guidelines relay setting

8/11/2019 Guidelines Relay Setting

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MODEL SETTING CALCULATIONS FOR TYPICAL IEDs

LINE PROTECTION SETTING GUIDE LINES

PROTECTION SYSTEM AUDIT CHECK LIST

RECOMMENDATIONS FOR PROTECTION MANAGEMENT

SUB-COMMITTEE ON RELAY/PROTECTION UNDER TASK

FORCE FOR POWER SYSTEM ANALYSIS UNDER

CONTIGENCIES


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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.


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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, ABBVikas Saxena, Jindal Power


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LIST OF CONTENTS

PreambleSection 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


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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


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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 andthus 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. Settingcalculation 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


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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 ofany 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.


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MODEL SETTING CALCULATION DOCUMENT FOR A TYPICAL

IED USED FOR TRANSMISSION LINE PROTECTION


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Model setting calculation document for Transmission Line

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..........................................................................................102.1.2 List of functions available and those used............................................................10

2.2 REC670 ..............................................................................................................................16

2.2.1 Terminal identification..........................................................................................162.2.2 List of functions available and those used............................................................16

3.0 SETTING CALCULATIONSAND RECOMMENDED SETTINGS FOR REL670.................23

3.1 REL670...............................................................................................................................23

3.1.1 Analog Inputs.......................................................................................................233.1.2 Local Human-Machine Interface ..........................................................................263.1.3 Indication LEDs....................................................................................................263.1.4 Time Synchronization ..........................................................................................283.1.5 Parameter Setting Groups ...................................................................................313.1.6 Test Mode Functionality TEST.............................................................................32

3.1.7

IED Identifiers......................................................................................................34

3.1.8 Rated System Frequency PRIMVAL....................................................................353.1.9 Signal Matrix For Analog Inputs SMAI .................................................................353.1.10 General settings of Distance protection zones.....................................................373.1.11 Distance Protection Zone, Quadrilateral Characteristic (Zone 1) ZMQPDIS.........393.1.12 Distance Protection Zone, Quadrilateral Characteristic (Zone 2) ZMQAPDIS .....443.1.13 Distance Protection Zone, Quadrilateral Characteristic (Zone 3) ZMQAPDIS ......473.1.14 Distance Protection Zone, Quadrilateral Characteristic (Zone 5) ZMQAPDIS ......503.1.15 Phase Selection with Load Encroachment, Quadrilateral Characteristic FDPSPDIS

543.1.16 Broken Conductor Check BRCPTOC (Normally used for Alarm purpose only) ....623.1.17 Tripping Logic SMPPTRC....................................................................................633.1.18 Trip Matrix Logic TMAGGIO.................................................................................653.1.19 Automatic Switch Onto Fault Logic, Voltage And Current Based ZCVPSOF........663.1.20 Power Swing Detection ZMRPSB........................................................................68


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3.2.1 Analog Inputs.......................................................................................................933.2.2 Local Human-Machine Interface ..........................................................................95

3.2.3 Indication LEDs....................................................................................................963.2.4 Time Synchronization ..........................................................................................973.2.5 Parameter Setting Groups .................................................................................1013.2.6 Test Mode Functionality TEST...........................................................................1023.2.7 IED Identifiers....................................................................................................1033.2.8 Rated System Frequency PRIMVAL..................................................................1033.2.9 Signal Matrix For Analog Inputs SMAI ...............................................................1033.2.10 Synchrocheck function (SYN1) ..........................................................................1063.2.11 Autorecloser SMBRREC....................................................................................1103.2.12 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


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LIST OF FIGURES

Figure 1-1: Network line diagram of the protected line ....................................................................................... 8Figure 1-2: Equivalent representation of the protected line with source impedance .......................................... 9Figure 3-1: Setting angles for discrimination of forward and reverse fault........................................................ 37Figure 3-2: Characteristic for phase-to-earth measuring, ohm/loop domain..................................................... 39Figure 3-3: Characteristic for phase-to-phase measuring................................................................................. 40Figure 3-4: Relation between distance protection ZMQPDIS and FDPSPDIS for phase-to-earth faultloop>60........................................... ............................................................................................................... 54Figure 3-5: Relation between distance protection (ZMQPDIS) and FDPSPDIS characteristic for phase-to-phase fault for line>60........................................... ........................................................................................ 55

Figure 3-6: Load encroachment characteristic .................................................................................................. 56Figure 3-7: Operating characteristic for ZMRPSB function ............................................................................... 68Figure 3-8: Characteristics for Phase to Phase faults ....................................................................................... 75Figure 3-9: Characteristics for Phase to Earth faults ........................................................................................ 76

Figure A-1: System details for the network under consideration for relay setting........................................... 123Figure A-2: 3-Ph fault current for 220 kV side fault ......................................................................................... 124Figure A-3: Over Current Relay Curve Co-ordination and Operating Time .................................................... 125Figure A-4: Ph-G fault current for 220 kV side fault ........................................................................................ 126

Figure A-5: Earth Fault Relay Curve Co-ordination and Operating Time ....................................................... 127Figure A-6: Earth fault relay co-ordination for 400 kV bus fault at Station B (Remote bus of the protected line)......................................................................................................................................................................... 128Figure 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................................ 131Figure B-2: SLG Fault at bus B with source at Station A and Line A-S out of service and Earthed ............... 134Figure B-3: SLG Fault at bus B with sources at Station A & B and Line A-S out of service and Earthed ...... 135Figure 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 ...... 138Figure B-7: SLG Fault at bus B with sources at Station A, B & S and Line B-S out of service and Earthed .. 139Figure B-8: SLG Fault at bus S with source at Station A and Line A-B out of service and Earthed ............... 140Figure B-9: SLG Fault at bus S with sources at Station A & B and Line A-B out of service and Earthed ...... 141Figure B-10: SLG Fault at bus S with sources at Station A, B & S and Line A-B out of service and Earthed 142Figure B-11: SLG Fault at bus B with source at Station A .............................................................................. 143Figure B-12: SLG Fault at bus B with sources at Station A and B.................................................................. 144Figure B-13: SLG Fault at bus B with sources at Station A, B & S ................................................................. 145Figure 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.................................................................. 147Figure B-16: SLG Fault at bus S with sources at Station A, B & S ................................................................. 148


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LIST OF TABLES

Table 2-1: List of functions in REL670 .......................................................................................................... 10Table 2-2: List of functions in REC670 .......................................................................................................... 16Table 3-1: Analog inputs ................................................................................................................................. 24Table 3-2: Local human machine interface ....................................................................................................... 26Table 3-3: LEDGEN Non group settings (basic) ............................................................................................... 27Table 3-4: Time synchronization settings.......................................................................................................... 29Table 3-5: Parameter setting group................................................................................................................... 32Table 3-6: Test mode functionality .................................................................................................................... 34Table 3-7: IED Identifiers ................................................................................................................................... 34

Table 3-8: Rated system frequency .................................................................................................................. 35Table 3-9: Signal Matrix For Analog Inputs ....................................................................................................... 36Table 3-10: General settings for distance protection ........................................................................................ 38Table 3-11: ZONE 1 Settings ............................................................................................................................ 43Table 3-12: ZONE 2 Settings ............................................................................................................................ 46Table 3-13: ZONE 3 Settings........................................................................................................................... 49Table 3-14: ZONE 5 Settings........................................................................................................................... 52Table 3-15: Phase Selection with Load Encroachment, Quadrilateral Characteristic ...................................... 61Table 3-16: Broken Conductor Check ............................................................................................................... 63Table 3-17: Tripping Logic................................................................................................................................. 64Table 3-18: Trip Matrix Logic............................................................................................................................. 65Table 3-19: Automatic Switch Onto Fault Logic ................................................................................................ 67Table 3-20: Power Swing Detection ............................................................................................................... 73Table 3-21: Scheme Communication Logic For Distance Or Overcurrent Protection ...................................... 77Table 3-22: Stub Protection............................................................................................................................... 78Table 3-23: Fuse Failure Supervision ............................................................................................................... 79Table 3-24: Four Step Residual Overcurrent Protection ................................................................................... 83Table 3-25: Two Step Overvoltage Protection .................................................................................................. 86Table 3-26: Setting of fault locator values ......................................................................................................... 89

Table 3-27: Disturbance Report ........................................................................................................................ 92Table 3-28: Analog Inputs ................................................................................................................................. 93Table 3-29: Local human machine interface ..................................................................................................... 96Table 3-30: LEDGEN Non group settings (basic) ............................................................................................. 96Table 3-31: Time Synchronization..................................................................................................................... 99Table 3-32: Parameter Setting Groups ........................................................................................................... 102Table 3-33: Test Mode Functionality ............................................................................................................... 102Table 3-34: IED Identifiers ............................................................................................................................... 103Table 3-35: Rated System Frequency............................................................................................................. 103

Table 3-36: Signal Matrix For Analog Inputs ................................................................................................... 105

Table 3-37: Synchrocheck function ................................................................................................................. 108Table 3-38: Autorecloser ................................................................................................................................. 116Table 3-39: Disturbance Report ...................................................................................................................... 119Table A-1 Settings of Over current and Earth fault relays............................................................................... 122Table B-1: Fault At Station-B With Source At Station A and Line A-S Earthed........................................... 134Table B-2: Fault At Station-B With Sources At Station A & B and Line A-S Earthed .......................... 135


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


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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


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1.0 BASIC SYSTEM PARAMETERS

1.1 Network line diagram of the protected line and adjacent circuitsThe 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.


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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 /km

R0 + jX0 = 0.2689 + j1.072 /km

R0M + jX0M = 0.228 + j0.662 /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 flowanalysis 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.


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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/featureactivated

Yes/No

RecommendedSettingsprovided

1 Analog Inputs YES

2 Local Human-Machine Interface YES

3 Indication LEDs YES


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Yes/No


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

20Distance Protection Zone, Quadrilateral

Characteristic (Zone 2) ZMQAPDISYES


Characteristic (Zone 3) ZMQAPDISYES


Characteristic (Zone 4) ZMQAPDISNO


Ch i i (Z 5) ZMQAPDISYES


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Yes/No


27Automatic Switch Onto Fault Logic, VoltageAnd Current Based ZCVPSOF

YES

28Instantaneous Phase Overcurrent ProtectionPHPIOC

NO

29 Four Step Phase Overcurrent ProtectionOC4PTOC

NO

30Instantaneous Residual Overcurrent ProtectionEFPIOC

NO

31Four Step Residual Overcurrent ProtectionEF4PTOC

YES

32Sensitive Directional Residual Overcurrent AndPower Protection SDEPSDE

NO

33Thermal Overload Protection, One TimeConstant 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 ProtectionCVGAPC-4 functions NO

40 Current Circuit Supervision CCSRDIF NO

41 Fuse Failure Supervision SDDRFUF YES


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Yes/No


45 Generic Double Point Function Block DPGGIO NO

46Single Point Generic Control 8 SignalsSPC8GGIO

NO

47

Automationbits, Command Function For

DNP3.0 AUTOBITS NO

48 Single Command, 16 Signals SINGLECMD NO

49Scheme Communication Logic For Distance OrOvercurrent Protection ZCPSCH

YES

50Current Reversal And Weak-End Infeed Logic

For Distance Protection ZCRWPSCH

NO

51 Local Acceleration Logic ZCLCPLAL NO

52 Direct Transfer Trip Logic YES

53Low Active Power And Power Factor ProtectionLAPPGAPC

NO

54 Compensated Over and UndervoltageProtection COUVGAPC

NO

55Sudden Change in Current VariationSCCVPTOC

NO

56 Carrier Receive Logic LCCRPTRC NO

57Negative Sequence Overvoltage ProtectionLCNSPTOV NO

58Zero Sequence Overvoltage ProtectionLCZSPTOV

NO

Negative Sequence Overcurrent Protection


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Yes/No


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 LogicNode

Representation B16IFCVI

NO

69 Integer To Boolean 16 Conversion IB16 NO

70

Integer To Boolean 16 Conversion With LogicNode

Representation IB16FCVB

NO

71 Measurements CVMMXN YES

72 Phase Current Measurement CMMXU YES

73 Phase-Phase Voltage Measurement VMMXU YES

74Current Sequence Component MeasurementCMSQI

YES

75 Voltage Sequence Measurement VMSQI YES

76 Phase-Neutral Voltage Measurement VNMMXU NO

77 Event Counter CNTGGIO YES

78 Event Function EVENT YES


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Yes/No


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

89Function For Energy Calculation And DemandHandling ETPMMTR

NO

90 IEC 61850-8-1 Communication Protocol NO

91IEC 61850 Generic Communication I/OFunctions SPGGIO, SP16GGIO

NO

92IEC 61850-8-1 Redundant Station BusCommunication

NO

93 IEC 61850-9-2LE Communication Protocol NO

94 LON Communication Protocol NO

95 SPA Communication Protocol NO


97

Multiple Command And TransmitMULTICMDRCV,

MULTICMDSND

NO

98 Remote Communication NO


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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/Functionsactivated

Yes/No


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


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Yes/No


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

20Instantaneous Phase Overcurrent ProtectionPHPIOC

NO

21Four Step Phase Overcurrent ProtectionOC4PTOC

NO

22Instantaneous Residual Overcurrent

Protection EFPIOCNO

23Four Step Residual Overcurrent ProtectionEF4PTOC

NO

24Four step directional negative phasesequence overcurrent protection NS4PTOC

NO

25Sensitive Directional Residual OvercurrentAnd Power Protection SDEPSDE NO

26Thermal Overload Protection, One TimeConstant LPTTR

NO

Thermal overload protection two time


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Yes/No

RecommendedSettings

provided

31Directional Underpower ProtectionGUPPDUP

NO

32Directional Overpower ProtectionGOPPDOP

NO

33 Broken Conductor Check BRCPTOC NO

34 Capacitor bank protection CBPGAPC NO

35Two Step Undervoltage ProtectionUV2PTUV

NO

36 Two Step Overvoltage Protection OV2PTOV NO

37Two Step Residual Overvoltage ProtectionROV2PTOV

NO

38 Voltage Differential Protection VDCPTOV NO

39 Loss Of Voltage Check LOVPTUV NO

40 Underfrequency Protection SAPTUF NO

41 Overfrequency Protection SAPTOF NO

42Rate-Of-Change Frequency ProtectionSAPFRC

NO

43General Current and Voltage ProtectionCVGAPC

NO

44 Current Circuit Supervision CCSRDIF NO

45 Fuse Failure Supervision SDDRFUF NO

46Synchrocheck, Energizing Check, AndSynchronizing SESRSYN

YES


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Yes/No

RecommendedSettings

provided

50Logic Rotating Switch For FunctionSelection And LHMI Presentation SLGGIO

NO

51 Selector Mini Switch VSGGIO NO

52Generic Double Point Function Block

DPGGIONO

53Single Point Generic Control 8 SignalsSPC8GGIO

NO

54Automationbits, Command Function ForDNP3.0 AUTOBITS

NO

55 Single Command, 16 Signals SINGLECMD NO

56Scheme Communication Logic For DistanceOr Overcurrent Protection ZCPSCH

NO

57Phase Segregated Scheme CommunicationLogic For Distance Protection ZC1PPSCH

NO

58Current Reversal And Weak-End Infeed

Logic For Distance Protection ZCRWPSCHNO

59 Local Acceleration Logic ZCLCPLAL NO

60Scheme Communication Logic For ResidualOvercurrent Protection ECPSCH

NO

61Current Reversal And Weak-End InfeedLogic For Residual Overcurrent ProtectionECRWPSCH

NO

62Current Reversal And Weak-End InfeedLogic For Phase SegregatedCommunication ZC1WPSCH

NO

M d l i l l i d f T i i Li


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Yes/No

RecommendedSettings

provided

66Sudden Change In Current VariationSCCVPTOC

NO

67 Carrier Receive Logic LCCRPTRC NO

68Negative Sequence Overvoltage Protection

LCNSPTOVNO

69Zero Sequence Overvoltage ProtectionLCZSPTOV

NO

70Negative Sequence Overcurrent ProtectionLCNSPTOC

NO

71Zero Sequence Overcurrent ProtectionLCZSPTOC 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 WithLogic Node

Representation B16IFCVI

NO

80 Integer To Boolean 16 Conversion IB16 NO

Model setting calc lation doc ment for Transmission Line


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Yes/No

RecommendedSettings

provided

84Phase-Phase Voltage MeasurementVMMXU

YES

85Current Sequence ComponentMeasurement CMSQI

YES

86 Voltage Sequence Measurement VMSQI YES

87Phase-Neutral Voltage MeasurementVNMMXU

NO

88 Event Counter CNTGGIO YES

89 Event Function EVENT YES

90 Logical Signal Status Report BINSTATREP NO

91 Fault Locator LMBRFLO NO

92Measured Value Expander BlockRANGE_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

100Function For Energy Calculation AndDemand Handling ETPMMTR

NO



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Yes/No

RecommendedSettings

provided

104 IEC 61850-9-2LE Communication Protocol NO

105 LON Communication Protocol NO

106 SPA Communication Protocol NO


108

Multiple Command And TransmitMULTICMDRCV,

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.



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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



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Recommended Settings:

Table 3-1 gives the recommended settings for the analog inputs.

Table 3-1: Analog inputs

SettingParameter

DescriptionRecommended

Settings Unit

PhaseAngleRefReference channel for phase angle

PresentationTRM40-Ch1 -

CTStarPoint1ToObject= towards protected object,

FromObject= the oppositeToObject -

CTsec1 Rated CT secondary current 1 A

CTprim1 Rated CT primary current 1000 A





CTStarPoint3

ToObject= towards protected object,

FromObject= the opposite ToObject -







ToObject towards protected object



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ode sett g ca cu at o docu e t o a s ss o e

SettingParameter


Settings Unit

FromObject= the opposite



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

I/O Module 2 On 40 30 Pos Slot3





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g

3.1.2 Local Human-Machine Interface

Recommended Settings:Table 3-2 gives the recommended settings for Local human machine interface.

Table 3-2: Local human machine interface

SettingParameter


Settings Unit

Language Local HMI language English -

DisplayTimeout Local HMI display timeout 60 Min

AutoRepeatActivation 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. Iftrip still persist, it will f lash.

tRestart: Not applicable for the above case.

tMax:Not applicable for the above case.



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Table 3-3 gives the recommended settings for Indication LEDs.

Table 3-3: LEDGEN Non group settings (basic)

SettingParameter


Settings Unit

Operation Operation mode for the LED function On -

tRestart Defines the disturbance length 0.0 s

tMaxMaximum time for the definition of a

disturbance0.0 s

SeqTypeLED1 Sequence type for LED 1 LatchedAck-S-F -















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3.1.4 Time Synchronization

Guidelines for Settings: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

Synchbased 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.



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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

applicable in present case.

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 -



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SYNCHBIN Non group settings (basic)

SettingParameter Description

Recommended

Settings Unit

ModulePositionHardware position of IO module for time

Synchronization3 -

BinaryInputBinary input number for time

synchronization1 -

BinDetection Positive or negative edge detection PositiveEdge -

SYNCHSNTP Non group settings (basic)

Setting Parameter DescriptionRecommended

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)

SettingParameter

Description RecommendedSettings Unit

MonthInYear Month in year when daylight time starts March -

DayInWeek Day in week when daylight time starts Sunday -

WeekInMonthWeek in month when daylight time

starts

Last -

UTCTimeOfDayUTC Time of day in seconds when

daylight time starts3600 s



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DSTEND Non group settings (basic)

SettingParameter


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 -

UTCTimeOfDayUTC Time of day in seconds when

daylight time starts3600 s

TIMEZONE Non group settings (basic)

SettingParameter


Settings Unit

NoHalfHourUTC Number of half-hours from UTC +11 -

SYNCHIRIG-B Non group settings (basic)

SettingParameter


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.



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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)

SettingParameter


tPulse length of pulse when setting

Changed1 s

SETGRPS Non group settings (basic)

SettingParameter


Settings Unit

ActiveSetGrp ActiveSettingGroup SettingGroup1 -

MAXSETGR Max number of setting groups 1-6 1 No

3.1.6 Test Mode Functionality TEST




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



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Table 3-6: Test mode functionality

TESTMODE Non group settings (basic)

SettingParameter


Settings Unit

TestMode Test mode in operation (On) or not (Off) Off -

EventDisable Event disable during testmode Off -

CmdTestBitCommand bit for test required or not

during testmodeOff -

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)

SettingParameter


Settings Unit

StationName Station name Station-A -

StationNumber Station number 0 -

ObjectName Object name Line-1 -

ObjectNumber Object number 0 -

U itN U it REL670 M1



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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)

SettingParameter


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



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connected to 3rdSMAI 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

SettingParameter


Settings Unit

DFTRefExtOut DFT reference for external output InternalDFTRef -

DFTReference DFT reference InternalDFTRef -

ConnectionType Input connection type Ph-Ph -

TYPE 1=Voltage, 2=Current1 or 2 based oninput

Ch

Negation Negation Off -



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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 115respectively. 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.




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Recommended Settings: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)

SettingParameter


Settings Unit

IBase Base setting for current level 1000 A

UBase Base setting for voltage level 400 kV

IMinOpPPMinimum operate delta current forPhase-Phase loops

20 %IB

IMinOpPEMinimum operate phase current for

Phase-Earth loops20 %IB

ArgNegResAngle of blinder in second quadrant for

forward direction115 Deg

ArgDirAngle of blinder in fourth quadrant for

forward direction15 Deg



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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.



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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



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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 thecurrent 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 3I0current 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' = 46.664 Note! Zone will send carrier signal

The secondary setting will thus be

X1Z1 = 12.833

Set the positive sequence resistance for phase faults to (this gives the characteristic angle)



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X0Z1 = 44.81

Set the zero sequence resistance for earth faults to

R0Z1' = 40.873


R0Z1 = 11.24

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 . (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 forphase faults.

The resistive reach (phase to earth) is set as 50 keeping a value of 10 for tower footing

resistance, arc-resistance of 15and remote end infeed effect of 25(considering equal fault feed

from both side)

Set the resistive reach for phase faults to:

RFPPZ1' = 30(loop value)


RFPPZ1 = 8.25

Set the resistive reach for earth faults to

RFPEZ1= 50


RFPEZ1 = 13.75

Set the Base current for the Distance protection zones in primary Ampere.

Zone 1 setting of timers.



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Table 3-11 gives the recommended settings for ZONE 1 Settings.

Table 3-11: ZONE 1 Settings

SettingParameter


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

OperationPP

Operation mode Off/On of Ph-Ph loops On -

Timer tPPOperation mode Off/On of Zone timer, Ph-Ph

On -

tPP Time delay of trip,Ph-Ph 0.000 s

OperationPE

Operation mode Off/On of Ph-E loops On -

Timer tPE Operation mode Off/On of Zone timer, Ph-E On -



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IMinOpINMinimum operate residual current forPhase-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 inmind while arriving at resistive reach setting for Zone-2.

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.



to 20% of IBase.



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OperationDir = ForwardOperation PP = On

Operation PE = On

Zone 2 phase fault reach is set to 150.0%of the total line reactance

X1Z2' = 87.495 Zone is accelerated at receipt of Carrier signal.


X1Z2 = 24.061


R1Z2' = 8.208


R1Z2 = 2.257

Setting of zone earth fault zero sequence values

X0Z2' = 305.52 150.0%of the total line reactance


X0Z2 = 84.018


R0Z2' = 76.637

The secondary setting will thus beR0Z2 = 21.075

Setting of the fault resistive cover

The resistive reach for phase to phase is set to cover a maximum expected fault resistance of

30.0

(Considering a factor of 2 on the Zone-1 resistive reach value to take care of in-feed effect)

Set the resistive reach for phase faults to:

RFPPZ2' = 60


RFPPZ2 =16 5


Z 2 ti tti


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Zone 2 timers setting

Setting of Zone timer activation for phase-phase and earth faults

tPP2 = On

tPE2 = On

Setting of Zone timers:

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.




SettingParameter


Settings Unit


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 -


R1 Positive sequence resistance reach 8.208 ohm/p



RFPPFault resistance reach in ohm/loop Ph-

60 h /l



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SettingParameter


Settings Unit


Operation PE Operation mode Off/On of Ph-E loops On -

Timer tPEOperation mode Off/On of Zone timer,Ph-E

On -

tPE Time delay of trip,Ph-E 0.35 s

IMinOpPPMinimum operate delta current for Phase-Phase loops

20 %IB

IMinOpPEMinimum operate phase current forPhase-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.


IMinOpPP: Setting of minimum sensitivity for zone Phase Phase elements Measures IL IL for each


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to 20% of IBase.IMinOpPE: Setting of minimum operating current for Phase faults. Measures ILx. This is the



OperationDir = Forward

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' = 199.304


X1Z3 = 54.809


R1Z3' = 18.697


R1Z3 = 5.142


X0Z3' = 695.942 120% of sum of protected line and adjacent longest lines

reactance is considered.


X0Z3 = 191.384


R0Z3' = 174.57


The faults on remote lines will have in-feed of fault current through the fault resistance from other


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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' = 75(Loop value)


RFPPZ3 = 20.625


RFPEZ3= 125


RFPEZ3 = 34.375

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

ParameterDescription

Recommended

Settings Unit

O ti O ti Off / O O


Setting Recommended


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Setting

ParameterDescription

Recommended

Settings Unit



RFPP Fault resistance reach in ohm/loop , Ph-Ph 75 ohm/l


Operation

PPOperation mode Off/On of Ph-Ph loops On -

Timer t1PP Operation mode Off/On of Zone timer, Ph-Ph On -

tPP Time delay of trip,Ph-Ph 1 s

Operation

PEOperation mode Off/On of Ph-E loops On -

Timer t1PE Operation mode Off/On of Zone timer, Ph-E On -

t1PE Time delay of trip,Ph-E 1 s

IMinOpPPMinimum operate delta current for Phase-

Phase loops20 %IB

IMinOpPEMinimum operate phase current for

Phase-Earth loops20 %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

t ti f lt l d ith Z 1 f lt l f li t f th b t ti F


IBase:Set the Base current for the Distance protection zones in primary Ampere here. Set to the


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p p y p


UBase: Set the Base voltage for the Distance protection zones in primary kV here. Set to thevoltage value of the primary winding of the VT. This parameter is set to 400kV in present case.



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' = 6.14


X1Z5 = 1.689


R1Z5' = 0.576


R1Z5 = 0.158


X0Z5' = 21.44

The secondary setting will thus beX0Z5 = 5.896


R0Z5' = 5.378


RFPPZ5 = 20.625


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RFPEZ5= 125The secondary setting will thus be

RFPPZ5 = 34.375

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.




SettingParameter


Settings Unit


IBase Base current , i.e. rated current 1000 A

Ubase Base voltage , i.e. rated voltage 400.00 kV

OperationDir Operation mode of directionality Reverse -



Setting Recommended


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SettingParameter


Settings Unit


OperationPP

Operation mode Off/On of Ph-Ph loops On -

Timer t1PP Operation mode Off/On of Zone timer, Ph-Ph On -


OperationPE

Operation mode Off/On of Ph-E loops On -

Timer t1PE Operation mode Off/On of Zone timer, Ph-E On -

t1PE Time delay of trip,Ph-E 0.35 s

IMinOpPP Minimum operate delta current for Phase-Phase loops 20 %IB

IMinOpPEMinimum operate phase current for Phase-Earth loops

20 %IB



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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:



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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 characteristicfor phase-to-phase fault for line>60



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RLdFw: Forward resistive reach within the load impedance areaRLdRv: 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


3I0 residual current must fulfill the conditions according to the equations given below


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3.I00.5 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 30is 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.

X1PHS1.44 X1Zm

X0PHS1.44 X0Zm

where:

X1Zm is the reactive reach for the zone to be covered by FDPSPDIS, and the constant 1.44 is a

safety margin

X0 is the zero sequence reactive reach for the zone to be covered by FDPSPDIS


where:

RFPE i h i RFPE f h l hi b d b FDPSPDIS


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RFPEZmis the setting RFPE for the longest overreaching zone to be covered by FDPSPDIS.

Phase-to-earth fault in reverse directionReactive 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:

RFPPZmis 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 60to



i i t i d i h t th f lt f t T b t t 20% f IB


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Setting Calculations: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),

= 86.4

RLmin= 86.4 x cos30 = 74.82. Since considered load

guidelines relay setting

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