petronas drilling operations guideline

© 2013 PETROLIAM NASIONAL BERHAD (PETRONAS)

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DRILLING AND WELLOPERATIONS

VOLUME 8

PETRONAS Proceduresand Guidelines for Upstream

Activities (PPGUA 3.0)

VOLUME 8DRILLING AND WELLOPERATIONS

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Table of Contents

Executive Summary 10Contact Information 10Definitions 11-13Official Correspondence 14Company Press Release 14Section 1: Drilling Programme Approval 15 1.1 Notification 15 1.2 Wellsite Survey and Shallow Hazard Report 15 1.3 Well Positioning 15 1.3.1 Pre-survey Preparation 15 1.3.2 Positioning Operations 16 1.3.3 Post-positioning Works 16 1.4 Notice of Operations (NOOP) 16-17 1.5 Variations 17Section 2: Recording and Reporting 18 2.1 Priority Reporting 18 2.2 Rig Arrival and Release Notice 18 2.3 Daily Drilling Report 18-19 2.4 Final Drilling and Completion Report 19-20 2.5 Supporting Reports 20Section 3: Drilling Quality Assurance/Quality Control 21 3.1 Quality Plan 21 3.2 Quality Requirements 21 3.3 Quality Implementation and Continuous Improvement 21-22Section 4: Drilling Unit Design, Manning and Logistics 23 4.1 Drilling Unit Design 23 4.1.1 Drilling Unit Inspection 23 4.1.2 General Arrangement Drawings 23-24 4.2 Blowout Preventer Equipment 24 4.3 Protection Against External Hazards 24 4.4 Personnel Safety and Welfare 24 4.4.1 Safety Guards and Exits 24 4.4.2 Derrick Escape 25 4.4.3 Rotary Tongs 25 4.4.4 Medical Facilities and Provisions 25


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4.5 Fire Protection 25 4.5.1 Fire Fighting Equipment 25-26 4.5.2 Fire Alarm System 26 4.6 Gas Detection 26 4.7 Pollution Prevention 26 4.8 Helideck on Drilling Units 26-27 4.9 Pressure System 27 4.10 Electrical Installation 27 4.10.1 Equipment and Standards 27 4.10.2 Lighting 28 4.10.3 Emergency Electrical Power Supply 28 4.11 Forced Air System and Ventilation 28 4.11.1 Hazardous System 28 4.11.2 Ventilation 28 4.11.3 Engines and Motors 29 4.11.4 Exhaust Pipes 29 4.12 Weather Data Recording 29 4.13 Diving 29 4.14 Emergency Shutdown 29 4.15 Manning 29 4.16 Support Craft 30Section 5: Well Design and Drilling Operations 31 5.1 Drilling Unit Moving and Positioning 31 5.1.1 General Provision 31 5.1.2 Anchor Testing for Drilling Unit 31 5.1.3 Bottom Supported Unit 31-32 5.1.4 Dynamically Positioned Units 32 5.1.5 Diving Operations 32 5.2 Casing and Cementing 32 5.2.1 Drive Pipe 33 5.2.2 Conductor Casing 33-34 5.2.3 Surface Casing 34 5.2.4 Intermediate Casing 34 5.2.5 Production Casing 34-35 5.2.6 Casing Pressure Test 35-36

5.2.7 Records 36 5.2.8 Cementation 36-37


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5.2.9 Excess Cement Volume 37 5.2.10 Inadequate Cement Job 37 5.3 Well Directional Survey 37 5.3.1 Vertical Well 37 5.3.2 Directional Well 37-38 5.4 Well Control Equipment and Testing 38 5.4.1 BOP System 38 5.4.2 Auxiliary Equipment 38-39 5.4.3 Diverter System 39 5.4.4 Surface BOP Stack 39-40 5.4.5 Subsea BOP Stack 40-41 5.4.5.1 Subsea BOP Diversion 41 5.4.6 BOP Test 41 5.4.6.1 BOP Control System 41-42 5.4.6.2 Pressure Test 42 5.4.6.3 Function Test 42-43 5.4.7 Inspection and Maintenance 43 5.4.8 Personnel Competency 43-44 5.5 Drilling Fluid Programme 44 5.5.1 Primary Well Control 44-45 5.5.2 Drilling Fluid Test 45-46 5.5.3 Drilling Fluid Quantity 46 5.6 Formation Integrity Test 46 5.7 Lost Circulation 47 5.8 Detection of Overpressure 47 5.9 Suspension of Operations 47-48 5.10 Shallow Hazards and Hydrocarbons 48 5.11 Underbalanced Drilling 49 5.12 H2S Drilling Operations 49 5.12.1 Physical Properties and Toxicity 49-50 5.12.2 Breathing Equipment 50 5.12.3 H2S Gas Detection 50 5.12.4 Wind Direction Equipment 50 5.12.5 Ventilation 50 5.12.6 Personnel Training 51 5.12.7 Contingency Plan 51 5.12.8 Drilling Unit Equipment 51-52


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5.12.8.1 Drill Pipe 52 5.12.8.2 Tubulars 52 5.12.8.3 BOP and Related Equipments 52 5.12.8.4 Flare System 52 5.12.9 Drilling Operations 52 5.12.9.1 Pipe Trips and Stripping 52 5.12.9.2 Well Control 53 5.12.9.3 Coring 53 5.12.9.4 Drilling Fluid 53 5.12.10 Well Testing Operations 53 5.13 HPHT Drilling Operations 54 5.13.1 Risk Management 54 5.13.2 Personnel Training 54 5.13.3 Preparation and Planning 54-55 5.13.4 Well Engineering and Design 55 5.13.5 Drilling Unit and Equipment 56 5.13.6 Contingency Plan 56Section 6: Formation Evaluation 57 6.1 Drill Cutting Sampling 57 6.1.1 Sample Frequency 57 6.1.2 Sample Container 57 6.2 Coring 57 6.2.1 Conventional Cores 57 6.2.2 Side Wall Cores 57-58 6.3 Formation Evaluation Logging 58 6.4 Oil and Gas Flow Testing 58Section 7: Completion Operations 59 7.1 General Provision 59 7.2 Wellhead Equipment 59 7.3 Tubing Requirements 59-60 7.4 Subsurface Safety Valve 60 7.4.1 Installation 60 7.4.2 Valve Specifications 60-61 7.4.3 Reinstalling, Testing and Maintenance 61 7.4.4 Tubing and Plug Testing 61 7.4.5 Additional Protective Equipment 61 7.4.6 Records 61-62


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7.5 Packer Requirements 62 7.5.1 Cement Packer 62 7.5.2 Circulating Device 62 7.6 Separation of Zones 62 7.7 Landing Nipples 63 7.8 Completion Fluid 63 7.9 Packer Fluid 63Section 8: Barriers and Well Integrity 64 8.1 Number of Well Barriers 64 8.2 Barrier Failure and Restoration 64 8.3 Barrier Material 64 8.3.1 Solidified Cement 64 8.3.2 Mechanical Barrier 64-65 8.3.3 Fluid Barrier 65 8.4 Well Integrity Management 65Section 9: Plug and Abandonment of Wells 66 9.1 Responsibility to Abandon a Well 66 9.2 Application to Abandon a Well 66-67 9.3 Subsequent Report of Abandonment 67 9.4 Permanent Abandonment 67 9.4.1 Isolation of Zones in Open Hole 67-68 9.4.2 Isolation of Open Hole 68 9.4.3 Plugging or Isolation of Perforated Intervals 68-69 9.4.4 Plugging of Casing Stub 69 9.4.4.1 Stub Terminating Inside Casing String 69 9.4.4.2 Stub Terminating Below Casing String 69 9.4.4.3 Liner Top or Screen 69-70 9.4.4.4 Plugging of Annular Space 70 9.5 Surface Plug 70 9.6 Testing of Plugs 70 9.7 Abandonment Fluid 70-71 9.8 Clearance of Location 71 9.9 Well Suspension 71 9.10 Temporary Well Suspension 71 9.11 Suspended Well 71


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Section 10: Workover and Well Intervention Operations 72 10.1 General Requirement 72 10.1.1 Well Intervention 72-73 10.1.2 Workover 73 10.1.3 Operations 73 10.2 Workover Unit and Equipment 73 10.2.1 Workover Structure 73 10.2.2 Travelling Block Safety Device 73 10.2.3 Pumping Equipment 73-74 10.2.4 Pumping Operations 74 10.2.5 Hazardous Chemicals 74 10.3 Well Unloading Operations 74-75 10.4 Notification and Submittal Requirements – Workover 75 10.4.1 Notice of Workover Operations and Major Well Intervention 75 10.4.2 Workover Reports and Data Retention 76 10.4.3 Daily Workover Report 76 10.4.4 Final Workover Report 76-77 10.5 Major Well Intervention Operations 77 10.6 Notification and Submittal Requirements – Major Well Intervention 77 10.6.1 Well Intervention Activity Reports 77-78 10.7 Routine Well Intervention Operations 78 10.8 Well Control Equipment 78 10.8.1 Workover Pressure Control Equipment 78 10.8.2 Well Intervention Pressure Control Equipment 79 10.8.2.1 Coil Tubing Operations 79 10.8.2.2 Electric Line or Braided Line Operations 79 10.8.2.3 Slickline Operations 79 10.8.2.4 Snubbing Operations 79-80 10.8.3 Other Equipment 80 10.8.4 Well Control Fluids 80 10.8.5 Well Control 80 10.8.6 Pressure and Function Test 81 10.8.6.1 Pressure Test 81 10.8.6.2 Function Test 81 10.8.6.3 Lubricators 81 10.9 Emergency Shutdown (ESD) 81 10.10 Wireline Operations 82


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10.10.1 General Requirements 82 10.10.2 Operations in Cased Hole 82 10.10.3 Operations in Open Hole 83 10.10.4 Swabbing Operations 83-84 10.11 Rigging Up or Down of Workover or Completion Equipment 84Section 11: Onshore Drilling Operations 85 11.1 Drill Site and Camp Design 85 11.1.1 License and Permits 85 11.1.2 Risk Assessment 85-86 11.1.3 Access Road 86 11.1.4 Campsite 87 11.1.5 Water Pit and Drilling Fluid Pit 87-88 11.1.6 Flare Pit and Vent/Bleed-Off Line 88 11.1.7 Water Well and Water Source 88 11.1.8 Fencing and Well Security 88 11.2 Environment Protection and HSE 89 11.2.1 Emergency Response 89 11.2.2 Protection of Fresh Water Sands 89 11.2.3 Well Near Water Source 89 11.2.4 Drilling Liquid Waste, Contamination and Spills 89-90 11.2.5 Fire Prevention and Safety 90 11.2.5.1 Smoking 90 11.2.5.2 Engines Exhaust 90 11.2.5.3 Engines Intake 91 11.2.6 Restoration of Drill Site 91 11.3 Well Design and Drilling Operations 91 11.3.1 Reference for Well Depth 91 11.3.2 BOP System 91 11.3.3 Pressure and Function Test 91 11.3.4 Casing Programme 92 11.3.4.1 Stove Pipe 92 11.4 Plug and Abandonment of Well 92Section 12: Onshore Completion, Workover and Intervention Operations 93 12.1 General 93 12.2 Subsurface Safety Valve 93 12.3 Well Stimulation 93 12.4 Disposal of Produced Fluids 93-94


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12.5 Onshore Wellhead Valve Assembly 94 12.6 Wells on Pump 94Section 13: Waste Material Handling and Disposal 95 13.1 Material Handling 95 13.1.1 Bulk Material 95 13.1.2 Other Material 95 13.2 Disposal of Material 96 13.2.1 Drilling Fluid 96-97 13.2.2 Solid Waste 97 13.2.3 Liquid Waste 97-98 13.2.4 Sewage 98 13.3 Pollution Prevention 98 13.3.1 Offshore Pollution 98 13.3.2 Blowout Contingency Plan 98-99 13.3.3 Onshore Pollution 99-100Abbreviations 101-103Appendix 1 104-106Acknowledgements 107


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Executive SummaryThis volume provides procedures for conducting offshore and onshore well drilling, completion, testing, workover, intervention and servicing activities inMalaysia. These procedures may be added to or amended from time to time upon written notice by PETRONAS and provided such additions or amendments areconsistent with the provisions of the Contract. In adding to or amending theprocedures, PETRONAS shall consider the incremental expenditures which may be incurred by Contractor in complying with the amended procedures.

This document provides auditable procedures for planning, preparation andexecution phases including well design, operations, equipment specification andrequirements for inspections, testing and audits including High Pressure HighTemperature (HPHT) well design soundness verification and deepwater wellcontingency plan. Contractor may request exception or exemption to theseprocedures and exception or exemption may be granted when PETRONAS andContractor agree that prudent practice is served and Health, Safety andEnvironment (HSE) risk arising from the exception or exemption remain As Low As Reasonably Practicable (ALARP).

PETRONAS shall have the right to be actively involved in all phases of Contractor’s well drilling, completion, testing, workover, intervention and servicing activities planning, preparation and execution.

Contact InformationAll correspondence related to this volume shall be addressed to:

General ManagerDrilling Petroleum Operations Management Petroleum Management Unit


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DefinitionsIn this procedure, terms and expressions not specifically defined below shall have the sense and meaning commonly attributed to them in the oil and gas exploration and production industry unless the context requires otherwise:

TERM DEFINITION

Autoshear System A safety system that is designed to automatically shut-in the wellbore in the event of a disconnect of the Lower Marine Riser Package (LMRP). When the autoshear is armed, a disconnect of the LMRP closes the shear rams.

Coiled-Tubing Operations Operations using spooled non-jointed pipe through thewellhead and well tubing.

Conductor Casing The second casing string set in the order of normal installation based on the relevant engineering and/or geological factors (including the presence or absence of hydrocarbons, potential hazards and water depth). The Conductor Casing may also be first casing string set in lieu of Drive Pipe or Structural Casing to support unconsolidated deposits and to provide hole stability for initial drilling operations.

Deadman System A safety system that when armed is designed to automatically close the wellbore in the event of a simultaneous absence of hydraulic supply and signal transmission capacity in both subsea control pods.

Deepwater Generally described as water depth beyond 300 metres.

Diverter A device for the purpose of diverting the uncontrolled flow of fluid from the well bore.

Drill Stem Test A test that is performed by allowing formation fluids to flow to the surface through the drill pipe or test string. It is normally used for determination of well productivity.

Drilling Programme The programme for the drilling of one specific well.

Drilling Sequence A programme for the drilling of one or more wells as presented in the annual Work Programme & Budget (WPB) and its subsequent revisions.

Drilling Unit A drill ship, submersible, semi-submersible, barge, jack-up, land rig or other vessels used in a drilling programme and includes a drilling rig and other related facilities installed on a vessel.


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TERM DEFINITION

Drive pipe or Structural Casing

The first casing string set in the order of normal installation by driving, jetting or drilling to a competent bed as means to provide support to unconsolidated deposits and to provide hole stability for initial drilling operation.

Emergency Disconnect System (EDS)

A system that when activated initiates a pre-programmed sequence of well securing Blowout Preventer (BOP) functions in a minimum amount of time prior to disconnection of the LMRP.

External Hazard Environmental conditions occurring on the drilling unit ordrilling base which threaten the safety of the operation.

High Pressure HighTemperature (HPHT)

A well generally described as having an undisturbedBottom Hole Temperature (BHT) greater than 300°F (149°C) andmaximum pore pressure exceeding 0.8 psi/ft or requiringpressure control equipment with a rated working pressure inexcess of 10,000 psi.

Intermediate Casing The string or strings of casing set after the surface casing in the order of normal installation to protect against anticipatedpressures, mud weight, sediment, and other well conditions. The setting depth for this casing is normally based on the pressure test of the exposed formation below the surface casing shoe or any other previous intermediate casing shoe and anticipated formation pressure of the hole section to be drilled.

Kick Influx of wellbore fluid into the wellbore and possible loss of primary control of the well which shall be controlled by secondary control (BOP).

Liner A string of casing installed inside a casing string or another liner and lapped back inside the previous casing or liner for at least 30 metres. A liner may be used as a drilling liner or production liner. A liner may also be tied back to surface ifrequired in which it will be regarded as a production string.

Lubricator Assembly A setup consisting of wireline BOP, a riser assembly with a bleed valve and a wireline pack off.

Non-FDP wells Wells that are not included in the original approved Field Development Plan (FDP) and require additional approval from PETRONAS. A minimum of fourtteen (14) days notice shall be given prior to spudding the well.

Offshore Well A well drilled from offshore drilling unit.


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TERM DEFINITION

Oil Spill Any unexpected loss of crude oil, condensate or hydrocarbon containment that reaches the environment, for example, water or land irrespective of quantity recovered.

Open Hole A well bore or portion of a wellbore that is not protected by casing.

Production Casing A string of casing which is set for the purpose of completing the well for production.

Shooting Nipple Assembly Wireline packoff and a riser assembly held in place by BOP.

Small-Tubing Operations Operations using jointed pipes through the wellhead and well tubing.

Snubbing Operations Operations using jointed tubing or drill pipe and a snubbing unit under pressure conditions, either through the wellhead valve assembly and well tubing of a completed well or through the BOP and wellbore of a conventional operation.

Spud The initial penetration of the ground or sea floor for the purpose of drilling a well.

Stripping Operations Operations that require manipulation of the drill string or work string through BOP, under low or moderate pressure, without the use of a snubbing unit.

Surface Casing The casing string set after the Conductor Casing in the order of normal installation in a competent bed based upon relevant engineering and/or geological factors, including the presence or absence of hydrocarbons, potential hazards, and water depths. The Surface Casing shall be set in order for the next hole section to be drilled with BOP.

Waste Material Refuse, non-biodegradable garbage or any other uselessmaterial generated during drilling and related operations excluding fluid and drill cuttings.

Well InterventionOperations

Remedial operations performed with the christmas tree not removed.

Well Material Any formation or reservoir material obtained from a well and includes cuttings, cores or fluids.

Well Suspension The temporary cessation of drilling/completion activities(waiting for final completion or abandonment).

Workover Operations Remedial operations performed with the christmas treeremoved and BOP installed.


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Official CorrespondenceRefer to Appendix 1 of this volume.

Company Press ReleaseContractor shall obtain prior written approval from PETRONAS for all pressreleases issued regarding wells drilled under these procedures.


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Section 1: Drilling Programme Approval

Notice of Operations (NOOP) shall be prepared by Contractor and submitted to PETRONAS for approval or notification (whichever is appropriate) in a timelymanner. Significant deviations to the NOOP programme with prior PETRONAS’approval and Management of Change (MOC) process shall be managed byContractor with considerations on impact to health, safety, environment, project/well costs and PETRONAS/Contractor image. Contractor is responsible to avoidretroactive approval request by ensuring timely submission of all request toPETRONAS.

1.1 Notification Contractor shall notify PETRONAS in the Work Programme & Budget (WPB) and subsequent revisions of its intention to undertake any particular Drilling Campaign.

1.2 Wellsite Survey and Shallow Hazard Report Contractor shall conduct high-resolution geophysical site surveys to determine the existence of shallow gas, near-surface faulting, slumping, unusual bottom features, and other potential shallow hazards prior to the commencement of drilling operations. Remote sensing tools normally utilised in conducting such surveys shall include side-scan sonar, sea-bottom profiler and other shallow seismic instrument. Survey line spacing shall be a maximum of 250 metres apart in a 1-square-kilometre area centred on the wellsite. If in the opinion of the Contractor, surveys exist for a location nearby to the proposed location which may be taken as representative of the new location, or if extensive experience in a local area has shown that such surveys are not required, then additional surveys may not be required subject to PETRONAS’ approval. As and when requested such geophysical site surveys and shallow hazards reports shall be submitted to PETRONAS.

For deepwater operations, hazards such as shallow gas, shallow water flow, hydrates and expulsion features should be evaluated. 3D seismic or other imaging methods may be used in lieu of conventional shallow seismic, as appropriate.

1.3 Well Positioning

1.3.1 Pre-survey Preparation Contractor shall notify PETRONAS of a proposed well location prior to any positioning work.


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1.3.2 Positioning Operations Contractor shall ensure the safety of pipelines and cables underlying subsea and perform pre-spud and final post-spud verifications.

1.3.3 Post-positioning Works Contractor shall submit to PETRONAS a full operation report when available. The report shall be in hard copy or acceptable electronic format.

1.4 Notice of Operations (NOOP) The NOOP for all wells shall be submitted at least forteen (14) days prior to spud date in hard copy and acceptable electronic format. Field Development Plan (FDP) wells’ NOOP shall be submitted for information. All other wells’ NOOP shall be submitted for approval. The NOOP shall contain but not limited to the following information: a) Objectives of the well; b) Location map; c) Prognosis cross-section; d) Depth of well and proposed completion target (in True Vertical Depth (TVD) and Measured Depth (MD)); e) Directional drilling plan including anti-collision plan; f ) Casing programme and casing design criteria; g) Mud and cement plan; h) Bit selection and hydraulic programme (for each hole size); i ) Well logging, coring and other formation evaluation programme; j ) Estimated formation pressure and fracture gradient; k) Anticipated problems and drilling hazards; l ) Authorisation for Expenditure (AFE) breakdown; m) Estimated depth vs days and depth vs cost chart; n) Name and type of drilling unit; o) Contingency plan for operational problems. A Blowout Contingency Plan (BOCP) shall be provided in accordance with Section 13.3 for deepwater and HPHT wells; p) Propose full Plug & Abandonment (P&A) with drawing for exploration, appraisal and suspended wells; q) Well schedule; r ) Completion diagram (for development wells); s ) BOP configuration diagram; and t ) Negative or inflow test procedures and criteria for a successful test, if applicable (refer to Section 5.2.6).

Pre-spud meeting and/or drill on paper should be conducted. During the


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execution phase, if Contractor anticipates that there will be a potential cost overrun of 10% from the approved well cost or Non-Productive Time (NPT) more than fifty (50) consecutive hours, Contractor shall give written notice to PETRONAS. In addition, if the above well has been completed, Contractor shall submit and present the case to PETRONAS.

1.5 Variations Contractor may implement variations or deviation to the approved NOOP as deemed operationally necessary or desirable to achieve the agreed objectives of the well in an efficient and safe manner, however prior PETRONAS’ approval is required for significant deviations. The request for approval submission shall include risk assessment and/or MOC documents. Significant deviation refers to any changes that increase health, safety, environmental or financial risk and/or well cost. PETRONAS may require Contractor to show that specific equipment or procedures are consistent with the interests of safe and efficient operations. Contractor shall modify or replace any equipment or alter any procedure that cannot be shown to be safe. Contractor shall install new equipment or initiate new procedures if necessary to conduct safe operations. Notwithstanding the above, during an emergency or contingency, procedures or equipment may be altered without prior PETRONAS’ approval and in such cases, PETRONAS shall be notified forthwith of the alterations and the underlying circumstances within 24 hours.


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Section 2: Recording and Reporting

Drilling and well operations carried out by Contractor in Malaysia shall bereported to PETRONAS and relevant authorities for approval and information within the stated timeline. The reporting and report contents requirement shall adhere tothe procedures in this section. Contractor shall also record all the importantinformation pertaining to the operation and this information shall be madeavailable to PETRONAS as and when requested. 2.1 Priority Reporting Contractor shall inform PETRONAS immediately by the most rapid and practical means of every significant situation, event or accident, including but not limited to the loss of life, missing persons, serious injury, fire, loss of well control, imminent threat to safety of drilling unit, drilling rig or personnel, oil or toxic chemical spill, or the confirmed discovery of oil and gas. Contractor shall submit to PETRONAS, as soon as practicable, a comprehensive written report of the situation, event or accident, and shall notify relevant authorities as circumstances require. Refer to Volume 3: Health, Safety & Environment.

2.2 Rig Arrival and Release Notice Contractor shall inform PETRONAS within 24 hours by fax, e-mail or equivalent means: a) Of the date that the drilling unit arrives at the drilling location; and b) Of the actual hour and date that the drilling rig or drilling unit is released from the drilling location

Contractor shall also notify related government departments i.e. marine department, port authorities, fisheries department, maritime enforcement agency and customs department at least two (2) months prior to rig arrival and rig departure.

2.3 Daily Drilling Report Contractor shall submit the Daily Drilling Report (DDR) to PETRONAS containing but not limited to the following information: a) Well name or number; b) Rig name and type; c) Plan Total Depth (TD) in MD and TVD (metre); d) Current depth;


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e) Plan cost (USD or RM); f ) Current cost (daily and cumulative); g) Plan and actual days; h) Days ahead/behind; i ) The operations for last 24 hours; j ) NPT description and duration (daily and cumulative NPT); k) Set casing/liner size, properties and set depth; l ) Wellbore/directional survey for last 24 hours progress; m) Drilling fluid properties; n) Bottom-Hole Assembly (BHA) and drilling bit description; o) Number of Personnel on Board (POB); and p) HSE incidents

2.4 Final Drilling and Completion Report Contractor shall submit to PETRONAS a Final Drilling and Completion Report and electronic copy/soft copy on CD within sixty (60) days after a well has been drilled and completed, suspended or abandoned. PETRONAS may also request additional information when the need arises. The report shall include, but not limited to the following information: a) Well number and type; b) Rig name and type; c) Surface and sub-surface location grid and geographical coordinates of the well; d) Well depth (MD and TVD); e) Maximum angle reached; f ) Total days spent on the well; g) Summary of drilling operations; h) Basic reservoir/geological details; i ) Final wellbore sketch or completion diagram showing all downhole components (with their I.D., O.D., length, depth of installation) and description of wellhead and christmas tree; j ) Type and density of fluid left in the hole; k) Perforated intervals; l ) Initial production test results including registered pressure, fluid/gas flow rates and duration of test; m) List of wireline logs and its interpretation (cored intervals should also be shown); n) Casing size, type, grades, weights, depth set in MD and TVD; o) Mud composition, amount used and average per well oil-on-cuttings (OOC) percentage for drilling with Low Toxicity Oil Based Mud (LTOBM) or Synthetic Based Mud (SBM);


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p) Cement density, composition, volume of cement used and their estimated top in annulus; q) Depth-days chart, actual cost vs proposed; r ) Operational-time breakdown; s ) Summary of HSE incident and scheduled waste; t ) Summary of NPT; u) Directional drilling results and wellbore trajectory; and v ) Final estimated well cost

2.5 Supporting Reports Reports obtained or compiled by the Contractor regarding applied research work or studies, that contain information which is relevant to the safety of drilling operations in the programme area, shall be submitted to PETRONAS as soon as they are available. PETRONAS may request any additional information with regards to drilling operation at any time and Contractor shall submit the information to PETRONAS within agreed timeline.


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Section 3: Drilling Quality Assurance/Quality Control

Contractor shall have quality plans and procedures in place to ensure all drilling and completion services and goods provided are in accordance with contractual requirements (between Contractor and third party contractors) and able to perform as per the stated performance.

3.1 Quality Plan Contractor shall prepare a Quality Plan which as a minimum outline the following:

a) Categorising of services and goods based on its criticality considering the potential impact to health, safety, environment, well integrity, and project cost should an incident occur; b) Planned process controls to ensure quality is integrated from well planning to execution; c) Capture a process for managing non-conformance from actual event in the workshop or field to closure; d) Methods utilised to measure quality performance and improvement process; and e) Plans for periodic third party contractor assessments to ensure quality requirements are maintained and followed

3.2 Quality Requirements Contractor shall document all quality requirements in contract documents and/or purchase orders executed with drilling rig and third party contractors:

a) All drilling and completion equipment shall be delivered in accordance with the relevant industry standard(s) such as American Petroleum Institute (API) and International Organization for Standardization (ISO); and b) Drill strings shall be inspected in accordance to the latest version of TH Hill Standard DS-1 or equivalent inspection standard as applicable

3.3 Quality Implementation and Continuous Improvement All parties involved in well drilling and completion shall be responsible for ensuring quality from planning to execution. Contractor shall have qualified personnel responsible to ensure equipment and goods are inspected per the quality requirements. Processes to manage changes or deviations to Contractor’s Quality Assurance/Quality Control (QA/QC) requirements shall be in place.


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QA is a continuous improvement process. Contractor shall periodically review their performance (for example, non-productive time & cost, non-compliance reports, etc.) to gauge the effectiveness of Contractor, drilling rig and third party contractor’s QA/QC system. The process shall incorporate a quality database and lessons learnt. Contractor drilling management shall be responsible to ensure effectiveness of Contractor’s QA/QC system.


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Section 4: Drilling Unit Design, Manning and Logistics

Drilling units, support craft, base office and warehouses used by Contractor shall be ready with adequate fit-for-purpose equipment, detailed procedures,competent personnel and support services to ensure operation objectives are met andcarried out with adherence to HSE concerns and regulations. As and whenrequested by PETRONAS, copies of approval or certificates from recognised bodyshall be submitted to demonstrate equipment reliability and operation safety.

4.1 Drilling Unit Design Contractor shall submit upon the request of PETRONAS, copies of valid approvals or certificates from a recognised certification body to demonstrate that the proposed drilling programme can be safely executed by the drilling unit with a view to stability, operating limits, structural strength, fatigue, etc., during the course of all anticipated combinations of environmental and functional loads.

In the event that weather forecasts indicate conditions during which normal drilling operations could not continue, Contractor shall take necessary actions to interrupt drilling operations in time, so that the safety of the well and drilling unit shall not be jeopardised. 4.1.1 Drilling Unit Inspection After obtaining PETRONAS’ approval to award, Contractor shall be responsible for conducting full drilling unit inspection by an industry recognised third party at an opportune time prior to contract award. The aim of this inspection is to gain accurate assessment of the state of maintenance and working conditions of the equipment and systems on the drilling unit in accordance with the drilling unit’s contractual requirements. The objectives are to limit downtime and improve reliability and safety. All critical actions from the inspection shall be duly closed out prior to spudding of the first well. The inspection report shall be made available upon request by PETRONAS.

4.1.2 General Arrangement Drawings Upon request by PETRONAS, Contractor shall submit dimensional layouts and drawings of the drilling rig and camp. Upon request by PETRONAS, Contractor shall submit general arrangement drawings for all surface and subsea equipment on the drilling unit which shall include:

a) arrangements of drill floor, cellar deck, spider deck, moonpool


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areas and their associated equipment; b) arrangements of mud tanks, high and low pressure mud and cement slurry systems and bulk transfer system; c) arrangement of all surface and subsea well control systems including arrangement of choke manifold, testing and flaring systems; d) arrangement of other pressure systems; and e) position and type of all life-saving appliances, fire extinguishing and protection systems, fire stations and appliances, navigational safety appliances and alarm systems

4.2 Blowout Preventer Equipment Appropriate well control equipment shall be installed, maintained and tested to ensure well control in the course of normal safety drilling. The working pressure of such equipment shall exceed the maximum anticipated surface pressure to which it may be subjected to.

4.3 Protection Against External Hazards Contractor shall take precautions necessary to protect personnel and equipment from the external hazards of air and marine navigation and weather.

A red aircraft warning light of at least fifty (50) candelas shall be mounted at the top of the derrick so as to be visible from all directions.

Drilling units and support craft shall have navigational safety and marine aids which shall meet as a minimum, the requirements of the classification bureau; and for aircraft, the civil aviation regulatory authority.

Drilling units shall have emergency equipment and life-saving devices sufficient to permit the escape of all personnel under all conditions which shall meet as a minimum, the requirements of the classification bureau.

4.4 Personnel Safety and Welfare 4.4.1 Safety Guards and Exits The drilling unit shall be equipped with safety guards on all potentially dangerous or moving parts of machinery and with guard rails around the perimeter of the drill floor, deck areas, walk-ways, stairs and any other working area where persons may fall more than 1 metre. The derrick floor shall have at least two exits and preferably one each on opposite sides of the drill floor.


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4.4.2 Derrick Escape When a person is required to work in the derrick as part of normal drilling operations, an escape device acceptable by general industry practices shall be provided from the working platform in the derrick. Persons required to work on the derrick or at a height of 2 metres or higher, shall wear safety belts complete with tail rope having adequate length and strength. Contractor shall ensure that such safety belts are provided at all times on the derrick.

4.4.3 Rotary Tongs All make-up and breakout rotary tongs shall have suitable back-up lines made from flexible wire rope and tied down to a post having the rigidity to withstand maximum tong line pull.

4.4.4 Medical Facilities and Provisions An adequately equipped and supplied first aid room shall be provided at the rig site. A drilling unit shall have a sick bay which is easily accessible and is equipped and supplied to handle all minor indus trial accidents. The facilities in the sick bay shall include first aid and resuscitation equipment and shall have at least one (1) bed for every fiffty (50) persons or portion thereof. Detailed requirements are as per Volume 7, Section 8: PETRONAS Guidelines for Barges Operating Offshore Malaysia (PGBOOM).

4.5 Fire Protection Firefighting equipment and alarm shall be provided and maintained at every drill site to combat all classes of fires. 4.5.1 Fire Fighting Equipment Each drilling unit shall: a) Have appliances whereby at least two (2) jets of water, each of 53 gal/min at a minimum pressure of 40 psi can be rapidly and simultaneously directed into any part of the unit’s substructure at least one (1) of which shall be from a single length of hose; such appliances shall include at least two (3) power driven pumps located separately and at least three (3) fire hoses; in any case at least one fire hose shall be provided for every 30 metres in length of the unit or fraction thereof.


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b) Have readily accessible: • atleasttwo(2)proximityfirefightingsuits; • four(4)self-containedportablebreathingdevices;and • a suitable water supply source of sufficient capacity to assure adequate water supply

Notwithstanding the above, PETRONAS may require additional firefighting equipment to be installed if such equipment is considered necessary.

4.5.2 Fire Alarm System A drilling unit shall be equipped with a fire alarm system that includes detectors located: a) in engine rooms; b) in the boiler rooms; c) in paint lockers; d) in pump and mud tank rooms; and e) in the accommodation

and which is capable of automatically sounding an alarm and indicating on a panel the location of the fire. 4.6 Gas Detection A drilling unit shall be equipped with gas detection systems to monitor continuously at locations where there may be an accumulation of combustible vapours or gas. 4.7 Pollution Prevention The drilling unit shall be adequately equipped with facilities to prevent, reduce and control pollution of the surrounding environment in accordance and in compliance with the regulations as stipulated in the applicable Malaysian laws. All decks and/or equipment shall be equipped with curbs, gutters, drip pans and drains which shall be installed, where possible, to collect all discharge and piped to a collecting tank or sump, with safeguards for overflow, to be disposed in accordance with the applicable Malaysian Laws. 4.8 Helideck on Drilling Units If the drilling unit is equipped or required to have a helicopter deck, it shall be:


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a) of adequate size and structural strength to accommodate the sizes and types of helicopters to be used; b) located so as to provide an approach/departure sector of at least 180 degrees or higher free of obstruction; c) equipped with operable lights commonly used on heliports; d) equipped with a non-skid deck surface and safety nets around the perimeter; e) provided with access gangways; f ) provided with a coaming which shall contain any fuel spill from a leak in the helicopter fuel tanks if such tanks are installed above decks and with a drainage system which shall conduct such a spill away from the drilling unit; and g) equipped with a helicopter crash box located at the access to the helicopter deck

4.9 Pressure System Steam systems, pressure vessels, hot water boilers and steam generators shall be designed, constructed and inspected in accordance and in compliance with widely recognised industry codes.

4.10 Electrical Installation 4.10.1 Equipment and Standards Electrical equipment on drilling unit shall conform at least to API RP 500B ‘Recommended Practice for Classification of Areas for Electrical Installations at Drilling Rigs and Production Facilities on Land and on Marine Fixed and Mobile Platforms’. All electrical systems so designed and installed shall be grounded and shall be able to operate safely under hazardous conditions that may occur in the vicinity of the equipment. Electrical equipment on a drilling unit which is installed in drilling areas defined as Division I and Division II containing atmosphere listed under Class I, Group D, classification of the API RP 500B shall be explosion proof. An emergency shutdown switch, capable of shutting down all electrical equipment and power plants shall be provided at a minimum of two (2) control stations on the drilling unit.


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4.10.2 Lighting Adequate lighting shall be provided in all working areas inside and outside of the drilling rig and emergency lighting shall be provided for the proper illumination of vital areas such as control stations, well control equipment, stairways, exits, machinery areas, emergency generator area; and in the case of an offshore drilling unit; boat stations, passage ways and navigation control area. 4.10.3 Emergency Electrical Power Supply An independent emergency electrical power supply system capable of supplying sufficient power in the event of failure in the primary power supply shall be available to the drilling rig: a) to secure well; and b) for the operation of warning, lighting (in areas identified in Section 4.10.2), alarm, communication and fire extinguishing systems

A drilling unit shall be equipped with an independent emergency electrical power supply system consisting of:

a) a prime mover and generator complete with a fuel supply for a minimum of 24 hours and capable of supplying sufficient power for navigation lighting and warning systems; emergency lighting in areas identified in Section 4.10.2; alarm and communication systems; pumps that are essential for maintaining the trim of the vessel; abandonment systems when dependent on electrical power; and fire extinguishing systems; and b) storage batteries capable of supplying sufficient power to operate for 3 hours the communication system, the navigation and obstruction lights, aircraft warning lights and emergency lighting in areas identified in Section 4.10.2

4.11 Forced Air System and Ventilation 4.11.1 Hazardous System The hazardous areas on the drilling unit shall be in accordance with API RP 500B.

4.11.2 Ventilation Enclosed areas in the vicinity of the BOP stack and mud tanks and all enclosed working and living areas on the drilling base or drilling unit shall be properly ventilated and pressurized.


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4.11.3 Engines and Motors Engines, generators and motors located within any area as designated in Section 4.11.1 shall have their air intakes located in a non-hazardous area or the intakes shall be equipped with device to automatically or manually shutdown the diesel engine in the event of run away. All fans and blowers located inside rooms containing engines, boilers, mud pumps or mud tanks and all fans used for ventilating such rooms shall be equipped with remote shut-off switches. Air intakes and exhausts for machinery spaces shall be capable of being closed. 4.11.4 Exhaust Pipes Exhaust pipes from internal combustion engines and gas turbine plants shall be provided with proper flame and/or spark arrestors and shall be equipped with water cooled exhaust manifold or be insulated to prevent ignition of combustible gases and be safely vented to the atmosphere in a non-hazardous area.

4.12 Weather Data Recording If a Master Weather Station is not available to support any drilling operations, the drilling location shall have facilities, equipment or knowledgeable personnel to observe, measure and record the weather and sea conditions within the accuracy of the available equipment or observation techniques.

4.13 Diving An offshore drilling unit if required shall be equipped with diving apparatus suitable for the working depths, whenever it is anticipated that the drilling operations shall require assistance by divers based on the rig and in accordance with Volume 3: Health, Safety & Environment.

4.14 Emergency Shutdown Two Emergency Shutdown (ESD) control stations are required as a minimum. One (1) shall be located at the drillers console and another at a readily accessible safe location during all well operations. Units without drillers console shall have readily accessible ESD stations.

4.15 Manning Contractor shall require that a crew of sufficient number as determined by general industry manning levels and with adequate training is available for the operation of all equipment prior to activation of that equipment and that all crew members have or are receiving training relevant to their duties.


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4.16 Support Craft Service, supply and survey craft participating in a drilling programme, including vehicles, aircraft, standby craft and vessels, shall be designed and constructed to operate safely and to provide safe and efficient support for all drilling and related operations for which the craft are engaged, and Contractor shall, upon request, demonstrate to the satisfaction of PETRONAS, that support crafts are capable of safely operating in the environmental conditions prevailing in the area of drilling operations. (Contractor shall make reference to its own internal guideline with respect to the technical specification).


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Section 5: Well Design and Drilling Operations

Wells shall be designed to ensure the well and/or development objectives are met; safely and cost effectively. Casing, primary cementing and drilling fluid programmes shall be engineered to withstand anticipated stresses and should compensateprediction uncertainties. Drilling operations shall be carried out to ensure the well objectives are met with As Low As Reasonably Practicable (ALARP) risk and project/well costs containment. Contractor shall ensure that good oil field drilling practices and continuous improvement are implemented in well design/planning and throughout the drilling operations. Process shall be in place to managedeviations or changes with adequate review, risk assessment and Contractor’s authority’s approval. All wells drilled under the provisions of these procedures shall have been included in the original WPB or its subsequent revision.

5.1 Drilling Unit Moving and Positioning 5.1.1 General Provision A drilling unit shall not be moved to a different well location and anchors shall not be set or retrieved, if weather or sea conditions are such as to threaten the safety of operations or personnel. Drill pipe, drill collars, marine risers and other equipment stored on deck, which may shift during a move, shall be securely tied down before commencing the move. Anchor buoy and pennant lines shall be securely fastened to the bulwark or deck railings.

5.1.2 Anchor Testing for Drilling Unit When anchors are used for holding the unit on position at the wellsite, the anchor lines and anchors shall be tested to the maximum anticipated tension prior to drilling first hole section requiring installation of BOP. If this tension cannot be obtained, Contractor shall take the necessary remedial action. Mooring system analysis, design and evaluation shall be in accordance in accordance to API RP 2SK.

5.1.3 Bottom Supported Unit In areas of known scouring due to bottom current or tide actions and where the drilling unit is bottom-supported, the mat, the legs, faulting, hull or piles, surrounding sea floor shall be inspected regularly. If scour or fill of sea floor sediments or any other condition, likely to threaten the stability of the drilling unit, is evident, measures shall be taken without delay to protect the safety of the unit and the personnel on board.


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When the drilling unit is bottom-supported, the unit shall not be raised or lowered, if weather or sea conditions exceed those allowed in the drilling unit’s Marine Operations Manual to prevent undue risk to the safety of the personnel, operations and drilling unit.

5.1.4 Dynamically Positioned Units A dynamically positioned unit (DP) means a drilling unit or a vessel which automatically maintains its position and heading by means of thruster force. Units and vessels using DP system shall adhere to the latest International Maritime Organization (IMO) and International Marine Contractors Association (IMCA) guidelines on operational requirements, surveys and testing. IMO Equipment class shall be fit for purpose to the operations requirement and risk. IMO Equipment Class 2 and Class 3 or equivalent classification societies class notations DP units and/or vessels with redundancy system based on Failure Mode and Effect Analysis (FMEA) study and proving trials shall undergo annual DP trials by recognised classification societies to ensure safety and reliability of DP systems. Key DP personnel training, competence and experience requirements shall adhere to the latest IMCA M117 guideline. Trial reports and key DP personnel qualifications and experience records shall be made available upon request by PETRONAS.

5.1.5 Diving Operations Diving operations shall be undertaken only when in the opinion of the diving supervisor, sea and weather conditions permit these operations to be conducted safely and while they are being conducted, no other operations which may adversely affect the safety of the operations shall be conducted. Diving equipment shall be properly maintained and checked at the surface before commencing any diving operations and each diver shall maintain a personal log book detailing his dives and medical history.

5.2 Casing and Cementing For the purpose of this procedure, the casing strings in order of normal installation are: drive pipe or structural casing, conductor, surface casing, intermediate casing and production casing.

All casings shall be manufactured in compliance with API or ISO quality standards. Casing programme shall be designed to withstand anticipated stresses and should compensate for any prediction uncertainties.


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5.2.1 Drive Pipe This casing shall be set in a competent bed, with the objective of supporting unconsolidated formation and obtaining drilling fluid returns to surface. Normally driven to refusal or set at depth sufficient for its objective.

However, the presence of abnormally strong formations may permit the setting of this casing at a depth shallower than theoretically required. If this portion of the hole is drilled, it shall be cemented with a quantity of cement sufficient to fill the calculated annular space back to the sea floor (or surface for onshore).

5.2.2 Conductor Casing The initial conductor casing string shall be set in a competent formation (normally between 150 metres and 300 metres TVD below the sea floor (or surface for onshore)) and shall be based upon relevant engineering and geologic factors including the presence or absence of shallow gas, potential hazards and water depth. In cases where the conductor casing is set deeper than 300 metres below sea floor (or surface for onshore) and BOP pressure control is considered while drilling below the conductor casing shoe, a formation pressure integrity test shall be performed as required under Section 5.6. Unless jetted-in, the initial casing string shall be cemented with a quantity of cement sufficient to fill the calculated annular space back to the sea floor (or surface for onshore). The excess volume shall be as specified in Section 5.2.9 or based on field experience. The cement may be washed out to a depth not exceeding the depth of the structural casing shoe to facilitate casing removal upon well abandonment. Conductor casing may be eliminated at specific well locations if at least one (1) well has been drilled adjacent to the specified well location and well logs and mud monitoring procedures demonstrate the absence of shallow hydrocarbons or hazards. If shallow hydrocarbons are present and Contractor can exhibit that the well can be safely drilled without a conductor casing being set, then the conductor casing may be eliminated with prior approval from PETRONAS.


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For deepwater operations, conductor casing may be eliminated if geological factors, shallow hazards, and well structural integrity are maintained.

5.2.3 Surface Casing Surface casing setting depths shall be based upon relevant engineering and geologic factors, potential hazard, presence and absence of shallow gas (normally between 450 metres TVD and 1400 metres TVD below the sea floor (or surface for onshore)). Surface casing may be set at a depth where the formation strength is sufficient to support the programmed mud gradients for the next section of the hole and where the well control integrity can be provided until the next string of casing is set. Surface casing shall be cemented to surface or sea floor for subsea wells. After drilling out the surface casing shoe, a formation pressure Integrity test shall be performed as required under Section 5.6.

5.2.4 Intermediate Casing One or more strings of intermediate casing shall be set when required by anticipated pressures, mud weight, sediment, and other well conditions. The proposed setting depth for intermediate casing shall be based on the formation strength below the surface casing shoe or previous intermediate casing string. Intermediate casing shall be cemented with a calculated volume of cement sufficient to fill the annular space in the open hole to 150 metres above the highest hydrocarbon or freshwater bearing sand, or one-third of intermediate casing length, whichever is greater. If the intermediate casing is a liner, a minimum liner lap of 30 metres above the previous casing string shoe shall be applied. The liner lap shall be cemented and tested to determine whether a seal between the liner top and the next larger string has been achieved. For subsea wells, the top of cement may be kept below the surface casing shoe to prevent annular pressure build-up from causing failure to the surface or intermediate casing strings.

5.2.5 Production Casing This string shall be set before completing the well for production.


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A calculated volume of cement sufficient to fill the annular space at least 150 metres above the uppermost hydrocarbon zone or one-third of production casing length, whichever is greater, shall be used. When a liner is used as production string, it shall be lapped a minimum of 30 metres into the previous casing string, and the seal between the liner top and the next larger string shall be tested.

5.2.6 Casing Pressure Test After cementing, all casing strings shall be tested to verify integrity to withstand anticipated operating loads. As a minimum, the test pressure shall be as the following: Cemented Conductor - 200 psi Surface - 1000 psi Intermediate and Production - 0.73 psi/m TVD or 1500 psi whichever is greater Intermediate and Production liner (and liner-lap) shall be tested to a minimum of 500 psi above the formation fracture pressure at the casing shoe into which the liner is lapped, where permissible. However, the test pressure should not exceed 85% of the internal yield pressure of the casing. The casing shall be pressure tested for 15 minutes, and if the pressure declines more than 10%, remedial action shall be performed prior to drilling ahead, unless prior approval is obtained from PETRONAS. Note: Conductor casing pressure test is waived for deepwater operations After cementing any casing string, pressure testing of the casing can be conducted either upon bumping of the plug or after sufficient waiting time has lapsed based on cement laboratory test data. Avoidance of micro-annulus between cement and casing shall be considered. In case of back flow at the end of cementing operations, back pressure shall be applied until cement has set. Laboratory test data for the particular cement mix used in the well shall be used to determine the setting time required. Before drilling out of the casing shoe, sufficient time shall have elapsed to allow tail slurry to attain a compressive strength of at least 500 psi.


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Prior to any operations that put a well in an underbalanced mode or removal of hydrostatic barrier (such as switching to lighter fluid), a negative pressure or inflow test at a pressure below the lowest planned hydrostatic pressure shall be performed on casing and/or liner exposed to negative pressure and also mechanical barriers such as formation isolation valves, retrievable packers/plugs, etc. Contractor shall provide test procedures and criteria for a successful test in the NOOP or at an appropriate time prior to conducting the test.

For deepwater operations, prior to riser displacement to seawater, a negative test shall be performed. 5.2.7 Records The result of all casing pressure tests shall be witnessed by Contractor’s representative and recorded on the Driller’s log. This data shall be made available upon request by PETRONAS.

5.2.8 Cementation Cement and materials for well cementing shall conform to latest API Specification 10A. Well cement test shall conform to API RP10B-2/ ISO 10426-2 and deepwater well cement test shall conform to API RP 10B-3/ISO 10426-3. The cementation of surface casing, intermediate casing, production casing and liner shall be performed by conventional displacement method. In addition to cement slurry, preflush and spacer design, pipe centralisation to achieve optimum standoff and pipe movement shall be considered to improve drilling fluid removal and cement placement quality. A cement placement, centralizer placement, Equivalent Circulating Density (ECD), fluid displacement and applicable stress-analysis engineering software simulation shall be performed to support cementing design. Cementation design reports, post-job data and cement bond evaluation log result if any for all individual casing primary cementing operations shall be submitted to PETRONAS upon request. Other industry acceptable methods may be used such as inner string cementing or simply cementing without the use of wiper plugs where deemed appropriate without compromising primary cementation quality.

Cementing float equipment or other means of preventing backflow


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(U-tubing) of cement during cementing shall be incorporated into a casing string with thread locking compound. For conventional displacement method, a float collar shall be inserted in the casing string above one or two joints of casing above a float shoe. The float equipment performance criteria shall correspond to the anticipated service requirements per latest API RP 10F.

5.2.9 Excess Cement Volume The volume of cement slurry to be placed in the open hole annulus interval shall be based on the calculated annular volume using an estimated hole size plus and excess of cement slurry based on similar field experience or best practices or the following percentages of excess slurry: Structural - 100% excess Conductor - 50% excess Surface - 30% excess Intermediate or production - most accurate caliper available + 10% excess

5.2.10 Inadequate Cement Job Where indications exist that cementation quality is such that well integrity or objectives are jeopardised, Contractor shall inform PETRONAS and ensure that remedial action is taken without any delay. Contractor should run cement bond evaluation log. 5.3 Well Directional Survey 5.3.1 Vertical Well First surveys shall be taken at depth no greater than 60 metres below surface or mudline. Subsequent surveys shall be taken at 150 metres intervals but will not exceed 300 metres. Copies of all surveys regardless of their status shall be filed with PETRONAS. The report shall include but not limited to all tabulation of accumulated inclination angles, the TVD and vertical section. 5.3.2 Directional Well For wells with inclination greater than or equal to 5 degrees, first survey shall be taken at a depth no greater than 60 metres below drive pipe or conductor shoe, whichever is the first string of set casing. Subsequent surveys giving both inclination and azimuth shall be obtained on all directional wells at intervals not exceeding 150


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metres during the normal course of drilling, i.e. tangent sections. Two successive directional survey readings shall not exceed 30 metres in all planned angle and/or directional change portions of the hole. Anti-collision shall be taken into consideration. PETRONAS may require Contractor to submit the anti-collision report upon request. Copies of directional surveys report shall be submitted to PETRONAS. The reports shall include but not limited to the tabulation of the accumulative drift angles, direction, TVD, vertical section and the rectangular coordinates of each shot point. In calculating all surveys, a correction from true north to Universal Transverse Mercator Grid North shall be made after making the magnetic to true north correction.

5.4 Well Control Equipment and Testing 5.4.1 BOP System BOP equipment shall consist of an annular preventer and the specified number of ram-type preventers. Annular preventer shall be able to seal around any size of pipe in use, close on open hole and allow for drill pipe stripping. The pipe rams shall be of proper size to fit the pipe in use. The working pressure rating of any BOP component shall exceed the maximum anticipated surface pressure to which it may be subjected to. Unless otherwise specified herein, all BOP systems shall conform to API Standard 53 (latest edition) specification.

Elastomeric components rating shall be suitable for the operating environment and compatible with the drilling and completion fluid in use. All spare parts shall be from Original Equipment Manufacturer (OEM). BOP closing times shall as a minimum meet API Standard 53.

If any repair or replacement of surface or subsea BOP stack is necessary after its installation, this work shall be performed after the well has been secured as per Section 9.10.

5.4.2 Auxiliary Equipment The following auxiliary equipment shall also be provided: a) An inside BOP and a full-opening drill string safety valve in the open position with wrenches for operating the valves shall be maintained on the rig floor at all times while drilling operations


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are being conducted with crossovers if necessary; and b) A safety valve and circulating head shall be available on the rig floor, assembled with the proper connection to fit the casing that is being run in the hole at the time

5.4.3 Diverter System A diverter system shall be capable of diverting well flow away from the rig to provide protection for the drilling crew and rig equipment. It is installed to control well flows encountered at shallow depths and when the last string of casing is set in a formation of insufficient strength such that the well cannot be shut-in because of the danger of the flow broaching to the surface.

The diverter system shall conform to API RP 64 (latest edition) specification. As a minimum the system shall provide an annular preventer, with a spool below having two diverter lines (6” minimum I.D. for land rigs and 10” minimum I.D. for offshore rigs). The diverter lines shall have smooth bends and shall vent in different directions to permit downwind diversion.

In known areas, for second and subsequent wells from a platform where electrical logs have proven no hydrocarbons and/or other risk are present in the entire hole section drilled below the first casing string, drilling without a diverter may be acceptable. Contractor shall inform PETRONAS accordingly.

5.4.4 Surface BOP Stack The minimum stack requirements for drilling below any casing strings with surface BOP stack are described below: Surface BOP Stack Drive or structural - 1-Diverter Conductor - 1-Diverter Surface - Annular, 2-Pipe Rams and 1-Blind Shear Ram Intermediate - 1-Annular, 2-Pipe Rams and 1-Blind Shear Ram Blind shear ram – capable to shear and seal all grades of drill pipe used through the stack. When a tapered drill string is in use, the following alternatives shall apply:

a) A set of pipe rams to fit the smaller string of drill pipe installed in


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the existing BOP stack; or b) Variable bore rams may be fitted in place of one or both sets of pipe rams; or c) An additional set of BOP equipped with a set of pipe rams to fit the smaller string of drill pipe

5.4.5 Subsea BOP Stack The minimum stack requirements for drilling below any casing strings with subsea BOP stack are described below: Subsea BOP Stack Conductor - Riserless Surface - 1-Annular, 2-Pipe Rams and 1-Blind Shear Ram Intermediate - 1-Annular, 2-Pipe Rams and 1-Blind Shear Ram When a tapered drill string is in use, the following alternatives shall apply: a) Variable bore rams may be fitted in place of one or both sets of pipe rams; or b) A second annular preventer may be used in lieu of pipe rams to seal the smaller strings; or c) An additional set of BOP equipped with a set of pipe rams to fit the smaller string of drill pipe Subsea BOP stack shall be equipped with:

a) Blind shear ram – capable to shear and seal all grades of drillpipe used through the stack; b) A subsea accumulator system or suitable alternate is required to provide fast closure of the preventers and for cycling all critical functions in case of loss of power fluid connection to the surface; c) A fail-safe design shall be incorporated into the BOP system and shall include dual pod control systems and fail-safe valve on critical lines and outlets; and d) Remotely Operated Vehicle (ROV) intervention capability, which at a minimum shall allow the operation of functions conforming to API Standard 53

All DP drilling units operating with subsea BOP stack shall be equipped with the following secondary intervention systems (refer to Definitions Section):


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a) Autoshear b) Deadman c) Emergency Disconnect system (EDS)

Autoshear, deadman and EDS are optional for moored drilling units.

Floating drilling units operating with Surface BOP (SBOP) system with drilling riser designed to contain wellbore pressure shall be equipped with a Seabed Isolation Device (SID).

Prior to the removal of marine riser, the riser shall be displaced with sea water after successful negative test. Contractor shall ensure that sufficient hydrostatic head exists within the well bore to compensate for the reduction in head and maintain a safe well condition, where possible.

5.4.5.1 Subsea BOP Diversion Drilling units that utilise a subsea BOP stack and marine riser shall be fitted with a diverter system to safely manage gas in the marine riser. This shall include two (2) diverter/overboard lines arranged to be as straight as possible to minimise erosion. The diverter lines shall be individually selectable,and arranged to allow overboard discharge in a safe manner in any prevailing wind direction. The diverter line system shall be equipped with automatic, remotely controlled full opening valves, which open prior to closing the diverter element.

For Managed Pressure Drilling (MPD) and other operations, when a rotating control device is installed on the marine riser, it is not required to simultaneously have the marine riser diverter system available.

5.4.6 BOP Test Every drilling unit shall have a written BOP equipment testing procedure.

5.4.6.1 BOP Control System A minimum of two (2) BOP control stations shall be provided. One (1) station shall be on the drilling floor and another stationlocated at a remote readily accessible safe area. Accumulators or pumps shall maintain a pressure capacity reserve at all times to provide for repeated


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operations of hydraulic BOPs. The control panel shall be fitted with alarms for low accumulator pressure as well as for low level in the control fluid reservoir.

5.4.6.2 Pressure Test For initial BOP system acceptance test, each component of the BOP stack assembly and related control equipment shall be pressure tested to their rated working pressure. Subsequent pressure test shall be the maximum anticipated surface pressure (or maximum anticipated wellhead pressure for subsea BOP) and up to 70% of rated working pressure for annular preventer. A 200 – 300 psi low pressure BOP test shall be conducted prior to high pressure test to maximum anticipated surface pressure. Each test shall hold the required pressure for 5 minutes with no indication of leakage. All test records shall be made available upon request by PETRONAS. The BOP equipment shall be tested according to the following procedures:

a) When installed or stump tested prior to installation; b) Not less than once in 14 days beyond that period PETRONAS approval shall be obtained. However, the blind shear ram may not be tested; c) Before drilling out after each string of casing has been set and cemented or relevant element and connection to be tested provided not exceeding 14 days between tests; and d) Following repairs that require disconnecting a pressure seal in the assembly

Note: 1. Ram bonnets shall be tested every time opened 2. After installation of subsea BOP stack onto the wellhead, the BOP-to-wellhead connector pressure test may be limited to the maximum anticipated wellhead pressure in the next hole section

5.4.6.3 Function Test While drill pipe is in use, the following actuation procedures shall be performed, as a minimum, to determine proper functioning of the BOP and control stations:

a) Pipe rams: Actuated weekly, and after nippling up; b) Blind shear rams: Actuated whilst drill pipe is out of


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the hole, after stack is nippled up, once each trip but not more than once each day (except for subsea BOP); c) Tapered drill string pipe rams: Actuated weekly, and after nippling up; d) Annular-type preventer: Actuated on the drill pipe, in connection with the pressure test, once each week; e) Actuation of control station shall be alternating between primary and remote BOP control stations; f ) Subsea BOPs shall be actuated at least on weekly basis. Shear rams shall be function tested prior to drilling out each set casing; and g) Auto shear, deadman and ROV intervention operating systems shall be function tested during subsea BOP stump test. 5.4.7 Inspection and Maintenance BOP system shall undergo an assessment by an industry recognised third party well control equipment and system authority when a drilling unit initially comes under contract. All critical actions from the assessment shall be closed out prior to drilling. Shearing capability of shear rams shall be verified either by testing or review of previously conducted test data. The report shall be made available upon request by PETRONAS. All BOP systems and marine risers and associated equipment shall be inspected and maintained in accordance with the manufacturer’s recommended maintenance procedures. Inspection of subsea installations shall be accomplished by the use of ROV, rig camera or divers. This requirement will be waived for a period not to exceed 4 days in the event of a ROV or rig camera breakdown. All BOP tests, maintenance and inspection shall be recorded on the Driller’s log.

5.4.8 Personnel Competency All supervisory drilling personnel shall be in possession of a valid industry recognised well control training certificate and be fully familiar with well control procedures and BOP equipment before starting work on a well. Well control drills and response time shall be recorded on the Driller’s log. Drill objectives and acceptable response shall be predefined. Regular and realistic drills shall be conducted to train involved


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personnel to achieve the acceptable response.

5.5 Drilling Fluid Programme The characteristics used, testing of drilling fluid and the implementation of related drilling procedures shall be designed to prevent the loss of well control. Quantities of drilling fluid materials sufficient to provide well control shall be maintained readily accessible for use at all times.

5.5.1 Primary Well Control Before starting pulling out of the hole with drill pipe, the drilling fluid shall be properly conditioned. Proper conditioning means that:

a) There is no indication of influx of formation fluids prior to pulling the drill pipe out of the hole; b) The weight of the returning drilling fluid is essentially the same as the drilling fluid entering the hole; and c) Other drilling fluid properties recorded on the daily drilling log are within the specified ranges required to drill the hole.

When the drilling fluid in the hole is circulated, the Driller’s log shall be monitored. When coming out of the hole with the drill pipe, the annulus shall be filled with drilling fluid to ensure sufficient over balance (at least 0.3 ppg or 100 psi) whichever is less is maintained at all time.

For operations where narrow margins prevent a 0.3 ppg or 100 psi overbalance, other methods, such as pumping out of hole, reduced tripping speeds and increased frequency of flow checks should be employed to maintain well control. A device for measuring the amount of drilling fluid to fill the hole shall be used. If there is at any time an indication of swabbing or influx of formation fluids, the necessary safety devices and action shall be employed to control the well. The drilling fluid in the hole shall be circulated or reverse circulated prior to pulling drill-stem test tools from the hole.

The hole shall be filled by accurately measured volumes of drilling fluid. The following information shall be posted near the driller: a) The number of stands of drill pipe and drill collars that may be pulled between the times of filling the hole;


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b) The number of barrels and pump strokes required to fill the hole for the designated number of stands of drill pipe and drill collars; c) For each casing string, the maximum pressure that can be contained under the BOPs before controlled bleeding off excess pressure through the choke. Drill pipe pressure shall be monitored when bleeding off pressure for well control; and d) Where continuous fill trip tank equipment is used, only the number of barrels required to fill the hole per stand of drill pipe or drill collars and the maximum allowable casing pressure need be posted

An operable degasser shall be installed in the drilling fluid system prior to commencement of drilling operations. It shall be maintained for use throughout the drilling and completion of the well.

If any variant of MPD method is used for more precise control of well annular pressure profile, Contractor shall ensure that MPD procedures are in place as well as risk assessment/Hazard and Operability (HAZOP) analysis and personnel familiarisation training are completed. Contractor shall select the MPD method that best addresses drilling problems cost effectively.

5.5.2 Drilling Fluid Test Drilling fluid testing equipment shall be maintained on the drilling rig at all times, and drilling fluid tests shall be performed once every 12 hours or more frequently as conditions warrant. Such tests shall be conducted in accordance with procedures outlined in API RP 13B, latest revision, or other relevant codes and the results recorded and maintained at the drill site. The following drilling fluid system monitoring equipment shall be installed with derrick floor indicators and used at the point in the drilling operations when drilling fluid returns are established and throughout subsequent drilling operations: a) Recording mud pit level indicator to determine mud pit volume gains and losses. This indicator shall include a visual and audio warning device; b) Drilling fluid volume measuring device for accurately determining drilling fluid volumes required to fill the hole on trips; c) Drilling fluid return indicator to determine that returns essentially equal the pump discharge rate; and


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d) Gas-detecting equipment to monitor the drilling fluid returns

5.5.3 Drilling Fluid Quantity Sufficient drilling fluid materials shall be stored on the drilling unit to meet any normal and foreseeable emergency conditions. Subject to the above, and taking into account the availability of the drilling fluid storage capacity of the drilling unit, the minimum quantities of drilling fluid materials required shall be based on the following: a) The quantity of the drilling fluid materials shall be based on renewing a volume of the calculated capacity of the active drilling fluid system; and b) The quantity of the weighting material shall be based on the amount required to increase the drilling fluid density of the active drilling fluid volume to overcome the highest anticipated formation pressure for the hole section to be drilled

When the drilling fluid quantity required exceeds the storage capacity of the drilling unit, the Contractor shall demonstrate that the drilling fluid inventories on hand are sufficient to maintain well control until additional quantities can be delivered to the well site.

Drilling operations shall be suspended in the absence of minimum quantities of drilling fluid material as specified above.

5.6 Formation Integrity Test Before drilling to a maximum of 3 metres of new hole below the surface casing (if set below 300 metres below seabed) and intermediate casing shoe, a pressure test shall be performed to obtain data to be used in estimating the formation fracture gradient. This test can be stopped when sufficient knowledge of the field has been gathered. Pressure data shall be obtained by either testing to formation leak-off or to a controlled formation capability test. The results of this test shall be recorded in the Driller’s log and used to determine the depth and maximum mud weight to be used in drilling the next interval of open hole. If during the course of drilling the hole, the mud weight approaches within 0.5 ppg (0.026psi/ft) of the formation fracture gradient or the formation capability test, Contractor shall exercise prudent drilling practice to ensure well integrity and safety of the operations.


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5.7 Lost Circulation During all normal drilling operations below the conductor, drilling shall cease immediately whenever the drilling fluid pumped down the drill pipe is not returning to the surface and drilling shall not be continued until adequate circulation has been established. In case of known areas or zones of loss circulation, it may be permissible to drill ahead with continuing losses guided by operational and contingency procedures. Contractor shall exercise prudent drilling practices to ensure well integrity and safety of the operations.

5.8 Detection of Overpressure Characteristics of the formation lithology and the formation fluid content shall be monitored continuously after setting structural casing during exploration drilling to detect the transition from normally pressured formations to abnormally high pressured formations which normally include but not limited to monitoring of: a) Shale gas in the drilling fluid returns; b) The shape of shale chips in drill cuttings; c) The normalised drillability trend of the shale and in conjunction the plotting of ‘dc’ exponent values derived from the rate of penetration or subsequent modification of it; d) The change in temperature and salinity of the drilling fluid returns; and e) Indications of hole squeezing due to bore hole instability, torque and drag

If a transition into an over-pressured formation is indicated, Contractor shall take steps to attempt to verify the pressure of the transition zone using recognised techniques when prudent to do so, and to maintain primary control of the well as drilling proceeds into the over-pressured formation, including modifying the drilling programme and equipment as required.

5.9 Suspension of Operations In the event of a fatal accident, those operations associated with the fatality shall be suspended as soon as safely possible and shall not be resumed without the approval of the Police (Royal Malaysia Police) or other relevant authority. An operation shall be suspended as soon as possible if the continuation of the operation causes, or is likely to cause an oil spill; or endangers, or is likely to endanger, the safety of personnel, the security of the well, the safety of the drilling unit and the operation shall remain suspended until it can resume


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safely. Conditions under which drilling shall be suspended in the case of a drilling unit: a) Inability to maintain primary well control; b) Problems are experienced with critical BOP system component or control system; c) Failure of wellhead, casing or drilling fluid system; d) Uncontrolled fire at the drilling site; e) Failure of a significant portion of the primary power source; f ) Inability to maintain adequate stability and buoyancy of the drilling unit; g) Inability to satisfactorily maintain the position of the drilling unit over the well; h) Excessive motions of the drilling unit caused by sea-state or weather conditions; i ) While diving operations are being conducted at or near any part of the subsea drilling system

All large scale incidents or accidents causing damage to equipment shall be immediately reported to PETRONAS in writing giving estimated cost of damage, downtime and root cause.

5.10 Shallow Hazards and Hydrocarbons In all areas where shallow hazards or hydrocarbons are known, seismic data shall be obtained. An appropriate shallow hazard contingency plan shall also be in place. All seismic data relating to shallow hazards shall be submitted to PETRONAS. Well locations shall be selected where the risk associated with shallow hazard is avoidable or manageable. A well location shall if possible be moved if the potential consequences and/or possible presence of a shallow hazard are significant (i.e. moderate or high).

For drilling operations with a bottom supported drilling unit and/or drilling from a fixed structure where presence of shallow hazards or hydrocarbons are possible, a small diameter initial pilot hole of 8-1/2 inch or smaller size from the bottom of the conductor casing to the proposed surface casing seat shall be drilled and logged to aid in determining the presence or absence of these hazards.

For drilling operations with floating drilling unit (not from a fixed structure), systems and procedures shall be in place to continuously monitor the operation for indications of a shallow hazard, and to ensure the safe and swift move of the drilling unit to a position that is sufficiently remote from the area of possible hazard or disturbance caused by any uncontrolled flow of formation fluids.


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5.11 Underbalanced Drilling Underbalanced drilling is defined as deliberately drilling where the pore pressure of the formation being drilled is greater than the hydrostatic pressure exerted by column of drilling fluid and formation fluids are allowed to flow into wellbore. In this respect, balanced pressure drilling is a subcategory of underbalanced drilling because the annular pressure is expected to fall below the formation pressure during pipe movement. In general, underbalanced drilling is aimed at improving drilling rate, limiting lost circulation and protecting reservoir formation. Underbalanced drilling shall be conducted only when the requirements below are satisfied and subject to further discussion and approval by PETRONAS prior to execution: a) Assessment of risk and benefit of underbalanced drilling (economic and technical justification to change from conventional drilling); b) Assessment of fluid type to be used (gas, mist, foam, gasified liquid and liquid); c) Identification and assessment of equipment to be used that covers both surface and sub-surface (gas compression, gas generation, separation, foam, pressure control, downhole tools, BOP stack, rotating head, etc.); d) Preparation of detailed underbalanced design programme (fluid design, expected Rate of Penetration (ROP), wellbore model, fluid velocity, cutting transport, cost analysis, etc.) and contingency plans; and e) Environmental and safety concerns associated with underbalanced drilling shall be addressed and documented. A primary consideration of environmental protection shall include handling of returning fluid from wellbore.

5.12 H2S Drilling Operations When operations are undertaken involving formations or reservoirs known or expected to contain Hydrogen Sulphide (H2S) or, if unknown, upon encountering H2S, the following preventive measures shall be taken to control the effects of the toxicity, flammability and corrosive characteristics of the H2S gas.

5.12.1 Physical Properties and Toxicity H2S is a highly toxic gas, rapidly causing death when inhaled in high concentration. Its toxicity is almost the same as hydrogen cyanide and is between five and six times more toxic than carbon monoxide. H2S is heavier than air with specific gravity of 1.189 and it is colourless. It forms an explosive mixture with air between 4.3 and 46.0 percent by volume. The acceptable maximum concentration for


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a continuous eight hours exposure of personnel is 10 parts per million (ppm) in air, which is 0.001% by volume.

5.12.2 Breathing Equipment An adequate number of self-contained positive pressure breathing equipment shall be made available at all times on the rig floor, shale shaker, mud pit area, pump area and other areas where H2S might accumulate in hazardous quantities. All essential personnel in drilling operation shall be required to use this equipment when necessary. Resuscitators with spare oxygen bottle shall be provided at each emergency centre. A cascade air-bottle system shall be provided to refill the self-contained breathing equipment bottles. At any time and in the vicinity where the concentration of H2S in the atmosphere exceeds 20 ppm, breathing equipment shall be worn. 5.12.3 H2S Gas Detection Automatic continuous H2S sensors shall be installed, be in working condition and routinely function tested according to API RP14C to cover as a minimum the areas of bell nipple, flowline and shale shakers, mud pits, sack room, motor room and living quarters. These sensors shall activate audible and visual alarms when sensing a minimum of 5 ppm of H2S in atmosphere. In addition, portable hand operated type H2S gas detectors shall be made available to all essential personnel during drilling operation in H2S environment.

5.12.4 Wind Direction Equipment Wind direction equipment (such as wind sock and wind streamers) shall be installed in sufficient quantity at prominent locations to indicate to all personnel on or in the immediate vicinity of the facility the wind direction at all times for determining safe upwind areas in the event that H2S is present in the atmosphere. 5.12.5 Ventilation Ventilation devices shall be explosion proof and situated in areas where H2S may accumulate. Movable ventilation devices shall be provided in work areas and be multi-directional and capable of dispersing H2S away from working personnel.


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5.12.6 Personnel Training All personnel shall be informed as to the hazards of H2S. They shall be trained in the use of H2S safety equipment, informed of H2S detectors and alarms, ventilation equipment, prevailing winds, briefing areas, warning systems and evacuation procedures. All crew members shall be familiar with basic first-aid procedure applicable to victims of H2S exposure. Emphasis shall be placed upon rescue and first aid for H2S victims.

5.12.7 Contingency Plan A contingency plan shall be developed and a copy shall be submitted to PETRONAS prior to the commencement of drilling operation in H2S environment. The plan shall include but not be limited to the following: a) Physical property, toxicity level and physical effect of H2S; b) Safety procedures, equipment and training; c) Operating procedures during; • Conditionswithlessthan10ppmH2S in the atmosphere. • Conditionswithmore than 10 ppm but less than 20 ppm H2S in the atmosphere (limited danger to life). • Conditionswithmorethan20ppmH2S in the atmosphere (high danger to life). d) Responsibility and duty of personnel for each operating condition; e) Evacuation plan; and f ) Agencies to be notified during emergency

Information on emergency procedures shall be posted in Bahasa Malaysia and English at prominent locations on the operations facilities.

5.12.8 Drilling Unit Equipment H2S gas is highly corrosive to steel and at high stress levels, Sulfide Stress Cracking (SSC) may occur in a very short time. All tubulars, wellhead equipment, and other drilling related equipment which may be exposed to H2S conditions and susceptible to SSC shall be selected in accordance with the guideline presented in National Association of Corrosion Engineers (NACE) MR0175/ISO15156 considering metallurgical properties and/or environment in contact with the tubulars and equipment in order to reduce the chances of


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failure due to SSC.

5.12.8.1 Drill Pipe To reduce potential failure due to SSC, steel drill pipe should have a yield strength of 95,000 psi or less, unless it is heat treated by quenching and tempering. Alternatively control of the environment in contact with the drill pipe shall be considered. Assessment shall be conducted to ensure risk of drill string failure is ALARP. 5.12.8.2 Tubulars Tubulars including casing, tubing, coupling, flange and related equipment shall be designed for H2S service. Field welding on casing, except conductor and surface casing strings is prohibited, unless the Contractor can prove it is safe to do otherwise.

5.12.8.3 BOP and Related Equipments BOP, choke line, choke manifold and valves shall be designed and fabricated for H2S service utilising the most advanced technology. Elastomer, packing and other non-ferrous part exposed to H2S shall be resistant at the maximum anticipated temperature of exposure.

5.12.8.4 Flare System The flare system shall be designed to safely collect and burn H2S gas. Flare lines shall be located as far away from the operating facilities as feasible in the manner to compensate for wind changes. The flare shall be equipped with a pilot and an automatic igniter.

5.12.9 Drilling Operations 5.12.9.1 Pipe Trips and Stripping Every effort shall be made to pull drill string dry while maintaining well control. If it is necessary to pull the drill string wet after penetration of H2S bearing zones, monitoring of H2S of the working areas shall be increased. The monitoring of H2S in the vicinity of the displaced drilling fluid returned shall also be increased.

5.12.9.2 Well Control If gas cutting of drilling fluids beyond 0.2 ppg is


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encountered, the BOP shall be closed while maintaining drilling fluid circulation through the choke line to the mud-gas separator. The mud-gas separator shall be connected into the flare system. The degasser shall be used until the drilling fluid is free of entrained gas.

5.12.9.3 Coring When coming out of the hole with a core barrel under suspected H2S condition, the drilling crew shall wear breathing mask before pulling the last twenty stands or at any time H2S is detected at surface. “Mask on” shall continue while opening the core barrel and examining the cores. Cores to be transported shall be sealed and marked for the presence of H2S. 5.12.9.4 Drilling Fluid Suitable water or oil base drilling fluid should be used in drilling formations containing H2S gas. A pH of 10.0 and above shall be maintained in a water base mud to control corrosion and prevent SSC. Consideration shall also be given the use of H2S scavengers in both water and oil base drilling fluid systems. Sufficient quantities of additives shall be maintained at well site for addition to neutralise H2S picked up by the drilling fluid system. Drilling fluid containing H2S shall be degassed and the gases removed shall be burned with the flare system and shall be continuously monitored for H2S concentration. 5.12.10 Well Testing Operations During well test, the level of H2S concentration shall be monitored at first hydrocarbon to surface and at regular intervals subsequent to first hydrocarbon. All produced gases shall be burned with the flare system if the gases are flammable. All well test equipment, well head equipment and tubular goods shall meet the H2S service requirement. Drill pipe shall not be used for testing well with H2S. The water cushion shall be inhibited in order to prevent H2S corrosion. The test equipment shall be flushed with treated fluid for the same purpose at the end of the test.


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5.13 HPHT Drilling Operations Wells having an undisturbed bottom hole temperature (BHT) greater than 300 °F (149 °C) and maximum pore pressure exceeding 0.8 psi/ft or requiring pressure control equipment with a rated working pressure in excess of 10,000 psi shall adhere to the following procedures. Contractor should consider the following procedures for high pressure (HP) wells.

5.13.1 Risk Management HSE considerations shall have the utmost priority in all phases of planning and execution of HPHT well construction, completion, testing and abandonment.

Drilling, completing, testing and abandoning wells in HPHT environments are riskier due to being complex, having a higher probability of well control incident and of equipment failure. Thus all geological and operational hazards shall be identified and assessed. A Risk Management Plan shall be in place, covering hazard detection, preventive or risk reduction actions, consequence mitigation and Management of Change (MOC) process.

5.13.2 Personnel Training Skilled and experienced personnel guided by good operational procedures and practices are a paramount prerequisite for HPHT well engineering and construction. Personnel involved in planning and execution (including Drilling Engineers, Superintendents, Supervisors, Geologist, third party contractors and rig crew) shall have proven experience of HPHT operations and undergo suitable HPHT training, to understand the HPHT well engineering, equipment, operations, uncertainties and constraints. Training shall also focus on safety awareness, communication, roles and responsibilities, H2S likelihood and well control matters. Persons requiring HPHT training shall work under the supervision of suitably experienced persons.

5.13.3 Preparation and Planning HPHT geological and geotechnical expertise shall be available to ensure sound and reliable well design parameters and down-hole predictions/simulations, since these are the basis for well design, equipment selection, contingency plans and identification of uncertainties that shall be addressed to successfully meet well objectives safely and with low NPT.

Whilst considering HPHT exploration and/or appraisal well data acquisition programme, Contractor shall consider and obtain all


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necessary data needed to engineer and plan the potential HPHT development wells.

An input assumption document shall be prepared for all HPHT wells and form the basis for well design. All safety critical parameters such as pore/fracture pressure prediction, temperature prediction, fluid description, H2S and testing/production requirements shall be clearly documented and verified. In addition, development wells input assumptions shall consider production fluids characteristics, rates and life of well.

Contractor shall have independent verification of the input assumption document by an industry recognised third party or a competent technical authority within Contractor’s organisation independent of the HPHT project. The report shall be made available upon request by PETRONAS.

5.13.4 Well Engineering and Design An HPHT Drilling, Completions and Testing Operations manual shall be in place detailing the standards and procedures and practices for drilling and tripping, flow checks, fingerprinting, formation evaluation, coring, well control, testing, completions, plug & abandonment and emergency response. It shall also include barrier philosophy and verification plans. This document shall be bridged with drilling contractor’s Safety Management System.

An HPHT Well Control plan shall be prepared. The plan shall encompass kick prevention and detection and also details on various shut-in scenarios, killing and circulating kick methods. The plan shall consider all necessary equipment requirement and availability.

A life-of-well development well design shall be in place addressing annulus gas migration risks to ALARP. Contractor shall identify safety critical cementation and qualify proposed cementation to ensure the cement will not degrade at elevated temperatures or when subjected to very large stress changes associated with pressure changes within the well.

Contractor shall have independent verification of the final well designs by an industry recognised third party or a competent technical authority within Contractor’s organisation independent of the HPHT project. The report shall be made available upon request by PETRONAS.


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5.13.5 Drilling Unit and Equipment Drilling units proposed for HPHT operations shall be audited for HPHT technical fitness for purpose and readiness by an industry recognised third party authority in HPHT drilling rig auditing. All critical actions from the audit shall be duly closed out prior to drilling any HPHT hole sections. The report shall be made available upon request by PETRONAS.

Relevant information on Emergency Response Plan shall be posted in Bahasa Malaysia and English at prominent locations on the operations facilities.

Contractor shall ensure that all tubular, connections, wellheads, completion equipment, testing equipment and other safety critical equipment are qualified for proposed design loads and production fluids. A QA/QC plan shall be agreed and implemented with the equipment supplier.

5.13.6 Contingency Plan A Blowout Contingency Plan (BOCP) for suitably rated relief well shall be submitted to PETRONAS in the NOOP in accordance with Section 13.3.

As for development wells, an assessment of the effect of reservoir compaction and depletion shall be conducted to verify that development wells are suitably designed to mitigate any loss of integrity due to the effects.


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Section 6: Formation Evaluation

Contractor shall obtain sufficient well data and samples during operation to permit geological and reservoir evaluation of the well and to achieve all well objectives while ensuring operation safety and wellbore integrity. The applicable formation evaluation data and reports shall be made available to PETRONAS in a proper and timely manner.

6.1 Drill Cutting Sampling

6.1.1 Sample Frequency The frequency of sampling drill cuttings for geological purpose shall be one sample each for every 5 metres drilled in objective zones and for every 10 metres drilled in other part of the hole in exploration and appraisal wells and one sample each for every 10 metres drilled in production hole in development wells. Samples prior to setting surface casing on platform development wells need be obtained on only the first four wells. Sampling frequency shall be indicated in the NOOP.

6.1.2 Sample Container Each container of drill cuttings shall be accurately and durably labeled when filled, with the name of the well and the interval depth. Where samples cannot be obtained, the interval and the reasons shall be recorded.

6.2 Coring Proposals for coring shall be indicated in the NOOP to include but not limited to the depth interval of coring, objectives and reservoirs to be cored.

6.2.1 Conventional Cores The core recovered from the core barrels shall be properly extracted, oriented, marked and described immediately and properly placed and vertically oriented in core containers. The cores shall be accurately and durably labelled with the name of the well, the depth interval of the core and the sequential number of the container if more than one.

6.2.2 Side Wall Cores Side wall cores shall be described as soon as practical or in the case of side wall cores that are to be preserved for future analysis, a chip taken from the core prior to preservation shall be described. The cores shall be placed in suitable containers that are accurately and


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durably labelled with the name of the well and the depth of the core.

6.3 Formation Evaluation Logging The applicable reports and logs shall be properly and timely submitted to PETRONAS. Field prints of individual runs of all electrical, radioactive or other formation evaluation logging operations, directional and other surveys shall be submitted to PETRONAS. Formation evaluation log, directional and other surveys shall be submitted to PETRONAS through Final Drilling & Completion Report. All occurrences of oil, gas and other minerals of potential geological interest shall be noted on the formation evaluation log to include all important zones of porosity and interpreted contents thereof, cased intervals and complete details on drill-stem or wireline formation tests. 6.4 Oil and Gas Flow Testing Flow assurance issues, such as hydrate formation and waxing at cold temperatures should be considered and handled appropriately prior to flow testing a deepwater well. Refer to Volume 7, Section 2: Well Test & Surveillance.


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Section 7: Completion Operations

Contractor shall design well completion to withstand all expected loadsthroughout different phases of well life. Completion operations shall be executedin a safe and efficient manner. Well completion shall be done under an approvedwritten work programme only and all well completion activities shall be recordedand made available to PETRONAS.

7.1 General Provision Well Completion Philosophy shall be addressed in the FDP considering reservoir characteristics, pressure, temperature, corrosion, well barriers, producibility, operability, well surveillance requirements, well maintenance feasibility, total life cycle cost as well as well abandonment aspects. Well completion operations shall be conducted in a safe and efficient manner to protect against harm or damage to life, property, environment and natural resources including hydrocarbon resources. 7.2 Wellhead Equipment All completed wells shall be equipped with wellhead valve assemblies with a rated working pressure which equals or exceeds the maximum anticipated pressure to which the wellhead may be subjected. Connections and valves shall be designed and installed to permit fluid to be pumped between any two strings of casing not cemented to the ocean floor. In subsea completions, access to other than the production casing is not required, provided that a unitised wellhead system is used which has a working pressure rating in excess of the maximum anticipated pressure. Wellhead valve equipment shall consist, as a minimum, of the crown or swab valve, a Surface Safety Valve (SSV) and a master valve, in the christmas tree. The SSV shall be the second valve in the flow stream from the wellbore. Wellheads and christmas trees’ design or type should be standardised wherever possible to minimise spares, cost of change over, etc. 7.3 Tubing Requirements Tubing shall be sized to best suit reservoir properties and economic benefits. All tubing shall have a rated minimum internal yield pressure greater than the maximum anticipated pressure. Only new tubing or used tubing which has been tested or inspected and found to be suitable for well conditions shall be installed in wells. All tubing


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and connections that are internally coated shall be suitable for the temperature and well fluid characteristic. 7.4 Subsurface Safety Valve All tubing installations open to a hydrocarbon bearing zone shall be equipped with a Surface Controlled Subsurface Safety Valve (SCSSV) located at least 30 metres below the sea floor. An injection valve capable of preventing backflow may be installed in lieu of a SCSSV in an injection well with PETRONAS’ approval. Such valve shall be located at least 30 metres below the sea floor. Any other method/replacement of subsurface safety valve (SSSV) requires PETRONAS’ approval. The prime purpose of the SSSV is to protect people, property and the environment against uncontrolled production while safeguarding the hydrocarbon resource asset.

The SCSSV is not considered a permanent barrier. However a SCSSV may be used as a temporary barrier in some circumstances when used in combination with a mechanical barrier such as plug or back pressure valve (BPV) for BOP and/or tree removal provided that the following conditions are met:

a) The SCSSV has been inflow tested in excess of the anticipated differential pressure that valve could be exposed to, prior to being used as a barrier; and b) The well is monitored at all time

A risk analysis shall be conducted to address all the possible failure modes, their likelihood of occurring and identify mitigation steps to reduce the likelihood and/or limit the consequences. 7.4.1 Installation All tubing installation in wells shall be equipped with a functioning SCSSV. Notwithstanding the above, during emergency, alternative safety devices (for example, subsurface control devices) may be temporarily installed without prior consent of PETRONAS. PETRONAS shall be notified of the situation and circumstances. 7.4.2 Valve Specifications Contractor shall use subsurface safety devices that comply with the minimum standards set forth in the latest API Specification for


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quality assurance including design, material and functional test requirements and for verification of independent party’s performance testing and manufacturer’s functional testing of such valves. 7.4.3 Reinstalling, Testing and Maintenance Contractor shall install, test and maintain the SSSV systems based on their operating and inspection maintenance philosophy. 7.4.4 Tubing and Plug Testing A shut-in well equipped with a tubing plug or other device shall be inspected for leakage of not less than once in six (6) months. If leakage is detected, the plug shall be removed, repaired and reinstalled, or an additional tubing plug may be installed in lieu of removal and repair. 7.4.5 Additional Protective Equipment All tubing installations in which a wireline or pumpdown retrievable subsurface safety device is to be installed shall be equipped with a landing nipple which comes with flow couplings or other protective equipment above the landing nipple to provide for sitting of the subsurface safety devices.

Any subsurface controlled SSSV installation shall require PETRONAS’ prior approval. However, during emergency, the installation of the subsurface controlled SSSV can be carried out prior to PETRONAS’ approval but the request shall be submitted within thirty (30) days limit after the installation. Contractor shall consult and obtain approval from PETRONAS prior to using a subsurface controlled subsurface safety valve. The request for approval shall include:

a) Explanation of actions taken since the SCSSV failure was noticed; b) Valve type and specifications; c) Valve setting and test certificates; d) Well schematics showing TVD, MD; e) Tubing pressure modelling/plots for Closed-In Bottom Hole Pressure (CIBHP), Flowing Bottom Hole Pressure (FBHP), Flowing Pressure at valve depth, Flowing Tubing Head Pressure (FTHP) and Closed-In tubing Head Pressure (CITHP); and f ) Long term solution

7.4.6 Records Contractor shall maintain records which include design


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specifications, verification of assembly and setting depth, removal date, reason for removal, reinstallation date and all mechanical failures or malfunctions with notations as to the cause. Such records shall be made available upon request by PETRONAS.

7.5 Packer Requirements All completions open to hydrocarbon bearing zone(s) shall be completed with the tubing-casing annulus packed off above the uppermost open casing perforations unless it is a monobore (tubingless) completion. A packer leakage test (if packer is utilised) shall be performed upon initial installation of the packer to ensure isolation of the tubing-casing annulus. 7.5.1 Cement Packer Cement packer described in this section refers to the application where cement is used to fill up tubing-production casing annulus and serves as a production packer. This technique is applicable where marginal amount of hydrocarbon is found behind production casing but above the existing uppermost packer. Contractor shall submit request for approval to PETRONAS at least 30 days prior to work execution. The request shall include the following: a) risked economic model; b) comparison with alternative solutions i.e. workover; and c) considerations on abandonment solutions including options that can be done prior to cement packer and the final abandonment. All involved costs shall be accounted.

For cement packer application, the cement in annulus column casing and tubing shall be at least 500 ft above the uppermost perforations. Cement packer shall be verified by evaluation logs and pressure testing. 7.5.2 Circulating Device For all wells, manually operated sliding side door shall incorporate a seating nipple on top and shall be of shift-down-to-open type to allow isolation. 7.6 Separation of Zones Multiple completions in the same wellbore shall require the separation of each completion either through packers or cement or a combination of the two. When feasible, a packer leakage test shall be conducted to check isolation of the producing zone.


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7.7 Landing Nipples Tubing hanger(s) shall be equipped with landing nipples or plug bushings to receive pump-through tubing plugs or back pressure valves. Requirements for landing nipples shall be considered at completion design stage. Contractor shall ensure that the landing nipples are properly chosen considering flow path area, pressure rating, etc.

7.8 Completion Fluid The fluids used during well completion/workover operations which serve to control the well while it is open, transport solids out of and into the well, displace well treatments, bring the well in, augment perforating and protect the producing formation during perforating and subsequent exposure shall be designed to minimise adverse effects on steel surfaces and formation damage.

7.9 Packer Fluid The fluid which is left in the tubing-casing annulus above a packer is required to meet many of the same requirements as workover fluids. Packer fluids serve to reduce differential pressure across the packer, protect annular steel surfaces from corrosion, aid to control the well when the packer is being set or retrieved and may thermally insulate the tubing during production or injection.


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Section 8: Barriers and Well Integrity

Contractor shall provide priority on well integrity considerations foroperations, well suspension and well abandonment. The objective shall be focusedon prevention of uncontrolled release of formation fluids from the well on apermanent basis and/or reduce the risk of such escape of fluids to ALARP.Another focus shall be prevention of sustained casing pressure (SCP). It shall be recognised that the key to well integrity is highly dependent on the soundness ofthe initial well design and success of primary cementations of casings and liners.

8.1 Number of Well Barriers There shall be two (2) well barriers available during all well activities and operations, including suspended or abandoned wells to prevent uncontrolled outflow from the borehole/well to the external environment.

There shall be one well barrier in place during all well activities and operations, including suspended or abandoned wells, to prevent uncontrolled cross flow in the wellbore between formation zones.

8.2 Barrier Failure and Restoration Should any of the barriers be lost, Contractor shall give priority to restore the function and number of required barriers accordingly. Contractor shall submit to PETRONAS the proposed barrier restoration plan complete with relevant details, schematic, operational and barrier verification steps prior to execution.

8.3 Barrier Material Permanent barrier shall be defined as an impermeable and non-shrinking barrier or combined barriers that create(s) a seal that has a permanent/ eternal characteristic. Means of creating seal through the use of physical elements may be categorised into three (3) types:

8.3.1 Solidified Cement A solidified cement barrier element is a barrier that will maintain a permanent seal provided that its position, quantity and quality has been tested and verified for its intended purposes. Its placement records shall be reviewed and actual placement is confirmed to have met the minimum design requirements. Cement plug set in a tubular section that is uncemented or has poor annular cement bond is not considered a barrier.

8.3.2 Mechanical Barrier A mechanical barrier element is a seal achieved by mechanical


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means in a wellbore. Plugs, bridge plugs, cement retainer and packers are acceptable as permanent barriers if used with cement. When cement is used as a barrier during well construction together with mechanical barriers, then the mechanical barriers are complementary to a properly executed cementing operation.

8.3.3 Fluid Barrier Fluid barrier element is a column of fluid(s) exerting hydrostatic pressure which exceeds the pore pressure of the potential flow zone. These fluids may include drilling fluids, brine and water. It shall be recognised that the hydrostatic contribution of any of these fluids may change with time. Thus, the use of this barrier shall be carefully planned, calculated and continuously monitored and replenished as necessary. Considerations shall be given to hydrostatic pressure, friction through circulation, fluid properties and formation strengths that are exposed to this fluid column. Fluid barriers are not considered as permanent barrier.

8.4 Well Integrity Management Contractor shall establish a well integrity management system (WIMS) to ensure well condition is structurally sound with competent pressure seals that eliminate and/or reduce the risk of uncontrolled and/or unintended release of formation fluids throughout the well life cycle. The management system shall include procedures for barriers monitoring, maintenance and continuous integrity verification. The methods and frequency for verifying the condition of barrier shall be defined and documented.

All annuli capable of being monitored in a well shall be routinely measured for pressure build-up. The frequency of monitoring shall be appropriate to the well criticality, failure severity and previously known problems. PETRONAS shall be immediately informed regarding wells diagnosed with SCP. SCP means casing annular pressure build-up (casing/wellhead pressure returns after bleed-off).

Contractor shall submit monthly well integrity report to PETRONAS. The report shall include:

a) Database system that provides up-to-date well integrity and barrier status (for example, leaks, corrosion, erosion, etc.) for all wells; and b) SCP status tracking and condition


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Section 9: Plug and Abandonment of Wells

Contractor shall adhere to or exceed the minimum plug and abandonment (P&A)requirements provided to ensure full and adequate isolation of formation fluids both within the wellbore and from surface or seabed. Plugs shall be verified to ensure correct depth placement with the required sealing capability. Well P&A programme and suspension plans shall be submitted to PETRONAS for approval in a timelymanner.

9.1 Responsibility to Abandon a Well Contractor shall ensure that: a) A well or a portion of a well that is not suspended or completed is abandoned; and b) Where a well is abandoned, it shall be abandoned in accordance with applicable provisions under Section 9

When a well or a portion of a well has not been abandoned in accordance with applicable provisions under Section 9, it shall be the responsibility of the Contractor, when required by PETRONAS, to properly re-abandon the well.

9.2 Application to Abandon a Well Contractor shall submit to PETRONAS a request for approval to abandon any well prior to execution. It shall be recognised that each well is unique and shall be considered on an individual basis. The submission shall include reasons for abandonment as well as the following information:

a) Programme outlining operational steps and barrier verification (testing). It shall also include description for plug types, downhole placement technique and downhole cement slurry support (to prevent slurry slumping). b) Current status and proposed P&A well schematic complete with descriptions for the following details: • Welldepth; • Allperforatedintervalsincludingthosethathavebeenplugged; • Casingandtubingdepthsanddescription; • Estimatedtopsofcementineachcasingannulus; • Subsurfaceequipmentanddepths; • Plugtypes,locationsandlengths; • Typesanddensityoffluidsleftinhole; • Perforatingandcasingcuttingplans; • Casingremovaldepths; • Reservoir strata, subsurface pressures of all known potential


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reservoirs and estimated pressures; and • Cementbondevaluationlogresult,ifrecorded PETRONAS may request additional requirements where it deems necessary or to enhance benefits.

9.3 Subsequent Report of Abandonment Contractor shall produce a detailed report of the manner in which the abandonment or plugging work was accomplished: the nature and quantities of materials used in the plugging; the location and extend, by depth, of casing left in the well; the volume of drilling fluid used and the records of barrier verification tests performed. It shall also contain information related to removal of casing strings and wellhead. This report shall be submitted to PETRONAS in accordance with Section 2.4. Contractor shall archive the records of abandoned well for future eventualities.

9.4 Permanent Abandonment Permanent abandonment proposal shall be prepared with the following objectives:

a) Provide downhole isolation between hydrocarbon zones; b) Protect freshwater aquifers; and c) Prevent migration of formation fluids through the wellbore

The materials used as barriers for well abandonment shall be able to withstand the load and environmental conditions that the barriers may be exposed to for the time the well will be abandoned.

9.4.1 Isolation of Zones in Open Hole In uncased portions of wells, cement plugs shall be spaced to extend 30 metres below the bottom and to 30 metres above the top of any hydrocarbon zones and fresh water zones shallower than 300 metres, to isolate all hydrocarbon bearing zones from one another and from water bearing formations and to prevent any fluids migrating to the surface. A cement plug that is not supported by the bottom of the well shall, after Wait-on-Cement (WOC) to harden, be tagged with 10,000 lbs. or the maximum safe tagging weight that can be applied with the string in use. After an unsuccessful fishing operation for stuck pipe, where possible, the fish shall be perforated and cement shall be pumped


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through the perforations to cement the annulus between the fish and the hole to isolate any open sands that are present. If any hydrocarbon bearing sands are exposed below the fish, Contractor shall consider taking remedial action to prevent cross flow between them. Where this is not possible, a cement plug shall be positioned that extends at least 30 metres above the fish to isolate the fish from the open hole above the fish. The plug shall be tested in accordance with Section 9.6. In the event that any of the above fish carries a radioactive source, Atomic Energy Licensing Board (AELB) under the Ministry of Science, Technology and Innovation (MOSTI) approval shall be sought before any decision is made to abandon the well and/or bore. A copy of AELB approval letter shall be provided to PETRONAS when requesting for approval to abandon. Where there is possible risk of subsequent drilling into the source, coloured cement shall be used.

9.4.2 Isolation of Open Hole Where there is an open hole below the casing, a cement plug shall be placed in the deepest casing string in accordance with (a) below. In the event lost circulation conditions have been experienced or are anticipated, a permanent bridge plug (or equivalent) may be placed in accordance with (b) below: a) A cement plug set by the displacement method so as to extend a minimum of 30 metres above and 30 metres below the casing shoe. The plug shall be tested in accordance with Section 9.6 b) A permanent bridge plug (or equivalent) set within 45 metres above the casing shoe with 30 metres of cement set on top of the plug. The plug shall be tested in accordance with Section 9.6. Before setting the plug, attempts should be made to cure losses 9.4.3 Plugging or Isolation of Perforated Intervals A balanced cement plug shall be set by the displacement method opposite all open perforations extending a minimum of 30 metres above and 30 metres below the perforated interval or down to a casing plug, whichever is less. The plug shall be tested in accordance with Section 9.6. Cement is considered as the prime abandonment material. Alternative abandonment material and/or method shall be justified. PETRONAS may approve the following material and/or method for specific well conditions:


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a) A cement retainer with effective back pressure control or a permanent packer set not less than 15 metres and not more than 30 metres above the top of the perforated interval with a cement plug calculated to extend at least to the top of the perforated interval and 15 metres above the retainer or packer. The plug shall be tested in accordance with Section 9.6 b) A permanent bridge plug set not more than 45 metres above the top of the perforated interval with 30 metres of cement set on top of the plug. The plug shall be tested in accordance with Section 9.6

9.4.4 Plugging of Casing Stub If casing is cut and recovered leaving a stub, one of the following methods shall be used to plug the casing stub except conductor casing:

9.4.4.1 Stub Terminating Inside Casing String A stub terminating below a conductor casing shall be plugged by setting a cement plug so as to extend 30 metres above and 30 metres below the stub. The plug shall be tested in accordance with Section 9.6. Cement is considered as the prime abandonment material. Alternative abandonment material and/or method shall be justified. PETRONAS may approve the following material and/or method for specific well conditions: a) A cement retainer set approximately 15 metres above the stub with a volume of cement equivalent to 45 metres squeezed below the retainer and 15 metres above the retainer. The plug shall be tested in accordance with Section 9.6 b) A permanent bridge plug set approximately 15 metres above the stub with 30 metres of cement set on top of the plug. The plug shall be tested in accordance with Section 9.6

9.4.4.2 Stub Terminating Below Casing String If the stub is below the next larger string, plugging shall be accomplished in accordance with either Section 9.4.1 or Section 9.4.2.

9.4.4.3 Liner Top or Screen Liner or screen that is impractical to be removed shall be


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plugged in accordance with Section 9.4.4.1.

9.4.4.4 Plugging of Annular Space Any annular space communicating with any open hole and extending to the sea floor (or surface for onshore) shall be plugged with cement.

Note: This requirement is waived for deepwater operations

9.5 Surface Plug A cement plug at least 45 metres in length, with the top of the plug 45 metres or less below the sea floor, shall be placed in the smallest string of casing which extends to the sea floor. For subsea wellhead, the top of the plug may be set within 100 metres to the sea floor.

9.6 Testing of Plugs The plugs below the surface plug shall be verified and verification result documented to ensure correct depth placement with the required sealing capability, with the following tests: a) Weight or tag test by placing a minimum pipe weight of 10,000 lbs. on the plug; b) Pressure test by testing the casing against the plug with a minimum pump pressure of 1000 psi with no more than a 10 per cent pressure drop during a 15-minute period; and/or c) Inflow or negative pressure test to at least the maximum pressure differential that will be experienced by the plug post abandonment

The testing requirement shall be as the following:

a) Plug entirely in open hole shall be verified with weight test (unless bottom supported by the well or a successfully tested plug); b) Plug in cased hole shall be verified with both weight and pressure test; and c) Plug (the first plug below surface plug) in deepwater wells where a reduction of hydrostatic pressure will occur above the plug, shall be verified by inflow test in addition to the above testing requirements

9.7 Abandonment Fluid Each of the respective intervals of the hole between the various plugs shall be filled with drilling fluid of sufficient density to exert hydrostatic pressure exceeding the greatest formation pressure encountered while drilling the


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intervals between the plugs. In addition to the above, the hole shall be circulated so that the drilling fluid is gas-free and of uniform fluid weight.

9.8 Clearance of Location All casing, wellhead equipment and piling shall be removed as deep as practically possible (minimum of 1 metre) below the sea floor. Contractor shall provide written verification that the location has been cleared of all obstructions.

9.9 Well Suspension Any well which is to be suspended with no immediate intention to return to the well for further operations shall be filled with drilling fluid and cemented as required for permanent abandonment in accordance with Section 9.4.

9.10 Temporary Well Suspension Any well which is to be temporarily suspended prior to drilling ahead, completion or abandonment shall be filled with appropriate weighted fluid and cemented in accordance with Section 9.4.1, 9.4.2 and 9.4.3 and shall be equipped with two well barriers in the form of kill fluid used in accordance with Section 8.3.3 together with one of the following: a) Pressure tested casing or cement plug or liner lap; or b) Pressure tested mechanical barrier

In all cases, wellhead valve assembly tree or wellhead cap or BOP shall be employed to give pumping access to the well.

9.11 Suspended Well Contractor shall ensure any well that is suspended and that has not been completed within five (5) years from the date of suspension shall be either completed or abandoned. Records of suspended wells shall be retained in order to ease the re-entry or abandonment of the wells. Every well that is completed and/or inactive suspended shall be inspected at least once each year and reported to PETRONAS and shall be placed on production or abandoned within a period three (3) years from the date of suspension unless prior approval has been given by PETRONAS for the extension of the period.


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Section 10: Workover and Well Intervention Operations

Workover operations conducted on wells after initial completion for the purpose of maintenance, restoration or increasing the productivity shall be conducted in a safe and efficient manner. Workover programme or Notice of Workover Operations (NOWOP) shall be prepared by Contractor and submitted to PETRONAS for approval in a timely manner. Reporting and report contents requirement shall adhere to the procedures in this section.

10.1 General Requirement This section covers well activities which may be split into two broad categories:

a) Workover related to pulling completion and requiring assistance of hydraulic workover unit, hoist or workover rig b) Well intervention primarily within tubing but also includes work outside tubing that do not require pulling completion. This group is further divided into two subgroups; major well intervention and routine well intervention

All activities shall be done under two verified barriers. Contractor shall have a system in place to assure that personnel involved in these activities have acquired necessary competencies to perform the jobs. All equipment shall meet related industry recognised standards. All work shall be done under approved written work programme. Where a contingency plan requires well intervention activities, Contractor shall have procedures readily approved and all required equipment and personnel prepared.

10.1.1 Well Intervention A well intervention operation is conducted with equipment and support facilities that precludes requirement for a rig over the wellbore such as coiled tubing, slickline and snubbing activities. It also possible that this activity is combined with supporting vessel/boat utilisation in offshore environment. Rigless operation shall be conducted only when the minimum requirements below are completed: a) Safety concerns properly addressed (lifting equipment, platform integrity, well control, etc.); b) Operations risk and benefit evaluation; c) Cost analysis; and d) Environmental impact assessment


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Further discussion is required for any types of operation and/or method that are not covered in this document and subject to approval from PETRONAS. 10.1.2 Workover Workover is a remedial operation conducted with equipment and support facilities that includes requirement for workover rig over well bore. Further discussion is required for any types of operation and/or method that are not covered in this document and subject to approval from PETRONAS. 10.1.3 Operations Workover and testing operations whereby rig assistance is required shall not be undertaken, nor operations other than emergency well control be conducted unless rig crews and supporting service units are properly manned and supervised.

10.2 Workover Unit and Equipment

10.2.1 Workover Structure Workover units shall meet API 4F Specification for Drilling and Servicing Structure. Masts, derricks, substructures and related equipment shall be selected, installed, utilised and maintained with consideration given to the potential loads and conditions of loading that may be encountered by the operations. The conditions affecting loading include wind, setbacks, pulling and running tubular goods, and subsurface equipment, fishing, drilling and jarring operations.

10.2.2 Travelling Block Safety Device All workover and completion rigs shall be equipped with a travelling block safety-control device. The device shall be checked for proper operation after each drill-line slipping operation. The operational check shall be recorded in the daily well log.

10.2.3 Pumping Equipment Pumping equipment and lines shall be earthed and equipped with an overpressure protection. The emergency vent shall be routed to a safe area.

The flowlines from the pump manifold to the wellhead valve assembly shall have a rated working pressure equal to that of the


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wellhead equipment or to the maximum anticipated well or pumping pressure, whichever is less. A lubricator assembly with the necessary shut-off valves, bleed valves and pump connections to permit the safe installation and removal of the pumpdown tools shall be connected to the flowlines downstream of the pump manifold. Any polluting fluids bled from the lubricator shall be properly contained.

10.2.4 Pumping Operations Prior to pumping operations, the flowline from the pumping unit to the well connection shall be properly secured and pressure tested to the maximum anticipated pressure plus a safety margin. Pressure testing should be done with water, brine or any inert fluids. Appropriate high pressure shut-off and bleed valves shall be installed as a part of the pump manifold, permitting disconnection of the pump, if needed. Well fluids and gas returning from the well during pumping operations shall be safely handled and properly contained.

10.2.5 Hazardous Chemicals Any hazardous materials shall be delivered or store together with a correspondening Material Safety Data Sheet (MSDS). Spill combat/ neutralising agents should be available.

Appropriate first aid kits, safety shower and eye washer shall be available.

Liquid nitrogen, if spilled, can cause serious damages to steel structure and hence appropriate preventive and protective precaution shall be taken.

10.3 Well Unloading Operations Operations which involve unloading or cleaning up a well shall use piping or equivalent armoured flexible pipes, vessels and other control equipment in order to safely contain, handle and dispose of any flammable, hazardous or polluting material. Flammable liquids, including condensate and crude oil, shall not be placed in vessels having open tops. However, such liquids may be temporarily placed in vessels having open tops for on-going operations. A flammable liquid is defined as any liquid with a flash point below 37.8°C (100°F). If a well is routed to flare, considerations shall be taken to tide and/or wind


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directions, the position of the platform and vessels presence in the vicinity.

If the well is opened to flowline, Contractor shall ascertain that impacts to flowline (for example, clogging, corroding, etc.) are minimised. 10.4 Notification and Submittal Requirements – Workover Contractor shall notify PETRONAS in the WPB and subsequent revisions of its intention to undertake any particular workover campaign. Workover operations require prior approval from PETRONAS through the submittal of Notice of Workover Operations (NOWOP).

10.4.1 Notice of Workover Operations and Major Well Intervention Contractor shall submit NOWOP at least forteen (14) days prior to workover execution for approval. This requirement also applies to major well intervention as described in Section 10.5. The submitted NOWOP shall have been reviewed by PETRONAS’ parties responsible for the tasks affected by the proposed workover. NOWOP shall include the following information as a minimum:

a) Well problem description, job objective, proposed problem solution and justification of proposed workover; b) Present well status and well history; c) The name of all intervals proposed for completion or alternative completion; d) Accumulative oil, gas and water production; e) Shut-in surface and bottom hole pressure; f ) A well schematic drawing showing the present and proposed zones and the completion including depths and description of equipment to be used; g) Proposed workover procedures outline; h) Estimated time and expenditures breakdown; i ) Estimated reserve, incremental production including estimation methodology; j ) Potential problem or risk and mitigation plan; k) Cost analysis and detailed breakdown; l ) Safety and environmental assessment; m) Decision tree chart; and n) BOP stack diagram

Electronic copy of detailed workover procedures shall be submitted upon request by PETRONAS.


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10.4.2 Workover Reports and Data Retention All activities performed at the well site shall be recorded consistently in both reporting format and level of detail. The reporting requirements described below are aimed at capturing records of activities done, problems encountered, lessons learnt in order to facilitate performance improvement and knowledge management:

a) Daily Workover Report (DWR) shall be submitted daily; and b) Final Workover Report (FWR) shall be submitted to PETRONAS no later than 60 days after the workover is completed.

All reports shall be retained for future reference and made available to PETRONAS upon request.

10.4.3 Daily Workover Report Contractor shall submit the Daily Workover Report (DWR) to PETRONAS which contains but not limited to the following information: a) Well name; b) Rig name; c) Workover objectives; d) Cost estimate; e) Actual cost; f ) Duration estimate; g) Actual days; h) Operation summary with 24 hours’ outlook; i ) Operations activity time log including problems encountered description; j ) NPT-hour (daily and cumulative NPT); k) HSE issues (incident/accident); and l ) Look ahead plan and major concern (if any)

10.4.4 Final Workover Report After the workover operation is completed, all available information shall be submitted in a Final Workover Report (FWOR) to PETRONAS no later than sixty (60) days after the workover is completed. The report shall include but not limited to the following information: a) History of the well; b) Description and date of work performed; c) A well schematic drawing with tubing details before and after workover;


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d) Results of well test, before and after workover; e) Detailed estimate against actual expenditure; f ) Summary of workover operations and time break down; g) Zonal isolation intervals and pumped cement volume; and h) Lessons learnt and improvement initiative

10.5 Major Well Intervention Operations Prior approval from PETRONAS is required for the following activities which are considered as major well intervention: a) Coiled tubing operations; b) Well pumping/Stimulation; c) Electric line involving explosives and tractor tools; d) Planned fishing job or campaign; and e) Well integrity remediation

10.6 Notification and Submittal Requirements – Major Well Intervention Contractor shall notify PETRONAS in a Monthly Major Well Intervention Plan of its intention to carry out any major well intervention activities in the following months on a quarterly basis.

Major Well Intervention Plan shall be reviewed and endorsed by PETRONAS accordingly prior to operations execution.

Major Well Intervention Plan shall include the following details:

10.6.1 Well Intervention Activity Reports Contractor shall submit the Daily Major Well Intervention Report to PETRONAS which contains the following information as a minimum:

MONTH OF …………………………………

Coiled Tubing Well NameJob DescriptionPlan CostPlan DurationExpected Gain

Well NameJob DescriptionPlan CostPlan DurationExpected Gain



Electric Line Well NameJob DescriptionPlan CostPlan DurationExpected Gain





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a) Well number; b) Summary of operations for the last 24 hours including HSE report; c) NPT-Hour (daily and cumulative NPT); d) Look ahead plan and major concerns (if any); and e) Fish or well problem encountered or left behind

10.7 Routine Well Intervention Operations Certain routine operations such as pumpdown or through-tubing non-rig operations are considered maintenance operations and do not require approval by PETRONAS. However, Daily Routine Well Intervention Report shall be submitted to PETRONAS following the Daily Major Well Intervention Report’s format. Routine well intervention operations include the following: a) Paraffin cutting; b) Moving and setting tubing plugs, gas lift valves and SSSVs by wireline techniques; c) Opening and closing circulation ports; d) Bailling sand or sand cleanout; e) Pressure and temperature surveys; f) Swabbing; g) Scale removal; h) Measurement survey (caliper, gauge, depth and flowmeters, electric logs, etc.); and i) Wellhead repairs which do not require the installation of a BOP stack.

However, prior to removing the wellhead valve assembly, well control shall be maintained by well control fluids and by a downhole sealed off pressure tested annulus and tubing. In this condition, wellhead repair may be carried out involving removal of the wellhead valve assembly and tubing-casing annulus pack-off.

10.8 Well Control Equipment 10.8.1 Workover Pressure Control Equipment BOPs and other surface pressure control equipment shall have a rated working pressure which equals or exceeds the maximum anticipated surface pressure. For any operation involving movement of the tubing string, the minimum BOP requirement shall be as described in Section 5.4.4.


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10.8.2 Well Intervention Pressure Control Equipment

10.8.2.1 Coil Tubing Operations The minimum BOP shall consist of the following: a) A set of pipe-rams, hydraulically operated; b) A two-way slip assembly hydraulically operated; c) A pipe cutter (shear ram) assembly, hydraulically operated; d) A set of blind rams, hydraulically operated; e) A pipe stripper assembly; and f ) A spool with side outlets (if no side outlets are provided in the wellhead valve assembly)

The arrangement of the BOP shall be suitable for the service intended.

10.8.2.2 Electric Line or Braided Line Operations The minimum pressure control equipment shall consist of the following:

a) Grease injection head; b) Lubricator with bleed off valve; and c) Dual rams BOP with grease injection port

For certain critical operations, additional BOP or cutter may be added.

10.8.2.3 Slickline Operations The minimum pressure control equipment shall consist of the following:

a) Stuffing box; b) Lubricator with bleed off valve; and c) Single or Dual rams BOP (if necessary)

For certain critical operations, additional BOP or cutter may be added.

10.8.2.4 Snubbing Operations The minimum BOPs shall consist of the following: a) A set of pipe-rams hydraulically operated;


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b) 2 sets of stripper type pipe-rams BOPs, hydraulically operated with spacer spool; c) A pipe stripper assembly; and d) Hydraulically operated, or in exceptional cases, mechanically operated snubber slip and seal assembly; if the surface pressure is above 5000 psi, hydraulically operated blind rams shall be used

Upon installation of the snubbing unit, it shall be pressure tested for operation to the maximum anticipated surface pressure. Snubbing operations under pressure shall be performed with sufficient lighting. With the wellhead valve assembly installed, a work or swab valve or a blind ram-type BOP shall be mounted above the wing line to serve as a base for the BOP stack.

The workstring shall include a back pressure device near or at the bottom of the workstring and a landing nipple installed above the back pressure device to receive a blanking plug or check valve.

10.8.3 Other Equipment An operable inside BOP (back pressure valve) and a safety valve in the open position with proper end connections for tubing or workstring being used shall be maintained and be readily available on the rig floor (unless coiled tubing is being used). The valve shall have a pressure rating which exceeds the maximum anticipated surface pressure and shall be of such design that it can be run through the BOPs. The safety valve shall be pressure tested not less than once in every fourteen (14) days. The pressure test shall be recorded in the relevant field log. If necessary, a manifold and choke line shall be provided and tested with water to the rated working pressure of the BOPs or of the wellhead valve assembly, whichever is less. 10.8.4 Well Control Fluids The characteristics, use, density and testing of well control fluids shall be designed and maintained to minimise formation damage and assure well control. Quantities of materials sufficient to assure well control shall be maintained at the well site.


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10.8.5 Well Control Prior to pulling the production tubing from the well, tubing strings and casing annulus shall be circulated with well control fluids. The hole shall be filled by accurately measured volumes of well control fluids; wells which will not maintain a full column of fluid shall maintain the maximum fluid level. Fill-up operations shall be monitored by use of a mechanical, volumetric or electronic device during all trips in and out of the hole. A back pressure valve or wireline type plug, shall be installed and function tested if possible in each tubing string before removing BOP or wellhead valve assembly. The work shall be organised to minimise the time between the removal of the wellhead valve assembly and the installation of the BOP. The well shall be continuously monitored during workover or completion operations and shall not be left unattended at any time unless shut-in with assurance of complete well control. 10.8.6 Pressure and Function Test 10.8.6.1 Pressure Test Each component of the BOP stack assembly and related control equipment shall be individually tested in accordance with Section 5.4.6.2.

10.8.6.2 Function Test The actuation of the BOP shall be carried out as defined in accordance with Section 5.4.6.3.

10.8.6.3 Lubricators Lubricator assemblies shall be pressure tested each time they are installed to the maximum anticipated wellhead pressure and at least annually to their rated working pressure. The test date and test pressure of the former shall be recorded on the daily log, and that of the latter shall be indicated by a metal tag or band.

10.9 Emergency Shutdown (ESD) An ESD control station shall be located at the drillers console during all well operations. Units without drillers console shall have readily accessible ESD stations. Contractor shall have procedure for Simultaneous Production and Drilling Operations (SIPROD).


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10.10 Wireline Operations 10.10.1 General Requirements For the purpose of these requirements wireline operations include all cased hole or open hole operations, utilising either a solid or stranded line. The wireline packoff shall be monitored and maintained during wireline operations and the elements shall be replaced, when necessary, to assure a proper seal under pressure conditions. Operations under pressure conditions shall not allow fluids to flow through the wireline packoff, other than minor leakage necessary to permit free movement of the wireline. Minor leakage from packoff assemblies shall be properly contained and disposed of. Before commencing the wireline work, all equipment shall be checked for compliance with all applicable safety standards, including the use of explosion proof motors on all power equipment. When operations are temporarily suspended, the well shall be monitored or completely shut-in until operations resume. Wireline or conductor line operations during hours of darkness shall only be performed in the presence of a proper lighting. 10.10.2 Operations in Cased Hole When perforating or logging in a cased hole without the wellhead valve assembly installed and where communication exists from the wellbore to the formation, well control shall be maintained by well control fluid and the BOP. The well shall be monitored continuously on the trip tank. When logging in a cased hole without the wellhead valve assembly installed, where no communication exists from the wellbore to the formation, well control shall be maintained by the BOP or well control fluids. When running and perforating with tubing conveyed guns, well control shall be maintained by well control fluids and the BOPs. If the perforation assembly includes a packer above the guns, it is permitted to displace the workstring to underbalanced fluids to enable perforation under drawdown conditions.


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10.10.3 Operations in Open Hole Open hole operations such as induction-electrical, density and acoustic logging that are performed without the wellhead valve assembly installed shall maintained well control by the use of well control fluids and BOP. A lubricator assembly/or shooting nipple assembly shall also be used if necessary in order to safely run and retrieve wireline tools. All personnel not directly associated with the operations which utilise explosive devices or hazardous radioactive materials shall vacate the rig floor and substructure prior to device arming, entry and retrieval from the wellbore. Competent personnel shall verify that all explosive device systems, wireline units and BOPs are grounded to the basic rig structure and that no unsafe electric potential exists (for example, electric welding, exposed rig wiring near the cable etc.). Contractor shall ensure that safe operating procedures and test are used when handling any explosive devices. All primary charges and secondary charges shall be stored and transported exclusively in separated metal containers, marked with internationally recognised explosives signs. This also applies to defective detonators which have been removed from a misfired gun. Transfer of loaded gun without detonators is only allowed if properly identified and manifested with detonators stored in separate metal containers. Radio silence shall be observed just prior to arming any explosive device and at all times while the device is at the surface or less than 60 metres down the hole. The observation of radio silence shall be observed depending on the type of explosives and tools used. Electrical welding machines and top drive system shall be isolated. The impressed current cathodic protection equipment shall be switched off on offshore platforms prior to arming any explosive device and at all times, while the device is at the surface or less than 60 metres down the hole. 10.10.4 Swabbing Operations The swabbing of wells shall be performed with a lubricator assembly whether carried out with a small slickline or large braded line. Flow rates shall be controlled by the use of choke restrictions in the flowline. Swabbing of tubing strings capable of flowing


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hydrocarbons shall not be performed during hours of darkness unless approved by PETRONAS. 10.11 Rigging Up or Down of Workover or Completion Equipment The movement of workover or completion rigs and related equipment on and off an offshore facility, rigging up and rigging down, shall be conducted during daylight hours only unless adequate lighting is provided. Those wellheads, flowlines, production and other equipment which could be damaged by heavy lifting operations shall be shut-in and bled down or otherwise protected (well with tubing/casing annulus pressure which cannot be bled down shall be killed) prior to commencing heavy lift. SCSSV shall be closed or a tubing plug or back pressure valve shall be installed and tested if possible in each tubing string of wells that are exposed to possible damage in moving operations.


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Section 11: Onshore Drilling Operations

Contractor shall comply with the relevant regulations prior to constructing the well location. This includes but not limited to license and permits, risk assessment, protection of the environment and safety, culture and religious traditions in the area of operations, Emergency Response Plan (ERP) and restoration of the well location as per original condition.

11.1 Drill Site and Camp Design Land locations should be sized to accommodate a drilling rig, associated equipment, materials, consumables and to provide space to accommodate all staff. The overall size may vary considerably with the type of rig and operations.

The finished level should be sufficient to accommodate the maximum flood level. When defining the minimum required location area the following points should be taken into consideration:

a) Minimum rig layout; b) Accessibility of the equipment when the rig mast is laid down; c) Minimum size of waste pit; and d) Required manoeuvring area

11.1.1 License and Permits Prior to carrying out any activities, Contractor shall obtain the necessary work permits and should complete the following:

a) Preparation of Environmental Impact Assessment (EIA) report covering the civil engineering, transport and drilling operations; b) Preparation of a comprehensive HSE plan for the entire work phase, from start of survey until demobilisation; c) Topographical survey work; d) Obtaining permission to implement the project (for example, from local councils, forestry, building, environmental, irrigation departments, etc.); and e) Land acquisition

11.1.2 Risk Assessment The risk survey shall be conducted by a specialist contractor under the supervision of a civil engineer. At this early stage, a major contribution should be made towards environmental protection, by selecting access routes that have the smallest impact. Items that should be considered during this stage are:


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a) Effects on the habitat of animals as a result of a change in the natural drainage, surface water levels, aquifers; b) Effects on fauna and potential hazards to the local population, caused by excavations, filling, erosion, drainage and motorised traffic; c) Effects of increased accessibility for people by opening up tracks into previously inaccessible areas; d) Finding routes which are less utilised and therefore can be opened again for traffic after completion of the operation without causing resentment of interested communities; and e) Direct impact by the survey team on the environment, including minimising of vegetation cutting and controlling the survey crew (for example, by preventing littering and poaching)

11.1.3 Access Road Access road is required to transport equipment, crew and the drilling rig itself to the drilling site and the camp site. During the evaluation of a road access option the following aspects shall be considered:

a) Road capacity: The heaviest loads to be transported, maximum axle loads and the total number of axles expected to pass the road during the operation; b) Safety: Visibility, road width, horizontal and vertical alignment, requirement for protective structures, overhead obstructions, driving behaviour, signposting, escarpments, distances; c) Climate conditions: Occurring during the period of operations and effecting the quality and long term serviceability of the road; d) Terrain conditions: Hills, water crossings, load width and headroom, capacity of bridges, ferry crossings, seasonal inundation, access for the construction contractor; e) Subsoil conditions: Sand, laterite, black cotton, peat, clay, rock etc., both from foundation and construction material resource point of view; f ) Third party contractors: Availability, local expertise, materials and equipment, attitude towards safe working and protection of the environment; and g) During the exploration drilling, the use of access roads is for relatively short periods. Expenditure on maintenance should therefore be assessed against capital expenditure on more durable structures. Savings at the expense of safety shall never be made


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11.1.4 Campsite The campsite should contain accommodation and personnel support facilities such as bedrooms, kitchens, sanitary blocks, dining, recreation, laundry rooms, power generation, radio room, etc.

The campsite shall be located at a safe distance from the rig. Prior to determining the distance between the drill site and the campsite, the following should be considered:

a) presence of hazards for example hazardous gas; b) escape route; c) accessibility between the sites; d) company night driving policy; e) rig company safety policies; and f ) complete risk assessment of the operating area

Minimum distance of 300 metres is recommended and preferably should be positioned upwind from the drilling location. In areas with dangerous wildlife, fencing between rig and camp is recommended.

An unobstructed view from the camp to the rig is desirable from a safety and security point of view.

11.1.5 Water Pit and Drilling Fluid Pit The works shall be carried out by the Contractor in such a way to minimise disturbance to the surrounding ground.

Impermeable plastic liners shall be installed on all waste/mud pits. The liners shall be of heavy duty waterproof material and removable and reusable type. The pits shall have raised walls to prevent overflowing.

Any holes or tears in the liners shall be repaired. Life buoys shall be provided in clearly visible and accessible positions around pits containing water, liquid mud, etc. Rectangular roping shall be provided around each such pit to assist egress from the pit. Ropes shall be fixed, from corner to corner, around the perimeter and kept taut at all times.

Clear visible warning signs shall be placed around pits containing water, liquid mud, etc. Water pits shall be confined by a surrounding wire fence and provided with gates if there is potential of animal or human fall.


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Upon completion of the drilling operations and once the liquids contained within the water based mud cuttings pit have evaporated and the pit has dried out, Contractor shall backfill over and around the pit using locally obtained material and shall restore the area to its original condition.

In any event, pits shall not be left open to the atmosphere (other than while drying) and shall be left in such condition after remediation that they shall not constitute a danger to the local population, domestic animals or wildlife, etc.

11.1.6 Flare Pit and Vent/Bleed-Off Line All bleed/off/vent-line from the choke manifold direct to or through a mud gas separator shall be securely tied down and extended to the flare pit in a slightly downward direction.

Flare pit shall be located at least 50 metres away from the well, has raised walls and excavated to contain any liquid that might be bled-off without overflowing. Every effort shall be made to clear the area around the flare pit to be free of grass, debris, logs and flammable materials to reduce the hazards of fire. The flare pit on cessation of operations shall be backfilled and compacted.

11.1.7 Water Well and Water Source A continuous supply of water to the rig is essential to prevent rig downtime. Before the start of an extended drilling campaign, a comprehensive study should be made on the reliability of the possible drill water supply and the consequences of possible interruptions. Consideration should be given to using the contents of the waste pit as an emergency water source for well control. Nearby surface water should provide the most reliable and economic supply. However if this is not available, water well or water hauling by road tanker should be considered.

For domestic water consumption, well water shall first be examined and approved by a test laboratory for both human consumption and also drilling purposes.

11.1.8 Fencing and Well Security Whether a fence is required and the type depends very much on the environment. The presence of local communities or herds of animals will quickly justify a fence from a security and safety point of view. Usage of inexpensive, locally available material is recommended.


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11.2 Environment Protection and HSE

11.2.1 Emergency Response Contractor shall have an ERP for the site during both drilling and testing phases.

First aid kits in adequate numbers shall be available throughout the site. A clinic with first aid facilities, defibrillator unit and oxygen resuscitator shall be made available on site for emergency medical treatment. This clinic should be staffed by medical personnel (medical officer or site doctor/registered nurse). Any cases requiring more in depth health provision shall have detail MEDEVAC (Medical Evacuation) response.

Communication means for emergency purposes such as phone or radio shall be distributed in sufficient numbers. Alarm signals shall be available and tested regularly.

Notice boards shall be placed at pertinent locations to highlight measures in place. These boards will show as a minimum a facility layout with escape routes, muster locations, location of emergency equipment and emergency response team contact details.

11.2.2 Protection of Fresh Water Sands Fresh water sands shall be protected with cemented surface casing and such casing shall not be removed from the well at abandonment. In wells, where a short string of surface casing is set and cemented, deeper fresh water zone(s) shall be protected by setting cement plug(s) covering the water zone(s) and extending at least 30 metres above and below the zones.

11.2.3 Well Near Water Source When a drilling site is located near to the normal high water mark of a body of water or a stream and is in such situation that pollutants from the well may reach the water, Contractor shall construct dikes or trenches around the area and take other necessary measures as may be required to contain the pollutants. All land operations shall have a suitable collecting pit & skimmer to collect the liquid waste product and water run-off.

11.2.4 Drilling Liquid Waste, Contamination and Spills Liquid waste comprising of waste drilling mud, oily waste or other liquid products from a well shall be contained at all times and


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disposed in a manner that shall not pollute any surface water or underground source of potable water. Such liquids produced may be stored in a properly lined earthen pit at the well site, provided that such pit is excavated to a depth which shall contain all the waste fluid and shall not collect natural run-off water.

11.2.5 Fire Prevention and Safety Water supply of sufficient volume and pressure required to properly operate the firefighting equipment shall be made available at all time.

Any rubbish or debris that might constitute a fire hazard shall be removed to a safe distance from the vicinity of any well and the flare pit.

Any drilling rig with a camp located within 50 metres of the well shall be installed with an interconnected fire alarm system that is able of sounding an alarm automatically and also indicate on a panel the location of the fire.

Every room that is used as a sleeping accommodation for drill crew shall be equipped with a smoke detector and alarm.

11.2.5.1 Smoking Smoking shall be permitted only within safe and designated areas. Contractor shall ensure that proper signs and notices prohibiting smoking are posted at all designated no smoking areas at a drill site.

11.2.5.2 Engines Exhaust Any fixed internal combustion engine that is located within 25 metres of a drilling well onshore shall have the exhaust pipe of the engine in accordance to MEC 1 standard: a) Equipped with a spark arrester; b) Insulated or sufficiently cooled to prevent ignition of combustible gases; and c) Directed away from the wellbore or other sources of combustible gases and terminated at least 6 metres from the vertical centre line of the wellbore Only diesel driven engine are allowed for onshore drilling operation.


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11.2.5.3 Engines Intake Any fixed internal combustion engine that is located within 25 metres of a drilling well onshore shall be equipped with: a) Air intake shut-off valve that can be activated by a remote control device that is easily accessible from the Driller’s location; and b) A system of injecting inert gas into the cylinders or an air duct that conveys air to the engine from a source that is located 25 metres from the well

11.2.6 Restoration of Drill Site All refuse shall be cleared from the drill site on removal of the rig from the well and the area shall be restored to its original condition. Both the rathole and the mousehole shall be filled up and where applicable with cement plug at the surface. The cellar should be backfilled and restore the site as per original with markings of the well.

11.3 Well Design and Drilling Operations

11.3.1 Reference for Well Depth The measurement of any depth in a well during drilling or on the abandonment of the well shall be the rotary table of the drilling rig. For a well onshore, this height shall be measured from the elevation (reference mean sea level) of the natural ground surface prior to spud-in and it shall be from the elevation of the casing head flange after installation of the conductor or the surface casing.

11.3.2 BOP System The diverter system shall provide as a minimum, an annular preventer with one 10 inch diameter diverter line equipped with a remote controlled full opening valve near the well. The diverter line shall extend to a flare pit located at least 50 metres away from the well. The diverter system shall be operated by an automatic hydraulic accumulator system which could provide without recharging, fluid of sufficient volume and pressure to effect full closure of the annular preventer and open the remote controlled line valve(s). For all other BOP requirements, refer to Section 5.4.4.

11.3.3 Pressure and Function Test For all pressure and function testing, refer to Section 5.4.6.


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11.3.4 Casing Programme Supplementary to the casing and cementing requirements in the foregoing Section 5.2 and in lieu of drive pipe and/or conductor casing, the casing to be installed in an onshore well is:

11.3.4.1 Stove Pipe Stove pipe shall be set in a competent bed to ensure mud returns to the shaker whilst drilling for the next casing. Normally, such setting depth will be 30 metres or more below the natural ground level. However, the presence of abnormally strong formations may permit the setting of this casing at a depth shallower than that required. If this portion of the hole is drilled, it shall be cemented with a quantity of cement sufficient to fill the calculated space back to the bottom of the cellar.

11.4 Plug and Abandonment of Well All onshore wells shall be plugged and cemented for abandonment as required under Section 9.4. In addition, the Contractor shall ensure that:

a) All casing shall be cut at least 1 metre below the natural ground level with a minimum of 10 metres of cement plug placed in the innermost casing; and b) A steel plate of at least 7 millimetres thick shall be welded over the top of the largest casing in a manner that completely closes the well bore and the annulus between all strings of casing exposed at the cut point

In the event of a nuclear source equipment is left in hole after several unsuccessful attempts has been made, the abandoned well shall be marked with an appropriate signage. Refer to Section 9.4.1.


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Section 12: Onshore Completion, Workover and Intervention Operations

Contractor shall design completion for onshore wells to withstand all expected loads throughout different phases of well life. Completion operations shall be executed in a safe and efficient manner. Well completion shall be done under an approvedwritten work programme only and all well completion activities shall be recorded and made available to PETRONAS.

12.1 General Supplementary to the foregoing Section 7 and Section 10, Contractor shall comply with the following procedures in conducting onshore completion and workover activities.

12.2 Subsurface Safety Valve Any onshore well that is located within a 5 kilometre radius of a village, town or city and that is not on pump and is capable of producing gas in excess of 5 million cubic feet a day shall be installed with a SCSSV. This valve shall be installed in the tubing at least 30 metres below the ground level and such well will have a sealed casing-tubing annulus. 12.3 Well Stimulation In onshore wells where stimulation treatments employing maximum pressures in excess of 75% of the minimum internal yield pressure of the production casing shall be carried out only through the tubing and below a packer set as near to the production formation(s) as practicable.

12.4 Disposal of Produced Fluids Oilfield brines or other mineralised produced waters shall not be stored or evaporated using salt water disposal pits.

Impervious collecting pits constructed of clay or other suitable impermeable materials may be used for produced fluid disposal provided approval has been obtained from PETRONAS. Such pits in use when abandoned shall be backfilled and compacted.

Discharge of oilfield brines and other mineralised water into a surface drainage water course whether it be a dry of flowing creek or a stream or a river is prohibited unless approved by relevant authorities.

Such fluid may be disposed of upon approval by PETRONAS by injecting into porous formations or zones that by nature contain connate water compatible with the injecting fluid and that such zones are separated by impermeable beds that shall prevent polluting the fresh water sands.


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For any waste/hazardous material generated during operations shall be disposed in accordance to Section 13 Waste Material Handling and Disposal with reference to Volume 3, Section 1: Health, Safety and Environment.

12.5 Onshore Wellhead Valve Assembly All completed onshore wells which are capable of natural flow shall be equipped with wellhead valve assembly having fittings and connections with a rated working pressure greater than the maximum anticipated shut-in surface pressure of the well. Wells with surface pressures in excess of 1500 psi shall have two master valves.

When a well located near to the normal high water mark of a body of water or a stream or a river is in such a situation that the oil spill or leak may reach the water, Contractor shall ensure that when a well is not on pump, the wellhead valve assembly shall contain a SSV that shall automatically shut-off an uncontrolled flow of oil from the well in the event of a wellhead failure or leak. Such valve shall be the second valve from bottom to top arrangement.

12.6 Wells on Pump Wells which are incapable of natural flow and require pumping by sucker rods or submersible downhole pumps or any other mechanical lifting methods to produce may be exempted from requirements under Sections 10.2.4, 10.3, 10.8.4 and 10.8.5.


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Section 13: Waste Material Handling and Disposal

All waste materials from drilling and related operations shall be handled anddisposed in a manner that does not create a hazard to safety, health andenvironment and is in compliance with the applicable Malaysian laws.

13.1 Material Handling

13.1.1 Bulk Material All material handled in bulk such as barite, bentonite and cement shall be stored in properly designed containers to minimise contamination of the material from chemical and high humidity. Each container shall be properly labelled. Extreme care shall be utilised during loading, transporting and unloading bulk material to minimise contamination. All handling equipment and tanks shall be inspected according to the stated frequency on the preventive maintenance system of the rig for foreign substances that may cause contamination. Air dryers and condensation tanks shall also be inspected according to the stated frequency on the preventive maintenance system of the rig to assure that they are functioning properly. 13.1.2 Other Material Drilling fluid additives, not handled in bulk, shall be packaged in properly labelled containers and pallets and shall be waterproof to minimise deterioration and other precautions taken where damage or loss could create a hazard to personnel or the environment. Liquid fuel and oil shall be transported, transferred and stored in closed systems. Liquid fuel stored at or above deck level or ground surface shall be contained in closed and properly vented containers located at least 25 metres from the well for land drilling and 5 metres from the well for offshore drilling. For well unloading operations during workover, flammable liquids including condensate and crude oil may be placed in an open vessel as specified under Section 10.3. Every precaution shall be taken to avoid spillage while transferring fuel from supply vessel to the drilling site. After discharging fuel, the pumps shall be shut-off, the pressure released, the transfer hoses drained into the supply vessel and both hose ends securely plugged.


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13.2 Disposal of Material Wastes generated during drilling operations including used oil based mud including synthetic oil based mud and chemical residues/wastes resulting from drilling shall be managed in an environmentally safe and prudent manner in accordance with statutory and acceptable industrial practices. Wastes are not allowed to be discharged into the sea and shall be brought to shore for further handling if they cannot be properly processed and disposed at the rig site. Storage and disposal of these wastes including information on waste generated, stored, treated or disposed at the rig and wastes transported to shore base shall be recorded, tracked and in compliance with the requirements of the Environmental Quality (Scheduled Wastes) Regulations, 2005 or its amendment. Disposal of materials, wastes and equipment that are contaminated with Technologically Enhanced Naturally Occurring Radioactive Material (TENORM), shall comply with all applicable laws and regulations in Malaysia, but not limited to the followings: a) Atomic Energy Licensing Act, 1984; b) Radiation Protection (Licensing) Regulations, 1986; c) Radiation Protection (Basic Safety Standards) Regulations, 1988; d) Radiation Protection (Transport) Regulations, 1989; and e) LEM/TEK/30 SEM.2 , 1996- Guidelines on Radiological Monitoring for Oil and Gas Facilities Operators Associated with TENORM

Any TENORM disposal proposal shall be submitted to the Malaysian AELB for approval before license is applied and in general, a Radiological Impact Assessment (RIA) study shall be performed first. Copy of RIA shall be made available and submitted to PETRONAS for reference.

13.2.1 Drilling Fluid Only water based mud/fluids and synthetic based fluids of low toxicity is permitted for use of drilling. The use of low toxicity oil based mud and synthetic based mud shall be minimised and used only when necessary (based on geological formation and/or operational requirement). Spent oil/synthetic based mud and other remnants toxic materials are not allowed to be dumped into the sea. These materials shall be recovered, inventoried, properly labelled, contained and transported safely to shore or to a safe area designated for disposal in


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accordance to applicable Malaysian laws. Cuttings drilled with low toxicity oil based mud and/or synthetic based mud shall be properly washed and treated before disposing of into the sea in accordance with the PETRONAS E&P Minimum Environmental Specification (MES). 13.2.2 Solid Waste Contractor shall not, unless licensed by Department of Environment (DOE), burn or incinerate solid combustible waste on any premises from such operation. All wastes, residues or ashes produced shall be collected, recovered and transported back to shore for proper disposal in accordance to the approval from the local authorities or to a safe area designated for disposal in accordance to applicable Malaysian laws.

Solid non-combustible waste shall be divided into three principle types: domestic waste, industrial waste and schedule waste. It shall be transported to shore in appropriate containers for safe disposal at a site approved by DOE and/or the state or local authorities.

The disposal of solid waste (besides drilling disposal materials) into the sea is prohibited. Solid wastes shall be disposed at a site approved by the local authorities.

13.2.3 Liquid Waste Contractor shall not, unless licensed by DOE, discharge or spill any oil, mixture containing oil or environmentally hazardous substances, pollutants or fluid waste into the Malaysian waters. Discharge of oil and any liquid containing oil shall be in accordance with all applicable Malaysian laws.

Oil and gas produced while formation flow testing shall be properly stored in suitable containers and either transferred to shore or flared in a proper manner using an appropriate burner.

For offshore operations, waste engine lube oil, fuel oil, lubricants and other fluid mixtures containing oil shall be collected in a closed drain system labelled and transferred to shore for safe disposal or recycling. If production facilities are available at the worksite, for example when drilling in an existing field, arrangement with the facility operator shall be sought to dispose of the fluid waste into the effluent treatment sump.


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Excess acids shall be collected and stored in suitable containers for transportation to shore to be disposed of in a proper manner. Surface discharge shall only be allowed with approval from local authorities and pre-treatment for example, neutralisation is essential prior to the disposal.

13.2.4 Sewage Contractor shall not discharge or cause or permit the discharge of any refuse, garbage into the Malaysian waters. Sanitary and galley waste shall be disposed of in accordance with all applicable Malaysian laws.

13.3 Pollution Prevention

13.3.1 Offshore Pollution Any oil spill from drilling operations shall be recorded and reported to PETRONAS immediately noting size, type of pollutants, location and weather conditions. The detail incident notification procedures are stipulated in Volume 3, Section 2: Emergency Communication Procedures. Appropriate action shall be taken immediately by the responsible party and the costs for such action shall be at its expense. Contractor involved in drilling, extracting, producing, processing, transporting and marketing of oil and gas in offshore waters of Malaysia shall individually or jointly with two or more operators, maintain, organise and coordinate oil spill contingency plans which encompass all its offshore facilities. 13.3.2 Blowout Contingency Plan A BOCP shall be submitted to PETRONAS as an attachment to the NOOP for deepwater and HPHT wells meeting the description in the Definition Section items 5 and 14.

For deepwater wells, the BOCP shall include a subsea well containment response plan including details on:

a) Access to well capping system equipment and scope of services; b) Storing location for ready-to-deploy maintained equipment and estimated deployment duration to the proposed well site;


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c) Well capping system technical specification; d) Deployment strategies, containment system and logistical support (aircraft, vessel, ROV and etc.); and e) Personnel proficiency and preparedness

The BOCP for deepwater and HPHT wells shall include a plan for suitably rated relief well which shall contain:

a) preliminary well design and well location identification; b) identification of technically acceptable drilling units operating within the region; c) identification of tangibles and back up equipment; and d) overview of drilling unit and equipment mobilisation and relevant logistical support

13.3.3 Onshore Pollution All fluids generated during drilling, rainfall and clean-up operations should be discharged in a proper and safe manner. The drains should be positioned and constructed such that they do not pose a tripping hazard for personnel or equipment and prevent contamination of the environment with hydrocarbons and drilling fluids.

The drainage system may consist of the following elements:

a) impermeable drains; b) oil and mud traps; c) waste pit; d) holding basin (optional); and e) septic tank and soak away

An impermeable open drain channel should be installed along the periphery of the location. This drain should be equipped with mud and oil traps which discharge either into the surrounding areas or into a holding basin. This depends on the contaminant and possible effects of pollution on the surrounding habitat.

The waste pit should be located next to the shale shaker of the rig to prevent double handling of the cuttings. They are sized to contain all drilling cuttings and superfluous mud that will be produced during the drilling operation. Waste water collected in a drain surrounding the rig substructure, as well as waste water produced around mud pumps, mixing tanks and chemical stores, shall also be discharged to the mud and cuttings (waste) pits.


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In tropical areas, with very high groundwater levels and high precipitation, it is not always possible to contain all contaminated liquids. In these conditions, excess water should be discharged into the surroundings or into a holding basin for further retention or treatment after passing a mud and oil retaining trap. The decision to either discharge or to retain in a holding basin will depend on the sensitivity of the environment. The waste pits and holding basin shall be impermeable. Overflowing of waste pits and holding basins shall be prevented.


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TERM IN FULL

AELB Atomic Energy Licensing Board

AFE Authorisation for Expenditure

ALARP As Low As Reasonably Practicable

API American Petroleum Institute

BHA Bottom-Hole Assembly

BHT Bottom-Hole Temperature

BOCP Blowout Contingency Plan

BOP Blowout Preventer

BPV Back Pressure Valve

CIBHP Closed-In Bottom Hole Pressure

CITHP Closed-In Tubing Head Pressure

DDR Daily Drilling Report

DOE Department of Environment

DP Dynamic Positioning

DWR Daily Workover Report

ECD Equivalent Circulating Density

EDS Emergency Disconnect System

EIA Environmental Impact Assessment

ERP Emergency Response Plan

ESD Emergency Shutdown

FBHP Flowing Bottom Hole Pressure

FDCR Final Drilling and Completion Report

FDP Field Development Plan

FMEA Failure Mode and Effect Analysis

FTHP Flowing Tubing Head Pressure

FWR Final Workover Report

H2S Hydrogen Sulphide

HAZOP Hazard and Operability Analysis

HP High Pressure

HPHT High Pressure High Temperature

Abbreviations


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TERM IN FULL

HSE Health, Safety and Environment

IMCA International Marine Contractors Association

IMO International Maritime Organization

ISO International Organization for Standardization

LMRP Lower Marine Riser Package

MD Measured Depth

MEDEVAC Medical Evacuation

MES Minimum Environmental Specification

MOC Management Of Change

MOSTI Ministry of Science, Technology and Innovation

MPD Managed Pressure Drilling

MSDS Material Safety Data Sheet

NACE National Association of Corrosion Engineers

NOOP Notice of Operations

NOWOP Notice of Workover Operations

NPT Non-Productive Time

OEM Original Equipment Manufacturer

OOC Oil on Cuttings

P&A Plug and Abandonment

PETRONAS Petroliam Nasional Berhad

PGBOOM PETRONAS Guidelines for Barges Operating Offshore Malaysia

POB Personnel on Board

POM Petroleum Operations Management

ppm parts-per-million

PRD Petroleum Resource Development

PREX Petroleum Resource Exploration

PSC Production Sharing Contract

QA Quality Assurance

QC Quality Control

RIA Radiological Impact Assessment


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TERM IN FULL

RM Ringgit Malaysia

ROP Rate of Penetration

ROV Remotely Operated Vehicle

RP Recommended Practices

RSC Risk Service Contract

SBOP Surface Blowout Preventer

SCP Sustained Casing Pressure

SCSSV Surface Controlled Subsurface Safety Valve

SID Seabed Isolation Device

SIPROD Simultaneous Production and Drilling Operations

SSC Sulphide Stress Cracking

SSSV Subsurface Safety Valve

SSV Surface Safety Valve

TD Total Depth

TENORM Technologically Enhanced Naturally Occurring Radioactive Material

TVD True Vertical Depth

USD United States Dollar

WOC Wait-On-Cement

WIMS Well Integrity Management System

WPB Work Programme & Budget


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Appendix 1

PMU Correspondence List

*Please note that all approval request and information need to be submitted to PSC Exploration Management group.

EXPLORATION STAGE

NOOP as per

Proposal

• Info (PREX) • Info (POM)

Plug & Abandonment (P&A)

G&G Issues & Overall Approval

• Approval (PREX)

Drilling Related Issues

• Endorsement (POM)

EXECUTION PLANNING

Well Proposal

• Approval (PREX) • Endorsement of Drilling

Proposal (POM)

Drilling/Other Issues

• Approval (PREX) • Endorsement (POM)

G&G Issues

• Approval (PREX)

Daily Drilling Report (DDR)

• Mandatory to PREX & POM

• FDCR Mandatory to POM

Note:

1. DDR – DAILY DRILLING REPORT

2. G&G – GEOLOGY AND GEOPHYSICS

3. NOOP –

–NOTICE OF OPERATIONS

4. FDCR FINAL DRILLING AND COMPLETION REPORT

5. POM – PETROLEUM OPERATIONS MANAGEMENT

6. PREX – PETROLEUM RESOURCE EXPLORATION

7. P&A – PLUG & ABANDONMENT

Operations


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*Please note that producing oil fields (revisit, infill, etc.) are under the Petroleum Operations Management (POM) Department while oil & gas fields are under

Petroleum Resource Development (PRD) Department.

DEVELOPMENT STAGE

Dev Proposal (not as

per approved FDP, i.e.

change reservoir target)

• Approval (PRD) • Info (POM)

Operations Plug & Abandonment (P&A)

during Drilling

Daily Drilling Report (DDR)

• Mandatory to POM & PRD • FDCR Mandatory to POM

G&G Issues & Overall Approval

• Approval (PRD)

Drilling Related Issues

• Endorsement (POM)

EXECUTION PLANNING

FDP

• Approval (PRD) • Endorsement of Drilling

Proposal (POM)

NOOP per

FDP

• Info (PRD) • Info (POM)

G&G Issues

• Approval (PRD) • Info (POM)

Drilling/Other Issues

• Approval (POM) • Info (PRD)

Note:


2. FDCR – FINAL DRILLING AND COMPLETION REPORT

3. FDP – FIELD DEVELOPMENT PLAN

4. G&G – GEOLOGY AND GEOPHYSICS

5. NOOP – NOTICE OF OPERATIONS


7. PRD – PETROLEUM RESOURCE DEVELOPMENT

8. P&A – PLUG & ABANDONMENT


106 PPGUA/3.0/042/2013

NNoottee::


2. G&G – GEOLOGIST AND GEOPHYSIST

3. NOOP – NOTICE OF OPERATION

4. P&A – PLUG & ABANDON


6. PRD – PETROLEUM RESOURCE DEVELOPMENT

7. PREX – PETROLEUM RESOURCE EXPLORATION

PRODUCTION STAGE

Plug & Abandon (P&A)

Existing Well


DECOMMISSIONING STAGE

Well Abandonment



PPGUA/3.0/042/2013 107

NAME COMPANY

Malik Faisal Abdullah PMU (Team Leader)

Adrian Chesters KPOC

Adrin Shafil Ahmad Nasir BHPB

Alistair Gauld Newfield

Astyo Budi Ardi PMU

Benjamin Choo Murphy

Christian Baranthol TOTAL

Daniel Miessner PCSB

Fauzi Abbas Hess

George Jarvis EMEPMI

Gregoire Chabrol TOTAL

Ivan Tan Boon Kiat Shell

Jim Kelly Petrofac

Keith Stewart Talisman

Khairul Annuar Nordin PMU

M Zaidan Khalid PCSB

Neil Armstrong EMEPMI

Neil Hudson PCSB

Pankaj Jain PCSB

Patrick Brenan PCSB

Rifhan Zarif M Razali PMU

Rizal Awang Newfield

Rosli Hamzah PCSB

Sofiah Sharbudeen PMU

Vince Tilley Murphy

Zuka Row Shell

Acknowledgements

(in alphabetical order)

petronas drilling operations guideline

Engineering

drilling operations

drilling units

drilling unit design

final drilling

drilling unit inspection

operations volume

daily drilling report

positioning operations