Volume 7 Final CD

PETRONAS Procedures and Guidelines for Upstream Activities (PPGUA 3.0)

OPERATIONS MANAGEMENT VOLUME 7

© 2013 PETROLIAM NASIONAL BERHAD (PETRONAS) All rights reserved. No part of this document may be reproduced, stored in a retrieval system or transmitted in any form or by any means (electronic, mechanical, photocopying, recording or otherwise) without the permission of the copyright owner.

VOLUME 7

OPERATIONS MANAGEMENT Table of Contents Executive Summary Contact Information Definitions Section 1: Well and Reservoir Management 1.1 Introduction 1.1.1 Reservoir Management 1.1.2 Well Management 1.1.3 Annual Review (FRMR/FRW) 1.1.4 Full Field Review (FFR) 1.2 Different Stages of Reservoir Management 1.2.1 Early Depletion Stage 1.2.2 Middle and Late Stage 1.2.3 Full Field Review (FFR) 1.2.4 Improved and Enhanced Recovery 1.3 Well and Reservoir Management Plan 1.3.1 Reservoir Management Strategy and Plan 1.3.2 Well Flow Assurance Management 1.3.3 Idle String Management 1.4 Production Enhancement 1.5 Annual Field Performance Review 1.5.1 FRMR/FRW 1.5.2 Requirement for FRMR/FRW 1.6 Well Abandonment 1.7 Asset Relinquishment (Subsurface) Section 2: Well Test and Surveillance 2.1 Introduction 2.1.1 Oil Producing Well 2.1.2 Gas Producing Well 2.1.3 Injection Well 2.2 Periodic Production Rate Test 2.3 Bottom Hole Pressure Survey 2.3.1 Static Bottom Hole Pressure (SBHP) Survey 2.3.2 Transient Pressure Survey 2.3.3 Flowing Survey for Oil Producing Well 2.3.4 Deliverability Test for Gas Producing Well 2.3.5 Production Logging Tool (PLT) Survey

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11 11 13 15 15 15 16 16 16 17 17-18 18 18-19 19-20 20 20-21 21 21-22 22 22 22-23 23 23 23 24 24 24 24 24 24-25 25 25-26 26 26 26 27

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OPERATIONS MANAGEMENT 2.3.6 Saturation Logging Survey 2.4 Injection Wells 2.4.1 Injection Rate Measurement 2.4.2 Injectivity Test 2.4.3 Injection Profiling Survey 2.4.4 Injection Fall Off Survey 2.5 Record Keeping and Data Quality 2.6 Production Allocation 2.6.1 Production Allocation to Each Producing String 2.6.2 Production Allocation to Each Producing Interval Section 3: Facilities Reliability and Integrity Management 3.1 Introduction 3.2 Reference 3.3 Management System 3.3.1 Leadership and Commitment 3.3.2 Policy and Strategic Objectives 3.3.3 Organisation, Roles and Responsibilities 3.3.4 Reliability and Integrity Management Processes 3.3.5 Improvement Plan and Implementation 3.3.6 Assurance/Audit 3.3.7 Management Review 3.4 Operation of Facilities 3.5 Inspection and Maintenance 3.5.1 Compliance to Legislative Requirements 3.5.2 Philosophy and Related Documents 3.5.3 Minimum Requirements for Inspection & Maintenance of Topsides/Onshore Terminals 3.5.3.1 Mechanical Static Equipment 3.5.3.2 Major Rotating Equipment 3.5.3.3 Safeguarding Devices and Systems 3.5.3.4 Fire Fighting and Life Saving Equipment 3.5.4 Minimum Requirements for Inspection & Maintenance of Structures 3.5.5 Minimum Requirements for Inspection & Maintenance of Pipelines 3.5.6 Minimum Requirements for Inspection & Maintenance of Wellhead and Downhole Systems 3.5.7 Minimum Requirements for Inspection & Maintenance of Subsea Systems

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OPERATIONS MANAGEMENT 3.6 Planning and Implementation 3.7 Materials Management 3.8 Contracting and Contractor Management 3.9 Reporting and Key Performance Indicators (KPI) 3.10 Major Failures and Corrective Action 3.11 Management of Change 3.12 Information and Knowledge Management 3.13 Preservation 3.14 Facilities Modification, Upgrading or Rejuvenation Section 4: Liquid Hydrocarbon Measurement 4.1 Introduction 4.1.1 Scope 4.1.2 Distribution, Intended Use and Regulatory Considerations 4.2 Definitions 4.3 General Requirements 4.3.1 Units of Measurement 4.3.2 Approval Requirements 4.3.2.1 Measurement and Allocation Concept 4.3.2.2 Metering Project Implementation - Metering Specification 4.3.2.3 Metering Project Implementation - Metering Acceptance 4.3.3 Static Measurement Project Implementation 4.3.4 Government Regulatory Requirements 4.3.5 Deviation 4.3.6 Documentation 4.4 Design 4.4.1 General Requirements 4.4.2 Meter Run Design/Pipework 4.4.3 Meters 4.4.4 Prover Design 4.4.4.1 Displacement Prover 4.4.4.2 Master-Meter Prover 4.4.5 Field Instrument Requirements 4.4.6 Computer Based Monitoring and Control Functions Requirements 4.4.7 Sampling and Analysis Requirements 4.4.8 Metering Data 4.5 Calibration, Testing and Commissioning 4

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OPERATIONS MANAGEMENT 4.5.1 General Requirements 4.5.2 Calibration 4.5.2.1 Displacement Prover Calibration 4.5.2.2 Master-Meter Prover Calibration 4.5.3 Testing 4.5.3.1 General Testing 4.5.3.2 Factory Acceptance Test 4.5.3.3 Site Acceptance Test 4.5.4 Commissioning 4.6 Operation, Validation and Accounting 4.6.1 General Requirements 4.6.2 System Operations 4.6.3 System Validation 4.6.4 System Maintenance 4.6.5 Security 4.6.6 Accounting and Allocation 4.6.7 Metering Station Record Keeping 4.6.8 Direct Reporting 4.7 Final Provision 4.8 References Section 5: Gas Measurement 5.1 Introduction 5.1.1 Scope 5.1.2 Distribution, Intended Use and Regulatory Considerations 5.2 Definitions 5.3 General Requirements 5.3.1 Units of Measurement 5.3.2 Approval Requirements 5.3.2.1 Measurement and Allocation Concept 5.3.2.2 Metering Project Implementation - Metering Specification 5.3.2.3 Metering Project Implementation - Metering Acceptance 5.3.3 Government Regulatory Requirements 5.3.4 Deviation 5.3.5 Documentation 5.4 Design 5.4.1 General Requirements 5.4.2 Mechanical Requirements and Primary Element

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OPERATIONS MANAGEMENT 5.4.2.1 Orifice Meter 5.4.2.2 Gas Ultrasonic Meter (Multi-Path) 5.4.2.3 Other Meters 5.4.3 Field Instrument Requirements 5.4.4 Computer Based Monitoring and Control Functions Requirements 5.4.5 Sampling and Analytical Instrumentation 5.5 Calibration, Testing and Commissioning 5.5.1 General Requirements 5.5.2 Calibration 5.5.3 Testing 5.5.3.1 General Testing 5.5.3.2 Factory Acceptance Test 5.5.3.3 Site Acceptance Test 5.5.4 Commissioning 5.6 Operations, Validation and Accounting 5.6.1 General Requirements 5.6.2 System Operations 5.6.3 System Validation 5.6.4 System Maintenance 5.6.5 Security 5.6.6 Accounting and Allocation 5.6.7 Metering Station Record Keeping 5.6.8 Direct Reporting 5.7 Final Provision 5.8 References Section 6: Onshore/Offshore Operations 6.1 Introduction 6.2 Notice of Intent 6.3 Operations Manual/Equipment Dossier 6.4 Simultaneous Operations Procedures 6.5 As-Built Drawings 6.6 Shutdown 6.6.1 Shutdown Plan 6.6.2 Unplanned Shutdown 6.7 Daily Production Operations Report 6.8 Monthly Performance Report and Production Forecast 6.9 Terminal Operations 6.10 Inspection and Operations Audit 6

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OPERATIONS MANAGEMENT 6.11 Integrated Operations 150 6.11.1 Introduction 150 6.11.2 Objective 150 6.11.3 Requirement 150-151 6.11.4 Standard Request & Budget Submission 151 Section 7: Gas Flaring/Venting Limit 152 7.1 Objective 152 7.1.1 Non-Associated Gas (NAG) 152 7.1.2 Associated Gas (AG) 152-153 7.2 Flaring/Venting Limit 153 Section 8: PETRONAS Guidelines for Barges Operating Offshore Malaysia (PGBOOM) 154 8.1 Introduction 154 8.1.1 Application 154 8.1.2 Requirements 155-156 8.1.3 Definitions 156 8.1.3.1 Steel or Other Equivalent Material 156 8.1.3.2 Non-Combustible Materials 156 8.1.3.3 A Standard Fire Test (as defined in SOLAS Chapter II-2 Regulation 3) 156-157 8.1.3.4 “A” Class Divisions (as defined in SOLAS Chapter II-2 Regulation 3) 157 8.1.3.5 “B” Class Divisions (as defined in SOLAS Chapter II-2 Regulation 3) 157-158 8.1.3.6 “C” Class Divisions (as defined in SOLAS Chapter II-2 Regulation 3) 158 8.1.3.7 Public Spaces 158 8.1.3.8 Control Stations 158 8.1.3.9 Corridors 158 8.1.3.10 Accommodation Spaces 158 8.1.3.11 Stairways 158 8.1.3.12 Service Spaces (low risk) 159 8.1.3.13 Category “A” Machinery Spaces 159 8.1.3.14 Other Machinery Spaces 159 8.1.3.15 Hazardous Areas 159 8.1.3.16 High Risk Service Spaces 159 8.1.3.17 Open Decks 159 8.2 Accommodation Spaces 159 PPGUA/3.0/042/2013

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OPERATIONS MANAGEMENT 8.2.1 Restrictions 8.2.2 Construction 8.2.3 Arrangement of Sleeping Spaces 8.2.4 Size of Sleeping Spaces 8.2.5 Berths and Lockers 8.2.6 Washing, Toilet and Shower Spaces 8.2.7 Mess Rooms 8.2.8 Hospital (Sick Bay) 8.2.9 Miscellaneous Accommodation Spaces 8.3 Automatic Fire Detection and Alarm Systems 8.4 Automatic Flammable Gas Detection and Alarm Systems 8.5 Life Saving Appliances 8.5.1 Life Rafts 8.5.2 Life jackets 8.5.3 Lifebuoys 8.5.4 Line Throwing Appliances 8.5.5 Muster List 8.5.6 Survival Equipment 8.6 Fire Fighting Equipment 8.6.1 Fire Pump 8.6.2 Fire Water Main 8.6.3 Fire Hose 8.6.4 Hydrants (Fire Monitors) 8.6.5 International Shore Connection 8.6.6 Portable Fire Extinguisher 8.6.7 Firemen’s Outfits 8.6.8 Sprinkler System 8.7 Provision for Helicopter Services 8.7.1 Helideck 8.7.2 Fire Extinguishers 8.8 Operating Manual 8.8.1 Operating Manual 8.9 Structural Fire Integrity 8.9.1 Requirements Governing the Application of the Tables 8.10 General Waste and Scheduled Waste Management 8.11 Electrical Power Supply Section 9: Asset Relinquishment 9.1 Introduction 9.2 Relinquishment 8

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OPERATIONS MANAGEMENT 9.3 The Relinquishment Process 175 9.3.1 Exploration/Development Period 175 9.3.2 Production Period 176-177 Section 10: Decommissioning of Upstream Installations 178 10.1 Introduction 178 10.2 Decommissioning Philosophy and Requirement 178 10.2.1 PETRONAS’ Decommissioning Philosophy 178-179 10.2.2 General Decommissioning Requirement 179-180 10.3 Legal Framework 180 10.3.1 General 180-181 10.3.2 Environmental 181-182 10.3.3 International Obligations 182 10.4. Pre-decommissioning Process 182-183 10.4.1 Establishment of Decommissioning Options Assessment 183-186 10.4.2 Decommissioning Plan 186 10.4.3 HSE Requirement Health 186-187 10.4.4 Consultation and Liaison 187-188 10.4.5 Incorporation in Work, Programme and Budget (WPB) 188 10.5 Decommissioning Execution 188 10.5.1 Project Execution Plan 188-194 10.6 Post Decommissioning Process 194 10.6.1 Removal of Debris and Land/Seabed Clearance 194 10.6.2 Verification 194-195 10.6.3 Post Environmental Assessment 195 10.6.4 Disposal 195 10.7 Report 195 10.8 De-gazetting and Admiralty Chart 195 10.9 Residual Liability 195 10.10 Contractor’s Obligations during Handover 196 Section 11: Operating Performance Improvement 197 11.1 Introduction 197 11.2 Performance Management 197 11.2.1 Key Performance Indicators (KPI) 197-201 11.2.2 Performance Reporting 201-202 11.2.3 Management Meeting 202 11.3 Bad Actor Management 202 11.3.1 Identification of Bad Actor field 202-203 11.3.2 Action Item for Bad Actor field 203 11.3.3 Criteria to Graduate 203 PPGUA/3.0/042/2013

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OPERATIONS MANAGEMENT Abbreviations Appendix 1 Appendix 2 Appendix 3 Appendix 4 Appendix 5 Appendix 6 Appendix 7 Appendix 8 Appendix 9

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VOLUME 7

OPERATIONS MANAGEMENT Executive Summary This volume provides Contractor with a comprehensive inventory of all the guidelines related to Operations Management. The volume is arranged in eleven (11) sections as follows: SECTION

GUIDELINES

Section 1

Well and Reservoir Management

Section 2

Well Test and Surveillance

Section 3

Facilities Reliability and Integrity Management

Section 4

Liquid Hydrocarbon Measurement

Section 5

Gas Measurement

Section 6

Onshore/Offshore Operations

Section 7

Gas Flaring/Venting Limit

Section 8

PETRONAS Guidelines for Barges Operating Offshore Malaysia (PGBOOM)

Section 9

Asset Relinquishment

Section 10

Decommissioning of Upstream Installations

Section 11

Operating Performance Improvement

Contact Information All correspondence related to this volume shall be addressed to: SUBJECT

CONTACT

Well and Reservoir Management

Head Subsurface Asset Management Petroleum Operations Management Petroleum Management Unit

Well Test and Surveillance

Head Subsurface Asset Management Petroleum Operations Management Petroleum Management Unit

Facilities Reliability and Integrity Management

Head Production Operations Petroleum Operations Management Petroleum Management Unit

Liquid Hydrocarbon Measurement


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OPERATIONS MANAGEMENT SUBJECT

CONTACT

Gas Measurement


Onshore/Offshore Operations


Gas Flaring/Venting Limit


PETRONAS Guidelines for Barges Operating Offshore Malaysia (PGBOOM)


Asset Relinquishment

For Exploration Phase: Senior Manager Exploration PSC & Business Development Petroleum Resource Exploration Petroleum Management Unit For Development Phase: Senior Manager Commercial & Strategy – Value Management Petroleum Arrangement Petroleum Resource Development Petroleum Management Unit For Production Phase: Senior Manager Compliance Management Compliance Petroleum Operations Management Petroleum Management Unit

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Decommissioning of Upstream Installations


Operating Performance Improvement

Senior Manager Operational Excellence Compliance Petroleum Operations Management Petroleum Management Unit

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OPERATIONS MANAGEMENT Definitions TERM

DEFINITION

Equipment Register

An equipment inventory comprising pressure vessels, boilers, heat exchangers, launchers & receivers, tanks, cranes, Single-Leg Buoy Mooring (SLBM)/Single Buoy Mooring (SBM) systems, rotating equipment, structures, fire fighting and lifesaving equipment, pipelines, wellhead and subsea systems.

Facilities

Infrastructure related to the production and processing of hydrocarbons including but not limited to wells, structures, sub-structures, pipelines, sub-sea systems, terminals and floaters.

Halal

Allowed, permitted by Islamic Law and certified by local Islamic authority or foreign Islamic authorities approved by Jabatan Kemajuan Islam Malaysia (JAKIM).

Integrity

The ability of the asset to perform the required function(s) under specified operating conditions with the risk of failure endangering safety of personnel, environment or the asset value reduced to an acceptable level throughout its service life.

Major Failures

Facilities failure that leads to prolonged production deferment of up to seventy-two (72) hours, damage to facilities, adverse impact to Health, Safety and Environment and any other major failures deemed by PETRONAS to have a critical impact.

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OPERATIONS MANAGEMENT TERM

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DEFINITION

Marine Facilities

Defined as, but not limited to: Floating Production, Storage and Offloading Unit (FPSO), Floating Storage and Offloading Unit (FSO), Mobile Offshore Production Unit (MOPU), Single Point Anchor Reservoir (SPAR)/Tension Leg Platform (TLP) and their ancillaries (buoys, chains, anchors, turrets/risers).

Offshore Installations

Any upstream installation beyond the official coastal line (territorial sea, shallow water & deep water as in Appendix 8.5 to 8.7) that includes: platform topside & substructure, offshore pipeline, offshore development well/subsea well and marine facilities.

Onshore Installations

Any upstream installation that includes: land production topside & substructure, crude/gas terminal topside & substructure, land pipeline and land development wells.

Petroleum Arrangement

Types of contractual arrangements entered into between PETRONAS and any other parties, which may take the form of a Production Sharing Contract, Risk Service Contract and/or other forms of contract as may be developed by PETRONAS.

Pipeline

The physical facilities use to transport the product (liquid or gas) from one offshore platform to another offshore platform or from an offshore platform to Pipeline End Manifold (PLEM)/ Pipeline End Termination (PLET) or from an offshore platform to the terminal or from a subsea well to an offshore platform and all of the above which are governed by ASME code B31.4, ASME code B31.8 and API 17 B & J for flexible risers.

Reliability

The ability of the asset to perform the required function(s) under specified operating conditions for a stated period of time.

Shadowing Period

This refers to a duration during which the new Contractor learns and understands the production operations processes and procedures from the existing Contractor.

Substructure

Defined as, but not limited to: platform jackets, piles and other foundations.

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OPERATIONS MANAGEMENT Section 1: Well and Reservoir Management 1.1 Introduction

This section provides Contractor with the basic framework of the reservoir management guidelines for the following:

a) The continuous acquisition of reservoir data and the monitoring and analysis of reservoir performance, with reasonable accuracy and as appropriate through the field life cycle b) The carrying out of periodic FFR and other studies for the further development for ongoing reserves and production optimization c) The maintaining/keeping of accurate records pertaining to all reservoir related data for submission in accordance with Volume 10, Section 5: Data Management and Data Submission. An accurate well test plus other reservoir and production related data must be obtained in accordance with the requirements outlined in the relevant sections in this volume PETRONAS aims to promote optimum development by economically optimising hydrocarbon recovery and maintaining optimal field performance.

For the purpose of this section, the term “reservoir” may also include reference to a fault block or compartment where the unit is being managed.

Contractor must operate in a manner that is consistent with principles of sound reservoir management at all stages of the reservoir’s life cycle.

1.1.1 Reservoir Management Reservoir management is defined as:

An ever-changing and ongoing process, which must be conducted at all stages of petroleum reservoir system’s life cycle (from discovery to abandonment) thus ensuring the optimum development and depletion of the reservoirs.

Reservoir management must be a multidisciplinary process aimed at cost effectively enhancing the knowledge and understanding of the reservoir system and translating that enhanced understanding into operational plans for ongoing development in order to optimise production and reserves. A reservoir system includes any associated aquifers, gas caps, wells and surface facilities.

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OPERATIONS MANAGEMENT 1.1.2 Well Management Well management is defined as:

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A systematic approach to maintaining a conduit to and from the reservoir in order to ensure that optimum reservoir management can be achieved.

A well must serve its purpose, namely: to support reservoir management and surveillance whilst maintaining the integrity and safety of its operations. Well management includes well integrity management and idle well inventory management.

1.1.3

Annual Review (FRMR/FRW) An annual review is defined as an official discussion between Contractor and PETRONAS to discuss, but not necessarily be limited to the following topics:

a) b) c) d)

Contractor should supply visuals and other documentation relevant to the topics being discussed.

The annual review refers to the Field Reservoir Management Review (FRMR) and/or the Field Review Workshop (FRW).

1.1.4

Full Field Review (FFR) Full Field Review (FFR) entail a comprehensive and multidisciplinary re-evaluation of all basic reservoir characterisation data, dynamic reservoirs and well performance data as well as considering the relevant surface facilities pertaining to an oil or gas field. This re-evaluation must use the most relevant current interpretation techniques to maximise knowledge distillation from the data. Such re-evaluation should include, but not be limited to:

a) b) c) d) e)

reservoir performance well performance future plans the way forward for the discussed field

seismic reprocessing sequence stratigraphic correlations petrophysical re-evaluation re-evaluation of reservoir and fluid properties fit for purpose 3-D static and dynamic reservoir modeling

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OPERATIONS MANAGEMENT 1.2

Different Stages of Reservoir Management

1.2.1 Early Depletion Stage Contractor shall operate in a manner that is consistent with the optimum reservoir management strategy of the field as approved in the Field Development Plan (FDP). Contractor shall ensure that prudent reservoir management policies or strategies are being implemented at all times. The reservoir management strategy may need to be revised or modified in light of any new data that is acquired during the initial development stage. Depending upon the variations of the new data from the FDP data, a revised FFR may be required.

During the course of production operations, Contractor is required to maintain a database of production, pressure, reservoir performance and data relating to reservoir geological description. Contractor shall update models and/or the performance forecast, with the new data, when necessary. Contractor shall also submit a proposal for PETRONAS’ review and approval if the reservoir performance and other data show that a different reservoir management strategy other than that approved in the FDP is required for optimum reservoir management. Prior to submitting the proposal for PETRONAS’ approval, Contractor shall hold an upfront technical review with PETRONAS.

Due to the uncertain drive mechanism and in accordance with prudent management practices all Gas-Oil-Ratio (GOR) controls or reservoir pressure controls, where appropriate, shall be addressed in the approved FDP. If significant uncertainty exists in the reservoir drive mechanism, the FDPs should contain multiple scenarios that cover the potential range of reservoir drive mechanisms and reservoir descriptions and consequently the range of anticipated reservoir behavior.

However, if no studies have been conducted, the reservoir GOR shall be limited to one and a half times the solution gas-oil ratio at initial reservoir pressure (1.5 x Rsi) during the initial production stage. This is to ensure that there is no adverse impact to oil recovery and to allow sufficient time to gather data which will aid in understanding the behaviour of the reservoir.

Nevertheless, Contractor may request PETRONAS’ approval for a revision of the GOR limit with regard to technical justification and in accordance with good industry practices. PPGUA/3.0/042/2013

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OPERATIONS MANAGEMENT Reservoir depletion shall not exceed ten percent (10%) of developed EUR per year, any depletion rate exceeding ten percent (10%) needs to be supported by techno-commercial studies and approved by PETRONAS.

Some fields may be subjected to the National Depletion Policy (NDP). Refer to Volume 4, Section 3: Crude Oil Annual Production Target and Quarterly Performance Review (QPR).

1.2.2 Middle and Late Stage Contractor must continue to gather and analyse reservoir performance data and operate in a manner that is consistent with the optimum reservoir management strategy of the field, in line with Section 1.3.1: Reservoir Management Strategy and Plan in this volume. Contractor shall apply the appropriate reservoir management tools and/or techniques for analysing field performance. Any new data that becomes available during the course of producing the field and reservoir can be used to compare actual performance to that forecasted in the FDP. Any deviation in performance from the FDP will deter optimum reservoir management and limit reservoir recovery. 1.2.3

Full Field Review (FFR) Contractor is required to conduct reservoir studies such as: a full field review or a depletion study when new data becomes available, for example, new or reinterpreted seismic data or new well data. This requirement should also be applied when the performance deviates from the FDP forecast. When performance is as expected, Contractor shall also nevertheless conduct the full field review/depletion study at least once every three (3) to five (5) years from the time of initial production. The results from the reservoir studies must be submitted to PETRONAS for review. These full field reviews/depletion studies shall cover but not be limited to subsurface static and dynamic model updates and further development opportunities.

FFR must examine interfaces and mutual optimization of the reservoirs, wells and the surface facilities and seek production and reserves optimization opportunities including, but not limited to examining the potential for:

a) Workovers b) Infill drilling 18

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OPERATIONS MANAGEMENT

c) d) e) f )

Artificial lift Secondary recovery Enhanced/improved recovery Surface facilities debottlenecking and optimisation

While some existing evaluation of data sets such as seismic, petrophysical interpretations, reservoir and fluid properties or transient well test analyses may be accepted, they must be thoroughly reviewed as part of the FFR exercise and the decision not to re-evaluate any data set comprehensively justified to PETRONAS’ satisfaction.

At any time when it is observed that the performance of the field and reservoir deviates from the FDP forecast, Contractor shall conduct FFR. FFR process flow and approval process is described in Volume 6, Section 1: Field Development Plan (FDP) Review and Approval Process.

1.2.4

Improved and Enhanced Recovery At any stage of reservoir depletion Contractor shall look for opportunities to add reserves. Artificial lift and/or improved recovery method (surface pressure debottlenecking) may be implemented in cases where natural drive mechanisms are insufficient and it is economically viable. Contractor shall submit the artificial lift and/or improved recovery programme in the FDP or FDP Revision for PETRONAS’ technical review and approval.

Examples of improved recovery methods include but are not limited to, water injection and/or immiscible gas injection for pressure maintenance as well as displacement efficiency improvement.

For fields with water injection or gas injection, Contractor shall conduct voidage replacement and a volumetric sweep analysis of each reservoir and present a summary of the results to PETRONAS on an annual basis. For water injection, the voidage replacement policy of each reservoir will be determined by the optimum reservoir management strategy (for example operating reservoir pressure requirement, injection target percentage (%) of pore volume hydrocarbon) of the field. For immiscible gas injection for pressure maintenance, the voidage replacement policy of each reservoir will be determined by the optimum reservoir management strategy (for example operating reservoir pressure requirement, injection target percentage (%) of pore volume hydrocarbon) of the field and/or a group of fields sharing the same infrastructure.

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At any stage of depletion, Contractor may seek PETRONAS’ approval for the application of enhanced recovery techniques. Contractor shall conduct a screening study for enhanced recovery development opportunities during the initial FDP and/or investigate this as part of the FFR.

Examples of enhanced recovery techniques include, but are not limited to:

a) b) c) d) e) f )

immiscible or miscible gas injection microbial enhanced recovery surfactant flooding steam flooding polymer flooding air injection

In particular, Contractor must examine the potential for reserves optimisation and geo-sequestration of greenhouse gas through immiscible and miscible carbon dioxide injection into fields that contain gas reservoirs with high carbon dioxide content.

1.3 Well and Reservoir Management Plan

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Contractor shall submit a Reservoir Management Plan (RMP) to PETRONAS for approval, which should include all strategies and plans. This RMP will be subjected to review during the annual review (FRMR/FRW). The content shall include the following but not be limited to:

1.3.1

Reservoir Management Strategy and Plan The Reservoir Management Strategy and Plan should include the various recommended operational conditions that have been developed during the field development stage with the purpose of maximising the reserves/recovery.

As stipulated in Section 1.2 in this volume, the Reservoir Management Plan shall be reviewed periodically based on when new data is acquired during the production phase of the reservoir or if there is any deviation of reservoir performance from that predicted and during every FFR. Contractor shall also provide PETRONAS with an updated simulation model of the reservoir that is compatible with PETRONAS’ system as and when requested in order to facilitate the review of the revision/update to the RMP. Any other technical study that supports the justification to revise or update the RMP may also be submitted.

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Any revision or update to the RMP requires PETRONAS approval prior to implementation as stipulated in Appendix 1.

1.3.2 Well Flow Assurance Management Contractor shall ensure reliable and continuous flow of production stream from the formation to the processing facilities and injection stream from processing facilities to the formation. Contractor shall make all efforts to remove any obstruction to flow (for example wax, asphaltine, scale, hydrate and sand) leading to sub optimal production/injection.

Integrated flow assurance studies/assessment needs to be done in the FDP and to be periodically reviewed as the new information are available during production.

1.3.3

Idle String Management Idle string is defined as a string that has not produced or injected for more than ninety (90) consecutive days. The idle string is classified according the state of its capacity. Refer to Appendix 2 for information on how an idle string is defined and classified.

Strings that are able to produce but are temporarily shut down because they are cyclic or swing producers are not considered idle. These cyclic producers are defined as having intermittent flow with shut downs of less than ninety (90) days.

Contractor shall ensure that all strings in its inventory including injectors are active or serve their purpose in supporting reservoir management and surveillance while maintaining integrity and safety of their operations. Wells or strings that fall into the idle category must undergo a proper inventory and be categorised according to the above definition. Contractor shall also plan to reactivate the idle wells or strings as soon as possible. The inventory must be updated and shared with PETRONAS on a monthly basis.

Contractor shall conduct a production rate well test every quarter for strings that are non-effective or idle to re-evaluate their potential and gather the necessary information to determine if the wells can return to production. Under any condition if Contractor wants to produce the Reservoir Management (RM) non-effective idle strings with a deviation from the approved Reservoir Management Plan (RMP), Contractor shall inform PETRONAS of the deviation from the approved RMP.

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Contractor shall reinstate effective idle strings within one (1) year from the date the well became idle. If Contractor anticipates that the idle string would not be able to be reinstated within one (1) year, Contractor shall supply PETRONAS with a valid justification in order to get agreement.

If the well is declared idle because it has been depleted (under Reservoir (RES) category) and Contractor does not believe it has any future potential and given that PETRONAS agrees with this assessment, then Contractor shall submit a plan for well abandonment. This submission to PETRONAS shall be within one (1) year from the date the well was agreed by PETRONAS to be RES depleted idle. For Ultimate Recovery (UR) depleted idle string, the plan and timeline to produce the identified behind casing potential shall be included in monthly update to PETRONAS.

1.4 Production Enhancement

Contractor shall take action to improve the injection or deliverable performance of a well as deemed necessary. To achieve this, Contractor may carry out workovers and/or other well work activity and artificial lift programmes. Contractor shall refer to Appendix 1, which lists the activities required for submission of the proposal for PETRONAS’ approval.

To ensure smooth delivery, Contractor should initiate a discussion for any activity requiring a workover unit three (3) months before the expected execution date. Discussions for activities that do not require a workover unit should start one (1) month before the expected execution date.

Contractor shall share the results of any production enhancement activities they undertake with PETRONAS within three (3) months of the completion of the activities.

1.5 Annual Field Performance Review 1.5.1 22

FRMR/FRW Contractor shall present PETRONAS with an assessment of the field performance/surveillance, in the annual Field Reservoir Management Review (FRMR). The timing for the annual review will be determined by PETRONAS with agreement from Contractor and the package submission deadline will be two (2) weeks before the date of the review. PETRONAS may request a detailed review of the well in a Field Review Workshop (FRW) which will be requested with ample notice to Contractor or at least once every two (2) years. Contractor shall also invite PETRONAS to participate in any in-house well by well review to obtain exemption for a separate FRW.

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OPERATIONS MANAGEMENT Contractor should assess the RMP annually and this should be reviewed by PETRONAS during the annual performance review (FRMR or FRW). 1.5.2

Requirement for FRMR/FRW Contractor shall make all necessary data and information available during any review. Contractor should refer to FRMR Guideline, which is available upon request for template and the FRW requirements. The package presentation shall follow this template for an effective review session of the field and reservoir. Contractor shall use recent data and information in the presentation package. The data and information shall be as recent as three (3) months prior to the planned review session. Contractor shall also make sure that key personnel are available during the review.

1.6 Well Abandonment

Contractor shall submit any plans for well abandonment for PETRONAS’ approval in accordance with Volume 8, Section 9: Plug and Abandonment of Wells or once Contractor and/or PETRONAS has determined that the reservoir/well is no longer economically productive and has no future potential to produce. This requirement shall be in line with Section 10: Decommissioning of Upstream Installations in this volume.

1.7 Asset Relinquishment (Subsurface)

Contractor shall continue to gather and analyse reservoir performance data and operate in a manner that is consistent with the optimum reservoir management strategy of the field in line with Section 1.3.1 at any time during the period of the Contract.

At the end of the Contract period, Contractor shall uphold surveillance compliance and reservoir management strategy of the field and reservoir. Contractor shall maintain all the data and information pertaining to the field and make it readily available to PETRONAS by the end of the Contract agreement. Contractor shall handover all the wells in a safe and operable condition at the end of the Contract period. This requirement shall be in line with Section 9: Asset Relinquishment in this volume.

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OPERATIONS MANAGEMENT Section 2: Well Test and Surveillance 2.1 Introduction This section provides the scope and requirements for the information PETRONAS requires to be submitted related to the completion and recompletion of development/production wells on well test and production allocations.

It also outlines the procedures to be adopted for acquiring basic information relating to reservoir management. These procedures do not cover all aspects of well testing and production allocations however and ought to be regarded as the necessary requirements while ensuring safety and integrity of production facilities based on good oilfield practices.

For any areas of well test and surveillance that are not specifically mentioned in this section, Contractor is obliged to use best oilfield practices, internationally recognised codes and standards and at all times comply with the relevant Malaysian Law.

Contractor must gather information from all newly completed and active wells for the purpose of reservoir management. An active well is defined as a well or string that is producing with a stable rate and is not intermittent for more than ten (10) days in one (1) calendar month.

2.1.1

Oil Producing Well An oil producing well is defined as a well or string that is completed in the oil zone in the reservoir(s) and is intended to produce oil from the reservoir.

2.1.2

Gas Producing Well A gas producing well is defined as a well or string that is completed in the gas zone in the Non-Associated Gas (NAG) reservoir(s) or in gas cap zone in the oil reservoir(s) and is intended to produce gas from the reservoir.

2.1.3

Injection Well An injection well is defined as a well or string that is completed in either a gas, oil or water zone in the reservoir(s) and is intended to inject gas, water or other fluids for the purpose of reservoir management or fluid disposal.

2.2 Periodic Production Rate Test 24

Upon the initial completion or recompletion of a well, Contractor shall carry out the initial production rate test as soon as stable flow is established and/or has been subject to not more than sixty (60) days of initial PPGUA/3.0/042/2013

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production or at the first safe opportunity available. The test shall be carried out on each separated producing interval of the well whenever the interval is put into production.

Contractor shall conduct subsequent production rate tests monthly for all active producers. Additional production rate tests shall also be conducted if the following conditions arise:

a) b) c)

The new choke size has never been used before The well performance is anticipated to be significantly different from that predicted As per PETRONAS’ request

A shut-in well with the capability of flowing shall be tested quarterly.

Results of the production test shall be maintained by Contractor and must be submitted as per Volume 10, Section 5: Data Management and Data Submission. The test report shall include but not be limited to the following information: a) Choke size used for the well during the time the production test was conducted b) Result of the production rate test, including Base Sediment & Water (BS&W) measurement, gas lift or other related information, where applicable c) Measurement of the surface production conditions, namely: tubing and casing head pressure, pressure and temperature (where applicable) of the measuring equipment d) Bottom hole pressure and temperature data where down hole gauge is available For an oil and gas well, the measurement devices to be used for well testing purposes shall be calibrated annually with an accuracy of +/- ten percent (10%).

It is Contractor’s responsibility to ensure that the measurement system for well testing purposes at all times complies with the required accuracy of ten percent (10%). This can be conducted by means of onsite calibration or other methods that are deemed appropriate.

2.3 Bottom Hole Pressure Survey 2.3.1 Static Bottom Hole Pressure (SBHP) Survey This survey shall be conducted on at least fifty percent (50%) of the PPGUA/3.0/042/2013

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total active producers in each reservoir annually for the first two (2) years of its producing life and on at least twenty-five percent (25%) of total active producers thereafter. An additional survey shall also be conducted if PETRONAS so requests. The survey can be conducted on active or non-active producers.

2.3.2

Transient Pressure Survey Contractor shall conduct pressure build up (PBU) or drawdown (DD) pressure survey(s) for newly completed or recompleted oil wells for each reservoir or based on PETRONAS’ requirement. The pressure build up shall be conducted with the following sequences:

a) b) c) d)

The length of the build-up or DD period must be sufficient to capture well and reservoir parameters.

first/initial flow first buildup main flow final/main buildup

This survey shall be conducted at the first safe opportunity available. Subsequent to the initial survey, a periodical survey shall be conducted on each active producer when deemed necessary for reservoir characterisation and wellbore evaluation. The exercise shall be conducted in accordance with prudent reservoir management practices.

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2.3.3

Flowing Survey for Oil Producing Well For oil wells with artificial lift, Contractor shall conduct a flow survey every two (2) years as a minimum requirement to validate the well model and achieve optimum well operating condition.

2.3.4

Deliverability Test for Gas Producing Well Upon the initial completion or the recompletion of gas wells, Contractor shall carry out the initial deliverability test as soon as stable flow is established and/or has been subject to not more than sixty (60) days of initial production; or at the first available safe opportunity. The test shall be carried out on each separate producing interval of the well whenever the interval is put on production. The test shall be carried out on a minimum of three (3) rates.

Subsequent to the initial deliverability test, a periodical delivery test shall be performed at least once a year on all active producers. If a single rate test indicates significant delivery change, the deliverability test shall be repeated.

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OPERATIONS MANAGEMENT 2.3.5

Production Logging Tool (PLT) Survey For commingle oil reservoirs, Contractor shall conduct an initial PLT survey to define the proper production allocation and/or identify any well/reservoir problems. The subsequent survey shall be conducted as and when required. For non-commingle oil reservoirs, the PLT survey shall be conducted as required by PETRONAS.

For commingle gas reservoirs, Contractor shall conduct an annual PLT survey to define the proper production allocation and/or identify any well/reservoir problems. 2.3.6

Saturation Logging Survey Contractor shall conduct a saturation logging survey for oil reservoirs once every two (2) years in some key wells, so as to define the saturation distribution in the reservoir.

Contractor shall conduct saturation logging surveys for gas reservoirs as required by PETRONAS.

2.4 Injection Wells 2.4.1 Injection Rate Measurement Injection volume shall be measured on well basis and subsurface allocation shall be done on monthly basis. 2.4.2

Injectivity Test Contractor shall conduct an initial injectivity test for every injection well or any well that has been converted to an injection well for the purpose of pressure maintenance. For water injection, the test shall be done until it reaches above the fracture pressure or the maximum safe operating injection pressure, to determine the reservoir fracture gradient and other well/reservoir information.

The test shall be conducted after thirty (30) days of injection but not later than after ninety (90) days of injection or at the first safe practical opportunity available after thirty (30) days of injection. 2.4.3

Injection Profiling Survey For commingle reservoirs, Contractor shall conduct an initial Injection Profiling Survey to define the proper injection allocation and /or identify any well/reservoir problems. The subsequent survey shall be done once every two (2) years as a minimum requirement.

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OPERATIONS MANAGEMENT 2.4.4 Injection Fall Off Survey Contractor shall conduct an initial Injection Fall Off Survey for newly completed or recompleted wells for each reservoir. The length of the shut in period must be sufficient to capture well and reservoir parameters.

This survey shall be conducted after thirty (30) days of injection but not later than ninety (90) days of injection or at the first safe practical opportunity available after thirty (30) days of injection.

Subsequent to the initial survey, a periodic survey shall be conducted on each active injector when deemed necessary for wellbore evaluation. The exercise shall be conducted in accordance with prudent reservoir management practices.

2.5 Record Keeping and Data Quality

The results of the above tests shall be maintained by Contractor and shall be submitted to PETRONAS in accordance with Volume 10, Section 5: Data Management and Data Submission.

Contractor is responsible to ensure that all data and information of the well tests and surveys are validated to ensure the reliability and usability of these data and information.

2.6 Production Allocation 2.6.1

Production Allocation to Each Producing String The production rates of oil, gas, condensate (if applicable) and formation water for an individual string shall be determined based on a production rate test and monthly production. This allocation should be carried out at the end of each calendar month.

2.6.2 Production Allocation to Each Producing Interval When two (2) or more producing intervals are being produced through a common string, the oil, gas, condensate (if applicable) and formation water production of the string shall be allocated to each producing interval according to the split ratio for the individual fluid. 28

A determination of the split ratios shall be made before a new combination of producing intervals is put into production or when the combination is changed or when the data indicates a change is in order. A revision of the split ratios shall be made, when deemed necessary, based on well performance and survey and when operationally feasible.

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For wells that are not accessible for survey, the split ratio shall be based upon a reservoir engineering calculation from the subject well or from other wells in the same field. Consideration should be given to data such as: porosity, thickness, estimated permeability, reservoir pressure and other characteristics of the producing intervals for calculations of the split ratio.

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OPERATIONS MANAGEMENT Section 3: Facilities Reliability & Integrity Management 3.1 Introduction

The safe and efficient operation of facilities is essential to Contractor’s and PETRONAS’ successful business and Health, Safety and Environment (HSE) performance. Apart from enabling the achievement of the desired production target and the quality of the hydrocarbons produced, it is important to ensure that all facilities operate with integrity and reliability to preclude any undesirable HSE impacts resulting from functional failures of such facilities. All facilities must perform their functions as intended and when facilities’ performance falls below the intended level, effective corrective actions need to be promptly implemented.

3.2 Reference

In managing reliability and integrity of facilities, Contractor is required to adopt a full life cycle management concept, which encompasses all phases of the facilities life cycle - from conceptualisation to decommissioning. It must comply with PETRONAS’ minimum requirement for Process Safety Management.

Throughout the field development phase, measures to ensure reliability and integrity must be incorporated into the Field Development Plan (FDP) and the design of the facilities. In addition, the highest standards of reliability and integrity should be applied during the construction, installation and commissioning of facilities. These are to be addressed as part of the assurance programme for each development project.

Throughout the production phase, reliability and integrity must be sustained and safeguarded through prudent operations and proper inspection and maintenance of facilities.

Due consideration should also be given to the reliability and integrity of the facilities prior to relinquishing the field to PETRONAS. Contractor is required to ensure that the integrity of the facilities is in the state that enables safe and reliable operation after the handover. Contractor must conduct Facilities Extended Full Life Cycle Study for ageing facilities and fields at least five (5) years before the end of design life with the exception of fields with unjustifiable economics.

Throughout the facilities’ life cycle, the measures adopted to ensure a reduction of the risks associated with their operation are to be based on the principle of As Low as Reasonably Practicable (ALARP).

3.3 Management System 30

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OPERATIONS MANAGEMENT integrated with HSE best practices as well as Quality Management. Contractor is therefore required to incorporate the following key elements of reliability and integrity into all its management systems, at a minimum, in order to provide a structured framework for effective management of the facilities. 3.3.1

Leadership and Commitment Contractor’s management shall demonstrate visible leadership and commitment by placing high priority and playing an active role in all activities related to the reliability and integrity of each facility. Apart from allocating sufficient financial and human resources, the management must also put a mechanism in place that measures and monitors the performance of the facilities in terms of reliability and integrity. In addition, Contractor’s management is required to inspire, motivate and empower their employees to achieve the targeted reliability and integrity of the facilities and to take account of the impact this has on business performance.

3.3.2

Policy and Strategic Objectives The policy shall clearly outline the principles, objectives, strategies and performance targets related to facilities, reliability and integrity. Contractor must ensure the dissemination of the policy and strategic objectives to all employees and to other relevant parties as necessary.

3.3.3

Organisation, Roles and Responsibilities Contractor is required to establish a functional structure and allocate resources to show that reliability and integrity management is a department’s responsibility. Hence, the roles, responsibilities and accountability of all relevant personnel must be clearly defined.

Contractor is also required to institute a method of communication that allows for the dissemination of information about the facilities’ reliability and integrity management across its organisation.

3.3.4

Reliability and Integrity Management Processes Contractor is obliged to identify and clearly define methodologies that assure the reliability and integrity of facilities. As minimum requirements, the methodologies must include the following:

a) b) c)

risk assessment to estimate the magnitude of risk and determine the risk tolerance risk and reliability management to determine the maintenance requirements of the facilities criticality assessment to determine the relative importance of equipment to the overall operation of the facilities PPGUA/3.0/042/2013

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OPERATIONS MANAGEMENT d) e) f ) g) h) 3.3.5

incident investigation and failure analysis Bad Actor Management to identify and rank issues relating to the facilities’ reliability and integrity and to work towards elimination of the problems remnant life assessment to ensure the safe operation of critical equipment and those nearing the end of their design life assessment of operational performance, process effectiveness and personnel competencies implementation of an Improvement Plan

Improvement Plan and Implementation Contractor must review or assess the reliability and integrity performance of the facilities and identify any areas that need improvement. Corrective or improvement efforts shall be prioritised according to Contractor’s criticality and risk matrix.

3.3.6 Assurance/Audit Contractor is required to conduct an assurance/audit to verify compliance to and assess the effectiveness of the management system. PETRONAS, at its discretion, may participate in the assurance /audit or conduct a similar exercise. 3.3.7

Management Review Contractor’s management shall review the performance and remedial plans that relate to the facilities’ reliability and integrity. Any improvement objectives and targets must be in line with PETRONAS’ aspirations and requirements.

Apart from assuring performance, the review must also aim to:

a) b) c)

establish optimal use of all resources assure the competency of all personnel and/or any subcontractor apply appropriate existing and new technology

Following the review, appropriate improvement measures are to be implemented accordingly.

Proper implementation is essential to the effectiveness of the management system and therefore, the management system must be supported by relevant guidelines, standards and procedures.

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OPERATIONS MANAGEMENT 3.4 Operation of Facilities

Contractor shall prudently ensure safe, reliable and efficient operation of facilities. Procedures and work instructions for both routine and non-routine activities are to be developed and adhered to during operations. Contractor shall employ adequate number of competent personnel for its production operations. The operating procedures and other relevant technical instructions including drawings and equipment dossier shall be made accessible on locations and updated when necessary.

The operating limits as defined during design of facilities are to be monitored during operations so as to ensure the design intents are met. Should the operating limits deviate from the design basis, Contractor is to undertake necessary corrective measures to ensure safety, reliability and efficiency of facilities’ operations. In addition Contractor shall monitor the quality of produced hydrocarbon and effluent to ensure that there is no presence of elements which will be detrimental to integrity and reliability of facilities.

3.5 Inspection and Maintenance

Inspection and maintenance needs to be an integral and essential part of Contractor’s overall production operation strategy. The functional fitness of all facilities must be maintained to ensure their suitability to the activity. Contractor shall also ensure that the activities are undertaken effectively in order to realise the desired performance of the facilities.

3.5.1 Compliance to Legislative Requirements All inspection and maintenance activities undertaken by Contractor shall be, as a minimum in full compliance with relevant legislation including, but not limited to, applicable offshore self-regulation with reference to Offshore Self-Regulation Management System (OSR MS). 3.5.2 Philosophy and Related Documents Contractor must develop and establish an inspection and maintenance philosophy outlining the objectives, policies and principles governing the inspection and maintenance of the facilities. In addition, the document needs to include strategies that address or mitigate potential threats to the reliability and integrity of the facilities. As much as possible, cost effectiveness shall be a primary consideration.

As deemed necessary by changes in legislations, revision in company standards, assessment of maintenance effectiveness, advancement in technology or enhancement in industry best practices, Contractor shall review and update its system and all documents related to PPGUA/3.0/042/2013

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inspection and maintenance of facilities.

Contractor shall submit one (1) copy of document related to facilities reliability and integrity management and a list of equipment register to PETRONAS. Should there be any revision to any of the documents, Contractor is to provide PETRONAS with the updated revision within six (6) months of such change.

3.5.3 Minimum Requirements for Inspection & Maintenance of Topsides/ Onshore Terminals

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3.5.3.1

Mechanical Static Equipment Mechanical static equipment includes pressure vessels, pipings, boilers, heat exchangers, launchers & receivers, tanks, cranes, Single-Leg Buoy Mooring (SLBM)/Single Buoy Mooring (SBM) systems including floating hoses and subsea hoses.

Contractor must establish an appropriate corrosion management programme including chemical applications, microbiological monitoring and appropriate analysis to ensure the sustained integrity of static equipment.

A baseline survey must be conducted before any equipment is put into service (new static equipment or any that has been inherited from another Contractor) to obtain a reference which future surveys will be compared against. A periodic inspection of equipment consisting of both external visual checks for coating degradation and an assessment of internal corrosion and/or erosion through wall thickness measurement shall be the basis for condition-based maintenance of the equipment.

For pressure vessels that cannot be internally inspected, a suitable alternative method must be used. Additionally, an appropriate technique shall be employed to perform Corrosion Under Insulation (CUI) and heat exchanger tubes inspection tube inspections.

Contractor may adopt a risk-based methodology for inspection of static equipment in lieu of the time-based approach. However, the risk-based methodology selected by Contractor must be able to reduce the associated residual risks to an acceptable level to ensure safe operation of the equipment and to comply with OSR-MS. Any action

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to rectify findings that are identified during the inspection of static equipment shall be promptly taken by Contractor to avoid failures.

The maintenance or replacement of any equipment shall be determined based on the inspection findings.

3.5.3.2

Major Rotating Equipment Major rotating equipment includes gas turbines, internal combustion engines (gas & diesel), gas compressors (reciprocating & centrifugal) and pumps.

As much as possible, Contractor shall adopt a risk and reliability management methodology to determine the appropriate inspection and maintenance strategy, tasks and intervals.

Planned preventive maintenance must be performed based on Original Equipment Manufacturer (OEM) recommendations and if applicable, improved practices acquired as a result of Contractor’s operational experience. Contractor, whenever feasible, shall continuously or periodically conduct condition monitoring to establish a basis for predictive or condition-based maintenance of equipment. This condition monitoring must include vibration and temperature monitoring, operating parameters trending, lube oil analysis and boroscope inspection.

Functional test to address dormant failures must be conducted at a defined frequency for emergency equipment such as firewater pumps and emergency diesel generators as well as for standby equipment and any safeguarding/protective machinery.

Major inspection and overhaul must be performed based on the combination of OEM recommendations and any condition monitoring data acquired. Any inspection and overhaul must take the operating parameters and mode of operation into consideration. Contractor must provide PETRONAS with any major rotating equipment overhaul and change out plan on an annual basis.

3.5.3.3 Safeguarding Devices and Systems The devices and systems are safety-critical items which PPGUA/3.0/042/2013

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detect abnormal conditions, perform logical processing and initiate necessary executive actions per defined Cause and Effect Matrix to ensure the facilities are brought to a safe state.

Such devices and systems include:

a) instrumentations such as sensors, transmitters, switches and pilots b) detectors c) initiating devices such as breakglasses, pushbuttons, kill knobs and fusible plugs d) fire and gas systems e) shutdown systems f ) High-Integrity Pressure Protection system (HIPPS) g) shutdown and blowdown valves h) pressure relief devices such as relief valves and rupture discs

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Contractor is required to conduct periodic functional tests for all safety-critical/protective devices and systems at a defined frequency to address dormant failures within the devices and systems. The testing will establish that the Cause & Effect Matrix, implemented in the systems, remains correct and unchanged. Pressure relief devices shall be subjected to periodic non-destructive functional tests. In order to avoid failures, Contractor shall promptly rectify any faults or failures that are identified during these functional tests or inspections of safety-critical devices and systems.

However, impact to production resulting from such testing needs to be taken into consideration and minimised. Where possible, Contractor must employ technologies and practices that allow on-line testing of devices and systems.

Where applicable, shutdown & blowdown valves and pressure relief valves are required be inspected for leakage, damage and corrosion.

3.5.3.4

Fire Fighting and Life Saving Equipment Contractor shall conduct periodic inspection and functional tests for all fire fighting equipment including fire water pumps, monitors, deluge, sprinklers, portable extinguishers and life saving equipment such as lifeboats, life rafts and escape capsules to ensure functionality and validity at all times.

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OPERATIONS MANAGEMENT 3.5.4 Minimum Requirements for Inspection & Maintenance of Structures Contractor must conduct a baseline survey which should include visual inspection of the entire structure including any appendages and Non-Destructive Test (NDT) on selected structural members and nodes.

In addition, Contractor is required to develop and implement a periodic survey programme that covers all structural members above the Mean Sea Level (MSL), the splash zone and below the MSL area. The survey must assess if there is any damage, anomaly, corrosion, marine growth, debris or coating deterioration. Visual inspection, NDT and Cathodic Protection (CP) reading must be part of the periodic survey programme.

Contractor may adopt a risk-based methodology for the inspection of structures in lieu of a time-based approach. However, the riskbased methodology selected must be able to reduce the residual risks associated with the structure to an acceptable level. Contractor must take immediate measures to rectify any findings that are identified during the inspection to avoid failures.

The maintenance requirements which may involve touch-up painting, major re-painting, repair or replacement of structural members and cleaning of marine growth are to be condition-based as necessitated by the survey findings.

3.5.5 Minimum Requirements for Inspection & Maintenance of Pipelines Pipelines include subsea pipelines, risers, onshore (buried and above ground) pipelines and associated facilities.

Contractor is required to establish Pipeline Integrity Management System (PIMS) manual in accordance with PETRONAS’ Pipeline Safety & Integrity Regulatory framework.

Contractor must develop and implement an appropriate corrosion management programme to sustain the integrity of all pipelines. The corrosion management programme shall, whenever applicable, include chemical inhibition, dissolved gas analysis, microbiological monitoring and cathodic protection.

All pipelines shall be equipped with facilities for internal cleaning and internal inspection that can detect both internal and external defect to ascertain the condition of the pipelines. Any deviation will be subjected to economics and risk assessment for PETRONAS’ consideration. PPGUA/3.0/042/2013

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Contractor shall conduct a baseline survey for pipeline internal and external within the first two (2) years of service. Contractor must adopt risk-based methodology for pipeline inspections to assess the risk associated with pipeline failure and are required to implement measures to mitigate any associated residual risks to an acceptable level, to ensure safe operation of all pipelines.

Contractor must deal promptly to rectify any findings that are identified as critical during a pipeline or riser inspection, in order to avoid failures. All anomalies that have the potential to threaten the integrity of the pipeline leading to failure shall be reported to PETRONAS. Contractor is required to conduct integrity assessment such as the Fitness For Service (FFS) assessment, which is to be based on the inspection findings for all pipelines. The integrity assessment must indicate the pipeline’s level of fitness to operate in the year of inspection at Maximum Allowable Operating Pressure (MAOP) as well as determining the remnant life of the pipeline and recommend the next inspection date for the pipeline. Contractor must submit the annual pipeline integrity report to PETRONAS.

To mitigate environmental impacts due to pipeline failure, Contractor’s operating trunk lines, which are subject to risk and feasibility, have to install a leak detection system.

Contractor shall further provide PETRONAS with any relevant information relating to the Pipeline Integrity Performance Monitoring (PIPeM) System as well as ensuring that the data provided is reliable and updated.

All pipeline plan modifications and repairs shall be reported to PETRONAS. Contractor shall extend a copy of the notification or reporting to authorities on any related pipeline to PETRONAS.

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3.5.6

Minimum Requirements for Inspection & Maintenance of Wellhead and Downhole Systems Contractor is required to establish and implement a system that comprehensively manages well integrity.

The inspection programme for wellheads and christmas trees, including assemblies, shall include visual checks for physical damage, corrosion and leaks. Christmas tree valves have to be subjected to leak and functional tests at a frequency determined by Contractor. Contractor must monitor corrosion and erosion in a downhole system, particularly with regard to production tubings, by using appropriate means. Measures to rectify any issues identified during

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the inspection must be promptly taken by Contractor to avoid failure.

The functionality of all Surface-Controlled Subsurface Safety Valve (SCSSSV) and wellhead valves must be assured through regular testing. To establish the integrity of a downhole system, Contractor shall also perform a bleed down and monitoring of annulus pressure build up. Monitoring of sand production from wells is also required to form part of the inspection programme for a downhole system.

Preventive maintenance for wellheads and christmas trees (including assemblies) shall include regular greasing/lubricating of and injection of sealing compounds into valves. Depending on functional test results, the SCSSSV may need a change-out or servicing.

3.5.7 Minimum Requirements for Inspection & Maintenance of Subsea Systems The entire subsea production system shall be ideally designed to be maintenance-free. All valves, fittings and connectors have to be maintenance-free for the whole of their design life. Based on manufacturer’s recommendations, Contractor shall also develop and implement inspection programmes for subsea systems using appropriate methods (Remote Operated Vehicle (ROV), Remote Operated Tool (ROT) and/or diver.) Due to the high cost of intervention, particularly for deepwater facilities, subsea systems shall, as much as possible, be designed for no scheduled/preventive maintenance.

3.6 Planning and Implementation

To ensure effectiveness in terms of both performance and cost, Contractor must properly plan and schedule all inspection and maintenance programmes. Contractor must employ appropriate computerised management system for planning and scheduling of such programmes.

All inspection and maintenance activities that will totally or partially impact production have to be clearly stated in the Work Programme & Budget (WPB). Timely and consistent execution is essential to ensure the effectiveness of planned inspection and maintenance activities. Contractor must endeavour to fully comply with its inspection and maintenance plan. Deviations from the plan shall be managed systematically. To minimise production impact, Contractor shall maximise opportunistic maintenance by capitalising on any facility shutdown.

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to HSE requirements during inspection and maintenance is non-negotiable and supersedes all economic considerations.

3.7 Materials Management

Whilst Contractor must avoid wastage due to incorrect and excessive inventory in the warehouse, it is critical that correct spare parts, tools and consumables for inspection and maintenance activities be made available in a timely manner. Stock inventory shall be determined based on criticality and failure rates of equipment and lead-time for spare parts.

The materials management system shall be integrated with the maintenance management system employing appropriate computer system.

Contractor shall refer to PETRONAS’ Tenders and Contracts Administrative Manual for Upstream Procurement on disposal of assets.

3.8 Contracting and Contractor Management

In the event of insufficient in-house resources or capability or due to specialised nature of certain works or purely for cost effectiveness reasons, Contractor may contract out inspection and maintenance works. However, Contractor shall ensure that all third party contractors are technically competent to perform the works. All tendering and contracting shall be undertaken in full compliance to PETRONAS’ procurement procedures.

Contractor shall be responsible to manage cost, schedule and quality aspects of the works whilst ensuring strict adherence to HSE requirements by Contractor employed for inspection and maintenance of facilities.

For facilities operated by Contractor under lease arrangement, Contractor shall be accountable to monitor and review the inspection and maintenance programme.

3.9 Reporting and Key Performance Indicators (KPI)

Contractor shall measure performance and report to PETRONAS on the compliance and effectiveness of reliability and integrity using the KPIs listed in Appendix 3.

3.10 Major Failures and Corrective Action

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Contractor shall inform PETRONAS of any findings that could potentially lead to HSE issues, major failure of the facility and production reliability.

Contractor must conduct Root Cause Failure Analysis (RCFA) for all major failures and are required to submit a copy of the RCFA report to PETRONAS.

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OPERATIONS MANAGEMENT the necessary corrective action(s) to safely resume production at the desired level and work out long term measure(s) to prevent a recurrence of the failure.

3.11 Management of Change

Contractor shall develop and maintain a system to properly manage all permanent and temporary changes and deviations including those covering the physical or functional aspects of the facilities, the operating procedures and the inspection and maintenance plan that may have an impact on the reliability and integrity of the facilities.

The principal elements of the change control system shall include, but not be limited to:

a) definition b) justification c) technical review d) risk assessment e) approving authority and documentation

Contractor shall periodically review the list and status of changes and institute necessary measures to counteract any adverse effects. Care must be taken, however, to ensure that the system does not degenerate such that expediency takes precedence over thorough review.

3.12 Information and Knowledge Management

All data, information, documents and technical drawings of Contractor’s facilities are to be properly maintained and updated. Data about the reliability and integrity of facilities is to be properly collected, validated, processed, analysed and documented. Contractor must maintain proper and auditable records of inspection and maintenance activities.

The history of failures, root cause(s) and remedial actions are to be properly documented. Documents containing information on the reliability and integrity of facilities are to be systematically managed by having a document management system in place. For ease of storage and the longevity of the documents, electronic copies are preferred over hard copies.

Lessons learnt and best practices are to be recorded, documented and disseminated in a systematic manner. PETRONAS may request that Contractor shares its lessons learnt with others.

3.13 Preservation

In the event that any facilities need to be put out of service, partially or PPGUA/3.0/042/2013

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totally, for a period exceeding three (3) months, Contractor shall develop the procedures to properly and cost effectively preserve the facilities or part of the facilities throughout the duration in accordance with equipment manufacturer’s recommendations or good industry practices.

3.14 Facilities Modification, Upgrading or Rejuvenation

Modification, upgrading or rejuvenation of facilities may be necessary due to the following reasons:

a) To enhance processing capacity (excluding requirements for new reserve development) b) To sustain/improve integrity or reliability c) To address obsolescence of the system or its component(s) d) To improve the quality of processed hydrocarbon e) To ensure effluent meets environmental regulatory specifications

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If the total estimated value of the project exceeds the threshold limit of RM10 Million or if the project is deemed critical by PETRONAS, Contractor shall submit the Facilities Improvement Plan (FIP)/Facilities Rejuvenation Plan (FRP) for PETRONAS’ approval prior to undertaking the project.

The document must contain the following information:

a) Objectives b) Project Definition c) Scope of Work d) Operations & Maintenance Philosophy e) Cost & Economics f ) Schedule g) Project Organization h) Contracting Strategy i ) Technology j ) HSE k) Quality Management

In the event of any changes to the project’s objective, concept, technology, cost, operation and maintenance philosophy, Contractor is required to submit a revision of the FIP/FRP. During the project’s implementation, Contractor must send PETRONAS a monthly progress report that highlights the progress, achievements, look-ahead plan and any other issues pertaining to the project. Contractor is further obliged to submit a close-out report after the project is completed.

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OPERATIONS MANAGEMENT Section 4: Liquid Hydrocarbon Measurement 4.1 Introduction This section provides the minimum requirements for the establishment of liquid hydrocarbon custody transfer and allocation metering systems. They shall be regarded as PETRONAS’ general requirements and shall be fully complied with whilst ensuring safety, accuracy and integrity of the liquid hydrocarbon metering systems based on oil and gas best practices, internationally recognised codes and standards and applicable Malaysian laws.

In cases where the requirements are not specifically stated in this section, Contractor shall derive the scope of work relevant to the liquid hydrocarbon metering systems based on oil and gas best practices, internationally recognised codes and standards and applicable Malaysian laws and shall implement the same accordingly.

4.1.1 Scope This section provides the minimum requirements for the design, installation, testing, commissioning, operation and maintenance of liquid hydrocarbon custody transfer and allocation metering systems. Unless otherwise specified, the requirements stipulated in this section are applicable to both types of liquid hydrocarbon metering systems. The objective of this section is to ensure that the liquid hydrocarbon metering systems are designed, installed, tested, commissioned, operated and maintained in accordance with PETRONAS’ minimum requirements for accurate dynamic measurement of liquid hydrocarbon.

This section does not give specific details for the requirements relating to static measurement, namely, tank gauging, however, it is recognised that should the dynamic measurement fails, the static measurement shall be used to determine quantity in accordance with the relevant approved offshore or onshore terminal procedures.

4.1.2

Distribution, Intended Use and Regulatory Considerations Unless otherwise authorised by PETRONAS, the distribution of this section is confined to any company that forms a part of PETRONAS, Contractor or any appointed third party appointed by Contractor for the above scope of work.

This section is intended to be used by all those involved in the design, installation, testing, commissioning, operations and maintenance of PPGUA/3.0/042/2013

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OPERATIONS MANAGEMENT liquid hydrocarbon custody transfer and allocation metering systems in PETRONAS, Contractor or the appointed third party. It is Contractor’s responsibility, as referred to in this section, to ensure that the requirements stipulated in this section are followed, if the above scope of work is outsourced or contracted out to the third party. In developing oil and gas fields that straddle a neighbouring country, Contractor shall carefully scrutinise the requirements of both PETRONAS and the co-host country to ascertain which are more stringent, which combination of the requirements will be acceptable with regard to safety, integrity and economics. In all cases, Contractor shall inform PETRONAS about any deviation from the requirements stipulated in this section that is considered to be necessary in order to comply with the requirements of the neighbouring country. PETRONAS may then negotiate with the Malaysian authorities and any other concerned authority with the objective of obtaining agreements to follow the requirements stipulated in this section as closely as possible and also to be cost effective.

4.2 Definitions

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Accuracy is the closeness of agreement between a measured quantity value and a true quantity value of a measurand.

Allocation metering system is a measuring system comprising mechanical, instruments and computer parts that register the measured liquid hydrocarbon quantities used for allocation purpose between differently owned fields that share common facilities. This type of system is normally designed with an uncertainty of within ±1%.

Automatic sampler is a system installed in a pipe and actuated by automatic control equipment that enables a representative sample to be obtained from liquid hydrocarbon flowing in the pipe. The system generally consists of a sampling probe, a sample extractor, an associated controller and a sample receiver. Normally, it is also equipped with a sampler performance monitoring device.

Computer part is a part of a liquid hydrocarbon metering system that consists of digital computers and receives digital signals from Analogue to Digital (A/D) converters or from digital instrument loops.

Custody transfer metering system is a measuring system comprising mechanical, instruments and computer parts that register the measured PPGUA/3.0/042/2013

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OPERATIONS MANAGEMENT liquid hydrocarbon quantities used for custody transfer purpose when there is a change in the liquid hydrocarbon ownership. This type of system is normally designed with an uncertainty of within ±0.25% of standard volume. Density is a quantity of homogeneous substance represented by the ratio of its mass to its volume. The density varies as temperature changes and therefore it is generally expressed as mass per unit volume at a specific temperature. Density meter is also known as a densitometer that operates on a representative sample of liquid hydrocarbon withdrawn continuously from a process line or vessel via a sampling system.

Displacement prover is a prover that operates on the principle of repeatable displacement of a known volume of liquid hydrocarbon from a calibrated section of pipe between two (2) detectors. This includes provers that are commonly referred to as conventional pipe and small volume provers.

Flow computer is an arithmetic processing unit and associated memory device that accepts electrically converted signals representing input variables from a liquid hydrocarbon measuring system and performs calculations for the purpose of providing flow rate and the total quantity data.

Forced balance method is a method used to allocate hydrocarbon or hydrocarbon related products to a stream with higher level of uncertainty that flows to a common facility.

Instrument loop includes all elements that form part of the measurement of each individual quantity from a sensor to an input of A/D converter or an input of digital signal to a computer part.

Maximum flow rate is the maximum rate of flow recommended or authorised by the relevant meter manufacturer or regulatory body, respectively. The maximum rate is determined by considerations of accuracy, repeatability, linearity, durability and pressure drop.

Meter is a flow measuring device that indicates a measured flow rate. In some cases, it is also the device that indicates the total amount of liquid hydrocarbon passing through during a selected time interval.

Meter linearity is an ideal accuracy curve of a volume meter represented by a straight line denoting a constant meter factor. The meter linearity is expressed as the total range of accuracy curve deviation from such a straight line between the minimum and maximum recommended flow rates. PPGUA/3.0/042/2013

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Meter proving is an exercise carried out in accordance with the approved Validation Manual or proving procedure in order to determine a relationship between the volume of liquid hydrocarbon passing through a meter at a set of conditions and reference volume at the same conditions.

Meter run is the length of straight, unobstructed liquid hydrocarbon-flow conduit complete with an associated strainer, inlet and outlet piping, upstream and downstream straight lengths, a meter, a flow straightener, pressure transmitter and gauge, temperature transmitter and gauge with thermowell and an online density meter, where applicable.

Minimum flow rate is the minimum rate of flow recommended or authorised by the relevant meter manufacturer or regulatory body, respectively. The minimum rate is determined by considerations of accuracy, repeatability and linearity. Positive displacement meter is a meter that has a discrete volume segment as its measuring element and the volume is directly measured and counted by continuously separating or isolating a flow stream into discrete volume segments.

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Proration method is a method used to allocate hydrocarbon or hydrocarbon related products to streams in proportion to its measured quantities. The method is typically applied to streams having similar level of uncertainty.

Prover computer is an arithmetic processing unit and associated memory device that consists of proving function for proving a meter and calculation of meter factor.

Pulse interpolation is any of the various techniques by which the whole number of meter pulses are counted between two (2) events (such as detector switch closures) and the remaining fraction of a pulse between the two (2) events is calculated.

Repeatability is a quality characterisation of the ability of a measuring instrument to give identical indications or responses for repeated applications of the same value of measured quantity under stated conditions of use.

Sampling is an exercise in accordance with the approved sampling procedure that is carried out either automatically or manually to obtain a sample that is representative of liquid hydrocarbon in a pipe, tank or other vessel and to transfer that sample into a container from which a representative test specimen can be taken for analysis. PPGUA/3.0/042/2013

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Small volume prover is a prover used to calibrate a meter and having a volume between detectors that does not permit a minimum accumulation of 10,000 whole (unaltered) pulses from the meter. The small volume prover requires meter pulses discrimination by pulse interpolation or other techniques to increase its resolution.

Standard conditions are the standard reference conditions of temperature and pressure to which the measured volume is to be corrected. The standard reference conditions for pressure and temperature shall be 101.325 kPa (absolute) and 15°C, respectively in accordance with ISO 5024:1999.

Supervisory computer is an arithmetic processing unit and associated memory device that sends commands and accepts calculated data from each flow computer and a prover computer for station totalisation computation and archiving.

Terminal Operator refers to any party that operates common facilities either onshore, marine or in an authorised place.

Turbine meter is a meter that has a multi-bladed rotor or impeller as its measuring element to which a metered stream imparts rotational velocity proportional to the average velocity of the stream. The rotor revolutions are counted to register a measured volume.

Validation is a process of confirming or substantiating the accuracy of input variables to a measuring system at normal operating conditions using reference equipment traceable to certified standards.

Vendor refers to any party that manufactures or supplies equipment and provides services to perform the duties specified by Contractor.

Uncertainty is an absolute value parameter characterising the dispersion of the quantity values being attributed to a measurand, based on the information used.

4.3 General Requirements 4.3.1

Units of Measurement The standard conditions (base conditions) for all measurements shall be in SI units in accordance with ISO 5024:1999 at a pressure and temperature of 101.325 kPa (absolute) and 15°C, respectively. If volume is to be measured in imperial unit such as barrel, it shall be converted from the base Sl unit and referenced to a pressure and temperature of 14.696 psi (absolute) and 60°F, respectively. PPGUA/3.0/042/2013

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The liquid hydrocarbon measurement shall either be in volume, mass or energy.

4.3.2 Approval Requirements

4.3.2.1 Measurement and Allocation Concept Contractor shall submit a Measurement and Allocation Concept proposal to PETRONAS for approval during the FDP stage. Contractor shall carry out a financial exposure and cost benefit analysis during the concept evaluation and determine the most appropriate location or arrangement for the installation of any liquid hydrocarbon metering system, its meter run configuration and the required level of uncertainty. To facilitate the approval, the submission to PETRONAS shall include but not limited to the following information: a) Measurement philosophy b) Product allocation principles, where applicable c) Measurement methods and standards d) Production accounting exposure analysis e) Proposed uncertainty f ) Field area and installation layout with the main pipelines g) Project cost estimates

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The liquid hydrocarbon metering system can be used either for custody transfer or allocation purpose. There are two (2) categories of liquid hydrocarbon metering systems that fall under the purview of this section, namely:

a) Custody transfer metering system b) Allocation metering system

4.3.2.2

Metering Project Implementation – Metering Specification Contractor shall submit a Technical Requisition Package or equivalent documents relating to any liquid hydrocarbon metering system to PETRONAS for Metering Specification

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approval prior to the release of a tender plan. To facilitate the approval, the submission to PETRONAS shall include but not limited to the following information:

a) Design specifications and datasheets b) Design formulae and calculations c) Design uncertainty calculation and analysis based on ISO 5168:2005 or equivalent standards d) Design drawings inclusive of system architecture, Piping and Instrumentation Diagram (P&ID), instrument hook-up, isometric and general arrangement e) Other relevant information e.g. project milestone, WPB status and cost breakdown

Contractor shall submit a Functional Design Specification or equivalent documents inclusive of the above information to PETRONAS prior to the fabrication of the liquid hydrocarbon metering system and PETRONAS will inform Contractor if other information is required.

4.3.2.3

Metering Project Implementation - Metering Acceptance Contractor shall submit comprehensive project documents for any liquid hydrocarbon metering system to PETRONAS for Metering Acceptance approval for its official use. To facilitate the approval, the submission to PETRONAS shall include but not limited to the following:

a) Updated Functional Design Specification inclusive of the final design specifications, datasheets, formulae, calculations and uncertainty calculation and analysis b) As-built drawings inclusive of the final design system architecture, P&ID, instrument hook-up, isometric and general arrangement c) Factory Acceptance Test (FAT) and Site Acceptance Test (SAT) reports inclusive of the final test, validation and calibration procedures and results, punch list closure and work completion evidence d) The final Validation Manual and/or Measurement and Accounting/Allocation Manual/Procedure and other relevant procedures e) Approvals/certificates from all relevant authorities, certified/accredited third parties/independent laboratories traceable to their national certification/ accreditation and standards and manufacturers, where applicable PPGUA/3.0/042/2013

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OPERATIONS MANAGEMENT f ) Other relevant information e.g. validation and calibration schedules and equipment inventory list PETRONAS may grant the approval if the liquid hydrocarbon metering system performance and its documentation are satisfactory. 4.3.3

Static Measurement Project Implementation Contractor shall ensure that all liquid hydrocarbon tanks used for static measurement, namely, tank gauging for custody transfer or trade purpose, are calibrated by a certified/accredited third party traceable to its national certification/accreditation and standards and certified by National Metrology Laboratory - Standards and Industrial Research Institute of Malaysia (NML-SIRIM). Contractor shall submit a certificate of ullage tables to PETRONAS prior to official use.

The calibration shall be conducted in accordance with the following standards, where applicable: • • •

HM 2 (2000)(formerly IP PMM Part II, S1 or IP 202/69) ISO 7507-1:2003, ISO 7507-2:2005 and ISO 7507-4:2010 API MPMS Chapter 2.2A (R2012), API MPMS Chapter 2.2B (R2007) and API MPMS Chapter 2.2D (R2009)

The liquid hydrocarbon tank gauging and manual sampling shall be conducted in accordance with the following standards, where applicable: • • •

HM 4 (1998)(formerly IP PMM III, S1) and IP 475-2005 ISO 3170:2004 API MPMS Chapter 3.1A (2005) and API MPMS Chapter 8.1 (1995)

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The calculation of liquid hydrocarbon quantity shall be based on the following standards, where applicable: • •

HM 1 (1999) (formerly IP PMM Part I or IP 201/64) API MPMS Chapter 12.1.1 (2012) and API MPMS Chapter 12.3 (R2011)/Addendum (2007)

4.3.4 Government Regulatory Requirements All liquid hydrocarbon measurement systems shall be subject to the applicable Malaysian laws that include but not limited to the following: MALAYSIAN LAWS

LEGISLATIVE CONTROLS FOR

Customs Act 1967 (Act 235) Sales Tax Act 1972 (Act 64) Weights & Measures Act 1972 (Act 71)

Custody transfer or trade purpose

National Measurement System Act 2007 (Act 675)

Traceability purpose

Petroleum (Safety Measures) Act 1984 (Act 302)

Safety purpose

Contractor shall further ensure that the necessary approvals/ certifications are obtained from the following Malaysian authorities, where applicable: MALAYSIAN AUTHORITIES Royal Malaysian Customs Department

REGULATORY AUTHORITIES FOR Any liquid hydrocarbon measurement system used for custody transfer or trade purpose that may involve tax calculation.

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OPERATIONS MANAGEMENT MALAYSIAN AUTHORITIES NML-SIRIM (as the Custodian of Weights and Measures)

REGULATORY AUTHORITIES FOR Pattern or type approval of meter, master meter, displacement prover volume, prover tank volume, pipeline volume and tank ullage tables used for custody transfer or trade purpose. Similar approvals/certifications, i.e. pattern or type approval of meter and prover tank volume shall also be applied to any liquid hydrocarbon allocation metering system. Reference shall also be made to the relevant NML-SIRIM/SIRIM Berhad circulars for any liquid hydrocarbon measurement system used for custody transfer or trade purpose.

Department of Occupational Safety and Health (DOSH)

Fabrication and testing of any liquid hydrocarbon measurement system carried out in Malaysia, if required. Similar approval, if required, shall also be obtained if the liquid hydrocarbon measurement system is to be installed and operated onshore.

Contractor shall also ensure that the following equipment is traceable to NML-SIRIM (as the National Measurement Standards Laboratory) or any certified/accredited third party/independent laboratory traceable to its national certification/accreditation and standards, where applicable:

a) b) c) d)

The relevant equipment used for validating and calibrating the primary and secondary equipment and proving facility of any liquid hydrocarbon metering system The relevant equipment used for any liquid hydrocarbon tank calibration The relevant equipment used for any liquid hydrocarbon tank gauging The relevant equipment or reference materials used for laboratory analysis of any liquid hydrocarbon sample

4.3.5 Deviation Any deviation from the requirements stipulated in this section shall require PETRONAS’ approval with respect to:

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a) b) c)

measurement and allocation concept metering project implementation static measurement project implementation

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OPERATIONS MANAGEMENT d) operation and maintenance measurement system

of

any

liquid

hydrocarbon

4.3.6 Documentation Contractor shall establish and maintain up to date files containing all specifications, calculations and as-built drawings. The files shall also contain reports on verification revision, design, fabrication, installation and commissioning inclusive of inspection and testing programmes, operation manuals for all fixed and temporary phases and other relevant documentation.

Contractor shall ensure that all documentation throughout the project implementation is completed promptly, is readily available and inclusive of uncertainty analysis, FAT and SAT procedures and results and the project completion report. The information shall be submitted to PETRONAS upon the project completion.

Contractor shall establish an internal control system and maintain an up-to-date list of documentation.

4.4 Design 4.4.1

General Requirements A liquid hydrocarbon metering system shall be designed, fabricated, inspected and tested in accordance with the latest agreed editions and supplements of technical specifications, codes, standards and references mentioned in Section 4.8, where applicable, that may be amended or supplemented from time to time. Contractor shall request vendor to quote for the design, manufacture, testing, calibration and documentation of a fully integrated skid with its associated control panel. The liquid hydrocarbon metering system shall comprise the following major component parts:

a) Field Mounted Skid and Instrumentation • The minimum number of parallel meter runs required from the specified minimum and maximum flow rates at a specific accuracy with a complete standby meter run and/or a proving facility • All transducers and instrumentation necessary for measuring mass and volume flow rates, temperature, pressure, density and water content and proving operations PPGUA/3.0/042/2013

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OPERATIONS MANAGEMENT • •

Automatic and manual sampling systems All associated pipework, valves and fittings, access stairs, walkways (for operation, maintenance and validation) and drip pans

b) Control Panel and Computer System in Control Room • A control panel shall include all necessary terminations, computer and control systems and operational indicators • A computer system shall consist of flow and/or prover computers, supervisory computer and communication bus. The supervisory computer and communication bus shall be provided with full redundancy • All relevant items necessary for system functionality inclusive of equipment for testing, validation and calibration The liquid hydrocarbon metering system shall be designed to allow subsequent recalibration of a displacement prover on site with a portable master pipe prover-master meter calibration equipment, tank prover-master meter or calibration can. For a liquid hydrocarbon allocation metering system where a master meter is used, a calibration facility for proving the master meter shall be made available. Suitable process and electrical equipment and connections shall be provided for the above purposes. Bypassing the liquid hydrocarbon metering system is strictly forbidden for normal operations after commissioning and start-up. For the purpose of commissioning and start-up, should a bypass line be required, it shall be provided with a blind or positive shut off double block and bleed valve with telltale bleed for verifying shut off integrity. The valve shall always be sealed. All equipment within the skid shall be ergonomically arranged such that there is safe and easy access for operations, maintenance and validation. Facilities such as platforms, gratings and stairs shall be provided to accommodate any work that needs to be performed on the liquid hydrocarbon metering system. For a liquid hydrocarbon metering system with heat tracing insulation, all equipment and components that will be accessed periodically shall be provided with removable covers that are fitted with quick release fasteners. All equipment and materials supplied shall be brand new and suitable to be used in accordance with their design operating conditions.

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Other designs can be accepted provided that Contractor can demonstrate and provide documentation to show that they offer the equivalent or better accuracy and integrity of the liquid hydrocarbon metering system.

4.4.2

Meter Run Design/Pipework A meter run shall be designed in accordance with the following standards or other relevant standards as specified in Section 4.8, where applicable:

A typical liquid hydrocarbon custody transfer metering system schematic diagram is shown in Appendix 4, Figure 5.

• ISO 2714:1980, ISO 2715:1981, ISO 10790:1999/Amd 1: 2003 and ISO 12242:2012 • API MPMS Chapter 5.1 (R2011)/Errata (2008)/Errata (June 2011)ANSI/API MPMS Chapter 5.2 (2005), API MPMS Chap ter 5.3 (2005)/Addendum 1 (2009), API MPMS Chapter 5.4 (2005), API MPMS Chapter 5.5 (2005), API MPMS Chapter 5.6 (R2008) and ANSI/API MPMS Chapter 5.8 (2011)

The materials selected shall conform to the applicable codes, pressure and temperature ratings, process conditions, corrosion resistance, ingress protection and electrical safety classification. Each parallel meter run shall be provided with:

a) inlet and outlet piping b) stream control and prover inlet valves c) thermal relief valves d) a meter with upstream and downstream straight lengths or flow straightening vane as required e) a strainer with differential pressure gauge and draining facility. The strainer shall be able to handle the highest flow capacity of the meter with a minimum pressure drop f ) temperature transmitter and gauge with thermowell g) pressure transmitter and gauge The number of parallel meter runs shall be such that a liquid hydrocarbon metering system shall be capable of measuring all flow rates from the minimum to the maximum of the liquid hydrocarbon metering system throughput with one (1) meter run on standby and the remaining meter run still operating within its working range. PPGUA/3.0/042/2013

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OPERATIONS MANAGEMENT Full bore through conduits or ball valves should be fitted to the appropriate upstream, downstream and prover inlet of the meter runs. Double block and bleed valves shall be fitted at the following locations: a) Each meter run outlet to a prover inlet b) Each meter run outlet to an outlet header c) A prover outlet to the outlet header d) All prover drain lines These valves shall include instrumentation for cavity pressure relief and shut off integrity verification. Drain connections from the double block and bleed valves configuration shall have isolation valves and pressure gauges for verification of tight shut off. For an offshore liquid hydrocarbon metering system there shall be a suitable arrangement for the valves that meets safety standard. Flow control valves shall preferably be located at the following locations: a) On each meter run outlet between a tee and a double block and bleed valve outlet b) On the prover outlet between a 4-way diverter valve and a double block and bleed valve outlet The valves shall be capable of providing stable control over normal linear range of the meter as a minimum. Valve and actuator sizing calculations are required as part of the documentation. Thermal relief valves shall be provided for all sections of pipework capable of isolation and possible overpressure. All connections shall be self-draining. The total pressure drop of each meter run, at the maximum linear operating conditions, shall be provided. 4.4.3 Meters Turbine and positive displacement meters are normally used to measure liquid hydrocarbon for custody transfer purpose. However, the turbine meter has been the meter of choice for measuring liquid hydrocarbon for custody transfer and allocation purposes. The commonly used turbine meter is a twin-bladed helical turbine that 56

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OPERATIONS MANAGEMENT has reduced sensitivity to viscosity changes than conventional multi-bladed turbine. Although factors such as pressure, temperature, viscosity, flow range and fluid contamination may influence the type of meter selected, viscosity, flow rate and fluid contamination should be considered first. Preferably, the meter shall be initially calibrated in liquid hydrocarbon of the viscosity the system has been designed for and if not available, in water by a certified/accredited third party/independent laboratory traceable to its national certification/accreditation and standards. Viscosity performance shall be established when the meter is in operation.

The meter linearity shall be within ±0.25% of average meter factor over 10:1 flow range at a specific operating viscosity. The repeatability after five (5) consecutive proving runs under stable conditions shall be within ±0.025% of average meter factor at each flow rate point, where applicable.

The methods to calculate the linearity and repeatability shall be in accordance with NML-SIRIM/SIRIM Berhad Circular ALIR 1991/01, API MPMS Chapter 4.8 (R2007), API MPMS Chapter 5.3 (2005)/Addendum 1 (2009) and the common practice, where applicable. Other methods to calculate the linearity, repeatability or other performance characteristics shall be discussed with and agreed by PETRONAS prior to their application.

The repeatability shall be checked at the minimum and maximum flows and at evenly distributed flow rates within the specified 10:1 range, in both water and liquid hydrocarbon of the relevant viscosity. The former check shall be carried out at the relevant manufacturer’s facility during FAT and the latter during SAT.

In recent years, there have been growing needs to venture into other technology such as a coriolis or ultrasonic meter that may provide an alternative to turbine and positive displacement meters, for applications at conditions deemed unsuitable to them. The selection of the coriolis or ultrasonic meter shall be based on a need basis and is subject to PETRONAS’ approval.

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OPERATIONS MANAGEMENT 4.4.4 Prover Design A permanent meter proving facility shall be provided and designed as per the following standards, where applicable: • ISO 7278-1:1987, ISO 7278-2:1988, ISO 7278-3:1998 and ISO 7278-4:1999 • API MPMS Chapter 4.1 (R2009), API MPMS Chapter 4.2 (R2011), API MPMS Chapter 4.4 (R2005), API MPMS Chapter 4.5 (2011), API MPMS Chapter 4.6 (R2008), API MPMS Chapter 4.7 (2009), API MPMS Chapter 4.8 (R2007), API MPMS Chapter 4.9.1 (2005), API MPMS Chapter 4.9.2 (2005) and API MPMS Chapter 4.9.3 (2010) • Other relevant standards as specified in Section 4.8 References

The meter proving facility can use any of the following methods:

a) b)

Displacement prover Master-meter prover

4.4.4.1

Displacement Prover A displacement prover includes a calibrated section in which a displacer travels with flow, hence activates detection devices. All types of displacement prover systems operate on a principle of repeatable displacement of known volumes of liquid hydrocarbon from a calibrated section of pipe between the two (2) detectors. The displacement of the volume of liquid hydrocarbon is achieved by an oversized sphere or a piston travelling through the pipe. The liquid hydrocarbon flow should not be interrupted during meter proving. This uninterrupted flow permits a meter to be proved under specific operating conditions and at uniform flow rate without having to start and stop.

Generally, the displacement provers can be categorised as follows: a)

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Conventional Pipe Prover A conventional pipe prover shall preferably be bidirectional with quick opening and closing for sphere removal. These provers shall be designed and manufactured in accordance with the relevant standards

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OPERATIONS MANAGEMENT as specified in Section 4.4.4 and subscribe to the following criteria: • A number of meter pulses generated over a calibrated volume shall not be less than 10,000 whole pulses (unaltered) per trip i.e. 20,000 pulses (unaltered) total round trip volume • The resolution of the detectors or displacer system shall permit pulse resolution to be at least 1 part in 10,000 or a detection range within 0.0001. • Displacer velocity shall not exceed 3 m/s • Connections to the conventional pipe prover shall be downstream of meters • The conventional pipe prover shall be designed such that its repeatability during calibration of the volumes, where five (5) calibration trials i.e. five (5) consecutive runs are performed and be within ±0.01% of average volume • Appropriate connections shall be provided for the conventional pipe prover loop to facilitate recalibration with a portable master pipe prover-master meter or tank prover-master meter. Drain at the lowest point and vent at the highest point shall also be provided. The conventional pipe prover shall also be equipped with temperature and pressure measuring elements • Other considerations for the design inclusive of the following: - Detector Switches The conventional pipe prover shall have two (2) detector switches at each end of its prover loop with preferably four (4) independent calibrated volumes. The volumes from the cross-sectionally installed detector switches shall be very similar and these calibrated volumes are to be independent of each other, where at any point of time if either one (1) of the detector switches fails it does not invalidate the other volumes. The detector should be designed such that its contacting head protrudes far enough into the pipe to ensure switching takes place at all flow rates during calibration and normal operations. The detectors and switches should be weatherproofed against the corrosive marine environment and be suitable for electrical safety classification of the installation. PPGUA/3.0/042/2013

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OPERATIONS MANAGEMENT - Internal Diameter and Coating The internal diameter of the conventional pipe prover loop shall be consistent throughout and there shall be no tapping or drain point between the calibrated volumes of the conventional pipe prover. The internal coating of the conventional pipe prover shall provide a continuous level, durable and smooth surface for the application. Vendor shall provide full details of the coating, surface preparation and its method, method of application, the maximum allowable liquid hydrocarbon temperature and method of repair. The porosity and explosive decompression of the lining shall also be avoided. - 4-Way Diverter Valve A 4-way diverter valve shall be motorised and provided with a local and remote actuator together with a manual override hand wheel. If remote status of the valve is required, limit switches shall be provided. Necessary instrumentation to detect valve leakage shall also be included. The 4-way flow diverter valve in the bi-directional prover shall be fully seated and sealed before the displacer meets the first detector. - Freedom from Shock When the conventional pipe prover is operating at the maximum design flow rate, the displacer shall come to rest safely at the end of its travel without shock. - Guide Bars/Tees Careful design consideration shall be given to guide bars or tees to avoid any damage to the displacer. b) 60

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Small Volume Prover A small volume prover performance is critically dependent on the mechanical precision of its tube bore and movable element position detecting system, measurement accuracy and stability of temperature and

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OPERATIONS MANAGEMENT pressure, tightness of moving parts and ratio between diameter of the tube and the actual displacement of the moveable elements. For offshore applications, where space and weight are of important considerations, the small volume prover may provide smaller and lighter solutions. The small volume prover shall be designed and manufactured in accordance with the relevant standards as specified in Section 4.4.4 and the following criteria: • Connections to the small volume prover shall be installed downstream of meters • A piston seal leakage check kit shall be delivered together with the small volume prover • A field standard test measure should be delivered together with the small volume prover • The small volume prover shall be designed such that its repeatability during calibration of its volumes, where five (5) calibration trials, i.e. five (5) consecutive runs are performed and be within ±0.01% of average volume • Appropriate connections shall be provided for the small volume prover system to facilitate recalibration by water draw method at site • The small volume prover shall be vertically installed except for application with clean and stabilised liquid hydrocarbon The field standard test measure for the calibration of the small volume prover shall comply with the requirements of the relevant standards as specified in Section 4.4.4 and shall be supplied by vendor, with a certificate issued by a certified/accredited third party/independent laboratory traceable to its national certification/ accreditation and standards. Prior to the calibration of the small volume prover at site, the field standard test measure shall be first calibrated and certified by NML SIRIM. The following elements shall form the parts of the small volume prover: • A precision cylinder • A displacer piston, spheroid or other liquid PPGUA/3.0/042/2013

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OPERATIONS MANAGEMENT hydrocarbon separation device • A means of positioning and launching the displacer upstream of the calibrated section • The displacer detectors • A valve arrangement that allows liquid hydrocarbon to flow whilst the displacer is travelling from one position to the opposite position • Pressure measurement and indication devices • Temperature measurement and indication devices. • Instrumentation with timers, counters and pulse interpolation capabilities During the proving of a turbine or positive displacement meter, the displacer velocity shall not exceed 1.5 m/s. The small volume prover shall have a consistent inner diameter throughout the flow tube. The calibrated or swept volume of the small volume prover located between displacer-position sensors shall be free from any tapping, vent or drain point. The small volume prover shall be installed downstream of the meters. The small volume prover shall allow the displacer to come to rest safely and without shock at the end of its travel, when operating at the maximum design flow rate. There shall be no sign of cavitation in the small volume prover, valves or any other apparatus within specific temperature and pressure ranges when operating at the design maximum flow rate. The internal coating of the small volume prover shall have uniform bore, be durable and have a smooth long lasting surface. Block valves shall be installed to isolate the small volume prover from line pressure during maintenance, removal of the displacer and replacement of seal and cleaning. A drain at the lowest point and a vent at the highest point shall be provided. Pressure relief valves and leak detection facilities shall be installed with discharge piping to control thermal expansion of liquid hydrocarbon in the small volume prover whilst it is being isolated from the main stream. 62

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OPERATIONS MANAGEMENT 4.4.4.2

Master-Meter Prover A master meter is an indirect meter-proving device that has been proved by a direct prover (pipe or tank prover). A meter with exceptional linearity and repeatability is selected to serve as the master meter (transfer standard) for proving another meter or prover operating in the field. A comparison of two (2) outputs is the basis of the mastermeter proving method.

The master meter shall be designed and manufactured in accordance with the relevant standards as specified in Section 4.4.4.

The situations where master-meter proving method can achieve satisfactory results are those in which proving by a direct method cannot be accomplished because of logistical reasons such as the unavailability of the direct prover. However, the master-meter proving method introduces uncertainties between the meter being proved and the prover that is used to calibrate the master meter. The master-meter prover shall be used for a less critical metering system with considerations given on safety, accuracy, integrity and economic aspects.

The master meter should be placed at the downstream of the meter to be proved and shall be connected in series that are close enough to minimise corrections for volume during proving. All liquid hydrocarbon diverting valves between the meters shall have positive seals.

If the master meter is in portable service, it should be protected against damage during transportation, installation and handling. 4.4.5 Field Instrument Requirements a) Location of Sensors Temperature and pressure shall be measured in each meter run and at the inlet and outlet of the prover. b)

Installation of Instruments A thermowell shall be installed adjacent to each electronic temperature sensor or group of sensors for calibration purpose. It shall be possible to connect the test instruments in parallel with all pressure sensors in a liquid hydrocarbon metering system. The measurement of temperature, pressure and density PPGUA/3.0/042/2013

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OPERATIONS MANAGEMENT shall be representative of conditions at a meter and situated as follows: • In a volumetric measurement system: as close to the meter as possible without infringing API requirements or other standards as specified in this section • In a mass measurement system: as close to a density meter as possible that should also be located as near to the meter as possible without infringing API requirements or other standards as specified in this section c)

Instrument Loops Instrument loops shall be kept separated from other types of instrumentation and power supply cabling in the area of use. Cables and junction boxes shall not be shared with instrument loops that are not part of the liquid hydrocarbon metering system.

d)

Transmission of Pulse Signal Pulse signal transmission and treatment from a turbine meter shall be designed in accordance with the following standards, where applicable:

64

The cables and other parts of the instrument loops shall be designed and installed so that they will not be affected by electromagnetic fields.

• • •

HM 23 (1998)(formerly IP PMM Part XIII, S1 or IP 252/76) ISO 6551:1982 and BS EN ISO 6551:1996 API MPMS Chapter 5.5 (2005)

A pulse comparator shall be installed that signals an alarm when a pre-set number of error pulses occur on either of the transmission lines in accordance with the above codes. The preset level should be adjustable and when an alarm occurs, it should be recorded on a non-resettable comparator register. Where the pulse error alarm is determined by an error rate, the error threshold shall be less than one (1) count in 100,000. Pulse discrepancies that occur during low flow rates, experienced during meter starting and stopping, should be inhibited. The pulse transmission to a prover counter should be

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from one (1) or both of the secured lines to the pulse comparator and precautions should be taken to avoid any signal interference in a spur from the comparator line.

e)

Conversion of Signals from Analogue to Digital Form A/D conversions shall not contribute systematic errors to measurement. The total inaccuracy in analogue to digital conversion, including resolution, drift, linearity, repeatability and other random errors shall be within ±0.025% of full scale.

Internationally accepted pulse interpolation methods, for the pulse signals from the turbine meters, may be used if it can be proved that the accuracy of this liquid hydrocarbon metering system satisfies the requirements stipulated in this section and satisfactory documentation showing the reliability for the interpolation is produced.

When a single A/D conversion is used, a back-up converter is required. f )

Temperature Measurement A temperature sensor shall be constructed of 4-wire platinum Resistance Thermal Detector (RTD) element (100 Ω at 0°C), resistance tolerance Class A or equivalent classes. The resistance tolerance and the relation between resistance and temperature shall be in accordance with IEC 60751:2008. The sensor shall be installed in a thermowell.

A temperature transmitter should be located in the field using a head-mounted intelligent type. An intelligent analogue communication (4-20 mA) with superimposed Highway Addressable Remote Transducer (HART) shall be preferred. The transmitter output signal shall be linear with measured temperature. The transmitter shall have galvanic separation between the sensor element and output amplifier.

g)

Pressure Measurement A pressure transmitter range of specific series shall be selected so that normal operating pressure is between 50% and 75% of scale, but where a narrow-span instrument is required, the adjusted range shall cover the minimum and maximum operating pressures. An intelligent analogue communication

The accuracy of a complete circuit of temperature sensor or transmitter shall be within ±0.15°C.

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(4-20 mA) with superimposed HART shall be preferred. The accuracy of a complete loop of a pressure transmitter shall be within ±0.25% of span.

h)

Density Measurement The density measurement, where specified, shall be designed in accordance with the following standards, where applicable:

• • i )

HM 8 (1997) (formerly IP PMM Part VII, S2) API MPMS Chapter 9.1 (2012), API MPMS Chapter 9.2 (2012), API MPMS Chapter 9.3 (2012) and API MPMS Chapter 14.6 (R2012)/Errata (1998)

For mass measurement, two (2) density transducers should be installed. The installation shall be such that liquid hydrocarbon passing through a density meter is representative of line density and no gas can be trapped in the density meter that could cause error of the density reading. They should both be installed at an inlet of a liquid hydrocarbon metering system, within a fast loop arrangement. An insertion type density meter may be installed at the inlet or outlet of the liquid hydrocarbon metering system. The density meter installation should be such that one (1) will remain online for continuous density measurement whilst the other one (1) is taken out for maintenance or validation. Necessary correction to meter conditions shall be carried out. A built-in temperature sensor in the density meter shall only be used for indication purpose. The accuracy of a complete loop of density meter shall be within ±0.5 kg/m3. Control Room Instrumentation - Environmental Instruments that are sensitive to temperature or other environmental factors shall be installed in locations where these factors can be controlled.

4.4.6 Computer Based Monitoring and Control Functions Requirements a) General Metering and meter proving shall be managed by a computer system. Manual proving shall also be incorporated as a back-up. The computer system shall be installed in a central control room,

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local control room or local equipment room. Normally, separate computers shall be dedicated to each meter run, to a station and to a prover control. However, the functionality of the prover and supervisory computers may be combined into one (1) or more computers if it can be demonstrated that the required reliability, availability and redundancy standards will be met. However such an arrangement has to be agreed by PETRONAS.

The computer system is to be designed as follows: • The computer part in a liquid hydrocarbon metering system shall have no function other than that which involves the metering. The liquid hydrocarbon metering system shall be designed in such a way that the maximum liquid hydrocarbon flow will be measured • The computer part shall have the capability of continuously displaying the number of pulses received from the meter during proving • The computer system should include at least two (2) independent registers for storing accumulated fiscal quantities for each meter run and the station total. It shall not be possible to delete or change these registers by operator encroachment or power failure • The computer shall also be designed to ensure that amounts generated during validation or calibration, are registered separately from measured amounts • Manually entered parameters shall be displayed without rounding off or truncation of digits. The display on the computer shall have sufficient resolution to enable verification for the calculation accuracy, be carried out. Facilities shall be installed to prevent access to the computer by any unauthorised personnel • The computer system shall be designed in such a way that the transfer of data to a distributed control system, supervisory control and data acquisition or plant information system is permissible and all interfacing requirements such as handshaking and necessary software are provided • The computer part shall have an automatic watch over for differences between readings of measured values for parallel meter runs • For continuous monitoring of measurement data, the computer shall, for each meter run, automatically log and store for at least one (1) year the following data: - At intervals of one (1) hour cumulative quantities: meter factor and average values of pressure, temperature PPGUA/3.0/042/2013

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OPERATIONS MANAGEMENT and density. - At intervals of twenty-four (24) hours: cumulative quantities. The information shall be accessible on a printout in a clearly set out format using a standard computer printer and paper. Access to the logs shall not be possible without the use of a key operated switch. • The flow computer shall be able to receive, as a standard feature and without further modification, at least 2-pulse trains from a turbine meter to perform a pulse security check in accordance with the following standards, where applicable:

• • •

HM 23 (1998) (formerly IP PMM Part XIII, S1 or IP 252/76) ISO 6551:1982 and BS EN ISO 6551:1996 API MPMS Chapter 5.5 (2005)

• • • b) 68

ASTM D 1250 IP 200 1952 Tables, ANSI/ASTM D 125080 IP 200/52 API D 2540 1980 Tables and calculations shall be made available in the flow computer for correcting volume to standard conditions. Report facility for computer constants and keypad setting shall be available. The computer shall have the ability to perform a meter curve (foot-print) interpolation for a minimum of eight (8) calibration points.

Data Security The computer data transmission shall be designed in accordance with Level A in the following standards, where applicable: • • •

HM 23 (1998)(formerly IP PMM Part XIII, S1 or IP 252/76) ISO 6551:1982 and BS EN ISO 6551:1996 API MPMS Chapter 5.5 (2005)

The computer shall have a self-diagnostic capability. It shall monitor that programme loops are executed at the correct intervals by means of a watchdog function.

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The parts of memory that contain permanent data shall have a periodical check sum control. Algorithms and fixed parameters important for accurate computation of fiscal quantities shall be stored in non-alterable memory. A security system shall be provided for the manual entry of data. The computer system shall be designed for and have features provided for sealing. Programme version numbers shall be assigned to identify all programmes used and this will be able to be determined directly from a visual display unit or printout. The version number can be updated every time the permanent programme is altered.

c) Calculation Computer routines for fiscal measurement calculation shall satisfy the requirements of the following standards, where applicable: • HM 1 (1999)(formerly IP PMM Part I or IP 201/64) • ISO 9770:1989 • API MPMS Chapter 11.1 (2004)/Addendum (2007), API MPMS Chapter 11.2.2M (1986), API MPMS Chapter 11.2.4 (2007)/Errata (2011), API MPMS Chapter 12.2.1 (R2009)/Addendum (2007)/Errata (July 2009), API MPMS Chapter 12.2.2 (2003)/Addendum (2007), API MPMS Chapter 12.2.3 (R2009)/Addendum (2007), API MPMS Chapter 12.3 (R2011)/Addendum (2007) and API MPMS Chapter 21.2 (R2004)/Addendum 1 (2000) • ASTM D 1250 IP 200 1952 Tables and ANSI/ASTM D 1250-80 IP 200/52 API D 2540 1980 Tables • Other relevant equations and algorithms • Other relevant standards as specified in Section 4.8 References

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OPERATIONS MANAGEMENT The computer shall satisfy the following criteria: • The update time to changes of input signals shall not be more than two (2) seconds and parameters having a response time such as density and temperature shall not exceed five (5) seconds • The interval between each cycle for the computation of instantaneous flow rate and accumulated flow shall be less than ten (10) seconds • The algorithm for the calculation of meter factor at reference conditions shall contain all correction factors given in API MPMS Chapter 4.1 (R2009), API MPMS Chapter 12.2.1 (R2009)/Addendum (2007)/Errata (July 2009), API MPMS Chapter 12.2.2 (2003)/Addendum (2007) and API MPMS Chapter 12.2.3 (R2009)/Addendum (2007), where applicable • The algorithm and rounding off error for the computation of fiscal quantities in a flow computer shall be within ±0.001% for flow rate and ±0.01% for the totalisation (integration) of the computed values. Rounding or truncation shall only be carried out at the end of the final computation • The temperature reading in degrees Fahrenheit (°F) shall be corrected to one (1) decimal place. Temperature readings in degrees Celsius (°C) shall be corrected to two (2) decimal places • For meter factor and volume prover computation purposes, the decimal places used shall be as follows: - Correction for the Effect of Temperature on Liquid (CTL), Correction for the Effect of Pressure on Liquid (CPL), Correction for the Effect of Temperature on Steel (CTS) and Correction for the Effect of Pressure on Steel (CPS) – six (6) decimal places - Prover volume calculation – four (4) decimal places - Meter factor – six (6) decimal places - The final prover volume shall be corrected to three (3) decimal places d) 70

If there is any deviation from the above requirements, Contractor shall consult PETRONAS.

Printouts and Hardcopies A computer system should have dedicated printers for alarms and reports. The supervisory computer shall be able to electronically

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OPERATIONS MANAGEMENT archive all the alarms and reports. A common printer can be used if an acceptable priority routine is established. Automatic logging on the following information is to be provided: • Alarms for faults detected by the computer (date, time) • Inserted parameters/constant, both fixed and changeable. • Quantity report • Instantaneous values of rate and measured input parameters. Fixed values that are used instead of live signals shall be identified • Meter proving report. All data required for manual checks of calculated correction factors and meter factor shall also be included After consultation with PETRONAS, Contractor shall establish a system for reporting of agreed data. e) Meter Proving Algorithm Routine The design of the computer routine for meter proving operation shall be according to the following: • All meter runs outlet and prover inlet valves and status check for meter proving sequencing shall be automatic • All proving calculations shall be carried out by the computer system and printed automatically. Sufficient data shall be available on the printout such that meter proving calculations can be verified externally. Repeatability limits and the required number of consecutive runs for repeatability acceptance shall only be changeable with the highest security level. Meter repeatability shall be such that it can be calibrated against a permanent meter prover with a sequence of five (5) consecutive runs and meets ±0.025% of average meter factor or range of 0.05% • The maximum trial runs before the computer aborts the proving operation shall also be made changeable with the highest security level (default number of trial runs is ten (10)) • Prover stabilisation period for process conditions i.e. temperature, flow rate and pressure parameters of the stability limit, shall be user changeable with appropriate security level (supervisor/engineer) • Automatic loading of meter factor to flow computer upon confirmation from operator. Acceptable meter factor shall be within the meter factor high and low limit of the respective meter Contractor, after consultation with PETRONAS, shall establish a system for conducting the proving operation. PPGUA/3.0/042/2013

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OPERATIONS MANAGEMENT f )

Power Supply A computer system shall be equipped with an uninterruptable power supply system for back up purpose. Normal operation of a liquid hydrocarbon metering system shall not be affected if there is any change from one power source to another.

4.4.7 Sampling and Analysis Requirements A liquid hydrocarbon metering system shall be provided with an automatic sampling system to collect representative samples for the determination of Base Sediment and Water (BS&W), average density and for other analysis purposes. Manual spot sampling, for the purpose of back-up, shall be made available. The sampling system shall be designed in accordance with the following standards, where applicable: • • •

IP 476-2002 and IP 475-2005 ISO 3171:1988 and ISO 3170:2004 API MPMS Chapter 8.1 (1995), API MPMS Chapter 8.2 (R2010), ANSI/API MPMS Chapter 8.3 (R2010) and API MPMS Chapter 8.4 (2004)

A sampler controller and sample monitoring unit should be installed as part of the sampling system. The selection of sampling point shall be such that the pipeline condition at the selected point is homogeneous. Contractor needs to demonstrate, by calculation, whether there is any additional mixing requirement such as a static or jet to ensure homogeneity of the liquid hydrocarbon prior to sampling. Where slugs of water may be experienced, inline water detection probes shall be fitted to detect abnormal levels of water content. For the sampling of pressurised liquid hydrocarbon, the following should be observed: a) A pressurised cylinder should be lightweight b) The samples shall be representative and this can be achieved by taking them from the mixture in the cylinder prior to the extraction of liquid hydrocarbon either for further transportation or analysis. The integrity of the samples is to be maintained throughout the exercise c) For pressurised manual sampling, an appropriate sample point and a sampling cylinder for pressurised liquid is to 72

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be used. It shall be ensured that no lighter components of the fluid are able to be liberated out of the cylinder

4.4.8 Metering Data Metering data should be made available by Contractor at hourly basis, daily basis and/or upon request as specified in Appendix 4.1.

4.5 Calibration, Testing and Commissioning 4.5.1

General Requirements Prior to on-site installation, an FAT shall be conducted to check the integrity of both computer software and mechanical/skid instrumentation. The FAT procedure shall be agreed between Contractor and Vendor prior to the FAT.

During the FAT, all electronic and mechanical instrumentation shall be tested together. The prover system shall be calibrated by a certified/accredited third party/independent laboratory traceable to its national certification/accreditation and standards, before the flow integration test can be carried out. It is essential that Vendor shall demonstrate that the equipment had been internally tested and found to be in good working order before Contractor and PETRONAS are invited for the FAT.

All FAT results are to be fully documented and only upon successful completion of the FAT can a liquid hydrocarbon metering system be accepted and shipped out to an offshore or onshore site. On site, an SAT shall be carried out prior to the commissioning of the liquid hydrocarbon metering system. Validation and calibration of all instrumentation using certified test equipment traceable to NMLSIRIM shall be carried out. It is the responsibility of Contractor to ensure that the FAT and SAT procedures be made available prior to the tests. PETRONAS may request these procedures to be submitted for review.

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Contractor shall notify and invite PETRONAS and NML-SIRIM, where applicable, to witness the following activities, at least three (3) weeks in advance: WITNESSING REQUIREMENTS

CALIBRATION AND TESTING ACTIVITIES

PETRONAS, Contractor and Vendor

NML-SIRIM

Calibration of any displacement prover and master meter used for custody transfer or trade purpose

Yes

Yes

Calibration of any displacement prover and master meter used for allocation purpose

Yes

No

Calibration of any meter used for custody transfer or trade purpose

Yes

Refer to Note 1

Calibration of any meter used for allocation purpose

Yes

No

FAT of any liquid hydrocarbon metering system used for custody transfer, trade or allocation purpose

Yes

No

SAT of any liquid hydrocarbon metering system used for custody transfer or trade purpose

Yes

Yes

SAT of any liquid hydrocarbon metering system used for allocation purpose

Yes

No

Note 1: NML-SIRIM’s participation is not required unless the liquid hydrocarbon metering system has no displacement prover or master meter in place.

PETRONAS may decide on its participation for the calibration and testing activities.

4.5.2 Calibration a) General Liquid hydrocarbon custody transfer and allocation metering systems shall be calibrated with certified test equipment traceable to NML-SIRIM or any certified/accredited third party/independent laboratory traceable to its national certification/accreditation and standards. Secondary standards or test equipment used for validation and calibration of all relevant parts of the liquid hydrocarbon metering system shall be calibrated and certified by NML-SIRIM or any certified/accredited third party/independent laboratory traceable to its national certification/accreditation and standards. 74

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OPERATIONS MANAGEMENT b)

Instrument Calibration All relevant instruments used in any liquid hydrocarbon metering system shall be calibrated and certified by the manufacturers or any certified/accredited third party/independent laboratory traceable to their/its national certification/accreditation and standards.

c) Prover Calibration A prover system shall be calibrated at vendor’s facility as part of system checks and after installation on site, immediately prior to start-up. The details of the calibration method used will depend on the type of meter proving system installed. 4.5.2.1 Displacement Prover Calibration a) Conventional Pipe Prover Calibration A conventional pipe prover shall be calibrated using a water draw or master-meter proving method at vendor’s facility as part of the system checks. The conventional pipe prover shall also be calibrated by using a water draw or master-meter proving method upon installation on site for the SAT before it is put into service. If a master meter is used, the meter shall be calibrated on site using the water draw method. Similar method of calibration should be done both at vendor’s facility and on site. Both calibrations shall be in accordance with the relevant standards as specified in Section 4.8 in this volume.

All conventional pipe prover calibrations shall be performed by any certified/accredited third party/ independent laboratory traceable to its national certification/accreditation and standards and attested to in writing.

The relevant field standard test measure used for the conventional pipe prover volume calibration shall be calibrated and certified by NML-SIRIM. The conventional pipe prover shall be calibrated with at least two (2) separate volumes, although four (4) volumes are preferred. The conventional pipe prover shall be capable of producing corrected volumes for five (5) consecutive runs in any given direction within ±0.01% of average. The average of the five (5) consecutive round PPGUA/3.0/042/2013

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OPERATIONS MANAGEMENT trips volumes shall be used as the base volume of the conventional pipe prover. The conventional pipe prover volume calibration process shall be repeated at a flow rate change of at least 25% or greater, to verify any possible leakage during the base volume calibration. The corrected volumes for three (3) consecutive runs at any given direction shall repeat within ±0.01% of average. The average volume of the three (3) round trip volumes shall not deviate from the newly established prover base volume by more than 0.02%. Copies of calibration certificates for each of these and all subsequent calibrations shall be documented in a calibration report and shall be submitted to PETRONAS. These certificates shall show the reference numbers of sphere detectors. The calibrated volume shall be in SI units at standard reference conditions. b) Small Volume Prover Calibration A small volume prover shall be calibrated physically at Vendor’s facility using the water draw method as part of the system checks for both upstream and downstream volumes. The small volume prover shall also be calibrated by using the same method, namely, the water draw method upon installation on site before it is put into service. Both calibrations shall be in accordance with the standards as specified in Section 4.8. All small volume prover calibrations shall be performed by any certified/accredited third party/ independent laboratory traceable to its national certification/accreditation and standards and attested to in writing. The relevant field standard test measure used for the small volume prover calibration shall be calibrated and certified by NML-SIRIM. The small volume prover shall be calibrated physically for both upstream and downstream volumes if these volumes are used for meter proving. The small volume 76

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OPERATIONS MANAGEMENT 4.5.2.2

prover shall be capable of producing corrected volumes for five (5) consecutive runs in any given direction that are repeatable within ±0.01% of average. The average of the five (5) consecutive volumes shall be used as the base volume of the small volume prover. The small volume prover calibration process shall be repeated at a flow rate change of at least 25% or greater, to verify any possible leakage during the base volume calibration. The corrected volumes for three (3) consecutive runs in any given direction shall repeat within ±0.01% of average. The average volume of the three (3) round trip volumes shall not deviate from the newly established prover base volume by more than 0.02%. Copies of calibration certificates for each of these and all subsequent calibrations shall be documented in a calibration report and shall be submitted to PETRONAS. These certificates shall show the reference numbers of optical detectors. The calibrated volume shall be in SI units at standard reference conditions

Master-Meter Prover Calibration A master-meter prover shall be calibrated in similar liquid hydrocarbon or other liquid as appropriate that will be used during the meter operation. A linearity curve of the master meter should be developed at a minimum of eight (8) points over the range of the meter design. Five (5) of these points shall span within normal operating range (turndown ratio point to the maximum operating point (or design maximum)) and three (3) points shall span from below turndown ratio point to the minimum operating point (or design minimum). The linearity limit shall be within ±0.25% of average meter factor for up to 2” meter and ±0.15% of average meter factor for meter size greater than 2”. The meter factor that is applied to the master meter shall be the average value of five (5) consecutive runs repeating within ±0.01% of average meter factor.

Contractor shall consult both PETRONAS and NML SIRIM should there be more stringent requirements by NML-SIRIM with regard to the linearity and repeatability limits of any master meter used for custody transfer or trade purpose. PPGUA/3.0/042/2013

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All master meter calibrations shall be performed by any certified/accredited third party/independent laboratory traceable to its national certification/accreditation and standards and attested to in writing. Copies of calibration certificates for each of these and all subsequent calibrations shall be documented in a calibration report and shall be submitted to PETRONAS.

Meter Calibration The first calibration test on each meter shall be performed at vendor/manufacturer’s facility. For each type of meter used, vendor/manufacturer shall, prior to the FAT, demonstrate the performance of the meter by initial calibration with a suitable medium at a minimum of eight (8) flow rate points. Five (5) of these flow rate points shall span within normal operating range (turndown ratio point to the maximum operating flow rate (or design maximum)) and three (3) flow rate points shall span from below turndown ratio point to the minimum operating flow rate (or design minimum). Vendor/manufacturer shall issue a calibration certificate for the calibrated meter. Each flow rate point shall consist of five (5) consecutive runs and the results shall repeat within ±0.025% of average meter factor. The meter linearity shall be within ±0.25% of average meter factor over the specified normal operating flow range. During the SAT, vendor or Contractor shall perform the final test and calibration with liquid hydrocarbon against meter prover (displacement prover or master-meter prover).

4.5.3 Testing

4.5.3.1

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General Testing General testing shall include checking, flushing, cleaning, hydrostatic pressure testing and electrical earthing against the original specifications and drawings of a liquid hydrocarbon metering system and shall be done on an individual item basis. Vendor shall perform its own test prior to the FAT and provide the necessary evidence, if required, via filled test sheets.

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OPERATIONS MANAGEMENT 4.5.3.2 Factory Acceptance Test a) General Check Prior to further tests in the factory, a general check on a liquid hydrocarbon metering system is to be carried out. This includes checking of the following items: • Dimension check as per approved drawings and standards • Instrument installation and quantity check as per approved drawings and bill of quantity, respectively • Availability of all documentation b) Metering Panel and Instrumentation Equipment Tests • All panel and field mounted instrumentation, cabling and connectors shall be visually inspected for compliance with specifications with regard to segregation of cables, satisfactory access, vents, drains and general good quality of installation work • Calibration checks using precision test equipment shall be performed on all transducers, transmitters, converters, indicators, recorders, gauges and switches and the relevant instruments supplied for use with the liquid hydrocarbon metering system • All safety and relief valves shall be tested, set and tagged with the set pressure • An insulation test shall be made on all power supply and instrument cables and panel wiring using a voltage tester. Instruments that may cause internal damage shall be disconnected during the test. All resistance thermometer elements shall be tested for insulation resistance to BS EN 60751:2008 • A sample of the power circuit breakers shall be tested by simulating a short circuit failure • The control panel shall be fully functionally tested before connection to the skid using appropriate simulators and other test equipment • These tests shall include: - panel mounted receiving indicators - outputs from panel mounted controls - meter run and prover instruments - computer functional test - verification of computer calculation and integration accuracy - interlocks and alarms PPGUA/3.0/042/2013

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OPERATIONS MANAGEMENT - checking of power distribution circuits and breakers for correct wiring and - analogue functions shall be calibrated at a minimum of five (5) points rising and five (5) points falling in the range (0%, 25%, 50%, 75% and 100%) • All remotely operated valves shall be checked after installation on the skid by: - manual stroking of the valves to check limit switch actuation and to ensure full operating - local operation to verify phase of electrically operated actuators rotation and functioning of local controls - remote operation and checking of remote position indication and interlocks and - noting the time for each valve to full stroke in each direction • After connection between the panel and skid, loop checks shall be made on all circuits to check correct wiring and calibration of the liquid hydrocarbon metering system. This shall include checks of all alarms, interlocks, digital and analogue inputs and outputs • A check shall be made on the effects of power supply variations by setting all instruments in normal operating mode and varying the output voltage to upper and lower limits and noting the effect by repeating functional checks • The panel should be heat soaked for a minimum of one hundred (100) hours. Records shall be made of the temperature at selectedpoints on the panel. Following the completion of the heat soak, the loop checks shall be repeated at ambient temperature to ensure that none of the equipment has suffered any thermal effects. A check of microprocessor functional performance shall be made during the soak test (after internal panel temperatures have stabilised). • Measurement and records shall also be made on panel maximum power consumption (Alternating Current (AC) and Direct Current (DC)) • Data transfer to another system shall be checked for data accuracy, data correctness and redundant switching of communication channels • Spares should be tested upfront 80

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OPERATIONS MANAGEMENT •

A simulation test shall include simulating with at least five (5) different values that cover the minimum and maximum levels in the working range of the skid instrument and the computers using test simulators

The simulators shall simulate signals connected to the computers input or in any other way to secure a controlled, constant input to the computers.

Testing or simulating different functions of the computers shall include but not limited to manually input data, printouts, alarms and data transmission between the computers.

All computer calculations shall be verified by injecting known values into the computers and comparing the results using manual calculation e.g. flow calculation software. c) Flow Testing Calibration Prior to flow test at vendor’s facility, all individual equipment inclusive of mechanical equipment, instruments and computing systems has to be tested first. The liquid hydrocarbon metering system shall be connected to a suitable pump and test equipment where the following tests are to be carried out using water or another suitable test medium. • All meters shall be individually flow tested and proved against a prover at their rated minimum and maximum flows on five (5) flow rate points at the specified intervals between the minimum and maximum. Each flow rate point shall consist of five (5) consecutive runs and the results shall repeat within ±0.025% of average meter factor. The meter linearity shall be within ±0.25% of average meter factor over the specified normal operating flow range • Observations shall also be made and recorded relating to: - pressure drop across strainer - pressure drop across meter run - pressure drop across prover and - density measurement, if applicable PPGUA/3.0/042/2013

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OPERATIONS MANAGEMENT Checks shall be made during testing for the tightness of shut-off on high integrity and 4-way diverter valves. • Preferably, all meter runs shall be simultaneously flow tested, namely, for metering and proving and preferably up to the maximum linear capacity of each meter • Checks shall be made on the functioning of flow control valves • Checks shall be made on the correctness of meter proving algorithms • Checks shall be made to ensure correct reports such as the meter proving report and the metering report (hourly or batch report) are generated by the computer system • Checks on the correct functionality of the sampling system to ensure the volume collected and accuracy per number of grab, accuracy of sampling system, alarms and switching of sampling cylinders

Following the completion of flow testing, the liquid test medium shall be drained and a thorough inspection shall be carried out to determine the condition of the prover lining and other equipment, where possible.

Computer simulations shall be carried out whereby all computer calculations shall be verified. 4.5.3.3 Site Acceptance Test Contractor shall provide test procedure for punch list items arriving on site. Other items to be provided shall include but not limited to the following: a) Loop diagram and loop checkout sheets b) Full print database checking c) System functional test procedure and schedule The SAT shall be considered as an extension of the FAT. Prior to the SAT, all wiring terminations shall be checked and the powering of panels should be carried out by vendor or any authorised vendor’s representative. Some tests carried out during the FAT shall also be repeated 82

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during the SAT. The SAT specifically on the following:

shall

concentrate

more

a) Inspection of material and equipment upon arrival on site including spares and documentation. If damage occurred during transportation, it is important to establish without delay, the extent of the damage and whether it is repairable on site or it is necessary to order new materials. Suitable storage of materials and equipment should be provided b) Field calibration of the displacement prover or master meter and the relevant meter proving shall be conducted in accordance with the following standards, where applicable: • •

ISO 7278-1:1987, ISO 7278-2:1988, ISO 7278-3:1998 and ISO 7278-4:1999 API MPMS Chapter 4.1 (R2009), API MPMS Chapter 4.2 (R2011), API MPMS Chapter 4.4 (R2005), API MPMS Chapter 4.5 (2011), API MPMS Chapter 4.6 (R2008), API MPMS Chapter 4.7 (2009), API MPMS Chapter 4.8 (R2007), API MPMS Chapter 4.9.1 (2005), API MPMS Chapter 4.9.2 (2005) and API MPMS Chapter 4.9.3 (2010)

All calibration equipment used for the provers and other metering equipment shall be traceable to NML-SIRIM or any certified/accredited third party/independent laboratory traceable to its national certification/accreditation and standards c) All prover calibrations on liquid hydrocarbon custody transfer metering systems that involve tax calculation shall be witnessed by vendor, Contractor and NML-SIRIM. PETRONAS may at any time witness the calibration exercise. The results shall be certified by NML-SIRIM. In the case of a master meter, where it is not possible to calibrate it on site or at a local facility, certification or recognition by NML-SIRIM shall be obtained for the results of calibration overseas d) The metering panel and instrumentation equipment test shall also be repeated that shall also include the computations check carried out by the computer system. The calibration exercise PPGUA/3.0/042/2013

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OPERATIONS MANAGEMENT carried out on the instruments in the exercise is considered as Validation No. 1 e) The completed metering skid and panel shall be subject to an operational functional test during actual flow condition to demonstrate satisfactory performance at design flow rates f ) Contractor shall submit a project completion report that should include the first official validation report to PETRONAS within thirty (30) days of the system being commissioned. Approval from PETRONAS shall be obtained before the liquid hydrocarbon metering system is put in operation for official use 4.5.4 Commissioning a) General The installation, commissioning and start-up of a liquid hydrocarbon metering system shall be carried out in accordance with the requirements in this section. b)

Installation Quality Assurance Contractor shall develop a master plan for the installation and commissioning activities in order to provide sufficient assurance and evidence that the overall quality control shall be effectively maintained.

The master plan shall be applied systematically to all liquid hydrocarbon metering systems and deviations will not be tolerated. c) Commissioning Commissioning shall include the running of all rotating equipment, checking alignment, testing control loops, stroking valves, flushing, hydrotesting, the final testing of electrical instrumentation systems, purging, drying, inerting and other relevant activities usually carried out sequentially on a system basis. The commissioning is completed when the liquid hydrocarbon metering system is ready for start up. d) Start-up This begins with the introduction of process hydrocarbons not counting where these may have been used previously for pressure testing/purging. 84

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OPERATIONS MANAGEMENT 4.6 Operations, Validation and Accounting 4.6.1

General Requirements Contractor shall operate and maintain a liquid hydrocarbon metering system to the highest degree of engineering standard in order to maintain accuracy and integrity. As such, operating, validation and hydrocarbon accounting procedures/manuals shall be prepared by Contractor and approved by PETRONAS before start-up. These procedures shall document all activities that influence the measurement system.

4.6.2 System Operations Contractor is required to carry out the following essential activities: a) A liquid hydrocarbon metering system shall be operated and maintained in accordance with the manufacturer’s recommendations and approved operations, validation and hydrocarbon accounting procedures/manuals. Particular attention shall be given to flow stabilisation prior to meter proving and checking of block and bleed valves for leaks. • Meter Proving Operations for Continuous Flow Measurement System For a newly commissioned liquid hydrocarbon metering system with a dedicated meter proving facility in a continuous production system (as distinct from tanker loading), meters shall be proved at least once a month at approximately equal intervals between proving. The proving frequency may be reduced to every two (2) months or quarterly basis provided that the results of meter factor scatter be acceptable to PETRONAS and until a meter factor control chart is established The proving frequency may be further reduced upon approval by PETRONAS. • Meter Proving Operations for Batch Measurement System For tanker loading systems, any meter on stream shall be proved at least once regardless of the duration of loading. Additional proving is required on any stream where conditions have changed and an alarm of proving requirement is triggered. b) Where the type of meter other than those mentioned in this section, the type and frequency of meter proving by Contractor shall be determined based on a case-to-case PPGUA/3.0/042/2013

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basis by PETRONAS after consultation with Contractor. Account shall be taken of the type of meter and the process fluid and operational load cycle. Where a meter employing novel technology is to be used, extra evaluation periods and tests will usually be required before a long-term operational schedule can be determined.

c)

Meter factors that are acceptable for use shall be based on the acceptance criteria of repeatability within ±0.025% of average meter factor, of five (5) consecutive runs. A meter factor control chart shall be developed and meter factor high and low limits shall be established to verify the acceptability of the meter factors.

Any maintenance work on the prover that could affect the swept volume, e.g. changes of sphere detectors, switches, optical detectors or seals should not be undertaken without prior notice to PETRONAS requesting further advice about whether a calibration is required.

Pipe and small volume provers shall be calibrated at least once a year. Where this is not possible for operational or whatever reasons, a longer calibration interval may be considered by PETRONAS. However, the liquid hydrocarbon metering system that is affected by tax calculation shall require NML-SIRIM’s approval. For the case of pipe provers, inspection of the sphere, checking size and concentricity, other relevant factors should take place prior to calibration. After the calibration, all sphere detectors and switches shall be sealed.

Operating Manual An operating manual shall be prepared for the purpose of providing operational guidelines for operators in performing metering activities. It shall then describe the operations of a liquid hydrocarbon metering system that includes computers, skid instrumentation, sampling activities and other operations of the liquid hydrocarbon metering system. Amongst other things, the manual shall also include what actions are to be taken in case of a malfunction or an alarm triggered on the liquid hydrocarbon metering system. The contents of the manual shall contain the following as a minimum:

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OPERATIONS MANAGEMENT a) Overall process description b) Metering system description c) Metering instrument specification d) Computer system operations (including codes) and actions taken on alarms e) Metering system operations f ) Metering sealing procedure g) Sampling procedure

computer

read

4.6.3

System Validation In order to maintain the reliability and accuracy of a liquid hydrocarbon metering system, Contractor shall conduct a periodic validation and calibration of the liquid hydrocarbon metering system at a frequency agreed by PETRONAS. For a new liquid hydrocarbon metering system, monthly validation shall be performed. A new validation frequency can be agreed with PETRONAS after such time the liquid hydrocarbon metering system is stable. The validation and calibration shall be performed in accordance with a Validation Manual prepared by Contractor and approved by PETRONAS.

All validation and calibration results shall be recorded on the format agreed in a validation report. The validation report shall include but not limited to the following:

a) As-found and as-left results of the validation and calibration exercises b) System errors shall preferably be in accordance with ISO 5168:2005 c) Findings and recommendations d) Metering irregularities that have occurred since the previous validation and between the last validations

The validation report shall then be prepared after each validation and calibration exercise and submitted to PETRONAS within one (1) month. Any irregularity of the figures generated from the validation and calibration activity shall be endorsed by PETRONAS.

Validation Manual A Validation Manual shall be prepared for the purpose of providing guidelines for the verification of liquid hydrocarbon metering system instrumentation. The contents of the Validation Manual shall consist of, but not limited to the following:

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a)

Brief Description of Liquid Hydrocarbon Metering System This shall include a concise description of the design concept of the system and its instrumentation including the computer system. Descriptions such as the function of each individual instrument, its accuracy and location in the system layout, system capacity, flow operating condition and the schematic drawing of the liquid hydrocarbon metering system should be included.

The instrument description shall include the manufacturer’s name and model number, range, accuracy, input/output signal and tag number.

b)

Validation and Calibration Procedures Step-by-step validation and calibration procedures for the instruments shall be set out in detail for each individual instrument in the liquid hydrocarbon metering system. A set of validation check sheets shall also be included and all readings obtained during each validation and calibration shall be recorded on these check sheets. Adjustment shall be made when a reading is out of tolerance. After any adjustment, the complete test shall be repeated.

c)

Frequency of Validation and Calibration Contractor shall supply detail on the frequency of validation and calibration of each of the liquid hydrocarbon metering instruments.

d)

Flow Calculation The calculations/formulae used to arrive at the volume, mass and energy throughputs shall be clearly laid out. All flow constants that are to be used shall be shown in the actual units in which they are used. Where the flow constants are fixed, the actual values and their derivations shall be shown.

e)

Metering Irregularity Calculation All types of irregularities in the liquid hydrocarbon metering system and the methods for their correction shall be clearly stated.

f )

Validation and Calibration Equipment A list of validation and calibration equipment to be used in the validation exercise shall be provided in the Validation

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Manual. All information related to equipment specifications such as accuracy, repeatability, serial number and range shall also be provided.

The accuracy of the calibration equipment shall be better than the accuracy of the instrument to be validated. The equipment shall be traceable to NML-SIRIM or any certified/accredited third party/independent laboratory traceable to its national certification/accreditation and standards.

g)

System Error Calculation System error calculation shall be listed in the Validation Manual and preferably in accordance with ISO 5168:2005.

4.6.4 System Maintenance Contractor shall conduct maintenance of a liquid hydrocarbon metering system in order to retain its accuracy and integrity.

Contractor shall notify and seek PETRONAS’ approval before any change or modification is made to the liquid hydrocarbon metering system. Drawings and sufficient data shall be submitted together with the request for approval (refer to Section 4.3.2 in this volume).

Contractor shall notify and invite PETRONAS to witness maintenance activities related to modifications of the liquid hydrocarbon metering system. All results pertaining to these activities shall then be properly documented. Contractor shall also obtain from vendor the recommended comprehensive spare parts’ list and priced quotation for parts for commissioning and two (2) years’ operations.

4.6.5 Security All software and flow factors, status and alarm information stored in a liquid hydrocarbon metering system shall be protected to prevent loss of information by inadvertent operator action or input power failure. In order to ensure security of the data in the computers and other critical instrumentation in the liquid hydrocarbon metering system, sealing procedure shall be adhered to. Contractor shall prepare this procedure.

Critical instruments such as computers and critical valves shall be sealed where practically possible. This is to prevent any unauthorised PPGUA/3.0/042/2013

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entry or manipulation of the computer system and the opening or closing of the critical valves at the skid. The sample cans of the sampling systems shall be sealed. The seals shall have serial numbers for easy identification.

The last valve downstream of an outlet header or offloading valve shall be sealed as per Customs’ requirements (for a liquid hydrocarbon custody transfer metering system).

The sealing of these identified critical instruments shall be carried out by a person authorised by Contractor and shall be recorded in a dedicated sealed logbook. The logbook shall be kept in the metering control room where PETRONAS will review it on a need basis.

4.6.6 Accounting and Allocation a) General Requirements A Production Accounting/Allocation Manual shall clearly describe the methods used to allocate crude oil and condensate productions and natural gas sales, from the point of sale to the respective Contractor, by fields/streams and these shall be developed prior to the first oil/gas production. The allocation of products to Contractor is to be conducted monthly on the basis of mass, volume and/or energy. A Terminal Operator shall develop a production accounting/common allocation manual from the terminal to the respective tie-in Contractor. There are two (2) types of allocation methods used when the metering systems are installed between different ownership fields that share common facilities: • The “Full Allocation” or “Proration” method • The “Forced Balance” or “Measurement by Difference” method b) 90

Accounting/Allocation Manual/Procedure Contractor shall prepare an Accounting/Allocation Manual that shall require PETRONAS’ approval. The purpose of this manual is to precisely define the way metered and other data is to be used for the determination of sales, allocation and production quantities. This manual as the minimum

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requirements shall consist of the following: • Accounting and allocation overview • Production measurement system • Product sampling and analysis • Data requirements • Allocation algorithm and calculation • Inventory calculation method • Methods to account for irregularities in quantity

c) Accounting and Allocation Overview The approved concept by PETRONAS shall be adopted in the allocation manual that should include the following: • Allocation algorithm concept • Allocation network diagram • Metering systems • Allocation type i.e. “Full Allocation” or “Forced Balance” • Allocation system i.e. spreadsheet, software based and others d)

Production Measurement System This section shall consist of Primary and Secondary production measurement system that should include the following: • Meter type and uncertainty • Metering configuration • Meter standard calculation

e) f )

Product Sampling and Analysis This section shall consist of Primary and Secondary product sampling and analysis that should include the following: • Sampling location and configuration • Sampling method and frequency • Lab analysis methodology and standards • Samples validation process Data Requirements This section describes the data requirements to be used for production allocation that shall include but not limited to the following: • Mass • Volume • Heating value • BS&W

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OPERATIONS MANAGEMENT g)

Allocation Algorithm and Calculation The allocation algorithm and calculation shall consist of sequential mathematical equations that have been developed from the approved concept. Each equation shall be tested and accepted by the relevant parties prior to official use.

h) Inventory Calculation Method The inventory calculation, namely, pipeline inventory and tank inventory shall be prepared six (6) months before the expiry of the first gas/oil contract and shall be documented inside the manual/procedure. i ) Methods to Account for Irregularities in Quantity Contractor shall develop irregularities procedure that shall require PETRONAS’ approval. j ) Production Allocation Reporting Following the end of each calendar month and based on the official measurement in either the onshore or marine terminal or another authorised place, the monthly production of oil, gas, condensate (if applicable) and/or formation water for each field and production platform/station shall be determined. A monthly report shall be submitted within thirty (30) days from the end of the month under review and shall include the following reconciled figures: • Petroleum and/or formation water • Fluids injected • Petroleum/gas utilised, flared or vented, stored in and delivered from each production station/terminal

Monthly official allocation report produced that involves two (2) or more Contractors shall obtain the agreement of all their shareholders and PETRONAS’ approval prior to the distribution of the report.

A Typical Allocation Work Process Flow – Liquid Hydrocarbon is shown in Appendix 4.2, Figure 6.

4.6.7 Metering Station Record Keeping Logbooks/Records Contractor shall maintain an electronic/manual logbook and records of a liquid hydrocarbon metering system inclusive of a prover system, meter proving and metering printout. Records of parameters such 92

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OPERATIONS MANAGEMENT as meter flow rate, liquid temperature and density shall be kept for the liquid hydrocarbon metering system for at least three (3) months. All logbook and records shall be made available within a reasonable timeframe for inspection by PETRONAS. The electronic or manual logbook and records shall be maintained and should comprise information about the following systems: a)

Prover System Contractor shall maintain a logbook for the prover system detailing all calibrations, sphere detector serial numbers and any maintenance work done on the proving facilities loop and its associated equipment.

b) Metering System • Metering Logbook A logbook for the liquid hydrocarbon metering system shall be kept, preferably for each meter, showing details as follows: - Type, stream and tag number particulars including location and production measured - Totaliser readings, where applicable, on commencement and cessation of metering - All mechanical, electrical repairs or adjustments made to the meter or its read-out equipment and other parts of the liquid hydrocarbon metering system - Metering errors due to equipment malfunction, incorrect operations and relevant factors including data, time and totaliser readings; both at the time or on recognition, of an error condition and when remedial action is completed - Alarms, together with reasons and operator response - Any breakdown of the meter or withdrawal from normal service, including time and totaliser readings - Replacement of security seals when broken • Metering Record A manual/automatic recording should also be kept, at intervals of not more than one (1) hour, of the following parameters: - All meter totaliser readings - Meter flow rates (also relevant meter factors), pressure and temperature and (if measured continuously) density PPGUA/3.0/042/2013

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OPERATIONS MANAGEMENT One of these sets of readings should be recorded at 2400 hours or at the agreed time for taking the daily closing figure. Other parameters such as liquid density and the percentage of BS&W content should be recorded at the agreed intervals. •

Meter Proving Record Contractor shall also keep a meter proving record for each meter. This record should give the details of each proved run such as the proved flow rate, pressure, temperature and meter factor. The record shall include a running plot or similar control chart, so that any undue changes or fluctuations in meter factors may be easily detected.

4.6.8 Direct Reporting Contractor shall notify PETRONAS prior to any major maintenance and recalibration work on a liquid hydrocarbon metering system as well as other operational related activities. PETRONAS shall also be officially notified, when any abnormal situation or error occurs that could require significant adjustment to the totalised meter throughputs.

If a meter has to be removed for maintenance work or replacement, PETRONAS shall be officially informed with details of the meter serial number and the reasons for the action taken.

When correction to meter totalised figures is required due to known metering errors, a formal report shall be submitted to PETRONAS detailing the time of the occurrence, totaliser readings and suspected causes for the error.

4.7 Final Provision a) b) c)

94

The final acceptance of a liquid hydrocarbon metering system will depend on the successful completion of the SAT during actual flowing conditions at the field site Contractor shall submit a project completion report to PETRONAS at least thirty (30) days after the liquid hydrocarbon metering system has been commissioned for official approval of system usage PETRONAS reserves the right to increase the requirements for all items stipulated in this section

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OPERATIONS MANAGEMENT 4.8 References These references shall be used for the design, installation, testing, commissioning, operations and maintenance of liquid hydrocarbon custody transfer and allocation metering systems: • Customs Act 1967 (Act 235) • Sales Tax Act 1972 (Act 64) • Weights and Measures Act 1972 (Act 71) • National Measurement System Act 2007 (Act 675) • Petroleum (Safety Measures) Act 1984 (Act 302) • NML-SIRIM/SIRIM Berhad Circulars - ALIR 1991/01, ALIR 1991/02 and ALIR 2006/01 • NML-SIRIM/SIRIM Berhad Circular - Static Petroleum Measurement, Recommendations for Recalibration, Monitoring, Verification and Recalculation of Vertical Cylindrical Tanks, May 2000 • PETRONAS Technical Standards • IP 475-2005 Petroleum Liquids - Manual Sampling (ISO 3170:2004) • IP 476-2002 Petroleum Liquids - Automatic Sampling • HM 1 (1999) Calculation of Oil Quantities, Second Edition (formerly IP PMM Part I or IP 201/64) • HM 2 (2000) Tank Calibration, Section 1 - Strapping, Internal Diameter and Internal Offset Methods for the Calibration of Vertical Cylindrical Tanks, Second Edition (formerly IP PMM Part II, S1 or IP 202/69) • HM 4 (1998) Manual Measurement of Level in Tanks, Section 1 Non-Electrical Methods, First Edition (formerly IP PMM III, S1) • HM 8 (1997) Density, Sediment and Water, Section 2 - Continuous Density Measurement, Second Edition (formerly IP PMM Part VII, S2) • HM 23 (1998) Fidelity and Security of Measurement Data Transmission Systems, Section 1 - Electric and/or Electronic Pulsed Data Cabled Transmission for Fluid Metering Systems, Second Edition (formerly IP PMM Part XIII, S1 or IP 252/76) • ISO 1998-6:2000 Petroleum Industry - Terminology, Part 6 Measurement, First Edition • ISO 2714:1980 Liquid Hydrocarbons - Volumetric Measurement by Displacement Meter Systems Other than Dispensing Pumps, First Edition • ISO 2715:1981 Liquid Hydrocarbons - Volumetric Measurement by Turbine Meter Systems, First Edition • ISO 3170:2004 Petroleum Liquids - Manual Sampling, Third Edition • ISO 3171:1988 Petroleum Liquids - Automatic Pipelines Sampling, Second Edition • ISO 4124:1994 Liquid Hydrocarbons - Dynamic Measurement - Statistical Control of Volumetric Metering Systems, First Edition • ISO 4267-2:1988 Petroleum and Liquid Petroleum Products Calculation of Oil Quantities, Part 2 - Dynamic Measurement, First Edition PPGUA/3.0/042/2013

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OPERATIONS MANAGEMENT • ISO 5024:1999 Petroleum Liquids and Liquefied Petroleum Gases Measurement - Standard Reference Conditions, Second Edition • ISO 5168:2005 Measurement of Fluid Flow - Procedures for the Evaluation of Uncertainties, Second Edition • ISO 6551:1982 Petroleum Liquids and Gases - Fidelity and Security of Dynamic Measurement - Cabled Transmission of Electric and/or Electronic Pulsed Data, First Edition • ISO 7278-1:1987 Liquid Hydrocarbons - Dynamic Measurement Proving Systems for Volumetric Meters, Part 1 - General Principles, First Edition • ISO 7278-2:1988 Liquid Hydrocarbons - Dynamic Measurement Proving Systems for Volumetric Meters, Part 2 - Pipe Provers, First Edition • ISO 7278-3:1998 Liquid Hydrocarbons - Dynamic Measurement Proving Systems for Volumetric Meters, Part 3 - Pulse Interpolation Techniques, Second Edition • ISO 7278-4:1999 Liquid Hydrocarbons - Dynamic Measurement Proving Systems for Volumetric Meters, Part 4 - Guide for Operators of Pipe Provers, First Edition • ISO 7507-1:2003 Petroleum and Liquid Petroleum Products Calibration of Vertical Cylindrical Tanks, Part 1 - Strapping Method, Second Edition • ISO 7507-2:2005 Petroleum and Liquid Petroleum Products Calibration of Vertical Cylindrical Tanks, Part 2 - Optical-Reference Line Method, Second Edition • ISO 7507-4:2010 Petroleum and Liquid Petroleum Products Calibration of Vertical Cylindrical Tanks, Part 4 - Internal Electro Optical Distance-Ranging Method, Second Edition • ISO 9770:1989 Crude Petroleum and Petroleum Products Compressibility Factors for Hydrocarbons in the Range of 638 kg/m3 to 1074 kg/m3, First Edition • ISO 10790:1999/Amd 1:2003 Measurement of Fluid Flow in Closed Conduits – Guidance to the Selection, Installation and Use of Coriolis Meters (Mass Flow, Density and Volume Flow Measurements), Second Edition, Includes Amendment 1 - Guidelines for Gas Measurement • ISO 12242:2012 Measurement of Fluid Flow in Closed Conduits Ultrasonic Transit-Time Meters for Liquid, First Edition • ISO 80000-1:2009/Cor 1:2011 Quantities and Units, Part 1 – General, First Edition, Includes Corrigendum 1 • API MPMS Chapter 1 (1994) Chapter 1 - Vocabulary, Second Edition • API MPMS Chapter 2.2A (R2012) Chapter 2 - Tank Calibration, Section 2A - Measurement and Calibration of Upright Cylindrical Tanks by the Manual Strapping Method, First Edition (1995), Includes Reaffirmed (R2007) 96

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OPERATIONS MANAGEMENT • API MPMS Chapter 2.2B (R2007) Chapter 2 - Tank Calibration, Section 2B - Calibration of Upright Cylindrical Tanks Using the Optical Reference Line Method, First Edition (1989) • API MPMS Chapter 2.2D (R2009) Chapter 2 - Calibration of Upright Cylindrical Tanks Using the Internal Electro-Optical Distance Ranging Method, First Edition (2003) • API MPMS Chapter 3.1A (2005) Chapter 3 - Tank Gauging, Section 1A - Standard Practice for the Manual Gauging of Petroleum and Petroleum Products, Second Edition • API MPMS Chapter 4.1 (R2009) Chapter 4 - Proving Systems, Section 1 - Introduction, Third Edition (2005) • API MPMS Chapter 4.2 (R2011) Chapter 4 - Proving Systems, Section 2 - Displacement Provers, Third Edition (2003) • API MPMS Chapter 4.4 (R2005) Chapter 4 - Proving Systems, Section 4 - Tank Provers, Second Edition (1998) • API MPMS Chapter 4.5 (2011) Chapter 4 - Proving Systems, Section 5 - Master-Meter Provers, Third Edition • API MPMS Chapter 4.6 (R2008) Chapter 4 - Proving Systems, Section 6 - Pulse Interpolation, Second Edition (1999), Includes Errata • API MPMS Chapter 4.7 (2009) Chapter 4 - Proving Systems, Section 7 - Field Standard Test Measures, Third Edition • API MPMS Chapter 4.8 (R2007) Chapter 4 - Proving Systems, Section 8 - Operation of Proving Systems, First Edition (1995) • API MPMS Chapter 4.9.1 (2005) Chapter 4 - Proving Systems, Section 9 - Methods of Calibration for Displacement and Volumetric Tank Provers, Part 1 - Introduction to the Determination of the Volume of Displacement and Tank Provers, First Edition • API MPMS Chapter 4.9.2 (2005) Chapter 4 - Proving Systems, Section 9 - Methods of Calibration for Displacement and Volumetric Tank Provers, Part 2 - Determination of the Volume of Displacement and Tank Provers by the Waterdraw Method of Calibration, First Edition • API MPMS Chapter 4.9.3 (2010) Chapter 4 - Proving Systems, Section 9 - Methods of Calibration for Displacement and Volumetric Tank Provers, Part 3 - Determination of the Volume of Displacement Provers by the Master Meter Method of Calibration, First Edition • API MPMS Chapter 5.1 (R2011)/Errata (2008)/Errata 2 (2011) Chapter 5 - Metering, Section 1 - General Considerations for Measurement by Meters, Fourth Edition (2005), Includes Errata, Errata 2 (June 2011) • ANSI/API MPMS Chapter 5.2 (2005) Chapter 5 - Metering, Section 2 Measurement of Liquid Hydrocarbons by Displacement Meters, Third Edition • API MPMS Chapter 5.3 (2005)/Addendum 1 (2009) Chapter 5 –Metering, Section 3 - Measurement of Liquid Hydrocarbons by Turbine Meters, Fifth Edition, Includes Addendum 1 • API MPMS Chapter 5.4 (2005) Chapter 5 - Metering, Section 4 PPGUA/3.0/042/2013

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OPERATIONS MANAGEMENT Accessory Equipment for Liquid Meters, Fourth Edition • API MPMS Chapter 5.5 (2005) Chapter 5 - Metering, Section 5 Fidelity and Security of Flow Measurement Pulsed-Data Transmission Systems, Second Edition • API MPMS Chapter 5.6 (R2008) Chapter 5 - Metering, Section 6 Measurement of Liquid Hydrocarbons by Coriolis Meters, First Edition (2002) • ANSI/API MPMS Chapter 5.8 (2011) Chapter 5 - Metering, Section 8 Measurement of Liquid Hydrocarbons by Ultrasonic Flow Meters Using Transit Time Technology, Second Edition • ANSI/API MPMS Chapter 6.6 (R2012) Chapter 6 - Metering Assemblies, Section 6 - Pipeline Metering Systems, Second Edition (1991) • API MPMS Chapter 7.3 (2011) Chapter 7 - Temperature Determination, Section 3 - Fixed Automatic Tank Temperature Systems, Second Edition • API MPMS Chapter 8.1 (1995) Chapter 8 - Sampling, Section 1 Standard Practice for Manual Sampling of Petroleum and Petroleum Products, Third Edition • API MPMS Chapter 8.2 (R2010) Chapter 8 - Sampling, Section 2 Standard Practice for Automatic Sampling of Liquid Petroleum and Petroleum Products, Second Edition (1995) • ANSI/API MPMS Chapter 8.3 (R2010) Chapter 8 - Sampling, Section 3 - Standard Practice for Mixing and Handling of Liquid Samples of Petroleum and Petroleum Products, First Edition (1995), Includes Errata • API MPMS Chapter 8.4 (2004) Chapter 8 - Sampling, Section 4 Standard Practice for Sampling and Handling of Fuels for Volatility Measurement, Second Edition • API MPMS Chapter 9.1 (2012) Chapter 9 - Density Determination, Section 1 - Standard Test Method for Density, Relative Density or API Gravity of Crude Petroleum and Liquid Petroleum Products by Hydrometer Method, Third Edition • API MPMS Chapter 9.2 (2012) Chapter 9 - Density Determination, Section 2 - Standard Test Method for Density or Relative Density of Light Hydrocarbons by Pressure Hydrometer, Third Edition • API MPMS Chapter 9.3 (2012) Chapter 9 - Density Determination, Section 3 - Standard Test Method for Density, Relative Density and API Gravity of Crude Petroleum and Liquid Petroleum Products by Thermohydrometer Method, Third Edition • API MPMS Chapter 10.3 (2008) Chapter 10 - Sediment and Water, Section 3 - Standard Test Method for Water and Sediment in Crude Oil by the Centrifuge Method (Laboratory Procedure), Third Edition • API MPMS Chapter 10.4 (R2010) Chapter 10 - Sediment and Water, Section 4 - Determination of Water and/or Sediment in Crude Oil by 98

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OPERATIONS MANAGEMENT the Centrifuge Method (Field Procedure), Third Edition (1999) • API MPMS Chapter 11.1 (2004)/Addendum (2007) Chapter 11 Physical Properties Data, Section 1 - Temperature and Pressure Volume Correction Factors (VCF) Software for Generalized Crude Oils, Refined Products and Lubricating Oils (Single User), Includes Addendum • API MPMS Chapter 11.1 (2004)/Addendum 1 (2007) Chapter 11 Physical Properties Data, Section 1 - Temperature and Pressure Volume Correction Factors for Generalized Crude Oils, Refined Products and Lubricating Oils, Includes Addendum 1 (Adjunct to ASTM D 1250-04 and IP 200/04) • API MPMS Chapter 11.2.1M (1984) Chapter 11 - Physical Properties Data, Section 2 - Volume Correction Factors for Meter Proving and Hydrocarbon Compressibility Factors, Part 1M - Compressibility Factors for Hydrocarbons: 638-1074 Kilograms per Cubic Metre Range, First Edition (Incorporated in API MPMS Chapter 11.1 (2004) • API MPMS Chapter 11.2.2M (1986) Chapter 11 - Physical Properties Data, Section 2 - Volume Correction Factors for Meter Proving and Hydrocarbon Compressibility Factors, Part 2M - Compressibility Factors for Hydrocarbons: 350-637 Kilograms per Cubic Meter Density (15 deg. C) and 46 deg. C to 60 deg. C Metering Temperature, First Edition • API MPMS Chapter 11.2.4 (2007)/Errata (2011) Chapter 11 - Physical Properties Data, Section 2 - Volume Correction Factors for Meter Proving and Hydrocarbon Compressibility Factors, Part 4 Temperature Correction for the Volume of NGL and LPG Tables 23E, 24E, 53E, 54E, 59E and 60E, First Edition, Includes Errata • API MPMS Chapter 11.4.1 (2003) Chapter 11 - Physical Properties Data, Section 4 - Properties of Reference Materials, Part 1 - Density of Water and Water Volumetric Correction Factors for Water Calibration of Volumetric Provers, First Edition • API MPMS Chapter 12.1.1 (2012) EI HM 1 Section 1 - Calculation of Static Petroleum Quantities, Part 1 - Upright Cylindrical Tanks and Marine Quantities Vessels, Third Edition • API MPMS Chapter 12.2.1 (R2009)/Addendum (2007)/Errata (2009) Chapter 12 - Calculation of Petroleum Quantities, Section 2 Calculation of Petroleum Quantities Using Dynamic Measurement Methods and Volumetric Correction Factors, Part 1 - Introduction, Second Edition (1995), Includes Addendum, Errata (July 2009) • API MPMS Chapter 12.2.2 (2003)/Addendum (2007) Chapter 12 Calculation of Petroleum Quantities, Section 2 - Calculation of Petroleum Quantities Using Dynamic Measurement Methods and Volumetric Correction Factors, Part 2 - Measurement Tickets, Third Edition, Includes Addendum • API MPMS Chapter 12.2.3 (R2009)/Addendum (2007) Chapter 12 PPGUA/3.0/042/2013

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OPERATIONS MANAGEMENT Calculation of Petroleum Quantities, Section 2 - Calculation of Petroleum Quantities Using Dynamic Measurement Methods and Volumetric Correction Factors, Part 3 - Proving Reports, First Edition (1998), Includes Addendum • API MPMS Chapter 12.2.4 (R2009)/Addendum (2007)/Errata (2009) Chapter 12 - Calculation of Petroleum Quantities, Section 2 Calculation of Petroleum Quantities Using Dynamic Measurement Methods and Volumetric Correction Factors, Part 4 - Calculation of Base Prover Volumes by the Waterdraw Method, First Edition (1997), Includes Addendum, Errata (July 2009) • API MPMS Chapter 12.2.5 (R2011)/Addendum (2007)/Errata (2009) Chapter 12 - Calculation of Petroleum Quantities, Section 2 Calculation of Petroleum Quantities Using Dynamic Measurement Methods and Volumetric Correction Factors, Part 5 - Calculation of Base Prover Volume by Master Meter Method, First Edition (2001), Includes Addendum, Errata • API MPMS Chapter 12.3 (R2011)/Addendum (2007) Chapter 12 Calculation of Petroleum Quantities, Section 3 - Volumetric Shrinkage Resulting from Blending Light Hydrocarbons with Crude Oils, First Edition (1996), Includes Addendum • API MPMS Chapter 13.1 (R2011) Chapter 13 - Statistical Aspects of Measuring and Sampling, Section 1 - Statistical Concepts and Procedures in Measurement, First Edition (1985), Includes Reaffirmed (2006) • API MPMS Chapter 13.2 (R2011) Chapter 13 - Statistical Aspects of Measuring and Sampling, Section 2 - Statistical Methods of Evaluating Meter Proving Data, First Edition (1994), Includes Reaffirmed (2006) • API MPMS Chapter 14.6 (R2012)/Errata (1998) Chapter 14 - Natural Gas Fluids Measurement, Section 6 - Continuous Density Measurement, Includes Errata • API MPMS Chapter 15 (R2007) Chapter 15 - Guidelines for Use of the International System of Units (SI) in the Petroleum and Allied Industries, Third Edition (2001) • API MPMS Chapter 20.1 (R2011)/Addendum (2013) Chapter 20 Allocation Measurement of Oil and Natural Gas, Section 1 - Allocation Measurement, First Edition (1993), Includes Addendum • API MPMS Chapter 21.2 (R2004)/Addendum 1 (2000) Chapter 21 Flow Measurement Using Electronic Metering Systems, Part 2 Electronic Liquid Measurement, First Edition (1998), Includes Addendum 1 • ASTM D 1250 IP 200 1952 Temperature Correction Tables, 1952 Tables or Blue Book Tables • ANSI/ASTM D 1250-80 IP 200/52 API D 2540 1980 Temperature Correction Tables or 1980 Tables 100

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OPERATIONS MANAGEMENT • IEC 60751:2008 Industrial Platinum Resistance Thermometers and Platinum Temperature Sensors, Second Edition • BS EN 60751:2008 Industrial Platinum Resistance Thermometers and Platinum Temperature Sensors • BS EN ISO 6551:1996 Petroleum Liquids and Gases - Fidelity and Security of Dynamic Measurement - Cabled Transmission of Electric and/or Electronic Pulsed Data • ISA 5.1-2009 Instrumentation Symbols and Identification • BIPM JCGM 200:2008 (E/F) International Vocabulary of Metrology Basic and General Concepts and Associated Terms (VIM), Third Edition

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OPERATIONS MANAGEMENT Section 5: Gas Measurement 5.1 Introduction

This section provides the minimum requirements for the establishment of gas custody transfer and allocation metering systems. They shall be regarded as PETRONAS’ general requirements and shall be fully complied with whilst ensuring safety, accuracy and integrity of the gas metering systems based on oil and gas best practices, internationally recognised codes and standards and applicable Malaysian laws.

In cases where the requirements are not specifically stated in this section, Contractor shall derive the scope of work relevant to the gas metering systems based on oil and gas best practices, internationally recognised codes and standards and applicable Malaysian laws and shall implement the same accordingly.

5.1.1

Scope This section provides the minimum requirements for the design, installation, testing, commissioning, operations and maintenance of gas custody transfer and allocation metering systems. Unless otherwise specified, the requirements stipulated in this section are applicable to both types of gas metering systems.

The objective of this section is to ensure that the gas metering systems are designed, installed, tested, commissioned, operated and maintained in accordance with PETRONAS’ minimum requirements for accurate measurement of gas.

5.1.2

Distribution, Intended Use and Regulatory Considerations Unless otherwise authorised by PETRONAS, the distribution of this section is confined to any company that forms a part of PETRONAS, Contractor or any third party engaged by Contractor for the above scope of work.

This section is intended for use by all those involved in the design, installation, testing, commissioning, operations and maintenance of gas custody transfer and allocation metering systems in PETRONAS, Contractor or the appointed third party. It is Contractor’s responsibility, as referred to in this section, to ensure that the requirements stipulated in this section are followed, if the above scope of work is outsourced or contracted out to a third party.

In developing oil and gas fields that straddle a neighbouring country, Contractor shall carefully scrutinise the requirements of both 102

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OPERATIONS MANAGEMENT PETRONAS and the co-host country to ascertain which are more stringent, which combination of the requirements will be acceptable with regard to safety, integrity and economic aspects. In all cases, Contractor shall inform PETRONAS about any deviation from the requirements stipulated in this section that is considered to be necessary in order to comply with the requirements of the neighbouring country. PETRONAS may then negotiate with the Malaysian authorities and any other concerned authority with the objective of obtaining agreements to follow the requirements stipulated in this section as closely as possible and also to be cost effective.

5.2 Definitions

Accuracy is the closeness of agreement between a measured quantity value and a true quantity value of a measurand.

Automatic sampler is a system installed in a pipe and actuated by automatic control equipment that enables a representative sample to be obtained from gas flowing in the pipe. The system generally consists of a sampling probe, a sample extractor, an associated controller and a sample receiver. Normally, it is also equipped with a sampler performance monitoring device.

Computer part is a part of a gas metering system that consists of digital computers and receives digital signals from A/D converters or from digital instrument loops.

Custody transfer metering system is a measuring system comprising mechanical, instrument and computer parts that register the measured gas quantity used for custody transfer purpose when there is a change in the gas ownership. This type of system is normally designed with an uncertainty of within ±1%.

Allocation metering system is a measuring system comprising mechanical, instrument and computer parts that register the measured gas quantity used for allocation purpose between differently owned fields that share common facilities. This type of system is normally designed with an uncertainty of within ±2%.

Density is a quantity of homogeneous substance represented by the ratio of its mass to its volume. The density varies as temperature changes and therefore it is generally expressed as mass per unit volume at a specific temperature.

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Density meter is also known as a densitometer and operates on a representative sample of gas continuously withdrawn from a process line or vessel via a sampling system.

Flow computer is an arithmetic processing unit and associated memory device that accepts electrically converted signals representing input variables from a gas measuring system and performs calculations for the purpose of providing flow rate and the total quantity data.

Forced balance method is a method used to allocate hydrocarbon or hydrocarbon related products to a stream with higher level of uncertainty that flows to a common facility.

Gross Heating Value (mass based) is the number of heat units liberated when a mass unit of product in vapour phase is burnt completely in air saturated with water vapour at standard temperature and pressure. The gaseous products of combustion are brought to the same standard conditions for temperature and pressure, but the water produced is condensed to form liquid that is in equilibrium with the water vapour.

Instrument loop includes all elements that form part of the measurement of each individual quantity from a sensor to an input of A/D converter or an input of digital signal to a computer part.

Linearity is a deviation or spread of calibration data points from an acceptable straight line over a defined flow range.

Maximum flow rate is the maximum rate of flow recommended or authorised by either the relevant meter manufacturer or regulatory body, respectively. The maximum rate is determined by consideration of accuracy, repeatability, linearity, durability and pressure drop.

Meter is a flow measuring device that indicates a measured flow rate. In some cases, it is also the device that indicates the total amount of gas passing through a system during a selected time interval.

Meter run is the length of straight, unobstructed gas-flow conduit complete with an associated strainer, inlet and outlet piping, upstream and downstream straight lengths, a meter, a flow straightener, pressure transmitter and gauge, temperature transmitter, a thermowell gauge and an online density meter, where applicable.

Meter verification is an exercise carried out in accordance with the approved Validation Manual or verification procedure in order to verify the

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performance of a meter using a master meter at the same conditions or any agreed methodology deemed appropriate for the purpose.

Minimum flow rate is the minimum rate of flow recommended or authorised by the relevant meter manufacturer or regulatory body. The minimum rate is determined by considerations of accuracy, repeatability and linearity.

Orifice meter (plate) is a device used for measuring flow rate, either in volume or mass flow rate depending on calculations associated with the orifice plate. It uses the same principle as a venturi nozzle, namely, Bernoulli’s Principle.

Proration method is a method used to allocate hydrocarbon or hydrocarbon related products to streams in proportion to their metered quantities. The method is typically applied to streams having similar level of metering uncertainty.

Repeatability is a quality characterisation of the ability of a measuring instrument to give identical indications or responses for repeated applications of the same values of measured quantity under stated conditions of use.

Sampling is an exercise in accordance with the approved sampling procedure that is carried out either automatically or manually to obtain a sample that is representative of gas in a pipe, tank or other vessel and to transfer that sample into a container from which a representative test specimen can be taken for analysis.

Standard conditions are the standard reference conditions of temperature and pressure to which the measured volume is to be corrected. The standard reference conditions for pressure and temperature shall be 101.325 kPa (absolute) and 15°C, respectively in accordance with ISO 13443:1996.

Supervisory computer is an arithmetic processing unit and associated memory device that sends commands and accepts calculated data from each flow computer for station totalisation computation and archiving.

Terminal Operator refers to any party that operates common facilities either at onshore, marine or in an authorised place.

Ultrasonic meter is a meter that measures the velocity of gas (fluid) using the principle of ultrasound. The meter uses ultrasonic transducers to measure the average velocity along the path of an emitted ultrasound beam by averaging the difference in measured transit time between the pulses into PPGUA/3.0/042/2013

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and against the direction of flow.

Uncertainty is an absolute value parameter characterising the dispersion of the quantity values being attributed to a measurand, based on the information used.

Validation is a process for confirming or substantiating the accuracy of input variables to a measuring system at normal operating conditions and uses reference equipment traceable to certified standards.

Vendor refers to any party that manufactures or supplies equipment and provides services to perform the duties specified by Contractor.

5.3 General Requirements 5.3.1

Units of Measurement The standard conditions (base conditions) for all measurements shall be in SI units in accordance with ISO 13443:1996 at a pressure and temperature of 101.325 kPa (absolute) and 15°C, respectively.

The gas measurement shall either be in volume, mass or energy.

5.3.2 Approval Requirements

5.3.2.1

Measurement and Allocation Concept Contractor shall submit a Measurement and Allocation Concept proposal to PETRONAS for approval during the FDP stage. Contractor shall carry out a financial exposure and cost benefit analysis during the concept evaluation and determine an appropriate location or arrangement for the installation of any gas metering system, its meter run configuration and the required level of uncertainty. To facilitate the approval, the submission to PETRONAS shall include but not limited to the following information:

a) Measurement philosophy b) Product allocation principles, where applicable c) Measurement methods and standards d) Production accounting exposure analysis e) Proposed uncertainty f ) Field area and installation layout with the main pipelines g) Project cost estimates 106

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The gas metering system can be used either for custody transfer or allocation purpose. There are two (2) categories of gas metering systems that fall under the purview of this section, namely:

a) Custody transfer metering system b) Allocation metering system

It is Contractor’s responsibility to obtain agreements from the respective equity Partners and any other interested party that will be affected with the installation of the gas metering system before the concept is submitted to PETRONAS for approval.

5.3.2.2

Metering Project Implementation - Metering Specification Contractor shall submit a Technical Requisition Package or equivalent documents for any gas metering system to PETRONAS for Metering Specification approval prior to the release of a tender plan. To facilitate the approval, the submission to PETRONAS shall include but not limited to the following information:

a) Design specifications and datasheets b) Design formulae and calculations c) Design uncertainty calculation and analysis based on ISO 5168:2005 or equivalent standards d) Design drawings inclusive of system architecture, P&ID, instrument hook-up, isometric and general arrangement e) Other relevant information e.g. project milestones, WPB status and cost breakdown

Contractor shall submit a Functional Design Specification or equivalent documents inclusive of the above information to PETRONAS prior to the fabrication of the gas metering system and PETRONAS will inform Contractor if other information is required.

5.3.2.3

Metering Project Implementation - Metering Acceptance Contractor shall submit a comprehensive list of project documents for any gas metering system to PETRONAS for Metering Acceptance approval. To facilitate the approval, the submission to PETRONAS shall include but PPGUA/3.0/042/2013

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not limited to the following:

a) Updated Functional Design Specification inclusive of the final design specifications, datasheets, formulae, calculations and uncertainty calculation and analysis b) As-built drawings inclusive of the final design system architecture, P&ID, instrument hook-up, isometric and general arrangement c) FAT and SAT reports inclusive of the final test, validation and calibration procedures and results, punch list closure and work completion evidences d) The final Validation Manual and/or Measurement and Accounting/Allocation Manual/Procedure and other relevant procedures e) Approvals/certificates from all relevant authorities, certified/accredited third parties/independent laboratories traceable to their national certifications/ accreditations and standards and manufacturers, where applicable f ) Other relevant information e.g. validation and calibration schedules and equipment inventory list

PETRONAS may grant the approval if the gas metering system performance and its documentation are satisfactory.

5.3.3 Government Regulatory Requirements All gas metering systems shall be subject to the applicable Malaysian laws that shall include but not limited to the following :

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OPERATIONS MANAGEMENT MALAYSIAN LAWS

LEGISLATIVE CONTROLS FOR

Customs Act 1967 (Act 235) Sales Tax Act 1972 (Act 64) Weights & Measures Act 1972 (Act 71)

Custody transfer or trade purpose

National Measurement System Act 2007 (Act 675)

Traceability purpose

Petroleum (Safety Measures) Act 1984 (Act 302)

Safety purpose

Contractor shall further ensure that the necessary approvals/ certifications are obtained from the following Malaysian authorities, where applicable: MALAYSIAN AUTHORITIES

REGULATORY AUTHORITIES FOR

Royal Malaysian Customs Department

Any gas metering system used for custody transfer or trade purpose that may involve tax calculation.

NML-SIRIM (as the Custodian of Weights and Measures)

Pattern or type approval of meter and master meter used for custody transfer or trade purpose. Similar approvals/certifications, i.e. pattern or type approval of meter shall also be applied to any gas metering system. Reference shall also be made to the relevant NML-SIRIM/SIRIM Berhad circulars for any gas metering system used for custody transfer or trade purpose.

Department of Occupational Safety and Health (DOSH)

Fabrication and testing of any gas metering system carried out in Malaysia, if required. Similar approval, if required, shall also be obtained if the gas metering system is to be installed and operated onshore.

Contractor shall also ensure that the following equipment is traceable to NML-SIRIM (as the National Measurement Standards Laboratory) or any certified/accredited third party/independent laboratory traceable to its national certification/accreditationand standards, where applicable:

a) b)

The relevant validation equipment used for validating and calibrating the primary and secondary equipment and verification facility of any gas metering system The relevant equipment or reference materials used for laboratory analysis of any gas sample

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OPERATIONS MANAGEMENT 5.3.4 Deviation Any deviation from the requirements stipulated in this section shall requires PETRONAS’ approval with respect to:

a) b) c)

measurement and allocation concept, metering project implementations operations and maintenance of any gas metering system

5.3.5 Documentation Contractor shall establish and maintain up to date files containing all specifications, calculations and as-built drawings. The files shall also contain reports on verification revision, design, fabrication, installation and commissioning inclusive of inspection and testing programmes, operation manuals for all fixed and temporary phases and other relevant documentation.

Contractor shall ensure that all documentation during project implementation is completed promptly, is readily available and inclusive of uncertainty analysis, FAT and SAT procedures and results and the project completion report. The information shall be submitted to PETRONAS upon project completion.

Contractor shall establish an internal control system and maintain an up-to-date list of documentation.

5.4 Design 5.4.1

General Requirements A gas metering system shall be designed, fabricated, inspected and tested in accordance with the latest agreed editions and supplements of technical specifications, codes, standards and references mentioned in Section 5.8, where applicable, that may be amended or supplemented from time to time.

Contractor shall request vendor to quote for the design, manufacture, testing, calibration and documentation of a fully integrated skid with its associated control panel. The gas metering system shall comprise the following major component parts: a) Field Mounted Skid and Instrumentation • The minimum number of parallel meter runs required from the specified minimum and maximum flow 110

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OPERATIONS MANAGEMENT • • •

rates at a specific accuracy with a complete standby meter run and/or a verification facility All transducers and instrumentation necessary for measuring mass and volume flow rates, temperature, pressure, density and verification operations. A density calculation using gas component can be an alternative means in the event that direct measurement by the instrumentation is not possible Automatic and manual sampling systems All associated pipework, valves and fittings, access stairs, walkways (for operations, maintenance and validation) and drip pans

b) Control Panel and Computer System in Control Room • A control panel shall include all necessary terminations, computer and control systems and operational indicators • A computer system shall consist of flow computers, supervisory computer and communication bus. The supervisory computer and communication bus shall be provided with full redundancy • All relevant items necessary for system functionality inclusive of equipment for testing, validation and calibration The gas metering system shall have common inlet and outlet headers with valves to facilitate inspection and maintenance. No bypassing of the gas metering system is allowed for normal operations after start up. The gas metering system should be designed to minimise the probability of liquid carry-over into the gas metering system and from any condensation or separation that would have significant effect on measurement uncertainties. The energy content of the gas delivered shall be computed by multiplying the total mass over a period of time by average Gross Heating Value (GHV) of gas during the same period of time. The composition of gas GHV (mass based) shall be determined by using online gas chromatography or through flow proportional sampling and laboratory analysis. The Sl unit shall be used and the energy content of gas shall be expressed in megajoules (MJ) at standard conditions.

All equipment within the skid shall be ergonomically arranged such that there is safe and easy access for operation, maintenance and PPGUA/3.0/042/2013

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validation. Facilities such as platforms, gratings and stairs shall be provided to accommodate any work that needs to be performed on the gas metering system. All equipment and materials supplied shall be brand new and suitable to be used in accordance with their design operating conditions.

Where any new technology other than an orifice or ultrasonic meter is to be explored, details of the proposed equipment, its layout and verification procedure should be discussed with PETRONAS, in advance.

A typical gas custody transfer metering system schematic diagram is shown in Appendix 5, Figure 7.

5.4.2 Mechanical Requirements and Primary Element

5.4.2.1

Orifice Meter Orifice meter design and installation shall be in accordance with ISO 5167-1:2003 and ISO 51672:2003, unless otherwise specified in this section.

Proposals to implement any new requirement based on the latest revisions of ISO 5167-1 and ISO 5167-2 for the existing gas metering system, either partially or in full, should be discussed with PETRONAS prior to implementation. a) Orifice Plate and Fitting • The minimum diameter ratio (β ratio) shall not be less than 0.2 and the maximum allowable shall not exceed 0.6 • The maximum Differential Pressure (DP) of 0.5 bar shall be preferred. A higher DP may be used where it is demonstrated that the below conditions are met: - The deformation of the orifice plate at the maximum DP shall be less than 1% (i.e. not exceeding flatness limit). When measured on a bench or flat surface, the flatness shall be within 0.5%. - The uncertainty in flow caused by elastic deformation of the orifice plate shall be less than 0.1%. Deformation calculation shall be calculated for the worst-case condition if the meter forms 112

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OPERATIONS MANAGEMENT part of a blowdown system • An orifice plate shall have the thickness as determined in ISO 5167-1:2003 and ISO 5167 2:2003 • Upstream and downstream pressure tapping shall be in the same axial plane in accordance with the direction stated in ISO 5167-1:2003 and ISO 5167-2:2003 • Carrier for the orifice plate should be of the type that may allow the plate to be changed or removed for routine inspections without depressurising the line b) Meter Tubes Upstream and downstream straight pipe lengths from an orifice plate shall have lengths that correspond to “zero additional uncertainty” as specified in ISO 5167-2:2003. A meter tube should be installed in a manner that allows it to be able to be disassembled for inspection and maintenance of the inner wall both upstream and downstream of the orifice plate. The meter tube should be externally insulated to minimise heat transmission or loses to or from the surroundings to ensure temperature stability. The density tapping line and other lines such as a temperature transmitter that form part of density calculation shall be fully insulated to minimise errors. The use of flow straightening vanes, drain and vent holes in the meter tubes shall follow the recommendations as stipulated in ISO 5167 1:2003 and ISO 5167-2:2003.

The upstream pipe run between the primary device and first upstream fitting or disturbance may be made up of one (1) or more sections of pipes as per ISO 5167-1:2003 and ISO 51672:2003. It shall be ensured that the diameter step between any two (2) sections does not exceed PPGUA/3.0/042/2013

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OPERATIONS MANAGEMENT 0.3% of mean value of D, i.e. pipe diameter that is measured in accordance with ISO 5167-1:2003 and ISO 5167-2:2003. c) Valves and Fittings Both ends of the gas meter run shall be provided with block and bleed valves for isolation and this may be achieved either through conduit gates or full bore ball valves. The gas isolation system shall be designed in such a way that the DP across an orifice plate does not exceed 1 bar during pressurisation and depressurisation. Equalising line and valves shall be provided by passing across an inlet valve for pressurising/equalising and depressurising the meter run. The gas metering system shall be provided with a vent system. The connection to the system should not be located near to the orifice meter. Each connection shall be provided with dual block valves and a pressure gauge located in between the block valves. 5.4.2.2 Gas Ultrasonic Meter (Multi-Path) The design of a gas metering system shall be in accordance with the following standards, where applicable: • •

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ISO 17089-1:2010 AGA XQ0701 AGA Report No. 9 (2007) and AGA XQ0310 AGA Report No. 10 (2003)

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OPERATIONS MANAGEMENT Contractor should also consider recommendation from the meter’s

any specific manufacturer.

a)

General Requirements The ultrasonic meter to be used shall have a sufficient number of sound paths and shall be proven to provide a representative gas velocity measurement covering the cross section of a pipe at the relevant flow conditions.

The meter shall be installed in accordance with field proven installation practices. It shall also be installed such that no accumulation of liquid or particles could possibly occur in the vicinity of the transducers that could affect its performance.

The piping arrangement or construction of the meter shall allow for inspection and necessary maintenance on the meter to be carried out. Its transducer shall be retrievable and with the removal of a pair of the transducers, the uncertainty of the meter shall still be within the specified tolerable limit. All paired transducers shall be tagged accordingly. A facility for the detection of a meter malfunction such as transducer failure, should also be provided. A low flow alarm shall be indicated when the meter starts to operate below its specified minimum flow rate. Self-diagnostic features or equivalent features shall be provided and utilised for performance monitoring of the meter. Tamper-free computing features should be provided to log the required data. Precautionary measures should be taken if carbon dioxide (CO2) levels are expected to approach 8% (depending on technology development) or if the meter is operating near the critical gas density. The presence of high levels of some components in the gas such as CO2, can influence and possibly inhibit PPGUA/3.0/042/2013

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the operations of the meter.

b) Meter Tubes The number of meter tubes shall be based on design capacity and a standby run shall be provided for a gas metering system. A minimum set of a pair of offline transducers shall also be made available. The minimum upstream straight pipe length inclusive of a flow conditioner and the minimum downstream straight pipe length of the meter shall be 10D and 5D, respectively. For bi directional applications, both ends of the meter should be considered as upstream. It shall be further verified that the upstream and downstream of the meter will not result in the required measurement uncertainty to be exceeded. Flow straighteners of any recognised standard can be installed, if necessary.

The meter manufacturer shall be consulted about the installation location such as not installing the meter near a pressure reduction system such as valves and to ensure that the surrounding equipment will not affect the ultrasonic signals. Proper evaluation needs to be carried out.

5.4.2.3 Other Meters The use of other types of meter than an orifice and gas ultrasonic meter shall be subject to PETRONAS’ prior approval.

5.4.3 Field Instrument Requirements

a)

116

Installation of Instruments A thermowell shall be installed adjacent to each electronic temperature sensor or group of sensors for calibration. It shall be possible to connect test instruments in parallel with all pressure sensors in a gas metering system. Temperature, pressure and density, where the specified measuring points shall be representative of conditions at a meter and situated as follows:

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OPERATIONS MANAGEMENT • In volumetric measurement system: as close to the meter as possible without infringing ISO requirements or other standards as specified in this section. • In mass measurement system: as close to a density meter as possible that should also be located as near to the meter as possible without infringing ISO requirements or other standards as specified in this section. b)

Instrument Loops Instrument loops shall be kept separated from other types of instrumentation and power supply cabling in the area of use. Cables and junction boxes shall not be shared with instrument loops that are not part of the gas metering system.

The cables and other part of the instrument loops shall be designed and installed so that they will not be affected by electromagnetic fields.

c)

Temperature Measurement A temperature sensor shall be constructed of 4-wire platinum RTD element (100 Ω at 0°C), resistance tolerance Class A or equivalent classes. The resistance tolerance and the relation between resistance and temperature shall be in accordance with IEC 60751:2008. The sensor shall be installed in a thermowell.

A head-mounted intelligent temperature transmitter should be located in the field as well as intelligent analogue communication (4-20 mA) with superimposed HART shall be preferred. The transmitter output signal shall be linear with measured temperature. The transmitter shall have galvanic separation between the sensor element and output amplifier.

The temperature measuring device shall be located downstream of an orifice meter close to a density meter.

The accuracy of a complete circuit of temperature sensor or transmitter shall be within ±0.15°C.

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118

d)

Differential Pressure Measurement If relative measurement uncertainty at the lowest operational DP exceeds ±0.7%, each meter tube shall have more than one (1) transmitter, each covering a part of the total DP range in the system. In addition, there shall be a check DP cell connected to a computer part that will generate an alarm if the difference in readings from pay and check cell exceeds a set limit.

The signal from the pay transmitter shall normally be used to compute mass flow. In the event of the failure of the pay transmitter, a check transmitter will be used. The system shall also be designed in such a way that auto switch over is provided between low and high DPs.

Impulse lines connecting static and DP sensors shall be as short as possible and upstream and downstream pressure tappings shall be in the same axial plane and shall not be below the central axis of meter tube.

The DP sensor transmitter shall be installed vertically upright. The impulse lines shall have a downward gradient or tilt angle and shall also be provided with a condensate trap.

The DP sensor/transmitters shall be protected against weather and vibration. Manifolds valves and pipe assemblies shall be designed for isolation purpose, maintenance and shall also have the provision for online calibration.

The accuracy of a complete loop of DP transmitter shall be within ±0.25% of span.

e)

Pressure Measurement A pressure transmitter range of a specific series shall be selected so that normal operating pressure is between 50% and 75% of scale, but where a narrow-span instrument is required, the adjusted range shall cover the minimum and maximum operating pressures. An intelligent analogue communication (4-20 mA) with superimposed HART shall be preferred.

A static pressure tapping shall be in accordance with ISO 5167-1:2003 and ISO 5167-2:2003 and located in a plane

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of upstream pressure tapping. It shall be separated from the tapping used to measure DP.

The accuracy of a complete loop of pressure transmitter shall be within ±0.25% of span.

f)

Density Measurement The density measurement where designed in accordance with the where applicable:

• • •

specified following

preferably

shall be standards,

HM 8 (1997)(formerly IP PMM Part VII, S2) ANSI/API MPMS Chapter 14.6 (R2012) AGA XQ9212 AGA Report No. 8 (1994); and other equivalent standards

Gas density at the meter may be determined by continuous direct measurement using a density meter or calculated based on the equation of state with the measurements of gas temperature, pressure and composition. However, both methods can be used for pay and check functions. The minimum requirements for the density measurement using both methods are as follows:

• Each meter run shall be provided with a facility to measure online density. The position of the density meter shall be such that the density of gas is measured at line temperature and pressure • The output signal from the density meter shall be in the form of frequency • The density meter shall be provided with facilities for online calibration without needing to remove the unit from its mounting • The density meter shall be installed as near as possible to a density sample probe, downstream of an orifice meter, in a pocket. Density samples shall be extracted at a point 8D downstream of the orifice meter and returned to a flange tap downstream • A built-in RTD shall be used for indication purpose only and the whole system shall be insulated against heat loss • The accuracy for a complete density circuit using vacuum check method shall be within 300 ns PPGUA/3.0/042/2013

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OPERATIONS MANAGEMENT g)

Local Recorder For an orifice meter, a local recorder shall be used to give a local readout and act as a back-up unit for each flow computer. It can be either a chart recorder or an independently powered flow computer (e.g. solar powered or multi-stream flow computer).

Local recorder inputs or inputs to the independently powered flow computer for differential pressure, line temperature as well as line pressure shall be provided in each meter run in order to facilitate the computation of mass and volume throughput for a particular line, in case the main computer fails.

h)

The local recorder shall be located at a gas metering skid and shall be sheltered. Control Room Instrumentation Instruments that are sensitive to temperature or other environmental factors should be installed where these factors can be controlled.

5.4.4 Computer Based Monitoring and Control Functions Requirements a) General All gas metering computations shall be managed by a computer system. This system has to be installed in a central control room, local control room or local equipment room. Normally, separate computers will be dedicated for meter runs and station control. However, the functionality of the computers may be combined if it can be demonstrated that the required reliability, availability and redundancy standards will be met. However such an arrangement has to be agreed by PETRONAS. The computer system is to be designed as follows: • The computer part in a gas metering system shall have no functions other than those involved in the metering. The gas metering system shall be designed in such a way that the maximum gas flow will be measured • The system should include at least two (2) independent registers for storing accumulated fiscal quantities for each meter run and station total. It shall not be possible to delete or change these registers by operator encroachment or power failure 120

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OPERATIONS MANAGEMENT • The computer shall also be designed to ensure that cumulative quantities generated during validation/ calibration are registered separately from the measured amount • Manually entered parameters shall be displayed without rounding off or truncation of digits. The display on the computer shall have sufficient resolution to enable the verification for calculation accuracy, be carried out. Facilities shall be installed to prevent access to computer by any unauthorised personnel • The computer system shall be designed in such a way that the transfer of data to a distributed control system, supervisory control and data acquisition or plant information system is permissible and all interfacing requirements such as handshaking and necessary software are provided • Computer parts shall have an automatic watch-over for differences between readings of measured values, for parallel meter runs • For continuous monitoring of measurement data the computer shall, for each meter run, automatically log and store for at least one (1) year the following data: - at intervals of one (1) hour cumulative quantities and average values of pressure, temperature and density; - at intervals of twenty-four (24) hours: cumulative quantities This information shall be accessible on printout in a clearly set out format using standard computer printer and paper. Access to the logs will not be possible without the use of key operated switch. • A gas meter verification algorithm should be available • A report facility for computer constants keypad settings should be available • The computer will have the ability to perform meter curve (foot-print) interpolation for the minimum of eight (8) calibration points b) Data Security The computer data transmission shall be designed in accordance with Level A in HM 23 (1998) (formerly IP PMM Part XIII, S1 or IP 252/76). The computer is required to have a self-diagnostic capability. It shall monitor to ensure that programme loops PPGUA/3.0/042/2013

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are executed at the correct intervals by means of a watchdog function. The parts of the memory that contain permanent data shall have a periodical check sum control. Algorithms and fixed parameters important for accurate computation of fiscal quantities shall be stored in nonalterable memory. A security system shall be provided for manual data entry. The computer system shall be designed with features that provide for sealing.

Programme version numbers shall be assigned to identify all programmes and these shall be able to be determined directly from the visual display unit or printout. The version number can be updated every time permanent programme is altered. c) Calculation Computer routines for fiscal measurement calculation shall satisfy the requirements of the following standards, where applicable: • • • • •

122

ISO 5167-1:2003, ISO 5167-2:2003, ISO 5167-3:2003, ISO 5167-4:2003, ISO 6976:1995/Cor 3:1999, ISO 12213-1:2006, ISO 12213-2:2006, ISO 12213-3:2006 and ISO 17089-1:2010 AGA XQ9212 AGA Report No. 8 (1994), AGA XQ0701 AGA Report No. 9 (2007) and AGA XQ0310 AGA Report No. 10 (2003) GPA 2145-09 (2009) and GPA 2172-09 (2009) API MPMS 21.1 (2013) Other relevant standards as specified in Section 5.8 References

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OPERATIONS MANAGEMENT The computer shall satisfy the following criteria: • The update time to changes of input signals shall not be more than two (2) seconds and the parameters having a response time such as density and temperature shall not exceed five (5) seconds • The interval between each cycle for the computation of instantaneous flow rate and accumulated flow shall be less than ten (10) seconds • The algorithm and rounding off error for the computation of fiscal quantities in the flow computer shall be within ±0.001% for flow rate and ±0.01% for the totalisation of the computed values. Rounding or truncation shall only be carried out at the end of the final computation • Temperature readings in degrees Fahrenheit (°F) shall be corrected to one (1) decimal place and two (2) decimal places for readings in degrees Celcius (°C) Contractor shall consult PETRONAS if there is any deviation from the above requirements. d) Printouts and Hardcopies A computer system should have dedicated printers for alarms and reports. The supervisory computer shall be able to electronically archive all the alarms and reports. A common printer can be used if an acceptable priority routine has been established. Automatic logging of the following information is to be provided: • Alarms for faults detected by the computer (date, time) • Inserted parameters/constant, both fixed and changeable • Quantity report • Instantaneous values of rate and measured input parameters. Any fixed values that are used instead of live signals, shall be identified • A meter verification report. All data required for manual checks of calculated correction factors inclusive of errors After consultation with PETRONAS, Contractor establish a system for reporting of agreed data.

shall

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OPERATIONS MANAGEMENT e)

Power Supply A computer system shall be equipped with an uninterruptable power supply system for back up purpose. The normal operation of a gas metering system shall not be affected if there is any change from one power source to another.

5.4.5 Sampling and Analytical Instrumentation a) General Requirements – Sampling The recommendations as specified in ISO 10715:1997 are to be followed. A delay time calculation shall be performed to ensure that the delay time between the sample point and the analyser is kept short, at least shorter that the duration of the analytical cycle. b)

Online Gas Chromatograph GHV (mass based) shall be calculated in megajoules per kilogramme (MJ/kg) at standard conditions.

Packing materials used in each chromatograph column, carrier gas, valves configuration and pressure flow regulators shall be according to industry standards. Gas composition shall be determined with the defined uncertainty of a gas chromatograph based on ISO 69741:2012/Cor 1:2012, ISO 6974-2:2012, ISO 6974-3:2000, ISO 6974-4:2000, ISO 6974-5:2000 and ISO 6974-6:2002/ Cor 1:2003, where applicable.

The composition of the gas used for calibration of the gas chromatograph shall be as close as possible to the composition of the process gas. Standard test methods to determine and analyse the composition of the gas using gas chromatography shall be in accordance with ASTM D 1945 – 03 (2010).

A controller shall be programmed such that the computations are made based on the peak integration of individual component constituting the sample. Hydrocarbon fractions heavier than and including hexane should be combined and treated as normal hexane. 124

The analysis shall be normalised to 100% and the results shall be expressed in percentage mole fractions. An operating density calculation is normally performed by a

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computer system using the percentage mole fractions from the gas chromatograph. The computer system shall also be capable of calculating the following based on the compositional data according to ISO 6976:1995/Cor 3:1999: • Compressibility factor at standard conditions • Gross calorific value (synonomus with GHV) • Wobbe-index • Relative density (real/ideal) • Density at standard conditions

The sampling system used shall ensure that gas entering the gas chromatograph is representative and that the sampling tube is protected from liquid contamination.

The recommendations as specified in ISO 10715:1997 are to be followed. The route between a sampling point and the gas chromatograph shall be practically as short as possible.

c)

Gas Sampler System Where no online gas chromatograph is installed and an automatic gas sampler is used, it shall be able to collect and store a representative gas sample at line conditions for transportation and analysis. The system shall be in accordance with ISO 10715:1997.

The automatic gas sampler shall be provided with the following monitoring facilities: • Amount of sample collected • Health status of sampler controller/system • Sampler cans in use

d)

Manual Sample Point In addition to the above, a manual sampling point equipped with valves and quick connectors, be installed such that a representative sample of the gas can be collected if the above equipment fails. The manual sampling can be taken from the same probe.

e)

Metering Data Contractor shall make metering data available at hourly basis, daily basis and/or upon request as specified in Appendix 5.1.

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OPERATIONS MANAGEMENT 5.5 Calibration, Testing and Commissioning 5.5.1

General Requirements An FAT shall be conducted, prior to on-site installation, to check the integrity of both the computer software and the mechanical/skid instrumentation. The FAT procedure shall be agreed between Contractor and vendor prior to the FAT.

During the FAT, the electronic and mechanical instrumentation shall be tested together. It is essential that vendor shall demonstrate that the equipment has been internally tested and is in good working order before Contractor and PETRONAS are invited for the FAT.

All FAT results are to be fully documented and only upon successful completion of the FAT can a gas metering system be accepted and shipped out to an offshore or onshore site. Once on site, further testing shall be carried out prior to the commissioning of the gas metering system. Validation and calibration of all instruments using certified test equipment traceable to NML-SIRIM or any certified/ accredited third party/independent laboratory traceable to its national certification/accreditation and standards shall be carried out. It is the responsibility of Contractor to ensure that the FAT and SAT procedures are made available prior to the tests. PETRONAS may request these procedures to be submitted for review.

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Contractor shall notify and invite PETRONAS and NML-SIRIM, where applicable, to witness the following activities, at least three (3) weeks in advance:

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OPERATIONS MANAGEMENT WITNESSING REQUIREMENTS CALIBRATION AND TESTING ACTIVITIES

PETRONAS, Contractor and Vendor

NML-SIRIM

Calibration of any master meter used for custody transfer or trade purpose

Yes

Yes

Calibration of any master meter used for allocation purpose

Yes

No

Calibration of any meter used for custody transfer or trade purpose

Yes

Refer to Note 1

Calibration of any meter used for allocation purpose

Yes

No

FAT of any gas metering system used for custody transfer, trade or allocation purpose

Yes

No

SAT of any gas metering system used for custody transfer or trade purpose

Yes

Yes

SAT of any gas metering system used for allocation purpose

Yes

No

Note 1: NML-SIRIM’s participation is not required unless the gas metering system has no master meter in place.

PETRONAS may decide on its participation for the calibration and testing activities.

5.5.2 Calibration a) General Gas custody transfer and allocation metering systems shall be calibrated with certified test equipment traceable to NML-SIRIM or any certified/accredited third party/ independent laboratory traceable to its national certification/accreditation and standards. Secondary standards or test equipment used for validation and calibration of all relevant parts of the gas metering system shall be calibrated and certified by NML-SIRIM or any certified/accredited third party/independent laboratory traceable to its national certification/accreditation and standards. b) Meter Inspection/Calibration • Orifice Meter Inspection and measurement of upstream pipe sections PPGUA/3.0/042/2013

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(D) adjacent to an orifice plate shall be checked for circularity and cylindricality in accordance with ISO 5167-1:2003 and ISO 5167-2:2003. Inspection shall be conducted by a certified third party and shall be traceable to NML-SIRIM or any certified/accredited third party/independent laboratory traceable to its national certification/accreditation and standards.

•

Ultrasonic Meter An ultrasonic meter when intended for use for custody transfer and allocation purposes shall be initially calibrated at a certified/accredited laboratory traceable to its national certification/accreditation and standards at conditions near to its operational conditions and a certificate is to be issued.

The meter shall be calibrated under undisturbed and steady flow conditions, over a statistically significant duration of time and over an appropriate range of flow rates to describe the in-service response of the meter; a minimum of six (6), but preferably seven (7) points shall be taken. For example: for seven-point calibration: 100%, 70%, 40%, 25%, 10%, 5% of operating maximum flow rate (or design maximum) and the minimum flow rate (or design minimum) as specified in ISO 17089 1:2010. The meter shall be calibrated over the whole operating range (or design range) of the meter after which an errors curve shall be generated. The geometric dimensions of the ultrasonic meter that may affect the measurement results shall be measured by traceable equipment and its results made available on the certificate.

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Where system diagnostics is used to justify an extension to intervals between recalibrations for multi-path ultrasonic meters, the features and data acquired should be agreed with PETRONAS in advance.

•

Instrument Calibration All relevant instruments used in a gas metering system shall be calibrated and certified by the manufacturers or any certified/accredited third party/independent

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laboratory traceable to their/its national certification accreditation and standards.

5.5.3 Testing

5.5.3.1 General Testing General testing shall include checking against drawings, flushing, cleaning, hydrostatic pressure testing, electrical earthing and it shall be done on an individual item basis. Vendor shall perform its own test prior to the FAT and provide the necessary evidence if required via filed test sheets. 5.5.3.2 Factory Acceptance Test a) General Check Prior to further test in the factory, a general check on a gas metering system is to be carried out. This includes checking of the following items: • Dimension check as per approved drawings and standards • Instrument installation and quantity check as per approved drawings and bill of quantity, respectively • Availability of all documentations b) Metering Panel and Instrumentation Equipment Tests • All panel and field mounted instruments, cabling and connectors shall be visually inspected for compliance to specifications with regard to segregation of cables, satisfactory access, vents, drains and general good quality of installation work • Calibration checks using precision test equipment, shall be performed on all transducers, transmitters, converters, indicators, recorders, gauges and switches and the relevant instruments supplied for use with the gas metering system • All safety and relief valves shall be tested, set and tagged with the set pressure • An insulation test shall be undertaken on all power supply and instrument cables and panel wiring using a voltage tester. All instruments that may cause internal damage shall be disconnected during the test. All resistance thermometer elements shall PPGUA/3.0/042/2013

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OPERATIONS MANAGEMENT be tested for insulation resistance to BS EN 60751:2008 • A sample of the power circuit breakers to be used shall be tested by simulating a short circuit failure • The control panel shall be fully functionally tested before connection to the skid using appropriate simulators and other test equipment • These tests shall include: - panel mounted receiving indicators - outputs from panel mounted controls - meter run instruments - computer functional test - verification of computer calculation and integration accuracy - interlocks and alarms - checking of power distribution circuits and breakers for correct wiring - analogue functions shall be calibrated at a minimum of five (5) points rising and five (5) points falling in the range (0%, 25%, 50%, 75% and 100%) • All remotely operated valves shall be checked after installation on the skid by: - manual stroking of the valves to check limit switch actuation and to ensure full operations - local operations to verify the phase of electrically operated actuators rotation and functioning of local controls - remote operations and checking of remote position indications and interlocks - noting the time for each valve to fully stroke in each direction • After connection between the panel and skid, loop checks shall be carried out on all circuits to check correct wiring and calibration of the gas metering system. This shall include checks of all alarms, interlocks, digital and analogue inputs and outputs • A check shall be made on the effects of power supply variation by setting all instruments in normal operating mode and varying the output voltage to upper and lower limits whilst noting the effect by repeating functional checks • The panel should be heat soaked for a minimum of one hundred (100) hours. Records shall be made 130

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OPERATIONS MANAGEMENT of the temperature at selected points on the panel. Following completion of the heat soak, loop checks shall be repeated at ambient temperature to ensure that none of the equipment has suffered any adverse thermal effects. A check of the microprocessor functional performance shall be made during the soak test (after internal panel temperatures have stabilised) • Measurement and records shall also be made on panel maximum power consumption (AC & DC) • Data transfer to another system shall be checked for data accuracy, data correctness and redundant switching of communication channels • Spares should be tested upfront • A simulation test shall include simulating with at least five (5) different values that cover the minimum and maximum levels in the working range of the skid instrument and the computers using test simulators The simulators shall simulate signals connected to the computers input or in any other way to secure a controlled, constant input to the computers.

Testing or simulating different functions of the computers shall include but not limited to manually input data, printouts, alarms and data transmission between the computers.

All computer calculations shall be verified by injecting known values into the computers and comparing the results using a manual calculation method such as flow calculation software.

5.5.3.3

Site Acceptance Test Contractor shall provide test procedure for punch list items arriving on site. Other items to be provided shall include but not limited to the following:

a) Loop diagram and loop checkout sheets b) Full print database checking c) System functional test procedure and schedule PPGUA/3.0/042/2013

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The SAT shall be considered as an extension of the FAT. Prior to the SAT, all wiring terminations shall be checked and the powering of the panel should be carried out by vendor or any vendor’s authorised representative. Some tests carried out during the FAT shall also be repeated during the SAT. The SAT shall concentrate more specifically on the following:

a) Inspection of material and equipment upon arrival on site including spares and documentation. If damage occurs during transportation, it is important to establish without delay, the extent of the damage and whether it can be repaired on site or if it will be necessary to order new materials. Suitable storage of materials and equipment should be provided. b) Field inspection of the meter and the relevant meter verification shall be conducted in accordance with the following standards, where applicable: • •

ISO 5167-1:2003, ISO 5167-2:2003, ISO 51673:2003, ISO 5167-4:2003 and ISO 17089-1:2010 AGA XQ0701 AGA Report No. 9 (2007) and AGA XQ0310 AGA Report No. 10 (2003)

All calibration equipment used for the inspection, meter verification and other metering equipment shall be traceable to NML-SIRIM or any certified/ accredited third party/independent laboratory traceable to its national certification/accreditation and standards. c) All meter inspections and verification on custody transfer metering systems that involve tax calculation shall be witnessed by vendor, Contractor and NML-SIRIM. PETRONAS may at any time witness the inspection/verification exercise. The results shall be certified by NML SIRIM. d) In the case of a master meter, where it is not possible to calibrate it on site or at a local facility, certification or recognition by NML-SIRIM shall be obtained for the results of calibration overseas. 132

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OPERATIONS MANAGEMENT e) The metering panel and instrumentation equipment test shall also be repeated and shall also include the computations check carried out by the computer system. The instrument calibration exercise carried out in this exercise is considered as Validation No. 1. f ) The completed metering skid and panel shall be subject to operational functional test during actual flow conditions to demonstrate satisfactory performance at design flow rates. g) Contractor shall submit a project completion report that should include the first official validation report to PETRONAS within thirty (30) days of the system being commissioned. Approval from PETRONAS shall be obtained before the gas metering system is put in operation for official use. 5.5.4 Commissioning a) General The installation, commissioning and start-up of a gas metering system shall be carried out in accordance with the requirements in this section. b)

Installation Quality Assurance Contractor shall develop a master plan for all installation and commissioning activities in order to provide sufficient evidence and that the overall quality control shall be effectively maintained.

The master plan shall be applied systematically to all gas metering systems. Deviations will not be tolerated. c) Commissioning Commissioning shall include the running of all rotating equipment, checking alignment, testing control loops, stroking valves, flushing, hydrotesting, final test of electrical instrumentation systems, purging, drying, inerting and other relevant activities usually carried out sequentially on a system basis. The commissioning is completed when the gas metering system is ready for start-up. d) Start-up This begins with the introduction of process hydrocarbons not counting where these may have been used previously for pressure testing/purging. PPGUA/3.0/042/2013

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OPERATIONS MANAGEMENT 5.6 Operations, Validation and Accounting 5.6.1

General Requirements Contractor shall operate and maintain a gas metering system to the highest degree of engineering standard in order to maintain its accuracy and integrity. As such, Contractor shall prepare operating, validation and hydrocarbon accounting procedures/manuals and approved by PETRONAS before start-up. These procedures shall document all activities that influence the measurement system.

5.6.2 System Operations Contractor is required to carry out the following essential activities: a) A gas metering system shall be operated and maintained in accordance with the manufacturer’s recommendations and approved operations, validation and hydrocarbon accounting procedures/manuals. Particular attention shall be given to flow stabilisation prior to meter verification and checking of block and bleed valves for leaks.

For a newly commissioned gas metering system with a dedicated meter verification facility in a continuous production system, meters shall be verified at least once a month at approximately equal intervals between verification. The verification frequency may be reduced to every two (2) months or quarterly basis provided that the results of error scatter are acceptable to PETRONAS and until an error control chart is established.

The frequency of the verification may be further reduced upon approval by PETRONAS.

b)

Where the type of meter is other than those mentioned in this section, the type and frequency of meter verification by Contractor shall be determined based on a case-to-case basis by PETRONAS after consultation with Contractor. Account shall be taken of the type of meter, process fluid and operational load cycle. Where a meter that uses novel technology is to be used, extra evaluation periods and tests will usually be required before a long term operational schedule can be determined.

c) The error and its correction factor for acceptable ultrasonic meters shall be, where applicable, in accordance with the 134

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following standards: • • •

ISO 17089-1:2010 AGA XQ0701 AGA Report No. 9 (2007) AGA XQ0310 AGA Report No. 10 (2003)

Operating Manual An operating manual shall be prepared for the purpose of providing operational guidelines for operators in performing metering activities. It shall describe the operations of the gas metering system including computers, skid instrumentation, sampling activities and other operation of the gas metering system. The manual shall, amongst other things, include what action will be taken in case of a malfunction or an alarm triggered on the gas metering system. The contents of the manual shall contain the following as a minimum: a) Overall process description b) Metering system description c) Metering instrument specification d) Computer system operation (including codes) and actions taken on alarms e) Metering system operations f ) Metering sealing procedure g) Sampling procedure 5.6.3

computer

read

System Validation In order to maintain the reliability and accuracy of a gas metering system, Contractor shall conduct a periodic validation and calibration of the gas metering system at a frequency agreed by PETRONAS. For a new gas metering system, monthly validation shall be performed. A new validation frequency can be agreed with PETRONAS after such time as the gas metering system is stable. The validation and calibration shall be performed in accordance with a Validation Manual prepared by Contractor and approved by PETRONAS. All validation and calibration results shall be recorded in the format agreed upon in the validation report. The validation report shall include but not limited to the following:

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OPERATIONS MANAGEMENT a) As-found and as-left results of the validation and calibration exercises b) System errors shall preferably be in accordance with ISO 5168:2005 c) Findings and recommendations d) Metering irregularities that have occurred since the previous validation and between the last validations A validation report shall be prepared after each validation and calibration exercise and submitted to PETRONAS within one (1) month. Any irregularity of the figures generated from the validation and calibration shall be endorsed by PETRONAS. Validation Manual A Validation Manual shall be prepared for the purpose of providing guidelines for the verification of gas metering system instrumentation. The contents of the Validation Manual shall consist of, but not limited to the following:

136

a)

Brief Description of Gas Metering System This shall include a concise description of the design concept of the system and its instrumentation, including the computer system. Descriptions of the function of each individual instrument, its accuracy and location in the system layout, system capacity, flow operating condition and the schematic drawing of the gas metering system.

Instrument description shall include the manufacturer’s name, model number, range, accuracy, input/output signal and tag number.

b)

Validation and Calibration Procedures Step-by-step validation and calibration procedures for the instruments shall be given in detail for each individual instrument in the gas metering system. A set of validation check sheets shall also be included and all readings obtained during each validation and calibration exercise shall be recorded on these check sheets. Adjustments shall be made when a reading is out of tolerance. After making the adjustments, the complete test shall be repeated.

c)

Frequency of Validation and Calibration Contractor shall give a detailed account of the frequency of validation and calibration of each of the gas metering instruments.

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OPERATIONS MANAGEMENT d)

Flow Calculation The calculations/formulae used to arrive at volume, mass and energy throughputs shall be clearly laid out. All flow constants that are to be used shall be shown in the actual units in which they are used. Where the flow constants are fixed, the actual values and their derivations shall be shown.

e)

Metering Irregularity Calculation All types of irregularities of the gas metering system and the methods for their correction shall be clearly stated.

f )

Validation and Calibration Equipment A list of validation and calibration equipment to be used in the validation exercise shall be provided in the Validation Manual. All information related to equipment specifications such as its accuracy, repeatability, serial number and range shall also be provided.

The accuracy of the calibration equipment shall be better than the accuracy of the instrument to be validated.

The equipment shall be traceable to NML-SIRIM or any certified/accredited third party/independent laboratory traceable to its national certification/accreditation and standards.

g)

System Error Calculation Any system error calculation shall be listed in the Validation Manual and preferably in accordance with ISO 5168:2005.

5.6.4 System Maintenance Contractor shall maintain a gas metering system in order to maintain its accuracy and integrity.

Contractor shall notify and seek PETRONAS’ approval before any change or modification is made to the gas metering system. Drawings and sufficient data shall be submitted together with the request for approval (refer to Section 5.3.2 in this volume).

Contractor shall notify and invite PETRONAS to witness maintenance activities relating to the modification of a gas metering system. All results pertaining to these activities shall then be properly documented. Contractor shall also obtain from vendor the PPGUA/3.0/042/2013

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recommended comprehensive spare parts’ list and price quotation for parts for the commissioning and two (2) years’ operation.

5.6.5 Security All software and all flow factors, status and alarm information stored in a gas metering system shall be protected to prevent loss of information by inadvertent operator action or input power failure.

In order to ensure the data security in the computers and other critical instrumentation in the gas metering system, sealing procedure shall be adhered to. The procedure for sealing shall be prepared by Contractor.

Critical instruments such as the computers, transmitters and critical valves shall be sealed where practically possible to prevent unauthorised entry or manipulation of the computer system and opening or closing of the critical valves at the skid. The sample cans of the sampling systems shall be sealed. The seals shall have serial numbers for easy identification.

The last valve downstream of an outlet header or offloading valve shall be sealed as per Customs’ requirements (for a custody transfer metering system).

The sealing of these identified critical instruments shall be carried out by a person authorised by Contractor and shall be recorded in a dedicated sealing logbook. The logbook shall be kept in a metering control room where PETRONAS will review it on a need to basis.

5.6.6 Accounting and Allocation a) General Requirements A Production Accounting/Allocation Manual shall clearly describe the methods used to allocate crude oil and condensate productions and natural gas sales, from the point of sale to the respective Contractor, by fields/streams and these shall be developed prior to the first oil/gas production. The allocation of products to Contractor is to be conducted monthly on the basis of mass, volume and/or energy. A Terminal Operator shall develop a production accounting/common allocation manual from the terminal to the respective tie-in Contractor. 138

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OPERATIONS MANAGEMENT There are two (2) types of allocation methods used when the metering systems are installed between different ownership fields that share common facilities: • The “Full Allocation” or “Proration” method • The “Forced Balance” or “Measurement by Difference” method b)

Accounting/Allocation Manual/Procedure Contractor shall prepare an Accounting/Allocation Manual that shall require PETRONAS’ approval. The purpose of this manual is to precisely define the way metered and other data is to be used for the determination of sales, allocation and production quantities. This manual as the minimum requirements shall consist of the following: • Accounting and allocation overview • Production measurement system • Product sampling and analysis • Data requirements • Allocation algorithm and calculation • Inventory calculation method • Methods to account for irregularities in quantity

c) Accounting and Allocation Overview The approved concept by PETRONAS shall be adopted in the allocation manual that should include the following: • Allocation algorithm concept • Allocation network diagram • Metering systems • Allocation type i.e. “Full Allocation” or “Forced Balance” • Allocation system, i.e. spreadsheet, software based and others d)

Production Measurement System This section shall consist of Primary and Secondary production measurement system that should include the following: • Meter type and uncertainty • Metering configuration • Meter standard calculation

e)

Product Sampling and Analysis This section shall consist of Primary and Secondary product sampling and analysis that should include the following: • Sampling location and configuration PPGUA/3.0/042/2013

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OPERATIONS MANAGEMENT f ) g)

• • •

Sampling method and frequency Lab analysis methodology and standards Samples validation process

Data Requirements This section describes the data requirements to be used for production allocation that shall include but not limited to the following: • Mass • Volume • Heating value • BS&W Allocation Algorithm and Calculation The allocation algorithm and calculation shall consist of sequential mathematical equations that have been developed from the approved concept. Each equation shall be tested and accepted by the relevant parties prior to official use.

h) Inventory Calculation Method The inventory calculation, namely, pipeline inventory and tank inventory shall be prepared six (6) months before the expiry of the first gas/oil contract and shall be documented inside the manual/procedure. i) Methods to Account for Irregularities in Quantity Contractor shall develop irregularities procedure that shall require PETRONAS’ approval. j) Production Allocation Reporting Following the end of each calendar month and based on the official measurement in either the onshore or marine terminal or another authorised place, the monthly production of oil, gas, condensate (if applicable) and/or formation water for each field and production platform/ station shall be determined. A monthly report shall be submitted within thirty (30) days from the end of the month under review and shall include the following reconciled figures: • Petroleum and/or formation water • Fluids injected • Petroleum/gas utilised, flared or vented, stored in and delivered from each production station/terminal 140

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Monthly official allocation report produced that involves two (2) or more Contractors shall obtain the agreement of all their shareholders and PETRONAS’ approval prior to the distribution of the report.

A Typical Allocation Work Process Flow - Gas is shown in Appendix 5.2, Figure 8.

5.6.7 Metering Station Record Keeping Log Books/Records Contractor shall maintain an electronic/manual logbook and gas metering system records inclusive of inspection, master meter, meter verification and metering printout. Records of parameters such as meter flow rate and gas temperature and density shall be kept at the gas metering system for at least three (3) months. All logbook/ records shall be made available within a reasonable timeframe for inspection by PETRONAS. The electronic or manual logbook and records shall be maintained comprising information of the following systems: a) Metering Logbook A logbook for the gas metering system shall be kept preferably for each meter showing details of the following: • Particulars of type, stream and tag number including location and production measured • Totaliser readings, where applicable, on commencement and cessation of metering • All mechanical, electrical repairs or adjustments made to the meter or its read-out equipment and other parts of the gas metering system • Metering errors due to equipment malfunction, incorrect operation and relevant factors including data, time and totaliser readings; both at the time of or the recognition of an error as well as when remedial action is completed • Alarms, together with reasons and operator response • Any breakdown of the meter or withdrawal from normal service, including time and totaliser readings • Replacement of security seals when broken

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OPERATIONS MANAGEMENT b) Metering Record A manual/automatic recording should also be kept, at intervals of not more than one (1) hour, of the following parameters: • All meter totaliser readings • Meter flow rates (also relevant errors), pressure and temperature and density • Composition and heating value c) 5.6.8

One of these sets of readings should be recorded at 2400 hours or at the agreed time for taking the daily closing figure. Meter Verification Record Contractor shall also keep a meter verification record for each meter giving the details of each verified run such as verified flow rate, pressure, temperature and error. The record shall include a running plot or similar control chart, so that any undue change or fluctuation in errors may be easily detected.

Direct Reporting Contractor shall notify PETRONAS prior to any major maintenance and recalibration work on a gas metering system and also other operational related activities. PETRONAS shall also be officially notified, when any abnormal situation or error occurs that could require significant adjustment to the totalised meter throughputs.

If a meter needs to be removed for maintenance work or replacement, PETRONAS shall be officially informed with details of the meter serial number and the reasons for the action taken.

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When corrections to the meter totalised figures are needed, due to known metering errors, a formal report shall be submitted to PETRONAS detailing the times of the occurrence, totaliser readings and suspected causes for the errors.

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OPERATIONS MANAGEMENT 5.7

Final Provision

a) The final acceptance of a gas metering system will depend on the successful completion of the SAT during actual flowing conditions at field site b) Contractor shall submit a project completion report to PETRONAS at least thirty (30) days after the gas metering system has been commissioned for official approval of system usage c) PETRONAS reserves the right to increase the requirements for all items stipulated in this section d) PETRONAS may, in special cases, provide exemption from the requirements stipulated in this section

5.8 References These references shall be used for the design, installation, testing, commissioning, operation and maintenance of gas custody transfer and allocation metering systems: • Customs Act 1967 (Act 235) • Sales Tax Act 1972 (Act 64) • Weights and Measures Act 1972 (Act 71) • National Measurement System Act 2007 (Act 675) • Petroleum (Safety Measures) Act 1984 (Act 302) • PETRONAS Technical Standards • ISO 5167-1:2003 Measurement of Fluid Flow by Means of Pressure Differential Devices Inserted in Circular Cross-Section Conduits Running Full, Part 1 - General Principles and Requirements • ISO 5167-2:2003 Measurement of Fluid Flow by Means of Pressure Differential Devices Inserted in Circular Cross-Section Conduits Running Full, Part 2 - Orifice Plates • ISO 5167-3:2003 Measurement of Fluid Flow by Means of Pressure Differential Devices Inserted in Circular Cross-Section Conduits Running Full, Part 3 - Nozzles and Venturi Nozzles • ISO 5167-4:2003 Measurement of Fluid Flow by Means of Pressure Differential Devices Inserted in Circular Cross-Section Conduits Running Full, Part 4 - Venturi Tubes • ISO 5168:2005 Measurement of Fluid Flow - Procedures for the Evaluation of Uncertainties, Second Edition • ISO 6551:1982 Petroleum Liquids and Gases - Fidelity and Security of Dynamic Measurement - Cabled Transmission of Electric and/or Electronic Pulsed Data, First Edition • ISO 6974-1:2012/Cor 1:2012 Natural Gas - Determination of Composition and Associated Uncertainty by Gas Chromatography, Part 1 - General Guidelines and Calculation of Composition, Second Edition, Includes Corrigendum 1 (November 2012) • ISO 6974-2:2012 Natural Gas - Determination of Composition and PPGUA/3.0/042/2013

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OPERATIONS MANAGEMENT Associated Uncertainty by Gas Chromatography, Part 2 - Uncertainty Calculations, Second Edition • ISO 6974-3:2000 Natural Gas - Determination of Composition with Defined Uncertainty by Gas Chromatography, Part 3: Determination of Hydrogen, Helium, Oxygen, Nitrogen, Carbon Dioxide and Hydrocarbons Up to C8 Using Two Packed Columns, First Edition • ISO 6974-4:2000 Natural Gas - Determination of Composition with Defined Uncertainty by Gas Chromatography, Part 4 - Determination of Nitrogen, Carbon Dioxide and C1 to C5 and C6+ Hydrocarbons for a Laboratory and Online Measuring System Using Two Columns, First Edition • ISO 6974-5:2000 Natural Gas - Determination of Composition with Defined Uncertainty by Gas Chromatography, Part 5 - Determination of Nitrogen, Carbon Dioxide and C1 to C5 and C6+ Hydrocarbons for a Laboratory and Online Process Application Using Three Columns, First Edition • ISO 6974-6:2002/Cor 1:2003 Natural Gas - Determination of Composition with Defined Uncertainty by Gas Chromatography, Part 6 - Determination of Hydrogen, Helium, Oxygen, Nitrogen, Carbon Dioxide and C1 to C8 Hydrocarbons Using Three Capillary Columns, First Edition, Includes Corrigendum • ISO 6976:1995/Cor 3:1999 Natural Gas -- Calculation of Calorific Values, Density, Relative Density and Wobbe Index from Composition, Second Edition, Includes Corrigendum 3 • ISO 10715:1997 Natural Gas - Sampling Guidelines, First Edition • ISO 12213-1:2006 Natural Gas - Calculation of Compression Factor, Part 1 -Introduction and Guidelines, Second Edition • ISO 12213-2:2006 Natural Gas - Calculation of Compression Factor, Part 2 -Calculation Using Molar-Composition Analysis, Second Edition • ISO 12213-3:2006 Natural Gas - Calculation of Compression Factor, Part 3 -Calculation Using Physical Properties, Second Edition • IS0 13443:1996/Cor 1:1997 Natural Gas - Standard Reference Conditions, First Edition, Includes Corrigenda 1 • ISO 15970:2008 Natural Gas - Measurement of Properties Volumetric Properties: Density, Pressure, Temperature and Compression Factor, First Edition • ISO 17089-1:2010 Measurement of Fluid Flow in Closed Conduits - Ultrasonic Meters for Gas, Part 1 - Meters for Custody Transfer and Allocation Measurement, First Edition • ISO 80000-1:2009/Cor 1:2011 Quantities and Units, Part 1 - General, First Edition, Includes Corrigendum 1 • AGA XQ1201 AGA Report No. 3 (2012) Orifice Metering of Natural Gas and Other Related Hydrocarbon Fluids - Concentric, Square-Edged 144

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OPERATIONS MANAGEMENT Orifice Meters, Part 1 - General Equations and Uncertainty Guidelines, Fourth Edition • AGA XQ0901 AGA Report No. 5 (2009) Natural Gas Energy Measurement • AGA XQ9212 AGA Report No. 8 (1994) Compressibility Factor of Natural Gas and Related Hydrocarbon Gases, Second Edition • AGA XQ0701 AGA Report No. 9 (2007) Measurement of Gas by Multipath Ultrasonic Meters, Second Edition • AGA XQ0310 AGA Report No. 10 (2003) Speed of Sound in Natural Gas and Other Related Hydrocarbon Gases • GPA 2145-09 (2009) Table of Physical Properties for Hydrocarbons and Other Compounds of Interest to the Natural Gas Industry • GPA 2172-09 (2009) Calculation of Gross Heating Value, Relative Density, Compressibility and Theoretical Hydrocarbon Liquid Content for Natural Gas Mixtures for Custody Transfer, Third Edition • ANSI/API MPMS Chapter 14.6 (R2012) Chapter 14 - Natural Gas Fluids Measurement, Section 6 - Continuous Density Measurement, Second Edition (1991) • API MPMS 21.1 (2013) Chapter 21 - Flow Measurement Using Electronic Metering Systems, Section 1 - Electronic Gas Measurement, Second Edition • IEC 60751:2008 Industrial Platinum Resistance Thermometers and Platinum Temperature Sensors, Second Edition • BS EN 60751:2008 Industrial Platinum Resistance Thermometers and Platinum Temperature Sensors • BS EN ISO 6551:1996 Petroleum Liquids and Gases - Fidelity and Security of Dynamic Measurement - Cabled Transmission of Electric and/or Electronic Pulsed Data • ASTM D 1945 – 03 (2010) Standard Test Method for Analysis of Natural Gas by Gas Chromatography, Reapproved • ISA 5.1-2009 Instrumentation Symbols and Identification • BIPM JCGM 200:2008(E/F) International Vocabulary of Metrology Basic and General Concepts and Associated Terms (VIM), Third Edition

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OPERATIONS MANAGEMENT Section 6: Onshore/Offshore Operations 6.1 Introduction

This section provides the basic guidelines for the operations of onshore and offshore facilities, which shall include but not limited to:

a) Floating Production, Storage and Offloading (FPSOs) b) Floating Storage and Offloading (FSOs) c) Mobile Offshore Production Unit (MOPUs) d) Mobile Offshore Drilling Unit (MODUs) e) Work Barges f) Platforms g) Onshore Crude Oil, Condensate and Gas Terminals h) Other locations such as: supply bases and warehouses, as well as all other associated facilities and equipment for example: accommodation barges, pipelines, export facilities, pumps and compressors

Contractor shall operate these offshore and onshore facilities, structures and pipelines safely and in accordance with good and modern petroleum practices and in full compliance with PETRONAS HSE and regulatory requirements as well as all applicable Malaysian laws.

For all onshore and offshore facilities, Contractor is required to develop, update and maintain:

a) b) c) d) e) f ) g)

All onshore and offshore facilities must be free of drugs and alcohol. In addition, the food served shall be strictly Halal.

operation manuals simultaneous operations procedures as-built drawings shutdown programmes daily production operations report monthly performance report and production forecast operating procedure

6.2 Notice of Intent 146

Contractor must submit a notice of intent to the Head of Petroleum Operations Management (POM), Petroleum Management Unit (PMU) and advise them at least thirty (30) days before the commencement of operations with regard to any newly constructed onshore and offshore facilities, structures and pipelines. Any change of operatorship of these facilities shall likewise be dealt with as above. Contractor is required to PPGUA/3.0/042/2013

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advise PETRONAS immediately if there are any changes to the first commercial production date as defined in the Contract.

6.3 Operations Manual/Equipment Dossier

Contractor shall prepare relevant operation manual consisting of starting, operating and shutdown procedures. It shall outline the preventive measures and systems checks required to ensure proper functioning of all shutdown, control and alarm systems for production facilities.

Contractor must give a copy of the operation manual to PETRONAS as and when required.

Contractor must make all the latest operation manuals and/or equipment dossiers available to PETRONAS prior to field relinquishment as required under the Contract.

6.4 Simultaneous Operations Procedures

In the case of simultaneous operations that may expose personnel to harmful working conditions, increase the possibility of undesirable events, affects environment or cause property damage, Contractor is required to prepare the procedure for simultaneous operations and where necessary, update the relevant operations procedure.

The simultaneous operating procedures shall include the detail description of operations and procedures for mitigation of undesirable events.

Activities requiring simultaneous operations procedures include, among others: drilling, well work over, underwater activities and major construction operations and maintenance activities.

Contractor shall prepare a specific/dedicated simultaneous operations procedure for each activity and location prior to execution.

Contractor shall provide a copy of all simultaneous operations procedures to PETRONAS when requested.

6.5 As-Built Drawings

As-Built drawings must be made available to PETRONAS as and when requested. Contractor is required to update all As-Built drawings for facilities, structures and pipelines whenever modifications are carried out.

Contractor shall make available to PETRONAS, all the latest As-Built drawings prior to field relinquishment as required under the Contract.

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OPERATIONS MANAGEMENT 6.6 Shutdown 6.6.1 Shutdown Plan Contractor is required to advise PETRONAS on the annual shutdown plan, as per the original WPB submission, the reasons and the duration of the planned shutdown. Contractor shall update PETRONAS on a quarterly basis during the Quarterly Performance Review. 6.6.2 Unplanned Shutdown Contractor shall notify PETRONAS promptly of any major unplanned crude oil production shutdown. A major unplanned crude oil production shutdown refers to any shutdown event that was not planned in Contractor’s WPB, which may impact the agreed tanker lifting programme, as well as the monthly crude oil production forecast as submitted in accordance with Volume 4, Section 3: Crude Oil Annual Production Target and Quarterly Performance Review (QPR). Contractor shall notify PETRONAS promptly of any major unplanned gas production shutdown event which was not planned in Contractor’s WPB that has an impact on downstream gas customers.

Contractor shall also notify PETRONAS promptly of any shutdown of their crude oil/condensate/gas terminals and/or export facilities, either due to weather or concerns about technical integrity of associated equipment such as loading hoses, Single Anchor Leg Mooring (SALM), Single Buoy Mooring (SBM) and export pumps, which render the facilities as unavailable or unsafe for any loading operations to be performed.

Prompt notification means within twenty-four (24) hours via a telephone call or text message and must be followed up in writing either in the form of an e-mail or telefax. Notification must include, at a minimum: a) a description of the failure or the reason(s) for the shutdown b) an estimate of volume shortfall c) the impact on flaring or re-injection (where applicable) d) the actions taken e) the estimated time for normalisation These requirements are in addition to the normal Contractor’s reporting via the daily production operations report as described in Section 6.7 below. (Refer to Appendix 6: Format of the 24-hour Notification Report) 148

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OPERATIONS MANAGEMENT 6.7 Daily Production Operations Report

Contractor must submit or make accessible to PETRONAS, the daily operations report, which should include but not limited to:

a) crude, condensate, Associated Gas (AG) and Non-Associated Gas (NAG) production per platform and field b) crude and condensate sales and stocks c) gas sales and utilisation (for example flaring/venting, fuel, injection and/or lift) d) reasons for any abnormalities in the performance such as production shortfall and/or excessive gas flaring

The submission can be made via electronic mailing system.

Contractor is also required to ensure that the daily operations log is maintained and updated to record significant daily operational activities at all work locations.

6.8 Monthly Performance Report and Production Forecast Contractor shall submit a monthly performance report to PETRONAS by the 16th of the month as stipulated in Section 11: Operating Performance Improvement in this volume. Contractor must submit a Monthly Production Forecast to PETRONAS via email by the 4th week of the month for each field. This report shall include the detail of daily forecast for crude, condensate and gas production for the subsequent month including the planned and unplanned downtime assumption.

6.9 Terminal Operations

In addition to the above requirements, all onshore and offshore terminal operations for crude oil/condensate and gas terminals, namely: receiving, processing, stabilisation, storage, offloading and export/transfer facilities, must comply with the following requirements:

a) PETRONAS’ Measurement & Allocation Procedures that consist of the hydrocarbon inventory, loading, metering, validation, custody transfer and accounting procedures b) PETRONAS’ HSE requirements (refer to Volume 3: Health, Safety & Environment) c) PETRONAS’ Marine Guideline d) Malaysian Statutory requirements or any international instruments to which Malaysia has ratified e) Relevant PETRONAS’ procedures and Contractor’s internal requirements. PPGUA/3.0/042/2013

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OPERATIONS MANAGEMENT 6.10 Inspection and Operations Audit

PETRONAS reserves the right to conduct any operations inspection or audit at Contractor’s and/or their contractor’s operational locations, whenever and wherever necessary. This may be conducted either as a separate exercise or together with an inspection of the HSE, facilities and/or other activities open to inspection and audit.

6.11 Integrated Operations 6.11.1 Introduction Integrated Operations is an approach towards resource and asset optimisation that integrates people and work processes, appropriately facilitated by technology. It is a collaborative effort with optimisation in focus.

A Contractor who wishes to implement Integrated Operations shall submit the implementation plan to PETRONAS for approval. This may be applicable to Contractor who has critical operations issues as identified by the PETRONAS.

6.11.2 Objective The aim of operating in an integrated manner is to achieve the targeted or improved state in the following areas: a) b) c) d) e) f) g) h)

Business and operations decision-making HSE performance Reservoir drainage/ultimate recovery (UR) System efficiency and productivity (increased production or reduced deferment) Equipment condition monitoring and reliability Internal supply chain integration CAPEX and OPEX Operations transparency and real-time accessibility of data by PETRONAS

6.11.3 Requirement Integrated Operations requires: a) b) 150

an integration of business processes and advanced ICT technologies, supported by organisational alignment to deliver operational excellence the elimination of physical boundaries between people, making it possible in real-time or right-time to cooperate and collaborate across global business units

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OPERATIONS MANAGEMENT c)

that the application of information technology is adequately supported by competent resources, available infrastructure and work processes to ensure efficient and optimised asset operation

6.11.4 Standard Request & Budget Submission Submission of an Integrated Operations implementation plan fulfilling the stated pre-requisites must be directed to General Manager, Production Operations, Petroleum Operations Management, PMU for evaluation and approval.

Contractor should aim to align submission with WPB deadlines.

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OPERATIONS MANAGEMENT Section 7: Gas Flaring/Venting Limit 7.1 Objective

Contractor shall seek PETRONAS’ approval for flaring or venting of NonAssociated Gas (NAG) and Associated Gas (AG) resulting from production operation activities from a petroleum field.

Contractor must comply with the flaring or venting limit set by PETRONAS for the year.

7.1.1 Non-Associated Gas (NAG) NAG shall NOT be flared or vented, except under the following circumstances (subject to prior approval from PETRONAS): a) when gas is released from condensate stabilisation and gas conditioning units and the utilisation of such gas cannot be economically justified b) during cleaning up of a well and well evaluation tests not exceeding a continuous testing period of forty-eight (48) hours c) when gas is released during emergencies d) during regular scheduled facilities maintenance and inspection of gas related equipment (not exceeding the duration as stipulated in the WPB) e) during commissioning of gas related equipment not exceeding two (2) continuous weeks

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PETRONAS shall be notified of flaring or venting of NAG during the exploration and development operations.

7.1.2

Associated Gas (AG) Contractor shall seek PETRONAS’ approval for flaring or venting of AG as a result of production operations from any petroleum field.

Contractor must submit the corresponding AG production and utilisation forecast based on a crude oil availability forecast and shall provide justification for the flaring or venting level. The forecast shall be submitted together with the production forecast during the WPB and ECR submission (as stipulated in Volume 4, Section 4: Gas Production, Condensate and Quarterly Performance Review (QPR)).

PETRONAS shall convey the annual flaring/venting limit of AG from any petroleum field for Contractor to comply with.

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The flaring or venting of AG requires prior approval by PETRONAS except in the following cases:

a) b) c) d) e) f)

when gas vapours are released from storage vessels including tanks and specifically surge tanks and free water knock-out vessels and if such gas vapours cannot be economically utilised during temporary equipment failure (for example, compressor) of up to seventy-two (72) hours during cleaning up of a well, production test or any other well evaluation tests (not exceeding a continuous period of forty-eight (48) hours) when regular scheduled preventive maintenance, inspections and testing are conducted as per WPB when gas is released during emergencies (for example, emergency shutdowns, blanketing or pressure relief operations or as part of normal production operations (instrument gas)) during commissioning of gas related equipment (not exceeding two (2) weeks)

PETRONAS shall be notified of any flaring or venting of AG during any exploration and development operations.

7.2 Flaring/Venting Limit

Contractor must comply with PETRONAS’ annual flaring or venting limit set for the year by PETRONAS.

In the event that the flaring or venting exceeds the specific period as stipulated in Section 7.1.1 and 7.1.2, Contractor shall notify PETRONAS as per Volume 1: Preamble. In line with PETRONAS’ Carbon Commitment, Contractor must take all steps to: a) minimise the flaring at all facilities where operationally and economically feasible b) aim for zero continuous venting for venting facilities with more than twenty (20) years remaining life

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OPERATIONS MANAGEMENT Section 8: PETRONAS Guidelines for Barges Operating Offshore Malaysia (PGBOOM) 8.1 Introduction This section provides the procedures and guidelines for barges operating offshore Malaysia. It applies to all mobile offshore installation units and surface units which can be moved from place to place without major dismantling or modification, whether or not they have their own motive power.

The adoption of these procedures and guidelines will ensure the desired standardisation will be achieved, as well as upgrading the safety requirement for the barges.

8.1.1 Application The units include, but are not limited to the following: a) Mobile Offshore Drilling Units (MODUs) maintained for underwater exploitation or exploration of resources beneath the seabed b) Drilling Tender Barges maintained as of (a) above c) Accommodation Barges, Jack-ups and semisubmersibles used to accommodate offshore personnel d) Construction and Pipe Laying Barges or semisubmersibles used for offshore related construction operations e) Engineering Work Barges or semisubmersibles used for hook-up and commissioning of offshore installations f ) Engineering Work Barges or semisubmersibles used for the topside and underwater maintenance of offshore installations g) Well Stimulation Barges or semisubmersibles used for oil well stimulation exercises h) Floating Storage and Offloading Unit (FSO) and Floating Production, Storage and Offloading Unit (FPSO) i) Mobile Offshore Production Units (MOPUs)

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Provisions in Section 8.2 of this volume apply to (a) to (i) above and the provisions in Sections 8.3 to 8.8 apply to (c) to (i) above.

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OPERATIONS MANAGEMENT 8.1.2 Requirements Specific requirements are as follows: Accommodation Spaces

All constructions must comply with Section 8.2. They must be constructed from steel or an equivalent material. Applicable fire integrity standards must be used between adjacent spaces as per Tables 7A and 7B of Appendix 7.

Automatic Fire Detection and Alarm Systemm

An automatic fire detection and alarm system must be provided in all accommodation and service spaces. The system shall comply with Section 8.3.

Automatic Flammable Gas Detection and Alarm System

An automatic flammable gas detection and alarm system must be provided in all accommodation entrances and service spaces. The system shall comply with Section 8.4.

Life Saving Appliances

All life saving appliances must comply with Section 8.5. All barges that are involved in drilling activities that are either producing hydrocarbons or are shut-in or semi-submersible must be provided with rigid Totally Enclosed Motor Propelled Survival Craft (TEMPSC) and there must be sufficient places in the craft for all personnel. If no TEMPSC is available, Contractor must demonstrate that the substitute craft meets the same objectives as a TEMPSC.

Fire Fighting Equipment

All fire fighting equipment must comply with Section 8.6. A fixed fire extinguishing system in compliance with International Maritime Organization (IMO) must be provided in machinery spaces. Halon is strictly prohibited.

Provisions for Helicopter Facilities

Adequate provision for helicopter facilities, when provided, must comply with Section 8.7.

Operating Manual

An operating manual for safe operation of the unit must be kept on board and must comply with Section 8.8.

Structural Fire Integrity

The fire integrity of bulkheads and decks must comply with the minimum fire integrity requirements as prescribed in Tables 7A and 7B in Appendix 7.

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OPERATIONS MANAGEMENT General Waste and Scheduled Waste Management

Contractor must comply with PETRONAS E&P Minimum Environmental Specifications (MES) when managing general and scheduled waste. The discharge of untreated sewage is strictly prohibited, in compliance with Annex IV of Marine Pollutions (International Convention for Prevention of Pollution from Ships) (MARPOL). Oily bilge water must be discharged according to Annex I of MARPOL.

Electrical Power Supply

Portable generators are not allowed to supply the barge’s main power needs.

8.1.3 Definitions

8.1.3.1 Steel or Other Equivalent Material Where the words “steel or other equivalent material” occur, “equivalent material” means any non-combustible material which, by itself or due to insulation provided, has equivalent structural integrity to steel when exposed to the standard fire test (for example Aluminum Alloy with appropriate insulation). 8.1.3.2

Non-Combustible Materials Non-combustible materials are materials which neither burn nor give off flammable vapors in sufficient quantity to self-ignite when heated to approximately 750OC.

8.1.3.3 A Standard Fire Test (as defined in SOLAS Chapter II-2 Regulation 3) A Standard Fire Test requires that relevant bulkheads or decks are exposed in a test furnace to temperatures that approximately correspond to the standard time temperature curve. The exposed surface of the specimen must not be less than 4.65 square metres (50 square feet) and 2.44 metres (8 feet) in height/length of deck. The test conditions should resemble, as closely as possible, the intended construction and include, where appropriate, at least one joint. The standard time-temperature curve is defined by a smooth curve drawn through the following points measured above the initial furnace temperature:

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a) at the end of the first 5 minutes: 556OC b) at the end of the first 10 minutes: 659OC

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c) at the end of the first 15 minutes: 718OC d) at the end of the first 30 minutes: 821OC e) at the end of the first 60 minutes: 925OC

8.1.3.4 “A” Class Divisions (as defined in SOLAS Chapter II-2 Regulation 3) “A” class divisions are those divisions formed by bulkheads and decks which must comply with the following: a) They must be constructed of steel or other equivalent material; b) They have to be suitably stiffened; c) They must be constructed to be able to prevent the passage of smoke and flames in the one-hour standard fire test; d) They are required to be insulated with non-combustible materials such that: the average temperature of the unexposed side will not rise more than 139OC above the original temperature. Nor will the temperature, at any one point including any joint, rise more than 180OC above the original temperature, within the times listed below: • Class “A - 60”: 60 minutes • Class “A - 30”: 30 minutes • Class “A - 15”: 15 minutes • Class “A - 0”: 0 minute 8.1.3.5 “B” Class Divisions (as defined in SOLAS Chapter II-2 Regulation 3) “B” class divisions are those that are formed by bulkheads, decks, ceilings or linings, which must comply with the following: a) They must be so constructed as to be capable of preventing the passage of flame to the end of the first half hour of the standard fire test. b) They shall have an insulation value such that the average temperature of the unexposed side will not rise more than 139OC above the original temperature. Nor will the temperature at any one point, including any joint, rise more than 225OC above the original temperature, within the times listed below: • Class “B - 5” : 15 minutes • Class “B - 0” : 0 minute PPGUA/3.0/042/2013

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OPERATIONS MANAGEMENT c) They shall be constructed of approved non combustible materials. Additionally all materials used in the construction and erection of “B” class divisions shall be non-combustible. 8.1.3.6 “C” Class Divisions (as defined in SOLAS Chapter II-2 Regulation 3) “C” class divisions are divisions constructed of approved non combustible materials. They do not need to meet either of the requirements relative to the passage of smoke and flame or limitations relative to the temperature rise. 8.1.3.7

Public Spaces Public spaces are those portions of the accommodation which are used for halls, dining rooms, lounges and other similar permanently enclosed spaces.

8.1.3.8

Control Stations Control stations are:

a) spaces containing emergency sources of power and lighting b) spaces containing barge radio equipment, fire control and recording stations c) spaces containing centralised fire alarm equipment d) spaces containing centralised emergency public address system stations and equipment 8.1.3.9 Corridors Corridors mean corridors and lobbies.

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8.1.3.10

Accommodation Spaces Accommodation spaces are public spaces, corridors, lavatories, cabins, offices, hospitals, cinemas, games and hobbies rooms and pantries that do not contain cooking appliances or similar permanently enclosed spaces.

8.1.3.11

Stairways Stairways are interior stairways, lifts, escalators (other than those wholly contained within the machinery spaces) and enclosures. In this connection a stairway that is enclosed only at one (1) level should be regarded as part of the space from which it is not separated by a fire door.

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OPERATIONS MANAGEMENT 8.1.3.12 Service Spaces (low risk) Service spaces (low risk) are lockers and store rooms that have an area of less than 2 square metres, as well as drying rooms and laundries. 8.1.3.13

Category “A” Machinery Spaces Category “A” machinery spaces are all spaces that contain internal combustion type machinery with an aggregate total power of not less than 375 kilowatts or ones which contain an oil fired boiler or oil fuel unit. This category also includes any trunks to such spaces.

8.1.3.14 Other Machinery Spaces This category includes all machinery than those in category “A” above. 8.1.3.15

spaces

other

Hazardous Areas A hazardous area is any area where, the atmosphere is potentially inflammable due to operations or in areas where the use of machinery or electrical equipment without proper consideration may lead to a fire hazard or explosion.

8.1.3.16 High Risk Service Spaces Galleys, pantries containing cooking appliances, paint rooms, lockers and store rooms having areas of 2 square metres or more are regarded as being high risk service spaces as are, workshops, other than those forming part of the machinery spaces. 8.1.3.17 Open Decks Open decks are open deck spaces, excluding hazardous areas.

8.2 Accommodation Spaces 8.2.1 Restrictions a) There must be no direct communication between accommodation spaces and any chain locker, cargo stowage or machinery spaces, except through solid, close fitted doors or hatches b) There should be no access via vent or sounding tube, from a fuel or cargo oil tank into accommodation spaces. Access openings and sounding tubes may be located in corridors, provided they are closed and sealed air-tightly, when not in use PPGUA/3.0/042/2013

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OPERATIONS MANAGEMENT c) Accommodation must be of a permanent fixture d) Sharing of a sleeping berth between two (2) people of different work shift (hot beds) is also strictly prohibited 8.2.2 Construction a) Each space used for sleeping, recreation or as a hospital (sick bay) that is adjacent to immediately above a machinery stowage space, paint locker, drying room, washroom, toilet or other odour source must be made odour proof b) Each accommodation space must be protected from operational heat and noise c) Where the shell or an unsheathed weather deck forms the boundary of an accommodation space, the shell of the deck must have a covering that prevents the formation of moisture d) The deck heads of each accommodation space must be light in colour e) Each accommodation space in which water may accumulate must have a drain scupper located at its lowest part, considering the average trim of the unit f ) Each public toilet must be constructed and located in a way that odour from the unit is prevented from polluting any sleeping spaces, mess halls, recreational facilities or hospital (sick bays) g) Built-up types of accommodation are strictly not allowed 8.2.3

Arrangement of Sleeping Spaces Wherever practicable, crew from the same shift should be berthed together to minimise sleep disturbance caused by personnel getting up for work or just finishing a working period.

8.2.4 Size of Sleeping Spaces No sleeping space may accommodate more than four (4) berths/ people. Each occupant must have access to at least: a) 2.8 square metres (approximately 30 square feet) of deck area; and b) 5 cubic metres (approximately 210 cubic feet) of volume Each sleeping space must have at least 191 centimetres (approximately 6 feet 3 inches) of clear headroom over deck areas.

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OPERATIONS MANAGEMENT 8.2.5 Berths and Lockers a) Each sleeping space must have a separate berth for each occupant b) No more than one (1) berth may be placed over another c) Each berth must have a framework of a hard smooth material that is not likely to corrode or harbour vermin. Each berth and locker shall be permanently secured to the decks d) Each berth must be arranged to provide ample room for easy occupancy e) Each berth must be at least 76 centimetres (approximately 30 inches) wide by 193 centimetres (approximately 76 inches) long f ) Adjacent berths must be separated by a partition that extends at least 46 centimetres (approximately 18 inches) above the sleeping surface g) The bottom of the lower berth must be at least 30 centimetres (approximately 12 inches) above the deck h) The bottom of the upper berth must be at least 76 centimetres (approximately 2 feet 6 inches) from the bottom of the berth below it or from the deck or any pipe, ventilating duct or overhead installation i ) Each berth must have its own light j ) Each occupant of a sleeping space must have an easily accessible locker made of hard, smooth material k) Each locker must be at least 0.194 square metres (approximately 300 square inches) in cross section and 1.53 metres (approximately 60 inches) high 8.2.6 Washing, Toilet and Shower Spaces For the purposes of this section: a) “Private Facility” means a toilet, washing or shower space that is accessible only from one (1) single or double occupancy sleeping space b) “Semi-Private Facility” means a toilet, washing or shower space that is accessible from either of two one-to-four person occupancy sleeping spaces; and c) “Public Facility” means a toilet, washing or shower space that is not private or semi-private Requirements are as follows: a) Each private facility must have one (1) toilet, one (1) shower and one (1) washbasin, all of which may be in a single space PPGUA/3.0/042/2013

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OPERATIONS MANAGEMENT b) Each semi-private facility must have at least one (1) toilet and one shower, which may be in a single space c) Each room adjoining a semi-private facility must have a washbasin if a washbasin is not installed in a semi-private facility d) Each unit must have access to at least one (1) toilet, one shower and one (1) washbasin for each eight (8) persons who occupy a sleeping space that does not have private or semi-private facilities e) Urinals may be installed in toilet rooms, but toilets must be provided and cannot be replaced by a urinal f ) Each public toilet and washing space must be conveniently located to the sleeping space that it serves g) No public facility may open into any sleeping space h) Each washbasin, shower and bathtub must have hot and cold running water i ) Adjacent toilets must be separated by a partition that is open at the top and bottom for ventilation and cleaning j ) Public toilet facilities and shower facilities must be separated k) Each toilet must have at least one (1) washbasin unless the only access to the toilet is through a washing space l ) Each washing space and toilet space must be so constructed and arranged that it can be kept in a clean and sanitary condition and the plumbing and mechanical appliances kept in good working order m) Washbasins may be located in a sleeping space 8.2.7 Mess Rooms a) Each mess room must be able to seat the number of people expected to eat in the mess room at any one time. b) Food served in the mess room shall be strictly Halal 8.2.8 Hospital (Sick Bay) a) Each unit carrying twelve (12) or more people on a voyage of more than (3) days must have a hospital (sick bay) space b) Each hospital (sick bay) space must be suitably separated from other spaces c) No hospital (sick bay) space may be used for any other purpose, when it is being used for care of the sick d) The entrance to each hospital (sick bay) space must be wide enough to easily allow access to a person on a stretcher 162

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OPERATIONS MANAGEMENT e) f ) g) h) i ) j ) k)

Each berth in the hospital (sick bay) space must be made of metal Each upper berth must be hinged and arranged so that it can be secured clear of the lower berth Each hospital (sick bay) space must have at least one (1) berth that is accessible from both sides There must be one (1) berth for every fifty (50) people or portion thereof and the number of berths in a hospital (sick bay) should not exceed two (2) Each hospital (sick bay) space must have a toilet, washbasin and bath-tub or shower that is accessible from the hospital (sick bay) Each hospital (sick bay) space must have a clothes locker, a table and seats The air conditioning system shall be isolated from the main system

8.2.9 Miscellaneous Accommodation Spaces a) Each unit must have enough facilities to provide a twenty four (24)-hour laundry service (i.e. clothes returned in twelve (12) hours) b) Each unit must have enough equipment or space to provide a twenty-four (24)-hour clothes drying service for all personnel on board c) Each unit must have an accommodation space that can be used for recreation d) Each unit must have an accommodation space that can be used as a Muslim prayer room

8.3 Automatic Fire Detection and Alarm Systems a) The system must be capable of immediate automatic activation with no manual activation by the crew necessary and has to include: • An automatic visual and audible alarm that activates whenever any fire detector comes into operation • An indicator showing the location of the fire in any space served by the system • The centralised placement of indicators on the navigating bridge or in the Main Fire Control station. These areas must be manned or equipped to ensure that any alarm from the system is immediately received by a responsible member of the crew • A fault detector that indicates any fault that may develop in the alarm system

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OPERATIONS MANAGEMENT b) The detection system must be sensitive to abnormal air temperatures and abnormal concentrations of smoke or by other factors indicative of incipient fire in any of one of the spaces to be protected c) The detection system must not be used for any purpose other than fire detection d) The detectors must turn on the alarm by the opening or closing of contacts or by other appropriate methods. Detectors that rely on the closing of contacts must be sealed and the circuit continuously monitored to indicate any fault conditions e) All fire detectors must be: • Fitted in an appropriate position and suitably protected against impact and physical damage • Suitable for use in a marine environment • Placed in an open position clear of beams and other objects likely to obstruct the flow of hot gases or smoke to the sensitive element f ) At least one (1) detector must be installed in each space where detection facilities are required and there shall not be less than one (1) detector for each 37 square meters (400 square feet) of deck area or as per the approved ship’s safety plan. In large spaces, the detectors should be arranged in a regular formation so that no detector is more than 9 metres (30 feet) from another detector or more than 4.5 metres (15 feet) from a bulkhead g) There must be at least two (2) independent sources of power for the fire alarm and fire detection system, one of which shall be an emergency source. The electrical supply should have separate feeders reserved solely for that purpose. The feeders have to run to a change-over switch situated in the control station for the fire detection system h) Contractor is required to display a plan of the automatic alarm systems adjacent to each indicating unit showing the spaces covered i ) Contractor is also responsible for testing the detectors and the indicator units by applying hot air or smoke at detector positions as recommended by the operation manual j ) There must be one (1) spare detector head for every five (5) detectors

8.4 Automatic Flammable Gas Detection and Alarm Systems Contractor is required to ensure that a fixed automatic hydrocarbon gas detection and alarm system is provided to continuously monitor all enclosed areas of the unit in which an accumulation of flammable gas may be expected to occur. It must also be capable of indicating, at the main control point, by aural and visual means the presence and location of an accumulation.

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At least two (2) portable gas-monitoring devices must be provided, each being capable of accurately measuring concentrations of flammable gas.

At least two (2) portable hydrogen sulphide gas monitoring devices are required on the unit.

8.5 Life Saving Appliances All barges must carry the following equipment: 8.5.1 Life Rafts Enough life rafts must be provided to accommodate twice the total number of people onboard. Barges that are involved in drilling activities and all semisubmersibles are required to carry: a) Rigid and Totally Enclosed Motor Propelled Survival Craft (TEMPSC) of sufficient capacity to accommodate all people onboard b) Life rafts of sufficient capacity to accommodate all persons onboard. 8.5.2

Life jackets These must comply with the IMO-LSA (Life Saving Appliance) code. There must also be twice the number of lifejackets onboard as people. Each life jacket must be fitted with a whistle and a battery powered light or equivalent.

Each person must have a life jacket stowed in their accommodation. Additional life jackets must also be stowed at or near the normal embarkation positions. They must be kept in a suitable dry stowage position and be unlocked and clearly marked. Work vests are not to be considered as life jackets at any time.

8.5.3 Lifebuoys At least eight (8) lifebuoys of a type complying with the LSA Code shall be provided so that they can be quickly thrown overboard in an emergency. Barge shall carry not less than the number of lifebuoys as per the following table :

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OPERATIONS MANAGEMENT LENGTH OF BARGE IN METRES

MINIMUM NUMBER OF LIFEBUOYS

Less than 100

Eight (8)

100 – 150

Ten (10)

150 – 200

Twelve (12)

Above 200

Fourteen (14)

At least half of the lifebuoys shall have self-igniting lights complying with the LSA Code attached and at least one on each side with a buoyant lifeline the length should be at least 1.5 times the freeboard at light draft or 30 metres whichever is greater. In addition the selfactivating smoke signal is to be provided to at least two (2) of the lifebuoys attached with self-igniting lights.

8.5.4

Line Throwing Appliances These must be of an approved type capable of carrying a line not less than 230 metres (250 yards) with reasonable accuracy and shall include not less than four (4) projectiles and four (4) lines.

8.5.5 Muster List This must outline the special duties that have been allocated to member of the crew in the event of an emergency. It should also specify a set of clear signals for calling all the crew to their survival craft, life raft and fire stations and shall give full particulars of those signals. 8.5.6 Survival Equipment All survival craft, life rafts, life jackets and lifebuoys must incorporate retro-reflective material.

8.6 Fire Fighting Equipment

All barges must have a range of firefighting equipment as follows:

8.6.1 Fire Pump There must be at least two (2) independently driven fire pumps onboard each barge.

There must also be an alternative means of providing water for fire fighting in case a fire puts all the fire pumps out of action. This must be a fixed pump independently driven which is capable of supplying two (2) jets of water.

Portable fire pumps are strictly prohibited.

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OPERATIONS MANAGEMENT 8.6.2

Fire Water Main The diameter of pipes for the fire water main must be sufficient to effectively distribute the maximum required discharge from two (2) fire pumps operating simultaneously.

8.6.3

Fire Hose There should be one (1) fire hose on deck each complete with couplings and nozzles for each 30 metres (100 feet) length of the ship and one (1) spare. Under no circumstance shall there be less than five (5) fire hoses on deck. Machinery spaces shall also be provided with fire hoses.

8.6.4

Hydrants (Fire Monitors) Hydrants (fire monitors) must be positioned so that at least two (2) jets of water from different hydrants (fire monitors) can be used to contain the fire. Each length of fire hose coming from the hydrants must be long enough to reach all parts of the barge normally accessible by the crew.

8.6.5

International Shore Connection There must be at least one (1) international shore connection and communication facilities should be placed so that the connection is available from either side of the barge.

8.6.6 Portable Fire Extinguisher A sufficient number of portable fire extinguishers must be supplied to ensure that at least one (1) extinguisher will be readily available for use in any part of the accommodation or service spaces at all times. The minimum number of extinguishers must be not less than five (5) units. 8.6.7 Firemen’s Outfits At least two (2) sets of fireman’s outfits must be provided or additional sets, according to the approved safety plan. Firemen’s outfits must be stored in a way that makes them easily accessible and ready for use. The firemen’s outfit shall consist of the following as a minimum: a) Protective clothing made of fire-resistant material to protect the skin from the heat radiating from the fire and from burns and scalding by steam. The outer surface must be water-resistant b) Rubber boots and gloves or another electrically non conducting material PPGUA/3.0/042/2013

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OPERATIONS MANAGEMENT c) d) e) f) g) h)

A rigid helmet providing effective protection against impact An electrical safety lamp of an approved type with a maximum burning period of three (3) hours An axe Self-contained breathing apparatus of an approved type A fireproof lifeline of sufficient length and strength that it is capable of being attached by a snap hook to a harness on a separate belt in order to prevent the breathing apparatus becoming detached when the lifeline is operated At least two (2) fire control plans permanently exhibited in all barges for the guidance of the crew. They should consist of a General Arrangement Plan clearly showing the Control Stations on each deck, the particulars of the Fire Alarm and Detection Systems, the location of fire extinguishing appliances and the means of accessing different compartments, areas and decks in an emergency

8.6.8 Sprinkler System All sprinkler systems are to be specified by Contractor and outlined in their respective contracts.

8.7 Provision for Helicopter Services 8.7.1 Helideck All mobile or fixed offshore helidecks operating in Malaysian waters are to comply with Airport Standard Directives (ASD).

ASD 103, ASD 104, ASD 106 and ASD 904 directives require Contractor to get approval before constructing a helideck and to be granted helideck certification before helicopter is permitted to land and take off. The helideck must be designed to accommodate the largest, heaviest helicopter intended to be used at the facility. The size must be equal to the diameter ‘D–value’ and be heavy enough to equal the tonnage ‘t–value’ (refer to PTS 37.19.10.31). The helideck shall be adequately equipped with serviceable equipment and be competently manned to ensure the safety of the helideck and helicopter operations.

The helideck must have sufficiently clear approach/departure paths for the helicopter to land and take off in any wind and weather condition within the permitted range for helicopter operations within the bisector of the 210° Obstacle Free Sector (OFS) and 150° Limited Obstacle Sector (LOS).

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The helideck must comply with the following requirements:

a) b) c) d) e) f)

The helideck must be in dark green colour. The perimeter of the landing area is required to be clearly marked with a white painted line 30 cm wide. Non-slip materials must be used Correct helideck markings and sizes shall be adhered for name, side identification panels, D-value, t-value, H-marking, TD/PM marking (circle), perimeter line and Chevron markings Sufficient flush fitting tie-down points should be provided for securing the helicopter when it’s not in use The perimeter safety net should extend 1.5 metres in the horizontal plane and be arranged so that the outboard edge does not exceed 25cm from the landing area and has an angled upward and outward slope of approximately 10°. HELIMESH stainless steel material is recommended for the perimeter safety net. Any horizontal bars attached to the perimeter safety net to support aerial, sensor, solar systems and antennas that could cause infringement or noncompliance are prohibited A minimum of two (2) access/egress routes located apart from each other are required for embarking and disembarking passengers. A third emergency access escape route may be installed for adequacy of evacuation Perimeter lighting must be installed according to the DCA’s recommendations for night landing. The lights shall be placed along the perimeter

8.7.2 Fire Extinguishers The following fire extinguishers must be provided and stored on all helidecks allowing ease of access: a) A suitable foam system consisting of monitors or foam making branch pipes that are capable of delivering sufficient foam according to the D-value size of the helideck b) There must be one (1) or more dry powder fire extinguishers with an overall capacity of not less than forty five 45 kilograms c) CO2 extinguishers having a total content of not less than eighteen (18) kilograms must be provided. These must have a long lance to enable the extinguisher to reach the engine area of the helicopter d) At least two (2) dual-purpose nozzles (twin agent units) and PPGUA/3.0/042/2013

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OPERATIONS MANAGEMENT e)

hoses sufficient to reach any part of the helicopter deck A Deck Integrated Fire Fighting System (DIFFS) capable of delivering foam and/or seawater in a jet/spray pattern to the whole of the landing area is recommended

8.8 Operating Manual 8.8.1

Operating Manual An Operating Manual containing guidance for the safe operation of the unit under normal and emergency conditions should be on board and available to all concerned.

The Operating Manual should include but not be limited to the following information, where applicable: a) A general description of the unit b) General arrangement plans showing watertight compartments, closures, vents, permanent ballast and allowable deck loadings c) Light ship data and hydrostatic curves or equivalent d) Capacity plan showing the capacity, center of gravity and free surface correction for each tank e) Stability information setting forth the allowable maximum height of the center of gravity in relation to draught data or other parameters. Stability calculation shall be carried out prior to every operation f ) Plans and instructions for the operation of the ballast system g) Schematic diagrams of main and emergency power supplies and electrical installations h) Fire control plan including type and location of firefighting appliances and escape routes from all compartments i ) Safety provisions including location and operation of life saving appliances and a procedure for evacuation of personnel from the unit j ) Procedures for anchor handling k) Procedures for adverse weather conditions l ) Procedures for management of waste discharges, inclusive of hydrocarbon and effluent discharges and sewage and garbage in compliance with all relevant maritime laws and regulations m) Muster list and station bill

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OPERATIONS MANAGEMENT 8.9 Structural Fire Integrity The fire integrity of bulkheads and decks must comply with the minimum fire integrity requirements as prescribed in Tables 7A and 7B in Appendix 7. 8.9.1 Requirements Governing the Application of the Tables Tables 7A and 7B in Appendix 7 shall be applied to the bulkheads and decks separating adjacent spaces, respectively.

To determine the appropriate fire integrity standards to be applied to divisions between adjacent spaces, Contractor are directed to categories 1-11 below. The title of each category is intended to be typical rather than restrictive.

The number preceding each category refers to the applicable column or row in the tables. 1. Control Stations 2. Corridors 3. Accommodation Spaces 4. Stairways 5. Low Risk Service Spaces 6. Category A Machinery Spaces 7. Other Machinery Spaces 8. Hazardous Areas 9. Service Spaces (high risk) 10. Open Decks 11. Sanitary Spaces and Communal Facilities (such as showers, baths and lavatories)

The following notes are to be applied to both Tables 7A and 7B in Appendix 7, as appropriate:

a) b) c)

The boundary bulkhead or decks need to be an ‘A-60’ class divisions between spaces containing an emergency power source or emergency power source components that adjoin a space containing the barge’s service generator Where spaces are of the same numerical category, the bulkhead or deck rating, shown in the tables, is only required when the adjacent spaces are being used for a different purpose. For example, in category 9, a galley next to a galley does not require a bulkhead but a galley next to a paint room requires an “A-O” bulkhead Bulkheads separating the navigation bridge, chartroom and radio room from each other may be “B-O” rating PPGUA/3.0/042/2013

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OPERATIONS MANAGEMENT d) Where an asterisk (*) appears in the tables, the division is required to be made of steel or equivalent material but is not required to be of “A” Class standard

Windows and sidecuttles, with the exception of navigation bridge windows, must be non-opening. Navigation bridge windows may be of the opening type provided their design permits rapid closure. PETRONAS may permit windows and sidecuttles outside hazardous areas to be of the opening type.

External doors in the superstructure and deckhouse shall be constructed to “A-O” standard and must be self-closing, where practicable.

Protection of accommodation spaces, services spaces and control stations is as follows:

a) b) c) d) e) 172

Corridor bulkheads, including doors, need to be “A” or “B” Class divisions extending from deck to deck. Where continuous “B” Class ceilings and/or linings are fitted on both sides of the bulkhead, the bulkhead may terminate at the continuous ceiling or lining. Doors of cabins and public spaces in such bulkheads may have a louvre in the lower half of the door. These openings shall not be provided in a door in an “A” or “B” Class division forming a stairway enclosure Stairs should be constructed of steel or other equivalent material. Stairways which only penetrate a single deck should be protected, at least at one level, by “A” or “B” Class divisions and self-closing doors so as to limit the rapid spread of fire from one deck to another. “A” Class divisions should protect personnel lift trunks. Stairways and lift trunks which penetrate more than a single deck should be surrounded by “A” Class divisions and protected by self-closing doors at all levels. Self-closing doors should not be fitted with holdback hooks. However, holdback arrangements incorporating remote release fittings of the fail-safe type may be utilised Air spaces enclosed behind ceilings, paneling or linings should be divided by close fitting draught stops spaced not more than 14 metres apart Ceilings, linings, bulkheads and all insulation, except for the insulation in refrigerated compartments, should be

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OPERATIONS MANAGEMENT constructed of a non-combustible material. Vapour barriers and adhesives used for insulation, as well as insulation for pipe fittings for cold service systems do not need to be non-combustible, but they should be kept to a minimum and their exposed surfaces should have resistance to flame propagation f ) The framing, including grounds and bulkhead joints, linings, ceilings and draught stops need to be made from non combustible material g) All exposed surfaces in corridors and stairway enclosures and surfaces in concealed or inaccessible spaces in accommodation spaces and control stations is required to have low flame-spread characteristics h) Bulkheads, linings and ceilings may have combustible veneers provided that the thickness of such veneers must not exceed 2 millimetres within any space other than corridors, stairway enclosures and control stations where the thickness of such veneers must not exceed 1.5 millimetres i ) Primary deck coverings, if applied, must be of approved materials that will not readily ignite j ) Paints, varnishes and other finishes used on exposed interior surfaces must not offer any undue fire hazard and should be incapable of producing excessive quantities of smoke or toxic fumes k) Ducts provided for the ventilation of Category A machinery spaces and hazardous areas should not pass through any accommodation and service spaces or control stations. However, this requirement may be waived provided that: • The ducts are constructed of steel and insulated to “A-60” standard; or • The ducts are constructed of steel and fitted with an automatic fire damper close to the boundary and must be insulated to “A-60” standard to a point at least 5 metres beyond the fire damper l ) The ducts provided for the ventilation of accommodation and service spaces or control stations should not pass through any Category A machinery spaces or hazardous areas. However, this may be waived provided that the ducts are constructed of steel and an automatic fire damper is fitted close to the boundaries covered

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OPERATIONS MANAGEMENT 8.10 General Waste and Scheduled Waste Management

Contractor must comply with PETRONAS E&P MES when managing general and scheduled waste.

The discharge of untreated sewage is strictly prohibited, in compliance with Annex IV of MARPOL.

Oily bilge water must be discharged according to Annex I of MARPOL.

8.11 Electrical Power Supply

174

Portable generators are not allowed to supply the barge’s main power needs.

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OPERATIONS MANAGEMENT Section 9: Asset Relinquishment 9.1 Introduction

This section provides the procedures for sub-block, oil field or gas field relinquishment and the expiration of Contracts.

9.2 Relinquishment

PETRONAS will coordinate the overall relinquishment process as below: CATEGORY

FOCAL PEOPLE

Relinquishment during the exploration period

Senior General Manager, Petroleum Resource Exploration (PREX)

Relinquishment during development and gas holding period

Senior General Manager, Petroleum Resource Development (PRD)

Relinquishment during production period

Senior General Manager, Petroleum Operations Management (POM)

9.3 The Relinquishment Process 9.3.1 Exploration/Development Period a) Relinquishment with Notification The notification of relinquishment shall PETRONAS in accordance with the Contract.

be

made

to

b)

Document submission Contractor shall submit a detail Relinquishment and Remaining Prospectivity Report that includes a Geological & Geophysical assessment to PETRONAS.

Contractor shall also provide PETRONAS with a list of available Geological, Geophysical, Petrophysical and Engineering data, acquired through seismic investigation, well drilling, interpretative works, in accordance with Volume 10, Section 5: Data Management and Data Submission.

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9.3.2 Production Period

Figure 1: Relinquishment Process for Production Period

Notice to PETRONAS on expiry date (At least twenty-four (24) months before expiry)

Conduct Due Diligence Audit (DDA) (At least eighteen (18) months before expiry)

Commencement of shadowing period (At least nine (9) months before expiry)

Notice to PETRONAS on Contractor’s future plan for the sub-block/ oil field/gas field (At least twelve (12) months before expiry)

Official handover (Expiry date)

a) The objectives of the Due Diligence Audit (DDA) are as follows: • To ensure the smooth relinquishment of producing sub-blocks, oil fields or gas fields to PETRONAS • To assure the reliability and integrity of the petroleum facilities upon relinquishment to PETRONAS • To ensure the continuity of the petroleum operations in a safe and working condition in the post Production Period or when the Contract expires b) Notices to PETRONAS: • Contractor shall notify PETRONAS about the expiry of the Production Period or Contract at least twenty four (24) months prior to the expiry date • Contractor shall notify PETRONAS of their intent or future plans for the sub-blocks, oil fields or gas fields in terms of either continuing operation or relinquishing it to PETRONAS at least twelve (12) months prior to the expiry date c) PETRONAS and Contractor shall conduct a DDA at least eighteen (18) months prior to the expiry date, in accordance with the agreed Terms of Reference. d) The scope of the DDA shall include but not be limited to: • Maintenance & Reliability 176

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OPERATIONS MANAGEMENT • Engineering & Projects • Health, Safety & Environment • Production Operation Management • Sub-surface • Business & Legal • Data & Document Management • Human Resource e) PETRONAS and Contractor shall jointly establish a Relinquishment Task Force that should have a minimum structure as below: • Steering Committee (SC) - To oversee the overall progress and ensure the objectives of sub-block, oil field or gas field relinquishment are fully accomplished - To provide direction to the Working Committee (WC), endorse issues raised by the WC and approve the DDA Report • Working Committee (WC) - To direct and coordinate the audit fieldwork for the DDA activities - To optimise resources to ensure sufficient coverage for the DDA activities - To issue the final DDA Report Note: Once new Operator is identified, a Working Committee for Asset Relinquishment will be established to manage and ensure smooth petroleum operations handover to the new Operator. f ) The summary of agreed audit findings and action plans shall be incorporated in the DDA Report g) The costs associated with conducting the DDA and the execution of action plans outlined in the DDA Report, shall be part of the petroleum operation cost h) PETRONAS or any of its appointed parties and the existing Contractor shall discuss their mobilisation plan, not less than nine (9) months prior to the expiry date to facilitate the safe and smooth transfer of petroleum facilities i ) Existing Contractor shall provide all reasonable support required by PETRONAS or any party appointed by PETRONAS, to complete their familiarisation of the petroleum facilities until the expiry date Notes: 1. Reference shall also be made to Volume 9, Section 5: Reporting Statements for expiring contract quarterly audited accounts. 2. For asset transfer involving a Contract, the above DDA requirement shall be applicable. PPGUA/3.0/042/2013

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OPERATIONS MANAGEMENT Section 10: Decommissioning of Upstream Installations 10.1 Introduction

This section provides the guidelines and requirements for the decommissioning of Contractor’s upstream installations that includes both onshore and offshore installations. Decommissioning is a process that put disused upstream installations out of service. The purpose of this section is to provide guidance for all Contractors to ensure that all activities pertaining to decommissioning of upstream installation shall be consistent with the terms of the Contract, national and local laws and international conventions. While the intent of this section is to provide guidelines and requirements to decommission the onshore and offshore installation as a total, the requirement for single or partial equipment/module/pipeline/well decommissioning which is to be conducted during the operation stage shall be at PETRONAS’ discretion on a case by case basis.

PMU, as the custodian and statutory manager of the national petroleum resources in Malaysia, is obligated to address the process of the decommissioning of all disused upstream installations that have ceased to accommodate oil and gas production or are at the end of their design life, consistent with the national laws and international conventions.

Contractor conducting upstream installation decommissioning, pursuant to their Contract, must comply with these requirements, which may be expanded or amended from time to time upon written notice by PETRONAS.

10.2 Decommissioning Philosophy and Requirement 10.2.1 PETRONAS’ Decommissioning Philosophy Contractor shall adopt PETRONAS’ Decommissioning Philosophy as follows: a) PETRONAS, as the statutory manager for petroleum resources and/or owner of petroleum facilities, is required to adhere to the standards and obligations committed to by the Government of Malaysia and will adopt measures consistent with established international rules and standards in addition to the national and local laws b) Disused upstream installations need to be decommissioned. The extent of the removal shall be decided on a case-by case decommissioning assessment, taking into account all factors, particularly the legitimate interests of other Contractor, users of the sea, the safety of navigation and the preservation of the marine environment 178

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OPERATIONS MANAGEMENT c) It is envisaged that each case-by-case decommissioning assessment shall entail consultations involving all interested parties 10.2.2 General Decommissioning Requirement All disused upstream installations are required to be fully decommissioned, except where non-removal or partial removal is consistent with the standards and requirements imposed by this section. In general, decommissioning of upstream installations shall be evaluated on a case-by-case basis. In line with Contractor’s obligation as stipulated in Volume 6, Section 1: Field Development Plan (FDP) Review and Approval Process, Contractor shall provide the decommissioning plan, which must include but not be limited to schedule, method (options) and cost estimates based on the end of the petroleum operations’ life or the field’s economic life.

The decommissioning work is driven by the following factors:

a)

Safe operation of upstream installations towards integrity and HSE The integrity of upstream installations must be regularly assessed in line with Volume 7, Section 3: Facilities Reliability and Integrity Management. In the event that the integrity assessment falls below the integrity safe limit, poses serious risk to HSE and is beyond repair, Contractor may consider the upstream installations to be decommissioned.

b)

End of field economic life The field review can be conducted through a Full Field Review (FFR), Depletion Studies or Subsurface Review. The field review must be completed three (3) to five (5) years prior to the projected date the field’s production level is expected to decline or drop below Contractor’s forecasted economic region (case-by-case basis). The decision to decommission the field will be based on the field review and in cases where the field can no longer produce and/ or be redeveloped commercially using the current facilities and existing or new technology (including Enhanced Oil Recovery (EOR)).

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OPERATIONS MANAGEMENT The field review shall include but not limited to the following: • • •

Re-interpretation of the current seismic data. Study of redevelopment opportunities using Improved Oil Recovery (IOR) techniques Screening study for EOR opportunities and techniques.

The outcome of the field review shall be submitted to PETRONAS and the decision to decommission any field will be subjected to PETRONAS’ approval.

c)

Legislative requirements Refer to Section 10.3: Legal Framework below.

The general approval process for the decommissioning of upstream installations is shown in Appendix 8.1.

10.3 Legal Framework 10.3.1 General The following legislation and standards shall be referred to in the implementation of the various decommissioning options for disused upstream installations within Malaysia. At present, the government has not promulgated any specific decommissioning regulations for the oil and gas industry. There are however, enabling provisions in several Acts which allow the government to promulgate any decommissioning regulations as it deems fit.

These are:

a)

The Merchant Shipping Ordinance, 1952 - Section 485A. Power to make regulations relating to offshore industry structures. Notwithstanding anything contained in this Act, the Minister may make regulations for the purpose of ensuring the safety of and control over offshore industry structures, offshore industry mobile units and offshore industry vessels.

b)

The Continental Shelf Act, 1966 (Revised 1972) - Section 16.6. Regulations (1) The Yang di Pertuan Agong may make regulations for: Providing for the removal of installations or devices constructed,

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erected or placed in, on or above the continental shelf which have been abandoned or become disused.

c) Exclusive Economic Zone Act, 1984 • Section 21: Prohibition of construction, operation or use of artificial island, except with authorisation. - No person shall construct, operate or use any artificial island, installation or structure in the Exclusive Economic Zone or on the continental shelf except with the authorisation of the government and subject to such conditions as it may impose • Section 22: the consent of the government is necessary for delineating the course for laying of submarine cables and pipelines. - No person shall lay submarine cables or pipelines in the exclusive economic zone or on the continental shelf without the consent of the government as to the delineation of the course for the laying of such cables and pipelines - Without prejudice to the above, the government may impose such conditions as it may consider necessary for the laying or maintenance of such cables and pipelines in the exercise of its right to take reasonable measures for the exploration of the continental shelf, the exploitation of natural resources and the prevention, reduction and control of pollution from such cables or pipelines • Section 23: Duty of the owner of a submarine cable or pipeline. - The owner of any submarine cable or pipeline which has fallen into disuse or is beyond repair shall forthwith inform the government and must, if so directed by the government, remove such cable or pipeline within such a period of time as the Government may direct • Section 41: Power to make regulations. - The Yang di-Pertuan Agong may make regulations for carrying out the provisions of this Act 10.3.2 Environmental Potential environmental pollution arising from the decommissioning process has always been a critical dimension to consider. The relevant legislative acts to consider are as follows:

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OPERATIONS MANAGEMENT a) Exclusive Economic Zone Act 1984 • Section 2: Interpretation • Section 10: Offence in respect of the discharge or escape of certain substances b) Environmental Quality Act, 1974 • Section 27: Prohibition of discharge of oil into Malaysian waters • Section 29: Prohibition of discharge of wastes into Malaysian waters c) Environmental Quality (Prescribed Activities Environmental Impact Assessment) Order 1987 - Item 12. Petroleum d) “Environmental Impact Assessment Guidelines for Petroleum Industries”: an administrative guideline issued in 1997 by Department of Environment, Ministry of Science, Technology & Environment, Malaysia 10.3.3 International Obligations Malaysia is a party to the following international instruments and, therefore, it is obligated to uphold the decommissioning standards and requirements under those international instruments: a) United Nations Convention on the Law of the Sea (UNCLOS), 1982 Article 60(3) b) International Maritime Organization (IMO) Guidelines & Standards, 1989 c) International Convention for the Prevention of Pollution from Ships, 1973 and the modifying Protocol, 1978 (MARPOL 73/78) d) ASEAN Council on Petroleum (ASCOPE) Decommissioning Guideline

Notwithstanding to the above, Contractor shall adhere to this section as the requirement for decommissioning activities.

10.4. Pre-decommissioning Process

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A Decommissioning Options Assessment (for example, Best Practicable Environmental Option Assessment (BPEOA)) shall be conducted to evaluate potential decommissioning options, taking into consideration the strategies, environmental, safety and cost elements. In addition to that, the options recommended shall not pose any undue risk to human life, environment, existing asset and reputation.

The selection of the options above will be evaluated on a case-by-case basis. Contractor shall present their Decommissioning Options Assessment to PETRONAS for approval. The Decommissioning Options Assessment PPGUA/3.0/042/2013

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proposal shall include but not limited to:

a) b) c)

Removal options A relative ranking of the options based on its strengths and weaknesses The estimated cost and days for each option including the schedule for the recommended option

10.4.1 Establishment of Decommissioning Options Assessment Contractor shall forward Decommissioning Options Assessment for PETRONAS’ consideration, which shall include but not limited to: a) Onshore Installations • Production and Crude/Gas Terminal Topside & Substructure Total removal and reinstatement of land in this option the entire topside and substructure of production and crude/gas terminal above ground shall be totally removed and the land shall be reinstated. Total land reinstatement shall be subjected to local authorities’ requirement. •

Land Pipeline Land pipelines above ground must be totally removed while underground pipelines can be decommissioned either by leaving them in-situ or by total removal. However, the decommissioning of land pipelines may be subject to local authorities’ regulations and requirements.

•

Land Development Well Land development well decommissioning shall be conducted as per Volume 8: Drilling and Well Operations.

• Relocation/Reuse of any Onshore Installations Other than disposing their onshore installations as scrap, Contractor may consider either relocating or reusing them. Relocation means the installations are technically feasible to be used for oil and gas operations at a different location.

Reuse involves using the installations for other purposes than oil & gas.

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OPERATIONS MANAGEMENT For PETRONAS’ consideration of these options, Contractor shall: - identify immediate or future developments in the area that use similar types of facilities - investigate whether the existing facilities are suitable for continued use - estimate the duration and maintenance cost of the mothball period - prepare the system for minimum maintenance upon PETRONAS’ approval to proceed. There may be a request from government authorities or PETRONAS, other than these decommissioning options, as such, PMU shall inform Contractor accordingly and discuss the way forward. b) Offshore Installations • Offshore Platform Substructures - Total Removal In this option the entire offshore platform substructure above the seabed is removed. The substructure shall be disposed by taking it onshore where it can either be scrapped, relocated or reused. • Partial Removal Partial removal would leave the lower part of the substructure in place at a minimum of fifty-five (55) metres water clearance from mean low tide sea level or as specified by the local authorities. The top part of the substructure shall be disposed by taking it onshore where it can either be scrapped, relocated or reused. • Topple in Place The substructure is toppled into the seabed at a minimum of fifty-five (55) metres water clearance from mean low tide sea level or as specified by local authorities. •

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Artificial Reef Depending on the local authorities’ requirements, the substructures could either be toppled in place or relocated to designated sites to create artificial reefs.

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OPERATIONS MANAGEMENT c) Offshore Platform Topsides • Total Removal The topsides shall be disposed by taking them onshore where they can either be scrapped, relocated or reused. •

Offshore Pipeline Depending of the local authorities’ requirements, offshore pipelines can be decommissioned either by leaving them in-situ or by total removal.

•

Offshore Development Well Offshore decommissioning for shallow and deep water development wells shall be conducted as per Volume 8: Drilling and Well Operations.

•

Marine Facilities The decommissioning and removal of marine facilities which are owned by PETRONAS shall be decided by PETRONAS in line with the findings of the Decommissioning Options Assessment. The leased marine facilities shall be decommissioned as specified in the leasing contracts.

•

Relocation/Reuse of any Offshore Installations Other than disposing their disused offshore installations as scrap or converting them into artificial reefs, Contractor may consider either relocating or reusing them.

Relocation means that the installations are technically feasible to be used for oil and gas operations at a different location.

Reusing involves disused installations being used for other purposes other than oil and gas.

For PETRONAS’ consideration of these options, Contractor shall: - identify immediate or future developments in the area that could use similar types of facilities; - investigate whether the existing facilities are suitable for continued use - estimate the duration and maintenance cost of the mothball period - prepare the system for minimum maintenance; upon PPGUA/3.0/042/2013

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PETRONAS’ approval to proceed.

There may be a request from government authorities or PETRONAS, other than these decommissioning options, as such, PETRONAS shall inform Contractor accordingly and discuss the way forward.

10.4.2 Decommissioning Plan A decommissioning plan deals with the overall decommissioning strategy and plan of disused upstream installations. Refer to Appendix 8.2 for the requirements to be included in the decommissioning plan where the precise content of a decommissioning plan may vary according to the circumstances. Contractor is only required to submit one (1) decommissioning plan per campaign that may involve decommissioning of topsides, substructures, pipelines, wells and marine facilities together. Contractor must submit the decommissioning plan to PETRONAS for approval at least twelve (12) months prior to the decommissioning activities. 10.4.3 HSE Requirement Health HSE considerations for each decommissioning option will vary to be consistent with the Decommissioning Options Assessment taking into account human life, environment, asset and reputation. While the approved decommissioning option must not pose any adverse impact to the environment, it is required to properly balance the considerations of environmental protection, safety and cost. An Environmental Management Plan (EMP) together with the comparative environmental risks associated with different decommissioning alternatives will be required for submission to PETRONAS for review and approval six (6) months prior to the decommissioning activities. In the case where an Environmental Impact Assessment (EIA) is applicable, the EMP needs to be consistent with the EIA requirements.

The EMP shall cover but not limited to:

a) b) 186

Pre-decommissioning activities covering baseline studies, chemical and waste inventory and pollution control Decommissioning activities covering environmental aspects and any significant impact of platform decommissioning and mitigation measures to be taken during platform removal, transport and disposal to minimise health, safety and environmental impact

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OPERATIONS MANAGEMENT c) Post-decommissioning activities covering the monitoring of the impact/effects on the marine environment and ecosystem, navigation and other users of the sea

The risk assessment must be conducted to cover the safety, health and social aspects of the proposed decommissioning proposal for submission to PETRONAS. It should include but not limited to:

a) Identification of hazard potential issues consequential impacts of the option selected b) Measures to reduce risks to As Low As Practicable (ALARP)

and

the

Reasonably

10.4.4

Consultation and Liaison An integral part of the decommissioning plan is to demonstrate the industry’s high level of environmental awareness and ability to be proactive. In the event that a public consultation process becomes necessary in certain cases, Contractor may be required to assist PETRONAS to initiate and manage the dialogue process to obtain the community and stakeholders’ views and concerns.

Decommissioning may also require notification to/approval from the local authorities, before proceeding with any activities. As such, PETRONAS together with Contractor are required to liaise accordingly with those relevant local authorities to notify and/or obtain necessary approval.

The various departments include but not limited to:

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OPERATIONS MANAGEMENT DEPARTMENT

CONSULTATION AND LIAISON ON

Department of Environment

Protection and preservation of the marine environment

Federal Marine Department

Safety of navigation, search and rescue and other maritime services

Maritime Enforcement Coordination Centre

Coordination of the enforcement of maritime activities in Malaysian waters

Department Of Fisheries

Fishing industry, marine parks and reserves, including coral reefs and artificial reefs, enforcement on fishing activities

Inland Revenue

Taxation

Royal Customs

Excise duty

Attorney General’s Office

Legal aspects of maritime affairs

Local Authorities

Disposal and potential use of platforms on land

Department of Safety and Occupational Health

Policies and legislations of occupational safety and health

10.4.5 Incorporation in Work, Programme and Budget (WPB) As soon as PETRONAS approves the decommissioning plan, Contractor shall provide budget provisions for the decommissioning activities as part of the immediate forthcoming WPB. The detailed information required must be consistent with the pre-budget guidelines. Decommissioning activities shall only commence after PETRONAS approves the decommissioning WPB.

10.5 Decommissioning Execution 10.5.1 Project Execution Plan A Decommissioning Project Execution Plan (PEP) needs to be submitted to PETRONAS for review at least one (1) month prior to execution. In the event of any deviation from the approved Decommissioning Plan, Contractor shall seek PETRONAS’ approval for execution. Refer to Appendix 8.3 for table of content. a) Onshore Installation • Production and Crude/Gas Terminal Topside & Substructure Total Removal and Reinstatement of Land The integrity of the topside and substructure of the production and crude/gas terminal shall be reassessed prior to decommissioning to ensure safe

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OPERATIONS MANAGEMENT decommissioning activities. The entire topside and substructure of a production and crude/gas terminal above ground, must be totally removed. Contractor must ensure that the piles are cut at a minimum two (2) metres below the ground or as specified by standard regulation and the land reinstated back to its original condition. Total land reinstatement shall be subjected to the relevant local authorities’ requirements. • Land Pipeline Above ground land pipelines must be totally removed whereas underground pipelines can be decommissioned by either leaving them in-situ or by total removal. Land pipeline decommissioning work involves flushing and cleaning to meet regulatory requirements Pipelines, which are to be left in-situ, shall be flushed, cut and plugged at both ends at a minimum of two (2) metres underground. However, land pipelines decommissioning may be subjected to local authorities’ regulation and requirement. • Land Development Well Land development well decommissioning shall be conducted as per Volume 8: Drilling and Well Operations. •

Relocate/Reuse of any Onshore Installations Other than disposing of onshore installations as scrap, Contractor may consider either relocating or reusing them. However, relocation is only an option if it is technically feasible to use the installations in oil and gas operations at a different location.

Reusing involves the usage of the onshore installations for purposes other than oil and gas. For PETRONAS’ consideration of these options, Contractor shall: - identify immediate or future developments in the area that can use similar facilities; - investigate whether the existing facilities are suitable for continued use - estimate the duration and maintenance cost of the mothball period PPGUA/3.0/042/2013

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OPERATIONS MANAGEMENT - prepare the system for minimum maintenance; upon PETRONAS’ approval to proceed There may be a request from government authorities or PETRONAS, other than these decommissioning options, as such, PETRONAS shall inform Contractor accordingly and discuss the way forward. b) Offshore Installation • Offshore Platform Substructures The integrity of offshore platform substructures shall be reassessed prior to decommissioning to ensure safe decommissioning activities. The International Maritime Organization (IMO) Guidelines and Standards for the Removal of Offshore Installations and structures on the Continental Shelf and in the Exclusive Economic Zone, adopted by IMO’s Resolution A.672 (16), sets out the minimum global standards to be applied for the removal of offshore platform substructures. In general, the applicable means are: - Total Removal This is achieved by lifting/floating the substructure after the piles have been cut. The cut must be made at a minimum of one (1) metre below the mud line subject to the cutting method used and seabed conditions such as the siltation rate, erosion rate and type of soil. The substructure must be disposed by taking it onshore where it can either be scrapped, relocated or reused. - Partial Removal Partial removal would leave the lower part of the substructure in place allowing a minimum of fifty-five (55) metres water clearance from the mean low tide sea level or as specified by local authorities. The top part of substructure must be disposed by taking it onshore where it can either be scrapped, relocated or reused. - Topple in Place The substructure is toppled to the seabed at its piled location giving a minimum of fifty-five (55) metres water clearance from the mean low tide sea level or as specified by local authorities. 190

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OPERATIONS MANAGEMENT - Artificial Reef Artificial reef options depend authorities’ requirements.

on

the

local

The substructures can either be toppled in place or relocated to a designated site to create an artificial reef. There are various factors to be considered such as: - the potential enhancement for fisheries, - the usefulness of the platform, - the environmental impact and effect to other users of the sea.

If the platform is located in an ideal reef site, the topple-in-place option is often the best provided the water depth at the site is sufficient to provide navigational clearance of fifty-five (55) metres or as specified by local authorities.

For this artificial reef option, PETRONAS and Contractor must liaise with the relevant local authorities when choosing this removal option. • Offshore Platform Topside Contractor is required to comply with Section 3.13 upon cessation of production. In addition, Contractor must obtain prior approval from PETRONAS for the removal of any components from the facilities until decommissioning has been completed.

Decommissioning activities shall only be carried out after the platform has been totally shutdown, cleared of all hazardous materials and certified safe for decommissioning to proceed.

The scope of the decommissioning requirements should cover at least the four (4) principal categories of all production and utilities systems topside namely: - Hydrocarbon systems All separators, process vessels and piping shall be purged and flushed. Residual hydrocarbons shall be collected and disposed at a certified PPGUA/3.0/042/2013

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OPERATIONS MANAGEMENT onshore disposal site/agency. Radioactive materials must be handled according to Atomic Energy Licensing Board (AELB) guidelines. - Non-hazardous systems Cooling water, firewater, utility air and instruments need to be de-pressurised, flushed, drained and isolated. - Toxic and hazardous chemical systems Toxic and hazardous materials must be removed. The system has to be purged, flushed and detoxified. Any discharge of cleaning effluent must satisfy applicable regulations. - Electrical power systems Decommissioning of electrical systems is a planned sequenced shutdown of all motor control centers, switchgear and generators according to proper safety procedures. Upon completion of all decommissioning work, the topside must be rendered safe for hot work via a Permit To Work (PTW) system. The issuance of a safe certificate for hot work must be strictly enforced. The integrity of the structures has to be verified prior to any cutting, removal, lifting/floatation and transportation of any package or modules. The center of gravity of the topsides loads have to be established. •

Offshore Pipeline Depending on government authorities’ requirement, offshore pipelines can be decommissioned either by leaving them in-situ or by total removal. Pipeline decommissioning work involves flushing and cleaning to meet regulatory requirements. Pipelines that are left in-situ shall be flushed, cut and plugged, with their ends buried at minimum of one (1) metre below the mud line.

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Based on industrial best practices, the risers, tube turns and a minimum of one hundred and fifty (150) metres of the pipeline section from the base of the substructure must be totally removed. The removal can be concurrent with substructure removal where applicable.

Where appropriate, special measures and considerations need to be taken for decommissioning ‘hot tap’ or other special pipeline-to-pipeline connections. This reduces the risk and exposure of the remaining section of pipeline. Before executing total pipeline removal, Contractor must consult the relevant local authorities on method and disposal options.

• Offshore Development Well Offshore development well decommissioning shall be conducted as per Volume 8: Drilling and Well Operations. • Marine Facilities The decommissioning and removal of marine facilities owned by PETRONAS shall be decided by PETRONAS in line with the findings of the Decommissioning Options Assessment. The leased marine facilities shall be decommissioned as specified in the leasing contracts. • Relocation/Reuse of any Offshore Installations Other than disposal as scrap or an artificial reef, Contractor may consider either relocating or reusing the decommissioned installations. Relocation is viable when the installations are technically feasible to use in oil and gas operations at a different location. Reusing involves putting the decommissioned installations to use for other than oil and gas purposes. Contractor seeking PETRONAS’ consideration for relocation or reuse must: - identify the immediate or future developments in the area that can use similar types of facilities - investigate whether the existing facilities are suitable PPGUA/3.0/042/2013

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OPERATIONS MANAGEMENT for continued use - estimate the duration and maintenance cost of the mothball period - prepare the system for minimum maintenance upon PETRONAS’ approval to proceed.

Other than Contractor, there may be request from external parties or PETRONAS to choose one of these options. In such cases, PETRONAS will inform Contractor accordingly to discuss the way forward.

10.6 Post Decommissioning Process 10.6.1 Removal of Debris and Land/Seabed Clearance Upon completion of all decommissioning activities, the land/seabed in the upstream installation vicinity must be cleared of all debris that has to be properly disposed according to legislative requirements. For partial removal or in-situ toppling, the remaining structures must be surveyed and their positions recorded. This information should be submitted to PETRONAS and/or the relevant local authorities.

Contractor is required to check the specified area and remove any debris located within its footprint and the vicinity of the upstream installation (gazette area). Contractor must verify that the site is clear after decommissioning by appropriate methods such as an underwater diver’s survey, trawling in two (2) directions across the location or any other suitable method.

10.6.2 Verification Contractor must verify that the area has been cleared of all obstructions and debris. They are required to run side-scan sonar or bottom-scan sonar or any other suitable method, across the location to ensure that there is no debris cluttering the specified area. Where practicable, Contractor shall also visually record the cleared site area as evidence.

Contractor must conduct the survey immediately after the completion of decommissioning work. Contractor shall submit the detail survey report and certification to PETRONAS in writing. The report must include, but not limited to the following:

a) Extent of the area surveyed, (as per gazette) or specified otherwise by PETRONAS b) Survey method used 194

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OPERATIONS MANAGEMENT c) d)

Original Survey Report by the Surveyor Original third party Certification. PETRONAS and Contractor shall mutually agree on the selection of third party Certifier and Surveyor

10.6.3 Post Environmental Assessment Contractor must conduct the Post Environmental Assessment within three (3) months from the date of completion of decommissioning work to ensure that there is no adverse impact on the surrounding marine and land environment. This assessment shall be consistent with the Post Decommissioning Environmental Assessment Plan as per the approved PEP.

After completion of the Post Environmental Assessment, the findings must be submitted or presented to PETRONAS and the relevant authorities. Upon acceptance of the Post Environmental Assessment, Contractor must close out any action item(s) if required.

10.6.4 Disposal Contractor shall comply with the approved PEP and PETRONAS’ Upstream Surplus Material Management (USMM). Contractor shall manage disposal until completion and submit the close out report.

10.7 Report

During the execution of the decommissioning stage, Contractor is required to regularly update PETRONAS on the project’s progress.

Upon completion of decommissioning activities, Contractor must also submit to PETRONAS the Final Closeout Report no later than six (6) months after completion of decommissioning work. The report must cover all pre-decommissioning, decommissioning and post decommissioning activities. Refer to Appendix 8.4 for the Table Of Content. Hard and soft copies of the report must be submitted.

10.8 De-gazetting and Admiralty Chart

Contractor must submit to PETRONAS, an application to de-gazette and update the admiralty chart of the decommissioned upstream installation and its relevant area within one (1) month after the submission of the Final Closeut Report.

10.9 Residual Liability

Pending the issuance of a National Policy on the Restoration of Oil and Gas Fields, any residual liability of all disused upstream installations shall be decided by PETRONAS, in consultation with the relevant government authorities. PPGUA/3.0/042/2013

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OPERATIONS MANAGEMENT 10.10 Contractor’s Obligations during Handover

If Contractor is to relinquish field(s) to PETRONAS, they must provide the following information to the extent that such information is in the Contractor’s possession in addition to any other information stipulated by the Contract, which is required for decommissioning planning:

a) Estimated remaining field life at hand-over date b) Operating costs for at least three (3) years preceding the hand-over date c) Statement on wells abandonment experience for the field d) Recommended method for abandonment of remaining wells e) Topside inventory and their remaining life where appropriate f ) Underwater survey/inspection data/information for the year of handover and all the previous inspection years g) All as-built drawings, operating manuals and design documentation h) Engineering evaluation of inspection and repair history for the substructure i ) The status and composition of the drill cutting pile where applicable j ) Report on any settlement and soil properties up to five (5) metres below the seabed (consistent with EIA requirements) k) Structural integrity assessment supported by appropriate structural analyses l ) Recommendation for future use of the redundant installations m) Estimated cost(s) for decommissioning based on recommended option(s) n) Latest report on anomalies and shallow gas within the vicinity of the installation

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All the handover processes shall be consistent with Section 9: Asset Relinquishment in this volume.

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OPERATIONS MANAGEMENT Section 11: Operating Performance Improvement 11.1 Introduction

Operating Performance Improvement is a continuous process of optimising the producing assets’ potential and as such deliver the highest level of production. This section provides Contractor with guidelines for performance management and the explanation of various terminologies relating to the conduct of performance management. It is important that Contractor understands the detail explanation of the terminologies and its methodology and ensure that the required reporting being executed with integrity and clarity.

PETRONAS aspires for Contractor to drive operational excellence in the upstream activities. Contractor may, at its own effort or upon instructed by PETRONAS, conduct improvement initiatives on specific activities (i.e. production operations or projects) or lessons learned from an incident, in the event that performance of the activities is below than expected.

11.2 Performance Management

This section defines the KPI, reporting requirements and meeting frequency in addressing Contractor’s performance.

11.2.1

Key Performance Indicators (KPI) There are five (5) measurements used to benchmark Contractor’s operational management performance in Malaysian upstream environment, as follows: KPI

UNIT OF MEASUREMENT

Overall Equipment Effectiveness (OEE)

%

Utilisation

%

Gas Delivery Reliability (GDR)

%

Unit Production Cost (UPC)

RM/boe

P1 Action Items

numbers

a)

Overall Equipment Effectiveness (OEE) OEE is a key performance indicator that measures the efficiency of the producing platform facilities to deliver production as planned. It provides a standard methodology to measure and benchmark platform and field performance.

OEE calculation is as follows: PPGUA/3.0/042/2013

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OPERATIONS MANAGEMENT Oil OEE: Reconciled Production (excluding idle wells’ production)

(Oil Technical Availability)

Gas OEE: Reconciled Sales Gas (Gas Technical Availability)

x 100%

x 100%

Refer to Appendix 9 for both oil and gas OEE models and the associated terms & definitions.

• Special considerations for prolonged subsurface issues Wells that are only affected by subsurface issues which have been prolonged for a period of three (3) consecutive months shall be allowed to revise their Technical Potential (TP) calculation when executing the calculation for the subsequent months. However such revision shall be subjected to the reservoir or petroleum engineers’ acceptance. An illustration of the mechanism for TP revision is as in Figure 2 below: Figure 2: Illustration of OEE Reporting for prolonged subsurface issues

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OPERATIONS MANAGEMENT TP1, TP2, TPX: Technical Potential for the month as defined in the Quarterly Capacity Review

X1, X2, XX

: Well deferment due to subsurface issues (kb/d)

With assumption that the subsurface issues occurred at Quarter 1 and extended above 90 days until Quarter 3: - For April reporting, OEE shall be based on TP4 - For May reporting, OEE shall be based on TP5–X5 - For Jun reporting, OEE shall be based on TP6 (if the subsurface issue is resolved in May)

After three (3) months of a prolonged subsurface issue, Contractor must submit an additional copy of the Operating Performance Report (OPR) for OEE reporting based on the revised TP, as demonstrated by Figure 2: (Illustration of OEE Reporting for prolonged subsurface issues).

• Special considerations for surface facilities constraint In cases where a platform’s surface facilities constraint is present, the forecasted technical potential must assume the maximum allowable production that the facilities’ were designed for. b) Utilisation Utilisation is a key performance indicator that compares actual production against technical potential to gauge production effectiveness.

The utilisation calculation is as follows:

Reconciled Production (excluding idle wells’ production) x 100% Technical Potential

Refer to Appendix 9 for associated terms & definitions.

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OPERATIONS MANAGEMENT c)

Gas Delivery Reliability (GDR) GDR is a key performance indicator that measures Contractor’s ability to meet gas nomination. There are two (2) measurements of GDR : GDR (days): the percentage of days meeting 95% of daily nomination in one particular month; number of days meeting 95% of daily nomination in the month

x 100%

number of days in the month GDR (vol.): the percentage of monthly average sales gas over monthly average sales gas nomination in one particular month; monthly average sales gas montlhy average sales gas nomination

•

x 100%

Special considerations for planned shutdown In event of a planned shutdown, whenever there is zero nomination or downstream issues that are affecting upstream production, the respective number of days shall therefore be excluded from the number of days calculated or that particular month

d)

Unit Production Cost (UPC) UPC is defined as the cost incurred to produce, process and transport one barrel of oil or the equivalent of sellable hydrocarbon products.

The UPC (RM/boe) calculation is as follows: Total production OPEX (RM) Total production (boe)

x 100%

Total production is inclusive of total liquid (oil and condensate) and total gas sales.

e)

Priority 1 (P1) Action Item A P1 Action Item is defined as action items that may impact the organisation against HSE, image and economic consequences if the items are not effectively reported and attended to.

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Classification of P1 follows the following : Figure 3: Risk Matrix

This matrix serves as a guideline to Contractor in determining P1 Action Items. Any Contractor who has already established its own risk matrix shall map it to this matrix for standardisation and report the outstanding P1 action items to PETRONAS accordingly. Additionally, outstanding P1 action items whose risks have been mitigated and fall into P2 still need to be reported until completion.

Note that P2 and P3 action items might change to P1 status if they are left unattended. Contractor is therefore expected to execute P2 and P3 action items as well as the P1 action items.

11.2.2 Performance Reporting Contractor must submit the following reports to PETRONAS :

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OPERATIONS MANAGEMENT REPORT Operating Performance Report

CONTENT a) b) c) d) e) f) g) h)

FREQUENCY

TP Actual Production Unplanned Deferment Planned Deferment OEE Utilisation GDR UPC

Monthly (no later than 16th of the following month)

Outstanding P1 Action Items Report

Status of outstanding P1 action items Monthly (no later (including action items which risk have than 16th of the been mitigated and fall into P2), stating following month) how long the items have been overdue: a) Less than 3 months b) More than 3 months c) More than 6 months d) More than 9 months

Bad Actor Initiatives Update

Status updates for each initiative/action item.

Quarterly (no later than 16th in the first month of following quarter)

11.2.3 Management Meeting All Contractor of producing fields is required to attend regular performance management meetings with PETRONAS as follows: MEETING

ATTENDEES

Quarterly

Head of Contractor

PSC-OPI Meeting

Review Malaysia production performance and track gap closure initiatives

Quarterly

PETRONAS OPI and Contractor’s Focal Point

Bad Actor Management Bad Actor Management is a process of managing fields which are consistently low in OEE performance as such to overcome their challenges and shortfalls and improve their performance.

11.3.1

202

FREQUENCY

Drive domestic upstream OPI activities across all producing Contractor towards operational excellence

11.3

OBJECTIVE

Upstream Working Group Meeting (UWGM)

Identification of Bad Actor field At the end of every year, bad actor fields will be identified. A field is identified as a Bad Actor when it meets the following criteria:

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OPERATIONS MANAGEMENT TYPE OF FIELD

BAD ACTOR CRITERIA

Oil

a) Field’s WPB target is more than 5 kb/d b) Field’s annual average OEE is below 90% c) Field is not affected by cascaded deferment due to interruption at other facilities within Contractor’s operatorship

Gas

a) Field’s WPB target is more than 10% of total Contractor’s gas target b) Field’s annual average OEE is below 90% c) Field is not affected by cascaded deferment due to interruption at other facilities within Contractor’s operatorship

11.3.2 Action Item for Bad Actor field Upon identification of Bad Actor field, Contractor should submit to PETRONAS the following, by the end of February of each year: a) Root Cause Problem Solving (RCPS) report for the field performance b) Action Items/Initiatives to resolve issues affecting field’s OEE

Progress of the action items/initiatives are to be reported to PETRONAS on a quarterly basis as mentioned in Section 11.2.2.

11.3.3 Criteria to Graduate A field is considered out of Bad Actor list when it meets following criteria: TYPE OF FIELD

GRADUATION CRITERIA

Oil

Monthly OEE is 90% or above for 6 consecutive months; or field’s annual average OEE is more than 90%

Gas

Monthly OEE is 90% or above for 6 consecutive months; or field’s annual average OEE is more than 90%

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OPERATIONS MANAGEMENT Abbreviations TERM

IN FULL

°C

degrees Celcius

°F

degrees Fahrenheit

B

Beta

Ω

Ohm

AC

Alternating Current

A/D

Analogue to Digital

AG

Associated Gas

AELB

Atomic Energy Licensing Board

AGA

American Gas Association

AL

Artificial Lift

ALARP

As Low as Reasonably Practicable

ALIR

‘Flow’ in English

Amd

Amendment

ANSI

American National Standards Institute

ASME

American Society of Mechanical Engineers

API

American Petroleum Institute

ASTM

American Society for Testing and Materials

ASD

Airport Standard Directives

ASCOPE

ASEAN Council on Petroleum

BIPM

Bureau International des Poids et Mesures

BS

British Standards

BS&W

Base Sediment and Water

BPEOA

Best Practicable Environmental Option Assessment

CAPEX

Capital Expenditure

CP

Cathodic Protection

CTL

Correction for the Effect of Temperature on Liquid

CPL

Correction for the Effect of Pressure on Liquid

CTS

Correction for the Effect of Temperature on Steel

CPS

Correction for the Effect of Pressure on Steel

CO2

Carbon Dioxide

204

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IN FULL

CR

Capacity Review

CUI

Corrosion Under Insulation

CTLm

Correction for the Effect of Temperature on Liquid in Meter

CPLm

Correction for the Effect of Pressure on Liquid in Meter

CTLp

Correction for the Effect of Temperature on Liquid in Prover

CPLp

Correction for the Effect of Pressure on Liquid in Prover

CTSp

Correction for the Effect of Temperature on Steel Prover

CPSp

Correction for the Effect of Pressure on Steel Prover

DC

Direct Current

DCA

Department of Civil Aviation

DDA

Due Diligence Audit

DD

Drawdown

DIFFS

Deck Integrated Fire Fighting System

DP

Differential Pressure

E/F

English/French

EI

Energy Institute

EIA

Environmental Impact Assessment

ECR

Enhanced Capacity Review

EN

European Standard

EUR

Estimated Ultimate Recovery

EMP

Environmental Management Plan

EOR

Enhanced Oil Recovery

FAC

Facilities

FAT

Factory Acceptance Test

FDP

Field Development Plan

FFR

Full Field Reviews

FFS

Fitness For Service

FIP

Facilities Improvement Plan

FPSO

Floating Production, Storage and Offloading

FRMR

Field Reservoir Management Review

FRW

Field Review Workshop

FRP

Facilities Rejuvenation Plan

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206

IN FULL

FSO

Floating Storage and Offloading

FWAP

Flow Weighted Average Pressure

FWAT

Flow Weighted Average Temperature

GDR

Gas Delivery Reliability

GHV

Gross Heating Value

GOR

Gas-Oil-Ratio

GSA

Gas Sales Agreement

HART

Highway Addressable Remote Transducer

HIPPS

High-Integrity Pressure Protection system

HM

Hydrocarbon Measurement

HSE

Health, Safety and Environment

ICT

Information and Communication Technology

IEC

International Electrotechnical Commission

IMO

International Maritime Organization

IP

Institute of Petroleum

IOR

Improved Oil Recovery

ISA

Instrument Society of America

ISO

International Organization for Standardization

JAKIM

Jabatan Kemajuan Islam Malaysia

JCGM

Joint Committee for Guides in Metrology

kg/m3

kilogrammes per cubic metre

kPa

kilopascals

KPI

Key Performance Indicator

LIMIT

Facilities Limit

LOS

Limited Obstacle Sector

LSA

Life Saving Appliance

LOS

Limited Obstacle Sector

mA

milliamperes

MAOP

Maximum Allowable Operating Pressure

MARPOL

International Convention for Prevention of Pollution from Ships

MECH

Mechanical

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IN FULL

MES

Minimum Environmental Specifications

MJ/kg

megajoules per kilogramme

MODU

Mobile Offshore Drilling Unit

MOPU

Mobile Offshore Production Unit

MPMS

Manual of Petroleum Measurement Standards

MSL

Mean Sea Level

NAG

Non-Associated Gas

NEC

National Electrical Code

NDP

National Depletion Policy

NDT

Non-Destructive Test

NIST

National Institute of Standards and Technology

NML

National Metrology Laboratory

ns

nanoseconds

OEE

Overall Equipment Effectiveness

OEM

Original Equipment Manufacturer

OFS

Obstacle Free Sector

OPEX

Operating Expenditure

OPNS

Operations

OPR

Operating Performance Report

OSR-MS

Offshore Self-Regulation Management System

P1

Priority 1

PBU

Pressure Build Up

PEP

Project Execution Plan

PGBOOM

PETRONAS Guidelines for Barges Operating Offshore Malaysia

PLEM

Pipeline End Manifold

PLET

Pipeline End Termination

PIPeM

Pipeline Integrity Performance Monitoring

P&ID

Piping and Instrumentation Diagram

PLT

Production Logging Tool

PMM

Petroleum Measurement Manual

PMU

Petroleum Management Unit

POM

Petroleum Operations Management

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208

IN FULL

PRD

Petroleum Resource Development

PREX

Petroleum Resource Exploration

PSC

Production Sharing Contract

PTW

Permit To Work

PTS

PETRONAS Technical Standard

Q1

Quarter One (1)

Q2

Quarter Two (2)

PIMS

Pipeline Integrity Management System

RCFA

Root Cause Failure Analysis

RCPS

Root Cause Problem Solving

RES

Reservoir

RM

Reservoir Management

RMD

Remedial

RMP

Reservoir Management Plan

RSC

Risk Service Contract

ROV

Remote Operated Vehicle

ROT

Remote Operated Tool

RTD

Resistance Thermal Detector

SALM

Single Anchor Leg Mooring

SAT

Site Acceptance Test

SBHP

Static Bottom Hole Pressure

SBM

Single Buoy Mooring

SC

Steering Committee

SCSSSV

Surface-Controlled Subsurface Safety Valve

SI

International System of Units

SIRIM

Standards and Industrial Research Institute of Malaysia

SLBM

Single-Leg Buoy Mooring

SOLAS

Safety of Life at Sea

SPAR

Single Point Anchor Reservoir

TD/PM

Touchdown/Positioning Marking

TEMPSC

Totally Enclosed Motor Propelled Survival Craft

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IN FULL

TLP

Tension Leg Platform

TP

Technical Potential

UNCLOS

United Nations Convention on the Law of the Sea

UPC

Unit Production Cost

UR

Ultimate Recovery

USMM

Upstream Surplus Material Management

UWGM

Upstream Working Group Meeting

VIM

International Vocabulary of Metrology - Basic and General Concepts and Associated Terms

WC

Working Committee

WPB

Work Programme & Budget

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OPERATIONS MANAGEMENT Appendix 1 List of Technical Proposals which require PETRONAS’ Approval NO.

210

TECHNICAL PROPOSAL

DOCUMENT

PETRONAS APPROVAL AUTHORITIES/ TIMING

1

Any new wells not included in the approved FDP

a) FDP revision, or b) Notice of Operations

2

Any workover wells of the following objectives: a) Recomplete/deepen to new zone not developed, addressed in the FDP, b) Sidetrack new zone not developed, addressed in the FDP

a) FDP Revision b) Technical Proposal

3

Any wells intervention/workover with the following objectives: a) Recompletion/Adding perforation b) Thru-tubing reperforation c) Sidetrack existing zones d) Squeeze/plug job e) Sand control installation f) Mechanical repair g) Stimulation/fracturing h) Change in well utility i) Change of lift mechanism

Technical Proposal

POM, PMU/Two (2) weeks

4

FDP revision: a) Development of new reservoirs, wells, platform b) Appraisal of new area c) Changes to drainage plan i.e.: • Platforms • Wells • Type of completions d) Changes to development concept for example waterflood, gas injection, EOR, evacuation route, integrated development, FPSO. etc.

FDP Revision

PRD, PMU/One (1) month

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OPERATIONS MANAGEMENT NO.

TECHNICAL PROPOSAL

DOCUMENT

PETRONAS APPROVAL AUTHORITIES/ TIMING

5

Reservoir Management Plan Revisions: a) GOR limit revision/relaxation b) Gas/Water injection revision c) EOR application d) Production policy i.e.: • Offtake by well/reservoir • Commingle/decommingle zone e) Change in depletion strategy and well utility i.e.: • Oil’s producer to gas/water injection • Gas injection to gas producer

Technical Proposal

POM, PMU/One (1) Month

6

Facilities Improvement Plan (FIP) Revision/ Facilities Rejuvenation Plan (FRP): Any changes of: a) Objective b) Concept/Scheme c) Technology d) Operations & Maintenance Philosophy

FIP Revision

POM, PMU/One (1) Month

Notes: a) Other activities not listed above do not require PETRONAS’ technical approval. b) Contractor may apply for exception to the above approval timing i.e. when good opportunity arises with justification for PETRONAS’ approval. c) The PETRONAS’ approval timing is based on best endeavour basis and subject to issues being resolved.

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OPERATIONS MANAGEMENT Appendix 2 Idle String Classification and Definition IDLE STRING CLASSIFICATION

212

Effective idle

Capacity shut in from existing zones within current facilities handling constraints, with definitive short term action plans and economical to realize

Non-effective idle

Capacity shut in from existing zones which will not provide net production gain due to facilities constraint or reservoir

Depleted idle

Capacity shut in from existing zones in which the reserve is uneconomical to realize

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OPERATIONS MANAGEMENT IDLE STRING CODES DEFINITION Effective Idle

NonEffective Idle

Depleted

Mechanical (MECH)

Strings that are shut-in due to mechanical problems, i.e. the strings are waiting for christmas tree or down hole tubing/ completion servicing/repair (such as tubing patch, pull plug/ SCSSV problems, insert valve etc.)

Artificial Lift (AL)

Strings that are shut-in due to artificial lift equipment problems, while waiting on gas lift valve installation, gas lift valve or down hole pump repair

Facilities (FAC)

Strings that are shut-in due to facilities related problem. Includes strings that are waiting on surface facilities repair and planned upgrade or production/injection flow line (includes gas lift flow line)

Operation (OPNS)

Strings that are shut-in due to operational reasons i.e. emulsion, water quality problem, sand production, etc

Remedial (RMD)

Strings that are shut-in and require remedial work at perforation/ near wellbore zone for reactivation. Includes additional perforation job, stimulation, gravel packing, etc

Facilities Limit (LIMIT)

Strings that are shut-in due to facilities constraints, i.e. compressor, water handling limits, insufficient gas lift gas, platform allowable/offtake limit or not economic to revive

Reservoir Management (RM)

Strings that are shut-in due to reservoir management guidelines, i.e. GOR limit

Reservoir (RES)

Strings that have depleted in existing zone and have no behind casing potential

Ultimate Recovery (UR)

Strings that have depleted in existing zone and have behind casing potential (i.e. additional perforation, recompletion opportunities, etc.)

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OPERATIONS MANAGEMENT Appendix 3 List of KPIs for Facilities Reliability and Integrity KPI ELEMENT

DEFINITION

UNIT OF MEASURE

Compliance to overall planned maintenance

Number of PMs completed Number of PMs planned x 100%

%

Compliance of critical safety devices and systems preventive maintenance

Number of PMs completed x 100% Number of PMs planned

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OPERATIONS MANAGEMENT Appendix 4 Typical Liquid Hydrocarbon Metering System Figure 5: Typical Liquid Hydrocarbon Custody Transfer Metering System Schematic Diagram

4.1 Metering Data

The following metering data, including but not limited to, shall be made available and printed automatically or on demand:

4.1.1

Continuous Flow Measurement The metering data for continuous flow measurement should consist of Hourly Report, Sale Report and Production Report.

a) Hourly Report • date/time of report • gross/standard/net volume and mass (if applicable) start (cumulative) • gross/standard/net volume and mass (if applicable) finish (cumulative) PPGUA/3.0/042/2013

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OPERATIONS MANAGEMENT • gross/standard/net volume and mass (if applicable) (gross volume start – gross volume finish) • flow rate • Flow Weighted Average Temperature (FWAT) • Flow Weighted Average Pressure (FWAP) • density • calculated Correction for the Effect of Temperature on Liquid (CTL) • calculated Correction for the Effect of Temperature on Liquid (CPL) • base oil and water density settings • calculated water-cut b) Sale Report (for example 00:00 – 00:00) c) Production Report (for example 06:00 – 06:00)

216

4.1.2

Batch Measurement The metering data for batch measurement i.e. tanker loading should consist of Batch Start Report, Batch Hourly Report, Batch End Report and Meter Proving Record.

a) b) c)

Batch Start Report • batch number • batch start date/time • gross volume start (cumulative) • gross volume finish (cumulative) • gross volume (gross volume start – gross volume finish) • flow rate • meter factor • temperature • pressure • prover and meter runs settings and constants log Batch Hourly Report • batch number • report date/hour • gross volume start (cumulative) • gross volume finish (cumulative) • gross volume (gross volume start – gross volume finish) • flow rate • meter factor • temperature • pressure Batch End Report • batch number • batch start date/time

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OPERATIONS MANAGEMENT • batch end date/time • gross volume start (cumulative) • gross volume finish (cumulative) • gross volume (gross volume start – gross volume finish) • FWAT • FWAP • meter factor • calculated CTL • calculated CPL • standard volume d) Meter Proving Report • batch number • prover volume identification/volume • meter tag no. • proving start date/time • proving end date/time • trial run number • For each trial run: - volume flow rate - pulse count - flight time - density - line temperature - line pressure - prover temperature - prover pressure - Correction for the Effect of Temperature on Liquid in Meter (CTLm) - Correction for the Effect of Pressure on Liquidcin Meter (CPLm) - Correction for the Effect of Temperature on Liquid in Prover (CTLp) - Correction for the Effect of Pressure on Liquid in Prover (CPLp) - Correction for the Effect of Temperature on Steel Prover (CTSp) - Correction for the Effect of Pressure on Steel Prover (CPSp) - Meter Factor • every final average of five (5) consecutive trial runs resulting to successful meter proving: - volume flow rate - pulse count - flight time PPGUA/3.0/042/2013

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OPERATIONS MANAGEMENT - density - line temperature - line pressure - prover temperature - prover pressure - CTLm, CPLm, CTLp, CPLp, CTSp, CPSp - meter factor - meter factor repeatability % - previous in use meter factor - difference between the new and previous in use meter factor

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OPERATIONS MANAGEMENT 4.2 Figure 6: Typical Allocation Work Process Flow – Liquid Hydrocarbon STAGE

ROLES & RESPONSIBILITIES • Once the metering arrangement/ concept has been agreed by stakeholders and approved by PETRONAS • Term in commercial agreement i.e. GSA/UGSA finalised and agreed by all parties

Measurement Concept & Commercial Agreement Finalised

Independent

Independent or tie-in to existing network

Tie-in • To identify type of enhancement • For tie-in to the existing system, need to develop new MAP

• To develop new MAP or revamp the allocation concept to accommodate existing arrangement or tie-in

New Measurement Allocation Procedures (MAP)

Revamp Current Allocation Concept & Develop Detailed Algorithm

Develop Allocation Algorithm

Algorithm Cross Check & Acceptance Test

• Perform algorithm cross check and testing prior acceptance


Algorithm Manual/ Procedure Revision

• To revise current allocation manual/ procedure to accommodate the enhancement

Monthly Closing

• Closing meeting will be done within 30 day of following month end to finalise the production figures

th

Reporting

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OPERATIONS MANAGEMENT Appendix 5 Typical Gas Metering System Figure 7: Typical Gas Custody Transfer Metering System Schematic Diagram

5.1

Metering Data

The following metering data, including but not limited to, shall be made available and printed automatically or on demand:

5.1.1

Continuous Flow Measurement The metering data for continuous flow measurement should consist of Hourly Report, Sale Report and Production Report.

a) Hourly Report • date/time of report • gross/standard/net volume, ghv and mass (if applicable) start (cumulative) • gross/standard/net volume, ghv and mass (if applicable) 220

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OPERATIONS MANAGEMENT finish (cumulative) • gross/std/net volume, ghv and mass (if (gross volume start – gross volume finish) • flow rate • FWAT • FWAP • density b) Sale Report (for example 00:00 – 00:00) c) Production Report (for example 06:00 – 06:00)

applicable)

5.2 Figure 8: Typical Allocation Work Process Flow - Gas STAGE

ROLES & RESPONSIBILITIES • Once the metering arrangement/ concept has been agreed by stakeholders and approved by PETRONAS • Term in commercial agreement i.e. GSA/UGSA finalised and agreed by all parties

Measurement Concept & Commercial Agreement Finalised

Independent

Independent or tie-in to existing network

Tie-in • To identify type of enhancement • For tie-in to the existing system, need to develop new MAP

• To develop new MAP or revamp the allocation concept to accommodate existing arrangement or tie-in

New Measurement Allocation Procedures (MAP)

Revamp Current Allocation Concept & Develop Detailed Algorithm

Develop Allocation Algorithm


• Perform algorithm cross check and testing prior acceptance


Algorithm Manual/ Procedure Revision

• To revise current allocation manual/ procedure to accommodate the enhancement

Monthly Closing

• Closing meeting will be done within 30 day of following month end to finalise the production figures

th

Reporting

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OPERATIONS MANAGEMENT Appendix 6 Format of the 24 Hours’ Notification Report MAJOR UNSCHEDULED PRODUCTION SHUTDOWN INITIAL NOTIFICATION FORM TO

FROM

Senior General Manager, POM, PMU

Fax No.: 03 2331 2770

General Manager, Production Operations, POM, PMU

Fax No.: 03 2331 3168 / 69

Senior Manager, Production Operations, POM, PMU

Fax No.: 03 2331 3168

Contractor’s Operations Manager

Date of Report :

SHUTDOWN INCIDENT • Description of the incident

IMMEDIATE CAUSE OF SHUTDOWN • Description of failure/reason(s) of shutdown (preliminary findings acceptable)

IMPACT OF SHUTDOWN • Estimated volume of production impacted • Impact on flaring and re-injection (if applicable)

MITIGATION ACTION TAKEN & FORWARD PLANS • Immediate action taken • Estimated time for normalisation

CONTACT PERSON

* For immediate notification via sms/call, contact PMU Duty personnel at: 019-223 0979.

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OPERATIONS MANAGEMENT Appendix 7 Table 7A – Fire integrity of bulkheads separating adjacent spaces SPACES

(1)

(2)

(3)

(4)

(5)

(6)

(7)

(8)

(9)

(10)

(11)

Control Stations (1)

A-0 (c)

A-0

A-60

A-0

A-15

A-60

A-15

A-60 (d)

A-60

*

A-0

C

B-0

B-0 A-0 (b)

B-0

A-60

A-0

A-0 (d)

A-0

*

B-0

C

B-0 A-0 (b)

B-0

A-60

A-0

A-0 (d)

A-0

*

C

B-0 A-0 (b)

B-0 A-0 (b)

A-60

A-0

A-0 (d)

A-0

*

B-0 A-0 (b)

C

A-60

A-0

A-0

A-0

*

B-0

*(a)

A-0 (a)

A-60

A-60

*

A-0

A-0 (a) (d)

A-0

A-0

*

A-0

A-0

-

A-0

Service spaces (high risk) (9)

*

A-0

Open decks (10)

-

*

Corridors

(2)

Accommodation Spaces (3)

Stairways

(4)

Service spaces (low risk) (5) Machinery spaces of category

(6)

Other machinery spaces (7) Hazardous areas (8)

Sanitary and similar spaces (11)

C

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OPERATIONS MANAGEMENT Table 7B – Fire integrity of decks separating adjacent spaces SPACE ABOVE

(1)

(2)

(3)

(4)

(5)

(6)

(7)

(8)

(9)

(10)

(11)

A-0

A-0

A-0

A-0

A-0

A-60

A-0

A-0 (d)

A-0

*

A-0

Corridors (2)

A-0

*

*

A-0

*

A-60

A-0

A-0 (d)

A-0

*

*

Accommodation Spaces (3)

A-60

A-0

*

A-0

*

A-60

A-0

A-0 (d)

A-0

*

*

Stairways (4)

A-0

A-0

A-0

*

A-0

A-60

A-0

A-0 (d)

A-0

*

A-0

Service spaces (low risk) (5)

A-15

A-0

A-0

A-0

*

A-60

A-0

A-0

A-0

*

A-0

Machinery spaces of category (6)

A-60

A-60

A-60

A-60

A-60

*(a)

A-60

A-60

A-60

*

A-0

Other machinery spaces (7)

A-15

A-0

A-0

A-0

A-0

A-0 (a)

*(a)

A-0

A-0

*

A-0

Hazardous areas (8)

A-60 (d)

A-0 (d)

A-0 (d)

A-0 (d)

A-0

A-60

A-0

-

A-0

*

A-0

Service spaces (high risk) (9)

A-60

A-0

A-0

A-0

A-0

A-60

A-0

A-0

A-0 (d)

*

A-0

Open decks (10)

*

*

*

*

*

*

*

-

*

-

*

Sanitary and similar spaces (11)

A-0

A-0

*

A-0

*

A-0

A-0

A-0

A-0

*

*

SPACE BELOW Control Stations

(1)

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OPERATIONS MANAGEMENT Notes for Table 7A and 7B: a) Where the space contains an emergency power source or components of an emergency power source adjoining a space containing a ship’s service generator or the components of a ship’s service generator, the boundary bulkhead or deck between those spaces should be a “A-60” class division. b) Where spaces are of the same numerical category, the bulkhead or deck rating, shown in the tables, is only required when the adjacent spaces are being used for a different purpose. For example, in category 9, a galley next to a galley does not require a bulkhead but a galley next to a paint room requires an “A-O” bulkhead. c) Bulkheads separating the navigation bridge, chartroom and radio room from each other may be “B-O” rating. d) Where an asterisk (*) appears in the tables, the division is required to be made of steel or equivalent material but is not required to be of “A” Class standard. However, where a deck is penetrated for the passage of electric cable, pipes and vent duct such penetrator should be made tight to prevent the passage of flame and smoke.

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OPERATIONS MANAGEMENT Appendix 8 8.1 Figure 9: Process Flowchart for Decommissioning of Upstream Installations

8.2 Decommissioning Plan Requirement 1. 2. 3. 4.

226

Executive Summary Decommissioning Plan a) Objective b) Decommissioning Base-Plan c) Decommissioning Process d) Planning e) Contracting Strategy f) Assessment of Risk g) Legal Framework h) Stakeholder Engagement Petroleum Engineering a) Summary of Subsurface Review b) Prospect (G&G) c) Further Development (Reservoir Status) d) Conclusion e) Recommendation to decommission field Operations a) Background

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OPERATIONS MANAGEMENT b) Development History c) Production History (operations maintenance, operating expenditures, production) 5. Decommissioning Engineering a) Facilities (Platform/Pipeline) Description b) Pre-decommissioning Study c) Well Decommissioning d) Facilities Decommissioning 6. Health, Safety & Environment a) Health Issues b) Safety Issues c) Environmental Issues 7. Decommissioning Project Schedule 8. Cost a) Cost Estimate b) Taxation Clause c) Custom/Excise Duty 9. Decommissioning Project Planning a) Team b) Contracting 10. Reference 11. Appendices

inspections,

8.3 Project Execution Plan 1. Executive Summary 2. Project Background a) Project Description b) Scope of Activities 3. Organisation and Resources a) Project Team b) Resources Plan and Responsibilities 4. Contracting Strategy 5. Planning & Scheduling a) Baseline Schedule b) Schedule Control c) Reporting 6. Cost a) Cost Estimate b) Cost Monitoring and Control c) Taxation Clause d) Custom/Excise Duty 7. Execution (by Activities) a) Engineering b) Disposal Plan PPGUA/3.0/042/2013

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OPERATIONS MANAGEMENT c) Authorities Involved 8. Health, Safety & Environment a) HSE Management Plan b) Environmental Assessment Plan 9. Reference 10. Appendices

8.4 Final Closeout Report 1. Executive Summary a) Background b) Organisation Chart/Project Team • Schedule Plan vs. Actual • Main Chronological Events c) Cost • Pre-Decommissioning • Decommissioning • Post Decommissioning 2. Project Execution Plan 3. Pre-Decommissioning a) Organisation Chart b) Detail Schedule • Schedule Plan vs. Actual • Main Chronological Events c) Detail Execution 4. Decommissioning a) Organisation Chart b) Detail Schedule • Schedule Plan vs. Actual • Main Chronological Events c) Detail Execution 5. Post Decommissioning a) Organisation Chart b) Detail Schedule • Schedule Plan vs. Actual • Main Chronological Events c) Detail Execution 6. Lessons Learnt and Recommendation a) Pre-Decommissioning b) Decommissioning c) Post Decommissioning 7. Conclusion 8. Reference 9. Appendices a) Survey Verification Report 228

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b) Disposal Report c) Post Environmental Assessment Report d) As-Built Drawings/Documents

8.5 Figure 10: Upstream installation beyond the official coastal line – Territorial Sea

LAND

LIMIT OF TERRITORIAL SEA (12 NAUTICAL MILES)

TERRITORIAL SEA

Fixed Platform

Port/Jetty SALM/SBM

CONTI

TERRITORIAL SEA

NEN SHEL TAL F

Seabed CONTI

NEN SLOPE TAL

Seabed CONTI

Seabed

NENTA L RISE

EEZ ACT Decorate Guideline - PPGUA Sect 14

Per UNCLOS 1982 United Nation Convention on the Law of the Sea

(≤200m – Shallow Water) (>200m – Deep Water)

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OPERATIONS MANAGEMENT 8.6 Figure 11: Upstream installation beyond the official coastal line – Shallow Water

LAND

TERRITORIAL SEA

LIMIT OF TERRITORIAL SEA (12 NAUTICALMILES)

SHALLOW WATER

Fixed Platform

Turret

ESO

SHIP

SALM/SBM Gas pipeline

Seabed

CON

TINE

TERRITORIAL SEA

NTIA L SHEL F

Anchor chain Sub sea facility

pile

TINE

well

EEZ ACT Decorate Guideline PPGUA Sect 14

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Seabed

CON

NTIA L SLOPE


Seabed

CON

TINE

NTIA L RISE


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OPERATIONS MANAGEMENT 8.7 Figure 12: Upstream installation beyond the official coastal line – Deepwater DEEPWATER (>200 meters water depth) SEA TERRITORIAL SEA (12TERRITORIAL NAUTICALMILES)SHALLOW WATER

DEEPWATER

LIMIT OF

Fixed platform

Fixed platform Turret

Sub sea facility

Seabed Gas pipeline

SHIP

Bridge

FPSO/FSO

pile

ENTAL SHELF

Anchor chain

Seabed

CONTIN

Gas pipeline

well

ENTAL SLOPE


Turret

SHIP

FSO

SALM/SBM

Anchor system Achor system

CONTIN

EEZ ACT Decorate Guideline PPGUA Sect 14

MOPU Storage facilities

Buoy system Anchor chain

CONTIN

well

ENTAL RISE

Seabed

Sub sea facility


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OPERATIONS MANAGEMENT Appendix 9 OEE MODEL Figure 13 : Oil OEE Model Actual Production (excluding idle wells’ production)

Actual Production (excluding idle wells’ production)

Planned Deferment as per Q1 CR Submission

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Planned Deferment NOT as per Q1 CR Submission

Excluding Unplanned Idle Wells’ Production

Utilisation

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OPERATIONS MANAGEMENT Figure 14: Gas OEE Model

Utilisation

Planned Deferment as per Q1 CR Submission

Planned Deferment NOT as per Q1 CR Submission

OEE MODEL TERMS & DEFINITIONS TERM

DEFINITION

Actual Production

Amount of production that is reconciled to the volume received by terminal.

Unplanned Deferment

Amount of deferment due to activities/events that is inevitable due to safety or reasonable causes that result in wells being shut-in for temporary period until the interruption is rectified.

Planned Deferment NOT as per Q1 CR submission

Amount of deferment due to planned shutdown that is not included in Q1 CR; or planned as per Q1 CR but exceeding the planned duration

Oil Technical Availability

Equivalent to: Forecasted Technical Potential – External Deferment – Planned Deferment as per Q1 CR submission

Gas Technical Availability

Equivalent to: Forecasted Technical Potential – External Deferment – Operational Usage – Planned Deferment as per Q1 CR submission

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DEFINITION

Planned Deferment as per Q1 CR submission

Amount of deferment due to planned shutdown per specified period as approved by PETRONAS as per Q1 CR, so long as it is carried out within the year and does not exceed the planned duration.

Operational Usage

Amount of gas used onboard the facilities governed by the same GSA, i.e. fuel gas, gas lift, gas injection, blanket gas, utility/instrument gas and operational venting & flaring.

External Deferment

Amount of deferment due to matters out of Contractor’s control, i.e. government’s directive not stated in existing regulations, PETRONAS’ directive other than stated in PPGUA, void of export means, cascaded effects due to interruption at other facilities not within Contractor’s operatorship, bad weather, catastrophic events etc.

Forecasted Technical Potential

Forecasted well technical potential based on latest quarterly Capacity Review submission (e.g. for April, May and June, the TPs will be based on Q2 CR submission).

Unaccounted Loss/Gain

Amount of production loss or gain mostly due to unrealised or overestimated technical potential.

For purpose of deferment analysis and gap sizing, unplanned deferment is further categorised according to its direct causes. For detailed list of deferment category, refer to the appended Deferment Categorisation below. Notes: a) All figures are based on monthly average figures. b) In lieu of reconciled production, metered production will be deemed acceptable as actual production. DEFERMENT CATEGORISATION Level 1 CODE W

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CATEGORIES Well & Reservoir

PPGUA/3.0/042/2013

DEFINITION Production deferment attributed to well equipment, subsurface devices and reservoir conditions that relate to the well-bore itself.

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OPERATIONS MANAGEMENT CODE

CATEGORIES

DEFINITION

O

Operations

Production deferment attributed to production operations activities itself or caused by drilling, workover, construction, storage constraints, logistic, etc. It covers mainly planned activities and human related deficiencies such as unnecessary delay, no materials, logistic etc

P

Process & Utilities

Production deferment attributed to design related issues of the process equipment and piping, instrumentation and control, and metering

R

Rotating Equipment

Production deferment attributed to systems with rotating equipment such as compressors, turbo machineries, pumps, motors and generators

E

External

Production deferment attributed to: • PETRONAS’ requirements (other than stipulated in PPGUA) • Government’s requirements (other than stipulated in regulations) • Cascaded effects due to interruption at other facilities not within Contractor’s operatorship • Uncontrolled events such as bad weather, permit issue or catastrophic events

Level 2 W-WELL & RESERVOIR CODE

CATEGORIES

DEFINITION

W1

Reservoir conditions

Deferment due to reservoir or fluid conditions/characteristics

W2

Well condition

Deferment due to abnormal operations or failure of wellbore, tubing or wellhead including all auxiliary systems and associated components

W3

Artificial lift

Deferment due to abnormal operations or failure of artificial systems including all auxiliary systems and associated components

W4

Reservoir management

Deferment incurred to maintain optimal field performance and maximize hydrocarbon recovery as per Reservoir Management Plan (RMP)

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OPERATIONS MANAGEMENT O-OPERATIONS CODE

CATEGORIES

DEFINITION

O1

Drilling & workover

Deferment due to drilling and workover activities

O2

Wireline

Deferment due to wireline activities

O3

Offloading operations

Deferment due to crude oil offloading/lifting activities

O4

Production operations

Deferment resulting from error in human intervention during normal operations or lack of resources (including manpower and logistics) to resume production (back-online) following a shutdown

O5

Inspection & maintenance

Deferment necessitated by inspection and preventive maintenance activities for surface facilities and wells

O6

Construction

Deferment due to construction activities including installation, hook-up/tie-in, repair and commissioning activities

R-ROTATING EQUIPMENT CODE

236

CATEGORIES

DEFINITION

R1

Export compression

Deferment due to abnormal operations or failure of compression systems related to export gas including all ‘booster’ compression systems. It includes major components (prime movers and gas compressors) and all auxiliary systems and associated components not limited to skid limits.

R2

Gas lift compression

Deferment due to abnormal operations or failure of compression systems related to gas lift including major components (prime movers and gas compressors) and all auxiliary systems and associated components not limited to skid limits.

R3

Power generation

Deferment due to abnormal operations or failure of electrical power generation systems including major components (prime movers and alternators) and all auxiliary systems and associated components not limited to skid limits. It excludes electrical power distribution systems

R4

Export pumps

Deferment due to abnormal operations or failure of pumping systems related to crude oil and condensate export including all ‘booster’ -pumping systems. It includes major components (prime movers and pumps) and all auxiliary system and associated components not limited to skid limits.

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OPERATIONS MANAGEMENT P-PROCESS & UTILITIES CODE

CATEGORIES

DEFINITION

P1

Separation

Deferment due to abnormal operations or failure of process fluid separation system including all auxiliary systems and associated components

P2

Gas dehydration

Deferment due to abnormal operations or failure of gas dehydration system including all auxiliary systems and associated components

P3

Safeguarding & control system

Deferment due to failure or abnormal operations of main safeguarding and control systems (Distributed Control System (DCS), Fire & Gas System (FGS) and Alarm & Shutdown System or functionally equivalent) including all auxiliary systems and associated components. It does not include local/on-skid equipment/system safeguarding and control functions. Also includes firewater system and all auxiliary systems and associated components

P4

Metering

Deferment due to abnormal operations or failure of hydrocarbon measurement system including all auxiliary systems and associated components

P5

Produced water

Deferment due to abnormal operations or failure of treatment and disposal system for produced water including all auxiliary systems and associated components

P6

Pipeline

Deferment due to abnormal operations or failure of pipeline (including all associated components) used for evacuation of production or gas lifting

P7

Storage & Offloading

Deferment due to abnormal operations or failure of storage and offloading system for produced hydrocarbon including all auxiliary systems and associated components

P8

Utilities

Deferment due to abnormal operations or failure of general (excluding power generation) or process utilities system including all auxiliary systems and associated components. Include fuel gas, instrument air/gas and power distribution system

E-EXTERNAL CODE

CATEGORIES

DEFINITION

E1

Government

Deferment arising from government’s requirements other than what is stated in existing or new regulations

E2

PETRONAS

Deferment arising from PETRONAS’ requirements other than what is stated in PPGUA. It includes changes to approved production allowable and flaring limit

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OPERATIONS MANAGEMENT CODE

238

CATEGORIES

DEFINITION

E3

Transportation

Deferment related to means to deliver produced hydrocarbon to customers

E4

Others

Deferment due to cascading effects of activities or events at other facilities not within the same operatorship and uncontrolled events such as bad weather, permit issue or catastrophic events.

PPGUA/3.0/042/2013

Volume 7 Final CD

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