SESCo eTender Notices System - Sarawak Energy

SUPPLY, DELIVERY, INSTALLATION, TESTING AND COMMISSIONING OF MAIN 2 CURRENT DIFFERENTIAL PROTECTION RELAYS FOR OHL 1 & 2 LINKING KEMANTAN AND SARIKEI 132KV SUBSTATIONS

(TENDER REF. NO.: TPCI/T/01/22)

TENDER NOTICE

Suitably qualified tenderers are invited for the SUPPLY, DELIVERY, INSTALLATION, TESTING AND COMMISSIONING OF MAIN 2 CURRENT DIFFERENTIAL PROTECTION RELAYS FOR OHL 1 & 2 LINKING KEMANTAN AND SARIKEI 132KV SUBSTATIONS stated as follows:

Tender Reference No. Title Eligibility

TPCI/T/01/22

SUPPLY, DELIVERY, INSTALLATION, TESTING AND COMMISSIONING OF MAIN 2 CURRENT DIFFERENTIAL PROTECTION RELAYS FOR OHL 1 & 2 LINKING KEMANTAN AND SARIKEI 132KV SUBSTATIONS

UPKJ Works: Electrical Works Class: I Heads: VIIB SUB-HEAD 4a

Instruction to Tenderers:

Mandatory Requirement Tenderers shall possess adequate financial capability and experience as follows:

1. MUST BE REGISTERED WITH UPKJ (WORKS: ELECTRICAL WORKS, CLASS: I; HEADS: VIIB; SUB-HEAD 4A) *Interested tenderers are required to produce evidence of fulfilling above-mentioned mandatory requirement. Failing

which, your intention will be rejected.

General Instructions

1. This tender exercise will be conducted on an online Ariba platform. The entire event will be managed by SEPRO (Sarawak Energy e-Procurement) Team. Tender details are available for viewing at https://etender.sarawakenergy.com/etender/notice/notice.jsp

2. Please note that all Tenderers are required to register in SEPRO to participate in this tender. If your company is not registered in SEPRO, please allow ample time to complete registration. Vendors can self-register to SEPRO via the URL provided: http://bit.ly/register2SEPRO. The registration is free of charge.

3. Interested Tenderer that meets the eligibility is required to do the following steps: A) Email your interest to participate for this tender exercise to [email protected]. Please

include the following details:

• Tender Reference:

• Tender Title:

• Company Contact Person:

• Company Name:

• Phone Number:

• Email Address:

• (Attach all softcopy of evidence for mandatory requirement)

https://etender.sarawakenergy.com/etender/notice/notice.jsp

http://bit.ly/register2SEPRO

mailto:[email protected]

4. Tender documents can only be accessible to the Tenderer after registration. A) SEPRO team will acknowledge receipt upon receiving your email on interest to participate. If you have

any inquiries on SEPRO please contact us at the following channel:

• Email: [email protected]

• Phone: 082-330127

Monday to Thursday : 9.00am – 1.00pm and 2.00pm – 4.00pm

Friday : 9.00am – 11.30am and 2.30pm – 4.00pm

Note: Sarawak Energy Berhad is not liable for any cost incurred by the Tenderer in preparing the tenders.

Tender submission shall be submitted online through SEPRO system no later than 3:00 p.m. (Malaysia Local Time) on the date specified

below.

Tender Reference Number Closing Date Closing Time

TPCI/T/01/22 Wednesday, 23rd March 2022 3:00 PM

All enquiries regarding the Tender should be addressed to:

Transmission Protection, Control, and Instrumentation (TPCI) Sarawak Energy Berhad, Level 5, Menara Sarawak Energy No.1, The Isthmus 93050 Kuching, Sarawak. Attention: Ir. Ling Lee Eng Designation: Senior Manager II Tel. No.: +6 082 – 388 388 (8524) Fax No.: +6 082 – 344054 Email: [email protected] Lau Li Chuan Designation: Electrical Engineer Tel. No.: +6019-8111247 Email: [email protected] Chia Min Piau Designation: Technical Executive Tel. No.: +6019-8596342 Email: [email protected]


SUPPLY, DELIVERY, INSTALLATION, TESTING AND COMMISSIONING

OF MAIN 2 CURRENT DIFFERENTIAL PROTECTION RELAYS FOR OHL

1 & 2 LINKING KEMANTAN AND SARIKEI 132KV SUBSTATIONS

TENDER DOCUMENTS: SARAWAK ENERGY REF. NO. TPCI/T/01/22

PART I – TENDER PROCEDURES






SECTION 1 – INTRODUCTION

This Introduction should be read in conjunction with Tender Appendix A [Scope of Works /

Specifications] set out in Part II, Section 2 of the Tender Documents.

Part I, Section 1 – Introduction

Tender for Supply, Delivery, Installation, Testing and Commissioning of Main 2 Current Differential Protection

Relays for OHL 1 and 2 Linking Kemantan and Sarikei 132kV Substations. (Sarawak Energy Ref. No.

TPCI/T/01/22) 1

INTRODUCTION

Purpose The purpose of this tender process is to procure Tender Offers from contractors to perform all Works required in connection with Supply, Delivery, Installation, Testing and Commissioning of Main 2 Current Differential Protection Relays for OHL 1 and 2 Linking Kemantan and Sarikei 132kV Substations.

Background Sarawak Energy is wholly owned by the State Government of Sarawak and is responsible for the generation, transmission, and distribution of electricity to industrial and residential customers within Sarawak.

Sarawak Energy has a proud history of more than 70 years of service to the Sarawak community and now provides electricity to more than 500,000 account holders. In recent years, Sarawak Energy has made strong progress on an exciting transformation journey, focused on harnessing the State’s abundant energy resources in hydropower, natural gas and coal to create new opportunities for the Sarawak community. With firm plans for further rapid growth, Sarawak Energy is on track to become the leading producer of renewable energy in Southeast Asia.

By supporting the State Government’s Sarawak Corridor of Renewable Energy or SCORE program, Sarawak Energy is helping our community reach the goal of becoming a high-income State by 2020.

Commercial basis for tender offers Tender Offers shall be submitted in accordance with the requirements set out in the Tender Documents.

The Conditions of Contract are based upon Sarawak Energy’s standard terms and supported by Contract Appendices that collectively set out and describe Sarawak Energy’s requirements for the Works.

The Contract Price shall be in lump sum price.




TPCI/T/01/22) 2

SCOPE OF WORKS / SPECIFICATIONS

The Works to be performed by the Contractor include the following:

CONTENTS

1 GENERAL REQUIREMENT 5

2 SCOPE OF WORK 6

2.1 KEMANTAN 275/132/33KV SUBSTATION 6

2.2 SARIKEI 132/33KV SUBSTATION 8

2.3 RELAY SETTINGS & SCHEME TESTS BY CAPE SIMULATION 10

2.4 DOCUMENTATION 10

3 PROTECTION SYSTEM 11

3.1 GENERAL 11

3.2 RELAYS 13

3.3 PROTECTION SCHEME 14

3.4 TRANSMISSION LINE PROTECTION 14

3.4.1 GENERAL 14

3.4.2 LINE DISTANCE PROTECTION 17

3.4.3 LINE DIFFERENTIAL PROTECTION 20

3.4.4 AUTO-RECLOSING SCHEME 22

3.4.5 TRIPPING RELAY 24

3.4.6 TRIP CIRCUIT SUPERVISION 24

3.4.7 RELAY SETTINGS 25

3.4.8 ENGINEERING DESIGN DRAWING 27

3.4.9 CURRENT TRANSFORMER CALCULATIONS 27

4 ASSOCIATED WORK AND INTERFACE 28

4.1 ARRANGEMENT OF FACILITIES 28




TPCI/T/01/22) 3

4.2 CONTROL SWITCHES AND PUSHBUTTONS 28

4.3 MINIATURE CIRCUIT BREAKERS, FUSE AND LINKS 28

4.4 PANEL WIRING 29

4.5 ALARMS 30

5 INSTALLATION, TESTING & COMMISSIONING 32

5.1 GENERAL 32

5.2 TESTING SCHEDULE AND PROCEDURES 33

5.3 SITE ACCEPTANCE TESTING (SAT) PROCESS FLOWCHAT 34

5.3.1 MULTICORE CABLE TERMINATION CHECK AND TESTS 34

5.3.2 COMPONENT LEVEL TESTING FOR SECONDARY EQUIPMENT 35

5.3.3 PROTECTION SCHEME TESTING, INCLUDING CORRECT SCHEME

OPERATION, STABILITY AND TRIP TESTS. 38

5.4 PRE-COMMISSIONING INSPECTION (PCXI) 39

5.4.1 DOCUMENTATION REVIEW 39

5.4.2 DRAWING ACCURACY 39

5.4.3 SETTINGS 40

5.4.4 SITE ACCEPTANCE TEST RECORDS 40

5.4.5 DEFECTS 40

5.4.6 SPARES AND SPECIAL TOOLS 40

5.4.7 CUBICLE INSPECTION 40

5.4.8 SETTINGS CHECK 41

5.5 END TO END TESTS 41

5.6 ON-LOAD TESTS 42

6 LOCAL TECHNICAL SUPPORT 44

7 PAYMENT TERMS 44

8 PROJECT COMPLETION 44




TPCI/T/01/22) 4

9 APPENDIX 45

9.1 ACCEPTED RELAY LIST 45

9.2 TRANSIENT NETWORK ANALYSER TEST PLAN 45

9.3 PROTECTION RELAY TEST REQUIREMENT 45




TPCI/T/01/22) 5

1 GENERAL REQUIREMENT

I. The Contractor shall provide at minimum, one reference from the project cited as related experience to show the competence of the erecting organization to undertake installation, testing and commissioning of protection relay in EHV substation together with details of specialised staff and testing personnel.

II. The Contractor shall provide at minimum, one reference from the project cited as related experience to show the competence of perform the protection coordination study and transmission line protection settings calculation by using Transient Network Analyzer (TNA).

III. The Contractor shall provide two (2) competent person (tester) who holds a valid Certificate of Competency (permitted scope of work: Protection, Control & Instrumentation works up to 275kV) issued by SESCO's Competency, Authorisation and Safety Council permitting him to carry out specific operations and or work on SESCO’s protection, control, and instrumentation equipment during installation, testing and commissioning.

IV. The Contractor will be deemed to have visited and examined the site before tendering to ascertain local conditions under which the works are to be executed. The Tender amount or rates will be held to include the completion of all the Works indicated in the drawings or in the Specification. No claim will be entertained on lack of knowledge of the site conditions or any difficulty that may arise in respect with the entirely of the works specified.

V. Any equipment supplied under this contract found faulty prior to the end of the maintenance period shall be replaced by the Contractor. The Contractor shall also provide a fault report from the manufacturer detailing the cause of the fault.




TPCI/T/01/22) 6

2 SCOPE OF WORK

The works to be performed by the Contractor under the Contract comprises the

performance of all activities and the provision of all resources necessary to complete

the engineering, procurement, installation, testing and commissioning of Main 2

Current Differential Protection for OHL 1 and 2 Linking Kemantan and Sarikei 132kV

Substation.

These activities include:

2.1 KEMANTAN 275/132/33KV SUBSTATION

a) Supply, delivery and install two (2) nos. of Main 2 Current Differential Protection

relay for Sarikei 132kV OHL 1 & 2 feeders including complete wiring and cabling.

b) Supply, delivery and install of all the necessary materials to complete the installation

of the current differential protection as listed following:

I. Three (3) units Test Block compatible with Main protection relay

II. One (1) unit Test Plug compatible with supplied Test Block

III. (Four) 4 units Tripping Relay c/w base

IV. Twelve (12) units of auxiliary relay c/w base

V. Four (4) lots of Fibre Patch Code

VI. Six (6) Units of 2 Pole MCB C/W Auxiliary Contact

VII. Six (6) Units of 3 Pole MCB C/W Auxiliary Contact

VIII. Ten (10) units of component terminal block with integrated diodes

IX. Twenty (20) units for tripping isolation link c/w front connected fuse holder

X. Two (2) units Test Mode switch for Current Differential Relay

XI. Two (2) units of Tele protection Normal/Test/Lamp Test Switch For DI

XII. Eight (8) units Tele protection push button.

XIII. Four (4) set of Terminal Block Number Labelling (no. 1 to 50)

XIV. Four (4) pieces of Blanking plates for relay panel

XV. 3 Box of ABB Cable Lugs (2.5mm)

XVI. Any additional flexible PVC conduit, cable trunking, terminal blocks, cable

tray, labeling, earthing cable, cable, cable lug, cable marker and ferrules

(Brand: Partex), combine flex with cable lug, belden cable, coxial cable, balun,

dc changeover, test socket etc. required for internal relay panel, converter

panel and control panel etc to complete the retrofitting work shall be

deemed in this contract.

XVII. Any other equipment needed to satisfy the requirements of Contract Clause

3 [Protection System] and Clause 4 [Associated Work and Interface].




TPCI/T/01/22) 7

c) Supply, install, test and commission four (4) units of 2Mbps communication converter with accessories i.e Balun (IDC) at existing communication converter panel for Sarikei 132kV OHL 1 & 2 feeders Main 2 Current Differential protection including complete wiring and cabling.

d) Retrofitting of existing Relay Panel, Control Panel and Communication Converter

panel for Sarikei 132kV OHL 1 & 2 feeders includes: i. All the modification works on the relay panels, control panel for alarm and trip

signals to complete Main 2 Current Differential Protection retrofitting works

shall be included in this contract.

ii. To lay control cable from switchyard to control panel or relay panel, and from

relay panel to control panel or interface panel.

iii. Any necessary cable trays, fixing materials and all other equipment needed to

satisfy the requirements of Contract Clause 3 [Protection System].

iv. Communication converter panel:

✓ Supply, lay and terminate complete lot of communication cables from

communication converter to multiplexer via BELDEN type 8102 double

shielded twisted pair cables. The cable shall be laid in flexible conduit.

✓ Supply, lay and terminate complete lot of fibre optic cable and all accessories

for connection from relay panels to communication converter panel.

Dedicated flexible conduit shall be used for each run of fibre optic cable.

✓ The following works are included in the scope of this Contract and the cost of

these are deemed to be included in the Contract price:

- Cut and hack of the lean concrete for the cable entry from the

basement to the communication panels for the converter panels.

- Remedial works to buildings, foundations etc. as a result of damage

caused during installation under this Contract

e) Complete testing and commissioning of Main 2 Current Differential Protection system for Sarikei 132kV OHL 1 & 2 feeders including Bench Tests, Relay functional and conjunctive tests, end to end tests and trip tests. Refer to Contract Clause 5 [Installation, testing and Commissioning] for requirement of testing and commissioning for Main 2 Current Differential Protection system.




TPCI/T/01/22) 8

2.2 SARIKEI 132/33KV SUBSTATION

a) Supply, delivery and install two (2) nos. of Main 2 Current Differential Protection relay

for Kemantan 132kV OHL 1 & 2 feeders including complete wiring and cabling.

b) Supply, delivery and install of all the necessary materials to complete the installation

of the current differential protection as listed following:

I. Three (3) units Test Block compatible with Main protection relay

II. One (1) unit Test Plug compatible with supplied Test Block

III. (Four) 4 units Tripping Relay c/w base

IV. Twelve (12) units of auxiliary relay c/w base

V. Four (4) lots of Fibre Patch Code

VI. Six (6) Units of 2 Pole MCB C/W Auxiliary Contact

VII. Six (6) Units of 3 Pole MCB C/W Auxiliary Contact

VIII. Ten (10) units of component terminal block with integrated diodes

IX. Twenty (20) units for tripping isolation link c/w front connected fuse holder

X. Two (2) units Test Mode switch for Current Differential Relay

XI. Two (2) units of Tele protection Normal/Test/Lamp Test Switch For DI

XII. Eight (8) units Tele protection push button.

XIII. Four (4) set of Terminal Block Number Labelling (no. 1 to 50)

XIV. Four (4) pieces of Blanking plates for relay panel

XV. 3 Box of ABB Cable Lugs (2.5mm)

XVI. Any additional flexible PVC conduit, cable trunking, terminal blocks, cable

tray, labeling, earthing cable, cable, cable lug, cable marker and ferrules

(Brand: Partex), combine flex with cable lug, belden cable, coxial cable, balun,

dc changeover, test socket etc. required for internal relay panel, converter

panel and control panel etc to complete the retrofitting work shall be

deemed in this contract.

XVII. Any other equipment needed to satisfy the requirements of Contract Clause

3 [Protection System] and Clause 4 [Associated Work and Interface].

c) Supply, delivery and install of one (1) communication converter cubicle including four (4) units of 2Mbps communication converter with all the necessary accessories i.e Balun (IDC), cables and wiring where applicable for Kemantan 132kV OHL 1 & 2 feeders Main 2 Current Differential protection.

d) Retrofitting of existing Relay Panel and Control Panel for Kemantan 132kV OHL 1 & 2 feeders includes:




TPCI/T/01/22) 9

i. All the modification works on the relay panels, control panel for alarm and trip

signals to complete Main 2 Current Differential Protection retrofitting works

shall be included in this contract.

ii. To lay control cable from switchyard to control panel or relay panel, and from

relay panel to control panel or interface panel.

iii. Any necessary cable trays, fixing materials and all other equipment needed to

satisfy the requirements of Contract Clause 3 [Protection System].

iv. Supply, lay and terminate complete lot of communication cables from

communication converter to multiplexer via BELDEN type 8102 double shielded

twisted pair cables. The cable shall be laid in flexible conduit.

v. Supply, lay and terminate complete lot of fibre optic cable and all accessories for

connection from relay panels to communication converter panel. Dedicated

flexible conduit shall be used for each run of fibre optic cable.

e) Complete testing and commissioning of Main 2 Current Differential Protection system for Kemantan 132kV OHL 1 & 2 feeders including Bench Tests, Relay functional and conjunctive tests, end to end tests and trip tests. Refer to Contract Clause 5 [Installation, testing and Commissioning] for requirement of testing and commissioning for Main 2 Current Differential Protection system.




TPCI/T/01/22) 10

2.3 RELAY SETTINGS & SCHEME TESTS BY TRANSIENT NETWORK ANALYSER (TNA) OR

SIMULATOR

a) Proposed and recommend the relay setting for Main 2 Current Differential Protection

relay with backup distance protection for Kemantan – Sarikei 132kV OHL 1 & 2 feeders

and carry out scheme tests by using transient network analyser (TNA) or simulator to

determine suitability of settings recommendation includes:

I. Submit a written report on the TNA test results. The report shall in the least

contain an executive summary and recommendations of practical solutions

based on the findings of the study, study methodologies, descriptions and

definitions of cases studied, simulation and calculation results and analyses.

2.4 DOCUMENTATION

a) Three (3) sets of hardcopy and softcopy of the following document shall be provided

within 1 month from the date of commissioning of the current differential protection

to the Employer:

i. As-build drawings.

ii. Test reports.

iii. Operation & Maintenance instruction manual.




TPCI/T/01/22) 11

3 PROTECTION SYSTEM

3.1 GENERAL

(a) The protective system shall be designed to disconnect faulty circuits with speed and

certainty without interference of healthy circuits. It shall also be designed to prevent

incorrect operation of the circuit-breakers as a result of transient phenomena not

arising from a faulty condition of the section of the plant associated with each set of

relays, but which may occur during fault periods due to disturbances of the electrical

network.

(b) All elements of the protection system shall work with greatest possible reliability

under all expected service conditions.

(c) All protection schemes shall be shown to be suitable and stable for the stated

maximum system fault levels.

(d) The protection sensitivity shall be shown to be adequate for the stated minimum

system fault levels.

(e) The protection system plus the circuit-breakers shall have fault clearing time of 120-

140 ms for 275kV and 132kV systems.

(f) Each trip relay and/or tripping circuit shall be separately protected by a miniature

circuit-breaker. The voltage and integrity of each tripping circuit and/or trip coil shall

be separately monitored.

(g) Advance warning of impending trip action shall be given where possible. This is

generally to be achieved by the initiation of a first stage alarm, set to operate before

the trip condition is reached.

(h) The Contractor shall ensure that each electrical protection relay is independent of

others and can be individually isolated to allow each one alone to be taken out of

service for testing or operational purposes.

(i) All trip initiating devices shall include a LED operation indicator on the respective

protection cubicle. Electrical protective devices may require interposing relays with

sufficient contacts to perform the alarm functions plus one spare normally-open




TPCI/T/01/22) 12

contact. A minimum of two initiating contacts are required: one for tripping and the

other for operating the interposing relay.

(j) Front panel mounted relay test facilities shall be provided. Test facilities shall consist

of a relay test block mounted adjacent to each relay with provision for automatic short

circuiting of current transformer secondary circuit. It should only be necessary to plug

a test handle in the test block to get the correct opening of trip circuits, short-circuiting

of current transformer secondary circuits (make before break) and opening of voltage

transformer circuits.

(k) Test block shall be of approved type (refer to Appendix F: SEB Accepted Relay List with

provision for isolation and short circuiting of current transformer secondary circuit by

means of shorting the contacts or movement of links from their normal operating

position or any other testing arrangement approved by the Employer. Test block

insulation shall be rated at 2kV and be suitable for cable size of minimum 4 square

mm.

(l) Isolation of tripping circuits via solid links shall be provided for test and maintenance

purposes. Links shall be provided for isolation of individual protection trip circuits and

the common protection trip circuit to each circuit breaker trip coil.

(m) Links shall be clearly labelled, mounted in accessible positions and the link covers

coloured white.

(n) Each current transformer circuit shall be earthed through a removable link at one

point only and this shall be located in the relay cubicle.

(o) The following requirements shall apply to all electrical protective relays:

I.All relays offered must therefore have been accepted to be used in SEB

transmission system and listed in the SEB Accepted relay list (refer to Appendix

9.1)

II.All necessary, converters and auxiliary power supply units etc. shall be provided

by the Contractor.

(p) The Contractor shall submit, for the Employer's approval, tables (facility schedules)

detailing the proposed monitoring, control, indication, alarm and protection facilities




TPCI/T/01/22) 13

to be provided for Line Current Differential protection for Kemantan - Sarikei OHL 1 &

2 feeders.

3.2 RELAYS

(a) The specific technical requirements for the electrical protective relays, auxiliary relays

and associated devices required for the protection of the transmission lines are

described in the following paragraphs.

i. All relays offered must therefore have been accepted to be used in SEB

transmission system and listed in the SEB accepted relay list (refer to Appendix

9.1)

ii. All necessary, converters and auxiliary power supply units etc. shall be

provided by the Contractor.

iii. Relays which rely for their operation on an external DC supply shall utilise for

this purpose the trip supply of the associated circuit-breaker. This supply shall

be monitored, and an alarm provided in event of failure.

iv. Any auxiliary supplies necessary to power electronic circuits shall be derived

from the main station battery and not from batteries internal to the protection.

v. Relays, whether mounted in panels or not, shall be provided with clearly

inscribed labels describing their application and rating in addition to the general-

purpose labels.

vi. All metal bases and frames of relays shall be earthed at the main cubicle

earthing bar, except when the latter must be insulated for special

requirements.

vii. Main tripping function is not preferred to go through trip relays. Direct contact

from protection to trip coil shall be implemented as far as possible.

viii. DC operating coils shall be placed in the circuit so that they are not connected

to the positive pole of the battery except through normally open (NO)

contacts.




TPCI/T/01/22) 14

3.3 PROTECTION SCHEME

(a) The Contractor shall provide a comprehensive Main 1 Current Differential protection

scheme for Kemantan - Sarikei 132kV OHL 1 & 2 feeders. Details of the complete

proposed protection scheme shall be submitted by the Contractor for approval by the

Employer.

(b) The protection scheme shall secure detection of all faults and operate to disconnect

the faulty circuit and/or equipment in a minimum of time to minimise permanent

damage. All protection facilities necessary to achieve such a scheme shall be provided

by the Contractor.

(c) Protection equipment shall be designed and applied to provide maximum

discrimination between faulty and healthy circuits. All equipment is to remain stable

during transient phenomena which may arise during switching or other disturbances

to the system.

(d) Wherever practicable the design of the duplicated protection schemes shall be based

on the "fail-safe" principle. For example, care shall be taken to ensure that loss of DC

supply or an open circuit does not cause incorrect opening or closing of any circuit-

breaker. Circuit-breaker or disconnector repeat relays shall be of the non-latching

type, and a discrepancy alarm shall be provided to check correct operation of the

repeat relays following a circuit-breaker or disconnector operation.

3.4 TRANSMISSION LINE PROTECTION

3.4.1 GENERAL

(a) Facilities shall be provided to enable one protection (Protection 1 or Protection 2) to

be taken out of service for maintenance or testing without affecting the operation of

the other protection in any way. The facilities shall include duplicate circuit-breaker

trip coils, separately fused DC circuits and the use of separate CT core. The protection

relays shall be arranged to initiate a single set of auto-reclosing equipment.

(b) The line protection schemes for each transmission line shall include the following protection relays:

i. Protection 1 – Line Current Differential Relay with backup distance and carrier assisted directional earth fault protection (*POTT).

ii. Protection 2 – Line Current Differential Relay with backup distance and carrier assisted directional earth fault protection (*POTT) for overhead line distance less than 80km, distance relay (*POTT) with carrier assisted directional earth fault protection(*POTT) for overhead line distance more than 80km.




TPCI/T/01/22) 15

iii. Different make of line differential relay shall be proposed if current differential relay is to be utilized for both Protection 1 and Protection 2.

iv. Three-phase over-current and earth fault relay, as back-up protection.

v. Auto reclose relay, initiated separately by Protection 1 and Protection 2.

vi. Trip circuit supervision, visible from the front of the cubicle without having to open the cubicle door, for Protection 1 and Protection 2.

vii. Auto-reclose (ARC) IN/Out switch located at control cubicle.

viii. Disturbance and event records, including software for disturbance analysis.

Note: *POTT - permissive overreach transfer trip scheme

(c) The existing line protection scheme for Kemantan - Sarikei 132kV line feeders

comprises:

i. Main 1: Current Differential Protection relay (LFCB) and external backup

directional earth fault protection operating in conjunction with tele-protection

channels over power line carrier circuits in a permissive scheme.

ii. Main 2: Distance Protection relay (Optimho LFZP) supplemented with SOTF

and carrier-assisted direction earth fault protection.

(d) The Main 2 Distance Protection Relays at these substations are to be replaced with

new Current Differential protection under this Contract for OHL 1 and 2 linking

Kemantan and Sarikei substation. Different make of line Current differential relay shall

be proposed for main 2 protection.

(e) The current differential shall be equipped supplemented with backup distance, SOTF,

VT supervision, power swing block and directional earth fault protection with all

optional features available on the existing protection at both Kemantan and Sarikei

substations.

(f) These Current Differential relays are also to operate with duplicate channels 2Mbits/s

protection data communication interface and the entire necessary communication

converter which required shall be included in this contract.




TPCI/T/01/22) 16

(g) Backup Directional Earth Fault Protection at both Kemantan and Sarikei substations

operate in conjunction with tele-protection channels to form a permissive scheme.

The Directional Earth Fault shall be available with 2 stages where stage 1 is aided

operation with carrier received and stage 2 with the time delay. The carrier send shall

be delay in minimum 100ms.




TPCI/T/01/22) 17

3.4.2 LINE DISTANCE PROTECTION

(a) The line distance protection shall include complete distance relays of full scheme, non-switched type for phase/earth and phase/phase faults, with the following functions:

i. Five phase–phase distance protection zones, comprise of three forward zones, one reverse zone and one accelerated zone. Each zone with independent setting

ii. Five phase–earth distance protection zones, comprise of three forward zones, one reverse zone and one accelerated zone. Each zone with independent setting.

iii. Tele-protection scheme for distance function - permissive underreach, permissive overreach, blocking scheme is ready to be selected.

iv. Direct intertripping via protection signalling channels.

v. Weak infeed logic to achieve fast tripping at the sending end in the event of a weak infeed at the receiving end.

vi. Switch on to fault protection.

vii. Fault locator.

viii. Power swing detection. Reset times shall be low to ensure the associated distance relay reverts to its normal role as soon as possible following a power swing.

ix. Indicators to show the relay tripped, zone indication and the phase or phases faulted. Indication must not be lost in the event of a supply failure.

x. Display: faulted phase(s), time and zone of operation and distance to fault.

xi. Fuse failure supervision.

xii. Single-pole and Three-pole tripping logic.

xiii. Auto-reclose logic 1 and/or 3 phases.

xiv. Disturbance and event records including software for disturbance analysis.

xv. At least six (6) binary inputs.

xvi. Mho/quadrilateral characteristics, separately configurable for each zone. Partially cross-polarised mho relays are preferred for Zones 1 and 2 for 2-phase and 3- phase faults but other characteristics will be considered. Quadrilateral characteristics with adaptive reactance measurement to avoid overreach or underreach for resistive faults with pre-fault load shall be provided for earth faults. The relays shall operate for faults in the direction of the protected line only.




TPCI/T/01/22) 18

xvii. Tele-protection scheme for directional earth fault (DEF) function. Directional earth fault relays will be arranged to operate in a permissive overreach scheme, which should be capable of being enabled or disabled as an option on the relay menu. A dedicated DEF-function communication channel is preferred to have the highest possible security against maloperations due to communication or polarising problems.

xviii. Directional polarisation may be by negative sequence voltage and current or by zero sequence voltage and current.

xix. The forward-looking directional earth fault function shall incorporate a definite time back-up stage. It shall also be possible to set standard inverse characteristic, with a minimum time delay so as not to interfere with the normal tripping from distance protection under maximum fault conditions.

(b) The directional earth fault protection shall initiate three pole tripping without auto-reclosing. It must therefore include a short time delay of 100ms to permit single pole tripping by the distance protection.

(c) The necessary circuitry shall be incorporated to inhibit the directional earth fault (DEF) elements during single phase to earth faults (by any main line differential or distance relay) and during the single phase auto reclose dead time. This feature shall be selectable by links or switches. Provision shall also be made to ensure that the earth fault elements reset during the single-phase dead time.

(d) Neither the distance protection scheme nor the directional earth fault scheme shall maloperate due to fault current reversal during sequential clearance of a fault on the parallel circuit. A current reversal guard is required to prevent the possibility of maloperation on current reversals following sequential opening of circuit breakers.

(e) Suitable time delays, or other approved means shall also be provided to extend the duration of the send signal initiated by the Zone 1 unit, to enable both ends of a protected circuit to trip, following a fault close to one end of a parallel circuit, which is fed from one end only. The extension of the duration of the send signal must not occur for permissive intertripping signals initiated by Zone 2 elements, as this may result in unwanted tripping of a healthy circuit during current reversals during fault clearance on a parallel circuit.

(f) The effect of zero sequence mutual coupling between the double circuit lines on the protection shall be described, together with any measures considered necessary to overcome this effect.

(g) The distance protection time delayed back-up Zones 2 and 3 and the directional earth fault scheme and back-up stage shall intertrip the remote station circuit breakers over direct intertripping channels. Auto reclosing shall not be initiated on receipt of direct




TPCI/T/01/22) 19

intertripping signal. Direct intertripping shall also be initiated in the event of a 3 phase fault in any zone.

(h) The unit scheme shall be self-monitoring from end-to-end and give separate alarms for relay failure or communication channel failure.

(i) The relays shall incorporate fault and event recording features. It shall be possible to transfer recordings out through a serial communication link and be saved in COMTRADE format. All necessary application and communication software are to be provided for protection monitoring through serial communication facilities.

(j) The integral direct intertripping facility shall be employed to initiate direct intertripping from one substation terminal to the remote terminal (and vice versa) on operation of:

i. Circuit breaker failure

ii. Directional earth fault protection

iii. Distance protection time delayed backup zones

iv. Backup overcurrent and earth fault protection.

v. Switch On To Fault protection

vi. Busbar protection

(k) A protection interface channel shall be provided. The protection interface channel shall be able to support 512kbit/s transmission speed and 2Mbit/s communication converter which support ITU-T G.703 (E1) standard shall also be supplied for interfacing with communication equipment (supplied by other). The distance between communication converter and communication equipment shall be less than the distance recommended by communication converter’s manufacturer.

(l) In addition, the relay shall readily support IEEE C37.94 communication protocol or be able to support it in the future by hardware and/or software upgrade without replacing the entire relay.

(m) The fibre optic cable for connection from relay to communication converter shall be under this contract. Connection from the communication converter to the multiplexer (provided by others) shall be via BELDEN 8102 shielded twisted pair cables supplied and connected to the relay under this contract. However, terminations to certain converters deploys RJ45 socket and plug. In that case, cable used should follow the recommendation as specified by the manufacturer of the communication converter.




TPCI/T/01/22) 20

3.4.3 LINE DIFFERENTIAL PROTECTION

(a) The line differential protection relay shall be an instantaneous percent differential type,

with double biased characteristic. The measurement system shall be of the three-phase,

low impedance principle. Three-phase and phase-phase faults shall be detected. Digital

current differential protection relays shall have phase segregated measuring elements,

providing single phase tripping for single phase faults and three phase tripping for multi-

phase faults. Evaluation should be done simultaneously at both line ends and take into

consideration both amplitude and phase angle.

(b) The relay shall be equipped with charging current and load compensation features.

(c) Delay in communication shall be continuously measured and automatically

compensated for.

(d) The maximum fault resistance coverage provided by the current differential relay for

each line section shall be stated assuming the load current is 1 per unit and the CT ratio

is selected to the maximum value.

(e) The unit scheme shall be self-monitoring from end-to-end and give separate alarms for

relay failure or communication channel failure. Any failure of the scheme shall

automatically render the scheme inoperative.

(f) The relay shall have backup distance and carrier-assisted directional earth fault (DEF)

protection. Refer to Section 3.4.2 for the requirements of backup distance and DEF

protection.

(g) In addition, the relay shall have the following functions:

i. Direct intertripping via protection signalling channels.

ii. Switch on to fault protection.

iii. Indicators to show the relay tripped, zone indication and the phase or phases

faulted. Indication must not be lost in the event of a supply failure.

iv. Display: faulted phase(s), time and zone of operation and distance to fault.

v. Fuse failure supervision.

vi. Single-pole and Three-pole tripping logic.

vii. Auto-reclose logic 1 and/or 3 phases.




TPCI/T/01/22) 21

viii. Disturbance and event records including software for disturbance analysis.

ix. At least six (6) binary inputs.

(h) The relays shall incorporate fault and event recording features. It shall be possible to

transfer recordings out through a serial communication link and be saved in COMTRADE

format. All necessary application and communication software are to be provided for

protection monitoring through serial communication facilities.

(i) The integral direct intertripping facility shall be employed to initiate direct intertripping

from one substation terminal to the remote terminal (and vice versa) on operation of:

i. circuit breaker failure

ii. directional earth fault protection

iii. distance protection time delayed backup zones

iv. Backup overcurrent and earth fault protection

v. Busbar protection

(j) Redundant protection interface channels shall be provided. The protection interface

channel shall be able to support 512kbit/s transmission speed and 2Mbit/s

communication converter which support ITU-T G.703 (E1) standard shall also be

supplied for interfacing with communication equipment (supplied by others). The

distance between communication converter and communication equipment shall be

less than the distance recommended by communication converter’s manufacturer.

(k) The fibre optic cable for connection from relay to communication converter shall be

under this contract. Connection from the communication converter to the multiplexer

(provided by others) shall be via BELDEN 8102 shielded twisted pair cables supplied and

connected to the relay under this contract. However, terminations to certain converters

deploys RJ45 socket and plug. In that case, cable used should follow the

recommendation as specified by the manufacturer of the communication converter.




TPCI/T/01/22) 22

3.4.4 AUTO-RECLOSING SCHEME

(a) The auto-reclose relay shall incorporate the following features:

i. Selectable 1 - 3 auto-reclose shots.

ii. Independent set dead time for each shot.

iii. Auto-reclose inhibit after manual close.

iv. Auto-reclose inhibition for backup protection.

v. Synchronism check.

(b) Reclosing shall be initiated following tripping by the digital current differential relay,

distance protection Zone 1 or accelerated Zone 2, or on receipt of a permissive

intertripping signal. Reclosure shall not be initiated in event of a three-phase fault,

tripping following circuit breaker failure, any type of fault in the second or third

distance relay back-up zones or when the circuit breaker is closed onto a fault on a

previously de-energised line. The following modes of operation shall be selectable by

means of a switch or switches:

i. Single pole, high speed reclosing. Auto-reclosing shall only be initiated in the

event of a single phase to earth. All other type of faults shall result in three

phase tripping without auto-reclosing.

ii. Three pole delayed reclosing. Delayed reclosing shall only be initiated in the

event of a single phase or two-phase fault. Three phase faults shall result in

tripping without auto-reclosing.

iii. Single pole, high speed/three pole delayed reclosing. Single pole, high speed

auto-reclosing shall be initiated only in the event of a single phase-earth fault

and delayed three pole reclosing initiated in the event of a two-phase fault.

Three phase tripping without reclosing shall take place for three phase faults.

(b) Means shall be provided to switch the auto reclosing equipment in and out of service

from the control panel and by supervisory control.

(c) If a second earth fault occurs during the single pole auto-reclose dead time, three

phase tripping with subsequent delayed three pole auto-reclose shall take place if the

auto-reclose selector switch is in the single and/or three pole reclosing mode. If the

selector switch is in the single pole reclose mode, three phase tripping with lockout




TPCI/T/01/22) 23

should follow. If the second fault is a phase-to-phase fault, three pole tripping without

reclosing shall take place for both selector switch positions.

(d) It is appreciated that if the second fault occurs just prior to or during the elapse of the

single pole dead time, it may not always be feasible to halt the single pole reclosing

sequence. Under such circumstances single pole closing will be tolerated but the

relaying scheme must ensure that all poles are then tripped immediately without

further reclosure. Tripping initiated by the circuit breaker pole discrepancy scheme

will not be permitted. Two shot reclosing i.e. single pole high speed followed by

delayed reclosing will not be permitted.

(e) The reclaim time shall be chosen to match the duty cycle of the circuit breakers,

assuming the shortest available dead time is chosen. The reclaim time shall not,

however, be less than five seconds, and the reclaim timer range shall extend to 180

seconds. The closing command shall be limited to two seconds, after which time the

reclosing equipment shall automatically reset without resetting the reclaim timer. The

reclosing equipment shall also reset if dead line check or synchronism check conditions

are not satisfied within five seconds of the check relays being energised.

(f) A counter shall be provided to record the number of reclosures.

(g) Deadline check relays shall monitor the condition of the line and busbar and permit

three pole reclosing under dead line conditions only when the line is de-energised and

the busbar is energised. The line is considered to be de-energised when the voltage is

less than 20% of rated voltage, and the busbar is considered to be energised when the

voltage is greater than 80% of rated voltage.

(h) In the case of an energised line, a synchronism check relay shall monitor the

magnitudes of the voltages on both sides of the open circuit breaker, and the phase

angle and frequency between these voltages. Closing is only permitted when these

are within prescribed limits.




TPCI/T/01/22) 24

3.4.5 TRIPPING RELAY

(a) All lock-out trips shall be routed via a hand reset and electrical reset relay with heavy

duty contacts.

(b) All tripping relays, where specified shall be of the heavy-duty type suitable for panel

mounting and have been accepted to be used in SEB transmission system and listed in

SEB accepted Relay List

(c) Trip relay contacts shall be suitably rated to satisfactorily perform their required duty

and relay operating time shall not exceed 10ms from initiation of trip relay operating

coil to contact close.

(d) The minimum operating current shall not be less than 50mA and the trip relay shall

not operate when a 10-microfarad capacitor charged to 150 volts (for a 110/125V trip

relay) is discharged into the relay operating coil.

(e) Closing of circuit-breakers from the substation control board or local control cubicle

or State Dispatch Centre shall be inhibited if the respective lock-out trip relays are not

reset.

(f) Facilities for electrical reset from the control panel and by supervisory control shall be

provided.

3.4.6 TRIP CIRCUIT SUPERVISION

(g) The trip circuit supervision shall be independent of the protection relays and provided

to monitor each pole of each trip circuit on each circuit-breaker, with separate

mechanisms per pole with the circuit-breaker in both the open and closed positions.

The status of the trip circuit shall be indicated on the front of the cubicle.

(h) Alarms shall be initiated to signal faulty trip circuits. The alarms circuits shall be

designed to prevent mal operation during momentary dips in the DC supply.

(i) The trip circuit supervision scheme shall provide continuous supervision of the trip

circuits of the circuit breaker in either the open or closed position and independent of

Local or Remote selection at the local operating position. It shall be suitable for use in

single pole tripping schemes where required. Series resistances shall be provided as

necessary to ensure that the trip coil will not operate in the event of a short circuit of

any one component in the supervision circuit.




TPCI/T/01/22) 25

(j) If an auto-reclose relay uses bridging contacts in the circuit breaker tripping scheme

where single pole tripping is employed, the bridging contacts provide an alternative

path for trip circuit supervision current and therefore a trip circuit failure in one phase

only, may not be detected. The trip circuit supervision scheme shall operate

satisfactorily and correctly under such conditions.

(k) Where specified, power supply supervision relays shall be provided to monitor the

duplicated DC power supplies within a relay cubicle where this supply is not already

monitored by the circuit breaker trip circuit supervision scheme. An alarm shall be

given if either supply voltage falls below 70% of nominal voltage. The relay shall be

equipped with a self-resetting flag indicator and shall be suitable for continuous

operation at 125% of nominal DC voltage.

3.4.7 RELAY SETTINGS

(a) The Contractor shall develop the protection plan for relay settings and submit for

Employer approval.

i. Relay settings for all protection relays shall be submitted to the Employer prior to

commissioning of any plant for approval. Because of the need to co-ordinate the

distance relay settings, settings shall also be provided for all distance relays

supplied under this Contract and existing devices which require settings to be

amended as a result of the work carried out under this Contract. Settings shall also

be provided for those relays and other equipment provided under this Section of

the Contract which do not require an intimate knowledge of existing relay settings

e.g. circuit breaker fail relays. Detailed calculations shall be provided supporting

the recommended settings.

ii. The Contractor shall also be responsible for the preparation of all device logic and

configuration files for protection relays. These settings and relay configuration

files shall be submitted for review along with protection settings.

iii. Where the programmable internal logic of numerical relays forms part of the

scheme design, the Contractor shall also provide these proposed configurations

along with the external schematic diagrams.

iv. The Contractor shall, prior to commencement of the Tests on Completion for the

substation protection system, apply the settings to the equipment, including those

on the corresponding line protection relays at remote end substation.




TPCI/T/01/22) 26

(b) Verify the recommended settings by using transient network analyser or simulator:

I. The 132kV line protection shall be subjected to scheme test using a transient network analyzer or real time digital simulator, such as RTDS or equivalent. A section of the SESCO power system shall be modelled, inclusive of line reactors.

II. Conjunctive tests are required to test the operation and stability of the line protection relays at both ends of a transmission line, for simulated SESCO power system faults, with sources at both ends. The simulation shall include the teleprotection signalling channel pickup & drop-off times.

III. The tests shall comprehensively cover the different fault types, fault incident angles, for various circuit configurations, double line, and single line operation, under maximum and minimum generation conditions.

IV. Fault shall be applied on 0%, 30%, 70%, 100% of the transmission line for internal solid and high ohmic fault and busbar, 0%, 100% of the parallel line for external solid and high ohmic faults. Tests for current reversal shall include solid and high ohmic faults.

V. Fault resistive coverage shall be determined iteratively to obtain the fault resistance which would lead to an instantaneous fault clearance at Kemantan and Sarikei.

VI. The tests are to include autoreclosing sequence, including evolving faults for a single pole tripping, reclosure, and three pole tripping sequence to the distance relays to simulate the distance protection response to a reclosure.

The TNA test plan requirements and guidelines shall be referred to APPENDIX 9.2




TPCI/T/01/22) 27

3.4.8 ENGINEERING DESIGN DRAWING

a) The Contractor shall submit engineering design drawing for Main 2 Current Differential

protection relay scheme for Kemantan – Sarikei 132kV OHL 1 & 2 feeders for the

Employer’s approval within three (3) months of the Contract commencement date.

b) The Contract documentation shall include modified circuits at existing substations.

These may include existing drawings and cable numbering systems where they are

unchanged and new drawings covering the modified and new equipment.

3.4.9 CURRENT TRANSFORMER CALCULATIONS

(a) The Contractor shall submit to the Engineer detailed calculation to prove that the

existing current transformer (CT ratio 500/1 and 250/1) can be used for the current

differential protection for Kemantan - Sarikei 132kV OHL 1 & 2 feeders. They shall be

presented within six weeks of the Contract commencement date.

The existing current transformer ratio details are such as listed below:

i. At Kemantan Substation

• 1250/500/250/1A – 5P15 *

ii. At Sarikei Substation

• 1250/500/250/1A - 5P15 *

The NEW current transformer ratio details are such as listed below:

i. At Kemantan Substation

• 1250/500/250/1A - 5P15 *

ii. At Sarikei Substation

• 1250/500/250/1A - 5P15 *

Note *: The upgrading of CT ratio from 250/1 to 500/1 for this relay retrofitting

works will be done by Employer.




TPCI/T/01/22) 28

4 ASSOCIATED WORK AND INTERFACE 4.1 ARRANGEMENT OF FACILITIES

(a) Relay equipment shall be mounted on existing relay panels and cubicles as specified. It

shall be mounted on Blanking Plate and any holes should be covered up.

(b) The Contractor shall be responsible under this Contract for the provision of terminal

blocks with isolating facilities where required for connection to relay and its accessories

under this contract. All circuits provided under this Contract whether or not they are

subject to the system control requirements at the present time, shall be designed and

constructed so that the standard facilities specified can be readily provided as required

in the future.

4.2 CONTROL SWITCHES AND PUSHBUTTONS

(a) Control switches and pushbuttons shall comply with IEC60947-5-1.

(b) Switches for other apparatus shall be operated by shrouded push button or have

handles of the spade type. Control reversing, selector and test switches shall be

mounted, constructed, and wired so as to facilitate the maintenance of contract without

the necessity for disconnecting wiring.

(c) Where necessary, control switches shall be capable of being locked in appropriate

positions. Such switches shall be controlled by independent springs, the use of contact

springs alone for restoring not being acceptable.

(d) All pushbuttons shall be of the non-retaining type made of non- hygroscopic material,

non-swelling and fitted to avoid any possibility of sticking. The contacts of all switches

and pushbuttons shall be strong and to have a positive wiping action when operated.

(e) Control switches use in direct control schemes shall be rated for the power station or

substation battery voltage and in any case not lower than 110V.

4.3 MINIATURE CIRCUIT BREAKERS, FUSE AND LINKS

(a) Facilities shall be provided for protection ad isolation of circuits associated with

protection, control, and instrumentations. They shall be of approved type and grouped,

as far as possible, according to their functions. They shall be clearly labelled, both on the

panels and the associated wiring diagrams.




TPCI/T/01/22) 29

(b) Facilities shall be provided to enable the control circuits for any circuit – breaker to be

individually isolated for maintenance purposes.

(c) All fuses shall incorporate HRC cartridges to BS HD 60269-2:2010 and IEC 60269 (BS EN

60269-1) Rewire-able type fuse will not be accepted.

(d) Fuse holders shall be designed to lock the cartridges firmly into position without the use

of screw champing devices.

(e) Miniature circuit- breaker shall comply with IEC60898 (BS EN 60898).

(f) When miniature air circuit – breaker is used on control, protection and alarm supplies,

tripping shall cause an alarm to be displayed.

4.4 PANEL WIRING

(a) All control and relay panel wiring secondary control wiring in circuit – breakers, motor

starters, control gear and the like shall be carried out in a neat and systematic manner

with cable supported clear of the panels and other surfaces at all points to obtain free

circulation of air.

(b) In all cases, the sequence of the wiring terminal shall be such that junction between

multi-core cables and the terminals is affected without crossover. Except where

terminals are approved by the Engineer for use with bare conductors, crimped

connectors of approved type shall be used to terminal all small wiring. Insulating bushes

shall be provided where necessary to prevent the chafing of wiring.

(c) All panel wiring shall comply with the requirement of BS 6231, Type A or B, as

appropriate. Conductors shall be copper and have a minimum cross section equivalent

to 50/0.25mm (2.5mm2), 7/0.67mm (2.5mm2) or 1/1.78mm (2.5mm2) but single

stranded conductors should only be employed for rigid connections which are not

subject to movement or vibration during shipment, operation or maintenance. Flexible

conductor equivalent to 30/0.25 (1.5mm2) or smaller sizes generally shall only be

employed when necessitated by design of panel or rack and its provision for

terminations, such design being subject to approval by Engineer.

(d) Wire colours shall comply with IEC 60227. Alternatively, where equipment is wired in

accordance with a manufacturer’s standard diagram, wiring may be carried out in a

single colour except that all connections to earth shall be green or green/yellow.




TPCI/T/01/22) 30

(e) Wiring diagrams must indicate wire colours. All wires shall be fitted with numbered

markers of approved type at each termination. At points of inter-connection between

wiring, where a change a numbering cannot be avoided, double markers shall be

provided. Such points shall be clearly indicated on the wiring diagram.

(f) The markers on all wiring directly connected to circuit breaker trip coils, tripping

switches, etc., shall be of a colour, preferably red, different from that of the remainder

and marked “trip”. No wires may be teed or jointed between terminal points. Electrical

wiring and instruments shall be so located that leakage of oil or water cannot affect

them. Bus wiring between control panels, etc. shall be fully insulated and completely

segregated from the main panel wiring.

(g) All metallic cases of instruments, control switches, relay etc., mounted on control panels

or in cubicles, steel or otherwise, shall be connected by means of copper conductors of

not less than 4 green and yellow or green/yellow.

4.5 ALARMS

(a) An alarm relay shall be provided for initiating a remote supervisory alarm at the system

control room and remote direct wire alarm at electric room.

(b) Alarm shall be sub-divided into trip and non-trip functions, and each arranged to

operate a common bell or buzzer as specified. All the expenses for making the existing

bell or buzzer into operation or replace the faulty bell or buzzer are deemed to be

included in the Contract Cost.

(c) Trip alarms are located on top rows of annunciator window while non-trip alarms are at

the bottom. Non-trip alarms are supposed to trigger a buzzer and trip alarms are to

trigger a bell. Red colour filter or red luminaries (LED type is preferred) shall be used for

trip alarms. Yellow colour filter or yellow luminaries shall be used for non-trip alarms.

(d) Means shall be provided for silencing audible alarms whilst leaving the bell or buzzer

free to sound if any other alarm circuit is energised.

(e) Alarm indicating lamps shall remain alight until cancelled by the resetting devices

initiating the alarms and the operation of a separate cancellation switch.




TPCI/T/01/22) 31

(f) Where devices initiate alarms when machines are shut-down the circuit should avoid

unnecessary display and sounding of the alarm condition.

(g) A common fascia for each circuit shall be provided and mounted on the associated

control panel. Common alarm fascia 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. The

number and type of alarm of alarms shall be to the approval of the Engineer. A common

accept key shall operate in such a way that it causes the light to become steady and

silence the audible alarm, and the flasher relays shall be arranged to be cut-out when

the substation is unattended. When no alarm fascia is specified, alarms shall be

displayed by means of individual lamps mounted on the control panels. Resetting of the

individual alarm relays shall only be possible after initiating contacts have been reset.

(h) For the purpose of transmission to the system control centre, alarms shall also be

received by SCADA interface cabinet located in the Substation Control Room (to present

these signals to the supervisory equipment and interposing relays). Therefore, a switch

internally (repeater to output) in the annunciator is preferable rather than individual

auxiliary switches.

(i) PC based software must be provided according to the contract, if applicable.




TPCI/T/01/22) 32

5 INSTALLATION, TESTING & COMMISSIONING 5.1 GENERAL

(a) The Contractor shall provide two (2) experienced and competent person/tester who

holds a valid Certificate of Competency (permitted scope of work: Protection, Control

& instrumentation works up to 275kV) i s s u e d by SESCO's Competency,

Authorisation and Safety Council permitting him to carry out specific operations and

or work on SESCO’s protection, control, and instrumentation equipment during installation,

testing and commissioning. The testing shall be carried out during normal working hours

as far as is applicable. Tests which involve existing apparatus and outages may be

carried out outside normal working hours. The Contractor shall give sufficient notice to

allow for the necessary outage arrangements to be made in conformity with the testing

program.

(b) The Tester shall complete Site Acceptance Tests (SAT) and verifications according to SAT

requirements (refer to Appendix 9.3: Protection Relay Test Requirements), IEC

standards and equipment manufacturer’s recommendations.

(c) The Tester shall provide all equipment and personnel required to carry out the tests at

Site, including the provision, installation and removal of all test instruments, the

connection and disconnection of plant items and obtaining of all records.

(d) The Tester shall submit evidence to the Employer that the instruments used for the tests

at Site have been calibrated at an approved testing laboratory within a period of up to

three months prior to the tests at Site.

(e) All tests conducted shall be documented on a proper test form.

(f) Expected values shall be presented on the test form for all test/measurements results.

A test shall only commence when the expected range of values of the test is available

and presented on the test form. Where the test result involves obtaining a particular

measurement, then error calculation for measurement shall be made available on the

test form.

(g) For test/check results that is not within the expected range, the tester is required to

mention it clearly in the test form. The tester is also required immediately update this

defect in the master defect list.

(h) All results shall be entered onto the test form immediately upon completion of a test.

Recording test results elsewhere and later transferring it onto the test form shall not be

practised.

(i) Employer shall participate and witness all SAT activities. All test reports shall be signed

by the Employer and the Tester immediately after the testing. A defect list shall be




TPCI/T/01/22) 33

maintained and monitored by the Tester/Contractor and the Employer respectively.

Any major defect or outstanding works that may affect the integrity of the operation

shall be rectified before commissioning. Any test results not signed by the Employer and

tester will not be accepted.

(j) The Tester himself shall certify all the test reports, relay configuration and updated

drawings immediately after completion of the SAT. These reports shall be compiled and

submitted to Employer for approval before commissioning.

(k) One set of these documents shall be kept in the Substation after commissioning.

(l) During the course of erection, the Employer shall have full access for the inspection of

the progress of work and for checking workmanship and accuracy as may be required.

On completion of the work prior to commissioning, all equipment shall be tested to the

satisfaction of the Employer to demonstrate that it is entirely suitable for operation.

(m) Commissioning tests shall be carried out in the presence, and to the satisfaction, of the

Employer. The Contractor will also need to conduct parts of the tests, especially those

related to operational functions and features. The tests shall be exhaustive and shall

demonstrate that the overall performance of the complete system satisfies every

requirement specified.

5.2 TESTING SCHEDULE AND PROCEDURES

(a) The Contractor/Tester shall prepare and submit the following to the Employer for

comments and approval prior to the commencement of SAT:

i. Comprehensive SAT testing schedule; and

ii. Test procedures for all tests and scheme check, explain in detail the steps taken

to conduct each test. These tests shall conform to certain standards and

practises.

(b) The SAT procedures shall detail the following:

i. Method of testing

ii. Equipment to be used for testing

iii. Parameters or guarantees to be established

iv. Sequence of tests to be performed

v. Test result form of the particular test

vi. All safety aspects performing a particular test

vii. A checklist on the preparation required before carrying the test




TPCI/T/01/22) 34

viii. A checklist on the normalization required after performing the test.

ix. Additional specific requirements, instructions or precaution notes shall be

clearly mentioned in the test procedure if it is to be used in a live substation.

x. All safety aspects required to carry out the test shall be clearly documented in

the test procedure.

5.3 SITE ACCEPTANCE TESTING (SAT) PROCESS FLOWCHAT

SAT process shall be conducted in stages, in the sequence listed below.

(a) Stage 1: Multicore cable termination check & Test.

(b) Stage 2: Component level testing for secondary equipment.

(c) Stage 3: Protection scheme testing, including correct scheme operation, stability,

and trip tests.

5.3.1 MULTICORE CABLE TERMINATION CHECK AND TESTS

(a) The Tester shall complete the multicore termination check and tests prior to

proceeding with other SAT activities.

(b) All multicore cables of the facility to be commissioned shall be checked and tested.

This shall include multicore cables from switchgear cubicles/panels to the Marshalling

Kiosk and all other cables between cubicles/panels.

(c) At least the following shall be checked and confirmed to be in accordance with the

cable schedule.

i. The multicore cable is numbered at both ends in accordance with the cable

core schedule.

ii. The multicore cable core size used in accordance with the cable core schedule.

iii. The multicore cable colour in accordance with the cable core schedule.

iv. The multicore cable scree/armour is effectively ground.

v. All spare cores are numbered in accordance with the cable core schedule.

vi. The spare multicores are separated numbered (cable and ferrule number) and

grouped according to cable number.

vii. The terminal block type and numbering in accordance with the cable core

schedule




TPCI/T/01/22) 35

viii. No jointing along the multicore cable.

ix. Type of cable marker and ferrule [cable marker and ferrules (Brand: Partex)

should be used for this contract].

x. Core numbering and terminal block numbering in accordance with the cable

core schedule.

xi. The termination is neat, proper, and tight.

xii. The correct size of cable glands and lugs are used.

xiii. Separate multicore cable used for AC/DC.

(d) At least the following test shall be performed on each core.

i. Insulation resistance test at 1kV DC.

ii. Continuity check.

5.3.2 COMPONENT LEVEL TESTING FOR SECONDARY EQUIPMENT

(a) All functions utilised in the Contractor’s design for the Works in accordance with the

Scope of Works and Employer’s Technical Requirements shall be tested according to

the Employer’s Protection Relay Test Requirements (refer to Appendix 9.3).

(b) Relay settings used to test the performance of the relay shall be noted in the test form

before injection.

(c) Check and record all protection relays, instrument and test plugs are labelled clearly

as required.

(d) Check and record that by inserting the test plug, the following action will take place:

I. The DC supply for the relay or instrument is not interrupted.

II. The signalling circuit for alarm, SCADA and event recorder are not interrupted.

III. Insertion of test plug shall isolate in the following sequence:

• First, all tripping signals from the relay are isolated.

• Followed by the incoming current circuits are short-circuited.

• Finally, the incoming voltage circuits are open-circuited.

(e) For the following protection scheme test, secondary injection shall be carried out from

terminal blocks instead of the test blocks:

I. Protection trip test.




TPCI/T/01/22) 36

II. Auto-reclose test.

III. Signalling check to control panel

IV. Signalling check to SCADA panel

V. Signalling check to disturbance/fault recorder

(f) In addition to test required in the Employer’s Protection Relay Test Requirements

(refer to Appendix 9.3), all test required by the relay or instrument manufacturer shall

also be performed.

(g) Any repair work of a relay after the completion of secondary injection tests, shall

subject the relay to a full retest.

(h) Secondary injection tests shall be undertaken with the final, approved settings and

configuration files installed in numerical relays. In case of upload of new settings or

configuration changes, all secondary injection testing of the affected relay(s) shall be

repeated.

(i) For protection relays, all functions that are in use shall be tested. Any function not in

use shall be proven to be defeated by testing.

(j) Each relay must be provided with a test form. In addition to the general information

required in a test form as in Employer’s standard test forms, at least the following

details of the relay under test shall be mentioned:

I. Relay Make

II. Relay Type

III. Version No.

IV. Relay Input Rating- Vac, Iac, Hz, Vdc

V. Burden (VA)

VI. Serial No.

(k) Expected results of the test shall be made available prior to any test.

(l) Error calculations shall be recorded for any result obtained.

(m) During secondary injection of protection relays, output contacts shall be monitored

and recorder for its functionality. For example:

I. Contacts initiating trip circuits

II. Contacts initiating mater trip relay

III. Contacts initiating breaker failure




TPCI/T/01/22) 37

IV. Contacts initiating auto-reclose

V. Contacts initiating counter

VI. Contacts initiating annunciator

VII. Contacts wired to disturbance recorder

VIII. Contacts wired to SCADA

(n) Test and record all digital inputs in use of a protection relay or instrument.

(o) For relays with any of the following functions, the function shall be tested and

documented.

I. Built-in instrument or metering function

II. Built-in event recorders

III. Built-in disturbance recorder

(p) Secondary injection tests shall be undertaken with the final, approved settings and

configuration files installed in numerical relays. In case of upload of new settings or

configuration changes, all secondary injection testing of the affected relay(s) shall be

repeated.




TPCI/T/01/22) 38

5.3.3 PROTECTION SCHEME TESTING, INCLUDING CORRECT SCHEME OPERATION, STABILITY

AND TRIP TESTS.

5.3.3.1 CT AND VT SECONDARY WIRING CHECK

(a) The correct polarity of CT connection and wiring accuracy shall be proven by primary

injection, recording measured quantities at the associated protection, metering,

disturbance recorder and control device(s).

(b) VTs circuits shall be similarly proven, although secondary injection may be utilised

where constrained by ratio(s).

5.3.3.2 CONTROL SCHEME TEST

(a) Monitoring and control system functional tests shall be undertaken to demonstrate

that all controls, protections, alarms, indications and calculations, including all

sequences, displays and printouts operate correctly.

(b) Check of functional characteristics or each of the electrical protections.

(c) Each control scheme shall be tested and proven (e.g. interlocks, voltage selection,

synchronising, alarms and interlocks). It shall be shown that a function works before

demonstrating that an interlock inhibits it.

(d) The correct function of all trip links shall be similarly proven.

(e) Schematic diagrams shall be highlighted “bit-by-bit” as control schemes are proven

and shall form part of the commissioning record.

(f) If any wiring is disturbed/disconnected, its function shall be proven again following

reconnection.

(g) A master list of any and all temporary links/jumpers shall be maintained on site by the

Tester at all times.

5.3.3.3 PROTECTION SCHEME & TRIP TESTS

(a) The function and correct tripping sequences of each protection scheme shall be

proven.

(b) Coordination of protection functions between the substation protections and the

related complementary generating unit protection functions (where applicable i.e.

power station interconnecting switchyards).

(c) Analysis of consistency of information and alarms originating from the substation

protection system.




TPCI/T/01/22) 39

(d) All functions utilised in the Contractor’s design for the Works in accordance with the

Scope of Works and Employer’s Technical Requirements shall be tested according to

the Employer’s Protection Relay Test Requirements.

(e) In addition to test required in the Employer’s Protection Relay Test Requirements, all

test required by the relay or instrument manufacturer shall also be performed.

5.4 PRE-COMMISSIONING INSPECTION (PCXI)

The Pre-Commissioning Inspection shall be carried out jointly by the Contractor, Tester, and

Employer, and include the items outlined in the following sub-clauses.

5.4.1 DOCUMENTATION REVIEW

The following documentation shall be presented in a dossier and available during PCXI:

(a) Master list of documentation

(b) Equipment database

(c) Operation and maintenance manuals

(d) Inspection and tests during manufacture reports (Type, Routine and Special Tests)

(e) Construction quality assurance records

(f) Mark-up drawings

(g) Site Acceptance Test records

(h) Settings and plant configuration

(i) Temporary link/jumpers master list

(j) Master Defect List

(k) List of spares and special tools

5.4.2 DRAWING ACCURACY

Random checks of drawings (including cable schedules/termination diagrams) shall be

conducted for accuracy.




TPCI/T/01/22) 40

5.4.3 SETTINGS

A record of all final endorsed primary and secondary settings and configuration details shall

be compiled in a logical manner and available on Site. A selective audit will be undertaken to

verify correct implementation.

5.4.4 SITE ACCEPTANCE TEST RECORDS

All SAT shall have been carried out prior to commissioning except:

I. Tests that can only be carried out during commissioning outage

II. On-load commissioning tests

All test records shall be available and signed by the Tester, Contractor, and (where applicable,

i.e. Witness and Hold points) the Employer

5.4.5 DEFECTS

The Master Defect List shall be reviewed to ensure no significant defects remain outstanding.

An action plan shall be in place to ensure all defects will be cleared within a reasonable time

following commissioning.

5.4.6 SPARES AND SPECIAL TOOLS

Receipt of spare parts and special tools required under the Contract shall be confirmed by the

Employer.

5.4.7 CUBICLE INSPECTION

(a) The inspection shall be carried out using an approved checklist. Each cubicle shall have

a dedicated check list. Cubicle inspection shall be documented as part of

commissioning report.

(b) As a minimum, the following criteria shall be checked for each Protection, Control and

Marshalling cubicle:

I. Heaters are switched on

II. All MCB’s are switched on

III. All terminal block links are closed and tight including spares

IV. All wires are properly terminated (except spare wires)




TPCI/T/01/22) 41

V. A proper note (to include: purpose, person-in charge and date) shall be made

available for any of the following case:

i. terminal block links are left Open intentionally

ii. wires open/disconnected intentionally

iii. MCBs left ‘ off’

VI. Check that there are no openings e.g holes, doors are properly closed and door

gasket seals are in tact

VII. Cubicle lighting facility shall be functioning

VIII. Panel earthing and component earthing is completed

IX. Cleanliness of panel

X. All temporary shorting/looping are removed

5.4.8 SETTINGS CHECK

a. All protection relay settings shall be re-checked with the documented final

approved/endorsed settings

b. Confirm that date and time of relays are set correctly

c. Confirm that relay fault recorders are set correctly

d. Clear all test records/events from relays and recorders

5.5 END TO END TESTS

(a) Transmission line feeders shall be subjected to successful End to End test before

energisation.

(b) End to end tests shall be conducted only after the successful completion of all PCXI

activities.

(c) The secondary injection test set shall be equipped with GPS facilities.

(d) After completion of end-to-end tests, it shall be confirmed all permanent settings are

restored and temporary links etc. normalised, as required for energisation.

(e) End to End test shall be carried out according to the Employer’s Protection Relay Test

Requirements




TPCI/T/01/22) 42

5.6 ON-LOAD TESTS

(a) On energizing of Plant, measurements shall be made on all associated CTs and

circuits of the plant.

(b) For voltage circuits the following secondary measurements and tests shall be carried

out at the source e.g. MK and at the component end e.g. protection relays,

instruments, recorders and etc.

i. all phase-to-phase voltage measurement;

ii. All phase to neutral voltage measurement;

iii. All phase to ground voltage measurements;

iv. All phase sequence tests;

v. phasing test (if reference bay is viable).

(c) For current circuits the following secondary measurements shall be carried out at the

component end, such as protection relays, instruments, recorders and associated

control devices.

i. all phase current measurement

ii. All neutral current measurement

(d) For all protection with specific operation direction “DEF, DOC” directional tests shall

be performed.

(e) For all protection relays with built-in instrument functions, all measurement reading

available from the relay shall be recorded.

(f) All fault recorders to be manually triggered and printout of this shall be documented.

(g) For CB with synchronizing facilities phase concurrence of VT secondary circuits shall

be checked with a closed-circuit breaker, then (and only then) all the following

closing conditions shall be tested from REMOTE and SUPERVISORY.

i. Live line – live bus

ii. Live line – dead bus

iii. Dead line – live bus

(h) For transformer, the on-load tap changer facility shall be checked e.g. parallel

operation, independent operation, auto tap raising and lowering.




TPCI/T/01/22) 43

(i) Monitoring of the performance of the substation metering facilities during ongoing

commissioning of the plant.

(j) All the above checks and tests shall be documented clearly as part of the

commissioning test report.




TPCI/T/01/22) 44

6 LOCAL TECHNICAL SUPPORT

(a) The contractor shall provide local technical support to Employer at all times with regards

to the entire proposed protection relay systems. The contractor shall submit to Employer

three names including the contact number of their local support based in Malaysia.

7 PAYMENT TERMS

(a) Payment shall be made in the following manner the Contract Price adjusted to give effect

to such additions thereto and such deductions therefrom as are provided for in this

Contract. For all payments, 10% of the payment value will be hold as retention sum.

i. 100 per cent of the CIF Definite Work value of the Contract, within 45 days after

presentation to the Employer of site receiving inspection, certificate or the Interim

Certificates issued by the Engineer and shipping document as appropriate.

ii. 100 per cent of the LTE and civil works costs, within 45 days after presentation to

the Employer of the Interim Certificated issued by Engineer.

iii. 2.5 percent retention sum (from each payment) within 45 days after presentation

to the Employer of the Provisional Acceptance Certificate issued by the Engineer.

iv. 2.5 percent retention sum (from each payment) within 45 days after presentation

to the Employer of the Final Acceptance Certificate issued by the Engineer.

(b) The Contractor shall submit an invoice for each Interim Payment.

8 PROJECT COMPLETION DURATION

(a) The duration of the Contract commencing 14 days from the date of official notice from

Employer until commissioning shall be less than 18 calendar months. The Contractor

shall summit details of the program for the complete system project.




TPCI/T/01/22) 45

9 APPENDIX

9.1 ACCEPTED RELAY LIST

9.2 TRANSIENT NETWORK ANALYSER TEST PLAN

9.3 PROTECTION RELAY TEST REQUIREMENT

**Kindly Refer to all Three (3) Document attached at the end of this document.

Part I – Tender Procedures






SECTION 2 – TENDER PARTICULARS

These Tender Particulars specify matters particular to this tender process and should be read

in conjunction with the Instructions to Tenderers set out in Part I, Section 3 of the Tender

Documents.

Part I, Section 3 – Instructions to Tenderers



TPCI/T/01/22) 1

Tender Particulars

Tender for Supply, Delivery, Installation, Testing and Commissioning of Main 2 Current Differential Protection Relays for OHL 1 and 2 Linking Kemantan and Sarikei 132kV

Substations.

No. Clause Reference

Description Details

1. Clause Error! Reference source not found.

Closing Date and Time 3:00 pm on 23rd March 2022


Eligibility Requirements

Eligibility Requirements include: UPKJ Works: Electrical Works Class: I Heads: VIIB SUB-HEAD 4a

3. Clause Error! Reference source not found. and Clause Error! Reference source not found.

Sarawak Energy’s Representative

Name and designation: Chia Min Piau (TE) Contact details: 019-8596342 Email: [email protected] Name and designation: LAU LI CHUAN (EE) Contact details: 019-8111247 Email: [email protected]


Tender Validity Period The period commencing from the Closing Date and Time and expiring on the date falling [one hundred and eighty (180)] days from the Closing Date and Time

5. Clause Error! Reference

Tender Briefing A tender briefing will be conducted as

follows:






TPCI/T/01/22) 2

Tender Particulars


Substations.

source not found.

The date and time for the tender briefing

is: Not Applicable

The location for the tender briefing is:

Not Applicable


Site Visit A site visit will be conducted as follows:

The date and time for the Site visit is:

To be advised upon request

The meeting point for the purposes of the

Site visit is:

To be advised upon request


Pricing Method Lump Sum


Value of Tender Security

I. Sarawakian Tenderers – Tender Security Waived.

II. Local Tenders (Malaysian except for Sarawakian Tenderers) – for estimated Tender Sum of above RM 2,000,000, the amount of Bid Bond shall be 2% of the tender sum subject to a maximum of RM100,000.

III. International Tenders - the amount shall be 5% of the Tender Sum subject to a maximum of RM1,000,000.

NOTE:

A scanned copy of the Tender Security shall be submitted digitally in SEPRO, and




TPCI/T/01/22) 3

Tender Particulars


Substations.

the original copy shall be submitted to the respective tender offices.

9. Clause 32 Format of Tender Offer Tenderers to submit the Tender Offer

online with all the required documents

including scanned copies of Tender

Securities where applicable, by uploading

the said documentation in SEPRO on or

before the tender Closing Date and Time.

10. Clause 34 Address for submission of Tender Offers

Tenderers to complete the Event Contents

by way of “Submit Entire Response” by the

Closing Date and Time.

11. Clause 35.1 Alternative Tender Offers

Tenderers may not submit Alternative Tender Offers.

ISSUED BY Protection, Control & Instrumentation Division, Transmission Department

DATE ISSUED 22 November 2021

VERSION 2.6

SEB Accepted Relay List


The items shown in this SEB Accepted Relay List (ARL) includes protection relays, disturbance

recorders and ancillary equipment used for transmission and distribution substation. The list

stipulated in this document supersedes all preceding issues including revisions.

Any supplier/manufacturer who desire to have their items placed on the list, or any user believing

an existing item should be removed from the list, or any communication calling attention to an

error or omission in the list, such as an obsolete item, etc, should address to:

Attention: SEB ARL [Vice-President, Transmission for Chief Executive Officer]

Every effort has been made to ensure the accuracy of this document. However, in case of any discrepancies, records of Transmission Protection, Control & Instrumentation Division are the authoritative source.

Chief Executive Officer Sarawak Energy Berhad

Menara Sarawak Energy No. 1, The Isthmus, 93050 Kuching

Sarawak, MALAYSIA. Tel : +6 082-388388 Fax : +6082-389983 / +6082-344054


TABLE OF CONTENTS

1 Protection Relays ............................................................................................................ 1

1.1 Current Differential Relay ............................................................................................................. 1

1.2 Distance Protection Relay ............................................................................................................. 3

1.3 Transformer Bias Differential Protection Relay ............................................................................ 6

1.4 Restricted Earth Fault Protection Relay ........................................................................................ 9

1.5 Busbar Protection Relay .............................................................................................................. 10

1.6 Overcurrent and Earth Fault Protection Relay ............................................................................ 11

1.7 Directional Overcurrent and Earth Fault Protection Relay ......................................................... 12

1.8 Transformer Standby Earth Fault Protection Relay .................................................................... 13

1.9 Sensitive Earth Fault Protection Relay ........................................................................................ 14

1.10 Directional Sensitive Earth Fault Protection Relay ..................................................................... 15

1.11 Circuit Breaker Fail Protection Relay .......................................................................................... 16

1.12 Over/Under Frequency Protection Relay .................................................................................... 17

1.13 Over/Under Voltage Protection Relay ........................................................................................ 18

1.14 Shunt Reactor High Impedance Circulating Protection Relay ..................................................... 19

1.15 Autoreclose + Synchro-Check Relay ............................................................................................ 20

1.16 Synchro-Check Relay ................................................................................................................... 22

1.17 Capacitor Bank Protection Relay ................................................................................................. 23

1.18 Stub Protection Relay .................................................................................................................. 25

2 Disturbance Recorder .................................................................................................... 26

3 Ancillary Equipment ...................................................................................................... 27

3.1 Trip Circuit Supervision Relay ..................................................................................................... 27

3.2 Lockout Relay .............................................................................................................................. 28

3.3 Tripping Relay ............................................................................................................................. 29

3.4 Test Terminal Block ..................................................................................................................... 31

3.5 DC Supervision Relay ................................................................................................................... 33

4 Substation Interrogation and Monitoring System ............................................................ 34


1 November 22, 2021

1 Protection Relays

1.1 Current Differential Relay

Function Manufacturer

/Country Relay Model

Ordering Code Firmware Version Voltage Limit Remarks

Current Differential

ABB Power Grids /

Sweden RED670

RED670*2.2-F00X00-A00000000000001000- B41100000100000000110000000- C01000100100000000010000000-D11000010-T0000- E11000-F0-S0-G010-H00000000000-K01010110-L0000- M0010000-P00000000000000000-B1X0-CF-CB-B-A6X0- C❶-PXXXXXXXXAAXXY ❶ - BIM / BOM

2.2.5.11 (2.2.2.1)

500kV

1MRK002810-AG (Short Ordering Code for RED670) RED670*2.2-F00X00-A00000000000001000- B41100000100000000110000000- C01000100100000000010000000-D11000010-T0000- E11000-F0-S0-G010-H00000000000-K01010110-L0000- M0010000-P00000000000000000-B1X0-CF-CB-B-A6X0- CD1AAXX-PXXXXXXXXAAXXY

275kV and 132kV

Ordering code for RED670 V2.2 if the remote end is using RED670 V1.1 :- RED670*2.2-F00X00-A00000000010000100- B41100000100000000110000000- C01000100100000000010000000-D11000010-T0000- E11000-F0-S0-G010-H00000000000-K01010110-L0000- M0010000-P00000000000000000-B1X0-CF-CB-B-A6X0- CD1AAXX-PXXXXXXXXAAXXX


2 November 22, 2021




SIEMENS /

Berlin, Germany

7SD522 7SD5221-4PB99-9HK5+ M1A+ N2A+ LOR

4.72 500kV, 275kV

and 132kV

GE / Stafford,

UK P545 P54581◊A◊S0760M

76 (Firmware) M (Hardware)

500kV, 275kV and 132kV

• Mandatory Accessories & Software:-

(a) MiCOM S1 Agile Software Communication Converter 2Mbps (P591601A0M0200B)

Schneider Electric /

Wuxi, Jiang Su, China

P545

P54531EA3M0H99M-SEB (without IEC61850) P54531QA6M0H99M-SEB (with IEC61850)

H9 500kV, 275kV

and 132kV


(a) Easergy Studio Communication Converter 2Mbps (P-2M-L3A11A011A)

NR Electric /

Nanjing, China PCS-931

PCS-931-AACB-BA◊XXBBXBBD◊XA-EN-R3.40

3.30 (CRC:55A2D7DB)


• PCS Explorer V1.1.6 (Unlimited

License)

• Communication Converter 2Mbps (MUX-2M)

SIEMENS /

Berlin, Germany

7SD 610 7SD6101-◊BB09-0BJ0+M2◊ 4.74 33kV and

below P-Set 4.73



P521 P521B0◊Z112DG0-SEB DG (Software

Version) 33kV and

below


3 November 22, 2021

1.2 Distance Protection Relay



Ordering Code Firmware Version

Voltage Limit Remarks

Distance Protection

SIEMENS / Berlin,

Germany 7SA 612

7SA6121-4NB99+5GB4+ M1A+LOR

4.74 500kV, 275kV

and 132kV



P443

P44331E◊3M0 H99M-SEB (if more binary inputs are required and without IEC61850) P44331QF6M0H99M-SEB (with IEC-61850)

H9

500kV • Mandatory Accessories & Software:-

(a) Easergy Studio (b) Communication Converter

2Mbps (P-2M-L-3A11A011A)

P44331EF3M0H99M-SEB

275kV and 132kV

GE / Stafford,

UK Agile P443

P44381◊F◊S0760M

76 (Firmware) M (Hardware)



(a) Micom S1 Agile Software

Version 1.20 and above

(b) Communication Converter G.703 2Mbps (P591602A0M0200B)


4 November 22, 2021





ABB Power Grids /

Sweden REL670

REL670*2.2-F00X00-A00000000000000000- B00000000000001000120000000- C01000100100000000020000000-D11000020-T0000- E11000-F0-S0-G010-H00000000000-K01010110-L0000- M0010000-P00000000000000000-B1X0-CF-CB-B-A6X0- C❶-PXXXXXXXXAAXXX ❶ - BIM / BOM 2.2.5.11

(2.2.2.1)

500kV

1MRK002812-AG (Short Ordering Code for REL670) REL670*2.2-F00X00-A00000000000000000- B00000000000001000120000000- C01000100100000000020000000-D11000020-T0000- E11000-F0-S0-G010-H00000000000-K01010110-L0000- M0010000-P00000000000000000-B1X0-CF-CB-B-A6X0- CD1AAXX-PXXXXXXXXAAXXX

275kV and 132kV


5 November 22, 2021





NR Electric /

Nanjing, China PCS-902

PCS-902-AACB-BA◊XXBBXBBD◊XA-EN-R3.40

3.30 (CRC:925276E6)


• PCS Explorer V1.1.6 (Unlimited License)

• Communication Converter 2Mbps (MUX-2M)


6 November 22, 2021

1.3 Transformer Bias Differential Protection Relay




Voltage Limit

Remarks

Transformer Bias

Differential Protection

GE / Stafford, UK

P643

P64392◊F◊S0060M

06 (Firmware)

M (Hardware)

500kV, 275kV and

132kV • 3 Windings

SIEMENS / Berlin,

Germany 7UT613

7UT6131-4EB91-1AB0+LOR

4.65

500kV • B= for Over flux

• 2 & 3 Windings

7UT6131-4EB91-1AA0+LOR 275kV and

132kV • 2 & 3 Windings



P633

P633-8B991◊H0-315-430-672-701-921-SEB (500kV without IEC61850) P633-8B9910H0-315-430-672-701-971-SEB (500kV with IEC61850)

315-430-672-701


P633-8B9910H0-315-430-672-701-971-SEB (132kV and 275kV without IEC61850)

275kV and 132kV

• 3 Windings



P632 P632-8B9010F0-315-420-672-701-921-SEB 315-420-672-701

275kV and 132kV

• 2 Windings


7 November 22, 2021




Voltage Limit

Remarks

ABB Power Grids /

Sweden RET670

RET670*2.2-F00X00-A00001000000000000- B00000000000000000000000000- C01000100100000000010000000-D11010010-T0000- E00000-F0-S0-G000-H00000000000-K00000000-L0000- M0010000-P00000000000000000-B1X0-CF-CB-B-A3X0- CD1AXXX-PXXXXXXXXXXXXX

2.2.5.11 (2.2.2.1)


1MRK002816-AG (Short Ordering Code for RET670) RET670*2.2-F00X00-A00010000000000000- B00000000000000000000000000- C01000100100000000010000000-D11000010-T0000- E00000-F0-S0-G000-H00000000000-K00000000-L0000- M0010000-P00000000000000000-B1X0-CF-CB-B-A3X0- CD1AXXX-PXXXXXXXXXXXXX

275kV and 132kV

• 2 Windings

RET670*2.2-F00X00-A00001000000000000- B00000000000000000000000000- C01000100100000000010000000-D11010010-T0000- E00000-F0-S0-G000-H00000000000-K00000000-L0000- M0010000-P00000000000000000-B1X0-CF-CB-B-A3X0- CD1AXXX-PXXXXXXXXXXXXX

• 3 Windings


8 November 22, 2021




Voltage Limit

Remarks

NR Electric / Nanjing, China

PCS-978 PCS-978-ACCB-CBBXXXAAXAA-EN-R3.42 1.67

(CRC:9D86D08A)

500kV, 275kV and

132kV

• PCS Explorer V1.1.6

(Unlimited License)

SIEMENS (REYROLLE) /

Berlin, Germany or Goa, India

7SR24 7SR2422-2NA11-0BA0

R8e-7e 33kV and

below • 2 Windings

SIEMENS/ Berlin,

Germany 7UT613 7UT6131-◊EB02-1AA0 4.65

33kV and below



P631 P631-4B9000◊0-316-428-672-701-921-SEB

316-428-672-701

(Software Version)

33kV and below

ABB/ Finland RET 615 RET615 HBT DBABA NBA1 ANN ◊1G 5.0 FP1 (5.1.6)

33kV and below


9 November 22, 2021

1.4 Restricted Earth Fault Protection Relay




Restricted Earth Fault Protection



7SR1101

7SR1101-3◊A◊◊-2CA0 *Pos 11 & 12 for IEC 61850

R4K-3d 500kV and

below



P721 P721000Z112CB0-SEB 12.B 500kV and

below

GE / Stafford, UK

P14N-B

P14NB11A1B062BA (No IEC61850 Option) P14NB16A6C062BA (IEC61850 Option)

62 500kV and

below

ABB/ Finland REB611 REB611HBA ABA 1NN ◊1G 2.0

(2.0.1) 33kV and

below


10 November 22, 2021

1.5 Busbar Protection Relay




High Impedance

Busbar Protection



P723 723000Z112CB0-SEB 12.B 500kV and

below



7SR23

7SR2302-1NA77-0CA0D

7SR230◊ = If more BI/BO is required for 500KV installation

R8e-1c 500kV, 275kV

and 132kV

ABB Power Grids /

Sweden REB650

REB6501.3-A03X00-X00-B1X0-D-H-SA-E-SA1B1-A❶-F ❶ - BIM / BOM

1.3.5.1 (1.3.0.4)

500kV

REB6501.3-A03X00-X00-B1X0-D-H-SA-E-SA1B1-AX-F

275kV and 132kV

GE /Stafford, UK

P14N-B


62 500kV and

below



7SR23 7SR2302-1NA12-0CA0D R8e-1c 33kV and

below



1.6 Overcurrent and Earth Fault Protection Relay






P123 P123-B00- Z112-EB-0-SEB EB (Software

Version) 500kV and

below

Overcurrent and Earth

Fault Protection



7SR1103 7SR1103-1◊A◊◊-2CA0 *Pos 11 & 12 for IEC 61850

R4K-3d 500kV and

below

GE / Stafford,

UK P14N

P14NB1◊A◊◊0530A

53 500kV and

below

SEL / USA 751A

For 110Vdc, 1A model: 751A11D1D0X0X810610 For 110Vdc, 5A model: 751A11D1D0X0X850610

R419 500kV, 275kV

and 132kV

SIEMENS/

Berlin, Germany

7SJ612 7SJ6121-4EB91-1FA0+L0R 4.93 500kV, 275kV

and 132kV

ABB / Finland REF611 REF611 HBB ABA 1NA◊ 1G 2.0

(2.0.1)

275kV and below



1.7 Directional Overcurrent and Earth Fault Protection Relay







R4K-3d 500kV and

below

Directional Overcurrent

and Earth Fault

Protection



P127 P127-BA0- Z112-FE-0-SEB FE (Software

Version) 500kV and

below

GE / Stafford, UK

P14D P14DB1◊A◊C0530A

53 500kV and

below

SIEMENS/

Berlin, Germany

7SJ622 7SJ6221-4EB91-1FC0+L0R 4.93 500kV and

below

ABB / Finland REF 615 REF615 HBF FAEAG NBA1 ANA◊ 1G

5.0 FP1 (5.1.6)

275kV and below



1.8 Transformer Standby Earth Fault Protection Relay


/Country Relay Model Ordering Code Firmware Version

Voltage Limit

Remarks


Berlin, Germany or Goa, India)


R4K-3d 500kV and

below

Transformer Standby Earth

Fault protection

GE / Stafford, UK

P14N P14NB1◊A◊◊0530A 53 500kV and

below




Version) 33kV and

below



1.9 Sensitive Earth Fault Protection Relay




Sensitive Earth Fault Protection

SIEMENS / Berlin,

Germany 7SJ612 7SJ6122-◊EB92-1FB0 4.93

33kV and below


Berlin, Germany or Goa, India)

7SR1101 7SR1101-3◊A12-2CA0 R4K-3d 33kV and

below


China P122 P122-C00-Z112-EC-0-SEB EC (Software Version)

33kV and below



1.10 Directional Sensitive Earth Fault Protection Relay




Directional Sensitive

Earth Fault Protection


China P127

P127CA0Z112FE0-SEB

15.E 33kV and

below



1.11 Circuit Breaker Fail Protection Relay

Function Manufacturer/

Country Relay Model


Voltage Limit

Remarks



P821 P821B00Z112AE0-SEB 10.E 500kV and

below

Circuit Breaker Failure

Protection

SIEMENS / Berlin, Germany

7VK611 7VK6111-4AB91-4YC0+L0R 4.71 500kV,

275kV and 132kV

ABB Power Grids / Sweden

REQ650

REQ650*1.3-A11X00-X00-B1X0-D-❶-S❷-E-SA3-AA❸-F ❶ - Mounting details ❷ - PSM ❸ - BIM /BOM

1.3.5.1 (Firmware)

1.3.0.4 (Product Version)

500kV

REQ650*1.3-A11X00-X00-B1X0-D-❶-S❷-E-SA3-AAXX-F ❶ - Mounting details ❷ - PSM

275kV and 132kV

GE /Stafford, UK P841 P84191◊A◊S081AM 81 500kV,

275kV and 132kV

SEL /USA 751A

For 110Vdc, 1A model: 751A11D1D0X0X810610 For 110Vdc, 5A model: 751A11D1D0X0X850610

R419 33kV and

below

SIEMENS /


7SR1103 7SR1103-1◊A12-2CA0 R4K-3d 33kV and

below



1.12 Over/Under Frequency Protection Relay


Country Relay Model


Over / Under

Frequency

SEL /USA 751A For 110Vdc model: 751A11D1D0X73810610

R419 500kV and

below

Schneider Electric / China

P3U30

P3U30-6AAA2BBBM (without IEC61850) P3U30-6AAA2BCBM (with IEC 61850)

30.108 500kV and

below


or Goa, India

7RW 7RW8020-5EB96-1DA0+L0R 4.62 500kV, 275kV

and 132kV

7RW 7RW8020-5EB00-1DA0 4.62 33kV and below



1.13 Over/Under Voltage Protection Relay




SEL /USA 751A For 110Vdc model: 751A11D1D0X73810610

R419 500kV and

below

SIEMENS

(REYROLLE) / Goa, India

7SR158 7SR1587 – 5HA12-2DA0/BB 2436H80011R4e-2a 500kV and

below

Over / Under

Voltage


P3U30

P3U30-6AAA2BBBM (without IEC61850) P3U30-6AAA2BCBM (with IEC 61850)

30.108 500kV and

below

SIEMENS / Berlin,

Germany or Goa, India

7RW 7RW8020-5EB96-1DA0+L0R 4.62 500kV, 132kV

and 132kV



1.14 Shunt Reactor High Impedance Circulating Protection Relay


Country Relay Model


Shunt Reactor

High Impedance Circulating Protection



7SR23

7SR2302-1NA77-0CA0D (Transmission) 7SR2302-1NA12-0CA0D (Distribution)


R8e-1c 500kV and

below


P723 P723000Z112CB0-SEB 12.B 500kV and

below

GE / Stafford, UK P14N-B


62 500kV and

below



1.15 Autoreclose + Synchro-Check Relay


Country Relay Model


Autoreclose + Synchro-

check

SIEMENS/ Berlin, Germany

7VK 7VK6111-4AB91-4YN0+LOR 4.71 500kV, 275kV

and 132kV



P841

P841311A3M0G79M-SEB (without IEC61850) P84131QA6M0G79M-SEB (with IEC61850)

G7 500kV, 275kV

and 132kV


REQ650

REQ650*1.3-A11X00-X00-B1X0-D-❶-S❷-E-SA3-AA❸-F ❶ - Mounting details ❷ - PSM ❸ - BIM /BOM

1.3.5.1 (1.3.0.4)

500kV

REQ650*1.3-A11X00-X00-B1X0-D-❶-S❷-E-SA3-AAXX-F ❶ - Mounting details ❷ - PSM

275kV and 132kV

GE / Stafford, UK

P841

P84191◊A◊S081AM

81 500kV, 275kV

and 132kV




Country Relay Model





Version) 33kV and below

SEL /USA 751A 751A6◊◊◊◊0X◊◊8◊0◊◊0 R419 33kV and below


or Goa, India) 7SR1103 7SR1103-1◊A12-2DA0 R4K-3d 33kV and below



1.16 Synchro-Check Relay


Country Relay Model


Synchronising Check


P3U30 P3U30-6AAA2BBBM (without IEC61850)

30.108 500kV and

below

SIEMENS/ Berlin, Germany

7VK 7VK6101-4AB91-4YN0+LOR 4.71 500kV, 275kV

and 132kV



P841

P841311A3M0G79M-SEB (without IEC61850) P84131QA6M0G79M-SEB (with IEC61850)

G7 500kV, 275kV

and 132kV

SIEMENS / Berlin,


7RW 7RW8020-5EB96-1DC0+L0R 4.62 500kV, 275kV

and 132kV


Goa, India 7SR157 7SR1578-5HA12-2CAO/BB 2436H80010R4e-2a

275kV and below

SIEMENS / Berlin,


7VK 7VK6101-◊AB02-4YN0 4.71 33kV and below

SIEMENS / Berlin,


7RW 7RW8020-5EB00-1DC0 4.62 33kV and below

SEL /USA 751A 751A5◊◊◊◊0X728◊0◊◊0 R419 33kV and below



1.17 Capacitor Bank Protection Relay


Country Relay Model



Capbank Overall Differential Protection


RET670

RET670*1.2-A30X00-D03-B1X0-AF-KB-B-A3-❶-XXX-XD ❶ - BIM / BOM

1.2

500kV

1MRK 004 816-AC (Short Ordering Code for Capbank RET670) RET670*1.2-A30X00-D03-B1X0-AF-KB-B-A3-DIAA-XXX-XD

275kV and 132kV

SIEMENS /

Berlin, Germany 7UT613 7UT6131-4EB91-1AA0+LOR 4.65




7SR23 7SR2303-1◊A◊◊-0CA0 R8e-1c 500kV, 275kV

and 132kV

1. Capacitor unbalance

2. Thermal overload protection

3. Reactor thermal overload protection

4. Resistor thermal overload

5. Resistor open circuit protection


Goa, India 7SR191

7SR1916-1HA12-2CAO (no IEC 61850) 7SR1916-1HA77-2CA0 (with IEC 61850)

R4e-2a 500kV, 275kV

and 132kV

• Function: a) Capacitor Bank

Unbalance Protection




Country Relay Model



SIEMENS


7SR1206

7SR1206-2◊A◊◊-2CA0 *Pos No 11 & 12 option for IEC 61850

R4K-3d 500kV, 275kV

and 132kV

• Function: a) Reactor Thermal

Overload Protection

SIEMENS


7SR1103 7SR1103-1◊A◊◊-2CA0 *Pos No 11 & 12 option for IEC 61850

R4K-3d 500kV275kV,

and 132kV

• Function: a) Resistor Thermal

Overload Protection b) Resistor Open Circuit

Protection

1. Capacitor unbalance/ thermal overload protection

2. Reactor thermal overload protection

3. Resistor thermal overload /open circuit protection

TRENCH /Austria

CPR 04 CPR4-00-110 4v81

(Software Version: 5v1)

275kV and 132kV

• Function: (a) Capacitor Bank

Unbalance Protection (b) Capacitor Bank

Thermal Overload Protection

(c) Reactor Thermal Overload Protection

(d) Resistor Thermal Overload Protection

(e) Resistor Open Circuit Protection

Schneider

Electric / China P3U30

P3U30-6AAA2BBBM (without IEC61850)

30.108 500kV and

below

• Function: (a) Capacitor Bank

Unbalance Protection (b) Capacitor Bank

Thermal Overload Protection



1.18 Stub Protection Relay


Country Relay Model



GE / Stafford,

UK P14N P14NB1◊A◊◊0530A 53

500kV and 275kV



P723 P723000Z112CB0-SEB 12.B 500kV and

275kV

Stub Protection



7SR23

7SR2302-1NA77-0CA0D


R8e-1c 500kV and

275kV

ABB / Sweden REB650

REB6501.3-A03X00-X00-B1X0-D-H-SA-E-SA1B1-A❶-F ❶ - BIM /BOM

1.3.5.1 (1.3.0.4)

500kV and 275kV



2 Disturbance Recorder


Country Model Ordering Code Firmware Version Voltage Limit Remarks

Disturbance Recorder

QUALITROL / Northern Ireland

BEN 6000 BEN 6000 2.5.25 500kV and

below

SIEMENS/Berlin, Germany

7KE85

7KE85-JAAA-AA0-0AAAA0-AA8111-13113A-AAA000-000AC1-CB1BA1-CB1CB1-

CB1CB1-BC1CG0-◊◊◊

7.50 500kV and

below

• Mandatory Accessories & Software: -

(a) DIGSI 5 software premium (b) SICAM PQ Analyzer (PQA)

software Ver 3.17 (c) SICAM PQS/PAS (Data

Concentrator) Ver 8.17 (d) GPS Clock

(e) Ethernet Switch

NR Electric / China

PCS-996 PCS-996RC-R4.08 PCS-996RA-4.08

4.08 (CRC: B703A1A0)


• Mandatory Accessories & Software: -

(a) PCS-PC5 Tools Software (b) DFR Manager Software

(c) DFR Helper (d) GPS Clock NR PCS-9785



3 Ancillary Equipment

3.1 Trip Circuit Supervision Relay


Country Model Ordering Code Voltage Limit Remarks

Trip Circuit Supervision

GE / Stafford, UK MVAX31 MVAX31S1DE0754A

500kV and below

SIEMENS / Europe

7PA3032 7PA3032-1AA00-1

500kV and below

(a) Single phase

Schneider Electric / Spain

REL913 REL91323

500kV and below

RMS / Australia ALPHA

XR5-◊◊ -1/4/6◊ (ALPHA XR Series)

500kV and below

ARTECHE / Spain VDF VDF10 500kV and

below

ABB / Sweden SPER IBI -

33kV and below



3.2 Lockout Relay



Lockout

GE / Stafford, UK MVAJ105 MVAJ105RA0802B 500kV and

below (a) Voltage rating: 110/125V

SIEMENS / Europe

7PA2231 7PA2◊◊1-1 500kV and

below

RMS/ Australia ALPHA/

DELTA/ 6RJ

TR 5/12 - ◊◊ - 1/2/3/4 ◊ (ALPHA TR Series)

500kV and below

AR 5/12 - ◊◊ - 1/2/3/4 ◊ (ALPHA AR Series- 1 element)

AR25 - ◊◊ - 1/2/3/4 ◊ (ALPHA AR Series- 2 element)

TRD-4◊◊ (DELTA TRD Series)

6RJ25-20-◊◊ (6RJ Series)


REL912

REL91263 (4 changeover contacts) 500kV and

below

REL91283 (8 changeover contacts)

ARTECHE / Spain B◊◊RP

BF4RP (4 changeover contacts)

500kV and below

BJ8RP (8 changeover contacts)

BJ10RP (10 changeover contacts)



3.3 Tripping Relay



Tripping

ABB / India ABB RXMS RXMS1 RK216 x63-AN 500kV and

below

SIEMENS/ Europe

7PA2732 7PA2◊◊2-0AA00-◊ 500kV and

below

SIEMENS/ Berlin,


TR221 7PG1522-1HA40-1AF0 500kV and

below

AR ◊11 7PG11◊1-1EA10-0C◊0

RMS/ Australia ALPHA/ DELTA

TR 5/12 - ◊◊ - 1/2/3/4 ◊ (ALPHA TR Series)

500kV and below

AR 5/12 - ◊◊ - 1/2/3/4 ◊ (ALPHA AR Series- 1 element)

AR 25 - ◊◊ - 1/2/3/4 ◊ (ALPHA AR Series-2 element)

TRD-4◊◊ - (DELTA TRD Series)


REL912

REL91203 (4 changeover contacts)

500kV and below

REL91223 (Fast trip relay with 4 changeover contacts)





GE / Stafford, UK MVAJ05

MVAJ051RA08◊◊B (5 Contact)

500kV and below

MVAJ101RA08◊◊A (10 Contact)

ARTECHE / Spain R◊◊R

OP01◊◊◊

RF4R OP01◊◊◊ (4 changeover contacts)

500kV and below

RJ8R OP01◊◊◊ (8 changeover contacts)

RI16R OP01◊◊◊ (16 changeover contacts)



3.4 Test Terminal Block



Test Terminal Block

ABB / India RTXP 18/24

a) Test Socket:

i. RTXP 18 RK926-115-◊◊

ii. RTXH 24 RK926 315-◊◊ b) Test Plug:

i. RTXH 18 RK926 011-BC ii. RTXH 24 RK926 016-AA

500kV and below

GE / Stafford, UK MMLG01 • Test Block: MMLG01R1AB0001E

• Test Plug: MMLB01AXAA0011E

500kV and below



2RMLG07 • Test Socket: 7XG2220-3AA00-0AA0

• Test Plug: 7XG2240-3AA00-0AA0


RMS/ Australia 4M Series • Test Socket: 4M400-◊◊

• Test Plug: 4M42◊-◊


Schneider Electric / Spain ETB14 • Test Socket: ETB14◊◊◊◊◊◊◊◊◊◊◊◊◊◊-V

• Test Plug: ETB14PV

500kV and below

ARTECHE / Spain TSB14

• Test Block:

TSB-14-◊◊◊◊◊◊◊◊◊◊◊◊◊◊-V

(Ordering Code for Manual CT Shorting:

TSB-14-11111111111111-V)

• Test Plug: TSB-14-P-V

500kV and below

Manual CT Shorting is required for 33kV and

below





ARTECHE / Spain TSB18

• Test Block:

TSB-18-◊◊◊◊◊◊◊◊◊◊◊◊◊◊◊◊◊◊-V

(Ordering Code for Manual CT Shorting:

TSB-18-111111111111111111-V)

• Test Plug: TSB-18-P-V

500kV and below

Manual CT Shorting is required for 33kV and

below



2RMLG01 • Test Socket: 7XG2220-1AA00-0AA0

• Test Plug: 7XG2240-1AA00-0AA0

33kV and below

RMS / Australia 4M Series • Test Block: 4M200-01

• Test Plug: 4M220-00

33kV and below



3.5 DC Supervision Relay



DC Supervision



XR152 7PG1741-3BD10-4AA0 500kV and

below


REL913 REL91344 500kV and

below

RMS / Australia Delta XRD

Series XRD-4◊◊

500kV and below

GE / Stafford, UK MVAX12 MVAX12R1CB075◊A 500kV and

below

ARTECHE / Spain RUT4 RUT4OP 500kV and

below



4 Substation Interrogation and Monitoring System Function Manufacturer/


Substation

Interrogation

and Monitoring

system

Malaysia

Advance

Remote

Access

Commander

(ARAC)

NA 132kV and above

• Mandatory Accessories &

Software:

a) ARAC Interrogation

Software

Important Note:

1. The recommended relay ordering no. indicated by ◊ are to be specified based on actual installation requirement / SEB application. 2. The protection relay manufacturer/supplier shall provide 10 years product warranty from the date of supply. Faulty relays shall be

collected from and replacement shall be delivered to SEB office without cost to SEB. 3. The Disturbance recorder manufacturer/supplier shall provide 5 years product warranty from the date of supply. Faulty disturbance

recorders shall be collected from and replacement shall be delivered to SEB office without cost to SEB. 4. The ancillary equipment manufacturer/supplier shall provide 5 years product warranty from the date of supply. Faulty ancillary

equipment shall be collected from and replacement shall be delivered to SEB office without cost to SEB.

Protection, Control & Instrumentation—Protection Relay RTDS Test Plan

SARAWAK ENERGY BERHAD

Line Protection Relay

Real Time Digital Simulation Test Plan

VERSION NO:

4.0

DATE: 27th May 2021

Protection, Control & Instrumentation—Protection Relay RTDS Test Plan

1

F11

GA

Fault Location

Note:

GA, GB : Source F1 : 0.1% F2 : 30% F3 : 70% F4 : 99.9% F5 : Fault on Left side Busbar F6 : Fault on Right side Busbar F7 : 0.1% on Parallel line F8 : 30% on Parallel line

F9 : 70% on Parallel line F10 : 99.9% on Parallel line F11 : 50% on Left Adjacent Longest Line F12 : 50% on Right Adjacent Longest Line F13 : Fault on Left Side Transformer LV Side F14 : Fault on Right Side Transformer LV Side F15 : Fault on Left Side Transformer HV Side F16 : Fault on Right Side Transformer HV Side

*All Test with Auto-Recloser in 1+3Pole Mode. Signals to be monitor for each side

CB Trip R Trip Lockout

CB Trip Y DEF Pickup Forward

CB Trip B DEF Pickup Reverse

DEF Carrier Received DEF Operated

DEF Carrier Send AR Operated

SOTF (Impedance) Operated AR Blocked

SOTF (Differential) Operated EF Blocked

Differential Trip Differential Lowset

Distance Z1 Pickup Differential Highset

Distance Z1 Trip Negative Sequence (Trip Enhanced)

Distance Z2 Pickup Distance R-ph Carrier Received

Distance Z2 Trip Distance R-ph Carrier Send

Distance Z3 Pickup Distance Y-ph Carrier Received

Distance Z3 Trip Distance Y-ph Carrier Send

Distance Z4 Pickup Distance B-ph Carrier Received

Distance Z4 Trip Distance B-ph Carrier Send

RELAY A LEFT SIDE

CB1B

F1 F2 F3 F4 F6 F5

F7 F8 F9 F10

LINE 1 CB1A

LINE 2 CB2B

CB2A

F14

F12

GB

RELAY B RIGHT SIDE

F13 F15 F16

Protection, Control & Instrumentation— Protection Relay RTDS Test Plan

2

No. Type of Fault: Line


Distance

1. Internal Fault with Successful Auto Reclose 1-12 1-12

2. Internal Resistive and High Resistive Fault with Unsuccessful Auto Reclose 13-23 13-36

3. Evolving fault 24-32 37-53

4.

Switch on to fault i. Switch on to fault with communication

a) Left Side Close onto fault 33-38 54-59

b) Right Side Close onto fault 39-44 60-65

ii. Switch on to fault without communication a) Left Side Close onto fault

45-50 66-71

b) Right Side Close onto fault 51-56 72-77

5. Permanent Metallic and High Resistive Faults on Protected Line without Communication

57-84 78-105

6. Busbar Fault, Parallel Line Open and Grounded with Communication Failure

85-96 106-117

7. Busbar Fault, Parallel Line in Service* 97-108 118-129

8. Permanent Metallic and Resistive Fault on Parallel Line (Parallel Line Unequal CB Opening Time)

109-122 130-143

9. Simultaneous Fault (Cross Country fault) 144-151

10.

External Permanent Metallic Fault on Adjacent Line and Remote End

Transformer LV Fault*

a) External Permanent Metallic Fault on Adjacent Line

123-130 152-159

b) Remote End Transformer LV Fault 131-138 160-167

c) Remote End Transformer HV Fault 139-146 168-175

11. Internal Fault with CT saturation 147-150 176-179 12. External Fault with CT saturation 151-154 180-183 13. Fault After Fuse Failure Monitor 155-156 184-185

14. Fault on parallel Line under heavily loaded condition, with successful Auto Reclose *

157-172 186-201

Notes:

*Not applicable for Product Approval TNA test.


3

1 Internal Fault with Successful Auto Reclose

Test Case : Internal Fault with Successful Auto Reclose

Fault Type : Transient Metallic Fault

Loading : Minimum Generation

Fault Duration : 0.3s

Expected Trip and Reclose Operation

:

Single Phase fault, trip faulted Phase and reclose

Phase-Phase Fault, trip three phase and reclose

Three Phase fault, no reclose

Possible Protection Operation : Current Differential Operation Distance Zone 1 Operation Distance Teleprotection Zone Operation

Test Case No. Fault Position Type of fault Rf [ohm] Angle [Degree]

Line Current Differential Distance

1. 1. F1 BG 0.05 0

2. 2. F1 BG 0.05 90

3. 3. F1 BC 0.05 0

4. 4. F1 BC 0.05 90

5. 5. F1 BCG 0.05 0

6. 6. F1 BCG 0.05 90

7. 7. F4 CG 0.05 0

8. 8. F4 CG 0.05 90

9. 9. F4 CA 0.05 0

10. 10. F4 CA 0.05 90

11. 11. F4 CAG 0.05 0

12. 12. F4 CAG 0.05 90


4

2 Internal Resistive and High Resistive Fault with Unsuccessful

Auto Reclose

Test Case : Internal Resistive and High Resistive Fault with Unsuccessful Auto Reclose

Fault Type : Permanent Resistive Fault

Loading : Maximum Generation

Fault Duration : 3s

Expected Result :

Single Phase fault, trip faulted phase, reclose and tripped three phases

Phase-Phase Fault, trip three phase and reclose and tripped three phases


Possible Protection

Operation :

Current Differential Operation Distance Zone 1 Operation Distance Teleprotection Zone Operation Directional Earth Fault (DEF) Operation



13. 13. F1 AG 0.05 90

14. 14. F1 AG 3 0

15. 15. F1 AG 10 90

16. 16. F1 AG 40 0

17. 17. F1 AG 80 90

18. 18. F1 AG 180 0

19. F2 BCG 0.05 90

20. F2 BCG 3 0

21. F2 BCG 10 90

22. F2 BCG 40 0

23. F2 BCG 80 90

24. F2 BCG 180 0

25. F3 CG 0.05 90

26. F3 CG 3 0

27. F3 CG 10 90

28. F3 CG 40 0

29. F3 CG 80 90

30. F3 CG 180 0

31. F4 ABG 0.05 0

19. 32. F4 ABG 3 90

20. 33. F4 ABG 10 0

21. 34. F4 ABG 40 90

22. 35. F4 ABG 80 0

23. 36. F4 ABG 180 90


5

3 Evolving Fault Test Case : Evolving Fault

Fault Type : Permanent Metallic Fault


Fault Duration : 3s

Expected Result : Trip faulted phase follow by tripped the other two phase and reclose

Possible Protection Operation

: Current Differential Operation Distance Zone 1 Operation Distance Teleprotection Zone Operation

Test Case No. FAULT 1 FAULT 2

Scenario Line


Distance Fault

Position Fault

Rf [ohm]

Fault Inception Angle[◦]

Fault Position

Fault Rf [ohm] Fault Inception

Angle [◦]

24. 37. F1 AG 0.05 0 F1 BG 0.05 0 Fault 2 in 10ms after F1




41. F2 BG 0.05 90 F2 CG 0.05 90 Fault 2 in 10ms after F1




45. F3 CG 0.05 0 F3 AG 0.05 0 Fault 2 in 10ms after F1




28. 49. F4 BG 0.05 90 F4 CG 0.05 90 Fault 2 in 10ms after F1






6

4 Switch On to Fault (SOTF) Test Case : Both Circuit Breakers are Open (Left Side Close Onto Fault)




Expected Operation : SOTF Operation and Trip Three Phase. No reclose.

Possible Protection Operation : Current Differential Operation Distance Zone 1 Operation Switch On to Fault Operation



33. 54. F1 AG 0.05 0

34. 55. F1 ABG 0.05 90

35. 56. F1 ABCG 0.05 0

36. 57. F4 AG 0.05 90

37. 58. F4 ABG 0.05 0

38. 59. F4 ABCG 0.05 90

Test Case : Both Circuit Breakers are Open (Right Side Close Onto Fault)





Possible Protection Operation : Current Differential Operation Distance Zone 1 Operation Switch On to Fault Operation



39. 60. F1 BG 0.05 0

40. 61. F1 BCG 0.05 90

41. 62. F1 ABCG 0.05 0

42. 63. F4 BG 0.05 90

43. 64. F4 BCG 0.05 0

44. 65. F4 ABCG 0.05 90


7

Test Scenario : Both Circuit Breakers are Open (Left Side Close Onto Fault) All Communication Fail, Backup Distance Protection Activated





Possible Protection Operation : Distance Zone 1 Operation Switch On to Fault Operation



45. 66. F1 AG 0.05 0

46. 67. F1 ABG 0.05 90

47. 68. F1 ABCG 0.05 0

48. 69. F4 AG 0.05 90

49. 70. F4 ABG 0.05 0

50. 71. F4 ABCG 0.05 90

Test Case : Both Circuit Breakers are Open (Right Side Close Onto Fault) All Communication Fail, Backup Distance Protection Activated





Possible Protection Operation : Distance Zone 1 Operation Switch On to Fault Operation



51. 72. F1 BG 0.05 0

52. 73. F1 BCG 0.05 90

53. 74. F1 ABCG 0.05 0

54. 75. F4 BG 0.05 90

55. 76. F4 BCG 0.05 0

56. 77. F4 ABCG 0.05 90


8

5 Permanent Metallic and High Resistive Faults on Protected Line

without Communication

Test Case : Permanent Metallic and High Resistive Faults on Protected Line

Fault Type : Permanent Metallic Fault and High Resistive Fault


Fault Duration : 3s

Expected

Operation

: Single Phase fault, trip faulted phase, reclose and tripped three phases

Phase-Phase Fault, trip three phase, reclose and tripped three phases

Trip three phase and no auto reclose (Zone 2,4 and DEF Operation)

Possible

Protection

Operation

:

Distance Zone 1 Operation Distance Zone 2 Operation Distance Zone 4 Operation Directional Earth Fault (DEF) Operation



57. 78. F1 AG 0.05 0

58. 79. F1 AB 0.05 90

59. 80. F1 ABG 0.05 0

60. 81. F1 ABCG 0.05 90

61. 82. F1 AG 10 0

62. 83. F1 AG 40 90

63. 84. F1 AG 80 0

64. 85. F2 BG 0.05 90

65. 86. F2 BC 0.05 0

66. 87. F2 BCG 0.05 90

67. 88. F2 ABCG 0.05 0

68. 89. F2 BG 10 90

69. 90. F2 BG 40 0

70. 91. F2 BG 80 90

71. 92. F3 CG 0.05 0

72. 93. F3 CA 0.05 90

73. 94. F3 CAG 0.05 0

74. 95. F3 ABCG 0.05 90

75. 96. F3 CG 10 0

76. 97. F3 CG 40 90

77. 98. F3 CG 80 0

78. 99. F4 BG 0.05 90

79. 100. F4 BC 0.05 0

80. 101. F4 BCG 0.05 90

81. 102. F4 ABCG 0.05 0

82. 103. F4 BG 10 90

83. 104. F4 BG 40 0

84. 105. F4 BG 80 90


9

6 Busbar Faults, Parallel Line Open and Grounded with

Communication Failure

Test Case : Busbar Faults, Parallel Line Open and Grounded with Communication Failure



Fault Duration : 3s

Expected Operation : Trip three phase and no auto reclose


: Distance Zone 2 Operation Distance Zone 4 Operation Directional Earth Fault (DEF) Operation



85. 106. F5 AG 0.05 0

86. 107. F5 AB 0.05 90

87. 108. F5 ABG 0.05 0

88. 109. F5 ABCG 0.05 90

89. 110. F5 AG 3 0

90. 111. F5 AG 10 90

91. 112. F6 BG 0.05 0

92. 113. F6 BC 0.05 90

93. 114. F6 BCG 0.05 0

94. 115. F6 ABCG 0.05 90

95. 116. F6 BG 10 0

96. 117. F6 BG 3 90


10

7 Busbar Faults, Parallel Line in Service

Test Case : Busbar Faults, Parallel Line in Service



Fault Duration : 3s

Expected Operation : Trip three phase and no auto reclose

Possible Protection Operation : Distance Zone 2 Operation

Distance Zone 4 Operation Directional Earth Fault (DEF) Operation



97. 118. F5 AG 0.05 0

98. 119. F5 AB 0.05 90

99. 120. F5 ABG 0.05 0

100. 121. F5 ABCG 0.05 90

101. 122. F5 AG 3 0

102. 123. F5 AG 10 90

103. 124. F6 BG 0.05 0

104. 125. F6 BC 0.05 90

105. 126. F6 BCG 0.05 0

106. 127. F6 ABCG 0.05 90

107. 128. F6 AG 3 0

108. 129. F6 AG 10 90


11

8 Permanent Metallic and Resistive Fault on Parallel Line

(Parallel Line Unequal CB Opening Time)

Test Case : External Permanent Metallic and Resistive Fault on Parallel Line (Parallel Line CB Open)

Fault Type : Permanent Metallic Fault and High Resistive Fault CB’s of parallel line open at 65/40ms



Expected Operation : No Tripping


: No protection operates



109. 130. F7 AG 0.05 0

110. 131. F7 AG 10 90

111. 132. F7 AB 0.05 0

112. 133. F7 ABG 0.05 90

113. 134. F7 ABG 10 0

114. 135. F7 ABCG 0.05 90

115. 136. F7 ABCG 3 0

116. 137. F10 AG 0.05 90

117. 138. F10 AG 10 0

118. 139. F10 AB 0.05 90

119. 140. F10 ABG 0.05 0

120. 141. F10 ABG 10 90

121. 142. F10 ABCG 0.05 0

122. 143. F10 ABCG 3 90


12

9 Simultaneous Faults (Cross Country Faults)

Test Case : Simultaneous Faults (Cross Country Faults)

Fault Type : Transient Metallic Fault on Protected and on Parallel Line CB’s of parallel line will open and clear fault



Expected Operation : Single Phase fault, trip faulted Phase and reclose


Distance Teleprotection Zone Operation

Test Case No. FAULT 1 FAULT 2

Line Current

Differential Distance

Fault Position Fault

Rf [ohm]

Fault Inception

Angle [◦]

Fault Position

Fault Rf

[ohm]

Fault Inception

Angle [◦]

144. F1 AG 0.05 0 F7 BG 0.05 0

145. F1 BG 0.05 90 F7 AG 0.05 90

146. F2 AG 0.05 0 F8 BG 0.05 0

147. F2 BG 0.05 90 F8 AG 0.05 90

148. F3 AG 0.05 0 F9 BG 0.05 0

149. F3 BG 0.05 90 F9 AG 0.05 90

150. F4 AG 0.05 0 F10 BG 0.05 0

151. F4 BG 0.05 90 F10 AG 0.05 90


13

10 External Permanent Metallic Fault on Adjacent Line and

Remote End (Transformer LV Fault)

a) External Permanent Metallic Fault on Adjacent Line Test Case : External Permanent Metallic Fault on Adjacent Line

Fault Type : Metallic Fault


Fault Duration : 3s

Expected Operation : No Operation Three phase trip and no reclose


Distance Zone 4 Operation Directional Earth Fault Operation



123. 152. F11 AG 0.05 0

124. 153. F11 AB 0.05 90

125. 154. F11 ABG 0.05 0

126. 155. F11 ABCG 0.05 90

127. 156. F12 AG 0.05 0

128. 157. F12 AB 0.05 90

129. 158. F12 ABG 0.05 0

130. 159. F12 ABCG 0.05 90

b) Remote End Transformer LV Fault Test Case : Remote End Transformer LV Fault

Fault Type : Permanent Metallic Fault at Remote End Transformer LV Left and Right Side


Fault Duration : 3s

Expected Operation : No Operation Three phase trip and no reclose

Possible Protection Operation : Directional Earth Fault Operation



131. 160. F13 AG 0.05 0

132. 161. F13 AB 0.05 90

133. 162. F13 ABG 0.05 0

134. 163. F13 ABCG 0.05 90

135. 164. F14 AG 0.05 0

136. 165. F14 AB 0.05 90

137. 166. F14 ABG 0.05 0

138. 167. F14 ABCG 0.05 90


14

c) Remote End Transformer HV Fault Test Case : Remote End Transformer HV Fault

Fault Type : Permanent Metallic Fault at Remote End Transformer HV Left and Right Side


Fault Duration : 3s

Expected Operation

: No Operation Three phase trip and no reclose


: Distance Zone 2 Operation Distance Zone 4 Operation Directional Earth Fault Operation



139. 168. F15 AG 0.05 0

140. 169. F15 AB 0.05 90

141. 170. F15 ABG 0.05 0

142. 171. F15 ABCG 0.05 90

143. 172. F16 AG 0.05 0

144. 173. F16 AB 0.05 90

145. 174. F16 ABG 0.05 0

146. 175. F16 ABCG 0.05 90


15

11 Internal Fault with CT Saturation

Test Case : Internal Fault with CT Saturation

Fault Type : Permanent Metallic Faults on the Line With CT Saturation


Fault Duration : 3s


: Single Phase fault, trip faulted Phase and reclose






147. 176. F1 AG 0.05 0

148. 177. F4 AG 0.05 90

149. 178. F1 ABC 0.05 0

150. 179. F4 ABC 0.05 90

12 External Fault with CT Saturation

Test Case : External Fault with CT Saturation

Fault Type : Permanent Metallic Faults on the Line With CT Saturation


Fault Duration : 3s


: No operation


: No protection operation



151. 180. F11 AG 0.05 0

152. 181. F11 ABCG 0.05 90

153. 182. F12 AG 0.05 0

154. 183. F12 ABCG 0.05 90


16

13 Fault After Fuse Failure Monitor

Test Case : Fault After Fuse Failure Monitor

Fault Type : Permanent Metallic Faults on the Line With Fuse Failure Operate


Fault Duration : 3s


: Single Phase fault, trip faulted Phase and reclose






155. 184. F1 AG 0.05 0

156. 185. F4 ABCG 0.05 90


17

14 Fault on parallel line under heavily loaded condition with

successful Auto Reclose

Test Case : Fault on parallel line under heavily loaded condition with successful Auto Reclose

Fault Type : Transient Metallic Fault

Loading : Heavily Loaded Network

Fault Duration : 3s


: No operation


: No protection operation



157. 186. F7 AG 0.05 0

158. 187. F7 AB 0.05 90

159. 188. F7 ABG 0.05 0

160. 189. F7 ABC 0.05 90

161. 190. F7 ABCG 0.05 0

162. 191. F8 BG 0.05 90

163. 192. F8 BC 0.05 0

164. 193. F8 ABC 0.05 90

165. 194. F9 BG 0.05 0

166. 195. F9 BC 0.05 90

167. 196. F9 ABC 0.05 0

168. 197. F10 AG 0.05 90

169. 198. F10 AB 0.05 0

170. 199. F10 ABG 0.05 90

171. 200. F10 ABC 0.05 0

172. 201. F10 ABCG 0.05 90

Transmission Protection, Control & Instrumentation – Protection Relay Testing Requirements

Transmission Protection, Control and Instrumentation Division

Transmission Protection Relay Testing Requirement Version 3.2 6th August 2018


Page 1

Terminology

All fault types : Include all Ph-G, Ph-Ph, 3Ph fault

Ph-G : Includes all single phase to ground fault – R-G, Y-G, B-G

Ph-Ph : Includes all phase to phase fault- R-Y, -Y-B, B-R

3Ph : Three phase fault – RYB

DOC : Directional Overcurrent

DEF : Directional Earth Fault

REF : Restricted Earth Fault

SBEF : Standby Earth Fault

CB : Circuit Breaker

CBF : Circuit Breaker Failure

AR : Auto Reclose

CT : Current Transformer

VT : Voltage Transformer


Page 2

Table of Contents

Terminology ............................................................................................................................................ 1

1. Distance Protection Relay .......................................................................................................... 3

2. Line Differential Protection Relay ....................................................................................................... 7

3. Biased Differential Protection Relay ........................................................................................ 13

4. Directional Overcurrent / Directional Earth Fault (DOC / DEF) Protection Relay .................... 16

5. Non Directional Overcurrent / Non Directional Earth Fault (OC / EF) Protection Relay .......... 18

6. Autoreclose (AR) and Synchronising Check Relay .................................................................... 20

7. Breaker Fail Protection Relay ................................................................................................... 23

8. Busbar Protection (BBP) and CT Supervision (Main and Duplicate) Relay............................... 25

9. Restricted Earth Fault (REF) Protection Relay .......................................................................... 27

10. Standby Earth Fault (SBEF) Protection Relay ........................................................................... 29

11. Synchronizing Timing Test ........................................................................................................ 31

12. Intertripping and Trip Test ....................................................................................................... 31

13. Disturbance Recorder .............................................................................................................. 32

14. Appendix .................................................................................................................................. 34


Page 3

1. Distance Protection Relay

1.1 Characteristic Test (Search Test)

Objective: To ascertain the reach setting of each individual zone.

Testing Requirement:

1. Each zone must be tested for every fault type with individual report.

2. The acceptable search test shall include at least 3 search points on each blinder. Refer Appendix 1a for example.

1.2 Operating Time Test (Shot Test)

Objective: To ascertain the trip time of each zone using test points

Testing Requirement :

1. All fault types must be tested. 2. At least 10 shots per zone to be distributed evenly over the zone with at least 3 test points on the

line angle. Refer Appendix 1b, 1c, 1d and 1e for example. 3. Shots at the boundary are to be avoided. Other active zone settings are not to be disabled when

testing is performed at a particular zone.

1.3 Teleprotection Signaling Test

Objective : To test the pulse length and transmission delay of all teleprotection signal


1. All teleprotection signaling tests must be performed inclusive of teleprotection push button test.

All teleprotection signals (e.g. DI Send, DI Received, PI DEF Send, PI DEF Receive, PI Distance R, PI Distance Y, PI Distance B, PI Distance Send and PI Distance Received) must be verified.

2. For signaling via Power Line Carrier (PLC) and Fiber Communication, a signal pulse length of 150ms is injected and the received signal is measured at the remote end by using Disturbance Recorder. If Disturbance Recorder is not available, protection relay’s internal disturbance recorder will be sufficient.

3. Can be performed during ETE test.

1.4 AR Dead Time and Distance All Zone Pickup DEF Blocking Test

Objective: To test the blocking of DEF during AR Dead Time and distance pickup on all zones.


1. All Phase-to-Ground fault types must be tested to ensure the DEF function is blocked during AR Dead Time and Distance protection pickup.


Page 4

1.5 Backup Directional Earth Fault (DEF) – Operating Boundary Angle Check

Objective : To test the operating angle of DEF


3. All Phase-to-Ground fault types must be tested.

1.6 Backup Directional Earth Fault (DEF) – Operating Time Test (Aided & Delayed Trip)

Objective : To test the operating time of the backup Directional Earth Fault protection

Testing Requirement

1. All Phase-to-Ground fault types must be tested on both aided trip operation and time delay operation.

2. If there are parallel lines, communication can be looped together to perform the test, otherwise spare relay shall be used.

3. To be perform before ETE.

1.7 Backup Directional Earth Fault (DEF) – Pickup and Drop Off Test

Objective: To test the pickup and drop off current of the backup Directional Earth Fault.

Testing Requirement

1. All Phase-to-Ground fault types must be tested at maximum torque angle (MTA) of the relay.

1.8 Loss of Potential Test

Objective: To test the pickup value U0 and to ensure VT dependent protection are blocked.


1. Pickup and drop off test on all 3 phases must be tested.

2. VT Failure must block all active VT dependent protections (e.g., Distance protection, DEF)

1.9 Switch-On-To-Fault Operating Timing Test (Impedance Principle)

Objective : To test the operating time of switch-on-to-fault for Impedance based Principle on all zones


1. All fault types must be tested.

1.10 Switch-On-To-Fault Operating Timing Test (Overcurrent Principle)

Objective : To measure the operating time of switch-on-to-fault for Overcurrent based Principle




Page 5

1.11 Switch-On-To-Fault Pickup Test (Overcurrent Principle)

Objective : To test the pickup current of Overcurrent based SOTF

Testing Requirement


1.12 Functional / Supervision Test - Alarm and Indicator Check

Objective : To test the Relay LED, Alarm check at annunciator, SCADA and Disturbance Recorder (DR) correct as per design


1. Check relay LED labeling, alarm at annunciator and Disturbance Recorder event according to the SEB standard.

2. All alarm must be simulated by injection from relay output up to annunciator, SCADA and DR. 3. All spare alarm windows at annunciator (Control Panel) and repeat relay output must be tested

up to the interface cubicle.

1.13 Functional / Supervision Test – Isolation Check

Objective: To test the isolation of the relay.


1. Relay does not maloperate when it is isolated and during normalization while being injected with fault current.

2. Isolation through Test Plug Checklist :

• Power Supply not interrupted

• CTs Shorted, VTs Open

• Signaling Circuit Isolated as per design

• Tripping Output Function on Test Plug Isolated 3. Isolation through Trip Link

1.14 Functional / Supervision Test – DC Interruption Test

Objective: To test the stability of the relay when power supply is switched off and on.


1. Relay does not maloperate during on load (through secondary injection) and no load condition

when DC power supply is interrupted.

1.15 Functional / Supervision Test – Measurement Check

Objective : To check the measurement of the relay


1. Inject nominal current & voltage. Measure secondary value for CT, VT and take relay measurement.

2. On Load Measurement check for symmetrical voltage and current after energising the circuit.


Page 6

1.16 Functional / Supervision Test – Power Swing Blocking

Objective : To test the stability of the relay during system unbalance


1. Relay stable without operation during power swing for all zones.

2. Prefer to perform using playback file.

1.17 Functional / Supervision Test – Binary Output Test

Objective : To test the binary output with actual operating timing


1. All binary outputs shall operate correctly and with specified timing as per technical manual and output description as per design.

1.18 Functional / Supervision Test – Actual CB Tripping

Objective : To test the wiring from the relay tripping output to the circuit breaker

To confirm that the circuit breaker trip accordingly

Test Requirement:

1. All breakers in the plant should be kept in closed position during the trip test. Only the breaker meant to trip shall trip.

2. Trip Test shall be performed using the actual CB (not Dummy Breaker)

3. During each trip test the performance of CB, Indication, Counter and facia shall be recorded.

4. During trip test, test the trip link isolation functionality

5. Each phase must be tested individually with individual CB operation.

1.19 Conjunctive Scheme Test

Objective : To test the protection scheme at the local end using dummy CB


1. Test Cases based on Appendix 3b Local Conjunctive Testing Matrix for Distance Protection.

1.20 End-to-End Commissioning Test

Objective : To check on the protection scheme and to ensure correct relay operation


1. Test cases based on Appendix 3d End-to-End Testing Matrix for Distance Protection.


Page 7

2. Line Differential Protection Relay

2.1. Characteristic Test (Search test)

Objective : To check the Line Differential Protection characteristic



2.2. Operating Time Test (Shot test)

Objective: To test the relay operating time of the Line Differential Protection.


1. Minimum 13 shots per phase. (Refer to appendix 2a for example )

2.3. Pickup and Drop Off Test (Lowset / Highset)

Objective : To test the pickup and drop off current of the Line Differential Protection based on lowest/highset setting



2. For lowest, inject current based on IDiff> setting

2.4. Operating Time (Lowset / Highset) Test

Objective: To test the relay response time on differential current injection based on lowset and highset setting.


1. All fault types must be tested for both Lowset and Hghset setting.

2. For lowset, inject current based on IDiff> setting

3. For highset, inject current based on 1.5x of IDiff>> setting

2.5. Harmonic Restrain Test

Objective : To test the stability of relay during the presence of harmonics


1. Test on Phase-to-Ground and Three Phase Fault.

2. To test the 2nd and 5th harmonics.


Page 8

2.6 Teleprotection Signaling Test

Objective : To test the pulse length and transmission delay of all teleprotection signals


1. All teleprotection signaling tests must be performed inclusive of teleprotection push button test. All teleprotection signals (e.g. DI Send, DI Received, PI DEF Send, PI DEF Receive) must be verified.

2. For signaling via Power Line Carrier (PLC) and Fiber Communication, a signal pulse length of 150ms is injected and the received signal is measured at the remote end by using Disturbance Recorder. If Disturbance Recorder is not available, the protection relay’s internal disturbance recorder will be sufficient.

3. Can be performed during ETE test.

2.7 AR Dead Time, Differential Pickup, and Inrush DEF Blocking Test

Objective: To test the blocking of DEF during AR Dead Time, Differential Pickup and presence of inrush.


1. All Phase-to-Ground fault types must be tested to ensure the DEF function is blocked during AR Dead Time, Differential Pickup and presence of inrush.

2.8 Backup Directional Earth Fault (DEF) – Operating Boundary Angle Check

Objective : To check on the operating angle of DEF



2.9 Backup Directional Earth Fault (DEF) – Operating Time Test (Aided & Delayed Trip)

Objective: To check the operating time for the backup Directional Earth Fault protection operation.

Testing Requirement

1. All Phase-to-Ground fault types must be tested on both aided trip operation and time delay operation.

2. If there are parallel lines, communication can be looped together to perform the test, otherwise spare relay can be used.

3. To be perform before ETE.

2.10 Backup Directional Earth Fault (DEF) – Pickup and Drop Off Test

Objective: To test the pickup and drop off current of the backup Directional Earth Fault.

Testing Requirement



Page 9

2.11 Backup Distance Characteristic Test (Search Test)

Objective: To ascertain the reach setting of each individual zone.


1. Each zone must be tested for every fault type with individual report.

2. The acceptable search test shall include at least 3 search points on each blinder. Refer Appendix 1a for example.

2.12 Backup Distance Operating Time Test (Shot Test)

Objective: To ascertain the trip time of each zone using test points


1. All fault types must be tested. 2. At least 10 shots per zone to be distributed evenly over the zone with at least 3 test points on

the line angle. Refer Appendix 1b, 1c, 1d and 1e for example.

2.13 Loss of Potential Test

Objective: To test the pickup and drop off value U0 and to ensure VT dependent protection are blocked.


1. Pickup and drop off test on all 3 phases must be tested.

2. VT Failure must block all active VT dependent protections (e.g Distance protection, DEF)

2.14 Switch-On-To-Fault Operating Timing Test (Impedance Principle)

Objective: To ascertain the operating time of switch-on-to-fault for Impedance based Principle on all zones.


1. All fault types must be tested

2.15 Switch -On-To-Fault Operating Timing Test (Differential Principle)

Objective: To ascertain the operating time of switch-on-to-fault for Differential based Principle on all zones.

Test Requirement:


2.16 Switch-On-To-Fault Operating Timing Test (Overcurrent Principle)

Objective: To ascertain the operating time of switch-on-to-fault for Overcurrent based Principle.




Page 10

2.17 Switch-On-To-Fault Pickup Test (Overcurrent Principle)

Objective : To ascertain the pickup current of Over Current (OC) based SOTF



2.18 Functional / Supervision Test – Alarm and Indicator Check




2. All alarms must be simulated by injection from relay output up to annunciator, SCADA and DR.

3. All spare alarm windows at annunciator (Control Panel) and repeat relay output must be tested up to the interface cubicle.


Objective: To test the isolation of local relay.


1. Relay does not maloperate after isolation and during normalization while being injected with fault current.






2.20 Functional / Supervision Test – Test Mode Switch Test

Objective: To test the blocking of relay in test mode.

Testing Requirement

1. Relay must block all tripping signals from all protections when it is switched to test mode.

2.21 Functional / Supervision Test – DC & Any Communication Fail Interruption Test


To test the stability and alarm of the relay when there is interruption on communication channel.

Testing Requirement: 1. Relay does not maloperate during on load (through secondary injection) and no load condition

when DC power supply is interrupted. 2. Differential protection must be active during failure of 1 communication channel. 3. Differential protection must be blocked when both communication channels are interrupted.


Page 11

2.22 Functional / Supervision Test – Power Swing Blocking

Objective: To test the stability of the relay during system unbalance.


1. Relay stable without operate during power swing for all zones.

2. Prefer to perform using playback file.


Objective : To test the binary output with actual operating timing.




Objective : To test the wiring from the relay tripping output to the circuit breaker.

To confirm the circuit breaker trip accordingly.












2.26 Conjunctive Scheme Test

Objective: To test the scheme used in the substation.


1. Test Cases based on Appendix 3a Local Conjunctive Testing Matrix for Current Differential Protection.

2. Test can be performed using dummy CB.


Page 12

2.27 End-to-End Commissioning Test

Objective : To verify the protection scheme and to ensure correct relay operation


1. Test cases based on Appendix 3c End-to-End Testing Matrix for Current Differential Protection.


Page 13

3. Biased Differential Protection Relay

3.1 Pickup and Drop Off Test

Objective: To test the pickup and drop off current of the Biased Differential protection.


1. All fault types must be tested. 2. Inject Current based on IDiff> setting.

3.2 Characteristic Test (Search Test)

Objective : To test the biased differential protection characteristic



3.3 Operating Time for IDiff >(Shot Test)

Objective: To test the operating time of the biased differential protection.


1. All fault types must be tested. 2. At least 10 shots distributed evenly along the graph Refer to appendix 2a for more details.

3.4 Operating Time IDiff >>

Objective : To test the operating time needed for the biased differential relay highset setting


1. All fault types must be tested. 2. Inject highset current 1.5x of IDiff>> setting.

Note : Check the continuous withstand current of the relay before testing

3.5 Harmonic Restrain Test

Objective : To test the biased differential relay’s response to harmonics during fault condition


1. Test on Phase-to-Ground and Three Phase Fault

2. To test the 2nd and 5th harmonics.


Page 14

3.6 Biased Differential Protection Relay Stability Test

Objective: To test the stability and operation of the relay during internal and external fault.


1. To test on all Phase-to-Ground fault types.

2. Test for Nominal Tap for HV-LV, HV-TV, LV-TV respectively.

3. Repeat all tests for CT at reverse polarity, in zone fault and out zone fault

4. Minimum injection current: 10% of rated CT Primary current.








Objective : To test the isolation of the relay through Test Plug and isolation procedure


1. Relay does not maloperate after isolation and during normalization while being injected with current.

2. Isolation Checklist


• CTs Shorted

• Tripping Output Function on Test Plug Isolated

• Tripping Link Isolated




1. Relay does not maloperate during on load (through secondary injection) and no load condition when DC power supply is interrupted.


Objective: To test the binary output with actual operating timing.


1. Binary output shall operate correctly and with specified timing & output description


Page 15


Objective: To test the wiring from the relay tripping output to the circuit breaker.








Objective : To verify the measurement of the relay


1. Inject nominal current. Measure secondary value for CT and take relay measurement.

2. On Load Measurement check for symmetrical current after energising the circuit.


Page 16

4. Directional Overcurrent / Directional Earth Fault (DOC / DEF)

Protection Relay

4.1 Operating Time Test

Objective: To test the operating time for the Directional OC/EF protection.



2. Test 1: Test at 2x, 4x and 6x of the finalized setting.

3. Test 2: Highset Test. Test using 1.05x of the setting.

4. Test 3: Test the drop-off time of the output contact.

4.2 Pickup and Drop-Off Test

Objective: To test the pickup and drop-off current of the Directional OC/EF protection for Lowset setting.



2. Test at finalized setting.

4.3 Boundary Angle Test

Objective : To test the operating angle of the Directional OC/EF Protection

Testing Requirement



Objective : To test the Relay LED, Alarm check at annunciator and SCADA correct as per design


1. Check relay LED labeling, alarm at annunciator according to SEB standard.

2. All alarms must be simulated by injection from relay output up to annunciator and SCADA.



Page 17




1. Relay does not maloperate after isolation and during normalization while being injected with

fault current.










2.














Objective: To check the measurement of the relay.





Page 18

5. Non Directional Overcurrent / Non Directional Earth Fault (OC /

EF) Protection Relay


Objective: To test the operating time needed for the Non Directional OC/EF protection.



2. Test 1 : Test at 2x, 4x and 6x of the finalized setting

3. Test 2 : Highset Test. Test using 1.05x of the setting

4. Test 3: Test the drop-off time of the output contact.

5.2 Pickup and Drop-Off Test

Objective: To test the pickup and drop-off current of the Non-Directional OC/EF protection for Lowset setting.



2. Test at finalized setting


Objective : To test the Relay LED, Alarm check at annunciator and SCADA correct as per design






Objective : To test the isolation of the relay



fault current

2. Isolation Checklist :


• CT Shorted




Page 19











To verify that the circuit breaker trips accordingly.









1. Inject nominal current & voltage. Measure secondary value for CT and take relay measurement

2. On Load Measurement checks for symmetrical current after energising the circuit.


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6. Autoreclose (AR) and Synchronising Check Relay

6.1 Syncheck Relay - Pickup and Drop Off Test

Objective: To test the different value of Syncheck relay in terms of voltage, phase angle and frequency.


1. Test on each of the Voltage (V), phase angle (degree) and frequency (Hz) individually based on

the finalized setting.

6.2 Syncheck – Operating Time Test

Objective: To test the operating time needed for the Syncheck relay to operate.


1. All the following conditions must be tested :

• Live Line/ Dead Bus

• Live Bus/ Dead Line

• Live Line/ Live Bus

• Dead Line/ Dead Bus

6.3 Auto Reclose – Operating Time Check

Objective: To test the operating time of the Autoreclose relay for single pole dead time and three pole dead time and reclaim time.


1. Single Pole Dead Time : 0.8s

2. Three Pole Dead Time : 5s (Source) , 5.5s (Load)

3. Reclaim Time : 180s

6.4 Phase Segregated Binary Input Signal Check

Objective : To check the signaling of binary input in different Autoreclose condition


1. All injections shall be through main 1 and main 2 protection relay.

2. Start AR Red Phase – Inject Red Phase Trip and AR Recloses Red Phase.

3. Start AR Yellow Phase – Inject Yellow Phase Trip and AR Recloses Yellow Phase.

4. Start AR Blue Phase – Inject Blue Phase Trip and AR Recloses Blue Phase


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6.5 Autoreclose Selector Switch Test

Objective: To test the scheme and operation of the Auto-Reclose pole selection.


1. AR OFF, 1 Pole, 3 Pole and 1+3Pole must be tested

2. AR OFF

• Test on one case each for Single phase, phase-to-phase and 3 phase.

3. 1 pole

• Test on all fault types.

4. 3 pole

• Test on all fault types. 5. 1+ 3 pole

• Test on all fault types


Objective: To test the Relay LED, Alarm check at annunciator, SCADA and Disturbance Recorder (DR) correct as per design.


1. Check relay LED labeling, alarm at annunciator and Disturbance Recorder event according to SEB standard.




Objective: To test the isolation of the relay through Test Plug.



fault current.









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6.9 Functional / Supervision Test – Actual CB Closing

Objective: To test the actual closing command up to the circuit breaker.


1. All breakers in the plant should be kept in closed position during the trip test. Only the breaker meant to reclose shall reclose.

2. CB re-closure shall be performed using the actual CB (not Dummy Breaker)

3. During each trip and reclose test the performance of CB, Indication, Counter and facia shall be recorded.





1. Inject nominal voltage. Confirm secondary value of VT and relay value.

2. Confirm voltage value and phasing after energising the circuit.


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7. Breaker Fail Protection Relay


Objective: To test the pickup and drop-off current of the Breaker Fail Relay.



2. Inject current and initialize start signal from relay. (CBF Start R, Y, B & Start 3 Poles)


Objective: To test the operating time needed for the Breaker Fail Protection Relay to operate.



2. Inject current and initialize start signal from relay. (CBF Start R, Y, B & Start 3 Poles)

7.3 Overall Scheme Check (F50BF1 + F50BF2)

Objective: To test the operating time of the 2 breaker fail operation.


1. Test the total operating time from BF initiated up to tripping

7.4 Breaker Fail Phase Segregation Signaling Check

Objective: To test the scheme and operation of the phase segregated breaker fail signaling.


1. All tripping signals to the Lockout relay shall start 3Ø CBF. Without current injection, relay should not operate.

2. Start CBF Red phase - inject Yellow and Blue Phase, relay should not operate. 3. Start CBF Yellow phase - inject Red and Blue Phase, relay should not operate. 4. Start CBF Blue Phase - inject Yellow and Red Phase, relay should not operate. 5. Start CBF R/Y/B/3Ø - inject RYB, relay should operate.




1. Relay does not maloperate during DC power supply interruption.


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1. Inject nominal current. Measure secondary value for CT and take relay measurement

2. ON load Measurement check for symmetrical current after energising the circuit.





fault current.



• CT Shorted



3. Isolation through Trip Link


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8. Busbar Protection (BBP) and CT Supervision (Main and Duplicate)

Relay

8.1 Pickup and Drop Off

Objective: To test the pickup and drop-off current of the Busbar Protection.



2. Stabilizing resistor has to be set to the correct resistance value.

3. Secondary current injection for Main, Reserve and Check zone relay.


Objective: To test the operating time of the Busbar Protection.




8.3 CT Supervision Relay – Pickup and Drop Off test

Objective: To test the pickup and drop-off current of the CT Supervision Relay.


1. Each phase must be tested.


3. CT Supervision operation must block Busbar Protection.

8.4 CT Supervision Relay -- Operating Time

Objective: To test the operating time needed for the CT Supervision Relay to operate.


1. Stabilizing resistor has to be adjusted to the correct resistance.


8.5 Busbar Stability Test

Objective: To test the operation and stability of the relay during internal and external fault.


1. Each phase must be tested on all feeders.

2. Minimum injection current: 10% of rated CT primary current.

3. Test on CT condition of Reverse Polarity, In Zone Fault and Out Zone Fault


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1. Relay does not maloperate when DC power supply is interrupted.








1. Inject nominal current. Measure secondary value for CT and take relay measurement.

2. On Load Measurement check for symmetrical and current after energising the circuit.


Objective: To test the isolation of the relay via Test Plug.



fault current.

2. Isolation Checklist :


• CT Shorted


3. Isolation through Trip Link and Tripping Relay.


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9. Restricted Earth Fault (REF) Protection Relay


Objective: To test the pickup and drop-off current of the REF relay.


1. All Phase to Ground fault types must be tested.

2. Must be tested together with correct shunt/stabilizing resistor value.

9.2 Operating Time

Objective: To test the operating time of the REF operation.


1. All Phase to Ground fault types must be tested.

2. Must be tested together with correct shunt/stabilizing resistor value.

9.3 REF Stability Test

Objective: To test the operation and stability of the relay during internal and external fault.


1. All Phase to Ground faults must be tested. (Test for HV-G and LV-G or TV-G for REF).

2. Repeat all tests for CT with reverse polarity, in zone fault and out zone fault.

3. Minimum injection current: 10% of rated CT Primary current.


Objective : To test the alarms, LED indication and other annunciation during a fault



2. All alarms must be simulated by injection from relay output up to annunciator and SCADA. 3. All spare alarm windows at annunciator (Control Panel) and repeat relay output must be tested

up to the interface cubicle.





fault current.



• CT Shorted



3. Isolation through Trip Link.


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1. Relay does not maloperate during on load (through secondary injection) and no load condition

when DC power supply is interrupted.














Objective : To check the measurement of the relay (if applicable)


1. Inject nominal current & voltage. Measure secondary value for CT and take relay measurement.

2. On Load Measurement check for symmetrical voltage and current after energizing the circuit.


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10. Standby Earth Fault (SBEF) Protection Relay


Objective: To test the pickup and drop-off current of the SBEF.


1. Phase to Ground fault to be tested.

10.2 Operating Time (Shot Test)

Objective: To test the operating time for Stage 1 and Stage 2 of the SBEF operation


1. Phase to Ground fault to be tested


Objective : To test the alarms, LED indication and other annunciation during a fault (if applicable)









fault current.



• CT Shorted



3. Isolation through Trip Link.




1. Relay does not maloperate when DC power supply is interrupted.


Page 30
















1. Inject nominal current & voltage. Measure secondary value for CT and take relay measurement.

2. On Load Measurement check for symmetrical voltage and current after energizing the circuit.


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11. Synchronizing Timing Test

11.1 Timing Test

Objective : To test the operating time of the timer/relay output contact


1. Test On-Delay Timer for Automatic Cut Off Synchronizing. 2. Test Supervisory and Local Close Synchronizing On Timer. 3. Test Synchronizing Bypass Timer.

12. Intertripping and Trip Test

12.1 Busbar Protection Trip Test

Objective: To ensure correct operation of Busbar tripping. Testing Requirement: 1. Tripping signal must be simulated from secondary injection to the Busbar protection relay. 2. All feeders must be tested will all circuit breakers closed before test. 3. Test carried out must be able to prove the operation is as per scheme and all tripping circuits are

correct. 4. During the Trip test, testing on isolation via Tripping Relay and Trip Link must be carried out to

ensure isolation is in correct.

12.2 Circuit Breaker Fail Trip Test

Objective : To test and prove the intertripping is correct as per scheme


1. Breaker fail protection for all feeders must be tested.

12.3 Transformer Protection Intertripping Test

Objective: To test and prove the intertripping is correct per scheme.

Testing Requirement

1. All protections on HV, LV and TV must be tested.

2. The intertripping test must be a conjunctive test with the 33kV side breaker and the 33kV Bus

Coupler breaker.

3. Operation of Lockout relay and alarm for all sides must be recorded.

4. Transformer guard protection intertripping must be tested.


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13. Disturbance Recorder

13.1 Accuracy Test (Slow and Fast Sub BEN)

Objective: To test the accuracy of the disturbance recorder in terms of voltage, current, frequency and power (MW and MVar).

Testing Requirement

1. Inject nominal current and voltage.

13.2 Digital Signal Mapping Test

Objective: To confirm the digital signal assignment with the corresponding output from relay.

Testing Requirement

1. Simulate all digital signals at the relay output by secondary injection to the relay, one signal at a time.

2. To check the actual CB open status. Only 3 pole CB is monitored by DR.

13.3 Threshold Test

Objective: To test the threshold setting of voltage, current and frequency.

Testing Requirement

1. Inject current, voltage and frequency based on the threshold setting to trigger the disturbance recorder.

13.4 Pre-fault and Post Fault time Test

Objective: To test the duration of pre-fault and post-fault time.

Testing Requirement

1. Simulate fault from relay to trigger the disturbance recorder.

13.5 Disturbance Recorder Calibration

Objective: To calibrate the disturbance recorder for accurate disturbance recording in terms of voltage, current and frequency.

Testing Requirement

1. Calibrate to the most accurate reading for voltage, current and frequency.

13.6 Disturbance Recorder Fault Locator

Objective : To test the accuracy of the fault locator function in the Disturbance Recorder

Testing Requirement

1. Simulate a fault at the relay and check the fault distance detected by the disturbance recorder.


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13.7 Disturbance Recorder – Alarm Check

Objective : To test the disturbance recorder internal supervision alarm

Testing Requirement

1. All internal supervision alarm of disturbance recorder should be tested.


Page 34

14. Appendix

Appendix 1a: Example of Distance Search Test


Page 35

Appendix 1b: Shot Test Example for Z1

Appendix 1c: Shot Test Example for Z2


Page 36

Appendix 1d: Shot Test Example for Z3

Appendix 1e: Shot Test Example for Z4


Page 37

Appendix 2a: Shot Test Example for Differential


Page 38

Conjunctive Test Testing Matrix

Current Differential Relay

Protection AR

Switch R Y B RY YB BR RYB Remarks

Local Conjunctive

Test Local Conjunctive






Test

Current Differential Protection

1 ✓ ✓ ✓ ✓ ✓ ✓ ✓

1+3 ✓ ✓ ✓ ✓ ✓ ✓ ✓

3 ✓ ✓ ✓ ✓ ✓ ✓ ✓

OFF ✓ ✓ ✓ ✓ ✓ ✓ ✓

Back-Up DEF Aided

1 ✓ ✓ ✓ ✓ ✓ ✓ ✓

1+3 ✓ ✓ ✓ ✓ ✓ ✓ ✓

3 ✓ ✓ ✓ ✓ ✓ ✓ ✓

OFF ✓ ✓ ✓ ✓ ✓ ✓ ✓

Back-Up DEF Time Delay

1 ✓ ✓ ✓ ✓ ✓ ✓ ✓

1+3 ✓ ✓ ✓ ✓ ✓ ✓ ✓

3 ✓ ✓ ✓ ✓ ✓ ✓ ✓

OFF ✓ ✓ ✓ ✓ ✓ ✓ ✓

Back-Up Distance

Zone 1 (Forward) 1 ✓ ✓ ✓ ✓ ✓ ✓ ✓

Zone 2 (Forward) 1 ✓ ✓ ✓ ✓ ✓ ✓ ✓

Zone 3 (Reverse) 1 ✓ ✓ ✓ ✓ ✓ ✓ ✓

Zone 4 (Forward) 1 ✓ ✓ ✓ ✓ ✓ ✓ ✓

Back-Up Directional OC 1 ✓ ✓ ✓ ✓ ✓ ✓ ✓

SOTF 1 ✓ ✓ ✓ ✓ ✓ ✓ ✓

Evolving Fault

1 ✓a ✓

b ✓

c

1+3 ✓a ✓

b ✓

c

a : 1st RØ Fault, 2nd YØ Fault

b : 1st YØ Fault, 2nd BØ Fault

c : 1st BØ Fault, 2nd RØ Fault

Pole Discordance 1 ✓ ✓ ✓

Conjunctive Test with Dummy CB ✓

Appendix 3a: Local Conjunctive Testing Matrix for Current Differential Protection


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Conjunctive Test Testing Matrix

Distance Protection Relay

Protection AR Switch R Y B RY YB BR RYB Remarks

Local Conjunctive







Test

Distance Protection

Zone 1 (Forward) Local 50%, Remote 50%

1 ✓ ✓ ✓ ✓ ✓ ✓ ✓

1+3 ✓ ✓ ✓ ✓ ✓ ✓ ✓

3 ✓ ✓ ✓ ✓ ✓ ✓ ✓

OFF ✓ ✓ ✓ ✓ ✓ ✓ ✓

Distance Aided Trip 1 ✓ ✓ ✓ ✓ ✓ ✓ ✓ Local Z1B, Remote Z1B 1+3 ✓ ✓ ✓ ✓ ✓ ✓ ✓

3 ✓ ✓ ✓ ✓ ✓ ✓ ✓

OFF ✓ ✓ ✓ ✓ ✓ ✓ ✓

Zone 2 (Forward)

1 ✓ ✓ ✓ ✓ ✓ ✓ ✓

1+3 ✓ ✓ ✓ ✓ ✓ ✓ ✓

3 ✓ ✓ ✓ ✓ ✓ ✓ ✓

OFF ✓ ✓ ✓ ✓ ✓ ✓ ✓

Zone 3 (Reverse)

1 ✓ ✓ ✓ ✓ ✓ ✓ ✓

1+3 ✓ ✓ ✓ ✓ ✓ ✓ ✓

3 ✓ ✓ ✓ ✓ ✓ ✓ ✓

OFF ✓ ✓ ✓ ✓ ✓ ✓ ✓

Zone 4 (Forward)

1 ✓ ✓ ✓ ✓ ✓ ✓ ✓

1+3 ✓ ✓ ✓ ✓ ✓ ✓ ✓

3 ✓ ✓ ✓ ✓ ✓ ✓ ✓

OFF ✓ ✓ ✓ ✓ ✓ ✓ ✓

Back-Up DEF Aided

1 ✓ ✓ ✓ ✓ ✓ ✓ ✓

1+3 ✓ ✓ ✓ ✓ ✓ ✓ ✓

3 ✓ ✓ ✓ ✓ ✓ ✓ ✓

OFF ✓ ✓ ✓ ✓ ✓ ✓ ✓


1 ✓ ✓ ✓ ✓ ✓ ✓ ✓

1+3 ✓ ✓ ✓ ✓ ✓ ✓ ✓

3 ✓ ✓ ✓ ✓ ✓ ✓ ✓

OFF ✓ ✓ ✓ ✓ ✓ ✓ ✓

SOTF 1 ✓ ✓ ✓ ✓ ✓ ✓ ✓

Evolving Fault

1 ✓a ✓

b ✓

c

1+3 ✓a ✓

b ✓

c

a : 1st RØ Fault, 2nd YØ Fault b : 1st YØ Fault, 2nd BØ Fault c : 1st BØ Fault, 2nd RØ Fault

Pole Discordance 1 ✓ ✓ ✓

Conjunctive Test with Dummy CB ✓

Appendix 3b: Local Conjunctive Testing Matrix for Distance Protection


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End To End Testing Matrix

Current Differential Relay

Protection AR

Switch R Y B RY YB BR RYB Remarks

One End

Injection1 Both End Injection

One End Injection1

Both End Injection

One End Injection1

Both End Injection

One End Injection1

Both End Injection

One End Injection1

Both End Injection

One End Injection1

Both End Injection

One End Injection1

Both End Injection

Current Differential Protection

1 • • • • • • •

1+3 • •

3 • •

OFF •

Back-Up DEF Aided

1 • • •

1+3

3

OFF


1 •

1+3

3

OFF

Back-Up Distance

Zone 1 (Forward) 1 •

Zone 2 (Forward) 1 •

Zone 3 (Reverse) 1

Zone 4 (Forward) 1

Back-Up Directional OC 1 •

SOTF 1 • • •

Evolving Fault (Simultaneous injection)

1 •a •b •c

1+3

•

a : 1st RØ Fault, 2nd YØ Fault

b : 1st YØ Fault, 2nd BØ Fault

c : 1st BØ Fault, 2nd RØ Fault

Pole Discordance 1 • • •

End to End Testing with Actual CB Test • 1 repeat at both end

Appendix 3c: End to End Testing Matrix for Current Differential Protection


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End To End Testing Matrix

Distance Protection Relay

Protection AR Switch R Y B RY YB BR RYB Remarks

One End

Injection1 Both End Injection

One End Injection1

Both End Injection

One End Injection1

Both End Injection

One End Injection1

Both End Injection

One End Injection1

Both End Injection

One End Injection1

Both End Injection

One End Injection1

Both End Injection

Distance Protection

Zone 1 (Forward) Local 50%, Remote 50%

1 • • •

1+3

3

OFF

Distance Aided Trip Local Z1B, Remote Z1B

1 • • • • • • •

1+3 • •

3 • •

OFF •

Zone 2 (Forward)

1 • •

1+3

3

OFF •

Zone 3 (Reverse)

1 •

1+3

3

Zone 4 (Forward)

1 •

1+3

3

OFF •

Back-Up DEF Aided

1 • • •

1+3

3

OFF


1 •

1+3

3

OFF

SOTF 1 • • •

Evolving Fault

1 • a •c

1+3

•b

a : 1st RØ Fault, 2nd YØ Fault b : 1st YØ Fault, 2nd BØ Fault c : 1st BØ Fault, 2nd RØ Fault

Pole Discordance 1 • • •

Simultaneous Fault 1 • • •

End to End Testing with Actual CB Test • 1 repeat at both end

Appendix 3d: End to End Testing Matrix for Distance Protection

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