ps_guidelines.pdf

MODELSETTINGCALCULATIONSFORTYPICALIEDs
LINEPROTECTIONSETTINGGUIDELINES
PROTECTIONSYSTEMAUDITCHECKLIST
RECOMMENDATIONSFORPROTECTIONMANAGEMENT
SUB-COMMITTEE ON RELAY/PROTECTION UNDER TASK
FORCE FOR POWER SYSTEM ANALYSIS UNDER
CONTIGENCIES
New Delhi March 2014

Protection subcommittee report
Preamble
As a follow up of one of the recommendations of the Enquiry Committee headed by Chairman,
CEA on grid disturbances that took place in Indian grid on 30th and 31st July 2012, Ministry of
Power constituted a ‘Task Force on Power System Analysis under Contingencies’ in December
2012. The Terms of Reference of Task Force broadly cover analysis of the network behaviour
under normal conditions and contingencies, review of the philosophy of operation of protection
relays, review of islanding schemes and technological options to improve the performance of
the grid.
Apart from the main Task Force two more sub-committees were constituted. One for system
studies for July-September 2013 conditions and another for examining philosophy of relay and
protection coordination.
The tasks assigned to the protection sub-committee were to review the protection setting
philosophy (including load encroachment, power swing blocking, out of step protection, back-up
protections) for protection relays installed at 765kV, 400kV, 220kV (132kV in NER) transmission
system and prepare procedure for protection audit. This was submitted to the Task Force on
22.07.2013.
Further one more task assigned to the protection sub-committee was to prepare model setting
calculations for typical IEDs used in protection of 400kV line, transformer, reactor and busbar.
This document gives the model setting calculations, line protection setting guide lines,
protection system audit check lists, recommendations for protection system management and
some details connected with protection audit.

Acknowledgement
The Protection sub-committee thanks members of “Task Force for Power System Analysis
under Contingencies” for all the support and encouragement. Further the Protection sub-
committee acknowledges the contribution from Mr Rajil Srivastava, Mr Abhay Kumar, Mr
Kailash Rathore of Power Grid, Mr Shaik Nadeem of ABB and Mr Vijaya Kumar of PRDC to the
work carried out by the sub - committee.
Sub-committee
Convener
B.S. Pandey, Power Grid
Members
P. P. Francis, NTPC
S.G. Patki, Tata Power
R. H. Satpute, MSETCL
Nagaraja, PRDC
Bapuji Palki, ABB
Vikas Saxena, Jindal Power

LISTOFCONTENTS
Preamble
Section Description Pages
1 : Introduction 1-3
2 : Model setting calculations -Line 1-149
3 : Model setting calculations-Transformer 1-132
4 : Model setting calculations- Shunt Reactor 1-120
5 : Model setting calculations- Busbar 1-15
6 : Relay setting guide lines for transmission lines 1-19
7 : Recommendations for protection system management 1-5
8 : Check list for audit of fault clearance system 1-16
9 : Details of protection audit 1-5

- 1 -
MODEL SETTING CALCULATION DOCUMENTS FOR
TYPICAL IEDs USED FOR THE PROTECTION OF DIFFERENT
POWER SYSTEM ELEMENTS IN 220kV, 400kV AND 765 kV
SUBSTATIONS
INTRODUCTION
In addition to setting criteria guide lines prepared by Subcommittee on relay/protection under
Task Force for Power System Analysis under Contingencies for 220kV, 400kV and 765kV
transmission lines, the Subcommittee has prepared model setting calculation documents for
IEDs used for protection of following elements.
• 400kV Transmission line
• 400/220/33kV Auto Transformer
• 400kV Shunt Reactor
• 400kV Bus Bar
While guide lines as finalized by the Subcommittee have been used for the setting calculation
document on transmission lines, for other power system elements like transformer, shunt
reactor and bus bar, guide lines as given in CBIP documents and manufacturer's manuals have
been used. The documents presented should serve as a model to various utilities in preparing
similar documents for different power system elements that are used in 220kV, 400kV and
765kV EHV and UHV transmission systems. The documents are prepared to meet following
expectations given in the Protection subcommittee report.
The numerical terminals referred as IED (Intelligent electronic device) contain apart from main
protection functions several other protection & supervision functions which may or may not be
used for a particular application. Many of these functions are having default settings which may
not be suitable and may lead to mal-operations. Thus, it is important that the recommended
setting document should contain all the settings for all functions that are used and indicate
clearly the functions not used (to be Blocked / Disabled). This shall be followed not only for Line
protection IEDs but also for other IEDs like Generator, Transformer, Reactor, Bus bar protection

- 2 -
and Control functions. It is also recommended that graphical representation of distance relay
zones on R-X plane including phase selection, load encroachment & power swing
characteristics should be done showing exact setting calculated.
Each of these documents has following main sections:
1. BASIC SYSTEM PARAMETERS: This section contains all the system related information
including single line diagram that will be required in carrying out the setting calculations and
thus form an important part. This information is unique to each element like line, transformer,
reactor or busbar. This helps not only in carrying out the setting calculations; it also helps in
future, if there is a need to revisit this data.
2. TERMINAL IDENTIFICATION AND LIST OF FUNCTIONS: This section contains brief details
of the IED and lists all the functions that are available in the IED and clearly identifies the ones
which are activated and those that are required to be set. Thus this section serves as a checklist
of all the functions used and gives a quick overview of functions that needs to be set.
3. SETTING CALCULATIONS AND RECOMMENDED SETTINGS: This section contains
subsections viz., Setting guide lines, Setting calculations and Recommended settings for each
function.
Setting guidelines: This subsection contains guide lines for each of the parameter to be set for
the function. The guidelines are taken from the report prepared by Protection subcommittee and
CBIP guide lines mentioned in the report. In addition to the main settings the IED also has
various other settings that need to be set. Guide lines for these settings are taken mainly from
manufacturer's user manuals and these are also given here in brief. In such instances, where
the setting is straight forward and does not involve any calculations, the recommended value
are given and where applicable the reasoning for the adopted setting is given. Setting
calculation based on the relay type, relay function is a major concern for utilities and
understanding each setting and basis for setting helps in arriving at right settings. Further the
guide lines help not only in carrying out the setting calculations, but also help in future, if
there is a need to revisit the settings to take corrective actions in case of any mal-operations.
Setting calculations: This subsection contains details of calculations using system parameters
for those parameters that need calculations. Other parameters that do not require any
calculations are not covered here. Making setting calculations after understanding the power
system implications and as per setting guidelines helps not only in arriving at the right settings
but also helps in future, if there is a need to revisit them to take corrective action in case of any

- 3 -
mal-operations (if excel based sheets with macros are used for setting calculations, they should
be used cautiously in a transparent manner and explained the reasoning associated with
macros / formulae).
Recommended settings: This subsection details recommended setting list with settings for all
the parameters. Settings given in this section need to be used by site engineer for setting the
IED.
It is recommended that these model setting calculations are reviewed periodically to take care of
any changes in manufacturer's design, use of simulation tools, RTDS, or better understanding
of settings and guidelines etc. It is also recommended that setting calculation documents are
prepared for IEDs of different manufacturers that are used in the system.
Disclaimer: The model setting calculations and recommended settings presented in this
document are for the specific case considered here. Further, the make of the relay considered is
also for illustration purpose only. In the settings which do not require any calculations based on
network data, few of the settings may need review for other practical cases. For settings that
require calculations, power system network data pertaining to respective cases is to be
considered. However, the methodology adopted in this example shall be used for calculating the
line and other equipment protection relay settings and arriving at list of recommended settings.

MODEL SETTING CALCULATION DOCUMENT FOR A TYPICAL
IED USED FOR TRANSMISSION LINE PROTECTION

Model setting calculation document for Transmission Line
2
TABLE OF CONTENTS
TABLE OF CONTENTS...............................................................................................................2
1.0 BASIC SYSTEM PARAMETERS .........................................................................................8
1.1 Network line diagram of the protected line and adjacent circuits ...................................8
1.2 Single line diagram of the double circuit line....................................................................9
1.3 Line parameters ..................................................................................................................9
2.0 TERMINAL IDENTIFICATION AND LIST OF FUNCTIONS................................................10
2.1 REL670...............................................................................................................................10
2.1.1 Terminal Identification..........................................................................................10
2.1.2 List of functions available and those used............................................................10
2.2 REC670 ..............................................................................................................................16
2.2.1 Terminal identification..........................................................................................16
2.2.2 List of functions available and those used............................................................16
3.0 SETTING CALCULATIONS AND RECOMMENDED SETTINGS FOR REL670.................23
3.1 REL670...............................................................................................................................23
3.1.1 Analog Inputs.......................................................................................................23
3.1.2 Local Human-Machine Interface ..........................................................................26
3.1.3 Indication LEDs....................................................................................................26
3.1.4 Time Synchronization ..........................................................................................28
3.1.5 Parameter Setting Groups ...................................................................................31
3.1.6 Test Mode Functionality TEST.............................................................................32
3.1.7 IED Identifiers......................................................................................................34
3.1.8 Rated System Frequency PRIMVAL....................................................................35
3.1.9 Signal Matrix For Analog Inputs SMAI .................................................................35
3.1.10 General settings of Distance protection zones .....................................................37
3.1.11 Distance Protection Zone, Quadrilateral Characteristic (Zone 1) ZMQPDIS.........39
3.1.12 Distance Protection Zone, Quadrilateral Characteristic (Zone 2) ZMQAPDIS .....44
3.1.13 Distance Protection Zone, Quadrilateral Characteristic (Zone 3) ZMQAPDIS ......47
3.1.14 Distance Protection Zone, Quadrilateral Characteristic (Zone 5) ZMQAPDIS ......50
3.1.15 Phase Selection with Load Encroachment, Quadrilateral Characteristic FDPSPDIS
54
3.1.16 Broken Conductor Check BRCPTOC (Normally used for Alarm purpose only) ....62
3.1.17 Tripping Logic SMPPTRC....................................................................................63
3.1.18 Trip Matrix Logic TMAGGIO.................................................................................65
3.1.19 Automatic Switch Onto Fault Logic, Voltage And Current Based ZCVPSOF........66
3.1.20 Power Swing Detection ZMRPSB ........................................................................68
3.1.21 Scheme Communication Logic For Distance Or Overcurrent Protection ZCPSCH
76
3.1.22 Stub Protection STBPTOC ..................................................................................77
3.1.23 Fuse Failure Supervision SDDRFUF ...................................................................78
3.1.24 Four Step Residual Overcurrent Protection EF4PTOC ........................................81
3.1.25 Two Step Overvoltage Protection OV2PTOV.......................................................85
3.1.26 Setting of fault locator values LFL........................................................................89
3.1.27 Disturbance Report DRPRDRE ...........................................................................90
3.2 REC670 ..............................................................................................................................93

3
3.2.1 Analog Inputs.......................................................................................................93
3.2.2 Local Human-Machine Interface ..........................................................................95
3.2.3 Indication LEDs....................................................................................................96
3.2.4 Time Synchronization ..........................................................................................97
3.2.5 Parameter Setting Groups .................................................................................101
3.2.6 Test Mode Functionality TEST...........................................................................102
3.2.7 IED Identifiers....................................................................................................103
3.2.8 Rated System Frequency PRIMVAL..................................................................103
3.2.9 Signal Matrix For Analog Inputs SMAI ...............................................................103
3.2.10 Synchrocheck function (SYN1) ..........................................................................106
3.2.11 Autorecloser SMBRREC....................................................................................110
3.2.12 Disturbance Report DRPRDRE .........................................................................118
APPENDIX-A: COORDINATION OF 400KV LINE PROTECTION ZONE-2 AND ZONE-3 WITH
IDMT O/C & E/F RELAYS OF 400KV SIDE OF ICT AND 220KV LINE...................................121
APPENDIX-B: EFFECT OF NETWORK CHANGE DUE TO A LINE LILO ON RELAY
SETTINGS OF LILO LINE & ADJACENT LINES....................................................................131

4
LIST OF FIGURES
Figure 1-1: Network line diagram of the protected line ....................................................................................... 8
Figure 1-2: Equivalent representation of the protected line with source impedance .......................................... 9
Figure 3-1: Setting angles for discrimination of forward and reverse fault........................................................ 37
Figure 3-2: Characteristic for phase-to-earth measuring, ohm/loop domain..................................................... 39
Figure 3-3: Characteristic for phase-to-phase measuring................................................................................. 40
Figure 3-4: Relation between distance protection ZMQPDIS and FDPSPDIS for phase-to-earth fault
φloop>60°........................................... ............................................................................................................... 54
Figure 3-5: Relation between distance protection (ZMQPDIS) and FDPSPDIS characteristic for phase-to-
phase fault for φline>60°........................................... ........................................................................................ 55
Figure 3-6: Load encroachment characteristic.................................................................................................. 56
Figure 3-7: Operating characteristic for ZMRPSB function ............................................................................... 68
Figure 3-8: Characteristics for Phase to Phase faults....................................................................................... 75
Figure 3-9: Characteristics for Phase to Earth faults ........................................................................................ 76
Figure A-1: System details for the network under consideration for relay setting........................................... 123
Figure A-2: 3-Ph fault current for 220 kV side fault ......................................................................................... 124
Figure A-3: Over Current Relay Curve Co-ordination and Operating Time .................................................... 125
Figure A-4: Ph-G fault current for 220 kV side fault ........................................................................................ 126
Figure A-5: Earth Fault Relay Curve Co-ordination and Operating Time ....................................................... 127
Figure A-6: Earth fault relay co-ordination for 400 kV bus fault at Station B (Remote bus of the protected line)
......................................................................................................................................................................... 128
Figure A-7: Earth fault relay operating time co-ordinated with Zone 3 time setting ....................................... 129
Figure B-1: Network line diagram of the system after the LILO of one circuit of line AB ................................ 131
Figure B-2: SLG Fault at bus B with source at Station A and Line A-S out of service and Earthed............... 134
Figure B-3: SLG Fault at bus B with sources at Station A & B and Line A-S out of service and Earthed ...... 135
Figure B-4: SLG Fault at bus B with sources at Station A, B & S and Line A-S out of service and Earthed.. 136
Figure B-5: SLG Fault at bus B with source at Station A and Line B-S out of service and Earthed............... 137
Figure B-6: SLG Fault at bus B with sources at Station A & B and Line B-S out of service and Earthed ...... 138
Figure B-7: SLG Fault at bus B with sources at Station A, B & S and Line B-S out of service and Earthed.. 139
Figure B-8: SLG Fault at bus S with source at Station A and Line A-B out of service and Earthed............... 140
Figure B-9: SLG Fault at bus S with sources at Station A & B and Line A-B out of service and Earthed ...... 141
Figure B-10: SLG Fault at bus S with sources at Station A, B & S and Line A-B out of service and Earthed 142
Figure B-11: SLG Fault at bus B with source at Station A .............................................................................. 143
Figure B-12: SLG Fault at bus B with sources at Station A and B.................................................................. 144
Figure B-13: SLG Fault at bus B with sources at Station A, B & S ................................................................. 145
Figure B-14: SLG Fault at bus S with source at Station A .............................................................................. 146
Figure B-15: SLG Fault at bus S with sources at Station A and B.................................................................. 147
Figure B-16: SLG Fault at bus S with sources at Station A, B & S ................................................................. 148

5
LIST OF TABLES
Table 2-1: List of functions in REL670 .......................................................................................................... 10
Table 2-2: List of functions in REC670.......................................................................................................... 16
Table 3-1: Analog inputs................................................................................................................................. 24
Table 3-2: Local human machine interface ....................................................................................................... 26
Table 3-3: LEDGEN Non group settings (basic) ............................................................................................... 27
Table 3-4: Time synchronization settings.......................................................................................................... 29
Table 3-5: Parameter setting group................................................................................................................... 32
Table 3-6: Test mode functionality .................................................................................................................... 34
Table 3-7: IED Identifiers................................................................................................................................... 34
Table 3-8: Rated system frequency .................................................................................................................. 35
Table 3-9: Signal Matrix For Analog Inputs....................................................................................................... 36
Table 3-10: General settings for distance protection ........................................................................................ 38
Table 3-11: ZONE 1 Settings ............................................................................................................................ 43
Table 3-12: ZONE 2 Settings ............................................................................................................................ 46
Table 3-13: ZONE 3 Settings........................................................................................................................... 49
Table 3-14: ZONE 5 Settings........................................................................................................................... 52
Table 3-15: Phase Selection with Load Encroachment, Quadrilateral Characteristic ...................................... 61
Table 3-16: Broken Conductor Check ............................................................................................................... 63
Table 3-17: Tripping Logic................................................................................................................................. 64
Table 3-18: Trip Matrix Logic............................................................................................................................. 65
Table 3-19: Automatic Switch Onto Fault Logic ................................................................................................ 67
Table 3-20: Power Swing Detection............................................................................................................... 73
Table 3-21: Scheme Communication Logic For Distance Or Overcurrent Protection ...................................... 77
Table 3-22: Stub Protection............................................................................................................................... 78
Table 3-23: Fuse Failure Supervision ............................................................................................................... 79
Table 3-24: Four Step Residual Overcurrent Protection................................................................................... 83
Table 3-25: Two Step Overvoltage Protection .................................................................................................. 86
Table 3-26: Setting of fault locator values......................................................................................................... 89
Table 3-27: Disturbance Report ........................................................................................................................ 92
Table 3-28: Analog Inputs ................................................................................................................................. 93
Table 3-29: Local human machine interface ..................................................................................................... 96
Table 3-30: LEDGEN Non group settings (basic) ............................................................................................. 96
Table 3-31: Time Synchronization..................................................................................................................... 99
Table 3-32: Parameter Setting Groups ........................................................................................................... 102
Table 3-33: Test Mode Functionality............................................................................................................... 102
Table 3-34: IED Identifiers............................................................................................................................... 103
Table 3-35: Rated System Frequency............................................................................................................. 103
Table 3-36: Signal Matrix For Analog Inputs................................................................................................... 105
Table 3-37: Synchrocheck function ................................................................................................................. 108
Table 3-38: Autorecloser ................................................................................................................................. 116
Table 3-39: Disturbance Report ...................................................................................................................... 119
Table A-1 Settings of Over current and Earth fault relays............................................................................... 122
Table B-1: Fault At Station-B With Source At Station – A and Line A-S Earthed ........................................... 134
Table B-2: Fault At Station-B With Sources At Station – A & B and Line A-S Earthed.......................... 135
Table B-3: Fault At Station-B With Sources At Station – A, B & S and Line A-S Earthed .............................. 136
Table B-4: Fault At Station-B With Source At Station – A and Line B-S Earthed ................................... 137
Table B-5: Fault At Station-B With Source At Station – A & B and Line B-S Earthed .................................... 138
Table B-6: Fault At Station-S With Source At Station – A and Line A-B Earthed ........................................... 140
Table B-7: Fault At Station-S With Sources At Station – A & B and Line A-B Earthed.......................... 141
Table B-8: Fault At Station-S With Sources At Station – A, B & S and Line A-B Earthed ..................... 142
Table B-9: Fault At Station-B With Source At Station A............................................................................ 143
Table B-10: Fault At Station-B With Sources At Station – A & B .................................................................... 144
Table B-11: Fault At Station-B With Sources At Station – A, B and S ............................................................ 145
Table B-12: Fault At Station-S Without Sources At Station – S & B ............................................................... 146

6
Table B-13: Fault At Station-S With Sources At Station – A & B .................................................................... 147
Table B-14: Fault At Station-S With Sources At Station – A, B & S................................................................ 148

7
SETTING CALCULATION EXAMPLE
SUB-STATION: Station-A
FEEDER: 400kV OHL from Station-A to Station-B
PROTECTION ELEMENT: Main-I Protection
Protection schematic Drg. Ref. No. XXXXXX

8
1.0 BASIC SYSTEM PARAMETERS
1.1 Network line diagram of the protected line and adjacent circuits
The network line diagram (Figure 1-1) of the system under consideration showing
protected line along with adjacent associated elements should be collected. The
network diagram should indicate the voltage level, line length, transformer/generator
rated MVA & fault contributions of each element for 3-ph fault at station-A and for
3-ph fault at Station-B.
Figure 1-1: Network line diagram of the protected line

9
1.2 Single line diagram of the double circuit line
Equivalent representation of the protected line based on network line diagram indicated at Figure 1-
1 is prepared as shown in Figure 1-2 indicating the source fault impedance at station-A and Station-
B, positive and zero sequence impedance of the protected line.
Figure 1-2: Equivalent representation of the protected line with source impedance
1.3 Line parameters
Line: Substation-A to Substation-B
Frequency: 50Hz
Line data: R1 + jX1 = 0.0288 + j0.307 Ω/km
R0 + jX0 = 0.2689 + j1.072 Ω/km
R0M + jX0M = 0.228 + j0.662 Ω/km
Line length: 190km
CT ratio: 1000/1A
CVT ratio: 400/0.11kV
Maximum expected load on line both import and export: This shall be obtained from the load flow
analysis of the power system under all possible contingency. From the load flow studies, 1500MVA
is the maximum expected load under worst contingency on this line at 90% system voltage.
Station-A
Protected Line 190km
190km
400kV 400kV
R1SA= 0.486Ω
X1SA= 13.939Ω
R1SB= 0.895Ω
X1SB=9.525Ω
Z1 = 5.472+j58.33 Ω
Z0 = 51.091+j203.68 Ω
Station-B

10
2.0 TERMINAL IDENTIFICATION AND LIST OF FUNCTIONS
The various functions required for the line protection are divided in two IEDs namely REL670 and
REC670 for the purpose of illustration. The terminal identification of this and list of various functions
available in these IEDs are given in this section.
2.1 REL670
2.1.1 Terminal Identification
Station Name: Station-A
Object Name: 400kV OHL from Station-A to Station-B
Unit Name: REL670 (Ver 1.2)
Relay serial No: XXXXXXXX
Frequency: 50Hz
Aux voltage: 220V DC
2.1.2 List of functions available and those used
Table 2-1 gives the list of functions/features available in REL670 relay and also indicates the
functions/feature for which settings are provided in this document. The functions/feature are
indicative and varies with IED ordering code & IED application configuration.
Table 2-1: List of functions in REL670
Sl.No. Function/features available In REL670
Function/feature
activated
Yes/No
Recommended
Settings
provided
1 Analog Inputs YES
2 Local Human-Machine Interface YES
3 Indication LEDs YES
4 Self supervision with internal event list YES
5 Time Synchronization YES
6 Parameter Setting Groups YES
7 Test Mode Functionality TEST YES

11
Function/feature
activated
Yes/No
Recommended
Settings
provided
8 Change Lock CHNGLCK NO
9 IED Identifiers YES
10 Product Information YES
11 Rated System Frequency PRIMVAL YES
12 Signal Matrix For Binary Inputs SMBI YES
13 Signal Matrix For Binary Outputs SMBO YES
14 Signal Matrix For mA Inputs SMMI NO
15 Signal Matrix For Analog Inputs SMAI YES
16 Summation Block 3 Phase 3PHSUM NO
17 Authority Status ATHSTAT NO
18 Denial Of Service DOS NO
19
Distance Protection Zone, Quadrilateral
Characteristic (Zone 1) ZMQPDIS
YES
20
Characteristic (Zone 2) ZMQAPDIS
YES
21
YES
22
NO
23
YES
24 Directional Impedance Quadrilateral ZDRDIR YES
25
Phase Selection With Load Encroachment,
Quadrilateral Characteristic FDPSPDIS
YES
26 Power Swing Detection ZMRPSB YES

12
Function/feature
activated
Yes/No
Recommended
Settings
provided
27
Automatic Switch Onto Fault Logic, Voltage
And Current Based ZCVPSOF
YES
28
Instantaneous Phase Overcurrent Protection
PHPIOC
NO
29
Four Step Phase Overcurrent Protection
OC4PTOC
NO
30
Instantaneous Residual Overcurrent Protection
EFPIOC
NO
31
Four Step Residual Overcurrent Protection
EF4PTOC
YES
32
Sensitive Directional Residual Overcurrent And
Power Protection SDEPSDE
NO
33
Thermal Overload Protection, One Time
Constant LPTTR
NO
34 Stub Protection STBPTOC YES
35 Broken Conductor Check BRCPTOC YES
36 Two Step Undervoltage Protection UV2PTUV YES
37 Two Step Overvoltage Protection OV2PTOV YES
38 Loss Of Voltage Check LOVPTUV NO
39
General Current And Voltage Protection
CVGAPC-4 functions
NO
40 Current Circuit Supervision CCSRDIF NO
41 Fuse Failure Supervision SDDRFUF YES
42
Horizontal Communication Via GOOSE For
Interlocking GOOSEINTLKRCV
NO
43
Logic Rotating Switch For Function Selection
And LHMI Presentation SLGGIO
NO
44 Selector Mini Switch VSGGIO NO

13
Function/feature
activated
Yes/No
Recommended
Settings
provided
45 Generic Double Point Function Block DPGGIO NO
46
Single Point Generic Control 8 Signals
SPC8GGIO
NO
47
Automationbits, Command Function For
DNP3.0 AUTOBITS
NO
48 Single Command, 16 Signals SINGLECMD NO
49
Scheme Communication Logic For Distance Or
Overcurrent Protection ZCPSCH
YES
50
Current Reversal And Weak-End Infeed Logic
For Distance Protection ZCRWPSCH
NO
51 Local Acceleration Logic ZCLCPLAL NO
52 Direct Transfer Trip Logic YES
53
Low Active Power And Power Factor Protection
LAPPGAPC
NO
54
Compensated Over and Undervoltage
Protection COUVGAPC
NO
55
Sudden Change in Current Variation
SCCVPTOC
NO
56 Carrier Receive Logic LCCRPTRC NO
57
Negative Sequence Overvoltage Protection
LCNSPTOV
NO
58
Zero Sequence Overvoltage Protection
LCZSPTOV
NO
59
Negative Sequence Overcurrent Protection
LCNSPTOC
NO
60
Zero Sequence Overcurrent Protection
LCZSPTOC
NO
61 Three Phase Overcurrent LCP3PTOC NO
62 Three Phase Undercurrent LCP3PTUC NO

14
Function/feature
activated
Yes/No
Recommended
Settings
provided
63 Tripping Logic SMPPTRC YES
64 Trip Matrix Logic TMAGGIO YES
65 Configurable Logic Blocks NO
66 Fixed Signal Function Block FXDSIGN NO
67 Boolean 16 To Integer Conversion B16I NO
68
Boolean 16 To Integer Conversion With Logic
Node
Representation B16IFCVI
NO
69 Integer To Boolean 16 Conversion IB16 NO
70
Integer To Boolean 16 Conversion With Logic
Node
Representation IB16FCVB
NO
71 Measurements CVMMXN YES
72 Phase Current Measurement CMMXU YES
73 Phase-Phase Voltage Measurement VMMXU YES
74
Current Sequence Component Measurement
CMSQI
YES
75 Voltage Sequence Measurement VMSQI YES
76 Phase-Neutral Voltage Measurement VNMMXU NO
77 Event Counter CNTGGIO YES
78 Event Function EVENT YES
79 Logical Signal Status Report BINSTATREP NO
80 Fault Locator LMBRFLO YES
81 Measured Value Expander Block RANGE_XP NO
82 Disturbance Report DRPRDRE YES

15
Function/feature
activated
Yes/No
Recommended
Settings
provided
83 Event List YES
84 Indications YES
85 Event Recorder YES
86 Trip Value Recorder YES
87 Disturbance Recorder YES
88 Pulse-Counter Logic PCGGIO NO
89
Function For Energy Calculation And Demand
Handling ETPMMTR
NO
90 IEC 61850-8-1 Communication Protocol NO
91
IEC 61850 Generic Communication I/O
Functions SPGGIO, SP16GGIO
NO
92
IEC 61850-8-1 Redundant Station Bus
Communication
NO
93 IEC 61850-9-2LE Communication Protocol NO
94 LON Communication Protocol NO
95 SPA Communication Protocol NO
97
Multiple Command And Transmit
MULTICMDRCV,
MULTICMDSND
NO
98 Remote Communication NO
Note: For setting parameters provided in the function listed above, refer section 3 of
application manual 1MRK506315-UEN, version 1.2.

16
2.2 REC670
2.2.1 Terminal identification
Object Name: 400kV OHL
Unit Name: REC670 (Ver 1.2)
Relay serial No: XXXXX
Frequency: 50Hz
Table 2-2 gives the list of functions/features available in REC670 relay and also indicates the
indicative and varies with IED ordering code IED application configuration.
Table 2-2: List of functions in REC670
Sl.No. Functions/Feature available In REC670
Features/Functions
activated
Yes/No
Recommended
Settings
provided
1 Analog Inputs YES

17
Features/Functions
activated
Yes/No
Recommended
Settings
provided
14 Signal Matrix For Ma Inputs SMMI NO
19 Differential Protection HZPDIF NO
20
Instantaneous Phase Overcurrent Protection
PHPIOC
NO
21
OC4PTOC
NO
22
Instantaneous Residual Overcurrent
Protection EFPIOC
NO
23
EF4PTOC
NO
24
Four step directional negative phase
sequence overcurrent protection NS4PTOC
NO
25
Sensitive Directional Residual Overcurrent
And Power Protection SDEPSDE
NO
26
Constant LPTTR
NO
27
Thermal overload protection, two time
constants TRPTTR
NO
28 Breaker Failure Protection CCRBRF NO
29 Stub Protection STBPTOC NO
30 Pole Discordance Protection CCRPLD NO

18
Features/Functions
activated
Yes/No
Recommended
Settings
provided
31
Directional Underpower Protection
GUPPDUP
NO
32
Directional Overpower Protection
GOPPDOP
NO
33 Broken Conductor Check BRCPTOC NO
34 Capacitor bank protection CBPGAPC NO
35
Two Step Undervoltage Protection
UV2PTUV
NO
36 Two Step Overvoltage Protection OV2PTOV NO
37
Two Step Residual Overvoltage Protection
ROV2PTOV
NO
38 Voltage Differential Protection VDCPTOV NO
40 Underfrequency Protection SAPTUF NO
41 Overfrequency Protection SAPTOF NO
42
Rate-Of-Change Frequency Protection
SAPFRC
NO
43
General Current and Voltage Protection
CVGAPC
NO
45 Fuse Failure Supervision SDDRFUF NO
46
Synchrocheck, Energizing Check, And
Synchronizing SESRSYN
YES
47 Autorecloser SMBRREC YES
48 Apparatus Control APC NO
49
NO

19
Features/Functions
activated
Yes/No
Recommended
Settings
provided
50
Logic Rotating Switch For Function
Selection And LHMI Presentation SLGGIO
NO
52
Generic Double Point Function Block
DPGGIO
NO
53
SPC8GGIO
NO
54
DNP3.0 AUTOBITS
NO
56
Scheme Communication Logic For Distance
Or Overcurrent Protection ZCPSCH
NO
57
Phase Segregated Scheme Communication
Logic For Distance Protection ZC1PPSCH
NO
58
Current Reversal And Weak-End Infeed
Logic For Distance Protection ZCRWPSCH
NO
60
Scheme Communication Logic For Residual
Overcurrent Protection ECPSCH
NO
61
Logic For Residual Overcurrent Protection
ECRWPSCH
NO
62
Logic For Phase Segregated
Communication ZC1WPSCH
NO
63 Direct Transfer Trip Logic NO
64
Low Active Power And Power Factor
Protection LAPPGAPC
NO
65
Compensated Over And Undervoltage
Protection COUVGAPC
NO

20
Features/Functions
activated
Yes/No
Recommended
Settings
provided
66
Sudden Change In Current Variation
SCCVPTOC
NO
68
LCNSPTOV
NO
69
LCZSPTOV
NO
70
LCNSPTOC
NO
71
LCZSPTOC
NO
74 Tripping Logic SMPPTRC NO
75 Trip Matrix Logic TMAGGIO NO
79
Boolean 16 To Integer Conversion With
Logic Node
Representation B16IFCVI
NO
81
Integer To Boolean 16 Conversion With
Logic Node
Representation IB16FCVB
NO

21
Features/Functions
activated
Yes/No
Recommended
Settings
provided
84
Phase-Phase Voltage Measurement
VMMXU
YES
85
Current Sequence Component
Measurement CMSQI
YES
87
Phase-Neutral Voltage Measurement
VNMMXU
NO
91 Fault Locator LMBRFLO NO
92
Measured Value Expander Block
RANGE_XP
NO
94 Event List YES
95 Indications YES
100
Function For Energy Calculation And
Demand Handling ETPMMTR
NO
102
IEC 61850 Generic Communication I/O
NO
103
Communication
NO

22
Features/Functions
activated
Yes/No
Recommended
Settings
provided
108
MULTICMDRCV,
MULTICMDSND
NO

23
3.0 SETTING CALCULATIONS AND RECOMMENDED
SETTINGS FOR REL670
The various functions required for the line protection are divided in two IEDs namely REL670 and
REC670. The setting calculations and recommended settings for various functions available in
these IEDs are given in this section.
3.1 REL670
3.1.1 Analog Inputs
Guidelines for Settings:
Configure analog inputs:
Current analog inputs as:
Ch 1 Ch 2 Ch 3 Ch 4 Ch 5 Ch 6
Name# IL1-CB1 IL2-CB1 IL3-CB1 IL1-CB2 IL2-CB2 IL3-CB2
CTprim 1000A 1000A 1000A 1000A 1000A 1000A
CTsec 1A 1A 1A 1A 1A 1A
CTStarPoint parameter indicates the CT secondary winding neutral earthing towards object
(ToObject) or towards busbar (FromObject).
Voltage analog input as:
Name# UL1 UL2 UL3 UL2BUS1 UL2BUS2 UL2L2
VTprim 400kV 400kV 400kV 400kV 400kV 400kV
VTsec 110V 110V 110V 110V 110V 110V
# User defined text

24
Recommended Settings:
Table 3-1 gives the recommended settings for the analog inputs.
Table 3-1: Analog inputs
Setting
Parameter
Description
Recommended
Settings Unit
PhaseAngleRef
Reference channel for phase angle
Presentation
TRM40-Ch1 -
CTStarPoint1
ToObject= towards protected object,
FromObject= the opposite
ToObject -
CTsec1 Rated CT secondary current 1 A
CTprim1 Rated CT primary current 1000 A
CTStarPoint2
ToObject -
CTStarPoint3
ToObject -
CTStarPoint4
ToObject -
CTStarPoint5
ToObject -
CTStarPoint6 ToObject= towards protected object, ToObject -

25
Setting
Parameter
Description
Recommended
Settings Unit
VTsec7 Rated VT secondary voltage 110 V
VTprim7 Rated VT primary voltage 400 kV
Binary input module (BIM) Settings
Operation OscBlock(Hz) OscRelease(Hz)
I/O Module 1 On 40 30 Pos Slot3
Note: OscBlock and OscRelease defines the filtering time at activation. Low frequency gives slow
response for digital input.

26
3.1.2 Local Human-Machine Interface
Table 3-2 gives the recommended settings for Local human machine interface.
Table 3-2: Local human machine interface
Setting
Parameter
Description
Recommended
Settings Unit
Language Local HMI language English -
DisplayTimeout Local HMI display timeout 60 Min
AutoRepeat
Activation of auto-repeat (On) or not
(Off)
On -
ContrastLevel Contrast level for display 0 %
DefaultScreen Default screen 0 -
EvListSrtOrder Sort order of event list Latest on top -
SymbolFont Symbol font for Single Line Diagram IEC -
3.1.3 Indication LEDs
This function block is to control LEDs in HMI.
SeqTypeLED1: Normally this parameter is set to LatchedAck-S-F. When trip occurs, it will glow
steady and latched till manually reset. When manually reset, it will go OFF when trip is not there. If
trip still persist, it will flash.
tRestart: Not applicable for the above case.
tMax: Not applicable for the above case.

27
Table 3-3 gives the recommended settings for Indication LEDs.
Table 3-3: LEDGEN Non group settings (basic)
Setting
Parameter
Description
Recommended
Settings Unit
Operation Operation mode for the LED function On -
tRestart Defines the disturbance length 0.0 s
tMax
Maximum time for the definition of a
disturbance
0.0 s
SeqTypeLED1 Sequence type for LED 1 LatchedAck-S-F -

28
3.1.4 Time Synchronization
These settings are used for synchronizing IED clock time with network time. Ex: GPS or IRIG-B time.
CoarseSyncSrc: Select the time synchronization source available such as SPA, LON, SNTP etc.
Synchronization messages from sources configured as coarse are checked against the internal relay
time and only if the difference in relay time and source time is more than 10s then relay time will be
reset with the source time. This parameter need to be based on time source available in site.
FineSyncSource: Select the time source available in network like IRIG-B, GPS, SNTP, SPA etc.
once it is selected, time of available time source in network will update to relay if there is a difference
in the time between relay and source. This parameter need to be based on time source available in
site.
SyncMaster: Normally it is set OFF. If time to the relay is received from a GPS antenna (example),
make the relay as master to synchronize with other relays.
TimeAdjustRate: Fast
HWSyncSrc: This is applicable if process bus IEC61850-9-2 protocol is used for receiving analog
values (optical CT PTs). In this case select time source available same as that of merging unit. This
setting is not applicable in present case.
AppSynch: If there is any loss of time sync, protection function will be blocked if AppSynch set to
Synch based on SyncAccLevel. If AppSunch set to NoSynch, protection functions are not blocked.
Recommended setting is NoSynch.
SyncAccLevel: If this is set to “Class T5 (1us)” and time synch error is more than 1us, protection
functions will be blocked. SyncAccLevel should be set to “Unspecified” when Nosynch is selected at
AppSynch. This parameter is not applicable in present case.
ModulePosition: if BIN is set for FineSyncSource, ModulePosition setting is applicable. Here slot
position of IO module in the relay is to be set (Which slot is used for BI). This parameter is not
applicable in present case.
BinaryInput: Which binary input is used for time sync input shall be set here. This parameter is
applicable if BIN is set for FineSyncSource. This parameter is not applicable in present case.
BinDetection: Which edge of input pulse need to be detected has to be set here (positive and
negative). This parameter is applicable if BIN is set for FineSyncSource. This parameter is not
ServerIP-Add: Here set Time source server IP address.
RedServIP-Add: If redundant server is available, set address of redundant server here.

29
MonthInYear, DayInWeek, WeekInMonth and UTCTimeOfDay for DSTBEGIN and DSTEND are
applicable where Day light saving is used. If it is not used set same date for both DSTBEGIN and
DSTEND. This setting is not applicable in this case.
NoHalfHourUTC: Time shift from GMT has to be set a multiple of half hours. Example for India it is
+05:30, means +11. Hence this parameter is set to +11 in present case.
SYNCHIRIG-B Non group settings: These settings are applicable if IRIG-B is used. This parameter
is not applicable in present case.
SynchType: Type of hardware input used for time sync, whether Opto or BNC. This parameter is not
TimeDomain: In present case this parameter is set to LocalTime.
Encoding: In present case this parameter is set to IRIG-B.
TimeZoneAs1344: In present case this parameter is set to PlusTZ.
Table 3-4 gives the recommended settings for Time synchonization.
Table 3-4: Time synchronization settings
TIMESYNCHGEN Non group settings (basic)
Setting
Parameter
Description
Recommended
Settings Unit
CoarseSyncSrc Coarse time synchronization source Off -
FineSyncSource Fine time synchronization source 0.0 -
SyncMaster Activate IED as synchronization master Off -
TimeAdjustRate Adjust rate for time synchronization Off -
HWSyncSrc Hardware time synchronization source Off -
AppSynch Time synchronization mode for application NoSynch -
SyncAccLevel Wanted time synchronization accuracy Unspecified -

30
SYNCHBIN Non group settings (basic)
Setting
Parameter
Description
Recommended
Settings Unit
ModulePosition
Hardware position of IO module for time
Synchronization
3 -
BinaryInput
Binary input number for time
synchronization
1 -
BinDetection Positive or negative edge detection PositiveEdge -
SYNCHSNTP Non group settings (basic)
Setting Parameter Description
Recommended
Settings Unit
ServerIP-Add Server IP-address 0.0.0.0 IP Address
RedServIP-Add Redundant server IP-address 0.0.0.0 IP Address
DSTBEGIN Non group settings (basic)
Setting
Parameter
Description
Recommended
Settings Unit
MonthInYear Month in year when daylight time starts March -
DayInWeek Day in week when daylight time starts Sunday -
WeekInMonth
Week in month when daylight time
starts
Last -
UTCTimeOfDay
UTC Time of day in seconds when
daylight time starts
3600 s

31
DSTEND Non group settings (basic)
Setting
Parameter
Description
Recommended
Settings Unit
MonthInYear Month in year when daylight time starts October -
WeekInMonth
starts
Last -
UTCTimeOfDay
3600 s
TIMEZONE Non group settings (basic)
Setting
Parameter
Description
Recommended
Settings Unit
NoHalfHourUTC Number of half-hours from UTC +11 -
SYNCHIRIG-B Non group settings (basic)
Setting
Parameter
Description
Recommended
Settings Unit
SynchType Type of synchronization Opto -
TimeDomain Time domain LocalTime -
Encoding Type of encoding IRIG-B -
TimeZoneAs1344 Time zone as in 1344 standard PlusTZ -
Note: Above setting parameters have to be set based on available time source at site.
3.1.5 Parameter Setting Groups

32
t: The length of the pulse, sent out by the output signal SETCHGD when an active group has
changed, is set with the parameter t. This is not the delay for changing setting group. This parameter
is normally recommended to set 1s.
MAXSETGR: The parameter MAXSETGR defines the maximum number of setting groups in use to
switch between. Only the selected number of setting groups will be available in the Parameter
Setting tool (PST) for activation with the ActiveGroup function block. This parameter is normally
recommended to set 1.
Table 3-5 gives the recommended settings for Parameter setting group.
Table 3-5: Parameter setting group
ActiveGroup Non group settings (basic)
Setting
Parameter
Description
Recommended
Settings Unit
t
Pulse length of pulse when setting
Changed
1 s
SETGRPS Non group settings (basic)
Setting
Parameter
Description
Recommended
Settings Unit
ActiveSetGrp ActiveSettingGroup SettingGroup1 -
MAXSETGR Max number of setting groups 1-6 1 No
3.1.6 Test Mode Functionality TEST
EventDisable: If it is ON, it will disable the events like in DR during test mode. Normally this
parameter is set to OFF.
CmdTestBit: In present case this parameter is set to Off.

33
Table 3-6 gives the recommended settings for Test mode functionality.

34
Table 3-6: Test mode functionality
TESTMODE Non group settings (basic)
Setting
Parameter
Description
Recommended
Settings Unit
TestMode Test mode in operation (On) or not (Off) Off -
EventDisable Event disable during testmode Off -
CmdTestBit
Command bit for test required or not
during testmode
Off -
3.1.7 IED Identifiers
Table 3-7 gives the recommended settings for IED Identifiers.
Table 3-7: IED Identifiers
TERMINALID Non group settings (basic)
Setting
Parameter
Description
Recommended
Settings Unit
StationName Station name Station-A -
StationNumber Station number 0 -
ObjectName Object name Line-1 -
ObjectNumber Object number 0 -
UnitName Unit name REL670 M1 -
UnitNumber Unit number 0 -

35
3.1.8 Rated System Frequency PRIMVAL
Table 3-8 gives the recommended settings for Rated system frequency.
Table 3-8: Rated system frequency
PRIMVAL Non group settings (basic)
Setting
Parameter
Description
Recommended
Settings Unit
Frequency Rated system frequency 50.0 Hz
3.1.9 Signal Matrix For Analog Inputs SMAI
DFTReference: Set ref for DFT filter adjustment here. These DFT reference block settings decide
DFT reference for DFT calculations.
The settings InternalDFTRef will use fixed DFT reference based on set system frequency.
AdDFTRefChn will use DFT reference from the selected group block, when own group selected
adaptive DFT reference will be used based on calculated signal frequency from own group. The
setting ExternalDFTRef will use reference based on what is connected to input DFTSPFC.
There are three different task groups of SMAI with 1ms, 3ms and 8ms. Use of each task group is
based on requirement of function, like differential protection requires 1ms, which is faster.
Each task group has 12 instances of SMAI, in that first instance has some additional features which
is called master. Others are slaves and they will follow master. If measured sample rate needs to be
transferred to other task group, it can be done only with master.
Receiving task group SMAI DFTreference shall be set to External DFT Ref.
DFTReference shall be set to default value InternalDFTRef if no VT input is available. Since VT input
is available in this case, the corresponding channel shall be set to DFTReference. Configuration file
has to be referred for this purpose.
DFTRefExtOut: This parameter is available only in Master. If reference is to be sent to other task
group, which reference need to be send has to be select here. For example, if voltage input is

36
connected to 3rd
SMAI of 1ms task group, AdDFTRefCh3 is to be set in DFTRefExtOut of 1ms task
group.
DFTRefExtOut shall be set to default value InternalDFTRef if no VT input is available. Configuration
file has to be referred for this purpose.
Negation: Set negation of the function block here. If R, Y, B and N inputs are connected and
Negation is set to NegateN, it will give output R, Y, B and –N. If Negation is set to Negate3Ph, it will
give output -R, -Y, -B and N.
If R, Y, B inputs are connected, N=R+Y+B, and it will do as above. This parameter is recommended
to be set to OFF normally.
MinValFreqMeas: Set the measured minimum value here. It is applicable only for voltage input.
SMAI will work only if measured input magnitude is greater than set value in MinValFreqMeas. This
parameter is recommended to set 10% normally.
UBase: Set the base voltage here. This is parameter is set to 400kV.
Table 3-9 gives the recommended settings for Signal Matrix For Analog Inputs.
Table 3-9: Signal Matrix For Analog Inputs
Setting
Parameter
Description
Recommended
Settings Unit
DFTRefExtOut DFT reference for external output InternalDFTRef -
DFTReference DFT reference InternalDFTRef -
ConnectionType Input connection type Ph-Ph -
TYPE 1=Voltage, 2=Current
1 or 2 based on
input
Ch
Negation Negation Off -
MinValFreqMeas
Limit for frequency calculation in % of
UBase
10 %
UBase Base voltage 400 kV

37
3.1.10 General settings of Distance protection zones
Figure 3-1 gives the setting angles for discrimination of forward and reverse fault.
ArgDir and ArgNegRes: Set the Directional angle Distance protection zones at ArgDir and set the
Negative restraint angle for Distance protection zone at ArgNegRes.
The setting of ArgDir and ArgNegRes is by default set to 15 (= -15) and 115°respectively. It should
not be changed unless system studies have shown the necessity.
IBase: set to the current value of the primary winding of the CT. This parameter is set to 1000A in
present case.
UBase: set to the voltage value of the primary winding of the VT. This parameter is set to 400kV in
present case.
IMinOpPP: This is the minimum current required in phase to phase fault for directionality purpose.
To be set to 20% of IBase.
IMinOpPE: This is the minimum current required in phase to earth fault for directionality purpose.
Figure 3-1: Setting angles for discrimination of forward and reverse fault

38
Table 3-10 gives the recommended settings for General settings for distance protection.
Table 3-10: General settings for distance protection
ZDRDIR Group settings (basic)
Setting
Parameter
Description
Recommended
Settings Unit
IBase Base setting for current level 1000 A
UBase Base setting for voltage level 400 kV
IMinOpPP
Minimum operate delta current for
Phase-Phase loops
20 %IB
IMinOpPE
Minimum operate phase current for
Phase-Earth loops
20 %IB
ArgNegRes
Angle of blinder in second quadrant for
forward direction
115 Deg
ArgDir
Angle of blinder in fourth quadrant for
forward direction
15 Deg

39
3.1.11 Distance Protection Zone, Quadrilateral Characteristic (Zone 1)
ZMQPDIS
General guide lines for Setting Distance protection Zones:
The zones are set directly in primary ohms R, X. The primary ohms R, X are recalculated to
secondary ohms with the current and voltage transformer ratios. Figures 3-2 and 3-3 show the
characteristics for phase-to-earth measuring and phase-to-phase measuring respectively.
The secondary values are presented as information for zone testing.
Figure 3-2: Characteristic for phase-to-earth measuring, ohm/loop domain

40
Figure 3-3: Characteristic for phase-to-phase measuring
Guidelines for Setting:
Zone-1:
Setting X1, R1 and X0, R0: To be set to cover 80% of protected line length. Zero sequence
compensation factor is (Z0 – Z1) / 3Z1.
RFPP and RFPE: For phase to ground faults, resistive reach should be set to give maximum
coverage considering fault resistance, arc resistance tower footing resistance. It has been
considered that ground fault would not be responsive to line loading.
Setting of the resistive reach for the underreaching zone 1 should follow the condition to minimize
the risk for overreaching:
RFPE ≤ 4.5 × X1

41
In case of phase to phase fault, resistive reach should be set to provide coverage against all types
of anticipated phase to phase faults subject to check of possibility against load point encroachment
considering minimum expected voltage and maximum load expected during short time emergency
system condition.
To minimize the risk for overreaching, limit the setting of the zone 1 reach in resistive direction for
phase-to-phase loop measurement to:
RFPP ≤ 3 × X1.
IBase: Set the Base current for the Distance protection zones in primary Ampere here. Set to the
current value of the primary winding of the CT. This parameter is set to 1000A in present case.
UBase: Set the Base voltage for the Distance protection zones in primary kV here. Set to the
voltage value of the primary winding of the VT. This parameter is set to 400kV in present case.
IMinOpPP: Setting of minimum sensitivity for zone Phase-Phase elements. Measures IL-IL for each
loop. This is the minimum current required in phase to phase fault for zone measurement. To be set
to 20% of IBase.
IMinOpPE: Setting of minimum operating current for Phase faults. Measures ILx. This is the
minimum current required in phase to earth fault for zone measurement. To be set to 20% of IBase.
IMinOpIN: This is the minimum 3I0 current required in phase to earth fault for zone measurement.
Setting Calculations:
OperationDir = Forward
Operation PP = On
Operation PE = On
Zone 1 phase fault reach is set to 80.0% of the total line reactance
X1Z1' = 46.664Ω Note! Zone will send carrier signal
The secondary setting will thus be
X1Z1 = 12.833Ω
Set the positive sequence resistance for phase faults to (this gives the characteristic angle)
R1Z1' = 4.378Ω
R1Z1 = 1.204Ω
Setting of zone earth fault zero sequence values
X0Z1' = 162.944Ω 80.0% of the total line reactance

42
X0Z1 = 44.81Ω
Set the zero sequence resistance for earth faults to
R0Z1' = 40.873Ω
R0Z1 = 11.24Ω
Setting of the fault resistive cover
The resistive reach(phase to Phase) is set to cover a maximum expected fault resistance arrived
from Warrington formula given below
Rarc =
It is set to 15.0 Ω. (Considering a minimum expected ph to ph fault current of 1500A and arc length
of 15meter).
Note that setting of fault resistance is the loop value whereas reactance setting is phase value for
phase faults.
The resistive reach (phase to earth) is set as 50 Ω keeping a value of 10 Ω for tower footing
resistance, arc-resistance of 15Ω and remote end infeed effect of 25Ω (considering equal fault feed
from both side)
Set the resistive reach for phase faults to:
RFPPZ1' = 30Ω (loop value)
RFPPZ1 = 8.25Ω
Set the resistive reach for earth faults to
RFPEZ1´= 50Ω
RFPEZ1 = 13.75Ω
Set the Base current for the Distance protection zones in primary Ampere.
Zone 1 setting of timers.
Setting of Zone timer activation for phase-phase and earth faults
tPP1 = On
tPE1 = On
Setting of Zone timers:
tPP1 = 0s
tPE1 = 0s

43
Table 3-11 gives the recommended settings for ZONE 1 Settings.
Table 3-11: ZONE 1 Settings
Setting
Parameter
Description
Recommended
Settings Unit
Operation Operation Off / On On -
IBase Base current , i.e rated current 1000 A
Ubase Base voltage , i.e.rated voltage 400.00 kV
OperationDir Operation mode of directionality Forward -
X1 Positive sequence reactance reach 46.664 ohm/p
R1 Positive sequence resistance reach 4.378 ohm/p
X0 Zero sequence reactance reach 162.944 ohm/p
R0 Zero sequence resistance for zone 40.873 ohm/p
RFPP Fault resistance reach in ohm/loop , Ph-Ph 30 ohm/l
RFPE Fault resistance reach in ohm/loop , Ph-E 50 ohm/l
Operation
PP
Operation mode Off/On of Ph-Ph loops On -
Timer tPP
Operation mode Off/On of Zone timer, Ph-
Ph
On -
tPP Time delay of trip,Ph-Ph 0.000 s
Operation
PE
Operation mode Off/On of Ph-E loops On -
Timer tPE Operation mode Off/On of Zone timer, Ph-E On -
tPE Time delay of trip,Ph-E 0.000 s
IMinOpPP
Minimum operate delta current for Phase-
Phase loops
20 %IB
IMinOpPE
Minimum operate phase current for Phase-
Earth loops
20 %IB

44
IMinOpIN
Minimum operate residual current for
Phase-Earth loops
10 %IB
ZMQAPDIS
Setting X1, R1 and X0, R0:
To be set to cover minimum 120% of length of principle line section. However, in case of double
circuit lines 150% coverage must be provided to take care of under reaching due to mutual coupling
effect. Zero sequence compensation factor is (Z0 – Z1) / 3Z1.
tPP and tPE settings:
A Zone-2 timing of 0.35s (considering LBB time of 200mS, CB open time of 60ms, resetting time of
30ms and safety margin of 60ms) is set for the present case.
RFPP and RFPE:
Guidelines given for resistive reach under zone-1 is applicable here also. Due to in-feeds, the
apparent fault resistance seen by relay is several times the actual value. This should be kept in
mind while arriving at resistive reach setting for Zone-2.
to 20% of IBase.

45
Operation PP = On
Operation PE = On
Zone 2 phase fault reach is set to 150.0% of the total line reactance
X1Z2' = 87.495Ω Zone is accelerated at receipt of Carrier signal.
X1Z2 = 24.061Ω
R1Z2' = 8.208Ω
R1Z2 = 2.257Ω
X0Z2' = 305.52Ω 150.0% of the total line reactance
X0Z2 = 84.018Ω
R0Z2' = 76.637Ω
R0Z2 = 21.075Ω
The resistive reach for phase to phase is set to cover a maximum expected fault resistance of
30.0Ω
(Considering a factor of 2 on the Zone-1 resistive reach value to take care of in-feed effect)
RFPPZ2' = 60Ω
RFPPZ2 =16.5Ω
RFPEZ2´= 75Ω
RFPPZ2 = 20.625Ω

46
Zone 2 timers setting
tPP2 = On
tPE2 = On
tPP2 = 0.35s
tPE2 = 0.35s
Note: In this case, Zone-2 reach is not encroaching into 220kV side of the transformer due to in-
feeds and therefore zone-2 tripping delay need not be coordinated with HV side backup protection
of Transformer as explained in Appendix-I.
Setting
Parameter
Description
Recommended
Settings Unit
IBase Base current , i.e. rated current 1000 A
Ubase Base voltage , i.e. rated voltage 400.00 kV
RFPP
Fault resistance reach in ohm/loop , Ph-
Ph
60 ohm/l
Operation PP Operation mode Off/On of Ph-Ph loops On -
Timer tPP
Operation mode Off/On of Zone timer,
Ph-Ph
On -

47
Setting
Parameter
Description
Recommended
Settings Unit
Operation PE Operation mode Off/On of Ph-E loops On -
Timer tPE
Operation mode Off/On of Zone timer,
Ph-E
On -
tPE Time delay of trip,Ph-E 0.35 s
IMinOpPP
Phase loops
20 %IB
IMinOpPE
Phase-Earth loops
20 %IB
ZMQAPDIS
Setting X1, R1 and X0, R0: Zone-3 should overreach the remote terminal of the longest adjacent
line by an acceptable margin (typically 20% of highest impedance seen) for all fault conditions.
Zero sequence compensation factor is (Z0 – Z1) / 3Z1.
tPP and tPE settings: Zone-3 timer should be set so as to provide discrimination with the
operating time of relays provided in subsequent sections with which Zone-3 reach of relay
being set, overlaps. In present case, Zone-3 time is set to 1.0s.
RFPP and RFPE: Guidelines given for resistive reach under zone-1 is applicable here also. Due to
in-feeds, the apparent fault resistance seen by relay is several times the actual value. This should
be kept in mind while arriving at resistive reach setting for Zone-3.

48
to 20% of IBase.
Operation PP = On
Operation PE = On
Setting of zone 3 Phase fault reach
Zone 3 phase fault reach is set to 120% of sum of protected line and adjacent longest lines
reactance is considered. Effect of in-feed not considered for practical reasons in the Zone-3 reach
setting.
X1Z3' = 199.304Ω
X1Z3 = 54.809Ω
R1Z3' = 18.697Ω
R1Z3 = 5.142Ω
X0Z3' = 695.942Ω 120% of sum of protected line and adjacent longest lines
reactance is considered.
X0Z3 = 191.384Ω
R0Z3' = 174.57Ω
R0Z3 = 48Ω
The resistive reach is set considering in-feed factor of 2.5 over Zone-1 resistive reach of 15.0 Ω for
Ph-Ph fault and 50Ω for Ph-E fault)

49
The faults on remote lines will have in-feed of fault current through the fault resistance from other
remote feeders which will make an apparent increase of the value. The setting is selected to take
care of above factors. Set the resistive reach for phase faults to:
RFPPZ3' = 75Ω (Loop value)
RFPPZ3 = 20.625Ω
RFPEZ3´= 125Ω
RFPEZ3 = 34.375Ω
Zone 3 timers setting
tPP3 = On
tPE3 = On
tPP3 = 1s
tPE3 = 1s
Note: In this case, Zone-3 reach is not encroaching into 220kV side of the transformer due to in-
feeds and therefore zone-3 tripping delay need not be coordinated with HV side backup protection
of Transformer as explained in Appendix-I.
Setting
Parameter
Description
Recommended
Settings Unit

50
Setting
Parameter
Description
Recommended
Settings Unit
Operation
PP
Timer t1PP Operation mode Off/On of Zone timer, Ph-Ph On -
tPP Time delay of trip,Ph-Ph 1 s
Operation
PE
Timer t1PE Operation mode Off/On of Zone timer, Ph-E On -
t1PE Time delay of trip,Ph-E 1 s
IMinOpPP
Phase loops
20 %IB
IMinOpPE
Phase-Earth loops
20 %IB
ZMQAPDIS
Setting X1, R1 and X0, R0: Reverse reach setting shall be 50% of shortest line connected to the
local bus bar. Zero sequence compensation factor is (Z0 – Z1) / 3Z1.
tPP and tPE settings: Zone-5 time delay would only need to co-ordinate with bus bar main
protection fault clearance and with Zone-1 fault clearance for lines out of the same substation. For
this reason, Zone-5 time is set as 0.35s.
RFPP and RFPE: The Zone-5 reverse reach must adequately cover expected levels of apparent
bus bar fault resistance, when allowing for multiple in feeds from other circuits. For this reason, its
resistive reach setting is to be kept identical to Zone-3 resistive reach setting.

51
to 20% of IBase.
OperationDir = Reverse
Operation PP = On
Operation PE = On
Zone 5 phase fault reach is set to 50.0% of the shortest line reactance connected to the same bus.
X1Z5' = 6.14Ω
X1Z5 = 1.689Ω
R1Z5' = 0.576Ω
R1Z5 = 0.158Ω
X0Z5' = 21.44Ω
X0Z5 = 5.896Ω
R0Z5' = 5.378Ω
R0Z5 = 1.479Ω
RFPPZ5' = 75Ω

52
RFPPZ5 = 20.625Ω
RFPEZ5´= 125Ω
RFPPZ5 = 34.375Ω
Zone 5 (Reverse Zone) timers setting
tPP5 = On
tPE5 = On
tPP5 = 0.35s
tPE5 = 0.35s
Note: Time setting of this zone is not overlapping with zone-2 time of the adjacent shortest line on
the same bus.
Setting
Parameter
Description
Recommended
Settings Unit
OperationDir Operation mode of directionality Reverse -

53
Setting
Parameter
Description
Recommended
Settings Unit
Operation
PP
Timer t1PP Operation mode Off/On of Zone timer, Ph-Ph On -
Operation
PE
Timer t1PE Operation mode Off/On of Zone timer, Ph-E On -
t1PE Time delay of trip,Ph-E 0.35 s
IMinOpPP
Phase loops
20 %IB
IMinOpPE
Minimum operate phase current for Phase-
Earth loops
20 %IB

54
3.1.15 Phase Selection with Load Encroachment, Quadrilateral Characteristic
FDPSPDIS
Figures 3-4, 3-5 and 3-6 show the characteristics for Phase selector and load encroachment:
1-FDPSPDIS (red line), 2-ZMQPDIS, 3-RFRvPEPHS, 4-(X1PHS+XN)/tan(60°
), 5-RFFwPEPHS, 6-
RFPEZm, 7-X1PHS+XN, 8-φloop, 9-X1ZM+XN
Figure 3-4: Relation between distance protection ZMQPDIS and FDPSPDIS for phase-to-earth
fault φloop60°

55
1-FDPSPDIS (red line), 2-ZMQPDIS, 3-0.5 x RFRvPP PHS, 4- X1PHS/ tan (60°
), 5-0.5 x
RFFwPPPHS, 6-0.5 x RFPPZm, 7-X1PHS, 8-X1Zm
Figure 3-5: Relation between distance protection (ZMQPDIS) and FDPSPDIS characteristic
for phase-to-phase fault for φline60°

56
RLdFw: Forward resistive reach within the load impedance area
RLdRv: Reverse resistive reach within the load impedance area
ArgLd: Load angle determining the load impedance reach
Figure 3-6: Load encroachment characteristic
With the extended Zone-3 reach settings, that may be required to address the many under reaching
factors already considered, load impedance encroachment is a significant risk to long lines of an
interconnected power system. Not only the minimum load impedance under expected modes of
system operation be considered in risk assessment, but also the minimum impedance that might be
sustained for seconds or minutes during abnormal or emergency system conditions. Failure to do
so could jeopardize power system security.
For high resistive earth fault where impedance locus lies in the Blinder zone, fault clearance shall be
provided by the back-up directional earth fault relay.
IBase: Set the Base current for the Phase selection function in primary Ampere here. Set to the
UBase: set to the voltage value of the primary winding of the VT. This parameter is set to 400kV in
present case.
INBlockPP: Setting of phase-phase blocking current element for other phases at an earth fault. It is
3I0 limit for blocking phase-to-phase measuring loop. To be set 40% of IPh.
INReleasePE: Setting of Neutral release current (shall be set below minimum neutral current
expected at earth faults) here. It is the setting for the minimum residual current needed to enable
operation in the phase to earth fault loops (in %). To be set 20% of IPh.

57
3I0 residual current must fulfill the conditions according to the equations given below
3.I0 ≥ 0.5× IMinOpPE
|3.I0| ≥ . Iphmax
where:
IMinOpPE is the minimum operation current for forward zones
Iphmax is the maximum phase current in any of three phases.
Conditions that have to be fulfilled in order to release the phase-to-phase loop are:
3I0 IMinOpPE
|3.I0| . Iphmax
where:
IMinOpPE is the minimum operation current for earth measuring loops,
Iphmax is maximal magnitude of the phase currents.
Guidelines for Load encroachment:
The minimum load impedance can be calculated on the basis of maximum permitted power flow of
1500MVA over the protected line and minimum permitted system voltage. Minimum permitted system
voltage assumed is 360kV (90% of base voltage)
For setting angle for load blinder, a value of 30° is set which is adequate.
Guidelines for Phase selection:
Reactive reach
The reactive reach in forward direction must as minimum be set to cover the measuring zone used
in the Teleprotection schemes, mostly zone 2.
X1PHS ≥ 1.44 × X1Zm
X0PHS ≥ 1.44 ×X0Zm
where:
X1Zm is the reactive reach for the zone to be covered by FDPSPDIS, and the constant 1.44 is a
safety margin
X0Zm is the zero-sequence reactive reach for the zone to be covered by FDPSPDIS
The reactive reach in reverse direction is automatically set to the same reach as for forward
direction. No additional setting is required.
Fault resistance reach
The resistive reach must cover RFPE for the overreaching zone to be covered, mostly zone 2.
RFFwPEmin ≥ 1.1 × RFPEZm

58
where:
RFPEZm is the setting RFPE for the longest overreaching zone to be covered by FDPSPDIS.
Phase-to-earth fault in reverse direction
Reactive reach
The reactive reach in reverse direction is the same as for forward so no additional setting is
required.
Resistive reach
The resistive reach in reverse direction must be set longer than the longest reverse zones. In
blocking schemes it must be set longer than the overreaching zone at remote end that is used in the
communication scheme.
RFRvPE ≥ 1.2 ×RFPE ZmRv
Phase-to-phase fault in forward direction
Reactive reach
The reach in reactive direction is determined by phase-to-earth reach setting X1.
No extra setting is required.
Resistive reach
In the same way as for phase-to-earth fault, the reach is automatically calculated based on setting
X1. The reach will be X1/tan(60°
) =X1/ √(3).
Fault resistance reach
The fault resistance reaches in forward direction RFFwPP, must cover RFPPZm with at least 25%
margin. RFPPZm is the setting of fault resistance for phase to phase fault for the longest
overreaching zone to be covered by FDPSPDIS
RFFwPP ≥ 1.25 × RFPPZm
where:
RFPPZm is the setting of the longest reach of the overreaching zones that must be covered by
FDPSPDIS .
RFRvPP ≥ 1.25 × RFPPzmRv
The proposed margin of 25% will cater for the risk of cut off of the zone measuring characteristic
that might occur at three-phase fault when FDPSPDIS characteristic angle is changed from 60°to
90°
.
to 20% of IBase.

59
Calculations for Load encroachment:
Ur = 400kV, Umin = 0.90x400 = 360kV,
CT ratio = 1000/1A and PT ratio = 400kV/110V
Maximum load in MVA = 1500
ZLmin = 360 x 360/ (1500),
= 86.4Ω
RLmin = 86.4 x cos30 = 74.82Ω. Since considered load angle = 30°
RLdFw = 74.82Ω
It is important to adjust the setting of load encroachment resistance RLdFw in Phase selection with
load encroachment (FDPSPDIS) to the value equal to or less than the calculated value of RLdInFw
in power swing.
In present case RLdInFw = 54.62Ω (calculations are given in PSB settings)
But calculated value of RLdFw for a maximum load of 1500MVA is 74.82Ω. Hence as per the above
recommendation from manual, RLdFw is set to 54.62Ω instated of 74.82Ω.
RLdFw = 54.62Ω.
RLdFw' = 11.375Ω
Set the load limitation in the reverse (import) direction
RLdRv = 41.297Ω
RLdRv' = 11.375Ω
Set the angle of the load limitation line
ARGLd = 30°
Calculations for Phase selection:
Phase selector phase fault reach is set to 144.0% of Zone 2 reach setting as per REL670 manual.
Positive sequence reactance as set for the reach of phase selectors in reactive direction
X1 = 125.993Ω (1.44 x Zone-2 X1)
X1 = 34.648Ω
Earth fault reach zero sequence component is set to 144.0% of Zone 2 zero sequence value

60
Zero sequence reactance as set for the reach of phase selectors in reactive direction at phase-to-
earth faults
X0 = 439.95Ω
X0 = 120.986Ω
Reach of the phase selector in resistive direction at ph-to-ph faults (Note! In ohms per loop)
RFFwPP = 75Ω (1.25 x Zone-2 RFPP)RFRvPP = 75Ω
RFFwPP = 20.625Ω RFRvPP = 20.625Ω
Reach of the phase selector in resistive direction at phase-to-earth faults
RFFwPE = 90Ω (1.2 x Zone-2 RFPE) RFRvPE = 90Ω
RFFwPE = 24.75Ω RFRvPE = 24.75Ω
Note: The reach of phase selectors should cover only zone-2. If it is set to cover zone-3 it may
become large and phase selection may not be accurate.
Operation of impedance based measurement
OperationZ = On
Operation of current based measurement
OperationI = On
Start value for phase over-current element
IPh = 120% x Ibase
Start value for trip from 3I0 over-current element
IN = 20% x Ibase
Operation mode Off / On of Zone timer, Ph-Ph
TimerPP = Off
Time delay to trip, Ph-Ph
tPP = 3.000s
Operation mode Off / On of Zone timer, Ph-E
TimerPE = Off
Time delay to trip, Ph-E
tPE = 3.000s

61
Table 3-15 gives the recommended settings for Phase Selection with Load Encroachment,
Quadrilateral Characteristic.
Table 3-15: Phase Selection with Load Encroachment, Quadrilateral Characteristic
Setting
Parameter
Description
Recommended
Settings Unit
UBase Base voltage , i.e rated voltage 400 kV
INBlockPP
3Io limit for blocking phase-to-phase
measuring loops
40 %IPh
INReleasePE
3Io limit for releasing phase-to-earth
measuring loops
20 %IPh
RLdFw
Forward resistive reach within the load
impedance area
54.62 ohm/p
RLdRv
Reverse resistive reach within the load
impedance area
54.62 ohm/p
ArgLd
Load angle determining the load
impedance reach
30 Deg
RFFwPP Fault resistance reach Ph-Ph, forward 75 ohm/l
RFRvPP Fault resistance reach Ph-Ph, reverse 75 ohm/l
RFFwPE Fault resistance reach Ph-E, forward 90 ohm/l
RFRvPE Fault resistance reach Ph-E, reverse 90 ohm/l
IMinOpPP
Phase loops
20 %IB
IMinOpPE
3Io limit for blocking phase-to-earth
measuring loops
20 %IB
OperationZ Operation of impedance based On -

62
Setting
Parameter
Description
Recommended
Settings Unit
measurement
OperationI Operation of current based measurement On -
IPh Start value for phase over-current element 120 %IB
IN
Start value for trip from 3I0 over-current
element
20 %IB
TimerPP
Operation mode Off / On of Zone timer,
Ph-Ph
Off -
tPP Time delay to trip, Ph-Ph 3.000 s
TimerPE
Ph-E
Off -
tPE Time delay to trip, Ph-E 3.000 s
3.1.16 Broken Conductor Check BRCPTOC (Normally used for Alarm purpose
only)
Broken conductor check BRCPTOC must be set to detect open phase/s (series faults) with different
loads on the line. BRCPTOC must at the same time be set to not operate for maximum asymmetry
which can exist due to, for example, not transposed power lines.
All settings are in primary values or percentage.
IBase: Set the Base current for the function on which the current levels are based. Set IBase to
power line rated current or CT rated current. This parameter is set to 1000A in present case.
IP: Set the operating current for BRC function at which the measurement starts. Unsymmetry for
trip is 20% Imax-min. Set minimum operating level per phase IP to typically 10-20% of rated
current. Normally this parameter is recommended to set 20% of IBase.
Iub: Set the unsymmetry level. Note! One current must also be below 50% of IP. Set the
unsymmetrical current, which is relation between the difference of the minimum and maximum
phase currents to the maximum phase current to typical Iub = 50%.

63
For example, If line load current is 1000A, 1000A and 1000A in all 3 phases, when an conductor is
broken in R-ph, currents will be 0A, 1000A and 1000A respectively. Then Iub = (1000-0)/1000 =
100%, which is more 50% (set value), hence relay will give Alarm/trip.
Note that it must be set to avoid problem with asymmetry under minimum operating conditions.
tOper: Setting of the time delay for the alarm or trip of function. This parameter is normally set to
20s.
tReset: Time delay in reset. This parameter is normally set to 0.1s.
Table 3-16 gives the recommended settings for Broken Conductor Check.
Table 3-16: Broken Conductor Check
Setting
Parameter
Description
Recommended
Settings Unit
IBase IBase 1000 A
Iub
Unbalance current operation value in
percent of max current
50 %IM
IP
Minimum phase current for operation of
Iub in % of Ibase
20 %IB
tOper Operate time delay 20.00 s
tReset Time delay in reset 0.100 s
3.1.17 Tripping Logic SMPPTRC
All trip outputs from protection functions has to be routed to trip coil through SMPPTRC.
For example, If there is a transient fault, trip output from distance function will not be long enough to
open breaker in case Distance function trip signal is directly connected to Trip coil. SMPPTRC
function will give a pulse of set length (150ms) even if trip signal is obtained for transient fault.

64
tTripMin: Sets the required minimum duration of the trip pulse. It should be set to ensure that the
breaker is tripped and if a signal is used to start Breaker failure protection CCRBRF longer than the
back-up trip timer in CCRBRF. Normal setting is 0.150s.
Program: For Line protection trip, this parameter is recommended to be set to 1ph/3ph. If only 3-ph
trip is required, this needs to be set to 3 phase. In present case it is to be set to 1ph/3ph.
tWaitForPHS: It Secures 3-pole trip when phase selection fails. For example, if fault is at 90% of
protected line in R-ph, Zcom trip is obtained using scheme communication. SMPPTRC will wait for
Zone-2 R-ph sart till the time delay set in tWaitForPHS to trip R-ph at local end. If no Zone-2 R-ph
start from local end, it will issue a 3-ph trip after the time delay set in tWaitForPHS. This parameter
is set to 0.050s.
TripLockout: If this set to ON, Trip output and CLLKOUT both will be latched. If it is set off, only
CLLKOUT will be latched. Normally recommended setting is OFF.
AutoLock: If it is ON, lockout will be with both trip and SETLKOUT input. If it is set to OFF, lockout
will be with only SETLKOUT input. This parameter is normally recommended to be set to OFF.
Table 3-17 gives the recommended settings for Tripping Logic.
Table 3-17: Tripping Logic
Setting
Parameter
Description
Recommended
Settings Unit
Program
Three ph; single or three ph; single, two or
three ph trip
1ph/3ph -
tTripMin Minimum duration of trip output signal 0.150 s
tWaitForPHS
Secures 3-pole trip when phase selection
failed
0.050 s
TripLockout
On: activate output (CLLKOUT) and trip
latch, Off: only outp
Off -
AutoLock
On: lockout from input (SETLKOUT) and
trip, Off: only inp
Off -

65
3.1.18 Trip Matrix Logic TMAGGIO
This function is only for the OR operation of any signals (normally used for trip signals). For
example, all distance 3-ph trips (from z-2, z-3 and z-4), SOTF trip, TOV, TOC and TEF trips using
TMAGGIO function.
PulseTime: Defines the pulse time delay. When used for direct tripping of circuit breaker(s) the
pulse time delay shall be set to approximately 0.150s in order to obtain satisfactory minimum
duration of the trip pulse to the circuit breaker trip coils. If TMAGGIO is used without SMPPTRC, set
pulse width of trip signal from TMAGGIO in PulseTime.
OnDelay: It is delay for output from TMAGGIO. If it is set to 100ms, even if trip is available, it will
not give output till 100ms. Hence it should be set to 0s. OnDelay timer is to avoid operation of
outputs for spurious inputs.
OffDelay: time delay for output to reset after inputs got reset. For example, if it set to 100ms as
OffDelay, even if trip goes OFF, the output will appear 100ms. If “steady” mode is used, pulsetime
setting is not applicable, then output can be prolonged to 150ms with this setting. If TMAGGIO is
used with SMPPTRC, this should be set to 0s.
ModeOutput1, ModeOutput2, ModeOutput3: To select whether steady or pulsed. If steady is
selected, it will give output till input is present if OffDelay is set to zero. If pulsed is sleceted, output
will be same as that of SMPPTRC.
Table 3-18 gives the recommended settings for Trip Matrix Logic.
Table 3-18: Trip Matrix Logic
Setting
Parameter
Description
Recommended
Settings Unit
PulseTime Output pulse time 0.0 s
OnDelay Output on delay time 0.0 s
OffDelay Output off delay time 0.0 s
ModeOutput1 Mode for output ,1 steady or pulsed Steady -
ModeOutput2 Mode for output 2, steady or pulsed Steady -

66
3.1.19 Automatic Switch Onto Fault Logic, Voltage And Current Based
ZCVPSOF
Mode: The operation of ZCVPSOF has three modes for defining the criteria for trip. When Mode is
set to Impedance, the operation criteria is based on the start of overeaching zone from impedance
zone measurement (Normally zone-2). A non-directional output signal should be used from an
overreaching zone. The selection of Impedance mode gives increased security. Impedance mode is
selected in present case.
AutoInit: Automatic activating of the ZCVPSOF function is by default set to Off. If automatic
activation Deadline detection is required, set the parameter Autoinit to On. Otherwise the logic will be
activated by an external BC input. It is set to OFF in present case and the logic has to be activated
by an external BC input.
If Autoinit mode=OFF, only Breaker Close (BC) input is used to detect dead line condition.
If Autoinit mode=ON, either UI Level detection of internal funciton or Breaker Close (BC) input is
used to detect dead line condition.
It has been assumed that in the present case CB close command input is available to the
relay as external binary input.
tSOTF: Time of SOTF function active status after breaker closed in impedance mode. This is
normally set to 0.2s. It means, till 0.2s, SOTF function will be active after breaker closed.
IBase: Set the Base current for the SOTF function in primary Ampere. This parameter is set to
1000A in present case.
UBase: Setting of the Base voltage level on which the Dead line voltage is based. This parameter is
set to 400kV in present case.
IPh: Setting of under current. This setting is applicable only if mode=UILevel or UILvImp and
Autoinit mode=ON. In present case, this parameter is not applicable.
UPh: Setting of the U voltage. This setting is applicable only if mode=UILevel or UILvImp and
Autoinit mode=ON. In present case, this parameter is not applicable.
tDuration: Set the required duration of low UI check to achieve operation (to ensure dead line
condition). This setting is applicable only if mode=UILevel or UILvImp. In present case, this
parameter is not applicable.
tDLD: Set the required time for all currents and all voltages to be low to Auto Initiate the SOTF
function. This setting is applicable only if Autoinit mode=ON. In present case, this parameter is not
applicable.

67
Table 3-19 gives the recommended settings for Automatic Switch Onto Fault Logic.
Table 3-19: Automatic Switch Onto Fault Logic
Setting
Parameter
Description
Recommended
Settings Unit
IBase Base current (A) 1000 A
UBase Base voltage L-L (kV) 400 kV
Mode Mode of operation of SOTF Function Impedance -
AutoInit Automatic switch onto fault initialization Off -
IPh
Current level for detection of dead line in %
of IBase
20 %IB
UPh
Voltage level for detection of dead line in %
of UBase
40 %UB
tDuration Time delay for UI detection (s) 0.5 s
tSOTF
Drop off delay time of switch onto fault
function
0.2 s
tDLD
Delay time for activation of dead line
detection
0.15 s

68
3.1.20 Power Swing Detection ZMRPSB
The various settings for power swing detection are shown in Figure 3-7.
Note: setting parameters are in italic and refer Table 3-20 for notations
Figure 3-7: Operating characteristic for ZMRPSB function
There are a number of options one can select in implementing power-swing protection in their
system. Designing the power system protection to avoid or preclude cascade tripping is a
requirement of the power system. Below are two possible options:

69
• Block all Zones except Zone-I
• Block All Zones and Trip with Out of Step (OOS) Function
In present case Relay is configured for Block all zones except Zone-1.
Settings for inner and outer characteristics of Power swing function are set as per guidelines given
in Application manual and Technical reference manual of REL670. Timer settings are to be set on
the following assumptions.
Maximum possible initial frequency of power oscillation Ȕsi = 1.5Hz
Maximum possible consecutive frequency of power oscillation Ȕsc = 5Hz
These values will decide tP1 and tP2 setting parameters.
tH: System studies should determine the settings for the hold timer tH. The purpose of this timer is,
to secure continuous output signal from Power swing detection function (ZMRPSB) during the
power swing, even after the transient impedance leaves ZMRPSB operating characteristic and is
expected to return within a certain time due to continuous swinging. Consider the minimum possible
speed of power swinging in a particular system.
In the absence of above information, timer tH is set to 0.5s.
tP1 and tP2: The tP1 timer serve as detection of initial power swings, which are usually not as fast
as the later swings are. The tP2 timer become activated for the detection of the consecutive swings,
if the measured impedance exit the operate area and returns within the time delay, set on the tW
waiting timer.
When initial swing comes, its speed should be more than tP1, once it leaves the characteristics
timer tW starts. If swing comes again within tW, its speed shall be more than tP2. Otherwise if it
comes again after tW, its speed shall be more than tP1.
tR1, tR2 and tEF timers are Inhibit timers. These timers are used to release PSB blocking under
certain conditions.
tEF: The setting of the tEF timer must cover, with sufficient margin, the opening time of a circuit
breaker and the dead-time of a single-phase autoreclosing together with the breaker closing time.
tEF is used to release PSB blocking when the circuit breaker closes onto persistent single-phase
fault after single-phase auto reclosing dead time. This parameter is not applicable in present case.
tR1: The tR1 inhibit timer delays the influence of the detected residual current on the inhibit criteria
for ZMRPSB. It prevents operation of the function for short transients in the residual current
measured by the IED.
tR1 is used to release PSB blocking if an earth-fault appears during the power swing (input
IOCHECK is high) and the power swing has been detected before the earth-fault (activation of the

70
signal I0CHECK). If residual current persist for more than tR1 set delay, PSB allows Distance
protection to trip. Otherwise Directional Earth fault protection has to issue trip under this condition.
Above two timers tR1 and tEF requires a binary start input from a Directional Earth fault function.
This has to be configured during IED engineering. Normally timer tR1 is recommended to be set to
0.3s and tEF can be set to 2s (since 1ph dead time is 1s).
tR2: The tR2 inhibit timer disables the output START signal from ZMRPSB function, if the measured
impedance remains within ZMRPSB operating area for a time longer than the set tR2 value. This
time delay was usually set to approximately two seconds in older power-swing devices.
tR2 is used to release PSB blocking if the power swing has been detected and measured
impedance remains within its PSB operate characteristic for the set time delay tR2.
Setting of the positive sequence reactance for PSB function to operate in Forward direction
X1InFw = 219.234Ω gives X1InFw=60.289Ω
Where X1lnFw = X1lnRv = 1.1 * maximum of all zone’s X1 (In present case, it is zone-3)
Setting of the line resistance for the characteristic angle of the characteristic
R1LIn = 18.697Ω gives R1LIn= 5.142Ω
Where R1Lln = maximum of all zone’s R1(In present case, it is zone-3)
Setting of the resistance for PSB function to operate in Forward direction
R1FInFw = 82.5Ω gives R1FInFw= 22.69Ω
Where R1FlnFw = R1FlnRv = 1.1 * maximum of all zone’s RFPP(In present case, it is zone-3)
Setting of the positive sequence reactance for PSB function to operate in reverse direction
X1InRv = 219.234Ω gives X1InRv=60.289Ω
Setting of the resistance for PSB function to operate in reverse direction
R1FInRv = 82.5Ω gives R1FInRv= 22.69Ω
Setting of the Power Swing Detection, Load enchroachment factor ON-OFF
OperationLdCh = On
Setting of the Outer Load resistance in forward direction for the Load enchroachment function, when
utilized
RLdOutFw = KL × RLmin, where RLmin = 74.82Ω and KL = 0.9 for the lines
150km
Since this factor is already consider in arriving at maximum load MVA (1500MVA) same is not
considered again here through the factor KL.
Hence RLdOutFw = 74.82Ω gives RLdOutFw= 20.576Ω

71
Setting of the Outer Load resistance in Reverse direction for the Load enchroachment function,
when utilized
RLdOutRv = 74.82Ω gives RLdOutRv= 20.576Ω
Calculations for kLdRFw and kLdRRv:
RLdInFw = kLdRFw× RLdOutFw
System Impedance, Zs = Local end source Impedance + Remote end source Impedance + Protected
Line Impedance
Local end source Impedance = (kV)2
/fault MVA = (400kV)2
/ (1.732 x 400kV x 18.55kA) = 12.45Ω at
80°
Remote end source Impedance = (kV)2
/fault MVA = (400kV)2
/ (1.732 x 400kV x 24.81kA) = 9.308Ω at
80°
Local and remote end source impedance angles are assumed as 80°
.
Hence System Impedance, Zs = 12.45Ω at 80° + 9.308 Ω at 80° + 58.59 Ω at 84.6° = 80.297 Ω at
83.36°
tP1=
Where
= 2 ● arc tan = 56.44°
and
= 2 ● arc tan
where RLdInFwmax = 0.8 x RLdOutFw = 67.7°
Now tP1= where = 1.5Hz
tP1 = 0.021 which is less than 30ms(Minimum)
Hence tP1 = 30ms
= 360°● ● tP1min + where = 1.5Hz
Hence = 72.64°

72
tP2max= where = 5Hz
Hence tP2 = 9ms
= = 54.62Ω
kLdRFw = = 0.73
It is important to adjust the setting of load encroachment resistance RLdFw in Phase selection with
load encroachment (FDPSPDIS) to the value equal to or less than the calculated value of RLdInFw.
In present case RLdInFw = 54.62Ω
But calculated value of RLdFw for a maximum load of 1500MVA is 74.82Ω. Hence as per the above
recommendation from manual, RLdFw is set to 54.62Ω instated of 74.82Ω.
RLdFw = 54.62Ω.
It is at the same time necessary to adjust the load angle in FDPSPDIS to follow the condition
presented in equation below
≥ arc tan
ArgLdPHS = 30°
Hence by using above equation ArgLdPSD = 19.43°need to be set in relay.
Setting of the PSD timers:
Initial PSD timer tP1 = 0.030s
Fast PSD timer tP2 = 0.011s
hold timer for initiate of Fast PSD timer tW = 0.250s
Hold timer for PSD detected tH = 0.500s
timer overriding 1-ph Reclosing tEF = 2.000s
to delay block by the IN current tR1 = 0.300s
Blocking output at slow swings tR2 = 2.000s
Note: These settings need to be verified for minimum source impedance (Maximum Fault level)
and maximum source impedance (Minimum Fault level) conditions.
Time for first swing and second swing shall be calculated using below equations

73
Table 3-20 gives the recommended settings for Power Swing Detection.
Table 3-20: Power Swing Detection
Setting
Parameter
Description
Recommended
Settings Unit
Operation Operation Mode On/Off On -
X1InFw Inner reactive boundary , forward 219.234 ohm
R1LIn
Line resistance for inner characteristic
angle
18.697 ohm
R1FInFw
Fault resistance coverage to inner
resistive line , forward
198 ohm
X1InRv Inner reactive boundary , reverse 219.234 ohm
R1FInRv
Fault resistance line to inner resistive
boundary , reverse
198 ohm
OperationLdCh
Operation of load discrimination
characteristic
On -
RLdOutFw Outer resistive load boundary , forward 74.82 ohm
ArgLd
Load angle determining load impedance
area
19.43 Deg
RLdOutRv Outer resistive load boundary , reverse 74.82 ohm
kLdRFw
Multiplication factor for inner resistive load
boundary , forward
0.73 Mult
kLdRRv
Multiplication factor for inner resistive load
boundary , reverse
0.73 Mult
tEF
Timer for overcoming single - pole
reclosing dead time.
2.000 s
IMinOpPE Minimum operate current in % of Ibase. 20.000 %IB
IBase Base setting for current level settings. 1000 A
tP1 Timer for detection of initial power swing 0.03 s

74
Setting
Parameter
Description
Recommended
Settings Unit
tP2
Timer for detection of subsequent power
swings
0.011 s
tW Waiting timer for activation of tP2 timer 0.25 s
tH
Timer for holding power swing START
output
0.5 s
tR1
Timer giving delay to inhibit by residual
current
0.3 s
tR2
Timer giving delay to inhibit at very slow
swing
2.0 s

75
Figure 3-8 and 3-9 show the graphical representation of the following in R-X plane.
Zone-1
Zone-2
Zone-3
Zone-5
PHS with Load encroachment
PSD
Figure 3-8: Characteristics for Phase to Phase faults

76
Figure 3-9: Characteristics for Phase to Earth faults
3.1.21 Scheme Communication Logic For Distance Or Overcurrent Protection
ZCPSCH
Guidelines for Setting
If Permissive Underreach is set, tCoord and tSendMin settings are applicable.
tCoord: Received communication signal is combined with the output from an overreaching zone till
the set duration in tCoord. There is less concern about false signal causing an incorrect trip.
Therefore set the timer tCoord to zero.
tSendMin: To assure a sufficient duration of the received signal (CR) at the remote end, the send
signal (CS) at local end can be prolonged by a tSendMin reset timer. The recommended setting of
tSendMin is 100ms.

77
Table 3-21 gives the recommended settings for Scheme Communication Logic For Distance Or
Overcurrent Protection.
Table 3-21: Scheme Communication Logic For Distance Or Overcurrent Protection
Setting
Parameter
Description
Recommended
Settings Unit
Operation Operation Mode On/Off On -
SchemeType Scheme type Permissive UR -
tCoord
Co-ordination time for blocking
communication scheme
0.000 s
tSendMin
Minimum duration of a carrier send
signal
0.100 s
Unblock
Operation mode of unblocking
logic
Off -
tSecurity
Security timer for loss of carrier
guard detection
0.035 s
3.1.22 Stub Protection STBPTOC
I: Current level for the Stub protection is set in % of IBase. This parameter should be set so that all
faults on the stub can be detected. The setting should thus be based on fault calculations. This
should not mal-operate for through faults due to spill currents. Recommended setting is 250% of
IBase.
t: Time delay of the operation. Normally the function shall be instantaneous. Due to mismatch of
CT, during transient conditions for external faults, time can be set to 50ms.
ReleaseMode: Select whether the function shall operate continuous or only at release from release
input. Setting Releasemode shall be set to Release mode when this protection needs to be
activated with Line isolator open status. If “Continuous” mode of operation is selected, this
protection will be active irrespective of external binary input (Like line isolator status). This
protection is recommended to be set to “Release”.

78
IBase: Set the Base current for the function on which the current levels are based. This parameter
is set to 1000A in present case.
Table 3-22 gives the recommended settings for Stub Protection.
Table 3-22: Stub Protection
Setting
Parameter
Description
Recommended
Settings Unit
IBase Base current 1000 A
ReleaseMode Release of stub protection Release -
I Operate current level in % of IBase 250 %IB
t Time delay 0.050 s
3.1.23 Fuse Failure Supervision SDDRFUF
Guidelines for Setting
Setting for OpMode: Setting of the operating mode for the Fuse failure supervision. Zero sequence
based fuse fail detection is enabled and settings for the same are given based on below
recommendations.
3U0 and 3I0: The setting of 3U0 should not be set lower than maximal zero sequence voltage
during normal operation condition. The setting of 3I0 must be higher than maximal zero sequence
current during normal operating condition. In present case, 3U0 is set to 30% of UBase and 3I0 is
set to 10% of IBase.
3U2 and 3I2: These parameters are not applicable if OpMode is selected to UZsIZs.
DUDI: This is another philosophy for detecting fusefail like Zero sequence based and Negative
sequence based algorithm. If OpMode is set to UZsIZs and OpDUDI is kept ON, fusefail detection
will be OR operation of these two modes. This is recommended to set ON.

79
DU and DI: DUDI method will measure the difference in voltage (should be more than set in
DU) and difference in current (should be less than set in DI). DU is recommended to set 60% of
UBase and DI is recommended to set 15% of IBase.
UPh and IPh: For DUDI mode, voltage in the corresponding phase shall be more than set value
in UPh for 1.5cycles before actual fuse fail condition and current should be more than set value in
IPh before fuse fail. UPh is recommended to set 70% of UBase and IPh is recommended to set
10% of IBase.
A criterion based on delta current and delta voltage measurements can be added to the fuse failure
supervision function in order to detect a three phase fuse failure, which in practice is more
associated with voltage transformer switching during station operations. In present case, this
parameter is set ON.
SealIn: Setting of the seal-in function On-Off giving seal-in of alarm until voltages are symmetrical
and high. If sealin is ON and fusefail persists for more than 5s, outputs blockz and blocku will get
sealin (means latched) until any one phase voltage is less than USealIn setting. It will release
when all three voltages goes above USealIn setting. In present case, this parameter is made ON
and recommended setting for USealIn is 70% of UBase.
Dead line detection: If any phase voltage is less than UDLD set value and corresponding current
is less than IDLD set value, this will consider as dead line and it will block Z only, it will not block U.
There is no ON or OFF for this philosophy.
During real fuse fail condition, FF function will block both Z and U. UDLD is recommended to set to
60% of UBase and IDLD is recommended to set 5% of IBase.
UBase: Setting of the Base voltage level on which the voltage setting is based. In present case this
parameter is set to 400kV.
IBase: Set the Base current for the function on which the current levels are based. In present case
this parameter is set to 1000A.
Table 3-23 gives the recommended settings for Fuse Failure Supervision.
Table 3-23: Fuse Failure Supervision
Setting
Parameter
Description
Recommended
Settings Unit

80
Setting
Parameter
Description
Recommended
Settings Unit
OpMode Operating mode UZsIZs -
3U0
residual overvoltage element in % of
Ubase
30 %IB
3I0
Operate level of residual undercurrent
element in % of Ibase
10
%IB
3U2
Operate level of neg seq overvoltage
element in % of Ubase
20
%IB
3I2
Operate level of neg seq undercurrent
10
%IB
OpDUDI
Operation of change based function
Off/On
On -
DU
Operate level of change in phase voltage
in % of Ubase
60 %UB
DI Operate level of change in phase 15 %IB
UPh
Operate level of phase voltage in % of
Ubase.
70 %UB
IPh
Operate level of phase current in % of
IBase
10 %IB
SealIn Seal in functionality Off/On On -
USealln
Operate level of seal-in phase voltage in
%of Ubase
70 %UB
IDLD
Operate level for open phase current
detection in % of IBase
5 %IB
UDLD Operate level for open phase voltage 60
%UB

81
3.1.24 Four Step Residual Overcurrent Protection EF4PTOC
The ground over current threshold should be set to ensure detection of all ground faults, but above
any continuous residual current under normal system operation. The timing should be coordinated
with the Zone-3 timing for a remote end bus fault.
IBase: Set the Base current for the function on which the current levels are based. This parameter
is set to 1000A in present case.
UBase: Setting of the Base voltage level on which the directional polarizing voltage is based. This
parameter is set to 400kV in present case.
DirMode1: Setting of the operating direction for the stage or switch it off. This parameter is set to
“Forward” in present case.
Characteristic1: Setting of the operating characteristic. This parameter is set to “IEC Norm. Inv.” in
present case.
IN1: Setting of the operating current level in primary values. This parameter is set to 20% of base
current in present case.
IN1Mult: Set the current multiplier for IN1 valid at activation of input ENMULT. As this parameter is
not applicable in present case, setting is left with default value of 1.
t1: When definite time characteristic has been selected, set the definite time delay. This parameter
k1: Set the back-up trip time delay multiplier for inverse characteristic. Refer Appendix-I for more
details.
t1Min: Set the Minimum operating time for inverse characteristic. This parameter is set more than
Zone-3 operating time. Hence this parameter is set to 1.1s in present case.
ResetTypeCrv1: Select the reset curve type for the inverse delay. This parameter is recommended
to set “Instantaneous”. However, to emulate the disc reset behavior, this can be set to IEC.
tReset1: Set the Reset time delay for definite time delayed function. This parameter is not
applicable if ResetTypeCrv1 is set to Instantaneous.
HarmRestrain1: Set the release of Harmonic restraint blocking for the stage. This parameter is kept
ON by considering Trafo charging directly through line.
polMethod: Set the method of directional polarizing to be used. If it is set as “Voltage”, it will
measure 3U0 from 3 phase voltages and -3U0 is reference. If it is set “Current”, it will measure 3I0
from I3PPOL input and calculate 3U0 using RNPol and XNPol values. If it is set “Dual”, it will
consider sum of above two voltages for reference. In present case, it is set to “Voltage”.

82
UPolMin: Setting of the minimum neutral point polarizing voltage level for the directional function.
Generally this parameter is recommended to set 1% of base voltage.
IPolMin, RNPol, XNPol: These parameters are not applicable if polMethod is set to “Voltage”.
AngleRCA: Set the relay characteristic angle, i.e. the angle between the neutral point voltage and
current. This parameter is recommended to be set to 65°
.
INDir: Minimum current required for directionality. This should be lower than pickup of earth fault
protection. This parameter is normally recommended to be set to 10% of the base current.
2ndHarmStab: Setting of the harmonic content in IN current blocking level. This is to block earth
fault protection during inrush conditions. Setting is in percentage of I2/I1. This parameter is normally
recommended to be set to 20%.
BlkParTransf: Set the harmonic seal-in blocking at parallel transformers on if problems are
expected due to sympathetic inrush. If residual current is higher during switching of a transformer
connecting in parallel with other transformer and if 2nd
harmonic current is lower than 2ndHarmStab
set value, earth fault protection may operate because of high residual current. Inrush current in Line
CTs may be higher at beginning and later it may be reduced. If “BlkParTransf” is set ON, protection
will be blocked till residual current is lower than set pickup of selected “UseStartValue”. This
parameter is normally recommended to be set to OFF.
UseStartValue: Select a step which is set for sensitive earth fault protection for above blocking.
This parameter is not applicable if BlkParTransf is set to OFF.
SOTF: Set the SOTF function operating mode. If “SOTF” is set ON, as per the logic given in TRM,
trip from SOTF requires start of step-2 or step-3 along with the activation of breaker closing
command. Since Directional earth function has IDMT characteristics, SOTF is set to OFF.
ActivationSOTF, ActUndertime, t4U, tSOTF, tUndertime, HarmResSOTF: These parameters are
not applicable if SOTF is set to OFF.
IN1: This parameter is set to 20% of base current in present case, which is 200A in primary.
k1 (TMS): This parameter is set to 0.3 in present case.
Refer Appendix-I for more details of above two settings.

83
Table 3-24 gives the recommended settings for Four Step Residual Overcurrent Protection.
Table 3-24: Four Step Residual Overcurrent Protection
Setting
Parameter
Description
Recommended
Settings Unit
IBase Base value for current settings 1000 A
UBase Base value for voltage settings.
(Check with PT input in configuration )
400 kV
AngleRCA Relay characteristic angle (RCA) 65 Deg
polMethod Type of polarization Voltage -
UPolMin Minimum voltage level for polarization in %
of UBase
1 %UB
IPolMin Minimum current level for polarization in
% of IBase
5 %IB
RNPol Real part of source Z to be used for current
polar-isation
5 Ohm
XNPol Imaginary part of source Z to be used for
current polarisation
40 ohm
INDir Residual current level for Direction release
in % of IBase
10 %IB
2ndHarmStab Second harmonic restrain operation in % of
IN amplitude
20 %
BlkParTransf Enable blocking at paral-lel transformers Off -
UseStartValue Current level blk at paral-lel transf (step1, 2,
3 or 4)
IN4 -
SOTF SOTF operation mode (Off/SOTF/Under-
time/SOTF+undertime)
Off -
ActivationSOTF Select signal that shall activate SOTF Open -

84
Setting
Parameter
Description
Recommended
Settings Unit
StepForSOTF Selection of step used for SOTF Step 2 -
HarmResSOTF Enable harmonic restrain function in SOTF Off -
tSOTF Time delay for SOTF 0.200 S
t4U Switch-onto-fault active time 1.000 S
DirMode1 Directional mode of step 1 (off, nodir,
forward, reverse)
Forward -
Characterist1 Time delay curve type for step 1 IEC Norm. Invr. -
IN1 Operate residual current level for step 1 in
% of IBase
20 %IB
t1 Independent (definite) time delay of step 1 0 s
k1 Time multiplier for the dependent time
delay for step 1
0.3 -
IN1Mult Multiplier for scaling the current setting
value for step 1
1.0 -
t1Min Minimum operate time for inverse curves
for step 1
1.1 s
HarmRestrain1 Enable block of step 1 from harmonic
restrain
On -
forward, reverse)
Off -
forward, reverse)
Off -
forward, reverse)
Off -

85
3.1.25 Two Step Overvoltage Protection OV2PTOV
Recommendation for 400kV Lines: Low set stage (Stage-I) may be set in the range of 110% - 112%
(typically 110%) with a time delay of 5s. High set stage (Stage-II) may be set in the range 140% -
150% with a time delay of 100ms.
UBase: Setting of the Base voltage level on which the voltage settings are based. This parameter is
U1: Setting of the U voltage. This parameter is recommended set 110% of the base voltage in
present case, which is 440kV.
OpMode1: Setting of the Overvoltage function measuring mode for involved voltages. Normally this
parameter is recommended to be set to 1 out of 3.
Characterist1: Setting of the characteristic for the time delay, inverse or definite time. Normally this
parameter is recommended to be set to Definite time.
t1: Setting of the definite time delay, when selected. This parameter is recommended to be set to 5s
in present case.
k1: Set the time delay multiplier for inverse characteristic, when selected. This parameter is not
applicable if Characterist1 is set to Definite time.
t1Min: Setting of the definite minimum operating time for the inverse characteristic. This parameter
is not applicable if Characterist1 is set to Definite time.
t1Reset: Setting of the definite time reset time. This parameter is not applicable if ResetTypeCrv1 is
set to Instantaneous.
HystAbsn1: Absolute hysteresis is set in % of UBase. The setting of this parameter is highly
dependent of the application. In OV2PTOV, this can be set as low as 0.5%. Which means drop-off
to pickup ratio can be set upto 99.5%.
U2: Setting of the U voltage. This parameter is recommended to be set to 140% of the base
voltage in present case, which is 560kV.
OpMode2: Setting of the Overvoltage function measuring mode for involved voltages. Normally this
parameter is recommended to be set to 1 out of 3.
Characterist2: Setting of the characteristic for the time delay, inverse or definite time. Normally this
parameter is recommended to be set to Definite time.

86
t2: Setting of the definite time delay, when selected. This parameter is recommended to be set to
0.1s in present case.
k2: Set the time delay multiplier for inverse characteristic, when selected. This parameter is not
applicable if Characterist2 is set to Definite time.
t2Min: Setting of the definite minimum operating time for the inverse characteristic. This parameter
is not applicable if Characterist2 is set to Definite time.
t2Reset: Setting of the definite time reset time. This parameter is not applicable if ResetTypeCrv2 is
set to Instantaneous.
HystAbsn2: Absolute hysteresis set in % of UBase. The setting of this parameter is highly
dependent of the application. In OV2PTOV, this can be set as low as 0.5%. Which means drop-off
to pickup ratio can be set upto 99.5%.
Table 3-25 gives the recommended settings for Two Step Overvoltage Protection.
Table 3-25: Two Step Overvoltage Protection
Setting
Parameter
Description
Recommended
Settings Unit
ConnType Group selector for connection type PhPh DFT -
OperationStep1 Enable execution of step 1 On -
Characterist1
Selection of time delay curve type for
step 1
Definite time -
OpMode1
Number of phases required for op (1 of
3, 2 of 3, 3 of 3) from step 1
1 out of 3 -
U1
Voltage setting/start val (DT IDMT) in
% of UBase, step 1
110 %UB
t1 Definitive time delay of step 1 5 s

87
Setting
Parameter
Description
Recommended
Settings Unit
t1Min
Minimum operate time for inverse
curves for step 1
5 s
k1
Time multiplier for the inverse time delay
for step 1
0.05 -
HystAbs1
Absolute hysteresis in % of UBase, step
1
0.5 %UB
OperationStep2 Enable execution of step 2 On -
Characterist2
Selection of time delay curve type for
step 2
Definite time -
OpMode2
3, 2 of 3, 3 of 3) from step 2
1 out of 3 -
U2
Voltage setting/start val (DT IDMT) in
% of UBase, step 2
140 %UB
t2 Definitive time delay of step 2 0.1 s
t2Min
Minimum operate time for inverse
curves for step 2
0.1 s
k2
for step2
0.05 -
HystAbs2
Absolute hysteresis in % of UBase, step
2
0.5 %UB
tReset1 Reset time delay used in IEC Definite
Time curve step 1
0.025 s
ResetTypeCrv1 Selection of used IDMT reset curve type
for step 1
Instantaneous -
tIReset1 Time delay in IDMT reset (s), step 1 0.025 s
ACrv1 Parameter A for customer programmable
curve for step 1
1.000 -
BCrv1 Parameter B for customer programmable
curve for step 1
1.000 -
CCrv1 Parameter C for customer 0.0 -

88
Setting
Parameter
Description
Recommended
Settings Unit
programmable curve for step 1
DCrv1 Parameter D for customer
0.000 -
PCrv1 Parameter P for customer programmable
curve for step 1
1.000 -
CrvSat1 Tuning param for prog. over voltage
IDMT curve, step 1
0 -
Time curve step 2
0.025 s
ResetTypeCrv2 Selection of used IDMT reset curve type
for step 2
Instantaneous -
tIReset2 Time delay in IDMT reset (s), step 2 0.025 s
ACrv2 Parameter A for customer programmable
curve for step 2
1.000 -
BCrv2 Parameter B for customer programmable
curve for step 2
1.000 -
CCrv2 Parameter C for customer
0.0 -
DCrv2 Parameter D for customer
0.000 -
PCrv2 Parameter P for customer programmable
curve for step 2
1.000 -
CrvSat2 Tuning param for prog. over voltage
IDMT curve, step 2
0 %

89
3.1.26 Setting of fault locator values LFL
Line length unit: km
Length: 190km
X1: j58.33Ω
R1: 5.472Ω
X0: j203.68Ω
R0: 51.091Ω
X1SA: j12.26Ω
R1SA: 1.616Ω
X1SB: j9.167Ω
R1SB: 5.472Ω
XM0: j125.87Ω
RM0: 43.32Ω
Table 3-26 gives the recommended settings for Setting of fault locator values.
Table 3-26: Setting of fault locator values
Setting
Parameter
Description
Recommended
Settings Unit
R1A Source resistance A (near end) 1.616 ohm/p
X1A Source reactance A (near end) 12.26 ohm/p
R1B Source resistance B (far end) 5.472 ohm/p
X1B Source reactance B (far end) 9.167 ohm/p
R1L Positive sequence line resistance 5.472 ohm/p
X1L Positive sequence line reactance 58.33 ohm/p
R0L Zero sequence line resistance 51.091 ohm/p
X0L Zero sequence line reactance 203.68 ohm/p

90
R0M Zero sequence mutual resistance 43.32 ohm/p
X0M Zero sequence mutual reactance 125.87 ohm/p
LineLength Length of line 190 km
3.1.27 Disturbance Report DRPRDRE
Start function to disturbance recorder is to be provided by change in state of one or more of the
events connected and/or by any external triggering so that recording of events during a fault or
system disturbance can be obtained. List of typical signals recommended to be recorded is given
below:
Recommended Analog signals
From CT:
IA
IB
IC
IN
From Line VT:
VAN
VBN
VCN
Fron Aux VT
Vo
Recommended Digital Signals for triggering (Typical)
— Main 1 Carrier receive
— Main 1 Trip
— Z3 start
— Power swing detected
— Line O/V Stage I/Stage II
— Reactor Fault Trip (If applicable)
— Stub Protection Optd.

91
— Main II Trip
— Main II Carrier Receive
— Direct Trip CH A/B Receive
— Bus bar trip
— Main/Tie CB LBB Optd.
— Main/Tie CB A/R operated.
— Main/Tie CB A/R unsuccessful
List of signals used for Analog triggering of DR
— Rate of change of frequency (if available)
— Over Voltage
— Under Voltage
— Over Current
Note: These may need modification depending upon Protections chosen and the contact availability
for certain functions.
Recording capacity
— Record minimum eight (8) analog inputs and minimum sixteen (16) binary signals per bay or
circuit.
Memory capacity
— Minimum 3 s of total recording time
Recording times
— Minimum prefault recording time of 200ms
— Minimum Post fault recording time of 2500ms
PreFaultRecT: is the recording time before the starting point of the disturbance. The setting is
recommended to be set to 0.2s.
PostFaultRecT: This is the maximum recording time after the disappearance of the trig-signal. The
setting is recommended to be set to 2.5s
TimeLimit: It is the maximum recording time after trig. The parameter limits the recording time if
some trigging condition (fault-time) is very long or permanently set without reset. The setting is
recommended to be set to 3s

92
PostRetrig: If it is made ON, new disturbance will be recorded if new trigger signal appears during
a recording. If it is made OFF, a separate DR will not be triggered if new trigger signal appears
during a recording. This parameter is recommended to be set to OFF normally.
ZeroAngleRef: Need to set the analog channel which can be used as reference for phasors,
frequency measurement. Channel 1 set in present case.
Table 3-27 gives the recommended settings for Disturbance Report.
Table 3-27: Disturbance Report
Setting
Parameter
Description
Recommended
Settings Unit
Operation Operation Off/On On -
PreFaultRecT Pre-fault recording time 0.2 s
PostFaultRecT Post-fault recording time 2.5 s
TimeLimit Fault recording time limit 3.00 s
PostRetrig Post-fault retrig enabled (On) or not (Off) Off -
ZeroAngleRef
Reference channel (voltage), phasors,
frequency measurement
1 Ch
OpModeTest Operation mode during test mode Off -

93
3.2 REC670
3.2.1 Analog Inputs
CTprim 1000 1000 1000 1000 1000 1000
Name# UL1 UL2 UL3 UL2BUS1 UL2BUS2 UL2L2
VTsec 110V 110V 110V 110V 110V 110V
# User defined text
Table 3-28 gives the recommended settings for Analog Inputs.
Table 3-28: Analog Inputs
Setting
Parameter
Description
Recommended
Settings Unit
PhaseAngleRef
presentation
TRM40-Ch1 -

94
Setting
Parameter
Description
Recommended
Settings Unit
CTStarPoint2
ToObject -
CTStarPoint3
ToObject -
CTStarPoint4
ToObject -
CTStarPoint5
ToObject -
CTStarPoint6
ToObject -

95
Setting
Parameter
Description
Recommended
Settings Unit
Note: OscBlock and OscRelease define the filtering time at activation. Low frequency gives slow

96
Setting
Parameter
Description
Recommended
Settings Unit
AutoRepeat
(Off)
On -
steady and latched till manually reset. When manually reset, it will go OFF when trip is not there. If
trip still persist, it will flash.
Setting
Parameter
Description
Recommended
Settings Unit

97
Setting
Parameter
Description
Recommended
Settings Unit
tMax
disturbance
0.0 s
These settings are used for synchronizing IED clock time with network time. Ex: GPS or IRIG-B time.
CoarseSyncSrc: Select the time synchronization source available such as SPA, LON, SNTP etc.
Synchronization messages from sources configured as coarse are checked against the internal relay

98
time and only if the difference in relay time and source time is more than 10s then relay time will be
reset with the source time. This parameter need to be based on time source available in site.
once it is selected, time of available time source in network will update to relay if there is a difference
in the time between relay and source. This parameter need to be based on time source available in
site.
SyncMaster: Normally it is set OFF. If time to the relay is received from a GPS antenna (example),
make the relay as master to synchronize with other relays.
HWSyncSrc: This is applicable if process bus IEC61850-9-2 protocol is used for receiving analog
values (optical CT PTs). In this case select time source available same as that of merging unit. This
setting is not applicable in present case.
AppSynch: If there is any loss of time sync, protection function will be blocked if AppSynch set to
Synch based on SyncAccLevel. If AppSunch set to NoSynch, protection functions are not blocked.
Recommended setting is NoSynch.
SyncAccLevel: If this is set to “Class T5 (1us)” and time synch error is more than 1us, protection
functions will be blocked. SyncAccLevel should be set to “Unspecified” when Nosynch is selected at
AppSynch. This parameter is not applicable in present case.
ModulePosition: if BIN is set for FineSyncSource, ModulePosition setting is applicable. Here slot
position of IO module in the relay is to be set (Which slot is used for BI). This parameter is not
NoHalfHourUTC: Time shift from GMT has to be set a multiple of half hours. Example for India it is
+05:30, means +11. Hence this parameter is set to +11 in present case.

99
SYNCHIRIG-B Non group settings: These settings are applicable if IRIG-B is used. This parameter
SynchType: Type of hardware input used for time sync, whether Opto or BNC. This parameter is not
Table 3-31 gives the recommended settings for Time Synchronization.
Table 3-31: Time Synchronization
Setting
Parameter
Description
Recommended
Settings Unit
Setting
Parameter
Description
Recommended
Settings Unit
ModulePosition
Synchronization
3 -
BinaryInput
Synchronization
1 -

100
Recommended
Settings Unit
Setting
Parameter
Description
Recommended
Settings Unit
WeekInMonth Week in month when daylight time starts Last -
UTCTimeOfDay
3600 s
Setting
Parameter
Description
Recommended
Settings Unit
WeekInMonth
starts
Last -
UTCTimeOfDay
3600 s

101
Setting
Parameter
Description
Recommended
Settings Unit
Setting
Parameter
Description
Recommended
Settings Unit
changed, is set with the parameter t. This is not the delay for changing setting group. This parameter
is normally recommended to set 1s.
MAXSETGR: The parameter MAXSETGR defines the maximum number of setting groups in use to
switch between. Only the selected number of setting groups will be available in the Parameter
Table 3-32 gives the recommended settings for Parameter Setting Groups.

102
Table 3-32: Parameter Setting Groups
Setting
Parameter
Description
Recommended
Settings Unit
t
Changed
1 s
Setting
Parameter
Description
Recommended
Settings Unit
Table 3-33 gives the recommended settings for Test Mode Functionality.
Table 3-33: Test Mode Functionality
Setting
Parameter
Description
Recommended
Settings Unit
CmdTestBit Command bit for test required or not Off -

103
during testmode
Setting
Parameter
Description
Recommended
Settings Unit
ObjectName Object name Line -
UnitName Unit name REC670 -
Table 3-35 gives the recommended settings for Rated System Frequency.
Table 3-35: Rated System Frequency
Setting
Parameter
Description
Recommended
Settings Unit

104
DFTReference: Set ref for DFT filter adjustment here. These DFT reference block settings decide
DFT reference for DFT calculations.
Each task group has 12 instances of SMAI, in that first instance has some additional features which
is called master. Others are slaves and they will follow master. If measured sample rate needs to be
transferred to other task group, it can be done only with master.
DFTReference shall be set to default value InternalDFTRef if no VT input is available. Since VT input
is available in this case, the corresponding channel shall be set to DFTReference. Configuration file
has to be referred for this purpose.
DFTRefExtOut: This parameter is available only in Master. If reference is to be sent to other task
group, which reference need to be send has to be select here. For example, if voltage input is
connected to 3rd
SMAI of 1ms task group, AdDFTRefCh3 is to be set in DFTRefExtOut of 1ms task
group.
DFTRefExtOut shall be set to default value InternalDFTRef if no VT input is available. Configuration
file has to be referred for this purpose.
Negation is set to NegateN, it will give output R, Y, B and –N. If Negation is set to Negate3Ph, it will
give output -R, -Y, -B and N.
If R, Y, B inputs are connected, N=R+Y+B, and it will do as above. This parameter is recommended
to be set to OFF normally.
SMAI will work only if measured input magnitude is greater than set value in MinValFreqMeas. This
parameter is recommended to be set to 10% normally.

105
Setting
Parameter
Description
Recommended
Settings Unit
DFTRefExtOut DFT reference for external output (As per configuration) -
DFTReference DFT reference (As per configuration) -
TYPE 1=Voltage, 2=Current 1 or 2 based on input Ch
MinValFreqMeas
UBase
10 %

106
3.2.10 Synchrocheck function (SYN1)
SelPhaseBus1: Setting of the input phase for Bus 1 voltage reference. This parameter has to be set
based on the corresponding phase PT/CVT input connected to this function. Present case, this
parameter is set to L1 (R-phase)
SelPhaseLine1: Setting of the phase or line 1 voltage measurement. This parameter has to be set
based on the corresponding phase PT/CVT input connected to this function. Present case, this
parameter is set to L1 (R-phase).
SelPhaseBus2: Setting of the input phase for Bus 2 voltage reference (used in multi breaker
schemes only). This parameter has to be set based on the corresponding phase PT/CVT input
connected to this function. Present case, this parameter is set to L1 (R-phase)
SelPhaseLine2: Setting of the phase or line 2 voltage reference (used in multi breaker schemes
only). This parameter has to be set based on the corresponding phase PT/CVT input connected to
this function. Present case, this parameter is set to L1 (R-phase)
UBase: Setting of the Base voltage level on which the voltage settings are based. This parameter is
PhaseShift: This setting is used to compensate for a phase shift caused by a transformer between
the two measurement points for bus voltage and line voltage, or by a use of different voltages as a
reference for the bus and line voltages. The set value is added to the measured line phase angle.
The bus voltage is the reference voltage. This parameter is set to 0°in present case.
URatio: The URatio is defined as URatio = bus voltage/line voltage. This setting scales up the line
voltage to an equal level with the bus voltage. This parameter is set to 1 in present case.
CBConfig: Set available bus configuration here if external PT selection for sync is not available.
If No voltage sel. is set, the default voltages used will be U-Line1 and U-Bus1. This is also the case
when external voltage selection is provided. Fuse failure supervision for the used inputs must also be
connected. In present case this parameter is set to 1 1/2 bus CB.
To allow closing of breakers between asynchronous networks a synchronizing function is provided.
The systems are defined to be asynchronous when the frequency difference between bus and line is
larger than an adjustable parameter.
OperationSC: This decides whether Synchrocheck function is OFF or ON. In present case this
UHighBusSC and UHighLineSC: Set the operating level for the Bus high voltage and Line high
voltage at Line synchronism check. The voltage level settings must be chosen in relation to the bus
or line network voltage. The threshold voltages UHighBusSC and UHighLineSC have to be set lower

107
than the value at which the breaker is expected to close with the synchronism check. A typical value
can be 80% of the base voltages.
UDiffSC: Setting of the allowed voltage difference for Manual and Auto synchronism check. The
setting for voltage difference between line and bus in p.u, defined as (U-Bus/
UBaseBus) - (U-Line/UBaseLine). Normally this parameter is recommended to set 0.15pu.
FreqDiffM and FreqDiffA: The frequency difference level settings for Manual and Auto sync. A
typical value for FreqDiffM can be100mHz for a connected system, and a typical value for FreqDiffA
can be 100-200 mHz. FreqDiffA is not applicable in present case.
PhaseDiffM and PhaseDiffA: The phase angle difference level settings for Manual and Auto sync.
PhaseDiffM is normally recommended to set 30°
. Phas eDiffA is not applicable in present case.
tSCM and tSCA: Setting of the time delay for Manual and Auto synchronism check. Circuit breaker
closing is thus not permitted until the synchrocheck situation has remained constant throughout the
set delay setting time. Typical values for tSCM and tSCA can be 0.1s.
Auto related settings are not applicable if outputs related to Auto from this function block for 3-ph
Autorecloser operation is not used.
AutoEnerg and ManEnerg: Setting of the energizing check directions to be activated for AutoEnerg.
Setting of the manual Dead line/bus and Dead/Dead switching conditions to be allowed for
ManEnerg.
DLLB, Dead Line Live Bus, the line voltage is below set value of ULowLineEnerg and the bus
voltage is above set value of UHighBusEnerg. DBLL, Dead Bus Live Line, the bus voltage is below
set value of ULowBusEnerg and the line voltage is above set value of UHighLineEnerg.
AutoEnerg is made OFF and ManEnerg is set to Both of the above DLLB, DBLL. Hence Auto related
parameters are not applicable.
ManEnergDBDL: This need to be made OFF to avoid manual closing of the breaker if both Bus and
Line are dead. In present case this parameter is set OFF.
UHighBusEnerg and UHighLineEnerg: Set the operating level for the Bus high voltage at Line
energizing for UHighBusEnerg. Set the operating level for the Line high voltage at Bus energizing for
UHighLineEnerg.
The threshold voltages UHighBusEnerg and UHighLineEnerg have to be set lower than the value at
which the network is considered to be energized. A typical value can be 80% of the base voltages. If
system voltages are above the set values here, relay will consider it as Live condition.
ULowBusEnerg and ULowLineEnerg: Setting of the operating voltage level for the low Bus voltage
level at Bus energizing for ULowBusEnerg. Setting of the operating voltage level for the low line
voltage level at line energizing for ULowLineEnerg.

108
The threshold voltages ULowBusEnerg and ULowLineEnerg, have to be set to a value greater than
the value where the network is considered not to be energized. A typical value can be 40% of the
base voltages. If system voltages are below the set values here, relay will consider it as Dead
condition.
UMaxEnerg: Setting of the maximum live voltage level at which energizing is allowed. This setting is
used to block the closing when the voltage on the live side is above the set value of UMaxEnerg. In
present case this parameter is set to 105% of UBase.
tAutoEnerg and tManEnerg: Set the time delay for the Auto Energizing and Manual Energizing.
The purpose of the timer delay settings, tAutoEnerg and tManEnerg, is to ensure that the dead side
remains de-energized and that the condition is not due to a temporary interference. If the conditions
do not persist for the specified time, the delay timer is reset and the procedure is restarted when the
conditions are fulfilled again. Circuit breaker closing is thus not permitted until the energizing
condition has remained constant throughout the set delay setting time. Normally tManEnerg is
recommended to set 0.1s. tAutoEnerg is not applicable in present case.
OperationSynch: Operation for synchronizing function Off/ On. This parameter is recommended to
set OFF.
FreqDiffMin, FreqDiffMax, UHighBusSynch, UHighLineSynch, UDiffSynch, tClosePulse,
tBreaker, tMinSynch and tMaxSynch: These parameters are not applicable if OperationSynch is
set to OFF.
Table 3-37 gives the recommended settings for Synchrocheck function.
Table 3-37: Synchrocheck function
Setting
Parameter
Description
Recommended
Settings
Unit
CBConfig Select CB configuration 1 1/2 bus CB -
UBaseBus Base value for busbar voltage settings 400.000 kV
UBaseLine Base value for line voltage settings 400.000 kV
PhaseShift Phase shift 0 Deg
URatio Voltage ratio 1.000 -

109
Setting
Parameter
Description
Recommended
Settings
Unit
OperationSynch
Operation for synchronizing function Off/
On
Off -
OperationSC
Operation for synchronism check function
Off/On
On -
UHighBusSC
Voltage high limit bus for synchrocheck in %
of UBaseBus
80.0 %UBB
UHighLineSC
Voltage high limit line for synchrocheck in %
of UBaseLine
80.0 %UBL
UDiffSC Voltage difference limit in p.u 0.15 pu
FreqDiffA
Frequency difference limit between bus
and line Auto
0.010 Hz
FreqDiffM
and line Manual
0.10 Hz
PhaseDiffA
Phase angle difference limit between
bus and line Auto
30.0 Deg
PhaseDiffM
bus and line Manual
30.0 Deg
tSCA Time delay output for synchrocheck Auto 0.100 s
tSCM
Time delay output for synchrocheck
Manual
0.100 s
AutoEnerg Automatic energizing check mode Off -
ManEnerg Manual energizing check mode Both -
ManEnergDBDL Manual dead bus, dead line energizing Off -
UHighBusEnerg
Voltage high limit bus for energizing
check in % of UBaseBus
80.0 %UBB
UHighLineEnerg
Voltage high limit line for energizing
check in % of UBaseLine
80.0 %UBL

110
Setting
Parameter
Description
Recommended
Settings
Unit
ULowBusEnerg
Voltage low limit bus for energizing
40.0 %UBB
ULowLineEnerg
Voltage low limit line for energizing
40.0 %UBL
UMaxEnerg
Maximum voltage for energizing in % of
UBase, Line and/or Bus
105.0 %UB
tAutoEnerg
Time delay for automatic energizing
Check
0.100 s
tManEnerg Time delay for manual energizing check 0.100 s
SelPhaseBus1 Select phase for busbar1
Phase L1 for
busbar1
-
Phase L1 for
busbar2
-
SelPhaseLine1 Select phase for line1 Phase L1 for line1 -
3.2.11 Autorecloser SMBRREC
Fast simultaneous tripping of the breakers at both ends of a faulty line is essential for successful
auto-reclosing. Therefore, availability of protection signaling equipment is a pre-requisite.
Starting and Blocking of Auto-reclose Relays:
Some protections start auto-reclosing and others block. Protections which start A/R are Main-I and
Main-II line protections.
Protections which block A/R are:
— Breaker Fail Relay
— Line Reactor Protections
— O/V Protection

111
— Received Direct Transfer trip signals
— Busbar Protection
— Zone 2/3 of Distance Protection
— Carrier Fail Conditions
— Circuit Breaker Problems.
When a reclosing relay receives start and block A/R impulse simultaneously, block signal
dominates. Similarly, if it receives 'start' for 1-phase fault immediately followed by multi-phase fault
the later one dominates over the previous one.
Operation: If it is set ON, Autorecloser will be ON always but initiation is required to START input
from trip relay to start the timers in Autorecloser. If External ctrl is selected, on or off of Autorecloser
function will be using an external switch via IO or communication ports. In present case, this
parameter is set to External ctrl.
ARMode: This parameter is set to 1/2ph in present case. If 2 phase fault occurs, it is converted to
3-ph trip through trip logic (configured in relay).
All the available ARmodes are explained below.
3 phase: If 3 phase is selected, Autorecloser all shots will be 3-ph for all faults.
1/2/3ph: If 1/2/3ph is selected, Autorecloser first shot will be 1ph for 1ph fault, 2-ph for 2-ph fault
and 3-ph for 3-ph fault. If first shot fails, next shots will be 3-ph for all faults.
1/2ph: If 1/2ph is selected, Autorecloser will be 1ph for 1ph fault and 2-ph for 2-ph fault. For 3-ph
faults, Autorecloser will not work and it will not close the breaker after dead time. If first shot fails,
next shots will be 3-ph for 1ph and 2ph faults.
TR2P and TR3P inputs required if 2ph and 3ph Autorecloser is needed.
1ph+1*2ph: If 1ph+1*2ph is selected, Autorecloser first shot will be 1ph for 1ph fault and 2-ph for 2-
ph. If first shot fails, next shots will be 3-ph for 1ph faults. For 2ph faults, first shot will be 2ph and
no next shots, only 3ph trip, if it fails. For 3ph fault, Autorecloser will not work and it will not close
the breaker after dead time.
If 1ph fault occurred, Autorecloser will go for 1ph reclose after a 1ph trip. If Autorecloser fails to
close, it will go for 3ph trip and next Autorecloser will 3ph and it will continue based on no of shots
setting.

112
If 2ph fault occurred, Autorecloser will go for 2ph reclose after a 2ph trip. If Autorecloser fails to
close, it will go for 3ph trip and there will not be next Autorecloser cycle even if set more number of
shots in setting.
1/2ph+1*3ph: If 1ph+1*3ph is selected, Autorecloser first shot will be 1ph for 1ph fault, 2-ph for 2-
ph fault and 3-ph for 3-ph fault. If first shot fails, next shots will be 3-ph for 1ph and 2ph faults. For
3ph faults, first shot will be 3ph and no next shots, only 3ph trip.
1ph+1*2/3ph: If 1ph+1*2/3ph is selected, Autorecloser first shot will be 1ph for 1ph fault, 2-ph for 2-
ph fault and 3-ph for 3-ph fault. If first shot fails, next shots will be 3-ph only for 1ph. For 2ph or 3ph
faults, first shot will be 2ph or 3ph respectively and no next shots, only 3ph trip.
t1 1ph, t1 2ph and t1 3ph are the first shot dead times for 1ph, 2ph and 3ph faults. t1 2ph and t1
3ph are not applicable for 1ph Auto recloser.
t2 3Ph, t3 3Ph, t4 3Ph and t5 3Ph are not applicable if NoOfShots is set to 1.
Single phase dead time of 1.0 s. is recommended for both 400 kV and 220 kV systems.
t1 3PhHS: This timer is applicable if STARTHS input is used. This can be used where tripping by
different protection stages is needed. For this case, dead timer shall be normally in the range of
400ms. This is a high speed auto recloser without synchrocheck. Hence this should be set to a low
value. It may be used when one wants to use two different dead times in different protection trip
operations. This input starts the dead time t1 3PhHS. This parameter is not applicable in present
case.
tReclaim: After closing command to breaker, this timer will start, if fault occurred during this timer,
auto recloser will go for second shot or will issue 3ph trip based on setting.
According to IEC Publication 56.2, a breaker must be capable of withstanding the following
operating cycle with full rated breaking current:
0 + 0.3 s + CO + 3 min + CO
The recommended operating cycle at 400 kV and 220 kV is as per the IEC standard. Therefore,
reclaim time of 25s is recommended.
tSync: Maximum time for Synchro check condition to be fulfilled (Not applicable for 1-ph A/R). This
is applicable when 3ph Autorecloser is used.
tTrip: If trip command and start auto-reclosing signal persist for more than tTrip time, Autorecloser
will be either blocked or extend the auto-reclosing dead time based on Extended t1 setting. It will
block if Extended t1=OFF and it will extend auto-reclosing dead time if Extended t1=ON. A trip pulse
longer than the set time tTrip will inhibit the reclosing.

113
At a setting somewhat longer than the auto-reclosing open time, this facility will not influence the
reclosing. Normally this parameter is set to 0.2s.
tPulse: It is just closing pulse width of CB closing command from Autorecloser. This parameter in
normally recommended to set 0.2s.
tCBClosedMin: If either main or tie CB is kept open prior to the occurrence of fault, the Autoreclose
closing pulse should not be given to that breaker.
Setting tCBClosedMin is the minimum time the CB shall be kept closed prior to occurrence of a fault
to get an AR attempt. If the CB has not been closed for at least this minimum time, a reclosing start
will not be accepted. Normally this parameter is set to 5s.
tUnsucCl: CB check time before unsuccessful alarm. Normally the signal UNSUCCL appears when
a new trip and start is received after the last reclosing shot has been made and the auto-reclosing
function is blocked.
The signal resets once the reclaim time has elapsed. The “unsuccessful” signal can also be made to
depend on CB position input. The parameter UnsucClByCBChk should then be set to CBCheck,
and a timer tUnsucCl should also be set. If the CB does not respond to the closing command and
does not close, but remains open, the output UNSUCCL becomes high after time tUnsucCl.
The Unsuccessful output can for example, be used in Multi-Breaker arrangement to cancel the auto-
reclosing function for the second breaker, if the first breaker closed onto a persistent fault. It can
also be used to generate a Lock-out of manual closing until the operator has reset the Lock-out.
Normally this parameter is set to 3s.
Priority: In a multi-C.B. arrangement one C.B. can be taken out of operation and the line still be
kept in service. After a line fault, only those C.Bs which were closed before the fault shall be
reclosed.
In multi-C.B. arrangement it is desirable to have a priority arrangement so as to avoid closing of
both the breakers in case of a permanent fault. This will help in avoiding unnecessary wear and
tear. In this case, the breaker selected as priority High is reclosed first and only if it is successful,
the other breaker gets reclosing impulse.
A natural priority is that the C.B. near the busbar is reclosed first. In case of faults on two lines on
both sides of a tie C.B. the tie C.B. is reclosed after the outer C.Bs. The outer C.Bs. do not need a
prioriting with respect to each other.
In a single breaker arrangement the setting is Priority = None. In a multi-breaker arrangement the
setting for the first CB, the Master, is Priority = High and for the other CB Priority = Low.
While the reclosing of the master is in progress, it issues the signal WFMASTER.

114
A reset delay of one second ensures that the WAIT signal is kept high for the duration of the
breaker closing time. In the slave unit, the signal WAIT holds back a reclosing operation. When the
WAIT signal is reset at the time of a successful reclosing of the first CB, the slave unit is released to
continue the reclosing sequence.
tWaitForMaster: Setting of the maximum wait time for Master to be ready. In single CB
applications, one sets Priority = None. At sequential reclosing the function of the first CB, e.g. near
the busbar, is set Priority = High and for the second CB Priority = Low. The maximum waiting time,
tWaitForMaster of the second CB is set longer than the “auto-reclosing open time” and a margin for
synchrocheck at the first CB. Typical setting is tWaitForMaster=60s.
Whenever Zone1 Trips TIE CB as well as BUS CB Opens and First Dead time of Main CB starts
and in the mean time tWaitForMaster (TIE CB) starts elapsing. If WFMASTER does not deactivate
with in tWaitForMaster then TIE CB AR get deactivated. If WFMASTER deactivate before
tWaitForMaster then TIE CB Dead Time starts and at the end of Dead time TIE CB Reclose will
happen.
NoOfShots: The maximum number of reclosing shots in an auto-reclosing cycle is selected by the
setting parameter NoOfShots. This parameter is set to 1.
StartByCBOpen: To be set ON if AR is to be started by CB open position. To start auto-reclosing
by CB position Open instead of from protection trip signals, one has to configure the CB Open
position signal to inputs CBPOS and START and set a parameter StartByCBOpen = On and
CBAuxContType = NormClosed (normally closed). One also has to configure and connect signals
from manual trip commands to input INHIBIT. Normally this is kept OFF.
CBAuxContType: Select the type of contact used for the CB Position input.
CBAuxContType=NormClosed is also set and a CB auxiliary contact of type NC (normally closed) is
connected to inputs CBPOS and START. When the signal changes from “CB closed” to “CB open”,
an auto-reclosing start pulse is generated and latched in the function, subject to the usual checks.
Here it needs to be set whether NC or NO auxiliary contact of the CB is connected to the relay.
Normally NO contact is used.
CBReadyType: The selection depends on the type of performance available from the CB operating
gear. At setting OCO (CB ready for an Open – Close – Open cycle), the condition is checked only at
the start of the reclosing cycle. The signal will disappear after tripping, but the CB will still be able to
perform the C-O sequence. For the selection CO (CB ready for a Close – Open cycle) the condition
is also checked after the set auto-reclosing dead time. This selection has a value first of all at
multishot reclosing to ensure that the CB is ready for a C-O sequence at shot 2 and further shots.
During single-shot reclosing, the OCO selection can be used. A breaker shall according to its duty

115
cycle always have storing energy for a CO operation after the first trip. (IEC 56 duty cycle is O-0.3s
CO-3minCO).
Extended t1: Extended t1 for PLC failure activated or not. An auto-reclosing open time extension
delay, tExtended t1, can be added to the normal shot 1 delay. It is intended to come into use if the
communication channel for permissive line protection is lost. In such a case there can be a
significant time difference in fault clearance at the two ends of the line. A longer “auto-reclosing
open time” can then be useful. This extension time is controlled by setting parameter Extended
t1=On and the input PLCLOST. Typical setting in such a case: Extended t1 = On and tExtended t1
= 0.8 s. In present case Extended t1 is set to OFF.
tInhibit: A typical setting is tInhibit = 5.0s to ensure reliable interruption and temporary blocking of
the function. Function will be blocked during this time after the tinhibit has been activated.
CutPulse: The CB closing command, CLOSECB is given as a pulse with a duration set by
parameter tPulse. For circuit-breakers without an anti-pumping function, close pulse cutting can be
used. It is selected by parameter CutPulse=On. In case of a new trip pulse (start), the closing
command pulse is then cut (interrupted). The minimum closing pulse length is always 50 ms.
If CB is with anti-pumping relay, this CutPulse can be set OFF. In present case, this parameter is
set to OFF.
Follow CB: Select if the multi-shot cycle to advance to next shot at a new fault if CB has been
closed during dead time. The usual setting is Follow CB = Off. The setting On can be used for
delayed reclosing with long delay, to cover the case when a CB is being manually closed during the
“auto-reclosing open time” before the auto-reclosing function has issued its CB closing command.
AutoCont: Setting of the operating mode for next AR attempt (continue if CB does not close). This
is applicable only if multi-shots are selected. The normal setting is AutoCont = Off.
UnsucClByCBChk: Setting of the signal mode at Unsuccessful reclosing. The “unsuccessful”
signal can also be made to depend on CB position input using UnsucClByCBChk setting. 3ph trip is
issued if breaker has not been closed even if there is no trip output from distance relay.
Normally this parameter is set to NoCBCheck.
BlockByUnsucCl: Blocking of the Auto reclose program at unsuccessful auto reclosing. If this is
made ON, Autorecloser will be blocked for unsuccessful Autorecloser and it must be unblocked by
using the input BLKOFF. Normal this setting is Off.
ZoneSeqCoord: In present case this parameter is set to OFF.
Table 3-38 gives the recommended settings for Autorecloser.

116
Table 3-38: Autorecloser
Setting
Parameter
Description
Recommended
Settings
Unit
Operation Off, ExternalCtrl, On ExternalCtrl -
ARMode The AR mode selection e.g. 3ph, 1/3ph 1ph -
t1 1Ph Open time for shot 1, single-phase 1.000 s
t1 3Ph Open time for shot 1, delayed reclosing 3ph 6.000 s
t1 3PhHS
Open time for shot 1, high speed reclosing
3ph
0.400 s
tReclaim Duration of the reclaim time 25.00 s
tSync Maximum wait time for synchrocheck OK 30.00 s
tTrip Maximum trip pulse duration 0.200 s
tPulse Close pulse duration 0.200 s
tCBClosedMin
Min time that CB must be closed before
new sequence allows
5 s
tUnsucCl
Wait time for CB before indicating
Unsuccessful/ Successful
30.00 s
Priority
Priority selection between adjacent
terminals None/Low/ High
High -
tWaitForMaster Maximum wait time for release from Master 60.00 s
NoOfShots Max number of reclosing shots 1-5 1 -
StartByCBOpen
To be set ON if AR is to be started by CB
open position
Off -
CBAuxContType
Select the CB aux contact type NC/NO for
CBPOS input
NormOpen -
CBReadyType
Select type of circuit breaker ready signal
CO/OCO
OCO -
t1 2Ph Open time for shot 1, two-phase 1.000 s
t2 3Ph Open time for shot 2, three-phase 30.00 s
Extended t1
Extended open time at loss of permissive
channel Off/On
Off -
tExtended t1
3Ph Dead time is extended with this value
at loss of perm ch
0.500 s

117
Setting
Parameter
Description
Recommended
Settings
Unit
tInhibit Inhibit reclosing reset time 5.000 s
CutPulse Shorten closing pulse at a new trip Off/On Off s
Follow CB
Advance to next shot if CB has been closed
during dead time
Off -
AutoCont
Continue with next reclosing-shot if
breaker did not close
Off -
tAutoContWait
Wait time after close command before
proceeding to next shot
4.000 s
UnsucClByCBChk
Unsuccessful closing signal obtained by
checking CB position
NoCBCheck -
BlockByUnsucCl Block AR at unsuccessful reclosing Off -
ZoneSeqCoord
Coordination of downstream devices to
local prot unit's AR
Off -

118
below:
From CT:
IA
IB
IC
IN
From Line VT:
VAN
VBN
VCN
Fron Aux VT
Vo
Recommended Digital Signals(Typical)
— Main 1 Trip
— Main II Trip
— CBI Status APH
— CB I Status BPH
— CB I Status CPH
— CB II Status A PH
— CB II Status B PH
— CB II Status C PH
Note: These may need modification depending upon Protections chosen and the contact availability
for certain functions.
Recording capacity

119
— Record minimum eight analog inputs (8) and minimum 16 binary signals per bay or
circuit.
Memory capacity
— Minimum 3s of total recording time
Recording times
PreFaultRecT: It is the recording time before the starting point of the disturbance. The setting is
PostFaultRecT: This is the maximum recording time after the disappearance of the trig-signal. The
setting is recommended to be set to 2.5s
PostRetrig: If it is made ON, new disturbance will be recorded if new trigger signal appears during
a recording. If it is made OFF, a separate DR will not be triggered if new trigger signal appears
during a recording. This parameter is recommended to be set to OFF normally.
Setting
Parameter
Description
Recommended
Settings Unit
ZeroAngleRef Reference channel (voltage), phasors, 1 Ch

120

121
APPENDIX-A: Coordination of 400kV Line Protection Zone-2 and Zone-3
with IDMT O/C E/F relays of 400kV side of ICT and 220kV Line
Zone-2 and Zone-3 timers of 400kV line distance relay need to be coordinated with 400kV side
IDMT O/C and E/F relays provided on the 400/220kV ICT and 220kV line in order to make sure that
for faults on 220kV line, the IDMT O/C and E/F relays have chance to operate before Zone 2 or
Zone-3 of 400kV Distance relay operates for the cases where Zone 2/Zone 3 reach encroaches into
220kV side of Transformer.
The calculations given in this appendix are with following objective:
1. Settings to be provided on IDMT O/C relays of 400kV side of ICT and on 220 kV line (As per the
protection guideline, 220kV line protection shall have distance relay as Main-I and Main-II.
However, most of the utilities use single distance main and back up O/C protection and hence
O/C protection on 220kV line has also been considered for illustration).
3. Settings to be provided on IDMT E/F relays on 400kV line, 400kV side of ICT and 220kV line
4. Coordination curves for ICT O/C relays with Zone-2 and Zone-3
5. Coordination curves for ICT E/F relays with Zone-2 and Zone-3
6. Does Zone-2 and Zone-3 reaches encroach into 220kV side of ICT for 1-ph and ph-ph faults for
various fault levels.
1. System Details:
Figure A-1 shows the system details for the network under consideration for relay setting. Table
A-1 gives the setting for the over current and earth fault relays for the network under
consideration.
2. 3-Ph Fault Current:
Figure A-2 shows the 3-Ph fault currents operating time of relays for a fault at 5% of 220kV
L-1. The operating times are taken from phase over current coordination curves given in figure
A-3.
3. Ph-G Fault Current:
Figure A-4 shows the earth fault currents operating time of relays for a fault at 5% of 220kV L-
1. The operating times are taken from earth fault current coordination curves given in figure A-5.

122
SLD given in Figure A-6 shows 1-Ph fault current operating time of the relay for a fault at
remote end of the 400kV line. The operating time are taken from over current coordination
curves given in figure A-7. Operating of Directional E/F relay is less than Zone 3 operating time
for the fault current more than1302.28A. Hence minimum time (tMin) of Directional E/F relay is
set to 1.1s to achieve coordination of Directional E/F relay with Zone-3 operating time. Fault
current will be more than 1302.28A for the fault in protected line section.
Table A-1 Settings of Over current and Earth fault relays
Phase Relay Settings
Thermal / Curve
(NEMA Code :67)
Instantaneous
Setting
(NEMA Code :50)
SI.
NO
Relay Name CT ratio
Base
current
set Ib in A Plug
setting Ip
(I/Ib) in%
TMS
Tp
Ip
(I/Ib) in%
Tp
in s
1 TR-1 Primary 1000/1 A 455 150% 0.24 800% 0.05
2 220kV Directional O/C 800/1 A 800 100% 0.25 - -
Earth Relay Settings
Thermal / Curve
(NEMA Code :67N)
Instantaneous
Setting
(NEMA Code :50N)
SI.
NO
Relay Name CT ratio
Base
current
set Ib in A Plug
setting Ie
(I/Ib) in%
TMS
Te
Ie
(I/Ib) in%
Te
in s
2 TR-1 Primary 1000/1 A 455 20% 0.56 800% 0.05

123
Figure A-1: System details for the network under consideration for relay setting

124
Figure A-2: 3-Ph fault current for 220 kV side fault

125
Figure A-3: Over Current Relay Curve Co-ordination and Operating Time

126
Figure A-4: Ph-G fault current for 220 kV side fault

127
Figure A-5: Earth Fault Relay Curve Co-ordination and Operating Time

128
Figure A-6: Earth fault relay co-ordination for 400 kV bus fault at Station B (Remote bus of
the protected line)

129
Figure A-7: Earth fault relay operating time co-ordinated with Zone 3 time setting

130
4. Extent of reach of Zone 2 and Zone 3 in to 220kV side
A. For 3ph faults
Check for Zone-2 and Zone-3 reach encroachment into 220kV side of ICT
Zone-2 reactive reach X2 = 87.5Ω
Reactance of 400kV line = 58.33Ω
Reactance of single ICT = 63.49Ω
Reactance of 3 ICTs in parallel = 21.16Ω
Reactance of 3 ICTs in parallel considering infeed from 400kV = ( ) x 21.16Ω
= 182.36Ω
Reactance seen by Zone-2 and Zone-3 elements = 240.69Ω
From the above it can be seen that neither Zone-2 nor Zone-3 reach beyond ICT.
B. For 1ph faults
Check for Zone-2 and Zone-3 reach encroachment into 220kV side of ICT
Reactance of 400kV line = 58.33Ω
Reactance of single ICT = 63.49Ω
Reactance of 3 ICTs in parallel = 21.16Ω
Reactance of 3 ICTs in parallel considering infeed from 400kV= ( ) x 21.16Ω
= 217.48Ω
Reactance seen by Zone-2 and Zone-3 elements = 275.81Ω
From the above it can be seen that neither Zone-2 nor Zone-3 reach beyond ICT.
5. Conclusions:
a. In the present case, because of the infeed effect, Zone-2 and Zone-3 of distance relay at Station-A
is not looking into 220kV side of the auto-transformer even with all the 3 bank in service.
b. The operation timing coordination of Overcurrent relay and earth fault relay of transformer with
Zone-3 is verified.

131
APPENDIX-B: Effect of network change due to a line LILO on relay
settings of LILO line adjacent lines
In example considered for the sample distance relay setting calculation, the 400kV double circuited
line between station-A and station-B has now a loop-in loop-out connection at a distance of 120km
form station-A in one of the circuit. The other circuit, there is no loop-in loop-out. Figure B-1 shows
the modified network.
Figure B-1: Network line diagram of the system after the LILO of one circuit of line AB
Due to change in the network after the LILO, the settings of following functions in the line
protections of lines at various stations will have to be reviewed and revised as described below for
the present case:
Station-A:
Line that has LILO connection (Line A-S): New settings are required for Main distance relays. The
effect of mutual coupling will have to be considered as before.

132
Parallel circuit Line that has not LILO connection (Line A-B): Effects of mutual coupling needs to be
studied because of LILO in the adjacent parallel line.
Station-B:
Line that has LILO connection (Line B-S): New settings are required for Main distance relays for
Line B-S. The effect of mutual coupling will have to be considered as before.
Parallel circuit Line that has not LILO connection (Line B-A): Effects of mutual coupling needs to be
studied because of LILO in the adjacent parallel line.
Station-S:
Line S-A and Line S-B: Being a new station, settings are required for Main distance relays.
To understand the effect of mutual coupling on zone-1 and zone-2 settings, studies have been done
on several possible configurations and these are described in the section below.
Impact of mutual coupling on distance protection in LILO case
Distance relaying of ph-ph and three-phase faults is not influenced by the parallel line. For
protection of phase-to-earth faults, however a measuring error occurs. In principle this error appears
due to the fact that the parallel line earth-current (IEP = 3.I0P) induces a voltage IEP. Z0m/3 in the fault
loop.
The distance relay phase-to-earth units measure;
Where:
is phase to earth short circuit voltage at the relay location in the faulted phase
is short circuit current in the faulted phase
is earth current of faulty line
is earth compensation factor.
Considering the conventional value of earth return compensation as given by

133
The distance protection zone reaches vary with the switching state of the parallel line configuration.
The most common are listed below.
I. Parallel line out of service and earthed at both ends.
II. Parallel line switched off and not earthed or earthed only at one line end.
III. Both lines in service.
The impedance measured by the distance relay will be different depending on the operation
condition of the parallel line.
Given below are several cases studied. The line data used here is as under.
Z1: Line positive sequence impedance = 0.0288+j0.307 ohm/km
Z0: Line zero sequence impedance =0.2689+j1.072 ohm/km
Z0m: Mutual zero sequence impedance = 0.228 + j0.662 ohm/km
Measurement errors in distance relays for a double circuited line with LILO:
The distance protection zone reaches vary with the switching state of the parallel line configuration.
Different configurations of the line with and without the sources at remote end and LILO end are
studied and the measured reach values of the distance relay and voltage, currents observed after
the occurrence of the fault are tabulated.
The error in measured impedance is computed as
%Error = Measured Impedance – Actual Impedance
Actual Impedance

134
Case 1: Parallel line A-S switched off and earthed at both ends and fault at station-B
1.1 Line A-S out of service and earthed at both ends and fault at station-B – source at end A only
(Figure B-2 and Table B-1)
Figure B-2: SLG Fault at bus B with source at Station A and Line A-S out of service and
Earthed
Table B-1: Fault At Station-B With Source At Station – A and Line A-S Earthed
Fault location Line Impedance in Ω Apparent Impedance (Z) in Ω % Error
Station B 58.30 49.43 -15.21

135
1.2 Line A-S out of service and earthed at both ends and fault at station-B – sources at ends A and B
Figure B-3: SLG Fault at bus B with sources at Station A B and Line A-S out of service and
Earthed
Table B-2: Fault At Station-B With Sources At Station – A B and Line A-S Earthed
Station B 58.30 49.88 -14.44

136
1.3 Line A-S out of service and earthed at both ends and fault at station-B – sources at ends A, B
and S (Figure B-4 and Table B-3)
Figure B-4: SLG Fault at bus B with sources at Station A, B S and Line A-S out of service
and Earthed
Table B-3: Fault At Station-B With Sources At Station – A, B S and Line A-S Earthed
Station B 58.30 60.09 3.07
In case-1, the distance relay provided on line AB overreaches by 15.2% when source is only at A,
14.44% when source is present at A and B, underreaches by 3% when source is present at A, B
and S. Therefor with zone-1 setting of 80% on line AB, the relay can overreach in to the next
section. Since such occurrences are rare, the risk of overreach will have to be accepted. One factor
in favor of this is the overreach in the following line is normally heavily reduced due to infeeds at the
remote stations.

137
Case 2: Parallel line B-S switched off and earthed at both ends and fault at station-B
2.1 Line B-S out of service and earthed at both ends and fault at station-B – source at end A only
Figure B-5: SLG Fault at bus B with source at Station A and Line B-S out of service and
Earthed
Table B-4: Fault At Station-B With Source At Station – A and Line B-S Earthed
Station B 58.30 52.96 -9.15

138
2.2 Line B-S out of service and earthed at both ends and fault at station-B – sources at ends A and
B (Figure B-6 and Table B-5)
Figure B-6: SLG Fault at bus B with sources at Station A B and Line B-S out of service
and Earthed
Table B-5: Fault At Station-B With Source At Station – A B and Line B-S Earthed
Fault location Line Impedance in (Ω) Apparent Impedance (Z) in Ω % Error
Station B 58.30 53.31 -8.56
2.3 Line B-S out of service and earthed at both ends and fault at station-B – sources at ends A, B

139
Figure B-7: SLG Fault at bus B with sources at Station A, B S and Line B-S out of service
and Earthed
Table B-1: Fault At Station-B With Source At Station – A, B S and Line B-S Earthed
Station B 58.30 46.17 -20.80
In case-2, the distance relay provided on line AB overreaches by 9.1% when source is only at A,
8.5% when source is present at A and B, 20.8% when source is present at A, B and S. Therefor
with zone-1 setting of 80% on line AB, the relay can overreach in to the next section. Since such
occurrences are rare, the risk of overreach will have to be accepted. One factor in favor of this is the
overreach in the following line is normally heavily reduced due to infeeds at the remote stations.
Case 3: Parallel line A-B switched off and earthed at both ends and fault at station-S

140
3.1 Line A-B out of service and earthed at both ends and fault at station-S – source at end A only
Figure B-8: SLG Fault at bus S with source at Station A and Line A-B out of service and
Earthed
Table B-6: Fault At Station-S With Source At Station – A and Line A-B Earthed
Station B 36.84 31.60 -14.22
3.2 Line A-B out of service and earthed at both ends and fault at station-S – sources at ends A and
B (Figure B-9 and Table B-8)

141
Figure B-9: SLG Fault at bus S with sources at Station A B and Line A-B out of service and
Earthed
Table B-7: Fault At Station-S With Sources At Station – A B and Line A-B Earthed
Station B 36.84 38.41 4.26
3.3 Line A-B out of service and earthed at both ends and fault at station-S – sources at ends A, B

142
Figure B-10: SLG Fault at bus S with sources at Station A, B S and Line A-B out of service
and Earthed
Table B-8: Fault At Station-S With Sources At Station – A, B S and Line A-B Earthed
Station B 36.84 38.18 3.63
In case-3, the distance relay provided on line AS overreaches by 14.2% when source is only at A,
underreaches by 4.2% when source is present at A and B, underreaches by 3.63% when source is
present at A, B and S. Therefor with zone-1 setting of 80% on line AS, the relay can overreach in to
the next section. Since such occurrences are rare, the risk of overreach will have to be accepted.
One factor in favor of this is the overreach in the following line is normally heavily reduced due to
infeeds at the remote stations.
Case 4: All lines are in service and fault at station-B

143
4.1 All lines are in service and fault at station-B– source at end A only (Figure B-11 and Table B-
10)
Figure B-11: SLG Fault at bus B with source at Station A
Table B-9: Fault At Station-B With Source At Station A
Station B 58.30 80.21 37.58
4.2 All lines are in service and fault at station-B– sources at ends A and B (Figure B-12 and Table
B-11)

144
Figure B-12: SLG Fault at bus B with sources at Station A and B
Table B-10: Fault At Station-B With Sources At Station – A B
Station B 58.30 74.37 27.56
4.3 All lines are in service and fault at station-B– sources at ends A, B and S (Figure B-13 and
Table B-12)

145
Figure B-13: SLG Fault at bus B with sources at Station A, B S
Table B-11: Fault At Station-B With Sources At Station – A, B and S
Station B 58.30 74.57 27.90
In case-4, the distance relay provided on line AB under reaches by 37.6% when source is only at A,
27.5% when source is present at A and B, 27.9% when source is present at A, B and S. From this it
can be seen that zone-2 tends to under reach and it will not be able to cover the whole section fully
and this is not acceptable. For this reason zone-2 must be set to 120%+37.6%, which is
approximately 160% of the protected line impedance rather than the conventional 120% in order to
accommodate the under reaching effect due to mutual coupling.
Case 5: All lines are in service and fault at station-S
5.1 All lines are in service and fault at station-S– source at end A only (Figure B-14 and Table B-13)

146
Figure B-14: SLG Fault at bus S with source at Station A
Table B-12: Fault At Station-S Without Sources At Station – S B
Station S 36.84 44.25 20.11
5.2 All lines are in service and fault at station-S– sources at ends A and B (Figure B-15 and Table
B-14)

147
Figure B-15: SLG Fault at bus S with sources at Station A and B
Table B-13: Fault At Station-S With Sources At Station – A B
Station S 36.84 37.78 2.55
5.3 All lines are in service and fault at station-S– sources at ends A, B and S (Figure B-16 and
Table B-15)

148
Figure B-16: SLG Fault at bus S with sources at Station A, B S
Table B-14: Fault At Station-S With Sources At Station – A, B S
Station S 36.84 37.64 2.17
In case-5, the distance relay provided on line AS under reaches by 20.1% when source is only at
A, 2.5% when source is present at A and B, 2.2% when source is present at A, B and S. From this
it can be seen that zone-2 tends to under reach and it will not be able to cover the whole section
fully and this is not acceptable. For this reason zone-2 must be set to 120%+20%, which is equal to
140% of the protected line impedance rather than the conventional 120% in order to accommodate
the under reaching effect due to mutual coupling.
Conclusions:
Based on the above studies following conclusions can be made for setting of zone-1 and zone-2 in
case of double circuit line with LILO.

149
• Zone 1 reach setting:
Zone 1: To be set to cover 80% of protected line length. Set zero sequence compensation factor
KN as (Z0 – Z1) / 3Z1. With this setting, the relay may overreach when parallel circuit is open
and grounded at both ends. This risk is considered acceptable. One factor which mitigates this
risk is that the overreach is normally reduced due to infeeds at the remote station.
• Zone 2 reach setting:
Zone 2: To be set to cover minimum 120% of length of principle line section. However, in case
of double circuit lines 140-160% coverage must be provided to take care of under reaching due
to mutual coupling effect. Set zero sequence compensation factor KN as (Z0 – Z1) / 3Z1. Setting
of 140-160% is arrived at considering an expected under reach of about 20-40% when both
lines are in parallel and a margin of 20%.
********************************************

IED USED FOR 400/220/33kV AUTO TRANSFORMER
PROTECTION

Model setting calculation document for Auto Transformer
2
TABLE OF CONTENTS
TABLE OF CONTENTS .............................................................................................................. 2
1 BASIC SYSTEM PARAMETERS......................................................................................... 7
1.1 Network line diagram of the protected Transformer and adjacent circuits.................... 7
1.2 Single line diagram of the Auto Transformer ................................................................... 7
1.3 Transformer parameters .................................................................................................. 10
2 TERMINAL IDENTIFICATION AND LIST OF FUNCTIONS................................................11
2.1 RET670-1........................................................................................................................... 11
2.1.1 Terminal Identification....................................................................................11
2.1.2 List of functions available and those used......................................................11
2.2 RET670-2........................................................................................................................... 16
2.3 REC670.............................................................................................................................. 21
2.3.1 Terminal identification ....................................................................................21
3 SETTING CALCULATIONS AND RECOMMENDED SETTINGS FOR RET670-1..............27
3.1 RET670-1........................................................................................................................... 27
3.1.1 Analog Inputs.................................................................................................27
3.1.2 Local Human-Machine Interface.....................................................................29
3.1.3 Indication LEDs..............................................................................................30
3.1.4 Time Synchronization.....................................................................................31
3.1.5 Parameter Setting Groups..............................................................................35
3.1.6 Test Mode Functionality TEST .......................................................................35
3.1.7 IED Identifiers ................................................................................................36
3.1.8 Rated System Frequency PRIMVAL ..............................................................36
3.1.9 Signal Matrix For Analog Inputs SMAI............................................................37
3.1.10 Transformer differential protection T3WPDIF .................................................38
3.1.11 Tripping Logic SMPPTRC ..............................................................................47
3.1.12 Trip Matrix Logic TMAGGIO...........................................................................48
3.1.13 Four Step Phase Overcurrent Protection OC4PTOC:1 (Used for HV side).....49
3.1.14 Four Step Phase Overcurrent Protection OC4PTOC:2 (Used for HV side
Overload alarm) 56
3.1.15 Four Step Residual Overcurrent Protection EF4PTOC (Used for HV side).....60
3.1.16 Overexcitation protection OEXPVPH—(HV side) ...........................................68
3.1.17 Disturbance Report DRPRDRE......................................................................73
3.2 RET670-2........................................................................................................................... 76
3.2.1 Analog Inputs.................................................................................................76
3.2.3 Indication LEDs..............................................................................................78

3
3.2.7 IED Identifiers ................................................................................................85
3.2.10 1Ph High impedance differential protection HZPDIF ......................................87
3.2.11 Four Step Phase Overcurrent Protection OC4PTOC---(For IV side)...............90
3.2.12 Four Step Residual Overcurrent Protection EF4PTOC---(for IV side).............95
3.2.13 Overexcitation protection OEXPVPH---(IV side)...........................................101
3.2.14 Disturbance Report DRPRDRE....................................................................105
3.3 REC670............................................................................................................................ 108
3.3.1 Analog Inputs...............................................................................................108
3.3.2 Local Human-Machine Interface...................................................................110
3.3.3 Indication LEDs............................................................................................111
3.3.4 Time Synchronization...................................................................................112
3.3.5 Parameter Setting Groups............................................................................115
3.3.6 Test Mode Functionality TEST .....................................................................116
3.3.7 IED Identifiers ..............................................................................................116
3.3.8 Rated System Frequency PRIMVAL ............................................................117
3.3.9 Signal Matrix For Analog Inputs SMAI..........................................................117
3.3.10 Synchrocheck function (SYN1).....................................................................119
APPENDIX-A: CO-ORDINATION OF 400KV/220KV ICT IDMT O/C E/F RELAYS AT
STATION-A..............................................................................................................................124

4
LIST OF FIGURES
Figure 1-1: Network line diagram of the protected Transformer...................................................................7
Figure 1-2: Single line diagram of the Auto Transformer with CT ratios.......................................................8
Figure 3-1: Representation of the restrained and the unrestrained operate characteristics ......................39
Figure 3-2: Directional function characteristic............................................................................................50
Figure 3-3: Operating characteristic for earth-fault directional element.....................................................61
Figure 3-4: A typical overexcitation capability curve and V/Hz protection settings for power transformer 70
Figure 3-5: Relay tailor made curve and Transformer withstand limit curve (V/Hz Vs s) ..........................71
Figure 3-9: Relay tailor made curve and Transformer with stable limit curve (V/Hz Vs s) ......................103
Figure A-1: System details for the network under consideration for relay setting ....................................127
Figure A-2: 3-Ph fault current for 220 kV side line fault ............................................................................127
Figure A-3: 3-Ph fault current for 220 kV side bus fault............................................................................128
Figure A-4: Phase Over Current Relay Curve Co-ordination and Operating Time for 220 kV line fault...129
Figure A-5: Ph-G fault current for 220 kV side line fault ...........................................................................130
Figure A-6: Ph-G fault current for 220 kV side bus fault...........................................................................130
Figure A-7: Earth Fault Relay Curve Co-ordination and Operating Time Operating Time for 220 kV line
fault............................................................................................................................................................131
Figure A-8: 3-Ph fault current for 400 kV side bus fault............................................................................132
Figure A-9: Ph-G fault current for 400 kV side bus fault...........................................................................132

5
LIST OF TABLES
Table 1-1: Details of CTs and PTs on both HV and IV sides of AT ..............................................................9
Table 2-1: List of functions in RET670-1.....................................................................................................11
Table 2-3: List of functions in REC670 .......................................................................................................21
Table 3-1: Analog inputs .............................................................................................................................28
Table 3-2: Local human machine interface.................................................................................................29
Table 3-3: LEDGEN Non group settings (basic).........................................................................................30
Table 3-4: Time synchronization settings ...................................................................................................33
Table 3-5: Parameter setting group ............................................................................................................35
Table 3-6: Test mode functionality..............................................................................................................36
Table 3-7: IED Identifiers ............................................................................................................................36
Table 3-8: Rated system frequency............................................................................................................37
Table 3-9: Signal Matrix For Analog Inputs.................................................................................................38
Table 3-10: Differential protection Settings.................................................................................................44
Table 3-11: Tripping Logic ..........................................................................................................................47
Table 3-12: Trip Matrix Logic ......................................................................................................................48
Table 3-13: Four Step Phase Overcurrent Protection ................................................................................53
Table 3-15: Four Step Residual Overcurrent Protection.............................................................................65
Table 3-16: Overexcitation protection OEXPVPH ......................................................................................72
Table 3-17: Disturbance Report..................................................................................................................75
Table 3-18: Analog inputs ...........................................................................................................................76
Table 3-19: Local human machine interface...............................................................................................78
Table 3-20: LEDGEN Non group settings (basic).......................................................................................79
Table 3-21: Time synchronization settings .................................................................................................81
Table 3-22: Parameter setting group ..........................................................................................................84
Table 3-23: Test mode functionality............................................................................................................84
Table 3-24: IED Identifiers ..........................................................................................................................85
Table 3-25: Rated system frequency..........................................................................................................85
Table 3-26: Signal Matrix For Analog Inputs...............................................................................................87
Table 3-27: 1Ph High impedance differential protection HZPDIF...............................................................89
Table 3-30: Overexcitation protection OEXPVPH ....................................................................................104
Table 3-31: Disturbance Report................................................................................................................107
Table 3-32: Analog Inputs.........................................................................................................................108
Table 3-33: Local human machine interface.............................................................................................110
Table 3-34: LEDGEN Non group settings (basic).....................................................................................111
Table 3-35: Time Synchronization ............................................................................................................113
Table 3-36: Parameter Setting Groups .....................................................................................................115
Table 3-37: Test Mode Functionality.........................................................................................................116
Table 3-38: IED Identifiers ........................................................................................................................117
Table 3-39: Rated System Frequency ......................................................................................................117
Table 3-40: Signal Matrix For Analog Inputs.............................................................................................118
Table 3-41: Setting of Synchrocheck function ..........................................................................................122
Table A-1 Settings of Over current and Earth fault relays ........................................................................126

6
FEEDER: 400/220/33kV Auto Transformer at Station-A
PROTECTION ELEMENT: Main-I Main-II Protection

7
1 BASIC SYSTEM PARAMETERS
1.1 Network line diagram of the protected Transformer and adjacent
circuits
The network line diagram (Figure 1-1) of the system under consideration showing
protected Transformer along with adjacent associated elements is shown below.
The network diagram should indicate the voltage levels, line lengths,
transformer/generator rated MVA fault contributions of each element for 3-ph
fault at station-A 400kV and 220kV buses.
Figure 1-1: Network line diagram of the protected Transformer
1.2 Single line diagram of the Auto Transformer
Single line diagram of the Auto transformer, various protection functions used and CT/PT
connections is shown in Figure 1-2.

8
Figure 1-2: Single line diagram of the Auto Transformer with CT ratios

9
CT and PT details:
Table 1-1 gives the Details of CTs and PTs on both HV and IV sides of AT.
Table 1-1: Details of CTs and PTs on both HV and IV sides of AT
CT details
Name of
the CT
Name of the
Core
CT ratio CT details
CORE-1 1000/1A
CLASS:PS, Vk:2000V, Imax at Vk:60mA, Rct@75
DEGREE CENTIGRADE ohm: 5Ω
CORE-2 1000/1A
CORE-3 1000/1A CLASS:0.2, 30VA
CORE-4 2000/1A
4B-CT
CORE-5 2000/1A
CORE-1 2000/1A
CORE-2 2000/1A
CORE-3 1000/1A
CORE-4 1000/1A
4C-CT
CORE-5 1000/1A
CORE-1 1000/1A
DEGREE CENTIGRADE ohm: 2.5Ω
1CT
CORE-1 1000/1A
2CT
NCT CORE-1 1000/1A
CORE-1 1600/1A
CORE-2 800/1A
2C-CT
CORE-4 800/1A
CORE-5 800/1A

10
PT details
Name of the PT Name of the Core PT ratio PT details
HV PT I (400/√3)/(0.11/√3) 3P, 50VA
LV PT I (220/√3)/(0.11/√3) 3P, 50VA
1.3 Transformer parameters
Transformer: At Substation-A
Frequency: 50Hz
%Impedance: 12.5%
Transformer Rating: 315MVA, 400/220/33kV, 454.7/826.7/1837A (OFAF)
Vector Group: YNa0d11

11
2 TERMINAL IDENTIFICATION AND LIST OF FUNCTIONS
The various functions required for the Auto Transformer protection are divided in three IEDs
namely RET670-1, RET670-2 and REC670 for the purpose of illustration. The terminal
identification of this and list of various functions available in these IEDs are given in this section.
2.1 RET670-1
Object Name: 400/220/33kV Auto Transformer
Unit Name: RET670-1(ver1.2)--Differential and HV Over-fluxing relay, HV Back-up O/C E/F relay
Frequency: 50Hz
Table 2-1 gives the list of functions/features available in RET670-1 relay and also indicates the
functions/feature for which settings are provided in this document. The functions/features are
indicative and vary with IED ordering code IED application configuration.
Table 2-1: List of functions in RET670-1
Sl.No. Function/features available In RET670 Function/feature
activated
Yes/No
Recommended
Settings
provided
1 Analog Inputs YES

12
14 Signal Matrix For mA Inputs SMMI YES
19 Transformer differential protection
T3WPDIF
YES
20 1Ph High impedance differential protection
HZPDIF
NO
21 Instantaneous Phase Overcurrent
Protection PHPIOC
NO
22 Four Step Phase Overcurrent Protection
OC4PTOC:1
YES
OC4PTOC:2
YES
24 Instantaneous Residual Overcurrent
Protection EFPIOC
NO
25 Four Step Residual Overcurrent Protection
EF4PTOC
YES
26 Four step directional negative phase
sequence overcurrent protection
NS4PTOC
NO
27 Sensitive directional residual overcurrent
and power protection SDEPSDE
NO
28 Thermal overload protection, two time
constants TRPTTR
YES
29 Breaker failure protection CCRBRF NO
30 Pole discordance protection CCRPLD NO

13
31 Directional underpower protection
GUPPDUP
NO
32 Overexcitation protection OEXPVPH YES
33 Single Point Generic Control 8 Signals
SPC8GGIO
NO
34 Automationbits, Command Function For
DNP3.0 AUTOBITS
NO
35 Single Command, 16 Signals
SINGLECMD
NO
36 Scheme Communication Logic For
Distance Or Overcurrent Protection
ZCPSCH
NO
37 Current Reversal And Weak-End Infeed
Logic For Distance Protection
ZCRWPSCH
NO
40 Low Active Power And Power Factor
Protection LAPPGAPC
NO
41 Compensated Over and Undervoltage
Protection COUVGAPC
NO
42 Sudden Change in Current Variation
SCCVPTOC
NO
44 Negative Sequence Overvoltage
Protection LCNSPTOV
NO
45 Zero Sequence Overvoltage Protection
LCZSPTOV
NO
46 Negative Sequence Overcurrent
Protection LCNSPTOC
NO
47 Zero Sequence Overcurrent Protection
LCZSPTOC
NO

14
54 Boolean 16 To Integer Conversion B16I YES
55 Boolean 16 To Integer Conversion With
Logic Node Representation B16IFCVI
NO
57 Integer To Boolean 16 Conversion With
Logic Node Representation IB16FCVB
NO
58 Measurements CVMMXN NO
59 Phase Current Measurement CMMXU NO
60 Phase-Phase Voltage Measurement
VMMXU
NO
61 Current Sequence Component
Measurement CMSQI
NO
62 Voltage Sequence Measurement VMSQI NO
63 Phase-Neutral Voltage Measurement
VNMMXU
NO
64 Event Counter CNTGGIO NO
65 Event Function EVENT NO
66 Logical Signal Status Report
BINSTATREP
NO
68 Measured Value Expander Block
RANGE_XP
NO
70 Event List NO
71 Indications NO

15
76 Function For Energy Calculation And
NO
78 IEC 61850 Generic Communication I/O
NO
79 IEC 61850-8-1 Redundant Station Bus
Communication
NO
84 Multiple Command And Transmit
MULTICMDRCV, MULTICMDSND
NO

16
2.2 RET670-2
Unit Name: RET670-2 (Ver 1.2) -- REF and LV Over-fluxing relay, IV Back-up O/C E/F relay#
Frequency: 50Hz
activated
Yes/No
Recommended
Settings
provided
1 Analog Inputs YES

17
T3WPDIF
NO
HZPDIF
YES
Protection PHPIOC
NO
OC4PTOC
YES
Protection EFPIOC
NO
EF4PTOC
YES
NS4PTOC
NO
NO
constants TRPTTR
NO
30 Directional underpower protection
GUPPDUP
NO
31 Overexcitation protection OEXPVPH YES
SPC8GGIO
NO
DNP3.0 AUTOBITS
NO

18
SINGLECMD
NO
ZCPSCH
NO
ZCRWPSCH
NO
Protection LAPPGAPC
NO
Protection COUVGAPC
NO
SCCVPTOC
NO
Protection LCNSPTOV
NO
LCZSPTOV
NO
Protection LCNSPTOC
NO
LCZSPTOC
NO
54 Boolean 16 To Integer Conversion With NO

19
NO
VMMXU
NO
Measurement CMSQI
NO
VNMMXU
NO
BINSTATREP
NO
RANGE_XP
NO
69 Event List NO
70 Indications NO
NO
NO
78 IEC 61850-8-1 Redundant Station Bus NO

20
Communication
NO

21
2.3 REC670
Frequency: 50Hz
Sl.No.
Functions/Feature available In REC670 Features/Functions
activated
Yes/No
Recommended
Settings
provided
1 Analog Inputs YES

22
20
Instantaneous Phase Overcurrent
Protection PHPIOC
NO
21
OC4PTOC
NO
22
Instantaneous Residual Overcurrent
Protection EFPIOC
NO
23
EF4PTOC
NO
24
Four step directional negative phase
sequence overcurrent protection NS4PTOC
NO
25
Sensitive Directional Residual Overcurrent
NO
26
Constant LPTTR
NO
27
Thermal overload protection, two time
constants TRPTTR
NO
31
Directional Underpower Protection
GUPPDUP
NO
32
Directional Overpower Protection
GOPPDOP
NO
35 Two Step Undervoltage Protection
UV2PTUV
NO
36 Two Step Overvoltage Protection NO

23
OV2PTOV
37
Two Step Residual Overvoltage Protection
ROV2PTOV
NO
42
Rate-Of-Change Frequency Protection
SAPFRC
NO
43
General Current and Voltage Protection
CVGAPC
NO
46
Synchrocheck, Energizing Check, And
YES
47 Autorecloser SMBRREC NO
49
NO
50
Logic Rotating Switch For Function
NO
52
Generic Double Point Function Block
DPGGIO
NO
53
SPC8GGIO
NO
54
DNP3.0 AUTOBITS
NO
56
Scheme Communication Logic For
ZCPSCH
NO
57 Phase Segregated Scheme Communication NO

24
Logic For Distance Protection ZC1PPSCH
58
Logic For Distance Protection ZCRWPSCH
NO
60
Scheme Communication Logic For
Residual Overcurrent Protection ECPSCH
NO
61
ECRWPSCH
NO
62
NO
64
Low Active Power And Power Factor
Protection LAPPGAPC
NO
65
Compensated Over And Undervoltage
Protection COUVGAPC
NO
66
Sudden Change In Current Variation
SCCVPTOC
NO
68
LCNSPTOV
NO
69
LCZSPTOV
NO
70
LCNSPTOC
NO
71
LCZSPTOC
NO

25
79
Boolean 16 To Integer Conversion With
NO
81
Integer To Boolean 16 Conversion With
NO
84
Phase-Phase Voltage Measurement
VMMXU
YES
85
Current Sequence Component
Measurement CMSQI
YES
87
Phase-Neutral Voltage Measurement
VNMMXU
NO
92
Measured Value Expander Block
RANGE_XP
NO
93 Disturbance Report DRPRDRE NO
94 Event List YES
95 Indications YES
100
Function For Energy Calculation And
NO
102 IEC 61850 Generic Communication I/O NO

26
103
Communication
NO
108
NO

27
3 SETTING CALCULATIONS AND RECOMMENDED SETTINGS
FOR RET670-1
The various functions required for the transformer protection are divided in three IEDs namely
RET670-1, RET670-2 and REC670. The setting calculations and recommended settings for
various functions available in these IEDs are given in this section.
# HV and IV side Back up Directional overcurrent and earth fault protections shall preferably be
provided in a separate IED to ensure better reliability.
3.1 RET670-1
3.1.1 Analog Inputs
Name# HV-IL1 HV-IL2 HV-IL3 IV-IL1 IV-IL2 IV-IL3
CTprim 1000A 1000A 1000A 800A 800A 800A
Name# UL1 UL2 UL3 SPARE SPARE SPARE
VTsec 110V 110V 110V 110V 110V 110V
# User defined text
Table 3-1 gives the recommended settings for Analog inputs.

28
Setting
Parameter
Description
Recommended
Settings Unit
PhaseAngleRef
Presentation
TRM40-Ch1 -
CTStarPoint1
ToObject -
CTStarPoint2
ToObject -
CTsec2 Rated CT secondary current 1A A
CTprim2 Rated CT primary current 1000A A
CTStarPoint3
ToObject -
CTStarPoint4
ToObject -
CTStarPoint5
ToObject -
CTStarPoint6
ToObject -

29
Note: OscBlock and OscRelease defines the filtering time at activation. Low frequency gives
slow response for digital input.
Setting
Parameter
Description
Recommended
Settings Unit
AutoRepeat
(Off)
On -

30
Setting
Parameter
Description
Recommended
Settings Unit
steady and latched till manually reset. When manually reset, it will go OFF when trip is not there.
If trip still persist, it will flash.
Setting
Parameter
Description
Recommended
Settings Unit
tMax
disturbance
0.0 s

31
These settings are used for synchronizing IED clock time with network time. Ex: GPS or IRIG-B
time.
CoarseSyncSrc: Select the time synchronization source available such as SPA, LON, SNTP
etc. Synchronization messages from sources configured as coarse are checked against the
internal relay time and only if the difference in relay time and source time is more than 10s then
relay time will be reset with the source time. This parameter need to be based on time source
available in site.
once it is selected, time of available time source in network will update to relay if there is a
difference in the time between relay and source. This parameter need to be based on time
source available in site.
SyncMaster: Normally it is set OFF. If time to the relay is received from a GPS antenna
(example), make the relay as master to synchronize with other relays.
HWSyncSrc: This is applicable if process bus IEC61850-9-2 protocol is used for receiving
analog values (optical CT PTs). In this case select time source available same as that of merging
unit. This setting is not applicable in present case.

32
AppSynch: If there is any loss of time sync, protection function will be blocked if AppSynch set
to Synch based on SyncAccLevel. If AppSunch set to NoSynch, protection functions are not
blocked. Recommended setting is NoSynch.
SyncAccLevel: If this is set to “Class T5 (1us)” and time synch error is more than 1us,
protection functions will be blocked. SyncAccLevel should be set to “Unspecified” when Nosynch
is selected at AppSynch. This parameter is not applicable in present case.
ModulePosition: if BIN is set for FineSyncSource, ModulePosition setting is applicable. Here
slot position of IO module in the relay is to be set (Which slot is used for BI). This parameter is
not applicable in present case.
NoHalfHourUTC: Time shift from GMT has to be set a multiple of half hours. Example for India
it is +05:30, means +11. Hence this parameter is set to +11 in present case.
SYNCHIRIG-B Non group settings: These settings are applicable if IRIG-B is used. This
parameter is not applicable in present case.
SynchType: Type of hardware input used for time sync, whether Opto or BNC. This parameter
Table 3-4 gives the recommended settings for Time synchronization.

33
Setting
Parameter
Description
Recommended
Settings Unit
Setting
Parameter
Description
Recommended
Settings Unit
ModulePosition
Synchronization
3 -
BinaryInput
synchronization
1 -
Recommended
Settings Unit

34
Setting
Parameter
Description
Recommended
Settings Unit
UTCTimeOfDay
3600 s
Setting
Parameter
Description
Recommended
Settings Unit
UTCTimeOfDay
3600 s
Setting
Parameter
Description
Recommended
Settings Unit
Setting
Parameter
Description
Recommended
Settings Unit

35
changed, is set with the parameter t. This is not the delay for changing setting group. This
parameter is normally recommended to set 1s.
MAXSETGR: The parameter MAXSETGR defines the maximum number of setting groups in use
to switch between. Only the selected number of setting groups will be available in the Parameter
Setting
Parameter
Description
Recommended
Settings Unit
t
Changed
1 s
Setting
Parameter
Description
Recommended
Settings Unit

36
Setting
Parameter
Description
Recommended
Settings Unit
CmdTestBit
during testmode
Off -
Setting
Parameter
Description
Recommended
Settings Unit
ObjectName Object name Transformer -
UnitName Unit name RET670 M1 -

37
Setting
Parameter
Description
Recommended
Settings Unit
DFTReference: Set ref for DFT filter adjustment here. These DFT reference block settings
decide DFT reference for DFT calculations.
Each task group has 12 instances of SMAI, in that first instance has some additional features
which is called master. Others are slaves and they will follow master. If measured sample rate
needs to be transferred to other task group, it can be done only with master.
DFTReference shall be set to default value InternalDFTRef if no VT input is available. Since VT
input is available in this case, the corresponding channel shall be set to DFTReference.
Configuration file has to be referred for this purpose.
DFTRefExtOut: This parameter is available only in Master. If reference is to be sent to other
task group, which reference need to be send has to be select here. For example, if voltage input
is connected to 3rd
SMAI of 1ms task group, AdDFTRefCh3 is to be set in DFTRefExtOut of 1ms
task group.
DFTRefExtOut shall be set to default value InternalDFTRef if no VT input is available.
Negation is set to NegateN, it will give output R, Y, B and –N. If Negation is set to Negate3Ph, it
will give output -R, -Y, -B and N.

38
If R, Y, B inputs are connected, N=R+Y+B, and it will do as above. This parameter is
recommended to be set to OFF normally.
SMAI will work only if measured input magnitude is greater than set value in MinValFreqMeas.
This parameter is recommended to set 10% normally.
Setting
Parameter
Description
Recommended
Settings Unit
MinValFreqMeas
Limit for frequency calculation in %
of UBase
10 %
3.1.10 Transformer differential protection T3WPDIF
There are two types of differential relays. Percentage biased differential relay with harmonic
restraint (2nd
and 5th
harmonic restraint) with a high set unit and high impedance differential relay.
For a multi-winding transformer only percentage biased relay can be applied whereas for
autotransformer both percentage biased and high impedance relays can be used. The simplicity
of comparing current into all terminals of the transformer gives the differential relay very high
reliability.
In case of percentage biased differential relays current transformers or auxiliary CT's in a delta
(In case of numerical relays this is done internally) connection have to be used at grounded

39
transformer windings to avoid false operation on external faults. The removed zero sequence
component, however, makes the transformer differential relay less sensitive.
The differential relay protection does an excellent job of meeting a large number of the
protective relaying requirements, but must be combined with other protective devices to provide
full transformer protection.
In case of breaker and half switching schemes, the differential protection C.Ts. associated with
Main and Tie breakers should be connected to separate bias windings and these should not be
paralleled in order to avoid false operation due to dissimilar C.T. transient response.
Differential protection is the most commonly applied protection for large power transformers in
transmission system.
Figure 3-1 shows the restrained and the unrestrained operate characteristics of Differential
protection.
Figure 3-1: Representation of the restrained and the unrestrained operate characteristics

40
SOTFMode: Transformer differential (TW2PDIF for two winding and TW3PDIF for three
winding) function in the IED has a built-in, advanced switch onto fault feature. This feature can
be enabled or disabled by a setting parameter SOTFMode. When SOTFMode = On this feature
is enabled. However it shall be noted that when this feature is enabled it is not possible to test
2nd harmonic blocking feature by simply injecting one current with superimposed second
harmonic. In that case the switch on to fault feature will operate and differential protection will
trip. However for real inrush case the differential protection function will properly restrain from
operation. In present case this parameter is set OFF.
IDiffAlarm: Differential protection continuously monitors the level of the fundamental frequency
differential currents and gives an alarm if the pre-set value is simultaneously exceeded in all
three phases. This feature can be used to monitor the integrity of on-load tap-changer
compensation within the differential function.
The threshold for the alarm pickup level is defined by setting parameter IDiffAlarm. This
threshold should be typically set in such way to obtain operation when on-load tap-changer
measured value within differential function differs for more than two steps from the actual on-
load tap-changer position. To obtain such operation set parameter IDiffAlarm equal to two times
the on-load tap-changer step size (For example, typical setting value is 5% to 10% of base
current). Set the time delayed defined by parameter tAlarmDelay two times longer than the on-
load tapchanger mechanical operating time (For example, typical setting value 10s).
In present case, OLTC compensation is not used. Hence this parameter is set to 10%.
tAlarmDelay: Set the time delayed defined by parameter tAlarmDelay two times longer than the
on-load tap changer mechanical operating time. This parameter is set to 15s in present case.
IdMin: IdMin (Sensitivity in section 1, multiple of trans. HV side rated current set under the
parameter RatedCurrentW1). Default settings for the operating characteristic with IdMin = 0.3pu
of the power transformer rated current can be recommended as a default setting in normal
applications. If the conditions are known more in detail, higher or lower sensitivity can be
chosen. The selection of suitable characteristic should in such cases be based on the
knowledge of the class of the current transformers, availability of information on the load tap
changer position, short circuit power of the systems, and so on. In present case, the tap
changer range is +10% to -10%, considering the margin of 10%, recommended IdMin=0.2pu.
IdUnre: The unrestrained (that is, non-stabilized, instantaneous) part of the differential
protection is used for very high differential currents, where it should be beyond any doubt, that
the fault is internal. This settable limit is constant (that is, not proportional to the bias current).

41
Neither harmonic, nor any other restrain is applied to this limit, which is therefore allowed to trip
power transformer instantaneously. Unrestrained operation level has default value of IdUnre =
10pu, which is typically acceptable for most of the standard power transformer applications.
However in the following cases these setting need to be changed accordingly:
• When CT from T-connection are connected to IED, as in the breaker-and-a half or the ring
bus scheme, special care shall be taken in order to prevent unwanted operation of transformer
differential IED for through-faults due to different CT saturation of T-connected CTs. Thus if
such uneven saturation is a possibility it is typically required to increase unrestrained
operational level to IdUnre = 20-25pu. Since in present case, uneven CT saturation is not
expected, this parameter is set to 10pu.
CrossBlockEn: In the algorithm the user can control the cross-blocking between the phases via
the setting parameter CrossBlockEn. When parameter CrossBlockEn is set to On, cross
blocking between phases will be introduced. There are no time related settings involved, but the
phase with the operating point above the set bias characteristic will be able to cross-block other
two phases if it is self-blocked by any of the previously explained restrained criteria. It is
recommended to set this parameter to ON.
When parameter CrossBlockEn is set to Off, any cross blocking between phases will be
disabled. In present case it is set ON.
NegSeqDiffEn: The internal/external fault discriminator is a very powerful and reliable
supplementary criterion to the traditional differential protection. It is recommended that this
feature shall be always used (that is, On) when protecting three-phase power transformers. The
internal/external fault discriminator detects even minor faults, with a high sensitivity and at high
speed, and at the same time discriminates with a high degree of dependability between internal
and external faults. In the absence of credible field experience, it is set to OFF in the present
case.
IMinNegSeq and NegSeqROA: These parameters are not applicable if NegSeqDiffEn is set to
OFF.
EndSection1, EndSection2, SlopeSection2 and SlopeSection3: EndSection1 (End of
section 1, as multiple of transformer HV side rated current set under the parameter
RatedCurrentW1), EndSection2 (End of section 2, as multiple of transformer HV side rated
current set under the parameter RatedCurrentW1), SlopeSection2 (Slope in section 2),
SlopeSection3 (Slope in section 3). The selection of suitable characteristic should in such
cases be based on the knowledge of the class of the current transformers, availability of
information on the load tap changer position, short circuit power of the systems, and so on.

42
The usual practice for transformer protection is to set the bias characteristic to a value of at
least twice the value of the expected spill current under through faults conditions. These criteria
can vary considerably from application to application and are often a matter of judgment.
In section 2, a certain minor slope is introduced which is supposed to cope with false differential
currents proportional to higher than normal currents through the current transformers.
The more pronounced slope in section 3 is designed to result in a higher tolerance to substantial
current transformer saturation at high through-fault currents, which may be expected in this
section.
In present case, these parameters are left with the default values recommended by manual.
EndSection1, EndSection2, SlopeSection2 and SlopeSection3 are set to 1.25, 3, 40% and 80%
respectively.
I2/I1Ratio: If the ratio of the second harmonic to fundamental harmonic in the differential current
is above the settable limit, the operation of the differential protection is restrained. It is
recommended to set parameter I2/I1Ratio = 15% as default value in case no special reasons
exist to choose other value.
I5/I1Ratio: If the ratio of the fifth harmonic to fundamental harmonic in the differential current is
above a settable limit the operation is restrained. It is recommended to use I5/I1Ratio = 25% as
default value in case no special reasons exist to choose another setting.
OpenCTEnable: The built-in open CT feature can be enabled or disabled by a setting
parameter OpenCTEnable (Off/On). When enabled, this feature prevents mal-operation when a
loaded main CT connected to Transformer differential protection is by mistake open circuited on
the secondary side. In present case this parameter is set OFF.
tOCTAlarmDelay, tOCTResetDelay and tOCTUnrstDelay: These parameters are not
applicable if OpenCTEnable is set OFF.
RatedVoltageW1: Rated voltage of transformer winding 1 (HV winding) in kV. This parameter is
set to 400kV.
RatedVoltageW2: Rated voltage of transformer winding 2 in kV. This parameter is set to
220kV.
RatedVoltageW3: Rated voltage of transformer winding 3 in kV. This parameter is set to 33kV.
RatedCurrentW1: Rated current of transformer winding 1 (HV winding) in A. This parameter is
set to 455A.
RatedCurrentW2: Rated current of transformer winding 2 in A. This parameter is set to 827A.
RatedCurrentW3: Rated current of transformer winding 3 in A. This parameter is set to 1837A.
Above setting parameters are calculated based on 400/220/33kV 315MVA ICT rating details.

43
ConnectTypeW1: Connection type of winding 1: Y-wye or D-delta. This parameter is set to Y.
ConnectTypeW3: Connection type of winding 3: Y-wye or D-delta. This parameter is set to D.
ClockNumberW2: Phase displacement between W2 W1=HV winding, hour notation. This
parameter is set to 0 as it is Auto transformer.
parameter is set to 11, since Auto transformer clock symbol is YNa0d11.
ZSCurrSubtrW1: Enable zer. seq. current subtraction for W1 side, On / Off. The elimination of
zero sequence current is done numerically and no auxiliary transformers or zero sequence traps
are necessary. In present case this parameter is set ON.
ZSCurrSubtrW2: Enable zer. seq. current subtraction for W2 side, On / Off. In present case this
ZSCurrSubtrW3: Enable zer. seq. current subtraction for W3 side, On / Off. For delta windings
this feature shall be enabled only if an earthing transformer exists within differential zone on the
delta side of the protected power transformer. In present case this parameter is set OFF.
TconfigForW1: Two CT inputs (T-config.) for winding 1, YES / NO. For application with so
called T configuration, that is, two restraint CT inputs from one side of the protected power
transformer, such as in the case of breaker-and a- half scheme the primary CT ratings can be
much higher than the rating of the protected power transformer. In present case this parameter
is set to Yes.
CT1RatingW1, CT2RatingW1: CT primary rating in A, T-branch 1, on transf. W1 side and CT
primary in A, T-branch 2, on transf. W1 side. In preset case, these parameters are set to 1000A.
TconfigForW2: Two CT inputs (T-config.) for winding 2, YES / NO. In present case this
parameter is set to No.
CT1RatingW2, CT2RatingW2: These parameters are not applicable TconfigForW2 is set to
NO.
NO.
LocationOLTC1: Transformer winding where OLTC1 is Located. Parameter LocationOLTC1
defines the winding where first OLTC (OLTC1) is physically located. In present case, this is set
to “Not Used”.

44
LowTapPosOLTC1, RatedTapOLTC1, HighTapPsOLTC1, TapHighVoltTC1,
StepSizeOLTC1: These parameters are not applicable if LocationOLTC1 is set to “Not Used”.
LocationOLTC2: Transformer winding where OLTC2 is Located. In present case, this is set to
“Not Used”.
Table 3-10 gives the recommended settings for Differential protection.
Table 3-10: Differential protection Settings
T3WPDIF Group settings (basic)
Setting
Parameter
Description
Recommended
Settings Unit
SOTFMode
Operation mode for switch onto fault
feature
Off -
tAlarmDelay Time delay for diff currents alarm level 15 s
IDiffAlarm Dif. cur. alarm, multiple of base curr,
usually W1 curr.
0.10 IB
IdMin Section1 sensitivity, multi. of base curr,
usually W1 curr.
0.20 IB
IdUnre Unrestr. prot. limit, multi. of base curr.
usually W1 curr.
10 IB
CrossBlockEn Operation Off/On for cross-block logic
between phases
On -
NegSeqDiffEn Operation Off/On for neg. seq.
differential protections
Off -
IMinNegSeq Neg. seq. curr. limit, mult. of base curr,
usually W1 curr.
0.04 IB
NegSeqROA Operate Angle for int. / ext. neg. seq.
fault discriminator
60.0 Deg
T3WPDIF Group settings (advanced)
Setting
Parameter
Description
Recommended
Settings Unit
EndSection1
End of section 1, multi. of base current,
usually W1 curr.
1.25 IB
EndSection2 End of section 2, multi. of base current, 3 IB

45
usually W1 curr.
SlopeSection2 Slope in section 2 of operate-restrain
characteristic, in %
40 %
80 %
I2/I1Ratio Max. ratio of 2nd harm. to fundamental
harm dif. curr. in %
15 %
I5/I1Ratio Max. ratio of 5th harm. to fundamental
25 %
OpenCTEnable Open CT detection feature. Open
CTEnable Off/On
Off -
tOCTAlarmDelay Open CT: time in s to alarm after an
open CT is detected
3 s
tOCTResetDelay Reset delay in s. After delay, diff.
function is activated
0.25 s
tOCTUnrstDelay Unrestrained diff. protection blocked
after this delay, in s
10.0 s
T3WPDIF Non group settings (basic)
Setting
Parameter
Description
Recommended
Settings Unit
RatedVoltageW1 Rated voltage of transformer winding 1
(HV winding) in kV
400 kV
in kV
220 kV
in kV
33 kV
RatedCurrentW1 Rated current of transformer winding 1
(HV winding) in A
455 A
in A
827 A
in A
1837 A
ConnectTypeW1 Connection type of winding 1: Y-wye or
D-delta
WYE(Y) -
D-delta
WYE(Y) -
D-delta
Delta (D) -
ClockNumberW2 Phase displacement between W2
W1=HV winding, hour notation
0 [0 deg] -
11[30 deg lead] -
ZSCurrSubtrW1 Enable zer. seq. current subtraction for
W1 side, On / Off
On -
W2 side, On / Off
On -

46
W3 side, On / Off
Off -
TconfigForW1 Two CT inputs (T-config.) for winding 1,
YES / NO
Yes -
CT1RatingW1 CT primary rating in A, T-branch 1, on
transf. W1 side
1000 A
CT2RatingW1 CT primary in A, T-branch 2, on transf.
W1 side
1000 A
YES / NO
No -
transf. W2 side
800 A
transf. W2 side
800 A
YES / NO
No -
transf. W3 side
1000 A
transf. W3 side
1000 A
LocationOLTC1 Transformer winding where OLTC1 is
located
Not Used -
LowTapPosOLTC
1
OLTC1 lowest tap position designation
(e.g. 1)
1 -
RatedTapOLTC1 OLTC1 rated tap/mid-tap position
designation (e.g. 6)
6 -
HighTapPsOLTC
1
OLTC1 highest tap position designation
(e.g. 11)
11 -
TapHighVoltTC1 OLTC1 end-tap position with winding
highest no-load voltage
1 -
StepSizeOLTC1 Voltage change per OLTC1 step in
percent of rated voltage
1.0 %
located
Not Used -
LowTapPosOLTC
2
OLTC2 lowest tap position designation
(e.g. 1)
1 -
6 -
HighTapPsOLTC
2
OLTC2 highest tap position designation
(e.g. 11)
11 -
1 -
1.0 %

47
All trip outputs from protection functions have to be routed to trip coil through SMPPTRC.
SMPPTRC function will give a pulse of set length (150ms) if trip signal is obtained.
tTripMin: Sets the required minimum duration of the trip pulse. It should be set to ensure that
the breaker is tripped and if a signal is used to start Breaker failure protection CCRBRF longer
than the back-up trip timer in CCRBRF. Normal setting is 0.150s.
Program: For Transformer protection trip, this parameter is recommended to be set to 3 phase.
tWaitForPHS: It Secures 3-pole trip when phase selection fails. In present case, there is no
phase selection, this parameter is not applicable. Therefor minimum setting of 0.02s is set.
CLLKOUT will be latched. Normally recommended setting is OFF. Therefor minimum setting of
0.02s is set.
AutoLock: If it is ON, lockout will be with both trip and SETLKOUT input. If it is set to OFF,
lockout will be with only SETLKOUT input. This parameter is normally recommended to be set
to OFF.
Setting
Parameter
Description
Recommended
Settings Unit
Program
three ph trip
3 phase -
tWaitForPHS
failed
0.020 s
TripLockout
Off -
AutoLock
trip, Off: only inp
Off -

48
example, all Differential, REF, TOC and TEF trips using TMAGGIO function.
duration of the trip pulse to the circuit breaker trip coils. If TMAGGIO is used without SMPPTRC,
set pulse width of trip signal from TMAGGIO in PulseTime.
OnDelay: It is delay for output from TMAGGIO. If it is set to 100ms, even if trip is available, it
will not give output till 100ms. Hence it should be set to 0s. OnDelay timer is to avoid operation
of outputs for spurious inputs.
OffDelay, even if trip goes OFF, the output will appear 100ms. If “steady” mode is used,
pulsetime setting is not applicable, then output can be prolonged to 150ms with this setting. If
TMAGGIO is used with SMPPTRC, this should be set to 0s.
selected, it will give output till input is present if OffDelay is set to zero. If pulsed is selected,
output will be same as that of SMPPTRC.
Setting
Parameter
Description
Recommended
Settings Unit

49
3.1.13 Four Step Phase Overcurrent Protection OC4PTOC:1 (Used for HV side)
The phase over current protection is a very inexpensive, simple and reliable scheme for fault
detection and is used for transformer protection applications. It can provide limited overload
protection but cannot provide instantaneous protection for all internal faults. It can also provide
back-up protection for bus bars. It does provide for transformer fault withstand protection and
some limited over load protection. It can provide back-up for failure of the switching device but
only with very long time delays. In normal applications, directional over current relays are
located on both the HV and IV sides of the transformer. Both relays are set to see into the
transformer. This allows better coordination with external over current relays because of the
need to see only part of the transformer windings.
An additional high set unit is also usually provided. The instantaneous elements help in
providing high-speed clearance of heavy current faults that threaten system stability. The relay
(Instantaneous element) suffers from having to be set very high to prevent tripping on transformer
inrush. Therefore it is ineffective for low magnitude internal transformer faults or phase to ground
faults on the low voltage side of the transformer.
Numerical over current relays provide upgraded performance for transformer back-up protection.
The digital filters remove the DC component and harmonics from the inrush current. Numerical
back-up over current relays can therefore be set much more sensitive than conventional types
and are recommended to be used.
The non-directional over current relays are used when they could be coordinated with the over
current protection on connecting lines. Coordination requirements usually require the clearing
times to be longer than the other types of back-up protection. Directional over current relay
improves the co-ordination by being set to look through the transformer impedance. For this
reason they are normally used for all interconnecting transformers. When applied on both sides
of the transformer, the current levels where coordination with line relaying is required is limited by
the transformer impedance which greatly improves the tripping times for higher current faults in
the transformer. The directional ground over current relay can be set much more sensitive and
with very short time delays. For all interconnecting transformers use of directional over current
and ground over current relays with high set units are recommended.
There are number of general problems with back-up relay viz., the sensitivity to the harmonic and
inrush currents. Setting must be able to allow inrush, which usually means de-sensitizing the

50
back-up relay. Numerical relays can filter harmonics and DC offset currents from the inrush and
therefore may be preferred.
The phase over current threshold should be set to ensure detection of all phase faults, but
above any continuous phase current under normal system operation. The timing should be
coordinated with the phase over current protection of downstream network.
The non-directional Instantaneous high set overcurrent element shall be set to a value
which is 1.3 times the transformer through fault current or transformer inrush current,
whichever is higher.
Figure 3-2 shows the directional function characteristic.
Where1. RCA = Relay characteristic angle, 2. ROA = Relay operating angle,
3. Reverse, 4. Forward
Figure 3-2: Directional function characteristic

51
IBase: Set the Base current for the function on which the current levels are based. This
parameter is set to 455A in present case, which is Transformer HV winding rated current.
UBase: Setting of the Base voltage level on which the directional polarizing voltage is based.
This parameter is set to 400kV in present case, which is Transformer HV winding rated voltage.
AngleRCA: Set the relay characteristic angle, i.e. the angle between the neutral point voltage
and current. This parameter is recommended to be set to 65°
.
AngleROA: Set the relay operating angle, i.e the angle sector of the directional function. This
parameter is recommended to be set to 80°
.
StartPhSel: Number of phases required for operation (1 of 3, 2 of 3, 3 of 3). This parameter is
recommended to be set to 1 out of 3.
DirMode1: Setting of the operating direction for the stage or switch it off. This parameter is set
to “Forward” in present case, which shall be looking towards transformer.
Characteristic1: Setting of the operating characteristic. This parameter is set to “IEC Norm.
Inv.” in present case.
I1: Setting of the operating current level in primary values. This parameter is set to 150% of
base current in present case (two or more transformer 3-ph banks operating in parallel).
t1: When inverse time overcurrent characteristic is selected, the operate time of the stage will
be the sum of the inverse time delay and the set definite time delay. Thus, if only the inverse
time delay is required, it is of utmost importance to set the definite time delay for that stage to
zero. Hence this parameter is set to 0s in present case.
k1: Set the back-up trip time delay multiplier for inverse characteristic. Refer Appendix for more
details.
IMin1: Minimum operate current for step1 in % of IBase. This parameter is set to 150% of base
t1Min: Set the Minimum operating time for inverse characteristic. This parameter is set to 0.1s
in present case.
I1Mult: Set the current multiplier for I1 valid at activation of input ENMULT. As this parameter is
to “Non-directional” in present case.
Characteristic2: Setting of the operating characteristic. This parameter is set to “IEC Def.
Time” in present case.
I2: Setting of the operating current level in primary values. Normally this parameter shall be set
to a current which is higher of 1.3 times the transformer through fault current (220kV side bus

52
fault) or transformer inrush current (Normally 8 -10 times the rated current, which can be set
much lower because of the DC and harmonic filtering in the numerical relays). This value is set
to 800% of HV rated current in present case.
IN2Mult: Set the current multiplier for IN1 valid at activation of input ENMULT. As this
parameter is not applicable in present case, setting is left with default value of 1.
t2: Independent (definitive) time delay of step 2. This parameter can be set in the range of 50-
100ms. In present case, this parameter is set to 50ms.
k2: Set the back-up trip time delay multiplier for inverse characteristic. This parameter is not
applicable in present case since Characteristic2 is set to “IEC Def. Time”.
t2Min: Set the Minimum operating time for inverse characteristic. This parameter is not
IMinOpPhSel: Minimum current for phase selection set in % of IBase. This setting should be
less than the lowest step setting. General recommended setting is 7%.
ResetTypeCrv1: Select the reset curve type for the inverse delay. This parameter is
recommended to set “Instantaneous”. However, to emulate the disc reset behavior, this can be
set to IEC.
tPCrv1, tACrv1, tBCrv1, tCCrv1, tPRCrv1, tTRCrv1 and tCRCrv1: These parameters are
applicable only if Characterist1 is set to Programmable.
HarmRestrain1: Set the release of Harmonic restraint blocking for the stage. This parameter is
kept ON to make the protection stable during charging conditions.
set to IEC.

53
I1: This parameter is set to 150% of base current in present case, which is 683A in primary.
t2: This parameter is set to 0.05s in present case.
Refer Appendix for more details of above four settings.
Table 3-13 gives the recommended settings for Four Step Phase Overcurrent Protection.
Table 3-13: Four Step Phase Overcurrent Protection
OC4PTOC Group settings (basic)
Setting
Parameter
Description
Recommended
Settings Unit
UBase
Base value for voltage settings.
400 kV
AngleROA Relay operation angle (ROA) 80 Deg
StartPhSel
3, 2 of 3, 3 of 3)
1 out of 3 -
DirMode1
Directional mode of step 1 (off, nodir,
forward, reverse)
Forward -
I1
Phase current operate level for step1 in
% of IBase
150 %IB
k1
for step 1
0.26 -
IMin1 Minimum operate current for step1 in % 150% %IB

54
of IBase
t1Min
Minimum operate time for inverse curves
for step 1
0.1 s
I1Mult
Multiplier for scaling the current setting
value for step 1
1.0 -
DirMode2
forward, reverse)
Non-directional -
Characterist2 Time delay curve type for step 2 IEC Def. Time -
I2
% of IBase
800 %IB
k2
for step 2
0 -
IMin2
Minimum operate current for step2 in %
of IBase
800% %IB
t2Min
for step 2
0 s
I2Mult
value for step 2
1.0 -
DirMode3
Directional mode of step 3 (off, nondir,
forward, reverse)
Off -
DirMode4
forward, reverse)
Off -
OC4PTOC Group settings (advanced)
IMinOpPhSel
Minimum current for phase selection in
% of IBase
7 %IB
2ndHarmStab
Second harmonic restrain operation in % of IN
amplitude
15 %
ResetTypeCrv1 Selection of reset curve type for step 1 Instantaneous -
Time curve step 1
0.020 s
tPCrv1
Parameter P for customer programmable
curve for step 1
1 -

55
tACrv1
Parameter A for customer programmable
curve for step 1
13.5 -
tBCrv1
Parameter B for customer programmable
curve for step 1
0 -
tCCrv1
Parameter C for customer
1 -
tPRCrv1
Parameter PR for customer
0.5 -
tTRCrv1
Parameter TR for customer
13.5 -
tCRCrv1
Parameter CR for customer
1 -
HarmRestrain1 Enable block of step 1 from harmonic restrain On -
tReset2
Reset time delay used in IEC Definite
Time curve step 2
0.020 s
tPCrv2
curve for step 2
1 -
tACrv2
curve for step 2
13.5 -
tBCrv2
curve for step 2
0 -
tCCrv2
1 -
tPRCrv2
0.5 -
tTRCrv2
13.5 -
tCRCrv2
1 -
HarmRestrain2 Enable block of step 2 from harmonic restrain On -

56
3.1.14 Four Step Phase Overcurrent Protection OC4PTOC:2 (Used for HV side
Overload alarm)
This function is used for Transformer Over load protection.
Oil Temperature Sensors
The top oil temperature sensors can detect overheating. The temperature limit settings
vary from utility to utility and also depend upon manufacturer's recommendations. Typical
settings are 95°
C for alarm and 100°
C for trip. Bec ause of the heating and cooling
requirements of a transmission power transformer some specialized temperature
protection is required to provide protection over the full range of operating limits of the
transformer. The transformer temperature depends upon the ambient temperature, the
cooling system condition, the excitation voltage and the transformer load. To provide for
temperature protection a sensor is usually provided to indicate top oil temperature. The
power transformers have a large thermal heat sink and can withstand overloads for certain
limited time. Selective protection, monitoring and load management are considered
necessary. The tripping of the transformer should be the last action.
Winding Temperature Sensors
Winding temperature sensors can detect overheating. The temperature limit settings vary from
utility to utility and also depend upon manufacturer's recommendations. Typical settings are
100°
C for alarm and 110°
C for trip. To simulate the winding temperature, a resistor sized to
approximate the heating in the transformer winding at full load is used. The resistor is fed by a
current transformer from one of the phase currents. To add oil temperature, the top oil is
circulated in to a well within the resistor. This combined heating of the resistor from transformer
current and top oil, is used to simulate the winding temperature.
These two relays do not meet any of the other requirements but are again the only relays which
meet the over load temperature limit requirements.
For higher reliability duplicating of the initiating contacts is sometimes done and may be
considered on a case-to-case basis.
Overload Relay
It is also a practice to use a simple over current relay with a time delay arranged to give alarm to
warn the operator of any overloading of the transformer. Use of thermal relay to provide tripping

57
is also practiced by some utilities. But in present case, it is not done because this might trip the
transformer too early which is not desirable.
In the event of sudden increase in load current, the mechanical protections like Oil temperature
high and Winding temperature high should take care of this as described above.
Overload relay shall be set at 105% of rated current with delay of 5 seconds. This shall be
connected to give only alarm and not for tripping. The Alarm is used to alert the operator to
take necessary steps to reduce loading.
This parameter is not applicable in present case, since DirMode1 is set to Non-directional.
. This parameter is not applicable
in present case, since DirMode1 is set to Non-directional.
. This par ameter is not applicable in present case,
since DirMode1 is set to Non-directional.
StartPhSel: Number of phases required for op (1 of 3, 2 of 3, 3 of 3). This parameter is
base current in present case.
t1: This is the definite time delay for step-I. In present case this parameter is set to 5s.
applicable in present case, since Characteristic1 is set to IEC Def. Time.

58
DirMode2, DirMode3 and DirMode4: Setting of the operating direction for the stage or switch it
off. All three stages are set to OFF.
set to IEC.
Setting
Parameter
Description
Recommended
Settings Unit
UBase
400 kV
StartPhSel
3, 2 of 3, 3 of 3)
1 out of 3 -
DirMode1
forward, reverse)
Non-directional -

59
Characterist1 Time delay curve type for step 1 IEC Dif. Time -
I1
% of IBase
105 %IB
k1
for step 1
0.3 -
IMin1
of IBase
105 %IB
t1Min
for step 1
0 s
I1Mult
value for step 1
1.0 -
DirMode2
forward, reverse)
Off -
DirMode3
forward, reverse)
Off -
DirMode4
forward, reverse)
Off -
IMinOpPhSel
% of IBase
7 %IB
2ndHarmStab
Second harmonic restrain operation in %
of IN amplitude
20 %
tReset1
Time curve step 1
0.020 s
tPCrv1
curve for step 1
1 -
tACrv1
curve for step 1
13.5 -
tBCrv1
curve for step 1
0 -

60
tCCrv1
1 -
tPRCrv1
0.5 -
tTRCrv1
13.5 -
tCRCrv1
1 -
HarmRestrain1
Enable block of step 1 from harmonic
restrain
On -
Important note: The above function used for overload alarm shall be configured for alarm
and no trip in the signal matrix of IED.
3.1.15 Four Step Residual Overcurrent Protection EF4PTOC (Used for HV side)
Various ground fault protections used are described below. Generally, these protections are
meant to provide the grounded winding with a low sensitivity ground fault protection only. They
do not provide other types of protection.
Zero Sequence Over Current Relays
Zero-sequence over current relays provide protection against internal phase-to-ground faults.
The neutral current or the residual current may energize the over current relay. The setting may
be much lower than the rated phase current. Harmonic restraint may be required to obtain
sensitive settings. An additional high set unit is also usually provided.
Directional Earth Fault Relay
This type of protection is also specific to transformers with at least one directly grounded or
resistance grounded winding. The protection is specialized to protect for winding faults to
ground. The connections of the over current units can be only in the neutral, or in the residual
phase. These connections can be set much lower than the phase over current because of the
cancellation of the phase current.

61
The sensitivity to the harmonic and inrush currents can be one of the main problems with back-
up ground over current relays. Settings must be able to allow inrush, which usually means
desensitizing the back-up relay. Numerical relay offers the best characteristic since digital filters
remove harmonics and DC offset currents from the inrush.
Figure 3-3 shows the Operating characteristic for earth-fault directional element.
Figure 3-3: Operating characteristic for earth-fault directional element

62
The ground over current threshold should be set to ensure detection of all ground faults, but
above any continuous residual current under normal system operation. The timing should be
coordinated with the downstream backup protection including Zone-3 timing for a remote end
220kV bus fault.
IN1: Setting of the operating current level in primary values. This parameter is set to 20% of
k1: Set the back-up trip time delay multiplier (TMS) for inverse characteristic. Refer Appendix
for more details.
in present case.
set to IEC.

63
IN2: Setting of the operating current level in primary values. Normally this parameter shall be
set to a current which is higher of 1.3 times the transformer 1-phase through fault current
(220kV side bus fault) or transformer inrush current (Normally 8 -10 times the rated current,
which can be set much lower because of the DC and harmonic filtering in the numerical relays).
This value is set to 800% of HV rated current in present case.
t2: Independent (definitive) time delay of step 2, this parameter is set to 50ms in present case.
set to IEC.
measure 3U0 from 3 phase voltages and -3U0 is reference. If it is set “Current”, it will measure
3I0 from I3PPOL input and calculate 3U0 using RNPol and XNPol values. If it is set “Dual”, it will
UPolMin: Setting of the minimum neutral point polarizing voltage level for the directional
function. Generally this parameter is recommended to set 1% of base voltage.
.

64
INDir: Minimum current required for directionality. This should be lower than pickup of earth
fault protection. This parameter is normally recommended to be set to 10% of the base current.
2ndHarmStab: Setting of the harmonic content in IN current blocking level. This is to block
earth fault protection during inrush conditions. Setting is in percentage of I2/I1. This parameter
is normally recommended to be set to 15%.
expected due to sympathetic inrush. If residual current is higher during switching of a
transformer connecting in parallel with other transformer and if 2nd
harmonic current is lower
than 2ndHarmStab set value, earth fault protection may operate because of high residual
current. Inrush current in Line CTs may be higher at beginning and later it may be reduced. If
“BlkParTransf” is set ON, protection will be blocked till residual current is lower than set pickup
of selected “UseStartValue”. This parameter is normally recommended to be set to OFF.
UseStartValue: Select a step which is set for sensitive earth fault protection for above
blocking. This parameter is not applicable if BlkParTransf is set to OFF.
SOTF: Set the SOTF function operating mode. If “SOTF” is set ON, as per the logic given in
TRM, trip from SOTF requires start of step-2 or step-3 along with the activation of breaker
closing command. Since Directional earth function has IDMT characteristics, SOTF is set to
OFF.
ActivationSOTF, ActUndertime, t4U, tSOTF, tUndertime, HarmResSOTF: These parameters
are not applicable if SOTF is set to OFF.

65
Setting
Parameter
Description
Recommended
Settings Unit
UBase
400 kV
UPolMin
Minimum voltage level for polarization in %
of UBase
1 %UB
IPolMin
Minimum current level for polarization in
% of IBase
5 %IB
RNPol
Real part of source Z to be used for current
polar-isation
5 Ohm
XNPol
Imaginary part of source Z to be used for
40 ohm
INDir
Residual current level for Direction release
in % of IBase
10 %IB
2ndHarmStab
of IN amplitude
15 %
UseStartValue
Current level blk at paral-lel transf (step1, 2,
3 or 4)
IN4 -
SOTF
SOTF operation mode (Off/SOTF/Under-
Off -
tSOTF Time delay for SOTF 0.200 s
t4U Switch-onto-fault active time 1.000 s
DirMode1 Directional mode of step 1 (off, nodir, Forward -

66
forward, reverse)
IN1
Operate residual current level for step 1 in
% of IBase
20 %IB
k1
Time multiplier for the dependent time
delay for step 1
0.58 -
IN1Mult
value for step 1
1.0 -
t1Min
for step 1
0.1 s
ResetTypeCrv1 Reset curve type for step 1 Instantaneous -
tReset1 Reset time delay for step 1 0.0 s
HarmRestrain1
restrain
On -
tPCrv1
curve for step 1
1 -
tACrv1
curve for step 1
13.5 -
tBCrv1
curve for step 1
0 -
tCCrv1
1 -
tPRCrv1
0.5 -
tTRCrv1
13.5 -
tCRCrv1
1 -
DirMode2
forward, reverse)
Non-directional -
IN2 Operate residual current level for step 2 in 800 %IB

67
% of IBase
t2 Independent (definite) time delay of step 2 0.05 s
k2
delay for step 2
0.0 -
IN2Mult
value for step 2
1.0 -
t2Min
for step 2
0 s
HarmRestrain2
restrain
On -
tPCrv2
curve for step 2
1 -
tACrv2
curve for step 2
13.5 -
tBCrv2
curve for step 2
0 -
tCCrv2
1 -
tPRCrv2
0.5 -
tTRCrv2
13.5 -
tCRCrv2
1 -
DirMode3
forward, reverse)
Off -
DirMode4
forward, reverse)
Off -

68
3.1.16 Overexcitation protection OEXPVPH—(HV side)
This is another type of specialized protective relaying application where only one protective
level is covered. No other relay provides adequate over-excitation protection of the transformer
core. Damage to the core laminations can occur if an excitation larger than the Volts/Hertz
rating of the transformer is reached. This type of protection does not cover any requirements
except this one.
For grid transformers this protection may lead to cascade tripping due to the fact that all the
substation transformers subjected to over voltages coupled with drop in frequency will be allowed
to trip. An extract from CIGRE, SC-34 working group report 'Transformer overfluxing protection
from ELECTRA (No31), 1973 is reproduced below:
Considering margins between rated and saturation flux densities previously stated, it is
concluded that, in general, no special over fluxing protection is necessary for transformers
connected to the system and this is confirmed by literature and the replies from working groups
enquiries
In Indian power system, it has been a practice to use over excitation relay for the grid
transformers also.
The transformer overfluxing protection has been recommended on both sides for
interconnecting transformers. This is to cover all possible operating conditions, e.g. the
transformer may remain energised from either side. For other transformers overfluxing relay
shall be provided on the untapped winding of the Transformer.
IBase: The IBase setting is the setting of the base (per unit) current on which all percentage
settings are based. Normally the power transformer rated current is used but alternatively the
current transformer rated current can be set. This parameter is set to 455A in present case,
which is Transformer HV winding rated current.
UBase: The UBase setting is the setting of the base (per unit) voltage on which all percentage
settings are based. The setting is normally the system voltage level. This parameter is set to
400kV in present case, which is Transformer HV winding rated voltage.
V/Hz: Operating level for the inverse characteristic, IEEE or tailor made. The operation is
based on the relation between rated voltage and rated frequency and set as a percentage

69
factor. Normal setting is around 108-110% depending of the capability curve for the
transformer/generator. In present case this is set to 110% based on given Overfluxing curve.
V/Hz: Operating level for the tMin definite time delay used at high over-voltages. The
operation is based on the relation between rated voltage and rated frequency and set as a
percentage factor. Normal setting is around 110-180% depending of the capability curve for the
transformer/generator. Setting should be above the knee-point when the characteristic starts to
be straight on the high side. In present case this is set to 150% based on given Overfluxing
curve.
XLeak: The transformer leakage reactance on which the compensation of voltage measurement
with load current is based. The setting shall be the transformer leak reactance in primary ohms.
If no current compensation is used (mostly the case) the setting is not used.
TrPulse: The length of the trip pulse. Normally the final trip pulse is decided by the trip function
block. A typical pulse length can be 150ms.
tMin: The operating times at voltages higher than the set V/Hz. The setting shall match
capabilities on these high voltages. In present case this is set to 1s based on given Overfluxing
curve.
tMax: For overvoltages close to the set value times can be extremely long if a high K time
constant is used. A maximum time can then be set to cut the longest times. Generally this
parameter is recommended to set to maximum available set value i.e 9000s.
tCooling: The cooling time constant giving the reset time when voltages drops below the set
value. Shall be set above the cooling time constant of the transformer.
The default value is recommended to be used if the constant is not known. Hence this
parameter is left with the default value of 1200s.
CurveType: Selection of the curve type for the inverse delay. The IEEE curves or tailor made
curve can be selected depending of which one matches the capability curve best. Tailor made
curve is recommended to match relay set curve with transformer withstanding curve.
kForIEEE: The time constant for the inverse characteristic. Select the one giving the best match
to the transformer capability. This parameter is not applicable if CurveType is selected to Tailor
made.
AlarmLevel: Setting of the alarm level in percentage of the set trip level. The alarm level is
normally set at around 98% of the trip level.
tAlarm: Setting of the time to alarm is given from when the alarm level has been reached.
Typical recommended setting is 5s.

70
A typical overexcitation capability curve and V/Hz protection settings for power transformer is
illustrated in Figure 3-4.
Figure 3-4: A typical overexcitation capability curve and V/Hz protection settings for
power transformer
As per the Transformer Over Fluxing curve provided, Tailor made curve is selected and setting
parameters for tailor made curve are arrived from given Over Fluxing curve as explained below.
V/Hz for the protection is set equal to the permissible continuous overexcitation according to
overexcitation curve provided V/Hz= 110%. When the overexcitation is equal to V/Hz, tripping
is obtained after a time equal to the setting of t1. When the overexcitation is equal to the set
value of V/Hz, tripping is obtained after a time equal to the setting of t6. The interval between
V/Hz and V/Hz is automatically divided up in five equal steps, and the time delays t2 to t5

71
will be allocated to these values of overexcitation. In this case, each step will be (150-110) /5 =
8%, since V/Hz is set to 150% and V/Hz is set to 110% of rated V/Hz.
90% of its capability limits is considered for tripping. For example, if transformer can withstand
126% of Overflux till 55s from Overfluxing curve, we have set trip time 0.9 x 55 = 49.5s in relay
to protect transformer before entering danger zone. The settings of time delays t1 to t6 are listed
in table below. Figure 3-5 shows the tailor made curve for Over fluxing protection.
U/F % Timer Time set (s)
110 t1 9000
118 t2 90
126 t3 49.5
134 t4 18
142 t5 4
150 t6 1
Figure 3-5: Relay tailor made curve and Transformer withstand limit curve (V/Hz Vs s)

72
Table 3-16 gives the recommended settings for Overexcitation protection.
Table 3-16: Overexcitation protection OEXPVPH
OEXPVPH Group settings (basic)
Setting
Parameter
Description
Recommended
Settings Unit
IBase Base current (rated phase current) in A 455 A
UBase Base voltage (main voltage) in kV 400 kV
V/Hz
Operate level of V/Hz at no load and
rated freq in % of (Ubase/frated)
110 %UB/f
V/Hz
High level of V/Hz above which tMin is
used, in % of (Ubase/frated)
150 %UB/f
XLeak
Winding leakage reactance in primary
ohms
0.000 Ohm
TrPulse Length of the pulse for trip signal (in sec) 0.150 s
tMin
Minimum trip delay for V/Hz inverse
curve, in sec
1 s
tMax
Maximum trip delay for V/Hz inverse
curve, in sec
9000 s
tCooling
Transformer magnetic core cooling time
constant, in sec
1200 s
CurveType
Inverse time curve selection, IEEE/Tailor
made
Tailor made -
kForIEEE
Time multiplier for IEEE inverse type
curve
1 -
AlarmLevel Alarm operate level as % of operate level 98 %
tAlarm Alarm time delay, in sec 5 s

73
OEXPVPH Group settings (advanced)
Setting
Parameter
Description
Recommended
Settings Unit
t1Tailor
Time delay t1 (longest) for tailor made
curve, in sec
9000 s
t2Tailor Time delay t2 for tailor made curve, in sec 90 s
t3Tailor Time delay t3 for tailor made curve, in sec 49.5 s
T6Tailor
Time delay t6 (shortest) for tailor made
curve, in sec
1 s
OEXPVPH Non group settings (basic)
Setting
Parameter
Description
Recommended
Settings Unit
MeasuredU Selection of measured voltage PosSeq -
MeasuredI Selection of measured current PosSeq -
system disturbance can be obtained. List of typical signals recommended to be recorded is
given below:
From 400kV Main Bay CT:
IA
IB
IC
IN
From 400kV Tie Bay CT:

74
IA
IB
IC
IN
From 220kV CT:
IA
IB
IC
IN
From 400kV Bus PT:
VAN
VBN
VCN
— Gr-A Trip
— Gr-B Trip
— Intertrip from 220kV Receive
— 400kV Bus bar trip
— Under Voltage
— Over Current
Note: These may need modification depending upon Protections chosen and the contact
availability for certain functions.
Recording capacity
— Record minimum eight (8) analog inputs and minimum sixteen (16) binary signals per
bay or circuit.
Memory capacity
Recording times

75
PostFaultRecT: This is the maximum recording time after the disappearance of the trig-signal.
The setting is recommended to be set to 2.5s
PostRetrig: If it is made ON, new disturbance will be recorded if new trigger signal appears
during a recording. If it is made OFF, a separate DR will not be triggered if new trigger signal
appears during a recording. This parameter is recommended to be set to OFF normally.
Setting
Parameter
Description
Recommended
Settings Unit
ZeroAngleRef
1 Ch

76
3.2 RET670-2
3.2.1 Analog Inputs
Name# REF MV OC-R MV OC-Y MV OC-B SPARE SPARE
CTprim 1 800 800 800 1000 1000
Name# UL1-MV UL2-MV UL3-MV SPARE SPARE SPARE
VTsec 110V 110V 110V 110V 110V 110V
# User defined text
Setting
Parameter
Description
Recommended
Settings Unit
PhaseAngleRef
Presentation
TRM40-Ch1 -
CTStarPoint1
ToObject -
CTStarPoint2
ToObject -

77
CTStarPoint3
ToObject -
CTStarPoint4
ToObject -
CTStarPoint5
ToObject -
CTStarPoint6
ToObject -

78
Setting
Parameter
Description
Recommended
Settings Unit
AutoRepeat
(Off)
On -

79
Setting
Parameter
Description
Recommended
Settings Unit
tMax
disturbance
0.0 s

80
time.
available in site.

81
Setting
Parameter
Description
Recommended
Settings Unit
Setting
Parameter
Description
Recommended
Settings Unit
ModulePosition
Synchronization
3 -

82
BinaryInput
synchronization
1 -
Recommended
Settings Unit
Setting
Parameter
Description
Recommended
Settings Unit
WeekInMonth
starts
Last -
UTCTimeOfDay
3600 s
Setting
Parameter
Description
Recommended
Settings Unit
WeekInMonth
starts
Last -
UTCTimeOfDay
3600 s

83
Setting
Parameter
Description
Recommended
Settings Unit
Setting
Parameter
Description
Recommended
Settings Unit

84
Setting
Parameter
Description
Recommended
Settings Unit
t
Changed
1 s
Setting
Parameter
Description
Recommended
Settings Unit
Setting
Parameter
Description
Recommended
Settings Unit
CmdTestBit
during testmode
Off -

85
Setting
Parameter
Description
Recommended
Settings Unit
Setting
Parameter
Description
Recommended
Settings Unit

86
is connected to 3rd
task group.

87
Setting
Parameter
Description
Recommended
Settings Unit
MinValFreqMeas
of UBase
10 %
3.2.10 1Ph High impedance differential protection HZPDIF
Zero- sequence differential relays (Restricted earth fault relay) provide best protection against
phase-to-ground faults in transformers connected to solidly grounded systems or resistance
grounded transformers. The residual current and the neutral current energize the relay.
Whenever separate phase-wise C.Ts are available on neutral side of transformer, triple pole
high impedance relay may be provided instead of single pole R.E.F. relay.
UAlarm: Set the alarm level. The sensitivity can roughly be calculated as a divider from the
calculated sensitivity of the differential level. A typical setting is 20% of UTrip It can be used as
scheme supervision stage.
tAlarm: Set the time for the alarm. A typical setting is 5s.
UTrip: The level is selected with margin to the calculated required voltage to achieve stability.
Values can be 20-200 V dependent on the application.
SeriesResistor: Set the value of the stabilizing series resistor. Adjust the resistor as close as
possible to the calculated value. Measure the value achieved and set this value here.

88
This Protection is based on High Impedance differential scheme.
The setting value of the relay can be calculated as below:
CT Details: HV phase side, IV side and Neutral side –1000 /1, CL: PS
Rct = 5Ω
Rl = 2.178Ω, considered 250mts distance from Phase/Neutral CT to relay connected using a
cable of 2.5mm2
having resistance of 8.71Ω/km.
Voltage drop across the circulating current circuit for external faults,
Us = Ikmax x (Rct + 2* Rl)/n where
Maximum through fault current (3-ph) = 220kV / (1.732 x (Source Impedance + Trafo
Impedance))
Source Impedance = 0 (Assumed)
MVA Rating = 315MVA
Base impedance = kV2
/ MVA = 153.65Ω
Actual impedance = 153.65 * (12.5 / 100) = 19.21Ω
Maximum through fault current (3-ph) = 220kV / (1.732 x (0+19.21)) = 6.613kA
Rct = the internal resistance of the current transformer secondary winding = 5Ω
Rl = the total resistance of the longest measuring circuit loop = 2.178Ω
n = turns ratio of the current transformer = 1/1000
Hence Us = 6613 x (5 + 2x2.178) * 1 /1000 = 61.87V
Recommended Settings = 68.06 ≈ 68 V with a margin of 10%. (A typical margin is 10 to
50%.)
CT requirement with Vk = 2*Us = 2* 68 = 136V Approx. (min)
REF high impedance Function element is used with Stabilizing resistor.
Pickup shall be decided based on the following criteria:
Stabilizing resistor:
For a sensitivity of 2% i.e 0.02*In, (This 2% setting is for 400kV class transformers. For 765kV
transformer, this could be set higher to take care of DC offset CT errors)
Rs ≥ Us/I =68/0.02 = 3400Ω to be connected in series.
Chosen Rs= 3400Ω. (Approx)
Primary operating sensitivity:
Iprim = n x ( Irelay + Iu + mx Im )
where, n = turn ratio of the CT = 1000 in present case.

89
Irelay = relay set operation current in secondary Amps = 20mA in present case.
Iu = leakage current through the Voltage Dependent Resistor (VDR) at stabilizing voltage Us =
3mA
Approximate value of the current thorough non-linear resistor for the voltage of 68V (Us) is 3mA.
This is considered from the Current voltage characteristics for the non-linear resistors.
m = number of CTs connected in parallel in the secondary circuit = 4 in present case.
Im = magnetizing current of the CT at stabilizing voltage Us = 2mA in present case.
This value is calculated by using CT magnetizing current 60mA at Vk and Vk = 2000V.
By using above values, Iprim = 1000 x (20+ 3 + 3x2) = 29A.
Kindly Note that the following requirements for applying High impedance differential relays.
• Turns ratios of CTs should be identical
• Auxiliary CTs should not be used
• Loop impedance (Rct+2Rl) up to the CT paralleling point should be identical
• Magnetizing characteristics should be identical
Table 3-27 gives the recommended settings for 1Ph High impedance differential protection.
Table 3-27: 1Ph High impedance differential protection HZPDIF
Setting
Parameter
Description
Recommended
Settings Unit
UAlarm
Alarm voltage level in volts on CT
secondary side
13.6 V
tAlarm Time delay to activate alarm 5 s
UTrip
Operate voltage level in volts on CT
secondary side
68 V
SeriesResistor Value of series resistor in Ohms 3400 ohm
Note: The respective analog channel in RET670 (For REF current input) should be set to
1:1.

90
3.2.11 Four Step Phase Overcurrent Protection OC4PTOC---(For IV side)
The phase over current threshold should be set to ensure detection of all phase faults, but
above any continuous phase current under normal system operation. The timing should be
coordinated with the upstream phase over current protection. The guiding philosophy is similar
to the one described for the HV back-up overcurrent function in RET670-1 (Refer Figure 3-2).
parameter is set to 827A in present case, which is Transformer IV winding rated current.
This parameter is set to 220kV in present case, which is Transformer IV winding rated voltage.
.
.
details.
in present case.

91
I2: Setting of the operating current level in primary values. Normally this parameter shall be set
to 130% of maximum transformer 1-phase through fault current or transformer inrush current
whichever is higher.
set to IEC.
set to IEC.

92
I1: This parameter is set to 150% of base current in present case, which is 909.7A in primary.
Setting
Parameter
Description
Recommended
Settings Unit
UBase
220 kV
StartPhSel
3, 2 of 3, 3 of 3)
1 out of 3 -
DirMode1
forward, reverse)
Forward -
I1
% of IBase
150 %IB

93
k1
for step 1
0.18 -
IMin1
of IBase
150 %IB
t1Min
for step 1
0.1 s
I1Mult
value for step 1
1.0 -
DirMode2
forward, reverse)
Non-directional -
I2
% of IBase
800 %IB
k2
for step 2
0.3 -
IMin2
of IBase
800% %IB
t2Min
for step 2
0 s
I2Mult
value for step 2
1.0 -
DirMode3
forward, reverse)
Off -
DirMode4
forward, reverse)
Off -

94
IMinOpPhSel
% of IBase
7 %IB
2ndHarmStab
of IN amplitude
20 %
tReset1
Time curve step 1
0.020 s
tPCrv1
curve for step 1
1 -
tACrv1
curve for step 1
13.5 -
tBCrv1
curve for step 1
0 -
tCCrv1
1 -
tPRCrv1
0.5 -
tTRCrv1
13.5 -
tCRCrv1
1 -
HarmRestrain1
restrain
On -
tReset2
Time curve step 2
0.020 s
tPCrv2
curve for step 2
1 -
tACrv2
curve for step 2
13.5 -
tBCrv2
curve for step 2
0 -

95
tCCrv2
1 -
tPRCrv2
0.5 -
tTRCrv2
13.5 -
tCRCrv2
1 -
HarmRestrain2
restrain
On -
3.2.12 Four Step Residual Overcurrent Protection EF4PTOC---(for IV side)
Guiding philosophy for this function is similar to that described for HV back-up earth fault
function in RET670-1 (Refer Figure 3-3).
above any continuous residual current under normal system operation. The timing should be
coordinated with the upstream backup protection including Zone-3 timing for a remote end
400kV bus fault.
parameter is set to 827A in present case, which is Transformer IV winding rated current.
This parameter is set to 220kV in present case, which is Transformer IV winding rated voltage.

96
details.
in present case.
set to IEC.
IN2: Setting of the operating current level in primary values. Normally this parameter shall be
set to 130% of maximum transformer through fault current.

97
set to IEC.
measure 3U0 from 3 phase voltages and -3U0 is reference. If it is set “Current”, it will measure
3I0 from I3PPOL input and calculate 3U0 using RNPol and XNPol values. If it is set “Dual”, it will
function. Generally this parameter is recommended to set 1% of base voltage.
.
fault protection. This parameter is normally recommended to be set to 10% of the base current.

98
OFF.
Setting
Parameter
Description
Recommended
Settings Unit
UBase
220 kV
UPolMin
of UBase
1 %UB
IPolMin
Minimum current level for polarization in
% of IBase
5 %IB
RNPol
polar-isation
5 Ohm
XNPol
40 ohm
INDir
in % of IBase
10 %IB

99
2ndHarmStab
of IN amplitude
15 %
UseStartValue
3 or 4)
IN4 -
SOTF
Off -
DirMode1
forward, reverse)
Forward -
IN1
% of IBase
20 %IB
k1
delay for step 1
0.51 -
IN1Mult
value for step 1
1.0 -
t1Min
for step 1
0 s
HarmRestrain1
restrain
On -
tPCrv1
curve for step 1
1 -
tACrv1 Parameter A for customer programmable
curve for step 1
13.5 -
tBCrv1
curve for step 1
0 -

100
tCCrv1
1 -
tPRCrv1
0.5 -
tTRCrv1
13.5 -
tCRCrv1
1 -
DirMode2
forward, reverse)
Non-directional -
IN2
% of IBase
800 %IB
k2
delay for step 2
0.0 -
IN2Mult
value for step 2
1.0 -
t2Min
for step 2
0 s
HarmRestrain2
restrain
On -
tPCrv2
curve for step 2
1 -
tACrv2
curve for step 2
13.5 -
tBCrv2
curve for step 2
0 -
tCCrv2 Parameter C for customer
1 -
tPRCrv2
0.5 -

101
tTRCrv2
13.5 -
tCRCrv2
1 -
DirMode3
forward, reverse)
Off -
DirMode4
forward, reverse)
Off -
3.2.13 Overexcitation protection OEXPVPH---(IV side)
Guiding philosophy for this protection is similar to that given for HV side overfluxing function in
RET670-1 (Refer Figure 3-4 for typical overexcitation capability curve).
IBase: The IBase setting is the setting of the base (per unit) current on which all percentage
settings are based. Normally the power transformer rated current is used but alternatively the
current transformer rated current can be set. This parameter is set to 827A in present case,
which is Transformer IV winding rated current.
UBase: The UBase setting is the setting of the base (per unit) voltage on which all percentage
settings are based. The setting is normally the system voltage level. This parameter is set to
220kV in present case, which is Transformer IV winding rated voltage.
V/Hz: Operating level for the inverse characteristic, IEEE or tailor made. The operation is
based on the relation between rated voltage and rated frequency and set as a percentage
factor. Normal setting is around 108-110% depending of the capability curve for the
transformer/generator. In present case this is set to 110% based on given Overfluxing curve.
V/Hz: Operating level for the tMin definite time delay used at high overvoltages. The
operation is based on the relation between rated voltage and rated frequency and set as a
percentage factor. Normal setting is around 110-180% depending of the capability curve for the
transformer/generator. Setting should be above the knee-point when the characteristic starts to
be straight on the high side. In present case this is set to 150% based on given Overfluxing
curve.

102
XLeak: The transformer leakage reactance on which the compensation of voltage measurement
with load current is based. The setting shall be the transformer leak reactance in primary ohms.
If no current compensation is used (mostly the case) the setting is not used.
TrPulse: The length of the trip pulse. Normally the final trip pulse is decided by the trip function
block. A typical pulse length can be 150ms.
tMin: The operating times at voltages higher than the set V/Hz. The setting shall match
capabilities on these high voltages. In present case this is set to 1s based on given Overfluxing
curve.
tMax: For overvoltages close to the set value times can be extremely long if a high K time
constant is used. A maximum time can then be set to cut the longest times. Generally this
parameter is recommended to set to maximum available value i.e. 9000s.
tCooling: The cooling time constant giving the reset time when voltages drops below the set
value. It shall be set above the cooling time constant of the transformer.
The default value is recommended to be used if the constant is not known. Hence this
parameter is left with the default value of 1200s.
CurveType: Selection of the curve type for the inverse delay. The IEEE curves or tailor made
curve can be selected depending of which one matches the capability curve best. Tailor made
curve is recommended to match relay set curve with transformer withstanding curve.
kForIEEE: The time constant for the inverse characteristic. Select the one giving the best match
to the transformer capability. This parameter is not applicable if CurveType is selected to Tailor
made.
AlarmLevel: Setting of the alarm level in percentage of the set trip level. The alarm level is
normally set at around 98% of the trip level.
tAlarm: Setting of the time to alarm is given from when the alarm level has been reached.
Typical recommended setting is 5s.
As per the Transformer Over Fluxing curve provided, Tailor made curve is selected and setting
parameters for tailor made curve are arrived from given Over Fluxing curve as explained below.
V/Hz for the protection is set equal to the permissible continuous overexcitation according to
overexcitation curve provided V/Hz= 110%. When the overexcitation is equal to V/Hz, tripping
is obtained after a time equal to the setting of t1. When the overexcitation is equal to the set
value of V/Hz, tripping is obtained after a time equal to the setting of t6. The interval between
V/Hz and V/Hz is automatically divided up in five equal steps, and the time delays t2 to t5

103
will be allocated to these values of overexcitation. In this case, each step will be (150-110) /5 =
8%, since V/Hz is set to 150% and V/Hz is set to 110% of rated V/Hz.
We have considered 90% of its capability limits for tripping. For example, if transformer can
withstand 126% of Overflux till 55sec from Overfluxing curve, we have set trip time 0.9 x 55 =
49.5s in relay to protect transformer before entering danger zone. The settings of time delays t1
to t6 are listed in table below. Figure 3-9 shows the tailor made curve for Over fluxing protection.
U/F % Timer Time set (s)
110 t1 9000
118 t2 90
126 t3 49.5
134 t4 18
142 t5 4
150 t6 1
Figure 3-6: Relay tailor made curve and Transformer with stable limit curve (V/Hz Vs s)

104
Table 3-30 gives the recommended settings for Overexcitation protection.
Table 3-30: Overexcitation protection OEXPVPH
OEXPVPH Group settings (basic)
Setting
Parameter
Description
Recommended
Settings Unit
IBase Base current (rated phase current) in A 827 A
UBase Base voltage (main voltage) in kV 220 kV
V/Hz
Operate level of V/Hz at no load and
rated freq in % of (Ubase/frated)
110 %UB/f
V/Hz
High level of V/Hz above which tMin is
used, in % of (Ubase/frated)
150 %UB/f
XLeak
Winding leakage reactance in primary
ohms
0.000 Ohm
TrPulse Length of the pulse for trip signal (in sec) 0.150 s
tMin
Minimum trip delay for V/Hz inverse
curve, in sec
1 s
tMax
Maximum trip delay for V/Hz inverse
curve, in sec
9000 s
tCooling
Transformer magnetic core cooling time
constant, in sec
1200 s
CurveType
Inverse time curve selection, IEEE/Tailor
made
Tailor made -
kForIEEE
Time multiplier for IEEE inverse type
curve
1 -
AlarmLevel Alarm operate level as % of operate level 98 %
tAlarm Alarm time delay, in sec 5 s

105
OEXPVPH Group settings (advanced)
Setting
Parameter
Description
Recommended
Settings Unit
t1Tailor
Time delay t1 (longest) for tailor made
curve, in sec
9000 s
t3Tailor Time delay t3 for tailor made curve, in sec 49.5 s
T6Tailor
Time delay t6 (shortest) for tailor made
curve, in sec
1 s
OEXPVPH Non group settings (basic)
Setting
Parameter
Description
Recommended
Settings Unit
MeasuredU Selection of measured voltage PosSeq -
MeasuredI Selection of measured current PosSeq -
given below:
From REF input:
Iref
From 220kV CT:
IA
IB
IC

106
IN
From 220kV Bus PT:
VAN
VBN
VCN
— Group-A Trip
— Group-B Trip
— Inter Trip from HV side Receive
— 220kV CB LBB trip
— Over Current
— Under voltage
Recording capacity
bay or circuit.
Memory capacity
Recording times
— Minimum pre-fault recording time of 200ms

107
Setting
Parameter
Description
Recommended
Settings Unit
ZeroAngleRef
1 Ch

108
3.3 REC670
3.3.1 Analog Inputs
CTprim 1000A 1000A 1000A 1000A 1000A 1000A
Name# UL1-HV UL2-HV UL3-HV UL1-MV UL2-MV UL3-MV
VTsec 110V 110V 110V 110V 110V 110V
# User defined text
Setting
Parameter
Description
Recommended
Settings Unit
PhaseAngleRef
Presentation
TRM40-Ch1 -
CTStarPoint1
ToObject -

109
CTStarPoint3
ToObject -
CTStarPoint4
ToObject -
CTStarPoint5
ToObject -
CTStarPoint6
ToObject -

110
Setting
Parameter
Description
Recommended
Settings Unit
AutoRepeat
(Off)
On -

111
Setting
Parameter
Description
Recommended
Settings Unit
tMax
Disturbance
0.0 s

112
time.
available in site.

113
TimeDomain: In present case, this parameter is set to LocalTime.
Encoding: In present case, this parameter is set to IRIG-B
TimeZoneAs1344: In present case, this parameter is set to PlusTZ
Setting
Parameter
Description
Recommended
Settings Unit

114
Setting
Parameter
Description
Recommended
Settings Unit
ModulePosition
Synchronization
3 -
BinaryInput
Synchronization
1 -
Recommended
Settings Unit
Setting
Parameter
Description
Recommended
Settings Unit
UTCTimeOfDay
3600 s
Setting
Parameter
Description
Recommended
Settings Unit
WeekInMonth
starts
Last -
UTCTimeOfDay UTC Time of day in seconds when 3600 s

115
Setting
Parameter
Description
Recommended
Settings Unit
Setting
Parameter
Description
Recommended
Settings Unit
Setting
Parameter
Description
Recommended
Settings Unit

116
t Pulse length of pulse when setting Changed 1 s
Setting
Parameter
Description
Recommended
Settings Unit
Setting
Parameter
Description
Recommended
Settings Unit
CmdTestBit
during testmode
Off -

117
Setting
Parameter
Description
Recommended
Settings Unit
Setting
Parameter
Description
Recommended
Settings Unit

118
is connected to 3rd
task group.
This parameter is recommended to be set to 10% normally.
Setting
Parameter
Description
Recommended
Settings Unit

119
MinValFreqMeas
UBase
10 %
SelPhaseBus1: Setting of the input phase for Bus 1 voltage reference. This parameter has to be
set based on the corresponding phase PT/CVT input connected to this function. Present case,
this parameter is set to L1 (R-phase)
SelPhaseLine1: Setting of the phase or line 1 voltage measurement. This parameter has to be
this parameter is set to L1 (R-phase).
only). This parameter has to be set based on the corresponding phase PT/CVT input connected
to this function. Present case, this parameter is set to L1 (R-phase)
UBase: Setting of the Base voltage level on which the voltage settings are based. This
PhaseShift: This setting is used to compensate for a phase shift caused by a transformer
between the two measurement points for bus voltage and line voltage, or by a use of different
voltages as a reference for the bus and line voltages. The set value is added to the measured
line phase angle. The bus voltage is the reference voltage. This parameter is set to 0°in present
case.
URatio: The URatio is defined as URatio = bus voltage/line voltage. This setting scales up the
line voltage to an equal level with the bus voltage. This parameter is set to 1 in present case.
If No voltage sel. is set, the default voltages used will be U-Line1 and U-Bus1. This is also the
case when external voltage selection is provided. Fuse failure supervision for the used inputs
must also be connected. In present case this parameter is set to 1 1/2 bus CB.

120
To allow closing of breakers between asynchronous networks a synchronizing function is
provided. The systems are defined to be asynchronous when the frequency difference between
bus and line is larger than an adjustable parameter.
voltage at Line synchronism check. The voltage level settings must be chosen in relation to the
bus or line network voltage. The threshold voltages UHighBusSC and UHighLineSC have to be
set lower than the value at which the breaker is expected to close with the synchronism check. A
typical value can be 80% of the base voltages.
typical value for FreqDiffM can be10 mHz for a connected system, and a typical value for
FreqDiffA can be 100-200 mHz. FreqDiffA is not applicable in present case.
PhaseDiffM and PhaseDiffA: The phase angle difference level settings for Manual and Auto
sync. PhaseDiffM is normally recommended to set 30°. PhaseDiffA is not applicable in present
case.
tSCM and tSCA: Setting of the time delay for Manual and Auto synchronism check. Circuit
breaker closing is thus not permitted until the synchrocheck situation has remained constant
throughout the set delay setting time. Typical values for tSCM and tSCA can be 0.1s.
AutoEnerg and ManEnerg: Setting of the energizing check directions to be activated for
AutoEnerg. Setting of the manual Dead line/bus and Dead/Dead switching conditions to be
allowed for ManEnerg.
voltage is above set value of UHighBusEnerg. DBLL, Dead Bus Live Line, the bus voltage is
below set value of ULowBusEnerg and the line voltage is above set value of UHighLineEnerg.
AutoEnerg is made OFF and ManEnerg is set to Both of the above DLLB, DBLL. Hence Auto
related parameters are not applicable.
ManEnergDBDL: This need to be made OFF to avoid manual closing of the breaker if both Bus
and Line are dead. In present case this parameter is set OFF.

121
energizing for UHighBusEnerg. Set the operating level for the Line high voltage at Bus
energizing for UHighLineEnerg.
The threshold voltages UHighBusEnerg and UHighLineEnerg have to be set lower than the value
at which the network is considered to be energized. A typical value can be 80% of the base
voltages. If system voltages are above the set values here, relay will consider it as Live
condition.
ULowBusEnerg and ULowLineEnerg: Setting of the operating voltage level for the low Bus
voltage level at Bus energizing for ULowBusEnerg. Setting of the operating voltage level for the
low line voltage level at line energizing for ULowLineEnerg.
The threshold voltages ULowBusEnerg and ULowLineEnerg, have to be set to a value greater
than the value where the network is considered not to be energized. A typical value can be 40%
of the base voltages. If system voltages are below the set values here, relay will consider it as
Dead condition.
UMaxEnerg: Setting of the maximum live voltage level at which energizing is allowed. This
setting is used to block the closing when the voltage on the live side is above the set value of
UMaxEnerg. In present case this parameter is set to 105% of UBase.
The purpose of the timer delay settings, tAutoEnerg and tManEnerg, is to ensure that the dead
side remains de-energized and that the condition is not due to a temporary interference. If the
conditions do not persist for the specified time, the delay timer is reset and the procedure is
restarted when the conditions are fulfilled again. Circuit breaker closing is thus not permitted until
the energizing condition has remained constant throughout the set delay setting time. Normally
tManEnerg is recommended to set 0.1s. tAutoEnerg is not applicable in present case.
OperationSynch: Operation for synchronizing function Off/ On. This parameter is recommended
to set OFF.
tBreaker, tMinSynch and tMaxSynch: These parameters are not applicable if OperationSynch
is set to OFF.

122
Table 3-41: Setting of Synchrocheck function
Setting
Parameter
Description
Recommended
Settings
Unit
OperationSynch
Operation for synchronizing function Off/
On
Off -
OperationSC
Off/On
On -
UHighBusSC
Voltage high limit bus for synchrocheck in %
of UBaseBus
80.0 %UBB
UHighLineSC
Voltage high limit line for synchrocheck in %
of UBaseLine
80.0 %UBL
FreqDiffA
and line Auto
0.10 Hz
FreqDiffM
and line Manual
0.10 Hz
PhaseDiffA
bus and line Auto
30.0 Deg
PhaseDiffM
bus and line Manual
30.0 Deg
tSCM
Manual
0.100 s
UHighBusEnerg Voltage high limit bus for energizing 80.0 %UBB

123
UHighLineEnerg
Voltage high limit line for energizing
80.0 %UBL
ULowBusEnerg
Voltage low limit bus for energizing
40.0 %UBB
ULowLineEnerg
Voltage low limit line for energizing
40.0 %UBL
UMaxEnerg
105.0 %UB
tAutoEnerg
Time delay for automatic energizing
Check
0.100 s
Phase L1 for
busbar1
-
Phase L1 for
busbar2
-

124
APPENDIX-A: Co-ordination of 400kV/220kV ICT IDMT O/C E/F
relays at Station-A
The calculations given in this appendix are with following objective:
1. Settings to be provided on IDMT O/C E/F relays of 400kV side and 220kV side of ICT.
2. Verification of IDMT O/C E/F relay operating times for 3-Phase and Ph-G faults at
different locations.
3. Coordination curves for ICT O/C E/F relays with adjacent line/transformer O/C E/F
relays in the substation.
Basis for setting of O/C E/F relay on 400kV side of ICT:
Instantaneous setting (50/50N):
This relay is set to operate at 0.05s for a current which is higher of 1.3 times the transformer
through fault current (220kV side bus fault) or transformer inrush current (Normally 8 -10
times the rated current, which can be set much lower because of the DC and harmonic
filtering in the numerical relays). This setting comes to generally 8 times the transformer
primary rated current.
IDMT O/C E/F setting (67/67N):
These relays are to be coordinated with 67/67N of 220kV outgoing feeders on the LV side of
the ICT. 67/67N of 220kV outgoing feeders are set to operate at 1.1s for the remote 220kV
bus fault in order to give back up to zone 3 protection provided on 220kV lines.
Basis for setting of O/C E/F relay on 220kV side of ICT:
Instantaneous setting (50/50N):
This relay is set to operate at 0.05s for a current which is higher of 1.3 times the transformer
through fault current (400kV side bus fault) or transformer inrush current (Normally 8 -10
times the rated current, which can be set much lower because of the DC and harmonic
filtering in the numerical relays). This setting comes to generally 8 times the transformer
secondary rated current.
IDMT O/C setting (67):
These relays are to be coordinated with distance relay (21) zone 3 settings of 400kV
outgoing feeders on the HV side of the ICT. As the zone 3 setting is 1s, this should be set at
1.1s.

125
IDMT E/F setting (67N):
These relays are to be coordinated with directional earth fault relay (67N) settings of 400kV
outgoing feeders on the HV side of the ICT. 67N of 400kV outgoing feeders are set to
operate at 1.1s for the remote 400kV bus fault in order to give back up to zone 3 protection
provided on 400kV lines.
1. System Details:
Figure A-1 shows the system details for the network under consideration for relay setting.
Table A-1 gives the setting for the over current and earth fault relays for the network under
consideration.
2. 3-Ph Fault Current:
Figure A-2 A-3 shows the 3-Ph fault currents operating time of relays for a fault at 5% of
220kV Line and for a fault at 220kV Bus respectively. The operating times are taken from
phase over current coordination curves given in figure A-4.
3. Ph-G Fault Current:
Figure A-5 6 shows the earth fault currents operating time of relays for a fault at 5% of
220kV Line and for a fault at 220kV Bus respectively. The operating times are taken from
earth fault current coordination curves given in figure A-7.
Figure-8 9 shows the 3-Ph and Ph-G fault currents along with the operating times of
relays for a fault at 400kV bus. The IDMT O/C E/F relay setting calculation procedure for
the 220kV side of ICT is as similar to the 400kV side relay.

126
Table A-1 Settings of Over current and Earth fault relays
Phase Relay Settings
Thermal / Curve
(NEMA Code :67)
Instantaneous Setting
(NEMA Code :50)
SI.NO Relay Name CT ratio
Base
Current
Ib in A
Plug
setting
Ip in I/Ib
in%
TMS
Tp
Ip
in I/Ib in%
Tp
in s
1 TR-1 400kV Side 1000/1A 455 150 0.26 800 0.05
2 TR-2 220kV Side 800/1A 827 150 0.18 800 0.05
Earth Relay Settings
Thermal / Curve
(NEMA Code :67N)
Instantaneous Setting
(NEMA Code :50N)
SI.NO Relay Name CT ratio
Base
Current
Ib in A
Plug
setting
Ie in I/Ib
in%
TMS
Te
Ie
in I/Ib in%
Te
in s
1 TR-1 400kV Side 1000/1A 455 20 0.58 800 0.05
2 TR-2 220kV Side 800/1A 827 20 0.51 800 0.05
Note: Considered base current for HV side is 455A LV side is 827A.

127
Figure A-1: System details for the network under consideration for relay setting
Figure A-2: 3-Ph fault current for 220 kV side line fault

128
Figure A-3: 3-Ph fault current for 220 kV side bus fault

129
Figure A-4: Phase Over Current Relay Curve Co-ordination and Operating Time for 220 kV line fault

130
Figure A-5: Ph-G fault current for 220 kV side line fault
Figure A-6: Ph-G fault current for 220 kV side bus fault

131
Figure A-7: Earth Fault Relay Curve Co-ordination and Operating Time Operating Time for 220 kV line fault

132
Figure A-8: 3-Ph fault current for 400 kV side bus fault
Figure A-9: Ph-G fault current for 400 kV side bus fault

IED USED FOR 400kV 80MVAR SHUNT REACTOR
PROTECTION

Model setting calculation document for Shunt Reactor
2
TABLE OF CONTENTS
1.1 Single line diagram of the Shunt Reactor......................................................................... 8
1.2 Reactor parameters.......................................................................................................... 10
2 TERMINAL IDENTIFICATION AND LIST OF FUNCTIONS................................................11
2.1 RET670-1........................................................................................................................... 11
2.2 RET670-2........................................................................................................................... 15
2.3 REL670.............................................................................................................................. 20
2.4 REC670.............................................................................................................................. 25
2.4.1 Terminal identification ....................................................................................25
3 SETTING CALCULATIONS AND RECOMMENDED SETTINGS FOR RET670-1..............31
3.1 RET670-1........................................................................................................................... 31
3.1.1 Analog Inputs.................................................................................................31
3.1.3 Indication LEDs..............................................................................................34
3.1.7 IED Identifiers ................................................................................................40
3.1.10 Transformer differential protection T3WPDIF .................................................42
3.2 RET670-2........................................................................................................................... 55
3.2.1 Analog Inputs.................................................................................................55
3.2.3 Indication LEDs..............................................................................................57
3.2.7 IED Identifiers ................................................................................................63

3
3.2.10 1Ph High impedance differential protection HZPDIF ......................................66
3.3 REL670.............................................................................................................................. 71
3.3.1 Analog Inputs.................................................................................................71
3.3.3 Indication LEDs..............................................................................................73
3.3.7 IED Identifiers ................................................................................................79
3.3.10 Full-scheme distance measuring, Mho Characteristic (Zone 1) ZMHPDIS .....82
3.3.13 Fuse Failure Supervision SDDRFUF..............................................................88
3.3.14 Four Step Phase Overcurrent Protection OC4PTOC......................................90
3.3.15 Four Step Residual Overcurrent Protection EF4PTOC...................................96
3.3.16 Disturbance Report DRPRDRE....................................................................102
3.4 REC670............................................................................................................................ 105
3.4.1 Analog Inputs...............................................................................................105
3.4.2 Local Human-Machine Interface...................................................................107
3.4.3 Indication LEDs............................................................................................107
3.4.4 Time Synchronization...................................................................................109
3.4.5 Parameter Setting Groups............................................................................112
3.4.6 Test Mode Functionality TEST .....................................................................113
3.4.7 IED Identifiers ..............................................................................................113
3.4.8 Rated System Frequency PRIMVAL ............................................................114
3.4.9 Signal Matrix For Analog Inputs SMAI..........................................................114
3.4.10 Synchrocheck function (SYN1).....................................................................116

4
LIST OF FIGURES
Figure 1-1: Single line diagram of the Shunt Reactor with CT ratios............................................................8
Figure 3-1: Representation of the restrained and the unrestrained operate characteristics ......................43

5
LIST OF TABLES
Table 1-1: CT and PT details ........................................................................................................................9
Table 2-3: List of functions in REL670........................................................................................................20
Table 2-4: List of functions in REC670 .......................................................................................................25
Table 3-1: Analog inputs .............................................................................................................................32
Table 3-2: Local human machine interface.................................................................................................33
Table 3-3: LEDGEN Non group settings (basic).........................................................................................34
Table 3-4: Time synchronization settings ..................................................................................................36
Table 3-5: Parameter setting group ............................................................................................................39
Table 3-6: Test mode functionality..............................................................................................................40
Table 3-7: IED Identifiers ............................................................................................................................40
Table 3-8: Rated system frequency............................................................................................................41
Table 3-9: Signal Matrix For Analog Inputs.................................................................................................42
Table 3-10: Differential protection Settings.................................................................................................47
Table 3-23: 1Ph High impedance differential protection HZPDIF...............................................................68
Table 3-34: ZONE 1 Settings......................................................................................................................84
Table 3-37: Fuse Failure Supervision.........................................................................................................89
Table 3-40: Disturbance Report................................................................................................................103
Table 3-41: Analog Inputs.........................................................................................................................105
Table 3-42: Local human machine interface.............................................................................................107
Table 3-43: LEDGEN Non group settings (basic).....................................................................................108
Table 3-44: Time Synchronization ............................................................................................................110
Table 3-45: Parameter Setting Groups .....................................................................................................112
Table 3-46: Test Mode Functionality.........................................................................................................113
Table 3-47: IED Identifiers ........................................................................................................................113
Table 3-48: Rated System Frequency ......................................................................................................114

6
Table 3-49: Signal Matrix For Analog Inputs.............................................................................................115
Table 3-50: Synchrocheck function Settings.............................................................................................118

7
FEEDER: 400kV 80MVAR Shut Reactor at Station-A

8
1.1 Single line diagram of the Shunt Reactor
Single line diagram of the Shunt Reactor, various protection functions used and CT/PT
connections is shown in figure 1-1.
Figure 1-1: Single line diagram of the Shunt Reactor with CT ratios

9
CT and PT details:
Table 1-1 gives the Details of CTs and PTs.
Table 1-1: CT and PT details
CT details (typical, for illustration purpose only)
Name of
the CT
Name of the
Core
CT ratio CT details
CORE-1 1000/1A
CORE-2 1000/1A
CORE-4 1000/1A
4B-CT
CORE-5 1000/1A
CORE-1 2000/1A
CORE-2 2000/1A
CORE-4 1000/1A
4C-CT
CORE-5 1000/1A
CORE-1 200/1A
CORE-2 200/1A
CORE-3 200/1A
4C-CT2
CORE-4 200/1A CLASS:1, 15VA
CORE-1 200/1A
CORE-2 109.97/2A CLASS:5, 15VA
CORE-3 1000/1A
4C-CT3
CORE-4 1000/1A
PT details
Name of the PT Name of the Core PT ratio PT details
PT I 400/0.11kV 3P, 50VA

10
1.2 Reactor parameters
Reactor: At Substation-A
Frequency: 50Hz
Positive Sequence Impedance: 2205Ω
Zero Sequence Impedance: 0.9 to 1.0 times of positive sequence
(Assumed 1 times for present case)
Reactor Rating: 80MVAR, 420kV, 110A (ONAN)
Vector Group: Star with Neutral grounded

11
The various functions required for the Shunt Reactor protection are divided in four IEDs namely
RET670-1, RET670-2, REL670 and REC670 for the purpose of illustration. The terminal
identification of this and list of various functions available in these IEDs are given in this section.
2.1 RET670-1
Object Name: 400kV Shunt Reactor
Unit Name: RET670-1 (Ver 1.2)
Frequency: 50Hz
activated
Yes/No
Recommended
Settings
provided
1 Analog Inputs YES

12
T3WPDIF
YES
Protection PHPIOC
NO
OC4PTOC:1
NO
OC4PTOC:2
NO
Protection EFPIOC
NO
EF4PTOC
NO
constants TRPTTR
NO
SPC8GGIO
NO
DNP3.0 AUTOBITS
NO
SINGLECMD
NO
30 Scheme Communication Logic For NO

13
ZCPSCH
ZCRWPSCH
NO
Protection LCNSPTOV
NO
LCZSPTOV
NO
Protection LCNSPTOC
NO
LCZSPTOC
NO
NO
NO
VMMXU
NO
Measurement CMSQI
NO

14
VNMMXU
NO
BINSTATREP
NO
RANGE_XP
NO
60 Event List NO
61 Indications NO
NO
NO
Communication
NO
NO

15
2.2 RET670-2
Unit Name: RET670-2 (Ver 1.2)
Frequency: 50Hz
activated
Yes/No
Recommended
Settings
provided
1 Analog Inputs YES

16
T3WPDIF
NO
HZPDIF
YES
Protection PHPIOC
NO
OC4PTOC
NO
Protection EFPIOC
NO
EF4PTOC
NO
NS4PTOC
NO
NO
constants TRPTTR
NO
SPC8GGIO
NO
DNP3.0 AUTOBITS
NO
32 Single Command, 16 Signals NO

17
SINGLECMD
ZCPSCH
NO
ZCRWPSCH
NO
Protection LAPPGAPC
NO
Protection COUVGAPC
NO
SCCVPTOC
NO
Protection LCNSPTOV
NO
LCZSPTOV
NO
Protection LCNSPTOC
NO
LCZSPTOC
NO
NO

18
NO
VMMXU
NO
Measurement CMSQI
NO
VNMMXU
NO
BINSTATREP
NO
RANGE_XP
NO
67 Event List NO
68 Indications NO
NO
NO
Communication
NO

19
NO

20
2.3 REL670
Unit Name: REL670 (Ver 1.2)
Frequency: 50Hz
Table 2-3 gives the list of functions/features available in REL670 relay and also indicates the
Table 2-3: List of functions in REL670
Sl.No. Function/features available In REL670 Function/feature
activated
Yes/No
Recommended
Settings
provided
1 Analog Inputs YES

21
14 Signal Matrix For mA Inputs SMMI NO
19 Full-scheme distance measuring, Mho
characteristic ZMHPDIS
YES
20 Mho impedance supervision logic
ZSMGAPC
NO
21 Faulty phase identification with load
encroachment FMPSPDIS
YES
22 Directional impedance element for mho
characteristic ZDMRDIR
YES
23 Power Swing Detection ZMRPSB NO
24 Automatic Switch Onto Fault Logic,
Voltage And Current Based ZCVPSOF
NO
Protection PHPIOC
NO
OC4PTOC
YES
Protection EFPIOC
NO
EF4PTOC
YES
29 Sensitive Directional Residual Overcurrent
NO
30 General Current And Voltage Protection
CVGAPC-4 functions
NO
32 Fuse Failure Supervision SDDRFUF YES
33 Horizontal Communication Via GOOSE
For Interlocking GOOSEINTLKRCV
NO
34 Logic Rotating Switch For Function NO

22
36 Generic Double Point Function Block
DPGGIO
NO
SPC8GGIO
NO
DNP3.0 AUTOBITS
NO
SINGLECMD
NO
ZCPSCH
NO
ZCRWPSCH
NO
43 Direct Transfer Trip Logic YES
Protection LAPPGAPC
NO
Protection COUVGAPC
NO
SCCVPTOC
NO
Protection LCNSPTOV
NO
LCZSPTOV
NO
Protection LCNSPTOC
NO
LCZSPTOC
NO

23
NO
NO
VMMXU
YES
Measurement CMSQI
YES
VNMMXU
NO
BINSTATREP
NO
RANGE_XP
NO
74 Event List YES
75 Indications YES

24
NO
NO
Communication
NO
NO

25
2.4 REC670
Frequency: 50Hz
Sl.No. Functions/Feature available In REC670 Features/Functions
activated
Yes/No
Recommended
Settings
provided
1 Analog Inputs YES

26
Protection PHPIOC
NO
OC4PTOC
YES
Protection EFPIOC
NO
EF4PTOC
YES
NS4PTOC
NO
25 Sensitive Directional Residual Overcurrent
NO
26 Thermal Overload Protection, One Time
Constant LPTTR
NO
constants TRPTTR
NO
31 Directional Underpower Protection
GUPPDUP
NO
32 Directional Overpower Protection
GOPPDOP
NO
35 Two Step Undervoltage Protection
UV2PTUV
NO
36 Two Step Overvoltage Protection NO

27
OV2PTOV
37 Two Step Residual Overvoltage Protection
ROV2PTOV
NO
42 Rate-Of-Change Frequency Protection
SAPFRC
NO
43 General Current and Voltage Protection
CVGAPC
NO
46 Synchrocheck, Energizing Check, And
YES
47 Autorecloser SMBRREC NO
49 Horizontal Communication Via GOOSE
For Interlocking GOOSEINTLKRCV
NO
50 Logic Rotating Switch For Function
NO
52 Generic Double Point Function Block
DPGGIO
NO
SPC8GGIO
NO
DNP3.0 AUTOBITS
NO
SINGLECMD
NO
ZCPSCH
NO
57 Phase Segregated Scheme
Communication Logic For Distance
NO

28
Protection ZC1PPSCH
ZCRWPSCH
NO
Residual Overcurrent Protection ECPSCH
NO
ECRWPSCH
NO
NO
Protection LAPPGAPC
NO
65 Compensated Over And Undervoltage
Protection COUVGAPC
NO
66 Sudden Change In Current Variation
SCCVPTOC
NO
Protection LCNSPTOV
NO
LCZSPTOV
NO
Protection LCNSPTOC
NO
LCZSPTOC
NO

29
NO
NO
VMMXU
YES
Measurement CMSQI
YES
VNMMXU
NO
BINSTATREP
NO
RANGE_XP
NO
93 Disturbance Report DRPRDRE NO
94 Event List YES
95 Indications YES
NO

30
NO
Communication
NO
NO

31
3 SETTING CALCULATIONS AND RECOMMENDED
SETTINGS FOR RET670-1
The various functions required for the Reactor protection are divided in four IEDs namely
RET670-1, RET670-2, REL670 and REC670. The setting calculations and recommended
settings for various functions available in these IEDs are given in this section.
3.1 RET670-1
3.1.1 Analog Inputs
CTprim 1000A 1000A 1000A 1000A 1000A 1000A
VTsec 110V 110V 110V 110V 110V 110V
# User defined text

32
Setting
Parameter
Description
Recommended
Settings Unit
PhaseAngleRef
Presentation
TRM40-Ch1 -
CTStarPoint1
ToObject -
CTStarPoint2
ToObject -
CTStarPoint3
ToObject -
CTStarPoint4
ToObject -
CTStarPoint5
ToObject -
CTStarPoint6
ToObject -

33
Setting
Parameter
Description
Recommended
Settings Unit
AutoRepeat
(Off)
On -

34
Setting
Parameter
Description
Recommended
Settings Unit
Setting
Parameter
Description
Recommended
Settings Unit
tMax
disturbance
0.0 s

35
time.
available in site.

36
Setting
Parameter
Description
Recommended
Settings Unit

37
Setting
Parameter
Description
Recommended
Settings Unit
ModulePosition
Synchronization
3 -
BinaryInput
synchronization
1 -
Recommended
Settings Unit
Setting
Parameter
Description
Recommended
Settings Unit
WeekInMonth
starts
Last -
UTCTimeOfDay
3600 s

38
Setting
Parameter
Description
Recommended
Settings Unit
WeekInMonth
starts
Last -
UTCTimeOfDay
3600 s
Setting
Parameter
Description
Recommended
Settings Unit
Setting
Parameter
Description
Recommended
Settings Unit

39
Setting
Parameter
Description
Recommended
Settings Unit
Setting
Parameter
Description
Recommended
Settings Unit

40
Setting
Parameter
Description
Recommended
Settings Unit
CmdTestBit
during testmode
Off -
Setting
Parameter
Description
Recommended
Settings Unit
ObjectName Object name Bus Reactor -

41
Setting
Parameter
Description Recommended Settings
Unit
is connected to 3rd
task group.

42
Setting
Parameter
Description
Recommended
Settings Unit
MinValFreqMeas
of UBase
10 %
3.1.10 Transformer differential protection T3WPDIF
There are two types of differential relays. Percentage biased differential relay with harmonic
restraint (2nd
and 5th
harmonic restraint) with a high set unit and high impedance differential relay.
For shunt reactor both percentage biased and high impedance relays can be used depending on
the availability of CTs with identical characteristics. The simplicity of comparing current into all
terminals of the reactor gives the differential relay very high reliability.
Note: If identical CTs are available for Differential protection, It is advantageous to use high
impedance function for Differential relay to achieve higher sensitivity. Setting computation for
High Impedance Differential function shall be similar to one illustrated for high impedance REF
function.

43
In case of breaker and half switching schemes, the differential protection C.Ts. associated with
Main and Tie breakers should be connected to separate bias windings and these should not be
paralleled in order to avoid false operation due to dissimilar C.T. transient response.
In case of percentage biased differential relays current transformers or auxiliary CT's in a delta
connection (In case of numerical relays this is done internally) have to be used at grounded
reactor windings to avoid false operation on external faults. The removed zero sequence
component, however, makes the reactor differential relay less sensitive.
Figure 3-1 shows the restrained and the unrestrained operate characteristics of Differential
protection.
Figure 3-1: Representation of the restrained and the unrestrained operate characteristics

44
SOTFMode: Transformer differential (TW2PDIF for two winding and TW3PDIF for three
winding) function in the IED has a built-in, advanced switch onto fault feature. This feature can
be enabled or disabled by a setting parameter SOTFMode. When SOTFMode = On this feature
is enabled. However it shall be noted that when this feature is enabled it is not possible to test
2nd harmonic blocking feature by simply injecting one current with superimposed second
harmonic. In that case the switch on to fault feature will operate and differential protection will
trip. However for real inrush case the differential protection function will properly restrain from
operation. In present case this parameter is set OFF.
IDiffAlarm: Differential protection continuously monitors the level of the fundamental frequency
differential currents and gives an alarm if the pre-set value is simultaneously exceeded in all
three phases. The threshold for the alarm pickup level is defined by setting parameter
IDiffAlarm. IDiffAlarm is set to 10%.
tAlarmDelay: Set this parameter to 10s.
IdMin: Since no tap changer is provided for the reactor, this parameter is recommended to set
0.2pu.
IdUnre: The unrestrained (that is, non-stabilized, instantaneous) part of the differential
protection is used for very high differential currents, where it should be beyond any doubt, that
the fault is internal. This settable limit is constant (that is, not proportional to the bias current).
Neither harmonic, nor any other restrain is applied to this limit, which is therefore allowed to trip
reactor instantaneously. Unrestrained operation level has default value of IdUnre = 10pu, which
is typically acceptable for most of the shunt reactor applications. However in the following cases
these setting need to be changed accordingly:
When CT from T-connection are connected to IED, as in the breaker-and-a half or the ring bus
scheme, special care shall be taken in order to prevent unwanted operation of reactor
differential IED for through-faults due to different CT saturation of T-connected CTs. Thus if
such uneven saturation is a possibility it is typically required to increase unrestrained
operational level to IdUnre = 20-25pu. Since in this case, uneven CT saturation is not expected,
the function is used for breaker-and-a half scheme, this prater is set to 15pu.
CrossBlockEn: In the algorithm the user can control the cross-blocking between the phases via
the setting parameter CrossBlockEn. When parameter CrossBlockEn is set to On, cross
blocking between phases will be introduced. There are no time related settings involved, but the
phase with the operating point above the set bias characteristic will be able to cross-block other

45
two phases if it is self-blocked by any of the previously explained restrained criteria. It is
recommended to set this parameter to ON.
When parameter CrossBlockEn is set to Off, any cross blocking between phases will be
disabled. In present case it is set ON.
NegSeqDiffEn: The internal/external fault discriminator is a very powerful and reliable
supplementary criterion to the traditional differential protection. It is recommended that this
feature shall be always used (that is, On) when protecting three-phase shunt reactors. The
internal/external fault discriminator detects even minor faults, with a high sensitivity and at high
speed, and at the same time discriminates with a high degree of dependability between internal
and external faults. In the absence of credible field experience, it is set to OFF in present case.
IMinNegSeq and NegSeqROA: These parameters are not applicable if NegSeqDiffEn is set to
OFF.
EndSection1, EndSection2, SlopeSection2 and SlopeSection3: In present case, these
parameters are left with the default values recommended by manual. EndSection1,
EndSection2, SlopeSection2 and SlopeSection3 are set to 1.25, 3, 40% and 80% respectively.
Note: If controlled switching is not used for shunt reactor, the Differential protection might mal-
operate especially for 765kV shunt reactors. This can be prevented by temporarily increasing
the setting of differential protection during charging conditions.
I2/I1Ratio: If the ratio of the second harmonic to fundamental harmonic in the differential current
is above the settable limit, the operation of the differential protection is restrained. It is
recommended to set parameter I2/I1Ratio = 15% as default value in case no special reasons
exist to choose other value.
I5/I1Ratio: If the ratio of the fifth harmonic to fundamental harmonic in the differential current is
above a settable limit the operation is restrained. It is recommended to use I5/I1Ratio = 25% as
default value in case no special reasons exist to choose another setting.
OpenCTEnable: The built-in open CT feature can be enabled or disabled by a setting
parameter OpenCTEnable (Off/On). When enabled, this feature prevents mal-operation when a
loaded main CT connected to Reactor differential protection is by mistake open circuited on the
secondary side. In present case this parameter is set OFF.
tOCTAlarmDelay , tOCTResetDelay and tOCTUnrstDelay: These parameters are not
applicable if OpenCTEnable is set OFF.
RatedVoltageW1: Rated voltage of shunt reactor in kV. This parameter is set to 400kV.

46
RatedCurrentW1: Rated current of shunt reactor in A. This parameter is set to 110A.
Above setting parameters are set based on 400kV 80MVAR Reactor rating details.
parameter is set to 0 as it is Shunt Reactor.
parameter is set to 0 as it is Shunt Reactor.
ZSCurrSubtrW1: Enable zer. seq. current subtraction for W1 side, On / Off. The elimination of
zero sequence current is done numerically and no auxiliary transformers or zero sequence traps
are necessary. In present case this parameter is set ON.
TconfigForW1: Two CT inputs (T-config.) for winding 1, YES / NO. For application with so
called T configuration, that is, two restraint CT inputs from one side of the protected shunt
reactor, such as in the case of breaker-and a- half scheme the primary CT ratings can be much
higher than the rating of the protected shunt reactor. In present case this parameter is set to
NO. Since Main CT input can be configured to W1 and Tie CT can be configured to W2.
NO.
NO.
NO.

47
LocationOLTC1: Transformer winding where OLTC1 is Located. Parameter LocationOLTC1
defines the winding where first OLTC (OLTC1) is physically located. In present case, this is set
to “Not Used”.
LocationOLTC2: Transformer winding where OLTC2 is Located. In present case, this is set to
“Not Used”.
Table 3-10: Differential protection Settings
T3WPDIF Group settings (basic)
Setting
Parameter
Description
Recommended
Settings Unit
SOTFMode
Operation mode for switch onto fault
feature
Off -
tAlarmDelay Time delay for diff currents alarm level 10 s
IDiffAlarm Dif. cur. alarm, multiple of base curr,
usually W1 curr.
0.1 IB
IdMin Section1 sensitivity, multi. of base curr,
usually W1 curr.
0.2 IB
IdUnre Unrestr. prot. limit, multi. of base curr.
usually W1 curr.
15 IB
CrossBlockEn Operation Off/On for cross-block logic
between phases
On -
NegSeqDiffEn Operation Off/On for neg. seq.
differential protections
Off -
IMinNegSeq Neg. seq. curr. limit, mult. of base curr,
usually W1 curr.
0.04 IB
NegSeqROA Operate Angle for int. / ext. neg. seq.
fault discriminator
60.0 Deg

48
T3WPDIF Group settings (advanced)
Setting
Parameter
Description
Recommended
Settings Unit
EndSection1
usually W1 curr.
1.25 IB
EndSection2
usually W1 curr.
3 IB
40 %
80 %
I2/I1Ratio Max. ratio of 2nd harm. to fundamental
15 %
I5/I1Ratio Max. ratio of 5th harm. to fundamental
25 %
OpenCTEnable Open CT detection feature. Open
CTEnable Off/On
Off -
tOCTAlarmDelay Open CT: time in s to alarm after an
open CT is detected
3 s
tOCTResetDelay Reset delay in s. After delay, diff.
function is activated
0.25 s
tOCTUnrstDelay Unrestrained diff. protection blocked
after this delay, in s
10.0 s
T3WPDIF Non group settings (basic)
Setting
Parameter
Description
Recommended
Settings Unit
(HV winding) in kV
400 kV
RatedVoltageW2 Rated voltage of transformer winding 2 in
kV
400
kV
RatedVoltageW3 Rated voltage of transformer winding 3 in
kV
400
kV
(HV winding) in A
110 A
RatedCurrentW2 Rated current of transformer winding 2 in
A
110
A
RatedCurrentW3 Rated current of transformer winding 3 in
A
110
A
D-delta
WYE(Y) -
D-delta
WYE(Y) -
ConnectTypeW3 Connection type of winding 3: Y-wye or WYE(Y) -

49
D-delta
0 [0 deg] -
0 [0 deg] -
W1 side, On / Off
On -
W2 side, On / Off
On -
W3 side, On / Off
On -
YES / NO
No -
transf. W1 side
1000 A
CT2RatingW1 CT primary in A, T-branch 2, on transf.
W1 side
1000 A
YES / NO
No -
transf. W2 side
1000 A
transf. W2 side
1000 A
YES / NO
No -
transf. W3 side
1000 A
transf. W3 side
1000 A
located
Not Used -
LowTapPosOLTC1 OLTC1 lowest tap position designation
(e.g. 1)
1 -
6 -
HighTapPsOLTC1 OLTC1 highest tap position designation
(e.g. 11)
11 -
1 -
1.0 %
located
Not Used -
LowTapPosOLTC2 OLTC2 lowest tap position designation
(e.g. 1)
1 -
6 -
HighTapPsOLTC2 OLTC2 highest tap position designation
(e.g. 11)
11 -

50
1 -
1.0 %
All trip outputs from protection functions have to be routed to trip coil through SMPPTRC.
SMPPTRC function will give a pulse of set length (150ms) if trip signal is obtained.
Program: For Reactor protection trip, this parameter is recommended to be set to 3 phase.
tWaitForPHS: It Secures 3-pole trip when phase selection fails. In present case, there is no
phase selection, this parameter is not applicable.
to OFF.
Setting
Parameter
Description
Recommended
Settings Unit
Program Three ph; single or three ph; single, two or
three ph trip
3 phase -
tWaitForPHS
failed
0.020 s
TripLockout
Off -
AutoLock On: lockout from input (SETLKOUT) and Off -

51
trip, Off: only inp
example, all Differential, REF, TOC and TEF trips using TMAGGIO function.
Setting
Parameter
Description
Recommended
Settings Unit

52
below:
From 400kV Main bay CTs:
IA
IB
IC
IN
From 400kV Tie Bay CTs:
IA
IB
IC
IN
From 400kV Reactor Neutral side CTs:
IA
IB
IC
IN
Differential currents from Differential protection function block
IDL1
IDL2
IDL3
From 400kV Bus PT:
VAN
VBN
VCN
— Group-A Trip
— Group-B Trip

53
— Direct Transfer Trip Sent (in case of line reactor)
— Over Voltage
Recording capacity
bay or circuit.
Memory capacity
Recording times

54
Setting
Parameter
Description
Recommended
Settings Unit
ZeroAngleRef
1 Ch

55
3.2 RET670-2
3.2.1 Analog Inputs
Name# REF REF REF SPARE SPARE SPARE
CTprim 1A 1A 1A 1000A 1000A 1000A
In case of line reactor with neutral reactor, REF used shall be single phase type. In case of
bus reactor, since CTs are available on either side of shunt reactor, REF used shall be of 3-
phase type. (In this case, it is assumed Bus reactor). The above analog inputs has been set
accordingly.
VTsec 110V 110V 110V 110V 110V 110V
# User defined text
Setting
Parameter
Description
Recommended
Settings Unit
PhaseAngleRef
Presentation
TRM40-Ch1 -
CTStarPoint1
ToObject -

56
CTStarPoint2
ToObject -
CTStarPoint3
ToObject -
CTStarPoint4
ToObject -
CTStarPoint5
ToObject -
CTStarPoint6
ToObject -

57
Setting
Parameter
Description
Recommended
Settings Unit
AutoRepeat
(Off)
On -

58
Setting
Parameter
Description
Recommended
Settings Unit
tMax
disturbance
0.0 s

59
time.
available in site.

60
Setting
Parameter
Description
Recommended
Settings Unit

61
Setting
Parameter
Description
Recommended
Settings Unit
ModulePosition
Synchronization
3 -
BinaryInput
synchronization
1 -
Recommended
Settings Unit
Setting
Parameter
Description
Recommended
Settings Unit
WeekInMonth
starts
Last -
UTCTimeOfDay
3600 s
Setting
Parameter
Description
Recommended
Settings Unit
UTCTimeOfDay UTC Time of day in seconds when 3600 s

62
Setting
Parameter
Description
Recommended
Settings Unit
Setting
Parameter
Description
Recommended
Settings Unit
Setting
Parameter
Description
Recommended
Settings Unit
t Pulse length of pulse when setting 1 s

63
Changed
Setting
Parameter
Description
Recommended
Settings Unit
Setting
Parameter
Description
Recommended
Settings Unit
CmdTestBit
during testmode
Off -

64
Setting
Parameter
Description
Recommended
Settings Unit
Setting
Parameter
Description
Recommended
Settings Unit

65
is connected to 3rd
task group.
Setting
Parameter
Description
Recommended
Settings Unit

66
MinValFreqMeas
of UBase
10 %
3.2.10 1Ph High impedance differential protection HZPDIF
It may be noted that the connection of Restricted Earth Fault protection on the neutral side shall
be from Neutral side bushing CTs (in case of bus reactor) or from the ground side CT in the
neutral grounding reactor (for line shunt reactor). The latter is to ensure that the protection
covers the neutral earthing reactor as well in the protected zone.
Zero-sequence differential relays (Restricted earth fault relay) provide protection against phase-
to-ground faults in shunt reactors supplied from solidly grounded systems. Generally, this
protection is also provided for EHV shunt reactor with Neutral Grounding reactor connected
between star point of shunt reactor and ground.
Whenever separate phase-wise C.Ts are available on neutral side of Reactor, triple pole high
impedance relay may be provided instead of single pole R.E.F. relay.
UAlarm: Set the alarm level. The sensitivity can roughly be calculated as a divider from the
calculated sensitivity of the differential level. A typical setting is 20% of UTrip It can be used as
scheme supervision stage.
tAlarm: Set the time for the alarm. A typical setting is 5 seconds.
UTrip: The level is selected with margin to the calculated required voltage to achieve stability.
Values can be 20-200 V dependent on the application.
SeriesResistor: Set the value of the stabilizing series resistor. Adjust the resistor as close as
possible to the calculated value. Measure the value achieved and set this value here.
This Protection is based on High Impedance differential scheme.
The setting value of the relay can be calculated as below:
CT Details: Phase side and Neutral side –200 /1, CL: PS
Rct = 1Ω

67
Rl = 2.178Ω, considered 250mts distance from Phase/Neutral CT to relay connected using a
cable of 2.5mm2
having resistance of 8.71ohms/km.
Voltage drop across the circulating current circuit for external faults,
Us = Ikmax x (Rct + 2* Rl)/n where
Maximum through fault current (3-ph) = 110 * 6 = 660A (considered charging currents up to 6
times rated current)
Rct = the internal resistance of the current transformer secondary winding = 1Ω
Rl = the total resistance of the longest measuring circuit loop = 2.178Ω
n = turns ratio of the current transformer = 1/200
Hence Us = 660 x (1 + 2x2.178) * 1 /200 = 17.67V
Recommended Settings = 19.44 ≈ 20V with a margin of 10%. (A typical margin is 10 to
50%)
CT requirement with Vk = 2*Us = 2* 20 = 40V Approx. (min)
REF high impedance Function element is used with Stabilizing resistor.
Pickup shall be decided based on the following criteria:
Stabilizing resistor:
For a sensitivity of 2% i.e 0.02*In,
Rs ≥ Us/I =20/0.02 = 1000Ω to be connected in series.
Chosen Rs= 1000Ω. (Approx)
Primary operating sensitivity:
Iprim = n x ( Irelay + Iu + mx Im )
where, n = turn ratio of the CT = 200 in present case.
Irelay = relay set operation current in secondary Amps = 20mA in present case.
Iu = leakage current through the Voltage Dependent Resistor (VDR) at stabilizing voltage Us =
1mA
Approximate value of the current thorough non-linear resistor for the voltage of 20V (Us) is 1mA.
This is considered from the Current voltage characteristics for the non-linear resistors.
m = number of CTs connected in parallel in the secondary circuit = 2 in present case.
Im = magnetizing current of the CT at stabilizing voltage Us = 3mA in present case.
This value is calculated by using CT magnetizing current 30mA at Vk and Vk = 200V.
By using above values, Iprim = 200 x (20+ 1 + 2x3) = 5.4A.
Kindly Note that the following requirements for applying High impedance differential relays.
• Turns ratios of CTs should be identical
• Auxiliary CTs should not be used

68
• Loop impedance (Rct+2Rl) up to the CT paralleling point should be identical
• Magnetizing characteristics should be identical
Table 3-23 gives the recommended settings for 1Ph High impedance differential protection.
Table 3-23: 1Ph High impedance differential protection HZPDIF
Setting
Parameter
Description
Recommended
Settings Unit
UAlarm
Alarm voltage level in volts on CT
secondary side
4 V
tAlarm Time delay to activate alarm 5 s
UTrip
Operate voltage level in volts on CT
secondary side
20 V
SeriesResistor Value of series resistor in Ohms 1000 ohm
Note: The respective analogue channels in RET670-2 (for REF current inputs) should be
set to 1:1.
below:
Differential currents from 1PH High impedance functions:
IREFL1
I REFL2
I REFL3

69
— Group-A Trip
— Group-B Trip
— Direct Transfer Trip Sent (in case of line reactor)
— Over Voltage
Recording capacity
bay or circuit.
Memory capacity
Recording times

70
Setting
Parameter
Description
Recommended
Settings Unit
ZeroAngleRef
1 Ch

71
3.3 REL670
3.3.1 Analog Inputs
Name# IL1-CB1 IL2-CB1 IL3-CB1 SPARE SPARE SPARE
CTprim 1000A 1000A 1000A 200A 200A 200A
VTsec 110V 110V 110V 110V 110V 110V
# User defined text
Setting
Parameter
Description
Recommended
Settings Unit
PhaseAngleRef
Presentation
TRM40-Ch1 -
CTStarPoint1
ToObject -

72
CTStarPoint3
ToObject -
CTStarPoint4
ToObject -
CTStarPoint5
ToObject -
CTStarPoint6
ToObject -

73
Setting
Parameter
Description
Recommended
Settings Unit
AutoRepeat
(Off)
On -

74
Setting
Parameter
Description
Recommended
Settings Unit
tMax
disturbance
0.0 s

75
time.
available in site.

76
Setting
Parameter
Description
Recommended
Settings Unit

77
Setting
Parameter
Description
Recommended
Settings Unit
ModulePosition
Synchronization
3 -
BinaryInput
synchronization
1 -
Recommended
Settings Unit
Setting
Parameter
Description
Recommended
Settings Unit
WeekInMonth
starts
Last -
UTCTimeOfDay
3600 s
Setting
Parameter
Description
Recommended
Settings Unit
UTCTimeOfDay
3600 s

78
Setting
Parameter
Description
Recommended
Settings Unit
Setting
Parameter
Description
Recommended
Settings Unit
Setting
Parameter
Description
Recommended
Settings Unit
t
Changed
1 s

79
Setting
Parameter
Description
Recommended
Settings Unit
Setting
Parameter
Description
Recommended
Settings Unit
CmdTestBit
during testmode
Off -

80
Setting
Parameter
Description
Recommended
Settings Unit
ObjectName Object name Shunt Reactor -
UnitName Unit name REL670 -
Setting
Parameter
Description
Recommended
Settings Unit

81
is connected to 3rd
task group.
Setting
Parameter
Description
Recommended
Settings Unit

82
MinValFreqMeas
of UBase
10 %
3.3.10 Full-scheme distance measuring, Mho Characteristic (Zone 1)
ZMHPDIS
Undesired operation of impedance protection during switching conditions has been observed
but the tendency seems to be reduced by numerical distance protection due to modern filtering
algorithms.
The impedance or overcurrent backup protection may not be able to detect inter-turn fault in the
reactor, for which the buchholz may be the only answer, unless the number of turns involved is
very high. Manufacturers of reactor and relays may be consulted in this regard.
Typical setting for impedance type of relays are -
Reach - 60% of Reactor Impedance Time setting - 1 sec.
Impedance relays are used as primary protection or as back-up protection for the reactor. It is
also used for detecting turn-to-turn faults within the reactor. Such relays also monitor the faults
inside the reactor at some good percentage of winding faults. Turn-to-turn faults inside reactor
winding may not change the through current of the reactor but the impedance values change
drastically up to at least 50 % of impedance of the reactor. It consists of a single or preferably a
two-zone impedance relay on the high side of the reactor looking into the reactor.
The impedance relay has some benefits of providing high speed tripping in the Zone-1 protection
and slower speed tripping in Zone-2. It must not be set to operate for inrush characteristics
during reactor energization or de-energization. The setting of the relay has to be coordinated
while taking into account the energizing and d-energizing transients.
The zones are set directly in primary ohms R, X. The primary ohms R, X are recalculated to
secondary ohms with the current and voltage transformer ratios.
The secondary values are presented as information for zone testing.

83
Zone-1:
Setting of ZPE and ZPP: To be set to cover 60% of Reactor impedance. Zero sequence
compensation factor is (Z0 – Z1) / 3Z1.
IBase: Set the Base current for the Impedance protection zones in primary Ampere here. Set
the Reactor rated current value. This parameter is set to 110A in present case.
UBase: Set the Base voltage for the Impedance protection zones in primary kV here. Set the
Reactor rated voltage value. This parameter is set to 420kV in present case.
IMinOpPP: Setting of minimum sensitivity for zone Phase-Phase elements. Measures IL-IL for
each loop. This is the minimum current required in phase to phase fault for zone measurement.
minimum current required in phase to earth fault for zone measurement. To be set to 10% of
IBase.
DirMode: Direction mode. This parameter is set to Offset.
LoadEncMode: Load encroachment mode Off/On. This parameter is recommended to set OFF.
ReachMode: Reach mode Over/Underreach. This parameter is not applicable in present case.
OpModePE: Operation mode Off / On of Phase-Earth loops. This parameter is recommended to
set ON.
KN: Magnitude of earth return compensation factor KN. Refer setting calculation section.
KNAng: Angle for earth return compensation factor KN. This parameter is set to 90°
.
ZRevPE: Reverse reach of the phase to earth loop(magnitude).This parameter is set same as
that of ZPE.
tPE: Delay time for operation of phase to earth elements. This parameter is set to 1s.
ZRevPP: Reverse reach of the phase to phase loop(magnitude). This parameter is set same as
that of ZPP.
ZAngPP: Angle for positive sequence line impedance for Phase-Phase elements. This
parameter is set to 90°
.
OffsetMhoDir: Direction mode for offset mho. This parameter is set to Non-directional.
OpModePE: Operation mode Off / On of Phase-Earth loops. This parameter is set to ON.
OpModePP: Operation mode Off / On of Phase-Phase loops. This parameter is set to ON.

84
Zone 1 phase fault reach is set to 60.0% of the total reactor impedance
ZPP' = 1323Ω
ZPP = 72.765Ω
Same value is set for ZRevPP, ZPE and ZRevPE.
Earth return compensation factor KN:
KN = (Z0 – Z1) / 3Z1 = -0.033
Considered Z0 = 0.9xZ1 = 1190.7Ω
Table 3-34 gives the recommended settings for ZONE 1.
Setting
Parameter
Description
Recommended
Settings Unit
Ubase Base voltage , i.e.rated voltage 420.00 kV
DirMode Direction mode Offset -
LoadEncMode Load encroachment mode Off/On Off -
ReachMode Reach mode Over/Underreach Underreach -
OpModePE
Operation mode Off / On of Phase-Earth
loops
On -
ZPE
Positive sequence impedance setting for
Phase-Earth loop
1323 ohm/p
ZAngPE
Angle for positive sequence line
impedance for Phase-Earth loop
90 Deg
KN
Magnitud of earth return compensation
factor KN
-0.03333 ohm/p
KNAng
Angle for earth return compensation
factor KN
0 ohm/p
ZRevPE Reverse reach of the phase to earth 1323 ohm/p

85
loop(magnitude)
tPE
Delay time for operation of phase to
earth elements
1 s
IMinOpPE
Minimum operation phase to earth
current
10 %IB
OpModePP
Operation mode Off / On of Phase-
Phase loops
On -
ZPP
Impedance setting reach for phase to
phase elements
1323 ohm/p
ZAngPP
Angle for positive sequence line
impedance for Phase-Phase elements
90 Deg
ZRevPP
Reverse reach of the phase to phase
loop(magnitude)
1323 ohm/p
tPP
Delay time for operation of phase to
phase
1 s
IMinOpPP
Minimum operation phase to phase
current
10 %IB
ZMHPDIS Group settings (advanced)
Setting
Parameter
Description
Recommended
Settings Unit
OffsetMhoDir Direction mode for offset mho Non-directional -
OpModetPE
Ph-E
On -
OpModetPP
Ph-ph
On -
All trip outputs from protection functions has to be routed to trip coil through SMPPTRC.
For example, If there is a transient fault, trip output from distance function will not be long
enough to open breaker in case Distance function trip signal is directly connected to Trip coil.

86
SMPPTRC function will give a pulse of set length (150ms) even if trip signal is obtained for
transient fault.
Program: If only 3-ph trip is required, this needs to be set to 3 phase. In present case it is to be
set to 3 phase.
tWaitForPHS: It Secures 3-pole trip when phase selection fails. For example, if fault is at 90%
of protected line in R-ph, Zcom trip is obtained using scheme communication. SMPPTRC will
wait for Zone-2 R-ph sart till the time delay set in tWaitForPHS to trip R-ph at local end. If no
Zone-2 R-ph start from local end, it will issue a 3-ph trip after the time delay set in tWaitForPHS.
This parameter is set to 0.050s.
to OFF.
Setting
Parameter
Description
Recommended
Settings Unit
Program
three ph trip
3 phase -
tWaitForPHS
failed
0.050 s
TripLockout
Off -
AutoLock
trip, Off: only inp
Off -

87
example, all distance 3-ph trips (from z-2, z-3 and z-4), SOTF trip, TOV, TOC and TEF trips
using TMAGGIO function.
Setting
Parameter
Description
Recommended
Settings Unit

88
3.3.13 Fuse Failure Supervision SDDRFUF
Setting for OpMode: Setting of the operating mode for the Fuse failure supervision. Zero
sequence based fuse fail detection is enabled and settings for the same are given based on
below recommendations.
3U0 and 3I0: The setting of 3U0 should not be set lower than maximal zero sequence
voltage during normal operation condition. The setting of 3I0 must be higher than maximal
zero sequence current during normal operating condition. In present case, 3U0 is set to 30%
of UBase and 3I0 is set to 10% of IBase.
3U2 and 3I2: These parameters are not applicable if OpMode is selected to UZsIZs.
DUDI: This is another philosophy for detecting fusefail like Zero sequence based and Negative
sequence based algorithm. If OpMode is set to UZsIZs and OpDUDI is kept ON, fusefail
detection will be OR operation of these two modes. This is recommended to set ON.
DU and DI: DUDI method will measure the difference in voltage (should be more than set in
DU) and difference in current (should be less than set in DI). DU is recommended to set
60% of UBase and DI is recommended to set 15% of IBase.
UPh and IPh: For DUDI mode, voltage in the corresponding phase shall be more than set
value in UPh for 1.5cycles before actual fuse fail condition and current should be more than
set value in IPh before fuse fail. UPh is recommended to set 70% of UBase and IPh is
recommended to set 10% of IBase.
A criterion based on delta current and delta voltage measurements can be added to the fuse
failure supervision function in order to detect a three phase fuse failure, which in practice is
more associated with voltage transformer switching during station operations. In present case,
this parameter is set ON.
SealIn: Setting of the seal-in function On-Off giving seal-in of alarm until voltages are
symmetrical and high. If sealin is ON and fusefail persists for more than 5s, outputs blockz and
blocku will get sealin (means latched) until any one phase voltage is less than USealIn setting.
It will release when all three voltages goes above USealIn setting. In present case, this
parameter is made ON and recommended setting for USealIn is 70% of UBase.
Dead line detection: If any phase voltage is less than UDLD set value and corresponding
current is less than IDLD set value, this will consider as dead line and it will block Z only, it will
not block U. There is no ON or OFF for this philosophy.

89
During real fuse fail condition, FF function will block both Z and U. UDLD is recommended to
set to 60% of UBase and IDLD is recommended to set 5% of IBase.
UBase: Setting of the Base voltage level on which the voltage setting is based. In present case
this parameter is set to 400kV.
IBase: Set the Base current for the function on which the current levels are based. In present
case this parameter is set to 110A.
Table 3-37 gives the recommended settings for Fuse Failure Supervision.
Table 3-37: Fuse Failure Supervision
Setting
Parameter
Description
Recommended
Settings Unit
OpMode Operating mode UZsIZs -
3U0
residual overvoltage element in % of
Ubase
30 %IB
3I0
Operate level of residual undercurrent
10 %IB
3U2
Operate level of neg seq overvoltage
element in % of Ubase
20 %IB
3I2
Operate level of neg seq undercurrent
10 %IB
OpDUDI
Operation of change based function
Off/On
On -
DU
Operate level of change in phase voltage
in % of Ubase
60 %UB
DI Operate level of change in phase 15 %IB
UPh
Operate level of phase voltage in % of
Ubase.
70 %UB
IPh
Operate level of phase current in % of
IBase
10 %IB

90
SealIn Seal in functionality Off/On On -
USealln
Operate level of seal-in phase voltage in
%of Ubase
70 %UB
IDLD
Operate level for open phase current
detection in % of IBase
5 %IB
UDLD Operate level for open phase voltage 60
%UB
3.3.14 Four Step Phase Overcurrent Protection OC4PTOC
The Phase Over current protection and Earth fault relays are widely used in comparison to
impedance type of relay for providing backup protections to shun reactors. See reference:
The phase over current protection is a very inexpensive, simple, and reliable scheme for fault
detection and is used for some reactor protection applications as a back-up protection. The
setting must be high enough to prevent inrush currents from causing unwanted operation. When
used it should have both instantaneous and time delayed elements. The instantaneous elements
help in providing high speed clearance of heavy current faults which threaten system stability.
The impedance or overcurrent backup protection may not be able to detect inter-turn fault in the
reactor, for which the buchholz may be the only answer, unless the number of turns involved is
very high. Manufacturers of reactor and relays may be consulted in this regard.
Typical settings for O/C relays are:
Current Setting - 1.3 x Rated current Time setting - 1 sec.
parameter is set to 110A in present case, which is Reactor rated current.
This parameter is set to 400kV in present case, which is Reactor rated voltage. This parameter
is not applicable in present case, since DirMode1 is set to Non-directional.

91
and current. This parameter is not applicable in present case, since DirMode1 is set to Non-
directional.
parameter is not applicable in present case, since DirMode1 is set to Non-directional.
Characteristic2: Setting of the operating characteristic. This parameter is set to “Non-
directional” in present case.
I2: Setting of the operating current level in primary values. This setting value shall be higher
than 6 times Reactor rated current considering inrush. This parameter is set to 1500% of
Reactor rated current in present case. However, this setting can be set more sensitive if bushing
CTs are used.
t2: Independent (definitive) time delay of step 2, this parameter can be set in the range 50 to
100msec. It is set to 50ms in present case.

92
IMin2: Minimum operate current for step2 in % of IBase. This parameter is set to 1500% of
set to IEC.
set to IEC.
DirMode3 and DirMode4: Setting of the operating direction for the stage or switch it off. Two
stages are set to OFF.
t1: This parameter is set to 1s in present case.

93
Setting
Parameter
Description
Recommended
Settings Unit
UBase
400 kV
StartPhSel
3, 2 of 3, 3 of 3)
1 out of 3 -
DirMode1
forward, reverse)
Non-Directional -
I1
% of IBase
130 %IB
k1
for step 1
0 -
IMin1
of IBase
130 %IB
t1Min
for step 1
0 s
I1Mult
value for step 1
1.0 -
DirMode2
forward, reverse)
Non-Directional -

94
I2
% of IBase
1500 %IB
k2
for step 2
0 -
IMin2
of IBase
1500 %IB
t2Min
for step 2
0 s
I2Mult
value for step 2
1.0 -
DirMode3
forward, reverse)
Off -
DirMode4
forward, reverse)
Off -
IMinOpPhSel
% of IBase
7 %IB
2ndHarmStab
of IN amplitude
20 %
tReset1
Time curve step 1
0.020 s
tPCrv1
curve for step 1
1 -
tACrv1
curve for step 1
13.5 -
tBCrv1
curve for step 1
0 -
tCCrv1
Parameter C for customer programmable
curve for step 1
1 -

95
tPRCrv1
0.5 -
tTRCrv1
13.5 -
tCRCrv1
1 -
HarmRestrain1
restrain
On -
tReset2
Time curve step 2
0.020 s
tPCrv2
curve for step 2
1 -
tACrv2
curve for step 2
13.5 -
tBCrv2
curve for step 2
0 -
tCCrv2
1 -
tPRCrv2
0.5 -
tTRCrv2
13.5 -
tCRCrv2
1 -
HarmRestrain2
restrain
On -

96
3.3.15 Four Step Residual Overcurrent Protection EF4PTOC
The ground fault protection within the shunt reactor is best provided by simple conventional
Restricted Earth Fault (REF) relay selected and set on the same philosophy as for transformer
REF. For tertiary connected reactors neutral over voltage relays are used. Sometimes a ground
over current relay is used as a backup protection when phase overcurrent protection is provided.
The ground over current protection is a very inexpensive, simple, and reliable scheme for fault
detection and is used for some reactor protection applications as a back-up protection for phase-
to-ground faults. This is used in conjunction with phase over current relay. When used it should
have both instantaneous and time delayed elements.
The sensitivity to the harmonic and inrush currents is one of the main problems with back-up
ground over current relays. Settings must be able to allow inrush, which usually means
desensitizing the back-up relay. Numerical relay offer the best characteristic in this area since
the digital filters remove harmonics and DC offset currents from the inrush and are, therefore,
recommended.
above any continuous residual current under normal system operation.
parameter is set to 110A in present case, which is Reactor rated current.
This parameter is set to 400kV in present case, which is Reactor rated voltage. This parameter
is not applicable in present case, since DirMode1 is set to Non-directional.

97
k1: Set the back-up trip time delay multiplier (TMS) for inverse characteristic. This parameter is
not applicable in present case, since Characteristic1 is set to IEC Def. Time.
set to IEC.
IN2: Setting of the operating current level in primary values. This can be made very sensitive
by using Bushing CT input with a setting of 100% of base current. As bay CTs are being used,
this parameter is set to 1000% of base current in present case.
t2: Independent (definitive) time delay of step 2, this parameter can be set in the range 50 to
100msec. It is set to 50ms in present case.
set to IEC.

98
polMethod: Set the method of directional polarizing to be used. This parameter is not
applicable in present case, since DirMode1 is set to Non-directional.
function. This parameter is not applicable in present case, since DirMode1 and DirMode2 are
set to Non-directional.
IPolMin, RNPol, XNPol: These parameter is not applicable in present case, since DirMode1 is
set to Non-directional.
and current. This parameter is not applicable in present case, since DirMode1 and DirMode2
are set to Non-directional.
fault protection. This parameter is not applicable in present case, since DirMode1 and DirMode2
are set to Non-directional.
OFF.

99
t1: This parameter is set to 1s in present case.
Setting
Parameter
Description
Recommended
Settings Unit
UBase
400 kV
UPolMin
of UBase
1 %UB
IPolMin
Minimum current level for polarization in %
of IBase
5 %IB
RNPol
polar-isation
5 Ohm
XNPol
40 Ohm
INDir
in % of IBase
10 %IB
2ndHarmStab
Second harmonic restrain operation in % of
IN amplitude
20 %

100
UseStartValue
3 or 4)
IN4 -
SOTF
Off -
DirMode1
forward, reverse)
Non-Directional -
IN1
% of IBase
20 %IB
k1
Time multiplier for the dependent time delay
for step 1
0 -
IN1Mult
value for step 1
1.0 -
t1Min
Minimum operate time for inverse curves for
step 1
0 s
HarmRestrain1
restrain
On -
tPCrv1
curve for step 1
1 -
tACrv1
curve for step 1
13.5 -
tBCrv1
curve for step 1
0 -
tCCrv1
curve for step 1
1 -

101
tPRCrv1
Parameter PR for customer programmable
curve for step 1
0.5 -
tTRCrv1
Parameter TR for customer programmable
curve for step 1
13.5 -
tCRCrv1
Parameter CR for customer programmable
curve for step 1
1 -
DirMode2
forward, reverse)
Non-Directional -
IN2
% of IBase
1000 %IB
k2
Time multiplier for the dependent time delay
for step 2
0.0 -
IN2Mult
value for step 2
1.0 -
t2Min
Minimum operate time for inverse curves for
step 2
0 s
HarmRestrain2
restrain
On -
tPCrv2
curve for step 2
1 -
tACrv2
curve for step 2
13.5 -
tBCrv2
curve for step 2
0 -
tCCrv2
curve for step 2
1 -
tPRCrv2 Parameter PR for customer programmable
curve for step 2
0.5 -
tTRCrv2
Parameter TR for customer programmable
curve for step 2
13.5 -

102
tCRCrv2
Parameter CR for customer programmable
curve for step 2
1 -
DirMode3
forward, reverse)
Off -
DirMode4
forward, reverse)
Off -
given below:
From CT:
IA
IB
IC
IN
From Bus PT:
VAN
VBN
VCN
— Group-A trip
— Z1 Start
— Group-B trip
— Direct Transfer Trip (only for Line reactors)
— Bus bar trip
— Over Voltage

103
Recording capacity
bay or circuit.
Memory capacity
Recording times
Setting
Parameter
Description
Recommended
Settings Unit

104
ZeroAngleRef
1 Ch

105
3.4 REC670
3.4.1 Analog Inputs
Name# IL1-CB1 IL2-CB1 IL3-CB1 SPARE SPARE SPARE
CTprim 200A 200A 200A 1000A 1000A 1000A
Name# BUS PT BUS PT BUS PT SEL-PT* SEL-PT SEL-PT
VTsec 110V 110V 110V 110V 110V 110V
*SEL-PT: Selected PT input for synchronizing function
# User defined text
Setting
Parameter
Description
Recommended
Settings Unit
PhaseAngleRef
presentation
TRM40-Ch1 -
CTStarPoint1
ToObject -

106
CTStarPoint2
ToObject -
CTStarPoint3
ToObject -
CTStarPoint4
ToObject -
CTStarPoint5
ToObject -
CTStarPoint6
ToObject -

107
Setting
Parameter
Description
Recommended
Settings Unit
AutoRepeat
(Off)
On -

108
Setting
Parameter
Description
Recommended
Settings Unit
tMax
disturbance
0.0 s

109
time.
available in site.

110
Setting
Parameter
Description
Recommended
Settings Unit

111
Setting
Parameter
Description
Recommended
Settings Unit
ModulePosition
Synchronization
3 -
BinaryInput
Synchronization
1 -
Recommended
Settings Unit
Setting
Parameter
Description
Recommended
Settings Unit
UTCTimeOfDay
3600 s
Setting
Parameter
Description
Recommended
Settings Unit
UTCTimeOfDay
3600 s

112
Setting
Parameter
Description
Recommended
Settings Unit
Setting
Parameter
Description
Recommended
Settings Unit
Setting
Parameter
Description
Recommended
Settings Unit

113
Setting
Parameter
Description
Recommended
Settings Unit
Setting
Parameter
Description
Recommended
Settings Unit
CmdTestBit
Command bit for test required or not during
testmode
Off -
Setting
Parameter
Description
Recommended
Settings Unit

114
Setting
Parameter
Description
Recommended
Settings Unit

115
is connected to 3rd
task group.
This parameter is recommended to be set to 10% normally.
Setting
Parameter
Description
Recommended
Settings Unit
MinValFreqMeas
UBase
10 %

116
SelPhaseBus1: Setting of the input phase for Bus 1 voltage reference. This parameter has to be
this parameter is set to L1 (R-phase)
SelPhaseLine1: Setting of the phase or line 1 voltage measurement. This parameter has to be
this parameter is set to L1 (R-phase).
only). This parameter has to be set based on the corresponding phase PT/CVT input connected
to this function. Present case, this parameter is set to L1 (R-phase)
UBase: Setting of the Base voltage level on which the voltage settings are based. This
PhaseShift: This setting is used to compensate for a phase shift caused by a transformer
between the two measurement points for bus voltage and line voltage, or by a use of different
voltages as a reference for the bus and line voltages. The set value is added to the measured
line phase angle. The bus voltage is the reference voltage. This parameter is set to 0°in present
case.
URatio: The URatio is defined as URatio = bus voltage/line voltage. This setting scales up the
line voltage to an equal level with the bus voltage. This parameter is set to 1 in present case.
If No voltage sel. is set, the default voltages used will be U-Line1 and U-Bus1. This is also the
case when external voltage selection is provided. Fuse failure supervision for the used inputs
must also be connected. In present case this parameter is set to 1 1/2 bus CB.
To allow closing of breakers between asynchronous networks a synchronizing function is
provided. The systems are defined to be asynchronous when the frequency difference between
bus and line is larger than an adjustable parameter.

117
voltage at Line synchronism check. The voltage level settings must be chosen in relation to the
bus or line network voltage. The threshold voltages UHighBusSC and UHighLineSC have to be
set lower than the value at which the breaker is expected to close with the synchronism check. A
typical value can be 80% of the base voltages.
typical value for FreqDiffM can be10 mHz for a connected system, and a typical value for
FreqDiffA can be 100-200 mHz. FreqDiffA is not applicable in present case.
PhaseDiffM and PhaseDiffA: The phase angle difference level settings for Manual and Auto
sync. PhaseDiffM is normally recommended to set 30°. PhaseDiffA is not applicable in present
case.
tSCM and tSCA: Setting of the time delay for Manual and Auto synchronism check. Circuit
breaker closing is thus not permitted until the synchrocheck situation has remained constant
throughout the set delay setting time. Typical values for tSCM and tSCA can be 0.1s.
AutoEnerg and ManEnerg: Setting of the energizing check directions to be activated for
AutoEnerg. Setting of the manual Dead line/bus and Dead/Dead switching conditions to be
allowed for ManEnerg.
voltage is above set value of UHighBusEnerg. DBLL, Dead Bus Live Line, the bus voltage is
below set value of ULowBusEnerg and the line voltage is above set value of UHighLineEnerg.
AutoEnerg is made OFF and ManEnerg is set to Both of the above DLLB, DBLL. Hence Auto
related parameters are not applicable.
ManEnergDBDL: This need to be made OFF to avoid manual closing of the breaker if both Bus
and Line are dead. In present case this parameter is set OFF.
energizing for UHighBusEnerg. Set the operating level for the Line high voltage at Bus
energizing for UHighLineEnerg.
The threshold voltages UHighBusEnerg and UHighLineEnerg have to be set lower than the value
at which the network is considered to be energized. A typical value can be 80% of the base

118
voltages. If system voltages are above the set values here, relay will consider it as Live
condition.
ULowBusEnerg and ULowLineEnerg: Setting of the operating voltage level for the low Bus
voltage level at Bus energizing for ULowBusEnerg. Setting of the operating voltage level for the
low line voltage level at line energizing for ULowLineEnerg.
The threshold voltages ULowBusEnerg and ULowLineEnerg, have to be set to a value greater
than the value where the network is considered not to be energized. A typical value can be 40%
of the base voltages. If system voltages are below the set values here, relay will consider it as
Dead condition.
UMaxEnerg: Setting of the maximum live voltage level at which energizing is allowed. This
setting is used to block the closing when the voltage on the live side is above the set value of
UMaxEnerg. In present case this parameter is set to 105% of UBase.
The purpose of the timer delay settings, tAutoEnerg and tManEnerg, is to ensure that the dead
side remains de-energized and that the condition is not due to a temporary interference. If the
conditions do not persist for the specified time, the delay timer is reset and the procedure is
restarted when the conditions are fulfilled again. Circuit breaker closing is thus not permitted until
the energizing condition has remained constant throughout the set delay setting time. Normally
tManEnerg is recommended to set 0.1s. tAutoEnerg is not applicable in present case.
OperationSynch: Operation for synchronizing function Off/ On. This parameter is recommended
to set OFF.
tBreaker, tMinSynch and tMaxSynch: These parameters are not applicable if OperationSynch
is set to OFF.
Table 3-50: Synchrocheck function Settings
Setting
Parameter
Description
Recommended
Settings
Unit

119
OperationSynch Operation for synchronizing function Off/ On Off -
OperationSC
Off/On
On -
UHighBusSC
Voltage high limit bus for synchrocheck in % of
UBaseBus
80.0 %UBB
UHighLineSC
Voltage high limit line for synchrocheck in % of
UBaseLine
80.0 %UBL
FreqDiffA
and line Auto
0.10 Hz
FreqDiffM
and line Manual
0.10 Hz
PhaseDiffA
bus and line Auto
30.0 Deg
PhaseDiffM
bus and line Manual
30.0 Deg
tSCM
Manual
0.100 s
UHighBusEnerg
Voltage high limit bus for energizing check in
% of UBaseBus
80.0 %UBB
UHighLineEnerg
Voltage high limit line for energizing check in
% of UBaseLine
80.0 %UBL
ULowBusEnerg
Voltage low limit bus for energizing check in %
of UBaseBus
40.0 %UBB
ULowLineEnerg
Voltage low limit line for energizing check in %
of UBaseLine
40.0 %UBL

120
UMaxEnerg
105.0 %UB
tAutoEnerg Time delay for automatic energizing check 0.100 s
Phase L1 for
busbar1
-
Phase L1 for
busbar2
-
SelPhaseLine1 Select phase for line1
Phase L1 for
line1
-
SelPhaseLine2 Select phase for line2
Phase L1 for
line2
-
ADDITIONAL NOTES:
1. These settings provided for the Shunt Reactor are for the considered case of Bus
Reactor connected in one and half CB bus configuration.
2. For the case of Shunt reactor used as Line Reactor, the Settings get modified
due to the fact that Reactor bushing CT inputs are used for reactor protection in
place of Bay CT used for some functions in the present case.
3. In the case of Bus Reactor also, It is advisable to use Bushing CT for Reactor
Back-up impedance protection function. Teed protection can be used additionally
for the protection of T point of the associated bay.
4. Back-up over-current and earth fault protection can also be duplicated in any of
the other IED.

IED USED FOR 400kV BUSBAR PROTECTION

Model setting calculation document for Busbar
2
TABLE OF CONTENTS
1.1 Single line diagram of the Busbar..................................................................................... 6
1.2 Busbar parameters............................................................................................................. 6
2 TERMINAL IDENTIFICATION AND LIST OF FUNCTIONS................................................. 7
2.1 REB500................................................................................................................................ 7
2.1.1 Terminal Identification..................................................................................... 7
2.1.2 List of functions available and those used....................................................... 7
3 SETTING CALCULATIONS AND RECOMMENDED SETTINGS FOR REB500 ................. 8
3.1 REB500................................................................................................................................ 8
3.1.1 Busbar Protection (BBP) ................................................................................. 8
3.1.2 Breaker Failure Protection (BFP) ...................................................................11

3
LIST OF FIGURES
Figure 1-1: Single line diagram of the Busbar with CT connections.............................................................6
Figure 3-1: Operating characteristics of the restrained amplitude comparison function...............................9

4
LIST OF TABLES
Table 2-1: List of functions in REB500..........................................................................................................7
Table 3-1: Differential protection settings ...................................................................................................11
Table 3-2: Breaker failure protection settings .............................................................................................15

5
400kV Busbar

6
1.1 Single line diagram of the Busbar
Single line diagram of the Busbar and CT/PT connections is shown in Figure 1-1.
Figure 1-1: Single line diagram of the Busbar with CT connections
CT details:
CT core used for Busbar protection (same is applicable for both main-I and main-II relays):
Ratio: 2000/1A, CLASS: PS, Vk: 4000V, Imax at Vk: 120mA, Rct@75 DEGREE
CENTIGRADE ohm: 10Ω
Above details are applicable for all the bays of 400kV Busbar protection.
1.2 Busbar parameters
Busbar: At Substation-A
Frequency: 50Hz
Maximum fault level 3-ph: 20.41kA
Maximum fault level 1-ph: 12.41kA

7
The various functions required for the Busbar protection are provided in REB500 IED. The
terminal identification of this and list of various functions available in these IEDs are given in this
section.
2.1 REB500
Object Name: 400kV Busbar
Unit Name: REB500
Frequency: 50Hz
Table 2-1 gives the list of functions/features available in REB500 relay and also indicates the
Table 2-1: List of functions in REB500
Sl.No. Function/features available In REB500
Function/feature
activated
Yes/No
Recommended
Settings
provided
1 Busbar protection YES
2 Breaker failure protection YES
“Distributed busbar protection REB500 including line and transformer protection
Operating instruction” 1MRB520292-Uen, version 7.6.

8
3 SETTING CALCULATIONS AND RECOMMENDED
SETTINGS FOR REB500
The various functions required for the Busbar protection are provided in REB500. The setting
calculations and recommended settings for various functions available in this IED are given in
this section.
3.1 REB500
3.1.1 Busbar Protection (BBP)
Some general comments on BB protection application and settings are covered here.
If left uncleared, the effect of a fault in a bus-zone can be potentially far more damaging than
faults on other items of primary plant. The unplanned or unselective outage of the bus bar can
lead to the loss of power supply to a widespread area. The failure to clear a bus fault can lead to
considerable equipment damage and system instability. Therefore bus bar protection has an
important role to play.
Few important points related to application and settings are given below.
• Bus bar protections being of unit type, back-up protection is provided either by duplicating
the bus bar protection, or by reverse zone of line distance protection, or by time delayed
distance relays in the remote stations.
• Where the main bus bar protection is provided by the second zone elements of distance
relays (i.e., when no bus bar protection is provided), back-up protection can be considered
as being provided by the 3rd
zone elements of distance relays in the more remote stations.
• For substations of high strategic importance or where the bus arrangements are complex,
the complete bus bar protection should be fully duplicated.
• In cases where the burn-through time of SF6 switchgear is considered to be shorter than the
tripping time from remote back-up protection, then also the bus bar protection must be
duplicated.
• Faults lying between C.B and C.T. shall be cleared from one side by opening of C.B on
busbar protection operation. However clearing of fault from other side shall be through
breaker failure protection/back up protection.

9
• 3 Phase trip relays shall be provided for each circuit breaker which shall also initiate B.F.P.
of concerned breaker.
• C.T wire supervision relays should be set with a sensitivity such that they can detect C.T.
secondary open circuit even in case of least loaded feeder.
• Bus bar differential protection should have overall sensitivity above heaviest loaded feeder
current unless a separate check zone has been provided. In cases where fault currents are
expected to be low, the protection should be sensitive enough to take care of such expected
low fault current.
Relay operating characteristic is shown in Figure 3-1.
Figure 3-1: Operating characteristics of the restrained amplitude comparison function
IKmin (Op. char. ‘L1, L2, L3’): This dialog is for entering the parameters applicable to the
phase fault operating characteristic.
The pick-up setting for the fault current (IKmin) must be less (80%) than the lowest fault current
that can occur on the busbars (IKMS). These is a risk of the protection being too insensitive at
higher settings.

10
Providing the minimum fault current (IKMS) is high enough, IKmin should be set higher than the
maximum load current.
The ‘restrained amplitude comparison’ algorithm detects an internal fault when the settings for
IKmin and k are exceeded. A tripping command is only issued, however, providing the phase
comparison function detects an internal fault at the same time.
This is normally set to 1.3 times Maximum load current so that the value is set higher than the
maximum load current. Lowest fault current that can occur on Busbars are typically very higher
than the highest CT ratio.
k (Op. char. ‘L1, L2, L3’): The factor “k” (slope) is normally set to 0.80. Numerous tests on a
network model have shown this setting to be the most favorable.
Note: During a thorough-fault and normal operation, it is impossible for the differential
(operating) current to be higher than the restrain current.
Differential current alarm (Op. char. ‘L1, L2, L3’): Alarm should be set lower than the lowest
load current. A typical setting is 5%.
Delay (Op. char. ‘L1, L2, L3’): Differential current alarm, a typical setting is 5s.
IKmin (Op. char. ‘L0’): Ikmin for ‘L0’ shall be set to 50% of the Ikmin of L1, L2, L3.
The procedure for setting the ground fault characteristic is the same as for phase faults.
This dialog is only available providing a neutral current measurement has been configured.
k, Differential current alarm, Delay (Op. char. ‘L0’): These parameters are set same as that
of Op. char. ‘L1, L2, L3’.
IKmin, k, Differential current alarm, Delay (Op. char. ‘Check-Zone’): These parameters are
set same as that of Op. char. ‘L1, L2, L3’. These settings are not visible if check zone is not
used.
IKmin (Op. char. ‘L1, L2, L3’):
Maximum load current=2000A (CT ratio used for Busbar protection is considered)
Here CT ratio of any bay has been considered for settings. Check with actual max load and set
accordingly.
Ikmin =2600A (1.3 times of Maximum load current).
IKmin (Op. char. ‘L0’): Ikmin for ‘L0’ shall be set to 50% of the Ikmin of L1, L2, L3, i.e. 1300A.
Differential current alarm (Op. char. ‘L1, L2, L3’):
In present case, Min bay current is 69A, i.e., 50Mvar, 420kV Bus Reactor bay current, which is
2.7% of Ikmin(2600A). As the minimum available setting is 5%, hence 5% is set.

11
Table 3-1: Differential protection settings
Setting Parameter
Recommended
Settings Unit
IKmin Op. char. ‘L1, L2, L3’ 2600 A
K Op. char. ‘L1, L2, L3’ 0.80
Differential current alarm Op. char. ‘L1, L2, L3’ 5 % IKmin
Delay (Differential current alarm) Op. char. ‘L1, L2,
L3’
5 s
IKmin
Op. char. ‘L0’
1300 A
k
Op. char. ‘L0’
0.80
Differential current alarm
Op. char. ‘L0’
5 % IKmin
Delay
(Differential current alarm)
Op. char. ‘L0’
5 s
3.1.2 Breaker Failure Protection (BFP)
Some general comments on Breaker failure protection application and settings are described
here.
Failure of a circuit breaker to open when a trip signal has been given to it can lead to wide
spread tripping. Disconnecting the adjacent breakers using a breaker failure protection can
contain the impact. Failure to provide this protection can lead to considerable equipment
damage and system instability. Therefore breaker fail protection has an important role to play.
Some important points related to its application and settings are given below.
• One may decide to plan and operate the power system to avoid transient instability at shunt
faults with a stuck breaker. The back-up fault clearance time then determines the power

12
transfer capability of the transmission network. This means that it is very important to have a
fast breaker failure protection.
• The relay is separate for each breaker and is to be connected in the secondary circuit of the
CTs associated with that particular breaker. This CT secondary may be a separate core, if
available. Otherwise it shall be clubbed with Main-I or Main-II protection core.
• For line breakers, direct tripping of remote end breaker(s) should be arranged on operation
of LBB protection. For transformer breakers, direct tripping of breaker(s) on the other side of
the transformer should be arranged on operation of LBB protection.
• For lines employing single phase auto-reclosing, the LBB relays should be started on a
single phase basis from the trip relays. This is to avoid load currents in the healthy phases,
after single phase tripping, leading to unwanted operation of the breaker failure protection,
since the current setting is normally lower than the load current.
• It is considered a good practice to have DC circuits of Gr.A and Gr.B protections and LBB
relay independent. A separately fused supply should be taken for LBB relay in this case.
• LBB cannot operate without proper initiation. It is good practice to provide redundant trip
output and breaker fail input where other forms of redundancy does not exist. One way of
doing this is by providing separate aux. relay in parallel with trip unit and using contacts of
these for LBB initiation.
• Separation should be maintained between protective relay and CB trip coil DC circuit so that
short circuit or blown fuse in the CB circuit will not prevent the protective relay from
energizing the LBB scheme.
• In addition to other fault sensing relays the LBB relay should be initiated by Busbar
protection, since failure of CB to clear a bus fault would result in the loss of entire station if
LBB relay is not initiated.
• Whenever used in combination with busbar protection scheme, tripping logic of the same
shall be used for LBB protection also.
• For breaker-fail relaying for low energy faults like buchholz operation, special considerations
may have to be given to ensure proper scheme operation by using CB contact logic in
addition to current detectors. It is recommended that for operation of Buchholz protection, an
additional criterion from breaker auxiliary contact may be provided.
• Current level detectors should be set as sensitive as the main protections. A general setting
of 200A primary value (this should be more than the minimum operating current of the main
protection) is commonly practiced for lines and transformers. However, in case of existing

13
schemes associated with lines having single phase autoreclosure and where phase wise
initiation is not available, it is recommended that 2ph + 1 E/F element may be used with
phase element set above maximum expected load current while E/F element may be set
sensitively.
• Current level detector for generators may be set at 50 mA (for 1A C.T. secondary).
• Timer setting should be set considering breaker interrupting time, current detector reset time
and a margin. Generally a timer setting of 200ms has been found to be adequate.
• It is recommended that the utilities maintain the circuit breaker performance data, which will
be useful in planning back-up protection and other actions pertaining to circuit breaker
performance and maintenance.
• It is desirable that the back-up fault clearance time is shorter than the operating time of the
remote protections. One would lose the advantages with the expensive bus bar
configuration, if Zone-2 of the distance protection in the remote substations operates faster
than the breaker failure protection.
• It is possible to use one delay for single-phase faults and a shorter delay for multi-phase
faults in the breaker fail protection. This is done to avoid transient instability during multi-
phase faults in combination with a stuck breaker. The critical fault clearance time is much
longer for single-phase faults than for multi-phase faults.
• It is possible to design the breaker failure protection to have two steps. This approach may
decrease the risk for unwanted operation of the breaker failure protection during
maintenance and fault tracing. Therefore it is recommended utilities consider two-stage
tripping to avoid any unwanted operation of circuit breaker fail protection.
• It is a good practice to use breaker failure protection provided in a separate hardware than
the one used for main protection, when a multifunction numerical protective relay is used for
line, transformer, reactor etc. This will help avoid losing breaker fail protection function when
main protection fails. Thus it can be separate stand-alone relay or provided in bay controller
or as part of bus bar protection. If the main protections are duplicated and have built in
breaker fail function, providing it in a separate hard ware is not required. In such cases the
breaker fail function gets duplicated.

14
BFP active: Set whether BFP need to be active or not. It is set to active in present case.
Setting (per current transformer): Basically, the current setting (IE) should be less than the
minimum fault current IKmin of the corresponding feeder (approx. 80%. i.e. 0.8). Just to satisfy
this condition, the setting would be
=
In present case, this parameter is set to 0.2.
Timer 1 active: A second attempt is made to trip the circuit-breaker at the end of the set time t1
plus the internal processing time ta1.
Timer t2 is also started at the end t1. Timer 1 active setting is to activate or deactivate this timer.
Hence this parameter is set to active in present case.
Timer 2 active: Should the circuit-breaker again fail to trip within the set time of t2 plus the
internal processing time ta2, the breakers surrounding the fault are inter tripped. This parameter
is to activate the backup trip delay. Timer 2 active settings is to activate of deactivate this timer.
Hence this parameter is set to active in present case.
Timer t1: This is retrip time delay. In present case this parameter is set to 100ms.
To avoid any risk of a premature tripping command by the breaker failure protection, the
minimum setting of the timer t1 must be longer than the maximum time required for a successful
main protection trip plus the maximum reset time of the overcurrent function.
Minimum time for timer t1 is t1 tCB + tv + tmargin.
Minimum t1 setting for a circuit-breaker operating time (tCB) of 40 ms
t1 tCB + tv + tmargin = 40 ms + 19 ms + 20 ms 79 ms
Maximum backup tripping time for a circuit-breaker operating time (tCB) of 40 ms
t1max = [te+ta1] + tCB + tv + tmargin = 24 ms + 40 ms + 19 ms + 20 ms = 103 ms.
Timer t2: This is backup trip time delay. In present case this parameter is set to 100ms.
Zone2 time of the distance relay must be set higher than the time of operation of LBB.
To avoid any risk of premature inter tripping of the surrounding breakers by the breaker failure
protection in the event of a successful backup trip at the end of t1, the minimum setting of the
timer t2 must be longer than the maximum time required for a backup trip plus the maximum
reset time of the overcurrent function.
Minimum time for timer t2 is t2 ta1 + tCB + tv + tmargin
Minimum t2 setting for a circuit-breaker operating time (tCB) of 40 ms

15
t2 tCB + [ta1 + tv] + tmargin = 40 ms + 33 ms + 20 ms 93 ms
Maximum inter tripping time for a circuit-breaker operating time (tCB) of 40 ms
t2max = [te+ta1+ ta2]+ 2*(tCB + tv + tmargin) = 46 ms+ 2*(40 ms+19 ms+20 ms) = 204 ms.
Only if the above guidelines for the minimum settings of the breaker failure timers are strictly
observed is the correct operation of the breaker failure protection assured.
The maximum tripping time can be calculated on the basis of the settings for t1 and t2, the
recommended safety margin and the internal processing time.
Intertripping pulse duration: The trigger inputs are scanned every 16ms. A trigger signal
must have a pulse duration of at least 16ms to be certain that it will be detected. This parameter
is left to default value of 200ms.
Logic type: The internal breaker failure protection can be changed for special applications. For
normal breaker failure protection, this logic shall be set to 1 (Default value).
Table 3-2 gives the recommended setting for Breaker failure protection.
Table 3-2: Breaker failure protection settings
Setting Parameter Recommended Settings
Unit
BFP active Active
Setting (per current transformer) 0.2 IN
Timer 1 active Active
Timer 2 active active
Timer t1 100 ms
Timer t2 100 ms
Intertripping pulse duration 200 ms
Logic type 1

PROTECTIVE RELAY SETTING GUIDELINES FOR 220kV, 400kV AND 765kV
TRANSMISSION LINES
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Table of Contents
A. UNCOMPENSATED TRANSMISSION LINES...................................................................3
1. ZONE-1 REACH SETTING: ...................................................................................................3
4. RESISTIVE REACH SETTING ...............................................................................................4
5. ZONE-2 TIMER SETTING:.....................................................................................................5
6. ZONE-3 TIMER SETTING......................................................................................................7
7. LOAD IMPEDANCE ENCROACHMENT ..........................................................................7
8. ZONE-4 SUBSTATION LOCAL BACKUP PROTECTION SETTINGS...........................8
9. USE OF SYSTEM STUDIES TO ANALYSE DISTANCE RELAY BEHAVIOUR ............9
10. DIRECTIONAL PHASE OVER CURRENT PROTECTION ........................................10
11. DIRECTIONAL GROUND OVER CURRENT PROTECTION SETTINGS ...............10
12. POWER SWING BLOCKING FUNCTION :..................................................................11
12.1. Block all Zones except Zone-I :......................................................................................11
12.2. Block All Zones and Trip with Out of Step (OOS) Function ...........................................12
12.3. Placement of OOS trip Systems ....................................................................................12
13. LINE OVERVOLTAGE PROTECTION ..........................................................................13
14. LINE DIFFERENTIAL PROTECTION............................................................................13
15. MAINTAINING OPERATION OF POWER STATION AUXILIARY SYSTEM OF
NUCLEAR POWER PLANTS: .....................................................................................................13
16. COORDINATION BETWEEN SYSTEM STUDY GROUP AND PROTECTION
ENGINEERS ...................................................................................................................................14
B. SERIES COMPENSATED TRANSMISSION LINES:............................................................14
1) VOLTAGE AND CURRENT INVERSION.........................................................................14
1.1. Voltage inversion on Series Compensated line: ........................................................14

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1.2. Current inversion on Series Compensated line: ........................................................14
2) LOW FREQUENCY TRANSIENTS.....................................................................................15
3) MOV INFLUENCE AND APPARENT IMPEDANCE .....................................................15
4) IMPACT OF SC ON PROTECTIVE RELAYS OF ADJACENT LINES...........................16
5) MULTI CIRCUIT LINES .......................................................................................................16
6) DIRECTIONAL RESIDUAL OVERCURRENT PROTECTION ......................................17
7) DISTANCE PROTECTION SETTINGS GUIDELINES.....................................................18
8) SIMULATION STUDIES.......................................................................................................19

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A review was made by the Protection Task force of the setting criteria for 220kV,
400kV and 765kV transmission lines (both uncompensated and series compensated)
and the recommendations on the settings to be adopted are given below. The
recommendations are based on guidelines given in following documents.
• CBIP Publication no 274: Manual on Protection of Generators, Generator
Transformers and 220kV and 400kV Networks
• CBIP Publication no 296: Manual on Reliable Fault Clearance and Back-Up
Protection of EHV and UHV Transmission Networks
• CIGRE WG B5.10, 411: Protection, Control and Monitoring Of Series
Compensated Networks
• CIGRE WG 34.04 ; Application Guide on Protection Of Complex
Transmission Network Configurations
A.UNCOMPENSATED TRANSMISSION LINES
1. ZONE-1 REACH SETTING:
Zone-1: To be set to cover 80% of protected line length. Set zero sequence
compensation factor KN as (Z0 – Z1) / 3Z1.
Where:
Z1= Positive sequence impedance of the protected line
Z0 = Zero sequence impedance of the protected line
Note: With this setting, the relay may overreach when parallel circuit is open and
grounded at both ends. This risk is considered acceptable.
Zone-2: To be set to cover minimum 120% of length of principle line section.
However, in case of double circuit lines 150% coverage must be provided to take
care of under reaching due to mutual coupling effect. Set KN as (Z0 – Z1) / 3Z1.
The 150% setting is arrived at considering an expected under reach of about 30%
when both lines are in parallel and a margin of 20%. The degree of under reach can

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be calculated using equation K0M / 1+K0 Where K0M = Z0M/ 3Z1 and K0 = (Z0 – Z1)
/ 3Z1. It is recommended to check the degree of under reach due to mutual coupling
effect to be sure that setting of 150% is adequate.
Sometimes impedance so selected might enter the next voltage level. However, un-
selectivity in the Zone-2 grading is generally not to be expected when in-feeds exist
at the remote sub-station as they reduce the overreach considerably.
This holds good for majority of the cases, however, for certain cases, where in-feed
from other feeder at the local bus is not significant, Zone-2 of remote end relay may
see the fault at lower voltage level. Care has to be taken for all such cases by suitable
time delay.
Zone-3 distance protection can offer time-delayed remote back-up protection for an
adjacent transmission circuit. To achieve this, Zone-3 distance elements must be set
according to the following criteria where possible.
Zone-3 should overreach the remote terminal of the longest adjacent line by an
acceptable margin (typically 20% of highest impedance seen) for all fault conditions.
Set KN as (Z0 – Z1) / 3Z1.
However, in such case where Zone-3 reach is set to enter into next lower voltage
level, Zone-3 timing shall be coordinated with the back-up protection (Directional
over current and earth fault relay) of power transformer. Where such coordination
cannot be realised, other means like application of back up distance protection for
power transformer or special protection scheme logic may have to be considered to
achieve protection coordination.
4. RESISTIVE REACH SETTING
For phase to ground faults, resistive reach should be set to give maximum coverage
considering fault resistance, arc resistance tower footing resistance. It has been
considered that ground fault would not be responsive to line loading.

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For Zone-1 resistive reach, attention has to be given to any limitations indicated by
manufacturer in respect of resistive setting vis-a-vis reactance setting to avoid
overreach due to remote in-feed. It is recommended to study the impact of remote end
infeed for expected power flow fault resistance on the extent of overreach. This is
particularly important for short lines.
In case of phase to phase fault, resistive reach should be set to provide coverage
against all types of anticipated phase to phase faults subject to check of possibility
against load point encroachment considering minimum expected voltage and
maximum load expected during short time emergency system condition.
It is recommended that all the distance relays should have quadrilateral / polygon
characteristic. For relays having Mho characteristic, it is desirable to have load
encroachment prevention characteristic or a blinder.
In the absence of credible data regarding minimum voltage and maximum load
expected for a line during emergency system condition, following criteria may be
considered for deciding load point encroachment:
• Maximum load current (Imax) may be considered as 1.5 times the thermal
rating of the line or 1.5 times the associated bay equipment current rating (the
minimum of the bay equipment individual rating) whichever is lower.
(Caution: The rating considered is approximately 15minutes rating of the
transmission facility).
• Minimum voltage (Vmin) to be considered as 0.85pu (85%).
Due to in-feeds, the apparent fault resistance seen by relay is several times the actual
value. This should be kept in mind while arriving at resistive reach setting for Zone-
2 and Zone-3.
5. ZONE-2 TIMER SETTING:
A Zone-2 timing of 0.35 seconds (considering LBB time of 200mSec, CB open time of
60ms, resetting time of 30ms and safety margin of 60ms) is recommended. However,

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if a long line is followed by a short line, then a higher setting (typically 0.6second)
may be adopted on long line to avoid indiscriminate tripping through Zone-2
operation on both lines.
For special cases, following shall be the guiding philosophy:
Since Zone-2 distance protection is set to overreach the circuit it is intended to
protect, it will also be responsive to faults within adjacent power system circuit. For
this reason the time delay for Zone–2 back-up protection must be set to coordinate
with clearance of adjacent circuit faults, within reach, by the intended main
protection or by breaker fail protection.
The following formula would be the basis for determining the minimum acceptable
Zone-2 time setting:
s
reset
z
CB
MA
z t
t
t
t
t +
+
+
2
2
Where:
tZ2 = Required Zone-2 time delay
tMA = Operating time of slowest adjacent circuit main protection or Circuit
Local back-up for faults within Zone-2 reach
tCB = Associated adjacent circuit breaker clearance time
tZ2reset = Resetting time of Zone-2 impedance element with load current
present
tS = Safety margin for tolerance (e.g. 50 to 100ms)
Unequal lengths of transmission circuit can make it difficult to meet the Zone-2
secondary reach setting criterion. In such cases it will be necessary to co-ordinate
Zone-2 with longer time delay. The time tMA in equation must be the adjacent circuit
Zone-2 protection operating time.

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6. ZONE-3 TIMER SETTING
Zone-3 timer should be set so as to provide discrimination with the operating time
of relays provided in subsequent sections with which Zone-3 reach of relay being
set, overlaps. Typical recommended Zone-3 time is 0.8 to 1.0 second.
For Special cases, where co-ordination between long and short lines is required,
following formula would be the basis for determining the minimum acceptable
Zone-3 time setting:
s
reset
z
CB
MA
z t
t
t
t
t +
+
+
3
3
Where:
tZ3 = Required Zone-3 time delay
tMA = Operating time of slowest adjacent circuit local back-up protection
tCB = Associated adjacent circuit breaker clearance time
tZ3reset = Resetting time of Zone-3 impedance element with load current present
tS = Safety margin for tolerance (e.g. 50 to 100milliseconds)
7. LOAD IMPEDANCE ENCROACHMENT
With the extended Zone-3 reach settings, that may be required to address the many
under reaching factors already considered, load impedance encroachment is a
significant risk to long lines of an interconnected power system. Not only the
minimum load impedance under expected modes of system operation be considered
in risk assessment, but also the minimum impedance that might be sustained for
seconds or minutes during abnormal or emergency system conditions. Failure to do
so could jeopardize power system security.
Ideal solution to tackle load encroachment may be based on the use of blinders or by
suitably setting the resistive reach of specially shaped impedance elements or by use
of polygon type impedance elements.

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It is recommended that all the distance relays should have quadrilateral / polygon
characteristic. For relays having Mho characteristics, it is desirable to have load
encroachment prevention characteristics or a blinder.
In the absence of credible data regarding minimum voltage and maximum load
expected for a feeder during emergency system condition, following criteria may be
considered for deciding resistive reach / blinder setting to prevent load point
encroachment:
• Maximum load current (Imax) may be considered as 1.5 times the thermal
rating of the line or 1.5 times the associated bay equipment current rating ( the
minimum of the bay equipment individual rating) whichever is lower.
(Caution: The rating considered is approximately 15 minutes rating of the
transmission facility).
• Minimum voltage (Vmin) to be considered as 0.85pu (85%).
• For setting angle for load blinder, a value of 30 degree may be adequate in most
cases.
For high resistive earth fault where impedance locus lies in the Blinder zone, fault
clearance shall be provided by the back-up directional earth fault relay.
8. ZONE-4 SUBSTATION LOCAL BACKUP PROTECTION SETTINGS
Zone-3 distance protection is usually targeted to provide only remote back-up
protection. In such a case, the distance relay may be provided with an additional
zone of reverse-looking protection (e.g. Zone-4) to offer substation-local back-up
protection. The criterion for setting Zone-4 reverse reach would be as under.
• The Zone-4 reverse reach must adequately cover expected levels of apparent bus
bar fault resistance, when allowing for multiple in feeds from other circuits. For
this reason, its resistive reach setting is to be kept identical to Zone-3 resistive
reach setting.

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With a reverse reach setting of less than the Zone-1 reach of distance protection for
the shortest line connected to the local bus bar, the Zone-4 time delay would only
need to co-ordinate with bus bar main protection fault clearance and with Zone-1
fault clearance for lines out of the same substation. For this reason this can be set
according to the Zone-2 time setting guidelines.
9. USE OF SYSTEM STUDIES TO ANALYSE DISTANCE RELAY BEHAVIOUR
Often during system disturbance conditions, due to tripping of one or more trunk
lines, some lines get overloaded and the system voltage drops. During such
conditions the back-up distance elements may become susceptible to operation due
to encroachment of impedance locus in to the distance relay characteristic.
While the ohmic characteristic of a distance relay is independent of voltage, the load
is not generally constant-impedance. The apparent impedance presented to a
distance relay, as the load voltage varies, will depend on the voltage characteristic of
the load. If the low voltage situation resulted from the loss of one or more
transmission lines or generating units, there may be a substantial change in the real
and reactive power flow through the line in question. The combination of low
voltage and worsened phase angle may cause a long set relay to operate undesirably
either on steady state basis, or in response to recoverable swings related to the
initiating event.
The apparent impedance seen by the relay is affected by in-feeds, mutual coupling
and therefore the behaviour of distance relay during various system condition needs
to be studied wherever necessary to achieve proper relay coordination.
It is desirable and hence recommended that system studies are conducted using computer-
aided tools to assess the security of protection by finding out trajectory of impedance in
various zones of distance relay under abnormal or emergency system condition on case-to-
case basis particularly for critical lines / corridors.
In addition, the settings must be fine-tuned, simulating faults using Real Time Digital
Simulator on case-to-case basis particularly for critical lines / corridors.

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Such facilities available at CPRI, POWERGRID or elsewhere in the country should
be used for protection related studies.
10. DIRECTIONAL PHASE OVER CURRENT PROTECTION
Directional phase over current relays are still being used as back-up protection for
220kV transmission lines by many utilities. In view of time coordination issues and
increased fault clearance time in the event of failure of main distance protection, it is
recommended that for all 220kV lines also main-1 and main-2 protections similar to 400kV
lines be provided.
11. DIRECTIONAL GROUND OVER CURRENT PROTECTION (DEF) SETTINGS
Normally this protection is applied as a supplement to main protection when
ground fault currents may be lower than the threshold of phase over current
protection. It might also be applied as main protection for high resistance faults.
The ground over current threshold should be set to ensure detection of all ground
faults, but above any continuous residual current under normal system operation.
Continuous residual current may arise because of following:
• Unbalanced series impedances of untransposed transmission circuits
• Unbalanced shunt capacitance of transmission circuits.
• Third harmonic current circulation.
Various types of directional elements may be employed to control operation of
ground over current (zero sequence over current) protection response. The most
common approach is to employ Phase angle difference between Zero sequence
voltage and current, since the relaying signals can easily be derived by summing
phase current signals and by summing phase voltage signals from a suitable voltage
transformer.
However this method is not suitable for some applications where transmission lines
terminated at different substations, run partially in parallel. In such cases following

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type of directional control is recommended to be used for the directional earth fault
relay.
• Relative phase of negative sequence voltage and current
To ensure proper coordination, operating time must be set according to following
criteria:
The DEF protection should not operate when the circuit local backup protection of
remote end clears a fault in an adjacent circuit i.e DEF should be coordinated with
the remote end LBB.
12. POWER SWING BLOCKING FUNCTION
While the power-swing protection philosophy is simple, it is often difficult to
implement it in a large power system because of the complexity of the system and
the different operating conditions that must be studied. There are a number of
options one can select in implementing power-swing protection in their system.
Designing the power system protection to avoid or preclude cascade tripping is a
requirement of modern day power system. Below we list two possible options:
12.1. Block all Zones except Zone-I
This application applies a blocking signal to the higher impedance zones of
distance relay and allows Zone 1 to trip if the swing enters its operating
characteristic. Breaker application is also a consideration when tripping during
a power swing. A subset of this application is to block the Zone 2 and higher
impedance zones for a preset time (Unblock time delay) and allow a trip if the
detection relays do not reset.
In this application, if the swing enters Zone 1, a trip is issued, assuming that the
swing impedance entering the Zone-1 characteristic is indicative of loss of
synchronism. However, a major disadvantage associated with this philosophy
is that indiscriminate line tripping can take place, even for recoverable power
swings and risk of damage to breaker.

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12.2. Block All Zones and Trip with Out of Step (OOS) Function
This application applies a blocking signal to all distance relay zones and order
tripping if the power swing is unstable using the OOS function (function built
in modern distance relays or as a standalone relay). This application is the
recommended approach since a controlled separation of the power system can
be achieved at preselected network locations. Tripping after the swing is well
past the 180 degree position is the recommended option from CB operation
point of view.
Normally all relay are having Power swing Un-block timer which unblocks on
very slow power swing condition (when impedance locus stays within a zone
for a long duration). Typically the Power swing un-blocking time setting is
2sec.
However, on detection of a line fault, the relay has to be de-blocked.
12.3. Placement of OOS trip Systems
Out of step tripping protection (Standalone relay or built-in function of Main
relay) shall be provided on all the selected lines. The locations where it is
desired to split the system on out of step condition shall be decided based on
system studies.
The selection of network locations for placement of OOS systems can best be obtained
through transient stability studies covering many possible operating conditions.
Till such studies are carried out and Out-of-Step protection is enabled on all identified
lines, it is recommended to continue with the existing practice of Non-Blocking of
Zone-I on Power Swing as mentioned under Option-12.1 above. However it should be
remembered that with this practice the line might trip for a recoverable swing and it is
not good to breakers.
Committee strongly recommends that required studies must be carried out at the
earliest possible time (within a timeframe of one year) to exercise the option-12.2
12.3 above.

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13. LINE OVERVOLTAGE PROTECTION
FOR 400kV LINES: Low set stage (Stage-I) may be set in the range of 110% - 112%
(typically 110%) with a time delay of 5 seconds. High set stage (Stage-II) may be set
in the range 140% - 150% with a time delay of 100milliseconds.
FOR 765kV LINES: Low set stage (Stage-I) may be set in the range of 106% - 109%
(typically 108%) with a time delay of 5 seconds. High set stage (Stage-II) may be set
in the range 140% - 150% with a time delay of 100milliseconds.
However, for over voltage Stage-I protection, a time grading of 1 to 3 seconds may
be provided between overvoltage relays of double circuit lines. Grading on
overvoltage tripping for various lines emanating from a station may be considered
and same can be achieved using voltage as well as time grading. Longest timed
delay should be checked with expected operating time of Over-fluxing relay of the
transformer to ensure disconnection of line before tripping of transformer.
It is desirable to have Drop-off to pick-up ratio of overvoltage relay better than 97%
(Considering limitation of various manufacturers relay on this aspect).
14. LINE DIFFERENTIAL PROTECTION
Many transmission lines are now having OPGW or separate optic fibre laid for the
communication. Where ever such facilities are available, it is recommended to have
the line differential protection as Main-I protection with distance protection as
backup (built-in Main relay or standalone). Main-II protection shall continue to be
distance protection. For cables and composite lines, line differential protection with
built in distance back up shall be applied as Main-I protection and distance relay as
Main-II protection. Auto-recloser shall be blocked for faults in the cables.
15. MAINTAINING OPERATION OF POWER STATION AUXILIARY SYSTEM OF
NUCLEAR POWER PLANTS:
Depression of power supply voltages for auxiliary plant in some generating stations
may reduce the station output. Maintenance of full generation output may be a

TRANSMISSION LINES
Page 14 of 19
critical power system security factor. In the case of nuclear plant, auxiliary power
supplies are also a major factor in providing full nuclear plant safety and security.
The potential loss of system generation or the potential challenges to nuclear plant
safety systems may be factors which will dictate the longest acceptable clearance
times for transmission circuit faults in the vicinity of a power station. This should be
further taken up with utilities of nuclear plants and this and any other requirements
should be understood and addressed.
16. COORDINATION BETWEEN SYSTEM STUDY GROUP AND PROTECTION
ENGINEERS
For quite a few cases where system behaviour issues are involved it is
recommended that power system study group is associated with the protection
engineers. For example power swing locus, out of step tripping locations, faults
withstands capability, zone2 and zone3 overlap reach settings calculations are areas
where system study group role is critical/essential.
B. SERIES COMPENSATED TRANSMISSION LINES:
Following phenomenon associated with the protection of Series compensated lines
require special attention:
1) VOLTAGE AND CURRENT INVERSION
1.1. Voltage inversion on Series Compensated line:
In this case the voltage at the relay point reverses its direction. This
phenomenon is commonly called as voltage inversion. Voltage inversion causes
false decision in conventional directional relays. Special measures must be
taken in the distance relays to guard against this phenomenon.
1.2. Current inversion on Series Compensated line:
Fault current will lead source voltage by 90 degrees if XC XS +XL1
Current inversion causes a false directional decision of distance relays (voltage

TRANSMISSION LINES
Page 15 of 19
memories do not help in this case). [Here XC is reactance of series capacitor, XS
is source reactance and XL1 is reactance of the line]
Current inversion influences operation of distance relays and therefore they
cannot be applied without additional logic for the protection of series
compensated lines when possibility of current inversion exists. Performance of
directional comparison protections, based on residual (zero sequence) and
negative sequence currents are also affected by current inversion. It is therefore,
recommended to check the possibility of current inversion through system studies at the
planning stage itself.
2) LOW FREQUENCY TRANSIENTS
Series capacitors introduce oscillations in currents and voltages in the power
systems, which are not common in non-compensated systems. These oscillations
have frequencies lower than the rated system frequency and may cause delayed
increase of fault currents, delayed operation of spark gaps as well as delayed
operation of protective relays.
Low frequency transients have in general no significant influence on operation of
line current differential protection as well as on phase comparison protection.
However they may significantly influence the correct operation of distance
protection in two ways:
-They increase the operating time of distance protection, which may in turn
influence negatively the system stability
-They may cause overreaching of instantaneous distance protection zones
and this way result in unnecessary tripping on series compensated lines.
It is recommended to reduce the reach setting by a safety factor (Ks) to take care of
possible overreach due to low frequency oscillations.
3) MOV INFLUENCE AND APPARENT IMPEDANCE
Metal oxide varistors (MOV) are used for capacitor over-voltage protection. In
contrast to spark gaps, MOVs carry current when the instantaneous voltage drop

TRANSMISSION LINES
Page 16 of 19
across the capacitor becomes higher than the protective voltage level in each half-
cycle. Extensive studies have been done by Bonneville Power Administration in
USA to arrive at a non-linear equivalent circuit for a series connected capacitor
using an MOV. The composite impedance depends on total fault current and
protection factor kp.
The later is defined by equation.
MOV
p
NC
U
k
U
=
Where UMOV is voltage at which MOV starts to conduct theoretically and UNC is
voltage across the series capacitor when carrying its rated nominal current
This should be considered while relay setting.
4) IMPACT OF SC ON PROTECTIVE RELAYS OF ADJACENT LINES
Voltage inversion is not limited only to the buses and to the relay points close to the
series compensated line. It can spread deep into the network and this way influence
the selection of protection devices (mostly distance relays) at remote ends of the
lines adjacent to the series compensated circuit, and sometimes even deeper in the
network. Estimation of their influence on performances of existing distance relays of
adjacent lines must be studied. In the study, it is necessary to consider cases with
higher fault resistances, for which spark gaps or MOVs on series capacitors will not
conduct at all.
If voltage inversion is found to occur, it may be necessary to replace the existing
distance relays in those lines with distance relays that are designed to guard against
this phenomenon.
5) MULTI CIRCUIT LINES
Two parallel power lines both series compensated running close to each other and
ending at the same busbar at both ends) can cause some additional challenges for
distance protection due to the zero sequence mutual impedance. The current

TRANSMISSION LINES
Page 17 of 19
reversal phenomenon can also raise problems from the protection point of view,
particularly when the power lines are relatively short and when permissive
overreach schemes are used.
Influence of zero sequence mutual impedance
Zero sequence mutual impedance ZM0 will not significantly influence the operation
of distance protection as long as both circuits are operating in parallel and all
precautions related to settings of distance protection on series compensated line
have been considered. Influence of parallel line switched off earthed at both ends,
on the operation of distance protection on single operating circuit is well known.
The presence of series capacitor additionally exaggerates the effect of zero sequence
mutual impedance between two circuits. The effect of zero sequence mutual
impedance on possible overreaching of distance relays is increased further compared
to case of non-compensated lines. This is because while the series capacitor will
compensate self-impedance of the zero sequence network the mutual impedance
will be same as in the case of non-compensated double circuit lines. The reach of
under reaching distance protection zone 1 for phase to earth measuring loops must
further be reduced for such operating conditions.
Zero sequence mutual impedance may also disturb the correct operation of distance
protection for external evolving faults during auto reclosing, when one circuit is
disconnected in one phase and runs in parallel during dead time of single pole auto
reclosing cycle. It is recommended to study all such operating conditions by dynamic
simulations in order to fine tune settings of distance relays.
6) DIRECTIONAL RESIDUAL OVERCURRENT PROTECTION
All basic application considerations, characteristic for directional residual over-
current protection on normal power lines apply also to series compensated lines
with following additions. Low fault currents are characteristic of high resistive
faults. This means that the fault currents may not be enough to cause voltage drops
on series capacitors that would be sufficient to start their over-voltage protection.

TRANSMISSION LINES
Page 18 of 19
Spark gaps may not flash over in most cases, and metal oxide varistors (MOVs) may
not conduct any significant current. Series capacitors may remain fully inserted
during high resistive earth faults.
Local end directional residual OC protection:
The directional relay operates always correctly for reverse faults. VT located
between bus and capacitor generally does not influence directional measurement.
But in case VT is located between line and capacitor it may influence correct
operation: While reverse faults are detected correctly the forward operation is
dependent on system conditions. Additional zero sequence source impedance can be
added into relay circuits to secure correct directional measurement.
Remote end directional residual OC protection:
In this case the current can be reduced to extremely low values due to low zero
sequence impedance at capacitor end. Further the measured residual voltage can be
reduced to very low value due to low zero sequence source impedance and/or low
zero sequence current. Zero sequence current inversion may occur at the capacitor
end (dependent on fault position). Directional negative sequence OC protection too
may face very similar conditions.
Adaptive application of both the above OC protection principles can be considered
wherever required to get the desired result.
7) DISTANCE PROTECTION SETTINGS GUIDELINES
Basic criteria applied for Z1 Z2 reach settings are :
• Zone-1 should never overreach for the fault at remote bus
• Zone-2 should never under reach for fault on protected line
• Permissive overreach (POR) schemes are usually applied
Distance protection Zone 1 shall be set to

TRANSMISSION LINES
Page 19 of 19
Zone-1 is set usually at 80% of Ks x ( )
1 11 12
Z S C
X K X X X
= ⋅ + − Where X11 is
reactance between CT and capacitor and X12 is reactance between capacitor and
remote end Bus, Xc is reactance of capacitor and KS is safety factor to prevent
possible overreaching due to low frequency (sub-harmonic) oscillations. These
setting guidelines are applicable when VT is installed on the bus side of the
capacitor . It is possible to remove XC from the above equation in case VT is installed
on line side , but it is still necessary to consider the safety factor.
Alternatively, Zone-1 is set at 80% of line impedance with a time delay of
100millisecond. POR Communication scheme logic is modified such that relay
trips instantaneously in Zone-1 on carrier receive. ( For remote end relay of
the line looking into series capacitor)
Zone-2 is set to 120 % of uncompensated line impedance for single circuit line.
For double circuit lines, special considerations are mentioned at Section B-5
above.
Phase locked voltage memory is used to cope with the voltage inversion.
Alternatively, an intentional time delay may be applied to overcome
directionality problems related to voltage inversion.
Special consideration may be required in over voltage stage-I (low set) trip
setting for series compensated double circuit lines. It has been experienced
that in case of tripping of a heavily loaded circuit, other circuit experience
sudden voltage rise due to load transfer. To prevent tripping of other circuit
on such cases, over-voltage stage-I setting for series compensated double
circuit lines may be kept higher at 113%.
8) SIMULATION STUDIES
System studies, Use of real Time digital simulators, Tests using EMTP files are very
important when applying protections for series compensated lines. It is recommended
to carry out such studies specific to each line.

PROTECTION SYSTEM MANAGEMENT
Page 1 of 5
Table of Contents
RECOMMENDATIONS FOR PROTECTION SYSTEM MANAGEMENT: ................................2
1. ESTABLISHING PROTECTION APPLICATION DEPARTMENT:.................................2
2. RELAY SETTING CALCULATIONS....................................................................................2
3. COORDINATION WITH SYSTEM STUDY GROUP, SYSTEM PLANNING GROUP
AND OTHER STAKEHOLDERS...................................................................................................3
4. SIMULATION TESTING FOR CHECKING DEPENDABILITY AND SECURITY OF
PROTECTION SYSTEM FOR CRITICAL LINES AND SERIES COMPENSATED LINES...3
5. ADOPTION OF RELAY SETTING AND FUNCTIONAL VERIFICATION OF
SETTING AT SITE ...........................................................................................................................4
6. STORAGE AND MANAGEMENT OF RELAY SETTINGS ..............................................4
7. ROOT CAUSE ANALYSIS OF MAJOR PROTECTION TRIPPING (MULTIPLE
ELEMENT OUTAGE) ALONGWITH CORRECTIVE IMPROVEMENT MEASURES .....4
8. PERFORMANCE INDICES: DEPENDABILITY SECURITY OF PROTECTION
SYSTEM.............................................................................................................................................5
9. PERIODIC PROTECTION AUDIT........................................................................................5
10. REGULAR TRAINING AND CERTIFICATION.............................................................5

Page 2 of 5
RECOMMENDATIONS FOR PROTECTION SYSTEM MANAGEMENT:
During the discussions and interactions with the various stake holders of the
protection system, it was strongly felt by the protection sub-committee members
that in addition to technical issues related to protection, the management issues
related to protection system need to be addressed. A questionnaire related to
applicable protection setting coordination philosophy was sent to all utilities
through RPC. Responses were received only from few utilities. These responses
show that there is no uniformity in the protection philosophy followed by different
utilities throughout the country. Further, lack of response from most of the utilities
also indicates the lack of resources on their part to handle the protection system. In
order to comprehensively address the protection issues in the utilities, following are
the recommendations.
1. ESTABLISHING PROTECTION APPLICATION DEPARTMENT:
1.1. It is recommended that each utility establishes a protection application
department with adequate manpower and skill set.
1.2. The protection system skill set is gained with experience, resolving
various practical problems, case studies, close interaction with the relay
manufactures and field engineers. Therefore it is proposed that such
people should be nurtured to have a long standing career growth in the
protection application department.
2. RELAY SETTING CALCULATIONS
2.1. The protection group should do periodic relay setting calculations as and
when necessitated by system configuration changes. A relay setting
approval system should be in place.
2.2. Relay setting calculations also need to be revisited whenever the minor
configuration or loading changes in the system due to operational
constraints. Feedback from the field/substations on the performance of

Page 3 of 5
the relay settings should be collected and settings should be reviewed
and corrected if required.
3. COORDINATION WITH SYSTEM STUDY GROUP, SYSTEM
PLANNING GROUP AND OTHER STAKEHOLDERS
3.1. It is recommended that each utility has a strong system study group with
adequate manpower and skill set that can carry out various system
studies required for arriving at system related settings in protection
system in addition to others studies.
3.2. The protection application department should closely work in co-
ordination with the utility system study group, system planning group,
the system operation group.
3.3. Wherever applicable, it should also co-ordinate and work with all power
utilities to arrive at the proper relay setting calculations taking the system
as a whole.
3.4. The interface point relay setting calculations at CTU-STU, STU-
DISCOMS, STU-GEN Companies, CTU-GEN Companies and also
generator backup relay setting calculations related to system performance
should be periodically reviewed and jointly concurrence should be
arrived. The approved relay settings should be properly document.
3.5. Any un-resolved issues among the stakeholders should be taken up with
the RPC and resolved.
4. SIMULATION TESTING FOR CHECKING DEPENDABILITY AND
SECURITY OF PROTECTION SYSTEM FOR CRITICAL LINES
AND SERIES COMPENSATED LINES
4.1. Committee felt that even though Real Time Digital Simulation (RTDS) and
other simulation facilities are available in the country, use of the same by
the protection group is very minimum or nil.
4.2. It is recommended that protection system for critical lines, all series
compensated lines along with interconnected lines should be simulated
for intended operation under normal and abnormal system conditions

Page 4 of 5
and tested for the dependability and security of protection system. The
RTDS facilities available in the country like at CPRI, POWERGRID and
other places should be made use of for this purpose.
4.3. The network model should be periodically updated with the system
parameters, as and when network changes are incorporated.
5. ADOPTION OF RELAY SETTING AND FUNCTIONAL
VERIFICATION OF SETTING AT SITE
5.1. Protection application department shall ensure through field testing
group that the final relay settings are exactly adopted in the relays at field.
5.2. There should be clear template for the setting adoption duly authorized
and approved by the field testing in charge.
5.3. No relay setting in the field shall be changed without proper
documentation and approval by the protection application department.
5.4. Protection application department shall periodically verify the
implemented setting at site through an audit process.
6. STORAGE AND MANAGEMENT OF RELAY SETTINGS
6.1. The committee felt that with the application of numerical relays, increased
system size volume of relay setting, associated data to be handled is
enormous. It is recommended that utilities shall evolve proper storage and
management mechanism (version control) for relay settings.
6.2. Along with the relay setting data, IED configuration file should also be
stored and managed.
7. ROOT CAUSE ANALYSIS OF MAJOR PROTECTION TRIPPING
(MULTIPLE ELEMENT OUTAGE) ALONGWITH CORRECTIVE
IMPROVEMENT MEASURES
7.1. The routine trippings are generally analysed by the field protection
personnel. For every tripping, a trip report along with associated DR and
event logger file shall be generated. However, for major tripping in the
system, it is recommended that the protection application department
shall perform the root cause analysis of the event.

Page 5 of 5
7.2. The root cause analysis shall address the cause of fault, any mal-operation
or non-operation of relays, protection scheme etc.
7.3. The root cause analysis shall identify corrective and improvement
measures required in the relay setting, protection scheme or any other
changes to ensure the system security, reliability and dependability of the
protection system.
7.4. Protection application group shall keep proper records of corrective and
improvement actions taken.
8. PERFORMANCE INDICES: DEPENDABILITY SECURITY OF
PROTECTION SYSTEM
8.1. The committee felt that key performance indices should be calculated on
yearly basis on the dependability and security of protection system as
brought out in CBIP manual.
9. PERIODIC PROTECTION AUDIT
9.1. Periodic audit of the protection system shall be ensured by the protection
application team.
9.2. The audit shall broadly cover the three important aspect of protection
system, namely the philosophy, the setting, the healthiness of Fault
Clearing System.
10.REGULAR TRAINING AND CERTIFICATION
10.1.The members of the protection application team shall undergo regular
training to enhance update their skill sets.
10.2. The training modules shall consist of system studies, relaying
applications, testing commissioning
10.3. Certification of protection system field engineer for the testing
commissioning of relay, protection scheme is strongly recommended.

CHECK LIST FOR AUDIT OF FAULT CLEARANCE SYSTEM FOR
765kV, 400kV 220kV SUBSTATIONS
Page 1 of 16
Introduction:
This check list is prepared by the Protection sub-committee under task force to
enable audit of practices followed in protection application criteria used for
setting calculations in 220kV, 400kV 765kV substations. It aims to cover the
entire fault clearance system used for overhead lines cables, power
transformers, shunt reactors and bus bars in a substation. The objective is to
check if the fault clearance system provided gives reliable fault clearance.
The check list is generally based on the guidelines given in the following
documents:
• CBIP Publication no 274: Manual on Protection of Generators, Generator
Transformers and 220kV and 400kV Networks
• CBIP Publication no 296: Manual on Reliable Fault Clearance and Back-Up
Protection of EHV and UHV Transmission Networks
• CIGRE WG B5.10, 411: Protection, Control and Monitoring Of Series
Compensated Networks

Page 2 of 16
CHECK-LIST:
Check list for different protected objects elements in fault clearance system are as
under:
(put √ mark in the appropriate box )
A. Transmission Lines (OHL and Cables)
1. Independent Main-I and Main-II protection (of different make OR
different type) is provided with carrier aided scheme
YES NO
2. Are the Main-I Main-II relays connected to two separate DC
sources (Group-A and Group-B)
YES NO
3. Is the Distance protection (Non-switched type, suitable for 1-ph 3-
ph tripping) as Main1 and Main2 provided to ensure selectivity
reliability for all faults in the shortest possible time
YES NO
4. Is both main-I Main-II distance relay are numerical design having
Quadrilateral or Polygon operating characteristic
YES NO
5. In the Main-I / Main-II Distance protection, Zone-I is set cover 80%
of the protected line section
YES NO
6. In the Main-I / Main-II distance protection, Zone-2 is set cover 120%
of the protected line section in case of Single circuit line and 150% in
case of Double circuit line
YES NO
7. In the Main-I / Main-II distance protection, Zone-3 is set cover 120%
of the total of protected line section plus longest line at remote end as
a minimum.
YES NO

Page 3 of 16
8. Resistive reach for Ground fault element set to give maximum
coverage considering fault resistance, arc resistance tower
footing resistance. ( In case, It is not possible to set the ground
fault and phase fault reaches separately, load point
encroachment condition imposed on Phase fault resistive reach
shall be applied)
YES NO
9. Resistive reach for Phase fault element set to give maximum
coverage subject to check of possibility against load point
encroachment considering minimum expected voltage and
maximum load.
YES NO
10. In case of short lines, is manufacturers recommendation considered
in respect of resistive setting vis a vis reactance setting to avoid
overreach.
YES NO
11 Is Zone-2 time delay of Main-I / Main-II distance relay set to 0.350
seconds ?
In case any other value has been set for Zone-II timer, kindly specify
the value and justification thereof.
YES NO
12 Is Zone-3 timer is set to provide discrimination with the operating
time of relays at adjacent sections with which Zone-3 reach of relay is
set to overlap.
Please specify the Zone-3 time set.
YES NO
13. Is Zone-4 reach set in reverse direction to cover expected levels of
apparent bus bar fault resistance, when allowing for multiple in
feeds from other circuits?
YES NO
14. Is reverse looking Zone-4 time delay set as Zone-2 time delay? YES NO
15. Is Switch on to fault (SOTF) function provided in distance relay to
take care of line energisation on fault?
Whether SOTF initiation has been implemented using hardwire logic
YES NO
YES NO

Page 4 of 16
In case of Breaker and half switching scheme, whether initiation of
line SOTF from CB closing has been interlocked with the other CB
YES NO
16. Whether VT fuse fail detection function has been correctly set to
block the distance function operation on VT fuse failure
YES NO
17. Is the sensitive IDMT directional E/F relay (either separate relay or
built-in function of Main relay) for protection against high resistive
earth faults?
YES NO
18. Is additional element (Back-up distance) for remote back-up
protection function provided in case of unit protection is used as
Main relay for lines?
YES NO
19. In case of Cables, is unit protection provided as Main-I Main-II
protection with distance as back-up.
YES NO
20. Are the line parameters used for setting the relay verified by field
testing
YES NO
21. Is Two stages Over-Voltage protection provided for 765 400kV
Lines?
Do you apply grading in over-voltage setting for lines at one station.
Please specify the setting values adopted for:
Stage-I : (typical value - 106 to 112 % , delay : 4-7 Sec)
Stage-II: (typical value - 140 to 150%, delay: 0 to 100msec.)
YES NO
YES NO
22. Is 1-ph Auto –reclosing provided on 765, 400 220kV lines? Please
specify the set value:
Dead time: (typical 1 Sec)
Reclaim time: (typical 25 Sec)
YES NO

Page 5 of 16
23. Is the Distance communication. Scheme Permissive Over Reach
(POR) applied for short lines and Permissive Under Reach (PUR)
applied for long lines?
If any other communication scheme has been applied, please provide
the detail with justification thereof.
YES NO
24. Is the Current reversal guard logic for POR scheme provided on
Double circuit lines?
YES NO
25. In case the protected line is getting terminated at a station having
very low fault level i.e. HVDC terminal, whether week end-infeed
feature has been enabled in respective distance relay or not
YES NO
26. In case of protected line is originating from nuclear power station,
are the special requirement (stability of nuclear plant auxiliaries) as
required by them has been met
YES NO
27. What line current , Voltage and Load angle have been considered for
Load encroachment blinder setting and what is the resultant MVA
that the line can carry without load encroachment.
(In the absence of Load encroachment blinder function, this limit
shall be applied to Zone-3 phase fault resistive reach.)
I=
V=
Angle:
S=
28. a) What are the Zones blocked on Power swing block function:
b) Setting for Unblock timer: (typical 02 second)
c) Out of Step trip enabled
Z1 / Z2 / Z3 / Z4
Time:
YES NO
29. Whether the location of Out of step relay has been identified on the
basis of power system simulation studies
YES NO
30. a) Is the Disturbance recorder and Fault locator provided on all line
feeder ?
b) Whether standalone or built in Main relay
c) Whether DR is having automatic fault record download facility to
a central PC
d) Whether DR is time synchronised with the GPS based time
YES NO
Standalone / built-
in
YES NO

Page 6 of 16
synchronising equipment
e) Whether DR analog channels contain line phase neutral current
and line phase neutral voltage.
f) Whether DR digital channel as a minimum contain the CB status,
Main-I II trip status, LBB trip status, Over-voltage trip status,
Stub protn trip status, Permissive and direct carrier receive status,
Line reactor trip status.
YES NO
YES NO
YES NO
B. Power Transformers
1. Do you use Group A and Group B protections connected to separate
DC sources for power transformers
YES NO
2. Do you follow CBIP guideline (274 296) for protection setting of
transformer
YES NO
3. Do you use duplicated PRD and Bucholtz initiating contact for power
transformers at 765kV and 400kV levels
YES NO
4. Do you classify transformer protections as below in groups:
Group A Group B
• Biased differential relay Restricted earth fault (REF) relay
• PRD , WTI Buchholz Protection, OTI
• Back up Protection(HV) Back up Protection(MV)
• Overfluxing protection(HV) Overfluxing protection(MV)
YES NO
5. In case of Breaker half switching scheme, whether CT associated
with Main Tie Breakers are connected to separate bias winding of
the low impedance Biased differential protection in order to avoid
false operation due to dissimilar CT response.
YES NO
6. Is Restricted earth fault (REF) protection used a high impedance type YES NO

Page 7 of 16
7. Are Main protection relays provided for transformer are of numerical
design.
YES NO
8. a) Are directional over current earth fault relays provided as
back-up protection of Transformer are of numerical design.
b) Do the back-up earth fault relays have harmonic restrain feature
YES NO
YES NO
9. Is Fire protection system (HVW type) provided for power
transformer and functioning
YES NO
10. a) Is the Disturbance recorder provided for Transformer feeder
a central PC
d) Whether DR is time synchronised with the GPS time
synchronising equipment
YES NO
Standalone/built-in
YES NO
YES NO
C. Shunt Reactors
1. Do you use Group A and Group B protections connected to separate
DC sources for reactors
YES NO
2. Do you follow CBIP guideline (274 and 296) for protection setting of
reactors
YES NO
3. Do you use duplicated PRD and Bucholtz initiating contact for
Reactors at 765kV and 400kV levels
YES NO
4. Do you classify Reactor protections as below in groups:
Group A Group B
• Biased differential relay R.E.F Protection
YES NO

Page 8 of 16
• PRD , WTI Buchholz Protection, OTI
• Back up impedance Protection Or Direction O/C E/F relay
5 In case of Breaker half switching scheme, whether CT associated with
Main Tie Breakers are connected to separate bias winding of the low
impedance Biased differential protection in order to avoid false
operation due to dissimilar CT response.
YES NO
6 Is Restricted earth fault (REF) protection used a high impedance type YES NO
7 Are Main back-up protection relays provided for Reactor are of
numerical design.
YES NO
8 Is Fire protection system (HVW type) provided for Reactor and
functioning
YES NO
9 a) Is the Disturbance recorder and Fault locator provided on all the
Shunt Reactors used in 765 kV, 400 kV substations?
c) Whether DR is having automatic fault record download facility to a
central PC
YES NO
Standalone/built-
in
YES NO
D. Bus bars
1. Bus Bar protection for 765, 400 220kV buses is provided YES NO
2. Duplicated Bus bar protection is provided for 765kV and 400kV
buses
YES NO
3. CBIP guideline for Protection (274 and 296) settings is followed YES NO

Page 9 of 16
4 In an existing substation if CTs are of different ratios, is biased type
bus protection provided.
YES NO
5 In stations where single bus bar protection is provided, is backup
provided by reverse looking elements of distance relays or by second
zone elements of remote end distance relays?
YES NO
6 In case of GIS where burn through time of SF6 is shorter than remote
back up protection is the bus bar protection duplicated irrespective of
voltage level?
YES NO
7 Since it is difficult to get shutdowns to allow periodic testing of bus
protection, numerical bus protections with self-supervision feature is
an answer. Is this followed?
YES NO
E. Disturbance Recorder (DR) and Event Logger (EL)
1 a) Is the Disturbance recorder and Fault locator provided on all line
feeder of 765, 400 220kV substations?
a central PC
d) Whether Central PC for DR , EL are powered by Inverter (fed
from station DC)
YES NO
Standalone / built-
in
YES NO
YES NO
2. Whether DR is having the following main signals for lines:
Analogue signals:
• From CT: IA, IB, IC, IN
• From VT: VAN, VBN, VCN
• From Aux. VT: V0
Digital Signals
• Main 1 Carrier receive
YES NO

Page 10 of 16
• Main 1 Trip
• Line O/V Stage I / Stage II
• Reactor Fault Trip
• Stub Protection Operated.
• Main II Trip
• Main II Carrier Receive
• Direct Trip CH I / II
• CB I Status (PH-R, Y B)
• CB II Status (PH R, Y B)
• Bus bar trip
• Main / Tie CB LBB Operated
• Main / Tie Auto-reclose operated.
DR for Transformer / Reactor feeder should contain analog channel
like input currents voltage. Binary signal include all protection trip
input, Main Tie CB status, LBB trip
3. Whether substation (765, 400 , 220kV) is having Event logger facility
(standalone or built-in-SAS)
YES NO
4. Whether GPS based time synchronizing equipment is provided at the
substation for time synchronizing of Main relays / DR/ Event logger
/ SAS/ PMU / Line Current Differential Relays
YES NO

Page 11 of 16
F. Circuit Breakers
1. Is breaker fail protection ( LBB / BFR) provided for all the Circuit
Breakers at 220kV , 400kV 765kV rating
YES NO
3. For Circuit Breaker connected to line feeder / transformer feeder,
whether operation of LBB / BFR sends direct trip signal to trip
remote end breaker ?
YES NO
4. For lines employing single phase auto reclosing, Is start signal from
protection trip to LBB / BFR relay is given on single phase basis?
YES NO
5. Is separate relay provided for each breaker and the relay has to be
connected from the secondary circuit of the CTs associated with that
particular breaker?
YES NO
6. Is LBB relay provided with separate DC circuit independent from
Group-A and Group-B Protections?
YES NO
7. Is the LBB initiation provided with initiating contact independent of
CB trip relay contact?
YES NO
8. Is Separation maintained between protective relay and CB trip coil
DC circuit so that short circuit or blown fuse in the CB circuit will not
prevent the protective relay from energizing the LBB scheme?
YES NO
9. Is LBB relay initiated by Bus bar protection in addition to other fault
sensing relays, since failure of CB to clear a bus fault would result in
the loss of entire station if BFP relay is not initiated?
YES NO
10. Is tripping logic of the bus bar protection scheme used for LBB
protection also?
YES NO
11. Are the special considerations provided to ensure proper scheme
operation by using Circuit Breaker contact logic in addition to
current detectors in cases breaker-fail relaying for low energy faults
like buchholz operation?
YES NO

Page 12 of 16
12. Are the Current level detectors set as sensitive as the main
protection? (Generally setting of 0.2 A is commonly practiced for
lines and transformers)
YES NO
13. Is timer set considering breaker interrupting time, current detector
reset time and a margin? (Generally a timer setting of 200ms has been
found to be adequate)
YES NO
14. Is the back-up fault clearance time is shorter than the operating time
of the remote protections (distance relay Zone-2) ?
YES NO
15. Is the breaker failure protection provided with two steps ( First stage
– retrip own CB, Second stage- Trip all associated CBs) . This
mitigates unwanted operation of breaker failure protection during
maintenance and fault tracing.
YES NO
16. Is the breaker failure protection hardware provided is separate from
line /transformer feeder protection?
YES NO
G. Communication systems
1. a) Do you use PLCC for tele-protection of distance relays at 765, 400
220kV feeders
b) Specify type of coupling
c) Whether redundant PLCC channels provided for 400 765kV
lines
d) Specify number of PLCC channels per circuit :
e) Whether dependability security of each tele-protection channel
measured record kept ?
YES NO
( Ph-Ph / Ph-G/
Inter-circuit)
YES NO
( One / two)
YES NO
2. a) In case you use OPGW for tele-protection, are they on
geographically diversified route for Main-I and Main-II relay?
b) Whether dedicated fibre is being used for Main-I / Main-II relay
or multiplexed channel are being used.
YES NO
Dedicated /
multiplexed

Page 13 of 16
H. Station DC supply systems
1. Do you have two separate independent DC system (220V or 110V)
(Source-A and Source-B)
YES NO
2. Do you have two independent DC system (48V) for PLCC
(source-A and source-B)
YES NO
3. There is no mixing of supplies from DC source-A and DC source-B YES NO
4. Whether the protection relays and trip circuits are segregated into
two independent system fed through fuses from two different DC
source
YES NO
5. Whether Bay wise distribution of DC supply done in the following
way:
a) Protection
b) CB functions
c) Isolator / earth switch functions
d) Annunciation / Indications
e) Monitoring functions
YES NO
6 Whether following has been ensured in the cabling:
a) Separate cables are used for AC DC circuits
b) Separate cables are used for DC-I DC-II circuits
c) Separate cables are used for different cores of CT and CVT
outputs to enhance reliability security
YES NO
7 Is guidelines prescribed in CBIP manual 274 296 followed in
general
YES NO

Page 14 of 16
E. PERFORMANCE INDICES
1. Is there a system of periodically measuring Dependability
Security of Protection system (as given in CBIP manual 296)
and recorded
YES NO
2. Is there a system of periodically measuring Dependability of
switchgear associated with Protection system and recorded
YES NO
3. Is there a process of Root cause analysis of unwanted tripping
events
YES NO
4. Are improvement action like revision of relay setting, better
maintenance practices, modernising retrofitting of switching
protection system taken based on above data.
YES NO
5. Is attention also given to DC supply system, tele-protection
signalling, healthiness of tripping cables, terminations etc. in
order to improve the performance of fault clearance system
YES NO

Page 15 of 16
F. ADDITIONAL CHECKS FOR SERIES COMPENSATED LINES
1. What is the operating principle of Main protection
employed
Distance
Line Current
differential
2. Are both main-I Main-II distance relay are numerical design YES NO
3. Are both main-I Main-II distance relay suitable for Series
compensated lines
YES NO
4. Are POR tele-protection scheme employed for distance relays YES NO
5. Position of Line VT provided on series compensated line Between Capacitor
and line
Between Capacitor
and Bus
6. What is the under reaching (Zone 1) setting used in
teleprotection schemes (Local Remote end)
% of line length
Rationale:
7. What is the overreaching (Zone 2) setting in used teleprotection
schemes
% of line length
Rationale:
8. What kinds of measurement techniques are used to cope with
voltage inversion?
Phase locked voltage
memory
Intentional time delay
Other, specify:
9. Whether system studies carried out to check the possibility of
current inversion due to series compensation
YES NO
10. Whether any system studies conducted to find the impact of YES NO

Page 16 of 16
series compensation on the performance of protections installed
on adjacent lines? If yes, how many lines were found to be
affected. Pl. specify ________________
11 If YES, are the affected protections on adjacent lines changed /
setting revised after the introduction of series compensation?
YES NO
12. Is dynamic simulation done to fine tune settings of distance relay
installed on series compensated double circuit lines?
YES NO
13. Whether performance of directional earth fault relay verifies by
simulation studies
YES NO
14. When is flashover of spark gaps expected? For protected line
Faults up to ohms
For external faults an
adjacent lines
15. Whether measures taken for under/overreach problems at sub-
harmonic oscillations?
YES NO
16. Whether MOV influence considered while setting the distance
relay reach
YES NO
17. Have you experienced any security problems (Relay mal-
operation) with high frequency transients caused by
Flashover of spark gaps
Line energisation
Other, specify:
YES NO
18. If YES, how the above problem has been addressed? __________________

DETAILS OF PROTECTION AUDIT
A.
General
Information:
1 Name of Sub-
station 2 Date of first commissioning
3 Type of Bus
Switching Scheme: 4 Whether SLD collected or Not:
5 Audit Team:
1.
2.
3.
1)
Instrument
Transformer ( To be filled for each one of them)
A
Current
transformer (C T)
1 Location of CT
a
Date of CT ratio
Test Testing
b
Core I Core II Core III Core IV Core V Core VI
i Ratio Adopted
ii Ratio measured
iii error calculated
Knee point voltage
B Capacitive voltage transformer (C V T)
1 Location of CVT
a Date of Testing
b CVT ratio Test
Core I Core II Core III
i Ratio Adopted
ii Ratio measured
2 Location of CVT
a Date of Testing
b CVT ratio Test
Core I Core II Core III
i Ratio Adopted

ii Ratio measured
2) Availability of Protection System
A) Bus Bar relay
765kV 400kV 220kV
i) Make and Model
of Bus Bar relay
ii) Whether stability
checks done or not
iii) Date of testing
iv) Remarks (if any)
C) Sub-station protection and monitoring Equipments
System
LBB
(Make Model)
Functional
(Yes / No)
Date of last
testing
Event
Logger
(Make
Model)
Functional
(Yes / No)
Synchonising
Facility
Available or
not
Synchro Check
Relay (Make and
Model)
Setting of
Synhrocheck
Relay
i) 765kV System
II) 400kV System
III) 220kV System
D.
Transmission Line
Protection
Name of Line
Main-I
Protection
(Make and
Model)
Functional
(Yes / No)
Date of
testing
Main-II
Protection
(Make and
Model)
Functional
(Yes / No)
Date of
testing
LBB Protection
(Make and Model)
Functional
(Yes / No)
Date of
testing
PLCC/Pro
tection
coupler
(Make
and
Model)
Functional
(Yes / No)
DR
(Make
Model)
Functional
(Yes / No)
Time
Synch. Unit
(Make
Model)
OK
/ Not
OK
i) Line-1
ii) Line-2
iii) Line-3
iv) Line-4
v) Line-5
vi) Line-6
E) Transformer Protection

Name of ICT
Differential
Protection
(Make Model)
REF
Protection
(Make
Model)
Back-up
Over Current
Protection
(Make
Model)
Over Flux
Protection
(Make
Model)
OTI/WTI
Indication
working or
not
Bucholtz
/
PRD
Other protection
Date of last
testing
LA
Rating
HV Side
LA Rating
IV Side
i) ICT-1
ii) ICT-2
iii) ICT-3
iv) ICT-4
F) Reactor Protection
Name of Reactor
Differential
Protection
(Make Model)
REF
Protection
(Make
Model)
Back-up
Impedance
Protection
(Make
Model)
OTI/WTI
Indication
working or
not
Bucholtz
/ PRD
Other prot’n Date of testing
LA Rating HV
Side
i)
Line -1 Reactor
ii) Line -2 Reactor
iii) Bus Reactor-1
iv) Bus Reactor-2
3) Line Parameter
Line 1 Line 2 Line 3 Line 4 Line 5 Line 6
i) Name of Line
ii) Line Length
iii)
Line Parameters
( In Ohms/Per KM/Per Phase Primary
value)
R1
X1
Ro
Xo
RoM
XoM
iv)
Present Relay
setting
a
Adopted Relay
setting
Enclosed as Annexure -I ( Please enclose the settings for all lines, transformers, Reactors and
Bus Bars)
b Recommended Enclosed as Annexure -II ( Please enclose the settings for all lines, transformers, Reactors and

relay setting Bus Bars)
4) DC supply
220 /110 V DC-I 220 /110 V DC-II 48 V DC-I 48 V DC-II
a
Measured voltage
(to be measured at
furthereset Panel
i) Positive to Earth NA NA
ii) Negative to Earth
b
No.of Cells Per
Bank
c
Availability of
Battery Charger Yes/No Yes/No Yes/No Yes/No
5) Circuit Breaker
Make and Model Status of Breaker
Available or Not
No.of
trip/close coil
healthiness
PIR (Available
or Not)
Date of
Last Timing
taken
Remarks (If
any)
A. 765kV System
i). 765kV Bay-1
ii). 765kV Bay-2
iii). 765kV Bay-3
iv). 765kV Bay-4
v). 765kV Bay-5
vi). 765kV Bay-6
B. 400kV System
i). 400 KV Bay-1
ii). 400 Kv Bay-2
iii). 400 Kv Bay-3
iv). 400 Kv Bay-4
v). 400 Kv Bay-5
vi). 400 Kv Bay-6
vii). 400 Kv Bay-7
viii)
. 400 Kv Bay-8
ix). 400 Kv Bay-9
x). 400 Kv Bay-10
B 220kV System
i). 220kV Bay-1
ii). 220kV Bay-2
iii). 220kV Bay-3
iv). 220kV Bay-4
v). 220kV Bay-5

vi). 220kV Bay-6
vii). 220kV Bay-7
viii)
. 220kV Bay-8
Note: rows to be added / deleted as required for no. of bays
6)
Availability of
auxiliary System
i)
Auxiliary Supply Source of Supply Reliability of Supply
Average
tripping per
month
Supply-I
Supply-II
ii) DG Set
Make
Rating
Whether Dg set on
Auto or manual
Fuel level
7)
Availability of UFR
relay
Make
Setting
8)
Availability of
df/dt relay
Make
Setting
9)
Special Protection
Scheme (SPS)
Available (Yes/No)
Verification
10)
Status of Corrective action based on
Tripping analysis
11) Any Other Observation/ Comments

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