2.1 System time............................................................................................................................ 260 17.13.2.2 Synchronization..................................................................................................................... 260 Section 18 Requirements.................................................................................................. 263 18.1 Current transformer requirements............................................................................................263 18.1.1 Current transformer classification........................................................................................ 263 18.1.2 Conditions.................................................................................................................................. 263 18.1.3 Fault current...............................................................................................................................264 18.1.4 Secondary wire resistance and additional load..................................................................264 18.1.5 General current transformer requirements......................................................................... 265 18.1.6 Rated equivalent secondary e.m.f. requirements...............................................................265 18.1.6.1 Transformer differential protection.................................................................................. 265 18.1.6.2 Distance protection...............................................................................................................266 18.1.6.3 Breaker failure protection.................................................................................................... 267 18.1.6.4 Restricted earth fault protection (low impedance differential)...................................268 18.1.7 Current transformer requirements for CTs according to other standards.................. 270 18.1.7.1 Current transformers according to IEC 61869-2, class P, PR........................................ 270 18.1.7.2 Current transformers according to IEC 61869-2, class PX, PXR (and old IEC 60044-6, class TPS and old British Standard, class X)....................................................271 18.1.7.3 Current transformers according to ANSI/IEEE................................................................ 271 18.2 Voltage transformer requirements............................................................................................ 272 18.3 SNTP server requirements............................................................................................................272 Section 19 Glossary............................................................................................................273 Table of contents 10 Application manual

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 GUID-C9B8127F-5748-4BEA-9E4F-CC762FE28A3A v10 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 504 158-UEN A Section 1 Introduction 11 Application manual

GUID-3AA69EA6-F1D8-47C6-A8E6-562F29C67172 v15 IEC07000220-4-en.vsd Planning & purchase Engineering Installing Commissioning Operation Maintenance Decommissioning Deinstalling & disposal Application manual Operation manual Installation manual Engineering manual Communication protocol manual Cyber security deployment guideline Technical manual Commissioning manual IEC07000220 V4 EN-US 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, DNP3, LON and SPA. 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 well as verifying settings by secondary injection. The manual describes the process of testing an IED in a station 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. Section 1 1MRK 504 158-UEN A Introduction 12 Application manual

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 operation principle 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 Document revision history GUID-C8027F8A-D3CB-41C1-B078-F9E59BB73A6C v2.1.1 Document revision/date History January 2016 First Release March 2019 Maintenance Release 1.3.3 Related documents GUID-94E8A5CA-BE1B-45AF-81E7-5A41D34EE112 v4 Documents related to RET650 Document numbers Application manual 1MRK 504 158-UEN Commissioning manual 1MRK 504 160-UEN Product guide 1MRK 504 161-BEN Technical manual 1MRK 504 159-UEN Type test certificate 1MRK 504 161-TEN 650 series manuals Document numbers Operation manual 1MRK 500 125-UEN Engineering manual 1MRK 511 381-UEN Installation manual 1MRK 514 025-UEN Communication protocol manual, DNP3 1MRK 511 374-UUS Communication protocol manual, IEC 60870-5-103 1MRK 511 377-UEN Communication protocol manual, IEC 61850 Edition 1 1MRK 511 375-UEN Communication protocol manual, IEC 61850 Edition 2 1MRK 511 376-UEN Communication protocol manual, LON 1MRK 511 378-UEN Communication protocol manual, SPA 1MRK 511 379-UEN Point list manual, DNP3 1MRK 511 380-UUS Table continues on next page 1MRK 504 158-UEN A Section 1 Introduction 13 Application manual

Document numbers Accessories guide IEC: 1MRK 514 012-UEN ANSI: 1MRK 514 012-UUS Cyber security deployment guideline 1MRK 511 382-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 GUID-2945B229-DAB0-4F15-8A0E-B9CF0C2C7B15 v12 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. Class 1 Laser product. Take adequate measures to protect the eyes and do not view directly with optical instruments. 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. Section 1 1MRK 504 158-UEN A Introduction 14 Application manual

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. • Dimensions are provided both in inches and millimeters. If it is not specifically mentioned then the dimension is in millimeters. 1.5 IEC 61850 edition 1 / edition 2 mapping GUID-C5133366-7260-4C47-A975-7DBAB3A33A96 v3 Table 1: IEC 61850 edition 1 / edition 2 mapping Function block name Edition 1 logical nodes Edition 2 logical nodes AGSAL AGSAL SECLLN0 AGSAL ALMCALH ALMCALH ALMCALH ALTIM - ALTIM ALTMS - ALTMS ALTRK - ALTRK BRCPTOC BRCPTOC BRCPTOC BTIGAPC B16IFCVI BTIGAPC CCPDSC CCRPLD CCPDSC CCRBRF CCRBRF CCRBRF CCSSPVC CCSRDIF CCSSPVC CMMXU CMMXU CMMXU CMSQI CMSQI CMSQI CVGAPC GF2LLN0 GF2MMXN GF2PHAR GF2PTOV GF2PTUC GF2PTUV GF2PVOC PH1PTRC GF2MMXN GF2PHAR GF2PTOV GF2PTUC GF2PTUV GF2PVOC PH1PTRC CVMMXN CVMMXN CVMMXN DPGAPC DPGGIO DPGAPC DRPRDRE DRPRDRE DRPRDRE Table continues on next page 1MRK 504 158-UEN A Section 1 Introduction 15 Application manual

Edition 1 logical nodes Edition 2 logical nodes EF4PTOC EF4LLN0 EF4PTRC EF4RDIR GEN4PHAR PH1PTOC EF4PTRC EF4RDIR GEN4PHAR PH1PTOC EFPIOC EFPIOC EFPIOC ETPMMTR ETPMMTR ETPMMTR FUFSPVC SDDRFUF FUFSPVC HZPDIF HZPDIF HZPDIF INDCALH INDCALH INDCALH ITBGAPC IB16FCVB ITBGAPC L4UFCNT L4UFCNT L4UFCNT LCPTTR LCPTTR LCPTTR LD0LLN0 LLN0 LLN0 LDLPSCH LDLPDIF LDLPSCH LFPTTR LFPTTR LFPTTR LMBRFLO LMBRFLO LMBRFLO LOVPTUV LOVPTUV LOVPTUV LPHD LPHD LPHD LT3CPDIF LT3CPDIF LT3CGAPC LT3CPDIF LT3CPHAR LT3CPTRC MVGAPC MVGGIO MVGAPC NS4PTOC EF4LLN0 EF4PTRC EF4RDIR GEN4PHAR PH1PTOC EF4PTRC EF4RDIR PH1PTOC OC4PTOC OC4LLN0 GEN4PHAR PH3PTOC PH3PTRC GEN4PHAR PH3PTOC PH3PTRC OV2PTOV GEN2LLN0 OV2PTOV PH1PTRC OV2PTOV PH1PTRC PCFCNT PCGGIO PCFCNT PHPIOC PHPIOC PHPIOC PRPSTATUS RCHLCCH RCHLCCH SCHLCCH QCBAY QCBAY BAY/LLN0 QCRSV QCRSV QCRSV REFPDIF REFPDIF REFPDIF ROV2PTOV GEN2LLN0 PH1PTRC ROV2PTOV PH1PTRC ROV2PTOV SCILO SCILO SCILO SCSWI SCSWI SCSWI Table continues on next page Section 1 1MRK 504 158-UEN A Introduction 16 Application manual

Edition 1 logical nodes Edition 2 logical nodes 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 SXCBR SXCBR SXCBR SXSWI SXSWI SXSWI T3WPDIF T3WPDIF T3WGAPC T3WPDIF T3WPHAR T3WPTRC TEIGAPC TEIGGIO TEIGAPC TEILGAPC TEILGGIO TEILGAPC TMAGAPC TMAGGIO TMAGAPC TRPTTR TRPTTR TRPTTR UV2PTUV GEN2LLN0 PH1PTRC UV2PTUV PH1PTRC UV2PTUV VMMXU VMMXU VMMXU VMSQI VMSQI VMSQI VNMMXU VNMMXU VNMMXU VSGAPC VSGGIO VSGAPC WRNCALH WRNCALH WRNCALH ZCLCPSCH ZCLCPLAL ZCLCPSCH ZCPSCH ZCPSCH ZCPSCH ZCRWPSCH ZCRWPSCH ZCRWPSCH ZCVPSOF ZCVPSOF ZCVPSOF ZMFPDIS ZMFLLN0 PSFPDIS ZMFPDIS ZMFPTRC ZMMMXU PSFPDIS PSFPDIS ZMFPDIS ZMFPTRC ZMMMXU 1MRK 504 158-UEN A Section 1 Introduction 17 Application manual

GUID-EB939A4F-1C88-4EB1-A217-571FEF72AC7B v2 The RET650 provides fast and selective protection, monitoring and control functions for two- and three-winding transformers, autotransformers, generator-transformer units and shunt reactors. The IED is designed to operate correctly over a wide frequency range in order to accommodate power system frequency variations during disturbances and generator startup and shutdown. Apparatus control for 3 circuit breakers is included. A fast differential protection function with built-in transformer ratio matching and vector group compensation makes this IED the ideal solution even for the most demanding applications. Since RET650 has very low requirements on the main CTs, no interposing CTs are required. The differential protection function is provided with 2nd harmonic and waveform- blocking restraint features to avoid tripping for magnetizing inrush current, and 5th harmonic restraint to avoid tripping for overexcitation. The differential function offers a high sensitivity for low-level internal faults. The unique and innovative sensitive differential protection feature of the RET650 provides the best possible coverage for internal turn-to-turn winding faults, based on the theory of symmetrical components. A low impedance restricted earth-fault protection function is available as a complimentary sensitive and fast main protection against winding earth faults. This function includes a directional zero-sequence current criterion for additional security. Tripping from pressure relief/Buchholz and temperature devices can be implemented through the IED's binary inputs, where trip signal conditioning can be performed (pulsing, lockout, additional logics, etc). The binary inputs are thoroughly stabilized against disturbances in order to prevent incorrect operations due to for example DC system capacitive discharges or DC earth faults. Versatile phase, earth and zero sequence overcurrent functions with directional capability provide further alternative backup protections. Thermal overload with two time-constants and breaker failure protection is also available. A built-in disturbance and event recorder provides valuable data to the user about status and operation for post-fault disturbance analysis. One pre-configured package has been defined for the following application: • Three-winding transformer in single breaker arrangements (A05) The package is configured and ready for direct use. Analog and control circuits have been predefined and other signals need to be applied as required for each application. The pre- configured IED can be changed and adapted to suit specific applications with the graphical configuration tool. Forcing of binary inputs and outputs is a convenient way to test wiring in substations as well as testing configuration logic in the IEDs. Basically it means that all binary inputs and outputs on the IED I/O modules (BOM, BIM and IOM) can be forced to arbitrary values. Central Account Management is an authentication infrastructure that offers a secure solution for enforcing access control to IEDs and other systems within a substation. This incorporates 1MRK 504 158-UEN A Section 2 Application 19 Application manual

completely transparent to the user. The Flexible Product Naming allows the customer to use an IED-vendor independent 61850 model of the IED. This customer model will be used as the IEC 61850 data model, but all other aspects of the IED will remain unchanged (e.g., names on the local HMI and names in the tools). This offers significant flexibility to adapt the IED to the customers system and standard solution 2.2 Main protection functions GUID-66BAAD98-851D-4AAC-B386-B38B57718BD2 v12 Table 2: Example of quantities 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 Transformer RET650 (A05) Differential protection T3WPDIF 87T Transformer differential protection, three winding 1 REFPDIF 87N Restricted earth fault protection, low impedance 2 2.3 Back-up protection functions GUID-A8D0852F-807F-4442-8730-E44808E194F0 v11 IEC 61850 ANSI Function description Transformer RET650 (A05) Current protection PHPIOC 50 Instantaneous phase overcurrent protection 1 OC4PTOC 51_671) Four step phase overcurrent protection 3 EFPIOC 50N Instantaneous residual overcurrent protection 1 EF4PTOC 51N 67N2) Four step residual overcurrent protection 2 SDEPSDE 67N Sensitive directional residual overcurrent and power protection TRPTTR 49 Thermal overload protection, two time constant 1 CCRBRF 50BF Breaker failure protection 3 GUPPDUP 37 Directional underpower protection GOPPDOP 32 Directional overpower protection BRCPTOC 46 Broken conductor check LOVPTUV 27 Loss of voltage check Multipurpose protection CVGAPC General current and voltage protection 3 1) 67 requires voltage 2) 67N requires voltage Section 2 1MRK 504 158-UEN A Application 20 Application manual

GUID-E3777F16-0B76-4157-A3BF-0B6B978863DE v13 IEC 61850 ANSI Function description Transformer RET650 (A05) Control QCBAY Apparatus control 1 LOCREM Handling of LRswitch positions 1 LOCREMCTRL LHMI control of PSTO 1 SLGAPC Logic Rotating Switch for function selection and LHMI presentation 15 VSGAPC Selector mini switch 20 DPGAPC Generic communication function for Double Point indication 16 SPC8GAPC Single Point Generic Control 8 signals 5 AUTOBITS AutomationBits, command function for DNP3.0 3 SINGLECMD Single command, 16 signals 4 I103CMD Function commands for IEC 60870-5-103 1 I103GENCMD Function commands generic for IEC 60870-5-103 50 I103POSCMD IED commands with position and select for IEC 60870-5-103 50 I103POSCMDV IED direct commands with position for IEC 60870-5-503 50 I103IEDCMD IED commands for IEC 60870-5-103 1 I103USRCMD Function commands user defined for IEC 60870-5-103 4 SCILO Interlocking 3 SCSWI Switch Controller 3 SXCBR Circuit Breaker 3 Circuit breaker for 3CB 1 Secondary system supervision FUFSPVC Fuse failure supervision 1 Logic SMPPTRC Tripping logic 6 TMAGAPC Trip matrix logic 12 ALMCALH Logic for group alarm 5 WRNCALH Logic for group warning 5 INDCALH Logic for group indication 5 AND, GATE, INV, LLD, OR, PULSETIMER, RSMEMORY, SRMEMORY, TIMERSET, XOR Basic configurable logic blocks (see Table 3) 40–420 FXDSIGN Fixed signal function block 1 B16I Boolean 16 to Integer conversion 18 BTIGAPC Boolean 16 to Integer conversion with Logic Node representation 16 IB16 Integer to Boolean 16 conversion 18 ITBGAPC Integer to Boolean 16 conversion with Logic Node representation 16 TEIGAPC Elapsed time integrator with limit transgression and overflow supervision 12 INTCOMP Comparator for integer inputs 12 Table continues on next page 1MRK 504 158-UEN A Section 2 Application 21 Application manual

12 Monitoring CVMMXN, VMMXU, CMSQI, VMSQI, VNMMXU Measurements 6 CMMXU Measurements 10 AISVBAS Function block for service value presentation of secondary analog inputs 1 SSIMG Gas medium supervision 21 SSIML Liquid medium supervision 3 SSCBR Circuit breaker condition monitoring 9 EVENT Event function 20 DRPRDRE, A1RADR-A4RADR, B1RBDR-B8RBDR Disturbance report 1 SPGAPC Generic communication function for Single Point indication 64 SP16GAPC Generic communication function for Single Point indication 16 inputs 16 MVGAPC Generic communication function for Measured Value 24 BINSTATREP Logical signal status report 3 RANGE_XP Measured value expander block 66 I103MEAS Measurands for IEC 60870-5-103 1 I103MEASUSR Measurands user defined signals for IEC 60870-5-103 3 I103AR Function status auto-recloser for IEC 60870-5-103 1 I103EF Function status earth-fault for IEC 60870-5-103 1 I103FLTPROT Function status fault protection for IEC 60870-5-103 1 I103IED IED status for IEC 60870-5-103 1 I103SUPERV Supervison status for IEC 60870-5-103 1 I103USRDEF Status for user defined signals for IEC 60870-5-103 20 L4UFCNT Event counter with limit supervision 30 TEILGAPC Running hour-meter 6 Metering PCFCNT Pulse-counter logic 16 ETPMMTR Function for energy calculation and demand handling 6 Table 3: Total number of instances for basic configurable logic blocks Basic configurable logic block Total number of instances AND 280 GATE 40 INV 420 LLD 40 OR 280 PULSETIMER 40 RSMEMORY 40 Table continues on next page Section 2 1MRK 504 158-UEN A Application 22 Application manual

Total number of instances SRMEMORY 40 TIMERSET 60 XOR 40 2.5 Communication GUID-5F144B53-B9A7-4173-80CF-CD4C84579CB5 v13 IEC 61850 ANSI Function description Transformer RET650 (A05) Station communication LONSPA, SPA SPA communication protocol 1 ADE LON communciation protocol 1 HORZCOMM Network variables via LON 1 PROTOCOL Operation selection between SPA and IEC 60870-5-103 for SLM 1 RS485PROT Operation selection for RS485 1 RS485GEN RS485 1 DNPGEN DNP3.0 communication general protocol 1 DNPGENTCP DNP3.0 communication general TCP protocol 1 CHSERRS485 DNP3.0 for EIA-485 communication protocol 1 CH1TCP, CH2TCP, CH3TCP, CH4TCP DNP3.0 for TCP/IP communication protocol 1 CHSEROPT DNP3.0 for TCP/IP and EIA-485 communication protocol 1 MSTSER DNP3.0 for serial communication protocol 1 MST1TCP, MST2TCP, MST3TCP, MST4TCP DNP3.0 for TCP/IP communication protocol 1 DNPFREC DNP3.0 fault records for TCP/IP and EIA-485 communication protocol 1 IEC 61850-8-1 Parameter setting function for IEC 61850 1 GOOSEINTLKRCV Horizontal communication via GOOSE for interlocking 59 GOOSEBINRCV GOOSE binary receive 16 GOOSEDPRCV GOOSE function block to receive a double point value 64 GOOSEINTRCV GOOSE function block to receive an integer value 32 GOOSEMVRCV GOOSE function block to receive a measurand value 60 GOOSESPRCV GOOSE function block to receive a single point value 64 MULTICMDRCV/ MULTICMDSND Multiple command and transmit 60/10 FRONT, LANABI, LANAB, LANCDI, LANCD, GATEWAY Ethernet configuration 1 OPTICAL103 IEC 60870-5-103 Optical serial communication 1 RS485103 IEC 60870-5-103 serial communication for RS485 1 AGSAL Generic security application component 1 LD0LLN0 IEC 61850 LD0 LLN0 1 SYSLLN0 IEC 61850 SYS LLN0 1 Table continues on next page 1MRK 504 158-UEN A Section 2 Application 23 Application manual

1 PCMACCS IED configuration protocol 1 SECALARM Component for mapping security events on protocols such as DNP3 and IEC103 1 FSTACCS, FSTACCSNA Field service tool access via SPA protocol over ethernet communication 1 ACTIVLOG Activity logging parameters 1 ALTRK Service Tracking 1 SINGLELCCH Single ethernet port link status 1 PRPSTATUS Dual ethernet port link status 1 PRP IEC 62439-3 parallel redundancy protocol 1-P03 2.6 Basic IED functions GUID-C8F0E5D2-E305-4184-9627-F6B5864216CA v10 Table 4: 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 BININPUT, SYNCHCAN, SYNCHGPS, SYNCHCMPPS, SYNCHLON, SYNCHPPH, SYNCHPPS, SNTP, 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 SMAI1 - SMAI12 Signal matrix for analog inputs 3PHSUM Summation block 3 phase ATHSTAT Authority status ATHCHCK Authority check AUTHMAN Authority management FTPACCS FTP access with password Table continues on next page Section 2 1MRK 504 158-UEN A Application 24 Application manual

name Description 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 MSTSER DNP3.0 for serial communication protocol Table 5: Local HMI functions IEC 61850 or function name ANSI Description LHMICTRL Local HMI signals LANGUAGE Local human machine language SCREEN Local HMI Local human machine screen behavior FNKEYTY1–FNKEYTY5 FNKEYMD1– FNKEYMD5 Parameter setting function for HMI in PCM600 LEDGEN General LED indication part for LHMI OPENCLOSE_LED LHMI LEDs for open and close keys GRP1_LED1– GRP1_LED15 GRP2_LED1– GRP2_LED15 GRP3_LED1– GRP3_LED15 Basic part for CP HW LED indication module 1MRK 504 158-UEN A Section 2 Application 25 Application manual

3.1.1 Introduction GUID-79B8BC84-4AAB-44E7-86CD-FF63098B009D v1 The basic delivery includes one binary input module and one binary output module, which is sufficient for the default configured IO to trip and close circuit breaker. All IEDs can be reconfigured with the help of the ACT configuration tool in the PCM600 engineering platform. The IED can be adapted to special applications and special logic can be developed, such as logic for automatic opening of disconnectors and closing of ring bays, automatic load transfer from one busbar to the other, and so on. The basic IED configuration is provided with the signal matrix, mimic and the application configuration prepared for the functions included in the product by default. All parameters should be verified by the customer, since these are specific to the system, object or application. 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. The configurations are as far as found necessary provided with application comments to explain why the signals have been connected in the special way. On request, ABB is available to support the re-configuration work, either directly or to do the design checking. 3.1.1.1 Description of A05 GUID-62ED3636-147F-409C-9E92-A77E428CB506 v1 Three-winding transformer in single breaker arrangements. 1MRK 504 158-UEN A Section 3 Configuration 27 Application manual

arrangement 12AI (10I+2U) W2_QA1 W1_QB2 W1_QB1 W3_QA1 W1_QA1 Other Functions available from the function library W1 W2 W3 PH PIOC 50 3I>> OC4 PTOC 51 4(3I>) CC RBRF 50BF 3I>BF OC4 PTOC 51 4(3I>) CC RBRF 50BF 3I>BF OC4 PTOC 51 3I> CC RBRF 50BF 3I>BF FUF SPVC U>/I< SMP PTRC 94 1 → 0 SMP PTRC 94 1 → 0 C MSQI MET Isqi C MMXU MET I TR PTTR 49 θ> C MSQI MET Isqi Q CBAY 3 Control S SIMG 63 CV GAPC 2(I>/U<) SMP PTRC 94 1 → 0 DRP RDRE DFR/SER DR REF PDIF 87N IdN/I C MMXU MET I C MMXU MET I EF PIOC 50N IN>> C MSQI MET Isqi S SIML 71 WA1 WA2 W1_CT W1_NCT W3_CT W2_CT WA1 WA1 IEC15000405-2-en.vsd S SCBR S SCBR S SCBR S CILO 3 Control S CSWI 3 Control S XCBR 3 Control S SCBR S SCBR S SCBR S CILO 3 Control S CSWI 3 Control S XCBR 3 Control S SCBR S SCBR S SCBR S CILO 3 Control S CSWI 3 Control S XCBR 3 Control EF4PTOC 51N/67N T3W PDIF 87T 3Id/I> W1_QA1 EF4 PTOC 51N_67N 4(IN>) W3_QA1 W2_QA1 REF PDIF 87N IdN/I IEC15000405 V2 EN-US Figure 2: Configuration diagram for configuration A05 Section 3 1MRK 504 158-UEN A Configuration 28 Application manual

measurement results and correct protection operations. For power measuring and all directional and differential functions the directions of the input currents must be defined in order to reflect the way the current transformers are installed/connected in the field ( primary and secondary connections ). 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 availability of VT inputs depends on the ordered transformer input module (TRM) type. 4.2 Setting guidelines SEMOD55068-1 v1 SEMOD130348-4 v5 The available setting parameters related to analog inputs are depending on the actual hardware (TRM) and the logic configuration made in PCM600. If a second TRM is used, at least one TRM channel must be configured to get the service values. However, the MU physical channel must be configured to get service values from that channel. 4.2.1 Setting of the phase reference channel SEMOD55055-5 v3 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. 4.2.1.1 Example SEMOD55055-11 v4 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. 1MRK 504 158-UEN A Section 4 Analog inputs 29 Application manual

SEMOD55055-16 v5 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 3 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 3. Protected Object Line, transformer, etc Forward Reverse Definition of direction for directional functions Measured quantity is positive when flowing towards the object e.g. P, Q, I Reverse Forward 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-US Figure 3: 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. 4.2.2.1 Example 1 SEMOD55055-23 v5 Two IEDs used for protection of two objects. Section 4 1MRK 504 158-UEN A Analog inputs 30 Application manual

Set parameter CTStarPoint with Transformer as reference object. Correct setting is "ToObject" Forward Reverse 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 Is Is Ip Ip Ip IED IED IEC05000753 V2 EN-US Figure 4: Example how to set CTStarPoint parameters in the IED The figure 4 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 SEMOD55055-29 v6 Two IEDs used for protection of two objects and sharing a CT. 1MRK 504 158-UEN A Section 4 Analog inputs 31 Application manual

Set parameter CTStarPoint with Transformer as reference object. Correct setting is "ToObject" Forward Reverse 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-US Figure 5: 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 SEMOD55055-35 v6 One IED used to protect two objects. Section 4 1MRK 504 158-UEN A Analog inputs 32 Application manual

Set parameter CTStarPoint with Transformer as reference object. Correct setting is "ToObject" Reverse Forward 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-US Figure 6: 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 7. 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 504 158-UEN A Section 4 Analog inputs 33 Application manual

for transformer functions: Set parameter CTStarPoint with Transformer as reference object. Correct setting is "ToObject" Forward Reverse 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-US Figure 7: Example how to set CTStarPoint parameters in the IED 4.2.2.4 Examples on how to connect, configure and set CT inputs for most commonly used CT connections SEMOD55055-296 v6 Figure 8 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 IPri 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-US Figure 8: Commonly used markings of CT terminals Section 4 1MRK 504 158-UEN A Analog inputs 34 Application manual

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 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 SEMOD55055-352 v10 Figure 9 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 504 158-UEN A Section 4 Analog inputs 35 Application manual

Figure 9: 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 Figure 9. ' • 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 504 158-UEN A Analog inputs 36 Application manual

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 figure 10: L1 IL1 IL2 IL3 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-US Figure 10: Star connected three-phase CT set with its star point away from the protected object In the example in figure 10 case everything is done in a similar way as in the above described example (figure 9). The only difference is the setting of the parameter CTStarPoint of the used current inputs on the TRM (item 2 in figure 10 and 9): 1MRK 504 158-UEN A Section 4 Analog inputs 37 Application manual

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 figure 10. L1 IL1 IL2 IL3 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-US Figure 11: 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). Table continues on next page Section 4 1MRK 504 158-UEN A Analog inputs 38 Application manual

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. 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 SEMOD55055-392 v7 Figure 12 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. 1MRK 504 158-UEN A Section 4 Analog inputs 39 Application manual

Figure 12: Delta DAB connected three-phase CT set 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. Section 4 1MRK 504 158-UEN A Analog inputs 40 Application manual

L1 IL1 IL2 IL3 L2 L3 Protected Object IED CT 800/1 in Delta DAC Connected 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-US Figure 13: 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 180º by setting ToObject. 4.2.2.7 Example how to connect single-phase CT to the IED SEMOD55055-431 v7 Figure 14 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 504 158-UEN A Section 4 Analog inputs 41 Application manual

Figure 14: 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 14: CTprim = 1000 A CTsec = 1A CTStarPoint=ToObject For connection (b) shown in figure 14: 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. 4.2.3 Relationships between setting parameter Base Current, CT rated primary current and minimum pickup of a protection IED GUID-8EB19363-9178-4F04-A6AC-AF0C2F99C5AB v1 Note that for all line protection applications (e.g. distance protection or line differential protection) the parameter Base Current (i.e. IBase setting in the IED) used by the relevant protection function, shall always be set equal to the largest rated CT primary current among all Section 4 1MRK 504 158-UEN A Analog inputs 42 Application manual

CTPrim under the IED TRM settings. For all other protection applications (e.g. generator, shunt reactor, shunt capacitor and transformer protection) it is typically desirable to set IBase parameter equal to the rated current of the protected object. However this is only recommended to do if the rated current of the protected object is within the range of 40% to 120% of the selected CT rated primary current. If for any reason (e.g. high maximum short circuit current) the rated current of the protected object is less than 40% of the rated CT primary current, it is strongly recommended to set the parameter IBase in the IED to be equal to the largest rated CT primary current among all CTs involved in the protection scheme and installed on the same voltage level. This will effectively make the protection scheme less sensitive; however, such measures are necessary in order to avoid possible problems with loss of the measurement accuracy in the IED. Regardless of the applied relationship between the IBase parameter and the rated CT primary current, the corresponding minimum pickup of the function on the CT secondary side must always be verified. It is strongly recommended that the minimum pickup of any instantaneous protection function (e.g. differential, restricted earth fault, distance, instantaneous overcurrent, etc.) shall under no circumstances be less than 4% of the used IED CT input rating (i.e. 1A or 5A). This corresponds to 40mA secondary for IED 1A rated inputs and to 200mA secondary for IED 5A rated inputs used by the function. This shall be individually verified for all current inputs involved in the protection scheme. Note that exceptions from the above 4% rule may be acceptable for very special applications (e.g. when Multipurpose filter SMAIHPAC is involved in the protection scheme). 4.2.4 Setting of voltage channels SEMOD55055-44 v3 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. 4.2.4.1 Example SEMOD55055-47 v2 Consider a VT with the following data: 132 110 3 3 kV V EQUATION2016 V1 EN-US (Equation 1) The following setting should be used: VTprim=132 (value in kV) VTsec=110 (value in V) 4.2.4.2 Examples how to connect, configure and set VT inputs for most commonly used VT connections SEMOD55055-60 v5 Figure 15 defines the marking of voltage transformer terminals commonly used around the world. 1MRK 504 158-UEN A Section 4 Analog inputs 43 Application manual

Figure 15: 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 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. 4.2.4.3 Examples on how to connect a three phase-to-earth connected VT to the IED SEMOD55055-87 v8 Figure 16 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 504 158-UEN A Analog inputs 44 Application manual

Figure 16: 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 3 110 110 3 = EQUATION1903 V1 EN-US (Equation 2) Table continues on next page 1MRK 504 158-UEN A Section 4 Analog inputs 45 Application manual

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 18. 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. 4.2.4.4 Example on how to connect a phase-to-phase connected VT to the IED SEMOD55055-134 v6 Figure 17 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 504 158-UEN A Analog inputs 46 Application manual

Figure 17: 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. 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. 1MRK 504 158-UEN A Section 4 Analog inputs 47 Application manual

impedance earthed or unearthed netwoeks SEMOD55055-163 v8 Figure 18 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 3 Ph Ph Ph N U U U - - = × = × EQUATION1921 V3 EN-US (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 18 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. 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-US Figure 18: Open delta connected VT in high impedance earthed power system Section 4 1MRK 504 158-UEN A Analog inputs 48 Application manual

+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 11.43 VTprim kV = × = EQUATION1923 V1 EN-US (Equation 4) 110 sec 3 110 3 VT V = × = EQUATION1924 V1 EN-US (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 3 110 110 3 × = EQUATION1925 V1 EN-US (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. 4.2.4.6 Example how to connect the open delta VT to the IED for low impedance earthed or solidly earthed power systems SEMOD55055-199 v6 Figure 19 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: 1MRK 504 158-UEN A Section 4 Analog inputs 49 Application manual

(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 19 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-US Figure 19: Open delta connected VT in low impedance or solidly earthed power system Section 4 1MRK 504 158-UEN A Analog inputs 50 Application manual

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-US (Equation 8) 115 sec 3 115 3 VT V = × = EQUATION1929 V1 EN-US (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 3 115 115 3 = EQUATION1930 V1 EN-US (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. 4.2.4.7 Example on how to connect a neutral point VT to the IED GUID-E0EE34BE-A9B0-4F4F-9C06-BBBE87AD0017 v1 Figure 20 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. 1MRK 504 158-UEN A Section 4 Analog inputs 51 Application manual

value of Uo voltage will be equal to: 0 3 Ph Ph Ph E U U U - - = = EQUATION1931 V2 EN-US (Equation 11) Figure 20gives 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. 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-US Figure 20: Neutral point connected VT 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-US (Equation 12) sec 100 VT V = EQUATION1934 V1 EN-US (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. Table continues on next page Section 4 1MRK 504 158-UEN A Analog inputs 52 Application manual

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. 1MRK 504 158-UEN A Section 4 Analog inputs 53 Application manual

Figure 21: Local human-machine interface The LHMI of the IED contains the following elements: • Keypad • Display (LCD) • LED indicators • Communication port for PCM600 The LHMI is used for setting, monitoring and controlling. 1MRK 504 158-UEN A Section 5 Local HMI 55 Application manual

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. IEC15000270-1-en.vsdx IEC15000270 V1 EN-US Figure 22: Display layout 1 Path 2 Content 3 Status 4 Scroll bar (appears when needed) The function key 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. Section 5 1MRK 504 158-UEN A Local HMI 56 Application manual

Figure 23: Function button panel The indication LED panel shows on request the alarm text labels for the indication LEDs. Three indication LED pages are available. IEC13000240-1-en.vsd GUID-5157100F-E8C0-4FAB-B979-FD4A971475E3 V1 EN-US Figure 24: Indication LED panel The function button and indication 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 panels have a dynamic width that depends on the label string length. 5.2 LEDs AMU0600427 v12 The LHMI includes three status LEDs above the display: Ready, Start and Trip. There are 15 programmable indication LEDs on the front of the LHMI. Each LED can indicate three states with the colors: green, yellow and red. The texts related to each three-color LED are divided into three panels. There are 3 separate panels of LEDs available. The 15 physical three-color LEDs in one LED group can indicate 45 different signals. Altogether, 135 signals can be indicated since there are 1MRK 504 158-UEN A Section 5 Local HMI 57 Application manual

the lowest priority. For example, if on one panel there is an indication that requires the green LED to be lit, and on another panel there is an indication that requires the red LED to be lit, the red LED takes priority and is lit. The LEDs can be configured with PCM600 and the operation mode can be selected with the LHMI or PCM600. Information panels for the indication LEDs are shown by pressing the Multipage button. Pressing that button cycles through the three pages. A lit or un-acknowledged LED is indicated with a highlight. Such lines can be selected by using the Up/Down arrow buttons. Pressing the Enter key shows details about the selected LED. Pressing the ESC button exits from information pop-ups as well as from the LED panel as such. The Multipage button has a LED. This LED is lit whenever any LED on any panel is lit. If there are un-acknowledged indication LEDs, then the Multipage LED blinks. To acknowledge LEDs, press the Clear button to enter the Reset menu (refer to description of this menu for details). There are two additional LEDs which are next to the control buttons and . They can, for example, represent the status of a circuit breaker. The LEDs are controlled by the function block OPENCLOSE_LED which must be configured to show the status of the breaker. 5.3 Keypad AMU0600428 v17 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 504 158-UEN A Local HMI 58 Application manual

Figure 25: 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 19 Menu 20 Clear 21 Help 1MRK 504 158-UEN A Section 5 Local HMI 59 Application manual

24 IED status LEDs 5.4 Local HMI functionality 5.4.1 Protection and alarm indication GUID-09CCB9F1-9B27-4C12-B253-FBE95EA537F5 v15 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 6: Ready LED (green) LED state Description Off Auxiliary supply voltage is disconnected. On Normal operation. Flashing Internal fault has occurred. Table 7: 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 504 158-UEN A Local HMI 60 Application manual

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 9: 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 GUID-5EE466E3-932B-4311-9FE1-76ECD8D6E245 v9 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. 5.4.3 Front communication GUID-FD72A445-C8C1-4BFE-90E3-0AC78AE17C45 v10 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. • The yellow LED is not used; it is always off. 1MRK 504 158-UEN A Section 5 Local HMI 61 Application manual

Figure 26: RJ-45 communication port and green indicator LED 1 RJ-45 connector 2 Green indicator LED The default IP address for the IED front port is 10.1.150.3 and the corresponding subnetwork mask is 255.255.255.0. It can be set through the local HMI path Main menu/Configuration/ Communication/Ethernet configuration/FRONT:1. Do not connect the IED front port to a LAN. Connect only a single local PC with PCM600 to the front port. It is only intended for temporary use, such as commissioning and testing. Section 5 1MRK 504 158-UEN A Local HMI 62 Application manual

IP14639-1 v3 6.1.1 Application M16722-3 v9 The transformer differential protection is a unit protection. It serves as the main protection of transformers in case of winding failure. The protective zone of a differential protection includes the transformer itself, the bus-work or cables between the current transformers and the power transformer. When bushing current transformers are used for the differential IED, the protective zone does not include the bus-work or cables between the circuit breaker and the power transformer. In some substations there is a current differential protection relay for the busbar. Such a busbar protection will include the bus-work or cables between the circuit breaker and the power transformer. Internal electrical faults are very serious and will cause immediate damage. Short circuits and earth faults in windings and terminals will normally be detected by the differential protection. Interturn faults are flashovers between conductors within the same physical winding. It is possible to detect interturn faults if sufficient number of turns are short-circuited. Interturn faults are the most difficult transformer winding fault to detect with electrical protections. A small interturn fault including just a few turns will result in an undetectable amount of current until it develops into an earth or phase fault. For this reason it is important that the differential protection has a high level of sensitivity and that it is possible to use a sensitive setting without causing unwanted operations during external faults. It is important that the faulty transformer be disconnected as fast as possible. As the differential protection is a unit protection it can be designed for fast tripping, thus providing selective disconnection of the faulty transformer. The differential protection should never operate on faults outside the protective zone. A transformer differential protection compares the current flowing into the transformer with the current leaving the transformer. A correct analysis of fault conditions by the differential protection must take into consideration changes due to the voltage, current and phase angle caused by the protected transformer. Traditional transformer differential protection functions required auxiliary transformers for correction of the phase shift and ratio. The numerical microprocessor based differential algorithm as implemented in the IED compensates for both the turn-ratio and the phase shift internally in the software. No auxiliary current transformers are necessary. The differential current should theoretically be zero during normal load or external faults if the turn-ratio and the phase shift are correctly compensated. However, there are several different phenomena other than internal faults that will cause unwanted and false differential currents. The main reasons for unwanted differential currents may be: • mismatch due to varying tap changer positions • different characteristics, loads and operating conditions of the current transformers • zero sequence currents that only flow on one side of the power transformer • normal magnetizing currents • magnetizing inrush currents • overexcitation magnetizing currents 1MRK 504 158-UEN A Section 6 Differential protection 63 Application manual

in variety of application for two winding transformer protection. In such application, it is suggested to set the tertiary winding (W3) rated current and rated voltage to the exact same rating as secondary winding (W2). 6.1.2 Setting guidelines IP14936-1 v2 M15266-4 v5 The parameters for the Transformer differential protection function are set via the local HMI or Protection and Control IED Manager (PCM600). 6.1.2.1 Restrained and unrestrained differential protection M15266-289 v10 To make a differential IED as sensitive and stable as possible, restrained differential protections have been developed and are now adopted as the general practice in the protection of power transformers. The protection should be provided with a proportional bias, which makes the protection operate for a certain percentage differential current related to the current through the transformer. This stabilizes the protection under through fault conditions while still permitting the system to have good basic sensitivity. The bias current can be defined in many different ways. One classical way of defining the bias current has been Ibias = (I1 + I2) / 2, where I1 is the magnitude of the power transformer primary current, and I2 the magnitude of the power transformer secondary current. However, it has been found that if the bias current is defined as the highest power transformer current this will reflect the difficulties met by the current transformers much better. The differential protection function uses the highest current of all restrain inputs as bias current. For applications where the power transformer rated current and the CT primary rated current can differ considerably, (applications with T-connections), measured currents in the T connections are converted to pu value using the rated primary current of the CT, but one additional "measuring" point is introduced as sum of this two T currents. This summed current is converted to pu value using the power transformer winding rated currents. After that the highest pu value is taken as bias current in pu. In this way the best possible combination between sensitivity and security for differential protection function with T connection is obtained. The main philosophy behind the principle with the operate bias characteristic is to increase the pickup level when the current transformers have difficult operating conditions. This bias quantity gives the best stability against an unwanted operation during external faults. The usual practice for transformer protection is to set the bias characteristic to a value of at least twice the value of the expected spill current under through faults conditions. These criteria can vary considerably from application to application and are often a matter of judgment. The second slope is increased to ensure stability under heavy through fault conditions which could lead to increased differential current due to saturation of current transformers. Default settings for the operating characteristic with IdMin = 0.3pu of the power transformer rated current can be recommended as a default setting in normal applications. If the conditions are known more in detail, higher or lower sensitivity can be chosen. The selection of suitable characteristic should in such cases be based on the knowledge of the class of the current transformers, availability of information on the load tap changer position, short circuit power of the systems, and so on. The second section of the restrain characteristic has an increased slope in order to deal with increased differential current due to additional power transformer losses during heavy loading of the transformer and external fault currents. The third section of the restrain characteristic decreases the sensitivity of the restrained differential function further in order to cope with CT saturation and transformer losses during heavy through faults. A default setting for the operating characteristic with IdMin = 0.3 * IBase is recommended in normal applications. If the conditions are known in more detail, higher or lower sensitivity can be chosen. The selection of suitable characteristic should in such cases be based on the knowledge of the class of the current transformers, availability of information on the tap changer position, short circuit power of the systems, and so on. Section 6 1MRK 504 158-UEN A Differential protection 64 Application manual

the differential protection will be either in series with the power transformer windings or the current transformers will be in breakers that are part of the bus, such as a breaker-and-a-half or a ring bus scheme. For current transformers with primaries in series with the power transformer winding, the current transformer primary current for external faults will be limited by the transformer impedance. When the current transformers are part of the bus scheme, as in the breaker-and-a-half or the ring bus scheme, the current transformer primary current is not limited by the power transformer impedance. High primary currents may be expected. In either case, any deficiency of current output caused by saturation of one current transformer that is not matched by a similar deficiency of another current transformer will cause a false differential current to appear. Differential protection can overcome this problem if the bias is obtained separately from each set of current transformer circuits. It is therefore important to avoid paralleling of two or more current transformers for connection to a single restraint input. Each current connected to the IED is available for biasing the differential protection function. The unrestrained operation level has a default value of IdUnre = 10pu, which is typically acceptable for most of the standard power transformer applications. In the following case, this setting need to be changed accordingly: • When CT from "T-connection" are connected to IED, as in the breaker-and-a-half or the ring bus scheme, special care shall be taken in order to prevent unwanted operation of transformer differential IED for through-faults due to different CT saturation of "T- connected" CTs. Thus if such uneven saturation is a possibility it is typically required to increase unrestrained operational level to IdUnre = 20-25pu • For differential applications on HV shunt reactors, due to the fact that there is no heavy through-fault condition, the unrestrained differential operation level can be set to IdUnre = 1.75pu The overall operating characteristic of the transformer differential protection is shown in figure 27. 1MRK 504 158-UEN A Section 6 Differential protection 65 Application manual

operate current [ times IBase ] SlopeSection2 SlopeSection3 en05000187-2.vsd IEC05000187 V2 EN-US Figure 27: Representation of the restrained, and the unrestrained operate characteristics 100% Ioperate slope Irestrain D = D × EQUATION1246 V1 EN-US (Equation 14) and where the restrained characteristic is defined by the settings: 1. IdMin 2. EndSection1 3. EndSection2 4. SlopeSection2 5. SlopeSection3 6.1.2.2 Elimination of zero sequence currents M15266-286 v8 A differential protection may operate undesirably due to external earth-faults in cases where the zero sequence current can flow on only one side of the power transformer, but not on the other side. This is the case when zero sequence current cannot be properly transformed to the other side of the power transformer. Power transformer connection groups of the Yd or Dy type cannot transform zero sequence current. If a delta winding of a power transformer is earthed via an earthing transformer inside the zone protected by the differential protection there will be an unwanted differential current in case of an external earth-fault. The same is true for an earthed star winding. Even if both the star and delta winding are earthed, the zero sequence current is usually limited by the earthing transformer on the delta side of the power Section 6 1MRK 504 158-UEN A Differential protection 66 Application manual

protection insensitive to external earth-faults in these situations the zero sequence currents must be eliminated from the power transformer IED currents on the earthed windings, so that they do not appear as differential currents. This had once been achieved by means of interposing auxiliary current transformers. The elimination of zero sequence current is done numerically by setting ZSCurrSubtrWx=Off or On and doesn't require any auxiliary transformers or zero sequence traps. Instead it is necessary to eliminate the zero sequence current from every individual winding by proper setting of setting parameters ZSCurrSubtrWx=Off or On. In case of a zig-zag winding, use one of the two following options: • A delta winding • A wye winding with zero sequence subtraction set to ON 6.1.2.3 Inrush restraint methods M15266-6 v7 With a combination of the second harmonic restraint and the waveform restraint methods it is possible to get a protection with high security and stability against inrush effects and at the same time maintain high performance in case of heavy internal faults even if the current transformers are saturated. Both these restraint methods are used by the IED. The second harmonic restraint function has a settable level. If the ratio of the second harmonic to the fundamental in the differential current is above the settable limit, the operation of the differential protection is restrained. It is recommended to set parameter I2/I1Ratio = 15% as default value in case no special reasons exist to choose another value. 6.1.2.4 Overexcitation restraint method M15266-320 v9 In case of an overexcited transformer, the winding currents contain odd harmonic components because the currents waveform are symmetrical relative to the time axis. As the third harmonic currents cannot flow into a delta winding, the fifth harmonic is the lowest harmonic which can serve as a criterion for overexcitation. The differential protection function is provided with a fifth harmonic restraint to prevent the protection from operation during an overexcitation condition of a power transformer. If the ratio of the fifth harmonic to the fundamental in the differential current is above a settable limit the operation is restrained. It is recommended to use I5/I1Ratio = 25% as default value in case no special reasons exist to choose another setting. 6.1.2.5 Cross-blocking between phases M15266-317 v7 Basic definition of the cross-blocking is that one of the three phases can block operation (that is, tripping) of the other two phases due to the harmonic pollution of the differential current in that phase (waveform, 2nd or 5th harmonic content). In the algorithm the user can control the cross-blocking between the phases via the setting parameter CrossBlockEn. When parameter CrossBlockEn is set to On, cross blocking between phases will be introduced. There are no time related settings involved, but the phase with the operating point above the set bias characteristic will be able to cross-block the other two phases if it is self-blocked by any of the previously explained restrained criteria. As soon as the operating point for this phase is below the set bias characteristic cross blocking from that phase will be inhibited. In this way cross- blocking of the temporary nature is achieved. It should be noted that this is the default (recommended) setting value for this parameter. When parameter CrossBlockEn is set to Off, any cross blocking between phases will be disabled. 1MRK 504 158-UEN A Section 6 Differential protection 67 Application manual

M15266-269 v10 The external/internal fault discriminator operation is based on the relative position of the two phasors (in case of a two-winding transformer) representing the W1 and W2 negative sequence current contributions, defined by matrix expression see the technical reference manual. It practically performs a directional comparison between these two phasors. In order to perform a directional comparison of the two phasors their magnitudes must be high enough so that one can be sure that they are due to a fault. On the other hand, in order to guarantee a good sensitivity of the internal/external fault discriminator, the value of this minimum limit must not be too high. Therefore this limit value (IMinNegSeq) is settable in the range from 1% to 20% of the differential protections IBasecurrent, which is in our case the power transformer HV side rated current. The default value is 4%. Only if the magnitude of both negative sequence current contributions are above the set limit, the relative position between these two phasors is checked. If either of the negative sequence current contributions, which should be compared, is too small (less than the set value for IMinNegSeq), no directional comparison is made in order to avoid the possibility to produce a wrong decision. This magnitude check, guarantees stability of the algorithm when the power transformer is energized. In cases where the protected transformer can be energized with a load connected on the LV side (e.g. a step-up transformer in a power station with directly connected auxiliary transformer on its LV side) the value for this setting shall be increased to at least 12%. This is necessary in order to prevent unwanted operation due to LV side currents during the transformer inrush. The setting NegSeqROA represents the so-called Relay Operate Angle, which determines the boundary between the internal and external fault regions. It can be selected in the range from 30 degrees to 90 degrees, with a step of 1 degree. The default value is 60 degrees. The default setting 60 degrees somewhat favors security in comparison to dependability. If the user has no well-justified reason for another value, 60 degrees shall be applied. If the above conditions concerning magnitudes are fulfilled, the internal/external fault discriminator compares the relative phase angle between the negative sequence current contributions from the HV side and LV side of the power transformer using the following two rules : • If the negative sequence currents contributions from HV and LV sides are in phase or at least in the internal fault region, the fault is internal. • If the negative sequence currents contributions from HV and LV sides are 180 degrees out of phase or at least in the external fault region, the fault is external. Under external fault condition and with no current transformer saturation, the relative angle is theoretically equal to 180 degrees. During internal fault and with no current transformer saturation, the angle shall ideally be 0 degrees, but due to possible different negative sequence source impedance angles on HV and LV side of power transformer, it may differ somewhat from the ideal zero value. The internal/external fault discriminator has proved to be very reliable. If a fault is detected, that is, START signals set by ordinary differential protection, and at the same time the internal/external fault discriminator characterizes this fault as an internal, any eventual blocking signals produced by either the harmonic or the waveform restraints are ignored. If the bias current is more than 110% of IBase, the negative sequence threshold (IMinNegSeq) is increased internally.. This assures response times of the differential protection below one power system cycle (below 20 ms for 50 Hz system) for all more severe internal faults. Even for heavy internal faults with severely saturated current transformers this differential protection operates well below one cycle, since the harmonic distortions in the differential currents do not slow down the differential protection operation. Practically, an unrestrained operation is achieved for all internal faults. Section 6 1MRK 504 158-UEN A Differential protection 68 Application manual

transformers are concerned. If a disturbance is detected and the internal/external fault discriminator characterizes this fault as an external fault, the conventional additional criteria are posed on the differential algorithm before its trip is allowed. This assures high algorithm stability during external faults. However, at the same time the differential function is still capable of tripping quickly for evolving faults. The principle of the internal/external fault discriminator can be extended to autotransformers and transformers with three windings. If all three windings are connected to their respective networks then three directional comparisons are made, but only two comparisons are necessary in order to positively determine the position of the fault with respect to the protected zone. The directional comparisons which are possible, are: W1 - (W2+W3) and W2 - (W1+W3). The rule applied by the internal/external fault discriminator in case of three-winding power transformers is: • If any comparison indicates an internal fault, then it is an internal fault. • If any comparison indicates an external fault, then it is an external fault If one of the windings is not connected, the algorithm automatically reduces to the two- winding version. Nevertheless, the whole power transformer is protected, including the non- connected winding. 6.1.2.7 Differential current alarm M15266-337 v6 Differential protection continuously monitors the level of the fundamental frequency differential currents and gives an alarm if the pre-set value is simultaneously exceeded in all three phases. This feature can be used to monitor the integrity of on-load tap-changer compensation within the differential function. The threshold for the alarm pickup level is defined by setting parameter IDiffAlarm. This threshold should be typically set in such way to obtain operation when on-load tap-changer measured value within differential function differs for more than two steps from the actual on-load tap-changer position. To obtain such operation set parameter IDiffAlarm equal to two times the on-load tap-changer step size (For example, typical setting value is 5% to 10% of base current). Set the time delay defined by parameter tAlarmDelay two times longer than the on-load tap-changer mechanical operating time (For example, typical setting value 10s). 6.1.2.8 Open CT detection M15266-340 v5 The Transformer differential function has a built-in, advanced open CT detection feature. This feature can block the unexpected operation created by the Transformer differential function in case of open CT secondary circuit under normal load condition. An alarm signal can also be issued to station operational personnel to make remedy action once the open CT condition is detected. The following setting parameters are related to this feature: • Setting parameter OpenCTEnable enables/disables this feature • Setting parameter tOCTAlarmDelay defines the time delay after which the alarm signal will be given • Setting parameter tOCTReset defines the time delay after which the open CT condition will reset once the defective CT circuits have been rectified • Once the open CT condition has been detected, then all the differential protection functions are blocked except the unrestraint (instantaneous) differential protection The outputs of open CT condition related parameters are listed below: 1MRK 504 158-UEN A Section 6 Differential protection 69 Application manual

• OpenCTAlarm: Alarm issued after the setting delay • OpenCTIN: Open CT in CT group inputs (1 for input 1 and 2 for input 2) • OpenCTPH: Open CT with phase information (1 for phase L1, 2 for phase L2, 3 for phase L3) 6.1.2.9 Switch onto fault feature M15266-348 v5 The Transformer differential function in the IED has a built-in, advanced switch onto fault feature. This feature can be enabled or disabled by the setting parameter SOTFMode. When SOTFMode = On this feature is enabled. It shall be noted that when this feature is enabled it is not possible to test the 2nd harmonic blocking feature by simply injecting one current with superimposed second harmonic. In that case the switch on to fault feature will operate and the differential protection will trip. However for a real inrush case the differential protection function will properly restrain from operation. For more information about the operating principles of the switch onto fault feature please read the Technical Manual. 6.1.3 Setting example SEMOD167745-1 v1 6.1.3.1 Introduction SEMOD167720-5 v6 Differential protection for power transformers has been used for decades. In order to correctly apply transformer differential protection proper compensation is needed for: • power transformer phase shift (vector group compensation) • CT secondary currents magnitude difference on different sides of the protected transformer (ratio compensation) • zero sequence current elimination (zero sequence current reduction) shall be done. In the past this was performed with help of interposing CTs or special connection of main CTs (delta connected CTs). With numerical technology all these compensations are done in IED software. The Differential transformer protection is capable to provide differential protection for all standard three-phase power transformers without any interposing CTs. It has been designed with assumption that all main CTs will be star connected. For such applications it is then only necessary to enter directly CT rated data and power transformer data as they are given on the power transformer nameplate and differential protection will automatically balance itself. These are internal compensations within the differential function. The protected power transformer data are always entered as they are given on the nameplate. Differential function will by itself correlate nameplate data and properly select the reference windings. However the IED can also be used in applications where some of the main CTs are connected in delta. In such cases the ratio for the main CT connected in delta shall be intentionally set for √ (3)=1.732 times smaller than actual ratio of individual phase CTs (for example, instead of 800/5 set 462/5) In case the ratio is 800/2.88A, often designed for such typical delta connections, set the ratio as 800/5 in the IED. At the same time the power transformer vector group shall be set as Yy0 because the IED shall not internally provide any phase angle shift compensation. The necessary phase angle shift compensation will be provided externally by delta connected main CT. All other settings should have the same values irrespective of main CT connections. Section 6 1MRK 504 158-UEN A Differential protection 70 Application manual

SEMOD167749-5 v3 Three most typical main CT connections used for transformer differential protection are shown in figure 28. It is assumed that the primary phase sequence is L1-L2-L3. L1 IL1 IL1-IL2 IL2-IL3 IL3-IL1 IL1-IL3 IL2-IL1 IL3-IL2 IL1 IL2 IL3 Protected Transformer Winding CT Star Connected CT in Delta DAC Connected CT in Delta DAB Connected IL2 IL3 L2 L3 en06000549.vsd IEC06000549 V1 EN-US Figure 28: Commonly used main CT connections for Transformer differential protection. For star connected main CTs, secondary currents fed to the IED: • are directly proportional to the measured primary currents • are in phase with the measured primary currents • contain all sequence components including zero sequence current component For star connected main CTs, the main CT ratio shall be set as it is in actual application. The “StarPoint” parameter, for the particular star connection shown in figure 28, shall be set ToObject. If star connected main CTs have their star point away from the protected transformer this parameter should be set FromObject. For delta DAC connected main CTs, secondary currents fed to the IED: • are increased √3 times (1.732 times) in comparison with star connected CTs • lag by 30° the primary winding currents (this CT connection rotates currents by 30° in clockwise direction) • do not contain zero sequence current component For DAC delta connected main CTs, ratio shall be set for √3 times smaller than the actual ratio of individual phase CTs. The “StarPoint” parameter, for this particular connection shall be set ToObject. It shall be noted that delta DAC connected main CTs must be connected exactly as shown in figure 28. For delta DAB connected main CTs, secondary currents fed to the IED: • are increased √3 times (1.732 times) in comparison with star connected CTs • lead by 30° the primary winding currents (this CT connection rotates currents by 30° in anti-clockwise direction) • do not contain zero sequence current component 1MRK 504 158-UEN A Section 6 Differential protection 71 Application manual

actual ratio of individual phase CTs. The “StarPoint” parameter, for this particular connection shall be set ToObject. It shall be noted that delta DAB connected main CTs must be connected exactly as shown in figure 28. For more detailed info regarding CT data settings please refer to the three application examples presented in section "Application Examples". 6.1.3.3 Application Examples SEMOD167854-5 v2 Three application examples will be given here. For each example two differential protection solutions will be presented: • First solution will be with all main CTs star connected. • Second solution will be with delta connected main CT on Y (that is, star) connected sides of the protected power transformer. For each differential protection solution the following settings will be given: 1. Input CT channels on the transformer input modules. 2. General settings for the transformer differential protection where specific data about protected power transformer shall be entered. Finally the setting for the differential protection characteristic will be given for all presented applications. Example 1: Star-delta connected power transformer without on-load tap-changer SEMOD167854-110 v6 Single line diagrams for two possible solutions for such type of power transformer with all relevant application data are given in figure 29. Section 6 1MRK 504 158-UEN A Differential protection 72 Application manual

Figure 29: Two differential protection solutions for star-delta connected power transformer For this particular power transformer the 69 kV side phase-to-earth no-load voltages lead by 30 degrees the 12.5 kV side phase-to- earth no-load voltages. Thus when external phase angle shift compensation is done by connecting main HV CTs in delta, as shown in the right-hand side in figure 29, it must be ensured that the HV currents are rotated by 30° in clockwise direction. Thus the DAC delta CT connection must be used for 69 kV CTs in order to put 69 kV & 12.5 kV currents in phase. To ensure proper application of the IED for this power transformer it is necessary to do the following: 1. Check that HV & LV CTs are connected to 5 A CT inputs in the IED. 2. For second solution make sure that HV delta connected CTs are DAC connected. 3. For star connected CTs make sure how they are stared (that is, earthed) to/from protected transformer. 4. Enter the following settings for all three CT input channels used for the LV side CTs see table 10. Table 10: CT input channels used for the LV side CTs Setting parameter Selected value for both solutions CTprim 800 CTsec 5 CTStarPoint ToObject 1MRK 504 158-UEN A Section 6 Differential protection 73 Application manual

table 11. Table 11: CT input channels used for the HV side CTs Setting parameter Selected value for solution 1 (star connected CT) Selected value for solution 2 (delta connected CT) CTprim 300 300 173 3 = EQUATION1888 V1 EN-US (Equation 15) CTsec 5 5 CTStarPoint From Object ToObject To compensate for delta connected CTs, see equation 15. 6. Assume GBASVAL:1 is used for winding 1 (W1, HV-side) base values: Set Ibase = 175 A (rated current), Ubase= 69 kV (rated voltage). 7. Assume GBASVAL:2 is used for winding 2 (W2, LV-side) base values: Set Ibase = 965 A (rated current), Ubase= 12.5 kV (rated voltage). 8. Enter the following values for the general settings of the Transformer differential protection function, see table 12. Table 12: General settings of the differential protection function Setting parameter Select value for solution 1 (star connected CT) Selected value for solution 2 (delta connected CT) GlobalBaseSelW1 1 (GBASVAL:1) 1 (GBASVAL:1) GlobalBaseSelW2 2 (GBASVAL:2) 2 (GBASVAL:2) ConnectTypeW1 STAR (Y) STAR (Y) ConnectTypeW2 delta=d star=y 1) ClockNumberW2 1 [30 deg lag] 0 [0 deg] 1) ZSCurrSubtrW1 On Off 2) ZSCurrSubtrW2 Off Off TconfigForW1 No No TconfigForW2 No No LocationOLTC1 Not used Not used Other Parameters Not relevant for this application. Use default value. Not relevant for this application. Use default value. 1) To compensate for delta connected CTs 2) Zero-sequence current is already removed by connecting main CTs in delta Delta-star connected power transformer without tap changer SEMOD167854-209 v5 Single line diagrams for two possible solutions for such type of power transformer with all relevant application data are given in figure 30. Section 6 1MRK 504 158-UEN A Differential protection 74 Application manual

Figure 30: Two differential protection solutions for delta-star connected power transformer For this particular power transformer the 115 kV side phase-to-earth no-load voltages lead by 30° the 24.9 kV side phase-to-earth no-load voltages. Thus when external phase angle shift compensation is done by connecting main 24.9 kV CTs in delta, as shown in the right-hand side in figure 30, it must be ensured that the 24.9 kV currents are rotated by 30° in anti-clockwise direction. Thus, the DAB CT delta connection (see figure 30) must be used for 24.9 kV CTs in order to put 115 kV & 24.9 kV currents in phase. To ensure proper application of the IED for this power transformer it is necessary to do the following: 1. Check that HV & LV CTs are connected to 5 A CT inputs in the IED. 2. For second solution make sure that LV delta connected CTs are DAB connected. 3. For star connected CTs make sure how they are 'star'red (that is, earthed) to/from protected transformer. 4. Enter the following settings for all three CT input channels used for the HV side CTs, see table 13. Table 13: CT input channels used for the HV side CTs Setting parameter Selected value for both solutions CTprim 400 CTsec 5 CTStarPoint ToObject 5. Enter the following settings for all three CT input channels used for the LV side CTs, see table "CT input channels used for the LV side CTs". 1MRK 504 158-UEN A Section 6 Differential protection 75 Application manual

Setting parameter Selected value for Solution 1 (star connected CT) Selected value for Solution 2 (delta connected CT) CTprim 1500 1500 866 3 = EQUATION1889 V1 EN-US (Equation 16) CTsec 5 5 CTStarPoint ToObject ToObject To compensate for delta connected CTs, see equation 16. 6. Assume GBASVAL:1 is used for winding 1 (W1, HV-side) base values: Set Ibase = 301 A (rated current), Ubase= 115 kV (rated voltage). 7. Assume GBASVAL:2 is used for winding 2 (W2, LV-side) base values: Set Ibase = 1391 A (rated current), Ubase= 24.9 kV (rated voltage). 8. Enter the following values for the general settings of the differential protection function, see table14. Table 14: General settings of the differential protection Setting parameter selected value for both Solution 1 (star conected CT) Selected value for both Solution 2 (delta connected CT) GlobalBaseSelW1 1 (GBASVAL:1) 1 (GBASVAL:1) GlobalBaseSelW2 2 (GBASVAL:2) 2 (GBASVAL:2) ConnectTypeW1 Delta (D) STAR (Y) 1) ConnectTypeW2 star=y star=y ClockNumberW2 1 [30 deg lag] 0 [0 deg] 1) ZSCurrSubtrW1 Off Off ZSCurrSubtrW2 On On 2) TconfigForW1 No No TconfigForW2 No No LocationOLTC1 Not Used Not Used Other parameters Not relevant for this application. Use default value. Not relevant for this application. Use default value. 1) To compensate for delta connected CTs. 2) Zero-sequence current is already removed by connecting main CTs in delta. 6.1.3.4 Summary and conclusions SEMOD168160-5 v3 The IED can be used for differential protection of three-phase power transformers with main CTs either star or delta connected. However the IED has been designed with the assumption that all main CTS are star connected. The IED can be used in applications where the main CTs are delta connected. For such applications the following shall be kept in mind: Section 6 1MRK 504 158-UEN A Differential protection 76 Application manual

individual phase CT ratio. 2. The power transformer vector group shall typically be set as Yy0 because the compensation for power transformer the actual phase shift is provided by the external delta CT connection. 3. The zero sequence current is eliminated by the main CT delta connections. Thus on sides where CTs are connected in delta the zero sequence current elimination shall be set to Off in the IED. The following table summarizes the most commonly used star-delta vector groups around the world and provides information about the required type of main CT delta connection on the star side of the protected transformer. IEC vector group Positive sequence no-load voltage phasor diagram Required delta CT connection type on star side of the protected power transformer and internal vector group setting in the IED YNd1 Y IEC06000559 V1 EN-US DAC/Yy0 Dyn1 Y IEC06000560 V1 EN-US DAB/Yy0 YNd11 Y IEC06000561 V1 EN-US DAB/Yy0 Table continues on next page 1MRK 504 158-UEN A Section 6 Differential protection 77 Application manual

Positive sequence no-load voltage phasor diagram Required delta CT connection type on star side of the protected power transformer and internal vector group setting in the IED Dyn11 Y IEC06000562 V1 EN-US DAC/Yy0 YNd5 Y IEC06000563 V1 EN-US DAB/Yy6 Dyn5 Y IEC06000564 V1 EN-US DAC/Yy6 6.2 Low impedance restricted earth fault protection REFPDIF IP14640-1 v6 6.2.1 Identification M14843-1 v5 Function description IEC 61850 identification IEC 60617 identification ANSI/IEEE C37.2 device number Restricted earth-fault protection, low impedance REFPDIF IdN/I SYMBOL-AA V1 EN-US 87N 6.2.2 Application IP14941-1 v1 M13940-3 v11 A breakdown of the insulation between a transformer winding and the core or the tank may result in a large fault current which causes severe damage to the windings and the transformer core. A high gas pressure may develop, damaging the transformer tank. Fast and sensitive detection of earth faults in a power transformer winding can be obtained in solidly earthed or low impedance earthed networks by the restricted earth-fault protection. Section 6 1MRK 504 158-UEN A Differential protection 78 Application manual

point (in case of star-connected windings) or through a separate earthing transformer (in case of delta-connected windings). The low impedance restricted earth-fault protection REFPDIF is a winding protection function. It protects the power transformer winding against faults involving earth. Observe that single phase-to-earth faults are the most common fault types in transformers. A sensitive earth-fault protection is therefore desirable. A restricted earth-fault protection is the fastest and the most sensitive protection, a power transformer winding can have and will detect faults such as: • earth faults in the transformer winding when the network is earthed through an impedance • earth faults in the transformer winding in solidly earthed network when the point of the fault is close to the winding star point. The restricted earth-fault protection is not affected, as a differential protection, with the following power transformer related phenomena: • magnetizing inrush currents • overexcitation magnetizing currents • load tap changer • external and internal phase faults which do not involve earth • symmetrical overload conditions Due to its features, REFPDIF is often used as a main protection of the transformer winding for all faults involving earth. 6.2.2.1 Transformer winding, solidly earthed M13048-3 v9 The most common application is on a solidly earthed transformer winding. The connection is shown in figure 31. 1MRK 504 158-UEN A Section 6 Differential protection 79 Application manual

Figure 31: Connection of the low impedance Restricted earth-fault function REFPDIF for a directly (solidly) earthed transformer winding 6.2.2.2 Transformer winding, earthed through zig-zag earthing transformer M13048-8 v11 A common application is for low reactance earthed transformer where the earthing is through separate zig-zag earthing transformers. The fault current is then limited to typical 800 to 2000 A for each transformer. The connection for this application is shown in figure 32. Section 6 1MRK 504 158-UEN A Differential protection 80 Application manual

I3PW1CT1 I3P IdN/I Protected winding W1 I3PW2CT1 I3P IdN/I REFPDIF - 2 Protected winding W2 Earthing transformer IEC09000110-4-EN.vsd IEC09000110-4-EN V2 EN-US Figure 32: Connection of the low impedance Restricted earth-fault function REFPDIF for a zig-zag earthing transformer 6.2.2.3 Autotransformer winding, solidly earthed M13048-13 v9 Autotransformers can be protected with the low impedance restricted earth-fault protection function REFPDIF. The complete transformer will then be protected including the HV side, the neutral connection and the LV side. The connection of REFPDIF for this application is shown in figure 33. 1MRK 504 158-UEN A Section 6 Differential protection 81 Application manual

Figure 33: Connection of restricted earth fault, low impedance function REFPDIF for an autotransformer, solidly earthed 6.2.2.4 Reactor winding, solidly earthed M13048-18 v10 Reactors can be protected with restricted earth-fault protection, low impedance function REFPDIF. The connection of REFPDIF for this application is shown in figure 34. Section 6 1MRK 504 158-UEN A Differential protection 82 Application manual

Figure 34: Connection of restricted earth-fault, low impedance function REFPDIF for a solidly earthed reactor 6.2.2.5 CT earthing direction M13048-29 v12 To make the restricted earth-fault protection REFPDIF operate correctly, the main CTs are always supposed to be star -connected. The main CT's neutral (star) formation can be positioned in either way, ToObject or FromObject. However, internally REFPDIF always uses reference directions towards the protected transformers, as shown in Figure "". Thus the IED always measures the primary currents on all sides and in the neutral of the power transformer with the same reference direction towards the power transformer windings. The earthing can be freely selected for each of the involved current transformers. 6.2.3 Setting guidelines IP14942-1 v1 6.2.3.1 Setting and configuration M13052-3 v3 Recommendation for analog inputs M13052-8 v9 I3P: Neutral point current ( All analog inputs connected as 3Ph groups in ACT). I3PW1CT1: Phase currents for winding 1 first current transformer set. I3PW1CT2: Phase currents for winding1 second current transformer set for multi-breaker arrangements. When not required configure input to "GRP-OFF". 1MRK 504 158-UEN A Section 6 Differential protection 83 Application manual

autotransformers. I3PW2CT2: Phase currents for winding 2 second current transformer set for multi-breaker arrangements. Used when protecting an autotransformer. When not required, configure input to "GRP-OFF". Recommendation for Binary input signals M13052-17 v7 Refer to the pre-configured configurations for details. BLOCK: The input will block the operation of the function. Can be used, for example, to block for a limited time the operation during special service conditions. Recommendation for output signals M13052-21 v8 Refer to pre-configured configurations for details. START: The start output indicates that Idiff is in the operate region of the characteristic. TRIP: The trip output is activated when all operating criteria are fulfilled. DIROK: The output is activated when the directional criteria has been fulfilled. BLK2H: The output is activated when the function is blocked due to a too high level of second harmonic. 6.2.3.2 Settings M13052-28 v12 The parameters for the restricted earth-fault protection, low impedance function REFPDIF are set via the local HMI or PCM600. 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. Operation: The operation of REFPDIF can be switched On/Off. IdMin: The setting gives the minimum operation value. The setting is in percent of the IBase value of the chosen GlobalBaseSel. The neutral current must always be larger than half of this value. A normal setting is 30% of power transformer-winding rated current for a solidly earthed winding. CTFactorPri1: A factor to allow a sensitive function also at multi-breaker arrangement where the rating in the bay is much higher than the rated current of the transformer winding. The stabilizing can then be high so an unnecessary high fault level can be required. The setting is normally 1.0 but in multi-breaker arrangement the setting shall be CT primary rating/IBase. CTFactorPri2: A factor to allow a sensitive function also at multi-breaker arrangement where the rating in the bay is much higher than the rated current of the transformer winding. The stabilizing can then be high so an unnecessary high fault level can be required. The setting is normally 1.0 but in multi-breaker arrangement the setting shall be CT primary rating/IBase. CTFactorSec1: See setting CTFactorPri1. Only difference is that CTFactorSec1 is related to W2 side. CTFactorSec2: See setting CTFactorPri2. Only difference is that CTFactorSec2 is related to W2 side. Section 6 1MRK 504 158-UEN A Differential protection 84 Application manual

IP14506-1 v6 7.1.1 Identification M14880-1 v4 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-US 50 7.1.2 Application M12911-3 v5 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. 7.1.3 Setting guidelines IP14979-1 v1 M12915-4 v8 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. 1MRK 504 158-UEN A Section 7 Current protection 85 Application manual

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. GlobalBaseSel: Selects the global base value group used by the function to define (IBase), (UBase) and (SBase). 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. IP>>MinEd2Set: Minimum settable operate phase current level in % of IBase, for IEC 61850 Ed. 2 settings. IP>>MaxEd2Set: Maximum settable operate phase current level in % of IBase, for IEC 61850 Ed. 2 settings. 7.1.3.1 Meshed network without parallel line M12915-9 v7 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 35, 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. ~ ~ ZA ZB Z L A B IED I fB Fault IEC09000022-1-en.vsd IEC09000022 V1 EN-US Figure 35: 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 36. In order to get the maximum through fault current, the minimum value for ZB and the maximum value for ZA have to be considered. Section 7 1MRK 504 158-UEN A Current protection 86 Application manual

Figure 36: 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 , ( ) ³ EQUATION78 V1 EN-US (Equation 17) 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: min 1.3 sI I ³ × EQUATION79 V3 EN-US (Equation 18) 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 37. IEC09000024-1-en.vsd ~ ~ ZA ZB Z L A B IED I F Fault IEC09000024 V1 EN-US Figure 37: Fault current: IF 100 Is IP IBase >>= × EQUATION1147 V3 EN-US (Equation 19) 1MRK 504 158-UEN A Section 7 Current protection 87 Application manual

M12915-34 v6 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 38 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 38 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. IEC09000025-1-en.vsd ~ ~ ZA ZB ZL1 A B I M Fault IED ZL2 M C Line 1 Line 2 IEC09000025 V1 EN-US Figure 38: 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 , , ( ) ³ EQUATION82 V1 EN-US (Equation 20) 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 ³1.3·Imin EQUATION83 V2 EN-US (Equation 21) 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-US (Equation 22) Section 7 1MRK 504 158-UEN A Current protection 88 Application manual

SEMOD129998-1 v7 7.2.1 Identification M14885-1 v5 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-US 51_67 7.2.2 Application M15335-3 v8 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 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 1MRK 504 158-UEN A Section 7 Current protection 89 Application manual

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 IP14982-1 v1 M12982-4 v14 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. The parameters for the directional phase overcurrent protection, four steps OC4PTOC are set via the local HMI or PCM600. The following settings can be done for OC4PTOC. GlobalBaseSel: Selects the global base value group used by the function to define (IBase), (UBase) and (SBase). 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 On or Off. AngleRCA: Protection characteristic angle set in degrees. If the angle of the fault loop current has the angle RCA, the direction to the fault is forward. AngleROA: Angle value, given in degrees, to define the angle sector of the directional function, shown in Figure 39. StartPhSel: Number of phases, with high current, required for operation. The setting possibilities are: 1 out of 3, 2 out of 3 and 3 out of 3. The default setting is 1 out of 3. IMinOpPhSel: Minimum current setting level for releasing the directional start signals in % of IB. This setting should be less than the lowest step setting. The default setting is 7% of IB. 2ndHarmStab: Operate level of 2nd harmonic current restrain set in % of the fundamental current. The setting range is 5 - 100% in steps of 1%. The default setting is 20%. Section 7 1MRK 504 158-UEN A Current protection 90 Application manual

Figure 39: 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 M12982-19 v10.1.1 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 15. Table 15: Inverse time characteristics Curve name ANSI Extremely Inverse ANSI Very Inverse ANSI Normal Inverse Table continues on next page 1MRK 504 158-UEN A Section 7 Current protection 91 Application manual

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 or RD (logarithmic) The different characteristics are described in Technical manual. Ix>: Operate phase current level for step x given in % of IB. Ix>MaxEd2Set and Ix>MinEd2Set should only be changed if remote setting of operation current level, Ix>, is used. The limits are used for decreasing the used range of the Ix> setting. If Ix> is set outside Ix>MaxEd2Set and Ix>MinEd2Set, the closest of the limits to Ix> is used by the function. If Ix>MaxEd2Set is smaller than Ix>MinEd2Set, the limits are swapped. 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 inverse time delay for step x. IMinx: Minimum operate current in % of IB for all inverse time characteristics, below which no operation takes place. 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. IxMult: Multiplier for scaling of the current setting value. If a binary input signal ENMULTx (enableMultiplier) is activated the current operation level is increased by this setting constant. Setting range: 1.0-10.0 Section 7 1MRK 504 158-UEN A Current protection 92 Application manual

Figure 40: Minimum operate current and operate time for inverse time characteristics In order to fully comply with the definition of the curve, the setting parameter txMin shall be set to a value equal to the operating time of the selected inverse curve for twenty times the set current pickup value. Note that the operate time is dependent on the selected time multiplier setting kx. ResetTypeCrvx: The reset of the delay timer can be made as shown in Table 16. Table 16: 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 Technical manual. There are some restrictions regarding the choice of the reset delay. For the definite time delay characteristics, the possible delay time setting 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. tResetx: Constant reset time delay in seconds for step x. tPCrvx, tACrvx, tBCrvx, tCCrvx: These parameters are used by the customer to create the inverse time characteristic curve. See equation 23 for the time characteristic equation. For more information, refer to Technical manual. 1MRK 504 158-UEN A Section 7 Current protection 93 Application manual

(Equation 23) tPRCrvx, tTRCrvx, tCRCrvx: These parameters are used by the customer to create the inverse reset time characteristic curve. For more information, refer to Technical manual. HarmRestrainx: Enables the block of step x from the harmonic restrain function (2nd harmonic). This function should be used when there is a risk of an unwanted trip caused by power transformer inrush currents. It can be set to Off/On. 7.2.3.2 2nd harmonic restrain M12982-91 v8 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 41. Section 7 1MRK 504 158-UEN A Current protection 94 Application manual