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.
Protection subcommittee report
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 subcommittee 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
Protection subcommittee report
LIST OF CONTENTS Preamble Section Description 1 : Introduction
Pages 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
Protection subcommittee report
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 -1-
Protection subcommittee report 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 -2-
Protection subcommittee report mal-operations (if excel based sheets with macros are used for setting calculations, they should be used cautiously in a transparent manner and explained the reasoning associated with macros / formulae). Recommended settings: This subsection details recommended setting list with settings for all the parameters. Settings given in this section need to be used by site engineer for setting the IED.
It is recommended that these model setting calculations are reviewed periodically to take care of any changes in manufacturer's design, use of simulation tools, RTDS, or better understanding of settings and guidelines etc. It is also recommended that setting calculation documents are prepared for IEDs of different manufacturers that are used in the system. Disclaimer: The model setting calculations and recommended settings presented in this document are for the specific case considered here. Further, the make of the relay considered is also for illustration purpose only. In the settings which do not require any calculations based on network data, few of the settings may need review for other practical cases. For settings that require calculations, power system network data pertaining to respective cases is to be considered. However, the methodology adopted in this example shall be used for calculating the line and other equipment protection relay settings and arriving at list of recommended settings.
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MODEL SETTING CALCULATION DOCUMENT FOR A TYPICAL IED USED FOR TRANSMISSION LINE PROTECTION
Model setting calculation document for Transmission Line
TABLE OF CONTENTS TABLE OF CONTENTS...............................................................................................................2 1.0 BASIC SYSTEM PARAMETERS .........................................................................................8 1.1 Network line diagram of the protected line and adjacent circuits ...................................8 1.2 Single line diagram of the double circuit line....................................................................9 1.3 Line parameters ..................................................................................................................9 2.0 TERMINAL IDENTIFICATION AND LIST OF FUNCTIONS................................................10 2.1 REL670...............................................................................................................................10 2.1.1 Terminal Identification..........................................................................................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 3.1.2 3.1.3 3.1.4 3.1.5 3.1.6 3.1.7 3.1.8 3.1.9 3.1.10 3.1.11 3.1.12 3.1.13 3.1.14 3.1.15
Analog Inputs.......................................................................................................23 Local Human-Machine Interface ..........................................................................26 Indication LEDs....................................................................................................26 Time Synchronization ..........................................................................................28 Parameter Setting Groups ...................................................................................31 Test Mode Functionality TEST.............................................................................32 IED Identifiers ......................................................................................................34 Rated System Frequency PRIMVAL ....................................................................35 Signal Matrix For Analog Inputs SMAI .................................................................35 General settings of Distance protection zones .....................................................37 Distance Protection Zone, Quadrilateral Characteristic (Zone 1) ZMQPDIS.........39 Distance Protection Zone, Quadrilateral Characteristic (Zone 2) ZMQAPDIS .....44 Distance Protection Zone, Quadrilateral Characteristic (Zone 3) ZMQAPDIS ......47 Distance Protection Zone, Quadrilateral Characteristic (Zone 5) ZMQAPDIS ......50 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 2
Model setting calculation document for Transmission Line
Analog Inputs.......................................................................................................93 3.2.1 3.2.2 Local Human-Machine Interface ..........................................................................95 3.2.3 Indication LEDs....................................................................................................96 3.2.4 Time Synchronization ..........................................................................................97 3.2.5 Parameter Setting Groups ................................................................................. 101 3.2.6 Test Mode Functionality TEST........................................................................... 102 3.2.7 IED Identifiers .................................................................................................... 103 3.2.8 Rated System Frequency PRIMVAL .................................................................. 103 3.2.9 Signal Matrix For Analog Inputs SMAI ............................................................... 103 3.2.10 Synchrocheck function (SYN1) .......................................................................... 106 3.2.11 Autorecloser SMBRREC.................................................................................... 110 3.2.12 Disturbance Report DRPRDRE ......................................................................... 118 APPENDIX-A: COORDINATION OF 400KV LINE PROTECTION ZONE-2 AND ZONE-3 WITH IDMT O/C & E/F RELAYS OF 400KV SIDE OF ICT AND 220KV LINE................................... 121 APPENDIX-B: EFFECT OF NETWORK CHANGE DUE TO A LINE LILO ON RELAY SETTINGS OF LILO LINE & ADJACENT LINES .................................................................... 131
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Model setting calculation document for Transmission Line
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-tophase 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
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Model setting calculation document for Transmission Line
LIST OF TABLES Table 2-1: List of functions in REL670 .......................................................................................................... 10 Table 2-2: List of functions in REC670.......................................................................................................... 16 Table 3-1: Analog inputs................................................................................................................................. 24 Table 3-2: Local human machine interface ....................................................................................................... 26 Table 3-3: LEDGEN Non group settings (basic) ............................................................................................... 27 Table 3-4: Time synchronization settings.......................................................................................................... 29 Table 3-5: Parameter setting group................................................................................................................... 32 Table 3-6: Test mode functionality .................................................................................................................... 34 Table 3-7: IED Identifiers................................................................................................................................... 34 Table 3-8: Rated system frequency .................................................................................................................. 35 Table 3-9: Signal Matrix For Analog Inputs ....................................................................................................... 36 Table 3-10: General settings for distance protection ........................................................................................ 38 Table 3-11: ZONE 1 Settings ............................................................................................................................ 43 Table 3-12: ZONE 2 Settings ............................................................................................................................ 46 Table 3-13: ZONE 3 Settings........................................................................................................................... 49 Table 3-14: ZONE 5 Settings........................................................................................................................... 52 Table 3-15: Phase Selection with Load Encroachment, Quadrilateral Characteristic ...................................... 61 Table 3-16: Broken Conductor Check ............................................................................................................... 63 Table 3-17: Tripping Logic................................................................................................................................. 64 Table 3-18: Trip Matrix Logic............................................................................................................................. 65 Table 3-19: Automatic Switch Onto Fault Logic ................................................................................................ 67 Table 3-20: Power Swing Detection ............................................................................................................... 73 Table 3-21: Scheme Communication Logic For Distance Or Overcurrent Protection ...................................... 77 Table 3-22: Stub Protection............................................................................................................................... 78 Table 3-23: Fuse Failure Supervision ............................................................................................................... 79 Table 3-24: Four Step Residual Overcurrent Protection ................................................................................... 83 Table 3-25: Two Step Overvoltage Protection .................................................................................................. 86 Table 3-26: Setting of fault locator values ......................................................................................................... 89 Table 3-27: Disturbance Report ........................................................................................................................ 92 Table 3-28: Analog Inputs ................................................................................................................................. 93 Table 3-29: Local human machine interface ..................................................................................................... 96 Table 3-30: LEDGEN Non group settings (basic) ............................................................................................. 96 Table 3-31: Time Synchronization..................................................................................................................... 99 Table 3-32: Parameter Setting Groups ........................................................................................................... 102 Table 3-33: Test Mode Functionality ............................................................................................................... 102 Table 3-34: IED Identifiers............................................................................................................................... 103 Table 3-35: Rated System Frequency............................................................................................................. 103 Table 3-36: Signal Matrix For Analog Inputs ................................................................................................... 105 Table 3-37: Synchrocheck function ................................................................................................................. 108 Table 3-38: Autorecloser ................................................................................................................................. 116 Table 3-39: Disturbance Report ...................................................................................................................... 119 Table A-1 Settings of Over current and Earth fault relays............................................................................... 122 Table B-1: Fault At Station-B With Source At Station – A and Line A-S Earthed ........................................... 134 Table B-2: Fault At Station-B With Sources At Station – A & B and Line A-S Earthed .......................... 135 Table B-3: Fault At Station-B With Sources At Station – A, B & S and Line A-S Earthed .............................. 136 Table B-4: Fault At Station-B With Source At Station – A and Line B-S Earthed ................................... 137 Table B-5: Fault At Station-B With Source At Station – A & B and Line B-S Earthed .................................... 138 Table B-6: Fault At Station-S With Source At Station – A and Line A-B Earthed ........................................... 140 Table B-7: Fault At Station-S With Sources At Station – A & B and Line A-B Earthed .......................... 141 Table B-8: Fault At Station-S With Sources At Station – A, B & S and Line A-B Earthed ..................... 142 Table B-9: Fault At Station-B With Source At Station A............................................................................ 143 Table B-10: Fault At Station-B With Sources At Station – A & B .................................................................... 144 Table B-11: Fault At Station-B With Sources At Station – A, B and S ............................................................ 145 Table B-12: Fault At Station-S Without Sources At Station – S & B ............................................................... 146
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Model setting calculation document for Transmission Line
Table B-13: Fault At Station-S With Sources At Station – A & B .................................................................... 147 Table B-14: Fault At Station-S With Sources At Station – A, B & S................................................................ 148
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Model setting calculation document for Transmission Line
SETTING CALCULATION EXAMPLE
SUB-STATION: Station-A FEEDER: 400kV OHL from Station-A to Station-B PROTECTION ELEMENT: Main-I Protection Protection schematic Drg. Ref. No. XXXXXX
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Model setting calculation document for Transmission Line
1.0 BASIC SYSTEM PARAMETERS 1.1 Network line diagram of the protected line and adjacent circuits The network line diagram (Figure 1-1) of the system under consideration showing protected line along with adjacent associated elements should be collected. The network diagram should indicate the voltage level, line length, transformer/generator rated MVA & fault contributions of each element for 3-ph fault at station-A and for 3-ph fault at Station-B.
Figure 1-1: Network line diagram of the protected line
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Model setting calculation document for Transmission Line
1.2 Single line diagram of the double circuit line Equivalent representation of the protected line based on network line diagram indicated at Figure 11 is prepared as shown in Figure 1-2 indicating the source fault impedance at station-A and StationB, positive and zero sequence impedance of the protected line.
R1SA= 0.486Ω X1SA= 13.939Ω
400kV
Z1 = 5.472+j58.33 Ω Z0 = 51.091+j203.68 Ω
400kV
Protected Line 190km
R1SB= 0.895Ω X1SB=9.525Ω
190km Station-A
Station-B
Figure 1-2: Equivalent representation of the protected line with source impedance
1.3 Line parameters Line:
Substation-A to Substation-B
Frequency:
50Hz
Line data:
R1 + jX1 = 0.0288 + j0.307 Ω/km R0 + jX0 = 0.2689 + j1.072 Ω/km R0M + jX0M = 0.228 + j0.662 Ω/km
Line length:
190km
CT ratio:
1000/1A
CVT ratio:
400/0.11kV
Maximum expected load on line both import and export: This shall be obtained from the load flow analysis of the power system under all possible contingency. From the load flow studies, 1500MVA is the maximum expected load under worst contingency on this line at 90% system voltage.
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Model setting calculation document for Transmission Line
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
10
Model setting calculation document for Transmission Line
Sl.No.
Function/features available In REL670
Function/feature 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
20
21
22
23
Distance Protection Zone, Quadrilateral Characteristic (Zone 1) ZMQPDIS Distance Protection Zone, Quadrilateral Characteristic (Zone 2) ZMQAPDIS Distance Protection Zone, Quadrilateral Characteristic (Zone 3) ZMQAPDIS Distance Protection Zone, Quadrilateral Characteristic (Zone 4) ZMQAPDIS Distance Protection Zone, Quadrilateral Characteristic (Zone 5) ZMQAPDIS
Recommended Settings provided
YES
YES
YES
NO
YES
24
Directional Impedance Quadrilateral ZDRDIR
YES
25
Phase Selection With Load Encroachment, Quadrilateral Characteristic FDPSPDIS
YES
26
Power Swing Detection ZMRPSB
YES
11
Model setting calculation document for Transmission Line
Sl.No.
Function/features available In REL670
Function/feature activated Yes/No
Recommended Settings provided
27
Automatic Switch Onto Fault Logic, Voltage And Current Based ZCVPSOF
YES
28
Instantaneous Phase Overcurrent Protection PHPIOC
NO
29
Four Step Phase Overcurrent Protection OC4PTOC
NO
30
Instantaneous Residual Overcurrent Protection EFPIOC
NO
31
Four Step Residual Overcurrent Protection EF4PTOC
YES
32
Sensitive Directional Residual Overcurrent And Power Protection SDEPSDE
NO
33
Thermal Overload Protection, One Time Constant LPTTR
NO
34
Stub Protection STBPTOC
YES
35
Broken Conductor Check BRCPTOC
YES
36
Two Step Undervoltage Protection UV2PTUV
YES
37
Two Step Overvoltage Protection OV2PTOV
YES
38
Loss Of Voltage Check LOVPTUV
NO
39
General Current And Voltage Protection CVGAPC-4 functions
NO
40
Current Circuit Supervision CCSRDIF
NO
41
Fuse Failure Supervision SDDRFUF
YES
42
Horizontal Communication Via GOOSE For Interlocking GOOSEINTLKRCV
NO
43
Logic Rotating Switch For Function Selection And LHMI Presentation SLGGIO
NO
44
Selector Mini Switch VSGGIO
NO 12
Model setting calculation document for Transmission Line
Sl.No.
Function/features available In REL670
Function/feature 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
13
Recommended Settings provided
Model setting calculation document for Transmission Line
Sl.No.
Function/features available In REL670
Function/feature activated Yes/No
Recommended Settings provided
63
Tripping Logic SMPPTRC
YES
64
Trip Matrix Logic TMAGGIO
YES
65
Configurable Logic Blocks
NO
66
Fixed Signal Function Block FXDSIGN
NO
67
Boolean 16 To Integer Conversion B16I
NO
68
Boolean 16 To Integer Conversion With Logic Node
NO
Representation B16IFCVI 69
Integer To Boolean 16 Conversion IB16
NO
70
Integer To Boolean 16 Conversion With Logic Node
NO
Representation IB16FCVB 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
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Model setting calculation document for Transmission Line
Sl.No.
Function/features available In REL670
Function/feature 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
96
IEC 60870-5-103 Communication Protocol
NO
97
Multiple Command And Transmit MULTICMDRCV,
NO
Recommended Settings provided
MULTICMDSND 98
Remote Communication
NO
Note: For setting parameters provided in the function listed above, refer section 3 of application manual 1MRK506315-UEN, version 1.2.
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Model setting calculation document for Transmission Line
2.2 REC670 2.2.1 Terminal identification Station Name:
Station-A
Object Name:
400kV OHL
Unit Name:
REC670 (Ver 1.2)
Relay serial No:
XXXXX
Frequency:
50Hz
Aux voltage:
220V DC
2.2.2 List of functions available and those used Table 2-2 gives the list of functions/features available in REC670 relay and also indicates the functions/feature for which settings are provided in this document. The functions/feature are indicative and varies with IED ordering code & IED application configuration.
Table 2-2: List of functions in REC670
Sl.No.
Functions/Feature available In REC670
Features/Functions activated Yes/No
Recommended Settings provided
1
Analog Inputs
YES
2
Local Human-Machine Interface
YES
3
Indication LEDs
YES
4
Self supervision with internal event list
YES
5
Time Synchronization
YES
6
Parameter Setting Groups
YES
7
Test Mode Functionality TEST
YES
8
Change Lock CHNGLCK
NO
9
IED Identifiers
YES
10
Product Information
YES
11
Rated System Frequency PRIMVAL
YES
16
Model setting calculation document for Transmission Line
Sl.No.
Functions/Feature available In REC670
Features/Functions activated Yes/No
12
Signal Matrix For Binary Inputs SMBI
YES
13
Signal Matrix For Binary Outputs SMBO
YES
14
Signal Matrix For Ma Inputs SMMI
NO
15
Signal Matrix For Analog Inputs SMAI
YES
16
Summation Block 3 Phase 3PHSUM
NO
17
Authority Status ATHSTAT
NO
18
Denial Of Service DOS
NO
19
Differential Protection HZPDIF
NO
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
17
Recommended Settings provided
Model setting calculation document for Transmission Line
Sl.No.
Functions/Feature available In REC670
Features/Functions activated Yes/No
Recommended Settings provided
31
Directional Underpower Protection GUPPDUP
NO
32
Directional Overpower Protection GOPPDOP
NO
33
Broken Conductor Check BRCPTOC
NO
34
Capacitor bank protection CBPGAPC
NO
35
Two Step Undervoltage Protection UV2PTUV
NO
36
Two Step Overvoltage Protection OV2PTOV
NO
37
Two Step Residual Overvoltage Protection ROV2PTOV
NO
38
Voltage Differential Protection VDCPTOV
NO
39
Loss Of Voltage Check LOVPTUV
NO
40
Underfrequency Protection SAPTUF
NO
41
Overfrequency Protection SAPTOF
NO
42
Rate-Of-Change Frequency Protection SAPFRC
NO
43
General Current and Voltage Protection CVGAPC
NO
44
Current Circuit Supervision CCSRDIF
NO
45
Fuse Failure Supervision SDDRFUF
NO
46
Synchrocheck, Energizing Check, And Synchronizing SESRSYN
YES
47
Autorecloser SMBRREC
YES
48
Apparatus Control APC
NO
49
Horizontal Communication Via GOOSE For Interlocking GOOSEINTLKRCV
NO
18
Model setting calculation document for Transmission Line
Sl.No.
Functions/Feature available In REC670
Features/Functions activated Yes/No
50
Logic Rotating Switch For Function Selection And LHMI Presentation SLGGIO
NO
51
Selector Mini Switch VSGGIO
NO
52
Generic Double Point Function Block DPGGIO
NO
53
Single Point Generic Control 8 Signals SPC8GGIO
NO
54
Automationbits, Command Function For DNP3.0 AUTOBITS
NO
55
Single Command, 16 Signals SINGLECMD
NO
56
Scheme Communication Logic For Distance Or Overcurrent Protection ZCPSCH
NO
57
Phase Segregated Scheme Communication Logic For Distance Protection ZC1PPSCH
NO
58
Current Reversal And Weak-End Infeed Logic For Distance Protection ZCRWPSCH
NO
59
Local Acceleration Logic ZCLCPLAL
NO
60
Scheme Communication Logic For Residual Overcurrent Protection ECPSCH
NO
61
Current Reversal And Weak-End Infeed Logic For Residual Overcurrent Protection ECRWPSCH
NO
62
Current Reversal And Weak-End Infeed Logic For Phase Segregated Communication ZC1WPSCH
NO
63
Direct Transfer Trip Logic
NO
64
Low Active Power And Power Factor Protection LAPPGAPC
NO
65
Compensated Over And Undervoltage Protection COUVGAPC
NO
19
Recommended Settings provided
Model setting calculation document for Transmission Line
Sl.No.
Functions/Feature available In REC670
Features/Functions activated Yes/No
66
Sudden Change In Current Variation SCCVPTOC
NO
67
Carrier Receive Logic LCCRPTRC
NO
68
Negative Sequence Overvoltage Protection LCNSPTOV
NO
69
Zero Sequence Overvoltage Protection LCZSPTOV
NO
70
Negative Sequence Overcurrent Protection LCNSPTOC
NO
71
Zero Sequence Overcurrent Protection LCZSPTOC
NO
72
Three Phase Overcurrent LCP3PTOC
NO
73
Three Phase Undercurrent LCP3PTUC
NO
74
Tripping Logic SMPPTRC
NO
75
Trip Matrix Logic TMAGGIO
NO
76
Configurable Logic Blocks
NO
77
Fixed Signal Function Block FXDSIGN
NO
78
Boolean 16 To Integer Conversion B16I
NO
79
Boolean 16 To Integer Conversion With Logic Node
NO
Representation B16IFCVI 80
Integer To Boolean 16 Conversion IB16
NO
81
Integer To Boolean 16 Conversion With Logic Node
NO
Representation IB16FCVB 82
Measurements CVMMXN
YES
83
Phase Current Measurement CMMXU
YES
20
Recommended Settings provided
Model setting calculation document for Transmission Line
Sl.No.
Functions/Feature available In REC670
Features/Functions activated Yes/No
84
Phase-Phase Voltage Measurement VMMXU
YES
85
Current Sequence Component Measurement CMSQI
YES
86
Voltage Sequence Measurement VMSQI
YES
87
Phase-Neutral Voltage Measurement VNMMXU
NO
88
Event Counter CNTGGIO
YES
89
Event Function EVENT
YES
90
Logical Signal Status Report BINSTATREP
NO
91
Fault Locator LMBRFLO
NO
92
Measured Value Expander Block RANGE_XP
NO
93
Disturbance Report DRPRDRE
YES
94
Event List
YES
95
Indications
YES
96
Event Recorder
YES
97
Trip Value Recorder
YES
98
Disturbance Recorder
YES
99
Pulse-Counter Logic PCGGIO
NO
100
Function For Energy Calculation And Demand Handling ETPMMTR
NO
101
IEC 61850-8-1 Communication Protocol
NO
102
IEC 61850 Generic Communication I/O Functions SPGGIO, SP16GGIO
NO
103
IEC 61850-8-1 Redundant Station Bus Communication
NO
21
Recommended Settings provided
Model setting calculation document for Transmission Line
Sl.No.
Functions/Feature available In REC670
Features/Functions activated Yes/No
104
IEC 61850-9-2LE Communication Protocol
NO
105
LON Communication Protocol
NO
106
SPA Communication Protocol
NO
107
IEC 60870-5-103 Communication Protocol
NO
108
Multiple Command And Transmit MULTICMDRCV,
NO
Recommended Settings provided
MULTICMDSND 109
Remote Communication
NO
Note: For setting parameters provided in the function listed above, refer section 3 of application manual 1MRK511230-UEN, version 1.2.
22
Model setting calculation document for Transmission Line
3.0 SETTING
CALCULATIONS
AND
RECOMMENDED
SETTINGS FOR REL670 The various functions required for the line protection are divided in two IEDs namely REL670 and REC670. The setting calculations and recommended settings for various functions available in these IEDs are given in this section.
3.1 REL670 3.1.1 Analog Inputs Guidelines for Settings: Configure analog inputs: Current analog inputs as: Ch 1
Ch 2
Ch 3
Ch 4
Ch 5
Ch 6
Name#
IL1-CB1
IL2-CB1
IL3-CB1
IL1-CB2
IL2-CB2
IL3-CB2
CTprim
1000A
1000A
1000A
1000A
1000A
1000A
CTsec
1A
1A
1A
1A
1A
1A
CTStarPoint parameter indicates the CT secondary winding neutral earthing towards object (ToObject) or towards busbar (FromObject).
Voltage analog input as: Ch 1
Ch 2
Ch 3
Ch 4
Ch 5
Ch 6
Name#
UL1
UL2
UL3
UL2BUS1
UL2BUS2
UL2L2
VTprim
400kV
400kV
400kV
400kV
400kV
400kV
VTsec
110V
110V
110V
110V
110V
110V
# User defined text
23
Model setting calculation document for Transmission Line
Recommended Settings: Table 3-1 gives the recommended settings for the analog inputs. Table 3-1: Analog inputs Setting Parameter PhaseAngleRef
CTStarPoint1
Recommended
Description
Settings
Reference channel for phase angle Presentation ToObject= towards protected object, FromObject= the opposite
Unit
TRM40-Ch1
-
ToObject
-
CTsec1
Rated CT secondary current
1
A
CTprim1
Rated CT primary current
1000
A
ToObject
-
CTStarPoint2
ToObject= towards protected object, FromObject= the opposite
CTsec2
Rated CT secondary current
1
A
CTprim2
Rated CT primary current
1000
A
ToObject
-
CTStarPoint3
ToObject= towards protected object, FromObject= the opposite
CTsec3
Rated CT secondary current
1
A
CTprim3
Rated CT primary current
1000
A
ToObject
-
CTStarPoint4
ToObject= towards protected object, FromObject= the opposite
CTsec4
Rated CT secondary current
1
A
CTprim4
Rated CT primary current
1000
A
ToObject
-
CTStarPoint5
ToObject= towards protected object, FromObject= the opposite
CTsec5
Rated CT secondary current
1
A
CTprim5
Rated CT primary current
1000
A
CTStarPoint6
ToObject= towards protected object,
ToObject
24
-
Model setting calculation document for Transmission Line
Setting Parameter
Recommended
Description
Settings
Unit
FromObject= the opposite CTsec6
Rated CT secondary current
1
A
CTprim6
Rated CT primary current
1000
A
VTsec7
Rated VT secondary voltage
110
V
VTprim7
Rated VT primary voltage
400
kV
VTsec8
Rated VT secondary voltage
110
V
VTprim8
Rated VT primary voltage
400
kV
VTsec9
Rated VT secondary voltage
110
V
VTprim9
Rated VT primary voltage
400
kV
VTsec10
Rated VT secondary voltage
110
V
VTprim10
Rated VT primary voltage
400
kV
VTsec11
Rated VT secondary voltage
110
V
VTprim11
Rated VT primary voltage
400
kV
VTsec12
Rated VT secondary voltage
110
V
VTprim12
Rated VT primary voltage
400
kV
Binary input module (BIM) Settings
I/O Module 1 I/O Module 2 I/O Module 3 I/O Module 4 I/O Module 5
Operation On On On On On
OscBlock(Hz) 40 40 40 40
OscRelease(Hz) 30 30 30 30
Pos Slot3 Pos Slot3 Pos Slot3 Pos Slot3
40
30
Pos Slot3
Note: OscBlock and OscRelease defines the filtering time at activation. Low frequency gives slow response for digital input.
25
Model setting calculation document for Transmission Line
3.1.2 Local Human-Machine Interface Recommended Settings: Table 3-2 gives the recommended settings for Local human machine interface. Table 3-2: Local human machine interface Setting Parameter
Description
Language
Recommended Settings
Unit
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.
26
Model setting calculation document for Transmission Line
Recommended Settings: Table 3-3 gives the recommended settings for Indication LEDs. Table 3-3: LEDGEN Non group settings (basic) Setting Parameter
Recommended
Description
Settings
Unit
Operation
Operation mode for the LED function
On
-
tRestart
Defines the disturbance length
0.0
s
0.0
s
tMax
Maximum time for the definition of a disturbance
SeqTypeLED1
Sequence type for LED 1
LatchedAck-S-F
-
SeqTypeLED2
Sequence type for LED 2
LatchedAck-S-F
-
SeqTypeLED3
Sequence type for LED 3
LatchedAck-S-F
-
SeqTypeLED4
Sequence type for LED 4
LatchedAck-S-F
-
SeqTypeLED5
Sequence type for LED 5
LatchedAck-S-F
-
SeqTypeLED6
Sequence type for LED 6
LatchedAck-S-F
-
SeqTypeLED7
Sequence type for LED 7
LatchedAck-S-F
-
SeqTypeLED8
Sequence type for LED 8
LatchedAck-S-F
-
SeqTypeLED9
Sequence type for LED 9
LatchedAck-S-F
-
SeqTypeLED10
Sequence type for LED 10
LatchedAck-S-F
-
SeqTypeLED11
Sequence type for LED 11
LatchedAck-S-F
-
SeqTypeLED12
Sequence type for LED 12
LatchedAck-S-F
-
SeqTypeLED13
Sequence type for LED 13
LatchedAck-S-F
-
SeqTypeLED14
Sequence type for LED 14
LatchedAck-S-F
-
SeqTypeLED15
Sequence type for LED 15
LatchedAck-S-F
-
27
Model setting calculation document for Transmission Line
3.1.4 Time Synchronization Guidelines for Settings: These settings are used for synchronizing IED clock time with network time. Ex: GPS or IRIG-B time. CoarseSyncSrc: Select the time synchronization source available such as SPA, LON, SNTP etc. Synchronization messages from sources configured as coarse are checked against the internal relay time and only if the difference in relay time and source time is more than 10s then relay time will be reset with the source time. This parameter need to be based on time source available in site. FineSyncSource: Select the time source available in network like IRIG-B, GPS, SNTP, SPA etc. once it is selected, time of available time source in network will update to relay if there is a difference in the time between relay and source. This parameter need to be based on time source available in site. SyncMaster: Normally it is set OFF. If time to the relay is received from a GPS antenna (example), make the relay as master to synchronize with other relays. TimeAdjustRate: Fast HWSyncSrc: This is applicable if process bus IEC61850-9-2 protocol is used for receiving analog values (optical CT PTs). In this case select time source available same as that of merging unit. This setting is not applicable in present case. AppSynch: If there is any loss of time sync, protection function will be blocked if AppSynch set to Synch based on SyncAccLevel. If AppSunch set to NoSynch, protection functions are not blocked. Recommended setting is NoSynch. SyncAccLevel: If this is set to “Class T5 (1us)” and time synch error is more than 1us, protection functions will be blocked. SyncAccLevel should be set to “Unspecified” when Nosynch is selected at AppSynch. This parameter is not applicable in present case. ModulePosition: if BIN is set for FineSyncSource, ModulePosition setting is applicable. Here slot position of IO module in the relay is to be set (Which slot is used for BI). This parameter is not applicable in present case. BinaryInput: Which binary input is used for time sync input shall be set here. This parameter is applicable if BIN is set for FineSyncSource. This parameter is not applicable in present case. BinDetection: Which edge of input pulse need to be detected has to be set here (positive and negative). This parameter is applicable if BIN is set for FineSyncSource. This parameter is not applicable in present case. ServerIP-Add: Here set Time source server IP address. RedServIP-Add: If redundant server is available, set address of redundant server here. 28
Model setting calculation document for Transmission Line
MonthInYear, DayInWeek, WeekInMonth and UTCTimeOfDay for DSTBEGIN and DSTEND are applicable where Day light saving is used. If it is not used set same date for both DSTBEGIN and DSTEND. This setting is not applicable in this case. NoHalfHourUTC: Time shift from GMT has to be set a multiple of half hours. Example for India it is +05:30, means +11. Hence this parameter is set to +11 in present case. SYNCHIRIG-B Non group settings: These settings are applicable if IRIG-B is used. This parameter is not applicable in present case. SynchType: Type of hardware input used for time sync, whether Opto or BNC. This parameter is not applicable in present case. TimeDomain: In present case this parameter is set to LocalTime. Encoding: In present case this parameter is set to IRIG-B. TimeZoneAs1344: In present case this parameter is set to PlusTZ.
Recommended Settings: Table 3-4 gives the recommended settings for Time synchonization. Table 3-4: Time synchronization settings TIMESYNCHGEN Non group settings (basic) Setting Parameter
Recommended
Description
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
-
29
Model setting calculation document for Transmission Line
SYNCHBIN Non group settings (basic) Setting Parameter ModulePosition
BinaryInput BinDetection
Recommended
Description Hardware position of IO module for time Synchronization Binary input number for time synchronization Positive or negative edge detection
Settings
Unit
3
-
1
-
PositiveEdge
-
SYNCHSNTP Non group settings (basic) Setting Parameter
Description
ServerIP-Add RedServIP-Add
Recommended Settings
Unit
Server IP-address
0.0.0.0
IP Address
Redundant server IP-address
0.0.0.0
IP Address
DSTBEGIN Non group settings (basic) Setting Parameter
Description
MonthInYear
Recommended Settings
Unit
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
-
3600
s
UTCTimeOfDay
UTC Time of day in seconds when daylight time starts
30
Model setting calculation document for Transmission Line
DSTEND Non group settings (basic) Setting Parameter
Recommended
Description
Settings
Unit
MonthInYear
Month in year when daylight time starts
October
-
DayInWeek
Day in week when daylight time starts
Sunday
-
WeekInMonth
Week in month when daylight time starts
Last
-
3600
s
UTCTimeOfDay
UTC Time of day in seconds when daylight time starts
TIMEZONE Non group settings (basic) Recommended
Setting Parameter
Description
NoHalfHourUTC
Number of half-hours from UTC
Settings
Unit
+11
-
SYNCHIRIG-B Non group settings (basic) Setting Parameter
Recommended
Description
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 Guidelines for Settings:
31
Model setting calculation document for Transmission Line
t: The length of the pulse, sent out by the output signal SETCHGD when an active group has changed, is set with the parameter t. This is not the delay for changing setting group. This parameter is normally recommended to set 1s. MAXSETGR: The parameter MAXSETGR defines the maximum number of setting groups in use to switch between. Only the selected number of setting groups will be available in the Parameter Setting tool (PST) for activation with the ActiveGroup function block. This parameter is normally recommended to set 1.
Recommended Settings: Table 3-5 gives the recommended settings for Parameter setting group. Table 3-5: Parameter setting group ActiveGroup Non group settings (basic) Setting Parameter t
Description Pulse length of pulse when setting Changed
Recommended Settings
Unit
1
s
SETGRPS Non group settings (basic) Setting Parameter
Description
ActiveSetGrp MAXSETGR
Recommended Settings
Unit
ActiveSettingGroup
SettingGroup1
-
Max number of setting groups 1-6
1
No
3.1.6 Test Mode Functionality TEST Guidelines for Settings: EventDisable: If it is ON, it will disable the events like in DR during test mode. Normally this parameter is set to OFF. CmdTestBit: In present case this parameter is set to Off.
Recommended Settings: 32
Model setting calculation document for Transmission Line
Table 3-6 gives the recommended settings for Test mode functionality.
33
Model setting calculation document for Transmission Line
Table 3-6: Test mode functionality TESTMODE Non group settings (basic) Setting Parameter
Description
TestMode EventDisable CmdTestBit
Recommended Settings
Unit
Test mode in operation (On) or not (Off)
Off
-
Event disable during testmode
Off
-
Off
-
Command bit for test required or not during testmode
3.1.7 IED Identifiers Recommended Settings: Table 3-7 gives the recommended settings for IED Identifiers. Table 3-7: IED Identifiers TERMINALID Non group settings (basic) Setting Parameter
Recommended Description 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
-
34
Model setting calculation document for Transmission Line
3.1.8 Rated System Frequency PRIMVAL Recommended Settings: Table 3-8 gives the recommended settings for Rated system frequency.
Table 3-8: Rated system frequency PRIMVAL Non group settings (basic) Setting Parameter
Description
Frequency
Rated system frequency
Recommended Settings
Unit
50.0
Hz
3.1.9 Signal Matrix For Analog Inputs SMAI Guidelines for Settings: DFTReference: Set ref for DFT filter adjustment here. These DFT reference block settings decide DFT reference for DFT calculations. The settings InternalDFTRef will use fixed DFT reference based on set system frequency. AdDFTRefChn will use DFT reference from the selected group block, when own group selected adaptive DFT reference will be used based on calculated signal frequency from own group. The setting ExternalDFTRef will use reference based on what is connected to input DFTSPFC. There are three different task groups of SMAI with 1ms, 3ms and 8ms. Use of each task group is based on requirement of function, like differential protection requires 1ms, which is faster. Each task group has 12 instances of SMAI, in that first instance has some additional features which is called master. Others are slaves and they will follow master. If measured sample rate needs to be transferred to other task group, it can be done only with master. Receiving task group SMAI DFTreference shall be set to External DFT Ref. DFTReference shall be set to default value InternalDFTRef if no VT input is available. Since VT input is available in this case, the corresponding channel shall be set to DFTReference. Configuration file has to be referred for this purpose. DFTRefExtOut: This parameter is available only in Master. If reference is to be sent to other task group, which reference need to be send has to be select here. For example, if voltage input is
35
Model setting calculation document for Transmission Line
connected to 3rd SMAI of 1ms task group, AdDFTRefCh3 is to be set in DFTRefExtOut of 1ms task group. DFTRefExtOut shall be set to default value InternalDFTRef if no VT input is available. Configuration file has to be referred for this purpose. Negation: Set negation of the function block here. If R, Y, B and N inputs are connected and Negation is set to NegateN, it will give output R, Y, B and –N. If Negation is set to Negate3Ph, it will give output -R, -Y, -B and N. If R, Y, B inputs are connected, N=R+Y+B, and it will do as above. This parameter is recommended to be set to OFF normally. MinValFreqMeas: Set the measured minimum value here. It is applicable only for voltage input. SMAI will work only if measured input magnitude is greater than set value in MinValFreqMeas. This parameter is recommended to set 10% normally. UBase: Set the base voltage here. This is parameter is set to 400kV.
Recommended Settings: Table 3-9 gives the recommended settings for Signal Matrix For Analog Inputs.
Table 3-9: Signal Matrix For Analog Inputs Setting Parameter
Description
DFTRefExtOut
Recommended Settings
Unit
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
-
10
%
400
kV
MinValFreqMeas UBase
Limit for frequency calculation in % of UBase Base voltage
36
Model setting calculation document for Transmission Line
3.1.10 General settings of Distance protection zones Guidelines for Settings: Figure 3-1 gives the setting angles for discrimination of forward and reverse fault. ArgDir and ArgNegRes: Set the Directional angle Distance protection zones at ArgDir and set the Negative restraint angle for Distance protection zone at ArgNegRes. The setting of ArgDir and ArgNegRes is by default set to 15 (= -15) and 115° respectively. It should not be changed unless system studies have shown the necessity. IBase: set to the current value of the primary winding of the CT. This parameter is set to 1000A in present case. UBase: set to the voltage value of the primary winding of the VT. This parameter is set to 400kV in present case. IMinOpPP: This is the minimum current required in phase to phase fault for directionality purpose. To be set to 20% of IBase. IMinOpPE: This is the minimum current required in phase to earth fault for directionality purpose. To be set to 20% of IBase.
Figure 3-1: Setting angles for discrimination of forward and reverse fault 37
Model setting calculation document for Transmission Line
Recommended Settings: Table 3-10 gives the recommended settings for General settings for distance protection. Table 3-10: General settings for distance protection ZDRDIR Group settings (basic) Recommended
Setting Parameter
Description
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
20
%IB
115
Deg
15
Deg
IMinOpPE
ArgNegRes
ArgDir
Settings
Minimum operate phase current for Phase-Earth loops Angle of blinder in second quadrant for forward direction Angle of blinder in fourth quadrant for forward direction
38
Unit
Model setting calculation document for Transmission Line
3.1.11 Distance
Protection
Zone,
Quadrilateral
Characteristic
(Zone
ZMQPDIS General guide lines for Setting Distance protection Zones: The zones are set directly in primary ohms R, X. The primary ohms R, X are recalculated to secondary ohms with the current and voltage transformer ratios. Figures 3-2 and 3-3 show the characteristics for phase-to-earth measuring and phase-to-phase measuring respectively. The secondary values are presented as information for zone testing.
Figure 3-2: Characteristic for phase-to-earth measuring, ohm/loop domain
39
1)
Model setting calculation document for Transmission Line
Figure 3-3: Characteristic for phase-to-phase measuring
Guidelines for Setting: Zone-1: Setting X1, R1 and X0, R0: To be set to cover 80% of protected line length. Zero sequence compensation factor is (Z0 – Z1) / 3Z1. RFPP and RFPE: For phase to ground faults, resistive reach should be set to give maximum coverage considering fault resistance, arc resistance & tower footing resistance.
It has been
considered that ground fault would not be responsive to line loading. Setting of the resistive reach for the underreaching zone 1 should follow the condition to minimize the risk for overreaching: RFPE ≤ 4.5 × X1
40
Model setting calculation document for Transmission Line
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. To be set to 10% of IBase.
Setting Calculations: OperationDir = Forward Operation PP = On Operation PE = On Zone 1 phase fault reach is set to
80.0% of the total line reactance
X1Z1' = 46.664Ω
Note! Zone will send carrier signal
The secondary setting will thus be X1Z1 = 12.833Ω Set the positive sequence resistance for phase faults to (this gives the characteristic angle) R1Z1' = 4.378Ω The secondary setting will thus be R1Z1 = 1.204Ω Setting of zone earth fault zero sequence values X0Z1' = 162.944Ω
80.0% of the total line reactance 41
Model setting calculation document for Transmission Line
The secondary setting will thus be X0Z1 = 44.81Ω Set the zero sequence resistance for earth faults to R0Z1' = 40.873Ω The secondary setting will thus be 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) The secondary setting will thus be RFPPZ1 = 8.25Ω Set the resistive reach for earth faults to RFPEZ1´= 50Ω The secondary setting will thus be RFPEZ1 = 13.75Ω Set the Base current for the Distance protection zones in primary Ampere. Zone 1 setting of timers. Setting of Zone timer activation for phase-phase and earth faults tPP1 = On tPE1 = On Setting of Zone timers: tPP1 = 0s tPE1 = 0s 42
Model setting calculation document for Transmission Line
Recommended Settings: Table 3-11 gives the recommended settings for ZONE 1 Settings.
Table 3-11: ZONE 1 Settings Setting Parameter
Recommended Settings
Description
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, PhPh
On
-
tPP
Time delay of trip,Ph-Ph
0.000
s
Operation PE
Operation mode Off/On of Ph-E loops
On
-
Timer tPE
Operation mode Off/On of Zone timer, Ph-E
On
-
tPE
Time delay of trip,Ph-E
0.000
s
IMinOpPP
Minimum operate delta current for PhasePhase loops
20
%IB
IMinOpPE
Minimum operate phase current for PhaseEarth loops
20
%IB
43
Model setting calculation document for Transmission Line
IMinOpIN
Minimum operate residual current for Phase-Earth loops
3.1.12 Distance
Protection
Zone,
10
Quadrilateral
%IB
Characteristic
(Zone
2)
ZMQAPDIS Guidelines for Setting: Setting X1, R1 and X0, R0: To be set to cover minimum 120% of length of principle line section. However, in case of double circuit lines 150% coverage must be provided to take care of under reaching due to mutual coupling effect. Zero sequence compensation factor is (Z0 – Z1) / 3Z1. tPP and tPE settings: A Zone-2 timing of 0.35s (considering LBB time of 200mS, CB open time of 60ms, resetting time of 30ms and safety margin of 60ms) is set for the present case. RFPP and RFPE: Guidelines given for resistive reach under zone-1 is applicable here also. Due to in-feeds, the apparent fault resistance seen by relay is several times the actual value. This should be kept in mind while arriving at resistive reach setting for Zone-2. IBase: Set the Base current for the Distance protection zones in primary Ampere here. Set to the current value of the primary winding of the CT. This parameter is set to 1000A in present case. UBase: Set the Base voltage for the Distance protection zones in primary kV here. Set to the voltage value of the primary winding of the VT. This parameter is set to 400kV in present case. IMinOpPP: Setting of minimum sensitivity for zone Phase-Phase elements. Measures IL-IL for each loop. This is the minimum current required in phase to phase fault for zone measurement. To be set to 20% of IBase. IMinOpPE: Setting of minimum operating current for Phase faults. Measures ILx. This is the minimum current required in phase to earth fault for zone measurement. To be set to 20% of IBase.
44
Model setting calculation document for Transmission Line
Setting Calculations: OperationDir = Forward Operation PP = On Operation PE = On Zone 2 phase fault reach is set to 150.0% of the total line reactance X1Z2' = 87.495Ω
Zone is accelerated at receipt of Carrier signal.
The secondary setting will thus be X1Z2 = 24.061Ω Set the positive sequence resistance for phase faults to (this gives the characteristic angle) R1Z2' = 8.208Ω The secondary setting will thus be R1Z2 = 2.257Ω Setting of zone earth fault zero sequence values X0Z2' = 305.52Ω
150.0% of the total line reactance
The secondary setting will thus be X0Z2 = 84.018Ω Set the zero sequence resistance for earth faults to R0Z2' = 76.637Ω The secondary setting will thus be R0Z2 = 21.075Ω Setting of the fault resistive cover The resistive reach for phase to phase is set to cover a maximum expected fault resistance of 30.0Ω (Considering a factor of 2 on the Zone-1 resistive reach value to take care of in-feed effect) Set the resistive reach for phase faults to: RFPPZ2' = 60Ω The secondary setting will thus be RFPPZ2 =16.5Ω Set the resistive reach for earth faults to RFPEZ2´= 75Ω The secondary setting will thus be RFPPZ2 = 20.625Ω
45
Model setting calculation document for Transmission Line
Zone 2 timers setting Setting of Zone timer activation for phase-phase and earth faults tPP2 = On tPE2 = On Setting of Zone timers: tPP2 = 0.35s tPE2 = 0.35s Note: In this case, Zone-2 reach is not encroaching into 220kV side of the transformer due to infeeds and therefore zone-2 tripping delay need not be coordinated with HV side backup protection of Transformer as explained in Appendix-I.
Recommended Settings: Table 3-12 gives the recommended settings for ZONE 2 Settings. Table 3-12: ZONE 2 Settings Setting Parameter
Recommended
Description
Settings
Unit
On
-
Operation
Operation Off / On
IBase
Base current , i.e. rated current
1000
A
Ubase
Base voltage , i.e. rated voltage
400.00
kV
OperationDir
Operation mode of directionality
Forward
-
X1
Positive sequence reactance reach
87.495
ohm/p
R1
Positive sequence resistance reach
8.208
ohm/p
X0
Zero sequence reactance reach
305.52
ohm/p
R0
Zero sequence resistance for zone
76.637
ohm/p
RFPP
Fault resistance reach in ohm/loop , PhPh
60
ohm/l
RFPE
Fault resistance reach in ohm/loop , Ph-E
75
ohm/l
Operation PP
Operation mode Off/On of Ph-Ph loops
On
-
Timer tPP
Operation mode Off/On of Zone timer, Ph-Ph
On
-
46
Model setting calculation document for Transmission Line
Setting Parameter
Recommended
Description
Settings
Unit
0.35
s
tPP
Time delay of trip,Ph-Ph
Operation PE
Operation mode Off/On of Ph-E loops
On
-
Timer tPE
Operation mode Off/On of Zone timer, Ph-E
On
-
tPE
Time delay of trip,Ph-E
0.35
s
IMinOpPP
Minimum operate delta current for PhasePhase loops
20
%IB
IMinOpPE
Minimum operate phase current for Phase-Earth loops
20
%IB
3.1.13 Distance
Protection
Zone,
Quadrilateral
Characteristic
(Zone
3)
ZMQAPDIS Guidelines for Setting: 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. 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.
47
Model setting calculation document for Transmission Line
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.
Setting Calculations: OperationDir = Forward Operation PP = On Operation PE = On Setting of zone 3 Phase fault reach Zone 3 phase fault reach is set to 120% of sum of protected line and adjacent longest lines reactance is considered. Effect of in-feed not considered for practical reasons in the Zone-3 reach setting. X1Z3' = 199.304Ω The secondary setting will thus be X1Z3 = 54.809Ω Set the positive sequence resistance for phase faults to (this gives the characteristic angle) R1Z3' = 18.697Ω The secondary setting will thus be R1Z3 = 5.142Ω Setting of zone earth fault zero sequence values X0Z3' = 695.942Ω
120% of sum of protected line and adjacent longest lines
reactance is considered. The secondary setting will thus be X0Z3 = 191.384Ω Set the zero sequence resistance for earth faults to R0Z3' = 174.57Ω The secondary setting will thus be 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)
48
Model setting calculation document for Transmission Line
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) The secondary setting will thus be RFPPZ3 = 20.625Ω Set the resistive reach for earth faults to RFPEZ3´= 125Ω The secondary setting will thus be RFPEZ3 = 34.375Ω Zone 3 timers setting Setting of Zone timer activation for phase-phase and earth faults tPP3 = On tPE3 = On Setting of Zone timers: tPP3 = 1s tPE3 = 1s Note: In this case, Zone-3 reach is not encroaching into 220kV side of the transformer due to infeeds and therefore zone-3 tripping delay need not be coordinated with HV side backup protection of Transformer as explained in Appendix-I.
Recommended Settings: Table 3-13 gives the recommended settings for ZONE 3 Settings.
Table 3-13: ZONE 3 Settings Setting Parameter
Recommended
Description
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
199.304
ohm/p
R1
Positive sequence resistance reach
18.697
ohm/p
49
Model setting calculation document for Transmission Line
Setting Parameter
Recommended
Description
Settings
Unit
X0
Zero sequence reactance reach
695.942
ohm/p
R0
Zero sequence resistance for zone
174.57
ohm/p
RFPP
Fault resistance reach in ohm/loop , Ph-Ph
75
ohm/l
RFPE
Fault resistance reach in ohm/loop , Ph-E
125
ohm/l
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 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
20
%IB
20
%IB
Operation PP
Operation PE
IMinOpPP
IMinOpPE
Minimum operate delta current for PhasePhase loops Minimum operate phase current for Phase-Earth loops
3.1.14 Distance
Protection
Zone,
Quadrilateral
Characteristic
(Zone
5)
ZMQAPDIS Guidelines for Setting: 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.
50
Model setting calculation document for Transmission Line
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.
Setting Calculations: 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 The secondary setting will thus be X1Z5 = 1.689Ω Set the positive sequence resistance for phase faults to (this gives the characteristic angle) R1Z5' = 0.576Ω The secondary setting will thus be R1Z5 = 0.158Ω Setting of zone earth fault zero sequence values X0Z5' = 21.44Ω The secondary setting will thus be X0Z5 = 5.896Ω Set the zero sequence resistance for earth faults to R0Z5' = 5.378Ω The secondary setting will thus be R0Z5 = 1.479Ω Setting of the fault resistive cover Set the resistive reach for phase faults to: RFPPZ5' = 75Ω The secondary setting will thus be 51
Model setting calculation document for Transmission Line
RFPPZ5 = 20.625Ω Set the resistive reach for earth faults to RFPEZ5´= 125Ω The secondary setting will thus be RFPPZ5 = 34.375Ω Zone 5 (Reverse Zone) timers setting Setting of Zone timer activation for phase-phase and earth faults tPP5 = On tPE5 = On Setting of Zone timers: 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: Table 3-14 gives the recommended settings for ZONE 5 Settings.
Table 3-14: ZONE 5 Settings Setting Parameter
Description
Operation
Recommended Settings
Unit
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
Reverse
-
X1
Positive sequence reactance reach
6.14
ohm/p
R1
Positive sequence resistance reach
1.689
ohm/p
X0
Zero sequence reactance reach
21.44
ohm/p
R0
Zero sequence resistance for zone
5.378
ohm/p
RFPP
Fault resistance reach in ohm/loop , Ph-Ph
75
ohm/l
52
Model setting calculation document for Transmission Line
Setting Parameter
Description
RFPE
Recommended Settings
Unit
Fault resistance reach in ohm/loop , Ph-E
125
ohm/l
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
0.35
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
0.35
s
IMinOpPP
Minimum operate delta current for PhasePhase loops
20
%IB
IMinOpPE
Minimum operate phase current for PhaseEarth loops
20
%IB
53
Model setting calculation document for Transmission Line
3.1.15
Phase Selection with Load Encroachment, Quadrilateral Characteristic FDPSPDIS
Figures 3-4, 3-5 and 3-6 show the characteristics for Phase selector and load encroachment:
1-FDPSPDIS (red line), 2-ZMQPDIS, 3-RFRvPEPHS, 4-(X1PHS+XN)/tan(60°), 5-RFFwPEPHS, 6RFPEZm, 7-X1PHS+XN, 8-φloop, 9-X1ZM+XN Figure 3-4: Relation between distance protection ZMQPDIS and FDPSPDIS for phase-to-earth fault φloop>60°
54
Model setting calculation document for Transmission Line
1-FDPSPDIS (red line), 2-ZMQPDIS, 3-0.5 x RFRvPP PHS, 4- X1PHS/ tan (60°), 5-0.5 x RFFwPPPHS, 6-0.5 x RFPPZm, 7-X1PHS, 8-X1Zm
Figure 3-5: Relation between distance protection (ZMQPDIS) and FDPSPDIS characteristic for phase-to-phase fault for φline>60°
55
Model setting calculation document for Transmission Line
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
Guidelines for Setting: 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 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. 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. 56
Model setting calculation document for Transmission Line
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 57
Model setting calculation document for Transmission Line
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°. 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.
58
Model setting calculation document for Transmission Line
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.
Setting Calculations: Calculations for Load encroachment: Ur = 400kV, Umin = 0.90x400 = 360kV, CT ratio = 1000/1A and PT ratio = 400kV/110V Maximum load in MVA = 1500 ZLmin = 360 x 360/ (1500), = 86.4Ω 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. The secondary setting will thus be RLdFw' = 11.375Ω Set the load limitation in the reverse (import) direction RLdRv = 41.297Ω The secondary setting will thus be 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)
The secondary setting will thus be X1" = 34.648Ω Earth fault reach zero sequence component is set to 144.0% of Zone 2 zero sequence value 59
Model setting calculation document for Transmission Line
Zero sequence reactance as set for the reach of phase selectors in reactive direction at phase-toearth faults X0 = 439.95Ω The secondary setting will thus be 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
The secondary setting will thus be 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
The secondary setting will thus be 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
60
Model setting calculation document for Transmission Line
Recommended Settings: Table 3-15 gives the recommended settings for Phase Selection with Load Encroachment, Quadrilateral Characteristic.
Table 3-15: Phase Selection with Load Encroachment, Quadrilateral Characteristic Setting Parameter
Description
IBase
Recommended Settings
Unit
Base current , i.e rated current
1000
A
UBase
Base voltage , i.e rated voltage
400
kV
INBlockPP
3Io limit for blocking phase-to-phase measuring loops
40
%IPh
INReleasePE
3Io limit for releasing phase-to-earth measuring loops
20
%IPh
RLdFw
Forward resistive reach within the load impedance area
54.62
ohm/p
RLdRv
Reverse resistive reach within the load impedance area
54.62
ohm/p
ArgLd
Load angle determining the load impedance reach
30
Deg
X1
Positive sequence reactance reach
125.993
ohm/p
X0
Zero sequence reactance reach
439.95
ohm/p
RFFwPP
Fault resistance reach Ph-Ph, forward
75
ohm/l
RFRvPP
Fault resistance reach Ph-Ph, reverse
75
ohm/l
RFFwPE
Fault resistance reach Ph-E, forward
90
ohm/l
RFRvPE
Fault resistance reach Ph-E, reverse
90
ohm/l
IMinOpPP
Minimum operate delta current for PhasePhase loops
20
%IB
IMinOpPE
3Io limit for blocking phase-to-earth measuring loops
20
%IB
OperationZ<
Operation of impedance based
On
-
61
Model setting calculation document for Transmission Line
Setting Parameter
Recommended
Description
Settings
Unit
measurement OperationI>
Operation of current based measurement
On
-
IPh>
Start value for phase over-current element
120
%IB
IN>
Start value for trip from 3I0 over-current element
20
%IB
TimerPP
Operation mode Off / On of Zone timer, Ph-Ph
Off
-
tPP
Time delay to trip, Ph-Ph
3.000
s
TimerPE
Operation mode Off / On of Zone timer, Ph-E
Off
-
tPE
Time delay to trip, Ph-E
3.000
s
3.1.16 Broken Conductor Check BRCPTOC (Normally used for Alarm purpose only) Guidelines for Setting: 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%.
62
Model setting calculation document for Transmission Line
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.
Recommended Settings: Table 3-16 gives the recommended settings for Broken Conductor Check. Table 3-16: Broken Conductor Check Setting Parameter
Description
Operation
Recommended Settings
Unit
Operation Off / On
On
-
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 Guidelines for Setting: 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.
63
Model setting calculation document for Transmission Line
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.
Recommended Settings: Table 3-17 gives the recommended settings for Tripping Logic.
Table 3-17: Tripping Logic Setting Parameter
Description
Operation
Recommended Settings
Unit
Operation Off / On
On
-
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
-
64
Model setting calculation document for Transmission Line
3.1.18 Trip Matrix Logic TMAGGIO Guidelines for Setting: 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.
Recommended Settings: Table 3-18 gives the recommended settings for Trip Matrix Logic. Table 3-18: Trip Matrix Logic Setting Parameter
Recommended
Description
Settings
Unit
Operation
Operation Off / On
On
-
PulseTime
Output pulse time
0.0
s
OnDelay
Output on delay time
0.0
s
OffDelay
Output off delay time
0.0
s
ModeOutput1 Mode for output ,1 steady or pulsed
Steady
-
ModeOutput2 Mode for output 2, steady or pulsed
Steady
-
ModeOutput3 Mode for output 3, steady or pulsed
Steady
-
65
Model setting calculation document for Transmission Line
3.1.19 Automatic Switch Onto Fault Logic, Voltage And Current Based ZCVPSOF Guidelines for Setting: Mode: The operation of ZCVPSOF has three modes for defining the criteria for trip. When Mode is set to Impedance, the operation criteria is based on the start of overeaching zone from impedance zone measurement (Normally zone-2). A non-directional output signal should be used from an overreaching zone. The selection of Impedance mode gives increased security. Impedance mode is selected in present case. AutoInit: Automatic activating of the ZCVPSOF function is by default set to Off. If automatic activation Deadline detection is required, set the parameter Autoinit to On. Otherwise the logic will be activated by an external BC input. It is set to OFF in present case and the logic has to be activated by an external BC input. If Autoinit mode=OFF, only Breaker Close (BC) input is used to detect dead line condition. If Autoinit mode=ON, either UI Level detection of internal funciton or Breaker Close (BC) input is used to detect dead line condition. It has been assumed that in the present case CB close command input is available to the relay as external binary input. tSOTF: Time of SOTF function active status after breaker closed in impedance mode. This is normally set to 0.2s. It means, till 0.2s, SOTF function will be active after breaker closed. IBase: Set the Base current for the SOTF function in primary Ampere. This parameter is set to 1000A in present case. UBase: Setting of the Base voltage level on which the Dead line voltage is based. This parameter is set to 400kV in present case. IPh<: Setting of under current. This setting is applicable only if mode=UILevel or 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. 66
Model setting calculation document for Transmission Line
Recommended Settings: Table 3-19 gives the recommended settings for Automatic Switch Onto Fault Logic. Table 3-19: Automatic Switch Onto Fault Logic Setting Parameter
Description
Operation
Recommended Settings
Unit
Operation Off / On
On
-
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
67
Model setting calculation document for Transmission Line
3.1.20 Power Swing Detection ZMRPSB The various settings for power swing detection are shown in Figure 3-7.
Note: setting parameters are in italic and refer Table 3-20 for notations Figure 3-7: Operating characteristic for ZMRPSB function
Guidelines for Setting: 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: 68
Model setting calculation document for Transmission Line • •
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 69
Model setting calculation document for Transmission Line
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 70
Model setting calculation document for Transmission Line
Setting of the Outer Load resistance in Reverse direction for the Load enchroachment function, when utilized RLdOutRv = 74.82Ω
gives RLdOutRv"= 20.576Ω
Calculations for kLdRFw and kLdRRv: RLdInFw = kLdRFw× RLdOutFw System Impedance, Zs = Local end source Impedance + Remote end source Impedance + Protected Line Impedance Local end source Impedance = (kV)2/fault MVA = (400kV)2 / (1.732 x 400kV x 18.55kA) = 12.45Ω at 80° Remote end source Impedance = (kV)2/fault MVA = (400kV)2 / (1.732 x 400kV x 24.81kA) = 9.308Ω at 80° Local and remote end source impedance angles are assumed as 80°. Hence System Impedance, Zs = 12.45Ω at 80° + 9.308 Ω at 80° + 58.59 Ω at 84.6° = 80.297 Ω at 83.36°
tP1= Where
= 2 ● arc tan
= 56.44°
and
= 2 ● arc tan where RLdInFwmax = 0.8 x RLdOutFw = 67.7°
Now tP1=
where
= 1.5Hz
tP1 = 0.021 which is less than 30ms(Minimum) Hence tP1 = 30ms
= 360°● Hence
● tP1min +
where
= 72.64° 71
= 1.5Hz
Model setting calculation document for Transmission Line
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
72
Model setting calculation document for Transmission Line
Recommended Settings: Table 3-20 gives the recommended settings for Power Swing Detection. Table 3-20: Power Swing Detection Setting Parameter
Description
Operation
Recommended Settings
Unit
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
73
Model setting calculation document for Transmission Line
Setting Parameter
Description
tP2
Recommended Settings
Unit
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
74
Model setting calculation document for Transmission Line
Figure 3-8 and 3-9 show the graphical representation of the following in R-X plane. Zone-1 Zone-2 Zone-3 Zone-5 PHS with Load encroachment PSD
Figure 3-8: Characteristics for Phase to Phase faults
75
Model setting calculation document for Transmission Line
Figure 3-9: Characteristics for Phase to Earth faults
3.1.21 Scheme Communication Logic For Distance Or Overcurrent Protection ZCPSCH Guidelines for Setting If Permissive Underreach is set, tCoord and tSendMin settings are applicable. tCoord: Received communication signal is combined with the output from an overreaching zone till the set duration in tCoord. There is less concern about false signal causing an incorrect trip. Therefore set the timer tCoord to zero. tSendMin: To assure a sufficient duration of the received signal (CR) at the remote end, the send signal (CS) at local end can be prolonged by a tSendMin reset timer. The recommended setting of tSendMin is 100ms. 76
Model setting calculation document for Transmission Line
Recommended Settings: Table 3-21 gives the recommended settings for Scheme Communication Logic For Distance Or Overcurrent Protection.
Table 3-21: Scheme Communication Logic For Distance Or Overcurrent Protection Setting Parameter
Description
Operation
Recommended Settings
Unit
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 0.100 signal
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 Guidelines for Setting: 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”. 77
Model setting calculation document for Transmission Line
IBase: Set the Base current for the function on which the current levels are based. This parameter is set to 1000A in present case.
Recommended Settings: Table 3-22 gives the recommended settings for Stub Protection.
Table 3-22: Stub Protection Setting Parameter
Description
Operation
Recommended Settings
Unit
Operation Off / On
On
-
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.
78
Model setting calculation document for Transmission Line
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.
Recommended Settings: Table 3-23 gives the recommended settings for Fuse Failure Supervision.
Table 3-23: Fuse Failure Supervision Setting Parameter
Description
Operation
Operation Off / On
Recommended
79
Settings
Unit
On
-
Model setting calculation document for Transmission Line
Setting Parameter
Description
IBase
Recommended Settings
Unit
Base current
1000
A
UBase
Base voltage
400
kV
OpMode
Operating mode
UZsIZs
-
3U0>
residual overvoltage element in % of Ubase
30
%IB
3I0<
Operate level of residual undercurrent element in % of Ibase
10
3U2>
Operate level of neg seq overvoltage element in % of Ubase
20
3I2<
Operate level of neg seq undercurrent element in % of Ibase
10
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
80
%IB
%IB
%IB
%UB
Model setting calculation document for Transmission Line
3.1.24 Four Step Residual Overcurrent Protection EF4PTOC Guidelines for Setting: 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 is not applicable in present case. 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”. 81
Model setting calculation document for Transmission Line
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, tUndertime, HarmResSOTF: These parameters are not applicable if SOTF is set to OFF.
Setting Calculations: 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.
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Model setting calculation document for Transmission Line
Recommended Settings: Table 3-24 gives the recommended settings for Four Step Residual Overcurrent Protection.
Table 3-24: Four Step Residual Overcurrent Protection Setting Parameter
Description
Operation
Recommended Settings
Unit
Operation Off / On
On
-
IBase
Base value for current settings
1000
A
UBase
Base value for voltage settings.
400
kV
(Check with PT input in configuration ) AngleRCA
Relay characteristic angle (RCA)
65
Deg
polMethod
Type of polarization
Voltage
-
UPolMin
Minimum voltage level for polarization in % 1 of UBase
%UB
IPolMin
Minimum current level for polarization in % of IBase
%IB
RNPol
Real part of source Z to be used for current 5 polar-isation
Ohm
XNPol
Imaginary part of source Z to be used for current polarisation
40
ohm
IN>Dir
Residual current level for Direction release 10 in % of IBase
%IB
2ndHarmStab
Second harmonic restrain operation in % of 20 IN amplitude
%
BlkParTransf
Enable blocking at paral-lel transformers
-
UseStartValue
Current level blk at paral-lel transf (step1, 2, IN4> 3 or 4)
-
SOTF
SOTF operation mode (Off/SOTF/Undertime/SOTF+undertime)
Off
-
Open
-
ActivationSOTF Select signal that shall activate SOTF
83
5
Off
Model setting calculation document for Transmission Line
Recommended
Setting Parameter
Description
StepForSOTF
Selection of step used for SOTF
Settings
Unit
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
-
DirMode2
Directional mode of step 2 (off, nodir, forward, reverse)
Off
-
DirMode3
Directional mode of step 3 (off, nodir, forward, reverse)
Off
-
DirMode4
Directional mode of step 4 (off, nodir, forward, reverse)
Off
-
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Model setting calculation document for Transmission Line
3.1.25 Two Step Overvoltage Protection OV2PTOV Guidelines for Settings: 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 set to 400kV in present case. 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. 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. 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.
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Model setting calculation document for Transmission Line
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. ResetTypeCrv2: 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. 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%.
Recommended Settings: Table 3-25 gives the recommended settings for Two Step Overvoltage Protection.
Table 3-25: Two Step Overvoltage Protection Setting Parameter
Description
ConnType
Recommended Settings
Unit
Group selector for connection type
PhPh DFT
-
Operation
Operation Off / On
On
-
UBase
Base voltage
400
kV
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
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Model setting calculation document for Transmission Line
Setting Parameter
Description
t1Min
Recommended Settings
Unit
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
0.025
s
Instantaneous
-
Time curve step 1 ResetTypeCrv1
Selection of used IDMT reset curve type for step 1
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
-
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Model setting calculation document for Transmission Line
Setting Parameter
Recommended
Description
Settings
Unit
0.000
-
programmable curve for step 1 DCrv1
Parameter D for customer programmable curve for step 1
PCrv1
Parameter P for customer programmable curve for step 1
1.000
-
CrvSat1
Tuning param for prog. over voltage
0
-
0.025
s
Instantaneous
-
IDMT curve, step 1 tReset2
Reset time delay used in IEC Definite Time curve step 2
ResetTypeCrv2
Selection of used IDMT reset curve type for step 2
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
-
0.000
-
programmable curve for step 2 DCrv2
Parameter D for customer programmable curve for step 2
PCrv2
Parameter P for customer programmable curve for step 2
1.000
-
CrvSat2
Tuning param for prog. over voltage
0
%
IDMT curve, step 2
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Model setting calculation document for Transmission Line
3.1.26 Setting of fault locator values LFL Setting Calculations: 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
Recommended Settings: Table 3-26 gives the recommended settings for Setting of fault locator values.
Table 3-26: Setting of fault locator values Setting Parameter
Description
R1A
Recommended Settings
Unit
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
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Model setting calculation document for Transmission Line
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 Guidelines for Setting: 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. 90
Model setting calculation document for Transmission Line
— 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
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Model setting calculation document for Transmission Line
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.
Recommended Settings: Table 3-27 gives the recommended settings for Disturbance Report.
Table 3-27: Disturbance Report Setting Parameter
Description
Operation
Recommended Settings
Unit
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
-
1
Ch
Off
-
ZeroAngleRef OpModeTest
Reference channel (voltage), phasors, frequency measurement Operation mode during test mode
92
Model setting calculation document for Transmission Line
3.2 REC670 3.2.1 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
1000
1000
1000
1000
1000
1000
CTsec
1A
1A
1A
1A
1A
1A
CTStarPoint parameter indicates the CT secondary winding neutral earthing towards object (ToObject) or towards busbar (FromObject). Voltage analog input as: Ch 1
Ch 2
Ch 3
Ch 4
Ch 5
Ch 6
Name#
UL1
UL2
UL3
UL2BUS1
UL2BUS2
UL2L2
VTprim
400kV
400kV
400kV
400kV
400kV
400kV
VTsec
110V
110V
110V
110V
110V
110V
# User defined text
Recommended Settings: Table 3-28 gives the recommended settings for Analog Inputs.
Table 3-28: Analog Inputs Setting Parameter PhaseAngleRef CTStarPoint1
Recommended
Description Reference channel for phase angle presentation ToObject= towards protected object, 93
Settings
Unit
TRM40-Ch1
-
ToObject
-
Model setting calculation document for Transmission Line
Setting Parameter
Recommended
Description
Settings
Unit
FromObject= the opposite CTsec1
Rated CT secondary current
1
A
CTprim1
Rated CT primary current
1000
A
ToObject
-
CTStarPoint2
ToObject= towards protected object, FromObject= the opposite
CTsec2
Rated CT secondary current
1
A
CTprim2
Rated CT primary current
1000
A
ToObject
-
CTStarPoint3
ToObject= towards protected object, FromObject= the opposite
CTsec3
Rated CT secondary current
1
A
CTprim3
Rated CT primary current
1000
A
ToObject
-
CTStarPoint4
ToObject= towards protected object, FromObject= the opposite
CTsec4
Rated CT secondary current
1
A
CTprim4
Rated CT primary current
1000
A
ToObject
-
CTStarPoint5
ToObject= towards protected object, FromObject= the opposite
CTsec5
Rated CT secondary current
1
A
CTprim5
Rated CT primary current
1000
A
ToObject
-
CTStarPoint6
ToObject= towards protected object, FromObject= the opposite
CTsec6
Rated CT secondary current
1
A
CTprim6
Rated CT primary current
1000
A
VTsec7
Rated VT secondary voltage
110
V
VTprim7
Rated VT primary voltage
400
kV
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Model setting calculation document for Transmission Line
Setting Parameter
Description
VTsec8
Recommended Settings
Unit
Rated VT secondary voltage
110
V
VTprim8
Rated VT primary voltage
400
kV
VTsec9
Rated VT secondary voltage
110
V
VTprim9
Rated VT primary voltage
400
kV
VTsec10
Rated VT secondary voltage
110
V
VTprim10
Rated VT primary voltage
400
kV
VTsec11
Rated VT secondary voltage
110
V
VTprim11
Rated VT primary voltage
400
kV
VTsec12
Rated VT secondary voltage
110
V
VTprim12
Rated VT primary voltage
400
kV
Binary input module (BIM) Settings
I/O Module 1 I/O Module 2 I/O Module 3 I/O Module 4 I/O Module 5
Operation On On On On On
OscBlock(Hz) 40 40 40 40 40
OscRelease(Hz) 30 30 30 30 30
Pos Slot3 Pos Slot3 Pos Slot3 Pos Slot3 Pos Slot3
Note: OscBlock and OscRelease define the filtering time at activation. Low frequency gives slow response for digital input.
3.2.2 Local Human-Machine Interface Recommended Settings: Table 3-29 gives the recommended settings for Local human machine interface.
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Model setting calculation document for Transmission Line
Table 3-29: Local human machine interface Setting Parameter
Description
Language
Recommended Settings
Unit
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
-
3.2.3 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.
Recommended Settings: Table 3-30 gives the recommended settings for Indication LEDs. Table 3-30: LEDGEN Non group settings (basic) Setting Parameter
Recommended
Description
Settings
96
Unit
Model setting calculation document for Transmission Line
Setting Parameter
Description
Operation tRestart tMax
Recommended Settings
Unit
Operation mode for the LED function
On
-
Defines the disturbance length
0.0
s
0.0
s
Maximum time for the definition of a disturbance
SeqTypeLED1
Sequence type for LED 1
LatchedAck-S-F
-
SeqTypeLED2
Sequence type for LED 2
LatchedAck-S-F
-
SeqTypeLED3
Sequence type for LED 3
LatchedAck-S-F
-
SeqTypeLED4
Sequence type for LED 4
LatchedAck-S-F
-
SeqTypeLED5
Sequence type for LED 5
LatchedAck-S-F
-
SeqTypeLED6
Sequence type for LED 6
LatchedAck-S-F
-
SeqTypeLED7
Sequence type for LED 7
LatchedAck-S-F
-
SeqTypeLED8
Sequence type for LED 8
LatchedAck-S-F
-
SeqTypeLED9
Sequence type for LED 9
LatchedAck-S-F
-
SeqTypeLED10
Sequence type for LED 10
LatchedAck-S-F
-
SeqTypeLED11
Sequence type for LED 11
LatchedAck-S-F
-
SeqTypeLED12
Sequence type for LED 12
LatchedAck-S-F
-
SeqTypeLED13
Sequence type for LED 13
LatchedAck-S-F
-
SeqTypeLED14
Sequence type for LED 14
LatchedAck-S-F
-
SeqTypeLED15
Sequence type for LED 15
LatchedAck-S-F
-
3.2.4 Time Synchronization Guidelines for Settings: These settings are used for synchronizing IED clock time with network time. Ex: GPS or IRIG-B time. CoarseSyncSrc: Select the time synchronization source available such as SPA, LON, SNTP etc. Synchronization messages from sources configured as coarse are checked against the internal relay 97
Model setting calculation document for Transmission Line
time and only if the difference in relay time and source time is more than 10s then relay time will be reset with the source time. This parameter need to be based on time source available in site. FineSyncSource: Select the time source available in network like IRIG-B, GPS, SNTP, SPA etc. once it is selected, time of available time source in network will update to relay if there is a difference in the time between relay and source. This parameter need to be based on time source available in site. SyncMaster: Normally it is set OFF. If time to the relay is received from a GPS antenna (example), make the relay as master to synchronize with other relays. TimeAdjustRate: Fast HWSyncSrc: This is applicable if process bus IEC61850-9-2 protocol is used for receiving analog values (optical CT PTs). In this case select time source available same as that of merging unit. This setting is not applicable in present case. AppSynch: If there is any loss of time sync, protection function will be blocked if AppSynch set to Synch based on SyncAccLevel. If AppSunch set to NoSynch, protection functions are not blocked. Recommended setting is NoSynch. SyncAccLevel: If this is set to “Class T5 (1us)” and time synch error is more than 1us, protection functions will be blocked. SyncAccLevel should be set to “Unspecified” when Nosynch is selected at AppSynch. This parameter is not applicable in present case. ModulePosition: if BIN is set for FineSyncSource, ModulePosition setting is applicable. Here slot position of IO module in the relay is to be set (Which slot is used for BI). This parameter is not applicable in present case. BinaryInput: Which binary input is used for time sync input shall be set here. This parameter is applicable if BIN is set for FineSyncSource. This parameter is not applicable in present case. BinDetection: Which edge of input pulse need to be detected has to be set here (positive and negative). This parameter is applicable if BIN is set for FineSyncSource. This parameter is not applicable in present case. ServerIP-Add: Here set Time source server IP address. RedServIP-Add: If redundant server is available, set address of redundant server here. 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.
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Model setting calculation document for Transmission Line
SYNCHIRIG-B Non group settings: These settings are applicable if IRIG-B is used. This parameter is not applicable in present case. SynchType: Type of hardware input used for time sync, whether Opto or BNC. This parameter is not applicable in present case. TimeDomain: In present case this parameter is set to LocalTime. Encoding: In present case this parameter is set to IRIG-B. TimeZoneAs1344: In present case this parameter is set to PlusTZ.
Recommended Settings: Table 3-31 gives the recommended settings for Time Synchronization. Table 3-31: Time Synchronization TIMESYNCHGEN Non group settings (basic) Setting Parameter
Description
CoarseSyncSrc
Recommended Settings
Unit
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
-
SYNCHBIN Non group settings (basic) Setting Parameter ModulePosition
BinaryInput BinDetection
Recommended
Description Hardware position of IO module for time Synchronization Binary input number for time Synchronization Positive or negative edge detection
99
Settings
Unit
3
-
1
-
PositiveEdge
-
Model setting calculation document for Transmission Line
SYNCHSNTP Non group settings (basic) Recommended Setting Parameter
Description Settings
Unit
ServerIP-Add
Server IP-address
0.0.0.0
IP Address
RedServIP-Add
Redundant server IP-address
0.0.0.0
IP Address
DSTBEGIN Non group settings (basic) Setting Parameter
Description
MonthInYear
Recommended Settings
Unit
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
-
3600
s
UTCTimeOfDay
UTC Time of day in seconds when daylight time starts
DSTEND Non group settings (basic) Setting Parameter
Description
MonthInYear
Recommended Settings
Unit
Month in year when daylight time starts
October
-
DayInWeek
Day in week when daylight time starts
Sunday
-
WeekInMonth
Week in month when daylight time starts
Last
-
3600
s
UTCTimeOfDay
UTC Time of day in seconds when daylight time starts
100
Model setting calculation document for Transmission Line
TIMEZONE Non group settings (basic) Recommended
Setting Parameter
Description
NoHalfHourUTC
Number of half-hours from UTC
Settings
Unit
+11
-
SYNCHIRIG-B Non group settings (basic) Setting Parameter
Recommended
Description
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.
3.2.5 Parameter Setting Groups Guidelines for Settings: t: The length of the pulse, sent out by the output signal SETCHGD when an active group has changed, is set with the parameter t. This is not the delay for changing setting group. This parameter is normally recommended to set 1s. MAXSETGR: The parameter MAXSETGR defines the maximum number of setting groups in use to switch between. Only the selected number of setting groups will be available in the Parameter Setting tool (PST) for activation with the ActiveGroup function block. This parameter is normally recommended to set 1.
Recommended Settings: Table 3-32 gives the recommended settings for Parameter Setting Groups.
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Model setting calculation document for Transmission Line
Table 3-32: Parameter Setting Groups ActiveGroup Non group settings (basic) Setting Parameter t
Recommended
Description Pulse length of pulse when setting Changed
Settings
Unit
1
s
SETGRPS Non group settings (basic) Setting Parameter
Description
ActiveSetGrp MAXSETGR
Recommended Settings
Unit
ActiveSettingGroup
SettingGroup1
-
Max number of setting groups 1-6
1
No
3.2.6 Test Mode Functionality TEST Guidelines for Settings: EventDisable: If it is ON, it will disable the events like in DR during test mode. Normally this parameter is set to OFF. CmdTestBit: In present case this parameter is set to Off.
Recommended Settings: Table 3-33 gives the recommended settings for Test Mode Functionality. Table 3-33: Test Mode Functionality TESTMODE Non group settings (basic) Setting Parameter
Description
TestMode
Recommended Settings
Unit
Test mode in operation (On) or not (Off)
Off
-
EventDisable
Event disable during testmode
Off
-
CmdTestBit
Command bit for test required or not
Off
-
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Model setting calculation document for Transmission Line
during testmode
3.2.7 IED Identifiers Recommended Settings: Table 3-34 gives the recommended settings for IED Identifiers. Table 3-34: IED Identifiers TERMINALID Non group settings (basic) Setting Parameter
Description
StationName
Recommended Settings
Unit
Station name
Station-A
-
StationNumber
Station number
0
-
ObjectName
Object name
Line
-
ObjectNumber
Object number
0
-
UnitName
Unit name
REC670
-
UnitNumber
Unit number
0
-
3.2.8 Rated System Frequency PRIMVAL Recommended Settings: Table 3-35 gives the recommended settings for Rated System Frequency. Table 3-35: Rated System Frequency PRIMVAL Non group settings (basic) Setting Parameter
Description
Frequency
Rated system frequency
Recommended Settings
Unit
50.0
Hz
3.2.9 Signal Matrix For Analog Inputs SMAI Guidelines for Settings: 103
Model setting calculation document for Transmission Line
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 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 be set to 10% normally. UBase: Set the base voltage here. This is parameter is set to 400kV.
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Model setting calculation document for Transmission Line
Recommended Settings: Table 3-36 gives the recommended settings for Signal Matrix For Analog Inputs. Table 3-36: Signal Matrix For Analog Inputs Setting Parameter
Description
DFTRefExtOut
Recommended Settings
Unit
DFT reference for external output
(As per configuration)
-
DFTReference
DFT reference
(As per configuration)
-
ConnectionType
Input connection type
Ph-Ph
-
TYPE
1=Voltage, 2=Current
1 or 2 based on input
Ch
Negation
Negation
Off
-
10
%
400
kV
MinValFreqMeas UBase
Limit for frequency calculation in % of UBase Base voltage
105
Model setting calculation document for Transmission Line
3.2.10 Synchrocheck function (SYN1) Guidelines for Settings: 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 set to 400kV in present case. 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 parameter is set ON. 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 106
Model setting calculation document for Transmission Line
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. 107
Model setting calculation document for Transmission Line
The threshold voltages ULowBusEnerg and ULowLineEnerg, have to be set to a value greater than the value where the network is considered not to be energized. A typical value can be 40% of the base voltages. If system voltages are below the set values here, relay will consider it as Dead condition. UMaxEnerg: Setting of the maximum live voltage level at which energizing is allowed. This setting is used to block the closing when the voltage on the live side is above the set value of UMaxEnerg. In present case this parameter is set to 105% of UBase. tAutoEnerg and tManEnerg: Set the time delay for the Auto Energizing and Manual Energizing. The purpose of the timer delay settings, tAutoEnerg and tManEnerg, is to ensure that the dead side remains de-energized and that the condition is not due to a temporary interference. If the conditions do not persist for the specified time, the delay timer is reset and the procedure is restarted when the conditions are fulfilled again. Circuit breaker closing is thus not permitted until the energizing condition has remained constant throughout the set delay setting time. Normally tManEnerg is recommended to set 0.1s. tAutoEnerg is not applicable in present case. OperationSynch: Operation for synchronizing function Off/ On. This parameter is recommended to set OFF. FreqDiffMin, FreqDiffMax, UHighBusSynch, UHighLineSynch, UDiffSynch, tClosePulse, tBreaker, tMinSynch and tMaxSynch: These parameters are not applicable if OperationSynch is set to OFF.
Recommended Settings: Table 3-37 gives the recommended settings for Synchrocheck function. Table 3-37: Synchrocheck function Recommended
Setting Parameter
Description
Operation
Operation Off / On
On
-
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
-
Settings
108
Unit
Model setting calculation document for Transmission Line
Setting Parameter OperationSynch
Recommended
Description
Settings
Operation for synchronizing function Off/ On
Unit
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
0.010
Hz
0.10
Hz
30.0
Deg
30.0
Deg
0.100
s
0.100
s
FreqDiffA
FreqDiffM
PhaseDiffA
PhaseDiffM tSCA tSCM
Frequency difference limit between bus and line Auto Frequency difference limit between bus and line Manual Phase angle difference limit between bus and line Auto Phase angle difference limit between bus and line Manual Time delay output for synchrocheck Auto Time delay output for synchrocheck Manual
AutoEnerg
Automatic energizing check mode
Off
-
ManEnerg
Manual energizing check mode
Both
-
ManEnergDBDL
Manual dead bus, dead line energizing
Off
-
80.0
%UBB
80.0
%UBL
UHighBusEnerg
UHighLineEnerg
Voltage high limit bus for energizing check in % of UBaseBus Voltage high limit line for energizing check in % of UBaseLine
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Model setting calculation document for Transmission Line
Setting Parameter ULowBusEnerg
ULowLineEnerg
UMaxEnerg
tAutoEnerg
Recommended
Description
Settings
Voltage low limit bus for energizing check in % of UBaseBus Voltage low limit line for energizing check in % of UBaseLine Maximum voltage for energizing in % of UBase, Line and/or Bus Time delay for automatic energizing Check
Unit
40.0
%UBB
40.0
%UBL
105.0
%UB
0.100
s
0.100
s
tManEnerg
Time delay for manual energizing check
SelPhaseBus1
Select phase for busbar1
SelPhaseBus2
Select phase for busbar2
SelPhaseLine1
Select phase for line1
Phase L1 for line1
-
SelPhaseLine2
Select phase for line2
Phase L1 for line2
-
Phase L1 for busbar1 Phase L1 for busbar2
-
-
3.2.11 Autorecloser SMBRREC Guidelines for Setting: 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 110
Model setting calculation document for Transmission Line
—
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 2ph. 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.
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Model setting calculation document for Transmission Line
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 2ph 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 2ph 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. 112
Model setting calculation document for Transmission Line
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 autoreclosing 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. 113
Model setting calculation document for Transmission Line
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 114
Model setting calculation document for Transmission Line
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.
Recommended Settings: Table 3-38 gives the recommended settings for Autorecloser. 115
Model setting calculation document for Transmission Line
Table 3-38: Autorecloser Setting Parameter
Description
Recommended
Unit
Settings
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
30.00
s
High
-
tUnsucCl Priority
Wait time for CB before indicating Unsuccessful/ Successful Priority selection between adjacent terminals None/Low/ 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
t3 3Ph
Open time for shot 3, three-phase
30.00
s
t4 3Ph
Open time for shot 4, three-phase
30.00
s
t5 3Ph
Open time for shot 5, 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
116
Model setting calculation document for Transmission Line
Setting Parameter
Description
Recommended
Unit
Settings
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
-
Off
-
AutoCont
Continue with next reclosing-shot if breaker did not close
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
-
117
Model setting calculation document for Transmission Line
3.2.12 Disturbance Report DRPRDRE Guidelines for Setting: 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(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
118
Model setting calculation document for Transmission Line
— 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 — Minimum prefault recording time of 200ms — Minimum Post fault recording time of 2500ms PreFaultRecT: It 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 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.
Recommended Settings: Table 3-39 gives the recommended settings for Disturbance Report. Table 3-39: Disturbance Report Setting Parameter
Description
Operation
Recommended Settings
Unit
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,
1
Ch
119
Model setting calculation document for Transmission Line
frequency measurement OpModeTest
Operation mode during test mode
120
Off
-
Model setting calculation document for Transmission Line
APPENDIX-A: Coordination of 400kV Line Protection Zone-2 and Zone-3 with IDMT O/C & E/F relays of 400kV side of ICT and 220kV Line Zone-2 and Zone-3 timers of 400kV line distance relay need to be coordinated with 400kV side IDMT O/C and E/F relays provided on the 400/220kV ICT and 220kV line in order to make sure that for faults on 220kV line, the IDMT O/C and E/F relays have chance to operate before Zone 2 or Zone-3 of 400kV Distance relay operates for the cases where Zone 2/Zone 3 reach encroaches into 220kV side of Transformer.
The calculations given in this appendix are with following objective: 1. Settings to be provided on IDMT O/C relays of 400kV side of ICT and on 220 kV line (As per the protection guideline, 220kV line protection shall have distance relay as Main-I and Main-II. However, most of the utilities use single distance main and back up O/C protection and hence O/C protection on 220kV line has also been considered for illustration). 3. Settings to be provided on IDMT E/F relays on 400kV line, 400kV side of ICT and 220kV line 4. Coordination curves for ICT O/C relays with Zone-2 and Zone-3 5. Coordination curves for ICT E/F relays with Zone-2 and Zone-3 6. Does Zone-2 and Zone-3 reaches encroach into 220kV side of ICT for 1-ph and ph-ph faults for various fault levels.
1. System Details: Figure A-1 shows the system details for the network under consideration for relay setting. Table A-1 gives the setting for the over current and earth fault relays for the network under consideration.
2. 3-Ph Fault Current: Figure A-2 shows the 3-Ph fault currents & operating time of relays for a fault at 5% of 220kV L-1. The operating times are taken from phase over current coordination curves given in figure A-3.
3. Ph-G Fault Current: Figure A-4 shows the earth fault currents & operating time of relays for a fault at 5% of 220kV L1. The operating times are taken from earth fault current coordination curves given in figure A-5. 121
Model setting calculation document for Transmission Line
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
SI. NO
Relay Name
CT ratio
Base current set Ib in A
Thermal / Curve (NEMA Code :67)
Instantaneous Setting (NEMA Code :50)
Plug setting Ip> (I/Ib) in%
TMS T p>
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) SI. NO
Relay Name
CT ratio
Base current set Ib in A
Instantaneous Setting (NEMA Code :50N)
Plug setting Ie> (I/Ib) in%
TMS Te>
Ie>> (I/Ib) in%
Te>> in s
1
400kV Directional O/C
1000/1 A
1000
20%
0.30
-
-
2
TR-1 Primary
1000/1 A
455
20%
0.56
800%
0.05
3
220kV Directional O/C
800/1 A
800
15%
0.43
-
-
122
Model setting calculation document for Transmission Line
Figure A-1: System details for the network under consideration for relay setting 123
Model setting calculation document for Transmission Line
Figure A-2: 3-Ph fault current for 220 kV side fault 124
Model setting calculation document for Transmission Line
Figure A-3: Over Current Relay Curve Co-ordination and Operating Time 125
Model setting calculation document for Transmission Line
Figure A-4: Ph-G fault current for 220 kV side fault 126
Model setting calculation document for Transmission Line
Figure A-5: Earth Fault Relay Curve Co-ordination and Operating Time 127
Model setting calculation document for Transmission Line
Figure A-6: Earth fault relay co-ordination for 400 kV bus fault at Station B (Remote bus of the protected line) 128
Model setting calculation document for Transmission Line
Figure A-7: Earth fault relay operating time co-ordinated with Zone 3 time setting 129
Model setting calculation document for Transmission Line
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 Zone-3 reactive reach X3 = 199.3Ω 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 Zone-2 reactive reach X2 = 87.5Ω Zone-3 reactive reach X3 = 199.3Ω 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. 130
Model setting calculation document for Transmission Line
APPENDIX-B: Effect of network change due to a line LILO on relay settings of LILO line & adjacent lines In example considered for the sample distance relay setting calculation, the 400kV double circuited line between station-A and station-B has now a loop-in loop-out connection at a distance of 120km form station-A in one of the circuit. The other circuit, there is no loop-in loop-out. Figure B-1 shows the modified network.
Figure B-1: Network line diagram of the system after the LILO of one circuit of line AB Due to change in the network after the LILO, the settings of following functions in the line protections of lines at various stations will have to be reviewed and revised as described below for the present case: Station-A: Line that has LILO connection (Line A-S): New settings are required for Main distance relays. The effect of mutual coupling will have to be considered as before. 131
Model setting calculation document for Transmission Line
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
132
Model setting calculation document for Transmission Line
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
133
Model setting calculation document for Transmission Line
Case 1: Parallel line A-S switched off and earthed at both ends and fault at station-B
1.1 Line A-S out of service and earthed at both ends and fault at station-B – source at end A only (Figure B-2 and Table B-1)
Figure B-2: SLG Fault at bus B with source at Station A and Line A-S out of service and Earthed
Table B-1: Fault At Station-B With Source At Station – A and Line A-S Earthed Fault location
Line Impedance in Ω
Apparent Impedance (Z) in Ω
% Error
Station B
58.30
49.43
-15.21
134
Model setting calculation document for Transmission Line
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 and Table B-2)
Figure B-3: SLG Fault at bus B with sources at Station A & B and Line A-S out of service and Earthed
Table B-2: Fault At Station-B With Sources At Station – A & B and Line A-S Earthed Fault location
Line Impedance in Ω
Apparent Impedance (Z) in Ω
% Error
Station B
58.30
49.88
-14.44
135
Model setting calculation document for Transmission Line
1.3 Line A-S out of service and earthed at both ends and fault at station-B – sources at ends A, B and S (Figure B-4 and Table B-3)
Figure B-4: SLG Fault at bus B with sources at Station A, B & S and Line A-S out of service and Earthed Table B-3: Fault At Station-B With Sources At Station – A, B & S and Line A-S Earthed Fault location Station B
Line Impedance in Ω 58.30
Apparent Impedance (Z) in Ω 60.09
% Error 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.
136
Model setting calculation document for Transmission Line
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 and Table B-4)
Figure B-5: SLG Fault at bus B with source at Station A and Line B-S out of service and Earthed Table B-4: Fault At Station-B With Source At Station – A and Line B-S Earthed Fault location
Line Impedance in Ω
Apparent Impedance (Z) in Ω
% Error
Station B
58.30
52.96
-9.15
137
Model setting calculation document for Transmission Line
2.2 Line B-S out of service and earthed at both ends and fault at station-B – sources at ends A and B (Figure B-6 and Table B-5)
Figure B-6: SLG Fault at bus B with sources at Station A & B and Line B-S out of service and Earthed Table B-5: Fault At Station-B With Source At Station – A & B and Line B-S Earthed Fault location Station B
Line Impedance in (Ω) 58.30
Apparent Impedance (Z) in Ω 53.31
% Error -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 and S (Figure B-7 and Table B-6) 138
Model setting calculation document for Transmission Line
Figure B-7: SLG Fault at bus B with sources at Station A, B & S and Line B-S out of service and Earthed
Table B-1: Fault At Station-B With Source At Station – A, B & S and Line B-S Earthed Fault location Station B
Line Impedance in Ω 58.30
Apparent Impedance (Z) in Ω 46.17
% Error -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
139
Model setting calculation document for Transmission Line
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 and Table B-7)
Figure B-8: SLG Fault at bus S with source at Station A and Line A-B out of service and Earthed
Table B-6: Fault At Station-S With Source At Station – A and Line A-B Earthed Fault location
Line Impedance in Ω
Apparent Impedance (Z) in Ω
% Error
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) 140
Model setting calculation document for Transmission Line
Figure B-9: SLG Fault at bus S with sources at Station A & B and Line A-B out of service and Earthed
Table B-7: Fault At Station-S With Sources At Station – A & B and Line A-B Earthed Fault location Station B
Line Impedance in Ω 36.84
Apparent Impedance (Z) in Ω 38.41
% Error 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 and S (Figure B-10 and Table B-9)
141
Model setting calculation document for Transmission Line
Figure B-10: SLG Fault at bus S with sources at Station A, B & S and Line A-B out of service and Earthed
Table B-8: Fault At Station-S With Sources At Station – A, B & S and Line A-B Earthed Fault location
Line Impedance in Ω
Apparent Impedance (Z) in Ω
% Error
Station B
36.84
38.18
3.63
In case-3, the distance relay provided on line AS overreaches by 14.2% when source is only at A, underreaches by 4.2% when source is present at A and B, underreaches by 3.63% when source is present at A, B and S. Therefor with zone-1 setting of 80% on line AS, the relay can overreach in to the next section. Since such occurrences are rare, the risk of overreach will have to be accepted. One factor in favor of this is the overreach in the following line is normally heavily reduced due to infeeds at the remote stations. Case 4: All lines are in service and fault at station-B
142
Model setting calculation document for Transmission Line
4.1 All lines are in service and fault at station-B– source at end A only (Figure B-11 and Table B10)
Figure B-11: SLG Fault at bus B with source at Station A
Table B-9: Fault At Station-B With Source At Station A Fault location
Line Impedance in Ω
Apparent Impedance (Z) in Ω
% Error
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) 143
Model setting calculation document for Transmission Line
Figure B-12: SLG Fault at bus B with sources at Station A and B
Table B-10: Fault At Station-B With Sources At Station – A & B Fault location
Line Impedance in Ω
Apparent Impedance (Z) in Ω
% Error
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) 144
Model setting calculation document for Transmission Line
Figure B-13: SLG Fault at bus B with sources at Station A, B & S
Table B-11: Fault At Station-B With Sources At Station – A, B and S Fault location
Line Impedance in Ω
Apparent Impedance (Z) in Ω
% Error
Station B
58.30
74.57
27.90
In case-4, the distance relay provided on line AB under reaches by 37.6% when source is only at A, 27.5% when source is present at A and B, 27.9% when source is present at A, B and S. From this it can be seen that zone-2 tends to under reach and it will not be able to cover the whole section fully and this is not acceptable. For this reason zone-2 must be set to 120%+37.6%, which is approximately 160% of the protected line impedance rather than the conventional 120% in order to accommodate the under reaching effect due to mutual coupling. Case 5: All lines are in service and fault at station-S
5.1 All lines are in service and fault at station-S– source at end A only (Figure B-14 and Table B-13) 145
Model setting calculation document for Transmission Line
Figure B-14: SLG Fault at bus S with source at Station A
Table B-12: Fault At Station-S Without Sources At Station – S & B Fault location Station S
Line Impedance in Ω 36.84
Apparent Impedance (Z) in Ω 44.25
% Error 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) 146
Model setting calculation document for Transmission Line
Figure B-15: SLG Fault at bus S with sources at Station A and B
Table B-13: Fault At Station-S With Sources At Station – A & B Fault location Station S
Line Impedance in Ω 36.84
Apparent Impedance (Z) in Ω 37.78
% Error 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)
147
Model setting calculation document for Transmission Line
Figure B-16: SLG Fault at bus S with sources at Station A, B & S
Table B-14: Fault At Station-S With Sources At Station – A, B & S Fault location
Line Impedance in Ω
Apparent Impedance (Z) in Ω
% Error
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. 148
Model setting calculation document for Transmission Line
•
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%.
********************************************
149
MODEL SETTING CALCULATION DOCUMENT FOR A TYPICAL IED USED FOR 400/220/33kV AUTO TRANSFORMER PROTECTION
Model setting calculation document for Auto Transformer
TABLE OF CONTENTS TABLE OF CONTENTS .............................................................................................................. 2 1
BASIC SYSTEM PARAMETERS......................................................................................... 7
1.1 Network line diagram of the protected Transformer and adjacent circuits.................... 7 1.2 Single line diagram of the Auto Transformer ................................................................... 7 1.3 Transformer parameters .................................................................................................. 10 2
TERMINAL IDENTIFICATION AND LIST OF FUNCTIONS................................................11
2.1 RET670-1........................................................................................................................... 11 2.1.1 Terminal Identification ....................................................................................11 2.1.2 List of functions available and those used ......................................................11 2.2 RET670-2........................................................................................................................... 16 2.2.1 Terminal Identification ....................................................................................16 2.2.2 List of functions available and those used ......................................................16 2.3 REC670.............................................................................................................................. 21
3
2.3.1 Terminal identification ....................................................................................21 2.3.2 List of functions available and those used ......................................................21 SETTING CALCULATIONS AND RECOMMENDED SETTINGS FOR RET670-1..............27
3.1 RET670-1........................................................................................................................... 27 3.1.1 Analog Inputs .................................................................................................27 3.1.2 Local Human-Machine Interface.....................................................................29 3.1.3 Indication LEDs..............................................................................................30 3.1.4 Time Synchronization.....................................................................................31 3.1.5 Parameter Setting Groups..............................................................................35 3.1.6 Test Mode Functionality TEST .......................................................................35 3.1.7 IED Identifiers ................................................................................................36 3.1.8 Rated System Frequency PRIMVAL ..............................................................36 3.1.9 Signal Matrix For Analog Inputs SMAI............................................................37 3.1.10 Transformer differential protection T3WPDIF .................................................38 3.1.11 Tripping Logic SMPPTRC ..............................................................................47 3.1.12 Trip Matrix Logic TMAGGIO...........................................................................48 3.1.13 Four Step Phase Overcurrent Protection OC4PTOC:1 (Used for HV side).....49 3.1.14 Four Step Phase Overcurrent Protection OC4PTOC:2 (Used for HV side Overload alarm) 56 3.1.15 Four Step Residual Overcurrent Protection EF4PTOC (Used for HV side).....60 3.1.16 Overexcitation protection OEXPVPH—(HV side) ...........................................68 3.1.17 Disturbance Report DRPRDRE......................................................................73 3.2 RET670-2........................................................................................................................... 76 3.2.1 3.2.2 3.2.3 3.2.4 3.2.5 3.2.6
Analog Inputs .................................................................................................76 Local Human-Machine Interface.....................................................................78 Indication LEDs..............................................................................................78 Time Synchronization.....................................................................................80 Parameter Setting Groups..............................................................................83 Test Mode Functionality TEST .......................................................................84 2
Model setting calculation document for Auto Transformer 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
3
Model setting calculation document for Auto Transformer
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
4
Model setting calculation document for Auto Transformer
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
5
Model setting calculation document for Auto Transformer
SETTING CALCULATION EXAMPLE
SUB-STATION: Station-A FEEDER: 400/220/33kV Auto Transformer at Station-A PROTECTION ELEMENT: Main-I & Main-II Protection Protection schematic Drg. Ref. No. XXXXXX
6
Model setting calculation document for Auto Transformer
1
BASIC SYSTEM PARAMETERS
1.1 Network line diagram of the protected Transformer and adjacent circuits The network line diagram (Figure 1-1) of the system under consideration showing protected Transformer along with adjacent associated elements is shown below. The network diagram should indicate the voltage levels, line lengths, transformer/generator rated MVA & fault contributions of each element for 3-ph fault at station-A 400kV and 220kV buses.
Figure 1-1: Network line diagram of the protected Transformer
1.2 Single line diagram of the Auto Transformer Single line diagram of the Auto transformer, various protection functions used and CT/PT connections is shown in Figure 1-2. 7
Model setting calculation document for Auto Transformer
Figure 1-2: Single line diagram of the Auto Transformer with CT ratios 8
Model setting calculation document for Auto Transformer 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
4B-CT
4C-CT
1CT
2CT NCT
2C-CT
Name of the Core
CT ratio
CORE-1
1000/1A
CORE-2
1000/1A
CORE-3
1000/1A
CORE-4
2000/1A
CORE-5
2000/1A
CORE-1
2000/1A
CORE-2
2000/1A
CORE-3
1000/1A
CORE-4
1000/1A
CORE-5
1000/1A
CORE-1
1000/1A
CORE-2
600/1A
CORE-1
1000/1A
CORE-2
1000/1A
CORE-1
1000/1A
CORE-1
1600/1A
CORE-2
800/1A
CORE-3
800/1A
CORE-4
800/1A
CORE-5
800/1A
CT details CLASS:PS, Vk:2000V, Imax at Vk:60mA, Rct@75 DEGREE CENTIGRADE ohm: <5Ω CLASS:PS, Vk:2000V, Imax at Vk:60mA, Rct@75 DEGREE CENTIGRADE ohm: <5Ω CLASS:0.2, 30VA CLASS:PS, Vk:4000V, Imax at Vk:120mA, Rct@75 DEGREE CENTIGRADE ohm: <10Ω CLASS:PS, Vk:4000V, Imax at Vk:120mA, Rct@75 DEGREE CENTIGRADE ohm: <10Ω CLASS:PS, Vk:4000V, Imax at Vk:120mA, Rct@75 DEGREE CENTIGRADE ohm: <10Ω CLASS:PS, Vk:4000V, Imax at Vk:120mA, Rct@75 DEGREE CENTIGRADE ohm: <10Ω CLASS:PS, Vk:2000V, Imax at Vk:60mA, Rct@75 DEGREE CENTIGRADE ohm: <5Ω CLASS:PS, Vk:2000V, Imax at Vk:60mA, Rct@75 DEGREE CENTIGRADE ohm: <5Ω CLASS:PS, Vk:2000V, Imax at Vk:60mA, Rct@75 DEGREE CENTIGRADE ohm: <5Ω CLASS:PS, Vk:1000V, Imax at Vk:60mA, Rct@75 DEGREE CENTIGRADE ohm: <2.5Ω CLASS:0.2, 30VA CLASS:PS, Vk:1000V, Imax at Vk:60mA, Rct@75 DEGREE CENTIGRADE ohm: <2.5Ω CLASS:0.2, 30VA CLASS:PS, Vk:1000V, Imax at Vk:60mA, Rct@75 DEGREE CENTIGRADE ohm: <2.5Ω CLASS:PS, Vk:1600V, Imax at Vk:50mA, Rct@75 DEGREE CENTIGRADE ohm: <8Ω CLASS:PS, Vk:800V, Imax at Vk:50mA, Rct@75 DEGREE CENTIGRADE ohm: <4Ω CLASS:0.2, 30VA CLASS:PS, Vk:800V, Imax at Vk:50mA, Rct@75 DEGREE CENTIGRADE ohm: <4Ω CLASS:PS, Vk:800V, Imax at Vk:50mA, Rct@75 DEGREE CENTIGRADE ohm: <4Ω
9
Model setting calculation document for Auto Transformer
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
10
Model setting calculation document for Auto Transformer
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 2.1.1 Terminal Identification Station Name:
Station-A
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
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 RET670-1 relay and also indicates the functions/feature for which settings are provided in this document. The functions/features are indicative and vary with IED ordering code & IED application configuration. Table 2-1: List of functions in RET670-1 Sl.No.
Function/features available In RET670
Function/feature
Recommended
activated
Settings
Yes/No
provided
1
Analog Inputs
YES
2
Local Human-Machine Interface
YES
3
Indication LEDs
YES
4
Self supervision with internal event list
YES
5
Time Synchronization
YES
6
Parameter Setting Groups
YES
7
Test Mode Functionality TEST
YES
8
Change Lock CHNGLCK
NO
11
Model setting calculation document for Auto Transformer 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
YES
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
Transformer differential protection
YES
T3WPDIF 20
1Ph High impedance differential protection
NO
HZPDIF 21
Instantaneous Phase Overcurrent
NO
Protection PHPIOC 22
Four Step Phase Overcurrent Protection
YES
YES
OC4PTOC:1 23
Four Step Phase Overcurrent Protection OC4PTOC:2
24
Instantaneous Residual Overcurrent
NO
Protection EFPIOC 25
Four Step Residual Overcurrent Protection
YES
EF4PTOC 26
Four step directional negative phase
NO
sequence overcurrent protection NS4PTOC 27
Sensitive directional residual overcurrent
NO
and power protection SDEPSDE 28
Thermal overload protection, two time
YES
constants TRPTTR 29
Breaker failure protection CCRBRF
NO
30
Pole discordance protection CCRPLD
NO
12
Model setting calculation document for Auto Transformer 31
Directional underpower protection
NO
GUPPDUP 32
Overexcitation protection OEXPVPH
YES
33
Single Point Generic Control 8 Signals
NO
SPC8GGIO 34
Automationbits, Command Function For
NO
DNP3.0 AUTOBITS 35
Single Command, 16 Signals
NO
SINGLECMD 36
Scheme Communication Logic For
NO
Distance Or Overcurrent Protection ZCPSCH 37
Current Reversal And Weak-End Infeed
NO
Logic For Distance Protection ZCRWPSCH 38
Local Acceleration Logic ZCLCPLAL
NO
39
Direct Transfer Trip Logic
NO
40
Low Active Power And Power Factor
NO
Protection LAPPGAPC 41
Compensated Over and Undervoltage
NO
Protection COUVGAPC 42
Sudden Change in Current Variation
NO
SCCVPTOC 43
Carrier Receive Logic LCCRPTRC
NO
44
Negative Sequence Overvoltage
NO
Protection LCNSPTOV 45
Zero Sequence Overvoltage Protection
NO
LCZSPTOV 46
Negative Sequence Overcurrent
NO
Protection LCNSPTOC 47
Zero Sequence Overcurrent Protection
NO
LCZSPTOC 48
Three Phase Overcurrent LCP3PTOC
13
NO
Model setting calculation document for Auto Transformer 49
Three Phase Undercurrent LCP3PTUC
NO
50
Tripping Logic SMPPTRC
YES
51
Trip Matrix Logic TMAGGIO
YES
52
Configurable Logic Blocks
NO
53
Fixed Signal Function Block FXDSIGN
NO
54
Boolean 16 To Integer Conversion B16I
YES
55
Boolean 16 To Integer Conversion With
NO
Logic Node Representation B16IFCVI 56
Integer To Boolean 16 Conversion IB16
NO
57
Integer To Boolean 16 Conversion With
NO
Logic Node Representation IB16FCVB 58
Measurements CVMMXN
NO
59
Phase Current Measurement CMMXU
NO
60
Phase-Phase Voltage Measurement
NO
VMMXU 61
Current Sequence Component
NO
Measurement CMSQI 62
Voltage Sequence Measurement VMSQI
NO
63
Phase-Neutral Voltage Measurement
NO
VNMMXU 64
Event Counter CNTGGIO
NO
65
Event Function EVENT
NO
66
Logical Signal Status Report
NO
BINSTATREP 67
Fault Locator LMBRFLO
NO
68
Measured Value Expander Block
NO
RANGE_XP 69
Disturbance Report DRPRDRE
YES
70
Event List
NO
71
Indications
NO
72
Event Recorder
YES
73
Trip Value Recorder
YES
74
Disturbance Recorder
YES
14
Model setting calculation document for Auto Transformer 75
Pulse-Counter Logic PCGGIO
NO
76
Function For Energy Calculation And
NO
Demand Handling ETPMMTR 77
IEC 61850-8-1 Communication Protocol
NO
78
IEC 61850 Generic Communication I/O
NO
Functions SPGGIO, SP16GGIO 79
IEC 61850-8-1 Redundant Station Bus
NO
Communication 80
IEC 61850-9-2LE Communication Protocol
NO
81
LON Communication Protocol
NO
82
SPA Communication Protocol
NO
83
IEC 60870-5-103 Communication Protocol
NO
84
Multiple Command And Transmit
NO
MULTICMDRCV, MULTICMDSND 85
Remote Communication
NO
Note: For setting parameters provided in the function listed above, refer section 3 of application manual 1MRK504116-UEN, version 1.2.
15
Model setting calculation document for Auto Transformer
2.2 RET670-2 2.2.1 Terminal Identification Station Name:
Station-A
Object Name:
400/220/33kV Auto Transformer
Unit Name:
RET670-2 (Ver 1.2) -- REF and LV Over-fluxing relay, IV Back-up O/C & E/F relay#
Relay serial No:
XXXXXXXX
Frequency:
50Hz
Aux voltage:
220V DC
2.2.2 List of functions available and those used Table 2-2 gives the list of functions/features available in RET670-2 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 2-2: List of functions in RET670-2 Sl.No.
Function/features available In RET670
Function/feature
Recommended
activated
Settings
Yes/No
provided
1
Analog Inputs
YES
2
Local Human-Machine Interface
YES
3
Indication LEDs
YES
4
Self supervision with internal event list
YES
5
Time Synchronization
YES
6
Parameter Setting Groups
YES
7
Test Mode Functionality TEST
YES
8
Change Lock CHNGLCK
NO
9
IED Identifiers
YES
10
Product Information
YES
11
Rated System Frequency PRIMVAL
YES
12
Signal Matrix For Binary Inputs SMBI
YES
13
Signal Matrix For Binary Outputs SMBO
YES
16
Model setting calculation document for Auto Transformer 14
Signal Matrix For mA Inputs SMMI
YES
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
Transformer differential protection
NO
T3WPDIF 20
1Ph High impedance differential protection
YES
HZPDIF 21
Instantaneous Phase Overcurrent
NO
Protection PHPIOC 22
Four Step Phase Overcurrent Protection
YES
OC4PTOC 23
Instantaneous Residual Overcurrent
NO
Protection EFPIOC 24
Four Step Residual Overcurrent Protection
YES
EF4PTOC 25
Four step directional negative phase
NO
sequence overcurrent protection NS4PTOC 26
Sensitive directional residual overcurrent
NO
and power protection SDEPSDE 27
Thermal overload protection, two time
NO
constants TRPTTR 28
Breaker failure protection CCRBRF
NO
29
Pole discordance protection CCRPLD
NO
30
Directional underpower protection
NO
GUPPDUP 31
Overexcitation protection OEXPVPH
YES
32
Single Point Generic Control 8 Signals
NO
SPC8GGIO 33
Automationbits, Command Function For DNP3.0 AUTOBITS
17
NO
Model setting calculation document for Auto Transformer 34
Single Command, 16 Signals
NO
SINGLECMD 35
Scheme Communication Logic For
NO
Distance Or Overcurrent Protection ZCPSCH 36
Current Reversal And Weak-End Infeed
NO
Logic For Distance Protection ZCRWPSCH 37
Local Acceleration Logic ZCLCPLAL
NO
38
Direct Transfer Trip Logic
NO
39
Low Active Power And Power Factor
NO
Protection LAPPGAPC 40
Compensated Over and Undervoltage
NO
Protection COUVGAPC 41
Sudden Change in Current Variation
NO
SCCVPTOC 42
Carrier Receive Logic LCCRPTRC
NO
43
Negative Sequence Overvoltage
NO
Protection LCNSPTOV 44
Zero Sequence Overvoltage Protection
NO
LCZSPTOV 45
Negative Sequence Overcurrent
NO
Protection LCNSPTOC 46
Zero Sequence Overcurrent Protection
NO
LCZSPTOC 47
Three Phase Overcurrent LCP3PTOC
NO
48
Three Phase Undercurrent LCP3PTUC
NO
49
Tripping Logic SMPPTRC
YES
50
Trip Matrix Logic TMAGGIO
YES
51
Configurable Logic Blocks
NO
52
Fixed Signal Function Block FXDSIGN
NO
53
Boolean 16 To Integer Conversion B16I
YES
54
Boolean 16 To Integer Conversion With
NO
18
Model setting calculation document for Auto Transformer Logic Node Representation B16IFCVI 55
Integer To Boolean 16 Conversion IB16
NO
56
Integer To Boolean 16 Conversion With
NO
Logic Node Representation IB16FCVB 57
Measurements CVMMXN
NO
58
Phase Current Measurement CMMXU
NO
59
Phase-Phase Voltage Measurement
NO
VMMXU 60
Current Sequence Component
NO
Measurement CMSQI 61
Voltage Sequence Measurement VMSQI
NO
62
Phase-Neutral Voltage Measurement
NO
VNMMXU 63
Event Counter CNTGGIO
NO
64
Event Function EVENT
NO
65
Logical Signal Status Report
NO
BINSTATREP 66
Fault Locator LMBRFLO
NO
67
Measured Value Expander Block
NO
RANGE_XP 68
Disturbance Report DRPRDRE
YES
69
Event List
NO
70
Indications
NO
71
Event Recorder
YES
72
Trip Value Recorder
YES
73
Disturbance Recorder
YES
74
Pulse-Counter Logic PCGGIO
NO
75
Function For Energy Calculation And
NO
Demand Handling ETPMMTR 76
IEC 61850-8-1 Communication Protocol
NO
77
IEC 61850 Generic Communication I/O
NO
Functions SPGGIO, SP16GGIO 78
IEC 61850-8-1 Redundant Station Bus
19
NO
Model setting calculation document for Auto Transformer Communication 79
IEC 61850-9-2LE Communication Protocol
NO
80
LON Communication Protocol
NO
81
SPA Communication Protocol
NO
82
IEC 60870-5-103 Communication Protocol
NO
83
Multiple Command And Transmit
NO
MULTICMDRCV, MULTICMDSND 84
Remote Communication
NO
Note: For setting parameters provided in the function listed above, refer section 3 of application manual 1MRK504116-UEN, version 1.2.
20
Model setting calculation document for Auto Transformer
2.3 REC670 2.3.1 Terminal identification Station Name:
Station-A
Object Name:
400/220/33kV Auto Transformer
Unit Name:
REC670 (Ver 1.2)
Relay serial No:
XXXXX
Frequency:
50Hz
Aux voltage:
220V DC
2.3.2 List of functions available and those used Table 2-3 gives the list of functions/features available in REC670 relay and also indicates the functions/feature for which settings are provided in this document. The functions/feature are indicative and varies with IED ordering code & IED application configuration. Table 2-3: List of functions in REC670 Functions/Feature available In REC670 Sl.No.
Features/Functions
Recommended
activated
Settings
Yes/No
provided
1
Analog Inputs
YES
2
Indication LEDs
YES
3
Local Human-Machine Interface
YES
4
Self supervision with internal event list
YES
5
Time Synchronization
YES
6
Parameter Setting Groups
YES
7
Test Mode Functionality TEST
YES
8
Change Lock CHNGLCK
NO
9
IED Identifiers
YES
10
Product Information
YES
11
Rated System Frequency PRIMVAL
YES
12
Signal Matrix For Binary Inputs SMBI
YES
13
Signal Matrix For Binary Outputs SMBO
YES
21
Model setting calculation document for Auto Transformer 14
Signal Matrix For Ma Inputs SMMI
NO
15
Signal Matrix For Analog Inputs SMAI
YES
16
Summation Block 3 Phase 3PHSUM
NO
17
Authority Status ATHSTAT
NO
18
Denial Of Service DOS
NO
19
Differential Protection HZPDIF
NO
Instantaneous Phase Overcurrent
NO
20
21
22
23
24
25
26
27
Protection PHPIOC Four Step Phase Overcurrent Protection
NO
OC4PTOC Instantaneous Residual Overcurrent
NO
Protection EFPIOC Four Step Residual Overcurrent Protection
NO
EF4PTOC Four step directional negative phase
NO
sequence overcurrent protection NS4PTOC Sensitive Directional Residual Overcurrent
NO
And Power Protection SDEPSDE Thermal Overload Protection, One Time
NO
Constant LPTTR Thermal overload protection, two time
NO
constants TRPTTR
28
Breaker Failure Protection CCRBRF
NO
29
Stub Protection STBPTOC
NO
30
Pole Discordance Protection CCRPLD
NO
Directional Underpower Protection
NO
31
32
GUPPDUP Directional Overpower Protection
NO
GOPPDOP
33
Broken Conductor Check BRCPTOC
NO
34
Capacitor bank protection CBPGAPC
NO
35
Two Step Undervoltage Protection UV2PTUV Two Step Overvoltage Protection
NO
36
22
NO
Model setting calculation document for Auto Transformer OV2PTOV 37
Two Step Residual Overvoltage Protection
NO
ROV2PTOV
38
Voltage Differential Protection VDCPTOV
NO
39
Loss Of Voltage Check LOVPTUV
NO
40
Underfrequency Protection SAPTUF
NO
41
Overfrequency Protection SAPTOF
NO
Rate-Of-Change Frequency Protection
NO
42
43
SAPFRC General Current and Voltage Protection
NO
CVGAPC
44
Current Circuit Supervision CCSRDIF
NO
45
Fuse Failure Supervision SDDRFUF
NO
Synchrocheck, Energizing Check, And
YES
46
Synchronizing SESRSYN
47
Autorecloser SMBRREC
NO
48
Apparatus Control APC
NO
Horizontal Communication Via GOOSE For
NO
49
50 51 52
53
54 55
56
Interlocking GOOSEINTLKRCV Logic Rotating Switch For Function
NO
Selection And LHMI Presentation SLGGIO Selector Mini Switch VSGGIO
NO
Generic Double Point Function Block
NO
DPGGIO Single Point Generic Control 8 Signals
NO
SPC8GGIO Automationbits, Command Function For
NO
DNP3.0 AUTOBITS Single Command, 16 Signals SINGLECMD
NO
Scheme Communication Logic For
NO
Distance Or Overcurrent Protection ZCPSCH
57
Phase Segregated Scheme Communication
23
NO
Model setting calculation document for Auto Transformer Logic For Distance Protection ZC1PPSCH 58 59 60
Current Reversal And Weak-End Infeed Logic For Distance Protection ZCRWPSCH Local Acceleration Logic ZCLCPLAL
NO
Scheme Communication Logic For
NO
Residual Overcurrent Protection ECPSCH Current Reversal And Weak-End Infeed
61
NO
NO
Logic For Residual Overcurrent Protection ECRWPSCH Current Reversal And Weak-End Infeed
62
NO
Logic For Phase Segregated Communication ZC1WPSCH
63 64
65
66 67 68
69
70
71
Direct Transfer Trip Logic
NO
Low Active Power And Power Factor
NO
Protection LAPPGAPC Compensated Over And Undervoltage
NO
Protection COUVGAPC Sudden Change In Current Variation
NO
SCCVPTOC Carrier Receive Logic LCCRPTRC
NO
Negative Sequence Overvoltage Protection
NO
LCNSPTOV Zero Sequence Overvoltage Protection
NO
LCZSPTOV Negative Sequence Overcurrent Protection
NO
LCNSPTOC Zero Sequence Overcurrent Protection
NO
LCZSPTOC
72
Three Phase Overcurrent LCP3PTOC
NO
73
Three Phase Undercurrent LCP3PTUC
NO
74
Tripping Logic SMPPTRC
NO
75
Trip Matrix Logic TMAGGIO
NO
76
Configurable Logic Blocks
NO
24
Model setting calculation document for Auto Transformer 77
Fixed Signal Function Block FXDSIGN
NO
78
Boolean 16 To Integer Conversion B16I
NO
Boolean 16 To Integer Conversion With
NO
79 80 81
Logic Node Representation B16IFCVI Integer To Boolean 16 Conversion IB16
NO
Integer To Boolean 16 Conversion With
NO
Logic Node Representation IB16FCVB
82
Measurements CVMMXN
YES
83
Phase Current Measurement CMMXU
YES
Phase-Phase Voltage Measurement
YES
84
85 86 87
VMMXU Current Sequence Component
YES
Measurement CMSQI Voltage Sequence Measurement VMSQI
YES
Phase-Neutral Voltage Measurement
NO
VNMMXU
88
Event Counter CNTGGIO
YES
89
Event Function EVENT
YES
90
Logical Signal Status Report BINSTATREP
NO
91
Fault Locator LMBRFLO
NO
Measured Value Expander Block
NO
92
RANGE_XP
93
Disturbance Report DRPRDRE
NO
94
Event List
YES
95
Indications
YES
96
Event Recorder
YES
97
Trip Value Recorder
YES
98
Disturbance Recorder
YES
99
Pulse-Counter Logic PCGGIO
NO
Function For Energy Calculation And
NO
100
Demand Handling ETPMMTR
101
IEC 61850-8-1 Communication Protocol
NO
102
IEC 61850 Generic Communication I/O
NO
25
Model setting calculation document for Auto Transformer Functions SPGGIO, SP16GGIO 103
IEC 61850-8-1 Redundant Station Bus
NO
Communication
104 IEC 61850-9-2LE Communication Protocol
NO
105
LON Communication Protocol
NO
106
SPA Communication Protocol
NO
107 IEC 60870-5-103 Communication Protocol 108 109
Multiple Command And Transmit
NO NO
MULTICMDRCV, MULTICMDSND Remote Communication
NO
Note: For setting parameters provided in the function listed above, refer section 3 of application manual 1MRK511230-UEN, version 1.2.
26
Model setting calculation document for Auto Transformer
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 Guidelines for Settings: Configure analog inputs: Current analog inputs as: Name# CTprim CTsec
Ch 1 HV-IL1 1000A 1A
Ch 2 HV-IL2 1000A 1A
Ch 3 HV-IL3 1000A 1A
Ch 4 IV-IL1 800A 1A
Ch 5 IV-IL2 800A 1A
Ch 6 IV-IL3 800A 1A
CTStarPoint parameter indicates the CT secondary winding neutral earthing towards object (ToObject) or towards busbar (FromObject).
Voltage analog input as: Name# VTprim VTsec
Ch 1 UL1 400kV 110V
Ch 2 UL2 400kV 110V
Ch 3 UL3 400kV 110V
Ch 4 SPARE 400kV 110V
# User defined text
Recommended Settings: Table 3-1 gives the recommended settings for Analog inputs. 27
Ch 5 SPARE 400kV 110V
Ch 6 SPARE 400kV 110V
Model setting calculation document for Auto Transformer
Table 3-1: Analog inputs Setting Parameter PhaseAngleRef
CTStarPoint1
Recommended
Description Reference channel for phase angle Presentation ToObject= towards protected object, FromObject= the opposite
Settings
Unit
TRM40-Ch1
-
ToObject
-
CTsec1
Rated CT secondary current
1
A
CTprim1
Rated CT primary current
1000
A
ToObject
-
CTStarPoint2
ToObject= towards protected object, FromObject= the opposite
CTsec2
Rated CT secondary current
1A
A
CTprim2
Rated CT primary current
1000A
A
ToObject
-
CTStarPoint3
ToObject= towards protected object, FromObject= the opposite
CTsec3
Rated CT secondary current
1
A
CTprim3
Rated CT primary current
1000
A
ToObject
-
CTStarPoint4
ToObject= towards protected object, FromObject= the opposite
CTsec4
Rated CT secondary current
1
A
CTprim4
Rated CT primary current
800
A
ToObject
-
CTStarPoint5
ToObject= towards protected object, FromObject= the opposite
CTsec5
Rated CT secondary current
1
A
CTprim5
Rated CT primary current
800
A
CTStarPoint6
ToObject= towards protected object, FromObject= the opposite
ToObject
-
CTsec6
Rated CT secondary current
1
A
CTprim6
Rated CT primary current
800
A
VTsec7
Rated VT secondary voltage
110
V
VTprim7
Rated VT primary voltage
400
kV
VTsec8
Rated VT secondary voltage
110
V
28
Model setting calculation document for Auto Transformer VTprim8
Rated VT primary voltage
400
kV
VTsec9
Rated VT secondary voltage
110
V
VTprim9
Rated VT primary voltage
400
kV
VTsec10
Rated VT secondary voltage
110
V
VTprim10
Rated VT primary voltage
400
kV
VTsec11
Rated VT secondary voltage
110
V
VTprim11
Rated VT primary voltage
400
kV
VTsec12
Rated VT secondary voltage
110
V
VTprim12
Rated VT primary voltage
400
kV
Binary input module (BIM) Settings I/O Module 1 I/O Module 2 I/O Module 3 I/O Module 4 I/O Module 5
Operation On On On On On
OscBlock(Hz) 40 40 40 40 40
OscRelease(Hz) 30 30 30 30 30
Pos Slot3 Pos Slot3 Pos Slot3 Pos Slot3 Pos Slot3
Note: OscBlock and OscRelease defines the filtering time at activation. Low frequency gives slow response for digital input.
3.1.2 Local Human-Machine Interface Recommended Settings: Table 3-2 gives the recommended settings for Local human machine interface. Table 3-2: Local human machine interface Setting Parameter
Description
Language
Recommended Settings
Unit
Local HMI language
English
-
DisplayTimeout
Local HMI display timeout
60
Min
AutoRepeat
Activation of auto-repeat (On) or not (Off)
On
-
29
Model setting calculation document for Auto Transformer
Setting Parameter
Description
ContrastLevel
Recommended Settings
Unit
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.
Recommended Settings: Table 3-3 gives the recommended settings for Indication LEDs. Table 3-3: LEDGEN Non group settings (basic) Setting Parameter
Recommended
Description
Settings
Unit
Operation
Operation mode for the LED function
On
-
tRestart
Defines the disturbance length
0.0
s
0.0
s
tMax
Maximum time for the definition of a disturbance
SeqTypeLED1
Sequence type for LED 1
LatchedAck-S-F
-
SeqTypeLED2
Sequence type for LED 2
LatchedAck-S-F
-
SeqTypeLED3
Sequence type for LED 3
LatchedAck-S-F
-
SeqTypeLED4
Sequence type for LED 4
LatchedAck-S-F
-
30
Model setting calculation document for Auto Transformer SeqTypeLED5
Sequence type for LED 5
LatchedAck-S-F
-
SeqTypeLED6
Sequence type for LED 6
LatchedAck-S-F
-
SeqTypeLED7
Sequence type for LED 7
LatchedAck-S-F
-
SeqTypeLED8
Sequence type for LED 8
LatchedAck-S-F
-
SeqTypeLED9
Sequence type for LED 9
LatchedAck-S-F
-
SeqTypeLED10
Sequence type for LED 10
LatchedAck-S-F
-
SeqTypeLED11
Sequence type for LED 11
LatchedAck-S-F
-
SeqTypeLED12
Sequence type for LED 12
LatchedAck-S-F
-
SeqTypeLED13
Sequence type for LED 13
LatchedAck-S-F
-
SeqTypeLED14
Sequence type for LED 14
LatchedAck-S-F
-
SeqTypeLED15
Sequence type for LED 15
LatchedAck-S-F
-
3.1.4 Time Synchronization Guidelines for Settings: These settings are used for synchronizing IED clock time with network time. Ex: GPS or IRIG-B time. CoarseSyncSrc: Select the time synchronization source available such as SPA, LON, SNTP etc. Synchronization messages from sources configured as coarse are checked against the internal relay time and only if the difference in relay time and source time is more than 10s then relay time will be reset with the source time. This parameter need to be based on time source available in site. FineSyncSource: Select the time source available in network like IRIG-B, GPS, SNTP, SPA etc. once it is selected, time of available time source in network will update to relay if there is a difference in the time between relay and source. This parameter need to be based on time source available in site. SyncMaster: Normally it is set OFF. If time to the relay is received from a GPS antenna (example), make the relay as master to synchronize with other relays. TimeAdjustRate: Fast HWSyncSrc: This is applicable if process bus IEC61850-9-2 protocol is used for receiving analog values (optical CT PTs). In this case select time source available same as that of merging unit. This setting is not applicable in present case.
31
Model setting calculation document for Auto Transformer AppSynch: If there is any loss of time sync, protection function will be blocked if AppSynch set to Synch based on SyncAccLevel. If AppSunch set to NoSynch, protection functions are not blocked. Recommended setting is NoSynch. SyncAccLevel: If this is set to “Class T5 (1us)” and time synch error is more than 1us, protection functions will be blocked. SyncAccLevel should be set to “Unspecified” when Nosynch is selected at AppSynch. This parameter is not applicable in present case. ModulePosition: if BIN is set for FineSyncSource, ModulePosition setting is applicable. Here slot position of IO module in the relay is to be set (Which slot is used for BI). This parameter is not applicable in present case. BinaryInput: Which binary input is used for time sync input shall be set here. This parameter is applicable if BIN is set for FineSyncSource. This parameter is not applicable in present case. BinDetection: Which edge of input pulse need to be detected has to be set here (positive and negative). This parameter is applicable if BIN is set for FineSyncSource. This parameter is not applicable in present case. ServerIP-Add: Here set Time source server IP address. RedServIP-Add: If redundant server is available, set address of redundant server here. MonthInYear, DayInWeek, WeekInMonth and UTCTimeOfDay for DSTBEGIN and DSTEND are applicable where Day light saving is used. If it is not used set same date for both DSTBEGIN and DSTEND. This setting is not applicable in this case. NoHalfHourUTC: Time shift from GMT has to be set a multiple of half hours. Example for India it is +05:30, means +11. Hence this parameter is set to +11 in present case. SYNCHIRIG-B Non group settings: These settings are applicable if IRIG-B is used. This parameter is not applicable in present case. SynchType: Type of hardware input used for time sync, whether Opto or BNC. This parameter is not applicable in present case. TimeDomain: In present case this parameter is set to LocalTime. Encoding: In present case this parameter is set to IRIG-B. TimeZoneAs1344: In present case this parameter is set to PlusTZ.
Recommended Settings: Table 3-4 gives the recommended settings for Time synchronization.
32
Model setting calculation document for Auto Transformer
Table 3-4: Time synchronization settings TIMESYNCHGEN Non group settings (basic) Setting
Recommended
Description
Parameter
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
-
SYNCHBIN Non group settings (basic) Setting Parameter ModulePosition
BinaryInput BinDetection
Recommended
Description Hardware position of IO module for time Synchronization Binary input number for time synchronization Positive or negative edge detection
Settings
Unit
3
-
1
-
PositiveEdge
-
SYNCHSNTP Non group settings (basic) Setting Parameter
Description
ServerIP-Add RedServIP-Add
Recommended Settings
Unit
Server IP-address
0.0.0.0
IP Address
Redundant server IP-address
0.0.0.0
IP Address
33
Model setting calculation document for Auto Transformer
DSTBEGIN Non group settings (basic) Setting Parameter
Recommended
Description
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
-
3600
s
UTCTimeOfDay
UTC Time of day in seconds when daylight time starts
DSTEND Non group settings (basic) Setting Parameter
Recommended
Description
Settings
Unit
MonthInYear
Month in year when daylight time starts
October
-
DayInWeek
Day in week when daylight time starts
Sunday
-
WeekInMonth
Week in month when daylight time starts
Last
-
3600
s
UTCTimeOfDay
UTC Time of day in seconds when daylight time starts
TIMEZONE Non group settings (basic) Setting Parameter NoHalfHourUTC
Recommended
Description Number of half-hours from UTC
Settings
Unit
+11
-
SYNCHIRIG-B Non group settings (basic) Setting Parameter
Recommended
Description
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.
34
Model setting calculation document for Auto Transformer
3.1.5 Parameter Setting Groups Guidelines for Settings: t: The length of the pulse, sent out by the output signal SETCHGD when an active group has changed, is set with the parameter t. This is not the delay for changing setting group. This parameter is normally recommended to set 1s. MAXSETGR: The parameter MAXSETGR defines the maximum number of setting groups in use to switch between. Only the selected number of setting groups will be available in the Parameter Setting tool (PST) for activation with the ActiveGroup function block. This parameter is normally recommended to set 1.
Recommended Settings: Table 3-5 gives the recommended settings for Parameter setting group. Table 3-5: Parameter setting group ActiveGroup Non group settings (basic) Setting Parameter t
Recommended
Description Pulse length of pulse when setting Changed
Settings
Unit
1
s
SETGRPS Non group settings (basic) Setting Parameter
Recommended
Description
Settings
Unit
ActiveSetGrp
ActiveSettingGroup
SettingGroup1
-
MAXSETGR
Max number of setting groups 1-6
1
No
3.1.6 Test Mode Functionality TEST Guidelines for Settings: EventDisable: If it is ON, it will disable the events like in DR during test mode. Normally this parameter is set to OFF. CmdTestBit: In present case this parameter is set to Off.
35
Model setting calculation document for Auto Transformer
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 Parameter
Recommended
Description
Settings
Unit
TestMode
Test mode in operation (On) or not (Off)
Off
-
EventDisable
Event disable during testmode
Off
-
Off
-
CmdTestBit
Command bit for test required or not during testmode
3.1.7 IED Identifiers Recommended Settings: Table 3-7 gives the recommended settings for IED Identifiers. Table 3-7: IED Identifiers TERMINALID Non group settings (basic) Setting Parameter
Description
Recommended Settings
Unit
StationName
Station name
Station-A
-
StationNumber
Station number
0
-
ObjectName
Object name
Transformer
-
ObjectNumber
Object number
0
-
UnitName
Unit name
RET670 M1
-
UnitNumber
Unit number
0
-
3.1.8 Rated System Frequency PRIMVAL Recommended Settings: Table 3-8 gives the recommended settings for Rated system frequency.
36
Model setting calculation document for Auto Transformer Table 3-8: Rated system frequency PRIMVAL Non group settings (basic) Setting Parameter Frequency
Recommended
Description Rated system frequency
Settings
Unit
50.0
Hz
3.1.9 Signal Matrix For Analog Inputs SMAI Guidelines for Settings: DFTReference: Set ref for DFT filter adjustment here. These DFT reference block settings decide DFT reference for DFT calculations. The settings InternalDFTRef will use fixed DFT reference based on set system frequency. AdDFTRefChn will use DFT reference from the selected group block, when own group selected adaptive DFT reference will be used based on calculated signal frequency from own group. The setting ExternalDFTRef will use reference based on what is connected to input DFTSPFC. There are three different task groups of SMAI with 1ms, 3ms and 8ms. Use of each task group is based on requirement of function, like differential protection requires 1ms, which is faster. Each task group has 12 instances of SMAI, in that first instance has some additional features which is called master. Others are slaves and they will follow master. If measured sample rate needs to be transferred to other task group, it can be done only with master. Receiving task group SMAI DFTreference shall be set to External DFT Ref. DFTReference shall be set to default value InternalDFTRef if no VT input is available. Since VT input is available in this case, the corresponding channel shall be set to DFTReference. Configuration file has to be referred for this purpose. DFTRefExtOut: This parameter is available only in Master. If reference is to be sent to other task 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: 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.
37
Model setting calculation document for Auto Transformer If R, Y, B inputs are connected, N=R+Y+B, and it will do as above. This parameter is recommended to be set to OFF normally. MinValFreqMeas: Set the measured minimum value here. It is applicable only for voltage input. SMAI will work only if measured input magnitude is greater than set value in MinValFreqMeas. This parameter is recommended to set 10% normally. UBase: Set the base voltage here. This is parameter is set to 400kV.
Recommended Settings: Table 3-9 gives the recommended settings for Signal Matrix For Analog Inputs. Table 3-9: Signal Matrix For Analog Inputs Setting Parameter
Recommended
Description
Settings
Unit
DFTRefExtOut
DFT reference for external output
(As per configuration)
-
DFTReference
DFT reference
(As per configuration)
-
ConnectionType
Input connection type
Ph-Ph
-
TYPE
1=Voltage, 2=Current
1 or 2 based on input
Ch
Negation
Negation
Off
-
10
%
400
kV
MinValFreqMeas UBase
Limit for frequency calculation in % of UBase Base voltage
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
38
Model setting calculation document for Auto Transformer transformer windings to avoid false operation on external faults. The removed zero sequence component, however, makes the transformer differential relay less sensitive. The differential relay protection does an excellent job of meeting a large number of the protective relaying requirements, but must be combined with other protective devices to provide full transformer protection. In case of breaker and half switching schemes, the differential protection C.Ts. associated with Main and Tie breakers should be connected to separate bias windings and these should not be paralleled in order to avoid false operation due to dissimilar C.T. transient response. Differential protection is the most commonly applied protection for large power transformers in transmission system. Figure 3-1 shows the restrained and the unrestrained operate characteristics of Differential protection.
Figure 3-1: Representation of the restrained and the unrestrained operate characteristics 39
Model setting calculation document for Auto Transformer
Guidelines for Settings: 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 onload 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 onload 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). 40
Model setting calculation document for Auto Transformer Neither harmonic, nor any other restrain is applied to this limit, which is therefore allowed to trip power transformer instantaneously. Unrestrained operation level has default value of IdUnre = 10pu, which is typically acceptable for most of the standard power transformer applications. However in the following cases these setting need to be changed accordingly: • When CT from "T-connection" are connected to IED, as in the breaker-and-a half or the ring bus scheme, special care shall be taken in order to prevent unwanted operation of transformer differential IED for through-faults due to different CT saturation of "T-connected" CTs. Thus if such uneven saturation is a possibility it is typically required to increase unrestrained operational level to IdUnre = 20-25pu. Since in present case, uneven CT saturation is not expected, this parameter is set to 10pu. CrossBlockEn: In the algorithm the user can control the cross-blocking between the phases via the setting parameter CrossBlockEn. When parameter CrossBlockEn is set to On, cross blocking between phases will be introduced. There are no time related settings involved, but the phase with the operating point above the set bias characteristic will be able to cross-block other two phases if it is self-blocked by any of the previously explained restrained criteria. It is recommended to set this parameter to ON. When parameter CrossBlockEn is set to Off, any cross blocking between phases will be disabled. In present case it is set ON. NegSeqDiffEn: The internal/external fault discriminator is a very powerful and reliable supplementary criterion to the traditional differential protection. It is recommended that this feature shall be always used (that is, On) when protecting three-phase power transformers. The internal/external fault discriminator detects even minor faults, with a high sensitivity and at high speed, and at the same time discriminates with a high degree of dependability between internal and external faults. In the absence of credible field experience, it is set to OFF in the present case. IMinNegSeq and NegSeqROA: These parameters are not applicable if NegSeqDiffEn is set to OFF. EndSection1, EndSection2, SlopeSection2 and SlopeSection3: EndSection1 (End of section 1, as multiple of transformer HV side rated current set under the parameter RatedCurrentW1), EndSection2 (End of section 2, as multiple of transformer HV side rated current set under the parameter RatedCurrentW1), SlopeSection2 (Slope in section 2), SlopeSection3 (Slope in section 3). The selection of suitable characteristic should in such cases be based on the knowledge of the class of the current transformers, availability of information on the load tap changer position, short circuit power of the systems, and so on. 41
Model setting calculation document for Auto Transformer 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. 42
Model setting calculation document for Auto Transformer ConnectTypeW1: Connection type of winding 1: Y-wye or D-delta. This parameter is set to Y. ConnectTypeW2: Connection type of winding 2: 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. ClockNumberW3: Phase displacement between W3 & W1=HV winding, hour notation. This 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 parameter is set ON. 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. TconfigForW3: Two CT inputs (T-config.) for winding 3, YES / NO. In present case this parameter is set to No. CT1RatingW3, CT2RatingW3: These parameters are not applicable TconfigForW3 is set to 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”.
43
Model setting calculation document for Auto Transformer LowTapPosOLTC1,
RatedTapOLTC1,
HighTapPsOLTC1,
TapHighVoltTC1,
StepSizeOLTC1: These parameters are not applicable if LocationOLTC1 is set to “Not Used”. LocationOLTC2: Transformer winding where OLTC2 is Located. In present case, this is set to “Not Used”. LowTapPosOLTC2,
RatedTapOLTC2,
HighTapPsOLTC2,
TapHighVoltTC2,
StepSizeOLTC2: These parameters are not applicable if LocationOLTC2 is set to “Not Used”.
Recommended Settings: Table 3-10 gives the recommended settings for Differential protection. Table 3-10: Differential protection Settings T3WPDIF Group settings (basic) Setting Parameter
Recommended
Description
Settings
Unit
Operation
Operation Off / On
On
-
SOTFMode
Operation mode for switch onto fault feature
Off
-
15
s
0.10
IB
0.20
IB
10
IB
On
-
Off
-
0.04
IB
60.0
Deg
tAlarmDelay IDiffAlarm IdMin IdUnre CrossBlockEn NegSeqDiffEn IMinNegSeq NegSeqROA
Time delay for diff currents alarm level Dif. cur. alarm, multiple of base curr, usually W1 curr. Section1 sensitivity, multi. of base curr, usually W1 curr. Unrestr. prot. limit, multi. of base curr. usually W1 curr. Operation Off/On for cross-block logic between phases Operation Off/On for neg. seq. differential protections Neg. seq. curr. limit, mult. of base curr, usually W1 curr. Operate Angle for int. / ext. neg. seq. fault discriminator
T3WPDIF Group settings (advanced) Setting Parameter
Recommended
Description
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
44
Model setting calculation document for Auto Transformer usually W1 curr. Slope in section 2 of operate-restrain characteristic, in % Slope in section 3 of operate-restrain SlopeSection3 characteristic, in % Max. ratio of 2nd harm. to fundamental I2/I1Ratio harm dif. curr. in % Max. ratio of 5th harm. to fundamental I5/I1Ratio harm dif. curr. in % Open CT detection feature. Open OpenCTEnable CTEnable Off/On Open CT: time in s to alarm after an tOCTAlarmDelay open CT is detected tOCTResetDelay Reset delay in s. After delay, diff. function is activated tOCTUnrstDelay Unrestrained diff. protection blocked after this delay, in s SlopeSection2
40
%
80
%
15
%
25
%
Off
-
3
s
0.25
s
10.0
s
T3WPDIF Non group settings (basic) Setting Parameter RatedVoltageW1 RatedVoltageW2 RatedVoltageW3 RatedCurrentW1 RatedCurrentW2 RatedCurrentW3 ConnectTypeW1 ConnectTypeW2 ConnectTypeW3 ClockNumberW2 ClockNumberW3 ZSCurrSubtrW1 ZSCurrSubtrW2
Recommended
Description Rated voltage of transformer winding 1 (HV winding) in kV Rated voltage of transformer winding 2 in kV Rated voltage of transformer winding 3 in kV Rated current of transformer winding 1 (HV winding) in A Rated current of transformer winding 2 in A Rated current of transformer winding 3 in A Connection type of winding 1: Y-wye or D-delta Connection type of winding 2: Y-wye or D-delta Connection type of winding 3: Y-wye or D-delta Phase displacement between W2 & W1=HV winding, hour notation Phase displacement between W3 & W1=HV winding, hour notation Enable zer. seq. current subtraction for W1 side, On / Off Enable zer. seq. current subtraction for W2 side, On / Off 45
Settings
Unit
400
kV
220
kV
33
kV
455
A
827
A
1837
A
WYE(Y)
-
WYE(Y)
-
Delta (D)
-
0 [0 deg]
-
11[30 deg lead]
-
On
-
On
-
Model setting calculation document for Auto Transformer
ZSCurrSubtrW3 TconfigForW1 CT1RatingW1 CT2RatingW1 TconfigForW2 CT1RatingW2 CT2RatingW2 TconfigForW3 CT1RatingW3 CT2RatingW3 LocationOLTC1 LowTapPosOLTC 1 RatedTapOLTC1 HighTapPsOLTC 1 TapHighVoltTC1 StepSizeOLTC1 LocationOLTC2 LowTapPosOLTC 2 RatedTapOLTC2 HighTapPsOLTC 2 TapHighVoltTC2 StepSizeOLTC2
Enable zer. seq. current subtraction for W3 side, On / Off Two CT inputs (T-config.) for winding 1, YES / NO CT primary rating in A, T-branch 1, on transf. W1 side CT primary in A, T-branch 2, on transf. W1 side Two CT inputs (T-config.) for winding 2, YES / NO CT primary rating in A, T-branch 1, on transf. W2 side CT primary rating in A, T-branch 2, on transf. W2 side Two CT inputs (T-config.) for winding 3, YES / NO CT primary rating in A, T-branch 1, on transf. W3 side CT primary rating in A, T-branch 2, on transf. W3 side Transformer winding where OLTC1 is located
Off
-
Yes
-
1000
A
1000
A
No
-
800
A
800
A
No
-
1000
A
1000
A
Not Used
-
OLTC1 lowest tap position designation (e.g. 1)
1
-
OLTC1 rated tap/mid-tap position designation (e.g. 6)
6
-
OLTC1 highest tap position designation (e.g. 11)
11
-
OLTC1 end-tap position with winding highest no-load voltage Voltage change per OLTC1 step in percent of rated voltage Transformer winding where OLTC2 is located
1
-
1.0
%
Not Used
-
OLTC2 lowest tap position designation (e.g. 1)
1
-
OLTC2 rated tap/mid-tap position designation (e.g. 6)
6
-
OLTC2 highest tap position designation (e.g. 11)
11
-
OLTC2 end-tap position with winding highest no-load voltage Voltage change per OLTC2 step in percent of rated voltage
1
-
1.0
%
46
Model setting calculation document for Auto Transformer
3.1.11 Tripping Logic SMPPTRC Guidelines for Setting: 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. 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. 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.
Recommended Settings: Table 3-11 gives the recommended settings for Tripping Logic. Table 3-11: Tripping Logic Setting Parameter Operation Program tTripMin tWaitForPHS
TripLockout
AutoLock
Recommended
Description Operation Off / On Three ph; single or three ph; single, two or three ph trip Minimum duration of trip output signal Secures 3-pole trip when phase selection failed On: activate output (CLLKOUT) and trip latch, Off: only outp On: lockout from input (SETLKOUT) and trip, Off: only inp
47
Settings
Unit
On
-
3 phase
-
0.150
s
0.020
s
Off
-
Off
-
Model setting calculation document for Auto Transformer
3.1.12 Trip Matrix Logic TMAGGIO Guidelines for Setting: This function is only for the OR operation of any signals (normally used for trip signals). For example, all Differential, REF, 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 selected, output will be same as that of SMPPTRC.
Recommended Settings: Table 3-12 gives the recommended settings for Trip Matrix Logic. Table 3-12: Trip Matrix Logic Setting Parameter
Recommended
Description
Settings
Unit
Operation
Operation Off / On
On
-
PulseTime
Output pulse time
0.0
s
OnDelay
Output on delay time
0.0
s
OffDelay
Output off delay time
0.0
s
ModeOutput1 Mode for output ,1 steady or pulsed
Steady
-
ModeOutput2 Mode for output 2, steady or pulsed
Steady
-
ModeOutput3 Mode for output 3, steady or pulsed
Steady
-
48
Model setting calculation document for Auto Transformer
3.1.13 Four Step Phase Overcurrent Protection OC4PTOC:1 (Used for HV side) The phase over current protection is a very inexpensive, simple and reliable scheme for fault detection and is used for transformer protection applications. It can provide limited overload protection but cannot provide instantaneous protection for all internal faults. It can also provide back-up protection for bus bars. It does provide for transformer fault withstand protection and some limited over load protection. It can provide back-up for failure of the switching device but only with very long time delays. In normal applications, directional over current relays are located on both the HV and IV sides of the transformer. Both relays are set to see into the transformer. This allows better coordination with external over current relays because of the need to see only part of the transformer windings. An additional high set unit is also usually provided. The instantaneous elements help in providing high-speed clearance of heavy current faults that threaten system stability. The relay (Instantaneous element) suffers from having to be set very high to prevent tripping on transformer inrush. Therefore it is ineffective for low magnitude internal transformer faults or phase to ground faults on the low voltage side of the transformer. Numerical over current relays provide upgraded performance for transformer back-up protection. The digital filters remove the DC component and harmonics from the inrush current. Numerical back-up over current relays can therefore be set much more sensitive than conventional types and are recommended to be used. The non-directional over current relays are used when they could be coordinated with the over current protection on connecting lines. Coordination requirements usually require the clearing times to be longer than the other types of back-up protection. Directional over current relay improves the co-ordination by being set to look through the transformer impedance. For this reason they are normally used for all interconnecting transformers. When applied on both sides of the transformer, the current levels where coordination with line relaying is required is limited by the transformer impedance which greatly improves the tripping times for higher current faults in the transformer. The directional ground over current relay can be set much more sensitive and with very short time delays. For all interconnecting transformers use of directional over current and ground over current relays with high set units are recommended. There are number of general problems with back-up relay viz., the sensitivity to the harmonic and inrush currents. Setting must be able to allow inrush, which usually means de-sensitizing the
49
Model setting calculation document for Auto Transformer 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.
Guidelines for Setting: 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
50
Model setting calculation document for Auto Transformer 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 current in present case. 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 not applicable in present case, setting is left with default value of 1. DirMode2: Setting of the operating direction for the stage or switch it off. This parameter is set 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 51
Model setting calculation document for Auto Transformer 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 50100ms. 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”. IMin2: Minimum operate current for step2 in % of IBase. This parameter is set to 800% of base current in present case. t2Min: Set the Minimum operating time for inverse characteristic. This parameter is not applicable in present case since Characteristic2 is set to “IEC Def. Time”. I2Mult: Set the current multiplier for I2 valid at activation of input ENMULT. As this parameter is not applicable in present case, setting is left with default value of 1. 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. tReset1: Set the Reset time delay for definite time delayed function. This parameter is not applicable if ResetTypeCrv1 is set to Instantaneous. tPCrv1, tACrv1, tBCrv1, tCCrv1, tPRCrv1, tTRCrv1 and tCRCrv1: These parameters are applicable only if Characterist1 is set to Programmable. HarmRestrain1: Set the release of Harmonic restraint blocking for the stage. This parameter is kept ON to make the protection stable during charging conditions. ResetTypeCrv2: 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. tReset2: Set the Reset time delay for definite time delayed function. This parameter is not applicable if ResetTypeCrv1 is set to Instantaneous. tPCrv2, tACrv2, tBCrv2, tCCrv2, tPRCrv2, tTRCrv2 and tCRCrv2: These parameters are applicable only if Characterist2 is set to Programmable.
52
Model setting calculation document for Auto Transformer HarmRestrain2: Set the release of Harmonic restraint blocking for the stage. This parameter is kept ON to make the protection stable during charging conditions.
Setting Calculations: I1>: This parameter is set to 150% of base current in present case, which is 683A in primary. k1 (TMS): This parameter is set to 0.26 in present case. I2>: This parameter is set to 800% of base current in present case, which is 3640A in primary. t2: This parameter is set to 0.05s in present case. Refer Appendix for more details of above four settings.
Recommended Settings: Table 3-13 gives the recommended settings for Four Step Phase Overcurrent Protection. Table 3-13: Four Step Phase Overcurrent Protection OC4PTOC Group settings (basic) Setting Parameter
Recommended
Description
Settings
Unit
Operation
Operation Off / On
On
-
IBase
Base value for current settings
455
A
400
kV
UBase
Base value for voltage settings. (Check with PT input in configuration )
AngleRCA
Relay characteristic angle (RCA)
65
Deg
AngleROA
Relay operation angle (ROA)
80
Deg
1 out of 3
-
Forward
-
IEC Norm. Invr.
-
150
%IB
0
s
0.26
-
150%
%IB
StartPhSel
DirMode1 Characterist1 I1> t1 k1 IMin1
Number of phases required for op (1 of 3, 2 of 3, 3 of 3) Directional mode of step 1 (off, nodir, forward, reverse) Time delay curve type for step 1 Phase current operate level for step1 in % of IBase Definitive time delay of step 1 Time multiplier for the inverse time delay for step 1 Minimum operate current for step1 in % 53
Model setting calculation document for Auto Transformer of IBase t1Min
I1Mult
DirMode2 Characterist2 I2> t2 k2
IMin2
t2Min
I2Mult
DirMode3
DirMode4
Minimum operate time for inverse curves for step 1 Multiplier for scaling the current setting value for step 1 Directional mode of step 2 (off, nodir, forward, reverse) Time delay curve type for step 2 Phase current operate level for step2 in % of IBase Definitive time delay of step 2 Time multiplier for the inverse time delay for step 2 Minimum operate current for step2 in % of IBase Minimum operate time for inverse curves for step 2 Multiplier for scaling the current setting value for step 2 Directional mode of step 3 (off, nondir, forward, reverse) Directional mode of step 4 (off, nondir, forward, reverse)
0.1
s
1.0
-
Non-directional
-
IEC Def. Time
-
800
%IB
0.05
s
0
-
800%
%IB
0
s
1.0
-
Off
-
Off
-
OC4PTOC Group settings (advanced) IMinOpPhSel
2ndHarmStab
Minimum current for phase selection in % of IBase Second harmonic restrain operation in % of IN amplitude
ResetTypeCrv1 Selection of reset curve type for step 1 tReset1 tPCrv1
Reset time delay used in IEC Definite Time curve step 1 Parameter P for customer programmable curve for step 1 54
7
%IB
15
%
Instantaneous
-
0.020
s
1
-
Model setting calculation document for Auto Transformer
tACrv1
tBCrv1
tCCrv1
tPRCrv1
tTRCrv1
tCRCrv1 HarmRestrain1
Parameter A for customer programmable curve for step 1 Parameter B for customer programmable curve for step 1 Parameter C for customer programmable curve for step 1 Parameter PR for customer programmable curve for step 1 Parameter TR for customer programmable curve for step 1 Parameter CR for customer programmable curve for step 1 Enable block of step 1 from harmonic restrain
ResetTypeCrv2 Selection of reset curve type for step 2 tReset2
tPCrv2
tACrv2
tBCrv2
tCCrv2
tPRCrv2
tTRCrv2
tCRCrv2 HarmRestrain2
Reset time delay used in IEC Definite Time curve step 2 Parameter P for customer programmable curve for step 2 Parameter A for customer programmable curve for step 2 Parameter B for customer programmable curve for step 2 Parameter C for customer programmable curve for step 2 Parameter PR for customer programmable curve for step 2 Parameter TR for customer programmable curve for step 2 Parameter CR for customer programmable curve for step 2 Enable block of step 2 from harmonic restrain
55
13.5
-
0
-
1
-
0.5
-
13.5
-
1
-
On
-
Instantaneous
-
0.020
s
1
-
13.5
-
0
-
1
-
0.5
-
13.5
-
1
-
On
-
Model setting calculation document for Auto Transformer
3.1.14 Four Step Phase Overcurrent Protection OC4PTOC:2
(Used for HV side
Overload alarm)
This function is used for Transformer Over load protection. Oil Temperature Sensors The top oil temperature sensors can detect overheating. The temperature limit settings vary from utility to utility and also depend upon manufacturer's recommendations. Typical settings are 95°C for alarm and 100°C for trip. Bec ause of the heating and cooling requirements of a transmission power transformer some specialized temperature protection is required to provide protection over the full range of operating limits of the transformer. The transformer temperature depends upon the ambient temperature, the cooling system condition, the excitation voltage and the transformer load. To provide for temperature protection a sensor is usually provided to indicate top oil temperature. The power transformers have a large thermal heat sink and can withstand overloads for certain limited time. Selective protection, monitoring and load management are considered necessary. The tripping of the transformer should be the last action. Winding Temperature Sensors Winding temperature sensors can detect overheating. The temperature limit settings vary from utility to utility and also depend upon manufacturer's recommendations. Typical settings are 100°C for alarm and 110°C for trip. To simulate the winding temperature, a resistor sized to approximate the heating in the transformer winding at full load is used. The resistor is fed by a current transformer from one of the phase currents. To add oil temperature, the top oil is circulated in to a well within the resistor. This combined heating of the resistor from transformer current and top oil, is used to simulate the winding temperature. These two relays do not meet any of the other requirements but are again the only relays which meet the over load temperature limit requirements. For higher reliability duplicating of the initiating contacts is sometimes done and may be considered on a case-to-case basis. Overload Relay It is also a practice to use a simple over current relay with a time delay arranged to give alarm to warn the operator of any overloading of the transformer. Use of thermal relay to provide tripping 56
Model setting calculation document for Auto Transformer 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.
Guidelines for Setting: 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. This parameter is not applicable in present case, since DirMode1 is set to Non-directional. 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°. This parameter is not applicable in present case, since DirMode1 is set to Non-directional. AngleROA: Set the relay operating angle, i.e the angle sector of the directional function. This 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 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 “Non-directional” in present case. Characteristic1: Setting of the operating characteristic. This parameter is set to “IEC Def. Time” in present case. I1>: Setting of the operating current level in primary values. This parameter is set to 105% of base current in present case. t1: This is the definite time delay for step-I. In present case this parameter is set to 5s. k1: Set the back-up trip time delay multiplier for inverse characteristic. This parameter is not applicable in present case, since Characteristic1 is set to IEC Def. Time. IMin1: Minimum operate current for step1 in % of IBase. This parameter is set to 105% of base current in present case. 57
Model setting calculation document for Auto Transformer t1Min: Set the Minimum operating time for inverse characteristic. This parameter is not applicable in present case, since Characteristic1 is set to IEC Def. Time. I1Mult: Set the current multiplier for I1 valid at activation of input ENMULT. As this parameter is not applicable in present case, setting is left with default value of 1. DirMode2, DirMode3 and DirMode4: Setting of the operating direction for the stage or switch it off. All three stages are set to OFF. 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. tReset1: Set the Reset time delay for definite time delayed function. This parameter is not applicable if ResetTypeCrv1 is set to Instantaneous. tPCrv1, tACrv1, tBCrv1, tCCrv1, tPRCrv1, tTRCrv1 and tCRCrv1: These parameters are applicable only if Characterist1 is set to Programmable. HarmRestrain1: Set the release of Harmonic restraint blocking for the stage. This parameter is kept ON to make the protection stable during charging conditions.
Recommended Settings: Table 3-14 gives the recommended settings for Four Step Phase Overcurrent Protection. Table 3-14: Four Step Phase Overcurrent Protection OC4PTOC Group settings (basic) Setting Parameter
Recommended
Description
Settings
Unit
Operation
Operation Off / On
On
-
IBase
Base value for current settings
455
A
400
kV
UBase
Base value for voltage settings. (Check with PT input in configuration )
AngleRCA
Relay characteristic angle (RCA)
65
Deg
AngleROA
Relay operation angle (ROA)
80
Deg
1 out of 3
-
Non-directional
-
StartPhSel
DirMode1
Number of phases required for op (1 of 3, 2 of 3, 3 of 3) Directional mode of step 1 (off, nodir, forward, reverse)
58
Model setting calculation document for Auto Transformer Characterist1 I1> t1 k1
IMin1
t1Min
I1Mult
DirMode2
DirMode3
DirMode4
Time delay curve type for step 1 Phase current operate level for step1 in % of IBase Definitive time delay of step 1 Time multiplier for the inverse time delay for step 1 Minimum operate current for step1 in % of IBase Minimum operate time for inverse curves for step 1 Multiplier for scaling the current setting value for step 1 Directional mode of step 2 (off, nodir, forward, reverse) Directional mode of step 3 (off, nondir, forward, reverse) Directional mode of step 4 (off, nondir, forward, reverse)
IEC Dif. Time
-
105
%IB
5
s
0.3
-
105
%IB
0
s
1.0
-
Off
-
Off
-
Off
-
7
%IB
20
%
Instantaneous
-
0.020
s
1
-
13.5
-
0
-
OC4PTOC Group settings (advanced) IMinOpPhSel
2ndHarmStab
Minimum current for phase selection in % of IBase Second harmonic restrain operation in % of IN amplitude
ResetTypeCrv1 Selection of reset curve type for step 1 tReset1
tPCrv1
tACrv1
tBCrv1
Reset time delay used in IEC Definite Time curve step 1 Parameter P for customer programmable curve for step 1 Parameter A for customer programmable curve for step 1 Parameter B for customer programmable curve for step 1
59
Model setting calculation document for Auto Transformer
tCCrv1
tPRCrv1
tTRCrv1
tCRCrv1
HarmRestrain1
Parameter C for customer programmable curve for step 1 Parameter PR for customer programmable curve for step 1 Parameter TR for customer programmable curve for step 1 Parameter CR for customer programmable curve for step 1 Enable block of step 1 from harmonic restrain
1
-
0.5
-
13.5
-
1
-
On
-
Important note: The above function used for overload alarm shall be configured for alarm and no trip in the signal matrix of IED.
3.1.15 Four Step Residual Overcurrent Protection EF4PTOC (Used for HV side) Various ground fault protections used are described below. Generally, these protections are meant to provide the grounded winding with a low sensitivity ground fault protection only. They do not provide other types of protection. Zero Sequence Over Current Relays Zero-sequence over current relays provide protection against internal phase-to-ground faults. The neutral current or the residual current may energize the over current relay. The setting may be much lower than the rated phase current. Harmonic restraint may be required to obtain sensitive settings. An additional high set unit is also usually provided. Directional Earth Fault Relay This type of protection is also specific to transformers with at least one directly grounded or resistance grounded winding. The protection is specialized to protect for winding faults to ground. The connections of the over current units can be only in the neutral, or in the residual phase. These connections can be set much lower than the phase over current because of the cancellation of the phase current.
60
Model setting calculation document for Auto Transformer The sensitivity to the harmonic and inrush currents can be one of the main problems with backup 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.
Guidelines for Setting: Figure 3-3 shows the Operating characteristic for earth-fault directional element.
Figure 3-3: Operating characteristic for earth-fault directional element
61
Model setting calculation document for Auto Transformer 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. 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. 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. 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 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 (TMS) for inverse characteristic. Refer Appendix for more details. t1Min: Set the Minimum operating time for inverse characteristic. This parameter is set to 0.1s 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 to make the protection stable during charging conditions. tPCrv1, tACrv1, tBCrv1, tCCrv1, tPRCrv1, tTRCrv1 and tCRCrv1: These parameters are applicable only if Characterist1 is set to Programmable.
62
Model setting calculation document for Auto Transformer DirMode2: Setting of the operating direction for the stage or switch it off. This parameter is set to “Non-directional” in present case. Characteristic2: Setting of the operating characteristic. This parameter is set to “IEC Def. Time” in present case. 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. 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 is set to 50ms in present case. 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 applicable in present case since Characteristic2 is set to “IEC Def. Time”. ResetTypeCrv2: 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. tReset2: Set the Reset time delay for definite time delayed function. This parameter is not applicable if ResetTypeCrv1 is set to Instantaneous. HarmRestrain2: Set the release of Harmonic restraint blocking for the stage. This parameter is kept ON to make the protection stable during charging conditions. tPCrv2, tACrv2, tBCrv2, tCCrv2, tPRCrv2, tTRCrv2 and tCRCrv2: These parameters are applicable only if Characterist2 is set to Programmable. 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”. 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°. 63
Model setting calculation document for Auto Transformer 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%. BlkParTransf: Set the harmonic seal-in blocking at parallel transformers on if problems are expected due to sympathetic inrush. If residual current is higher during switching of a transformer connecting in parallel with other transformer and if 2nd harmonic current is lower than 2ndHarmStab set value, earth fault protection may operate because of high residual current. Inrush current in Line CTs may be higher at beginning and later it may be reduced. If “BlkParTransf” is set ON, protection will be blocked till residual current is lower than set pickup of selected “UseStartValue”. This parameter is normally recommended to be set to OFF. UseStartValue:
Select a step which is set for sensitive earth fault protection for above
blocking. This parameter is not applicable if BlkParTransf is set to OFF. SOTF: Set the SOTF function operating mode. If “SOTF” is set ON, as per the logic given in TRM, trip from SOTF requires start of step-2 or step-3 along with the activation of breaker closing command. Since Directional earth function has IDMT characteristics, SOTF is set to OFF. ActivationSOTF, ActUndertime, t4U, tSOTF, tUndertime, HarmResSOTF: These parameters are not applicable if SOTF is set to OFF.
Setting Calculations: IN1>: This parameter is set to 20% of base current in present case, which is 91A in primary. k1 (TMS): This parameter is set to 0.58 in present case. IN2>: This parameter is set to 800% of base current in present case, which is 3640A in primary. t2: This parameter is set to 0.05s in present case. Refer Appendix for more details of above four settings.
Recommended Settings: Table 3-15 gives the recommended settings for Four Step Residual Overcurrent Protection.
64
Model setting calculation document for Auto Transformer
Table 3-15: Four Step Residual Overcurrent Protection Setting Parameter
Recommended
Description
Settings
Unit
Operation
Operation Off / On
On
-
IBase
Base value for current settings
455
A
400
kV
UBase
Base value for voltage settings. (Check with PT input in configuration )
AngleRCA
Relay characteristic angle (RCA)
65
Deg
polMethod
Type of polarization
Voltage
-
1
%UB
5
%IB
5
Ohm
40
ohm
10
%IB
15
%
Off
-
IN4>
-
Off
-
ActivationSOTF Select signal that shall activate SOTF
Open
-
StepForSOTF
Step 2
-
UPolMin
IPolMin
RNPol
XNPol
IN>Dir
2ndHarmStab BlkParTransf UseStartValue
SOTF
Minimum voltage level for polarization in % of UBase Minimum current level for polarization in % of IBase Real part of source Z to be used for current polar-isation Imaginary part of source Z to be used for current polarisation Residual current level for Direction release in % of IBase Second harmonic restrain operation in % of IN amplitude Enable blocking at paral-lel transformers Current level blk at paral-lel transf (step1, 2, 3 or 4) SOTF operation mode (Off/SOTF/Undertime/SOTF+undertime)
Selection of step used for SOTF
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
-
65
Model setting calculation document for Auto Transformer forward, reverse) Characterist1 IN1> t1 k1
Time delay curve type for step 1 Operate residual current level for step 1 in % of IBase
IEC Norm. Invr.
-
20
%IB
Independent (definite) time delay of step 1 0 Time multiplier for the dependent time
s
0.58
-
1.0
-
0.1
s
ResetTypeCrv1 Reset curve type for step 1
Instantaneous
-
tReset1
0.0
s
On
-
1
-
13.5
-
0
-
1
-
0.5
-
13.5
-
1
-
Non-directional
-
IN1Mult
t1Min
HarmRestrain1
tPCrv1
tACrv1
tBCrv1
tCCrv1
tPRCrv1
tTRCrv1
tCRCrv1
DirMode2
delay for step 1 Multiplier for scaling the current setting value for step 1 Minimum operate time for inverse curves for step 1
Reset time delay for step 1 Enable block of step 1 from harmonic restrain Parameter P for customer programmable curve for step 1 Parameter A for customer programmable curve for step 1 Parameter B for customer programmable curve for step 1 Parameter C for customer programmable curve for step 1 Parameter PR for customer programmable curve for step 1 Parameter TR for customer programmable curve for step 1 Parameter CR for customer programmable curve for step 1 Directional mode of step 2 (off, nondir, forward, reverse)
Characterist2
Time delay curve type for step 2
IEC Def. Time
-
IN2>
Operate residual current level for step 2 in
800
%IB
66
Model setting calculation document for Auto Transformer % of IBase t2 k2
Independent (definite) time delay of step 2 0.05 Time multiplier for the dependent time
s
0.0
-
1.0
-
0
s
ResetTypeCrv2 Reset curve type for step 2
Instantaneous
-
tReset2
0.020
s
On
-
1
-
13.5
-
0
-
1
-
0.5
-
13.5
-
1
-
Off
-
Off
-
IN2Mult
t2Min
HarmRestrain2
tPCrv2
tACrv2
tBCrv2
tCCrv2
tPRCrv2
tTRCrv2
tCRCrv2
DirMode3
DirMode4
delay for step 2 Multiplier for scaling the current setting value for step 2 Minimum operate time for inverse curves for step 2
Reset time delay for step 2 Enable block of step 2 from harmonic restrain Parameter P for customer programmable curve for step 2 Parameter A for customer programmable curve for step 2 Parameter B for customer programmable curve for step 2 Parameter C for customer programmable curve for step 2 Parameter PR for customer programmable curve for step 2 Parameter TR for customer programmable curve for step 2 Parameter CR for customer programmable curve for step 2 Directional mode of step 3 (off, nondir, forward, reverse) Directional mode of step 4 (off, nondir, forward, reverse)
67
Model setting calculation document for Auto Transformer
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.
Guidelines for Setting: 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 68
Model setting calculation document for Auto Transformer 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.
69
Model setting calculation document for Auto Transformer A typical overexcitation capability curve and V/Hz protection settings for power transformer is illustrated in Figure 3-4.
Figure 3-4: A typical overexcitation capability curve and V/Hz protection settings for power transformer
Setting Calculations: 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
70
Model setting calculation document for Auto Transformer will be allocated to these values of overexcitation. In this case, each step will be (150-110) /5 = 8%, since V/Hz>> is set to 150% and V/Hz> is set to 110% of rated V/Hz. 90% of its capability limits is considered for tripping. For example, if transformer can withstand 126% of Overflux till 55s from Overfluxing curve, we have set trip time 0.9 x 55 = 49.5s in relay to protect transformer before entering danger zone. The settings of time delays t1 to t6 are listed in table below. Figure 3-5 shows the tailor made curve for Over fluxing protection.
U/F %
Timer
Time set (s)
110
t1
9000
118
t2
90
126
t3
49.5
134
t4
18
142
t5
4
150
t6
1
Figure 3-5: Relay tailor made curve and Transformer withstand limit curve (V/Hz Vs s)
71
Model setting calculation document for Auto Transformer
Recommended Settings: Table 3-16 gives the recommended settings for Overexcitation protection. Table 3-16: Overexcitation protection OEXPVPH OEXPVPH Group settings (basic) Setting Parameter
Recommended
Description
Settings
Unit
Operation
Operation Off / On
On
-
IBase
Base current (rated phase current) in A
455
A
UBase
Base voltage (main voltage) in kV
400
kV
110
%UB/f
150
%UB/f
0.000
Ohm
0.150
s
1
s
9000
s
1200
s
Tailor made
-
1
-
V/Hz>
V/Hz>>
XLeak TrPulse tMin
tMax
tCooling
CurveType
kForIEEE
Operate level of V/Hz at no load and rated freq in % of (Ubase/frated) High level of V/Hz above which tMin is used, in % of (Ubase/frated) Winding leakage reactance in primary ohms Length of the pulse for trip signal (in sec) Minimum trip delay for V/Hz inverse curve, in sec Maximum trip delay for V/Hz inverse curve, in sec Transformer magnetic core cooling time constant, in sec Inverse time curve selection, IEEE/Tailor made Time multiplier for IEEE inverse type curve
AlarmLevel
Alarm operate level as % of operate level
98
%
tAlarm
Alarm time delay, in sec
5
s
72
Model setting calculation document for Auto Transformer
OEXPVPH Group settings (advanced) Setting Parameter t1Tailor
Recommended
Description Time delay t1 (longest) for tailor made curve, in sec
Settings
Unit
9000
s
t2Tailor
Time delay t2 for tailor made curve, in sec
90
s
t3Tailor
Time delay t3 for tailor made curve, in sec
49.5
s
t4Tailor
Time delay t4 for tailor made curve, in sec
18
s
t5Tailor
Time delay t5 for tailor made curve, in sec
4
s
1
s
T6Tailor
Time delay t6 (shortest) for tailor made curve, in sec
OEXPVPH Non group settings (basic) Setting Parameter
Recommended
Description
Settings
Unit
MeasuredU
Selection of measured voltage
PosSeq
-
MeasuredI
Selection of measured current
PosSeq
-
3.1.17 Disturbance Report DRPRDRE Guidelines for Setting: 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 400kV Main Bay CT: IA IB IC IN From 400kV Tie Bay CT:
73
Model setting calculation document for Auto Transformer IA IB IC IN From 220kV CT: IA IB IC IN From 400kV Bus PT: VAN VBN VCN Recommended Digital Signals for triggering (Typical) — Gr-A Trip — Gr-B Trip — Intertrip from 220kV Receive — 400kV Bus bar trip — Main/Tie CB LBB Optd. List of signals used for Analog triggering of DR — 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 74
Model setting calculation document for Auto Transformer — 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 0.5s. 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 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.
Recommended Settings: Table 3-17 gives the recommended settings for Disturbance Report. Table 3-17: Disturbance Report Setting Parameter
Recommended
Description
Settings
Unit
Operation
Operation Off/On
On
-
PreFaultRecT
Pre-fault recording time
0.5
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
-
1
Ch
Off
-
ZeroAngleRef OpModeTest
Reference channel (voltage), phasors, frequency measurement Operation mode during test mode
75
Model setting calculation document for Auto Transformer
3.2 RET670-2 3.2.1 Analog Inputs Guidelines for Settings: Configure analog inputs: Current analog inputs as: Name# CTprim CTsec
Ch 1 REF 1 1A
Ch 2 MV OC-R 800 1A
Ch 3 MV OC-Y 800 1A
Ch 4 MV OC-B 800 1A
Ch 5 SPARE 1000 1A
Ch 6 SPARE 1000 1A
CTStarPoint parameter indicates the CT secondary winding neutral earthing towards object (ToObject) or towards busbar (FromObject). Voltage analog input as: Name# VTprim VTsec
Ch 1 UL1-MV 220kV 110V
Ch 2 UL2-MV 220kV 110V
Ch 3 UL3-MV 220kV 110V
Ch 4 SPARE 220kV 110V
Ch 5 SPARE 220kV 110V
Ch 6 SPARE 220kV 110V
# User defined text
Recommended Settings: Table 3-18 gives the recommended settings for Analog inputs. Table 3-18: Analog inputs Setting Parameter PhaseAngleRef
CTStarPoint1
Recommended
Description Reference channel for phase angle Presentation ToObject= towards protected object, FromObject= the opposite
Settings
Unit
TRM40-Ch1
-
ToObject
-
CTsec1
Rated CT secondary current
1
A
CTprim1
Rated CT primary current
1
A
ToObject
-
CTStarPoint2
ToObject= towards protected object, FromObject= the opposite 76
Model setting calculation document for Auto Transformer CTsec2
Rated CT secondary current
1
A
CTprim2
Rated CT primary current
800
A
ToObject
-
CTStarPoint3
ToObject= towards protected object, FromObject= the opposite
CTsec3
Rated CT secondary current
1
A
CTprim3
Rated CT primary current
800
A
ToObject
-
CTStarPoint4
ToObject= towards protected object, FromObject= the opposite
CTsec4
Rated CT secondary current
1
A
CTprim4
Rated CT primary current
800
A
ToObject
-
CTStarPoint5
ToObject= towards protected object, FromObject= the opposite
CTsec5
Rated CT secondary current
1
A
CTprim5
Rated CT primary current
1000
A
CTStarPoint6
ToObject= towards protected object, FromObject= the opposite
ToObject
-
CTsec6
Rated CT secondary current
1
A
CTprim6
Rated CT primary current
1000
A
VTsec7
Rated VT secondary voltage
110
V
VTprim7
Rated VT primary voltage
220
kV
VTsec8
Rated VT secondary voltage
110
V
VTprim8
Rated VT primary voltage
220
kV
VTsec9
Rated VT secondary voltage
110
V
VTprim9
Rated VT primary voltage
220
kV
VTsec10
Rated VT secondary voltage
110
V
VTprim10
Rated VT primary voltage
220
kV
VTsec11
Rated VT secondary voltage
110
V
VTprim11
Rated VT primary voltage
220
kV
VTsec12
Rated VT secondary voltage
110
V
VTprim12
Rated VT primary voltage
220
kV
77
Model setting calculation document for Auto Transformer
Binary input module (BIM) Settings I/O Module 1 I/O Module 2 I/O Module 3 I/O Module 4 I/O Module 5
Operation On On On On On
OscBlock(Hz) 40 40 40 40 40
OscRelease(Hz) 30 30 30 30 30
Pos Slot3 Pos Slot3 Pos Slot3 Pos Slot3 Pos Slot3
Note: OscBlock and OscRelease define the filtering time at activation. Low frequency gives slow response for digital input.
3.2.2 Local Human-Machine Interface Recommended Settings: Table 3-19 gives the recommended settings for Local human machine interface. Table 3-19: Local human machine interface Setting Parameter
Description
Language
Recommended Settings
Unit
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
-
3.2.3 Indication LEDs Guidelines for Settings: This function block is to control LEDs in HMI. 78
Model setting calculation document for Auto Transformer 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.
Recommended Settings: Table 3-20 gives the recommended settings for Indication LEDs. Table 3-20: LEDGEN Non group settings (basic) Setting Parameter
Recommended
Description
Settings
Unit
Operation
Operation mode for the LED function
On
-
tRestart
Defines the disturbance length
0.0
s
0.0
s
tMax
Maximum time for the definition of a disturbance
SeqTypeLED1
Sequence type for LED 1
LatchedAck-S-F
-
SeqTypeLED2
Sequence type for LED 2
LatchedAck-S-F
-
SeqTypeLED3
Sequence type for LED 3
LatchedAck-S-F
-
SeqTypeLED4
Sequence type for LED 4
LatchedAck-S-F
-
SeqTypeLED5
Sequence type for LED 5
LatchedAck-S-F
-
SeqTypeLED6
Sequence type for LED 6
LatchedAck-S-F
-
SeqTypeLED7
Sequence type for LED 7
LatchedAck-S-F
-
SeqTypeLED8
Sequence type for LED 8
LatchedAck-S-F
-
SeqTypeLED9
Sequence type for LED 9
LatchedAck-S-F
-
SeqTypeLED10
Sequence type for LED 10
LatchedAck-S-F
-
SeqTypeLED11
Sequence type for LED 11
LatchedAck-S-F
-
SeqTypeLED12
Sequence type for LED 12
LatchedAck-S-F
-
SeqTypeLED13
Sequence type for LED 13
LatchedAck-S-F
-
SeqTypeLED14
Sequence type for LED 14
LatchedAck-S-F
-
SeqTypeLED15
Sequence type for LED 15
LatchedAck-S-F
-
79
Model setting calculation document for Auto Transformer
3.2.4 Time Synchronization Guidelines for Settings: These settings are used for synchronizing IED clock time with network time. Ex: GPS or IRIG-B time. CoarseSyncSrc: Select the time synchronization source available such as SPA, LON, SNTP etc. Synchronization messages from sources configured as coarse are checked against the internal relay time and only if the difference in relay time and source time is more than 10s then relay time will be reset with the source time. This parameter need to be based on time source available in site. FineSyncSource: Select the time source available in network like IRIG-B, GPS, SNTP, SPA etc. once it is selected, time of available time source in network will update to relay if there is a difference in the time between relay and source. This parameter need to be based on time source available in site. SyncMaster: Normally it is set OFF. If time to the relay is received from a GPS antenna (example), make the relay as master to synchronize with other relays. TimeAdjustRate: Fast HWSyncSrc: This is applicable if process bus IEC61850-9-2 protocol is used for receiving analog values (optical CT PTs). In this case select time source available same as that of merging unit. This setting is not applicable in present case. AppSynch: If there is any loss of time sync, protection function will be blocked if AppSynch set to Synch based on SyncAccLevel. If AppSunch set to NoSynch, protection functions are not blocked. Recommended setting is NoSynch. SyncAccLevel: If this is set to “Class T5 (1us)” and time synch error is more than 1us, protection functions will be blocked. SyncAccLevel should be set to “Unspecified” when Nosynch is selected at AppSynch. This parameter is not applicable in present case. ModulePosition: if BIN is set for FineSyncSource, ModulePosition setting is applicable. Here slot position of IO module in the relay is to be set (Which slot is used for BI). This parameter is not applicable in present case. BinaryInput: Which binary input is used for time sync input shall be set here. This parameter is applicable if BIN is set for FineSyncSource. This parameter is not applicable in present case. BinDetection: Which edge of input pulse need to be detected has to be set here (positive and negative). This parameter is applicable if BIN is set for FineSyncSource. This parameter is not applicable in present case.
80
Model setting calculation document for Auto Transformer ServerIP-Add: Here set Time source server IP address. RedServIP-Add: If redundant server is available, set address of redundant server here. MonthInYear, DayInWeek, WeekInMonth and UTCTimeOfDay for DSTBEGIN and DSTEND are applicable where Day light saving is used. If it is not used set same date for both DSTBEGIN and DSTEND. This setting is not applicable in this case. NoHalfHourUTC: Time shift from GMT has to be set a multiple of half hours. Example for India it is +05:30, means +11. Hence this parameter is set to +11 in present case. SYNCHIRIG-B Non group settings: These settings are applicable if IRIG-B is used. This parameter is not applicable in present case. SynchType: Type of hardware input used for time sync, whether Opto or BNC. This parameter is not applicable in present case. TimeDomain: In present case this parameter is set to LocalTime. Encoding: In present case this parameter is set to IRIG-B. TimeZoneAs1344: In present case this parameter is set to PlusTZ.
Recommended Settings: Table 3-21 gives the recommended settings for Time synchronization. Table 3-21: Time synchronization settings TIMESYNCHGEN Non group settings (basic) Setting Parameter
Recommended
Description
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
-
SYNCHBIN Non group settings (basic) Setting Parameter ModulePosition
Recommended
Description Hardware position of IO module for time Synchronization 81
Settings
Unit
3
-
Model setting calculation document for Auto Transformer
BinaryInput BinDetection
Binary input number for time synchronization Positive or negative edge detection
1
-
PositiveEdge
-
SYNCHSNTP Non group settings (basic) Setting Parameter
Description
ServerIP-Add RedServIP-Add
Recommended Settings
Unit
Server IP-address
0.0.0.0
IP Address
Redundant server IP-address
0.0.0.0
IP Address
DSTBEGIN Non group settings (basic) Setting Parameter
Recommended
Description
Settings
Unit
MonthInYear
Month in year when daylight time starts
March
-
DayInWeek
Day in week when daylight time starts
Sunday
-
Last
-
3600
s
WeekInMonth
UTCTimeOfDay
Week in month when daylight time starts UTC Time of day in seconds when daylight time starts
DSTEND Non group settings (basic) Setting Parameter
Recommended
Description
Settings
Unit
MonthInYear
Month in year when daylight time starts
October
-
DayInWeek
Day in week when daylight time starts
Sunday
-
Last
-
3600
s
WeekInMonth
UTCTimeOfDay
Week in month when daylight time starts UTC Time of day in seconds when daylight time starts
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Model setting calculation document for Auto Transformer
TIMEZONE Non group settings (basic) Setting Parameter NoHalfHourUTC
Recommended
Description Number of half-hours from UTC
Settings
Unit
+11
-
SYNCHIRIG-B Non group settings (basic) Setting Parameter
Recommended
Description
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.
3.2.5 Parameter Setting Groups Guidelines for Settings: t: The length of the pulse, sent out by the output signal SETCHGD when an active group has changed, is set with the parameter t. This is not the delay for changing setting group. This parameter is normally recommended to set 1s. MAXSETGR: The parameter MAXSETGR defines the maximum number of setting groups in use to switch between. Only the selected number of setting groups will be available in the Parameter Setting tool (PST) for activation with the ActiveGroup function block. This parameter is normally recommended to set 1.
Recommended Settings: Table 3-22 gives the recommended settings for Parameter setting group.
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Model setting calculation document for Auto Transformer
Table 3-22: Parameter setting group ActiveGroup Non group settings (basic) Setting Parameter t
Recommended
Description Pulse length of pulse when setting Changed
Settings
Unit
1
s
SETGRPS Non group settings (basic) Setting Parameter
Recommended
Description
Settings
Unit
ActiveSetGrp
ActiveSettingGroup
SettingGroup1
-
MAXSETGR
Max number of setting groups 1-6
1
No
3.2.6 Test Mode Functionality TEST Guidelines for Settings: EventDisable: If it is ON, it will disable the events like in DR during test mode. Normally this parameter is set to OFF. CmdTestBit: In present case this parameter is set to Off.
Recommended Settings: Table 3-23 gives the recommended settings for Test mode functionality. Table 3-23: Test mode functionality TESTMODE Non group settings (basic) Setting Parameter
Recommended
Description
Settings
Unit
TestMode
Test mode in operation (On) or not (Off)
Off
-
EventDisable
Event disable during testmode
Off
-
Off
-
CmdTestBit
Command bit for test required or not during testmode
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Model setting calculation document for Auto Transformer
3.2.7 IED Identifiers Recommended Settings: Table 3-24 gives the recommended settings for IED Identifiers. Table 3-24: IED Identifiers TERMINALID Non group settings (basic) Setting
Description
Parameter
Recommended Settings
Unit
StationName
Station name
Station-A
-
StationNumber
Station number
0
-
ObjectName
Object name
Transformer
-
ObjectNumber
Object number
0
-
UnitName
Unit name
RET670 M2
-
UnitNumber
Unit number
0
-
3.2.8 Rated System Frequency PRIMVAL Recommended Settings: Table 3-25 gives the recommended settings for Rated system frequency. Table 3-25: Rated system frequency PRIMVAL Non group settings (basic) Setting Parameter Frequency
Recommended
Description Rated system frequency
Settings
Unit
50.0
Hz
3.2.9 Signal Matrix For Analog Inputs SMAI Guidelines for Settings: DFTReference: Set ref for DFT filter adjustment here. These DFT reference block settings decide DFT reference for DFT calculations.
85
Model setting calculation document for Auto Transformer 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 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 220kV.
Recommended Settings: Table 3-26 gives the recommended settings for Signal Matrix For Analog Inputs.
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Model setting calculation document for Auto Transformer
Table 3-26: Signal Matrix For Analog Inputs Setting Parameter
Recommended
Description
Settings
Unit
DFTRefExtOut
DFT reference for external output
(As per configuration)
-
DFTReference
DFT reference
(As per configuration)
-
ConnectionType
Input connection type
Ph-Ph
-
TYPE
1=Voltage, 2=Current
1 or 2 based on input
Ch
Negation
Negation
Off
-
10
%
220
kV
MinValFreqMeas UBase
Limit for frequency calculation in % of UBase Base voltage
3.2.10 1Ph High impedance differential protection HZPDIF Zero- sequence differential relays (Restricted earth fault relay) provide best protection against phase-to-ground faults in transformers connected to solidly grounded systems or resistance grounded transformers. The residual current and the neutral current energize the relay. Whenever separate phase-wise C.Ts are available on neutral side of transformer, triple pole high impedance relay may be provided instead of single pole R.E.F. relay.
Guidelines for Setting: 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.
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Model setting calculation document for Auto Transformer
Setting Calculations: 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. 88
Model setting calculation document for Auto Transformer Irelay = relay set operation current in secondary Amps = 20mA in present case. Iu = leakage current through the Voltage Dependent Resistor (VDR) at stabilizing voltage Us = 3mA Approximate value of the current thorough non-linear resistor for the voltage of 68V (Us) is 3mA. This is considered from the Current voltage characteristics for the non-linear resistors. m = number of CTs connected in parallel in the secondary circuit = 4 in present case. Im = magnetizing current of the CT at stabilizing voltage Us = 2mA in present case. This value is calculated by using CT magnetizing current 60mA at Vk and Vk = 2000V. By using above values, Iprim = 1000 x (20+ 3 + 3x2) = 29A. Kindly Note that the following requirements for applying High impedance differential relays. •
Turns ratios of CTs should be identical
•
Auxiliary CTs should not be used
•
Loop impedance (Rct+2Rl) up to the CT paralleling point should be identical
•
Magnetizing characteristics should be identical
Recommended Settings: Table 3-27 gives the recommended settings for 1Ph High impedance differential protection. Table 3-27: 1Ph High impedance differential protection HZPDIF Setting Parameter Operation U>Alarm tAlarm U>Trip SeriesResistor
Recommended
Description Operation Off / On Alarm voltage level in volts on CT secondary side Time delay to activate alarm Operate voltage level in volts on CT secondary side Value of series resistor in Ohms
Settings
Unit
On
-
13.6
V
5
s
68
V
3400
ohm
Note: The respective analog channel in RET670 (For REF current input) should be set to 1:1.
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Model setting calculation document for Auto Transformer
3.2.11 Four Step Phase Overcurrent Protection OC4PTOC---(For IV side) The phase over current threshold should be set to ensure detection of all phase faults, but above any continuous phase current under normal system operation. The timing should be coordinated with the upstream phase over current protection. The guiding philosophy is similar to the one described for the HV back-up overcurrent function in RET670-1 (Refer Figure 3-2).
Guidelines for Setting: IBase: Set the Base current for the function on which the current levels are based. This parameter is set to 827A in present case, which is Transformer IV winding rated current. UBase: Setting of the Base voltage level on which the directional polarizing voltage is based. This parameter is set to 220kV in present case, which is Transformer IV 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 op (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. 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 current in present case. t1Min: Set the Minimum operating time for inverse characteristic. This parameter is set to 0.1s in present case.
90
Model setting calculation document for Auto Transformer I1Mult: Set the current multiplier for I1 valid at activation of input ENMULT. As this parameter is not applicable in present case, setting is left with default value of 1. DirMode2: Setting of the operating direction for the stage or switch it off. This parameter is set 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 130% of maximum transformer 1-phase through fault current or transformer inrush current whichever is higher. 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 is set to 50ms in present case. 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”. IMin2: Minimum operate current for step2 in % of IBase. This parameter is set to 800% of base current in present case. t2Min: Set the Minimum operating time for inverse characteristic. This parameter is not applicable in present case since Characteristic2 is set to “IEC Def. Time”. I2Mult: Set the current multiplier for I2 valid at activation of input ENMULT. As this parameter is not applicable in present case, setting is left with default value of 1. 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. tReset1: Set the Reset time delay for definite time delayed function. This parameter is not applicable if ResetTypeCrv1 is set to Instantaneous. tPCrv1, tACrv1, tBCrv1, tCCrv1, tPRCrv1, tTRCrv1 and tCRCrv1: These parameters are applicable only if Characterist1 is set to Programmable. HarmRestrain1: Set the release of Harmonic restraint blocking for the stage. This parameter is kept ON to make the protection stable during charging conditions. ResetTypeCrv2: 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. 91
Model setting calculation document for Auto Transformer tReset2: Set the Reset time delay for definite time delayed function. This parameter is not applicable if ResetTypeCrv1 is set to Instantaneous. tPCrv2, tACrv2, tBCrv2, tCCrv2, tPRCrv2, tTRCrv2 and tCRCrv2: These parameters are applicable only if Characterist2 is set to Programmable. HarmRestrain2: Set the release of Harmonic restraint blocking for the stage. This parameter is kept ON to make the protection stable during charging conditions.
Setting Calculations: I1>: This parameter is set to 150% of base current in present case, which is 909.7A in primary. k1 (TMS): This parameter is set to 0.18 in present case. I2>: This parameter is set to 800% of base current in present case, which is 6616A in primary. t2: This parameter is set to 0.05s in present case. Refer Appendix for more details of above four settings.
Recommended Settings: Table 3-28 gives the recommended settings for Four Step Phase Overcurrent Protection. Table 3-28: Four Step Phase Overcurrent Protection OC4PTOC Group settings (basic) Setting Parameter
Recommended
Description
Settings
Unit
Operation
Operation Off / On
On
-
IBase
Base value for current settings
827
A
220
kV
UBase
Base value for voltage settings. (Check with PT input in configuration )
AngleRCA
Relay characteristic angle (RCA)
65
Deg
AngleROA
Relay operation angle (ROA)
80
Deg
1 out of 3
-
Forward
-
IEC Norm. Invr.
-
150
%IB
StartPhSel
DirMode1 Characterist1 I1>
Number of phases required for op (1 of 3, 2 of 3, 3 of 3) Directional mode of step 1 (off, nodir, forward, reverse) Time delay curve type for step 1 Phase current operate level for step1 in % of IBase 92
Model setting calculation document for Auto Transformer t1 k1
IMin1
t1Min
I1Mult
DirMode2 Characterist2 I2> t2 k2
IMin2
t2Min
I2Mult
DirMode3
DirMode4
Definitive time delay of step 1 Time multiplier for the inverse time delay for step 1 Minimum operate current for step1 in % of IBase Minimum operate time for inverse curves for step 1 Multiplier for scaling the current setting value for step 1 Directional mode of step 2 (off, nodir, forward, reverse) Time delay curve type for step 2 Phase current operate level for step2 in % of IBase Definitive time delay of step 2 Time multiplier for the inverse time delay for step 2 Minimum operate current for step2 in % of IBase Minimum operate time for inverse curves for step 2 Multiplier for scaling the current setting value for step 2 Directional mode of step 3 (off, nondir, forward, reverse) Directional mode of step 4 (off, nondir, forward, reverse)
93
0
s
0.18
-
150
%IB
0.1
s
1.0
-
Non-directional
-
IEC Def. Time
-
800
%IB
0.05
s
0.3
-
800%
%IB
0
s
1.0
-
Off
-
Off
-
Model setting calculation document for Auto Transformer
OC4PTOC Group settings (advanced) IMinOpPhSel
2ndHarmStab
Minimum current for phase selection in % of IBase Second harmonic restrain operation in % of IN amplitude
ResetTypeCrv1 Selection of reset curve type for step 1 tReset1
tPCrv1
tACrv1
tBCrv1
tCCrv1
tPRCrv1
tTRCrv1
tCRCrv1
HarmRestrain1
Reset time delay used in IEC Definite Time curve step 1 Parameter P for customer programmable curve for step 1 Parameter A for customer programmable curve for step 1 Parameter B for customer programmable curve for step 1 Parameter C for customer programmable curve for step 1 Parameter PR for customer programmable curve for step 1 Parameter TR for customer programmable curve for step 1 Parameter CR for customer programmable curve for step 1 Enable block of step 1 from harmonic restrain
ResetTypeCrv2 Selection of reset curve type for step 2 tReset2
tPCrv2
tACrv2
tBCrv2
Reset time delay used in IEC Definite Time curve step 2 Parameter P for customer programmable curve for step 2 Parameter A for customer programmable curve for step 2 Parameter B for customer programmable curve for step 2 94
7
%IB
20
%
Instantaneous
-
0.020
s
1
-
13.5
-
0
-
1
-
0.5
-
13.5
-
1
-
On
-
Instantaneous
-
0.020
s
1
-
13.5
-
0
-
Model setting calculation document for Auto Transformer
tCCrv2
tPRCrv2
tTRCrv2
tCRCrv2
HarmRestrain2
Parameter C for customer programmable curve for step 2 Parameter PR for customer programmable curve for step 2 Parameter TR for customer programmable curve for step 2 Parameter CR for customer programmable curve for step 2 Enable block of step 2 from harmonic restrain
1
-
0.5
-
13.5
-
1
-
On
-
3.2.12 Four Step Residual Overcurrent Protection EF4PTOC---(for IV side) Guiding philosophy for this function is similar to that described for HV back-up earth fault function in RET670-1 (Refer Figure 3-3).
Guidelines for Setting: 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 upstream backup protection including Zone-3 timing for a remote end 400kV bus fault. IBase: Set the Base current for the function on which the current levels are based. This parameter is set to 827A in present case, which is Transformer IV winding rated current. UBase: Setting of the Base voltage level on which the directional polarizing voltage is based. This parameter is set to 220kV in present case, which is Transformer IV winding rated voltage. 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. IN1>: Setting of the operating current level in primary values. This parameter is set to 20% of base current in present case.
95
Model setting calculation document for Auto Transformer 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 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. t1Min: Set the Minimum operating time for inverse characteristic. This parameter is set to 0.1s 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 to make the protection stable during charging conditions. tPCrv1, tACrv1, tBCrv1, tCCrv1, tPRCrv1, tTRCrv1 and tCRCrv1: These parameters are applicable only if Characterist1 is set to Programmable. DirMode2: Setting of the operating direction for the stage or switch it off. This parameter is set to “Non-directional” in present case. Characteristic2: Setting of the operating characteristic. This parameter is set to “IEC Def. Time” in present case. IN2>: Setting of the operating current level in primary values. Normally this parameter shall be set to 130% of maximum transformer through fault current. 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 is set to 50ms in present case. 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 applicable in present case since Characteristic2 is set to “IEC Def. Time”.
96
Model setting calculation document for Auto Transformer ResetTypeCrv2: 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. tReset2: Set the Reset time delay for definite time delayed function. This parameter is not applicable if ResetTypeCrv1 is set to Instantaneous. HarmRestrain2: Set the release of Harmonic restraint blocking for the stage. This parameter is kept ON to make the protection stable during charging conditions. tPCrv2, tACrv2, tBCrv2, tCCrv2, tPRCrv2, tTRCrv2 and tCRCrv2: These parameters are applicable only if Characterist2 is set to Programmable. 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”. 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 97
Model setting calculation document for Auto Transformer closing command. Since Directional earth function has IDMT characteristics, SOTF is set to OFF. ActivationSOTF, ActUndertime, t4U, tSOTF, tUndertime, HarmResSOTF: These parameters are not applicable if SOTF is set to OFF.
Setting Calculations: IN1>: This parameter is set to 20% of base current in present case, which is 91A in primary. k1 (TMS): This parameter is set to 0.51 in present case. IN2>: This parameter is set to 800% of base current in present case, which is 6616A in primary. t2: This parameter is set to 0.05s in present case. Refer Appendix for more details of above four settings.
Recommended Settings: Table 3-29 gives the recommended settings for Four Step Residual Overcurrent Protection. Table 3-29: Four Step Residual Overcurrent Protection Setting Parameter
Recommended
Description
Settings
Unit
Operation
Operation Off / On
On
-
IBase
Base value for current settings
827
A
220
kV
UBase
Base value for voltage settings. (Check with PT input in configuration )
AngleRCA
Relay characteristic angle (RCA)
65
Deg
polMethod
Type of polarization
Voltage
-
1
%UB
5
%IB
5
Ohm
40
ohm
10
%IB
UPolMin
IPolMin
RNPol
XNPol
IN>Dir
Minimum voltage level for polarization in % of UBase Minimum current level for polarization in % of IBase Real part of source Z to be used for current polar-isation Imaginary part of source Z to be used for current polarisation Residual current level for Direction release in % of IBase 98
Model setting calculation document for Auto Transformer
2ndHarmStab
Second harmonic restrain operation in %
15
%
Off
-
IN4>
-
Off
-
ActivationSOTF Select signal that shall activate SOTF
Open
-
StepForSOTF
Step 2
-
BlkParTransf UseStartValue
SOTF
of IN amplitude Enable blocking at paral-lel transformers Current level blk at paral-lel transf (step1, 2, 3 or 4) SOTF operation mode (Off/SOTF/Undertime/SOTF+undertime)
Selection of step used for SOTF
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
Forward
-
IEC Norm. Invr.
-
20
%IB
DirMode1 Characterist1 IN1> t1 k1
Directional mode of step 1 (off, nodir, forward, reverse) Time delay curve type for step 1 Operate residual current level for step 1 in % of IBase
Independent (definite) time delay of step 1 0 Time multiplier for the dependent time
s
0.51
-
1.0
-
0
s
ResetTypeCrv1 Reset curve type for step 1
Instantaneous
-
tReset1
0.020
s
On
-
1
-
13.5
-
0
-
IN1Mult
t1Min
HarmRestrain1
tPCrv1 tACrv1 tBCrv1
delay for step 1 Multiplier for scaling the current setting value for step 1 Minimum operate time for inverse curves for step 1
Reset time delay for step 1 Enable block of step 1 from harmonic restrain Parameter P for customer programmable curve for step 1 Parameter A for customer programmable curve for step 1 Parameter B for customer programmable curve for step 1 99
Model setting calculation document for Auto Transformer
tCCrv1
tPRCrv1
tTRCrv1
tCRCrv1
DirMode2 Characterist2 IN2> t2 k2
Parameter C for customer programmable curve for step 1 Parameter PR for customer programmable curve for step 1 Parameter TR for customer programmable curve for step 1 Parameter CR for customer programmable curve for step 1 Directional mode of step 2 (off, nondir, forward, reverse) Time delay curve type for step 2 Operate residual current level for step 2 in % of IBase
1
-
0.5
-
13.5
-
1
-
Non-directional
-
IEC Def. Time
-
800
%IB
Independent (definite) time delay of step 2 0.05 Time multiplier for the dependent time
s
0.0
-
1.0
-
0
s
ResetTypeCrv2 Reset curve type for step 2
Instantaneous
-
tReset2
0.020
s
On
-
1
-
13.5
-
0
-
1
-
0.5
-
IN2Mult
t2Min
HarmRestrain2
tPCrv2
tACrv2
tBCrv2 tCCrv2 tPRCrv2
delay for step 2 Multiplier for scaling the current setting value for step 2 Minimum operate time for inverse curves for step 2
Reset time delay for step 2 Enable block of step 2 from harmonic restrain Parameter P for customer programmable curve for step 2 Parameter A for customer programmable curve for step 2 Parameter B for customer programmable curve for step 2 Parameter C for customer programmable curve for step 2 Parameter PR for customer programmable curve for step 2 100
Model setting calculation document for Auto Transformer
tTRCrv2
tCRCrv2
DirMode3
DirMode4
Parameter TR for customer programmable curve for step 2 Parameter CR for customer programmable curve for step 2 Directional mode of step 3 (off, nondir, forward, reverse) Directional mode of step 4 (off, nondir, forward, reverse)
13.5
-
1
-
Off
-
Off
-
3.2.13 Overexcitation protection OEXPVPH---(IV side) Guiding philosophy for this protection is similar to that given for HV side overfluxing function in RET670-1 (Refer Figure 3-4 for typical overexcitation capability curve).
Guidelines for Setting: 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.
101
Model setting calculation document for Auto Transformer 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.
Setting Calculations: 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 102
Model setting calculation document for Auto Transformer will be allocated to these values of overexcitation. In this case, each step will be (150-110) /5 = 8%, since V/Hz>> is set to 150% and V/Hz> is set to 110% of rated V/Hz. We have considered 90% of its capability limits for tripping. For example, if transformer can withstand 126% of Overflux till 55sec from Overfluxing curve, we have set trip time 0.9 x 55 = 49.5s in relay to protect transformer before entering danger zone. The settings of time delays t1 to t6 are listed in table below. Figure 3-9 shows the tailor made curve for Over fluxing protection.
U/F %
Timer
Time set (s)
110
t1
9000
118
t2
90
126
t3
49.5
134
t4
18
142
t5
4
150
t6
1
Figure 3-6: Relay tailor made curve and Transformer with stable limit curve (V/Hz Vs s)
103
Model setting calculation document for Auto Transformer
Recommended Settings: Table 3-30 gives the recommended settings for Overexcitation protection. Table 3-30: Overexcitation protection OEXPVPH OEXPVPH Group settings (basic) Setting Parameter
Recommended
Description
Settings
Unit
Operation
Operation Off / On
On
-
IBase
Base current (rated phase current) in A
827
A
UBase
Base voltage (main voltage) in kV
220
kV
110
%UB/f
150
%UB/f
0.000
Ohm
0.150
s
1
s
9000
s
1200
s
Tailor made
-
1
-
V/Hz>
V/Hz>>
XLeak TrPulse tMin
tMax
tCooling
CurveType
kForIEEE
Operate level of V/Hz at no load and rated freq in % of (Ubase/frated) High level of V/Hz above which tMin is used, in % of (Ubase/frated) Winding leakage reactance in primary ohms Length of the pulse for trip signal (in sec) Minimum trip delay for V/Hz inverse curve, in sec Maximum trip delay for V/Hz inverse curve, in sec Transformer magnetic core cooling time constant, in sec Inverse time curve selection, IEEE/Tailor made Time multiplier for IEEE inverse type curve
AlarmLevel
Alarm operate level as % of operate level
98
%
tAlarm
Alarm time delay, in sec
5
s
104
Model setting calculation document for Auto Transformer
OEXPVPH Group settings (advanced) Setting Parameter t1Tailor
Recommended
Description Time delay t1 (longest) for tailor made curve, in sec
Settings
Unit
9000
s
t2Tailor
Time delay t2 for tailor made curve, in sec
90
s
t3Tailor
Time delay t3 for tailor made curve, in sec
49.5
s
t4Tailor
Time delay t4 for tailor made curve, in sec
18
s
t5Tailor
Time delay t5 for tailor made curve, in sec
4
s
1
s
T6Tailor
Time delay t6 (shortest) for tailor made curve, in sec
OEXPVPH Non group settings (basic) Setting Parameter
Recommended
Description
Settings
Unit
MeasuredU
Selection of measured voltage
PosSeq
-
MeasuredI
Selection of measured current
PosSeq
-
3.2.14 Disturbance Report DRPRDRE Guidelines for Setting: 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 REF input: Iref From 220kV CT: IA IB IC
105
Model setting calculation document for Auto Transformer IN From 220kV Bus PT: VAN VBN VCN Recommended Digital Signals for triggering (Typical) — Group-A Trip — Group-B Trip — Inter Trip from HV side Receive — 220kV Bus bar trip — 220kV CB LBB trip List of signals used for Analog triggering of DR — Over Current — Under voltage 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 pre-fault 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 0.5s. 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
106
Model setting calculation document for Auto Transformer 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.
Recommended Settings: Table 3-31 gives the recommended settings for Disturbance Report. Table 3-31: Disturbance Report Setting Parameter
Recommended
Description
Settings
Unit
Operation
Operation Off/On
On
-
PreFaultRecT
Pre-fault recording time
0.5
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
-
1
Ch
Off
-
ZeroAngleRef OpModeTest
Reference channel (voltage), phasors, frequency measurement Operation mode during test mode
107
Model setting calculation document for Auto Transformer
3.3 REC670 3.3.1 Analog Inputs Guidelines for Settings: Configure analog inputs: Current analog inputs as: Name# CTprim CTsec
Ch 1 IL1-CB1 1000A 1A
Ch 2 IL2-CB1 1000A 1A
Ch 3 IL3-CB1 1000A 1A
Ch 4 IL1-CB2 1000A 1A
Ch 5 IL2-CB2 1000A 1A
Ch 6 IL3-CB2 1000A 1A
CTStarPoint parameter indicates the CT secondary winding neutral earthing towards object (ToObject) or towards busbar (FromObject). Voltage analog input as: Name# VTprim VTsec
Ch 1 UL1-HV 400kV 110V
Ch 2 UL2-HV 400kV 110V
Ch 3 UL3-HV 400kV 110V
Ch 4 UL1-MV 220kV 110V
Ch 5 UL2-MV 220kV 110V
Ch 6 UL3-MV 220kV 110V
# User defined text
Recommended Settings: Table 3-32 gives the recommended settings for Analog Inputs. Table 3-32: Analog Inputs Setting Parameter PhaseAngleRef
CTStarPoint1
Recommended
Description Reference channel for phase angle Presentation ToObject= towards protected object, FromObject= the opposite
Settings
Unit
TRM40-Ch1
-
ToObject
-
CTsec1
Rated CT secondary current
1
A
CTprim1
Rated CT primary current
1000
A
CTStarPoint2
ToObject= towards protected object,
ToObject
-
108
Model setting calculation document for Auto Transformer FromObject= the opposite CTsec2
Rated CT secondary current
1
A
CTprim2
Rated CT primary current
1000
A
ToObject
-
CTStarPoint3
ToObject= towards protected object, FromObject= the opposite
CTsec3
Rated CT secondary current
1
A
CTprim3
Rated CT primary current
1000
A
ToObject
-
CTStarPoint4
ToObject= towards protected object, FromObject= the opposite
CTsec4
Rated CT secondary current
1
A
CTprim4
Rated CT primary current
1000
A
ToObject
-
CTStarPoint5
ToObject= towards protected object, FromObject= the opposite
CTsec5
Rated CT secondary current
1
A
CTprim5
Rated CT primary current
1000
A
CTStarPoint6
ToObject= towards protected object, FromObject= the opposite
ToObject
-
CTsec6
Rated CT secondary current
1
A
CTprim6
Rated CT primary current
1000
A
VTsec7
Rated VT secondary voltage
110
V
VTprim7
Rated VT primary voltage
400
kV
VTsec8
Rated VT secondary voltage
110
V
VTprim8
Rated VT primary voltage
400
kV
VTsec9
Rated VT secondary voltage
110
V
VTprim9
Rated VT primary voltage
400
kV
VTsec10
Rated VT secondary voltage
110
V
VTprim10
Rated VT primary voltage
220
kV
VTsec11
Rated VT secondary voltage
110
V
VTprim11
Rated VT primary voltage
220
kV
VTsec12
Rated VT secondary voltage
110
V
VTprim12
Rated VT primary voltage
220
kV
109
Model setting calculation document for Auto Transformer
Binary input module (BIM) Settings
I/O Module 1 I/O Module 2 I/O Module 3 I/O Module 4 I/O Module 5
Operation On On On On On
OscBlock(Hz) 40 40 40 40 40
OscRelease(Hz) 30 30 30 30 30
Pos Slot3 Pos Slot3 Pos Slot3 Pos Slot3 Pos Slot3
Note: OscBlock and OscRelease define the filtering time at activation. Low frequency gives slow response for digital input.
3.3.2 Local Human-Machine Interface Recommended Settings: Table 3-33 gives the recommended settings for Local human machine interface. Table 3-33: Local human machine interface Setting Parameter
Description
Language
Recommended Settings
Unit
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
-
110
Model setting calculation document for Auto Transformer
3.3.3 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.
Recommended Settings: Table 3-34 gives the recommended settings for Indication LEDs. Table 3-34: LEDGEN Non group settings (basic) Setting Parameter
Recommended
Description
Settings
Unit
Operation
Operation mode for the LED function
On
-
tRestart
Defines the disturbance length
0.0
s
0.0
s
tMax
Maximum time for the definition of a Disturbance
SeqTypeLED1
Sequence type for LED 1
LatchedAck-S-F
-
SeqTypeLED2
Sequence type for LED 2
LatchedAck-S-F
-
SeqTypeLED3
Sequence type for LED 3
LatchedAck-S-F
-
SeqTypeLED4
Sequence type for LED 4
LatchedAck-S-F
-
SeqTypeLED5
Sequence type for LED 5
LatchedAck-S-F
-
SeqTypeLED6
Sequence type for LED 6
LatchedAck-S-F
-
SeqTypeLED7
Sequence type for LED 7
LatchedAck-S-F
-
SeqTypeLED8
Sequence type for LED 8
LatchedAck-S-F
-
SeqTypeLED9
Sequence type for LED 9
LatchedAck-S-F
-
SeqTypeLED10
Sequence type for LED 10
LatchedAck-S-F
-
SeqTypeLED11
Sequence type for LED 11
LatchedAck-S-F
-
SeqTypeLED12
Sequence type for LED 12
LatchedAck-S-F
-
SeqTypeLED13
Sequence type for LED 13
LatchedAck-S-F
-
SeqTypeLED14
Sequence type for LED 14
LatchedAck-S-F
-
SeqTypeLED15
Sequence type for LED 15
LatchedAck-S-F
-
111
Model setting calculation document for Auto Transformer
3.3.4 Time Synchronization Guidelines for Settings: These settings are used for synchronizing IED clock time with network time. Ex: GPS or IRIG-B time. CoarseSyncSrc: Select the time synchronization source available such as SPA, LON, SNTP etc. Synchronization messages from sources configured as coarse are checked against the internal relay time and only if the difference in relay time and source time is more than 10s then relay time will be reset with the source time. This parameter need to be based on time source available in site. FineSyncSource: Select the time source available in network like IRIG-B, GPS, SNTP, SPA etc. once it is selected, time of available time source in network will update to relay if there is a difference in the time between relay and source. This parameter need to be based on time source available in site. SyncMaster: Normally it is set OFF. If time to the relay is received from a GPS antenna (example), make the relay as master to synchronize with other relays. TimeAdjustRate: Fast HWSyncSrc: This is applicable if process bus IEC61850-9-2 protocol is used for receiving analog values (optical CT PTs). In this case select time source available same as that of merging unit. This setting is not applicable in present case. AppSynch: If there is any loss of time sync, protection function will be blocked if AppSynch set to Synch based on SyncAccLevel. If AppSunch set to NoSynch, protection functions are not blocked. Recommended setting is NoSynch. SyncAccLevel: If this is set to “Class T5 (1us)” and time synch error is more than 1us, protection functions will be blocked. SyncAccLevel should be set to “Unspecified” when Nosynch is selected at AppSynch. This parameter is not applicable in present case. ModulePosition: if BIN is set for FineSyncSource, ModulePosition setting is applicable. Here slot position of IO module in the relay is to be set (Which slot is used for BI). This parameter is not applicable in present case. BinaryInput: Which binary input is used for time sync input shall be set here. This parameter is applicable if BIN is set for FineSyncSource. This parameter is not applicable in present case. BinDetection: Which edge of input pulse need to be detected has to be set here (positive and negative). This parameter is applicable if BIN is set for FineSyncSource. This parameter is not applicable in present case.
112
Model setting calculation document for Auto Transformer ServerIP-Add: Here set Time source server IP address. RedServIP-Add: If redundant server is available, set address of redundant server here. MonthInYear, DayInWeek, WeekInMonth and UTCTimeOfDay for DSTBEGIN and DSTEND are applicable where Day light saving is used. If it is not used set same date for both DSTBEGIN and DSTEND. This setting is not applicable in this case. NoHalfHourUTC: Time shift from GMT has to be set a multiple of half hours. Example for India it is +05:30, means +11. Hence this parameter is set to +11 in present case. SYNCHIRIG-B Non group settings: These settings are applicable if
IRIG-B is used. This
parameter is not applicable in present case. SynchType: Type of hardware input used for time sync, whether Opto or BNC. This parameter is not applicable in present case. TimeDomain: In present case, this parameter is set to LocalTime. Encoding: In present case, this parameter is set to IRIG-B TimeZoneAs1344: In present case, this parameter is set to PlusTZ
Recommended Settings: Table 3-35 gives the recommended settings for Time Synchronization. Table 3-35: Time Synchronization TIMESYNCHGEN Non group settings (basic) Setting Parameter
Recommended
Description
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
-
113
Model setting calculation document for Auto Transformer
SYNCHBIN Non group settings (basic) Setting Parameter ModulePosition
BinaryInput BinDetection
Recommended
Description Hardware position of IO module for time Synchronization Binary input number for time Synchronization Positive or negative edge detection
Settings
Unit
3
-
1
-
PositiveEdge
-
SYNCHSNTP Non group settings (basic) Setting Parameter
Description
ServerIP-Add RedServIP-Add
Recommended Settings
Unit
Server IP-address
0.0.0.0
IP Address
Redundant server IP-address
0.0.0.0
IP Address
DSTBEGIN Non group settings (basic) Setting Parameter
Recommended
Description
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
-
3600
s
UTCTimeOfDay
UTC Time of day in seconds when daylight time starts
DSTEND Non group settings (basic) Setting Parameter
Recommended
Description
Settings
Unit
MonthInYear
Month in year when daylight time starts
October
-
DayInWeek
Day in week when daylight time starts
Sunday
-
Last
-
3600
s
WeekInMonth UTCTimeOfDay
Week in month when daylight time starts UTC Time of day in seconds when
114
Model setting calculation document for Auto Transformer daylight time starts TIMEZONE Non group settings (basic) Setting
Recommended
Description
Parameter NoHalfHourUTC
Number of half-hours from UTC
Settings
Unit
+11
-
SYNCHIRIG-B Non group settings (basic) Setting
Recommended
Description
Parameter
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.
3.3.5 Parameter Setting Groups Guidelines for Settings: t: The length of the pulse, sent out by the output signal SETCHGD when an active group has changed, is set with the parameter t. This is not the delay for changing setting group. This parameter is normally recommended to set 1s. MAXSETGR: The parameter MAXSETGR defines the maximum number of setting groups in use to switch between. Only the selected number of setting groups will be available in the Parameter Setting tool (PST) for activation with the ActiveGroup function block. This parameter is normally recommended to set 1.
Recommended Settings: Table 3-36 gives the recommended settings for Parameter Setting Groups. Table 3-36: Parameter Setting Groups ActiveGroup Non group settings (basic) Setting Parameter
Recommended
Description
Settings 115
Unit
Model setting calculation document for Auto Transformer t
Pulse length of pulse when setting Changed
1
s
SETGRPS Non group settings (basic) Setting Parameter
Recommended
Description
Settings
Unit
ActiveSetGrp
ActiveSettingGroup
SettingGroup1
-
MAXSETGR
Max number of setting groups 1-6
1
No
3.3.6 Test Mode Functionality TEST Guidelines for Settings: EventDisable: If it is ON, it will disable the events like in DR during test mode. Normally this parameter is set to OFF. CmdTestBit: In present case this parameter is set to Off.
Recommended Settings: Table 3-37 gives the recommended settings for Test Mode Functionality. Table 3-37: Test Mode Functionality TESTMODE Non group settings (basic) Setting Parameter
Recommended
Description
Settings
Unit
TestMode
Test mode in operation (On) or not (Off)
Off
-
EventDisable
Event disable during testmode
Off
-
Off
-
CmdTestBit
Command bit for test required or not during testmode
3.3.7 IED Identifiers Recommended Settings: Table 3-38 gives the recommended settings for IED Identifiers.
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Model setting calculation document for Auto Transformer
Table 3-38: IED Identifiers TERMINALID Non group settings (basic) Setting
Description
Parameter
Recommended Settings
Unit
StationName
Station name
Station-A
-
StationNumber
Station number
0
-
ObjectName
Object name
Transformer
-
ObjectNumber
Object number
0
-
UnitName
Unit name
REC670
-
UnitNumber
Unit number
0
-
3.3.8 Rated System Frequency PRIMVAL Recommended Settings: Table 3-39 gives the recommended settings for Rated System Frequency. Table 3-39: Rated System Frequency PRIMVAL Non group settings (basic) Setting Parameter Frequency
Recommended
Description Rated system frequency
Settings
Unit
50.0
Hz
3.3.9 Signal Matrix For Analog Inputs SMAI Guidelines for Settings: DFTReference: Set ref for DFT filter adjustment here. These DFT reference block settings decide DFT reference for DFT calculations. The settings InternalDFTRef will use fixed DFT reference based on set system frequency. AdDFTRefChn will use DFT reference from the selected group block, when own group selected adaptive DFT reference will be used based on calculated signal frequency from own group. The setting ExternalDFTRef will use reference based on what is connected to input DFTSPFC.
117
Model setting calculation document for Auto Transformer 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 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 be set to 10% normally. UBase: Set the base voltage here. This is parameter is set to 400kV.
Recommended Settings: Table 3-39 gives the recommended settings for Signal Matrix For Analog Inputs. Table 3-40: Signal Matrix For Analog Inputs Setting Parameter
Recommended
Description
Settings
Unit
DFTRefExtOut
DFT reference for external output
(As per configuration)
-
DFTReference
DFT reference
(As per configuration)
-
ConnectionType
Input connection type
Ph-Ph
-
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Model setting calculation document for Auto Transformer TYPE
1=Voltage, 2=Current
1 or 2 based on input
Ch
Negation
Negation
Off
-
10
%
400
kV
MinValFreqMeas UBase
Limit for frequency calculation in % of UBase Base voltage
3.3.10 Synchrocheck function (SYN1) Guidelines for Settings: 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 set to 400kV in present case. 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. 119
Model setting calculation document for Auto Transformer 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 parameter is set ON. 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 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 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. 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. 120
Model setting calculation document for Auto Transformer 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. The threshold voltages ULowBusEnerg and ULowLineEnerg, have to be set to a value greater than the value where the network is considered not to be energized. A typical value can be 40% of the base voltages. If system voltages are below the set values here, relay will consider it as Dead condition. UMaxEnerg: Setting of the maximum live voltage level at which energizing is allowed. This setting is used to block the closing when the voltage on the live side is above the set value of UMaxEnerg. In present case this parameter is set to 105% of UBase. tAutoEnerg and tManEnerg: Set the time delay for the Auto Energizing and Manual Energizing. The purpose of the timer delay settings, tAutoEnerg and tManEnerg, is to ensure that the dead side remains de-energized and that the condition is not due to a temporary interference. If the conditions do not persist for the specified time, the delay timer is reset and the procedure is restarted when the conditions are fulfilled again. Circuit breaker closing is thus not permitted until the energizing condition has remained constant throughout the set delay setting time. Normally tManEnerg is recommended to set 0.1s. tAutoEnerg is not applicable in present case. OperationSynch: Operation for synchronizing function Off/ On. This parameter is recommended to set OFF. FreqDiffMin, FreqDiffMax, UHighBusSynch, UHighLineSynch, UDiffSynch, tClosePulse, tBreaker, tMinSynch and tMaxSynch: These parameters are not applicable if OperationSynch is set to OFF.
Recommended Settings: Table 3-39 gives the recommended settings for Synchrocheck function.
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Model setting calculation document for Auto Transformer Table 3-41: Setting of Synchrocheck function Setting Parameter
Recommended
Description
Settings
Unit
Operation
Operation Off / On
On
-
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
-
Off
-
On
-
80.0
%UBB
80.0
%UBL
0.15
pu
0.10
Hz
0.10
Hz
30.0
Deg
30.0
Deg
0.100
s
0.100
s
OperationSynch
OperationSC
UHighBusSC
UHighLineSC UDiffSC FreqDiffA
FreqDiffM
PhaseDiffA
PhaseDiffM tSCA tSCM
Operation for synchronizing function Off/ On Operation for synchronism check function Off/On Voltage high limit bus for synchrocheck in % of UBaseBus Voltage high limit line for synchrocheck in % of UBaseLine Voltage difference limit in p.u Frequency difference limit between bus and line Auto Frequency difference limit between bus and line Manual Phase angle difference limit between bus and line Auto Phase angle difference limit between bus and line Manual Time delay output for synchrocheck Auto Time delay output for synchrocheck Manual
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
80.0
%UBB
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Model setting calculation document for Auto Transformer check in % of UBaseBus UHighLineEnerg
ULowBusEnerg
ULowLineEnerg
UMaxEnerg
tAutoEnerg
Voltage high limit line for energizing check in % of UBaseLine Voltage low limit bus for energizing check in % of UBaseBus Voltage low limit line for energizing check in % of UBaseLine Maximum voltage for energizing in % of UBase, Line and/or Bus Time delay for automatic energizing Check
80.0
%UBL
40.0
%UBB
40.0
%UBL
105.0
%UB
0.100
s
0.100
s
tManEnerg
Time delay for manual energizing check
SelPhaseBus1
Select phase for busbar1
SelPhaseBus2
Select phase for busbar2
SelPhaseLine1
Select phase for line1
Phase L1 for line1
-
SelPhaseLine2
Select phase for line2
Phase L1 for line2
-
Phase L1 for busbar1 Phase L1 for busbar2
123
-
-
Model setting calculation document for Auto Transformer
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.
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Model setting calculation document for Auto Transformer
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.
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Model setting calculation document for Auto Transformer
Table A-1 Settings of Over current and Earth fault relays Phase Relay Settings Thermal / Curve (NEMA Code :67) SI.NO
Relay Name
CT ratio
Base Current Ib in A
Instantaneous Setting (NEMA Code :50)
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) SI.NO
Relay Name
CT ratio
Base Current Ib in A
Instantaneous Setting (NEMA Code :50N)
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.
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Model setting calculation document for Auto Transformer
Figure A-1: System details for the network under consideration for relay setting
Figure A-2: 3-Ph fault current for 220 kV side line fault
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Model setting calculation document for Auto Transformer
Figure A-3: 3-Ph fault current for 220 kV side bus fault
128
Model setting calculation document for Auto Transformer
Figure A-4: Phase Over Current Relay Curve Co-ordination and Operating Time for 220 kV line fault 129
Model setting calculation document for Auto Transformer
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 130
Model setting calculation document for Auto Transformer
Figure A-7: Earth Fault Relay Curve Co-ordination and Operating Time Operating Time for 220 kV line fault 131
Model setting calculation document for Auto Transformer
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 132
MODEL SETTING CALCULATION DOCUMENT FOR A TYPICAL IED USED FOR 400kV 80MVAR SHUNT REACTOR PROTECTION
Model setting calculation document for Shunt Reactor
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 2.1.1 Terminal Identification ....................................................................................11 2.1.2 List of functions available and those used ......................................................11 2.2 RET670-2........................................................................................................................... 15 2.2.1 Terminal Identification ....................................................................................15 2.2.2 List of functions available and those used ......................................................15 2.3 REL670 .............................................................................................................................. 20 2.3.1 Terminal Identification ....................................................................................20 2.3.2 List of functions available and those used ......................................................20 2.4 REC670.............................................................................................................................. 25
3
2.4.1 Terminal identification ....................................................................................25 2.4.2 List of functions available and those used ......................................................25 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 3.2.2 3.2.3 3.2.4 3.2.5 3.2.6 3.2.7 3.2.8 3.2.9
Analog Inputs .................................................................................................55 Local Human-Machine Interface.....................................................................57 Indication LEDs..............................................................................................57 Time Synchronization.....................................................................................59 Parameter Setting Groups..............................................................................62 Test Mode Functionality TEST .......................................................................63 IED Identifiers ................................................................................................63 Rated System Frequency PRIMVAL ..............................................................64 Signal Matrix For Analog Inputs SMAI............................................................64 2
Model setting calculation document for Shunt Reactor 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 3.4.2 3.4.3 3.4.4 3.4.5 3.4.6 3.4.7 3.4.8 3.4.9 3.4.10
Analog Inputs ...............................................................................................105 Local Human-Machine Interface...................................................................107 Indication LEDs............................................................................................107 Time Synchronization...................................................................................109 Parameter Setting Groups............................................................................112 Test Mode Functionality TEST .....................................................................113 IED Identifiers ..............................................................................................113 Rated System Frequency PRIMVAL ............................................................114 Signal Matrix For Analog Inputs SMAI..........................................................114 Synchrocheck function (SYN1).....................................................................116
3
Model setting calculation document for Shunt Reactor
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
4
Model setting calculation document for Shunt Reactor
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
5
Model setting calculation document for Shunt Reactor Table 3-49: Signal Matrix For Analog Inputs............................................................................................. 115 Table 3-50: Synchrocheck function Settings............................................................................................. 118
6
Model setting calculation document for Shunt Reactor
SETTING CALCULATION EXAMPLE
SUB-STATION: Station-A FEEDER: 400kV 80MVAR Shut Reactor at Station-A PROTECTION ELEMENT: Main-I & Main-II Protection Protection schematic Drg. Ref. No. XXXXXX
7
Model setting calculation document for Shunt Reactor
1
BASIC SYSTEM PARAMETERS
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
8
Model setting calculation document for Shunt Reactor 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
4B-CT
4C-CT
4C-CT2
4C-CT3
Name of the Core
CT ratio
CORE-1
1000/1A
CORE-2
1000/1A
CORE-3
1000/1A
CORE-4
1000/1A
CORE-5
1000/1A
CORE-1
2000/1A
CORE-2
2000/1A
CORE-3
1000/1A
CORE-4
1000/1A
CORE-5
1000/1A
CORE-1
200/1A
CORE-2
200/1A
CORE-3
200/1A
CORE-4
200/1A
CORE-1
200/1A
CORE-2
109.97/2A
CORE-3
1000/1A
CORE-4
1000/1A
CT details CLASS:PS, Vk:2000V, Imax at Vk:60mA, Rct@75 DEGREE CENTIGRADE ohm: <5Ω CLASS:PS, Vk:2000V, Imax at Vk:60mA, Rct@75 DEGREE CENTIGRADE ohm: <5Ω CLASS:0.2, 20VA CLASS:PS, Vk:2000V, Imax at Vk:60mA, Rct@75 DEGREE CENTIGRADE ohm: <5Ω CLASS:PS, Vk:2000V, Imax at Vk:60mA, Rct@75 DEGREE CENTIGRADE ohm: <5Ω CLASS:PS, Vk:4000V, Imax at Vk:60mA, Rct@75 DEGREE CENTIGRADE ohm: <10Ω CLASS:PS, Vk:4000V, Imax at Vk:120mA, Rct@75 DEGREE CENTIGRADE ohm: <10Ω CLASS:0.2, 20VA CLASS:PS, Vk:2000V, Imax at Vk:60mA, Rct@75 DEGREE CENTIGRADE ohm: <5Ω CLASS:PS, Vk:2000V, Imax at Vk:60mA, Rct@75 DEGREE CENTIGRADE ohm: <5Ω CLASS:PS, Vk:200V, Imax at Vk:30mA, Rct@75 DEGREE CENTIGRADE ohm: <1Ω CLASS:PS, Vk:200V, Imax at Vk:30mA, Rct@75 DEGREE CENTIGRADE ohm: <1Ω CLASS:PS, Vk:200V, Imax at Vk:30mA, Rct@75 DEGREE CENTIGRADE ohm: <1Ω CLASS:1, 15VA CLASS:PS, Vk:200V, Imax at Vk:30mA, Rct@75 DEGREE CENTIGRADE ohm: <1Ω CLASS:5, 15VA CLASS:PS, Vk:1600V, Imax at Vk:50mA, Rct@75 DEGREE CENTIGRADE ohm: <8Ω CLASS:PS, Vk:1600V, Imax at Vk:50mA, Rct@75 DEGREE CENTIGRADE ohm: <8Ω PT details
Name of the PT
Name of the Core
PT ratio
PT details
PT
I
400/0.11kV
3P, 50VA
9
Model setting calculation document for Shunt Reactor
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
10
Model setting calculation document for Shunt Reactor
2 TERMINAL IDENTIFICATION AND LIST OF FUNCTIONS 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 2.1.1 Terminal Identification Station Name:
Station-A
Object Name:
400kV Shunt Reactor
Unit Name:
RET670-1 (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 RET670-1 relay and also indicates the functions/feature for which settings are provided in this document. The functions/features are indicative and vary with IED ordering code & IED application configuration.
Table 2-1: List of functions in RET670-1 Sl.No.
Function/features available In RET670
Function/feature
Recommended
activated
Settings
Yes/No
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
Model setting calculation document for Shunt Reactor 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
YES
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
Transformer differential protection
YES
T3WPDIF 20
Instantaneous Phase Overcurrent
NO
Protection PHPIOC 21
Four Step Phase Overcurrent Protection
NO
OC4PTOC:1 22
Four Step Phase Overcurrent Protection
NO
OC4PTOC:2 23
Instantaneous Residual Overcurrent
NO
Protection EFPIOC 24
Four Step Residual Overcurrent Protection
NO
EF4PTOC 25
Thermal overload protection, two time
NO
constants TRPTTR 26
Breaker failure protection CCRBRF
NO
27
Single Point Generic Control 8 Signals
NO
SPC8GGIO 28
Automationbits, Command Function For
NO
DNP3.0 AUTOBITS 29
Single Command, 16 Signals
NO
SINGLECMD 30
Scheme Communication Logic For
12
NO
Model setting calculation document for Shunt Reactor Distance Or Overcurrent Protection ZCPSCH 31
Current Reversal And Weak-End Infeed
NO
Logic For Distance Protection ZCRWPSCH 32
Local Acceleration Logic ZCLCPLAL
NO
33
Direct Transfer Trip Logic
NO
34
Negative Sequence Overvoltage
NO
Protection LCNSPTOV 35
Zero Sequence Overvoltage Protection
NO
LCZSPTOV 36
Negative Sequence Overcurrent
NO
Protection LCNSPTOC 37
Zero Sequence Overcurrent Protection
NO
LCZSPTOC 38
Three Phase Overcurrent LCP3PTOC
NO
39
Three Phase Undercurrent LCP3PTUC
NO
40
Tripping Logic SMPPTRC
YES
41
Trip Matrix Logic TMAGGIO
YES
42
Configurable Logic Blocks
NO
43
Fixed Signal Function Block FXDSIGN
NO
44
Boolean 16 To Integer Conversion B16I
YES
45
Boolean 16 To Integer Conversion With
NO
Logic Node Representation B16IFCVI 46
Integer To Boolean 16 Conversion IB16
NO
47
Integer To Boolean 16 Conversion With
NO
Logic Node Representation IB16FCVB 48
Measurements CVMMXN
NO
49
Phase Current Measurement CMMXU
NO
50
Phase-Phase Voltage Measurement
NO
VMMXU 51
Current Sequence Component
NO
Measurement CMSQI
13
Model setting calculation document for Shunt Reactor 52
Voltage Sequence Measurement VMSQI
NO
53
Phase-Neutral Voltage Measurement
NO
VNMMXU 54
Event Counter CNTGGIO
NO
55
Event Function EVENT
NO
56
Logical Signal Status Report
NO
BINSTATREP 57
Fault Locator LMBRFLO
NO
58
Measured Value Expander Block
NO
RANGE_XP 59
Disturbance Report DRPRDRE
YES
60
Event List
NO
61
Indications
NO
62
Event Recorder
YES
63
Trip Value Recorder
YES
64
Disturbance Recorder
YES
65
Pulse-Counter Logic PCGGIO
NO
66
Function For Energy Calculation And
NO
Demand Handling ETPMMTR 67
IEC 61850-8-1 Communication Protocol
NO
68
IEC 61850 Generic Communication I/O
NO
Functions SPGGIO, SP16GGIO 69
IEC 61850-8-1 Redundant Station Bus
NO
Communication 70
IEC 61850-9-2LE Communication Protocol
NO
71
LON Communication Protocol
NO
72
SPA Communication Protocol
NO
73
IEC 60870-5-103 Communication Protocol
NO
74
Multiple Command And Transmit
NO
MULTICMDRCV, MULTICMDSND 75
Remote Communication
NO
14
Model setting calculation document for Shunt Reactor Note: For setting parameters provided in the function listed above, refer section 3 of application manual 1MRK504116-UEN, version 1.2.
2.2 RET670-2 2.2.1 Terminal Identification Station Name:
Station-A
Object Name:
400kV Shunt Reactor
Unit Name:
RET670-2 (Ver 1.2)
Relay serial No:
XXXXXXXX
Frequency:
50Hz
Aux voltage:
220V DC
2.2.2 List of functions available and those used Table 2-2 gives the list of functions/features available in RET670-2 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 2-2: List of functions in RET670-2 Sl.No.
Function/features available In RET670
Function/feature
Recommended
activated
Settings
Yes/No
provided
1
Analog Inputs
YES
2
Local Human-Machine Interface
YES
3
Indication LEDs
YES
4
Self supervision with internal event list
YES
5
Time Synchronization
YES
6
Parameter Setting Groups
YES
7
Test Mode Functionality TEST
YES
8
Change Lock CHNGLCK
NO
9
IED Identifiers
YES
10
Product Information
YES
11
Rated System Frequency PRIMVAL
YES
15
Model setting calculation document for Shunt Reactor 12
Signal Matrix For Binary Inputs SMBI
YES
13
Signal Matrix For Binary Outputs SMBO
YES
14
Signal Matrix For mA Inputs SMMI
YES
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
Transformer differential protection
NO
T3WPDIF 20
1Ph High impedance differential protection
YES
HZPDIF 21
Instantaneous Phase Overcurrent
NO
Protection PHPIOC 22
Four Step Phase Overcurrent Protection
NO
OC4PTOC 23
Instantaneous Residual Overcurrent
NO
Protection EFPIOC 24
Four Step Residual Overcurrent Protection
NO
EF4PTOC 25
Four step directional negative phase
NO
sequence overcurrent protection NS4PTOC 26
Sensitive directional residual overcurrent
NO
and power protection SDEPSDE 27
Thermal overload protection, two time
NO
constants TRPTTR 28
Breaker failure protection CCRBRF
NO
29
Pole discordance protection CCRPLD
NO
30
Single Point Generic Control 8 Signals
NO
SPC8GGIO 31
Automationbits, Command Function For
NO
DNP3.0 AUTOBITS 32
Single Command, 16 Signals
NO
16
Model setting calculation document for Shunt Reactor SINGLECMD 33
Scheme Communication Logic For
NO
Distance Or Overcurrent Protection ZCPSCH 34
Current Reversal And Weak-End Infeed
NO
Logic For Distance Protection ZCRWPSCH 35
Local Acceleration Logic ZCLCPLAL
NO
36
Direct Transfer Trip Logic
NO
37
Low Active Power And Power Factor
NO
Protection LAPPGAPC 38
Compensated Over and Undervoltage
NO
Protection COUVGAPC 39
Sudden Change in Current Variation
NO
SCCVPTOC 40
Carrier Receive Logic LCCRPTRC
NO
41
Negative Sequence Overvoltage
NO
Protection LCNSPTOV 42
Zero Sequence Overvoltage Protection
NO
LCZSPTOV 43
Negative Sequence Overcurrent
NO
Protection LCNSPTOC 44
Zero Sequence Overcurrent Protection
NO
LCZSPTOC 45
Three Phase Overcurrent LCP3PTOC
NO
46
Three Phase Undercurrent LCP3PTUC
NO
47
Tripping Logic SMPPTRC
YES
48
Trip Matrix Logic TMAGGIO
YES
49
Configurable Logic Blocks
NO
50
Fixed Signal Function Block FXDSIGN
NO
51
Boolean 16 To Integer Conversion B16I
YES
52
Boolean 16 To Integer Conversion With
NO
Logic Node Representation B16IFCVI
17
Model setting calculation document for Shunt Reactor 53
Integer To Boolean 16 Conversion IB16
NO
54
Integer To Boolean 16 Conversion With
NO
Logic Node Representation IB16FCVB 55
Measurements CVMMXN
NO
56
Phase Current Measurement CMMXU
NO
57
Phase-Phase Voltage Measurement
NO
VMMXU 58
Current Sequence Component
NO
Measurement CMSQI 59
Voltage Sequence Measurement VMSQI
NO
60
Phase-Neutral Voltage Measurement
NO
VNMMXU 61
Event Counter CNTGGIO
NO
62
Event Function EVENT
NO
63
Logical Signal Status Report
NO
BINSTATREP 64
Fault Locator LMBRFLO
NO
65
Measured Value Expander Block
NO
RANGE_XP 66
Disturbance Report DRPRDRE
YES
67
Event List
NO
68
Indications
NO
69
Event Recorder
YES
70
Trip Value Recorder
YES
71
Disturbance Recorder
YES
72
Pulse-Counter Logic PCGGIO
NO
73
Function For Energy Calculation And
NO
Demand Handling ETPMMTR 74
IEC 61850-8-1 Communication Protocol
NO
75
IEC 61850 Generic Communication I/O
NO
Functions SPGGIO, SP16GGIO 76
IEC 61850-8-1 Redundant Station Bus Communication
18
NO
Model setting calculation document for Shunt Reactor 77
IEC 61850-9-2LE Communication Protocol
NO
78
LON Communication Protocol
NO
79
SPA Communication Protocol
NO
80
IEC 60870-5-103 Communication Protocol
NO
81
Multiple Command And Transmit
NO
MULTICMDRCV, MULTICMDSND 82
Remote Communication
NO
Note: For setting parameters provided in the function listed above, refer section 3 of application manual 1MRK504116-UEN, version 1.2.
19
Model setting calculation document for Shunt Reactor
2.3 REL670 2.3.1 Terminal Identification Station Name:
Station-A
Object Name:
400kV Shunt Reactor
Unit Name:
REL670 (Ver 1.2)
Relay serial No:
XXXXXXXX
Frequency:
50Hz
Aux voltage:
220V DC
2.3.2 List of functions available and those used Table 2-3 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 2-3: List of functions in REL670 Sl.No.
Function/features available In REL670
Function/feature
Recommended
activated
Settings
Yes/No
provided
1
Analog Inputs
YES
2
Local Human-Machine Interface
YES
3
Indication LEDs
YES
4
Self supervision with internal event list
YES
5
Time Synchronization
YES
6
Parameter Setting Groups
YES
7
Test Mode Functionality TEST
YES
8
Change Lock CHNGLCK
NO
9
IED Identifiers
YES
10
Product Information
YES
11
Rated System Frequency PRIMVAL
YES
12
Signal Matrix For Binary Inputs SMBI
YES
13
Signal Matrix For Binary Outputs SMBO
YES
20
Model setting calculation document for Shunt Reactor 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
Full-scheme distance measuring, Mho
YES
characteristic ZMHPDIS 20
Mho impedance supervision logic
NO
ZSMGAPC 21
Faulty phase identification with load
YES
YES
encroachment FMPSPDIS 22
Directional impedance element for mho characteristic ZDMRDIR
23
Power Swing Detection ZMRPSB
NO
24
Automatic Switch Onto Fault Logic,
NO
Voltage And Current Based ZCVPSOF 25
Instantaneous Phase Overcurrent
NO
Protection PHPIOC 26
Four Step Phase Overcurrent Protection
YES
OC4PTOC 27
Instantaneous Residual Overcurrent
NO
Protection EFPIOC 28
Four Step Residual Overcurrent Protection
YES
EF4PTOC 29
Sensitive Directional Residual Overcurrent
NO
And Power Protection SDEPSDE 30
General Current And Voltage Protection
NO
CVGAPC-4 functions 31
Current Circuit Supervision CCSRDIF
NO
32
Fuse Failure Supervision SDDRFUF
YES
33
Horizontal Communication Via GOOSE
NO
For Interlocking GOOSEINTLKRCV 34
Logic Rotating Switch For Function
21
NO
Model setting calculation document for Shunt Reactor Selection And LHMI Presentation SLGGIO 35
Selector Mini Switch VSGGIO
NO
36
Generic Double Point Function Block
NO
DPGGIO 37
Single Point Generic Control 8 Signals
NO
SPC8GGIO 38
Automationbits, Command Function For
NO
DNP3.0 AUTOBITS 39
Single Command, 16 Signals
NO
SINGLECMD 40
Scheme Communication Logic For
NO
Distance Or Overcurrent Protection ZCPSCH 41
Current Reversal And Weak-End Infeed
NO
Logic For Distance Protection ZCRWPSCH 42
Local Acceleration Logic ZCLCPLAL
NO
43
Direct Transfer Trip Logic
YES
44
Low Active Power And Power Factor
NO
Protection LAPPGAPC 45
Compensated Over and Undervoltage
NO
Protection COUVGAPC 46
Sudden Change in Current Variation
NO
SCCVPTOC 47
Carrier Receive Logic LCCRPTRC
NO
48
Negative Sequence Overvoltage
NO
Protection LCNSPTOV 49
Zero Sequence Overvoltage Protection
NO
LCZSPTOV 50
Negative Sequence Overcurrent
NO
Protection LCNSPTOC 51
Zero Sequence Overcurrent Protection LCZSPTOC
22
NO
Model setting calculation document for Shunt Reactor 52
Three Phase Overcurrent LCP3PTOC
NO
53
Three Phase Undercurrent LCP3PTUC
NO
54
Tripping Logic SMPPTRC
YES
55
Trip Matrix Logic TMAGGIO
YES
56
Configurable Logic Blocks
NO
57
Fixed Signal Function Block FXDSIGN
NO
58
Boolean 16 To Integer Conversion B16I
NO
59
Boolean 16 To Integer Conversion With
NO
Logic Node Representation B16IFCVI 60
Integer To Boolean 16 Conversion IB16
NO
61
Integer To Boolean 16 Conversion With
NO
Logic Node Representation IB16FCVB 62
Measurements CVMMXN
YES
63
Phase Current Measurement CMMXU
YES
64
Phase-Phase Voltage Measurement
YES
VMMXU 65
Current Sequence Component
YES
Measurement CMSQI 66
Voltage Sequence Measurement VMSQI
YES
67
Phase-Neutral Voltage Measurement
NO
VNMMXU 68
Event Counter CNTGGIO
YES
69
Event Function EVENT
YES
70
Logical Signal Status Report
NO
BINSTATREP 71
Fault Locator LMBRFLO
NO
72
Measured Value Expander Block
NO
RANGE_XP 73
Disturbance Report DRPRDRE
YES
74
Event List
YES
75
Indications
YES
76
Event Recorder
YES
77
Trip Value Recorder
YES
23
Model setting calculation document for Shunt Reactor 78
Disturbance Recorder
YES
79
Pulse-Counter Logic PCGGIO
NO
80
Function For Energy Calculation And
NO
Demand Handling ETPMMTR 81
IEC 61850-8-1 Communication Protocol
NO
82
IEC 61850 Generic Communication I/O
NO
Functions SPGGIO, SP16GGIO 83
IEC 61850-8-1 Redundant Station Bus
NO
Communication 84
IEC 61850-9-2LE Communication Protocol
NO
85
LON Communication Protocol
NO
86
SPA Communication Protocol
NO
87
IEC 60870-5-103 Communication Protocol
NO
88
Multiple Command And Transmit
NO
MULTICMDRCV, MULTICMDSND 89
Remote Communication
NO
Note: For setting parameters provided in the function listed above, refer section 3 of application manual 1MRK506315-UEN, version 1.2.
24
Model setting calculation document for Shunt Reactor
2.4 REC670 2.4.1 Terminal identification Station Name:
Station-A
Object Name:
400kV Shunt Reactor
Unit Name:
REC670 (Ver 1.2)
Relay serial No:
XXXXX
Frequency:
50Hz
Aux voltage:
220V DC
2.4.2 List of functions available and those used Table 2-4 gives the list of functions/features available in REC670 relay and also indicates the functions/feature for which settings are provided in this document. The functions/feature are indicative and varies with IED ordering code & IED application configuration. Table 2-4: List of functions in REC670 Sl.No.
Functions/Feature available In REC670
Features/Functions
Recommended
activated
Settings
Yes/No
provided
1
Analog Inputs
YES
2
Local Human-Machine Interface
YES
3
Indication LEDs
YES
4
Self supervision with internal event list
YES
5
Time Synchronization
YES
6
Parameter Setting Groups
YES
7
Test Mode Functionality TEST
YES
8
Change Lock CHNGLCK
NO
9
IED Identifiers
YES
10
Product Information
YES
11
Rated System Frequency PRIMVAL
YES
12
Signal Matrix For Binary Inputs SMBI
YES
13
Signal Matrix For Binary Outputs SMBO
YES
14
Signal Matrix For Ma Inputs SMMI
NO
25
Model setting calculation document for Shunt Reactor 15
Signal Matrix For Analog Inputs SMAI
YES
16
Summation Block 3 Phase 3PHSUM
NO
17
Authority Status ATHSTAT
NO
18
Denial Of Service DOS
NO
19
Differential Protection HZPDIF
NO
20
Instantaneous Phase Overcurrent
NO
Protection PHPIOC 21
Four Step Phase Overcurrent Protection
YES
OC4PTOC 22
Instantaneous Residual Overcurrent
NO
Protection EFPIOC 23
Four Step Residual Overcurrent Protection
YES
EF4PTOC 24
Four step directional negative phase
NO
sequence overcurrent protection NS4PTOC 25
Sensitive Directional Residual Overcurrent
NO
And Power Protection SDEPSDE 26
Thermal Overload Protection, One Time
NO
Constant LPTTR 27
Thermal overload protection, two time
NO
constants TRPTTR 28
Breaker Failure Protection CCRBRF
NO
29
Stub Protection STBPTOC
NO
30
Pole Discordance Protection CCRPLD
NO
31
Directional Underpower Protection
NO
GUPPDUP 32
Directional Overpower Protection
NO
GOPPDOP 33
Broken Conductor Check BRCPTOC
NO
34
Capacitor bank protection CBPGAPC
NO
35
Two Step Undervoltage Protection UV2PTUV Two Step Overvoltage Protection
NO
36
26
NO
Model setting calculation document for Shunt Reactor OV2PTOV 37
Two Step Residual Overvoltage Protection
NO
ROV2PTOV 38
Voltage Differential Protection VDCPTOV
NO
39
Loss Of Voltage Check LOVPTUV
NO
40
Underfrequency Protection SAPTUF
NO
41
Overfrequency Protection SAPTOF
NO
42
Rate-Of-Change Frequency Protection
NO
SAPFRC 43
General Current and Voltage Protection
NO
CVGAPC 44
Current Circuit Supervision CCSRDIF
NO
45
Fuse Failure Supervision SDDRFUF
NO
46
Synchrocheck, Energizing Check, And
YES
Synchronizing SESRSYN 47
Autorecloser SMBRREC
NO
48
Apparatus Control APC
NO
49
Horizontal Communication Via GOOSE
NO
For Interlocking GOOSEINTLKRCV 50
Logic Rotating Switch For Function
NO
Selection And LHMI Presentation SLGGIO 51
Selector Mini Switch VSGGIO
NO
52
Generic Double Point Function Block
NO
DPGGIO 53
Single Point Generic Control 8 Signals
NO
SPC8GGIO 54
Automationbits, Command Function For
NO
DNP3.0 AUTOBITS 55 56
57
Single Command, 16 Signals SINGLECMD Scheme Communication Logic For Distance Or Overcurrent Protection ZCPSCH Phase Segregated Scheme Communication Logic For Distance 27
NO NO
NO
Model setting calculation document for Shunt Reactor Protection ZC1PPSCH 58
Current Reversal And Weak-End Infeed
NO
Logic For Distance Protection ZCRWPSCH 59
Local Acceleration Logic ZCLCPLAL
NO
60
Scheme Communication Logic For
NO
Residual Overcurrent Protection ECPSCH 61
Current Reversal And Weak-End Infeed
NO
Logic For Residual Overcurrent Protection ECRWPSCH 62
Current Reversal And Weak-End Infeed
NO
Logic For Phase Segregated Communication ZC1WPSCH 63
Direct Transfer Trip Logic
NO
64
Low Active Power And Power Factor
NO
Protection LAPPGAPC 65
Compensated Over And Undervoltage
NO
Protection COUVGAPC 66
Sudden Change In Current Variation
NO
SCCVPTOC 67
Carrier Receive Logic LCCRPTRC
NO
68
Negative Sequence Overvoltage
NO
Protection LCNSPTOV 69
Zero Sequence Overvoltage Protection
NO
LCZSPTOV 70
Negative Sequence Overcurrent
NO
Protection LCNSPTOC 71
Zero Sequence Overcurrent Protection
NO
LCZSPTOC 72
Three Phase Overcurrent LCP3PTOC
NO
73
Three Phase Undercurrent LCP3PTUC
NO
74
Tripping Logic SMPPTRC
NO
75
Trip Matrix Logic TMAGGIO
NO
28
Model setting calculation document for Shunt Reactor 76
Configurable Logic Blocks
NO
77
Fixed Signal Function Block FXDSIGN
NO
78
Boolean 16 To Integer Conversion B16I
NO
79
Boolean 16 To Integer Conversion With
NO
Logic Node Representation B16IFCVI 80
Integer To Boolean 16 Conversion IB16
NO
81
Integer To Boolean 16 Conversion With
NO
Logic Node Representation IB16FCVB 82
Measurements CVMMXN
YES
83
Phase Current Measurement CMMXU
YES
84
Phase-Phase Voltage Measurement
YES
VMMXU 85
Current Sequence Component
YES
Measurement CMSQI 86
Voltage Sequence Measurement VMSQI
YES
87
Phase-Neutral Voltage Measurement
NO
VNMMXU 88
Event Counter CNTGGIO
YES
89
Event Function EVENT
YES
90
Logical Signal Status Report
NO
BINSTATREP 91
Fault Locator LMBRFLO
NO
92
Measured Value Expander Block
NO
RANGE_XP 93
Disturbance Report DRPRDRE
NO
94
Event List
YES
95
Indications
YES
96
Event Recorder
YES
97
Trip Value Recorder
YES
98
Disturbance Recorder
YES
99
Pulse-Counter Logic PCGGIO
NO
100
Function For Energy Calculation And
NO
Demand Handling ETPMMTR
29
Model setting calculation document for Shunt Reactor 101
IEC 61850-8-1 Communication Protocol
NO
102
IEC 61850 Generic Communication I/O
NO
Functions SPGGIO, SP16GGIO 103
IEC 61850-8-1 Redundant Station Bus
NO
Communication 104
IEC 61850-9-2LE Communication Protocol
NO
105
LON Communication Protocol
NO
106
SPA Communication Protocol
NO
107
IEC 60870-5-103 Communication Protocol
NO
108
Multiple Command And Transmit
NO
MULTICMDRCV, MULTICMDSND 109
Remote Communication
NO
Note: For setting parameters provided in the function listed above, refer section 3 of application manual 1MRK511230-UEN, version 1.2.
30
Model setting calculation document for Shunt Reactor
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 Guidelines for Settings: Configure analog inputs: Current analog inputs as: Name# CTprim CTsec
Ch 1 IL1-CB1 1000A 1A
Ch 2 IL2-CB1 1000A 1A
Ch 3 IL3-CB1 1000A 1A
Ch 4 IL1-CB2 1000A 1A
Ch 5 IL2-CB2 1000A 1A
Ch 6 IL3-CB2 1000A 1A
CTStarPoint parameter indicates the CT secondary winding neutral earthing towards object (ToObject) or towards busbar (FromObject).
Voltage analog input as: Name# VTprim VTsec
Ch 1 UL1 400kV 110V
Ch 2 UL2 400kV 110V
Ch 3 UL3 400kV 110V
Ch 4 SPARE 400kV 110V
# User defined text
Recommended Settings: Table 3-1 gives the recommended settings for Analog inputs.
31
Ch 5 SPARE 400kV 110V
Ch 6 SPARE 400kV 110V
Model setting calculation document for Shunt Reactor
Table 3-1: Analog inputs Setting Parameter PhaseAngleRef
CTStarPoint1
Recommended
Description Reference channel for phase angle Presentation ToObject= towards protected object, FromObject= the opposite
Settings
Unit
TRM40-Ch1
-
ToObject
-
CTsec1
Rated CT secondary current
1
A
CTprim1
Rated CT primary current
1000
A
ToObject
-
CTStarPoint2
ToObject= towards protected object, FromObject= the opposite
CTsec2
Rated CT secondary current
1
A
CTprim2
Rated CT primary current
1000
A
ToObject
-
CTStarPoint3
ToObject= towards protected object, FromObject= the opposite
CTsec3
Rated CT secondary current
1
A
CTprim3
Rated CT primary current
1000
A
ToObject
-
CTStarPoint4
ToObject= towards protected object, FromObject= the opposite
CTsec4
Rated CT secondary current
1
A
CTprim4
Rated CT primary current
1000
A
ToObject
-
CTStarPoint5
ToObject= towards protected object, FromObject= the opposite
CTsec5
Rated CT secondary current
1
A
CTprim5
Rated CT primary current
1000
A
CTStarPoint6
ToObject= towards protected object, FromObject= the opposite
ToObject
-
CTsec6
Rated CT secondary current
1
A
CTprim6
Rated CT primary current
1000
A
VTsec7
Rated VT secondary voltage
110
V
VTprim7
Rated VT primary voltage
400
kV
VTsec8
Rated VT secondary voltage
110
V
32
Model setting calculation document for Shunt Reactor VTprim8
Rated VT primary voltage
400
kV
VTsec9
Rated VT secondary voltage
110
V
VTprim9
Rated VT primary voltage
400
kV
VTsec10
Rated VT secondary voltage
110
V
VTprim10
Rated VT primary voltage
400
kV
VTsec11
Rated VT secondary voltage
110
V
VTprim11
Rated VT primary voltage
400
kV
VTsec12
Rated VT secondary voltage
110
V
VTprim12
Rated VT primary voltage
400
kV
Binary input module (BIM) Settings
I/O Module 1 I/O Module 2 I/O Module 3 I/O Module 4 I/O Module 5
Operation On On On On On
OscBlock(Hz) 40 40 40 40 40
OscRelease(Hz) 30 30 30 30 30
Pos Slot3 Pos Slot3 Pos Slot3 Pos Slot3 Pos Slot3
Note: OscBlock and OscRelease defines the filtering time at activation. Low frequency gives slow response for digital input.
3.1.2 Local Human-Machine Interface Recommended Settings: Table 3-2 gives the recommended settings for Local human machine interface. Table 3-2: Local human machine interface Setting Parameter
Description
Language
Recommended Settings
Unit
Local HMI language
English
-
DisplayTimeout
Local HMI display timeout
60
Min
AutoRepeat
Activation of auto-repeat (On) or not (Off)
On
-
33
Model setting calculation document for Shunt Reactor
Setting Parameter
Description
ContrastLevel
Recommended Settings
Unit
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.
Recommended Settings: Table 3-3 gives the recommended settings for Indication LEDs. Table 3-3: LEDGEN Non group settings (basic) Setting Parameter
Recommended
Description
Settings
Unit
Operation
Operation mode for the LED function
On
-
tRestart
Defines the disturbance length
0.0
s
0.0
s
tMax
Maximum time for the definition of a disturbance
SeqTypeLED1
Sequence type for LED 1
LatchedAck-S-F
-
SeqTypeLED2
Sequence type for LED 2
LatchedAck-S-F
-
SeqTypeLED3
Sequence type for LED 3
LatchedAck-S-F
-
SeqTypeLED4
Sequence type for LED 4
LatchedAck-S-F
-
SeqTypeLED5
Sequence type for LED 5
LatchedAck-S-F
-
34
Model setting calculation document for Shunt Reactor SeqTypeLED6
Sequence type for LED 6
LatchedAck-S-F
-
SeqTypeLED7
Sequence type for LED 7
LatchedAck-S-F
-
SeqTypeLED8
Sequence type for LED 8
LatchedAck-S-F
-
SeqTypeLED9
Sequence type for LED 9
LatchedAck-S-F
-
SeqTypeLED10
Sequence type for LED 10
LatchedAck-S-F
-
SeqTypeLED11
Sequence type for LED 11
LatchedAck-S-F
-
SeqTypeLED12
Sequence type for LED 12
LatchedAck-S-F
-
SeqTypeLED13
Sequence type for LED 13
LatchedAck-S-F
-
SeqTypeLED14
Sequence type for LED 14
LatchedAck-S-F
-
SeqTypeLED15
Sequence type for LED 15
LatchedAck-S-F
-
3.1.4 Time Synchronization Guidelines for Settings: These settings are used for synchronizing IED clock time with network time. Ex: GPS or IRIG-B time. CoarseSyncSrc: Select the time synchronization source available such as SPA, LON, SNTP etc. Synchronization messages from sources configured as coarse are checked against the internal relay time and only if the difference in relay time and source time is more than 10s then relay time will be reset with the source time. This parameter need to be based on time source available in site. FineSyncSource: Select the time source available in network like IRIG-B, GPS, SNTP, SPA etc. once it is selected, time of available time source in network will update to relay if there is a difference in the time between relay and source. This parameter need to be based on time source available in site. SyncMaster: Normally it is set OFF. If time to the relay is received from a GPS antenna (example), make the relay as master to synchronize with other relays. TimeAdjustRate: Fast HWSyncSrc: This is applicable if process bus IEC61850-9-2 protocol is used for receiving analog values (optical CT PTs). In this case select time source available same as that of merging unit. This setting is not applicable in present case. AppSynch: If there is any loss of time sync, protection function will be blocked if AppSynch set to Synch based on SyncAccLevel. If AppSunch set to NoSynch, protection functions are not blocked. Recommended setting is NoSynch. 35
Model setting calculation document for Shunt Reactor SyncAccLevel: If this is set to “Class T5 (1us)” and time synch error is more than 1us, protection functions will be blocked. SyncAccLevel should be set to “Unspecified” when Nosynch is selected at AppSynch. This parameter is not applicable in present case. ModulePosition: if BIN is set for FineSyncSource, ModulePosition setting is applicable. Here slot position of IO module in the relay is to be set (Which slot is used for BI). This parameter is not applicable in present case. BinaryInput: Which binary input is used for time sync input shall be set here. This parameter is applicable if BIN is set for FineSyncSource. This parameter is not applicable in present case. BinDetection: Which edge of input pulse need to be detected has to be set here (positive and negative). This parameter is applicable if BIN is set for FineSyncSource. This parameter is not applicable in present case. ServerIP-Add: Here set Time source server IP address. RedServIP-Add: If redundant server is available, set address of redundant server here. MonthInYear, DayInWeek, WeekInMonth and UTCTimeOfDay for DSTBEGIN and DSTEND are applicable where Day light saving is used. If it is not used set same date for both DSTBEGIN and DSTEND. This setting is not applicable in this case. NoHalfHourUTC: Time shift from GMT has to be set a multiple of half hours. Example for India it is +05:30, means +11. Hence this parameter is set to +11 in present case. SYNCHIRIG-B Non group settings: These settings are applicable if IRIG-B is used. This parameter is not applicable in present case. SynchType: Type of hardware input used for time sync, whether Opto or BNC. This parameter is not applicable in present case. TimeDomain: In present case this parameter is set to LocalTime. Encoding: In present case this parameter is set to IRIG-B. TimeZoneAs1344: In present case this parameter is set to PlusTZ.
Recommended Settings: Table 3-4 gives the recommended settings for Time synchronization. Table 3-4: Time synchronization settings TIMESYNCHGEN Non group settings (basic) Setting Parameter CoarseSyncSrc
Recommended
Description Coarse time synchronization source
36
Settings
Unit
Off
-
Model setting calculation document for Shunt Reactor 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
-
SYNCHBIN Non group settings (basic) Setting Parameter ModulePosition
BinaryInput BinDetection
Recommended
Description Hardware position of IO module for time Synchronization Binary input number for time synchronization Positive or negative edge detection
Settings
Unit
3
-
1
-
PositiveEdge
-
SYNCHSNTP Non group settings (basic) Setting Parameter
Description
ServerIP-Add RedServIP-Add
Recommended Settings
Unit
Server IP-address
0.0.0.0
IP Address
Redundant server IP-address
0.0.0.0
IP Address
DSTBEGIN Non group settings (basic) Setting Parameter
Recommended
Description
Settings
Unit
MonthInYear
Month in year when daylight time starts
March
-
DayInWeek
Day in week when daylight time starts
Sunday
-
Last
-
3600
s
WeekInMonth
UTCTimeOfDay
Week in month when daylight time starts UTC Time of day in seconds when daylight time starts
37
Model setting calculation document for Shunt Reactor
DSTEND Non group settings (basic) Setting Parameter
Recommended
Description
Settings
Unit
MonthInYear
Month in year when daylight time starts
October
-
DayInWeek
Day in week when daylight time starts
Sunday
-
Last
-
3600
s
WeekInMonth
UTCTimeOfDay
Week in month when daylight time starts UTC Time of day in seconds when daylight time starts
TIMEZONE Non group settings (basic) Setting Parameter NoHalfHourUTC
Recommended
Description Number of half-hours from UTC
Settings
Unit
+11
-
SYNCHIRIG-B Non group settings (basic) Setting Parameter
Recommended
Description
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 Guidelines for Settings: 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 38
Model setting calculation document for Shunt Reactor Setting tool (PST) for activation with the ActiveGroup function block. This parameter is normally recommended to set 1.
Recommended Settings: Table 3-5 gives the recommended settings for Parameter setting group. Table 3-5: Parameter setting group ActiveGroup Non group settings (basic) Setting Parameter t
Recommended
Description Pulse length of pulse when setting Changed
Settings
Unit
1
s
SETGRPS Non group settings (basic) Setting Parameter
Recommended
Description
Settings
Unit
ActiveSetGrp
ActiveSettingGroup
SettingGroup1
-
MAXSETGR
Max number of setting groups 1-6
1
No
3.1.6 Test Mode Functionality TEST Guidelines for Settings: EventDisable: If it is ON, it will disable the events like in DR during test mode. Normally this parameter is set to OFF. CmdTestBit: In present case this parameter is set to Off.
Recommended Settings: Table 3-6 gives the recommended settings for Test mode functionality.
39
Model setting calculation document for Shunt Reactor
Table 3-6: Test mode functionality TESTMODE Non group settings (basic) Setting Parameter
Recommended
Description
Settings
Unit
TestMode
Test mode in operation (On) or not (Off)
Off
-
EventDisable
Event disable during testmode
Off
-
Off
-
CmdTestBit
Command bit for test required or not during testmode
3.1.7 IED Identifiers Recommended Settings: Table 3-7 gives the recommended settings for IED Identifiers. Table 3-7: IED Identifiers TERMINALID Non group settings (basic) Setting Parameter
Description
Recommended Settings
Unit
StationName
Station name
Station-A
-
StationNumber
Station number
0
-
ObjectName
Object name
Bus Reactor
-
ObjectNumber
Object number
0
-
UnitName
Unit name
RET670 M1
-
UnitNumber
Unit number
0
-
3.1.8 Rated System Frequency PRIMVAL Recommended Settings: Table 3-8 gives the recommended settings for Rated system frequency.
40
Model setting calculation document for Shunt Reactor
Table 3-8: Rated system frequency PRIMVAL Non group settings (basic) Setting Parameter Frequency
Description
Recommended Settings
Rated system frequency
50.0
Unit Hz
3.1.9 Signal Matrix For Analog Inputs SMAI Guidelines for Settings: DFTReference: Set ref for DFT filter adjustment here. These DFT reference block settings decide DFT reference for DFT calculations. The settings InternalDFTRef will use fixed DFT reference based on set system frequency. AdDFTRefChn will use DFT reference from the selected group block, when own group selected adaptive DFT reference will be used based on calculated signal frequency from own group. The setting ExternalDFTRef will use reference based on what is connected to input DFTSPFC. There are three different task groups of SMAI with 1ms, 3ms and 8ms. Use of each task group is based on requirement of function, like differential protection requires 1ms, which is faster. Each task group has 12 instances of SMAI, in that first instance has some additional features which is called master. Others are slaves and they will follow master. If measured sample rate needs to be transferred to other task group, it can be done only with master. Receiving task group SMAI DFTreference shall be set to External DFT Ref. DFTReference shall be set to default value InternalDFTRef if no VT input is available. Since VT input is available in this case, the corresponding channel shall be set to DFTReference. Configuration file has to be referred for this purpose. DFTRefExtOut: This parameter is available only in Master. If reference is to be sent to other task 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: 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. 41
Model setting calculation document for Shunt Reactor If R, Y, B inputs are connected, N=R+Y+B, and it will do as above. This parameter is recommended to be set to OFF normally. MinValFreqMeas: Set the measured minimum value here. It is applicable only for voltage input. SMAI will work only if measured input magnitude is greater than set value in MinValFreqMeas. This parameter is recommended to set 10% normally. UBase: Set the base voltage here. This is parameter is set to 400kV.
Recommended Settings: Table 3-9 gives the recommended settings for Signal Matrix For Analog Inputs. Table 3-9: Signal Matrix For Analog Inputs Setting Parameter
Recommended
Description
Settings
Unit
DFTRefExtOut
DFT reference for external output
(As per configuration)
-
DFTReference
DFT reference
(As per configuration)
-
ConnectionType
Input connection type
Ph-Ph
-
TYPE
1=Voltage, 2=Current
1 or 2 based on input
Ch
Negation
Negation
Off
-
10
%
400
kV
MinValFreqMeas UBase
Limit for frequency calculation in % of UBase Base voltage
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. 42
Model setting calculation document for Shunt Reactor 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
43
Model setting calculation document for Shunt Reactor
Guidelines for Settings: 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 44
Model setting calculation document for Shunt Reactor 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 maloperate 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. RatedVoltageW2: Rated voltage of shunt reactor in kV. This parameter is set to 400kV. RatedVoltageW3: Rated voltage of shunt reactor in kV. This parameter is set to 400kV. 45
Model setting calculation document for Shunt Reactor RatedCurrentW1: Rated current of shunt reactor in A. This parameter is set to 110A. RatedCurrentW2: Rated current of shunt reactor in A. This parameter is set to 110A. RatedCurrentW3: 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. ConnectTypeW1: Connection type of winding 1: Y-wye or D-delta. This parameter is set to Y. ConnectTypeW2: Connection type of winding 2: 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 Y. ClockNumberW2: Phase displacement between W2 & W1=HV winding, hour notation. This parameter is set to 0 as it is Shunt Reactor. ClockNumberW3: Phase displacement between W3 & W1=HV winding, hour notation. This 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. ZSCurrSubtrW2: Enable zer. seq. current subtraction for W2 side, On / Off. In present case this parameter is set ON. ZSCurrSubtrW3: Enable zer. seq. current subtraction for W3 side, On / Off. 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. CT1RatingW1, CT2RatingW1: These parameters are not applicable TconfigForW1 is set to NO. 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. TconfigForW3: Two CT inputs (T-config.) for winding 3, YES / NO. In present case this parameter is set to No. CT1RatingW3, CT2RatingW3: These parameters are not applicable TconfigForW3 is set to NO.
46
Model setting calculation document for Shunt Reactor 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,
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,
TapHighVoltTC2,
StepSizeOLTC2: These parameters are not applicable if LocationOLTC2 is set to “Not Used”.
Recommended Settings: Table 3-10 gives the recommended settings for Differential protection. Table 3-10: Differential protection Settings T3WPDIF Group settings (basic) Setting Parameter
Recommended
Description
Settings
Unit
Operation
Operation Off / On
On
-
SOTFMode
Operation mode for switch onto fault feature
Off
-
10
s
0.1
IB
0.2
IB
15
IB
On
-
Off
-
0.04
IB
60.0
Deg
tAlarmDelay IDiffAlarm IdMin IdUnre CrossBlockEn NegSeqDiffEn IMinNegSeq NegSeqROA
Time delay for diff currents alarm level Dif. cur. alarm, multiple of base curr, usually W1 curr. Section1 sensitivity, multi. of base curr, usually W1 curr. Unrestr. prot. limit, multi. of base curr. usually W1 curr. Operation Off/On for cross-block logic between phases Operation Off/On for neg. seq. differential protections Neg. seq. curr. limit, mult. of base curr, usually W1 curr. Operate Angle for int. / ext. neg. seq. fault discriminator
47
Model setting calculation document for Shunt Reactor
T3WPDIF Group settings (advanced) Setting Parameter
Recommended
Description
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
%
15
%
25
%
Off
-
3
s
0.25
s
10.0
s
Slope in section 2 of operate-restrain characteristic, in % Slope in section 3 of operate-restrain SlopeSection3 characteristic, in % Max. ratio of 2nd harm. to fundamental I2/I1Ratio harm dif. curr. in % Max. ratio of 5th harm. to fundamental I5/I1Ratio harm dif. curr. in % Open CT detection feature. Open OpenCTEnable CTEnable Off/On Open CT: time in s to alarm after an tOCTAlarmDelay open CT is detected tOCTResetDelay Reset delay in s. After delay, diff. function is activated tOCTUnrstDelay Unrestrained diff. protection blocked after this delay, in s SlopeSection2
T3WPDIF Non group settings (basic) Setting Parameter RatedVoltageW1 RatedVoltageW2 RatedVoltageW3 RatedCurrentW1 RatedCurrentW2 RatedCurrentW3 ConnectTypeW1 ConnectTypeW2 ConnectTypeW3
Recommended
Description Rated voltage of transformer winding 1 (HV winding) in kV Rated voltage of transformer winding 2 in kV Rated voltage of transformer winding 3 in kV Rated current of transformer winding 1 (HV winding) in A Rated current of transformer winding 2 in A Rated current of transformer winding 3 in A Connection type of winding 1: Y-wye or D-delta Connection type of winding 2: Y-wye or D-delta Connection type of winding 3: Y-wye or 48
Settings
Unit
400
kV
400 400 110 110 110
kV kV A A A
WYE(Y)
-
WYE(Y)
-
WYE(Y)
-
Model setting calculation document for Shunt Reactor D-delta Phase displacement between W2 & ClockNumberW2 W1=HV winding, hour notation Phase displacement between W3 & ClockNumberW3 W1=HV winding, hour notation Enable zer. seq. current subtraction for ZSCurrSubtrW1 W1 side, On / Off Enable zer. seq. current subtraction for ZSCurrSubtrW2 W2 side, On / Off Enable zer. seq. current subtraction for ZSCurrSubtrW3 W3 side, On / Off Two CT inputs (T-config.) for winding 1, TconfigForW1 YES / NO CT primary rating in A, T-branch 1, on CT1RatingW1 transf. W1 side CT primary in A, T-branch 2, on transf. CT2RatingW1 W1 side Two CT inputs (T-config.) for winding 2, TconfigForW2 YES / NO CT primary rating in A, T-branch 1, on CT1RatingW2 transf. W2 side CT primary rating in A, T-branch 2, on CT2RatingW2 transf. W2 side Two CT inputs (T-config.) for winding 3, TconfigForW3 YES / NO CT primary rating in A, T-branch 1, on CT1RatingW3 transf. W3 side CT primary rating in A, T-branch 2, on CT2RatingW3 transf. W3 side Transformer winding where OLTC1 is LocationOLTC1 located LowTapPosOLTC1 OLTC1 lowest tap position designation (e.g. 1) OLTC1 rated tap/mid-tap position RatedTapOLTC1 designation (e.g. 6) HighTapPsOLTC1 OLTC1 highest tap position designation (e.g. 11) OLTC1 end-tap position with winding TapHighVoltTC1 highest no-load voltage Voltage change per OLTC1 step in StepSizeOLTC1 percent of rated voltage Transformer winding where OLTC2 is LocationOLTC2 located LowTapPosOLTC2 OLTC2 lowest tap position designation (e.g. 1) OLTC2 rated tap/mid-tap position RatedTapOLTC2 designation (e.g. 6) HighTapPsOLTC2 OLTC2 highest tap position designation (e.g. 11)
49
0 [0 deg]
-
0 [0 deg]
-
On
-
On
-
On
-
No
-
1000
A
1000
A
No
-
1000
A
1000
A
No
-
1000
A
1000
A
Not Used
-
1
-
6
-
11
-
1
-
1.0
%
Not Used
-
1
-
6
-
11
-
Model setting calculation document for Shunt Reactor
TapHighVoltTC2 StepSizeOLTC2
OLTC2 end-tap position with winding highest no-load voltage Voltage change per OLTC2 step in percent of rated voltage
1
-
1.0
%
3.1.11 Tripping Logic SMPPTRC Guidelines for Setting: 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 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. 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.
Recommended Settings: Table 3-11 gives the recommended settings for Tripping Logic. Table 3-11: Tripping Logic Setting Parameter
Recommended
Description
Settings
Unit
Operation
Operation Off / On
On
-
Program
Three ph; single or three ph; single, two or three ph trip Minimum duration of trip output signal
3 phase
-
0.150
s
0.020
s
Off
-
Off
-
tTripMin tWaitForPHS
TripLockout AutoLock
Secures 3-pole trip when phase selection failed On: activate output (CLLKOUT) and trip latch, Off: only outp On: lockout from input (SETLKOUT) and 50
Model setting calculation document for Shunt Reactor trip, Off: only inp
3.1.12 Trip Matrix Logic TMAGGIO Guidelines for Setting: This function is only for the OR operation of any signals (normally used for trip signals). For example, all Differential, REF, 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 selected, output will be same as that of SMPPTRC.
Recommended Settings: Table 3-12 gives the recommended settings for Trip Matrix Logic. Table 3-12: Trip Matrix Logic Setting Parameter
Recommended
Description
Settings
Unit
Operation
Operation Off / On
On
-
PulseTime
Output pulse time
0.0
s
OnDelay
Output on delay time
0.0
s
OffDelay
Output off delay time
0.0
s
ModeOutput1 Mode for output ,1 steady or pulsed
Steady
-
ModeOutput2 Mode for output 2, steady or pulsed
Steady
-
ModeOutput3 Mode for output 3, steady or pulsed
Steady
-
51
Model setting calculation document for Shunt Reactor
3.1.13 Disturbance Report DRPRDRE Guidelines for Setting: 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 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 Recommended Digital Signals for triggering (Typical) — Group-A Trip — Group-B Trip 52
Model setting calculation document for Shunt Reactor — Direct Transfer Trip Sent (in case of line reactor) — 400kV Bus bar trip — Main/Tie CB LBB Optd. List of signals used for Analog triggering of DR — Over Voltage 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 0.5s. 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 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.
Recommended Settings: Table 3-13 gives the recommended settings for Disturbance Report.
53
Model setting calculation document for Shunt Reactor Table 3-13: Disturbance Report Setting Parameter
Recommended
Description
Settings
Unit
Operation
Operation Off/On
On
-
PreFaultRecT
Pre-fault recording time
0.5
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
-
1
Ch
Off
-
ZeroAngleRef OpModeTest
Reference channel (voltage), phasors, frequency measurement Operation mode during test mode
54
Model setting calculation document for Shunt Reactor
3.2 RET670-2 3.2.1 Analog Inputs Guidelines for Settings: Configure analog inputs: Current analog inputs as: Name# CTprim CTsec
Ch 1 REF 1A 1A
Ch 2 REF
Ch 3 REF
Ch 4 SPARE
1A 1A
1A 1A
1000A 1A
Ch 5 SPARE 1000A 1A
Ch 6 SPARE 1000A 1A
CTStarPoint parameter indicates the CT secondary winding neutral earthing towards object (ToObject) or towards busbar (FromObject). 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 3phase type. (In this case, it is assumed Bus reactor). The above analog inputs has been set accordingly. Voltage analog input as: Name# VTprim VTsec
Ch 1 UL1 400kV 110V
Ch 2 UL2 400kV 110V
Ch 3 UL3 400kV 110V
Ch 4 SPARE 400kV 110V
Ch 5 SPARE 400kV 110V
Ch 6 SPARE 400kV 110V
# User defined text
Recommended Settings: Table 3-14 gives the recommended settings for Analog inputs. Table 3-14: Analog inputs Setting Parameter PhaseAngleRef
CTStarPoint1
Recommended
Description Reference channel for phase angle Presentation ToObject= towards protected object, FromObject= the opposite 55
Settings
Unit
TRM40-Ch1
-
ToObject
-
Model setting calculation document for Shunt Reactor CTsec1
Rated CT secondary current
1
A
CTprim1
Rated CT primary current
1
A
ToObject
-
CTStarPoint2
ToObject= towards protected object, FromObject= the opposite
CTsec2
Rated CT secondary current
1
A
CTprim2
Rated CT primary current
1
A
ToObject
-
CTStarPoint3
ToObject= towards protected object, FromObject= the opposite
CTsec3
Rated CT secondary current
1
A
CTprim3
Rated CT primary current
1
A
ToObject
-
CTStarPoint4
ToObject= towards protected object, FromObject= the opposite
CTsec4
Rated CT secondary current
1
A
CTprim4
Rated CT primary current
1000
A
ToObject
-
CTStarPoint5
ToObject= towards protected object, FromObject= the opposite
CTsec5
Rated CT secondary current
1
A
CTprim5
Rated CT primary current
1000
A
CTStarPoint6
ToObject= towards protected object, FromObject= the opposite
ToObject
-
CTsec6
Rated CT secondary current
1
A
CTprim6
Rated CT primary current
1000
A
VTsec7
Rated VT secondary voltage
110
V
VTprim7
Rated VT primary voltage
400
kV
VTsec8
Rated VT secondary voltage
110
V
VTprim8
Rated VT primary voltage
400
kV
VTsec9
Rated VT secondary voltage
110
V
VTprim9
Rated VT primary voltage
400
kV
VTsec10
Rated VT secondary voltage
110
V
VTprim10
Rated VT primary voltage
400
kV
VTsec11
Rated VT secondary voltage
110
V
VTprim11
Rated VT primary voltage
400
kV
VTsec12
Rated VT secondary voltage
110
V
56
Model setting calculation document for Shunt Reactor VTprim12
Rated VT primary voltage
400
kV
Binary input module (BIM) Settings
I/O Module 1 I/O Module 2 I/O Module 3 I/O Module 4 I/O Module 5
Operation On On On On On
OscBlock(Hz) 40 40 40 40 40
OscRelease(Hz) 30 30 30 30 30
Pos Slot3 Pos Slot3 Pos Slot3 Pos Slot3 Pos Slot3
Note: OscBlock and OscRelease defines the filtering time at activation. Low frequency gives slow response for digital input.
3.2.2 Local Human-Machine Interface Recommended Settings: Table 3-15 gives the recommended settings for Local human machine interface. Table 3-15: Local human machine interface Setting Parameter
Description
Language
Recommended Settings
Unit
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
-
3.2.3 Indication LEDs Guidelines for Settings: This function block is to control LEDs in HMI. 57
Model setting calculation document for Shunt Reactor 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.
Recommended Settings: Table 3-16 gives the recommended settings for Indication LEDs. Table 3-16: LEDGEN Non group settings (basic) Setting Parameter
Recommended
Description
Settings
Unit
Operation
Operation mode for the LED function
On
-
tRestart
Defines the disturbance length
0.0
s
0.0
s
tMax
Maximum time for the definition of a disturbance
SeqTypeLED1
Sequence type for LED 1
LatchedAck-S-F
-
SeqTypeLED2
Sequence type for LED 2
LatchedAck-S-F
-
SeqTypeLED3
Sequence type for LED 3
LatchedAck-S-F
-
SeqTypeLED4
Sequence type for LED 4
LatchedAck-S-F
-
SeqTypeLED5
Sequence type for LED 5
LatchedAck-S-F
-
SeqTypeLED6
Sequence type for LED 6
LatchedAck-S-F
-
SeqTypeLED7
Sequence type for LED 7
LatchedAck-S-F
-
SeqTypeLED8
Sequence type for LED 8
LatchedAck-S-F
-
SeqTypeLED9
Sequence type for LED 9
LatchedAck-S-F
-
SeqTypeLED10
Sequence type for LED 10
LatchedAck-S-F
-
SeqTypeLED11
Sequence type for LED 11
LatchedAck-S-F
-
SeqTypeLED12
Sequence type for LED 12
LatchedAck-S-F
-
SeqTypeLED13
Sequence type for LED 13
LatchedAck-S-F
-
SeqTypeLED14
Sequence type for LED 14
LatchedAck-S-F
-
SeqTypeLED15
Sequence type for LED 15
LatchedAck-S-F
-
58
Model setting calculation document for Shunt Reactor
3.2.4 Time Synchronization Guidelines for Settings: These settings are used for synchronizing IED clock time with network time. Ex: GPS or IRIG-B time. CoarseSyncSrc: Select the time synchronization source available such as SPA, LON, SNTP etc. Synchronization messages from sources configured as coarse are checked against the internal relay time and only if the difference in relay time and source time is more than 10s then relay time will be reset with the source time. This parameter need to be based on time source available in site. FineSyncSource: Select the time source available in network like IRIG-B, GPS, SNTP, SPA etc. once it is selected, time of available time source in network will update to relay if there is a difference in the time between relay and source. This parameter need to be based on time source available in site. SyncMaster: Normally it is set OFF. If time to the relay is received from a GPS antenna (example), make the relay as master to synchronize with other relays. TimeAdjustRate: Fast HWSyncSrc: This is applicable if process bus IEC61850-9-2 protocol is used for receiving analog values (optical CT PTs). In this case select time source available same as that of merging unit. This setting is not applicable in present case. AppSynch: If there is any loss of time sync, protection function will be blocked if AppSynch set to Synch based on SyncAccLevel. If AppSunch set to NoSynch, protection functions are not blocked. Recommended setting is NoSynch. SyncAccLevel: If this is set to “Class T5 (1us)” and time synch error is more than 1us, protection functions will be blocked. SyncAccLevel should be set to “Unspecified” when Nosynch is selected at AppSynch. This parameter is not applicable in present case. ModulePosition: if BIN is set for FineSyncSource, ModulePosition setting is applicable. Here slot position of IO module in the relay is to be set (Which slot is used for BI). This parameter is not applicable in present case. BinaryInput: Which binary input is used for time sync input shall be set here. This parameter is applicable if BIN is set for FineSyncSource. This parameter is not applicable in present case.
59
Model setting calculation document for Shunt Reactor BinDetection: Which edge of input pulse need to be detected has to be set here (positive and negative). This parameter is applicable if BIN is set for FineSyncSource. This parameter is not applicable in present case. ServerIP-Add: Here set Time source server IP address. RedServIP-Add: If redundant server is available, set address of redundant server here. MonthInYear, DayInWeek, WeekInMonth and UTCTimeOfDay for DSTBEGIN and DSTEND are applicable where Day light saving is used. If it is not used set same date for both DSTBEGIN and DSTEND. This setting is not applicable in this case. NoHalfHourUTC: Time shift from GMT has to be set a multiple of half hours. Example for India it is +05:30, means +11. Hence this parameter is set to +11 in present case. SYNCHIRIG-B Non group settings: These settings are applicable if IRIG-B is used. This parameter is not applicable in present case. SynchType: Type of hardware input used for time sync, whether Opto or BNC. This parameter is not applicable in present case. TimeDomain: In present case this parameter is set to LocalTime. Encoding: In present case this parameter is set to IRIG-B. TimeZoneAs1344: In present case this parameter is set to PlusTZ.
Recommended Settings: Table 3-17 gives the recommended settings for Time synchronization. Table 3-17: Time synchronization settings TIMESYNCHGEN Non group settings (basic) Setting Parameter
Recommended
Description
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
-
60
Model setting calculation document for Shunt Reactor
SYNCHBIN Non group settings (basic) Setting Parameter ModulePosition
BinaryInput BinDetection
Recommended
Description Hardware position of IO module for time Synchronization Binary input number for time synchronization Positive or negative edge detection
Settings
Unit
3
-
1
-
PositiveEdge
-
SYNCHSNTP Non group settings (basic) Setting Parameter
Description
ServerIP-Add RedServIP-Add
Recommended Settings
Unit
Server IP-address
0.0.0.0
IP Address
Redundant server IP-address
0.0.0.0
IP Address
DSTBEGIN Non group settings (basic) Setting Parameter
Recommended
Description
Settings
Unit
MonthInYear
Month in year when daylight time starts
March
-
DayInWeek
Day in week when daylight time starts
Sunday
-
Last
-
3600
s
WeekInMonth
UTCTimeOfDay
Week in month when daylight time starts UTC Time of day in seconds when daylight time starts
DSTEND Non group settings (basic) Setting Parameter
Recommended
Description
Settings
Unit
MonthInYear
Month in year when daylight time starts
October
-
DayInWeek
Day in week when daylight time starts
Sunday
-
WeekInMonth
Week in month when daylight time starts
Last
-
UTCTimeOfDay
UTC Time of day in seconds when
3600
s
61
Model setting calculation document for Shunt Reactor daylight time starts TIMEZONE Non group settings (basic) Setting
Recommended
Description
Parameter NoHalfHourUTC
Number of half-hours from UTC
Settings
Unit
+11
-
SYNCHIRIG-B Non group settings (basic) Setting
Recommended
Description
Parameter
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.
3.2.5 Parameter Setting Groups Guidelines for Settings: t: The length of the pulse, sent out by the output signal SETCHGD when an active group has changed, is set with the parameter t. This is not the delay for changing setting group. This parameter is normally recommended to set 1s. MAXSETGR: The parameter MAXSETGR defines the maximum number of setting groups in use to switch between. Only the selected number of setting groups will be available in the Parameter Setting tool (PST) for activation with the ActiveGroup function block. This parameter is normally recommended to set 1.
Recommended Settings: Table 3-18 gives the recommended settings for Parameter setting group. Table 3-18: Parameter setting group ActiveGroup Non group settings (basic) Setting Parameter t
Recommended
Description Pulse length of pulse when setting 62
Settings
Unit
1
s
Model setting calculation document for Shunt Reactor Changed SETGRPS Non group settings (basic) Setting Parameter
Recommended
Description
Settings
Unit
ActiveSetGrp
ActiveSettingGroup
SettingGroup1
-
MAXSETGR
Max number of setting groups 1-6
1
No
3.2.6 Test Mode Functionality TEST Guidelines for Settings: EventDisable: If it is ON, it will disable the events like in DR during test mode. Normally this parameter is set to OFF. CmdTestBit: In present case this parameter is set to Off.
Recommended Settings: Table 3-19 gives the recommended settings for Test mode functionality. Table 3-19: Test mode functionality TESTMODE Non group settings (basic) Setting Parameter
Recommended
Description
Settings
Unit
TestMode
Test mode in operation (On) or not (Off)
Off
-
EventDisable
Event disable during testmode
Off
-
Off
-
CmdTestBit
Command bit for test required or not during testmode
3.2.7 IED Identifiers Recommended Settings: Table 3-20 gives the recommended settings for IED Identifiers.
63
Model setting calculation document for Shunt Reactor
Table 3-20: IED Identifiers TERMINALID Non group settings (basic) Setting
Description
Parameter
Recommended Settings
Unit
StationName
Station name
Station-A
-
StationNumber
Station number
0
-
ObjectName
Object name
Bus Reactor
-
ObjectNumber
Object number
0
-
UnitName
Unit name
RET670 M2
-
UnitNumber
Unit number
0
-
3.2.8 Rated System Frequency PRIMVAL Recommended Settings: Table 3-21 gives the recommended settings for Rated system frequency. Table 3-21: Rated system frequency PRIMVAL Non group settings (basic) Setting Parameter Frequency
Recommended
Description Rated system frequency
Settings
Unit
50.0
Hz
3.2.9 Signal Matrix For Analog Inputs SMAI Guidelines for Settings: DFTReference: Set ref for DFT filter adjustment here. These DFT reference block settings decide DFT reference for DFT calculations. The settings InternalDFTRef will use fixed DFT reference based on set system frequency. AdDFTRefChn will use DFT reference from the selected group block, when own group selected adaptive DFT reference will be used based on calculated signal frequency from own group. The setting ExternalDFTRef will use reference based on what is connected to input DFTSPFC. There are three different task groups of SMAI with 1ms, 3ms and 8ms. Use of each task group is based on requirement of function, like differential protection requires 1ms, which is faster. 64
Model setting calculation document for Shunt Reactor 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 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 220kV.
Recommended Settings: Table 3-22 gives the recommended settings for Signal Matrix For Analog Inputs. Table 3-22: Signal Matrix For Analog Inputs Setting Parameter
Recommended
Description
Settings
Unit
DFTRefExtOut
DFT reference for external output
(As per configuration)
-
DFTReference
DFT reference
(As per configuration)
-
ConnectionType
Input connection type
Ph-Ph
-
TYPE
1=Voltage, 2=Current
1 or 2 based on input
Ch
Negation
Negation
Off
-
65
Model setting calculation document for Shunt Reactor
MinValFreqMeas UBase
Limit for frequency calculation in % of UBase Base voltage
10
%
220
kV
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 phaseto-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.
Guidelines for Setting: 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.
Setting Calculations: 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 66
Model setting calculation document for Shunt Reactor 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 67
Model setting calculation document for Shunt Reactor •
Loop impedance (Rct+2Rl) up to the CT paralleling point should be identical
•
Magnetizing characteristics should be identical
Recommended Settings: Table 3-23 gives the recommended settings for 1Ph High impedance differential protection. Table 3-23: 1Ph High impedance differential protection HZPDIF Setting Parameter Operation U>Alarm tAlarm U>Trip SeriesResistor
Recommended
Description Operation Off / On Alarm voltage level in volts on CT secondary side Time delay to activate alarm Operate voltage level in volts on CT secondary side Value of series resistor in Ohms
Settings
Unit
On
-
4
V
5
s
20
V
1000
ohm
Note: The respective analogue channels in RET670-2 (for REF current inputs) should be set to 1:1.
3.2.11 Disturbance Report DRPRDRE Guidelines for Setting: 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 Differential currents from 1PH High impedance functions: IREFL1 I REFL2 I REFL3 Recommended Digital Signals for triggering (Typical)
68
Model setting calculation document for Shunt Reactor — Group-A Trip — Group-B Trip — Direct Transfer Trip Sent (in case of line reactor) — 400kV Bus bar trip — Main/Tie CB LBB Optd. List of signals used for Analog triggering of DR — Over Voltage 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 3s of total recording time Recording times — Minimum prefault recording time of 500ms — 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 0.5s. 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 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.
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Model setting calculation document for Shunt Reactor
Recommended Settings: Table 3-24 gives the recommended settings for Disturbance Report. Table 3-24: Disturbance Report Setting Parameter
Recommended
Description
Settings
Unit
Operation
Operation Off/On
On
-
PreFaultRecT
Pre-fault recording time
0.5
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
-
1
Ch
Off
-
ZeroAngleRef OpModeTest
Reference channel (voltage), phasors, frequency measurement Operation mode during test mode
70
Model setting calculation document for Shunt Reactor
3.3 REL670 3.3.1 Analog Inputs Guidelines for Settings: Configure analog inputs: Current analog inputs as: Name# CTprim CTsec
Ch 1 IL1-CB1 1000A 1A
Ch 2 IL2-CB1 1000A 1A
Ch 3 IL3-CB1 1000A 1A
Ch 4 SPARE 200A 1A
Ch 5 SPARE 200A 1A
Ch 6 SPARE 200A 1A
CTStarPoint parameter indicates the CT secondary winding neutral earthing towards object (ToObject) or towards busbar (FromObject). Voltage analog input as: Name# VTprim VTsec
Ch 1 UL1 400kV 110V
Ch 2 UL2 400kV 110V
Ch 3 UL3 400kV 110V
Ch 4 SPARE 400kV 110V
Ch 5 SPARE 400kV 110V
Ch 6 SPARE 400kV 110V
# User defined text
Recommended Settings: Table 3-25 gives the recommended settings for Analog inputs. Table 3-25: Analog inputs Setting Parameter PhaseAngleRef
CTStarPoint1
Recommended
Description Reference channel for phase angle Presentation ToObject= towards protected object, FromObject= the opposite
Settings
Unit
TRM40-Ch1
-
ToObject
-
CTsec1
Rated CT secondary current
1
A
CTprim1
Rated CT primary current
1000
A
CTStarPoint2
ToObject= towards protected object,
ToObject
-
71
Model setting calculation document for Shunt Reactor FromObject= the opposite CTsec2
Rated CT secondary current
1
A
CTprim2
Rated CT primary current
1000
A
ToObject
-
CTStarPoint3
ToObject= towards protected object, FromObject= the opposite
CTsec3
Rated CT secondary current
1
A
CTprim3
Rated CT primary current
1000
A
ToObject
-
CTStarPoint4
ToObject= towards protected object, FromObject= the opposite
CTsec4
Rated CT secondary current
1
A
CTprim4
Rated CT primary current
200
A
ToObject
-
CTStarPoint5
ToObject= towards protected object, FromObject= the opposite
CTsec5
Rated CT secondary current
1
A
CTprim5
Rated CT primary current
200
A
CTStarPoint6
ToObject= towards protected object, FromObject= the opposite
ToObject
-
CTsec6
Rated CT secondary current
1
A
CTprim6
Rated CT primary current
200
A
VTsec7
Rated VT secondary voltage
110
V
VTprim7
Rated VT primary voltage
400
kV
VTsec8
Rated VT secondary voltage
110
V
VTprim8
Rated VT primary voltage
400
kV
VTsec9
Rated VT secondary voltage
110
V
VTprim9
Rated VT primary voltage
400
kV
VTsec10
Rated VT secondary voltage
110
V
VTprim10
Rated VT primary voltage
400
kV
VTsec11
Rated VT secondary voltage
110
V
VTprim11
Rated VT primary voltage
400
kV
VTsec12
Rated VT secondary voltage
110
V
VTprim12
Rated VT primary voltage
400
kV
72
Model setting calculation document for Shunt Reactor
Binary input module (BIM) Settings
I/O Module 1 I/O Module 2 I/O Module 3 I/O Module 4 I/O Module 5
Operation On On On On On
OscBlock(Hz) 40 40 40 40 40
OscRelease(Hz) 30 30 30 30 30
Pos Slot3 Pos Slot3 Pos Slot3 Pos Slot3 Pos Slot3
Note: OscBlock and OscRelease defines the filtering time at activation. Low frequency gives slow response for digital input.
3.3.2 Local Human-Machine Interface Recommended Settings: Table 3-26 gives the recommended settings for Local human machine interface. Table 3-26: Local human machine interface Setting Parameter
Description
Language
Recommended Settings
Unit
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
-
3.3.3 Indication LEDs Guidelines for Settings: This function block is to control LEDs in HMI. 73
Model setting calculation document for Shunt Reactor 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.
Recommended Settings: Table 3-27 gives the recommended settings for Indication LEDs. Table 3-27: LEDGEN Non group settings (basic) Setting Parameter
Recommended
Description
Settings
Unit
Operation
Operation mode for the LED function
On
-
tRestart
Defines the disturbance length
0.0
s
0.0
s
tMax
Maximum time for the definition of a disturbance
SeqTypeLED1
Sequence type for LED 1
LatchedAck-S-F
-
SeqTypeLED2
Sequence type for LED 2
LatchedAck-S-F
-
SeqTypeLED3
Sequence type for LED 3
LatchedAck-S-F
-
SeqTypeLED4
Sequence type for LED 4
LatchedAck-S-F
-
SeqTypeLED5
Sequence type for LED 5
LatchedAck-S-F
-
SeqTypeLED6
Sequence type for LED 6
LatchedAck-S-F
-
SeqTypeLED7
Sequence type for LED 7
LatchedAck-S-F
-
SeqTypeLED8
Sequence type for LED 8
LatchedAck-S-F
-
SeqTypeLED9
Sequence type for LED 9
LatchedAck-S-F
-
SeqTypeLED10
Sequence type for LED 10
LatchedAck-S-F
-
SeqTypeLED11
Sequence type for LED 11
LatchedAck-S-F
-
SeqTypeLED12
Sequence type for LED 12
LatchedAck-S-F
-
SeqTypeLED13
Sequence type for LED 13
LatchedAck-S-F
-
SeqTypeLED14
Sequence type for LED 14
LatchedAck-S-F
-
SeqTypeLED15
Sequence type for LED 15
LatchedAck-S-F
-
74
Model setting calculation document for Shunt Reactor
3.3.4 Time Synchronization Guidelines for Settings: These settings are used for synchronizing IED clock time with network time. Ex: GPS or IRIG-B time. CoarseSyncSrc: Select the time synchronization source available such as SPA, LON, SNTP etc. Synchronization messages from sources configured as coarse are checked against the internal relay time and only if the difference in relay time and source time is more than 10s then relay time will be reset with the source time. This parameter need to be based on time source available in site. FineSyncSource: Select the time source available in network like IRIG-B, GPS, SNTP, SPA etc. once it is selected, time of available time source in network will update to relay if there is a difference in the time between relay and source. This parameter need to be based on time source available in site. SyncMaster: Normally it is set OFF. If time to the relay is received from a GPS antenna (example), make the relay as master to synchronize with other relays. TimeAdjustRate: Fast HWSyncSrc: This is applicable if process bus IEC61850-9-2 protocol is used for receiving analog values (optical CT PTs). In this case select time source available same as that of merging unit. This setting is not applicable in present case. AppSynch: If there is any loss of time sync, protection function will be blocked if AppSynch set to Synch based on SyncAccLevel. If AppSunch set to NoSynch, protection functions are not blocked. Recommended setting is NoSynch. SyncAccLevel: If this is set to “Class T5 (1us)” and time synch error is more than 1us, protection functions will be blocked. SyncAccLevel should be set to “Unspecified” when Nosynch is selected at AppSynch. This parameter is not applicable in present case. ModulePosition: if BIN is set for FineSyncSource, ModulePosition setting is applicable. Here slot position of IO module in the relay is to be set (Which slot is used for BI). This parameter is not applicable in present case. BinaryInput: Which binary input is used for time sync input shall be set here. This parameter is applicable if BIN is set for FineSyncSource. This parameter is not applicable in present case.
75
Model setting calculation document for Shunt Reactor BinDetection: Which edge of input pulse need to be detected has to be set here (positive and negative). This parameter is applicable if BIN is set for FineSyncSource. This parameter is not applicable in present case. ServerIP-Add: Here set Time source server IP address. RedServIP-Add: If redundant server is available, set address of redundant server here. MonthInYear, DayInWeek, WeekInMonth and UTCTimeOfDay for DSTBEGIN and DSTEND are applicable where Day light saving is used. If it is not used set same date for both DSTBEGIN and DSTEND. This setting is not applicable in this case. NoHalfHourUTC: Time shift from GMT has to be set a multiple of half hours. Example for India it is +05:30, means +11. Hence this parameter is set to +11 in present case. SYNCHIRIG-B Non group settings: These settings are applicable if
IRIG-B is used. This
parameter is not applicable in present case. SynchType: Type of hardware input used for time sync, whether Opto or BNC. This parameter is not applicable in present case. TimeDomain: In present case this parameter is set to LocalTime. Encoding: In present case this parameter is set to IRIG-B. TimeZoneAs1344: In present case this parameter is set to PlusTZ.
Recommended Settings: Table 3-28 gives the recommended settings for Time synchronization. Table 3-28: Time synchronization settings TIMESYNCHGEN Non group settings (basic) Setting Parameter
Recommended
Description
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
-
76
Model setting calculation document for Shunt Reactor SYNCHBIN Non group settings (basic) Setting Parameter ModulePosition
BinaryInput BinDetection
Recommended
Description Hardware position of IO module for time Synchronization Binary input number for time synchronization Positive or negative edge detection
Settings
Unit
3
-
1
-
PositiveEdge
-
SYNCHSNTP Non group settings (basic) Setting Parameter
Description
ServerIP-Add RedServIP-Add
Recommended Settings
Unit
Server IP-address
0.0.0.0
IP Address
Redundant server IP-address
0.0.0.0
IP Address
DSTBEGIN Non group settings (basic) Setting Parameter
Recommended
Description
Settings
Unit
MonthInYear
Month in year when daylight time starts
March
-
DayInWeek
Day in week when daylight time starts
Sunday
-
Last
-
3600
s
WeekInMonth
UTCTimeOfDay
Week in month when daylight time starts UTC Time of day in seconds when daylight time starts
DSTEND Non group settings (basic) Setting Parameter
Recommended
Description
Settings
Unit
MonthInYear
Month in year when daylight time starts
October
-
DayInWeek
Day in week when daylight time starts
Sunday
-
WeekInMonth
Week in month when daylight time starts
Last
-
3600
s
UTCTimeOfDay
UTC Time of day in seconds when daylight time starts
77
Model setting calculation document for Shunt Reactor TIMEZONE Non group settings (basic) Setting
Recommended
Description
Parameter NoHalfHourUTC
Number of half-hours from UTC
Settings
Unit
+11
-
SYNCHIRIG-B Non group settings (basic) Setting
Recommended
Description
Parameter
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.
3.3.5 Parameter Setting Groups Guidelines for Settings: t: The length of the pulse, sent out by the output signal SETCHGD when an active group has changed, is set with the parameter t. This is not the delay for changing setting group. This parameter is normally recommended to set 1s. MAXSETGR: The parameter MAXSETGR defines the maximum number of setting groups in use to switch between. Only the selected number of setting groups will be available in the Parameter Setting tool (PST) for activation with the ActiveGroup function block. This parameter is normally recommended to set 1.
Recommended Settings: Table 3-29 gives the recommended settings for Parameter setting group. Table 3-29: Parameter setting group ActiveGroup Non group settings (basic) Setting Parameter t
Recommended
Description Pulse length of pulse when setting Changed 78
Settings
Unit
1
s
Model setting calculation document for Shunt Reactor SETGRPS Non group settings (basic) Setting Parameter
Recommended
Description
Settings
Unit
ActiveSetGrp
ActiveSettingGroup
SettingGroup1
-
MAXSETGR
Max number of setting groups 1-6
1
No
3.3.6 Test Mode Functionality TEST Guidelines for Settings: EventDisable: If it is ON, it will disable the events like in DR during test mode. Normally this parameter is set to OFF. CmdTestBit: In present case this parameter is set to Off.
Recommended Settings: Table 3-30 gives the recommended settings for Test mode functionality. Table 3-30: Test mode functionality TESTMODE Non group settings (basic) Setting Parameter
Recommended
Description
Settings
Unit
TestMode
Test mode in operation (On) or not (Off)
Off
-
EventDisable
Event disable during testmode
Off
-
Off
-
CmdTestBit
Command bit for test required or not during testmode
3.3.7 IED Identifiers Recommended Settings: Table 3-31 gives the recommended settings for IED Identifiers.
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Model setting calculation document for Shunt Reactor
Table 3-31: IED Identifiers TERMINALID Non group settings (basic) Setting
Description
Parameter
Recommended Settings
Unit
StationName
Station name
Station-A
-
StationNumber
Station number
0
-
ObjectName
Object name
Shunt Reactor
-
ObjectNumber
Object number
0
-
UnitName
Unit name
REL670
-
UnitNumber
Unit number
0
-
3.3.8 Rated System Frequency PRIMVAL Recommended Settings: Table 3-32 gives the recommended settings for Rated system frequency. Table 3-32: Rated system frequency PRIMVAL Non group settings (basic) Setting Parameter Frequency
Recommended
Description Rated system frequency
Settings
Unit
50.0
Hz
3.3.9 Signal Matrix For Analog Inputs SMAI Guidelines for Settings: DFTReference: Set ref for DFT filter adjustment here. These DFT reference block settings decide DFT reference for DFT calculations. The settings InternalDFTRef will use fixed DFT reference based on set system frequency. AdDFTRefChn will use DFT reference from the selected group block, when own group selected adaptive DFT reference will be used based on calculated signal frequency from own group. The setting ExternalDFTRef will use reference based on what is connected to input DFTSPFC. There are three different task groups of SMAI with 1ms, 3ms and 8ms. Use of each task group is based on requirement of function, like differential protection requires 1ms, which is faster. 80
Model setting calculation document for Shunt Reactor 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 connected to 3rd SMAI of 1ms task group, AdDFTRefCh3 is to be set in DFTRefExtOut of 1ms task group. DFTRefExtOut shall be set to default value InternalDFTRef if no VT input is available. Configuration file has to be referred for this purpose. Negation: Set negation of the function block here. If R, Y, B and N inputs are connected and Negation is set to NegateN, it will give output R, Y, B and –N. If Negation is set to Negate3Ph, it will give output -R, -Y, -B and N. If R, Y, B inputs are connected, N=R+Y+B, and it will do as above. This parameter is recommended to be set to OFF normally. MinValFreqMeas: Set the measured minimum value here. It is applicable only for voltage input. SMAI will work only if measured input magnitude is greater than set value in MinValFreqMeas. This parameter is recommended to set 10% normally. UBase: Set the base voltage here. This is parameter is set to 400kV.
Recommended Settings: Table 3-33 gives the recommended settings for Signal Matrix For Analog Inputs. Table 3-33: Signal Matrix For Analog Inputs Setting Parameter
Recommended
Description
Settings
Unit
DFTRefExtOut
DFT reference for external output
(As per configuration)
-
DFTReference
DFT reference
(As per configuration)
-
ConnectionType
Input connection type
Ph-Ph
-
TYPE
1=Voltage, 2=Current
1 or 2 based on input
Ch
Negation
Negation
Off
-
81
Model setting calculation document for Shunt Reactor
MinValFreqMeas UBase
Limit for frequency calculation in % of UBase Base voltage
10
%
400
kV
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.
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Model setting calculation document for Shunt Reactor
Guidelines for Setting: 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. To be set to 10% 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 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.
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Model setting calculation document for Shunt Reactor
Setting Calculations: Zone 1 phase fault reach is set to
60.0% of the total reactor impedance
ZPP' = 1323Ω The secondary setting will thus be 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
Recommended Settings: Table 3-34 gives the recommended settings for ZONE 1. Table 3-34: ZONE 1 Settings Setting Parameter
Recommended
Description
Settings
Unit
Operation
Operation Off / On
On
-
IBase
Base current , i.e rated current
110
A
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
-
On
-
1323
ohm/p
90
Deg
-0.03333
ohm/p
0
ohm/p
1323
ohm/p
OpModePE
ZPE
ZAngPE
KN
KNAng ZRevPE
Operation mode Off / On of Phase-Earth loops Positive sequence impedance setting for Phase-Earth loop Angle for positive sequence line impedance for Phase-Earth loop Magnitud of earth return compensation factor KN Angle for earth return compensation factor KN Reverse reach of the phase to earth 84
Model setting calculation document for Shunt Reactor loop(magnitude) tPE
IMinOpPE
OpModePP
ZPP
ZAngPP
ZRevPP
tPP
IMinOpPP
Delay time for operation of phase to earth elements Minimum operation phase to earth current Operation mode Off / On of PhasePhase loops Impedance setting reach for phase to phase elements Angle for positive sequence line impedance for Phase-Phase elements Reverse reach of the phase to phase loop(magnitude) Delay time for operation of phase to phase Minimum operation phase to phase current
1
s
10
%IB
On
-
1323
ohm/p
90
Deg
1323
ohm/p
1
s
10
%IB
ZMHPDIS Group settings (advanced) Setting Parameter
Recommended
Description
OffsetMhoDir Direction mode for offset mho OpModetPE
OpModetPP
Operation mode Off / On of Zone timer, Ph-E Operation mode Off / On of Zone timer, Ph-ph
Settings
Unit
Non-directional
-
On
-
On
-
3.3.11 Tripping Logic SMPPTRC Guidelines for Setting: 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.
85
Model setting calculation document for Shunt Reactor SMPPTRC function will give a pulse of set length (150ms) even if trip signal is obtained for transient fault. 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: 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. 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.
Recommended Settings: Table 3-35 gives the recommended settings for Tripping Logic. Table 3-35: Tripping Logic Setting Parameter Operation Program tTripMin tWaitForPHS
TripLockout
AutoLock
Recommended
Description Operation Off / On Three ph; single or three ph; single, two or three ph trip Minimum duration of trip output signal Secures 3-pole trip when phase selection failed On: activate output (CLLKOUT) and trip latch, Off: only outp On: lockout from input (SETLKOUT) and trip, Off: only inp
86
Settings
Unit
On
-
3 phase
-
0.150
s
0.050
s
Off
-
Off
-
Model setting calculation document for Shunt Reactor
3.3.12 Trip Matrix Logic TMAGGIO Guidelines for Setting: 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 selected, output will be same as that of SMPPTRC.
Recommended Settings: Table 3-36 gives the recommended settings for Trip Matrix Logic. Table 3-36: Trip Matrix Logic Setting Parameter
Recommended
Description
Settings
Unit
Operation
Operation Off / On
On
-
PulseTime
Output pulse time
0.0
s
OnDelay
Output on delay time
0.0
s
OffDelay
Output off delay time
0.0
s
ModeOutput1 Mode for output ,1 steady or pulsed
Steady
-
ModeOutput2 Mode for output 2, steady or pulsed
Steady
-
ModeOutput3 Mode for output 3, steady or pulsed
Steady
-
87
Model setting calculation document for Shunt Reactor
3.3.13 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. 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.
88
Model setting calculation document for Shunt Reactor 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.
Recommended Settings: Table 3-37 gives the recommended settings for Fuse Failure Supervision. Table 3-37: Fuse Failure Supervision Setting Parameter
Recommended
Description
Settings
Unit
Operation
Operation Off / On
On
-
IBase
Base current
110
A
UBase
Base voltage
400
kV
OpMode
Operating mode
UZsIZs
-
30
%IB
10
%IB
20
%IB
10
%IB
On
-
60
%UB
15
%IB
70
%UB
10
%IB
3U0>
3I0<
3U2>
3I2<
OpDUDI
DU> DI< UPh>
IPh>
residual overvoltage element in % of Ubase Operate level of residual undercurrent element in % of Ibase Operate level of neg seq overvoltage element in % of Ubase Operate level of neg seq undercurrent element in % of Ibase Operation of change based function Off/On Operate level of change in phase voltage in % of Ubase Operate level of change in phase Operate level of phase voltage in % of Ubase. Operate level of phase current in % of IBase 89
Model setting calculation document for Shunt Reactor SealIn USealln<
IDLD< UDLD<
Seal in functionality Off/On Operate level of seal-in phase voltage in %of Ubase Operate level for open phase current detection in % of IBase Operate level for open phase voltage
On
-
70
%UB
5
%IB
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.
Guidelines for Setting: IBase: Set the Base current for the function on which the current levels are based. This parameter is set to 110A in present case, which is Reactor 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 Reactor rated voltage. This parameter is not applicable in present case, since DirMode1 is set to Non-directional.
90
Model setting calculation document for Shunt Reactor AngleRCA: Set the relay characteristic angle, i.e. the angle between the neutral point voltage and current. This parameter is not applicable in present case, since DirMode1 is set to Nondirectional. AngleROA: Set the relay operating angle, i.e the angle sector of the directional function. This parameter 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 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 “Non-directional” in present case. Characteristic1: Setting of the operating characteristic. This parameter is set to “IEC Def. Time” in present case. I1>: Setting of the operating current level in primary values. This parameter is set to 130% of base current in present case. t1: This is the definite time delay for step-I. In present case this parameter is set to 1s. k1: Set the back-up trip time delay multiplier for inverse characteristic. This parameter is not applicable in present case, since Characteristic1 is set to IEC Def. Time. IMin1: Minimum operate current for step1 in % of IBase. This parameter is set to 130% of base current in present case. t1Min: Set the Minimum operating time for inverse characteristic. This parameter is not applicable in present case, since Characteristic1 is set to IEC Def. Time. I1Mult: Set the current multiplier for I1 valid at activation of input ENMULT. As this parameter is not applicable in present case, setting is left with default value of 1. DirMode2: Setting of the operating direction for the stage or switch it off. This parameter is set to “Non-directional” in present case. Characteristic2: Setting of the operating characteristic. This parameter is set to “Nondirectional” 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. 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 50 to 100msec. It is set to 50ms in present case. 91
Model setting calculation document for Shunt Reactor 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”. IMin2: Minimum operate current for step2 in % of IBase. This parameter is set to 1500% of base current in present case. t2Min: Set the Minimum operating time for inverse characteristic. This parameter is not applicable in present case since Characteristic2 is set to “IEC Def. Time”. I2Mult: Set the current multiplier for I2 valid at activation of input ENMULT. As this parameter is not applicable in present case, setting is left with default value of 1. 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. tReset1: Set the Reset time delay for definite time delayed function. This parameter is not applicable if ResetTypeCrv1 is set to Instantaneous. tPCrv1, tACrv1, tBCrv1, tCCrv1, tPRCrv1, tTRCrv1 and tCRCrv1: These parameters are applicable only if Characterist1 is set to Programmable. HarmRestrain1: Set the release of Harmonic restraint blocking for the stage. This parameter is kept ON to make the protection stable during charging conditions. ResetTypeCrv2: 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. tReset2: Set the Reset time delay for definite time delayed function. This parameter is not applicable if ResetTypeCrv1 is set to Instantaneous. tPCrv2, tACrv2, tBCrv2, tCCrv2, tPRCrv2, tTRCrv2 and tCRCrv2: These parameters are applicable only if Characterist2 is set to Programmable. HarmRestrain2: Set the release of Harmonic restraint blocking for the stage. This parameter is kept ON to make the protection stable during charging conditions. DirMode3 and DirMode4: Setting of the operating direction for the stage or switch it off. Two stages are set to OFF.
Setting Calculations: I1>: This parameter is set to 130% of base current in present case, which is 143A in primary. t1: This parameter is set to 1s in present case. 92
Model setting calculation document for Shunt Reactor I2>: This parameter is set to 1500% of base current in present case, which is 1650A in primary. t2: This parameter is set to 0.05s in present case.
Recommended Settings: 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 Parameter
Recommended
Description
Settings
Unit
Operation
Operation Off / On
On
-
IBase
Base value for current settings
110
A
400
kV
UBase
Base value for voltage settings. (Check with PT input in configuration )
AngleRCA
Relay characteristic angle (RCA)
65
Deg
AngleROA
Relay operation angle (ROA)
80
Deg
1 out of 3
-
Non-Directional
-
IEC Def. Time
-
130
%IB
1
s
0
-
130
%IB
0
s
1.0
-
Non-Directional
-
StartPhSel
DirMode1 Characterist1 I1> t1 k1
IMin1
t1Min
I1Mult
DirMode2
Number of phases required for op (1 of 3, 2 of 3, 3 of 3) Directional mode of step 1 (off, nodir, forward, reverse) Time delay curve type for step 1 Phase current operate level for step1 in % of IBase Definitive time delay of step 1 Time multiplier for the inverse time delay for step 1 Minimum operate current for step1 in % of IBase Minimum operate time for inverse curves for step 1 Multiplier for scaling the current setting value for step 1 Directional mode of step 2 (off, nodir, forward, reverse) 93
Model setting calculation document for Shunt Reactor Characterist2 I2> t2 k2
IMin2
t2Min
I2Mult
DirMode3
DirMode4
Time delay curve type for step 2 Phase current operate level for step2 in % of IBase Definitive time delay of step 2 Time multiplier for the inverse time delay for step 2 Minimum operate current for step2 in % of IBase Minimum operate time for inverse curves for step 2 Multiplier for scaling the current setting value for step 2 Directional mode of step 3 (off, nondir, forward, reverse) Directional mode of step 4 (off, nondir, forward, reverse)
IEC Def. Time
-
1500
%IB
0.05
s
0
-
1500
%IB
0
s
1.0
-
Off
-
Off
-
7
%IB
20
%
Instantaneous
-
0.020
s
1
-
13.5
-
0
-
1
-
OC4PTOC Group settings (advanced) IMinOpPhSel
2ndHarmStab
Minimum current for phase selection in % of IBase Second harmonic restrain operation in % of IN amplitude
ResetTypeCrv1 Selection of reset curve type for step 1 tReset1
tPCrv1
tACrv1
tBCrv1
tCCrv1
Reset time delay used in IEC Definite Time curve step 1 Parameter P for customer programmable curve for step 1 Parameter A for customer programmable curve for step 1 Parameter B for customer programmable curve for step 1 Parameter C for customer programmable curve for step 1
94
Model setting calculation document for Shunt Reactor
tPRCrv1
tTRCrv1
tCRCrv1
HarmRestrain1
Parameter PR for customer programmable curve for step 1 Parameter TR for customer programmable curve for step 1 Parameter CR for customer programmable curve for step 1 Enable block of step 1 from harmonic restrain
ResetTypeCrv2 Selection of reset curve type for step 2 tReset2
tPCrv2
tACrv2
tBCrv2
tCCrv2
tPRCrv2
tTRCrv2
tCRCrv2
HarmRestrain2
Reset time delay used in IEC Definite Time curve step 2 Parameter P for customer programmable curve for step 2 Parameter A for customer programmable curve for step 2 Parameter B for customer programmable curve for step 2 Parameter C for customer programmable curve for step 2 Parameter PR for customer programmable curve for step 2 Parameter TR for customer programmable curve for step 2 Parameter CR for customer programmable curve for step 2 Enable block of step 2 from harmonic restrain
95
0.5
-
13.5
-
1
-
On
-
Instantaneous
-
0.020
s
1
-
13.5
-
0
-
1
-
0.5
-
13.5
-
1
-
On
-
Model setting calculation document for Shunt Reactor
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 phaseto-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.
Guidelines for Setting: 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. IBase: Set the Base current for the function on which the current levels are based. This parameter is set to 110A in present case, which is Reactor 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 Reactor rated voltage. This parameter is not applicable in present case, since DirMode1 is set to Non-directional. DirMode1: Setting of the operating direction for the stage or switch it off. This parameter is set to “Non-directional” in present case. Characteristic1: Setting of the operating characteristic. This parameter is set to “IEC Def. Time” 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. 96
Model setting calculation document for Shunt Reactor t1: This is the definite time delay for step-I. In present case this parameter is set to 1s. 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. t1Min: Set the Minimum operating time for inverse characteristic. This parameter is not applicable in present case, since Characteristic1 is set to IEC Def. Time. 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 to make the protection stable during charging conditions. tPCrv1, tACrv1, tBCrv1, tCCrv1, tPRCrv1, tTRCrv1 and tCRCrv1: These parameters are applicable only if Characterist1 is set to Programmable. DirMode2: Setting of the operating direction for the stage or switch it off. This parameter is set to “Non-directional” in present case. Characteristic2: Setting of the operating characteristic. This parameter is set to “IEC Def. Time” in present case. 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. 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 50 to 100msec. It is set to 50ms in present case. 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 applicable in present case since Characteristic2 is set to “IEC Def. Time”. ResetTypeCrv2: 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. tReset2: Set the Reset time delay for definite time delayed function. This parameter is not applicable if ResetTypeCrv1 is set to Instantaneous. 97
Model setting calculation document for Shunt Reactor HarmRestrain2: Set the release of Harmonic restraint blocking for the stage. This parameter is kept ON to make the protection stable during charging conditions. tPCrv2, tACrv2, tBCrv2, tCCrv2, tPRCrv2, tTRCrv2 and tCRCrv2: These parameters are applicable only if Characterist2 is set to Programmable. 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. UPolMin: Setting of the minimum neutral point polarizing voltage level for the 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. AngleRCA: Set the relay characteristic angle, i.e. the angle between the neutral point voltage and current. This parameter is not applicable in present case, since DirMode1 and DirMode2 are set to Non-directional. IN>Dir: Minimum current required for directionality. This should be lower than pickup of earth fault protection. This parameter is not applicable in present case, since DirMode1 and DirMode2 are set to Non-directional. 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.
98
Model setting calculation document for Shunt Reactor ActivationSOTF, ActUndertime, t4U, tSOTF, tUndertime, HarmResSOTF: These parameters are not applicable if SOTF is set to OFF.
Setting Calculations: IN1>: This parameter is set to 20% of base current in present case, which is 22A in primary. t1: This parameter is set to 1s in present case. IN2>: This parameter is set to 1000% of base current in present case, which is 110A in primary. t2: This parameter is set to 0.05s in present case.
Recommended Settings: Table 3-39 gives the recommended settings for Four Step Residual Overcurrent Protection. Table 3-39: Four Step Residual Overcurrent Protection Setting Parameter
Recommended
Description
Settings
Unit
Operation
Operation Off / On
On
-
IBase
Base value for current settings
110
A
400
kV
UBase
Base value for voltage settings. (Check with PT input in configuration )
AngleRCA
Relay characteristic angle (RCA)
65
Deg
polMethod
Type of polarization
Voltage
-
1
%UB
5
%IB
5
Ohm
40
Ohm
10
%IB
20
%
Off
-
UPolMin
IPolMin
RNPol
XNPol
IN>Dir
2ndHarmStab BlkParTransf
Minimum voltage level for polarization in % of UBase Minimum current level for polarization in % of IBase Real part of source Z to be used for current polar-isation Imaginary part of source Z to be used for current polarisation Residual current level for Direction release in % of IBase Second harmonic restrain operation in % of IN amplitude Enable blocking at paral-lel transformers 99
Model setting calculation document for Shunt Reactor
UseStartValue
Current level blk at paral-lel transf (step1, 2,
IN4>
-
Off
-
ActivationSOTF Select signal that shall activate SOTF
Open
-
StepForSOTF
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
Non-Directional
-
IEC Def. Time
-
20
%IB
0.5
s
0
-
1.0
-
0
s
ResetTypeCrv1 Reset curve type for step 1
Instantaneous
-
tReset1
0.020
s
On
-
1
-
13.5
-
0
-
1
-
SOTF
DirMode1 Characterist1 IN1> t1 k1
IN1Mult
t1Min
HarmRestrain1
tPCrv1
tACrv1
tBCrv1
tCCrv1
3 or 4) SOTF operation mode (Off/SOTF/Undertime/SOTF+undertime)
Selection of step used for SOTF
Directional mode of step 1 (off, nodir, forward, reverse) Time delay curve type for step 1 Operate residual current level for step 1 in % of IBase Independent (definite) time delay of step 1 Time multiplier for the dependent time delay for step 1 Multiplier for scaling the current setting value for step 1 Minimum operate time for inverse curves for step 1
Reset time delay for step 1 Enable block of step 1 from harmonic restrain Parameter P for customer programmable curve for step 1 Parameter A for customer programmable curve for step 1 Parameter B for customer programmable curve for step 1 Parameter C for customer programmable curve for step 1
100
Model setting calculation document for Shunt Reactor
tPRCrv1
Parameter PR for customer programmable
0.5
-
13.5
-
1
-
Non-Directional
-
IEC Def. Time
-
1000
%IB
0.05
s
0.0
-
1.0
-
0
s
ResetTypeCrv2 Reset curve type for step 2
Instantaneous
-
tReset2
0.020
s
On
-
1
-
13.5
-
0
-
1
-
0.5
-
13.5
-
tTRCrv1
tCRCrv1
DirMode2 Characterist2 IN2> t2 k2
IN2Mult
t2Min
HarmRestrain2
tPCrv2
tACrv2
tBCrv2
tCCrv2 tPRCrv2 tTRCrv2
curve for step 1 Parameter TR for customer programmable curve for step 1 Parameter CR for customer programmable curve for step 1 Directional mode of step 2 (off, nondir, forward, reverse) Time delay curve type for step 2 Operate residual current level for step 2 in % of IBase Independent (definite) time delay of step 2 Time multiplier for the dependent time delay for step 2 Multiplier for scaling the current setting value for step 2 Minimum operate time for inverse curves for step 2
Reset time delay for step 2 Enable block of step 2 from harmonic restrain Parameter P for customer programmable curve for step 2 Parameter A for customer programmable curve for step 2 Parameter B for customer programmable curve for step 2 Parameter C for customer programmable curve for step 2 Parameter PR for customer programmable curve for step 2 Parameter TR for customer programmable curve for step 2 101
Model setting calculation document for Shunt Reactor
tCRCrv2
DirMode3
DirMode4
Parameter CR for customer programmable curve for step 2 Directional mode of step 3 (off, nondir, forward, reverse) Directional mode of step 4 (off, nondir, forward, reverse)
1
-
Off
-
Off
-
3.3.16 Disturbance Report DRPRDRE Guidelines for Setting: 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 Bus PT: VAN VBN VCN Recommended Digital Signals for triggering (Typical) — Group-A trip — Z1 Start — Group-B trip — Direct Transfer Trip (only for Line reactors) — Bus bar trip — Main/Tie CB LBB Optd. List of signals used for Analog triggering of DR — Over Voltage 102
Model setting calculation document for Shunt Reactor 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 3s 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 0.5s. 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 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.
Recommended Settings: Table 3-40 gives the recommended settings for Disturbance Report. Table 3-40: Disturbance Report Setting Parameter
Recommended
Description
Settings
Unit
Operation
Operation Off/On
On
-
PreFaultRecT
Pre-fault recording time
0.5
s
PostFaultRecT
Post-fault recording time
2.5
s
103
Model setting calculation document for Shunt Reactor TimeLimit
Fault recording time limit
3.00
s
PostRetrig
Post-fault retrig enabled (On) or not (Off)
Off
-
1
Ch
Off
-
ZeroAngleRef OpModeTest
Reference channel (voltage), phasors, frequency measurement Operation mode during test mode
104
Model setting calculation document for Shunt Reactor
3.4 REC670 3.4.1 Analog Inputs Guidelines for Settings: Configure analog inputs: Current analog inputs as: Name# CTprim CTsec
Ch 1 IL1-CB1 200A 1A
Ch 2 IL2-CB1 200A 1A
Ch 3 IL3-CB1 200A 1A
Ch 4 SPARE 1000A 1A
Ch 5 SPARE 1000A 1A
Ch 6 SPARE 1000A 1A
CTStarPoint parameter indicates the CT secondary winding neutral earthing towards object (ToObject) or towards busbar (FromObject).
Voltage analog input as: Name# VTprim VTsec
Ch 1 BUS PT 400kV 110V
Ch 2 BUS PT 400kV 110V
Ch 3 BUS PT 400kV 110V
Ch 4 SEL-PT* 400kV 110V
Ch 5 SEL-PT 400kV 110V
Ch 6 SEL-PT 400kV 110V
*SEL-PT: Selected PT input for synchronizing function # User defined text
Recommended Settings: Table 3-41 gives the recommended settings for Analog Inputs. Table 3-41: Analog Inputs Setting Parameter PhaseAngleRef
CTStarPoint1
Recommended
Description Reference channel for phase angle presentation ToObject= towards protected object, FromObject= the opposite
Settings
Unit
TRM40-Ch1
-
ToObject
-
CTsec1
Rated CT secondary current
1
A
CTprim1
Rated CT primary current
200
A
105
Model setting calculation document for Shunt Reactor
CTStarPoint2
ToObject= towards protected object, FromObject= the opposite
ToObject
-
CTsec2
Rated CT secondary current
1
A
CTprim2
Rated CT primary current
200
A
ToObject
-
CTStarPoint3
ToObject= towards protected object, FromObject= the opposite
CTsec3
Rated CT secondary current
1
A
CTprim3
Rated CT primary current
200
A
ToObject
-
CTStarPoint4
ToObject= towards protected object, FromObject= the opposite
CTsec4
Rated CT secondary current
1
A
CTprim4
Rated CT primary current
1000
A
ToObject
-
CTStarPoint5
ToObject= towards protected object, FromObject= the opposite
CTsec5
Rated CT secondary current
1
A
CTprim5
Rated CT primary current
1000
A
CTStarPoint6
ToObject= towards protected object, FromObject= the opposite
ToObject
-
CTsec6
Rated CT secondary current
1
A
CTprim6
Rated CT primary current
1000
A
VTsec7
Rated VT secondary voltage
110
V
VTprim7
Rated VT primary voltage
400
kV
VTsec8
Rated VT secondary voltage
110
V
VTprim8
Rated VT primary voltage
400
kV
VTsec9
Rated VT secondary voltage
110
V
VTprim9
Rated VT primary voltage
400
kV
VTsec10
Rated VT secondary voltage
110
V
VTprim10
Rated VT primary voltage
400
kV
VTsec11
Rated VT secondary voltage
110
V
VTprim11
Rated VT primary voltage
400
kV
VTsec12
Rated VT secondary voltage
110
V
VTprim12
Rated VT primary voltage
400
kV
106
Model setting calculation document for Shunt Reactor Binary input module (BIM) Settings I/O Module 1 I/O Module 2 I/O Module 3 I/O Module 4 I/O Module 5
Operation On On On On On
OscBlock(Hz) 40 40 40 40 40
OscRelease(Hz) 30 30 30 30 30
Pos Slot3 Pos Slot3 Pos Slot3 Pos Slot3 Pos Slot3
Note: OscBlock and OscRelease define the filtering time at activation. Low frequency gives slow response for digital input.
3.4.2 Local Human-Machine Interface Recommended Settings: Table 3-42 gives the recommended settings for Local human machine interface. Table 3-42: Local human machine interface Setting Parameter
Description
Language
Recommended Settings
Unit
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
-
3.4.3 Indication LEDs Guidelines for Settings: This function block is to control LEDs in HMI.
107
Model setting calculation document for Shunt Reactor 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.
Recommended Settings: Table 3-43 gives the recommended settings for Indication LEDs. Table 3-43: LEDGEN Non group settings (basic) Setting Parameter
Recommended
Description
Settings
Unit
Operation
Operation mode for the LED function
On
-
tRestart
Defines the disturbance length
0.0
s
0.0
s
tMax
Maximum time for the definition of a disturbance
SeqTypeLED1
Sequence type for LED 1
LatchedAck-S-F
-
SeqTypeLED2
Sequence type for LED 2
LatchedAck-S-F
-
SeqTypeLED3
Sequence type for LED 3
LatchedAck-S-F
-
SeqTypeLED4
Sequence type for LED 4
LatchedAck-S-F
-
SeqTypeLED5
Sequence type for LED 5
LatchedAck-S-F
-
SeqTypeLED6
Sequence type for LED 6
LatchedAck-S-F
-
SeqTypeLED7
Sequence type for LED 7
LatchedAck-S-F
-
SeqTypeLED8
Sequence type for LED 8
LatchedAck-S-F
-
SeqTypeLED9
Sequence type for LED 9
LatchedAck-S-F
-
SeqTypeLED10
Sequence type for LED 10
LatchedAck-S-F
-
SeqTypeLED11
Sequence type for LED 11
LatchedAck-S-F
-
SeqTypeLED12
Sequence type for LED 12
LatchedAck-S-F
-
SeqTypeLED13
Sequence type for LED 13
LatchedAck-S-F
-
SeqTypeLED14
Sequence type for LED 14
LatchedAck-S-F
-
SeqTypeLED15
Sequence type for LED 15
LatchedAck-S-F
-
108
Model setting calculation document for Shunt Reactor
3.4.4 Time Synchronization Guidelines for Settings: These settings are used for synchronizing IED clock time with network time. Ex: GPS or IRIG-B time. CoarseSyncSrc: Select the time synchronization source available such as SPA, LON, SNTP etc. Synchronization messages from sources configured as coarse are checked against the internal relay time and only if the difference in relay time and source time is more than 10s then relay time will be reset with the source time. This parameter need to be based on time source available in site. FineSyncSource: Select the time source available in network like IRIG-B, GPS, SNTP, SPA etc. once it is selected, time of available time source in network will update to relay if there is a difference in the time between relay and source. This parameter need to be based on time source available in site. SyncMaster: Normally it is set OFF. If time to the relay is received from a GPS antenna (example), make the relay as master to synchronize with other relays. TimeAdjustRate: Fast HWSyncSrc: This is applicable if process bus IEC61850-9-2 protocol is used for receiving analog values (optical CT PTs). In this case select time source available same as that of merging unit. This setting is not applicable in present case. AppSynch: If there is any loss of time sync, protection function will be blocked if AppSynch set to Synch based on SyncAccLevel. If AppSunch set to NoSynch, protection functions are not blocked. Recommended setting is NoSynch. SyncAccLevel: If this is set to “Class T5 (1us)” and time synch error is more than 1us, protection functions will be blocked. SyncAccLevel should be set to “Unspecified” when Nosynch is selected at AppSynch. This parameter is not applicable in present case. ModulePosition: if BIN is set for FineSyncSource, ModulePosition setting is applicable. Here slot position of IO module in the relay is to be set (Which slot is used for BI). This parameter is not applicable in present case. BinaryInput: Which binary input is used for time sync input shall be set here. This parameter is applicable if BIN is set for FineSyncSource. This parameter is not applicable in present case.
109
Model setting calculation document for Shunt Reactor BinDetection: Which edge of input pulse need to be detected has to be set here (positive and negative). This parameter is applicable if BIN is set for FineSyncSource. This parameter is not applicable in present case. ServerIP-Add: Here set Time source server IP address. RedServIP-Add: If redundant server is available, set address of redundant server here. MonthInYear, DayInWeek, WeekInMonth and UTCTimeOfDay for DSTBEGIN and DSTEND are applicable where Day light saving is used. If it is not used set same date for both DSTBEGIN and DSTEND. This setting is not applicable in this case. NoHalfHourUTC: Time shift from GMT has to be set a multiple of half hours. Example for India it is +05:30, means +11. Hence this parameter is set to +11 in present case. SYNCHIRIG-B Non group settings: These settings are applicable if
IRIG-B is used. This
parameter is not applicable in present case. SynchType: Type of hardware input used for time sync, whether Opto or BNC. This parameter is not applicable in present case. TimeDomain: In present case this parameter is set to LocalTime. Encoding: In present case this parameter is set to IRIG-B. TimeZoneAs1344: In present case this parameter is set to PlusTZ.
Recommended Settings: Table 3-44 gives the recommended settings for Time Synchronization. Table 3-44: Time Synchronization TIMESYNCHGEN Non group settings (basic) Setting Parameter
Recommended
Description
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
-
110
Model setting calculation document for Shunt Reactor SYNCHBIN Non group settings (basic) Setting Parameter ModulePosition
BinaryInput BinDetection
Recommended
Description Hardware position of IO module for time Synchronization Binary input number for time Synchronization Positive or negative edge detection
Settings
Unit
3
-
1
-
PositiveEdge
-
SYNCHSNTP Non group settings (basic) Setting Parameter
Description
ServerIP-Add RedServIP-Add
Recommended Settings
Unit
Server IP-address
0.0.0.0
IP Address
Redundant server IP-address
0.0.0.0
IP Address
DSTBEGIN Non group settings (basic) Setting Parameter
Recommended
Description
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
-
3600
s
UTCTimeOfDay
UTC Time of day in seconds when daylight time starts
DSTEND Non group settings (basic) Setting Parameter
Recommended
Description
Settings
Unit
MonthInYear
Month in year when daylight time starts
October
-
DayInWeek
Day in week when daylight time starts
Sunday
-
WeekInMonth
Week in month when daylight time starts
Last
-
3600
s
UTCTimeOfDay
UTC Time of day in seconds when daylight time starts
111
Model setting calculation document for Shunt Reactor TIMEZONE Non group settings (basic) Setting
Recommended
Description
Parameter NoHalfHourUTC
Number of half-hours from UTC
Settings
Unit
+11
-
SYNCHIRIG-B Non group settings (basic) Setting
Recommended
Description
Parameter
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.
3.4.5 Parameter Setting Groups Guidelines for Settings: t: The length of the pulse, sent out by the output signal SETCHGD when an active group has changed, is set with the parameter t. This is not the delay for changing setting group. This parameter is normally recommended to set 1s. MAXSETGR: The parameter MAXSETGR defines the maximum number of setting groups in use to switch between. Only the selected number of setting groups will be available in the Parameter Setting tool (PST) for activation with the ActiveGroup function block. This parameter is normally recommended to set 1.
Recommended Settings: Table 3-45 gives the recommended settings for Parameter Setting Groups. Table 3-45: Parameter Setting Groups ActiveGroup Non group settings (basic) Setting Parameter t
Recommended
Description Pulse length of pulse when setting Changed 112
Settings
Unit
1
s
Model setting calculation document for Shunt Reactor SETGRPS Non group settings (basic) Setting Parameter
Recommended
Description
Settings
Unit
ActiveSetGrp
ActiveSettingGroup
SettingGroup1
-
MAXSETGR
Max number of setting groups 1-6
1
No
3.4.6 Test Mode Functionality TEST Guidelines for Settings: EventDisable: If it is ON, it will disable the events like in DR during test mode. Normally this parameter is set to OFF. CmdTestBit: In present case this parameter is set to Off.
Recommended Settings: Table 3-46 gives the recommended settings for Test Mode Functionality. Table 3-46: Test Mode Functionality TESTMODE Non group settings (basic) Setting Parameter
Recommended
Description
Settings
Unit
TestMode
Test mode in operation (On) or not (Off)
Off
-
EventDisable
Event disable during testmode
Off
-
Off
-
CmdTestBit
Command bit for test required or not during testmode
3.4.7 IED Identifiers Recommended Settings: Table 3-47 gives the recommended settings for IED Identifiers. Table 3-47: IED Identifiers TERMINALID Non group settings (basic) Setting Parameter StationName
Description Station name
Recommended Settings
Unit
Station-A
-
113
Model setting calculation document for Shunt Reactor StationNumber
Station number
0
-
ObjectName
Object name
Bus Reactor
-
ObjectNumber
Object number
0
-
UnitName
Unit name
REC670
-
UnitNumber
Unit number
0
-
3.4.8 Rated System Frequency PRIMVAL Recommended Settings: Table 3-48 gives the recommended settings for Rated System Frequency. Table 3-48: Rated System Frequency PRIMVAL Non group settings (basic) Setting Parameter Frequency
Recommended
Description Rated system frequency
Settings
Unit
50.0
Hz
3.4.9 Signal Matrix For Analog Inputs SMAI Guidelines for Settings: DFTReference: Set ref for DFT filter adjustment here. These DFT reference block settings decide DFT reference for DFT calculations. The settings InternalDFTRef will use fixed DFT reference based on set system frequency. AdDFTRefChn will use DFT reference from the selected group block, when own group selected adaptive DFT reference will be used based on calculated signal frequency from own group. The setting ExternalDFTRef will use reference based on what is connected to input DFTSPFC. There are three different task groups of SMAI with 1ms, 3ms and 8ms. Use of each task group is based on requirement of function, like differential protection requires 1ms, which is faster. Each task group has 12 instances of SMAI, in that first instance has some additional features which is called master. Others are slaves and they will follow master. If measured sample rate needs to be transferred to other task group, it can be done only with master. Receiving task group SMAI DFTreference shall be set to External DFT Ref.
114
Model setting calculation document for Shunt Reactor 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: 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 be set to 10% normally. UBase: Set the base voltage here. This is parameter is set to 400kV.
Recommended Settings: Table 3-49 gives the recommended settings for Signal Matrix For Analog Inputs. Table 3-49: Signal Matrix For Analog Inputs Setting Parameter
Recommended
Description
Settings
Unit
DFTRefExtOut
DFT reference for external output
(As per configuration)
-
DFTReference
DFT reference
(As per configuration)
-
ConnectionType
Input connection type
Ph-Ph
-
TYPE
1=Voltage, 2=Current
1 or 2 based on input
Ch
Negation
Negation
Off
-
10
%
400
kV
MinValFreqMeas UBase
Limit for frequency calculation in % of UBase Base voltage
115
Model setting calculation document for Shunt Reactor
3.4.10 Synchrocheck function (SYN1) Guidelines for Settings: 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 set to 400kV in present case. 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 parameter is set ON.
116
Model setting calculation document for Shunt Reactor 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 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 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. 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 117
Model setting calculation document for Shunt Reactor 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. tAutoEnerg and tManEnerg: Set the time delay for the Auto Energizing and Manual Energizing. The purpose of the timer delay settings, tAutoEnerg and tManEnerg, is to ensure that the dead side remains de-energized and that the condition is not due to a temporary interference. If the conditions do not persist for the specified time, the delay timer is reset and the procedure is restarted when the conditions are fulfilled again. Circuit breaker closing is thus not permitted until the energizing condition has remained constant throughout the set delay setting time. Normally tManEnerg is recommended to set 0.1s. tAutoEnerg is not applicable in present case. OperationSynch: Operation for synchronizing function Off/ On. This parameter is recommended to set OFF. FreqDiffMin, FreqDiffMax, UHighBusSynch, UHighLineSynch, UDiffSynch, tClosePulse, tBreaker, tMinSynch and tMaxSynch: These parameters are not applicable if OperationSynch is set to OFF.
Recommended Settings: Table 3-50 gives the recommended settings for Synchrocheck function. Table 3-50: Synchrocheck function Settings Setting Parameter
Recommended
Description
Settings
Unit
Operation
Operation Off / On
On
-
CBConfig
Select CB configuration
1 1/2 bus CB
-
UBaseBus
Base value for busbar voltage settings
400.000
kV
118
Model setting calculation document for Shunt Reactor UBaseLine
Base value for line voltage settings
400.000
kV
PhaseShift
Phase shift
0
Deg
URatio
Voltage ratio
1.000
-
OperationSynch
Operation for synchronizing function Off/ On
Off
-
On
-
80.0
%UBB
80.0
%UBL
0.15
pu
0.10
Hz
0.10
Hz
30.0
Deg
30.0
Deg
0.100
s
0.100
s
OperationSC
UHighBusSC
UHighLineSC UDiffSC FreqDiffA
FreqDiffM
PhaseDiffA
PhaseDiffM tSCA tSCM
Operation for synchronism check function Off/On Voltage high limit bus for synchrocheck in % of UBaseBus Voltage high limit line for synchrocheck in % of UBaseLine Voltage difference limit in p.u Frequency difference limit between bus and line Auto Frequency difference limit between bus and line Manual Phase angle difference limit between bus and line Auto Phase angle difference limit between bus and line Manual Time delay output for synchrocheck Auto Time delay output for synchrocheck Manual
AutoEnerg
Automatic energizing check mode
Off
-
ManEnerg
Manual energizing check mode
Both
-
ManEnergDBDL
Manual dead bus, dead line energizing
Off
-
80.0
%UBB
80.0
%UBL
40.0
%UBB
40.0
%UBL
UHighBusEnerg
UHighLineEnerg
ULowBusEnerg
ULowLineEnerg
Voltage high limit bus for energizing check in % of UBaseBus Voltage high limit line for energizing check in % of UBaseLine Voltage low limit bus for energizing check in % of UBaseBus Voltage low limit line for energizing check in % of UBaseLine
119
Model setting calculation document for Shunt Reactor
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
SelPhaseBus2
Select phase for busbar2
SelPhaseLine1
Select phase for line1
SelPhaseLine2
Select phase for line2
Phase L1 for busbar1 Phase L1 for busbar2 Phase L1 for line1 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.
120
MODEL SETTING CALCULATION DOCUMENT FOR A TYPICAL IED USED FOR 400kV BUSBAR PROTECTION
Model setting calculation document for Busbar
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
3
2.1.1 Terminal Identification ..................................................................................... 7 2.1.2 List of functions available and those used ....................................................... 7 SETTING CALCULATIONS AND RECOMMENDED SETTINGS FOR REB500 ................. 8
3.1 REB500................................................................................................................................ 8 3.1.1 3.1.2
Busbar Protection (BBP) ................................................................................. 8 Breaker Failure Protection (BFP) ...................................................................11
2
Model setting calculation document for Busbar
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
3
Model setting calculation document for Busbar
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
4
Model setting calculation document for Busbar
SETTING CALCULATION EXAMPLE
SUB-STATION: Station-A 400kV Busbar PROTECTION ELEMENT: Main-I & Main-II Protection Protection schematic Drg. Ref. No. XXXXXX
5
Model setting calculation document for Busbar
1
BASIC SYSTEM PARAMETERS
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 6
Model setting calculation document for Busbar
2
TERMINAL IDENTIFICATION AND LIST OF FUNCTIONS
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 Station Name:
Station-A
Object Name:
400kV Busbar
Unit Name:
REB500
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 REB500 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 REB500
Sl.No.
Function/features available In REB500
Function/feature
Recommended
activated
Settings
Yes/No
provided
1
Busbar protection
YES
2
Breaker failure protection
YES
Note: For setting parameters provided in the function listed above, refer section 5 of “Distributed busbar protection REB500 including line and transformer protection Operating instruction” 1MRB520292-Uen, version 7.6.
7
Model setting calculation document for Busbar
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.
8
Model setting calculation document for Busbar •
3 Phase trip relays shall be provided for each circuit breaker which shall also initiate B.F.P. of concerned breaker.
•
C.T wire supervision relays should be set with a sensitivity such that they can detect C.T. secondary open circuit even in case of least loaded feeder.
•
Bus bar differential protection should have overall sensitivity above heaviest loaded feeder current unless a separate check zone has been provided. In cases where fault currents are expected to be low, the protection should be sensitive enough to take care of such expected low fault current.
Relay operating characteristic is shown in Figure 3-1.
Figure 3-1: Operating characteristics of the restrained amplitude comparison function
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.
9
Model setting calculation document for Busbar Providing the minimum fault current (IKMS) is high enough, IKmin should be set higher than the maximum load current. The ‘restrained amplitude comparison’ algorithm detects an internal fault when the settings for IKmin and k are exceeded. A tripping command is only issued, however, providing the phase comparison function detects an internal fault at the same time. This is normally set to 1.3 times Maximum load current so that the value is set higher than the maximum load current. Lowest fault current that can occur on Busbars are typically very higher than the highest CT ratio. k (Op. char. ‘L1, L2, L3’): The factor “k” (slope) is normally set to 0.80. Numerous tests on a network model have shown this setting to be the most favorable. Note: During a thorough-fault and normal operation, it is impossible for the differential (operating) current to be higher than the restrain current. Differential current alarm (Op. char. ‘L1, L2, L3’): Alarm should be set lower than the lowest load current. A typical setting is 5%. Delay (Op. char. ‘L1, L2, L3’): Differential current alarm, a typical setting is 5s. IKmin (Op. char. ‘L0’): Ikmin for ‘L0’ shall be set to 50% of the Ikmin of L1, L2, L3. The procedure for setting the ground fault characteristic is the same as for phase faults. This dialog is only available providing a neutral current measurement has been configured. k, Differential current alarm, Delay (Op. char. ‘L0’): These parameters are set same as that of Op. char. ‘L1, L2, L3’. IKmin, k, Differential current alarm, Delay (Op. char. ‘Check-Zone’): These parameters are set same as that of Op. char. ‘L1, L2, L3’. These settings are not visible if check zone is not used.
Setting Calculations: 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. 10
Model setting calculation document for Busbar
Recommended Settings: Table 3-1 gives the recommended settings for Differential protection. Table 3-1: Differential protection settings Recommended
Setting Parameter
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
5
s
1300
A
Delay (Differential current alarm) Op. char. ‘L1, L2, L3’ IKmin Op. char. ‘L0’ k
0.80
Op. char. ‘L0’ Differential current alarm Op. char. ‘L0’
5
% IKmin
5
s
Delay (Differential current alarm) Op. char. ‘L0’
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 11
Model setting calculation document for Busbar 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 12
Model setting calculation document for Busbar 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 multiphase 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.
13
Model setting calculation document for Busbar
Guidelines for Settings: 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 14
Model setting calculation document for Busbar 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).
Recommended Settings: Table 3-2 gives the recommended setting for Breaker failure protection. Table 3-2: Breaker failure protection settings Setting Parameter
Recommended Settings
BFP active
Active
Setting (per current transformer)
0.2
Timer 1 active
Active
Timer 2 active
active
Timer t1
100
ms
Timer t2
100
ms
Intertripping pulse duration
200
ms
Logic type
1
15
Unit
IN
PROTECTIVE RELAY SETTING GUIDELINES FOR 220kV, 400kV AND 765kV TRANSMISSION LINES
Table of Contents A.
UNCOMPENSATED TRANSMISSION LINES...................................................................3
1.
ZONE-1 REACH SETTING: ...................................................................................................3
2.
ZONE-2 REACH SETTING: ...................................................................................................3
3.
ZONE-3 REACH SETTING: ...................................................................................................4
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 Page 1 of 19
PROTECTIVE RELAY SETTING GUIDELINES FOR 220kV, 400kV AND 765kV TRANSMISSION LINES
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
Page 2 of 19
PROTECTIVE RELAY SETTING GUIDELINES FOR 220kV, 400kV AND 765kV TRANSMISSION LINES
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. compensation factor KN as (Z0 – Z1) / 3Z1.
Set zero sequence
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. 2. 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 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 Page 3 of 19
PROTECTIVE RELAY SETTING GUIDELINES FOR 220kV, 400kV AND 765kV TRANSMISSION LINES
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, unselectivity 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. 3. ZONE-3 REACH SETTING: 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. Page 4 of 19
PROTECTIVE RELAY SETTING GUIDELINES FOR 220kV, 400kV AND 765kV TRANSMISSION LINES
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 Zone2 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, Page 5 of 19
PROTECTIVE RELAY SETTING GUIDELINES FOR 220kV, 400kV AND 765kV TRANSMISSION LINES
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: t z 2 > t MA + t CB + t z 2 reset + t s
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.
Page 6 of 19
PROTECTIVE RELAY SETTING GUIDELINES FOR 220kV, 400kV AND 765kV TRANSMISSION LINES
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: t z 3 > t MA + tCB + t z 3reset + t s
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.
Page 7 of 19
PROTECTIVE RELAY SETTING GUIDELINES FOR 220kV, 400kV AND 765kV TRANSMISSION LINES
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.
Page 8 of 19
PROTECTIVE RELAY SETTING GUIDELINES FOR 220kV, 400kV AND 765kV TRANSMISSION LINES
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 computeraided 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-tocase 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. Page 9 of 19
PROTECTIVE RELAY SETTING GUIDELINES FOR 220kV, 400kV AND 765kV TRANSMISSION LINES
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
Page 10 of 19
PROTECTIVE RELAY SETTING GUIDELINES FOR 220kV, 400kV AND 765kV TRANSMISSION LINES
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.
Page 11 of 19
PROTECTIVE RELAY SETTING GUIDELINES FOR 220kV, 400kV AND 765kV TRANSMISSION LINES
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.
Page 12 of 19
PROTECTIVE RELAY SETTING GUIDELINES FOR 220kV, 400kV AND 765kV TRANSMISSION LINES
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
Page 13 of 19
PROTECTIVE RELAY SETTING GUIDELINES FOR 220kV, 400kV AND 765kV TRANSMISSION LINES
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 Page 14 of 19
PROTECTIVE RELAY SETTING GUIDELINES FOR 220kV, 400kV AND 765kV TRANSMISSION LINES
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 Page 15 of 19
PROTECTIVE RELAY SETTING GUIDELINES FOR 220kV, 400kV AND 765kV TRANSMISSION LINES
across the capacitor becomes higher than the protective voltage level in each halfcycle. 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. kp =
U MOV U NC
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 Page 16 of 19
PROTECTIVE RELAY SETTING GUIDELINES FOR 220kV, 400kV AND 765kV TRANSMISSION LINES
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 overcurrent 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. Page 17 of 19
PROTECTIVE RELAY SETTING GUIDELINES FOR 220kV, 400kV AND 765kV TRANSMISSION LINES
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 Page 18 of 19
PROTECTIVE RELAY SETTING GUIDELINES FOR 220kV, 400kV AND 765kV TRANSMISSION LINES
Zone-1 is set usually at 80% of Ks x X Z 1 = K S ⋅ ( X 11 + X 12 − X C ) 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.
Page 19 of 19
PROTECTION SYSTEM MANAGEMENT
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. 10.
PERIODIC PROTECTION AUDIT ........................................................................................5 REGULAR TRAINING AND CERTIFICATION.............................................................5
Page 1 of 5
PROTECTION SYSTEM MANAGEMENT
RECOMMENDATIONS FOR PROTECTION SYSTEM MANAGEMENT: During the discussions and interactions with the various stake holders of the protection system, it was strongly felt by the protection sub-committee members that in addition to technical issues related to protection, the management issues related to protection system need to be addressed. A questionnaire related to applicable protection setting & coordination philosophy was sent to all utilities through RPC. Responses were received only from few utilities. These responses show that there is no uniformity in the protection philosophy followed by different utilities throughout the country. Further, lack of response from most of the utilities also indicates the lack of resources on their part to handle the protection system. In order to comprehensively address the protection issues in the utilities, following are the recommendations.
1. ESTABLISHING PROTECTION APPLICATION DEPARTMENT: 1.1. It is recommended that each utility establishes a protection application department with adequate manpower and skill set. 1.2. The protection system skill set is gained with experience, resolving various practical problems, case studies, close interaction with the relay manufactures and field engineers. Therefore it is proposed that such people should be nurtured to have a long standing career growth in the protection application department.
2. RELAY SETTING CALCULATIONS 2.1. The protection group should do periodic relay setting calculations as and when necessitated by system configuration changes. A relay setting approval system should be in place. 2.2. Relay setting calculations also need to be revisited whenever the minor configuration or loading changes in the system due to operational constraints. Feedback from the field/substations on the performance of
Page 2 of 5
PROTECTION SYSTEM MANAGEMENT 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 coordination 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, STUDISCOMS, STU-GEN Companies, CTU-GEN Companies and also generator backup relay setting calculations related to system performance should be periodically reviewed and jointly concurrence should be arrived. The approved relay settings should be properly document. 3.5. Any un-resolved issues among the stakeholders should be taken up with the RPC and resolved.
4. SIMULATION TESTING FOR CHECKING DEPENDABILITY AND SECURITY OF PROTECTION SYSTEM FOR CRITICAL LINES AND SERIES COMPENSATED LINES 4.1. Committee felt that even though Real Time Digital Simulation (RTDS) and other simulation facilities are available in the country, use of the same by the protection group is very minimum or nil. 4.2. It is recommended that protection system for critical lines, all series compensated lines along with interconnected lines should be simulated for intended operation under normal and abnormal system conditions Page 3 of 5
PROTECTION SYSTEM MANAGEMENT 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 VERIFICATION OF SETTING AT SITE
AND
FUNCTIONAL
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 4 of 5
PROTECTION SYSTEM MANAGEMENT 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.
Page 5 of 5
CHECK LIST FOR AUDIT OF FAULT CLEARANCE SYSTEM FOR 765kV, 400kV & 220kV SUBSTATIONS
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 1 of 16
CHECK LIST FOR AUDIT OF FAULT CLEARANCE SYSTEM FOR 765kV, 400kV & 220kV SUBSTATIONS
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 & 3ph 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 2 of 16
CHECK LIST FOR AUDIT OF FAULT CLEARANCE SYSTEM FOR 765kV, 400kV & 220kV SUBSTATIONS
8.
Resistive reach for Ground fault element set to give maximum
YES
NO
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) 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 ?
YES
NO
In case any other value has been set for Zone-II timer, kindly specify the value and justification thereof. 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
YES
NO
apparent bus bar fault resistance, when allowing for multiple in feeds from other circuits? 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?
YES
NO
YES
NO
Whether SOTF initiation has been implemented using hardwire logic
Page 3 of 16
CHECK LIST FOR AUDIT OF FAULT CLEARANCE SYSTEM FOR 765kV, 400kV & 220kV SUBSTATIONS
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?
YES
NO
YES
NO
YES
NO
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.) 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)
Page 4 of 16
CHECK LIST FOR AUDIT OF FAULT CLEARANCE SYSTEM FOR 765kV, 400kV & 220kV SUBSTATIONS
23.
Is the Distance communication. Scheme Permissive Over Reach (POR) applied for short lines and Permissive Under Reach (PUR) applied for long lines?
YES
NO
If any other communication scheme has been applied, please provide the detail with justification thereof. 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.)
28.
a) What are the Zones blocked on Power swing block function: b) Setting for Unblock timer: (typical 02 second)
I= V= Angle: S= Z1 / Z2 / Z3 / Z4 Time:
c) Out of Step trip enabled
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 ?
YES
NO
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 Page 5 of 16
Standalone / builtin YES
NO
CHECK LIST FOR AUDIT OF FAULT CLEARANCE SYSTEM FOR 765kV, 400kV & 220kV SUBSTATIONS
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:
YES
NO
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)
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 6 of 16
CHECK LIST FOR AUDIT OF FAULT CLEARANCE SYSTEM FOR 765kV, 400kV & 220kV SUBSTATIONS
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.
YES
NO
YES
NO
b) Do the back-up earth fault relays have harmonic restrain feature 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
YES
NO
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 time synchronising equipment
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:
YES
NO
Group A •
Page 7 of 16
Biased differential relay
Group B R.E.F Protection
CHECK LIST FOR AUDIT OF FAULT CLEARANCE SYSTEM FOR 765kV, 400kV & 220kV SUBSTATIONS
•
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?
YES
NO
b) Whether standalone or built in Main relay c) Whether DR is having automatic fault record download facility to a central PC
Standalone/builtin 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 8 of 16
CHECK LIST FOR AUDIT OF FAULT CLEARANCE SYSTEM FOR 765kV, 400kV & 220kV SUBSTATIONS
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
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? b) Whether standalone or built in Main relay
c) Whether DR is having automatic fault record download facility to a central PC
2.
Standalone / builtin YES
NO
d) Whether Central PC for DR , EL are powered by Inverter (fed from station DC)
YES
NO
Whether DR is having the following main signals for lines:
YES
NO
Analogue signals: •
From CT: IA, IB, IC, IN
•
From VT: VAN, VBN, VCN
•
From Aux. VT: V0
Digital Signals • Page 9 of 16
Main 1 Carrier receive
CHECK LIST FOR AUDIT OF FAULT CLEARANCE SYSTEM FOR 765kV, 400kV & 220kV SUBSTATIONS
•
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 10 of 16
CHECK LIST FOR AUDIT OF FAULT CLEARANCE SYSTEM FOR 765kV, 400kV & 220kV SUBSTATIONS
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 11 of 16
CHECK LIST FOR AUDIT OF FAULT CLEARANCE SYSTEM FOR 765kV, 400kV & 220kV SUBSTATIONS
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
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 ?
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.
Page 12 of 16
( Ph-Ph / Ph-G/ Inter-circuit) YES
NO
( One / two) YES
NO
YES
NO
Dedicated / multiplexed
CHECK LIST FOR AUDIT OF FAULT CLEARANCE SYSTEM FOR 765kV, 400kV & 220kV SUBSTATIONS
H. Station DC supply systems 1.
Do you have two separate independent DC system (220V or 110V)
YES
NO
YES
NO
(Source-A and Source-B) 2.
Do you have two independent DC system (48V) for PLCC (source-A and source-B)
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:
YES
NO
YES
NO
YES
NO
a) Protection b) CB functions c) Isolator / earth switch functions d) Annunciation / Indications e) Monitoring functions 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
7
Is guidelines prescribed in CBIP manual 274 & 296 followed in general
Page 13 of 16
CHECK LIST FOR AUDIT OF FAULT CLEARANCE SYSTEM FOR 765kV, 400kV & 220kV SUBSTATIONS
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 14 of 16
CHECK LIST FOR AUDIT OF FAULT CLEARANCE SYSTEM FOR 765kV, 400kV & 220kV SUBSTATIONS
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)
7.
What is the overreaching (Zone 2) setting in used teleprotection schemes
8.
What kinds of measurement techniques are used to cope with voltage inversion?
% of line length Rationale: % of line length Rationale: Phase locked voltage memory Intentional time delay Other, specify:
9.
Whether system studies carried out to check the possibility of
YES
NO
YES
NO
current inversion due to series compensation
10.
Whether any system studies conducted to find the impact of
Page 15 of 16
CHECK LIST FOR AUDIT OF FAULT CLEARANCE SYSTEM FOR 765kV, 400kV & 220kV SUBSTATIONS
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 /
YES
NO
YES
NO
YES
NO
setting revised after the introduction of series compensation?
12.
Is dynamic simulation done to fine tune settings of distance relay installed on series compensated double circuit lines?
13.
Whether performance of directional earth fault relay verifies by simulation studies
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-
YES
NO
YES
NO
YES
NO
harmonic oscillations?
16.
Whether MOV influence considered while setting the distance relay reach
17.
Have you experienced any security problems (Relay maloperation) with high frequency transients caused by Flashover of spark gaps Line energisation Other, specify:
18.
If YES, how the above problem has been addressed?
Page 16 of 16
__________________
DETAILS OF PROTECTION AUDIT A. 1 3 5
General Information: Name of Substation Type of Bus Switching Scheme:
Instrument Transformer
A
Current transformer (C T)
a
4 Whether SLD collected or Not:
Audit Team: 1. 2. 3.
1)
1
2 Date of first commissioning
( To be filled for each one of them)
Location of CT Date of CT ratio Test Testing
b Core I
Core II
Core III
Core I
Core II
Core III
Core I
Core II
Core III
i ii iii
Ratio Adopted Ratio measured error calculated Knee point voltage
B
Capacitive voltage transformer (C V T)
1 a b
Location of CVT Date of Testing CVT ratio Test
i ii iii
Ratio Adopted Ratio measured error calculated
2 a b
Location of CVT Date of Testing CVT ratio Test
i
Ratio Adopted
Core IV
Core V
Core VI
ii iii
Ratio measured error calculated
2)
Availability of Protection System
A)
Bus Bar relay 765kV
i)
Make and Model of Bus Bar relay
ii)
Whether stability checks done or not Date of testing Remarks (if any)
iii) iv)
C)
400kV
220kV
Sub-station protection and monitoring Equipments
System i) II) III)
765kV System 400kV System 220kV System
D.
Transmission Line Protection
Name of Line
LBB (Make & Model)
Main-I Protection (Make and Model)
i) ii) iii) iv) v) vi)
Line-1 Line-2 Line-3 Line-4 Line-5 Line-6
E)
Transformer Protection
Functional (Yes / No)
Functional (Yes / No)
Date of last testing
Event Logger (Make & Model)
Date of testing
Main-II Protection (Make and Model)
Functional (Yes / No)
Functional (Yes / No)
Synchonising Facility Available or not
Date of testing
Synchro Check Relay (Make and Model)
LBB Protection (Make and Model)
Setting of Synhrocheck Relay
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
Name of ICT
i) ii) iii) iv)
ICT-1 ICT-2 ICT-3 ICT-4
F)
Reactor Protection
Name of Reactor
i) ii) iii) iv)
Line -1 Reactor Line -2 Reactor Bus Reactor-1 Bus Reactor-2
3)
Line Parameter
i) ii) iii)
iv) a b
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
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
Line 1 Name of Line Line Length Line Parameters ( In Ohms/Per KM/Per Phase Primary value) R1 X1 Ro Xo RoM XoM Present Relay setting Adopted Relay setting Recommended
Line 2
Line 3
Line 4
Line 5
Line 6
Enclosed as Annexure -I ( Please enclose the settings for all lines, transformers, Reactors and Bus Bars) Enclosed as Annexure -II ( Please enclose the settings for all lines, transformers, Reactors and
LA Rating HV Side
LA Rating IV Side
relay setting
4)
Bus Bars)
DC supply 220 /110 V DC-I
a i) ii) b c
5)
Measured voltage (to be measured at furthereset Panel Positive to Earth Negative to Earth No.of Cells Per Bank Availability of Battery Charger
Yes/No
48 V DC-I
48 V DC-II
NA
NA
Yes/No
Yes/No
Status of Breaker Available or Not
No.of trip/close coil & healthiness
Yes/No
Circuit Breaker Make and Model
A. i). ii). iii). iv). v). vi). B. i). ii). iii). iv). v). vi). vii). viii) . ix). x). B i). ii). iii). iv). v).
220 /110 V DC-II
765kV System 765kV Bay-1 765kV Bay-2 765kV Bay-3 765kV Bay-4 765kV Bay-5 765kV Bay-6 400kV System 400 KV Bay-1 400 Kv Bay-2 400 Kv Bay-3 400 Kv Bay-4 400 Kv Bay-5 400 Kv Bay-6 400 Kv Bay-7 400 Kv Bay-8 400 Kv Bay-9 400 Kv Bay-10 220kV System 220kV Bay-1 220kV Bay-2 220kV Bay-3 220kV Bay-4 220kV Bay-5
PIR (Available or Not)
Date of Last Timing taken
Remarks (If any)
vi). vii). viii) .
6)
220kV Bay-6 220kV Bay-7 220kV Bay-8 Note: rows to be added / deleted as required for no. of bays Availability of auxiliary System
i) Auxiliary Supply Supply-I Supply-II ii)
7)
8)
9)
Source of Supply
DG Set Make Rating Whether Dg set on Auto or manual Fuel level Availability of UFR relay Make Setting Availability of df/dt relay Make Setting Special Protection Scheme (SPS) Available (Yes/No) Verification
10)
Status of Corrective action based on Tripping analysis
11)
Any Other Observation/ Comments
Reliability of Supply
Average tripping per month