Guidelines Relay Setting
Short Description
REL670...
Description
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.
-3-
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
3
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
4
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
5
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
6
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
7
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
8
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.
9
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
14
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.
15
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: 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
82
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.
83
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
84
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.
86
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.
87
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.
89
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.
116
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
-
118
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.
121
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
122
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.
124
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.
125
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.
126
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
127
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: 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: 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
View more...
Comments
