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,
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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
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