Sp 1107 Electrical Protection Systems.pdf

Petroleum Development Oman L.L.C. SP-1107 Specification for Electrical Protection System

Document ID

Document Type

Security

Discipline

Owner

Issue Date

Revision

SP-1107

Specification

Restricted

Electrical

UIE (UEE) – CFDH-Electrical

Oct. 16

4.0

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i

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Document Authorisation

Authorised For Issue

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ii Revision History The following is a brief summary of the 4 most recent revisions to this document. Details of all revisions prior to these are held on file by the issuing department.

Rev No. Version 2.0

Date Jan 00

Author Shailesh Desai, OIE/1

Version 2.1 Revision 3

Sep 03 Jul’08

Revision 4

Oct. 16

Wim Moelker, TTE/1 Van Zanten Wouter, UIE/1 Khalid Zadjali - UIE/6

Scope / Remarks Revised and converted to Specification as per PDO Policy Cascade Revised as per periodical review policy Thoroughly revised Thoroughly revised

iii Related Business Processes Code

Business Process (EPBM 4.0)

iv Related Corporate Management Frame Work (CMF) Documents The related CMF Documents can be retrieved from the Corporate Business Control Documentation Register CMF.

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TABLE OF CONTENTS i

Document Authorisation ...................................................................................................... 3

ii

Revision History.................................................................................................................... 4

iii

Related Business Processes ............................................................................................... 4

iv

Related Corporate Management Frame Work (CMF) Documents ................................... 4

1

Introduction ..................................................................................................................... 1413 1.1

SCOPE ........................................................................................................................ 1413

1.2

COMPLIANCE WITH STANDARD ............................................................................. 1413

1.3 APPLICABLE STANDARDS, SPECIFICATIONS AND CODES ................................ 1413 1.3.1 PDO Standards ......................................................................................... 1413 1.3.2 SIOP/SIEP Standards ............................................................................... 1514 1.3.3 International Standards ............................................................................. 1514 2

General Protection Requirements................................................................................. 1716 2.1 PROTECTION PHILOSOPHY .................................................................................... 1716 2.1.1 Objectives.................................................................................................. 1716 2.1.2 Application of Relays to Standard Schemes ............................................. 1817 2.1.3 132kV Substations with Breaker-and-Half Scheme .................................. 1817 2.1.4 Automatic Bus Transfer Schemes............................................................. 1918 2.1.5 Circuit Breakers for Generators, Motors and 132kV Feeders ................... 1918 2.1.6 Opening time for HV vacuum contactor or circuit breaker ........................ 1918 2.1.7 33kV Expulsion Fuse, PMR & Outdoor CB ............................................... 1918 2.1.8 Transformers in 33kV OHL system ........................................................... 2019 2.2

SYSTEM EARTHING.................................................................................................. 2019

2.3 RELAY SPECIFICATIONS ......................................................................................... 2019 2.3.1 Communication Requirements .................................................................. 2120 2.3.2 Relay setting, configuring Tool & the relay soft files ................................. 2120 2.3.3 Other Requirements .................................................................................. 2120 2.3.4 Use of Relays for Operational Interlocks etc. ............................................ 2221 2.3.5 Relay Operation Indication ........................................................................ 2221 2.4

RELAY COMMUNICATION SYSTEM ........................................................................ 2221

2.5

MULTIFUNCTION METER (MFM) ............................................................................. 2423

2.6

CURRENT TRANSFORMERS ................................................................................... 2423

2.7

VOLTAGE TRANSFORMERS .................................................................................... 2625

2.8 INSTALLATION AND DESIGN REQUIREMENTS..................................................... 2726 2.8.1 General Requirements .............................................................................. 2726 2.8.2 Protection, Control & Metering schemes - Lead numbering ..................... 2826 2.8.3 Earthing ..................................................................................................... 2827 2.8.4 Current Transformer Earthing ................................................................... 2827 2.8.5 Connections for Protection Testing ........................................................... 2928 2.8.6 Power Supply to Protection Relays ........................................................... 2928 2.8.6.1 PMR Control / Protection Power Supplies ................................................ 3029 2.8.7 Labelling .................................................................................................... 3029 2.8.8 Miniature Circuit Breakers (MCBs) ........................................................... 3029 3

Specific Protection Requirements ................................................................................ 3130 3.1 OVERHEAD LINE FEEDERS – UP TO 33KV ............................................................ 3130 3.1.1 Overhead Line Feeder - 33kV Switchboard .............................................. 3130 3.1.2 Pole Mounted Reclosers (PMRs) .............................................................. 3231

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Petroleum Development Oman LLC 3.1.2.1 3.1.2.2 3.1.2.3 3.1.2.4 3.1.2.5 3.1.3

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33kV Switchrack incomer PMRs ............................................................... 3231 33kV Unit Transformer PMRs/Outdoor CBs ............................................. 3231 33kV Switchrack outgoing OHL feeders / OHL Tap-off PMRs .................. 3231 33kV OHL Spur-line PMRs ........................................................................ 3231 Pipeline Protection PMRs .......................................................................... 3332 Auto-reclose Function ................................................................................ 3332

3.2 33KV INTERCONNECTIONS BETWEEN STATIONS............................................... 3332 3.2.1 Line differential Protection ......................................................................... 3332 3.2.2 Back-up protection ..................................................................................... 3433 3.3 132KV OVERHEAD LINES ......................................................................................... 3433 3.3.1 Main-1 and Main-2 Protection Relays ....................................................... 3433 3.3.1.1 Line Differential Protection (87L) ............................................................... 3433 3.3.1.2 Distance Protection (21) ............................................................................ 3534 3.3.1.3 Power swing blocking ................................................................................ 3534 3.3.1.4 Voltage transformer supervision (VTS) ..................................................... 3534 3.3.1.5 Switch onto fault (SOTF) ........................................................................... 3534 3.3.1.6 Self-Monitoring .......................................................................................... 3534 3.3.1.7 Echo of tele-protection signal when circuit breaker is open ...................... 3534 3.3.1.8 Weak in-feed ............................................................................................. 3635 3.3.1.9 Current reversal guard............................................................................... 3635 3.3.1.10 Directional Earth fault (DEF) ..................................................................... 3635 3.3.1.11 Directional Overcurrent (DOC) .................................................................. 3635 3.3.1.12 Broken conductor protection & Thermal protection ................................... 3635 3.3.2 Auto-reclose and Synchronising Check Relay .......................................... 3635 3.3.2.1 Auto-reclose (79) ....................................................................................... 3635 3.3.2.2 Synchronising Check (25CH) .................................................................... 3635 3.3.2.3 Breaker Fail (50BF) Protection .................................................................. 3736 3.3.2.4 Undervoltage Protection (27)..................................................................... 3736 3.3.2.5 Voltage transformer supervision (VTS) ..................................................... 3736 3.3.2.6 132kV RIMA, RUNIB, NIM(W), NIM(E), AMAL & MAR Substations – VT Secondary circuits ..................................................................................... 3736 3.4 TRANSFORMER PROTECTION................................................................................ 3736 3.4.1 Specification of Transformer Protection .................................................... 3736 3.4.1.1 Transformer Biased Differential and Restricted Earth Fault Protection Specification .............................................................................................. 3736 3.4.1.2 Directional and Non Directional Overcurrent & Earth fault Protection....... 3837 3.4.1.3 Standby Earth fault protection ................................................................... 3837 3.4.1.4 Non-Electrical Protection devices .............................................................. 3938 3.4.2 Transformer Protection Schemes .............................................................. 3938 3.4.2.1 HV Switchboards with incomers working in parallel .................................. 3938 3.4.2.2 Transformers with HV (6.6kV or 11kV or 33kV) primary and 415V secondary winding....................................................................................................... 4039 a) Transformers Controlled by Fused Contactors ......................................... 4140 b) Transformers Connected To HV Fuses..................................................... 4140 c) Transformers Connected to HV Circuit Breakers ...................................... 4241 3.4.2.3 Transformers with HV primary (33kV and below) and HV secondary windings ................................................................................................................... 4241 3.4.2.4 Transformers with 132kV primary and 33kV, 11kV or 6.6kV secondary windings ..................................................................................................... 4241 3.4.2.5 Auto Transformers ..................................................................................... 4342 3.5 MAIN GENERATING UNITS....................................................................................... 4342 3.5.1 General ...................................................................................................... 4342 3.5.2 Specific Protection Functions .................................................................... 4443 3.5.2.1 Generator differential (87G)....................................................................... 4443 3.5.2.2 Overall generator and generator transformer differential and REF (87GT, 87N(HV)) ................................................................................................... 4443 Page 6

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Petroleum Development Oman LLC 3.5.2.3 3.5.2.4 a) b) c) 3.5.2.5 3.5.2.6 3.5.2.7 3.5.2.8 3.5.2.9 3.5.2.10 3.5.2.11 3.5.2.12 3.5.2.13 3.5.2.14 3.5.2.15 3.5.2.16 3.6

Revision: 4.0 Effective: Oct. 16

Generator-Transformer HV Overcurrent & Earth fault Protection: ............ 4443 Earth fault Protection ................................................................................. 4443 Stator earth fault protection – 0-95% (59N, 50/51G)................................. 4443 Stator earth fault Protection – 95-100% .................................................... 4544 Generator Busbar Earth fault protection (59BN) ....................................... 4544 Overfluxing (24) ......................................................................................... 4645 Loss of excitation (40) ............................................................................... 4645 Reverse power (32R) ................................................................................ 4645 Negative phase sequence (46) ................................................................. 4746 Dead machine protection / Inadvertent Energisation (AE) Protection (50/27G) ................................................................................................................... 4746 Pole slipping protection (78) ...................................................................... 4746 Undervoltage and Overvoltage Protection (27/59) .................................... 4746 Underfrequency and overfrequency protection (81U/O) ........................... 4746 Backup overcurrent protection, Voltage dependent (51V) ........................ 4746 Under Impedance protection (21G/21GT)................................................. 4847 Breaker failure (50BF) ............................................................................... 4847 Other protections ....................................................................................... 4948

LV GENERATING UNITS ........................................................................................... 4948

3.7 132KV AND 33KV BUSBAR PROTECTION .............................................................. 4948 3.7.1 General ...................................................................................................... 4948 3.7.1.1 132kV Substations .................................................................................... 4948 3.7.1.2 33kV Switchboards.................................................................................... 4948 3.7.2 Protection Scheme Requirements ............................................................ 4948 3.7.3 Schemes ................................................................................................... 5049 3.7.3.1 Busbar with two or more Bus Sections ..................................................... 5049 Isolator Contacts ........................................................................................................ 5049 3.7.3.2 Double Busbar with Low Impedance Busbar Differential Protection ......... 5049 a) CT Switching ............................................................................................. 5049 b) Isolator Contacts ....................................................................................... 5149 3.7.3.3 Busbar with single Bus Section ................................................................. 5150 3.8 MOTOR PROTECTION .............................................................................................. 5150 3.8.1 General ...................................................................................................... 5150 3.8.1.1 Vital / Essential Duty motors – short time voltage dips ............................. 5150 a) Definition: Vital Service ............................................................................. 5150 b) Definition: Essential Service...................................................................... 5150 3.8.1.2 Type of Switchgear for Drives ................................................................... 5250 3.8.1.3 Vital service motors including Fire safety related ones ............................. 5251 3.8.2 LV Motors .................................................................................................. 5251 3.8.3 HV Motors ................................................................................................. 5251 3.8.3.1 Protection Requirements - General........................................................... 5251 3.8.3.2 Unit Transformer-motor & Earth fault protection ....................................... 5453 3.8.3.3 Protection Scheme Requirements ............................................................ 5453 a) Breaker failure (BF) protection .................................................................. 5453 b) Unit Transformer - Motor ........................................................................... 5453 c) Unit Transformer – Synchronous Motor .................................................... 5453 d) Schemes with long cables / OHL on Unit Transformer secondary ........... 5554 e) Schemes other than those covered in SP ................................................. 5554 3.8.3.4 Unit Transformer- Motor with VSD ............................................................ 5554 3.9 CAPACITOR BANKS .................................................................................................. 5655 3.9.1 General ...................................................................................................... 5655 3.9.2 Motor Capacitors ....................................................................................... 5655 3.9.3 Switchboard Capacitors ............................................................................ 5756

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3.10 UNDERVOLTAGE / OVERVOLTAGE RELAYS ......................................................... 5756 3.11 UNDERFREQUENCY LOAD SHEDDING .................................................................. 5756 3.11.1 Relay Requirements .................................................................................. 5756 3.11.2 Application of the Scheme ......................................................................... 5756 3.11.3 Scheme Requirement ................................................................................ 5756 3.11.3.1 Unit Transformer - Motors ......................................................................... 5856 3.12 SYNCHRONISING ...................................................................................................... 5857 3.12.1 Relay Specification .................................................................................... 5957 3.12.2 Synchronisation Schemes for Substations ................................................ 5958 3.13 AUXILIARY RELAYS................................................................................................... 6058 3.13.1 Trip Circuit Supervision ............................................................................. 6058 3.13.2 Trip and Lockout Relays ............................................................................ 6059 3.13.3 Interposing Relays ..................................................................................... 6160 4

Protection Calculations, Settings and Representation ............................................... 6261 4.1 GENERAL ................................................................................................................... 6261 4.1.1 Documentation Preparation and References ............................................ 6261 4.1.2 Basis for Calculations and Guidelines for Time Grading........................... 6362 4.1.2.1 Fault Currents ............................................................................................ 6362 4.1.2.2 Time decrement......................................................................................... 6362 4.1.2.3 Grading Margins ........................................................................................ 6362

5

Specific Protection Setting Requirements ................................................................... 6564 5.1 OVERHEAD LINE FEEDERS - 33KV AND BELOW .................................................. 6564 5.1.1 HV Fuses ................................................................................................... 6564 5.1.2 Overcurrent and Earth fault Protection ...................................................... 6564 5.1.3 Directional Overcurrent and Earth fault Elements ..................................... 6564 5.1.4 CBCT Connected Earth fault Protection .................................................... 6665 5.1.5 Thermal & Broken Conductor Protections ................................................. 6665 5.1.6 Pole Mounted Reclosers (PMRs) .............................................................. 6766 5.1.6.1 Overcurrent & Earth fault Protection Settings for End PMRs .................... 6766 5.1.6.2 Overcurrent & Earth fault Protection Settings for Upstream PMRs........... 6766 5.1.6.3 Other settings for PMRs ............................................................................ 6766 5.2 33KV INTERCONNECTIONS BETWEEN STATIONS............................................... 6766 5.2.1 Line Differential Protection ........................................................................ 6766 5.2.2 Back-up protection ..................................................................................... 6866 5.3 132KV OVERHEAD LINES ......................................................................................... 6867 5.3.1 Main-1 and Main-2 Protection Relays ....................................................... 6867 5.3.1.1 Line Differential Protection ........................................................................ 6867 5.3.1.2 Distance Protection -Scheme .................................................................... 6867 5.3.1.3 Distance Protection - Choice of Characteristics ........................................ 6867 5.3.1.4 Distance Protection - Zone Settings .......................................................... 6867 5.3.1.4.1 132kV OHL Impedance Data..................................................................... 6867 5.3.1.4.2 Zone 1 setting ............................................................................................ 6867 5.3.1.4.3 Zone 2 setting ............................................................................................ 6867 5.3.1.4.4 Current Reversal Guard timer setting ........................................................ 6968 5.3.1.4.5 Zone 3 setting ............................................................................................ 6968 5.3.1.4.6 Zone 4 setting ............................................................................................ 6968 5.3.1.4.7 Mutual compensation ................................................................................ 6968 5.3.1.4.8 Load Impedance and resistive reach setting ............................................. 6968 5.3.1.5 Power Swing Blocking ............................................................................... 7069 5.3.1.6 Directional Earth fault (DEF) Element ....................................................... 7069 5.3.1.7 Directional Overcurrent (DOC) .................................................................. 7069 5.3.1.8 VTS, SOTF, TOR, Fault Locator, functions ............................................... 7069 5.3.1.9 Time delay settings .................................................................................... 7170 5.3.1.10 Thermal Overload and Broken conductor protection Settings................... 7170

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Auto-reclose and Synchronising Check Relay .......................................... 7170 Auto-reclose Function ............................................................................... 7170 Synchronising Check Function .................................................................. 7271 Breaker Fail Protection .............................................................................. 7271 Undervoltage Protection ............................................................................ 7271 VT Supervision .......................................................................................... 7271

5.4 TRANSFORMER PROTECTION ............................................................................... 7271 5.4.1 Fuses for Transformer Protection ............................................................. 7271 5.4.2 Overcurrent and Earth fault Settings ......................................................... 7372 5.4.2.1 Highset Overcurrent element pickup setting ............................................. 7372 5.4.2.2 Coordination between 132kV Transformer highset protection & Zone 2 of upstream 132kV OHLs .............................................................................. 7372 5.4.2.3 Coordination between Transformer incomer overcurrent protection and downstream motor feeders ....................................................................... 7372 5.4.2.4 Primary Overcurrent Protection Coordination for ph-ph faults on secondary (Dy) ............................................................................................................ 7472 5.4.2.5 Transformer Primary Overcurrent protection and Standby Earth fault protection on Secondary ........................................................................... 7473 5.4.2.6 Earth fault protection settings .................................................................... 7473 5.4.2.7 Fused contactors and Feeder protection .................................................. 7573 5.4.2.8 Transformer (with 415V Secondary) Protection ........................................ 7574 5.4.2.9 415V Standby earth fault protection .......................................................... 7574 5.4.3 Directional Overcurrent / Earth fault Elements.......................................... 7574 5.4.4 Transformer Biased Differential Protection ............................................... 7674 5.4.5 Transformer Restricted Earth fault Protection........................................... 7675 5.4.6 OLTC-AVR ................................................................................................ 7675 5.5 GENERATOR / GENERATOR TRANSFORMER ...................................................... 7775 5.5.1 Generator Differential Protection............................................................... 7776 5.5.2 Generator, Generator-Transformer Differential and HV Restricted Earth Fault .................................................................................................................. 7776 5.5.3 Generator-Transformer HV Overcurrent & Earth fault Protection: ............ 7776 5.5.4 Stator Earth fault ....................................................................................... 7776 5.5.5 Overfluxing ................................................................................................ 7776 5.5.6 Overvoltage ............................................................................................... 7876 5.5.7 Loss of Excitation ...................................................................................... 7877 5.5.8 Reverse Power / Low Forward Power ....................................................... 7877 5.5.9 Negative Phase Sequence ........................................................................ 7877 5.5.10 Underfrequency and Overfrequency ......................................................... 7877 5.5.11 Backup Overcurrent Protection (51V) ....................................................... 7977 5.5.12 Under Impedance Protection (21G/21GT) ................................................ 7978 5.6

LV GENERATORS ..................................................................................................... 7978

5.7

BUSBAR PROTECTION............................................................................................. 7978

5.8 MOTOR PROTECTION .............................................................................................. 8079 5.8.1 Fuses for Motor Protection ........................................................................ 8079 5.8.2 Motor Protection Relay .............................................................................. 8079 5.8.2.1 Short Circuit Protection (50) settings ........................................................ 8079 5.8.2.2 Earth fault Protection (51G) settings ......................................................... 8179 5.8.2.3 Thermal Overload protection (49) settings ................................................ 8180 5.8.2.4 Prolonged Start & Stall Protection (51S/LR) settings ................................ 8180 5.8.2.5 Negative phase sequence protection (46) settings ................................... 8180 5.8.2.6 Neutral voltage displacement protection (59N) settings ........................... 8280 5.8.2.7 Out-of-step protection (78) for Synchronous motors ................................. 8281 5.8.2.8 Loss of Excitation protection (40) for Synchronous motors ...................... 8281 5.8.2.9 Overvoltage protection (59) for Synchronous motors ............................... 8281 5.8.2.10 Additional requirements for Vital Service / Fire-safety related drives ....... 8281 5.8.3 Motors driven by VSDs ............................................................................. 8281 Page 9

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UNDERFREQUENCY LOAD SHEDDING & START INHIBITION ............................. 8381

5.10 SYNCHRONISING ...................................................................................................... 8382 5.10.1 33/11/6.6kV switchboards.......................................................................... 8382 5.10.2 Generators / Generator transformer feeders at Power Stations................ 8382 5.10.3 132kV OHLs .............................................................................................. 8482 5.11 VOLTAGE RELAYS .................................................................................................... 8483 5.11.1 6.6kV / 11kV Induction Motors ................................................................... 8483 5.11.2 Synchronous motor.................................................................................... 8483 5.11.3 Voltage Relays for Automatic Bus Transfer Scheme ................................ 8483 5.11.4 Protection Relays with voltage input.......................................................... 8483 5.12 THERMAL PROTECTION OF TRANSFORMERS ..................................................... 8583 5.13 DISTURBANCE RECORDER SETTINGS.................................................................. 8584 5.13.1 Electromechanical etc. relays in the substaion.......................................... 8584

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Protection and Control Logic Diagrams....................................................................... 8685

7

Numerical Relays, Representation of Details .............................................................. 8786 7.1

SCOPE OF WORK DURING DETAILED DESIGN (PANEL ENGINEERING) .......... 8786

7.2

SCOPE OF WORK DURING PROTECTION SETTINGS .......................................... 8786

8

Indicating lamps.............................................................................................................. 8988

9

Alarm schemes................................................................................................................ 9089

10 Definitions ....................................................................................................................... 9190 10.1 GENERAL ................................................................................................................... 9190 10.2 TECHNICAL ................................................................................................................ 9190 10.3 ABBREVIATIONS ....................................................................................................... 9190 Appendix A: Check list of Information to be provided to PDO for the purpose of Protection Assessment ................................................................................. 9493 Appendix B: ANSI / IEC Symbols.......................................................................................... 9695 Appendix C: Generator/GSUT/UAT Trip Matrix (Includes Protection Alarms) – Typical 9897 Appendix D: Trip Matrix - Transformer feeder (Typical) ............................................... 101100 Appendix E: Trip Matrix - 132kV OHL Feeder (Typical) ................................................. 103102 Appendix F: Trip Matrix - 33kV OHL/Cable Feeder (Typical) ........................................ 104103 Appendix G: Trip Matrix - HV Motor Protection (Typical) ............................................. 105104 Appendix H: Trip Matrix - HV Unit Trafo - Motor Protection (Typical) ......................... 106105 Appendix I: Technical Differences between MVAA relays and PRIMA relays .............. 107106 Appendix J: Expulsion Fuse Links Current-Time Characteristic Curves .................... 108107 Appendix K: Synchronous Motors – Typical Voltage – Time Stability Characteristic 110109 Appendix L: Elm Conductor – Thermal Overload Characteristic (Typical) .................. 111110 Appendix M: Motor Protection Relay – Programmable Scheme Logic ........................ 112111 Appendix Q: Typical Protection Settings for Capacitor Banks ..................................... 116115 Appendix R: Typical Settings for Automatic Power Factor Controller (APFC) with Capacitor Banks ......................................................................................... 117116 SP USER-COMMENT FORM .............................................................................................. 118117 ASSOCIATED DIAGRAMS Figure No.

Drawing No., Rev. STD 4 6500 XXX

Title INDEX, LEGEND ETC.

Index

STD 4 6500 000 D

Index Sheet /SP1107 Standard Drawings

Legend

STD 4 6500 001 D

Legend Sheet/Electrical Symbols

STD 4 6501 xxx

33KV OHL / CABLE

Figure 1.1

STD 4 6501 001 D

Protection and Metering SLD for 33kV Overhead Line / Cable Feeder

Figure 1.2

STD 4 6501 002 C

Protection and Metering SLD for 33kV Overhead Line / Cable (Interconnector with Bi-directional Power Flow)

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Figure No.

Drawing No., Rev. STD 4 6502 xxx

Title 132KV OHL / CABLE

Figure 2.1

STD 4 6502 001 D

Protection and Metering SLD for 132kV Overhead Line

STD 4 6503 xxx

TRANSFORMERS

Figure 3.1

STD 4 6503 001 D

Protection and Metering SLD for transformers with 415V Secondary

Figure 3.2

STD 4 6503 002 D

Protection and Metering SLD for HV/HV transformer with <500m Primary Connection – Up to 33kV

Figure 3.3

STD 4 6503 003 D

Protection and Metering SLD for HV/HV transformer with >500m Primary Connection – Up to 33kV

Figure 3.4

STD 4 6503 004 D

Protection and Metering SLD for transformer with 132kV Primary winding

Figure 3.5

STD 4 6503 005 A

Protection and Metering SLD for Distribution Transformer with 132kV Primary winding (<500m)

Figure 3.6

STD 4 6503 006 A

Protection and Metering SLD for Distribution Transformer with 132kV Primary winding (>500m)

STD 4 6504 xxx

GENERATORS

Figure 4.1

STD 4 6504 001 D

Protection and Metering SLD for Generators connected to 33kV Switchgear (Without GCB)

Figure 4.2

STD 4 6504 002 C

Vacant

Figure 4.3

STD 4 6504 003 C

Protection and Metering SLD for LV Generator

Figure 4.4

STD 4 6504 004 C

Protection and Metering SLD for connected to 132kV Grid (With GCB)

STD 4 6505 xxx

HV MOTORS

Figure 5.1

STD 4 6505 001 D

Protection and Metering SLD for HV Motor

Figure 5.2

STD 4 6505 002 D

Protection and Metering SLD for Unit Transformer / Synchronous Motor Circuit – 33kV

Figure 5.3

STD 4 6505 003 D

Protection and Metering SLD for Unit Transformer / Induction Motor Circuit – 33kV

Figure 5.4

STD 4 6505 004 A

Protection and Metering SLD for Unit Transformer / Synchronous Motor Circuit (with Long Feeder on Transformer Secondary) – 132kV

Figure 5.5

STD 4 6505 005 A

Protection and Metering SLD for Unit Transformer / Induction Motor Circuit (with Long Feeder on Transformer Secondary) – 132kV

Figure 5.6

STD 4 6505 006 A

Protection and Metering SLD for VFD / Synchronous Motor (Transformer Primary-132kV)

STD 4 6506 xxx

BUSBAR PROTECTION

Figure 6.1

STD 4 6506 001 C

Protection SLD for 132kV Busbar with more than one bus section

Figure 6.2

STD 4 6506 002 C

Protection SLD for 132kV Busbar with single bus section

Figure 6.3

STD 4 6506 003 A

Vacant

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SP-1107 Specification for Electrical Protection Systems

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Drawing No., Rev. STD 4 6506 004 B

Title Protection SLD for 132kV Busbar with Double Busbar Arrangement (For Low Impedance Relay)

STD 4 6507 xxx

AUXILIARY SCHEMES (AC/DC DISTRIBUTION, VSS, SSS, LS SCHEMES ETC.)

Figure 7.1

STD 4 6507 001 C

DC Supply Distribution Scheme

Figure 7.2

STD 4 6507 002 C

Arrangement for digital communication between ECR and Numerical Relays

Figure 7.3

STD 4 6507 003 A

Vacant

Figure 7.4

STD 4 6507 004 B

Synchronising Selection Scheme for typical HV System

Figure 7.5

STD 4 6507 005 B

Synchronising Selection & Control Block Logic for typical HV Feeder

Figure 7.6

STD 4 6507 006 B

Load Shedding Scheme (LSS) for typical HV System

STD 4 6508 xxx

GENERAL (TYPICAL SCHEDULES, FORMATS, SCHEMES ETC.)

Figure 8.1

STD 4 6508 001 B

Vacant

Figure 8.2

STD 4 6508 002 A

Typical example of Programmable Logic / Masking for Numeric relays

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1

Introduction

1.1

SCOPE This SP specifies the electrical protection schemes and equipment that shall be applied to all new PDO projects and is complementary to DEP 33.64.10.10-GEN and DEP 33.64.10.17.GEN. The scope of SP includes 132kV, 33kV, 11kV, 6.6kV and 415V Systems. In 415V system, the scope limited up to 415V incomer circuit breakers and ACB/MCCB outgoings. With regard to the 415V motor feeders and SFU outgoing feeders, stipulations in DEP and relevant SP shall apply. Further, for extensions / modifications to existing installations, RMUs etc., the SP may be applied with appropriate modification to retain the integrity. Numerical relays have capability for control, interlocking & monitoring of connected feeders, in addition to protection. However, as per the current philosophy of PDO, the SP considers use of protection functionality only and not Control and interlocking. In case of installations with Substation Control System (SCS) or Substation Automation & Monitoring System (SAMS) using the control, interlocking & monitoring capabilities of the numerical protection relays, the SP can be applied with appropriate modifications (especially the section dealing with Relay Communication System), with prior approval of CFDH-Electrical. The new power station 132kV substations are with breaker-and-half schemes. The scope of the document covers these substations as well.

1.2

COMPLIANCE WITH STANDARD For any deviation from this Standard the written agreement of PDO shall be obtained prior to performing related engineering work. Compliance with this Standard for modifications or extension work to existing facilities may not always be possible; in such cases PDO's written instructions shall be obtained to indicate whether a deviation is acceptable. The document uses the device function numbers vide IEEE/ANSI C37.2. The equivalent graphical symbols vide IEC 60617 are tabulated (for commonly used protection functions) at Appendix B, for ready reference.

1.3

APPLICABLE STANDARDS, SPECIFICATIONS AND CODES

1.3.1

PDO Standards

Page 14

SP-1105

-

Electrical Standard Drawings.

SP-1103

-

Electrical Engineering Guidelines.

SP-1109

-

Specification for Earthing and Bonding

SP-1121

-

Specification for Low Control Assemblies.

SP-1120

-

Specification for High Voltage Switchgear & Control Assemblies.

SP-2047

-

Specification for Preparation Engineering Drawings

Voltage

SP-1107 Specification for Electrical Protection Systems

Switchgear &

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Content

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1.3.2

1.3.3

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SP-2167

-

Specification for Fire Water Pumps/Package

PR-1265

-

Procedures for Maintaining Power System Network Models

PR-1168

-

Power Systems Emergency Response Procedure

PR-1942

-

Electrical Equipment Numbering Procedure

S 64.000

-

Standard Drawing - Electrical Symbols in Addition to IEC 60617

S 67.004 & S 67.028

-

Standard Drawings - Schematic diagrams of control circuits for HV & LV motors

S 67.019

-

Standard Drawing - Single line diagrams of LV Switchboard panels

S-67040 – S-67060

-

Standard Drawings - Typical HV Single Line Diagrams

DEP 33.10.03.10-Gen-

-

Symbols and Identification System - Electrical.

DEP 33.64.10.10-Gen-

-

Electrical Engineering Design.

DEP 33.64.10.17-Gen

-

Application of Protective Functions For Electrical Systems

DEP 33.65.11.31-Gen-

-

Synchronous AC Machines

DEP 33.65.40.31-Gen-

-

Power Transformers (Amendments/Supplements to IEC 60076 and IEC 60726).

DEP 33.66.05.31-Gen-

-

Electrical Machines – Cage-Induction Type

DEP 33.66.05.33-Gen-

-

A.C. electrical variable speed drive systems

DEP 33.67.01.31-Gen-

-

Low-Voltage AC Switchgear and Controlgear Assemblies. (Amendments/Supplements to IEC 60439).

DEP 33.67.51.31-Gen-

-

High-Voltage Switchgear and Controlgear Assemblies.

IEC 61869

-

Instrument Transformers (CTs & VTs)

IEC 60255

-

Specification for Electrical Relays.

IEC 60076-5

-

Power Transformers, Ability to withstand short circuits.

IEC 60787

-

Application guide for the selection of high-voltage current limiting fuse-links for transformer circuits

IEC 61000

-

Electromagnetic Compatibility (EMC)

IEC 61850

-

Communication Standard for Substations

IEC 60617

-

Graphical symbols for diagrams

ANSI/IEEE C37.2

-

IEEE standard electrical power system device function numbers and contact designations

ANSI/IEEE C37.91

-

IEEE guide for protective relay applications to power transformers.

SIOP/SIEP Standards

International Standards

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IEEE C37.96

-

IEEE Guide for AC Motor Protection

IEEE C37.99

-

IEEE Guide for the protection of Shunt Capacitor banks

IEEE C37.101

-

IEEE Guide for Generator Ground Protection

IEEE C37.102

-

IEEE Guide for the AC Generator Protection

IEEE Std C57.13.3

-

IEEE Guide for Grounding of Instrument Transformer Secondary Circuits and Cases

IEEE Std 242

-

IEEE Recommended Practice for Protection and Coordination of Industrial and Commercial Power Systems

NFPA 20

:

Standard for the Installation of Stationary Pumps for Fire Protection

NFPA 70

:

National Electrical Code

Energy Networks Association, UK TS 48-3

-

Instantaneous High-Impedance Differential Protection.

TS 48-4

-

DC Relays associated with a Tripping Function in Protection Systems.

-

Functional Test Requirements- Overcurrent and Earth Fault Protection

TS 48-6-6

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General Protection Requirements The general principles to be adopted when applying electrical protection and control systems are outlined in DEP 33.64.10.10-Gen 'Electrical Engineering Design. Further information concerning protection of individual items of plant can be found in the relevant equipment DEP. This SP provides additional information concerning PDO requirements for protection schemes. It includes standard protection single line diagrams and Control/Protection block diagrams to be applied to PDO systems. Current PDO philosophy is to maintain distinction among protection, control, interlocking and metering schemes. Hence, protective relays shall not be used for routing the control commands or for interlocking / metering purposes without specific approval of UIE. Safety interlocking shall be hardwired. For the power system configurations not covered in this SP specific approval shall be obtained from UIE/6.

2.1

PROTECTION PHILOSOPHY

2.1.1

Objectives The prime objectives of electrical protection systems are to reliably: 

Identify system faults and automatically initiate action to isolate the affected plant whilst minimising disruption to the healthy part of the system.



Prevent, or minimise, equipment damage by early identification of fault conditions and rapid control action.



Identify abnormal conditions that could affect personnel safety (e.g. touch voltages of faulted equipment) and avoid these by design.



Maintain full plant availability - i.e. avoid nuisance trips.

To meet the above objectives, the main requirements of a protection system are: 

Redundancy - i.e. if a single protection device or circuit fails there must be an independent secondary method for fault identification and isolation.

Note: Secondary protection need not have such stringent requirements for minimal disruption as the primary protection.

Page 17



The possibility of dormant, un-revealed faults in protection systems should be minimised by design - e.g. use of trip circuit supervision, selfchecking relays etc.



Positive operation for the full range of anticipated system fault levels



Fault clearance within the critical clearing times for system stability.



No operation for short time overloads and normal system transients such as motor starting currents; transformer magnetising inrush currents, switching surges etc.



Fail-safe logic is widely used in C&A schemes but not in Electrical schemes. In case there is a problem in trip circuit or in DC supply, the same is annunciated calling for urgent action of operator and the subject feeder is allowed to continue in service. In electrical systems, the backup protection is expected to clear a fault in case of problem in the

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protection scheme of subject faulty feeder. For process safeguard trip etc. the C&A schemes shall include monitoring of subject CB opening and issue trip command to the upstream CB, in case the subject CB is not open within a specified time due to problems in the protection scheme (DC supply etc.) or due to issues with CB operating mechanism. 2.1.2

Application of Relays to Standard Schemes This SP contains standard protection schemes for a number of electrical system building blocks common to PDO systems. Main and Back-up protections are identified in the scheme with physically separate relays. Multifunction numerical protection relays incorporating features such as self-checking, programmable scheme logic, communication, measured value display and disturbance/fault recording facilities shall be applied unless it is specifically agreed to do otherwise. The self-check feature for multifunction relays shall include the following minimum continuous self-monitoring features: 

Auxiliary supply supervision



Checksum on all protection algorithms



Memory checks



Checks on input modules (A/D converter)



Watchdog supervision on program execution



Check on Opto input and digital output modules

Only relays with above self-supervision / diagnostic features may be considered for integrating multiple protection functions into one relay. However, Main and Back-up protections shall not be combined into one relay. Wherever, two nos. of Main relays (Main-1 and Main-2 relays) are provided (e.g. for the Generators and 132kV Overhead Line feeders), main and backup protections are combined in the same relay and provided in both Main-1 and Main-2 relays. 2.1.3

132kV Substations with Breaker-and-Half Scheme The new power station 132kV substations are with breaker-and-half scheme. The breaker-and-half scheme with double bus arrangement is different from the normal single bus arrangement in that,

Page 18



The tie-bay CTs are paralleled with those in main bay for protection and metering purposes.



The main bay as well as tie-bay circuit breakers are provided with BF protection.



Busbar protection of a bus shall trip the main bay breakers connected to the respective bus. Busbar protection shall not trip the remote ends of the OHL or Transformer, considering that the power supply to OHL or Transformer is not affected during a bus fault.



The Breaker fail protection of main bay breakers shall initiate the respective busbar trip and in addition, trip of the associated tie-bay breaker. The Breaker Fail protection of tie-bay breakers shall trip the adjacent main bay breakers only. Breaker fail protection for main bay breaker and tie-bay breaker shall trip remote ends as well, with lockout. Remote ends, in case of transformer feeders, mean the secondary side

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of the transformer. Breaker fail protection relay and scheme shall comply with requirement in clause 3.3.2.3. 

Stub protection is not required in PDO system. There is no Line isolator in the standard configuration adopted by PDO and hence if a Line is down, the respective cross bay main breaker and mid breaker will have to be kept off.



Transformer feeders shall be provided Synchro-check facility at LV (33 or 11 or 6.6kV) Switchboards for uninterrupted changeover.

The auto-reclose scheme for breaker-and-half substations, shall always consider main bay breaker. Whenever, main bay breaker is not available (but feeder is still in service through tie-bay breaker), the auto-reclose scheme for the respective feeder shall be selected ‘Out’. Tie-bay breaker is also tripped along with the main bay breakers, by the main bay protection relays whenever there is a transient fault. In order to keep the auto-reclose scheme simple, closing of tie-bay breakers in 132kV breaker-and-half substations are not included as part of auto-reclose schemes. However, the tie-bay breakers shall be auto-restored to service on successful auto-reclose of the feeder. The criteria for the same shall be:

  

2.1.4

Main bay breaker is closed AR successful (Completion of Reclaim time) Synch permissive available. Synch check shall verify the o voltages of two Line VTs, in case of OHL & OHL or OHL & GSUT o voltages of Line VT and Bus VT, in case of OHL & Transformer

Automatic Bus Transfer Schemes In case automatic bus transfer scheme is specified, the switchboard shall include protective and trip lockout relays/releases in the incomers. The incomer trip lockout relay (incomer overcurrent, incomer earth fault as well as standby earth fault protection) contact shall be wired in the bus transfer scheme to inhibit the bus transfer in case the tripping of incomer is due to an uncleared downstream fault or bus fault. Time delays for the bus transfer schemes shall be such that bus transfer at upstream switchboard shall be carried out first. Bus transfer at downstream switchboard shall be carried out later if it is required (e.g. in case of failure of bus transfer at upstream switchboard).

2.1.5

Circuit Breakers for Generators, Motors and 132kV Feeders The Circuit breakers for generators, motors and 132kV feeders shall have two trip coils. The protection shall be arranged to trip both the trip coils. Additionally for motor circuit breaker an under voltage release device shall be provided to ensure the fail safe operation as per SP-1120.

2.1.6

Opening time for HV vacuum contactor or circuit breaker Opening time for HV vacuum contactor or circuit breaker shall not be more than 50ms. The vacuum contactor and the associated fuse shall be co-ordinated to ensure that the fuse always operates at all values of current to clear the faults within contactor’s maximum breaking/withstand capacity.

2.1.7

33kV Expulsion Fuse, PMR & Outdoor CB 33kV Expulsion fuses have limited fault rating of 8kA (Bussman data). Hence, installations with fault levels exceeding 6kA shall not employ expulsion (drop-out)

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fuses. These fuses should not be typically installed up to distance of 11.0kM on the single ELM conductor from 33kV switchboard having short circuit current as 31.5kA. Pole Mounted Reclosers (PMRs) are available up to a fault rating of 16kA at present. Hence, wherever, circuit isolation is required, PMRs shall be specified if the fault currents at the location do not exceed 14kA and hence PMRs should not be typically installed up to distance of 3.0kM on the single ELM conductor from 33kV switchboard having short circuit current as 31.5kA. Outdoor circuit breakers (OCB) shall be preferred only if estimated fault levels at the location exceed 14kA. In place of PMR or OCB, possibility of installing current limiting type HRC fuses shall be explored if there are no concerns from operation and maintenance team. Short circuit calculation shall be carried out by the contractor / design consultant during design stage to determine the fault current before recommending any of the above options. Parallel operation of 33kV switchboard incomers and possible future increase of 132kV source fault levels shall be considered while estimating the 33kV fault levels at the load point. 2.1.8

Transformers in 33kV OHL system Further, transformers installed in field up to a rating of 2500kVA need not be provided 33kV OCB / PMR and instead Fuse-Disconnector is adequate. This applies even if the transformer secondary voltage rating is 6.6kV (though such small ratings shall be avoided when the secondary voltage rating is over 415V).

2.2

SYSTEM EARTHING 33kV system shall be solidly earthed by earthing the neutral of secondary winding of 132/34.5kV, delta/star power transformers. 6.6kV and 11kV systems shall be low resistance earthed by restricting earth fault current to 300A by Neutral Earthing Resistor (NER) on the secondary of incoming delta/star transformers (However, it is not applicable for 6.6/11kV star winding of unit transformers for motors and clause 3.8.3.2 shall be referred).

2.3

RELAY SPECIFICATIONS All relays shall conform to IEC 60255 and shall be of approved make. Further, only those relay types (for a given make) which are proven for not less than two years in desert environment similar to that of Oman shall only be considered. The vendor shall confirm that the relay models supplied are current and service & support will be available for 10-years as a minimum, from the date of supply. Further, vendor is expected to inform the owner the company obsolescence plan for various relay models, 3-years advance as a minimum. Vendor shall also clearly indicate hardware and software versions of the relays. The relays available in market are categorized as Transmission products and Distribution products by the vendors. It is general understanding that transmission products are built with higher quality levels and options than the distribution products, considering greater importance of transmission equipment. Thus, it is expected that the vendor of protection schemes offer only those relays categorized as Transmission products for use in 132kV power system. In case of any doubt, prior approval shall be sought from PDO Protection Head. All relays (protection relays as well as auxiliary/interposing, trip/lockout relays etc.) in the control and protection schemes shall be 110V DC rated, in general. However, relays shall withstand 125V DC on continuous basis considering the float voltage level for 110V battery. In remote locations with no 110V DC UPS facility, the relays can be 110V AC rated.

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All overcurrent and earth fault protection relays shall have inrush (2nd harmonic) blocking feature. In case of feeders with small CT ratio with respect to available fault current, it is recommended to select the protection relays with provision of highset overcurrent protection operation on ‘Inst’ or ‘peak’ current sensing and not on RMS current sensing so that the protection operates before the subject CT goes into saturation. 2.3.1

Communication Requirements For relays with communication facilities \ programmable scheme logic \ binary code settings, it shall be possible to connect relays to local PC for the purpose of logic checks and setting modifications. It shall be possible to make this connection without need of removing any connections to the relay. In addition to the local interface facility all the protection relays shall be supplied with remote communication facility to central control room. All the numerical protection relays shall comply with IEC 61850 communication requirements. Built-in protection modules in PMRs / RMUs and protection releases in the 415V circuit breakers can be an exception. Where protection relays in the 415V incomers form part of the local control / monitoring / data acquisition system (for example, 415V incomers for the switchboards in 132/33kV substation), the relays shall be IEC 61850 compliant. However, where the 415V switchboards are installed with no connection to local control / monitoring / data acquisition system (for example, switchboards in isolated field locations), the compliance with IEC 61850 in the 415V incomer relays is optional.

2.3.2

Relay setting, configuring Tool & the relay soft files Further, the scope shall include supply of software with at least three licences for using in PDO / Consultants’ offices for setting / configuration studies / disturbance, event, fault record viewing. Before equipment is ordered, sufficient studies shall be performed for providing tie-in with the existing local \ remote PC system. Studies shall also be carried out to determine the protection requirements and to ensure that appropriate relay protection functions and setting ranges with required sensitivities are chosen. The logic schemes for individual relays shall be configured in respective relays in accordance with the approved scheme drawings and tested before despatch of the relay panels. The soft copy of the scheme logic also shall be sent in a CD (in duplicate), for verification during relay setting studies / commissioning.

2.3.3

Other Requirements All numerical protective relays shall have enough no of contacts / thyristor outputs adequately rated to operate tripping relays and circuit breakers directly, i.e. without the imposition of auxiliary relays. The contacts shall be capable of making and interrupting the tripping currents, which occur, unless specific provision is made for interrupting the current on contacts elsewhere in the circuits. The relays are expected to provide direct trip to all the relevant breakers in addition to operating master trip/lockout relay and hence shall have adequate output contacts. Requirement of number of inputs and outputs shall be decided base on the individual feeder protection scheme. At least two nos. each spare inputs and outputs shall be made available for client’s future use. Contractor shall select relay model number based on the recommendations from PDO. However, in absence of any recommendations, contractor shall submit his proposal for PDO approval. It shall not be possible to change the relay settings without removing the protective relay case (electromechanical/static type relays) or without pass word control (numerical type), as the case may be.

Page 21

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For the protections based on high impedance principle (e.g. busbar protection or Restricted Earth fault protection for transformer windings), the relays can be electromechanical or static type. For all other protection functions, the relays shall be numerical type and shall include self supervision, fault/event/disturbance record capability as well as communication capability, as a minimum. Time dependent overcurrent and earth fault protection relays should incorporate definite time characteristic and a selection of standard inverse, very inverse, extremely inverse and long-time inverse operating characteristics to IEC 60255. Highset element shall have adjustable time delay and inhibiting facility. Dropout to pickup ratio for all current operating protection elements shall not be less than 70% even at the lowest protection setting. PDO electrical system doesn’t have high resistive earthing except for generators and unit transformer connected motors. Hence, earth fault protection element provided in the relays shall not saturate up to expected earth fault currents. Relay coils operating on DC shall be designed so that any coils energised from the positive pole of the battery are via normally open contacts. This is to minimise the effects of electrolysis. 2.3.4

Use of Relays for Operational Interlocks etc. Use of protection relays for operational interlocks is subject to specific approval after addressing issues such as fail-safe features, redundancy, facility of software back-up etc.

2.3.5

Relay Operation Indication All protective relays shall be provided with hand reset operation indicators. These operating indicators shall be designed in such a way as to prevent any accidental resetting of the indicators. It shall be possible to retrieve event-recording data after failure of auxiliary DC supply. Indication of relay operation shall be retained until manually reset, irrespective of whether or not the relay protective function has previously been self-reset. Wherever programmable LED’s are used for such indications the correct signal description shall be displayed in the form of label next to each LED. For relays with LCD displays in abbreviated forms the correct description of all the possible abbreviations shall be affixed at suitable location for operator reference. Where mechanical flags are employed, these shall be clearly marked in a permanent manner; adhesive labels shall not be used.

2.4

RELAY COMMUNICATION SYSTEM All the numerical protection relays shall be IEC61850 compliant. Protocol converters shall not be used unless specifically permitted by the Owner. The IEC 61850 protocol is Ethernet based and is the worldwide standard for protection and control systems used by utilities. By means of this protocol, information can also be exchanged directly between bay units / relays / IEDs so as to set up simple, masterless systems for bay and system interlocking (not a requirement in PDO as per current practice). Fig. 7.2 indicates typical interface of numerical relays with local/station computer and virtual computer. All the numerical relays in a given station shall be wired to a TCP/IP based communication bus and shall be connected to a local/station computer via Ethernet switches. The local /station computer shall be industrial type and act as

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Device for communicating / accessing any of the relays in the substation.

The communication to the remote system (i.e. virtual computer) shall be through PDO WAN. The virtual computer can be any individual computer in any of the PDO offices which can access local / station computer through Citrix. The local / station computer along with main Ethernet switch shall be rack mounted in a vertical cabinet. Wherever possible, this vertical cabinet shall be placed in central location and opposite to C&R panels/switchboards for better view. Vertical cabinet shall also contain SNTP GPS time server required for time synchronisation, with antenna mounted on the roof of the building. Time resolution shall be 1ms or better. Power supply to local/station computer shall be 110V DC. If is not possible to provide local/station computer suitable for 110V DC, power supply to local/station computer can be 240V AC. This 240V AC power supply shall be derived from station 110V DC supply by 110V DC to 240V AC inverter. This inverter shall be industrial type. If 240V AC UPS power supply is available in the station, it can be connected to local/station computer and in such case 110V DC to 240V AC inverter is not required. Auxiliary power supplies to all other hardware (e.g. Ethernet switches etc.) supplied as part of the Relay Communication System shall be derived from the 110V DC auxiliary power supplies available in the relay panels/switchboards. The following minimum functionality shall be made available at the local/station computer as well as virtual computer, for which the scope shall include any additional hardware/software required for: 

Display of the quantities measured by relay such as currents and voltages.



Retrieval of disturbance records stored in relay buffer.



Retrieval of event records stored in relay buffer.



Setting and configuring the relays



Switching of setting groups, wherever applicable



Review of programmable logic / binary coded settings



Time synchronisation of all the devices in the station including local/station computer.

Further, the system shall enable access to, 

Local/station computer (in turn to individual numerical relay in the station) from virtual computer located anywhere in the PDO network through appropriate authorisation.



Access controls to the system having various privileges access level, at least three levels are required. The Contractor shall propose and configure each level with appropriate privileges according to the Company requirement and approval.

The specification for the local/station computer, Ethernet switches, GPS clock system etc. shall be agreed with PDO IT before purchase. Once installed, the system shall be registered with PDO IT for the purpose of monitoring/trouble shooting, software upgrades, maintenance etc. The required Storage capacity (Hard disk) in the local/station computer shall depend on the no. of total relays in the substation to be connected to the computer with its associated data.

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Commissioning of Relay Communication System shall not be considered complete until required access, display, protection relay setting & configuration and data retrieval from virtual computer is demonstrated by the contractor.

2.5

MULTIFUNCTION METER (MFM) The numeric multifunction meters (MFM) shall comply with IEC 61000-4-30, IEC 61000-4-7 and IEC 61557-12 and shall have following functionalities as a minimum: a. Real time viewing of voltage, current, real power, reactive power, power factor and maximum demand with auto scrolling facility. b. Accumulated energy c. Total Harmonic Distortion with spectrum analysis and waveform scopes for both voltage and current d. MFM shall capture maximum demand data at the interval of every 15 minutes as minimum and store this data in the internal memory for at least 50 weeks and provide reports as required. e. MFM shall store the measurements of the main voltage characteristics in the internal memory. The reports are made on the basis of this stored data. Data for the last 50 weeks as minimum and variations of the measured quantities (Voltage sag/swell/interruptions) from the standard values are stored in the report, which enables detection of anomalies in the network. f. MFM shall have waveform recording capability, which can be triggered by limits set internally for the measured parameters or from external inputs. MFM shall be capable of storing 10 waveform records as minimum. Each record shall be of duration not less than 10 seconds with resolution of 10ms or better. g. All the data shall be time stamped and MFM shall have time synchronization facility through communication network. h. MFM shall have self-monitoring functionality and provide an output contact for alarm. i. MFM shall have large LCD display screen with back light for easy viewing and scrolling of measured parameters. j. For communication with SCADA / DCS / Other Control System, MFM shall have a rear RS485 port with protocol as confirmed by supplier of SCADA / DCS / Other Control System. MFM shall also have a front port for connecting to a laptop for configuring/viewing/downloading. k. All required measurements, weekly reports and alarms can also be stored locally in the internal memory. Stored data can then be transferred to a memory card or accessed through communication for post analysis. The limits and the required quality in a monitored period can be defined for each monitored characteristic. The make and model number of the MFM shall be specified by the vendor in the offer which shall be subjected to review and approval by the Company. All required software with license and cords/cables required for settings and viewing of data shall be included in the offer.

2.6

CURRENT TRANSFORMERS All current transformers (CTs) for protection, metering and indication shall comply with the respective, relevant clauses of IEC61869. The current transformers for primary protection shall have accuracy class PX with appropriate Knee Point Voltage (Vk), CT resistance (Rct) and magnetising current. Those for back-up protection shall have accuracy class 5P. The core balance current transformer (CBCT) shall also have protection accuracy class. The protection class CT shall have appropriate VA rating

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and accuracy limiting factor (ALF). The CT sizing shall ensure proper working of protective devices for all short circuit currents up to the rated value of switchgear. The 132kV bays shall have five core CTs. High impedance Motor/Generator differential / Transformer restricted earth fault / Busbar differential protection shall have dedicated CTs (not shared by any other protections/meters). The CT sizing shall ensure speed of operation better than 40ms (@5xIs typically). All CTs connected to any high impedance differential or restricted earth fault protection scheme shall have identical parameters. Current transformer primaries shall be of low reactance bar primary type wherever possible. Split core type current transformers shall not be accepted. Current transformers shall have a thermal rating at least equal to circuit requirements and a short time (through-fault) rating at least equal to that of the associated switchgear. Current transformers shall have an output rating adequate to cater for the burden (CT leads, relay, etc) connected to them. They shall have sufficient rating, terminal voltage and overcurrent performance, where applicable, for the satisfactory operation of their associated equipment. Accuracy class of protective current transformers shall be selected dependent upon the particular application. The Accuracy Limit Factor (ALF) shall be selected with consideration to the maximum value of primary current up to which maintenance of accuracy is required. In case of feeders with small CT ratio with respect to available fault current, it shall be ensured that CT doesn’t saturate up to two times of estimated highset instantaneous setting as minimum. For the transformer / generator / motor differential, distance / line differential, restricted earth fault and busbar differential protections, CTs should be Class PX type. The specification for Class PX CTs shall include: 

Compliance with IEC 61869



Rated primary current, turns ratio, rated knee-point e.m.f. at maximum secondary turns



Maximum exciting current at the rated knee-point e.m.f. or at a stated percentage thereof



Maximum resistance of the secondary winding (at a stated temperature)

The applicable X/R value of the system for the CT sizing calculations shall be obtained from PDO. Preliminary calculations regarding both stability and sensitivity of the high impedance differential schemes shall be performed and submitted for PDO’s approval before ordering of the CTs (switchboards / transformers). This is to enable determination of CT characteristics and the setting ranges of relays. The basis for the calculations shall be the relay manufacturer’s guidelines. The specified CT parameters shall be reviewed and confirmed once the Switchboards/C&R panels are ordered / relay types are decided. The CT sizing calculation shall consider rated short circuit current of the switchgear / busbar and not the estimated one. References of formulas from the relay manuals for CT sizing, relay manufacturer’s guidelines and all other inputs required for CT sizing shall be part of the CT sizing calculation document. All CT sizing calculations are subject to PDO approval. Earth fault relays fed from residually connected CTs can be susceptible to spurious trips due to the tolerances of CTs, particularly during transient conditions which can include large differences in phase voltages. Therefore, 6.6kV and 11kV earth fault relays should be connected to a core balance CT. The ratio of CBCT shall be selected Page 25

SP-1107 Specification for Electrical Protection Systems

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to detect 5A of primary fault current at the lowest relay setting and shall be protection class. Typical ratio of CBCT shall be 50/1A. CBCT shall also be provided for 33kV OHL feeders. If more than one three phase cables are used in parallel, separate CBCT shall be installed for each cable and these CBCTs shall be connected in parallel across a common relay. Whenever CBCTs are installed over the rectangular busbars (or cables in flat formation) before the cable compartment terminals, they shall be rectangular type (with compensation coils for flux imbalance, built-in). Three core cables (or single core cable in trefoil) shall be centred in the CBCT window while installation. This is important to minimise the flux imbalance and resultant spill current in the CBCT secondary wires. In case of 415V feeders with 4-wire distribution, neutral wire also shall pass through CBCT. The transformer neutral CT ratio for standby earth fault protection shall be 50% of the transformer rated current for solidly earthed system and 100% of the NER Current rating for low resistance / high resistance earthed systems (transformers with 11 or 6.6kV secondary). The transformer neutral CT ratio for restricted earth fault protection shall be same as the ratio of phase CTs for this protection. For the 33kV system and below, whenever it is required to locate CTs with transformer, these CTs shall be standalone type and bushing CTs are not acceptable. However, for the system voltage of 132kV and above, bushing CTs can be provided. Measurement CT sizing shall ensure that CT saturates before short time withstand capability of meters and effective Instrument Security Factor of the CT at connected burden is below withstand capability of meters.

2.7

VOLTAGE TRANSFORMERS Voltage transformers shall be provided for busbars in all switchgears and for 132kV substations. Each VT shall have two secondary windings as a minimum. These shall be identical in all respects, shall be star-connected and have dual accuracy class, metering as well as protection. Voltage inputs to redundant protections shall be segregated. The VTs in switchgear panels shall be draw-out type or in case of GIS, with appropriate isolation arrangement. Voltage transformers for 132kV OHL feeders and generator transformer feeders shall be electromagnetic type. 132kV bus Voltage transformers shall be capacitor type and provided with PQ sensors. All voltage transformers (VTs) shall comply with the requirements of IEC61869. They shall have a rated secondary output voltage of 110V (or 100V in specific cases, such as generator VTs), a measuring accuracy class in accordance with DEP 33.67.51.31Gen and an output rating adequate to cater for the burdens connected to them. VTs for high impedance earthed systems shall have voltage factor of 1.2 continuous and 1.9 for 30s. All VT sizing calculations are subject to PDO approval. Where one set of VTs supplies a number of different circuits, each circuit shall be separately protected with lockable MCBs. MCBs on VT circuits shall have facilities to lock them in open position. This is to avoid possible back energisation of HV equipment via the VT circuitry.

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The VT secondary MCB in the protection circuits shall be fast acting (typically < 5ms) type so that the auxiliary contact of VT MCBs can be used for blocking the respective voltage dependent relays (in the event of opening of MCB).

2.8

INSTALLATION AND DESIGN REQUIREMENTS

2.8.1

General Requirements Protection relays shall be mounted on panels individual to each circuit concerned. Where space permits, these shall be in the switchgear cubicle, otherwise a separate relay panel suite shall be provided. Relays shall not be mounted on the HV circuit breaker moving portion or in any position where they may be subject to vibration during normal operation. All protective relays shall be visible from the front of the panel without having to open the panel door. Relays shall be flush or rack mounted in dust and moisture proof cases or enclosures. In general, the rules for design and installation in accordance with IEC 61000-5-1 and IEC 61000-5-2 shall be followed in order to achieve an industrial level Electromagnetic compatible (EMC) environment (as described in IEC 61000-2-5 and IEC 61000-6-2) inside low voltage compartments where protective relays / other devices are located. More specifically the following installation requirements shall apply: The relays with LED and / or LCD displays shall be mounted at convenient height so that the LED labels and LCD displays are easily read. The relays with programmable logic capabilities shall be provided with PC based Graphical User Interface. The facility of all requisite plug-in connections (e.g. RS232) shall be provided on the relay for local access during commissioning as well as maintenance. Panels provided as extensions, or for erection in the same room as existing panels, should be of similar design and appearance to those existing. Equipment, meters, etc. mounted on such panels, likewise should be of a style and scaling similar to the existing equipment. Fuses and links shall be positioned at the bottom of the front face of the panels except on panels forming extensions to existing boards where the arrangement should match the existing panels. The minimum size of cable used for CT circuits shall be 4 sq. mm. For other circuits the minimum size shall be 1.5 sq. mm. All cables shall be stranded in order to avoid the possibility of a break of a single conductor resulting in an open circuit condition. External multi-core cables shall be armoured and routed in order to limit external electrically impressed voltages to a minimum. Optic fibre cables wherever used shall be protected against physical damage. In case of multi-ratio CTs, all the CT ratios available shall be indicated, with the used CT ratio underlined specifically. In case of 132kV C&R panels (and 33kV, if the C&R panels are separate), the control schemes of circuit breaker, disconnecting switch as well as the CT/PT/ Bay Marshalling box drawings shall be reproduced in the C&R panel scheme drawings, for ready reference. The trip contact from numerical protective relays shall be directly wired to trip coil of the circuit breaker and these trip contacts shall be provided with dwell time of 500ms in order to ensure that trip coils are de-energised by circuit breaker auxiliary contacts and not by relay contacts. Another contact shall be used for energising associated trip & lock out relay (86).

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Protection, Control & Metering schemes - Lead numbering The lead numbers are standardised as below so that any PDO protection engineer can easily identify the purpose for which the lead is connected by looking at the lead number. J Series

DC Incoming

J1, J2 etc.

K Series

Control – Closing, Tripping etc.

K1, K2, K3 etc.

L Series

Alarms, Indications Annunciations

L1, L2, L3 etc.

E Series

Potential Secondaries

Transformer

E1, E2, E3 etc.

H Series

Low Voltage Auxiliary AC Supplies

H1, H2, H3 etc.

A Series

CT Secondary and Special Protection

A1, A2, A3 etc.

B Series

Busbar Protection

B1, B2, B3 etc.

C Series

Protection Circuits

C1, C2, C3 etc.

D Series

Metering Circuits

D1, D2, D3 etc.

and

Further, certain lead numbers are standardised as follows and should be compulsorily adopted with ferrules at termination of leads. J1 – DC Positive J2 – DC Negative Control & Alarms Remote Close: Local Close: Remote trip: Local Trip: 2.8.3

K15R K15L K5R K5L

Earthing Each control and relay panel shall be provided with a copper earth bar of not less than 70 sq. mm cross-section and arranged so that the bars of adjacent panels can be joined together to form a common bus. All metallic relay, instrument and metering cases shall be connected to the earth bar by means of cable of not less than 2.5 sq. mm cross-section. The physical contact of case to panel does not suffice.

2.8.4

Current Transformer Earthing Current transformer earthing is required for personnel protection. Current transformers associated with a protection circuit shall be earthed at one point only, which may be local to the protection relays. Each protection circuit shall be earthed at one point only to avoid the flow of circulating currents which may flow if earths are made at two or more locations and differences of potential between the earthing points arise. This could result in spurious relay operations. In case of Core balance CTs, correct practice shall be followed with regard to power cable armour earthing, in order to avoid maloperation of earth fault protection due to armour currents.

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IEEE Std C57.13.3 shall be referred for further guidance on the subject. The earth connection shall be made through a removable bolted link. Current transformers for indication and metering shall have their secondaries earthed local to the position of installation. It is required for personnel protection. 2.8.5

Connections for Protection Testing Readily accessible facilities shall be provided to allow injection and functional testing of protection relays and associated circuits without the need to make any disconnections. These should consist of test socket blocks that allow test plugs to be inserted, with independent access to either side of the broken circuit. They shall allow:   

Access to all relay input and output circuits, including power supply circuits Isolation of VT circuits Isolation and shorting of CT circuits.

External test points are not required for relays having integral test facilities accessible with test plugs to all input and output circuits. Numerical relays with programmable logic shall have a facility to individually switch on or off all the output relays through software interface. This shall be possible without disturbing programmed protection/control logic. This facility is required for commissioning of SCADA alarms and signalling. Links shall be provided for isolation of the trip circuits of each protection relay and the common trip circuit to each circuit breaker trip coil. The isolation facility for testing shall ensure that any alarms generated, as a result of testing, are not transmitted to SCADA as normal alarms. 2.8.6

Power Supply to Protection Relays The power supply from the DC UPS distribution board (DCUPS DB) shall be extended independently to protection relays and trip coil(s) through the associated Control & Relay Panel (CRP). The auxiliary power supply wiring shall be done by looping in all the equipment supply terminals in series, thus forming single (positive and negative) supply bus with as many connection points as the number of equipment. This supply bus shall end at the terminals of DC supply supervision relay. This arrangement ensures 100% coverage of auxiliary supply wiring for supervision. Typical DC supply distribution scheme is indicated in fig. 7.1. Two feeders each shall extend DC supplies from DCUPS DB. These two feeders shall form two independent DC supply buses in control & relay panel. The two breaker trip coils shall be wired to two supplies drawn from above DC buses. The associated main and back up protection equipment shall also be supplied from two independent DC buses. Both DC supply buses shall be independently supervised by two supply supervision relays. Same principle shall be followed for DC supply distribution of other HV switchgears with two trip coils. For other switchboards, DC supply distribution shall be in line with scheme indicated in fig. 7.1. In small installations where 110V DC UPS power supply is not envisaged/not available, such as RMUs or isolated 415V Switchboards, the protection should be through modules built-in to the breakers (e.g. self powered relays, protection releases etc.). Relays, if provided, can be AC/DC power supply operated (including breaker trip power supplies) as required. It may be mentioned that some of the 415V breaker releases are being provided DC auxiliary supplies from line VT through AC/DC converter.

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All such supplies shall be connected phase-to-phase and not phase-to-earth. These supplies shall have auto changeover scheme so that healthy supplies are available even during abnormal conditions (like one incomer not available or a fault in the outgoing feeders). 2.8.6.1

PMR Control / Protection Power Supplies PMRs are provided with VTs to charge the internal battery and provide auxiliary supplies to the PMR including the control / protection module. However, if the PMR is located close to a substation/plant, the 110V DC / 240V AC UPS supplies shall be provided for PMR protection and control. This will ensure better reliability by eliminating the battery and charging circuit in the PMR. However, further DC to DC or AC to DC conversion shall be provided in the PMR control / protection module.

2.8.7

Labelling All relays and links shall be provided with clearly inscribed labels describing their application in an unambiguous manner, which shall be consistent with the description given on the schematic and wiring diagrams.

2.8.8

Miniature Circuit Breakers (MCBs) Miniature circuit breakers (MCBs) shall comply with IEC 60947. Miniature circuit breakers (MCBs) in the VT circuits shall additionally comply with the stipulations at clause 2.7 above and shall have an auxiliary contact to raise an alarm when the MCB is open. MCBs shall be installed behind a door or cover to prevent tripping by inadvertent contact. The rating of MCB provided in the DC UPS supply distribution scheme (e.g. control & protection schemes in the relay panels or switchgear panels) shall be coordinated with the upstream MCB in the outgoing feeders of DC UPS distribution board. This protection coordination shall be demonstrated through coordination curves during design stage. This also applies to AC UPS distribution (e.g. AVR panel, excitation panel etc.)

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Specific Protection Requirements The specific requirements of protection elements and protection schemes for different types of circuits are indicated in this section.

3.1

OVERHEAD LINE FEEDERS – UP TO 33KV

3.1.1

Overhead Line Feeder - 33kV Switchboard Overhead Line Feeders from 33kV switchboard shall be provided overcurrent protection (51/50), residual earth fault protection (51N/50N) and CBCT based earth fault protection (51G). Overcurrent and earth fault protection shall have a selection of operating characteristics and highset instantaneous protection. The choice of characteristic shall be made with consideration of the protection discrimination requirements. Both overcurrent and earth fault protections shall have inrush (2nd harmonic) blocking feature. CBCT connected earth fault protection (51G), provided as standard, shall be capable of detecting less than 5A primary earth fault current. This protection may be incorporated into the multifunction relay provided the requirement of sensitivity is complied. CBCT shall not be connected to sensitive earth fault protection element of the relay for solidly / effectively earthed system and low resistance earthed system. The relay shall also have facility to detect thermal condition of the OHL based on long time inverse characteristic and also broken conductor condition based on I2/I1 (Negative phase sequence current / Positive phase sequence current) or any other appropriate principle. The broken conductor condition shall be annunciated in the SCADA. No trip is envisaged. However, setting of thermal protection for 33kV OHLs is not envisaged in the current practice in PDO. On parallel feeders, time dependent directional overcurrent and earth fault relays shall be provided. For the rings, if any, formed by 33kV interconnections between stations, time dependent directional overcurrent and earth fault relays shall be installed as appropriate to maintain selective tripping throughout the ring. Directional overcurrent elements shall be cross-polarised to ensure sufficient sensitivity under various fault conditions. The relay shall have selectable maximum torque angle so that same relay can be applied for different type of feeders. The directional element shall be able to detect and maintain the direction of operation even after collapse of voltage signal. Voltage input for directional relays shall be from a VT secondary, different from that supplying to the primary protection. This is to ensure fuse failure in one VT secondary circuit will not affect both the protections. Directional relays shall inhibit the protection on detection of “VT fuse fail”. Where studies show that minimum fault levels are below the required setting of overcurrent relays, use of distance relays or voltage controlled overcurrent / earth fault relays shall be considered. All 33kV overhead line feeders from 33kV switchboard shall be provided with autoreclosing facilities. The protection scheme for a typical 33kV radial overhead line feeder is shown in Fig. 1.1. Typical trip matrix is attached as Appendix-F.

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Pole Mounted Reclosers (PMRs) The 33kV ring system provided for field distribution consists of pole mounted load break switches and / or auto-reclose breaker (PMR - Pole Mounted Recloser) provided at the switchrack outgoing feeder or OHL tap off point. Installation of PMRs shall be in line with clause 2.1.7 . The PMRs shall be with built-in microprocessor based protection/reclose modules and set to protect for faults in the OHL downstream of the PMR. The scope of PMR supply shall include software for setting / configuring / event, fault, disturbance record viewing of the protection module. Overcurrent and earth fault protection in PMR shall have a selection of operating characteristics and highset instantaneous protection. The choice of characteristic shall be made with consideration of the protection discrimination requirements. Both overcurrent and earth fault protections shall have inrush (2nd harmonic) blocking feature. If PMR is used for pipeline protection trip or any external trip, controller shall have settable time delay (or debounce time) to trip the PMR. This time delay is required to ride over transient voltage dips. However, it shall be applicable only for pipeline protection trip or other external trips and not for electrical protection trips or transformer mounted protection trips. Pipeline protection relay contact shall be disconnected from the trip circuit, if PMR is not used for pipeline protection.

3.1.2.1

33kV Switchrack incomer PMRs 33kV Switchrack incomers are from a 33kV switch board in the respective stations. Generally, these incomers are provided with Disconnecting Switches. For any uncleared faults in the downstream 33kV feeders, the outgoing feeder protection at the 33kV switchboard is expected to act as back-up. Hence, even if a PMR is installed at the switchrack incomer, the same is expected to be used as an on-load isolator and the protection as well as reclosing functions disabled. It is recommended not to provide any tap-off from OHL before 33kV Switchrack. However, in case, there is a tap-off from the OHL before the Switchrack, then, the Switchrack incomer PMR protection needs to be set to ensure that the uncleared outdoor feeder faults at switchrack doesn’t trip the feeder at the 33kV switchboard.

3.1.2.2

33kV Unit Transformer PMRs/Outdoor CBs In case of unit transformer-motors connected to 33kV field OHL with one PMR/OCB at the unit transformer primary and another PMR/OCB as breaker back-up for Process safeguarding trips, the back-up breaker (PMR/OCB) shall not have any protection / reclose module and shall be wired to trip through Process safeguard logic.

3.1.2.3

33kV Switchrack outgoing OHL feeders / OHL Tap-off PMRs The source end of an overhead line from 33kV switchrack or 33kV tap off from main OHL ring system should be provided with PMR. Tap-off in the 33kV OHL system shall always be from the main OHL and not from the OHL that is already a tap-off (from the main OHL). It is not recommended to provide tap-off PMR from branch overhead line supplied from another tap-off PMR. In case the above becomes inevitable due to the field conditions, the subject shall be discussed and approval sought at the design stage, with PDO protection head to address coordination issues, if any.

3.1.2.4

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33kV OHL Spur-line PMRs Spur line PMR may be provided at the primary terminals of the distribution transformer.

SP-1107 Specification for Electrical Protection Systems

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3.1.2.5

Pipeline Protection PMRs In case, two PMRs are installed in series for pipeline protection, first PMR shall have both electrical protection as well as pipeline protection and second PMR shall have only pipeline protection without any electrical protection.

3.1.3

Auto-reclose Function Even though as per current PDO philosophy, auto-reclose function is disabled for 33kV OHL, all overhead line feeders from 33kV switchboard and all 33kV PMRs shall be provided auto-reclose function as follows: The line breaker shall be reclosed after a dead time, which shall be adjustable between 1 and 60 seconds. The dead time shall be set long enough to allow undervoltage protection on motor control centres or variable speed drive units to operate and the motors to be disconnected. The dead time shall be typically 5s. If the fault persists or recurs within the reclaim time, which shall be adjustable between 1 and 200 seconds after the initial recloser, then the fault shall be cleared by IDMT overcurrent / earth fault protection. Operation of the time dependent protection within the reclaim time shall result in tripping of CB and lockout of the auto reclose scheme. The reclaim time selected shall be longer than the operating time of the time dependent protection and longer than the reset time of the circuit breaker closing mechanism. The reclaim time shall be typically 180s. The scheme shall include an operation indicator and operation counter with facilities to lockout after a set number of operations. Facilities shall also be provided to manually inhibit the auto reclose scheme as required (during Live-line washing of OHL insulators, for example).

3.2

33KV INTERCONNECTIONS BETWEEN STATIONS The protection of 33kV interconnecting feeder is shown in fig. 1.2. Typical trip matrix is attached as Appendix-F. The 33kV feeders interconnecting stations, where there is a possibility of bi-directional power flow, line differential or high impedance differential (for feeder lengths < 500metres) protection, as required, shall be provided as main protection. The directional overcurrent relays shall act as back up to line differential protection. Directional elements from overcurrent and earth fault relays shall be utilised to obtain selective tripping in either direction during relay co-ordination exercise.

3.2.1

Line differential Protection The relay shall use fibre optic cable for current comparison and communication between two ends. Line differential protection shall be numerical, operating on current comparison principle. The comparison shall be on per phase basis. The protection shall be able to identify fault type and provide visible indication for the faulty phases. Relay shall have capability of providing inter-tripping facility on external trip signals with clear identification of inter-tripping action. It should not be construed as operation of differential element. Identical Make and Type of the relays shall be provided at either end of OHLs in order to ensure problem-free communication with each other. If and when applied to lines with tee off transformer feeders, the relay shall have the capability of identifying transformer inrush currents and restrain the operation during such condition.

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Paralleling of current transformers is not allowed in line differential protection schemes and in order to meet this requirement, relays with adequate analogue inputs shall be selected. Line differential relays shall not be used for the routing of permissive / interlocking signals between two ends. Separate Binary Input/Output module for electrical to fibre optic interface shall be provided for the routing of permissive / interlocking signals between two ends. Relay shall be able to monitor the communication and provide alarm and also block the operation of relay. Relay should have facility of overcurrent back up under failed communication condition. The communication requirements of the protection shall be clearly identified taking in to consideration the distance between the two terminals and compatibility of all the interface equipment shall be clearly established. 3.2.2

Back-up protection The backup protection shall be provided by directional overcurrent and earth fault relay. The specification of this relay shall be same as clause 3.1.1.

3.3

132KV OVERHEAD LINES 132kV overhead lines shall have minimum two main protection relays (Main-1 & Main2). Each of the two main relays shall separately energise both trip coils. Two trip/lockout relays shall be used for the two trip coils. Each main protection relay (Main-1 & Main-2) shall have Line differential protection (87L), Distance protection (21), Directional Overcurrent / Earth fault protection, aided DEF, Thermal overload protection (49), Broken conductor protection, fault locator, etc. In addition, separate protection relay having at least auto-reclose function (79), synchronising check function (25CH), breaker fail protection (50BF) and undervoltage protection (27) shall be provided. The protection schemes required are shown in Fig. 2.1. Typical trip matrix is attached as Appendix-E.

3.3.1

Main-1 and Main-2 Protection Relays Redundant multifunction protection relays (i.e. Main-1 and Main-2) shall be provided. Main-1 and Main-2 should be of different manufacturer. Both relays from same manufacturer are acceptable only when they are on different algorithm and platform (i.e. entirely different hardware and software). Identical Make and Type of the relays shall be provided at either end of OHLs in order to ensure problem-free communication with each other. Relays shall have dual redundant protection communication channels between other end relays. Test features shall be provided for routine checking of the integrity of the protection communication channels. This may be either an end-to-end or a reflex test. These facilities shall include all features necessary to permit these tests with the feeder in service, with minimum risk of unwanted tripping. Relays shall have sufficient trip outputs to trip the circuit breaker directly and initiate operation of trip & lockout relays (86), auto-reclose function, breaker fail protection, SCADA alarms and local annunciation. Both relays shall have at least following functions:

3.3.1.1

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Line Differential Protection (87L) The line differential protection shall be as per clause 3.2.1. SP-1107 Specification for Electrical Protection Systems

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Distance Protection (21) Distance protection shall employ 6 separate measuring elements for each zone, i.e. one for each type of fault in each zone (e.g. R-Y Z1, Y-B Z1, B-R Z1, R-E Z1, Y-E Z1 and B-E Z1). Relays selected shall have measuring characteristics (e.g. mho, offset mho, lenticular, quadrilateral, etc), which are immune to mal-operation due to load current, transformer magnetising inrush currents, line de-energisation and similar system transient conditions. The relays shall have facility of selection of various single ended as well as carrieraided distance protection schemes. The minimum options shall include zone extension, permissive underreach, permissive overreach, echo feature, blocking and direct transfer trip schemes. The relays shall also include mutual compensation feature meant for parallel line feeders. The relays shall be immune to the transients introduced by CVTs during faults.

3.3.1.3

Power swing blocking The power swing blocking feature detects impedances encroaching in to the operating characteristic due to disturbances which result in transient changes in the rotor angles of generators at either end of a line. The power swing blocking feature shall detect impedance encroaching into the relay operating characteristic due to any disturbance resulting in transient changes in the rotor angles of generators at either end of a line. For these conditions tripping shall be blocked to allow the power system to return to a stable condition. Power swing blocking should be inhibited on zero sequence current detection. The relay shall be able to clearly distinguish a 3 Phase fault condition and power swing condition.

3.3.1.4

Voltage transformer supervision (VTS) The voltage transformer supervision (VTS) feature shall supervise the voltage signal to the Main-1 and Main-2 relays and shall operate for loss of voltage, due to, for example, tripping of an MCB. Loss of voltage shall not result in tripping. VTS operation shall initiate an alarm and shall inhibit the voltage based protections.

3.3.1.5

Switch onto fault (SOTF) The switch onto fault feature shall provide fast clearance, when closing onto a line, which is faulted anywhere along its length. This includes cases where close up three phase line faults, which may result in zero or very low voltage at the VT primary windings.

3.3.1.6

Self-Monitoring Comprehensive self-monitoring features specified in the clause 2.1.2 shall be provided.

3.3.1.7

Echo of tele-protection signal when circuit breaker is open The echo feature shall ensure that even with the remote circuit breaker open, the permissive overreach aided trip and DEF aided scheme achieves fast clearance for faults anywhere along the line length. In situations where the remote circuit breaker is open, and a fault occurs on the line, the tele-protection signal from the local relay shall be retransmitted (echoed) at the remote end back to the local end thus allowing fast clearance.

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Echoing of the received teleprotection signal shall be enabled through the programmable logic available in the numerical relays and not through the protection settings. 3.3.1.8

Weak in-feed The weak in-feed feature shall be provided. However, it shall be kept disabled.

3.3.1.9

Current reversal guard The current reversal guard feature shall prevent mal-operation through current reversal conditions during fault clearance on parallel lines.

3.3.1.10 Directional Earth fault (DEF) Directional earth fault protection shall be provided to cater for high-resistance earth faults. The directional earth fault scheme shall operate in conjunction with a protection communication channels to provide rapid clearance of this type of fault, on the receipt of a teleprotection signal from remote end. In case of parallel lines (double circuits), directional earth fault shall be polarised with negative sequence voltage instead of zero sequence voltage to prevent mal-operation due to mutual coupling. In line with the distance protection, the method of operation will permit selection between -either the permissive overreach or blocking mode and shall include Echo of tele-protection signal when the circuit breaker is open. The directional earth fault protection shall also be capable of IEC inverse and definite time delayed tripping independent of the receipt of a carrier signal. 3.3.1.11 Directional Overcurrent (DOC) Directional overcurrent protection shall be provided for backup protection. It shall have IEC inverse and definite time trip characteristics. 3.3.1.12 Broken conductor protection & Thermal protection Thermal protection based on long time inverse principle and broken conductor protection based on (I2/I1) or any other appropriate principle shall be provided. The broken conductor protections shall be annunciated in the SCADA. No trip is envisaged for broken conductor protection. 3.3.2

Auto-reclose and Synchronising Check Relay This multifunction protection relay shall have at least following functions:

3.3.2.1

Auto-reclose (79) Auto-reclose shall be provided for all 132kV overhead line feeders. It should be initiated for the operation of line differential protection (87), Zone-1 distance protection, distance protection carrier aided trip (permissive overreach) and DEF carrier aided trip. Zone-2, Zone-3 & Zone-4 distance protections, Directional overcurrent and earth fault time delayed protections, SOTF and TOR protections, busbar protection shall initiate auto-reclose lockout.

3.3.2.2

Synchronising Check (25CH) Synchronising check shall be provided for all 132kV overhead line feeders. Synchronising check protection specification shall be as described at clause 3.12.

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Revision: 4.0 Effective: Oct. 16

Breaker Fail (50BF) Protection Breaker fail protection (50BF) shall be provided for all 132kV overhead line feeders. However, as per current PDO philosophy, it shall be kept disabled except for 132kV substations with breaker-and-half scheme. In case of 132kV Substations with Breaker-and-half scheme, the breaker fail protection shall be enabled. The main bay breaker fail protection shall trip the corresponding tiebay breaker, the respective busbar as well as trip the remote end. The tie-bay breaker fail protection shall trip the two adjacent main bay breakers as well as trip the corresponding remote ends. Lockout shall be provided for associated remote ends too. Breaker fail protection scheme shall include contact of the disconnector status so that this scheme is available only when disconnector is closed. In addition, isolation link shall be included in the tripping scheme in order to isolate it during testing of the protection relays. The breaker fail protection relay specifications shall be as described at 3.5.2.15.

3.3.2.4

Undervoltage Protection (27) Undervoltage protection shall be provided and shall be used to provide earth switch close permissive in case of dead line condition.

3.3.2.5

Voltage transformer supervision (VTS) The voltage transformer supervision (VTS) feature shall supervise the voltage signal to relay and shall operate for loss of voltage, due to, for example, tripping of an MCB. VTS operation shall initiate an alarm and shall inhibit the all voltage based functions (e.g. synchronising check, DLLB or LLDB conditions, undervoltage etc.).

3.3.2.6

132kV RIMA, RUNIB, NIM(W), NIM(E), AMAL & MAR Substations – VT Secondary circuits The existing 132kV schemes in RIMA, RUNIB, NIMR(W), NIMR(E), AMAL and MARMUL substations have y-phase terminal of the VT secondaries earthed instead of usual star point. These substations are old and it is important to verify the schemes whenever new feeders are planned in the said substations and ensure the compatibility. This applies to protection, voltage selection and metering as well as synchronising schemes.

3.4

TRANSFORMER PROTECTION

3.4.1

Specification of Transformer Protection This section identifies the requirements of standard protection provided for transformers of various sizes. Section 3.4.2 specifies the applicability of these protections to various transformers depending on application and size.

3.4.1.1

Transformer Biased Differential and Restricted Earth Fault Protection Specification Biased differential protection provides high-speed unit protection for phase and earth faults of the transformer primary and secondary windings. Transformer Biased differential protection relays shall be of the multifunction numerical microprocessor type and shall incorporate integral CT ratio and vector group compensation and integral restricted earth fault protection. The biased differential protection shall be of the high-speed type. The relay shall have facility to detect transformer magnetising inrush currents and thus prevent operation of relay during energisation of transformer under normal conditions. The techniques used for restraining protection operation under above conditions should not cause the

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slowdown of relay operation under heavy internal fault conditions e.g. faults at transformer terminals. The operating characteristic of the bias protection shall ensure stability on any transformer tap position under maximum through-fault conditions. Paralleling of current transformers (e.g. for the transformer supplied from switchyard with one and half breaker scheme, etc.) is not allowed in biased differential protection schemes and in order to meet this requirement, relays with adequate analogue inputs shall be selected. Whenever transformer restricted earth fault protection is based on high impedance principle, it shall include either internally, or for connection externally, the appropriate stabilising resistors and voltage limiting devices. For the resistance earthed system, restricted earth fault protection shall be based on the low impedance principle. Restricted earth fault relays shall be installed on transformer star windings to increase winding coverage since these relays provide virtually complete cover for earth faults. For the REF protection based on the low impedance principle, phase CTs need not be distinct and separate from those for transformer differential protection. For the REF protection based on the high impedance principle, phase CTs shall be distinct and separate from those for transformer differential protection, unless there is confirmation from vendor as to the reliable, proven performance of the scheme to that effect. Cables and connections between the transformer and the switchgear should be in the protected zones of the biased differential and restricted earth fault relays. 3.4.1.2

Directional and Non Directional Overcurrent & Earth fault Protection The IDMTL overcurrent, earth fault and highset overcurrent, earth fault protection for distribution transformers shall be as per clause 3.1.1. Highset overcurrent and earth fault elements shall be of the low transient overreach type Both overcurrent and earth fault protections shall have inrush (2nd harmonic) blocking feature. The use of numerical relays with multiple IDMTL and high set elements along with directional elements are preferred rather than discrete directional and non- directional relays.

3.4.1.3

Standby Earth fault protection Standby earth fault protection is connected to the neutral CT in the transformer neutral circuit. This shall be set to detect faults in the transformer windings and shall be coordinated using time delay for faults in the outgoing feeders of the switchboard. Standby earth fault protection neutral CT shall not connected to sensitive earth fault protection element of the relay for solidly / effectively earthed system and low resistance earthed system. In case of resistance earthed neutrals, the earth fault protection relay shall include an instantaneous element as well set to isolate the transformer without delay in case of flashover in the resistor cabinet and consequent high currents during an earth fault in the system. The current pick up for the instantaneous element shall be set 150% of the NER rating. The CT shall be high accuracy type with a ratio as applicable for the rating of NER. Standby earth fault protection can be part of the feeder overcurrent / earth fault protection or can be a separate relay.

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Non-Electrical Protection devices Excess winding temperature, excess oil temperature and pressure release device protections and protection for on load tap changer (OLTC) shall be provided in accordance with DEP 33.65.40.31 – Gen and SP-1117. Buchholz protection shall be provided on all oil filled transformers fitted with a conservator tank. The Buchholz device shall be a two-element device giving operation under low gassing and surge conditions. Transformer on load tap-changer compartments shall be provided with a separate Buchholz device. Low oil level and pressure relief devices shall be provided when specified. The low oil shall initiate an alarm whilst the pressure relief shall initiate a trip. The non-electrical external protection devices functions such as tap changer and transformer Buchholz, oil and winding temperature, low oil level, and pressure relief device operation shall not be wired to the Transformer differential protection relay or any other numerical relay. In order to ensure adequate redundancy, these functions shall be wired to individual interposing relays which will in turn provide alarm (local as well as SCADA), trip and indication signals. The interposing relays shall conform to sec 3.13.3. Oil and winding temperature protections shall be used for alarm only. However, if micro switch is used instead of mercury switch for oil and winding temperature indicators, stage-2 of these alarms should be connected for breaker trip as well as for lockout relay.

3.4.2

Transformer Protection Schemes The degree of protections applied to power transformers is normally related to the rating of the transformer. However, in certain instances, e.g., duplicate supplies to essential service boards, the use of faster-acting discriminative protection normally associated with larger transformers may be justified on smaller unit sizes. The schemes of this Standard are only providing minimum requirements. Fig 3.1 includes Transformer with 415V Secondary connected to 33kV OHL, through Fuse-Disconnector. This shall be applicable even for transformers with HV secondary, provided the transformer rating doesn’t exceed 2.5MVA. In such a case, the transformer incomers on secondary shall be provided overcurrent and earth fault protection, Standby Earth fault protection and voltage unbalance protection for detection of 33kV fuse failure. The Standard protection schemes for HV/HV transformer with primary or secondary connections longer than 500 meters shall include line differential protection (87L) for the leads. In such a case, line differential relay (87L) shall include transformer too in the protection zone and the transformer differential protection in this relay shall conform to the requirements as stipulated at Clause 3.4.1.1 above. Standard protection schemes for different transformer sizes / configurations are provided as part of this SP. In case of a requirement other than the identified ones, new scheme specific to the project can be prepared and got approved by CFDH-E. Guidance can be taken from the existing standard drawings while preparing the new drawing.

3.4.2.1

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HV Switchboards with incomers working in parallel 33kV system in PDO is operated with bus section breaker closed. Hence, summation (partial differential) type overcurrent & earth fault protection using the incomer and bus section CTs shall be provided for 33kV switchgears so as to clear the busbar as well as uncleared outgoing feeder faults, selectively. Connection of CTs for partial differential protection scheme shall be in line with section 13.4.5 of IEEE standard 242. Use of summation CT is not relevant for this scheme and hence it shall not be provided. SP-1107 Specification for Electrical Protection Systems

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The partial differential relay shall be one per bus section and on operation, shall trip all the incomers to the respective bus section as well as the bus section breaker. The partial differential protection needs to be in service even when one of the incomers is under maintenance shutdown. Hence, each section Partial differential OC/EF protection shall be located in the Bus Section / Extension panels (total 2nos relays in BS panel) with DC supplies as well as trip/lockout relays separate from that of incomer panels. Each relay shall have its own Trip/Lockout relay that would trip (& close block) the respective bus section incomer and the bus section breaker. Directional Overcurrent & Earth fault relay and Standby Earth fault (SBEF) relay in the incomers will be wired to 132kV lockout relay and thus there is no need to have separate lockout relays in the incomers. The CTs in bus section shall overlap to ensure fast clearance of bus section faults. All the transformer / generator incomers, bus section breakers as well as tie feeders from other switchboards shall be wired in to the scheme. This scheme is also applicable for HV switchboards, which are supplied from tie feeders from other HV switchboard with bus section breaker closed and having no transformer / generator incomers. With more sources connected to each bus section of the switchboard there is a possibility that the summed-up current to the relay exceeds nominal relay input rating of 1A, even during normal load conditions. This shall be evaluated on case-to-case basis, so as not to subject the relay to continuous overload. All such source feeders shall include directional overcurrent & earth fault relays, set to look away from the busbars, to act as backup to the transformer / feeder differential protection. In addition to directional overcurrent & earth fault protection, this relay shall also have non-directional overcurrent and earth fault protection. Standby earth fault protection shall have two stages at least. The first stage shall coordinate with the partial differential earth fault protection and the second stage shall be set sensitive to detect transformer winding faults. Both stages shall trip the transformer primary breaker & master trip / lockout relay and 33kV incomer breaker. In addition to 33kV switchgear, if any other switchgear is operated with incomers in parallel in line with the project requirement, protections shall be provided in line with this clause. 3.4.2.2

Transformers with HV (6.6kV or 11kV or 33kV) primary and 415V secondary winding Fig. 3.1 shows the protection that shall be used for transformers with 415V secondary. Typical trip matrix is attached as Appendix-D. Transformer differential protection and restricted earth fault protection are not required for transformers with 415V secondary. Standby earth fault protection connected to a CT in the neutral connection shall be used to provide protection against LV earth faults. This protection can be provided on the 415V switchgear. However, standby earth fault protection in HV switchgear / relay panel is recommended, if HV panel is within 300m from transformer. If possible, the standby earth fault protection can also be provided in the LSIG protection release of 415V incomer circuit breaker and in such case discrete standby earth fault protection relay is not required. This neutral CT which is to be connected to LSIG protection release and located at the transformer terminal box shall be selected and supplied as per recommendation of manufacturer of the LSIG protection release. On the secondary side of the transformers, incomer feeders to the 415V switchboards shall be provided with circuit breakers. For overcurrent and earth fault protection, LSIG protection release shall be provided. To enable co-ordination with downstream protection devices, these shall have adjustable time and current settings.

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In case, switchboard outgoing feeders include harmonic producing loads (e.g. thyristor controlled heaters etc.), the suitability of earth fault protection release (against any spurious trips due to harmonics) for switchboard incomers as well as corresponding outgoing feeders, shall be verified with the manufacturer. If necessary, numerical relays for overcurrent & earth fault protection can be provided instead of electronic protection release. In such case, separate neutral CT shall be provided and connected in parallel with phase CTs for the earth fault protection. It is required to ensure that earth fault protection doesn’t operate for load unbalance current. In remote isolated locations, it is preferred to have built-in all the required protections in the ACB/MCCB releases and have no standalone protection relays / lockout relay. This is for the reason that these stations are without access to any DC UPS. In case protection relays are provided, the trip output contacts from the relays shall be latched and reset push-button provided on the panel (and its contacts wired to the inputs of the relays) for resetting the protection trips once trouble shooting is completed. In case of switchboards with automatic bus transfer schemes, the incomers shall include trip/lockout relay (86). The incomer overcurrent and earth fault protections shall be wired to the lockout relay (86). The lockout relay contact output shall be wired to inhibit the automatic bus transfer scheme in case the incomer trip is caused by bus fault or uncleared downstream fault (back up protection operation). The rating of any fuse protected LV circuit which derives power supply from the 415V switchboard should not exceed 25% of the rating of the transformer incomer to the switchboard or 100A, whichever is lower. Similarly, the rating of any fuse-protected LV-circuit which derives power supply from a 415V DB should not exceed 50% of the rating of the fuse protected 415V incomers to the distribution board. Where the rating of the LV circuit (excluding motor feeders) is 100A and above, in order to ensure proper protection coordination, current limiting type MCCB with LSIG protection release shall be provided. Protection coordination with upstream MCCB / ACB and downstream MCCB / fuse shall be ensured. SP-1121, DEP33.64.10.10 and IEEE Std 242 may be consulted for further guidance. 415V Circuit breakers are supplied with built-in no-volt/undervoltage releases as standard accessory by some vendors. The same shall be verified during scheme checking and the releases removed as these can cause avoidable supply failures at 415V switchboards when there is voltage dip due to faults elsewhere in the system. a)

Transformers Controlled by Fused Contactors For transformer rated 1600kVA and lower, a fused contactor can be provided instead of a circuit breaker on the HV side of the transformer. The contactor shall be latched type and there shall be a means to trip all three phases when one or more fuse links operate. The characteristics of the protection, the contactor, and the associated fuse shall be co-ordinated to ensure that the fuse always operates at all values of current to clear the faults within contactor’s maximum breaking/withstand capacity.

b)

Transformers Connected To HV Fuses Transformers of ratings 2500kVA or less can be connected to an overhead line system or to cable ring main systems through fuse-disconnectors or fused ring main units respectively. Protection against failure of the HV fuse on the primary side of transformer shall be provided. It is recommended to provide this protection by enabling voltage unbalance protection in the LSIG protection release of 415V incomer circuit

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breaker so that discrete voltage based protection (27U) relay for HV fuse failure detection is avoided. However, requirement of standby earth fault protection, Winding Temperature trip, Oil Temperature trip and Pressure Release Device trip can be exempted for transformers rated 300kVA and less. For details with regard to HV fuse selection, refer clause 5.4.1. c)

Transformers Connected to HV Circuit Breakers Transformers rated above 1600kVA, when supplied from HV switchboard, shall be connected to an HV circuit breaker, this is required to ensure appropriate protection coordination between outgoing transformer feeder and incomer of the switchboard. The high set instantaneous overcurrent and earth fault elements shall be enabled on the HV side.

3.4.2.3

Transformers with HV primary (33kV and below) and HV secondary windings Fig. 3.2 show the protection scheme that shall be applied to HV/HV transformers with primary connections less than or equal to 500 metres in length. Typical trip matrix is attached as Appendix-D. Time dependent overcurrent and earth fault and highset overcurrent and earth fault protection incorporated into a multifunction numerical relay shall be used on the primary winding of the transformer. Differential protection for transformer rated 5.0MVA & above and restricted earth fault protection shall be provided as per clause 3.4.1.1. Time dependent standby earth fault protection shall be used on the neutral connection of the transformer. Fig. 3.3 shows the protection scheme that shall be used on transformers where primary connections are longer than 500 metres. In this case, the line differential protection (87L) shall be provided on 33kV connections in line with clause 3.2.1. The inter-tripping (Direct Intertripping-DIT) facility of line differential protection relay shall be used to communicate trip signals between LV and HV panels through the protection communication channels.

3.4.2.4

Transformers with 132kV primary and 33kV, 11kV or 6.6kV secondary windings Figs. 3.4, 3.5 & 3.6 show the protection schemes that shall be used for transformers with 132kV primary voltage. Typical trip matrix is attached as Appendix-D. Time dependent overcurrent and earth fault and highset overcurrent and earth fault protection incorporated into a multifunction numerical relay shall be used on the primary winding of the transformer. Differential protection and restricted earth fault protection shall be provided as per clause 3.4.1.1. Time dependent standby earth fault protection shall be used on the neutral connection of the transformer. Whenever primary connections are longer than 500 metres, one line differential protection relay shall be provided on 132kV overhead line / cable feeder , which shall be same as main-1 and main-2 relays in line with clause 3.3 of this document. The inter-tripping (Direct Intertripping-DIT) facility of this protection relay shall be used to communicate trip signals between LV and HV panels through the protection communication channels. In case the secondary feeder length is more than 500meters, line differential protection (87L) shall be provided for secondary connection in line with clause 3.2.1. The intertripping (Direct Intertripping-DIT) facility of line protection relay shall be used to communicate trip signals between LV and HV panels through the protection communication channels.

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3.4.2.5

Auto Transformers Auto transformers are single winding transformers. Hence, the differential protection shall be high impedance type using nine CT scheme (3nos. each in primary, secondary as well as star end of the transformer windings). Separate REF protection is not relevant for the auto transformers.

3.5

MAIN GENERATING UNITS

3.5.1

General The generator protection system and trip logic shall broadly be in line with IEEE guidelines (IEEE C37.102 / C37.101). Fig. 4.1 indicates the protection scheme that shall be used for generators connected to the 33kV system through generator transformers without generator circuit breaker (GCB). Fig. 4.4 indicates the protection scheme that shall be used for generators connected to the 132kV grid through generator transformers with generator circuit breaker (GCB). The trip matrix indicated at Appendix-C is typical and shall be applied to all the grid connected generators with suitable changes to suit the configuration. The arrangement shown shall be regarded as the minimum acceptable in terms of the number of protection functions and degree of redundancy. Other arrangements of multifunction and separate relays providing a greater number of functions and/or greater levels of redundancy will also be considered. In view of the complexity and various types of protective functions involved, it is essential to provide separate trip relays, one for each generator circuit breaker, field circuit breaker, turbine etc. The classification of tripping for different types of fault i.e. faults, which should issue trip commands to generator circuit breaker (GCB), Field CB and turbine shall be as per the trip matrix given at Appendix-C. The logic shown here shall be considered as a minimum. The trip logic / classification proposed by contractor shall include any other protection deemed necessary. Such classification shall include other abnormal conditions such as failure of prime over, drop on steam / gas pressure, excessive vibration, differential expansion of rotary parts etc. Multifunction numerical microprocessor relays shall be used for the main generator and generator transformer protection functions. Depending on the limitations of the number of analogue inputs (CT and PT inputs) it may not be possible for single relays to meet all the protection requirements of generator and generator transformer. When finalising the number of numerical relays needed to cover complete protection requirements attention must be shown to allocate the protection functions in such a way that different relays are functionally complementary to each other. For the generators with generator circuit breaker, redundant multifunction protection relays (i.e. Main-1 and Main-2) shall be provided. Main-1 and Main-2 should be of different manufacturer. Both relays from same manufacturer are acceptable only when they are on different algorithm and platform (i.e. entirely different hardware and software). Duplicate trip coils shall be provided for the HV generator circuit breaker and generator transformer circuit breaker. The protection trip relays shall trip both coils and shall initiate operation of respective lockout relays.

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Specific Protection Functions Following are the requirements of specific protection functions to be provided for generators. The trip logic to be followed for each protection function is indicated in Appendix-C.

3.5.2.1

Generator differential (87G) The generator differential protection shall provide phase and earth fault unit protection for the stator. The protection shall be high impedance type. Alternatively, Percentage type Generator Differential protection can be provided. In case of percentage type Generator differential protection, the protection shall be provided by the variable slope, biased differential relay. The relay shall be very sensitive to internal faults and the bias characteristics shall make the relay stable for heavy external faults. In case of high impedance earthed generators, the Generator Differential protection may not be adequately sensitive and is further discussed below under “Earth Fault Protection”.

3.5.2.2

Overall generator and generator transformer differential and REF (87GT, 87N(HV)) The multifunction numerical microprocessor overall generator-transformer biased differential protection relay shall be as per specification clause 3.4.1.1. This shall act as back-up to faults in generator, the bus duct in addition to the generator transformer. 5th harmonic blocking for generator transformer differential protection shall be enabled as separate overfluxing protection is always available for the generator transformers.

3.5.2.3

Generator-Transformer HV Overcurrent & Earth fault Protection: Directional overcurrent and earth fault protection (67/67N) shall be provided for faults looking towards generator transformer. In addition, if non-directional overcurrent protection (50/51) may also be enabled,

3.5.2.4

Earth fault Protection High impedance earthed generators shall be provided Stator earth fault protection as below to complement the generator differential protection. The Calculation shall be in line with IEEE C37.101 practice and the sizing shall ensure that the resistive currents are at least 150% of the capacitive currents in the system, to limit the overvoltages. The NGT primary voltage rating shall be same as the generator phase-to-phase voltage rating. Stator earth fault protection shall be capable of providing coverage for at least 95% of the stator winding. In addition, generator schemes with generator circuit breaker (GCB) shall include generator busbar earth fault protection to protect the circuit on the transformer side of the generator voltage circuit breaker when the breaker is open. Generators connected to 132kV grid through generator transformers with generator circuit breaker (GCB) shall also be provided 95%-100% earth fault protection, additionally. a)

Stator earth fault protection – 0-95% (59N, 50/51G) One scheme shall be based on residual (broken delta) overvoltage detection and incorporated in Main-1 relay. Other scheme shall be based NER (on secondary of NET) current measurement and incorporated in Main-2 relay. The NER current measurement scheme shall detect earth faults on at least 95% of the generator windings. The relay shall be insensitive to frequencies other than 50Hz. The relay shall have an inverse time characteristic. The relay shall

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be comprehensive, transient free and free from maloperation due to harmonics, load changes and faults beyond the generator transformer. A time overcurrent relay with instantaneous element (50/51G) shall be used (connected to the CT in the NER circuit). The CT shall be of high accuracy type and the primary current rating shall be equal to the NER rating. The relay setting shall be chosen so as to prevent maloperation due to the third harmonic currents in the system. Instantaneous element shall be set to operate in case of flashover/shorting of NER (accidental solid earth fault). In case of distribution transformer type grounding, the CT ratio shall be such that the current in CT the secondary circuit shall be equal to earth fault current on the primary side of the distribution transformer. In case of HV resistor connected directly in generator neutral circuit, the neutral CT ratio shall be unity (5/5A). (Reference IEEE C37.101). The residual (broken delta) overvoltage measurement through generator line VTs shall detect earth faults by monitoring a shift in the neutral-to-earth voltage (59N). The relay shall be insensitive to frequencies other than 50Hz and have an inverse time characteristic. The relay shall be comprehensive, transient free and free from maloperation due to harmonics, load changes and faults beyond the generator transformer. The protection shall be set to coordinate with the Busbar earth fault protection. The Ynyn0 connected VTs may cause maloperation of Stator Earth fault protection for earth faults on the secondary of VTs. Hence, VT secondary earthing shall be modified to y-phase earthing instead of star point earthing to minimise the effect of VT-secondary wiring earth faults on the Stator earth fault protection. b)

Stator earth fault Protection – 95-100% One scheme shall be based on low frequency voltage injection and incorporated in Main-1 relay. Other scheme shall be based on the measurement of third harmonic voltage at the neutral end of the generator and incorporated in Main-2 relay. Injection method for protecting the entire stator winding of a generator is to deploy signal injection equipment to inject a low frequency voltage between the stator star point and earth. An earth fault at any winding location will result in the flow of a measurable injection current to cause protection operation. This form of protection can provide earth fault protection when the generator is at standstill, prior to run-up. In the third harmonic voltage measurement method, an undervoltage element (27TH) shall be provided to cover for earth faults at the neutral end of the stator winding by monitoring the third harmonic voltage produced by the non-linearity of the generator. In order to avoid maloperation when operating at low power output, the third harmonic voltage element can be inhibited using an overcurrent or power element (kW, kVAr or kVA) and internal programmable logic. Third harmonic voltage measurement method shall be provided for alarm only.

c)

Generator Busbar Earth fault protection (59BN) In case of generator schemes with Generator Circuit Breaker, the busbars between generator circuit breaker and the Generator transformer/unit auxiliary transformer(s) shall be protected against earth faults. The protection shall be based on monitoring of residual voltage on Bus VT secondary side. The generator busbar earth fault protection may be interlocked with the generator circuit breaker status (available only when the GCB is open). Alternatively, if the protection is available all the time, then, it needs to be

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coordinated with the generator stator earth fault protection upstream, as described above. 3.5.2.5

Overfluxing (24) The flux in the core of the transformer is directly proportional to voltage and inversely proportional to frequency. Overfluxing conditions can occur if the AVR attempts to maintain nominal voltage during run up and run down of the generator or due to an overvoltage condition following a load rejection. Overfluxing protection shall protect the generator transformer from thermal damage of the core due to excessive flux in the magnetic circuit. Generator Transformers / Unit auxiliary transformers built to IEC 60076 can withstand 125% overfluxing for 1minute and 140% for 5s. The protection shall be with inverse time characteristic and shall be set to closely match with the transformer overfluxing characteristic so as to avoid unnecessary trip.

3.5.2.6

Loss of excitation (40) Loss of excitation protection is provided to protect the generator rotor from overheating due to the slip-frequency currents induced when excitation is lost and it operates as an induction generator. The stator winding may also overheat due to the high level of reactive current drawn from the system. A loss of excitation condition may be caused by a fault in the excitation system or by incorrect opening of the field circuit breaker. The system itself is put at risk, as it has to supply the lost VAR output of the generator suffering the field failure in addition to the VAR required to excite it as an induction generator. This protection shall be additional to any loss of excitation protection that may have been included in the generator excitation system / AVR panel. The protection shall consist of offset mho element. The complete shutdown of the set is not always necessary for loss of excitation. The shutdown is required only when loss of excitation is going to lead to system instability. For this purpose loss of excitation protection shall be complemented with instantaneous undervoltage element.

3.5.2.7

Reverse power (32R) The reverse power protection function provides protection against mechanical damage to the turbine in the event of loss of turbine output whilst still connected to the system. Under such conditions the generator will run as a motor, drawing active power from the system. Continued operation under these conditions can cause damage to the turbine. In addition the protection shall be as sensitive (especially with steam turbines and this may not be an issue with gas turbines which have motoring power requirement of approximately 50% of its rating due to compressor load) as practical in order to detect turbine governor failure. In case of steam turbines, this protection shall be provided with a separate high accuracy measurement class CT so as to reliably sense the motoring power. For steam turbines, reverse power protection shall have two stages. First stage shall have low time delay and be anded with turbine trip signal (valve close status). Second stage shall be without turbine trip signal and have higher time delay. In case of gas turbines, single stage protection shall be provided without turbine trip signal and have low time delay. A time delayed trip shall be provided such that there shall be no risk of maloperation during power swings. The contact of this relay shall not be used to trip the turbine during planned shutdowns.

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Negative phase sequence (46) The negative phase sequence protection function provides protection against the effects of excessive rotor heating that can occur due to unbalanced loading of the generator. This can be as a result of system faults or unbalanced system loads. The protection shall be able to identify and protect the generator against short term as well as sustained negative sequence loading. The protection shall be arranged to provide a first stage alarm and a second stage trip.

3.5.2.9

Dead machine protection / Inadvertent Energisation (AE) Protection (50/27G) In order to avoid catastrophic failure of the generator due to sudden application of balanced three-phase voltage to the generator when it is shut down or on turning gear, dead machine protection shall be provided. The protection shall be retained in service during the generator shutdown and be designed to trip generator breaker required to isolate the unit However, in case of planned shutdown of generator, disconnector with generator circuit breaker shall be kept open so that there is no possibility of sudden application of three phase voltage to the generator. The relay shall be interlocked to avoid its mal-operation under power swing & loss of excitation conditions.

3.5.2.10 Pole slipping protection (78) Pole slipping can occur either due to scarcity of excitation or due to uncleared primary system faults. Pole-slipping, if allowed to persist, may result in instability of other machines connected to the system resulting in wide spread system disturbance in addition to mechanical stresses in the rotating parts leading to ultimate machine failure. Protection shall be provided to detect the pole-slip condition and isolate the generator. 3.5.2.11 Undervoltage and Overvoltage Protection (27/59) An overvoltage condition may arise due to a faulty voltage regulator or load rejection whilst on manual regulator control. The overvoltage protection function provides protection against insulation damage which can occur due to the excessive stresses which result from an overvoltage condition. The protection shall have two stages – one for urgent trip on detection of transferred voltage surges from the grid and the second set to coordinate with the generator AVR response. The setting shall be time delayed to ensure that the machine doesn’t trip on overvoltage during load throw-off. Undervoltage protection shall be wired only for alarm so as to alert the operator for corrective action. This is in line with IEEE C37.102. 3.5.2.12 Underfrequency and overfrequency protection (81U/O) The frequency measuring element shall have two stages for underfrequency settings and one stage of overfrequency setting. Underfrequency shall be wired for alarm so as to allow corrective action by operator. The generators shall be allowed to continue to work within the frequency range as stipulated by Oman Grid Code. Currently the frequency range for continuous operation of generators is 47.5Hz to 51.5Hz. 3.5.2.13 Backup overcurrent protection, Voltage dependent (51V) For generators directly connected to the grid or switchboard without generator transformer, voltage controlled overcurrent protection shall be provided as back up protection for uncleared system faults fed by generator.

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For generators connected to the 33kV switchboard through generator transformer, voltage restrained overcurrent protection shall be provided as back up protection for uncleared system faults fed by generator. The voltage dependent mode shall be used for protecting the generator when the fault current and generator terminal voltage fall below normal load values due to generator’s inability to sustain high fault current for uncleared faults. In voltage-controlled mode, when voltage drops below a predefined value, the relay shall switch over from ‘overcurrent characteristics’ to ‘fault characteristics’. In voltage-restrained mode, the relay shall be able to modify the time current characteristic continuously depending on the value of terminal voltage. Backup Overcurrent protection shall be set to coordinate with the Overcurrent protection in the outgoing feeders at the Grid bus. 3.5.2.14 Under Impedance protection (21G/21GT) For generators connected to 132kV grid through generator transformers with generator circuit breaker (GCB), under impedance protection (21GT) shall be provided on the HV side of the generator transformer. An adjustable time delay shall be provided to ensure that co-ordination with the main system protection is achieved such that the impedance protection only operates for faults not cleared by the main system protection, especially distance protection on 132kV OHL feeders. For all generators connected to 132kV grid through generator transformers, under impedance protection (21G) should be provided on generator side of generatortransformer, in this case neutral of this relay shall be left unearthed to prevent its operation on generator earth faults since these faults are taken care by other protections. 3.5.2.15 Breaker failure (50BF) Breaker failure protection shall be provided for all main generators. This protection shall act when the generator circuit breaker or HV circuit breaker (52G-LV or 52G-HV) fails to open on a fault. Breaker failure protection shall initiate tripping of breaker(s), which is (are) next to the failed breaker on source side(s). The following requirements shall be met by breaker fail protection provided for generator breakers 

The ratio of resetting current to operating current for current detection element used in breaker failure function shall be in the range of 80 to 90% or better.



The resetting time of the current detection element shall not be more than 20ms (preferably of the order of 5-10ms)



Continuous energisation of current detection element may lead to sluggish resetting or even non-resetting of this element in rare case even after breaker has opened and cleared the fault. To overcome this problem the current detector circuit in breaker failure protection shall be energised only after trip command is issued to the breaker.

Auxiliary contact of breaker shall be used in parallel with current detection element to ensure correct operation in case there is insufficient current for current detection to operate. The breaker failure protection shall be initiated by all trip relays associated with generator breaker tripping. In case of generators connected to 132kV grid, breaker fail protection scheme shall include contact of the disconnector status so that breaker fail scheme is available only when disconnector is closed.

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In case of generators connected to 11kV or 33kV switchboards, the breaker ‘service’ position contact or alternatively, the isolator status contact (in case of GIS) shall be put in series with the breaker status contact to prevent maloperation of breaker fail protection scheme when the feeder is down. The breaker fail protection relay shall be distinct from the main protection relays. Alternatively, the BF protection shall be enabled in both the main protection relays so that the breaker fail protection is not disabled, in case of unavailability of either protection relay. Isolation link shall be included in the tripping scheme in order to isolate it during testing of the protection relays. 3.5.2.16 Other protections Stator temperature, diode failure, rotor earth fault, over-speed protection etc. shall be provided as part of the generator and turbine control functions. Rotor earth fault protection for generators connected to 132kV grid through generator transformers with generator circuit breaker (GCB), shall comprise two relays, one for alarm on occurrence of first earth fault and the other for trip in the event of second earth fault occurring when the first earth fault is persisting. The alarm relay shall detect the single earth fault anywhere in the field circuit. The relay shall be incorporated with suitable DC bias voltage. The scheme shall not use a permanently connected brush.

3.6

LV GENERATING UNITS The protection scheme shall be as shown in Fig. 4.3.

3.7

132KV AND 33KV BUSBAR PROTECTION

3.7.1

General 33kV Switchboards connected to generators and all the 132kV busbars shall be provided with Busbar protection. In PDO, Busbar protection is not envisaged for other 33kV switchboards and all the switchgears below 33kV.

3.7.1.1

132kV Substations For 132kV busbars, phase and earth fault protection based on the high impedance principle of differential protection shall be provided. Discriminating zones and an overall check zone shall be applied. These zones shall operate from two independent CT cores. Low impedance numerical busbar protection (Fig 6.4) may be considered for double busbars with CT switching requirements, as it simplifies the scheme thus improving the reliability.

3.7.1.2

33kV Switchboards The busbar protection for 33kV Switchboards with generating sources shall be based on high impedance principle similar to that for 132kV busbars. Where there is no generation connected, busbar protection is not required.

3.7.2

Protection Scheme Requirements To mitigate against the possibility of a relay mal-operation resulting in the loss of a complete section of a busbar, operation of both the discriminating zone and check zone shall be required for tripping to occur. The trip signal from the bus zone protection shall be wired to both trip coils. The bus zone protection shall also initiate direct inter-trip (DIT) signal to the remote end of 132kV feeder circuits through fibre optic protection communication channel.

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This also shall lead to lockout of remote ends, due to the fact that the busbar trip could be due to a fault between the breaker and CT of a particular bay or due to BF protection trip (Breaker-and-half scheme). Busbar protection shall also trip both the primary and secondary circuit breakers of any 132kV bus connected transformers and shutdown any connected generators. In case of breaker-and-half schemes, refer 2.1.3 above. Secondary circuit of a CT shall be continuously monitored, so that in the event of an open circuit an alarm shall be given, the secondary circuit shorted and the tripping rendered inoperative by means of an electrically operated relay. Switches shall also be provided to take each zone out of service. The trip relays for bus zone protection shall be located in the busbar protection panel and shall be wired directly to the switchgear for tripping. 3.7.3

Schemes Busbar protection shall be used at all 132kV substations. Two sets of CTs shall be provided, one on either side of bus section breaker / bus coupler breaker for zone overlap for busbar with two or more bus sections and for double busbar configurations.

3.7.3.1

Busbar with two or more Bus Sections Fig. 6.1 shows the scheme that shall be adopted for a 132kV substation with more than one section of busbar. The scheme consists of three zones of busbar protection, one for each Bus and one overall check zone. Isolator Contacts All the auxiliary contacts used in CT switching scheme shall be silver-plated. In case of Normally Open contacts two contacts in parallel shall be used in CT circuits. Auxiliary contacts used in busbar protection scheme shall meet the following requirements While closing of Isolator, Auxiliary Contacts shall close before Pre-arcing of Primary contacts. While opening of Isolator, Auxiliary Contacts shall open after Primary contacts open.

3.7.3.2

Double Busbar with Low Impedance Busbar Differential Protection The scheme for double busbar is shown in fig. 6.4. Scheme consists of three zones of busbar protection, one each for Bus and one overall check zone. The scheme can be hard wired, based on conventional protection relays or in the form of software logic, based on numerical relays, specifically designed for busbar protection and CT Switching application. a)

CT Switching Switching the line CT inputs to corresponding bus Zone relay shall be carried out by bi-stable relays, imaging the position of bus isolators. It shall be ensured that CT circuits do not become open under any operating / switching sequences. Use of auxiliary CTs is possible with low impedance busbar differential protection and ensures continuity of main CT circuit. Main CTs shall be suitably sized for the burden of auxiliary CTs.

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Isolator Contacts Operation of imaging relays shall be monitored continuously to generate alarm on detecting malfunction. Auxiliary contacts of Bus isolators should be used to drive these bi-stable relays. Type of isolator contacts should be as specified in fig 6.4. All the auxiliary contacts used in CT switching scheme shall be silver-plated. In case of Normally Open contacts two contacts in parallel shall be used in CT circuits. Auxiliary contacts used in busbar protection scheme shall meet the following requirements While closing of Isolator, Auxiliary Contacts shall close before Pre-arcing of Primary contacts. While opening of Isolator, Auxiliary Contacts shall open after Primary contacts open. NO and NC auxiliary contacts shall not have overlap to prevent hunting of CT switching relays during travel of isolator contacts from fully open to fully closed condition. If isolator auxiliary contacts are derived from multiplication relay, then it shall be ensured that relay is switched to ON position as soon as isolator blades move from OFF position. DC supply for operation of imaging relays shall be derived from the same source as operating supply for respective isolators.

3.7.3.3

Busbar with single Bus Section The scheme for a single busbar without line circuit breaker is shown in Fig. 6.2. The design features shall be the same as for the double section busbar except that a check zone is not required.

3.8

MOTOR PROTECTION

3.8.1

General General protection requirements for motors installed in hazardous and non-hazardous areas are specified in DEP 33.64.10.10-Gen.

3.8.1.1

Vital / Essential Duty motors – short time voltage dips DEP 33.64.10.10 defines Vital and Essential Services as below: a)

Definition: Vital Service “A service which, if it fails in operation or when called upon, can cause an unsafe condition of the process and/or electrical installation, jeopardise life, or cause major damage to the installation.”

b)

Definition: Essential Service “A service which, if it fails in operation or when called upon, will affect the continuity, quality or quantity of the product.”

These are identified by electrical design group in consultation with PDO-Process during design stage of the project and listed in the Utility Data Sheets. The vital / essential duty motors shall not trip during short-time voltage dips in the system (such as the ones caused by faults elsewhere in the system), depending on the requirement.

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3.8.1.3

Type of Switchgear for Drives 

HV contactor shall not be provided for motors rated more than 1.2MW, instead, circuit breakers shall be provided. This is required to ensure appropriate protection coordination between outgoing motor feeder and incomer of the switchboard.



The contactor and the associated fuse shall be co-ordinated to ensure that the fuse always operates at all values of current to clear the faults within contactor’s maximum breaking/withstand capacity.



Motor contactors shall not have high dropout time delay as coordination between fuse and contactor is ensured by selection of fuse so that all the short circuit faults are cleared by fuse.



If the motors are VSD controlled, the VSD shall include transient voltage dip ride-through function as per DEP 33.66.05.33-Gen.

Vital service motors including Fire safety related ones Motor switchgear & control gear for vital service drives (either HV or LV) including Fire Water Pumps and other fire safety related drives shall conform to NFPA20/70 requirements. Vital service motor protection trip shall be limited to locked rotor and short circuit protection only. The locked rotor protection pickup setting shall not be less than 300% of the motor full load current and shall not trip before 8s. Overload protection and earth fault protection shall be wired only for alarm.

3.8.2

LV Motors Protection requirements for LV motors shall be as per SP-1121, DEP 33.64.10.10-Gen and DEP 33.67.01.31-Gen.

3.8.3

HV Motors

3.8.3.1

Protection Requirements - General HV motor circuit protection shall be provided with multifunction numerical microprocessor based relay (motor protection relay). The relay shall have the facility to display measured values, store motor starting time/starting current and fault currents, communicate, accept an external trip input and shall incorporate as a minimum the following protection functions: 

Short-circuit protection (50)



Thermal Overload protection (49)



Phase Unbalance and loss of phase protection (46)



Locked Rotor and excessive start time protection (51LR/48)



CBCT connected Earth fault protection (51G) for switchboard connected motors



Undervoltage protection (27) with an adjustable time delay

Motors shall also have: 

frequent starting limitation protection or restart inhibit protection (66).

Restart inhibit protection or frequent starting limitation protection shall be provided for close inhibit only and shall not be used for tripping the motor. Additionally,  Page 52

under-load protection

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shall be provided for submerged pump drives. Separate motor differential protection (87M) shall be provided for motors rated 3.5MW and above. In such case, two nos. of motor protection relays (MPR) shall be provided and they shall be multifunction relay having all motor protections as well as motor differential protection (87M). All applicable motor protections and motor differential protection shall be enabled in both relays. For synchronous motors, motor protection relays should be of different manufacturer, both relays from same manufacturer are acceptable only when they are on different algorithm and platform (i.e. entirely different hardware and software). For motors connected through unit transformers, common differential protection shall be provided for unit transformer and motor combination for the motors rated below 3.5MW and it shall be as per clause 3.4.1.1. The earth fault protection for motors connected to HV Switchboard shall be through CBCT. CBCT shall not be connected to sensitive earth fault protection element of the relay. In addition to the motor protections specified above, Synchronous motors shall also be provided protection against 

Loss of excitation (40),



Out-of-step / pole slipping (78)



Rotating diode failure detection



Overvoltage (59) and



Rotor Earth fault protection (64R)*

* Rotor Earth fault protection shall be provided if the same is vendor standard design. If rotor earth fault protection is provided, it shall be wireless type (i.e. without slip rings and brushes). For description of out-of-step and loss of excitation protections, clause 3.5.2 should be referred. Out-of-step protection based on power factor sensing (55) is not acceptable and shall be impedance based (78). Undervoltage protection for synchronous motors shall have an inverse characteristic matching the stability curve of the motor. 132kV Unit transformer connected motor protection relay shall include underfrequency protection element with adjustable time delay for including the feeder under Load Shedding Schemes of PDO. When the underfrequency element operates, it shall issue a separate annunciation as “Load shedding protection operated” in order to distinguish from motor protection operation. Rate-of-rise of frequency element is not required. The numerical motor protection relays can accept Temperature detector inputs from motor windings, bearings etc. However, the current practice in PDO is to wire these detectors to the C&A panels. Hence, the motor protection relays may not be specified to have the feature (that is optional). To provide sufficient protection for the motor under stalling conditions and at the same time allowing normal running-up of the motor under lowest allowable motor starting voltage, 

the motor safe stall time shall in general be greater than the normal running-up time by a margin of at least 3s.

If the same cannot be met due to large inertia of the drive or otherwise, stalling protection initiated from a motor shaft speed sensing switch shall be applied. In certain cases when motors are fed via unit transformers the voltage at the motor terminal may fall below 80%. In such a case it may be possible to set the motor protection relay without exceeding the thermal limits of the motor, i.e. starting times Page 53

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longer than the safe stall time at 100% voltage can be allowed knowing that motor terminals are never going to be subjected with 100% voltage during starting. Discretion may be applied to the requirement of a speed-sensing switch for such motors. 3.8.3.2

Unit Transformer-motor & Earth fault protection In case of unit transformer connected motors, the Neutral Earthing Resistor (NER) on the secondary of unit transformer shall be sized to limit earth fault current to 20A in order to avoid irreparable motor core damage in case of stator earth fault.. However, calculation shall be carried out to ensure that NER current is not less than 150% of the total estimated capacitive current in the system. (Refer IEEE C37.101). With earth fault currents limited to 20A on the unit transformer secondary side, there is no need for transformer restricted earth fault protection (87N). Adequate earth fault protection shall be ensured by sensitive standby earth fault protection (51G) connected to neutral CT and additionally neutral voltage displacement protection (59N) shall be provided. Neutral CT shall be high accuracy type with primary rated at 100% of the NER current rating. Large Synchronous motors are similar to Synchronous generators in design. Hence, high resistance earthing of motor voltage system similar to unit transformer connected generators can be provided. The earth fault protection shall ensure coverage of not less than 95% of the motor windings. For further details on earth fault protection of Synchronous motors, clause 3.5.2.4 can be referred.

3.8.3.3

Protection Scheme Requirements The protection scheme used for directly connected motors is shown in Fig. 5.1. Typical trip matrix is attached as Appendix-G. The protection schemes for unit transformer connected synchronous motors and induction motors are shown in Figs. 5.2 & 5.4 and Figs. 5.3 & 5.5 respectively. Typical trip matrix for unit transformer connected motors is attached as Appendix-H. Typical protection scheme for Unit Transformer connected Synchronous motor with VFD is shown in Fig 5.6 and the drawing is for information only. a)

b)

Breaker failure (BF) protection Breaker fail protection on the process safeguarding trip or other process stop/trip command from IPS/DCS/FCS system is not required in electrical protection relay or switchgear panel. Any such requirement will be taken care in the DCS/FCS/IPS system by Control & Automation teams and trip command to upstream breaker(s) will be directly wired from DCS/FCS/IPS system in case motor breaker fails to trip. Unit Transformer - Motor The scheme for unit transformer – motor shall include circuit breaker at motor terminals also. This breaker shall be operated for process trips and motor protection trips. The Transformer/motor Differential protections and earth fault protection shall trip 33/132kV breaker as well as the motor circuit breaker. 132kV connected unit transformers shall be with OLTC to address the impact of allowable 132kV voltage variation of +/-10% (SP-1103) on the motor starting.

c)

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Unit Transformer – Synchronous Motor In addition to requirements for unit transformer – motor in line with clause 3.8.3.3 (b), following are the requirements for unit transformer – synchronous motor.

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Synchronous motors supplied to Shell standards (DEP 33.65.11.31-Gen) can operate continuously at 0.9 leading (at a motor terminal voltage of 0.9pu) and supply VArs to the system. The excitation controller shall include excitation booster module to help prevent motor going out-of-step during system faults. This also will help in the event of sudden load increase on the drive (and prevent out-of-step trip) due to process changes. Power supplies to the excitation circuit / AVR / excitation panel shall be reliable, derived from AC / DC UPS. If normal AC supplies are used the same shall be from redundant sources with appropriate auto changeover facility Further, in the interest of PDO power system 

the unit transformers (nominal tap & the OLTC tap range) shall be designed so as not to have any restriction in its capacity in export/absorption of VArs as per the motor rating, even working at extreme limits of motor terminal voltage.



the unit transformers shall be supplied with OLTC. The Synchronous motor excitation controller shall be designed to coordinate with the Unit Transformer OLTC-AVR so as to allow the motor to work at the set power factor without causing voltage violations at motor terminals.



the unit transformer’s rated no-load voltage at principal tap shall be same as the motor rated voltage so that the motor will not trip on overvoltage when synchronised.

d)

Schemes with long cables / OHL on Unit Transformer secondary Schemes involving long power cable or OHL on secondary of unit transformers shall not be preferred as these are likely to be less reliable (due to more number of cable runs and associate cable joints/terminations or OHL faults).

e)

Schemes other than those covered in SP Standard protection schemes for different unit transformer-motor configurations are provided as part of this SP. In case of a requirement other than the identified ones, new scheme specific to the project can be prepared and got approved by CFDH-E. For example, The schemes in standard drawings for 132kV connected unit transformer– motors are with cable lengths above 500 meters on secondary of unit transformer-to-motor circuit breaker. In case the OHL / cable lengths on unit transformer secondary are below 500 meters, the scheme can be modified to exclude line differential protection (87L) for long cable / OHL. In such a case, the transformer differential/LV-REF protection shall include in its zone the transformer secondary cables too. Similarly, in case of OHL/cable longer than 500 meters on primary of unit transformer, line differential protection (87L) shall be considered for OHL/cable on primary of the transformer. Line differential protection (87L) shall comply with clause 3.2.1. The line differential protection (87L) shall include transformer too in the protection zone. The transformer differential protection in this relay shall conform to the requirements as stipulated at Clause 3.4.1.1. Guidance can be taken from the existing standard drawings while preparing the new drawing.

3.8.3.4

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Unit Transformer- Motor with VSD A typical scheme (Fig. 5.6) is attached for protection of large unit transformer- motor with VSD. The scheme is typical and for information only. Printed 10/10/16 SP-1107 Specification for Electrical Protection Systems

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Protections shall comply with IEEE C37.96, DEP 33.66.05.33-Gen and DEP drawing S67.057. OLTC may not be provided in case of VSD-motors if the starting and running requirements as per DEP/SP can be met without OLTC for Unit Transformer. The requirement of synchronous motor as well as the requirement of bi-directional power flow capability of the drive (for VAR export or regenerative braking etc.) shall be discussed during tender stage on case-to-case basis and requirement of OLTC should be considered. Differential and other motor protection elements should be capable of operating at frequencies other than 50Hz as per the allowable speed variation of the drive specification. The design basis report shall capture this aspect and the impact of harmonic rich environment that is prevalent in the drive system while selecting the relays / protection for VSD transformer, Harmonic filters and the motor. In case of ungrounded power system, earth fault protection shall be based on broken delta voltage detection and shall cover complete system, Converter input side, output to motor, harmonic filter banks etc. The earth fault protection on the input side of the converter shall be effective under all conditions, while the converter is ‘on’ as well as ‘off’. Further, 132kV connected Unit Transformer-Motors shall include a circuit breaker at the input terminals of VSD for process control / trips. Alternate to circuit breaker at VSD input terminals, two 132kV circuit breakers can be provided.

3.9

CAPACITOR BANKS

3.9.1

General Capacitor units shall be with integral fuse protection as stipulated in DEP. All the capacitor banks greater than 1000kVAr rating shall be connected in Double-Star configuration and shall be provided with unbalance protection to detect failed capacitor units and annunciate / isolate the feeder. This is in line with DEP 33.64.10.10-Gen. Protection (including settings) of capacitor banks shall, in general, be as per IEC 60871 / IEEE C37.99 / the manufacturer standard. Capacitor bank protection relays need not be IEC61850 compliant. For the typical protection settings of capacitor banks, appendix-Q shall be referred.

3.9.2

Motor Capacitors It is not recommended to provide power factor correction capacitors at the motor terminals. If they are proposed for any project, shall be subject to CFDH-E approval. In case of motors with power factor correction capacitor at their terminals, a single switching device and associated relays and/or fuses that control/protect both the motor and the capacitor shall be provided (DEP33.64.10.10-Gen). The motor connected power factor correction capacitor sizing calculation shall address the issue of self-excitation (Refer Clause. 27.5.3 of IEC 60871-1 which states typically the capacitive current shall not exceed 90% of the motor no-load current and typically, the no-load current of motors varies from 20% for 2-pole machines to 60% for 20-pole ones). Wherever possible, the motor vendor shall be contacted for recommendation on the maximum permissible capacitor rating. The calculation shall be subject to PDO approval. Fixed type Power Factor Correction Capacitors connected across Motor terminals shall have differential protection CTs at phase terminals, so as to exclude the capacitor from the unit-transformer - motor differential protection zone. The motor protection relay shall also protect the capacitor.

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Capacitors shall not be connected in parallel with motors performing a vital or essential service e.g. drives of instrument air compressors, fire water pumps etc., in accordance with DEP33.64.10.10. 3.9.3

Switchboard Capacitors Power Factor Correction Capacitors connected to the switchgear busbars shall have more than one stage and switching arrangement with control through Automatic Power Factor Controller (APFC). APFC shall be set as per the manufacturer’s guidelines and meeting the requirements stipulated in DEP. For the typical settings of APFC controller, appendix-R shall be referred. The protection scheme shall include Overvoltage protection.

3.10

UNDERVOLTAGE / OVERVOLTAGE RELAYS Undervoltage / overvoltage relays shall have a minimum two voltage elements connected across three phases. Relays shall be with built in time delays. Pickup to dropout ratio for voltage relays shall be within 5% of unity. The relay shall block the operation of undervoltage elements under no-voltage condition.

3.11

UNDERFREQUENCY LOAD SHEDDING

3.11.1

Relay Requirements Underfrequency relays with adjustable frequency and time delay settings shall be of the numeric type and shall be insensitive to harmonic voltage distortion and to transient voltage deviations. The relay shall have: 

four stages of underfrequency settings.



rate of change of frequency element.

The relay shall block the operation of frequency elements under no-voltage condition. The load shedding relay shall be discrete and use of functionality available in any other protection relay is not acceptable. However, it can be clubbed with bus undervoltage protection relays. 3.11.2

Application of the Scheme All 33kV, 11kV and 6.6kV switchboards shall be equipped with the facility of tripping the loads (outgoing breakers) under under-frequency conditions. Tie feeders between the stations shall not be tripped under load shedding scheme.

3.11.3

Scheme Requirement Fig. 7.6 indicates the load shedding scheme for a typical HV system. One relay per bus shall be provided, incorporating four stages of protection. The voltage input to the underfrequency relay shall be automatically selected from the secondary voltage of either busbar. Also, one common load shedding On/Off switch per bus shall be provided. Output from the load shedding relay shall be bus-wired to every feeder panel and five position (four stage and off position) selector switch shall be provided in each feeder panel to select the feeder to any tripping stage or to an OFF position.

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Unit Transformer - Motors In case of motors connected through unit transformers (other than 33kV Switchboard connected unit transformers), the underfrequency element (at least one stage) with adjustable timer shall be provided in the Motor protection relay for setting the load shedding trip as per the load shedding study report. When the underfrequency element operates, it shall issue a separate annunciation as “Load shedding protection operated” in order to distinguish from motor protection operation. Rate-of-rise of frequency element is not required.

3.12

SYNCHRONISING Overview of Synchronising Selection Scheme for a typical HV system is indicated in Fig. 7.4. Synchronising check relay shall be provided to prevent inadvertent closing of the breaker under ‘out of phase condition. Synchronising check relay shall be provided for all 132kV overhead line breakers, 132kV bus section breakers, 132kV bus coupler breakers, 132/33kV and 132/11kV transformer feeders where generation (or alternative source) may be connected to the LV side. This facility shall also be provided to 33kV feeders, which are used for interconnection of two stations. Synchronising facility which can be common for one substation shall comprise of double voltmeter, double frequency meter, synchroscope for incoming and running voltages, Synchronisation Auto / Manual selection switch and lockable Synchro-check IN / BYPASS selector switch. All these equipment shall be mounted on hinged synchronising panel that can be easily viewed from either end of the (switchgear) control panel. Use of common synchronising check relay is not recommended in 132kV substations and hence separate synchronising check relay shall be provided for each 132kV feeder. The generator synchronising scheme (manual as well as automatic) shall facilitate use of both generator voltage CB (or 52G-LV, if available) and the 132kV grid voltage CB (52G-HV). The generator synchronising is normally through turbine control system. In addition, manual synchronising facility shall be provided in generator control panel. Further, Generator synchronising, at either 52G-LV or 52G-HV, can be initiated from SCADA (to be executed by Turbine control system). Generator synchronising at 52GHV can also be initiated from 132kV CRP. In addition, it shall be possible to close 52GHV from CRP or SCADA in override mode to back energise the generator transformer (with 52G-LV open). Use of synchronising check element in the protection relays is acceptable provided it meets the technical requirements. These elements require external triggering and the same shall be addressed in the C&R panel schemes by wiring the Synchronising selector switch / SCADA synch selection signal to the relay as a binary input and programming appropriately. All other switchboards including 415V ones shall be interlocked with the respective upstream switchboards to keep the schemes simple and economical, yet reliable. In these switchboards, synchronising check relay is optional and shall be preferred only in case of practical difficulty in interlocking with the upstream switchboard. Switchboards supplied from 132kV breaker-and-half substations, 33kV Switchracks and 11kV RMUs are some of the cases which may require synchronising check relay for paralleling. The synchronising check relays need not be IEC61850 compliant.

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For 33kV Switchracks, Field Ring mains and 11kV RMUs, the check (at present) is through switching programs and the same practice shall continue. 3.12.1

Relay Specification Synchronising check relays shall check the phase, slip frequency and magnitude of the voltage difference at synchronising, and inhibit closure outside acceptable limits. Synchronising check relays shall also have option of Dead Line Live Bus (DLLB) and Live Line Dead Bus (LLDB) closing in the override mode. Live and dead voltage settings shall be provided so that Dead Line Live Bus (DLLB) or Live Line Dead Bus (LLDB) condition can be determined.

3.12.2

Synchronisation Schemes for Substations Feeders in the same station (controlled from same room) may share synchronising equipment. All the switchgears/substations shall be provided with Bus VTs. The bus voltage input is required for synchronising, metering, for providing voltage polarisation to directional relays in transformer feeders, for undervoltage protection of motors and for providing voltage / frequency signals to load shedding schemes. In the existing substations / switchboards, there are no bus VTs. For the extension of existing switchgear / switchboards, the voltage selection scheme for new switchgear panels shall be fully integrated with the existing scheme. Running and Incoming voltages required for synchronisation shall be derived from bus VT and line VT respectively. For the synchronisation of bus section breaker / bus coupler breaker, one bus VT supply shall be taken as running voltage and other bus VT supply shall be taken as incoming voltage. Once the voltages of a particular feeder are selected for synchronisation, it shall prevent simultaneous selection of any other feeder in order to prevent paralleling of two VT supplies. Requirements of synchronising schemes are outlined in the block logic diagram shown in Fig. 7.5. Every feeder requiring synchronising facility shall be provided with a key operated ON/OFF/OVERRIDE switch in the control room. A single key shall operate all the switches of one switchgear. This key shall be locked in both ON and OVERRIDE position. In SCADA selection between SYN ON & OVERRIDE shall be provided for all feeders. Interlocking shall be ensured by software programming in SCADA. ‘SYN ON’ signal shall be wired to the synchronising check relay for triggering the synchronising check. Synchronising scheme shall -

Provide a Remote / Supervisory selector switch in control room to select the breaker closing operation from either control room or SCADA.

-

Shall allow closing of breaker in “SYN ON” mode only after check of system synchronism by synchronising check relay.

-

Shall allow closing of a breaker in OVERRIDE mode only after check of Live Line Dead Bus or Dead Line Live Bus check by synchronising check relay

In case of Dead Bus – Dead Line condition, no remote closing is envisaged. An interlocking scheme shall be devised at each substation so that it shall not be possible to parallel two power stations other than via circuit breakers, which are equipped with synchronising facilities. The scheme shall take cognisance of the status of disconnectors and circuit breakers. Page 59

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AUXILIARY RELAYS

3.13.1

Trip Circuit Supervision

Revision: 4.0 Effective: Oct. 16

Trip circuit supervision shall be applied to all HV circuit breakers. Trip circuit supervision shall be provided to monitor the trip circuits with the circuit breaker in both open and closed state. Where duplicate trip coils are provided, both trip circuits shall be monitored. The trip circuit shall be wired by looping-in relay contacts in sequence, so that the entire trip wiring is monitored. Protection tripping shall not be routed through the circuit breaker LOCAL/REMOTE control selector switch. The trip isolation link in the circuit breaker control cubicle shall be monitored by the trip circuit supervision. Relay elements shall be delayed on drop-off to prevent false alarms. Relay alarm elements shall be equipped with self-resetting flag indicators. Series resistances shall be provided in trip circuit supervision circuits to prevent maltripping should a relay element become short-circuited. The use of Trip Circuit Supervision function, wherever it is a part of a Numerical Relay is acceptable only if there a single numerical protection relay for the subject feeder and the function meets the above detailed requirements. 3.13.2

Trip and Lockout Relays Protection trips to the circuit breakers shall be wired directly from the numerical relay trip outputs. Trip/Lockout relays shall be provided for all feeders. The trip command to the circuit breaker shall be issued from trip/lock out relay, in addition to direct trip from the protective relays. The trip/lockout relays shall be high burden type complying with TS 48-4 Class EB 2 or Class ESI 2. High burden relays are less susceptible to mal-operations due to capacitive discharge currents (e.g. under conditions such as an earth fault on the secondary wiring associated with the trip relay operating coil circuits). They also permit the use of supervision relays. These shall be one for each trip coil / protection group. The period between energisation of the trip relay coil and closure of the tripping contacts shall be less than 10ms. The tripping contacts shall have making capacity of the maximum current, which can occur in the circuit controlled by these relays. They shall also be capable of breaking such currents unless provision is made for breaking the current on contacts elsewhere in the circuits. Lockout relays are used to block the closing of a breaker under faulty conditions. To prevent resetting of this relay on failure of auxiliary supply the latching mechanism of the lockout relay shall be mechanical. The reset mechanism of the lockout relay shall be hand reset as well as electrically operated to facilitate both local and remote resetting. Lockout relays shall be equipped with a pair of normally closed contacts arranged to break its own coil circuit when in the latched position, thus avoiding battery drain. Flag shall be provided for the lockout relays. Resetting of the flag shall match the resetting of the relay. Separate trip relays shall be provided when the lockout function is not called for and, the protection relay doesn’t have output contacts rated for tripping function. The trip

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relays shall be self reset type with hand reset flag. These relays shall be suitable for continuous energisation, in addition to being high burden type. 3.13.3

Interposing Relays Interposing relays are widely used in protection schemes. Some of the applications are, 

routing the transformer mounted protections such as Buchholz relay and the inter-trip signals from primary to secondary side of the transformer



in case of interconnecting feeders, routing of signals from one end to the other end



routing of breaker fail protection signals to the upstream breaker panel(s)



contact multiplication

The interposing relays when used in protection / tripping schemes shall have the same level of reliability / robustness (for example, high speed operation, high degree of mechanical stability against seismic, vibration and shock, high inductive breaking capacity of the contacts) as the main protection relays to ensure the integrity of the protection schemes. In case of long signal cables, these intertripping relays need to be immune to induced AC voltages additionally. Comparison between Protection class interposing / auxiliary relay and the general purpose auxiliary relay is provided at Appendix-I, for better understanding. Hence, these shall be type MVAWA (ALSTOM make) or equivalent. However, if length of the control cables energising interposing relays are not long and these cables don’t run along with other power cables or primary ground path, MVAA (ALSTOM Make) type relay or equivalent may be used in order to avoid higher time delay. Decision to use MVAA type relays shall be assessed during engineering stage of the project. General purpose relays (such as SCHRACK, PRIMA, OMRON, PLA) shall not be acceptable. Interposing relay’s contact shall not break the trip coil current when it is connected to trip coil directly and hence it shall always be connected in parallel with contact of trip & lockout relay (86). In case of both trip and alarm interposing relays, contacts shall be self reset type and the flag hand reset type.

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4

Protection Calculations, Settings and Representation

4.1

GENERAL TA-1 (CFDH-E) is the approval authority for protection settings. Approval must be obtained before new equipment is commissioned or existing settings are revised. Protection studies and setting recommendations shall only be undertaken by PDO consultants approved specifically for such studies.

4.1.1

Documentation Preparation and References Protection settings shall be recorded on schedules. Protection schedules, submitted for approval for other relays than overcurrent and earth fault protection, shall be accompanied with supporting calculations. The schedules shall include important information on the feeders, relay complete model (MLFB, Cortec etc.) no., applicable drawing references for the transformers, protection schemes etc. The schedules shall reflect a level of uniformity for better control, for example, all the redundant feeders shall have one set of settings in a substation. Protection grading curves shall be provided for overcurrent and earth fault coordination and shall be in colour, for better clarity. The document shall be of sufficient detail giving relevant information regarding the selection of each setting. Description of the system and of operating modes on which the settings are based shall be clearly indicated. In the relay setting schedule, voltage element settings shall be indicated in percentage of rated voltage in addition to absolute value, for better clarity. Calculations showing compliance with the relay manufacturers CT requirements shall be provided - especially for biased differential, high impedance differential and distance protection. The motive for choosing a particular CT rating and accuracy class shall also be provided (see clause 2.6) A checklist of the information required is given in Appendix A. DIgSILENT software shall be used for determination of overcurrent and earth fault settings. The guidelines specified in the document PR-1265 shall be followed for submittal of relay settings, relay operating curves, fault currents etc. The grading curves shall include the following information: 

The reference voltage level



Overcurrent / earth fault relay operation at setting.



Fuse curves showing both the pre-arcing and operating characteristic



Motor starting characteristic



Motor thermal withstand

The following particulars shall be given in the study document as a basis for the relay settings. When close scrutiny is needed, these particulars should be represented in the form of curves.

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

Maximum and minimum fault levels



Transformer fault current withstand capacity



Transformer magnetising inrush current

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Power cable short circuit withstand capacity



Contactor short circuit breaking capacity.

4.1.2

Basis for Calculations and Guidelines for Time Grading

4.1.2.1

Fault Currents

Revision: 4.0 Effective: Oct. 16

The 100ms (5 cycle) and 10ms (1/2 cycle) maximum and minimum fault currents (rms symmetrical values) shall form the basis for calculating the time dependent and instantaneous relay settings respectively. The bus fault currents shall be considered ensuring that the short time rating of the switchgear bus and other equipment is not exceeded. Limited duration overcurrents arising from single or group motor starting / reacceleration shall be permitted. The fault current flowing through a given branch shall be calculated with DIgSILENT model under various operating scenarios. Fault current calculations shall be included in the study. The minimum value of the fault current flowing through branch shall be considered for checking the sensitivity of the relays and tripping times. Instead of Ia, 3Io shall be considered from DIgSILENT output for the calculation of earth fault current magnitude. The IDMT coordination in PDO is based on IEC curves. The multiple of current at which the inverse curve flattens is either 20 or 30 times of the set value. It varies with the relay manufacturer, type of curves and type of relay used. This affects the protection coordination and hence shall be taken in to account. 4.1.2.2

Time decrement When determining the sensitivity of the IDMTL element, it shall be ensured as a general guideline that fault current is more than the relay operating current for 0.1s, 0.5s, and 2s intervals.

4.1.2.3

Grading Margins The pickup for overcurrent protection shall typically be 125% of the feeder rating. The setting can be lower in case of OHL tap-offs and others, depending on the expected loading. The overcurrent pickup setting shall preferably be less than half the calculated fault current for minimum fault level conditions considering realistic operating conditions. The earth fault protection pick up shall be typically 

5 to 15% of the protected equipment rating or feeder rating for solidly earthed system or



5 to 15% of the NER rating for resistance earthed system.

CBCT connected earth fault protection for 33kV OHL feeders and SEF protection for 33kV PMRs shall typically be set at 5A. In case of fuse-backed contactor feeders, short circuit protection shall not be provided (as the same is ensured by fuses) to allow fuses to blow and prevent contactor damage in case high current faults and earth fault protection shall be typically delayed by 0.1s to provide better stability during inrush currents.. The grading margin between adjacent electronic time dependent overcurrent and earth fault relays shall not be less than 0.30s. In case of Numerical relays, the same shall not be less than 0.25s.

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provided the protection operating time at the source end is not exceeding 1s. In case of bus section breaker, grading need not be provided if the normal operation is with bus section breaker in open position. This time interval shall be maintained at the maximum short circuit current that can flow through both the protections simultaneously or at the instantaneous setting of the relay nearest to the fault, whichever is the lower value of current. For example, while verifying coordination at the bus level, between outgoing and incoming feeders, the scenario “Bus section(s) open” or/and only one source On (if more than one source connected to the same bus)” shall be considered. A lower grading margin should be considered only in case the above grading margin results in tripping times higher than the equipment withstand ratings in the station and shall be based on the formula: T’ = 0.2t + tcb + 0.08 seconds. Where T’ = minimum grading time interval t = nominal operating time of relay nearest to fault(s) tcb = circuit breaker interrupting time(s) IDMT protection elements in numerical relays shall be set to reset instantaneously (on current coming down below the pickup setting) unless the relay needs to coordinate with an electro-mechanical relay downstream. With the IDMT overcurrent protection set to reset instantaneously (on opening of breaker), it is adequate to coordinate for one start of the motor (the largest motor with all the other feeders in service). In case the relay reset is not instantaneous and for electromechanical type relays, the protection stability during motor starting shall be verified as follows: In case of HV incomers to the switchboard with motor outgoing feeders, the overcurrent coordination at the incomer level should take into account two successive hot starts that are permitted for the HV motors. This also applies to the overcurrent protection on the primary of unit transformers, in case of unit transformer-motor feeders. The no. of permissible successive hot starts in case of LV motors is three. Directional overcurrent relays (at receiving ends) set to look towards the source need not be coordinated and can have sensitive settings. For grading between relays and downstream fuses the margin shall generally be no less than 0.2s. The total clearing time of the fuse shall be used for coordination purposes. In circumstances where a closer margin between the relay and the fuse characteristics may be advantageous, the minimum grading time interval shall be based on the formula: T’ = 0.4t + 0.15 Where T’ = minimum grading time interval t = total clearing time of the fuse at fault current considered Discrimination between fuses is required in the high fault current region (i.e. currents which operate the fuse in less than 0.01s) and if discrimination is achieved in this area, then it is assured at all lower current levels. If the pre-arcing I2t value is not exceeded, there will be no deterioration in the fuse characteristic. Therefore, if the total I2t value of the smaller fuse doesn’t exceed the pre-arcing value of the larger fuse then discrimination between the two fuses will be satisfactory. A margin should be allowed however, for fuse tolerances. Generally, the pre-arcing I2t of the major fuse shall exceed the total operating I2t of the minor fuse by a margin of approximately 40%.

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Specific Protection Setting Requirements This section provides general guidelines to be followed when determining the settings of various protections. However these guidelines shall be treated as a reference only and the guidelines do not relieve the contractor / design consultant of the responsibility of determining required settings to provide adequate protection to the equipment. For further guidance, the PDO practice (including any documents / communication issued time-to-time) as well as the industry recognised protection reference documents such as IEEE Std 242 (Buff book), Network Protection and Application Guide (NPAG of AREVA) shall be consulted.

5.1

OVERHEAD LINE FEEDERS - 33KV AND BELOW

5.1.1

HV Fuses Discrimination between fuses is required in the high fault current region (i.e. currents which blow a fuse in less than 0.01s). If discrimination is achieved in this region then it is assured at all lower current levels. If the pre-arcing I²t value is not exceeded then there will be no deterioration of the fuse characteristic. Therefore, if the total I²t value of the smaller fuse does not exceed the pre-arcing I²t value of the larger fuse then discrimination between the two fuses will be satisfactory. A margin should be allowed however, for fuse tolerances. Generally, the pre-arcing I²t of the major fuse shall exceed the total operating I²t of the minor fuse by a margin of approximately 40%. As a general guideline for satisfactory grading between two fuses the rating of the upstream fuse shall be at least twice the rating of the largest downstream fuse. When fuses are selected according to the fuse manufacturer’s application guideline, a copy of the guideline shall be provided. Installation of HV fuses shall be done in line with clause 2.1.7 and HV fuses for transformers are discussed at clause 5.4.1.

5.1.2

Overcurrent and Earth fault Protection 33kV overhead lines without earth wire have a high fault loop resistance for earth faults considering the soil conditions in the interior and that the currents have to return to the source through the soil. For overhead line feeders from 33kV switchboard, IDMT overcurrent protection pickup should be set at 100% of the feeder rating and IDMT earth fault protection pickup should be set at 15% of the feeder raring. General guidelines provided under clause 4.1.2.3 shall be applied for time setting. If three-phase fault and earth fault levels at upstream protection device are higher than 1.3 times of corresponding fault levels at downstream protection device, upstream protection device shall be provided instantaneous overcurrent and earth fault protection, set at 1.3 times of corresponding downstream fault level. Whenever, instantaneous protection is enabled, inrush blocking function shall also be enabled.

5.1.3

Directional Overcurrent and Earth fault Elements When used on parallel feeders direction of trip shall be opposite to the direction of normal power flow.

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The operating time of this element shall be less than the operating time of the nondirectional element on the feeder parallel to it by an adequate grading margin. This should be achieved by selecting a lower current as well as time settings. The fault angle, the lagging angle between the expected fault current and the voltage is depending on the fault impedance. Generally it will range from 45° to 60° for phase faults with the higher value applicable for overhead lines and the lower value applicable for transformer feeders. Hence the relay angle chosen (with quadrature line voltage input employed for polarisation, called cross polarisation) should be +30° (i.e. 90°-60°) for overhead line feeders. The + sign indicates that the relay will operate when current is flowing away from the bus. Typically, the Relay Characteristic Angle (RCA) settings for cross-polarised Directional overcurrent protection shall be, Plain feeders (with Zero Sequence source behind the relay location)

+30°

Transformer feeders (with Zero Sequence source in front of the relay location)

+45°

If operation is needed for the currents flowing towards the bus, then the setting of +30° shall be corrected with 180° to a value of –150° (i.e. 30°-180°). It shall be noted that the above guidelines are general and if more precise information is available about fault angles then this should be considered when specifying the angle settings. Residual voltage polarisation is adopted for Earth fault protection, in general. For earth faults the characteristic angle should be typically between 0° to –60°. However the actual setting shall be decided based on the type of polarisation used, system earthing and relay manufacturer’s guidelines. Typically, the Relay Characteristic Angle settings for Residual voltage polarised Directional Earth fault protection shall be, Resistance Earthed Systems

0°

Distribution Systems (Solidly earthed), 33kV

(-)45°

Transmission Systems (Solidly earthed), 132kV

(-)60°

The directional elements shall be set to block on detection of “VT fuse fail” and issue alarm. 5.1.4

CBCT Connected Earth fault Protection CBCT connected earth fault protection (51G) shall be capable of detecting less than 5A primary earth fault current at the minimum relay setting. Minimum time delay shall be 4s, to avoid mal-operation at transient unbalances during switching of ring circuits through isolators or during phase fault conditions. Under fault conditions, imbalance of the system voltage will cause an unbalance in the capacitive current drawn in each phase of a feeder. It is possible for a healthy feeder to trip via CBCT connected earth fault protection due to unbalanced capacitive currents. The pickup of CBCT connected earth fault protection shall be set higher than the expected capacitive current; typically a primary operating current setting of three times the steady state phase-to-earth capacitive current should be satisfactory CBCT connected earth fault protection need not be co-ordinated with standard earth fault relays. CBCT connected earth fault protection shall be coordinated independently with sensitive earth fault (SEF) protection in the downstream PMRs.

5.1.5

Thermal & Broken Conductor Protections Thermal protection is not envisaged for 33kV OHLs as per present practice.

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The broken conductor detection based on I2/I1 threshold shall have typical settings of 20% pickup & 60s time delay of. The broken conductor condition shall be annunciated in the SCADA. No trip is envisaged. 5.1.6

Pole Mounted Reclosers (PMRs)

5.1.6.1

Overcurrent & Earth fault Protection Settings for End PMRs As far as possible, it is recommended to clear the faults on the 33kV overhead lines within 0.1s so that voltage dips on the healthy circuits doesn’t exist for longer time. Hence, typical overcurrent and earth fault protection settings for the remotest end PMR (i.e. PMR which has no other PMR in its downstream circuit) are as follows: Overcurrent protection: Current Pickup: 120A, Characteristics: Standard Inverse and TMS: 0.05. Earth fault protection: Current Pickup: 40A, Characteristics: Standard Inverse and TMS: 0.05. SEF protection: Current Pickup: 5A, Delay: 5s

5.1.6.2

Overcurrent & Earth fault Protection Settings for Upstream PMRs PMRs which are installed in the upstream of end PMRs shall be coordinated with all the PMRs in the downstream circuit. For overcurrent protection and earth fault protection, as far as possible current pickup and characteristics should be set same as for the end PMR. TMS shall be modified as necessary for coordination with downstream PMRs. However it should be ensured that current pickup for overcurrent protection is not less than 125% of the total load current. If three phase fault and earth fault levels at upstream PMR are higher than 1.3 times of corresponding fault levels at downstream PMR, upstream PMR shall be provided instantaneous overcurrent and earth fault protection and set at 1.3 times of corresponding downstream fault level. Whenever, instantaneous protection is enabled, inrush blocking function shall also be enabled. Recommended SEF protection: Current Pickup: 8A, Delay: 1s more than time delay for downstream PMR.

5.1.6.3

Other settings for PMRs Settable time delay (or debounce time) shall be set at 1s for the pipeline protection trips or other external trips which are wired in fail safe mode through a tripping relay energised from AC supply. This time delay is required in order to avoid nuisance tripping due to momentary voltage dip. If the tripping relay is energised from DC UPS supply then time delay is not required. The transformer mounted protections (e.g. buchholz trip etc.) and other electrical protection trips shall be wired as “energise to trip” and hence time delay is not required. For these protections time delay shall not be provided.

5.2

33KV INTERCONNECTIONS BETWEEN STATIONS

5.2.1

Line Differential Protection The line differential protection relays from different manufacturers differ substantially in design. Hence the settings of line differential protections shall be worked out based on relay manufacturer’s guidelines. Overcurrent and Earth fault Protection Elements in line differential protection relays: The same settings of back up protection shall be repeated in these relays (overcurrent and earth fault elements are generally available in these relays) to provide additional back up protection to the feeder.

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Back-up protection Directional relays shall be provided to act quickly, even under bi-directional power flow conditions for faults in the interconnector. The directional relays shall be set to look in the direction of the interconnector at both the stations. The setting of non-directional / directional back up overcurrent and earth fault protections shall be as per clause 5.1.2 & 5.1.3.

5.3

132KV OVERHEAD LINES

5.3.1

Main-1 and Main-2 Protection Relays

5.3.1.1

Line Differential Protection The line differential protection elements from different manufacturers differ substantially in design. Hence the settings of line differential protections shall be worked out based on relay manufacturer’s guidelines.

5.3.1.2

Distance Protection -Scheme As dual redundant protection communication cannel is provided, Permissive Overreaching scheme (e.g. POR, POTT scheme) shall be applied. Permissive Overreaching scheme is preferred to Permissive Underreaching scheme (e.g. PUR, PUTT scheme) because the resistive reach of zone-2 or zone-1B element is higher than zone-1 element. The carrier signal shall be initiated by zone-2 or zone-1B.

5.3.1.3

Distance Protection - Choice of Characteristics The quadrilateral or fully cross-polarised mho characteristic provides a better coverage for arc resistance and under high ground resistance conditions. Hence quadrilateral characteristic should be selected for earth faults in particular and for phase faults in general.

5.3.1.4

Distance Protection - Zone Settings

5.3.1.4.1

132kV OHL Impedance Data For 132kV OHLs built on Wood Poles, Steel Towers and Concrete Poles, impedance data shall be calculated as per PDO standard SP-1114A, SP-1114B and SP-1114C respectively. The impedance data to be obtained from the OHL consultant before start of protection study. The actual lengths and the impedance data may vary slightly during execution. The calculated zone reaches for distance protection shall be verified and confirmed with the measured data before actual commissioning.

5.3.1.4.2

Zone 1 setting Zone-1 impedance setting shall be 80% of the protected line section. This should ensure that under no circumstances the relay would operate for faults beyond the protected line section. The same shall be 70% in case of parallel lines (including substantial length of Double Circuit construction), to prevent overreaching due to the effect of mutual induction when the other circuit is shut down and earthed at both ends.

5.3.1.4.3

Zone 2 setting The zone-2 reach shall be 120% of protected section. This shall be verified against reaching beyond 50% of the shortest line from remote substation as well as beyond the transformers (operating in parallel) at the remote substation. A safety margin of

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20% should be considered for transformer impedance while verifying that zone-2 doesn’t reach beyond the transformer winding. In case zone-2 setting reaches beyond 50% of the shortest line from remote substation, it should be limited up to 50% of the shortest line from remote substation. OHLs with line differential protection or OHL parallel to protected line (if any) shall not be considered for shortest line from remote substation. Similarly, if zone-2 setting reaches beyond the 80% of the transformer (operating in parallel) at the remote substation, it should be limited up to 80% of the transformers (operating in parallel) at the remote substation, 5.3.1.4.4

Current Reversal Guard timer setting Current reversal guard is applicable when there are parallel paths (or double circuit lines) between two substations. The guard is relevant if Zone-2 is set 150% of the subject line or more and for DEF/aided channel. Typical setting shall be 55ms (with maximum signalling channel reset time considered as 20ms). Current reversal guard timer need not be set if the DEF aided element operation is set with time delay. Thus, Current reversal guard time delay is not required for Zone-2 and DEF elements set as per the guidelines in this section.

5.3.1.4.5

Zone 3 setting Zone-3 shall be set in forward direction to provide backup protection for all overhead lines from remote substation. Zone-3 reach shall be set at 120% of (protected overhead line plus longest overhead line from remote substation). OHL parallel to protected overhead line (if any) shall not be considered for longest overhead line from remote substation. In case zone-3 setting reaches beyond 80% of the transformers (operating in parallel) at the remote substation, zone-3 setting should be limited up to 80% of the transformers (operating in parallel) at the remote substation. Underreach due to infeeds at remote substation should not be considered.

5.3.1.4.6

Zone 4 setting Zone-4 shall be set to cover in the reverse direction of uncleared close-up faults or back up for busbar faults. The same shall be 

25% of Zone-1 for protected line length <30km and



10% of Zone-1 for protected line length equal to or greater than 30km.

5.3.1.4.7

Mutual compensation For double circuit parallel lines on steel towers between any two substations, in order to eliminate effect of mutual flux coupling on the ground distance elements, mutual compensation shall be enabled using current from parallel line.

5.3.1.4.8

Load Impedance and resistive reach setting Load impedance shall be calculated at 

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90% of the rated voltage



0.8 power factor

Revision: 4.0 Effective: Oct. 16

Wherever, single ELM OHL is connected in parallel with the twin ELM OHL between same substations, load impedance of twin ELM OHL shall be considered for the single ELM OHL too. This is required to temporarily allow sudden overloading of the single ELM OHL when twin ELM OHL is tripped. The resistive reach for phase faults and earth faults shall be set in line with the relay manufacturer’s recommendations. 5.3.1.5

Power Swing Blocking Power swing blocking feature shall be enabled for all 132kV substation interconnecting feeders and shall be set to block for zone-1 and zone-2. Power swing blocking should be inhibited on zero sequence current detection.

5.3.1.6

Directional Earth fault (DEF) Element For the setting of the directional earth fault elements, the guidelines specified under clause 5.1.3 shall be followed. For rapid clearance of earth fault in the protected overhead line, carrier aided DEF trip shall be provided with Permissive Overreaching scheme. For all new overhead lines where main-1 and main-2 protection relays (with dual redundant protection communication channels) are provided, non carrier aided directional earth fault protection shall be disabled. For the existing overhead lines where main-1 and main-2 protection relays (with dual redundant protection communication channels) are not provided, non carrier aided directional earth fault protection shall be enabled and set at 80A. IEC inverse characteristic and TMS at 0.25. In addition, definite time protection with long time delay of 5s shall be provided for high resistance earth faults. The minimum operating time of the non carrier aided directional earth fault protection element should not be less than the operating time of the zone-2 element.

5.3.1.7

Directional Overcurrent (DOC) For the setting of the back-up directional overcurrent elements, the guidelines specified under clause 5.1.3 shall be followed. For all new overhead lines, where main-1 and main-2 protection relays (with dual redundant communication channels) are provided, directional overcurrent protection shall be disabled. For the existing overhead lines where main-1 and main-2 protection relays (with dual redundant protection communication channels) are not provided, directional overcurrent protection shall be enabled and set at 175% of rated current of the overhead line, IEC inverse characteristic and TMS at 0.25. It shall be ensured that it also coordinates with overcurrent protection on primary side of the transformers at remote substation for phase faults on the secondary side of the transformer.

5.3.1.8

VTS, SOTF, TOR, Fault Locator, functions VT supervision, SOTF, TOR and Fault locator functions shall be set. VT supervision shall be auto-reset. VT fuse fail shall be annunciated and also set to block all the voltage dependent protections. Switch-on-to-fault (SOTF) function shall be set to operate for Zone 1 & Zone 2 and shall be active for duration of 60s after the CB is closed.

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TOR (Trip on Reclose) shall be enabled for Zone 1 & Zone 2. Distance-to-fault locator function shall be set to provide reading in terms of kilometres. In case of parallel lines, CT from the other circuit shall be wired to the relay and mutual compensation shall be set in the relay, for correct working of Fault locator with parallel lines.

5.3.1.9

Time delay settings Relay operating times for different elements shall be, Zone 1

-

Instantaneous

Distance, Carrier aided

-

Instantaneous

DEF, Carrier aided

-

100ms (to allow Surge Arresters to discharge during lightning phenomenon)

Zone 2

-

250ms (less than critical clearing time 300ms for 132kV system in PDO)

Zone 3

-

1s

Zone 4

-

1s

Power Swing block

-

All Zones, Time: 10s in general and 2s for those interconnectors identified for system split., Unblock: on detection of Zero sequence current

SOTF

-

Zone 1 & Zone 2, Active for: 60s from the moment CB is closed

TOR

-

Zone 1 & Zone 2

5.3.1.10 Thermal Overload and Broken conductor protection Settings Thermal protection based on long time inverse principle and broken conductor protection based on (I2/I1) shall be set. Typical Overload characteristics of Elm conductor for different pre-load conditions are given at Appendix-L for ready reference. The typical settings for thermal protection are 

Thermal Trip



Time constant 12minutes

110%(i.e. 440A for single ELM and 880A for twin ELM)

The thermal alarm shall be set at 70% of thermal trip and wired to SCADA. Thermal trip shall be wired to Trip coil-1 and 2 of 132kV breaker. Lockout is not required. Typical settings for broken conductor protection based on (I2/I1) are 

Pickup

20%



time delay

60s.

Broken conductor protection alarm shall be annunciated in the SCADA and no trip is envisaged. 5.3.2

Auto-reclose and Synchronising Check Relay

5.3.2.1

Auto-reclose Function One no. three pole auto-reclose shall be provided and trip after reclose shall initiate auto-reclose lockout.

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One end of the overhead line, which has lower fault level, shall be provided autoreclose with dead line closing. Other end of the overhead line, which has higher fault level, shall be provided auto-reclose with synchronising check closing. Auto-reclose dead time for dead line closing shall be set at 5s and for synchronising check closing, dead time shall be set at 10s. Reclaim time shall be set at 15s.

5.3.2.2

Synchronising Check Function For the setting of the synchronising check function, the guidelines specified under clause 5.10.3 shall be followed.

5.3.2.3

Breaker Fail Protection The typical settings for BF protection shall be

5.3.2.4



Pickup: 200mA



Time delay: 200ms

Undervoltage Protection The typical settings of undervoltage protection for earth switch interlock shall be

5.3.2.5



Pickup: 20% (To determine dead line condition)



Time delay: 5s

VT Supervision

VTS operation shall initiate an alarm and shall inhibit the all voltage based functions (e.g. synchronising check, undervoltage etc.). VT supervision shall be auto-reset.

5.4

TRANSFORMER PROTECTION

5.4.1

Fuses for Transformer Protection Fuse links intended for transformer circuit protection shall comply with IEC 60787 / 60282. The fuse-link must withstand the transformer inrush current, considered for practical purposes as 

12 x transformer full load current for 100ms and



25 times for 10ms.

The minimum current rating of the fuse-link shall be 

125% of transformer full load current.

For transformers connected to an overhead line system through HV fuse cut-outs, it must be ensured that the maximum system fault level at the point of application is within the breaking capacity of the fuse. This may mean choosing a higher ampere rated fuse than the calculation demands at times. Installation of fuses shall be done in line with clause 2.1.7. In case of high fault level, PMR shall be installed in line with clause 2.1.7. In case there are motors connected on Low Voltage side, the HV fuse sizing shall take the motor starting requirements into consideration so as to avoid fuse blowing. Page 72

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The melting data of the type-T expulsion fuses is given at Appendix-D for ready reference. HV fuse ratings for 33kV connected transformers shall be in line with STD 4 1554 001.3. Also, refer clause 5.1.1 above for general guidelines for fuse selection. 5.4.2

Overcurrent and Earth fault Settings The setting of overcurrent element shall be 

greater (typically 125%) than the maximum rated current of the circuit being protected. At the same time it shall be



less than half the calculated fault current for minimum fault level conditions, considering normal operating conditions.

In addition, the settings chosen should not allow the short circuit capacity of cables and transformers to be exceeded. Partial differential protection overcurrent pickup setting shall be 125% of the total bus load or the total rating of all loads supplied from the bus section. This is important especially when the subject bus section has more than one source connected to it. 5.4.2.1

Highset Overcurrent element pickup setting Sensitivity and operating time must also allow for magnetising inrush currents during transformer energising. Settings of the instantaneous element for a transformer feeder circuit must be above: 

1.3 x transformer maximum symmetrical through-fault current, and



The maximum magnetising inrush current to avoid any undesirable tripping during switching.

When manufacturer’s data is not available, magnetising inrush current is generally assumed to be 

12 x full load current for 100ms (and 25 x full load current for 10ms).

In most applications, the requirement to set the relay above the LV fault level will automatically result in settings which will be above the level of magnetising inrush current. When the system available fault level is lower than the expected energisation inrush current, the highset pickup shall be set lower than the estimated inrush current magnitude by enabling the inrush (2nd harmonic) blocking feature to prevent trip during energisation. 5.4.2.2

Coordination between 132kV Transformer highset protection & Zone 2 of upstream 132kV OHLs The faults on the 132kV side of the transformer are sensed by zone-2 elements from other stations. Hence it is essential that highset element on the 132kV transformer feeders is set 

well below the minimum fault current on the 132kV side of the transformer to prevent operation of distance relays at other stations.

However, this may not be possible in locations with low system fault levels and in all such cases, transformer differential / REF protection can be depended upon. 5.4.2.3

Coordination between Transformer incomer overcurrent downstream motor feeders Overcurrent protection on incoming circuits should be set such that 

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protection

and

tripping will not occur if the circuit is fully loaded and at the same time

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the largest rated motor supplied by the circuit is starting.

Primary Overcurrent Protection Coordination for ph-ph faults on secondary (Dy) When grading through a Delta/Star transformer a phase-to-phase fault condition on the low voltage (Star) side (0.866 of the three phase fault value) produces the same magnitude of fault current in one phase on the high voltage (Delta) side (2-1-1 current distribution) as would a three phase low voltage fault condition. Hence, the settings calculated should 

ensure discrimination between the LV relays at 0.866 x LV three-phase fault current and HV relay at LV three-phase fault current.

5.4.2.5

Transformer Primary Overcurrent protection and Standby Earth fault protection on Secondary Standby Earth fault Protection should grade with the overcurrent protection on the primary (Delta) side of a transformer, because an earth fault on the secondary (Star) side would appear on the primary side as 1/3 p.u. fault current in two phases.

5.4.2.6

Earth fault protection settings The earth fault protection on each feeder must be set such that 

The minimum earth fault currents are detected and that co-ordination with the downstream devices is achieved.



Arcing faults are not considered in setting the earth fault relay. However, earth fault current settings are set well below minimum fault levels to allow for reduced fault currents.



Standby earth fault protection for 33kV system shall have two IDMT stages at least. The first stage shall coordinate with the incomer earth fault (partial differential) protection and the second stage shall be set sensitive (Pickup-25A approx, time delay-5s) to detect Transformer winding faults. .



The 11kV and 6.6kV systems in PDO are resistance earthed. Where a Neutral Earthing Resistor (NER) is used to limit the earth fault current to 300A. It is possible that an earth fault condition could cause a flashover of the NER and hence a dramatic increase in the earth fault current. For this reason, two stage Standby earth fault protection shall be applied: The first stage shall be set in the range of 5 to 15% of the NER current rating and definite time characteristics which co-ordinate with downstream earth fault protection. The second stage shall be set at 150% of NER current setting but with zero time delay, providing fast clearance of an earth fault which gives rise to an NER flashover.

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

Earth fault protection relay shall be connected through CBCT on the primary side of a delta-star transformer supplied from 6.6kV or 11kV switchgears. It shall be set in the range of 5 to 15% of the NER current rating. For vacuum contactor feeders, time delay of 0.1s shall be provided in order to provide better stability during inrush currents.



Where an earth fault relay is residually connected on the primary side of a delta-star transformer (e.g. on 33kV or 132kV system), earth fault protection should be set:- current pickup at 15% of transformer rated current, TMS as 0.1 and characteristics as standard inverse. Highset element should also be set same as overcurrent highset protection setting with inrush (2nd harmonic) blocking enabled.

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5.4.2.7

Fused contactors and Feeder protection For transformers controlled by fused contactors on primary side, instantaneous element shall be disabled to prevent attempted opening of the contactor beyond its breaking capacity.

5.4.2.8

Transformer (with 415V Secondary) Protection The overcurrent protection on the LV side shall be set to clear faults 

within 1s for a fault current of 50% of the minimum 3-phase short circuit current.

This is to take in to account the effect of fault arc resistance in limiting the magnitude of current. Instantaneous overcurrent protection in the LV incomer feeder shall be enabled and typically set at the 50% of the available phase fault current. Some of the switchgear vendors supply undervoltage release as a standard with the circuit breakers in the switchboard. The same shall be avoided (made dysfunctional, if provided) to prevent loss of 415V power supplies during a fault elsewhere in the system (due to ensuing undervoltage). 5.4.2.9

415V Standby earth fault protection The standby earth fault protection shall be in set in two stages. The first stage shall coordinate with 415V incomer earth fault protection or downstream fuses, if there is no 415V incomer earth fault protection. It shall be set IDMT characteristic to clear 

the earth fault current equal to 50% of the minimum prospective symmetrical three phase short circuit current in less than a second.

The second element of the standby earth fault protection shall be set as sensitive earth fault protection – 

Pickup

25A (approx)



Time delay

5s

(This is to ensure that the low current earth faults (which cannot cause the respective feeder fuses to blow) as well as the transformer winding faults are not left hanging on to the system for too long.) Both stages shall trip the 415V incomer as well as upstream HV breaker (if provided). 5.4.3

Directional Overcurrent / Earth fault Elements Directional relays shall be provided in transformer incomers intended to be working in parallel, such as transformer incomers to the 33kV Switchboard. This protection shall be back-up to the transformer differential / REF protection. In case there is no generation on the secondary of transformer, the pickup and TMS shall be set sensitive, as there is no coordination required. They shall be set at: Dir. overcurrent pickup-100% of the rated current, Characteristics-SI & TMS-0.1 Directional earth fault pickup-20% of the rated current, Characteristics-SI & TMS-0.1 In case there is generation on the secondary of transformer, the settings shall allow power flow towards primary. The relay shall be considered in the coordination studies, as necessary. RCA setting shall be as per the guidelines for directional settings at clause 5.1.3.

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For generator transformers, the directional overcurrent protection on HV side shall be set above the power drawn by the Generator auxiliary power supply system. This protection shall act as backup to the generator transformer differential protection 5.4.4

Transformer Biased Differential Protection The through-fault stability of the transformer differential protection is very critical. It must be ensured that CTs do not get saturated under heavy through-fault conditions. It is not enough to check the stability of the protection at the through-fault currents alone because such calculation does not consider DC offset, unfavourable core magnetisation of CT etc. Value of system X/R ratio reflects the possible DC offset. Relay manufacturer’s catalogue provides sufficient guidelines and safety factors for the above conditions and shall be used for establishing the through-fault stability of the protection. The protection shall be set to detect magnetic inrush (by way of 2nd harmonic current sensing or other means) and block the protection. The sensitivity of the relay shall be set to maximise the protection of the winding whilst maintaining stability for maximum (off-tap) through-fault conditions, taking into account CT mismatch and the possible permutation for CT saturation. The winding coverage obtained by this relay is typically 80% and is often much less when the transformer neutral point is earthed through a resistance. Zero sequence filtering shall be enabled in the relay for Y-connected sides of the transformer.

5.4.5

Transformer Restricted Earth fault Protection Relay manufacturers guidelines shall be followed for selecting the through-fault stability limit for restricted earth fault protection. It should be assumed that any earthing resistor could become short-circuited. The effective fault settings for transformer REF protection shall be between 10-60% of the rated current of the protected winding for solidly earthed systems. Pickup setting for REF protection shall not be more than 5% of the rated primary current of phase side CTs for resistance earthed system. Maximum resistance of associated stabilising resistor for high impedance type restricted earth fault protection shall be selected such that required setting is within 60% to 100% of maximum resistance. Otherwise it shall be proved by calculation that heat dissipation during normal operation and fault operation is within selected continuous and short time withstand limits. The maximum peak voltage developed across a current transformer secondary wiring shall not exceed 2.5kV under maximum internal fault conditions. If necessary, surge suppressors (non-linear resistors, also called metrosils) shall be provided to limit the voltage developed to 2.5kV peak or less.

5.4.6

OLTC-AVR OLTC-AVR for transformers shall be set as per the recommendation of the manufacturer. OLTC-AVR if provided for generator transformer shall be set taking care not to interfere with the Generator excitation AVR functioning. As a general rule, OLTC-AVR response shall be delayed so as not to respond on transient voltage dips. Dead band shall be set to prevent too frequent operations / hunting. Refer appendix-P for Typical settings of OLTC-AVR.

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GENERATOR / GENERATOR TRANSFORMER The generator protection should be set in accordance with the manufacturer’s recommendation and as per IEEE guidelines. The settings shall be critically reviewed from the power system point of view. This applies specifically to the protections like underfrequency, undervoltage and generator backup overcurrent / under impedance protection. The guidelines below as well as those under clause 3.5 above shall be followed for setting of various generator / generator transformer / unit auxiliary transformer protections.

5.5.1

Generator Differential Protection Generator differential protection (biased type) should have two bias settings, one for internal faults and another for external faults. The bias setting of 10 to 25% is considered satisfactory for providing stability against external faults. The bias setting for internal faults shall be chosen as low as possible in order to produce almost zero restraint condition for internal faults. The current setting shall be as sensitive as possible. Typically down to 5%. However the effective setting shall be worked out after taking into account CT magnetising currents.

5.5.2

Generator, Generator-Transformer Differential and HV Restricted Earth Fault The setting guidelines as per clause 5.4.4 and 5.4.5 are valid.

5.5.3

Generator-Transformer HV Overcurrent & Earth fault Protection: Directional overcurrent and earth fault protection (67/67N) shall be provided for faults looking towards generator transformer. Following settings should be adopted. Dir. overcurrent pickup-100% of the rated current, Characteristics-SI & TMS-0.1 Directional earth fault pickup-20% of the rated current, Characteristics-SI & TMS-0.1 In addition, if non-directional overcurrent protection (50/51) is also enabled, setting shall be based on rating of the generator transformer at expected minimum temperature at site during winter season. This is to cover higher output available from gas turbine during winter periods. Suitable setting may be decided in line with data sheets/curves for the generator transformer, generator and gas turbine.

5.5.4

Stator Earth fault Stator earth fault shall have two settings to maximise the coverage. The low set element should be set not higher than 5% and time delayed to prevent chances of mal-operations. The actual delay shall depend on manufacturer’s recommendations regarding withstand capabilities of the machine. The high set element should be set in the range of 10 to 15% with instantaneous operation. For generators connected to the 132kV grid through generator transformers with generator circuit breaker (GCB), two independent forms of earth fault protection are required. The scheme shall include 95% as well as 100% earth fault protection as described at clause 3.5.2.4 above.

5.5.5

Overfluxing In general the protective curve of the relay should be below the generator transformer / unit auxiliary transformer overfluxing capability curve. The setting should be able to detect at least 5% change in the nominal voltage to frequency ratio. The operating time may vary from 0.2s to several seconds depending on the design philosophy and AVR control, which shall be finalised in consultation with the generator/generator

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transformer supplier. In any case, the setting shall not be too sensitive to cause undesirable operation of the protection. 5.5.6

Overvoltage The voltage setting shall be adjustable between 100% and 120% of the phase-tophase nominal voltage with a time delay adjustable between 1 and 3s, in order to avoid tripping due to transient overvoltages. Instantaneous overvoltage protection for voltages beyond above limits (say set at 150%) shall be as per manufacturer’s recommendations.

5.5.7

Loss of Excitation When the operation of mho relay is accompanied by operation of undervoltage relays, then the generator shall be shut down completely. However if there is no operation of the undervoltage relay then the tripping shall be time delayed. This time delay shall depend on the ability of the control system to restore the excitation.

5.5.8

Reverse Power / Low Forward Power The reverse power or low forward power protection is mainly provided to protect the turbine against pitting during failure of prime mover. Hence the requirements of this protection shall be worked out in consultation with turbine supplier. Package unit supplier shall define clearly the threshold reverse power level, which will not cause any damage to the system in general and turbine blades in particular. The reverse power element (relay) shall be able to detect and operate under these threshold levels. Also refer clause 3.5.2.7 above.

5.5.9

Negative Phase Sequence The basis for the setting of the negative phase sequence element shall be the negative sequence current withstand characteristic of the generator. The current pickup settings shall be selected to allow the generator to operate within its permissible continuous negative sequence current. The operating time characteristic shall be selected to match the generator’s short time withstand characteristic for operation under fault conditions. Stage 1 (Alarm) shall have an adjustable setting to match the generator continuous negative phase sequence current withstand capability and shall include an adjustable definite time delay or fixed time delay of not less than 3s.Stage 2 (Trip) shall have an adjustable thermal characteristic capable of being set to match the generator short time negative phase sequence current withstand capability based on (I2)2t characteristic. It shall be possible to set the Stage 2 to pickup at a negative phase sequence current equal to the generator continuous withstand capability while still closely matching the generator (I2)2t capability.

5.5.10

Underfrequency and Overfrequency The setting of the underfrequency trip shall not be over 47.5Hz to allow the underfrequency based load shedding (in the power system) maximum time to act. The setting shall also ensure the tripping of the generator circuit breaker before the turbine under speed level is reached. It shall avoid turbine trip and keep the generator running so that the generator can be put back on line as soon as system conditions allow. The overfrequency element shall be used as back up to governor speed control equipment. Overfrequency trip shall be setting shall not be less than 51.5Hz.

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Backup Overcurrent Protection (51V) The voltage controlled overcurrent mode should be selected for generators, which are directly connected to the switchboard without generator transformer. For generators connected to 33kV switchboard through generator transformers, the voltage restrained overcurrent protection should be provided. The voltage setting for characteristic changeover shall be set below the voltage reduction, which may occur due to a single phase-to-earth fault. At the same time, the voltage setting shall be set above the minimum voltage that may occur during a remote three-phase fault. This protection is meant to provide backup for any uncleared system faults. Hence the setting of this protection shall be time graded with the downstream overcurrent protection.

5.5.12

Under Impedance Protection (21G/21GT) The 21G protection shall be set to operate at approximately 70% of the rated generator transformer impedance after allowing for short time overloads and minimum operating voltage under normal conditions. The 21GT protection shall be set to 120% of impedance of longest 132kV overhead line from substation. It shall be ensured that 21GT setting is not more than 70% of the load impedance. Time delay for 21GT setting shall be coordinated with time delay for zone-3 protection of the 132kV overhead lines from substation.

5.6

LV GENERATORS For the larger generators fitted with fast acting automatic voltage regulators voltage is generally held to an acceptable level under the conditions of an external fault. This enables operation of normal overcurrent relays. However it is not valid for all LV generators. Hence voltage controlled element is used to switch the relay operating characteristic when the generator voltage drops due to a heavy external fault. The setting chosen shall be such that the switched characteristic provides proper sensitivity and grading under reduced voltage condition.

5.7

BUSBAR PROTECTION For high impedance busbar differential protection, the through-fault stability limit shall be not less than the switchgear short circuit rating. It should be assumed that any earthing resistor could become short-circuited. The effective fault setting for the high impedance busbar differential protection shall be between 10 and 30% of the minimum fault current available, unless otherwise agreed by PDO. The sensitivity of this protection shall be established after considering all future feeders for which substation is designed for. Maximum resistance of associated stabilising resistor for high impedance type busbar protection shall be selected such that required setting is within 60% to 100% of maximum resistance. Otherwise it shall be proved by calculation that heat dissipation during normal operation and fault operation is within selected continuous and short time withstand limits. The maximum peak voltage developed over the current transformer secondary wiring shall not exceed 2.5kVp under maximum internal fault conditions. If necessary, surge suppressors (non-linear resistors, also called metrosils) shall be installed to limit the voltage.

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Busbar protection trip logic shall include busbar trip in case of generator transformer feeder BF protection operation. In case of breaker-and-half scheme substations, the busbar trip scheme shall include BF protection of main bay breakers connected to the respective busbars. Intertrips related to BF protection shall lockout the remote breakers too. In case of busbar trip, the remote ends also shall be locked out, considering the busbar protection operation could be due to a fault between breaker and CT or due to BF protection operation (breaker-and-half scheme).

5.8

MOTOR PROTECTION

5.8.1

Fuses for Motor Protection Fuse links intended for motor circuit protection must be able to withstand the starting current of the motor and carry the normal full-load current continuously without deterioration. Fuse-links shall be selected in accordance with the fuse link manufacturer’s recommendations, taking into consideration the number of starts per hour, the voltage rating of the motor, the run-up time of the motor and the starting current of the motor and the coordination between fuse and contactor. The current rating of fuse link however, must not be less than 

5.8.2

1.25 times the rated current of the motor.

Motor Protection Relay Numerical Motor protection relays use thermal imaging methods to protect the motor against thermal overloads. The setting criteria may differ from manufacturer to manufacturer depending on the thermal-imaging algorithm used by them. However the setting chosen must ensure that the relay trip time for thermal overload is always less than the motor thermal withstand time at respective current for both hot as well as cold conditions. When setting thermal overload elements it shall be ensured that the motor temperature does not rise beyond class B insulation limits even though the motors are provided with class-F insulation. For protections not detailed below, clause 3.8 above shall be referred. Undervoltage protection settings for motors shall be as indicated at clause 5.11 below

5.8.2.1

Short Circuit Protection (50) settings In case of motors connected to circuit breakers, short circuit protection shall be provided. Protection settings shall be 

125% of the motor starting current (lock rotor current) with 0.1s time delay



250% of the motor starting current (lock rotor current) without any time delay (instantaneous setting)

The motor starting current (especially in case of unit transformer connected motors) shall be at the expected motor terminal voltage during starting. Short circuit protection shall be disabled for motors connected to HV contactors. Shortcircuit protection for these feeders is provided by fuse.

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Earth fault Protection (51G) settings In case of motors connected to 6.6kV /11kV system, earth fault current is limited by NER. The earth fault protection for the motors is provided by CBCT operated earth fault element or by earth fault element connected to the transformer neutral in case of motors with unit transformer. The setting of this element shall be 

in the range of 5 to 15% of the NER current rating

Residually connected earth fault element, shall not be set too sensitive (less than 15% of the motor rated current) to prevent mal-operation during motor starting. Time delay of 0.1s shall be provided in order to provide better stability. For unit transformer connected motors, earth fault current is limited to 20A by NER and hence time delay of 1s should be provided for better stability. 5.8.2.3

Thermal Overload protection (49) settings Typically, the thermal overload element pickup shall be 

105% of the motor rated current.

Thermal protection shall be coordinated with the motor characteristic up to a load of 150% rated only. ‘Thermal protection inhibit during start’ feature shall be enabled in the motor protection relay as this allows better coordination of thermal protection with the motor thermal withstand capability at near the motor rated current (and as there is a separate protection for prolonged start condition).. 5.8.2.4

Prolonged Start & Stall Protection (51S/LR) settings Most of the modern Motor protection relays include separate protection for prolonged start and stall conditions. The current magnitude during motor start can be different from that during stall condition, especially in case of motors with assisted start (e.g. Reactor-start). The pickup for each of the elements shall be selected as 

Average of 105% of motor rated current and the motor starting current at the expected terminal voltage.

Time delay shall be selected providing a margin of 

2s minimum from the motor data for hot start and stall withstand capability.

To be realistic, the starting and stall withstand times appropriate for the expected motor terminal voltage shall be considered. The start detection criteria shall be 

5.8.2.5

(circuit breaker status contact + the current drawn by motor, both criteria have to be present).

Negative phase sequence protection (46) settings Negative phase sequence currents do most harm when the condition occurs during motor start. Typically, first stage setting shall be 

Pickup equal to 30% of motor full load current.



Time Delay shall be 1s to ensure stability against external faults

The negative phase sequence currents during running are generally factored in to the thermal overload protection and hence second stage protection may not be required. However, if it is not factored in to the thermal overload protection element, relay shall have a second stage negative phase sequence protection element, which can be set Page 81

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either with inverse characteristic to coordinate with the motor negative sequence characteristic or with higher definite time delay at low pickup setting. 5.8.2.6

Neutral voltage displacement protection (59N) settings This protection is applicable for unit transformer connected motors due to high resistance earthing, setting shall be 

in the range of 5 to 15% of the phase to neutral voltage



time delay shall be 1s to ensure stability against external faults

5.8.2.7

Out-of-step protection (78) for Synchronous motors Settings of out-of-step protection shall be as per the relay manufacturer’s guidelines.

5.8.2.8

Loss of Excitation protection (40) for Synchronous motors Out-of-step protection as above will not be able to detect partial loss of excitation conditions. Hence, Loss of excitation protection shall also be enabled in the motor protection relay. This shall be set in the same lines as that for generators. Settings of other parameters shall be as per the relay manufacturer’s guidelines.

5.8.2.9

Overvoltage protection (59) for Synchronous motors Overvoltage protection shall be provided for alarm purpose only. Tripping of motor is not preferred on overvoltage protection. However, if motor manufacturer recommends tripping of motor on overvoltage, it shall not be set up to 110% of rated voltage.

5.8.2.10 Additional requirements for Vital Service / Fire-safety related drives These drives shall be allowed to operate to destruction if required for safety of the plant / personnel. Hence, Motor protection settings for Fire water pumps and other drives related to fire safety shall conform to NFPA. Vital service / Fire pump motor protection trip shall be limited to locked rotor and short circuit protection only. Overload protection, undervoltage protection and earth fault protection shall be wired only for alarm. There shall be no timers to prevent repeated start/stops. 

Motor circuit fuses, in case of fuse-backed contactor feeders shall be sized to hold o

600% of the full-load current rating of the motor for at least

o

100s.



5.8.3

Locked rotor protection pickup shall be set at a minimum of o

300% of motor full load current and

o

tripping time between 8s and 20s.

Motors driven by VSDs When VSDs are used, most protective functions are programmed into VSD. The VSD is controlled from process control room. The VSDs shall include transient voltage dip ride-through feature so as to avoid tripping of VSD during faults elsewhere in the system. Protections shall comply with DEP 33.66.05.33-Gen, DEP Drawing S67.057 and IEEE C37.96. 

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The power supply feeder breaker to VSD will not see the motor starting current and hence the protection need not be coordinated for the motor starting currents.

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

The current for any fault downstream of VSD is limited by the VSD generally. Hence, it is adequate if the feeder protection is set to protect for faults in the cable feeder.



Protection of the cable feeder shall be set meeting the recommendation of the VSD vendor.

Typical protection scheme for 25MW rated VSD-Motor feeder is indicated at Fig. 5.6.

5.9

UNDERFREQUENCY LOAD SHEDDING & START INHIBITION Settings of a load shedding scheme such as number of stages, amount of load being shed in each stage, minimum frequencies are specified in the document ‘Load Shedding Plan’ approved by CFDH-E. This plan may be revised after addition / deletion of any major load or generation in the PDO system. The load shedding in PDO is, in general, based on four stages of underfrequency. Rate of change of frequency, undervoltage sensing for Load shedding may be adopted in some areas on case-to-case basis. The settings are often accompanied by a minimum time delay of 0.3s, to prevent operation during temporary oscillations and the delay itself could be in-built in the relay sampling scheme, depending on the relay type/design. Load shedding study is conducted periodically in PDO and the recommended settings for different areas adopted in PR-1168 as per the study recommendation. The load shedding setting schedules are maintained separately (distinct from protection setting schedules) for each of the areas.

5.10

SYNCHRONISING The requirements for settings of synchronising check relay (25CH) shall be as follows. 

The acceptable frequency difference (f) which should range from 0.01Hz to 0.2Hz



The acceptable phase angle difference () which may range from 5° – 15° (higher in case of 132kV OHLs)



The acceptable voltage difference (v), which should be between 0.5% – 10%.

The time for which the voltage locus of both systems should remain within the set points may be set between 0.5s and 5s typically. 5.10.1

33/11/6.6kV switchboards For breakers for which operator is certain that sources on both sides are already paralleled at a higher voltage level, the settings could be

5.10.2



v should be 2.5%. This is to prevent closing of a (33/11/6.6kV) bus section breaker when two transformers are at different taps.



The lower time setting of 0.5s is acceptable.

Generators / Generator transformer feeders at Power Stations The more stringent conditions from the above ranges should be applicable for critical links such as 132kV generators / generator transformer feeders and lines linking two separate power systems / islands, which may involve major load swings under unfavourable conditions. For such links, the setting of 

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f should be 0.05Hz or 0.1%

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 should be 10°,



V should be 5%.

Revision: 4.0 Effective: Oct. 16

The operation of the relay shall be enabled only under live line and live bus condition. The relay shall not give permissive signal under dead bus or dead line conditions. In addition to above settings, exact breaker operating time shall also be provided to match the instant of closing. 5.10.3

132kV OHLs For 132kV OHLs, the settings shall be 

f should be 0.05Hz or 0.1% (in terms of timer setting, 2s for 40° phase angle difference)



 should be 35°, this allows a window of -35° to +35°



V should be 10%.

If the OHL is interconnecting two separate power systems / islands, then the settings as in Clause 5.10.2 shall be applied.

5.11

VOLTAGE RELAYS The main purpose of undervoltage protection in PDO network is to trip motor feeders in case of sustained undervoltage or no voltage conditions.

5.11.1

6.6kV / 11kV Induction Motors For the 6.6kV / 11kV motors, the voltage setting of 75% of system nominal voltage and time delay of 2s should be provided in the motor protection relay. In case of unit transformer connected motors, undervoltage protection shall be inhibited during motor starting, as the design starting voltage is allowed to be less than 80% rated.

5.11.2

Synchronous motor Synchronous motors can be stable even at lower voltages and for longer duration. In case of synchronous motors, undervoltage protection shall preferably be with inverse characteristic and set to coordinate with the motor voltage stability curve, with sufficient margins. Typically, the undervoltage pickup shall not be greater than 60% rated. In case definite time characteristic is used, the setting shall be 60% and time delay shall be 3s or as recommended by motor manufacturer. Typical Voltage stability characteristic curve for Synchronous motors is included at Appendix-E for reference.

5.11.3

Voltage Relays for Automatic Bus Transfer Scheme Undervoltage protection relays with incomer feeders of a switchboard shall be set at 75% in order to trip the incomer feeder. Time delay for the incomer undervoltage relays shall be 3s for the upstream 6.6kV or 11kV switchboards and 4 to 5 seconds for the downstream 415V switchboards. Healthy condition of the bus shall be determined by more than 90% voltage for 2s.

5.11.4

Protection Relays with voltage input All protection relays with the voltage input shall be set for undervoltage, overvoltage, underfrequency and overfrequency protection in order to trigger the disturbance records. These shall be typically set at 20% deviation for voltage and 5% deviation for

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frequency from the nominal value. The disturbance record may typically be set for 5s duration or as long as possible in a given relay model.

5.12

THERMAL PROTECTION OF TRANSFORMERS As per IEC 60076-2, the final temperature limits for oil and winding are 100°C/105°C respectively. Hence,

5.13



The Alarm stage-1 and stage-2 settings for Oil Temperature shall be 90/100°C.



The settings for Winding Temperature Alarm stage-1 and stage-2 should be 95/105°C.

DISTURBANCE RECORDER SETTINGS Typical Disturbance recorder settings shall be 

Pre-fault – 0.5s,



Post-fault – 1.5s,



“Trigger & Save on Pickup” for switchboard incomers / OHLs / Interconnectors etc. This includes unit transformer protection in case of unit transformer – motor feeders. This is to have a backup record for a downstream feeder fault)



“Trigger on Pickup and Save on Trip” for motor feeders.

The disturbance recorder shall be enabled for all electrical trips. In case trigger on pickup is not available and the trigger takes place only on trip, the pre-fault (pre-trigger) duration shall be maximised to capture the waveforms during the fault event. The waveform record after the CB is open is not much of significance and, can be limited to  5.13.1

100ms (typical).

Electromechanical etc. relays in the substaion The trip outputs of Electromechanical / static relays such as MCAG/MFAC/7VH and any other relays without DR facility shall be wired to the numerical relays in one of the feeders to trigger the DR for the purpose of recording the data.

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Protection and Control Logic Diagrams One drawing for each type of feeder shall be prepared and submitted for approval. This shall form the basis for preparation of circuit diagrams for the relay and control panel and switchgear panels.

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Numerical Relays, Representation of Details Numerical relays offer great advantage over conventional relays in terms of flexibility. Unlike conventional relays, the contacts, input signals, operating logic of various protection and auxiliary functions can be software programmed in the form of binary coded mask settings, programmable logic diagrams, special relay settings etc. The intent of this clause is to demarcate between these software settings and identify proper documents under which they shall be represented.

7.1

SCOPE OF WORK ENGINEERING)

DURING

DETAILED

DESIGN

(PANEL

Fig. 8.2 shows a typical example of Programmable Logic / Masking for Numeric relays to be carried out by detailed design consultant / panel manufacturer. For numerical relays, the programming of input and output signals shall be carried out by the detail design consultant / relay panel manufacturer. Any change of the functions assigned to these input and output signals may have to be accompanied by external wiring changes. Hence all the assigned digital Input/Output signals to the relays shall be clearly marked in the relay and control panel drawing along with its required binary code or any other form of input instruction needed for programming the input/output signals. Any spare Input/Output signals shall be clearly marked so that if needed, these signals can be programmed at site during commissioning by commissioning engineer. Such programming shall be reflected in the as-built drawings of the relay and control panel. The programmable logic is functionally an extension of or an improvement over hardware logic wired with selection of various auxiliary relays. Hence all such logic programming shall also be represented in the relay and control panel drawings as specified above. In general, any relay programming carried out to meet the requirements specified under relevant clauses from section 3, ‘Specific Protection Requirements’ will have to be programmed during the relay panel manufacturing process and will have to be represented in the drawing of the relay and control panels. The soft copies of the above files and the relay setting/software tool shall be sent in a CD (in duplicate) to the client along with the panels. The updated relay files shall be stored in PDO’s Electrical Protection System Database on commissioning of the project.

7.2

SCOPE OF WORK DURING PROTECTION SETTINGS In general the relay setting documents shall represent various parameter settings, changes of which in no way affect the wiring of relays to other components. In addition, relay setting document shall list all the available protection and auxiliary functions of the relay and whether these functions are enabled or disabled. Whenever multiple setting groups are used during the relay setting exercise, the settings of both groups shall be clearly represented in the relay setting documents along with the conditions of switchovers. Wherever alternate group settings are not used, the unused groups shall be specifically disabled or if cannot be disabled, a note shall be included to say that all groups to be set identical to the selected protection group.

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If needed for activation of setting group any internal or external logic shall be clearly marked along with the relay setting document. Such logic shall be incorporated at site during commissioning and shall be transferred to the relay and control panel drawing as a part of the as-built drawing. The schedules shall also include menu/configuration settings, I/O mapping details, Programmable Logic diagrams / details (such as PSL, CFC) etc. for the numerical relays. Relay vendors, in general, recommend to use default logic (PSL logic or CFC logic or other relay manufacturer’s logic) provided with the relays. This shall be kept in mind while modifying the default logic for a specific project. The vendor-sent soft copies of the relay setting/configuration files for the project shall be received by the protection consultant from PDO and updated once the protection study is approved. The updated soft files of the relays shall also be submitted to PDO (in addition to the studies / schedules) for storage in Electrical Protection System Database. The as-built relay setting schedules and the relay setting/configuration/logic files shall be sent by Site team to PDO after the feeder is commissioned, for updating Electrical Protection System Database.

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Indicating lamps Indicating lamps shall be supplied from the substation battery. At unattended substations a switch shall be provided on the bus section control/relay panel, so that all indicating lamps can be switched off, if so desired. Lamp fittings shall allow for adequate ventilation, and in the event of a failure, allow for easy removal and replacement of the lamp without the use of special tools. Lamp test facilities shall be provided so that all lamps on one panel can be tested simultaneously by operation of a common switch.

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Alarm schemes The alarms being provided by the contractor shall be indicated in the protection and control logic diagram specified in clause 6. Alarms shall operate a common buzzer. The alarm scheme shall operate from the station battery. Means shall be provided for silencing audible alarms whilst leaving the buzzer free to sound if any other alarm circuit is energised. Alarm indicating lamps shall remain on until cancelled by resetting the devices initiating the alarms and the operation of a separate cancellation key. A common facia for each circuit shall be provided and mounted on the associated panel. Common alarm facia shall be of the multi-window type (preferably with individually replaceable windows) with individual alarms operated from self seal-in relays and indicated by flashing illumination of an inscribed transparent window. Operation of the common accept-key shall cause the light to become steady and silence the audible alarm. A lamp test push button shall be provided for each facia. Each facia shall include at least two spare windows for possible future use. A selector switch shall be provided on the bus-section control/relay panel labelled Attended / Unattended. With the switch selected to Unattended, the alarm indications and buzzer shall be de-energised such that there will be no drain on the substation battery. Operation of the switch shall not affect the sending of the alarm to the Control Centre. Where applicable, contractors shall provide potential-free auxiliary switches, contacts or auxiliary relays on equipment to initiate alarm signals for transmission by SCADA to the Control Centre. Some of these alarm contacts will be paralleled in the SCADA marshalling cubicle to transmit only a common alarm to the SCADA equipment from a group of alarm contacts, others will be connected to the SCADA equipment independently. Details of the alarms to be initiated and transmitted are listed on the SCADA Input/Output Schedules for each substation. Means shall be provided to delay the receipt of nuisance alarms both at the alarm facia and over the SCADA system, e.g., alarms, which would otherwise be received for a transient dip in system voltage.

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Definitions

10.1

GENERAL

Revision: 4.0 Effective: Oct. 16

For the purposes of this SP the following definitions shall be used. Shall - The word 'shall' is to be understood as mandatory. Should - The word 'should' is to be understood as strongly recommended. May - The word 'may' is to be understood as indicating a possible course of action. The Company - Petroleum Development of Oman LLC of Muscat, Sultanate of Oman. User - A specialist engineer, Consultant or Contractor who applies this Standard. Consultant - A party to a Contract with the Company who is responsible for providing design, engineering and other related consultancy services under a Contract. Contractor - A party to a Contract with the Company who is responsible for construction and other related Works specified in a Contract. On occasion, for example in 'turnkey' contracts, a Contractor may be responsible for the duties of both Consultant and Contractor. Manufacturer - A party responsible for the manufacture of equipment or material to perform the duties specified by the Company. Vendor/Supplier - A party responsible for the supply of equipment, materials or product-related services in accordance with a Purchase Order issued by PDO or its nominated Purchasing Office.

10.2

TECHNICAL Teleprotection - A means whereby a protection command is transmitted to a remote location. Buchholz Relay - A device for detecting accumulation of gas or sudden oil surges within an oil-immersed transformer or reactor tank. Restricted Earth Fault - A protection scheme for detection of earth faults on a specific item of plant. Discriminating Zone - A protection scheme for detection of faults within a defined area of plant (usually busbars). Numerical Protection Relay - A relay in where the analogue input signals are converted to digital form and sampled before being proceeded by the micro-processor.

10.3

ABBREVIATIONS A - Ampere AC - Alternating Current ARC – Automatic Recloser AVC - Automatic Voltage Controller AVR - Automatic Voltage Regulator BF Protection – Breaker Fail Protection CB – Circuit Breaker CBCT – Core Balance Current Transformer

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CFDH-E – Corporate Functional Discipline Head - Electrical CT - Current Transformer CVT - Capacitor Voltage Transformer DC - Direct Current DB - Distribution Board DEF – Directional Earth fault element (in Distance relay) DEP - Design and Engineering Practice (SIPM) DIgSILENT – DIgSILENT software for power system studies ERD – Engineering Reference Document (PDO) GSUT – Generator Step-Up Transformer HRC - High Rupturing Capacity HV - High Voltage IDMTL – Inverse Definite Minimum Time Lag IEC - International Electrotechnical Commission IED – Intelligent Electronic Device (a general term that includes numerical relays) IEEE/ANSI – Institute of Electrical and Electronics Engineers / American National Standards Institute km - kilometres kV - kiloVolt kVA / MVA - kiloVolt Ampere / Million Volt Ampere kW / MW – kilo Watt / Mega Watt MVAR – Mega Volt Ampere Reactive VAr / kVAr – Volt Ampere Reactive / Kilo Volt Ampere Reactive LCD – Liquid Crystal Display LED – Light Emitting Diode LSIG - Overload, Short-circuit with Delayed Trip, Instantaneous Short-circuit and Ground-fault (circuit breaker trip functions) LV - Low Voltage MCB – Miniature Circuit Breaker MCCB – Moulded Case Circuit Breaker MFM - Multifunction Meter ms – millisecond NET – Neutral Earthing Transformer NER – Neutral Earthing Resistor OCB – Outdoor Circuit Breaker OHL – Overhead Line OLTC – On-Load Tap Changer PDO - Petroleum Development Oman LLC Page 92

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Petroleum Development Oman LLC PMR – Pole Mounted Recloser PR – Procedures (PDO) PT – Potential Transformer REF – Restricted Earth fault protection s – second SCADA – Supervisory Control And Data Acquisition SIEP - Shell International Exploration & Production SIOP - Shell International Oil Products SIPM - Shell Internationale Petroleum Maatschappij BV SOTF – Switch On To Fault logic SP - Specification (PDO) SSS – Synchronising Selection Scheme / Synchronising Selection Switch TOR – Trip On Reclose UAT – Unit Auxiliary Transformer VSD – Variable Speed Drive VSS – Voltage Selection Scheme / Voltage Selector Switch VT - Voltage Transformer VTS – Voltage Transformer Supervision

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Petroleum Development Oman LLC APPENDIX A: CHECK LIST OF INFORMATION TO BE PROTECTION ASSESSMENT

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PROVIDED TO PDO FOR THE PURPOSE OF

FAULT CURRENT CALCULATIONS / REPORT 

Fault current calculation to establish fault currents seen by the relays and switchgear under various operating scenarios.

Or 

The DIgSILENT outputs providing the above information based on PDO approved DIgSILENT model.

RELAY SETTINGS CALCULATIONS       

  

Relay Setting Schedule Setting Calculation Sheets / Basis document Extract of Fuse Manufacturers Application Guidelines (for Transformers and Motors) Protection Grading Curves Extract of Relay Manufacturers CT requirements Calculation Showing Compliance with Relay Manufacturers' CT Requirements Approved copies of Key Single Line Diagram and Protection Single Line Diagram containing all the information as per SP2047 shall be submitted. From the following details, any data, which is not represented in single line diagram, shall be provided separately. Relay soft files as finalised during FAT and associated relay setting/configuration software tool PSL/CFC diagrams in hard as well as soft copies Stabilising Resistor & Metrosil details (high impedance current differential protection)

CT DATA    

Ratio, Accuracy Class, Rated Output, Accuracy Limit Factor Magnetisation Curve CT secondary winding resistance CT secondary lead length, conductor size

VT DATA VT Ratio, VT Accuracy Class, VT Rated Output MOTOR DATA          Page 94

Rated Voltage, Full Load Current, and kW, Efficiency, Power Factor, No-load current Locked Rotor Current and withstand time motor "hot". (Both at 80% and 100% volts for switchboard connected motors and at design terminal voltage for unit transformer connected motors) Starting time (at 80% and 100% volts for switchboard connected motors and at design terminal voltage for unit transformer connected motors) Starting current, motor terminal voltage and time in case of reactor start (or any other assisted start) motors Allowed number of starts/hour from both hot and cold Thermal Damage Curve, Heating and Cooling Time constants Negative phase sequence current withstand characteristic Undervoltage vs Stability characteristic (Synchronous motors) Recommendation for ‘Loss of load’ protection (Submerged pump drives) SP-1107 Specification for Electrical Protection Systems

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Speed switch /sensor provided or not. Details including settings of the sensor shall be provided. Excitation panel details including settings for various protection modules in excitation panel such as rotor earth fault protection, diode failure protection (Synchronous motors) NET/NER calculation (Unit Transformer motors) Motor-Capacitor sizing calculation (for induction motors, if provided)

TRANSFORMER DATA    

     

Voltage Ratio, MVA Rating, Vector Group, Impedance volts, X/R value (or Resistance and Reactance) Tapping Range, step; AVR – setting recommendation Through-Fault Current Withstand Zero sequence impedance (in case of Earthing (Zig zag) auxiliary transformers, additionally zero sequence impedance of zigzag winding for faults in the EAT primary side and zero sequence impedance of EAT for faults in EAT secondary side) Transformer inrush current Transformer winding capacitance NER details (for transformer with 6.6kV or 11kV secondary) Neutral as well as Phase CT details Primary fuse sizing calculation / rating details Overfluxing withstand capability curve (for Generator / Unit auxiliary transformer)

OVERHEAD LINE AND CABLE / BUSDUCT DATA      

33kV OHL layout indicating the OHL lengths to tap-off point Resistance /km Reactance /km Susceptance  siemens/km Short Circuit Withstand (Conductor and Armour) Thermal Overload capability curve

GENERATOR DATA         

MW / MVAR Capability chart showing base and peak load operation. Voltage Rating Reactance (Xd, Xd', Xd'') Time Constants (T'do, T''do) Negative sequence current / voltage withstand curve Generator fault current decrement curve Generator 3rd harmonic voltage vs speed curve Generator winding capacitance NET/NER sizing calculation and details

SWITCHGEAR DATA      Page 95

Voltage Rating, Maximum Continuous Current Rating, Short Circuit Rating and Time, CT/VT details as listed above Short Circuit Breaking Capacity of Contactors and back-up fuse rating/basis Fault Making Capacity Operating (Close / Open) Time of Switchgear Protection modules type, with literature and software copy (OHL PMRs / outdoor CBs) SP-1107 Specification for Electrical Protection Systems

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APPENDIX B: ANSI / IEC SYMBOLS The IEEE/ANSI C37.2 uses numbering system for various functions, supplemented by letters where amplification of the subject function is required. IEC 60617 uses graphical symbols. The table below lists frequently used ANSI device numbers and the equivalent graphical symbols vide IEC. FUNCTIONS

ANSI

Arc flash Detector

AFD

Automatic Tap Change Control Auto-reclose

79

Other Common Designations

IEC 61850 SARC

Overtemperature

26

PTTR

˥>

Overvoltage

59

PTOV

V>

Phase Angle

78

Phase Comparison

87P

Broken Conductor

46BC

PTOC

I2/I1>

Busbar Differential

87B

PDIF

Idiff>

Circuit Breaker

52

XCBR

CB

52a

XCBR

52b 89

XCBR XSWI

CC

Cold Load PickUp

51CLP

Current Transformer Supervision 16

Digital Fault Recorder

DFR

Phase-Balance (eg. 46 Negative Phasor Data Concentrator PDC Sequence) Current Phasor Measurement Unit PMU Pilot-Wire or Carrier 85 Communications Point-on-Wave Switching

CLP RVCS

Data Communications Device

(1>

DAR PSB, OST, OOS BFP

Closing Coil

12

AVR

RPSB RBRF

CLK

Overspeed

CTS

RDRE, RADR, RBDR

> PDIF PTOC

I2>

PSCH CPOW

POW

Pole Dead (Circuit Breaker Open) Positive Sequence 47 Undervoltage Power Factor (Over) 55O

PTUV

Power Factor (Under)

55U

Power Quality Monitor Push Button

PQM PB

PTUV

V1<

POPF

PF>, cos >

PUPF

PF<, cos <

QFVR, QITR, QIUB, PQ QVTR, QVUB, QVVR

Directional Earth Fault Overcurrent Directional Over Power

67N 32O

PTOC PDOP

IN>, t>, DEF P>

Directional Overcurrent

67P

PTOC

I>

Rate of Change of 81R Frequency Remote Terminal Unit / RTU Data Restricted Earth Fault 87N Concentrator (Biased) Restricted Earth Fault (High 87N Imp.) Reverse Power 32R

Directional Under Power

32U

PDUP

P<

Rotor Earth Fault

64R

PEFI

Distance

21

PDIS

Z

Rotor Thermal Overload

49R

PTTR

Distance Aided Schemes

21/85

PSCH

Router

16ER

Disturbance Recorder

DDR

RDRE, RADR, RBDR

DR

Dynamic Line Rating

49DLR

PTTR

DLR

Earth Fault Overcurrent

51N

PTOC

IN>

Ethernet Switch

16ES

Fault Locator

21FL

RFLO

Fuse Fail Overcurrent

51FF

PTOC

Generator Differential

87G

PDIF

Delta Directional Comparison

High Impedance Earth Fault Detection Human Machine Interface

f1I / f1V

HIZ HMI

PHIZ IHMI

Instantaneous Overcurrent

50

PTOC

Interlocked Overcurrent Busbar Protection InterlockingScheme

51BB 3

PTOC CILO

Interturn Fault

50

PDIF

Line Differential

87L

PDIF

Page 96

Other Common Designations

IEC 61850

RREC

68 50BF

Clock or Timing Source

ANSI

ATCC

Blocking (eg. Power Swing Blocking) or “out-of-step” Breaker Failure

Circuit Breaker Closed Auxiliary Contacts Circuit Breaker Open Auxiliary Contacts Circuit Switch

FUNCTIONS

DTF

Idiff> Hi-Z I>

Sensitive Directional Earth 67SEF Fault Sequence of Events SER Overcurrent Recorder Switch on to Fault SOTF

df/dt

PDIF

Idiff>, REF

PDIF

Idiff>, REF

PDOP

PTOC

Isef> SOE

PSOF

Stator Earth Fault

64S

100% Stator Earth Fault 3rd harmonic Stator Thermal Overload undervoltage, 3rd Stub Bus Protection harmonic overvoltage, low frequency injection Substation Metering

27TN, 59TN, 49S 64S 50ST MET

MMTR, MMXU

Synchronism Check

25

RSYN

CS

Thermal Device (eg. RTD, 26 thermistor) Thermal Overload 49

PTTR PTTR

RTD

Through Fault Monitoring Thru

MMXU

TF

Time Delay Idiff>

PFRC

Time Overcurrent IDMT)

PTOC

PTTR PTUV/PTOV/PEFI PTOC

2 (eg. 51

SP-1107 Specification for Electrical Protection Systems

t>, TD PTOC

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Petroleum Development Oman LLC

FUNCTIONS

ANSI

Load Restoration

81R

Lockout Relay

86

Loss of Field / Under Excitation Loss of Life

Other Common Designations

IEC 61850

FUNCTIONS

ANSI

PTOF

Transformer Differential

40

PDUP

Transformer Inrush 68 Detection Transient Earth Fault

LoL

MMTR

Motor Differential

87M

PDIF

Motor Emergency Restart

66/86

Motor Locked Rotor

51LR

PMRI/PMSS

Turbine Frequency Undercurrent

Motor Number of Starts

66

PMRI/PMSS

Underfrequency

Motor Reacceleration Authorisation

27LV

Motor Restart Inhibition

49, 66

PMRI

Motor Starting Time Supervision

48, 51LR, 49R

PMRI/PMSS

Negative Sequence Overvoltage

47

PTOV

Motor Anti-Backspin

Negative Phase Sequence Thermal

46T

Idiff>

Tripping Relay

V2>

94 Abnormal 81AB

PDIF

PTEF

PTRC PTAF

37

PTUC

I<

81U

PTUF

f<

Underspeed or Zero Speed 14 Device

PZSU

(1<

Undervoltage

PTUV

V<

27

Unintentional Energisation 50/27 (Dead Machine Protection) Voltage Balance 60 Voltage Overcurrent

Dependent 51V

PDMP PTOV PVOC PVPH

PTOV

VN>

Voltage Supervision

RVCS

78

PPAM

OST, OOS

Voltage Vector Shift

81O

PTOF

f>

Wattmetric Earth Fault

Out of Step Trip (Pole Slip) Overfrequency

TGF TCS

Volts per Hertz Overfluxing 24

59N

Idiff>

PHAR

YN

Neutral Displacement Voltage (Residual Overvoltage)

Page 97

ABS

Trip Circuit Monitor / TCM Supervision Trip Coil TC

PTTR

Neutral Admittance

87T

Other Common Designations

IEC 61850

Transformer VTS

64W

SP-1107 Specification for Electrical Protection Systems

V/Hz

PVSP

f1V

PSDE

PN>

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APPENDIX C: GENERATOR/GSUT/UAT TRIP MATRIX (INCLUDES PROTECTION ALARMS) – TYPICAL The trip matrix as below mainly addresses protections of Generator/GSUT/UAT island with GCB (Standard Drawing STD 4 6504 004). This is typical and shall be applied for all grid connected generators after making suitable changes. Mechanical / Turbine protections also trip the generator; however, these are not included hereunder and need to be covered as appropriate. Lockout is not indicated but is required. Multiple trip/lockout relays as required shall be provided. LEGEND for Class of Shutdown A

Normal shutdown type-1 : Trip GCB, Trip Excitation, GT/ST Running Normal shutdown type-2 : Unload GT, Trip GCB, Trip Excitation, Trip GT/ST via Turbine Control System ( GT/ST Shuts down) Emergency shutdown type-1 : Trip GCB, Trip Excitation, Trip GT/ST via Turbine Control System ( GT/ST Shuts down)

B C D

Emergency shutdown type-2 : Trip GCB, Trip Excitation, Trip GT/ST via Turbine Control System ( GT/ST Shuts down), Trip 132kV CB(s), Trip 6.6kV incomer

E

Trip 132kV Bus Circuit Breaker(s) Only

F

Trip GCB only

G

Trip 132kV Bus Tie Circuit Breaker(s) only

H

Trip 6.6kV incomer circuit breakers only Class of Shutdown

CAUSE

A

B

C

D

E

F

G

H

Protection Device No.

















87G

















59N

















51G

















64R-1

















64R-2

















26G-1

















26G-2

















64S

















59GN/27TH

















5

















40G

















27/40

Page 98

Description Generator Differential Operated Generator stator earth fault (residual overvoltage) relay operated (0 to 95%) Generator stator earth fault current relay operated (0 to 95%) Generator rotor earth fault relay first stage operated (<80kohm) Generator rotor earth fault relay second stage operated( <5kohm) Generator Fire Detector temperature high Stage 1 ( 80deg C) - (Alarm) Generator Fire detector temperature high Stage 2 ( 100deg C) - CO2 Release Generator stator earth fault (low frequency injection) protection operated (95 to 100%) Generator stator earth fault (third harmonic based) protection operated (95 to 100%) – Alarm Only Emergency stop push button operated Loss of excitation relay operated together with 27/40 relay operated and protection PT fuse healthy 40G relay operated together with 27/40 rly not operated, protection PT

SP-1107 Specification for Electrical Protection Systems

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H

CAUSE

G

F

E

D

C

B

A

Class of Shutdown Protection Device No.

















46G-1

















46G-2

















51V

















78G

















24GT-1

















24GT-2

















50/27G

















27G-1

















27G-2

















81U-1/81O-1



81U-2/81O-2

















59G-1

















59G-2

















32R-1

















32R-2

















50LBB

















21GT

















51.1G











59BN

















60.2G

















60.4G

















60.5G

Page 99

Description fuse healthy and with time delay Negative sequence current relay stage-1 operated (Alarm) Negative sequence current relay stage-2 operated Voltage dependent Overcurrent relay with Inverse Characteristics for directly connected generators Pole slipping relay operated GSUT Overfluxing protection relay stage-1 operated ("Reduce Excitation" command to AVR) GSUT Overfluxing protection relay stage-2 operated (Not to operate lockout relay for GCB) Inadvertent Energisation (Dead machine) protection operated Undervoltage relay operated - Stage 1 (Prompt Operator for GSUT-OLTC operation) Undervoltage relay operated together with PT fuse healthy - Stage 2 (Not to operate lockout relay for GCB) Underfrequency/Overfrequency relay stage-1 operated (Prompt Operator for Load Management) Underfrequency/Overfrequency relay stage-2 operated (Not to operate lockout relay for GCB) Generator overvoltage relay stage1 operated (Alarm) Generator overvoltage relay stage2 operated (Not to operate lockout relay for GCB) Reverse power relay stage-1 operated (Not to operate lockout relay for GCB) Reverse power relay stage-2 operated (Not to operate lockout relay for GCB) Generator Circuit Breaker fail protection operated Generator Backup impedance relay operated together with PT fuse healthy ( 132kV side) Overcurrent protection relay operated (Prompt Operator for Load Management) 11kV bus earth fault relay operated AVR PT1 fuse failure (AVR Transfer from Auto/1 to Auto/2) AVR PT2 fuse failure (AVR transfer from Auto/2 to Auto/1) Metering PT fuse failure (Alarm)

SP-1107 Specification for Electrical Protection Systems

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Revision: 4.0 Effective: Oct. 16

Petroleum Development Oman LLC Class of Shutdown

CAUSE

A

B

C

D

E

F

G

H

Protection Device No.

















58

















58

















60.1G

















60.3G

















FFR

















87GT

















87N(GT)

















51G(GT)

















51/51N(GT)

















67/67N(GT)

















21G

















50BF1

















50BF2































 

 

 

 

 

 

 

 

87T 87N(LV)

















51G(LV)

















50, 51, 51N































































Page 100

86T

Description Exciter Diode Failure (Open ckt) (Alarm) Exciter Diode Failure (Short ckt) (Alarm) Protection PT1 fuse failure - (Block voltage dependent protection) Protection PT2 fuse failure - (Block voltage dependent protection) Synchronisation PT fuse failure (Block Synchronisation) Generator transformer differential relay operated Generator transformer HV REF protection operated Generator transformer HV standby earth fault protection operated Generator transformer non-directional overcurrent and earth fault relay operated ( 132kV side) Generator transformer directional overcurrent and earth fault relay operated ( 132kV side) Generator backup impedance protection. Operated ( 11kV Side) 132kV Bus Circuit Breaker Fail - Also to respective 132kV B/B trip 132kV Tie Circuit Breaker Fail - Also to respective main breakers trip Generator transformer 49(OT)A-1&2, 49(WT)A-1&2, 63(B)A, 63(TCB)A, 71(LO)A (Alarm) Generator transformer 63(B)T, 63(TCB)T, 63(PR)T MVUAT diff. Protection operated MVUAT LV REF Protection operated MVUAT LV Standby Earth fault protection operated MVUAT Non-directional overcurrent, & earth fault protection operated (primary side) MVUAT 63(B)T, 63(TCB)T, 63PRV(T) MVUAT 49(OT)A-1&2, 49(WT)A-1&2, 63(B)A, 63(TCB)A, 71(LO)A (Alarm) 6.6kV MVUAS switchboard incomer master trip relay operated IPS trip

SP-1107 Specification for Electrical Protection Systems

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Petroleum Development Oman LLC APPENDIX D: TRIP MATRIX - TRANSFORMER FEEDER (TYPICAL) LEGEND A Open Transformer HV CB1 B Open Transformer LV CB C Open LV Bus section CB D Close Block-HV CB (Operate Lockout Relay2) E Close Block –LV CB (Operate Lockout Relay) F Close Block –LV Bus section CB (Operate Lockout Relay)

B

C

D

E

F

Cause

A

Effect / Action item Protection Device No.













87T

























87N (LV)













87B













63(B)T, 63(TCB)T, 63PRV(T)5













50/50N/51/51N (HV)

























51G (LV-SBEF) – Stage1 & Stage2













51/51N (LV)

Description Transformer Operated

Differential

Protection

Transformer LV-REF Protection Operated 132kV Bus Differential Protection operated (Note4) Main Transformer mounted protection operated6 Transformer HV overcurrent / earth fault protection operated HV bus section CB opening (Note7) Transformer LV Standby earth fault protection – Stage1 & Stage2 operated8 Transformer LV incomer overcurrent / earth fault protection operated

1

In case of 132kV CB with two trip coils, each of the protections shall be wired to both the trip coils. 2 One no. trip/lockout relay for each trip coil. However, each trip/lockout relay at 132kV shall also operate both the trip coils of 132kV circuit breaker as well as LV CB. 3 It shall not be possible to close LVCB when HVCB is open. 4 When 87L relay is provided due to long cable/OHL, signal to trip LV CB, shall be sent through Direct Inter Trip (DIT) over protection communication channel in the 87L and shall be without any additional delay. 5

If micro switch is used instead of mercury switch for oil and winding temperature indicators, stage-2 of these alarms should be connected for breaker trip as well as for lockout relay 6 Transformer mounted protections are wired to trip / lockout relays through Interposing relays. Direct trip from the interposing relays to the CB can be wired in parallel with contact of 86 relay so that trip coil is not opened by contacts of the interposing relays. 7 LV Bus section breaker shall open whenever HV bus section breaker opens but only after verifying that all the three LV breakers (two incomers & bus section breaker) are in closed position and after a time delay of 500ms. 8 Whenever LV incomer earth fault protection (or partial differential earth fault protection) is available and coordinated with LV standby earth fault protection. In such case. LV standby earth fault protection (both stage-1 and stage-2) need not operate lockout relay (86) in the LV incomer or bus section feeders. Page 101

SP-1107 Specification for Electrical Protection Systems

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Petroleum Development Oman LLC

B

C

D

E

F

Cause

A

Effect / Action item Protection Device No.













51-PD/51N-PD (LV) Partial Diff connection













67/67N (LV)













87L(HV) or 87L(LV)













Description Transformer LV incomer Partial Diff connected overcurrent / earth fault protection operated Transformer LV Dir overcurrent & earth fault protection operated Line differential protection Operated (If applicable) 415V incomer neutral overcurrent protection (for Transformer 33kV side DO fuse fail)

Note: In case of Breaker-and-half scheme substations, feeder trip means trip of respective main CB as well as the tie breaker (the only exception being in case of busbar trip). For BF protection, 132kV OHL trip matrix shall apply, except that the remote breaker corresponds to Transformer secondary breaker.

1

Through respective local relay (87L)

Page 102

SP-1107 Specification for Electrical Protection Systems

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Petroleum Development Oman LLC APPENDIX E: TRIP MATRIX - 132KV OHL FEEDER (TYPICAL) LEGEND A Open Local 132kV CB B Open Remote 132kV CB C Open Bus section / Buscoupler CB D Close Block-Local 132kV CB (Operate Lockout Relay1) E Close Block –Remote 132kV CB (Operate Lockout Relay1) F Close Block –Bus section / Bus coupler CB (Operate Lockout Relay) Cause

F

E

D

C

B

A

Effect / Action item Protection Device No.

Description

Line Differential Trip, Zone-1 Trip, Distance protection Aided Trip, DEF Aided trip ( Note3) Zone-2, Zone-3, Zone-4, SOTF, TOR, Z2, Z3, Z4, SOTF, , Auto-reclose Lockout protection       TOR, , 79-Lockout operated Directional Overcurrent, Non-aided 67, 67N       Directional Earth fault (Note4) 49 Thermal Overload Protection (Note5)       87B Busbar Protection Trip Note6       Busbar Protection Trip signal from Remote end busbar protection 87B (Remote)       (received through protection communication channel)Note7 50BF (Main bay Main bay BF Trip (in case of Breaker      CB) and-half scheme). Note8 Tie bay BF Trip (in case of Breaker50BF (Tie bay CB)       and-half scheme).(Note9) Note: In case of Breaker-and-half scheme substations, feeder trip means trip of respective main CB as well as the tie breaker (the only exception being in case of busbar trip). 











87L, Z1, 21-Aided Trip, DEF-Aided Trip

1

One no. trip/lockout relay for each trip coil. However, each trip/lockout relay at 132kV shall operate both the trip coils of 132kV CB 2

Tripping of remote end shall be carried out through direct inter-tripping on indicated protections, only when remote end is identified as weak source. Protection scheme shall be prepared accordingly during detailed engineering. 3

87L, Z1, 21-Aided Trip and DEF Aided Trip protection shall also initiate auto-reclose.

4

Only applicable for existing overhead lines where both main-1 and main-2 protection relays are not available. They shall be disabled where both main-1 and main-2 protection relays available. 5

For overhead lines where both main-1 and main-2 protection relays are available.

6

Remote end CB shall be tripped and locked out through Direct Intertrip function in Main-1 & Main-2 Relays. Tie bay CB & Remote end CB opening is not required in case of breaker-andhalf configuration switchyards 7

Received through Direct Intertrip function in Main-1 & Main-2 Relays. Not applicable, when remote station has breaker and half configuration switchyard. 8

In case of main bay CB fail protection, trip & lockout of tie bay CB & remote CB and triggering the respective busbar trip is required 9

In case of tie bay CB fail protection, trip & lockout of both main bay CB on either side of the subject Tie bay CB and remote end CB is required. Page 103

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Petroleum Development Oman LLC APPENDIX F: TRIP MATRIX - 33KV OHL/CABLE FEEDER (TYPICAL) LEGEND A Open Local 33kV CB B Open Remote 33kV CB C Open Bus section CB D Close Block-Local 33kV CB (Operate Lockout Relay) E Close Block –Remote 33kV CB (Operate Lockout Relay) F Close Block –Bus section CB (Operate Lockout Relay) Cause



















51-PD/51N-PD Partial Diff connection













87L













21













81U

E



D



C



51/51N/51G or 67/67N/67G

B

Protection Device No.

A

F

Effect / Action item

Description Directional / Non-directional Overcurrent / Earth fault / CBCT connected earth fault protection operated (as applicable) Incomer Partial Differential connected Overcurrent / Earth fault protection operated (as applicable) Line differential protection (as applicable) Distance protection (as applicable) Load shedding scheme trip (From Relay in Bus section panel in case of Switchboard connected feeders)

1

Subject to specified reclose cycles for each protection element. Refer SP1107 for AutoReclose scheme (79) requirements. 2

Through respective local relay (87L)

Page 104

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Petroleum Development Oman LLC APPENDIX G: TRIP MATRIX - HV MOTOR PROTECTION (TYPICAL) LEGEND A Open Motor CB B Open Incomer/Bus section (Upstream) CBs C Close Block-Motor CB (Operate Lockout Relay) D Close Block –Incomer/Bus section (Upstream) CBs (Operate Lockout Relay) E Thermal Close Block Motor CB (Self Reset Type) Effect / Action item

A

B

C

D

E

Cause















 



















Page 105

  



Protection Device No. 87M MPR (50/51/51G/46/49/48/5 1LR)



MPR (49/66)



MPR(27)



81U

Description Motor Differential Protection Operated (if applicable) Motor Protection – Electrical/Non-Electrical Faults Motor Protection – Thermal Lockout / No. of Starts / Restart Inhibit Motor Undervoltage Protection (if applicable) Load shedding scheme trip (From Relay in Bus section panel in case of Switchboard connected feeders)

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Petroleum Development Oman LLC APPENDIX H: TRIP MATRIX - HV UNIT TRAFO - MOTOR PROTECTION (TYPICAL) LEGEND A Open Transformer HV CB B Open Transformer LV CB (Motor CB) C Close Block-Transformer CB (Operate Lockout Relay1) D Close Block –Motor CB (Operate Lockout Relay) E Thermal Close Block Motor CB (Self Reset Type)

C





















































  

 

 













E

B

 

Cause Protection Device No.

Description



87T

Transformer Differential Protection Operated (as applicable)



, 63(B)T, 63(TCB)T, 63PRV(T)



50/50N/51/51N (HV)



51G (LV-SBEF)



87M



87T/M



MPR - 50/51 /4648//49/51LR)



MPR (59N)



MPR (49/66)

  

 

87L(HV) or 87L(LV)



MPR (40 / 64R / 58 / 78 / 59)





MPR (81U)

D

A

Effect / Action item         

MPR (27)

Transformer mounted protections operated Transformer HV Overcurrent / Earth fault protection operated Transformer LV Standby Earth fault protection operated Motor Differential Protection Operated (as applicable) Transformer - Motor Differential Protection Operated (as applicable) Motor Protection Relay Operated – Electrical / NonElectrical Faults Motor Protection Relay Operated – Neutral Voltage Based Earth Fault Motor Protection – Thermal Lockout/ No. of Starts / Restart Inhibit Motor Undervoltage Protection Operated Line differential protection Operated (as applicable) Loss of Excitation / Rotor earth fault / Diode Failure / Out-of-step / Overvoltage protection (For Synchronous Motors) Operated Load shedding scheme trip

1

One no. trip/lockout relay for each trip coil. However, each protection and trip/lockout relay shall operate both the trip coils. 2

It shall not be possible to close LVCB when HVCB is open.

3

Through respective local relay (87L)

Page 106

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APPENDIX I: TECHNICAL DIFFERENCES BETWEEN MVAA RELAYS AND PRIMA RELAYS (Typical, for information only)

Sl. No 1 2

3 4

5

Item Description Continuous Voltage Withstand rating Operating Time

Maximum number of output contacts possible Standard contact type Breaking capacity Mechanical environment Vibration (IEC 255-21-1: 1988)

Page 107

MVAA Relays

PRIMA Relays

120% of its max. voltage rating continuously. 12-25ms depending on the number of contacts and relay type. 8

110% of its max. voltage rating continuously. 25ms for dc operated relays.

50W (inductive) with maxima of 5A and 300V.

30W (inductive) at 100V.

Response class 2

Response class 1

4

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APPENDIX J: EXPULSION FUSE LINKS CURRENT-TIME CHARACTERISTIC CURVES (Typical, for information only) Reference: ANSI C37-42 / IEC 60282-2

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APPENDIX K: SYNCHRONOUS MOTORS – TYPICAL VOLTAGE – TIME STABILITY CHARACTERISTIC (Typical, for information only)

Page 110

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Petroleum Development Oman LLC APPENDIX L: ELM CONDUCTOR – THERMAL OVERLOAD CHARACTERISTIC (TYPICAL)

Short term thermal overloads for single conductor Elm conductors 100% pre fault loading

90% pre fault loading

70% pre fault loading

35% pre fault loading

0% pre fault loading

transfer limit of the Hubara - Sayala OHL

200% 190%

Allowable percentage overload

180% 170% 160% 150% 140% 130% 120% 110% 100% 3

8

13

18

Minutes - Post fault

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APPENDIX M: MOTOR PROTECTION RELAY – PROGRAMMABLE SCHEME LOGIC (Typical, for information only)

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Appendix P: Typical Setting for Voltage Regulator with Transformer OLTC For the settings of Voltage Regulator with transformer’s On Load Tap Changer (OLTC), typical settings of Voltage Regulator TAPCON 230 with MR Make OLTC, are provided as below: Parameter AVR ID Activation T2 Active Desired Volt. Level Analog Val. Tap Pos Max Analog Val. Tap Pos Min Analog Val. Volt.Lev. Max Analog Val. Volt.Level Min App. Confirm Timeout Bandwidth Baud Rate Baud Rate Communication Blocking Overcurr. I> Blocking Overvolt. U> Blocking Undercurr. I< Blocking Undervolt. U< Blocking lower Tap Blocking upper Tap CAN Address CT Terminal Characteristics T1 Circ. Current Blocking Circ. Current Sensitivity Compensation Method Communication Port Communication Protocol Delay Parallel Failure Delay Time T1 Delay Time T2 Delay Time U< Desired Voltage Level 1 Desired Voltage Level 2 Desired Voltage Level 3 Display % / A Display Dimming Display kV / V Foll. Tapping w/o Umeas Follower Tapping Direction Function Monitoring GPI 1 - X4:13 GPI 2 - X4:14 GPI 3 - X4:15 GPI 4 - X4:16 GPI 5 - X4:17 GPI 6 - X4:18 GPI 7 - X6:1 GPI 8 - X6:2 GPO 1 - X4:9 Page 113

Unit % % % % s % % % s s s s kV kV kV -

Value 0004 T2 on DVL 1 100,0 0,0 100,0 0,0 5 1,50 9.6 kBaud 9.6 kBaud Off Off Off On 0 40 0 Unknown T1 integral 20,0 0,0 LDC RS232 Modbus RTU 10 180 10,0 10,0 33,00 33,00 33,00 % On kV Off Standard Off Off Off Off Quick Tap DVL 2 DVL 3 ParGroup1 ParGroup2 Off

Min 0 0 0 0 1 0,5 -128 -128 0 0,5 0 1 0 1 0 14,70 14,70 14,70 -

Max 100 100 100 100 60 9 128 128 16 40 100 99 600 10 20 42,00 42,00 42,00 -

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Petroleum Development Oman LLC Parameter GPO 2 - X4:12 GPO 3 - X5:9 GPO 4 - X5:12 GPO 5 - X5:18 GPO 6 - X5:21 GPO 7 - X5:24 IP address Key Lock LED 1 LED 2 LED 3 green LED 3 yellow LED 4 red LED 4 yellow Language Line Drop Compensation Ur Line Drop Compensation Ux Local / Remote Local SCADA Address Manual / Auto Master/Foll. Curr. Block. Max. Tap Difference Meas.Transformer Circuit Motor Runtime Neg. Act. Pow. Block. Normset Activation Operation Counter Optical Fibre Light On/Off Overcurrent I> [%] Overvoltage U> [%] Parallel Control Enable Parallel Operation Method Paralleling Group Primary Current Primary Voltage Pulse Time RS485 Trans. Delay Time Remote Volt. Level Setting SCADA Master Address Secondary Voltage Stand-alone Blocking TCP Port Tap Pos Limit Block Mode Tap Position Lower Value Tap Position Upper Value Tap pos. indication U< Below 30V Undercurrent I< [%] Undervoltage U< [%] Unsolicited Retries Page 114

Unit V V s % % A kV s ms V % % -

Value Off ParState ParError Undervolt. Overvolt. Overcurr. 0.0.0.0 On Circ.current Bandwidth < Bandwidth > Off Off Off English 0,0 0,0 Remote 0 Auto Blocking 1 0 1PH 10,0 Off Off 0 Off 110 105 On Circ.current None 0 33,0 1,5 5 Off 0 110,0 On 1234 Off 1 17 BCD On 0 70 3

Min 0.0.0.0 -25 -25 0 1 0 0 50 100 0 0 0 0 0 57 0 -40 -40 0 60 0

Max 255.255.255.255 25 25 9999 4 30 99999999 210 140 10000 999,9 10 254 9999 123 32767 40 40 210 100 100

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Petroleum Development Oman LLC Parameter Unsolicited messages Voltage Level Lower Val. Voltage Level Upper Val. Z - Comp. Limit Z - Comp. Volt Rise

Page 115

Unit V V % %

Value Off 80,0 140,0 0,0 0,0

Min 0 0 0 0

Max 140 140 15 15

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Petroleum Development Oman LLC APPENDIX Q: TYPICAL PROTECTION SETTINGS FOR CAPACITOR BANKS

For the protection settings of capacitor banks, typical settings of capacitor protection relay RLC04 (Make - Strike Technologies) are provided as below: SETTING RANGE PROTECTION DUTY STAGE OVERLOAD PROTECTION (TRUE RMS ) Overload ALARM setting Overload TRIP setting Irms>/In 0.25 to 1.50 Irms>: xt 0.1 to 1200s Irms>> / In 0.2 to 10.0 Irms>>: xt 0.03 to 10s STAGE UNBALANCE PROTECTION

STEP

0.1s 0.03s

SETTINGS 115% of the stage nominal current 125% of the stage nominal current Overload ALARM setting 30s Overload TRIP setting 5s

Unbalance ALARM setting

Average of unbalance currents due to 2nd and 3rd fuse failure

Unbalance TRIP setting

Average of unbalance currents due to 3rd and 4th fuse failure

Iub_al / In 0.01 to 2 Unbalance ALARM Setting Iub_al : xt 0.1 to 600s 0.1s 1s Iub > / In 0.01 to 2.0 Unbalance TRIP Setting Iub > : xt 0.1 to 14400s 0.1s 0.5s STAGE OVERCURRENT (FUNDAMENTAL) PROTECTION Overcurrent LOW SET TRIP setting 125% of the stage nominal current Overcurrent HIGH SET TRIP setting 200% of the stage nominal current I1>/In 0.25 to 1.50 Overcurrent Low Set Trip Setting I1>: xt 0.1 to 1200s 0.1s 5s I1>> / In 0.2 to 10.0 Overcurrent High Set Trip Setting I1>>: xt 0.05 to 10s 0.05s 1s STAGE EARTH FAULT CURRENT PROTECTION Under Current TRIP setting 20% of the stage nominal current Io>/In 0.05 to 1 Under current Trip Setting Io>: xt 0.1 to 60s 0.1s 0.2s STAGE UNDER CURRENT PROTECTION Under Current TRIP setting 70% of the stage nominal current I1/In 0.01 to 1 Low Set Trip Ilub> xt 0.1 to 60s 0.1s 2s Ilub >> / In 0.01 to 1 High Set Trip Ilub >> xt 0.05 to 10s 0.05s 0.5s REPETITIVE PEAK OVERVOLTAGE PROTECTION Icr / In 100% Capacitor Rated Current / CT Ratio Vc>/ Vcr 0.80 to 1.50 1.1 Vc >> / Vcr 0.80 to 10.0 2.0 Vc >> xt 0.03 to 10.0s 0.03s 0.03s Vc > reset : xt 1s to 3600s 1s 30s

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Petroleum Development Oman LLC APPENDIX R: TYPICAL SETTINGS CAPACITOR BANKS

FOR

AUTOMATIC POWER FACTOR CONTROLLER (APFC)

WITH

For the settings of Automatic Power Factor Controller (APFC) with capacitor banks, typical settings of BLR-Q(U) (Make - BELUK) are provided as below: FUNCTION CT factor VT factor Nominal Voltage (L-L) Connection measurement Synchronization frequency Phase Compensation V-tolerance min V-tolerance min Countdown Start Al Temperature offset CT type 1A Discharge Time Step type Fast Max. Step Value Cos phi 1 Cos phi 2 Switch interval Switch Interval step exchange Asymmetry factor Step recognition Switch Cycle Balancing Switch Cycle Balancing % Step Exchange Control Sensitivity Control Q Offset I < limit freeze steps Q Cap. Steps turn off Fast Meas. Delay Alarm Control Alarm No Current Alarm Step Fault Alarm Step Warning Alarm Power Factor Time Delay Alarm Harmonics U Alarm Harmonics I Alarm Overload P Alarm Overload Q Limit Overload Q Alarm P- Export Limit temperature 1 Limit temperature 2 DI Input Alarm Frequency Alarm Modbus Baudrate Modbus Parity Modbus Address Storage Interval Synchronisation DI Input Setup DI Input

Page 117

SETTING RANGE 1 - 6500 1 – 350 100 – 35000V L-N, L-L Auto., 50Hz, 60Hz 0-345Degree 2-90% 2-30% Yes / No -10 to 10 Degree Yes / No 0.1 – 1200s Normal, fix on, fix off 0 – 9999.9kVAR 0.6i – 1 – 0.7c 0.6i – 1 – 0.7c 0.5 – 1200s 0.5 – 1200s -127 to +127 On/Off Yes / No 1 – 15% Yes / No 55 – 100% Auto/LIFO/Progressive filterfilter / Combi -+3200kVar Yes / No Yes / No 0 – 900 Periods Disabled, M, DO, D Disabled, M, DO, D Disabled, M, DO, D Disabled, M, DO, D Disabled, M, DO, D 1S – 36000S Disabled, M, DO, D Disabled, M, DO, D Disabled, M, DO, D Disabled, M, DO, D 1 … 99999.9kVar Disabled, M, DO, D Disabled, M, DO, D Disabled, M, DO, D Disabled, M, DO, D Disabled, M, DO, D 1200 - 38400 8E1, 8̊1, 8N2 1 - 247 0 – 720min On/Off High/Low

STEPS

15Degree

SP-1107 Specification for Electrical Protection Systems

SETTING As per site As per site As per site L-L 50Hz 000 + 90 Degree -10% +10% Yes 0Degree No 600s Normal 0kVAR i.95 c.99 600s 2s 1 Off Yes 10% No 55% Auto 0kVar No No 50 Periods M Disabled Disabled Disabled Disabled 300S Disabled Disabled Disabled Disabled 1kVar Disabled Disabled Disabled Disabled Disabled 9600 8E1 1 0min Off High

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