Guidelines Relay Setting

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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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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, ABB

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LIST OF CONTENTS

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

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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 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

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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 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

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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 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.

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MODEL SETTING CALCULATION DOCUMENT FOR A TYPICAL

IED USED FOR TRANSMISSION LINE PROTECTION

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2

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

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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

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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

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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 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.

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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 1-1-2 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

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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/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

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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

Characteristic (Zone 2) ZMQAPDIS YES

Characteristic (Zone 4) ZMQAPDIS NO

24 Directional Impedance Quadrilateral ZDRDIR YES

25 Phase Selection With Load Encroachment,

Quadrilateral Characteristic FDPSPDIS YES

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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

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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

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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

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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.

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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/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

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Sl.No. Functions/Feature available In REC670

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

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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

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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

Current Reversal And Weak-End Infeed Logic For Residual Overcurrent Protection ECRWPSCH

NO

62

Current Reversal And Weak-End Infeed 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

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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

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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

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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.

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3.0 SETTING

CALCULATIONS

AND

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

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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

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Setting

Recommended

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

Note: OscBlock and OscRelease defines the filtering time at activation. Low frequency gives slow response for digital input.

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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 Setting

Recommended

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

Guidelines for Settings:

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.

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Recommended Settings:

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

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

Recommended

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 - SeqTypeLED2 Sequence type for LED 2 LatchedAck-S-F - SeqTypeLED3 Sequence type for LED 3 LatchedAck-S-F - SeqTypeLED4 Sequence type for LED 4 LatchedAck-S-F - SeqTypeLED5 Sequence type for LED 5 LatchedAck-S-F - SeqTypeLED6 Sequence type for LED 6 LatchedAck-S-F - SeqTypeLED7 Sequence type for LED 7 LatchedAck-S-F - SeqTypeLED8 Sequence type for LED 8 LatchedAck-S-F - SeqTypeLED9 Sequence type for LED 9 LatchedAck-S-F - SeqTypeLED10 Sequence type for LED 10 LatchedAck-S-F - SeqTypeLED11 Sequence type for LED 11 LatchedAck-S-F - SeqTypeLED12 Sequence type for LED 12 LatchedAck-S-F - SeqTypeLED13 Sequence type for LED 13 LatchedAck-S-F - SeqTypeLED14 Sequence type for LED 14 LatchedAck-S-F - SeqTypeLED15 Sequence type for LED 15 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

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 applicable in present case.

ServerIP-Add: Here set Time source server IP address.

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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.

Recommended Settings:

Table 3-4 gives the recommended settings for Time synchonization.

Table 3-4: Time synchronization settings TIMESYNCHGEN Non group settings (basic)

Setting

Recommended

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 -

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SYNCHBIN Non group settings (basic) Setting

Recommended

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

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

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

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DSTEND Non group settings (basic) Setting

Recommended

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

Recommended Settings Unit

NoHalfHourUTC Number of half-hours from UTC +11 -

SYNCHIRIG-B Non group settings (basic) Setting

Recommended

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

Guidelines for Settings:

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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.

Recommended Settings:

Table 3-5 gives the recommended settings for Parameter setting group.

Table 3-5: Parameter setting group ActiveGroup Non group settings (basic)

Setting

Recommended

t Pulse length of pulse when setting

Changed 1 s

SETGRPS Non group settings (basic) Setting

Recommended

ActiveSetGrp ActiveSettingGroup SettingGroup1 -

MAXSETGR Max number of setting groups 1-6 1 No

3.1.6 Test Mode Functionality TEST

Guidelines for Settings:

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.

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Table 3-6: Test mode functionality TESTMODE Non group settings (basic)

Setting

Recommended

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

Recommended Settings:

Table 3-7 gives the recommended settings for IED Identifiers.

Table 3-7: IED Identifiers TERMINALID Non group settings (basic)

Setting

Recommended

StationName Station name Station-A -

StationNumber Station number 0 -

ObjectName Object name Line-1 -

ObjectNumber Object number 0 -

UnitName Unit name REL670 M1 -

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3.1.8 Rated System Frequency PRIMVAL

Recommended Settings:

Table 3-8 gives the recommended settings for Rated system frequency.

Table 3-8: Rated system frequency PRIMVAL Non group settings (basic)

Setting

Recommended

Frequency Rated system frequency 50.0 Hz

3.1.9 Signal Matrix For Analog Inputs SMAI

Guidelines for Settings:

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

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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.

Recommended Settings:

Table 3-9 gives the recommended settings for Signal Matrix For Analog Inputs.

Table 3-9: Signal Matrix For Analog Inputs Setting

Recommended

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 %

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3.1.10 General settings of Distance protection zones

Guidelines for Settings:

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.

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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)

Setting

Recommended

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

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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

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:

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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 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

The secondary setting will thus be R1Z1 = 1.204Ω

Setting of zone earth fault zero sequence values

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42 The secondary setting will thus be

X0Z1 = 44.81Ω

Set the zero sequence resistance for earth faults to R0Z1' = 40.873Ω

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

R_{arc =}

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) The secondary setting will thus be

RFPPZ1 = 8.25Ω

Set the resistive reach for earth faults to RFPEZ1´= 50Ω

The secondary setting will thus be 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

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Recommended Settings:

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

Table 3-11: ZONE 1 Settings Setting

Recommended

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

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44 IMinOpIN Minimum operate residual current for

Phase-Earth loops 10 %IB

3.1.12 Distance Protection Zone, Quadrilateral Characteristic (Zone 2)

ZMQAPDIS

Guidelines for Setting:

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.

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

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Setting Calculations:

OperationDir = Forward 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. The secondary setting will thus be

X1Z2 = 24.061Ω

Set the positive sequence resistance for phase faults to (this gives the characteristic angle) R1Z2' = 8.208Ω

Setting of zone earth fault zero sequence values

X0Z2' = 305.52Ω 150.0%of the total line reactance The secondary setting will thus be

X0Z2 = 84.018Ω

Set the zero sequence resistance for earth faults to R0Z2' = 76.637Ω

Setting of the fault resistive cover

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) Set the resistive reach for phase faults to:

RFPPZ2' = 60Ω The secondary setting will thus be

RFPPZ2 =16.5Ω

Set the resistive reach for earth faults to RFPEZ2´= 75Ω

The secondary setting will thus be RFPPZ2 = 20.625Ω

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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.

Recommended Settings:

Table 3-12 gives the recommended settings for ZONE 2 Settings.

Table 3-12: ZONE 2 Settings Setting

Recommended

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 87.495 ohm/p

R1 Positive sequence resistance reach 8.208 ohm/p

X0 Zero sequence reactance reach 305.52 ohm/p

R0 Zero sequence resistance for zone 76.637 ohm/p

RFPP Fault resistance reach in ohm/loop ,

Ph-Ph 60 ohm/l

RFPE Fault resistance reach in ohm/loop , Ph-E 75 ohm/l Operation PP Operation mode Off/On of Ph-Ph loops On -

Timer tPP Operation mode Off/On of Zone timer,

Guidelines Relay Setting

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

Preamble

Acknowledgement

Sub-committee

LIST OF CONTENTS

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

MODEL SETTING CALCULATION DOCUMENTS FOR

TYPICAL IEDs USED FOR THE PROTECTION OF DIFFERENT

POWER SYSTEM ELEMENTS IN 220kV, 400kV AND 765 kV

SUBSTATIONS

INTRODUCTION

MODEL SETTING CALCULATION DOCUMENT FOR A TYPICAL

IED USED FOR TRANSMISSION LINE PROTECTION

TABLE OF CONTENTS

LIST OF FIGURES

LIST OF TABLES

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

1.0 BASIC SYSTEM PARAMETERS

1.1 Network line diagram of the protected line and adjacent circuits

1.2 Single line diagram of the double circuit line

1.3 Line parameters

2.0 TERMINAL IDENTIFICATION AND LIST OF FUNCTIONS

2.1 REL670

2.1.1 Terminal Identification

2.1.2 List of functions available and those used

2.2 REC670

2.2.1 Terminal identification

2.2.2 List of functions available and those used

3.0 SETTING

CALCULATIONS

AND

RECOMMENDED

SETTINGS FOR REL670

3.1

REL670

3.1.1 Analog Inputs

Guidelines for Settings:

Recommended Settings:

3.1.2 Local Human-Machine Interface

Recommended Settings:

3.1.3 Indication LEDs

Guidelines for Settings:

Recommended Settings:

3.1.4 Time Synchronization

Guidelines for Settings:

Recommended Settings:

3.1.5 Parameter Setting Groups

Guidelines for Settings:

Recommended Settings:

3.1.6 Test Mode Functionality TEST