csc-103 line protection ied technical application … line... · chapter 4 line differential...

CSC-103

Line Protection IED

Technical Application Manual

Version：V1.01

Doc. Code：0SF.451.083(E)

Issued Date：2012.8

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

1

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

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

3

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 ................................ 92

1.5 Reports .................................................................................................................... 105

1.6 Technical data.......................................................................................................... 106

Chapter 6 Teleprotection .......................................................................................................... 109

1 Teleprotection schemes for distance ..................................................................................110

1.1 Introduction ..............................................................................................................110

1.2 Teleprotection principle ...........................................................................................110

1.2.1 Permissive underreach transfer trip (PUTT) scheme ...............................110

1.2.2 Permissive overreach transfer trip (POTT) scheme ................................. 111

1.2.3 Blocking scheme ............................................................................................112

1.2.4 Additional teleprotection logics ....................................................................114

1.3 Input and output signals ...........................................................................................115

1.4 Setting parameters ....................................................................................................116

1.4.1 Setting list ........................................................................................................117

1.4.2 Setting explanation ........................................................................................117

1.5 Reports .....................................................................................................................118

1.6 Technical data...........................................................................................................118

2 Teleprotection for directional earth fault protection ..........................................................119

2.1 Introduction ..............................................................................................................119

2.2 Protection principle ..................................................................................................119

2.3 Input and output signals .......................................................................................... 120

2.4 Setting parameters ................................................................................................... 121

2.4.1 Setting lists ..................................................................................................... 122

2.5 Reports .................................................................................................................... 122

Chapter 7 Overcurrent protection ............................................................................................ 125

1 Overcurrent protection ........................................................................................................ 126

1.1 Introduction ............................................................................................................. 126


1.2.1 Measured quantities ..................................................................................... 126

1.2.2 Time characteristic ........................................................................................ 126

1.2.3 Direciton determination feature ................................................................... 128

1.2.4 Logic diagram ................................................................................................ 129

1.3 Input and output signals ........................................................................................... 130


1.4.1 Setting list ....................................................................................................... 132

1.5 Reports ..................................................................................................................... 133

1.6 Technical data .......................................................................................................... 133

Chapter 8 Earth fault protection ............................................................................................... 137

1 Directional/Non-directional earth fault portection ............................................................ 138

1.1 Introduction ............................................................................................................. 138


1.2.1 Time delays characteristic ........................................................................... 139

1.2.2 Inrush restraint feature ................................................................................. 140

1.2.3 Earth fault direction determination .............................................................. 141

1.2.4 Logic diagram ................................................................................................ 143



1.4.1 Setting lists ..................................................................................................... 146

1.4.2 Setting calculation example ......................................................................... 149

1.5 Reports ..................................................................................................................... 149

1.6 Technical data .......................................................................................................... 150

Chapter 9 Emergency/backup overcurrent and earth fault protection ...................................... 153

1 Emergency/backup overcurrent protection ...................................................................... 154

1.1 Introduction ............................................................................................................. 154


1.2.1 Tripping time characteristic .......................................................................... 154


1.2.3 Logic diagram ................................................................................................ 156



1.4.1 Setting lists ..................................................................................................... 157

1.5 Reports ..................................................................................................................... 159

1.6 Technical data .......................................................................................................... 159

2 Emergency/backup earth fault protection ......................................................................... 161

2.1 Introduction ............................................................................................................. 161


2.2.1 Tripping time characteristic .......................................................................... 161


2.2.3 Logic diagram ................................................................................................ 163



2.4.1 Setting list ....................................................................................................... 164

2.5 IED report ................................................................................................................ 165

2.6 Technical data .......................................................................................................... 166

Chapter 10 Switch-Onto-Fault protection .................................................................................. 169

1 Switch-Onto-Fault protection .............................................................................................. 170

5

1.1 Introduction ............................................................................................................. 170

1.2 Function principle.................................................................................................... 170

1.2.1 Function description ...................................................................................... 170

1.2.2 Logic diagram ................................................................................................ 171



1.4.1 Setting lists ..................................................................................................... 173

1.4.2 Setting calculation example ......................................................................... 174

1.5 Reports .................................................................................................................... 174

1.6 Technical data.......................................................................................................... 175

Chapter 11 Overload protection ................................................................................................. 177

1 Overload protection ............................................................................................................. 178



1.1.2 Logic diagram ................................................................................................ 178



1.3.1 Setting lists ..................................................................................................... 179

1.4 Reports .................................................................................................................... 179

Chapter 12 Overvoltage protection ............................................................................................ 181

1 Overvoltage protection ........................................................................................................ 182

1.1 Introduction ............................................................................................................. 182


1.2.1 Phase to phase overvoltage protection ..................................................... 182

1.2.2 Phase to earth overvlotage protection ....................................................... 183

1.2.3 Logic diagram ................................................................................................ 183



1.4.1 Setting lists ..................................................................................................... 185

1.5 Reports .................................................................................................................... 185

1.6 Technical data.......................................................................................................... 186

Chapter 13 Undervoltage protection .......................................................................................... 187

1 Undervoltage protection ...................................................................................................... 188

1.1 Introduction ............................................................................................................. 188


1.2.1 Phase to phase underovltage protection ................................................... 188

1.2.2 Phase to earth undervoltage protection ..................................................... 189

1.2.3 Depending on the VT location ..................................................................... 189

1.2.4 Logic diagram ................................................................................................ 190



1.4.1 Setting lists ..................................................................................................... 193

1.5 Reports .................................................................................................................... 194

1.6 Technical data.......................................................................................................... 194

Chapter 14 Circuit breaker failure protection ............................................................................ 197

1 Circuit breaker failure protection ........................................................................................ 198

1.1 Introduction ............................................................................................................. 198

1.2 Function Description ............................................................................................... 199

1.2.1 Current criterion evaluation.......................................................................... 200

1.2.2 Circuit breaker auxiliary contact evaluation ............................................... 201

1.2.3 Logic diagram ................................................................................................ 202



1.4.1 Setting lists ..................................................................................................... 207

1.5 Reports ..................................................................................................................... 208

1.6 Technical data .......................................................................................................... 209

Chapter 15 Dead zone protection ............................................................................................... 211

1 Dead zone protection .......................................................................................................... 212

1.1 Introduction ............................................................................................................. 212



1.2.2 Logic diagram ................................................................................................ 213



1.4.1 Setting lists ..................................................................................................... 215

1.5 Reports ..................................................................................................................... 216

1.6 Technical data .......................................................................................................... 216

Chapter 16 STUB protection ...................................................................................................... 217

1 STUB protection ................................................................................................................... 218

1.1 Introduction ............................................................................................................. 218



1.2.2 Logic diagram ................................................................................................ 219



1.4.1 Setting lists ..................................................................................................... 220

1.5 Reports ..................................................................................................................... 221

1.6 Technical data .......................................................................................................... 221

Chapter 17 Poles discordance protection ................................................................................... 223

1 Poles discordance protection ............................................................................................. 224

1.1 Introdcution ............................................................................................................. 224



1.2.2 Logic diagram ................................................................................................ 225



1.4.1 Setting lists ..................................................................................................... 227

1.5 Reports ..................................................................................................................... 227

7

1.6 Technical data.......................................................................................................... 228

Chapter 18 Synchro-check and energizing check function ........................................................ 229

1 Synchro-check and energizing check function ................................................................ 230

1.1 Introduction ............................................................................................................. 230


1.2.1 Synchro-check mode .................................................................................... 230

1.2.2 Energizing ckeck mode ................................................................................ 231

1.2.3 Override mode ............................................................................................... 232

1.2.4 Logic diagram ................................................................................................ 232



1.4.1 Setting lists ..................................................................................................... 234

1.4.2 Setting explanation ....................................................................................... 235

1.5 Reports .................................................................................................................... 235

1.6 Technical data.......................................................................................................... 236

Chapter 19 Auto-reclosing function ........................................................................................... 239

1 Auto-reclosing ....................................................................................................................... 240

1.1 Introduction ............................................................................................................. 240


1.2.1 Single-shot reclosing .................................................................................... 240

1.2.2 Multi-shot reclosing ....................................................................................... 242

1.2.3 Auto-reclosing operation mode ................................................................... 244

1.2.4 Auto-reclosing initiation ................................................................................ 245

1.2.5 Cooperating with external protection IED .................................................. 246

1.2.6 Auto-reclosing logic ...................................................................................... 247

1.2.7 AR blocked conditions .................................................................................. 249

1.2.8 Logic diagram ................................................................................................ 250



1.4.1 Setting lists ..................................................................................................... 254

1.5 Reports .................................................................................................................... 256

1.6 Technical data.......................................................................................................... 257

Chapter 20 Secondary system supervision ................................................................................. 259

1 Current circuit supervision .................................................................................................. 260

1.1 Introduction ............................................................................................................. 260

1.2 Function diagram ..................................................................................................... 260



1.4.1 Setting lists ..................................................................................................... 261

1.4.2 Setting explanation ....................................................................................... 261

1.5 Reports .................................................................................................................... 261

2 Fuse failure supervision ...................................................................................................... 262

2.1 Introduction ............................................................................................................. 262


2.2.1 Three phases (symmetrical) VT Fail .......................................................... 262

2.2.2 Single/two phases (asymmetrical) VT Fail ................................................ 263

2.2.3 Logic diagram ................................................................................................ 263



2.4.1 Setting list ....................................................................................................... 265

2.5 Technical data .......................................................................................................... 266

Chapter 21 Monitoring ............................................................................................................... 269

1 Check Phase-sequence for voltage and current ............................................................. 270

1.1 Introduction ............................................................................................................. 270

2 Check 3I0 polarity ................................................................................................................ 270

2.1 Introduction ............................................................................................................. 270

3 Check the third harmonic of voltage .................................................................................. 270

3.1 Introduction ............................................................................................................. 270

4 Check auxiliary contact of circuit breaker ......................................................................... 270

4.1 Introduction ............................................................................................................. 270

5 Broken conductor ................................................................................................................. 271

5.1 Introduction ............................................................................................................. 271

5.1.1 Logic diagram ................................................................................................ 271



5.3.1 Setting list ....................................................................................................... 272

5.4 Reports ..................................................................................................................... 273

6 Fault locator .......................................................................................................................... 274

6.1 Introduction ............................................................................................................. 274

Chapter 22 Station communication ............................................................................................ 277

1 Overview ................................................................................................................................ 278

2 Protocol .................................................................................................................................. 278

2.1 IEC61850-8 communication protocol ..................................................................... 278

2.2 IEC60870-5-103 communication protocol .............................................................. 278

3 Communication port ............................................................................................................. 279

3.1 Front communication port ....................................................................................... 279

3.2 RS485 communication ports ................................................................................... 279

3.3 Ethernet communication ports ................................................................................. 279

4 Typical communication scheme ......................................................................................... 279

4.1 Typical substation communication scheme ............................................................. 279

4.2 Typical time synchronizing scheme ........................................................................ 280

5 Technical data ....................................................................................................................... 281


5.2 RS485 communication port ..................................................................................... 281

5.3 Ethernet communication port .................................................................................. 281

5.4 Time synchronization .............................................................................................. 282

Chapter 23 Remote communication ........................................................................................... 283

1 Binary signal transfer ........................................................................................................... 284

9

2 Remote communication channel ....................................................................................... 284

2.1 Introduction ............................................................................................................. 284

3 Technical data ....................................................................................................................... 286

3.1 Fiber optic communication ports ............................................................................. 286

Chapter 24 Hardware ................................................................................................................. 289

1 Introduction ........................................................................................................................... 290

1.1 IED structure ........................................................................................................... 290

1.2 IED appearance ....................................................................................................... 290

1.3 IED module arrangement ........................................................................................ 291

1.4 The rear view of the protection IED ........................................................................ 291

2 Local human-machine interface ........................................................................................ 292

2.1 Human machine interface ........................................................................................ 292

2.2 LCD ......................................................................................................................... 293

2.3 Keypad .................................................................................................................... 293

2.4 Shortcut keys and functional keys ........................................................................... 294

2.5 LED ......................................................................................................................... 295


3 Analog input module ............................................................................................................ 297

3.1 Introduction ............................................................................................................. 297

3.2 Terminals of Analogue Input Module (AIM) .......................................................... 297

3.3 Technical data.......................................................................................................... 298

3.3.1 Internal current transformer ......................................................................... 298

3.3.2 Internal voltage transformer ......................................................................... 299

4 CPU module ......................................................................................................................... 300

4.1 Introduction ............................................................................................................. 300

4.2 Communication ports of CPU module (CPU) ......................................................... 300

5 Communication module ...................................................................................................... 302

5.1 Introduction ............................................................................................................. 302

5.2 Substaion communication port ................................................................................ 302

5.2.1 RS232 communication ports ....................................................................... 302

5.2.2 RS485 communication ports ....................................................................... 302

5.2.3 Ethernet communication ports .................................................................... 302

5.2.4 Time synchronization port ............................................................................ 303

5.3 Terminals of Communication Module .................................................................... 303

5.4 Operating reports ..................................................................................................... 304

5.5 Technical data.......................................................................................................... 304

5.5.1 Front communication port ............................................................................ 304

5.5.2 RS485 communication port ......................................................................... 305

5.5.3 Ethernet communication port ...................................................................... 305

5.5.4 Time synchronization .................................................................................... 306

6 Binary input module ............................................................................................................. 307

6.1 Introduction ............................................................................................................. 307

6.2 Terminals of Binary Input Module (BIM) ............................................................... 307

6.3 Technical data.......................................................................................................... 309

7 Binary output module ........................................................................................................... 310

7.1 Introduction ............................................................................................................. 310

7.2 Terminals of Binary Output Module (BOM) .......................................................... 310

7.2.1 Binary Output Module A ............................................................................... 310

7.2.2 Binary Output Module C ............................................................................... 313

7.3 Technical data .......................................................................................................... 314

8 Power supply module .......................................................................................................... 316

8.1 Introduction ............................................................................................................. 316

8.2 Terminals of Power Supply Module (PSM) ............................................................ 316

8.3 Technical data .......................................................................................................... 318

9 Techinical data ..................................................................................................................... 319

9.1 Basic data................................................................................................................. 319

9.1.1 Frequency ....................................................................................................... 319

9.1.2 Internal current transformer ......................................................................... 319

9.1.3 Internal voltage transformer ......................................................................... 319

9.1.4 Auxiliary voltage ............................................................................................ 320

9.1.5 Binary inputs .................................................................................................. 320

9.1.6 Binary outputs ................................................................................................ 320

9.2 Type tests ................................................................................................................. 321

9.2.1 Product safety-related tests ......................................................................... 321

9.2.2 Electromagnetic immunity tests .................................................................. 322

9.2.3 DC voltage interruption test ......................................................................... 324

9.2.4 Electromagnetic emission test .................................................................... 324

9.2.5 Mechanical tests ............................................................................................ 325

9.2.6 Climatic tests .................................................................................................. 325

9.2.7 CE Certificate ................................................................................................. 326

9.3 IED design ............................................................................................................... 326

Chapter 25 Appendix ................................................................................................................. 327

1 General setting list ............................................................................................................... 328

1.1 Function setting list ................................................................................................. 328

1.2 Binary setting list ..................................................................................................... 340

2 General report list................................................................................................................. 348

3 Typical connection ............................................................................................................... 356

4 Time inverse characteristic ................................................................................................. 359

4.1 11 kinds of IEC and ANSI inverse time characteristic curves ................................ 359

4.2 User defined characteristic ...................................................................................... 359

5 CT requirement ..................................................................................................................... 361

5.1 Overview ................................................................................................................. 361

5.2 Current transformer classification ........................................................................... 361

5.3 Abbreviations (according to IEC 60044-1, -6, as defined) ...................................... 362

5.4 General current transformer requirements ............................................................... 363

5.4.1 Protective checking current ......................................................................... 363

5.4.2 CT class .......................................................................................................... 364

5.4.3 Accuracy class ............................................................................................... 366

11

5.4.4 Ratio of CT ..................................................................................................... 366

5.4.5 Rated secondary current .............................................................................. 366

5.4.6 Secondary burden ......................................................................................... 366

5.5 Rated equivalent secondary e.m.f requirements ...................................................... 367

5.5.1 Line differential protection ............................................................................ 367

5.5.2 Transformer differential protection .............................................................. 368

5.5.3 Busbar differential protection ....................................................................... 369

5.5.4 Distance protection ....................................................................................... 370

5.5.5 Definite time overcurrent protection and earth fault protection .............. 371

5.5.6 Inverse time overcurrent protection and earth fault protection .............. 372

Chapter 1 Introduction

1


About this chapter

This chapter gives an overview of SIFANG line Protection

IED.


2

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.


3

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


4

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)

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)


5

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


6

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

Logical Node

Name

IEC 60617

graphical

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 85–21,21N PSCH

Communication scheme for earth fault

protection 85–67N PSCH

Current protection

Overcurrent protection 50,51,67 PTOC

3IINV>

3I >>

3I >>>

Earth fault protection 50N, 51N,

67N PEFM

I0INV>

I0>>

I0>>>

Emergency/backup overcurrent

protection 50,51 PTOC

3IINV>

3I >

Emergency/backup earth fault

protection 50N,51N PTOC

I0INV>

I0 >

Switch-onto-fault protection 50HS PSOF 3I >HS

I0>HS

Overload protection 50OL PTOC 3I >OL

Voltage protection

Overvoltage protection 59 PTOV 3U>

3U>>


7

Undervoltage protection 27 PTUV 3U<

3U<<

Breaker control function

Breaker failure protection 50BF RBRF

3I> BF

I0>BF

I2>BF

Dead zone protection 50SH-Z

STUB protection 50STUB PTOC 3I>STUB

Poles discordance protection 50PD RPLD

3I< PD

I0>PD

I2>PD

Synchro-check and energizing check 25 RSYN

Auto-recloser 79 RREC O→I

Single- and/or three-pole tripping 94-1/3 PTRC

Secondary system supervision

CT secondary circuit supervision

VT secondary circuit supervision 97FF

3.2 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


8

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


9

Functions

IED testing

Disturbance recording analysis

IED configuration

Printing


10

Chapter 2 General IED application

11


About this chapter

This chapter describes the use of the included software

functions in the IED. The chapter discusses general

application possibilities.


12

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.


13

2 Report record

The report record includes tripping, alarm and operation reports. See

Chapter 25 for detail.


14

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. Explanation Default Unit Min. Max.

T_Pre Fault Time setting for recording time

before fault occurred 0.05 s 0.05 0.3


15


T_Post Fault Time setting for recording time

after fault occurred 1 s 0.50 4.50

DR_Sample Rate

Sample rate for fault recording

(0: 600 sample/cycle, 1:1200

sample/cycle)

0 0 1


16

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 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

4.3 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


17

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


18

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.


19

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:

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.

5.2.1 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.


20

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.


21

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.


22

Chapter 3 Basic protection elements

23

Chapter 3 Basic protection

elements

About this chapter

This chapter describes basic protection elements including

startup elements, phase selectors and directional elements.


24

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:

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

1.2 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

3 0 _i I abrupt

Equation 1

where


25

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 Min3I0_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


26

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

3I0_SOTF is the zero-sequence current setting of SOTF protection

1.4 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


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


I_OC Inv is the setting value of inverse time stage of the overcurrent


I_Em/BU OC is the setting value of emergency/backup overcurrent

protection


27

I_Inv_Em/BU OC is the setting value for inverse time stage of

emergency/backup overcurrent protection

I_STUB is the setting value of STUB protection

I_SOTF is the setting value of SOTF protection

1.5 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:

Upe is each phase-to-earth voltage

Upp is each phase-to-phase volatge.


U_Secondary is the system secondary rated voltage

1.6 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


28

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


29

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

I

A B C AB BC CA ABC

IAB ＋＋ — ＋＋＋＋＋＋

IBC — ＋＋＋＋＋＋＋＋

ICA ＋ — ＋＋＋＋＋＋＋

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 ( 2 0I I ) can be usded to

select faulty phases. This concept has been shown in Figure 1 and Table

3.

.

I0a

+300

-300

+90 -900 0

+150 -15000

AN,BCN

ABN

CN,ABN

CAN

BN,CAN

BCN

Figure 1 relation between angle of zero and negative sequence component for various


30

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:


31

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.


32

Forward

Angle_EF

Bisector

0_Ref3U

0°

-3I 0

3I 090°

Angle_Range

EF

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.


33

Forward

Angle_Neg

I3 2

I-3 2

3 RefU 2_

0°

90°

Bisector

Angle_Range

Neg

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.


34

X

RR_Set

Forward

Reverse

X_Set

-n∙X_Set

-n∙R_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.

(Ir:5A/1A)

Max.

(Ir:5A/1A)

Default

setting

(Ir:5A/1A)

Description

I_abrupt A 0.08Ir 20Ir 0.2Ir

Sudden-change

current threshold of

startup element

T_Relay Reset s 0.5 10 1 The reset time of relay

U_Primary kV 30 800 230 Rated primary voltage

(phase to phase)

U_Secondary V 100 120 100 Rated secondary


35

Setting Unit Min.

(Ir:5A/1A)

Max.

(Ir:5A/1A)

Default

setting

(Ir:5A/1A)

Description

voltage (phase to

phase)

CT_Primary kA 0.05 5 3 Rated primary current

CT_Secondary A 1 5 1 Rated secondary

current

4.2 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.

3) Primary rated voltage：Is set according to the actual rated primary

voltage of VT in kV..

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.


36

Chapter 4 Line differential protection

37

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.


38

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

CSC-103 CSC-103

MCB TA TA CB

N

IM A、B、C IM A、B、C

IN A、B、C IN A、B、C

Channel

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.


39

6 Phase-segregated current differential protection

The protection provides two-slope percent differential characteristic, as

shown in Figure 6.

IDiff

IRes

I_2Diff

I_1Res

K1

K2

operating area

I_1Diff

I_2Res

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


40

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:

( ) ( )Diff M MC N NCI I I I I

Re ( ) ( )s M MC N NCI I I I I

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:

_

Re ,

Re

1 0 3 _

2 _ , 3 _

Diff Set

Diff s Diff

Diff s

I I

I K I at I I Set

I K I I Set at I Set


41

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

ΔIRes

ΔI_2Diff

ΔI_1Res

K1

K2

operating area

ΔI_1Diff

ΔI_2Res

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


42

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.

Diff M NI I I

Re s M NI I I

ΔIM : Variable of current flowing toward the protected feeder from end M

ΔIN : Variable of current flowing toward the protected feeder from end N


_

Re ,

Re

1 0 3 _

2 _ , 3 _

Diff Set

Diff s Diff

Diff s Diff

I I

I K I at I I Set

I K I I Set at I I Set


43

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

I0Res

I_0Diff

Operating area

K

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.


44

0 (I ) (I ) (I ) ( ) ( ) ( )Diff MA MAC MB MBC MC MCC NA NAC NB NBC NC NCCI I I I I I I I I I

0 (I ) (I ) (I ) ( ) ( ) ( )Diff MA MAC MB MBC MC MCC NA NAC NB NBC NC NCCI I I I I I I I I I

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


0 _

0 0 Re

I Diff Set

Diff s

I

I kI


45

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).

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.

9.1.2 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.


46

9.2 Capacitive current compensation

I M NIc I 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


47

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.

1

1

1

2MC

C

UMI

j X

2

2

2

2MC

C

UMI

j X

0

0

0

2MC

C

UMI

j X

If XC1 ＝XC2, each phase charging current of terminals M are respectively

as below.

1 2 0

1 0

1 0

1 2 0 0 0

2 2

0 0

2 2

MAC MC MC MC

C C

C C

I I I I

UM UM UM UM UM

j X j X

UMA UM UM

j X j X

1 2 0

1 0

1 0

2* *

2* 1 * 2 0 0

0

2 2

0 0

2 2

MBC MC MC MC

C C

C C

I I I I

UM UM UM UMUM

j X j X

UMB UM UM

j X j X


48

1 2 0

1 0

1 0

2* *

2* 1 * 2 0 0

0

2 2

0 0

2 2

MCC MC MC MC

C C

C C

I I I I

UM UM UM UMUM

j X j X

UMC UM UM

j X j X

In the same way, each phase charging current of terminals N are

respectively as below.

1 0

0 0

2 2NAC

C C

UNA UN UNI

j X j X

1 0

0 0

2 2NBC

C C

UNB UN UNI

j X j X

1 0

0 0

2 2NCC

C C

UNA UN UNI

j X j X

9.3 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.


49

IDiff

IRes

I_LDiffCT

K

Operating area

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


50

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

Relay trip

A

N

D

3I0>I_Diff ZeroSeq

No CT Fail

T_Diff ZeroSeq

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.


51

A

N

D

O

R

Offside: BI_PhA CB Open

Offside:startup

Offside: Func_Diff Curr On

Offside: BI_PhB CB Open

Offside: BI_PhC CB Open

A

N

D

Channel OK

Relay startup A

N

DFunc_Diff Curr On

A

N

D

IA_diff>I_Diff High

A Phase CT fail

A

N

D

IA_diff>I_Diff TA Fail A

N

D

A

N

D

Relay trip

Block Diff CT_Fail off

IB_diff>I_Diff High

B Phase CT fail

A

N

D

IB_diff>I_Diff TA Fail A

N

D

O

RBlock Diff CT_Fail off

IC_diff>I_Diff High

C Phase CT fail

A

N

D

IC_diff>I_Diff TA Fail A

N

DBlock Diff CT_Fail off

A Phase CT fail

B Phase CT fail

C Phase CT fail

O

R

Block Diff CT_Fail on

Block 3Ph Diff CT_Fail on

A

N

D

O

R

O

R

O

R

Figure 14 Phase-segregated current differential protection logic


52

DTT By Z2 on

DTT By Z3 on

DTT By startup

DTT By Z2 on

DTT By Z3 on

DTT By startup on

ZONE2 forward

ZONE3 forward

General startup

A

N

D

A

N

D O

R

A

N

D

Dtt singal receive

A

N

D

Relay trip

Figure 15 DTT logic

9.10 Input and output signals

IP1

IP2

IP3

UP1

UP2

UP3

Trip PhA

Trip PhB

Trip PhC

Trip 3Ph

Relay Block AR

Relay Startup

Relay Trip

Tele_Trans1

Tele_Trans2

DTT

Chan_A_Test

Chan_B_Test

Curr Diff Trip

BO_DTT

Tele_Trans1

Tele_Trans2

Channel A Alarm

Channel B Alarm

Table 5 Analog input list

Signal Description

IP1 Signal for current input 1



UP1 Signal for voltage input 1




53

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

No. Setting Unit Min.

(Ir:5A/1A) Max. (Ir:5A/1A)

Default setting

(Ir:5A/1A)

I_Diff High A 0.1Ir 20Ir 0.4Ir high current threshold of

differential protection

I_Diff Low A 0.1Ir 20Ir 0.4Ir low current threshold of


I_Diff TA Fail A 0.1Ir 20Ir 2Ir current threshold of

differential protection at


54

CT failure

I_Diff

ZeroSeq A 0.1Ir 20Ir 0.2Ir

zero sequence current

threshold of zero

sequence differential

protection

T_Diff

ZeroSeq s 0.1 60 0.1

delay time of zero


protection

T_DTT s 0 10 0.1 delay time of DTT

CT Factor 0.2 1 1 convert factor of CT ratio

XC1 Ohm 40 9000 9000

positive sequence

capacitive reactance of

line

XC0 Ohm 40 9000 9000 zero sequence capacitive

reactance of line

X1_Reactor Ohm 90 9000 9000

positive sequence

reactance of shunt

reactor

X0_Reactor Ohm 90 9000 9000 zero sequence reactance

of shunt reactor

Local

Address 0 65535 00000

identified code of local

end of line

Opposite

Address 0 65535 0

identified code of

opposite end of line

Table 9 Line differential protection function setting list

Setting Unit Min.

(Ir:5A/1A)

Max.

(Ir:5A/1A)

Default

setting

(Ir:5A/1A)

Description

Func_Diff

Curr 0 1 1


enable(1)/disable(0)

Func_Diff

Curr Abrupt 0 1 1

sudden change



Dual_Channel 0 1 1

double

channels(1)/single

channel(0)

Master Mode 0 1 1 master mode (1)/

slaver mode (0)

Comp

Capacitor Cur 0 1 0

capacitive current

compensation



55

Block Diff

CT_Fail 0 1 1

CT failure block



Block 3Ph Diff

CT_Fail 0 1 0

CT fail block 3

phases(1)/ CT fail

block single phase(0)

Diff_Zero Init

AR 0 1 1

AR initiated by zero


protection

Chan_A

Ext_Clock 0 1 0

Channel A apply

external clock

enable(1)/internal

clock disable(0)

Chan_A 64k

Rate 0 1 0

Channel A at 64Kb/s

enable(1)/2M Kb/s

disable(0)

Chan_B

Ext_Clock 0 1 0

Channel B apply

external clock


Chan_B 64k

Rate 0 1 0

Channel B at 64Kb/s


Loop Test 0 1 0

channel loop test

mode


DTT By

Startup 0 1 1

DTT under startup

element control

DTT By Z2 0 1

DTT under Zone 2

distance element

control

DTT By Z3 0 1

DTT under Zone 3

distance element

control

9.11.2 Setting explanation

9.11.2.1 Explanation of part setting

1) ‖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.


56

2) 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.

3) ‖ 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.

4) ‖ 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.

5) ‖ XC1‖,‖ XC0‖： Set according to secondary value of line full-length.

11

/2 1

C TA TVX N NfC

01

/2 0

C TA TVX N NfC

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.


57

Table 10 Compensation capacitor setting

Voltage

grade

(kV)

Positive-sequence

capacitive reactance（Ω）

Zero-sequence

capacitive reactance（Ω）

Capacitive

current（A）

220 3736 5260 34

330 2860 4170 66

500 2590 3790 111

750 2242 3322 193

Secondary value calculation:

(100 / ) / Xc 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

6) ‖ X1_Reactor‖, ‖ X0_Reactor‖：Convert the capacity of shunt

reactor into secondary value to set.

TA TV

2X1_ Reactor N / N U / S

TA TV N

20 _ Re N / N (U / S+3X )X actor

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

1

2 62000 / 7500 800000 / 3 100 10 568.8DKX

0 2000 / 7500 3 500 400DKX


58

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‖.

8) 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‖.

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


59

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


60

9.13 Technical data

Table 14 Line differential protection technical data

NOTE: Ir: CT rated secondary current, 1A or 5A;

Item Rang or Value Tolerance

Differential current of

Phase segregated


Sudden change


0.1 Ir to 20.00 Ir ≤±3% or ±0.02Ir

Differential current of

Zero sequence differential

protection

0.1 Ir to 4.00 Ir ≤±3% or ±0.02Ir

Time delay of Zero


protection

0.00 to 60.00s, step 0.01s ≤±1% or +20 ms

Operating time of

Phase segregated


Sudden change


25ms typically at 200% setting,

and IDifferential>2IRestraint

Chapter 5 Distance protection

61


About this chapter


output signals, parameter, IED report and technical data for

distance protection function.


62

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.

R

Zone 1

X

Zone 2

Zone 3

Zone 4

Zone 5

Zone 4 Reverse

(optional)

Zone 5 Reverse

(optional)

Zone Ext.

Figure 16 Distance protection zone characteristics


1.2.1 Full scheme protection


63

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-E L2-E L3-E

L1-E L2-E L3-E

L1-E L2-E L3-E

L1-E L2-E L3-E

L1-L2 L2-L3 L3-L1

L1-L2 L2-L3 L3-L1

L1-L2 L2-L3 L3-L1

L1-L2 L2-L3 L3-L1

L1-L2 L2-L3 L3-L1

ZONE 1

ZONE 2

ZONE 3

ZONE 4

ZONE 5

L1-E L2-E L3-E L1-L2 L2-L3 L3-L1 EXTENDED ZONE 1

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

R

X_Zset

R_Zset

Φ_Ztop

Φ_Zbottom

Φ_ZleftΦ_Zright


64

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


65

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

R

XSet

RSet

ΦTop

ΦBottom

ΦLeft

ΦRightXOffset

ROffset


66

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:

C B, A, :)3IK(IRdt

)3IKd(IφLU 0rΦΦ

0XΦΦ


67

Equation 6

Measuring of the phase-phase impedance for multi-phase faults is as

follows:

CA BC, AB, :IRdt

dILU ΦΦΦΦ

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.


68

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:

L1-E L2-EL

L1 L2

U -UZ =

I -I

Equation 11

In addition, solving differential equation for single phase (e.g. A-E)

results:

Figure 21 Single-phases (A-B) short circuit

E EL1-E A L L E L L A L L E r L x L

L L

R XU =I R +JX -I ( R J X ) I R +JX -I (K R JK X )

R X

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


69

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


70

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 Power swing blocking


71

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:

ZRZLZS

ERESIL

Equation 13

The direction of current flow will remain the same during the power swing

event. Only the voltage displacement will change.


72

The impedance measured at an IED at bus A would then be:

ZSERES

ZRZLZSESZS

IL

ES

IL

ZSILES

IL

VAZ

).(.

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:

22 sin)cos(

sin)cos(

1)sin(cos

)sin(cos

k

jkk

jk

jk

ERES

ES

Equation 15

For the particular case where the two sources magnitudes are equal or k

is one, Equation 15 can be expressed as:

)2

cot1(2

1 j

ERES

ES

Equation 16

And finally the impedance measured at the IED will be:

ZSjZRZLZS

IL

VAZ

)

2cot1(

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.


73

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


74

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


75

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.

|150 0|

NO PS 1 (2,3,4,5)O

R

O

RA

N

D

A

N

D

A

N

D

―I_PSB‖ startup

Fault detect swing

unblocking

Current change

startup

Zero- sequence

current startup

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|


76

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.


77

(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.


78

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)


79

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


80

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:

Z1 detection

A

N

D

Impedance

Within z1

Forward direction

No PS 1

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.


81

Zone 2 faults

Zone 2 fault detection logic is shown in Figure 30.

Z2 detection

A

N

D

Impedance

Within Z2

NOT reverse direction

No Ps 2

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

Z3 detectionO

R

A

N

D

Impedance

Within Z3


Asymmetric fault

No PS 3

Impedance

Within Z3

Symmetric fault

No Ps 3

A

N

D

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


82

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‖.

Z4 detectionO

R

A

N

D

Impedance

Within Z4


Impedance

Within Z4

NOT forward direction

A

N

D

Reverse_Z4 Off

No PS 4

Reverse_Z4 On


83

Z5 detectionO

R

A

N

D

Impedance

Within Z5


Impedance

Within Z5

NOT forward direction

A

N

D

Reverse_Z5 Off

No PS 5

Reverse_Z5 On

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

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.


84

Unpermenent trip

O

R

A

N

D

Permenent tripA

N

D

|T1 0|

A

N

D

O

R

|T2 0|

|T3 0|

|T4 0|

|T5 0|Z5 detection

Z4 detection

Z3 detection

Z2 detection

Z1 detection

O

R

SOTF

VT fail

Ext Z1 detection |T1Ext 0|

Func_SOTF On

Figure 33 Distance protection tripping logic

Trip single phase

O

R

A

N

DSingle fault

Trip Tree phase

Permenent Trip

AR not ready

Relay Trip 3pole on

Two phase fault

AR Init By 2p off

O

R

Three phase fault

AR Init By 3p on

AR Init By 3p off

AR Init By 2p on

Relay Trip 3pole off

O

RAR Init By 2p off

BI “1P Trip

Block”

A

N

D

Figure 34 Trip logic

Note:


85

The above trip logic applies to the first zone and the extended first zone

of distance protection as well as teleprotection


IP1

IP2

IP3

IN（M）

Trip PhA

Trip PhB

Trip PhC

Trip 3Ph

Relay Block AR

Zone1 Trip

Zone2 Trip

Zone3 Trip

Zone4 Trip

Zone5 Trip

Zone1Ext Trip

Relay Startup

Relay Trip

PSB Dist OPTD

IN

UP1

UP2

UP3


Signal Description




IN External input of zero-sequence current

IN(M) External input of zero-sequence current of

adjacent line





Signal Description




86

Signal Description





Relay Block AR Permanent trip, or AR being blocked

Zone1 Trip Zone1 distance protection trip





Zone1Ext Trip Extended zone1 distance protection trip

PSB Dist OPTD Distance operated in power swing


1.4.1 Setting list

Table 17 Distance protection function setting list

Setting Unit Min.

(Ir:5A/1A)

Max.

(Ir:5A/1

A)

Default

setting

(Ir:5A/1A)

Description

Kx -0.33 8 1 compensation factor of zero

sequence reactance

Kr -0.33 8 1 compensation factor of zero

sequence resistance

Km -0.33 8 0

compensation factor of zero

sequence mutual

inductance of parallel line

X_Line Ohm 0.01 600 10 positive reactance of the

whole line

R_Line Ohm 0.01 600 2 positive resistance of the

whole line

Line length km 0.1 999 100 Length of line

I_PSB A 0.5 20Ir 2Ir current threshold of power

system unstability detection

R1_PE Ohm 0.01/0.05 120/600 1/5 resistance reach of zone 1

of phase to earth distance


87

Setting Unit Min.

(Ir:5A/1A)

Max.

(Ir:5A/1

A)

Default

setting

(Ir:5A/1A)

Description

protection

X1_PE Ohm 0.01/0.05 120/600 1/5

reactance reach of zone 1 of

phase to earth distance

protection

R2_PE Ohm 0.01/0.05 120/600 1.6/8

resistance reach of zone 2


protection

X2_PE Ohm 0.01/0.05 120/600 1.6/8



protection

R3_PE Ohm 0.01/0.05 120/600 2.4/12



protection

X3_PE Ohm 0.01/0.05 120/600 2.4/12



protection

R4_PE Ohm 0.01/0.05 120/600 3/15



protection

X4_PE Ohm 0.01/0.05 120/600 3/15



protection

R5_PE Ohm 0.01/0.05 120/600 3.6/18



protection

X5_PE Ohm 0.01/0.05 120/600 3.6/18



protection

R1Ext_PE Ohm 0.01/0.05 120/600 1.6/8

resistance reach of

extended zone 1 of phase to

earth distance protection

X1Ext_PE Ohm 0.01/0.05 120/600 1.6/8

reactance reach of


earth distance protection

T1_PE s 0 60 0

delay time of zone 1 of


protection

T2_PE s 0 60 0.3



protection

T3_PE s 0 60 0.6 delay time of zone 3 of


88

Setting Unit Min.

(Ir:5A/1A)

Max.

(Ir:5A/1

A)

Default

setting

(Ir:5A/1A)

Description


protection

T4_PE s 0 60 0.9



protection

T5_PE s 0 60 1.2



protection

T1_Ext_PE s 0 60 0.05

delay time of extended zone

1 of phase to earth distance

protection

R1_PP Ohm 0.01/0.05 120/600 1/5


of phase to phase distance

protection

X1_PP Ohm 0.01/0.05 120/600 1/5


phase to phase distance

protection

R2_PP Ohm 0.01/0.05 120/600 1.6/8



protection

X2_PP Ohm 0.01/0.05 120/600 1.6/8



protection

R3_PP Ohm 0.01/0.05 120/600 2.4/12



protection

X3_PP Ohm 0.01/0.05 120/600 2.4/12



protection

R4_PP Ohm 0.01/0.05 120/600 3/15



protection

X4_PP Ohm 0.01/0.05 120/600 3/15



protection

R5_PP Ohm 0.01/0.05 120/600 3.6/18



protection

X5_PP Ohm 0.01/0.05 120/600 3.6/18



protection


89

Setting Unit Min.

(Ir:5A/1A)

Max.

(Ir:5A/1

A)

Default

setting

(Ir:5A/1A)

Description

R1Ext_PP Ohm 0.01/0.05 120/600 1.6/8

resistance reach of


phase distance protection

X1Ext_PP Ohm 0.01/0.05 120/600 1.6/8

reactance reach of


phase distance protection

T1_PP s 0 60 0



protection

T2_PP s 0 60 0.3



protection

T3_PP s 0 60 0.6



protection

T4_PP s 0 60 0.9



protection

T5_PP s 0 60 1.2



protection

T1_Ext_PP s 0 60 0.05

delay time of extended zone

1 of phase to phase

distance protection

3I0_Dist_P

E A 0.1Ir 2Ir 0.1Ir


threshold of phase to earth

distance protection

3U0_Dist_

PE V 0.5 60 1

zero sequence voltage

threshold of phase to earth

distance protection

Table 18 Distance protection binary setting list


Func_Z1 First zone distance protection

operating mode (On/Off) 1 0 1

Func_Z2

Second zone distance

protection operating mode

(On/Off)

1 0 1


90


Func_Z3 Third zone distance protection

operating mode (On/Off) 1 0 1

Func_Z4

Fourth zone distance


(On/Off)

1 0 1

Reverse_Z4

Setting for fourth zone

distance protection operation

as reverse

0 0 1

Func_Z5 Fifth zone distance protection

operating mode 1 0 1

Reverse_Z5

Setting for fifth zone distance

protection operation as for

reverse

0 0 1

Func_Z1Ext

Extended zone 1 distance


(On/Off)

1 0 1

Z1_PS Blocking

Blocking of the first zone

distance protection in power

swing

1 0 1

Z2_PS Blocking

Blocking of the second zone

distance protection in power

swing

1 0 1

Z3_PS Blocking

Blocking of the third zone

distance protection when

power swing

1 0 1

Z4_PS Blocking

Blocking of the fourth zone

distance forward protection in

power swing

1 0 1

Z5_PS Blocking

Blocking of the fifth zone

distance forward protection in

power swing

1 0 1

Z1Ext_PS Blocking

Blocking of the extended zone

1 distance forward protection

in power swing

1 0 1

Z2 Speedup

Second zone distance

protection speedup operating

mode by auto-reclosing on to

fault

0 0 1

Z3 Speedup

Third zone distance protection

speedup operating mode by

auto-reclosing on to fault

0 0 1


91


Z23 Speedup Inrush Block Distance protection speedup

operating blocked by inrush 0 0 1


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.

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.

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


92

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.

1.4.3 Calculation example for distance parameter settings

The solidy grounded 400kV overhead Line A-B has been shown in

21/21N

127km 139km

PTR:400/0.1kV

CTR:2000/5

A BC

21/21N

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.

21/21N

127km 139km

PTR:400/0.1kV

CTR:2000/5

A BC

21/21N

Figure 35 400kV Overhead Line (A-B) protected by distance protection

For line 1 (line AB):


93

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

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.


94

RE/RL = 0 1

13

R R

R

=3.00

XE/XL 0 1

13

X X

X

= 0.52

x' = 0.04 Ω/km in secondary side

Time Delays：

T1-p-e or p-p time delay 0.0 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:

3

2500 / 2

PH MIN

m ph ph spacingRarc

I

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


95

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: 0.03024+ j0.35276

Ω/km

Connected Line length: 127.0 km

Positive sequence impedance, Z_Line: 3.840+ j44.8 Ω=0.024+

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):

1.2 /( 1)

2

Rarc CTR PTRR Z

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


96

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

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

14°

14°

63.4°

7°

RDZ

XDZ

R (Ω)

X (Ω)


97

Figure 36

85.1°63.4°

3.81

X (ohm)

R (ohm)

7°

Line

angle

0.33

0.04

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,

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

85.1°63.4°

3.58

X (ohm)

R (ohm)

7°

Line

angle

0.33

0.04


98

Figure 38 Characteristic zone example


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 ( 1) ( 1) 2.5 ( 1)X Z R Z X Z

So,

3.05≤ R (Z1) ≤9.53

Therefore, in this case, setting value for R(Z1) is considered as:

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.

2(1 )

1TF

IR Effective Tower Resistance

I

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.


99

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: 3m

1 min

2500 2

ph

V Ph Tower SpacingRarc

I

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

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] : 1.374490915

pu = 1.986


100

kA

And on secondary side,

I3ph- min=4.965 A

So, arc resistance will be:

Rarc=7.55 Ω

1.2 ( ) /( 1)

1

TF

E

L

Rarc R CTR PTRRE Z

R

R

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.

1

0.8 ( 1) ( 1) 2.5 ( 1)

1

E

L

E

L

X

XX Z RE Z X ZR

R

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


101

Power swing blocking zones All zones

Zone Z2 & Z3 impedance setting

According to the grading requirement:

( 2) 0.8 1 0.8 2shortestCTR

X Z X Line X LinePTR

X+Line1 =44.8 Ω in primary

X+Line2 =48.928 Ω

CTR=2000/5 A

CTR/PTR=0.100

PTR=400/0.1kV

So,

X (Z2) =6.72 Ω in secondary side

85.1°63.4°

6.72

X (ohm)

R (ohm)

7°

Line

angle

0.58

0.07

Figure 39 Zone 2 protection characteristic setting


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.


102

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:

sec

( 2)( 2) ( 1)

( 1 )ondary

X ZR Z Min R Z

X Line

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:

( 2)( 2) 1.2 ( 1)

( 1 )

X ZRE Z RE Z

X Line

secondary

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


103

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:

14°

14°

63.4°

7°

RDZ

XDZ

R (Ω)

X (Ω)


Rlo

ad

=4

0

37° 63.4°

26.6°

30.1

15.1

X (ohm)

R (ohm)


104


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

R(Z2), Resistance for ph-ph-faults 4.70

Ω

X(Z2), Reactance 6.79

Ω

RE(Z2), Resistance for ph-e faults 5.58

Ω

XE(Z2), Reactance 6.79

Ω

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 7.05

Ω

X(Z3), Reactance 10.19

Ω

RE(Z3), Resistance for ph-e faults 8.37

Ω

XE(Z3), Reactance 10.19

Ω

Zone Z4

Zone 4 is considered to protect %30 of the zone 1 in reverse direction.


105

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

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


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





Zone1Ext Trip Zone 1 Extended distance trip

Dist SOTF Ttrip Distance element instantaneous trip after switching on to fault


106

(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

Dist Evol Trip

Distance zone 1 evolvement trip, for example, A phase to earth fault

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


Abbr. Meaning

Func_Dist Blk Distance function blocked by VT fail


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



Number of settable zone 5 zones, with additional

extended zone

Distance characteristic Polygonal


107

Resistance setting range 0.01Ω～120Ω, step 0.01Ω,

when Ir=5A;

0.05Ω～600Ω, step 0.01Ω,

when Ir=1A;

≤± 5.0% static accuracy

Conditions:

Voltage range: 0.01 Ur to 1.2

Ur

Current range: 0.12 Ir to 20 Ir Reactance setting range 0.01Ω～120Ω, step 0.01Ω,

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

zone 1

≤±5%, at 0.5<SIR<30


108

Chapter 6 Teleprotection

109


About this chapter


output signals, parameters, IED report and technical data

used for teleprotection function.


110

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

|200 0| CARR Send signal

O

R

A

N

D

A

N

DRelay trip

A

N

D

Relay startup

Relay reset

Zone 1 operation

A

N

D

Zone 2 operation

Delay time 5ms A

N

DCARR Received

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

―POR mode‖ is set to ―1-on‖. The permissive overreach transfer trip logic

has been shown in the below figure.

|200 0| CARR Send signal

O

R

A

N

D

A

N

DRelay trip

A

N

D

Relay startup

Relay reset

A

N

D

Zone 2 operation

Delay time 5ms A

N

DCARR Received

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

CARR Send signal

A

N

D

A

N

DRelay trip

A

N

D

Relay startup

Relay reset

A

N

D

Zone 4 （reverse）operation

Delay time 25ms A

N

DCARR Received

Zone 2 operation

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

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

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.


IP1

IP2

IP3

UP1

UP2

UP3

Carr Recv(Dist)

Carr Fail(Dist)

BI_DTT Send

BI_DTT Recv

Trip PhA

Trip PhB

Trip PhC

Trip 3Ph

Relay Block AR

Carr Send(Dist)

Carr Fail(Dist)

Tele_Dist_Trip

Weak End Infeed

BO_DTT Send

BO_DTT Recv

Relay Startup

Relay Trip

IN


116


Signal Description









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


Signal Description








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



117

1.4.1 Setting list

Table 26 Tele-Dist protection function setting list


T_Tele Reversal Time delay for

direction reversing 40 ms 0 100

Table 27 Tele-Dist protection binary setting list


Weak InFeed Weak InFeed Mode 0 0 1

Blocking Mode Blocking Mode 0 0 1

PUR Mode PUR Mode 0 0 1

POR Mode POR Mode 1 0 1

Func_Z1

first zone distance

protection Operating

mode

1 0 1

Func_Z2

second zone distance

protection Operating

mode

1 0 1


1) 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.

2) 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.

3) 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


118

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


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


Abbr. Meaning

Carr Fail (Dist) Carrier fail in distance tele-protection

Tele Mode Alarm Tele Mode Alarm


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


Operating time 25ms typically in permission

mode for 21/21N, at 70%

setting


119

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.


To detect earth fault reliably and selectively, IED considers teleprotection

scheme as following:

CARR (DEF) Send

O

R

A

N

D

A

N

D

Relay trip

A

N

D

Relay startup

Relay reset

A

N

D

Zero-Forward

direction

A

N

DCARR (DEF)

Received

3I0>3I0_Tele EF

POR Mode on

Tele_EF Inrush unblock

|200 0|Trip

|T_tele EF|

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

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‖


IP1

IP2

IP3

UP1

UP2

UP3

Carr Recv(DEF)

Carr Fail(DEF)

BI_DTT Send

BI_DTT Recv

Trip PhA

Trip PhB

Trip PhC

Trip 3Ph

Relay Block AR

Carr Send(DEF)

Carr Fail(DEF)

Tele_DEF_Trip

Weak End Infeed

BO_DTT Send

BO_DTT Recv

Relay Startup

Relay Trip

Weak InFeed


Signal Description



121

Signal Description







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


Signal Description








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



122

2.4.1 Setting lists

Table 35 Tele-EF protection function setting list

Setting Unit

Min.

(Ir:5A/

1A)

Max.

(Ir:5A/

1A)

Default

setting

(Ir:5A/1A)

Description

T_Tele

Reversal ms 0 100 40 Time delay of power reserve

3I0_Tele

EF A 0.08Ir 20Ir 0.2Ir

zero sequence current threshold of

tele-protection based on earth fault

protection

T0_Tele

EF s 0.01 10 0.15

time delay of tele-protection based on

earth fault protection

Table 36Tele-EF protection binary setting list


POR Mode POR Mode 1 0 1

Func_Tele EF Tele earth fault

protection function 0 0 1

Tele_EF Inrush Block

Tele earth fault

protection blocked by

inrush

0 0 1

Tele_EF Init AR

Auto reclosure

initiated by tele earth

fault protection

0 0 1

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


Abbr. Meaning

Tele Evol Trip

Tele evolvement trip, for example, A phase to earth fault happened,

and then B phase to earth fault followed, the latter is considered as

an evolvement trip


123

Abbr. Meaning

Carr Send(DEF) Send carrier signal in DEF

Tele_DEF_Trip Tele_DEF trip


Abbr. Meaning

Carr Fail(DEF) Carrier fail in TeleDEF

Tele Mode Alarm Tele Mode Alarm


Abbr. Meaning

Func_Tele_DEF On TeleDEF function on

Func_TeleDEF Off TeleDEF function off


124

Chapter 7 Overcurrent protection

125


About this chapter

This chapter describes the protection principle, input and output

signals, parameter, IED report and technical data used for

overcurrent protection.


126

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


1.2.1 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

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:

_

_ _ _

_

P OC Inv

A OC InvT B OC Inv K OC INV

i

I 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

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.

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

UBC_Ref

Angle_OC

IA

IA-

0°

90°

Bisector

Angle_Range

OC

Figure 47 Overcurrent protection directional characteristic

where:

Angle_OC: The settable characteristic angle

Angle_Range OC: 85º


129

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 aI bcU

B bI caU

C cI abU

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

Func_OC1

OC1 Inrush Block On

OC1 Inrush Block Off

OC1 Inrush Block On

OC1 Direction Off

AND

OC1 Direction On

OC1 Inrush Block Off

AND

AND

T_OC1

AND

OR

AND

Ia>I_OC1

Phase A forward

VT fail

<Imax_2H_UnBlk

Ia2/Ia1>

Cross blocking

Ia2/Ia1 >

Ib2/Ib1 >

Ic2/Ic1 >

T2h_Cross_Blk<

Cross blocking

Trip

Figure 48 Logic diagram for overcurrent protection



131

IP1

IP2

IP3

Trip PhA

Trip PhB

Trip PhC

Trip 3Ph

Relay Block AR

Relay Startup

Relay Trip

OC1_Trip

OC2_Trip

OC Inv Trip

UP1

UP2

UP3


Signal Description

IP1 Current input for phase A

IP2 Current input for phase B

IP3 Current input for phase C





Signal Description








OC1_Trip 1st stage OC trip

OC2_Trip 2nd

stage OC trip

OC Inv Trip Time-inverse overcurrent trip



132

1.4.1 Setting list

Table 43 Overcurrent protection function setting list

Setting Unit Min.

(Ir:5A/1A)

Max.

(Ir:5A/1A)

Default setting

(Ir:5A/1A) Description

I_OC1 A 0.08Ir 20Ir 2Ir current threshold of

overcurrent stage 1

T_OC1 s 0 60 0.1 delay time of

overcurrent stage 1

I_OC2 A 0.08Ir 20Ir 1Ir current threshold of

overcurrent stage 2

T_OC2 s 0 60 0.3 delay time of

overcurrent stage 2

Curve_OC

Inv 1 12 1

No.of inverse time

characteristic curve

of overcurrent

I_OC Inv A 0.08Ir 20Ir 1Ir

start current of

inverse time

overcurrent

K_OC Inv 0.05 999 1

time multiplier of

customized inverse

time characteristic

curve for

overcurrent

A_OC Inv s 0 200 0.14

time constant A of

customized inverse

time characteristic

curve for

overcurrent

B_OC Inv s 0 60 0

time constant B of

customized inverse

time characteristic

curve for

overcurrent

P_OC Inv 0 10 0.02

index of customized

inverse time

characteristic curve

for overcurrent

Angle_OC Degre

e 0 90 60

the angle of

bisector of

operation area of

overcurrent


133

Setting Unit Min.

(Ir:5A/1A)

Max.

(Ir:5A/1A)

Default setting


directional element

Imax_2H_Un

Blk A 0.25 20Ir 5Ir

the maximum

current to release

harmornic block

Ratio_I2/I1 0.07 0.5 0.2

ratio of 2rd

harmonic to

fundamental

component

T2h_Cross_B

lk s 0 60 1

delay time of cross

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


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 Technical data


134


Table 46 Overcurrent protection technical data


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


IEC standard Normal inverse;

Very inverse;

Extremely inverse;

Long inverse

≤ ±5% setting + 40ms, at 2

<I/ISETTING < 20, in accordance

with IEC60255-151

ANSI Inverse;

Short inverse;

Long inverse;

Moderately inverse;

Very inverse;

Extremely inverse;

Definite inverse


<I/ISETTING < 20, in

accordance with ANSI/IEEE

C37.112,

user-defined characteristic

T=



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 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

Operating area range 170° ≤ ±3°, at phase to phase voltage >1V Characteristic angle 0° to 90°, step 1°


135

Table 47 Inrush restraint function

Item Range or value Tolerance

Upper function limit

Max current for inrush

restraint

0.25 Ir to 20.00 Ir ≤ ±3% setting value or

±0.02Ir

Ratio of 2nd

harmonic current

to fundamental component

current

0.10 to 0.45, step 0.01

Cross-block (IL1, IL2, IL3)

(settable time)

0.00s to 60.00 s, step 0.01s ≤ ±1% setting or +40ms


136

Chapter 8 Earth fault protection

137


About this chapter


signals, parameter, IED report and technical data used for earth

fault portection.


138

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

Individually selectable inrush blocking for each stage

Inrush blocking using 2nd harmonic measured phase current


VT fail monitoring for directional earth fault protection


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

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.

_

_ _ _

_

P EF Inv

A EF InvT B EF Inv K EF INV

i

I 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

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

Inrush BLK 3I0A

N

D

Max(Ia1,Ib1,Ic1) < Imax_2H_UnBlk

Max(Ia2/Ia1, Ib2/Ib1,

Ic2/Ic1)>Ratio_I2/I1

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

Forward

Angle_EF

Bisector

0_Ref3U

0°

-3I 0

3I 090°

Angle_Range

EF

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

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.

Forward

Angle_Neg

I3 2

I-3 2

3 RefU 2_

0°

90°

Bisector

Angle_Range

Neg

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

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）

Forward direction（by

negative sequence direction

element）

3U0<1VO

RForwardA

N

D

EF U2/I2 Dir on

Figure 52 Logic for directiion determination

―0‖

―1‖

EF1 Direction off

EF1 Direction on

EF1 Inrush Block off

EF1 Inrush Block on

EF1 Trip

A

N

D

3I0 > 3I0_EF1

T_EF1

Func_EF1 on

Inrush BLK 3I0

Forward

Figure 53 Tripping logic of the first stage of definite earth fault protection

―0‖

―1‖

EF2 Direction off

EF2 Direction on

EF2 Inrush Block off

EF2 Inrush Block on

A

N

D

3I0 > 3I0_EF2

Inrush BLK 3I0

ForwardEF2 TripT_EF2

Func_EF2 on


145

Figure 54 Tripping logic of the second stage of definite earth fault protection

―0‖

―1‖

EF Inv Direction off

EF Inv Direction on

EF Inv Inrush Block off

EF Inv Inrush Block on

EF_INV Trip

A

N

D

3I0 > 3I0_INV

Func_EF Inv on

Inrush BLK 3I0

Forward

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.


IP1

IP2

IP3

UP1

UP2

UP3

EF1_Trip

EF2_Trip

EF Inv_Trip

Relay Startup

Relay Trip

Trip PhA

Trip PhB

Trip PhC

Trip 3Ph

Relay Block AR

IN


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


146

Signal Description

UP3 Phase-C voltage input


Signal Description








EF1_Trip 1st stage EF Trip

EF2_Trip 2nd

stage EF Trip

EF Inv_Trip Inverse time stage EF Trip


1.4.1 Setting lists

Table 50 EF protection function setting list

Setting Unit

Min.

(Ir:5A/1A

)

Max.

(Ir:5A/

1A)

Default

setting

(Ir:5A/1

A)

Description

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

3I0_EF2 A 0.08Ir 20Ir 0.2Ir



protection stage 2

T_EF2 s 0 60 0.3 delay time of earth fault

protection stage 2


147

Setting Unit

Min.

(Ir:5A/1A

)

Max.

(Ir:5A/

1A)

Default

setting

(Ir:5A/1

A)

Description

Curve_EF Inv 1 12 1

No. of inverse time

characteristic curve of earth

fault protection

3I0_EF Inv A 0.08Ir 20Ir 0.2Ir start current of inverse time


K_EF Inv 0.05 999 1

time multiplier of customized

inverse time characteristic

curve for earth fault

protection

A_EF Inv s 0 200 0.14

time constant A of

customized inverse time

characteristic curve for earth

fault protection

B_EF Inv s 0 60 0

time constant B of


characteristic curve for earth

fault protection

P_EF Inv 0 10 0.02

index of customized inverse

time characteristic curve for

earht fault protection

Angle_EF Degree 0 90 70

the angle of bisector of

operation area of zero

sequnce directional element

Angle_Neg Degree 50 90 70


operation area of negative

sequnce directional element

Table 51 EF protection binary setting list


Func_EF1

Operation for the first

definite stage of the


1 0 1

EF1 Direction

Directional mode for

the first definite stage

of the earth fault

protection

1 0 1

EF1 Inrush Block Inrush restraint mode 1 0 1


148


for the first definite

stage of the earth fault

protection

Func_EF2

Operation for the

second definite stage

of the earth fault

protection

1 0 1

EF2 Direction


the first definite stage

of the earth fault

protection

1 0 1

EF2 Inrush Block

Inrush restraint mode

for the second definite


protection

1 0 1

Func_EF Inv

Operation for the

time-inverse stage of

the earth fault

protection

1 0 1

EF Inv Direction


the time-inverse stage

of the earth fault

protection

0 0 1

EF Inv Inrush Block

Inrush restraint mode

for the time-inverse


protection

0 0 1

EF U2/I2 Dir

Negative-sequence

direction detection

element for earth fault

protection

0 0 1

EF1 Init AR

Auto-reclosure

initiated by the first



0 0 1

EF2 Init AR

Auto-reclosure

initiated by the first



0 0 1


149

1.4.2 Setting calculation example

21/21N

127km 139km

PTR:400/0.1kV

CTR:2000/5

A BC

21/21N

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 0.32A

Curve_EF Inv 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

1.5 Reports


150



EF1 Trip 1st stage EF Trip

EF2 Trip 2nd

stage EF Trip

EF Inv Trip Inverse time stage EF Trip



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


Table 54 Earth fault protection (ANSI 50N, 51N, 67N)

Item Rang or value Tolerance

Definite time characteristic


Time delay 0.00 to 60.00s, step 0.01s

≤ ±1% setting or +40ms, at 200% operating setting




Very inverse;

Extremely inverse;

Long inverse

IEC60255-151


<I/ISETTING < 20

ANSI Inverse;

Short inverse;

Long inverse;

Moderately inverse;

ANSI/IEEE C37.112,


<I/ISETTING < 20


151

Very inverse;

Extremely inverse;

Definite inverse

user-defined characteristic

T=

IEC60255-151


<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




Directional element

Operating area range of zero

sequence directional element 160°

≤ ±3°, at 3U0≥1V

Characteristic angle 0° to 90°, step 1°

Operating area range of

negative sequence directional

element

160°

≤ ±3°, at 3U2≥2V

Characteristic angle 50° to 90°, step 1°


152

Chapter 9 Emergency/backup overcurrent and earth fault protection

153

Chapter 9 Emergency/backup

overcurrent and earth fault

protection

About this chapter


signals, parameter, IED report and technical data included in

emergency/backup overcurrent and earth fault protection.


154

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



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

Time-inverse characteristic is set according to the following equation:

_ /

_ / _ / _ /

_ /

P EM BU OC Inv

A EM BU OC InvT B EM BU OC Inv K 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


from the measured current. Once the calculated time elapsed, repoprt

―Em/Bu OC Trip‖ will be issued.


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 2nd 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

1.2.3 Logic diagram

Em/BU OC Inrush Block Off

Em/BU OC Inrush Block Off

Func_Em/BU OC

Func_BU OC on

Em/BU OC Inrush Block On

Em/BU OC Inrush Block On

Ia>I_Em/BU OC

VT fail

Ia<Imax_2H_UnBlk

Ia2/Ia1>Ratio_I2/I1

A

N

D

A

N

D

T_Em/BU OC

Cross blocking

Ia2/Ia1 >

Ib2/Ib1 >

Ic2/Ic1 >

T2h_Cross_Blk

Trip

Cross blocking

O

R

O

R

A

N

D

MaxIa, Ib,

Ic<Imax_2H_UnBlk

Figure 58 Emergency/backup protection function logic diagram



157

IP1

IP2

IP3

Trip PhA

Trip PhB

Trip PhC

Trip 3Ph

Relay Block AR

Relay Startup

Relay Trip

Em/BU OC1_Trip

Em/BU OCInv_Trip

UP1

UP2

UP3


Signal Description








Signal Description








Em/BU OC1_Trip 1st stage emergency OC trip

Em/BU OCInv_Trip Time-inverse emergency OC trip


1.4.1 Setting lists


158

Table 57 Funciton setting list for emergency/backup overcurrent protection

Setting Unit

Min.

(Ir:5A/

1A)

Max.

(Ir:5

A/1A

)

Default

setting

(Ir:5A/1A)

Description

I_Em/BU OC A 0.08Ir 20Ir 1Ir


emergency/backup overcurrent

stage 1

T_Em/BU OC s 0 60 0.3 delay time of emergency/backup

overcurrent stage 1

Curve_Em/BU OC

Inv 1 12 1

No.of inverse time characteristic

curve of emergency/backup

overcurrent

I_Inv_Em/BU OC A 0.08Ir 20Ir 1Ir start current of inverse time


K_Em/BU OC Inv 0.05 999 1


inverse time characteristic curve

for emergency/backup overcurrent

A_Em/BU OC Inv s 0 200 0.14

time constant A of customized



B_Em/BU OC Inv s 0 60 0

time constant B of customized



P_Em/BU OC Inv 0 10 0.02

index of customized inverse time

characteristic curve for


Imax_2H_UnBlk A 0.25 20Ir 5Ir the maximum current to release

harmornic block

Ratio_I2/I1 0.07 0.5 0.2 ratio of 2rd harmonic to

fundamental component

T2h_Cross_Blk s 0 60 1 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

Name Description

Func_Em/BU OC Inv Inverse time stage of emergency overcurrent protection enabled

or disabled

Em/BU OC Inv Inrush

Block

Inrush restraint of emergency/backup overcurrent protection for

inverse stage enabled or disabled

1.5 Reports



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


Table 60 T Emergency/backup overcurrent protection technical data


Definite time characteristics


Time delay 0.00 to 60.00s, step 0.01s ≤ ±1% setting or +40ms, at 200% operating setting




Very inverse;

Extremely inverse;

Long inverse



with IEC60255-151

ANSI Inverse;

Short inverse;

Long inverse;

Moderately inverse;

Very inverse;




C37.112,


160

Extremely inverse;

Definite inverse

User-defined characteristic

T=



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 0.005

Set time Multiplier for step

n: k

0.05 to 999.0, step 0.01





161

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


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


2.2.1 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

Time-inverse characteristic is set according to the following equation:

_ /

_ / _ / _ /

_ /

P EM BU EF Inv

A EM BU EF InvT B EM BU EF Inv K 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


from the measured current. Once the calculated time elapsed, repoprt

―Em/Bu EF Trip‖ will be issued.


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

2.2.3 Logic diagram

Em/BU EF Inrush Block Off

Func_Em/BU EF on

Func_BU EF on

Em/BU EF Inrush Block On

A

N

D

VT fail

3I0>3I0_Em/BU EF

T_Em/BU EFTrip

<Imax_2H_UnBlk

Ratio_I2/I1>

A

N

D

Figure 59 Emergency/backup earth fault protection logic diagram


IP1

IP2

IP3

Trip PhA

Trip PhB

Trip PhC

Trip 3Ph

Relay Block AR

Relay Startup

Relay Trip

Em/Bu EF Trip

Em/Bu EFInv Trip

UP1

UP2

UP3

IN


Signal Description









164


Signal Description








Em/Bu EF Trip Emergency/Backup Earth Fault Trip

Em/BU EFInv_Trip Emergency/Backup Earth Fault inverse time

Trip


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

(Ir:5A/1A)

Description

3I0_Em/BU EF A 0.08Ir 20Ir 0.2Ir



protection stage 1

T_Em/BU EF s 0 60 0.3 delay time of earth fault

protection stage 1

Curve_Em/BU

EF Inv 1 12 1

No. of inverse time

characteristic curve of

emergency/backup earth

fault protection

3I0_Inv_Em/BU


start current of inverse time


fault protection

K_Em/BU EF Inv 0.05 999 1


inverse time characteristic

curve for emergency/backup



165

Setting Un

it

Min.

(Ir:5A/1

A)

Max.

(Ir:5A/1A)

Default

setting

(Ir:5A/1A)

Description

A_Em/BU EF Inv s 0 200 0.14

time constant A of




fault protection

B_Em/BU EF Inv s 0 60 0

time constant B of




fault protection

P_Em/BU EF Inv 0 10 0.02

index of customized inverse

time characteristic curve for

emergency/backup earht

fault protection

Imax_2H_UnBlk A 0.25 20Ir 5Ir the maximum current to

release harmornic block

Ratio_I2/I1 0.07 0.5 0.2 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 Inrush restraint of emergency earth fault protection enabled or

disabled

Func_Em/BU EF Inv Inverse time stage of emergency earth fault protection enabled or

disabled

Em/BU EF Inv Inrush

Block

Inrush restraint of emergency earth fault protection inverse stage

enabled or disabled

2.5 IED report


166



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


Table 66 Technical data for emergency/backup earth fault protection

Item Rang or value Tolerance

Definite time characteristic


Time delay 0.00 to 60.00s, step 0.01s

≤ ±1% setting or +40ms, at 200% operating setting




Very inverse;

Extremely inverse;

Long inverse



with IEC60255-151

ANSI Inverse;

Short inverse;

Long inverse;

Moderately inverse;

Very inverse;

Extremely inverse;

Definite inverse




C37.112,

User-defined characteristic

T=



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

0.005

Set time Multiplier for step n: k 0.05 to 999.0, step 0.01





168

Chapter 10 Switch-onto-fault protection

169

Chapter 10 Switch-Onto-Fault

protection

About this chapter


signals, parameter, IED report and technical data included in

Switch-Onto-Fault protection function.


170

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

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.

1.2.2 Logic diagram

10s

T_Relay Reset

T_OC_SOTF

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

A

N

D

Relay startup

Impedance within

zone1,2,3

Over current

operationO

R

Zero-sequence

operationT_EF_SOTF

A

N

D

SOTF Inrush Block Off

SOTF Inrush Block OnCross blocking

No fault

A

N

D

A

N

D

Trip

Relay reset

Relay Startup

Figure 60 SOTF protection logic



172

IP1

IP2

IP3

PhA CB Open

PhB CB Open

PhC CB Open

SOTF Trip

UP1

UP2

UP3

Relay Block AR

Relay Trip

Relay Startup

IN

MC/AR Block


Signal Description









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


Signal Description



173

Signal Description



SOTF Trip SOTF Trip


1.4.1 Setting lists

Table 70 SOTF protection function setting list

Setting Uni

t

Min.

(Ir:5A/1A)

Max.

(Ir:5A/1A)

Default

setting

(Ir:5A/1A)

Description

I_SOTF A 0.08Ir 20Ir 2Ir

phase current threshold of

overcurrent element of

switch onto fault protection

T_OC_SOT

F s 0 60 0

delay time of overcurrent

element of switch onto fault

protection

3I0_SOTF A 0.08Ir 20Ir 0.5Ir

zero sequnce current

threshold of switch onto fault

protection

T_EF_SOTF s 0 60 0.1

delay time of zero sequce

overcurrent of switch onto

fault protection

Table 71 SOTF protection binary setting list


Func_SOTF SOTF protection


SOTF Inrush Block SOTF protection

blocked by inrush 1 0 1


174

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

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

1.5 Reports



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



Func_SOTF On SOTF function on

Func_SOTF Off SOTF function off

1.6 Technical data


Table 74 Switch-onto-fault protection technical data


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

overcurrent

0.00s to 60.00s, step 0.01s ≤ ±1% setting or +40ms, at

200% operating setting

Time delay of zero sequence

current

0.00s to 60.00s, step 0.01s ≤ ±1% setting or +40ms, at



176

Chapter 11 Overload protection

177


About this chapter



overload protection function.


178

1 Overload protection



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.

1.1.2 Logic diagram

Func_OL on

Ia>I_OL Alarm

O

RIb>I_OL Alarm

Ic>I_OL Alarm

T_OL Alarm

A

N

DTrip

Figure 61 Logic diagram for overload protection


IP1

IP2

IP3


Signal Description



179

Signal Description




1.3.1 Setting lists

Table 76 Function setting list for overload protection

Setting Uni

t

Min.

(Ir:5A/1A

)

Max.

(Ir:5A/1A)

Default

setting

(Ir:5A/1

A)

Description

I_OL Alarm A 0.08Ir 20Ir 2Ir current threshold of overload

alarm

T_OL

Alarm s 0.1 6000 20 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


Overload Alarm Overload protection alarm


180

Chapter 12 Overvoltage protection

181


About this chapter



overvoltage protection.


182

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


1.2.1 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

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

OV PE on

OV PE off

OV Trip on

OV Trip off

Ua>U_OV1

Ub>U_OV1 O

RUc>U_OV1

Uab>U_OV1

Ubc>U_OV1 O

RUca>U_OV1

O

RT_OV

Trip

Alarm

Figure 62 Logic diagram for overvoltage protection



184

UP1

UP2

UP3

Trip PhA

Trip PhB

Trip PhC

Trip 3Ph

Relay Block AR

Relay Startup

Relay Trip

OV1 Alarm

OV2 Alarm

OV1_Trip

OV2_Trip


Signal Description





Signal Description








OV1 Alarm 1st

stage OV alarm

OV2 Alarm 2nd

stage OV alarm

OV1_Trip 1st

stage OV trip

OV2_Trip 2nd

stage OV trip



185

1.4.1 Setting lists

Table 81 Function setting list for overvoltage protection

Parameter Range Default Unit Description

U_OV1 40~200 65 V Voltage setting for overvoltage protection

stage 1

T_OV1 0~60 0.3 s Time setting for overvoltage protection

stage 1

U_OV2 40~200 63 V Voltage setting for overvoltage protection

stage 2

T_OV2 0~60 0.6 s Time setting for overvoltage protection

stage 2

Dropout_OV 0.9~0.99 0.95 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



OV1 Trip Overvoltage stage 1 trip

OV2 Trip Overvoltage stage 2 trip


186



OV1 Alarm Overvoltage stage 1 alarm

OV2 Alarm Overvoltage stage 2 alarm

1.6 Technical data

Table 85 Technical data for overvoltage protection


Voltage connection Phase-to-phase voltages or

phase-to-earth voltages

≤ ±3 % setting or ±1 V

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


Reset time <40ms

Chapter 13 Undervoltage protection

187


About this chapter



undervoltage protection function.


188

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


1.2.1 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

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

Protection

IED

A

B

C

N

A

B

C

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

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

UV Chk All Phase off

UV Chk All Phase on

UV PE on

UV Chk All Phase on

UV Chk All Phase off

UV PE off

UV Chk CB off

UV Chk CB on

UV Chk Current on

UV Chk Current off

Func_UV

UV Trip on

UV Trip off

Ua<U_UV

Ub<U_UV

Uc<U_UV

O

R

Ua<U_UV

Ub<U_UV

Uc<U_UV

A

N

D

O

R

Uab<U_UV

Ubc<U_UV

Uca<U_UV

O

R

Uab<U_UV

Ubc<U_UV

Uca<U_UV

A

N

D

O

R

O

R

O

R

O

R

BI_PhA CB Open

IA(IB,IC)>I_UV_

Chk

VT fail

VT Fail on

A

N

D

T_UV

Trip

Alarm

BI_PhB CB Open

BI_PhC CB Open

O

R

BI_AR In Progress 1

Figure 64 Logic diagram for undervoltage protection



192

UP1

UP2

UP3

Trip PhA

Trip PhB

Trip PhC

Trip 3Ph

Relay Block AR

Relay Startup

Relay Trip

UV1 Alarm

UV2 Alarm

UV1_Trip

UV2_Trip

IP1

IP2

IP3

PhA CB Open

PhB CB Open

PhC CB Open

AR In Progress


Signal Description








Signal Description




AR In Progress AR In Progress


Signal Description





193

Signal Description





UV1 Alarm 1st

stage UV alarm

UV2 Alarm 2nd

stage UV alarm

UV1_Trip 1st

stage UV trip

UV2_Trip 2nd

stage UV trip


1.4.1 Setting lists

Table 89 Undervoltage protection function setting list

Setting Uni

t

Min.

(Ir:5A/1A

)

Max.

(Ir:5A/1A)

Default

setting

(Ir:5A/1A)

Description

U_UV1 V 5 150 40 voltage threshold of undervoltage

stage 1

T_UV1 s 0 60 0.3 delay time of undervoltage stage 1

U_UV2 V 5 150 45 voltage threshold of undervoltage

stage 2

T_UV2 s 0 60 0.6 delay time of undervoltage stage 2

Dropout_U

V 1.01 2 1.05 reset ratio of undervoltage

I_UV_Chk A 0.08Ir 2Ir 0.1Ir current threshold of undervoltage

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

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



UV1 Trip Undervoltage stage 1 trip

UV2 Trip Undervoltage stage 2 trip



UV1 Alarm Undervoltage stage 1 alarm

UV2 Alarm Undervoltage stage 2 alarm

1.6 Technical data

Table 93 Technical data for undervoltage protection


Voltage connection Phase-to-phase voltages or

phase-to-earth voltages

≤ ±3 % setting or ±1 V

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


Current criteria 0.08 to 2.00 Ir ≤ ±3% setting or ±0.02Ir


195

Reset time ≤ 50 ms


196

Chapter 14 Circuit breaker failure protection

197

Chapter 14 Circuit breaker failure

protection

About this chapter


signals, parameter, IED report and technical data used for circuit

breaker failure protection function.


198

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.

Bus

IFAULT

Trip

Line2 Line3 LineN

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

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

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

CBF Chk 3I0/3I2 Off

CBF Chk 3I0/3I2 on

CBF Chk 3I0/3I2 Off

CBF Chk 3I0/3I2 on

CBF Chk 3I0/3I2 Off

CBF Chk 3I0/3I2 on

Ia > I_CBF

3I0 > 3I0_CBF

3I2 > 3I2_CBF

Ib > I_CBF

Ic > I_CBF

O

R

Ib > I_CBF

3I0 > 3I0_CBF

3I2 > 3I2_CBF

Ic > I_CBF

Ia > I_CBF

O

R

A

N

D

A

N

D

Ic > I_CBF

3I0 > 3I0_CBF

3I2 > 3I2_CBF

Ib > I_CBF

Ia > I_CBF

O

R

A

N

D

O

R

O

R

O

R

CBF Curr. Crit. A

CBF Curr. Crit. B

CBF Curr. Crit. C

O

R CBF Curr. Crit. 3P


201

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

BI_PhA CB Open

BI_PhA Init CBF

CBF Curr. Crit. A O

R

A

N

D

A

N

D

O

R

A

N

D

A

N

D

BI_PhB CB Open

BI_PhB Init CBF

CBF Curr. Crit. B

A

N

DA

N

DO

R

BI_PhC CB Open

BI_PhC Init CBF

CBF Curr. Crit. C

BI_PhA CB Open

BI_PhB CB Open

BI_PhC CB Open

3Ph Init CBF

CBF Curr. Crit. 3P

A

N

D

CB A is closed

CB B is closed

CB C is closed

A

N

D

A

N

DO

R

CB ≥1P is closed

Figure 67 Circuit breaker auxiliary contact evaluation

1.2.3 Logic diagram


203

BI_PhA Init CBF

BI_PhB Init CBF

BI_PhC Init CBF

BI_3Ph Init CBF

O

RT_alam Init CBF Err

BI_PhA Init CBF

Inter PhA Init CBF

BI_PhB Init CBF

Inter PhB Init CBF

BI_PhC Init CBF

Inter PhC Init CBF

A

N

D

A

N

D

A

N

D

O

R

O

R

O

R

A

N

D

A

N

D

A

N

DA

N

D

O

R

BI_3Ph Init CBF

Inter 3Ph Init CBF

PhA Init CBF

PhB Init CBF

PhC Init CBF

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

CBF Chk CB Status

CBF Chk CB Status

CBF Chk CB Status

CBF Chk CB Status

CB A is closed

CBF Curr. Crit. A

PhA Init CBF

CB B is closed

CBF Curr. Crit. B

PhB Init CBF

CB C is closed

CBF Curr. Crit. C

PhC Init CBF

A

N

D

A

N

D

A

N

D

A

N

D

O

R

O

R

O

R

CB ≥1P is closed

CBF Curr. Crit. 3P

3Ph Init CBF

O

R

CBF A Startup

CBF B Startup

CBF C Startup

CBF 3P Startup

Figure 69 CBF protection startup logic


205

T_CBF1CBF A Startup

T_CBF1CBF B Startup

T_CBF1CBF C Startup

O

R

O

R

O

R

CBF1 Trip PhA

CBF1 Trip PhB

CBF1 Trip PhCA

N

D

O

R

A

N

D

CBF1 Trip 3Ph

T_CBF1CBF 3P Startup

A

N

D

Figure 70 First stage CBF tripping logic

CBF 1P Trip 3P On

T_CBF 1P Trip 3PO

R

CBF A Startup

CBF B Startup

CBF C Startup

CBF1 Trip 3Ph

O

R

O

R

CBF 1P Trip 3P On

T_CBF 1P Trip 3PO

R

CBF 1P Trip 3P On

T_CBF 1P Trip 3P

CBF1 1P Trip 3P

Figure 71 Three-phase local CB re-tripping from single phase CBF initiation

T_CBF2CBF A Startup

T_CBF2CBF B Startup

T_CBF2CBF C Startup

CBF2 Trip O

R

T_CBF2CBF 3P Startup


206

Figure 72 Second stage CBF tripping logic


IP1

CBF1_Trip

IP2

IP3

PhA Init CBF

PhB Init CBF

PhC Init CBF CBF 1P Trip 3P

3Ph Init CBF CBF2 Trip

PhA CB Open

PhB CB Open

PhC CB Open

Trip PhA

Trip PhB

Trip PhC

Trip 3Ph

Relay Block AR

Relay Startup

Relay Trip

IN


Signal Description

IP1 signal for current input 1





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





207


Signal Description








CBF1 Trip 1st stage CBF operation

CBF 1P Trip 3P Three phase re-tripping for single phase CBF

CBF2 Trip 2nd

stage CBF operation


1.4.1 Setting lists

Table 97 CBF protection function setting list

Setting

U

ni

t

Min.

(Ir:5A

/1A)

Max.

(Ir:5A/1A)

Default

setting

(Ir:5A/1A

)

Description

I_CBF A 0.08Ir 20Ir 1Ir phase current threshold of circuit breaker

failure protection

3I0_CBF A 0.08Ir 20Ir 0.2Ir zero sequence current threshold of

circuit breaker failure protection

3I2_CBF A 0.08Ir 20Ir 0.2Ir negative sequence current threshold of


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

T_CBF 1P

Trip 3P s 0.05 32 0.1

delay time of three phase tripping of CBF

stage 1

Table 98 CBF protection binary setting list



208


Func_CBF CBF protection


CBF 1P Trip 3P

Three pole tripping in

the case of single

pole failure

0 0 1

CBF Chk 3I0/3I2

zero and negative

sequence current

checking by CBF

protection

1 0 1

CBF Chk CB Status

CB Auxiliary contact

checking for CBF

protection

0 0 1

1.5 Reports



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



BI_Init CBF Err CBF initiation BI error



Func_CBF On CBF function on

Func_CBF Off CBF function off


209

1.6 Technical data


Table 102 Breaker failure protection technical data


phase current

Negative sequence current


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

200% operating setting Time delay of stage 2 0.00s to 32.00 s, step 0.01s

Reset time of stage 1 < 20ms


210

Chapter 15 Dead zone protection

211


About this chapter


signals, parameter, IED report and technical data used for dead

zone (short zone) protection function.


212

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.


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.

Bus

IFAULT

Trip

Line1 Line2 LineN

Opened CB

Closed CB

Legend:

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

Bus

IFAULT

Relay

Inter trip

Line1 Line2 LineN

Trip

Opened CB

Closed CB

Legend:

Figure 74 Dead zone tripping concept for feeders with line side CTs


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 Logic diagram


214

Func_Dead Zone On

PhA Init CBF

PhB Init CBF

PhC Init CBF

3Ph Init CBF

CBF Curr. Crit. A

CBF Curr. Crit. B

CBF Curr. Crit. C

BI_PhA CB Open

BI_PhB CB Open

BI_PhC CB Open

O

R

O

R

A

N

D

A

N

D

T_Dead Zone Dead Zone Trip

Figure 75 Dead zone protection logic


IP1

DeadZone_TripIP2

IP3

PhA Init CBF

PhB Init CBF

PhC Init CBF

3Ph Init CBF

PhA CB Open

PhB CB Open

PhC CB Open

Relay Block AR

Relay Startup

Relay Trip


Signal Description





215


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





Signal Description



DeadZone_Trip DeadZone Trip



1.4.1 Setting lists

Table 106 Dead zone protection function setting list


T_Dead Zone Time delay setting for

dead zone protection 1 s 0 32

Table 107 Dead zone protection binary setting list


Func_Dead Zone Dead Zone protection



216

1.5 Reports



Dead Zone Trip Dead zone trip



Func_DZ On DZ function on

Func_DZ Off DZ function off

1.6 Technical data




Time delay 0.00s to 32.00s, step 0.01s ≤ ±1% setting or +40 ms, at


Chapter 16 STUB protection

217


About this chapter


signals, parameter, IED report and technical data used for STUB



218

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.



Stub fault

CB1

CB3

CB2

CT1

CT3

CT2

Disconnector1

Disconnector2

Feeder1

Feeder2

Busbar A

Busbar B


219

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

Func_STUB

Ia>I_STUB

T_STUB

BI_STUB Enable

A

N

D

Permanent

trip

Ib>I_STUB

Ic>I_STUB

O

R

Figure 77 Logic diagram for STUB protection


IP1

STUB TripIP2

IP3

Relay Block AR

Relay Startup

Relay TripSTUB Enable


220


Signal Description





Signal Description

STUB Enable STUB protection enabled


Signal Description



STUB Trip STUB Trip



1.4.1 Setting lists

Table 113 Setting value list for STUB protection

Setting Unit

Min.

(Ir:5A/1

A)

Max.

(Ir:5A/1A)

Default

setting

(Ir:5A/1A)

Description

I_STUB A 0.08Ir 20Ir 1Ir current threshold of STUB

protection

T_STUB s 0 60 1 delay time of STUB protection


221

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



STUB Trip STUB protection trip

1.6 Technical data


Table 116 Technical data for STUB protection






222

Chapter 17 Poles discordance protection

223

Chapter 17 Poles discordance

protection

About this chapter


signals, parameter, IED report and technical data for poles

discordance protection.


224

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.



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

poles, all three poles must be closed even if the breaker auxiliary contacts

indicate a different status.

1.2.2 Logic diagram

5s

Func_PD On

PD Chk 3I0/3I2 on

BI_PhA CB Open A

N

DIa > 0.06Ir

BI_PhB CB Open A

N

DIb > 0.06Ir

BI_PhC CB Open A

N

DIc > 0.06Ir

BI_PhA CB Open

A

N

D

BI_PhB CB Open

BI_PhC CB Open

BI_PhA CB Open A

N

DIa < 0.06Ir

BI_PhB CB Open A

N

DIb < 0.06Ir

BI_PhC CB Open A

N

DIc< 0.06Ir

O

R

3I2 > 3I2_PD

3I0 > 3I0_PD

PD Chk 3I0/3I2 off

O

R

O

R

A

N

D

CB Err Blk PD

A

N

D

PD TripT_PD

BI_AR In Progress 1

Figure 78 Logic diagram for poles discordance protection



226

IP1

IP2

IP3

PhA CB Open

PhB CB Open

PhC CB Open

Trip 3Ph

Relay Block AR

PD_Trip

Relay Startup

Relay Trip

AR In Progress

IN


Signal Description






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


Signal Description



PD_Trip PD Trip


CB Err Blk PD Pole discordance blocked by CB error

PD Trip Fail Pole discordance trip fail


227


1.4.1 Setting lists

Table 120 Function setting list for poles discordance protection

Setting Unit

Min.

(Ir:5A/1

A)

Max.

(Ir:5A/1A)

Default setting


3I0_PD A 0 20Ir 0.4Ir


threshold of pole discordance

protection

3I2_PD A 0 20Ir 0.4Ir

negative sequence current

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



PD Startup Poles discordance protection startup

PD Trip Poles discordance protection trip


228



CB Err Blk PD Circuit breaker error block poles discordance protection

PD Trip Fail Poles discordance protection trip fail

1.6 Technical data


Table 124 Technical data for poles discordance protection





Chapter 18 Synchro-check and energizing check function

229

Chapter 18 Synchro-check and

energizing check function

About this chapter


signals, parameter, IED report and technical data used in

synchro-check and energizing check function.


230

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:

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.


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

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:

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‖

1.2.2 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

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

AR_EnergChkDLLB

on

VT_Line off

T_MaxSynExt

Ua(Ub,Uc) >Umin_Syn

Ux>Umin_Syn

Anglediff<Angle_Syn Diff

Freqdiff<Freq_Syn Diff

Udiff<U_Syn Diff

A

N

DA

N

D

T_Syn Check

Synchr-check or

energizing check

meet

Synchr-check or

energizing check

fail

A

N

D

Ux <Umax_Energ

Ua(Ub,Uc)

>Umin_Syn

VT_Line off

A

N

D

Ux>Umin_Syn

Ua(Ub,Uc)

<Umax_Energ

A

N

D

Ux<Umax_Energ

Ua(Ub,Uc)

<Umax_Energ

VT_Line on

A

N

D

Ux >Umin_Syn

Ua(Ub,Uc)

<Umax_Energ

VT_Line on

A

N

D

Ux<Umax_Energ

Ua(Ub,Uc)

>Umin_Syn

O

R

O

R

AR_Syn Check on

AR_Syn Check off

O

R

AR_EnergChkDLLB off

O

R

AR_EnergChkDLLB

on

AR_EnergChkLLDB

off

O

R

AR_EnergChkDLDB

off

O

R

O

R

AR_EnergChkDLDB

on

AR_EnergChkDLLB

off

AR_EnergChkDLLB

on

O

R

AR_EnergChkLLDB

off

AR_EnergChkLLDB

on

Figure 79 Logic diagram for synchro-check functio



234

UP1

UP2

UP3

UPX


Signal Description




UPX Reference voltage input


1.4.1 Setting lists

Table 126 Synchro-check function setting list

Setting Unit

Min.

(Ir:5A

/1A)

Max.

(Ir:5A/1

A)

Default

setting

(Ir:5A/1A)

Description

Angle_Syn

Diff Degree 1 80 30

angle difference threshold of

synchronizing

U_Syn Diff V 1 40 10 voltage difference threshold of

synchronizing

Freq_Syn

Diff Hz 0.02 2 0.05

frequency difference threshold of

synchronizing

T_Syn

Check s 0 60 0.05 delay time of synchronizing

T_MaxSynE

xt 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 Maximum voltage of unenergizing

checking


235

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) ―Angle_Syn Diff‖：Maximum allowable phase difference between bus

voltage and line angle under synchronization check mode.

2) ―U_Syn Diff‖：Maximum allowable phase difference between bus voltage

and line voltage under synchronization check mode.

3) ―Freq_Syn Diff‖：Maximum allowable frequency difference between bus

voltage and line frequency under synchronization check mode.

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.

8) 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‖.

1.5 Reports


236



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



SYN Voltage Err Voltage abnormity for synchronization check

1.6 Technical data


Table 130 Synchro-check and voltage check technical data


Operating mode Synchronization check:

Synch-check

Energizing check, and synch-check if energizing check failure

Override

Energizing check:

Dead V4 and dead V3Ph

Dead V4 and live V3Ph

Live V4 and dead V3Ph

Voltage threshold of dead line

or bus

10 to 50 V (phase to earth),

step 1 V

≤ ± 3 % setting or 1 V


237

Voltage threshold of live line

or bus

30 to 65 V (phase to earth),

step 1 V

≤ ± 3 % setting or 1 V

∆V-measurement Voltage

difference

1 to 40 V (phase-to-earth),

steps 1 V

≤ ± 1V

Δf-measurement (f2>f1;

f2<f1)

0.02 to 2.00 Hz, step, 0.01

Hz,

≤ ± 20 mHz

Δα-measurement (α2>α1;

α2<α1)

1 ° to 80 °, step, 1 ° ≤ ± 3°

Minimum measuring time 0.05 to 60.00 s, step,0.01 s, ≤ ± 1.5 % setting value or +60

ms

Maximum synch-check

extension time

0.05 to 60.00 s, step,0.01 s, ≤ ± 1 % setting value or +50

ms


238

Chapter 19 Auto-reclosing function

239


About this chapter



Auto-reclosing function.


240

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:

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


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

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

Trip Command

CB Open PosItion

AR Initiate

Closing Command

T_Reclaim

T_Action

Fault

Synchro-check or

voltage check OK

T_Reset

T_3P AR1

T_Action

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

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

Trip Command

CB Open PosItion

AR Initiate

Closing Command

T_Reclaim

T_Action

Fault

Synchro-check or

voltage check OK

T_Reset

T_3P AR1

T_Action

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

“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:

Differential protection

Distance Z1


246

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

Protection

IEDProtection

IED with AR

BO-Trip PhA

BO-Trip PhB

BO-Trip PhC

BI-PhA Init AR

BI-PhB Init AR

BI-PhC Init AR

BO Relay Block AR BI-MC/AR Block

BI-AR OFFOffOn

+

BO-Trip 3Ph BI-3Ph Init AR

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:

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


248

Trip Command

CB Open PosItion

AR Initiate

Closing Command

T_Reclaim

T_Action

Fault

Synchro-check or

voltage check OK

T_Syn Check

T_MaxSynExt

T_3P AR1

t 1 t 3t 2 t 4 t 5 t 6

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

Trip Command

CB Open Position

AR for CB: AR Initiate

AR for CB: Closing command

T_Action

Fault

AR for CB: Synchro-check or

voltage check OK

AR for CB: T_3P AR1

AR for CB: T_Reclaim

AR for CB: T_Reset

Figure 84 A permanent three-phase fault, single shot, unsuccessful reclosing

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‖.

1.2.7 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

―T_CB Faulty‖ finishing, auto-reclosing will be blocked for ―T_AR Reset‖.

1.2.8 Logic diagram

BI_PhA Init AR 1-0

A Phase no current

BI_PhB Init AR 1-0

AND

B Phase no current

BI_PhC Init AR 1-0

AND

C Phase no current

OR

BI_PhA Init AR 1-0

ANDBI_PhB Init AR 1-0

3 Phase no current

BI_PhB Init AR 1-0

ANDBI_PhC Init AR 1-0

3 Phase no current

BI_PhC Init AR 1-0

ANDBI_PhA Init AR 1-0

3 Phase no current

OR

BI_3Ph Init AR 1-0

AND

3 Phase no current

Single phase Startup ARAND

3 phase Startup AR

AND

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

BI_PhA CB Open 0-1

AND

OR

AND

BI_PhA CB Open 0-1

AND

BI_PhB CB Open 0-1

OR

Single phase Startup ARAND

3 phase Startup AR

3P CBOpen Init AR on

BI_PhB CB Open 0-1

BI_PhC CB Open 0-1


AND

BI_PhC CB Open 0-1

BI_PhA CB Open 0-1



BI_PhB CB Open 0-1

AND


BI_PhC CB Open 0-1

AND1P CBOpen Init AR on

Figure 86 Logic diagram 2 for auto-reclosing startup

AR_Chk3PVol =1

Ua(Ub,Uc) >Umin_Syn

OR

2)

t

AR_Chk3PVol =0

Note:

1) t = T_Syn Check

2) t = T_3P AR

3) t = T_MaxSynExt

AND

3)

0

1)

t 0

AND Check 3Ph Voltage OK

Check 3 Ph failure

t 0

Figure 87 Logic diagram of checking 3 phase voltage


252

3 Ph Tripping: 0-1

Ph A Tripping: 0-1

BI_MC/AR block: 0-1

Backup protection tripping

Alarm: Relay fault

Ph B Tripping: 0-1

Ph B Tripping: 0-1

Single phase initiate AR

NO check

AR_1p mode =1

AR_1p(3p) mode =1

Energizing check OK

Synchro-check OK

BI_CB Faulty

AR Closing

Check 3Ph Voltage OK

AND

OR 1)

AND

AR_3p mode = 1

AR_1p(3p) mode =1

AND

OR

3 phase initiate AR

AND

OR

2)

OR

AND

4)

Note:

1) t = T_1P AR

2) t = T_3P AR

3) t = T_MaxSynExt

4) t = T_CB Faulty

AR Fail

AR_3p mode =1

OR

Relay trip 3 Ph = 1

AR_1p mode = 1

AND

OR

AND

AR Lockout

BI_AR off: 0-1

AR_Disable =1

Relay Trip 3 pole =1

OR

AND

t 0

t 0

t 0

t 0

3)

OR

Figure 88 Logic diagram of auto-reclosing


253


IP1

IP2

IP3

PhA Init AR

AR off

PhB Init AR

PhC Init AR

3Ph Init AR

MC/AR Block

AR Close

AR Lockout

AR Not Ready

AR Final Trip

AR In Progress

AR Successful

CB Faulty

UP1

UP2

UP3

PhA CB Open

PhB CB Open

PhC CB Open

3Ph CB Open

UP4

V1P MCB Fail


Signal Description




UP1 signal for voltage input 1





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

Signal Description

PhC Init AR PhaseC initiate AR

3Ph Init AR Three phase initiate AR

CB Faulty

In order to avoid Auto-reclosing in the case of

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


Signal Description


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.


1.4.1 Setting lists


255

Table 134 Auto reclosure function setting list

Setting Uni

t

Min.

(Ir:5A/

1A)

Max.

(Ir:5A/1

A)

Default

setting

(Ir:5A/1A)

Description

T_1P AR1 s 0.05 10 0.6 delay time of shot 1 of single pole

reclosing


reclosing


reclosing


reclosing

T_3P AR1 s 0.05 60 1.1 delay time of shot 1 of three pole

reclosing


reclosing


reclosing


reclosing

T_Action ms 80 500 80

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

Times_AR 1 4 1 quanty of shots

T_Syn

Check s 0 60 0.05 delay time of synchronizing

T_MaxSynE

xt s 0.05 60 10 duration of quit synchronizing

T_AR Reset s 0.5 60 3 duration of CB reclosing prepartion

Table 135 Auto reclosure binary setting list


AR Init By 2p AR Initiated by

phase-to-phase fault 0 0 1

AR Init By 3p AR Initiated by three

phase fault 1 0 1

Relay Trip 3pole Three phase tripping 0 0 1

Tele_EF Init AR Auto reclosure 0 0 1


256


initiated by tele earth

fault protection

EF1 Init AR

Auto-reclosing

initiated by first stage

zero-sequence current

protection

0 0 1

EF2 Init AR

Auto-reclosing

initiated by second

stage zero-sequence

current protection

0 0 1

AR_1p mode

single phase mode for

Auto-reclosing

function

1 0 1

AR_3p mode On

three phase mode for

Auto-reclosing

function

0 0 1

AR_1p(3p) mode

one and three phase

mode for

Auto-reclosing

function

0 0 1

AR_Disable Auto-reclosing

function disabled 0 0 1

AR_Override Override mode for AR

enabled or disabled 1 0 1

AR_Syn check

Synchronization check

for AR enabled or

disabled

0 0 1

AR_Chk3PVol

three phase voltage

check for single phase

AR

0 0 1

AR Final Trip Final trip by AR 0 0 1

1P CBOpen Init AR AR initiated by single

phase CB open 0 0 1

3P CBOpen Init AR AR initiated by three

phase CB open 0 0 1

1.5 Reports


257



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



AR Mode Alarm Autoreclosure mode alarm



Func_AR On AR function on

Func_AR Off AR function off

BI_AR Off AR off BI

1.6 Technical data



258


Number of reclosing shots Up to 4

Shot 1 to 4 is individually

selectable

AR initiating functions Internal protection functions

External binary input

Dead time, separated setting

for shots 1 to 4

0.05 s to 60.00 s, step 0.01 s ≤ ± 1 % setting value or +50

ms

Reclaim time 0.50 s to 60.00s, step 0.01 s

Blocking duration time (AR

reset time)

0.05 s to 60.00s, step 0.01 s

Circuit breaker ready

supervision time

0.50 s to 60.00 s, step 0.01 s

Dead time extension for

synch-check (Max. SYNT

EXT)

0.05 s to 60.00 s, step 0.01 s

Chapter 20 Secondary system supervision

259

Chapter 20 Secondary system

supervision

About this chapter



secondary system supervision function.


260

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 FailIN



Signal Description



Signal Description


261

Signal Description

CT Fail CT Fail


1.4.1 Setting lists

Table 141 Fuse failure supervision function setting list

Setting Unit Min.

(Ir:5A/1A)

Max.

(Ir:5

A/1A

)

Default

setting

(Ir:5A/1A)

Description

3I0_CT Fail A 0.08Ir 2Ir 0.2Ir zero sequence current threshold

of CT failure detection

Table 142 Fuse failure supervision binary setting list


CT Fail Check CT mode 1 0 1


1.5 Reports



CT Fail CT fail


262

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:

Symmetrical/Asymmetrical VT fail detection

3-phase AC voltage MCB monitoring

Applicable in solid, compensated or isolated networks


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

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

more than 10 sec.

Figure 89 shows logic diagram of VT failure supervision as it is implemented.

10S

500ms

10S

Solid earthed off

Solid earthed on

Max(Ia,Ib,Ic)>I_VT Fail

A

N

D

maxUa,Ub,Uc<Upe_VT Fail

3U0 < (Upe_VT Fail-1)

3U0 >=(Upe_VT Fail-1)

MaxUab,Ubc,Uca-MinUab,Ubc,Uca>

Upp_VT Fail

A

N

D

Relay Start up

VT Fail on

VT Fail block

minUa,Ub,Uc>Upe_VT Normal

A

N

D

3I0>3I02_VT Fail or 3I2>3I02_VT Fail

A

N

D

A

N

D

A

N

D

A

N

D

A

N

D

A

N

D

O

R

O

R

BI_V3P MCB

Fail 0-1 VT Fail block

Alarm report

O

R

VT Fail unblock

Figure 89 VT fail blocking/unblocking logic



265

IP1

IP2

IP3

V3P MCB Fail

IU1

IU2

IU3

VT Fail

IN


Signal Description









Signal Description

V3P MCB Fail Three phase VT fail


Signal Description

VT Fail VT Fail


2.4.1 Setting list


266


Setting Unit

Min.

(Ir:5A/1

A)

Max.

(Ir:5A/1A)

Default

setting

(Ir:5A/1A

)

Description

I_VT Fail A 0.08Ir 0.2Ir 0.1Ir current threshold of PT failure

detection

3I02_VT Fail A 0.08Ir 0.2Ir 0.1Ir

Negative sequence/zero

sequence current threshold of

release blocking due to VT

failure

Upe_VT Fail V 7 20 8 voltage (phase to earth)

threshold of PT failure detection

Upp_VT Fail V 10 30 16 voltage (phase to phase)

threshold of PT failure detection

Upe_VT

Normal V 40 65 40

restore voltage threshold of PT

failure detection



VT Fail Check VT 1 0 1

Solid Earthed The system is solid

earthed system 1 0 1

2.5 Technical data


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

sequence current

0.08Ir to 0.20Ir, step 0.01A ≤ ±5% setting or ±0.02Ir

Maximum phase to earth

voltage

7.0V to 20.0V, step 0.01V ≤ ±3% setting or ±1 V

Maximum phase to phase 10.0V to 30.0V, step 0.01V ≤ ±3% setting or ±1 V


267

voltage

Normal phase to earth

voltage

40.0V to 65.0V, step 0.01V ≤ ±3% setting or ±1 V


268

Chapter 21 Monitoring

269


About this chapter



monitoring function.

Chapter 21 Mornitoring

270

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

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

T_Broken Conduct

Broken Conduct Trip Off

T_Broken Conduct

Broken Conduct Trip On

BI_PhA CB Open

O

RBI_PhA CB Open

BI_PhA CB Open

3I2>3I2_Broken

Conduct

Func_Broken Conduct on

A

N

DA

N

D

A

N

D

Broken

Conduct

Alarm

Broken

ConductTrip

Figure 90 Broken conductor logic



272

IP1

IP2

IP3

BRKN COND Trip

BRKN COND Alarm

PhA CB Open

PhB CB Open

PhC CB Open


Signal Description





Signal Description

PhA CB Open Phase A CB Open

PhB CB Open Phase B CB Open

PhC CB Open Phase C CB Open


Signal Description

BRKN COND Trip BRKN COND trip

BRKN COND Alarm BRKN COND alarm


5.3.1 Setting list


273

Table 153 Broken conductor supervision function setting list

Setting Uni

t

Min.

(Ir:5A/1

A)

Max.

(Ir:5A/

1A)

Default

setting

(Ir:5A/1

A)

Description

3I2_Broken

Conduct A 0.08Ir 2Ir 2Ir

nagative sequence current

threshold of conduct broken

detection

T_Broken

Conduct s 0 250 10

time delay of conduct broken

detection

Table 154 Broken conductor supervision binary setting list


Func_Broken Conduct Broken Conduct

function 1 0 1

Broken Conduct Trip Broken Conduct Trip

function 0 0 1

5.4 Reports



BRKN COND Trip Broken conductor protection trip



BRKN COND Alarm Broken conductor alarm


274

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

CSC-101

52

IA

IB

IC

IN

IN (M)

52

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

A(B,C)

A(B,C) N m M

UZ=

I +K 3I0+jK IN

Equation 23

where

N

Z0-Z1K =

3Z1

MM

X0K =

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 ZL1, XL1,

is calculated from the following equation. This is done by separating the real

and imaginary parts of the following equation.

m L1 k g iαA Km1 L1 g

m m m

I Z +I RU IZ = = =Z + R e

I I I

Equation 24

M N

Im InIk Rg

L2L1

jX

R

ZL1

ZM1

jαgeR

Im

Ik

XL1

XM1

Figure 92 Remote end infeed compensation in fault location calculation


276

Chapter 22 Station communication

277


About this chapter

This chapter describes the communication possibilities in a

substation automation system.


278

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

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

Gateway

or

converter

Work Station 3

Server or

Work Station 1

Server or

Work Station 2

Work Station 4

Net 2: IEC61850/IEC103,Ethernet Port B

Net 3: IEC103, RS485 Port A

Net 4: IEC103, RS485 Port B

Net 1: IEC61850/IEC103,Ethernet Port A

Gateway

or

converter

SwitchSwitch Switch

Switch

Switch

Switch

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 IRIG-B Pulse

Ethernet port IRIG-B port Binary input

Figure 94 Time synchronizing modes


281

5 Technical data


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


Max. length of communication cable 100m

For IEC 61850 protocol

Communication speed 100 Mbit/s




282

Optical communication port ( optional )

Number 0 to 2

Connection SC connector


Optical cable type Multi-mode

Max. length of communication cable 2.0km

IEC 61850 protocol




5.4 Time synchronization

Item Data

Mode Pulse mode

IRIG-B signal format IRIG-B000



Voltage levels differential input

Chapter 23 Remote communication

283


About this chapter

This chapter describes the remote communication possibilities

applied by protection functions.


284

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

IED IED

Single-mode FO

Length: <60kM or

60~100kM

Overhead Line or Cable

Channel A


285

Figure 95 Single channel, communication through dedicated fiber optical cable

IED IED

Channel A

Channel B

Single-mode FO

Length: <60kM or

60~100kM


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.

o

e

Communication

converter

Communication

converter

Digital

communication

network

G703.5(E1: 2048kbit/s)

G703.1(64kbit/s)

IED IED


e

o


286

Figure 97 Single Channel, communication through digital communication network

Communication

converter

o

e

e

oo

e

e

oDigital

communication

network Communication

converter

G703.5(E1: 2048kbit/s)

G703.1(64kbit/s)

IED IED


Digital

communication

network

Channel B

Channel A

Figure 98 Double channels, communication through digital communication network

Single-mode FO

Length: <60kM or

60~100kM

IED IED

Channel A

Channel B

o

e

Digital

communication

network

e

o

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

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 100kM


288

Chapter 24 Hardware

289

Chapter 24 Hardware

About this chapter

This chapter describes the IED hardware.

Chapter 24 Hardware

290

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

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291

1.3 IED module arrangement

X1 X2 X3 X4 X5 X6 X7 X8 X9 X10

AIM CPU1 CPU2 COM BIM BOM1 BOM2 BOM3 BOM4 PSM

An

alo

gu

e In

pu

t mod

ule

CP

U m

odu

le 1

CP

U m

odu

le 2

Co

mm

unic

atio

n

mo

du

le

Bin

ary

inpu

t mo

du

le

Bin

ary

outp

ut m

odu

le 1

Bin

ary

outp

ut m

odu

le 2

Bin

ary

outp

ut m

odu

le 3

Bin

ary

outp

ut m

odu

le 4

Spa

re s

lot fo

r bin

ary

outp

ut m

odu

le

Po

wer s

upp

ly m

odu

le

Figure 101 Module arrangement （front view, when open the front panel）

1.4 The rear view of the protection IED

Test port

X3

COM

X2X4X5X6X7X8 X1

AIM

X10

PSM

Ethernet ports Fiber Optical ports

X 9

For BIM and BOM

Figure 102 Rear view of the protection IED

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292

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.

2

1

3

45

68

7

Figure 103 Front panel layout with 8 LEDs

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293

2

1

3

45

68

7

Figure 104 Front panel layout with 20 LEDs

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

2.2 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

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294

operate the IED are described below.

Table 157 function of keys of the keypad

Key function

SET

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

RESET key:

Reset LEDs

Return to normal scrolling display mode directly

2.4 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

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295

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

1 Run Green Steady lighting: Operation normally

Flashing: IED startup

8 Alarm Red

Steady lighting: Alarm II, meaning abnormal situation,

only the faulty function is out of service. Power supply

for tripping output is not blocked.

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


1 Run Green Steady lighting: Operation normally

Flashing: IED startup

11 Alarm Red

Steady lighting: Alarm II, meaning abnormal situation,

only the faulty function is out of service. Power supply

for tripping output is not blocked.

Flashing: Alarm I, meaning severe internal fault, all

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296


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.


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.

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297

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)

b01 a01

b02 a02

b03 a03

a04b04

a05b05

a06b06

a07b07

a08b08

a09b09

a10b10

a11b11

ab

a12b12

Figure 105 Terminals arrangement of AIM E

Table 161 Description of terminals of AIM E

Terminal Analogue Remark

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298

Input

a01 IA Star point

b01 I’A

a02 IB Star point

b02 I’B

a03 IC Star point

b03 I’C

a04 I’N

b04 IN Star point

a05 I’NM

b05 INM Star point

a06 Null

b06 Null

a07 Null

b07 Null

a08 Null

b08 Null

a09 Null

b09 Null

a10 U4 Star point

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 Standard Data

Rated current Ir IEC 60255-1 1 or 5 A

Nominal current range 0.05 Ir to 30 Ir

Nominal current range of 0.005 to 1 A

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299

sensitive CT

Power consumption (per

phase)

≤ 0.1 VA at Ir = 1 A;

≤ 0.5 VA at Ir = 5 A

≤ 0.5 VA for sensitive CT

Thermal overload capability IEC 60255-1

IEC 60255-27

100 Ir for 1 s

4 Ir continuous

Thermal overload capability for

sensitive CT

IEC 60255-27

DL/T 478-2001

100 A for 1 s

3 A continuous

3.3.2 Internal voltage transformer

Item Standard Data

Rated voltage Vr (ph-ph) IEC 60255-1 100 V /110 V

Nominal range (ph-e) 0.4 V to 120 V

Power consumption at Vr = 110

V

IEC 60255-27

DL/T 478-2001

≤ 0.1 VA per phase

Thermal overload capability

(phase-neutral voltage)

IEC 60255-27

DL/T 478-2001

2 Vr, for 10s

1.5 Vr, continuous

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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

TX

RX

TX

Ch A

Ch B

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301

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

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302

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

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303

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

03

04

05

06

07

08

09

10

11

12

13

14

15

16

Ethernet port B

Ethernet port A

Ethernet port C

Figure 107 Terminals arrangement of COM

Table 163 Definition of terminals of COM

Terminal Definition

01 Null

02 Null

03 Null

04 Null

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304

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



system

Ethernet

Port C



system

5.4 Operating reports


DI Comm Fail DI communication error

DO Comm Fail DO communication error

5.5 Technical data

5.5.1 Front communication port

Item Data

Number 1

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305

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



Max. length of communication cable 1.0 km

Test voltage 500 V AC against earth


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


Max. length of communication cable 100m

For IEC 61850 protocol




Optical communication port ( optional )

Number 0 to 2

Connection SC connector


Optical cable type Multi-mode

Max. length of communication cable 2.0km

IEC 61850 protocol

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306




5.5.4 Time synchronization

Item Data

Mode Pulse mode

IRIG-B signal format IRIG-B000



Voltage levels differential input

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307

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)

c02 a02

c04 a04

c06 a06

a08c08

a10c10

a12c12

a14c14

a16c16

a18c18

a20c20

a22c22

a24c24

a26c26

a28c28

a30c30

a32c32

ac

DC -DC -

Figure 108: Terminals arrangement of BIM A

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308

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

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309

6.3 Technical data

Item Standard Data

Input voltage range IEC60255-1 110/125 V

220/250 V

Threshold1: guarantee

operation

IEC60255-1 154V, for 220/250V

77V, for 110V/125V

Threshold2: uncertain

operation

IEC60255-1 132V, for 220/250V ;

66V, for 110V/125V

Response time/reset time IEC60255-1 Software provides de-bounce

time

Power consumption,

energized

IEC60255-1 Max. 0.5 W/input, 110V

Max. 1 W/input, 220V

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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.

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311

a02

R

1

a04

a06

a08

a10

a12

a14

a16

a18

a20

a22

a24

a26

a28

a30

a32

ac

c02

c04

c06

c08

c10

c12

c14

c16

c18

c20

c22

c24

c26

c28

c30

c32

R

3

R

5

R

7

R

9

R

11

R

13

R

15

R

16

R

2

R

4

R

6

R

8

R

10

R

12

R

14

Figure 109 Terminals arrangement of BOM A

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312

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































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313

7.2.2 Binary Output Module C

The module provides 16 output relays for signal, with total 19 contacts.

a02

a04

a06

a08

a10

a12

a14

a16

a18

a20

a22

a24

a26

a28

a30

a32

ac

c02

c04

c06

c08

c10

c12

c14

c16

c18

c20

c22

c24

c26

c28

c30

c32

R

4

R

5

R

1

R

2

R

3

R

6

R

7

R

16

R

9

R

10

R

11

R

12

R

13

R

14

R

15

R

8

Figure 110 Terminals arrangement of BOM C

Table 166 Definition of terminals of BOM C

Terminal Definition Related relay

a02 Signal 1-0, Common terminal of signal contact group 1

c02 Signal 2-0, Common terminal of signal contact group 2

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314

a04 Signal contact 1-1 Output relay 1

c04 Signal contact 2-1 Output relay 1





a10 Signal 3-0, Common terminal of signal contact group 3

c10 Signal 4-0, Common terminal of signal contact group 4























7.3 Technical data

Item Standard Data

Max. system voltage IEC60255-1 250V /~

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315

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

Mechanical endurance,

Unloaded

IEC60255-1 50,000,000 cycles (3 Hz

switching frequency)

Mechanical endurance, making IEC60255-1 ≥1000 cycles


breaking

IEC60255-1 ≥1000 cycles

Specification state verification IEC60255-1

IEC60255-23

IEC61810-1

UL/CSA、TŰV

Contact circuit resistance

measurement

IEC60255-1

IEC60255-23

IEC61810-1

30mΩ

Open Contact insulation test

(AC Dielectric strength)

IEC60255-1

IEC60255-27

AC1000V 1min

Maximum temperature of parts

and materials

IEC60255-1 55

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316

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

(2) ±12V: Power for A/D

(3) + 5V: Power for all micro-chips

8.2 Terminals of Power Supply Module (PSM)

c02 a02

c04 a04

c06 a06

a08c08

a10c10

a12c12

a14c14

a16c16

a18c18

a20c20

a22c22

a24c24

a26c26

a28c28

a30c30

a32c32

ac

DC 24V +

OUTPUTS

DC 24V -

OUTPUTS

AUX.DC +

INPUT

AUX. DC -

INPUT

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317

Figure 111 Terminals arrangement of PSM

Table 167 Definition of terminals of PSM

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





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



a20 AUX. power input 1, DC +

c20 AUX. power input 2, DC +

a22 AUX. power input 3, DC +

c22 AUX. power input 4, DC +



a26 AUX. power input 1, DC -

c26 AUX. power input 2, DC -

a28 AUX. power input 3, DC -

c28 AUX. power input 4, DC -



a32 Terminal for earthing

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318

c32 Terminal for earthing

8.3 Technical data

Item Standard Data

Rated auxiliary voltage Uaux IEC60255-1 110 to 250V

Permissible tolerance IEC60255-1 ±%20 Uaux

Power consumption at

quiescent state

IEC60255-1 ≤ 50 W per power supply

module


maximum load


module

Inrush Current IEC60255-1 T ≤ 10 ms/I≤ 25 A per power

supply module,

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319

9 Techinical data

9.1 Basic data

9.1.1 Frequency

Item Standard Data

Rated system frequency IEC 60255-1 50 Hz or 60Hz

9.1.2 Internal current transformer

Item Standard Data

Rated current Ir IEC 60255-1 1 or 5 A

Nominal current range 0.05 Ir to 30 Ir

Nominal current range of

sensitive CT

0.005 to 1 A

Power consumption (per

phase)

≤ 0.1 VA at Ir = 1 A;

≤ 0.5 VA at Ir = 5 A

≤ 0.5 VA for sensitive CT

Thermal overload capability IEC 60255-1

IEC 60255-27

100 Ir for 1 s

4 Ir continuous

Thermal overload capability for

sensitive CT

IEC 60255-27

DL/T 478-2001

100 A for 1 s

3 A continuous

9.1.3 Internal voltage transformer

Item Standard Data

Rated voltage Vr (ph-ph) IEC 60255-1 100 V /110 V

Nominal range (ph-e) 0.4 V to 120 V

Power consumption at Vr = 110

V

IEC 60255-27

DL/T 478-2001

≤ 0.1 VA per phase

Thermal overload capability

(phase-neutral voltage)

IEC 60255-27

DL/T 478-2001

2 Vr, for 10s

1.5 Vr, continuous

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320

9.1.4 Auxiliary voltage

Item Standard Data

Rated auxiliary voltage Uaux IEC60255-1 110 to 250V

Permissible tolerance IEC60255-1 ±%20 Uaux


quiescent state


module


maximum load


module

Inrush Current IEC60255-1 T ≤ 10 ms/I≤ 25 A per power

supply module,

9.1.5 Binary inputs

Item Standard Data

Input voltage range IEC60255-1 110/125 V

220/250 V

Threshold1: guarantee

operation

IEC60255-1 154V, for 220/250V

77V, for 110V/125V

Threshold2: uncertain

operation

IEC60255-1 132V, for 220/250V ;

66V, for 110V/125V

Response time/reset time IEC60255-1 Software provides de-bounce

time

Power consumption,

energized

IEC60255-1 Max. 0.5 W/input, 110V

Max. 1 W/input, 220V

9.1.6 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

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Unloaded

IEC60255-1 50,000,000 cycles (3 Hz

switching frequency)

Mechanical endurance, making IEC60255-1 ≥1000 cycles


breaking

IEC60255-1 ≥1000 cycles

Specification state verification IEC60255-1

IEC60255-23

IEC61810-1

UL/CSA、TŰV

Contact circuit resistance

measurement

IEC60255-1

IEC60255-23

IEC61810-1

30mΩ

Open Contact insulation test

(AC Dielectric strength)

IEC60255-1

IEC60255-27

AC1000V 1min

Maximum temperature of parts

and materials

IEC60255-1 55

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

IEC 60529

Front plate: IP40

Rear, side, top and bottom: IP

30

Power frequency high voltage

withstand test

IEC 60255-5

EN 60255-5

ANSI C37.90

GB/T 15145-2001

DL/T 478-2001

2KV, 50Hz

2.8kV

between the following circuits:

auxiliary power supply

CT / VT inputs

binary inputs

binary outputs

case earth

500V, 50Hz

between the following circuits:

Chapter 24 Hardware

322

Item Standard Data

Communication ports to

case earth

time synchronization

terminals to case earth

Impulse voltage test IEC60255-5

IEC 60255-27

EN 60255-5

ANSI C37.90

GB/T 15145-2001

DL/T 478-2001

5kV (1.2/50μs, 0.5J)

If Ui≥63V

1kV if Ui<63V

Tested between the following

circuits:


CT / VT inputs

binary inputs

binary outputs

case earth

Note: Ui: Rated voltage

Insulation resistance IEC60255-5

IEC 60255-27

EN 60255-5

ANSI C37.90

GB/T 15145-2001

DL/T 478-2001

≥ 100 MΩ at 500 V

Protective bonding resistance IEC60255-27 ≤ 0.1Ω

Fire withstand/flammability IEC60255-27 Class V2

9.2.2 Electromagnetic immunity tests

Item Standard Data

1 MHz burst immunity test IEC60255-22-1

IEC60255-26

IEC61000-4-18

EN 60255-22-1

ANSI/IEEE C37.90.1

Class III

2.5 kV CM ; 1 kV DM

Tested on the following circuits:


CT / VT inputs

binary inputs

binary outputs

1 kV CM ; 0 kV DM


communication ports

Electrostatic discharge IEC 60255-22-2 Level 4

Chapter 24 Hardware

323

IEC 61000-4-2

EN 60255-22-2

8 kV contact discharge;

15 kV air gap discharge;

both polarities; 150 pF; Ri = 330

Ω

Radiated electromagnetic field

disturbance test

IEC 60255-22-3

EN 60255-22-3

Frequency sweep:

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

disturbance test

IEC 60255-22-3

EN 60255-22-3

Pulse-modulated

10 V/m, 900 MHz; repetition rate

200 Hz, on duration 50 %

Electric fast transient/burst

immunity test

IEC 60255-22-4,

IEC 61000-4-4

EN 60255-22-4

ANSI/IEEE C37.90.1

Class A, 4KV



CT / VT inputs

binary inputs

binary outputs

Class A, 1KV


communication ports

Surge immunity test IEC 60255-22-5

IEC 61000-4-5

4.0kV L-E

2.0kV L-L



CT / VT inputs

binary inputs

binary outputs

500V L-E


communication ports

Conduct immunity test IEC 60255-22-6

IEC 61000-4-6

Frequency sweep: 150 kHz – 80

MHz

spot frequencies: 27 MHz and

68 MHz

10 V

AM, 80%, 1 kHz

Chapter 24 Hardware

324

Power frequency immunity test IEC60255-22-7 Class A

300 V CM

150 V DM

Power frequency magnetic field

test

IEC 61000-4-8 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



CT / VT inputs

binary inputs

binary outputs

1 kV CM ; 0 kV DM


communication ports

9.2.3 DC voltage interruption test

Item Standard Data

DC voltage dips IEC 60255-11 100% 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

/start-up

IEC 60255-11 60 s shut down ramp

5 min power off

60 s start-up ramp

DC voltage reverse polarity IEC 60255-11 1 min

9.2.4 Electromagnetic emission test

Item Standard Data

Radiated emission IEC60255-25

EN60255-25

CISPR22

30MHz to 1GHz ( IT device may

up to 5 GHz)

Conducted emission IEC60255-25

EN60255-25

CISPR22

0.15MHz to 30MHz

Chapter 24 Hardware

325

9.2.5 Mechanical tests

Item Standard Data

Sinusoidal Vibration response

test

IEC60255-21-1

EN 60255-21-1

Class 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

endurance test

IEC60255-21-1

EN 60255-21-1

Class 1

10 Hz to 150 Hz: 1 g

20 sweep cycle in each axis

Relay non-energized

Shock response test IEC60255-21-2

EN 60255-21-2

Class 1

5 g, 11 ms duration

3 shocks in both directions of 3

axes

Relay energized

Shock withstand test IEC60255-21-2

EN 60255-21-2

Class 1

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 Standard Data

Chapter 24 Hardware

326

Cold test - Operation IEC60255-27

IEC60068-2-1

-10°C, 16 hours, rated load

Cold test – Storage IEC60255-27

IEC60068-2-1

-25°C, 16 hours

Dry heat test – Operation [IEC60255-27

IEC60068-2-2

+55°C, 16 hours, rated load

Dry heat test – Storage IEC60255-27

IEC60068-2-2

+70°C, 16 hours

Change of temperature IEC60255-27

IEC60068-2-14

Test Nb, figure 2, 5 cycles

-10°C / +55°C

Damp heat static test IEC60255-27

IEC60068-2-78

+40°C, 93% r.h. 10 days, rated

load

Damp heat cyclic test IEC60255-27

IEC60068-2-30

+55°C, 93% r.h. 6 cycles, rated

load

9.2.7 CE Certificate

Item Data

EMC Directive EN 61000-6-2 and EN61000-6-4 (EMC

Council Directive 2004/108/EC)

Low voltage directive EN 60255-27 (Low-voltage directive 2006/95

EC).

9.3 IED design

Item Data

Case size 4U×19inch

Weight ≤ 10kg

Chapter 25 Appendix

327

Chapter 25 Appendix

About this chapter

This chapter describes the appendix.

Chapter 25 Appendix

328

1 General setting list

1.1 Function setting list

No Setting Unit

Min.

(Ir:5A/1

A)

Max.

(Ir:5A/1

A)

Default

setting

(Ir:5A/1A)

Description

1 I_abrupt A 0.08Ir 20Ir 0.2Ir

Sudden-change


startup element

2 T_Relay

Reset s 0.5 10 1 The reset time of relay

3 U_Primary kV 30 800 230 Rated primary voltage

(phase to phase)

4 U_Seconda

ry V 100 120 100

Rated secondary

voltage (phase to

phase)

5 CT_Primary kA 0.05 5 3 Rated primary current

6 CT_Second

ary A 1 5 1

Rated secondary

current

7 I_VT Fail A 0.08Ir 0.2Ir 0.1Ir current threshold of PT

failure detection

8 3I02_VT

Fail A 0.08Ir 0.2Ir 0.1Ir

Negative

sequence/zero

sequence current

threshold of release

blocking due to VT

failure

9 Upe_VT

Fail V 7 20 8

voltage (phase to

earth) threshold of PT

failure detection

10 Upp_VT

Fail V 10 30 16

voltage (phase to

phase) threshold of PT

failure detection

11 Upe_VT

Normal V 40 65 40

restore voltage

threshold of PT failure

detection

12 3I0_CT Fail A 0.08Ir 2Ir 0.2Ir


threshold of CT failure

detection

Chapter 25 Appendix

329

13 3I2_Broken

Conduct A 0.08Ir 2Ir 2Ir

nagative sequence


conduct broken

detection

14 T_Broken

Conduct s 0 250 10

time delay of conduct

broken detection

15 Kx -0.33 8 1

compensation factor of

zero sequence

reactance

16 Kr -0.33 8 1


zero sequence

resistance

17 Km -0.33 8 0


zero sequence mutual

inductance of parallel

line

18 X_Line Ohm 0.01 600 10 positive reactance of

the whole line

19 R_Line Ohm 0.01 600 2 positive resistance of

the whole line

20 Line length km 0.1 999 100 Length of line

21 T_Tele

Reversal ms 0 100 40

Time delay of power

reserve

22 3I0_Tele



threshold of

tele-protection based

on earth fault

protection

23 T0_Tele EF s 0.01 10 0.15

time delay of

tele-protection based

on earth fault

protection

24 I_PSB A 0.5 20Ir 2Ir


power system

unstability detection

25 R1_PE Ohm 0.01/0.

05

120/60

0 1/5

resistance reach of

zone 1 of phase to

earth distance

protection

26 X1_PE Ohm 0.01/0.

05

120/60

0 1/5

reactance reach of

zone 1 of phase to

earth distance

protection

Chapter 25 Appendix

330

27 R2_PE Ohm 0.01/0.

05

120/60

0 1.6/8

resistance reach of

zone 2 of phase to

earth distance

protection

28 X2_PE Ohm 0.01/0.

05

120/60

0 1.6/8

reactance reach of

zone 2 of phase to

earth distance

protection

29 R3_PE Ohm 0.01/0.

05

120/60

0 2.4/12

resistance reach of

zone 3 of phase to

earth distance

protection

30 X3_PE Ohm 0.01/0.

05

120/60

0 2.4/12

reactance reach of

zone 3 of phase to

earth distance

protection

31 R4_PE Ohm 0.01/0.

05

120/60

0 3/15

resistance reach of

zone 4 of phase to

earth distance

protection

32 X4_PE Ohm 0.01/0.

05

120/60

0 3/15

reactance reach of

zone 4 of phase to

earth distance

protection

33 R5_PE Ohm 0.01/0.

05

120/60

0 3.6/18

resistance reach of

zone 5 of phase to

earth distance

protection

34 X5_PE Ohm 0.01/0.

05

120/60

0 3.6/18

reactance reach of

zone 5 of phase to

earth distance

protection

35 R1Ext_PE Ohm 0.01/0.

05

120/60

0 1.6/8

resistance reach of

extended zone 1 of

phase to earth

distance protection

36 X1Ext_PE Ohm 0.01/0.

05

120/60

0 1.6/8

reactance reach of

extended zone 1 of

phase to earth

distance protection

37 T1_PE s 0 60 0


phase to earth

distance protection

Chapter 25 Appendix

331

38 T2_PE s 0 60 0.3


phase to earth

distance protection

39 T3_PE s 0 60 0.6


phase to earth

distance protection

40 T4_PE s 0 60 0.9


phase to earth

distance protection

41 T5_PE s 0 60 1.2


phase to earth

distance protection

42 T1_Ext_PE s 0 60 0.05

delay time of extended

zone 1 of phase to

earth distance

protection

43 R1_PP Ohm 0.01/0.

05

120/60

0 1/5

resistance reach of

zone 1 of phase to

phase distance

protection

44 X1_PP Ohm 0.01/0.

05

120/60

0 1/5

reactance reach of

zone 1 of phase to

phase distance

protection

45 R2_PP Ohm 0.01/0.

05

120/60

0 1.6/8

resistance reach of

zone 2 of phase to

phase distance

protection

46 X2_PP Ohm 0.01/0.

05

120/60

0 1.6/8

reactance reach of

zone 2 of phase to

phase distance

protection

47 R3_PP Ohm 0.01/0.

05

120/60

0 2.4/12

resistance reach of

zone 3 of phase to

phase distance

protection

48 X3_PP Ohm 0.01/0.

05

120/60

0 2.4/12

reactance reach of

zone 3 of phase to

phase distance

protection

49 R4_PP Ohm 0.01/0.

05

120/60

0 3/15

resistance reach of

zone 4 of phase to

phase distance

protection

Chapter 25 Appendix

332

50 X4_PP Ohm 0.01/0.

05

120/60

0 3/15

reactance reach of

zone 4 of phase to

phase distance

protection

51 R5_PP Ohm 0.01/0.

05

120/60

0 3.6/18

resistance reach of

zone 5 of phase to

phase distance

protection

52 X5_PP Ohm 0.01/0.

05

120/60

0 3.6/18

reactance reach of

zone 5 of phase to

phase distance

protection

53 R1Ext_PP Ohm 0.01/0.

05

120/60

0 1.6/8

resistance reach of

extended zone 1 of

phase to phase

distance protection

54 X1Ext_PP Ohm 0.01/0.

05

120/60

0 1.6/8

reactance reach of

extended zone 1 of

phase to phase

distance protection

55 T1_PP s 0 60 0


phase to phase

distance protection

56 T2_PP s 0 60 0.3


phase to phase

distance protection

57 T3_PP s 0 60 0.6


phase to phase

distance protection

58 T4_PP s 0 60 0.9


phase to phase

distance protection

59 T5_PP s 0 60 1.2


phase to phase

distance protection

60 T1_Ext_PP s 0 60 0.05

delay time of extended

zone 1 of phase to

phase distance

protection

61 I_SOTF_Di

st A 0.08Ir 2Ir 0.2Ir


manual switch onto

faulty line for

distance+G252

Chapter 25 Appendix

333

62 3I0_Dist_P

E A 0.1Ir 2Ir 0.1Ir


threshold of phase to

earth distance

protection

63 3U0_Dist_

PE V 0.5 60 1

zero sequence voltage

threshold of phase to

earth distance

protection

64 I_Diff High A 0.1Ir 20Ir 0.4Ir

high current threshold

of differential

protection

65 I_Diff Low A 0.1Ir 20Ir 0.4Ir

low current threshold

of differential

protection

66 I_Diff TA

Fail A 0.1Ir 20Ir 2Ir



at CT failure

67 I_Diff

ZeroSeq A 0.1Ir 20Ir 0.2Ir


threshold of zero


protection

68 T_Diff

ZeroSeq s 0.1 60 0.1

delay time of zero


protection

69 T_DTT s 0 10 0.1 delay time of DTT

70 CT Factor 0.2 1 1 convert factor of CT

ratio

71 XC1 Ohm 40 9000 9000

positive sequence

capacitive reactance

of line

72 XC0 Ohm 40 9000 9000

zero sequence

capacitive reactance

of line

73 X1_Reactor Ohm 90 9000 9000

positive sequence

reactance of shunt

reactor

74 X0_Reactor Ohm 90 9000 9000

zero sequence

reactance of shunt

reactor

75 Local

Address 0 65535 0

identified code of local

end of line

76 Opposite

Address 0 65535 0

identified code of

opposite end of line

77 I_OC1 A 0.08Ir 20Ir 2Ir current threshold of

Chapter 25 Appendix

334

overcurrent stage 1

78 T_OC1 s 0 60 0.1 delay time of

overcurrent stage 1

79 I_OC2 A 0.08Ir 20Ir 1Ir current threshold of

overcurrent stage 2

80 T_OC2 s 0 60 0.3 delay time of

overcurrent stage 2

81 Curve_OC

Inv 1 12 1

No.of inverse time


overcurrent

82 I_OC Inv A 0.08Ir 20Ir 1Ir start current of inverse

time overcurrent

83 K_OC Inv 0.05 999 1

time multiplier of

customized inverse

time characteristic

curve for overcurrent

84 A_OC Inv s 0 200 0.14

time constant A of

customized inverse

time characteristic


85 B_OC Inv s 0 60 0

time constant B of

customized inverse

time characteristic


86 P_OC Inv 0 10 0.02

index of customized

inverse time


overcurrent

87 Angle_OC Degre

e 0 90 60


operation area of

overcurrent directional

element

88 Imax_2H_U

nBlk A 0.25 20Ir 5Ir

the maximum current

to release harmornic

block

89 Ratio_I2/I1 0.07 0.5 0.2

ratio of 2rd harmonic

to fundamental

component

90 T2h_Cross

_Blk s 0 60 1

delay time of cross

block by 2rd

harmormic

91 3I0_EF1 A 0.08Ir 20Ir 0.5Ir



protection stage 1

Chapter 25 Appendix

335

92 T_EF1 s 0 60 0.1 delay time of earth

fault protection stage 1

93 3I0_EF2 A 0.08Ir 20Ir 0.2Ir



protection stage 2

94 T_EF2 s 0 60 0.3 delay time of earth


95 Curve_EF

Inv 1 12 1

No. of inverse time



96 3I0_EF Inv A 0.08Ir 20Ir 0.2Ir

start current of inverse

time earth fault

protection

97 K_EF Inv 0.05 999 1

time multiplier of

customized inverse

time characteristic


protection

98 A_EF Inv s 0 200 0.14

time constant A of

customized inverse

time characteristic


protection

99 B_EF Inv s 0 60 0

time constant B of

customized inverse

time characteristic


protection

100 P_EF Inv 0 10 0.02

index of customized

inverse time



101 Angle_EF Degre

e 0 90 70


operation area of zero

sequnce directional

element

102 Angle_Neg Degre

e 50 90 70


operation area of

negative sequnce

directional element

103 I_Em/BU

OC A 0.08Ir 20Ir 1Ir


emergency/backup

overcurrent stage 1

Chapter 25 Appendix

336

104 T_Em/BU

OC s 0 60 0.3

delay time of

emergency/backup

overcurrent stage 1

105 Curve_Em/

BU OC Inv 1 12 1

No.of inverse time


emergency/backup

overcurrent

106 I_Inv_Em/B

U OC A 0.08Ir 20Ir 1Ir


time

emergency/backup

overcurrent

107 K_Em/BU

OC Inv 0.05 999 1

time multiplier of

customized inverse

time characteristic

curve for

emergency/backup

overcurrent

108 A_Em/BU

OC Inv s 0 200 0.14

time constant A of

customized inverse

time characteristic

curve for

emergency/backup

overcurrent

109 B_Em/BU

OC Inv s 0 60 0

time constant B of

customized inverse

time characteristic

curve for

emergency/backup

overcurrent

110 P_Em/BU

OC Inv 0 10 0.02

index of customized

inverse time


emergency/backup

overcurrent

111 3I0_Em/BU




protection stage 1

112 T_Em/BU

EF s 0 60 0.3

delay time of earth


113 Curve_Em/

BU EF Inv 1 12 1

No. of inverse time


emergency/backup


Chapter 25 Appendix

337

114 3I0_Inv_E

m/BU EF A 0.08Ir 20Ir 0.2Ir


time

emergency/backup


115 K_Em/BU

EF Inv 0.05 999 1

time multiplier of

customized inverse

time characteristic

curve for

emergency/backup


116 A_Em/BU

EF Inv s 0 200 0.14

time constant A of

customized inverse

time characteristic

curve for

emergency/backup


117 B_Em/BU

EF Inv s 0 60 0

time constant B of

customized inverse

time characteristic

curve for

emergency/backup


118 P_Em/BU

EF Inv 0 10 0.02

index of customized

inverse time


emergency/backup


119 I_STUB A 0.08Ir 20Ir 1Ir current threshold of

STUB protection

120 T_STUB s 0 60 1 delay time of STUB

protection

121 I_SOTF A 0.08Ir 20Ir 2Ir

phase current

threshold of


switch onto fault

protection

122 T_OC_SOT

F s 0 60 0

delay time of


switch onto fault

protection

123 3I0_SOTF A 0.08Ir 20Ir 0.5Ir

zero sequnce current

threshold of switch

onto fault protection

Chapter 25 Appendix

338

124 T_EF_SOT

F s 0 60 0.1

delay time of zero

sequce overcurrent of

switch onto fault

protection

125 I_OL Alarm A 0.08Ir 20Ir 2Ir current threshold of

overload alarm

126 T_OL

Alarm s 0.1 6000 20

delay time of overload

alarm

127 U_OV1 V 40 200 65 voltage threshold of

overvoltage stage 1

128 T_OV1 s 0 60 0.3 delay time of

overvoltage stage 1

129 U_OV2 V 40 200 63 voltage threshold of

overvoltage stage 2

130 T_OV2 s 0 60 0.6 delay time of

overvoltage stage 2

131 Dropout_O

V 0.9 0.99 0.95

reset ratio of

overvoltage

132 U_UV1 V 5 150 40 voltage threshold of

undervoltage stage 1

133 T_UV1 s 0 60 0.3 delay time of


134 U_UV2 V 5 150 45 voltage threshold of


135 T_UV2 s 0 60 0.6 delay time of


136 Dropout_U

V 1.01 2 1.05

reset ratio of

undervoltage

137 I_UV_Chk A 0.08Ir 2Ir 0.1Ir current threshold of

undervoltage

138 I_CBF A 0.08Ir 20Ir 1Ir

phase current

threshold of circuit

breaker failure

protection

139 3I0_CBF A 0.08Ir 20Ir 0.2Ir


threshold of circuit

breaker failure

protection

140 3I2_CBF A 0.08Ir 20Ir 0.2Ir

negative sequence


circuit breaker failure

protection

141 T_CBF1 s 0 32 0 delay time of CBF

stage 1

Chapter 25 Appendix

339

142 T_CBF2 s 0.1 32 0.2 delay time of CBF

stage 2

143 T_CBF 1P

Trip 3P s 0.05 32 0.1

delay time of three

phase tripping of CBF

stage 1

144 3I0_PD A 0 20Ir 0.4Ir


threshold of pole

discordance protection

145 3I2_PD A 0 20Ir 0.4Ir

negative sequence


pole discordance

protection

146 T_PD s 0 60 2 delay time of pole


147 T_Dead

Zone s 0 32 1

delay time of dead

zone protection

148 T_1P AR1 s 0.05 10 0.6 delay time of shot 1 of

single pole reclosing








three pole reclosing







156 Angle_Syn

Diff

Degre

e 1 80 30

angle difference

threshold of

synchronizing

157 U_Syn Diff V 1 40 10

voltage difference

threshold of

synchronizing

158 Freq_Syn

Diff Hz 0.02 2 0.05

frequency difference

threshold of

synchronizing

159 T_Action ms 80 500 80

duration of the circuit

breaker closing

pulse

Chapter 25 Appendix

340

160 T_Reclaim s 0.05 60 3 Reclaim time

161 T_CB

Faulty s 0.5 60 1 duration of CB ready

162 Times_AR 1 4 1 available shot number

163 T_Syn

Check s 0 60 0.05

delay time of

synchronizing

164 T_MaxSyn

Ext s 0.05 60 10

duration of quit

synchronizing

165 T_AR

Reset s 0.5 60 3

duration of CB

reclosing prepartion

166 Umin_Syn V 30 65 40 Minimum voltage of

synchronizing

167 Umax_Ener

g V 10 50 30

Maximum voltage of

unenergizing checking

1.2 Binary setting list

No Setting Min. Max.

Default

setting Description

1 VT_Line 0 1 0

1: VT on line side; 0: VT on bus

side

2 BI SetGrp Switch 0 1 0

binary input switch active setting

group enable(1)/disable(0)

3 Relay Test Mode 0 1 0 Test mode enable(1)/disable(0)

4 Blk Remote

Access 0 1 0

block remote control


5 AR Init By 2p 0 1 0

phase to phase fault initiate auto

recloser enable(1)/disable(0)

6 AR Init By 3p 0 1 1

three phase fault initiate auto

recloser enable(1)/disable(0)

7 Relay Trip 3pole 0 1 0

three pole tripping mode


8 VT Fail 0 1 1

VT failure detection


9 Solid Earthed 0 1 1 solid earthed system(1)

10 CT Fail 0 1 1

CT failure detection


11 Func_Broken

Conduct 0 1 1

conduct broken detection


12 Broken Conduct

Trip 0 1 0

conduct broken tripping (1)/alarm

(0)

13 Weak InFeed 0 1 0

weak infeed function


Chapter 25 Appendix

341


Default

setting Description

14

Blocking Mode 0 1 0

blocking scheme of

tele-protection


15 PUR Mode 0 1 0

PUTT scheme of tele-protection


16 POR Mode 0 1 1

POTT scheme of tele-protection


17

Func_Tele EF 0 1 0

tele-protection based on earth

fault protection


18

Tele_EF Inrush

Block 0 1 0

Inrush block tele-protection based

on earth fault protection tele

protection based on earth fault

protection enable(1)/disable(0)

19

Tele_EF Init AR 0 1 0

tele-protection based on earth

fault protection initiate recloaser


20 Func_Z1 0 1 1

distance zone 1


21 Func_Z2 0 1 1

distance zone 2


22 Func_Z3 0 1 1

distance zone 3


23 Func_Z4 0 1 1

distance zone 4


24 Reverse_Z4 0 1 0

distance zone 4 reserve direction

(1)/forward direction(0)

25 Func_Z5 0 1 1

distance zone 5


26 Reverse_Z5 0 1 0

distance zone 5 reserve direction

(1)/forward direction(0)

27 Func_Z1Ext 0 1 1

distance extended zone 1


28

Z1_PS Blocking 0 1 1

power swing element block

distance zone 1


29



distance zone 2


30



distance zone 3


Chapter 25 Appendix

342


Default

setting Description

31



distance zone 4


32



distance zone 5


33 Z1Ext_PS

Blocking 0 1 1


extended distance zone 1


34

Z2 Speedup 0 1 0

distance zone 2 instantaneous

tripping at reclosing onto fault


35

Z3 Speedup 0 1 0

distance zone 3 instantaneous

tripping at reclosing onto fault


36

Z23 Speedup

Inrush Block 0 1 0

Inrush block the zone 2 or/and 3

instantaneous tripping at

recolsing onto fault


37 Func_OC1 0 1 1

overcurrent stage 1


38 OC1 Direction 0 1 1

overcurrent stage 1 with direction

element enable(1)/disable(0)

39 OC1 Inrush Block 0 1 1

overcurrent stage 1 blcoked by

inrush enable(1)/disable(0)

40 Func_OC2 0 1 1

overcurrent stage 2


41 OC2 Direction 0 1 1

overcurrent stage 2 with direction

element enable(1)/disable(0)

42 OC2 Inrush Block 0 1 1

overcurrent stage 2 blcoked by


43 Func_OC Inv 0 1 1

inverse time overcurrent


44

OC Inv Direction 0 1 0

inverse time overcurrent with

direction element


45 OC Inv Inrush

Block 0 1 0

inverse time overcurrent blocked

by inrush enable(1)/disable(0)

46 Func_EF1 0 1 1

earth fault protection stage 1


47 EF1 Direction 0 1 1

earth fault protection stage 1 with

direction element

Chapter 25 Appendix

343


Default

setting Description


48

EF1 Inrush Block 0 1 1


bloced by inrush


49 Func_EF2 0 1 1



50

EF2 Direction 0 1 1

earth fault protection stage 2 with

direction element


51

EF2 Inrush Block 0 1 1


bloced by inrush


52 Func_EF Inv 0 1 1

inverse time earth fault protection


53

EF Inv Direction 0 1 0


with direction element


54 EF Inv Inrush

Block 0 1 0


blocked by inrush


55

EF U2/I2 Dir 0 1 0

negative sequence direction

element for eath fault protection


56

EF1 Init AR 0 1 0


initiate recloser


57

EF2 Init AR 0 1 0


initiate recloser


58 Func_BU OC 0 1 0

1:backup overcurrent enable; 0:

emergency overcurrent enable

59 Func_Em/BU OC 0 1 1

emergency overcurrent


60 Em/BU OC Inrush

Block 0 1 0

emergency overcurrent blocked

by inrush enable(1)/disable(0)

61 Func_Em/BU OC

Inv 0 1 1

emergency inverse time

overcurrent enable(1)/disable(0)

62 Em/BU OC Inv

Inrush Block 0 1 0

emergency inverse time

overcurrent blocked by inrush


Chapter 25 Appendix

344


Default

setting Description

63

Func_BU EF 0

1:backup earth fault protection

enable;0:emergency earth fault

protection enable

64 Func_Em/BU EF 0 1 1

emergency earth fault protection


65 Em/BU EF Inrush

Block 0 1 0

emergency earth fault protection

blocked by inrush


66 Func_Em/BU EF

Inv 0 1 1

emergency inverse time earth

fault protection


67 Em/BU EF Inv

Inrush Block 0 1 0

emergency inverse time earth

fault protection blocked by inrush


68 Func_STUB 0 1 0

STUB protection


69 Func_SOTF 0 1 1

SOTF protection


70 SOTF Inrush Block 0 1 1

SOTF protection blocked by


71 Func_OL 0 1 1 overload enable(1)/disable(0)

72 Func_OV1 0 1 1

overvoltage stage 1


73 OV1 Trip 0 1 0

overvoltage stage 1 tripping

(1)/alarm(0)

74 Func_OV2 0 1 1

overvoltage stage 2


75 OV2 Trip 0 1 0

overvoltage stage 2 tripping

(1)/alarm(0)

76

OV PE 0 1 1

1: phase to earth voltage applied

by overvoltage;0: phase to phase

voltage applied by overvoltage

77 Func_UV1 0 1 0



78 UV1 Trip 0 1 0


tripping(1)/alarm(0)

79 Func_UV2 0 1 0



80 UV2 Trip 0 1 0


tripping(1)/alarm(0)

Chapter 25 Appendix

345


Default

setting Description

81

UV PE 0 1 1

1: phase to earth voltage applied

by undervoltage;0: phase to

phase voltage applied by

undervoltage

82

UV Chk All Phase 0 1 0

all three phase voltage must be

less than threshold


83 UV Chk Current 0 1 0

current threshold for undervoltage


84

UV Chk CB 0 1 0

criterion of state of circuit breaker

for undervoltage


85 Func_CBF 0 1 1



86

CBF 1P Trip 3P 0 1 0

delay time three-pole tripping

when one pole of circuit breaker

failure enable(1)/disable(0)

87

CBF Chk 3I0/3I2 0 1 1


criterion and zero sequence

current criterion for circuit breaker

failure protection


88 CBF Chk CB

Status 0 1 0

criterion of state of circuit breaker

for circuit breaker failure


89 Func_PD 0 1 1

pole discordance protection


90

PD Chk 3I0/3I2 0 1 0


criterion and zero sequence

current criterion for pole



91 Func_Dead Zone 0 1 1

dead zone protection


92 AR_1p mode 0 1 1

single pole reclosing mode


93 AR_3p mode 0 1 0

three pole reclosing mode


94 AR_1p(3p) mode 0 1 0

complicate reclosing mode


95 AR_Disable 0 1 0 recloser disable

96 AR_Override 0 1 1 overriding synchronization

Chapter 25 Appendix

346


Default

setting Description


97 AR_EnergChkDLL

B 0 1 0

check dead line and live bus


98 AR_EnergChkLLD

B 0 1 0

check live line and dead bus


99 AR_EnergChkDLD

B 0 1 0

check dead line and dead bus


100 AR_Syn check 0 1 0

check synchronization


101

AR_Chk3PVol 0 1 0

1:three phase must be energized

before single pole reclosing;0:

recloasing without any condition

102

AR Final Trip 0 1 0

three pole tripping when recoser

is blocked after recloser was

initiated due to single pole tripping


103 1P CBOpen Init

AR 0 1 0

recloser can be initiated by single

pole tripping due to mechanical

cause enable(1)/disable(0)

104 3P CBOpen Init

AR 0 1 0

recloser can be initiated by three

pole tripping due to mechanical

cause enable(1)/disable(0)

105 Func_Diff Curr 0 1 1



106 Func_Diff Curr

Abrupt 0 1 1

sudden change differential


107 Dual_Channel 0 1 1

double channels(1)/single

channel(0)

108 Master Mode 0 1 1 master mode (1)/ slaver mode (0)

109 Comp Capacitor

Cur 0 1 0

capacitive current compensation


110 Block Diff CT_Fail 0 1 1

CT failure block differential


111 Block 3Ph Diff

CT_Fail 0 1 0

block three phases(1)/block

broken phase(0)

112 Diff_Zero Init AR 0 1 1

AR initiated by zero sequence


113 Chan_A Ext_Clock 0 1 0

Channel A apply external clock


114 Chan_A 64k Rate 0 1 0

Channel A at 64Kb/s


Chapter 25 Appendix

347


Default

setting Description

115 Chan_B Ext_Clock 0 1 0

Channel B apply external clock


116 Chan_B 64k Rate 0 1 0

Channel B at 64Kb/s


117 Loop Test 0 1 0

channel loop test mode


118 DTT By Startup 0 1 1

DTT under startup element

control

119 DTT By Z2 0 1

DTT under Zone 2 distance

element control

120 DTT By Z3 0 1

DTT under Zone 3 distance

element control

Chapter 25 Appendix

348

2 General report list

Table 168 event report list

No. Abbr.

(LCD Display)

Meaning

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

Chapter 25 Appendix

349

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

Chapter 25 Appendix

350

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

Chapter 25 Appendix

351

Table 169 alarming report list

No 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

352

No Abbr.


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 1st stage undervoltage alarm

71 UV2 Alarm 2nd

stage undervoltage alarm

Chapter 25 Appendix

353

No Abbr.


72 V1P_MCB VT Fail V1P_MCB alarm

73 V3P_MCB VT Fail V3P_MCB alarm

74 VT Fail VT Fail

Table 170 operation report list

No. Abbr.


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

354

No. Abbr.


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

Chapter 25 Appendix

355

No. Abbr.


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

356

3 Typical connection

A. For one breaker of single or double busbar arrangement

IA

IB

IC

UB

UA

UC

U4

IN

UN

Protection IED

A

B

C

* * *

a01

a02

a03

a04

b01

b02

b03

b04

a10

a09

b09

b10

a07

b07

Figure 112 Typical connection diagram for one breaker of single or double busbar

arrangement

Chapter 25 Appendix

357

B. For one and half breaker arrangement

* **

IA

IB

IC

UB

UA

UC

U4

IN

UN

Protection IED

a01

a02

a03

a04

b01

b02

b03

b04

a10

a09

b09

b10

a07

b07

A

B

C

A

B

C

* **

Figure 113 Typical connection diagram for one and half breaker arrangement

Chapter 25 Appendix

358

C. For parallel lines

IA

IB

IC

UB

UA

UC

U4

IN

UN

Protection IED

A

B

C

* * *

a01

a02

a03

a04

b01

b02

b03

b04

a10

a09

b09

b10

a07

b07

***

INM

a05

b05

Figure 114 Typical connection diagram for parallel lines

Chapter 25 Appendix

359

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. 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

4.2 User defined characteristic

For the inverse time characteristic, also can be set as user defined

characteristic if the setting is set to 12.

K

Chapter 25 Appendix

360

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

Chapter 25 Appendix

361

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

Chapter 25 Appendix

362

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

K‖ssc

Effective symmetrical short-circuit current factor

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)

Chapter 25 Appendix

363

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

Chapter 25 Appendix

364

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

Chapter 25 Appendix

365

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.

Chapter 25 Appendix

366

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

Chapter 25 Appendix

367

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

Chapter 25 Appendix

368

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


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.

Chapter 25 Appendix

369

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


For PX class CT, Ek can be verified as below:

Where


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,

Chapter 25 Appendix

370

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)



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.


Where

Chapter 25 Appendix

371


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


5.5.5 Definite time overcurrent protection and earth fault protection

For TPY CT,

Kssc should be satisfied following requirement:

Where



I”pcf: Maximum applied operating setting value (A)



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:

Chapter 25 Appendix

372

Where



I”pcf: Maximum applied operating setting value (A)


Where


For PX class CT,

Ek should be verified based on below equation.

Where


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)


Chapter 25 Appendix

373

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)


Where


For PX class CT,

Ek should be verified based on below equation.

Where


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