CSC-103 Line Protection IED Technical Application Manual CSC-103 Line Protection IED Technical Application Manual Compiled: Jin Rui Checked: Hou Changsong Standardized:Wu Shuna Inspected: Cui Chenfan Version: V1.02 Doc.Code:0SF.451.083 (E) Issued Date:2013.9 Version:V1.02 Doc. Code:0SF.451.083(E) Issued Date:2013.9 Copyright owner: Beijing Sifang Automation Co., Ltd Note: the company keeps the right to perfect the instruction. If equipment does not agree with the instruction at anywhere, please contact our company in time. We will provide you with corresponding service. ® is registered trademark of Beijing Sifang Automation Co., Ltd. We reserve all rights to this document, even in the event that a patent is issued and a different commercial proprietary right is registered. Improper use, in particular reproduction and dissemination to third parties, is not permitted. This document has been carefully checked. If the user nevertheless detects any errors, he is asked to notify us as soon as possible. The data contained in this manual is intended solely for the product description and is not to be deemed to be a statement of guaranteed properties. In the interests of our customers, we constantly seek to ensure that our products are developed to the latest technological standards as a result; it is possible that there may be some differences between the hardware/software product and this information product. Manufacturer: Beijing Sifang Automation Co., Ltd. Tel: +86-10-62961515 Fax: +86-10-62981900 Internet: http://www.sf-auto.com Add: No.9, Shangdi 4th Street, Haidian District, Beijing, P.R.C.100085 Preface Purpose of this manual This manual describes the functions, operation, installation, and placing into service of device CSC-103. In particular, one will find: Information on how to configure the device scope and a description of the device functions and setting options; Instructions for mounting and commissioning; Compilation of the technical specifications; A compilation of the most significant data for experienced users in the Appendix. Target Audience Protection engineers, commissioning engineers, personnel concerned with adjustment, checking, and service of selective protective equipment, automatic and control facilities, and personnel of electrical facilities and power plants. Applicability of this Manual This manual is valid for SIFANG Distance Protection IED CSC-103; firmware version V1.00 and higher Indication of Conformity Additional Support In case of further questions concerning IED CSC-103 system, please contact SIFANG representative. Safety information Strictly follow the company and international safety regulations. Working in a high voltage environment requires serious approch to aviod human injuries and damage to equipment Do not touch any circuitry during operation. Potentially lethal voltages and currents are present Avoid to touching the circuitry when covers are removed. The IED contains electirc circuits which can be damaged if exposed to static electricity. Lethal high voltage circuits are also exposed when covers are removed Using the isolated test pins when measuring signals in open circuitry. Potentially lethal voltages and currents are present Never connect or disconnect wire and/or connector to or from IED during normal operation. Dangerous voltages and currents are present. Operation may be interrupted and IED and measuring circuitry may be damaged Always connect the IED to protective earth regardless of the operating conditions. Operating the IED without proper earthing may damage both IED and measuring circuitry and may cause injuries in case of an accident. Do not disconnect the secondary connection of current transformer without short-circuiting the transformer’s secondary winding. Operating a current transformer with the secondary winding open will cause a high voltage that may damage the transformer and may cause injuries to humans. Do not remove the screw from a powered IED or from an IED connected to power circuitry. Potentially lethal voltages and currents are present Using the certified conductive bags to transport PCBs (modules). Handling modules with a conductive wrist strap connected to protective earth and on an antistatic surface. Electrostatic discharge may cause damage to the module due to electronic circuits are sensitive to this phenomenon Do not connect live wires to the IED, internal circuitry may be damaged When replacing modules using a conductive wrist strap connected to protective earth. Electrostatic discharge may damage the modules and IED circuitry When installing and commissioning, take care to avoid electrical shock if accessing wiring and connection IEDs Changing the setting value group will inevitably change the IEDs operation. Be careful and check regulations before making the change Contents Chapter 1 Introduction ............................................................................................................1 1 Overview ...............................................................................................................................2 2 Features................................................................................................................................3 3 Functions ..............................................................................................................................6 3.1 Protection functions...............................................................................................6 3.2 Monitoring functions ..............................................................................................7 3.3 Station communication .........................................................................................8 3.4 Remote communication ........................................................................................8 3.5 IED software tools .................................................................................................8 Chapter 2 General IED application ...................................................................................... 11 1 Display information ............................................................................................................12 1.1 LCD screen display function...............................................................................12 1.2 Analog display function ....................................................................................... 12 1.3 Report display function ....................................................................................... 12 1.4 Menu dispaly function ......................................................................................... 12 2 Report record ..................................................................................................................... 13 3 Disturbance recorder .........................................................................................................14 3.1 Introduction ..........................................................................................................14 3.2 Setting ..................................................................................................................14 4 Self supervision function ...................................................................................................16 4.1 Introduction ..........................................................................................................16 4.2 Self supervision principle .................................................................................... 16 4.3 Self supervision report ........................................................................................ 16 5 Time synchronization .........................................................................................................18 5.1 Introduction ..........................................................................................................18 5.2 Synchronization principle .................................................................................... 18 5.2.1 Synchronization from IRIG .................................................................................19 5.2.2 Synchronization via PPS or PPM.......................................................................19 5.2.3 Synchronization via SNTP ..................................................................................19 6 Setting .................................................................................................................................20 6.1 Introduction ..........................................................................................................20 6.2 Operation principle .............................................................................................. 20 7 Authorization ...................................................................................................................... 21 7.1 Introduction ..........................................................................................................21 Chapter 3 Basic protection elements ..................................................................................23 1 Startup element ..................................................................................................................24 1.1 Introduction ..........................................................................................................24 1.2 Sudden-change current startup element ........................................................... 24 1.3 Zero-sequence current startup element ............................................................ 25 1.4 Overcurrent startup element...............................................................................26 1.5 Low-voltage startup element (for weak infeed systems)..................................27 1.6 Steady state consistence loosing startup .......................................................... 27 1 2 Phase selector ................................................................................................................... 28 2.1 Introduction .......................................................................................................... 28 2.2 Sudden-change current phase selector ............................................................ 28 2.3 Symmetric component phase selector .............................................................. 29 2.4 Low-voltage phase selector................................................................................ 30 3 Directional elements .......................................................................................................... 31 3.1 Introduction .......................................................................................................... 31 3.2 Memory voltage directional element .................................................................. 31 3.3 Zero sequence component directional element ............................................... 31 3.4 Negative sequence component directional element ........................................ 32 3.5 Impedance directional elements ........................................................................ 33 4 Setting parameters ............................................................................................................ 34 4.1 Setting list ............................................................................................................ 34 4.2 Setting explanation.............................................................................................. 35 Chapter 4 Line differential protection .................................................................................. 37 5 Line differential protection ................................................................................................. 38 5.1 Introduction .......................................................................................................... 38 5.2 Protection principle.............................................................................................. 38 6 Phase-segregated current differential protection ............................................................ 39 7 Sudden-change current differential protection ................................................................ 41 8 Zero-sequence current differential protection.................................................................. 43 9 Other principle .................................................................................................................... 45 9.1 Startup element ................................................................................................... 45 9.1.1 Weak-source system startup....................................................................... 45 9.1.2 Remote beckon startup ............................................................................... 45 9.2 Capacitive current compensation ...................................................................... 46 9.3 CT saturation discrimination ............................................................................... 48 9.4 Tele-transmission binary signals ........................................................................ 49 9.5 Direct transfer trip ................................................................................................ 49 9.6 Time synchronization of Sampling ..................................................................... 49 9.7 Redundant remote communication channels ................................................... 50 9.8 Switch onto fault protection function .................................................................. 50 9.9 Logic diagram ...................................................................................................... 50 9.10 Input and output signals ..................................................................................... 52 9.11 Setting parameters .............................................................................................. 53 9.11.1 Setting list ..................................................................................................... 53 9.11.2 Setting explanation ...................................................................................... 55 9.12 Reports................................................................................................................. 58 9.13 Technical data ...................................................................................................... 60 Chapter 5 Distance protection ............................................................................................. 61 1 Distance protection ............................................................................................................ 62 1.1 Introduction .......................................................................................................... 62 1.2 Protection principle.............................................................................................. 62 1.2.1 Full scheme protection ................................................................................ 62 1.2.2 Impedance characteristic ............................................................................63 1.2.3 Extended polygonal distance protection zone characteristic ................... 64 1.2.4 Minimum operating current .........................................................................66 1.2.5 Measuring principle ...................................................................................... 66 1.2.6 Distance element direction determination ..................................................69 1.2.7 Power swing blocking ..................................................................................70 1.2.8 Phase-to-earth fault determination ............................................................. 79 1.2.9 Logic diagram ............................................................................................... 79 1.3 Input and output signals...................................................................................... 85 1.4 Setting parameters .............................................................................................. 86 1.4.1 Setting list .....................................................................................................86 1.4.2 Setting explanation ...................................................................................... 91 1.4.3 Calculation example for distance parameter settings ............................... 93 1.5 Reports ...............................................................................................................106 1.6 Technical data ...................................................................................................107 Chapter 6 Teleprotection .................................................................................................... 110 1 Teleprotection schemes for distance .............................................................................. 111 1.1 Introduction ........................................................................................................ 111 1.2 Teleprotection principle..................................................................................... 111 1.2.1 Permissive underreach transfer trip (PUTT) scheme ............................. 111 1.2.2 Permissive overreach transfer trip (POTT) scheme ................................ 112 1.2.3 Blocking scheme ........................................................................................ 113 1.2.4 Additional teleprotection logics ................................................................. 115 1.3 Input and output signals.................................................................................... 116 1.4 Setting parameters ............................................................................................ 117 1.4.1 Setting list ................................................................................................... 118 1.4.2 Setting explanation .................................................................................... 118 1.5 Reports ............................................................................................................... 119 1.6 Technical data ................................................................................................... 119 2 Teleprotection for directional earth fault protection ....................................................... 120 2.1 Introduction ........................................................................................................120 2.2 Protection principle............................................................................................ 120 2.3 Input and output signals.................................................................................... 121 2.4 Setting parameters ............................................................................................ 122 2.4.1 Setting lists .................................................................................................123 2.5 Reports ...............................................................................................................123 Chapter 7 Overcurrent protection ...................................................................................... 126 1 Overcurrent protection .....................................................................................................127 1.1 Introduction ........................................................................................................127 1.2 Protection principle............................................................................................ 127 1.2.1 Measured quantities .................................................................................. 127 1.2.2 Time characteristic ..................................................................................... 127 1.2.3 Direciton determination feature .................................................................129 1.2.4 Logic diagram ............................................................................................. 130 3 1.3 1.4 Input and output signals ................................................................................... 131 Setting parameters ............................................................................................ 132 1.4.1 Setting list ................................................................................................... 133 1.5 Reports............................................................................................................... 134 1.6 Technical data ................................................................................................... 134 Chapter 8 Earth fault protection ......................................................................................... 138 1 Directional/Non-directional earth fault portection .......................................................... 139 1.1 Introduction ........................................................................................................ 139 1.2 Protection principle............................................................................................ 139 1.2.1 Time delays characteristic ......................................................................... 140 1.2.2 Inrush restraint feature .............................................................................. 141 1.2.3 Earth fault direction determination ............................................................ 142 1.2.4 Logic diagram ............................................................................................. 144 1.3 Input and output signals ................................................................................... 146 1.4 Setting parameters ............................................................................................ 147 1.4.1 Setting lists ................................................................................................. 147 1.4.2 Setting calculation example ...................................................................... 150 1.5 Reports............................................................................................................... 150 1.6 Technical data ................................................................................................... 151 Chapter 9 Emergency/backup overcurrent and earth fault protection ............................ 154 1 Emergency/backup overcurrent protection .................................................................... 155 1.1 Introduction ........................................................................................................ 155 1.2 Protection principle............................................................................................ 155 1.2.1 Tripping time characteristic ....................................................................... 155 1.2.2 Inrush restraint feature .............................................................................. 156 1.2.3 Logic diagram ............................................................................................. 157 1.3 Input and output signals ................................................................................... 157 1.4 Setting parameters ............................................................................................ 158 1.4.1 Setting lists ................................................................................................. 158 1.5 Reports............................................................................................................... 160 1.6 Technical data ................................................................................................... 160 2 Emergency/backup earth fault protection ...................................................................... 162 2.1 Introduction ........................................................................................................ 162 2.2 Protection principle............................................................................................ 162 2.2.1 Tripping time characteristic ....................................................................... 162 2.2.2 Inrush restraint feature .............................................................................. 163 2.2.3 Logic diagram ............................................................................................. 164 2.3 Input and output signals ................................................................................... 164 2.4 Setting parameters ............................................................................................ 165 2.4.1 Setting list ................................................................................................... 165 2.5 IED report........................................................................................................... 166 2.6 Technical data ................................................................................................... 167 Chapter 10 Switch-Onto-Fault protection............................................................................ 170 1 Switch-Onto-Fault protection .......................................................................................... 171 1.1 1.2 Introduction ........................................................................................................171 Function principle .............................................................................................. 171 1.2.1 Function description ................................................................................... 171 1.2.2 Logic diagram ............................................................................................. 172 1.3 Input and output signals.................................................................................... 172 1.4 Setting parameters ............................................................................................ 174 1.4.1 Setting lists .................................................................................................174 1.4.2 Setting calculation example ......................................................................175 1.5 Reports ...............................................................................................................175 1.6 Technical data ...................................................................................................176 Chapter 11 Overload protection ........................................................................................... 178 1 Overload protection .........................................................................................................179 1.1 Protection principle............................................................................................ 179 1.1.1 Function description ................................................................................... 179 1.1.2 Logic diagram ............................................................................................. 179 1.2 Input and output signals.................................................................................... 179 1.3 Setting parameters ............................................................................................ 180 1.3.1 Setting lists .................................................................................................180 1.4 Reports ...............................................................................................................180 Chapter 12 Overvoltage protection ...................................................................................... 182 1 Overvoltage protection ....................................................................................................183 1.1 Introduction ........................................................................................................183 1.2 Protection principle............................................................................................ 183 1.2.1 Phase to phase overvoltage protection .................................................... 183 1.2.2 Phase to earth overvlotage protection ..................................................... 184 1.2.3 Logic diagram ............................................................................................. 184 1.3 Input and output signals.................................................................................... 184 1.4 Setting parameters ............................................................................................ 185 1.4.1 Setting lists .................................................................................................186 1.5 Reports ...............................................................................................................186 1.6 Technical data ...................................................................................................187 Chapter 13 Undervoltage protection.................................................................................... 188 1 Undervoltage protection ..................................................................................................189 1.1 Introduction ........................................................................................................189 1.2 Protection principle............................................................................................ 189 1.2.1 Phase to phase underovltage protection ................................................. 189 1.2.2 Phase to earth undervoltage protection ................................................... 190 1.2.3 Depending on the VT location ...................................................................190 1.2.4 Logic diagram ............................................................................................. 191 1.3 Input and output signals.................................................................................... 192 1.4 Setting parameters ............................................................................................ 194 1.4.1 Setting lists .................................................................................................194 1.5 Reports ...............................................................................................................195 1.6 Technical data ...................................................................................................195 5 Chapter 14 Circuit breaker failure protection ...................................................................... 198 1 Circuit breaker failure protection..................................................................................... 199 1.1 Introduction ........................................................................................................ 199 1.2 Function Description ......................................................................................... 200 1.2.1 Current criterion evaluation ....................................................................... 201 1.2.2 Circuit breaker auxiliary contact evaluation ............................................. 202 1.2.3 Logic diagram ............................................................................................. 203 1.3 Input and output signals ................................................................................... 207 1.4 Setting parameters ............................................................................................ 208 1.4.1 Setting lists ................................................................................................. 208 1.5 Reports............................................................................................................... 209 1.6 Technical data ................................................................................................... 210 Chapter 15 Dead zone protection ........................................................................................ 212 1 Dead zone protection ...................................................................................................... 213 1.1 Introduction ........................................................................................................ 213 1.2 Protection principle............................................................................................ 213 1.2.1 Function description................................................................................... 214 1.2.2 Logic diagram ............................................................................................. 214 1.3 Input and output signals ................................................................................... 215 1.4 Setting parameters ............................................................................................ 216 1.4.1 Setting lists ................................................................................................. 216 1.5 Reports............................................................................................................... 217 1.6 Technical data ................................................................................................... 217 Chapter 16 STUB protection ................................................................................................ 218 1 STUB protection............................................................................................................... 219 1.1 Introduction ........................................................................................................ 219 1.2 Protection principle............................................................................................ 219 1.2.1 Function description................................................................................... 219 1.2.2 Logic diagram ............................................................................................. 220 1.3 Input and output signals ................................................................................... 220 1.4 Setting parameters ............................................................................................ 221 1.4.1 Setting lists ................................................................................................. 221 1.5 Reports............................................................................................................... 222 1.6 Technical data ................................................................................................... 222 Chapter 17 Poles discordance protection ........................................................................... 224 1 Poles discordance protection .......................................................................................... 225 1.1 Introdcution ........................................................................................................ 225 1.2 Protection principle............................................................................................ 225 1.2.1 Function description................................................................................... 225 1.2.2 Logic diagram ............................................................................................. 226 1.3 Input and output signals ................................................................................... 226 1.4 Setting parameters ............................................................................................ 228 1.4.1 Setting lists ................................................................................................. 228 1.5 Reports............................................................................................................... 228 1.6 Technical data ...................................................................................................229 Chapter 18 Synchro-check and energizing check function ...............................................230 1 Synchro-check and energizing check function .............................................................. 231 1.1 Introduction ........................................................................................................231 1.2 Function principle .............................................................................................. 231 1.2.1 Synchro-check mode ................................................................................. 231 1.2.2 Energizing ckeck mode .............................................................................232 1.2.3 Override mode............................................................................................ 233 1.2.4 Logic diagram ............................................................................................. 233 1.3 Input and output signals.................................................................................... 234 1.4 Setting parameters ............................................................................................ 235 1.4.1 Setting lists .................................................................................................235 1.4.2 Setting explanation .................................................................................... 236 1.5 Reports ...............................................................................................................236 1.6 Technical data ...................................................................................................237 Chapter 19 Auto-reclosing function ..................................................................................... 240 1 Auto-reclosing .................................................................................................................. 241 1.1 Introduction ........................................................................................................241 1.2 Function principle .............................................................................................. 241 1.2.1 Single-shot reclosing ................................................................................. 241 1.2.2 Multi-shot reclosing .................................................................................... 243 1.2.3 Auto-reclosing operation mode .................................................................245 1.2.4 Auto-reclosing initiation .............................................................................246 1.2.5 Cooperating with external protection IED ................................................247 1.2.6 Auto-reclosing logic.................................................................................... 248 1.2.7 AR blocked conditions ...............................................................................250 1.2.8 Logic diagram ............................................................................................. 251 1.3 Input and output signals.................................................................................... 254 1.4 Setting parameters ............................................................................................ 255 1.4.1 Setting lists .................................................................................................255 1.5 Reports ...............................................................................................................257 1.6 Technical data ...................................................................................................258 Chapter 20 Secondary system supervision ........................................................................260 1 Current circuit supervision............................................................................................... 261 1.1 Introduction ........................................................................................................261 1.2 Function diagram............................................................................................... 261 1.3 Input and output signals.................................................................................... 261 1.4 Setting parameters ............................................................................................ 262 1.4.1 Setting lists .................................................................................................262 1.4.2 Setting explanation .................................................................................... 262 1.5 Reports ...............................................................................................................262 2 Fuse failure supervision ..................................................................................................263 2.1 Introduction ........................................................................................................263 2.2 Function principle .............................................................................................. 263 7 2.2.1 Three phases (symmetrical) VT Fail ........................................................ 263 2.2.2 Single/two phases (asymmetrical) VT Fail............................................... 264 2.2.3 Logic diagram ............................................................................................. 264 2.3 Input and output signals ................................................................................... 265 2.4 Setting parameters ............................................................................................ 266 2.4.1 Setting list ................................................................................................... 266 2.5 Technical data ................................................................................................... 267 Chapter 21 Monitoring .......................................................................................................... 270 1 Check Phase-sequence for voltage and current ........................................................... 271 1.1 Introduction ........................................................................................................ 271 2 Check 3I0 polarity ............................................................................................................ 271 2.1 Introduction ........................................................................................................ 271 3 Check the third harmonic of voltage ............................................................................... 271 3.1 Introduction ........................................................................................................ 271 4 Check auxiliary contact of circuit breaker ...................................................................... 271 4.1 Introduction ........................................................................................................ 271 5 Broken conductor............................................................................................................. 272 5.1 Introduction ........................................................................................................ 272 5.1.1 Logic diagram ............................................................................................. 272 5.2 Input and output signals ................................................................................... 272 5.3 Setting parameters ............................................................................................ 273 5.3.1 Setting list ................................................................................................... 273 5.4 Reports............................................................................................................... 274 6 Fault locator...................................................................................................................... 275 6.1 Introduction ........................................................................................................ 275 Chapter 22 Station communication...................................................................................... 278 1 Overview........................................................................................................................... 279 2 Protocol............................................................................................................................. 279 2.1 IEC61850-8 communication protocol .............................................................. 279 2.2 IEC60870-5-103 communication protocol....................................................... 279 3 Communication port ........................................................................................................ 280 3.1 Front communication port ................................................................................. 280 3.2 RS485 communication ports ............................................................................ 280 3.3 Ethernet communication ports ......................................................................... 280 4 Typical communication scheme...................................................................................... 280 4.1 Typical substation communication scheme .................................................... 280 4.2 Typical time synchronizing scheme ................................................................. 281 5 Technical data .................................................................................................................. 282 5.1 Front communication port ................................................................................. 282 5.2 RS485 communication port .............................................................................. 282 5.3 Ethernet communication port ........................................................................... 282 5.4 Time synchronization ........................................................................................ 283 Chapter 23 Remote communication .................................................................................... 284 1 Binary signal transfer ....................................................................................................... 285 2 Remote communication channel .................................................................................... 285 2.1 Introduction ........................................................................................................285 3 Technical data .................................................................................................................. 287 3.1 Fiber optic communication ports ......................................................................287 Chapter 24 Hardware............................................................................................................290 1 Introduction ....................................................................................................................... 291 1.1 IED structure ......................................................................................................291 1.2 IED appearance.................................................................................................291 1.3 IED module arrangement ................................................................................. 292 1.4 The rear view of the protection IED .................................................................292 2 Local human-machine interface ..................................................................................... 293 2.1 Human machine interface................................................................................. 293 2.2 LCD .................................................................................................................... 294 2.3 Keypad ...............................................................................................................294 2.4 Shortcut keys and functional keys ...................................................................295 2.5 LED..................................................................................................................... 296 2.6 Front communication port ................................................................................. 297 3 Analog input module ........................................................................................................298 3.1 Introduction ........................................................................................................298 3.2 Terminals of Analogue Input Module (AIM) .................................................... 298 3.3 Technical data ...................................................................................................299 3.3.1 Internal current transformer.......................................................................299 3.3.2 Internal voltage transformer ......................................................................300 4 CPU module ..................................................................................................................... 301 4.1 Introduction ........................................................................................................301 4.2 Communication ports of CPU module (CPU) ................................................. 301 5 Communication module...................................................................................................303 5.1 Introduction ........................................................................................................303 5.2 Substaion communication port .........................................................................303 5.2.1 RS232 communication ports .....................................................................303 5.2.2 RS485 communication ports .....................................................................303 5.2.3 Ethernet communication ports ..................................................................303 5.2.4 Time synchronization port .........................................................................304 5.3 Terminals of Communication Module .............................................................. 304 5.4 Operating reports .............................................................................................. 305 5.5 Technical data ...................................................................................................305 5.5.1 Front communication port..........................................................................305 5.5.2 RS485 communication port .......................................................................306 5.5.3 Ethernet communication port ....................................................................306 5.5.4 Time synchronization ................................................................................. 307 6 Binary input module .........................................................................................................308 6.1 Introduction ........................................................................................................308 6.2 Terminals of Binary Input Module (BIM) .......................................................... 308 6.3 Technical data ...................................................................................................310 9 7 Binary output module....................................................................................................... 311 7.1 Introduction ........................................................................................................ 311 7.2 Terminals of Binary Output Module (BOM) ..................................................... 311 7.2.1 Binary Output Module A ............................................................................ 311 7.2.2 Binary Output Module C ............................................................................ 314 7.3 Technical data ................................................................................................... 315 8 Power supply module ...................................................................................................... 317 8.1 Introduction ........................................................................................................ 317 8.2 Terminals of Power Supply Module (PSM) ..................................................... 317 8.3 Technical data ................................................................................................... 319 9 Techinical data ................................................................................................................. 320 9.1 Basic data .......................................................................................................... 320 9.1.1 Frequency................................................................................................... 320 9.1.2 Internal current transformer....................................................................... 320 9.1.3 Internal voltage transformer ...................................................................... 320 9.1.4 Auxiliary voltage ......................................................................................... 321 9.1.5 Binary inputs ............................................................................................... 321 9.1.6 Binary outputs ............................................................................................ 321 9.2 Type tests .......................................................................................................... 322 9.2.1 Product safety-related tests ...................................................................... 322 9.2.2 Electromagnetic immunity tests ................................................................ 323 9.2.3 DC voltage interruption test....................................................................... 325 9.2.4 Electromagnetic emission test .................................................................. 325 9.2.5 Mechanical tests ........................................................................................ 326 9.2.6 Climatic tests .............................................................................................. 326 9.2.7 CE Certificate ............................................................................................. 327 9.3 IED design ......................................................................................................... 327 Chapter 25 Appendix ............................................................................................................ 328 1 General setting list ........................................................................................................... 329 1.1 Function setting list ........................................................................................... 329 1.2 Binary setting list ............................................................................................... 341 2 General report list ............................................................................................................ 349 3 Typical connection ........................................................................................................... 357 4 Time inverse characteristic ............................................................................................. 360 4.1 11 kinds of IEC and ANSI inverse time characteristic curves ....................... 360 4.2 User defined characteristic ............................................................................... 360 5 CT requirement ................................................................................................................ 362 5.1 Overview ............................................................................................................ 362 5.2 Current transformer classification .................................................................... 362 5.3 Abbreviations (according to IEC 60044-1, -6, as defined)............................. 363 5.4 General current transformer requirements...................................................... 364 5.4.1 Protective checking current ....................................................................... 364 5.4.2 CT class ...................................................................................................... 365 5.4.3 Accuracy class ........................................................................................... 367 5.4.4 Ratio of CT..................................................................................................367 5.4.5 Rated secondary current ...........................................................................367 5.4.6 Secondary burden...................................................................................... 367 5.5 Rated equivalent secondary e.m.f requirements ............................................368 5.5.1 Line differential protection .........................................................................368 5.5.2 Transformer differential protection ............................................................ 369 5.5.3 Busbar differential protection ....................................................................370 5.5.4 Distance protection .................................................................................... 371 5.5.5 Definite time overcurrent protection and earth fault protection ..............372 5.5.6 Inverse time overcurrent protection and earth fault protection ...............373 11 Chapter 1 Introduction Chapter 1 Introduction About this chapter This chapter gives an overview of SIFANG line Protection IED. 1 Chapter 1 Introduction 1 Overview The CSC-103 is selective, reliable and high speed comprehensive transmission line protection IED (Intelligent Electronic Device) for overhead lines, cables or combination of them, with powerful capabilities to cover following applications: Overhead lines and cables at all voltage levels Two and three-end lines All type of station arrangement, such as 1.5 breakers arrangement double bus arrangement, etc. Extremely long lines with series compensation Short lines Heavily loaded lines Satisfy the requirement for single and /or three pole tripping Communication with station automation system The IED provides line differential protection functions based on phase-segregated measurement with high sensitivity for faults and reliable phase selection. The full scheme distance protection is also provided with innovative and proven quadrilateral characteristic. Five distance zones have fully independent measuring and setting which provides high flexibility of the protection for all types of lines. Many other functions are also employed to provide a complete backup protection library. The wide application flexibility makes the IED an excellent choice for both new installations and retrofitting of the existing stations. 2 Chapter 1 Introduction 2 Features Protection and monitoring IED with extensive functional library, user configuration possibility and expandable hardware design to meet special user requirements Redundant A/D sampling channels and interlocked dual CPU modules guarantee the high security and reliability of the IED Single and/or three phase tripping/reclosing High sensitive startup elements, which enhance the IED sensitivity in all disturbance conditions and avoid mal-operation Current sudden-change startup element Zero sequence current startup element Over current startup element Undervoltage startup element for weak-infeed end of lines Three kinds of faulty phase selectors are combined to guarantee the correction of phase selection: Current sudden-change phase selector Zero sequence and negative sequence phase selector Undervoltage phase selector Four kinds of directional elements cooperate each other so as to determine the fault direction correctly and promptly: Memory voltage directional element Zero sequence component directional element Negative sequence component directional element Impedance directional element Line differential protection (87L): Phase-segregated measurement with high sensitivity Charging current compensation High reliability against external fault with CT saturation detection Automatic conversion of CT ratios Time synchronization of sampling Redundant communication channels without channel switching 3 Chapter 1 Introduction delay Full scheme phase-to-phase and phase-to-earth distance protection with five quadrilateral protection zones and additional extension zone characteristic (21, 21N) Power swing function (68) 4 Proven and reliable principle of power swing logic Unblock elements during power swing All common types of tele-protection communication scheme (85) Permissive Underreach Transfer Trip (PUTT) scheme Permissive Overreach Transfer Trip (POTT) scheme Blocking scheme Inter-tripping scheme Particular logic for tele-protection communication scheme Current reversal Weak-infeed end Evolving fault logic Sequence tripping logic Contacts and/or up to two fiber optical ports can be used for tele-protection communication scheme A complete protection functions library, include: Distance protection with quadrilateral characteristic (21,21N) Power swing function (68) Tele-protection communication scheme for distance protection (85-21,21N) Tele-protection communication scheme with dedicated earth fault protection (85-67N) Overcurrent protection (50, 51, 67) Earth fault protection (50N, 51N, 67N) Emergency/backup overcurrent protection (50, 51) Emergency/backup earth fault protection (50N, 51N) Switch-onto-fault protection (50HS) Chapter 1 Introduction Overload protection (50OL) Overvoltage protection (59) Undervoltage protection (27) Circuit breaker failure protection (50BF) Poles discordance protection (50PD) Dead zone protection (50SH-Z) STUB protection (50STUB) Synchro-check and energizing check (25) Auto-recloser function for single- and/or three-phase reclosing (79) Voltage transformer secondary circuit supervision (97FF) Current transformer secondary circuit supervision Self-supervision on all modules in the IED Complete IED information recording: tripping reports, alarm reports, startup reports and general operation reports. Any kinds of reports can be stored up to 1000 and be memorized even if power interruption occurs. Remote communication Tele-protection contacts for power line carrier protection interface Up to two fiber optical ports for remote communication applied to protection function, like tele-protection Vast range fiber internal modem, applied single–mode optical fiber cable External optical/electrical converter, which support communication through SDH or PCM, for G.703 (64kbit/s) and G.703E1 (2048kbit/s) Up to three electric /optical Ethernet ports can be selected to communicate with substation automation system by IEC61850 or IEC60870-5-103 protocols Up to two electric RS-485 ports can be selected to communicate with substation automation system by IEC60870-5-103 protocol Time synchronization via network(SNTP), pulse and IRIG-B mode Configurable LEDs (Light Emitting Diodes) and output relays satisfied users’ requirement 5 Chapter 1 Introduction Versatile human-machine interface Multifunctional software tool CSmart for setting, monitoring, fault recording analysis, configuration, etc. 3 Functions 3.1 Protection functions Description ANSI Code IEC 61850 IEC 60617 Logical Node graphical Name symbol Differential protection Line differential protection 87L PDIF Distance protection Distance protection 21, 21N PDIS Z< Power-swing function 68 RPSB Zpsb Tele-protection Communication scheme for distance protection Communication scheme for earth fault protection 85–21,21N PSCH 85–67N PSCH Current protection 3IINV> Overcurrent protection 50,51,67 PTOC 3I >> 3I >>> Earth fault protection Emergency/backup overcurrent 50N, 51N, 67N I0INV> PEFM I0>>> 50,51 PTOC 50N,51N PTOC Switch-onto-fault protection 50HS PSOF Overload protection 50OL PTOC protection Emergency/backup earth fault protection I0>> 3IINV> 3I > I0INV> I0 > 3I >HS I0>HS 3I >OL Voltage protection Overvoltage protection 6 59 PTOV 3U> 3U>> Chapter 1 Introduction Undervoltage protection 27 PTUV 3U< 3U<< Breaker control function 3I> BF Breaker failure protection 50BF RBRF I0>BF I2>BF Dead zone protection 50SH-Z STUB protection 50STUB PTOC Poles discordance protection 50PD RPLD 3I>STUB 3I< PD I0>PD I2>PD Synchro-check and energizing check 25 RSYN Auto-recloser 79 RREC Single- and/or three-pole tripping 94-1/3 PTRC O→I Secondary system supervision CT secondary circuit supervision VT secondary circuit supervision 3.2 97FF Monitoring functions Description Redundant A/D sampling data self-check Phase-sequence of voltage and current supervision 3I0 polarity supervision The third harmonic of voltage supervision Synchro-check reference voltage supervision Auxiliary contacts of circuit breaker supervision Broken conductor check Self-supervision Logicality of setting self-check Fault locator Fault recorder 7 Chapter 1 Introduction 3.3 Station communication Description Front communication port Isolated RS232 port Rear communication port 0-2 isolated electrical RS485 communication ports 0-3 Ethernet electrical/optical communication ports Time synchronization port Communication protocols IEC 61850 protocol IEC 60870-5-103 protocol 3.4 Remote communication Description Communication port Contact(s) interface for power line carrier 0– 2 fiber optical communication port(s) Communication distance Up to 100kM Connection mode Direction fiber cable connection Digital communication network through converter 3.5 IED software tools Functions Reading measuring value Reading IED report Setting 8 Chapter 1 Introduction Functions IED testing Disturbance recording analysis IED configuration Printing 9 Chapter 1 Introduction 10 Chapter 2 General IED application Chapter 2 General IED application About this chapter This chapter describes the use of the included software functions in the IED. The chapter discusses general application possibilities. 11 Chapter 2 General IED application 1 Display information 1.1 LCD screen display function The LCD screen displays measured analog, report ouputs and menu. 1.2 Analog display function The analog display includes measured Ia, Ib, Ic, 3I0, IN, Ua, Ub, Uc, UX 1.3 Report display function The report display includes tripping, alarm and operation recording. 1.4 Menu dispaly function The menu dispaly includes main menu and debugging menu, see Chapter 24 for detail. 12 Chapter 2 General IED application 2 Report record The report record includes tripping, alarm and operation reports. See Chapter 25 for detail. 13 Chapter 2 General IED application 3 Disturbance recorder 3.1 Introduction To get fast, complete and reliable information about fault current, voltage, binary signal and other disturbances in the power system is very important. This is accomplished by the disturbance recorder function and facilitates a better understanding of the behavior of the power system and related primary and secondary equipment during and after a disturbance. An analysis of the recorded data provides valuable information that can be used to explain a disturbance, basis for change of IED setting plan, improvement of existing equipment etc. The disturbance recorder, always included in the IED, acquires sampled data from measured analogue quantities, calculated analogue quantity, binary input and output signals. The function is characterized by great flexibility and is not dependent on the operation of protection functions. It can even record disturbances not tripped by protection functions. The disturbance recorder information is saved for each of the recorded disturbances in the IED and the user may use the local human machine interface or dedicated tool to get some general information about the recordings. The disturbance recording information is included in the disturbance recorder files. The information is also available on a station bus according to IEC 61850 and IEC 60870-5-103. Fault wave recorder with great capacity, can record full process of any fault, and can save the corresponding records. Optional data format or wave format is provided, and can be exported through serial port or Ethernet port by COMTRADE format. 3.2 Setting Abbr. T_Pre Fault 14 Explanation Time setting for recording time before fault occurred Default Unit Min. Max. 0.05 s 0.05 0.3 Chapter 2 General IED application Abbr. T_Post Fault Explanation Time setting for recording time after fault occurred Default Unit Min. Max. 1 s 0.50 4.50 0 1 Sample rate for fault recording DR_Sample Rate (0: 600 sample/cycle, 1:1200 0 sample/cycle) 15 Chapter 2 General IED application 4 Self supervision function 4.1 Introduction The IED may test all hardware components itself, including loop out of the relay coil. Watch can find whether or not the IED is in fault through warning LED and warning characters which show in liquid crystal display and display reports to tell fault type. The method of fault elimination is replacing fault board or eliminating external fault. 4.2 4.3 Self supervision principle Measuring the resistance between analog circuits and ground Measuring the output voltage in every class Checking the zero drift and scale Verifying alarm circuit Verifying binary input Checking actual live tripping including circuit breaker Checking the setting values and parameters Self supervision report Table 1 Self supervision report Abbr.(LCD Display) Description Sample Err AI sampling data error Soft Version Err Soft Version error EquipPara Err Equipment parameter error ROM Verify Err CRC verification for ROM error Setting Err Setting value error 16 Chapter 2 General IED application Abbr.(LCD Display) Description Set Group Err Pointer of setting group error BO No Response Binary output (BO) no response BO Breakdown Binary output (BO) breakdown SRAM Check Err SRAM check error FLASH Check Err FLASH check error BI Config Err BI configuration error BO Config Err BO configuration error BI Comm Fail BI communication error BO Comm Fail BO communication error Test BO Un_reset Test BO unreset BI Breakdown BI breakdown DI Input Err BI input error NO/NC Discord NO/NC discordance BI Check Err BI check error BI EEPROM Err BI EEPROM error BO EEPROM Err BO EEPROM error Sys Config Err System Configuration Error Battery Off Battery Off Meas Freq Alarm Measurement Frequency Alarm Not Used Not used Trip Fail Trip fail PhA CB Open Err PhaseA CB position BI error PhB CB Open Err PhaseB CB position BI error PhC CB Open Err PhaseC CB position BI error 3Ph Seq Err Three phase sequence error AI Channel Err AI channel error 3I0 Reverse 3I0 reverse 3I0 Imbalance 3I0 imbalance 17 Chapter 2 General IED application 5 Time synchronization 5.1 Introduction Use the time synchronization source selector to select a common source of absolute time for the IED when it is a part of a protection system. This makes comparison of events and disturbance data between all IEDs in a SA system possible. 5.2 Synchronization principle Time definitions The error of a clock is the difference between the actual time of the clock, and the time the clock is intended to have. The rate accuracy of a clock is normally called the clock accuracy and means how much the error increases, i.e. how much the clock gains or loses time. A disciplined clock is a clock that “knows” its own faults and tries to compensate for them, i.e. a trained clock. Synchronization principle From a general point of view synchronization can be seen as a hierarchical structure. A module is synchronized from a higher level and provides synchronization to lower levels. 18 Chapter 2 General IED application A module is said to be synchronized when it periodically receives synchronization messages from a higher level. As the level decreases, the accuracy of the synchronization decreases as well. A module can have several potential sources of synchronization, with different maximum errors, which gives the module the possibility to choose the source with the best quality, and to adjust its internal clock from this source. The maximum error of a clock can be defined as a function of: 5.2.1 The maximum error of the last used synchronization message The time since the last used synchronization message The rate accuracy of the internal clock in the module. Synchronization from IRIG The built in GPS clock module receives and decodes time information from the global positioning system. The module is located on the Communication Module (MASTER). The GPS interfaces to the IED supply two possible synchronization methods, IRIGB and PPS (or PPM). 5.2.2 Synchronization via PPS or PPM The IED accepts PPS or PPM to the GPS interfaces on the Communication Module. These pulses can be generated from e.g. station master clock. If the station master clock is not synchronized from a world wide source, time will be a relative time valid for the substation. Both positive and negative edges on the signal can be accepted. This signal is also considered as a fine signal. 5.2.3 Synchronization via SNTP SNTP provides a “Ping-Pong” method of synchronization. A message is sent from an IED to an SNTP-server, and the SNTP-server returns the message after filling in a reception time and a transmission time. SNTP operates via the normal Ethernet network that connects IEDs together in an IEC61850 network. For SNTP to operate properly, there must be a SNTP-server present, preferably in the same station. The SNTP synchronization provides an accuracy that will give 1ms accuracy for binary inputs. The IED itself can be set as a SNTP-time server. 19 Chapter 2 General IED application 6 Setting 6.1 Introduction Settings are divided into separate lists according to different functions. The printed setting sheet consists of two parts -setting list and communication parameters. 6.2 Operation principle The setting procedure can be ended at the time by the key “SET” or “QUIT”. If the key “SET” is pressed, the display shows the question “choose setting zone”. The range of setting zone is from 1 to 16. After confirming with the setting zone-key “SET”, those new settings will be valid. If key “QUIT” is pressed instead, all modification which have been changed will be ignored. 20 Chapter 2 General IED application 7 Authorization 7.1 Introduction To safeguard the interests of our customers, both the IED and the tools that are accessing the IED are protected, subject of authorization handling. The concept of authorization, as it is implemented in the IED and the associated tools is based on the following facts: There are two types of points of access to the IED: local, through the local HMI remote, through the communication ports There are different levels (or types) of guest, super user and protection engineer that can access or operate different areas of the IED and tools functionality. 21 Chapter 2 General IED application 22 Chapter 3 Basic protection elements Chapter 3 Basic protection elements About this chapter This chapter describes basic protection elements including startup elements, phase selectors and directional elements. 23 Chapter 3 Basic protection elements 1 Startup element 1.1 Introduction Startup elements are designed to detect a faulty condition in the power system and initiate all necessary procedures for selective clearance of the fault, e.g. determination of the faulted loop(s), delaying time starting for different functions. IED startup can release DC power supply for binary output contacts. Once startup element operates, it does not reset until all abnormal conditions have reset. Startup element includes: 1.2 Current sudden-change startup element(abrupt current) Zero-sequence current startup element Over current startup element Low-voltage startup element in weak-source steady state consistence loosing startup Sudden-change current startup element Sudden-change current startup element is the main startup element that can sensitively detect most of faults. Its criteria are as followings: i I _ abrupt or 3i0 I _ abrupt Equation 1 where 24 Chapter 3 Basic protection elements Δi is the sudden-change value of phase current sample means AB,BC or CA, e.g. iAB= iA-iB Δ3i0 is sudden-change value of zero sequence current sample I_abrupt is the setting value of sudden-change current startup element. The sudden-change current startup operates when any phase-to-phase current sudden-change Δi or zero-sequence sudden-change current Δ3i0 continuously exceed the setting I_abrupt. 1.3 Zero-sequence current startup element In addition to current sudden-change startup element, zero-sequence current element has also been considered to improve required sensitivity of the fault detection at faults with high resistance. As an auxiliary startup element, it operates with a short time delay. Its criterion is as following: 3I0 > k×I0dz Equation 2 Where 3I0 is the trippled value of zero-sequence current k is internal coefficient I0dz is Min{3I0_Tele EF, 3I0_EF1, 3I0_EF2, 3I0_EF Inv, 3I0_Em/BU EF, 3I0_Inv_Em/BU EF, 3I0_SOTF} 3I0_Tele EF is setting value of teleprotection based on earth fault protection 3I0_EF1 is the setting value of definite time stage 1 of the earth fault protection 3I0_EF2 is the setting value of definite time stage 2 of the earth fault protection 3I0_EF Inv is the setting value of inverse time stage of the earth fault protection 25 Chapter 3 Basic protection elements 3I0_Em/BU EF is the setting value of emergency/backup earth fault protection 3I0_Inv_Em/BU EF is the setting value of emergency/backup earth fault protection 1.4 3I0_SOTF is the zero-sequence current setting of SOTF protection Overcurrent startup element If overcurrent protection function is enabled, over current startup element is also considered to improve fault detection sensitivity. Same as zero sequence current startup and to get reliable action, overcurrent startup operates with 30ms delay as an auxiliary startup element. Its criteria are as follows: Ia > k×Ioc or Ib > k×Ioc or Ic > k×Ioc Equation 3 where Ia(b,c) is measured phase currents k is internal coefficient Ioc is min{ I_OC1, I_OC2, I_OC Inv, I_Em/BU OC, I_Inv_Em/BU OC, I_STUB, I_SOTF } I_OC1 is the setting value of definite time stage 1 of the overcurrent protection function. I_OC2 is the setting value of definite time stage 2 of the overcurrent protection function. I_OC Inv is the setting value of inverse time stage of the overcurrent protection function. I_Em/BU OC is the setting value of emergency/backup overcurrent protection 26 Chapter 3 Basic protection elements I_Inv_Em/BU OC is the setting value for inverse time stage of emergency/backup overcurrent protection 1.5 I_STUB is the setting value of STUB protection I_SOTF is the setting value of SOTF protection Low-voltage startup element (for weak infeed systems) In conditions that one end of the protected line has a weak-source and accordingly the fault sudden-change phase to phase current is too low to startup the IED, low-voltage startup element can come into service to startup the tele-protection communication scheme with weak-echo logic. When IED receives signaIs from another side, its operation criteria are as follows: Upe < k×Upe_Secondary or Upp < k×Upp_Secondary Equation 4 where: 1.6 Upe is each phase-to-earth voltage Upp is each phase-to-phase volatge. k is internal coefficient U_Secondary is the system secondary rated voltage Steady state consistence loosing startup The operation criteria of steady state consistance loosing startup are (OR logic) as followings: Ia > I_PSB, Ib > I_PSB, Ic > I_PSB, and the sudden-change current 27 Chapter 3 Basic protection elements startup element hasn't operated All the phase-to-phase impedance of AB, BC and CA are located in zone 3 area, and the sudden-change current startup element hasn't operated If any of the conditions has continued for 30ms, steady state consistence loosing startup will operated. 2 Phase selector 2.1 Introduction To efficiently detect faulty phase(s), An integrated phase selector is used for various fault types. By processing on the currents and voltages values, IED detects whether a fault is single-phase or multiple-phase. Therefore, selected phase(s) is (are) used to issue phase selective trip command. Three types of phase selector are designed: Sudden-change current phase selector Fault current symmetric component (zero and negative sequence) phase selector Low voltage phase selector Current sudden-change phase selector routine operates immediately after sudden-change current startup. In addition, symmetric component phase selector is implemented. However, both current sudden-change phase and symmetric component phase selector are not applicable for weak-infeed sides. Therefore, low-voltage phase selector is employed in this condition. 2.2 Sudden-change current phase selector Current Sudden-change phase selector employs phase-to-phase differential currents IAB, IBC and ICA (IXY=IX-IY). Faulty phases can be determined by comparing the values of these differential current toward each other. Table 2 shows the relative value of the phase-to-phase differential current IAB, IBC and ICA at the various fault types. In this table “+” means 28 Chapter 3 Basic protection elements the larger value,“++” the largest one,and “-” indicates the small one. Therefore after any current sudden-change startup, the value of IAB, IBC and ICA are sorted into three categories mentioned above. Accordingly, 7 categories, each of them indicates one type of fault, may happen. For example, if the values of IAB and ICA are large while IBC is small (with regard to each other), IED will select fault type as phase A fault. Nevertheless, if IAB is very large, while IBC and ICA are small at the same time, IED will determine fault type as AB. Table 2 Current sudden-change phase selection scheme Phase Selected A B C AB BC CA ABC IAB + + — ++ + + ++ IBC — + + + ++ + ++ ICA + — + + + ++ ++ I 2.3 Symmetric component phase selector As mentioned before, IED additionally applys symmetric component phase selector. This method mainly uses the angle between zero and negative sequence components of the fault current. It also confirms the seleted phases by calculating phase-phase impedances. Theoretical analysis has demonstrated that the angle betweenzero and negative sequence current components ( I 2 I 0 ) can be usded to select faulty phases. This concept has been shown in Figure 1 and Table 3. I0a +30 0 AN,BCN ABN +90 0 -30 BCN 0 0 -90 CN,ABN BN,CAN 0 +150 CAN 0 -150 . Figure 1 relation between angle of zero and negative sequence component for various 29 Chapter 3 Basic protection elements fault types Table 3 Symmetric component phase selector scheme mode Angle range Selected fault type 1 +30° to -30° A→G or BC→G 2 +90° to +30° AB→G 3 +150° to +90° C→G or AB→G 4 -150° to +150° CA→G 5 -90° to -150° B→G or CA→G 6 -30° to -90° BC→G For example, if the angle between I2 and I0 is in the range of -30°to +30° the fault type may be A-phase to ground or BC-phases to ground. As indicated inTable 3, areas 2, 4 and 6 directly determines related fault type, but areas 1, 3 and 5 indicate that two type of fault may happen. In this case, the two fault types can be differentiated by phase-to-phase impedance calculation. If the impedance is larger than specified value, then phase-to-phase fault is impossible and single-phase to ground fault will be confirmed. Otherwise phase-to-phase fault will be selected. 2.4 Low-voltage phase selector In the case of weak-infeed source, two previous phase selector cannot operate reliablly. Therefore low-voltage phase selector has been considered in the weak-infeed sides. In this case the IED will monitor VT Fail condition. When there is no problem with VT and IED receives signaIs from another side, low-voltage phase selector can operate according to the following criteria: Upe < k×Upe_Secondary or Upp < k×Upp_Secondary Equation 5 where: 30 Chapter 3 Basic protection elements Upe and Upp are phase-to-earth and phase-to-phase volatges, respectively. U_Secondary is the system secondary rated voltage k is the internal coefficient 3 Directional elements 3.1 Introduction Four kinds of directional elements are employed for reliable determination of various faults direction. The related protection modules, such as distance protection, tele-protection, overcurrent and earth fault protections, utilize the output of the directional elements as one of their operating condition. All the following directional elements will cooperate with the above protection functions. 3.2 Memory voltage directional element The IED uses the memory voltage and fault current to determine the direction of the fault. Therefore, transient voltage of short circuit conditions won’t influence the direction detection. Additionally, it improves the direction detection sensitivity for symmetrical or asymmetrical close-in faults with extremely low voltage. But it should be noted that the memory voltage cannot be effective for a long time. Therefore, the following directional elements will work as supplement to detect direction correctly. 3.3 Zero sequence component directional element Zero-sequence directional element has efficient features in the solidly grounded system. The directional characteristic only relates to zero sequence impedance angle of the zero sequence network of power system, regardless of the quantity of load current and/or fault resistance throughout the fault. The characteristic of the zero sequence directional is illustrated in Figure 2. 31 Chapter 3 Basic protection elements 3I 0 90° 0° 3U 0_Ref Angle_EF Angle_Range EF Forward -3 I 0 Bisector Figure 2 Characteristic of zero sequence directional element where: Angle_EF: The settable characteristic angle Angle_Range EF: 80º The angle of direction characteristic can be adjusted by Angle_EF setting value to comply with different system condition. Fault direction is detected as forward if -3i0 phasor is in shaded area of Figure 2. 3.4 Negative sequence component directional element Negative sequence directional element can make an accurate direction discrimination in any asymmetric fault. The directional characteristic only relates to negative sequence impedance angle of the negative sequence network of power system, regardless the quantity of load current and/or fault resistance throughout the fault. The characteristic of the negative sequence directional element is illustrated in Figure 3. 32 Chapter 3 Basic protection elements 3I2 90° 0° 3 U 2_ Ref Angle_Neg Angle_Range Neg Forward -3 I 2 Bisector Figure 3 Characteristic of negative sequence directional element where: Angle_Neg: The settable characteristic angle Angle_Range Neg: 80º The angle of direction characteristic can be adjusted by Angle_Neg setting value to comply with different system condition. Fault direction is detected as forward if -3i2 phasor is in shaded area of Figure 3. 3.5 Impedance directional elements The characteristic of the impedance directional element (shown in Figure 4) is the same with the characteristic of distance protection. 33 Chapter 3 Basic protection elements X_Set X Forward -n∙R_Set R_Set R Reverse -n∙X_Set Figure 4 Impedance direction detectioncharacteristic element where: R_SET: The resistance setting value of relevant zone of distance protection X_SET: The reactance setting of relevant zone of distance protection n: Multiplier for reverse directional element, which makes the reverse directional element more sensitive than forward one. For distance protection, n should be selected as 1; for teleprotection, n should be selected as 1.25; 4 Setting parameters 4.1 Setting list Table 4 Basic protection element setting list Setting Unit Min. Max. (Ir:5A/1A) (Ir:5A/1A) 0.08Ir 20Ir Default setting Description (Ir:5A/1A) Sudden-change I_abrupt A 0.2Ir current threshold of startup element T_Relay Reset s 0.5 10 1 U_Primary kV 30 800 230 U_Secondary V 100 120 100 34 The reset time of relay Rated primary voltage (phase to phase) Rated secondary Chapter 3 Basic protection elements Setting Unit Min. Max. (Ir:5A/1A) (Ir:5A/1A) Default setting Description (Ir:5A/1A) voltage (phase to phase) CT_Primary kA 0.05 5 3 CT_Secondary A 1 5 1 4.2 Rated primary current Rated secondary current Setting explanation The setting values are all secondary values if there is no special note. Impedance setting is set according to impedance of line. In this manual, wherever zero-sequence current is refered, the meaning is 3I0. 1) I_abrupt:0.2In is commonly recommended. In general, the primary value of settings “I_abrupt” and I_PS” must be consistent in both sides of the protected line. However, if the difference between the sensitivity angles (of the too sides) is too large, the settings of two sides may also be different. 2) “I_PSB”:shoule be set more than maximum load current. Primary rated voltage:Is set according to the actual rated primary voltage of VT in kV.. 3) 4) Primary rated current: Is set according to the rated primary current in kA. 5) Secondary rated current: Can be set to 1A or 5A. 6) Secondary rated voltage: Can be set to 100V to 120V. 35 Chapter 3 Basic protection elements 36 Chapter 4 Line differential protection Chapter 4 Line differential protection About this chapter This chapter describes the protection principle, input and output signals, parameter, IED report and technical data used for line differential protection function. 37 Chapter 4 Line differential protection 5 Line differential protection 5.1 Introduction The line differential protection consists of three protection functions, phase segregated differential protection function, sudden change current differential protection function and zero sequence current differential protection function. These three functions are associated to achieve high sensitivity and reliability with capacitive charge current compensation and reliable phase selection, during various system disturbances. The precise time synchronization of sampling ensures the differential protection of both end IEDs to operate reliably. 5.2 Protection principle N M CB TA IM TA IM A、B、C CSC-103 A、B、C CSC-103 Channel IN A、B、C CB IN A、B、C Figure 5 Structure of digital current differential system In Figure 5, two IED are settled at terminals M and N, the protection is connected to communication terminal equipment with optic cables. The optical termination of the relay is fixed on its rear panel. 38 Chapter 4 Line differential protection 6 Phase-segregated current differential protection The protection provides two-slope percent differential characteristic, as shown in Figure 6. IDiff operating area K2 I_2Diff K1 I_1Diff I_1Res I_2Res IRes Figure 6 Characteristic of phase-segregated current differential protection where: IDiff: Differential currents, calculated separately in each phase IRes: Restraining currents calculated separately in each phase K1 = 0.6 K2 = 0.8 I_1Diff= 1 I_Set; I_2Diff= 3 I_Set I_1Res= 3 I_Set I_2Res= 5 I_Set 39 Chapter 4 Line differential protection I_Set= I_Diff High, the different current high setting The differential current IDiff and the restraining current IRes are calculated in the IED using the measured current flowing through both ends of the protected feeder (end M and end N), according to following formula: IDiff ( IM IMC ) ( IN INC ) I Re s ( IM IMC ) ( IN INC ) where: IMC and INC: The capacitive charging current in each phase of the protected line, which are calculated from the measured voltage in each end of the line The characteristics can be described with following formula: IDiff I _ Set at 0 IDiff 3I _ Set IDiff K1I Re s , IDiff K 2 I Re s I _ Set , at 3I _ Set 40 Chapter 4 Line differential protection 7 Sudden-change current differential protection The sudden-change current differential protection calculates the fault current only, the sudden change variable part of whole current. Without influence of load current, the protection function has high sensitivity, especially, to fault through arc resistance on heavy load line. However, for the sudden change current, the variable will fade out quickly in short time, thus, the whole current differential protection presented above is still needed to cover entire fault detection and clearance period. The protection provides two-slope percent differential characteristic shown in Figure 7. ΔIDiff operating area K2 ΔI_2Diff K1 ΔI_1Diff ΔI_1Res ΔI_2Res ΔIRes Figure 7 Characteristic of sudden-change current differential protection where: ΔIDiff : Sudden-change of differential currents ΔIRes : Sudden-change of restraining currents K1 = 0.6 K2 = 0.8 ΔI_1Diff= 1 I_Set 41 Chapter 4 Line differential protection ΔI_2Diff= 3 I_Set ΔI_1Res= 3 I_Set ΔI_2Res= 5 I_Set I_Set: I_Diff High, the different current high setting ΔIDiff and ΔIRes calculated by using the calculated change in current flowing through both ends of the protected feeder (end M and end N) in each phase, according to the following formula. IDiff IM IN I Re s IM IN ΔIM : Variable of current flowing toward the protected feeder from end M ΔIN : Variable of current flowing toward the protected feeder from end N The characteristics can be described with following formula: IDiff I _ Set at 0 IDiff 3I _ Set IDiff K1I Re s , IDiff K 2I Re s I _ Set , at IDiff 3I _ Set 42 Chapter 4 Line differential protection 8 Zero-sequence current differential protection As a complement to phase segregated differential protection, the zero sequence current differential protection is used to enhance the sensitivity on the earth fault through high arc resistance. It always clears the fault after a delay time. The protection provides one slope percent differential characteristic, as shown in Figure 8. I0Diff Operating area K I_0Diff I0Res Figure 8 Characteristic of zero-sequence current differential protection where: I0Diff: Zero sequence differential currents I0Res: Zero sequence restraining currents K=0.75 I_0Diff: I_Diff ZeroSeq, the zero sequence differential current setting The differential current I0Diff and the restraining current I0Res are calculated in the IED using the measured current flowing through both sides of the protected feeder (End M and N), according to following formula. 43 Chapter 4 Line differential protection I 0 Diff (I MA IMAC ) (I MB IMBC ) (I MC IMCC ) ( INA INAC ) ( INB INBC ) ( INC INCC ) I 0 Diff (I MA IMAC ) (I MB IMBC ) (I MC IMCC ) ( INA INAC ) ( INB INBC ) ( INC INCC ) where: IMx and INx: the measured currents of phase x flowing toward the protected object in ends M and N, respectively IMxC and INxC: the capacitive charging currents calculated for phase x in ends M and N, respectively x: represents Phase A, B or C The characteristics can be described with following formula: I 0 Diff I _ Set I 0 Diff kI 0 Re s 44 Chapter 4 Line differential protection 9 Other principle 9.1 Startup element 9.1.1 Weak-source system startup If one of the ends of the protected line is weak source or without source, the current may be very small when internal fault occurs and IED can’t be initiated. Under this circumstance, the weak-source system startup element could be started by low-voltage and differential current. If all the following conditions are satisfied, IED in weak-source end could be started after it receives startup signal from remote terminal. Thus, it will trip after sending out a permissive signal to the remote end (to let it trip). 9.1.2 Receive startup signal from remote terminal. There is at least one phase differential current larger than the operation current: IA(,B,C)_Diff> I_Diff. The corresponding phase ro earth voltage Upe is less than 36V or phase-to-phase voltage Upp less than 60V. Remote beckon startup If fault occurs in high resistance line, IED far from fault location may not be able to start as its current may be very small, even if IED near the fault location can start reliably. Under this circumstance, the remote beckon startup element could be started by differential current and sudden-change voltage. If all the following conditions are satisfied, Remote beckon startup element could be started: Receive startup signal from opposite side. Zero-sequence differential current is larger than the operation current: 3I0 > I_Diff ZeroSeq, or segregated-phase differential current is larger than the operation current:IA(,B,C)_Diff> I_Diff; Local IED: ΔUPE>8V or Δ3U0 >1V. 45 Chapter 4 Line differential protection 9.2 Capacitive current compensation Ic I M IN is calculated as actual measured charging current under normal operation(before startup). IC is taken as floating threshold after startup. The actual voltage of both terminals is used to accurately compensate charging current that is called half compensation scheme which half charging current of both terminals are compensated respectively. Figure 9 Positive equivalent circuit of line using a PI section Figure 10 Negative equivalent circuit of line using a PI section Figure 11 Zero-sequence equivalent circuit of line using a PI section Positive-, negative- and zero-sequence equivalent circuit of line using a PI 46 Chapter 4 Line differential protection section are shown as above figures. Their charging currents can be calculated as follows: Based on A-phase, each sequence charging current of terminals M are respectively as below. IMC1 UM 1 j 2 XC1 IMC 2 UM 2 j 2 XC 2 IMC 0 UM 0 j 2 XC 0 If XC1 =XC2, each phase charging current of terminals M are respectively as below. IMAC IMC1 IMC 2 IMC 0 UM 1 UM 2 UM 0 UM 0 j 2 XC1 UM 0 j 2 XC 0 UMA UM 0 UM 0 j 2 XC1 j 2 XC 0 2 IMBC * IMC1 * IMC 2 IMC 0 2 *UM 1 *UM 2 UM 0 UM 0 UM 0 j 2 XC1 j 2 XC 0 UMB UM 0 UM 0 j 2 XC1 j 2 XC 0 47 Chapter 4 Line differential protection 2 IMCC * IMC1 * IMC 2 IMC 0 2 *UM 1 *UM 2 UM 0 UM 0 UM 0 j 2 XC1 j 2 XC 0 UMC UM 0 UM 0 j 2 XC1 j 2 XC 0 In the same way, each phase charging current of terminals N are respectively as below. 9.3 INAC UNA UN 0 UN 0 j 2 XC1 j 2 XC 0 INBC UNB UN 0 UN 0 j 2 XC1 j 2 XC 0 INCC UNA UN 0 UN 0 j 2 XC1 j 2 XC 0 CT saturation discrimination Based on current waveform principle, the protection can discriminate the CT saturation condition. Once under this condition, the protection will use a new differential and restraint characteristic shown in Figure 12, to guarantee the security of the protection. 48 Chapter 4 Line differential protection IDiff Operating area K I_LDiffCT IRes Figure 12 Characteristic of phase segregated differential protection at CT saturation where: I_LDiffCT= Max (I_Diff High, I_Diff Low, 0.5 CT_Secondary) CT_Secondary: The CT secondary rated current K=0.9 9.4 Tele-transmission binary signals In the IED, two binary signals can be transmitted to the remote end of the line in the binary bits of each data frame, which are tele-transmission command 1 and tele-transmission command 2. When the remote IED receives the signals, relevant operation will be performed. 9.5 Direct transfer trip In the IED, one binary input is provided for remote trip to ensure the remote IED fast tripping when fault occurs between CT and circuit breaker, or in case of a breaker failure. It is used to transmit the trip command of dead zone protection or circuit breaker failure protection to trip the opposite end circuit breaker. 9.6 Time synchronization of Sampling The differential protection of both end IEDs can be set as master or slave 49 Chapter 4 Line differential protection mode. If one IED is set as master, the IED at the other end should be set as slave. To ensure sampling synchronization between both IEDs, the salve IED sends a frame of synchronization request to master IED. After the master IED receives the frame, it returns a frame of data including its local time. Then the slave IED can calculate both the communication delay time and the sampling time difference with the master IED. Thus, the slave IED adjusts its sampling time and the IEDs of both ends come to complete sampling synchronization. 9.7 Redundant remote communication channels The differential protection is able to receive data from the redundant remote communication channels in parallel. When one of the channels is broken, there is no time delay for primary channel switching. 9.8 Switch onto fault protection function Under either auto reclosing or manual closing process, the protection function is able to discriminate these conditions to give an instantaneous tripping once closing on permanent faulty line. 9.9 Logic diagram 3I0>I_Diff ZeroSeq No CT Fail A N D T_Diff ZeroSeq Relay trip Figure 13 Zero-sequence current differential protection Note: if the setting “Diff_Zero Init AR” is enabled, AR could be initiated by Zero-sequence current differential protection. 50 Chapter 4 Line differential protection Offside: BI_PhA CB Open Offside: BI_PhB CB Open O R Offside: BI_PhC CB Open A N D Offside:startup Offside: Func_Diff Curr On Channel OK A N D Relay startup Func_Diff Curr On A N D A N D A N D A N D IA_diff>I_Diff High A Phase CT fail A N D IA_diff>I_Diff TA Fail Block Diff CT_Fail off O R A N D IB_diff>I_Diff High B Phase CT fail A N D IB_diff>I_Diff TA Fail Block Diff CT_Fail off Relay trip O R O R A N D IC_diff>I_Diff High C Phase CT fail A N D IC_diff>I_Diff TA Fail Block Diff CT_Fail off O R A Phase CT fail B Phase CT fail C Phase CT fail Block Diff CT_Fail on O R A N D Block 3Ph Diff CT_Fail on Figure 14 Phase-segregated current differential protection logic 51 Chapter 4 Line differential protection DTT By Z2 on A N D ZONE2 forward A N D ZONE3 forward DTT By Z3 on DTT By startup General startup O R DTT By Z2 on DTT By Z3 on DTT By startup on A N D A N D Dtt singal receive Figure 15 DTT logic 9.10 Input and output signals IP1 Trip PhA IP2 Trip PhB IP3 Trip PhC UP1 Trip 3Ph UP2 Relay Block AR UP3 Curr Diff Trip Tele_Trans1 BO_DTT Tele_Trans2 Tele_Trans1 DTT Tele_Trans2 Chan_A_Test Channel A Alarm Chan_B_Test Channel B Alarm Relay Startup Relay Trip Table 5 Analog input list Signal Description IP1 Signal for current input 1 IP2 Signal for current input 2 IP3 Signal for current input 3 UP1 Signal for voltage input 1 UP2 Signal for voltage input 2 UP3 Signal for voltage input 3 52 Relay trip Chapter 4 Line differential protection Table 6 Binary input list Signal Description Tele_Trans1 Tele transmission binary input 1 Tele_Trans2 Tele transmission binary input 2 DTT DTT Chan_A_Test Channel A test Chan_B_Test Channel B test Table 7 Binary output list Signal Description Relay Startup Relay Startup Relay Trip Relay Trip Trip PhA Trip phase A Trip PhB Trip phase B Trip PhC Trip phase C Trip 3Ph Trip three phases Relay Block AR Permanent trip Curr Diff Trip Current differential protection trip BO_DTT DTT binary output Tele_Trans1 Tele transmission binary output 1 Tele_Trans2 Tele transmission binary output 2 Channel A Alarm Channel A alarm Channel B Alarm Channel B alarm 9.11 Setting parameters 9.11.1 Setting list Table 8 Line differential protection function setting list Min. No. Setting Unit I_Diff High A 0.1Ir 20Ir 0.4Ir I_Diff Low A 0.1Ir 20Ir 0.4Ir I_Diff TA Fail A 0.1Ir 20Ir 2Ir (Ir:5A/1A) Max. (Ir:5A/1A) Default setting (Ir:5A/1A) high current threshold of differential protection low current threshold of differential protection current threshold of differential protection at 53 Chapter 4 Line differential protection CT failure zero sequence current I_Diff ZeroSeq A 0.1Ir 20Ir threshold of zero 0.2Ir sequence differential protection T_Diff ZeroSeq T_DTT delay time of zero s 0.1 60 0.1 sequence differential protection s CT Factor 0 10 0.1 0.2 1 1 delay time of DTT convert factor of CT ratio positive sequence XC1 Ohm 40 9000 9000 capacitive reactance of line XC0 Ohm 40 9000 9000 X1_Reactor Ohm 90 9000 9000 zero sequence capacitive reactance of line positive sequence reactance of shunt reactor X0_Reactor Ohm Local Address Opposite Address 90 9000 9000 0 65535 00000 0 65535 0 zero sequence reactance of shunt reactor identified code of local end of line identified code of opposite end of line Table 9 Line differential protection function setting list Setting Unit Func_Diff Curr Min. Max. (Ir:5A/1A) (Ir:5A/1A) 0 1 Default setting Description (Ir:5A/1A) 1 differential protection enable(1)/disable(0) sudden change Func_Diff 0 Curr Abrupt 1 1 differential protection enable(1)/disable(0) double Dual_Channel 0 1 1 channels(1)/single channel(0) Master Mode Comp Capacitor Cur 54 0 1 1 master mode (1)/ slaver mode (0) capacitive current 0 1 0 compensation enable(1)/disable(0) Chapter 4 Line differential protection CT failure block Block Diff 0 CT_Fail 1 1 differential protection enable(1)/disable(0) Block 3Ph Diff CT_Fail CT fail block 3 0 1 0 phases(1)/ CT fail block single phase(0) AR initiated by zero Diff_Zero Init 0 AR 1 1 sequence differential protection Channel A apply Chan_A 0 Ext_Clock 1 external clock 0 enable(1)/internal clock disable(0) Channel A at 64Kb/s Chan_A 64k 0 Rate 1 0 enable(1)/2M Kb/s disable(0) Channel B apply Chan_B 0 Ext_Clock 1 0 external clock enable(1)/disable(0) Chan_B 64k 0 Rate 1 Channel B at 64Kb/s 0 enable(1)/disable(0) channel loop test Loop Test 0 1 0 mode enable(1)/disable(0) DTT By 0 Startup 1 1 DTT under startup element control DTT under Zone 2 DTT By Z2 0 1 distance element control DTT under Zone 3 DTT By Z3 0 1 distance element control 9.11.2 Setting explanation 9.11.2.1 Explanation of part setting ”I_Diff High”:For the long lines, set to be larger than 2-times capacitive current if capacitive current compensation is employed, or larger than 2.5-times capacitive current if capacitive current compensation is not enabled. For the short lines, current differential protection has higher sensitivity due to few capacitive current of line, then, this setting can be raised properly. 1) 55 Chapter 4 Line differential protection I_Diff Low”:For the long lines, set to be larger than 1.5-times capacitive current if capacitive current compensation is employed, or larger than 1.875-times capacitive current if capacitive current compensation is not enabled. It has 40ms time delay.” I_Diff ZeroSeq”: Set to avoid the maximum unbalanced current at external three-phase fault while it has enough sensitivity at internal earth fault with high resistance. It is generally believed that setting of zero-current differential protection is less than 0.1In. This setting of both terminal protections ought to be set as secondary values based on the same primary values. 2) ” I_Diff TA Fail”: Set to avoid the maximum load current during normal operation. This setting of both terminal protections ought to be set as secondary values based on the same primary values. Attention: If “Block Diff CT_Fail” is enabled, differential protection will lose selectivity when external fault occurs after TA fail. 3) ” CT Factor”: It is set to be 1 for the protection with the biggest rated primary current of CT, compensation factor of the other protections is set to be the value obtained by dividing primary rated current of local TA by the maximum primary rated current. For example, TA ratio of terminal M is 1200/1,that of terminal N is 800/5, and that of terminal T is 600/5. Compensation factor of M can be set to 1,that of N is 800/1200=0.6667,and that of T is 600/1200=0.5. 4) 5) ” XC1”,” XC0”: Set according to secondary value of line full-length. 1 XC1 NTA / NTV 2fC1 1 XC 0 NTA / NTV 2fC 0 When the capacitive current is less than 0.1In, capacitive current of compensation is needless, so the control world “Comp Capacitor Cur” set "0", and the positive- and zero-sequence capacitive reactance of line could be set as 9000. When the capacitive current exceeds 0.1In. The control world “Comp Capacitor Cur” should be set "1". Set according to secondary value of line full-length. Table 10 provide reference to capacitive reactance and capacitive current of per 100 km. When adjusting setting, TA transformation ratio and TV transformation ratio should be considered. 56 Chapter 4 Line differential protection Table 10 Compensation capacitor setting Voltage Positive-sequence Zero-sequence Capacitive grade capacitive reactance(Ω) capacitive reactance(Ω) current(A) (kV) 220 3736 5260 34 330 2860 4170 66 500 2590 3790 111 750 2242 3322 193 Secondary value calculation: Xc (100 / l ) TA ratio / TV ratio l: the line length Xc: Capacitive reactance per 100 km For example:The 220 kV line length is 130km, the TA transformation ratio is 1200/1=1200, the TV transformation ratio is 220/0.1=2200, then: ” XC1”:3736*(100/130)*1200/2200=1567Ω ” XC0”:5260*(100/130)*1200/2200=2206Ω ” X1_Reactor”, ” X0_Reactor”:Convert the capacity of shunt reactor into secondary value to set. 6) 2 X1_ Reactor NTA / NTV U / S 2 X 0 _ Re actor NTA / NTV (U / S+3XN) Where, XN is the neutral-point earthing reactance of shunt reactor. For example, a shunt reactor, rated voltage U=800kV,rated capacity S =3×100Mvar, the neutral-point earthing reactance is 500Ω, TA ratio NTA =2000/1, TV ratio NTV=750/0.1, then 2 6 XDK 1 2000 / 7500 800000 / 3 100 10 568.8 XDK 0 2000 / 7500 3 500 400 57 Chapter 4 Line differential protection If shunt reactor is not installed at one terminal of line, this setting is set to the upper limit (secondary value) : XDK1 = 9000 Ω XDK0 = 9000 Ω Each pilot protection system has one and only address identification code in the power grid. Identification code of equipment address can be set via the setting of “Local Address” and “Opposite Address”. 7) The IED sends “Local Address” together with reports to the remote when reports are transportted. Only the address code in received report equals to “Opposite Address” could the IED work normally. If the address code in received report not equal to “Opposite Address”, but equal to “Local Address”, the IED will alarm “Chan_A(B) Loop Err”. If the address code in received report neither equals to “Local Address” nor equals to “Opposite Address”, the IED will alarm “Chan_A(B) Addr Err”. To make optic self-looping test, the control bit of “Loop Test” has to be set to “1”. In normal operation, this setting should be set as “0”. 8) 9.12 Reports Table 11 Event report list Abbr. Meaning Curr Diff Trip Current differential protection trip Zero Diff Trip Zero-sequence current differential protection trip Curr Diff Evol Current differential evolvement trip DTT DTT Tele_Trans1 OPTD Tele transmission 1 operated Tele_Trans2 OPTD Tele transmission 2 operated Tele_Trans1 Drop Tele transmission 1 dropout Tele_Trans2 Drop Tele transmission 2 dropout WeakInfeed Init WeakInfeed initiated OppositeEnd Init Opposite end initiated 3Ph Diff_Curr Current for three phase differential current 3PH Res_Curr Current for three phase restraining current BI_DTT DTT binary input BI_Tele_Trans1 Tele transmission 1 binary input BI_Tele_Trans2 Tele transmission 2 binary input OppositeEnd Trip Opposite end Trip Sample No_Syn sample without synchronization 58 Chapter 4 Line differential protection Abbr. Meaning Sample Syn OK sample is synchronized successfully Channel A Data Data from channel A Channel B Data Data from channel B Curr Diff SOTF SOTF on current differential fault Table 12 Alarm report list Abbr. Meaning Local CT Fail Local CT fail Opposite CT Fail Opposite CT fail Diff_Curr Alarm Differential current exists for long period TeleSyn Mode Err Synchronizing mode error Chan_A Loop Err Channel A loop error Chan_B Loop Err Channel B loop error Chan_A Comm Err Channel A communication error Chan_B Comm Err Channel B communication error Chan_A Samp Err No sampling data for channel A Chan_B Samp Err No sampling data for channel B BI_DTT Alarm DTT binary input alarm Chan_Loop Enable Channel loop enabled Chan_A Addr Err Channel A address error Chan_B Addr Err Channel B address error ChanA_B Across Channel A and B across Opposite CommErr Opposite side communication error Func_CurDiff Err Current differential error DoubleChan Test Double channel test Table 13 Operation report list Abbr. Meaning Func_DiffCurr On Differential current protection on FuncDiffCurr Off Differential current protection off Chan_A Tele_Loop Channel A loop on Chan_A Loop Off Channel A loop off Chan_B Tele_Loop Channel B loop on Chan_B Loop Off Channel B loop off Chan_A Comm OK Channel A communication resumed Chan_B Comm OK Channel B communication resumed OppositeEnd On Opposite end on OppositeEnd Off Opposite end off 59 Chapter 4 Line differential protection 9.13 Technical data Table 14 Line differential protection technical data NOTE: Ir: CT rated secondary current, 1A or 5A; Item Differential current of Rang or Value Tolerance 0.1 Ir to 20.00 Ir ≤±3% or ±0.02Ir 0.1 Ir to 4.00 Ir ≤±3% or ±0.02Ir 0.00 to 60.00s, step 0.01s ≤±1% or +20 ms Phase segregated differential protection Sudden change differential protection Differential current of Zero sequence differential protection Time delay of Zero sequence differential protection Operating time of 25ms typically at 200% setting, and IDifferential>2IRestraint Phase segregated differential protection Sudden change differential protection 60 Chapter 5 Distance protection Chapter 5 Distance protection About this chapter This chapter describes the protection principle, input and output signals, parameter, IED report and technical data for distance protection function. 61 Chapter 5 Distance protection 1 Distance protection 1.1 Introduction Transmission line distance protection covers five full scheme protection zones in addition to one zone extension. The IED employes separated measuring element for three single-phase fault loops and three phase to phase fault loops for each individual zones. Individual settable zones in resistance and reactance component give the flexibility for useing on overhead lines and cables of different types and lengths. The independent measurement of impedance for each fault loop together with a sensitive and reliable built in phase selection makes the function suitable in applications with single phase auto-reclosing. Figure 16 illustrates the different available zone characteristics. X Zone 5 Zone 4 Zone 3 Zone 2 Zone Ext. Zone 1 R Zone 4 Reverse (optional) Zone 5 Reverse (optional) Figure 16 Distance protection zone characteristics 1.2 Protection principle 1.2.1 Full scheme protection 62 Chapter 5 Distance protection The execution of the different fault loops are of full scheme type, which means that each fault loop for phase to earth faults and phase to phase faults for forward and reverse faults are executed in parallel. Figure 17 presents an outline of the different measuring loops for the basic five, impedance-measuring zones and zone extension. L1-E L2-E L3-E L1-L2 L2-L3 L3-L1 ZONE 1 L1-E L2-E L3-E L1-L2 L2-L3 L3-L1 EXTENDED ZONE 1 L1-E L2-E L3-E L1-L2 L2-L3 L3-L1 ZONE 2 L1-E L2-E L3-E L1-L2 L2-L3 L3-L1 ZONE 3 L1-E L2-E L3-E L1-L2 L2-L3 L3-L1 ZONE 4 L1-E L2-E L3-E L1-L2 L2-L3 L3-L1 ZONE 5 Figure 17 Different measuring loops at phase-earth fault and phase-phase fault Each distance protection zone performs like one independent distance protection IED with six measuring elements. 1.2.2 Impedance characteristic The IED utilizes quadrilateral characteristic as shown in Figure 18. X X_Zset Φ_Ztop Φ_Zleft Φ_Zright R_Zset R Φ_Zbottom 63 Chapter 5 Distance protection Figure 18 Characteristics of distance protection where: R_Zset: R_ZnPP or R_ZnPE; X_Zset: X_ZnPP or X_ZnPE; R_ZnPP: Resistance reach setting for phase to phase fault. Subscript n means the number of protection zone. Subscript PP means phase to phase fault. n: value range: 1, 1Ext, 2, 3, 4, 5. R_ZnPE: Resistance reach setting for phase to earth fault. Subscript X means the number of protection zone. Subscript PE means phase to earth fault. X_ZnPP: Reactance reach setting for phase to phase fault X_ZnPE: Reactance reach setting for phase to earth fault Φ_Ztop: The upper boundary angle of the characteristic in the first quadrant is designed to avoid distance protection overreaching when a close-in fault happens on the adjacent line Φ_Zbottom: The bottom boundary angle of the characteristic in the fourth quadrant improves the reliability of the IED to operate reliably for close-in faults with arc resistance Φ_Zright: The right boundary angle of characteristic in the first quadrant is used to deal with load encroachment problems Φ_Zleft: The left boundary angle of the characteristic in the second quadrant considers the line impedance angle which generally is not larger than 90°. Thus this angle guarantees the correct operation of the IED. 1.2.3 Extended polygonal distance protection zone characteristic When a fault occurs on the piont of the protection relay installed, the 64 Chapter 5 Distance protection voltage can be zero, theoretically, at the point of the fault. Considering the VT and other errors, when the polarity of the impedance measurement does not reflect the true distance from the fault, two incorrect cases may occur: The fault is near the bus and in the forward direction but measured impedance is not within the forward quadrilateral characteristic. The fault is near the bus and in the reverse direction but measured impedance is not within the reverse quarilateral characteristic Using fault phase current and voltage only, resistance value can not accurately determine whether fault occurs in the reverse direction or the forward direction. To solve the problem, IED considers the small rectangle near to origin to extend protection zones. Therefore, to increase relay reliable operation in addition to the tripping characteristic mentioned above, an extended zone area with a little rectangular characteristic is involved. In this case, final direction is determined based on both extended zone charachterisitc and the criteria mentioned in Figure 19, including memory voltage direction element, the zero sequence directional element, and the negative sequence direction element. In other words, relay generates trip if both direction and extended zone impedance confirm each other. This rectangular area, which is called impedance-offset characteristic, has been shown in Figure 19 which is added to the characteristic shown in Figure 18. X XSet ΦTop ΦLeft XOffset ΦRight ROffset ΦBottom R RSet 65 Chapter 5 Distance protection Figure 19 Extended polygonal distance protection zone characteristic The rectangular offset characteristic (illustrated in Figure 19) is calculated automatically according to the related distance zones settings. where: X Offset :Min{ X Set/2 , 0.5(when In=5A)/2.5 (when In=1A)} R Offset: Min{ Max{ Min{ 8×XOffset , RSet/4 }, 2×XOffset } , RSet} R_ZSet: R_ZnPP or R_ZnPE X_ZSet: X_ZnPP or X_ZnPE 1.2.4 Minimum operating current The operation of the distance measuring zone is blocked if the magnitudes of input currents fall below certain threshold values. For both phase-to-earth loop and phase-to-phase loop, Ln is blocked if ILn < 0.1In ILn is the RMS value of the current in phase Ln. 1.2.5 Measuring principle A separate measuring system has been provided for each of the six possible impedance loops A-E, B-E, C-E, A-B, B-C, C-A. The impedance calculation will be continued whether a fault has been detected. Based on the following differential equations, measuring elements calculates relevant loop impedances with real-time voltages and currents. Measuring of the single phase impedance for a single phase fault is as follows: U Φ LΦ 66 d(Iφ K X 3I 0 ) R Φ (IΦ K r 3I 0 ) dt : A, B, C Chapter 5 Distance protection Equation 6 Measuring of the phase-phase impedance for multi-phase faults is as follows: UΦ LΦ dI R Φ IΦ dt : AB, BC, CA Equation 7 Where, Kx and Kr are residual compensation factors. Matching of the earth to line impedance is an essential prerequisite for the accurate measurement of the fault distance (distance protection, fault locator) during earth faults. This compensation will be done by residual compensation settings value: Kx=(X0-X1)/3X1 Equation 8 and Kr=(R0-R1)/3R1 Equation 9 Measuring resistance R and reactance X (ωL=2πfL) at IED location can be obtained by solving above differential equations. For example, solving above equations leads to the following relation for phase-phase (A-B) short circuit which can be used to calculate the phase-to-phase loop impedance. 67 Chapter 5 Distance protection Figure 20 Phase-phases (A-B) short circuit IL1 ·ZL – IL2 ·ZL = UL1-E – UL2-E Equation 10 With: U, I the (complex) measured quantities and Z = R + jX the (complex) line impedance The line impedance is computed as: ZL = U L1-E -U L2-E I L1 -I L2 Equation 11 In addition, solving differential equation for single phase (e.g. A-E) results: Figure 21 Single-phases (A-B) short circuit U L1-E =I A R L +JX L -I E ( RE X R L J E X L ) I A R L +JX L -I E (K r R L JK x X L ) RL XL Equation 12 This can be used for resistance and reactance calculation by separating it to real and imaginary parts. The impedances of the unfaulted loops are also influenced by the short-circuit currents and voltages in the short-circuited phases. For example, during an A-E fault, the short-circuit current in phase L1 also 68 Chapter 5 Distance protection appears in the measuring loops A-B and C-A. The earth current is also measured in loops B-E and C-E. In addition to the load currents which may flow, the unfaulted loops will be affected by faulted loop current which have nothing to do with the actual fault distance/impedance. Effect in the unfaulted loops is usually larger than the short-circuit impedance of the faulted loop, because the unfaulted loop only carries a part of the fault current and always has a larger voltage than the faulted loop. As mentioned before, after triggering impedance calculations by any startup element, all impedance loops will be calculated by separated (non-switch) measuring systems. First, the symmetric component phase selector chooses the influenced loops, than the IED compare the impedance of these loops to remove the unfaulted loops. 1.2.6 Distance element direction determination Considering the VT and other errors, the polarity of the measured impedance may not reflect the true distance from the fault. So, the IED judges the fault direction through using integrated directional elements. Using memory voltage to judge the direction of the distance protection is an efficient method. Therefore, IED also uses the memory voltage and fault current to determine the direction of the fault. Under normal circumstances, using memory voltage to judge the direction of the fault has merit, since the transient process has not been affected. But the memory voltage can not be a long effective quantity. Therefore, IED needs to rely on forward and reverse direction to expand the logic. IED uses the direction of zero sequence and negative sequence directional elemenst to supplement the direction of the distance protection. Zero-sequence directional element has very good features in the neutral grounding system. The directional characteristics only relates to zero sequence impedance angle of the zero sequence network of back power system which has large or small load current and/or fault resistance effects. There is no memory voltage problem, and direction can be reliably detected using zero-sequence directional element. For more detail about zero sequence direction detection refer to Earth fault protection. Negative sequence directional element has very clear direction in any asymmetric fault. The directional characteristics only relate to negative sequence impedance angle of the negative sequence network of back power system which has large or small load current and/or fault 69 Chapter 5 Distance protection resistance effects, etc. Like zero sequence, there is also no memory voltage problem, and direction can be reliably detected in this case by using negative sequence. For more detail refer the chapter earth fault protection. In summary, the distance protection has two essential conditions to operate: corresponding direction detection element is satisfied and calculated impedance is entered into the impedance characteristics zone. The usage of direction elements is different for five zone characteristics: The first zone: it is used as fast zone commonly. Since high speed and required selectivity are quite essential, requirements for the direction component must be “forward” direction. The extended first zone: it is different from the other five zones. It doesn't work until the Auto-reclosing has been fully charged. It is a back up of teleprotection. The second zone: it is used as time delay zone commonly. Considering enough reliability, its direction criterion is “not reverse” direction. The third zone: Generally, it is used as the last forward direction zone. The delay time is longer. Its direction criterion is “not reverse” direction. The fourth zone: it is used as non-forward direction zone commonly, so requirement for the direction component is “not forward” direction. The fifth zone: like zone 4, if it is used as reverse direction, its direction criterion is “not forward” direction. For three phase faults, direction checking is only determined by memory voltage. In this case, IED considers impedance characteristics as well as memory voltage determination. If there is neither a current measured voltage nor a memorized voltage available which is sufficient for measuring the direction, the IED selects the forward direction. In practice this can only occur when the circuit breaker closes onto a de-energized line, and there is a fault on this line (e.g. closing onto an earthed line). 1.2.7 70 Power swing blocking Chapter 5 Distance protection 1.2.7.1 Introduction Power swings are oscillations in power flow. The power grid is a very dynamic network that connects generation to load via transmission lines. A disturbance-such as a sudden change of load whereas the mechanical power input to generators remains relatively constant, a power system fault, or a trip of a large generation unit-may break the balance, cause the oscillations among the generator rotor angles and force the generators to adjust to a new operating condition. The adjustment will not happen instantaneously due to the inertia of the generator prime movers. Oscillation rate is determined by the inertia of the system and impedances between different generators. 1.2.7.2 Principle of operation Power swings are variations in power flow that occur when the internal voltages of generators at different locations of the power system slip relative to each other. In this way, voltage and current waveforms will have a low frequency oscillation over the power system nominal frequency. Therefore impedance trajectory seen by a distance IED may enter the fault detection zones and cause unwanted IED operation. For example consider a simple case with two machine system shown in Figure 22 to show the system behavior in power swing condition. Figure 22 Two machine system to simulate power swing behavior 1.2.7.3 Impedance trajectory The current passing through the feeder (IL) will be calculated in any time by: IL ES ER ZS ZL ZR Equation 13 The direction of current flow will remain the same during the power swing event. Only the voltage displacement will change. 71 Chapter 5 Distance protection The impedance measured at an IED at bus A would then be: Z VA ES IL.ZS ES ES.(ZS ZL ZR) ZS ZS IL IL IL ES ER Equation 14 It is assumed that that ES has a phase advance of δ over ER and that the ratio of the two source voltage magnitudes, ES/ER, is k. Then: ES k (cos j sin ) k (k cos ) j sin ES ER k (cos j sin ) 1 (k cos ) 2 sin 2 Equation 15 For the particular case where the two sources magnitudes are equal or k is one, Equation 15 can be expressed as: ES 1 (1 j cot ) ES ER 2 2 Equation 16 And finally the impedance measured at the IED will be: Z VA (ZS ZL ZR) (1 j cot ) ZS IL 2 2 Equation 17 Therefore, the trajectory of the measured impedance at the IED during a power swing varies when the angle between the two source voltages changes. Figure 23 shows the impedance trajectories for different voltage ratios between two machines. 72 Chapter 5 Distance protection Figure 23 Impedance trajectories for k values Figure 24 shows the practical possible impedance trajectory which may happen in the power system. Cases 1 and 2 indicate a stable power swing which entered the distance protection tripping zone. Case 3 is unstable power swing which enters and exits the trip zones. Case 4 also shows the impedance trajectory in the case of short circuit occurrence in the power system. Figure 24 Impedance trajectories for different power swing conditions 1.2.7.4 Power swing blocking/unblocking To ensure the correct operation of the protection logic and avoiding IED mal-operation in power swings conditions, power swing blocking function 73 Chapter 5 Distance protection has been integrated in IED. The main purpose of the PSB function is to differentiate between faults and power swings and block distance. However, faults that occur during a power swing must be detected and cleared with a high degree of selectivity and dependability. Power swing blocking happens if one of the following conditions remains for 30ms. All phase currents are bigger than the current setting of “I_PS”, and the sudden-change current elements have not operated. All phase-to-phase impedances loops enter into the largest zone of distance relay, and the sudden-change current elements have not operated. As mentioned, if any of the above conditions has been valid for 30ms, power swing startup will operate and protection program is switched to power swing blocking routine. At the same time, “I_PS STARTUP” (for the first condtion) or “Z STARTUP” (for the second condition) and “RELAY STARTUP” signals are reported. It should be note that “I_PSB” should be set larger than maximum load current in the protected feeder. Operation of sudden-change current indicates a fault occured in the power system network. In short circuit conditions, the measured impedance jumps instantaneously from load impedance area to the fault detection zones. On the other hand, power swings have a slow behavior. So, lack of operation of current sudden-change element beside high measured current and/or low calculated impedance indicates that power swing happened in the system. Therefore above condition has been used to initiate power swing startup element. In addition, experimental results of power swing show that it is not possible for impedance vector to come into the first distance zone in 150 msec after current sudden-change startup operation. Therefore, power swing blocking logic has been designed such that in 150 msec after current sudden-change startup, power swing blocking will not happen and distance protection can trip in this duration if required conditions fulfill. System power swings are normally three-phase symmetrical processes. Therefore, in general, a certain degree of measured value symmetry may be assumed. Accordingly, beside current sudden-change startup, zero sequence current startup will be used to remove or prevent power swing blocking. In addition fault detection during a power swing removes power swing blocking in the tripping logic. This unblocking logic of the zones which have already blocked with 74 Chapter 5 Distance protection power swing blocing has been shown in Figure 25. In this logic, “Z1(2,3,4,5)_PS blocking” indicates corresponding setting value for blocking of the zones in power swing condition. “I_PSB” startup Zero- sequence current startup Current change startup Fault detect swing unblocking O R |150 A N D 0| A N D O R NO PS 1 (2,3,4,5) A N D Z1(2,3,4,5)_PS blocking Figure 25 Power swing unblocking release logic The amount of kinetic energy gained by the generators during a fault is directly proportional to fault duration and the positive sequence voltage at the point of fault. Therefore, application of highspeed relaying systems and high-speed breakers is essential in locations where fast fault clearing is important. So, the faults that occur during a power swing must be detected and cleared with a high degree of selectivity and dependability. For this purpose, IED considers different fault detector elements during power swing occurrence for symmetric and asymmetric faults. It also provides six binary settings which can be set to block individually each protection zones (“Zx_PS blocking” where x, 1, 1Ext, 2, 3, 4,5, indicates zone number). In the duration of power swing, there is a special program module to detect whether power swing has been finished or not. So, after removing of all the conditions that indicate power swing occurrence, IED will be reset and exited from power swing module by “Relay reset” time. 1.2.9.4.1 Asymmetric faults detection element Power swing is generally a three phase system and some degree of symmetric behavior is considered in this condition. Therefore, zero and negative sequence current can distinguish fault from power swing. The criterion is described as following: |I0|>m1|I1| or I 2>m2|I 1| 75 Chapter 5 Distance protection Equation 18 Factors m1 and m2 ensure that power swing can be reliability differentiated from internal asymmetric faults. When only power swing occurs in the network, zero and negative sequences will be close to zero and it is not possible for the above equations to be fulfilled. When both power swing and external asymmetric fault occur, the zero and negative sequences, which will be seen by IED, are not so considerable to satisfy above equations. But in the case of power swing and internal asymmetric fault happening at the same time, zero and negative sequence of the measured current will be large enough to detect the fault in the power swing durations. Therefore, mal-operation of the protection IED will be prevented by checking above criteria. 1.2.9.4.2 Three phase fault detection element As mentioned, the amount of kinetic energy in the generator rotors is proportional to duration of faults which may be dangerous for system stability, particularly in three phase faults. Therefore, a three phase fault in power swing duration should be cleared as soon as possible. IED guarantees fast tripping of the three phase faults in power swing duration by considering following states. Impedance and resistance trajectory in the power swing During power swing, measuring resistance or impedance at the IED location will change continuously with time. Changing rate will be affected by the inertia of the system and impedances between different generators. In addition, this rate is also characterized by swing period and the machine angle, δ. Figure 26 shows a typical trajectory of measuring resistance in the power swing duration. Rf indicates normal load resistance component and Tz power swing period. During power swing, whether the trajectory of measuring impedance is a line or a circular arc on R-X plane depends on the voltage ratios between machines in an equivalent two machine system. 76 Chapter 5 Distance protection (a) Resistance (Rm) trajectory in normal and power swing condition (b) Impedance trajectory on R-X plane in power swing condition Figure 26 Trajectory of the measuring impedance during power swing Resistance trajectory in three phase faults When a three phase fault occurs on the protected line, resistance component of measuring impedance maybe changes due to short circuit arc. Analysis shows that arc resistance rating in three phase fault is far less than that of resistance changing corresponding to the possibly largest swing period. Figure 27 illustrates measured resistance trajectory in normal and three phase fault conditions. In this figure RK indicates resistance in three phase short circuit. Unlike power swing conditions, resistance variation after three phase fault is negligible. 77 Chapter 5 Distance protection Figure 27 Measuring resistance trajectory in normal and three phase faults Therefore, power system is determined to be in power swing condition if its measuring resistanceis continuously changing in a monotony manner. Conversely, three phase short circuit will be determined if resistance variations seem to be a small constant. To determine the resistance variation threshold value, worst case condition is considered. This will happen when the difference between internal angles of generators is 180°(in an equivalent two machine system) and power system has maximum power swing period TZMAX. This condition has been shown in Figure 28. Figure 28 Trajectory of the measuring resistance with δ=180o and TZMAX Therefore, a minimum resistance variation ΔRmin(180°,TZMAX,τ) is obtained by introducing a measuring window time equal to τ. In this way, for any swing period, the following relation will be valid for measured resistance variation: ΔR ≥ ΔRmin(180°,TZMAX, τ) Equation 19 Considering measuring error and margin coefficient, above criterion should be changed to: ΔR ≥ K×ΔRmin(180°,TZMAX, τ) 78 Chapter 5 Distance protection Equation 20 where K is a less than 1. Considering above processes, fault detection criteria in power swing condition will be as following: If resistance variation follows: ΔR < ΔRmin(180o,TZMAX, τ), it is concluded that three phase short has occurred during the power swing. If resistance variation follows: ΔR ≥ ΔRmin(180o,TZMAX, τ), it is concluded power swing condition without three phase fault has happened. Fault detection using impedance jumping In conditions when three phase fault suddenly occurs on the protected line outside the power swing center point or the generator difference angle (δ) is not approximately 180°, the magnitude and angle of measured impedance will jump and exceed rated changes. Based on this behavior, distance element can be unblocked quickly when three-phase fault happen with above conditions. 1.2.8 Phase-to-earth fault determination For phase-to-earth fault logic, zero-sequence current or zero-sequence voltage should also be considered. For solid earthed system, only if the measured trinal zero-sequence current is no less than the setting “3I0_Dist_PE” could phase-to-earth fault be determined; For isolated netral system, only if the measured trinal zero-sequence current is no less than the setting “3I0_Dist_PE”, and the measured trinal zero-sequence voltage is no less than the setting “3U0_Dist_PE”, could phase-to-earth fault be determined. 1.2.9 Logic diagram 79 Chapter 5 Distance protection 1.2.9.1 Distance protection tripping logic As mentioned, when a fault occurres, one or more startup elements, including current sudden-change startup, zero sequence current startup and low-voltage startup, will detect the fault. Impedance calculation computes all measuring loops (A, B, C, A-B, B-C, C-A) simultaneously using 6 measuring systems. Additionally, phase selector sequence will run and determines faulted loops accurately. Finarlly, selected fault impedance and setting values will be compared to verify that fault is within protection zones. By checking and fulfilling the fault detection criteria, IED distance protection will trip according to the following logics for different faults and zones: No Power swing One of the main criteria in tripping logic of different zones is that IED doesn’t detect power swing. Power swing blocking can be activated individually by different binary settings (Zx_PS blocking, where x indicates a zone number). In IED, power swing will be detected by power swing startup elements (for detail information refers under heading “Power swing blocking/unblocking”). Zone 1 faults Zone 1 fault detection logic is shown as following figure: Impedance Within Z1 Forward direction No PS 1 Func_Z1=1 Imp.Oper.Zone=0 Test Pos.Imp=0 80 A N D Z1 detection Chapter 5 Distance protection Figure 29 Zone 1 fault detection logic A fault is considered in Zone 1 if the calculated impedance lies within Z1 characteristic zone and direction checking criteria confirms that the fault is forward direction. In addition, power swing unblocking should be released. As mentioned before, power swing blocking for zone 1 can be selected individually by binary setting “Z1_PS blocking”. If the “Z1_PS blocking” is set to “off”, power swing blocking is disabled. If the setting “Z1_PS blocking” is set to “on”, power swing blocking will be enabled. Zone 2 faults Zone 2 fault detection logic is shown in Figure 30. Impedance Within Z2 Not reverse direction No PS 2 A N D Func_Z2=1 Z2 detection Imp.Oper.Zone=0 Test Pos.Imp=0 Figure 30 Zone 2 fault detection logic A fault is considered in Zone 2 if the calculated impedance lies within Z2 characteristic zone and direction checking criteria confirms that the fault is not reverse. In addition, power swing unblocking should be released. As mentioned above, power swing blocking for zone 1 can be selected individually by binary setting “Z2_PS blocking”. If “Z2_PS blocking” is set to “off”, power swing blocking is disabled. If “Z2_PS blocking” is set to “on”, power swing blocking will be enabled. Zone 3 faults 81 Chapter 5 Distance protection Impedance Within Z3 Not reverse direction Asymmetric fault No PS 3 Func_Z3=1 A N D Imp.Oper.Zone=0 O R Test.Pos.Imp=0 Z3 detection Impedance Within Z3 Symmetric fault No PS 3 Func_Z3=1 A N D Imp.Oper.Zone=0 Test Pos.Imp=0 Figure 31 Zone 3 fault detection tripping logic Above figure shows the fault detection logic of zone 3. The main condition of detection is that the calculated impedance lies within Z3 characteristic zone. In addition, detection logic is different for symmetric and asymmetric faults. For asymmetric faults IED checks direction criteria to be not reverse while in symmetric faults only the calculated impedance will be considered. Same as previous ones, power swing blocking for zone 3 can also be selected individually by binary setting “Z3_PS blocking”. If “Z3_PS blocking” is set to “off”, power swing blocking is disabled. If “Z3_PS blocking” is set to “on”, power swing blocking will be enabled. Zone 4 & 5 faults Figure 25 shows fault detection logic of zones 4 and 5. Same as zone3, calculated impedance vector is the main criteria of the zones 4 and 5 detection logic. Since these zones can be selected as forward or reverse direction, detection logic will be different in these two cases. Forward direction will be selected if direction detection criteria conciders that the fault is “Not Reverse”. Conversely, inverse direction will be selected if direction detection checking determines fault as “Not Forward”. Here, it is also possible to select zones 4 and 5 blocking in power swing condition by binary settings “Z4_PS blocking” and “Z5_PS blocking”. 82 Chapter 5 Distance protection Impedance Within Z4 NOT reverse direction Func_Z4=1 Reverse_Z4=0 Imp.Oper.Zone=0 A N D Test.Pos.Imp=0 No PS 4 O R Z4 detection Impedance Within Z4 NOT forward direction Func_Z4=1 Reverse_Z4=1 A N D Imp.Oper.Zone=0 Test Pos.Imp=0 Impedance Within Z5 NOT reverse direction Func_Z5=1 Reverse_Z5=0 Imp.Oper.Zone=0 A N D Test.Pos.Imp=0 No PS 5 O R Z5 detection Impedance Within Z5 NOT forward direction Func_Z5=1 Reverse_Z5=1 A N D Imp.Oper.Zone=0 Test Pos.Imp=0 Figure 32 Zones 4 and 5 fault detection in tripping logic 1.2.9.2 Tripping logic Distance protection tripping will be blocked in the case of VT Fail 83 Chapter 5 Distance protection detection (for more detail, refer to under heading “VT Fail detection”). In addition in the case of Switch-onto-Fault condition, the delay timers of zone 1, 2 and 3 will be bypassed and short circuit will be immediately removed. IED provides two binary settings, “AR Init by 3p” “AR Init by 2p” to set auto-reclosing operation for three phase faults, phase to phase fault, and single phase faults. If both binary settings “AR Init by 3p” and “AR Init by 2p” are disabled, IED only initiates auto-reclosing for single phase faults. If both “AR Init by 3p” and “AR Init by 2p” are enabled, IED can operate both for three phase faults, phase to phase fault, and single phase faults. If binary setting “AR Init By 2p” is enabled, while “AR Init By 3p” is disabled, AR will only be initiated by phase to phase fault or single phase faults. Tripping of distance protection by Zone 2 to 5 is also considered to be permanent without any auto-reclosing initiation. VT fail Func_SOTF On A N D SOTF O R Z1 detection Ext Z1 detection |T1 A N D 0| |T1Ext 0| Z2 detection |T2 0| Z3 detection |T3 0| Z4 detection |T4 0| Z5 detection |T5 0| 84 Unpermenent trip O R A N D O R Permenent trip Chapter 5 Distance protection Figure 33 Distance protection tripping logic AR not ready A N D Single fault Trip single phase Relay Trip 3pole off Relay Trip 3pole on A N D BI “1P Trip Block” O R Trip Tree phase AR Init By 2p on Two phase fault AR Init By 2p off AR Init By 3p on Three phase fault O R AR Init By 3p off Permenent Trip O R AR Init By 2p off Figure 34 Trip logic Note: The above trip logic applies to the first zone and the extended first zone of distance protection as well as teleprotection 1.3 Input and output signals IP1 Trip PhA IP2 Trip PhB IP3 Trip PhC IN Trip 3Ph IN(M) Relay Block AR UP1 Zone1 Trip UP2 Zone2 Trip UP3 Zone3 Trip Zone4 Trip Zone5 Trip Zone1Ext Trip PSB Dist OPTD Relay Startup Relay Trip 85 Chapter 5 Distance protection Table 15 Analog input list Signal Description IP1 Signal for current input 1 IP2 Signal for current input 2 IP3 Signal for current input 3 IN External input of zero-sequence current IN(M) External input of zero-sequence current of adjacent line UP1 Signal for voltage input 1 UP2 Signal for voltage input 2 UP3 Signal for voltage input 3 Table 16 Binary output list Signal Description Relay Startup Relay Startup Relay Trip Relay Trip Trip PhA Trip phase A Trip PhB Trip phase B Trip PhC Trip phase C Trip 3Ph Trip three phases Relay Block AR Permanent trip, or AR being blocked Zone1 Trip Zone1 distance protection trip Zone2 Trip Zone2 distance protection trip Zone3 Trip Zone3 distance protection trip Zone4 Trip Zone4 distance protection trip Zone5 Trip Zone5 distance protection trip Zone1Ext Trip Extended zone1 distance protection trip PSB Dist OPTD Distance operated in power swing 1.4 Setting parameters 1.4.1 Setting list 86 Chapter 5 Distance protection Table 17 Distance protection function setting list Setting Unit Min. (Ir:5A/1A) Max. Default (Ir:5A/1 setting A) (Ir:5A/1A) Kx -0.33 8 1 Kr -0.33 8 1 Description compensation factor of zero sequence reactance compensation factor of zero sequence resistance compensation factor of zero Km -0.33 8 0 sequence mutual inductance of parallel line X_Line Ohm 0.01 600 10 R_Line Ohm 0.01 600 2 Line length km 0.1 999 100 I_PSB A 0.5 20Ir 2Ir R1_PE Ohm 0.01/0.05 120/600 1/5 positive reactance of the whole line positive resistance of the whole line Length of line current threshold of power system unstability detection resistance reach of zone 1 of phase to earth distance protection reactance reach of zone 1 of X1_PE Ohm 0.01/0.05 120/600 1/5 phase to earth distance protection resistance reach of zone 2 R2_PE Ohm 0.01/0.05 120/600 1.6/8 of phase to earth distance protection reactance reach of zone 2 of X2_PE Ohm 0.01/0.05 120/600 1.6/8 phase to earth distance protection resistance reach of zone 3 R3_PE Ohm 0.01/0.05 120/600 2.4/12 of phase to earth distance protection reactance reach of zone 3 of X3_PE Ohm 0.01/0.05 120/600 2.4/12 phase to earth distance protection resistance reach of zone 4 R4_PE Ohm 0.01/0.05 120/600 3/15 of phase to earth distance protection reactance reach of zone 4 of X4_PE Ohm 0.01/0.05 120/600 3/15 phase to earth distance protection R5_PE Ohm 0.01/0.05 120/600 3.6/18 resistance reach of zone 5 87 Chapter 5 Distance protection Setting Unit Min. (Ir:5A/1A) Max. Default (Ir:5A/1 setting A) (Ir:5A/1A) Description of phase to earth distance protection reactance reach of zone 5 of X5_PE Ohm 0.01/0.05 120/600 3.6/18 phase to earth distance protection resistance reach of R1Ext_PE Ohm 0.01/0.05 120/600 1.6/8 extended zone 1 of phase to earth distance protection reactance reach of X1Ext_PE Ohm 0.01/0.05 120/600 1.6/8 extended zone 1 of phase to earth distance protection delay time of zone 1 of T1_PE s 0 60 0 phase to earth distance protection delay time of zone 2 of T2_PE s 0 60 0.3 phase to earth distance protection delay time of zone 3 of T3_PE s 0 60 0.6 phase to earth distance protection delay time of zone 4 of T4_PE s 0 60 0.9 phase to earth distance protection delay time of zone 5 of T5_PE s 0 60 1.2 phase to earth distance protection delay time of extended zone T1_Ext_PE s 0 60 0.05 1 of phase to earth distance protection resistance reach of zone 1 R1_PP Ohm 0.01/0.05 120/600 1/5 of phase to phase distance protection reactance reach of zone 1 of X1_PP Ohm 0.01/0.05 120/600 1/5 phase to phase distance protection resistance reach of zone 2 R2_PP Ohm 0.01/0.05 120/600 1.6/8 of phase to phase distance protection reactance reach of zone 2 of X2_PP Ohm 0.01/0.05 120/600 1.6/8 phase to phase distance protection 88 Chapter 5 Distance protection Setting Unit Min. (Ir:5A/1A) Max. Default (Ir:5A/1 setting A) (Ir:5A/1A) Description resistance reach of zone 3 R3_PP Ohm 0.01/0.05 120/600 2.4/12 of phase to phase distance protection reactance reach of zone 3 of X3_PP Ohm 0.01/0.05 120/600 2.4/12 phase to phase distance protection resistance reach of zone 4 R4_PP Ohm 0.01/0.05 120/600 3/15 of phase to phase distance protection reactance reach of zone 4 of X4_PP Ohm 0.01/0.05 120/600 3/15 phase to phase distance protection resistance reach of zone 5 R5_PP Ohm 0.01/0.05 120/600 3.6/18 of phase to phase distance protection reactance reach of zone 5 of X5_PP Ohm 0.01/0.05 120/600 3.6/18 phase to phase distance protection resistance reach of R1Ext_PP Ohm 0.01/0.05 120/600 1.6/8 extended zone 1 of phase to phase distance protection reactance reach of X1Ext_PP Ohm 0.01/0.05 120/600 1.6/8 extended zone 1 of phase to phase distance protection delay time of zone 1 of T1_PP s 0 60 0 phase to phase distance protection delay time of zone 2 of T2_PP s 0 60 0.3 phase to phase distance protection delay time of zone 3 of T3_PP s 0 60 0.6 phase to phase distance protection delay time of zone 4 of T4_PP s 0 60 0.9 phase to phase distance protection delay time of zone 5 of T5_PP s 0 60 1.2 phase to phase distance protection T1_Ext_PP s 0 60 0.05 delay time of extended zone 1 of phase to phase 89 Chapter 5 Distance protection Setting Min. Unit (Ir:5A/1A) Max. Default (Ir:5A/1 setting A) (Ir:5A/1A) Description distance protection 3I0_Dist_P E zero sequence current A 0.1Ir 2Ir 0.1Ir threshold of phase to earth distance protection 3U0_Dist_ PE zero sequence voltage V 0.5 60 1 threshold of phase to earth distance protection Table 18 Distance protection binary setting list Abbr. Func_Z1 Explanation First zone distance protection operating mode (On/Off) Default Unit Min. Max. 1 0 1 1 0 1 1 0 1 1 0 1 0 0 1 1 0 1 0 0 1 1 0 1 1 0 1 1 0 1 1 0 1 Second zone distance Func_Z2 protection operating mode (On/Off) Func_Z3 Third zone distance protection operating mode (On/Off) Fourth zone distance Func_Z4 protection operating mode (On/Off) Setting for fourth zone Reverse_Z4 distance protection operation as reverse Func_Z5 Fifth zone distance protection operating mode Setting for fifth zone distance Reverse_Z5 protection operation as for reverse Extended zone 1 distance Func_Z1Ext protection operating mode (On/Off) Blocking of the first zone Z1_PS Blocking distance protection in power swing Blocking of the second zone Z2_PS Blocking distance protection in power swing Z3_PS Blocking 90 Blocking of the third zone Chapter 5 Distance protection Abbr. Explanation Default Unit Min. Max. 1 0 1 1 0 1 1 0 1 0 0 1 0 0 1 0 0 1 1 0 1 1 0 1 distance protection when power swing Blocking of the fourth zone Z4_PS Blocking distance forward protection in power swing Blocking of the fifth zone Z5_PS Blocking distance forward protection in power swing Blocking of the extended zone Z1Ext_PS Blocking 1 distance forward protection in power swing Second zone distance Z2 Speedup protection speedup operating mode by auto-reclosing on to fault Third zone distance protection Z3 Speedup speedup operating mode by auto-reclosing on to fault Z23 Speedup Inrush Block Distance protection speedup operating blocked by inrush (0)The direction element is active; The small rectangular near zero point is reactive; Imp.Oper.Zone (1)The direction element is reactive; The small rectangular near zero point is active (0)The direction element is Test Pos.Imp active ; (1)The direction element is reactive Note: The two settings, ‘Imp.Oper.Zone’ and ‘Test Pos.Imp’, should set as 1 only for testing. They must be set as 0 in service. 1.4.2 Setting explanation Kx: Reactance compensation factor,It should be calculated based on the actual line parameters. Finally, the setting value should be less than or close to calculation value. 91 Chapter 5 Distance protection KX = (X0-X1) / 3X1 Kr: Resistance compensation factor, It should be Calculated based on the actual line parameters. Finally, the setting value should be less than or close to calculation value. KR = (R0-R1) / 3R1 Km: Compensation factor for zero sequence mutual reactance of parallel lines, It shoule be calculated based on the actual line parameters.The setting value should be less than or close to calculation value. X0m is the zero sequence mutual reactance in the parrallel lines. X1 is the positive sequence reactance of the line where IED is located. Km= X0m/3X1 X_Line and R_Line: Line positive reactance and resistance:It is set according to secondary values of actual line parameters. 92 Zone 1 FUNC, Zone Ext FUNC, Zone 2 FUNC, Zone 3 FUNC, Zone 4 FUNC and Zone 5 FUNC can be set by “Func_Z1”, “Func_Z1Ext” “Func_Z2”, “Func_Z3”, “Func_Z4”, “Func_Z5”individually. Reverse_Z4 and forward_Z4: zone 4 of the distance can be selected to operate for reverse direction or forward direction. The mode of operation can be set in these binary settings. Reverse_Z5 and forward_Z5: zone 5 of the distance can be selected to operate for reverse direction or forward direction. The mode of operation can be set in these binary settings. Power swing Blocking: the operation of zone 1, extension zone 1, zone 2, zone 3, zone 4 and zone 5 can be separately selected to be block or unblock during power swing. When the bit is set to “1”, distance protection zones are disabled by power swing blocking elements. If the bit is set to “0”, for any distance protection zone, the relay can send trip command even in power swing condition. “3I0_Dist_PE” and “3U0_Dist_PE”: minimum zero-sequence current and minimum zero-sequence voltage for phase-to-earth protection operation. Chapter 5 Distance protection 1.4.3 Calculation example for distance parameter settings The solidy grounded 400kV overhead Line A-B has been shown in A B 127km C 139km 21/21N 21/21N PTR:400/0.1kV CTR:2000/5 Figure 35 and line parameters are as follows. It is assumed that the line does not support teleprotection scheme beacuase lack of any communication link. A B 127km C 139km 21/21N 21/21N PTR:400/0.1kV CTR:2000/5 Figure 35 400kV Overhead Line (A-B) protected by distance protection For line 1 (line AB): S1 (length): 127 km Current Transformer: 2000 A/5 A Voltage transformer: 400 kV/0.1 kV Rated Frequency: 50 Hz Rated power of the line: 300MVA Full scale current of the line: 433A R+Line1 =0.030 Ω/km 93 Chapter 5 Distance protection X+Line1 =0.353 Ω/km R0line1 =0.302 Ω/km X0Line1 =0.900 Ω/km For line 2: S2 (length) = 139 km R+Line2 =0.030 Ω/km X+Line2 =0.352 Ω/km R0line2 =0.311 Ω/km X0Line2 =0.898 Ω/km So, The line angle can be derived from the line parameters: Φ = arctan (X+ / R+) So Line 1 Angle: 85.1° The resistance ratio RE/RL and the reactance ratio XE/XL should be applied for zero sequence compensation calculations. They are calculated separately, and do not correspond to the real and imaginary components of ZE/ZL. RE/RL XE/XL x' = 0.04 Ω/km = R 0 R1 =3.00 3R1 X 0 X1 = 0.52 3X 1 in secondary side Time Delays: 94 T1-p-e or p-p time delay 0.0 sec T2-p-e or p-p time delay 0.3 sec Chapter 5 Distance protection T3-p-e or p-p time delay 0.6 sec T4-p-e or p-p time delay 0.3 sec T5 inactive Zone Z1 impedance settings The resistance settings of the individual zones have to cover the fault resistance at the fault location. For the Zone 1 setting only arc faults will be considered. The length of the arc is greater than the spacing between the conductors (ph-ph), because the arc is blown into a curve due to thermal and magnetic forces. For estimation purposes it is assumed that arc lenght is twice the conductor spacing. To obtain the largest value of Rarc, which is required for the setting, the smallest value of fault current must be used. According to the conceptthat arc approximately has the characteristic with 2500V/m, the arc resistance will be calculated with the following equation: Rarc 2500 / m 2 ph ph spacing I 3PH MIN To calculate the minimum three phase short circuit current, it is required to calculate the short circuit current in the end of line: Min 3ph short circuit current in the local end, Isc: 10 kA Short circuit capacity=SCC=√3×VL×Isc: 6920 MVA S_base: 1000 MVA SCC_pu: 6.92 pu Z_source_pu≈ 1/Scc_pu: 0.14 pu Z_source_ohm: 23.12 Ω L_source= 0.073598 H Positive sequence impedance: Ω/km 0.03024+ j0.35276 Connected Line length: 127.0 km Positive sequence impedance, Z_Line: 3.840+ j44.8 Ω=0.024+ 95 Chapter 5 Distance protection j0.280 pu I3ph- min=1pu/[Z_source+Z_Line] : 2.350 pu =3.396 kA On secondary I3ph- min: 8.489 A So, by considering the 3 m Ph-Ph spacing: Rarc =4.417Ω By addition of a 20 % safety margin and conversion to secondary impedance the following minimum setting is calculated (division by 2 is because of this fact that Rarc appears in ph-ph loop measurement while the setting is done as phase impedance or positive sequence impedance): R( Z1) 1.2 Rarc CTR / PTR 2 So, R (Z1)min=0.265 Ω in Secondary Side This calculated value corresponds to the smallest setting required to obtain the desired arc resistance coverage. Depending on the X(Z1) reach calculated, this setting may be increased to obtain the desired Zone 1 polygon symmetry. For phase to phase fault X1+ =0.353 Ω/km CTR=2000/5A CTR/PTR=0.100 PTR=400/0.1kV L1=127km Xline1+ =4.48 Ω Secondary Rline+ =0.384 Ω Secondary Since, there is not any tele-protection scheme, to get fast tripping on the 96 Chapter 5 Distance protection longer length, Z1 setting for phase to phase fault is set to %85 of the line instead %80. X (Z1) =0.85 ×X+Line1 -Secondary So, X (Z1) = 3.81Ω in Secondary Side X (Ω) XDZ 7° 14° 63.4° 14° RDZ R (Ω) Figure 36 X (ohm) Line angle 0.04 7° 3.81 85.1° 63.4° R (ohm) 0.33 Figure 37 According to the above figure, reactance setting of the zone 1 is considered as: X (Z1)SET = 3.81 + 0.04 =3.85 Ω in Secondary Side For phase to ground fault Considering some error in the parameter calculation of RE/RL and XE/XL, 97 Chapter 5 Distance protection the reactance reach is considered as %80 of line A-B. XE (Z1) = 0.8 ×X+Line1-Secondary So, XE (Z1) =3.58 Ω in Secondary Side Line angle X (ohm) 0.04 7° 3.58 85.1° 63.4° R (ohm) 0.33 Figure 38 Characteristic zone example According to the above figure, reactance setting of the zone 1 is considered as: XE (Z1)SET =3.58 + 0.04=3.62 Ω in Secondary Side For phase to phase fault Considering minimum setting vaule of R(Z1) calculated before, for overhead line protection applications, the following rule of thumb may be used for the R(Z1) setting to get the best symmetry on polygon characteristic: 0.8 X ( Z1) R( Z1) 2.5 X ( Z1) So, 3.05≤ R (Z1) ≤9.53 Therefore, in this case, setting value for R(Z1) is considered as: 98 Chapter 5 Distance protection R (Z1) = 3.10Ω in Secondary Side For phase to earth fault The phase to earth fault resistance reach is calculated along the same way as ph-ph faults. For the earth fault however, not only the arc voltage but also the tower footing resistance must be considered. RTF (1 I2 ) Effective Tower Resistance I1 It is assumed that each tower resistance equals to: 15Ω Effective tower resistance considering the parallel connection of multiple tower footing resistance ≈2Ω In the above equation, I2/I1 is the ratio between earth fault currents at the opposite end to the local one. Where no information is available on the current ratio, a value of approx. 3 is assumed for a conservative approach. Assumed I2/I1=3 So, RTF=8Ω For the calculation of Rarc using the formula introduced above, without detail information about the tower configuration, ph totower spacing is assumed to be 3m in the worst case (conservative solution). Assumed ph-tower spacing: Rarc 3m 2500V 2 Ph Tower Spacing I 1 ph min Min 1ph short circuit current in the local end, Isc: 5kA S_base: 1000 MVA I_base: 1.445 kA Isc pu: 3.46 pu 99 Chapter 5 Distance protection Zs=2Z+source+Z0source_pu≈ 1/(Isc pu/3): 0.87pu Positive sequence impedance: 0.0302+ j0.353 Ω/km Zero sequence impedance 0.302+ j0.900 Ω/km Connected Line lengh: 127.0 km Positive sequence impedance, Z1_Line: 3.840+ j44.8 Ω =0.024+ j0.28 pu Zero sequence impedance, Z0_Line: 38.354+ 114.3 Ω =0.240+ j0.714 pu I1ph- min=3×1pu/[Zs+2Z1_Line+Z0_Line] : pu = kA 1.374490915 1.986 And on secondary side, I3ph- min=4.965 A So, arc resistance will be: Rarc=7.55 RE ( Z1) Ω 1.2 ( Rarc RTF ) CTR / PTR RE 1 RL So, RE (Z1) =0.5 Ω in Secondary Side This calculated value corresponds to the smallest setting required to obtain the desired resistance coverage. Depending on the X(Z1) reach calculated above, this setting may be increased to obtain desired Zone 1 polygon symmetry. 100 Chapter 5 Distance protection XE XL 2.5 X ( Z1) 0.8 X ( Z1) RE ( Z1) RE 1 RL 1 So, 3.05≤RE (Z1)≤3.62 Therefore, in this case, setting value for RE(Z1) is considered as: RE (Z1) =3.10Ω in Secondary Side Operating mode Z1 Forward R(Z1), Resistance for ph-ph-faults 3.10 Ω X(Z1), Reactance 3.81 Ω RE(Z1), Resistance for ph-e faults 3.10 Ω XE(Z1), Reactance 3.58 Ω Tele protection scheme inactive Power swing blocking zones All zones Zone Z2 & Z3 impedance setting According to the grading requirement: X ( Z 2) 0.8 X Line1 0.8 X Line2shortest X+Line1 =44.8 Ω CTR PTR in primary X+Line2 =48.928 Ω CTR=2000/5 A CTR/PTR=0.100 PTR=400/0.1kV So, 101 Chapter 5 Distance protection X (Z2) =6.72 Ω in secondary side X (ohm) Line angle 0.07 6.72 7° 85.1° 63.4° R (ohm) 0.58 Figure 39 Zone 2 protection characteristic setting According to the above figure, reactance setting of the zone 1 is considered as: X(Z2)SET =XE (Z2)SET =6.72 + 0.07= 6.79 Ω in secondary side Resistance coverage for all arc faults up to the set reach must be applied. As this zone is applied with overreach, an additional safety margin is included, based on a minimum setting equivalent to the X(Z2) setting and arc resistance setting for internal faults, R(Z1) setting. Therefore: R( Z 2) Min X ( Z 2) R(Z1) X ( Line1sec ondary ) So,R (Z2) Min =4.65 Ω in secondary side According to the above minimum value, the setting is considered as: R (Z2) =4.70Ω in secondary side Similar to the R(Z2) setting, the minimum required reach for RE(Z2) setting is based on the RE(Z1) setting which covers all internal fault resistance and the X(Z2) setting which determines the amount of overreach. Alternatively, the RE(Z2) reach can be calculated from the R(Z2) reach with the following equation: RE ( Z 2) 102 X ( Z 2) 1.2 RE ( Z1) X ( Line1secondary ) Chapter 5 Distance protection So, RE (Z2)Min=5.58 Ω in secondary side Here the maximum value between R(Z2) and RE(Z2)min is selected: So, RE (Z2) =5.58 Ω in Secondary Side On the other hand, the resistance reach setting for Z2 and Z3 are set according to the maximum load current and minimum load voltage. The values are set somewhat (approx. 10 %) below the minimum expected load impedance. Maximum transmission power =250MVA Imax =401 A at Vmin=0.9*Vn Zload_Prim. = (0.9 × 400kV) / (401 ×√3) =518.334 Ω Zload_Sec=52 Ω When applying a security margin of 10 % the following is set: Zload_Sec. =47 Ω Assuming a minimum power factor of CosΦmin at full load condition = 0.85 So, Rload_Sec. =40 Ω The spread angle of the load trapezoid Φ load (Ø-E) and Φload (Ø-Ø) must be greater (approx. 5°) than the maximum arising load angle (corresponding to the minimum power factor cosΦ). Φ load = ArcCos (0.85) + 5 ≈37° Therefore, according to the protection zones characteristic and maximum calculated load impedance and angle, we will have: 103 Chapter 5 Distance protection X (Ω) XDZ 7° 14° 63.4° 14° RDZ R (Ω) Figure 40 Characteristic zone example X (ohm) 30.1 26.6° 63.4° 15.1 Rload=40 37° R (ohm) Figure 41 Characteristic zone example Therefore the maximum setting of R-Z3 should be as: 40-15.1=24.91 Ω The calculated resistance for Z2 is far from the above maximum value and so is acceptable. Finally, the zone 2 and 3 setting should as follows: Operating mode Z2 Forward 104 R(Z2), Resistance for ph-ph-faults Ω 4.70 X(Z2), Reactance Ω 6.79 RE(Z2), Resistance for ph-e faults 5.58 Chapter 5 Distance protection Ω XE(Z2), Reactance Ω 6.79 Without any information about line3, Z3 is set %50 larger than Zone2, as follows: Operating mode Z3 Forward R(Z3), Resistance for ph-ph-faults Ω 7.05 X(Z3), Reactance Ω 10.19 RE(Z3), Resistance for ph-e faults Ω 8.37 XE(Z3), Reactance Ω 10.19 Zone Z4 Zone 4 is considered to protect %30 of the zone 1 in reverse direction. So, X (Z4) =0.3X(Z1)=1.16 Ω in secondary side So, XE(Z4) =0.3XE(Z1)=1.07 Ω in secondary side So, R (Z4) = 0.3R(Z1)= 0.93 Ω in secondary side Similar to the R(Z4) setting, the upper and lower limits are defined by minimum required reach and symmetry. In this application RE(Z4) reach is set same as R(Z4). And finally: RE(Z4) = 0.3RE(Z1)= 0.93 Ω in secondary side Operating mode Z4 Reverse R(Z4), Resistance for ph-ph-faults 0.93Ohm X(Z4), Reactance 1.16Ohm 105 Chapter 5 Distance protection RE(Z4), Resistance for ph-e faults 0.93Ohm XE(Z4), Reactance 1.07Ohm Zone Z5 Zone 5 is set to be inactive. 1.5 Reports Table 19 Event report list Abbr. Meaning Relay Startup Protection startup Dist Startup Impedance element startup 3I0 Startup Zero-current startup I_PS Startup Current startup for Power swing Zone1 Trip Zone 1 distance trip Zone2 Trip Zone 2 distance trip Zone3 Trip Zone 3 distance trip Zone4 Trip Zone 4 distance trip Zone5 Trip Zone 5 distance trip Zone1Ext Trip Zone 1 Extended distance trip Dist SOTF Ttrip Distance element instantaneous trip after switching on to fault (SOTF) PSB Dist OPTD Distance operated in power swing Z2 Speedup Trip Z2 instantaneous trip in SOTF or auto-reclosing on fault Z3 Speedup Trip Z3 instantaneous trip in SOTF or auto-reclosing on fault Trip Blk AR(3T) Permanent trip for 3-ph tripping failure Relay Trip 3P Trip 3 poles 3P Trip (1T_Fail) three phase trip for 1-ph tripping failure Distance zone 1 evolvement trip, for example, A phase to earth fault Dist Evol Trip happened, and then B phase to earth fault followed, the latter is considered as an evolvement trip Fault Location Fault location Impedance_FL Impedance of fault location Table 20 Alarm report list 106 Chapter 5 Distance protection Abbr. Meaning Func_Dist Blk Distance function blocked by VT fail Table 21 Operation report list Abbr. Meaning Test mode On Test mode On Test mode Off Test mode Off Func_Dist On Distance function on Func_Dist Off Distance function off Func_PSB On PSB function on Func_PSB Off PSB function off 1.6 Technical data Table 22 Distance protection technical data NOTE: Ir: CT rated secondary current, 1A or 5A; Item Number of settable zone Rang or Value Tolerance 5 zones, with additional extended zone Distance characteristic Polygonal Resistance setting range 0.01Ω~120Ω, step 0.01Ω, ≤± 5.0% static accuracy when Ir=5A; Conditions: 0.05Ω~600Ω, step 0.01Ω, Voltage range: 0.01 Ur to 1.2 when Ir=1A; Ur 0.01Ω~120Ω, step 0.01Ω, Current range: 0.12 Ir to 20 Ir Reactance setting range when Ir=5A; 0.05Ω~600Ω, step 0.01Ω, when Ir=1A; Time delay of distance zones 0.00 to 60.00s, step 0.01s ≤±1% or +20 ms, at 70% operating setting and setting time > 60ms Operation time 22ms typically at 70% setting of zone 1 Dynamic overreaching for ≤±5%, at 0.5<SIR<30 zone 1 107 Chapter 5 Distance protection 108 Chapter 5 Distance protection 109 Chapter 6 Teleprotection Chapter 6 Teleprotection About this chapter This chapter describes the protection principle, input and output signals, parameters, IED report and technical data used for teleprotection function. 110 Chapter 6 Teleprotection 1 Teleprotection schemes for distance 1.1 Introduction Distance teleprotection is an important function in the IED to get fast tripping of the short circuit in the area near to remote end. The function employs carrier sending and receiving feature, power line carrier (PLC) or dedicated fiber optic communication channels, to implement different tele-protection scheme configuration. 1.2 Teleprotection principle 1.2.1 Permissive underreach transfer trip (PUTT) scheme By setting the binary “PUR mode” to “1/on”, teleprotection logic works in permissive under reach mode. The permissive under reach transfer trip is shown in Figure 42. The scheme is based on receiving and sending signals. IED sends distance carrier signal if its startup elements operate and a fault occurs in the first protection zone (Z1). To get reliable operation in remote line end, the carrier send signal is prolong for 200 msec after resetting of the trip signal. According to this scheme, IED will generate a trip command if a fault has been detected in second protection zone (Z2) and a carrier signal has been received for at least 5 msec. According to the mode selected (single phase operation, three phase protection and also auto-reclosing mode), teleprotection scheme can generate single or three phase tripping.For more detail about tripping mode refer under heading “Automatic reclosing function”. In the following, different conditions are considered to show the operation of the IED in the permissive under reach transfer trip mode. 111 Chapter 6 Teleprotection Relay startup A N D Relay reset A N D Zone 1 operation Zone 2 operation Delay time 5ms CARR Received A N D A N D O R |200 0| Trip A N D CARR Send signal Relay trip Figure 42 Teleprotection logic for permissive under reach transfer trip Internal fault-faults within protected line Startup element operates when an internal fault occurs. If the fault has been detected in Z1, IED trips local CB and sends signal to the remote end. If fault occurs in the protected line outside Z1 setting, local CB will be tripped instantaneously by detection of fault in Z2 and receiving of the carrier signal from remote end for at least 5 msec. External fault-faults outside of the protected line For external faults in reverse direction, protection IED doesn’t send a distance carrier signal. Therefore, remote end distance relay doesn’t generate an instantaneous trip command by only detection of a fault in its Z2 characteristic. Conversely, for external faults in forward direction, local IED may detect the fault in Z2 but it doesn’t generate trip command because lack of any receiving carrier signal from remote end. Therefore both local and remote end distance protection will be stable for the external faults without any tripping. 1.2.2 Permissive overreach transfer trip (POTT) scheme This mode of operation can also be useful for extremely short lines where a typical setting of 85% of line length for Z1 is not possible and selective non-delayed tripping could not be achieved. In this case zone Z1 must be delayed by a time, to avoid non- selective tripping of distance protection by Z1. Teleprotection logic works in permissive overreach mode if binary setting 112 Chapter 6 Teleprotection “POR mode” is set to “1-on”. The permissive overreach transfer trip logic has been shown in the below figure. Relay startup A N D Relay reset A N D Zone 2 operation Delay time 5ms CARR Received A N D A N D O R |200 0| Trip A N D CARR Send signal Relay trip Figure 43 Teleprotection logic for permissive over reach transfer trip This scheme is based on receiving and sending signals. IED sends distance carrier signal if startup elements operate and a fault occurs in the Z2 protection zone. To get reliable operation of the remote end, any carrier sent signal is prolonged for 200ms after resetting of trip signal. Additionally, to support permissive overreach scheme in the case of weak infeed sources, special echo logic is considered in IED. In this scheme, IED generates a trip command if a fault has been detected in Z2 zone and a carrier signal received for at least 5 msec. According to mode selected (single phase operation, three phase protection and also auto-reclosing mode), teleprotection scheme can generate single or three phase tripping. For more detail about tripping mode refer under heading “Automatic reclosing function”. 1.2.3 Blocking scheme In this scheme of operation, the transferring signal is utilized to block the IED during external faults. The blocking signal should only be transmitted when the fault is outside the protected zone in reverse direction. The significant advantage of the blocking procedure is that no signal needs to be transferred during faults on the protected feeder. Teleprotection blocking will be applied in if the binary setting “Blocking mode” is set to “1-on”. Related logic is shown in Figure 44 113 Chapter 6 Teleprotection Relay startup Relay reset A N D Zone 4 (reverse) operation A N D Zone 2 operation Delay time 25ms CARR Received A N D CARR Send signal A N D Relay trip A N D Figure 44 Blocking scheme IED sends blocking signal if startup elements operate and a fault has been detected in reverse direction, e.g. Z4 considered as reverse. In this scheme, IED generates a trip command if a fault has been detected in Z2 of the protection zones and no blocking signal received for at least 25 msec. According to the selected mode (single phase operation, three phase protection and also auto-reclosing mode), teleprotection scheme can generate single or three phase tripping. For more detail about tripping mode refer under heading “Auto-reclosing function”. In the following, different conditions will be considered to show operation of the protected IED in the blocking mode. Internal faults - faults within protected line If an internal fault occurs, startup element operates and IED trips local CB instantaneously if it is within Z1 zone. Since the fault is not reverse, no blocking signal will be sent and remote end will generate trip command by detection the fault in its Z2 zone. If fault occurs in the protected line but outside of the Z1 setting, local CB tripping happen instantaneously by detection of fault in Z2 and no receiving blocking signal from remote end for at least 25 msec. External faults - faults outside of protected line For external faults in the reverse direction, IED sends a distance carrier blocking signal. Therefore, remote end distance relay doesn’t generate an instantaneous trip command by only detection of a fault in its Z2 characteristic zone. Conversely, in the case of external fault in forward direction, local IED may detect the fault in Z2 but it doesn’t generate trip command because of the receiving blocking signal from remote end. 114 Chapter 6 Teleprotection Therefore both local and remote end distance IED will not trip for this external fault. 1.2.4 Additional teleprotection logics 1.2.4.1 Direction reversing for external fault For parallel lines, an external fault can cause direction reversal that may generate unwanted tripping, if no suitable solution is considered. For example, in Figure 45, there are parallel lines protected by distance protection on each side. Additionally, the lines are protected using POTT scheme. In this figure, a fault is occurred on line C-D and next to breaker D. IED A can see the fault in its Z2 but its tripping will be prevented because no carrier signal is received from side B. Now, if breaker in D is tripped by its local IED before circuit breaker C, the fault current direction in line A-B will suddenly reverse. This may cause distance teleprotection in B to send carrier signal and therefore generate unwanted tripping of breaker A. To have a reliable and selective trip command in each side and solve the problem in these transition situations, some coordination time should be considered. For this purpose, IED sends signal with a setting delay time, “T_Tele Reversal”, if direction changes from reverse to forward. This setting delay time exceeds the period when both sides detect forward direction. Additionally, to have a reliable and selective trip command for another internal fault, both sides will trip only after receiving signal for at least 15msec. Figure 45 Direction reversing for external fault in parallel lines 1.2.4.2 Weak infeed feeders A special case for the application of permissive over reach transfer trip is that fast tripping must be achieved for a feeder that has a weak infeed at one end. In this case an additional echo-circuit with tripping supplement must be provided at this end. 115 Chapter 6 Teleprotection During a fault behind the weak infeed end, short circuit current flows through the protected feeder to the fault location. The IED at the weak infeed end will start with this current and recognize the fault in the reverse direction. It will therefore not send a release signal to the strong infeed end. The permissive over reach transfer trip protection is stable. During an internal fault near the strong source side the IED at the weak infeed end will not pickup, as insufficient current flows from this side into the feeder. The signal received by the weak infeed end is returned as an echo and allows the tripping at the strong infeed. Simultaneously with the echo, the circuit breaker at the weak infeed end may be tripped by the IED. Therefore by operating low voltage startup element and receiving carrier signal for at least 5 msec, distance carrier signal will be sent and prolonged for 200 msec to ensure the IED at the remote end (strong source) trips quickly and reliably. In this case local weak feeder generates trip command, too. In addition, in the case of carrier receiving and then CB opening, signal sending will be prolonged for 200 msec to correct and reliable operation of remote end. 1.3 Input and output signals IP1 Trip PhA IP2 Trip PhB IP3 Trip PhC IN Trip 3Ph UP1 UP2 UP3 Carr Recv(Dist) Relay Block AR Carr Send(Dist) Carr Fail(Dist) Tele_Dist_Trip Carr Fail(Dist) Weak End Infeed BI_DTT Send BO_DTT Send BI_DTT Recv BO_DTT Recv Relay Startup Relay Trip 116 Chapter 6 Teleprotection Table 23 Analog input list Signal Description IP1 Signal for current input 1 IP2 Signal for current input 2 IP3 Signal for current input 3 IN External input of zero-sequence current UP1 Signal for voltage input 1 UP2 Signal for voltage input 2 UP3 Signal for voltage input 3 Table 24 Binary input list Signal Description Carr Recv (Dist) Carrier signal received for Dist protection Carr Fail (Dist) Carrier signal failed for Dist protection BI_DTT Send Direct Tele trip send BI_DTT Recv Direct Tele trip receive Table 25 Binary output list Signal Description Relay Startup Relay Startup Relay Trip Relay Trip Trip PhA Trip phase A Trip PhB Trip phase B Trip PhC Trip phase C Trip 3Ph Trip three phases Relay Block AR Permanent trip Carr Send(Dist) Carrier signal sent for Dist protection Carr Fail(Dist) Carrier signal failed for Dist protection Tele_Dist_Trip Tele_Dist trip Weak End Infeed Weak End Infeed BO_DTT Send Direct tele trip send BO_DTT Recv Direct tele trip receive 1.4 Setting parameters 117 Chapter 6 Teleprotection 1.4.1 Setting list Table 26 Tele-Dist protection function setting list Abbr. Explanation T_Tele Reversal Time delay for direction reversing Default Unit 40 ms Min. Max. 0 100 Min. Max. Table 27 Tele-Dist protection binary setting list Abbr. Weak InFeed Explanation Default Unit Weak InFeed Mode 0 0 1 Blocking Mode 0 0 1 PUR Mode PUR Mode 0 0 1 POR Mode POR Mode 1 0 1 1 0 1 1 0 1 Blocking Mode first zone distance Func_Z1 protection Operating mode second zone distance Func_Z2 protection Operating mode 1.4.2 Setting explanation Conditions for enabling weak-source function: If only one side of the protected line is weak-source, the protection can be done selectively when the IED in weak side operates in Week InFeed mode. 1) POR mode: If this bit is set to “1/on” then the bits “Blocking mode” and “PUR mode” must be set to “0/off”. Under this mode, if zone2 module needs to send permissive signal, close the contacts of sending signal, “Carr Send (Dist)”, to send permissive signal. If zone2 module needs to stop sending permissive signal, open this contact to stop sending permissive signal. At the same time, the binary setting “Func_Z2” should be enabled. 2) PUR mode: If this bit is set to “1/on”, bits “Blocking mode” and “POR mode” must be set to “off”. Under this mode, if zone2 module needs to 3) 118 Chapter 6 Teleprotection send permissive signal, close the contacts of sending signal, “Carr Send(Dist)”, to send permissive signal. If zone2 module needs to stop sending permissive signal, open the contacts of sending signal to stop sending permissive signal. At the same time, both binary settings of “Func_Z1” and “Func_Z2” should be enabled. 1.5 Reports Table 28 Event report list Abbr. Meaning Tele_DIST_Trip Distance protection tripping using tele-protection signal Tele Evol Trip Tele evolvement trip Carr Stop(Dist) Carrier signal stopped for Dist protection, only in blocking mode Carr Stop(CBO) Carrier signal stopped for CB open, only in blocking mode Carr Stop(Weak) Carrier signal stopped for weak-infeed end , only in blocking mode Carr Send(Dist) Carrier signal sent for Dist protection Carr Send(CBO) Carrier signal sent for Dist protection Carr Send(Weak) Carrier signal sent for weak-infeed end Table 29 Alarm report list Abbr. Meaning Carr Fail (Dist) Carrier fail in distance tele-protection Tele Mode Alarm Tele Mode Alarm Table 30 Operation report list Abbr. Meaning Func_TeleDist On Distance tele-protection function on FuncTeleDist Off Distance tele-protection function off 1.6 Technical data Table 31 Tele-protection technical data Item Operating time Rang or Value Tolerance 25ms typically in permission mode for 21/21N, at 70% setting 119 Chapter 6 Teleprotection 2 Teleprotection for directional earth fault protection 2.1 Introduction Teleprotection for directional earth fault is an important feature in the transmission line protection. Similar to distance tele-protection, the function employs carrier sending and receiving feature, power line carrier (PLC) or dedicated fiber optic communication channels, to implement different tele-protection scheme configuration. 2.2 Protection principle To detect earth fault reliably and selectively, IED considers teleprotection scheme as following: Relay startup A N D Relay reset A N D Zero-Forward direction 3I0>3I0_Tele EF POR Mode on A N D A N D O R |200 0| Trip |T_tele EF| CARR (DEF) Send Relay trip A N D CARR (DEF) Received Tele_EF Inrush unblock Figure 46 Teleprotection for directional earth fault logic It will come into operation if binary setting “3I0_Tele_FUNC” is set to “1/on” and “POR” mode has been selected.In the case of an internal fault, the startup elements operate and DEF carrier signal will be sent if measured earth fault current exceed setting “3I0_Tele EF”, its direction indicates forward fault and its delay time setting “T0_tele EF” expired. In addition, if binary setting “Tele_EF Inrush Block” has been set to “1/on”, directional earth fault carrier sending can be blocked by inrush current detection. When an external fault occurs, fault direction in one end will be reverse. 120 Chapter 6 Teleprotection Therefore, in this end, no tripping command will be generated by directional earth fault carrier receiving. In addition, carrier sending will prolong for 200 msec for reliable operation of remote end. The prolongation of the send signal only comes into effect when the protection has already issued a trip command. This ensures that the permissive signal releases the opposite line end even if the earth fault is very rapidly cleared by a different independent protection. 2.2.1.1 Direction reversing for external fault For detail please refer “1.2.4.1Direction reversing for external fault”. 2.2.1.2 Weak infeed feeders For detail please refer “1.2.4.2Weak infeed feeders” 2.3 Input and output signals IP1 Trip PhA IP2 Trip PhB IP3 Trip PhC UP1 Trip 3Ph UP2 Relay Block AR UP3 Carr Send(DEF) Carr Recv(DEF) Carr Fail(DEF) BI_DTT Send Tele_DEF_Trip BI_DTT Recv Weak End Infeed Weak InFeed BO_DTT Send Carr Fail(DEF) BO_DTT Recv Relay Startup Relay Trip Table 32 Analog input list Signal Description IP1 Signal for current input 1 121 Chapter 6 Teleprotection Signal Description IP2 Signal for current input 2 IP3 Signal for current input 3 UP1 Signal for voltage input 1 UP2 Signal for voltage input 2 UP3 Signal for voltage input 3 Table 33 Binary input list Signal Description Carr Recv(DEF) Carrier signal received for DEF protection Carr Fail(DEF) Carrier signal failed for DEF protection BI_DTT Send Direct tele trip send BI_DTT Recv Direct Tele trip receive POR Mode POR Mode Weak InFeed Weak InFeed Mode Table 34 Binary output list Signal Description Relay Startup Relay Startup Relay Trip Relay Trip Trip PhA Trip phase A Trip PhB Trip phase B Trip PhC Trip phase C Trip 3Ph Trip three phases Relay Block AR Permanent trip Carr Send(DEF) Carrier signal sent for DEF protection Carr Fail(DEF) Carrier signal failed for DEF protection Tele_DEF_Trip Tele_DEF trip Weak End Infeed Weak End Infeed BO_DTT Send Direct Tele trip send BO_DTT Recv Direct Tele trip receive 2.4 122 Setting parameters Chapter 6 Teleprotection Setting lists 2.4.1 Table 35 Tele-EF protection function setting list Setting Unit T_Tele Reversal Min. Max. Default (Ir:5A/ (Ir:5A/ setting 1A) 1A) (Ir:5A/1A) 0 100 40 ms Description Time delay of power reserve zero sequence current threshold of 3I0_Tele A EF 0.08Ir 20Ir 0.2Ir tele-protection based on earth fault protection T0_Tele s EF 0.01 10 0.15 time delay of tele-protection based on earth fault protection Table 36Tele-EF protection binary setting list Abbr. Explanation POR Mode Default POR Mode Tele earth fault Func_Tele EF protection function Unit Min. Max. 1 0 1 0 0 1 0 0 1 0 0 1 Tele earth fault Tele_EF Inrush Block protection blocked by inrush Auto reclosure Tele_EF Init AR initiated by tele earth fault protection Note: For tele-EF protection, the setting binary “POR Mode” must be enabled, while the setting binary “PUR Mode” must be disabled. 2.5 Reports Table 37 Event report list Abbr. Meaning Tele evolvement trip, for example, A phase to earth fault happened, Tele Evol Trip and then B phase to earth fault followed, the latter is considered as an evolvement trip 123 Chapter 6 Teleprotection Abbr. Meaning Carr Send(DEF) Send carrier signal in DEF Tele_DEF_Trip Tele_DEF trip Table 38 Alarm report list Abbr. Meaning Carr Fail(DEF) Carrier fail in TeleDEF Tele Mode Alarm Tele Mode Alarm Table 39 Operation report list Abbr. Meaning Func_Tele_DEF On TeleDEF function on Func_TeleDEF Off TeleDEF function off 124 Chapter 6 Teleprotection 125 Chapter 7 Overcurrent protection Chapter 7 Overcurrent protection About this chapter This chapter describes the protection principle, input and output signals, parameter, IED report and technical data used for overcurrent protection. 126 Chapter 7 Overcurrent protection 1 Overcurrent protection 1.1 Introduction The directional/non-directional overcurrent protection function can be applied as backup protection functions in various applications for transmission lines. The directional overcurrent protection can be used based on both the magnitude of the fault current and the direction of power flow to the fault location. Main features of the overcurrent protection are as follows: 2 definite time stages and 1 inverse time stage Supporting of all IEC and ANSI predefined time-inverse characteristic curves (4 IEC and 7 ANSI) as well as an optional user defined characteristic Settable directional element characteristic angle, to satisfy different network conditions and applications Each stage can be set individually as directional/non-directional Each stage can be set individually for inrush restraint Cross blocking function for inrush restraint Settable maximum inrush current VT secondary circuit supervision for directional protection. Once VT failure happens, the directional stage can be set to be blocked automatically 1.2 Protection principle 1.2.1 Measured quantities The phase currents are fed to the IED via the input current transformers. The earth current 3I0 could also be connected to the starpoint of the current transformer set directly as measured quantity. 1.2.2 Time characteristic 127 Chapter 7 Overcurrent protection There are 2 definite time stages and 1 inverse time stage. All 12 kinds of the time-inverse characteristics are available. It is also possible to create a user defined characteristic. Each stage can operate in conjunction with the integrated inrush restraint, directional determination feature. Furthermore, each stage is independent from each other and can be combined as desired. Each phase current is compared with the corresponding setting value with delay time. If currents exceed the associated pickup setting value, after the time delay elapse, the trip command is issued. The pickup value for time-inverse stage can be set in setting value. The measured phase currents compare with corresponding setting value. The protection will issue a trip command with corresponding time delay if any phase exceeds the setting value. The time delay of time-inverse characteristic is calculated based on the type of the characteristic, the magnitude of the current and a time multiplier. For the time-inverse characteristic, both ANSI and IEC based standard curves are available and any user-defined characteristic can be defined using the following equation: A _ OC T i I _ OC Inv Inv P _ OC Inv B _ OC Inv K _ OC INV Equation 21 where: A_OC Inv: Time factor for inverse time stage B_OC Inv: Time delay for inverse time stage P_OC Inv: index for inverse time stage K_OC Inv: Time multiplier Inrush restraint feature The IED may detect large magnetizing inrush currents during transformer energizing. Inrush current comprises large second harmonic current which does not appear in short circuit current. Therefore, inrush current may affect the protection functions which will operate based on the fundamental component of the measured current. Accordingly, inrush restraint logic is provided to prevent overcurrent protection from maloperation. 128 Chapter 7 Overcurrent protection The inrush restraint feature operates based on evaluation of the 2 nd harmonic content which is present in measured current. The inrush condition is recognized when the ratio of second harmonic current to fundamental component exceeds the corresponding setting value for each phase. The setting value is applicable for both definite time stage and inverse time stage. The inrush restraint feature will be performed as soon as the ratio exceeds the set threshold. Furthermore, by recognition of the inrush current in one phase, it is possible to set the protection in a way that not only the phase with the considerable inrush current, but also the other phases are blocked for a certain time. This is achieved by cross-blocking feature integrated in the IED. Additionally, the inrush restraint feature has a maximum inrush current setting. Once the measuring current exceeds the setting, the overcurrent protection will not be blocked any longer. 1.2.3 Direciton determination feature The direction detection is performed by determining the position of current vector in directional characteristic. In other words, it is done by comparing phase angle between the fault current and the reference voltage. Figure 47 illustrates the direction detection characteristic for phase A element. Forward 90° IA Bisector Angle_Range OC Angle_OC 0° U BC_Ref -IA Figure 47 Overcurrent protection directional characteristic where: Angle_OC: The settable characteristic angle Angle_Range OC: 85º 129 Chapter 7 Overcurrent protection Table 40 presents the assignment of the applied measuring quantities used in direction determination for different fault types. In this way, healthy line to line voltages are used as reference voltage for determination of fault current direction in any phase. Table 40 Assignment of the current and corresponding reference voltage for directional element Phase Current Voltage A Ia U bc B Ib U ca C Ic U ab For three-phase short-circuit fault, without any healthy phase, memory voltage values are used to determine direction if the measured voltage values are not sufficient. During direction detection, if VT fail happens (a short circuit or broken wire in the voltage transformer's secondary circuit or voltage transformer fuse), maloperation may occur by directional overcurrent elements if there is not any monitoring on the measured voltage. In such situation, directional (if selected) overcurrent protection will be blocked. 1.2.4 Logic diagram The logic diagram for Phase-A has been shown in the below figure. The logic is valid for other phased in similar way. 130 Chapter 7 Overcurrent protection Ia>I_OC1 OC1 Direction Off OC1 Direction On AND Phase A forward AND VT fail OC1 Inrush Block Off <Imax_2H_UnBlk OC1 Inrush Block On AND Ia2/Ia1> T_OC1 Func_OC1 AND OC1 Inrush Block Off Trip OC1 Inrush Block On Cross blocking Ia2/Ia1 > Ib2/Ib1 > OR AND Ic2/Ic1 > Cross blocking T2h_Cross_Blk< Figure 48 Logic diagram for overcurrent protection 1.3 Input and output signals 131 Chapter 7 Overcurrent protection IP1 Trip PhA IP2 Trip PhB IP3 Trip PhC UP1 Trip 3Ph UP2 Relay Block AR OC1_Trip UP3 OC2_Trip OC Inv Trip Relay Startup Relay Trip Table 41 Analog input list Signal Description IP1 Current input for phase A IP2 Current input for phase B IP3 Current input for phase C UP1 Signal for voltage input 1 UP2 Signal for voltage input 2 UP3 Signal for voltage input 3 Table 42 Binary output list Signal Description Relay Startup Relay Startup Relay Trip Relay Trip Trip PhA Trip phase A Trip PhB Trip phase B Trip PhC Trip phase C Trip 3Ph Trip three phases Relay Block AR Permanent trip OC1_Trip 1st stage OC trip OC2_Trip 2 stage OC trip OC Inv Trip Time-inverse overcurrent trip 1.4 132 nd Setting parameters Chapter 7 Overcurrent protection Setting list 1.4.1 Table 43 Overcurrent protection function setting list Min. Max. Default setting (Ir:5A/1A) (Ir:5A/1A) (Ir:5A/1A) A 0.08Ir 20Ir 2Ir T_OC1 s 0 60 0.1 I_OC2 A 0.08Ir 20Ir 1Ir T_OC2 s 0 60 0.3 1 12 1 Setting Unit I_OC1 Description current threshold of overcurrent stage 1 delay time of overcurrent stage 1 current threshold of overcurrent stage 2 delay time of overcurrent stage 2 No.of inverse time Curve_OC Inv characteristic curve of overcurrent start current of I_OC Inv A 0.08Ir 20Ir 1Ir inverse time overcurrent time multiplier of customized inverse K_OC Inv 0.05 999 1 time characteristic curve for overcurrent time constant A of customized inverse A_OC Inv s 0 200 0.14 time characteristic curve for overcurrent time constant B of customized inverse B_OC Inv s 0 60 0 time characteristic curve for overcurrent index of customized P_OC Inv 0 10 0.02 inverse time characteristic curve for overcurrent the angle of Angle_OC Degre e 0 90 60 bisector of operation area of overcurrent 133 Chapter 7 Overcurrent protection Setting Unit Min. Max. Default setting (Ir:5A/1A) (Ir:5A/1A) (Ir:5A/1A) Description directional element Imax_2H_Un Blk the maximum A 0.25 20Ir 5Ir current to release harmornic block ratio of 2rd Ratio_I2/I1 0.07 0.5 0.2 harmonic to fundamental component T2h_Cross_B lk delay time of cross s 0 60 1 block by 2rd harmormic Table 44 Overcurrent protection binary setting list Name Description Func_OC1 Overcurrent stage 1 enabled or disabled OC1 Direction Direction detection for overcurrent stage 1 enabled or disabled OC1 Inrush Block Inrush restraint for overcurrent stage 1 enabled or disabled Func_OC2 Overcurrent stage 2 enabled or disabled OC2 Direction Direction of overcurrent stage 2 enabled or disabled OC2 Inrush Block Inrush restraint for overcurrent stage 2 enabled or disabled Func_OC Inv Time-Inverse stage for overcurrent enabled or disabled OC Inv Direction Direction detection for inverse time stage enabled or disabled OC Inv Inrush Block Inrush restraint for inverse time stage enabled or disabled 1.5 Reports Table 45 Event report list Information Description OC1 Trip Overcurrent stage 1 trip OC2 Trip Overcurrent stage 2 trip OC Inv Trip Inverse time stage of overcurrent protection trip 1.6 134 Technical data Chapter 7 Overcurrent protection NOTE: Ir: CT rated secondary current, 1A or 5A; Table 46 Overcurrent protection technical data Item Rang or Value Tolerance Definite time characteristics Current 0.08 Ir to 20.00 Ir ≤ ±3% setting or ±0.02Ir Time delay 0.00 to 60.00s, step 0.01s ≤ ±1% setting or +40ms, at 200% operating setting Inverse time characteristics Current 0.08 Ir to 20.00 Ir ≤ ±3% setting or ±0.02Ir IEC standard Normal inverse; ≤ ±5% setting + 40ms, at 2 Very inverse; <I/ISETTING < 20, in accordance Extremely inverse; with IEC60255-151 Long inverse ANSI Inverse; ≤ ±5% setting + 40ms, at 2 Short inverse; <I/ISETTING < 20, in Long inverse; accordance with ANSI/IEEE Moderately inverse; C37.112, Very inverse; Extremely inverse; Definite inverse ≤ ±5% setting + 40ms, at 2 user-defined characteristic <I/ISETTING < 20, in accordance T= with IEC60255-151 Time factor of inverse time, 0.005 to 200.0s, step 0.001s A Delay of inverse time, B 0.000 to 60.00s, step 0.01s Index of inverse time, P 0.005 to 10.00, step 0.005 Set time Multiplier for step 0.05 to 999.0, step 0.01 n: k Minimum operating time Maximum operating time 20ms 100s Reset mode instantaneous Directional element Operating area range Characteristic angle 0°to 90°, step 1° ≤ ±3°, at phase to phase voltage >1V 135 Chapter 7 Overcurrent protection Table 47 Inrush restraint function Item Upper function limit Range or value 0.25 Ir to 20.00 Ir Max current for inrush Tolerance ≤ ±3% setting value or ±0.02Ir restraint nd Ratio of 2 harmonic current 0.10 to 0.45, step 0.01 to fundamental component current Cross-block (IL1, IL2, IL3) (settable time) 136 0.00s to 60.00 s, step 0.01s ≤ ±1% setting or +40ms Chapter 7 Overcurrent protection 137 Chapter 8 Earth fault protection Chapter 8 Earth fault protection About this chapter This chapter describes the protection principle, input and output signals, parameter, IED report and technical data used for earth fault portection. 138 Chapter 8 Earth fault protection 1 Directional/Non-directional earth fault portection 1.1 Introduction In the grounded systems, extremely large fault resistances could cause calculated impedance to be outside the fault detection characteristic of the distance protection. Therefore, protection relay may not trip by distance protection function and need to be supplemented by other protections. So, the directional/non-directional earth fault protection function which can detect reliably high resistance faults is required. The directional earth fault protection allows the application of the protection IED also in systems where protection coordination depends on both the magnitude of the fault current and the direction of power flow to the fault location, for instance in case of parallel lines. Generally directional/non-directional protection function features following options: 2 definite time stages and 1 inverse stage (covers all IEC/ANSI characteristics) Individually selectable direction detection for each stage Negative sequence direction detection (selectable) in the cases that 3U0 is less than 1V and 3U2>3U0 1.2 Individually selectable inrush blocking for each stage Inrush blocking using 2nd harmonic measured phase current Settable maximum inrush current VT fail monitoring for directional earth fault protection Protection principle Three earth fault protection stages are provided, two definite time stages and one inverse time stage. All stages can operate in conjunction with the 139 Chapter 8 Earth fault protection integrated inrush restraint and directional functions. Furthermore, the stages are independent from each other and can be combined as desired. They can be enabled or disabled by dedicated binary settings. These binary settings include “Func_EF1”, “Func_EF2” and “Func_EF Inv”. For example, by applying setting “1/on” to “Func_EF1”, corresponding stage of earth fault protection would be enabled. Individual pickup value for each definite stage can be defined by settings “3I0_EF1” and “3I0_EF2”. By applying the settings, the measured zero sequence current is compared separately with the setting value for each stage. If the corresponding current is exceeded, startup signal will be reported. 1.2.1 Time delays characteristic The timer is set to count up for a pre-defined time delay. The time delay can be set for each definite stage individually through settings “T_EF1” and “T_EF1”. Accordingly, whenever the set time delays elapsed, a trip command is issued. For Time-inverse characteristic, the pickup value can be defined by setting “3I0_EF Inv”. The measured zero sequence current is compared with corresponding setting value. If it exceeds the setting, related signal will be reported and the tripping time is calculated according to the pre-defined characteristic. The tripping curve can be set as IEC or ANSI standard curves or any user-defined characteristic by following tripping time equation. A _ EF T i I _ EF Inv Inv P _ EF Inv B _ EF Inv K _ EF INV Equation 22 where: A_EF Inv: Time factor for inverse time stage B_EF Inv: Time delay for inverse time stage P_EF Inv: index for inverse time stage 140 Chapter 8 Earth fault protection K_EF Inv: Time multiplier By applying the desired setting values, the device calculates the tripping time from the zero sequence current. Once the calculated time elapsed, report “EF Inv Trip” will be issued. 1.2.2 Inrush restraint feature The integrated earth fault protection may detect large magnetizing inrush currents when a power transformer installed at downstream path is energized. The inrush current may be several times of the nominal current, and may last from several tens of milliseconds to several seconds. Inrush current comprises second harmonic as well as a considerable fundamental component. It is possible to apply the inrush restraint feature separately to each definite stage and inverse time-current stage of earth fault element by using binary setting “EF1 Inrush Block”, “EF2 Inrush Block” and “EF Inv Inrush Block”. By applying setting “1/on” to the binary settings, no trip command will be issued, if an inrush condition is detected. Since the inrush current contains a relatively large second harmonic component which is nearly absent during a fault current, the inrush restraint operates based on the evaluation of the second harmonic content which is present in the phase currents. Generally, inrush restraint for earth fault protection is performed based on the second harmonic contents of three phase currents. The inrush condition is recognized if the ratio of second harmonic content in each phase current to their fundamental component exceeds setting value “Ratio_I2/I1”. The setting is applicable to the both definite stages of earth fault protection element as well as the inverse time-current stage. As soon as the measured ratio exceeds the set threshold, a blocking is applied to those stages whose corresponding binary setting is considered to be block mode. Furthermore, if the fundamental component of each phase current exceeds the upper limit value “Imax_2H_UnBlk”, the inrush restraint will no longer be effective, since a high-current fault is assumed in this case. Figure 49 shows the logic of inrush restraint feature applied to earth fault protection. It is based on phase currents and can be applied to any stage individually. 141 Chapter 8 Earth fault protection Max(Ia1,Ib1,Ic1) < Imax_2H_UnBlk A N D Max(Ia2/Ia1, Ib2/Ib1, Ic2/Ic1)>Ratio_I2/I1 Inrush BLK 3I0 Figure 49 Inrush restraint blocking logic 1.2.3 Earth fault direction determination The integrated directional function can be applied to each stage of earth fault element via individual binary settings. These control words include “EF1 Direction”, “EF2 Direction” and “EF Inv Direction”. There are two possibilities for direction determination of earth faults. The first is based on zero sequence components and the second is based on negative sequence components. The following subsections go on to demonstrate basic principle of the two methods. 1.2.3.1 Zero sequence directional component In this method, the direction determination is performed by comparing the zero sequence quantities. In current path, the measured IN current is valid when the neutral current is connected to the device. In the voltage path, the calculated zero sequence voltage (3U0) is used as reference voltage. This can be performed when 3U0 magnitude is larger than 1V. In order to satisfy different network conditions and applications, the reference voltage can be rotated by adjustable angle “Angle_EF” between 0° and 90° in clockwise direction (negative sign). It should be noted that the settings affect all the directional stages of earth fault element. In this way, the vector of rotated reference voltage can be closely adjusted to the vector of fault current -3I0 which lags the fault voltage 3U0 by the fault angle Φd. This would provide the best possible result for the direction determination. The rotated reference voltage defines the forward and reverse area. The forward area is the range between -80°and +80°of the rotated reference voltage. If the vector of the fault current -3I0 is in this area, the device detects forward direction. Figure 50 shows an example of direction determination for a fault in phase A. As can be seen from the figure, fault current 3I0 lags from fault voltage Va. Accordingly, fault current -3I0 lags residual sequence voltage 3U0 by this angle. The reference voltage 3U0 is rotated to be as close as possible to -3I0 current. Furthermore, the forward area is depicted in the figure. 142 Chapter 8 Earth fault protection 3I 0 90° 0° 3U 0_Ref Angle_EF Angle_Range EF Forward -3 I 0 Bisector Figure 50 Characteristic of zero sequence directional element where: Angle_EF: The settable characteristic angle Angle_Range EF: 80º 1.2.3.2 Negative sequence directional component This method is particularly suitable when the zero sequence voltage has a small magnitude, for instance when a considerable zero sequence mutual coupling exists between parallel lines or when there is an unfavorable zero sequence impedance. In such cases it may be desirable to determine direction of fault current by using negative sequence components. To do so, it is required to set binary setting “EF U2/I2 Dir” to “1/On”. By applying this setting, the direction determination of earth fault current is performed by default using the zero sequence components. However, when the magnitude of zero sequence voltage falls below permissible threshold of 1V and negative sequence voltage is larger that 2V, the direction determination turns to use the negative sequence components. In this case, the direction determination is performed by comparing the negative sequence system quantities. To do so, three times of the calculated negative sequence current 3I2 (3I2=IA+a2IB+aIC) is compared with three times of the calculated negative sequence voltage 3V2 (3U2=UA+a2UB+aUC) as reference voltage, where a is equal to 120°. On the contrary, by applying setting “0/Off” to the binary setting “EF U2/I2 Dir”, the direction of earth fault current is only determined by using the zero 143 Chapter 8 Earth fault protection sequence components. In this regard, if the zero sequence voltage has a magnitude larger than 1V, proper determination of fault direction is warranted. The fault current -3I2 lags from the voltage 3U2. To satisfy different applications, the reference voltage can be rotated by adjustable angle “Angle_adjust_Neg” between 50°and 90°in clockwise direction (negative sign) to be as close as possible to the vector of fault current -3I2. This would provide the best possible outcome for the direction determination. The rotated reference voltage defines the forward and reverse area. The forward area is the range between -80°and +80°of the rotated reference voltage. If the vector of the fault current -3I2 is in this area, the device detects forward direction. Below figure shows an example of direction determination for a fault in phase A. 3I2 90° 0° 3 U 2_ Ref Angle_Neg Angle_Range Neg Forward -3 I 2 Bisector Figure 51 Characteristic of negative sequence directional element where: Angle_Neg: The settable characteristic angle Angle_Range Neg: 80º During direction decision, a VT Fail condition may result in false or undesired tripping by directional earth fault element. Therefore occurance of the VT Fail, directional earth fault protection will be blocked. 1.2.4 Logic diagram The tripping logics of directional/non-directional earth fault protection are 144 Chapter 8 Earth fault protection shown in below figure. As shown, the tripping logic of the earth fault protection will be affected individually by inrush and direction criteria. Whenever the zero sequence current exceeds the related setting value and other mentioned criteria is satisfied, corresponding timer will be started and tripping command will be generated by expiring the time setting. Forward direction(by zero sequence direction element) 3U0<1V O R A N D Forward direction(by negative sequence direction element) Forward EF U2/I2 Dir on Figure 52 Logic for directiion determination 3I0 > 3I0_EF1 EF1 Inrush Block off “0” Inrush BLK 3I0 EF1 Inrush Block on EF1 Direction off “1” Forward A Func_EF1 on N T_EF1 D EF1 Trip EF1 Direction on Figure 53 Tripping logic of the first stage of definite earth fault protection 3I0 > 3I0_EF2 EF2 Inrush Block off “0” Inrush BLK 3I0 EF2 Inrush Block on EF2 Direction off “1” Forward A N D Func_EF2 on T_EF2 EF2 Trip EF2 Direction on 145 Chapter 8 Earth fault protection Figure 54 Tripping logic of the second stage of definite earth fault protection 3I0 > 3I0_INV EF Inv Inrush Block off “0” Inrush BLK 3I0 EF Inv Inrush Block on EF Inv Direction off A N D “1” Forward Func_EF Inv on EF_INV Trip EF Inv Direction on Figure 55 Tripping logic of the inverse stage of earth fault protection The whole tripping logics for EF1 and EF2 are the same as Figure 56, if binary setting of “EF1 Init AR” and “EF2 Init AR” are enabled respectively. 1.3 Input and output signals IP1 Trip PhA IP2 Trip PhB IP3 Trip PhC IN Trip 3Ph UP1 Relay Block AR UP2 EF1_Trip UP3 EF2_Trip EF Inv_Trip Relay Startup Relay Trip Table 48 Analog input list Signal Description IP1 Phase-A current input IP2 Phase-B current input IP3 Phase-C current input IN External input of zero-sequence current UP1 Phase-A voltage input UP2 Phase-B voltage input 146 Chapter 8 Earth fault protection Signal Description UP3 Phase-C voltage input Table 49 Binary output list Signal Description Relay Startup Relay Startup Relay Trip Relay Trip Trip PhA Trip phase A Trip PhB Trip phase B Trip PhC Trip phase C Trip 3Ph Trip three phases Relay Block AR Permanent trip EF1_Trip EF2_Trip EF Inv_Trip 1st stage EF Trip 2nd stage EF Trip Inverse time stage EF Trip 1.4 Setting parameters 1.4.1 Setting lists Table 50 EF protection function setting list Setting Unit Min. Max. (Ir:5A/1A (Ir:5A/ ) 1A) Default setting (Ir:5A/1 Description A) zero sequence current 3I0_EF1 A 0.08Ir 20Ir 0.5Ir threshold of earth fault protection stage 1 T_EF1 s 0 60 0.1 delay time of earth fault protection stage 1 zero sequence current 3I0_EF2 A 0.08Ir 20Ir 0.2Ir threshold of earth fault protection stage 2 T_EF2 s 0 60 0.3 delay time of earth fault protection stage 2 147 Chapter 8 Earth fault protection Setting Unit Min. Max. (Ir:5A/1A (Ir:5A/ ) 1A) Default setting Description (Ir:5A/1 A) No. of inverse time Curve_EF Inv 1 12 1 characteristic curve of earth fault protection 3I0_EF Inv A 0.08Ir 20Ir start current of inverse time 0.2Ir earth fault protection time multiplier of customized K_EF Inv 0.05 999 inverse time characteristic 1 curve for earth fault protection time constant A of A_EF Inv s 0 200 customized inverse time 0.14 characteristic curve for earth fault protection time constant B of B_EF Inv s 0 60 customized inverse time 0 characteristic curve for earth fault protection index of customized inverse P_EF Inv 0 10 0.02 time characteristic curve for earht fault protection the angle of bisector of Angle_EF Degree 0 90 70 operation area of zero sequnce directional element the angle of bisector of Angle_Neg Degree 50 90 70 operation area of negative sequnce directional element Table 51 EF protection binary setting list Abbr. Explanation Default Unit Min. Max. 1 0 1 1 0 1 1 0 1 Operation for the first Func_EF1 definite stage of the earth fault protection Directional mode for EF1 Direction the first definite stage of the earth fault protection EF1 Inrush Block 148 Inrush restraint mode Chapter 8 Earth fault protection Abbr. Explanation Default Unit Min. Max. 1 0 1 1 0 1 1 0 1 1 0 1 0 0 1 0 0 1 0 0 1 0 0 1 0 0 1 for the first definite stage of the earth fault protection Operation for the Func_EF2 second definite stage of the earth fault protection Directional mode for EF2 Direction the first definite stage of the earth fault protection Inrush restraint mode EF2 Inrush Block for the second definite stage of the earth fault protection Operation for the Func_EF Inv time-inverse stage of the earth fault protection Directional mode for EF Inv Direction the time-inverse stage of the earth fault protection Inrush restraint mode EF Inv Inrush Block for the time-inverse stage of the earth fault protection Negative-sequence EF U2/I2 Dir direction detection element for earth fault protection Auto-reclosure EF1 Init AR initiated by the first definite stage of the earth fault protection Auto-reclosure EF2 Init AR initiated by the first definite stage of the earth fault protection 149 Chapter 8 Earth fault protection Setting calculation example 1.4.2 A B 127km C 139km 21/21N 21/21N PTR:400/0.1kV CTR:2000/5 Figure 57 400kV Overhead transmission line protection relay setting Here, a typical setting calculation of the inverse stage of the earth fault protection is presented. The characteristic is selected as IEC Normal Inverse. Additionally the function is set for operation in forward direction. It is assumed that maximum transmission power is equal to: 250 MVA Assuming a safety factor of 20% corresponds to Imax-Prim = 433 A 3I0inv prim = 0.3× Imax-Prim, So, 3I0_EF Inv =0.32 A By comparing the IEC Normal Inverse characteristic and IED setting values are considered as follows: 3I0_EF Inv Curve_EF Inv 1.5 150 0.32A 1(IEC Normal Invers) Inrush detection for Iverse stage active Directional (forward) for Iverse stage Yes 3U2/3I2 direction in addition to 3U0/3I0 Yes Reports Chapter 8 Earth fault protection Table 52 Event report list Information Description EF1 Trip 1 stage EF Trip EF2 Trip 2 stage EF Trip EF Inv Trip Inverse time stage EF Trip st nd Table 53 Operation report list Information Description Func_EF On EF function on Func_EF Off EF function off Func_EF Inv On Inverse stage EF function on Func_EF Inv Off Inverse stage EF function off 1.6 Technical data NOTE: Ir: CT rated secondary current, 1A or 5A; Table 54 Earth fault protection (ANSI 50N, 51N, 67N) Item Rang or value Tolerance Definite time characteristic Current Time delay 0.08 Ir to 20.00 Ir 0.00 to 60.00s, step 0.01s ≤ ±3% setting or ±0.02Ir ≤ ±1% setting or +40ms, at 200% operating setting Inverse time characteristics Current 0.08 Ir to 20.00 Ir ≤ ±3% setting or ±0.02Ir IEC standard Normal inverse; IEC60255-151 Very inverse; ≤ ±5% setting + 40ms, at 2 Extremely inverse; <I/ISETTING < 20 Long inverse ANSI Inverse; ANSI/IEEE C37.112, Short inverse; ≤ ±5% setting + 40ms, at 2 Long inverse; <I/ISETTING < 20 Moderately inverse; 151 Chapter 8 Earth fault protection Very inverse; Extremely inverse; Definite inverse IEC60255-151 user-defined characteristic ≤ ±5% setting + 40ms, at 2 T= <I/ISETTING < 20 Time factor of inverse time, A 0.005 to 200.0s, step 0.001s Delay of inverse time, B 0.000 to 60.00s, step 0.01s Index of inverse time, P 0.005 to 10.00, step 0.005 set time Multiplier for step n: k 0.05 to 999.0, step 0.01 Minimum operating time 20ms Maximum operating time 100s Reset mode instantaneous Directional element ≤ ±3°, at 3U0≥1V Operating area range of zero sequence directional element Characteristic angle 0°to 90°, step 1° ≤ ±3°, at 3U2≥2V Operating area range of negative sequence directional element Characteristic angle 152 50°to 90°, step 1° Chapter 8 Earth fault protection 153 Chapter 9 Emergency/backup overcurrent and earth fault protection Chapter 9 Emergency/backup overcurrent and earth fault protection About this chapter This chapter describes the protection principle, input and output signals, parameter, IED report and technical data included in emergency/backup overcurrent and earth fault protection. 154 Chapter 9 Emergency/backup overcurrent and earth fault protection 1 Emergency/backup overcurrent protection 1.1 Introduction In the case of VT Fail condition, all distance zones and protection functions related with voltage input are out of service. In this case, an emergency overcurrent protection comes into operation. Additionally, the protection can be set as backup non-directional overcurrent protection according to the user’s requirement. In case of emergency mode of operation, the function VT Fail supervision function should be enabled. The protection provides following features: One definite time stage One inverse time stage all kinds of IEC and ANSI time-inverse characteristics curve as well as optional user defined characteristic Inrush restraint function can be set for each stage separately Cross blocking of inrush detection Settable maximum inrush current 1.2 Protection principle 1.2.1 Tripping time characteristic The tripping time can be set as definite time delay or time-inverse characteristic. All (11) kinds of time-inverse characteristics are available. It is also possible to create a user-defined time characteristic. Each stage can operate in conjunction with the integrated inrush restraint which operates based on measured phase currents.Each phase current is compared with the corresponding setting value and related delay time. If currents exceed the associated pickup value, the trip command is issued after expiry of the set time delay. 155 Chapter 9 Emergency/backup overcurrent and earth fault protection Time-inverse characteristic is set according to the following equation: A _ EM / BU OC Inv T B _ EM / BU OC Inv K _ EM / BU OC INV P _ EM / BU OC Inv i I _ EM / BU OC Inv where: A_Em/BU OC Inv: Coefficient setting for emergency inverse time overcurrent B_Em/BU OC Inv: Time delay setting for emergency inverse time overcurrent P_Em/BU OC Inv: Index for inverse time overcurrent K_Em/BU OC Inv: Multiplier setting for emergency inverse time overcurrent By applying the desired setting values, the device calculates the tripping time from the measured current. Once the calculated time elapsed, repoprt “Em/Bu OC Trip” will be issued. 1.2.2 Inrush restraint feature The protection IED may detect large magnetizing inrush currents during transformer energizing. In addition to considerable unbalance fundamental current, inrush current comprises large second harmonic current which does not appear in short circuit current. Therefore, the inrush current may affect the protection functions which operate based on the fundamental component of the measured current. Accordingly, inrush restraint logic is provided to prevent emergency/backup overcurrent protection from maloperation. The inrush restraint feature operates based on evaluation of the 2 nd harmonic content which is present in measured current. The inrush condition is recognized if the ratio of second harmonic current to fundamental component exceeds the corresponding setting value. The setting value is applicable for both definite time stage and inverse time stage. The inrush restraint feature will be performed as soon as the ratio exceeds the set threshold. Furthermore, by recognition of the inrush current in one phase, it is possible to set the protection in a way that not only the phase with the considerable inrush current, but also the other phases of the protection are blocked for a certain time. This is achieved by cross-blocking feature integrated in the IED. The inrush restraint function has a maximum inrush current setting. Once the measuring current exceeds the setting, the protection will not be blocked any longer. 156 Chapter 9 Emergency/backup overcurrent and earth fault protection 1.2.3 Logic diagram Ia>I_Em/BU OC Func_Em/BU OC VT fail A N D Func_BU OC on Em/BU OC Inrush Block Off Ia<Imax_2H_UnBlk Ia2/Ia1>Ratio_I2/I1 A N D Em/BU OC Inrush Block On T_Em/BU OC Em/BU OC Inrush Block Off O R Trip Em/BU OC Inrush Block On Cross blocking Max{Ia, Ib, Ic}<Imax_2H_UnBlk A N D Ia2/Ia1 > Ib2/Ib1 > T2h_Cross_Blk Cross blocking O R Ic2/Ic1 > Figure 58 Emergency/backup protection function logic diagram 1.3 Input and output signals 157 Chapter 9 Emergency/backup overcurrent and earth fault protection IP1 Trip PhA IP2 Trip PhB IP3 Trip PhC Trip 3Ph UP1 Relay Block AR UP2 Em/BU OC1_Trip UP3 Em/BU OCInv_Trip Relay Startup Relay Trip Table 55 Analog input list Signal Description IP1 Phase-A current input IP2 Phase-B current input IP3 Phase-C current input UP1 Phase-A voltage input UP2 Phase-B voltage input UP3 Phase-C voltage input Table 56 Binary output list Signal Description Relay Startup Relay Startup Relay Trip Relay Trip Trip PhA Trip phase A Trip PhB Trip phase B Trip PhC Trip phase C Trip 3Ph Trip three phases Relay Block AR Permanent trip Em/BU OC1_Trip 1st stage emergency OC trip Em/BU OCInv_Trip Time-inverse emergency OC trip 1.4 Setting parameters 1.4.1 Setting lists 158 Chapter 9 Emergency/backup overcurrent and earth fault protection Table 57 Funciton setting list for emergency/backup overcurrent protection Min. Setting Unit (Ir:5A/ 1A) Max. (Ir:5 A/1A ) Default setting Description (Ir:5A/1A) current threshold of I_Em/BU OC A 0.08Ir 20Ir 1Ir emergency/backup overcurrent stage 1 T_Em/BU OC s 60 0.3 delay time of emergency/backup overcurrent stage 1 No.of inverse time characteristic Curve_Em/BU OC 1 Inv I_Inv_Em/BU OC 0 12 1 curve of emergency/backup overcurrent A 0.08Ir 20Ir 1Ir start current of inverse time emergency/backup overcurrent time multiplier of customized K_Em/BU OC Inv 0.05 999 1 inverse time characteristic curve for emergency/backup overcurrent time constant A of customized A_Em/BU OC Inv s 0 200 0.14 inverse time characteristic curve for emergency/backup overcurrent time constant B of customized B_Em/BU OC Inv s 0 60 0 inverse time characteristic curve for emergency/backup overcurrent index of customized inverse time P_Em/BU OC Inv 0 10 0.02 characteristic curve for emergency/backup overcurrent Imax_2H_UnBlk A Ratio_I2/I1 T2h_Cross_Blk s 0.25 20Ir 5Ir 0.07 0.5 0.2 0 60 1 the maximum current to release harmornic block ratio of 2rd harmonic to fundamental component delay time of cross block by 2rd harmormic Table 58 Binary setting list for emergency/backup overcurrent protection Name Description Func_BU OC Backup overcurrent protection enabled or disabled Func_Em/BU OC Emergency overcurrent protection stage 1 enabled or disabled Em/BU OC Inrush Block Inrush restraint of emergency/backup overcurrent protection stage 1 enabled or disabled 159 Chapter 9 Emergency/backup overcurrent and earth fault protection Name Description Func_Em/BU OC Inv Inverse time stage of emergency overcurrent protection enabled or disabled Em/BU OC Inv Inrush Inrush restraint of emergency/backup overcurrent protection for Block inverse stage enabled or disabled 1.5 Reports Table 59 Event report list Information Description Em/Bu OC Trip Emergency/backup overcurrent protection trip Em/Bu OCInv Trip Emergency/backup overcurrent protection inverse time stage trip 1.6 Technical data NOTE: Ir: CT rated secondary current, 1A or 5A; Table 60 T Emergency/backup overcurrent protection technical data Item Rang or Value Tolerance Definite time characteristics Current 0.08 Ir to 20.00 Ir Time delay 0.00 to 60.00s, step 0.01s ≤ ±3% setting or ±0.02Ir ≤ ±1% setting or +40ms, at 200% operating setting Inverse time characteristics Current 0.08 Ir to 20.00 Ir ≤ ±3% setting or ±0.02Ir IEC standard Normal inverse; ≤ ±5% setting + 40ms, at 2 Very inverse; <I/ISETTING < 20, in accordance Extremely inverse; with IEC60255-151 Long inverse ANSI Inverse; ≤ ±5% setting + 40ms, at 2 Short inverse; <I/ISETTING < 20, in Long inverse; accordance with ANSI/IEEE Moderately inverse; Very inverse; 160 C37.112, Chapter 9 Emergency/backup overcurrent and earth fault protection Extremely inverse; Definite inverse ≤ ±5% setting + 40ms, at 2 User-defined characteristic T= <I/ISETTING < 20, in accordance with IEC60255-151 Time factor of inverse time, 0.005 to 200.0s, step 0.001s A Delay of inverse time, B 0.000 to 60.00s, step 0.01s Index of inverse time, P 0.005 to 10.00, step 0.005 Set time Multiplier for step 0.05 to 999.0, step 0.01 n: k Minimum operating time Maximum operating time 20ms 100s Reset mode instantaneous 161 Chapter 9 Emergency/backup overcurrent and earth fault protection 2 Emergency/backup earth fault protection 2.1 Introduction In the case of VT Fail condition, all distance protection element and protection functions relating with voltage input are out of operation. In this case an emergency earth fault protection can come into operation. Additionally, the protection can be set as backup non directional earth fault protection according to the user’s requirement. In case of emergency mode of operation, the function VT Fail supervision should beenabled. The protection provides following features: One definite time stage One inverse time stage All kinds of IEC and ANSI inverse characteristics curve as well as optional user defined characteristic Inrush restraint can be selected individually for each stage Settable maximum inrush current CT secondary circuit supervision for earth fault protection. Once CT failure happens, all stages will be blocked Zero-sequence current is obtained from external input 2.2 Protection principle 2.2.1 Tripping time characteristic The tripping time can be set as definite time delay or time-inverse characteristic. All (11) kinds of time-inverse characteristics are available. It is also possible to create a user-defined time character ristic. Each stage can operate in conjunction with the integrated inrush restraint which operates based on measured phase currents. The external input earth current is compared with the corresponding setting value and related delay time. If current exceed the associated pickup value, the trip command is issued after expiry of the set time delay. 162 Chapter 9 Emergency/backup overcurrent and earth fault protection Time-inverse characteristic is set according to the following equation: A _ EM / BU EF Inv T B _ EM / BU EF Inv K _ EM / BU EF INV P _ EM / BU EF Inv i I _ EM / BU EF Inv where: A_Em/BU EF Inv: Coefficient setting for emergency zero-sequence inverse time B_Em/BU OC Inv: Time delay setting for emergency zero-sequence inverse time P_Em/BU OC Inv: Index for emergency zero-sequence inverse time K_Em/BU OC Inv: Multiplier setting for emergency zero-sequence inverse time By applying the desired setting values, the device calculates the tripping time from the measured current. Once the calculated time elapsed, repoprt “Em/Bu EF Trip” will be issued. 2.2.2 Inrush restraint feature The IED may detect large magnetizing inrush currents during transformer energizing. In addition to considerable unbalance fundamental current, inrush current comprises large second harmonic current which does not appear in short circuit current. Therefore, the inrush current may affect the protection functions which operate based on the fundamental component of the measured current. Accordingly, inrush restraint logic is provided to prevent emergency/backup earth fault protection from maloperation. The inrush restraint feature operates based on evaluation of the 2nd harmonic content which is present in measured current. The inrush condition is recognized when the ratio of second harmonic current to fundamental component exceeds the corresponding setting value for each phase. The setting value is applicable for both definite time stage and inverse time stage. The inrush restraint feature will be performed as soon as the ratio exceeds the set threshold. The inrush restraint function has a maximum inrush current setting. Once the measuring current exceeds the setting, the protection will not be blocked any longer. 163 Chapter 9 Emergency/backup overcurrent and earth fault protection Logic diagram 2.2.3 3I0>3I0_Em/BU EF Func_Em/BU EF on VT fail A N D Func_BU EF on T_Em/BU EF Trip Em/BU EF Inrush Block Off <Imax_2H_UnBlk Ratio_I2/I1> A N D Em/BU EF Inrush Block On Figure 59 Emergency/backup earth fault protection logic diagram 2.3 Input and output signals IP1 Trip PhA IP2 Trip PhB IP3 Trip PhC IN Trip 3Ph UP1 UP2 UP3 Relay Block AR Em/Bu EF Trip Em/Bu EFInv Trip Relay Startup Relay Trip Table 61 Analog input list Signal Description IP1 Phase-A current input IP2 Phase-B current input IP3 Phase-C current input IN External input of zero-sequence current UP1 Phase-A voltage input UP2 Phase-B voltage input UP3 Phase-C voltage input 164 Chapter 9 Emergency/backup overcurrent and earth fault protection Table 62 Binary output list Signal Description Relay Startup Relay Startup Relay Trip Relay Trip Trip PhA Trip phase A Trip PhB Trip phase B Trip PhC Trip phase C Trip 3Ph Trip three phases Relay Block AR Permanent trip Em/Bu EF Trip Emergency/Backup Earth Fault Trip Emergency/Backup Earth Fault inverse time Em/BU EFInv_Trip Trip 2.4 Setting parameters 2.4.1 Setting list Table 63 Emergency/backup earth fault protection function setting list Setting Un it Min. (Ir:5A/1 A) Max. (Ir:5A/1A) Default setting Description (Ir:5A/1A) zero sequence current 3I0_Em/BU EF A 0.08Ir 20Ir 0.2Ir threshold of earth fault protection stage 1 T_Em/BU EF s 0 60 0.3 delay time of earth fault protection stage 1 No. of inverse time Curve_Em/BU 1 EF Inv 12 1 characteristic curve of emergency/backup earth fault protection 3I0_Inv_Em/BU EF start current of inverse time A 0.08Ir 20Ir 0.2Ir emergency/backup earth fault protection time multiplier of customized K_Em/BU EF Inv 0.05 999 1 inverse time characteristic curve for emergency/backup earth fault protection 165 Chapter 9 Emergency/backup overcurrent and earth fault protection Setting Un it Min. (Ir:5A/1 A) Max. (Ir:5A/1A) Default setting Description (Ir:5A/1A) time constant A of customized inverse time A_Em/BU EF Inv s 0 200 0.14 characteristic curve for emergency/backup earth fault protection time constant B of customized inverse time B_Em/BU EF Inv s 0 60 0 characteristic curve for emergency/backup earth fault protection index of customized inverse P_Em/BU EF Inv 0 10 0.02 time characteristic curve for emergency/backup earht fault protection Imax_2H_UnBlk A Ratio_I2/I1 0.25 20Ir 5Ir 0.07 0.5 0.2 the maximum current to release harmornic block ratio of 2rd harmonic to fundamental component Table 64 Emergency/backup earth fault protection binary setting list Name Description Func_BU EF Backup earth fault protection enabled or disabled Func_Em/BU EF Emergency earth fault protection enabled or disabled Em/BU EF Inrush Block Func_Em/BU EF Inv Inrush restraint of emergency earth fault protection enabled or disabled Inverse time stage of emergency earth fault protection enabled or disabled Em/BU EF Inv Inrush Inrush restraint of emergency earth fault protection inverse stage Block enabled or disabled 2.5 166 IED report Chapter 9 Emergency/backup overcurrent and earth fault protection Table 65 Event report list Information Description Em/Bu EF Trip Emergency/backup earth fault protection trip Em/Bu EFInv Trip Emergency/backup earth fault protection inverse time stage trip 2.6 Technical data NOTE: Ir: CT rated secondary current, 1A or 5A; Table 66 Technical data for emergency/backup earth fault protection Item Rang or value Tolerance Definite time characteristic Current Time delay 0.08 Ir to 20.00 Ir 0.00 to 60.00s, step 0.01s ≤ ±3% setting or ±0.02Ir ≤ ±1% setting or +40ms, at 200% operating setting Inverse time characteristics Current 0.08 Ir to 20.00 Ir ≤ ±3% setting or ±0.02Ir IEC standard Normal inverse; ≤ ±5% setting + 40ms, at 2 Very inverse; <I/ISETTING < 20, in accordance Extremely inverse; with IEC60255-151 Long inverse ANSI Inverse; ≤ ±5% setting + 40ms, at 2 Short inverse; <I/ISETTING < 20, in Long inverse; accordance with ANSI/IEEE Moderately inverse; C37.112, Very inverse; Extremely inverse; Definite inverse ≤ ±5% setting + 40ms, at 2 User-defined characteristic T= <I/ISETTING < 20, in accordance with IEC60255-151 Time factor of inverse time, A 0.005 to 200.0s, step 0.001s Delay of inverse time, B 0.000 to 60.00s, step 0.01s Index of inverse time, P 0.005 to 10.00, step 167 Chapter 9 Emergency/backup overcurrent and earth fault protection 0.005 Set time Multiplier for step n: k 0.05 to 999.0, step 0.01 Minimum operating time 20ms Maximum operating time 100s Reset mode instantaneous 168 Chapter 9 Emergency/backup overcurrent and earth fault protection 169 Chapter 10 Switch-onto-fault protection Chapter 10 Switch-Onto-Fault protection About this chapter This chapter describes the protection principle, input and output signals, parameter, IED report and technical data included in Switch-Onto-Fault protection function. 170 Chapter 10 Switch-onto-fault protection 1 Switch-Onto-Fault protection 1.1 Introduction The IED has a high speed switch-onto-fault protection function to clear immediately faults on the feeders that are switched onto a high-current short circuit. Its main application may be in the case that a feeder is energized when the earth switch is closed. 1.2 Function principle 1.2.1 Function description Switch-onto-fault protection can be enabled by binary setting “SOTF FUNC”. If this is set to “1/on”, switch-onto-fault protection will be active. Conversely, setting “SOTF FUNC” to “0/ off” will disable the function. The energization of the feeder is determined by the circuit breaker state recognition function. The prerequisite for switch-onto-fault operation is that circuit breaker has been open for 10 seconds, or the binary input “MC/AR Block”changes from 1 to 0. SOTF function will be active after rising edge of receiving signal “MC/AR block” and if relay does not startup. The SOTF sequence will be inactive 1 second after falling edge of signal “MC/AR block” ” if no fault has been occured in the system. SOTF protection operates based on three elements: distance protection, overcurrent protection and zero sequence (earth fault) protection. Distance element of switch-onto-fault protection will trip instantaneously, without any delay time, if calculated impedance lies in the protected zones (zone 1, zone 2 or zone 3) and the maximum {Ia(b,c)}>I_SOTF_Dist. In addition, switch-onto-fault protection is supplemented by overcurrent and earth fault protections, and can generate trip command after settable delay times (“T_OC_SOTF” and “T_EF_SOTF”). For “T_EF_SOTF”, since IED needs to consider that three phases of CB are not closed at the same time, it is recommended to set this value. (Besides, the program has already considered 40ms time delay itself. ) Overcurrent elements works based on maximum measured phase currents and will trip after related delay time if maximum phase current exceeds setting “I_SOTF”. Similarly, earth fault protection operates if measured zero sequence current exceeds setting value 171 Chapter 10 Switch-onto-fault protection of “3I0_SOTF”. Additionally, it can be selected that overcurrent and earth fault element of switch-onto-fault protection to be blocked in the case of inrush current. If binary setting “SOTF Inrush Block” set to “1/on”, blocking will be applied to distance zone 2, zone 3, overcurrent and earth fault element. Setting to “0/off” will lead to ignoring of the inrush blocking for switch-onto-fault function. Similarly, if the measured current value exceeds the setting “Imax_2H_UnBlk”, it is assumed that a short circuit happened and inrush blocking will not be considered. Figure 60 shows the tripping logic diagram of switch-onto-fault protection. Logic diagram 1.2.2 Func_SOTF on BI“MC/AR Block”1 to 0 O R BI “PhA CB Open”0 to 1 BI “PhB CB Open”0 to 1 BI “PhC CB Open”0 to 1 10s A N D Relay Startup A N D Relay startup Trip Impedance within zone1,2,3 Over current operation Zero-sequence operation T_OC_SOTF T_EF_SOTF O R A N D T_Relay Reset SOTF Inrush Block Off SOTF Inrush Block On Cross blocking A N D No fault Figure 60 SOTF protection logic 1.3 172 Input and output signals Relay reset Chapter 10 Switch-onto-fault protection IP1 Relay Block AR IP2 SOTF Trip IP3 Relay Startup Relay Trip IN UP1 UP2 UP3 PhA CB Open PhB CB Open PhC CB Open MC/AR Block Table 67 Analog input list Signal Description IP1 Signal for current input 1 IP2 Signal for current input 2 IP3 Signal for current input 3 IN External input of zero-sequence current UP1 Signal for voltage input 1 UP2 Signal for voltage input 2 UP3 Signal for voltage input 3 Table 68 Binary input list Signal Description PhA CB Open PhaseA CB open PhB CB Open PhaseB CB open PhC CB Open PhaseC CB open MC/AR Block AR block Table 69 Binary output list Signal Description Relay Startup Relay Startup 173 Chapter 10 Switch-onto-fault protection Signal Description Relay Trip Relay Trip Relay Block AR Permanent trip SOTF Trip SOTF Trip 1.4 Setting parameters 1.4.1 Setting lists Table 70 SOTF protection function setting list Setting Uni Min. Max. t (Ir:5A/1A) (Ir:5A/1A) Default setting Description (Ir:5A/1A) phase current threshold of I_SOTF A 0.08Ir 20Ir 2Ir overcurrent element of switch onto fault protection T_OC_SOT F delay time of overcurrent s 0 60 0 element of switch onto fault protection zero sequnce current 3I0_SOTF A 0.08Ir 20Ir 0.5Ir threshold of switch onto fault protection delay time of zero sequce T_EF_SOTF s 0 60 0.1 overcurrent of switch onto fault protection Table 71 SOTF protection binary setting list Abbr. Func_SOTF SOTF Inrush Block 174 Explanation SOTF protection operating mode SOTF protection blocked by inrush Default Unit Min. Max. 1 0 1 1 0 1 Chapter 10 Switch-onto-fault protection 1.4.2 Setting calculation example The data related to 400kV overhead line are used here to set overcurrent and zero-sequence element of SOTF function.It is assumed that maximum transmission power is equal to: 250 MVA Assuming a safety factor of 20% corresponds to Imax-Prim =433 A I>>> prim=2.0 × Imax-Prim So, I>>> sec=2.17A 3I0>>> prim=0.3 × Imax-Prim So, 3I0>>> sec= 0.32A 1.5 High Speed SOTF-O/C is ON I>>> Pickup 2.17A 3I0>>> Pickup 0.32A Time for I>>> SOTF 0.00sec Time for 3I0>>> SOTF 0.00sec Inrush detection for SOTF current active Reports Table 72 Event report list Information Description Dist SOTF Ttrip Distance relay speed up trip after switching on to fault (SOTF) EF SOTF Trip Earth Fault relay speed up after SOTF OC SOTF Trip Overcurrent relay speed up after SOTF 175 Chapter 10 Switch-onto-fault protection Table 73 Operation report list Information Description Func_SOTF On SOTF function on Func_SOTF Off SOTF function off 1.6 Technical data NOTE: Ir: CT rated secondary current, 1A or 5A; Table 74 Switch-onto-fault protection technical data Item Rang or Value Tolerance Phase current 0.08 Ir to 20.00 Ir ≤ ±3% setting or ±0.02Ir Zero-sequence current 0.08 Ir to 20.00 Ir ≤ ±3% setting or ±0.02Ir Time delay of phase 0.00s to 60.00s, step 0.01s ≤ ±1% setting or +40ms, at overcurrent Time delay of zero sequence current 176 200% operating setting 0.00s to 60.00s, step 0.01s ≤ ±1% setting or +40ms, at 200% operating setting Chapter 10 Switch-onto-fault protection 177 Chapter 11 Overload protection Chapter 11 Overload protection About this chapter This chapter describes the protection principle, input and output signals, parameter, IED report and technical data used for overload protection function. 178 Chapter 11 Overload protection 1 Overload protection 1.1 Protection principle 1.1.1 Function description In some applications, the load is flowing through the feeder can be so important for operator of the system to consider corrective actions. Therefore, the IED can supervise load flow in real time. If allof the phase currents are greater than the dedicated setting, the protection will report an overload alarm when the time setting “T_OL Alarm” has been elapsed. Logic diagram 1.1.2 Ia>I_OL Alarm O R Ib>I_OL Alarm T_OL Alarm A N D Ic>I_OL Alarm Func_OL on Trip Figure 61 Logic diagram for overload protection 1.2 Input and output signals IP1 IP2 IP3 Table 75 Analog input list Signal Description IP1 Signal for current input 1 179 Chapter 11 Overload protection Signal Description IP2 Signal for current input 2 IP3 Signal for current input 3 1.3 Setting parameters 1.3.1 Setting lists Table 76 Function setting list for overload protection Uni Setting t I_OL Alarm T_OL Alarm Default Min. (Ir:5A/1A ) Max. setting (Ir:5A/1A) (Ir:5A/1 Description A) A 0.08Ir 20Ir 2Ir s 0.1 6000 20 current threshold of overload alarm delay time of overload alarm Table 77 Binary setting list for overload protection Name Description Func_OL Overload function enabled or disabled 1.4 Reports Table 78 Alarm information list Information Description Overload Alarm Overload protection alarm 180 Chapter 11 Overload protection 181 Chapter 12 Overvoltage protection Chapter 12 Overvoltage protection About this chapter This chapter describes the protection principle, input and output signals, parameter, IED report and technical data used for overvoltage protection. 182 Chapter 12 Overvoltage protection 1 Overvoltage protection 1.1 Introduction Voltage protection has the function to protect electrical equipment against overvoltage condition. Abnormally high voltages often occur e.g. in low loaded, long distance transmission lines, in islanded systems when generator voltage regulation fails, or after full load shutdown of a generator from the system. Even if compensation reactors are used to avoid line overvoltage by compensation of the line capacitance and thus reduction of the overvoltage, the overvoltage will endanger the insulation if the reactors fail (e.g. fault clearance). The line must be disconnected within very short time. The protection provides the following features: Two definite time stages Each stage can be set to alarm or trip Measuring voltage between phase-earth voltage and phase-phase (selectable) Settable dropout ratio 1.2 Protection principle 1.2.1 Phase to phase overvoltage protection All the three phase voltages are measured continuously, and compared with the corresponding setting value. If a phase voltage exceeds the set thresholds, “U_OV1” or “U_OV2”, after expiry of the time delays, “T_OV1’ or “T_OV2”, the protection IED will issue alarm signal or trip command according to the user’s requirement. There are two stages included in overvoltage protection, each stage can be set to alarm or trip separately in binary setting, and the time delay for each stage can be individually set. Thus, the alarming or tripping can be time-coordinated based on how severe the voltage increase, e.g. in case of 183 Chapter 12 Overvoltage protection high overvoltage, the trip command will be issued with a short time delay, whereas for the less severe overvoltage, trip or alarm signal can be issued with a longer time delay. Additionaly, the dropout ratio of the overvoltage protection can be set in setting “Dropout_OV”. Therefore, the trip command of overvoltage is reset if the measured voltage comes bellow the ratio value mentioned in this setting. 1.2.2 Phase to earth overvlotage protection The phase to earth overvoltage protection operates just like the phase to phase protection except that it detects phase to earth voltages. 1.2.3 Logic diagram Ua>U_OV1 Ub>U_OV1 O R OV PE on Uc>U_OV1 OV Trip on Trip Uab>U_OV1 Ubc>U_OV1 O R OV PE off O R T_OV OV Trip off Uca>U_OV1 Figure 62 Logic diagram for overvoltage protection 1.3 184 Input and output signals Alarm Chapter 12 Overvoltage protection UP1 Trip PhA UP2 Trip PhB UP3 Trip PhC Trip 3Ph Relay Block AR OV1 Alarm OV2 Alarm OV1_Trip OV2_Trip Relay Startup Relay Trip Table 79 Analog input list Signal Description UP1 Signal for voltage input 1 UP2 Signal for voltage input 2 UP3 Signal for voltage input 3 Table 80 Binary output list Signal Description Relay Startup Relay Startup Relay Trip Relay Trip Trip PhA Trip phase A Trip PhB Trip phase B Trip PhC Trip phase C Trip 3Ph Trip three phases Relay Block AR Permanent trip OV1 Alarm 1st stage OV alarm OV2 Alarm 2 stage OV alarm OV1_Trip 1st stage OV trip OV2_Trip 2nd stage OV trip 1.4 nd Setting parameters 185 Chapter 12 Overvoltage protection 1.4.1 Setting lists Table 81 Function setting list for overvoltage protection Parameter Range Default Unit U_OV1 40~200 65 V T_OV1 0~60 0.3 s U_OV2 40~200 63 V T_OV2 0~60 0.6 s Dropout_OV 0.9~0.99 0.95 Description Voltage setting for overvoltage protection stage 1 Time setting for overvoltage protection stage 1 Voltage setting for overvoltage protection stage 2 Time setting for overvoltage protection stage 2 Dropout ratio for overvoltage protection Table 82 Binary setting list for overvoltage protection Name Description Func_OV1 First stage overvoltage protection operating mode OV1 Trip First stage overvoltage protection trip/alarm mode Func_OV2 Second stage overvoltage protection operating mode OV2 Trip Second stage overvoltage protection trip/alarm mode OV PE Overvoltage protection based on phase-to-earth voltage 1.5 Reports Table 83 Event report list Information Description OV1 Trip Overvoltage stage 1 trip OV2 Trip Overvoltage stage 2 trip 186 Chapter 12 Overvoltage protection Table 84 Alarm report list Information Description OV1 Alarm Overvoltage stage 1 alarm OV2 Alarm Overvoltage stage 2 alarm 1.6 Technical data Table 85 Technical data for overvoltage protection Item Voltage connection Rang or Value Phase-to-phase voltages or Tolerance ≤ ±3 % setting or ±1 V phase-to-earth voltages Phase to earth voltage 40 to 100 V, step 1 V ≤ ±3 % setting or ±1 V Phase to phase voltage 80 to 200 V, step 1 V ≤ ±3 % setting or ±1 V Reset ratio 0.90 to 0.99, step 0.01 ≤ ±3 % setting Time delay 0.00 to 60.00 s, step 0.01s ≤ ±1 % setting or +50 ms, at 120% operating setting Reset time <40ms 187 Chapter 13 Undervoltage protection Chapter 13 Undervoltage protection About this chapter This chapter describes the protection principle, input and output signals, parameter, IED report and technical data used for undervoltage protection function. 188 Chapter 13 Undervoltage protection 1 Undervoltage protection 1.1 Introduction Voltage protection has the function to protect electrical equipment against undervoltage. The protection can detect voltage collapse on transmission lines to prevent unwanted operation condition and stability problems. The protection provides the following features: Two definite time stages Each stage can be set to alarm or trip Measuring voltage between phase-earth voltage and phase-phase (selectable) Current criteria supervision Circuit breaker aux. contact supervision VT secondary circuit supervision, the undervoltage function will be blocked when VT failure happens Settable dropout ratio, both for single phase and three phases 1.2 Protection principle 1.2.1 Phase to phase underovltage protection All the three phase voltages are measured continuously, and compared with the corresponding setting value. If one phase voltage or three phase voltages (by “UV PE” and “UV Chk All Phase”) falls below the set thresholds, “U_UV1” or “U_UV2”, after expiry of the time delays, “T_OV1’ or “T_OV2”, the protection IED will issue alarm signal or trip command according to the user’s requirement. There are two stages included in overvoltage protection; each stage can be set to alarm or trip separately by binary settings, “UV1 Trip” and “UV2 Trip”. Thus, the alarming or tripping can be time-coordinated based on how severe the voltage collapse, e.g. in case of severe undervoltage happens, the trip 189 Chapter 13 Undervoltage protection command will be issued with a short time delay, whereas for the less severe undervoltage, trip or alarm signal can be issued with a longer time delay. The undervoltage protection integrated can also be set for selection of the measureing quantities. In this way, the user can select that the undervoltage detection occurs when at least one phase sees voltage reduction or the reduction of voltage should occur in all three phases. This feature can be selected using binary setting “UV Chk All Phase”. Additionaly, the dropout ratio of the undervoltage protection can be set in setting “Dropout_UV”. Therefore, the trip command of overvoltage is reset if the measured voltage comes bellow the ratio value mentioned in this setting. 1.2.2 Phase to earth undervoltage protection The phase to earth undervoltage protection operates just like the phase to phase protection except that the quantities considered are phase to earth voltages. 1.2.3 Depending on the VT location Depending on the configuration of the substations, the voltage transformers are located on the busbar side or on the line side. This results in a different behaviour of the undervoltage protection. 1.2.3.1 VT at busbar side A B C Protection IED A B C N Figure 63 VT located at busbar side When a tripping command is issued and the circuit breaker is open, the voltage remains on the source side while the line side voltage drops to zero. In this case, undervoltage protection may remain pickup. Therefore, to 190 Chapter 13 Undervoltage protection resolve the problem, additional current criterion is considered. With the current criterion, undervoltage protection can be maintained only when the undervoltage criterion satisfied and a minimum current are exceeded the setting “I_UV_Chk”. The undervoltage protection would dropout as soon as the current falls below the corresponding setting. If the voltage transformer is installed on the busbar side and it is not desired to check the current flow, this criterion can be disabled by binary setting “UV Chk Current”. 1.2.3.2 Circuit breaker auxiliary contact checking The IED can operate based on circuit breaker auxiliary contact supervision criterion, for more security. With this feature, the IED would issue a trip command when the circuit breaker is closed. This criterion can be enabled or disabled via binary setting “UV Chk CB”. If it is not desired to supervise the circuit breaker position for undervoltage protection, the criterion can be disabled by the binary setting. 1.2.4 Logic diagram 191 Chapter 13 Undervoltage protection Ua<U_UV O R Ub<U_UV UV Chk All Phase off Uc<U_UV O R UV PE on Ua<U_UV A N D Ub<U_UV UV Chk All Phase on Uc<U_UV O R Uab<U_UV O R Ubc<U_UV UV Chk All Phase on Uca<U_UV O R UV PE off Uab<U_UV A N D Ubc<U_UV UV Chk All Phase off Uca<U_UV UV Chk CB off BI_PhA CB Open O R BI_PhB CB Open BI_PhC CB Open O R UV Trip on Trip UV Chk CB on Func_UV IA(IB,IC)>I_UV_ Chk T_UV UV Chk Current on O R UV Chk Current off A N D Alarm UV Trip off VT Fail on VT fail BI_AR In Progress 1 Figure 64 Logic diagram for undervoltage protection 1.3 192 Input and output signals Chapter 13 Undervoltage protection IP1 Trip PhA IP2 Trip PhB IP3 Trip PhC UP1 Trip 3Ph UP2 Relay Block AR UP3 UV1 Alarm PhA CB Open UV2 Alarm PhB CB Open UV1_Trip PhC CB Open UV2_Trip AR In Progress Relay Startup Relay Trip Table 86 Analog input list Signal Description IP1 Phase-A current input IP2 Phase-B current input IP3 Phase-C current input UP1 Phase-A voltage input UP2 Phase-B voltage input UP3 Phase-C voltage input Table 87 Binary input list Signal Description PhA CB Open PhaseA CB open PhB CB Open PhaseB CB open PhC CB Open PhaseC CB open AR In Progress AR In Progress Table 88 Binary output list Signal Description Relay Startup Relay Startup Relay Trip Relay Trip Trip PhA Trip phase A 193 Chapter 13 Undervoltage protection Signal Description Trip PhB Trip phase B Trip PhC Trip phase C Trip 3Ph Trip three phases Relay Block AR Permanent trip UV1 Alarm 1st stage UV alarm UV2 Alarm 2nd stage UV alarm UV1_Trip 1st stage UV trip UV2_Trip 2nd stage UV trip 1.4 Setting parameters 1.4.1 Setting lists Table 89 Undervoltage protection function setting list Setting Uni t Min. (Ir:5A/1A ) Max. (Ir:5A/1A) Default setting Description (Ir:5A/1A) voltage threshold of undervoltage U_UV1 V 5 150 40 T_UV1 s 0 60 0.3 U_UV2 V 5 150 45 T_UV2 s 0 60 0.6 delay time of undervoltage stage 2 1.01 2 1.05 reset ratio of undervoltage 0.08Ir 2Ir 0.1Ir current threshold of undervoltage Dropout_U V I_UV_Chk A stage 1 delay time of undervoltage stage 1 voltage threshold of undervoltage stage 2 Table 90 Undervoltage protection binary setting list Name Description Func_UV1 Undervoltage stage 1 enabled or disabled UV1 Trip Undervotage stage 1 tripping enabled or disabled Func_UV2 Undervoltage stage 2 enabled or disabled UV2 Trip Undervotage stage 2 tripping enabled or disabled UV PE Phase to phase measured for undervoltage protection 194 Chapter 13 Undervoltage protection Name Description UV Chk All Phase Three phase voltage checked for undervoltage protection UV Chk Current Current checked for undervoltage protection UV Chk CB CB Aux. contact checked for undervoltage protection 1.5 Reports Table 91 Event report list Information Description UV1 Trip Undervoltage stage 1 trip UV2 Trip Undervoltage stage 2 trip Table 92 Alarm report list Information Description UV1 Alarm Undervoltage stage 1 alarm UV2 Alarm Undervoltage stage 2 alarm 1.6 Technical data Table 93 Technical data for undervoltage protection Item Voltage connection Rang or Value Phase-to-phase voltages or Tolerance ≤ ±3 % setting or ±1 V phase-to-earth voltages Phase to earth voltage 5 to 75 V , step 1 V ≤ ±3 % setting or ±1 V Phase to phase voltage 10 to 150 V, step 1 V ≤ ±3 % setting or ±1 V Reset ratio 1.01 to 2.00, step 0.01 ≤ ±3 % setting Time delay 0.00 to 120.00 s, step 0.01 s ≤ ±1 % setting or +50 ms, at 80% operating setting Current criteria 0.08 to 2.00 Ir ≤ ±3% setting or ±0.02Ir 195 Chapter 13 Undervoltage protection Reset time 196 ≤ 50 ms Chapter 13 Undervoltage protection 197 Chapter 14 Circuit breaker failure protection Chapter 14 Circuit breaker failure protection About this chapter This chapter describes the protection principle, input and output signals, parameter, IED report and technical data used for circuit breaker failure protection function. 198 Chapter 14 Circuit breaker failure protection 1 Circuit breaker failure protection 1.1 Introduction The circuit breaker failure (CBF) protection function monitors proper tripping of the relevant circuit breaker. Normally, the circuit breaker should be tripped and therefore interrupt the fault current whenever a short circuit protection function issues a trip command. Circuit breaker failure protection provides rapid back-up fault clearance, in the event of circuit breaker malfunction in respond to a trip command. Line2 Line3 LineN Bus Trip IFAULT Figure 65 Simplified function diagram of circuit breaker failure protection with current flow monitoring The Main CBF protection is as following: Two trip stages (local CB retripping and busbar trip) Internal/external initiation Single/three phase CBF initiation CB Aux checking Current criteria checking (including phase, zero and negative sequence current) 199 Chapter 14 Circuit breaker failure protection 1.2 Function Description Circuit breaker failure protection can be enabled or disabled, via binary setting “Func_CBF”. If the binary setting is set to “1/on”, CBF protection would be switched on. In this case, by operation of a protection function and subsequent CBF initiation, a preset timer counts up. The CBF function issues a local trip command (e.g. via a second trip coil) if the circuit breaker has not been opened after expiry of the time setting “T_CBF1”. If the circuit breaker doesn’t respond to the repeated trip command until time setting “T_CBF2”, the function issues a trip command to isolate the fault by tripping other surrounding backup circuit breakers (e.g. the other CBs connected to the same bus section with faulty CB). Initiation of CBF protection can be carried out by both internal and external protection functions. If CBF needs to be initiated by means of external protection functions, specified binary inputs (BI) should be marshaled to the equipment. 4 digital inputs are provided for externally initiation of the integrated CBF function. The first one is 3-phase CBF initiation “3Ph Init CBF”. For phase segregated initiation other three binary inputs has been considered as “PhA Init CBF”, “PhB Init CBF” and “PhC Init CBF”. These can be applicable if the circuit breaker supports separated trip coil for each phase and single phase auto-recloser function is active on the feeder. Additionally, internal protection functions that can initiate the CBF protection integrated are as following: Distance protection Teleprotection based on distance/DEF Directional earth fault protection Over current protection SOTF protection Emergency/Backup EF protection Emergency/Backup overcurrent protection Overvoltage protection (trip stages) External initiation using binary input There are two criteria for breaker failure detection: the first one is to check whether the actual current flow effectively disappeared after a tripping command had been issued. The second one is to evaluate the circuit breaker auxiliary contact status. Since circuit breaker is supposed to be open when 200 Chapter 14 Circuit breaker failure protection current disappears from the circuit, the first criterion (current monitoring) is the most reliable means for IED to be informed about proper operation of circuit breaker if the CBF initiating function had been based on current measurement. Therefore,, both current monitoring and CB aux.contact are applied to detect circuit breaker failure condition. In this context, the monitored current of each phase is compared with the pre-defined setting, “I_CBF”. Furthermore, it is also possible to select current checking in case of zero-sequence and negative-sequence currents via binary setting “CBF Chk 3I0/3I2”. If setting “1/On” is applied at the binary setting, zero-sequence and negative-sequence currents are calculated and compared with user-defined settings. Corresponding settings include “3I0_CBF” for zero-sequence current and “3I2_CBF” for negative-sequence current. The logic for current criterion evaluation for CBF protection shows in Figure 66. 1.2.1 Current criterion evaluation Ia > I_CBF CBF Chk 3I0/3I2 Off 3I0 > 3I0_CBF 3I2 > 3I2_CBF Ib > I_CBF O R A N D O R CBF Curr. Crit. A O R CBF Curr. Crit. B O R CBF Curr. Crit. C CBF Chk 3I0/3I2 on Ic > I_CBF Ib > I_CBF CBF Chk 3I0/3I2 Off 3I0 > 3I0_CBF 3I2 > 3I2_CBF Ic > I_CBF O R A N D CBF Chk 3I0/3I2 on Ia > I_CBF Ic > I_CBF CBF Chk 3I0/3I2 Off 3I0 > 3I0_CBF 3I2 > 3I2_CBF Ib > I_CBF Ia > I_CBF O R A N D CBF Chk 3I0/3I2 on O R CBF Curr. Crit. 3P 201 Chapter 14 Circuit breaker failure protection Figure 66 Current criterion evaluation for CBF protection 1.2.2 Circuit breaker auxiliary contact evaluation For protection functions where the tripping criterion is not dependent on current measurement, current flow is not a suitable criterion for detection of circuit breaker operation. In this case, the position of the circuit breaker auxiliary contact should be used to determine if the circuit breaker properly operated. It is possible to evaluate the circuit breaker operation from its auxiliary contact status. To do so, binary setting “CBF Chk CB Status” should be set to “1/On” to integrate circuit breaker auxiliary contacts into CBF function. A precondition for evaluating circuit breaker auxiliary contact is that open status of CB should be marshaled to digital inputs of ““PhA CB Open”, “PhB CB Open” and “PhC CB Open”. The logic for evaluation of CB auxiliary contact for CBF protection is shown in Figure 67. In this logic, the positions of the circuit breaker poles are determined from CB aux. contacts if IED doesn’t detect current flowing in the diagram. 202 Chapter 14 Circuit breaker failure protection BI_PhA CB Open BI_PhA Init CBF CBF Curr. Crit. A A N D O R BI_PhB CB Open BI_PhB Init CBF CBF Curr. Crit. B A N D O R BI_PhC CB Open BI_PhC Init CBF CBF Curr. Crit. C A N D O R A N D CB A is closed A N D CB B is closed A N D CB C is closed A N D CB ≥1P is closed BI_PhA CB Open A N D BI_PhB CB Open BI_PhC CB Open 3Ph Init CBF CBF Curr. Crit. 3P O R A N D Figure 67 Circuit breaker auxiliary contact evaluation 1.2.3 Logic diagram 203 Chapter 14 Circuit breaker failure protection BI_PhA Init CBF BI_PhB Init CBF BI_PhC Init CBF O R T_alam Init CBF Err BI_3Ph Init CBF BI_PhA Init CBF A N D O R PhA Init CBF A N D O R PhB Init CBF A N D O R PhC Init CBF Inter PhA Init CBF BI_PhB Init CBF Inter PhB Init CBF BI_PhC Init CBF Inter PhC Init CBF BI_3Ph Init CBF A N D A N D A N D A N D O R 3Ph Init CBF Inter 3Ph Init CBF Figure 68 Internal and external initiation Note: In this figure, “T_alarm” is a time period already designed in the program. T_alarm equals to max {15s, T_CBF1+1s, T_CBFs+1s, T_Dead Zone +1s}, when the corresponding functions are enabled. After this period, the alarm event “BI_Init CBF Err ” will be issued. 204 Chapter 14 Circuit breaker failure protection CB A is closed CBF Chk CB Status CBF Curr. Crit. A O R PhA Init CBF CB B is closed CBF Chk CB Status CBF Curr. Crit. B A N D CB C is closed CBF Chk CB Status CBF Curr. Crit. C PhC Init CBF CBF Chk CB Status 3Ph Init CBF CBF B Startup O R A N D CB ≥1P is closed CBF A Startup O R PhB Init CBF CBF Curr. Crit. 3P A N D O R A N D CBF C Startup CBF 3P Startup Figure 69 CBF protection startup logic 205 Chapter 14 Circuit breaker failure protection CBF A Startup T_CBF1 CBF B Startup T_CBF1 CBF C Startup T_CBF1 A N D A N D A N D CBF 3P Startup O R O R CBF1 Trip PhA O R CBF1 Trip PhB O R CBF1 Trip PhC CBF1 Trip 3Ph T_CBF1 Figure 70 First stage CBF tripping logic CBF A Startup CBF B Startup CBF C Startup CBF1 Trip 3Ph O R O R O R T_CBF 1P Trip 3P CBF 1P Trip 3P On T_CBF 1P Trip 3P CBF 1P Trip 3P On O R CBF1 1P Trip 3P T_CBF 1P Trip 3P CBF 1P Trip 3P On Figure 71 Three-phase local CB re-tripping from single phase CBF initiation CBF A Startup T_CBF2 CBF B Startup T_CBF2 CBF C Startup T_CBF2 CBF 3P Startup T_CBF2 206 O R CBF2 Trip Chapter 14 Circuit breaker failure protection Figure 72 Second stage CBF tripping logic 1.3 Input and output signals IP1 Trip PhA IP2 Trip PhB IP3 Trip PhC IN Trip 3Ph PhA Init CBF Relay Block AR PhB Init CBF CBF1_Trip PhC Init CBF CBF 1P Trip 3P 3Ph Init CBF CBF2 Trip PhA CB Open Relay Startup PhB CB Open Relay Trip PhC CB Open Table 94 Analog input list Signal Description IP1 signal for current input 1 IP2 signal for current input 2 IP3 signal for current input 3 IN External input of zero-sequence current Table 95 Binary input list Signal Description PhA Init CBF PhaseA initiate CBF PhB Init CBF PhaseB initiate CBF PhC Init CBF PhaseC initiate CBF 3Ph Init CBF Three phase initiate CBF PhA CB Open PhaseA CB open PhB CB Open PhaseB CB open PhC CB Open PhaseC CB open 207 Chapter 14 Circuit breaker failure protection Table 96 Binary output list Signal Description Relay Startup Relay Startup Relay Trip Relay Trip Trip PhA Trip phase A Trip PhB Trip phase B Trip PhC Trip phase C Trip 3Ph Trip three phases Relay Block AR Permanent trip CBF1 Trip 1st stage CBF operation CBF 1P Trip 3P Three phase re-tripping for single phase CBF CBF2 Trip 2nd stage CBF operation 1.4 Setting parameters 1.4.1 Setting lists Table 97 CBF protection function setting list Default U Min. ni (Ir:5A t /1A) I_CBF A 0.08Ir 20Ir 1Ir 3I0_CBF A 0.08Ir 20Ir 0.2Ir 3I2_CBF A 0.08Ir 20Ir 0.2Ir T_CBF1 s 0 32 0 delay time of CBF stage 1 T_CBF2 s 0.1 32 0.2 delay time of CBF stage 2 s 0.05 32 0.1 Setting T_CBF 1P Trip 3P Max. setting (Ir:5A/1A) (Ir:5A/1A Description ) phase current threshold of circuit breaker failure protection zero sequence current threshold of circuit breaker failure protection negative sequence current threshold of circuit breaker failure protection delay time of three phase tripping of CBF stage 1 Table 98 CBF protection binary setting list Abbr. 208 Explanation Default Unit Min. Max. Chapter 14 Circuit breaker failure protection Abbr. Explanation Default CBF protection Func_CBF operating mode Unit Min. Max. 1 0 1 0 0 1 1 0 1 0 0 1 Three pole tripping in CBF 1P Trip 3P the case of single pole failure zero and negative sequence current CBF Chk 3I0/3I2 checking by CBF protection CB Auxiliary contact CBF Chk CB Status checking for CBF protection 1.5 Reports Table 99 Event report list Information Description CBF StartUp CBF Startup CBF1 Trip 1st stage CBF operation tripping CBF2 Trip 2nd stage CBF operation tripping CBF 1P Trip 3P Three phase tripping for single pole CBF Table 100 Alarm report list Information Description BI_Init CBF Err CBF initiation BI error Table 101 Operation report list Information Description Func_CBF On CBF function on Func_CBF Off CBF function off 209 Chapter 14 Circuit breaker failure protection 1.6 Technical data NOTE: Ir: CT rated secondary current, 1A or 5A; Table 102 Breaker failure protection technical data Item Rang or Value Tolerance 0.08 Ir to 20.00 Ir ≤ ±3% setting or ±0.02Ir Time delay of stage 1 0.00s to 32.00 s, step 0.01s ≤ ±1% setting or +25 ms, at Time delay of stage 2 0.00s to 32.00 s, step 0.01s 200% operating setting Reset time of stage 1 < 20ms phase current Negative sequence current zero sequence current 210 Chapter 14 Circuit breaker failure protection 211 Chapter 15 Dead zone protection Chapter 15 Dead zone protection About this chapter This chapter describes the protection principle, input and output signals, parameter, IED report and technical data used for dead zone (short zone) protection function. 212 Chapter 15 Dead zone protection 1 Dead zone protection 1.1 Introduction The IED provides this protection function to protect dead zone, the short area between circuit breaker and CT in the case that CB is open. Therefore, by occurrence of a fault in dead zone, the short circuit current is measured by protection IED while CB auxiliary contacts indicate the CB is open. 1.2 Protection principle In the case of feeders with bus side CTs, once a fault occurs in the dead zone, the IED trips the relevant busbar zone CBs. Tripping concept is illustrated in the below figure. Trip Bus IFAULT Line1 Line2 LineN Legend: Opened CB Closed CB Figure 73 Tripping logic for applying bus side CT For feeders with line side CTs, when a fault occurs in the dead zone, protection IED sends a transfer trip to remote end IED to isolate the fault. 213 Chapter 15 Dead zone protection Inter trip Bus IFAULT Line1 Line2 Trip LineN Relay Legend: Opened CB Closed CB Figure 74 Dead zone tripping concept for feeders with line side CTs 1.2.1 Function description Internal/external initiation Self-adaptive for bus side CT or line side CT. For bus side CTs, the dead zone protection will select to trip breakers on other lines connected to the same busbar. For line side CTs, the dead zone protection will select trip opposite side breakers on the same line. 1.2.2 214 Logic diagram Chapter 15 Dead zone protection PhA Init CBF PhB Init CBF PhC Init CBF O R 3Ph Init CBF CBF Curr. Crit. A CBF Curr. Crit. B A N D O R CBF Curr. Crit. C BI_PhA CB Open BI_PhB CB Open BI_PhC CB Open T_Dead Zone Dead Zone Trip Func_Dead Zone On A N D Figure 75 Dead zone protection logic 1.3 Input and output signals IP1 Relay Block AR IP2 DeadZone_Trip Relay Startup IP3 PhA Init CBF Relay Trip PhB Init CBF PhC Init CBF 3Ph Init CBF PhA CB Open PhB CB Open PhC CB Open Table 103 Analog input list Signal Description IP1 signal for current input 1 IP2 signal for current input 2 IP3 signal for current input 3 215 Chapter 15 Dead zone protection Table 104 Binary input list Signal Description PhA Init CBF PhaseA initiate CBF PhB Init CBF PhaseB initiate CBF PhC Init CBF PhaseC initiate CBF 3Ph Init CBF Three phase initiate CBF PhA CB Open PhaseA CB open PhB CB Open PhaseB CB open PhC CB Open PhaseC CB open Table 105 Binary output list Signal Description Relay Startup Relay Startup Relay Trip Relay Trip DeadZone_Trip DeadZone Trip Relay Block AR Permanent trip 1.4 Setting parameters 1.4.1 Setting lists Table 106 Dead zone protection function setting list Abbr. Explanation T_Dead Zone Default Unit Min. Max. 1 s 0 32 Unit Min. Max. 0 1 Time delay setting for dead zone protection Table 107 Dead zone protection binary setting list Abbr. Func_Dead Zone 216 Explanation Dead Zone protection operating mode Default 1 Chapter 15 Dead zone protection 1.5 Reports Table 108 Event report list Information Description Dead Zone Trip Dead zone trip Table 109 Operation report list Information Description Func_DZ On DZ function on Func_DZ Off DZ function off 1.6 Technical data NOTE: Ir: CT rated secondary current, 1A or 5A; Item Rang or Value Tolerance Current 0.08 Ir to 20.00 Ir ≤ ±3% setting or ±0.02Ir Time delay 0.00s to 32.00s, step 0.01s ≤ ±1% setting or +40 ms, at 200% operating setting 217 Chapter 16 STUB protection Chapter 16 STUB protection About this chapter This chapter describes the protection principle, input and output signals, parameter, IED report and technical data used for STUB protection function. 218 Chapter 16 STUB protection 1 STUB protection 1.1 Introduction Capacitor Voltage Transforemers (CVTs) are commonly installed at the line side of transmission lines. Therefore, for the cases that transmission line is taken out of service and the line disconnector is open, the distance protection will not be able to operate and must be blocked. The STUB protection protects the zone between the CTs and the open disconnector. The STUB protection is enabled when the open position of the disconnector is informed to the IED through connected binary input. The function supports one definite stage with the logic shown inbelow figure. 1.2 Protection principle 1.2.1 Function description Busbar A CB1 CT1 Stub fault Feeder1 Disconnector1 CB3 CT3 Feeder2 Disconnector2 CT2 CB2 Busbar B 219 Chapter 16 STUB protection Figure 76 STUB fault at circuit breaker arrangement If IED detects short circuit current flowing while the line disconnector is open, STUB fault is detected for the short circuit in the area between the current transformers and the line disconnector. Here, the summation of CT1 and CT3 presents the short circuit current. The STUB protection is an overcurrent protection which is only in service if the status of the line disconnector indicates the open condition. The binary input must therefore be informed via an auxiliary contact of the disconnector. In the case of a closed line disconnector, the STUB protection is out of service. The STUB protection stage provides one definite time overcurrent stage with settable delay time. This protection function can be enabled or disabled via the binary setting “Func_STUB”. Corresponding current setting value can be inserted in “I_STUB” setting. The IED generate trip command whenever the time setting “T_STUB” is elapsed. 1.2.2 Logic diagram Ia>I_STUB Ib>I_STUB O R Ic>I_STUB Func_STUB BI_STUB Enable A N D T_STUB Figure 77 Logic diagram for STUB protection 1.3 Input and output signals IP1 Relay Block AR IP2 STUB Trip IP3 Relay Startup STUB Enable 220 Relay Trip Permanent trip Chapter 16 STUB protection Table 110 Analog input list Signal Description IP1 signal for current input 1 IP2 signal for current input 2 IP3 signal for current input 3 Table 111 Binary input list Signal Description STUB Enable STUB protection enabled Table 112 Binary output list Signal Description Relay Startup Relay Startup Relay Trip Relay Trip STUB Trip STUB Trip Relay Block AR Permanent trip 1.4 Setting parameters 1.4.1 Setting lists Table 113 Setting value list for STUB protection Min. Setting Unit (Ir:5A/1 A) Max. (Ir:5A/1A) Default setting Description (Ir:5A/1A) I_STUB A 0.08Ir 20Ir 1Ir T_STUB s 0 60 1 current threshold of STUB protection delay time of STUB protection 221 Chapter 16 STUB protection Table 114 Binary setting list for STUB protection Name Description STUB Enable Enable or disable STUB protection Func_STUB Stub protection operating mode 1.5 Reports Table 115 Event report list Information Description STUB Trip STUB protection trip 1.6 Technical data NOTE: Ir: CT rated secondary current, 1A or 5A; Table 116 Technical data for STUB protection Item Rang or Value Tolerance Current 0.08 Ir to 20.00 Ir ≤ ±3% setting or ±0.02Ir Time delay 0.00s to 60.00s, step 0.01s ≤ ±1% setting or +40 ms, at 200% operating setting 222 Chapter 16 STUB protection 223 Chapter 17 Poles discordance protection Chapter 17 Poles discordance protection About this chapter This chapter describes the protection principle, input and output signals, parameter, IED report and technical data for poles discordance protection. 224 Chapter 17 Poles discordance protection 1 Poles discordance protection 1.1 Introdcution Under normal operating condition, all three poles of the circuit breaker must be closed or open at the same time. The phase separated operating circuit breakers can be in different positions (close-open) due to electrical or mechanical failures. This can cause negative and zero sequence currents which gives thermal stress on rotating machines and can cause unwanted operation of zero sequence or negative sequence current functions. Single pole opening of the circuit breaker is permitted only in the short period related to single pole dead times, otherwise the breaker is tripped three pole to resolve the problem. If the problem still remains, the remote end can be intertripped via circuit breaker failure protection function to clear the unsymmetrical load situation. The pole discordance function operates based on information from auxiliary contacts of the circuit breaker for the three phases with additional criteria from unsymmetrical phase current. 1.2 Protection principle 1.2.1 Function description The CB position signals are connected to IED via binary input in order to monitor the CB status. Poles discordance condition is established when binary setting “Func_PD” is set to “1/on” and at least one pole is open and at the same time not all three poles are closed. The auxiliary contacts of the circuit breakers are checked with corresponding phase currents for plausibility check. Error alarm “CB Err Blk PD” is reported after 5 sec whenever CB auxiliary contacts indicate that one pole is open but at the same time current is flowing through the pole. Additionally the function can be informed via binary setting “PD Chk 3I0/3I2” for additionaly zero and negative sequence current as well as current criteria involved in CBF protection. Pole discordance can be detected when current is not flowing through all three poles. When current is flowing through all three 225 Chapter 17 Poles discordance protection poles, all three poles must be closed even if the breaker auxiliary contacts indicate a different status. 1.2.2 Logic diagram A N D BI_PhA CB Open Ia > 0.06Ir A N D BI_PhB CB Open Ib > 0.06Ir O R A N D BI_PhC CB Open Ic > 0.06Ir BI_PhA CB Open A N D 5s CB Err Blk PD A N D BI_PhB CB Open BI_PhC CB Open A N D BI_PhA CB Open Ia < 0.06Ir A N D BI_PhB CB Open Ib < 0.06Ir A N D O R T_PD Func_PD On A N D BI_PhC CB Open Ic< 0.06Ir 3I2 > 3I2_PD O R 3I0 > 3I0_PD PD Chk 3I0/3I2 on PD Chk 3I0/3I2 off BI_AR In Progress 1 Figure 78 Logic diagram for poles discordance protection 1.3 226 Input and output signals PD Trip Chapter 17 Poles discordance protection IP1 Trip 3Ph IP2 Relay Block AR IP3 PD_Trip Relay Startup IN Relay Trip PhA CB Open PhB CB Open PhC CB Open AR In Progress Table 117 Analog input list Signal Description IP1 Phase-A current input IP2 Phase-B current input IP3 Phase-C current input IN External input of zero-sequence current Table 118 Binary input list Signal Description PhA CB Open Phase A CB open PhB CB Open Phase B CB open PhC CB Open Phase C CB open AR In Progress AR in progress, to block poles discordance operation Table 119 Binary output list Signal Description Relay Startup Relay Startup Relay Trip Relay Trip PD_Trip PD Trip Relay Block AR Permanent trip CB Err Blk PD Pole discordance blocked by CB error PD Trip Fail Pole discordance trip fail 227 Chapter 17 Poles discordance protection 1.4 Setting parameters 1.4.1 Setting lists Table 120 Function setting list for poles discordance protection Min. Setting Unit (Ir:5A/1 A) Max. Default setting (Ir:5A/1A) (Ir:5A/1A) Description zero sequence current 3I0_PD A 0 20Ir 0.4Ir threshold of pole discordance protection negative sequence current 3I2_PD A 0 20Ir 0.4Ir threshold of pole discordance protection T_PD s 0 60 2 delay time of pole discordance protection Table 121 Binary setting list for poles discordance protection Name Description Func_PD Enable or disable poles discordance protection PD Chk 3I0/3I2 Enable or disable 3I0/3I2 criteria 1.5 Reports Table 122 Event report list Information Description PD Startup Poles discordance protection startup PD Trip Poles discordance protection trip 228 Chapter 17 Poles discordance protection Table 123 Alarm report list Information Description CB Err Blk PD Circuit breaker error block poles discordance protection PD Trip Fail Poles discordance protection trip fail 1.6 Technical data NOTE: Ir: CT rated secondary current, 1A or 5A; Table 124 Technical data for poles discordance protection Item Rang or Value Tolerance Current 0.08 Ir to 20.00 Ir ≤ ±3% setting or ±0.02Ir Time delay 0.00s to 60.00s, step 0.01s ≤ ±1% setting or +40 ms, at 200% operating setting 229 Chapter 18 Synchro-check and energizing check function Chapter 18 Synchro-check and energizing check function About this chapter This chapter describes the protection principle, input and output signals, parameter, IED report and technical data used in synchro-check and energizing check function. 230 Chapter 18 Synchro-check and energizing check function 1 Synchro-check and energizing check function 1.1 Introduction The synchronism and voltage check function ensures that the stability of the network is not endangered when switching a line onto a busbar. The voltage of the feeder to be energized is compared to that of the busbar to check conformances in terms of magnitude, phase angle and frequency within certain tolerances. The synchro-check function checks whether the voltages on both sides of the circuit breaker are synchronize, or at least one side is dead to ensure closing can be done safely. When comparing the two voltages, the synchro check uses the voltages from busbar and outgoing feeder. If the voltage transformers for the protective functions are connected to the line side, the reference voltage has to be connected to a busbar voltage. If the voltage transformers for the protective functions are connected to the busbar side, the reference voltage has to be connected to a line voltage. Note: 1.2 The reference voltage (single phase voltage) must be phase to earth voltage. The voltage phase for synchro-ckeck and energizing check can be identified automatically by protection IED and there is no need to be set by user. Function principle Synchro-check function can operate in several modes of operation, including full synchro-check mode, energizing mode (dead line or bus check) and override (synchro-check bypass) mode. 1.2.1 Synchro-check mode 231 Chapter 18 Synchro-check and energizing check function The voltage difference, frequency difference and phase angle difference values are measured in the IED and are available for the synchro-check function for evaluation. By synchronization request, the synchronization conditions will be checked continuously. If the line voltages and busbar voltages are larger than the value of “Umin_Syn” and meet the synchronization conditions, synchronized reclosure can be performed. At the end of the dead time, synchronization request will be initiated and the synchronization conditions are continuously checked to be met for a certain time during maximal extended time “T_MaxSynExt”. By satisfying synch-check condition in this period, the monitor timer will stop and close command will be issued for AR. Before releasing a close command at synchronization conditions, all of the following conditions should be satisfied: 1.2.2 All three phases voltage U(a,b,c) should be above the setting value “Umin_Syn”. The reference voltage should be above the setting value “Umin_Syn”. The voltage difference should be within the permissible deviation “U_Syn Diff” The angle difference should be within the permissible deviation “Angle_Syn Diff” The frequency difference should be within the permissible deviation “Freq_Syn Diff” Energizing ckeck mode In this mode of operation, the low voltage (dead) condition is checked continuously whenever synchronization check is requested. If the line voltages are less than “Umax_Energ”, reclosure can be performed. If the line voltages and busbar voltages are all larger than “Umin_Syn”, the check mode will automatically turn to full synchronization check mode. In auto-recloser procedure, synchronization check request is triggered at the end of the dead time. If the low voltage conditions are continuously met for a certain numbers and during maximum extended time “T_MaxSynExt”, the 232 Chapter 18 Synchro-check and energizing check function monitor timer will stop and close command will be issued for AR. Before releasing a close command in low voltage conditions, one of the following conditions need to be checked according to requirement: Energizing check for dead line and live bus for AR enabled or disabled, when the control word “AR_EnergChkDLLB” is on Energizing check for live line and live bus for AR enabled or disabled, when the control word “AR_EnergChkLLDB” is on Energizing check for dead line and dead bus for AR enabled or disabled, when the control word “AR_EnergChkDLDB” is on 1.2.3 Override mode In this mode, autoreclosure will be released without any check. 1.2.4 Logic diagram 233 Chapter 18 Synchro-check and energizing check function AR_Syn Check off Ua(Ub,Uc) >Umin_Syn AR_Syn Check on A N D Ux>Umin_Syn Anglediff<Angle_Syn Diff O R A N D O R T_Syn Check Synchr-check or energizing check meet Freqdiff<Freq_Syn Diff Udiff<U_Syn Diff AR_EnergChkDLLB off Ux <Umax_Energ Ua(Ub,Uc) >Umin_Syn VT_Line off AR_EnergChkDLLB on A N D Ua(Ub,Uc) <Umax_Energ VT_Line off A N D A N D Ua(Ub,Uc) <Umax_Energ O R O R AR_EnergChkDLDB off AR_EnergChkDLDB on Ux<Umax_Energ O R AR_EnergChkLLDB off AR_EnergChkDLLB on Ux>Umin_Syn T_MaxSynExt O R AR_EnergChkDLLB off AR_EnergChkDLLB on Ux >Umin_Syn Ua(Ub,Uc) <Umax_Energ VT_Line on Ux<Umax_Energ Ua(Ub,Uc) >Umin_Syn O R A N D AR_EnergChkLLDB off A N D AR_EnergChkLLDB on O R VT_Line on Figure 79 Logic diagram for synchro-check functio 1.3 234 Input and output signals Synchr-check or energizing check fail Chapter 18 Synchro-check and energizing check function UP1 UP2 UP3 UPX Table 125 Analog input list Signal Description UP1 Phase-A voltage input UP2 Phase-B voltage input UP3 Phase-C voltage input UPX Reference voltage input 1.4 Setting parameters 1.4.1 Setting lists Table 126 Synchro-check function setting list Min. Max. Default (Ir:5A (Ir:5A/1 setting /1A) A) (Ir:5A/1A) Degree 1 80 30 V 1 40 10 Hz 0.02 2 0.05 s 0 60 0.05 s 0.05 60 10 duration of quit synchronizing Umin_Syn V 30 65 40 Minimum voltage of synchronizing Umax_Energ V 10 50 30 Setting Angle_Syn Diff U_Syn Diff Freq_Syn Diff T_Syn Check T_MaxSynE xt Unit Description angle difference threshold of synchronizing voltage difference threshold of synchronizing frequency difference threshold of synchronizing delay time of synchronizing Maximum voltage of unenergizing checking 235 Chapter 18 Synchro-check and energizing check function Table 127 Synchro-check binary setting list Name Description AR_Override Override mode for AR enabled or disabled AR_EnergChkDLLB Dead line live bus of energizing check for AR enabled or disabled AR_EnergChkLLDB Live line dead bus of energizing check for AR enabled or disabled AR_EnergChkDLDB Dead line dead bus of energizing check for AR enabled or disabled AR_Syn check Synchronization check for AR enabled or disabled 1.4.2 Setting explanation “Angle_Syn Diff”:Maximum allowable phase difference between bus voltage and line angle under synchronization check mode. 1) “U_Syn Diff”:Maximum allowable phase difference between bus voltage and line voltage under synchronization check mode. 2) “Freq_Syn Diff”:Maximum allowable frequency difference between bus voltage and line frequency under synchronization check mode. 3) 4) “T_Syn Check”: delay time of synchronizing. 5) “T_MaxSynExt”: Duration of quit synchronizing. 6) “Umin_Syn”: Minimum voltage of synchronizing. 7) “Umax_Energ”: Maximum voltage of unenergizing checking. Bits of “AR_Override”, “AR_EnergChkDLLB”, “AR_EnergChkLLDB”, “AR_EnergChkDLDB” and “AR_Syn check”: All of these three modes are autoreclosure check modes. If anyone of them is set to “on”, the others must be set to “off”. 8) 1.5 236 Reports Chapter 18 Synchro-check and energizing check function Table 128 Event report list Information Description Syn Request Begin to synchronization check AR_EnergChk OK Energizing check OK Syn Failure Synchronization check timeout Syn OK Synchronization check OK Syn Vdiff fail Voltage difference for synchronization check fail Syn Fdiff fail Frequency difference for synchronization check fail Syn Angdiff fail Angle difference for synchronization check fail EnergChk fail Energizing check fail Table 129 Alarm report list Information Description SYN Voltage Err Voltage abnormity for synchronization check 1.6 Technical data NOTE: Ir: CT rated secondary current, 1A or 5A; Table 130 Synchro-check and voltage check technical data Item Operating mode Rang or Value Synchronization check: Synch-check Energizing check, and synch-check if energizing check failure Override Tolerance Energizing check: Dead V4 and dead V3Ph Dead V4 and live V3Ph Live V4 and dead V3Ph Voltage threshold of dead line 10 to 50 V (phase to earth), or bus step 1 V ≤ ± 3 % setting or 1 V 237 Chapter 18 Synchro-check and energizing check function Voltage threshold of live line 30 to 65 V (phase to earth), or bus step 1 V ∆V-measurement Voltage 1 to 40 V (phase-to-earth), difference steps 1 V Δf-measurement (f2>f1; 0.02 to 2.00 Hz, step, 0.01 ≤ ± 3 % setting or 1 V ≤ ± 1V ≤ ± 20 mHz f2<f1) Hz, Δα-measurement (α2>α1; 1 °to 80 °, step, 1 ° ≤ ± 3° 0.05 to 60.00 s, step,0.01 s, ≤ ± 1.5 % setting value or +60 α2<α1) Minimum measuring time ms Maximum synch-check extension time 238 0.05 to 60.00 s, step,0.01 s, ≤ ± 1 % setting value or +50 ms Chapter 18 Synchro-check and energizing check function 239 Chapter 19 Auto-reclosing function Chapter 19 Auto-reclosing function About this chapter This chapter describes the protection principle, input and output signals, parameter, IED report and technical data used in Auto-reclosing function. 240 Chapter 19 Auto-reclosing function 1 Auto-reclosing 1.1 Introduction For restoration of the normal service after a fault, an auto-reclosing attempt is mostly made for overhead lines. Experiences show that about 85% of faults are transient and can disappear when an auto-reclosing attempt is performed. This means that the line can be connected again; the reconnection is accomplished after a dead time via the automatic reclosing system. If the fault still exists after auto-reclosing, for example, arc has not been cleared, the protection will re-trip the circuit breaker (hereinafter is referred as CB). Auto-reclosing is only permitted on overhead lines because a short circuit arc can be extinguished only in overhead lines and not cable feeders. Main features of the auto-reclosing function (hereinafter is referred as AR) are as following: 1.2 4 shots auto-reclosing (selectable) Individually settable dead time for three phase and single phase fault and for each shot Internal/external AR initiation Single/three phase AR operation CB ready supervision CB Aux. interrogation Cooperation with internal synch-check function for reclosing command Function principle The AR is able to cooperate with single-pole operated CB as well as three-pole operated CB. The function provides up to 4 auto-reclosing shots that can be determined by setting, “Times_AR”. Moreover, since the time required for extinguishing short circuit arc is different for single or three phase faults, the different dead time settings, “T_1P ARn” and “T_3P ARn” ( n represents 1, 2, 3, or 4), AR have been provided to set single-pole tripping dead time and three-pole tripping dead time of each shot separately. 1.2.1 Single-shot reclosing 241 Chapter 19 Auto-reclosing function When an external trip command initiates AR function, the reclosing program is being executed. Dead time will be started by falling edge of the external initiation signal. When dead time interval “T_1P AR1” or “T_3P AR1” has elapsed, monitoring time “T_MaxSynExt” is started. During this period, whenever synchronization condition is continuously met for “T_Syn Check”, a closing pulse signal is issued. At the same time, reclaim time “T_Reclaim” is started. If a new fault occurs before the reclaim time elapses, AR function is blocked and cause final tripping of CB. However, if no fault occurs in reclaim time, AR is reset and therefore will be ready for future reclosing attempts. The typical tripping-reclosing procedure of single shot reclosing scheme, is illustrated in time sequence diagrams, Figure 80, and is described as following: 1) After trip command issued, CB will be opened in a short time. 2) The auto-reclosing is initiated when the current is cleared. 3) After the auto-reclosing delay time, T_1P AR1 (or T_3P AR1), elapses, the reclosing command is issued if all reclosing conditions (e.g. synchro-check for 3-pole tripping) are satisfied without any blocking reclosing input. 4) The AR pulse lasts for “T_Action”. 5) At the moment that the closing signal is issued, reclaim timer “T_Reclaim” is started. By the end of this period, “T_Reclaim”, if there is not fault happening, auto-reclosing operation is successful and then the report, “AR Success”, is issued. 6) From the end of reclaim time, auto-reclosing function is blocked for the AR reset time “T_AR Reset”. 7) If another fault occurs after the time, T_AR Reset, elapses, the auto-reclosing is ready now, and then a new tripping-reclosing procedure is started and performed in same way. 242 Chapter 19 Auto-reclosing function Fault Trip Command CB Open PosItion AR Initiate T_3P AR1 Synchro-check or voltage check OK T_Action T_Action Closing Command T_Reclaim T_Reset Figure 80 Two transient three-phase faults, two tripping-reclosing procedures 1.2.2 Multi-shot reclosing The first reclosing shot is, in principle, the same as the single-shot auto-reclosing. If the first reclosing is unsuccessful, it doesn’t result in a final trip, if multi-shot reclosing is set to be performed. In this case, if a fault occurs during reclaim time of the first reclosing shot, it would result in the start of the next reclose shot with dead time “T_1pAR1”, “T_1p AR2”, ”T_1p AR3”, “T_1p AR4”, “T_3P AR2”, “T_3P AR3” or “T_3P AR4”. This procedure can be repeated until the whole reclosing shots which are set inside the device is performed. Different dead times can be set to various shots of AR function. This can be performed through settings “T_1pAR1”, “T_1p AR2”, ”T_1p AR3”, “T_1p AR4”, T_3p AR1”, “T_3p AR2”, ”T_3p AR3”, “T_3p AR4”. However, if none of reclosing shots is successful, i.e. the fault doesn’t disappear after the last programmed shot, a final trip is issued, and reclosing attempts are announced to be unsuccessful. The typical tripping-reclosing procedure of two shots reclosing scheme, is illustrated in time sequence diagrams, Figure 81, and is described as following: 1) After trip command issued, CB will be opened in a short time. 2) The auto-reclosing is initiated when the current is cleared. 243 Chapter 19 Auto-reclosing function 3) After the auto-reclosing delay time, T_1P AR1 (or T_3P AR1), elapses, the reclosing command is issued if all reclosing conditions (e.g. synchro-check for 3-pole tripping) are satisfied without any blocking reclosing input. 4) The AR pulse lasts for “T_Action”. 5) At the moment that the closing signal is issued, reclaim timer “T_Reclaim” is started. 6) If the circuit breaker is closed on a fault during the period between the dropout of closing command and the end of T_Reclaim, second tripping-reclosing procedure for second shot is started and performed like the first tripping-reclosing procedure. 7) In this way, following shots will be performed in sequence if applied. 8) If none of the reclosing is successful, in other words, the fault is still remained after the last shot reclosing, the final trip takes place, and the result is “AR Fail” and AR should be blocked for AR reset time. 9) If one of the preset reclosing shots is successful, meaning that, by the end of this period, “T_Reclaim”, there is not fault happening again, the report, “AR Success”, is issued. 10) From the end of reclaim time, auto-reclosing function is blocked for the AR reset time “T_AR Reset”. 11) If another fault occurs after the time, T_AR Reset, elapses, the auto-reclosing is ready now, and then a new multi shots tripping-reclosing procedure is started and performed in same way. 244 Chapter 19 Auto-reclosing function Fault Trip Command CB Open PosItion AR Initiate T_3P AR1 Synchro-check or voltage check OK T_Action T_Action Closing Command T_Reclaim T_Reset Figure 81 A permanent three-phase fault, two reclosing shots and final tripping 1.2.3 Auto-reclosing operation mode For the IED, whether single-pole tripping operation or three-pole tripping operation and whether AR is active or not is determined by following binary settings and related binary inputs. The relevant binary settings are described as following, “AR_1p mode” In this mode of operation, auto-reclosing function will be initiated by single phase tripping condition as well as using the external single pole binary input initiation. If the three-phase AR initiation binary input, 3Ph Init AR, is active, the closing function will be blocked. “AR_3p mode” In this mode of operation, auto-reclosing function only operates for three pole closing. “AR_1p(3p) mode” In this mode of operation, auto-reclosing function operates for both single pole tripping as well as three pole tripping. 245 Chapter 19 Auto-reclosing function “AR_Disable” By setting this binary setting to “1”, auto-reclosing function will be off or out of service. Note: If any illegal setting has been done, “AR FUNC Alarm” is reported. “AR Init by 3p” By setting this binary setting to “1”, auto-reclosing function can be initiated by three phase faults as well as single phase faults. Otherwise, auto-reclosing can be done only for single phase faults according to the mode of auto-reclosing operation define previously. “AR Init by 2p” By setting this binary setting to “1”, auto-reclosing function can be initiated by two phase fault. “Relay Trip 3pole” When AR is disabled, by setting this binary setting to “0”, IED performs single- pole tripping at single phase fault and perform three-pole tripping at multi-phase fault. Setting this binary setting to “1” will result in three-pole tripping at any faults. “AR Final Trip” By setting this binary setting to “1”, auto-reclosing function generates a three pole trip command for an unsuccessful single pole reclosing. In the “AR_1P mode”, after a single pole tripping, if auto-reclosing function is blocked suddenly during the dead time of a 1-pole reclosing cycle, the circuit breaker will be kept in poles discordance state. To avoiding this state, by binary setting “AR Final Trip” at 1, the IED will issue a 3-pole trip command to open the rest of circuit breaker poles. This binary setting is always used in the situation without pole discordance protection applied. 1.2.4 Auto-reclosing initiation The auto-reclosing function can be initiated by the internal functions listed below: 246 Differential protection Distance Z1 Chapter 19 Auto-reclosing function Teleprotection based on distance tripping Directional earth fault protection-stage 1 (selectable by binary setting “DEF1 Initiate AR”) Directional earth fault protection-stage 2 (selectable by binary setting “DEF2 Initiate AR”) Teleprotection directional earth fault tripping (selectable by binary setting “Pilot_DEF Init AR”) Phase selective AR external initiation; AR will be initiated by falling edge of the receiving trip signals (“1” to “0”) AR can be initiated by external functions via four binary inputs: PhA Init AR External phase A tripping output initiates AR PhB Init AR External phase B tripping output initiates AR PhC Init AR External phase C tripping output initiates AR 3Ph Init AR External three-phase tripping output initiates AR 1.2.5 Cooperating with external protection IED The AR can cooperate with external protection IED. The AR can be initiated or blocked by external protection IED via dedicated binary inputs. Figure 82 shows the typical connection between AR binary inputs and external protection IED binary outputs. 247 Chapter 19 Auto-reclosing function Protection IED BO-Trip PhA BI-PhA Init AR BO-Trip PhB BI-PhB Init AR BO-Trip PhC BI-PhC Init AR BO-Trip 3Ph BI-3Ph Init AR BO Relay Block AR BI-MC/AR Block On Off Protection IED with AR BI-AR OFF + Figure 82 Typical connection between two protection IEDs with/without AR 1.2.6 Auto-reclosing logic Some important points regarded to auto-reclosing logic are described as following: 248 In the case of blocking of auto-reclosing via “MC/AR block”, blocking will be started by rising edge of “MC/AR block” and will be extended by “T_AR_Reset” time after falling edge of this binary input. In the case of three phase reclosing with sychro-check requesting, dead time can last for “T_3P AR” + “T_MaxSynExt” at most, from the auto-reclosing initiation input end. In this condition, IED starts to check synchronization conditions at the end of “T_3P AR”. Before the end of period, “T_MaxSynExt”, if the synchronization conditions are continuously met for the time, “T_Syn Check” at least, the close command will be issued. After the end of period, “T_MaxSynExt”, if synchronization conditions are still not continuously met, the report, “AR Failure”, will be issued and the auto-reclosing function will be blocked for time, “T_AR Reset”. The logic is illustrated in flowing time sequence diagram Chapter 19 Auto-reclosing function Fault Trip Command CB Open PosItion AR Initiate T_3P AR1 t1 t2 t3 t4 t5 t6 Synchro-check or voltage check OK T_Syn Check T_MaxSynExt T_Action Closing Command T_Reclaim T_Reset Note: T_Syn Check > t1, t2, t4, t5, t6; T_Syn Check ≤ t3 Figure 83 A permanent three-phase fault, successful synchronizing for first shot, fail synchronizing for second shot Close command pulse lasts for “T_Action” at most. During this time, it does not check synchronization conditions any longer. Before the end of close command pulse, if any function tripping happen, the close command is terminated. 249 Chapter 19 Auto-reclosing function Fault Trip Command CB Open Position AR for CB: AR Initiate AR for CB: T_3P AR1 AR for CB: Synchro-check or voltage check OK T_Action AR for CB: Closing command AR for CB: T_Reclaim AR for CB: T_Reset Figure 84 A permanent three-phase fault, single shot, unsuccessful reclosing 1.2.7 To prevent automatic reclosing during feeder dead status (CB Open), for example, in the IED testing, AR is initiated at first shot only when the CB has been closed for more than setting time, “T_AR Reset”. AR blocked conditions If binary input “AR Off” is present, auto-reclosing function will be out of service Whenever the binary input “MC/AR Block” is received, auto-reclosing function will be blocked for setting “T_AR Reset”. Whenever circuit breaker abnormal condition is detected, auto-reclosing function will be blocked. In order to avoid auto-reclosing in the case of CB faulty, for example, CB spring charge faulty, a binary input, “CB Faulty”, is considered to receive CB ready status. Therefore, after synchronization check condition meets, the input “CB Faulty”will be checked. If it doesn’t disappear before time period 250 Chapter 19 Auto-reclosing function “T_CB Faulty” finishing, auto-reclosing will be blocked for “T_AR Reset”. 1.2.8 Logic diagram BI_PhA Init AR 1-0 AND A Phase no current BI_PhB Init AR 1-0 AND OR B Phase no current AND Single phase Startup AR BI_PhC Init AR 1-0 AND C Phase no current BI_PhA Init AR 1-0 BI_PhB Init AR 1-0 AND 3 Phase no current BI_PhB Init AR 1-0 BI_PhC Init AR 1-0 AND 3 Phase no current OR 3 phase Startup AR BI_PhC Init AR 1-0 BI_PhA Init AR 1-0 AND 3 Phase no current BI_3Ph Init AR 1-0 AND 3 Phase no current Figure 85 Logic diagram 1 for auto-reclosing startup Besides, auto-reclosing startup could also be triggered by circuit breaker opening as following figure: 251 Chapter 19 Auto-reclosing function BI_PhA CB Open 0-1 1P CBOpen Init AR on AND BI_PhB CB Open 0-1 AND Single phase Startup AR AND OR 1P CBOpen Init AR on BI_PhC CB Open 0-1 1P CBOpen Init AR on AND BI_PhA CB Open 0-1 BI_PhB CB Open 0-1 AND 3P CBOpen Init AR on BI_PhB CB Open 0-1 BI_PhC CB Open 0-1 3 phase Startup AR OR AND 3P CBOpen Init AR on BI_PhC CB Open 0-1 BI_PhA CB Open 0-1 AND 3P CBOpen Init AR on Figure 86 Logic diagram 2 for auto-reclosing startup AR_Chk3PVol =0 1) AR_Chk3PVol =1 t OR 0 AND Ua(Ub,Uc) >Umin_Syn AND t 0 Check 3Ph Voltage OK 3) 2) t 0 Note: 1) t = T_Syn Check 2) t = T_3P AR 3) t = T_MaxSynExt Figure 87 Logic diagram of checking 3 phase voltage 252 Check 3 Ph failure Chapter 19 Auto-reclosing function Check 3Ph Voltage OK AR_1p mode =1 AND AR_1p(3p) mode =1 1) OR AND t 0 Single phase initiate AR OR AR_3p mode = 1 AR_1p(3p) mode =1 OR AND 3 phase initiate AR 2) AND t 0 NO check OR Energizing check OK 3) t 0 Synchro-check OK AND AR Closing BI_MC/AR block: 0-1 Backup protection tripping OR Alarm: Relay fault BI_AR off: 0-1 OR AR_Disable =1 4) t BI_CB Faulty 0 AR Fail Relay Trip 3 pole =1 AND AR_3p mode =1 Ph A Tripping: 0-1 OR Ph B Tripping: 0-1 AR Lockout AND Ph B Tripping: 0-1 OR 3 Ph Tripping: 0-1 AND Relay trip 3 Ph = 1 AR_1p mode = 1 Note: 1) t = T_1P AR 2) t = T_3P AR 3) t = T_MaxSynExt 4) t = T_CB Faulty Figure 88 Logic diagram of auto-reclosing 253 Chapter 19 Auto-reclosing function 1.3 Input and output signals AR Close IP1 IP2 AR Lockout IP3 AR Not Ready UP1 AR Final Trip UP2 AR In Progress UP3 AR Successful UP4 PhA Init AR PhB Init AR PhC Init AR 3Ph Init AR MC/AR Block AR off CB Faulty PhA CB Open PhB CB Open PhC CB Open 3Ph CB Open V1P MCB Fail Table 131 Analog input list Signal Description IP1 signal for current input 1 IP2 signal for current input 2 IP3 signal for current input 3 UP1 signal for voltage input 1 UP2 signal for voltage input 2 UP3 signal for voltage input 3 UP4 signal for voltage input 4 Table 132 Binary input list Signal Description AR Off AR function off MC/AR Block AR block PhA Init AR PhaseA initiate AR PhB Init AR PhaseB initiate AR 254 Chapter 19 Auto-reclosing function Signal Description PhC Init AR PhaseC initiate AR 3Ph Init AR Three phase initiate AR In order to avoid Auto-reclosing in the case of CB Faulty CB faulty, for example CB spring charge faulty PhA CB Open Phase A CB Open PhB CB Open Phase B CB Open PhC CB Open Phase C CB Open V1P MCB Fail VT broken of UX in synchrocheck Table 133 Binary output list Signal Description Relay Block AR Permanent trip AR Close AR Close AR Lockout AR Lockout, AR Not Ready AR Not Ready AR Final Trip AR Final Trip AR In Progress AR In Progress AR Successful AR Successful AR Fail AR Fail Note: “AR lockout”: If this contact is output, IED will only trip three poles. “AR Final Trip”:If single AR has startup but AR can’t be enabled for any reason, this contact will be output for three pole tripping, if the setting “AR Final Trip” has been enabled. 1.4 Setting parameters 1.4.1 Setting lists 255 Chapter 19 Auto-reclosing function Table 134 Auto reclosure function setting list Uni Setting t Min. Max. Default (Ir:5A/ (Ir:5A/1 setting 1A) A) (Ir:5A/1A) T_1P AR1 s 0.05 10 0.6 T_1P AR2 s 0.05 10 0.7 T_1P AR3 s 0.05 10 0.8 T_1P AR4 s 0.05 10 0.9 T_3P AR1 s 0.05 60 1.1 T_3P AR2 s 0.05 60 1.2 T_3P AR3 s 0.05 60 1.3 T_3P AR4 s 0.05 60 1.4 T_Action ms 80 500 80 Description delay time of shot 1 of single pole reclosing delay time of shot 2 of single pole reclosing delay time of shot 3 of single pole reclosing delay time of shot 4 of single pole reclosing delay time of shot 1 of three pole reclosing delay time of shot 2 of three pole reclosing delay time of shot 3 of three pole reclosing delay time of shot 4 of three pole reclosing duration of the circuit breaker closing pulse T_Reclaim s 0.05 60 3 Reclaim time T_CB Faulty s 0.5 60 1 duration of CB ready 1 4 1 quanty of shots s 0 60 0.05 s 0.05 60 10 duration of quit synchronizing s 0.5 60 3 duration of CB reclosing prepartion Times_AR T_Syn Check T_MaxSynE xt T_AR Reset delay time of synchronizing Table 135 Auto reclosure binary setting list Abbr. AR Init By 2p AR Init By 3p 256 Explanation AR Initiated by phase-to-phase fault AR Initiated by three phase fault Default Unit Min. Max. 0 0 1 1 0 1 Relay Trip 3pole Three phase tripping 0 0 1 Tele_EF Init AR Auto reclosure 0 0 1 Chapter 19 Auto-reclosing function Abbr. Explanation Default Unit Min. Max. 0 0 1 0 0 1 1 0 1 0 0 1 0 0 1 0 0 1 1 0 1 0 0 1 0 0 1 0 0 1 0 0 1 0 0 1 initiated by tele earth fault protection Auto-reclosing EF1 Init AR initiated by first stage zero-sequence current protection Auto-reclosing EF2 Init AR initiated by second stage zero-sequence current protection single phase mode for AR_1p mode Auto-reclosing function three phase mode for AR_3p mode On Auto-reclosing function one and three phase AR_1p(3p) mode mode for Auto-reclosing function AR_Disable AR_Override Auto-reclosing function disabled Override mode for AR enabled or disabled Synchronization check AR_Syn check for AR enabled or disabled three phase voltage AR_Chk3PVol check for single phase AR AR Final Trip 1P CBOpen Init AR 3P CBOpen Init AR 1.5 Final trip by AR AR initiated by single phase CB open AR initiated by three phase CB open Reports 257 Chapter 19 Auto-reclosing function Table 136 Event report list Information Description 1st Reclose First reclose 2nd Reclose Second reclose 3rd Reclose Third reclose 4th Reclose Fourth reclose 1Ph Trip Init AR Autoreclose by one phase trip 1Ph CBO Init AR Autoreclose by one phase circuit breaker opening 1Ph CBO Blk AR Autoreclose blocked by one phase circuit breaker opening 3Ph Trip Init AR Autoreclose initiated by three phase trip 3Ph CBO Init AR Autoreclose initiated by three phase breaker opening 3Ph CBO Blk AR Autoreclose blocked by three phase trip AR Block Autoreclose blocked BI MC/AR BLOCK Autoreclose BI blocked AR Success Autoreclose success AR Final Trip Final trip for autoreclose AR in progress Autoreclose is in progress AR Failure Autoreclosure failed Table 137 Alarm report list Information Description AR Mode Alarm Autoreclosure mode alarm Table 138 Operation report list Information Description Func_AR On AR function on Func_AR Off AR function off BI_AR Off AR off BI 1.6 Technical data NOTE: Ir: CT rated secondary current, 1A or 5A; 258 Chapter 19 Auto-reclosing function Item Number of reclosing shots Rang or Value Tolerance Up to 4 Shot 1 to 4 is individually selectable AR initiating functions Internal protection functions External binary input Dead time, separated setting 0.05 s to 60.00 s, step 0.01 s for shots 1 to 4 ≤ ± 1 % setting value or +50 ms Reclaim time 0.50 s to 60.00s, step 0.01 s Blocking duration time (AR 0.05 s to 60.00s, step 0.01 s reset time) Circuit breaker ready 0.50 s to 60.00 s, step 0.01 s supervision time Dead time extension for 0.05 s to 60.00 s, step 0.01 s synch-check (Max. SYNT EXT) 259 Chapter 20 Secondary system supervision Chapter 20 Secondary system supervision About this chapter This chapter describes the protection principle, input and output signals, parameter, IED report and technical data used in secondary system supervision function. 260 Chapter 20 Secondary system supervision 1 Current circuit supervision 1.1 Introduction Open or short circuited current transformer cores can cause unwanted operation of many protection functions such as earth fault protection and negative sequence current functions. It must be remembered that a blocking of protection functions at CT open causes extremely high voltages that can stress the secondary circuit. To prevent IED from wrong tripping, interruptions in the secondary circuits of current transformers is detected and reported by the device. When the measured zero-sequence current is always larger than the setting value of “3I0_CT Fail” for 12 sec, “CT Fail” is reported and zero-sequence current protection will be blocked. 1.2 Function diagram CT Fail IN 1.3 Input and output signals Table 139 Analog input list Signal Description IN External input of zero-sequence current Table 140 Binary output list Signal Description 261 Chapter 20 Secondary system supervision Signal Description CT Fail CT Fail 1.4 Setting parameters 1.4.1 Setting lists Table 141 Fuse failure supervision function setting list Max. Setting Unit Min. (Ir:5 (Ir:5A/1A) A/1A ) 3I0_CT Fail A 0.08Ir Default setting Description (Ir:5A/1A) 2Ir 0.2Ir zero sequence current threshold of CT failure detection Table 142 Fuse failure supervision binary setting list Abbr. Explanation CT Fail Default Check CT mode 1.4.2 Setting explanation 1.5 Reports Table 143 Alarm report list Information Description CT Fail CT fail 262 1 Unit Min. Max. 0 1 Chapter 20 Secondary system supervision 2 Fuse failure supervision 2.1 Introduction In the event of a measured voltage failure due to a broken conductor or a short circuit fault in the secondary circuit of voltage transformer, those protection functions which are based on under-voltage criteria may mistakenly see a voltage of zero. VT failure supervision function is provided to inform those functions about a voltage failure. VT supervision can be used to monitor the voltage transformer circuit, single-phase VT failures, two-phase or three-phase VT failures. Its main features are as follows: 2.2 Symmetrical/Asymmetrical VT fail detection 3-phase AC voltage MCB monitoring Applicable in solid, compensated or isolated networks Function principle VT failure supervision function can be enabled or disabled via binary setting “VT Fail”. By applying setting “1/on” to this binary setting, VT failure supervision function would monitor the voltage transformer circuit. As mentioned, the function is able to detect single-phase broken, two-phase broken or three-phase broken faults in secondary circuit of voltage transformer, if a three-phase connection is applied. There are three main criteria for VT failure detection; the first is dedicated to detect three-phase broken faults. The second and third ones are to detect single or two-phase broken faults in solid earthed and isolated/resistance earthed systems, respectively. A precondition to meet these three criteria is that IED should not startup and the calculated zero sequence and negative sequence currents should be less than setting of “3I02_ VT Fail”. The criteria are as follows: 2.2.1 Three phases (symmetrical) VT Fail The calculated zero sequence voltage 3U0 as well as maximum of three phase-to-earth voltages is less than the setting of “Upe_VT Fail” and at the 263 Chapter 20 Secondary system supervision same time, maximum of three phase currents is higher than setting of “I_ VT Fail”. This condition may correspond to three phase broken fault in secondary circuit of the voltage transformer if no startup element has been activated. 2.2.2 Single/two phases (asymmetrical) VT Fail 1. The calculated zero sequence voltage 3U0 is more than the setting of “Upe_VT Fail”. This condition may correspond to single or two-phase broken fault in secondary circuit of the voltage transformer, if the system starpoint is solidly earthed and no startup element has been activated. 2. The calculated zero sequence voltage 3U0 is more than the setting of “Upe_VT Fail”, and at the same time, the difference between the maximum and minimum phase-to-phase voltages is more than the setting of “Upp_VT Fail”. This condition may correspond to single or two-phase broken fault in secondary circuit of the voltage transformer, if the system starpoint is isolated or resistance earthed and no startup element has been activated. In addition to the mentioned conditions, IED has the capability to be informed about the VT MCB failure through its digital inputs “V3P MCB Fail”. In this context, VT fail is detected, if the corresponding binary input is active. 2.2.3 Logic diagram If VT failure supervision detects a failure in voltage transformer secondary circuit, either by means of the above mentioned criteria or reception of a VT MCB fail indication, all the protection functions, which are based on direction component or low voltage criteria, will be blocked. Furthermore, Alarm report “VT fail” is issued after 10s delay time. The blocking condition would be removed if one of the following conditions is met within the 10 sec delay time (previous to Alarm “VT fail”). 1. Without IED startup, minimum phase voltage becomes more than setting of “Upe_VT Normal” for 500ms. 2. Without IED startup, minimum phase voltage becomes more than setting of “Upe_VT Normal” and at the same time, the calculated zero sequence and negative sequence current of corresponding side becomes more than the setting of “3I02_ VT Fail”. Subsequent to VT fail alarm, the blocking condition of respective protection functions would be removed if without IED startup, the minimum phase voltage becomes more than the setting of “Upe_VT Normal” for a duration 264 Chapter 20 Secondary system supervision more than 10 sec. Figure 89 shows logic diagram of VT failure supervision as it is implemented. Max(Ia,Ib,Ic)>I_VT Fail A N D max{Ua,Ub,Uc}< Upe_VT Fail 3U0 < (Upe_VT Fail-1) 3U0 >=(Upe_VT Fail-1) Solid earthed on Solid earthed off Max{Uab,Ubc,Uca}Min{Uab,Ubc,Uca}> Upp_VT Fail A N D Relay Start up O R A N D O R BI_V3P MCB Fail 0-1 VT Fail on A N D VT Fail block O R VT Fail unblock 10S Alarm report VT Fail block min{Ua,Ub,Uc}> Upe_VT Normal A N D A N D 500ms A N D 3I0>3I02_VT Fail or 3I2>3I02_VT Fail A N D A N D 10S Figure 89 VT fail blocking/unblocking logic 2.3 Input and output signals 265 Chapter 20 Secondary system supervision IP1 VT Fail IP2 IP3 IN IU1 IU2 IU3 V3P MCB Fail Table 144 Analog input list Signal Description IP1 signal for current input 1 IP2 signal for current input 2 IP3 signal for current input 3 IN External input of zero-sequence current UP1 signal for voltage input 1 UP2 signal for voltage input 2 UP3 signal for voltage input 3 Table 145 Binary input list Signal Description V3P MCB Fail Three phase VT fail Table 146 Binary output list Signal Description VT Fail VT Fail 2.4 Setting parameters 2.4.1 Setting list 266 Chapter 20 Secondary system supervision Table 147 Fuse failure supervision function setting list Default Min. Setting Unit (Ir:5A/1 A) I_VT Fail A Max. setting (Ir:5A/1A) (Ir:5A/1A Description ) 0.08Ir 0.2Ir current threshold of PT failure 0.1Ir detection Negative sequence/zero 3I02_VT Fail A 0.08Ir 0.2Ir sequence current threshold of 0.1Ir release blocking due to VT failure Upe_VT Fail V 7 20 8 Upp_VT Fail V 10 30 16 V 40 65 40 Upe_VT Normal voltage (phase to earth) threshold of PT failure detection voltage (phase to phase) threshold of PT failure detection restore voltage threshold of PT failure detection Table 148 Fuse failure supervision function setting list Abbr. VT Fail Solid Earthed 2.5 Explanation Default Check VT The system is solid earthed system Unit Min. Max. 1 0 1 1 0 1 Technical data NOTE: Ir: CT rated secondary current, 1A or 5A; Table 149 VT secondary circuit supervision technical data Item Range or value Tolerances Minimum current 0.08Ir to 0.20Ir, step 0.01A ≤ ±3% setting or ±0.02Ir Minimum zero or negative 0.08Ir to 0.20Ir, step 0.01A ≤ ±5% setting or ±0.02Ir 7.0V to 20.0V, step 0.01V ≤ ±3% setting or ±1 V 10.0V to 30.0V, step 0.01V ≤ ±3% setting or ±1 V sequence current Maximum phase to earth voltage Maximum phase to phase 267 Chapter 20 Secondary system supervision voltage Normal phase to earth voltage 268 40.0V to 65.0V, step 0.01V ≤ ±3% setting or ±1 V Chapter 20 Secondary system supervision 269 Chapter 21 Mornitoring Chapter 21 Monitoring About this chapter This chapter describes the protection principle, input and output signals, parameter, IED report and technical data used in monitoring function. 270 Chapter 21 Monitoring 1 Check Phase-sequence for voltage and current 1.1 Introduction In normal condition of power system, whether AC circuits of three phases are connected in right sequence or not can be distinguished by phasor comparison of three phases current and voltage. If they are in abnormal sequence, “3Ph SEQ Err” will be reported. 2 Check 3I0 polarity 2.1 Introduction By comparing value and phasor of calculated 3I0 (IA+IB+IC) with that of 3I0 external connected, whether the polarity of external 3I0 is connected in reverse or not can be differentiated. If it is in reverse, “3I0 Reverse” will be reported. 3 Check the third harmonic of voltage 3.1 Introduction If the third harmonic voltage exceeds 4V, “Harmonic Alarm” will be reported with 10s delay time, but the protection is not blocked. 4 Check auxiliary contact of circuit breaker 4.1 Introduction If auxiliary contact of CB indicates that circuit breaker pole is open but at the 271 Chapter 21 Mornitoring same time and current is flowing trough corresponding phase, “CB Open A (B or C) Err” is reported after 2sec delay time.. 5 Broken conductor 5.1 Introduction The system supervises load flow in real time. If negative current is greater than the setting of “3I2_Broken Conduct”, after “T_Broken Conduct”, “BRKN COND Alarm” is reported. The following logic shows the logic diagram of thebroken conductor. 5.1.1 Logic diagram BI_PhA CB Open BI_PhA CB Open O R BI_PhA CB Open 3I2>3I2_Broken Conduct A N D A N D Func_Broken Conduct on A N D Broken Conduct Trip Off Broken Conduct Trip On Figure 90 Broken conductor logic 5.2 272 Input and output signals T_Broken Conduct T_Broken Conduct Broken Conduct Alarm Broken Conduct Trip Chapter 21 Monitoring IP1 BRKN COND Trip IP2 BRKN COND Alarm IP3 PhA CB Open PhB CB Open PhC CB Open Table 150 Analog input list Signal Description IP1 signal for current input 1 IP2 signal for current input 2 IP3 signal for current input 3 Table 151 Binary input list Signal Description PhA CB Open Phase A CB Open PhB CB Open Phase B CB Open PhC CB Open Phase C CB Open Table 152 Binary output list Signal Description BRKN COND Trip BRKN COND trip BRKN COND Alarm BRKN COND alarm 5.3 Setting parameters 5.3.1 Setting list 273 Chapter 21 Mornitoring Table 153 Broken conductor supervision function setting list Uni Setting t Min. Max. (Ir:5A/1 (Ir:5A/ A) 1A) Default setting (Ir:5A/1 Description A) nagative sequence current 3I2_Broken A Conduct 0.08Ir 2Ir 2Ir threshold of conduct broken detection T_Broken s Conduct 0 250 10 time delay of conduct broken detection Table 154 Broken conductor supervision binary setting list Abbr. Explanation Func_Broken Conduct Broken Conduct Trip 5.4 Default Broken Conduct function Broken Conduct Trip function Reports Table 155 Event report list Information Description BRKN COND Trip Broken conductor protection trip Table 156 Alarm report list Information Description BRKN COND Alarm Broken conductor alarm 274 Unit Min. Max. 1 0 1 0 0 1 Chapter 21 Monitoring 6 Fault locator 6.1 Introduction Fault location is a process aimed at locating the occurred fault with the highest possibly accuracy. A fault locator is mainly the supplementary protection equipment, which apply the fault location algorithms for estimating the distance to fault. IED reports fault location after protection tripping. Fault location is calculated according fundamental frequency component of the measured voltages and currents corresponding to the faulty phases. Making use of the fundamental frequency voltages and currents at the line terminal, together with the line paramenters appears as the most popular way for detrmining the fault location. Additionally, there are some conditions that affect the calculated impedance so that it is not exactly corresponding to distance of the fault. For example, zero sequence coupling compensation on parallel transmission lines affects the fault location calculated by protection relays.Therefore, for parallel transmission lines, IED need to consider mutual inductance, so it should be informed about the zero sequence current of the other line, “IN(mutual)” via analogue module of the equipment (Figure 91). L1 L2 L3 52 52 CSC-101 IA IB IC IN IN (M) Figure 91 Parallel line compensation for fault location Following equation can be used to determine fault location considering parallel line and zero sequence compensation. 275 Chapter 21 Mornitoring Z= U A(B,C) IA(B,C) +K N 3I0+jK m IN M Equation 23 where KN = Z0-Z1 3Z1 KM = X0M X1 Other condition that affect on calculated distance is remote end infeed (Figure 92), which can be suitably compensated in order that fault location can be calculated as accurate as possible. For this purpose, imaginary part of Z L1, XL1, is calculated from the following equation. This is done by separating the real and imaginary parts of the following equation. Zm1 = U A I m ZL1 +I k R g I = =ZL1 + K R g eiα Im Im Im Equation 24 jX Ik R e jα Im g N M L2 L1 XL1 ZL1 XM1 Im Ik Rg In ZM1 R Figure 92 Remote end infeed compensation in fault location calculation 276 Chapter 21 Monitoring 277 Chapter 22 Station communication Chapter 22 Station communication About this chapter This chapter describes the communication possibilities in a substation automation system. 278 Chapter 22 Station communication 1 Overview Each IED is provided with a communication interface, enabling it to connect to one or many substation level systems or equipment. The following communication protocols are available: IEC 61850-8-1 communication protocol 60870-5-103 communication protocol The IED is able to connect to one or more substation level systems or equipments simultaneously, through the communication ports and supported protocols. 2 Protocol 2.1 IEC61850-8 communication protocol IEC 61850-8-1 allows two or more intelligent electronic devices (IEDs) from one or several vendors to exchange information and to use it in the performance of their functions and for correct co-operation. GOOSE (Generic Object Oriented Substation Event), which is a part of IEC 61850-8-1 standard, allows the IEDs to communicate state and control information amongst themselves, using a publish-subscribe mechanism. That is, upon detecting an event, the IED(s) use a multi-cast transmission to notify those devices that have registered to receive the data. An IED can, by publishing a GOOSE message, report its status. It can also request a control action to be directed at any device in the network. 2.2 IEC60870-5-103 communication protocol The IEC 60870-5-103 communication protocol is mainly used when a protection IED communicates with a third party control or monitoring system. This system must have software that can interpret the IEC 60870-5-103 communication messages. The IEC 60870-5-103 is an unbalanced (master-slave) protocol for coded-bit 279 Chapter 22 Station communication serial communication exchanging information with a control system. In IEC terminology a primary station is a master and a secondary station is a slave. The communication is based on a point-to-point principle. The master must have software that can interpret the IEC 60870-5-103 communication messages. For detailed information about IEC 60870-5-103, refer to the “IEC60870 standard” part 5: “Transmission protocols”, and to the section 103: “Companion standard for the informative interface of protection equipment”. 3 Communication port 3.1 Front communication port There is a serial RS232 port on the front plate of all IEDs. Through this port, the IED can be connected to the personal computer for setting, testing, and configuration using the dedicated Sifang software tool. 3.2 RS485 communication ports Up to 2 isolated electrical RS485 communication ports are provided to connect with substation automation system. These two ports can work in parallel for IEC60870-5-103. 3.3 Ethernet communication ports Up to 3 electrical or optical Ethernet communication ports are provided to connect with substation automation system. These two out of three ports can work in parallel for protocol, IEC61850 or IEC60870-5-103. 4 Typical communication scheme 4.1 Typical substation communication scheme 280 Chapter 22 Station communication Server or Work Station 1 Work Station 3 Server or Work Station 2 Switch Work Station 4 Net 1: IEC61850/IEC103,Ethernet Port A Switch Net 2: IEC61850/IEC103,Ethernet Port B Switch Switch Switch Gateway or converter Switch Gateway or converter Net 4: IEC103, RS485 Port B Net 3: IEC103, RS485 Port A Figure 93 Connection example for multi-networks of station automation system 4.2 Typical time synchronizing scheme All IEDs feature a permanently integrated electrical time synchronization port. It can be used to feed timing telegrams in IRIG-B or pulse format into the IEDs via time synchronization receivers. The IED can adapt the second or minute pulse in the pulse mode automatically. Meanwhile, SNTP network time synchronization can be applied. Below figure illustrates the optional time synchronization modes. SNTP Ethernet port IRIG-B IRIG-B port Pulse Binary input Figure 94 Time synchronizing modes 281 Chapter 22 Station communication 5 Technical data 5.1 Front communication port Item Data Number 1 Connection Isolated, RS232; front panel, 9-pin subminiature connector, for software tools Communication speed 9600 baud Max. length of communication cable 15 m 5.2 RS485 communication port Item Data Number 0 to 2 Connection 2-wire connector Rear port in communication module Max. length of communication cable 1.0 km Test voltage 500 V AC against earth For IEC 60870-5-103 protocol Communication speed Factory setting 9600 baud, Min. 1200 baud, Max. 19200 baud 5.3 Ethernet communication port Item Data Electrical communication port Number 0 to 3 Connection RJ45 connector Rear port in communication module Max. length of communication cable 100m For IEC 61850 protocol Communication speed 100 Mbit/s For IEC 60870-5-103 protocol Communication speed 282 100 Mbit/s Chapter 22 Station communication Optical communication port ( optional ) Number 0 to 2 Connection SC connector Rear port in communication module Optical cable type Multi-mode Max. length of communication cable 2.0km IEC 61850 protocol Communication speed 100 Mbit/s IEC 60870-5-103 protocol Communication speed 5.4 100 Mbit/s Time synchronization Item Data Mode Pulse mode IRIG-B signal format IRIG-B000 Connection 2-wire connector Rear port in communication module Voltage levels differential input 283 Chapter 23 Remote communication Chapter 23 Remote communication About this chapter This chapter describes the remote communication possibilities applied by protection functions. 284 Chapter 23 Remote communication 1 Binary signal transfer The binary signals can be exchanged through remote communication channels between the two IEDs on the two end of the transmission line or cable respectively. This functionality is mainly used for the line Tele-protection communication schemes, e.g., POTT or PUTT schemes, blocking scheme and inter trip and so on. 2 Remote communication channel 2.1 Introduction The IEDs are able to communicate with each other in two types: Directly fiber-optical cable connection mode at distances up to 100 km Through the communication converter with G.703 or G.703E1 interface through the public digital communication network Because there are up to two selectable fiber-optical remote communication ports, the IED can work in the redundant communication channel mode, with advantage of no time-delay channel switch in case of the primary channel broken Overhead Line or Cable Single-mode FO Length: <60kM or 60~100kM Channel A IED IED 285 Chapter 23 Remote communication Figure 95 Single channel, communication through dedicated fiber optical cable Overhead Line or Cable Single-mode FO Length: <60kM or 60~100kM Channel A Channel B IED IED Figure 96 Double channels, communication through dedicated fiber optical cable The link between the IED and a multiplexed communication network is made by dedicated communication converters (CSC186). They have a fiber-optic interface with 1310 nm and 2 FC connectors to the protection IED. The converter can be set to support an electrical G703-64 kbit/s or G703-E1 2Mbit/s interface, according the requirement of the multiplexed communication network. Overhead Line or Cable G703.5(E1: 2048kbit/s) G703.1(64kbit/s) o e IED 286 Communication converter Digital communication network e o Communication converter IED Chapter 23 Remote communication Figure 97 Single Channel, communication through digital communication network Overhead Line or Cable G703.5(E1: 2048kbit/s) G703.1(64kbit/s) Channel A Digital communication network o e o e IED Communication converter Digital communication network e o e o Communication converter IED Channel B Figure 98 Double channels, communication through digital communication network Overhead Line or Cable Single-mode FO Length: <60kM or 60~100kM Channel A o IED e Digital communication network e o IED Channel B G703.5(E1: 2048kbit/s) G703.1(64kbit/s) Figure 99 Double channels, one channel through digital communication network, one channel through dedicated fiber optical cables 3 Technical data 3.1 Fiber optic communication ports 287 Chapter 23 Remote communication Item Data Number 1 to 2 Fiber optic cable type Single-mode Optic wavelength 1310nm, when the transmission distance <60km; 1550nm, when the transmission distance >60km Optic received sensitivity -38dBm Emitter electric level >-8dBm; (the transmission distance <40km) >-4dBm; (the transmission distance 40~ 60km) >-3dBm; (the transmission distance >60km) Fiber optic connector type FC, when the transmission distance <60km) SC, when the transmission distance >60km Data transmission rate 64 kbit/s, G703; 2,048 kbit/s, G703-E1 Max. transmission distance 288 100kM Chapter 23 Remote communication 289 Chapter 24 Hardware Chapter 24 Hardware About this chapter This chapter describes the IED hardware. 290 Chapter 24 Hardware 1 Introduction 1.1 IED structure The enclosure for equipment is 19 inches in width and 4U in height according to IEC 60297-3. The equipment is flush mounting with panel cutout and cabinet. Connection terminals to other system on the rear. The front panel of equipment is aluminium alloy by founding in integer and overturn downwards. LCD, LED and setting keys are mounted on the panel. There is a serial interface on the panel suitable for connecting to PC. Draw-out modules for serviceability are fixed by lock component. The modules can be combined through the bus on the rear board. Both the equipment and the other system can be combined through the rear interfaces. 1.2 IED appearance Figure 100 Protection IED front view 291 Chapter 24 Hardware 1.3 IED module arrangement X1 X2 X3 X4 AIM CPU1 CPU2 COM BIM X5 X6 X7 X8 X9 X10 BOM1 BOM2 BOM3 BOM4 PSM Power supply module Spare slot for binary output module Binary output module 4 Binary output module 3 Binary output module 2 Binary output module 1 Binary input module Communication module CPU module 2 CPU module 1 Analogue Input module Figure 101 Module arrangement (front view, when open the front panel) 1.4 The rear view of the protection IED Test port X10 PSM For BIM and BOM X9 X8 X7 X6 Ethernet ports X5 X4 X3 COM Figure 102 Rear view of the protection IED 292 Fiber Optical ports X2 X1 AIM Chapter 24 Hardware 2 Local human-machine interface Setting operation and interrogation of numerical protection systems can be carried out via the integrated membrane keyboard and display panel located on the front plate. All the necessary operating parameters can be entered and all the information can be read out from here, e.g. display, main menu, debugging menu. Operation is, additionally, possible via interface socket by means of a personal computer or similar. 2.1 Human machine interface Front panel adopts little arc streamline and beelines sculpt, and function keys for MMI are reasonably distributed in faceplate. Panel layout is shown as Figure 103. 1 5 4 2 3 8 6 7 Figure 103 Front panel layout with 8 LEDs 293 Chapter 24 Hardware 1 5 4 2 3 8 6 7 Figure 104 Front panel layout with 20 LEDs 2.2 1. Liquid crystal display (LCD) 2. LEDs 3. Shortcut function keys 4. Arrow keys 5. Reset key 6. Quit key 7. Set key 8. RS232 communication port LCD The member of keyboard and display panel is externally arranged similar to a pocked calculator. 2.3 Keypad The keypad is used to monitor and operate the IED. The keypad has the same look and feel in all IEDs in the CSC series. LCD screens and other details may differ but the way the keys function is identical. The keys used to 294 Chapter 24 Hardware operate the IED are described below. Table 157 function of keys of the keypad Key SET function SET key: Enters main menu or sub-menu, and confirms the setting changes QUIT QUIT key: Navigates backward the upper menu. Cancels current operation and navigates backward the upper menu. Returns normal rolling display mode Locks and unlocks current display in the normal scrolling display mode; (the locked display mode is indicated by a key type icon on the upright corner of LCD.) Right arrow key: Moves right in menu. Left arrow key: Moves left in menu. Up arrow key: Moves up in menu Page up between screens Increases value of setting. Down arrow key Moves down in menu Page down between screens Decreases the value of setting. RESET key: RESET 2.4 Reset LEDs Return to normal scrolling display mode directly Shortcut keys and functional keys The shortcut keys and functional keys are below the LCD on the front panel. These keys are designated to execute the frequent menu operations for user’s convenience. The keys used to operate the IED are described below. Table 158 function of Shortcut keys and functional keys Key function F1 Reserved F2 Reserved 295 Chapter 24 Hardware F3 Reserved F4 Reserved + Plus key: Switch next setting group forward as active setting group, meaning the number of setting group plus one. _ Minus key Switch next setting group backward as active setting group , meaning the number of setting group subtracted one. 2.5 LED The definitions of the LEDs are fixed and described below for 8 LEDs. Table 159 Definition of 8 LEDs No LED Color Description Steady lighting: Operation normally 1 Run Green Flashing: IED startup Steady lighting: Alarm II, meaning abnormal situation, only the faulty function is out of service. Power supply for tripping output is not blocked. 8 Alarm Red Flashing: Alarm I, meaning severe internal fault, all protections are out of service. And power supply for tripping outputs is blocked as well. The definitions of the LEDs are fixed and described below for 20 LEDs. Table 160 Definition of 20 LEDs No LED Color Description Steady lighting: Operation normally 1 Run Green Flashing: IED startup Steady lighting: Alarm II, meaning abnormal situation, only the faulty function is out of service. Power supply 11 Alarm Red for tripping output is not blocked. Flashing: Alarm I, meaning severe internal fault, all 296 Chapter 24 Hardware No LED Color Description protections are out of service. And power supply for tripping outputs is blocked as well. The other LEDs which are not described above can be configured. 2.6 Front communication port There is a serial RS232 port on the front plate of all the IEDs. Through this port, the IED can be connected to the personal computer for setting, testing, and configuration using the dedicated Sifang software tool. 297 Chapter 24 Hardware 3 Analog input module 3.1 Introduction The analogue input module is used to galvanically separate and transform the secondary currents and voltages generated by the measuring transformers. There are two types of current transformer: Rated current 5A with linearity range 50mA~150A and rated current 1A with linearity range 100mA~30A (please indicate clearly when order the product). 3.2 Terminals of Analogue Input Module (AIM) b a b01 a01 b02 a02 b03 a03 b04 a04 b05 a05 b06 a06 b07 a07 b08 a08 b09 a09 b10 a10 b11 a11 b12 a12 Figure 105 Terminals arrangement of AIM E Table 161 Description of terminals of AIM E Terminal 298 Analogue Remark Chapter 24 Hardware Input a01 IA b01 I’A a02 IB b02 I’B a03 IC b03 I’C a04 I’N b04 IN a05 I’NM b05 INM a06 Null b06 Null a07 Null b07 Null a08 Null b08 Null a09 Null b09 Null a10 U4 b10 U’4 a11 UB Star point b11 UC Star point a12 UA Star point b12 UN 3.3 Technical data 3.3.1 Internal current transformer Item Rated current Ir Star point Star point Star point Star point Star point Star point Standard IEC 60255-1 Data 1 or 5 A Nominal current range 0.05 Ir to 30 Ir Nominal current range of 0.005 to 1 A 299 Chapter 24 Hardware sensitive CT Power consumption (per ≤ 0.1 VA at Ir = 1 A; phase) ≤ 0.5 VA at Ir = 5 A ≤ 0.5 VA for sensitive CT Thermal overload capability IEC 60255-1 100 Ir for 1 s IEC 60255-27 4 Ir continuous Thermal overload capability for IEC 60255-27 100 A for 1 s sensitive CT DL/T 478-2001 3 A continuous 3.3.2 Internal voltage transformer Item Rated voltage Vr (ph-ph) Standard IEC 60255-1 Nominal range (ph-e) Data 100 V /110 V 0.4 V to 120 V ≤ 0.1 VA per phase Power consumption at Vr = 110 IEC 60255-27 V DL/T 478-2001 Thermal overload capability IEC 60255-27 2 Vr, for 10s (phase-neutral voltage) DL/T 478-2001 1.5 Vr, continuous 300 Chapter 24 Hardware 4 CPU module 4.1 Introduction The CPU module handles all protection functions and logic. There are two CPU modules in the IED, CPU1 and CPU2, with the same software and hardware. They work in parallel and interlock each other to prevent maloperation due to the internal faults of one CPU modules. Moreover, the redundant A/D sampling channels are equipped. By comparing the data from redundant sampling channels, any sampling data errors and the channel hardware faults can be detected immediately and the proper alarm and blocking is initiated in time. 4.2 Communication ports of CPU module (CPU) RX Ch A TX RX Ch B TX 301 Chapter 24 Hardware Figure 106 Communication ports arrangement of CPU module Table 162 Definition of communication ports of CPU module Ports Definition Ch A RX Remote communication channel A optical fiber data receiving port Ch A TX Remote communication channel A optical fiber data transmitting port Ch B RX Remote communication channel B optical fiber data receiving port Ch B TX Remote communication channel B optical fiber data transmitting port Note: These ports are optional 302 Chapter 24 Hardware 5 Communication module 5.1 Introduction The communication module performs communication between the internal protection system and external equipments such as HMI, engineering workstation, substation automation system, RTU, etc., to transmit remote metering, remote signaling, SOE, event reports and record data. Up to 3 channels isolated electrical or optical Ethernet ports and up to 2 channels RS485 serial communication ports can be provided in communication module to meet the communication demands of different substation automation system and RTU at the same time. The time synchronization port is equipped, which can work in pulse mode or IRIG-B mode. SNTP mode can be applied through communication port. In addition, a series printer port is also reserved. 5.2 Substaion communication port 5.2.1 RS232 communication ports There is a serial RS232 port on the front plate of all the IEDs. Through this port, the IED can be connected to the personal computer for setting, testing, and configuration using the dedicated Sifang software tool. 5.2.2 RS485 communication ports Up to 2 isolated electrical RS485 communication ports are provided to connect with substation automation system. These two ports can work in parallel for IEC60870-5-103. 5.2.3 Ethernet communication ports Up to 3 electrical or optical Ethernet communication ports are provided to connect with substation automation system. Two out of these three ports can 303 Chapter 24 Hardware work in parallel for protocol, IEC61850 or IEC60870-5-103. 5.2.4 Time synchronization port All IEDs feature a permanently integrated electrical time synchronization port. It can be used to feed timing telegrams in IRIG-B or pulse format into the IEDs via time synchronization receivers. The IED can adapt the second or minute pulse in the pulse mode automatically. Meanwhile, SNTP network time synchronization can also be applied. 5.3 Terminals of Communication Module 01 02 Ethernet port A 03 04 05 06 Ethernet port B 07 08 09 10 11 Ethernet port C 12 13 14 15 16 Figure 107 Terminals arrangement of COM Table 163 Definition of terminals of COM 304 Terminal Definition 01 Null 02 Null 03 Null 04 Null Chapter 24 Hardware 05 Optional RS485 port - 2B 06 Optional RS485 port - 2A 07 Optional RS485 port - 1B 08 Optional RS485 port - 1A 09 Time synchronization 10 Time synchronization GND 11 Null 12 Null 13 Null 14 Null 15 Null 16 Null Ethernet Port A Optional optical fiber or RJ45 port for station automation system Ethernet Port B Optional optical fiber or RJ45 port for station automation system Ethernet Port C Optional optical fiber or RJ45 port for station automation system 5.4 Operating reports Information Description DI Comm Fail DI communication error DO Comm Fail DO communication error 5.5 Technical data 5.5.1 Front communication port Item Number Data 1 305 Chapter 24 Hardware Connection Isolated, RS232; front panel, 9-pin subminiature connector, for software tools Communication speed 9600 baud Max. length of communication cable 15 m 5.5.2 RS485 communication port Item Data Number 0 to 2 Connection 2-wire connector Rear port in communication module Max. length of communication cable 1.0 km Test voltage 500 V AC against earth For IEC 60870-5-103 protocol Communication speed Factory setting 9600 baud, Min. 1200 baud, Max. 19200 baud 5.5.3 Ethernet communication port Item Data Electrical communication port Number 0 to 3 Connection RJ45 connector Rear port in communication module Max. length of communication cable 100m For IEC 61850 protocol Communication speed 100 Mbit/s For IEC 60870-5-103 protocol Communication speed 100 Mbit/s Optical communication port ( optional ) Number 0 to 2 Connection SC connector Rear port in communication module Optical cable type Multi-mode Max. length of communication cable 2.0km IEC 61850 protocol 306 Chapter 24 Hardware Communication speed 100 Mbit/s IEC 60870-5-103 protocol Communication speed 5.5.4 100 Mbit/s Time synchronization Item Data Mode Pulse mode IRIG-B signal format IRIG-B000 Connection 2-wire connector Rear port in communication module Voltage levels differential input 307 Chapter 24 Hardware 6 Binary input module 6.1 Introduction The binary input module is used to connect the input signals and alarm signals such as the auxiliary contacts of the circuit breaker (CB), etc. The negative terminal of power supply for BI module, 220V or 110V, should be connected to the terminal. 6.2 Terminals of Binary Input Module (BIM) c a c02 a02 c04 a04 c06 a06 c08 a08 c10 a10 c12 a12 c14 a14 c16 a16 c18 a18 c20 a20 c22 a22 c24 a24 c26 a26 c28 a28 c30 a30 c32 DC - DC - a32 Figure 108: Terminals arrangement of BIM A 308 Chapter 24 Hardware Table 164 Definition of terminals of BIM A Terminal Definition Remark a02 BI1 BI group 1 c02 BI2 BI group 2 a04 BI3 BI group 1 c04 BI4 BI group 2 a06 BI5 BI group 1 c06 BI6 BI group 2 a08 BI7 BI group 1 c08 BI8 BI group 2 a10 BI9 BI group 1 c10 BI10 BI group 2 a12 BI11 BI group 1 c12 BI12 BI group 2 a14 BI13 BI group 1 c14 BI14 BI group 2 a16 BI15 BI group 1 c16 BI16 BI group 2 a18 BI17 BI group 1 c18 BI18 BI group 2 a20 BI19 BI group 1 c20 BI20 BI group 2 a22 BI21 BI group 1 c22 BI22 BI group 2 a24 BI23 BI group 1 c24 BI24 BI group 2 a26 BI25 BI group 1 c26 BI26 BI group 2 a28 BI27 BI group 1 c28 BI28 BI group 2 a30 BI29 BI group 1 c30 BI30 BI group 2 a32 DC - Input Common terminal of BI group 1 c32 DC - Input Common terminal of BI group 2 309 Chapter 24 Hardware 6.3 Technical data Item Input voltage range Standard IEC60255-1 Data 110/125 V 220/250 V Threshold1: guarantee IEC60255-1 operation Threshold2: uncertain 77V, for 110V/125V IEC60255-1 operation Response time/reset time 154V, for 220/250V 132V, for 220/250V ; 66V, for 110V/125V IEC60255-1 Software provides de-bounce time Power consumption, energized 310 IEC60255-1 Max. 0.5 W/input, 110V Max. 1 W/input, 220V Chapter 24 Hardware 7 Binary output module 7.1 Introduction The binary output modules mainly provide tripping output contacts, initiating output contacts and signaling output contacts. All the tripping output relays have contacts with a high switching capacity and are blocked by protection startup elements. Each output relay can be configured to satisfy the demands of users. 7.2 Terminals of Binary Output Module (BOM) 7.2.1 Binary Output Module A The module provides 16 output relays for tripping or initiating, with total 16 contacts. 311 Chapter 24 Hardware R 1 R 3 R 5 R 7 R 9 R 11 R 13 R 15 c a c02 a02 c04 a04 c06 a06 c08 a08 c10 a10 c12 a12 c14 a14 c16 a16 c18 a18 c20 a20 c22 a22 c24 a24 c26 a26 c28 a28 c30 a30 c32 a32 R 2 R 4 R 6 R 8 R 10 R 12 R 14 R 16 Figure 109 Terminals arrangement of BOM A 312 Chapter 24 Hardware Table 165 Definition of terminals of BOM A Terminal Definition Related relay a02 Trip contact 1-0 Output relay 1 c02 Trip contact 1-1 Output relay 1 a04 Trip contact 2-0 Output relay 2 c04 Trip contact 2-1 Output relay 2 a06 Trip contact 3-0 Output relay 3 c06 Trip contact 3-1 Output relay 3 a08 Trip contact 4-0 Output relay 4 c08 Trip contact 4-1 Output relay 4 a10 Trip contact 5-0 Output relay 5 c10 Trip contact 5-1 Output relay 5 a12 Trip contact 6-0 Output relay 6 c12 Trip contact 6-1 Output relay 6 a14 Trip contact 7-0 Output relay 7 c14 Trip contact 7-1 Output relay 7 a16 Trip contact 8-0 Output relay 8 c16 Trip contact 8-1 Output relay 8 a18 Trip contact 9-0 Output relay 9 c18 Trip contact 9-1 Output relay 9 a20 Trip contact 10-0 Output relay 10 c20 Trip contact 10-1 Output relay 10 a22 Trip contact 11-0 Output relay 11 c22 Trip contact 11-1 Output relay 11 a24 Trip contact 12-0 Output relay 12 c24 Trip contact 12-1 Output relay 12 a26 Trip contact 13-0 Output relay 13 c26 Trip contact 13-1 Output relay 13 a28 Trip contact 14-0 Output relay 14 c28 Trip contact 14-1 Output relay 14 a30 Trip contact 15-0 Output relay 15 c30 Trip contact 15-1 Output relay 15 a32 Trip contact 16-0 Output relay 16 c32 Trip contact 16-1 Output relay 16 313 Chapter 24 Hardware Binary Output Module C 7.2.2 The module provides 16 output relays for signal, with total 19 contacts. R 4 R 5 R 1 R 2 R 3 R 6 R 7 c a c02 a02 c04 a04 c06 a06 c08 a08 c10 a10 c12 a12 c14 a14 c16 a16 c18 a18 c20 a20 c22 a22 c24 a24 c26 a26 c28 a28 c30 a30 c32 a32 R 8 R 9 R 10 R 11 R 12 R 13 R 14 R 15 R 16 Figure 110 Terminals arrangement of BOM C Table 166 Definition of terminals of BOM C Terminal 314 Definition a02 Signal 1-0, Common terminal of signal contact group 1 c02 Signal 2-0, Common terminal of signal contact group 2 Related relay Chapter 24 Hardware 7.3 a04 Signal contact 1-1 Output relay 1 c04 Signal contact 2-1 Output relay 1 a06 Signal contact 1-2 Output relay 2 c06 Signal contact 2-2 Output relay 2 a08 Signal contact 1-3 Output relay 3 c08 Signal contact 2-3 Output relay 3 a10 Signal 3-0, Common terminal of signal contact group 3 c10 Signal 4-0, Common terminal of signal contact group 4 a12 Signal contact 3-1 Output relay 4 c12 Signal contact 4-1 Output relay 7 a14 Signal contact 3-2 Output relay 5 c14 Signal contact 4-2 Output relay 6 a16 Signal contact 5-0 Output relay 8 c16 Signal contact 5-1 Output relay 8 a18 Signal contact 6-0 Output relay 9 c18 Signal contact 6-1 Output relay 9 a20 Signal contact 7-0 Output relay 10 c20 Signal contact 7-1 Output relay 10 a22 Signal contact 8-0 Output relay 11 c22 Signal contact 8-1 Output relay 11 a24 Signal contact 9-0 Output relay 12 c24 Signal contact 9-1 Output relay 12 a26 Signal contact 10-0 Output relay 13 c26 Signal contact 10-1 Output relay 13 a28 Signal contact 11-0 Output relay 14 c28 Signal contact 11-1 Output relay 14 a30 Signal contact 12-0 Output relay 15 c30 Signal contact 12-1 Output relay 15 a32 Signal contact 13-0 Output relay 16 c32 Signal contact 13-1 Output relay 16 Technical data Item Max. system voltage Standard IEC60255-1 Data 250V /~ 315 Chapter 24 Hardware Current carrying capacity IEC60255-1 5 A continuous, 30A,200ms ON, 15s OFF Making capacity IEC60255-1 1100 W( ) at inductive load with L/R>40 ms 1000 VA(AC) Breaking capacity Mechanical endurance, IEC60255-1 IEC60255-1 Unloaded 220V , 0.15A, at L/R≤40 ms 110V , 0.30A, at L/R≤40 ms 50,000,000 cycles (3 Hz switching frequency) Mechanical endurance, making IEC60255-1 ≥1000 cycles Mechanical endurance, IEC60255-1 ≥1000 cycles IEC60255-1 UL/CSA、TŰV breaking Specification state verification IEC60255-23 IEC61810-1 Contact circuit resistance IEC60255-1 measurement IEC60255-23 30mΩ IEC61810-1 Open Contact insulation test IEC60255-1 (AC Dielectric strength) IEC60255-27 Maximum temperature of parts IEC60255-1 and materials 316 AC1000V 1min 55℃ Chapter 24 Hardware 8 Power supply module 8.1 Introduction The power supply module is used to provide the correct internal voltages and full isolation between the terminal and the battery system. Its power input is DC 220V or 110V (according to the order code), and its outputs are five groups of power supply. (1) +24V two groups provided: Power for inputs of the corresponding binary inputs of the CPU module 8.2 (2) ±12V: Power for A/D (3) + 5V: Power for all micro-chips Terminals of Power Supply Module (PSM) c c02 c04 a DC 24V + OUTPUTS a04 a06 c06 a08 c08 c10 a02 DC 24V OUTPUTS a10 c12 a12 c14 a14 c16 a16 c18 a18 c20 c22 AUX.DC + INPUT c24 c26 c28 a20 a22 a24 AUX. DC INPUT a26 a28 c30 a30 c32 a32 317 Chapter 24 Hardware Figure 111 Terminals arrangement of PSM Table 167 Definition of terminals of PSM 318 Terminal Definition a02 AUX.DC 24V+ output 1 c02 AUX.DC 24V+ output 2 a04 AUX.DC 24V+ output 3 c04 AUX.DC 24V+ output 4 a06 Isolated terminal, not wired c06 Isolated terminal, not wired a08 AUX.DC 24V- output 1 c08 AUX.DC 24V- output 2 a10 AUX.DC 24V- output 3 c10 AUX.DC 24V- output 4 a12 AUX.DC 24V- output 5 c12 AUX.DC 24V- output 6 a14 Alarm contact A1, for AUX.DC power input failure c14 Alarm contact A0, for AUX.DC power input failure a16 Alarm contact B1, for AUX.DC power input failure c16 Alarm contact B0, for AUX.DC power input failure a18 Isolated terminal, not wired c18 Isolated terminal, not wired a20 AUX. power input 1, DC + c20 AUX. power input 2, DC + a22 AUX. power input 3, DC + c22 AUX. power input 4, DC + a24 Isolated terminal, not wired c24 Isolated terminal, not wired a26 AUX. power input 1, DC - c26 AUX. power input 2, DC - a28 AUX. power input 3, DC - c28 AUX. power input 4, DC - a30 Isolated terminal, not wired c30 Isolated terminal, not wired a32 Terminal for earthing Chapter 24 Hardware c32 8.3 Terminal for earthing Technical data Item Standard Data Rated auxiliary voltage Uaux IEC60255-1 110 to 250V Permissible tolerance IEC60255-1 ±%20 Uaux Power consumption at IEC60255-1 ≤ 50 W per power supply quiescent state Power consumption at module IEC60255-1 maximum load Inrush Current ≤ 60 W per power supply module IEC60255-1 T ≤ 10 ms/I≤ 25 A per power supply module, 319 Chapter 24 Hardware 9 Techinical data 9.1 Basic data 9.1.1 Frequency Item Rated system frequency 9.1.2 Standard IEC 60255-1 Data 50 Hz or 60Hz Internal current transformer Item Rated current Ir Standard IEC 60255-1 Data 1 or 5 A Nominal current range 0.05 Ir to 30 Ir Nominal current range of 0.005 to 1 A sensitive CT Power consumption (per ≤ 0.1 VA at Ir = 1 A; phase) ≤ 0.5 VA at Ir = 5 A ≤ 0.5 VA for sensitive CT Thermal overload capability IEC 60255-1 100 Ir for 1 s IEC 60255-27 4 Ir continuous Thermal overload capability for IEC 60255-27 100 A for 1 s sensitive CT DL/T 478-2001 3 A continuous 9.1.3 Internal voltage transformer Item Rated voltage Vr (ph-ph) Standard IEC 60255-1 Nominal range (ph-e) Data 100 V /110 V 0.4 V to 120 V ≤ 0.1 VA per phase Power consumption at Vr = 110 IEC 60255-27 V DL/T 478-2001 Thermal overload capability IEC 60255-27 2 Vr, for 10s (phase-neutral voltage) DL/T 478-2001 1.5 Vr, continuous 320 Chapter 24 Hardware 9.1.4 Auxiliary voltage Item Standard Data Rated auxiliary voltage Uaux IEC60255-1 110 to 250V Permissible tolerance IEC60255-1 ±%20 Uaux Power consumption at IEC60255-1 ≤ 50 W per power supply quiescent state module Power consumption at IEC60255-1 maximum load ≤ 60 W per power supply module Inrush Current IEC60255-1 T ≤ 10 ms/I≤ 25 A per power supply module, 9.1.5 Binary inputs Item Input voltage range Standard IEC60255-1 Data 110/125 V 220/250 V Threshold1: guarantee IEC60255-1 operation 154V, for 220/250V 77V, for 110V/125V Threshold2: uncertain IEC60255-1 operation 132V, for 220/250V ; 66V, for 110V/125V Response time/reset time IEC60255-1 Software provides de-bounce time Power consumption, IEC60255-1 energized 9.1.6 Max. 0.5 W/input, 110V Max. 1 W/input, 220V Binary outputs Item Standard Data Max. system voltage IEC60255-1 250V /~ Current carrying capacity IEC60255-1 5 A continuous, 30A,200ms ON, 15s OFF Making capacity IEC60255-1 1100 W( ) at inductive load with L/R>40 ms 1000 VA(AC) Breaking capacity IEC60255-1 220V , 0.15A, at L/R≤40 ms 110V , 0.30A, at L/R≤40 ms 321 Chapter 24 Hardware Mechanical endurance, IEC60255-1 Unloaded 50,000,000 cycles (3 Hz switching frequency) Mechanical endurance, making IEC60255-1 ≥1000 cycles Mechanical endurance, IEC60255-1 ≥1000 cycles IEC60255-1 UL/CSA、TŰV breaking Specification state verification IEC60255-23 IEC61810-1 Contact circuit resistance IEC60255-1 measurement IEC60255-23 30mΩ IEC61810-1 Open Contact insulation test IEC60255-1 (AC Dielectric strength) IEC60255-27 Maximum temperature of parts IEC60255-1 AC1000V 1min 55℃ and materials 9.2 Type tests 9.2.1 Product safety-related tests Item Standard Data Over voltage category IEC60255-27 Category III Pollution degree IEC60255-27 Degree 2 Insulation IEC60255-27 Basic insulation Degree of protection (IP) IEC60255-27 Front plate: IP40 IEC 60529 Rear, side, top and bottom: IP 30 Power frequency high voltage IEC 60255-5 2KV, 50Hz withstand test EN 60255-5 2.8kV ANSI C37.90 between the following circuits: GB/T 15145-2001 auxiliary power supply DL/T 478-2001 CT / VT inputs binary inputs binary outputs case earth 500V, 50Hz between the following circuits: 322 Chapter 24 Hardware Item Standard Data Communication ports to case earth time synchronization terminals to case earth Impulse voltage test IEC60255-5 5kV (1.2/50μs, 0.5J) IEC 60255-27 If Ui≥63V EN 60255-5 1kV if Ui<63V ANSI C37.90 Tested between the following GB/T 15145-2001 circuits: DL/T 478-2001 auxiliary power supply CT / VT inputs binary inputs binary outputs case earth Note: Ui: Rated voltage Insulation resistance IEC60255-5 ≥ 100 MΩ at 500 V IEC 60255-27 EN 60255-5 ANSI C37.90 GB/T 15145-2001 DL/T 478-2001 Protective bonding resistance IEC60255-27 ≤ 0.1Ω Fire withstand/flammability IEC60255-27 Class V2 9.2.2 Electromagnetic immunity tests Item 1 MHz burst immunity test Standard Data IEC60255-22-1 Class III IEC60255-26 2.5 kV CM ; 1 kV DM IEC61000-4-18 Tested on the following circuits: EN 60255-22-1 auxiliary power supply ANSI/IEEE C37.90.1 CT / VT inputs binary inputs binary outputs 1 kV CM ; 0 kV DM Tested on the following circuits: communication ports Electrostatic discharge IEC 60255-22-2 Level 4 323 Chapter 24 Hardware IEC 61000-4-2 8 kV contact discharge; EN 60255-22-2 15 kV air gap discharge; both polarities; 150 pF; Ri = 330 Ω Radiated electromagnetic field IEC 60255-22-3 Frequency sweep: disturbance test EN 60255-22-3 80 MHz – 1 GHz; 1.4 GHz – 2.7 GHz spot frequencies: 80 MHz; 160 MHz; 380 MHz; 450 MHz; 900 MHz; 1850 MHz; 2150 MHz 10 V/m AM, 80%, 1 kHz Radiated electromagnetic field IEC 60255-22-3 Pulse-modulated disturbance test EN 60255-22-3 10 V/m, 900 MHz; repetition rate 200 Hz, on duration 50 % Electric fast transient/burst IEC 60255-22-4, Class A, 4KV immunity test IEC 61000-4-4 Tested on the following circuits: EN 60255-22-4 auxiliary power supply ANSI/IEEE C37.90.1 CT / VT inputs binary inputs binary outputs Class A, 1KV Tested on the following circuits: communication ports Surge immunity test IEC 60255-22-5 4.0kV L-E IEC 61000-4-5 2.0kV L-L Tested on the following circuits: auxiliary power supply CT / VT inputs binary inputs binary outputs 500V L-E Tested on the following circuits: communication ports Conduct immunity test IEC 60255-22-6 Frequency sweep: 150 kHz – 80 IEC 61000-4-6 MHz spot frequencies: 27 MHz and 68 MHz 10 V AM, 80%, 1 kHz 324 Chapter 24 Hardware Power frequency immunity test IEC60255-22-7 Class A 300 V CM 150 V DM Power frequency magnetic field IEC 61000-4-8 test Level 4 30 A/m cont. / 300 A/m 1 s to 3 s 100 kHz burst immunity test IEC61000-4-18 2.5 kV CM ; 1 kV DM Tested on the following circuits: auxiliary power supply CT / VT inputs binary inputs binary outputs 1 kV CM ; 0 kV DM Tested on the following circuits: communication ports 9.2.3 DC voltage interruption test Item DC voltage dips Standard IEC 60255-11 Data 100% reduction 20 ms 60% reduction 200 ms 30% reduction 500 ms DC voltage interruptions IEC 60255-11 100% reduction 5 s DC voltage ripple IEC 60255-11 15%, twice rated frequency DC voltage gradual shut–down IEC 60255-11 60 s shut down ramp /start-up 5 min power off 60 s start-up ramp DC voltage reverse polarity 9.2.4 IEC 60255-11 1 min Electromagnetic emission test Item Radiated emission Standard Data IEC60255-25 30MHz to 1GHz ( IT device may EN60255-25 up to 5 GHz) CISPR22 Conducted emission IEC60255-25 0.15MHz to 30MHz EN60255-25 CISPR22 325 Chapter 24 Hardware 9.2.5 Mechanical tests Item Standard Data Sinusoidal Vibration response IEC60255-21-1 Class 1 test EN 60255-21-1 10 Hz to 60 Hz: 0.075 mm 60 Hz to 150 Hz: 1 g 1 sweep cycle in each axis Relay energized Sinusoidal Vibration IEC60255-21-1 Class 1 endurance test EN 60255-21-1 10 Hz to 150 Hz: 1 g 20 sweep cycle in each axis Relay non-energized Shock response test IEC60255-21-2 Class 1 EN 60255-21-2 5 g, 11 ms duration 3 shocks in both directions of 3 axes Relay energized Shock withstand test IEC60255-21-2 Class 1 EN 60255-21-2 15 g, 11 ms duration 3 shocks in both directions of 3 axes Relay non-energized Bump test IEC60255-21-2 Class 1 10 g, 16 ms duration 1000 shocks in both directions of 3 axes Relay non-energized Seismic test IEC60255-21-3 Class 1 X-axis 1 Hz to 8/9 Hz: 7.5 mm X-axis 8/9 Hz to 35 Hz :2 g Y-axis 1 Hz to 8/9 Hz: 3.75 mm Y-axis 8/9 Hz to 35 Hz :1 g 1 sweep cycle in each axis, Relay energized 9.2.6 Climatic tests Item 326 Standard Data Chapter 24 Hardware Cold test - Operation IEC60255-27 -10°C, 16 hours, rated load IEC60068-2-1 Cold test – Storage IEC60255-27 -25°C, 16 hours IEC60068-2-1 Dry heat test – Operation [IEC60255-27 +55°C, 16 hours, rated load IEC60068-2-2 Dry heat test – Storage IEC60255-27 +70°C, 16 hours IEC60068-2-2 Change of temperature Damp heat static test Damp heat cyclic test 9.2.7 IEC60255-27 Test Nb, figure 2, 5 cycles IEC60068-2-14 -10°C / +55°C IEC60255-27 +40°C, 93% r.h. 10 days, rated IEC60068-2-78 load IEC60255-27 +55°C, 93% r.h. 6 cycles, rated IEC60068-2-30 load CE Certificate Item EN 61000-6-2 and EN61000-6-4 (EMC EMC Directive Council Directive 2004/108/EC) Low voltage directive 9.3 Data EN 60255-27 (Low-voltage directive 2006/95 EC). IED design Item Data Case size 4U×19inch Weight ≤ 10kg 327 Chapter 25 Appendix Chapter 25 Appendix About this chapter This chapter describes the appendix. 328 Chapter 25 Appendix 1 General setting list 1.1 Function setting list No Setting Unit Min. Max. Default (Ir:5A/1 (Ir:5A/1 setting A) A) (Ir:5A/1A) Description Sudden-change 1 I_abrupt A 0.08Ir 20Ir 0.2Ir current threshold of startup element 2 3 4 5 6 7 T_Relay Reset U_Primary U_Seconda ry CT_Primary CT_Second ary I_VT Fail s 0.5 10 1 kV 30 800 230 The reset time of relay Rated primary voltage (phase to phase) Rated secondary V 100 120 100 voltage (phase to phase) kA 0.05 5 3 A 1 5 1 A 0.08Ir 0.2Ir 0.1Ir Rated primary current Rated secondary current current threshold of PT failure detection Negative sequence/zero 8 3I02_VT Fail A 0.08Ir 0.2Ir 0.1Ir sequence current threshold of release blocking due to VT failure 9 10 11 Upe_VT Fail Upp_VT Fail Upe_VT Normal voltage (phase to V 7 20 8 earth) threshold of PT failure detection voltage (phase to V 10 30 16 phase) threshold of PT failure detection restore voltage V 40 65 40 threshold of PT failure detection zero sequence current 12 3I0_CT Fail A 0.08Ir 2Ir 0.2Ir threshold of CT failure detection 329 Chapter 25 Appendix nagative sequence 13 3I2_Broken Conduct A 0.08Ir 2Ir 2Ir current threshold of conduct broken detection 14 T_Broken Conduct s 0 250 10 time delay of conduct broken detection compensation factor of 15 Kx -0.33 8 1 zero sequence reactance compensation factor of 16 Kr -0.33 8 1 zero sequence resistance compensation factor of 17 Km -0.33 8 0 zero sequence mutual inductance of parallel line 18 X_Line Ohm 0.01 600 10 19 R_Line Ohm 0.01 600 2 20 Line length km 0.1 999 100 ms 0 100 40 21 T_Tele Reversal positive reactance of the whole line positive resistance of the whole line Length of line Time delay of power reserve zero sequence current 22 3I0_Tele EF threshold of A 0.08Ir 20Ir 0.2Ir tele-protection based on earth fault protection time delay of 23 T0_Tele EF s 0.01 10 0.15 tele-protection based on earth fault protection current threshold of 24 I_PSB A 0.5 20Ir 2Ir power system unstability detection resistance reach of 25 R1_PE Ohm 0.01/0. 120/60 05 0 1/5 zone 1 of phase to earth distance protection reactance reach of 26 X1_PE Ohm 0.01/0. 120/60 05 0 1/5 zone 1 of phase to earth distance protection 330 Chapter 25 Appendix resistance reach of 27 R2_PE Ohm 0.01/0. 120/60 05 0 1.6/8 zone 2 of phase to earth distance protection reactance reach of 28 X2_PE Ohm 0.01/0. 120/60 05 0 1.6/8 zone 2 of phase to earth distance protection resistance reach of 29 R3_PE Ohm 0.01/0. 120/60 05 0 2.4/12 zone 3 of phase to earth distance protection reactance reach of 30 X3_PE Ohm 0.01/0. 120/60 05 0 2.4/12 zone 3 of phase to earth distance protection resistance reach of 31 R4_PE Ohm 0.01/0. 120/60 05 0 3/15 zone 4 of phase to earth distance protection reactance reach of 32 X4_PE Ohm 0.01/0. 120/60 05 0 3/15 zone 4 of phase to earth distance protection resistance reach of 33 R5_PE Ohm 0.01/0. 120/60 05 0 3.6/18 zone 5 of phase to earth distance protection reactance reach of 34 X5_PE Ohm 0.01/0. 120/60 05 0 3.6/18 zone 5 of phase to earth distance protection resistance reach of 35 R1Ext_PE Ohm 0.01/0. 120/60 05 0 1.6/8 extended zone 1 of phase to earth distance protection reactance reach of 36 X1Ext_PE Ohm 0.01/0. 120/60 05 0 1.6/8 extended zone 1 of phase to earth distance protection delay time of zone 1 of 37 T1_PE s 0 60 0 phase to earth distance protection 331 Chapter 25 Appendix delay time of zone 2 of 38 T2_PE s 0 60 0.3 phase to earth distance protection delay time of zone 3 of 39 T3_PE s 0 60 0.6 phase to earth distance protection delay time of zone 4 of 40 T4_PE s 0 60 0.9 phase to earth distance protection delay time of zone 5 of 41 T5_PE s 0 60 1.2 phase to earth distance protection delay time of extended 42 T1_Ext_PE s 0 60 0.05 zone 1 of phase to earth distance protection resistance reach of 43 R1_PP Ohm 0.01/0. 120/60 05 0 1/5 zone 1 of phase to phase distance protection reactance reach of 44 X1_PP Ohm 0.01/0. 120/60 05 0 1/5 zone 1 of phase to phase distance protection resistance reach of 45 R2_PP Ohm 0.01/0. 120/60 05 0 1.6/8 zone 2 of phase to phase distance protection reactance reach of 46 X2_PP Ohm 0.01/0. 120/60 05 0 1.6/8 zone 2 of phase to phase distance protection resistance reach of 47 R3_PP Ohm 0.01/0. 120/60 05 0 2.4/12 zone 3 of phase to phase distance protection reactance reach of 48 X3_PP Ohm 0.01/0. 120/60 05 0 2.4/12 zone 3 of phase to phase distance protection resistance reach of 49 R4_PP Ohm 0.01/0. 120/60 05 0 3/15 zone 4 of phase to phase distance protection 332 Chapter 25 Appendix reactance reach of 50 X4_PP Ohm 0.01/0. 120/60 05 0 3/15 zone 4 of phase to phase distance protection resistance reach of 51 R5_PP Ohm 0.01/0. 120/60 05 0 3.6/18 zone 5 of phase to phase distance protection reactance reach of 52 X5_PP Ohm 0.01/0. 120/60 05 0 3.6/18 zone 5 of phase to phase distance protection resistance reach of 53 R1Ext_PP Ohm 0.01/0. 120/60 05 0 1.6/8 extended zone 1 of phase to phase distance protection reactance reach of 54 X1Ext_PP Ohm 0.01/0. 120/60 05 0 1.6/8 extended zone 1 of phase to phase distance protection delay time of zone 1 of 55 T1_PP s 0 60 0 phase to phase distance protection delay time of zone 2 of 56 T2_PP s 0 60 0.3 phase to phase distance protection delay time of zone 3 of 57 T3_PP s 0 60 0.6 phase to phase distance protection delay time of zone 4 of 58 T4_PP s 0 60 0.9 phase to phase distance protection delay time of zone 5 of 59 T5_PP s 0 60 1.2 phase to phase distance protection delay time of extended 60 T1_Ext_PP s 0 60 0.05 zone 1 of phase to phase distance protection current threshold of 61 I_SOTF_Di st A 0.08Ir 2Ir 0.2Ir manual switch onto faulty line for distance+G252 333 Chapter 25 Appendix zero sequence current 62 3I0_Dist_P E A 0.1Ir 2Ir 0.1Ir threshold of phase to earth distance protection zero sequence voltage 63 3U0_Dist_ PE V 0.5 60 1 threshold of phase to earth distance protection high current threshold 64 I_Diff High A 0.1Ir 20Ir 0.4Ir of differential protection low current threshold 65 I_Diff Low A 0.1Ir 20Ir 0.4Ir of differential protection 66 I_Diff TA Fail current threshold of A 0.1Ir 20Ir 2Ir differential protection at CT failure zero sequence current 67 I_Diff ZeroSeq A 0.1Ir 20Ir 0.2Ir threshold of zero sequence differential protection 68 T_Diff ZeroSeq 69 T_DTT 70 CT Factor delay time of zero s 0.1 60 0.1 sequence differential protection s 0 10 0.1 0.2 1 1 delay time of DTT convert factor of CT ratio positive sequence 71 XC1 Ohm 40 9000 9000 capacitive reactance of line zero sequence 72 XC0 Ohm 40 9000 9000 capacitive reactance of line positive sequence 73 X1_Reactor Ohm 90 9000 9000 reactance of shunt reactor zero sequence 74 X0_Reactor Ohm 90 9000 9000 reactance of shunt reactor 75 76 77 334 Local Address Opposite Address I_OC1 A 0 65535 0 0 65535 0 0.08Ir 20Ir 2Ir identified code of local end of line identified code of opposite end of line current threshold of Chapter 25 Appendix overcurrent stage 1 78 T_OC1 s 0 60 0.1 79 I_OC2 A 0.08Ir 20Ir 1Ir 80 T_OC2 s 0 60 0.3 81 82 overcurrent stage 1 current threshold of overcurrent stage 2 delay time of overcurrent stage 2 No.of inverse time Curve_OC 1 Inv I_OC Inv delay time of 12 1 characteristic curve of overcurrent A 0.08Ir 20Ir 1Ir start current of inverse time overcurrent time multiplier of 83 K_OC Inv 0.05 999 1 customized inverse time characteristic curve for overcurrent time constant A of 84 A_OC Inv s 0 200 0.14 customized inverse time characteristic curve for overcurrent time constant B of 85 B_OC Inv s 0 60 0 customized inverse time characteristic curve for overcurrent index of customized 86 P_OC Inv 0 10 0.02 inverse time characteristic curve for overcurrent the angle of bisector of 87 Angle_OC Degre e 0 90 60 operation area of overcurrent directional element 88 Imax_2H_U nBlk the maximum current A 0.25 20Ir 5Ir to release harmornic block ratio of 2rd harmonic 89 Ratio_I2/I1 0.07 0.5 0.2 to fundamental component 90 T2h_Cross _Blk delay time of cross s 0 60 1 block by 2rd harmormic zero sequence current 91 3I0_EF1 A 0.08Ir 20Ir 0.5Ir threshold of earth fault protection stage 1 335 Chapter 25 Appendix 92 T_EF1 s 0 60 0.1 delay time of earth fault protection stage 1 zero sequence current 93 3I0_EF2 A 0.08Ir 20Ir 0.2Ir threshold of earth fault protection stage 2 94 95 T_EF2 s 0 60 0.3 delay time of earth fault protection stage 2 No. of inverse time Curve_EF 1 Inv 12 1 characteristic curve of earth fault protection start current of inverse 96 3I0_EF Inv A 0.08Ir 20Ir 0.2Ir time earth fault protection time multiplier of customized inverse 97 K_EF Inv 0.05 999 1 time characteristic curve for earth fault protection time constant A of customized inverse 98 A_EF Inv s 0 200 0.14 time characteristic curve for earth fault protection time constant B of customized inverse 99 B_EF Inv s 0 60 0 time characteristic curve for earth fault protection index of customized 100 P_EF Inv 0 10 0.02 inverse time characteristic curve for earht fault protection the angle of bisector of 101 Angle_EF Degre e 0 90 70 operation area of zero sequnce directional element the angle of bisector of 102 Angle_Neg Degre e 50 90 70 operation area of negative sequnce directional element 103 336 I_Em/BU OC current threshold of A 0.08Ir 20Ir 1Ir emergency/backup overcurrent stage 1 Chapter 25 Appendix 104 T_Em/BU OC delay time of s 0 60 0.3 emergency/backup overcurrent stage 1 No.of inverse time 105 Curve_Em/ 1 BU OC Inv 12 1 characteristic curve of emergency/backup overcurrent start current of inverse 106 I_Inv_Em/B U OC A 0.08Ir 20Ir 1Ir time emergency/backup overcurrent time multiplier of customized inverse 107 K_Em/BU 0.05 OC Inv 999 1 time characteristic curve for emergency/backup overcurrent time constant A of customized inverse 108 A_Em/BU OC Inv s 0 200 0.14 time characteristic curve for emergency/backup overcurrent time constant B of customized inverse 109 B_Em/BU OC Inv s 0 60 0 time characteristic curve for emergency/backup overcurrent index of customized 110 inverse time P_Em/BU 0 OC Inv 10 0.02 characteristic curve for emergency/backup overcurrent 111 112 3I0_Em/BU EF T_Em/BU EF zero sequence current A 0.08Ir 20Ir 0.2Ir threshold of earth fault protection stage 1 s 0 60 0.3 delay time of earth fault protection stage 1 No. of inverse time 113 Curve_Em/ BU EF Inv 1 12 1 characteristic curve of emergency/backup earth fault protection 337 Chapter 25 Appendix start current of inverse 114 3I0_Inv_E m/BU EF A 0.08Ir 20Ir 0.2Ir time emergency/backup earth fault protection time multiplier of customized inverse 115 K_Em/BU 0.05 EF Inv 999 1 time characteristic curve for emergency/backup earth fault protection time constant A of customized inverse 116 A_Em/BU EF Inv s 0 200 0.14 time characteristic curve for emergency/backup earth fault protection time constant B of customized inverse 117 B_Em/BU EF Inv s 0 60 0 time characteristic curve for emergency/backup earth fault protection index of customized 118 inverse time P_Em/BU 0 EF Inv 10 0.02 characteristic curve for emergency/backup earht fault protection 119 I_STUB A 0.08Ir 20Ir 1Ir 120 T_STUB s 0 60 1 current threshold of STUB protection delay time of STUB protection phase current threshold of 121 I_SOTF A 0.08Ir 20Ir 2Ir overcurrent element of switch onto fault protection delay time of 122 T_OC_SOT F s 0 60 0 overcurrent element of switch onto fault protection zero sequnce current 123 3I0_SOTF A 0.08Ir 20Ir 0.5Ir threshold of switch onto fault protection 338 Chapter 25 Appendix delay time of zero 124 T_EF_SOT F s 0 60 0.1 sequce overcurrent of switch onto fault protection 125 126 I_OL Alarm T_OL Alarm A 0.08Ir 20Ir 2Ir s 0.1 6000 20 127 U_OV1 V 40 200 65 128 T_OV1 s 0 60 0.3 129 U_OV2 V 40 200 63 130 T_OV2 s 0 60 0.6 0.9 0.99 0.95 131 Dropout_O V 132 U_UV1 V 5 150 40 133 T_UV1 s 0 60 0.3 134 U_UV2 V 5 150 45 135 T_UV2 s 0 60 0.6 1.01 2 1.05 0.08Ir 2Ir 0.1Ir 136 137 Dropout_U V I_UV_Chk A current threshold of overload alarm delay time of overload alarm voltage threshold of overvoltage stage 1 delay time of overvoltage stage 1 voltage threshold of overvoltage stage 2 delay time of overvoltage stage 2 reset ratio of overvoltage voltage threshold of undervoltage stage 1 delay time of undervoltage stage 1 voltage threshold of undervoltage stage 2 delay time of undervoltage stage 2 reset ratio of undervoltage current threshold of undervoltage phase current 138 I_CBF A 0.08Ir 20Ir 1Ir threshold of circuit breaker failure protection zero sequence current 139 3I0_CBF A 0.08Ir 20Ir 0.2Ir threshold of circuit breaker failure protection negative sequence 140 3I2_CBF A 0.08Ir 20Ir 0.2Ir current threshold of circuit breaker failure protection 141 T_CBF1 s 0 32 0 delay time of CBF stage 1 339 Chapter 25 Appendix 142 143 T_CBF2 T_CBF 1P Trip 3P s 0.1 32 0.2 delay time of CBF stage 2 delay time of three s 0.05 32 0.1 phase tripping of CBF stage 1 zero sequence current 144 3I0_PD A 0 20Ir 0.4Ir threshold of pole discordance protection negative sequence 145 3I2_PD A 0 20Ir 0.4Ir current threshold of pole discordance protection 146 147 T_PD T_Dead Zone s 0 60 2 s 0 32 1 148 T_1P AR1 s 0.05 10 0.6 149 T_1P AR2 s 0.05 10 0.7 150 T_1P AR3 s 0.05 10 0.8 151 T_1P AR4 s 0.05 10 0.9 152 T_3P AR1 s 0.05 60 1.1 153 T_3P AR2 s 0.05 60 1.2 154 T_3P AR3 s 0.05 60 1.3 155 T_3P AR4 s 0.05 60 1.4 Angle_Syn Degre Diff e 156 delay time of pole discordance protection delay time of dead zone protection delay time of shot 1 of single pole reclosing delay time of shot 2 of single pole reclosing delay time of shot 3 of single pole reclosing delay time of shot 4 of single pole reclosing delay time of shot 1 of three pole reclosing delay time of shot 2 of three pole reclosing delay time of shot 3 of three pole reclosing delay time of shot 4 of three pole reclosing angle difference 1 80 30 threshold of synchronizing voltage difference 157 U_Syn Diff V 1 40 10 threshold of synchronizing 158 Freq_Syn Diff frequency difference Hz 0.02 2 0.05 threshold of synchronizing duration of the circuit 159 T_Action ms 80 500 80 breaker closing pulse 340 Chapter 25 Appendix 160 161 162 163 164 165 166 167 1.2 No T_Reclaim T_CB Faulty s 0.05 60 3 Reclaim time s 0.5 60 1 duration of CB ready 1 4 1 available shot number s 0 60 0.05 s 0.05 60 10 s 0.5 60 3 V 30 65 40 V 10 50 30 Times_AR T_Syn Check T_MaxSyn Ext T_AR Reset Umin_Syn Umax_Ener g Default Min. Max. VT_Line 0 1 0 BI SetGrp Switch 0 1 0 3 Relay Test Mode 0 1 0 4 Blk Remote 0 1 0 AR Init By 2p 0 1 0 AR Init By 3p 0 1 1 Relay Trip 3pole 0 1 0 VT Fail 0 1 1 Solid Earthed 0 1 1 CT Fail 0 1 1 0 1 1 0 1 0 0 1 0 2 Access 5 6 7 8 9 10 11 Func_Broken Conduct 12 Broken Conduct Trip 13 synchronizing duration of quit synchronizing duration of CB reclosing prepartion Minimum voltage of synchronizing Maximum voltage of unenergizing checking Binary setting list Setting 1 delay time of Weak InFeed Description setting 1: VT on line side; 0: VT on bus side binary input switch active setting group enable(1)/disable(0) Test mode enable(1)/disable(0) block remote control enable(1)/disable(0) phase to phase fault initiate auto recloser enable(1)/disable(0) three phase fault initiate auto recloser enable(1)/disable(0) three pole tripping mode enable(1)/disable(0) VT failure detection enable(1)/disable(0) solid earthed system(1) CT failure detection enable(1)/disable(0) conduct broken detection enable(1)/disable(0) conduct broken tripping (1)/alarm (0) weak infeed function enable(1)/disable(0) 341 Chapter 25 Appendix No Setting Min. Max. Default setting 14 Description blocking scheme of Blocking Mode 0 1 0 tele-protection enable(1)/disable(0) 15 16 PUR Mode 0 1 0 POR Mode 0 1 1 17 PUTT scheme of tele-protection enable(1)/disable(0) POTT scheme of tele-protection enable(1)/disable(0) tele-protection based on earth Func_Tele EF 0 1 0 fault protection enable(1)/disable(0) 18 Inrush block tele-protection based Tele_EF Inrush Block 0 1 0 on earth fault protection tele protection based on earth fault protection enable(1)/disable(0) 19 tele-protection based on earth Tele_EF Init AR 0 1 0 fault protection initiate recloaser enable(1)/disable(0) 20 21 22 23 24 25 26 27 Func_Z1 0 1 1 Func_Z2 0 1 1 Func_Z3 0 1 1 Func_Z4 0 1 1 Reverse_Z4 0 1 0 Func_Z5 0 1 1 Reverse_Z5 0 1 0 Func_Z1Ext 0 1 1 28 distance zone 1 enable(1)/disable(0) distance zone 2 enable(1)/disable(0) distance zone 3 enable(1)/disable(0) distance zone 4 enable(1)/disable(0) distance zone 4 reserve direction (1)/forward direction(0) distance zone 5 enable(1)/disable(0) distance zone 5 reserve direction (1)/forward direction(0) distance extended zone 1 enable(1)/disable(0) power swing element block Z1_PS Blocking 0 1 1 distance zone 1 enable(1)/disable(0) 29 power swing element block Z2_PS Blocking 0 1 1 distance zone 2 enable(1)/disable(0) 30 power swing element block Z3_PS Blocking 0 1 1 distance zone 3 enable(1)/disable(0) 342 Chapter 25 Appendix No Setting Min. Max. Default Description setting 31 power swing element block Z4_PS Blocking 0 1 1 distance zone 4 enable(1)/disable(0) 32 power swing element block Z5_PS Blocking 0 1 1 distance zone 5 enable(1)/disable(0) 33 Z1Ext_PS Blocking power swing element block 0 1 1 extended distance zone 1 enable(1)/disable(0) 34 distance zone 2 instantaneous Z2 Speedup 0 1 0 tripping at reclosing onto fault enable(1)/disable(0) 35 distance zone 3 instantaneous Z3 Speedup 0 1 0 tripping at reclosing onto fault enable(1)/disable(0) 36 Inrush block the zone 2 or/and 3 Z23 Speedup Inrush Block 0 1 0 instantaneous tripping at recolsing onto fault enable(1)/disable(0) 37 (0)The direction element is active; The small rectangular near zero Imp.Oper.Zone 0 1 1 point is reactive; (1)The direction element is reactive; The small rectangular near zero point is active 38 (0)The direction element is Test Pos.Imp 0 1 1 active ; (1)The direction element is reactive 39 40 41 42 43 44 45 Func_OC1 0 1 1 OC1 Direction 0 1 1 OC1 Inrush Block 0 1 1 Func_OC2 0 1 1 OC2 Direction 0 1 1 OC2 Inrush Block 0 1 1 Func_OC Inv 0 1 1 overcurrent stage 1 enable(1)/disable(0) overcurrent stage 1 with direction element enable(1)/disable(0) overcurrent stage 1 blcoked by inrush enable(1)/disable(0) overcurrent stage 2 enable(1)/disable(0) overcurrent stage 2 with direction element enable(1)/disable(0) overcurrent stage 2 blcoked by inrush enable(1)/disable(0) inverse time overcurrent enable(1)/disable(0) 343 Chapter 25 Appendix No Setting Min. Max. Default setting 46 Description inverse time overcurrent with OC Inv Direction 0 1 0 direction element enable(1)/disable(0) 47 OC Inv Inrush Block 48 Func_EF1 0 1 0 0 1 1 49 inverse time overcurrent blocked by inrush enable(1)/disable(0) earth fault protection stage 1 enable(1)/disable(0) earth fault protection stage 1 with EF1 Direction 0 1 1 direction element enable(1)/disable(0) 50 earth fault protection stage 1 EF1 Inrush Block 0 1 1 bloced by inrush enable(1)/disable(0) 51 Func_EF2 0 1 1 52 earth fault protection stage 2 enable(1)/disable(0) earth fault protection stage 2 with EF2 Direction 0 1 1 direction element enable(1)/disable(0) 53 earth fault protection stage 2 EF2 Inrush Block 0 1 1 bloced by inrush enable(1)/disable(0) 54 Func_EF Inv 0 1 1 55 inverse time earth fault protection enable(1)/disable(0) inverse time earth fault protection EF Inv Direction 0 1 0 with direction element enable(1)/disable(0) 56 EF Inv Inrush Block inverse time earth fault protection 0 1 0 blocked by inrush enable(1)/disable(0) 57 negative sequence direction EF U2/I2 Dir 0 1 0 element for eath fault protection enable(1)/disable(0) 58 earth fault protection stage 1 EF1 Init AR 0 1 0 initiate recloser enable(1)/disable(0) 59 earth fault protection stage 2 EF2 Init AR 0 1 0 initiate recloser enable(1)/disable(0) 60 61 344 Func_BU OC 0 1 0 Func_Em/BU OC 0 1 1 1:backup overcurrent enable; 0: emergency overcurrent enable emergency overcurrent enable(1)/disable(0) Chapter 25 Appendix No 62 Setting Em/BU OC Inrush Block 63 Func_Em/BU OC Inv 64 Em/BU OC Inv Inrush Block Default Min. Max. 0 1 0 0 1 1 setting Description emergency overcurrent blocked by inrush enable(1)/disable(0) emergency inverse time overcurrent enable(1)/disable(0) emergency inverse time 0 1 0 overcurrent blocked by inrush enable(1)/disable(0) 65 1:backup earth fault protection Func_BU EF 0 enable;0:emergency earth fault protection enable 66 67 Func_Em/BU EF Em/BU EF Inrush Block 68 Func_Em/BU EF Inv 69 Em/BU EF Inv Inrush Block 70 71 72 73 74 75 76 77 0 1 1 emergency earth fault protection enable(1)/disable(0) emergency earth fault protection 0 1 0 blocked by inrush enable(1)/disable(0) emergency inverse time earth 0 1 1 fault protection enable(1)/disable(0) emergency inverse time earth 0 1 0 fault protection blocked by inrush enable(1)/disable(0) Func_STUB 0 1 0 Func_SOTF 0 1 1 SOTF Inrush Block 0 1 1 Func_OL 0 1 1 Func_OV1 0 1 1 OV1 Trip 0 1 0 Func_OV2 0 1 1 OV2 Trip 0 1 0 78 STUB protection enable(1)/disable(0) SOTF protection enable(1)/disable(0) SOTF protection blocked by inrush enable(1)/disable(0) overload enable(1)/disable(0) overvoltage stage 1 enable(1)/disable(0) overvoltage stage 1 tripping (1)/alarm(0) overvoltage stage 2 enable(1)/disable(0) overvoltage stage 2 tripping (1)/alarm(0) 1: phase to earth voltage applied OV PE 0 1 1 by overvoltage;0: phase to phase voltage applied by overvoltage 79 80 Func_UV1 0 1 0 UV1 Trip 0 1 0 undervoltage stage 1 enable(1)/disable(0) undervoltage stage 1 345 Chapter 25 Appendix No Setting Min. Max. Default setting Description tripping(1)/alarm(0) 81 82 Func_UV2 0 1 0 UV2 Trip 0 1 0 83 undervoltage stage 2 enable(1)/disable(0) undervoltage stage 2 tripping(1)/alarm(0) 1: phase to earth voltage applied UV PE 0 1 1 by undervoltage;0: phase to phase voltage applied by undervoltage 84 all three phase voltage must be UV Chk All Phase 0 1 0 less than threshold enable(1)/disable(0) 85 UV Chk Current 0 1 0 86 current threshold for undervoltage enable(1)/disable(0) criterion of state of circuit breaker UV Chk CB 0 1 0 for undervoltage enable(1)/disable(1) 87 Func_CBF 0 1 1 CBF 1P Trip 3P 0 1 0 88 circuit breaker failure protection enable(1)/disable(1) delay time three-pole tripping when one pole of circuit breaker failure enable(1)/disable(0) 89 negative sequence current criterion and zero sequence CBF Chk 3I0/3I2 0 1 1 current criterion for circuit breaker failure protection enable(1)/disable(0) 90 CBF Chk CB Status 91 Func_PD criterion of state of circuit breaker 0 1 0 for circuit breaker failure protection enable(1)/disable(0) 0 1 1 92 pole discordance protection enable(1)/disable(0) negative sequence current criterion and zero sequence PD Chk 3I0/3I2 0 1 0 current criterion for pole discordance protection enable(1)/disable(0) 93 94 95 346 Func_Dead Zone 0 1 1 AR_1p mode 0 1 1 AR_3p mode 0 1 0 dead zone protection enable(1)/disable(0) single pole reclosing mode enable(1)/disable(0) three pole reclosing mode Chapter 25 Appendix No Setting Min. Max. Default Description setting enable(1)/disable(1) 96 97 98 99 AR_1p(3p) mode 0 1 0 AR_Disable 0 1 0 AR_Override 0 1 1 0 1 0 0 1 0 0 1 0 0 1 0 AR_EnergChkDLL B 100 AR_EnergChkLLD B 101 AR_EnergChkDLD B 102 AR_Syn check 103 complicate reclosing mode enable(1)/disable(0) recloser disable overriding synchronization enable(1)/disable(0) check dead line and live bus enable(1)/disable(0) check live line and dead bus enable(1)/disable(0) check dead line and dead bus enable(1)/disable(0) check synchronization enable(1)/disable(0) 1:three phase must be energized AR_Chk3PVol 0 1 0 before single pole reclosing;0: recloasing without any condition 104 three pole tripping when recoser AR Final Trip 0 1 0 is blocked after recloser was initiated due to single pole tripping enable(1)/disable(0) 105 1P CBOpen Init AR 106 3P CBOpen Init AR 107 108 Func_Diff Curr 110 111 113 0 recloser can be initiated by three 0 1 0 0 1 1 Dual_Channel 0 1 1 Master Mode 0 1 1 0 1 0 0 1 1 0 1 0 Comp Capacitor Block Diff CT_Fail Block 3Ph Diff CT_Fail pole tripping due to mechanical cause enable(1)/disable(0) 1 Func_Diff Curr pole tripping due to mechanical cause enable(1)/disable(0) 1 Cur 112 1 0 Abrupt 109 recloser can be initiated by single 0 differential protection enable(1)/disable(0) sudden change differential protection enable(1)/disable(0) double channels(1)/single channel(0) master mode (1)/ slaver mode (0) capacitive current compensation enable(1)/disable(0) CT failure block differential protection enable(1)/disable(0) block three phases(1)/block broken phase(0) 347 Chapter 25 Appendix No 114 115 116 117 118 119 120 121 122 Default Setting Min. Max. Diff_Zero Init AR 0 1 1 Chan_A Ext_Clock 0 1 0 Chan_A 64k Rate 0 1 0 Chan_B Ext_Clock 0 1 0 Chan_B 64k Rate 0 1 0 Loop Test 0 1 0 DTT By Startup 0 1 1 DTT By Z2 0 1 DTT By Z3 0 1 Description setting AR initiated by zero sequence differential protection Channel A apply external clock enable(1)/disable(0) Channel A at 64Kb/s enable(1)/disable(0) Channel B apply external clock enable(1)/disable(0) Channel B at 64Kb/s enable(1)/disable(0) channel loop test mode enable(1)/disable(0) DTT under startup element control DTT under Zone 2 distance element control DTT under Zone 3 distance element control Note: The two settings, ‘Imp.Oper.Zone’ and ‘Test Pos.Imp’, should set as 1 only for testing. They must be set as 0 in service. 348 Chapter 25 Appendix 2 General report list Table 168 event report list No. Abbr. Meaning (LCD Display) 1. Relay Startup Protection startup 2. Dist Startup Impedance element startup 3. 3I0 Startup Zero-current startup 4. I_PS Startup current startup for Power swing 5. BI Change Binary input change 6. Zone1 Trip Zone I distance trip 7. Zone2 Trip Zone II distance trip 8. Zone3 Trip Zone III distance trip 9. Zone4 Trip Zone Ⅳ distance trip 10. Zone5 Trip Zone Ⅳ distance trip 11. Zone1Ext Trip Zone 1 Extended distance trip 12. Dist SOTF Ttrip distance relay speed up trip after switching on to fault(SOTF) 13. PSB Dist OPTD PSB Distance operated 14. Z2 Speedup Trip Z2 Speedup Trip 15. Z3 Speedup Trip Z3 Speedup Trip 16. Trip Blk AR(3T) Permanent trip for 3-ph tripping failure 17. Relay Trip 3P Trip 3 poles 18. 3P Trip(1T_Fail) three phase trip for 1-ph tripping failure 19. Dist Evol Trip Distance zone 1 evolvement trip 20. Fault Location Fault location 21. Impedance_FL Impedance of fault location 22. Tele_DIST_Trip Tele_DIST trip 23. Tele Evol Trip Tele evolvement trip 24. Carr Stop(Dist) Carrier signal stopped for Dist protection 25. Carr Stop(CBO) Carrier signal stopped for CB open 26. Carr Stop(Weak) Carrier signal stopped for weak-infeed end 27. Carr Send(Dist) Carrier signal sent for Dist protection 28. Carr Send(CBO) Carrier signal sent for Dist protection 29. Carr Send(Weak) Carrier signal sent for weak-infeed end 30. Direct Trip Send Direct Trip Send 31. Direct Trip Recv Direct Trip Receive 349 Chapter 25 Appendix 32. Carr Send(DEF) Send carrier signal in DEF 33. Tele_DEF_Trip Tele_DEF trip 34. Curr Diff Trip Current differential protection trip 35. Zero Diff Trip Zero-sequence current differential protection trip 36. Curr Diff Evol Current differential evolvement trip 37. DTT DTT 38. Tele_Trans1 OPTD Tele transmission 1 operated 39. Tele_Trans2 OPTD Tele transmission 2 operated 40. Tele_Trans1 Drop Tele transmission 1 dropout 41. Tele_Trans2 Drop Tele transmission 2 dropout 42. WeakInfeed Init WeakInfeed initiated 43. OppositeEnd Init Opposite end initiated 44. 3Ph Diff_Curr Current for three phase differential current 45. 3PH Res_Curr Current for three phase restraining current 46. BI_DTT DTT binary input 47. BI_Tele_Trans1 Tele transmission 1 binary input 48. BI_Tele_Trans2 Tele transmission 2 binary input 49. OppositeEnd Trip Opposite end Trip 50. Sample No_Syn sample without synchronization 51. Sample Syn OK sample is synchronized successfully 52. Channel A Data Data from channel A 53. Channel B Data Data from channel B 54. Curr Diff SOTF SOTF on current differential fault 55. EF1 Trip 1st stage EF Trip 56. EF2 Trip 2nd stage EF Trip 57. EF Inv Trip Inverse time stage EF Trip 58. EF SOTF Trip Earth Fault relay speed up after SOTF 59. Em/Bu EF Trip Emergency/Backup Earth Fault Trip 60. Em/Bu EFInv Trip Emergency/Backup Earth Fault inverse time Trip 61. OC Startup Overcurrent Startup 62. OC1 Trip 1st stage Overcurrent startup 63. OC2 Trip 2nd stage Overcurrent startup 64. OC Inv Trip inverse time stage overcurrent Startup 65. OC SOTF Trip Overcurrent relay speed up after SOTF 66. Em/Bu OC Trip Emergency/Backup overcurrent trip 67. Em/Bu OCInv Trip Inverse time stage emergency/Backup overcurrent trip 68. Inrush Blk Inrush blocking 69. STUB Trip STUB trip 70. OV1 Trip 1st stage overvoltageStartup 350 Chapter 25 Appendix 71. OV2 Trip 2nd stage overvoltageStartup 72. UV1 Trip 1st stage undervoltageStartup 73. UV2 Trip 2nd stage undervoltageStartup 74. CBF StartUp CBF Startup 75. CBF1 Trip 1st stage CBF operation 76. CBF2 Trip 2nd stage CBF operation 77. CBF 1P Trip 3P three phase trip for single phase CBF 78. PD Startup Phasor disturbance startup 79. PD Trip Phasor disturbance trip 80. Dead Zone Init Dead zone initiate 81. Dead Zone Trip Dead zone trip 82. BRKN COND Trip Broken conductor protection trip 83. 1st Reclose First reclose 84. 2nd Reclose Second reclose 85. 3rd Reclose Third reclose 86. 4th Reclose Fourth reclose 87. 1Ph Trip Init AR Autoreclose by one phase trip 88. 1Ph CBO Init AR Autoreclose by one phase breaker opening 89. 1Ph CBO Blk AR Autoreclose blocked by one phase breaker opening 90. 3Ph Trip Init AR Autoreclose initiated by three phase trip 91. 3Ph CBO Init AR Autoreclose initiated by three phase breaker opening 92. 3Ph CBO Blk AR Autoreclose blocked by three phase trip 93. Syn Phase Change Synchronizing phase fail 94. AR Block Autoreclose blocked 95. BI MC/AR BLOCK Autoreclose BI blocked 96. Syn Request Synchronizing began 97. AR_EnergChk OK Energing Check ok 98. Syn Failure Synchronizing check failure 99. Syn OK Synchronizing check ok 100. Syn Vdiff fail Voltage difference synchronizing check failed 101. Syn Fdiff fail Frequency difference synchronizing check failed 102. Syn Angdiff fail Angle difference synchronizing check failed 103. EnergChk fail Energizing check failed 104. AR Success Autoreclose success 105. AR Final Trip Final trip for autoreclose 106. AR in progress Autoreclose is in progress 107. AR Failure Autoreclosure failed 108. Relay Reset Relay reset 109. BI SetGroup Mode BI SetGroup Mode 351 Chapter 25 Appendix Table 169 alarming report list No 352 Abbr. (LCD Display) Meaning 1 3I0 Imbalance 3I0 imbalance 2 3I0 Reverse 3I0 reverse 3 3Ph Seq Err Three phase sequence error 4 AI Channel Err AI channel error 5 AR Mode Alarm Autoreclosure mode alarm 6 Battery Off Battery Off 7 BI_DTT Alarm DTT binary input alarm 8 BI_Init CBF Err CBF initiation BI error 9 BI_V1P_MCB Err V1P_MCB BI alarm 10 BI_V1P_MCB Err V1P_MCB BI alarm 11 BRKN COND Alarm Broken conductor alarm 12 Carr Fail(DEF) Carrier fail in TeleDEF 13 Carr Fail(Dist) Carrier fail in TeleDist 14 CB Err Blk PD Pole discordance blocked by CB error 15 Chan_A Addr Err Channel A address error 16 Chan_A Comm Err Channel A communication error 17 Chan_A Loop Err Channel A loop error 18 Chan_A Samp Err No sampling data for channel A 19 Chan_B Addr Err Channel B address error 20 Chan_B Comm Err Channel B communication error 21 Chan_B Loop Err Channel B loop error 22 Chan_B Samp Err No sampling data for channel B 23 Chan_Loop Enable Channel loop enabled 24 ChanA_B Across Channel A and B across 25 CT Fail CT fail 26 DI Breakdown DI breakdown 27 DI Check Err DI check error 28 DI Comm Fail DI communication error 29 DI Config Err DI configuration error 30 DI EEPROM Err DI EEPROM error 31 DI Input Err DI input error 32 Diff_Curr Alarm Differential current exists for long period 33 DO Breakdown Binary output (BO) breakdown 34 DO Comm Fail DO communication error 35 DO Config Err DO configuration error Chapter 25 Appendix No Abbr. (LCD Display) Meaning 36 DO EEPROM Err DO EEPROM error 37 DO No Response Binary output (BO) no response 38 DoubleChan Test Double channel test 39 EquipPara Err Equipment parameter error 40 FLASH Check Err FLASH check error 41 Func_CurDiff Err Current differential error 42 Func_Dist Blk Distance function blocked by VT fail 43 Func_UV Blk Undervoltage function blocked by VT fail 44 Local CT Fail Local CT fail 45 Meas Freq Alarm Measurement Frequency Alarm 46 NO/NC Discord NO/NC discordance 47 Opposite CommErr Opposite side communication error 48 Opposite CT Fail Opposite CT fail 49 OV/UV Trip Fail Overvoltage / Undervoltage Trip Fail 50 OV1 Alarm 1st stage overvoltage alarm 51 OV2 Alarm 2nd stage overvoltage alarm 52 Overload Overload alarm 53 PD Trip Fail Pole discordance trip fail 54 PhA CB Open Err PhaseA CB position DI error 55 PhB CB Open Err PhaseB CB position DI error 56 PhC CB Open Err PhaseC CB position DI error 57 ROM Verify Err CRC verification for ROM error 58 Sample Err AI sampling data error 59 Set Group Err Pointer of setting group error 60 Setting Err Setting value error 61 Soft Version Err Soft Version error 62 SRAM Check Err SRAM check error 63 SYN Voltage Err Voltage error for synchronizing check 64 Sys Config Err System Configuration Error 65 Tele Mode Alarm Tele Mode Alarm 66 TeleSyn Mode Err Synchronizing mode error 67 Test DO Un_reset Test DO unreset 68 Trip Fail Trip fail 69 U_3rd_Harm Alarm 3rd harmonic wave too large 70 UV1 Alarm 1 stage undervoltage alarm 71 UV2 Alarm 2 stage undervoltage alarm st nd 353 Chapter 25 Appendix No Abbr. (LCD Display) 72 V1P_MCB VT Fail V1P_MCB alarm 73 V3P_MCB VT Fail V3P_MCB alarm 74 VT Fail VT Fail Meaning Table 170 operation report list No. 354 Abbr. (LCD Display) Meaning 1. SwSetGroup OK Successful to switch setting group 2. Write Set OK Successful to write setting values 3. WriteEquipParaOK Successful to write equipment parameter 4. WriteConfig OK Successful to write configuration 5. AdjScale OK Successful to adjust scale of AI 6. ClrConfig OK Successful to clear configuration 7. Cpu Reset CPU reset 8. Reset Config Reset configuration 9. Test BO OK Test BO OK 10. VT Recovery VT recovery 11. AdjDrift OK Successful to adjust zero drift of AI 12. Clear All Rpt OK Clear all report OK 13. MeasFreqOK Measurement frequency OK 14. Func_DiffCurr On Differential current protection on 15. FuncDiffCurr Off Differential current protection off 16. Chan_A Tele_Loop Channel A loop on 17. Chan_A Loop Off Channel A loop off 18. Chan_B Tele_Loop Channel B loop on 19. Chan_B Loop Off Channel B loop off 20. Chan_A Comm OK Channel A communication resumed 21. Chan_B Comm OK Channel B communication resumed 22. OppositeEnd On Opposite end on 23. OppositeEnd Off Opposite end off 24. Test mode On Test mode On 25. Test mode Off Test mode Off 26. Func_VT Fail On VT fail function on 27. Func_VT Fail Off VT fail function off 28. Func_Dist On Distance function on Chapter 25 Appendix No. Abbr. (LCD Display) Meaning 29. Func_Dist Off Distance function off 30. Func_PSB On PSB function on 31. Func_PSB Off PSB function off 32. Func_TeleDist On TeleDist function on 33. FuncTeleDist Off TeleDist function off 34. Func_Tele_DEF On TeleDEF function on 35. Func_TeleDEF Off TeleDEF function off 36. Func_EF On EF function on 37. Func_EF Off EF function off 38. Func_EF Inv On Inverse stage EF function on 39. Func_EF Inv Off Inverse stage EF function off 40. Func_OC On OC function on 41. Func_OC Off OC function off 42. Func_OC Inv On Inverse stage OC function on 43. Func_OC Inv Off Inverse stage OC function off 44. Func_BU_OC On BU OC function on 45. Func_BU_OC Off BU OC function off 46. Func_BU_EF On BU EF function on 47. Func_BU_EF Off BU EF function off 48. Func_STUB On STUB function on 49. Func_STUB Off STUB function off 50. Func_SOTF On SOTF function on 51. Func_SOTF Off SOTF function off 52. Func_OV On OV function on 53. Func_OV Off OV function off 54. Func_UV On UV function on 55. Func_UV Off UV function off 56. Func_AR On AR function on 57. Func_AR Off AR function off 58. AR Syn On Syncronizing function on 59. AR Syn Off Syncronizing function off 60. AR EnergChk On Engergizing check function on 61. AR EnergChk Off Engergizing check function off 62. AR Override On Override function on 63. AR Override Off Override function off 64. BI_AR Off AR off BI 355 Chapter 25 Appendix No. 356 Abbr. (LCD Display) Meaning 65. Func_CBF On CBF function on 66. Func_CBF Off CBF function off 67. Func_PD On PD function on 68. Func_PD Off PD function off 69. Func_DZ On DZ function on 70. Func_DZ Off DZ function off Chapter 25 Appendix 3 Typical connection A. For one breaker of single or double busbar arrangement A B C Protection IED a01 b01 IA a02 b02 * * * IB a03 b03 IC a04 b04 a10 a09 b09 b10 IN UA UB UC UN a07 b07 U4 Figure 112 Typical connection diagram for one breaker of single or double busbar arrangement 357 Chapter 25 Appendix B. For one and half breaker arrangement A B C * * * * * * Protection IED a01 b01 IA a02 b02 IB a03 b03 IC a04 b04 a10 a09 b09 b10 IN UA UB UC UN a07 b07 U4 A B C Figure 113 Typical connection diagram for one and half breaker arrangement 358 Chapter 25 Appendix C. For parallel lines A B C Protection IED a01 b01 IA a02 b02 * * * IB * a03 b03 * * IC a04 b04 a10 a09 b09 b10 IN UA UB UC UN a07 b07 U4 a05 b05 INM Figure 114 Typical connection diagram for parallel lines 359 Chapter 25 Appendix 4 Time inverse characteristic 4.1 11 kinds of IEC and ANSI inverse time characteristic curves In the setting, if the curve number is set for inverse time characteristic, which is corresponding to the characteristic curve in the following tabel. Both IEC and ANSI based standard curves are available. Table 171 11 kinds of IEC and ANSI inverse time characteristic Curves No. 4.2 IDMTL Curves Parameter A Parameter P Parameter B 1 IEC INV. 0.14 0.02 0 2 IEC VERY INV. 13.5 1.0 0 3 IEC EXTERMELY INV. 80.0 2.0 0 4 IEC LONG INV. 120.0 1.0 0 5 ANSI INV. 8.9341 2.0938 0.17966 6 ANSI SHORT INV. 0.2663 1.2969 0.03393 7 ANSI LONG INV. 5.6143 1 2.18592 8 ANSI MODERATELY INV. 0.0103 0.02 0.0228 9 ANSI VERY INV. 3.922 2.0 0.0982 10 ANSI EXTERMELY INV. 5.64 2.0 0.02434 11 ANSI DEFINITE INV. 0.4797 1.5625 0.21359 User defined characteristic For the inverse time characteristic, also can be set as user defined characteristic if the setting is set to 12. K 360 Chapter 25 Appendix Equation 25 where: A: Time factor for inverse time stage B: Delay time for inverse time stage P: index for inverse time stage K: Set time multiplier for step n 361 Chapter 25 Appendix 5 CT requirement 5.1 Overview In practice, the conventional magnetic- core current transformer (hereinafter as referred CT) is not able to transform the current signal accurately in whole fault period of all possible faults because of manufactured cost and installation space limited. CT Saturation will cause distortion of the current signal and can result in a failure to operate or cause unwanted operations of some functions. Although more and more protection IEDs have been designed to permit CT saturation with maintained correct operation, the performance of protection IED is still depended on the correct selection of CT. 5.2 Current transformer classification The conventional CTs are usually manufactured in accordance with the standard, IEC 60044, ANSI / IEEE C57.13, ANSI / IEEE C37.110 or other comparable standards, which CTs are specified in different protection class. Currently, the CT for protection are classified according to functional performance as follows: Class P CT Accuracy limit defined by composite error with steady symmetric primary current. No limit for remanent flux. Class PR CT CT with limited remanence factor for which, in some cased, a value of the secondary loop time constant and/or a limiting value of the winding resistance may also be specified. Class PX CT Low leakage reactance for which knowledge of the transformer secondary excitation characteristic, secondary winding resistance, secondary burden resistance and turns ratio is sufficient to assess its performance in relation to the protective relay system with which it is to be used. Class TPS CT Low leakage flux current transient transformer for which performance is 362 Chapter 25 Appendix defined by the secondary excitation characteristics and turns ratio error limits. No limit for remanent flux Class TPX CT Accuracy limit defined by peak instantaneous error during specified transient duty cycle. No limit for remanent flux. Class TPY CT Accuracy limit defined by peak instantaneous error during specified transient duty cycle. Remanent flux not to exceed 10% of the saturation flux.. Class TPZ CT Accuracy limit defined by peak instantaneous alternating current component error during single energization with maximum d.c. offset at specified secondary loop time constant. No requirements for d.c. component error limit. Remanent flux to be practically negligible. TPE class CT (TPE represents transient protection and electronic type CT) 5.3 Abbreviations (according to IEC 60044-1, -6, as defined) Abbrev. Description Esl Rated secondary limiting e.m.f Eal Rated equivalent limiting secondary e.m.f Ek Rated knee point e.m.f Uk Knee point voltage (r.m.s.) Kalf Accuracy limit factor Kssc Rated symmetrical short-circuit current factor K’ssc Effective symmetrical short-circuit current factor K”ssc based on different Ipcf Kpcf Protective checking factor Ks Specified transient factor Kx Dimensioning factor Ktd Transient dimensioning factor Ipn Rated primary current Isn Rated secondary current Ipsc Rated primary short-circuit current Ipcf protective checking current Isscmax Maximum symmetrical short-circuit current Rct Secondary winding d.c. resistance at 75 °C / 167 °F (or other specified temperature) 363 Chapter 25 Appendix Rb Rated resistive burden R’b = Rlead + Rrelay = actual connected resistive burden Rs Total resistance of the secondary circuit, inclusive of the secondary winding resistance corrected to 75℃, unless otherwise specified, and inclusive of all external burden connected. Rlead Wire loop resistance Zbn Rated relay burden Zb Actual relay burden Tp Specified primary time constant Ts Secondary loop time constant 5.4 General current transformer requirements 5.4.1 Protective checking current The current error of CT should be within the accuracy limit required at specified fault current. To verify the CT accuracy performance, Ipcf, primary protective checking current, should be chosed properly and carefully. For different protections, Ipcf is the selected fault current in proper fault position of the corresponding fault, which will flow through the verified CT. To guarantee the reliability of protection relay, Ipcf should be the maximum fault current at internal fault. E.g. maximum primary three phase short-circuit fault current or single phase earth fault current depended on system sequence impedance, in different positions. Moreover, to guarantee the security of protection relay, Ipcf should be the maximum fault current at external fault. Last but not least, Ipcf calculation should be based on the future possible system power capacity Kpcf, protective checking factor, is always used to verified the CT performance To reduce the influence of transient state, Kalf, Accuracy limit factor of CT, should be larger than the following requirement 364 Chapter 25 Appendix Ks, Specified transient factor, should be decided based on actual operation state and operation experiences by user. 5.4.2 CT class The selected CT should guarantee that the error is within the required accuracy limit at steady symmetric short circuit current. The influence of short circuit current DC component and remanence should be considered, based on extent of system transient influence, protection function characteristic, consequence of transient saturation and actual operating experience. To fulfill the requirement on a specified time to saturation, the rated equivalent secondary e.m.f of CTs must higher than the required maximum equivalent secondary e.m.f that is calculated based on actual application. For the CTs applied to transmission line protection, transformer differential protection with 330kV voltage level and above, and 300MW and above generator-transformer set differential protection, the power system time constant is so large that the CT is easy to saturate severely due to system transient state. To prevent the CT from saturation at actual duty cycle, TP class CT is preferred. For TPS class CT, Eal (rated equivalent secondary limiting e.m.f) is generally determined as follows: Where Ks: Specified transient factor Kssc: Rated symmetrical short-circuit current factor For TPX, TPY and TPZ class CT, Eal (rated equivalent secondary limiting e.m.f) is generally determined as follows: Where 365 Chapter 25 Appendix Ktd: Rated transient dimensioning factor Considering at short circuit current with 100% offset For C-t-O duty cycle, t: duration of one duty cycle; For C-t’-O-tfr-C-t”-O duty cycle, t’: duration of first duty cycle; t”: duration of second duty cycle; tfr: duration between two duty cycle; For the CTs applied to 110 - 220kV voltage level transmission line protection, 110 - 220kV voltage level transformer differential protection, 100-200MW generator-transformer set differential protection, and large capacity motor differential protection, the influence of system transient state to CT is so less that the CT selection is based on system steady fault state mainly, and leave proper margin to tolerate the negative effect of possible transient state. Therefore, P, PR, PX class CT can be always applied. For P class and PR class CT, Esl (the rated secondary limited e.m.f) is generally determined as follows: Kalf: Accuracy limit factor For PX class CT, Ek (rated knee point e.m.f) is generally determined as follows: Kx: Demensioning factor For the CTs applied to protection for110kV voltage level and below system, the CT should be selected based on system steady fault state condition. P class CT is always applied. 366 Chapter 25 Appendix 5.4.3 Accuracy class The CT accuracy class should guarantee that the protection relay applied is able to operate correctly even at a very sensitive setting, e.g. for a sensitive residual overcurrent protection. Generally, the current transformer should have an accuracy class, which have an current error at rated primary current, that is less than ±1% (e.g. class 5P). If current transformers with less accuracy are used it is advisable to check the actual unwanted residual current during the commissioning. 5.4.4 Ratio of CT The current transformer ratio is mainly selected based on power system data like e.g. maximum load. However, it should be verified that the current to the protection is higher than the minimum operating value for all faults that are to be detected with the selected CT ratio. The minimum operating current is different for different functions and settable normally. So each function should be checked separately. 5.4.5 Rated secondary current There are 2 standard rated secondary currents, 1A or 5A. Generally, 1 A should be preferred, particularly in HV and EHV stations, to reduce the burden of the CT secondary circuit. Because 5A rated CTs, i.e. I2R is 25x compared to only 1x for a 1A CT. However, in some cases to reduce the CT secondary circuit open voltage, 5A can be applied. 5.4.6 Secondary burden Too high flux will result in CT saturation. The secondary e.m.f is directly proportional to linked flux. To feed rated secondary current, CT need to generate enough secondary e.m.f to feed the secondary burden. Consequently, Higher secondary burden, need Higher secondary e.m.f, and then closer to saturation. So the actual secondary burden R’b must be less than the rated secondary burden Rb of applied CT, presented Rb > R’b The CT actual secondary burden R’b consists of wiring loop resistance Rlead and the actual relay burdens Zb in whole secondary circuit, which is calculated by following equation 367 Chapter 25 Appendix R’b = Rlead + Zb The rated relay burden, Zbn, is calculated as below: Where Sr: the burden of IED current input channel per phase, in VA; For earth faults, the loop includes both phase and neutral wire, normally twice the resistance of the single secondary wire. For three-phase faults the neutral current is zero and it is just necessary to consider the resistance up to the point where the phase wires are connected to the common neutral wire. The most common practice is to use four wires secondary cables so it normally is sufficient to consider just a single secondary wire for the three-phase case. In isolated or high impedance earthed systems the phase-to-earth fault is not the considered dimensioning case and therefore the resistance of the single secondary wire always can be used in the calculation, for this case. 5.5 Rated equivalent secondary e.m.f requirements To guarantee correct operation, the current transformers (CTs) must be able to correctly reproduce the current for a minimum time before the CT will begin to saturate. 5.5.1 Line differential protection The protection is designed to accept CTs with same characteristic but different CT ratios between two terminals of feeder. The difference of ratio should not be more than 4 times. Because the operating characteristic of the line differential protection is based on the calculation of fundamental component of current, the CT saturation will result in too much error of the calculation of differential current and reduce the security of the protection. The CT applied should meet following requirement. For 330kV and above transmission line protection, TPY CT is preferred. To guarantee the accuracy, Kssc should be satisfied following requirement: Where 368 Chapter 25 Appendix I’pcf: Maximum primary fundamental frequency fault current at internal faults (A) I”pcf: Maximum primary fundamental frequency fault current at external faults (A) Considering auto-reclosing operation, Eal should meet the following requirement, at C-O-C-O duty cycle Where K’td: Recommended transient dimensioning factor for verification, 1.2. recommended To 220kV transmission line protection, Class 5P20 CT is preferred. Because the system time constant is less relatively, and then DC component is less, the probability of CT saturation due to through fault current at external fault is reduced more and more. Esl can be verified as below: Where Ks: Specified transient factor, 2 recommended Only at special case, e.g. short output feeder of large power plant, the PX class CT is recommended. Ek should be verified based on below equation. Where Ks: Specified transient factor, 2 recommended 5.5.2 Transformer differential protection It is recommended that the CT of each side could be same class and with same characteristic to guarantee the protection sensitivity. For the CTs applied to 330kV voltage level and above step-down transformer, TPY class CT is preferred for each side. 369 Chapter 25 Appendix For the CTs of high voltage side and middle voltage side, Eal should be verified at external fault C-O-C-O duty cycle. For the CT of low voltage side in delta connection, Eal should be verified at external three phase short circuit fault C-O duty cycle. Eal must meet the requirement based on following equations: Where K’td: Recommended transient dimensioning factor for verification, 3 recommended For 220kV voltage level and below transformer differential protection, P Class, PR class and PX class is able to be used. Because the system time constant is less relatively, and then DC component is less, the probability of CT saturation due to through fault current at external fault is reduced more and more. For P Class, PR class CT, Esl can be verified as below: Where Ks: Specified transient factor, 2 recommended For PX class CT, Ek can be verified as below: Where Ks: Specified transient factor, 2 recommended 5.5.3 Busbar differential protection The busbar differential protection is able to detect CT saturation in extremely short time and then block protection at external fault. The protection can discriminate the internal or external fault in 2-3 ms before CT saturation. So the currents from different class CT of different feeders are permitted to inject into the protection relay. The rated secondary e.m.f of CTs is verified by maximum symmetric short circuit current at external fault. For P Class, PR class CT, 370 Chapter 25 Appendix For TP class CT, Ipcf: Maximum primary short circuit current at external faults (A) 5.5.4 Distance protection For 330kV and above transmission line protection, TPY CT is preferred. To guarantee the accuracy, Kssc should be satisfied following requirement: Where I’pcf: Maximum primary fundamental frequency current at close-in forward and reverse faults (A) I”pcf: Maximum primary fundamental frequency current at faults at the end of zone 1 reach (A) Considering auto-reclosing operation, Eal should meet the following requirement, at C-O-C-O duty cycle Where K’td: Recommended transient dimensioning factor for verification, 3. recommended for line which length is shorter than 50kM, 5 recommended for line which length is longer than 50kM To 220kV voltage and below transmission line protection, P Class CT is preferred, e.g. 5P20. Esl can be verified as below: Where 371 Chapter 25 Appendix Ks: Specified transient factor, 2 recommended Only at special case, e.g. short output feeder of large power plant, the PX class CT is recommended. Ek should be verified based on below equation. Where Ks: Specified transient factor, 2 recommended 5.5.5 Definite time overcurrent protection and earth fault protection For TPY CT, Kssc should be satisfied following requirement: Where I’pcf: Maximum primary fundamental frequency current at close-in forward and reverse faults (A) I”pcf: Maximum applied operating setting value (A) Considering auto-reclosing operation, Eal should meet the following requirement, at C-O-C-O duty cycle Where K’td: Recommended transient dimensioning factor for verification, 1.2 recommended For P Class and PR class CT, Kalf should be satisfied following requirement: 372 Chapter 25 Appendix Where I’pcf: Maximum primary fundamental frequency current at close-in forward and reverse faults (A) I”pcf: Maximum applied operating setting value (A) Esl can be verified as below: Where Ks: Specified transient factor, 2 recommended For PX class CT, Ek should be verified based on below equation. Where Ks: Specified transient factor, 2 recommended 5.5.6 Inverse time overcurrent protection and earth fault protection For TPY CT, Kssc should be satisfied following requirement: Where I’pcf: Maximum applied primary startup current setting value (A) Considering auto-reclosing operation, Eal should meet the following 373 Chapter 25 Appendix requirement, at C-O duty cycle Where K’td: Recommended transient dimensioning factor for verification, 1.2 recommended For P Class and PR class CT, Kalf should be satisfied following requirement: Where I’pcf: Maximum applied primary startup current setting value (A) Esl can be verified as below: Where Ks: Specified transient factor, 2 recommended For PX class CT, Ek should be verified based on below equation. Where Ks: Specified transient factor, 2 recommended 374