wrpc.gov.inwrpc.gov.in/pcm/relay_set.pdfprotection subcommittee report preamble as a follow up of...

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

New Delhi March 2014

Protection subcommittee report

Preamble

As a follow up of one of the recommendations of the Enquiry Committee headed by Chairman,

CEA on grid disturbances that took place in Indian grid on 30th and 31st July 2012, Ministry of

Power constituted a ‘Task Force on Power System Analysis under Contingencies’ in December

2012. The Terms of Reference of Task Force broadly cover analysis of the network behaviour

under normal conditions and contingencies, review of the philosophy of operation of protection

relays, review of islanding schemes and technological options to improve the performance of

the grid.

Apart from the main Task Force two more sub-committees were constituted. One for system

studies for July-September 2013 conditions and another for examining philosophy of relay and

protection coordination.

The tasks assigned to the protection sub-committee were to review the protection setting

philosophy (including load encroachment, power swing blocking, out of step protection, back-up

protections) for protection relays installed at 765kV, 400kV, 220kV (132kV in NER) transmission

system and prepare procedure for protection audit. This was submitted to the Task Force on

22.07.2013.

Further one more task assigned to the protection sub-committee was to prepare model setting

calculations for typical IEDs used in protection of 400kV line, transformer, reactor and busbar.

This document gives the model setting calculations, line protection setting guide lines,

protection system audit check lists, recommendations for protection system management and

some details connected with protection audit.


Acknowledgement

The Protection sub-committee thanks members of “Task Force for Power System Analysis

under Contingencies” for all the support and encouragement. Further the Protection sub-

committee acknowledges the contribution from Mr Rajil Srivastava, Mr Abhay Kumar, Mr

Kailash Rathore of Power Grid, Mr Shaik Nadeem of ABB and Mr Vijaya Kumar of PRDC to the

work carried out by the sub - committee.

Sub-committee

Convener

B.S. Pandey, Power Grid

Members

P. P. Francis, NTPC

S.G. Patki, Tata Power

R. H. Satpute, MSETCL

Nagaraja, PRDC

Bapuji Palki, ABB

Vikas Saxena, Jindal Power


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

9 : Details of protection audit 1-5


- 1 -

MODEL SETTING CALCULATION DOCUMENTS FOR

TYPICAL IEDs USED FOR THE PROTECTION OF DIFFERENT

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

SUBSTATIONS

INTRODUCTION In addition to setting criteria guide lines prepared by Subcommittee on relay/protection under

Task Force for Power System Analysis under Contingencies for 220kV, 400kV and 765kV

transmission lines, the Subcommittee has prepared model setting calculation documents for

IEDs used for protection of following elements.

• 400kV Transmission line

• 400/220/33kV Auto Transformer

• 400kV Shunt Reactor

• 400kV Bus Bar

While guide lines as finalized by the Subcommittee have been used for the setting calculation

document on transmission lines, for other power system elements like transformer, shunt

reactor and bus bar, guide lines as given in CBIP documents and manufacturer's manuals have

been used. The documents presented should serve as a model to various utilities in preparing

similar documents for different power system elements that are used in 220kV, 400kV and

765kV EHV and UHV transmission systems. The documents are prepared to meet following

expectations given in the Protection subcommittee report.

The numerical terminals referred as IED (Intelligent electronic device) contain apart from main

protection functions several other protection & supervision functions which may or may not be

used for a particular application. Many of these functions are having default settings which may

not be suitable and may lead to mal-operations. Thus, it is important that the recommended

setting document should contain all the settings for all functions that are used and indicate

clearly the functions not used (to be Blocked / Disabled). This shall be followed not only for Line

protection IEDs but also for other IEDs like Generator, Transformer, Reactor, Bus bar protection


- 2 -

and Control functions. It is also recommended that graphical representation of distance relay

zones on R-X plane including phase selection, load encroachment & power swing

characteristics should be done showing exact setting calculated.

Each of these documents has following main sections:

1. BASIC SYSTEM PARAMETERS: This section contains all the system related information

including single line diagram that will be required in carrying out the setting calculations and

thus form an important part. This information is unique to each element like line, transformer,

reactor or busbar. This helps not only in carrying out the setting calculations; it also helps in

future, if there is a need to revisit this data.

2. TERMINAL IDENTIFICATION AND LIST OF FUNCTIONS: This section contains brief details

of the IED and lists all the functions that are available in the IED and clearly identifies the ones

which are activated and those that are required to be set. Thus this section serves as a checklist

of all the functions used and gives a quick overview of functions that needs to be set.

3. SETTING CALCULATIONS AND RECOMMENDED SETTINGS: This section contains

subsections viz., Setting guide lines, Setting calculations and Recommended settings for each

function.

Setting guidelines: This subsection contains guide lines for each of the parameter to be set for

the function. The guidelines are taken from the report prepared by Protection subcommittee and

CBIP guide lines mentioned in the report. In addition to the main settings the IED also has

various other settings that need to be set. Guide lines for these settings are taken mainly from

manufacturer's user manuals and these are also given here in brief. In such instances, where

the setting is straight forward and does not involve any calculations, the recommended value

are given and where applicable the reasoning for the adopted setting is given. Setting

calculation based on the relay type, relay function is a major concern for utilities and

understanding each setting and basis for setting helps in arriving at right settings. Further the

guide lines help not only in carrying out the setting calculations, but also help in future, if

there is a need to revisit the settings to take corrective actions in case of any mal-operations.

Setting calculations: This subsection contains details of calculations using system parameters

for those parameters that need calculations. Other parameters that do not require any

calculations are not covered here. Making setting calculations after understanding the power

system implications and as per setting guidelines helps not only in arriving at the right settings

but also helps in future, if there is a need to revisit them to take corrective action in case of any


- 3 -

mal-operations (if excel based sheets with macros are used for setting calculations, they should

be used cautiously in a transparent manner and explained the reasoning associated with

macros / formulae).

Recommended settings: This subsection details recommended setting list with settings for all

the parameters. Settings given in this section need to be used by site engineer for setting the

IED.

It is recommended that these model setting calculations are reviewed periodically to take care of

any changes in manufacturer's design, use of simulation tools, RTDS, or better understanding

of settings and guidelines etc. It is also recommended that setting calculation documents are

prepared for IEDs of different manufacturers that are used in the system.

Disclaimer: The model setting calculations and recommended settings presented in this

document are for the specific case considered here. Further, the make of the relay considered is

also for illustration purpose only. In the settings which do not require any calculations based on

network data, few of the settings may need review for other practical cases. For settings that

require calculations, power system network data pertaining to respective cases is to be

considered. However, the methodology adopted in this example shall be used for calculating the

line and other equipment protection relay settings and arriving at list of recommended settings.

MODEL SETTING CALCULATION DOCUMENT FOR A TYPICAL

IED USED FOR TRANSMISSION LINE PROTECTION

Model setting calculation document for Transmission Line

2

TABLE OF CONTENTS

TABLE OF CONTENTS.................................. .............................................................................2

1.0 BASIC SYSTEM PARAMETERS ............................ .............................................................8

1.1 Network line diagram of the protected line and adja cent circuits ...................................8

1.2 Single line diagram of the double circuit line..... ...............................................................9

1.3 Line parameters .................................... ..............................................................................9

2.0 TERMINAL IDENTIFICATION AND LIST OF FUNCTIONS...... ..........................................10

2.1 REL670...............................................................................................................................10

2.1.1 Terminal Identification..........................................................................................10 2.1.2 List of functions available and those used............................................................10

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

2.2.1 Terminal identification..........................................................................................16 2.2.2 List of functions available and those used............................................................16

3.0 SETTING CALCULATIONS AND RECOMMENDED SETTINGS FOR REL670................ .23

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

3.1.1 Analog Inputs.......................................................................................................23 3.1.2 Local Human-Machine Interface ..........................................................................26 3.1.3 Indication LEDs....................................................................................................26 3.1.4 Time Synchronization ..........................................................................................28 3.1.5 Parameter Setting Groups ...................................................................................31 3.1.6 Test Mode Functionality TEST.............................................................................32 3.1.7 IED Identifiers ......................................................................................................34 3.1.8 Rated System Frequency PRIMVAL ....................................................................35 3.1.9 Signal Matrix For Analog Inputs SMAI .................................................................35 3.1.10 General settings of Distance protection zones .....................................................37 3.1.11 Distance Protection Zone, Quadrilateral Characteristic (Zone 1) ZMQPDIS.........39 3.1.12 Distance Protection Zone, Quadrilateral Characteristic (Zone 2) ZMQAPDIS .....44 3.1.13 Distance Protection Zone, Quadrilateral Characteristic (Zone 3) ZMQAPDIS ......47 3.1.14 Distance Protection Zone, Quadrilateral Characteristic (Zone 5) ZMQAPDIS ......50 3.1.15 Phase Selection with Load Encroachment, Quadrilateral Characteristic FDPSPDIS

54 3.1.16 Broken Conductor Check BRCPTOC (Normally used for Alarm purpose only) ....62 3.1.17 Tripping Logic SMPPTRC....................................................................................63 3.1.18 Trip Matrix Logic TMAGGIO.................................................................................65 3.1.19 Automatic Switch Onto Fault Logic, Voltage And Current Based ZCVPSOF........66 3.1.20 Power Swing Detection ZMRPSB ........................................................................68 3.1.21 Scheme Communication Logic For Distance Or Overcurrent Protection ZCPSCH

76 3.1.22 Stub Protection STBPTOC ..................................................................................77 3.1.23 Fuse Failure Supervision SDDRFUF ...................................................................78 3.1.24 Four Step Residual Overcurrent Protection EF4PTOC ........................................81 3.1.25 Two Step Overvoltage Protection OV2PTOV.......................................................85 3.1.26 Setting of fault locator values LFL........................................................................89 3.1.27 Disturbance Report DRPRDRE ...........................................................................90

3.2 REC670 ..............................................................................................................................93


3

3.2.1 Analog Inputs.......................................................................................................93 3.2.2 Local Human-Machine Interface ..........................................................................95 3.2.3 Indication LEDs....................................................................................................96 3.2.4 Time Synchronization ..........................................................................................97 3.2.5 Parameter Setting Groups .................................................................................101 3.2.6 Test Mode Functionality TEST...........................................................................102 3.2.7 IED Identifiers ....................................................................................................103 3.2.8 Rated System Frequency PRIMVAL ..................................................................103 3.2.9 Signal Matrix For Analog Inputs SMAI ...............................................................103 3.2.10 Synchrocheck function (SYN1) ..........................................................................106 3.2.11 Autorecloser SMBRREC....................................................................................110 3.2.12 Disturbance Report DRPRDRE .........................................................................118

APPENDIX-A: COORDINATION OF 400KV LINE PROTECTION Z ONE-2 AND ZONE-3 WITH

IDMT O/C & E/F RELAYS OF 400KV SIDE OF ICT AND 220K V LINE...................................121

APPENDIX-B: EFFECT OF NETWORK CHANGE DUE TO A LINE LILO ON RELAY

SETTINGS OF LILO LINE & ADJACENT LINES............. .......................................................131


4

LIST OF FIGURES

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


5

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


6

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


7

SETTING CALCULATION EXAMPLE

SUB-STATION: Station-A

FEEDER: 400kV OHL from Station-A to Station-B

PROTECTION ELEMENT: Main-I Protection

Protection schematic Drg. Ref. No. XXXXXX


8

1.0 BASIC SYSTEM PARAMETERS

1.1 Network line diagram of the protected line and adjacent circuits The network line diagram (Figure 1-1) of the system under consideration showing

protected line along with adjacent associated elements should be collected. The

network diagram should indicate the voltage level, line length, transformer/generator

rated MVA & fault contributions of each element for 3-ph fault at station-A and for

3-ph fault at Station-B.

Figure 1-1: Network line diagram of the protected l ine


9

1.2 Single line diagram of the double circuit line

Equivalent representation of the protected line based on network line diagram indicated at Figure 1-

1 is prepared as shown in Figure 1-2 indicating the source fault impedance at station-A and Station-

B, positive and zero sequence impedance of the protected line.

Figure 1-2: Equivalent representation of the protec ted line with source impedance

1.3 Line parameters

Line: Substation-A to Substation-B

Frequency: 50Hz

Line data: R1 + jX1 = 0.0288 + j0.307 Ω/km

R0 + jX0 = 0.2689 + j1.072 Ω/km

R0M + jX0M = 0.228 + j0.662 Ω/km

Line length: 190km

CT ratio: 1000/1A

CVT ratio: 400/0.11kV

Maximum expected load on line both import and export: This shall be obtained from the load flow

analysis of the power system under all possible contingency. From the load flow studies, 1500MVA

is the maximum expected load under worst contingency on this line at 90% system voltage.

Station-A

Protected Line 190km

190km

400kV 400kV R1SA= 0.486Ω

X1SA= 13.939Ω

R1SB= 0.895Ω

X1SB=9.525Ω

Z1 = 5.472+j58.33 Ω

Z0 = 51.091+j203.68 Ω

Station-B


10

2.0 TERMINAL IDENTIFICATION AND LIST OF FUNCTIONS

The various functions required for the line protection are divided in two IEDs namely REL670 and

REC670 for the purpose of illustration. The terminal identification of this and list of various functions

available in these IEDs are given in this section.

2.1 REL670

2.1.1 Terminal Identification Station Name: Station-A

Object Name: 400kV OHL from Station-A to Station-B

Unit Name: REL670 (Ver 1.2)

Relay serial No: XXXXXXXX

Frequency: 50Hz

Aux voltage: 220V DC

2.1.2 List of functions available and those used

Table 2-1 gives the list of functions/features available in REL670 relay and also indicates the

functions/feature for which settings are provided in this document. The functions/feature are

indicative and varies with IED ordering code & IED application configuration.

Table 2-1: List of functions in REL670

Sl.No. Function/features available In REL670 Function/feature

activated

Yes/No

Recommended Settings provided

1 Analog Inputs YES

2 Local Human-Machine Interface YES

3 Indication LEDs YES

4 Self supervision with internal event list YES

5 Time Synchronization YES

6 Parameter Setting Groups YES

7 Test Mode Functionality TEST YES


11


activated

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


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

26 Power Swing Detection ZMRPSB YES


12


activated

Yes/No


27 Automatic Switch Onto Fault Logic, Voltage And Current Based ZCVPSOF YES

28 Instantaneous Phase Overcurrent Protection PHPIOC NO

29 Four Step Phase Overcurrent Protection OC4PTOC NO

30 Instantaneous Residual Overcurrent Protection EFPIOC NO

31 Four Step Residual Overcurrent Protection EF4PTOC YES

32 Sensitive Directional Residual Overcurrent And Power Protection SDEPSDE NO

33 Thermal Overload Protection, One Time Constant LPTTR NO

34 Stub Protection STBPTOC YES

35 Broken Conductor Check BRCPTOC YES

36 Two Step Undervoltage Protection UV2PTUV YES

37 Two Step Overvoltage Protection OV2PTOV YES

38 Loss Of Voltage Check LOVPTUV NO

39 General Current And Voltage Protection CVGAPC-4 functions NO

40 Current Circuit Supervision CCSRDIF NO

41 Fuse Failure Supervision SDDRFUF YES

42 Horizontal Communication Via GOOSE For Interlocking GOOSEINTLKRCV NO

43 Logic Rotating Switch For Function Selection And LHMI Presentation SLGGIO NO

44 Selector Mini Switch VSGGIO NO


13


activated

Yes/No


45 Generic Double Point Function Block DPGGIO NO

46 Single Point Generic Control 8 Signals SPC8GGIO NO

47 Automationbits, Command Function For DNP3.0 AUTOBITS NO

48 Single Command, 16 Signals SINGLECMD NO

49 Scheme Communication Logic For Distance Or Overcurrent Protection ZCPSCH YES

50 Current Reversal And Weak-End Infeed Logic For Distance Protection ZCRWPSCH NO

51 Local Acceleration Logic ZCLCPLAL NO

52 Direct Transfer Trip Logic YES

53 Low Active Power And Power Factor Protection LAPPGAPC NO

54 Compensated Over and Undervoltage Protection COUVGAPC NO

55 Sudden Change in Current Variation SCCVPTOC NO

56 Carrier Receive Logic LCCRPTRC NO

57 Negative Sequence Overvoltage Protection LCNSPTOV NO

58 Zero Sequence Overvoltage Protection LCZSPTOV NO

59 Negative Sequence Overcurrent Protection LCNSPTOC NO

60 Zero Sequence Overcurrent Protection LCZSPTOC NO

61 Three Phase Overcurrent LCP3PTOC NO

62 Three Phase Undercurrent LCP3PTUC NO


14


activated

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 Logic Node

Representation B16IFCVI NO

69 Integer To Boolean 16 Conversion IB16 NO

70 Integer To Boolean 16 Conversion With Logic Node

Representation IB16FCVB NO

71 Measurements CVMMXN YES

72 Phase Current Measurement CMMXU YES

73 Phase-Phase Voltage Measurement VMMXU YES

74 Current Sequence Component Measurement CMSQI YES

75 Voltage Sequence Measurement VMSQI YES

76 Phase-Neutral Voltage Measurement VNMMXU NO

77 Event Counter CNTGGIO YES

78 Event Function EVENT YES

79 Logical Signal Status Report BINSTATREP NO

80 Fault Locator LMBRFLO YES

81 Measured Value Expander Block RANGE_XP NO

82 Disturbance Report DRPRDRE YES


15


activated

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

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 functi on listed above, refer section 3 of

application manual 1MRK506315-UEN, version 1.2.


16

2.2 REC670

2.2.1 Terminal identification

Station Name: Station-A

Object Name: 400kV OHL

Unit Name: REC670 (Ver 1.2)

Relay serial No: XXXXX

Frequency: 50Hz



Table 2-2 gives the list of functions/features available in REC670 relay and also indicates the



Table 2-2: List of functions in REC670

Sl.No. Functions/Feature available In REC670 Features/Functions

activated

Yes/No


1 Analog Inputs YES












17


activated

Yes/No




14 Signal Matrix For Ma Inputs SMMI NO





19 Differential Protection HZPDIF NO

20 Instantaneous Phase Overcurrent Protection PHPIOC NO

21 Four Step Phase Overcurrent Protection OC4PTOC NO

22 Instantaneous Residual Overcurrent Protection EFPIOC NO

23 Four Step Residual Overcurrent Protection EF4PTOC NO

24 Four step directional negative phase sequence overcurrent protection NS4PTOC NO

25 Sensitive Directional Residual Overcurrent And Power Protection SDEPSDE NO

26 Thermal Overload Protection, One Time Constant LPTTR NO

27 Thermal overload protection, two time constants TRPTTR NO

28 Breaker Failure Protection CCRBRF NO

29 Stub Protection STBPTOC NO

30 Pole Discordance Protection CCRPLD NO


18


activated

Yes/No


31 Directional Underpower Protection GUPPDUP NO

32 Directional Overpower Protection GOPPDOP NO

33 Broken Conductor Check BRCPTOC NO

34 Capacitor bank protection CBPGAPC NO

35 Two Step Undervoltage Protection UV2PTUV NO

36 Two Step Overvoltage Protection OV2PTOV NO

37 Two Step Residual Overvoltage Protection ROV2PTOV NO

38 Voltage Differential Protection VDCPTOV NO


40 Underfrequency Protection SAPTUF NO

41 Overfrequency Protection SAPTOF NO

42 Rate-Of-Change Frequency Protection SAPFRC NO

43 General Current and Voltage Protection CVGAPC NO


45 Fuse Failure Supervision SDDRFUF NO

46 Synchrocheck, Energizing Check, And Synchronizing SESRSYN YES

47 Autorecloser SMBRREC YES

48 Apparatus Control APC NO

49 Horizontal Communication Via GOOSE For Interlocking GOOSEINTLKRCV NO


19


activated

Yes/No


50 Logic Rotating Switch For Function Selection And LHMI Presentation SLGGIO 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


56 Scheme Communication Logic For Distance Or Overcurrent Protection ZCPSCH NO

57 Phase Segregated Scheme Communication Logic For Distance Protection ZC1PPSCH NO

58 Current Reversal And Weak-End Infeed Logic For Distance Protection ZCRWPSCH NO


60 Scheme Communication Logic For Residual Overcurrent Protection ECPSCH NO

61 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 Protection COUVGAPC NO


20


activated

Yes/No


66 Sudden Change In Current Variation SCCVPTOC 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



74 Tripping Logic SMPPTRC NO

75 Trip Matrix Logic TMAGGIO NO




79 Boolean 16 To Integer Conversion With Logic Node

Representation B16IFCVI NO


81 Integer To Boolean 16 Conversion With Logic Node

Representation IB16FCVB NO




21


activated

Yes/No


84 Phase-Phase Voltage Measurement VMMXU YES

85 Current Sequence Component Measurement CMSQI YES


87 Phase-Neutral Voltage Measurement VNMMXU NO




91 Fault Locator LMBRFLO NO

92 Measured Value Expander Block RANGE_XP NO


94 Event List YES

95 Indications YES





100 Function For Energy Calculation And Demand Handling ETPMMTR NO


102 IEC 61850 Generic Communication I/O Functions SPGGIO, SP16GGIO NO

103 IEC 61850-8-1 Redundant Station Bus Communication NO


22


activated

Yes/No






108 Multiple Command And Transmit MULTICMDRCV,

MULTICMDSND NO





23

3.0 SETTING CALCULATIONS AND RECOMMENDED

SETTINGS FOR REL670

The various functions required for the line protection are divided in two IEDs namely REL670 and

REC670. The setting calculations and recommended settings for various functions available in

these IEDs are given in this section.

3.1 REL670

3.1.1 Analog Inputs

Guidelines for Settings:

Configure analog inputs:

Current analog inputs as:

Ch 1 Ch 2 Ch 3 Ch 4 Ch 5 Ch 6

Name# IL1-CB1 IL2-CB1 IL3-CB1 IL1-CB2 IL2-CB2 IL3-CB2

CTprim 1000A 1000A 1000A 1000A 1000A 1000A

CTsec 1A 1A 1A 1A 1A 1A

CTStarPoint parameter indicates the CT secondary winding neutral earthing towards object

(ToObject) or towards busbar (FromObject).

Voltage analog input as:


Name# UL1 UL2 UL3 UL2BUS1 UL2BUS2 UL2L2

VTprim 400kV 400kV 400kV 400kV 400kV 400kV

VTsec 110V 110V 110V 110V 110V 110V

# User defined text


24

Recommended Settings:

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

Table 3-1: Analog inputs

Setting Parameter Description

Recommended

Settings

Unit

PhaseAngleRef Reference channel for phase angle

Presentation TRM40-Ch1 -

CTStarPoint1 ToObject= towards protected object,

FromObject= the opposite ToObject -

CTsec1 Rated CT secondary current 1 A

CTprim1 Rated CT primary current 1000 A

















CTStarPoint6 ToObject= towards protected object, ToObject -


25


Recommended

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 I/O Module 3 On 40 30 Pos Slot3 I/O Module 4 On 40 30 Pos Slot3

I/O Module 5 On 40 30 Pos Slot3

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

response for digital input.


26

3.1.2 Local Human-Machine Interface


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

Table 3-2: Local human machine interface


Recommended

Settings

Unit

Language Local HMI language English -

DisplayTimeout Local HMI display timeout 60 Min

AutoRepeat Activation of auto-repeat (On) or not (Off) On -

ContrastLevel Contrast level for display 0 %

DefaultScreen Default screen 0 -

EvListSrtOrder Sort order of event list Latest on top -

SymbolFont Symbol font for Single Line Diagram IEC -

3.1.3 Indication LEDs

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.


27


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

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


Recommended

Settings

Unit

Operation Operation mode for the LED function On -

tRestart Defines the disturbance length 0.0 s

tMax Maximum time for the definition of a

disturbance 0.0 s

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
















28

3.1.4 Time Synchronization


These settings are used for synchronizing IED clock time with network time. Ex: GPS or IRIG-B time.

CoarseSyncSrc: Select the time synchronization source available such as SPA, LON, SNTP etc.

Synchronization messages from sources configured as coarse are checked against the internal relay

time and only if the difference in relay time and source time is more than 10s then relay time will be

reset with the source time. This parameter need to be based on time source available in site.

FineSyncSource: Select the time source available in network like IRIG-B, GPS, SNTP, SPA etc.

once it is selected, time of available time source in network will update to relay if there is a difference

in the time between relay and source. This parameter need to be based on time source available in

site.

SyncMaster: Normally it is set OFF. If time to the relay is received from a GPS antenna (example),

make the relay as master to synchronize with other relays.

TimeAdjustRate: Fast

HWSyncSrc: This is applicable if process bus IEC61850-9-2 protocol is used for receiving analog

values (optical CT PTs). In this case select time source available same as that of merging unit. This

setting is not applicable in present case.

AppSynch: If there is any loss of time sync, protection function will be blocked if AppSynch set to

Synch based on SyncAccLevel. If AppSunch set to NoSynch, protection functions are not blocked.

Recommended setting is NoSynch.

SyncAccLevel: If this is set to “Class T5 (1us)” and time synch error is more than 1us, protection

functions will be blocked. SyncAccLevel should be set to “Unspecified” when Nosynch is selected at

AppSynch. This parameter is not applicable in present case.

ModulePosition: if BIN is set for FineSyncSource, ModulePosition setting is applicable. Here slot

position of IO module in the relay is to be set (Which slot is used for BI). This parameter is not

applicable in present case.

BinaryInput: Which binary input is used for time sync input shall be set here. This parameter is

applicable if BIN is set for FineSyncSource. This parameter is not applicable in present case.

BinDetection: Which edge of input pulse need to be detected has to be set here (positive and

negative). This parameter is applicable if BIN is set for FineSyncSource. This parameter is not


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

RedServIP-Add: If redundant server is available, set address of redundant server here.


29

MonthInYear, DayInWeek, WeekInMonth and UTCTimeOfDay for DSTBEGIN and DSTEND are

applicable where Day light saving is used. If it is not used set same date for both DSTBEGIN and

DSTEND. This setting is not applicable in this case.

NoHalfHourUTC: Time shift from GMT has to be set a multiple of half hours. Example for India it is

+05:30, means +11. Hence this parameter is set to +11 in present case.

SYNCHIRIG-B Non group settings: These settings are applicable if IRIG-B is used. This parameter

is not applicable in present case.

SynchType: Type of hardware input used for time sync, whether Opto or BNC. This parameter is not


TimeDomain: In present case this parameter is set to LocalTime.

Encoding: In present case this parameter is set to IRIG-B.

TimeZoneAs1344: In present case this parameter is set to PlusTZ.


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

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


Recommended

Settings

Unit

CoarseSyncSrc Coarse time synchronization source Off -

FineSyncSource Fine time synchronization source 0.0 -

SyncMaster Activate IED as synchronization master Off -

TimeAdjustRate Adjust rate for time synchronization Off -

HWSyncSrc Hardware time synchronization source Off -

AppSynch Time synchronization mode for application NoSynch -

SyncAccLevel Wanted time synchronization accuracy Unspecified -


30

SYNCHBIN Non group settings (basic)


Recommended

Settings

Unit

ModulePosition Hardware position of IO module for time

Synchronization 3 -

BinaryInput Binary input number for time

synchronization 1 -

BinDetection Positive or negative edge detection PositiveEdge -

SYNCHSNTP Non group settings (basic)

Setting Parameter Description Recommended

Settings

Unit

ServerIP-Add Server IP-address 0.0.0.0 IP Address

RedServIP-Add Redundant server IP-address 0.0.0.0 IP Address

DSTBEGIN Non group settings (basic)


Recommended

Settings

Unit

MonthInYear Month in year when daylight time starts March -

DayInWeek Day in week when daylight time starts Sunday -

WeekInMonth Week in month when daylight time starts Last -

UTCTimeOfDay UTC Time of day in seconds when

daylight time starts 3600 s


31

DSTEND Non group settings (basic)


Recommended

Settings

Unit

MonthInYear Month in year when daylight time starts October -





TIMEZONE Non group settings (basic)


Recommended

Settings

Unit

NoHalfHourUTC Number of half-hours from UTC +11 -

SYNCHIRIG-B Non group settings (basic)


Recommended

Settings

Unit

SynchType Type of synchronization Opto -

TimeDomain Time domain LocalTime -

Encoding Type of encoding IRIG-B -

TimeZoneAs1344 Time zone as in 1344 standard PlusTZ -

Note: Above setting parameters have to be set based on available time source at site.

3.1.5 Parameter Setting Groups



32

t: The length of the pulse, sent out by the output signal SETCHGD when an active group has

changed, is set with the parameter t. This is not the delay for changing setting group. This parameter

is normally recommended to set 1s.

MAXSETGR: The parameter MAXSETGR defines the maximum number of setting groups in use to

switch between. Only the selected number of setting groups will be available in the Parameter

Setting tool (PST) for activation with the ActiveGroup function block. This parameter is normally

recommended to set 1.


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

Table 3-5: Parameter setting group

ActiveGroup Non group settings (basic)


Settings Unit

t Pulse length of pulse when setting

Changed 1 s

SETGRPS Non group settings (basic)


Recommended

Settings

Unit

ActiveSetGrp ActiveSettingGroup SettingGroup1 -

MAXSETGR Max number of setting groups 1-6 1 No

3.1.6 Test Mode Functionality TEST


EventDisable: If it is ON, it will disable the events like in DR during test mode. Normally this

parameter is set to OFF.

CmdTestBit: In present case this parameter is set to Off.



33

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


34

Table 3-6: Test mode functionality

TESTMODE Non group settings (basic)


Recommended

Settings

Unit

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

EventDisable Event disable during testmode Off -

CmdTestBit Command bit for test required or not

during testmode Off -

3.1.7 IED Identifiers


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

Table 3-7: IED Identifiers

TERMINALID Non group settings (basic)

Setting

Parameter Description

Recommended

Settings

Unit

StationName Station name Station-A -

StationNumber Station number 0 -

ObjectName Object name Line-1 -

ObjectNumber Object number 0 -

UnitName Unit name REL670 M1 -

UnitNumber Unit number 0 -


35

3.1.8 Rated System Frequency PRIMVAL


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

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


Recommended

Settings

Unit

Frequency Rated system frequency 50.0 Hz

3.1.9 Signal Matrix For Analog Inputs SMAI


DFTReference : Set ref for DFT filter adjustment here. These DFT reference block settings decide

DFT reference for DFT calculations.

The settings InternalDFTRef will use fixed DFT reference based on set system frequency.

AdDFTRefChn will use DFT reference from the selected group block, when own group selected

adaptive DFT reference will be used based on calculated signal frequency from own group. The

setting ExternalDFTRef will use reference based on what is connected to input DFTSPFC.

There are three different task groups of SMAI with 1ms, 3ms and 8ms. Use of each task group is

based on requirement of function, like differential protection requires 1ms, which is faster.

Each task group has 12 instances of SMAI, in that first instance has some additional features which

is called master. Others are slaves and they will follow master. If measured sample rate needs to be

transferred to other task group, it can be done only with master.

Receiving task group SMAI DFTreference shall be set to External DFT Ref.

DFTReference shall be set to default value InternalDFTRef if no VT input is available. Since VT input

is available in this case, the corresponding channel shall be set to DFTReference. Configuration file

has to be referred for this purpose.

DFTRefExtOut: This parameter is available only in Master. If reference is to be sent to other task

group, which reference need to be send has to be select here. For example, if voltage input is


36

connected to 3rd SMAI of 1ms task group, AdDFTRefCh3 is to be set in DFTRefExtOut of 1ms task

group.

DFTRefExtOut shall be set to default value InternalDFTRef if no VT input is available. Configuration

file has to be referred for this purpose.

Negation: Set negation of the function block here. If R, Y, B and N inputs are connected and

Negation is set to NegateN, it will give output R, Y, B and –N. If Negation is set to Negate3Ph, it will

give output -R, -Y, -B and N.

If R, Y, B inputs are connected, N=R+Y+B, and it will do as above. This parameter is recommended

to be set to OFF normally.

MinValFreqMeas: Set the measured minimum value here. It is applicable only for voltage input.

SMAI will work only if measured input magnitude is greater than set value in MinValFreqMeas. This

parameter is recommended to set 10% normally.

UBase: Set the base voltage here. This is parameter is set to 400kV.


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

Table 3-9: Signal Matrix For Analog Inputs


Recommended

Settings

Unit

DFTRefExtOut DFT reference for external output InternalDFTRef -

DFTReference DFT reference InternalDFTRef -

ConnectionType Input connection type Ph-Ph -

TYPE 1=Voltage, 2=Current 1 or 2 based on input Ch

Negation Negation Off -

MinValFreqMeas Limit for frequency calculation in % of

UBase 10 %

UBase Base voltage 400 kV


37

3.1.10 General settings of Distance protection zone s


Figure 3-1 gives the setting angles for discrimination of forward and reverse fault.

ArgDir and ArgNegRes: Set the Directional angle Distance protection zones at ArgDir and set the

Negative restraint angle for Distance protection zone at ArgNegRes.

The setting of ArgDir and ArgNegRes is by default set to 15 (= -15) and 115° respectively. It should

not be changed unless system studies have shown the necessity.

IBase: set to the current value of the primary winding of the CT. This parameter is set to 1000A in

present case.

UBase: set to the voltage value of the primary winding of the VT. This parameter is set to 400kV in

present case.

IMinOpPP: This is the minimum current required in phase to phase fault for directionality purpose.

To be set to 20% of IBase.

IMinOpPE: This is the minimum current required in phase to earth fault for directionality purpose.


Figure 3-1: Setting angles for discrimination of fo rward and reverse fault


38

Recommended Settings: Table 3-10 gives the recommended settings for General settings for distance protection.

Table 3-10: General settings for distance protectio n ZDRDIR Group settings (basic)


Recommended

Settings

Unit

IBase Base setting for current level 1000 A

UBase Base setting for voltage level 400 kV

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

IMinOpPE Minimum operate phase current for

Phase-Earth loops 20 %IB

ArgNegRes Angle of blinder in second quadrant for

forward direction 115 Deg

ArgDir Angle of blinder in fourth quadrant for

forward direction 15 Deg


39

3.1.11 Distance Protection Zone, Quadrilateral Char acteristic (Zone 1)

ZMQPDIS

General guide lines for Setting Distance protection Zones:

The zones are set directly in primary ohms R, X. The primary ohms R, X are recalculated to

secondary ohms with the current and voltage transformer ratios. Figures 3-2 and 3-3 show the

characteristics for phase-to-earth measuring and phase-to-phase measuring respectively.

The secondary values are presented as information for zone testing.

Figure 3-2: Characteristic for phase-to-earth measu ring, ohm/loop domain


40

Figure 3-3: Characteristic for phase-to-phase measu ring

Guidelines for Setting:

Zone-1:

Setting X1, R1 and X0, R0: To be set to cover 80% of protected line length. Zero sequence

compensation factor is (Z0 – Z1) / 3Z1.

RFPP and RFPE: For phase to ground faults, resistive reach should be set to give maximum

coverage considering fault resistance, arc resistance & tower footing resistance. It has been

considered that ground fault would not be responsive to line loading.

Setting of the resistive reach for the underreaching zone 1 should follow the condition to minimize

the risk for overreaching:

RFPE ≤ 4.5 × X1


41

In case of phase to phase fault, resistive reach should be set to provide coverage against all types

of anticipated phase to phase faults subject to check of possibility against load point encroachment

considering minimum expected voltage and maximum load expected during short time emergency

system condition.

To minimize the risk for overreaching, limit the setting of the zone 1 reach in resistive direction for

phase-to-phase loop measurement to:

RFPP ≤ 3 × X1.

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

current value of the primary winding of the CT. This parameter is set to 1000A in present case.

UBase: Set the Base voltage for the Distance protection zones in primary kV here. Set to the

voltage value of the primary winding of the VT. This parameter is set to 400kV in present case.

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

loop. This is the minimum current required in phase to phase fault for zone measurement. To be set

to 20% of IBase.

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

minimum current required in phase to earth fault for zone measurement. To be set to 20% of IBase.

IMinOpIN: This is the minimum 3I0 current required in phase to earth fault for zone measurement.


Setting Calculations:

OperationDir = Forward

Operation PP = On

Operation PE = On

Zone 1 phase fault reach is set to 80.0% of the total line reactance

X1Z1' = 46.664Ω Note! Zone will send carrier signal

The secondary setting will thus be

X1Z1 = 12.833Ω

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

R1Z1' = 4.378Ω


R1Z1 = 1.204Ω

Setting of zone earth fault zero sequence values

X0Z1' = 162.944Ω 80.0% of the total line reactance


42


X0Z1 = 44.81Ω

Set the zero sequence resistance for earth faults to

R0Z1' = 40.873Ω


R0Z1 = 11.24Ω

Setting of the fault resistive cover

The resistive reach(phase to Phase) is set to cover a maximum expected fault resistance arrived

from Warrington formula given below

Rarc =

It is set to 15.0 Ω. (Considering a minimum expected ph to ph fault current of 1500A and arc length

of 15meter).

Note that setting of fault resistance is the loop value whereas reactance setting is phase value for

phase faults.

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

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

from both side)

Set the resistive reach for phase faults to:

RFPPZ1' = 30Ω (loop value)


RFPPZ1 = 8.25Ω

Set the resistive reach for earth faults to

RFPEZ1´= 50Ω


RFPEZ1 = 13.75Ω

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

Zone 1 setting of timers.

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

tPP1 = On

tPE1 = On

Setting of Zone timers:

tPP1 = 0s

tPE1 = 0s


43


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

Table 3-11: ZONE 1 Settings


Settings

Unit

Operation Operation Off / On On -

IBase Base current , i.e rated current 1000 A

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

OperationDir Operation mode of directionality Forward -

X1 Positive sequence reactance reach 46.664 ohm/p

R1 Positive sequence resistance reach 4.378 ohm/p

X0 Zero sequence reactance reach 162.944 ohm/p

R0 Zero sequence resistance for zone 40.873 ohm/p

RFPP Fault resistance reach in ohm/loop , Ph-Ph 30 ohm/l

RFPE Fault resistance reach in ohm/loop , Ph-E 50 ohm/l

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

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

tPP Time delay of trip,Ph-Ph 0.000 s

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

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

tPE Time delay of trip,Ph-E 0.000 s


IMinOpPE Minimum operate phase current for Phase-Earth loops 20 %IB


44

IMinOpIN Minimum operate residual current for Phase-Earth loops 10 %IB


ZMQAPDIS


Setting X1, R1 and X0, R0:

To be set to cover minimum 120% of length of principle line section. However, in case of double

circuit lines 150% coverage must be provided to take care of under reaching due to mutual coupling

effect. Zero sequence compensation factor is (Z0 – Z1) / 3Z1.

tPP and tPE settings:

A Zone-2 timing of 0.35s (considering LBB time of 200mS, CB open time of 60ms, resetting time of

30ms and safety margin of 60ms) is set for the present case.

RFPP and RFPE:

Guidelines given for resistive reach under zone-1 is applicable here also. Due to in-feeds, the

apparent fault resistance seen by relay is several times the actual value. This should be kept in

mind while arriving at resistive reach setting for Zone-2.







to 20% of IBase.




45



Operation PP = On

Operation PE = On

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

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


X1Z2 = 24.061Ω


R1Z2' = 8.208Ω


R1Z2 = 2.257Ω


X0Z2' = 305.52Ω 150.0% of the total line reactance


X0Z2 = 84.018Ω


R0Z2' = 76.637Ω


R0Z2 = 21.075Ω


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

30.0Ω

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


RFPPZ2' = 60Ω


RFPPZ2 =16.5Ω


RFPEZ2´= 75Ω


RFPPZ2 = 20.625Ω


46

Zone 2 timers setting


tPP2 = On

tPE2 = On


tPP2 = 0.35s

tPE2 = 0.35s

Note: In this case, Zone-2 reach is not encroaching into 220kV side of the transformer due to in-

feeds and therefore zone-2 tripping delay need not be coordinated with HV side backup protection

of Transformer as explained in Appendix-I.





Recommended

Settings

Unit


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

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









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


47


Recommended

Settings

Unit



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

tPE Time delay of trip,Ph-E 0.35 s




ZMQAPDIS


Setting X1, R1 and X0, R0: Zone-3 should overreach the remote terminal of the longest adjacent

line by an acceptable margin (typically 20% of highest impedance seen) for all fault conditions.

Zero sequence compensation factor is (Z0 – Z1) / 3Z1.

tPP and tPE settings: Zone-3 timer should be set so as to provide discrimination with the

operating time of relays provided in subsequent sections with which Zone-3 reach of relay

being set, overlaps. In present case, Zone-3 time is set to 1.0s.

RFPP and RFPE: Guidelines given for resistive reach under zone-1 is applicable here also. Due to

in-feeds, the apparent fault resistance seen by relay is several times the actual value. This should

be kept in mind while arriving at resistive reach setting for Zone-3.






48



to 20% of IBase.





Operation PP = On

Operation PE = On

Setting of zone 3 Phase fault reach

Zone 3 phase fault reach is set to 120% of sum of protected line and adjacent longest lines

reactance is considered. Effect of in-feed not considered for practical reasons in the Zone-3 reach

setting.

X1Z3' = 199.304Ω


X1Z3 = 54.809Ω


R1Z3' = 18.697Ω


R1Z3 = 5.142Ω


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

reactance is considered.


X0Z3 = 191.384Ω


R0Z3' = 174.57Ω


R0Z3 = 48Ω

The resistive reach is set considering in-feed factor of 2.5 over Zone-1 resistive reach of 15.0 Ω for

Ph-Ph fault and 50Ω for Ph-E fault)


49

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

remote feeders which will make an apparent increase of the value. The setting is selected to take

care of above factors. Set the resistive reach for phase faults to:

RFPPZ3' = 75Ω (Loop value)


RFPPZ3 = 20.625Ω


RFPEZ3´= 125Ω


RFPEZ3 = 34.375Ω

Zone 3 timers setting


tPP3 = On

tPE3 = On


tPP3 = 1s

tPE3 = 1s

Note: In this case, Zone-3 reach is not encroaching into 220kV side of the transformer due to in-

feeds and therefore zone-3 tripping delay need not be coordinated with HV side backup protection

of Transformer as explained in Appendix-I.



Table 3-13: ZONE 3 Settings Setting


Recommended

Settings Unit








50

Setting


Recommended

Settings Unit





Operation

PP Operation 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

PE 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 1 s

IMinOpPP Minimum operate delta current for Phase-

Phase loops 20 %IB

IMinOpPE Minimum operate phase current for

Phase-Earth loops 20 %IB


ZMQAPDIS


Setting X1, R1 and X0, R0: Reverse reach setting shall be 50% of shortest line connected to the

local bus bar. Zero sequence compensation factor is (Z0 – Z1) / 3Z1.

tPP and tPE settings: Zone-5 time delay would only need to co-ordinate with bus bar main

protection fault clearance and with Zone-1 fault clearance for lines out of the same substation. For

this reason, Zone-5 time is set as 0.35s.

RFPP and RFPE: The Zone-5 reverse reach must adequately cover expected levels of apparent

bus bar fault resistance, when allowing for multiple in feeds from other circuits. For this reason, its

resistive reach setting is to be kept identical to Zone-3 resistive reach setting.


51







to 20% of IBase.




OperationDir = Reverse

Operation PP = On

Operation PE = On

Zone 5 phase fault reach is set to 50.0% of the shortest line reactance connected to the same bus.

X1Z5' = 6.14Ω


X1Z5 = 1.689Ω


R1Z5' = 0.576Ω


R1Z5 = 0.158Ω


X0Z5' = 21.44Ω


X0Z5 = 5.896Ω


R0Z5' = 5.378Ω


R0Z5 = 1.479Ω



RFPPZ5' = 75Ω



52

RFPPZ5 = 20.625Ω


RFPEZ5´= 125Ω


RFPPZ5 = 34.375Ω

Zone 5 (Reverse Zone) timers setting


tPP5 = On

tPE5 = On


tPP5 = 0.35s

tPE5 = 0.35s

Note: Time setting of this zone is not overlapping with zone-2 time of the adjacent shortest line on

the same bus.





Recommended

Settings

Unit




OperationDir Operation mode of directionality Reverse -







53


Recommended

Settings

Unit



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



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

t1PE Time delay of trip,Ph-E 0.35 s




54

3.1.15 Phase Selection with Load Encroachment, Quad rilateral Characteristic

FDPSPDIS

Figures 3-4, 3-5 and 3-6 show the characteristics for Phase selector and load encroachment:

1-FDPSPDIS (red line), 2-ZMQPDIS, 3-RFRvPEPHS, 4-(X1PHS+XN)/tan(60°), 5-RFFwPEPHS, 6-

RFPEZm, 7-X1PHS+XN, 8-φloop, 9-X1ZM+XN

Figure 3-4: Relation between distance protection ZM QPDIS and FDPSPDIS for phase-to-earth fault φloop>60°


55

1-FDPSPDIS (red line), 2-ZMQPDIS, 3-0.5 x RFRvPP PHS, 4- X1PHS/ tan (60°), 5-0.5 x

RFFwPPPHS, 6-0.5 x RFPPZm, 7-X1PHS, 8-X1Zm

Figure 3-5: Relation between distance protection (Z MQPDIS) and FDPSPDIS characteristic for phase-to-phase fault for φline>60°


56

RLdFw: Forward resistive reach within the load impedance area RLdRv: Reverse resistive reach within the load impedance area

ArgLd: Load angle determining the load impedance reach

Figure 3-6: Load encroachment characteristic


With the extended Zone-3 reach settings, that may be required to address the many under reaching

factors already considered, load impedance encroachment is a significant risk to long lines of an

interconnected power system. Not only the minimum load impedance under expected modes of

system operation be considered in risk assessment, but also the minimum impedance that might be

sustained for seconds or minutes during abnormal or emergency system conditions. Failure to do

so could jeopardize power system security.

For high resistive earth fault where impedance locus lies in the Blinder zone, fault clearance shall be

provided by the back-up directional earth fault relay.

IBase: Set the Base current for the Phase selection function in primary Ampere here. Set to the


UBase: set to the voltage value of the primary winding of the VT. This parameter is set to 400kV in

present case.

INBlockPP: Setting of phase-phase blocking current element for other phases at an earth fault. It is

3I0 limit for blocking phase-to-phase measuring loop. To be set 40% of IPh.

INReleasePE: Setting of Neutral release current (shall be set below minimum neutral current

expected at earth faults) here. It is the setting for the minimum residual current needed to enable

operation in the phase to earth fault loops (in %). To be set 20% of IPh.


57

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

3.I0 ≥ 0.5× IMinOpPE

|3.I0| ≥ . Iphmax

where:

IMinOpPE is the minimum operation current for forward zones

Iphmax is the maximum phase current in any of three phases.

Conditions that have to be fulfilled in order to release the phase-to-phase loop are:

3I0 < IMinOpPE

|3.I0| < . Iphmax

where:

IMinOpPE is the minimum operation current for earth measuring loops,

Iphmax is maximal magnitude of the phase currents.

Guidelines for Load encroachment:

The minimum load impedance can be calculated on the basis of maximum permitted power flow of

1500MVA over the protected line and minimum permitted system voltage. Minimum permitted system

voltage assumed is 360kV (90% of base voltage)

For setting angle for load blinder, a value of 30° is set which is adequate.

Guidelines for Phase selection:

Reactive reach

The reactive reach in forward direction must as minimum be set to cover the measuring zone used

in the Teleprotection schemes, mostly zone 2.

X1PHS ≥ 1.44 × X1Zm

X0PHS ≥ 1.44 ×X0Zm

where:

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

safety margin

X0Zm is the zero-sequence reactive reach for the zone to be covered by FDPSPDIS

The reactive reach in reverse direction is automatically set to the same reach as for forward

direction. No additional setting is required.

Fault resistance reach

The resistive reach must cover RFPE for the overreaching zone to be covered, mostly zone 2.

RFFwPEmin ≥ 1.1 × RFPEZm


58

where:

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

Phase-to-earth fault in reverse direction

Reactive reach

The reactive reach in reverse direction is the same as for forward so no additional setting is

required.

Resistive reach

The resistive reach in reverse direction must be set longer than the longest reverse zones. In

blocking schemes it must be set longer than the overreaching zone at remote end that is used in the

communication scheme.

RFRvPE ≥ 1.2 ×RFPE ZmRv

Phase-to-phase fault in forward direction

Reactive reach

The reach in reactive direction is determined by phase-to-earth reach setting X1.

No extra setting is required.

Resistive reach

In the same way as for phase-to-earth fault, the reach is automatically calculated based on setting

X1. The reach will be X1/tan(60°) =X1/ √(3).

Fault resistance reach

The fault resistance reaches in forward direction RFFwPP, must cover RFPPZm with at least 25%

margin. RFPPZm is the setting of fault resistance for phase to phase fault for the longest

overreaching zone to be covered by FDPSPDIS

RFFwPP ≥ 1.25 × RFPPZm

where:

RFPPZm is the setting of the longest reach of the overreaching zones that must be covered by

FDPSPDIS .

RFRvPP ≥ 1.25 × RFPPzmRv

The proposed margin of 25% will cater for the risk of cut off of the zone measuring characteristic

that might occur at three-phase fault when FDPSPDIS characteristic angle is changed from 60° to

90°.



to 20% of IBase.


59




Calculations for Load encroachment:

Ur = 400kV, Umin = 0.90x400 = 360kV,

CT ratio = 1000/1A and PT ratio = 400kV/110V

Maximum load in MVA = 1500

ZLmin = 360 x 360/ (1500),

= 86.4Ω

RLmin = 86.4 x cos30 = 74.82Ω. Since considered load angle = 30°

RLdFw = 74.82Ω

It is important to adjust the setting of load encroachment resistance RLdFw in Phase selection with

load encroachment (FDPSPDIS) to the value equal to or less than the calculated value of RLdInFw

in power swing.

In present case RLdInFw = 54.62Ω (calculations are given in PSB settings)

But calculated value of RLdFw for a maximum load of 1500MVA is 74.82Ω. Hence as per the above

recommendation from manual, RLdFw is set to 54.62Ω instated of 74.82Ω.

RLdFw = 54.62Ω.


RLdFw' = 11.375Ω

Set the load limitation in the reverse (import) direction

RLdRv = 41.297Ω


RLdRv' = 11.375Ω

Set the angle of the load limitation line

ARGLd = 30°

Calculations for Phase selection:

Phase selector phase fault reach is set to 144.0% of Zone 2 reach setting as per REL670 manual.

Positive sequence reactance as set for the reach of phase selectors in reactive direction

X1 = 125.993Ω (1.44 x Zone-2 X1)


X1" = 34.648Ω

Earth fault reach zero sequence component is set to 144.0% of Zone 2 zero sequence value


60

Zero sequence reactance as set for the reach of phase selectors in reactive direction at phase-to-

earth faults

X0 = 439.95Ω


X0" = 120.986Ω

Reach of the phase selector in resistive direction at ph-to-ph faults (Note! In ohms per loop)

RFFwPP = 75Ω (1.25 x Zone-2 RFPP) RFRvPP = 75Ω


RFFwPP" = 20.625Ω RFRvPP" = 20.625Ω

Reach of the phase selector in resistive direction at phase-to-earth faults

RFFwPE = 90Ω (1.2 x Zone-2 RFPE) RFRvPE = 90Ω


RFFwPE" = 24.75Ω RFRvPE" = 24.75Ω

Note: The reach of phase selectors should cover only zone-2. If it is set to cover zone-3 it may

become large and phase selection may not be accurate.

Operation of impedance based measurement

OperationZ< = On

Operation of current based measurement

OperationI> = On

Start value for phase over-current element

IPh> = 120% x Ibase

Start value for trip from 3I0 over-current element

IN> = 20% x Ibase

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

TimerPP = Off

Time delay to trip, Ph-Ph

tPP = 3.000s

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

TimerPE = Off

Time delay to trip, Ph-E

tPE = 3.000s


61


Table 3-15 gives the recommended settings for Phase Selection with Load Encroachment,

Quadrilateral Characteristic.

Table 3-15: Phase Selection with Load Encroachment, Quadrilateral Characteristic


Recommended

Settings

Unit


UBase Base voltage , i.e rated voltage 400 kV

INBlockPP 3Io limit for blocking phase-to-phase measuring loops 40 %IPh

INReleasePE 3Io limit for releasing phase-to-earth measuring loops 20 %IPh

RLdFw Forward resistive reach within the load impedance area 54.62 ohm/p

RLdRv Reverse resistive reach within the load impedance area 54.62 ohm/p

ArgLd Load angle determining the load impedance reach 30 Deg



RFFwPP Fault resistance reach Ph-Ph, forward 75 ohm/l

RFRvPP Fault resistance reach Ph-Ph, reverse 75 ohm/l

RFFwPE Fault resistance reach Ph-E, forward 90 ohm/l

RFRvPE Fault resistance reach Ph-E, reverse 90 ohm/l


IMinOpPE 3Io limit for blocking phase-to-earth measuring loops 20 %IB

OperationZ< Operation of impedance based On -


62


Recommended

Settings

Unit

measurement

OperationI> Operation of current based measurement On -

IPh> Start value for phase over-current element 120 %IB

IN> Start value for trip from 3I0 over-current element 20 %IB

TimerPP Operation mode Off / On of Zone timer, Ph-Ph Off -

tPP Time delay to trip, Ph-Ph 3.000 s

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

tPE Time delay to trip, Ph-E 3.000 s

3.1.16 Broken Conductor Check BRCPTOC (Normally use d for Alarm purpose

only)


Broken conductor check BRCPTOC must be set to detect open phase/s (series faults) with different

loads on the line. BRCPTOC must at the same time be set to not operate for maximum asymmetry

which can exist due to, for example, not transposed power lines.

All settings are in primary values or percentage.

IBase: Set the Base current for the function on which the current levels are based. Set IBase to

power line rated current or CT rated current. This parameter is set to 1000A in present case.

IP>: Set the operating current for BRC function at which the measurement starts. Unsymmetry for

trip is 20% Imax-min. Set minimum operating level per phase IP> to typically 10-20% of rated

current. Normally this parameter is recommended to set 20% of IBase.

Iub>: Set the unsymmetry level. Note! One current must also be below 50% of IP. Set the

unsymmetrical current, which is relation between the difference of the minimum and maximum

phase currents to the maximum phase current to typical Iub> = 50%.


63

For example, If line load current is 1000A, 1000A and 1000A in all 3 phases, when an conductor is

broken in R-ph, currents will be 0A, 1000A and 1000A respectively. Then Iub = (1000-0)/1000 =

100%, which is more 50% (set value), hence relay will give Alarm/trip.

Note that it must be set to avoid problem with asymmetry under minimum operating conditions.

tOper: Setting of the time delay for the alarm or trip of function. This parameter is normally set to

20s.

tReset : Time delay in reset. This parameter is normally set to 0.1s.


Table 3-16 gives the recommended settings for Broken Conductor Check. Table 3-16: Broken Conductor Check


Recommended

Settings

Unit


IBase IBase 1000 A

Iub> Unbalance current operation value in percent of max current 50 %IM

IP> Minimum phase current for operation of Iub> in % of Ibase 20 %IB

tOper Operate time delay 20.00 s

tReset Time delay in reset 0.100 s

3.1.17 Tripping Logic SMPPTRC


All trip outputs from protection functions has to be routed to trip coil through SMPPTRC.

For example, If there is a transient fault, trip output from distance function will not be long enough to

open breaker in case Distance function trip signal is directly connected to Trip coil. SMPPTRC

function will give a pulse of set length (150ms) even if trip signal is obtained for transient fault.


64

tTripMin: Sets the required minimum duration of the trip pulse. It should be set to ensure that the

breaker is tripped and if a signal is used to start Breaker failure protection CCRBRF longer than the

back-up trip timer in CCRBRF. Normal setting is 0.150s.

Program: For Line protection trip, this parameter is recommended to be set to 1ph/3ph. If only 3-ph

trip is required, this needs to be set to 3 phase. In present case it is to be set to 1ph/3ph.

tWaitForPHS: It Secures 3-pole trip when phase selection fails. For example, if fault is at 90% of

protected line in R-ph, Zcom trip is obtained using scheme communication. SMPPTRC will wait for

Zone-2 R-ph sart till the time delay set in tWaitForPHS to trip R-ph at local end. If no Zone-2 R-ph

start from local end, it will issue a 3-ph trip after the time delay set in tWaitForPHS. This parameter

is set to 0.050s.

TripLockout: If this set to ON, Trip output and CLLKOUT both will be latched. If it is set off, only

CLLKOUT will be latched. Normally recommended setting is OFF.

AutoLock: If it is ON, lockout will be with both trip and SETLKOUT input. If it is set to OFF, lockout

will be with only SETLKOUT input. This parameter is normally recommended to be set to OFF.


Table 3-17 gives the recommended settings for Tripping Logic.

Table 3-17: Tripping Logic


Recommended

Settings

Unit


Program Three ph; single or three ph; single, two or three ph trip 1ph/3ph -

tTripMin Minimum duration of trip output signal 0.150 s

tWaitForPHS Secures 3-pole trip when phase selection failed 0.050 s

TripLockout On: activate output (CLLKOUT) and trip latch, Off: only outp Off -

AutoLock On: lockout from input (SETLKOUT) and trip, Off: only inp Off -


65

3.1.18 Trip Matrix Logic TMAGGIO


This function is only for the OR operation of any signals (normally used for trip signals). For

example, all distance 3-ph trips (from z-2, z-3 and z-4), SOTF trip, TOV, TOC and TEF trips using

TMAGGIO function.

PulseTime: Defines the pulse time delay. When used for direct tripping of circuit breaker(s) the

pulse time delay shall be set to approximately 0.150s in order to obtain satisfactory minimum

duration of the trip pulse to the circuit breaker trip coils. If TMAGGIO is used without SMPPTRC, set

pulse width of trip signal from TMAGGIO in PulseTime.

OnDelay: It is delay for output from TMAGGIO. If it is set to 100ms, even if trip is available, it will

not give output till 100ms. Hence it should be set to 0s. OnDelay timer is to avoid operation of

outputs for spurious inputs.

OffDelay: time delay for output to reset after inputs got reset. For example, if it set to 100ms as

OffDelay, even if trip goes OFF, the output will appear 100ms. If “steady” mode is used, pulsetime

setting is not applicable, then output can be prolonged to 150ms with this setting. If TMAGGIO is

used with SMPPTRC, this should be set to 0s.

ModeOutput1, ModeOutput2, ModeOutput3: To select whether steady or pulsed. If steady is

selected, it will give output till input is present if OffDelay is set to zero. If pulsed is sleceted, output

will be same as that of SMPPTRC.


Table 3-18 gives the recommended settings for Trip Matrix Logic.

Table 3-18: Trip Matrix Logic Setting


Recommended

Settings Unit


PulseTime Output pulse time 0.0 s

OnDelay Output on delay time 0.0 s

OffDelay Output off delay time 0.0 s

ModeOutput1 Mode for output ,1 steady or pulsed Steady -

ModeOutput2 Mode for output 2, steady or pulsed Steady -



66

3.1.19 Automatic Switch Onto Fault Logic, Voltage A nd Current Based

ZCVPSOF


Mode: The operation of ZCVPSOF has three modes for defining the criteria for trip. When Mode is

set to Impedance, the operation criteria is based on the start of overeaching zone from impedance

zone measurement (Normally zone-2). A non-directional output signal should be used from an

overreaching zone. The selection of Impedance mode gives increased security. Impedance mode is

selected in present case.

AutoInit: Automatic activating of the ZCVPSOF function is by default set to Off. If automatic

activation Deadline detection is required, set the parameter Autoinit to On. Otherwise the logic will be

activated by an external BC input. It is set to OFF in present case and the logic has to be activated

by an external BC input.

If Autoinit mode=OFF, only Breaker Close (BC) input is used to detect dead line condition.

If Autoinit mode=ON, either UI Level detection of internal funciton or Breaker Close (BC) input is

used to detect dead line condition.

It has been assumed that in the present case CB clo se command input is available to the

relay as external binary input.

tSOTF: Time of SOTF function active status after breaker closed in impedance mode. This is

normally set to 0.2s. It means, till 0.2s, SOTF function will be active after breaker closed.

IBase: Set the Base current for the SOTF function in primary Ampere. This parameter is set to

1000A in present case.

UBase: Setting of the Base voltage level on which the Dead line voltage is based. This parameter is

set to 400kV in present case.

IPh<: Setting of under current. This setting is applicable only if mode=UILevel or UILv&Imp and

Autoinit mode=ON. In present case, this parameter is not applicable.

UPh<: Setting of the U< voltage. This setting is applicable only if mode=UILevel or UILv&Imp and

Autoinit mode=ON. In present case, this parameter is not applicable.

tDuration: Set the required duration of low UI check to achieve operation (to ensure dead line

condition). This setting is applicable only if mode=UILevel or UILv&Imp. In present case, this

parameter is not applicable.

tDLD: Set the required time for all currents and all voltages to be low to Auto Initiate the SOTF

function. This setting is applicable only if Autoinit mode=ON. In present case, this parameter is not

applicable.


67


Table 3-19 gives the recommended settings for Automatic Switch Onto Fault Logic.

Table 3-19: Automatic Switch Onto Fault Logic


Recommended

Settings

Unit


IBase Base current (A) 1000 A

UBase Base voltage L-L (kV) 400 kV

Mode Mode of operation of SOTF Function Impedance -

AutoInit Automatic switch onto fault initialization Off -

IPh< Current level for detection of dead line in % of IBase 20 %IB

UPh< Voltage level for detection of dead line in % of UBase 40 %UB

tDuration Time delay for UI detection (s) 0.5 s

tSOTF Drop off delay time of switch onto fault function 0.2 s

tDLD Delay time for activation of dead line detection 0.15 s


68

3.1.20 Power Swing Detection ZMRPSB

The various settings for power swing detection are shown in Figure 3-7.

Note: setting parameters are in italic and refer Table 3-20 for notations

Figure 3-7: Operating characteristic for ZMRPSB fun ction


There are a number of options one can select in implementing power-swing protection in their

system. Designing the power system protection to avoid or preclude cascade tripping is a

requirement of the power system. Below are two possible options:


69

• Block all Zones except Zone-I • Block All Zones and Trip with Out of Step (OOS) Function

In present case Relay is configured for Block all zones except Zone-1.

Settings for inner and outer characteristics of Power swing function are set as per guidelines given

in Application manual and Technical reference manual of REL670. Timer settings are to be set on

the following assumptions.

Maximum possible initial frequency of power oscillation Ȕsi = 1.5Hz

Maximum possible consecutive frequency of power oscillation Ȕsc = 5Hz

These values will decide tP1 and tP2 setting parameters.

tH: System studies should determine the settings for the hold timer tH. The purpose of this timer is,

to secure continuous output signal from Power swing detection function (ZMRPSB) during the

power swing, even after the transient impedance leaves ZMRPSB operating characteristic and is

expected to return within a certain time due to continuous swinging. Consider the minimum possible

speed of power swinging in a particular system.

In the absence of above information, timer tH is set to 0.5s.

tP1 and tP2: The tP1 timer serve as detection of initial power swings, which are usually not as fast

as the later swings are. The tP2 timer become activated for the detection of the consecutive swings,

if the measured impedance exit the operate area and returns within the time delay, set on the tW

waiting timer.

When initial swing comes, its speed should be more than tP1, once it leaves the characteristics

timer tW starts. If swing comes again within tW, its speed shall be more than tP2. Otherwise if it

comes again after tW, its speed shall be more than tP1.

tR1, tR2 and tEF timers are Inhibit timers. These timers are used to release PSB blocking under

certain conditions.

tEF: The setting of the tEF timer must cover, with sufficient margin, the opening time of a circuit

breaker and the dead-time of a single-phase autoreclosing together with the breaker closing time.

tEF is used to release PSB blocking when the circuit breaker closes onto persistent single-phase

fault after single-phase auto reclosing dead time. This parameter is not applicable in present case.

tR1: The tR1 inhibit timer delays the influence of the detected residual current on the inhibit criteria

for ZMRPSB. It prevents operation of the function for short transients in the residual current

measured by the IED.

tR1 is used to release PSB blocking if an earth-fault appears during the power swing (input

IOCHECK is high) and the power swing has been detected before the earth-fault (activation of the


70

signal I0CHECK). If residual current persist for more than tR1 set delay, PSB allows Distance

protection to trip. Otherwise Directional Earth fault protection has to issue trip under this condition.

Above two timers tR1 and tEF requires a binary start input from a Directional Earth fault function.

This has to be configured during IED engineering. Normally timer tR1 is recommended to be set to

0.3s and tEF can be set to 2s (since 1ph dead time is 1s).

tR2: The tR2 inhibit timer disables the output START signal from ZMRPSB function, if the measured

impedance remains within ZMRPSB operating area for a time longer than the set tR2 value. This

time delay was usually set to approximately two seconds in older power-swing devices.

tR2 is used to release PSB blocking if the power swing has been detected and measured

impedance remains within its PSB operate characteristic for the set time delay tR2.

Setting Calculations: Setting of the positive sequence reactance for PSB function to operate in Forward direction

X1InFw = 219.234Ω gives X1InFw"=60.289Ω

Where X1lnFw = X1lnRv = 1.1 * maximum of all zone’s X1 (In present case, it is zone-3)

Setting of the line resistance for the characteristic angle of the characteristic

R1LIn = 18.697Ω gives R1LIn"= 5.142Ω

Where R1Lln = maximum of all zone’s R1(In present case, it is zone-3)

Setting of the resistance for PSB function to operate in Forward direction

R1FInFw = 82.5Ω gives R1FInFw"= 22.69Ω

Where R1FlnFw = R1FlnRv = 1.1 * maximum of all zone’s RFPP(In present case, it is zone-3)

Setting of the positive sequence reactance for PSB function to operate in reverse direction

X1InRv = 219.234Ω gives X1InRv"=60.289Ω

Setting of the resistance for PSB function to operate in reverse direction

R1FInRv = 82.5Ω gives R1FInRv"= 22.69Ω

Setting of the Power Swing Detection, Load enchroachment factor ON-OFF

OperationLdCh = On

Setting of the Outer Load resistance in forward direction for the Load enchroachment function, when

utilized

RLdOutFw = KL × RLmin, where RLmin = 74.82Ω and KL = 0.9 for the lines

>150km

Since this factor is already consider in arriving at maximum load MVA (1500MVA) same is not

considered again here through the factor KL.

Hence RLdOutFw = 74.82Ω gives RLdOutFw"= 20.576Ω


71

Setting of the Outer Load resistance in Reverse direction for the Load enchroachment function,

when utilized

RLdOutRv = 74.82Ω gives RLdOutRv"= 20.576Ω

Calculations for kLdRFw and kLdRRv:

RLdInFw = kLdRFw× RLdOutFw

System Impedance, Zs = Local end source Impedance + Remote end source Impedance + Protected

Line Impedance

Local end source Impedance = (kV)2/fault MVA = (400kV)2 / (1.732 x 400kV x 18.55kA) = 12.45Ω at

80°

Remote end source Impedance = (kV)2/fault MVA = (400kV)2 / (1.732 x 400kV x 24.81kA) = 9.308Ω at

80°

Local and remote end source impedance angles are assumed as 80°.

Hence System Impedance, Zs = 12.45Ω at 80° + 9.308Ω at 80° + 58.59Ω at 84.6° = 80.297Ω at

83.36°

tP1=

Where

= 2 arc tan = 56.44°

and

= 2 arc tan

where RLdInFwmax = 0.8 x RLdOutFw = 67.7°

Now tP1= where = 1.5Hz

tP1 = 0.021 which is less than 30ms(Minimum)

Hence tP1 = 30ms

= 360° tP1min + where = 1.5Hz

Hence = 72.64°


72

tP2max= where = 5Hz

Hence tP2 = 9ms

= = 54.62Ω

kLdRFw = = 0.73

It is important to adjust the setting of load encroachment resistance RLdFw in Phase selection with

load encroachment (FDPSPDIS) to the value equal to or less than the calculated value of RLdInFw.

In present case RLdInFw = 54.62Ω

But calculated value of RLdFw for a maximum load of 1500MVA is 74.82Ω. Hence as per the above

recommendation from manual, RLdFw is set to 54.62Ω instated of 74.82Ω.

RLdFw = 54.62Ω.

It is at the same time necessary to adjust the load angle in FDPSPDIS to follow the condition

presented in equation below

≥ arc tan

ArgLdPHS = 30°

Hence by using above equation ArgLdPSD = 19.43° need to be set in relay.

Setting of the PSD timers:

Initial PSD timer tP1 = 0.030s

Fast PSD timer tP2 = 0.011s

hold timer for initiate of Fast PSD timer tW = 0.250s

Hold timer for PSD detected tH = 0.500s

timer overriding 1-ph Reclosing tEF = 2.000s

to delay block by the IN current tR1 = 0.300s

Blocking output at slow swings tR2 = 2.000s

Note: These settings need to be verified for minimum source impedance (Maximum Fault level)

and maximum source impedance (Minimum Fault level) conditions.

Time for first swing and second swing shall be calculated using below equations


73


Table 3-20 gives the recommended settings for Power Swing Detection.

Table 3-20: Power Swing Detection


Recommended

Settings

Unit

Operation Operation Mode On/Off On -

X1InFw Inner reactive boundary , forward 219.234 ohm

R1LIn Line resistance for inner characteristic angle 18.697 ohm

R1FInFw Fault resistance coverage to inner resistive line , forward 198 ohm

X1InRv Inner reactive boundary , reverse 219.234 ohm

R1FInRv Fault resistance line to inner resistive boundary , reverse 198 ohm

OperationLdCh Operation of load discrimination characteristic On -

RLdOutFw Outer resistive load boundary , forward 74.82 ohm

ArgLd Load angle determining load impedance area 19.43 Deg

RLdOutRv Outer resistive load boundary , reverse 74.82 ohm

kLdRFw Multiplication factor for inner resistive load boundary , forward 0.73 Mult

kLdRRv Multiplication factor for inner resistive load boundary , reverse 0.73 Mult

tEF Timer for overcoming single - pole reclosing dead time. 2.000 s

IMinOpPE Minimum operate current in % of Ibase. 20.000 %IB

IBase Base setting for current level settings. 1000 A

tP1 Timer for detection of initial power swing 0.03 s


74


Recommended

Settings

Unit

tP2 Timer for detection of subsequent power swings 0.011 s

tW Waiting timer for activation of tP2 timer 0.25 s

tH Timer for holding power swing START output 0.5 s

tR1 Timer giving delay to inhibit by residual current 0.3 s

tR2 Timer giving delay to inhibit at very slow swing 2.0 s


75

Figure 3-8 and 3-9 show the graphical representation of the following in R-X plane.

Zone-1

Zone-2

Zone-3

Zone-5

PHS with Load encroachment

PSD

Figure 3-8: Characteristics for Phase to Phase faul ts


76

Figure 3-9: Characteristics for Phase to Earth faul ts

3.1.21 Scheme Communication Logic For Distance Or O vercurrent Protection

ZCPSCH

Guidelines for Setting

If Permissive Underreach is set, tCoord and tSendMin settings are applicable.

tCoord: Received communication signal is combined with the output from an overreaching zone till

the set duration in tCoord. There is less concern about false signal causing an incorrect trip.

Therefore set the timer tCoord to zero.

tSendMin: To assure a sufficient duration of the received signal (CR) at the remote end, the send

signal (CS) at local end can be prolonged by a tSendMin reset timer. The recommended setting of

tSendMin is 100ms.


77


Table 3-21 gives the recommended settings for Scheme Communication Logic For Distance Or

Overcurrent Protection.

Table 3-21: Scheme Communication Logic For Distance Or Overcurrent Protection


Recommended

Settings

Unit

Operation Operation Mode On/Off On -

SchemeType Scheme type Permissive UR -

tCoord Co-ordination time for blocking communication scheme 0.000 s

tSendMin Minimum duration of a carrier send signal 0.100 s

Unblock Operation mode of unblocking logic Off -

tSecurity Security timer for loss of carrier guard detection 0.035 s

3.1.22 Stub Protection STBPTOC


I>: Current level for the Stub protection is set in % of IBase. This parameter should be set so that all

faults on the stub can be detected. The setting should thus be based on fault calculations. This

should not mal-operate for through faults due to spill currents. Recommended setting is 250% of

IBase.

t: Time delay of the operation. Normally the function shall be instantaneous. Due to mismatch of

CT, during transient conditions for external faults, time can be set to 50ms.

ReleaseMode: Select whether the function shall operate continuous or only at release from release

input. Setting Releasemode shall be set to Release mode when this protection needs to be

activated with Line isolator open status. If “Continuous” mode of operation is selected, this

protection will be active irrespective of external binary input (Like line isolator status). This

protection is recommended to be set to “Release”.


78

IBase: Set the Base current for the function on which the current levels are based. This parameter

is set to 1000A in present case.


Table 3-22 gives the recommended settings for Stub Protection.

Table 3-22: Stub Protection


Recommended

Settings

Unit


IBase Base current 1000 A

ReleaseMode Release of stub protection Release -

I> Operate current level in % of IBase 250 %IB

t Time delay 0.050 s

3.1.23 Fuse Failure Supervision SDDRFUF

Guidelines for Setting

Setting for OpMode: Setting of the operating mode for the Fuse failure supervision. Zero sequence

based fuse fail detection is enabled and settings for the same are given based on below

recommendations.

3U0> and 3I0<: The setting of 3U0> should not be set lower than maximal zero sequence voltage

during normal operation condition. The setting of 3I0< must be higher than maximal zero sequence

current during normal operating condition. In present case, 3U0> is set to 30% of UBase and 3I0< is

set to 10% of IBase.

3U2> and 3I2<: These parameters are not applicable if OpMode is selected to UZsIZs.

DUDI: This is another philosophy for detecting fusefail like Zero sequence based and Negative

sequence based algorithm. If OpMode is set to UZsIZs and OpDUDI is kept ON, fusefail detection

will be OR operation of these two modes. This is recommended to set ON.


79

DU> and DI<: DUDI method will measure the difference in voltage (should be more than set in

DU>) and difference in current (should be less than set in DI<). DU> is recommended to set 60% of

UBase and DI< is recommended to set 15% of IBase.

UPh> and IPh>: For DUDI mode, voltage in the corresponding phase shall be more than set value

in UPh> for 1.5cycles before actual fuse fail condition and current should be more than set value in

IPh> before fuse fail. UPh> is recommended to set 70% of UBase and IPh> is recommended to set

10% of IBase.

A criterion based on delta current and delta voltage measurements can be added to the fuse failure

supervision function in order to detect a three phase fuse failure, which in practice is more

associated with voltage transformer switching during station operations. In present case, this

parameter is set ON.

SealIn: Setting of the seal-in function On-Off giving seal-in of alarm until voltages are symmetrical

and high. If sealin is ON and fusefail persists for more than 5s, outputs blockz and blocku will get

sealin (means latched) until any one phase voltage is less than USealIn< setting. It will release

when all three voltages goes above USealIn< setting. In present case, this parameter is made ON

and recommended setting for USealIn< is 70% of UBase.

Dead line detection: If any phase voltage is less than UDLD< set value and corresponding current

is less than IDLD< set value, this will consider as dead line and it will block Z only, it will not block U.

There is no ON or OFF for this philosophy.

During real fuse fail condition, FF function will block both Z and U. UDLD< is recommended to set to

60% of UBase and IDLD< is recommended to set 5% of IBase.

UBase: Setting of the Base voltage level on which the voltage setting is based. In present case this

parameter is set to 400kV.

IBase: Set the Base current for the function on which the current levels are based. In present case

this parameter is set to 1000A.


Table 3-23 gives the recommended settings for Fuse Failure Supervision.

Table 3-23: Fuse Failure Supervision


Recommended

Settings

Unit



80


Recommended

Settings

Unit



OpMode Operating mode UZsIZs -

3U0> residual overvoltage element in % of Ubase 30 %IB

3I0< Operate level of residual undercurrent element in % of Ibase 10

%IB

3U2> Operate level of neg seq overvoltage element in % of Ubase 20

%IB

3I2< Operate level of neg seq undercurrent element in % of Ibase 10

%IB

OpDUDI Operation of change based function Off/On On -

DU> Operate level of change in phase voltage in % of Ubase 60 %UB

DI< Operate level of change in phase 15 %IB

UPh> Operate level of phase voltage in % of Ubase. 70 %UB

IPh> Operate level of phase current in % of IBase 10 %IB

SealIn Seal in functionality Off/On On -

USealln< Operate level of seal-in phase voltage in %of Ubase 70 %UB

IDLD< Operate level for open phase current detection in % of IBase 5 %IB

UDLD< Operate level for open phase voltage 60

%UB


81

3.1.24 Four Step Residual Overcurrent Protection EF 4PTOC


The ground over current threshold should be set to ensure detection of all ground faults, but above

any continuous residual current under normal system operation. The timing should be coordinated

with the Zone-3 timing for a remote end bus fault.

IBase: Set the Base current for the function on which the current levels are based. This parameter

is set to 1000A in present case.

UBase: Setting of the Base voltage level on which the directional polarizing voltage is based. This

parameter is set to 400kV in present case.

DirMode1: Setting of the operating direction for the stage or switch it off. This parameter is set to

“Forward” in present case.

Characteristic1: Setting of the operating characteristic. This parameter is set to “IEC Norm. Inv.” in

present case.

IN1>: Setting of the operating current level in primary values. This parameter is set to 20% of base

current in present case.

IN1Mult: Set the current multiplier for IN1 valid at activation of input ENMULT. As this parameter is

not applicable in present case, setting is left with default value of 1.

t1: When definite time characteristic has been selected, set the definite time delay. This parameter


k1: Set the back-up trip time delay multiplier for inverse characteristic. Refer Appendix-I for more

details.

t1Min: Set the Minimum operating time for inverse characteristic. This parameter is set more than

Zone-3 operating time. Hence this parameter is set to 1.1s in present case.

ResetTypeCrv1: Select the reset curve type for the inverse delay. This parameter is recommended

to set “Instantaneous”. However, to emulate the disc reset behavior, this can be set to IEC.

tReset1: Set the Reset time delay for definite time delayed function. This parameter is not

applicable if ResetTypeCrv1 is set to Instantaneous.

HarmRestrain1: Set the release of Harmonic restraint blocking for the stage. This parameter is kept

ON by considering Trafo charging directly through line.

polMethod: Set the method of directional polarizing to be used. If it is set as “Voltage”, it will

measure 3U0 from 3 phase voltages and -3U0 is reference. If it is set “Current”, it will measure 3I0

from I3PPOL input and calculate 3U0 using RNPol and XNPol values. If it is set “Dual”, it will

consider sum of above two voltages for reference. In present case, it is set to “Voltage”.


82

UPolMin: Setting of the minimum neutral point polarizing voltage level for the directional function.

Generally this parameter is recommended to set 1% of base voltage.

IPolMin, RNPol, XNPol : These parameters are not applicable if polMethod is set to “Voltage”.

AngleRCA: Set the relay characteristic angle, i.e. the angle between the neutral point voltage and

current. This parameter is recommended to be set to 65°.

IN>Dir: Minimum current required for directionality. This should be lower than pickup of earth fault

protection. This parameter is normally recommended to be set to 10% of the base current.

2ndHarmStab: Setting of the harmonic content in IN current blocking level. This is to block earth

fault protection during inrush conditions. Setting is in percentage of I2/I1. This parameter is normally

recommended to be set to 20%.

BlkParTransf: Set the harmonic seal-in blocking at parallel transformers on if problems are

expected due to sympathetic inrush. If residual current is higher during switching of a transformer

connecting in parallel with other transformer and if 2nd harmonic current is lower than 2ndHarmStab

set value, earth fault protection may operate because of high residual current. Inrush current in Line

CTs may be higher at beginning and later it may be reduced. If “BlkParTransf” is set ON, protection

will be blocked till residual current is lower than set pickup of selected “UseStartValue”. This

parameter is normally recommended to be set to OFF.

UseStartValue: Select a step which is set for sensitive earth fault protection for above blocking.

This parameter is not applicable if BlkParTransf is set to OFF.

SOTF: Set the SOTF function operating mode. If “SOTF” is set ON, as per the logic given in TRM,

trip from SOTF requires start of step-2 or step-3 along with the activation of breaker closing

command. Since Directional earth function has IDMT characteristics, SOTF is set to OFF.

ActivationSOTF, ActUndertime, t4U, tSOTF, tUndertim e, HarmResSOTF: These parameters are

not applicable if SOTF is set to OFF.


IN1>: This parameter is set to 20% of base current in present case, which is 200A in primary.

k1 (TMS): This parameter is set to 0.3 in present case.

Refer Appendix-I for more details of above two settings.


83


Table 3-24 gives the recommended settings for Four Step Residual Overcurrent Protection.

Table 3-24: Four Step Residual Overcurrent Protecti on


Recommended

Settings

Unit


IBase Base value for current settings 1000 A

UBase Base value for voltage settings.

(Check with PT input in configuration )

400 kV

AngleRCA Relay characteristic angle (RCA) 65 Deg

polMethod Type of polarization Voltage -

UPolMin Minimum voltage level for polarization in % of UBase

1 %UB

IPolMin Minimum current level for polarization in % of IBase

5 %IB

RNPol Real part of source Z to be used for current polar-isation

5 Ohm

XNPol Imaginary part of source Z to be used for current polarisation

40 ohm

IN>Dir Residual current level for Direction release in % of IBase

10 %IB

2ndHarmStab Second harmonic restrain operation in % of IN amplitude

20 %

BlkParTransf Enable blocking at paral-lel transformers Off -

UseStartValue Current level blk at paral-lel transf (step1, 2, 3 or 4)

IN4> -

SOTF SOTF operation mode (Off/SOTF/Under-time/SOTF+undertime)

Off -

ActivationSOTF Select signal that shall activate SOTF Open -


84


Recommended

Settings

Unit

StepForSOTF Selection of step used for SOTF Step 2 -

HarmResSOTF Enable harmonic restrain function in SOTF Off -

tSOTF Time delay for SOTF 0.200 S

t4U Switch-onto-fault active time 1.000 S

DirMode1 Directional mode of step 1 (off, nodir, forward, reverse)

Forward -

Characterist1 Time delay curve type for step 1 IEC Norm. Invr. -

IN1> Operate residual current level for step 1 in % of IBase

20 %IB

t1 Independent (definite) time delay of step 1 0 s

k1 Time multiplier for the dependent time delay for step 1

0.3 -

IN1Mult Multiplier for scaling the current setting value for step 1

1.0 -

t1Min Minimum operate time for inverse curves for step 1

1.1 s

HarmRestrain1 Enable block of step 1 from harmonic restrain

On -


Off -


Off -


Off -


85

3.1.25 Two Step Overvoltage Protection OV2PTOV


Recommendation for 400kV Lines: Low set stage (Stage-I) may be set in the range of 110% - 112%

(typically 110%) with a time delay of 5s. High set stage (Stage-II) may be set in the range 140% -

150% with a time delay of 100ms.

UBase: Setting of the Base voltage level on which the voltage settings are based. This parameter is


U1>: Setting of the U> voltage. This parameter is recommended set 110% of the base voltage in

present case, which is 440kV.

OpMode1: Setting of the Overvoltage function measuring mode for involved voltages. Normally this

parameter is recommended to be set to 1 out of 3.

Characterist1: Setting of the characteristic for the time delay, inverse or definite time. Normally this

parameter is recommended to be set to Definite time.

t1: Setting of the definite time delay, when selected. This parameter is recommended to be set to 5s

in present case.

k1: Set the time delay multiplier for inverse characteristic, when selected. This parameter is not

applicable if Characterist1 is set to Definite time.

t1Min: Setting of the definite minimum operating time for the inverse characteristic. This parameter

is not applicable if Characterist1 is set to Definite time.



t1Reset: Setting of the definite time reset time. This parameter is not applicable if ResetTypeCrv1 is

set to Instantaneous.

HystAbsn1: Absolute hysteresis is set in % of UBase. The setting of this parameter is highly

dependent of the application. In OV2PTOV, this can be set as low as 0.5%. Which means drop-off

to pickup ratio can be set upto 99.5%.

U2>: Setting of the U>> voltage. This parameter is recommended to be set to 140% of the base

voltage in present case, which is 560kV.

OpMode2: Setting of the Overvoltage function measuring mode for involved voltages. Normally this

parameter is recommended to be set to 1 out of 3.

Characterist2: Setting of the characteristic for the time delay, inverse or definite time. Normally this

parameter is recommended to be set to Definite time.


86

t2: Setting of the definite time delay, when selected. This parameter is recommended to be set to

0.1s in present case.

k2: Set the time delay multiplier for inverse characteristic, when selected. This parameter is not

applicable if Characterist2 is set to Definite time.

t2Min: Setting of the definite minimum operating time for the inverse characteristic. This parameter

is not applicable if Characterist2 is set to Definite time.



t2Reset: Setting of the definite time reset time. This parameter is not applicable if ResetTypeCrv2 is

set to Instantaneous.

HystAbsn2: Absolute hysteresis set in % of UBase. The setting of this parameter is highly

dependent of the application. In OV2PTOV, this can be set as low as 0.5%. Which means drop-off

to pickup ratio can be set upto 99.5%.


Table 3-25 gives the recommended settings for Two Step Overvoltage Protection.

Table 3-25: Two Step Overvoltage Protection


Recommended

Settings

Unit

ConnType Group selector for connection type PhPh DFT -



OperationStep1 Enable execution of step 1 On -

Characterist1 Selection of time delay curve type for step 1 Definite time -

OpMode1 Number of phases required for op (1 of 3, 2 of 3, 3 of 3) from step 1 1 out of 3 -

U1> Voltage setting/start val (DT & IDMT) in % of UBase, step 1 110 %UB

t1 Definitive time delay of step 1 5 s


87


Recommended

Settings

Unit

t1Min Minimum operate time for inverse curves for step 1 5 s

k1 Time multiplier for the inverse time delay for step 1 0.05 -

HystAbs1 Absolute hysteresis in % of UBase, step 1 0.5 %UB

OperationStep2 Enable execution of step 2 On -

Characterist2 Selection of time delay curve type for step 2 Definite time -

OpMode2 Number of phases required for op (1 of 3, 2 of 3, 3 of 3) from step 2 1 out of 3 -

U2> Voltage setting/start val (DT & IDMT) in % of UBase, step 2 140 %UB

t2 Definitive time delay of step 2 0.1 s

t2Min Minimum operate time for inverse curves for step 2 0.1 s

k2 Time multiplier for the inverse time delay for step2 0.05 -

HystAbs2 Absolute hysteresis in % of UBase, step 2 0.5 %UB

tReset1 Reset time delay used in IEC Definite

Time curve step 1

0.025 s

ResetTypeCrv1 Selection of used IDMT reset curve type

for step 1

Instantaneous -

tIReset1 Time delay in IDMT reset (s), step 1 0.025 s

ACrv1 Parameter A for customer programmable curve for step 1

1.000 -

BCrv1 Parameter B for customer programmable curve for step 1

1.000 -

CCrv1 Parameter C for customer 0.0 -


88


Recommended

Settings

Unit

programmable curve for step 1

DCrv1 Parameter D for customer


0.000 -

PCrv1 Parameter P for customer programmable curve for step 1

1.000 -

CrvSat1 Tuning param for prog. over voltage

IDMT curve, step 1

0 -


Time curve step 2

0.025 s

ResetTypeCrv2 Selection of used IDMT reset curve type

for step 2

Instantaneous -

tIReset2 Time delay in IDMT reset (s), step 2 0.025 s

ACrv2 Parameter A for customer programmable curve for step 2

1.000 -

BCrv2 Parameter B for customer programmable curve for step 2

1.000 -

CCrv2 Parameter C for customer


0.0 -

DCrv2 Parameter D for customer


0.000 -

PCrv2 Parameter P for customer programmable curve for step 2

1.000 -

CrvSat2 Tuning param for prog. over voltage

IDMT curve, step 2

0 %


89

3.1.26 Setting of fault locator values LFL


Line length unit: km

Length: 190km

X1: j58.33Ω

R1: 5.472Ω

X0: j203.68Ω

R0: 51.091Ω

X1SA: j12.26Ω

R1SA: 1.616Ω

X1SB: j9.167Ω

R1SB: 5.472Ω

XM0: j125.87Ω

RM0: 43.32Ω


Table 3-26 gives the recommended settings for Setting of fault locator values.

Table 3-26: Setting of fault locator values


Recommended

Settings

Unit

R1A Source resistance A (near end) 1.616 ohm/p

X1A Source reactance A (near end) 12.26 ohm/p

R1B Source resistance B (far end) 5.472 ohm/p

X1B Source reactance B (far end) 9.167 ohm/p

R1L Positive sequence line resistance 5.472 ohm/p

X1L Positive sequence line reactance 58.33 ohm/p

R0L Zero sequence line resistance 51.091 ohm/p

X0L Zero sequence line reactance 203.68 ohm/p


90

R0M Zero sequence mutual resistance 43.32 ohm/p

X0M Zero sequence mutual reactance 125.87 ohm/p

LineLength Length of line 190 km

3.1.27 Disturbance Report DRPRDRE


Start function to disturbance recorder is to be provided by change in state of one or more of the

events connected and/or by any external triggering so that recording of events during a fault or

system disturbance can be obtained. List of typical signals recommended to be recorded is given

below:

Recommended Analog signals

From CT:

IA

IB

IC

IN

From Line VT:

VAN

VBN

VCN

Fron Aux VT

Vo

Recommended Digital Signals for triggering (Typical)

— Main 1 Carrier receive

— Main 1 Trip

— Z3 start

— Power swing detected

— Line O/V Stage I/Stage II

— Reactor Fault Trip (If applicable)

— Stub Protection Optd.


91

— Main II Trip

— Main II Carrier Receive

— Direct Trip CH A/B Receive

— Bus bar trip

— Main/Tie CB LBB Optd.

— Main/Tie CB A/R operated.

— Main/Tie CB A/R unsuccessful

List of signals used for Analog triggering of DR

— Rate of change of frequency (if available)

— Over Voltage

— Under Voltage

— Over Current

Note: These may need modification depending upon Protections chosen and the contact availability

for certain functions.

Recording capacity

— Record minimum eight (8) analog inputs and minimum sixteen (16) binary signals per bay or

circuit.

Memory capacity

— Minimum 3 s of total recording time

Recording times

— Minimum prefault recording time of 200ms

— Minimum Post fault recording time of 2500ms

PreFaultRecT: is the recording time before the starting point of the disturbance. The setting is

recommended to be set to 0.2s.

PostFaultRecT: This is the maximum recording time after the disappearance of the trig-signal. The

setting is recommended to be set to 2.5s

TimeLimit: It is the maximum recording time after trig. The parameter limits the recording time if

some trigging condition (fault-time) is very long or permanently set without reset. The setting is

recommended to be set to 3s


92

PostRetrig: If it is made ON, new disturbance will be recorded if new trigger signal appears during

a recording. If it is made OFF, a separate DR will not be triggered if new trigger signal appears

during a recording. This parameter is recommended to be set to OFF normally.

ZeroAngleRef: Need to set the analog channel which can be used as reference for phasors,

frequency measurement. Channel 1 set in present case.


Table 3-27 gives the recommended settings for Disturbance Report.

Table 3-27: Disturbance Report


Recommended

Settings

Unit

Operation Operation Off/On On -

PreFaultRecT Pre-fault recording time 0.2 s

PostFaultRecT Post-fault recording time 2.5 s

TimeLimit Fault recording time limit 3.00 s

PostRetrig Post-fault retrig enabled (On) or not (Off) Off -

ZeroAngleRef Reference channel (voltage), phasors,

frequency measurement 1 Ch

OpModeTest Operation mode during test mode Off -


93

3.2 REC670

3.2.1 Analog Inputs





Name# IL1-CB1 IL2-CB1 IL3-CB1 IL1-CB2 IL2-CB2 IL3-CB2

CTprim 1000 1000 1000 1000 1000 1000

CTsec 1A 1A 1A 1A 1A 1A





Name# UL1 UL2 UL3 UL2BUS1 UL2BUS2 UL2L2

VTprim 400kV 400kV 400kV 400kV 400kV 400kV

VTsec 110V 110V 110V 110V 110V 110V

# User defined text


Table 3-28 gives the recommended settings for Analog Inputs.

Table 3-28: Analog Inputs


Recommended

Settings

Unit


presentation TRM40-Ch1 -



94


Recommended

Settings

Unit



























95


Recommended

Settings

Unit













I/O Module 1 On 40 30 Pos Slot3 I/O Module 2 On 40 30 Pos Slot3 I/O Module 3 On 40 30 Pos Slot3 I/O Module 4 On 40 30 Pos Slot3 I/O Module 5 On 40 30 Pos Slot3

Note: OscBlock and OscRelease define the filtering time at activation. Low frequency gives slow






96



Recommended

Settings

Unit










This function block is to control LEDs in HMI.


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.







Recommended

Settings

Unit


97


Recommended

Settings

Unit




disturbance 0.0 s


















These settings are used for synchronizing IED clock time with network time. Ex: GPS or IRIG-B time.

CoarseSyncSrc: Select the time synchronization source available such as SPA, LON, SNTP etc.

Synchronization messages from sources configured as coarse are checked against the internal relay


98

time and only if the difference in relay time and source time is more than 10s then relay time will be

reset with the source time. This parameter need to be based on time source available in site.


once it is selected, time of available time source in network will update to relay if there is a difference

in the time between relay and source. This parameter need to be based on time source available in

site.

SyncMaster: Normally it is set OFF. If time to the relay is received from a GPS antenna (example),

make the relay as master to synchronize with other relays.


HWSyncSrc: This is applicable if process bus IEC61850-9-2 protocol is used for receiving analog

values (optical CT PTs). In this case select time source available same as that of merging unit. This

setting is not applicable in present case.

AppSynch: If there is any loss of time sync, protection function will be blocked if AppSynch set to

Synch based on SyncAccLevel. If AppSunch set to NoSynch, protection functions are not blocked.

Recommended setting is NoSynch.

SyncAccLevel: If this is set to “Class T5 (1us)” and time synch error is more than 1us, protection

functions will be blocked. SyncAccLevel should be set to “Unspecified” when Nosynch is selected at

AppSynch. This parameter is not applicable in present case.

ModulePosition: if BIN is set for FineSyncSource, ModulePosition setting is applicable. Here slot

position of IO module in the relay is to be set (Which slot is used for BI). This parameter is not












NoHalfHourUTC: Time shift from GMT has to be set a multiple of half hours. Example for India it is

+05:30, means +11. Hence this parameter is set to +11 in present case.


99

SYNCHIRIG-B Non group settings: These settings are applicable if IRIG-B is used. This parameter


SynchType: Type of hardware input used for time sync, whether Opto or BNC. This parameter is not






Table 3-31 gives the recommended settings for Time Synchronization.

Table 3-31: Time Synchronization TIMESYNCHGEN Non group settings (basic)


Recommended

Settings

Unit










Recommended

Settings

Unit


Synchronization 3 -


Synchronization 1 -



100



Settings

Unit





Recommended

Settings

Unit








Recommended

Settings

Unit







101



Recommended

Settings

Unit



Setting


Recommended

Settings Unit









changed, is set with the parameter t. This is not the delay for changing setting group. This parameter

is normally recommended to set 1s.

MAXSETGR: The parameter MAXSETGR defines the maximum number of setting groups in use to

switch between. Only the selected number of setting groups will be available in the Parameter




Table 3-32 gives the recommended settings for Parameter Setting Groups.


102

Table 3-32: Parameter Setting Groups



Recommended

Settings

Unit


Changed 1 s



Recommended

Settings

Unit









Table 3-33 gives the recommended settings for Test Mode Functionality.

Table 3-33: Test Mode Functionality TESTMODE Non group settings (basic)


Recommended

Settings

Unit



CmdTestBit Command bit for test required or not Off -


103

during testmode




Table 3-34: IED Identifiers TERMINALID Non group settings (basic)


Recommended

Settings

Unit



ObjectName Object name Line -


UnitName Unit name REC670 -




Table 3-35 gives the recommended settings for Rated System Frequency.

Table 3-35: Rated System Frequency PRIMVAL Non group settings (basic)


Recommended

Settings

Unit





104

DFTReference : Set ref for DFT filter adjustment here. These DFT reference block settings decide

DFT reference for DFT calculations.







Each task group has 12 instances of SMAI, in that first instance has some additional features which

is called master. Others are slaves and they will follow master. If measured sample rate needs to be

transferred to other task group, it can be done only with master.


DFTReference shall be set to default value InternalDFTRef if no VT input is available. Since VT input

is available in this case, the corresponding channel shall be set to DFTReference. Configuration file

has to be referred for this purpose.

DFTRefExtOut: This parameter is available only in Master. If reference is to be sent to other task

group, which reference need to be send has to be select here. For example, if voltage input is

connected to 3rd SMAI of 1ms task group, AdDFTRefCh3 is to be set in DFTRefExtOut of 1ms task

group.

DFTRefExtOut shall be set to default value InternalDFTRef if no VT input is available. Configuration

file has to be referred for this purpose.


Negation is set to NegateN, it will give output R, Y, B and –N. If Negation is set to Negate3Ph, it will

give output -R, -Y, -B and N.

If R, Y, B inputs are connected, N=R+Y+B, and it will do as above. This parameter is recommended

to be set to OFF normally.


SMAI will work only if measured input magnitude is greater than set value in MinValFreqMeas. This

parameter is recommended to be set to 10% normally.



105





Recommended

Settings

Unit

DFTRefExtOut DFT reference for external output (As per configuration) -

DFTReference DFT reference (As per configuration) -





UBase 10 %



106

3.2.10 Synchrocheck function (SYN1)


SelPhaseBus1: Setting of the input phase for Bus 1 voltage reference. This parameter has to be set

based on the corresponding phase PT/CVT input connected to this function. Present case, this

parameter is set to L1 (R-phase)

SelPhaseLine1: Setting of the phase or line 1 voltage measurement. This parameter has to be set

based on the corresponding phase PT/CVT input connected to this function. Present case, this

parameter is set to L1 (R-phase).

SelPhaseBus2: Setting of the input phase for Bus 2 voltage reference (used in multi breaker

schemes only). This parameter has to be set based on the corresponding phase PT/CVT input

connected to this function. Present case, this parameter is set to L1 (R-phase)

SelPhaseLine2: Setting of the phase or line 2 voltage reference (used in multi breaker schemes

only). This parameter has to be set based on the corresponding phase PT/CVT input connected to

this function. Present case, this parameter is set to L1 (R-phase)

UBase: Setting of the Base voltage level on which the voltage settings are based. This parameter is


PhaseShift: This setting is used to compensate for a phase shift caused by a transformer between

the two measurement points for bus voltage and line voltage, or by a use of different voltages as a

reference for the bus and line voltages. The set value is added to the measured line phase angle.

The bus voltage is the reference voltage. This parameter is set to 0° in present case.

URatio: The URatio is defined as URatio = bus voltage/line voltage. This setting scales up the line

voltage to an equal level with the bus voltage. This parameter is set to 1 in present case.

CBConfig: Set available bus configuration here if external PT selection for sync is not available.

If No voltage sel. is set, the default voltages used will be U-Line1 and U-Bus1. This is also the case

when external voltage selection is provided. Fuse failure supervision for the used inputs must also be

connected. In present case this parameter is set to 1 1/2 bus CB.

To allow closing of breakers between asynchronous networks a synchronizing function is provided.

The systems are defined to be asynchronous when the frequency difference between bus and line is

larger than an adjustable parameter.

OperationSC: This decides whether Synchrocheck function is OFF or ON. In present case this


UHighBusSC and UHighLineSC: Set the operating level for the Bus high voltage and Line high

voltage at Line synchronism check. The voltage level settings must be chosen in relation to the bus

or line network voltage. The threshold voltages UHighBusSC and UHighLineSC have to be set lower


107

than the value at which the breaker is expected to close with the synchronism check. A typical value

can be 80% of the base voltages.

UDiffSC: Setting of the allowed voltage difference for Manual and Auto synchronism check. The

setting for voltage difference between line and bus in p.u, defined as (U-Bus/

UBaseBus) - (U-Line/UBaseLine). Normally this parameter is recommended to set 0.15pu.

FreqDiffM and FreqDiffA: The frequency difference level settings for Manual and Auto sync. A

typical value for FreqDiffM can be100mHz for a connected system, and a typical value for FreqDiffA

can be 100-200 mHz. FreqDiffA is not applicable in present case.

PhaseDiffM and PhaseDiffA: The phase angle difference level settings for Manual and Auto sync.

PhaseDiffM is normally recommended to set 30°. Phas eDiffA is not applicable in present case.

tSCM and tSCA: Setting of the time delay for Manual and Auto synchronism check. Circuit breaker

closing is thus not permitted until the synchrocheck situation has remained constant throughout the

set delay setting time. Typical values for tSCM and tSCA can be 0.1s.

Auto related settings are not applicable if outputs related to Auto from this function block for 3-ph

Autorecloser operation is not used.

AutoEnerg and ManEnerg: Setting of the energizing check directions to be activated for AutoEnerg.

Setting of the manual Dead line/bus and Dead/Dead switching conditions to be allowed for

ManEnerg.

DLLB, Dead Line Live Bus, the line voltage is below set value of ULowLineEnerg and the bus

voltage is above set value of UHighBusEnerg. DBLL, Dead Bus Live Line, the bus voltage is below

set value of ULowBusEnerg and the line voltage is above set value of UHighLineEnerg.

AutoEnerg is made OFF and ManEnerg is set to Both of the above DLLB, DBLL. Hence Auto related

parameters are not applicable.

ManEnergDBDL: This need to be made OFF to avoid manual closing of the breaker if both Bus and

Line are dead. In present case this parameter is set OFF.

UHighBusEnerg and UHighLineEnerg: Set the operating level for the Bus high voltage at Line

energizing for UHighBusEnerg. Set the operating level for the Line high voltage at Bus energizing for

UHighLineEnerg.

The threshold voltages UHighBusEnerg and UHighLineEnerg have to be set lower than the value at

which the network is considered to be energized. A typical value can be 80% of the base voltages. If

system voltages are above the set values here, relay will consider it as Live condition.

ULowBusEnerg and ULowLineEnerg: Setting of the operating voltage level for the low Bus voltage

level at Bus energizing for ULowBusEnerg. Setting of the operating voltage level for the low line

voltage level at line energizing for ULowLineEnerg.


108

The threshold voltages ULowBusEnerg and ULowLineEnerg, have to be set to a value greater than

the value where the network is considered not to be energized. A typical value can be 40% of the

base voltages. If system voltages are below the set values here, relay will consider it as Dead

condition.

UMaxEnerg: Setting of the maximum live voltage level at which energizing is allowed. This setting is

used to block the closing when the voltage on the live side is above the set value of UMaxEnerg. In

present case this parameter is set to 105% of UBase.

tAutoEnerg and tManEnerg: Set the time delay for the Auto Energizing and Manual Energizing.

The purpose of the timer delay settings, tAutoEnerg and tManEnerg, is to ensure that the dead side

remains de-energized and that the condition is not due to a temporary interference. If the conditions

do not persist for the specified time, the delay timer is reset and the procedure is restarted when the

conditions are fulfilled again. Circuit breaker closing is thus not permitted until the energizing

condition has remained constant throughout the set delay setting time. Normally tManEnerg is

recommended to set 0.1s. tAutoEnerg is not applicable in present case.

OperationSynch: Operation for synchronizing function Off/ On. This parameter is recommended to

set OFF.

FreqDiffMin, FreqDiffMax, UHighBusSynch, UHighLineS ynch, UDiffSynch, tClosePulse,

tBreaker, tMinSynch and tMaxSynch: These parameters are not applicable if OperationSynch is

set to OFF.


Table 3-37 gives the recommended settings for Synchrocheck function.

Table 3-37: Synchrocheck function


Recommended

Settings Unit


CBConfig Select CB configuration 1 1/2 bus CB -

UBaseBus Base value for busbar voltage settings 400.000 kV

UBaseLine Base value for line voltage settings 400.000 kV

PhaseShift Phase shift 0 Deg

URatio Voltage ratio 1.000 -


109


Recommended

Settings Unit

OperationSynch Operation for synchronizing function Off/

On Off -

OperationSC Operation for synchronism check function Off/On On -

UHighBusSC Voltage high limit bus for synchrocheck in % of UBaseBus 80.0 %UBB

UHighLineSC Voltage high limit line for synchrocheck in % of UBaseLine 80.0 %UBL

UDiffSC Voltage difference limit in p.u 0.15 pu

FreqDiffA Frequency difference limit between bus

and line Auto 0.010 Hz

FreqDiffM Frequency difference limit between bus

and line Manual 0.10 Hz

PhaseDiffA Phase angle difference limit between

bus and line Auto 30.0 Deg

PhaseDiffM Phase angle difference limit between

bus and line Manual 30.0 Deg

tSCA Time delay output for synchrocheck Auto 0.100 s

tSCM Time delay output for synchrocheck

Manual 0.100 s

AutoEnerg Automatic energizing check mode Off -

ManEnerg Manual energizing check mode Both -

ManEnergDBDL Manual dead bus, dead line energizing Off -

UHighBusEnerg Voltage high limit bus for energizing

check in % of UBaseBus 80.0 %UBB

UHighLineEnerg Voltage high limit line for energizing

check in % of UBaseLine 80.0 %UBL


110


Recommended

Settings Unit

ULowBusEnerg Voltage low limit bus for energizing


ULowLineEnerg Voltage low limit line for energizing


UMaxEnerg Maximum voltage for energizing in % of

UBase, Line and/or Bus 105.0 %UB

tAutoEnerg Time delay for automatic energizing

Check 0.100 s

tManEnerg Time delay for manual energizing check 0.100 s

SelPhaseBus1 Select phase for busbar1 Phase L1 for

busbar1 -


busbar2 -

SelPhaseLine1 Select phase for line1 Phase L1 for line1 -


3.2.11 Autorecloser SMBRREC


Fast simultaneous tripping of the breakers at both ends of a faulty line is essential for successful

auto-reclosing. Therefore, availability of protection signaling equipment is a pre-requisite.

Starting and Blocking of Auto-reclose Relays:

Some protections start auto-reclosing and others block. Protections which start A/R are Main-I and

Main-II line protections.

Protections which block A/R are:

— Breaker Fail Relay

— Line Reactor Protections

— O/V Protection


111

— Received Direct Transfer trip signals

— Busbar Protection

— Zone 2/3 of Distance Protection

— Carrier Fail Conditions

— Circuit Breaker Problems.

When a reclosing relay receives start and block A/R impulse simultaneously, block signal

dominates. Similarly, if it receives 'start' for 1-phase fault immediately followed by multi-phase fault

the later one dominates over the previous one.

Operation: If it is set ON, Autorecloser will be ON always but initiation is required to START input

from trip relay to start the timers in Autorecloser. If External ctrl is selected, on or off of Autorecloser

function will be using an external switch via IO or communication ports. In present case, this

parameter is set to External ctrl.

ARMode: This parameter is set to 1/2ph in present case. If 2 phase fault occurs, it is converted to

3-ph trip through trip logic (configured in relay).

All the available ARmodes are explained below.

3 phase: If 3 phase is selected, Autorecloser all shots will be 3-ph for all faults.

1/2/3ph: If 1/2/3ph is selected, Autorecloser first shot will be 1ph for 1ph fault, 2-ph for 2-ph fault

and 3-ph for 3-ph fault. If first shot fails, next shots will be 3-ph for all faults.

1/2ph: If 1/2ph is selected, Autorecloser will be 1ph for 1ph fault and 2-ph for 2-ph fault. For 3-ph

faults, Autorecloser will not work and it will not close the breaker after dead time. If first shot fails,

next shots will be 3-ph for 1ph and 2ph faults.

TR2P and TR3P inputs required if 2ph and 3ph Autorecloser is needed.

1ph+1*2ph: If 1ph+1*2ph is selected, Autorecloser first shot will be 1ph for 1ph fault and 2-ph for 2-

ph. If first shot fails, next shots will be 3-ph for 1ph faults. For 2ph faults, first shot will be 2ph and

no next shots, only 3ph trip, if it fails. For 3ph fault, Autorecloser will not work and it will not close

the breaker after dead time.

If 1ph fault occurred, Autorecloser will go for 1ph reclose after a 1ph trip. If Autorecloser fails to

close, it will go for 3ph trip and next Autorecloser will 3ph and it will continue based on no of shots

setting.


112

If 2ph fault occurred, Autorecloser will go for 2ph reclose after a 2ph trip. If Autorecloser fails to

close, it will go for 3ph trip and there will not be next Autorecloser cycle even if set more number of

shots in setting.

1/2ph+1*3ph: If 1ph+1*3ph is selected, Autorecloser first shot will be 1ph for 1ph fault, 2-ph for 2-

ph fault and 3-ph for 3-ph fault. If first shot fails, next shots will be 3-ph for 1ph and 2ph faults. For

3ph faults, first shot will be 3ph and no next shots, only 3ph trip.

1ph+1*2/3ph: If 1ph+1*2/3ph is selected, Autorecloser first shot will be 1ph for 1ph fault, 2-ph for 2-

ph fault and 3-ph for 3-ph fault. If first shot fails, next shots will be 3-ph only for 1ph. For 2ph or 3ph

faults, first shot will be 2ph or 3ph respectively and no next shots, only 3ph trip.

t1 1ph, t1 2ph and t1 3ph are the first shot dead times for 1ph, 2ph and 3ph faults. t1 2ph and t1

3ph are not applicable for 1ph Auto recloser.

t2 3Ph, t3 3Ph, t4 3Ph and t5 3Ph are not applicable if NoOfShots is set to 1.

Single phase dead time of 1.0 s. is recommended for both 400 kV and 220 kV systems.

t1 3PhHS: This timer is applicable if STARTHS input is used. This can be used where tripping by

different protection stages is needed. For this case, dead timer shall be normally in the range of

400ms. This is a high speed auto recloser without synchrocheck. Hence this should be set to a low

value. It may be used when one wants to use two different dead times in different protection trip

operations. This input starts the dead time t1 3PhHS. This parameter is not applicable in present

case.

tReclaim: After closing command to breaker, this timer will start, if fault occurred during this timer,

auto recloser will go for second shot or will issue 3ph trip based on setting.

According to IEC Publication 56.2, a breaker must be capable of withstanding the following

operating cycle with full rated breaking current:

0 + 0.3 s + CO + 3 min + CO

The recommended operating cycle at 400 kV and 220 kV is as per the IEC standard. Therefore,

reclaim time of 25s is recommended.

tSync: Maximum time for Synchro check condition to be fulfilled (Not applicable for 1-ph A/R). This

is applicable when 3ph Autorecloser is used.

tTrip: If trip command and start auto-reclosing signal persist for more than tTrip time, Autorecloser

will be either blocked or extend the auto-reclosing dead time based on Extended t1 setting. It will

block if Extended t1=OFF and it will extend auto-reclosing dead time if Extended t1=ON. A trip pulse

longer than the set time tTrip will inhibit the reclosing.


113

At a setting somewhat longer than the auto-reclosing open time, this facility will not influence the

reclosing. Normally this parameter is set to 0.2s.

tPulse: It is just closing pulse width of CB closing command from Autorecloser. This parameter in

normally recommended to set 0.2s.

tCBClosedMin: If either main or tie CB is kept open prior to the occurrence of fault, the Autoreclose

closing pulse should not be given to that breaker.

Setting tCBClosedMin is the minimum time the CB shall be kept closed prior to occurrence of a fault

to get an AR attempt. If the CB has not been closed for at least this minimum time, a reclosing start

will not be accepted. Normally this parameter is set to 5s.

tUnsucCl: CB check time before unsuccessful alarm. Normally the signal UNSUCCL appears when

a new trip and start is received after the last reclosing shot has been made and the auto-reclosing

function is blocked.

The signal resets once the reclaim time has elapsed. The “unsuccessful” signal can also be made to

depend on CB position input. The parameter UnsucClByCBChk should then be set to CBCheck,

and a timer tUnsucCl should also be set. If the CB does not respond to the closing command and

does not close, but remains open, the output UNSUCCL becomes high after time tUnsucCl.

The Unsuccessful output can for example, be used in Multi-Breaker arrangement to cancel the auto-

reclosing function for the second breaker, if the first breaker closed onto a persistent fault. It can

also be used to generate a Lock-out of manual closing until the operator has reset the Lock-out.

Normally this parameter is set to 3s.

Priority: In a multi-C.B. arrangement one C.B. can be taken out of operation and the line still be

kept in service. After a line fault, only those C.Bs which were closed before the fault shall be

reclosed.

In multi-C.B. arrangement it is desirable to have a priority arrangement so as to avoid closing of

both the breakers in case of a permanent fault. This will help in avoiding unnecessary wear and

tear. In this case, the breaker selected as priority High is reclosed first and only if it is successful,

the other breaker gets reclosing impulse.

A natural priority is that the C.B. near the busbar is reclosed first. In case of faults on two lines on

both sides of a tie C.B. the tie C.B. is reclosed after the outer C.Bs. The outer C.Bs. do not need a

prioriting with respect to each other.

In a single breaker arrangement the setting is Priority = None. In a multi-breaker arrangement the

setting for the first CB, the Master, is Priority = High and for the other CB Priority = Low.

While the reclosing of the master is in progress, it issues the signal WFMASTER.


114

A reset delay of one second ensures that the WAIT signal is kept high for the duration of the

breaker closing time. In the slave unit, the signal WAIT holds back a reclosing operation. When the

WAIT signal is reset at the time of a successful reclosing of the first CB, the slave unit is released to

continue the reclosing sequence.

tWaitForMaster: Setting of the maximum wait time for Master to be ready. In single CB

applications, one sets Priority = None. At sequential reclosing the function of the first CB, e.g. near

the busbar, is set Priority = High and for the second CB Priority = Low. The maximum waiting time,

tWaitForMaster of the second CB is set longer than the “auto-reclosing open time” and a margin for

synchrocheck at the first CB. Typical setting is tWaitForMaster=60s.

Whenever Zone1 Trips TIE CB as well as BUS CB Opens and First Dead time of Main CB starts

and in the mean time tWaitForMaster (TIE CB) starts elapsing. If WFMASTER does not deactivate

with in tWaitForMaster then TIE CB AR get deactivated. If WFMASTER deactivate before

tWaitForMaster then TIE CB Dead Time starts and at the end of Dead time TIE CB Reclose will

happen.

NoOfShots: The maximum number of reclosing shots in an auto-reclosing cycle is selected by the

setting parameter NoOfShots. This parameter is set to 1.

StartByCBOpen: To be set ON if AR is to be started by CB open position. To start auto-reclosing

by CB position Open instead of from protection trip signals, one has to configure the CB Open

position signal to inputs CBPOS and START and set a parameter StartByCBOpen = On and

CBAuxContType = NormClosed (normally closed). One also has to configure and connect signals

from manual trip commands to input INHIBIT. Normally this is kept OFF.

CBAuxContType: Select the type of contact used for the CB Position input.

CBAuxContType=NormClosed is also set and a CB auxiliary contact of type NC (normally closed) is

connected to inputs CBPOS and START. When the signal changes from “CB closed” to “CB open”,

an auto-reclosing start pulse is generated and latched in the function, subject to the usual checks.

Here it needs to be set whether NC or NO auxiliary contact of the CB is connected to the relay.

Normally NO contact is used.

CBReadyType: The selection depends on the type of performance available from the CB operating

gear. At setting OCO (CB ready for an Open – Close – Open cycle), the condition is checked only at

the start of the reclosing cycle. The signal will disappear after tripping, but the CB will still be able to

perform the C-O sequence. For the selection CO (CB ready for a Close – Open cycle) the condition

is also checked after the set auto-reclosing dead time. This selection has a value first of all at

multishot reclosing to ensure that the CB is ready for a C-O sequence at shot 2 and further shots.

During single-shot reclosing, the OCO selection can be used. A breaker shall according to its duty


115

cycle always have storing energy for a CO operation after the first trip. (IEC 56 duty cycle is O-0.3s

CO-3minCO).

Extended t1: Extended t1 for PLC failure activated or not. An auto-reclosing open time extension

delay, tExtended t1, can be added to the normal shot 1 delay. It is intended to come into use if the

communication channel for permissive line protection is lost. In such a case there can be a

significant time difference in fault clearance at the two ends of the line. A longer “auto-reclosing

open time” can then be useful. This extension time is controlled by setting parameter Extended

t1=On and the input PLCLOST. Typical setting in such a case: Extended t1 = On and tExtended t1

= 0.8 s. In present case Extended t1 is set to OFF.

tInhibit: A typical setting is tInhibit = 5.0s to ensure reliable interruption and temporary blocking of

the function. Function will be blocked during this time after the tinhibit has been activated.

CutPulse: The CB closing command, CLOSECB is given as a pulse with a duration set by

parameter tPulse. For circuit-breakers without an anti-pumping function, close pulse cutting can be

used. It is selected by parameter CutPulse=On. In case of a new trip pulse (start), the closing

command pulse is then cut (interrupted). The minimum closing pulse length is always 50 ms.

If CB is with anti-pumping relay, this CutPulse can be set OFF. In present case, this parameter is

set to OFF.

Follow CB: Select if the multi-shot cycle to advance to next shot at a new fault if CB has been

closed during dead time. The usual setting is Follow CB = Off. The setting On can be used for

delayed reclosing with long delay, to cover the case when a CB is being manually closed during the

“auto-reclosing open time” before the auto-reclosing function has issued its CB closing command.

AutoCont: Setting of the operating mode for next AR attempt (continue if CB does not close). This

is applicable only if multi-shots are selected. The normal setting is AutoCont = Off.

UnsucClByCBChk: Setting of the signal mode at Unsuccessful reclosing. The “unsuccessful”

signal can also be made to depend on CB position input using UnsucClByCBChk setting. 3ph trip is

issued if breaker has not been closed even if there is no trip output from distance relay.

Normally this parameter is set to NoCBCheck.

BlockByUnsucCl: Blocking of the Auto reclose program at unsuccessful auto reclosing. If this is

made ON, Autorecloser will be blocked for unsuccessful Autorecloser and it must be unblocked by

using the input BLKOFF. Normal this setting is Off.

ZoneSeqCoord: In present case this parameter is set to OFF.


Table 3-38 gives the recommended settings for Autorecloser.


116

Table 3-38: Autorecloser


Recommended

Settings Unit

Operation Off, ExternalCtrl, On ExternalCtrl -

ARMode The AR mode selection e.g. 3ph, 1/3ph 1ph -

t1 1Ph Open time for shot 1, single-phase 1.000 s

t1 3Ph Open time for shot 1, delayed reclosing 3ph 6.000 s

t1 3PhHS Open time for shot 1, high speed reclosing 3ph 0.400 s

tReclaim Duration of the reclaim time 25.00 s

tSync Maximum wait time for synchrocheck OK 30.00 s

tTrip Maximum trip pulse duration 0.200 s

tPulse Close pulse duration 0.200 s

tCBClosedMin Min time that CB must be closed before new sequence allows 5 s

tUnsucCl Wait time for CB before indicating

Unsuccessful/ Successful 30.00 s

Priority Priority selection between adjacent

terminals None/Low/ High High -

tWaitForMaster Maximum wait time for release from Master 60.00 s

NoOfShots Max number of reclosing shots 1-5 1 -

StartByCBOpen To be set ON if AR is to be started by CB open position Off -

CBAuxContType Select the CB aux contact type NC/NO for CBPOS input NormOpen -

CBReadyType Select type of circuit breaker ready signal CO/OCO OCO -

t1 2Ph Open time for shot 1, two-phase 1.000 s

t2 3Ph Open time for shot 2, three-phase 30.00 s




Extended t1 Extended open time at loss of permissive channel Off/On Off -

tExtended t1 3Ph Dead time is extended with this value at loss of perm ch 0.500 s


117


Recommended

Settings Unit

tInhibit Inhibit reclosing reset time 5.000 s

CutPulse Shorten closing pulse at a new trip Off/On Off s

Follow CB Advance to next shot if CB has been closed during dead time Off -

AutoCont Continue with next reclosing-shot if

breaker did not close Off -

tAutoContWait Wait time after close command before proceeding to next shot 4.000 s

UnsucClByCBChk Unsuccessful closing signal obtained by checking CB position NoCBCheck -

BlockByUnsucCl Block AR at unsuccessful reclosing Off -

ZoneSeqCoord Coordination of downstream devices to local prot unit's AR Off -


118






below:


From CT:

IA

IB

IC

IN

From Line VT:

VAN

VBN

VCN

Fron Aux VT

Vo

Recommended Digital Signals(Typical)

— Main 1 Trip

— Main II Trip

— CBI Status APH

— CB I Status BPH

— CB I Status CPH

— CB II Status A PH

— CB II Status B PH

— CB II Status C PH

Note: These may need modification depending upon Protections chosen and the contact availability

for certain functions.

Recording capacity


119

— Record minimum eight analog inputs (8) and minimum 16 binary signals per bay or

circuit.

Memory capacity

— Minimum 3s of total recording time

Recording times



PreFaultRecT: It is the recording time before the starting point of the disturbance. The setting is


PostFaultRecT: This is the maximum recording time after the disappearance of the trig-signal. The

setting is recommended to be set to 2.5s




PostRetrig: If it is made ON, new disturbance will be recorded if new trigger signal appears during

a recording. If it is made OFF, a separate DR will not be triggered if new trigger signal appears

during a recording. This parameter is recommended to be set to OFF normally.





Table 3-39: Disturbance Report


Recommended

Settings

Unit






ZeroAngleRef Reference channel (voltage), phasors, 1 Ch


120

frequency measurement



121

APPENDIX-A: Coordination of 400kV Line Protection Z one-2 and Zone-3 with IDMT O/C & E/F relays of 400kV side of ICT and 220kV Line

Zone-2 and Zone-3 timers of 400kV line distance relay need to be coordinated with 400kV side

IDMT O/C and E/F relays provided on the 400/220kV ICT and 220kV line in order to make sure that

for faults on 220kV line, the IDMT O/C and E/F relays have chance to operate before Zone 2 or

Zone-3 of 400kV Distance relay operates for the cases where Zone 2/Zone 3 reach encroaches into

220kV side of Transformer.

The calculations given in this appendix are with following objective:

1. Settings to be provided on IDMT O/C relays of 400kV side of ICT and on 220 kV line (As per the

protection guideline, 220kV line protection shall have distance relay as Main-I and Main-II.

However, most of the utilities use single distance main and back up O/C protection and hence

O/C protection on 220kV line has also been considered for illustration).

3. Settings to be provided on IDMT E/F relays on 400kV line, 400kV side of ICT and 220kV line

4. Coordination curves for ICT O/C relays with Zone-2 and Zone-3

5. Coordination curves for ICT E/F relays with Zone-2 and Zone-3

6. Does Zone-2 and Zone-3 reaches encroach into 220kV side of ICT for 1-ph and ph-ph faults for

various fault levels.

1. System Details:

Figure A-1 shows the system details for the network under consideration for relay setting. Table

A-1 gives the setting for the over current and earth fault relays for the network under

consideration.

2. 3-Ph Fault Current:

Figure A-2 shows the 3-Ph fault currents & operating time of relays for a fault at 5% of 220kV

L-1. The operating times are taken from phase over current coordination curves given in figure

A-3.

3. Ph-G Fault Current:

Figure A-4 shows the earth fault currents & operating time of relays for a fault at 5% of 220kV L-

1. The operating times are taken from earth fault current coordination curves given in figure A-5.


122

SLD given in Figure A-6 shows 1-Ph fault current & operating time of the relay for a fault at

remote end of the 400kV line. The operating time are taken from over current coordination

curves given in figure A-7. Operating of Directional E/F relay is less than Zone 3 operating time

for the fault current more than1302.28A. Hence minimum time (tMin) of Directional E/F relay is

set to 1.1s to achieve coordination of Directional E/F relay with Zone-3 operating time. Fault

current will be more than 1302.28A for the fault in protected line section.

Table A-1 Settings of Over current and Earth fault relays

Phase Relay Settings

Thermal / Curve (NEMA Code :67)

Instantaneous Setting

(NEMA Code :50) SI.NO Relay Name CT ratio

Base current

set Ib in A Plug setting I p>

(I/Ib) in%

TMS Tp>

Ip>> (I/Ib) in%

Tp>> in s

1 TR-1 Primary 1000/1 A 455 150% 0.24 800% 0.05

2 220kV Directional O/C 800/1 A 800 100% 0.25 - -

Earth Relay Settings

Thermal / Curve (NEMA Code :67N)

Instantaneous Setting

(NEMA Code :50N) SI.NO Relay Name CT ratio

Base current

set Ib in A Plug setting I e> (I/Ib) in%

TMS Te>

Ie>> (I/Ib) in%

Te>> in s


2 TR-1 Primary 1000/1 A 455 20% 0.56 800% 0.05



123

Figure A-1: System details for the network under co nsideration for relay setting


124

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


125

Figure A-3 : Over Current Relay Curve Co-ordination and Operatin g Time


126

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


127

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


128

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


129

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


130

4. Extent of reach of Zone 2 and Zone 3 in to 220kV side

A. For 3ph faults

Check for Zone-2 and Zone-3 reach encroachment into 220kV side of ICT

Zone-2 reactive reach X2 = 87.5Ω


Reactance of 400kV line = 58.33Ω

Reactance of single ICT = 63.49Ω

Reactance of 3 ICTs in parallel = 21.16Ω

Reactance of 3 ICTs in parallel considering infeed from 400kV = ( ) x 21.16Ω

= 182.36Ω

Reactance seen by Zone-2 and Zone-3 elements = 240.69Ω

From the above it can be seen that neither Zone-2 nor Zone-3 reach beyond ICT.

B. For 1ph faults

Check for Zone-2 and Zone-3 reach encroachment into 220kV side of ICT



Reactance of 400kV line = 58.33Ω

Reactance of single ICT = 63.49Ω

Reactance of 3 ICTs in parallel = 21.16Ω

Reactance of 3 ICTs in parallel considering infeed from 400kV= ( ) x 21.16Ω

= 217.48Ω

Reactance seen by Zone-2 and Zone-3 elements = 275.81Ω

From the above it can be seen that neither Zone-2 nor Zone-3 reach beyond ICT.

5. Conclusions:

a. In the present case, because of the infeed effect, Zone-2 and Zone-3 of distance relay at Station-A

is not looking into 220kV side of the auto-transformer even with all the 3 bank in service.

b. The operation timing coordination of Overcurrent relay and earth fault relay of transformer with

Zone-3 is verified.


131

APPENDIX-B: Effect of network change due to a line LILO on relay settings of LILO line & adjacent lines

In example considered for the sample distance relay setting calculation, the 400kV double circuited

line between station-A and station-B has now a loop-in loop-out connection at a distance of 120km

form station-A in one of the circuit. The other circuit, there is no loop-in loop-out. Figure B-1 shows

the modified network.

Figure B-1: Network line diagram of the system afte r the LILO of one circuit of line AB

Due to change in the network after the LILO, the settings of following functions in the line

protections of lines at various stations will have to be reviewed and revised as described below for

the present case:

Station-A:

Line that has LILO connection (Line A-S): New settings are required for Main distance relays. The

effect of mutual coupling will have to be considered as before.


132

Parallel circuit Line that has not LILO connection (Line A-B): Effects of mutual coupling needs to be

studied because of LILO in the adjacent parallel line.

Station-B:

Line that has LILO connection (Line B-S): New settings are required for Main distance relays for

Line B-S. The effect of mutual coupling will have to be considered as before.

Parallel circuit Line that has not LILO connection (Line B-A): Effects of mutual coupling needs to be

studied because of LILO in the adjacent parallel line.

Station-S:

Line S-A and Line S-B: Being a new station, settings are required for Main distance relays.

To understand the effect of mutual coupling on zone-1 and zone-2 settings, studies have been done

on several possible configurations and these are described in the section below.

Impact of mutual coupling on distance protection in LILO case

Distance relaying of ph-ph and three-phase faults is not influenced by the parallel line. For

protection of phase-to-earth faults, however a measuring error occurs. In principle this error appears

due to the fact that the parallel line earth-current (IEP = 3.I0P) induces a voltage IEP. Z0m/3 in the fault

loop.

The distance relay phase-to-earth units measure;

Where:

is phase to earth short circuit voltage at the relay location in the faulted phase

is short circuit current in the faulted phase

is earth current of faulty line

is earth compensation factor.

Considering the conventional value of earth return compensation as given by


133

The distance protection zone reaches vary with the switching state of the parallel line configuration.

The most common are listed below.

I. Parallel line out of service and earthed at both ends.

II. Parallel line switched off and not earthed or earthed only at one line end.

III. Both lines in service.

The impedance measured by the distance relay will be different depending on the operation

condition of the parallel line.

Given below are several cases studied. The line data used here is as under.

Z1: Line positive sequence impedance = 0.0288+j0.307 ohm/km

Z0: Line zero sequence impedance =0.2689+j1.072 ohm/km

Z0m: Mutual zero sequence impedance = 0.228 + j0.662 ohm/km

Measurement errors in distance relays for a double circuited line with LILO:

The distance protection zone reaches vary with the switching state of the parallel line configuration.

Different configurations of the line with and without the sources at remote end and LILO end are

studied and the measured reach values of the distance relay and voltage, currents observed after

the occurrence of the fault are tabulated.

The error in measured impedance is computed as

%Error = Measured Impedance – Actual Impedance

Actual Impedance


134

Case 1: Parallel line A-S switched off and earthed at both ends and fault at station-B

1.1 Line A-S out of service and earthed at both ends and fault at station-B – source at end A only

(Figure B-2 and Table B-1)

Figure B-2: SLG Fault at bus B with source at Stati on A and Line A-S out of service and Earthed

Table B-1: Fault At Station-B With Source At Statio n – A and Line A-S Earthed

Fault location Line Impedance in Ω Apparent Impedance (Z) in Ω % Error

Station B 58.30 49.43 -15.21


135

1.2 Line A-S out of service and earthed at both ends and fault at station-B – sources at ends A and B


Figure B-3: SLG Fault at bus B with sources at Station A & B an d Line A-S out of service and Earthed

Table B-2: Fault At Station-B With Sources At Stati on – A & B and Line A-S Earthed


Station B 58.30 49.88 -14.44


136

1.3 Line A-S out of service and earthed at both ends and fault at station-B – sources at ends A, B

and S (Figure B-4 and Table B-3)

Figure B-4: SLG Fault at bus B with sources at Stat ion A, B & S and Line A-S out of service and Earthed

Table B-3: Fault At Station-B With Sources At Stati on – A, B & S and Line A-S Earthed

Fault location Line Impedance in Ω Apparent Impedance (Z) in Ω % Error Station B 58.30 60.09 3.07

In case-1, the distance relay provided on line AB overreaches by 15.2% when source is only at A,

14.44% when source is present at A and B, underreaches by 3% when source is present at A, B

and S. Therefor with zone-1 setting of 80% on line AB, the relay can overreach in to the next

section. Since such occurrences are rare, the risk of overreach will have to be accepted. One factor

in favor of this is the overreach in the following line is normally heavily reduced due to infeeds at the

remote stations.


137

Case 2: Parallel line B-S switched off and earthed at both ends and fault at station-B

2.1 Line B-S out of service and earthed at both ends and fault at station-B – source at end A only


Figure B-5: SLG Fault at bus B with source at Stati on A and Line B-S out of service and Earthed

Table B-4: Fault At Station-B With Source At Statio n – A and Line B-S Earthed


Station B 58.30 52.96 -9.15


138

2.2 Line B-S out of service and earthed at both ends and fault at station-B – sources at ends A and

B (Figure B-6 and Table B-5)

Figure B-6: SLG Fault at bus B with sources at Station A & B an d Line B-S out of service and Earthed

Table B-5: Fault At Station-B With Source At Statio n – A & B and Line B-S Earthed

Fault location Line Impedance in ( Ω) Apparent Impedance (Z) in Ω % Error Station B 58.30 53.31 -8.56

2.3 Line B-S out of service and earthed at both ends and fault at station-B – sources at ends A, B



139

Figure B-7: SLG Fault at bus B with sources at Station A, B & S and Line B-S out of service and Earthed

Table B-1: Fault At Station-B With Source At Statio n – A, B & S and Line B-S Earthed


Station B 58.30 46.17 -20.80

In case-2, the distance relay provided on line AB overreaches by 9.1% when source is only at A,

8.5% when source is present at A and B, 20.8% when source is present at A, B and S. Therefor

with zone-1 setting of 80% on line AB, the relay can overreach in to the next section. Since such

occurrences are rare, the risk of overreach will have to be accepted. One factor in favor of this is the

overreach in the following line is normally heavily reduced due to infeeds at the remote stations.

Case 3: Parallel line A-B switched off and earthed at both ends and fault at station-S


140

3.1 Line A-B out of service and earthed at both ends and fault at station-S – source at end A only


Figure B-8: SLG Fault at bus S with source at Stati on A and Line A-B out of service and Earthed

Table B-6: Fault At Station-S With Source At Statio n – A and Line A-B Earthed


Station B 36.84 31.60 -14.22

3.2 Line A-B out of service and earthed at both ends and fault at station-S – sources at ends A and

B (Figure B-9 and Table B-8)


141

Figure B-9: SLG Fault at bus S with sources at Stat ion A & B and Line A-B out of service and Earthed

Table B-7: Fault At Station-S With Sources At Stati on – A & B and Line A-B Earthed

Fault location Line Impedance in Ω Apparent Impedance (Z) in Ω % Error Station B 36.84 38.41 4.26

3.3 Line A-B out of service and earthed at both ends and fault at station-S – sources at ends A, B



142

Figure B-10: SLG Fault at bus S with sources at Sta tion A, B & S and Line A-B out of service and Earthed

Table B-8: Fault At Station-S With Sources At Stati on – A, B & S and Line A-B Earthed


Station B 36.84 38.18 3.63

In case-3, the distance relay provided on line AS overreaches by 14.2% when source is only at A,

underreaches by 4.2% when source is present at A and B, underreaches by 3.63% when source is

present at A, B and S. Therefor with zone-1 setting of 80% on line AS, the relay can overreach in to

the next section. Since such occurrences are rare, the risk of overreach will have to be accepted.

One factor in favor of this is the overreach in the following line is normally heavily reduced due to

infeeds at the remote stations.

Case 4: All lines are in service and fault at stati on-B


143

4.1 All lines are in service and fault at station-B– source at end A only (Figure B-11 and Table B-

10)

Figure B-11: SLG Fault at bus B with source at Stat ion A

Table B-9: Fault At Station-B With Source At Statio n A


Station B 58.30 80.21 37.58

4.2 All lines are in service and fault at station-B– sources at ends A and B (Figure B-12 and Table

B-11)


144

Figure B-12: SLG Fault at bus B with sources at Sta tion A and B

Table B-10: Fault At Station-B With Sources At Stat ion – A & B


Station B 58.30 74.37 27.56

4.3 All lines are in service and fault at station-B– sources at ends A, B and S (Figure B-13 and

Table B-12)


145

Figure B-13: SLG Fault at bus B with sources at Sta tion A, B & S

Table B-11: Fault At Station-B With Sources At Stat ion – A, B and S


Station B 58.30 74.57 27.90

In case-4, the distance relay provided on line AB under reaches by 37.6% when source is only at A,

27.5% when source is present at A and B, 27.9% when source is present at A, B and S. From this it

can be seen that zone-2 tends to under reach and it will not be able to cover the whole section fully

and this is not acceptable. For this reason zone-2 must be set to 120%+37.6%, which is

approximately 160% of the protected line impedance rather than the conventional 120% in order to

accommodate the under reaching effect due to mutual coupling.

Case 5: All lines are in service and fault at stati on-S

5.1 All lines are in service and fault at station-S– source at end A only (Figure B-14 and Table B-13)


146

Figure B-14: SLG Fault at bus S with source at Stat ion A

Table B-12: Fault At Station-S Without Sources At S tation – S & B

Fault location Line Impedance in Ω Apparent Impedance (Z) in Ω % Error Station S 36.84 44.25 20.11

5.2 All lines are in service and fault at station-S– sources at ends A and B (Figure B-15 and Table

B-14)


147

Figure B-15: SLG Fault at bus S with sources at Sta tion A and B

Table B-13: Fault At Station-S With Sources At Stat ion – A & B

Fault location Line Impedance in Ω Apparent Impedance (Z) in Ω % Error Station S 36.84 37.78 2.55

5.3 All lines are in service and fault at station-S– sources at ends A, B and S (Figure B-16 and

Table B-15)


148

Figure B-16: SLG Fault at bus S with sources at Sta tion A, B & S

Table B-14: Fault At Station-S With Sources At Stat ion – A, B & S


Station S 36.84 37.64 2.17

In case-5, the distance relay provided on line AS under reaches by 20.1% when source is only at

A, 2.5% when source is present at A and B, 2.2% when source is present at A, B and S. From this

it can be seen that zone-2 tends to under reach and it will not be able to cover the whole section

fully and this is not acceptable. For this reason zone-2 must be set to 120%+20%, which is equal to

140% of the protected line impedance rather than the conventional 120% in order to accommodate

the under reaching effect due to mutual coupling.

Conclusions:

Based on the above studies following conclusions can be made for setting of zone-1 and zone-2 in

case of double circuit line with LILO.


149

• Zone 1 reach setting:

Zone 1: To be set to cover 80% of protected line length. Set zero sequence compensation factor

KN as (Z0 – Z1) / 3Z1. With this setting, the relay may overreach when parallel circuit is open

and grounded at both ends. This risk is considered acceptable. One factor which mitigates this

risk is that the overreach is normally reduced due to infeeds at the remote station.

• Zone 2 reach setting:

Zone 2: To be set to cover minimum 120% of length of principle line section. However, in case

of double circuit lines 140-160% coverage must be provided to take care of under reaching due

to mutual coupling effect. Set zero sequence compensation factor KN as (Z0 – Z1) / 3Z1. Setting

of 140-160% is arrived at considering an expected under reach of about 20-40% when both

lines are in parallel and a margin of 20%.

********************************************


IED USED FOR 400/220/33kV AUTO TRANSFORMER

PROTECTION

Model setting calculation document for Auto Transformer

2

TABLE OF CONTENTS

TABLE OF CONTENTS .................................. ............................................................................ 2

1 BASIC SYSTEM PARAMETERS............................ ............................................................. 7

1.1 Network line diagram of the protected Transformer a nd adjacent circuits.................... 7

1.2 Single line diagram of the Auto Transformer ........ ........................................................... 7

1.3 Transformer parameters ............................. ..................................................................... 10

2 TERMINAL IDENTIFICATION AND LIST OF FUNCTIONS...... ..........................................11

2.1 RET670-1........................................................................................................................... 11

2.1.1 Terminal Identification ....................................................................................11 2.1.2 List of functions available and those used ......................................................11

2.2 RET670-2........................................................................................................................... 16


2.3 REC670.............................................................................................................................. 21

2.3.1 Terminal identification ....................................................................................21 2.3.2 List of functions available and those used ......................................................21

3 SETTING CALCULATIONS AND RECOMMENDED SETTINGS FOR R ET670-1..............27

3.1 RET670-1........................................................................................................................... 27

3.1.1 Analog Inputs .................................................................................................27 3.1.2 Local Human-Machine Interface.....................................................................29 3.1.3 Indication LEDs..............................................................................................30 3.1.4 Time Synchronization.....................................................................................31 3.1.5 Parameter Setting Groups..............................................................................35 3.1.6 Test Mode Functionality TEST .......................................................................35 3.1.7 IED Identifiers ................................................................................................36 3.1.8 Rated System Frequency PRIMVAL ..............................................................36 3.1.9 Signal Matrix For Analog Inputs SMAI............................................................37 3.1.10 Transformer differential protection T3WPDIF .................................................38 3.1.11 Tripping Logic SMPPTRC ..............................................................................47 3.1.12 Trip Matrix Logic TMAGGIO...........................................................................48 3.1.13 Four Step Phase Overcurrent Protection OC4PTOC:1 (Used for HV side).....49 3.1.14 Four Step Phase Overcurrent Protection OC4PTOC:2 (Used for HV side

Overload alarm) 56 3.1.15 Four Step Residual Overcurrent Protection EF4PTOC (Used for HV side).....60 3.1.16 Overexcitation protection OEXPVPH—(HV side) ...........................................68 3.1.17 Disturbance Report DRPRDRE......................................................................73

3.2 RET670-2........................................................................................................................... 76

3.2.1 Analog Inputs .................................................................................................76 3.2.2 Local Human-Machine Interface.....................................................................78 3.2.3 Indication LEDs..............................................................................................78 3.2.4 Time Synchronization.....................................................................................80 3.2.5 Parameter Setting Groups..............................................................................83 3.2.6 Test Mode Functionality TEST .......................................................................84


3

3.2.7 IED Identifiers ................................................................................................85 3.2.8 Rated System Frequency PRIMVAL ..............................................................85 3.2.9 Signal Matrix For Analog Inputs SMAI............................................................85 3.2.10 1Ph High impedance differential protection HZPDIF ......................................87 3.2.11 Four Step Phase Overcurrent Protection OC4PTOC---(For IV side)...............90 3.2.12 Four Step Residual Overcurrent Protection EF4PTOC---(for IV side).............95 3.2.13 Overexcitation protection OEXPVPH---(IV side)...........................................101 3.2.14 Disturbance Report DRPRDRE....................................................................105

3.3 REC670............................................................................................................................ 108

3.3.1 Analog Inputs ...............................................................................................108 3.3.2 Local Human-Machine Interface...................................................................110 3.3.3 Indication LEDs............................................................................................111 3.3.4 Time Synchronization...................................................................................112 3.3.5 Parameter Setting Groups............................................................................115 3.3.6 Test Mode Functionality TEST .....................................................................116 3.3.7 IED Identifiers ..............................................................................................116 3.3.8 Rated System Frequency PRIMVAL ............................................................117 3.3.9 Signal Matrix For Analog Inputs SMAI..........................................................117 3.3.10 Synchrocheck function (SYN1).....................................................................119

APPENDIX-A: CO-ORDINATION OF 400KV/220KV ICT IDMT O /C & E/F RELAYS AT

STATION-A.......................................... ....................................................................................124


4

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


5

LIST OF TABLES Table 1-1: Details of CTs and PTs on both HV and IV sides of AT .............................................................. 9 Table 2-1: List of functions in RET670-1..................................................................................................... 11 Table 2-2: List of functions in RET670-2..................................................................................................... 16 Table 2-3: List of functions in REC670 ....................................................................................................... 21 Table 3-1: Analog inputs ............................................................................................................................. 28 Table 3-2: Local human machine interface................................................................................................. 29 Table 3-3: LEDGEN Non group settings (basic) ......................................................................................... 30 Table 3-4: Time synchronization settings ................................................................................................... 33 Table 3-5: Parameter setting group ............................................................................................................ 35 Table 3-6: Test mode functionality.............................................................................................................. 36 Table 3-7: IED Identifiers ............................................................................................................................ 36 Table 3-8: Rated system frequency ............................................................................................................ 37 Table 3-9: Signal Matrix For Analog Inputs................................................................................................. 38 Table 3-10: Differential protection Settings................................................................................................. 44 Table 3-11: Tripping Logic .......................................................................................................................... 47 Table 3-12: Trip Matrix Logic ...................................................................................................................... 48 Table 3-13: Four Step Phase Overcurrent Protection ................................................................................ 53 Table 3-14: Four Step Phase Overcurrent Protection ................................................................................ 58 Table 3-15: Four Step Residual Overcurrent Protection............................................................................. 65 Table 3-16: Overexcitation protection OEXPVPH ...................................................................................... 72 Table 3-17: Disturbance Report .................................................................................................................. 75 Table 3-18: Analog inputs ........................................................................................................................... 76 Table 3-19: Local human machine interface............................................................................................... 78 Table 3-20: LEDGEN Non group settings (basic) ....................................................................................... 79 Table 3-21: Time synchronization settings ................................................................................................. 81 Table 3-22: Parameter setting group .......................................................................................................... 84 Table 3-23: Test mode functionality............................................................................................................ 84 Table 3-24: IED Identifiers .......................................................................................................................... 85 Table 3-25: Rated system frequency .......................................................................................................... 85 Table 3-26: Signal Matrix For Analog Inputs............................................................................................... 87 Table 3-27: 1Ph High impedance differential protection HZPDIF............................................................... 89 Table 3-28: Four Step Phase Overcurrent Protection ................................................................................ 92 Table 3-29: Four Step Residual Overcurrent Protection............................................................................. 98 Table 3-30: Overexcitation protection OEXPVPH .................................................................................... 104 Table 3-31: Disturbance Report ................................................................................................................ 107 Table 3-32: Analog Inputs ......................................................................................................................... 108 Table 3-33: Local human machine interface............................................................................................. 110 Table 3-34: LEDGEN Non group settings (basic) ..................................................................................... 111 Table 3-35: Time Synchronization ............................................................................................................ 113 Table 3-36: Parameter Setting Groups ..................................................................................................... 115 Table 3-37: Test Mode Functionality......................................................................................................... 116 Table 3-38: IED Identifiers ........................................................................................................................ 117 Table 3-39: Rated System Frequency ...................................................................................................... 117 Table 3-40: Signal Matrix For Analog Inputs............................................................................................. 118 Table 3-41: Setting of Synchrocheck function .......................................................................................... 122 Table A-1 Settings of Over current and Earth fault relays ........................................................................ 126


6



FEEDER: 400/220/33kV Auto Transformer at Station-A

PROTECTION ELEMENT: Main-I & Main-II Protection



7

1 BASIC SYSTEM PARAMETERS

1.1 Network line diagram of the protected Transform er and adjacent circuits

The network line diagram (Figure 1-1) of the system under consideration showing

protected Transformer along with adjacent associated elements is shown below.

The network diagram should indicate the voltage levels, line lengths,

transformer/generator rated MVA & fault contributions of each element for 3-ph

fault at station-A 400kV and 220kV buses.

Figure 1-1: Network line diagram of the protected T ransformer

1.2 Single line diagram of the Auto Transformer

Single line diagram of the Auto transformer, various protection functions used and CT/PT

connections is shown in Figure 1-2.


8

Figure 1-2: Single line diagram of the Auto Transfo rmer with CT ratios


9

CT and PT details:

Table 1-1 gives the Details of CTs and PTs on both HV and IV sides of AT.

Table 1-1: Details of CTs and PTs on both HV and IV sides of AT

CT details

Name of the CT

Name of the Core CT ratio CT details

CORE-1 1000/1A CLASS:PS, Vk:2000V, Imax at Vk:60mA, Rct@75 DEGREE CENTIGRADE ohm: <5Ω


CORE-3 1000/1A CLASS:0.2, 30VA


4B-CT






4C-CT


CORE-1 1000/1A CLASS:PS, Vk:1000V, Imax at Vk:60mA, Rct@75 DEGREE CENTIGRADE ohm: <2.5Ω 1CT


CORE-1 1000/1A CLASS:PS, Vk:1000V, Imax at Vk:60mA, Rct@75 DEGREE CENTIGRADE ohm: <2.5Ω 2CT


NCT CORE-1 1000/1A CLASS:PS, Vk:1000V, Imax at Vk:60mA, Rct@75 DEGREE CENTIGRADE ohm: <2.5Ω



2C-CT





10

PT details

Name of the PT Name of the Core PT ratio PT details

HV PT I (400/√3)/(0.11/√3) 3P, 50VA

LV PT I (220/√3)/(0.11/√3) 3P, 50VA

1.3 Transformer parameters

Transformer: At Substation-A

Frequency: 50Hz

%Impedance: 12.5%

Transformer Rating: 315MVA, 400/220/33kV, 454.7/826.7/1837A (OFAF)

Vector Group: YNa0d11


11

2 TERMINAL IDENTIFICATION AND LIST OF FUNCTIONS

The various functions required for the Auto Transformer protection are divided in three IEDs

namely RET670-1, RET670-2 and REC670 for the purpose of illustration. The terminal

identification of this and list of various functions available in these IEDs are given in this section.

2.1 RET670-1


Object Name: 400/220/33kV Auto Transformer

Unit Name: RET670-1(ver1.2)--Differential and HV Over-fluxing relay, HV Back-up O/C & E/F relay


Frequency: 50Hz



Table 2-1 gives the list of functions/features available in RET670-1 relay and also indicates the

functions/feature for which settings are provided in this document. The functions/features are

indicative and vary with IED ordering code & IED application configuration.

Table 2-1: List of functions in RET670-1 Sl.No. Function/features available In RET670 Funct ion/feature

activated

Yes/No

Recommended

Settings

provided

1 Analog Inputs YES









12






14 Signal Matrix For mA Inputs SMMI YES





19 Transformer differential protection

T3WPDIF

YES

20 1Ph High impedance differential protection

HZPDIF

NO

21 Instantaneous Phase Overcurrent

Protection PHPIOC

NO

22 Four Step Phase Overcurrent Protection

OC4PTOC:1

YES


OC4PTOC:2

YES

24 Instantaneous Residual Overcurrent

Protection EFPIOC

NO

25 Four Step Residual Overcurrent Protection

EF4PTOC

YES

26 Four step directional negative phase

sequence overcurrent protection

NS4PTOC

NO

27 Sensitive directional residual overcurrent

and power protection SDEPSDE

NO

28 Thermal overload protection, two time

constants TRPTTR

YES

29 Breaker failure protection CCRBRF NO

30 Pole discordance protection CCRPLD NO


13

31 Directional underpower protection

GUPPDUP

NO

32 Overexcitation protection OEXPVPH YES

33 Single Point Generic Control 8 Signals

SPC8GGIO

NO

34 Automationbits, Command Function For

DNP3.0 AUTOBITS

NO

35 Single Command, 16 Signals

SINGLECMD

NO

36 Scheme Communication Logic For

Distance Or Overcurrent Protection

ZCPSCH

NO

37 Current Reversal And Weak-End Infeed

Logic For Distance Protection

ZCRWPSCH

NO



40 Low Active Power And Power Factor

Protection LAPPGAPC

NO

41 Compensated Over and Undervoltage

Protection COUVGAPC

NO

42 Sudden Change in Current Variation

SCCVPTOC

NO


44 Negative Sequence Overvoltage

Protection LCNSPTOV

NO

45 Zero Sequence Overvoltage Protection

LCZSPTOV

NO

46 Negative Sequence Overcurrent

Protection LCNSPTOC

NO

47 Zero Sequence Overcurrent Protection

LCZSPTOC

NO



14






54 Boolean 16 To Integer Conversion B16I YES

55 Boolean 16 To Integer Conversion With

Logic Node Representation B16IFCVI

NO


57 Integer To Boolean 16 Conversion With

Logic Node Representation IB16FCVB

NO

58 Measurements CVMMXN NO

59 Phase Current Measurement CMMXU NO

60 Phase-Phase Voltage Measurement

VMMXU

NO

61 Current Sequence Component

Measurement CMSQI

NO

62 Voltage Sequence Measurement VMSQI NO

63 Phase-Neutral Voltage Measurement

VNMMXU

NO

64 Event Counter CNTGGIO NO

65 Event Function EVENT NO

66 Logical Signal Status Report

BINSTATREP

NO


68 Measured Value Expander Block

RANGE_XP

NO


70 Event List NO

71 Indications NO





15


76 Function For Energy Calculation And

Demand Handling ETPMMTR

NO


78 IEC 61850 Generic Communication I/O

Functions SPGGIO, SP16GGIO

NO

79 IEC 61850-8-1 Redundant Station Bus

Communication

NO





84 Multiple Command And Transmit

MULTICMDRCV, MULTICMDSND

NO





16

2.2 RET670-2



Unit Name: RET670-2 (Ver 1.2) -- REF and LV Over-fluxing relay, IV Back-up O/C & E/F relay#


Frequency: 50Hz






Table 2-2: List of functions in RET670-2 Sl.No. Function/features available In RET670 Funct ion/feature

activated

Yes/No

Recommended

Settings

provided

1 Analog Inputs YES














17







T3WPDIF

NO


HZPDIF

YES


Protection PHPIOC

NO


OC4PTOC

YES


Protection EFPIOC

NO


EF4PTOC

YES



NS4PTOC

NO



NO


constants TRPTTR

NO



30 Directional underpower protection

GUPPDUP

NO

31 Overexcitation protection OEXPVPH YES


SPC8GGIO

NO


DNP3.0 AUTOBITS

NO


18


SINGLECMD

NO



ZCPSCH

NO



ZCRWPSCH

NO




Protection LAPPGAPC

NO


Protection COUVGAPC

NO


SCCVPTOC

NO



Protection LCNSPTOV

NO


LCZSPTOV

NO


Protection LCNSPTOC

NO


LCZSPTOC

NO








54 Boolean 16 To Integer Conversion With NO


19





NO




VMMXU

NO


Measurement CMSQI

NO



VNMMXU

NO




BINSTATREP

NO



RANGE_XP

NO


69 Event List NO

70 Indications NO







NO




NO

78 IEC 61850-8-1 Redundant Station Bus NO


20

Communication







NO





21

2.3 REC670






Frequency: 50Hz






Table 2-3: List of functions in REC670

Sl.No.

Functions/Feature available In REC670 Features/Fun ctions

activated

Yes/No

Recommended

Settings

provided

1 Analog Inputs YES














22








Protection PHPIOC

NO


OC4PTOC

NO


Protection EFPIOC

NO


EF4PTOC

NO


sequence overcurrent protection NS4PTOC

NO

25 Sensitive Directional Residual Overcurrent

And Power Protection SDEPSDE

NO

26 Thermal Overload Protection, One Time

Constant LPTTR

NO


constants TRPTTR

NO




31 Directional Underpower Protection

GUPPDUP

NO

32 Directional Overpower Protection

GOPPDOP

NO



35 Two Step Undervoltage Protection UV2PTUV

NO

36 Two Step Overvoltage Protection NO


23

OV2PTOV

37 Two Step Residual Overvoltage Protection

ROV2PTOV

NO





42 Rate-Of-Change Frequency Protection

SAPFRC

NO

43 General Current and Voltage Protection

CVGAPC

NO



46 Synchrocheck, Energizing Check, And

Synchronizing SESRSYN

YES

47 Autorecloser SMBRREC NO


49 Horizontal Communication Via GOOSE For

Interlocking GOOSEINTLKRCV

NO

50 Logic Rotating Switch For Function

Selection And LHMI Presentation SLGGIO

NO


52 Generic Double Point Function Block

DPGGIO

NO


SPC8GGIO

NO


DNP3.0 AUTOBITS

NO


56

Scheme Communication Logic For


ZCPSCH

NO

57 Phase Segregated Scheme Communication NO


24

Logic For Distance Protection ZC1PPSCH


Logic For Distance Protection ZCRWPSCH

NO



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



Protection LAPPGAPC

NO

65 Compensated Over And Undervoltage

Protection COUVGAPC

NO

66 Sudden Change In Current Variation

SCCVPTOC

NO


68 Negative Sequence Overvoltage Protection

LCNSPTOV

NO


LCZSPTOV

NO

70 Negative Sequence Overcurrent Protection

LCNSPTOC

NO


LCZSPTOC

NO







25





NO




NO




VMMXU

YES


Measurement CMSQI

YES



VNMMXU

NO






RANGE_XP

NO

93 Disturbance Report DRPRDRE NO

94 Event List YES

95 Indications YES





100Function For Energy Calculation And


NO


102 IEC 61850 Generic Communication I/O NO


26


103IEC 61850-8-1 Redundant Station Bus

Communication

NO





108Multiple Command And Transmit


NO





27

3 SETTING CALCULATIONS AND RECOMMENDED SETTINGS

FOR RET670-1

The various functions required for the transformer protection are divided in three IEDs namely

RET670-1, RET670-2 and REC670. The setting calculations and recommended settings for

various functions available in these IEDs are given in this section.

# HV and IV side Back up Directional overcurrent and earth fault protections shall preferably be

provided in a separate IED to ensure better reliability.

3.1 RET670-1

3.1.1 Analog Inputs




Ch 1 Ch 2 Ch 3 Ch 4 Ch 5 Ch 6 Name# HV-IL1 HV-IL2 HV-IL3 IV-IL1 IV-IL2 IV-IL3 CTprim 1000A 1000A 1000A 800A 800A 800A CTsec 1A 1A 1A 1A 1A 1A




Ch 1 Ch 2 Ch 3 Ch 4 Ch 5 Ch 6 Name# UL1 UL2 UL3 SPARE SPARE SPARE VTprim 400kV 400kV 400kV 400kV 400kV 400kV

VTsec 110V 110V 110V 110V 110V 110V

# User defined text


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


28

Table 3-1: Analog inputs Setting


Recommended

Settings Unit









CTsec2 Rated CT secondary current 1A A

CTprim2 Rated CT primary current 1000A A





















29













Note: OscBlock and OscRelease defines the filtering time at activation. Low frequency gives

slow response for digital input.






Recommended

Settings

Unit





30


Recommended

Settings

Unit








steady and latched till manually reset. When manually reset, it will go OFF when trip is not there.

If trip still persist, it will flash.






Setting


Recommended

Settings Unit




disturbance 0.0 s






31














These settings are used for synchronizing IED clock time with network time. Ex: GPS or IRIG-B

time.

CoarseSyncSrc: Select the time synchronization source available such as SPA, LON, SNTP

etc. Synchronization messages from sources configured as coarse are checked against the

internal relay time and only if the difference in relay time and source time is more than 10s then

relay time will be reset with the source time. This parameter need to be based on time source

available in site.


once it is selected, time of available time source in network will update to relay if there is a

difference in the time between relay and source. This parameter need to be based on time

source available in site.

SyncMaster: Normally it is set OFF. If time to the relay is received from a GPS antenna

(example), make the relay as master to synchronize with other relays.


HWSyncSrc: This is applicable if process bus IEC61850-9-2 protocol is used for receiving

analog values (optical CT PTs). In this case select time source available same as that of merging

unit. This setting is not applicable in present case.


32

AppSynch: If there is any loss of time sync, protection function will be blocked if AppSynch set

to Synch based on SyncAccLevel. If AppSunch set to NoSynch, protection functions are not

blocked. Recommended setting is NoSynch.

SyncAccLevel: If this is set to “Class T5 (1us)” and time synch error is more than 1us,

protection functions will be blocked. SyncAccLevel should be set to “Unspecified” when Nosynch

is selected at AppSynch. This parameter is not applicable in present case.

ModulePosition: if BIN is set for FineSyncSource, ModulePosition setting is applicable. Here

slot position of IO module in the relay is to be set (Which slot is used for BI). This parameter is

not applicable in present case.











NoHalfHourUTC: Time shift from GMT has to be set a multiple of half hours. Example for India

it is +05:30, means +11. Hence this parameter is set to +11 in present case.

SYNCHIRIG-B Non group settings: These settings are applicable if IRIG-B is used. This

parameter is not applicable in present case.

SynchType: Type of hardware input used for time sync, whether Opto or BNC. This parameter






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


33

Table 3-4: Time synchronization settings

TIMESYNCHGEN Non group settings (basic)

Setting


Recommended

Settings Unit









Setting


Recommended

Settings Unit


Synchronization 3 -


synchronization 1 -




Settings Unit




34


Setting


Recommended

Settings Unit







Setting


Recommended

Settings Unit







Setting


Recommended

Settings Unit



Setting


Recommended

Settings Unit







35




changed, is set with the parameter t. This is not the delay for changing setting group. This

parameter is normally recommended to set 1s.

MAXSETGR: The parameter MAXSETGR defines the maximum number of setting groups in use

to switch between. Only the selected number of setting groups will be available in the Parameter





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

Setting


Recommended

Settings Unit


Changed 1 s


Setting


Recommended

Settings Unit









36

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

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

Setting


Recommended

Settings Unit






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



Setting


Recommended

Settings

Unit



ObjectName Object name Transformer -


UnitName Unit name RET670 M1 -






37


Setting


Recommended

Settings Unit




DFTReference : Set ref for DFT filter adjustment here. These DFT reference block settings

decide DFT reference for DFT calculations.







Each task group has 12 instances of SMAI, in that first instance has some additional features

which is called master. Others are slaves and they will follow master. If measured sample rate

needs to be transferred to other task group, it can be done only with master.


DFTReference shall be set to default value InternalDFTRef if no VT input is available. Since VT

input is available in this case, the corresponding channel shall be set to DFTReference.

Configuration file has to be referred for this purpose.

DFTRefExtOut: This parameter is available only in Master. If reference is to be sent to other

task group, which reference need to be send has to be select here. For example, if voltage input

is connected to 3rd SMAI of 1ms task group, AdDFTRefCh3 is to be set in DFTRefExtOut of 1ms

task group.

DFTRefExtOut shall be set to default value InternalDFTRef if no VT input is available.



Negation is set to NegateN, it will give output R, Y, B and –N. If Negation is set to Negate3Ph, it

will give output -R, -Y, -B and N.


38

If R, Y, B inputs are connected, N=R+Y+B, and it will do as above. This parameter is

recommended to be set to OFF normally.


SMAI will work only if measured input magnitude is greater than set value in MinValFreqMeas.

This parameter is recommended to set 10% normally.




Table 3-9: Signal Matrix For Analog Inputs Setting


Recommended

Settings Unit






MinValFreqMeas Limit for frequency calculation in %

of UBase 10 %


3.1.10 Transformer differential protection T3WPDIF

There are two types of differential relays. Percentage biased differential relay with harmonic

restraint (2nd and 5th harmonic restraint) with a high set unit and high impedance differential relay.

For a multi-winding transformer only percentage biased relay can be applied whereas for

autotransformer both percentage biased and high impedance relays can be used. The simplicity

of comparing current into all terminals of the transformer gives the differential relay very high

reliability.

In case of percentage biased differential relays current transformers or auxiliary CT's in a delta

(In case of numerical relays this is done internally) connection have to be used at grounded


39

transformer windings to avoid false operation on external faults. The removed zero sequence

component, however, makes the transformer differential relay less sensitive.

The differential relay protection does an excellent job of meeting a large number of the

protective relaying requirements, but must be combined with other protective devices to provide

full transformer protection.

In case of breaker and half switching schemes, the differential protection C.Ts. associated with

Main and Tie breakers should be connected to separate bias windings and these should not be

paralleled in order to avoid false operation due to dissimilar C.T. transient response.

Differential protection is the most commonly applied protection for large power transformers in

transmission system.

Figure 3-1 shows the restrained and the unrestrained operate characteristics of Differential

protection.

Figure 3-1: Representation of the restrained and th e unrestrained operate characteristics


40


SOTFMode: Transformer differential (TW2PDIF for two winding and TW3PDIF for three

winding) function in the IED has a built-in, advanced switch onto fault feature. This feature can

be enabled or disabled by a setting parameter SOTFMode. When SOTFMode = On this feature

is enabled. However it shall be noted that when this feature is enabled it is not possible to test

2nd harmonic blocking feature by simply injecting one current with superimposed second

harmonic. In that case the switch on to fault feature will operate and differential protection will

trip. However for real inrush case the differential protection function will properly restrain from

operation. In present case this parameter is set OFF.

IDiffAlarm: Differential protection continuously monitors the level of the fundamental frequency

differential currents and gives an alarm if the pre-set value is simultaneously exceeded in all

three phases. This feature can be used to monitor the integrity of on-load tap-changer

compensation within the differential function.

The threshold for the alarm pickup level is defined by setting parameter IDiffAlarm. This

threshold should be typically set in such way to obtain operation when on-load tap-changer

measured value within differential function differs for more than two steps from the actual on-

load tap-changer position. To obtain such operation set parameter IDiffAlarm equal to two times

the on-load tap-changer step size (For example, typical setting value is 5% to 10% of base

current). Set the time delayed defined by parameter tAlarmDelay two times longer than the on-

load tapchanger mechanical operating time (For example, typical setting value 10s).

In present case, OLTC compensation is not used. Hence this parameter is set to 10%.

tAlarmDelay: Set the time delayed defined by parameter tAlarmDelay two times longer than the

on-load tap changer mechanical operating time. This parameter is set to 15s in present case.

IdMin: IdMin (Sensitivity in section 1, multiple of trans. HV side rated current set under the

parameter RatedCurrentW1). Default settings for the operating characteristic with IdMin = 0.3pu

of the power transformer rated current can be recommended as a default setting in normal

applications. If the conditions are known more in detail, higher or lower sensitivity can be

chosen. The selection of suitable characteristic should in such cases be based on the

knowledge of the class of the current transformers, availability of information on the load tap

changer position, short circuit power of the systems, and so on. In present case, the tap

changer range is +10% to -10%, considering the margin of 10%, recommended IdMin=0.2pu.

IdUnre: The unrestrained (that is, non-stabilized, "instantaneous") part of the differential

protection is used for very high differential currents, where it should be beyond any doubt, that

the fault is internal. This settable limit is constant (that is, not proportional to the bias current).


41

Neither harmonic, nor any other restrain is applied to this limit, which is therefore allowed to trip

power transformer instantaneously. Unrestrained operation level has default value of IdUnre =

10pu, which is typically acceptable for most of the standard power transformer applications.

However in the following cases these setting need to be changed accordingly:

• When CT from "T-connection" are connected to IED, as in the breaker-and-a half or the ring

bus scheme, special care shall be taken in order to prevent unwanted operation of transformer

differential IED for through-faults due to different CT saturation of "T-connected" CTs. Thus if

such uneven saturation is a possibility it is typically required to increase unrestrained

operational level to IdUnre = 20-25pu. Since in present case, uneven CT saturation is not

expected, this parameter is set to 10pu.

CrossBlockEn: In the algorithm the user can control the cross-blocking between the phases via

the setting parameter CrossBlockEn. When parameter CrossBlockEn is set to On, cross

blocking between phases will be introduced. There are no time related settings involved, but the

phase with the operating point above the set bias characteristic will be able to cross-block other

two phases if it is self-blocked by any of the previously explained restrained criteria. It is

recommended to set this parameter to ON.

When parameter CrossBlockEn is set to Off, any cross blocking between phases will be

disabled. In present case it is set ON.

NegSeqDiffEn: The internal/external fault discriminator is a very powerful and reliable

supplementary criterion to the traditional differential protection. It is recommended that this

feature shall be always used (that is, On) when protecting three-phase power transformers. The

internal/external fault discriminator detects even minor faults, with a high sensitivity and at high

speed, and at the same time discriminates with a high degree of dependability between internal

and external faults. In the absence of credible field experience, it is set to OFF in the present

case.

IMinNegSeq and NegSeqROA: These parameters are not applicable if NegSeqDiffEn is set to

OFF.

EndSection1, EndSection2, SlopeSection2 and SlopeSe ction3: EndSection1 (End of

section 1, as multiple of transformer HV side rated current set under the parameter

RatedCurrentW1), EndSection2 (End of section 2, as multiple of transformer HV side rated

current set under the parameter RatedCurrentW1), SlopeSection2 (Slope in section 2),

SlopeSection3 (Slope in section 3). The selection of suitable characteristic should in such

cases be based on the knowledge of the class of the current transformers, availability of

information on the load tap changer position, short circuit power of the systems, and so on.


42

The usual practice for transformer protection is to set the bias characteristic to a value of at

least twice the value of the expected spill current under through faults conditions. These criteria

can vary considerably from application to application and are often a matter of judgment.

In section 2, a certain minor slope is introduced which is supposed to cope with false differential

currents proportional to higher than normal currents through the current transformers.

The more pronounced slope in section 3 is designed to result in a higher tolerance to substantial

current transformer saturation at high through-fault currents, which may be expected in this

section.

In present case, these parameters are left with the default values recommended by manual.

EndSection1, EndSection2, SlopeSection2 and SlopeSection3 are set to 1.25, 3, 40% and 80%

respectively.

I2/I1Ratio: If the ratio of the second harmonic to fundamental harmonic in the differential current

is above the settable limit, the operation of the differential protection is restrained. It is

recommended to set parameter I2/I1Ratio = 15% as default value in case no special reasons

exist to choose other value.

I5/I1Ratio: If the ratio of the fifth harmonic to fundamental harmonic in the differential current is

above a settable limit the operation is restrained. It is recommended to use I5/I1Ratio = 25% as

default value in case no special reasons exist to choose another setting.

OpenCTEnable: The built-in open CT feature can be enabled or disabled by a setting

parameter OpenCTEnable (Off/On). When enabled, this feature prevents mal-operation when a

loaded main CT connected to Transformer differential protection is by mistake open circuited on

the secondary side. In present case this parameter is set OFF.

tOCTAlarmDelay, tOCTResetDelay and tOCTUnrstDelay: These parameters are not

applicable if OpenCTEnable is set OFF.

RatedVoltageW1: Rated voltage of transformer winding 1 (HV winding) in kV. This parameter is

set to 400kV.

RatedVoltageW2: Rated voltage of transformer winding 2 in kV. This parameter is set to

220kV.

RatedVoltageW3: Rated voltage of transformer winding 3 in kV. This parameter is set to 33kV.

RatedCurrentW1: Rated current of transformer winding 1 (HV winding) in A. This parameter is

set to 455A.

RatedCurrentW2: Rated current of transformer winding 2 in A. This parameter is set to 827A.

RatedCurrentW3: Rated current of transformer winding 3 in A. This parameter is set to 1837A.

Above setting parameters are calculated based on 400/220/33kV 315MVA ICT rating details.


43

ConnectTypeW1: Connection type of winding 1: Y-wye or D-delta. This parameter is set to Y.


ConnectTypeW3: Connection type of winding 3: Y-wye or D-delta. This parameter is set to D.

ClockNumberW2: Phase displacement between W2 & W1=HV winding, hour notation. This

parameter is set to 0 as it is Auto transformer.


parameter is set to 11, since Auto transformer clock symbol is YNa0d11.

ZSCurrSubtrW1: Enable zer. seq. current subtraction for W1 side, On / Off. The elimination of

zero sequence current is done numerically and no auxiliary transformers or zero sequence traps

are necessary. In present case this parameter is set ON.

ZSCurrSubtrW2: Enable zer. seq. current subtraction for W2 side, On / Off. In present case this


ZSCurrSubtrW3: Enable zer. seq. current subtraction for W3 side, On / Off. For delta windings

this feature shall be enabled only if an earthing transformer exists within differential zone on the

delta side of the protected power transformer. In present case this parameter is set OFF.

TconfigForW1: Two CT inputs (T-config.) for winding 1, YES / NO. For application with so

called "T" configuration, that is, two restraint CT inputs from one side of the protected power

transformer, such as in the case of breaker-and a- half scheme the primary CT ratings can be

much higher than the rating of the protected power transformer. In present case this parameter

is set to Yes.

CT1RatingW1, CT2RatingW1: CT primary rating in A, T-branch 1, on transf. W1 side and CT

primary in A, T-branch 2, on transf. W1 side. In preset case, these parameters are set to 1000A.

TconfigForW2: Two CT inputs (T-config.) for winding 2, YES / NO. In present case this

parameter is set to No.

CT1RatingW2, CT2RatingW2: These parameters are not applicable TconfigForW2 is set to

NO.




NO.

LocationOLTC1: Transformer winding where OLTC1 is Located. Parameter LocationOLTC1

defines the winding where first OLTC (OLTC1) is physically located. In present case, this is set

to “Not Used”.


44

LowTapPosOLTC1, RatedTapOLTC1, HighTapPsOLTC1, TapH ighVoltTC1,

StepSizeOLTC1: These parameters are not applicable if LocationOLTC1 is set to “Not Used”.

LocationOLTC2: Transformer winding where OLTC2 is Located. In present case, this is set to

“Not Used”.

LowTapPosOLTC2, RatedTapOLTC2, HighTapPsOLTC2, TapH ighVoltTC2,



Table 3-10 gives the recommended settings for Differential protection.

Table 3-10: Differential protection Settings

T3WPDIF Group settings (basic)

Setting


Recommended

Settings Unit


SOTFMode Operation mode for switch onto fault feature Off -

tAlarmDelay Time delay for diff currents alarm level 15 s

IDiffAlarm Dif. cur. alarm, multiple of base curr, usually W1 curr.

0.10 IB

IdMin Section1 sensitivity, multi. of base curr, usually W1 curr.

0.20 IB

IdUnre Unrestr. prot. limit, multi. of base curr. usually W1 curr.

10 IB

CrossBlockEn Operation Off/On for cross-block logic between phases

On -

NegSeqDiffEn Operation Off/On for neg. seq. differential protections

Off -

IMinNegSeq Neg. seq. curr. limit, mult. of base curr, usually W1 curr.

0.04 IB

NegSeqROA Operate Angle for int. / ext. neg. seq. fault discriminator

60.0 Deg

T3WPDIF Group settings (advanced)

Setting


Recommended

Settings Unit

EndSection1 End of section 1, multi. of base current, usually W1 curr. 1.25 IB

EndSection2 End of section 2, multi. of base current, 3 IB


45

usually W1 curr.

SlopeSection2 Slope in section 2 of operate-restrain characteristic, in %

40 %


80 %

I2/I1Ratio Max. ratio of 2nd harm. to fundamental harm dif. curr. in %

15 %

I5/I1Ratio Max. ratio of 5th harm. to fundamental harm dif. curr. in %

25 %

OpenCTEnable Open CT detection feature. Open CTEnable Off/On

Off -

tOCTAlarmDelay Open CT: time in s to alarm after an open CT is detected

3 s

tOCTResetDelay Reset delay in s. After delay, diff. function is activated

0.25 s

tOCTUnrstDelay Unrestrained diff. protection blocked after this delay, in s

10.0 s

T3WPDIF Non group settings (basic)

Setting


Recommended

Settings Unit

RatedVoltageW1 Rated voltage of transformer winding 1 (HV winding) in kV

400 kV

RatedVoltageW2 Rated voltage of transformer winding 2 in kV

220 kV


33 kV

RatedCurrentW1 Rated current of transformer winding 1 (HV winding) in A

455 A

RatedCurrentW2 Rated current of transformer winding 2 in A

827 A


1837 A

ConnectTypeW1 Connection type of winding 1: Y-wye or D-delta

WYE(Y) -


WYE(Y) -


Delta (D) -

ClockNumberW2 Phase displacement between W2 & W1=HV winding, hour notation

0 [0 deg] -


11[30 deg lead] -

ZSCurrSubtrW1 Enable zer. seq. current subtraction for W1 side, On / Off

On -


On -


46


Off -

TconfigForW1 Two CT inputs (T-config.) for winding 1, YES / NO

Yes -

CT1RatingW1 CT primary rating in A, T-branch 1, on transf. W1 side

1000 A

CT2RatingW1 CT primary in A, T-branch 2, on transf. W1 side

1000 A


No -


800 A


800 A


No -


1000 A


1000 A

LocationOLTC1 Transformer winding where OLTC1 is located

Not Used -

LowTapPosOLTC

1 OLTC1 lowest tap position designation (e.g. 1)

1 -

RatedTapOLTC1 OLTC1 rated tap/mid-tap position designation (e.g. 6)

6 -

HighTapPsOLTC

1 OLTC1 highest tap position designation (e.g. 11)

11 -

TapHighVoltTC1 OLTC1 end-tap position with winding highest no-load voltage

1 -

StepSizeOLTC1 Voltage change per OLTC1 step in percent of rated voltage

1.0 %


Not Used -

LowTapPosOLTC

2 OLTC2 lowest tap position designation (e.g. 1)

1 -


6 -

HighTapPsOLTC

2 OLTC2 highest tap position designation (e.g. 11)

11 -


1 -


1.0 %


47



All trip outputs from protection functions have to be routed to trip coil through SMPPTRC.

SMPPTRC function will give a pulse of set length (150ms) if trip signal is obtained.

tTripMin: Sets the required minimum duration of the trip pulse. It should be set to ensure that

the breaker is tripped and if a signal is used to start Breaker failure protection CCRBRF longer

than the back-up trip timer in CCRBRF. Normal setting is 0.150s.

Program: For Transformer protection trip, this parameter is recommended to be set to 3 phase.

tWaitForPHS: It Secures 3-pole trip when phase selection fails. In present case, there is no

phase selection, this parameter is not applicable. Therefor minimum setting of 0.02s is set.


CLLKOUT will be latched. Normally recommended setting is OFF. Therefor minimum setting of

0.02s is set.

AutoLock: If it is ON, lockout will be with both trip and SETLKOUT input. If it is set to OFF,

lockout will be with only SETLKOUT input. This parameter is normally recommended to be set

to OFF.


Table 3-11 gives the recommended settings for Tripping Logic.

Table 3-11: Tripping Logic Setting


Recommended

Settings Unit


Program Three ph; single or three ph; single, two or

three ph trip 3 phase -


tWaitForPHS Secures 3-pole trip when phase selection

failed 0.020 s

TripLockout On: activate output (CLLKOUT) and trip

latch, Off: only outp Off -

AutoLock On: lockout from input (SETLKOUT) and

trip, Off: only inp Off -


48




example, all Differential, REF, TOC and TEF trips using TMAGGIO function.



duration of the trip pulse to the circuit breaker trip coils. If TMAGGIO is used without SMPPTRC,

set pulse width of trip signal from TMAGGIO in PulseTime.

OnDelay: It is delay for output from TMAGGIO. If it is set to 100ms, even if trip is available, it

will not give output till 100ms. Hence it should be set to 0s. OnDelay timer is to avoid operation

of outputs for spurious inputs.


OffDelay, even if trip goes OFF, the output will appear 100ms. If “steady” mode is used,

pulsetime setting is not applicable, then output can be prolonged to 150ms with this setting. If

TMAGGIO is used with SMPPTRC, this should be set to 0s.


selected, it will give output till input is present if OffDelay is set to zero. If pulsed is selected,

output will be same as that of SMPPTRC.


Table 3-12 gives the recommended settings for Trip Matrix Logic. Table 3-12: Trip Matrix Logic

Setting


Recommended

Settings Unit









49

3.1.13 Four Step Phase Overcurrent Protection OC4PT OC:1 (Used for HV side)

The phase over current protection is a very inexpensive, simple and reliable scheme for fault

detection and is used for transformer protection applications. It can provide limited overload

protection but cannot provide instantaneous protection for all internal faults. It can also provide

back-up protection for bus bars. It does provide for transformer fault withstand protection and

some limited over load protection. It can provide back-up for failure of the switching device but

only with very long time delays. In normal applications, directional over current relays are

located on both the HV and IV sides of the transformer. Both relays are set to see into the

transformer. This allows better coordination with external over current relays because of the

need to see only part of the transformer windings.

An additional high set unit is also usually provided. The instantaneous elements help in

providing high-speed clearance of heavy current faults that threaten system stability. The relay

(Instantaneous element) suffers from having to be set very high to prevent tripping on transformer

inrush. Therefore it is ineffective for low magnitude internal transformer faults or phase to ground

faults on the low voltage side of the transformer.

Numerical over current relays provide upgraded performance for transformer back-up protection.

The digital filters remove the DC component and harmonics from the inrush current. Numerical

back-up over current relays can therefore be set much more sensitive than conventional types

and are recommended to be used.

The non-directional over current relays are used when they could be coordinated with the over

current protection on connecting lines. Coordination requirements usually require the clearing

times to be longer than the other types of back-up protection. Directional over current relay

improves the co-ordination by being set to look through the transformer impedance. For this

reason they are normally used for all interconnecting transformers. When applied on both sides

of the transformer, the current levels where coordination with line relaying is required is limited by

the transformer impedance which greatly improves the tripping times for higher current faults in

the transformer. The directional ground over current relay can be set much more sensitive and

with very short time delays. For all interconnecting transformers use of directional over current

and ground over current relays with high set units are recommended.

There are number of general problems with back-up relay viz., the sensitivity to the harmonic and

inrush currents. Setting must be able to allow inrush, which usually means de-sensitizing the


50

back-up relay. Numerical relays can filter harmonics and DC offset currents from the inrush and

therefore may be preferred.

The phase over current threshold should be set to ensure detection of all phase faults, but

above any continuous phase current under normal system operation. The timing should be

coordinated with the phase over current protection of downstream network.

The non-directional Instantaneous high set overcurrent element shall be set to a value

which is 1.3 times the transformer through fault current or transformer inrush current,

whichever is higher.


Figure 3-2 shows the directional function characteristic.

Where1. RCA = Relay characteristic angle, 2. ROA = Relay operating angle,

3. Reverse, 4. Forward

Figure 3-2: Directional function characteristic


51

IBase: Set the Base current for the function on which the current levels are based. This

parameter is set to 455A in present case, which is Transformer HV winding rated current.

UBase: Setting of the Base voltage level on which the directional polarizing voltage is based.

This parameter is set to 400kV in present case, which is Transformer HV winding rated voltage.

AngleRCA: Set the relay characteristic angle, i.e. the angle between the neutral point voltage

and current. This parameter is recommended to be set to 65°.

AngleROA: Set the relay operating angle, i.e the angle sector of the directional function. This

parameter is recommended to be set to 80°.

StartPhSel: Number of phases required for operation (1 of 3, 2 of 3, 3 of 3). This parameter is

recommended to be set to 1 out of 3.

DirMode1: Setting of the operating direction for the stage or switch it off. This parameter is set

to “Forward” in present case, which shall be looking towards transformer.

Characteristic1: Setting of the operating characteristic. This parameter is set to “IEC Norm.

Inv.” in present case.

I1>: Setting of the operating current level in primary values. This parameter is set to 150% of

base current in present case (two or more transformer 3-ph banks operating in parallel).

t1: When inverse time overcurrent characteristic is selected, the operate time of the stage will

be the sum of the inverse time delay and the set definite time delay. Thus, if only the inverse

time delay is required, it is of utmost importance to set the definite time delay for that stage to

zero. Hence this parameter is set to 0s in present case.

k1: Set the back-up trip time delay multiplier for inverse characteristic. Refer Appendix for more

details.

IMin1: Minimum operate current for step1 in % of IBase. This parameter is set to 150% of base


t1Min: Set the Minimum operating time for inverse characteristic. This parameter is set to 0.1s

in present case.

I1Mult: Set the current multiplier for I1 valid at activation of input ENMULT. As this parameter is



to “Non-directional” in present case.

Characteristic2: Setting of the operating characteristic. This parameter is set to “IEC Def.

Time” in present case.

I2>: Setting of the operating current level in primary values. Normally this parameter shall be set

to a current which is higher of 1.3 times the transformer through fault current (220kV side bus


52

fault) or transformer inrush current (Normally 8 -10 times the rated current, which can be set

much lower because of the DC and harmonic filtering in the numerical relays). This value is set

to 800% of HV rated current in present case.

IN2Mult: Set the current multiplier for IN1 valid at activation of input ENMULT. As this

parameter is not applicable in present case, setting is left with default value of 1.

t2: Independent (definitive) time delay of step 2. This parameter can be set in the range of 50-

100ms. In present case, this parameter is set to 50ms.

k2: Set the back-up trip time delay multiplier for inverse characteristic. This parameter is not

applicable in present case since Characteristic2 is set to “IEC Def. Time”.



t2Min: Set the Minimum operating time for inverse characteristic. This parameter is not




IMinOpPhSel: Minimum current for phase selection set in % of IBase. This setting should be

less than the lowest step setting. General recommended setting is 7%.

ResetTypeCrv1: Select the reset curve type for the inverse delay. This parameter is

recommended to set “Instantaneous”. However, to emulate the disc reset behavior, this can be

set to IEC.



tPCrv1, tACrv1, tBCrv1, tCCrv1, tPRCrv1, tTRCrv1 an d tCRCrv1: These parameters are

applicable only if Characterist1 is set to Programmable.

HarmRestrain1: Set the release of Harmonic restraint blocking for the stage. This parameter is

kept ON to make the protection stable during charging conditions.



set to IEC.






53




I1>: This parameter is set to 150% of base current in present case, which is 683A in primary.



t2: This parameter is set to 0.05s in present case.

Refer Appendix for more details of above four settings.


Table 3-13 gives the recommended settings for Four Step Phase Overcurrent Protection.

Table 3-13: Four Step Phase Overcurrent Protection OC4PTOC Group settings (basic)

Setting


Recommended

Settings

Unit




(Check with PT input in configuration ) 400 kV


AngleROA Relay operation angle (ROA) 80 Deg

StartPhSel Number of phases required for op (1 of

3, 2 of 3, 3 of 3) 1 out of 3 -

DirMode1 Directional mode of step 1 (off, nodir,

forward, reverse) Forward -


I1> Phase current operate level for step1 in

% of IBase 150 %IB


k1 Time multiplier for the inverse time delay

for step 1 0.26 -

IMin1 Minimum operate current for step1 in % 150% %IB


54

of IBase

t1Min Minimum operate time for inverse curves

for step 1 0.1 s

I1Mult Multiplier for scaling the current setting

value for step 1 1.0 -


forward, reverse) Non-directional -

Characterist2 Time delay curve type for step 2 IEC Def. Time -


% of IBase 800 %IB



for step 2 0 -

IMin2 Minimum operate current for step2 in %

of IBase 800% %IB


for step 2 0 s



DirMode3 Directional mode of step 3 (off, nondir,

forward, reverse) Off -



OC4PTOC Group settings (advanced)

IMinOpPhSel Minimum current for phase selection in

% of IBase 7 %IB

2ndHarmStab Second harmonic restrain operation in % of IN

amplitude 15 %

ResetTypeCrv1 Selection of reset curve type for step 1 Instantaneous -

tReset1 Reset time delay used in IEC Definite Time curve step 1

0.020 s

tPCrv1 Parameter P for customer programmable

curve for step 1 1 -


55

tACrv1 Parameter A for customer programmable

curve for step 1 13.5 -

tBCrv1 Parameter B for customer programmable


tCCrv1 Parameter C for customer

programmable curve for step 1 1 -

tPRCrv1 Parameter PR for customer

programmable curve for step 1 0.5 -

tTRCrv1 Parameter TR for customer


tCRCrv1 Parameter CR for customer


HarmRestrain1 Enable block of step 1 from harmonic restrain On -



Time curve step 2 0.020 s















HarmRestrain2 Enable block of step 2 from harmonic restrain On -


56

3.1.14 Four Step Phase Overcurrent Protection OC4PT OC:2 (Used for HV side

Overload alarm)

This function is used for Transformer Over load protection.

Oil Temperature Sensors

The top oil temperature sensors can detect overheating. The temperature limit settings

vary from utility to utility and also depend upon manufacturer's recommendations. Typical

settings are 95°C for alarm and 100°C for trip. Bec ause of the heating and cooling

requirements of a transmission power transformer some specialized temperature

protection is required to provide protection over the full range of operating limits of the

transformer. The transformer temperature depends upon the ambient temperature, the

cooling system condition, the excitation voltage and the transformer load. To provide for

temperature protection a sensor is usually provided to indicate top oil temperature. The

power transformers have a large thermal heat sink and can withstand overloads for certain

limited time. Selective protection, monitoring and load management are considered

necessary. The tripping of the transformer should be the last action.

Winding Temperature Sensors

Winding temperature sensors can detect overheating. The temperature limit settings vary from

utility to utility and also depend upon manufacturer's recommendations. Typical settings are

100°C for alarm and 110°C for trip. To simulate the winding temperature, a resistor sized to

approximate the heating in the transformer winding at full load is used. The resistor is fed by a

current transformer from one of the phase currents. To add oil temperature, the top oil is

circulated in to a well within the resistor. This combined heating of the resistor from transformer

current and top oil, is used to simulate the winding temperature.

These two relays do not meet any of the other requirements but are again the only relays which

meet the over load temperature limit requirements.

For higher reliability duplicating of the initiating contacts is sometimes done and may be

considered on a case-to-case basis.

Overload Relay

It is also a practice to use a simple over current relay with a time delay arranged to give alarm to

warn the operator of any overloading of the transformer. Use of thermal relay to provide tripping


57

is also practiced by some utilities. But in present case, it is not done because this might trip the

transformer too early which is not desirable.

In the event of sudden increase in load current, the mechanical protections like Oil temperature

high and Winding temperature high should take care of this as described above.

Overload relay shall be set at 105% of rated current with delay of 5 seconds. This shall be

connected to give only alarm and not for tripping. The Alarm is used to alert the operator to

take necessary steps to reduce loading.






This parameter is not applicable in present case, since DirMode1 is set to Non-directional.


and current. This parameter is recommended to be set to 65°. This parameter is not applicable

in present case, since DirMode1 is set to Non-directional.


parameter is recommended to be set to 80°. This par ameter is not applicable in present case,

since DirMode1 is set to Non-directional.

StartPhSel: Number of phases required for op (1 of 3, 2 of 3, 3 of 3). This parameter is







base current in present case.

t1: This is the definite time delay for step-I. In present case this parameter is set to 5s.


applicable in present case, since Characteristic1 is set to IEC Def. Time.




58





DirMode2, DirMode3 and DirMode4: Setting of the operating direction for the stage or switch it

off. All three stages are set to OFF.





set to IEC.










Setting


Recommended

Settings

Unit








3, 2 of 3, 3 of 3) 1 out of 3 -




59

Characterist1 Time delay curve type for step 1 IEC Dif. Time -


% of IBase 105 %IB



for step 1 0.3 -


of IBase 105 %IB


for step 1 0 s











% of IBase 7 %IB

2ndHarmStab Second harmonic restrain operation in %

of IN amplitude 20 %











60









HarmRestrain1 Enable block of step 1 from harmonic

restrain On -

Important note: The above function used for overload alarm shall b e configured for alarm and no trip in the signal matrix of IED.

3.1.15 Four Step Residual Overcurrent Protection EF 4PTOC (Used for HV side)

Various ground fault protections used are described below. Generally, these protections are

meant to provide the grounded winding with a low sensitivity ground fault protection only. They

do not provide other types of protection.

Zero Sequence Over Current Relays

Zero-sequence over current relays provide protection against internal phase-to-ground faults.

The neutral current or the residual current may energize the over current relay. The setting may

be much lower than the rated phase current. Harmonic restraint may be required to obtain

sensitive settings. An additional high set unit is also usually provided.

Directional Earth Fault Relay

This type of protection is also specific to transformers with at least one directly grounded or

resistance grounded winding. The protection is specialized to protect for winding faults to

ground. The connections of the over current units can be only in the neutral, or in the residual

phase. These connections can be set much lower than the phase over current because of the

cancellation of the phase current.


61

The sensitivity to the harmonic and inrush currents can be one of the main problems with back-

up ground over current relays. Settings must be able to allow inrush, which usually means

desensitizing the back-up relay. Numerical relay offers the best characteristic since digital filters

remove harmonics and DC offset currents from the inrush.


Figure 3-3 shows the Operating characteristic for earth-fault directional element.

Figure 3-3: Operating characteristic for earth-fau lt directional element


62

The ground over current threshold should be set to ensure detection of all ground faults, but

above any continuous residual current under normal system operation. The timing should be

coordinated with the downstream backup protection including Zone-3 timing for a remote end

220kV bus fault.









IN1>: Setting of the operating current level in primary values. This parameter is set to 20% of








k1: Set the back-up trip time delay multiplier (TMS) for inverse characteristic. Refer Appendix

for more details.


in present case.



set to IEC.








63





IN2>: Setting of the operating current level in primary values. Normally this parameter shall be

set to a current which is higher of 1.3 times the transformer 1-phase through fault current

(220kV side bus fault) or transformer inrush current (Normally 8 -10 times the rated current,

which can be set much lower because of the DC and harmonic filtering in the numerical relays).

This value is set to 800% of HV rated current in present case.



t2: Independent (definitive) time delay of step 2, this parameter is set to 50ms in present case.







set to IEC.








measure 3U0 from 3 phase voltages and -3U0 is reference. If it is set “Current”, it will measure

3I0 from I3PPOL input and calculate 3U0 using RNPol and XNPol values. If it is set “Dual”, it will


UPolMin: Setting of the minimum neutral point polarizing voltage level for the directional

function. Generally this parameter is recommended to set 1% of base voltage.





64

IN>Dir: Minimum current required for directionality. This should be lower than pickup of earth

fault protection. This parameter is normally recommended to be set to 10% of the base current.

2ndHarmStab: Setting of the harmonic content in IN current blocking level. This is to block

earth fault protection during inrush conditions. Setting is in percentage of I2/I1. This parameter

is normally recommended to be set to 15%.


expected due to sympathetic inrush. If residual current is higher during switching of a

transformer connecting in parallel with other transformer and if 2nd harmonic current is lower

than 2ndHarmStab set value, earth fault protection may operate because of high residual

current. Inrush current in Line CTs may be higher at beginning and later it may be reduced. If

“BlkParTransf” is set ON, protection will be blocked till residual current is lower than set pickup

of selected “UseStartValue”. This parameter is normally recommended to be set to OFF.

UseStartValue: Select a step which is set for sensitive earth fault protection for above

blocking. This parameter is not applicable if BlkParTransf is set to OFF.

SOTF: Set the SOTF function operating mode. If “SOTF” is set ON, as per the logic given in

TRM, trip from SOTF requires start of step-2 or step-3 along with the activation of breaker

closing command. Since Directional earth function has IDMT characteristics, SOTF is set to

OFF.

ActivationSOTF, ActUndertime, t4U, tSOTF, tUndertim e, HarmResSOTF: These parameters

are not applicable if SOTF is set to OFF.










65

Table 3-15: Four Step Residual Overcurrent Protecti on

Setting


Recommended

Settings

Unit







UPolMin Minimum voltage level for polarization in %

of UBase 1 %UB

IPolMin Minimum current level for polarization in

% of IBase 5 %IB

RNPol Real part of source Z to be used for current

polar-isation 5 Ohm

XNPol Imaginary part of source Z to be used for

current polarisation 40 ohm

IN>Dir Residual current level for Direction release

in % of IBase 10 %IB




UseStartValue Current level blk at paral-lel transf (step1, 2,

3 or 4) IN4> -

SOTF SOTF operation mode (Off/SOTF/Under-

time/SOTF+undertime) Off -




tSOTF Time delay for SOTF 0.200 s

t4U Switch-onto-fault active time 1.000 s

DirMode1 Directional mode of step 1 (off, nodir, Forward -


66

forward, reverse)


IN1> Operate residual current level for step 1 in

% of IBase 20 %IB


k1 Time multiplier for the dependent time

delay for step 1 0.58 -

IN1Mult Multiplier for scaling the current setting



for step 1 0.1 s

ResetTypeCrv1 Reset curve type for step 1 Instantaneous -

tReset1 Reset time delay for step 1 0.0 s


restrain On -


















IN2> Operate residual current level for step 2 in 800 %IB


67

% of IBase

t2 Independent (definite) time delay of step 2 0.05 s






for step 2 0 s




restrain On -




















68

3.1.16 Overexcitation protection OEXPVPH— (HV side)

This is another type of specialized protective relaying application where only one protective

level is covered. No other relay provides adequate over-excitation protection of the transformer

core. Damage to the core laminations can occur if an excitation larger than the Volts/Hertz

rating of the transformer is reached. This type of protection does not cover any requirements

except this one.

For grid transformers this protection may lead to cascade tripping due to the fact that all the

substation transformers subjected to over voltages coupled with drop in frequency will be allowed

to trip. An extract from CIGRE, SC-34 working group report 'Transformer overfluxing protection"

from ELECTRA (No31), 1973 is reproduced below:

"Considering margins between rated and saturation flux densities previously stated, it is

concluded that, in general, no special over fluxing protection is necessary for transformers

connected to the system and this is confirmed by literature and the replies from working groups

enquiries"

In Indian power system, it has been a practice to use over excitation relay for the grid

transformers also.

The transformer overfluxing protection has been recommended on both sides for

interconnecting transformers. This is to cover all possible operating conditions, e.g. the

transformer may remain energised from either side. For other transformers overfluxing relay

shall be provided on the untapped winding of the Transformer.


IBase: The IBase setting is the setting of the base (per unit) current on which all percentage

settings are based. Normally the power transformer rated current is used but alternatively the

current transformer rated current can be set. This parameter is set to 455A in present case,

which is Transformer HV winding rated current.

UBase: The UBase setting is the setting of the base (per unit) voltage on which all percentage

settings are based. The setting is normally the system voltage level. This parameter is set to

400kV in present case, which is Transformer HV winding rated voltage.

V/Hz>: Operating level for the inverse characteristic, IEEE or tailor made. The operation is

based on the relation between rated voltage and rated frequency and set as a percentage


69

factor. Normal setting is around 108-110% depending of the capability curve for the

transformer/generator. In present case this is set to 110% based on given Overfluxing curve.

V/Hz>>: Operating level for the tMin definite time delay used at high over-voltages. The

operation is based on the relation between rated voltage and rated frequency and set as a

percentage factor. Normal setting is around 110-180% depending of the capability curve for the

transformer/generator. Setting should be above the knee-point when the characteristic starts to

be straight on the high side. In present case this is set to 150% based on given Overfluxing

curve.

XLeak: The transformer leakage reactance on which the compensation of voltage measurement

with load current is based. The setting shall be the transformer leak reactance in primary ohms.

If no current compensation is used (mostly the case) the setting is not used.

TrPulse: The length of the trip pulse. Normally the final trip pulse is decided by the trip function

block. A typical pulse length can be 150ms.

tMin: The operating times at voltages higher than the set V/Hz>>. The setting shall match

capabilities on these high voltages. In present case this is set to 1s based on given Overfluxing

curve.

tMax: For overvoltages close to the set value times can be extremely long if a high K time

constant is used. A maximum time can then be set to cut the longest times. Generally this

parameter is recommended to set to maximum available set value i.e 9000s.

tCooling: The cooling time constant giving the reset time when voltages drops below the set

value. Shall be set above the cooling time constant of the transformer.

The default value is recommended to be used if the constant is not known. Hence this

parameter is left with the default value of 1200s.

CurveType: Selection of the curve type for the inverse delay. The IEEE curves or tailor made

curve can be selected depending of which one matches the capability curve best. Tailor made

curve is recommended to match relay set curve with transformer withstanding curve.

kForIEEE: The time constant for the inverse characteristic. Select the one giving the best match

to the transformer capability. This parameter is not applicable if CurveType is selected to Tailor

made.

AlarmLevel: Setting of the alarm level in percentage of the set trip level. The alarm level is

normally set at around 98% of the trip level.

tAlarm: Setting of the time to alarm is given from when the alarm level has been reached.

Typical recommended setting is 5s.


70

A typical overexcitation capability curve and V/Hz protection settings for power transformer is

illustrated in Figure 3-4.

Figure 3-4: A typical overexcitation capability cu rve and V/Hz protection settings for

power transformer


As per the Transformer Over Fluxing curve provided, Tailor made curve is selected and setting

parameters for tailor made curve are arrived from given Over Fluxing curve as explained below.

V/Hz> for the protection is set equal to the permissible continuous overexcitation according to

overexcitation curve provided V/Hz>= 110%. When the overexcitation is equal to V/Hz>, tripping

is obtained after a time equal to the setting of t1. When the overexcitation is equal to the set

value of V/Hz>>, tripping is obtained after a time equal to the setting of t6. The interval between

V/Hz>> and V/Hz> is automatically divided up in five equal steps, and the time delays t2 to t5


71

will be allocated to these values of overexcitation. In this case, each step will be (150-110) /5 =

8%, since V/Hz>> is set to 150% and V/Hz> is set to 110% of rated V/Hz.

90% of its capability limits is considered for tripping. For example, if transformer can withstand

126% of Overflux till 55s from Overfluxing curve, we have set trip time 0.9 x 55 = 49.5s in relay

to protect transformer before entering danger zone. The settings of time delays t1 to t6 are listed

in table below. Figure 3-5 shows the tailor made curve for Over fluxing protection.

U/F % Timer Time set (s)

110 t1 9000

118 t2 90

126 t3 49.5

134 t4 18

142 t5 4

150 t6 1

Figure 3-5: Relay tailor made curve and Transforme r withstand limit curve (V/Hz Vs s)


72


Table 3-16 gives the recommended settings for Overexcitation protection.

Table 3-16: Overexcitation protection OEXPVPH

OEXPVPH Group settings (basic)

Setting


Recommended

Settings

Unit


IBase Base current (rated phase current) in A 455 A

UBase Base voltage (main voltage) in kV 400 kV

V/Hz> Operate level of V/Hz at no load and

rated freq in % of (Ubase/frated) 110 %UB/f

V/Hz>> High level of V/Hz above which tMin is

used, in % of (Ubase/frated) 150 %UB/f

XLeak Winding leakage reactance in primary

ohms 0.000 Ohm

TrPulse Length of the pulse for trip signal (in sec) 0.150 s

tMin Minimum trip delay for V/Hz inverse

curve, in sec 1 s

tMax Maximum trip delay for V/Hz inverse

curve, in sec 9000 s

tCooling Transformer magnetic core cooling time

constant, in sec 1200 s

CurveType Inverse time curve selection, IEEE/Tailor

made Tailor made -

kForIEEE Time multiplier for IEEE inverse type

curve 1 -

AlarmLevel Alarm operate level as % of operate level 98 %

tAlarm Alarm time delay, in sec 5 s


73

OEXPVPH Group settings (advanced)

Setting


Recommended

Settings

Unit

t1Tailor Time delay t1 (longest) for tailor made


t2Tailor Time delay t2 for tailor made curve, in sec 90 s

t3Tailor Time delay t3 for tailor made curve, in sec 49.5 s



T6Tailor Time delay t6 (shortest) for tailor made

curve, in sec 1 s

OEXPVPH Non group settings (basic)

Setting


Recommended

Settings

Unit

MeasuredU Selection of measured voltage PosSeq -

MeasuredI Selection of measured current PosSeq -





system disturbance can be obtained. List of typical signals recommended to be recorded is

given below:


From 400kV Main Bay CT:

IA

IB

IC

IN

From 400kV Tie Bay CT:


74

IA

IB

IC

IN

From 220kV CT:

IA

IB

IC

IN

From 400kV Bus PT:

VAN

VBN

VCN


— Gr-A Trip

— Gr-B Trip

— Intertrip from 220kV Receive

— 400kV Bus bar trip



— Under Voltage

— Over Current

Note: These may need modification depending upon Protections chosen and the contact

availability for certain functions.

Recording capacity

— Record minimum eight (8) analog inputs and minimum sixteen (16) binary signals per

bay or circuit.

Memory capacity


Recording times



75




PostFaultRecT: This is the maximum recording time after the disappearance of the trig-signal.

The setting is recommended to be set to 2.5s




PostRetrig: If it is made ON, new disturbance will be recorded if new trigger signal appears

during a recording. If it is made OFF, a separate DR will not be triggered if new trigger signal

appears during a recording. This parameter is recommended to be set to OFF normally.





Table 3-17: Disturbance Report Setting


Recommended

Settings Unit










76

3.2 RET670-2

3.2.1 Analog Inputs




Ch 1 Ch 2 Ch 3 Ch 4 Ch 5 Ch 6 Name# REF MV OC-R MV OC-Y MV OC-B SPARE SPARE CTprim 1 800 800 800 1000 1000 CTsec 1A 1A 1A 1A 1A 1A




Ch 1 Ch 2 Ch 3 Ch 4 Ch 5 Ch 6 Name# UL1-MV UL2-MV UL3-MV SPARE SPARE SPARE VTprim 220kV 220kV 220kV 220kV 220kV 220kV

VTsec 110V 110V 110V 110V 110V 110V

# User defined text





Recommended

Settings Unit










77
































78











Recommended

Settings

Unit











79









Setting


Recommended

Settings Unit




disturbance 0.0 s

















80




time.





available in site.


























81


















Setting


Recommended

Settings Unit









Setting


Recommended

Settings Unit


Synchronization 3 -


82


synchronization 1 -




Settings Unit




Setting


Recommended

Settings Unit



WeekInMonth Week in month when daylight time

starts Last -




Setting


Recommended

Settings Unit




starts Last -




83


Setting


Recommended

Settings Unit



Setting


Recommended

Settings Unit


















84

Table 3-22: Parameter setting group


Setting


Recommended

Settings Unit


Changed 1 s


Setting


Recommended

Settings Unit








Recommended Settings: Table 3-23 gives the recommended settings for Test mode functionality.


Setting


Recommended

Settings Unit






85


Recommended Settings: Table 3-24 gives the recommended settings for IED Identifiers.



Setting


Recommended

Settings

Unit











Setting


Recommended

Settings Unit







86

















task group.















87


Setting


Recommended

Settings Unit







of UBase 10 %


3.2.10 1Ph High impedance differential protection H ZPDIF

Zero- sequence differential relays (Restricted earth fault relay) provide best protection against

phase-to-ground faults in transformers connected to solidly grounded systems or resistance

grounded transformers. The residual current and the neutral current energize the relay.

Whenever separate phase-wise C.Ts are available on neutral side of transformer, triple pole

high impedance relay may be provided instead of single pole R.E.F. relay.


U>Alarm: Set the alarm level. The sensitivity can roughly be calculated as a divider from the

calculated sensitivity of the differential level. A typical setting is 20% of U>Trip It can be used as

scheme supervision stage.

tAlarm: Set the time for the alarm. A typical setting is 5s.

U>Trip: The level is selected with margin to the calculated required voltage to achieve stability.

Values can be 20-200 V dependent on the application.

SeriesResistor: Set the value of the stabilizing series resistor. Adjust the resistor as close as

possible to the calculated value. Measure the value achieved and set this value here.


88


This Protection is based on High Impedance differential scheme.

The setting value of the relay can be calculated as below:

CT Details: HV phase side, IV side and Neutral side –1000 /1, CL: PS

Rct = 5Ω

Rl = 2.178Ω, considered 250mts distance from Phase/Neutral CT to relay connected using a

cable of 2.5mm2 having resistance of 8.71Ω/km.

Voltage drop across the circulating current circuit for external faults,

Us = Ikmax x (Rct + 2* Rl)/n where

Maximum through fault current (3-ph) = 220kV / (1.732 x (Source Impedance + Trafo

Impedance))

Source Impedance = 0 (Assumed)

MVA Rating = 315MVA

Base impedance = kV2 / MVA = 153.65Ω

Actual impedance = 153.65 * (12.5 / 100) = 19.21Ω

Maximum through fault current (3-ph) = 220kV / (1.732 x (0+19.21)) = 6.613kA

Rct = the internal resistance of the current transformer secondary winding = 5Ω

Rl = the total resistance of the longest measuring circuit loop = 2.178Ω

n = turns ratio of the current transformer = 1/1000

Hence Us = 6613 x (5 + 2x2.178) * 1 /1000 = 61.87V

Recommended Settings = 68.06 ≈ 68 V with a margin of 10%. (A typical margin is 10 to

50%.)

CT requirement with Vk = 2*Us = 2* 68 = 136V Approx. (min)

REF high impedance Function element is used with Stabilizing resistor.

Pickup shall be decided based on the following criteria:

Stabilizing resistor:

For a sensitivity of 2% i.e 0.02*In, (This 2% setting is for 400kV class transformers. For 765kV

transformer, this could be set higher to take care of DC offset & CT errors)

Rs ≥ Us/I =68/0.02 = 3400Ω to be connected in series.

Chosen Rs= 3400Ω. (Approx)

Primary operating sensitivity:

Iprim = n x ( Irelay + Iu + mx Im )

where, n = turn ratio of the CT = 1000 in present case.


89

Irelay = relay set operation current in secondary Amps = 20mA in present case.

Iu = leakage current through the Voltage Dependent Resistor (VDR) at stabilizing voltage Us =

3mA

Approximate value of the current thorough non-linear resistor for the voltage of 68V (Us) is 3mA.

This is considered from the Current voltage characteristics for the non-linear resistors.

m = number of CTs connected in parallel in the secondary circuit = 4 in present case.

Im = magnetizing current of the CT at stabilizing voltage Us = 2mA in present case.

This value is calculated by using CT magnetizing current 60mA at Vk and Vk = 2000V.

By using above values, Iprim = 1000 x (20+ 3 + 3x2) = 29A.

Kindly Note that the following requirements for app lying High impedance differential relays.

• Turns ratios of CTs should be identical

• Auxiliary CTs should not be used

• Loop impedance (Rct+2Rl) up to the CT paralleling p oint should be identical

• Magnetizing characteristics should be identical


Table 3-27 gives the recommended settings for 1Ph High impedance differential protection.

Table 3-27: 1Ph High impedance differential protect ion HZPDIF

Setting


Recommended

Settings

Unit


U>Alarm Alarm voltage level in volts on CT

secondary side 13.6 V

tAlarm Time delay to activate alarm 5 s

U>Trip Operate voltage level in volts on CT

secondary side 68 V

SeriesResistor Value of series resistor in Ohms 3400 ohm

Note: The respective analog channel in RET670 (For REF current input) should be set to

1:1.


90

3.2.11 Four Step Phase Overcurrent Protection OC4PT OC---(For IV side)

The phase over current threshold should be set to ensure detection of all phase faults, but

above any continuous phase current under normal system operation. The timing should be

coordinated with the upstream phase over current protection. The guiding philosophy is similar

to the one described for the HV back-up overcurrent function in RET670-1 (Refer Figure 3-2).



parameter is set to 827A in present case, which is Transformer IV winding rated current.


This parameter is set to 220kV in present case, which is Transformer IV winding rated voltage.




parameter is recommended to be set to 80°.














details.




in present case.


91







I2>: Setting of the operating current level in primary values. Normally this parameter shall be set

to 130% of maximum transformer 1-phase through fault current or transformer inrush current

whichever is higher.
















set to IEC.









set to IEC.


92








I1>: This parameter is set to 150% of base current in present case, which is 909.7A in primary.








Setting


Recommended

Settings

Unit








3, 2 of 3, 3 of 3) 1 out of 3 -





% of IBase 150 %IB


93



for step 1 0.18 -


of IBase 150 %IB


for step 1 0.1 s







% of IBase 800 %IB



for step 2 0.3 -


of IBase 800% %IB


for step 2 0 s








94



% of IBase 7 %IB





















restrain On -











95










restrain On -

3.2.12 Four Step Residual Overcurrent Protection EF 4PTOC---(for IV side)

Guiding philosophy for this function is similar to that described for HV back-up earth fault

function in RET670-1 (Refer Figure 3-3).



above any continuous residual current under normal system operation. The timing should be

coordinated with the upstream backup protection including Zone-3 timing for a remote end

400kV bus fault.


parameter is set to 827A in present case, which is Transformer IV winding rated current.


This parameter is set to 220kV in present case, which is Transformer IV winding rated voltage.








96








details.


in present case.



set to IEC.











IN2>: Setting of the operating current level in primary values. Normally this parameter shall be

set to 130% of maximum transformer through fault current.









97



set to IEC.








measure 3U0 from 3 phase voltages and -3U0 is reference. If it is set “Current”, it will measure

3I0 from I3PPOL input and calculate 3U0 using RNPol and XNPol values. If it is set “Dual”, it will



function. Generally this parameter is recommended to set 1% of base voltage.





fault protection. This parameter is normally recommended to be set to 10% of the base current.
















98


OFF.

ActivationSOTF, ActUndertime, t4U, tSOTF, tUndertim e, HarmResSOTF: These parameters










Table 3-29: Four Step Residual Overcurrent Protecti on Setting


Recommended

Settings

Unit








of UBase 1 %UB

IPolMin Minimum current level for polarization in

% of IBase 5 %IB


polar-isation 5 Ohm


current polarisation 40 ohm




99





3 or 4) IN4> -












% of IBase 20 %IB







for step 1 0 s




restrain On -



tACrv1 Parameter A for customer programmable curve for step 1

13.5 -




100













% of IBase 800 %IB







for step 2 0 s




restrain On -







tCCrv2 Parameter C for customer programmable curve for step 2

1 -




101









3.2.13 Overexcitation protection OEXPVPH ---(IV side)

Guiding philosophy for this protection is similar to that given for HV side overfluxing function in

RET670-1 (Refer Figure 3-4 for typical overexcitation capability curve).


IBase: The IBase setting is the setting of the base (per unit) current on which all percentage

settings are based. Normally the power transformer rated current is used but alternatively the

current transformer rated current can be set. This parameter is set to 827A in present case,

which is Transformer IV winding rated current.

UBase: The UBase setting is the setting of the base (per unit) voltage on which all percentage

settings are based. The setting is normally the system voltage level. This parameter is set to

220kV in present case, which is Transformer IV winding rated voltage.

V/Hz>: Operating level for the inverse characteristic, IEEE or tailor made. The operation is

based on the relation between rated voltage and rated frequency and set as a percentage

factor. Normal setting is around 108-110% depending of the capability curve for the

transformer/generator. In present case this is set to 110% based on given Overfluxing curve.

V/Hz>>: Operating level for the tMin definite time delay used at high overvoltages. The

operation is based on the relation between rated voltage and rated frequency and set as a

percentage factor. Normal setting is around 110-180% depending of the capability curve for the

transformer/generator. Setting should be above the knee-point when the characteristic starts to

be straight on the high side. In present case this is set to 150% based on given Overfluxing

curve.


102

XLeak: The transformer leakage reactance on which the compensation of voltage measurement

with load current is based. The setting shall be the transformer leak reactance in primary ohms.

If no current compensation is used (mostly the case) the setting is not used.

TrPulse: The length of the trip pulse. Normally the final trip pulse is decided by the trip function

block. A typical pulse length can be 150ms.

tMin: The operating times at voltages higher than the set V/Hz>>. The setting shall match

capabilities on these high voltages. In present case this is set to 1s based on given Overfluxing

curve.

tMax: For overvoltages close to the set value times can be extremely long if a high K time

constant is used. A maximum time can then be set to cut the longest times. Generally this

parameter is recommended to set to maximum available value i.e. 9000s.

tCooling: The cooling time constant giving the reset time when voltages drops below the set

value. It shall be set above the cooling time constant of the transformer.

The default value is recommended to be used if the constant is not known. Hence this

parameter is left with the default value of 1200s.

CurveType: Selection of the curve type for the inverse delay. The IEEE curves or tailor made

curve can be selected depending of which one matches the capability curve best. Tailor made

curve is recommended to match relay set curve with transformer withstanding curve.

kForIEEE: The time constant for the inverse characteristic. Select the one giving the best match

to the transformer capability. This parameter is not applicable if CurveType is selected to Tailor

made.

AlarmLevel: Setting of the alarm level in percentage of the set trip level. The alarm level is

normally set at around 98% of the trip level.

tAlarm: Setting of the time to alarm is given from when the alarm level has been reached.

Typical recommended setting is 5s.


As per the Transformer Over Fluxing curve provided, Tailor made curve is selected and setting

parameters for tailor made curve are arrived from given Over Fluxing curve as explained below.

V/Hz> for the protection is set equal to the permissible continuous overexcitation according to

overexcitation curve provided V/Hz>= 110%. When the overexcitation is equal to V/Hz>, tripping

is obtained after a time equal to the setting of t1. When the overexcitation is equal to the set

value of V/Hz>>, tripping is obtained after a time equal to the setting of t6. The interval between

V/Hz>> and V/Hz> is automatically divided up in five equal steps, and the time delays t2 to t5


103

will be allocated to these values of overexcitation. In this case, each step will be (150-110) /5 =

8%, since V/Hz>> is set to 150% and V/Hz> is set to 110% of rated V/Hz.

We have considered 90% of its capability limits for tripping. For example, if transformer can

withstand 126% of Overflux till 55sec from Overfluxing curve, we have set trip time 0.9 x 55 =

49.5s in relay to protect transformer before entering danger zone. The settings of time delays t1

to t6 are listed in table below. Figure 3-9 shows the tailor made curve for Over fluxing protection.

U/F % Timer Time set (s)

110 t1 9000

118 t2 90

126 t3 49.5

134 t4 18

142 t5 4

150 t6 1

Figure 3-6: Relay tailor made curve and Transforme r with stable limit curve (V/Hz Vs s)


104


Table 3-30 gives the recommended settings for Overexcitation protection.

Table 3-30: Overexcitation protection OEXPVPH

OEXPVPH Group settings (basic)

Setting


Recommended

Settings

Unit


IBase Base current (rated phase current) in A 827 A

UBase Base voltage (main voltage) in kV 220 kV

V/Hz> Operate level of V/Hz at no load and

rated freq in % of (Ubase/frated) 110 %UB/f

V/Hz>> High level of V/Hz above which tMin is

used, in % of (Ubase/frated) 150 %UB/f

XLeak Winding leakage reactance in primary

ohms 0.000 Ohm

TrPulse Length of the pulse for trip signal (in sec) 0.150 s

tMin Minimum trip delay for V/Hz inverse

curve, in sec 1 s

tMax Maximum trip delay for V/Hz inverse


tCooling Transformer magnetic core cooling time

constant, in sec 1200 s

CurveType Inverse time curve selection, IEEE/Tailor

made Tailor made -

kForIEEE Time multiplier for IEEE inverse type

curve 1 -

AlarmLevel Alarm operate level as % of operate level 98 %

tAlarm Alarm time delay, in sec 5 s


105

OEXPVPH Group settings (advanced)

Setting


Recommended

Settings

Unit

t1Tailor Time delay t1 (longest) for tailor made



t3Tailor Time delay t3 for tailor made curve, in sec 49.5 s



T6Tailor Time delay t6 (shortest) for tailor made

curve, in sec 1 s

OEXPVPH Non group settings (basic)

Setting


Recommended

Settings

Unit

MeasuredU Selection of measured voltage PosSeq -

MeasuredI Selection of measured current PosSeq -






given below:


From REF input:

Iref

From 220kV CT:

IA

IB

IC


106

IN

From 220kV Bus PT:

VAN

VBN

VCN


— Group-A Trip

— Group-B Trip

— Inter Trip from HV side Receive


— 220kV CB LBB trip


— Over Current

— Under voltage



Recording capacity


bay or circuit.

Memory capacity


Recording times

— Minimum pre-fault recording time of 200ms










107










Recommended

Settings Unit










108

3.3 REC670

3.3.1 Analog Inputs




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




Ch 1 Ch 2 Ch 3 Ch 4 Ch 5 Ch 6 Name# UL1-HV UL2-HV UL3-HV UL1-MV UL2-MV UL3-MV VTprim 400kV 400kV 400kV 220kV 220kV 220kV

VTsec 110V 110V 110V 110V 110V 110V

# User defined text


Table 3-32 gives the recommended settings for Analog Inputs.

Table 3-32: Analog Inputs Setting


Recommended

Settings Unit









109

































110











Recommended

Settings

Unit









111










Table 3-34: LEDGEN Non group settings (basic) Setting


Recommended

Settings Unit




Disturbance 0.0 s

















112




time.





available in site.


























113












TimeDomain: In present case, this parameter is set to LocalTime.

Encoding: In present case, this parameter is set to IRIG-B

TimeZoneAs1344: In present case, this parameter is set to PlusTZ


Table 3-35 gives the recommended settings for Time Synchronization.

Table 3-35: Time Synchronization TIMESYNCHGEN Non group settings (basic)

Setting


Recommended

Settings Unit









114


Setting


Recommended

Settings Unit


Synchronization 3 -


Synchronization 1 -




Settings Unit




Setting


Recommended

Settings Unit







Setting


Recommended

Settings Unit




starts Last -

UTCTimeOfDay UTC Time of day in seconds when 3600 s


115

daylight time starts


Setting


Recommended

Settings Unit



Setting


Recommended

Settings Unit
















Table 3-36 gives the recommended settings for Parameter Setting Groups.

Table 3-36: Parameter Setting Groups ActiveGroup Non group settings (basic)

Setting


Recommended

Settings Unit


116

t Pulse length of pulse when setting Changed 1 s


Setting


Recommended

Settings Unit









Table 3-37 gives the recommended settings for Test Mode Functionality.

Table 3-37: Test Mode Functionality TESTMODE Non group settings (basic)

Setting


Recommended

Settings Unit









117



Setting


Recommended

Settings

Unit









Table 3-39 gives the recommended settings for Rated System Frequency.

Table 3-39: Rated System Frequency PRIMVAL Non group settings (basic)

Setting


Recommended

Settings Unit











118













task group.










This parameter is recommended to be set to 10% normally.



Table 3-39 gives the recommended settings for Signal Matrix For Analog Inputs. Table 3-40: Signal Matrix For Analog Inputs

Setting


Recommended

Settings Unit





119




UBase 10 %




SelPhaseBus1: Setting of the input phase for Bus 1 voltage reference. This parameter has to be

set based on the corresponding phase PT/CVT input connected to this function. Present case,

this parameter is set to L1 (R-phase)

SelPhaseLine1: Setting of the phase or line 1 voltage measurement. This parameter has to be


this parameter is set to L1 (R-phase).





only). This parameter has to be set based on the corresponding phase PT/CVT input connected

to this function. Present case, this parameter is set to L1 (R-phase)

UBase: Setting of the Base voltage level on which the voltage settings are based. This


PhaseShift: This setting is used to compensate for a phase shift caused by a transformer

between the two measurement points for bus voltage and line voltage, or by a use of different

voltages as a reference for the bus and line voltages. The set value is added to the measured

line phase angle. The bus voltage is the reference voltage. This parameter is set to 0° in present

case.

URatio: The URatio is defined as URatio = bus voltage/line voltage. This setting scales up the

line voltage to an equal level with the bus voltage. This parameter is set to 1 in present case.


If No voltage sel. is set, the default voltages used will be U-Line1 and U-Bus1. This is also the

case when external voltage selection is provided. Fuse failure supervision for the used inputs

must also be connected. In present case this parameter is set to 1 1/2 bus CB.


120

To allow closing of breakers between asynchronous networks a synchronizing function is

provided. The systems are defined to be asynchronous when the frequency difference between

bus and line is larger than an adjustable parameter.




voltage at Line synchronism check. The voltage level settings must be chosen in relation to the

bus or line network voltage. The threshold voltages UHighBusSC and UHighLineSC have to be

set lower than the value at which the breaker is expected to close with the synchronism check. A

typical value can be 80% of the base voltages.





typical value for FreqDiffM can be10 mHz for a connected system, and a typical value for

FreqDiffA can be 100-200 mHz. FreqDiffA is not applicable in present case.

PhaseDiffM and PhaseDiffA: The phase angle difference level settings for Manual and Auto

sync. PhaseDiffM is normally recommended to set 30°. PhaseDiffA is not applicable in present

case.

tSCM and tSCA: Setting of the time delay for Manual and Auto synchronism check. Circuit

breaker closing is thus not permitted until the synchrocheck situation has remained constant

throughout the set delay setting time. Typical values for tSCM and tSCA can be 0.1s.



AutoEnerg and ManEnerg: Setting of the energizing check directions to be activated for

AutoEnerg. Setting of the manual Dead line/bus and Dead/Dead switching conditions to be

allowed for ManEnerg.


voltage is above set value of UHighBusEnerg. DBLL, Dead Bus Live Line, the bus voltage is

below set value of ULowBusEnerg and the line voltage is above set value of UHighLineEnerg.

AutoEnerg is made OFF and ManEnerg is set to Both of the above DLLB, DBLL. Hence Auto

related parameters are not applicable.

ManEnergDBDL: This need to be made OFF to avoid manual closing of the breaker if both Bus

and Line are dead. In present case this parameter is set OFF.


121


energizing for UHighBusEnerg. Set the operating level for the Line high voltage at Bus

energizing for UHighLineEnerg.

The threshold voltages UHighBusEnerg and UHighLineEnerg have to be set lower than the value

at which the network is considered to be energized. A typical value can be 80% of the base

voltages. If system voltages are above the set values here, relay will consider it as Live

condition.

ULowBusEnerg and ULowLineEnerg: Setting of the operating voltage level for the low Bus

voltage level at Bus energizing for ULowBusEnerg. Setting of the operating voltage level for the

low line voltage level at line energizing for ULowLineEnerg.

The threshold voltages ULowBusEnerg and ULowLineEnerg, have to be set to a value greater

than the value where the network is considered not to be energized. A typical value can be 40%

of the base voltages. If system voltages are below the set values here, relay will consider it as

Dead condition.

UMaxEnerg: Setting of the maximum live voltage level at which energizing is allowed. This

setting is used to block the closing when the voltage on the live side is above the set value of

UMaxEnerg. In present case this parameter is set to 105% of UBase.


The purpose of the timer delay settings, tAutoEnerg and tManEnerg, is to ensure that the dead

side remains de-energized and that the condition is not due to a temporary interference. If the

conditions do not persist for the specified time, the delay timer is reset and the procedure is

restarted when the conditions are fulfilled again. Circuit breaker closing is thus not permitted until

the energizing condition has remained constant throughout the set delay setting time. Normally

tManEnerg is recommended to set 0.1s. tAutoEnerg is not applicable in present case.

OperationSynch: Operation for synchronizing function Off/ On. This parameter is recommended

to set OFF.

FreqDiffMin, FreqDiffMax, UHighBusSynch, UHighLineS ynch, UDiffSynch, tClosePulse,

tBreaker, tMinSynch and tMaxSynch: These parameters are not applicable if OperationSynch

is set to OFF.


Table 3-39 gives the recommended settings for Synchrocheck function.


122

Table 3-41: Setting of Synchrocheck function Setting


Recommended

Settings Unit







OperationSynch Operation for synchronizing function Off/

On Off -

OperationSC Operation for synchronism check function

Off/On On -

UHighBusSC Voltage high limit bus for synchrocheck in %

of UBaseBus 80.0 %UBB

UHighLineSC Voltage high limit line for synchrocheck in %

of UBaseLine 80.0 %UBL












Manual 0.100 s




UHighBusEnerg Voltage high limit bus for energizing 80.0 %UBB


123

check in % of UBaseBus

UHighLineEnerg Voltage high limit line for energizing


ULowBusEnerg Voltage low limit bus for energizing


ULowLineEnerg Voltage low limit line for energizing




tAutoEnerg Time delay for automatic energizing

Check 0.100 s



busbar1 -


busbar2 -




124

APPENDIX-A: Co-ordination of 400kV/220kV ICT IDMT O /C & E/F

relays at Station-A

The calculations given in this appendix are with following objective:

1. Settings to be provided on IDMT O/C & E/F relays of 400kV side and 220kV side of ICT.

2. Verification of IDMT O/C & E/F relay operating times for 3-Phase and Ph-G faults at

different locations.

3. Coordination curves for ICT O/C & E/F relays with adjacent line/transformer O/C & E/F

relays in the substation.

Basis for setting of O/C & E/F relay on 400kV side of ICT:

Instantaneous setting (50/50N):

This relay is set to operate at 0.05s for a current which is higher of 1.3 times the transformer

through fault current (220kV side bus fault) or transformer inrush current (Normally 8 -10

times the rated current, which can be set much lower because of the DC and harmonic

filtering in the numerical relays). This setting comes to generally 8 times the transformer

primary rated current.

IDMT O/C & E/F setting (67/67N):

These relays are to be coordinated with 67/67N of 220kV outgoing feeders on the LV side of

the ICT. 67/67N of 220kV outgoing feeders are set to operate at 1.1s for the remote 220kV

bus fault in order to give back up to zone 3 protection provided on 220kV lines.

Basis for setting of O/C & E/F relay on 220kV side of ICT:

Instantaneous setting (50/50N):

This relay is set to operate at 0.05s for a current which is higher of 1.3 times the transformer

through fault current (400kV side bus fault) or transformer inrush current (Normally 8 -10

times the rated current, which can be set much lower because of the DC and harmonic

filtering in the numerical relays). This setting comes to generally 8 times the transformer

secondary rated current.

IDMT O/C setting (67):

These relays are to be coordinated with distance relay (21) zone 3 settings of 400kV

outgoing feeders on the HV side of the ICT. As the zone 3 setting is 1s, this should be set at

1.1s.


125

IDMT E/F setting (67N):

These relays are to be coordinated with directional earth fault relay (67N) settings of 400kV

outgoing feeders on the HV side of the ICT. 67N of 400kV outgoing feeders are set to

operate at 1.1s for the remote 400kV bus fault in order to give back up to zone 3 protection

provided on 400kV lines.

1. System Details:

Figure A-1 shows the system details for the network under consideration for relay setting.

Table A-1 gives the setting for the over current and earth fault relays for the network under

consideration.

2. 3-Ph Fault Current:

Figure A-2 & A-3 shows the 3-Ph fault currents & operating time of relays for a fault at 5% of

220kV Line and for a fault at 220kV Bus respectively. The operating times are taken from

phase over current coordination curves given in figure A-4.

3. Ph-G Fault Current:

Figure A-5 & 6 shows the earth fault currents & operating time of relays for a fault at 5% of

220kV Line and for a fault at 220kV Bus respectively. The operating times are taken from

earth fault current coordination curves given in figure A-7.

Figure-8 & 9 shows the 3-Ph and Ph-G fault currents along with the operating times of

relays for a fault at 400kV bus. The IDMT O/C & E/F relay setting calculation procedure for

the 220kV side of ICT is as similar to the 400kV side relay.


126

Table A-1 Settings of Over current and Earth fault relays

Phase Relay Settings

Thermal / Curve (NEMA Code :67)

Instantaneous Setting (NEMA Code :50)

SI.NO Relay Name CT ratio Base

Current Ib in A

Plug setting

Ip> in I/Ib in%

TMS Tp>

Ip>> in I/Ib in%

Tp>> in s

1 TR-1 400kV Side 1000/1A 455 150 0.26 800 0.05

2 TR-2 220kV Side 800/1A 827 150 0.18 800 0.05

Earth Relay Settings

Thermal / Curve (NEMA Code :67N)

Instantaneous Setting (NEMA Code :50N)

SI.NO Relay Name CT ratio Base

Current Ib in A

Plug setting

Ie> in I/Ib in%

TMS Te>

Ie>> in I/Ib in%

Te>> in s

1 TR-1 400kV Side 1000/1A 455 20 0.58 800 0.05

2 TR-2 220kV Side 800/1A 827 20 0.51 800 0.05

Note: Considered base current for HV side is 455A & LV side is 827A.


127

Figure A-1: System details for the network under co nsideration for relay setting

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


128

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


129

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


130

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

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


131

Figure A-7: Earth Fault Relay Curve Co-ordination a nd Operating Time Operating Time for 220 kV line fa ult


132

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

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


IED USED FOR 400kV 80MVAR SHUNT REACTOR

PROTECTION

Model setting calculation document for Shunt Reactor

2

TABLE OF CONTENTS

TABLE OF CONTENTS .............................................................................................................. 2

1 BASIC SYSTEM PARAMETERS......................................................................................... 8

1.1 Single line diagram of the Shunt Reactor......................................................................... 8

1.2 Reactor parameters.......................................................................................................... 10

2 TERMINAL IDENTIFICATION AND LIST OF FUNCTIONS................................................11

2.1 RET670-1........................................................................................................................... 11


2.2 RET670-2........................................................................................................................... 15


2.3 REL670 .............................................................................................................................. 20


2.4 REC670.............................................................................................................................. 25

2.4.1 Terminal identification ....................................................................................25 2.4.2 List of functions available and those used ......................................................25

3 SETTING CALCULATIONS AND RECOMMENDED SETTINGS FOR RET670-1..............31

3.1 RET670-1........................................................................................................................... 31

3.1.1 Analog Inputs .................................................................................................31 3.1.2 Local Human-Machine Interface.....................................................................33 3.1.3 Indication LEDs..............................................................................................34 3.1.4 Time Synchronization.....................................................................................35 3.1.5 Parameter Setting Groups..............................................................................38 3.1.6 Test Mode Functionality TEST .......................................................................39 3.1.7 IED Identifiers ................................................................................................40 3.1.8 Rated System Frequency PRIMVAL ..............................................................40 3.1.9 Signal Matrix For Analog Inputs SMAI............................................................41 3.1.10 Transformer differential protection T3WPDIF .................................................42 3.1.11 Tripping Logic SMPPTRC ..............................................................................50 3.1.12 Trip Matrix Logic TMAGGIO...........................................................................51 3.1.13 Disturbance Report DRPRDRE......................................................................52

3.2 RET670-2........................................................................................................................... 55

3.2.1 Analog Inputs .................................................................................................55 3.2.2 Local Human-Machine Interface.....................................................................57 3.2.3 Indication LEDs..............................................................................................57 3.2.4 Time Synchronization.....................................................................................59 3.2.5 Parameter Setting Groups..............................................................................62 3.2.6 Test Mode Functionality TEST .......................................................................63 3.2.7 IED Identifiers ................................................................................................63 3.2.8 Rated System Frequency PRIMVAL ..............................................................64 3.2.9 Signal Matrix For Analog Inputs SMAI............................................................64


3

3.2.10 1Ph High impedance differential protection HZPDIF ......................................66 3.2.11 Disturbance Report DRPRDRE......................................................................68

3.3 REL670 .............................................................................................................................. 71

3.3.1 Analog Inputs .................................................................................................71 3.3.2 Local Human-Machine Interface.....................................................................73 3.3.3 Indication LEDs..............................................................................................73 3.3.4 Time Synchronization.....................................................................................75 3.3.5 Parameter Setting Groups..............................................................................78 3.3.6 Test Mode Functionality TEST .......................................................................79 3.3.7 IED Identifiers ................................................................................................79 3.3.8 Rated System Frequency PRIMVAL ..............................................................80 3.3.9 Signal Matrix For Analog Inputs SMAI............................................................80 3.3.10 Full-scheme distance measuring, Mho Characteristic (Zone 1) ZMHPDIS .....82 3.3.11 Tripping Logic SMPPTRC ..............................................................................85 3.3.12 Trip Matrix Logic TMAGGIO...........................................................................87 3.3.13 Fuse Failure Supervision SDDRFUF..............................................................88 3.3.14 Four Step Phase Overcurrent Protection OC4PTOC......................................90 3.3.15 Four Step Residual Overcurrent Protection EF4PTOC...................................96 3.3.16 Disturbance Report DRPRDRE....................................................................102

3.4 REC670............................................................................................................................ 105

3.4.1 Analog Inputs ...............................................................................................105 3.4.2 Local Human-Machine Interface...................................................................107 3.4.3 Indication LEDs............................................................................................107 3.4.4 Time Synchronization...................................................................................109 3.4.5 Parameter Setting Groups............................................................................112 3.4.6 Test Mode Functionality TEST .....................................................................113 3.4.7 IED Identifiers ..............................................................................................113 3.4.8 Rated System Frequency PRIMVAL ............................................................114 3.4.9 Signal Matrix For Analog Inputs SMAI..........................................................114 3.4.10 Synchrocheck function (SYN1).....................................................................116


4

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


5

LIST OF TABLES Table 1-1: CT and PT details ........................................................................................................................ 9 Table 2-1: List of functions in RET670-1..................................................................................................... 11 Table 2-2: List of functions in RET670-2..................................................................................................... 15 Table 2-3: List of functions in REL670 ........................................................................................................ 20 Table 2-4: List of functions in REC670 ....................................................................................................... 25 Table 3-1: Analog inputs ............................................................................................................................. 32 Table 3-2: Local human machine interface................................................................................................. 33 Table 3-3: LEDGEN Non group settings (basic) ......................................................................................... 34 Table 3-4: Time synchronization settings .................................................................................................. 36 Table 3-5: Parameter setting group ............................................................................................................ 39 Table 3-6: Test mode functionality.............................................................................................................. 40 Table 3-7: IED Identifiers ............................................................................................................................ 40 Table 3-8: Rated system frequency ............................................................................................................ 41 Table 3-9: Signal Matrix For Analog Inputs................................................................................................. 42 Table 3-10: Differential protection Settings................................................................................................. 47 Table 3-11: Tripping Logic .......................................................................................................................... 50 Table 3-12: Trip Matrix Logic ...................................................................................................................... 51 Table 3-13: Disturbance Report .................................................................................................................. 54 Table 3-14: Analog inputs ........................................................................................................................... 55 Table 3-15: Local human machine interface............................................................................................... 57 Table 3-16: LEDGEN Non group settings (basic) ....................................................................................... 58 Table 3-17: Time synchronization settings ................................................................................................. 60 Table 3-18: Parameter setting group .......................................................................................................... 62 Table 3-19: Test mode functionality............................................................................................................ 63 Table 3-20: IED Identifiers .......................................................................................................................... 64 Table 3-21: Rated system frequency .......................................................................................................... 64 Table 3-22: Signal Matrix For Analog Inputs............................................................................................... 65 Table 3-23: 1Ph High impedance differential protection HZPDIF............................................................... 68 Table 3-24: Disturbance Report .................................................................................................................. 70 Table 3-25: Analog inputs ........................................................................................................................... 71 Table 3-26: Local human machine interface............................................................................................... 73 Table 3-27: LEDGEN Non group settings (basic) ....................................................................................... 74 Table 3-28: Time synchronization settings ................................................................................................. 76 Table 3-29: Parameter setting group .......................................................................................................... 78 Table 3-30: Test mode functionality............................................................................................................ 79 Table 3-31: IED Identifiers .......................................................................................................................... 80 Table 3-32: Rated system frequency .......................................................................................................... 80 Table 3-33: Signal Matrix For Analog Inputs............................................................................................... 81 Table 3-34: ZONE 1 Settings...................................................................................................................... 84 Table 3-35: Tripping Logic .......................................................................................................................... 86 Table 3-36: Trip Matrix Logic ...................................................................................................................... 87 Table 3-37: Fuse Failure Supervision ......................................................................................................... 89 Table 3-38: Four Step Phase Overcurrent Protection ................................................................................ 93 Table 3-39: Four Step Residual Overcurrent Protection............................................................................. 99 Table 3-40: Disturbance Report ................................................................................................................ 103 Table 3-41: Analog Inputs ......................................................................................................................... 105 Table 3-42: Local human machine interface............................................................................................. 107 Table 3-43: LEDGEN Non group settings (basic) ..................................................................................... 108 Table 3-44: Time Synchronization ............................................................................................................ 110 Table 3-45: Parameter Setting Groups ..................................................................................................... 112 Table 3-46: Test Mode Functionality......................................................................................................... 113 Table 3-47: IED Identifiers ........................................................................................................................ 113 Table 3-48: Rated System Frequency ...................................................................................................... 114


6

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


7



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




8


1.1 Single line diagram of the Shunt Reactor

Single line diagram of the Shunt Reactor, various protection functions used and CT/PT

connections is shown in figure 1-1.

Figure 1-1: Single line diagram of the Shunt Reactor with CT ratios


9

CT and PT details:

Table 1-1 gives the Details of CTs and PTs.

Table 1-1: CT and PT details

CT details (typical, for illustration purpose only)

Name of the CT

Name of the Core CT ratio CT details





4B-CT






4C-CT





4C-CT2

CORE-4 200/1A CLASS:1, 15VA


CORE-2 109.97/2A CLASS:5, 15VA


4C-CT3


PT details

Name of the PT Name of the Core PT ratio PT details

PT I 400/0.11kV 3P, 50VA


10

1.2 Reactor parameters

Reactor: At Substation-A

Frequency: 50Hz

Positive Sequence Impedance: 2205Ω

Zero Sequence Impedance: 0.9 to 1.0 times of positive sequence

(Assumed 1 times for present case)

Reactor Rating: 80MVAR, 420kV, 110A (ONAN)

Vector Group: Star with Neutral grounded


11


The various functions required for the Shunt Reactor protection are divided in four IEDs namely

RET670-1, RET670-2, REL670 and REC670 for the purpose of illustration. The terminal

identification of this and list of various functions available in these IEDs are given in this section.

2.1 RET670-1


Object Name: 400kV Shunt Reactor

Unit Name: RET670-1 (Ver 1.2)


Frequency: 50Hz






Table 2-1: List of functions in RET670-1 Sl.No. Function/features available In RET670 Function/feature

activated

Yes/No

Recommended

Settings

provided

1 Analog Inputs YES








12













T3WPDIF

YES


Protection PHPIOC

NO


OC4PTOC:1

NO


OC4PTOC:2

NO


Protection EFPIOC

NO


EF4PTOC

NO


constants TRPTTR

NO



SPC8GGIO

NO


DNP3.0 AUTOBITS

NO


SINGLECMD

NO

30 Scheme Communication Logic For NO


13


ZCPSCH



ZCRWPSCH

NO




Protection LCNSPTOV

NO


LCZSPTOV

NO


Protection LCNSPTOC

NO


LCZSPTOC

NO










NO




NO




VMMXU

NO


Measurement CMSQI

NO


14



VNMMXU

NO




BINSTATREP

NO



RANGE_XP

NO


60 Event List NO

61 Indications NO







NO




NO


Communication

NO







NO



15

Note: For setting parameters provided in the function listed above, refer section 3 of


2.2 RET670-2



Unit Name: RET670-2 (Ver 1.2)


Frequency: 50Hz






Table 2-2: List of functions in RET670-2 Sl.No. Function/features available In RET670 Function/feature

activated

Yes/No

Recommended

Settings

provided

1 Analog Inputs YES












16









T3WPDIF

NO


HZPDIF

YES


Protection PHPIOC

NO


OC4PTOC

NO


Protection EFPIOC

NO


EF4PTOC

NO



NS4PTOC

NO



NO


constants TRPTTR

NO




SPC8GGIO

NO


DNP3.0 AUTOBITS

NO

32 Single Command, 16 Signals NO


17

SINGLECMD



ZCPSCH

NO



ZCRWPSCH

NO




Protection LAPPGAPC

NO


Protection COUVGAPC

NO


SCCVPTOC

NO



Protection LCNSPTOV

NO


LCZSPTOV

NO


Protection LCNSPTOC

NO


LCZSPTOC

NO










NO


18




NO




VMMXU

NO


Measurement CMSQI

NO



VNMMXU

NO




BINSTATREP

NO



RANGE_XP

NO


67 Event List NO

68 Indications NO







NO




NO


Communication

NO


19







NO





20

2.3 REL670



Unit Name: REL670 (Ver 1.2)


Frequency: 50Hz



Table 2-3 gives the list of functions/features available in REL670 relay and also indicates the



Table 2-3: List of functions in REL670 Sl.No. Function/features available In REL670 Function/feature

activated

Yes/No

Recommended

Settings

provided

1 Analog Inputs YES














21

14 Signal Matrix For mA Inputs SMMI NO





19 Full-scheme distance measuring, Mho

characteristic ZMHPDIS

YES

20 Mho impedance supervision logic

ZSMGAPC

NO

21 Faulty phase identification with load

encroachment FMPSPDIS

YES

22 Directional impedance element for mho

characteristic ZDMRDIR

YES

23 Power Swing Detection ZMRPSB NO

24 Automatic Switch Onto Fault Logic,

Voltage And Current Based ZCVPSOF

NO


Protection PHPIOC

NO


OC4PTOC

YES


Protection EFPIOC

NO


EF4PTOC

YES



NO

30 General Current And Voltage Protection

CVGAPC-4 functions

NO


32 Fuse Failure Supervision SDDRFUF YES

33 Horizontal Communication Via GOOSE

For Interlocking GOOSEINTLKRCV

NO

34 Logic Rotating Switch For Function NO


22




DPGGIO

NO


SPC8GGIO

NO


DNP3.0 AUTOBITS

NO


SINGLECMD

NO



ZCPSCH

NO



ZCRWPSCH

NO


43 Direct Transfer Trip Logic YES


Protection LAPPGAPC

NO


Protection COUVGAPC

NO


SCCVPTOC

NO



Protection LCNSPTOV

NO


LCZSPTOV

NO


Protection LCNSPTOC

NO


LCZSPTOC

NO


23










NO




NO




VMMXU

YES


Measurement CMSQI

YES



VNMMXU

NO




BINSTATREP

NO



RANGE_XP

NO


74 Event List YES

75 Indications YES




24





NO




NO


Communication

NO







NO





25

2.4 REC670






Frequency: 50Hz






Table 2-4: List of functions in REC670 Sl.No. Functions/Feature available In REC670 Features/Functions

activated

Yes/No

Recommended

Settings

provided

1 Analog Inputs YES















26







Protection PHPIOC

NO


OC4PTOC

YES


Protection EFPIOC

NO


EF4PTOC

YES



NS4PTOC

NO



NO

26 Thermal Overload Protection, One Time

Constant LPTTR

NO


constants TRPTTR

NO




31 Directional Underpower Protection

GUPPDUP

NO

32 Directional Overpower Protection

GOPPDOP

NO



35 Two Step Undervoltage Protection UV2PTUV

NO

36 Two Step Overvoltage Protection NO


27

OV2PTOV

37 Two Step Residual Overvoltage Protection

ROV2PTOV

NO





42 Rate-Of-Change Frequency Protection

SAPFRC

NO

43 General Current and Voltage Protection

CVGAPC

NO



46 Synchrocheck, Energizing Check, And

Synchronizing SESRSYN

YES

47 Autorecloser SMBRREC NO


49 Horizontal Communication Via GOOSE

For Interlocking GOOSEINTLKRCV

NO

50 Logic Rotating Switch For Function


NO



DPGGIO

NO


SPC8GGIO

NO


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

NO


28

Protection ZC1PPSCH



ZCRWPSCH

NO



Residual Overcurrent Protection ECPSCH

NO


Logic For Residual Overcurrent Protection

ECRWPSCH

NO


Logic For Phase Segregated

Communication ZC1WPSCH

NO



Protection LAPPGAPC

NO

65 Compensated Over And Undervoltage

Protection COUVGAPC

NO

66 Sudden Change In Current Variation

SCCVPTOC

NO



Protection LCNSPTOV

NO


LCZSPTOV

NO


Protection LCNSPTOC

NO


LCZSPTOC

NO






29






NO




NO




VMMXU

YES


Measurement CMSQI

YES



VNMMXU

NO




BINSTATREP

NO



RANGE_XP

NO

93 Disturbance Report DRPRDRE NO

94 Event List YES

95 Indications YES







NO


30




NO


Communication

NO







NO





31

3 SETTING CALCULATIONS AND RECOMMENDED

SETTINGS FOR RET670-1

The various functions required for the Reactor protection are divided in four IEDs namely

RET670-1, RET670-2, REL670 and REC670. The setting calculations and recommended

settings for various functions available in these IEDs are given in this section.

3.1 RET670-1

3.1.1 Analog Inputs




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





VTsec 110V 110V 110V 110V 110V 110V

# User defined text




32

Table 3-1: Analog inputs

Setting


Recommended

Settings Unit































33




















Recommended

Settings

Unit





34


Recommended

Settings

Unit










tRestart: Not applicable for the above case.





Setting


Recommended

Settings Unit




disturbance 0.0 s







35














time.





available in site.















36





























Setting


Recommended

Settings Unit



37








Setting


Recommended

Settings Unit


Synchronization 3 -


synchronization 1 -




Settings Unit




Setting


Recommended

Settings Unit




starts Last -




38


Setting


Recommended

Settings Unit




starts Last -




Setting


Recommended

Settings Unit



Setting


Recommended

Settings Unit














39






Setting


Recommended

Settings Unit



Setting


Recommended

Settings Unit











40

Table 3-6: Test mode functionality


Setting


Recommended

Settings Unit










Setting


Recommended

Settings

Unit



ObjectName Object name Bus Reactor -








41

Table 3-8: Rated system frequency

PRIMVAL Non group settings (basic)

Setting

Parameter Description Recommended Settings

Unit




DFTReference: Set ref for DFT filter adjustment here. These DFT reference block settings


















task group.







42









Table 3-9: Signal Matrix For Analog Inputs Setting


Recommended

Settings Unit







of UBase 10 %


3.1.10 Transformer differential protection T3WPDIF

There are two types of differential relays. Percentage biased differential relay with harmonic

restraint (2nd and 5th harmonic restraint) with a high set unit and high impedance differential relay.

For shunt reactor both percentage biased and high impedance relays can be used depending on

the availability of CTs with identical characteristics. The simplicity of comparing current into all

terminals of the reactor gives the differential relay very high reliability.

Note: If identical CTs are available for Differential protection, It is advantageous to use high

impedance function for Differential relay to achieve higher sensitivity. Setting computation for

High Impedance Differential function shall be similar to one illustrated for high impedance REF

function.


43

In case of breaker and half switching schemes, the differential protection C.Ts. associated with

Main and Tie breakers should be connected to separate bias windings and these should not be

paralleled in order to avoid false operation due to dissimilar C.T. transient response.

In case of percentage biased differential relays current transformers or auxiliary CT's in a delta

connection (In case of numerical relays this is done internally) have to be used at grounded

reactor windings to avoid false operation on external faults. The removed zero sequence

component, however, makes the reactor differential relay less sensitive.

Figure 3-1 shows the restrained and the unrestrained operate characteristics of Differential

protection.

Figure 3-1: Representation of the restrained and the unrestrained operate characteristics


44


SOTFMode: Transformer differential (TW2PDIF for two winding and TW3PDIF for three

winding) function in the IED has a built-in, advanced switch onto fault feature. This feature can

be enabled or disabled by a setting parameter SOTFMode. When SOTFMode = On this feature

is enabled. However it shall be noted that when this feature is enabled it is not possible to test

2nd harmonic blocking feature by simply injecting one current with superimposed second

harmonic. In that case the switch on to fault feature will operate and differential protection will

trip. However for real inrush case the differential protection function will properly restrain from

operation. In present case this parameter is set OFF.

IDiffAlarm: Differential protection continuously monitors the level of the fundamental frequency

differential currents and gives an alarm if the pre-set value is simultaneously exceeded in all

three phases. The threshold for the alarm pickup level is defined by setting parameter

IDiffAlarm. IDiffAlarm is set to 10%.

tAlarmDelay: Set this parameter to 10s.

IdMin: Since no tap changer is provided for the reactor, this parameter is recommended to set

0.2pu.

IdUnre: The unrestrained (that is, non-stabilized, "instantaneous") part of the differential

protection is used for very high differential currents, where it should be beyond any doubt, that

the fault is internal. This settable limit is constant (that is, not proportional to the bias current).

Neither harmonic, nor any other restrain is applied to this limit, which is therefore allowed to trip

reactor instantaneously. Unrestrained operation level has default value of IdUnre = 10pu, which

is typically acceptable for most of the shunt reactor applications. However in the following cases

these setting need to be changed accordingly:

When CT from "T-connection" are connected to IED, as in the breaker-and-a half or the ring bus

scheme, special care shall be taken in order to prevent unwanted operation of reactor

differential IED for through-faults due to different CT saturation of "T-connected" CTs. Thus if

such uneven saturation is a possibility it is typically required to increase unrestrained

operational level to IdUnre = 20-25pu. Since in this case, uneven CT saturation is not expected,

the function is used for breaker-and-a half scheme, this prater is set to 15pu.

CrossBlockEn: In the algorithm the user can control the cross-blocking between the phases via

the setting parameter CrossBlockEn. When parameter CrossBlockEn is set to On, cross

blocking between phases will be introduced. There are no time related settings involved, but the

phase with the operating point above the set bias characteristic will be able to cross-block other


45

two phases if it is self-blocked by any of the previously explained restrained criteria. It is

recommended to set this parameter to ON.

When parameter CrossBlockEn is set to Off, any cross blocking between phases will be

disabled. In present case it is set ON.

NegSeqDiffEn: The internal/external fault discriminator is a very powerful and reliable

supplementary criterion to the traditional differential protection. It is recommended that this

feature shall be always used (that is, On) when protecting three-phase shunt reactors. The

internal/external fault discriminator detects even minor faults, with a high sensitivity and at high

speed, and at the same time discriminates with a high degree of dependability between internal

and external faults. In the absence of credible field experience, it is set to OFF in present case.

IMinNegSeq and NegSeqROA: These parameters are not applicable if NegSeqDiffEn is set to

OFF.

EndSection1, EndSection2, SlopeSection2 and SlopeSection3: In present case, these

parameters are left with the default values recommended by manual. EndSection1,

EndSection2, SlopeSection2 and SlopeSection3 are set to 1.25, 3, 40% and 80% respectively.

Note: If controlled switching is not used for shunt reactor, the Differential protection might mal-

operate especially for 765kV shunt reactors. This can be prevented by temporarily increasing

the setting of differential protection during charging conditions. I2/I1Ratio: If the ratio of the second harmonic to fundamental harmonic in the differential current

is above the settable limit, the operation of the differential protection is restrained. It is

recommended to set parameter I2/I1Ratio = 15% as default value in case no special reasons

exist to choose other value.

I5/I1Ratio: If the ratio of the fifth harmonic to fundamental harmonic in the differential current is

above a settable limit the operation is restrained. It is recommended to use I5/I1Ratio = 25% as

default value in case no special reasons exist to choose another setting.

OpenCTEnable: The built-in open CT feature can be enabled or disabled by a setting

parameter OpenCTEnable (Off/On). When enabled, this feature prevents mal-operation when a

loaded main CT connected to Reactor differential protection is by mistake open circuited on the

secondary side. In present case this parameter is set OFF.

tOCTAlarmDelay , tOCTResetDelay and tOCTUnrstDelay: These parameters are not

applicable if OpenCTEnable is set OFF.

RatedVoltageW1: Rated voltage of shunt reactor in kV. This parameter is set to 400kV.




46

RatedCurrentW1: Rated current of shunt reactor in A. This parameter is set to 110A.



Above setting parameters are set based on 400kV 80MVAR Reactor rating details.





parameter is set to 0 as it is Shunt Reactor.


parameter is set to 0 as it is Shunt Reactor.

ZSCurrSubtrW1: Enable zer. seq. current subtraction for W1 side, On / Off. The elimination of

zero sequence current is done numerically and no auxiliary transformers or zero sequence traps

are necessary. In present case this parameter is set ON.





TconfigForW1: Two CT inputs (T-config.) for winding 1, YES / NO. For application with so

called "T" configuration, that is, two restraint CT inputs from one side of the protected shunt

reactor, such as in the case of breaker-and a- half scheme the primary CT ratings can be much

higher than the rating of the protected shunt reactor. In present case this parameter is set to

NO. Since Main CT input can be configured to W1 and Tie CT can be configured to W2.


NO.




NO.




NO.


47

LocationOLTC1: Transformer winding where OLTC1 is Located. Parameter LocationOLTC1

defines the winding where first OLTC (OLTC1) is physically located. In present case, this is set

to “Not Used”.

LowTapPosOLTC1, RatedTapOLTC1, HighTapPsOLTC1, TapHighVoltTC1,


LocationOLTC2: Transformer winding where OLTC2 is Located. In present case, this is set to

“Not Used”.

LowTapPosOLTC2, RatedTapOLTC2, HighTapPsOLTC2, TapHighVoltTC2,




Table 3-10: Differential protection Settings T3WPDIF Group settings (basic)

Setting


Recommended

Settings Unit


SOTFMode Operation mode for switch onto fault feature Off -

tAlarmDelay Time delay for diff currents alarm level 10 s

IDiffAlarm Dif. cur. alarm, multiple of base curr, usually W1 curr.

0.1 IB

IdMin Section1 sensitivity, multi. of base curr, usually W1 curr.

0.2 IB

IdUnre Unrestr. prot. limit, multi. of base curr. usually W1 curr.

15 IB

CrossBlockEn Operation Off/On for cross-block logic between phases

On -

NegSeqDiffEn Operation Off/On for neg. seq. differential protections

Off -

IMinNegSeq Neg. seq. curr. limit, mult. of base curr, usually W1 curr.

0.04 IB

NegSeqROA Operate Angle for int. / ext. neg. seq. fault discriminator

60.0 Deg


48

T3WPDIF Group settings (advanced)

Setting


Recommended

Settings Unit

EndSection1 End of section 1, multi. of base current, usually W1 curr. 1.25 IB

EndSection2 End of section 2, multi. of base current, usually W1 curr. 3 IB


40 %


80 %

I2/I1Ratio Max. ratio of 2nd harm. to fundamental harm dif. curr. in %

15 %

I5/I1Ratio Max. ratio of 5th harm. to fundamental harm dif. curr. in %

25 %

OpenCTEnable Open CT detection feature. Open CTEnable Off/On

Off -

tOCTAlarmDelay Open CT: time in s to alarm after an open CT is detected

3 s

tOCTResetDelay Reset delay in s. After delay, diff. function is activated

0.25 s

tOCTUnrstDelay Unrestrained diff. protection blocked after this delay, in s

10.0 s

T3WPDIF Non group settings (basic)

Setting


Recommended

Settings Unit

RatedVoltageW1 Rated voltage of transformer winding 1 (HV winding) in kV

400 kV


400 kV


400 kV

RatedCurrentW1 Rated current of transformer winding 1 (HV winding) in A

110 A


110 A


110 A


WYE(Y) -


WYE(Y) -

ConnectTypeW3 Connection type of winding 3: Y-wye or WYE(Y) -


49

D-delta


0 [0 deg] -


0 [0 deg] -


On -


On -


On -


No -


1000 A

CT2RatingW1 CT primary in A, T-branch 2, on transf. W1 side

1000 A


No -


1000 A


1000 A


No -


1000 A


1000 A


Not Used -

LowTapPosOLTC1 OLTC1 lowest tap position designation (e.g. 1)

1 -


6 -

HighTapPsOLTC1 OLTC1 highest tap position designation (e.g. 11)

11 -


1 -


1.0 %


Not Used -

LowTapPosOLTC2 OLTC2 lowest tap position designation (e.g. 1)

1 -


6 -

HighTapPsOLTC2 OLTC2 highest tap position designation (e.g. 11)

11 -


50


1 -


1.0 %



All trip outputs from protection functions have to be routed to trip coil through SMPPTRC.

SMPPTRC function will give a pulse of set length (150ms) if trip signal is obtained.




Program: For Reactor protection trip, this parameter is recommended to be set to 3 phase.

tWaitForPHS: It Secures 3-pole trip when phase selection fails. In present case, there is no

phase selection, this parameter is not applicable.





to OFF.


Table 3-11 gives the recommended settings for Tripping Logic. Table 3-11: Tripping Logic

Setting


Recommended

Settings Unit


Program Three ph; single or three ph; single, two or three ph trip

3 phase -



failed 0.020 s



AutoLock On: lockout from input (SETLKOUT) and Off -


51

trip, Off: only inp




example, all Differential, REF, TOC and TEF trips using TMAGGIO function.

















Setting


Recommended

Settings Unit









52






below:


From 400kV Main bay CTs:

IA

IB

IC

IN

From 400kV Tie Bay CTs:

IA

IB

IC

IN

From 400kV Reactor Neutral side CTs:

IA

IB

IC

IN

Differential currents from Differential protection function block

IDL1

IDL2

IDL3

From 400kV Bus PT:

VAN

VBN

VCN


— Group-A Trip

— Group-B Trip


53

— Direct Transfer Trip Sent (in case of line reactor)




— Over Voltage



Recording capacity


bay or circuit.

Memory capacity


Recording times


















54



Recommended

Settings Unit










55

3.2 RET670-2

3.2.1 Analog Inputs




Ch 1 Ch 2 Ch 3 Ch 4 Ch 5 Ch 6 Name# REF REF REF SPARE SPARE SPARE CTprim 1A 1A 1A 1000A 1000A 1000A CTsec 1A 1A 1A 1A 1A 1A



In case of line reactor with neutral reactor, REF used shall be single phase type. In case of

bus reactor, since CTs are available on either side of shunt reactor, REF used shall be of 3-

phase type. (In this case, it is assumed Bus reactor). The above analog inputs has been set

accordingly.



VTsec 110V 110V 110V 110V 110V 110V

# User defined text


Table 3-14 gives the recommended settings for Analog inputs. Table 3-14: Analog inputs

Setting


Recommended

Settings Unit






56



































57












Recommended

Settings

Unit











58









Setting


Recommended

Settings Unit




disturbance 0.0 s

















59




time.





available in site.























60





















Setting


Recommended

Settings Unit









61


Setting


Recommended

Settings Unit


Synchronization 3 -


synchronization 1 -




Settings Unit




Setting


Recommended

Settings Unit




starts Last -




Setting


Recommended

Settings Unit




UTCTimeOfDay UTC Time of day in seconds when 3600 s


62

daylight time starts


Setting


Recommended

Settings Unit



Setting


Recommended

Settings Unit


















Setting


Recommended

Settings Unit

t Pulse length of pulse when setting 1 s


63

Changed


Setting


Recommended

Settings Unit











Setting


Recommended

Settings Unit









64



Setting


Recommended

Settings

Unit











Setting


Recommended

Settings Unit













65











task group.














Setting


Recommended

Settings Unit







66


of UBase 10 %


3.2.10 1Ph High impedance differential protection HZPDIF

It may be noted that the connection of Restricted Earth Fault protection on the neutral side shall

be from Neutral side bushing CTs (in case of bus reactor) or from the ground side CT in the

neutral grounding reactor (for line shunt reactor). The latter is to ensure that the protection

covers the neutral earthing reactor as well in the protected zone.

Zero-sequence differential relays (Restricted earth fault relay) provide protection against phase-

to-ground faults in shunt reactors supplied from solidly grounded systems. Generally, this

protection is also provided for EHV shunt reactor with Neutral Grounding reactor connected

between star point of shunt reactor and ground.

Whenever separate phase-wise C.Ts are available on neutral side of Reactor, triple pole high

impedance relay may be provided instead of single pole R.E.F. relay.


U>Alarm: Set the alarm level. The sensitivity can roughly be calculated as a divider from the

calculated sensitivity of the differential level. A typical setting is 20% of U>Trip It can be used as

scheme supervision stage.

tAlarm: Set the time for the alarm. A typical setting is 5 seconds.

U>Trip: The level is selected with margin to the calculated required voltage to achieve stability.

Values can be 20-200 V dependent on the application.

SeriesResistor: Set the value of the stabilizing series resistor. Adjust the resistor as close as

possible to the calculated value. Measure the value achieved and set this value here.


This Protection is based on High Impedance differential scheme.

The setting value of the relay can be calculated as below:

CT Details: Phase side and Neutral side –200 /1, CL: PS

Rct = 1Ω


67

Rl = 2.178Ω, considered 250mts distance from Phase/Neutral CT to relay connected using a

cable of 2.5mm2 having resistance of 8.71ohms/km.

Voltage drop across the circulating current circuit for external faults,

Us = Ikmax x (Rct + 2* Rl)/n where

Maximum through fault current (3-ph) = 110 * 6 = 660A (considered charging currents up to 6

times rated current)

Rct = the internal resistance of the current transformer secondary winding = 1Ω

Rl = the total resistance of the longest measuring circuit loop = 2.178Ω

n = turns ratio of the current transformer = 1/200

Hence Us = 660 x (1 + 2x2.178) * 1 /200 = 17.67V

Recommended Settings = 19.44 ≈ 20V with a margin of 10%. (A typical margin is 10 to

50%)

CT requirement with Vk = 2*Us = 2* 20 = 40V Approx. (min)

REF high impedance Function element is used with Stabilizing resistor.

Pickup shall be decided based on the following criteria:

Stabilizing resistor:

For a sensitivity of 2% i.e 0.02*In,

Rs ≥ Us/I =20/0.02 = 1000Ω to be connected in series.

Chosen Rs= 1000Ω. (Approx)

Primary operating sensitivity:

Iprim = n x ( Irelay + Iu + mx Im )

where, n = turn ratio of the CT = 200 in present case.

Irelay = relay set operation current in secondary Amps = 20mA in present case.

Iu = leakage current through the Voltage Dependent Resistor (VDR) at stabilizing voltage Us =

1mA

Approximate value of the current thorough non-linear resistor for the voltage of 20V (Us) is 1mA.

This is considered from the Current voltage characteristics for the non-linear resistors.

m = number of CTs connected in parallel in the secondary circuit = 2 in present case.

Im = magnetizing current of the CT at stabilizing voltage Us = 3mA in present case.

This value is calculated by using CT magnetizing current 30mA at Vk and Vk = 200V.

By using above values, Iprim = 200 x (20+ 1 + 2x3) = 5.4A.

Kindly Note that the following requirements for applying High impedance differential relays.

• Turns ratios of CTs should be identical

• Auxiliary CTs should not be used


68

• Loop impedance (Rct+2Rl) up to the CT paralleling point should be identical

• Magnetizing characteristics should be identical


Table 3-23 gives the recommended settings for 1Ph High impedance differential protection.

Table 3-23: 1Ph High impedance differential protection HZPDIF

Setting


Recommended

Settings

Unit


U>Alarm Alarm voltage level in volts on CT

secondary side 4 V

tAlarm Time delay to activate alarm 5 s

U>Trip Operate voltage level in volts on CT

secondary side 20 V

SeriesResistor Value of series resistor in Ohms 1000 ohm

Note: The respective analogue channels in RET670-2 (for REF current inputs) should be

set to 1:1.






below:


Differential currents from 1PH High impedance functions:

IREFL1

I REFL2

I REFL3



69

— Group-A Trip

— Group-B Trip

— Direct Transfer Trip Sent (in case of line reactor)




— Over Voltage



Recording capacity


bay or circuit.

Memory capacity


Recording times
















70





Recommended

Settings Unit










71

3.3 REL670

3.3.1 Analog Inputs




Ch 1 Ch 2 Ch 3 Ch 4 Ch 5 Ch 6 Name# IL1-CB1 IL2-CB1 IL3-CB1 SPARE SPARE SPARE CTprim 1000A 1000A 1000A 200A 200A 200A CTsec 1A 1A 1A 1A 1A 1A





VTsec 110V 110V 110V 110V 110V 110V

# User defined text





Recommended

Settings Unit









72

































73











Recommended

Settings

Unit











74









Setting


Recommended

Settings Unit




disturbance 0.0 s

















75




time.





available in site.























76



















Table 3-28 gives the recommended settings for Time synchronization. Table 3-28: Time synchronization settings


Setting


Recommended

Settings Unit









77


Setting


Recommended

Settings Unit


Synchronization 3 -


synchronization 1 -




Settings Unit




Setting


Recommended

Settings Unit




starts Last -




Setting


Recommended

Settings Unit







78


Setting


Recommended

Settings Unit



Setting


Recommended

Settings Unit
















Table 3-29 gives the recommended settings for Parameter setting group. Table 3-29: Parameter setting group


Setting


Recommended

Settings Unit


Changed 1 s


79


Setting


Recommended

Settings Unit









Table 3-30 gives the recommended settings for Test mode functionality. Table 3-30: Test mode functionality


Setting


Recommended

Settings Unit









80



Setting


Recommended

Settings

Unit



ObjectName Object name Shunt Reactor -


UnitName Unit name REL670 -




Table 3-32 gives the recommended settings for Rated system frequency. Table 3-32: Rated system frequency


Setting


Recommended

Settings Unit













81











task group.














Setting


Recommended

Settings Unit







82


of UBase 10 %


3.3.10 Full-scheme distance measuring, Mho Characteristic (Zone 1)

ZMHPDIS

Undesired operation of impedance protection during switching conditions has been observed

but the tendency seems to be reduced by numerical distance protection due to modern filtering

algorithms.

The impedance or overcurrent backup protection may not be able to detect inter-turn fault in the

reactor, for which the buchholz may be the only answer, unless the number of turns involved is

very high. Manufacturers of reactor and relays may be consulted in this regard.

Typical setting for impedance type of relays are -

Reach - 60% of Reactor Impedance Time setting - 1 sec.

Impedance relays are used as primary protection or as back-up protection for the reactor. It is

also used for detecting turn-to-turn faults within the reactor. Such relays also monitor the faults

inside the reactor at some good percentage of winding faults. Turn-to-turn faults inside reactor

winding may not change the through current of the reactor but the impedance values change

drastically up to at least 50 % of impedance of the reactor. It consists of a single or preferably a

two-zone impedance relay on the high side of the reactor looking into the reactor.

The impedance relay has some benefits of providing high speed tripping in the Zone-1 protection

and slower speed tripping in Zone-2. It must not be set to operate for inrush characteristics

during reactor energization or de-energization. The setting of the relay has to be coordinated

while taking into account the energizing and d-energizing transients.

The zones are set directly in primary ohms R, X. The primary ohms R, X are recalculated to

secondary ohms with the current and voltage transformer ratios.

The secondary values are presented as information for zone testing.


83


Zone-1:

Setting of ZPE and ZPP: To be set to cover 60% of Reactor impedance. Zero sequence

compensation factor is (Z0 – Z1) / 3Z1.

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

the Reactor rated current value. This parameter is set to 110A in present case.

UBase: Set the Base voltage for the Impedance protection zones in primary kV here. Set the

Reactor rated voltage value. This parameter is set to 420kV in present case.

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

each loop. This is the minimum current required in phase to phase fault for zone measurement.



minimum current required in phase to earth fault for zone measurement. To be set to 10% of

IBase.

DirMode: Direction mode. This parameter is set to Offset.

LoadEncMode: Load encroachment mode Off/On. This parameter is recommended to set OFF.

ReachMode: Reach mode Over/Underreach. This parameter is not applicable in present case.

OpModePE: Operation mode Off / On of Phase-Earth loops. This parameter is recommended to

set ON.

KN: Magnitude of earth return compensation factor KN. Refer setting calculation section.

KNAng: Angle for earth return compensation factor KN. This parameter is set to 90°.

ZRevPE: Reverse reach of the phase to earth loop(magnitude).This parameter is set same as

that of ZPE.

tPE: Delay time for operation of phase to earth elements. This parameter is set to 1s.

ZRevPP: Reverse reach of the phase to phase loop(magnitude). This parameter is set same as

that of ZPP.

ZAngPP: Angle for positive sequence line impedance for Phase-Phase elements. This

parameter is set to 90°.

OffsetMhoDir: Direction mode for offset mho. This parameter is set to Non-directional.

OpModePE: Operation mode Off / On of Phase-Earth loops. This parameter is set to ON.

OpModePP: Operation mode Off / On of Phase-Phase loops. This parameter is set to ON.


84


Zone 1 phase fault reach is set to 60.0% of the total reactor impedance

ZPP' = 1323Ω


ZPP = 72.765Ω

Same value is set for ZRevPP, ZPE and ZRevPE.

Earth return compensation factor KN:

KN = (Z0 – Z1) / 3Z1 = -0.033

Considered Z0 = 0.9xZ1 = 1190.7Ω


Table 3-34 gives the recommended settings for ZONE 1. Table 3-34: ZONE 1 Settings

Setting


Recommended

Settings

Unit



Ubase Base voltage , i.e.rated voltage 420.00 kV

DirMode Direction mode Offset -

LoadEncMode Load encroachment mode Off/On Off -

ReachMode Reach mode Over/Underreach Underreach -

OpModePE Operation mode Off / On of Phase-Earth

loops On -

ZPE Positive sequence impedance setting for

Phase-Earth loop 1323 ohm/p

ZAngPE Angle for positive sequence line

impedance for Phase-Earth loop 90 Deg

KN Magnitud of earth return compensation

factor KN -0.03333 ohm/p

KNAng Angle for earth return compensation

factor KN 0 ohm/p

ZRevPE Reverse reach of the phase to earth 1323 ohm/p


85

loop(magnitude)

tPE Delay time for operation of phase to

earth elements 1 s

IMinOpPE Minimum operation phase to earth

current 10 %IB

OpModePP Operation mode Off / On of Phase-

Phase loops On -

ZPP Impedance setting reach for phase to

phase elements 1323 ohm/p

ZAngPP Angle for positive sequence line

impedance for Phase-Phase elements 90 Deg

ZRevPP Reverse reach of the phase to phase

loop(magnitude) 1323 ohm/p

tPP Delay time for operation of phase to

phase 1 s

IMinOpPP Minimum operation phase to phase

current 10 %IB

ZMHPDIS Group settings (advanced)

Setting


Recommended

Settings

Unit

OffsetMhoDir Direction mode for offset mho Non-directional -

OpModetPE Operation mode Off / On of Zone timer,

Ph-E On -

OpModetPP Operation mode Off / On of Zone timer,

Ph-ph On -



All trip outputs from protection functions has to be routed to trip coil through SMPPTRC.

For example, If there is a transient fault, trip output from distance function will not be long

enough to open breaker in case Distance function trip signal is directly connected to Trip coil.


86

SMPPTRC function will give a pulse of set length (150ms) even if trip signal is obtained for

transient fault.




Program: If only 3-ph trip is required, this needs to be set to 3 phase. In present case it is to be

set to 3 phase.

tWaitForPHS: It Secures 3-pole trip when phase selection fails. For example, if fault is at 90%

of protected line in R-ph, Zcom trip is obtained using scheme communication. SMPPTRC will

wait for Zone-2 R-ph sart till the time delay set in tWaitForPHS to trip R-ph at local end. If no

Zone-2 R-ph start from local end, it will issue a 3-ph trip after the time delay set in tWaitForPHS.

This parameter is set to 0.050s.





to OFF.


Table 3-35 gives the recommended settings for Tripping Logic. Table 3-35: Tripping Logic

Setting


Recommended

Settings Unit


Program Three ph; single or three ph; single, two or

three ph trip 3 phase -



failed 0.050 s



AutoLock On: lockout from input (SETLKOUT) and

trip, Off: only inp Off -


87




example, all distance 3-ph trips (from z-2, z-3 and z-4), SOTF trip, TOV, TOC and TEF trips

using TMAGGIO function.

















Setting


Recommended

Settings Unit









88

3.3.13 Fuse Failure Supervision SDDRFUF


Setting for OpMode: Setting of the operating mode for the Fuse failure supervision. Zero

sequence based fuse fail detection is enabled and settings for the same are given based on

below recommendations.

3U0> and 3I0<: The setting of 3U0> should not be set lower than maximal zero sequence

voltage during normal operation condition. The setting of 3I0< must be higher than maximal

zero sequence current during normal operating condition. In present case, 3U0> is set to 30%

of UBase and 3I0< is set to 10% of IBase.

3U2> and 3I2<: These parameters are not applicable if OpMode is selected to UZsIZs.

DUDI: This is another philosophy for detecting fusefail like Zero sequence based and Negative

sequence based algorithm. If OpMode is set to UZsIZs and OpDUDI is kept ON, fusefail

detection will be OR operation of these two modes. This is recommended to set ON.

DU> and DI<: DUDI method will measure the difference in voltage (should be more than set in

DU>) and difference in current (should be less than set in DI<). DU> is recommended to set

60% of UBase and DI< is recommended to set 15% of IBase.

UPh> and IPh>: For DUDI mode, voltage in the corresponding phase shall be more than set

value in UPh> for 1.5cycles before actual fuse fail condition and current should be more than

set value in IPh> before fuse fail. UPh> is recommended to set 70% of UBase and IPh> is

recommended to set 10% of IBase.

A criterion based on delta current and delta voltage measurements can be added to the fuse

failure supervision function in order to detect a three phase fuse failure, which in practice is

more associated with voltage transformer switching during station operations. In present case,

this parameter is set ON.

SealIn: Setting of the seal-in function On-Off giving seal-in of alarm until voltages are

symmetrical and high. If sealin is ON and fusefail persists for more than 5s, outputs blockz and

blocku will get sealin (means latched) until any one phase voltage is less than USealIn< setting.

It will release when all three voltages goes above USealIn< setting. In present case, this

parameter is made ON and recommended setting for USealIn< is 70% of UBase.

Dead line detection: If any phase voltage is less than UDLD< set value and corresponding

current is less than IDLD< set value, this will consider as dead line and it will block Z only, it will

not block U. There is no ON or OFF for this philosophy.


89

During real fuse fail condition, FF function will block both Z and U. UDLD< is recommended to

set to 60% of UBase and IDLD< is recommended to set 5% of IBase.

UBase: Setting of the Base voltage level on which the voltage setting is based. In present case

this parameter is set to 400kV.

IBase: Set the Base current for the function on which the current levels are based. In present

case this parameter is set to 110A.


Table 3-37 gives the recommended settings for Fuse Failure Supervision. Table 3-37: Fuse Failure Supervision

Setting


Recommended

Settings Unit




OpMode Operating mode UZsIZs -

3U0> residual overvoltage element in % of

Ubase 30 %IB

3I0< Operate level of residual undercurrent

element in % of Ibase 10

%IB

3U2> Operate level of neg seq overvoltage

element in % of Ubase 20

%IB

3I2< Operate level of neg seq undercurrent

element in % of Ibase 10

%IB

OpDUDI Operation of change based function

Off/On On -

DU> Operate level of change in phase voltage

in % of Ubase 60 %UB

DI< Operate level of change in phase 15 %IB

UPh> Operate level of phase voltage in % of

Ubase. 70 %UB

IPh> Operate level of phase current in % of

IBase 10 %IB


90

SealIn Seal in functionality Off/On On -

USealln< Operate level of seal-in phase voltage in

%of Ubase 70 %UB

IDLD< Operate level for open phase current

detection in % of IBase 5 %IB

UDLD< Operate level for open phase voltage 60 %UB

3.3.14 Four Step Phase Overcurrent Protection OC4PTOC

The Phase Over current protection and Earth fault relays are widely used in comparison to

impedance type of relay for providing backup protections to shun reactors. See reference:

The phase over current protection is a very inexpensive, simple, and reliable scheme for fault

detection and is used for some reactor protection applications as a back-up protection. The

setting must be high enough to prevent inrush currents from causing unwanted operation. When

used it should have both instantaneous and time delayed elements. The instantaneous elements

help in providing high speed clearance of heavy current faults which threaten system stability.

The impedance or overcurrent backup protection may not be able to detect inter-turn fault in the

reactor, for which the buchholz may be the only answer, unless the number of turns involved is

very high. Manufacturers of reactor and relays may be consulted in this regard.

Typical settings for O/C relays are:

Current Setting - 1.3 x Rated current Time setting - 1 sec.



parameter is set to 110A in present case, which is Reactor rated current.


This parameter is set to 400kV in present case, which is Reactor rated voltage. This parameter

is not applicable in present case, since DirMode1 is set to Non-directional.


91


and current. This parameter is not applicable in present case, since DirMode1 is set to Non-

directional.


parameter is not applicable in present case, since DirMode1 is set to Non-directional.




















Characteristic2: Setting of the operating characteristic. This parameter is set to “Non-

directional” in present case.

I2>: Setting of the operating current level in primary values. This setting value shall be higher

than 6 times Reactor rated current considering inrush. This parameter is set to 1500% of

Reactor rated current in present case. However, this setting can be set more sensitive if bushing

CTs are used.



t2: Independent (definitive) time delay of step 2, this parameter can be set in the range 50 to

100msec. It is set to 50ms in present case.


92



IMin2: Minimum operate current for step2 in % of IBase. This parameter is set to 1500% of










set to IEC.



tPCrv1, tACrv1, tBCrv1, tCCrv1, tPRCrv1, tTRCrv1 and tCRCrv1: These parameters are






set to IEC.







DirMode3 and DirMode4: Setting of the operating direction for the stage or switch it off. Two

stages are set to OFF.



t1: This parameter is set to 1s in present case.


93




Table 3-38 gives the recommended settings for Four Step Phase Overcurrent Protection. Table 3-38: Four Step Phase Overcurrent Protection

OC4PTOC Group settings (basic)

Setting


Recommended

Settings

Unit








3, 2 of 3, 3 of 3) 1 out of 3 -


forward, reverse) Non-Directional -



% of IBase 130 %IB



for step 1 0 -


of IBase 130 %IB


for step 1 0 s






94



% of IBase 1500 %IB



for step 2 0 -


of IBase 1500 %IB


for step 2 0 s









% of IBase 7 %IB












tCCrv1 Parameter C for customer programmable



95








restrain On -



















restrain On -


96

3.3.15 Four Step Residual Overcurrent Protection EF4PTOC

The ground fault protection within the shunt reactor is best provided by simple conventional

Restricted Earth Fault (REF) relay selected and set on the same philosophy as for transformer

REF. For tertiary connected reactors neutral over voltage relays are used. Sometimes a ground

over current relay is used as a backup protection when phase overcurrent protection is provided.

The ground over current protection is a very inexpensive, simple, and reliable scheme for fault

detection and is used for some reactor protection applications as a back-up protection for phase-

to-ground faults. This is used in conjunction with phase over current relay. When used it should

have both instantaneous and time delayed elements.

The sensitivity to the harmonic and inrush currents is one of the main problems with back-up

ground over current relays. Settings must be able to allow inrush, which usually means

desensitizing the back-up relay. Numerical relay offer the best characteristic in this area since

the digital filters remove harmonics and DC offset currents from the inrush and are, therefore,

recommended.



above any continuous residual current under normal system operation.


parameter is set to 110A in present case, which is Reactor rated current.


This parameter is set to 400kV in present case, which is Reactor rated voltage. This parameter

is not applicable in present case, since DirMode1 is set to Non-directional.










97


k1: Set the back-up trip time delay multiplier (TMS) for inverse characteristic. This parameter is

not applicable in present case, since Characteristic1 is set to IEC Def. Time.





set to IEC.











IN2>: Setting of the operating current level in primary values. This can be made very sensitive

by using Bushing CT input with a setting of 100% of base current. As bay CTs are being used,

this parameter is set to 1000% of base current in present case.



t2: Independent (definitive) time delay of step 2, this parameter can be set in the range 50 to

100msec. It is set to 50ms in present case.







set to IEC.




98





polMethod: Set the method of directional polarizing to be used. This parameter is not

applicable in present case, since DirMode1 is set to Non-directional.


function. This parameter is not applicable in present case, since DirMode1 and DirMode2 are

set to Non-directional.

IPolMin, RNPol, XNPol: These parameter is not applicable in present case, since DirMode1 is

set to Non-directional.


and current. This parameter is not applicable in present case, since DirMode1 and DirMode2

are set to Non-directional.


fault protection. This parameter is not applicable in present case, since DirMode1 and DirMode2

are set to Non-directional.
















OFF.


99

ActivationSOTF, ActUndertime, t4U, tSOTF, tUndertime, HarmResSOTF: These parameters




t1: This parameter is set to 1s in present case.




Table 3-39 gives the recommended settings for Four Step Residual Overcurrent Protection. Table 3-39: Four Step Residual Overcurrent Protection

Setting


Recommended

Settings

Unit








of UBase 1 %UB

IPolMin Minimum current level for polarization in %

of IBase 5 %IB


polar-isation 5 Ohm


current polarisation 40 Ohm



2ndHarmStab Second harmonic restrain operation in % of

IN amplitude 20 %



100


3 or 4) IN4> -












% of IBase 20 %IB


k1 Time multiplier for the dependent time delay

for step 1 0 -



t1Min Minimum operate time for inverse curves for

step 1 0 s




restrain On -










101

tPRCrv1 Parameter PR for customer programmable


tTRCrv1 Parameter TR for customer programmable


tCRCrv1 Parameter CR for customer programmable






% of IBase 1000 %IB


k2 Time multiplier for the dependent time delay

for step 2 0.0 -



t2Min Minimum operate time for inverse curves for

step 2 0 s




restrain On -









tPRCrv2 Parameter PR for customer programmable curve for step 2

0.5 -

tTRCrv2 Parameter TR for customer programmable



102

tCRCrv2 Parameter CR for customer programmable











given below:


From CT:

IA

IB

IC

IN

From Bus PT:

VAN

VBN

VCN


— Group-A trip

— Z1 Start

— Group-B trip

— Direct Transfer Trip (only for Line reactors)

— Bus bar trip



— Over Voltage


103



Recording capacity


bay or circuit.

Memory capacity


Recording times
















Table 3-40 gives the recommended settings for Disturbance Report. Table 3-40: Disturbance Report

Setting


Recommended

Settings Unit





104







105

3.4 REC670

3.4.1 Analog Inputs




Ch 1 Ch 2 Ch 3 Ch 4 Ch 5 Ch 6 Name# IL1-CB1 IL2-CB1 IL3-CB1 SPARE SPARE SPARE CTprim 200A 200A 200A 1000A 1000A 1000A CTsec 1A 1A 1A 1A 1A 1A




Ch 1 Ch 2 Ch 3 Ch 4 Ch 5 Ch 6 Name# BUS PT BUS PT BUS PT SEL-PT* SEL-PT SEL-PT VTprim 400kV 400kV 400kV 400kV 400kV 400kV

VTsec 110V 110V 110V 110V 110V 110V

*SEL-PT: Selected PT input for synchronizing function

# User defined text


Table 3-41 gives the recommended settings for Analog Inputs. Table 3-41: Analog Inputs

Setting


Recommended

Settings Unit


presentation TRM40-Ch1 -






106


































107








Table 3-42 gives the recommended settings for Local human machine interface. Table 3-42: Local human machine interface


Recommended

Settings

Unit











108







Table 3-43 gives the recommended settings for Indication LEDs. Table 3-43: LEDGEN Non group settings (basic)

Setting


Recommended

Settings Unit




disturbance 0.0 s

















109




time.





available in site.























110



















Table 3-44 gives the recommended settings for Time Synchronization. Table 3-44: Time Synchronization


Setting


Recommended

Settings Unit









111


Setting


Recommended

Settings Unit


Synchronization 3 -


Synchronization 1 -




Settings Unit




Setting


Recommended

Settings Unit







Setting


Recommended

Settings Unit







112


Setting


Recommended

Settings Unit



Setting


Recommended

Settings Unit
















Table 3-45 gives the recommended settings for Parameter Setting Groups. Table 3-45: Parameter Setting Groups


Setting


Recommended

Settings Unit



113


Setting


Recommended

Settings Unit









Table 3-46 gives the recommended settings for Test Mode Functionality. Table 3-46: Test Mode Functionality


Setting


Recommended

Settings Unit



CmdTestBit Command bit for test required or not during

testmode Off -




Table 3-47: IED Identifiers TERMINALID Non group settings (basic)

Setting


Recommended

Settings

Unit



114








Table 3-48 gives the recommended settings for Rated System Frequency. Table 3-48: Rated System Frequency


Setting


Recommended

Settings Unit

















115







task group.










This parameter is recommended to be set to 10% normally.




Setting


Recommended

Settings Unit







UBase 10 %



116



SelPhaseBus1: Setting of the input phase for Bus 1 voltage reference. This parameter has to be


this parameter is set to L1 (R-phase)

SelPhaseLine1: Setting of the phase or line 1 voltage measurement. This parameter has to be


this parameter is set to L1 (R-phase).





only). This parameter has to be set based on the corresponding phase PT/CVT input connected

to this function. Present case, this parameter is set to L1 (R-phase)

UBase: Setting of the Base voltage level on which the voltage settings are based. This


PhaseShift: This setting is used to compensate for a phase shift caused by a transformer

between the two measurement points for bus voltage and line voltage, or by a use of different

voltages as a reference for the bus and line voltages. The set value is added to the measured

line phase angle. The bus voltage is the reference voltage. This parameter is set to 0° in present

case.

URatio: The URatio is defined as URatio = bus voltage/line voltage. This setting scales up the

line voltage to an equal level with the bus voltage. This parameter is set to 1 in present case.


If No voltage sel. is set, the default voltages used will be U-Line1 and U-Bus1. This is also the

case when external voltage selection is provided. Fuse failure supervision for the used inputs

must also be connected. In present case this parameter is set to 1 1/2 bus CB.

To allow closing of breakers between asynchronous networks a synchronizing function is

provided. The systems are defined to be asynchronous when the frequency difference between

bus and line is larger than an adjustable parameter.




117


voltage at Line synchronism check. The voltage level settings must be chosen in relation to the

bus or line network voltage. The threshold voltages UHighBusSC and UHighLineSC have to be

set lower than the value at which the breaker is expected to close with the synchronism check. A

typical value can be 80% of the base voltages.





typical value for FreqDiffM can be10 mHz for a connected system, and a typical value for

FreqDiffA can be 100-200 mHz. FreqDiffA is not applicable in present case.

PhaseDiffM and PhaseDiffA: The phase angle difference level settings for Manual and Auto

sync. PhaseDiffM is normally recommended to set 30°. PhaseDiffA is not applicable in present

case.

tSCM and tSCA: Setting of the time delay for Manual and Auto synchronism check. Circuit

breaker closing is thus not permitted until the synchrocheck situation has remained constant

throughout the set delay setting time. Typical values for tSCM and tSCA can be 0.1s.



AutoEnerg and ManEnerg: Setting of the energizing check directions to be activated for

AutoEnerg. Setting of the manual Dead line/bus and Dead/Dead switching conditions to be

allowed for ManEnerg.


voltage is above set value of UHighBusEnerg. DBLL, Dead Bus Live Line, the bus voltage is

below set value of ULowBusEnerg and the line voltage is above set value of UHighLineEnerg.

AutoEnerg is made OFF and ManEnerg is set to Both of the above DLLB, DBLL. Hence Auto

related parameters are not applicable.

ManEnergDBDL: This need to be made OFF to avoid manual closing of the breaker if both Bus

and Line are dead. In present case this parameter is set OFF.


energizing for UHighBusEnerg. Set the operating level for the Line high voltage at Bus

energizing for UHighLineEnerg.

The threshold voltages UHighBusEnerg and UHighLineEnerg have to be set lower than the value

at which the network is considered to be energized. A typical value can be 80% of the base


118

voltages. If system voltages are above the set values here, relay will consider it as Live

condition.

ULowBusEnerg and ULowLineEnerg: Setting of the operating voltage level for the low Bus

voltage level at Bus energizing for ULowBusEnerg. Setting of the operating voltage level for the

low line voltage level at line energizing for ULowLineEnerg.

The threshold voltages ULowBusEnerg and ULowLineEnerg, have to be set to a value greater

than the value where the network is considered not to be energized. A typical value can be 40%

of the base voltages. If system voltages are below the set values here, relay will consider it as

Dead condition.

UMaxEnerg: Setting of the maximum live voltage level at which energizing is allowed. This

setting is used to block the closing when the voltage on the live side is above the set value of

UMaxEnerg. In present case this parameter is set to 105% of UBase.


The purpose of the timer delay settings, tAutoEnerg and tManEnerg, is to ensure that the dead

side remains de-energized and that the condition is not due to a temporary interference. If the

conditions do not persist for the specified time, the delay timer is reset and the procedure is

restarted when the conditions are fulfilled again. Circuit breaker closing is thus not permitted until

the energizing condition has remained constant throughout the set delay setting time. Normally

tManEnerg is recommended to set 0.1s. tAutoEnerg is not applicable in present case.

OperationSynch: Operation for synchronizing function Off/ On. This parameter is recommended

to set OFF.

FreqDiffMin, FreqDiffMax, UHighBusSynch, UHighLineSynch, UDiffSynch, tClosePulse,

tBreaker, tMinSynch and tMaxSynch: These parameters are not applicable if OperationSynch

is set to OFF.


Table 3-50 gives the recommended settings for Synchrocheck function. Table 3-50: Synchrocheck function Settings

Setting


Recommended

Settings Unit





119




OperationSynch Operation for synchronizing function Off/ On Off -

OperationSC Operation for synchronism check function

Off/On On -

UHighBusSC Voltage high limit bus for synchrocheck in % of

UBaseBus 80.0 %UBB

UHighLineSC Voltage high limit line for synchrocheck in % of

UBaseLine 80.0 %UBL












Manual 0.100 s




UHighBusEnerg Voltage high limit bus for energizing check in

% of UBaseBus 80.0 %UBB

UHighLineEnerg Voltage high limit line for energizing check in

% of UBaseLine 80.0 %UBL

ULowBusEnerg Voltage low limit bus for energizing check in %

of UBaseBus 40.0 %UBB

ULowLineEnerg Voltage low limit line for energizing check in %

of UBaseLine 40.0 %UBL


120



tAutoEnerg Time delay for automatic energizing check 0.100 s



busbar1 -


busbar2 -

SelPhaseLine1 Select phase for line1 Phase L1 for

line1 -

SelPhaseLine2 Select phase for line2 Phase L1 for

line2 -

ADDITIONAL NOTES:

1. These settings provided for the Shunt Reactor are for the considered case of Bus

Reactor connected in one and half CB bus configuration. 2. For the case of Shunt reactor used as Line Reactor, the Settings get modified

due to the fact that Reactor bushing CT inputs are used for reactor protection in

place of Bay CT used for some functions in the present case. 3. In the case of Bus Reactor also, It is advisable to use Bushing CT for Reactor

Back-up impedance protection function. Teed protection can be used additionally

for the protection of T point of the associated bay. 4. Back-up over-current and earth fault protection can also be duplicated in any of

the other IED.


IED USED FOR 400kV BUSBAR PROTECTION

Model setting calculation document for Busbar

2

TABLE OF CONTENTS

TABLE OF CONTENTS .................................. ............................................................................ 2

1 BASIC SYSTEM PARAMETERS............................ ............................................................. 6

1.1 Single line diagram of the Busbar ..................................................................................... 6

1.2 Busbar parameters ............................................................................................................. 6

2 TERMINAL IDENTIFICATION AND LIST OF FUNCTIONS...... ........................................... 7

2.1 REB500................................................................................................................................ 7

2.1.1 Terminal Identification ..................................................................................... 7 2.1.2 List of functions available and those used ....................................................... 7

3 SETTING CALCULATIONS AND RECOMMENDED SETTINGS FOR R EB500 ................. 8

3.1 REB500................................................................................................................................ 8

3.1.1 Busbar Protection (BBP) ................................................................................. 8 3.1.2 Breaker Failure Protection (BFP) ...................................................................11


3

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


4

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


5



400kV Busbar




6


1.1 Single line diagram of the Busbar

Single line diagram of the Busbar and CT/PT connections is shown in Figure 1-1.

Figure 1-1: Single line diagram of the Busbar with CT connections CT details:

CT core used for Busbar protection (same is applicable for both main-I and main-II relays):

Ratio : 2000/1A, CLASS : PS, Vk: 4000V, Imax at Vk : 120mA, Rct@75 DEGREE

CENTIGRADE ohm : <10Ω

Above details are applicable for all the bays of 400kV Busbar protection.

1.2 Busbar parameters

Busbar: At Substation-A

Frequency: 50Hz

Maximum fault level 3-ph: 20.41kA

Maximum fault level 1-ph: 12.41kA


7


The various functions required for the Busbar protection are provided in REB500 IED. The

terminal identification of this and list of various functions available in these IEDs are given in this

section.

2.1 REB500

2.1.1 Terminal Identification


Object Name: 400kV Busbar

Unit Name: REB500


Frequency: 50Hz



Table 2-1 gives the list of functions/features available in REB500 relay and also indicates the



Table 2-1: List of functions in REB500

Sl.No. Function/features available In REB500

Function/feature

activated

Yes/No

Recommended

Settings

provided

1 Busbar protection YES

2 Breaker failure protection YES


“Distributed busbar protection REB500 including lin e and transformer protection

Operating instruction” 1MRB520292-Uen, version 7.6.


8

3 SETTING CALCULATIONS AND RECOMMENDED

SETTINGS FOR REB500

The various functions required for the Busbar protection are provided in REB500. The setting

calculations and recommended settings for various functions available in this IED are given in

this section.

3.1 REB500

3.1.1 Busbar Protection (BBP)

Some general comments on BB protection application and settings are covered here.

If left uncleared, the effect of a fault in a bus-zone can be potentially far more damaging than

faults on other items of primary plant. The unplanned or unselective outage of the bus bar can

lead to the loss of power supply to a widespread area. The failure to clear a bus fault can lead to

considerable equipment damage and system instability. Therefore bus bar protection has an

important role to play.

Few important points related to application and settings are given below.

• Bus bar protections being of unit type, back-up protection is provided either by duplicating

the bus bar protection, or by reverse zone of line distance protection, or by time delayed

distance relays in the remote stations.

• Where the main bus bar protection is provided by the second zone elements of distance

relays (i.e., when no bus bar protection is provided), back-up protection can be considered

as being provided by the 3rd zone elements of distance relays in the more remote stations.

• For substations of high strategic importance or where the bus arrangements are complex,

the complete bus bar protection should be fully duplicated.

• In cases where the burn-through time of SF6 switchgear is considered to be shorter than the

tripping time from remote back-up protection, then also the bus bar protection must be

duplicated.

• Faults lying between C.B and C.T. shall be cleared from one side by opening of C.B on

busbar protection operation. However clearing of fault from other side shall be through

breaker failure protection/back up protection.


9

• 3 Phase trip relays shall be provided for each circuit breaker which shall also initiate B.F.P.

of concerned breaker.

• C.T wire supervision relays should be set with a sensitivity such that they can detect C.T.

secondary open circuit even in case of least loaded feeder.

• Bus bar differential protection should have overall sensitivity above heaviest loaded feeder

current unless a separate check zone has been provided. In cases where fault currents are

expected to be low, the protection should be sensitive enough to take care of such expected

low fault current.

Relay operating characteristic is shown in Figure 3-1.

Figure 3-1: Operating characteristics of the restra ined amplitude comparison function Guidelines for Settings:

IKmin (Op. char. ‘L1, L2, L3’): This dialog is for entering the parameters applicable to the

phase fault operating characteristic.

The pick-up setting for the fault current (IKmin) must be less (80%) than the lowest fault current

that can occur on the busbars (IKMS). These is a risk of the protection being too insensitive at

higher settings.


10

Providing the minimum fault current (IKMS) is high enough, IKmin should be set higher than the

maximum load current.

The ‘restrained amplitude comparison’ algorithm detects an internal fault when the settings for

IKmin and k are exceeded. A tripping command is only issued, however, providing the phase

comparison function detects an internal fault at the same time.

This is normally set to 1.3 times Maximum load current so that the value is set higher than the

maximum load current. Lowest fault current that can occur on Busbars are typically very higher

than the highest CT ratio.

k (Op. char. ‘L1, L2, L3’): The factor “k” (slope) is normally set to 0.80. Numerous tests on a

network model have shown this setting to be the most favorable.

Note: During a thorough-fault and normal operation, it is impossible for the differential

(operating) current to be higher than the restrain current.

Differential current alarm (Op. char. ‘L1, L2, L3’) : Alarm should be set lower than the lowest

load current. A typical setting is 5%.

Delay (Op. char. ‘L1, L2, L3’): Differential current alarm, a typical setting is 5s.

IKmin (Op. char. ‘L0’): Ikmin for ‘L0’ shall be set to 50% of the Ikmin of L1, L2, L3.

The procedure for setting the ground fault characteristic is the same as for phase faults.

This dialog is only available providing a neutral current measurement has been configured.

k, Differential current alarm, Delay (Op. char. ‘L0 ’): These parameters are set same as that

of Op. char. ‘L1, L2, L3’.

IKmin, k, Differential current alarm, Delay (Op. c har. ‘Check-Zone’): These parameters are

set same as that of Op. char. ‘L1, L2, L3’. These settings are not visible if check zone is not

used.


IKmin (Op. char. ‘L1, L2, L3’):

Maximum load current=2000A (CT ratio used for Busbar protection is considered)

Here CT ratio of any bay has been considered for settings. Check with actual max load and set

accordingly.

Ikmin =2600A (1.3 times of Maximum load current).

IKmin (Op. char. ‘L0’): Ikmin for ‘L0’ shall be set to 50% of the Ikmin of L1, L2, L3, i.e. 1300A.

Differential current alarm (Op. char. ‘L1, L2, L3’) :

In present case, Min bay current is 69A, i.e., 50Mvar, 420kV Bus Reactor bay current, which is

2.7% of Ikmin(2600A). As the minimum available setting is 5%, hence 5% is set.


11



Table 3-1: Differential protection settings

Setting Parameter Recommended

Settings

Unit

IKmin Op. char. ‘L1, L2, L3’ 2600 A

K Op. char. ‘L1, L2, L3’ 0.80

Differential current alarm Op. char. ‘L1, L2, L3’ 5 % IKmin

Delay (Differential current alarm) Op. char. ‘L1, L2,

L3’ 5 s

IKmin

Op. char. ‘L0’ 1300 A

k

Op. char. ‘L0’ 0.80

Differential current alarm

Op. char. ‘L0’ 5 % IKmin

Delay

(Differential current alarm)

Op. char. ‘L0’

5 s

3.1.2 Breaker Failure Protection (BFP)

Some general comments on Breaker failure protection application and settings are described

here.

Failure of a circuit breaker to open when a trip signal has been given to it can lead to wide

spread tripping. Disconnecting the adjacent breakers using a breaker failure protection can

contain the impact. Failure to provide this protection can lead to considerable equipment

damage and system instability. Therefore breaker fail protection has an important role to play.

Some important points related to its application and settings are given below.

• One may decide to plan and operate the power system to avoid transient instability at shunt

faults with a stuck breaker. The back-up fault clearance time then determines the power


12

transfer capability of the transmission network. This means that it is very important to have a

fast breaker failure protection.

• The relay is separate for each breaker and is to be connected in the secondary circuit of the

CTs associated with that particular breaker. This CT secondary may be a separate core, if

available. Otherwise it shall be clubbed with Main-I or Main-II protection core.

• For line breakers, direct tripping of remote end breaker(s) should be arranged on operation

of LBB protection. For transformer breakers, direct tripping of breaker(s) on the other side of

the transformer should be arranged on operation of LBB protection.

• For lines employing single phase auto-reclosing, the LBB relays should be started on a

single phase basis from the trip relays. This is to avoid load currents in the healthy phases,

after single phase tripping, leading to unwanted operation of the breaker failure protection,

since the current setting is normally lower than the load current.

• It is considered a good practice to have DC circuits of Gr.A and Gr.B protections and LBB

relay independent. A separately fused supply should be taken for LBB relay in this case.

• LBB cannot operate without proper initiation. It is good practice to provide redundant trip

output and breaker fail input where other forms of redundancy does not exist. One way of

doing this is by providing separate aux. relay in parallel with trip unit and using contacts of

these for LBB initiation.

• Separation should be maintained between protective relay and CB trip coil DC circuit so that

short circuit or blown fuse in the CB circuit will not prevent the protective relay from

energizing the LBB scheme.

• In addition to other fault sensing relays the LBB relay should be initiated by Busbar

protection, since failure of CB to clear a bus fault would result in the loss of entire station if

LBB relay is not initiated.

• Whenever used in combination with busbar protection scheme, tripping logic of the same

shall be used for LBB protection also.

• For breaker-fail relaying for low energy faults like buchholz operation, special considerations

may have to be given to ensure proper scheme operation by using CB contact logic in

addition to current detectors. It is recommended that for operation of Buchholz protection, an

additional criterion from breaker auxiliary contact may be provided.

• Current level detectors should be set as sensitive as the main protections. A general setting

of 200A primary value (this should be more than the minimum operating current of the main

protection) is commonly practiced for lines and transformers. However, in case of existing


13

schemes associated with lines having single phase autoreclosure and where phase wise

initiation is not available, it is recommended that 2ph + 1 E/F element may be used with

phase element set above maximum expected load current while E/F element may be set

sensitively.

• Current level detector for generators may be set at 50 mA (for 1A C.T. secondary).

• Timer setting should be set considering breaker interrupting time, current detector reset time

and a margin. Generally a timer setting of 200ms has been found to be adequate.

• It is recommended that the utilities maintain the circuit breaker performance data, which will

be useful in planning back-up protection and other actions pertaining to circuit breaker

performance and maintenance.

• It is desirable that the back-up fault clearance time is shorter than the operating time of the

remote protections. One would lose the advantages with the expensive bus bar

configuration, if Zone-2 of the distance protection in the remote substations operates faster

than the breaker failure protection.

• It is possible to use one delay for single-phase faults and a shorter delay for multi-phase

faults in the breaker fail protection. This is done to avoid transient instability during multi-

phase faults in combination with a stuck breaker. The critical fault clearance time is much

longer for single-phase faults than for multi-phase faults.

• It is possible to design the breaker failure protection to have two steps. This approach may

decrease the risk for unwanted operation of the breaker failure protection during

maintenance and fault tracing. Therefore it is recommended utilities consider two-stage

tripping to avoid any unwanted operation of circuit breaker fail protection.

• It is a good practice to use breaker failure protection provided in a separate hardware than

the one used for main protection, when a multifunction numerical protective relay is used for

line, transformer, reactor etc. This will help avoid losing breaker fail protection function when

main protection fails. Thus it can be separate stand-alone relay or provided in bay controller

or as part of bus bar protection. If the main protections are duplicated and have built in

breaker fail function, providing it in a separate hard ware is not required. In such cases the

breaker fail function gets duplicated.


14


BFP active : Set whether BFP need to be active or not. It is set to active in present case.

Setting (per current transformer): Basically, the current setting (IE) should be less than the

minimum fault current IKmin of the corresponding feeder (approx. 80%. i.e. 0.8). Just to satisfy

this condition, the setting would be

= In present case, this parameter is set to 0.2.

Timer 1 active: A second attempt is made to trip the circuit-breaker at the end of the set time t1

plus the internal processing time ta1.

Timer t2 is also started at the end t1. Timer 1 active setting is to activate or deactivate this timer.

Hence this parameter is set to active in present case.

Timer 2 active: Should the circuit-breaker again fail to trip within the set time of t2 plus the

internal processing time ta2, the breakers surrounding the fault are inter tripped. This parameter

is to activate the backup trip delay. Timer 2 active settings is to activate of deactivate this timer.

Hence this parameter is set to active in present case.

Timer t1: This is retrip time delay. In present case this parameter is set to 100ms.

To avoid any risk of a premature tripping command by the breaker failure protection, the

minimum setting of the timer t1 must be longer than the maximum time required for a successful

main protection trip plus the maximum reset time of the overcurrent function.

Minimum time for timer t1 is t1 > tCB + tv + tmargin.

Minimum t1 setting for a circuit-breaker operating time (tCB) of 40 ms

t1 > tCB + tv + tmargin = 40 ms + 19 ms + 20 ms > 79 ms

Maximum backup tripping time for a circuit-breaker operating time (tCB) of 40 ms

t1max = [te+ta1] + tCB + tv + tmargin = 24 ms + 40 ms + 19 ms + 20 ms = 103 ms.

Timer t2: This is backup trip time delay. In present case this parameter is set to 100ms.

Zone2 time of the distance relay must be set higher than the time of operation of LBB.

To avoid any risk of premature inter tripping of the surrounding breakers by the breaker failure

protection in the event of a successful backup trip at the end of t1, the minimum setting of the

timer t2 must be longer than the maximum time required for a backup trip plus the maximum

reset time of the overcurrent function.

Minimum time for timer t2 is t2 > ta1 + tCB + tv + tmargin

Minimum t2 setting for a circuit-breaker operating time (tCB) of 40 ms


15

t2 > tCB + [ta1 + tv] + tmargin = 40 ms + 33 ms + 20 ms > 93 ms

Maximum inter tripping time for a circuit-breaker operating time (tCB) of 40 ms

t2max = [te+ta1+ ta2]+ 2*(tCB + tv + tmargin) = 46 ms+ 2*(40 ms+19 ms+20 ms) = 204 ms.

Only if the above guidelines for the minimum settings of the breaker failure timers are strictly

observed is the correct operation of the breaker failure protection assured.

The maximum tripping time can be calculated on the basis of the settings for t1 and t2, the

recommended safety margin and the internal processing time.

Intertripping pulse duration: The trigger inputs are scanned every 16ms. A trigger signal

must have a pulse duration of at least 16ms to be certain that it will be detected. This parameter

is left to default value of 200ms.

Logic type: The internal breaker failure protection can be changed for special applications. For

normal breaker failure protection, this logic shall be set to 1 (Default value).


Table 3-2 gives the recommended setting for Breaker failure protection.

Table 3-2: Breaker failure protection settings

Setting Parameter Recommended Settings

Unit

BFP active Active

Setting (per current transformer) 0.2 IN

Timer 1 active Active

Timer 2 active active

Timer t1 100 ms

Timer t2 100 ms

Intertripping pulse duration 200 ms

Logic type 1

PROTECTIVE RELAY SETTING GUIDELINES FOR 220kV, 400kV AND 765kV

TRANSMISSION LINES

Page 1 of 19

Table of Contents A. UNCOMPENSATED TRANSMISSION LINES...................................................................3

1. ZONE-1 REACH SETTING: ...................................................................................................3



4. RESISTIVE REACH SETTING ...............................................................................................4

5. ZONE-2 TIMER SETTING: .....................................................................................................5

6. ZONE-3 TIMER SETTING ...................................................................................................... 7

7. LOAD IMPEDANCE ENCROACHMENT ..........................................................................7

8. ZONE-4 SUBSTATION LOCAL BACKUP PROTECTION SETTINGS ...........................8

9. USE OF SYSTEM STUDIES TO ANALYSE DISTANCE RELAY BEHAVIOUR ............9

10. DIRECTIONAL PHASE OVER CURRENT PROTECTION ........................................10

11. DIRECTIONAL GROUND OVER CURRENT PROTECTION SETTINGS ...............10

12. POWER SWING BLOCKING FUNCTION : ..................................................................11

12.1. Block all Zones except Zone-I : ......................................................................................11

12.2. Block All Zones and Trip with Out of Step (OOS) Function ...........................................12

12.3. Placement of OOS trip Systems ....................................................................................12

13. LINE OVERVOLTAGE PROTECTION ..........................................................................13

14. LINE DIFFERENTIAL PROTECTION............................................................................13

15. MAINTAINING OPERATION OF POWER STATION AUXILIARY SYSTEM OF

NUCLEAR POWER PLANTS: .....................................................................................................13

16. COORDINATION BETWEEN SYSTEM STUDY GROUP AND PROTECTION

ENGINEERS ...................................................................................................................................14

B. SERIES COMPENSATED TRANSMISSION LINES: ............................................................14

1) VOLTAGE AND CURRENT INVERSION.........................................................................14

1.1. Voltage inversion on Series Compensated line: ........................................................14


TRANSMISSION LINES

Page 2 of 19

1.2. Current inversion on Series Compensated line: ........................................................14

2) LOW FREQUENCY TRANSIENTS .....................................................................................15

3) MOV INFLUENCE AND APPARENT IMPEDANCE .....................................................15

4) IMPACT OF SC ON PROTECTIVE RELAYS OF ADJACENT LINES ...........................16

5) MULTI CIRCUIT LINES .......................................................................................................16

6) DIRECTIONAL RESIDUAL OVERCURRENT PROTECTION ......................................17

7) DISTANCE PROTECTION SETTINGS GUIDELINES .....................................................18

8) SIMULATION STUDIES .......................................................................................................19


TRANSMISSION LINES

Page 3 of 19

A review was made by the Protection Task force of the setting criteria for 220kV,

400kV and 765kV transmission lines (both uncompensated and series compensated)

and the recommendations on the settings to be adopted are given below. The

recommendations are based on guidelines given in following documents.

• CBIP Publication no 274: Manual on Protection of Generators, Generator

Transformers and 220kV and 400kV Networks

• CBIP Publication no 296: Manual on Reliable Fault Clearance and Back-Up

Protection of EHV and UHV Transmission Networks

• CIGRE WG B5.10, 411: Protection, Control and Monitoring Of Series

Compensated Networks

• CIGRE WG 34.04 ; Application Guide on Protection Of Complex

Transmission Network Configurations

A. UNCOMPENSATED TRANSMISSION LINES

1. ZONE-1 REACH SETTING:

Zone-1: To be set to cover 80% of protected line length. Set zero sequence compensation factor KN as (Z0 – Z1) / 3Z1.

Where:

Z1= Positive sequence impedance of the protected line

Z0 = Zero sequence impedance of the protected line

Note: With this setting, the relay may overreach when parallel circuit is open and grounded at both ends. This risk is considered acceptable.


Zone-2: To be set to cover minimum 120% of length of principle line section.

However, in case of double circuit lines 150% coverage must be provided to take

care of under reaching due to mutual coupling effect. Set KN as (Z0 – Z1) / 3Z1.

The 150% setting is arrived at considering an expected under reach of about 30%

when both lines are in parallel and a margin of 20%. The degree of under reach can


TRANSMISSION LINES

Page 4 of 19

be calculated using equation K0M / 1+K0 Where K0M = Z0M/ 3Z1 and K0 = (Z0 – Z1)

/ 3Z1. It is recommended to check the degree of under reach due to mutual coupling

effect to be sure that setting of 150% is adequate.

Sometimes impedance so selected might enter the next voltage level. However, un-

selectivity in the Zone-2 grading is generally not to be expected when in-feeds exist

at the remote sub-station as they reduce the overreach considerably.

This holds good for majority of the cases, however, for certain cases, where in-feed

from other feeder at the local bus is not significant, Zone-2 of remote end relay may

see the fault at lower voltage level. Care has to be taken for all such cases by suitable

time delay.


Zone-3 distance protection can offer time-delayed remote back-up protection for an

adjacent transmission circuit. To achieve this, Zone-3 distance elements must be set

according to the following criteria where possible.

Zone-3 should overreach the remote terminal of the longest adjacent line by an

acceptable margin (typically 20% of highest impedance seen) for all fault conditions.

Set KN as (Z0 – Z1) / 3Z1.

However, in such case where Zone-3 reach is set to enter into next lower voltage

level, Zone-3 timing shall be coordinated with the back-up protection (Directional

over current and earth fault relay) of power transformer. Where such coordination

cannot be realised, other means like application of back up distance protection for

power transformer or special protection scheme logic may have to be considered to

achieve protection coordination.

4. RESISTIVE REACH SETTING

For phase to ground faults, resistive reach should be set to give maximum coverage

considering fault resistance, arc resistance & tower footing resistance. It has been

considered that ground fault would not be responsive to line loading.


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For Zone-1 resistive reach, attention has to be given to any limitations indicated by

manufacturer in respect of resistive setting vis-a-vis reactance setting to avoid

overreach due to remote in-feed. It is recommended to study the impact of remote end

infeed for expected power flow & fault resistance on the extent of overreach. This is

particularly important for short lines.

In case of phase to phase fault, resistive reach should be set to provide coverage

against all types of anticipated phase to phase faults subject to check of possibility

against load point encroachment considering minimum expected voltage and

maximum load expected during short time emergency system condition.

It is recommended that all the distance relays should have quadrilateral / polygon

characteristic. For relays having Mho characteristic, it is desirable to have load

encroachment prevention characteristic or a blinder.

In the absence of credible data regarding minimum voltage and maximum load

expected for a line during emergency system condition, following criteria may be

considered for deciding load point encroachment:

• Maximum load current (Imax) may be considered as 1.5 times the thermal

rating of the line or 1.5 times the associated bay equipment current rating (the

minimum of the bay equipment individual rating) whichever is lower.

(Caution: The rating considered is approximately 15minutes rating of the

transmission facility).

• Minimum voltage (Vmin) to be considered as 0.85pu (85%).

Due to in-feeds, the apparent fault resistance seen by relay is several times the actual

value. This should be kept in mind while arriving at resistive reach setting for Zone-

2 and Zone-3.

5. ZONE-2 TIMER SETTING:

A Zone-2 timing of 0.35 seconds (considering LBB time of 200mSec, CB open time of

60ms, resetting time of 30ms and safety margin of 60ms) is recommended. However,


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if a long line is followed by a short line, then a higher setting (typically 0.6second)

may be adopted on long line to avoid indiscriminate tripping through Zone-2

operation on both lines.

For special cases, following shall be the guiding philosophy:

Since Zone-2 distance protection is set to overreach the circuit it is intended to

protect, it will also be responsive to faults within adjacent power system circuit. For

this reason the time delay for Zone–2 back-up protection must be set to coordinate

with clearance of adjacent circuit faults, within reach, by the intended main

protection or by breaker fail protection.

The following formula would be the basis for determining the minimum acceptable

Zone-2 time setting:

sresetzCBMAz ttttt +++> 22

Where:

tZ2 = Required Zone-2 time delay

tMA = Operating time of slowest adjacent circuit main protection or Circuit

Local back-up for faults within Zone-2 reach

tCB = Associated adjacent circuit breaker clearance time

tZ2reset = Resetting time of Zone-2 impedance element with load current

present

tS = Safety margin for tolerance (e.g. 50 to 100ms)

Unequal lengths of transmission circuit can make it difficult to meet the Zone-2

secondary reach setting criterion. In such cases it will be necessary to co-ordinate

Zone-2 with longer time delay. The time tMA in equation must be the adjacent circuit

Zone-2 protection operating time.


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6. ZONE-3 TIMER SETTING

Zone-3 timer should be set so as to provide discrimination with the operating time

of relays provided in subsequent sections with which Zone-3 reach of relay being

set, overlaps. Typical recommended Zone-3 time is 0.8 to 1.0 second.

For Special cases, where co-ordination between long and short lines is required,

following formula would be the basis for determining the minimum acceptable

Zone-3 time setting:

sresetzCBMAz ttttt +++> 33

Where:

tZ3 = Required Zone-3 time delay

tMA = Operating time of slowest adjacent circuit local back-up protection

tCB = Associated adjacent circuit breaker clearance time

tZ3reset = Resetting time of Zone-3 impedance element with load current present

tS = Safety margin for tolerance (e.g. 50 to 100milliseconds)

7. LOAD IMPEDANCE ENCROACHMENT

With the extended Zone-3 reach settings, that may be required to address the many

under reaching factors already considered, load impedance encroachment is a

significant risk to long lines of an interconnected power system. Not only the

minimum load impedance under expected modes of system operation be considered

in risk assessment, but also the minimum impedance that might be sustained for

seconds or minutes during abnormal or emergency system conditions. Failure to do

so could jeopardize power system security.

Ideal solution to tackle load encroachment may be based on the use of blinders or by

suitably setting the resistive reach of specially shaped impedance elements or by use

of polygon type impedance elements.


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It is recommended that all the distance relays should have quadrilateral / polygon

characteristic. For relays having Mho characteristics, it is desirable to have load

encroachment prevention characteristics or a blinder.

In the absence of credible data regarding minimum voltage and maximum load

expected for a feeder during emergency system condition, following criteria may be

considered for deciding resistive reach / blinder setting to prevent load point

encroachment:

• Maximum load current (Imax) may be considered as 1.5 times the thermal

rating of the line or 1.5 times the associated bay equipment current rating ( the

minimum of the bay equipment individual rating) whichever is lower.

(Caution: The rating considered is approximately 15 minutes rating of the

transmission facility).

• Minimum voltage (Vmin) to be considered as 0.85pu (85%).

• For setting angle for load blinder, a value of 30 degree may be adequate in most

cases.

For high resistive earth fault where impedance locus lies in the Blinder zone, fault

clearance shall be provided by the back-up directional earth fault relay.

8. ZONE-4 SUBSTATION LOCAL BACKUP PROTECTION SETTINGS

Zone-3 distance protection is usually targeted to provide only remote back-up

protection. In such a case, the distance relay may be provided with an additional

zone of reverse-looking protection (e.g. Zone-4) to offer substation-local back-up

protection. The criterion for setting Zone-4 reverse reach would be as under.

• The Zone-4 reverse reach must adequately cover expected levels of apparent bus

bar fault resistance, when allowing for multiple in feeds from other circuits. For

this reason, its resistive reach setting is to be kept identical to Zone-3 resistive

reach setting.


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With a reverse reach setting of less than the Zone-1 reach of distance protection for

the shortest line connected to the local bus bar, the Zone-4 time delay would only

need to co-ordinate with bus bar main protection fault clearance and with Zone-1

fault clearance for lines out of the same substation. For this reason this can be set

according to the Zone-2 time setting guidelines.

9. USE OF SYSTEM STUDIES TO ANALYSE DISTANCE RELAY BEHAVIOUR

Often during system disturbance conditions, due to tripping of one or more trunk

lines, some lines get overloaded and the system voltage drops. During such

conditions the back-up distance elements may become susceptible to operation due

to encroachment of impedance locus in to the distance relay characteristic.

While the ohmic characteristic of a distance relay is independent of voltage, the load

is not generally constant-impedance. The apparent impedance presented to a

distance relay, as the load voltage varies, will depend on the voltage characteristic of

the load. If the low voltage situation resulted from the loss of one or more

transmission lines or generating units, there may be a substantial change in the real

and reactive power flow through the line in question. The combination of low

voltage and worsened phase angle may cause a long set relay to operate undesirably

either on steady state basis, or in response to recoverable swings related to the

initiating event.

The apparent impedance seen by the relay is affected by in-feeds, mutual coupling

and therefore the behaviour of distance relay during various system condition needs

to be studied wherever necessary to achieve proper relay coordination.

It is desirable and hence recommended that system studies are conducted using computer-

aided tools to assess the security of protection by finding out trajectory of impedance in

various zones of distance relay under abnormal or emergency system condition on case-to-

case basis particularly for critical lines / corridors.

In addition, the settings must be fine-tuned, simulating faults using Real Time Digital

Simulator on case-to-case basis particularly for critical lines / corridors.


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Such facilities available at CPRI, POWERGRID or elsewhere in the country should

be used for protection related studies.

10. DIRECTIONAL PHASE OVER CURRENT PROTECTION

Directional phase over current relays are still being used as back-up protection for

220kV transmission lines by many utilities. In view of time coordination issues and

increased fault clearance time in the event of failure of main distance protection, it is

recommended that for all 220kV lines also main-1 and main-2 protections similar to 400kV

lines be provided.

11. DIRECTIONAL GROUND OVER CURRENT PROTECTION (DEF) SETTINGS

Normally this protection is applied as a supplement to main protection when

ground fault currents may be lower than the threshold of phase over current

protection. It might also be applied as main protection for high resistance faults.

The ground over current threshold should be set to ensure detection of all ground

faults, but above any continuous residual current under normal system operation.

Continuous residual current may arise because of following:

• Unbalanced series impedances of untransposed transmission circuits

• Unbalanced shunt capacitance of transmission circuits.

• Third harmonic current circulation.

Various types of directional elements may be employed to control operation of

ground over current (zero sequence over current) protection response. The most

common approach is to employ Phase angle difference between Zero sequence

voltage and current, since the relaying signals can easily be derived by summing

phase current signals and by summing phase voltage signals from a suitable voltage

transformer.

However this method is not suitable for some applications where transmission lines

terminated at different substations, run partially in parallel. In such cases following


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type of directional control is recommended to be used for the directional earth fault

relay.

• Relative phase of negative sequence voltage and current

To ensure proper coordination, operating time must be set according to following

criteria:

The DEF protection should not operate when the circuit local backup protection of

remote end clears a fault in an adjacent circuit i.e DEF should be coordinated with

the remote end LBB.

12. POWER SWING BLOCKING FUNCTION

While the power-swing protection philosophy is simple, it is often difficult to

implement it in a large power system because of the complexity of the system and

the different operating conditions that must be studied. There are a number of

options one can select in implementing power-swing protection in their system.

Designing the power system protection to avoid or preclude cascade tripping is a

requirement of modern day power system. Below we list two possible options:

12.1. Block all Zones except Zone-I

This application applies a blocking signal to the higher impedance zones of

distance relay and allows Zone 1 to trip if the swing enters its operating

characteristic. Breaker application is also a consideration when tripping during

a power swing. A subset of this application is to block the Zone 2 and higher

impedance zones for a preset time (Unblock time delay) and allow a trip if the

detection relays do not reset.

In this application, if the swing enters Zone 1, a trip is issued, assuming that the

swing impedance entering the Zone-1 characteristic is indicative of loss of

synchronism. However, a major disadvantage associated with this philosophy

is that indiscriminate line tripping can take place, even for recoverable power

swings and risk of damage to breaker.


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12.2. Block All Zones and Trip with Out of Step (OOS) Function

This application applies a blocking signal to all distance relay zones and order

tripping if the power swing is unstable using the OOS function (function built

in modern distance relays or as a standalone relay). This application is the

recommended approach since a controlled separation of the power system can

be achieved at preselected network locations. Tripping after the swing is well

past the 180 degree position is the recommended option from CB operation

point of view.

Normally all relay are having Power swing Un-block timer which unblocks on

very slow power swing condition (when impedance locus stays within a zone

for a long duration). Typically the Power swing un-blocking time setting is

2sec.

However, on detection of a line fault, the relay has to be de-blocked.

12.3. Placement of OOS trip Systems

Out of step tripping protection (Standalone relay or built-in function of Main

relay) shall be provided on all the selected lines. The locations where it is

desired to split the system on out of step condition shall be decided based on

system studies.

The selection of network locations for placement of OOS systems can best be obtained

through transient stability studies covering many possible operating conditions.

Till such studies are carried out and Out-of-Step protection is enabled on all identified

lines, it is recommended to continue with the existing practice of Non-Blocking of

Zone-I on Power Swing as mentioned under Option-12.1 above. However it should be

remembered that with this practice the line might trip for a recoverable swing and it is

not good to breakers.

Committee strongly recommends that required studies must be carried out at the

earliest possible time (within a timeframe of one year) to exercise the option-12.2 &

12.3 above.


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13. LINE OVERVOLTAGE PROTECTION

FOR 400kV LINES: Low set stage (Stage-I) may be set in the range of 110% - 112%

(typically 110%) with a time delay of 5 seconds. High set stage (Stage-II) may be set

in the range 140% - 150% with a time delay of 100milliseconds.

FOR 765kV LINES: Low set stage (Stage-I) may be set in the range of 106% - 109%

(typically 108%) with a time delay of 5 seconds. High set stage (Stage-II) may be set

in the range 140% - 150% with a time delay of 100milliseconds.

However, for over voltage Stage-I protection, a time grading of 1 to 3 seconds may

be provided between overvoltage relays of double circuit lines. Grading on

overvoltage tripping for various lines emanating from a station may be considered

and same can be achieved using voltage as well as time grading. Longest timed

delay should be checked with expected operating time of Over-fluxing relay of the

transformer to ensure disconnection of line before tripping of transformer.

It is desirable to have Drop-off to pick-up ratio of overvoltage relay better than 97%

(Considering limitation of various manufacturers relay on this aspect).

14. LINE DIFFERENTIAL PROTECTION

Many transmission lines are now having OPGW or separate optic fibre laid for the

communication. Where ever such facilities are available, it is recommended to have

the line differential protection as Main-I protection with distance protection as

backup (built-in Main relay or standalone). Main-II protection shall continue to be

distance protection. For cables and composite lines, line differential protection with

built in distance back up shall be applied as Main-I protection and distance relay as

Main-II protection. Auto-recloser shall be blocked for faults in the cables.

15. MAINTAINING OPERATION OF POWER STATION AUXILIARY SYSTEM OF NUCLEAR POWER PLANTS:

Depression of power supply voltages for auxiliary plant in some generating stations

may reduce the station output. Maintenance of full generation output may be a


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critical power system security factor. In the case of nuclear plant, auxiliary power

supplies are also a major factor in providing full nuclear plant safety and security.

The potential loss of system generation or the potential challenges to nuclear plant

safety systems may be factors which will dictate the longest acceptable clearance

times for transmission circuit faults in the vicinity of a power station. This should be

further taken up with utilities of nuclear plants and this and any other requirements

should be understood and addressed.

16. COORDINATION BETWEEN SYSTEM STUDY GROUP AND PROTECTION ENGINEERS

For quite a few cases where system behaviour issues are involved it is

recommended that power system study group is associated with the protection

engineers. For example power swing locus, out of step tripping locations, faults

withstands capability, zone2 and zone3 overlap reach settings calculations are areas

where system study group role is critical/essential.

B. SERIES COMPENSATED TRANSMISSION LINES: Following phenomenon associated with the protection of Series compensated lines

require special attention:

1) VOLTAGE AND CURRENT INVERSION

1.1. Voltage inversion on Series Compensated line:

In this case the voltage at the relay point reverses its direction. This

phenomenon is commonly called as voltage inversion. Voltage inversion causes

false decision in conventional directional relays. Special measures must be

taken in the distance relays to guard against this phenomenon.

1.2. Current inversion on Series Compensated line:

Fault current will lead source voltage by 90 degrees if XC> XS +XL1

Current inversion causes a false directional decision of distance relays (voltage


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memories do not help in this case). [Here XC is reactance of series capacitor, XS

is source reactance and XL1 is reactance of the line]

Current inversion influences operation of distance relays and therefore they

cannot be applied without additional logic for the protection of series

compensated lines when possibility of current inversion exists. Performance of

directional comparison protections, based on residual (zero sequence) and

negative sequence currents are also affected by current inversion. It is therefore,

recommended to check the possibility of current inversion through system studies at the

planning stage itself.

2) LOW FREQUENCY TRANSIENTS

Series capacitors introduce oscillations in currents and voltages in the power

systems, which are not common in non-compensated systems. These oscillations

have frequencies lower than the rated system frequency and may cause delayed

increase of fault currents, delayed operation of spark gaps as well as delayed

operation of protective relays.

Low frequency transients have in general no significant influence on operation of

line current differential protection as well as on phase comparison protection.

However they may significantly influence the correct operation of distance

protection in two ways:

-They increase the operating time of distance protection, which may in turn

influence negatively the system stability

-They may cause overreaching of instantaneous distance protection zones

and this way result in unnecessary tripping on series compensated lines.

It is recommended to reduce the reach setting by a safety factor (Ks) to take care of

possible overreach due to low frequency oscillations.

3) MOV INFLUENCE AND APPARENT IMPEDANCE

Metal oxide varistors (MOV) are used for capacitor over-voltage protection. In

contrast to spark gaps, MOVs carry current when the instantaneous voltage drop


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across the capacitor becomes higher than the protective voltage level in each half-

cycle. Extensive studies have been done by Bonneville Power Administration in

USA to arrive at a non-linear equivalent circuit for a series connected capacitor

using an MOV. The composite impedance depends on total fault current and

protection factor kp.

The later is defined by equation.

MOVp

NC

Uk

U=

Where UMOV is voltage at which MOV starts to conduct theoretically and UNC is

voltage across the series capacitor when carrying its rated nominal current

This should be considered while relay setting.

4) IMPACT OF SC ON PROTECTIVE RELAYS OF ADJACENT LINES

Voltage inversion is not limited only to the buses and to the relay points close to the

series compensated line. It can spread deep into the network and this way influence

the selection of protection devices (mostly distance relays) at remote ends of the

lines adjacent to the series compensated circuit, and sometimes even deeper in the

network. Estimation of their influence on performances of existing distance relays of

adjacent lines must be studied. In the study, it is necessary to consider cases with

higher fault resistances, for which spark gaps or MOVs on series capacitors will not

conduct at all.

If voltage inversion is found to occur, it may be necessary to replace the existing

distance relays in those lines with distance relays that are designed to guard against

this phenomenon.

5) MULTI CIRCUIT LINES

Two parallel power lines both series compensated running close to each other and

ending at the same busbar at both ends) can cause some additional challenges for

distance protection due to the zero sequence mutual impedance. The current


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reversal phenomenon can also raise problems from the protection point of view,

particularly when the power lines are relatively short and when permissive

overreach schemes are used.

Influence of zero sequence mutual impedance

Zero sequence mutual impedance ZM0 will not significantly influence the operation

of distance protection as long as both circuits are operating in parallel and all

precautions related to settings of distance protection on series compensated line

have been considered. Influence of parallel line switched off & earthed at both ends,

on the operation of distance protection on single operating circuit is well known.

The presence of series capacitor additionally exaggerates the effect of zero sequence

mutual impedance between two circuits. The effect of zero sequence mutual

impedance on possible overreaching of distance relays is increased further compared

to case of non-compensated lines. This is because while the series capacitor will

compensate self-impedance of the zero sequence network the mutual impedance

will be same as in the case of non-compensated double circuit lines. The reach of

under reaching distance protection zone 1 for phase to earth measuring loops must

further be reduced for such operating conditions.

Zero sequence mutual impedance may also disturb the correct operation of distance

protection for external evolving faults during auto reclosing, when one circuit is

disconnected in one phase and runs in parallel during dead time of single pole auto

reclosing cycle. It is recommended to study all such operating conditions by dynamic

simulations in order to fine tune settings of distance relays.

6) DIRECTIONAL RESIDUAL OVERCURRENT PROTECTION

All basic application considerations, characteristic for directional residual over-

current protection on normal power lines apply also to series compensated lines

with following additions. Low fault currents are characteristic of high resistive

faults. This means that the fault currents may not be enough to cause voltage drops

on series capacitors that would be sufficient to start their over-voltage protection.


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Spark gaps may not flash over in most cases, and metal oxide varistors (MOVs) may

not conduct any significant current. Series capacitors may remain fully inserted

during high resistive earth faults.

Local end directional residual OC protection:

The directional relay operates always correctly for reverse faults. VT located

between bus and capacitor generally does not influence directional measurement.

But in case VT is located between line and capacitor it may influence correct

operation: While reverse faults are detected correctly the forward operation is

dependent on system conditions. Additional zero sequence source impedance can be

added into relay circuits to secure correct directional measurement.

Remote end directional residual OC protection:

In this case the current can be reduced to extremely low values due to low zero

sequence impedance at capacitor end. Further the measured residual voltage can be

reduced to very low value due to low zero sequence source impedance and/or low

zero sequence current. Zero sequence current inversion may occur at the capacitor

end (dependent on fault position). Directional negative sequence OC protection too

may face very similar conditions.

Adaptive application of both the above OC protection principles can be considered

wherever required to get the desired result.

7) DISTANCE PROTECTION SETTINGS GUIDELINES

Basic criteria applied for Z1 & Z2 reach settings are :

• Zone-1 should never overreach for the fault at remote bus

• Zone-2 should never under reach for fault on protected line

• Permissive overreach (POR) schemes are usually applied

Distance protection Zone 1 shall be set to


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Zone-1 is set usually at 80% of Ks x ( )1 11 12Z S CX K X X X= ⋅ + − Where X11 is

reactance between CT and capacitor and X12 is reactance between capacitor and

remote end Bus, Xc is reactance of capacitor and KS is safety factor to prevent

possible overreaching due to low frequency (sub-harmonic) oscillations. These

setting guidelines are applicable when VT is installed on the bus side of the

capacitor . It is possible to remove XC from the above equation in case VT is installed

on line side , but it is still necessary to consider the safety factor.

Alternatively, Zone-1 is set at 80% of line impedance with a time delay of

100millisecond. POR Communication scheme logic is modified such that relay

trips instantaneously in Zone-1 on carrier receive. ( For remote end relay of

the line looking into series capacitor)

Zone-2 is set to 120 % of uncompensated line impedance for single circuit line.

For double circuit lines, special considerations are mentioned at Section B-5

above.

Phase locked voltage memory is used to cope with the voltage inversion.

Alternatively, an intentional time delay may be applied to overcome

directionality problems related to voltage inversion.

Special consideration may be required in over voltage stage-I (low set) trip

setting for series compensated double circuit lines. It has been experienced

that in case of tripping of a heavily loaded circuit, other circuit experience

sudden voltage rise due to load transfer. To prevent tripping of other circuit

on such cases, over-voltage stage-I setting for series compensated double

circuit lines may be kept higher at 113%.

8) SIMULATION STUDIES

System studies, Use of real Time digital simulators, Tests using EMTP files are very

important when applying protections for series compensated lines. It is recommended

to carry out such studies specific to each line.

PROTECTION SYSTEM MANAGEMENT

Page 1 of 5

Table of Contents

RECOMMENDATIONS FOR PROTECTION SYSTEM MANAGEMENT: ................................2

1. ESTABLISHING PROTECTION APPLICATION DEPARTMENT: .................................2

2. RELAY SETTING CALCULATIONS ....................................................................................2

3. COORDINATION WITH SYSTEM STUDY GROUP, SYSTEM PLANNING GROUP

AND OTHER STAKEHOLDERS ...................................................................................................3

4. SIMULATION TESTING FOR CHECKING DEPENDABILITY AND SECURITY OF

PROTECTION SYSTEM FOR CRITICAL LINES AND SERIES COMPENSATED LINES ...3

5. ADOPTION OF RELAY SETTING AND FUNCTIONAL VERIFICATION OF

SETTING AT SITE ...........................................................................................................................4

6. STORAGE AND MANAGEMENT OF RELAY SETTINGS ..............................................4

7. ROOT CAUSE ANALYSIS OF MAJOR PROTECTION TRIPPING (MULTIPLE

ELEMENT OUTAGE) ALONGWITH CORRECTIVE & IMPROVEMENT MEASURES .....4

8. PERFORMANCE INDICES: DEPENDABILITY & SECURITY OF PROTECTION

SYSTEM .............................................................................................................................................5

9. PERIODIC PROTECTION AUDIT ........................................................................................5

10. REGULAR TRAINING AND CERTIFICATION.............................................................5


Page 2 of 5

RECOMMENDATIONS FOR PROTECTION SYSTEM MANAGEMENT:

During the discussions and interactions with the various stake holders of the

protection system, it was strongly felt by the protection sub-committee members

that in addition to technical issues related to protection, the management issues

related to protection system need to be addressed. A questionnaire related to

applicable protection setting & coordination philosophy was sent to all utilities

through RPC. Responses were received only from few utilities. These responses

show that there is no uniformity in the protection philosophy followed by different

utilities throughout the country. Further, lack of response from most of the utilities

also indicates the lack of resources on their part to handle the protection system. In

order to comprehensively address the protection issues in the utilities, following are

the recommendations.

1. ESTABLISHING PROTECTION APPLICATION DEPARTMENT:

1.1. It is recommended that each utility establishes a protection application

department with adequate manpower and skill set.

1.2. The protection system skill set is gained with experience, resolving

various practical problems, case studies, close interaction with the relay

manufactures and field engineers. Therefore it is proposed that such

people should be nurtured to have a long standing career growth in the

protection application department.

2. RELAY SETTING CALCULATIONS

2.1. The protection group should do periodic relay setting calculations as and

when necessitated by system configuration changes. A relay setting

approval system should be in place.

2.2. Relay setting calculations also need to be revisited whenever the minor

configuration or loading changes in the system due to operational

constraints. Feedback from the field/substations on the performance of


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the relay settings should be collected and settings should be reviewed

and corrected if required.

3. COORDINATION WITH SYSTEM STUDY GROUP, SYSTEM

PLANNING GROUP AND OTHER STAKEHOLDERS

3.1. It is recommended that each utility has a strong system study group with

adequate manpower and skill set that can carry out various system

studies required for arriving at system related settings in protection

system in addition to others studies.

3.2. The protection application department should closely work in co-

ordination with the utility system study group, system planning group,

the system operation group.

3.3. Wherever applicable, it should also co-ordinate and work with all power

utilities to arrive at the proper relay setting calculations taking the system

as a whole.

3.4. The interface point relay setting calculations at CTU-STU, STU-

DISCOMS, STU-GEN Companies, CTU-GEN Companies and also

generator backup relay setting calculations related to system performance

should be periodically reviewed and jointly concurrence should be

arrived. The approved relay settings should be properly document.

3.5. Any un-resolved issues among the stakeholders should be taken up with

the RPC and resolved.

4. SIMULATION TESTING FOR CHECKING DEPENDABILITY AND

SECURITY OF PROTECTION SYSTEM FOR CRITICAL LINES

AND SERIES COMPENSATED LINES

4.1. Committee felt that even though Real Time Digital Simulation (RTDS) and

other simulation facilities are available in the country, use of the same by

the protection group is very minimum or nil.

4.2. It is recommended that protection system for critical lines, all series

compensated lines along with interconnected lines should be simulated

for intended operation under normal and abnormal system conditions


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and tested for the dependability and security of protection system. The

RTDS facilities available in the country like at CPRI, POWERGRID and

other places should be made use of for this purpose.

4.3. The network model should be periodically updated with the system

parameters, as and when network changes are incorporated.

5. ADOPTION OF RELAY SETTING AND FUNCTIONAL

VERIFICATION OF SETTING AT SITE

5.1. Protection application department shall ensure through field testing

group that the final relay settings are exactly adopted in the relays at field.

5.2. There should be clear template for the setting adoption duly authorized

and approved by the field testing in charge.

5.3. No relay setting in the field shall be changed without proper

documentation and approval by the protection application department.

5.4. Protection application department shall periodically verify the

implemented setting at site through an audit process.

6. STORAGE AND MANAGEMENT OF RELAY SETTINGS

6.1. The committee felt that with the application of numerical relays, increased

system size & volume of relay setting, associated data to be handled is

enormous. It is recommended that utilities shall evolve proper storage and

management mechanism (version control) for relay settings.

6.2. Along with the relay setting data, IED configuration file should also be

stored and managed.

7. ROOT CAUSE ANALYSIS OF MAJOR PROTECTION TRIPPING

(MULTIPLE ELEMENT OUTAGE) ALONGWITH CORRECTIVE &

IMPROVEMENT MEASURES

7.1. The routine trippings are generally analysed by the field protection

personnel. For every tripping, a trip report along with associated DR and

event logger file shall be generated. However, for major tripping in the

system, it is recommended that the protection application department

shall perform the root cause analysis of the event.


Page 5 of 5

7.2. The root cause analysis shall address the cause of fault, any mal-operation

or non-operation of relays, protection scheme etc.

7.3. The root cause analysis shall identify corrective and improvement

measures required in the relay setting, protection scheme or any other

changes to ensure the system security, reliability and dependability of the

protection system.

7.4. Protection application group shall keep proper records of corrective and

improvement actions taken.

8. PERFORMANCE INDICES: DEPENDABILITY & SECURITY OF

PROTECTION SYSTEM

8.1. The committee felt that key performance indices should be calculated on

yearly basis on the dependability and security of protection system as

brought out in CBIP manual.

9. PERIODIC PROTECTION AUDIT

9.1. Periodic audit of the protection system shall be ensured by the protection

application team.

9.2. The audit shall broadly cover the three important aspect of protection

system, namely the philosophy, the setting, the healthiness of Fault

Clearing System.

10. REGULAR TRAINING AND CERTIFICATION

10.1. The members of the protection application team shall undergo regular

training to enhance & update their skill sets.

10.2. The training modules shall consist of system studies, relaying

applications, testing & commissioning

10.3. Certification of protection system field engineer for the testing &

commissioning of relay, protection scheme is strongly recommended.

CHECK LIST FOR AUDIT OF FAULT CLEARANCE SYSTEM FOR

765kV, 400kV & 220kV SUBSTATIONS

Page 1 of 16

Introduction:

This check list is prepared by the Protection sub-committee under task force to

enable audit of practices followed in protection application & criteria used for

setting calculations in 220kV, 400kV & 765kV substations. It aims to cover the

entire fault clearance system used for overhead lines & cables, power

transformers, shunt reactors and bus bars in a substation. The objective is to

check if the fault clearance system provided gives reliable fault clearance.

The check list is generally based on the guidelines given in the following

documents:

• CBIP Publication no 274: Manual on Protection of Generators, Generator

Transformers and 220kV and 400kV Networks

• CBIP Publication no 296: Manual on Reliable Fault Clearance and Back-Up

Protection of EHV and UHV Transmission Networks

• CIGRE WG B5.10, 411: Protection, Control and Monitoring Of Series

Compensated Networks



Page 2 of 16

CHECK-LIST:

Check list for different protected objects & elements in fault clearance system are as

under:

(put √ mark in the appropriate box )

A. Transmission Lines (OHL and Cables)

1. Independent Main-I and Main-II protection (of different make OR

different type) is provided with carrier aided scheme

YES NO

2. Are the Main-I & Main-II relays connected to two separate DC

sources (Group-A and Group-B)

YES NO

3. Is the Distance protection (Non-switched type, suitable for 1-ph & 3-

ph tripping) as Main1 and Main2 provided to ensure selectivity &

reliability for all faults in the shortest possible time

YES NO

4. Is both main-I & Main-II distance relay are numerical design having

Quadrilateral or Polygon operating characteristic

YES NO

5. In the Main-I / Main-II Distance protection, Zone-I is set cover 80%

of the protected line section

YES NO

6. In the Main-I / Main-II distance protection, Zone-2 is set cover 120%

of the protected line section in case of Single circuit line and 150% in

case of Double circuit line

YES NO

7. In the Main-I / Main-II distance protection, Zone-3 is set cover 120%

of the total of protected line section plus longest line at remote end as

a minimum.

YES NO



Page 3 of 16

8. Resistive reach for Ground fault element set to give maximum

coverage considering fault resistance, arc resistance & tower

footing resistance. ( In case, It is not possible to set the ground

fault and phase fault reaches separately, load point

encroachment condition imposed on Phase fault resistive reach

shall be applied)

YES NO

9. Resistive reach for Phase fault element set to give maximum

coverage subject to check of possibility against load point

encroachment considering minimum expected voltage and

maximum load.

YES NO

10. In case of short lines, is manufacturers recommendation considered

in respect of resistive setting vis a vis reactance setting to avoid

overreach.

YES NO

11 Is Zone-2 time delay of Main-I / Main-II distance relay set to 0.350

seconds ?

In case any other value has been set for Zone-II timer, kindly specify

the value and justification thereof.

YES NO

12 Is Zone-3 timer is set to provide discrimination with the operating

time of relays at adjacent sections with which Zone-3 reach of relay is

set to overlap.

Please specify the Zone-3 time set.

YES NO

13. Is Zone-4 reach set in reverse direction to cover expected levels of

apparent bus bar fault resistance, when allowing for multiple in

feeds from other circuits?

YES NO

14. Is reverse looking Zone-4 time delay set as Zone-2 time delay? YES NO

15. Is Switch on to fault (SOTF) function provided in distance relay to

take care of line energisation on fault?

Whether SOTF initiation has been implemented using hardwire logic

YES NO

YES NO



Page 4 of 16

In case of Breaker and half switching scheme, whether initiation of

line SOTF from CB closing has been interlocked with the other CB

YES NO

16. Whether VT fuse fail detection function has been correctly set to

block the distance function operation on VT fuse failure

YES NO

17. Is the sensitive IDMT directional E/F relay (either separate relay or

built-in function of Main relay) for protection against high resistive

earth faults?

YES NO

18. Is additional element (Back-up distance) for remote back-up

protection function provided in case of unit protection is used as

Main relay for lines?

YES NO

19. In case of Cables, is unit protection provided as Main-I & Main-II

protection with distance as back-up.

YES NO

20. Are the line parameters used for setting the relay verified by field

testing

YES NO

21. Is Two stages Over-Voltage protection provided for 765 & 400kV

Lines?

Do you apply grading in over-voltage setting for lines at one station.

Please specify the setting values adopted for:

Stage-I : (typical value - 106 to 112 % , delay : 4-7 Sec)

Stage-II: (typical value - 140 to 150%, delay: 0 to 100msec.)

YES NO

YES NO

22. Is 1-ph Auto –reclosing provided on 765, 400 & 220kV lines? Please

specify the set value:

Dead time: (typical 1 Sec)

Reclaim time: (typical 25 Sec)

YES NO



Page 5 of 16

23. Is the Distance communication. Scheme Permissive Over Reach

(POR) applied for short lines and Permissive Under Reach (PUR)

applied for long lines?

If any other communication scheme has been applied, please provide

the detail with justification thereof.

YES NO

24. Is the Current reversal guard logic for POR scheme provided on

Double circuit lines?

YES NO

25. In case the protected line is getting terminated at a station having

very low fault level i.e. HVDC terminal, whether week end-infeed

feature has been enabled in respective distance relay or not

YES NO

26. In case of protected line is originating from nuclear power station,

are the special requirement (stability of nuclear plant auxiliaries) as

required by them has been met

YES NO

27. What line current , Voltage and Load angle have been considered for

Load encroachment blinder setting and what is the resultant MVA

that the line can carry without load encroachment.

(In the absence of Load encroachment blinder function, this limit

shall be applied to Zone-3 phase fault resistive reach.)

I=

V=

Angle:

S=

28. a) What are the Zones blocked on Power swing block function:

b) Setting for Unblock timer: (typical 02 second)

c) Out of Step trip enabled

Z1 / Z2 / Z3 / Z4

Time:

YES NO

29. Whether the location of Out of step relay has been identified on the

basis of power system simulation studies

YES NO

30. a) Is the Disturbance recorder and Fault locator provided on all line

feeder ?

b) Whether standalone or built in Main relay

c) Whether DR is having automatic fault record download facility to

a central PC

d) Whether DR is time synchronised with the GPS based time

YES NO

Standalone / built-

in

YES NO



Page 6 of 16

synchronising equipment

e) Whether DR analog channels contain line phase & neutral current

and line phase & neutral voltage.

f) Whether DR digital channel as a minimum contain the CB status,

Main-I & II trip status, LBB trip status, Over-voltage trip status,

Stub protn trip status, Permissive and direct carrier receive status,

Line reactor trip status.

YES NO

YES NO

YES NO

B. Power Transformers

1. Do you use Group A and Group B protections connected to separate

DC sources for power transformers

YES NO

2. Do you follow CBIP guideline (274 & 296) for protection setting of

transformer

YES NO

3. Do you use duplicated PRD and Bucholtz initiating contact for power

transformers at 765kV and 400kV levels

YES NO

4. Do you classify transformer protections as below in groups:

Group A Group B

• Biased differential relay Restricted earth fault (REF) relay

• PRD , WTI Buchholz Protection, OTI

• Back up Protection(HV) Back up Protection(MV)

• Overfluxing protection(HV) Overfluxing protection(MV)

YES NO

5. In case of Breaker & half switching scheme, whether CT associated

with Main & Tie Breakers are connected to separate bias winding of

the low impedance Biased differential protection in order to avoid

false operation due to dissimilar CT response.

YES NO

6. Is Restricted earth fault (REF) protection used a high impedance type YES NO



Page 7 of 16

7. Are Main protection relays provided for transformer are of numerical

design.

YES NO

8. a) Are directional over current & earth fault relays provided as

back-up protection of Transformer are of numerical design.

b) Do the back-up earth fault relays have harmonic restrain feature

YES NO

YES NO

9. Is Fire protection system (HVW type) provided for power

transformer and functioning

YES NO

10. a) Is the Disturbance recorder provided for Transformer feeder



a central PC

d) Whether DR is time synchronised with the GPS time

synchronising equipment

YES NO

Standalone/built-in

YES NO

YES NO

C. Shunt Reactors

1. Do you use Group A and Group B protections connected to separate

DC sources for reactors

YES NO

2. Do you follow CBIP guideline (274 and 296) for protection setting of

reactors

YES NO

3. Do you use duplicated PRD and Bucholtz initiating contact for

Reactors at 765kV and 400kV levels

YES NO

4. Do you classify Reactor protections as below in groups:

Group A Group B

• Biased differential relay R.E.F Protection

YES NO



Page 8 of 16

• PRD , WTI Buchholz Protection, OTI

• Back up impedance Protection Or Direction O/C & E/F relay

5 In case of Breaker & half switching scheme, whether CT associated with

Main & Tie Breakers are connected to separate bias winding of the low

impedance Biased differential protection in order to avoid false

operation due to dissimilar CT response.

YES NO

6 Is Restricted earth fault (REF) protection used a high impedance type YES NO

7 Are Main & back-up protection relays provided for Reactor are of

numerical design.

YES NO

8 Is Fire protection system (HVW type) provided for Reactor and

functioning

YES NO

9 a) Is the Disturbance recorder and Fault locator provided on all the

Shunt Reactors used in 765 kV, 400 kV substations?


c) Whether DR is having automatic fault record download facility to a

central PC

YES NO

Standalone/built-

in

YES NO

D. Bus bars

1. Bus Bar protection for 765, 400 & 220kV buses is provided YES NO

2. Duplicated Bus bar protection is provided for 765kV and 400kV

buses

YES NO

3. CBIP guideline for Protection (274 and 296) settings is followed YES NO



Page 9 of 16

4 In an existing substation if CTs are of different ratios, is biased type

bus protection provided.

YES NO

5 In stations where single bus bar protection is provided, is backup

provided by reverse looking elements of distance relays or by second

zone elements of remote end distance relays?

YES NO

6 In case of GIS where burn through time of SF6 is shorter than remote

back up protection is the bus bar protection duplicated irrespective of

voltage level?

YES NO

7 Since it is difficult to get shutdowns to allow periodic testing of bus

protection, numerical bus protections with self-supervision feature is

an answer. Is this followed?

YES NO

E. Disturbance Recorder (DR) and Event Logger (EL)

1 a) Is the Disturbance recorder and Fault locator provided on all line

feeder of 765, 400 & 220kV substations?



a central PC

d) Whether Central PC for DR , EL are powered by Inverter (fed

from station DC)

YES NO

Standalone / built-

in

YES NO

YES NO

2. Whether DR is having the following main signals for lines:

Analogue signals:

• From CT: IA, IB, IC, IN

• From VT: VAN, VBN, VCN

• From Aux. VT: V0

Digital Signals

• Main 1 Carrier receive

YES NO



Page 10 of 16

• Main 1 Trip

• Line O/V Stage I / Stage II

• Reactor Fault Trip

• Stub Protection Operated.

• Main II Trip

• Main II Carrier Receive

• Direct Trip CH I / II

• CB I Status (PH-R, Y & B)

• CB II Status (PH R, Y & B)

• Bus bar trip

• Main / Tie CB LBB Operated

• Main / Tie Auto-reclose operated.

DR for Transformer / Reactor feeder should contain analog channel

like input currents & voltage. Binary signal include all protection trip

input, Main & Tie CB status, LBB trip

3. Whether substation (765, 400 , 220kV) is having Event logger facility

(standalone or built-in-SAS)

YES NO

4. Whether GPS based time synchronizing equipment is provided at the

substation for time synchronizing of Main relays / DR/ Event logger

/ SAS/ PMU / Line Current Differential Relays

YES NO



Page 11 of 16

F. Circuit Breakers

1. Is breaker fail protection ( LBB / BFR) provided for all the Circuit

Breakers at 220kV , 400kV & 765kV rating

YES NO

3. For Circuit Breaker connected to line feeder / transformer feeder,

whether operation of LBB / BFR sends direct trip signal to trip

remote end breaker ?

YES NO

4. For lines employing single phase auto reclosing, Is start signal from

protection trip to LBB / BFR relay is given on single phase basis?

YES NO

5. Is separate relay provided for each breaker and the relay has to be

connected from the secondary circuit of the CTs associated with that

particular breaker?

YES NO

6. Is LBB relay provided with separate DC circuit independent from

Group-A and Group-B Protections?

YES NO

7. Is the LBB initiation provided with initiating contact independent of

CB trip relay contact?

YES NO

8. Is Separation maintained between protective relay and CB trip coil

DC circuit so that short circuit or blown fuse in the CB circuit will not

prevent the protective relay from energizing the LBB scheme?

YES NO

9. Is LBB relay initiated by Bus bar protection in addition to other fault

sensing relays, since failure of CB to clear a bus fault would result in

the loss of entire station if BFP relay is not initiated?

YES NO

10. Is tripping logic of the bus bar protection scheme used for LBB

protection also?

YES NO

11. Are the special considerations provided to ensure proper scheme

operation by using Circuit Breaker contact logic in addition to

current detectors in cases breaker-fail relaying for low energy faults

like buchholz operation?

YES NO



Page 12 of 16

12. Are the Current level detectors set as sensitive as the main

protection? (Generally setting of 0.2 A is commonly practiced for

lines and transformers)

YES NO

13. Is timer set considering breaker interrupting time, current detector

reset time and a margin? (Generally a timer setting of 200ms has been

found to be adequate)

YES NO

14. Is the back-up fault clearance time is shorter than the operating time

of the remote protections (distance relay Zone-2) ?

YES NO

15. Is the breaker failure protection provided with two steps ( First stage

– retrip own CB, Second stage- Trip all associated CBs) . This

mitigates unwanted operation of breaker failure protection during

maintenance and fault tracing.

YES NO

16. Is the breaker failure protection hardware provided is separate from

line /transformer feeder protection?

YES NO

G. Communication systems

1.

a) Do you use PLCC for tele-protection of distance relays at 765, 400

& 220kV feeders

b) Specify type of coupling

c) Whether redundant PLCC channels provided for 400 & 765kV

lines

d) Specify number of PLCC channels per circuit :

e) Whether dependability & security of each tele-protection channel

measured & record kept ?

YES NO

( Ph-Ph / Ph-G/

Inter-circuit)

YES NO

( One / two)

YES NO

2. a) In case you use OPGW for tele-protection, are they on

geographically diversified route for Main-I and Main-II relay?

b) Whether dedicated fibre is being used for Main-I / Main-II relay

or multiplexed channel are being used.

YES NO

Dedicated /

multiplexed



Page 13 of 16

H. Station DC supply systems

1. Do you have two separate independent DC system (220V or 110V)

(Source-A and Source-B)

YES NO

2. Do you have two independent DC system (48V) for PLCC

(source-A and source-B)

YES NO

3. There is no mixing of supplies from DC source-A and DC source-B YES NO

4. Whether the protection relays and trip circuits are segregated into

two independent system fed through fuses from two different DC

source

YES NO

5. Whether Bay wise distribution of DC supply done in the following

way:

a) Protection

b) CB functions

c) Isolator / earth switch functions

d) Annunciation / Indications

e) Monitoring functions

YES NO

6 Whether following has been ensured in the cabling:

a) Separate cables are used for AC & DC circuits

b) Separate cables are used for DC-I & DC-II circuits

c) Separate cables are used for different cores of CT and CVT

outputs to enhance reliability & security

YES NO

7 Is guidelines prescribed in CBIP manual 274 & 296 followed in

general

YES NO



Page 14 of 16

E. PERFORMANCE INDICES

1. Is there a system of periodically measuring Dependability &

Security of Protection system (as given in CBIP manual 296)

and recorded

YES NO

2. Is there a system of periodically measuring Dependability of

switchgear associated with Protection system and recorded

YES NO

3. Is there a process of Root cause analysis of unwanted tripping

events

YES NO

4. Are improvement action like revision of relay setting, better

maintenance practices, modernising & retrofitting of switching

& protection system taken based on above data.

YES NO

5. Is attention also given to DC supply system, tele-protection

signalling, healthiness of tripping cables, terminations etc. in

order to improve the performance of fault clearance system

YES NO



Page 15 of 16

F. ADDITIONAL CHECKS FOR SERIES COMPENSATED LINES

1. What is the operating principle of Main protection

employed

Distance

Line Current

differential

2. Are both main-I & Main-II distance relay are numerical design YES NO

3. Are both main-I & Main-II distance relay suitable for Series

compensated lines

YES NO

4. Are POR tele-protection scheme employed for distance relays YES NO

5. Position of Line VT provided on series compensated line Between Capacitor

and line

Between Capacitor

and Bus

6. What is the under reaching (Zone 1) setting used in

teleprotection schemes (Local & Remote end)

% of line length

Rationale:

7. What is the overreaching (Zone 2) setting in used teleprotection

schemes

% of line length

Rationale:

8. What kinds of measurement techniques are used to cope with

voltage inversion?

Phase locked voltage

memory

Intentional time delay

Other, specify:

9. Whether system studies carried out to check the possibility of

current inversion due to series compensation

YES NO

10. Whether any system studies conducted to find the impact of YES NO



Page 16 of 16

series compensation on the performance of protections installed

on adjacent lines? If yes, how many lines were found to be

affected. Pl. specify ________________

11 If YES, are the affected protections on adjacent lines changed /

setting revised after the introduction of series compensation?

YES NO

12. Is dynamic simulation done to fine tune settings of distance relay

installed on series compensated double circuit lines?

YES NO

13. Whether performance of directional earth fault relay verifies by

simulation studies

YES NO

14. When is flashover of spark gaps expected? For protected line

Faults up to ohms

For external faults an

adjacent lines

15. Whether measures taken for under/overreach problems at sub-

harmonic oscillations?

YES NO

16. Whether MOV influence considered while setting the distance

relay reach

YES NO

17. Have you experienced any security problems (Relay mal-

operation) with high frequency transients caused by

Flashover of spark gaps

Line energisation

Other, specify:

YES NO

18. If YES, how the above problem has been addressed? __________________

DETAILS OF PROTECTION AUDIT

A. General

Information:

1 Name of Sub-

station 2 Date of first commissioning

3 Type of Bus

Switching Scheme: 4 Whether SLD collected or Not:

5 Audit Team:

1.

2.

3.

1) Instrument

Transformer ( To be filled for each one of them)

A Current

transformer (C T)

1 Location of CT

a Date of CT ratio

Test Testing

b

Core I Core II Core III Core IV Core V Core VI

i Ratio Adopted

ii Ratio measured

iii error calculated

Knee point voltage

B Capacitive voltage transformer (C V T)

1 Location of CVT

a Date of Testing

b CVT ratio Test

Core I Core II Core III

i Ratio Adopted

ii Ratio measured


2 Location of CVT

a Date of Testing

b CVT ratio Test

Core I Core II Core III

i Ratio Adopted

ii Ratio measured


2) Availability of Protection System

A) Bus Bar relay

765kV 400kV 220kV

i) Make and Model

of Bus Bar relay

ii) Whether stability

checks done or not

iii) Date of testing

iv) Remarks (if any)

C) Sub-station protection and monitoring Equipments

System LBB

(Make & Model)

Functional

(Yes / No)

Date of last

testing

Event

Logger

(Make &

Model)

Functional

(Yes / No)

Synchonising

Facility

Available or

not

Synchro Check

Relay (Make and

Model)

Setting of

Synhrocheck

Relay

i) 765kV System

II) 400kV System

III) 220kV System

D. Transmission Line

Protection

Name of Line

Main-I

Protection

(Make and

Model)

Functional

(Yes / No)

Date of

testing

Main-II

Protection

(Make and

Model)

Functional

(Yes / No)

Date of

testing

LBB Protection

(Make and Model)

Functional

(Yes / No)

Date of

testing

PLCC/Pro

tection

coupler

(Make

and

Model)

Functional

(Yes / No)

DR

(Make &

Model)

Functional

(Yes / No)

Time

Synch. Unit

(Make &

Model)

OK

/ Not

OK

i) Line-1

ii) Line-2

iii) Line-3

iv) Line-4

v) Line-5

vi) Line-6

E) Transformer Protection

Name of ICT

Differential

Protection

(Make & Model)

REF

Protection

(Make &

Model)

Back-up

Over Current

Protection

(Make &

Model)

Over Flux

Protection

(Make &

Model)

OTI/WTI

Indication

working or

not

Bucholtz

/

PRD

Other protection Date of last

testing

LA

Rating

HV Side

LA Rating

IV Side

i) ICT-1

ii) ICT-2

iii) ICT-3

iv) ICT-4

F) Reactor Protection

Name of Reactor

Differential

Protection

(Make & Model)

REF

Protection

(Make &

Model)

Back-up

Impedance

Protection

(Make &

Model)

OTI/WTI

Indication

working or

not

Bucholtz

/ PRD Other prot’n Date of testing

LA Rating HV

Side

i) Line -1 Reactor

ii) Line -2 Reactor

iii) Bus Reactor-1

iv) Bus Reactor-2

3) Line Parameter

Line 1 Line 2 Line 3 Line 4 Line 5 Line 6

i) Name of Line

ii) Line Length

iii)

Line Parameters

( In Ohms/Per KM/Per Phase Primary

value)

R1

X1

Ro

Xo

RoM

XoM

iv) Present Relay

setting

a Adopted Relay

setting

Enclosed as Annexure -I ( Please enclose the settings for all lines, transformers, Reactors and

Bus Bars)

b Recommended Enclosed as Annexure -II ( Please enclose the settings for all lines, transformers, Reactors and

relay setting Bus Bars)

4) DC supply

220 /110 V DC-I 220 /110 V DC-II 48 V DC-I 48 V DC-II

a Measured voltage

(to be measured at

furthereset Panel

i) Positive to Earth NA NA

ii) Negative to Earth

b No.of Cells Per

Bank

c Availability of

Battery Charger Yes/No Yes/No Yes/No Yes/No

5) Circuit Breaker

Make and Model Status of Breaker

Available or Not

No.of

trip/close coil

& healthiness

PIR (Available

or Not)

Date of

Last Timing

taken

Remarks (If

any)

A. 765kV System

i). 765kV Bay-1

ii). 765kV Bay-2

iii). 765kV Bay-3

iv). 765kV Bay-4

v). 765kV Bay-5

vi). 765kV Bay-6

B. 400kV System

i). 400 KV Bay-1

ii). 400 Kv Bay-2

iii). 400 Kv Bay-3

iv). 400 Kv Bay-4

v). 400 Kv Bay-5

vi). 400 Kv Bay-6

vii). 400 Kv Bay-7

viii)

. 400 Kv Bay-8

ix). 400 Kv Bay-9

x). 400 Kv Bay-10

B 220kV System

i). 220kV Bay-1

ii). 220kV Bay-2

iii). 220kV Bay-3

iv). 220kV Bay-4

v). 220kV Bay-5

vi). 220kV Bay-6

vii). 220kV Bay-7

viii)

. 220kV Bay-8

Note: rows to be added / deleted as required for no. of bays

6) Availability of

auxiliary System

i)

Auxiliary Supply Source of Supply Reliability of Supply

Average

tripping per

month

Supply-I

Supply-II

ii) DG Set

Make

Rating

Whether Dg set on

Auto or manual

Fuel level

7) Availability of UFR

relay

Make

Setting

8) Availability of

df/dt relay

Make

Setting

9) Special Protection

Scheme (SPS)

Available (Yes/No)

Verification

10) Status of Corrective action based on

Tripping analysis

11) Any Other Observation/ Comments

wrpc.gov.inwrpc.gov.in/pcm/relay_set.pdfprotection subcommittee report preamble as a follow up of...

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