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
Station Name: Station-A
Object Name: 400kV OHL
Unit Name: REC670 (Ver 1.2)
Relay serial No: XXXXX
Frequency: 50Hz
Aux voltage: 220V DC
2.2.2 List of functions available and those used
Table 2-2 gives the list of functions/features available in REC670 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 2-2: List of functions in REC670
Sl.No. Functions/Feature available In REC670
Features/Functions
activated
Yes/No
Recommended
Settings
provided
1 Analog Inputs YES
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
8 Change Lock CHNGLCK NO
9 IED Identifiers YES
10 Product Information YES
11 Rated System Frequency PRIMVAL YES

17
Features/Functions
activated
Yes/No
Recommended
Settings
provided
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 Differential Protection HZPDIF NO
20
Instantaneous Phase Overcurrent Protection
PHPIOC
NO
21
Four Step Phase Overcurrent Protection
OC4PTOC
NO
22
Instantaneous Residual Overcurrent
Protection EFPIOC
NO
23
Four Step Residual Overcurrent Protection
EF4PTOC
NO
24
Four step directional negative phase
sequence overcurrent protection NS4PTOC
NO
25
Sensitive Directional Residual Overcurrent
And Power Protection SDEPSDE
NO
26
Thermal Overload Protection, One Time
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
39 Loss Of Voltage Check LOVPTUV 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
44 Current Circuit Supervision CCSRDIF 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
Horizontal Communication Via GOOSE For
Interlocking GOOSEINTLKRCV
NO

19
Features/Functions
activated
Yes/No
Recommended
Settings
provided
50
Logic Rotating Switch For Function
Selection And LHMI Presentation SLGGIO
NO
51 Selector Mini Switch VSGGIO NO
52
Generic Double Point Function Block
DPGGIO
NO
53
Single Point Generic Control 8 Signals
SPC8GGIO
NO
54
Automationbits, Command Function For
DNP3.0 AUTOBITS
NO
55 Single Command, 16 Signals SINGLECMD 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
59 Local Acceleration Logic ZCLCPLAL 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
67 Carrier Receive Logic LCCRPTRC NO
68
Negative Sequence Overvoltage Protection
LCNSPTOV
NO
69
Zero Sequence Overvoltage Protection
LCZSPTOV
NO
70
Negative Sequence Overcurrent Protection
LCNSPTOC
NO
71
Zero Sequence Overcurrent Protection
LCZSPTOC
NO
72 Three Phase Overcurrent LCP3PTOC NO
73 Three Phase Undercurrent LCP3PTUC NO
74 Tripping Logic SMPPTRC NO
75 Trip Matrix Logic TMAGGIO NO
76 Configurable Logic Blocks NO
77 Fixed Signal Function Block FXDSIGN NO
78 Boolean 16 To Integer Conversion B16I NO
79
Boolean 16 To Integer Conversion With
Logic Node
Representation B16IFCVI
NO
80 Integer To Boolean 16 Conversion IB16 NO
81
Integer To Boolean 16 Conversion With
Logic Node
Representation IB16FCVB
NO
82 Measurements CVMMXN YES
83 Phase Current Measurement CMMXU YES

21
Features/Functions
activated
Yes/No
Recommended
Settings
provided
84
Phase-Phase Voltage Measurement
VMMXU
YES
85
Current Sequence Component
Measurement CMSQI
YES
86 Voltage Sequence Measurement VMSQI YES
87
Phase-Neutral Voltage Measurement
VNMMXU
NO
88 Event Counter CNTGGIO YES
89 Event Function EVENT YES
90 Logical Signal Status Report BINSTATREP NO
91 Fault Locator LMBRFLO NO
92
Measured Value Expander Block
RANGE_XP
NO
93 Disturbance Report DRPRDRE YES
94 Event List YES
95 Indications YES
96 Event Recorder YES
97 Trip Value Recorder YES
98 Disturbance Recorder YES
99 Pulse-Counter Logic PCGGIO NO
100
Function For Energy Calculation And
Demand Handling ETPMMTR
NO
102
IEC 61850 Generic Communication I/O
Functions SPGGIO, SP16GGIO
NO
103
IEC 61850-8-1 Redundant Station Bus
Communication
NO

22
Features/Functions
activated
Yes/No
Recommended
Settings
provided
104 IEC 61850-9-2LE Communication Protocol NO
105 LON Communication Protocol NO
106 SPA Communication Protocol NO
108
Multiple Command And Transmit
MULTICMDRCV,
MULTICMDSND
NO
109 Remote Communication NO
Note: For setting parameters provided in the function listed above, refer section 3 of
application manual 1MRK511230-UEN, version 1.2.

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:
Ch 1 Ch 2 Ch 3 Ch 4 Ch 5 Ch 6
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 -
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
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
IBase Base current , i.e rated current 1000 A
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
Operation mode Off / On of Zone timer,
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 -
ModeOutput3 Mode for output 3, steady or pulsed Steady -

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