Post on 31-Jan-2016
description
CSC-326
Transformer Protection IED
Technical Application Manual
CSC-326 Transformer
Protection IED
Technical Application Manual
Compiled: Jin Rui
Checked: Hou Changsong
Standardized: Li Lianchang
Inspected: Cui Chenfan
Version: V1.02
Doc.Code:0SF.450.085(E)
Issued Date:2014.12.25
Version:V1.02 Doc. Code:0SF.450.085(E)
Issued Date:2014.12 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 dis-semination 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 stand-ards as a result; it is possible that there may be some differences between the hard-ware/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
1
Preface
Purpose of this manual
This manual describes the functions, operation, installation, and placing into service of device CSC-326. 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-326; firmware version V1.00 and higher
Indication of Conformity
Additional Support
In case of further questions concerning IED CSC-326 system, please contact SIFANG representative.
Safety information
Strictly follow the company and international safety regulations. Working in a high voltage environment requires serious approch to aviod human injuries and damage to equipment
Do not touch any circuitry during operation. Potentially lethal voltages and currents are present
Avoid to touching the circuitry when covers are removed. The IED contains electirc circuits which can be damaged if exposed to static electricity. Lethal high voltage circuits are also exposed when covers are removed
Using the isolated test pins when measuring signals in open circuitry. Potentially lethal voltages and currents are present
Never connect or disconnect wire and/or connector to or from IED during normal operation. Dangerous voltages and currents are present. Operation may be interrupted and IED and measuring circuitry may be damaged
Always connect the IED to protective earth regardless of the operating conditions. Operating the IED without proper earthing may damage both IED and measuring circuitry and may cause injuries in case of an accident.
Do not disconnect the secondary connection of current transformer without short-circuiting the transformer’s secondary winding. Operating a current transformer with the secondary winding open will cause a high voltage that may damage the transformer and may cause injuries to humans.
Do not remove the screw from a powered IED or from an IED connected to power circuitry. Potentially lethal voltages and currents are present
Using the certified conductive bags to transport PCBs (modules). Handling modules with a conductive wrist strap connected to protective earth and on an antistatic surface. Electrostatic discharge may cause damage to the module due to electronic circuits are sensitive to this phenomenon
Do not connect live wires to the IED, internal circuitry may be damaged
When replacing modules using a conductive wrist strap connected to protective earth. Electrostatic discharge may damage the modules and IED circuitry
When installing and commissioning, take care to avoid electrical shock if accessing wiring and connection IEDs
Changing the setting value group will inevitably change the IEDs operation. Be careful and check regulations before making the change
Contents Chapter 1 Introduction ............................................................................................................. 1 1 Overview ............................................................................................................................... 2 2 Features................................................................................................................................ 3 Chapter 2 Basic protection elements ......................................................................................... 9 1 Startup element .................................................................................................................. 10
1.1 Introduction .......................................................................................................... 10 1.2 Sudden-change current startup element ........................................................... 10 1.3 Differential current startup element ................................................................... 10
2 Input and output signals .................................................................................................... 11 3 Settings ............................................................................................................................... 13 4 Report ................................................................................................................................. 16 Chapter 3 Differential protection ............................................................................................ 17 1 Introduction ......................................................................................................................... 18 2 Applications ........................................................................................................................ 18 3 Protection algorithm ........................................................................................................... 20
3.1 Differential and restraint current calculation ........................................................... 21 3.2 Automatic Ratio compensation............................................................................... 23 3.3 Automatic Vector group and zero sequence current compensation .......................... 27
4 Protection principle ............................................................................................................ 34 4.1 Instantaneous differential protection characteristic ................................................. 34 4.2 Treble slope percent differential protection characteristic ....................................... 35 4.3 Selective inrush stabilization schemes .................................................................... 38 4.3.1 2nd harmonic stabilization ..................................................................................... 39 4.3.2 Fuzzy recognition of inrush based on the waveform ............................................... 40 4.4 Overexcitation stabilization .................................................................................... 41 4.5 CT Failure supervision ........................................................................................... 44 4.6 CT Saturation supervision ...................................................................................... 45 4.7 Differential current supervision .............................................................................. 47
5 Input and output signals .................................................................................................... 48 6 Settings ............................................................................................................................... 50 7 Report ................................................................................................................................. 52 8 Technical data .................................................................................................................... 53 Chapter 4 Restricted earth fault protection.............................................................................. 54 1 Introduction ......................................................................................................................... 55 2 Applications ........................................................................................................................ 55 3 Protection principle ............................................................................................................ 57
3.1 Differential and restraint current calculation ........................................................... 58 3.2 Automatic Ratio compensation............................................................................... 60 3.3 Positive sequence current blocking ......................................................................... 62 3.4 Restricted earth fault current alarm ......................................................................... 63
4 Input and output signals .................................................................................................... 64 5 Settings ............................................................................................................................... 65
6 Report ................................................................................................................................. 67 7 Technical data .................................................................................................................... 68 Chapter 5 Overexcitation protection ....................................................................................... 70 1 Introduction ......................................................................................................................... 71 2 Protection principle ............................................................................................................ 71
2.1 Protection principle ................................................................................................ 71 2.2 Voltage channel configuration ................................................................................ 77
3 Input and output signals .................................................................................................... 78 4 Settings ............................................................................................................................... 79 5 Report ................................................................................................................................. 80 6 Technical data .................................................................................................................... 81 Chapter 6 Overcurrent protection ........................................................................................... 82 1 Introduction ......................................................................................................................... 83 2 Protection principle ............................................................................................................ 83
2.1 Protection Elements ............................................................................................... 83 2.2 Inrush Restraint Feature ......................................................................................... 85 2.3 Direction Determination Feature ............................................................................ 86 2.4 CBF initiation Feature ............................................................................................ 89
3 Input and output signals .................................................................................................... 90 4 Setting ................................................................................................................................. 91 5 Report ................................................................................................................................. 98 6 Technical data .................................................................................................................. 100 Chapter 7 Earth fault protection ........................................................................................... 101 1 Protection principle .......................................................................................................... 102
1.1 Protection elements .............................................................................................. 102 1.2 Inrush Restraint Feature ....................................................................................... 104 1.3 Direction Determination Feature .......................................................................... 105 1.4 CBF initiation Feature .......................................................................................... 107
2 Input and output signals .................................................................................................. 108 3 Setting ............................................................................................................................... 109 4 Report ............................................................................................................................... 116 5 Technical data .................................................................................................................. 117 Chapter 8 Neutral earth fault protection ................................................................................ 120 1 Protection principle .......................................................................................................... 121
1.1 Protection Elements ............................................................................................. 121 1.2 Inrush Restraint Feature ....................................................................................... 123 1.3 Direction Determination Feature .......................................................................... 123 1.4 CBF initiation Feature .......................................................................................... 126
2 Input and output signals .................................................................................................. 126 3 Setting ............................................................................................................................... 127 4 Report ............................................................................................................................... 133 5 Technical data .................................................................................................................. 134 Chapter 9 Thermal overload protection ................................................................................ 135 1 Introduction ....................................................................................................................... 136
2 Protection principle .......................................................................................................... 136 3 Input and output signals .................................................................................................. 138 4 Setting ............................................................................................................................... 139 5 Report ............................................................................................................................... 140 6 Technical data .................................................................................................................. 141 Chapter 10 Overload protection ............................................................................................. 143 1 Protection principle .......................................................................................................... 144 2 Input and output signals .................................................................................................. 145 3 Setting ............................................................................................................................... 146 4 Report ............................................................................................................................... 148 Chapter 11 Overvoltage protection ......................................................................................... 149 1 Introduction ....................................................................................................................... 150 2 Protection principle .......................................................................................................... 150
2.1 Phase to phase overvoltage protection .................................................................. 150 2.2 Phase to earth overvlotage protection ................................................................... 151
3 Logic diagram ................................................................................................................... 151 4 Input and output signals .................................................................................................. 151 5 Setting ............................................................................................................................... 152 6 Report ............................................................................................................................... 154 7 Technical data .................................................................................................................. 155 Chapter 12 Circuit breaker failure protection .......................................................................... 157 1 Introduction ....................................................................................................................... 158 2 Protection principle .......................................................................................................... 158 3 Logic diagram ................................................................................................................... 161 4 Input and output signals .................................................................................................. 163 5 Setting ............................................................................................................................... 164 6 Report ............................................................................................................................... 167 7 Technical data .................................................................................................................. 167 Chapter 13 Dead zone protection ........................................................................................... 169 1 Introduction ....................................................................................................................... 170 2 Protection principle .......................................................................................................... 170
2.1 Function description............................................................................................. 171 3 Logic diagram ................................................................................................................... 171 4 Input and output signals .................................................................................................. 172 5 Setting ............................................................................................................................... 173 6 Report ............................................................................................................................... 174 7 Technical data .................................................................................................................. 174 Chapter 14 STUB protection .................................................................................................. 175 1 Introduction ....................................................................................................................... 176 2 Protection principle .......................................................................................................... 176
2.1 Function description............................................................................................. 176 3 Logic diagram ................................................................................................................... 177 4 Input and output signals .................................................................................................. 177 5 Setting ............................................................................................................................... 178
6 Report ............................................................................................................................... 180 7 Technical data .................................................................................................................. 181 Chapter 15 Poles discordance protection ................................................................................ 183 1 Introdcution ....................................................................................................................... 184 2 Protection principle .......................................................................................................... 184
2.1 Function description ............................................................................................. 184 3 Logic diagram ................................................................................................................... 185 4 Input and output signals .................................................................................................. 186 5 Setting ............................................................................................................................... 187 6 Report ............................................................................................................................... 188 7 Technical data .................................................................................................................. 188 Chapter 16 Distance protection .............................................................................................. 189 1 Introdcution ....................................................................................................................... 190 2 Protection principle .......................................................................................................... 190
2.1 Function description ............................................................................................. 190 2.2 Auxiliary startup element ..................................................................................... 191
3 Logic diagram ................................................................................................................... 192 4 Input and output signals .................................................................................................. 192 5 Setting ............................................................................................................................... 193 6 Report ............................................................................................................................... 195 7 Technical data .................................................................................................................. 196 Chapter 17 Secondary system supervision .............................................................................. 197 1 VT failure supervision function ........................................................................................ 198 2 Function principle ............................................................................................................. 198 3 Input and output signals .................................................................................................. 201 4 Setting ............................................................................................................................... 202 5 Report ............................................................................................................................... 203 6 Technical data .................................................................................................................. 204 Chapter 18 External BIs to trip BOs ....................................................................................... 205 1 Introduction ....................................................................................................................... 206 2 Function principle ............................................................................................................. 206 3 BI Trigger Record ............................................................................................................. 207 4 BI Switch SetGroup ......................................................................................................... 208 5 BI “Blk Rem Access” and “RELAY TEST” ...................................................................... 208 6 BI “BI_Config1~ BI_Config2” and “BI TRIGGER DR1~ 10” ......................................... 209 7 Setting ............................................................................................................................... 209 Chapter 19 Station communication ......................................................................................... 211 1 Overview ........................................................................................................................... 212
1.1 Protocol ............................................................................................................... 212 1.1.1 LON communication protocol .................................................................... 212 1.1.2 IEC61850-8 communication protocol ....................................................... 212 1.1.3 IEC60870-5-103 communication protocol ............................................... 213
1.2 Communication port ............................................................................................ 213 1.2.1 Front communication port.......................................................................... 213
1.2.2 RS485 communication ports ..................................................................... 213 1.2.3 Ethernet communication ports .................................................................. 213
1.3 Technical data ...................................................................................................... 213 Front communication port .......................................................................................................... 214 RS485 communication port ........................................................................................................ 214 2 Typicalcommunication scheme ....................................................................................... 216
2.1 Typical substation communication scheme ........................................................... 216 2.2 Typical time synchronizing scheme ...................................................................... 216
Chapter 20 Hardware ............................................................................................................. 219 This chapter describes the IED hardware. ............................................................................ 219 1 Introduction ....................................................................................................................... 220
1.1 IED structure ....................................................................................................... 220 1.2 IED appearance.................................................................................................... 220 1.3 IED module arrangement ..................................................................................... 221 1.4 The rear view of the protection IED ..................................................................... 221
2 Local human-machine interface ..................................................................................... 222 2.1 Human machine interface ..................................................................................... 222 2.2 LCD .................................................................................................................... 223 2.3 Keypad ................................................................................................................ 223 2.4 Shortcut keys and functional keys ........................................................................ 224 2.5 LED ..................................................................................................................... 225 2.6 Front communication port .................................................................................... 226
3 Analog input module ........................................................................................................ 227 3.1 Introduction ......................................................................................................... 227 3.2 Terminals of Analogue Input Module (AIM) ........................................................ 227 3.3 Technical data ...................................................................................................... 229
3.3.1 Internal current transformer....................................................................... 229 3.3.2 Internal voltage transformer ...................................................................... 229
4 Communication module................................................................................................... 230 4.1 Introduction ......................................................................................................... 230 4.2 Substaion communication port ............................................................................. 230
4.2.1 RS232 communication ports ..................................................................... 230 4.2.2 RS485 communication ports ..................................................................... 230 4.2.3 Ethernet communication ports .................................................................. 230 4.2.4 Time synchronization port ......................................................................... 231
4.3 Terminals of Communication Module .................................................................. 231 4.4 Operating reports ................................................................................................. 232 4.5 Technical data ...................................................................................................... 232
4.5.1 Front communication port ......................................................................... 232 4.5.2 RS485 communication port ....................................................................... 233 4.5.3 Ethernet communication port .................................................................... 233 4.5.4 Time synchronization ................................................................................. 234
5 Binary input module ......................................................................................................... 235 5.1 Introduction ......................................................................................................... 235
5.2 Terminals of Binary Input Module (BIM) ............................................................. 235 5.3 Technical data ...................................................................................................... 237
6 Binary output module ....................................................................................................... 238 6.1 Introduction ......................................................................................................... 238 6.2 Terminals of Binary Output Module (BOM) ......................................................... 238
6.2.1 Binary Output Module A............................................................................. 238 6.2.2 Binary Output Module C ............................................................................ 241
6.3 Technical data ...................................................................................................... 243 7 Power supply module ...................................................................................................... 244
7.1 Introduction ......................................................................................................... 244 7.2 Terminals of Power Supply Module (PSM) .......................................................... 244 7.3 Technical data ...................................................................................................... 246
8 Terminal diagram ............................................................................................................. 247 8.1 Typical Terminal diagram of CSC-326 ................................................................. 247
9 Techinical data ................................................................................................................. 248 9.1 Basic data ............................................................................................................ 248
9.1.1 Frequency ................................................................................................... 248 9.1.2 Internal current transformer ....................................................................... 248 9.1.3 Internal voltage transformer ...................................................................... 248 9.1.4 Auxiliary voltage ......................................................................................... 248 9.1.5 Binary inputs ............................................................................................... 249 9.1.6 Binary outputs............................................................................................. 249
9.2 Type tests ............................................................................................................. 250 9.2.1 Product safety-related Tests ...................................................................... 250 9.2.2 Electromagnetic immunity tests ................................................................ 251 9.2.3 DC voltage interruption test ....................................................................... 253 9.2.4 Electromagnetic emission test .................................................................. 253 9.2.5 Mechanical tests ........................................................................................ 254 9.2.6 Climatic tests .............................................................................................. 255 9.2.7 CE Certificate ............................................................................................. 255
9.3 IED design ........................................................................................................... 255 Chapter 21 Appendix ............................................................................................................. 256 1 General setting list ........................................................................................................... 257
1.1 Function setting list .............................................................................................. 257 1.2 Binary setting list ................................................................................................. 276
2 General report list ............................................................................................................ 299 3 Time inverse characteristic ............................................................................................. 307
3.1 11 kinds of IEC and ANSI inverse time characteristic curves ................................ 307 3.2 User defined characteristic ................................................................................... 307
4 CT Requirement ............................................................................................................... 308 4.1 Overview ............................................................................................................. 308 4.2 Current transformer classification ......................................................................... 308 4.3 Abbreviations (according to IEC 60044-1, -6, as defined) ..................................... 309 4.4 General current transformer requirements ............................................................. 310
4.4.1 Protective checking current ....................................................................... 310 4.4.2 CT class ...................................................................................................... 311 4.4.3 Accuracy class ........................................................................................... 313 4.4.4 Ratio of CT ................................................................................................. 313 4.4.5 Rated secondary current ........................................................................... 313 4.4.6 Secondary burden...................................................................................... 313
4.5 Rated equivalent secondary e.m.f requirements .................................................... 314 4.5.1 Transformer differential protection ........................................................... 314
Chapter 1 Introduction
1
Chapter 1 Introduction
About this chapter This chapter gives an overview of SIFANG transformer pro-tection IED.
Chapter 1 Introduction
2
1 Overview It is selective, reliable and high speed IED (Intelligent Electronic Device) for transformer protection with powerful capabilities to cover following applications:
For large and medium two- or three-winding transformers, and au-totransformer
Used in a wide range of voltage levels, up to 1000kV
For single or multi-breaker arrangement
Up to 7 three-phase sets of CTs input (special ordering)
Work as main protection unit only or full functions unit for the complicated application
Communication with station automation system
The IED is able to provide all main protection functions and backup pro-tection functions in one case, including differential protection, restricted earth fault (REF), overexcitation, thermal overload, overcurrent, earth fault protection, etc.
The integrated flexible logic make the IED suitable to be applied to (au-to)transformers with all the possible vector groups, with/without earthing connection inside the protected zone.
The wide application flexibility makes the IED an excellent choice for both new installations and retrofitting of the existing stations.
.
Chapter 1 Introduction
3
2 Features Protection and monitoring IED with extensive functional library, user
configuration possibility and expandable hardware design to meet with user’s special requirements
Inter-lock between two CPU modules, avoiding mal-operation due to internal severe fault of one module
Transformer differential protection (87T)
Treble slope percent differential protection
Automatic CT ratio matching
Automatic vector group and zero sequence current compensation
Settable 2nd harmonic restraint function for transformer inrush
Fuzzy waveform recognition restraint function for transformer inrush
3rd or 5th harmonic restraint for overexcitation
CT saturation detection
CT secondarycircuit supervison
Differential current alarm
Restricted earth fault protection (87N)
Two slope percent REF protection
Automatic CT ratio matching
CT saturation recognition
REF differential current supervision
Positive sequence current blocking
A complete protection functions library, include:
Chapter 1 Introduction
4
Transformer differential protection (87T)
Restricted earth fault protection (87N)
Overcurrent protection (50, 51, 67)
Earth fault protection (50N, 51N, 67N)
Neutral earth fault protection (50G, 51G, 67G)
Thermal overload protection (49)
Overload protection (50OL)
Delta winding overload protection (50OL)
Overexcitation protection (24)
Overvoltage protection (59)
Circuit breaker failure protection (50BF)
Poles discordance protection (50PD)
Dead zone protection (50SH-Z)
Voltage transformer secondary circuit supervision (97FF)
Current transformer secondary circuit supervision
2 sets external trip commands (BIs → BOs)
Self-supervision to all modules in the IED
Complete information recording: tripping reports, alarm reports, startup reports and general operation reports. Any kinds of reports can be stored up to 2000 and be memorized in case of power disconnection
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
Chapter 1 Introduction
5
substation automation system by IEC60870-5-103 protocol
Time synchronization via network(SNTP), pulse and IRIG-B mode
Configurable LEDs and output relays satisfied users’ requirement
Versatile human-machine interface
Multifunctional software tool CSmart/CSPC for setting, monitoring, fault recording analysis, configuration, etc.
Chapter 1 Introduction
6
Protection functions
Description ANSI Code
IEC 61850
Logical Node
Name
IEC 60617
graphical symbol
Differential protection
Transformer differential protection 87T PDIF
Restricted earth fault protection 87N PDIF
Current protection
Overcurrent protection 50,51,67 PTOC
3IINV>
3I >>
3I >>>
Earth fault protection 50N, 51N, 67N PEFM
I0INV>
I0>>
I0>>>
Neutral earth fault protection 50G, 51G, 67G
Thermal overload protection 49 PTTR Ith
Overload protection 50OL PTOC 3I >OL
Delta Winding Overload Protection 50OL
Voltage protection
Overexcitation protection 24 PVPH U/f>
Overvoltage protection 59 PTOV 3U>
3U>>
Breaker protection and control function
Breaker failure protection 50BF RBRF
3I> BF
I0>BF
I2>BF
Dead zone protection 50SH-Z
Poles discordance protection 50PD RPLD
3I< PD
I0>PD
I2>PD
Secondary system supervision
CT secondary circuit supervision
VT secondary circuit supervision
Other functions
2 sets external trip commands (BIs →
BOs)
Chapter 1 Introduction
7
Monitoring functions
Description
Auxiliary contacts of circuit breaker supervision
Self-supervision
Fault recorder
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
Digital communication network through converter
IED software tools
Functions
Reading measuring value
Reading IED report
Setting
IED testing
Disturbance recording analysis
IED configuration
Printing
Chapter 1 Introduction
8
Chapter 2 Basic protection elements
9
Chapter 2 Basic protection elements
About this chapter
This chapter describes basic protection elements including startup elements, phase selectors and directional elements.
Chapter 2 Basic protection elements
10
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. The main startup element of CSC-326 is current sudden-change startup element(abrupt current), the backup startup element is diffrential current startup elment.
Startup element includes:
Current sudden-change startup element(abrupt current)
Differential current startup element
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:
_
( ) 2 ( ) ( 2 )startupi I
i i t i t T i t Tϕ
ϕ ϕ ϕ ϕ
∆ >∆ = − ∗ − + −
where
I_startup is a fix threshold value(IQd =0.2A when the secondary value of CT is 1A, and IQd =1A when secondary value of CT is 5A)
1.3 Differential current startup element
max _
max
_
, , ,
0.8 _
d diff startup
d d
diff startup
I I
I Max I a b c
I I percent diff
ϕ
ϕ ϕ ϕ
> = = =
where
I_diff startup is the startup threshold of differential protection, I_Percent Diff is a setting value, and Idφ is the phase differential current.
Chapter 2 Basic protection elements
11
2 Input and output signals
IA1
IB1
IC1
IA2
IB2
IC2
IA3
IB3
IC3
IA4
IB4
IC4
Relay Startup
IA5
IB5
IC5
Sudden-change current startup element
Figure 1 Sudden-change current startup element
Chapter 2 Basic protection elements
12
IA1
IB1
IC1
Differential current startup element
IA2
IB2
IC2
IA3
IB3
IC3
IA4
IB4
IC4
Relay Startup
IA5
IB5
IC5
Figure 2 Differential current startup element
Table 1 Analog input list
Signal Description
IA1 Phase A current input of 1st CT set IB1 Phase B current input of 1st CT set IC1 Phase C current input of 1st CT set IA2 Phase A current input of 2nd CT set IB2 Phase B current input of 2nd CT set IC2 Phase C current input of 2nd CT set IA3 Phase A current input of 3th CT set IB3 Phase B current input of 3th CT set IC3 Phase C current input of 3th CT set IA4 Phase A current input of 4th CT set IB4 Phase B current input of 4th CT set IC4 Phase C current input of 4th CT set IA5 Phase A current input of 5th CT set IB5 Phase B current input of 5th CT set IC5 Phase C current input of 5th CT set
Chapter 2 Basic protection elements
13
Table 2 Binary output list
Signal Description
Relay Startup Relay Startup
3 Settings Table 3 Settings of basic protection element
Setting Unit Min.
(Ir:5A/1A) Max.
(Ir:5A/1A)
Default setting
(Ir:5A/1A) Description
HV Wind Conn/Y-0 D-1
0 1 0
Connection for HV winding, 0:wye connection, 1:delta connection
MV Wind Conn/Y-0 D-1 (Only for three-winding transformers)
0 1 0
Connection for MV winding, 0:wye connection, 1:delta connection
LV Wind Conn/Y-0 D-1
0 1 1
Connection for LV winding, 0:wye connection, 1:delta connection
Vet Grp Angle 0 12 11
Vector Group Angle( VET GRP ANGLE)
SN MVA 1.000 3000. 120
Capacity of the transformer
HV VT Ratio 1.000 9999. 2200
Voltage transformer(VT) Ratio in HV side
HV CT Pri A 50.00 9999. 1200.0 CT Primary(PRI) current in HV side
HV CT Sec A 1.000 5.000 1.0 CT Secondary(SEC) current in HV side
HV Voltage Chan Sel
1 3 1 HV voltage channel location
MV Voltage Chan Sel
1 3 2 MV voltage channel location
Chapter 2 Basic protection elements
14
Setting Unit Min.
(Ir:5A/1A) Max.
(Ir:5A/1A)
Default setting
(Ir:5A/1A) Description
HV NCT Pri(REF) A 50.00 9999. 1200.0 Neutral CT (NCT) Primary(PRI) current in HV side for REF
HV NCT Sec(REF) A 1.000 5.000 1.0 Neutral CT (NCT) Secondary(SEC) current in HV side for REF
HV NCT Pri(BU) A 50.00 9999. 1200.0
Neutral CT (NCT) Primary(PRI) current in HV side for backup protection
HV NCT Sec(BU) A 1.000 5.000 1.0
Neutral CT (NCT) Secondary(PRI) current in HV side for backup protection
MV UN kV 1.000 1000. 110.0 Nominal voltage (UN) in Middle voltage (MV)side
MV VT Ratio 1.000 9999. 1100.0 Voltage transformer(VT) Ratio in MV side
MV CT Pri A 50.00 9999. 1200.0 CT Primary(PRI) current in MV side
MV CT Sec A 1.000 5.000 1.0 CT Secondary(SEC) current in MV side
MV NCT Pri(REF) A 50.00 9999. 1200.0 Neutral CT (NCT) Primary(PRI) current in MV side for REF
MV NCT Sec(REF) A 1.000 5.000 1.0 Neutral CT (NCT) Secondary(SEC) current in MV side for REF
MV NCT Pri(BU) A 50.00 9999. 1200.0
Neutral CT (NCT) Primary(PRI) current in MV side for backup protection
MV NCT Sec(BU) A 1.000 5.000 1.0
Neutral CT (NCT) Secondary(PRI) current in MV side for backup protection
LV UN kV 1.000 1000. 10.50 Nominal voltage (UN) in Low voltage (LV)side
LV VT Ratio 1.000 9999. 105.0 Voltage transformer(VT) Ratio in LV side
Chapter 2 Basic protection elements
15
Setting Unit Min.
(Ir:5A/1A) Max.
(Ir:5A/1A)
Default setting
(Ir:5A/1A) Description
LV CT Pri A 50.00 9999. 3000.0 CT Primary(PRI) current in LV side
LV CT Sec A 1.000 5.000 1.0 CT Secondary(SEC) current in LV side
LV Sec Inside Delta
A 1.000 5.000 1.0 CT Secondary(SEC) current in LV inside delta
HV Rated Cur Pri A 0 9999 - Rated primary current for HV side (calculated value, read only)
HV Rated Cur Sec A 0 9999 - Rated secondary current for HV side (calculated value, read only)
Ratio Factor KTAH 0 9999 - HV ratio factor for differ-ential protection (calcu-lated value, read only)
Ratio Factor KTAM 0 9999 - MV ratio factor for differ-ential protection (calcu-lated value, read only)
Ratio Factor KTAL 0 9999 - LV ratio factor for differ-ential protection (calcu-lated value, read only)
Ratio REF KTAH 0 9999 -
HV ratio factor, with ze-ro-sequence current calculated, for REF pro-tection (calculated val-ue, read only)
Ratio REF KNH 0 9999 -
HV ratio factor with ze-ro-sequence current di-rectly measured, for REF protection (calculated value, read only)
Ratio REF KTAM 0 9999 -
MV ratio factor, with ze-ro-sequence current calculated, for REF pro-tection (calculated val-ue, read only)
Ratio REF KNM 0 9999 -
MV ratio factor with ze-ro-sequence current di-rectly measured, for REF protection (calculated value, read only)
Chapter 2 Basic protection elements
16
Table 4 Binary settings of basic protection
Setting Unit Min. Max. Default setting
Description
Auto Trans 0 1 0
Autotransformer not common transformer 1-autotransformer ; 0- not autotransformer
Two-Wind Trans 0 1 0
Two-winding(TWO WIND ) not three -winding trans-former (TRANS) 1-two-winding trans; 0-three-winding trans
CT Fail Detect 0 1 0 VT Failure Detection On/Off 1-On, 0-Off.
4 Report Table 5 Event report list
Information Description
Relay startup The relay is initiated by startup elements
Chapter 3 Differential protection
17
Chapter 3 Differential protection
About this chapter This chapter describes the protection principle, input and output signals, parameter, IED report and technical data for differential protection function.
Chapter 3 Differential protection
18
1 Introduction The numerical current differential protection represents the main protec-tion function of the IED. It provides a fast short-circuit protection for power transformers. The protected zone is selectively limited by the CTs at its ends. The device is able to perform this function on 2 or 3 winding transformers in a variety of voltage levels and protected object types.
2 Applications The IED provides numerical differential protection function which can be used to protect power transformers in various configurations. For exam-ple, it is possible to use it for a two-winding transformer, three-winding transformer as well as auto-transformer. Examples for some of applica-tions are illustrated in the below figure.
A
B
C
HV LV1.AI
1.BI
1.CI
a
b
c
2.aI
2.bI
2.cI
CSC-326
Figure 3 Application of differential protection on a two-winding Yd transformer
Chapter 3 Differential protection
19
a
b
c
2.aI
2.bI
2.cI
A
B
C
CSC-326
1.AI
1.BI
1.CI
Figure 4 Application of differential protection on an auto transformer
A
B
C
HV
a
b
c
LV
CSC-326
1.AI
1.BI
1.CI
2.aI
2.bI
2.cI
Figure 5 Application of differential protection on a two-winding Yd
transformer with earthing transformer inside the protected zone
Chapter 3 Differential protection
20
A
B
C
HV
LV
1.AI
1.BI
1.CI
a
b
c
3.aI
3.bI
3.cI
CSC-326
a
b
c
2.aI
2.bI
2.cI
MV
Figure 6 Application of differential protection on a three-winding
Ydd transformer
3 Protection algorithm This section describes basic principle of differential protection function. First, the case of a single phase transformer with two windings is con-sidered. The basic principle is based on current comparison at two sides of the protected object. Indeed, the differential protection function makes use of the fact that a protected object carries always the same current at its two sides in healthy operation condition. This current flows into one side of the protected object and leaves it from the other side. A difference in currents is an indication of a fault within this section. An example of this condition is shown in below figure, when a fault inside the protected zone causes a current I1prim. + I2prim. flowing in from both sides of the protected object.
Chapter 3 Differential protection
21
Protected Zone
CT-1 CT-2Protected
Transformer
CSC-326
I1-prim. I2-prim.
I2I1
Figure 7 Basic principle of differential protection for two ends (single phase)
For protected objects with three or more sides, the basic principle is ex-panded in that the total of all currents flowing into the protected object is zero in healthy operation, whereas in case of a fault the total in-flowing current is equal to the fault current.
When an external fault causes a heavy current to flow through the pro-tected transformer, differences in the magnetic characteristics of the current transformers CT-1 and CT-2 under saturation condition may cause a significant difference in the secondary currents I1 + I2 connected to IED. If the difference is greater than the pickup threshold, the differen-tial protection function can trip even though no fault occurred in the pro-tected zone. To prevent the protection function from such erroneous op-eration, a restraint (stabilizing) current is brought in. For differential pro-tection IED, the restraint current is normally derived from the I1 and I2. The next subsection goes on to demonstrate how the differential and re-straint currents are calculated.
3.1 Differential and restraint current calculation
The differential current Idiff and the restraining current Ires are calculated by the following equation. The following definitions apply for each phase of the protected object.
≠−=
=
∑
∑−
=
••
=
•
1
1(max)
1
)(21 N
iijres
N
iidiff
jiIII
II
Chapter 3 Differential protection
22
Equation 1
Where iI is the current vector of side i, corresponding to HV, MV and LV
windings; N is total current inputs of the IED. In other words, it is number
of the protected object sides; (max)I j is the maximum current vector
among the N current inputs of the IED, suppose it is side j; 1
( )1
NI i ji
i
− •∑ ≠=
is
the sum of the other current inputs of the IED, not including side j. Idiff is derived from the fundamental frequency current and produces the trip-ping effect quantity, whereas Ires counteracts this effect. To clarify the situation, three important operating conditions with ideal and matched measurement qualities are examined.
(a) External fault under undisturbed conditions:
I1 flows into the protected zone, I2 leaves the protected zone, i.e. is negative according to the definition of signs, therefore I2 = –I1.
Idiff = I1 + I2 = I1 – I1 = 0
Ires = 0.5×| I1 - (–I1) | = 0.5×|2I1| = |I1|
No tripping effect (Idiff = 0); the restraint (Ires) corresponds to the exter-nal fault current flowing through the protected object.
(b) Internal fault, fed with equal currents from both sides:
The following applies I2 = I1
Idiff = I1 + I2 = I1 + I1 = 2 I1
Ires = 0.5×| I1 - I1| = 0
Tripping effect (Idiff) corresponds to double the fault current, and restraint value (Ires) are equal to zero.
(c) Internal fault, fed from one side only:
The following applies when assuming I2 = 0
Idiff = I1 + I2 = I1 + 0 = I1
Chapter 3 Differential protection
23
Ires = 0.5×|I1 - I2| =0.5× |I1 - 0| = 0.5×|I1|=0.5 I1
Tripping quantity (Idiff) and restraint quantity (Ires) are equal and corre-spond to the single-sided fault current.
The results show that the device is capable to properly discriminate in-ternal and external faults by using the definitions proposed for differential and restraint current. However, the device is still subjected to some in-fluences that induce differential currents even during normal operation condition. These influences should be compensated in appropriate manners. The specific treatments designed to cope with these influences includes automatic ratio compensation and automatic vector group compensation which are explored in the next subsections.
3.2 Automatic Ratio compensation
Differential protection of power transformers represents some problems in the application of current transformers. CTs should be matched to the current rating of each transformer winding, so that normal current through the power transformer is equal on the secondary side of the CT on dif-ferent windings. However, because only standard CT ratios are available, this matching may not be exact. As a result, the secondary currents of the current transformers are not generally equal when a current flows through the power transformer. The difference between the currents flowing through CTs’ secondary circuit depends on the transformation ra-tio of the protected power transformer, as well as the rated currents of the current transformers. Therefore, the currents should be matched in order to become comparable. To do so, the input currents of the IED are con-verted in relation to the power transformer rated currents. This is achieved by entering the characteristic values of the power transformer (i.e. rated apparent power and rated voltages) and primary rated currents of CTs into the IED by using user-entered settings. As a result, matching to various power transformer and current transformer ratios is performed purely mathematically inside the device. Therefore, no external matching transformer is required. In this context, the rated primary current of each side, I1N, is calculated automatically according to below equation.
Chapter 3 Differential protection
24
N
NN
US
I1
13
=
Equation 2
Where SN is rated apparent power of the transformer and U1N is rated voltage of the corresponding side.
The rated secondary current of each side, I2N, is then calculated.
CT
NN n
II 12 =
Equation 3
Rated secondary current of the high voltage side is then taken as the reference current. The currents of the other sides are automatically matched to the rated current of the high voltage side by calculation of correction factor KCT for MV and LV side, according to below equations, respectively:
HVCT
MVCT
HVN
MVN
HVCT
MVCT
MVNN
HVNN
MVCTMVN
HVCTHVN
MVN
HVNMVCT n
nUU
nn
USUS
nInI
II
K−
−
−
−
−
−
−
−
−−
−−
−
−− ⋅=⋅===
1
1
1
1
1
1
2
2
3/3/
//
Equation 4
HVCT
LVCT
HVN
LVN
HVCT
LVCT
LVNN
HVNN
LVCTLVN
HVCTHVN
LVN
HVNLVCT n
nUU
nn
USUS
nInI
II
K−
−
−
−
−
−
−
−
−−
−−
−
−− ⋅=⋅===
1
1
1
1
1
1
2
2
3/3/
//
Equation 5
Where KCT-MV is the correction factor for middle voltage side and KCT-LV is the correction factor for Low voltage side,
I1N is the primary rated current of the transformer (I1N-HV for high volt-age side, I1N-MV for middle voltage side and I1N-LV for low voltage
Chapter 3 Differential protection
25
side),
I2N is the secondary rated current of the transformer (I2N-HV for high voltage side, I2N-MV for middle voltage side, I2N-LV for low voltage side),
nCT is CT ratio of the transformer (nCT-HV for high voltage side, nCT-MV for middle voltage side, nCT-LV for low voltage side),
U1N is rated voltage of the transformer (U1N-HV for high voltage side, U1N-MV for middle voltage side, U1N-LV for low voltage side).
As mentioned previously, all of the calculations are automatically per-formed inside the IED by its CPU. The related settings can be found under the menu “Test Menu”.
Below figure shows an example of automatic ratio compensation in case of a two-winding transformer. The primary nominal currents of the HV and LV sides, (I1N = 402A, I2N= 1466A) are calculated from the rated ap-parent power of the transformer (160MVA) and the nominal voltages of each side (230kV and 63kV). Since the nominal currents of the current transformers deviate from the nominal currents of the power transformer sides, the secondary current of LV side is multiplied with the factor KCT-LV. Subsequent to this matching, equal current magnitudes are achieved at both sides under nominal conditions of the power transform-er.
CTRATIO=500/1A
SN=160MVA
CTRATIO=2000/1A
U1N-LV=63kVU1N-HV=230kV
Figure 8 Example of automatic ratio compensation in a two-winding transformer
1160
4023 230
− =×
=N HVMVA
I A
An
II
CT
HVNHVN 804.0
5004021
2 === −−
AMVAI LVN 1466
633160
1 =×
=−
Chapter 3 Differential protection
26
AI LVN 733.020001466
2 ==−
097.1733.0804.0
==−LVCTK
Concerning three-winding power transformers, the windings may have different power ratings. In order to compare secondary currents in an appropriate manner, all currents are matched to the rated secondary current of HV winding having highest power rating. This apparent power is nominated as the rated apparent power of the transformer.
Below figure shows an example of a three-winding power transformer. HV winding and MV winding are rated for 160MVA. The rated primary and secondary currents of these windings are calculated as shown in previous example. However, the LV winding has 25MVA rating (e.g. for auxiliary supply). The rated current of this winding may result in 721A. However, differential protection has to process comparable currents. Therefore, the currents of LV winding should be referred to the rated apparent power of the transformer, i.e. 160MVA. This results in a rated current of 4619A. This is the base value for the LV winding, which should be further multiplied by KCT-LV to be used in calculation process of dif-ferential protection.
CTRATIO=2000/1A
160MVA 160MVA
25MVA
CTRATIO=500/1A
CTRATIO=2500/1A
U1N-MV=63kVU1N-HV=230kV
U1N-LV=20kV
Figure 9 Example of automatic ratio compensation in a three-winding transformer
AMVAI LVN 4619203
1601 =
×=−
A
nI
ICT
LVNHVN 848.1
250046191
2 === −−
435.0
848.1804.0
==−LVCTK
If a three-winding transformer with a delta LV winding (with no CB in-
Chapter 3 Differential protection
27
stalled) is used to supply substation LVAC loads, it may be desired that LV current should not be integrated in differential protection. In this case, Binary setting “Diff Includes LV Cur” is used to select whether LV current should be included in differential protection calculation procedure or not. By applying setting “Diff Includes LV Cur” to 0, only HV and MV currents would be included in differential protection calculation. On the contrary, when a three-winding transformer is equipped with three CBs in its sides, it may be desired to include LV current in differential protection. This can be achieved by applying setting “Diff Includes LV Cur” to 1 to respective Binary setting.
3.3 Automatic Vector group and zero sequence
current compensation
Transformers have different vector groups, which cause a shift of the phase angles between the primary and the secondary side. Without ad-equate correction, this phase shift would cause a false differential current. Furthermore, the conditioning of the starpoint(s) of the power transformer has a great impact on the resulting differential current during through fault currents.
The IED removes this problem. To do so, all CTs at the power trans-former are connected Wye (polarity markings pointing away from the transformer). User-entered settings in the relay are then used to char-acterize the power transformer and allow the relay to automatically per-form all necessary phase angles, and zero sequence compensation. This section describes the procedures that perform this compensation inside the relay and produce the required calculated quantities for transformer differential protection. The phase angle compensation as well as zero sequence current elimination procedure is performed by programmed coefficient matrices which are capable to simulate the difference in phase angle of currents flowing through transformer windings. Thus, compen-sation is possible for the entire commonly used transformer vector groups. This simplifies application of the IED in various configurations, if the setting corresponding to vector Group Angle, “Vet Grp Angle”, is properly entered into the device, together with the settings for connection type of transformer windings in each side, “HV WIND CONN/Y-0 D-1”, “MV WIND CONN/Y-0 D-1”, “LV WIND CONN/Y-0 D-1”, which could be set to 1-delta or 0-wye. The basic principle of numerical vector group and zero-sequence compensation is shown through some examples. A through review of all possible connection groups as well as device treatment in each case is explored in Appendix.
Chapter 3 Differential protection
28
(1). Take example for Yy0 connection, including similar ones of Yy0 (separate or auto-connected windings), YNy0, Yyn0, YNyn0 (separate or auto-connected windings) and so on. Below figure shows an example in case of Yy0 connection group with no earthed starpoint. The figure shows the windings (left) and the vector diagrams of symmetrical cur-rents (right).
Yy0
C
c
A B
a b
A
BC
a
c b
Figure 10 Vector Group and zero sequence compensation for Yy0 transformer
The equations including the coefficient matrix are as follow:
1 -1 01 0 1 -13 -1 0 1
A A
B B
C C
I II II I
′ ′ = ⋅ ⋅ ′
Equation 6
1 -1 01 0 1 -13 -1 0 1
a a
b b
c c
I I
I I
I I
′ ′ = ⋅ ⋅ ′
Equation 7
According to these matrices, if we deduct side 1 currents BAI - I , the re-
sulting current AI ¢ has the same direction as AI ¢ on side 2. Multiplying it
Chapter 3 Differential protection
29
with1 3 , matches the absolute value. The matrices describe the con-
version for all three phases. Using these matrices, the elimination of zero sequence currents are warranted regardless of starpoint earth connec-tion.
As mentioned previously, the two above equations can be used similarly for auto-transformers, as the auto-connected windings in au-to-transformers can only be connected Y(N)y(n)0. If the starpoint is earthed, both the auto-connected HV and LV windings are affected. The zero sequence components in current flowing through both sides of the transformer are then coupled because of the common starpoint. These zero sequence components are eliminated by the application of the ma-trices presented in the above equations.
(2). Take example for Yd1 connection, including similar ones of Yd1 and YNd1 without earthing transformer installed at delta side. Below figure shows an example in case of Yd1 connection group with no earthed starpoint.
Yd1
A B C
a cb
BC
c
A
b
a
Figure 11 Vector Group compensation for Yd1 transformer
Chapter 3 Differential protection
30
The equation including the coefficient matrix is as follows:
1 0 -11 -1 1 03 0 -1 1
A A
B B
C C
I II II I
′ ′ = ⋅ ⋅ ′
Equation 8
If an earthing transformer/reactor is installed inside the protected zone on delta side, the IED should be informed about it by Binary setting “HV D_side Eliminate I0”, “MV D_side Eliminate I0” or “LV D_side Eliminate I0”. The Binary setting related to delta side with earthing connection should be set to “1-eliminate” in such condition. By taking example for Yd1 connection with earthing transformer installed at delta side, Binary setting “LV D_side Eliminate I0” is set to “1-eliminate”, and thus, device performs a zero sequence current elimination on delta side. In this case, the equations including the coefficient matrices are as follow:
1 0 -11 -1 1 03 0 -1 1
A A
B B
C C
I II II I
′ ′ = ⋅ ⋅ ′
Equation 9
−−−−−−
=
′
′
′
•
•
•
•
•
•
c
b
a
c
b
a
I
I
I
I
I
I
.211121112
.31
Equation 10
(3). Take example for Ydd3 connection, including similar ones of Ydd3 and YNdd3 without earthing transformer installed at delta sides. Below figure shows an example in case of Ydd3 connection group with no earthed starpoint in Wye side.
Chapter 3 Differential protection
31
Ydd3
A B C
ac b
BC
c(c’)
A
b(b’)
a(a’)
a'c' b'
Figure 12 Vector Group compensation for Ydd3 transformer
The equation including the coefficient matrix is as follows:
0 1 -11 -1 0 13 1 -1 0
A A
B B
C C
I II II I
′ ′ = ⋅ ⋅ ′
Equation 11
(4). Take example for Yd5 connection, including similar ones of Yd5 and YNd5 with earthing transformer installed at delta side. Below figure shows an example in case of Yd5 connection group with no earthed starpoint.
Chapter 3 Differential protection
32
Yd5
A B C
c ba
BC
b
A
a
c
Figure 13 Vector Group compensation for Yd5 transformer
By setting binary setting “LV D_side Eliminate I0” to “1-eliminate”, the equations including the coefficient matrices are as follow:
-1 1 01 0 -1 13 1 0 -1
A A
B B
C C
I II II I
′ ′ = ⋅ ⋅ ′
Equation 12
2 1 11 . 1 2 1 .3
1 1 2
a a
b b
cc
I II I
II
· ·
· ·
· ·
é ù é ù¢ê ú é ù ê ú- -ê ú ê ú ê úê ú ê ú ê ú¢ = - -ê ú ê ú ê úê ú ê ú ê ú- -¢ê ú ë û ê úê ú ë ûë û
Equation 13
(5). Take example for Dy1 connection, including similar ones of Dy1 and Dyn1 without earthing transformer installed at delta side. Below figure shows an example in case of Dy1 connection group with no earthed starpoint.
Chapter 3 Differential protection
33
Dy1
A B C
a b c
BC
c
A
b
a
Figure 14 Vector Group compensation for Dy1 transformer
The equation including the coefficient matrix is as follows:
1 -1 01 0 1 -13 -1 0 1
a a
b b
c c
I I
I I
I I
′ ′ = ⋅ ⋅ ′
Equation 14
If an earthing transformer/reactor is installed inside the protected zone on delta side, binary setting “HV D_side Eliminate I0” is set to “1-eliminate”, and thus, device performs a zero sequence current elimination on delta side. In this case, the equations including the coefficient matrices are as follow:
2 1 11 . 1 2 1 .3
1 1 2
A A
B B
CC
I II I
II
· ·
· ·
· ·
é ù é ù¢ê ú é ù ê ú- -ê ú ê ú ê úê ú ê ú ê ú¢ = - -ê ú ê ú ê úê ú ê ú ê ú- -¢ ë ûê ú ê úê ú ë ûë û
Equation 15
Chapter 3 Differential protection
34
1 -1 01 0 1 -13 -1 0 1
a a
b b
c c
I I
I I
I I
′ ′ = ⋅ ⋅ ′
Equation 16
Subsequent to application of the magnitude, vector group and zero se-quence compensation, the IED use the following calculated quantities (per phase) to discriminate between internal and external faults: funda-mental component of differential and restraint currents together with in-stantaneous value, 2nd and 5th harmonic contents of differential current. The following sections go on to demonstrate the fault recognition criteria using these derived quantities.
4 Protection principle
4.1 Instantaneous differential protection
characteristic
An instantaneous (unrestrained) differential characteristic which entails an overcurrent protection is provided for fast tripping on heavy internal faults. The characteristics can be enabled or disabled by using Binary setting “Func_Inst Diff” (1-on, 0-off). If setting “1-on” is selected, a trip signal is issued regardless of the magnitude of the restraining current, as soon as the differential current rises above the threshold ID>> (setting " I_Inst Diff "). The generated trip signal is phase selective. it means that the device issues event reports “Inst Diff Trip A”, “Inst Diff Trip B” or “Inst Diff Trip C”, when the calculated differential current in phase A, B or C exceeds the threshold ID>> (setting " I_Inst Diff "). The purpose of this stage of differential protection is extremely fast operation in case of high magnitude internal fault currents. This is always the case when the short circuit current is higher than IN/Uk%, which indicates a fault inside the power transformer. It should be noted that the magnitude of through fault currents are always lower than IN/Uk%, when they are supplied via power transformer. (In this equation, IN is nominal current and Uk% is short circuit voltage of the power transformer.)
The logic diagram of instantaneous differential protection is shown in below figure.
Chapter 3 Differential protection
35
Func_Inst Diff on
Ia>I_Inst DiffINST DIFF TripAAND
Ib>I_Inst Diff
Ib>I_Inst Diff
AND
AND
INST DIFF TripB
INST DIFF TripC
“1”
Figure 15 Tripping logic of the instantaneous differential protection
As mentioned previously and can be seen from the figure, the stage op-erates as an unrestrained protection function. In other words, it is not in-hibited by any of harmonic stabilization features of the percent differential element as well as the CT failure detection. This means that it can oper-ate even when, for example, a considerable second harmonic is present in the differential current, which is caused by current transformer satura-tion by a DC component in the fault current, and which could be inter-preted by the inrush inhibit function as an inrush current.
This high current stage evaluates the fundamental component of the dif-ferential current as well as the instantaneous values. Instantaneous value processing ensures fast tripping even in case the fundamental compo-nent of the current is strongly reduced by current transformer saturation. Fast trip area is shown in Figure 16.
4.2 Treble slope percent differential protection
characteristic
The percent differential protection uses a treble-slope dual break-point operating characteristic with magnetizing inrush and overexcitation and CT failure detection inhibits integrated. The treble slope characteristics can be enabled or disabled by using Binary setting “Func_Percent Diff” (1-on, 0-off). If setting 1-on is selected, the stage calculates differential and restraint current separately in each phase to obtain operating point in each operation condition. The derived point is then mapped into Idiff-Ires plane to examine whether it lies in trip or block area which is defined according to predefined operating characteristic. The operation charac-teristic is shown in below figure.
Chapter 3 Differential protection
36
I_ResPoint1 Diff
I_Percent Diff
IDiff
IRest
Restraint current
Diff
eren
tial c
urre
nt
Slope 3
Slope 2
Slope 1
Trip area
block area
I_Inst DiffFast trip area
I_ResPoint2 Diff
Figure 16 Differential protection characteristics for transformers
In this characteristic, branch 1 represents the sensitivity threshold of the differential protection. The setting of ID> (setting "I_Percent Diff") defines the minimum differential current required for operation. The setting is chosen based on the amount of differential current that might be seen under normal operating conditions which corresponds to constant error currents such as magnetizing currents and CT errors under no-load con-ditions. The setting for slope of branch 1 is applicable for restraint cur-rents of zero to the first break-point indicated on restraint axis (setting "I_ResPoint1 Diff"). The slope (setting “Slope1_Diff”) defines the ratio of differential to restraint current above which the percent differential stage will operate. The first break-point on restraint axis defines the end of the slope 1 region and the start of the second branch region. This setting should be set just above the maximum operating current level of the transformer. This level is somewhere between the maximum forced-cooled rated current of the transformer and the maximum emer-gency overload current level.
Branch 2 considers current-proportional errors which may result from transformation errors of the main CTs or the input CTs of the relay. This may also contain the error caused by the influence of tap changers in power transformers with voltage control. The setting for slope of branch 2 (setting “Slope2_Diff”) is applicable for restraint currents of the first break-point to the second one on restraint axis, and defines the ratio of differential to restraint current above which the element will operate. This slope is set to ensure sensitivity to internal faults at normal operating current levels. The second break-point on restraint axis (setting “I_ResPoint2 Diff”) defines the end of the slope 2 region and the begin-ning of the slope 3 region. This setting should be set to the level at which
Chapter 3 Differential protection
37
any of the protection CTs is probable to saturate.
In the range of high through fault currents which may give rise to high differential currents as a result of CT saturation, branch 3 is applicable to provide additional stabilization. The setting for the slope of this branch (setting “Slope3_Diff”) is applicable up to the point at which the branch intersects the characteristic of instantaneous differential protection.
As a summary of the fault detection using operating characteristics of the above figure, the calculated differential and restraint currents, IDiff and IRest, are compared by the differential protection with the operating characteristic according to the following formula ,
1 1
2 1 1 1 1 2
3 2 2 2 1 1 1 2
( )
( ) ( )
diff res D res R
diff res R R D R res R
diff res R R R R D R res
I S I I I II S I I S I I I I II S I I S I I S I I I I
>
>
>
≥ + ≤
≥ − + × + < ≤ ≥ − + − + × + <
Equation 17
Where S1 is the slope of the branch 1 (setting “Slope1_Diff”),
S2 is the slope of the branch 2, (setting “Slope2_Diff”),
S3 is the slope of the branch 3, (setting “Slope3_Diff”),
ID> is the setting for the sensitivity threshold of the differential protection, (setting “I_Percent Diff”),
IR1 is the setting for the first breakpoint restraint current, (setting “I_ResPoint1 Diff”),
IR2 is the setting for the second breakpoint restraint current, (setting “I_ResPoint2 Diff”).
If the operating point calculated from the quantities of differential and re-straint current falls into the trip area, a trip signal is issued by the percent differential protection. The issued signals are phase selective. They can be found in event report as “Per Diff Trip A”, “Per Diff Trip B” and “Per Diff Trip C”.
This stage cannot operate when there is an inrush or overexcitation sta-bilization or a restraint due to CT failure detection. This is illustrated in
Chapter 3 Differential protection
38
below logic diagram.
ID>
Phase-A
PER DIFF Trip A
PER DIFF Trip B
PER DIFF Trip C
AND
ID>
Phase-B
ID>
Phase-C
ArestAdiff II −− ,
BrestBdiff II −− ,
CrestCdiff II −− ,
AND
PER DIFF BLK A
PER DIFF BLK B
PER DIFF BLK C
CT FAIL
AND
Func_Percent Diff on
Block Diff at CT_Fail on
“1”
Figure 17 Tripping logic of the percent differential protection
It should be noted that when the IED is delivered, both the instantaneous and percent differential protection functions are switched off. Setting of “0-off” is applied for Binary settings “Func_Inst Diff” and “Func_Percent Diff”. This is because the fact that these protection functions should not be used before at least the vector group and other essential parameters for each side is correctly set. Without these settings the equipment may show unpredictable behavior. (E.g. tripping)
4.3 Selective inrush stabilization schemes
In power transformers, high short-time magnetizing currents may be present during power-up (inrush currents). The inrush current can amount to a multiple of the rated current. These currents enter the pro-tected zone. However, it does not exit again. They thus produce differen-tial quantities, as they seem like single-end fed fault currents. Therefore, they should be recognized in an appropriate manner. By this way, it is possible to prevent false operation of differential protection caused by inrush current. This possibility is provided in the IED. Selective inrush stabilization can be enabled or disabled by Binary setting “Block Diff at Inrush”, (1-Block, 0-Not Block). If setting “1-Block” is applied, the function monitors differential current to detect an inrush condition. If the condition
Chapter 3 Differential protection
39
is detected, it is possible to block differential protection phase-selectively. Furthermore, alarm report entitled “Diff 2har Blk” is issued whenever in-rush detection impose a blocking condition to differential protection. It should be noted that the latter, is generated when any condition (2nd harmonic, 3rd/5th harmonic, CT fail) leads to blocking of differential pro-tection.
The IED provides two schemes to detect inrush conditions. The first scheme is 2nd harmonic stabilization; the second scheme is fuzzy recognition of inrush conditions based on the waveform. The two schemes are convenient for user to be selected by the setting “2nd HAR NOT WAVE” (1-2nd harmonic on; 0-waveform on). The two implemented algorithm work alternatively. As soon as an inrush condition is recognized by each of them, a restraint condition is applied to the respective phase evaluation of percent differential protection. Since the applied restraint by 2nd harmonic detection operates individually per phase, the protection is fully operative even when the protected transformer is switched onto a single-phase fault, whereas inrush currents may possibly be present in one of the healthy phases. It is, however, possible to set the protection in a way that when the 2nd harmonic recognition is fulfilled only in one sin-gle phase, not only the phase with the inrush current, but also the re-maining phases of the percent differential protection are blocked. This is achieved by cross-blocking the differential protection for a certain period to avoid spurious tripping. The setting corresponds to “T_2nd Harm Block”. Within this time, all three phases are blocked as soon as an in-rush current is detected in any one phase. After the timer is expired, only the phase with inrush current content is blocked.
4.3.1 2nd harmonic stabilization
By selecting “1-Block” for control-word “Block Diff at Inrush” and select-ing“1-2nd harmonic” for Binary setting “2nd HAR NOT WAVE”, inrush current is recognized if the second harmonic content in the differential current exceeds a selectable threshold (setting “Ratio_2nd Harm”). The ratio between the 2nd harmonic and the fundamental frequency compo-nent is decisive to discriminate inrush conditions from the other operation conditions. The ratio is calculated by the below equation. As soon as the measured ratio exceeds the set thresholds, a restraint is applied to the percent differential protection in respective phase.
Chapter 3 Differential protection
40
22
ϕφ
φ KII
diff
diff >−
−
Equation 18
Where Idiff-φ2 is 2nd harmonics magnitude of differential current, Kφ2 is the setting for 2nd harmonics ratio, Idiff-φ is fundamental frequency component of differential current.
4.3.2 Fuzzy recognition of inrush based on the waveform
By selecting “1-block” in control-word “Block Diff at Inrush”, and selecting “0-waveform on” for Binary setting “2nd HAR NOT WAVE”, inrush current is detected by a fuzzy recognition method based on waveform. In this context, differential current waveform is sampled in each phase by 2n number of samples per cycle, each of the samples is nominated as I(k), k=1, 2, …, 2n. Then the value of X(k) is calculated according to the below equation.
nknkIkInkIkI
kX ,...,2,1,)()()()(
)( =++
++=
Equation 19
The smaller values of X(k) represent that the calculated point corre-sponds to fault condition with higher confidence level. Alternatively, the larger values of X(k) gives a picture that there is large content of inrush current in the waveform. Assume that X(k) belongs to “inrush Fuzzy class” with membership function of A[X(k)]. Then, the fuzzy similarity co-efficient for the n calculated values of X(k) in one cycle is defined as be-low equation.
∑=
=n
k
nkXAN1
/)]([
Equation 20
The derived value of N is used in the IED to assess the differential cur-rent corresponds to inrush condition or not. To do so, the value of N is compared with a threshold K, and inrush content is recognized in the
Chapter 3 Differential protection
41
current waveform, if N>K.
22
ϕφ
φ KII
Adiff
Adiff >−−
−−
22
ϕφ
φ KII
Bdiff
Bdiff >−−
−−
22
ϕφ
φ KII
Cdiff
Cdiff >−−
−−
OR
OR
OR
PER DIFF BLK A
PER DIFF BLK B
PER DIFF BLK C
AND
AND
AND
Func_Percent Diff on
2nd Harm Not Wave on
2nd Harm Not Wave on
2nd Harm Not Wave on
Block Diff at Inrush on
Block Diff at Inrush on
Block Diff at Inrush on
T_2nd Harm Block
T_2nd Harm Block
T_2nd Harm Block
“1”
Figure 18 logic diagram of inrush stabilization schemes by 2nd harmonic
Fuzzy Inrush Recognition in Ph-A
Fuzzy Inrush Recognition in Ph-B
Fuzzy Inrush Recognition in Ph-C
2nd Harm Not Wave offPER DIFF BLK A
PER DIFF BLK B
PER DIFF BLK C
AND
AND
AND
Func_Percent Diff on
Block Diff at Inrush on
Block Diff at Inrush on
Block Diff at Inrush on
T_2nd Harm Block
T_2nd Harm Block
T_2nd Harm Block
2nd Harm Not Wave off
2nd Harm Not Wave off
“1”
Figure 19 logic diagram of inrush stabilization schemes by fuzzy recognition
4.4 Overexcitation stabilization
Apart from the second harmonic, other harmonic contents can be se-lected in the IED to cause stabilization of percent differential protection. This is because the fact that unwanted differential currents caused by
Chapter 3 Differential protection
42
transformer overexcitation may result in false tripping of the percent dif-ferential protection. Since steady state overexcitation is characterized by odd harmonics, the 3rd or the 5th harmonic can be selected in the IED to judge for overexcitation stabilization. If it is desired to impose a blocking condition to percent differential protection by these harmonics, Binary setting “Block Diff at Overexcit” should be set to “1-on”. By applying this setting, alarm report entitled “Diff 3/5har Blk” is issued whenever 3rd or 5th harmonic detection impose a blocking condition to differential protec-tion. It should be noted that the latter, is generated when any condition (2nd harmonic, 3rd/5th harmonic, CT fail) leads to blocking of differential protection.
It is possible to use Binary setting “Overexcitation 3rd NOT 5th” to select whether 3rd or 5th harmonic detection is utilized for detection of overex-citation condition (1-3rd harmonic, 0-5th harmonic). Since the third har-monic is often eliminated in delta winding of power transformers, the fifth harmonic is more commonly used.
Similar to the 2nd harmonic stabilization, the applied restraint by 3rd or 5th harmonic detection operates individually per phase. It is, however, possible to set the protection in a way that when the 3rd or 5th harmonic recognition is fulfilled only in one single phase, not only the phase with the inrush current, but also the remaining phases of the percent differen-tial protection are blocked. This is achieved by cross-blocking the differ-ential protection for a certain period to avoid spurious tripping. The set-ting corresponds to “T_3/5th Harm Block”. Within this time, all three phases are blocked as soon as an 3rd or 5th harmonic is detected in any one phase. After the timer is expired, only the phase with 3rd or 5th harmonic content is blocked.
The detection method used for 3rd or 5th harmonic is similar to those applied for 2nd harmonic. However, setting “Ratio_3/5th Harm” is deci-sive in this case. It means that 3rd or 5th harmonic is recognized if the ratio between third or fifth harmonic and the fundamental frequency component of the differential current exceeds the setting threshold. The ratio is calculated by the below equation.
5/35/3
ϕφ
φ KI
I
diff
diff >−
−
Equation 21
Where Idiff-φ3/5 is 3rd/5th harmonic magnitude of differential current,
Chapter 3 Differential protection
43
Kφ3/5 is the setting for 3rd/5th harmonic ratio, Idiff-φ is fundamental frequency component of differential current. Below figure show logic di-agram of overexcitation stabilization.
Overexcit 3rd NOT 5th off OR
OR
OR
PER DIFF BLK A
PER DIFF BLK B
PER DIFF BLK C
AND
AND
AND
Block Diff at Overexcit on
Overexcit 3rd NOT 5th on
OR
OR
OR
T_3/5th Harm Block
T_3/5th Harm Block
T_3/5th Harm Block
5/33
−−−
−− > ϕφ
φ KII
Adiff
Adiff
5/35
−−−
−− > ϕφ
φ KII
Adiff
Adiff
5/33
−−−
−− > ϕφ
φ KII
Bdiff
Bdiff
5/35
−−−
−− > ϕφ
φ KII
Bdiff
Bdiff
5/33
−−−
−− > ϕφ
φ KII
Cdiff
Cdiff
5/35
−−−
−− > ϕφ
φ KII
Cdiff
Cdiff
“1”
Overexcit 3rd NOT 5th off
Overexcit 3rd NOT 5th on
Overexcit 3rd NOT 5th off
Overexcit 3rd NOT 5th on
Figure 20 logic diagram of overexcitation stabilization
Chapter 3 Differential protection
44
4.5 CT Failure supervision
During steady-state operation, the CT failure supervision monitors the transient behavior of the currents flowing through secondary circuit of each phase and thus registers failures in the secondary circuit of the current transformers for each side of the power transformer. The function can be enabled or disabled by using setting “CT Fail Detect” (1-On, 0-Off). If setting “1-On” is applied, IED issues the alarm report “Ph_A CT Fail”, “Ph_B CT Fail”, “Ph_C CT Fail”, whenever a CT failure is detected. It is also possible to set differential protection to be blocked or not at CT fail-ure detection through setting "Block Diff at CT_Fail" (1-Block, 0-Not Block). By setting “1-Block”, the percent differential protection is blocked immediately in all phases. Blocking condition is cancelled as soon as the device is again supplied with a normal current in the relevant faulty phase(s). It should be noted that the setting "Block Diff at CT_Fail" is not useful if the differential current is very high (more than 1.2 Ie, Ie is the rated current of high voltage side). In other words, blocking conditions takes place only for treble slope percent differential protection. This means that the instantaneous differential protection will issue trip if a dif-ferential current greater than setting “I_Inst Diff” is present, even if " Block Diff at CT_Fail " is set to 1-Block.
The criteria for CT failure detection are as follow:
The currents flowing through all three phases of CT secondary are nor-mal at each side of the protected object. As a result, the differential cur-rent is near to zero. When one or two phase current of one side is de-creased to less than a threshold (half of the memory current), at the same time all three phase currents in other side(s) are normal, and dif-ferential current is more than a threshold (>0.3I_Percent Diff) at least in one phase, the condition maybe an indication of CT failure in the muta-tive phase(s). CT failure detection logic is illustrated in below figure.
Chapter 3 Differential protection
45
CT Fail
OR
Max {Idiff_A, Idiff_B, Idiff_C}>0.3I_Percent Diff
Among {IMV_A, IMV_B, IMV_C} and {ILV_A, ILV_B, ILV_C} all currents without changing
Among {IHV_A, IHV_B, IHV_C} only 1 or 2 phase current decreased
Among {IHV_A, IHV_B, IHV_C} and {ILV_A, ILV_B, ILV_C} all currents without changing
Among {IMV_A, IMV_B, IMV_C} only 1 or 2 phase current decreased
Among {IHV_A, IHV_B, IHV_C} and {IMV_A, IMV_B, IMV_C} all currents without changing
Among {ILV_A, ILV_B, ILV_C} only 1 or 2 phase current decreased
AND
AND
AND
AND
CT Fail Detect on“1”
Figure 21 CT Fail detection logic
4.6 CT Saturation supervision
When Internal and external faults occurs, it is possible that transient and steady fault currents induce the CT saturation. CT saturation may lead to mal-operation of differential protection when an external fault occurs. In order to avoid mal-operation of protection in such situations, CT satura-tion supervision element is integrated in IED.
When transient saturation of CT occurs, the 2nd harmonic content in the corresponding phase current is dominant. Also whenever steady satura-tion of CT occurs, the 3rd harmonic content in the corresponding phase current is dominant. Both 2nd and 3rd harmonic contents of all phase currents of each side of the protected transformer are calculated to judge whether CT saturation occurs or not. Comprehensive harmonic ratio is calculated by below equation.
Chapter 3 Differential protection
46
harKII
II
>+φ
φ
φ
φ 32
Equation 22
Where:
Iφ2 is 2nd harmonic magnitude of phase current at each side,
Iφ3 is 3rd harmonic magnitude of phase current at each side,
Khar is the setting for comprehensive harmonic ratio, fixed in the soft-ware.
If the 2nd and 3rd harmonic contents of any phase current are more than Khar, then CT satisfies the above formulas and it is saturated. Usually before the CT saturation status, there is a short time period in which CT still works in its linear characteristic. By very fast CT saturation detection of IED, it needs only 4ms before any CT saturation happening to detect the fault which is internal or external fault. In order to distinguish satura-tion caused by internal faults and external faults effectively, percent dif-ferential protection based on sample values is used. If CT saturation is induced by external fault, differential protection will be blocked. However if CT saturation is induced by internal fault, differential protection will send its trip signal.
The typical saturation figure of phase A CT saturation is shown in below figure.
Figure 22 Typical phase A current transformer Saturation waveform
Chapter 3 Differential protection
47
4.7 Differential current supervision
In normal operation condition, zero differential current is assumed in each phase. The differential current supervision monitors the differential currents and checks its value to be less than a threshold. An alarm report is generated as “Diff Cur Alarm” after 5s, if the differential current ex-ceeds the threshold value. The alarm is an indication of miss-connection in CT secondary windings, and therefore is released to remind user to detect the faulty connection in secondary circuit and remove it. The func-tion can be enabled or disabled by using setting “Func_Diff Alarm” (1-On, 0-Off). The fixed threshold for releasing alarm is 0.3I_Percent Diff. How-ever, to avoid incorrect alarm indications, the threshold value is increased to 0.1A (in 1A nominal current inputs) and to 0.3A (in A nominal current inputs), if 0.3I_Percent Diff<0.1A. This is shown in below equations.
.
.
max{0.3 _ ,0.1 } 1max{0.3 _ ,0.3 } 5
D alarm n
D alarm n
I I Percent Diff A if I AI I Percent Diff A if I A
= = = =
Equation 23
Logic of differential current supervision is shown in below figure.
DIFF Alarm5s
Idiff_A>ID.alarm
Idiff_B>ID.alarm
Idiff_C>ID.alarm
OR
AND
Func_Diff Alarm on“1”
Figure 23 CT Fail detection logic
DANGER: Before Differential protection is put into operation on site, po-larity of current transformer must have been checked right by an energiz-ing test of every side of the transformer or a test of simulating an external fault of the side in primary system. Otherwise a mal-operation may occur during an external fault.
Chapter 3 Differential protection
48
5 Input and output signals
IA1
IB1
IC1
Diff Alarm
IA2
IB2
IC2
IA3
IB3
IC3
IA4
IB4
IC4
Diff Trip
Inst Diff A Trip
Inst Diff B Trip
Inst Diff C Trip
Per Diff A Trip
Per Diff B Trip
Per Diff C Trip
Relay Startup
IA5
IB5
IC5
Differential Protection
Figure 24 Transformer differention protection module, with up to 15 current inputs
Chapter 3 Differential protection
49
Table 6 Analog input list
Signal Description
IA1 Phase A current input of 1st CT set IB1 Phase B current input of 1st CT set IC1 Phase C current input of 1st CT set IA2 Phase A current input of 2nd CT set IB2 Phase B current input of 2nd CT set IC2 Phase C current input of 2nd CT set IA3 Phase A current input of 3th CT set IB3 Phase B current input of 3th CT set IC3 Phase C current input of 3th CT set IA4 Phase A current input of 4th CT set IB4 Phase B current input of 4th CT set IC4 Phase C current input of 4th CT set IA5 Phase A current input of 5th CT set IB5 Phase B current input of 5th CT set IC5 Phase C current input of 5th CT set
Table 7 Binary output list
Signal Description
Diff Alarm Differential alarm Diff Trip Differential trip Inst Diff A Trip Instantaneous differential phase A Trip Inst Diff B Trip Instantaneous differential phase B Trip Inst Diff C Trip Instantaneous differential phase C Trip Per Diff A Trip Percent differential phase A Trip Per Diff B Trip Percent differential phase B Trip Per Diff C Trip Percent differential phase C Trip
Relay Startup Relay Startup
Chapter 3 Differential protection
50
6 Settings Table 8 Instruction for Vector Group Angle setting
Binary setting values
HV Wind Conn/Y-0 D-1 0 0 0 1 1 1
MV Wind Conn/Y-0 D-1
(Only for three-winding trans-
formers)
0 1 0 1 1 0
LV Wind Conn/Y-0 D-1 1 1 0 1 0 0
Vet Grp Angle odd odd even even odd odd
Remarks
Y-Y-D-1
/3/5/7/9/
11
Y-D-D-1
/3/5/7/9/
11
Y-Y-Y-
2/4/6/8
/10/12
D-D-D-
2/4/6/8/
10/12
D-D-Y-
1/3/5/7
/9/11
D-Y-Y-
1/3/5/7
/9/11
Table 9 Settings of Differential protection
Setting Unit Min.
(Ir:5A/1A) Max.
(Ir:5A/1A)
Default setting
(Ir:5A/1A) Description
I_Inst Diff A 0.5Ir 20Ir 20 Instantaneous Differential (ID>>) current setting
I_Percent Diff A 0.08Ir 4Ir 2.1 Percentage Differential (ID>) current setting
I_ResPoint1 Diff A 0.1Ir Ir 2 The 1st breakpoint re-straint current (IR1)
I_ResPoint2 Diff A 0.1Ir 10Ir 2 The 2nd breakpoint re-straint current (IR2)
Slope1_Diff 0 0.2 0.2 the 1st slope
Slope2_Diff 0.2 0.7 0.5 the 2nd slope
Slope3_Diff 0.25 0.95 0.7 the 3rd slope
Ratio_2nd Harm 0.05 0.80 0.15 2nd harmonic(HAR) ratio
Ratio_3/5th Harm 0.05 0.80 0.35 3rd / 5th harmonic(HAR) ratio
Chapter 3 Differential protection
51
Setting Unit Min.
(Ir:5A/1A) Max.
(Ir:5A/1A)
Default setting
(Ir:5A/1A) Description
T_2nd Harm Block s 0 20 20
Within the delay 2nd harmonic block all three phases. After the delay, then only the local phase is blocked.
T_3/5th Harm Block
s 0 20 20
Within the delay 5th har-monic block all three phases. After the delay, then only the local phase is blocked.
Table 10 Binary settings of Differential protection
Setting Unit Min. Max. Default setting
Description
Func_Inst Diff 0 1 0 Instantaneous differential protection ON 1-on; 0-off.
Func_Percent Diff 0 1 0
Percentage differential pro-tection ON 1-on; 0-off.
Block Diff at Inrush 0 1 0
Inrush block differential pro-tection 1-block; 0-not block.
2nd Harm Not Wave
0 1 0
2nd harmonic (HAR) inhibit not the fuzzy recognition based on the wave-form(WAVE) 1-2nd harmonic on; 0- waveform on
Block Diff at Overexcit 0 1 0
Overexcitation block differ-ential protection 1-block; 0-not block.
Overexcit 3rd NOT 5th
0 1 0
Overexcitation stabilization judgement 3rd or 5th harmonic (HAR) inhibit on 1-3rd harmonic; 0-5th har-monic.
Func_Diff Alarm 0 1 0 Differential current (DIFF) Alarming on 1-on; 0-off.
Chapter 3 Differential protection
52
Setting Unit Min. Max. Default setting
Description
Block Diff at CT_Fail
0 1 0 Block differential protection when there is CT failure 1-block; 0-not block.
HV D_side Elimi-nate I0
0 1 0
Eliminate calculated 3I0 when HV side winding is connected in Delta mode 1- eliminate; 0-not eliminate
MV D_side Elimi-nate I0
0 1 0
Eliminate calculated 3I0 when MV side winding is connected in Delta mode 1- eliminate; 0-not eliminate
LV D_side Elimi-nate I0
0 1 0
Eliminate calculated 3I0 when LV side winding is connected in Delta mode 1- eliminate; 0-not eliminate
Diff Includes LV Cur
0 1 0
LV current is included in calculation of the differential protection. 1- Diff Includes LV Cur; 0-Diff NOT Includes LV Cur
7 Report Table 11 Event report list
Information Description
Per Diff Trip A
Treble slope percent Differential protection (ID>) trip for phase A/B/C Per Diff Trip B
Per Diff Trip C
Inst Diff Trip A
Instantaneous Differential protection (ID>>) trip for phase A/B/C Inst Diff Trip B
Inst Diff Trip C
Chapter 3 Differential protection
53
Table 12 Alarm report list
Information Description
Ph_A Ct Fail Phase A CT failure
Ph_B Ct Fail Phase B CT failure
Ph_C Ct Fail Phase C CT failure
Diff Cur Alarm Imbalance differential current alarm
Diff 2har Blk Differential protection is blocked by 2nd harmonic.
Diff 3/5har Blk Differential protection is blocked by 3rd or 5th harmonic.
Table 13 Operation report list
Information Description
Func_Diff On Differential protection is switched ON (by CW)
Func_Diff Off Differential protection is switched OFF (by CW)
8 Technical data Table 14 Differential protection technical data
Item Range or value Tolerance
Instantaneous differential current 0.5 Ir to 20.00 Ir ≤ ±3% setting or ±0.02Ir
Percentage differential current 0.08 Ir to 4.00 Ir ≤ ±3% setting or ±0.02Ir,
Restraint current 1 0.1 Ir to 1 Ir ≤ ±3% setting or ±0.02Ir
Restraint current 2 0.1 Ir to 10 Ir ≤ ±3% setting or ±0.02Ir
Slope 1 0.0 to 0.2
Slope 2 0.2 to 0.7
Slope 3 0.25 to 0.95
2nd harmonic restraint ratio 0.05 to 0.80 of fundamental
3rd / 5th harmonic restraint ratio 0.05 to 0.80 Reset ratio of restrained differ-ential approx. 0.7
Operating time of restraint dif-ferential
≤ 30ms at 200% setting, and IRDifferentialR>2IRRestraint
Operating time of instantaneous differential 20ms typically at 200% setting
Reset time approx. 40ms
Chapter 4 Restricted earth fault protection
54
Chapter 4 Restricted earth fault protection
About this chapter This chapter describes the protection principle, input and output signals, parameter, IED report and technical data for restricted earth fault protection function.
Chapter 4 Restricted earth fault protection
55
1 Introduction The restricted earth fault protection detects earth faults in power trans-formers with earthed starpoint or in non-earthed power transformers with a starpoint former (earthing transformer/reactor) installed inside the pro-tected zone. A precondition for using this function is that a CT should be installed in the starpoint connection, i.e. between the starpoint and earth. The starpoint CT and the phase CTs define the limits of the protected zone by restricted earth fault protection.
2 Applications The IED provides two restricted differential protection functions which can be used independently at various locations. For example, it is possi-ble to use them for both windings of YNyn transformer which is earthed at both starpoints. Further, one of them can be implemented to protect an earthed transformer winding and the other for an earthing transform-er/reactor. In case of auto-transformers, one of them is sufficient to pro-tect the auto-windings. Examples for some of applications are illustrated in the below figure.
A
B
C
HVa
b
c
LV
CSC-326 013I
2.AI
2.BI
2.CI
2.2.2.023 CBA IIII ++=
Figure 25 Application of restricted earth fault protection on an earthed transformer winding
Chapter 4 Restricted earth fault protection
56
A
B
C
HV
a
b
c
LV
013I ′
2.cI ′
2.bI ′
2.aI ′
CSC-3262.2.2.023 cba IIII ′+′+′=′
Figure 26 Application of restricted earth fault protection on an earthing transformer winding
A
B
C
HV
a
b
c
LV
013I
2.BI
2.CI
2.AI
CSC-326
2.2.2.023 CBA IIII ++=
013I ′
2.cI ′
2.bI ′
2.aI ′
2.2.2.023 cba IIII ′+′+′=′
Figure 27 Application of restricted earth fault protection on both sides of transformer
Chapter 4 Restricted earth fault protection
57
a
b
c
013I
3.aI
3.bI
3.cI
A
B
C
2.BI
2.CI
2.AI
CSC-326
2.2.2.023 CBA IIII ++=
3.3.3.033 cba IIII ++=
Figure 28 Application of restricted earth fault protection on an auto-transformer
3 Protection principle During healthy operation condition, no starpoint current 3I01 flows through the starpoint CT. Furthermore, the sum of the phase currents 3I02 =IA.2 + IB.2 + IC.2 is almost zero. In case of auto-transformer, both the re-sidual currents 3I02 =IA.2 + IB.2 + IC.2 and 3I03 =IA.3 + IB.3 + IC.3 are zero. With an earth fault inside the protected zone, a starpoint current 3I01 flows. Moreover, depending on the earthing conditions of the power system outside the protected zone, a further earth current may be rec-ognized in the residual current path of the phase CTs (3I02 and 3I03). Since all the currents flowing into the protected zone are defined positive, the residual current from the system (3I02 and 3I03) is more or less in phase with the starpoint current (3I01). With an earth fault outside the protected zone, a starpoint current 3I01 flows into the protected zone, together with equal residual current 3I02 and 3I03 which flows toward outside of the protected zone, through the phase CTs. Keeping in mind positive direction current flow, which is toward the protected zone, the starpoint current is in phase opposition with 3I02 and 3I03.
With the described situations, it may seem to be simple to discriminate an internal fault from an external one. However, there are some difficulties to do so. For instance, when a strong fault without earth connection occurs outside the protected zone, a residual current may appear in the residual current path of the phase CTs. The residual current is caused by different degrees of saturation in phase CTs and could simulate a fault in the protected zone. Thus, additional measures should be taken to prevent this current to cause false tripping. To achieve this objective, the re-stricted earth fault protection provides a restraint quantity.
Chapter 4 Restricted earth fault protection
58
3.1 Differential and restraint current calculation
The differential current Idiff0 and the restraining current Irest0 are calculated according to below figure.
{ }0 01 02 03
0 01 02 03
3 3 3
max 3 , 3 , 3
diff
rest
I I I I
I I I I
= + +
=
Equation 24
Idiff0 and Irest0 are compared by the restricted earth fault protection with a dual-slope operating characteristic defined by below equation and shown in below figure.
>×≥
≤≥
DDresresDdiff
DDresDdiff
SIIifISI
SIIifII
000000
00000
/
/
Equation 25
Where I0D is the setting for sensitivity threshold of restricted earth fault protection (setting “HV 3I0_REF”, “MV 3I0_REF” or “LV 3I0_REF”), and S0D is slope of the branch (setting “HV Slope_REF”, “MV Slope_REF” or “LV Slope_REF”).
This characteristic can be enabled or disabled by using Binary setting “HV Func_REF Trip”, “MV Func_REF Trip” or “LV Func_REF Trip”). If setting “1-on” is selected, a trip signal is issued by restricted earth fault protection when the operating point lies into tripping area (see below fig-ure) and the preset time delay is expired (setting “HV T_REF Trip”, “MV T_REF Trip” or “LV T_REF Trip”).
The trip logic for restricted earth fault protection is shown in below figure.
Chapter 4 Restricted earth fault protection
59
Diff0I
Res0I
3 0 _I REF
_Slope REF
Trip area
block area
Figure 29 Characteristic of restricted earth fault protection
AND
REF Trip
REF Alarm
Idiff0>HV 3I0_REF Alarm
Func_REF Trip on
T_REF Trip
T_REF Alarm Func_REF Alarm on A
ND
“1”
“1”
Figure 30 Tripping logic of the restricted earth fault protection
To clarify the proper operation during various situations, three important operating conditions are examined.
External fault:
3I01 enters the protected zone, whereas 3I02 leaves the protected zone, i.e. is negative according to the definition of signs, therefore 3I02 = –3I01.
Idiff0 = |3I01 + 3I02| = |3I01 – 3I02|= 0
Ires0 = max {|3I01|, |3I02|} = |3I01|
No tripping quantity (Idiff0 = 0); the restraint quantity (Irest0) corresponds to the external fault current flowing through the starpoint connection.
Internal fault, fed only from the starpoint:
Chapter 4 Restricted earth fault protection
60
In this case, 3I02=0, thus,
Idiff0 = |3I01 + 3I02| = |3I01 + 0| = |3I01|
Ires0 = max {|3I01|, |3I02|} = |3I01|
Both the tripping (Idiff0) and the restraint (Irest0) quantities correspond to the fault current flowing through the starpoint.
Internal fault, fed from the starpoint and from the system, e.g. with equal earth current magnitude:
Both the 3I01 and 3I02 enter the protected zone, thus having positive sign. The condition results in 3I02 = 3I01.
Idiff0 = |3I01 + 3I02| = |3I01 + 3I02|= 2×|3I01|
Ires0 = max {|3I01|, |3I02|} = |3I01|
Tripping quantity (Idiff0) corresponds to double the fault current flowing through the starpoint connection, and restraint quantity (Irest0) is equal to the fault current.
The results show that the device is capable to properly discriminate in-ternal and external earth faults by using the definitions proposed for dif-ferential and restraint current. However, the device is still subjected to some influences that induce differential currents even during normal op-eration condition. These influences should be compensated in appropri-ate manner. The specific treatments designed to cope with these influ-ences includes automatic ratio compensation which is explored as fol-lows.
3.2 Automatic Ratio compensation
Restricted earth fault protection represents some problems in the appli-cation of current transformers regarding to matching between phase and starpoint CTs. The problem is originated from different ratio of phase and starpoint CTs. The difference may result in a differential current in normal operation condition. To remove this problem, the input currents of the relay from starpoint CTs should be converted according to primary rated currents of phase and starpoint CTs. In the IED, this objective is achieved by taking a common reference value and converting all secondary cur-rents of starpoint CTs into the same reference. The conversion is per-
Chapter 4 Restricted earth fault protection
61
formed by calculation of ratio compensation factor for starpoint CTs. The compensation factors are then multiplied by the secondary current of starpoint CTs to make them comparable with those current measured at phase CTs. The conversion procedure is performed inside the device. The ratio compensation factors are calculated as follow:
HVPhase
HVStarpoHVStarpo n
nK
−
−− = int
int
Equation 26
MVPhase
MVStarpoMVStarpo n
nK
−
−− = int
int
Equation 27
LVPhase
LVStarpoLVStarpo n
nK
−
−− = int
int
Equation 28
Where int−Starpo HVK is the ratio compensation factor for HV starpoint CT;
int−Starpo MVK is the ratio compensation for MV starpoint CT and
int−Starpo LVK is the ratio compensation for LV starpoint CT;
For auto-transformer, in addition to the common winding starpoint CT, the measured current from phase winding of MV winding should also be converted to the common reference current. In this context, the ratio compensation factors are calculated as follow:
Equation 29
−
−
= Phase MVMV
Phase HV
nKn
Chapter 4 Restricted earth fault protection
62
HVPhase
StarpoStarpo n
nK
−
= intint
Equation 30
Where MVK is the ratio compensation factor for MV phase CT, and
intStarpoK is the ratio compensation factor for common winding starpoint
CT.
The reference current is selected as is shown in below figure.
Table 15 Reference side selection for REF functions
Type Function HV REF MV REF LV REF
2 winding HV CT --- LV CT
3 winding HV CT MV CT ---
Auto-transformer HV CT --- ---
3.3 Positive sequence current blocking
A
B
C
HVa
b
c
LV
CSC-326 013I
2.AI
2.BI
2.CI
2.2.2.023 CBA IIII ++=
CT2
When an external fault causes a heavy current to flow through the pro-tected transformer, differences in the magnetic characteristics of the current transformer CT2 under saturation condition may cause a signifi-cant difference in the secondary currents I02 connected to IED. If the difference is greater than the pickup threshold, the REF protection func-tion can trip even though no fault occurred in the protected zone. To prevent the protection function from such erroneous operation, a restraint (stabilizing) ratio, zero-sequence current divides positive-sequence cur-
Chapter 4 Restricted earth fault protection
63
rent, is brought in.
0
115%I
I>
Where I0 is zero-sequence current, I1 is positive-sequence current.
Only when the ratio is greater than 15% can the REF protection trip.
3.4 Restricted earth fault current alarm
In normal operation condition, zero differential current is expected for re-stricted earth fault protection. The Restricted earth fault current supervi-sion monitors Idiff0 and checks its value to be less than a threshold. An alarm report is generated as “HV REF 3I0 Alarm”, “MV REF 3I0 Alarm” or “LV REF 3I0 Alarm”, after the preset time of “HV T_REF Alarm”, “MV T_REF Alarm” or “LV T_REF Alarm”, if the differential current exceeds the threshold value “HV 3I0_REF”, “MV 3I0_REF” or “LV 3I0_REF”. The alarm is an indication of miss-connection in phase or starpoint CT sec-ondary windings, and therefore is released to remind user to detect the faulty connection in secondary circuit and remove it. The function can be enabled or disabled by using setting “HV Func_REF Alarm”, “MV Func_REF Alarm” or “LV Func_REF Alarm”, (1-On, 0-Off). The setting range of the threshold differential current to release restricted earth fault current alarm is on [0.08-10A]. However, to avoid incorrect alarm indica-tions, the threshold value is increased to 0.1A (in 1A nominal current in-puts) and to 0.3A (in 5A nominal current inputs), if the set value is less than 0.1A.
DANGER: Before Restricted Earth Fault protection is put into operation on
site, polarity of neutral current transformer for REF must have been
checked right by an energizing test of every side of the transformer or a
test of simulating an external fault of the side in primary system. Otherwise
a mal-operation may occur during an external earth fault.
Chapter 4 Restricted earth fault protection
64
4 Input and output signals
IA1
IB1
IC1
REF Alarm
IA2
IB2
IC2
IREF
REF Trip
Relay Startup
Restricted Earth Fault Protection
Figure 31 Restricted earth fault protection module
Table 16 Analog input list
Signal Description
IA1 Phase A current input of CT of circuit breaker 1 IB1 Phase B current input of CT of circuit breaker 1 IC1 Phase C current input of CT of circuit breaker 1 IA2 Phase A current input of CT of circuit breaker 2 IB2 Phase B current input of CT of circuit breaker 2 IC2 Phase C current input of CT of circuit breaker 2 IREF Neutral point current for REF
Table 17 Binary output list
Signal Description
REF Alarm Restricted Earth Fault alarm REF Trip Restricted Earth Fault trip
Relay Startup Relay Startup
Chapter 4 Restricted earth fault protection
65
5 Settings Table 18 Settings of Restricted earth fault protection for HV side of transformer
Setting Unit Min.
(Ir:5A/1A) Max.
(Ir:5A/1A)
Default setting
(Ir:5A/1A) Description
HV 3I0_REF A 0.08Ir 2Ir 2 Current setting for HV Re-stricted Earth Fault protection
HV
Slope_REF 0.2 0.95 0.5
Slope setting for HV Re-stricted Earth Fault protection
HV T_REF
Trip s 0 60 0.03
HV Restricted Earth Fault trip time setting
HV 3I0_REF
Alarm A 0.08Ir 2Ir 2
HV Restricted Earth Fault alarm current setting
HV T_REF
Alarm s 0 60 0.03
HV Restricted Earth Fault alarm time setting
Table 19 Binary settings of restricted earth fault protection for HV side of transformer
Setting Unit Min. Max. Default setting
Description
HV Func_REF
Trip 0 1 0
HV Restricted earth fault trip-stage ON 1-on; 0-off.
HV Func_REF
Alarm 0 1 0
HV Restricted earth fault Alarm-stage ON 1-on; 0-off.
Block HV REF
at HV CT_Fail 0 1 0
Block HV REF when CT failure, 1-Block;0-unblock
Table 20 Settings of Restricted earth fault protection for MV side of transformer
Setting Unit Min.
(Ir:5A/1A) Max.
(Ir:5A/1A)
Default setting
(Ir:5A/1A) Description
MV 3I0_REF A 0.08Ir 2Ir 2 Current setting for MV Re-stricted Earth Fault protection
MV
Slope_REF 0.2 0.95 0.5
Slope setting for MV Re-stricted Earth Fault protection
Chapter 4 Restricted earth fault protection
66
Setting Unit Min.
(Ir:5A/1A) Max.
(Ir:5A/1A)
Default setting
(Ir:5A/1A) Description
MV T_REF
Trip s 0 60 0.03
MV Restricted Earth Fault trip time setting
MV 3I0_REF
Alarm A 0.08Ir 2Ir 2
MV Restricted Earth Fault alarm current setting
MV T_REF
Alarm s 0 60 0.03
MV Restricted Earth Fault alarm time setting
Table 21 Binary settings of restricted earth fault protection for MV side of transformer
Setting Unit Min. Max. Default setting
Description
MV Func_REF Trip
0 1 0 MV Restricted earth fault trip-stage ON 1-on; 0-off.
MV Func_REF Alarm
0 1 0 MV Restricted earth fault Alarm-stage ON 1-on; 0-off.
Block MV REF at MV CT_Fail
0 1 0 Block MV REF when CT failure, 1-Block;0-unblock
Table 22 Settings of restricted earth fault protection for LV side of transformer
Setting Unit Min.
(Ir:5A/1A) Max.
(Ir:5A/1A)
Default setting
(Ir:5A/1A) Description
LV 3I0_REF A 0.08Ir 2Ir 2 Current setting for LV Re-stricted Earth Fault protection
LV Slope_REF 0.2 0.95 0.5 Slope setting for LV Re-stricted Earth Fault protection
LV T_REF Trip s 0 60 0.03 LV Restricted Earth Fault trip time setting
LV 3I0_REF
Alarm A 0.08Ir 2Ir 2
LV Restricted Earth Fault alarm current setting
LV T_REF
Alarm s 0 60 0.03
LV Restricted Earth Fault alarm time setting
Chapter 4 Restricted earth fault protection
67
Table 23 Binary settings of restricted earth fault protection for LV side of transformer
Setting Unit Min. Max. Default setting
Description
LV Func_REF Trip
0 1 0 LV Restricted earth fault trip-stage ON 1-on; 0-off.
LV Func_REF Alarm
0 1 0 LV Restricted earth fault Alarm-stage ON 1-on; 0-off.
Block LV REF at LV CT_Fail
0 1 0 Block LV REF when CT failure, 1-Block;0-unblock
6 Report Table 24 Event report list
Information Description
HV REF Trip HV Restricted Earth fault (REF) protection trip
MV REF Trip MV Restricted Earth fault (REF) protection trip
LV REF Trip LV Restricted Earth fault (REF) protection trip
Table 25 Alarm report list
Information Description
HV REF 3I0 Alarm HV Restricted Earth fault (REF) protection trip
MV REF 3I0 Alarm MV Restricted Earth fault (REF) protection trip
LV REF 3I0 Alarm LV Restricted Earth fault (REF) protection trip
Table 26 Operation report list
Information Description
HV Func_REF On HV REF protection is switched ON (by CW)
HV Func_REF Off HV REF protection is switched OFF (by CW)
MV Func_REF On MV REF protection is switched ON (by CW)
Chapter 4 Restricted earth fault protection
68
MV Func_REF Off MV REF protection is switched OFF (by CW)
LV Func_REF On LV REF protection is switched ON (by CW)
LV Func_REF Off LV REF protection is switched OFF (by CW)
7 Technical data Table 27 Restricted earth fault protection technical data
Item Rang or Value Tolerance
Differential current 0.08 Ir to 2.00 Ir ±3% setting or ±0.02Ir
Slope 0.2 to 0.95
Time delay 0.00 to 60.00s, step 0.01s ≤ ±1% setting or +40ms, at 200%
operating setting
Reset ratio Approx. 0.7, at tripping
Operating time ≤ 30ms, at 200% setting
Reset time approx. 40ms
Chapter 5 Overexcitation protection
69
Chapter 5 Overexcitation protection
70
Chapter 5 Overexcitation protection
About this chapter This chapter describes the protection principle, input and output signals, parameter, IED report and technical data for overexciation protection function.
Chapter 5 Overexcitation protection
71
1 Introduction The overexcitation protection is used to detect impermissible overexcitation
conditions which can endanger power transformers. An increase in trans-
former flux beyond the rated values leads to saturation of the iron core and to
large eddy current losses which cause impermissible temperature rise in
transformer core.
2 Protection principle
2.1 Protection principle
The overexcitation condition may occur in power plant transformers when a
load center is disconnected from the system, and the voltage regulator does
not operate sufficiently fast to control the associated voltage rise. Similarly,
the overexcitation condition may occur as result of a decrease in frequency,
e.g. in island system. To protect the power transformer in such conditions, the
overexcitation protection function should pick up when the permissible limit of
flux is exceeded in the transformer core. To do so, the overexcitation protec-
tion function measures the voltage/frequency (U/f) ratio which is proportional
to the flux density B in transformer core, and puts it in relation to the nominal
flux density BN. The decision is then made based on the calculated ratio as is
shown in below equation.
NNN fUfU
BBN ==
Equation 31
Where N is the ratio of volt/hertz calculated by the device.
U and f are the measured voltage and frequency, and UN and fN are the rated voltage and frequency (50Hz or 60Hz) of the device. While the rated fre-quency is fixed to 50Hz or 60Hz in software, device is informed about rated voltage by setting “Reference Voltage” which corresponds to nominal phase-neutral voltage of the protected transformer when is transferred to
Chapter 5 Overexcitation protection
72
secondary value, using the turn ratio of voltage transformer. Thus, the use of the overexcitation protection presumes that measured voltage is connected to the device. Calculation of voltage/hertz ratio above is performed based on the maximum voltage of the three phase-neutral or phase-phase voltages. Binary setting “V/F Voltage (0-VPP, 1-VPN)” determines whether phase-to-phase voltage or phase-neutral voltage should be used for overexcitation protection, by setting “0-VPP” or “1-VPN”, respectively.
It should be mentioned that the overexcitation protection can operate properly, only if frequency is in range of 0.5 - 1.3 times the rated frequency and voltage is greater than 0.7 times the rated voltage. If frequency or voltage is out of the specified range, an alarm report “U or F EXCEED” is generated by the device, after a fixed time delay of 150ms, and the overexcitation protection is blocked. The logic is shown in below figure.
OR
U or F EXCEED150msf<0.5fn or f>1.3fn
V<0.7Un
Figure 32 Condition for generating “U or F EXCEED” alarm
The overexcitation protection includes two definite characteristics (alarm and trip) and one thermal characteristic. The latter characteristic provides an ap-proximate replica of the temperature rise caused by overexcitation in the protected object. The definite alarm stage can be enabled or disabled by us-ing Binary setting “Func_Overexcit Alarm Def ” on. Similarly, the definite trip stage can be enabled or disabled by using Binary setting “Func_Overexcit Trip Def” on. Furthermore, the thermal characteristic can be set by Binary setting “Func_Overexcit Trip Inv” on. It should be mentioned that the overex-citation protection can be applied at HV, MV or LV side of the protected transformer. However, it is not recommended to apply the function on the transformer side with variable winding turns such as the transformer side with an installed tap changer. To enable the protection on a given side, setting of “HV Func_Overexcit” on, “MV Func_Overexcit” on and “LV Func_Overexcit” on should be applied to corresponding Binary settings. However, these set-tings should be applied to 1 only on one side at the same time. If any two of “HV Func_Overexcit”, “MV Func_Overexcit” and “HV Func_Overexcit” are set to 1 at the same time, alarm report “Setting Err” will be given by the device.
All the three available stages of the overexcitation protection use phase-to-phase voltage or phase-neutral voltage of the corresponding side in their calculations, based on the setting applied at Binary setting “V/F Voltage
Chapter 5 Overexcitation protection
73
(0-VPP, 1-VPN)”.
If the definite alarm stage is enabled in one side, and the calculated volt/hertz ration exceeds the threshold defined by setting “Func_Overexcit Alarm Def”, an alarm report “Def V/F Alarm ” is generated by the device, after the time delay “T_Definite Alarm” elapsed. The logic for the definite alarm stage of overexcitation protection is shown in below figure when it is applied to HV side. The logic is the same when the protection function is applied to other sides.
DEF V/F Alarm
AND
OR
OR
OR
U or F EXCEED
AND
( ) FVAlarmDEFfUN HvAB /,_ ⟩
( ) FVAlarmD EFfUN HvAC /,_ ⟩
( ) FVAlarmD EFfUN HvBC /,_ ⟩
( ) FVAlarmD EFfUN H vA /,_ ⟩
( ) FVA la rmD E FfUN H vB /,_ ⟩
( ) FVA la rmD E FfUN H vC /,_ ⟩
AND
HV Func_Overexcit on
Func_Overexcit Alarm Def on
T_Definite Alarm
V/F Voltage(0-VPP,1-VPN) on
“1”
“1”
“1”
Figure 33 Logic of the definite alarm stage for overexcitation protection
Similarly, if the definite trip stage is enabled in one side, and the calculated volt/hertz ration exceeds the threshold defined by setting “V/F_Definite Trip”, an event report “Def V/F Trip” is generated by the device, subsequent to the
Chapter 5 Overexcitation protection
74
expiration of time delay “T_Definite Trip”. Tripping Logic of the definite trip stage of overexcitation protection is shown in below figure.
DEF V/F Trip
AND
OR
OR
OR
U or F EXCEED
AND
( ) FVTripD E FfUN HvAB /,_ ⟩
`
( ) FVTripD E FfUN HvBC /,_ ⟩
( ) FVTripDEFfUN HvAC /,_ ⟩
( ) FVTripDEFfUN HvA /,_ ⟩
( ) FVTripDEFfUN HvB /,_ ⟩
( ) FVTripDEFfUN HvC /,_ ⟩
AND
HV Func_Overexcit on
Func_Overexcit Trip Def on
V/F Voltage(0-VPP,1-VPN) on
T_Definite Trip
“1”
“1”
“1”
Figure 34 Tripping logic of the definite trip stage for overexcitation protection
If thermal characteristic is set to “1-on” in one of transformer sides, it uses the measured voltage and frequency of the corresponding side (depending on the setting applied at Binary setting “V/F Voltage (0-VPP,1-VPN)”), together with ten points derived from the manufacturer data. The points correspond to the desired tripping times for a given volt/hertz ratios. Intermediate values are determined by performing linear interpolation by the device. The ratios range from N=1.05 to N=1.50. They are entered into the device by settings
Chapter 5 Overexcitation protection
75
“T1_Inverse V/F=1.05”, “T2_Inverse V/F=1.10”, “T3_Inverse V/F=1.15”, “T4_Inverse V/F=1.20”, “T5_Inverse V/F=1.25”, “T6_Inverse V/F=1.30”, “T7_Inverse V/F=1.35”, “T8_Inverse V/F=1.40”, “T9_Inverse V/F=1.45” and “T10_Inverse V/F=1.50”. The device uses these points to form an inverse characteristic such as those shown in below figure.
u/f
1.05
t(s)T10 T8 T6 T4 T2
1.10
1.15
1.201.25
1.30
1.35
1.40
1.45
1.50
T1T3T5T7T9
Figure 35 Thermal overexcitation characteristic
As can be seen from the above figure, N=1.05 works as a pickup threshold for thermal stage. The thermal replica is implemented in IED by a counter which is incremented from 0% to 100%, as soon as the calculated voltage/hertz ra-tio of exceeds the pickup threshold (N=1.05). If the counter reaches to 100% corresponding to expiration of trip time delay according to the trip character-istic, the event report “Inv V/F Trip” is given. The trip signal is cancelled as soon as the calculated voltage/hertz ratio falls below the pickup threshold (N=1.05). However, the counter is decremented to zero according to cool down time of the transformer (the time by which the thermal replica counter reaches from 100% to 0%). The cool down time is informed to the device by setting “T_Cool Down”.
Tripping Logic of the inverse thermal trip stage of overexcitation protection is shown in below figure.
Chapter 5 Overexcitation protection
76
Inv V/F Trip
AND
OR
U or F EXCEED
AND
OR
u/f
1.05
t(s)T10
T8 T6 T4 T2
1.10
1.15
1.20
1.25
1.30
1.35
1.40
1.45
1.50
T1T3T5T7T9
u/f
1.05
t(s)T10
T8 T6 T4 T2
1.10
1.15
1.20
1.25
1.30
1.35
1.40
1.45
1.50
T1T3T5T7T9
u/f
1.05
t(s)T10
T8 T6 T4 T2
1.10
1.15
1.20
1.25
1.30
1.35
1.40
1.45
1.50
T1T3T5T7T9
u/f
1.05
t(s)T10 T8 T6 T4 T2
1.101.151.201.251.301.351.401.451.50
T1T3T5T7T9
u/f
1.05
t(s)T10 T8 T6 T4 T2
1.101.151.201.251.301.351.401.451.50
T1T3T5T7T9
u/f
1.05
t(s)T10 T8 T6 T4 T2
1.101.151.201.251.301.351.401.451.50
T1T3T5T7T9
),( fUN HVAB−
),( fUN HVBC−
),( fUN HVAC−
),( fUN HVA−
),( fUN HVB−
),( fUN HVC−
HV Func_Overexcit on
Func_Overexcit Trip Inv on
V/F Voltage(0-VPP,1-VPN) on
OR
AND
“1”
“1”
Figure 36 Tripping logic of the thermal trip stage for overexcitation protection
NOTE: If it is possible for a given transformers to operate continuously under
Chapter 5 Overexcitation protection
77
the condition of N=1.05, corresponding time delay setting (“T1_Inverse
V/F=1.05”) should be set to 9999s. The same approach can be taken when, for
example, it is permissible for a transformer to operate continuously under the
condition N=1.10, N=1.15 and so on. It means that the thermal characteristic is
compound of 10 points at most, and it maybe contains less than 10 points. The
thermal characteristic would be disabled if all the delay time settings are set to
9999s.
2.2 Voltage channel configuration
UA/B/C voltage input channel of 1st Analog input module (hereinafter is ref-ered as AIM) is provided with the high accurate frequency measurement hardware circuit. In order to offer the high performance overexcitation function for HV, MV or LV side, the applied voltage input of HV side, MV side or LV side must be connected with the UA/B/C voltage input channel of 1st Analog input module (AIM1).
Only one of HV overexcitation, MV overexcitation or LV overexcitation func-tions could be enabled for one transformer, so settings of “HV Voltage Chan Sel” and “MV Voltage Chan Sel” under “Comm Para” submenu are used to select the voltage channel.
For example of HV side; the setting “HV Voltage Chan Sel” can be set as 1, 2 and 3 which means voltage channels are connected to the corresponding analog input module (see below table).
Table 28 Voltage channel selection setting
“Voltage Chan Sel” Voltage input channels, connected with external
volage inputs
1 UA/B/C voltage input channel of AIM1, which channels can
provide the frequency measurement hardware circuit.
2 UA/B/C voltage input channel of AIM2
3 UA/B/C voltage input channel of AIM3
If Binary setting “HV Func_Overexcit” is set 1 and “HV Voltage Chan Sel” is set 2 or 3 (not 1), alarm report “Setting Err” will be given by the device. If Bi-nary setting “MV Func_Overexcit” is set 1 and “MV Voltage Chan Sel” is set 2 or 3 (not 1), alarm report “Setting Err” will be given by the device. If “LV
Chapter 5 Overexcitation protection
78
Func_Overexcit”, anyone of “HV Voltage Chan Sel” and “MV Voltage Chan Sel” is set 1, alarm report “Setting Err” will be given by the device.
3 Input and output signals
UA
UB
UC
Relay Startup
Def V/F Alarm
Def V/F Trip
Inv V/F Trip
Overexcitation Protection
Figure 37 Overexcitation protection module
Table 29 Analog input list
Signal Description
UA Phase A voltage input UB Phase B voltage input UC Phase C voltage input
Table 30 Binary output list
Signal Description
Def V/F Alarm Overexcitation protection(V/F) alarm with definite (DEF) time characteristic
Def V/F Trip Overexcitation protection(V/F) tripping (Trip) with definite (DEF) time characteristic
Inv V/F Trip Overexcitation protection(V/F) tripping (Trip) with inverse(IVR) time characteristic
Relay Startup Relay Startup
Chapter 5 Overexcitation protection
79
4 Settings Table 31 Settings of overexcitation protection
Setting Unit Min.
(Ir:5A/1A) Max.
(Ir:5A/1A)
Default setting
(Ir:5A/1A) Description
Reference Volt-age
V 40 130 57.3 Nominal phase voltage in HV side
V/F_Definite Alarm
1 1.5 1.1 Alarming setting of volt/hertz
T_Definite Alarm s 0.1 9999 10 Timer setting for volt/hertz alarming stage
V/F_Definite Trip
1 1.5 1.2 Tripping setting of definite volt/hertz stage
T_Definite Trip s 0.1 9999 1 Timer setting for definite volt/hertz stage
T1_Inverse V/F=1.05
s 0.1 9999 10 Timer setting for volt/hertz=1.05
T2_Inverse V/F=1.10
s 0.1 9999 90 Timer setting for volt/hertz=1.10
T3_Inverse V/F=1.15
s 0.1 9999 80 Timer setting for volt/hertz=1.15
T4_Inverse V/F=1.20
s 0.1 9999 70 Timer setting for volt/hertz=1.20
T5_Inverse V/F=1.25
s 0.1 9999 60 Timer setting for volt/hertz=1.25
T6_Inverse V/F=1.30
s 0.1 9999 50 Timer setting for volt/hertz=1.30
T7_Inverse V/F=1.35
s 0.1 9999 45 Timer setting for volt/hertz=1.35
T8_Inverse V/F=1.40
s 0.1 9999 40 Timer setting for volt/hertz=1.40
T9_Inverse V/F=1.45
s 0.1 9999 35 Timer setting for volt/hertz=1.45
T10_Inverse V/F=1.50
s 0.1 9999 30 Timer setting for volt/hertz=1.50
T_Cool Down s 0.1 9999 25 Cool down time delay for overexcitation protection
Chapter 5 Overexcitation protection
80
Table 32 Binary settings of overexcitation protection
Setting Unit Min. Max. Default setting
Description
HV Func_Overexcit 0 1 0 HV Overexcitation (V/F) on 1-on; 0-off.
MV Func_Overexcit 0 1 0 MV Overexcitation (V/F) on 1-on; 0-off.
LV Func_Overexcit 0 1 0 LV Overexcitation (V/F) on 1-on; 0-off.
Func_Overexcit
Alarm Def 0 1 0
Definite Overexcitation (V/F) Alarming on 1-on; 0-off.
Func_Overexcit Trip
Def 0 1 0
Definite (DEF)Overexcitation (V/F) on 1-on; 0-off.
Func_Overexcit Trip
Inv 0 1 0
Inverse (IVR)Overexcitation (V/F) on 1-on; 0-off.
V/F Volt-
age(0-VPP,1-VPN) 0 1 0
Overexcitation protection uses phase-to-phase voltage (VPP) or phase-to-earth voltage (VPN) 0-VPP; 1-VPN.
5 Report Table 33 Event report list
Information Description
Def V/F Trip Overexcitation protection(V/F) tripping (Trip) with definite (DEF)
and inverse(IVR) time characteristic Inv V/F Trip
Table 34 Alarm report list
Information Description
Def V/F Alarm Overexcitation alarm
V or F Exceed Voltage or frequency is out of the permissible range
Chapter 5 Overexcitation protection
81
Information Description
(25-65Hertz, >0.7 Un)
Table 35 Operation report list
Information Description
Func_Overexc On Overexcitation protection is switched ON (by CW)
Func_Overexc Off Overexcitation protection is switched OFF (by CW)
6 Technical data Table 36 Overexcitation protection technical data
Item Rang or Value Tolerance
Reference voltage UN 40 to 130V, ≤ ±3 % setting or ±1 V
Inverse time characteristic Ratio: 1.00 to 1.50 ≤ ±2.5% of the setting or 0.01 Time delay 0.1s to 9999s ≤±5% setting or ±70ms Pair of Values for characteristic of V/f
1.05 /1.10 /1.15 /1.20 /1.25 /1.30 /1.35 /1.40 /1.45 /1.50 ≤±5% setting or ± 70ms
Reset time, Approx. 70ms
Reset ratio ≥0.96
Definite time characteristic
Time delay T 0.1s to 9999s ≤±5% setting or ±70ms, at 200% operating setting
Reset time, Approx. 70ms
Reset ratio ≥0.96
Chapter 6 Overcurrent protection
82
Chapter 6 Overcurrent protection
About this chapter This chapter describes the protection principle, input and output signals, parameter, IED report and technical data for overcurrent protection function.
Chapter 6 Overcurrent protection
83
1 Introduction The non-directional overcurrent elements can be applied as backup protec-tion functions for transformer as well as power system protection in networks with radial nature and those which are supplied from a single source. The directional overcurrent protection can also be applied in systems where pro-tection 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 par-allel transformers supplied from a single source.
2 Protection principle
2.1 Protection Elements
Each voltage side of the protected transformer is provided with three over-current protection elements from which two elements operate as definite overcurrent stages and the other one operates with inverse time-current characteristic. All the elements can operate in conjunction with the integrated inrush restraint and directional functions.
Various stages of the elements are independent from each other and can be combined as desired. They can be enabled or disabled in each side using dedicated Binary settings. These Binary settings include “HV Func_OC1”, “HV Func_OC2” and “HV Func_OC Inv”, for HV side overcurrent protection, “MV Func_OC1”, “MV Func_OC2” and “MV Func_OC Inv”, for MV side overcurrent protection, “LV Func_OC1”, “LV Func_OC2” and “LV Func_OC Inv”, for LV side overcurrent protection. For example by applying setting “1-on” to “HV Func_OC1”, respective stage of overcurrent protection would be enabled in HV side.
Individual pickup value for each definite stage can be defined by setting “HV I_OC1” and “HV I_OC2” for HV side, “MV I_OC1” and “MV I_OC2” for MV side, “LV I_OC1” and “LV I_OC2” for LV side. By applying these settings, each phase current is compared separately with the setting value for each stage. If the respective value is exceeded, a trip time delay timer is started. The con-dition for start of the delay timer is expressed mathematically by below equa-tion, in which a, b and c represent three phases.
( ), ,setI > I a b cf f=
Equation 32
The timer is set to count up to a user-defined time delay. The time delay can be set for each definite stage individually through settings “HV T_OC1” and
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“HV T_OC2” for HV side, “MV T_OC1” and “MV T_OC2” for MV side, “LV T_OC1” and “LV T_OC2” for LV side. After the user-defined time delays have been elapsed, a trip signal is issued if the inrush restraint feature is applied and no inrush current is detected or if inrush restraint is disabled. However, the overcurrent protection would be blocked and therefore, no tripping takes place if the inrush restraint feature is enabled and an inrush condition exists. Further, an alarm report is issued as “HV Inrush Blk BU”, “MV Inrush Blk BU” or “LV Inrush Blk BU” indicating that a blocking condition is imposed to over-current element by inrush condition detection.
The pickup value for the inverse time-current stage can be defined by setting “HV I_OC Inv”, “MV I_OC Inv” and “LV I_OC Inv” for HV, MV and LV sides, respectively. Each phase current is separately compared with corresponding setting value. If a current exceeds 1.1 times the setting value, corresponding stage picks up. If an inverse time-current stage picks up, the tripping time is calculated from the actual fault current flowing, using the selected tripping curve. Maximum tripping time is limited to 100s.
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 fol-lowing equation:
_
_ _ _
-1P OC Inv
S
A OC Invt K OC Inv B OC InvII
é ùê úê úê ú= ´ +ê úé ùê úê úê úê úê úë ûë û
Where I is the fault current;
Is is the current setting;
xV A_OC Inv: xV(HV/MV/LV) side time factor for inverse time stage
xV B_OC Inv: xV(HV/MV/LV) time delay for inverse time stage
xV P_OC Inv: xV(HV/MV/LV) index for inverse time stage
xV K_OC Inv: xV(HV/MV/LV) time multiplier Inrush restraint feature
(For detailed time inverse characteristic, refer to Appendix Time inverse characteristic)
As mentioned previously, selection among the curves can be carried out by settings “HV Func_OC Inv”, “MV Func_OC Inv” and “LV Func_OC Inv” for HV, MV and LV sides, respectively. Furthermore, the time multiplier K_OC Inv can be set by user to coordinate the integrated inverse time-current characteristic of the device with other overcurrent relays installed for power system protec-
Chapter 6 Overcurrent protection
85
tion. This can be performed by settings “HV K_OC Inv”, “MV K_OC Inv” and “LV K_OC Inv” in case of HV, MV and LV overcurrent elements, respectively.
By applying pickup current and time multiplier settings, the device calculates the tripping time from the measured current in each phase separately, based on the selected inverse curve. Once the calculated time has been elapsed, a trip signal is issued provided that no inrush current is detected or inrush re-straint is disabled. If the inrush restraint feature is enabled and an inrush condition exists, the overcurrent protection would be blocked and therefore no tripping takes place. However, an alarm report is generated as “HV Inrush Blk BU”, “MV Inrush Blk BU” or “LV Inrush Blk BU”, indicating the blocking condi-tion which is imposed to overcurrent element by detection of inrush condition.
The trip signals and corresponding event reports are available separately for each stage. These include “HV OC1 Trip”, “HV OC2 Trip” and “HV OC Inv Trip” for HV side, “MV OC1 Trip”, “MV OC2 Trip” and “MV OC Inv Trip” for MV side, “LV OC1 Trip”, “LV OC2 Trip” and “LV OC Inv Trip” for LV side overcur-rent elements.
2.2 Inrush Restraint Feature
The transformer overcurrent protection may detect large magnetizing inrush currents flowing when transformer is energized. The inrush current may be several times of the nominal current, and may last from several tens of milli-seconds to several seconds. Inrush current comprises second harmonic as well as considerable fundamental component. So it may affect the overcur-rent protection which operates based on the fundamental component of the measured current. Inrush blocking unit in overcurrent function is provided for this purpose. It is possible to apply the inrush restraint feature separately to each definite stage and inverse time-current stage of overcurrent element by using Binary settings “HV OC1 Inrush Block”, “HV OC2 Inrush Block” and “HV OC Inv Inrush Block” on for HV side, “MV OC1 Inrush Block”, “MV OC2 Inrush Block” and “MV OC Inv Inrush Block” for MV side, “LV OC1 Inrush Block”, “LV OC2 Inrush Block” and “LV OC Inv Inrush Block” for LV side. By applying set-ting “1-on” to each of the mentioned Binary settings, no trip command would be possible by corresponding stage, if an inrush condition is detected.
Since Inrush current contains a relatively large second harmonic component which is nearly absent during a fault current, the inrush restraint feature op-erates based on the evaluation of the second harmonic content which is present in the measured current. The inrush condition is recognized if the ra-tio of second harmonic current to fundamental component exceeds the set-ting values “HV Ratio_I2/I1”, “MV Ratio_I2/I1” or “LV Ratio_I2/I1” in each phase. The setting is applicable to both the definite stages of overcurrent protection element as well as the inverse time-current stage for each voltage side of the protected transformer. As soon as the measured ratio exceeds the set threshold, a restraint is applied to those stages for which corresponding setting is applied to make them blocked in inrush condition detection (“HV OC1 Inrush Block”, “HV OC2 Inrush Block” and “HV OC Inv Inrush Block” for HV side, “MV OC1 Inrush Block”, “MV OC2 Inrush Block” and “MV OC Inv Inrush Block” for MV side, “LV OC1 Inrush Block”, “LV OC2 Inrush Block” and “LV OC Inv Inrush Block” for LV side.).
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Since the applied restraint by second harmonic detection operates individu-ally per phase, the protection is fully operative even when the protected transformer is switched onto a single-phase fault, whereas inrush currents may possibly be present in one of the healthy phases. It is, however, possible to set the protection in a way that when the second harmonic recognition is fulfilled only in one single phase, not only the phase with the inrush current, but also the remaining phases of the overcurrent protection are blocked. This is achieved by cross-blocking the overcurrent protection for a certain period to avoid spurious tripping. The setting corresponds to “HV T2h_Cross_Blk”, “MV T2h_Cross_Blk”, “LV T2h_Cross_Blk”. Within this time, the overcurrent pro-tection in all three phases is blocked as soon as an inrush current is detected in any one phase. After the timer is expired, the overcurrent protection is blocked only in the phase with inrush current content. To put it more simply, cross blocking is reset if there is no more inrush in any phase, or the cross blocking time interval is elapsed. It should be noted that inrush currents flowing in the earth/ground path will not cross-block tripping by the phase elements.
Furthermore, if the fundamental component of phase current exceeds the upper limit value “HV Imax_2H_UnBlk”, “MV Imax_2H_UnBlk” or “LV Imax_2H_UnBlk”, the inrush restraint will no longer be effective in respective side, since a high-current fault is assumed in this case. The setting can be applied for each overcurrent element in each side of the protected trans-former.
2.3 Direction Determination Feature
The integrated directional function can be applied to each stage of overcur-rent element via dedicated Binary settings. These Binary settings include “HV OC1 Direction”, “HV OC2 Direction” and “HV OC Inv Direction” for HV side overcurrent stages, “MV OC1 Direction”, “MV OC2 Direction” and “MV OC Inv Direction” for MV side overcurrent stages and “LV OC1 Direction”, “LV OC2 Direction” and “LV OC Inv Direction” for LV side overcurrent stages. Fur-thermore, the directional orientation can be set individually for each stage of the overcurrent elements in various sides of the protected transformer. This can be performed by using Binary settings “HV OC1 Dir To Sys, “HV OC2 Dir To Sys” and “HV OC Inv Dir To Sys” for HV side, “MV OC1 Dir To Sys, “MV OC2 Dir To Sys” and “MV OC Inv Dir To Sys” for MV side, “LV OC1 Dir To Sys, “LV OC2 Dir To Sys” and “LV OC Inv Dir To Sys” for LV side. The possible settings for these Binary settings comprise “0-toward transformer” and “1-toward system”.
Basically, the direction determination is performed by determining the phase angle between the fault current and a reference voltage. The direction of a phase-directional element is detected by means of a cross-polarized voltage. It means that the fault current of the corresponding phase is used together with the healthy phase-to-phase voltage to determine direction of fault current. This takes effect to all three phases. Below figure shows the assignment of the measured values for the determination of fault direction for various types of pickups in phase overcurrent elements.
NOTE: The direction mentioned above is based on that the positive polarity is
Chapter 6 Overcurrent protection
87
at the side of the busbar and the negative polarity is at the side the trans-former.
Table 37 Voltage and current measurement used for direction determination
Phase Current Voltage
A aI bcU
B bI caU
C cI abU
As can be seen, the healthy voltages are used in direction determination. This allows for a correct direction determination even if the fault voltage has col-lapsed entirely because of a single-phase short-line fault. With three-phase short-line faults, memory voltage values are used to clearly determine the direction if the measurement voltages are not sufficient. The directional ele-ment of each side uses the voltage on itself side.
In a single-phase fault, the cross-polarized voltage (reference voltage) is 90° out of phase with the fault voltage. With phase-to-phase faults, the position of the reference voltage changes up to 30°, depending on the degree of collapse in the fault voltages. In order to satisfy different network conditions and ap-plications, the reference voltage can be rotated by an adjustable angle. For each side of the protected transformer, the directional angle can be set in-dependently. The settings include “HV Angle_OC”, “HV Angle_OC” and “LV Angle_OC”, for HV, MV and LV sides, respectively.
Forward
UBC_Ref
Angle_OC
IA
IA-
0°
90°
BisectorAngle_Range
OC
Figure 38 Overcurrent protection directional characteristic
where:
Angle_OC: The settable characteristic angle
Chapter 6 Overcurrent protection
88
Angle_Range OC: 85º
During direction decision by directional function, a VT Fail condition (a short circuit or broken wire in the voltage transformer's secondary circuit or opera-tion of the voltage transformer fuse) may result in false or undesired tripping by directional overcurrent elements. In such a situation, it is possible to select operation status of the directional overcurrent protection elements in each side by using a number of control worlds to block the overcurrent protection elements or keep them in operational state with no direction decision (block direction decision). The corresponding Binary settings include “Block HV OC at HV VT_FAIL”, “Block MV OC at MV VT_FAIL” and “Block LV OC at LV VT_FAIL”, for HV, MV and LV sides, respectively. When the Binary settings are set as 0 to select “HV OC1 Direction”, corresponding overcurrent protec-tion elements will not judge direction at the local side VT failure. When they set as 1 to select “Block OC at VT Fail”, no operation is possible by the overcurrent protection elements. It is noted that the Binary settings affect all the stages of corresponding overcurrent elements at each side. For instance, by applying setting “0- HV OC1 Direction”, all the three stages of the over-current element will remain operative without direction determination in case of any fault in secondary circuit of HV side voltage transformer. On the other hand, setting “1- Blk HV OC at HV VT_Fail” makes them blocked.
The logic for Definite and Inverse time IDMTL overcurrent protection is shown in below figure.
OC 1 (2)Trip
Direction Unit OK
OC Inv Trip
HV OC Direction on
DIR Positive
VT failure
Direct OK at VT FAIL
AND
AND
OR
HV Func_OC1 (2) on
I>HV I_OC1 (2)
Direction Unit OK
Inrush BLK OC
AND
HV T_OC1(2)
HV Func_OC Inv on
Inverse Curve>
Direction Unit OK
Inrush BLK OC
AND
t
“1”
“1”
“1”
Figure 39 Tripping logic for overcurrent protection
Chapter 6 Overcurrent protection
89
2.4 CBF initiation Feature
It is possible to set whether the overcurrent protection elements can initiate the integrated CBF protection or not. The available choices depend on the voltage side of the power transformer at which overcurrent protection is ap-plied. In this context, HV side overcurrent protection element always initiates HV side CBF function with no additional setting. However, it is possible to select whether it can initiate MV and LV CBF protection functions via Binary settings “HV OC Initiate LV CBF” and “HV OC Initiate MV CBF”, respectively.
MV side overcurrent protection element always initiates MV side CBF function with no additional setting. However, it is possible to select whether it can ini-tiate HV side CBF protection function via Binary setting “MV OC Initiate HV1 CBF”.
LV side overcurrent protection element always initiates LV side CBF function with no additional setting. However, it is possible to select whether it can ini-tiate HV side CBF protection function via Binary setting “LV OC Initiate HV1 CBF”.
More detail information about the initiation conditions and related Binary set-tings can be found as below.
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3 Input and output signals
IA1
IB1
IC1
IA2
IB2
IC2
UA
UB
UC
OC1 Trip
OC2 Trip
OC Inv Trip
Relay Startup
Overcurrent Protection
Figure 40 Overcurrent protection module
Table 38 Analog input list
Signal Description
IA1 Phase A current input of CT of circuit breaker 1 IB1 Phase B current input of CT of circuit breaker 1 IC1 Phase C current input of CT of circuit breaker 1 IA2 Phase A current input of CT of circuit breaker 2 IB2 Phase B current input of CT of circuit breaker 2 IC2 Phase C current input of CT of circuit breaker 2 UA Phase A voltage input UB Phase B voltage input UC Phase C voltage input
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Table 39 Binary output list
Signal Description
OC1 Trip Overcurrent stage 1 trip OC2 Trip Overcurrent stage 2 trip OC Inv Trip Overcurrent inverse stage trip
Relay Startup Relay Startup
4 Setting Table 40 Settings of overcurrent protection for HV side of transformer
Setting Unit Min.
(Ir:5A/1A) Max.
(Ir:5A/1A)
Default setting
(Ir:5A/1A) Description
HV I_OC1 A 0.05Ir 20Ir 5 HV overcurrent (O/C) current
setting for Stage 1
HV T_OC1 s 0 60 60 Time setting for HV OC,
Stage 1
HV I_OC2 A 0.05Ir 20Ir 5 HV overcurrent (O/C) current
setting for Stage 2
HV T_OC2 s 0 60 60 Time setting for HV OC,
Stage 2
HV Curve_OC Inv
1 12 1 Ref to appendix 3 page 307
HV I_OC Inv A 0.05Ir 20Ir 5 Ref to appendix 3 page 307
HV K_OC Inv 0.05 999 1 Ref to appendix 3 page 307
HV A_OC Inv s 0 200 0.14 Ref to appendix 3 page 307
HV B_OC Inv s 0 60 0 Ref to appendix 3 page 307
HV P_OC Inv 0 10 0.02 Ref to appendix 3 page 307
HV Angle_OC ° 0 90 45 The angle setting for voltage
ahead of current.
HV Imax_2H_UnBlk
A 0.25Ir 20Ir 5
The maximum 1st -harmonic
current setting to remove the
inrush block, in HV O/C pro-
tection
Chapter 6 Overcurrent protection
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Setting Unit Min.
(Ir:5A/1A) Max.
(Ir:5A/1A)
Default setting
(Ir:5A/1A) Description
HV Ratio_I2/I1 0.07 0.5 0.2
Inrush 2nd harmonic ratio set-
ting for blocking HV O/C
protection
HV T2h_Cross_Blk
s 0 60 20
Inrush 2nd harmonic
cross-block time for HV O/C
protection
Table 41 Binary settings of overcurrent protection for HV side of transformer
Setting Unit Min. Max. Default setting
Description
HV Func_OC1
0 1 0
The 1st stage of HV OC (OC_1)
protection is switched ON
1-on; 0-off.
HV OC1 Direc-tion 0 1 0
Direction (DIR) detection of HV
OC Stage 1 is switched ON
1-on; 0-off.
HV OC1 Dir To Sys
0 1 0
Direction unit of HV OC Stage 1
points to system
0 - point to the protected trans-
former
1- point to system HV OC1 Inrush Block 0 1 0
Inrush 2nd harmonic detection HV
OC Stage 1 is switched ON
1-on; 0-off.
HV Func_OC2
0 1 0
The 2nd stage of HV OC (OC_2)
protection is switched ON
1-on; 0-off. HV OC2 Direc-tion 0 1 0
Direction (DIR) detection of HV
OC Stage 2 is switched ON
1-on; 0-off.
HV OC2 Dir To Sys
0 1 0
Direction unit of HV OC Stage 2
points to system
0 - point to the protected trans-
former
1- point to system
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93
HV OC2 Inrush Block 0 1 0
Inrush 2nd harmonic detection HV
OC Stage 2 is switched ON
1-on; 0-off.
HV Func_OC Inv 0 1 0
The IDMTL inverse time stage of
HV OC protection is switched ON
1-on; 0-off. HV OC Inv Di-rection
0 1 0
Direction (DIR) detection of HV
OC IDMTL inverse time is
switched ON
1-on; 0-off. HV OC Inv Dir To Sys
0 1 0
Direction unit of HV OC IDMTL
inverse time points to system
0 - point to the protected trans-
former
1- point to system
HV OC Inv In-rush Block
0 1 0
Inrush 2nd harmonic detection HV
OC IDMTL inverse time is
switched ON
1-on; 0-off.
Block HV OC at HV VT_Fail
0 1 0
Select to block HV OC protection or exit direction unit, when HV VT fails 0- HV Direct OK at HV VT Fail 1- Blk HV OC at HV VT Fail
HV OC Initiate LV CBF 0 1 0
HV OC protection initiate LV side
CBF
0 - initiate, 1 – not initiate
HV OC Initiate MV CBF 0 1 0
HV OC protection initiate MV side
CBF
0 - initiate, 1 – not initiate
Table 42 Settings of overcurrent protection for MV side of transformer
Setting Unit Min.
(Ir:5A/1A) Max.
(Ir:5A/1A)
Default setting
(Ir:5A/1A) Description
MV I_OC1 A 0.05Ir 20Ir 5 MV overcurrent (O/C) current
setting for Stage 1
MV T_OC1 s 0 60 60 Time setting for MV OC,
Stage 1
Chapter 6 Overcurrent protection
94
MV I_OC2 A 0.05Ir 20Ir 5 MV overcurrent (O/C) current
setting for Stage 2
MV T_OC2 s 0 60 60 Time setting for MV OC,
Stage 2 MV Curve_OC Inv
1 12 1 Ref to appendix 3 page 307
MV I_OC Inv A 0.05Ir 20Ir 5 Ref to appendix 3 page 307
MV K_OC Inv 0.05 999 1 Ref to appendix 3 page 307
MV A_OC Inv s 0 200 0.14 Ref to appendix 3 page 307
MV B_OC Inv s 0 60 0 Ref to appendix 3 page 307
MV P_OC Inv 0 10 0.02 Ref to appendix 3 page 307
MV Angle_OC ° 0 90 45 The angle setting for voltage
ahead of current.
MV Imax_2H_UnBlk
A 0.25Ir 20Ir 5
The maximum 1st -harmonic
current setting to remove the
inrush block, in MV O/C pro-
tection
MV Ratio_I2/I1 0.07 0.5 0.2
Inrush 2nd harmonic ratio set-
ting for blocking MV O/C
protection
MV T2h_Cross_Blk
s 0 60 20
Inrush 2nd harmonic
cross-block time for MV O/C
protection
Table 43 Binary settings of overcurrent protection for MV side of transformer
Setting Unit Min. Max. Default setting
Description
MV Func_OC1
0 1 0
The 1st stage of MV OC (OC_1)
protection is switched ON
1-on; 0-off. MV OC1 Direc-tion 0 1 0
Direction (DIR) detection of MV OC
Stage 1 is switched ON
1-on; 0-off.
MV OC1 Dir To Sys
0 1 0
Direction unit of MV OC Stage 1
points to system
0 - point to the protected trans-
former
1- point to system
Chapter 6 Overcurrent protection
95
MV OC1 Inrush Block 0 1 0
Inrush 2nd harmonic detection MV
OC Stage 1 is switched ON
1-on; 0-off.
MV Func_OC2
0 1 0
The 2nd stage of MV OC (OC_2)
protection is switched ON
1-on; 0-off. MV OC2 Direc-tion 0 1 0
Direction (DIR) detection of MV OC
Stage 2 is switched ON
1-on; 0-off.
MV OC2 Dir To Sys
0 1 0
Direction unit of MV OC Stage 2
points to system
0 - point to the protected trans-
former
1- point to system MV OC2 Inrush Block 0 1 0
Inrush 2nd harmonic detection MV
OC Stage 2 is switched ON
1-on; 0-off.
MV Func_OC Inv 0 1 0
The IDMTL inverse time stage of
MV OC protection is switched ON
1-on; 0-off.
MV OC Inv Direction 0 1 0
Direction (DIR) detection of MV OC
IDMTL inverse time is switched ON
1-on; 0-off. MV OC Inv Dir To Sys
0 1 0
Direction unit of MV OC IDMTL in-
verse time points to system
0 - point to the protected trans-
former
1- point to system
MV OC Inv Inrush Block
0 1 0
Inrush 2nd harmonic detection MV
OC IDMTL inverse time is switched
ON
1-on; 0-off.
Block MV OC at MV VT_Fail
0 1 0
Select to block MV OC protection or exit direction unit, when MV VT fails 0- MV Direct OK at MV VT Fail 1- Blk MV OC at MV VT Fail
MV OC Initiate HV1 CBF 0 1 0
MV OC protection initiate HV1 side
CBF
0 - initiate, 1 – not initiate
Chapter 6 Overcurrent protection
96
Table 44 Settings of overcurrent protection for LV side of transformer
Unit Min.
(Ir:5A/1A) Max.
(Ir:5A/1A)
Default setting
(Ir:5A/1A) Description
LV I_OC1 A 0.05Ir 20Ir 5 LV overcurrent (O/C) current
setting for Stage 1
LV T_OC1 s 0 60 60 Time setting for LV OC,
Stage 1
LV I_OC2 A 0.05Ir 20Ir 5 LV overcurrent (O/C) current
setting for Stage 2
LV T_OC2 s 0 60 60 Time setting for LV OC,
Stage 2 LV Curve_OC Inv
1 12 1 Ref to appendix 3 page 307
LV I_OC Inv A 0.05Ir 20Ir 5 Ref to appendix 3 page 307
LV K_OC Inv 0.05 999 1 Ref to appendix 3 page 307
LV A_OC Inv s 0 200 0.14 Ref to appendix 3 page 307
LV B_OC Inv s 0 60 0 Ref to appendix 3 page 307
LV P_OC Inv 0 10 0.02 Ref to appendix 3 page 307
LV Angle_OC 0 90 45 The angle setting for voltage
ahead of current.
LV Imax_2H_UnBlk
0.25Ir 20Ir 5
The maximum 1st -harmonic
current setting to remove the
inrush block, in LV O/C pro-
tection
LV Ratio_I2/I1 0.07 0.5 0.2
Inrush 2nd harmonic ratio set-
ting for blocking LV O/C pro-
tection
LV T2h_Cross_Blk
0 60 20
Inrush 2nd harmonic
cross-block time for LV O/C
protection
Table 45 Binary settings of overcurrent protection for LV side of transformer
Setting Unit Min. Max. Default setting
Description
LV Func_OC1
0 1 0
The 1st stage of LV OC (OC_1)
protection is switched ON
1-on; 0-off.
Chapter 6 Overcurrent protection
97
LV OC1 Direc-tion 0 1 0
Direction (DIR) detection of LV
OC Stage 1 is switched ON
1-on; 0-off.
LV OC1 Dir To Sys
0 1 0
Direction unit of LV OC Stage 1
points to system
0 - point to the protected trans-
former
1- point to system LV OC1 Inrush Block 0 1 0
Inrush 2nd harmonic detection
LV OC Stage 1 is switched ON
1-on; 0-off.
LV Func_OC2
0 1 0
The 2nd stage of LV OC (OC_2)
protection is switched ON
1-on; 0-off. LV OC2 Direc-tion 0 1 0
Direction (DIR) detection of LV
OC Stage 2 is switched ON
1-on; 0-off.
LV OC2 Dir To Sys
0 1 0
Direction unit of LV OC Stage 2
points to system
0 - point to the protected trans-
former
1- point to system
LV OC2 Inrush Block 0 1 0
Inrush 2nd harmonic detection
LV OC Stage 2 is switched ON
1-on; 0-off. LV Func_OC Inv 0 1 0
The IDMTL inverse time stage of
LV OC protection is switched ON
1-on; 0-off.
LV OC Inv Di-rection
0 1 0
Direction (DIR) detection of LV
OC IDMTL inverse time is
switched ON
1-on; 0-off.
LV OC Inv Dir To Sys
0 1 0
Direction unit of LV OC IDMTL
inverse time points to system
0 - point to the protected trans-
former
1- point to system
Chapter 6 Overcurrent protection
98
LV OC Inv In-rush Block
0 1 0
Inrush 2nd harmonic detection LV
OC IDMTL inverse time is
switched ON
1-on; 0-off. Block LV OC at LV VT_Fail
0 1 0
Select to block LV OC protection or exit direction unit, when LV VT fails 0- LV Direct OK at LV VT Fail 1- Blk LV OC at LV VT Fail
LV OC Initiate HV1 CBF 0 1 0
LV OC protection initiate HV1
side CBF
0 - initiate, 1 – not initiate
5 Report Table 46 Event report list
Information Description
HV OC Inv Trip Inverse time stage of HV overcurrent protection trip
HV OC1 Trip HV overcurrent stage 1 trip
HV OC2 Trip HV overcurrent stage 2 trip
MV OC Inv Trip Inverse time stage of MV overcurrent protection trip
MV OC1 Trip MV overcurrent stage 1 trip
MV OC2 Trip MV overcurrent stage 2 trip
LV OC Inv Trip Inverse time stage of LV overcurrent protection trip
LV OC1 Trip LV overcurrent stage 1 trip
LV OC2 Trip LV overcurrent stage 2 trip
Table 47 Operation report list
Information Description
HV Func_OC On Overcurrent protection of HV side is switched ON (by CW)
HV Func_OC Off Overcurrent protection of HV side is switched OFF (by CW)
MV Func_OC On Overcurrent protection of MV side is switched ON (by CW)
MV Func_OC Off Overcurrent protection of MV side is switched OFF (by CW)
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99
Information Description
LV Func_OC On Overcurrent protection of LV side is switched ON (by CW)
LV Func_OC Off Overcurrent protection of LV side is switched OFF (by CW)
Chapter 6 Overcurrent protection
100
6 Technical data Table 48 Overcurrent protection technical data
Item Rang or Value Tolerance
Definite time characteristics
Current 0.08 Ir to 20.00 Ir ≤ ±3% setting or ±0.02Ir
Time delay 0.00 to 60.00s, step 0.01s ≤ ±1% setting or +40ms, at 200% operating setting
Reset time approx. 40ms
Reset ratio Approx. 0.95 at I/In ≥ 0.5
Inverse time characteristics
Current 0.08 Ir to 20.00 Ir ≤ ±3% setting or ±0.02Ir
IEC standard Normal inverse;
Very inverse;
Extremely inverse;
Long inverse
≤ ±5% setting + 40ms, at 2
<I/IRSETTINGR < 20, in accordance
with IEC60255-151
ANSI Inverse;
Short inverse;
Long inverse;
Moderately inverse;
Very inverse;
Extremely inverse;
Definite inverse
≤ ±5% setting + 40ms, at 2
<I/ISETTING < 20, in accord-
ance with ANSI/IEEE C37.112,
user-defined characteristic
T=
≤ ±5% setting + 40ms, at 2
<I/IRSETTINGR < 20, in accordance
with IEC60255-151
Time factor of inverse time, A 0.005 to 200.0s, step 0.001s
Delay of inverse time, B 0.000 to 60.00s, step 0.01s
Index of inverse time, P 0.005 to 10.00, step 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
Reset time approx. 40ms,
Directional element
Operating area range 170° ≤ ±3°, at phase to phase volt-age >1V Characteristic angle 0° to 90°, step 1°
Chapter 7 Earth fault protection
101
Chapter 7 Earth fault protection
About this chapter This chapter describes the protection principle, input and output signals, parameter, IED report and technical data for earth fault protection function.
Chapter 7 Earth fault protection
102
1 Protection principle
1.1 Protection elements
Each voltage side of the protected transformer is provided with three earth fault protection elements from which two elements operate as definite earth fault stages and the other one operates with inverse time-current characteris-tic. All the elements can operate in conjunction with the integrated inrush re-straint and directional functions.
Various stages of each element are independent from each other and can be combined as desired. They can be enabled or disabled in each side using dedicated Binary settings. These Binary settings include “HV Func_EF1”, “HV Func_EF2” and “HV Func_EF Inv” on, for HV side earth fault protection, “MV Func_EF1”, “MV Func_EF2” and “MV Func_EF Inv”, for MV side earth fault protection, “LV Func_EF1”, “LV Func_EF2” and “LV Func_EF Inv”, for LV side earth fault protection. For example by applying setting “1-on” to “HV Func_EF1”, respective stage of earth fault protection would be enabled in HV side.
Individual pickup value for each definite stage can be defined by setting “HV 3I0_EF1” and “HV 3I0_EF2” for HV side, “MV 3I0_EF1” and “MV 3I0_EF2” for MV side, “LV 3I0_EF1” and “LV 3I0_EF2” for LV side. By applying these set-tings, each earth current (quantity 3I0) calculated from the three phase cur-rents is compared separately with the setting value for each stage. If the re-spective value is exceeded, a trip time delay timer is started. The condition for start of the delay timer is expressed mathematically:
setII 00 33 >
Equation 33
The timer is set to count up to a user-defined time delay. The time delay can be set for each definite stage individually through settings “HV T_EF1” and “HV T_EF2” for HV side, “MV T_EF1” and “MV T_EF2” for MV side, “LV T_EF1” and “LV T_EF2” for LV side. After the user-defined time delay has been elapsed, a trip signal is issued if the inrush restraint feature is applied and no inrush current is detected or inrush restraint is disabled. The earth fault protection would be blocked and therefore, no tripping takes place if the inrush restraint feature is enabled and an inrush condition exists. However, an alarm report is issued nominated as “HV EF1 Inrush Block”, “HV EF2 Inrush Block” or “HV EF Inv Inrush Block”, indicating the blocking condition of earth fault element caused by inrush condition detection.
Pickup value for the inverse time-current stage can be set by setting “HV 3I0_EF Inv”, “MV 3I0_EF Inv” and “LV 3I0_EF Inv” for HV, MV and LV sides, respectively. Each earth current (quantity 3I0) calculated from the three phase
Chapter 7 Earth fault protection
103
currents is separately compared with corresponding setting value. If a current exceeds 1.1 times the setting value, corresponding stage picks up. When an inverse time-current stage picks up, the tripping time is calculated from the calculated quantity 3I0, using the selected tripping curve. Maximum tripping time is limited to 100s.
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 fol-lowing equation:
_
_ _ _
-1HP EF Inv
S
A EF Invt K EF Inv B EF InvII
é ùê úê úê ú= ´ +ê úé ùê úê úê úê úê úë ûë û
Equation 34
Where I is the calculated earth fault current;
Is is the current setting;
xV A_EF Inv: xV(HV/MV/LV) side time factor for inverse time stage
xV B_EF Inv: xV(HV/MV/LV) time delay for inverse time stage
xV P_EF Inv: xV(HV/MV/LV) index for inverse time stage
xV K_EF Inv: xV(HV/MV/LV) time multiplier Inrush restraint feature
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.
As mentioned previously, selection among the curves can be carried out by settings “HV Curve_EF Inv”, “MV Curve_EF Inv” and “LV Curve_EF Inv” for HV, MV and LV sides, respectively. Furthermore, the time multiplier K_EF Inv can be applied by user to coordinate the integrated inverse time-current characteristic of the device with other earth fault relays installed for power system protection. This can be performed by settings “HV K_EF Inv”, “MV K_EF Inv” and “LV K_EF Inv” in case of HV, MV and LV earth fault elements.
By applying pickup current and time multiplier settings, the device determines the tripping time from the calculated earth current, based on the selected in-verse curve. Once the calculated time has been elapsed, a trip signal is is-sued provided that no inrush current is detected or inrush restraint is disabled. If the inrush restraint feature is enabled and an inrush condition exists the earth fault protection would be blocked and therefore no tripping takes place.
Chapter 7 Earth fault protection
104
However, an alarm report is issued designated as “HV Inrush Blk BU”, “MV Inrush Blk BU” or “LV Inrush Blk BU”, indicating the blocking condition of overcurrent element caused by inrush condition detection.
The trip signals and corresponding event reports are available separately for each stage. They include “HV EF_1 Trip”, “HV EF_2 Trip” and “HV IDMTL EF Trip” for HV side, “MV EF_1 Trip”, “MV EF_2 Trip” and “MV IDMTL EF Trip” for MV side, “LV EF_1 Trip”, “LV EF_1 Trip” and “LV IDMTL EF Trip” for LV side earth fault elements.
1.2 Inrush Restraint Feature
The transformer earth fault protection may detect large magnetizing inrush currents flowing when transformer is energized. The inrush current may be several times of the nominal current, and may last from several tens of milli-seconds to several seconds.
Inrush current comprises second harmonic as well as a considerable funda-mental component. So, it may affect earth fault protection which operates based on the fundamental component of the measured current. Inrush blocking unit in earth fault function is provided for this purpose.
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 settings “HV EF1 Inrush Block”, “HV EF2 Inrush Block” and “HV EF Inv Inrush Block” for HV side, “MV EF1 Inrush Block”, “MV EF2 Inrush Block” and “MV EF Inv Inrush Block” for MV side, “LV EF1 Inrush Block”, “LV EF2 Inrush Block” and “LV EF Inv Inrush Block” on for LV side. By applying setting “1-on” to each of the mentioned Binary settings, no trip command would be possible by corresponding stage, if an inrush condition is detected.
Since the inrush current contains a relatively large second harmonic compo-nent which is nearly absent during a fault current, the inrush restraint oper-ates based on the evaluation of the second harmonic content which is present in the phase currents. The inrush condition is recognized if the ratio of second harmonic current to the fundamental component exceeds the setting value “HV Ratio_I2/I1_EF”, “MV Ratio_I2/I1_EF” or “LV Ratio_I2/I1_EF” in each phase current. The setting is applicable to both the 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 restraint is applied to those stages for which corresponding setting is applied to make them blocked in inrush condition detection (“HV EF1 Inrush Block”, “HV EF2 Inrush Block” and “HV EF Inv Inrush Block” on for HV side, “MV EF1 Inrush Block”, “MV EF2 Inrush Block” and “MV EF Inv Inrush Block” for MV side, “LV EF_1 Inrush Detect ON”, “LV EF1 Inrush Block”, “LV EF2 Inrush Block” and “LV EF Inv Inrush Block” for LV side).
Furthermore, if the fundamental component of each phase current exceeds the upper limit value “HV Ratio_I2/I1”, “MV Ratio_I2/I1” or “LV Ratio_I2/I1”, the inrush restraint will no longer effective in respective side, since a high-current fault is assumed in this case.
Chapter 7 Earth fault protection
105
1.3 Direction Determination Feature
The integrated directional function can be applied to each stage of earth fault elements via Binary settings. The Binary settings include “HV EF1 Direction”, “HV EF2 Direction” and “HV EF Inv Direction” on for HV side earth fault stages, “MV EF1 Direction”, “MV EF2 Direction” and “MV EF Inv Direction” for MV side earth fault stages and “LV EF1 Direction”, “LV EF2 Direction” and “LV EF Inv Direction” for LV side earth fault stages.
Furthermore, the directional orientation can be set individually for each stage of earth fault elements in various sides of the protected transformer. This can be performed by Binary settings “HV EF1 Dir To Sys”, “HV EF2 Dir To Sys” and “HV EF Inv Dir To Sys” for HV side, “MV EF1 Dir To Sys”, “MV EF2 Dir To Sys” and “MV EF Inv Dir To Sys” for MV side, “LV EF1 Dir To Sys”, “LV EF2 Dir To Sys” and “LV EF Inv Dir To Sys” for LV side. The possible settings for these Binary setting comprise “0-toward transformer” and “1-toward system”.
Basically, the direction determination is performed by comparing the zero sequence system quantities. In the current path, 3I0 current is calculated from the sum of the three phase currents. In the voltage path, the device calculates the zero sequence voltage 3V0 from the sum of the three phase voltages. Contrary to the directional phase elements, which work with the un-faulted voltage as reference voltage, the fault voltage itself is the reference voltage for the directional ground element. Depending on the connection of the volt-age transformer, this is the voltage 3V0 or VN. The directional element at each side operates with the residual/ neutral voltage of the same side.
In order to satisfy different network conditions and applications, the reference voltage can be rotated by an adjustable angle. For each side of the protected transformer, the directional angle can be set independently. The settings in-clude “HV Angle_EF”, “MV Angle_EF” and “LV Angle_EF”, for HV, MV and LV sides, respectively. It should be noted that the settings affect all the directional stages of the corresponding earth fault element.
NOTE: The direction mentioned above is based on that the positive polarities of
three phases CT. The voltage used by directional element is calculated by
three phase voltage. Details are shown as below.
Below figure 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.
Chapter 7 Earth fault protection
106
Forward
Angle_EF
Bisector
0_Ref3U
0°
-3I 0
3I 090°
Angle_Range EF
Figure 41 Characteristic of zero sequence directional element
where:
Angle_EF: The settable characteristic angle
Angle_Range EF: 80º
During direction decision by directional function, a VT Fail condition (a short circuit or broken wire in the voltage transformer's secondary system or an operation of the voltage transformer fuse) may result in false or undesired tripping by directional earth fault elements. In such a situation, it is possible to select operation status of the directional earth fault protection elements in each side by using a number of Binary settings to block the earth fault pro-tection elements or keep them in operational state with no direction decision (block direction decision). The Binary settings are designated as “Block HV EF at HV VT_Fail”, “Block MV EF at HV VT_Fail” and “Block LV EF at HV VT_Fail”, for HV, MV and LV sides, respectively. When the Binary settings are set as 0 to select “Direct OK at VT Fail”, corresponding earth fault protection elements will not judge direction at the local side VT failure. When they set as 1 to select “Block EF at VT Fail”, no operation is possible by the earth fault protection elements. It is noted that the Binary settings affect all the stages of corresponding earth fault elements at each side. For instance, by applying setting “Block HV EF at HV VT_Fail” off, all the three stages of the earth fault element will remain operative without direction determination in case of any fault in secondary circuit of HV side voltage transformer. On the other hand, setting “Block HV EF at HV VT_Fail” on makes them blocked.
It is possible to block earth fault protection elements in each side of the pro-tected transformer if a CT fail is detected in the same side. This can be per-formed by Binary settings “Block HV EF at HV CT_Fail”, “Blk MV EF at MV CT_FAIL” and “Blk LV EF at LV CT FAIL” in each voltage side. If setting 1 is applied to these Binary settings, any CT fail detection in a given side of the power transformer would bring blocking condition to all stages of the earth
Chapter 7 Earth fault protection
107
fault element which is applied in the same side.
The logic for definite and inverse time IDMTL earth fault protection is shown in below figure.
E/F Trip
E/F Direction Unit OK
IDMTL E/F Trip
HV EF Direction on
DIR Positive
VT failure
Direct OK at VT FAIL
AND
OR
AND
AND
HV Func_EF1 (2) on
3I0>HV 3I0_EF1(2)
Direction Unit OK
Inrush BLK EF
HV T_EF1(2)
HV Func_EF Inv on
Inverse Curve>
E/F Direction OK
Inrush BLK EF
AND
t
“1”
“1”
“1”
Figure 42 Tripping logic for earth fault protection
1.4 CBF initiation Feature
It is possible to set whether the earth fault protection elements can initiate the integrated CBF protection or not. The available choices depend on the volt-age side of the power transformer at which earth fault protection is applied. In this context, HV side earth fault protection element always initiates HV side CBF function with no additional setting. However, it is possible to select whether it can initiate MV and LV CBF protection functions via Binary settings “HV EF Initiate LV CBF” and “HV EF Initiate MV CBF” on, respectively.
MV side earth fault protection element always initiates MV side CBF function with no additional setting. However, it is possible to select whether it can ini-tiate HV side CBF protection function via Binary setting “MV EF Initiate HV1 CBF” on.
More detail information about the initiation conditions and related Binary set-tings can be found in below table.
Chapter 7 Earth fault protection
108
2 Input and output signals
IA1
IB1
IC1
IA2
IB2
IC2
UA
UB
UC
EF1 Trip
EF2 Trip
EF Inv Trip
Relay Startup
Earth Fault Protection
Figure 43 Earth fault protection module
Table 49 Analog input list
Signal Description
IA1 Phase A current input of CT of circuit breaker 1 IB1 Phase B current input of CT of circuit breaker 1 IC1 Phase C current input of CT of circuit breaker 1 IA2 Phase A current input of CT of circuit breaker 2 IB2 Phase B current input of CT of circuit breaker 2 IC2 Phase C current input of CT of circuit breaker 2 UA Phase A voltage input of VT of related winding of transformer UB Phase B voltage input of VT of related winding of transformer UC Phase C voltage input of VT of related winding of transformer
Table 50 Binary output list
Signal Description
EF1 Trip Earth Fault stage 1 trip EF2 Trip Earth Fault stage 2 trip EF Inv Trip Earth Fault inverse stage trip
Chapter 7 Earth fault protection
109
Signal Description
Relay Startup Relay Startup
3 Setting Table 51 Settings of earth fault protection for HV side of transformer
Setting Unit Min.
(Ir:5A/1A)
Max. (Ir:5A/1
A)
Default setting (Ir:5A/1
A)
Description
HV 3I0_EF1 A 0.05Ir 20Ir 5 HV earth fault (E/F) protection
current setting for Stage 1
HV T_EF1 s 0 60 60 Time setting for HV E/F, Stage 1
HV 3I0_EF2 A 0.05Ir 20Ir 5 HV earth fault (E/F) current set-
ting for Stage 2
HV T_EF2 s 0 60 60 Time setting for HV E/F, Stage 2
HV Curve_EF Inv
1 12 1 Ref to appendix 3 page 307
HV 3I0_EF Inv
A 0.05Ir 20Ir 1.2 Ref to appendix 3 page 307
HV K_EF Inv
0.05 999 1 Ref to appendix 3 page 307
HV A_EF Inv
s 0 200 0.14 Ref to appendix 3 page 307
HV B_EF Inv
s 0 60 0 Ref to appendix 3 page 307
HV P_EF Inv
0 10 0.02 Ref to appendix 3 page 307
HV An-gle_EF
° 0 90 45 The angle setting for voltage
ahead of current.
HV Imax_2H_UnBlk_EF
A 0.25Ir 20Ir 5
The maximum 1st -harmonic cur-
rent setting to remove the inrush
block, in HV EF protection
HV Ra-tio_I2/I1_EF
0.07 0.5 0.2
The maximum 1st -harmonic cur-
rent setting to remove the inrush
block, in HV EF protection
Chapter 7 Earth fault protection
110
Table 52 Binary settings of earth fault protection for HV side of transformer
Setting Unit Min. Max. Default setting
Description
HV Func_EF1 0 1 0
The 1st stage of HV earth fault
(EF_1) protection is switched ON
1-on; 0-off.
HV EF1 Direction 0 1 0
Direction (DIR) detection of HV EF
Stage 1 is switched ON
1-on; 0-off.
HV EF1 Dir To Sys
0 1 0
Direction unit of HV EF Stage 1
points to system
0 - point to the protected trans-
former
1- point to system
HV EF1 Inrush Block
0 1 0
Inrush 2nd harmonic detection HV
EF Stage 1 is switched ON
1-on; 0-off.
HV Func_EF2 0 1 0
The 2nd stage of HV earth fault
(EF_2) protection is switched ON
1-on; 0-off.
HV EF2 Direction 0 1 0
Direction (DIR) detection of HV EF
Stage 2 is switched ON
1-on; 0-off.
HV EF2 Dir To Sys
0 1 0
Direction unit of HV EF Stage 2
points to system
0 - point to the protected trans-
former
1- point to system
HV EF2 Inrush Block
0 1 0
Inrush 2nd harmonic detection HV
EF Stage 2 is switched ON
1-on; 0-off.
HV Func_EF Inv 0 1 0
The IDMTL inverse time stage of
HV EF protection is switched ON
1-on; 0-off.
HV EF Inv Direc-tion
0 1 0
Direction (DIR) detection of HV EF
IDMTL inverse time is switched
ON
1-on; 0-off.
Chapter 7 Earth fault protection
111
HV EF Inv Dir To Sys
0 1 0
Direction unit of HV EF IDMTL
inverse time points to system
0 - point to the protected trans-
former
1- point to system
HV EF Inv Inrush Block
0 1 0
Inrush 2nd harmonic detection HV
EF IDMTL inverse time is
switched ON
1-on; 0-off.
Block HV EF at HV VT_Fail
0 1 0
Select to block HV EF protection or exit direction unit, when HV VT fails 0 - HV Direct OK at HV VT Fail 1 - Blk HV EF at HV VT Fail
Block HV EF at HV CT_Fail
0 1 0 Block HV EF when there is HV CT failure 1-Block; 0-NOT block
HV EF Initiate LV CBF
0 1 0
HV EF protection initiate LV side
CBF
0 - initiate, 1 – not initiate
HV EF Initiate MV CBF
0 1 0
HV EF protection initiate MV side
CBF
0 - initiate, 1 – not initiate
Table 53 Settings of earth fault protection for MV side of transformer
Setting Unit Min.
(Ir:5A/1A)
Max. (Ir:5A/1
A)
Default setting (Ir:5A/1
A)
Description
MV 3I0_EF1
A 0.05Ir 20Ir 5 MV earth fault (E/F) protection
current setting for Stage 1
MV T_EF1 s 0 60 60 Time setting for MV E/F, Stage 1
MV 3I0_EF2
A 0.05Ir 20Ir 5 MV earth fault (E/F) current set-
ting for Stage 2
MV T_EF2 s 0 60 60 Time setting for MV E/F, Stage 2
MV Curve_EF Inv
1 12 1 Ref to appendix 3 page 307
MV 3I0_EF Inv
A 0.05Ir 20Ir 5 Ref to appendix 3 page 307
Chapter 7 Earth fault protection
112
MV K_EF Inv
0.05 999 1 Ref to appendix 3 page 307
MV A_EF Inv
s 0 200 0.14 Ref to appendix 3 page 307
MV B_EF Inv
s 0 60 0 Ref to appendix 3 page 307
MV P_EF Inv
0 10 0.02 Ref to appendix 3 page 307
MV An-gle_EF
° 0 90 45 The angle setting for voltage
ahead of current.
MV Imax_2H_UnBlk_EF
A 0.25Ir 20Ir 5
The maximum 1st -harmonic cur-
rent setting to remove the inrush
block, in MV E/F protection
MV Ra-tio_I2/I1_EF
0.07 0.5 0.2 Inrush 2nd harmonic ratio setting
for blocking MV E/F protection
Table 54 Binary settings of earth fault protection for MV side of transformer
Setting Unit Min. Max. Default setting
Description
MV Func_EF1 0 1 0
The 1st stage of MV earth fault
(EF_1) protection is switched ON
1-on; 0-off.
MV EF1 Direction 0 1 0
Direction (DIR) detection of MV
EF Stage 1 is switched ON
1-on; 0-off.
MV EF1 Dir To Sys
0 1 0
Direction unit of MV EF Stage 1
points to system
0 - point to the protected trans-
former
1- point to system
MV EF1 Inrush Block
0 1 0
Inrush 2nd harmonic detection MV
EF Stage 1 is switched ON
1-on; 0-off.
MV Func_EF2 0 1 0
The 2nd stage of MV earth fault
(EF_2) protection is switched ON
1-on; 0-off.
MV EF2 Direction 0 1 0
Direction (DIR) detection of MV
EF Stage 2 is switched ON
1-on; 0-off.
Chapter 7 Earth fault protection
113
MV EF2 Dir To Sys
0 1 0
Direction unit of MV EF Stage 2
points to system
0 - point to the protected trans-
former
1- point to system
MV EF2 Inrush Block
0 1 0
Inrush 2nd harmonic detection MV
EF Stage 2 is switched ON
1-on; 0-off.
MV Func_EF Inv 0 1 0
The IDMTL inverse time stage of
MV EF protection is switched ON
1-on; 0-off.
MV EF Inv Direc-tion
0 1 0
Direction (DIR) detection of MV
EF IDMTL inverse time is
switched ON
1-on; 0-off.
MV EF Inv Dir To Sys
0 1 0
Direction unit of MV EF IDMTL
inverse time points to system
0 - point to the protected trans-
former
1- point to system
MV EF Inv Inrush Block
0 1 0
Inrush 2nd harmonic detection MV
EF IDMTL inverse time is
switched ON
1-on; 0-off.
Block MV EF at MV VT_Fail
0 1 0
Select to block MV EF protection
or exit direction unit, when MV VT
fails
0 - MV Direct OK at MV VT Fail
1 - Blk MV EF at MV VT Fail
Block MV EF at MV CT_Fail
0 1 0
Block MV EF when there is MV CT
failure
1-Block; 0-NOT block
MV EF Initiate HV CBF
0 1 0
MV EF protection initiate HV1 side
CBF
0 - initiate, 1 – not initiate
Chapter 7 Earth fault protection
114
Table 55 Settings of earth fault protection for LV side of transformer
Setting Unit Min.
(Ir:5A/1A)
Max. (Ir:5A/1
A)
Default setting (Ir:5A/1
A)
Description
LV 3I0_EF1 A 0.05Ir 20Ir 5 LV earth fault (E/F) protection
current setting for Stage 1
LV T_EF1 s 0 60 60 Time setting for LV E/F, Stage 1
LV 3I0_EF2 A 0.05Ir 20Ir 5 LV earth fault (E/F) current setting
for Stage 2
LV T_EF2 s 0 60 60 Time setting for LV E/F, Stage 2
LV Curve_EF Inv
1 12 1 Ref to appendix 3 page 307
LV 3I0_EF Inv
A 0.05Ir 20Ir 5 Ref to appendix 3 page 307
LV K_EF Inv 0.05 999 1 Ref to appendix 3 page 307
LV A_EF Inv s 0 200 0.14 Ref to appendix 3 page 307
LV B_EF Inv s 0 60 0 Ref to appendix 3 page 307
LV P_EF Inv 0 10 0.02 Ref to appendix 3 page 307
LV An-gle_EF
° 0 90 45 The angle setting for voltage
ahead of current.
LV Imax_2H_UnBlk_EF
A 0.25Ir 20Ir 5
The maximum 1st -harmonic cur-
rent setting to remove the inrush
block, in LV E/F protection
LV Ra-tio_I2/I1_EF
0.07 0.5 0.2 Inrush 2nd harmonic ratio setting
for blocking LV E/F protection
Table 56 Binary settings of earth fault protection for LV side of transformer
Setting Unit Min. Max. Default setting
Description
LV Func_EF1 0 1 0
The 1st stage of LV earth fault
(EF_1) protection is switched ON
1-on; 0-off.
LV EF1 Direction 0 1 0
Direction (DIR) detection of LV EF
Stage 1 is switched ON
1-on; 0-off.
Chapter 7 Earth fault protection
115
LV EF1 Dir To Sys
0 1 0
Direction unit of LV EF Stage 1
points to system
0 - point to the protected trans-
former
1- point to system
LV EF1 Inrush Block
0 1 0
Inrush 2nd harmonic detection LV
EF Stage 1 is switched ON
1-on; 0-off.
LV Func_EF2 0 1 0
The 2nd stage of LV earth fault
(EF_2) protection is switched ON
1-on; 0-off.
LV EF2 Direction 0 1 0
Direction (DIR) detection of LV EF
Stage 2 is switched ON
1-on; 0-off.
LV EF2 Dir To Sys
0 1 0
Direction unit of LV EF Stage 2
points to system
0 - point to the protected trans-
former
1- point to system
LV EF2 Inrush Block
0 1 0
Inrush 2nd harmonic detection LV
EF Stage 2 is switched ON
1-on; 0-off.
LV Func_EF Inv 0 1 0
The IDMTL inverse time stage of
LV EF protection is switched ON
1-on; 0-off.
LV EF Inv Direc-tion
0 1 0
Direction (DIR) detection of LV EF
IDMTL inverse time is switched
ON
1-on; 0-off.
LV EF Inv Dir To Sys
0 1 0
Direction unit of LV EF IDMTL
inverse time points to system
0 - point to the protected trans-
former
1- point to system
LV EF Inv Inrush Block
0 1 0
Inrush 2nd harmonic detection LV
EF IDMTL inverse time is
switched ON
1-on; 0-off.
Chapter 7 Earth fault protection
116
Block LV EF at LV VT_Fail
0 1 0
Select to block LV EF protection or
exit direction unit, when LV VT
fails
0 - LV Direct OK at LV VT Fail
1 - Blk LV EF at LV VT Fail
Block LV EF at LV CT_Fail
0 1 0
Block LV EF when there is LV CT
failure
1-Block; 0-NOT block
LV EF Initiate HV CBF
0 1 0
LV EF protection initiate HV1 side
CBF
0 - initiate, 1 – not initiate
4 Report Table 57 Event report list
Information Description
HV EF Inv Trip Inverse time stage of HV earth fault protection trip
HV EF1 Trip HV earth fault stage 1 trip
HV EF2 Trip HV earth fault stage 2 trip
MV EF Inv Trip Inverse time stage of MV earth fault protection trip
MV EF1 Trip MV earth fault stage 1 trip
MV EF2 Trip MV earth fault stage 2 trip
LV EF Inv Trip Inverse time stage of LV earth fault protection trip
LV EF1 Trip LV earth fault stage 1 trip
LV EF2 Trip LV earth fault stage 2 trip
Table 58 Operation report list
Information Description
HV Func_EF On Earth fault protection of HV side is switched ON (by CW)
HV Func_EF Off Earth fault protection of HV side is switched OFF (by CW)
MV Func_EF On Earth fault protection of MV side is switched ON (by CW)
MV Func_EF Off Earth fault protection of MV side is switched OFF (by CW)
LV Func_EF On Earth fault protection of LV side is switched ON (by CW)
LV Func_EF Off Earth fault protection of LV side is switched OFF (by CW)
Chapter 7 Earth fault protection
117
5 Technical data Table 59 Earth fault protection technical data
Item Rang or value Tolerance
Definite time characteristic
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
Reset time approx. 40ms
Reset ratio Approx. 0.95 at I/Ir ≥ 0.5
Inverse time characteristics
Current 0.08 Ir to 20.00 Ir ≤ ±3% setting or ±0.02Ir
IEC standard Normal inverse;
Very inverse;
Extremely inverse;
Long inverse
IEC60255-151
≤ ±5% setting + 40ms, at 2
<I/IRSETTINGR < 20
ANSI Inverse;
Short inverse;
Long inverse;
Moderately inverse;
Very inverse;
Extremely inverse;
Definite inverse
ANSI/IEEE C37.112,
≤ ±5% setting + 40ms, at 2
<I/IRSETTINGR < 20
user-defined characteristic
T=
IEC60255-151
≤ ±5% setting + 40ms, at 2
<I/IRSETTINGR < 20
Time factor of inverse time, A 0.005 to 200.0s, step
0.001s
Delay of inverse time, B 0.000 to 60.00s, step 0.01s
Index of inverse time, P 0.005 to 10.00, step 0.005
set time Multiplier for step n: k 0.05 to 999.0, step 0.01
Minimum operating time 20ms
Maximum operating time 100s
Reset mode instantaneous
Reset time approx. 40ms
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 160° ≤ ±3°, at 3U2≥2V
Chapter 7 Earth fault protection
118
sequence directional element
Characteristic angle 50° to 90°, step 1°
Chapter 7 Earth fault protection
119
Chapter 8 Neutral earth fault protection
120
Chapter 8 Neutral earth fault protection
About this chapter This chapter describes the protection principle, input and output signals, parameter, IED report and technical data for neutral earth fault protection function.
Chapter 8 Neutral earth fault protection
121
1 Protection principle 1.1 Protection Elements
Each voltage side of the protected transformer is provided with three neutral earth fault protection elements from which two elements operate as definite earth fault stages and the other one operates with inverse time-current char-acteristic. All the elements can operate in conjunction with the integrated in-rush restraint and directional functions.
Various stages of each element are independent from each other and can be combined as desired. They can be enabled or disabled in each side using dedicated Binary settings. These Binary settings include “HV Func_Neu OC1”, “HV Func_Neu OC2” and “HV Func_Neu OC Inv”, for HV side earth fault protection, “MV Func_Neu OC1”, “MV Func_Neu OC2” and “MV Func_Neu OC Inv”, for MV side earth fault protection, “LV Func_Neu OC1”, “LV Func_Neu OC2” and “LV Func_Neu OC Inv”, for LV side earth fault protection. For example by applying setting “1-on” to “HV Func_Neu OC1”, respective stage of neutral earth fault protection would be enabled in HV side.
Individual pickup value for each definite stage can be defined by setting “HV 3I0_Neutral OC1” and “HV 3I0_Neutral OC2” for HV side, “MV 3I0_Neutral OC1” and “MV 3I0_Neutral OC2” for MV side, “LV 3I0_Neutral OC1” and “LV 3I0_Neutral OC2” for LV side. By applying these settings, each neutral current (quantity IN) measured from the installed neutral CT is compared separately with the setting value for each stage. If the respective value is exceeded, a trip time delay timer is started. The condition for start of the delay timer is ex-pressed mathematically:
setNN II _>
Equation 35
The timer is set to count up to a user-defined time delay. The time delay can be set for each definite stage individually through settings “HV T_Neutral OC1” and “HV T_Neutral OC2” for HV side, “MV T_Neutral OC1” and “MV T_Neutral OC2” for MV side, “LV T_Neutral OC1” and “LV T_Neutral OC2” for LV side. After the user-defined time delay has been elapsed, a trip signal is issued if the inrush restraint feature is applied and no inrush current is de-tected or inrush restraint is disabled. The neutral earth fault protection would be blocked and therefore, no tripping takes place if the inrush restraint feature is enabled and an inrush condition exists. However, an alarm report is issued nominated as “HV Inrush Blk BU”, “MV Inrush Blk BU” or “LV Inrush Blk BU”, indicating the blocking condition of neutral earth fault element caused by in-rush condition detection.
Pickup value for the inverse time-current stage can be set by setting “HV 3I0_NOC Inv”, “MV 3I0_NOC Inv” and “LV 3I0_NOC Inv” for HV, MV and LV sides, respectively. Each neutral current (quantity IN) measured by installed neutral CT is separately compared with corresponding setting value. If a cur-rent exceeds 1.1 times the setting value, corresponding stage picks up. When
Chapter 8 Neutral earth fault protection
122
an inverse time-current stage picks up, the tripping time is calculated from the measured quantity IN, using the selected tripping curve. Maximum tripping time is limited to 100s.
For Time-inverse characteristic, the pickup value can be defined by setting “3I0_NOC Inv”. The measured zero sequence current is compared with cor-responding setting value. If it exceeds the setting, related signal will be re-ported and the tripping time is calculated according to the pre-defined char-acteristic. The tripping curve can be set as IEC or ANSI standard curves or any user-defined characteristic by following tripping time equation.
_
_ _ _
-1P NOC Inv
S
A NOC Invt K NOC Inv B NOC InvII
é ùê úê úê ú= ´ +ê úé ùê úê úê úê úê úë ûë û
Equation 36
Where I is the calculated neutral current;
Is is the current setting;
where:
xV A_NOC Inv: xV(HV/MV/LV) side time factor for inverse time stage
xV B_NOC Inv: xV(HV/MV/LV) time delay for inverse time stage
xV P_NOC Inv: xV(HV/MV/LV) index for inverse time stage
xV K_NOC Inv: xV(HV/MV/LV) time multiplier Inrush restraint feature
As mentioned previously, selection between the curves can be carried out by settings “HV Curve_NOC Inv”, “MV Curve_NOC Inv” and “LV Curve_NOC Inv” for HV, MV and LV sides, respectively. Furthermore, the time multiplier K_NOC Inv can be applied by user to coordinate the integrated inverse time-current characteristic of the device with other relays installed for power system protection. This can be performed by settings “HV K_NOC Inv”, “MV K_NOC Inv” and “LV K_NOC Inv” in case of HV, MV and LV neutral earth fault elements.
By applying pickup current and time multiplier settings, the device determines the tripping time from the measured neutral current, based on the selected inverse curve. Once the calculated time has been elapsed, a trip signal is issued provided that no inrush current is detected or inrush restraint is disa-bled. If the inrush restraint feature is enabled and an inrush condition exists, the neutral earth fault protection would be blocked and therefore no tripping takes place. However, alarm report of “HV Inrush Blk BU”, “MV Inrush Blk BU” or “LV Inrush Blk BU” is issued, indicating the blocking condition of neutral earth fault element caused by inrush condition detection.
The trip signals and corresponding event reports are available separately for each stage. They include “HV Neu OC_1 Trip”, “HV Neu OC_2 Trip” and “HV Neu OC IDMTL” for HV side, “MV Neu OC_1 Trip”, “MV Neu OC_2 Trip” and “MV Neu OC IDMTL” for MV side, “LV Neu OC_1 Trip”, “LV Neu OC_1 Trip”
Chapter 8 Neutral earth fault protection
123
and “LV Neu OC IDMTL” for LV side neutral earth fault elements.
1.2 Inrush Restraint Feature The transformer neutral earth fault protection may detect large magnetizing inrush currents flowing when transformer 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 funda-mental component. So, it may affect neutral earth fault protection which op-erates based on the fundamental component of the measured current. Inrush blocking unit in neutral earth fault function is provided for this purpose.
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 settings “HV Neu OC1 Inrush Block”, “HV Neu OC2 Inrush Block” and “HV Neu OC Inv Inrush Block” on for HV side, “MV Neu OC1 Inrush Block”, “MV Neu OC2 Inrush Block” and “MV Neu OC Inv Inrush Block” on for MV side, “LV Neu OC1 Inrush Block”, “LV Neu OC2 Inrush Block” and “LV Neu OC Inv Inrush Block” on for LV side. By applying setting “1-on” to each of the men-tioned Binary settings, no trip command would be possible by corresponding stage, if an inrush condition is detected.
Since the inrush current contains a relatively large second harmonic compo-nent which is nearly absent during a fault current, the inrush restraint oper-ates based on the evaluation of the second harmonic content which is present in the measured neutral current (quantity IN), or in the phase currents, based on setting. The inrush condition is recognized if the ratio of second harmonic current to the fundamental component exceeds the setting value “HV Ra-tio_I2/I1_NOC”, “MV Ratio_I2/I1_NOC” or “LV Ratio_I2/I1_NOC” in the measured neutral current. The setting is applicable to both the definite stages of neutral earth fault protection element as well as the inverse time-current stage. As soon as the measured ratio exceeds the set threshold, a restraint is applied to those stages for which corresponding setting is applied to make them blocked in inrush condition detection (“HV Neu OC1 Inrush Block”, “HV Neu OC2 Inrush Block” and “HV Neu OC Inv Inrush Block” for HV side, “MV Neu OC1 Inrush Block”, “MV Neu OC2 Inrush Block” and “MV Neu OC Inv Inrush Block” for MV side, “LV Neu OC1 Inrush Block”, “LV Neu OC2 Inrush Block” and “LV Neu OC Inv Inrush Block” for LV side).
Furthermore, if the fundamental component of the measured neutral current exceeds the upper limit value “HV Imax_2H_UnBlk_NOC”, “MV Imax_2H_UnBlk_NOC” or “LV Imax_2H_UnBlk_NOC”, the inrush restraint will no longer effective in respective side, since a high-current fault is as-sumed in this case.
1.3 Direction Determination Feature The integrated directional function can be applied to each stage of neutral earth fault elements via Binary settings. The Binary settings include “HV Neu OC1 Direction”, “HV Neu OC2 Direction” and “HV Neu OC Inv Direction” on for HV side earth fault stages, “MV Neu OC1 Direction”, “MV Neu OC2 Direc-tion” and “MV Neu OC Inv Direction” for MV side earth fault stages and “LV
Chapter 8 Neutral earth fault protection
124
Neu OC1 Direction”, “LV Neu OC2 Direction” and “LV Neu OC Inv Direction” for LV side earth fault stages.
Furthermore, the directional orientation can be set individually for each stage of neutral earth fault elements in various sides of the protected transformer. This can be performed by Binary settings “HV Neu OC1 Dir To Sys”, “HV Neu OC2 Dir To Sys” and “HV Neu OC Inv Dir To Sys” for HV side, “MV Neu OC1 Dir To Sys”, “MV Neu OC2 Dir To Sys” and “MV Neu OC Inv Dir To Sys” for MV side, “LV Neu OC1 Dir To Sys”, “LV Neu OC2 Dir To Sys” and “LV Neu OC Inv Dir To Sys” for LV side. The possible settings for these Binary setting comprise “0-toward transformer” and “1-toward system”.
Basically, the direction determination is performed by comparing the zero sequence system quantities. In the current path, 3I0 current is measured from the neutral CT installed at the transformer starpoint. In the voltage path, the device calculates the zero sequence voltage 3V0 from the sum of the three phase voltages. Contrary to the directional phase elements, which work with the un-faulted voltage as reference voltage, in this application, the fault volt-age itself is the reference voltage. Depending on the connection of the volt-age transformer, this is the voltage 3V0 or VN. The directional element at each side operates with the residual/ neutral voltage of the same side.
In order to satisfy different network conditions and applications, the reference voltage can be rotated by an adjustable angle. For each side of the protected transformer, the directional angle can be set independently. The settings in-clude “HV Angle_NOC”, “MV Angle_NOC” and “LV Angle_NOC”, for HV, MV and LV sides, respectively. It should be noted that the settings affect all the directional stages of the corresponding neutral earth fault element.
Forward
Angle_EF
Bisector
0_Ref3U
0°
-3I 0
3I 090°
Angle_Range EF
Figure 44 Neutral directional element characteristic
where:
Angle_OC: The settable characteristic angle
Angle_Range OC: 80º
Chapter 8 Neutral earth fault protection
125
During direction decision by directional function, a VT Fail condition (a short circuit or broken wire in the voltage transformer's secondary system or an operation of the voltage transformer fuse) may result in false or undesired tripping by directional neutral earth fault elements. In such a situation, it is possible to select operation status of the directional neutral earth fault pro-tection elements in each side by using a number of Binary settings to block the neutral earth fault protection elements or keep them in operational state with no direction decision (block direction decision). The Binary settings are designated as “Block HV NOC at HV VT_Fail”, “Block MV NOC at HV VT_Fail” and “Block LV NOC at HV VT_Fail”, for HV, MV and LV sides, re-spectively. When the Binary settings are set as 0 to select “Direct OK at VT Fail”, corresponding neutral earth fault protection elements will not judge di-rection at the local side VT failure. When they set as 1 to select “Blk NEU OC at VT Fail”, no operation is possible by the neutral earth fault protection ele-ments. It is noted that the Binary settings affect all the stages of correspond-ing neutral earth fault elements at each side. For instance, by applying setting “Block HV NOC at HV VT_Fail” off, all the three stages of the neutral earth fault element will remain operative without direction determination in case of any fault in secondary circuit of HV side voltage transformer. On the other hand, setting “Block HV NOC at HV VT_Fail” on makes them blocked.
The logic for definite and inverse time IDMTL neutral earth fault protection is shown in below figure.
1) t: T_Neutral OC1(2)
t
Neu OC Direction on
Dir_Forward
Func_Neu OC1(2) on
3I0 > 3I0_Neutral OC1(2)
Func_Neu OC Inv on
And
And
Or
NOC Direction Unit OK
Inrush BLK NEF
3I0>3I0_NOC Inv
NOC Direction Unit OK
Inrush BLK NOC
Direct OK at VT FAIL
VT failure
And
And
NOC Inv Trip
Neutral OC Trip
NOC Direction Unit OK
1)
t
“1”
“1”
“1”
Figure 45 Tripping logic for neutral earth fault protection
Chapter 8 Neutral earth fault protection
126
1.4 CBF initiation Feature It is possible to set whether the neutral earth fault protection elements can in-itiate the integrated CBF protection or not. The available choices depend on the voltage side of the power transformer at which neutral earth fault protec-tion is applied. In this context, HV side neutral earth fault protection element always initiates HV side CBF function with no additional setting. However, it is possible to select whether it can initiate MV and LV CBF protection functions via Binary settings “HV Neu OC Init LV CBF” and “HV Neu OC Init MV CBF”, respectively.
MV side neutral earth fault protection element always initiates MV side CBF function with no additional setting.
2 Input and output signals
NEF1 TripINBK
NEF2 Trip
NEF Inv Trip
UA
UB
UC Relay Startup
Neutral Earth Fault Protection
Figure 46 Neutral earth fault protection module
Table 60 Analog output list
Signal Description
INBK Neutral current input of HV side, MV side, or LV side of transformer UA Phase A voltage input of HV side, MV side, or LV side of transformer UB Phase B voltage input of HV side, MV side, or LV side of transformer UC Phase C voltage input of HV side, MV side, or LV side of transformer
Table 61 Binary output list
Signal Description
NOC1 Trip Neutral Earth Fault stage 1 trip NOC2 Trip Neutral Earth Fault stage 2 trip NOC Inv Trip Neutral Earth Fault inverse stage trip Relay Startup Relay Startup
Chapter 8 Neutral earth fault protection
127
3 Setting Table 62 Settings of neutral earth fault protection for HV side of transformer
Setting Unit Min.
(Ir:5A/1A)
Max. (Ir:5A/1
A)
Default setting (Ir:5A/1
A) Description
HV 3I0_Neutral OC1
A 0.05Ir 20Ir 5 HV neutral over-current (NOC) protection current setting for Stage 1
HV T_Neutral OC1
s 0 60 60 Time setting for HV NOC, Stage 1
HV 3I0_Neutral OC2
A 0.05Ir 20Ir 5 HV neutral over-current (NOC) protection current setting for Stage 2
HV T_Neutral OC2
s 0 60 60 Time setting for HV NOC, Stage 1
HV Curve_NOC Inv
1 12 1 Ref to appendix 3 page 307
HV 3I0_NOC Inv A 0.05Ir 20Ir 5 Ref to appendix 3 page 307
HV K_NOC Inv 0.05 999 1 Ref to appendix 3 page 307
HV A_NOC Inv s 0 200 0.14 Ref to appendix 3 page 307
HV B_NOC Inv s 0 60 0 Ref to appendix 3 page 307
HV P_NOC Inv 0 10 0.02 Ref to appendix 3 page 307
HV An-gle_NOC ° 0 90 45
The angle setting for voltage ahead of current.
HV Imax_2H_UnBlk_NOC
A 0.25Ir 20Ir 5
The maximum 1st -harmonic current setting to remove the inrush block, in HV NOC protec-tion
HV Ra-tio_I2/I1_NOC
0.07 0.5 0.2 Inrush 2nd harmonic ratio setting for blocking HV NOC protection
Chapter 8 Neutral earth fault protection
128
Table 63 Binary settings of neutral earth fault protection for HV side of transformer
Setting Unit Min. Max. Default setting Description
HV Func_Neu OC1
0 1 0
The 1st stage of HV neutral OC (OC_1) protection is switched ON 1-on; 0-off.
HV Neu OC1 Di-rection
0 1 0
Direction (DIR) detection of HV neutral OC Stage 1 is switched ON 1-on; 0-off.
HV Neu OC1 Dir To Sys
0 1 0
Direction unit of HV neutral OC Stage 1 points to system 0 - point to the protected trans-former 1- point to system
HV Neu OC1 In-rush Block
0 1 0
Inrush 2nd harmonic detection HV neutral OC Stage 1 is switched ON 1-on; 0-off.
HV Func_Neu OC2
0 1 0
The 2nd stage of HV neutral OC (OC_2) protection is switched ON 1-on; 0-off.
HV Neu OC2 Di-rection
0 1 0
Direction (DIR) detection of HV neutral OC Stage 2 is switched ON 1-on; 0-off.
HV Neu OC2 Dir To Sys
0 1 0
Direction unit of HV neutral OC Stage 2 points to system 0 - point to the protected trans-former 1- point to system
HV Neu OC2 In-rush Block
0 1 0
Inrush 2nd harmonic detection HV neutral OC Stage 2 is switched ON 1-on; 0-off.
HV Func_Neu OC Inv
0 1 0
The IDMTL inverse time stage of HV neutral OC protection is switched ON 1-on; 0-off.
HV Neu OC Inv Direction
0 1 0
Direction (DIR) detection of HV neutral OC IDMTL inverse time stage is switched ON 1-on; 0-off.
HV Neu OC Inv Dir To Sys
0 1 0
Direction unit of HV neutral OC IDMTL inverse time stage points to system 0 - point to the protected trans-former 1- point to system
Chapter 8 Neutral earth fault protection
129
HV Neu OC Inv Inrush Block
0 1 0
Inrush 2nd harmonic detection HV neutral OC IDMTL inverse time stage is switched ON 1-on; 0-off.
Block HV NOC at HV VT_Fail
0 1 0
Select to block HV neutral OC protection or exit direction unit, when HV VT fails 0 - HV Direct OK at HV VT Fail 1 - Blk HV NOC at HV VT Fail
HV Neu OC Init MV CBF
0 1 0 HV neutral OC protection initiate LV side CBF 0 - initiate, 1 – not initiate
Table 64 Settings of neutral earth fault protection for MV side of transformer
Setting Unit Min.
(Ir:5A/1A)
Max. (Ir:5A/1
A)
Default setting (Ir:5A/1
A) Description
MV 3I0_Neutral OC1
A 0.05Ir 20Ir 5 MV neutral over-current (NOC) protection current setting for Stage 1
MV T_Neutral OC1
s 0 60 60 Time setting for MV NOC, Stage 1
MV 3I0_Neutral OC2
A 0.05Ir 20Ir 5 MV neutral over-current (NOC) protection current setting for Stage 2
MV T_Neutral OC2
s 0 60 60 Time setting for MV NOC, Stage 1
MV Curve_NOC Inv
1 12 1 Ref to appendix 3 page 307
MV 3I0_NOC Inv A 0.05Ir 20Ir 5 Ref to appendix 3 page 307
MV K_NOC Inv 0.05 999 1 Ref to appendix 3 page 307
MV A_NOC Inv s 0 200 0.14 Ref to appendix 3 page 307
MV B_NOC Inv s 0 60 0 Ref to appendix 3 page 307
MV P_NOC Inv 0 10 0.02 Ref to appendix 3 page 307
MV An-gle_NOC ° 0 90 45
The angle setting for voltage ahead of current.
MV Imax_2H_UnBlk_NOC
A 0.25Ir 20Ir 5
The maximum 1st -harmonic current setting to remove the inrush block, in MV NOC protec-tion
Chapter 8 Neutral earth fault protection
130
MV Ra-tio_I2/I1_NOC
0.07 0.5 0.2 Inrush 2nd harmonic ratio setting for blocking MV NOC protection
Table 65 Binary settings of neutral earth fault protection for MV side of transformer
Setting Unit Min. Max. Default setting Description
MV Func_Neu OC1
0 1 0
The 1st stage of MV neutral OC (OC_1) protection is switched ON 1-on; 0-off.
MV Neu OC1 Di-rection
0 1 0
Direction (DIR) detection of MV neutral OC Stage 1 is switched ON 1-on; 0-off.
MV Neu OC1 Dir To Sys
0 1 0
Direction unit of MV neutral OC Stage 1 points to system 0 - point to the protected trans-former 1- point to system
MV Neu OC1 In-rush Block
0 1 0
Inrush 2nd harmonic detection MV neutral OC Stage 1 is switched ON 1-on; 0-off.
MV Func_Neu OC2
0 1 0
The 2nd stage of MV neutral OC (OC_2) protection is switched ON 1-on; 0-off.
MV Neu OC2 Di-rection
0 1 0
Direction (DIR) detection of MV neutral OC Stage 2 is switched ON 1-on; 0-off.
MV Neu OC2 Dir To Sys
0 1 0
Direction unit of MV neutral OC Stage 2 points to system 0 - point to the protected trans-former 1- point to system
MV Neu OC2 In-rush Block
0 1 0
Inrush 2nd harmonic detection MV neutral OC Stage 2 is switched ON 1-on; 0-off.
MV Func_Neu OC Inv
0 1 0
The IDMTL inverse time stage of MV neutral OC protection is switched ON 1-on; 0-off.
MV Neu OC Inv Direction
0 1 0
Direction (DIR) detection of MV neutral OC IDMTL inverse time stage is switched ON 1-on; 0-off.
Chapter 8 Neutral earth fault protection
131
MV Neu OC Inv Dir To Sys
0 1 0
Direction unit of MV neutral OC IDMTL inverse time stage points to system 0 - point to the protected trans-former 1- point to system
MV Neu OC Inv Inrush Block
0 1 0
Inrush 2nd harmonic detection MV neutral OC IDMTL inverse time stage is switched ON 1-on; 0-off.
Block MV NOC at MV VT_Fail
0 1 0
Select to block MV neutral OC protection or exit direction unit, when MV VT fails 0 - MV Direct OK at MV VT Fail 1 - Blk MV NOC at MV VT Fail
MV Neu OC Init MV CBF
0 1 0 MV neutral OC protection initiate LV side CBF 0 - initiate, 1 – not initiate
Table 66 Settings of neutral earth fault protection for LV side of transformer
Setting Unit Min.
(Ir:5A/1A)
Max. (Ir:5A/1
A)
Default setting (Ir:5A/1
A) Description
LV 3I0_Neutral OC1
A 0.05Ir 20Ir 5 LV neutral over-current (NOC) protection current setting for Stage 1
LV T_Neutral OC1 s 0 60 60 Time setting for LV NOC, Stage 1
LV 3I0_Neutral OC2
A 0.05Ir 20Ir 5 LV neutral over-current (NOC) protection current setting for Stage 2
LV T_Neutral OC2 s 0 60 60 Time setting for LV NOC, Stage 1
LV Curve_NOC Inv
1 12 1 Ref to appendix 3 page 307
LV 3I0_NOC Inv A 0.05Ir 20Ir 5 Ref to appendix 3 page 307
LV K_NOC Inv 0.05 999 1 Ref to appendix 3 page 307
LV A_NOC Inv s 0 200 0.14 Ref to appendix 3 page 307
LV B_NOC Inv s 0 60 0 Ref to appendix 3 page 307
LV P_NOC Inv 0 10 0.02 Ref to appendix 3 page 307
Chapter 8 Neutral earth fault protection
132
LV An-gle_NOC ° 0 90 45
The angle setting for voltage ahead of current.
LV Imax_2H_UnBlk_NOC
A 0.25Ir 20Ir 5
The maximum 1st -harmonic current setting to remove the inrush block, in LV NOC protec-tion
LV Ra-tio_I2/I1_NOC
0.07 0.5 0.2 Inrush 2nd harmonic ratio setting for blocking LV NOC protection
Table 67 Binary settings of neutral earth fault protection for LV side of transformer
Setting Unit Min. Max. Default setting Description
LV Func_Neu OC1 0 1 0
The 1st stage of LV neutral OC (OC_1) protection is switched ON 1-on; 0-off.
LV Neu OC1 Direc-tion
0 1 0
Direction (DIR) detection of LV neutral OC Stage 1 is switched ON 1-on; 0-off.
LV Neu OC1 Dir To Sys
0 1 0
Direction unit of LV neutral OC Stage 1 points to system 0 - point to the protected trans-former 1- point to system
LV Neu OC1 Inrush Block
0 1 0
Inrush 2nd harmonic detection LV neutral OC Stage 1 is switched ON 1-on; 0-off.
LV Func_Neu OC2 0 1 0
The 2nd stage of LV neutral OC (OC_2) protection is switched ON 1-on; 0-off.
LV Neu OC2 Direc-tion
0 1 0
Direction (DIR) detection of LV neutral OC Stage 2 is switched ON 1-on; 0-off.
LV Neu OC2 Dir To Sys
0 1 0
Direction unit of LV neutral OC Stage 2 points to system 0 - point to the protected trans-former 1- point to system
LV Neu OC2 Inrush Block
0 1 0
Inrush 2nd harmonic detection LV neutral OC Stage 2 is switched ON 1-on; 0-off.
LV Func_Neu OC Inv
0 1 0
The IDMTL inverse time stage of LV neutral OC protection is switched ON 1-on; 0-off.
Chapter 8 Neutral earth fault protection
133
LV Neu OC Inv Di-rection
0 1 0
Direction (DIR) detection of LV neutral OC IDMTL inverse time stage is switched ON 1-on; 0-off.
LV Neu OC Inv Dir To Sys
0 1 0
Direction unit of LV neutral OC IDMTL inverse time stage points to system 0 - point to the protected trans-former 1- point to system
LV Neu OC Inv In-rush Block
0 1 0
Inrush 2nd harmonic detection LV neutral OC IDMTL inverse time stage is switched ON 1-on; 0-off.
Block LV NOC at LV VT_Fail
0 1 0
Select to block LV neutral OC protection or exit direction unit, when LV VT fails 0 - LV Direct OK at LV VT Fail 1 - Blk LV NOC at LV VT Fail
LV Neu OC Init LV CBF
0 1 0 LV neutral OC protection initiate LV side CBF 0 - initiate, 1 – not initiate
4 Report Table 68 Event report list
Information Description
HV NOC Inv Trip Inverse time stage of neutral OC protection trip HV NOC1 Trip HV neutral OC stage 1 trip HV NOC2 Trip HV neutral OC stage 2 trip MV EF Inv Trip Inverse time stage of MV neutral OC protection trip MV EF1 Trip MV neutral OC stage 1 trip MV EF2 Trip MV neutral OC stage 2 trip LV EF Inv Trip Inverse time stage of LV neutral OC protection trip LV EF1 Trip LV neutral OC stage 1 trip LV EF2 Trip LV neutral OC stage 2 trip
Table 69 Operation report list
Information Description
HV Func_NOC On NOC protection of HV side is switched ON (by CW) HV Func_NOC Off NOC protection of HV side is switched OFF (by CW) MV Func_NOC On NOC protection of MV side is switched ON (by CW) MV Func_NOC Off NOC protection of MV side is switched OFF (by CW)
Chapter 8 Neutral earth fault protection
134
Information Description
LV Func_NOC On NOC protection of LV side is switched ON (by CW) LV Func_NOC Off NOC protection of LV side is switched OFF (by CW)
5 Technical data Table 70 Neutral earth fault protection technical data
Item Rang or value Tolerance Definite time characteristic
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
Reset time approx. 40ms
Reset ratio Approx. 0.95 at I/Ir ≥ 0.5 Inverse time characteristics
Current 0.08 Ir to 20.00 Ir ≤ ±3% setting or ±0.02Ir IEC standard Normal inverse;
Very inverse; Extremely inverse; Long inverse
≤ ±5% setting + 40ms, at 2 <I/IRSETTINGR < 20, in accordance with IEC60255-151
ANSI Inverse; Short inverse; Long inverse; Moderately inverse; Very inverse; Extremely inverse; Definite inverse
≤ ±5% setting + 40ms, at 2 <I/ISETTING < 20, in accordance with ANSI/IEEE C37.112,
user-defined characteristic T=
≤ ±5% setting + 40ms, at 2 <I/IRSETTINGR < 20, in accordance with IEC60255-151
Time factor of inverse time, A 0.005 to 200.0s, step 0.001s
Delay of inverse time, B 0.000 to 60.00s, step 0.01s Index of inverse time, P 0.005 to 10.00, step 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
Reset time approx. 40ms
Directional element Operating area range 160° ≤ ±3°, at 3U0≥1V
Characteristic angle 0° to 90°, step 1° Operating area range 160° ≤ ±3°, at 3U2≥2V
Characteristic angle 0° to 90°, step 1°
Chapter 9 Thermal overload protection
135
Chapter 9 Thermal overload protection
About this chapter This chapter describes the protection principle, input and output signals, parameter, IED report and technical data for thermal overload protection function.
Chapter 9 Thermal overload protection
136
1 Introduction The insulating material surrounding the transformer windings ages rapidly if the temperature exceeds the design limit value. Furthermore, by using less and less metal per MVA of transformed power, the designed limit value is reduced in modern power transformers. Hence, it represents an essential requirement to provide thermal protection to supplement the winding temper-ature device. The thermal overload protection estimates winding temperature and therefore prevents damage to transformer caused by thermal overload-ing.
2 Protection principle The thermal overload protection includes two stages (alarm and trip). They work by using an approximate replica of the temperature rise in the protected object caused by overload. The thermal replica is implemented based on thermal models (Cold / Hot Curve) of IEC60255-8 Std., without ambient temperature influence.
Both of the alarm and trip stages can be enabled or disabled by using Binary setting “HV Func_Thermal OvLd”, “MV Func_Thermal OvLd” or “LV Func_Thermal OvLd” on. The thermal overload protection can be assigned to any desired side (HV, MV or LV) of the protected object. However, for trans-formers with tap changer, it is recommended to use the function on the non-regulated side. To enable the protection on each side, setting of “1-on” should be applied to corresponding Binary setting.
Both of the thermal overload stages can use cold curve or hot curve in their calculations, based on the setting applied at Binary setting “HV Cold Curve”, “MV Cold Curve” or “LV Cold Curve”. If the protection is enabled in one side, and the measured current in each phase of the protected transformer in cor-responding side exceeds the threshold defined by setting “HV I_Therm OL Alarm”, “MV I_Therm OL Alarm” or “LV I_Therm OL Alarm”, a counter is in-cremented from 0% to 100%. When the counter is accumulated to its alarm setting which correspond to the expiration of alarm time delay according to the selected cold/hot characteristic, the alarm report “HV Load Alarm”, “MV Load Alarm” or “LV Load Alarm” is given to allow a preventive load reduction. The alarm signal is cancelled as soon as the measured phase current falls below the threshold defined by setting “HV I_Therm OL Alarm”, “MV I_Therm OL Alarm” or “LV I_Therm OL Alarm”. However, the counter is decremented to zero according to cool down time of the transformer (the time by which the thermal replica counter reaches from 100% to 0%). The cool down time is informed to the device by setting “HV T_Const Cool Down”, “MV T_Const Cool Down” and “LV T_Const Cool Down”.
Similarly, if the measured current in each phase of the protected transformer in corresponding side exceeds the threshold defined by setting “HV I_Therm OL Trip”, “MV I_Therm OL Trip” or “LV I_Therm OL Trip”, a counter is incre-mented from 0% to 100%. If the counter reaches to 100% corresponding to expiration of trip time delay according to the selected cold/hot characteristic, the event report “HV THERM Trip”, “MV THERM Trip” or “LV THERM Trip” is
Chapter 9 Thermal overload protection
137
given. The alarm signal is cancelled as soon as the measured phase current falls below the threshold defined by setting “HV I_Therm OL Trip”, “MV I_Therm OL Trip” or “LV I_Therm OL Trip”. However, the counter is decre-mented to zero according to cool down time of the transformer which is en-tered into the device by setting “HV T_Const Cool Down”, “MV T_Const Cool Down” and “LV T_Const Cool Down”.
The cold and hot curves used in each thermal overload stages, is based on thermal curves defined in IEC 60255-8 Std.
The curves provide an operating current/time characteristic that corresponds to the current overload characteristic of the transformer windings. The for-mulas corresponding to cold and hot curve is denoted by (1-46) and (1-47), respectively. The cold curve provides no memory regarding to previous thermal condition of the transformer, whereas, by using the hot curve, the protection function is able to represent a memorized thermal profile of the protected transformer.
−= 22
2
lnθ
τII
It
ph
ph
Equation 37
−
−= 22
22
lnθ
τIIII
tph
Pph
Equation 38
Where,
t is alarm/trip time of thermal overload protection function in seconds,
τ is thermal time constant of heating for the power transformer, in seconds. It is usually provided by the manufacturer. The device is informed about it by settings “HV T_Const Therm”, “MV T_Const Therm” and “H\LV T_Const Therm”.
Iph is the current flowing through corresponding side of the transformer, in each phase. It means that the calculation is performed separately for each phase, based on fundamental component measurement and also includes the effect of harmonic contents up to 7th harmonic. Thus, the minimum cal-culated alarm/ trip time is decisive for evaluation of the thresholds.
IΘ is the setting for alarm and trip stages of the thermal overload protection, in rms. It should be set considering the maximum permissible thermal continu-ous overload current of the transformer windings and insulations. The setting is applied by using “HV I_Therm OL Alarm” and “HV I_Therm OL Trip” for HV side, “MV I_Therm OL Alarm” and “HV I_Therm OL Trip” for MV side, and “H\LV I_Therm OL Alarm” and “HV I_Therm OL Trip” for LV side of the power transformer.
IP is the prior current to overload, assuming sufficient time to reach
Chapter 9 Thermal overload protection
138
steady-state temperature.
NOTE: When Binary setting “xx Curve/Hot Curve” is set to 0, and fundamental current is less than the settings, and the heat accumulation is cleared and set as “0” automatically.
3 Input and output signals
IA1
IB1
IC1
IA2
IB2
IC2
Therm OL Trip
Therm OL Alarm
Relay Startup
Thermal Overload Protection
Figure 47 Thermal overload protection module
Table 71 Analog input list
Signal Description
IA1 Phase A current input of CT of circuit breaker 1 IB1 Phase B current input of CT of circuit breaker 1 IC1 Phase C current input of CT of circuit breaker 1 IA2 Phase A current input of CT of circuit breaker 2 IB2 Phase B current input of CT of circuit breaker 2 IC2 Phase C current input of CT of circuit breaker 2
Table 72 Binary output list
Signal Description
Therm OL Trip Thermal overload trip Therm OL Alarm Thermal overload alarm Relay Startup Relay Startup
Chapter 9 Thermal overload protection
139
4 Setting Table 73 Settings of thermal overload protection for HV side of transformer
Setting Unit Min.
(Ir:5A/1A)
Max. (Ir:5A/
1A)
Default setting (Ir:5A/
1A) Description
HV I_Therm OL Trip A 0.1Ir 5Ir 2 Setting for HV-side thermal overload trip-stage current
HV I_Therm OL Alarm A 0.1Ir 5Ir 2 Setting for HV-side thermal overload alarm-stage cur-rent
HV T_Const Therm s 1 9999 10 Time const for HV-side thermal overload protection
HV T_Const Cool Down s 1 9999 10
Cool down time delay for HV-side thermal overload
Table 74 Binary settings of thermal overload protection for HV side of transformer
Setting Unit Min. Max. Default setting Description
HV Func_Thermal OvLd
0 1 0 Thermal overload in HV side is switched on
0 - OFF, 1 - ON
HV Cold Curve 0 1 0 HV side using hot/cold curve type
0 – Hot curve, 1 – Cold curve
HV Thermal Init LV CBF
0 1 0 HV thermal overload protec-tion initiate LV side CBF
0 - initiate, 1 – not initiate
HV Thermal Init MV CBF
0 1 0 HV thermal overload protec-tion initiate MV side CBF
0 - initiate, 1 – not initiate
Table 75 Settings of thermal overload protection for MV side of transformer
Setting Unit Min.
(Ir:5A/1A)
Max. (Ir:5A/
1A)
Default setting (Ir:5A/
1A) Description
MV I_Therm OL Trip A 0.1Ir 5Ir 2 Setting for MV-side thermal overload trip-stage current
MV I_Therm OL Alarm A 0.1Ir 5Ir 2
Setting for MV-side thermal overload alarm-stage cur-rent
MV T_Const Therm s 1 9999 10 Time const for MV-side thermal overload protection
Chapter 9 Thermal overload protection
140
MV T_Const Cool Down s 1 9999 10 Cool down time delay for
MV-side thermal overload
Table 76 Binary settings of thermal overload protection for MV side of transformer
Setting Unit Min. Max. Default setting Description
MV Func_Thermal OvLd
0 1 0 Thermal overload in MV side is switched on
0 - OFF, 1 - ON
MV Cold Curve 0 1 0 MV side using hot/cold curve type
0 – Hot curve, 1 – Cold curve
MV Thermal Init HV1 CBF
0 1 0 MV thermal overload protec-tion initiate HV side CBF
0 - initiate, 1 – not initiate
5 Report Table 77 Event report list
Information Description
HV Therm OL Trip HV Thermal (TEM) Overload(OVLD) tripping (Trip)
MV Therm OL Trip MV Thermal (TEM) Overload(OVLD) tripping (Trip)
Table 78 Alarm report list
Information Description
HV Therm OL Alm HV Thermal overload Alarm
MV Therm OL Alm MV Thermal overload Alarm
Table 79 Operation report list
Information Description
HV Func_Therm On HV thermal overload protection is switched ON (by CW)
HV Func_Therm Off HV thermal overload protection is switched OFF (by CW)
MV Func_Therm On MV thermal overload protection is switched ON (by CW)
MV Func_Therm Off MV thermal overload protection is switched OFF (by CW)
Chapter 9 Thermal overload protection
141
6 Technical data Table 80 Thermal overload protection technical data
Item Rang or Value Tolerance
Current 0.1 Ir to 5.00 Ir ≤ ±3% setting or ±0.02Ir Thermal heating time constant 1 to 9999 s Thermal cooling time constant 1 to 9999 s
IEC cold curve
−= 22
2
lnθ
τII
It
eq
eq IEC 60255–8,
≤ ±5% setting or +40ms
IEC hot curve
−
−= 22
22
lnθ
τIIII
teq
Peq
IEC 60255–8, ≤ ±5% setting or +40ms
Chapter 9 Thermal overload protection
142
Chapter 10 Overload protection
143
Chapter 10 Overload protection
About this chapter This chapter describes the protection principle, input and output signals, parameter, IED report and technical data for overload protection function.
Chapter 10 Overload protection
144
1 Protection principle Overload protection is equipped for each voltage side and LV delta winding. The function is to protect all sides of windings of transformer continuous overload currents.
HV or MV or LV overload protection only comprises a definite time alarm stage.
Load Alarm
HV T_OverLoadHV Func_OverLoad onAND
Max(IA,IB,IC)>HV I_OverLoad
“1”
Figure 48 The logic for HV overload protection
The LV winding overload includes one alarm and two definite time tripping stages, namely low-setting tripping stage and high-setting tripping stage. The two tripping stage can be set respective to initiate each side CBF or not
The logic for overload protection is shown in below figure.
LW Load Alarm & T_OverLoad
LW Load Low_Stg & LW T_OvLd Low Trip
LW Load High_Stg & LW T_OvLd High Trip
LW Func_OvLd Alarm on
LW Func_OvLd Low Trip on
LW Func_OvLd High Trip on
Max(IA,IB,IC)> I_OverLoad
Max(IA,IB,IC)> LW I_OvLd Low Trip
Max(IA,IB,IC)>LW I_OvLd High Trip
“1”
“1”
“1”
Figure 49 The logic for LV winding overload protection
Chapter 10 Overload protection
145
2 Input and output signals
IA1
IB1
IC1
IA2
IB2
IC2
Overload Alarm
Relay Startup
Overload Protection
Figure 50 Overload protection module for HV, MV, or LV side of transformer
IA
IB
IC
Overload high set trip
Relay Startup
Overload Alarm
Overload low set trip
Delta Winding Overload Protection
Figure 51 Overload protection module for LV delta winding of transformer
Table 81 Analog input list
Signal Description
IA1 Phase A current input of CT of circuit breaker 1 IB1 Phase B current input of CT of circuit breaker 1 IC1 Phase C current input of CT of circuit breaker 1 IA2 Phase A current input of CT of circuit breaker 2 IB2 Phase B current input of CT of circuit breaker 2 IC2 Phase C current input of CT of circuit breaker 2
Table 82 Binary output list
Signal Description
Overload Alarm Overload Alarm Relay Startup Relay Startup
Chapter 10 Overload protection
146
3 Setting Table 83 Setting of overload protection for HV side of transformer
Setting Unit
Min. (Ir:5A/
1A)
Max. (Ir:5A/
1A)
Default setting (Ir:5A/1
A) Description
HV I_OverLoad A 0.1Ir 4Ir 2 Overcurrent Setting of overload
HV T_OverLoad s 0.1 3600 10 Time setting for overload
Table 84 Binary settings of overload protection for HV side of transformer
Setting Unit Min. Max. Default setting Description
HV Func_OverLoad 0 1 0 Overload (LOAD) protection in HV side is switched ON 1-on; 0-off.
Table 85 Setting of overload protection for MV side of transformer
Setting Unit Min.
(Ir:5A/1A)
Max. (Ir:5A/
1A)
Default setting (Ir:5A/
1A) Description
MV I_OverLoad A 0.1Ir 4Ir 2 Overcurrent Setting of overload
MV T_OverLoad s 0.1 3600 10 Time setting for overload
Table 86 Binary settings of overload protection for MV side of transformer
Setting Unit Min. Max. Default setting Description
MV Func_OverLoad 0 1 0 Overload (LOAD)in MV side on
Table 87 Setting of overload protection for LV side of transformer
Setting Unit Min.
(Ir:5A/1A)
Max. (Ir:5A/
1A)
Default setting (Ir:5A/
1A) Description
LV I_OverLoad A 0.1Ir 4Ir 2 Overcurrent Setting of overload
LV T_OverLoad s 0.1 3600 10 Time setting for overload
Chapter 10 Overload protection
147
Table 88 Binary settings of overload protection for LV side of transformer
Setting Unit Min. Max. Default setting Description
LV Func_OverLoad 0 1 0 Overload (LOAD)in LV side on
Table 89 Setting of overload protection for LV delta winding of transformer
Setting Unit Min.
(Ir:5A/1A)
Max. (Ir:5A/
1A)
Default setting (Ir:5A/1
A) Description
LW I_OvLd Alarm A 0.1Ir 4Ir 20 Alarm current setting of LV delta winding overload protection
LW T_OvLd Alarm s 0.1 3600 10 Alarm time setting of LV delta winding overload protection
LW I_OvLd Low Trip A 0.1Ir 4Ir 20
Low stage tripping current set-ting
LW T_OvLd Low Trip s 0.1 3600 10 Low stage tripping time setting
LW I_OvLd High Trip A 0.1Ir 4Ir 20
High stage tripping current set-ting
LW T_OvLd High Trip s 0.1 3600 10 High stage tripping time setting
Table 90 Binary settings of overload protection for LV delta winding of transformer
Setting Unit Min. Max. Default setting Description
LW Func_OvLd Alarm 0 1 0
Alarm stage of LV delta winding (LWIND) overload (LOAD) protection is switched ON. 1-on; 0-off.
LW Func_OvLd Low Trip
0 1 0 Low-setting trip stage of LV delta winding overload pro-tection is switched ON. 1-on; 0-off.
LW Func_OvLd High Trip
0 1 0 High-setting trip stage of LV delta winding overload pro-tection is switched ON. 1-on; 0-off.
Low Trip Init HV1 CBF 0 1 0
Low-setting trip stage of LV delta winding overload pro-tection initiate HV1 side CBF 0 - initiate, 1 – not initiate
High Trip Init HV1 CBF 0 1 0
High-setting trip stage of LV delta winding overload pro-tection initiate HV1 side CBF 0 - initiate, 1 – not initiate
Chapter 10 Overload protection
148
Low Trip Init MV CBF 0 1 0
Low-setting trip stage of LV delta winding overload pro-tection initiate MV side CBF 0 - initiate, 1 – not initiate
High Trip Init MV CBF 0 1 0
High-setting trip stage of LV delta winding overload pro-tection initiate MV side CBF - initiate, 1 – not initiate
4 Report Table 91 Event report list
Information Description
LW Load Low_Stg LV delta winding (LWIND) overload (LOAD) protection low setting trip
LW Load High_Stg LV delta winding (LWIND) overload (LOAD) protection high setting trip
Table 92 Alarm report list
Information Description
HV Load Alarm HV overload Alarm
MV Load Alarm MV overload Alarm
LV Load Alarm LV overload Alarm
Table 93 Operation report list
Information Description
HV Func_OL On HV overload protection is switched ON (by CW)
HV Func_OL Off HV overload protection is switched OFF (by CW)
MV Func_OL On MV overload protection is switched ON (by CW)
MV Func_OL Off MV overload protection is switched OFF (by CW)
LV Func_OL On LV overload protection is switched ON (by CW)
LV Func_OL Off LV overload protection is switched OFF (by CW)
Chapter 11 Overvoltage protection
149
Chapter 11 Overvoltage protection
About this chapter This chapter describes the protection principle, input and output signals, parameter, IED report and technical data used for over-voltage protection.
Chapter 11 Overvoltage protection
150
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 (se-lectable)
Settable dropout ratio
2 Protection principle
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 thresh-olds, “HV U_OV1” or “HV U_OV2” for HV said, “MV U_OV1” or “MV U_OV2” for MV said, after expiry of the time delays, “HV T_OV1’ or “HV T_OV2”, and “MV T_OV1’ or “MV 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 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.
Chapter 11 Overvoltage protection
151
Additionaly, the dropout ratio of the overvoltage protection can be set in set-ting “Dropout_OV”. Therefore, the trip command of overvoltage is reset if the measured voltage comes bellow the ratio value mentioned in this setting.
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.
3 Logic diagram
HV OV Chk PE on
HV OV Chk PE off
HV OV1 Trip on
HV OV1 Trip off
Ua>HV U_OV1
Ub>HV U_OV1 OR
Uc>HV U_OV1
Uab>HV U_OV1
Ubc>HV U_OV1 OR
Uca>HV U_OV1
OR HV T_OV1
Trip
Alarm
Figure 52 Logic diagram for overvoltage protection
4 Input and output signals
UA
UB
UC
Relay Startup
OV1 Trip
OV2 Trip
OV1 Alarm
OV2 Alarm
Overvoltage Protection
Figure 53 Overvoltage protection module
Chapter 11 Overvoltage protection
152
Table 94 Analog input list
Signal Description
UA Phase A voltage input UB Phase B voltage input UC Phase C voltage input
Table 95 Binary output list
Signal Description
OV1 Trip OV stage 1trip
OV2 Trip OV stage 2trip
OV1 Alarm OV stage 1 alarm
OV2 Alarm OV stage 2 alarm
Relay Startup Relay Startup
5 Setting Table 96 Function setting list for overvoltage protection for HV side of transformer
Setting Unit Min.
(Ir:5A/1A)
Max. (Ir:5A/1
A)
Default setting (Ir:5A/1
A)
Description
HV U_OV1 V 40 200 200 HV voltage setting for stage 1 of overvoltage protection
HV T_OV1 s 0 60 60 HV time setting for stage 1 of overvoltage protection
HV U_OV2 V 40 200 200 HV voltage setting for stage 2 of overvoltage protection
HV T_OV2 s 0 60 60 HV time setting for stage 2 of overvoltage protection
HV Dropout_OV 0.9 0.99 0.95 HV dropout ratio for overvolt-age protection
Chapter 11 Overvoltage protection
153
Table 97 Binary setting list for overvoltage protection for HV side of transformer
Setting Unit Min. Max. Default setting
Description
HV Func_OV1 0 1 0
HV overvoltage stage 1 enabled or disabled
HV Func_OV2 0 1 0
HV overvoltage stage 1 trip or alarm
HV Func_OV2 0 1 0
HV overvoltage stage 2 enabled or disabled
HV OV2 Trip 0 1 0
HV overvoltage stage 2 trip or alarm
HV OV Chk PE 0 1 0
HV phase to phase voltage or phase to earth measured for overvoltage protection
Table 98 Function setting list for overvoltage protection for MV side of transformer
Setting Unit Min.
(Ir:5A/1A)
Max. (Ir:5A/1
A)
Default setting (Ir:5A/1
A)
Description
MV U_OV1 V 40 200 200 MV voltage setting for stage 1 of overvoltage protection
MV T_OV1 s 0 60 60 MV time setting for stage 1 of overvoltage protection
MV U_OV2 V 40 200 200 MV voltage setting for stage 2 of overvoltage protection
MV T_OV2 s 0 60 60 MV time setting for stage 2 of overvoltage protection
MV Dropout_OV 0.9 0.99 0.95 MV dropout ratio for overvolt-age protection
Table 99 Binary setting list for overvoltage protection for MV side of transformer
Setting Unit Min. Max. Default setting
Description
MV Func_OV1 0 1 0
MV overvoltage stage 1 enabled or disabled
MV Func_OV2 0 1 0
MV overvoltage stage 1 trip or alarm
MV Func_OV2 0 1 0
MV overvoltage stage 2 enabled or disabled
Chapter 11 Overvoltage protection
154
Setting Unit Min. Max. Default setting
Description
MV OV2 Trip 0 1 0
MV overvoltage stage 2 trip or alarm
MV OV Chk PE 0 1 0
MV phase to phase voltage or phase to earth measured for overvoltage protection
6 Report Table 100 Event report list
Information Description
HV OV1 Trip HV overvoltage stage 1 trip HV OV2 Trip HV overvoltage stage 2 trip MV OV1 Trip MV overvoltage stage 1 trip MV OV2 Trip MV overvoltage stage 2 trip
Table 101 Alarm report list
Information Description
HV OV1 Alarm HV overvoltage stage 1 alarm HV OV2 Alarm HV overvoltage stage 2 alarm MV OV1 Alarm MV overvoltage stage 1 alarm MV OV2 Alarm MV overvoltage stage 2 alarm
Table 102 Operation report list
Description of event comment HV Func_OV On HV overvoltage protection is switched ON (by CW)
HV Func_OV Off HV overvoltage protection is switched OFF (by CW)
MV Func_OV On MV overvoltage protection is switched ON (by CW)
MV Func_OV Off MV overvoltage protection is switched OFF (by CW)
Chapter 11 Overvoltage protection
155
7 Technical data Table 103 Technical data for overvoltage protection
Item Rang or Value Tolerance
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
120% energizing setting
Reset time <40ms
Chapter 11 Overvoltage protection
156
Chapter 12 Circuit breaker failure protection
157
Chapter 12 Circuit breaker failure protection
About this chapter This chapter describes the protection principle, input and output signals, parameter, IED report and technical data for circuit breaker failure protection function.
Chapter 12 Circuit breaker failure protection
158
1 Introduction The circuit breaker failure (CBF) protection function monitors proper tripping of the relevant circuit breaker. There are two separate CBF protection inte-grated in the IED. They are dedicated to HV and MV sides of the protected transformer.
2 Protection principle Normally, the circuit breaker should be tripped and therefore interrupt the fault current whenever a short circuit protection function issues a trip command. The circuit breaker failure protection provides rapid back-up fault clearance, in the event of circuit breaker malfunction to respond to a trip command. This feature can be enabled or disabled at each side of the protected transformer via Binary settings “HV1 CBF ON”, “MV CBF ON”. If setting “1-On” is applied at these Binary settings, respective CBF protection will be switched on. In this case, by operation of a protection function, and subsequent CBF initiation by respective protection function, a report nominated as “HV1 CBF INIT” or “MV CBF INIT” is generated by the IED. Furthermore, CBF initiation causes a programmed timer to run toward a preset time delay limit. This time delay is set by user under the settings “HV1 T1_CBF” or “MV1 T1_CBF”. If the circuit breaker has not been opened after expiration of the preset time limit, the cir-cuit breaker failure protection issues a command to trip circuit breaker (e.g. via a second trip coil). Furthermore, event report of “HV1 CBF T1” or “MV CBF T1”is generated by the device. If the circuit breaker doesn’t respond to the repeated trip command, until another preset delay time which is set at “HV1 T2_CBF” or “MV1 T2_CBF”, the protection 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 as the faulty CB). Furthermore, event report of “HV1 CBF T2” or “MV CBF T2” is generated in this case.
Initiation of CBF protection can be carried out by both the internal and exter-nal protection functions. If it is desired to initiate the CBF protection by means of external protection functions, they should be marshaled to Binary input (BI) of “HV1 CBF EXT. INT” or “MV CBF EXT. INT” for HV or MV CBF protection respectively. Internal protection functions can initiate the CBF protection in-tegrated in IED (HV and/or MV CBF), according to the mapping shown in below table.
Chapter 12 Circuit breaker failure protection
159
Table 104 Internal functions mapping to initiate CBF protection
PROTECTION FUNCTIONS CBF INITIATION
HV1 MV
Percent Differential Protection Trip [IDIFF>] ● ● ●
High-Set Differential Protection Trip [IDIFF>>] ● ● ●
HV Restricted Earth Fault Protection Trip ● ● ●
MV Restricted Earth Fault Protection Trip ● ● ●
LV Restricted Earth Fault Protection Trip ● - ●
Overexcitation Protection INV Trip ● ● ●
Overexcitation Protection DEF Trip [U/f >>] ● ● ●
HV Thermal Overload Protection Trip ● CW [0/1] CW [0/1]
MV Thermal Overload Protection Trip CW [0/1] ● -
LV Thermal Overload Protection Trip CW [0/1] - ●
HV Overcurrent Protection Trip [INV / DEF (Stage-1,2)] ● CW [0/1] CW [0/1]
MV Overcurrent Protection Trip [INV / DEF Stage-1,2)] CW [0/1] ● -
LV Overcurrent Protection Trip [INV / DEF (Stage-1,2)] CW [0/1] - ●
HV Earth Fault Protection Trip [INV / DEF (Stage-1,2)] ● CW [0/1] CW [0/1]
MV Earth Fault Protection Trip [INV / DEF (Stage-1,2)] CW [0/1] ● -
LV Earth Fault Protection Trip [INV / DEF (Stage-1,2)] CW [0/1] - ●
HV Neutral Current Protection Trip [INV / DEF (Stage-1,2)]
● CW [0/1] CW [0/1]
MV Neutral Current Protection Trip [INV / DEF (Stage-1,2)]
CW [0/1] ● -
LV Neutral Current Protection Trip [INV / DEF (Stage-1,2)]
CW [0/1] - ●
Overload Protection for LV Winding Low-Stage Trip (Inside Delta)
CW [0/1] CW [0/1] -
Over Load Protection for LV Winding High-Stage Trip (Inside Delta)
CW [0/1] CW [0/1] -
DI1 Trip CW [0/1] CW [0/1] CW [0/1]
DI2 Trip CW [0/1] CW [0/1] CW [0/1]
Chapter 12 Circuit breaker failure protection
160
In above table,
● :means that the protection function working at a given side of the protected transformer always initiate the CBF protection applied in specified side of the power transformer. As can be seen, differential, restricted earth fault and overexcitation protection functions initiate CBF protection in each side of protected transformer with no additional settings.
The statement CW [0/1] means that the protection function can initiate CBF protection according to the setting which is applied at respective Binary set-ting. The setting includes “1: Initiate the CBF” and “0: Don’t initiate the CBF”. Related Binary settings are available for specific functions which include thermal overload, overcurrent, earth fault and neutral earth fault protections. Furthermore, the dash sign means that it is not possible to initiate CBF pro-tection of respective side by operation of a protection function working at a given side of the protected transformer.
There are two criteria for breaker failure detection: the first one is to check whether the actual current flow effectively disappeared after a tripping com-mand had been issued. The second one is to evaluate the circuit breaker auxiliary contact status. Since circuit breaker is supposed to be open when current disappears from the circuit, the first criterion (current monitoring) is the most reliable means for relay to be informed about proper operation of circuit breaker. Therefore, current monitoring is applied to detect circuit breaker failure condition. In this context, the monitored current of each phase is compared with the pre-defined setting. The settings are applied at “HV1 I_CBF OC” or “MV I_CBF OC”, for HV or MV CBF protection.
Furthermore, it is possible to implement current checking in case of ze-ro-sequence and negative-sequence currents via Binary setting “HV1 3I0/3I2 Check On”, “MV1 3I0/3I2 Check On”. If setting “1-On” is applied at these Bi-nary settings, zero-sequence and negative-sequence currents are calculated
and 0 A B C3I = I + I + I compared with user-defined settings. Corresponding
settings include “HV 3I0_CBF ZS” and “MV 3I0_CBF ZS” for zero-sequence current, and “HV 3I2_CBF NS” and “MV 3I2_CBF NS” for negative-sequence current.
For protection functions where the tripping criterion is not dependent on cur-rent, current flow is not a suitable criterion for proper operation of the breaker. 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 settings “HV1 CB Status Check On” or “MV CB Status Check On”
Chapter 12 Circuit breaker failure protection
161
should be set to “1-On” to integrate circuit breaker auxiliary contacts into CBF function..
It should be noted that evaluation of circuit breaker auxiliary contacts is car-ried out in CBF function only when the current flow monitoring has not picked up. Once the current flow criterion has picked up during the running time of CBF timers, the circuit breaker is assumed to be open as soon as the current disappears, even if the associated auxiliary contacts don’t indicate that the circuit breaker has opened. This gives preference to the more reliable current criterion and avoids over functioning due to a defect e.g. in the auxiliary con-tact mechanism or circuit.
3 Logic diagram
OR
BI_HV1 CB EXT.INT
Inter 3Ph Init CBFInit HV CBF
Figure 54 Internal and external initiation
Chapter 12 Circuit breaker failure protection
162
HV 3I0/3I2 Check Off
HV 3I0/3I2 Check On
HV 3I0/3I2 Check Off
HV 3I0/3I2 Check On
HV 3I0/3I2 Check Off
HV 3I0/3I2 Check On
Ia > HV1 I_CBF OC
3I0 > HV1 3I0_CBF ZS
3I2 > HV1 3I2_CBF NS
Ib >HV1 I_CBF OC
Ic > HV1 I_CBF OC
OR
Ib >HV1 I_CBF OC
3I0 > HV1 3I0_CBF ZS
3I2 > HV1 3I2_CBF NS
Ic > HV1 I_CBF OC
Ia >HV1 I_CBF OC
OR
AND
AND
Ic >HV1 I_CBF OC
3I0 > HV1 3I0_CBF ZS
3I2 > HV1 3I2_CBF NS
Ib > HV1 I_CBF OC
Ia > HV1 I_CBF OC
OR
AND
OR
OR
OR
OR Curr. Crit
Curr. Crit. C
Curr. Crit. B
Curr. Crit. A
Figure 55 Circuit breaker auxiliary contact evaluation
Init HV CBF
Curr. Crit
AND
ANDO
R
CB is closed
BI_HV1 CB Open A
BI_HV1 CB Open B
BI_HV1 CB Open C
AND
Figure 56 The logic for CB close
Chapter 12 Circuit breaker failure protection
163
T1_CBF
T2_CBF
CB Status Check On
CB is closed
Curr. crit.
Init HV CBF
OR
AND
Func_CBF onCBF stg1
CBF stg2
Figure 57 The logic for CBF protection
4 Input and output signals
IA
IB
IC
CB Pole A Open
CB Pole B Open
CB Pole C Open
EXT. INT CBF
CBF Stage 1 Trip
CBF Stage 2 Trip
Relay Startup
Circuit Breaker Failure Proteciton
Figure 58 Circuit breaker protection module
Table 105 Analog input list
Signal Description
IA Phase A current input IB Phase B current input IC Phase C current input
Table 106 Binary intput list
Signal Description
CB Pole A Open Circuit breaker(CB) pole A is open
Chapter 12 Circuit breaker failure protection
164
Signal Description
CB Pole B Open Circuit breaker(CB) pole A is open
CB Pole COpen Circuit breaker(CB) pole A is open
EXT.INT CBF initiate the CBF protection by external protection
Table 107 Binary output list
Signal Description
CBF Stage1 Trip CBF protection stage 1 trip
CBF Stage2 Trip CBF protection stage 1 trip
Relay Startup Relay Startup
5 Setting Table 108 Settings of CBF protection for HV side of transformer
Setting Unit Min.
(Ir:5A/1A) Max.
(Ir:5A/1A)
Default setting
(Ir:5A/1A) Description
HV I_CBF
OC A 0.05Ir 20Ir 5
Phase current setting value for
HVcircuit breaker failure (CBF)
protection
HV
3I2_CBF
NS
A 0.05Ir 20Ir 5
Negative sequence (NS) cur-
rent setting 23I value for HV
CBF protection
HV
3I0_CBF ZS A 0.05Ir 20Ir 5
Zero sequence (ZS) current
setting 03I value for HV1
CBF protection
HV T1_CBF s 0 32 10 Time setting value of Stage 1,
for HV CBF protection
HV T2_CBF s 0.1 32 10 Time setting value of Stage 2,
for HV CBF protection
Chapter 12 Circuit breaker failure protection
165
Table 109 Binary settings of CBF protection for HV side of transformer
Setting Unit Min. Max. Default setting
Description
HV Func_CBF 0 1 0
HV Circuit breaker failure (CBF) protection is switched ON 1-on; 0-off.
HV 3I0/3I2 Check On
0 1 0
HV CBF protection detect negative or zero sequence current 3I0 or 3I2. 1-Detect; 0- Not Detect
HV CB Status Check On
0 1 0 HV CBF protection detect HV1 CB status 1-Detect; 0- Not Detect
Table 110 Settings of CBF protection for MV side of transformer
Setting Unit Min.
(Ir:5A/1A) Max.
(Ir:5A/1A)
Default setting
(Ir:5A/1A) Description
MVI_CBF
OC A 0.05Ir 20Ir 5
Phase current setting value for
MV CBF protection
MV
3I2_CBF
NS
A 0.05Ir 20Ir 5
Negative sequence (NS) cur-
rent setting 23I value for MV
CBF protection
MV
3I0_CBF ZS A 0.05Ir 20Ir 5
Zero sequence (ZS) current
setting 03I value for MV CBF
protection
MV T1_CBF s 0 32 10 Time setting value of Stage 1,
for MV CBF protection
MV T2_CBF s 0.1 32 10 Time setting value of Stage 2,
for MV CBF protection
Table 111 Binary settings of CBF protection for MV side of transformer
Setting Unit Min. Max. Default setting
Description
Chapter 12 Circuit breaker failure protection
166
MV Func_CBF 0 1 0
MV Circuit breaker failure (CBF) protection is switched ON 1-on; 0-off.
MV 3I0/3I2 Check On
0 1 0
MV CBF protection detect negative or zero sequence current 3I0 or 3I2. 1-Detect; 0- Not Detect
MV CB Status Check On
0 1 0 MV CBF protection detect MV CB status 1-Detect; 0- Not Detect
Table 112 Settings of CBF protection for LV side of transformer
Setting Unit Min.
(Ir:5A/1A) Max.
(Ir:5A/1A)
Default setting
(Ir:5A/1A) Description
LV I_CBF
OC A 0.05Ir 20Ir 5
Phase current setting value for
LV CBF protection
LV 3I2_CBF
NS A 0.05Ir 20Ir 5
Negative sequence (NS) cur-
rent setting 23I value for LV
CBF protection
LV 3I0_CBF
ZS A 0.05Ir 20Ir 5
Zero sequence (ZS) current
setting 03I value for LV CBF
protection
LV T1_CBF s 0 32 10 Time setting value of Stage 1,
for LV CBF protection
LV T2_CBF s 0.1 32 10 Time setting value of Stage 2,
for LV CBF protection
Table 113 Binary settings of CBF protection for LV side of transformer
Setting Unit Min. Max. Default setting
Description
LV Func_CBF 0 1 0 LV Circuit breaker failure (CBF) protection is switched ON 1-on; 0-off.
LV 3I0/3I2 Check On
0 1 0 LV CBF protection detect neg-ative or zero sequence current 3I0 or 3I2.
Chapter 12 Circuit breaker failure protection
167
1-Detect; 0- Not Detect
LV CB Status Check On
0 1 0 LV CBF protection detect LV CB status 1-Detect; 0- Not Detect
6 Report Table 114 Event report list
Information Description
HV CBF1 Trip HV circuit breaker failure protection stage 1 trip
HV CBF2 Trip HV circuit breaker failure protection stage 2 trip
HV CBF Init Internal or external initiate HV circuit breaker failure protection
MV CBF1 Trip MV circuit breaker failure protection stage 1 trip
MV CBF2 Trip MV circuit breaker failure protection stage 2 trip
MV CBF Init Internal or external initiate MV circuit breaker failure protection
LV CBF1 Trip LV circuit breaker failure protection stage 1 trip
LV CBF2 Trip LV circuit breaker failure protection stage 2 trip
LV CBF Init Internal or external initiate LV circuit breaker failure protection
Table 115 Alarm report list
Description of event comment HV Func_CBF On HV circuit breaker failure protection is switched ON (by CW)
HV Func_CBF Off HV circuit breaker failure protection is switched OFF (by CW)
MV Func_CBF On MV circuit breaker failure protection is switched ON (by CW)
MV Func_CBF Off MV circuit breaker failure protection is switched OFF (by CW)
LV Func_CBF On LV circuit breaker failure protection is switched ON (by CW)
LV Func_CBF Off LV circuit breaker failure protection is switched OFF (by CW)
7 Technical data Item Rang or Value Tolerance
phase current
Negative sequence current
zero 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
Chapter 12 Circuit breaker failure protection
168
Time delay of stage 2 0.00s to 32.00 s, step 0.01s 200% energizing setting
Reset ratio >0.95
Reset time < 25ms
Chapter 13 Dead zone protection
169
Chapter 13 Dead zone protection
About this chapter This chapter describes the protection principle, input and output signals, parameter, IED report and technical data used for dead zone (short zone) protection function.
Chapter 13 Dead zone protection
170
1 Introduction The IED provides this protection function to protect dead zone, namely the 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 relay while CB auxiliary contacts indicate the CB is open.
Internal/ external initiation Self-adaptive for bus side CT or line side CT
When one bus side CT of feeder is applied, once a fault occurs in the dead zone, the IED trips the relevant busbar zone. Tripping logic is illustrated in below figure.
2 Protection principle In the case of feeders with bus side CTs, once a fault occurs in the dead zone, the IED trips the relevant busbar zone CBs. Tripping concept is illustrated in the below figure.
Bus2
IFAULT
Trip
T1
L1Ln
Bus1
Bus3
Opened CB
Closed CB
Legend:
Bus2
IFAULT
trip
T1
L1Ln
Bus1
Bus3
Opened CB
Closed CB
Legend:
Figure 59 Tripping logic for applying bus side CT and for applying line side CT
Chapter 13 Dead zone protection
171
2.1 Function description
Internal/external initiation
Self-adaptive for bus side CT or line side CT. For bus side CTs, the dead
zone protection will select to trip breakers on other lines connected to the
same busbar. For line side CTs, the dead zone protection will select trip op-
posite side breakers on the same line.
3 Logic diagram
Func_Dead Zone OnCurr. Crit.
Init HV CBF
AND
T_Dead Zone Dead Zone Trip
BI_HV PhA CB Open
AND
BI_HV 3Ph CB Close
BI_HV PhB CB Open
BI_HV PhC CB Open
AND
Func_HV CBF On
Figure 60 Dead zone protection logic
Chapter 13 Dead zone protection
172
4 Input and output signals
DZ Trip
Relay Startup
CB Pole A Open
CB Pole B Open
CB Pole C Open
CB 3 Poles Close
IA
IB
IC
Dear Zone Protection
Figure 61 Dead zone protection module
Table 116 Analog input list
Signal Description
IA Phase A current input IB Phase B current input IC Phase C current input
Table 117 Binary input list
Signal Description
CB Pole A Open Circuit breaker(CB) pole A is open
CB Pole B Open Circuit breaker(CB) pole B is open
CB Pole C Open Circuit breaker(CB) pole C is open
CB 3 Poles Close 3 poles of circuit breaker(CB) is close
Table 118 Binary output list
Signal Description
DZ Trip dead zone protection trip
Relay Startup Relay Startup
Chapter 13 Dead zone protection
173
5 Setting Table 119 Dead zone protection function setting list for HV side of transformer
Setting Unit Min.
(Ir:5A/1A) Max.
(Ir:5A/1A)
Default setting
(Ir:5A/1A) Description
HV T_Dead Zone s 0 32 10 Time delay setting for HV dead zone protection
Table 120 Dead zone protection binary setting list for HV side of transformer
Setting Unit Min. Max. Default setting
Description
HV Func_Dead Zone
0 1 0 Dead zone protection is switched ON 1-on; 0-off.
Table 121 Dead zone protection function setting list for MV side of transformer
Setting Unit Min.
(Ir:5A/1A) Max.
(Ir:5A/1A)
Default setting
(Ir:5A/1A) Description
MV T_Dead Zone s 0 32 10 Time delay setting for MV dead zone protection
Table 122 Dead zone protection binary setting list for MV side of transformer
Setting Unit Min. Max. Default setting
Description
MV Func_Dead Zone
0 1 0 Dead zone protection is switched ON 1-on; 0-off.
Table 123 Dead zone protection function setting list for LV side of transformer
Setting Unit Min.
(Ir:5A/1A) Max.
(Ir:5A/1A)
Default setting
(Ir:5A/1A) Description
LV T_Dead Zone
s 0 32 10 Time delay setting for LV dead zone protection
Chapter 13 Dead zone protection
174
Table 124 Dead zone protection binary setting list for LV side of transformer
Setting Unit Min. Max. Default setting
Description
LV Func_Dead Zone 0 1 0 Dead zone protection is switched ON 1-on; 0-off.
6 Report Table 125 Event report list
Information Description HV Dead Zone HV Dead zone trip
MV Dead Zone MV Dead zone trip
LV Dead Zone LV Dead zone trip
Table 126 Operation report list
Information Description HV Func_DZ On HV DZ function on
HV Func_DZ Off HV DZ function off
MV Func_DZ On MV DZ function on
MV Func_DZ Off MV DZ function off
LV Func_DZ On LV DZ function on
LV Func_DZ Off LV DZ function off
7 Technical data NOTE: Ir: CT rated secondary current, 1A or 5A; Item Rang or Value Tolerance
Current 0.08 Ir to 20.00 Ir ≤ ±3% setting or ±0.02Ir
Time delay 0.00s to 32.00s, step 0.01s ≤ ±1% setting or +40 ms, at
200% energizing setting
Reset ratio >0.95
Chapter 14 STUB protection
175
Chapter 14 STUB protection
About this chapter This chapter describes the protection principle, input and output signals, parameter, IED report and technical data used for STUB protection function.
Chapter 14 STUB protection
176
1 Introduction The STUB protection protects the zone between the CTs and the open dis-connector. 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.
2 Protection principle
2.1 Function description
Fault
CB1
CB3
CB2
CT1-2
CT3-2
CT2-1
Feeder 1 Disconnector
Feeder 2 Disconnector
Feeder1
Feeder2
Busbar A
Busbar B
CT3-1
CT2-2
CT1-1
Figure 62 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.
Chapter 14 STUB protection
177
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 ser-vice. 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.
3 Logic diagram
Func_STUB on
Ia>I_STUB
T_STUB
BI_STUB Enable
AND
Permanent trip
Ib>I_STUB
Ic>I_STUB
OR
“1”
Figure 63 Logic diagram for STUB protection
4 Input and output signals
IA1
IB1
IC1
IA2
IB2
IC2
STUB Trip
Relay Startup
STUB Protection
HV STUB Enable
Figure 64 STUB protection module
Chapter 14 STUB protection
178
Table 127 Analog input list
Signal Description
IA1 Phase A current input of CT of circuit breaker 1 IB1 Phase B current input of CT of circuit breaker 1 IC1 Phase C current input of CT of circuit breaker 1 IA2 Phase A current input of CT of circuit breaker 2 IB2 Phase B current input of CT of circuit breaker 2 IC2 Phase C current input of CT of circuit breaker 2
Table 128 Binary input list
Signal Description
HV STUB Enable Feeder disconnector is open, to enable the STUB protection
Table 129 Binary output list
Signal Description
STUB Trip STUB Trip Relay Startup Relay Startup
5 Setting Table 130 Setting value list for STUB protection for HV side of transformer
Setting Unit Min.
(Ir:5A/1A) Max.
(Ir:5A/1A)
Default setting
(Ir:5A/1A) Description
HV I_STUB A 0.05Ir 20Ir 100 current threshold of STUB protection
HV T_STUB s 0 60 60 delay time of STUB protec-tion
Chapter 14 STUB protection
179
Table 131 Binary setting list for STUB protection for HV side of transformer
Setting Unit Min. Max. Default setting
Description
HV Func_STUB 0 1 0
Enable or disable STUB protection
HV STUB Init LV CBF 0 1 0
STUB protection initiate
LV side CBF 0 - initiate, 1 – not initiate
HV STUB Init MV CBF 0 1 0
STUB protection initiate
HV side CBF 0 - initiate, 1 – not initiate
Table 132 Setting value list for STUB protection for MV side of transformer
Setting Unit Min.
(Ir:5A/1A) Max.
(Ir:5A/1A)
Default setting
(Ir:5A/1A) Description
MV I_STUB A 0.05Ir 20Ir 100 current threshold of STUB protection
MV T_STUB s 0 60 60 delay time of STUB protection
Table 133 Binary setting list for STUB protection for MV side of transformer
Setting Unit Min. Max. Default setting
Description
MV Func_STUB 0 1 0
Enable or disable STUB protection
MV STUB Init LV CBF 0 1 0
STUB protection initiate
LV side CBF 0 - initiate, 1 – not initiate
MV STUB Init MV CBF 0 1 0
STUB protection initiate
MV side CBF 0 - initiate, 1 – not initiate
Table 134 Setting value list for STUB protection for LV side of transformer
Setting Unit Min.
(Ir:5A/1A) Max.
(Ir:5A/1A)
Default setting
(Ir:5A/1A) Description
LV I_STUB A 0.05Ir 20Ir 100 current threshold of STUB protection
LV T_STUB s 0 60 60 delay time of STUB protection
Chapter 14 STUB protection
180
Table 135 Binary setting list for STUB protection for LV side of transformer
Setting Unit Min. Max. Default setting
Description
LV Func_STUB 0 1 0
Enable or disable STUB protection
LV STUB Init LV CBF 0 1 0
STUB protection initiate
LV side CBF 0 - initiate, 1 – not initiate
LV STUB Init MV CBF 0 1 0
STUB protection initiate
LV side CBF 0 - initiate, 1 – not initiate
6 Report Table 136 Event report list
Information Description
HV STUB Trip HV STUB protection trip MV STUB Trip MV STUB protection trip LV STUB Trip LV STUB protection trip
Table 137 Operation report list
Information Description HV Func_STUB On HV STUB function on
HV Func_STUB Off HV STUB function Off
MV Func_STUB On MV STUB function on
MV Func_STUB Off MV STUB function Off
LV Func_STUB On LV STUB function on
LV Func_STUB Off LV STUB function Off
Chapter 14 STUB protection
181
7 Technical data NOTE: Ir: CT rated secondary current, 1A or 5A;
Table 138 Technical data for STUB protection
Item Rang or Value Tolerance
Current 0.08 Ir to 20.00 Ir ≤ ±3% setting or ±0.02Ir
Time delay 0.00s to 60.00s, step 0.01s ≤ ±1% setting or +40 ms, at
200% energizing setting
Reset ratio >0.95
Chapter 14 STUB protection
182
Chapter 15 Poles discordance protection
183
Chapter 15 Poles discordance protection
About this chapter This chapter describes the protection principle, input and output signals, parameter, IED report and technical data for poles dis-cordance protection.
Chapter 15 Poles discordance protection
184
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 me-chanical 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 unsym-metrical 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.
2 Protection principle 2.1 Function description
The CB position signals are connected to IED via binary input in order to monitor the CB status. Poles discordance condition is established when bi-nary setting “HV Func_PD” for HV said, or “MV Func_PD” for MV said 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 “HV PD Chk 3I0/3I2” and “MV PD Chk 3I0/3I2”for additionaly zero and negative sequence current as well as current criteria involved in CBF protection. Pole discord-ance can be detected when current is not flowing through all three poles. When current is flowing through all three poles, all three poles must be closed even if the breaker auxiliary contacts indicate a different status.
Chapter 15 Poles discordance protection
185
3 Logic diagram
5s
Func_PD On
PD Chk 3I0/3I2 on
BI_CB Open A ANDIa > 0.06Ir
BI_CB Open B ANDIb > 0.06Ir
BI_CB Open C ANDIc > 0.06Ir
BI_CB Open AAND
BI_CB Open B
BI_CB Open C
BI_CB Open A ANDIa < 0.06Ir
BI_CB Open B ANDIb < 0.06Ir
BI_CB Open C ANDIc< 0.06Ir
OR
3I2 > 3I2_PD
3I0 >3I0_PDAND
Curr. Crit. AAND
Curr. Crit. B
Curr. Crit. C
PD Chk 3I0/3I2 off
OR
OR
AND
CB Err Blk PD
AND
PD Trip
T_PD
“1”
Figure 65 Logic diagram for poles discordance protection
Chapter 15 Poles discordance protection
186
4 Input and output signals
INBK
IA
IB
IC
CB Pole A Open
CB Pole B Open
CB Pole C Open
PD Trip
Relay Startup
Pole Discordance Protection
Figure 66 Poles discordance protection module
Table 139 Analog input list
Signal Description
IA Phase A current input
IB Phase B current input
IC Phase C current input
INBK Neutral current input
Table 140 Binary input list
Signal Description
CB Pole A Open Circuit breaker(CB) pole A is open CB Pole B Open Circuit breaker(CB) pole B is open CB Pole C Open Circuit breaker(CB) pole C is open
Table 141 Binary output list
Signal Description
PD Trip PD Trip Relay Startup Relay Startup
Chapter 15 Poles discordance protection
187
5 Setting Table 142 Function setting list for poles discordance protection for HV side of
tranformer
Setting Unit Min. Max. Default setting Description
HV 3I0_PD A 0.05Ir 20Ir 5 zero sequence current threshold of pole discordance protection
HV 3I2_PD A 0.05Ir 20Ir 5 negative sequence current threshold of pole discordance protection
HV T_PD s 0 60 10 delay time of pole discordance protection
Table 143 Binary setting list for poles discordance protection for HV side of tranformer
Setting Unit Min. Max. Default setting Description
MV Func_PD 0 1 0 Enable or disable MV poles discordance protection
MV PD Chk 3I0/3I2
0 1 0 Enable or disable 3I0/3I2 criteria
Table 144 Function setting list for poles discordance protection for MV side of tranformer
Setting Unit Min. Max. Default setting Description
MV 3I0_PD A 0.05Ir 20Ir 5 zero sequence current threshold of pole discordance protection
MV 3I2_PD A 0.05Ir 20Ir 5 negative sequence current threshold of pole discordance protection
MV T_PD s 0 60 10 delay time of pole discordance protection
Table 145 Binary setting list for poles discordance protection for MV side of tranformer
Setting Unit Min. Max. Default setting Description
MV Func_PD 0 1 0 Enable or disable MV poles discordance protection
MV PD Chk 3I0/3I2
0 1 0 Enable or disable 3I0/3I2 criteria
Chapter 15 Poles discordance protection
188
6 Report Table 146 Event report list
Information Description
HV PD Trip HV poles discordance protection trip MV PD Trip MV poles discordance protection trip
Table 147 Alarm report list
Information Description
CB Err Blk PD Circuit breaker error block poles discordance protection
Table 148 Operation report list
Information Description HV Func_PD On HV poles discordance function on HV Func_PD Off HV poles discordance function off MV Func_PD On MV poles discordance function on MV Func_PD Off MV poles discordance function off
7 Technical data NOTE: Ir: CT rated secondary current, 1A or 5A;
Table 149 Technical data for pole discordance
Item Rang or Value Tolerance Current 0.08 Ir to 20.00 Ir ≤ ±3% setting or ±0.02Ir Time delay 0.00s to 60.00s, step 0.01s ≤ ±1% setting or +40 ms, at
200% energizing setting Reset ratio >0.95
Chapter 16 Distance protection
189
Chapter 16 Distance protection
About this chapter This chapter describes the protection principle, input and output signals, parameter, IED report and technical data for poles dis-cordance protection.
Chapter 16 Distance protection
190
1 Introdcution Sub-transmission networks are being extended and often become more and more complex, consisting of a high number of multi-circuit and/or multi ter-minal lines of very different lengths. These changes in the network will nor-mally impose more stringent demands on the fault clearing equipment in or-der to maintain an unchanged or increased security level of the power sys-tem.
The distance protection function in the IED is designed to meet basic re-quirements for application on transformer and transmission lines.
2 Protection principle 2.1 Function description
Phase-to-phase distance protection has two settable distance stages; in ad-dition, every stage can be switched over via binary setting and every stage with 1 timer delay setting. Phase-to-phase distance calculations are based on the three phase-to-phase voltages and phase-to-phase currents. The formula is as follows:
−
−=
−
−=
−
−=
AC
ACCA
CB
CBBC
BA
BAAB
IIUU
Z
IIUU
Z
IIUU
Z
Where ZAB, ZBC, ZCA: phase-to-phase distance
Phase-to-earth distance protection has one settable distance stage, with 1 timer delay setting. The formula for calculation phase-to-earth distance is as follow:
03IKIU
Z
⋅+=
Φ
ΦΦ
Where ΦU - Phase voltage ( CBA ,,=Φ )
ΦI - Phase current ( CBA ,,=Φ )
K - Zero sequence current compensation factors
In order to avoiding the mal-operation of the distance protection, it is blocked when VT fuse failure occurs. Both distance characteristics are round.
Chapter 16 Distance protection
191
RZ
XZ
R
X
XZ×NZ
a) Direction to transformer
R
X
b) Direction to system
RZ×NZ
XZ×NZ
RZ
RZ×NZ
XZ
Figure 67 Tripping characteristics of distance protection
The positive direction for distance protection can be switched over via binary setting. For example, for phase-to-phase distance, if binary setting “DIS_1 DIR TO SYS” is set 1, it means direction for 1st stage phase-to-phase dis-tance is to system; and setting is set 0, it means direction to transformer. It is same to phase to earth distance.
2.2 Auxiliary startup element In order to avoid unwanted operation of distance protection and to insure correct operation when phase-to-phase fault and phase-to-earth fault occur. Auxiliary startup elements including negative current element and abrupt current element are adopted.
Auxiliary abrupt current startup element
When all kinds of faults occur in the protected section, current in HV or MV side will be abrupt change. Abrupt current startup element is adopted in dis-tance protection; the formula is as follows:
−+−−=∆
>∆
ΦΦΦΦ
Φ
)2(2)()(2.0
ntintitiiIi N
Where Φ∆i - abrupt current startup element
● Auxiliary negative current startup element
When all kinds of faults occur in the protected section, current in HV or MV side will be abrupt change. Abrupt current startup element is adopted in dis-tance protection; the formula is as follows:
−+−−=∆
>∆
ΦΦΦΦ
Φ
)2(2)()(2.0
ntintitiiIi N
Chapter 16 Distance protection
192
Where Φ∆i - abrupt current startup element
● Auxiliary negative current startup element
When the imbalance fault occurs in the protected section, negative current occurs at the same time. Using negative current is helpful to detect the im-balance faults. the formula is as follows:
ieII 2.02 > ( mhi ,= ) (5-12)
Where ieI - rated current of HV or MV side.
Phase-to-phase distance and phase-to-earth distance have same logic.
3 Logic diagram The typical logic of 1 stage of distance protection is shown in below figure.
VT failure
DIS Trip
DIS ON
&Distance Point
inside the Circle
T I2>0.2Ie
>=1NIi 2.0>∆ Φ
Figure 68 Tripping logic for distance protection
4 Input and output signals
HV DIS(Ph-N)Trip
HV DIS_1 Trip
Distance Protection
IA1
IB1
IC1
IA2
IB2
IC2
UA
UB
UC
HV DIS_2 Trip
Relay Startup
Figure 69 Distance protection module
Chapter 16 Distance protection
193
Table 150 Analog input list
Signal Description
IA1 Phase A current input of CT of circuit breaker 1
IB1 Phase B current input of CT of circuit breaker 1
IC1 Phase C current input of CT of circuit breaker 1
IA2 Phase A current input of CT of circuit breaker 2
IB2 Phase B current input of CT of circuit breaker 2
IC2 Phase C current input of CT of circuit breaker 2
UA Phase A voltage input of VT of related winding of transformer
UB Phase B voltage input of VT of related wind-ing of transformer
UC Phase C voltage input of VT of related wind-ing of transformer
Table 151 Binary output list
Signal Description
HV DIS(Ph-N)Trip Phase to Earth Distance (DIS Ph-N) tripping in HV side
HV DIS_1 Trip Phase to phase Distance (DIS) prot. Stage 1(_1) or Stage 2 (_2) tripping in HV side with time delay T
HV DIS_2 Trip
Relay Startup Relay Startup
5 Setting Table 152 Function setting list for distance protection for HV side of tranformer
Setting Title Setting options
Default setting Comment
1 HV DIS PH-N X 0.1..125Ω 10 Phase-to-earth distance(DIS PH-N) set-ting X
2 HV DIS PH-N R 0.1..125Ω 1 Phase-to-earth distance(DIS PH-N) set-ting R
3 HV DIS OFFSET RATIO 0.0..1.00 1 Offset ratio to setting
4 HV K FACTOR 0.0..99.0 1 zero sequence compensation coefficient
5 T HV DIS PH-N 0.1..20.0s 5 Timer setting for DIS PH-N
6 HV DIS1 PH-PH X1 0.1..125Ω 10 1st stage Phase-to-phase dis-tance(DIS1) setting X
7 HV DIS1 PH-PH R1 0.1..125Ω 1 1st stage Phase-to-phase dis-tance(DIS1) setting
Chapter 16 Distance protection
194
8 HV DIS1 OFFSET RATIO 0.0..1.00 1 Offset ratio to setting of 1st stage DIS1
9 T HV DIS1 PH-PH 0.1..20.0s 5 Timer setting for 1st stage DIS1
10 HV DIS2 PH-PH X2 0.1..125Ω 10 2nd stage Phase-to-phase dis-
tance(DIS2) setting X 11
HV DIS2 PH-PH R2 0.1..125Ω 1 2nd stage Phase-to-phase dis-tance(DIS2) setting
12 HV DIS2 OFFSET RATIO 0.0..1.00 1 Offset ratio to setting of 2nd stage DIS2
13 T HV DIS2 PH-PH 0.1..20.0s 5 Timer setting for 2nd stage DIS2
Table 153 Binary setting list for distance protection for HV side of tranformer
No Setting Title Setting options
Default setting Comment
1 HV DIS PH-N ON 0/1 0 Phase to earth distance(DIS PH-N) in HV side on.
2 HV DIS PH-N DIR TO SYS 0/1 0
Phase to earth Distance (DIS PH-N) direction(DIR) to system(SYS) in HV side
3 HV DIS1 PH-PH ON 0/1 0 1st stage phase to phase distance
(DIS1) in HV side on
4 HV DIS1 PH-PH DIR TO SYS 0/1 0
1st stage Phase to phase Distance (DIS1) direction(DIR) to system(SYS) in HV side
5 HV DIS2 PH-PH ON 0/1 0 2nd stage phase to phase distance
(DIS2) in HV side on
6 HV DIS2 PH-PH DIR TO SYS 0/1 0
2nd stage Phase to phase Distance (DIS2) direction(DIR) to system(SYS) in HV side
Table 154 Function setting list for distance protection for MV side of tranformer
No Setting Title Setting options
Default setting Comment
1 MV DIS PH-N X 0.1..125Ω 10 Phase-to-earth distance(DIS PH-N)
setting X 2
MV DIS PH-N R 0.1..125Ω 1 Phase-to-earth distance(DIS PH-N) setting R
3 MV DIS OFFSET RATIO 0.0..1.00 1 Offset ratio to setting
4 MV K FACTOR 0.0..99.0 1 zero sequence compensation coeffi-
cient 5
T MV DIS PH-N 0.1..20.0s 5 Timer setting for DIS PH-N
6 MV DIS1 PH-PH X1 0.1..125Ω 10 1st stage Phase-to-phase dis-
tance(DIS) setting X 7
MV DIS1 PH-PH R1 0.1..125Ω 1 1st stage Phase-to-phase dis-tance(DIS) setting
8 MV DIS1 OFFSET RATIO 0.0..1.00 1 Offset ratio to setting of 1st stage DIS1
Chapter 16 Distance protection
195
9 T MV DIS1 PH-PH 0.1..20.0s 5 Timer setting for 1st stage DIS1
10 MV DIS2 PH-PH X2 0.1..125Ω 10 2nd stage Phase-to-phase dis-
tance(DIS2) setting X 11
MV DIS2 PH-PH R2 0.1..125Ω 1 2nd stage Phase-to-phase dis-tance(DIS2) setting R
12 MV DIS2 OFFSET RATIO 0.0..1.00 1 Offset ratio to setting of 2nd stage DIS2
13 T MV DIS2 PH-PH 0.1..20.0s 5 Timer setting for 2nd stage DIS2
Table 155 Binary setting list for distance protection for MV side of tranformer
NO Setting Title Setting options
Default setting Comment
1 MV DIS PH-N ON 0/1 0 Phase to earth distance (DIS PH-N) in
MV side on.
2 MV DIS PH-N DIR TO SYS 0/1 0 Phase to earth Distance (DIS PH-N) di-
rection(DIR) to system(SYS) in MV side
3 MV DIS1 PH-PH ON 0/1 0 1st stage phase to phase distance (DIS1)
in MV side on
4 MV DIS1 PH-PH DIR TO SYS
0/1 0 1st stage Phase to phase Distance (DIS1) direction(DIR) to system(SYS) in MV side
5 MV DIS2 PH-PH ON 0/1 0 2nd stage phase to phase distance
(DIS2) in MV side on
6 MV DIS2 PH-PH DIR TO SYS
0/1 0 2nd stage Phase to phase Distance (DIS2) direction(DIR) to system(SYS) in MV side
6 Report Table 156 Event report list
Information Description
HV DIS(Ph-N)Trip Phase to Earth Distance (DIS Ph-N) tripping in HV side HV DIS_1 Trip Phase to phase Distance (DIS) prot. Stage 1(_1) or Stage 2 (_2)
tripping in HV side with time delay T HV DIS_2 Trip Relay Startup Relay Startup
Table 157 Operation report list
Information Description HV Func_Dis On HV distance protection on MV Func_Dis On MV distance protection on HV Func_Dis Off HV distance protection off MV Func_Dis Off MV distance protection off
Chapter 16 Distance protection
196
7 Technical data NOTE: Ir: CT rated secondary current, 1A or 5A;
Table 158 Technical data for distance protection
Item Rang or Value Tolerance Resistance setting range 0. 1Ω~25Ω, step 0.01Ω, when
Ir=5A; 0. 5Ω~125Ω, 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. 1Ω~25Ω, step 0.01Ω, when Ir=5A; 0. 5Ω~125Ω, step 0.01Ω, when Ir=1A;
Time delay of distance zones 0.1to 20.00s, step 0.01s ≤±1% or +20 ms Operation time 40ms typically at 70% setting of
zone
Dynamic overreaching ≤±5%, at 0.5<SIR<30
Chapter 17 Secondary system supervision
197
Chapter 17 Secondary system supervision
About this chapter This chapter describes the protection principle, input and output signals, parameter, IED report and technical data for secondary system supervision function.
Chapter 17 Secondary system supervision
198
1 VT failure supervision function 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 protec-tion functions which work based on voltage criteria may mistakenly see a voltage of zero. VT failure supervision function is provided to inform those functions about a voltage failure.
2 Function principle VT failure supervision function can be enabled or disabled in each side through Binary setting “HV VT Fail Detect”, “MV VT Fail Detect” and “LV VT Fail Detect”. By applying setting “1-On” to these Binary settings, respective VT failure supervision function would monitor the voltage transformer circuit of corresponding side. Each VT failure supervision function is able to detect single-phase broken, two-phase broken or three-phase broken faults in re-spective voltage transformer. There are three main criteria for VT failure de-tection; from them the first one is dedicated to detect three-phase broken faults. The second and third one is dedicated to detect single or two-phase broken faults in solid earthed and isolated/resistance earthed systems, re-spectively. A precondition to meet these three criteria is that the relay should not be picked up and the calculated zero sequence and negative sequence currents should be less than setting of “HV 3I02_ VT Fail”, “MV 3I02_ VT Fail” or “LV 3I02_ VT Fail”. These criteria are as follows:
The calculated zero sequence voltage 3U0 as well as maximum of three phase-to-earth voltages of respective side of the protected transformer are less than the setting of “HV Upe_VT Fail”, “MV Upe_VT Fail” or “LV Upe_VT Fail” and at the same time, maximum of three phase currents of respective side is higher than setting of “HV I_VT Fail”, “MV I_VT Fail” or “LV I_VT Fail”. This condition may correspond to three phase broken fault in secondary cir-cuit of the voltage transformer in respective side of the protected transformer.
The calculated zero sequence voltage 3U0 of respective side of the protected transformer is more than the setting of “HV Upe_VT Fail”, “MV Upe_VT Fail” or “LV Upe_VT Fail”. This condition may correspond to single or two-phase broken fault in secondary circuit of the voltage transformer in respective side of the protected transformer, if the system starpoint is solidly earthed.
The calculated zero sequence voltage 3U0 of respective side of the protected transformer is more than the setting of “HV Upe_VT Fail”, “MV Upe_VT Fail” or “LV Upe_VT Fail”, and at the same time, the difference between the max-imum and minimum phase-to-phase voltages of respective side is more than the setting of “HV Upp_VT Fail”, “MV Upp_VT Fail” or “LV Upp_VT Fail”. This condition may correspond to single or two-phase broken fault in secondary circuit of the voltage transformer in respective side of the protected trans-former, if the system starpoint is isolated or resistance earthed.
In addition to the mentioned conditions, the device has the capability to be informed about the VT MCB failure through its binary inputs. These inputs in-clude “HV MCB FAIL BI”, “MV MCB FAIL BI” and “LV MCB FAIL BI”. In this
Chapter 17 Secondary system supervision
199
context, VT fail is detected in corresponding side, if the respective binary in-puts are active.
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 operate based on di-rection determination would be blocked in corresponding side of the protected transformer, depending on the setting. Furthermore, an alarm report of “HV VT Fail”, “MV VT Fail” or “LV VT Fail”, is issued after 10s delay time. The blocking condition would be removed if one of the following conditions is met within the 10s delay time.
Minimum phase voltage of corresponding side of the protected transformer becomes more than setting of “HV Upe_VT Normal”, “MV Upe_VT Normal” or “LV Upe_VT Normal” for 500ms.
Minimum phase voltage of corresponding side becomes more than setting of “HV Upe_VT Normal”, “MV Upe_VT Normal” or “LV 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 “HV 3I02_VT Fail”, “MV 3I02_VT Fail” or “LV 3I02_VT Fail”.
Subsequent to reporting VT fail alarm, the blocking condition of respective protection functions would be removed if the minimum phase voltage of cor-responding side becomes more than the setting of “HV Upe_VT Normal”, “MV Upe_VT Normal” or “LV Upe_VT Normal” for a duration more than 10s.
Below figure shows logic diagram of VT failure supervision as it is imple-mented in the IED.
Chapter 17 Secondary system supervision
200
Max(Ia,Ib,Ic) > I_ VT Fail
Max{Ua,Ub,Uc} < Upe_VT Fail
3U0 < ( Upe_VT Fail-1)
Max{Uab,Ubc,Uca} - Min{Uab,Ubc,Uca}> Upp_VT Fail
3U0 >= (Upe_VT Fail-1)
Min{Ua,Ub,Uc} > Upe_VT Normal
3I0 > 3I02_VT Fail or3I2 > 3I02_VT Fail
min{Ua,Ub,Uc} > Upe_VT Normal
AND
AND
OR
AND
AND
OR
AND
AND
AND
500ms
AND
AND
10s
OR No VT Fail
VT Fail Detected 10s Alarm report
Solid Earth on
Solid Earth offAND
Relay Pickup
BI MCB Fail
HV VT Fail Detect on
VT Fail Detected
“1”
“1”
Figure 70 Logic of VT Failure supervision
Chapter 17 Secondary system supervision
201
3 Input and output signals
IA1
IB1
IC1
IA2
IB2
IC2
UA
UB
UC
VT Failure
Relay Startup
V3P MCB Fail
VT Secondary Circuit Supervision
Figure 71 VT Failure supervision module
Table 159 Analog input list
Signal Description
IA1 Phase A current input of CT of circuit breaker 1 IB1 Phase B current input of CT of circuit breaker 1 IC1 Phase C current input of CT of circuit breaker 1 IA2 Phase A current input of CT of circuit breaker 2 IB2 Phase B current input of CT of circuit breaker 2 IC2 Phase C current input of CT of circuit breaker 2 UA Phase A voltage input UB Phase B voltage input UC Phase C voltage input
Table 160 Binary input list
Signal Description
V3P MCB Fail VT failure informed by BI
Table 161 Binary output list
Signal Description
VT Failure VT Failure Relay Startup Relay Startup
Chapter 17 Secondary system supervision
202
4 Setting Table 162 Settings of VT failure supervision for HV side of transformer
Setting Title Unit Min. Max. Default setting Comment
HV I_VT Fail A 0.05Ir 0.2Ir 0.05 Minimum Current of VT failure for HV side
HV 3I02_ VT Fail A 0.05Ir 0.2Ir 0.5 Minimum zero or negative Cur-rent of HV VT fail
HV Upe_VT Fail V 7 20 8 Maximum phase to earth voltage of HV VT fail
HV Upp_VT Fail V 10 30 16 Maximum phase to phase volt-age of HV VT fail
HV Upe_VT Normal V 40 65 40 Minimum phase to phase volt-
age of HV VT normal
Table 163 Binary settings of VT failure supervision for HV side of transformer
Setting Title Unit Min. Max. Default Comment
HV VT FAIL Detect 0 1 0 HV VT Failure Detection On/Off 1-On, 0-Off.
HV Solid Earth 0 1 0
HV Earthing mode: 1: Solid earthed system ; 0: isolated system or resistance earthed.
Table 164 Settings of VT failure supervision for MV side of transformer
Setting Title Unit Min. Max. Default setting Comment
MV I_VT Fail A 0.05Ir 0.2Ir 0.05 Minimum Current of VT failure for MV side
MV 3I02_VT Fail A 0.05Ir 0.2Ir 0.5 Minimum zero or negative Cur-rent of MV VT fail
MV Upe_VT Fail V 7 20 8 Maximum phase to earth voltage of MV VT fail
MV Upp_VT Fail V 10 30 16 Maximum phase to phase volt-age of MV VT fail
MV Upe_VT Normal V 40 65 40 Minimum phase to phase volt-
age of MV VT normal
Table 165 Binary settings of VT failure supervision for MV side of transformer
Setting Title Unit Max. Min. Default Comment
MV VT FAIL Detect 1 0 0 MV VT Failure Detection On/Off 1-On, 0-Off.
MV Solid Earth 1 0 0
MV Earthing mode: 1: Solid earthed system ; 0: isolated system or re-sistance earthed.
Chapter 17 Secondary system supervision
203
Table 166 Settings of VT failure supervision for LV side of transformer
Setting Title Unit Min. Max. Default setting Comment
LV I_VT Fail A 0.05Ir 0.2Ir 0.05 Minimum Current of VT failure for LV side
LV 3I02_VT Fail A 0.05Ir 0.2Ir 0.5 Minimum zero or negative Cur-rent of LV VT fail
LV Upe_VT Fail V 7 20 8 Maximum phase to earth voltage of LV VT fail
LV Upp_VT Fail V 10 30 16 Maximum phase to phase volt-age of LV VT fail
LV Upe_VT Normal V 40 65 40 Minimum phase to phase volt-
age of LV VT normal
Table 167 Binary settings of VT failure supervision for LV side of transformer
Setting Title Unit Min. Max. Default Comment
LV VT FAIL Detect 0 1 0 LV VT Failure Detection On/Off 1-On, 0-Off.
LV Solid Earth 0 1 0
LV Earthing mode: 1: Solid earthed system ; 0: isolated system or resistance earthed.
5 Report Table 168 Alarm report list
Information Description
HV VT Fail HV VT Fail alarm MV VT Fail MV VT Fail alarm LV VT Fail LV VT Fail alarm
Table 169 Operation report list
Information Description HV Func_VT On HV VT failure supervision function on HV Func_VT Off HV VT failure supervision function off MV Func_VT On MV VT failure supervision function on MV Func_VT Off MV VT failure supervision function off LV Func_VT On LV VT failure supervision function on LV Func_VT Off LV VT failure supervision function off
Chapter 17 Secondary system supervision
204
6 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 se-quence 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 volt-age
10.0V to 30.0V, step 0.01V ≤ ±3% setting or ±1 V
Normal phase to earth voltage 40.0V to 65.0V, step 0.01V ≤ ±3% setting or ±1 V
Chapter 18 External Bis to trip BOs
205
Chapter 18 External BIs to trip BOs
About this chapter This chapter describes the protection principle, input and output signals, parameter, IED report and technical data for external BIs to trip BOs function.
Chapter 18 External Bis to trip BOs
206
1 Introduction Two special binary inputs (BI_Config1, BI_Config2) are provided which can be used to activate respective binary outputs (BO1 and BO2), according to the setting applied at Binary settings “BI1 Enable BO1” and “BI2 Enable BO2”. By applying setting “1-enable” to these Binary settings, BO1 will be activated if BI1 is energized. Similarly, BO2 will be activated if BI2 is energized.
2 Function principle The external BIs can be used in conjunction with the mechanical protections of the protected transformer (such as Buchholz, Winding temperature, and so on). In this context, trip commands of the main and backup mechanical pro-tections can be marshaled to BI1 and BI2, respectively. By doing so, the output trip commands would be provided at BO1 and BO2 respectively.
Since the trip command of mechanical protection has latched nature, two operating modes are provided for the BOs activation. The operating modes include direct and pulse tripping modes. In direct tripping mode, each BO contact is active as long as respective BI is energized, and after BI disap-pearance 20ms the BO contacts are deactivated. Whereas in pulse tripping mode, by each up-edge of BI, respective BO contacts remain active during a settable pulse time, and after the settable time, the BO contacts are inactive. The tripping modes can be selected for the BOs by Binary settings “BO1 Pulse Tripping” and “BO2 Pulse Tripping”. Pulse tripping mode would be possible if setting “1-Pulse Tripping” is applied to the Binary settings. Similarly, setting “0-Direct Tripping” activates direct tripping mode for respective BOs. The logic is shown in below figure.
Pulse Tripping TimeBI Enable BO on
BO Pulse Tripping
AND A
ND
AND
AND
BIx up edge BI trip BO
BI trip BO
“1”
“1”
01
10
10
10
20ms
Figure 72 Logic of external BIs to trip Bos
Furthermore, it is possible to set BIs to initiate CBF protection in HV, MV or LV
Chapter 18 External Bis to trip BOs
207
sides of protected transformer via a number of Binary settings. The Binary settings include “BI1 Init HV CBF”, “BI1 Init MV CBF” and “BI1 Init LV CBF” on for the first BI. Similarly, Binary settings “BI2 Init HV CBF”, “BI2 Init MV CBF” and “BI2 Init LV CBF” correspond to the second BI.
3 BI Trigger Record In the IED, it is possible for Binary inputs (BIs) to trigger disturbance record (DR). The exceptions are “Switch SetGroup”, “Blk Rem Access”, “Relay Test” and “Reset”. In this context, each Binary input can be set independently whether it can trigger DR or not. Further, it is possible to set whether BI trig-gers DR in it’s up or down edge. Example logic of BI “HV CB Open Status” triggering DR is given in below figure. The same logic is applied for the other BIs.
Equipment parameter “HV CB OPEN STATUS DOWN” = 1
(meaning DOWN edge)
BI “HV CB Open Status”Change from “1”to “0”
AND
BI“HV CB OPEN STATUS ENABLE”=1
BI “HV CB Open Status”Change from “0”to “1”
Equipment parameter “HV CB OPEN STATUS DOWN” = 0
(meaning UP edge)
AND
OR
Trigger Record
Figure 73 Logic of BI trigger record
Chapter 18 External Bis to trip BOs
208
4 BI Switch SetGroup BI “Switch SetGroup” is used to switch setting group of the device. Both “BI SetGrp Switch”and “Normal Set Switch” are selected by making change in the content of special Binary setting “BI SetGrp Switch” which can be set under “Common Para” submenu. When the Binary setting is set to 1, BI setting group switch mode is applied, on the contrary, Normal setting group switch mode (shortcut key or operate through the menu) is applied. For “BI SetGrp Switch” mode, When BI “Switch SetGroup” is deactivated, the content of Bi-nary setting “BI SetGrp Switch” is set to 0 and it means that no switching in setting groups is desired. In this case, Group 1 is applied to the device. When the BI is activated, the content of Binary setting “BI SetGrp Switch” is set to 1 and it means that “BI SetGrp Switch” mode is applied. Thus, the current set-ting-value would automatically be switched to Group 2. For the other switch mode, whether the BI is activated or not, setting group change is valid for shortcut key or operate through the menu.
5 BI “Blk Rem Access” and “RELAY TEST” There are two methods to block remote access to the device, BI “Blk Rem Access” or making change in the content of special Binary setting “NOT Blk Remote Access” which can be set under “Common Para” submenu.
When BI “Blk Rem Access” is activated, or the content of Binary setting “NOT Blk Remote Access” is set to 0, SCADA remote access is blocked to the de-vice and therefore, only local operation is permitted.
When BI “Blk Rem Access” is deactivated, and the content of Binary setting “NOT Blk Remote Access” is set to 1, both SCADA commands and local op-eration can be executed by the device.
Similarly, there are two methods to select test or normal operating mode of the device, BI “Relay Test” or making change in the content of special Binary setting “Relay Test Mode” which can be set under “Common Para” submenu.
When BI “Relay Test” is activated, or the content of Binary setting “Relay Test Mode” is set to 1, the relay is in test mode.
When BI “Relay Test” is deactivated, and the content of Binary setting “Relay Test Mode” is set to 0, the relay is in normal operation mode
Chapter 18 External Bis to trip BOs
209
6 BI “BI_Config1~ BI_Config2” and “BI TRIGGER DR1~ 10” Both “BI_Config1~ BI_Config2” and “BI Trigger DR1~ BI Trigger DR10” are binary inputs which can be recorded. BI_Config1~ BI_Config2 can operate to binary output X10 and X11. The names of these BIs can be modified by CSPC tools according to actual situation.
7 Setting Table 170 Setting of external BIs to trip BOs
Setting Unit Min.
(Ir:5A/1A) Max.
(Ir:5A/1A)
Default setting
(Ir:5A/1A) Description
T_Pulse Tripping
s 0.2 5 5 delay time of STUB protection
Table 171 Binary settings of external DIs to trip DOs
Setting Title Setting options
Default setting
Comment
BI1 Enable BO1
1/0 0 To select whether the 1st binary input (BI1) trip the 1st binary output (BO1) or not. 1-enable, 0-disable
BO1 Pulse Tripping
1/0 0
To select BO1 tripping in pulse mode or in direct mode 0- BO1 Direct Tripping, without delay 1- BO1 Pulse Tripping, with preset delay time
BI2 Enable BO2
1/0 0 To select whether the 2nd binary input (BI2) trip the 2nd binary output (BO2) or not. 1-enable, 0-disable
BO2 Pulse Tripping
1/0 0
To select BO2 tripping in pulse mode or in direct mode 0- BO2 Direct Tripping, without delay 1- BO2 Pulse Tripping, with preset delay time
BI1 Init HV CBF
1/0 0 whether BI1 initiate HV side CBF or not
0 - initiate, 1 – not initiate
BI1 Init MV CBF
1/0 0 whether BI1 initiate MV side CBF or not
0 - initiate, 1 – not initiate
Chapter 18 External Bis to trip BOs
210
Setting Title Setting options
Default setting
Comment
BI1 Init LV CBF
1/0 0 whether BI1 initiate LV side CBF or not
0 - initiate, 1 – not initiate
BI2 Init HV CBF
1/0 0 whether BI2 initiate HV side CBF or not
0 - initiate, 1 – not initiate
BI2 Init MV CBF
1/0 0 whether BI2 initiate MV side CBF or not
0 - initiate, 1 – not initiate
BI2 Init LV CBF
1/0 0 whether BI2 initiate LV side CBF or not
0 - initiate, 1 – not initiate
Chapter 19 Station communication
211
Chapter 19 Station communication
About this chapter This chapter describes the communication possibilities in a SA-system.
Chapter 19 Station communication
212
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:
LON communication protocol
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.
1.1 Protocol
1.1.1 LON communication protocol
The LON protocol is specified in the LonTalkProtocol Specification Version 3 from Echelon Corporation. This protocol is designed for communication in control networks and is a peer-to-peer protocol where all the devices con-nected to the network can communicate with each other directly.
1.1.2 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 perfor-mance 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 in-formation 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 pub-lishing a GOOSE message, report its status. It can also request a control ac-tion to be directed at any device in the network.
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213
1.1.3 IEC60870-5-103 communication protocol
The IEC 60870-5-103 communication protocol is mainly used when a protec-tion IED communicates with a third party control or monitoring system. This system must have software that can interpret the IEC 60870-5-103 commu-nication messages.
The IEC 60870-5-103 is an unbalanced (master-slave) protocol for coded-bit 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 mes-sages. 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”.
1.2 Communication port
1.2.1 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.
1.2.2 RS485 communication ports
Up to 2 isolated electrical RS485 communication ports are provided to con-nect with substation automation system. These two ports can work in parallel for IEC60870-5-103.
1.2.3 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.
1.3 Technical data
Chapter 19 Station communication
214
Front communication port
Item Data Number 1
Connection Isolated, RS232; front panel
9-pin subminiature connector, for CSmart
Communication speed 9600 baud
Max. length of communication cable 15 m
RS485 communication port
Item Data
Number 0~2
Connection 2-wire connector
Rear port in communication module
Max. length of communication cable 1.0 km
IEC 60870-5-103 protocol
Communication speed Factory setting 9600 baud
Min. 1200 baud, Max. 19200 baud
Ethernet communication port
Item Data
Electrical communication port
Number 0 ~ 3
Connection RJ45 connector
Rear port in communication module
Max. length of communication cable 100m
IEC 61850 protocol
Communication speed 100 Mbit/s
IEC 60870-5-103 protocol
Communication speed 100 Mbit/s
Optical communication port ( optional )
Number 0 ~ 3
Connection SC connector
Rear port in communication module
Chapter 19 Station communication
215
Item Data Optical cable type Multi-mode
Max. length of communication cable 2.0km
IEC 61850 protocol
Communication speed 100 Mbit/s
IEC 60870-5-103 protocol
Communication speed 100 Mbit/s
Time synchronization
Item Data Mode Pulse mode
IRIG-B signal format IRIG-B000
Connection 2-wire connector
Rear port in communication module
Voltage levels differential input
Chapter 19 Station communication
216
2 Typicalcommunication scheme
2.1 Typical substation communication scheme
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 ANet 4: IEC103, RS485 Port B
Net 1: IEC61850/IEC103,Ethernet Port A
Gateway or
converter
SwitchSwitch Switch
Switch
Switch
Switch
Figure 74 Connection example for multi-networks of station automation system
2.2 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.
Chapter 19 Station communication
217
SNTP IRIG-B Pulse
Ethernet port IRIG-B port Binary input
Figure 75 Time synchronizing modes
Chapter 19 Station communication
218
Chapter 20 Hardware
219
Chapter 20 Hardware
About this chapter This chapter describes the IED hardware.
Chapter 20 Hardware
220
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 in-
terfaces.
1.2 IED appearance
Figure 76 Protection IED front view
Chapter 20 Hardware
221
1.3 IED module arrangement
X1 X2 X3 X4 X5 X6 X7 X8 X9 X10 X11 X12 X13 AIM AIM AIM AIM COM BIM BOM1 BOM2 BOM3 BOM4 PSM
Analogue Input m
odule
Analogue Input m
odule
Analogue Input m
odule
Spare slot
Com
munication m
od-ule
Binary input m
odule
Spare slot
Binary output m
odule 1
Binary output m
odule 2
Binary output m
odule 3
Binary output m
odule 4
Spare slot
Pow
er supply module
Figure 77 Module arrangement (front view, when open the front panel)
1.4 The rear view of the protection IED
Test port
X5 COM
X6X8X9X12 X1AIM
X13PSM
X2AIM
X7 X3AIM
X11 X10
For BIM and BOM Ethernet ports
Figure 78 Rear view of the protection IED
Chapter 20 Hardware
222
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, de-bugging 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 are shown as below figures.
Chapter 20 Hardware
223
2
1
3
45
68 7
CSC-326
Figure 79 Front panel layout for 8 LEDs
2
1
3
45
68 7
CSC-326
Figure 80 Front panel layout for 20 LEDs
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
Chapter 20 Hardware
224
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 operate the IED are described below.
Table 172 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.
Chapter 20 Hardware
225
Table 173 function of Shortcut keys and functional keys
Key function F1 Reserved
F2 Reserved 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 , mean-
ing the number of setting group subtracted one.
2.5 LED
The definitions of the LEDs are fixed and descrbed below.
Table 174 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 175 Definition of 20 LEDs
No LED Color Description
1 Run Green Steady lighting: Operation normally
Flashing: IED startup
Chapter 20 Hardware
226
No LED Color Description
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 protections are out of service. And power supply for tripping outputs is blocked as well.
The other LEDs which are not described above can be configured.
2.6 Front communication port
There is a serial RS232 port on the front plate of all the IEDs. Through this port, the IED can be connected to the personal computer for setting, testing, and configuration using the dedicated Sifang software tool.
Chapter 20 Hardware
227
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 81 Terminals arrangement of AIM E
Chapter 20 Hardware
228
Table 176 Description of terminals of AIM E
Terminal Analogue
Input Remark
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 Star point
a07 Null
b07 Null Star point
a08 Null
b08 Null Star point
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
Chapter 20 Hardware
229
3.3 Technical data
3.3.1 Internal current transformer
Item Standard Data Rated current IRr IEC 60255-1 1 or 5 A
Nominal current range 0.05 IRr Rto 30 IRr
Nominal current range of sensitive
CT
0.005 to 1 A
Power consumption (per phase) ≤ 0.1 VA at IRrR = 1 A;
≤ 0.5 VA at IRrR = 5 A
≤ 0.5 VA for sensitive CT
Thermal overload capability IEC 60255-1 IEC 60255-27
100 IRrR for 1 s
4 IRrR 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 212BInternal voltage transformer
Item Standard Data Rated voltage VRrR (ph-ph) IEC 60255-1 100 V /110 V
Nominal range (ph-e) 0.4 V to 120 V
Power consumption at VRr R= 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 VRrR, for 10s
1.5 VRrR, continuous
Chapter 20 Hardware
230
4 Communication module
4.1 Introduction
The communication module performs communication between the internal protection system and external equipments such as HMI, engineering work-station, 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 communica-tion module to meet the communication demands of different substation au-tomation 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.
4.2 Substaion communication port
4.2.1 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.
4.2.2 RS485 communication ports
Up to 2 isolated electrical RS485 communication ports are provided to con-nect with substation automation system. These two ports can work in parallel for IEC60870-5-103.
4.2.3 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
Chapter 20 Hardware
231
work in parallel for protocol, IEC61850 or IEC60870-5-103.
4.2.4 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.
4.3 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 82 Terminals arrangement of COM
Table 177 Definition of terminals of COM
Terminal Definition
01 Null
02 Null
03 Null
04 Null
Chapter 20 Hardware
232
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 sys-
tem
Ethernet
Port B
Optional optical fiber or RJ45
port for station automation sys-
tem
Ethernet
Port C
Optional optical fiber or RJ45
port for station automation sys-
tem
4.4 Operating reports
Information Description DI Comm Fail DI communication error
DO Comm Fail DO communication error
4.5 Technical data
4.5.1 Front communication port
Item Data Number 1
Connection Isolated, RS232; front panel,
9-pin subminiature connector, for software tools
Chapter 20 Hardware
233
Communication speed 9600 baud
Max. length of communication cable 15 m
4.5.2 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
4.5.3 Ethernet communication port
Item Data
Electrical communication port
Number 0 to 3
Connection RJ45 connector
Rear port in communication module
Max. length of communication cable 100m
For IEC 61850 protocol
Communication speed 100 Mbit/s
For IEC 60870-5-103 protocol
Communication speed 100 Mbit/s
Optical communication port ( optional )
Number 0 to 2
Connection SC connector
Rear port in communication module
Optical cable type Multi-mode
Max. length of communication cable 2.0km
IEC 61850 protocol
Communication speed 100 Mbit/s
IEC 60870-5-103 protocol
Communication speed 100 Mbit/s
Chapter 20 Hardware
234
4.5.4 Time synchronization
Item Data Mode Pulse mode
IRIG-B signal format IRIG-B000
Connection 2-wire connector
Rear port in communication module
Voltage levels differential input
Chapter 20 Hardware
235
5 Binary input module
5.1 Introduction
The binary input module is used to connect the input signals and alarm sig-nals 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.
5.2 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 83: Terminals arrangement of BIM A
Chapter 20 Hardware
236
Table 178 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
Chapter 20 Hardware
237
5.3 Technical data
Item Standard Data
Input voltage range IEC60255-1 110/125 V DC
220/250 V DC
Threshold1: guarantee oper-
ation
IEC60255-1 154V, for 220/250V DC
77V, for 110V/125V DC
Threshold2: uncertain opera-
tion
IEC60255-1 132V, for 220/250V DC;
66V, for 110V/125V DC
Response time/reset time IEC60255-1 Software provides de-bounce
time
Power consumption, ener-
gized
IEC60255-1 Max. 0.2 W/input, 24V DC
Max. 0.5 W/input, 110V DC
Max. 1 W/input, 220V DC
Chapter 20 Hardware
238
6 Binary output module
6.1 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.
6.2 Terminals of Binary Output Module (BOM)
6.2.1 Binary Output Module A
The module provides 16 output relays for tripping or initiating, with total 16 contacts.
Chapter 20 Hardware
239
a02
R1
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
R3
R5
R7
R9
R11
R13
R15
R16
R2
R4
R6
R8
R10
R12
R14
Figure 84 Terminals arrangement of BOM A
Chapter 20 Hardware
240
Table 179 Definition of terminals of BOM A
Terminal Definition Related relay
a02 Trip contact 1-0 Output relay 1
c02 Trip contact 1-1 Output relay 1
a04 Trip contact 2-0 Output relay 2
c04 Trip contact 2-1 Output relay 2
a06 Trip contact 3-0 Output relay 3
c06 Trip contact 3-1 Output relay 3
a08 Trip contact 4-0 Output relay 4
c08 Trip contact 4-1 Output relay 4
a10 Trip contact 5-0 Output relay 5
c10 Trip contact 5-1 Output relay 5
a12 Trip contact 6-0 Output relay 6
c12 Trip contact 6-1 Output relay 6
a14 Trip contact 7-0 Output relay 7
c14 Trip contact 7-1 Output relay 7
a16 Trip contact 8-0 Output relay 8
c16 Trip contact 8-1 Output relay 8
a18 Trip contact 9-0 Output relay 9
c18 Trip contact 9-1 Output relay 9
a20 Trip contact 10-0 Output relay 10
c20 Trip contact 10-1 Output relay 10
a22 Trip contact 11-0 Output relay 11
c22 Trip contact 11-1 Output relay 11
a24 Trip contact 12-0 Output relay 12
c24 Trip contact 12-1 Output relay 12
a26 Trip contact 13-0 Output relay 13
c26 Trip contact 13-1 Output relay 13
a28 Trip contact 14-0 Output relay 14
c28 Trip contact 14-1 Output relay 14
a30 Trip contact 15-0 Output relay 15
c30 Trip contact 15-1 Output relay 15
a32 Trip contact 16-0 Output relay 16
c32 Trip contact 16-1 Output relay 16
Chapter 20 Hardware
241
6.2.2 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
R6
R7
R1
R2
R3
R5
R4
R16
R9
R10
R11
R12
R13
R14
R15
R8
Figure 85 Terminals arrangement of BOM C
Chapter 20 Hardware
242
Table 180 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
a04 Signal contact 1-1 Output relay 1
c04 Signal contact 2-1 Output relay 1
a06 Signal contact 1-2 Output relay 2
c06 Signal contact 2-2 Output relay 2
a08 Signal contact 1-3 Output relay 3
c08 Signal contact 2-3 Output relay 3
a10 Signal 3-0, Common terminal of signal contact group 3
c10 Signal 4-0, Common terminal of signal contact group 4
a12 Signal contact 3-1 Output relay 4
c12 Signal contact 4-1 Output relay 6
a14 Signal contact 3-2 Output relay 5
c14 Signal contact 4-2 Output relay 7
a16 Signal contact 5-0 Output relay 8
c16 Signal contact 5-1 Output relay 8
a18 Signal contact 6-0 Output relay 9
c18 Signal contact 6-1 Output relay 9
a20 Signal contact 7-0 Output relay 10
c20 Signal contact 7-1 Output relay 10
a22 Signal contact 8-0 Output relay 11
c22 Signal contact 8-1 Output relay 11
a24 Signal contact 9-0 Output relay 12
c24 Signal contact 9-1 Output relay 12
a26 Signal contact 10-0 Output relay 13
c26 Signal contact 10-1 Output relay 13
a28 Signal contact 11-0 Output relay 14
c28 Signal contact 11-1 Output relay 14
a30 Signal contact 12-0 Output relay 15
c30 Signal contact 12-1 Output relay 15
a32 Signal contact 13-0 Output relay 16
c32 Signal contact 13-1 Output relay 16
Chapter 20 Hardware
243
6.3 Technical data
Item Standard Data
Max. system voltage IEC60255-1 250V DC/AC
Current carrying capacity IEC60255-1 5 A continuous,
42A,1s ON, 9s OFF
Making capacity IEC60255-1 1100 W(DC) at inductive load
with L/R>40 ms
1000 VA(AC)
Breaking capacity IEC60255-1 ≥1000 cycles ,
DC220V, 0.15A, t=L/R≤40 ms
DC110V, 0.30A, t=L/R≤40 ms
Unloaded mechanical endur-
ance
IEC60255-1 50,000,000 cycles (3 Hz
switching frequency)
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℃
Chapter 20 Hardware
244
7 Power supply module
7.1 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 bi-nary inputs of the CPU module
(2) ±12V: Power for A/D
(3) + 5V: Power for all micro-chips
7.2 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
Figure 86 Terminals arrangement of PSM
Chapter 20 Hardware
245
Table 181 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
a10 AUX.DC 24V- output 3
c10 AUX.DC 24V- output 4
a12 AUX.DC 24V- output 5
c12 AUX.DC 24V- output 6
a14 Alarm contact A1, for AUX.DC power input failure
c14 Alarm contact A0, for AUX.DC power input failure
a16 Alarm contact B1, for AUX.DC power input failure
c16 Alarm contact B0, for AUX.DC power input failure
a18 Isolated terminal, not wired
c18 Isolated terminal, not wired
a20 AUX. power input 1, DC +
c20 AUX. power input 2, DC +
a22 AUX. power input 3, DC +
c22 AUX. power input 4, DC +
a24 Isolated terminal, not wired
c24 Isolated terminal, not wired
a26 AUX. power input 1, DC -
c26 AUX. power input 2, DC -
a28 AUX. power input 3, DC -
c28 AUX. power input 4, DC -
a30 Isolated terminal, not wired
c30 Isolated terminal, not wired
a32 Terminal for earthing
c32 Terminal for earthing
Chapter 20 Hardware
246
7.3 Technical data
Item Data
Rated auxiliary voltage VRaux 110~250V DC
Permissible tolerance ±%20 URaux
Power consumption
Normal operation ≤ 30 W
Tripping condition ≤ 50 W
Chapter 20 Hardware
247
8 Terminal diagram
8.1 Typical Terminal diagram of CSC-326 2 8
U3B
11
109
U3C
5 76431
ba
X3(AI Module)
X5(Master Module)
10/100M BASE-T
100M BASE-FX B RX
TXBA TX
BARXA
485-1A
485-1B
485-2B
GPSGND
LON-2B
LON-2A
LONGND
LON-1B
LON-1A
NOT USED
232-TRAN
232-RECV
232-GND
GPS
NOT USED
16
15
14
13
12
11
10987654321
485-2A
Reset
DC- Input
6
HV VT MCB Fail
8
Relay Test
Blk Rem Access
X6(BI Module)
42
ca
Switch SetGroup
DC- Input
Not Used
BI_Config1
Not Used
10
12
14
16
18
20
22
24
26
28
30
32
UL0
UL0'
U3A
12
U3N
MV VT MCB Fail
LV VT MCB Fail
BI_Config2
BI_Trigger_DR1
BI_Trigger_DR2
BI_Trigger_DR3
BI_Trigger_DR4
BI_Trigger_DR5
BI_Trigger_DR6
BI_Trigger_DR7
BI_Trigger_DR8
BI_Trigger_DR9
Not Used
HV STUB Enable
6 8
X11(BO Module)
42
ca
10
12
14
16
18
20
22
24
26
28
30
32
6 8
X8(BO Module)
42
ca
10
12
14
16
18
20
22
24
26
28
30
32
Diff Trip
SIG-
1COM
(+)
SIG-
2COM
(+)
SIG-
3COM
(+)
SIG-
4COM
(+)
Run
Alar
m-1
Per
Diff
A T
rip
Rela
y Fa
ult-
1
BO_C
onfi
g2
BO_C
onfi
g1
HV O
L Al
arm
MV O
L Al
arm
Run
Alar
m-2
Rela
y Fa
ult-
2
6 8X13(Power)
42
ca
10
12
14
16
18
20
22
24
26
28
30
32
R24V+ Out
DC
Fail
ure
R24V- Out
DC
Fail
ure
DC+ Input
DC- Input
2 8
U2B
11
109
U2C
5 76431
ba
X2(AI Module)
U2A
12
U2N
IH1B
IH1B'
2
INBK
H'IN
BKH
8
U1B
11
109
U1C
IH1C
5 76
IH1C'
43
IH1A
IH1A'
1
ba
IREF
H'IR
EFH
X1(AI Module)
U1A
12
U1N
HV REF Trip
Not Used
Def V/F Trip
Inv V/F Trip
HV OC1 Trip
HV OC2 Trip
HV OC Inv Trip
HV STUB Trip
HV Therm OL Trip
6 8
X9(BO Module)
42
ca
10
12
14
16
18
20
22
24
26
28
30
32
HV OV1 Trip
HV OV2 Trip
HV DIS(Ph-N) Trip
MV DIS(Ph-N) Trip
MV OC1 Trip
MV OC2 Trip
MV OC Inv Trip
LV OC Inv Trip
HV DIS (Ph-Ph) Trip
MV DIS (Ph-Ph) Trip
MV Therm OL Trip
IH2B
IH2B'
IH2C
IH2C'
IH2A
IH2A'
IM1B
IM1B'
IM1C
IM1C'
IM1A
IM1A'
ILB
ILB'
ILC
ILC'
ILA
ILA'
ILWB
ILWB'
ILWC
ILWC'
ILWA
ILWA'
BI_Trigger_DR10 Not Used
Not Used
Not Used 6 8
X10(BO Module)
42
ca
10
12
14
16
18
20
22
24
26
28
30
32
SIG-
1COM
(+)
SIG-
2COM
(+)
Diff Alarm-1
CT F
ail
SIG-
3COM
(+)
SIG-
4COM
(+)
HV REF Alarm-1
Diff
Tri
p-1
HV
Ther
mal
OL A
larm
Not
Used
Not
Used
MV V
T Fa
ilHV
VT
Fail
LV V
T Fa
ilLV
OL
Alar
mLW
OL
Alar
m
MV
Ther
mal
OL A
larm
Over
Exc
it D
EF A
larm
Diff
Tri
p-2
HV REF Trip-2
Not
Used
Per
Diff
B T
rip
Not Used
Not Used
Not Used
Not Used
Inst
Dif
f B
Trip
Inst
Dif
f C
Trip
Per
Diff
C T
rip
HV O
V1 A
lm
HV O
V2 A
lm
Rela
y St
artu
p
Inst
Dif
f A
Trip
Diff Alarm-2
HV REF Alarm-2
Not
Used
HV EF1 Trip
HV EF2 Trip
HV EF Inv Trip
HV NOC1 Trip
HV NOC2 Trip
HV NOC Inv Trip
MV EF1 Trip
MV EF2 Trip
MV EF Inv Trip
LV OC1 Trip
LV OC2 Trip
IM2B
IM2B'
IM2C
IM2C'
IM2A
IM2A'
HV REF Trip-1
Chapter 20 Hardware
248
9 Techinical data
9.1 Basic data
9.1.1 Frequency
Item Data
System rated frequency 50 Hz or 60Hz
9.1.2 224BInternal current transformer
Item Data
Rated current IRr 1 or 5 A
Nominal current range (0.05 – 20)x IRr
Power consumption (per phase) ≤ 0.1 VA at IRrR = 1 A;
≤ 0.5 VA at IRrR = 5 A
Thermal overload capability 100 x IRrR for 1 s
4 x IRrR continuous
9.1.3 225BInternal voltage transformer
Item Data
Rated voltage VRrR (ph-ph) 100-120
Nominal range (ph-e) 0.4 V to 120 V
Power consumption at VRr R= 110 V ≤ 0.1 VA per phase
Thermal overload capability (phase-neutral
voltage)
2VRrR, for 10s
1.5VRrR, continuous
9.1.4 226BAuxiliary voltage
Item Standard Data
Rated auxiliary voltage VRaux IEC60255-1 110 to 250V DC
Permissible tolerance IEC60255-1 ±%20 URaux
Chapter 20 Hardware
249
Item Standard Data
Power consumption at quies-
cent state
IEC60255-1 ≤ 50 W
Power consumption at maxi-
mum load
IEC60255-1 ≤ 60 W
Inrush Current IEC60255-1 T ≤ 10 ms/I≤ 25 A
9.1.5 Binary inputs
Item Standard Data
Input voltage range IEC60255-1 110/125 V DC
220/250 V DC
Threshold1: guarantee oper-
ation
IEC60255-1 154V, for 220/250V DC
77V, for 110V/125V DC
Threshold2: uncertain opera-
tion
IEC60255-1 132V, for 220/250V DC;
66V, for 110V/125V DC
Response time/reset time IEC60255-1 Software provides de-bounce
time
Power consumption, ener-
gized
IEC60255-1 Max. 0.2 W/input, 24V DC
Max. 0.5 W/input, 110V DC
Max. 1 W/input, 220V DC
9.1.6 228BBinary outputs
Item Standard Data
Max. system voltage IEC60255-1 250V DC/AC
Current carrying capacity IEC60255-1 5 A continuous,
42A,1s ON, 9s OFF
Making capacity IEC60255-1 1100 W(DC) at inductive load
with L/R>40 ms
1000 VA(AC)
Breaking capacity IEC60255-1 ≥1000 cycles ,
DC220V, 0.15A, t=L/R≤40 ms
DC110V, 0.30A, t=L/R≤40 ms
Unloaded mechanical endur-
ance
IEC60255-1 50,000,000 cycles (3 Hz
switching frequency)
Chapter 20 Hardware
250
Item Standard Data
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
ANSI C37.90
GB/T 15145-2001
DL/T 478-2001
2KV, 50Hz
2.8kV DC
between the following circuits:
auxiliary power supply
CT / VT inputs
binary inputs
binary outputs
case earth
500V, 50Hz
between the following circuits:
Communication ports to
case earth
time synchronization ter-
minals to case earth
Chapter 20 Hardware
251
Item Standard Data
Impulse voltage test IEC60255-5
IEC 60255-27
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:
auxiliary power supply
CT / VT inputs
binary inputs
binary outputs
case earth
Note: Ui: Rated voltage
Insulation resistance IEC60255-5
IEC 60255-27
ANSI C37.90
GB/T 15145-2001
DL/T 478-2001
≥ 100 MΩ at 500 VDC
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
ANSI/IEEE C37.90.1
class III
2.5 kV CM ; 1 kV DM
Tested on the following circuits:
auxiliary power supply
CT / VT inputs
binary inputs
binary outputs
1 kV CM ; 0 kV DM
Tested on the following circuits:
communication ports
Electrostatic discharge IEC 60255-22-2
IEC 61000-4-2
Level 4
8 kV contact discharge;
15 kV air gap discharge;
both polarities; 150 pF; RRiR = 330
Ω
Chapter 20 Hardware
252
Item Standard Data
Radiated electromagnetic field
disturbance test
IEC 60255-22-3 frequency sweep:
80 MHz – 1 GHz; 1.4 GHz – 2.7 G
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 pulse-modulated
10 V/m, 900 MHz; repetition rate
200 Hz, on duration 50 %
Electric fast transient/burst im-
munity test
IEC 60255-22-4,
IEC 61000-4-4
ANSI/IEEE C37.90.1
class A, 4KV
Tested on the following circuits:
auxiliary power supply
CT / VT inputs
binary inputs
binary outputs
class A, 2KV
Tested on the following circuits:
communication ports
Surge immunity test IEC 60255-22-5
IEC 61000-4-5
4.0kV L-E
2.0kV L-L
Tested on the following circuits:
auxiliary power supply
CT / VT inputs
binary inputs
binary outputs
2.0kV L-E
Tested on the following circuits:
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
Power frequency immunity test IEC60255-22-7 Class A
300 V CM
150 V DM
Chapter 20 Hardware
253
Item Standard Data
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
Tested on the following circuits:
auxiliary power supply
CT / VT inputs
binary inputs
binary outputs
1 kV CM ; 0 kV DM
Tested on the following circuits:
communication ports
9.2.3 231BDC voltage interruption test
Item Standard Data DC voltage dips IEC 60255-11 100% reduction 80 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 232BElectromagnetic emission test
Item Standard Data
Radiated emission IEC60255-25
CISPR22
30MHz to 1GHz ( IT device may
up to 5 GHz)
Conducted emission IEC60255-25
CISPR22
0.15MHz to 30MHz
Chapter 20 Hardware
254
9.2.5 Mechanical tests
Item Standard Data
Sinusoidal Vibration response
test
IEC60255-21-1 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 endur-
ance test
IEC60255-21-1 class 1
10 Hz to 150 Hz: 1 g
20 sweep cycle in each axis
Relay non-energized
Shock response test IEC60255-21-2 class 1
5 g, 11 ms duration
3 shocks in both directions of 3
axes
Relay energized
Shock withstand test IEC60255-21-2 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
Chapter 20 Hardware
255
9.2.6 Climatic tests
Item Standard Data 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 ≤ 8kg
Chapter 21 Appendix
256
Chapter 21 Appendix
Chapter 21 Appendix
257
1 General setting list
1.1 Function setting list
Setting Unit Min.
(Ir:5A/1A) Max.
(Ir:5A/1A)
Default setting
(Ir:5A/1A) Description
HV Wind Conn/Y
0 1 0 Connection for HV winding, 0:wye connection, 1:delta connection
MV Wind Conn/Y
0 1 0 Connection for MV winding, 0:wye connection, 1:delta connection
LV Wind Conn/Y
0 1 1 Connection for LV winding, 0:wye connection, 1:delta connection
Vet Grp Angle MVA 1.000 3000. 120.0 Vector Group Angle( VET
GRP ANGLE) SN kV 1.000 1000. 220.0 Capacity of the trans-
former HV VT Ratio MVA 1.000 9999. 2200.0 Voltage transformer(VT)
Ratio in HV side
HV CT Pri A 50.00 9999. 1200.0 CT Primary(PRI) current
in HV side
HV CT Sec A 1.000 5.000 1.0 CT Secondary(SEC) cur-
rent in HV side
HV Voltage Chan Sel
1 3 1 HV voltage channel loca-
tion
MV Voltage Chan Sel
1 3 2 MV voltage channel loca-
tion
HV NCT Pri(REF)
A 50.00 9999. 1200.0 Neutral CT (NCT) Prima-
ry(PRI) current in HV side
for REF
Chapter 21 Appendix
258
Setting Unit Min.
(Ir:5A/1A) Max.
(Ir:5A/1A)
Default setting
(Ir:5A/1A) Description
HV NCT Sec(REF)
A 1.000 5.000 1.0 Neutral CT (NCT) Sec-
ondary(SEC) current in
HV side for REF
HV NCT Pri(BU)
A 50.00 9999. 1200.0 Neutral CT (NCT) Prima-
ry(PRI) current in HV side
for backup protection
HV NCT Sec(BU)
A 1.000 5.000 1.0 Neutral CT (NCT) Sec-
ondary(PRI) current in HV
side for backup protection
MV UN kV 1.000 1000. 110.0 Nominal voltage (UN) in
Middle voltage (MV)side
MV VT Ratio 1.000 9999. 1100.0 Voltage transformer(VT)
Ratio in MV side
MV CT Pri A 50.00 9999. 1200.0 CT Primary(PRI) current
in MV side
MV CT Sec A 1.000 5.000 1.0 CT Secondary(SEC) cur-
rent in MV side
MV NCT Pri(REF)
A 50.00 9999. 1200.0 Neutral CT (NCT) Prima-
ry(PRI) current in MV side
for REF
MV NCT Sec(REF)
A 1.000 5.000 1.0 Neutral CT (NCT) Sec-
ondary(SEC) current in
MV side for REF
MV NCT Pri(BU)
A 50.00 9999. 1200.0 Neutral CT (NCT) Prima-
ry(PRI) current in MV side
for backup protection
MV NCT Sec(BU)
A 1.000 5.000 1.0 Neutral CT (NCT) Sec-
ondary(PRI) current in MV
side for backup protection
LV UN kV 1.000 1000. 10.50 Nominal voltage (UN) in
Low voltage (LV)side
LV VT Ratio 1.000 9999. 105.0 Voltage transformer(VT)
Ratio in LV side
LV CT Pri A 50.00 9999. 3000.0 CT Primary(PRI) current
in LV side
LV CT Sec A 1.000 5.000 1.0 CT Secondary(SEC) cur-
rent in LV side
Chapter 21 Appendix
259
Setting Unit Min.
(Ir:5A/1A) Max.
(Ir:5A/1A)
Default setting
(Ir:5A/1A) Description
LV Sec Inside Delta
A 1.000 5.000 1.0 CT Secondary(SEC)
current in LV inside delta
HV Rated Cur Pri
A 0 9999 Rated primary current for
HV side (calculated val-
ue, read only)
HV Rated Cur Sec
A 0 9999 Rated secondary current
for HV side (calculated value, read only)
Ratio Factor KTAH
0 9999 HV ratio factor for differ-
ential protection (calcu-lated value, read only)
Ratio Factor KTAM
0 9999 MV ratio factor for differ-
ential protection (calcu-lated value, read only)
Ratio Factor KTAL
0 9999 LV ratio factor for differ-
ential protection (calcu-lated value, read only)
Ratio REF KTAH
0 9999 HV ratio factor, with ze-
ro-sequence current
calculated, for REF pro-
tection (calculated val-ue, read only)
Ratio REF KNH
0 9999 HV ratio factor with ze-
ro-sequence current di-
rectly measured, for REF
protection (calculated value, read only)
Ratio REF KTAM
0 9999 MV ratio factor, with ze-
ro-sequence current
calculated, for REF pro-
tection (calculated val-ue, read only)
Ratio REF KNM
0 9999 MV ratio factor with ze-
ro-sequence current di-
rectly measured, for REF
protection (calculated value, read only)
Chapter 21 Appendix
260
Setting Unit Min.
(Ir:5A/1A) Max.
(Ir:5A/1A)
Default setting
(Ir:5A/1A) Description
I_Inst Diff A 0.5Ir 20Ir 20 Instantaneous Differential
(ID>>) current setting
I_Percent Diff A 0.08Ir 4Ir 2.1 Percentage Differential
(ID>) current setting
I_ResPoint1 Diff A 0.1Ir Ir 2 The 1st breakpoint re-
straint current (IR1)
I_ResPoint2 Diff A 0.1Ir 10Ir 2 The 2nd breakpoint re-
straint current (IR2)
Slope1_Diff 0 0.2 0.2 the 1st slope
Slope2_Diff 0.2 0.7 0.5 the 2nd slope
Slope3_Diff 0.25 0.95 0.7 the 3rd slope
Ratio_2nd Harm 0.05 0.80 0.15 2nd harmonic(HAR) ratio
Ratio_3/5th Harm 0.05 0.80 0.35 3rd / 5th harmonic(HAR)
ratio
T_2nd Harm Block
s 0 20 20 Within the delay 2nd
harmonic block all three
phases. After the delay,
then only the local phase
is blocked.
T_3/5th Harm Block
s 0 20 20 Within the delay 5th
harmonic block all three
phases. After the delay,
then only the local phase
is blocked.
HV 3I0_REF
A 0.08Ir 2Ir 2 Current setting for HV
Restricted Earth Fault
protection
HV Slope_REF
0.2 0.95 0.5 Slope setting for HV Re-
stricted Earth Fault pro-
tection
HV T_REF Trip s 0 60 0.03 HV Restricted Earth Fault
trip time setting
HV 3I0_REF Alarm A 0.08Ir 2Ir 2 HV Restricted Earth Fault
alarm current setting
HV T_REF Alarm s 0 60 0.03 HV Restricted Earth Fault
alarm time setting
Chapter 21 Appendix
261
Setting Unit Min.
(Ir:5A/1A) Max.
(Ir:5A/1A)
Default setting
(Ir:5A/1A) Description
MV 3I0_REF
A 0.08Ir 2Ir 2 Current setting for MV
Restricted Earth Fault
protection
MV Slope_REF
0.2 0.95 0.5 Slope setting for MV Re-
stricted Earth Fault pro-
tection
MV T_REF Trip s 0 60 0.03 MV Restricted Earth
Fault trip time setting
MV 3I0_REF Alarm
A 0.08Ir 2Ir 2 MV Restricted Earth
Fault alarm current set-
ting
MV T_REF Alarm s 0 60 0.03 MV Restricted Earth
Fault alarm time setting
LV 3I0_REF
A 0.08Ir 2Ir 2 Current setting for LV
Restricted Earth Fault
protection
LV Slope_REF
0.2 0.95 0.5 Slope setting for LV Re-
stricted Earth Fault pro-
tection
LV T_REF Trip s 0 60 0.03 LV Restricted Earth Fault
trip time setting
LV 3I0_REF Alarm A 0.08Ir 2Ir 2 LV Restricted Earth Fault
alarm current setting
LV T_REF Alarm s 0 60 0.03 LV Restricted Earth Fault
alarm time setting
Reference Voltage V 40 130 57.3 Nominal phase voltage in
HV side
V/F_Definite Alarm 1 1.5 1.1 Alarming setting of
volt/hertz
T_Definite Alarm s 0.1 9999 10 Timer setting for
volt/hertz alarming stage
V/F_Definite Trip 1 1.5 1.2 Tripping setting of defi-
nite volt/hertz stage
T_Definite Trip s 0.1 9999 1 Timer setting for definite
volt/hertz stage
T1_Inverse V/F=1.05
s 0.1 9999 10 Timer setting for
volt/hertz=1.05
Chapter 21 Appendix
262
Setting Unit Min.
(Ir:5A/1A) Max.
(Ir:5A/1A)
Default setting
(Ir:5A/1A) Description
T2_Inverse V/F=1.10
s 0.1 9999 90 Timer setting for
volt/hertz=1.10
T3_Inverse V/F=1.15
s 0.1 9999 80 Timer setting for
volt/hertz=1.15
T4_Inverse V/F=1.20
s 0.1 9999 70 Timer setting for
volt/hertz=1.20
T5_Inverse V/F=1.25
s 0.1 9999 60 Timer setting for
volt/hertz=1.25
T6_Inverse V/F=1.30
s 0.1 9999 50 Timer setting for
volt/hertz=1.30
T7_Inverse V/F=1.35
s 0.1 9999 45 Timer setting for
volt/hertz=1.35
T8_Inverse V/F=1.40
s 0.1 9999 40 Timer setting for
volt/hertz=1.40
T9_Inverse V/F=1.45
s 0.1 9999 35 Timer setting for
volt/hertz=1.45
T10_Inverse V/F=1.50
s 0.1 9999 30 Timer setting for
volt/hertz=1.50
T_Cool Down s 0.1 9999 25 Cool down time delay for
overexcitation protection
HV I_OC1
A 0.05Ir 20Ir 5 HV overcurrent (O/C)
current setting for Stage
1
HV T_OC1 s 0 60 60 Time setting for HV OC,
Stage 1
HV I_OC2
A 0.05Ir 20Ir 5 HV overcurrent (O/C)
current setting for Stage
2
HV T_OC2 s 0 60 60 Time setting for HV OC,
Stage 2
HV Curve_OC Inv
1 12 1 Ref to appendix 3 page
307
HV I_OC Inv A 0.05Ir 20Ir 5 Ref to appendix 3 page
307
HV K_OC Inv 0.05 999 1 Ref to appendix 3 page
307
Chapter 21 Appendix
263
Setting Unit Min.
(Ir:5A/1A) Max.
(Ir:5A/1A)
Default setting
(Ir:5A/1A) Description
HV A_OC Inv s 0 200 0.14 Ref to appendix 3 page
307
HV B_OC Inv s 0 60 0 Ref to appendix 3 page
307
HV P_OC Inv 0 10 0.02 Ref to appendix 3 page
307
HV Angle_OC ° 0 90 45 The angle setting for
voltage ahead of current.
HV Imax_2H_UnBlk
A 0.25Ir 20Ir 5 The maximum 1st
-harmonic current setting
to remove the inrush
block, in HV O/C protec-
tion
HV Ratio_I2/I1
0.07 0.5 0.2 Inrush 2nd harmonic ratio
setting for blocking HV
O/C protection
HV T2h_Cross_Blk
s 0 60 20 Inrush 2nd harmonic
cross-block time for HV
O/C protection
MV I_OC1
A 0.05Ir 20Ir 5 MV overcurrent (O/C)
current setting for Stage
1
MV T_OC1 s 0 60 60 Time setting for MV OC,
Stage 1
MV I_OC2
A 0.05Ir 20Ir 5 MV overcurrent (O/C)
current setting for Stage
2
MV T_OC2 s 0 60 60 Time setting for MV OC,
Stage 2
MV Curve_OC Inv
1 12 1 Ref to appendix 3 page
307
MV I_OC Inv A 0.05Ir 20Ir 5 Ref to appendix 3 page
307
MV K_OC Inv 0.05 999 1 Ref to appendix 3 page
307
MV A_OC Inv s 0 200 0.14 Ref to appendix 3 page
307
Chapter 21 Appendix
264
Setting Unit Min.
(Ir:5A/1A) Max.
(Ir:5A/1A)
Default setting
(Ir:5A/1A) Description
MV B_OC Inv s 0 60 0 Ref to appendix 3 page
307
MV P_OC Inv 0 10 0.02 Ref to appendix 3 page
307
MV Angle_OC ° 0 90 45 The angle setting for
voltage ahead of current.
MV Imax_2H_UnBlk
A 0.25Ir 20Ir 5 The maximum 1st
-harmonic current setting
to remove the inrush
block, in MV O/C protec-
tion
MV Ratio_I2/I1
0.07 0.5 0.2 Inrush 2nd harmonic ratio
setting for blocking MV
O/C protection
MV T2h_Cross_Blk
s 0 60 20 Inrush 2nd harmonic
cross-block time for MV
O/C protection
LV I_OC1
A 0.05Ir 20Ir 5 LV overcurrent (O/C)
current setting for Stage
1
LV T_OC1 s 0 60 60 Time setting for LV OC,
Stage 1
LV I_OC2
A 0.05Ir 20Ir 5 LV overcurrent (O/C)
current setting for Stage
2
LV T_OC2 s 0 60 60 Time setting for LV OC,
Stage 2
MV Curve_OC Inv
1 12 1 Ref to appendix 3 page
307
LV I_OC Inv A 0.05Ir 20Ir 5 Ref to appendix 3 page
307
LV K_OC Inv 0.05 999 1 Ref to appendix 3 page
307
LV A_OC Inv s 0 200 0.14 Ref to appendix 3 page
307
LV B_OC Inv s 0 60 0 Ref to appendix 3 page
307
Chapter 21 Appendix
265
Setting Unit Min.
(Ir:5A/1A) Max.
(Ir:5A/1A)
Default setting
(Ir:5A/1A) Description
LV P_OC Inv 0 10 0.02 Ref to appendix 3 page
307
LV Angle_OC 0 90 45 The angle setting for
voltage ahead of current.
LV Imax_2H_UnBlk
0.25Ir 20Ir 5 The maximum 1st
-harmonic current setting
to remove the inrush
block, in LV O/C protec-
tion
LV Ratio_I2/I1
0.07 0.5 0.2 Inrush 2nd harmonic ratio
setting for blocking LV
O/C protection
LV T2h_Cross_Blk
0 60 20 Inrush 2nd harmonic
cross-block time for LV
O/C protection
HV 3I0_EF1
A 0.05Ir 20Ir 5 HV earth fault (E/F) pro-
tection current setting for
Stage 1
HV T_EF1 s 0 60 60 Time setting for HV E/F,
Stage 1
HV 3I0_EF2 A 0.05Ir 20Ir 5 HV earth fault (E/F) cur-
rent setting for Stage 2
HV T_EF2 s 0 60 60 Time setting for HV E/F,
Stage 2
HV Curve_EF Inv 1 12 1 Ref to appendix 3 page
307
HV 3I0_EF Inv A 0.05Ir 20Ir 1.2 Ref to appendix 3 page
307
HV K_EF Inv 0.05 999 1 Ref to appendix 3 page
307
HV A_EF Inv s 0 200 0.14 Ref to appendix 3 page
307
HV B_EF Inv s 0 60 0 Ref to appendix 3 page
307
HV P_EF Inv 0 10 0.02 Ref to appendix 3 page
307
Chapter 21 Appendix
266
Setting Unit Min.
(Ir:5A/1A) Max.
(Ir:5A/1A)
Default setting
(Ir:5A/1A) Description
HV Angle_EF ° 0 90 45 The angle setting for
voltage ahead of current.
HV Imax_2H_UnBlk_E
F
A 0.25Ir 20Ir 5 The maximum 1st
-harmonic current setting
to remove the inrush
block, in HV EF protec-
tion
HV Ratio_I2/I1_EF
0.07 0.5 0.2 The maximum 1st
-harmonic current setting
to remove the inrush
block, in HV EF protec-
tion
MV 3I0_EF1
A 0.05Ir 20Ir 5 MV earth fault (E/F) pro-
tection current setting for
Stage 1
MV T_EF1 s 0 60 60 Time setting for MV E/F,
Stage 1
MV 3I0_EF2 A 0.05Ir 20Ir 5 MV earth fault (E/F) cur-
rent setting for Stage 2
MV T_EF2 s 0 60 60 Time setting for MV E/F,
Stage 2
MV Curve_EF Inv 1 12 1 Ref to appendix 3 page
307
MV 3I0_EF Inv A 0.05Ir 20Ir 5 Ref to appendix 3 page
307
MV K_EF Inv 0.05 999 1 Ref to appendix 3 page
307
MV A_EF Inv s 0 200 0.14 Ref to appendix 3 page
307
MV B_EF Inv s 0 60 0 Ref to appendix 3 page
307
MV P_EF Inv 0 10 0.02 Ref to appendix 3 page
307
MV Angle_EF ° 0 90 45 The angle setting for
voltage ahead of current.
Chapter 21 Appendix
267
Setting Unit Min.
(Ir:5A/1A) Max.
(Ir:5A/1A)
Default setting
(Ir:5A/1A) Description
MV Imax_2H_UnBlk_E
F
A 0.25Ir 20Ir 5 The maximum 1st
-harmonic current setting
to remove the inrush
block, in MV E/F protec-
tion
MV Ratio_I2/I1_EF
0.07 0.5 0.2 Inrush 2nd harmonic ratio
setting for blocking MV
E/F protection
LV 3I0_EF1
A 0.05Ir 20Ir 5 LV earth fault (E/F) pro-
tection current setting for
Stage 1
LV T_EF1 s 0 60 60 Time setting for LV E/F,
Stage 1
LV 3I0_EF2 A 0.05Ir 20Ir 5 LV earth fault (E/F) cur-
rent setting for Stage 2
LV T_EF2 s 0 60 60 Time setting for LV E/F,
Stage 2
LV Curve_EF Inv 1 12 1 Ref to appendix 3 page
307
LV 3I0_EF Inv A 0.05Ir 20Ir 5 Ref to appendix 3 page
307
LV K_EF Inv 0.05 999 1 Ref to appendix 3 page
307
LV A_EF Inv s 0 200 0.14 Ref to appendix 3 page
307
LV B_EF Inv s 0 60 0 Ref to appendix 3 page
307
LV P_EF Inv 0 10 0.02 Ref to appendix 3 page
307
LV Angle_EF ° 0 90 45 The angle setting for
voltage ahead of current.
LV Imax_2H_UnBlk_E
F
A 0.25Ir 20Ir 5 The maximum 1st
-harmonic current setting
to remove the inrush
block, in LV E/F protec-
tion
Chapter 21 Appendix
268
Setting Unit Min.
(Ir:5A/1A) Max.
(Ir:5A/1A)
Default setting
(Ir:5A/1A) Description
LV Ratio_I2/I1_EF
0.07 0.5 0.2 Inrush 2nd harmonic ratio
setting for blocking LV
E/F protection
HV 3I0_Neutral OC1
A 0.05Ir 20Ir 5 HV neutral over-current
(NOC) protection current
setting for Stage 1
HV T_Neutral OC1 s 0 60 60 Time setting for HV NOC,
Stage 1
HV 3I0_Neutral OC2
A 0.05Ir 20Ir 5 HV neutral over-current
(NOC) protection current
setting for Stage 2
HV T_Neutral OC2 s 0 60 60 Time setting for HV NOC,
Stage 1
HV Curve_NOC Inv
1 12 1 Ref to appendix 3 page
307
HV 3I0_NOC Inv A 0.05Ir 20Ir 5 Ref to appendix 3 page
307
HV K_NOC Inv 0.05 999 1 Ref to appendix 3 page
307
HV A_NOC Inv s 0 200 0.14 Ref to appendix 3 page
307
HV B_NOC Inv s 0 60 0 Ref to appendix 3 page
307
HV P_NOC Inv 0 10 0.02 Ref to appendix 3 page
307
HV Angle_NOC ° 0 90 45 The angle setting for
voltage ahead of current.
HV Imax_2H_UnBlk_
NOC
A 0.25Ir 20Ir 5 The maximum 1st
-harmonic current setting
to remove the inrush
block, in HV NOC protec-
tion
HV Ra-tio_I2/I1_NOC
0.07 0.5 0.2 Inrush 2nd harmonic ratio
setting for blocking HV
NOC protection
Chapter 21 Appendix
269
Setting Unit Min.
(Ir:5A/1A) Max.
(Ir:5A/1A)
Default setting
(Ir:5A/1A) Description
MV 3I0_Neutral OC1
A 0.05Ir 20Ir 5 MV neutral over-current
(NOC) protection current
setting for Stage 1
MV T_Neutral OC1 s 0 60 60 Time setting for MV NOC,
Stage 1
MV 3I0_Neutral OC2
A 0.05Ir 20Ir 5 MV neutral over-current
(NOC) protection current
setting for Stage 2
MV T_Neutral OC2 s 0 60 60 Time setting for MV NOC,
Stage 1
MV Curve_NOC Inv
1 12 1 Ref to appendix 3 page
307
MV 3I0_NOC Inv A 0.05Ir 20Ir 5 Ref to appendix 3 page
307
MV K_NOC Inv 0.05 999 1 Ref to appendix 3 page
307
MV A_NOC Inv s 0 200 0.14 Ref to appendix 3 page
307
MV B_NOC Inv s 0 60 0 Ref to appendix 3 page
307
MV P_NOC Inv 0 10 0.02 Ref to appendix 3 page
307
MV Angle_NOC ° 0 90 45 The angle setting for
voltage ahead of current.
MV Imax_2H_UnBlk_
NOC
A 0.25Ir 20Ir 5 The maximum 1st
-harmonic current setting
to remove the inrush
block, in MV NOC pro-
tection
MV Ra-tio_I2/I1_NOC
0.07 0.5 0.2 Inrush 2nd harmonic ratio
setting for blocking MV
NOC protection
LV 3I0_Neutral OC1
A 0.05Ir 20Ir 5 LV neutral over-current
(NOC) protection current
setting for Stage 1
LV T_Neutral OC1 s 0 60 60 Time setting for LV NOC,
Stage 1
Chapter 21 Appendix
270
Setting Unit Min.
(Ir:5A/1A) Max.
(Ir:5A/1A)
Default setting
(Ir:5A/1A) Description
LV 3I0_Neutral OC2
A 0.05Ir 20Ir 5 LV neutral over-current
(NOC) protection current
setting for Stage 2
LV T_Neutral OC2 s 0 60 60 Time setting for LV NOC,
Stage 1
LV Curve_NOC Inv 1 12 1 Ref to appendix 3 page
307
LV 3I0_NOC Inv A 0.05Ir 20Ir 5 Ref to appendix 3 page
307
LV K_NOC Inv 0.05 999 1 Ref to appendix 3 page
307
LV A_NOC Inv s 0 200 0.14 Ref to appendix 3 page
307
LV B_NOC Inv s 0 60 0 Ref to appendix 3 page
307
LV P_NOC Inv 0 10 0.02 Ref to appendix 3 page
307
LV Angle_NOC ° 0 90 45 The angle setting for
voltage ahead of current.
LV Imax_2H_UnBlk_
NOC
A 0.25Ir 20Ir 5 The maximum 1st
-harmonic current setting
to remove the inrush
block, in LV NOC protec-
tion
LV Ra-tio_I2/I1_NOC
0.07 0.5 0.2 Inrush 2nd harmonic ratio
setting for blocking LV
NOC protection
HV I_Therm OL Trip
A 0.1Ir 5Ir 2 Setting for HV-side
thermal overload
trip-stage current
HV I_Therm OL Alarm
A 0.1Ir 5Ir 2 Setting for HV-side
thermal overload
alarm-stage current
HV T_Const Therm
s 1 9999 10 Time const for HV-side
thermal overload protec-
tion
Chapter 21 Appendix
271
Setting Unit Min.
(Ir:5A/1A) Max.
(Ir:5A/1A)
Default setting
(Ir:5A/1A) Description
HV T_Const Cool Down
s 1 9999 10 Cool down time delay for
HV-side thermal overload
MV I_Therm OL Trip
A 0.1Ir 5Ir 2 Setting for MV-side
thermal overload
trip-stage current
MV I_Therm OL Alarm
A 0.1Ir 5Ir 2 Setting for MV-side
thermal overload
alarm-stage current
MV T_Const Therm
s 1 9999 10 Time const for MV-side
thermal overload protec-
tion
MV T_Const Cool Down
s 1 9999 10 Cool down time delay for
MV-side thermal overload
HV I_OverLoad A 0.1Ir 4Ir 2 Overcurrent Setting of
overload
HV T_OverLoad s 0.1 3600 10 Time setting for overload
MV I_OverLoad A 0.1Ir 4Ir 2 Overcurrent Setting of
overload
MV T_OverLoad s 0.1 3600 10 Time setting for overload
LV I_OverLoad A 0.1Ir 4Ir 2 Overcurrent Setting of
overload
LV T_OverLoad s 0.1 3600 10 Time setting for overload
LW I_OvLd Alarm
A 0.1Ir 4Ir 20 Alarm current setting of
LV delta winding overload
protection
LW T_OvLd Alarm
s 0.1 3600 10 Alarm time setting of LV
delta winding overload
protection
LW I_OvLd Low Trip
A 0.1Ir 4Ir 20 Low stage tripping cur-
rent setting
LW T_OvLd Low Trip
s 0.1 3600 10 Low stage tripping time
setting
LW I_OvLd High Trip
A 0.1Ir 4Ir 20 High stage tripping cur-
rent setting
LW T_OvLd High Trip
s 0.1 3600 10 High stage tripping time
setting
Chapter 21 Appendix
272
Setting Unit Min.
(Ir:5A/1A) Max.
(Ir:5A/1A)
Default setting
(Ir:5A/1A) Description
HV U_OV1
V 40 200 200 HV voltage setting for
stage 1 of overvoltage
protection
HV T_OV1
s 0 60 60 HV time setting for stage
1 of overvoltage protec-
tion
HV U_OV2
V 40 200 200 HV voltage setting for
stage 2 of overvoltage
protection
HV T_OV2
s 0 60 60 HV time setting for stage
2 of overvoltage protec-
tion
HV Dropout_OV 0.9 0.99 0.95 HV dropout ratio for
overvoltage protection
MV U_OV1
V 40 200 200 MV voltage setting for
stage 1 of overvoltage
protection
MV T_OV1
s 0 60 60 MV time setting for stage
1 of overvoltage protec-
tion
MV U_OV2
V 40 200 200 MV voltage setting for
stage 2 of overvoltage
protection
MV T_OV2
s 0 60 60 MV time setting for stage
2 of overvoltage protec-
tion
MV Dropout_OV 0.9 0.99 0.95 MV dropout ratio for
overvoltage protection
HV I_CBF OC
A 0.05Ir 20Ir 5 Phase current setting
value for HVcircuit
breaker failure (CBF)
protection
HV 3I2_CBF NS
A 0.05Ir 20Ir 5 Negative sequence (NS)
current setting 23I val-
ue for HV CBF protection
Chapter 21 Appendix
273
Setting Unit Min.
(Ir:5A/1A) Max.
(Ir:5A/1A)
Default setting
(Ir:5A/1A) Description
HV 3I0_CBF ZS
A 0.05Ir 20Ir 5 Zero sequence (ZS) cur-
rent setting 03I value
for HV1 CBF protection
HV T1_CBF
s 0 32 10 Time setting value of
Stage 1, for HV CBF
protection
HV T2_CBF
s 0.1 32 10 Time setting value of
Stage 2, for HV CBF
protection
MVI_CBF OC
A 0.05Ir 20Ir 5 Phase current setting
value for MV CBF pro-
tection
MV 3I2_CBF NS
A 0.05Ir 20Ir 5 Negative sequence (NS)
current setting 23I val-
ue for MV CBF protection
MV 3I0_CBF ZS
A 0.05Ir 20Ir 5 Zero sequence (ZS) cur-
rent setting 03I value
for MV CBF protection
MV T1_CBF
s 0 32 10 Time setting value of
Stage 1, for MV CBF
protection
MV T2_CBF
s 0.1 32 10 Time setting value of
Stage 2, for MV CBF
protection
LV I_CBF OC
A 0.05Ir 20Ir 5 Phase current setting
value for LV CBF protec-
tion
LV 3I2_CBF NS
A 0.05Ir 20Ir 5 Negative sequence (NS)
current setting 23I val-
ue for LV CBF protection
LV 3I0_CBF ZS
A 0.05Ir 20Ir 5 Zero sequence (ZS) cur-
rent setting 03I value
for LV CBF protection
Chapter 21 Appendix
274
Setting Unit Min.
(Ir:5A/1A) Max.
(Ir:5A/1A)
Default setting
(Ir:5A/1A) Description
LV T1_CBF
s 0 32 10 Time setting value of
Stage 1, for LV CBF pro-
tection
LV T2_CBF
s 0.1 32 10 Time setting value of
Stage 2, for LV CBF pro-
tection
HV T_Dead Zone
s 0 32 10 Time delay setting for HV
dead zone protection
MV T_Dead Zone
s 0 32 10 Time delay setting for MV
dead zone protection
LV T_Dead Zone
s 0 32 10 Time delay setting for LV
dead zone protection
HV I_STUB A 0.05Ir 20Ir 100 current threshold of
STUB protection
HV T_STUB s 0 60 60 delay time of STUB pro-
tection
MV I_STUB A 0.05Ir 20Ir 100 current threshold of
STUB protection
MV T_STUB s 0 60 60 delay time of STUB pro-
tection
LV I_STUB A 0.05Ir 20Ir 100 current threshold of
STUB protection
LV T_STUB s 0 60 60 delay time of STUB pro-
tection
HV 3I0_PD
A 0.05Ir 20Ir 5 zero sequence current
threshold of pole dis-
cordance protection
HV 3I2_PD
A 0.05Ir 20Ir 5 negative sequence cur-
rent threshold of pole
discordance protection
HV T_PD s 0 60 10 delay time of pole dis-
cordance protection
MV 3I0_PD
A 0.05Ir 20Ir 5 zero sequence current
threshold of pole dis-
cordance protection
Chapter 21 Appendix
275
Setting Unit Min.
(Ir:5A/1A) Max.
(Ir:5A/1A)
Default setting
(Ir:5A/1A) Description
MV 3I2_PD
A 0.05Ir 20Ir 5 negative sequence cur-
rent threshold of pole
discordance protection
MV T_PD s 0 60 10 delay time of pole dis-
cordance protection
HV I_VT Fail A 0.05Ir 0.2Ir 0.05 Minimum Current of VT
failure for HV side
HV 3I02_ VT Fail A 0.05Ir 0.2Ir 0.5 Minimum zero or nega-
tive Current of HV VT fail
HV Upe_VT Fail V 7 20 8 Maximum phase to earth
voltage of HV VT fail
HV Upp_VT Fail
V 10 30 16 Maximum phase to
phase voltage of HV VT
fail
HV Upe_VT Nor-mal
V 40 65 40 Minimum phase to phase
voltage of HV VT normal
MV I_VT Fail A 0.05Ir 0.2Ir 0.05 Minimum Current of VT
failure for MV side
MV 3I02_VT Fail A 0.05Ir 0.2Ir 0.5 Minimum zero or nega-
tive Current of MV VT fail
MV Upe_VT Fail V 7 20 8 Maximum phase to earth
voltage of MV VT fail
MV Upp_VT Fail
V 10 30 16 Maximum phase to
phase voltage of MV VT
fail
MV Upe_VT Nor-mal
V 40 65 40 Minimum phase to phase
voltage of MV VT normal
LV I_VT Fail A 0.05Ir 0.2Ir 0.05 Minimum Current of VT
failure for LV side
LV 3I02_VT Fail A 0.05Ir 0.2Ir 0.5 Minimum zero or nega-
tive Current of LV VT fail
LV Upe_VT Fail V 7 20 8 Maximum phase to earth
voltage of LV VT fail
LV Upp_VT Fail
V 10 30 16 Maximum phase to
phase voltage of LV VT
fail
Chapter 21 Appendix
276
Setting Unit Min.
(Ir:5A/1A) Max.
(Ir:5A/1A)
Default setting
(Ir:5A/1A) Description
LV Upe_VT Nor-mal
V 40 65 40 Minimum phase to phase
voltage of LV VT normal
T_Pulse Tripping s 0.2 5 5 delay time of STUB pro-
tection
1.2 Binary setting list
Setting Unit Min. Max. Default setting
Description
Auto Trans 0 1 0
Autotransformer not common transformer 1-autotransformer ;
0- not autotransformer Two-Wind Trans
0 1 0
Two-winding(TWO WIND ) not three -winding trans-former (TRANS) 1-two-winding trans;
0-three-winding trans CT Fail Detect
0 1 0 VT Failure Detection On/Off 1-On, 0-Off.
Setting Unit Min. Max.
Default setting
Description
Func_Inst Diff 0 1 0
Instantaneous differential protection ON 1-on; 0-off.
Func_Percent Diff 0 1 0
Percentage differential pro-tection ON 1-on; 0-off.
Block Diff at Inrush 0 1 0
Inrush block differential pro-tection 1-block; 0-not block.
2nd Harm Not Wave
0 1 0
2nd harmonic (HAR) inhibit not the fuzzy recognition based on the wave-form(WAVE) 1-2nd harmonic on; 0- waveform on
Block Diff at Overexcit 0 1 0
Overexcitation block differ-ential protection 1-block; 0-not block.
Chapter 21 Appendix
277
Setting Unit Min. Max. Default setting
Description
Overexcit 3rd NOT 5th
0 1 0
Overexcitation stabilization judgement 3rd or 5th harmonic (HAR) inhibit on 1-3rd harmonic; 0-5th har-monic.
Func_Diff Alarm 0 1 0
Differential current (DIFF) Alarming on 1-on; 0-off.
Block Diff at CT_Fail 0 1 0
Block differential protection when there is CT failure 1-block; 0-not block.
HV D_side Elimi-nate I0
0 1 0
Eliminate calculated 3I0 when HV side winding is connected in Delta mode 1- eliminate; 0-not eliminate
MV D_side Elimi-nate I0
0 1 0
Eliminate calculated 3I0 when MV side winding is connected in Delta mode 1- eliminate; 0-not eliminate
LV D_side Elimi-nate I0
0 1 0
Eliminate calculated 3I0 when LV side winding is connected in Delta mode 1- eliminate; 0-not eliminate
Diff Includes LV Cur
0 1 0
LV current is included in calculation of the differential protection. 1- Diff Includes LV Cur; 0-Diff NOT Includes LV Cur
HV Func_REF Trip 0 1 0
HV Restricted earth fault trip-stage ON 1-on; 0-off.
HV Func_REF Alarm 0 1 0
HV Restricted earth fault Alarm-stage ON 1-on; 0-off.
Block HV REF at HV CT_Fail 0 1 0
Block HV REF when CT failure, 1-Block;0-unblock
MV Func_REF Trip 0 1 0
MV Restricted earth fault trip-stage ON 1-on; 0-off.
Chapter 21 Appendix
278
Setting Unit Min. Max. Default setting
Description
MV Func_REF Alarm 0 1 0
MV Restricted earth fault Alarm-stage ON 1-on; 0-off.
Block MV REF at MV CT_Fail 0 1 0
Block MV REF when CT failure, 1-Block;0-unblock
LV Func_REF Trip 0 1 0
LV Restricted earth fault trip-stage ON 1-on; 0-off.
LV Func_REF Alarm 0 1 0
LV Restricted earth fault Alarm-stage ON 1-on; 0-off.
Block LV REF at LV CT_Fail 0 1 0
Block LV REF when CT fail-ure, 1-Block;0-unblock
HV Func_Overexcit
0 1 0 HV Overexcitation (V/F) on 1-on; 0-off.
MV Func_Overexcit
0 1 0 MV Overexcitation (V/F) on 1-on; 0-off.
LV Func_Overexcit 0 1 0
LV Overexcitation (V/F) on 1-on; 0-off.
Func_Overexcit Alarm Def 0 1 0
Definite Overexcitation (V/F) Alarming on 1-on; 0-off.
Func_Overexcit Trip Def 0 1 0
Definite (DEF)Overexcitation (V/F) on 1-on; 0-off.
Func_Overexcit Trip Inv 0 1 0
Inverse (IVR)Overexcitation (V/F) on 1-on; 0-off.
V/F Volt-age(0-VPP,1-VPN)
0 1 0
Overexcitation protection uses phase-to-phase volt-age (VPP) or phase-to-earth voltage (VPN) 0-VPP; 1-VPN.
HV Func_OC1
0 1 0
The 1st stage of HV OC (OC_1) protection is switched ON 1-on; 0-off.
Chapter 21 Appendix
279
Setting Unit Min. Max. Default setting
Description
HV OC1 Direction
0 1 0
Direction (DIR) detection of HV OC Stage 1 is switched ON 1-on; 0-off.
HV OC1 Dir To Sys
0 1 0
Direction unit of HV OC Stage 1 points to system 0 - point to the protected transformer 1- point to system
HV OC1 Inrush Block
0 1 0
Inrush 2nd harmonic detec-tion HV OC Stage 1 is switched ON 1-on; 0-off.
HV Func_OC2
0 1 0
The 2nd stage of HV OC (OC_2) protection is switched ON 1-on; 0-off.
HV OC2 Direction
0 1 0
Direction (DIR) detection of HV OC Stage 2 is switched ON 1-on; 0-off.
HV OC2 Dir To Sys
0 1 0
Direction unit of HV OC Stage 2 points to system 0 - point to the protected transformer 1- point to system
HV OC2 Inrush Block
0 1 0
Inrush 2nd harmonic detec-tion HV OC Stage 2 is switched ON 1-on; 0-off.
HV Func_OC Inv
0 1 0
The IDMTL inverse time stage of HV OC protection is switched ON 1-on; 0-off.
HV OC Inv Direc-tion
0 1 0
Direction (DIR) detection of HV OC IDMTL inverse time is switched ON 1-on; 0-off.
Chapter 21 Appendix
280
Setting Unit Min. Max. Default setting
Description
HV OC Inv Dir To Sys
0 1 0
Direction unit of HV OC ID-MTL inverse time points to system 0 - point to the protected transformer 1- point to system
HV OC Inv Inrush Block
0 1 0
Inrush 2nd harmonic detec-tion HV OC IDMTL inverse time is switched ON 1-on; 0-off.
Block HV OC at HV VT_Fail
0 1 0
Select to block HV OC pro-tection or exit direction unit, when HV VT fails 0- HV Direct OK at HV VT Fail 1- Blk HV OC at HV VT Fail
HV OC Initiate LV CBF 0 1 0
HV OC protection initiate LV side CBF 0 - initiate, 1 – not initiate
HV OC Initiate MV CBF 0 1 0
HV OC protection initiate MV side CBF 0 - initiate, 1 – not initiate
MV Func_OC1
0 1 0
The 1st stage of MV OC (OC_1) protection is switched ON 1-on; 0-off.
MV OC1 Direction
0 1 0
Direction (DIR) detection of MV OC Stage 1 is switched ON 1-on; 0-off.
MV OC1 Dir To Sys
0 1 0
Direction unit of MV OC Stage 1 points to system 0 - point to the protected transformer 1- point to system
MV OC1 Inrush Block
0 1 0
Inrush 2nd harmonic detec-tion MV OC Stage 1 is switched ON 1-on; 0-off.
Chapter 21 Appendix
281
Setting Unit Min. Max. Default setting
Description
MV Func_OC2
0 1 0
The 2nd stage of MV OC (OC_2) protection is switched ON 1-on; 0-off.
MV OC2 Direction
0 1 0
Direction (DIR) detection of MV OC Stage 2 is switched ON 1-on; 0-off.
MV OC2 Dir To Sys
0 1 0
Direction unit of MV OC Stage 2 points to system 0 - point to the protected transformer 1- point to system
MV OC2 Inrush Block
0 1 0
Inrush 2nd harmonic detec-tion MV OC Stage 2 is switched ON 1-on; 0-off.
MV Func_OC Inv
0 1 0
The IDMTL inverse time stage of MV OC protection is switched ON 1-on; 0-off.
MV OC Inv Direc-tion
0 1 0
Direction (DIR) detection of MV OC IDMTL inverse time is switched ON 1-on; 0-off.
MV OC Inv Dir To Sys
0 1 0
Direction unit of MV OC IDMTL inverse time points to system 0 - point to the protected transformer 1- point to system
MV OC Inv Inrush Block
0 1 0
Inrush 2nd harmonic detec-tion MV OC IDMTL inverse time is switched ON 1-on; 0-off.
Block MV OC at MV VT_Fail
0 1 0
Select to block MV OC pro-tection or exit direction unit, when MV VT fails 0- MV Direct OK at MV VT Fail 1- Blk MV OC at MV VT Fail
Chapter 21 Appendix
282
Setting Unit Min. Max. Default setting
Description
MV OC Initiate HV1 CBF 0 1 0
MV OC protection initiate HV1 side CBF 0 - initiate, 1 – not initiate
LV Func_OC1
0 1 0
The 1st stage of LV OC (OC_1) protection is switched ON 1-on; 0-off.
LV OC1 Direction
0 1 0
Direction (DIR) detection of LV OC Stage 1 is switched ON 1-on; 0-off.
LV OC1 Dir To Sys
0 1 0
Direction unit of LV OC Stage 1 points to system 0 - point to the protected transformer 1- point to system
LV OC1 Inrush Block
0 1 0
Inrush 2nd harmonic detec-tion LV OC Stage 1 is switched ON 1-on; 0-off.
LV Func_OC2
0 1 0
The 2nd stage of LV OC (OC_2) protection is switched ON 1-on; 0-off.
LV OC2 Direction
0 1 0
Direction (DIR) detection of LV OC Stage 2 is switched ON 1-on; 0-off.
LV OC2 Dir To Sys
0 1 0
Direction unit of LV OC Stage 2 points to system 0 - point to the protected transformer 1- point to system
LV OC2 Inrush Block
0 1 0
Inrush 2nd harmonic detec-tion LV OC Stage 2 is switched ON 1-on; 0-off.
LV Func_OC Inv
0 1 0
The IDMTL inverse time stage of LV OC protection is switched ON 1-on; 0-off.
Chapter 21 Appendix
283
Setting Unit Min. Max. Default setting
Description
LV OC Inv Direc-tion
0 1 0
Direction (DIR) detection of LV OC IDMTL inverse time is switched ON 1-on; 0-off.
LV OC Inv Dir To Sys
0 1 0
Direction unit of LV OC ID-MTL inverse time points to system 0 - point to the protected transformer 1- point to system
LV OC Inv Inrush Block
0 1 0
Inrush 2nd harmonic detec-tion LV OC IDMTL inverse time is switched ON 1-on; 0-off.
Block LV OC at LV VT_Fail
0 1 0
Select to block LV OC pro-tection or exit direction unit, when LV VT fails 0- LV Direct OK at LV VT Fail 1- Blk LV OC at LV VT Fail
LV OC Initiate HV1 CBF 0 1 0
LV OC protection initiate HV1 side CBF 0 - initiate, 1 – not initiate
HV Func_EF1
0 1 0
The 1st stage of HV earth fault (EF_1) protection is switched ON 1-on; 0-off.
HV EF1 Direction
0 1 0
Direction (DIR) detection of HV EF Stage 1 is switched ON 1-on; 0-off.
HV EF1 Dir To Sys
0 1 0
Direction unit of HV EF Stage 1 points to system 0 - point to the protected transformer 1- point to system
HV EF1 Inrush Block
0 1 0
Inrush 2nd harmonic detec-tion HV EF Stage 1 is switched ON 1-on; 0-off.
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284
Setting Unit Min. Max. Default setting
Description
HV Func_EF2
0 1 0
The 2nd stage of HV earth fault (EF_2) protection is switched ON 1-on; 0-off.
HV EF2 Direction
0 1 0
Direction (DIR) detection of HV EF Stage 2 is switched ON 1-on; 0-off.
HV EF2 Dir To Sys
0 1 0
Direction unit of HV EF Stage 2 points to system 0 - point to the protected transformer 1- point to system
HV EF2 Inrush Block
0 1 0
Inrush 2nd harmonic detec-tion HV EF Stage 2 is switched ON 1-on; 0-off.
HV Func_EF Inv
0 1 0
The IDMTL inverse time stage of HV EF protection is switched ON 1-on; 0-off.
HV EF Inv Direc-tion
0 1 0
Direction (DIR) detection of HV EF IDMTL inverse time is switched ON 1-on; 0-off.
HV EF Inv Dir To Sys
0 1 0
Direction unit of HV EF ID-MTL inverse time points to system 0 - point to the protected transformer 1- point to system
HV EF Inv Inrush Block
0 1 0
Inrush 2nd harmonic detec-tion HV EF IDMTL inverse time is switched ON 1-on; 0-off.
Block HV EF at HV VT_Fail
0 1 0
Select to block HV EF pro-tection or exit direction unit, when HV VT fails 0 - HV Direct OK at HV VT Fail 1 - Blk HV EF at HV VT Fail
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285
Setting Unit Min. Max. Default setting
Description
Block HV EF at HV CT_Fail 0 1 0
Block HV EF when there is HV CT failure 1-Block; 0-NOT block
HV EF Initiate LV CBF 0 1 0
HV EF protection initiate LV side CBF 0 - initiate, 1 – not initiate
HV EF Initiate MV CBF 0 1 0
HV EF protection initiate MV side CBF 0 - initiate, 1 – not initiate
MV Func_EF1
0 1 0
The 1st stage of MV earth fault (EF_1) protection is switched ON 1-on; 0-off.
MV EF1 Direction
0 1 0
Direction (DIR) detection of MV EF Stage 1 is switched ON 1-on; 0-off.
MV EF1 Dir To Sys
0 1 0
Direction unit of MV EF Stage 1 points to system 0 - point to the protected transformer 1- point to system
MV EF1 Inrush Block
0 1 0
Inrush 2nd harmonic detec-tion MV EF Stage 1 is switched ON 1-on; 0-off.
MV Func_EF2
0 1 0
The 2nd stage of MV earth fault (EF_2) protection is switched ON 1-on; 0-off.
MV EF2 Direction
0 1 0
Direction (DIR) detection of MV EF Stage 2 is switched ON 1-on; 0-off.
MV EF2 Dir To Sys
0 1 0
Direction unit of MV EF Stage 2 points to system 0 - point to the protected transformer 1- point to system
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286
Setting Unit Min. Max. Default setting
Description
MV EF2 Inrush Block
0 1 0
Inrush 2nd harmonic detec-tion MV EF Stage 2 is switched ON 1-on; 0-off.
MV Func_EF Inv
0 1 0
The IDMTL inverse time stage of MV EF protection is switched ON 1-on; 0-off.
MV EF Inv Direc-tion
0 1 0
Direction (DIR) detection of MV EF IDMTL inverse time is switched ON 1-on; 0-off.
MV EF Inv Dir To Sys
0 1 0
Direction unit of MV EF ID-MTL inverse time points to system 0 - point to the protected transformer 1- point to system
MV EF Inv Inrush Block
0 1 0
Inrush 2nd harmonic detec-tion MV EF IDMTL inverse time is switched ON 1-on; 0-off.
Block MV EF at MV VT_Fail
0 1 0
Select to block MV EF pro-tection or exit direction unit, when MV VT fails 0 - MV Direct OK at MV VT Fail 1 - Blk MV EF at MV VT Fail
Block MV EF at MV CT_Fail 0 1 0
Block MV EF when there is MV CT failure 1-Block; 0-NOT block
MV EF Initiate HV CBF 0 1 0
MV EF protection initiate HV1 side CBF 0 - initiate, 1 – not initiate
LV Func_EF1
0 1 0
The 1st stage of LV earth fault (EF_1) protection is switched ON 1-on; 0-off.
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287
Setting Unit Min. Max. Default setting
Description
LV EF1 Direction
0 1 0
Direction (DIR) detection of LV EF Stage 1 is switched ON 1-on; 0-off.
LV EF1 Dir To Sys
0 1 0
Direction unit of LV EF Stage 1 points to system 0 - point to the protected transformer 1- point to system
LV EF1 Inrush Block
0 1 0
Inrush 2nd harmonic detec-tion LV EF Stage 1 is switched ON 1-on; 0-off.
LV Func_EF2
0 1 0
The 2nd stage of LV earth fault (EF_2) protection is switched ON 1-on; 0-off.
LV EF2 Direction
0 1 0
Direction (DIR) detection of LV EF Stage 2 is switched ON 1-on; 0-off.
LV EF2 Dir To Sys
0 1 0
Direction unit of LV EF Stage 2 points to system 0 - point to the protected transformer 1- point to system
LV EF2 Inrush Block
0 1 0
Inrush 2nd harmonic detec-tion LV EF Stage 2 is switched ON 1-on; 0-off.
LV Func_EF Inv
0 1 0
The IDMTL inverse time stage of LV EF protection is switched ON 1-on; 0-off.
LV EF Inv Direction
0 1 0
Direction (DIR) detection of LV EF IDMTL inverse time is switched ON 1-on; 0-off.
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288
Setting Unit Min. Max. Default setting
Description
LV EF Inv Dir To Sys
0 1 0
Direction unit of LV EF ID-MTL inverse time points to system 0 - point to the protected transformer 1- point to system
LV EF Inv Inrush Block
0 1 0
Inrush 2nd harmonic detec-tion LV EF IDMTL inverse time is switched ON 1-on; 0-off.
Block LV EF at LV VT_Fail
0 1 0
Select to block LV EF pro-tection or exit direction unit, when LV VT fails 0 - LV Direct OK at LV VT Fail 1 - Blk LV EF at LV VT Fail
Block LV EF at LV CT_Fail 0 1 0
Block LV EF when there is LV CT failure 1-Block; 0-NOT block
LV EF Initiate HV CBF 0 1 0
LV EF protection initiate HV1 side CBF 0 - initiate, 1 – not initiate
HV Func_Neu OC1
0 1 0
The 1st stage of HV neutral OC (OC_1) protection is switched ON 1-on; 0-off.
HV Neu OC1 Di-rection
0 1 0
Direction (DIR) detection of HV neutral OC Stage 1 is switched ON 1-on; 0-off.
HV Neu OC1 Dir To Sys
0 1 0
Direction unit of HV neutral OC Stage 1 points to system 0 - point to the protected transformer 1- point to system
HV Neu OC1 In-rush Block
0 1 0
Inrush 2nd harmonic detec-tion HV neutral OC Stage 1 is switched ON 1-on; 0-off.
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289
Setting Unit Min. Max. Default setting
Description
HV Func_Neu OC2
0 1 0
The 2nd stage of HV neutral OC (OC_2) protection is switched ON 1-on; 0-off.
HV Neu OC2 Di-rection
0 1 0
Direction (DIR) detection of HV neutral OC Stage 2 is switched ON 1-on; 0-off.
HV Neu OC2 Dir To Sys
0 1 0
Direction unit of HV neutral OC Stage 2 points to system 0 - point to the protected transformer 1- point to system
HV Neu OC2 In-rush Block
0 1 0
Inrush 2nd harmonic detec-tion HV neutral OC Stage 2 is switched ON 1-on; 0-off.
HV Func_Neu OC Inv
0 1 0
The IDMTL inverse time stage of HV neutral OC pro-tection is switched ON 1-on; 0-off.
HV Neu OC Inv Direction
0 1 0
Direction (DIR) detection of HV neutral OC IDMTL in-verse time stage is switched ON 1-on; 0-off.
HV Neu OC Inv Dir To Sys
0 1 0
Direction unit of HV neutral OC IDMTL inverse time stage points to system 0 - point to the protected transformer 1- point to system
HV Neu OC Inv Inrush Block
0 1 0
Inrush 2nd harmonic detec-tion HV neutral OC IDMTL inverse time stage is switched ON 1-on; 0-off.
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290
Setting Unit Min. Max. Default setting
Description
Block HV NOC at HV VT_Fail
0 1 0
Select to block HV neutral OC protection or exit direc-tion unit, when HV VT fails 0 - HV Direct OK at HV VT Fail 1 - Blk HV NOC at HV VT Fail
HV Neu OC Init MV CBF 0 1 0
HV neutral OC protection initiate LV side CBF 0 - initiate, 1 – not initiate
MV Func_Neu OC1
0 1 0
The 1st stage of MV neutral OC (OC_1) protection is switched ON 1-on; 0-off.
MV Neu OC1 Di-rection
0 1 0
Direction (DIR) detection of MV neutral OC Stage 1 is switched ON 1-on; 0-off.
MV Neu OC1 Dir To Sys
0 1 0
Direction unit of MV neutral OC Stage 1 points to system 0 - point to the protected transformer 1- point to system
MV Neu OC1 In-rush Block
0 1 0
Inrush 2nd harmonic detec-tion MV neutral OC Stage 1 is switched ON 1-on; 0-off.
MV Func_Neu OC2
0 1 0
The 2nd stage of MV neutral OC (OC_2) protection is switched ON 1-on; 0-off.
MV Neu OC2 Di-rection
0 1 0
Direction (DIR) detection of MV neutral OC Stage 2 is switched ON 1-on; 0-off.
MV Neu OC2 Dir To Sys
0 1 0
Direction unit of MV neutral OC Stage 2 points to system 0 - point to the protected transformer 1- point to system
Chapter 21 Appendix
291
Setting Unit Min. Max. Default setting
Description
MV Neu OC2 In-rush Block
0 1 0
Inrush 2nd harmonic detec-tion MV neutral OC Stage 2 is switched ON 1-on; 0-off.
MV Func_Neu OC Inv
0 1 0
The IDMTL inverse time stage of MV neutral OC protection is switched ON 1-on; 0-off.
MV Neu OC Inv Direction
0 1 0
Direction (DIR) detection of MV neutral OC IDMTL in-verse time stage is switched ON 1-on; 0-off.
MV Neu OC Inv Dir To Sys
0 1 0
Direction unit of MV neutral OC IDMTL inverse time stage points to system 0 - point to the protected transformer 1- point to system
MV Neu OC Inv Inrush Block
0 1 0
Inrush 2nd harmonic detec-tion MV neutral OC IDMTL inverse time stage is switched ON 1-on; 0-off.
Block MV NOC at MV VT_Fail
0 1 0
Select to block MV neutral OC protection or exit direc-tion unit, when MV VT fails 0 - MV Direct OK at MV VT Fail 1 - Blk MV NOC at MV VT Fail
MV Neu OC Init MV CBF 0 1 0
MV neutral OC protection initiate LV side CBF 0 - initiate, 1 – not initiate
LV Func_Neu OC1
0 1 0
The 1st stage of LV neutral OC (OC_1) protection is switched ON 1-on; 0-off.
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292
Setting Unit Min. Max. Default setting
Description
LV Neu OC1 Di-rection
0 1 0
Direction (DIR) detection of LV neutral OC Stage 1 is switched ON 1-on; 0-off.
LV Neu OC1 Dir To Sys
0 1 0
Direction unit of LV neutral OC Stage 1 points to system 0 - point to the protected transformer 1- point to system
LV Neu OC1 In-rush Block
0 1 0
Inrush 2nd harmonic detec-tion LV neutral OC Stage 1 is switched ON 1-on; 0-off.
LV Func_Neu OC2
0 1 0
The 2nd stage of LV neutral OC (OC_2) protection is switched ON 1-on; 0-off.
LV Neu OC2 Di-rection
0 1 0
Direction (DIR) detection of LV neutral OC Stage 2 is switched ON 1-on; 0-off.
LV Neu OC2 Dir To Sys
0 1 0
Direction unit of LV neutral OC Stage 2 points to system 0 - point to the protected transformer 1- point to system
LV Neu OC2 In-rush Block
0 1 0
Inrush 2nd harmonic detec-tion LV neutral OC Stage 2 is switched ON 1-on; 0-off.
LV Func_Neu OC Inv
0 1 0
The IDMTL inverse time stage of LV neutral OC pro-tection is switched ON 1-on; 0-off.
LV Neu OC Inv Direction
0 1 0
Direction (DIR) detection of LV neutral OC IDMTL in-verse time stage is switched ON 1-on; 0-off.
Chapter 21 Appendix
293
Setting Unit Min. Max. Default setting
Description
LV Neu OC Inv Dir To Sys
0 1 0
Direction unit of LV neutral OC IDMTL inverse time stage points to system 0 - point to the protected transformer 1- point to system
LV Neu OC Inv Inrush Block
0 1 0
Inrush 2nd harmonic detec-tion LV neutral OC IDMTL inverse time stage is switched ON 1-on; 0-off.
Block LV NOC at LV VT_Fail
0 1 0
Select to block LV neutral OC protection or exit direc-tion unit, when LV VT fails 0 - LV Direct OK at LV VT Fail 1 - Blk LV NOC at LV VT Fail
LV Neu OC Init LV CBF 0 1 0
LV neutral OC protection initiate LV side CBF 0 - initiate, 1 – not initiate
HV Func_Thermal OvLd 0 1 0
Thermal overload in HV side is switched on 0 - OFF, 1 - ON
HV Cold Curve 0 1 0
HV side using hot/cold curve type 0 – Hot curve, 1 – Cold curve
HV Thermal Init LV CBF 0 1 0
HV thermal overload protec-tion initiate LV side CBF 0 - initiate, 1 – not initiate
HV Thermal Init MV CBF 0 1 0
HV thermal overload protec-tion initiate MV side CBF 0 - initiate, 1 – not initiate
MV Func_Thermal OvLd 0 1 0
Thermal overload in MV side is switched on 0 - OFF, 1 - ON
MV Cold Curve 0 1 0
MV side using hot/cold curve type 0 – Hot curve, 1 – Cold curve
MV Thermal Init HV1 CBF 0 1 0
MV thermal overload protec-tion initiate HV side CBF 0 - initiate, 1 – not initiate
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294
Setting Unit Min. Max. Default setting
Description
HV Func_OverLoad 0 1 0
Overload (LOAD) protection in HV side is switched ON 1-on; 0-off.
MV Func_OverLoad
0 1 0 Overload (LOAD)in MV side on
LV Func_OverLoad
0 1 0 Overload (LOAD)in LV side on
LW Func_OvLd Alarm
0 1 0
Alarm stage of LV delta winding (LWIND) overload (LOAD) protection is switched ON. 1-on; 0-off.
LW Func_OvLd Low Trip
0 1 0
Low-setting trip stage of LV delta winding overload pro-tection is switched ON. 1-on; 0-off.
LW Func_OvLd High Trip
0 1 0
High-setting trip stage of LV delta winding overload pro-tection is switched ON. 1-on; 0-off.
Low Trip Init HV1 CBF
0 1 0
Low-setting trip stage of LV delta winding overload pro-tection initiate HV1 side CBF 0 - initiate, 1 – not initiate
High Trip Init HV1 CBF
0 1 0
High-setting trip stage of LV delta winding overload pro-tection initiate HV1 side CBF 0 - initiate, 1 – not initiate
Low Trip Init MV CBF
0 1 0
Low-setting trip stage of LV delta winding overload pro-tection initiate MV side CBF 0 - initiate, 1 – not initiate
High Trip Init MV CBF
0 1 0
High-setting trip stage of LV delta winding overload pro-tection initiate MV side CBF - initiate, 1 – not initiate
HV Func_OV1 0 1 0
HV overvoltage stage 1 en-abled or disabled
HV Func_OV2 0 1 0
HV overvoltage stage 1 trip or alarm
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295
Setting Unit Min. Max. Default setting
Description
HV Func_OV2 0 1 0
HV overvoltage stage 2 en-abled or disabled
HV OV2 Trip 0 1 0
HV overvoltage stage 2 trip or alarm
HV OV Chk PE 0 1 0
HV phase to phase voltage or phase to earth measured for overvoltage protection
MV Func_OV1 0 1 0
MV overvoltage stage 1 en-abled or disabled
MV Func_OV2 0 1 0
MV overvoltage stage 1 trip or alarm
MV Func_OV2 0 1 0
MV overvoltage stage 2 en-abled or disabled
MV OV2 Trip 0 1 0
MV overvoltage stage 2 trip or alarm
MV OV Chk PE 0 1 0
MV phase to phase voltage or phase to earth measured for overvoltage protection
HV Func_CBF
0 1 0
HV Circuit breaker failure (CBF) protection is switched ON 1-on; 0-off.
HV 3I0/3I2 Check On
0 1 0
HV CBF protection detect negative or zero sequence current 3I0 or 3I2. 1-Detect; 0- Not Detect
HV CB Status Check On 0 1 0
HV CBF protection detect HV1 CB status 1-Detect; 0- Not Detect
MV Func_CBF
0 1 0
MV Circuit breaker failure (CBF) protection is switched ON 1-on; 0-off.
MV 3I0/3I2 Check On
0 1 0
MV CBF protection detect negative or zero sequence current 3I0 or 3I2. 1-Detect; 0- Not Detect
MV CB Status Check On 0 1 0
MV CBF protection detect MV CB status 1-Detect; 0- Not Detect
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296
Setting Unit Min. Max. Default setting
Description
LV Func_CBF
0 1 0
LV Circuit breaker failure (CBF) protection is switched ON 1-on; 0-off.
LV 3I0/3I2 Check On
0 1 0
LV CBF protection detect negative or zero sequence current 3I0 or 3I2. 1-Detect; 0- Not Detect
LV CB Status Check On 0 1 0
LV CBF protection detect LV CB status 1-Detect; 0- Not Detect
HV Func_Dead Zone 0 1 0
Dead zone protection is switched ON 1-on; 0-off.
MV Func_Dead Zone 0 1 0
Dead zone protection is switched ON 1-on; 0-off.
LV Func_Dead Zone 0 1 0
Dead zone protection is switched ON 1-on; 0-off.
HV Func_STUB 0 1 0
Enable or disable STUB protection
HV STUB Init LV CBF 0 1 0
STUB protection initiate LV side CBF 0 - initiate, 1 – not initiate
HV STUB Init MV CBF 0 1 0
STUB protection initiate HV side CBF 0 - initiate, 1 – not initiate
MV Func_STUB 0 1 0
Enable or disable STUB protection
MV STUB Init LV CBF 0 1 0
STUB protection initiate LV side CBF 0 - initiate, 1 – not initiate
MV STUB Init MV CBF 0 1 0
STUB protection initiate MV side CBF 0 - initiate, 1 – not initiate
LV Func_STUB 0 1 0
Enable or disable STUB protection
LV STUB Init LV CBF 0 1 0
STUB protection initiate LV side CBF 0 - initiate, 1 – not initiate
Chapter 21 Appendix
297
Setting Unit Min. Max. Default setting
Description
LV STUB Init MV CBF 0 1 0
STUB protection initiate LV side CBF 0 - initiate, 1 – not initiate
MV Func_PD 0 1 0
Enable or disable MV poles discordance protection
MV PD Chk 3I0/3I2 0 1 0
Enable or disable 3I0/3I2 criteria
MV Func_PD 0 1 0
Enable or disable MV poles discordance protection
MV PD Chk 3I0/3I2 0 1 0
Enable or disable 3I0/3I2 criteria
HV VT FAIL Detect 0 0 1
HV VT Failure Detection On/Off 1-On, 0-Off.
HV Solid Earth
0 0 1
HV Earthing mode: 1: Solid earthed system ; 0: isolated system or re-sistance earthed.
MV VT FAIL Detect 0 0 1
MV VT Failure Detection On/Off 1-On, 0-Off.
MV Solid Earth
0 0 1
MV Earthing mode: 1: Solid earthed system ; 0: isolated system or re-sistance earthed.
LV VT FAIL Detect 0 0 1
LV VT Failure Detection On/Off 1-On, 0-Off.
LV Solid Earth
0 0 1
LV Earthing mode: 1: Solid earthed system ; 0: isolated system or re-sistance earthed.
BI1 Enable BO1 0 0 1
To select whether the 1st binary input (BI1) trip the 1st binary output (BO1) or not. 1-enable, 0-disable
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298
Setting Unit Min. Max. Default setting
Description
BO1 Pulse Trip-ping
0 0 1
To select BO1 tripping in pulse mode or in direct mode 0- BO1 Direct Tripping, without delay 1- BO1 Pulse Tripping, with preset delay time
BI2 Enable BO2 0 0 1
To select whether the 2nd binary input (BI2) trip the 2nd binary output (BO2) or not. 1-enable, 0-disable
BO2 Pulse Trip-ping
0 0 1
To select BO2 tripping in pulse mode or in direct mode 0- BO2 Direct Tripping, without delay 1- BO2 Pulse Tripping, with preset delay time
BI1 Init HV CBF 0 0 1
whether BI1 initiate HV side
CBF or not
0 - initiate, 1 – not initiate
BI1 Init MV CBF 0 0 1
whether BI1 initiate MV side
CBF or not
0 - initiate, 1 – not initiate
BI1 Init LV CBF 0 0 1
whether BI1 initiate LV side
CBF or not
0 - initiate, 1 – not initiate
BI2 Init HV CBF 0 0 1
whether BI2 initiate HV side
CBF or not
0 - initiate, 1 – not initiate
BI2 Init MV CBF 0 0 1
whether BI2 initiate MV side
CBF or not
0 - initiate, 1 – not initiate
BI2 Init LV CBF 0 0 1
whether BI2 initiate LV side
CBF or not
0 - initiate, 1 – not initiate
Chapter 21 Appendix
299
2 General report list Table 182 event report list
Information Description
Relay startup The relay is initiated by startup elements
Per Diff Trip A
Treble slope percent Differential protection (ID>) trip for phase A/B/C Per Diff Trip B
Per Diff Trip C
Inst Diff Trip A
Instantaneous Differential protection (ID>>) trip for phase A/B/C Inst Diff Trip B
Inst Diff Trip C
HV REF Trip HV Restricted Earth fault (REF) protection trip
MV REF Trip MV Restricted Earth fault (REF) protection trip
LV REF Trip LV Restricted Earth fault (REF) protection trip
Def V/F Trip Overexcitation protection(V/F) tripping (Trip) with definite (DEF) and inverse(IVR) time characteristic Inv V/F Trip
HV OC Inv Trip Inverse time stage of HV overcurrent protection trip
HV OC1 Trip HV overcurrent stage 1 trip
HV OC2 Trip HV overcurrent stage 2 trip
MV OC Inv Trip Inverse time stage of MV overcurrent protection trip
MV OC1 Trip MV overcurrent stage 1 trip
MV OC2 Trip MV overcurrent stage 2 trip
LV OC Inv Trip Inverse time stage of LV overcurrent protection trip
LV OC1 Trip LV overcurrent stage 1 trip
LV OC2 Trip LV overcurrent stage 2 trip
HV EF Inv Trip Inverse time stage of HV earth fault protection trip
HV EF1 Trip HV earth fault stage 1 trip
HV EF2 Trip HV earth fault stage 2 trip
MV EF Inv Trip Inverse time stage of MV earth fault protection trip
MV EF1 Trip MV earth fault stage 1 trip
MV EF2 Trip MV earth fault stage 2 trip
Chapter 21 Appendix
300
Information Description
LV EF Inv Trip Inverse time stage of LV earth fault protection trip
LV EF1 Trip LV earth fault stage 1 trip
LV EF2 Trip LV earth fault stage 2 trip
HV NOC Inv Trip Inverse time stage of neutral OC protection trip
HV NOC1 Trip HV neutral OC stage 1 trip
HV NOC2 Trip HV neutral OC stage 2 trip
MV EF Inv Trip Inverse time stage of MV neutral OC protection trip
MV EF1 Trip MV neutral OC stage 1 trip
MV EF2 Trip MV neutral OC stage 2 trip
LV EF Inv Trip Inverse time stage of LV neutral OC protection trip
LV EF1 Trip LV neutral OC stage 1 trip
LV EF2 Trip LV neutral OC stage 2 trip
HV Therm OL Trip HV Thermal (TEM) Overload(OVLD) tripping (Trip)
MV Therm OL Trip MV Thermal (TEM) Overload(OVLD) tripping (Trip)
HV OV1 Trip HV overvoltage stage 1 trip
HV OV2 Trip HV overvoltage stage 2 trip
MV OV1 Trip MV overvoltage stage 1 trip
MV OV2 Trip MV overvoltage stage 2 trip
HV CBF1 Trip HV circuit breaker failure protection stage 1 trip
HV CBF2 Trip HV circuit breaker failure protection stage 2 trip
HV CBF Init Internal or external initiate HV circuit breaker failure protection
MV CBF1 Trip MV circuit breaker failure protection stage 1 trip
MV CBF2 Trip MV circuit breaker failure protection stage 2 trip
MV CBF Init Internal or external initiate MV circuit breaker failure protection
LV CBF1 Trip LV circuit breaker failure protection stage 1 trip
LV CBF2 Trip LV circuit breaker failure protection stage 2 trip
LV CBF Init Internal or external initiate LV circuit breaker failure protection
HV Dead Zone HV Dead zone trip
MV Dead Zone MV Dead zone trip
LV Dead Zone LV Dead zone trip
HV STUB Trip HV STUB protection trip
Chapter 21 Appendix
301
Information Description
MV STUB Trip MV STUB protection trip
LV STUB Trip LV STUB protection trip
HV PD Trip HV poles discordance protection trip
MV PD Trip MV poles discordance protection trip
HV VT Fail HV VT Fail alarm
MV VT Fail MV VT Fail alarm
LV VT Fail LV VT Fail alarm
Table 183 Alarm report list
No Abbr. (LCD Display) Description
1 Battery Off Battery off 2 BI Breakdown Binary input breakdown 3 BI Check Err Binary input checking is error
4 BI Comm Fail Binary input communication fail
5 BI Config Err Binary input configuration is error
6 BI EEPROM Err The EEPROM of binary input is error
7 BI Input Err Binary input error 8 BI_CBF Err Binary input error of CBF 9 BO Breakdown Binary output breakdown 10 BO Comm Fail Binary output communication fail
11 BO EEPROM Err The EEPROM of binary output is error
12 BO No Response No response of binary output
13 BOConfig Err Binary output configuration is error
14
CB Err Blk PD CB auxiliary contacts indicate that one pole is open but at the same time current is flowing through the pole.
15 CB Open A Err Binary input error of CB Open A
16 CB Open B Err Binary input error of CB Open B
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302
17 CB Open C Err Binary input error of CB Open C
18 CB Status Err CB Status Error 19 Def V/F Alarm Def V/F Alarm 20
Diff 2har Blk Inrush detection impose a blocking condi-tion to differential protection
21
Diff 3/5har Blk 3rd or 5th harmonic detection impose a blocking condition to differential protection
22 Diff Cur Alarm
Differential current exceeds the threshold value
23 EquipPara Err Equipment parameter is error
24 FLASH Check Err FLASH checking is error 25 H BI MCB VT Fail Binary input error of VT fail of MCB
26 H BI_V3P_MCB Err Binary input error of three phase MCB
27 HV 3U0 Alarm HV 3U0 Alarm 28 HV BLK VOL REGU Block tap changer control of transformer
29
HV Inrush Blk BU a blocking condition is imposed to backup protection by inrush condition detection
30 HV Load Alarm HV Load Alarm 31 HV OV1 Alarm Stage 1 of overvoltage protection alarm
32 HV OV2 Alarm Stage 2 of overvoltage protection alarm
33 HV REF 3I0 Alarm HV REF 3I0 Alarm 34 HV Therm OL Alm HV Thermal Overload Alarm
35 HV VT Fail HV VT Fail 36
HV1 I2 Alarm Negative-sequence current exceeds a thresh-old
37 HV2 I2 Alarm
Negative-sequence current exceeds a thresh-old
38 L BI MCB VT Fail Binary input error of VT fail of MCB
39 L BI_V3P_MCB Err Binary input error of three phase MCB
40 LV 3U0 Alarm LV 3U0 Alarm
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303
41 LV I2 Alarm
Negative-sequence current exceeds a thresh-old
42
LV Inrush Blk BU a blocking condition is imposed to backup protection by inrush condition detection
43 LV Load Alarm LV Load Alarm 44 LV REF 3I0 Alarm LV REF 3I0 Alarm 45 LV Therm OL Alm LV Thermal Overload Alarm
46 LV VT Fail LV VT Fail 47 LW Load Alarm LW Load Alarm 48 M BI MCB VT Fail Binary input error of VT fail of MCB
49 M BI_V3P_MCB Err Binary input error of three phase MCB
50 MV 3U0 Alarm MV 3U0 Alarm 51 MV BLK VOL REGU Block tap changer control of transformer
52 MV I2 Alarm
Negative-sequence current exceeds a thresh-old
53
MV Inrush Blk BU a blocking condition is imposed to backup protection by inrush condition detection
54 MV Load Alarm MV Load Alarm 55 MV OV1 Alarm Stage 1 of overvoltage protection alarm
56 MV OV2 Alarm Stage 2 of overvoltage protection alarm
57 MV REF 3I0 Alarm MV REF 3I0 Alarm 58 MV Therm OL Alm MV Thermal Overload Alarm
59 MV VT Fail MV VT Fail 60 NO/NC Discord NO/NC discord 61 Ph_A CT Fail Phase A CT Fail 62 Ph_B CT Fail Phase B CT Fail 63 Ph_C CT Fail Phase C CT Fail 64 ROM Verify Err ROM verifying is error 65 Sampling Err Sampling is error 66 Set Group Err Setting group is error 67 Setting Err Setting value is error 68 Soft Version Err Soft version is error 69 SRAM Check Err SRAM checking is error 70 Sys Config Err System configuration is error
Chapter 21 Appendix
304
71 Test BO Un_reset Do not reset after testing binary output
72 V or F Exceed
Voltage or frequency is out of the permissible range
Table 184 operation report list
No Information Description
1 Func_Diff On Differential protection is switched ON (by CW)
2 Func_Diff Off Differential protection is switched OFF (by CW)
3 HV Func_REF On HV REF protection is switched ON (by CW)
4 HV Func_REF Off HV REF protection is switched OFF (by CW)
5 MV Func_REF On MV REF protection is switched ON (by CW)
6 MV Func_REF Off MV REF protection is switched OFF (by CW)
7 LV Func_REF On LV REF protection is switched ON (by CW)
8 LV Func_REF Off LV REF protection is switched OFF (by CW)
9 Func_Overexc On Overexcitation protection is switched ON (by CW)
10 Func_Overexc Off Overexcitation protection is switched OFF (by CW)
11 HV Func_OC On
Overcurrent protection of HV side is switched ON (by CW)
12 HV Func_OC Off
Overcurrent protection of HV side is switched OFF (by CW)
13 MV Func_OC On
Overcurrent protection of MV side is switched ON (by CW)
14 MV Func_OC Off
Overcurrent protection of MV side is switched OFF (by CW)
15 LV Func_OC On
Overcurrent protection of LV side is switched ON (by CW)
16 LV Func_OC Off
Overcurrent protection of LV side is switched OFF (by CW)
17 HV Func_EF On
Earth fault protection of HV side is switched ON (by CW)
18 HV Func_EF Off
Earth fault protection of HV side is switched OFF (by CW)
19 MV Func_EF On
Earth fault protection of MV side is switched ON (by CW)
20 MV Func_EF Off
Earth fault protection of MV side is switched OFF (by CW)
21 LV Func_EF On
Earth fault protection of LV side is switched ON (by CW)
Chapter 21 Appendix
305
No Information Description
22 LV Func_EF Off
Earth fault protection of LV side is switched OFF (by CW)
23 HV Func_NOC On NOC protection of HV side is switched ON (by CW)
24 HV Func_NOC Off NOC protection of HV side is switched OFF (by CW)
25 MV Func_NOC On NOC protection of MV side is switched ON (by CW)
26 MV Func_NOC Off NOC protection of MV side is switched OFF (by CW)
27 LV Func_NOC On NOC protection of LV side is switched ON (by CW)
28 LV Func_NOC Off NOC protection of LV side is switched OFF (by CW)
29 HV Func_Therm On
HV thermal overload protection is switched ON (by CW)
30 HV Func_Therm Off
HV thermal overload protection is switched OFF (by CW)
31 MV Func_Therm On
MV thermal overload protection is switched ON (by CW)
32 MV Func_Therm Off
MV thermal overload protection is switched OFF (by CW)
33 HV Func_OL On HV overload protection is switched ON (by CW)
34 HV Func_OL Off HV overload protection is switched OFF (by CW)
35 MV Func_OL On MV overload protection is switched ON (by CW)
36 MV Func_OL Off MV overload protection is switched OFF (by CW)
37 LV Func_OL On LV overload protection is switched ON (by CW)
38 LV Func_OL Off LV overload protection is switched OFF (by CW)
39 HV Func_OV On HV overvoltage protection is switched ON (by CW)
40 HV Func_OV Off HV overvoltage protection is switched OFF (by CW)
41 MV Func_OV On MV overvoltage protection is switched ON (by CW)
42 MV Func_OV Off MV overvoltage protection is switched OFF (by CW)
43 HV Func_DZ On HV DZ function on
44 HV Func_DZ Off HV DZ function off
45 MV Func_DZ On MV DZ function on
46 MV Func_DZ Off MV DZ function off
47 LV Func_DZ On LV DZ function on
48 LV Func_DZ Off LV DZ function off
49 HV Func_STUB On HV STUB function on
50 HV Func_STUB Off HV STUB function Off
51 MV Func_STUB On MV STUB function on
52 MV Func_STUB Off MV STUB function Off
53 LV Func_STUB On LV STUB function on
54 LV Func_STUB Off LV STUB function Off
Chapter 21 Appendix
306
No Information Description
55 HV Func_PD On HV poles discordance function on
56 HV Func_PD Off HV poles discordance function off
57 MV Func_PD On MV poles discordance function on
58 MV Func_PD Off MV poles discordance function off
59 HV Func_VT On HV VT failure supervision function on
60 HV Func_VT Off HV VT failure supervision function off
61 MV Func_VT On MV VT failure supervision function on
62 MV Func_VT Off MV VT failure supervision function off
63 LV Func_VT On LV VT failure supervision function on
64 LV Func_VT Off LV VT failure supervision function off
Chapter 21 Appendix
307
3 Time inverse characteristic
3.1 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 185 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
3.2 User defined characteristic
For the inverse time characteristic, also can be set as user defined characteristic if the setting is set to 12.
K
Equation 39
Chapter 21 Appendix
308
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
4 CT Requirement
4.1 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 installa-tion 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.
4.2 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 per-formance 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 re-sistance may also be specified.
Class PX CT
Low leakage reactance for which knowledge of the transformer second-ary 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.
Chapter 21 Appendix
309
Class TPS CT
Low leakage flux current transient transformer for which performance is 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 tran-sient duty cycle. No limit for remanent flux.
Class TPY CT
Accuracy limit defined by peak instantaneous error during specified tran-sient duty cycle. Remanent flux not to exceed 10% of the saturation flux..
Class TPZ CT
Accuracy limit defined by peak instantaneous alternating current com-ponent error during single energization with maximum d.c. offset at specified secondary loop time constant. No requirements for d.c. com-ponent error limit. Remanent flux to be practically negligible.
TPE class CT (TPE represents transient protection and electronic type CT)
4.3 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
Chapter 21 Appendix
310
Rct Secondary winding d.c. resistance at 75 °C / 167 °F (or other specified temperature)
Rb Rated resistive burden R’b = Rlead + Rrelay = actual connected resistive
burden Rs Total resistance of the secondary circuit, inclu-
sive of the secondary winding resistance cor-rected 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
4.4 General current transformer requirements
4.4.1 Protective checking current
The current error of CT should be within the accuracy limit required at speci-fied fault current.
To verify the CT accuracy performance, Ipcf, primary protective checking current, should be chose properly and carefully.
For different protections, Ipcf is the selected fault current in proper fault po-sition 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 se-quence 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 perfor-mance
To reduce the influence of transient state, Kalf, Accuracy limit factor of CT,
Chapter 21 Appendix
311
should be larger than the following requirement
Ks, Specified transient factor, should be decided based on actual operation state and operation experiences by user.
4.4.2 CT class
The selected CT should guarantee that the error is within the required ac-curacy 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 ful-fill 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 gen-erator-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:
Chapter 21 Appendix
312
Where
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 gen-erally determined as follows:
Kalf: Accuracy limit factor
For PX class CT, Ek (rated knee point e.m.f) is generally determined as fol-lows:
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 21 Appendix
313
4.4.3 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.
4.4.4 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.
4.4.5 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 bur-den of the CT secondary circuit. Because 5A rated CTs, i.e. I2R is 25x com-pared to only 1x for a 1A CT. However, in some cases to reduce the CT secondary circuit open voltage, 5A can be applied.
4.4.6 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. Conse-quently, 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 21 Appendix
314
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 nor-mally 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.
4.5 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.
4.5.1 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.
For the CTs of high voltage side and middle voltage side, Eal should be ver-ified 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
Chapter 21 Appendix
315
recommended
For 220kV voltage level and below transformer differential protection, P Class, PR class and PX class is able to be used. Because the system time constant is less relatively, and then DC component is less, the probability of CT saturation due to through fault current at external fault is reduced more and more.
For P Class, PR class CT, Esl can be verified as below:
Where
Ks: Specified transient factor, 2 recommended
For PX class CT, Ek can be verified as below:
Where
Ks: Specified transient factor, 2 recommended