Asset Maintenance TNBT Guideline rev 03

7/25/2019 Asset Maintenance TNBT Guideline rev 03

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Document TitleRevision No:

3.0

ASSET MAINTENANCE GUIDELINESDate of Approval:Sep 2015 (TTC)

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Prepared by:

ASSET MANAGEMENT DEPARTMENTTRANSMISSION DIVISION

TENAGA NASIONAL BERHAD

RevisionNumber

Description of change record By Verifier Approver

1.0 New ASDU GM TTC

2.0 Changes are as per Appendix 1 ASDU GM TTC

3.0Review based on ITOMS WorkingGroup recommendation

OPU GM TTC

@ Copyright TNB Transmission Division

No part of this document may be reproduced or transmitted in any form whatsoever by

any means, including, without l imitation, electronic, photocopying, recording or otherwise,without the prior written consent of TNB Transmission Division. No information embodiedin documents which is not in the public domain shall be communicated in any mannerwhatsoever to any party without the prior written consent of TNB Transmission Division.




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INTRODUCTION ........................................................................................................... 6

1 Background ............................................................................................................ 62 Objectives .............................................................................................................. 6

3 Scope ..................................................................................................................... 7

4 Maintenance Type ........................................ ......................................... ................. 75 Methodology ..................... .................................................. ................................... 8

6 Implementation and Data Monitoring ............................. ........................................ 9

7 Maintenance Performance ............................ ......................................... ................. 9

8 Effective Date ...................................................................................................... 10

9 Acknowledgement............................................................... ................................. 10

10 References............................................................................................................ 10

A. MAINTENANCE GUIDELINES FOR SUBSTATIONS AND SUBSTATION

PRIMARY EQUIPMENT ............................................................................................. 11

1 Scope ................................................................................................................... 11

2 General Information .......... .................................................. ................................. 12

3 Inspection and Maintenance Plan ........................................ ................................. 14

3.1 Entire Plant ..................... ......................................... ...................................... 143.2 Building ...................... .................................................. ................................. 153.3 Switchyard ......................................... ........................................ .................... 17

3.4 High Voltage (HV) Outdoor Circuit Breaker .............................. .................... 183.5 Medium Voltage (MV) circuit breaker ..................... ...................................... 21

3.6 Power Transformers ............................... ......................................... ............... 233.7 Earthing Transformer ............................. ......................................... ............... 26

3.8 Transformer Cable Tails........... ................................ ...................................... 283.9 Current Transformer .............................. ......................................... ............... 29

3.10 Voltage Transformers/Capacitive Voltage Transformer ................... ............... 31

3.11 Disconnectors/Earth Switches ....................................... ................................. 32

3.12 Surge Arresters ........... .................................................. ................................. 34

3.13 Compensation Equipment ........................................ ...................................... 35

3.14 Substation Earth Grid and Overhead Earth Wire ............................. ............... 37

3.15 Neutral Earthing Resistors...................... ......................................... ............... 37

3.16 Busbar/Busbar clamps/Dropper .......... .................................................. .......... 38

3.17 SF6 Gas-Insulated Switchgears (GIS) ............................................................. 39

B. MAINTENANCE GUIDELINES FOR OVERHEAD TRANSMISSION LINES .... . 41

1 Scope ................................................................................................................... 41


3 Critical and Non-Critical Lines ..................... ......................................... ............... 41

4 Line Inspection and Maintenance ........................................ ................................. 424.1 Line Inspection ........... .................................................. ................................. 42

4.2 Line Maintenance .............................. .................................................. .......... 425 Inspection Tasks and Maintenance Plan................................................. ............... 43

5.1 Ground Patrol ........................................ ......................................... ............... 435.2 Aircraft Warning Light Maintenance - ..................... ...................................... 44

5.3 Tower Top Inspection ............................ ......................................... ............... 44




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5.4 Aerial Inspection ................................ .................................................. .......... 44

5.5 Thermographic Scanning ......................................... ...................................... 455.6 Rentice Clearing ................................ .................................................. .......... 45

5.7 Ground Access Point Maintenance ................................ ................................. 45

5.8 Tower Footing Resistance Measurement ......................................... ............... 455.9 Lowest Conductor Height Measurement ......................................... ............... 45

C. MAINTENANCE GUIDELINES FOR TRANSMISSION UNDERGROUND

AND SUBMARINE CABLES ...................................................................................... 47

1 Scope ................................................................................................................... 47



3.1 Cable route patrol............. ........................................ ...................................... 48

3.2 Offshore patrol for submarine cable .............................. ................................. 48

3.3 Oil containment and alarm system inspection for oil-filled cable .......... .......... 48

3.4 Operation test for oil containment alarm system for oil-filled cable ................ 48

3.5 Thermographic scanning .................... ........................................ .................... 48

3.6 Cable accessories and supporting structures inspection ................... ............... 483.7 Underground cable manholes and tunnel inspection ............................. .......... 493.8 Sheath insulation test for XLPE Cable ..................... ...................................... 49

3.9 Insulation resistance test..................... .................................................. .......... 493.10 Link box internal inspection ................... ......................................... ............... 49

3.11 Cable PD detection for XLPE cable .............................. ................................. 493.12 Cable outdoor sealing end inspection ............................ ................................. 49

D. MAINTENANCE GUIDELINES FOR PROTECTION SYSTEM............................ 511 Scope ................................................................................................................... 51


3 Maintenance Plan ......................................... ......................................... ............... 52

3.1 Distance Relays .......... .................................................. ................................. 53

3.2 Current Differential and Current Comparison Relays ..................................... 53

3.3 Pilot Wire Protection Relays ......................................... ................................. 55

3.4 Auto Re-close Relays ............................. ......................................... ............... 56

3.5 Synchro-check Relays ............................ ......................................... ............... 57

3.6 Over-current and Earth Fault Relays ............................. ................................. 57

3.7 Trip Circuit Supervision Relay ........... .................................................. .......... 58

3.8 Transformer Differential Relays ............................... ...................................... 59

3.9 Restricted Earth Fault Relays ........................................ ................................. 60

3.10 Standby Earth Fault Relays .................... ......................................... ............... 61

3.11 Stub Protection ........... .................................................. ................................. 623.12 High Impedance Busbar Differential Relays ......................................... .......... 63

3.13 Low Impedance Busbar Protection Scheme (Centralized and De-centralized) ................................................................................................................ 63

3.14 Circuit Breaker Failure Relays ........... .................................................. .......... 643.15 Thermal Overload Relays ......................................... ...................................... 65

3.16 Under/Over Frequency and Under/Over Voltage (For Protection FunctionOnly) 65




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3.17 Pole Discrepancy Relays .................... ........................................ .................... 66

3.18 Automatic Voltage Regulator (AVR) ............................ ................................. 673.19 Unbalanced Protection .................................................. ................................. 67

3.20 Transformer Guards ............................... ......................................... ............... 68

3.21 Local Instrument meters ..................... .................................................. .......... 683.22 Switch-sync (Point of Wave) relays .............................. ................................. 69

3.23 Reverse Power, Negative Phase Sequence, Over Excitation, Loss Excitation

and Under Impedance Relays .................................................................................... 69

3.24 Regular Inspection ........... ........................................ ...................................... 69

3.25 Other Maintenance ........... ........................................ ...................................... 69

4 Types of Relays Used in TNB Transmission Protection Scheme............ ............... 70

4.1 Feeder Bay Protection ............................ ......................................... ............... 70

4.2 Power Transformer/ Generator Transformer/ Reactor Bay Protection ............. 71

4.3 Capacitor Bank Protection........................................ ...................................... 72

4.4 Bus Coupler, Bus Section and Busbar Protection .......... ................................. 72

4.5 Generator Protection .............................. ......................................... ............... 73

E. MAINTENANCE GUIDELINES FOR STATIC VAR COMPENSATOR (SVC)EQUIPMENT ............................................................................................................... 741 Scope ................................................................................................................... 74

2 General Information .......... .................................................. ................................. 743 Inspection and Maintenance Plan ........................................ ................................. 74

3.1 Thyristor related equipment ................... ......................................... ............... 753.2 Control and Protection for SVC equipment ................... ................................. 76

3.3 SVC Primary Equipment .................... ........................................ .................... 773.4 Auxiliary Equipment .............................. ......................................... ............... 77

F. MAINTENANCE GUIDELINES FOR HIGH VOLTAGE DIRECT CURRENT

(HVDC) EQUIPMENT ........................................ ......................................... ............... 78

1 Scope ................................................................................................................... 78



3.1 Converter Equipment ............................. ......................................... ............... 78

3.2 DC Primary Equipment ...................... ........................................ .................... 79

3.3 AC Primary Equipment ...................... ........................................ .................... 81

3.4 HVDC Control and Protection ........... .................................................. .......... 82

3.5 General services and auxiliary equipment ..................... ................................. 82

G. MAINTENANCE GUIDELINES FOR SUBSTATION CONTROL SYSTEM

(SCS) ............................................................................................................................ 83

1 Scope ................................................................................................................... 832 General Information .......... .................................................. ................................. 83

3 Objectives ............................................................................................................ 844 Maintenance Plan ......................................... ......................................... ............... 85

4.1 Preventive Maintenance ..................... .................................................. .......... 855 Documentation ......................................... ........................................ .................... 85




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H. MAINTENANCE GUIDELINES FOR REMOTE TERMINAL UNIT (RTUS) ....... 86

1 Scope ................................................................................................................... 862 General Information .......... .................................................. ................................. 86

2.1 Failure Modes ........................................ ......................................... ............... 87

3 Objectives ............................................................................................................ 874 Maintenance Plan ......................................... ......................................... ............... 87

4.1 Failure Mode, Effect and Criticality Analysis (FMECA) ................................ 87

4.2 Preventive Maintenance ..................... .................................................. .......... 87

5 Documentation ......................................... ........................................ .................... 88




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INTRODUCTION

1 BackgroundTransmission network assets are developed, operated and maintained to provide

transportation of bulk power from generators to distributors.In TNB Transmission, these assets that consist of various equipment and plants are

grouped as follows:

· Substations

· Overhead Lines

· Underground Cables

· Secondary Systems (protection relays and telecontrol equipment)

Equipment currently in operation in the Transmission grid system consists of various

type and make. Majority of the equipment used are of overseas manufacturer. The age

of the equipment installed range from newly commissioned to 40 years. In managing

these assets, it is prudent for TNB to balance the cost and the risk involved in

maintaining the assets.

In line with industries practices in managing the asset and with the increasing

expectation for maintenance to deliver improved performance, Transmission Division

has prepared a Transmission Asset Maintenance Guidelines.

2 ObjectivesThe objectives of Transmission Asset Maintenance Guidelines are as follow:

· Provide a standard maintenance level requirement and practices in TNB’sTransmission Division.

· Optimise the maintenance cost and performance (reliability and availability)of transmission network assets.

· Assist Asset Maintenance Department to plan, implement and monitor the

prescribed inspection and maintenance strategies.

· Ensure maintenance practices comply with statutory requirements

· Ensure equipment health, personnel and public safety, and security of supply

· Assist departments in achieving Transmission Division’s business plans and

targets.




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To ensure the effective implementation of this guideline in Transmission Division

maintenance practice, subsequent departmental procedures and work instructions areto be prepared by Asset Maintenance Department. These documents shall provide:

· method, instructions and checklist to carry out inspection and maintenance task· recommendations on the corrective actions to be taken after observing findings/

results during inspection and maintenance task

3 Scope

The scope of this guideline covers all assets in substations, lines, cables, SVC, HVDCand secondary systems. Assets in Telecommunication System which are under TNB’s

ICT Division are covered in a separate document.

Equipment in operation consists of a large population with variety of manufacturers

which can be difficult to maintain as the maintenance procedures may be differentfrom one to another. Thus the Maintenance Guidelines is intended to serve majority of

the equipment installed in TNB transmission system. Nevertheless, specific

recommendations or instructions from the manufacturer need to be adhered to where

required.

4 Maintenance TypeFigure 1 shows the category of maintenance currently practiced in TNB Transmission

Division. Similar structure is also used in the computerized maintenance management

system (CMMS) also known as ERMS-PM.

Figure 1 – Category of Maintenance

Maintenance

PreventiveMaintenance

CorrectiveMaintenance

Routine/Scheduled

Maintenance

Condition BasedMaintenance

Emergency/Breakdown

Maintenance

DeferredMaintenance




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Preventive maintenance is carried out at predetermined intervals or corresponding to

prescribed criteria as determined by OEM or TNB. Preventive maintenance isintended to reduce the probability of failure or the performance degradation of an

item. Routine/Scheduled maintenance is carried out at a fixed interval (time,

operations) e.g. OLTC oil replacement after 4 years or 100,000 operations whichevercomes first. Condition based maintenance is initiated as a result of knowledge of the

condition of an item from monitoring e.g. visual inspection, thermovision and

diagnostic tests

Corrective maintenance is carried out after a failure or unacceptable condition has

occurred and intended to restore an item to a state in which it can perform its required

function. Emergency/Breakdown maintenance is carried out immediately to prevent

danger to personnel, equipment, or system performance e.g. equipment requires repair

under tripping situation. Deferred maintenance is maintenance work that may be

programmed for later action e.g. defect found during inspection and the repair is plan

in the next available outage.

The maintenance tasks and interval stated in this document are primarily for preventive maintenance works.

5 MethodologyThe guidelines review and formulation was carried out based on manufacturers

recommendation, statutory requirement and TNB’s operation and maintenance

experience. Using the available information, RCM 2 processes were adopted in

formulating the maintenance guidelines. Probable root causes of failures were

identified and the respective mitigating actions were identified to prevent andminimise re-occurrence of failures. Several RCM 2 workshops were held and

members from the various units and departments in the division were represented.The departments involved were:

· Asset Management Department

· Asset Maintenance Department

· Asset Development Department

· Engineering Department

Following the workshops, an inspection and maintenance plan outlining maintenancetasks to be performed and their frequencies were then established.

In general, the inspection and maintenance plan for the assets are categorized based

on two broad categories:

· Non –

intrusive Inspection: Inspection tasks where no outage of substation

equipment is required.

· Intrusive Inspection/Maintenance/Overhaul:

Inspection/Maintenance/Overhaul where the equipment is required to be de-energized and therefore plant/equipment outage is compulsory.




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The maintenance interval or frequencies are categorized into calendar time,

operational number and as required. Calendar time used is months and years. Thetime interval is normally determined by the statutory requirement, type of equipment

and probability of failure (P-F) interval of the equipment to be maintained. For

operational number, it is determined by the manufacturer ’s recommendation e.g.number of OLTC operation.

As for the as required maintenance interval, no specific interval has been defined. The

decision on the maintenance interval will be based on the operating environment of

the asset, operating duty of the asset, condition of the asset, performance of the asset,

age of the asset, criticality of the asset and event related e.g. condition assessment of

the asset. The Head of Department (HOD) may be required to carry out a RCM

analysis on the asset to be maintained.

6 Implementation and Data MonitoringAfter commissioning and prior to the equipment warranty expires, end-of-warranty

inspection and tests are carried out to determine the equipment condition. This is to

ensure equipment is acceptable for further operation in the network. Details of the

end-of-warranty test are covered in the Site Acceptance Test document. Once the end-

of-warranty test has been carried out successfully, the maintenance plan for the

equipment is finalised.

The maintenance interval outlined in this guideline is determined based on available

data at the point of the analysis. The guideline shall be reviewed in the future when

more data is collected and where reliability and efficiency indices could bedetermined.

Hence it is important that all observations during inspections, repair and replacement

work are properly recorded and documented by the Asset Maintenance Department inthe Plant Maintenance Module of the Enterprise Resource Management System

(ERMS).

7 Maintenance PerformanceIn ensuring that the objectives of maintenance are achieved, the maintenance

performance shall be monitored in terms of productivity, reliability and availability.

These performance indicators shall be specified in the respective Department’s KPI.The KPIs shall be set and recorded such that the KPIs are suitable for performance

trending and performance benchmarking with other utilities.




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8 Effective DateThis document is effective from 30th September 2008 and it supersedes any previous

document before this. However, this document will be reviewed and updated from

time to time when they are any changes to be made.

9 Acknowledgement

We wish to express our sincere gratitude and appreciation to the Asset MaintenanceDepartment, Engineering Department, Asset Development Department and Strategic

Development and Management Department and others who have contributed directlyor indirectly to make it possible for the Asset Management Department to formulate

this guideline.

10 References[1] TNB Transmission Operation & Maintenance, Network Performance

and Business Development Department, April 2002.

[2] Transmission Asset Maintenance Policy, Rev.1.1, Asset Strategy Unit,December 2004

[3] Internal Technical & Management audit reports, Asset ManagementDepartment.

[4] Internal Audit Reports, Group Internal Audit Division.

[5] SGM and GM Instructions, Strategic Development and Management

Department.

[6] Centralised Tripping Information System, Asset Management

Department.[7] Various equipment O&M manuals from manufacturers.




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A. MAINTENANCE GUIDELINES FORSUBSTATIONS AND SUBSTATION PRIMARY

EQUIPMENT

1 ScopeThis section provides guidelines for maintenance of all transmission substations in

TNB Transmission system. There are two types of transmission substation designsused in TNBT:

· Conventional or Air-Insulated Substations (AIS) – This design consists ofair-insulated equipment installed in outdoor switchyards. There is a control

building within the same substation compound which houses protectiverelays, control panels, communication equipment and low voltage

switchgears.

· Gas-Insulated Substations (GIS) – This design utilizes SF6 gas-insulated

equipment. In TNBT, the GIS switchgears can be located inside a buildingor outdoor.

The maintenance guidelines determine the tasks to be done at the substation site (civil

and M & E works) as well as primary equipment within the substation and the

frequencies of these tasks. The primary equipment covered in this document includes

equipment in substations energized at 11kV, 22kV, 33kV, 66kV, 132kV, 275kV and

500kV as follows:

i. Circuit breakers

ii. Power transformers

iii. Earthing transformers

iv. Transformer cable tails

v. Instrument Transformers

vi. Disconnectors/earthing switches

vii. Surge arresters

viii. Reactor/capacitor banksix. Earth grid and earth mast

x. Neutral Earthing Resistor

xi. Busbar/clamps/droppers




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2 General InformationPrimary equipment in the TNB Transmission system consists of a large population

with a variety of manufacturers and designs. In general, there are more than 20

manufacturers for each type of equipment.

Failure modes of the primary equipment vary from one to another. Typical root causes

of failure as captured form the Centralised Tripping Information System (CTIS) andRCM analysis include:

· Circuit Breakers

i. Loose parts in assembly

ii. Degradation of insulation medium (vacuum, oil, SF6)

iii. Worn out seals (pneumatic, gas, hydraulic)

iv. Fatigue operating rods, cranks, levers and linkages

v. Poor lubrication of linkages

· Power transformers

i. Outgoing feeder cable faults

ii. Animal encroachment

iii. Transformer cable tail and termination failures

iv. Vermin and moisture ingress into accessories

v. Earthing transformer failures

vi. Poor workmanship

vii. Poor maintenanceviii. Protection scheme failures

· GISi. Leaking SF6

ii. Flashover of the SF6 compartment

iii. Leaking hydraulic and pneumatic circuit breaker operating

mechanisms

· Earthing transformers

i. Poor workmanshipii. Animal encroachment

iii. Poor maintenanceiv. Vermin and moisture ingress into accessories

· Transformer cable tails

i. Poor cable quality & aging problems

ii. Poor workmanship on joints/terminations

· Instrument Transformers (capacitive voltage transformers (CVT),

electromagnetic voltage transformers (VT) and current transformers (CT))




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Major causes of insulation degradation of instrument transformer are as

follow:i. Contaminant ingress to the insulation

ii. Natural ageing due to service condition or age

iii. Transient surges

· Disconnectors/Earthing Switches

i. Misalignment of the blade

ii. Vermin intrusion due to improper/degrading seals at cable lugs

iii. Faulty motor

· Surge ArrestersMajor causes of degradation of surge arresters are as follow:

i. Wrong application class of surge arrester

ii. Moisture ingress to the insulation

iii. Degradation of housing – applicable to polymeric housing arresters

· Capacitor and Reactor Banksi. Encroachment of animals/birds at exposed terminal

ii. Short circuit of fuse of capacitor can

iii. Leaking of oil from capacitor unitiv. Degradation of paint for reactor (dry type)

· Earth grids/Earth Masts

i. Earth Shield wire: Rubbing at crossing due to loose connection togantry and conductor sag

ii. Fatigue fittings of earth shield wire

iii. Corrosion of earth terminationiv. Theft of earthing tape

· Neutral Earthing Resistors

Liquid type:

i. Evaporation/leaking of electrolyte

ii. Crystallization of electrolyte over years

Dry Type:

i. Loose/corroded connection

ii. Failure of resistor elements

· Busbar/clamps and connectors/droppers




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i. Loose/corroded connection

ii. Tilting of busbar/broken clamp due to sinking foundationiii. Exposed LV busbar

iv. Encroachment of foreign objects

3 Inspection and Maintenance PlanAfter commissioning and prior to the equipment warranty expires, end-of-warranty

inspection and tests are carried out to determine the equipment condition as to ensureequipment is acceptable for further operation in the network. Details of the end-of-

warranty test are covered in the Site Acceptance Test document. Once the end-of-warranty test has been carried out successfully, the maintenance plan for the

equipment is finalized.

Inspection and maintenance of substation and substation primary equipment arecarried out on a planned routine basis or when situation warrants. The maintenance

shall be adequate to provide the acceptable degree of confidence when operating the

substation. The maintenance type and maintenance frequency required by plant or

equipment are determined based on the manufacturers’ recommendations in the

Operation and Maintenance Manual, utilities best practices and RCM analysis carried

out by TNB Transmission. This section describes the inspection and maintenance

tasks required and the maintenance plan for the substation equipment.

3.1 Entire Plant

3.1.1 VegetationThis includes grass cutting and weeding for existing landscaping if any

3.1.2 Fencing inspection

To ensure both fencing and access gate are in good condition

3.1.3 Drainage inspection

To ensure all drains are not clogged

3.1.4 Lighting inspection

Perimeter lighting, switchyard lighting and building lighting shall be inspected




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3.1.5 Pest control

3.1.6 Roadway inspection

Table 3.1 Maintenance plan for entire plant

No. Details Intrusive/

Non-intrusive

Interval

3.1.1 Vegetation N Monthly

3.1.2 Fencing inspection N Monthly

3.1.3 Drainage inspection N Monthly

3.1.4 Lighting inspection N 2 Months

3.1.5 Pest control N 3 Months

3.1.6 Roadway inspection N 2 Months

3.2 Building

3.2.1 General inspection

This includes check on doors, windows, ceiling, walls, flooring, roller shuttersare in good condition

3.2.2 Air condition system inspection

3.2.3 Fire equipment inspection

i. For portable fire extinguisher equipment: renew BOMBAcertification as per statutory requirements

ii. For the CO2 system:

- Check zone operations for smoke and heat detectors

- Check wiring for continuity- Activate alarm at control box for correct zone operations

- Check high-pressure fire hose to ensure it is intact- Simulate fire within zones (without CO2 discharge)




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3.2.4 Water leakage inspection

3.2.5 Telephone system inspection

3.2.6 Lift/hoists/cranes servicing

3.2.7 Compressor system servicing

Table 3.2 Maintenance plan for building


Non-intrusive

Interval

3.2.1 General inspection N 2 Months

3.2.2 Air condition system inspection N 2 Months

3.2.3 Fire equipment inspection N 2 Months

3.2.4 Water leakage inspection N 2 Months

3.2.5 Telephone system inspection N 2 Months

3.2.6 Lift/hoists/cranes servicing N Yearly

3.2.7 Compressor system/ Standby generator servicing N Yearly




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3.3 Switchyard

3.3.1 Foundation inspectionCheck foundation for deterioration of base concrete and steel structure forwhite rust of all equipment

3.3.2 Thermo graphic scanning

Check all equipment, clamps, connections, bushings and cable terminations

for hot spot.

3.3.3 Earthing connection inspection

Check earthing connections to all the equipment.

Table 3.3 Maintenance plan for switchyard

No. Details Intrusive/ Non-

intrusive

Interval

3.3.1 Foundation inspection N 2 Months

3.3.2 Thermographic scanning N 6 Months

3.3.3 Earthing connection inspection N 2 Months




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3.4 High Voltage (HV) Outdoor Circuit Breaker

HV Outdoor circuit breaker in TNB’s Grid network uses SF6 or minimum oilas the interrupting medium with the former constitutes majority of the circuit

breakers. Three types of circuit breaker operating mechanism are in usedmainly spring operation followed by hydraulic operation and pneumatic

operation. The maintenance activities for the HV circuit breakers are asfollows:-

3.4.1 Visual inspection

i. Inspect insulators for crack, burn mark and chipping

ii. Check motor, compressor (for pneumatic breakers), pump

(hydraulic breakers) for unusual noiseiii. Inspect for oil leak/air leak of the operating mechanismiv. Inspect control circuit and operating mechanism cubicles for the

following:-

- heaters operation

- clean vents

- seals and latch

3.4.2 Trip counter reading

3.4.3 Motor run hour reading

This applies to pneumatic and hydraulic operating mechanism

3.4.4 Water purging from the air reservoir/vessel

This applies to pneumatic operated mechanism without auto-water-purge

facility

3.4.5 Operating mechanism check

i. Check pump/motor/compressor operation

ii. Lubrication of linkages where necessary.iii. For spring type operating mechanism:

- Check dashpot for sign of oil leaks

- Check spring guides/limit indicator are in place

iv. For hydraulic type operating mechanism:- Inspect accumulator pre-charge pressure and replace worn out

seals if necessary

- Inspect accumulator for corrosion and repaint if required.

- Check hydraulic pump operation, measuring the time taken to

pressurize the accumulator to required level.




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- Inspect operation of hydraulic oil pressure gauge for

hydraulic mechanism and alarm functions.

3.4.6 Gauges/interlock system check

i. Check operation of all gauges to ensure proper alarms are triggeredand interlocks operated (where applicable)

3.4.7 Diagnostic tests

i. Contact resistance measurementii. Circuit breaker timing test

iii. Dew point test and purity test for SF6 gasiv. Pre-insertion closing resistor/grading capacitance measurement

(where applicable).The above tests are carried out periodically or when required, in order to

determine the overall condition of the circuit breaker.

3.4.8 Additional diagnostic tests

i. Contact travel and speed measurementii. Circuit breaker vibration analysis

iii. Insulation test for tripping and closing circuit (from local controlcubicle onwards)

iv. SF6 contamination test

Additional diagnostic tests may only be performed upon directives by HOD

when situation warrants such as investigative measures when abnormalities

are detected during periodic diagnostic tests.

3.4.9 Seals/O-rings replacement

i. Replace seals/o-rings, hydraulic filter and hydraulic oil for

hydraulic operated mechanism. This specifically applies to Koncar

and Alsthom hydraulic operated circuit breakers

ii. Replace seals/o-rings for pneumatic operated mechanism. This

specifically applies to BBC pneumatic operated circuit breakers

3.4.10 Insulating oil replacement (applicable for minimum oil circuit breakers)

i. Replace insulating oilii. Inspect blast nozzle for pitting marks and misalignment

iii. Inspect arcing contacts

iv. Replace o-rings




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3.4.11 Circuit breaker operation

Circuit breaker is required to be operated by opening/closing operation of the

circuit breaker. This is to ensure that circuit breaker operates reliably when

intended thus reducing the possibility of CB slow-moving operation due tolong inactivity of circuit breaker.

Table 3.4 Maintenance plan for HV (outdoor) circuit breaker


intrusive

Interval

3.4.1 Visual inspection N 2 months

3.4.2 Trip counter reading N 2 months

3.4.3 Motor run hour reading N 2 months

3.4.4 Water purging from air reservoir N 2 months

3.4.5 Operating mechanism check I 4 Years/

2 Years forCapacitor and

Reactor Bank

3.4.6 Gauges/interlock system check I 4 Years

3.4.7 Diagnostic tests I 4 Years/2 Years for

Capacitor andReactor Bank

3.4.8 Additional diagnostic tests I As required

3.4.9 Seals/o-ring replacement for

hydraulic/pneumatic operating mechanism

I 8 Years

3.4.10 Insulating oil replacement for minimum oilcircuit breaker

I 4 Years or after 3faults whichever

comes first3.4.11 Circuit breaker operation I Once in 2 Years




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3.5 Medium Voltage (MV) circuit breaker

MV circuit breakers in TNB’s Grid network are metal-clad and use vacuum or

minimum oil as the interrupting medium with the former constitute majority ofthe circuit breakers. The MV circuit breaker uses spring operation for the

operating mechanism. The maintenance activities for the MV circuit breakersare as follows:-


i. Check all doors are properly closed

ii. Ensure switchgear door is locked with non-standard lock

3.5.2 Trip counter reading

3.5.3 Trip circuit healthy check

3.5.4 Airborne ultrasound test

3.5.5 Routine inspection

i. Inspect the spout and shutterii. Check discoloration of tulip contacts/busbar due to heat or

improper contactiii. Clean vacuum bottle (applicable to vacuum circuit breaker)

iv. Inspect railing alignment for blockagev. Check operating mechanism for signs of overheating

3.5.6 Lubrication

i. Grease contact fingers

ii. Lubricate linkages and operating mechanism as recommended bymanufacturer

iii. Check trip hook for LV switchgear.

3.5.7 Interlock system check

i. Inspect for both electrical and mechanical interlock




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i. Contact resistance measurement

ii. Vacuum insulation test (for vacuum circuit breakers)

iii. Circuit breaker timing test

The above tests are carried out periodically or when required, in order to

determine the overall condition of the circuit breaker.

3.5.9 Trip coil waveform measurement

3.5.10 Insulating oil replacement for oil circuit breakers

3.5.11 Circuit breaker operation

Circuit breaker is required to be operated by opening/closing operation of the

circuit breaker. This is to ensure that circuit breaker operates reliably when

intended thus reducing the possibility of CB slow-moving operation due tolong inactivity of circuit breaker.

Table 3.5 Maintenance plan for MV circuit breaker


intrusive

Interval

3.5.1 Visual inspection N 2 Months

3.5.2 Trip counter reading N 2 Months

3.5.3 Trip circuit healthy check N 2 Months

3.5.4 Airborne ultrasound test N 3 Months

3.5.5 Routine inspection I 4 Years3.5.6 Lubrication I 4 Years

3.5.7 Interlock system check I 4 Years

3.5.8 Diagnostic test I 4 Years

3.5.9 Trip coil waveform measurement I As required

3.5.10 Insulating oil replacement for oil circuit breakers I 4 Years or after 5

faults whichever

comes first

3.5.11 Circuit breaker operation I 2 Years or in line

with TNBDoutages

whichever comesfirst




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3.6 Power Transformers

Power transformers installed in TNB’s Grid network are of oil insulating type.Power transformer has four main components i.e. on-load tap changer

(OLTC), bushings, windings and insulating oil. Routine maintenance for power transformers are carried out on either time or operational basis. The

maintenance activities for the power transformers are as follows:-


i. Winding and oil temperature checksii. Oil level indicator and oil leak checks

iii. Gaskets, coolers, pumps, fans, motors operations checks

iv. Checks for oil leak at cable boxes and cablesv. Paint/protective coating and corrosion checksvi. Bushing: check for broken/damaged sheds

vii. Checks for leaking valves

viii. Checks for name plate visibility/readable

ix. Silica gel & container glass inspection

x. Local control cubicle panel door seals inspection

xi. Light, heater and thermostat setting in local control panel inspection

xii. Foundation plinth and cable bracket inspection

xiii. Check for Hydran alarm (if applicable)

3.6.2 OLTC position and operation counter reading

3.6.3 Oil tests

i. Analysis of dissolved gasses in oil (DGA)

ii. Moisture/water content in oil

iii. Neutralization index (acidity) of oil

iv. Dielectric breakdown of oil

3.6.4 Routine inspection and operational checks

i. Clean bushing/insulators

ii. Check of terminal blocks, oil level gauges, cable termination box andother accessories for being fully sealed/moisture proof.

iii. Simulation test on micro-switch for PRD and Buchholz relay

iv. Buchholz relay check (for flag/alarm operation and fascia indication)




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v. Test of emergency stop button for OLTC

vi. Test of fan switching element for on/off at right temperaturevii. Test of running oil/winding temperature alarm for functionality

viii. Test of MCB and alarm circuitry

ix. Test of OLTC timer alarmx. Test of OLTC out of step alarm

xi. Inspection of V-belt of OLTC motor for looseness

xii. Test operation of pump motor contactor

xiii. Valve position check

3.6.5 OLTC operational check

Running through of all tap positions is to be done on transformers during

routine inspection and operational checks (3.6.4) to ensure that the changing

of taps from the lowest to the highest is smooth thus preventing accumulation

of coke at the tap contacts. For transformer where the tap position is fixed,OLTC operational check is to be done every 2 years.

3.6.6 OLTC minor maintenance

i. Oil replacement and inspection of all transition resistors, braided wire

and contacts (Frequency is based on manufacturer ’s recommendations)

ii. Check condition of OLTC position and operation counters

3.6.7 OLTC parts replacement

i. Braided wire and contact parts replacement (Frequency is based on

manufacturer ’s recommendations)


i. Power factor test on transformer winding and bushing

ii. Insulation resistance test with polarisation index

iii. Transformer winding resistance test

iv. Oil power factor test

The above tests are carried out periodically or when required, in order todetermine the overall condition of the power transformer.




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i. Transformer ratio test

ii. Polarity and vector group test

iii. Core excitationiv. Frequency Response Analysis

Additional diagnostic tests may only be performed upon directives by HODwhen situation warrants or when abnormalities are detected e.g. after a

tripping event.

Table 3.6 Maintenance plan for power transformer


intrusive

Interval

3.6.1 Visual inspection N 2 Months3.6.2 OLTC position and operating counter reading N 2 Months

3.6.3 Oil sampling N Yearly

3.6.4 Routine inspection and operational checks I 4 Years

3.6.5 OLTC operational check I 4 Years or 2

Years for tapchanger at fixed

position.

3.6.6 OLTC minor maintenance I OEM’s

recommendation

3.6.7 OLTC parts replacement I OEM’srecommendation

3.6.8 Diagnostic tests I 4 Years





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3.7 Earthing Transformer


i. External connection checks

ii. Check of terminal blocks, oil level gauges, HV termination and other

accessories for being fully sealed/moisture proof

iii. Oil level indicator and oil leak checks

iv. Checks for oil leak at cable boxes and cablesv. Paint/protective coating and corrosion checks

vi. Transformer/cable guards inspection (for open bushing terminations)vii. Checks for leaking valves and valve positions

viii. Checks for name plate visibility/readable

ix. Silica gel & container glass inspectionx. Inspection of protective housing for Buchholz relayxi. Check conservator filling cap for tightness (for MTM transformers)

3.7.2 Oil sampling

i. Analysis of dissolved gasses in oil (DGA)

ii. Moisture/water content in oiliii. Neutralization index (acidity) of oil

iv. Dielectric breakdown of oil

3.7.3 Routine inspection and operational checks

i. Check cable termination condition at cable boxes.

ii. Rectify moisture condensation in cable boxes.

iii. Simulation test on micro-switch for PRD (if installed) and Buchholz

relay

iv. Buchholz relay check (for flag/alarm operation and fascia indication)

v. Test of MCB and alarm circuitry

vi. Valve position check


i. Power factor test on winding and bushingsii. Insulation resistance test with polarization index

The above tests are carried out periodically or when required, in order to

determine the overall condition of the earthing transformer.




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i. Transformer ratio test

ii. Polarity and vector group testiii. Core excitation test

iv. Winding resistance test

Additional diagnostic tests may only be performed upon directives by HODwhen situation warrants or when abnormalities are detected e.g. after a

tripping event.

Table 3.7 Maintenance plan for earthing transformer


intrusive

Interval


3.7.2 Oil sampling N Yearly

3.7.3 Routine inspection and operational checks I 4 Years3.7.4 Diagnostic tests I 4 Years





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3.8 Transformer Cable Tails

This covers power cable connections between transformers, earthing

transformers, switchgears and neutral earthing resistor inside the substation.


i. Check for leaks at transformer cable box

ii. Check termination oil leak/ discoloured

iii. Cable sheath earth connection

iv. If applicable inspect the SVL – cracks / tightnessv. If applicable check the cable sealing ends.

3.8.2 Cable accessories inspection

i. Inspect earthing connections at terminations

ii. Inspect cable support structure at transformer terminationsiii. Inspect general condition of cable trenchesiv. Inspect general condition of cable markers (if installed along cable

route in the substation)

3.8.3 Insulation resistance measurement with polarization index

3.8.4 Cable sheath insulation test

3.8.5 On-line partial discharge measurement

This is a diagnostic test and may only be performed upon directives by HOD

when situation warrants or on selected cables.

Table 3.8 Maintenance plan for transformer cable tails


intrusive

Interval


3.8.2 Cable accessories inspection N Yearly

3.8.3 Insulation resistance measurement I As required

3.8.4 Cable sheath insulation test I 4 Years

3.8.5 On-line partial discharge measurement N As required




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3.9 Current Transformer

Majority of current transformers installed in TNB’s Grid network arehermetically sealed. This type of current transformer requires minimal

maintenance. Based on the manufacturers’ recommendations in the Operationand Maintenance Manual, utilities best practices and RCM analysis carried out

by TNB Transmission, the maintenance type and frequency required by thecurrent transformer are determined. The maintenance activities for the current

transformers are as follows:-


i. Inspect oil level

ii. Check for oil leakageiii. Check for insulator chipping, damage and its cleanlinessiv. Check nameplate to ensure it is readable.

v. Check cable gland for the tightness & it is vermin proof


i. Secondary terminal box for corrosion and tightness of connectionii. Primary terminal for tight connection

iii. DLA tap for proper grounding

iv. Check condition of bellow.


i. Power factor test

ii. Capacitance measurement

Diagnostic tests may only be performed upon directives by HOD when

situation warrants such as oil leak detected during visual and routine

inspection.

3.9.4 Oil Tests

Diagnostic tests may only be performed upon directives by HOD whensituation warrants such as oil leak detected during visual and routine

inspection.




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Table 3.9 Maintenance plan for current transformer


intrusive

Interval


3.9.2 Routine inspection I 4 years

3.9.3 Diagnostic tests I As required

3.9.4 Oil tests I As required




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3.10 Voltage Transformers/Capacitive Voltage Transformer

Most of voltage transformers installed in TNB’s Grid network are of the

capacitive type and hermetically sealed. This type of voltage transformerrequires minimal maintenance. Based on the manufacturers’ recommendations

in the Operation and Maintenance Manual, utilities best practices and RCManalysis carried out by TNB Transmission, the maintenance type and

frequency required by the voltage transformer are determined. Themaintenance activities for the voltage transformers are as follows:-


i. Inspect oil level

ii. Check for oil leakage

iii. Check for insulator chipping and its cleanliness

3.10.2 Secondary voltage measurement


i. Secondary terminal box for corrosion and tightness of connection

ii. Primary terminal for tight connectioniii. Check condition of bellow

iv. Check voltage limiting device (where applicable)

3.10.4 Diagnostic test

i. Capacitance measurement

Diagnostic tests may only be performed upon directives by HOD when

situation warrants such as oil leak detected during visual and routineinspection.

Table 3.10 Maintenance plan for voltage transformer


intrusive

Interval


3.10.2 Secondary voltage measurement N 2 months

3.10.3 Routine inspection I 4 years

3.10.4 Diagnostic test I As required




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3.11 Disconnectors/Earth Switches

3.11.1 Visual inspectioni. Inspect insulators for cracks, or burns or pollutants deposits

ii. Check motor drive cabinet for the following:

- Heater operation

- Miniature circuit breaker (MCB)iii. Clean ventilation openings

iv. Check motor drive cabinet is properly latched and seals are in good

condition

v. Check for visible misalignment/over travel/discoloration of

primary contactsvi. Check for leakage of grease at insulator base and motor gear

vii. Check earth tape connections from the disconnectors to thesubstation earthing system

viii. Check condition of earth mat (if applicable)

3.11.2 Primary contact routine inspection

Where possiblei. Check tightness of bolts and nuts

ii. Check springs of female contact for rust and its elasticityiii. Check contact fingers for pitting marks, erosion, corrosion and

clean if necessaryiv. Check for alignment of primary contacts and arcing tips

v. Check arcing tips for excessive arc damagevi. Check for simultaneous closing of all blades for 3 phases

3.11.3 Operating mechanism functional check

i. Check linkages, rods and levers for smooth operation, ensure all joints are secured tightly

ii. Lubrication of bearings with appropriate approved grease for non

sealed bearings

iii. Grease rotating and hinges points

iv. Check alignment of auxiliary contacts

v. Grease operating mechanism of the auxiliary contacts

vi. Check operation of interlocks

vii. Check operation of motorviii. Check operation of all safety interlocks

ix. Operate ON/OFF switch to ensure proper functioning




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Table 3.11 Maintenance plan for disconnector


intrusive

Interval

3.11.1 Visual Inspection N 2 months

3.11.2 Primary contact routine inspection I 4 years

3.11.3 Operating mechanism functional check I 4 years Note :

Item 3.11.2, 3.11.3 are applicable to busbar disconnector when visual inspection/thermographicscanning detects sign of failure




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3.12 Surge Arresters

3.12.1 Visual inspectioni. Inspect for cracks, pollutant deposits on insulator housing

ii. Check for operation of pressure relief vent

iii. Check earthing connection from surge arresters to the groundiv. Check condition of surge counter and leakage current gauge

v. Record reading of surge counter and leakage current gauge

3.12.2 Resistive leakage current measurement


i. Visual inspection as per 3.12.1

ii. Clean insulators

Table 3.12 Maintenance plan for surge arresters


intrusive

Interval

3.12.1 Visual Inspection N 2 months

3.12.2 Resistive leakage current measurement N 6 months

3.12.3 Routine inspection I As per interval

of associated bay/feeder




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3.13 Compensation Equipment

3.13.1 Air-core reactors visual inspectioni. Inspect support insulators for cracks, or burns or pollutants deposits

ii. Check for paint damage

3.13.2 Oil-filled reactor visual inspection

i. Winding and oil temperature checks

ii. Oil level indicator and oil leak checks

iii. Gaskets, coolers, pumps, fans, motors operations checksiv. Checks for oil leak at cable boxes and cables

v. Paint/protective coating and corrosion checksvi. Checks for leaking valves and valve positions

vii. Checks for name plate visibility/readableviii. Silica gel & container glass inspection

ix. Foundation plinth and cable bracket inspection

3.13.3 Oil-filled reactor operational checks

i. Test of fan switching element for on/off at right temperature

ii. Test of running oil/winding temperature alarm for functionalityiii. Test of MCB and alarm circuitry

3.13.4 Oil test for oil-filled rector

i. Analysis of dissolved gasses in oil (DGA)ii. Moisture/water content in oil

iii. Neutralization index (acidity) of oiliv. Dielectric breakdown of oil

3.13.5 Reactor Measurement

i. Measure reactance value

3.13.6 Capacitor bank visual inspection

i. Check for leakage of oil

ii. Check for fouling, paint damageiii. Check for shrouding of live parts

3.13.7 Capacitance bank capacitance measurement

i. Measure capacitance value of individual capacitor canii. Measure terminal-to-terminal insulation resistance of capacitor can

iii. Measure terminal-to-case insulation resistance of capacitor caniv. Tightening of all primary connectivity with correct torque




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3.13 Maintenance plan for compensation equipment


intrusive

Interval

3.13.1 Air-cored reactors visual inspection N 2 months

3.13.2 Oil-filled reactors visual inspection N 2 months

3.13.3 Oil-filled reactors operational checks I 4 years

3.13.4 Oil-filled reactors oil test N Yearly

3.13.5 Reactor Measurement I 5 years

3.13.6 Capacitor bank visual inspection N 2 months

3.13.7 Capacitor bank capacitance measurement I 5 years




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3.14 Substation Earth Grid and Overhead Earth Wire

3.14.1 Visual inspection of overhead earth wirei. Check crossing of earth conductors to ensure conductors are not in

contact

ii. Check condition of conductor fittings

3.14.2 Visual inspection of gantry top

i. Check lightning rod condition and connection (where applicable)

3.14.3 Measurement for earth grid resistance

Table 3.14 Maintenance plan for substation earth grid/earth masts


Non-

intrusive

Interval

3.14.1 Visual inspection of earth mast N 6 months

3.14.2 Visual inspection of gantry top N 6 months

3.14.3 Measurement for earth grid resistance N 8 years

3.15 Neutral Earthing Resistors


i. Inspect electrolyte level (applicable to liquid type)

ii. Check ground connection

3.15.2 NER resistance measurement

Table 3.15 Maintenance plan for neutral earthing resistors


Non-intrusive

Interval


3.15.2 NER resistance measurement I As required(Dry type)

4 Years (Liquid

Type) Note:Item 3.15.2 is normally carried out during 11/33kV busbar shutdown




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3.16 Busbar/Busbar clamps/Dropper

3.16.1 Thermographic scanning

Table 3.16 Maintenance plan for busbar/busbar clamps/dropper


intrusive

Interval

3.16.1 Thermographic scanning N 6 months




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3.17 SF6 Gas-Insulated Switchgears (GIS)

Most of SF6 GIS installations in TNB’s Grid network are in-door and located

at power stations and urban areas. GIS installation requires minimalmaintenance. Based on the manufacturers’ recommendations in the Operation

and Maintenance Manual, utilities best practices and RCM analysis carried out by TNB Transmission, the maintenance type and frequency required by GIS

are determined. The maintenance activities for the GIS are as follows:-


i. Record the SF6 pressure from the density gaugeii. Check for oil leaks (applicable to hydraulic or hydraulic-spring

operated breakers)

iii. Check that all earth switches and disconnectors are locked withnon-standard padlocksiv. Check heater operation of control cubicle to prevent condensation

v. Check ‘ON/OFF’ indicator for correct indication

vi. Check earth connections

vii. Check for oil leaks at cable termination compartment

3.17.2 Motor run hour reading

Record motor run hour for circuit breakers with pneumatic and hydraulic

operating mechanisms

3.17.3 Trip counter readingRecord circuit breaker counter reading

3.17.4 Routine maintenance

i. Conduct circuit breaker timing test (where facility permits)

ii. Check contact resistance of circuit breakers and disconnectors sothat they are within tolerance (where facility permits)

iii. Check interlocks of disconnectors for correct operationiv. Greasing and oiling of linkages as recommended by OEM

v. Conduct SF6 dew point & SF6 purity measurement (inclusive of

busbar compartment)

vi. Check alarm and fascia indication for correct operation

vii. Bleeding of hydraulic oil




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3.17.5 Partial discharge measurement

3.17.6 Hydraulic oil and oil filter replacementThis applies to hydraulic and hydraulic-spring operated circuit breakers as

recommended by OEM.

3.17.7 Complete assessment of GIS

Complete assessment to determine overall condition of GIS.

3.17.8 Maintenance of SF6 gas handling device

Table 3.17 Maintenance plan for GIS


Non-

intrusive

Interval

3.17.1 Visual inspection N 2 months3.17.2 Motor run hour reading N 2 months3.17.3 Trip counter reading N 2 months3.17.4 Routine Maintenance I 4 years

3.17.5 Partial discharge measurement N 2 years

3.17.6 Hydraulic oil and oil filter replacement I OEM’srecommendation

3.17.7 Complete assessment of GIS I >16 years or 20fault clearing

whichever comes

first

3.17.8 Maintenance of SF6 gas handling device N As required




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B. MAINTENANCE GUIDELINES FOROVERHEAD TRANSMISSION LINES

1 ScopeThis section outlines the maintenance guidelines for 66kV, 132kV, 275kV and 500kV

transmission line network in Transmission Division. The guidelines describe the

maintenance works to be carried out and their frequencies.

2 General Information

Overhead transmission lines are meant to transmit electricity at high voltages fromgenerating plants/high voltage substations to customers. The transmission line

network in the Transmission Division’s system ranges from 66kV to 500kV.The total

length of transmission line network that is maintained by Transmission Divisionconstitutes more than 17,000 circuit-km.

Based on the analysis of failure modes on lines tripping history, it is concluded thatthe common causes of tripping are due to the followings:-

i. Lightning

ii. Encroachment activities

iii. Danger trees/bamboo shoots

iv. Broken cross arms

v. Line hardware failures (e.g. broken insulator strings, conductor snaps)vi. Others (e.g. relay faulty/malfunction, faulty surge arrestor and circuit

breaker, etc.)

3 Critical and Non-Critical LinesThe inspection frequency is determined by the area category of the lines which are:

a) Critical/Special (C)

This category includes transmission lines or sections of lines that fall into at

least one of the following conditions:

i. Highly loaded or strategic lines (to be determined by SPOD)

ii. Road/railway/river/line crossing

iii. Highly polluted areasa. Agricultural area with high usage of fertilizer or pesticide

b. Industrial area e.g. cement plant or steel plantc. Marine area or sea shores.




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b) Non-Critical (NC)This category includes transmission lines in areas other than described in (a)

above (e.g. rural, residential etc.)

The respective region(s) shall identify the criticality of lines/sections of lines based on

the above criteria. Any lines or sections of lines that do not fall within any of the

conditions as described above, but need special maintenance requirements, shall

nevertheless be attended to as required (e.g. soil erosion places).

4 Line Inspection and Maintenance

Failure modes have shown that other than lightning, most line tripping could be

avoided by ensuring healthy operation practice and carrying out thorough monitoringactivities. The controllable failures are addressed by categorizing the transmission

lines maintenance program into 2 major categories which are line inspection and line

maintenance.

4.1 Line Inspection

Line inspection shall be carried out while the line is energized and shall include the

following activities:

i. Ground patrol & rentice inspection

ii. Aircraft warning light system inspection

iii. Tower Top Inspection (TTI)

iv. Aerial inspection

v. Thermography scanvi. Rentice clearing

vii. Clearing of ground access pointviii. Measurement of tower footing resistance

4.2 Line Maintenance

Generally, maintenance actions are carried out based upon the condition of the linecomponent that is observed during inspection. Line maintenance works shall include

repair, replacement and refurbishment/overhaul works. Maintenance works on the line

component may be carried out by the following two methods:-

i. Live-line maintenance – maintenance work that is carried out using live line

tools and techniques on high voltage overhead transmission lines 132kV,275kV and 500kV. Maintenance of high voltage overhead transmission

lines shall be carried out using live-line maintenance technique in the




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event that the outage is not permitted due to system constraint or possible

high risk that could jeopardize system’s reliability.

ii. Dead-line maintenance – maintenance work that is carried out by the

respective regions of Asset Maintenance Department of TransmissionDivision on non-critical lines, where line outage is permitted by the

System Operation Department of Transmission Division.

5 Inspection Tasks and Maintenance Plan

Inspections of Right-of-way (ROW), conductors and towers shall be carried out on a planned routine basis or when situation warrants. This section describes the inspection

tasks and the maintenance plan required.

5.1 Ground Patrol

· Tower/Line components

i. Check for broken glass insulators or chipped porcelain insulatorsii. Check for missing, bending or corrosion bracing

iii. Check for operation of aircraft warning light (This task is best done inthe evening e.g. during thermovision inspection)

iv. Check stubs for signs of corrosion or soil erosion near tower legsv. Check for visibility and corrosion danger and phase plates

vi. Check for missing step boltsvii. Check for general condition of pole, tower, cross-arm, conductors,

fittings(including spacers and dampers) and earthwire

viii. Check for any dropped or moved spacer or vibration damperix. Check for corrosion or soil erosion at stays and stay anchors

x. Check for corrosion or damaged anti-climbing devicesxi. Check for corrosion or broken earth tape connection

xii. Check air craft warning spheres

· R.O.W./access route activities:Visual checks on:

i. vegetation conditionii. access roads

iii. centre pathsiv. construction activities under/near transmission lines

v. soil erosionvi. stubs covered by earth

vii. vegetation removal from tower legs

viii. alertness on danger tree outside rentice




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ix. trees above 6 feet height within R.O.W.

(Note: Transmission lines that traverse urban areas where there are active

construction activities should be patrolled at shorter intervals to prevent any

encroachment to the transmission lines. In the case of vegetation in R.O.W., certainlocal authorities require more frequent cutting of vegetation to ensure good aesthetics

of the local surrounding. In such cases, compliance to conditions imposed by local

authorities is necessary).

5.2 Aircraft Warning Light Maintenance -

This task is performed on aircraft warning light equipment where the

installation of such equipment is required by DCA. Maintenance is carried out

to examine the integrity of the aircraft warning light system which includes,

ensuring:-

i. Battery electrolyte is at adequate level

ii. Connectivity of cables is intact

iii. High intensity light bulbs are in good operating condition (including

reserve bulb)

iv. Cleaning of control box and solar panels etc.

5.3 Tower Top Inspection

This task entails climbing the tower while the line remains energized to visually

inspect the condition of the top part of line/tower components. It is imperative

that the safety clearances as outlined in the Line Maintenance Engineering

Guidelines are followed to carry out this task.

i. Check insulator pin for corrosion and/or pollution deposits conditionii. Check for detrimental cracks (for timber cross-arms) or bent/corroded

steel cross-arms

iii. Check insulator for cracks

iv. Check for connectivity and/or corrosion of earth bond atearthwire/OPGW cross-arms. Retighten if necessary.

v. Check for any displaced or dropped dampersvi. Check visibility and corrosion of air borne number plate

vii. Check stability and signs of corrosion of maintenance platformviii. Check condition of fittings

ix. Check condition Transmission Line Arrester (if applicable)

5.4 Aerial Inspection

This task may only be performed as and when required upon directives by

Heads of Departments in Transmission Division. Examples of situationsrequiring aerial inspection are listed below:-




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i. Emergency patrols to quickly locate faults after line trippingii. Inspection of overall conditions of towers and R.O.W. after floods or

monsoon season

iii. Patrols for lines traversing lands which are inaccessible using groundtransportation

5.5 Thermographic Scanning

i. Thermography scan of transmission lines that includes joints, mid-

span joints and clamps and to check for hotspots which indicatedeteriorating/loose connections.

5.6 Rentice Clearing

i. Cutting of vegetation within rentice area

5.7 Ground Access Point Maintenance

i. Maintaining ground access points for lines/towers so that access totowers is available at all times, especially when emergency work at

the tower location is required.

This task may only be performed as and when required upon directives byHeads of Departments in Transmission Division.

5.8 Tower Footing Resistance Measurement

i. Tower footing resistance (TFR) (to measure earth resistance at tower base)


HOD. Due consideration to be given to towers where the soil resistance mayvary due to seasonal changes or changes of soil condition and section of lines

that have experienced tripping due to lightning.

5.9 Lowest Conductor Height Measurement

i. Check for excessive sags of lowest conductor in accordance with

Section 3.13.8 of TNB Transmission Electrical Safety Rules (for

crossings and highly loaded lines only).




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Table B1 Maintenance Plan for Overhead Lines No Details Intrusive/

Non-Intrusive

Interval for

Critical Lines

Interval for Non-

Critical Lines5.1 Ground Patrol N < 3 Months or

As required

3 Months

5.2 Aircraft Warning Light

Maintenance

N Yearly Yearly

5.3 Tower Top Inspection N 4 Years 4 Years

5.4 Aerial Inspection N As required As required

5.5 Thermographic Scanning N Yearly 4 Years

5.6 Rentice Clearing N 6 months or

As required

6 months

5.7 Ground Access PointMaintenance

N As required As required

5.8 Tower Footing Resistance

Measurement

N As required As required

5.9 Lowest Conductor Height

Measurement

N 4 Years N/A

5.10 Rentice Clearing (Bandaran) N 2 Months 2 Months




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C. MAINTENANCE GUIDELINES FOR

TRANSMISSION UNDERGROUND ANDSUBMARINE CABLES

1 Scope

This section outlines the maintenance guidelines for 132kV, 230kV and 275kVunderground and submarine transmission cable network in the TNB Transmission

Division. The guidelines describe the maintenance works to be carried out and theirfrequencies.

2 General InformationUnderground transmission cables are commonly used in urban areas where there island constraint to build overhead transmission lines. The total circuit length of

underground cables that is maintained by TNB constitutes more than 700 km. Thereare 2 types of transmission cables used in the TNB transmission system. They are:

· Oil-filled cables

· XLPE insulated cables

Oil-filled cables are normally used as submarine cables in providing power

connection crossing the sea or the straits.

Based on the analysis of failure modes on transmission cables tripping history, it is

concluded that the common causes of tripping are due to the followings:· Human intervention

· Poor cable and accessories quality

· Poor workmanship on joints

3 Inspection and Maintenance PlanMaintenance of transmission cables and cable accessories shall be carried out on

a planned, routine basis. The maintenance works are aimed to provide acceptable

degree of confidence when operating the cables. This section describes the

inspection and maintenance tasks required and the maintenance plan for thetransmission cable.




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3.1 Cable route patrol

Inspection is carried out while the cable is in service and it includes the

following activities:

i. Check for missing or damaged cable markers/sign boardsii. Check for excavation/piling activities near/along the cable route and

condition of cable accessories e.g. underground oil pressure tankiii. Check physical condition of cable joint box/cable bridge/link box and

pressure gauge.iv. Check for condition of manhole cover (if applicable)

3.2 Offshore patrol for submarine cable

Regional Asset Maintenance office is required to seek cooperation from Jabatan

Laut Malaysia or relevant authority in monitoring maritime activities in the non-anchoring zone of the submarine cable and maintenance of the beacon house.

Monitoring and maintenance may include the following activities:i. Check condition of beacon light.

ii. Monitor maritime activities in the ‘non-anchoring zone’.

iii. Check overall condition of the beacon house.

3.3 Oil containment and alarm system inspection for oil-filled cable

i. Check for any operation of oil pressure alarm systemii. Check for oil leaks at cable sealing ends

iii. Check the condition of earthing connections

iv. Record oil pressure from gauge.v. Carry out lamp test at control panel

3.4 Operation test for oil containment alarm system for oil-filled

cable

3.5 Thermographic scanning

i. Check for hot spots on clamps, connections and overall thermal

condition of outdoor cable sealing ends

3.6 Cable accessories and supporting structures inspectioni. Inspection of cable bridge support structure

ii. Inspection of link boxes external condition

iii. Inspection of warning signs.




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3.7 Underground cable manholes and tunnel inspection

i. Check for condition of steel supporting structure

ii. Check for cable duct seal

iii. Check for overall concrete structure particularly for cracks and waterseepage.

iv. Check cable joint overall conditionv. Check for link box condition

vi. General cleaning and painting (when required)

3.8 Sheath insulation test for XLPE Cable

3.9 Insulation resistance test

i. Insulation resistance test for all cables


HOD.

3.10 Link box internal inspection

i. Check SVL conditionii. Check for cable bonding termination condition

iii. Check for moisture sealing condition and vermin proofingiv. Check general cleanliness

3.11 Cable PD detection for XLPE cable

Cable PD detection is carried out while the cable is in service. This task mayonly be performed as and when required upon directives by HOD.

3.12 Cable outdoor sealing end inspection

i. Check for any leakage on outdoor sealing end oilii. Check cleanliness of sealing end

iii. Check earthing connections




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Table C1 Maintenance Plan for Underground cables No Details Intrusive/

Non-IntrusiveInterval

3.1 Cable route patrol N 2 Months or asrequired

3.2 Offshore patrol for submarine

cable

N As required

3.3 Oil containment and alarm

system inspection

N 2 Months

3.4 Oil containment alarm systemoperation test

I 4 Years

3.5 Thermographic scanning N 6 Months

3.6 Cable accessories inspection N 6 Months

3.7 Underground cable manholesand tunnel inspection

N 4 Years

3.8 Sheath insulation test I 4 Years

3.9 Insulation resistance test I As required

3.10 Link Box Internal Inspection I 4 Years

3.11 Cable PD Detection N As required

3.12 Cable outdoor sealing end

inspection

N 2 Months in

substation

6 months for

terminal tower




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D. MAINTENANCE GUIDELINES FORPROTECTION SYSTEM

1 Scope

This section outlines the maintenance guideline for all protection and control schemes

installed in TNB transmission network. Where applicable, this section shall be appliedto Generation and Distribution protection maintenance scope of work and the

frequencies shall be decided by the respective owners. The purpose of performingmaintenance as stipulated in this Guideline is to ensure that all protective systems

component installed in the transmission network are in good working order. It is notintended to resolve design and commissioning related issues and failures

The boundary of the protection scope of maintenance is from the terminal blocks

(inclusive of terminal blocks) of the marshalling kiosks or/and local control panel (e.g.transformers/GIS) to the secondary equipment panels (e.g. Relay/control panels, RTUinterface panels). Marshaling Kiosk is under the ownership of Primary team.

This guideline determines the tasks to be done on the protection relay systems and

frequencies of these tasks. Protection relays are devices that detect and response to

any abnormalities in the system and initiate appropriate control action(s) such that the

power system is affected the least. At present, transmission grid system is also

equipped with system protection scheme such as Force Generator Tripping Scheme

(FGTS), ATTEND, DIHS, UVLS etc. These special protection schemes shall be

tested by AMNT from time to time upon request and coordination from National Load

Dispatch Center (NLDC).


There are four types of relays:

a) electromechanical

b) static (analogue)

c) digital

d) numerical

Protection relays in operation consist of large population with variety of

manufacturers that can be difficult to establish common maintenance procedures, as

one model is different from another. The maintenance frequency of the protection

system (which requires plant outage) will be based on the type of relay used for Main




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protection. For plants where the Main protection consists of electromechanical and/or

static relay, the frequency of maintenance (which requires plant outage) will be done inevery two years. For plants where the Main protection consists of digital and/or numerical

only, the frequency of maintenance (which requires plant outage) will be done in every

four years. The frequency of maintenance is determined based on the availability ofinternal supervision function on the protection relay.

From Reliability Centered Maintenance (RCM) analysis, three major failure modesfor the relays were identified:

§ Internal relay faulty – in static, digital, numerical relays, this will result in

changing the faulty cards or modules whereas in electromechanical relays, the

moving parts may get worn out after being in operation for a number of years.

§ Wrong settings – this failure mode can be attributed to staff configuring or

keying the wrong settings especially after maintenance work was done. There

were also cases were the relay themselves are giving such problems. For

instance, the potentiometer for the reach settings for static distance relay maywear out after so many years in operation.

§ Other (e.g. Faulty connections) – inputs include CT and VT signals to therelays and outputs include trip and alarm signals. There are many possibilities

that contribute to this failure mode where there is no signal coming in or goingout of the relays.

3 Maintenance Plan

Currently, protection systems in TNB consist of static, numerical, digital and

electromechanical relays. For maintenance purposes, the relays/schemes are groupedinto the following functional units:

a) Line/Cable/Hybrid Feeder Bay b) Power Transformer/ Generator Transformer/ Reactor Bay

c) Capacitor Bank Protectiond) Bus Coupler, Bus Section and Busbar Protection

e) Generator Protection

The types of relays/schemes used for each of the above functional units are shown in

section 4: Types of relay used in TNB Transmission Protection scheme.

The following are the inspection and maintenance task for all protection relays in the

network and the detailed plan including the inspection and maintenance cycle for thevarious types of relays:




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3.1 Distance Relays

(i) Check and confirm power supply unit is healthy

(ii) Check CB and Isolator auxiliary contacts to relay(iii) Check Local Alarms & annunciation (Facia & Substation Control System)(iv) Check Tele-protection signals

(v) Measurement of CT and VT input to relay(vi) Confirm settings and configuration

(vii) Functional Test

· Distance Reach check

· Timing test

· Power Swing Blocking operation

· Switch On To Fault functions

· Voltage Transformer Supervision functions

·

Directional Earth Fault if in used (includes external DEF )· Stub function if in used (include external Stub relay)

(viii) Confirm the operation of the tripping circuits(ix) Check for lock out operation

Table 3.1 Maintenance plan for Distance Relays

No Details (I/N) Interval

Digital/Numerical Non

Digital/Numerical

1 Check and confirm power supply unit is

healthy

N 2 Years 2 Years

2 Check CB and Isolator auxiliary contacts to

relay

N 2 Years 2 Years

3 Check local alarms and annunciation I 4 Years 2 Years

4 Check Tele-protection signals I 4 Years 2 Years

5 Measurement of CT and VT inputs to relay N 2 Years 2 Years

6 Confirm settings and configuration I 4 Years 2 Years

7 Functional Test I 4 Years 2 Years

8 Confirm operation of tripping circuit I 4 Years 2 Years

9 Check for lock out operation I 4 Years 2 Years

3.2 Current Differential and Current Comparison Relays


(ii) Check CB and Isolator auxiliary contacts to relay

(iii) Check Local Alarms & annunciation (Facia & Substation Control System)




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(iv) Check Tele-protection signals

(v) Measurement of CT (Or VT if used) inputs to relay(vi) Confirm settings and configuration

(vii) Functional Test

· Transfer or Inter-trip tripping if available· Backup Distance check if used ( Refer to Distance Relays Tests)

· Timing test

(viii) Confirm the operation of the tripping circuits

(ix) Check for lock out operation

Table 3.2 Maintenance plan for Current Differential and Current Comparison Relays


Digital/Numerical

Non

Digital/Numerical

1 Check and confirm power supply unit ishealthy

N 2 Years 2 Years

2 Check CB and Isolator auxiliary contacts torelay

N 2 Years 2 Years


4 Check Tele-protection signals I 4 Years 2 Years

5 Measurement of CT (or VT if used) inputsto relay

N 2 Years 2 Years








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3.3 Pilot Wire Protection Relays

(i) Check and confirm power supply unit is healthy(ii) Check Local Alarms & annunciation (Facia & Substation Control System)(iii) Check condition and integrity of pilot wire

(iv) Measurement of CT inputs to relay(v) Confirm settings and configuration

(vi) Functional Test

· Pilot wire supervision

· End to end injection tests

· Inter-tripping circuit

· Timing test

(vii) Confirm the operation of the tripping circuits

(viii) Check for lock out operation

Table 3.3 Maintenance plan for Pilot Wire Protection Relays



Digital/Numerical


N 2 Years 2 Years


3 Check condition and integrity of pilot wire I 4 Years 2 Years

4 Measurement of CT inputs to relay N 2 Years 2 Years








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3.4 Auto Re-close Relays

(i) Check and confirm power supply unit is healthy(ii) Check CB auxiliary and “Sync-check input” contacts to relay(iii) Check Local Alarms & annunciation (Facia & Substation Control System)

(iv) Confirm settings and configuration(v) Operational Test with actual breaker

(vi) Check for lock out operation

Table 3.4 Maintenance plan for Auto re-close Relays



Digital/Numerical


N 2 Years 2 Years

2 Check CB auxiliary and “Sync-checkinput” contacts to relay

N 2 Years 2 Years



5 Operational test with actual breaker I 4 Years 2 Years





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3.5 Synchro-check Relays


(ii) Check Local Alarms & annunciation (Facia & Substation Control System)(iii) Measurement of VT input to relay

(iv) Confirm settings and configuration

(v) Functional Test

Table 3.5 Maintenance plan for Synchro-check Relays



Digital/Numerical


healthy

N 2 Years 2 Years


3 Measurement of VT input to relay I 4 Years 2 Years4 Confirm settings and configuration I 4 Years 2 Years

5 Functional test I 4 Years 2 Years

3.6 Over-current and Earth Fault Relays


(ii) Check local Alarms & annunciation (Facia & Substation Control System)

(iii) Measurement of CT input to relay


(v) Operational and timing test

(vi) Built in Trip circuit supervision test if in used(vii) Confirm the operation of the tripping circuits





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Table 3.4 Maintenance plan for Over-current and Earth Fault Relays



Digital/Numerical1 Check and confirm power supply unit is

healthy

N 2 Years 2 Years


3 Measurement of CT input to relay N 2 Years 2 Years


5 Operational and timing test I 4 Years 2 Years

6 Built in trip circuit supervision test if inused

I 4 Years 2 Years

7 Confirm the operation of the tripping

circuits

I 4 Years 2 Years


3.7 Trip Circuit Supervision Relay


(ii) Check Local Alarms & annunciation (Facia & Substation Control System)

(iii) Operational test for each trip coil

Table 3.7 Maintenance plan for Trip Circuit Supervision Relays




healthy N 2 Years 2 Years


3 Operational test for each trip coil I 4 Years 2 Years




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3.8 Transformer Differential Relays


(ii) Check Local Alarms & annunciation (Facia & Substation Control System)(iii) Measurement of CT input to relay(iv) Confirm settings and configuration

(v) Functional Test

· Operational test

· Biased characteristic test

· Inrush Blocking

· Over-excitation / Over-fluxing if in used

· Timing test

(vi) Confirm the operation of the tripping circuits

(vii) Check for lock out operation

Table 3.8 Maintenance plan for Transformer Differential Relays



Digital/Numerical


N 2 Years 2 Years





6 Confirm the operation of tripping circuits I 4 Years 2 Years7 Check for lock out operation I 4 Years 2 Years




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3.9 Restricted Earth Fault Relays

(i) Check and confirm power supply unit is healthy(ii) Check Local Alarms & annunciation (Facia & Substation Control System)(iii) Confirm settings and configuration

(iv) Operational and Timing Test(v) Confirm the operation of the tripping circuits


Table 3.9 Maintenance plan for Restricted Earth Fault Relays


Digital/Numerical

Non

Digital/Numerical


N 2 Years 2 Years





circuits

I 4 Years 2 Years





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3.10 Standby Earth Fault Relays


(iv) Operational and timing test(v) Confirm the operation of the tripping circuits


Table 3.10 Maintenance plan for Standby Earth Fault Relays



Digital/Numerical


N 2 Years 2 Years



4 Operational test with actual breaker I 4 Years 2 Years

5 Confirm the operation of the trippingcircuits

I 4 years 2 Years





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3.11 Stub Protection

(i) Check and confirm power supply unit is healthy(ii) Check line Isolator auxiliary contacts to relay(iii) Check Local Alarms & annunciation (Facia & Substation Control System)

(iv) Confirm settings and configuration(v) Functional Test

· Transfer or Inter-trip tripping if available

· Timing test

(vi) Confirm the operation of the tripping circuits(vii) Check for lock out operation

Table 3.11 Maintenance plan for Stub Protection Relays



Digital/Numerical


N 2 Years 2 Years

2 Check line Isolator auxiliary contacts to

relay

N 2 Years 2 Years




6 Confirm the operation of tripping circuits I 4 Years 2 Years





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3.12 High Impedance Busbar Differential Relays


(iv) Operational and Timing Test for all zones(v) Test on CT Supervision Circuit

(vi) Check the condition of the tripping circuits

· Isolator auxiliary contact in tripping circuit for all bays

· Transfer trip to remote end if applicable(vii) Check for lock out operation

Table 3.12 Maintenance plan for High Impedance Busbar Differential Relays



Digital/Numerical


healthy

N 2 Years 2 Years



4 Operational and timing test for all zones I 4 Years 2 Years

5 Test on CT supervision circuit I 4 Years 2 Years

6 Check condition of tripping circuits N 2 Years 2 Years


3.13 Low Impedance Busbar Protection Scheme (Centralized and De-centralized)

(i) Check and confirm power supply unit is healthy(ii) Check Local Alarms & annunciation (Facia & Substation Control System)

(iii) Check CB and Isolator auxiliary contacts to relay

(iv) Measurement of CT inputs from all bays

(v) Confirm settings and configuration

(vi) Check the condition of the tripping circuits (negative check)




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Table 3.13 Maintenance plan for Low Impedance Busbar Protection Relays




healthy

N 2 Years 2 Years



relay

N 2 Years 2 Years

4 Measurement of CT inputs from all bays N 2 Years 2 Years


6 Check condition of tripping circuits(negative check)

N 2 Years 2 Years

3.14 Circuit Breaker Failure Relays


(ii) Check CB and Isolator auxiliary contacts to relay if wired

(iii) Check Local Alarms & annunciation (Facia & Substation Control System)

(iv) Measurement of CT input

(v) Check protection initiation to breaker failure relay

(vi) Confirm settings and configuration(vii) Operational and timing test

(viii) Check the condition of the tripping circuits

· Isolator auxiliary contact in tripping circuit

· Transfer trip to remote end(ix) Check for lock out operation

Table 3.14 Maintenance plan for Circuit Breaker Failure Relays



Digital/Numerical


N 2 Years 2 Years


relay

N 2 Years 2 Years


4 Measurement of CT inputs N 2 Years 2 Years5 Check protection initiation to breaker

failure relayI 4 Years 2 Years






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3.15 Thermal Overload Relays


(iii) Measurement of CT input to relay(iv) Confirm settings and configuration

(v) Operational and timing test(vi) Confirm the operation of the tripping and/or alarm circuits

(vii) Check for lock out operation if used

Table 3.15 Maintenance plan for Thermal Overload Relays



Digital/Numerical


N 2 Years 2 Years

2 Check local alarms and annunciation I 4 Years 2 Years3 Measurement of CT input to relay N 2 Years 2 Years



6 Confirm the operation of the trippingand/or alarm

I 4 Years 2 Years

7 Check for lock out operation if used I 4 Years 2 Years

3.16 Under/Over Frequency and Under/Over Voltage (For Protection FunctionOnly)



(iii) Measurement of VT input to relay



(vi) Confirm the operation of all relevant tripping circuits

(vii) Check for lock out operation




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Table 3.16 Maintenance plan for Under/Over Frequency and Under/Over Voltage Relays




healthy

N 2 Years 2 Years


3 Measurement of VT input to relay N 2 Years 2 Years



6 Confirm the operation of all the relevanttripping and/or alarm

I 4 Years 2 Years

7 Check for lock out operation if used I 4 Years 2 Years

3.17 Pole Discrepancy Relays



(iii) Operational and timing test

(iv) Confirm the operation of the tripping circuits

(v) Check for lock out operation

Table 3.17 Maintenance plan for Pole Discrepancy Relays



Digital/Numerical


healthy

N 2 Years 2 Years



4 Confirm the operation of the trippingand/or alarm

I 4 Years 2 Years





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3.18 Automatic Voltage Regulator (AVR)


(iii) Measurement of CT and VT input to relay(iv) Operational and timing test

Table 3.18 Maintenance plan for Automatic Voltage Regulator Relays



Digital/Numerical


healthy

N 2 Years 2 Years


3 Measurement of CT and VT input to relay N 2 Years 2 Years


Note: AVR supervisory test is to be conducted by Tele-control Unit.

3.19 Unbalanced Protection


(ii) Check Local Alarms & annunciation (Facia & Substation Control System)(iii) Measurement of CT input to relay



(vi) Functional Test

(vii) Confirm the operation of the tripping circuits





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Table 3.15 Maintenance plan for Unbalanced Protection Relays




healthy

N 2 Years 2 Years





6 Functional test


circuits

I 4 Years 2 Years


3.20 Transformer Guards

(i) Alarms check(ii) Confirm the operation of tripping circuits

Note: Maintenance tests for all transformer guards alarm and tripping signals are

under Primary unit. The transformer guards shall be jointly tested with the presence

of protection personnel.

3.21 Local Instrument meters

(i) Secondary Injection test

Note: Telecontrol section is responsible to ensure the reading registered (output

from transducers) at SCS and NLDC are within allowable range. Work to be

assisted by Protection.

Table 3.15 Maintenance plan for Instrument Meters



Digital/Numerical

1 Secondary injection test I 4 Years 2 Years




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3.22 Switch-sync (Point of Wave) relays

Table 3.16 Maintenance plan for Switch-sync (Point of Wave) Relays

No Details (I/N) Interval Digital/Numerical

Non

Digital/Numerical

1 Operational check and inspection I 2 Years 2 Years

3.23 Reverse Power, Negative Phase Sequence, Over Excitation, Loss Excitation

and Under Impedance Relays

Maintenance of these relays will be carried out upon request and completemaintenance task/checklist is to be provided by Power Plant Operator/ Generation

Division.

3.24 Regular Inspection

Component/Scheme Frequency Remark

Charger 2 months Including 30V DC

system

Battery Banks 6 months Including 30V DC

system

DC distribution board 2 months -

Protection Panels 2 months -

Control Panels 2 months -

RTCC/AVR 2 months -

Marshaling Kiosks 2 months -

Disturbance recorder 2 months -

Battery Alarm Test 2 months -

3.25 Other Maintenance

Component/Scheme Frequency Remarks

Discharge tests on battery

banks

4 years 4 years for each bank.




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4 Types of Relays Used in TNB Transmission Protection

Scheme

4.1 Feeder Bay Protection

Plant Voltage Level Component/Schemes Relay

Maintenance

Plan

Line 132 and below Distance Relay 3.1

Current Diff 3.2

OC/EF 3.6

DOC/DEF 3.6

Sync Check 3.5

Auto Re-close 3.4Breaker Failure 3.14

Measurement

Instruments

3.21

Line 500/275 Distance Relay 3.1

Current Diff 3. 2

OC/EF 3.6

DOC/DEF 3.6

Sync Check 3.5

Auto Re-close 3.4

Breaker Failure 3.14

MeasurementInstruments 3.21

Pole Discrepancy 3.17

Thermal Overload 3.15

Stub 3.11

Cable 132 and below Pilot Wire Scheme 3.3

Current Diff 3.2

OC/EF 3.6

DOC/DEF 3.6


Measurement

Instruments

3.21

Cable 275 Pilot Wire Scheme 3.3Current Diff 3.2

OC/EF 3.6

DOC/DEF 3.6




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Measurement

Instruments

3.21

Thermal Overload 3.15Stub 3.11

4.2 Power Transformer/ Generator Transformer/ Reactor Bay Protection

Plant Voltage Level Component/Schemes Relay

Maintenance

Plan

Transformer/

Reactor

132 and below Transformer Differential 3.8

REF (HV / LV) 3.9OC/EF (HV/ LV) 3.6

DOC/DEF 3.6

SBEF (where applicable) 3.10

Transformer guards 3.20

RTCC/AVR 3.18

MeasurementInstruments

3.21

Transformer/Reactor

500/275 Transformer Differential 3.8

High Impedance Diff 3.8

REF (HV/LV) 3.9

OC/EF (HV/LV) 3.6

DOC/DEF 3.6SBEF 3.10

Transformer Guards 3.20


RTCC/AVR 3.18

Measurement

Instrumentation

3.21




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4.3 Capacitor Bank Protection

Plant Voltage Level Component/Scheme

Relay

MaintenancePlan

Cap Bank All Unbalance Current 3.22

Under Current 3.6

Under/Over Voltage 3.16

OC/EF 3.6

Thermal Overload 3.15

Switch Sync 3.23

AVR 3.18

4.4 Bus Coupler, Bus Section and Busbar Protection

Special note: Bus section, Bus coupler and busbar maintenance are to be performed

together.

Plant Voltage LevelComponent/Scheme

Relay

Maintenance

Plan

Busbar 500/275/132 High/ Low Impedance 3.12, 3.13

CT supervision (for high

impedance relays

3.12, 3.13

Busbar Aux Contact 3.12, 3.13

Bus coupler

and Bussection

All Over Current 3.6




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4.5 Generator Protection

Plant Voltage Level Component/scheme RelayMaintenance

Plan

Generator All Overall Diff 3.8

Reverse Power 3.23

Negative Phase

Sequence

3.23

Over Excitation 3.23

Loss of Excitation 3.23

Under Impedance 3.23

Stator Earth Fault 3.6

Rotor Earth Fault 3.6Thermal Overload 3.15

Under/Over Frequency 3.16

Under/Over Voltage 3.16

Over-current/EarthFault

3.6

MeasurementInstrument

3.21




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E. MAINTENANCE GUIDELINES FOR STATIC VARCOMPENSATOR (SVC) EQUIPMENT

1 ScopeThis section outlines the maintenance guidelines for SVC equipment in TNB

Transmission Division. The guidelines describe the maintenance works to be carried out

on SVC equipment and their frequencies.


SVC is used mainly to provide voltage control during daily load cycles, dynamicreactive power reserves in the event of network disturbances such as loss of generation

and/or loss of transmission and also for damping of active power oscillations. At

present, there are two SVC installations located at KL North substation (KULN) andYong Peng North substation (YGPN).

The major equipment in SVC installation are Circuit breaker, Transformer, Thyristor-switched capacitor (TSC), Thyristor-controlled reactor (TCR), Filter banks and

secondary equipment. The maintenance strategy for SVC equipment is based on

manufacturer ’s recommendation and TNB maintenance experience.

In deriving the maintenance guidelines, SVC equipment are divided into four major

groups as follows:-

a) Thyristor related equipment b) Control and Protection for SVC Equipment

c) SVC Primary Equipmentd) Auxiliary equipment

3 Inspection and Maintenance PlanMaintenance of SVC and related equipment shall be carried out on a planned, routine

basis. The maintenance works are aimed to provide acceptable degree of confidence

when operating the SVC. This section describes the inspection and maintenance tasks

required and the maintenance plan for the SVC equipment.




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3.1 Thyristor related equipment

3.1.1 Thyristor Valves

No Details Intrusive/

Non-Intrusive

Interval

i Visual inspection on cleanliness,

fibre optics condition, coolingtubes and valve components

NI Monthly

ii Inspection on Trigger pulse

amplifier panels and LEDstatuses

NI Monthly

iii Inspection on By-pass Breaker

(where applicable)

NI Monthly

iv Check on power supply circuits

and test points at trigger pulseamplifier

I Quarterly

v Check Thyristor valve voltagedivision (as recommended by the

manufacturer)

I Yearly

vi Trigger pulse converter and

Thyristor fault monitoring (asrecommended by the

manufacturer)

I Yearly

3.1.2 Thyristor cooling system

No Details Intrusive/ Non-Intrusive Interval


leakage and general condition

NI Monthly

ii Record reading from pressuregauges, level meter, flow meter

and conductivity meter.

NI Monthly

iii Note the operational sound andvibration for the motor pump

NI Monthly

iv Check cooling supervision

function against actual operation

I Quarterly

v Cleaning of the outdoor air blast

coolers

I Quarterly

vi Thyristor cooling system yearend maintenance (as

recommended by the

manufacturer)

I Yearly




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3.2 Control and Protection for SVC equipment

The control system must provide stable operation under normal as well as

contingency conditions whilst the protection system is designed such that allequipment is fully protected and any equipment which is operating in abnormal

way is properly removed from service. All SVC protections are properlycoordinated between each of the SVC equipment and with the AC system

protection (where required).

3.2.1 VarMaster Control Local and Remote panel


Non-Intrusive

Interval


cubicle lights and heaters.

NI Monthly

ii Confirm correct readings areindicated on the meters and

instrumentations.

NI Monthly

iii Check for any alarm operationon the facia.

NI Monthly

iv Check computer operation andLED statuses.

NI Monthly

v VarMaster Hardware check (asrecommended by the

manufacturer)

I Yearly

vi VarMaster Control Pulse

computers functional check (asrecommended by the

manufacturer)

I Yearly

3.2.2 On-load measurement for protection scheme


Non-Intrusive

Interval

i Record the unbalance current for

capacitor banks

NI Monthly

ii Record current and voltage for

all protection scheme (as

recommended by themanufacturer)

NI Yearly




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3.2.3 Protection Relays for the SVC Primary Equipment

The maintenance task for the protection relays for the SVC Primary equipment

follows the maintenance task for the protection relays as mentioned in

Maintenance Guideline for Protection Systems.

3.3 SVC Primary Equipment

The SVC Primary equipment consists of transformer, circuit breaker, isolator,

current transformer, voltage transformer, capacitor, reactors and switchyard. The

maintenance task for the SVC primary equipment follows the maintenance task forequipment as mentioned in Substation Maintenance Guidelines.

3.4 Auxiliary EquipmentAuxiliary equipment includes ventilation, air conditioning, fire detection and

fighting system, building condition and etc. as appropriate. The maintenance taskfor these items follows the maintenance task for Building and Entire plant as

mentioned in Substation Maintenance Guidelines. Additional maintenance taskwhich is considered important is also to be carried out.

3.4.1 Measurement of room temperature


Non-Intrusive

Interval

i Measurement of roomtemperature for main control

room, Var Master conrol room

and Thyristor valve room.

NI Weekly




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F. MAINTENANCE GUIDELINES FOR HIGHVOLTAGE DIRECT CURRENT (HVDC)

EQUIPMENT

1 ScopeThis section outlines the maintenance guidelines for HVDC equipment in TNB

Transmission Division. The guidelines describe the maintenance works to be carriedout and their frequencies.


HVDC is used mainly for long distance transmission, interconnection of powersystems, long submarine cables and to increase efficiency in power control. At present, there is only one HVDC converter station in Gurun and the station provides

interconnection of the power networks between Malaysia and Thailand.

The maintenance guidelines cover equipment in HVDC convertor station. Themaintenance strategy for HVDC equipment is based from manufacturers’

recommendation and TNB maintenance experience.

In deriving the maintenance guidelines, HVDC convertor station is divided to five

major areas as follows:-

a) Convertor equipment

b) DC Primary Equipmentc) AC Primary Equipment

d) Control, Instrumentation and Protection

e) General services and auxiliary equipment

3 Inspection and Maintenance PlanMaintenance of HVDC equipment and related equipment shall be carried out on a

planned, routine basis. The maintenance works are aimed to provide acceptable

degree of confidence when operating the HVDC equipment. This section describes

the inspection and maintenance tasks required and the maintenance plan for the

HVDC equipment.

3.1 Converter Equipment

This includes equipment required for conversion from AC to DC and vice versa.

The convertor equipment is located in the Valve hall. It consist of indoor air

insulated suspension type thyristor and direct water cooling system for the

component of the valve.




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3.1.1 Thyristor Valve


Non-Intrusive

Interval

i Visual inspection N 2 Monthlyii Routine Inspection I Yearly

iii Check grading electrode 2% at

random and long rod insulators10% at random

I 4 Years

3.1.2 Valve cooling system

No Details Intrusive/ Non-Intrusive

Interval

i Visual inspectionCheck conductivity

N 2 Monthly

ii Routine InspectionCheck cooling coil for scaling,cleaning of cooling towers

I Yearly

iii Replace resin I 4 Years

iv Overhaul cooling pump I 2 Years

3.1.3 Thyristor Valve Electronics


Non-Intrusive

Interval

i Visual inspection and dustcleaning

I Yearly

3.2 DC Primary Equipment

DC Primary equipment provides the interfacing between the convertor

equipment and the DC overhead lines. The equipment and the maintenance task

are described in the following clauses.




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3.2.1 DC Filter Active Part

DC Filter active parts are used to eliminate higher harmonic and minimize

telecommunication interference. The maintenance activities are as follows:-


Non-Intrusive

Interval

i Visual Inspection N 2 Monthly

ii Replace backup batteries, clean

pcbs, lubrication and greasing

I Yearly

iii Replace fan bearings I After 30000 hrs ofoperation

iv Check tightness of connections I 5 Years

3.2.2 DC Voltage Divider

The maintenance task for DC Voltage divider follows the maintenance task forCapacitive Voltage Transformer as mentioned in Substation Maintenance

Guideline.

3.2.3 High Speed Ground Switch

High speed ground switch is used for continuous operation during neutral line

fault where the switch is closed and the DC current will return to the ground.The maintenance task for High Speed Ground Switch follows the maintenance

task for HV Circuit breaker as mentioned in Substation MaintenanceGuideline.

3.2.4 DC Filter Circuit Breaker

The maintenance task for DC Filter Circuit Breaker follows the maintenance

task for HV Circuit breaker as mentioned in Substation Maintenance

Guideline.

3.2.5 DC Disconnector, Grounding Switches and Valve Hall Earthing switches

The maintenance task for DC Disconnector, grounding switches and valve hall

earthing switches follows the maintenance task for Disconnectors as

mentioned in Substation Maintenance Guideline.

3.2.6 DC Filter Capacitors, DC Filter Reactors and Smoothing Reactors

The DC filters consist of capacitor and reactors and they are used to eliminate

the lower harmonic content. The smoothing reactors are used to reduce rate ofrise of DC current for DC side fault and it also forms part of high frequency

noise filtering. The maintenance task for DC Filter Capacitors, DC Filter

Reactors and Smoothing Reactors follows the maintenance task for

Compensation Equipment as mentioned in Substation Maintenance Guideline.




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3.2.7 DC Switchyard

The DC switchyard is similar to AC substation switchyard. The maintenance

task for DC switchyard follows the maintenance task for AC Switchyard asmentioned in Substation Maintenance Guideline.

3.3 AC Primary Equipment

AC Primary equipment provides the interfacing between the convertor

equipment and the AC network or the Transmission grid. The equipment andthe maintenance task are described in the following clause.

3.3.1 AC Filter Capacitors, AC Filter Reactors and Capacitor Subbank

The AC filters consist of capacitor and reactors and they are used to eliminate

the harmonic content. The Capacitor subbank is used for compensation ofreactive power absorbed by the converter. The maintenance task for AC Filter

Capacitors, AC Filter Reactors and Capacitor subbank follows themaintenance task for Compensation Equipment as mentioned in Substation

Maintenance Guideline.

3.3.2 AC Filter Resistors


Non-Intrusive

Interval

i Visual Inspection NI 2 Monthly

ii Cleaning , check tightness of

connections

I Yearly

3.3.3 Converter Transformer

The converter transformer consists of three single-phase, three-winding

transformer. The converter transformer is used to stepdown/up the AC voltageto commutation voltage for the converter equipment. The maintenance task for

Converter transformer follows the maintenance task for Power Transformer asmentioned in Substation Maintenance Guideline.

3.3.4 AC Current and Voltage Transformers

The AC Current and Voltage transformers are used for AC,DC Filters and

shunt reactors. The maintenance task for these instrument transformers followsthe maintenance task for current transformer and voltage transformer asmentioned in Substation Maintenance Guideline.

3.3.5 AC Switchyard

The maintenance task for HVDC station’s AC switchyard follows the

maintenance task for AC Switchyard as mentioned in Substation MaintenanceGuideline.




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3.4 HVDC Control and Protection

HVDC control system is designed such that to provide the desired power

transmission level. The control system must provide stable operation undernormal as well as contingency conditions.

The protection system is designed such that all equipment is fully protected andany equipment which is operating in abnormal way is properly removed from

service. All HVDC protections are properly coordinated between each of theHVDC equipment and with the AC system protection (where required).

The monitoring system provides operation information related to HVDCsystem, HVDC station, auxiliary equipment and station alarms. The

maintenance activities for HVDC control and protection are as follows:-


Non-Intrusive

Interval

i DC Protection and Pole ControlFunction test

Intrusive Yearly

ii Teleprotection Intertrip test Intrusive Yearly

iii Converter TransformerProtection test

Intrusive Yearly

iv AC Protection relays Intrusive Yearly

v Circuit breaker trip test Intrusive Yearly

The maintenance task for secondary DC supply system follows the maintenance

task as mentioned in Protection equipment maintenance guidelines.

3.5 General services and auxiliary equipment

Auxiliary equipment includes ventilation, air conditioning, fire detection and

fighting system, building condition and etc. as appropriate. The maintenance

task for these items follows the maintenance task for Building and entire plant

as mentioned in Substation maintenance guidelines.




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G. MAINTENANCE GUIDELINES FOR

SUBSTATION CONTROL SYSTEM (SCS)

1 Scope

The section outlines the maintenance guidelines for substation control system (SCS)installed in TNB Transmission network. The guidelines describe the tasks to be done on

the equipment and the frequencies of these tasks.


The Substation Control System (SCS) are installed in substations for the collection, processing, storage, retrieving, and distribution of data obtained from substation

equipment and other sources. SCS also supports the operation of power system by providing local monitoring and control facilities as well as providing interface to SCADA

master station for remote operation.

The SCS is designed to be an expandable, technology adaptable, modular hierarchy ofsegments, elements and subsystems. It is not expected that SCS equipment will require

extensive scheduled preventive maintenance. Advancements in technology, with self-

supervision features, have eliminated most preventive maintenance requirements.

· Operational Availability (OA)Operational Availability is measured from the issuance of fault reports to the

rectification of the problem.

· Mean Down Time (MDT)Maximum MDT is the maximum time for Maintenance Team toclear/repair/normalized the fault from the issuance of fault report to the rectification

of the problem.

·

Preventive MaintenancePreventive maintenance includes all scheduled maintenance action performed toretain SCS in specified condition. Scheduled maintenance includes the periodic

inspections, condition monitoring, critical item servicing, software back up andcalibration.




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· Corrective MaintenanceCorrective Maintenance includes unscheduled maintenance actions performed as a

result of SCS failure to restore the SCS to a specified condition. The tasks include

failure identification, isolation of faulty equipment, replacement and retesting.

· Failure ModesSCS failure could cause a total or partial failure to the Network, Station, and Bay

Level control and monitoring function. The SCS is designed such that a single failureshall not affect the operation and functions of both network level and station level.

The SCS is designed such that a single failure shall not affect the operation andfunctions of more than one bay or diameters.

Possible Failure includes:

Subsystem and Functions Failure ModeHuman Machine Interface Total Partial

Gateway Total

Station Level Controller Total Partial

Bay Controller Unit Total Partial

Internal Communication Network:

Single Bay Total Partial

Multiple Bay Impossible Impossible

3 Objectives

The primary objective of SCS maintenance is to achieve and sustain the operationalavailability (OA) and mean down time (MDT) objectives of the SCS at the least life cycle

cost.

It also describes the general concept and plan for maintaining Substation Control System(SCS) Hardware (HW) and Software (SW) in support of SCS operational objectives. This

guideline is applicable for maintenance support of SCS HW and SW until the end of thesystem life cycle.

This guideline also serves to:

i. Document SCS maintenance strategiesii. Optimize maintenance costs

iii. Standardize maintenance activitiesiv. Help achieve TNBT’s business plans and targets




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4 Maintenance Plan

4.1 Preventive Maintenance

Frequency Task

One year interval per substation Back up Application SoftwareData (Settings, Events, Log Files)

Visual Inspection

Cleaning

Maintenance support (i.e. Organization, Spares Parts Provision, etc) will be performed as

required to meet SCS operations requirements.

5 DocumentationAll visual inspection observation, tests performed on all SCS shall be recorded

appropriately and kept in regional database for future references and analysis. The datashall be kept both in hard copy and soft copy.




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H. MAINTENANCE GUIDELINES FOR REMOTE

TERMINAL UNIT (RTUS)

1 Scope

The section outlines the maintenance guidelines for all Remote Terminal Units (RTUs)installed in TNB Transmission network.

These guidelines determine the tasks to be done on the equipment and the frequencies of

these tasks.


The maintenance guidelines cover the Remote Terminal Unit and include the SupervisoryInterface Panel and the I/O wiring between the RTU and the Supervisory Interface Panel,

as shown in Figure 1 below. These guidelines does not cover plant auxiliary contacts,heavy-duty interposing relays and transducers mounted in control panels, DC system and

the communication network equipment.




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2.1 Failure Modes

· Hidden Failure

A functional failure that does not manifest itself until function is required.

· Partial FailureA failure that results in reduced performance or functionality of any of the RTU’s primary functions. For example, an RTU is said to have suffered a partial failure

when 16 out of its total 128 analog measurements cannot register any readings.

· Complete FailureFailure which results complete loss of all of the RTU’s primary functions.

3 Objectives

The primary objective of RTUs maintenance is to achieve and sustain the operationalavailability (OA) and mean down time (MDT) of the RTUs at the least life cycle cost.

The guidelines also serve to:

i. Document RTU maintenance strategiesii. Optimize maintenance costs

iii. Standardize maintenance activities

iv. Improve RTUs operational reliability and availabilityv. Help achieve TNBT’s business plans and targets

4 Maintenance Plan

4.1 Failure Mode, Effect and Criticality Analysis (FMECA)

FMECA study performed on the RTU established that the most appropriate maintenancestrategy involves operating the RTU to failure and restoring it back to service as soon as

possible.

The FMECA also identified the need to perform regular periodic inspections to ensurethat the RTU’s operating environment is within specified limits, and to conduct periodic

functional checks to resolve any hidden failures before they manifest themselves.

4.2 Preventive Maintenance

Periodic inspections shall be carried out on all RTU sites to:




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i. Ensure that RTU’s operating environment is within the specified acceptable

limits. The inspection shall check for environmental parameters such astemperature and input supply voltages. This Overall System Check shall be

carried out once a year on each RTU.ii. Confirm RTU functionality. Functional System Check shall be performed once

every 4 years and can be performed at the same time as the overall systemcheck.

5 DocumentationAll visual inspection observation, tests performed on all RTU shall be recorded

appropriately and kept in regional database for future references and analysis. The datashall be kept both in hard copy and soft copy.

Asset Maintenance TNBT Guideline rev 03

Documents

Transcript of Asset Maintenance TNBT Guideline rev 03