Ppgua Aug 2008 as Rolled Out Feb 2009

TABLE OF CONTENT PETRONAS PROCEDURES AND GUIDELINES FOR UPSTREAM ACTIVITIES (PPGUA)

SECTION 1 GUIDELINES FOR HEALTH, SAFETY AND ENVIRONMENT

Page I

1

Executive Summary

1

1.1

2

INTEGRATING HSE MS IN E&P LIFE CYCLE

1.2 HSE MS REQUIREMENTS AND EXPECTATIONS 1.2.1 Leadership & Commitment 1.2.2 Policy & Strategic Objectives 1.2.3 Organisational Structure, Resources & Documentation 1.2.4 Evaluation and Risk Management 1.2.4.1 Exploration Phase 1.2.4.2 Development Phase 1.2.4.3 Fabrication/Installation/HUC 1.2.4.4 Production Phase 1.2.4.5 Decommissioning Phase 1.2.5 Planning 1.2.5.1 Asset Integrity 1.2.5.2 Procedures and Work Instructions 1.2.5.3 Management of Change 1.2.5.4 Contingency and Emergency Planning 1.2.6 Implementation and Monitoring 1.2.6.1 Contractor HSE Management 1.2.7 Audit 1.2.8 Review

2 3 3 4 5 6 6 7 8 9 9 10 10 11 12 12 13 15 16

1.3

PETRONAS INSPECTION & AUDIT

16

1.4

REPORTING AND KEY PERFORMANCE INDICATOR (KPI)

16

1.5

INCIDENT REPORTING & INVESTIGATION

17

1.6

SAFETY PASSPORT

17

1.7

PROHIBITION OF DRUG AND ALCOHOL ABUSE

18

1.8

FACILITIES GAZZETTEMENT

18

1.9

OTHER RELATED PROCEDURES

19

SECTION 2 GUIDELINES FOR EXPLORATIONS SURVEY OPERATIONS

20

Executive Summary

20

2.1 FISH TRAP SURVEY OPERATIONS 2.1.1 Pre-Survey 2.1.2 Survey Operations 2.1.3 Post-Survey

21 21 21 22

2.2

23

MARINE SITE SURVEY OPERATIONS

SUPERSEDE ISSUE:

AUG 2000

ISSUED BY PETROLEUM MANAGEMENT UNIT

REVISION 2 AUG 2008

TABLE OF CONTENT PETRONAS PROCEDURES AND GUIDELINES FOR UPSTREAM ACTIVITIES (PPGUA) 2.2.1 2.2.2 2.2.3

Pre-Survey Survey Operations Post-Survey

Page II

23 23 24

2.3 MARINE SEISMIC SURVEY OPERATIONS 2.3.1 Pre-Survey 2.3.2 Survey Operations 2.3.3 Post-Survey

24 24 25 25

2.4 LAND SEISMIC SURVEY OPERATIONS 2.4.1 Pre-Survey 2.4.2 Survey Operations 2.4.3 Post-Survey

26 26 26 27

2.5 OCEAN BOTTOM CABLE AND SEABED LOGGING 2.5.1 Pre-Survey 2.5.2 Survey Operations 2.5.3 Post-Survey

27 27 28 28

SECTION 3 GUIDELINES FOR FDP REVIEW AND APPROVAL PROCESS

29

Executive Summary

29

3.1

GENERAL APPROACH

30

3.2

RESPONSIBILITY

30

3.3

CONTENT AND SUBMISSION

31

3.4

THE OVERALL PROCESS

32

3.5

KEY FEATURES OF MILESTONE REVIEWS

33

3.6

GUIDELINES FOR MILESTONE REVIEWS

35

3.7

GOVERNMENT AND PETRONAS' OBJECTIVES

36

3.8

APPROVAL FROM PETRONAS

36

3.9

FDP EXECUTION PHASE

37

3.10

DIVERGENCE FROM APPROVED FDP

38

SECTION 4 GUIDELINES FOR PROJECT DEVELOPMENT MANAGEMENT

41

Executive Summary

41

4.1

FIELD DEVELOPMENT PHASES

43

4.2

FIELD DEVELOPMENT PLAN (FDP) REVIEW AND APPROVAL PROCESS

44

SUPERSEDE ISSUE:

AUG 2000


REVISION 2 AUG 2008

TABLE OF CONTENT PETRONAS PROCEDURES AND GUIDELINES FOR UPSTREAM ACTIVITIES (PPGUA) 4.3

SPECIAL CONSIDERATIONS

Page III

45

4.4 PROJECT IMPLEMENTATION PHASES AND ACTIVITIES 4.4.1 Feasibility Study 4.4.2 Conceptual Design / Front End Engineering Design (FEED) 4.4.3 Detailed Design 4.4.4 Fabrication and Construction 4.4.5 Transportation and Installation 4.4.6 Hook-up and Commissioning (HUC) 4.4.7 Development Drilling 4.4.8 Facilities Decommissioning

46 46 47 48 49 50 51 51 52

4.5

CONTRACTING AND PROCUREMENT

52

4.6

HEALTH, SAFETY AND ENVIRONMENT (HSE)

52

4.7

PROJECT QUALITY ASSURANCE (QA)

53

4.8

REPORTING AND DOCUMENTATION

53

4.9

PROJECT PERFORMANCE

55

4.10

WORK PROGRAMME AND BUDGET (WP&B)

56

4.11

REGULATORY REQUIREMENTS

56

SECTION 5 PROCEDURES FOR DRILLING OPERATIONS

57

Executive Summary

57

5.1 DEFINITIONS 5.1.1 General 5.1.2 Specific 5.1.3 Abbreviations 5.1.4 Cross Reference Procedures 5.1.5 Official correspondence

58 58 58 61 62 62

5.2 DRILLING PROGRAMME APPROVAL 5.2.1 Notification 5.2.2 Wellsite Survey and Shallow Hazard Report 5.2.3 Well Positioning 5.2.3.1 Pre-survey Preparation 5.2.3.2 Positioning Operations 5.2.3.3 Post-positioning Works 5.2.4 Notice of Operations 5.2.5 Variations 5.2.6 Drilling Base or Drilling Unit Design 5.2.7 Support Craft 5.2.7.1 General 5.2.8 Equipment and Provision 5.2.8.1 General Requirements 5.2.8.2 Drilling Unit Ancillaries

62 62 62 63 63 63 63 63 64 65 65 65 66 66 66

SUPERSEDE ISSUE:

AUG 2000


REVISION 2 AUG 2008

TABLE OF CONTENT PETRONAS PROCEDURES AND GUIDELINES FOR UPSTREAM ACTIVITIES (PPGUA) 5.2.8.2.1 Pollution Prevention 5.2.8.2.2 Pressure Systems 5.2.8.2.3 Helideck on Drilling Units 5.2.8.3 Drilling Rigs 5.2.8.3.1 General Arrangement Drawings 5.2.8.4 BOP Equipment 5.2.8.5 Weather Data Recordings 5.2.8.6 Protection against External Hazards 5.2.8.7 Personnel Safety and Welfare 5.2.8.7.1 Safety Guards and Exits 5.2.8.7.2 Derrick Escape 5.2.8.7.3 Rotary Tongs 5.2.8.7.4 Medical Facilities and Provisions 5.2.8.8 Electrical Installation 5.2.8.8.1 Equipment and Standards 5.2.8.8.2 Lighting 5.2.8.8.3 Emergency Electrical Power Supply 5.2.8.9 Forced Air System and Ventilation 5.2.8.9.1 Hazardous Area 5.2.8.9.2 Ventilation 5.2.8.9.3 Engines and Motors 5.2.8.9.4 Exhaust Pipes 5.2.8.10 Fire Protection 5.2.8.10.1 Fire fighting equipment 5.2.8.10.2 Fire Alarm Systems 5.2.8.11 Diving 5.2.8.12 Gas Detection System 5.2.9 Personnel 5.2.10 Emergency Shutdown (ESD) 5.3 TECHNICAL REQUIREMENTS FOR DAILY OPERATION 5.3.1 General Provisions 5.3.2 Moving and Positioning Drilling Units 5.3.2.1 General Provisions 5.3.2.2 Anchor Testing For Drilling Units 5.3.2.3 Bottom Supported Units 5.3.2.4 Diving Operations 5.3.3 Casing and Cementing 5.3.3.1 General Requirements 5.3.3.2 Drive or Structural Casing 5.3.3.3 Conductor Casing 5.3.3.4 Surface Casing 5.3.3.5 Intermediate Casing 5.3.3.6 Production Casing 5.3.3.7 Pressure - Testing of Casing 5.3.3.8 Records 5.3.3.9 Cementation 5.3.3.10 Excess Cement Volume 5.3.3.11 Inadequate Cement Job 5.3.4 Well Directional Survey 5.3.4.1 Vertical Wells (Inclination ≤ 5° ) 5.3.4.2 Directional Wells (Inclination ≥ 5° ) SUPERSEDE ISSUE:

AUG 2000


Page IV

66 67 67 67 67 68 68 68 69 69 69 70 70 70 70 71 71 72 72 72 72 73 73 73 74 74 74 75 75 75 75 75 75 76 76 76 77 77 77 77 78 79 80 80 81 81 82 82 82 82 83 REVISION 2 AUG 2008

TABLE OF CONTENT PETRONAS PROCEDURES AND GUIDELINES FOR UPSTREAM ACTIVITIES (PPGUA) 5.3.5 Blowout Prevention 5.3.5.1 BOP Equipment 5.3.5.2 Auxiliary Equipment 5.3.5.3 Surface BOP 5.3.5.4 Subsea BOP 5.3.5.5 Subsea BOP Diversion 5.3.5.6 Testing of BOP 5.3.5.6.1 BOP Controls 5.3.5.6.2 Pressure Tests 5.3.5.6.3 Actuation 5.3.5.6.4 Inspection and Maintenance 5.3.6 Mud Programme 5.3.6.1 General Provisions 5.3.6.2 Mud Control 5.3.6.3 Mud Test Equipment 5.3.6.4 Mud Quantities 5.3.7 Formation Integrity Testing 5.3.8 Lost Circulation 5.3.9 Detection of Over-Pressure 5.3.10 Suspension of Operations 5.3.11 Floating Drilling Operations 5.3.12 Shallow Hazards or Hydrocarbons 5.3.13 Underbalanced Drilling 5.3.13.1 Defintion 5.3.13.2 General requirements

Page V

83 83 84 84 85 87 87 87 87 88 88 89 89 89 91 91 92 92 93 94 95 95 95 95 96

5.4 MATERIAL HANDLING AND DISPOSAL 5.4.1 Material Handling 5.4.1.1 Bulk Material 5.4.1.2 Other Materials 5.4.2 Disposal of Materials 5.4.2.1 Drilling Mud 5.4.2.2 Solid Waste 5.4.2.3 Fluid Waste 5.4.2.4 Sewage 5.4.3 Pollution Prevention

96 96 96 97 97 98 99 100 100 101

5.5 WELL EVALUATION 5.5.1 General Provisions 5.5.2 Drilling Cuttings 5.5.2.1 Sample Frequency 5.5.2.2 Sample Container 5.5.3 Cores 5.5.3.1 Conventional Cores 5.5.3.2 Side Wall Cores 5.5.4 Formation Evaluation Logging 5.5.5 Oil and Gas Flow Testing

101 101 102 102 102 102 102 102 103 103

5.6 RECORDING AND REPORTING 5.6.1 Priority Reports 5.6.1.1 General 5.6.1.2 Arrival and Rig Release Notice

103 103 103 104

SUPERSEDE ISSUE:

AUG 2000


REVISION 2 AUG 2008

TABLE OF CONTENT PETRONAS PROCEDURES AND GUIDELINES FOR UPSTREAM ACTIVITIES (PPGUA) 5.6.2 General Provisions 5.6.2.1 Daily Drilling Report 5.6.2.2 Supporting Reports 5.6.3 Final Drilling/Well Completion Report 5.6.4 Company Press Release

Page VI

104 104 105 105 106

5.7 PLUGGING AND ABANDONMENT OF WELLS 5.7.1 Responsibility to Abandon a Well 5.7.2 Application to Abandon a Well 5.7.3 Subsequent Report of Abandonment 5.7.4 Permanent Abandonment 5.7.4.1 Isolation of Zones in Open Hole 5.7.4.2 Isolation of Open Hole 5.7.4.3 Plugging or Isolation of Perforated Intervals 5.7.4.4 Plugging of Casing Stubs 5.7.4.4.1 Stub Terminating Inside Casing String 5.7.4.4.2 Stub Terminating Below Casing String 5.7.4.4.3 Liner Top or Screen 5.7.4.4.4 Plugging of Annular Space 5.7.4.4.5 Surface Plug 5.7.4.5 Testing of Plugs 5.7.4.6 Drilling Fluid 5.7.4.7 Clearance of Location 5.7.5 Well Suspension (Semi-Permanent Well Suspension) 5.7.6 Temporary Well Suspension 5.7.7 Suspended Well

106 106 107 107 107 107 108 109 109 109 110 110 110 110 111 111 111 112 112 112

5.8 COMPLETION OPERATION 5.8.1 General Provision 5.8.2 Wellhead Equipment 5.8.3 Tubing Requirements 5.8.4 Packer Requirements 5.8.5 Separation of Zones 5.8.6 Landing Nipple 5.8.7 Sub-surface Safety Valve 5.8.8 Completion Fluids

113 113 113 113 113 114 114 114 114

5.9 WORKOVER OPERATIONS 5.9.1 General Requirements 5.9.1.1 Operations 5.9.1.1.1 Workover Rigless definition 5.9.1.1.2 Workover Rig definition 5.9.1.2 Workover Structures 5.9.1.3 Pump-Down Operations 5.9.1.4 Travelling Block Safety Device 5.9.1.5 Well Control Fluids 5.9.1.6 Well Control 5.9.1.7 Well Unloading Operations 5.9.1.8 Pumping Operations 5.9.1.9 Emergency Shutdown (ESD) 5.9.2 Notification and Submittal Requirements 5.9.2.1 Notice of Workover Operations

115 115 115 115 115 116 116 116 116 117 117 117 118 118 118

SUPERSEDE ISSUE:

AUG 2000


REVISION 2 AUG 2008

TABLE OF CONTENT PETRONAS PROCEDURES AND GUIDELINES FOR UPSTREAM ACTIVITIES (PPGUA) 5.9.2.2 Workover Report 5.9.2.3 Routine Operations 5.9.3 Pressure Control Requirements 5.9.3.1 Major Workover Operations 5.9.3.2 Minor Workover Operations (Excluding Wireline Operation) 5.9.3.3 Coiled-Tubing Operations 5.9.3.4 Snubbing Operations 5.9.3.5 Other Equipment 5.9.4 Testing and Actuation Requirements 5.9.4.1 Pressure Test 5.9.4.2 Actuation 5.9.4.3 Lubricators 5.9.5 Wireline Operations 5.9.5.1 General Requirements 5.9.5.2 Operations In Cased Hole 5.9.5.3 Operations In Open Hole 5.9.5.4 Swabbing Operations 5.9.6 Rigging Up or Down of Workover or Completion Equipment

Page VII

119 119 120 120 120 121 121 122 122 122 122 123 123 123 124 124 125 125

5.10 HYDROGEN SULPHIDE (H2S) DRILLING OPERATIONS 5.10.1 General Provisions 5.10.2 Physical Properties and Toxicity of H2S 5.10.3 Breathing Equipment 5.10.4 H2S Gas Detection System 5.10.5 Wind Direction Equipment 5.10.6 Ventilation 5.10.7 Personnel Training 5.10.8 Contingency Plan 5.10.9 Rig Equipment 5.10.9.1 Drill Pipe 5.10.9.2 Tubulars 5.10.9.3 BOP and Related Equipment 5.10.9.4 Flare System 5.10.10 Drilling Operations 5.10.10.1 Pipe Trips and Stripping Operations 5.10.10.2 Well Control 5.10.10.3 Coring Operations 5.10.10.4 Mud Programme 5.10.11 Well Testing Operations

126 126 126 126 127 127 127 128 128 129 129 129 129 129 130 130 130 130 130 131

5.11 ONSHORE DRILLING OPERATION 5.11.1 General 5.11.2 Reference for Well Depth 5.11.3 Well Near Potential Hazardous Sites 5.11.4 Smoking 5.11.5 Fire Prevention and Safety 5.11.6 Engines 5.11.6.1 Internal Combustion Engines 5.11.6.2 Diesel Engines 5.11.7 Plug & Abandonment Requirements 5.11.8 Protection of Fresh Water Sands 5.11.9 Restoration of the Drill Site

131 131 131 132 132 132 132 132 133 133 134 134

SUPERSEDE ISSUE:

AUG 2000


REVISION 2 AUG 2008

TABLE OF CONTENT PETRONAS PROCEDURES AND GUIDELINES FOR UPSTREAM ACTIVITIES (PPGUA) 5.11.10 BOP Requirements 5.11.11 BOP Pressure Test 5.11.12 Flare Pit and Vent/Bleed-Off Line 5.11.13 Casings 5.11.13.1 Stove Pipe 5.11.13.2 Conductor Casing 5.11.14 Drilling Liquid Waste 5.11.15 Well Near Water 5.12 ONSHORE COMPLETION AND WORKOVER OPERATIONS 5.12.1 General 5.12.2 Sub-surface Safety Valve 5.12.3 Well Stimulation 5.12.4 Disposal of Produced Fluids 5.12.5 Onshore Wellhead Valve Assembly (X'mas Tree) 5.12.6 Wells on Pump 5.12.7 Fencing and Well Security

SECTION 6 PROCEDURES FOR SUBSURFACE SAFETY DEVICES

Page VIII

134 135 136 136 137 137 138 138 139 139 139 139 139 140 141 141

142

Executive Summary

142

6.1

INSTALLATION

143

6.2

SHUT-IN WELLS

143

6.3

INJECTION WELLS

143

6.4

VALVE SPECIFICATIONS

143

6.5

REINSTALLATION, TESTING AND MAINTENANCE

143

6.6

TUBING AND PLUG TESTING

144

6.7

ADDITIONAL PROTECTIVE EQUIPMENT

144

6.8

OTHER COMPLETION TECHNIQUES

144

6.9

RECORDS

144

SECTION 7 GUIDELINES FOR BARGES OPERATING OFFSHORE MALAYSIA

145

Executive Summary

145

7.1 INTRODUCTION 7.1.1 Application 7.1.2 Requirements 7.1.3 Definitions 7.1.3.1 ‘Steel or Other Equivalent Material” 7.1.3.2 Non-Combustible Materials 7.1.3.3 “A Standard Fire Test”

146 146 147 148 148 148 149

SUPERSEDE ISSUE:

AUG 2000


REVISION 2 AUG 2008

TABLE OF CONTENT PETRONAS PROCEDURES AND GUIDELINES FOR UPSTREAM ACTIVITIES (PPGUA) 7.1.3.4 7.1.3.5 7.1.3.6 7.1.3.7 7.1.3.8 7.1.3.9 7.1.3.10 7.1.3.11 7.1.3.12 7.1.3.13 7.1.3.14 7.1.3.15 7.1.3.16 7.1.3.17

“A” Class Divisions “B” Class Divisions “C” Class Divisions “Public Spaces” “Control Stations” “Corridors” “Accommodation Spaces” “Stairways” “Service Spaces (low risk)” “Machinery Spaces of Category A” “Other Machinery Spaces” “Hazardous Areas” “Service Spaces (high risk) “Open Decks”

Page IX

149 150 150 151 151 151 151 151 151 152 152 152 152 152

7.2 ACCOMMODATION SPACES 7.2.1 Restrictions 7.2.2 Construction of Accommodation Spaces 7.2.3 Arrangement of Sleeping Spaces 7.2.4 Size of Sleeping Spaces 7.2.5 Berths and Lockers 7.2.6 Wash Spaces, Toilet Spaces and Shower Spaces 7.2.7 Mess Rooms 7.2.8 Hospital (Sick Bay) Space 7.2.9 Hospital (Sick Bay) Space Not Required

153 153 153 154 154 154 155 157 157 158

7.3

AUTOMATIC FIRE DETECTION AND ALARM SYSTEMS

159

7.4

LIFE SAVING APPLIANCES

161

7.5 FIRE FIGHTING EQUIPMENT 7.5.1 Fire Pump 7.5.2 Fire Main 7.5.3 Fire Hose 7.5.4 Hydrants 7.5.5 International Shore Connection 7.5.6 Portable Fire Extinguisher 7.5.7 Firemen’s Outfits

162 162 162 162 163 163 163 163

7.6 PROVISION FOR HELICOPTER FACILITIES 7.6.1 Helicopter Deck 7.6.2 Fire Extinguisher

164 164 165

7.7 OPERATING REQUIREMENTS 7.7.1 Operating Manual

165 165

7.8

166

STRUCTURAL FIRE INTEGRITY TABLES

SECTION 8 PROCEDURES FOR CRUDE OIL PRODUCTION ALLOWABLES Executive Summary

SUPERSEDE ISSUE:

AUG 2000

171 171


REVISION 2 AUG 2008

TABLE OF CONTENT Page X

PETRONAS PROCEDURES AND GUIDELINES FOR UPSTREAM ACTIVITIES (PPGUA) 8.1

LONG TERM CRUDE OIL PRODUCTION FORECAST SUBMISSION BY PS CONTRACTOR

172

8.2

SHORT TERM APPROVED PRODUCTION LEVEL

172

8.3

PRODUCTION VARIATION

173

SECTION 9 PROCEDURES FOR GAS PRODUCTION & FLARING/VENTING LIMIT

175

Executive Summary

175

9.1

LONG TERM NON-ASSOCIATED GAS PRODUCTION FORECAST SUBMISSION BY PS CONTRACTOR 176

9.2

LONG TERM ASSOCIATED GAS PRODUCTION FORECAST SUBMISSION BY PS CONTRACTOR

176

9.3

SHORT TERM NON-ASSOCIATED AND ASSOCIATED GAS PRODUCTION

176

9.4 GAS FLARING / VENTING 9.4.1 Non-associated gas 9.4.2 Associated gas

177 177 178

9.5 FLARING/VENTING PERMIT

179

SECTION 10 GUIDELINES FOR ONSHORE/OFFSHORE OPERATIONS

180

Executive Summary

180

10.1

NOTICE OF INTENT

181

10.2

OPERATIONS MANUAL

181

10.3

SIMULTANEOUS OPERATIONS PROCEDURES

181

10.4 SHUTDOWN 10.4.1 Annual Shutdown Plan 10.4.2 Unplanned Shutdown

182 182 182

10.5

AS-BUILT DRAWINGS

183

10.6

DAILY PRODUCTION OPERATIONS REPORT

183

10.7

QUARTERLY PRODUCTION OPERATIONS REPORT

183

10.8

TERMINAL OPERATIONS

184

10.9

INSPECTION & OPERATIONS AUDIT

184

SECTION 11 GUIDELINES FOR FACILITIES RELIABILITY & INTEGRITY MANAGEMENT

185

Executive Summary

185

Definitions

186

SUPERSEDE ISSUE:

AUG 2000


REVISION 2 AUG 2008


Page XI

11.1

INTRODUCTION

187

11.2

FULL LIFE CYCLE MANAGEMENT

187

11.3

MANAGEMENT SYSTEM

187

11.4

OPERATIONS OF FACILITIES

189

11.5 INSPECTION AND MAINTENANCE 11.5.1 Compliance to Legislative Requirements 11.5.2 Philosophy and Related Documents 11.5.3 Minimum Requirements for Inspection & Maintenance 11.5.3.1 Topsides / Onshore Terminals 11.5.3.2 Structures 11.5.3.3 Pipelines 11.5.3.4 Wellhead and Downhole System 11.5.3.5 Subsea Systems 11.5.4 Planning and Implementation 11.5.5 Materials Management 11.5.6 Contracting and Contractor Management 11.5.7 Reporting and Key Performance Indicator (KPI)

190 190 190 191 191 194 194 196 196 197 197 197 198

11.6

MAJOR FAILURES AND CORRECTIVE ACTIONS

198

11.7

MANAGEMENT OF CHANGE

198

11.8

INFORMATION AND KNOWLEDGE MANAGEMENT

199

11.9

PRESERVATION

199

11.10 FACILITIES MODIFICATION, UPGRADING OR REJUVENATION

199

SECTION 12 GUIDELINES FOR RESERVOIR MANAGEMENT

201

Executive Summary

201

12.1 PREAMBLE 12.1.1 Reservoir Management 12.1.2 Full Field Reviews

202 202 202

12.2

EARLY DEPLETION STAGE

203

12.3

MIDDLE AND LATE STAGE

205

12.4

IMPROVED AND ENHANCED RECOVERY

205

12.5

RESERVOIR MANAGEMENT PLAN

207

12.6

WELL ABANDONMENT

207

SUPERSEDE ISSUE:

AUG 2000


REVISION 2 AUG 2008


Page XII

SECTION 13 GUIDELINES FOR WELL TEST, PRODUCTION MEASUREMENT AND ALLOCATION208 Executive Summary

208

13.1 OIL PRODUCING WELL 13.1.1 Production Rate Test 13.1.2 Bottom Hole Pressure Survey 13.1.2.1 Transient Pressure Survey 13.1.2.2 Static Bottom Hole Pressure (SBHP)Survey 13.1.2.3 Production Logging Tool (PLT) Survey 13.1.2.4 Flowing Survey 13.1.2.5 Fluid Contact Logging Survey

209 209 210 210 210 210 210 210

13.2 GAS PRODUCING WELL 13.2.1 Deliverability Test 13.2.2 Periodic Production Rate Test 13.2.3 Bottom Hole Pressure Survey 13.2.3.1 Transient Pressure Survey 13.2.3.2 Static Bottom Hole Pressure (SBHP)Survey 13.2.3.2.1 Production Logging Tool (PLT)Survey 13.2.3.2.2 Fluid Contact Logging Survey

211 211 211 212 212 212 212 212

13.3 INJECTION WELL 13.3.1 Injection Rate Measurement 13.3.2 Injectivity Test 13.3.3 Injection Profiling Survey 13.3.4 Injection Fall Off Survey

213 213 213 213 213

13.4

REQUIREMENT FOR WELL TESTING MEASUREMENT DEVICES.

214

13.5

EXCEPTION TO THE ABOVE REQUIREMENT

214

13.6

RECORD KEEPING

214

13.7 PRODUCTION MEASUREMENT AND ALLOCATION 13.7.1 Production to each Field and Platform/Production Station. 13.7.1.1 Measurement 13.7.1.2 Allocation

214 214 214 215

13.8

PRODUCTION ALLOCATION TO EACH PRODUCTION STRING

215

13.9

PRODUCTION ALLOCATION TO EACH PRODUCING INTERVAL

215

SECTION 14 GUIDELINES FOR DYNAMIC LIQUID HYDROCARBON MEASUREMENT

217

Executive Summary

217

14.1 INTRODUCTION 14.1.1 Scope 14.1.2 Distribution, Intended Use and Regulatory Considerations 14.1.3 Definitions 14.1.4 Abbreviations

218 218 218 219 223

SUPERSEDE ISSUE:

AUG 2000


REVISION 2 AUG 2008


Page XIII

14.2 GENERAL REQUIREMENTS 14.2.1 Units of Measurement 14.2.2 Approval Requirements 14.2.2.1 Measurement and Allocation Concept 14.2.2.2 Metering Project Implementation 14.2.2.3 Government Regulatory Requirement 14.2.2.4 Deviations 14.2.3 Documentation

224 224 224 224 226 227 227 227

14.3 DESIGN 14.3.1 General Requirement 14.3.2 Meter Run Design / Pipe Work 14.3.2.1 Flowmeter Type 14.3.2.2 Prover Design 14.3.2.3 Displacement Prover 14.3.2.4 Master-Meter Provers 14.3.3 Instrument Requirement 14.3.3.1 Field Instrumentation 14.3.3.1.1 Location of Sensors 14.3.3.1.2 Installation of Instruments 14.3.3.1.3 Instrument Loops 14.3.3.1.4 Transmission of Pulse Signal 14.3.3.1.5 Conversion of Signals from Analog to Digital Form 14.3.3.1.6 Temperature Measurement 14.3.3.1.7 Pressure Measurement 14.3.3.1.8 Density Measurement 14.3.3.2 Control Room Instrumentation 14.3.3.2.1 Environmental 14.3.4 Computer Based Monitoring and Control Functions Requirement 14.3.4.1 General 14.3.4.2 Data Security 14.3.4.3 Calculation 14.3.4.4 Printouts and Hardcopies 14.3.4.5 Meter Proving Algorithm Routine 14.3.4.6 Power Supply 14.3.5 Sampling and Analysis Requirement 14.3.6 Metering Data

228 228 230 232 232 233 238 239 239 239 239 240 240 241 241 241 242 242 242 243 243 244 245 246 246 247 247 248

14.4 TESTING, CALIBRATION AND COMMISSIONING 14.4.1 General Requirement 14.4.2 Calibration 14.4.2.1 General 14.4.2.2 Instrument Calibration 14.4.2.3 Prover Calibration 14.4.2.3.1 Displacement Prover Calibration 14.4.2.3.2 Master-Meter Prover Calibration 14.4.2.4 Meter Calibration 14.4.3 Testing 14.4.3.1 General Testing 14.4.3.2 Factory Acceptance Test 14.4.3.2.1 General Check 14.4.3.2.2 Metering Panel and Instrumentation Equipment Tests

249 249 249 249 250 250 250 252 253 253 253 254 254 254

SUPERSEDE ISSUE:

AUG 2000


REVISION 2 AUG 2008

TABLE OF CONTENT PETRONAS PROCEDURES AND GUIDELINES FOR UPSTREAM ACTIVITIES (PPGUA) 14.4.3.2.3 Flow Testing Calibration 14.4.3.3 Site Acceptance Test 14.4.4 Commissioning 14.4.4.1 General 14.4.4.2 Installation Quality Assurance 14.4.4.3 Commissioning 14.4.4.4 Start-up

Page XIV

257 259 260 260 260 260 261

14.5 OPERATION, VALIDATION AND ACCOUNTING 14.5.1 General Requirement 14.5.2 System Operation 14.5.2.1 Operating Manual 14.5.3 System Validation 14.5.3.1 Validation Manual 14.5.4 System Maintenance 14.5.5 Security 14.5.6 Accounting / Allocation Manual 14.5.7 Metering Station Record Keeping 14.5.7.1 Log Books/Records 14.5.8 Direct Reporting

261 261 261 263 263 264 266 266 267 267 267 269

14.6

FINAL PROVISION

270

14.7

REFERENCES

271

SECTION 15 GUIDELINES FOR GAS MEASUREMENT

275

Executive Summary

275

15.1 INTRODUCTION 15.1.1 Scope 15.1.2 Distribution, Intended Use and Regulatory Considerations 15.1.3 Definitions 15.1.3.1 General definitions 15.1.3.2 Specific definitions 15.1.4 Abbreviations

276 276 276 277 277 277 280

15.2 GENERAL REQUIREMENTS 15.2.1 Units of Measurement 15.2.2 Approval Requirements 15.2.2.1 Measurement and Allocation Concept 15.2.2.2 Metering Project Implementation 15.2.2.3 Government regulatory requirement 15.2.2.4 Deviations 15.2.3 Documentation

281 281 281 282 283 284 284 284

15.3 DESIGN 15.3.1 General Requirement 15.3.2 Mechanical Requirement and Primary Element 15.3.2.1 Orifice Meter 15.3.2.1.1 Orifice plate and fitting 15.3.2.1.2 Meter Tubes

285 285 286 286 287 287

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TABLE OF CONTENT PETRONAS PROCEDURES AND GUIDELINES FOR UPSTREAM ACTIVITIES (PPGUA) 15.3.2.1.3 Valves and Fittings 15.3.2.2 Gas Ultrasonic Flow Meter (Multipath) 15.3.2.2.1 General Requirements 15.3.2.2.2 Meter Tubes 15.3.2.3 Other Meters 15.3.3 Instrument Requirement 15.3.3.1 Field Instrumentation 15.3.3.1.1 Instrument loop 15.3.3.1.2 Differential Pressure Measurement 15.3.3.1.3 Density Measurement 15.3.3.1.4 Temperature Measurement 15.3.3.1.5 Pressure Measurement 15.3.3.1.6 Local Recorders 15.3.3.2 Control Room Instrumentation 15.3.4 Computer Based Monitoring and Control Functions Requirements 15.3.4.1 General 15.3.4.2 Data Security 15.3.4.3 Calculation 15.3.4.4 Printouts and Hardcopies 15.3.4.5 Power Supply 15.3.5 Sampling and Analytical Instrumentation 15.3.5.1 General Requirements – Sampling 15.3.5.2 On-Line Gas Chromatograph 15.3.5.3 Gas Sampler Systems

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288 289 289 290 290 291 291 291 291 292 293 294 294 295 295 295 297 297 298 298 298 298 299 300

15.4 TESTING, CALIBRATION AND COMMISSIONING 15.4.1 General Requirement 15.4.2 Calibration 15.4.2.1 General 15.4.2.2 Meter Calibration / Inspection 15.4.2.2.1 Orifice Meter 15.4.2.2.2 Ultrasonic Meter 15.4.2.3 Instrument Calibration 15.4.3 Testing 15.4.3.1 General Testing 15.4.3.2 Factory Acceptance Test 15.4.3.2.1 General Check 15.4.3.2.2 Metering Panel and Instrumentation Equipment Tests 15.4.3.3 Site Acceptance Test 15.4.4 Commissioning 15.4.4.1 General 15.4.4.2 Installation Quality Assurance 15.4.4.3 Commissioning 15.4.4.4 Start-up

300 300 301 301 301 301 302 302 302 302 303 303 303 305 306 306 307 307 307

15.5 OPERATION, VALIDATION AND ACCOUNTING 15.5.1 General Requirement 15.5.2 System Operation 15.5.2.1 Operating Manual 15.5.3 System Validation 15.5.3.1 Validation Manual 15.5.4 System Maintenance

307 307 308 308 308 309 311

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15.5.5 Security 15.5.6 Accounting / Allocation Manual 15.5.7 Metering Station Record Keeping 15.5.7.1 Log Books/Records 15.5.8 Direct Reporting

311 312 312 312 313

15.6

FINAL PROVISION

314

15.7

REFERENCE

315

SECTION 16 GUIDELINES FOR DECOMMISSIONING OF UPSTREAM INSTALLATION

316

Executive Summary

316

16.1 INTRODUCTION 16.1.1 Definitions

317 317

16.2

318

OBJECTIVE OF THE GUIDELINES

16.3 DECOMMISSIONING PHILOSOPHY AND REQUIREMENT 16.3.1 PETRONAS’ Decommissioning Philosophy 16.3.2 General Decommissioning Requirement 16.3.2.1 Safe Operations of the Facilities towards Integrity, Health, Safety and Environment (HSE) 16.3.2.2 Field Review 16.3.2.3 Legislative Requirement

318 318 319 319 320 320

16.4 LEGAL FRAMEWORK 16.4.1 General 16.4.2 Environmental 16.4.3 International Obligations

320 320 322 323

16.5 ONSHORE (LAND AND TERRITORIAL SEA) 16.5.1 Pre-Decommissioning Process 16.5.1.1 Establishment of Decommissioning Options for Onshore Facilities 16.5.1.1.1 Land Installations 16.5.1.1.1.1 Structure 16.5.1.1.1.2 Total Removal and Reinstatement of Land 16.5.1.1.1.3 Pipeline 16.5.1.1.1.4 Well 16.5.1.1.2 Territorial Sea 16.5.1.1.2.1 Sub-Structures 16.5.1.1.2.1.1 Relocate / Reuse 16.5.1.1.2.1.2 Artificial Reef 16.5.1.1.2.1.3 Total Removal 16.5.1.1.2.2 Topsides 16.5.1.1.2.2.1 Mothball / Relocate / Reuse 16.5.1.1.2.3 Pipeline 16.5.1.1.2.4 Well Abandonment 16.5.1.1.2.5 Marine Facilities 16.5.1.1.2.5.1 Relocate / Reuse 16.5.1.2 Decommissioning Plan 16.5.1.2.1 Health, Safety and Environment (HSE) Requirement Health

323 323 324 324 324 325 325 325 325 325 325 326 326 327 327 327 328 328 328 328 329

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16.5.1.2.2 Consultation and Liaison 16.5.1.3 Incorporation in Work Programme and Budget (WP&B) 16.5.2 Decommissioning Execution 16.5.2.1 Project Execution Plan 16.5.2.2 Land Installation Decommissioning 16.5.2.2.1 Structure 16.5.2.2.1.1 Mothball / Relocate / Reuse 16.5.2.2.2 Pipeline 16.5.2.2.3 Well Abandonment 16.5.2.3 Territorial Sea 16.5.2.3.1 Sub-Structure 16.5.2.3.1.1 Total Removal 16.5.2.3.1.2 Relocate/Reuse 16.5.2.3.1.3 Artificial Reef 16.5.2.3.2 Topside 16.5.2.3.3 Pipeline 16.5.2.3.4 Well Abandonment 16.5.2.3.5 Marine Facilities 16.5.3 Post Decommissioning Process 16.5.3.1 Removal of Debris and Seabed Clearance 16.5.3.2 Verification 16.5.3.3 Post Environmental Assessment 16.5.3.4 Disposal 16.5.3.5 Post Decommissioning Reports 16.5.4 Report 16.5.5 Degazettement 16.5.6 Residual Liability

330 331 331 331 332 332 332 332 332 332 332 333 333 333 334 335 335 336 336 336 336 337 337 338 338 338 338

16.6 SHALLOW WATER 16.6.1 Pre-Decommissioning Process 16.6.1.1 Establishment of Decommissioning Options 16.6.1.1.1 Sub-structures 16.6.1.1.1.1 Relocate / Reuse 16.6.1.1.1.2 Artificial Reef 16.6.1.1.1.3 Total Removal 16.6.1.1.1.4 Partial Removal 16.6.1.1.2 Topsides 16.6.1.1.2.1 Mothball / Relocate / Reuse 16.6.1.1.3 Pipeline 16.6.1.1.4 Well Abandonment 16.6.1.1.4.1 Dry Wellhead 16.6.1.1.4.2 Subsea Wellhead 16.6.1.1.5 Mobile and Floating Facilities 16.6.1.2 Decommissioning Plan 16.6.1.3 Health, Safety and Environment (HSE) Requirement 16.6.1.4 Consultation and Liaison 16.6.1.5 Incorporation in Work Programme and Budget (WP&B) 16.6.2 Decommissioning Process 16.6.2.1 Project Execution Plan 16.6.2.2 Sub-structures Decommissioning 16.6.2.2.1 Partial Removal 16.6.2.2.2 Total Removal 16.6.2.2.3 Topple

339 339 339 339 339 340 340 340 341 341 341 342 342 342 342 342 342 344 345 345 345 345 346 346 346

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TABLE OF CONTENT PETRONAS PROCEDURES AND GUIDELINES FOR UPSTREAM ACTIVITIES (PPGUA) 16.6.2.3 Topside 16.6.2.4 Pipeline 16.6.2.5 Well Abandonment 16.6.2.6 Marine Facilities 16.6.3 Post Decommissioning Process 16.6.3.1 Removal of Debris and Seabed Clearance 16.6.3.2 Verification 16.6.3.3 Post Environmental Assessment 16.6.3.4 Disposal 16.6.3.5 Post Decommissioning Reports 16.6.4 Report 16.6.5 Degazettement 16.6.6 Residual Liability 16.7 DEEPWATER 16.7.1 Pre-Decommissioning Process 16.7.1.1 Establishment of Decommissioning Options 16.7.1.1.1 Sub-structures 16.7.1.1.1.1 Relocate / Reuse 16.7.1.1.1.2 Artificial Reef 16.7.1.1.1.3 Total Removal 16.7.1.1.1.4 Partial Removal 16.7.1.1.2 Topsides 16.7.1.1.2.1 Mothball / Relocate / Reuse 16.7.1.1.3 Pipeline 16.7.1.1.4 Well Abandonment 16.7.1.1.4.1 Dry Wellhead 16.7.1.1.4.2 Subsea Wellhead 16.7.1.1.5 Mobile and Floating Facilities 16.7.1.2 Decommissioning Plan 16.7.1.3 Health, Safety and Environment (HSE) Requirement 16.7.1.4 Consultation and Liaison 16.7.1.5 Incorporation in Work Programme and Budget (WP&B) 16.7.2 Decommissioning Process 16.7.2.1 Project Execution Plan 16.7.2.2 Sub-structures Decommissioning 16.7.2.2.1 Partial Removal 16.7.2.2.2 Total Removal 16.7.2.2.3 Topple 16.7.2.3 Topside 16.7.2.4 Pipeline 16.7.2.5 Well Abandonment 16.7.2.6 Marine Facilities 16.7.3 Post Decommissioning Process 16.7.3.1 Removal of Debris and Seabed Clearance 16.7.3.2 Verification 16.7.3.3 Post Environmental Assessment 16.7.3.4 Disposal 16.7.3.5 Post Decommissioning Reports 16.7.4 Report

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TABLE OF CONTENT PETRONAS PROCEDURES AND GUIDELINES FOR UPSTREAM ACTIVITIES (PPGUA) 16.7.5 16.7.6 16.8

Degazettement Residual Liability

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363 363

PS CONTRACTORS’ OBLIGATIONS DURING HAND-OVER

SECTION 17 GUIDELINES FOR DATA MANAGEMENT AND SUBMISSION

363

365

Executive Summary

365

17.1

PREAMBLE

366

17.2

COMMITMENT AND ACCOUNTABILITY

366

17.3

DATA SUBMISSION GUIDELINE

366

17.4

DATA SUBMISSION CHECKLIST

367

17.5

DATA FORMAT STANDARD FOR SUBMISSION

367

SECTION 18 GUIDELINES FOR EMERGENCY COMMUNICATION PROCEDURE

368

Executive Summary

368

18.1

INTRODUCTION

369

18.2

SCOPE

369

18.3 DEFINITION 18.3.1 Incident 18.3.2 Emergency 18.3.3 Disaster & Crisis 18.3.4 Crisis

369 369 370 370 371

18.4

371

EMERGENCY RESPONSE PLAN

18.5 EMERGENCY CLASSIFICATION 18.5.1 TIER 1 - INCIDENT (Refer Figure 1) 18.5.2 TIER 2 - EMERGENCY (Refer Figure 2) 18.5.3 TIER 3- DISASTER & CRISIS SITUATION (Refer Figure 3)

373 373 375 378

18.6 NOTIFICATION OF EMERGENCIES AND RESPONSIBILITIES 18.6.1 PS Contractors 18.6.2 Petroleum Management Unit, PETRONAS

380 380 381

SECTION 19 GUIDELINES FOR OPERATING PERFORMANCE IMPROVEMENT (OPI)

382

Executive Summary

382

19.1

OVERALL EQUIPMENT EFFICIENCY (OEE) AND DOWNTIME DATA

383

19.2

ROOT CAUSE PROBLEM SOLVING (RCPS)

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19.3

GAP SIZING ANALYSIS

385

19.4

STAGE GATE

386

LIST OF APPENDIX Appendix 1

387

Appendix 2

396

Appendix 3

406

Appendix 4

419

Appendix 5

447

Appendix 6

451

Appendix 7

452

Appendix 8

454

Appendix 9

464

Appendix 10

465

Appendix 11

466

Appendix 12

467

Appendix 13

469

Appendix 14

470

Appendix 15

476

Appendix 16

478

Appendix 17

485

Appendix 18

519

Appendix 19

535

DEFINITION ACKNOWLEDGEMENT

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SECTION 1 GUIDELINES FOR HEALTH, SAFETY AND ENVIRONMENT Executive Summary This section provides guidelines and general requirements on managing Health, Safety and Environment (HSE) aspects of upstream petroleum operations and activities of the Production Sharing Contractor (PS Contractor) to ensure they are carried out prudently and effectively in line with the best practices currently prevalent in the industry and provide a means by which PETRONAS would be able to assess and steward the PS Contractor’s performance. In this respect, the PS Contractor shall have in place a documented Health, Safety and Environment Management System (HSE MS) or its equivalent system to ensure that the operational integrity of its upstream operations is meeting the PETRONAS HSE requirements inclusive of statutory requirements. It is the PS Contractor’s obligation to ensure that the elements of HSE MS are imbedded into their critical aspects of their exploration and production (E&P) life cycle from exploration through decommissioning. The system shall ensure continuous improvement in performance and provide evidence that all risks and critical operations have been assessed to minimise the risks to as low as reasonably practicable (ALARP).

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1.1 INTEGRATING HSE MS IN E&P LIFE CYCLE PS Contractor shall ensure that their HSE MS are integrated into the critical activities of the following generic phases of E & P below: Exploration Development Fabrication/Installation/HUC Production Decommissioning All requirements mentioned and contained in this HSE guideline shall apply equally for all PS Contractors’ activities and facilities related to E&P operations located both onshore and offshore. In managing and integrating HSE into PS Contractors’ overall business process and operations, adherence to PETRONAS guidelines and compliance to Governmental regulatory requirements are required.

1.2

HSE MS REQUIREMENTS AND EXPECTATIONS PS Contractor shall be guided by PETRONAS HSE MS requirements and expectation with regard to each phases of the E&P life cycle. However, PS Contractors are required to establish and document their own HSE MS which best suits their business and operations needs. PETRONAS envisages all their PS Contractor to be self-regulatory in all HSE aspects as part of corporate governance role, assuring and verifying HSE MS elements and complying with relevant HSE laws and regulations subscribed thereunder or in their absence, with internationally recognised standards. As part of corporate assurance process, PS Contractor HSE MS shall be independently verified via periodic audits. PS Contractor shall ensure that the operational integrity of its upstream operations is meeting PETRONAS HSE requirements inclusive of statutory requirements. A copy of PS Contractor HSE MS Manual and revisions shall be submitted to PETRONAS PMU Kuala Lumpur (KL) and Regional Offices for reference.

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PS Contractor HSE MS shall consist of at least, the following elements, basic requirements and expectations.

1.2.1 Leadership & Commitment PS Contractor Management shall demonstrate and be committed to HSE matters at all levels in its operation by having strong, visible leadership and commitment and accountability, and to make available the necessary resources to develop, operate and maintain the HSE MS. The PS Contractor Management shall visibly communicate their HSE MS to all staff and contractors. Target setting in HSE shall include proactive and reactive Key Performance Indicators (KPI’s) instilling positive HSE culture through promotions, awareness programmes, workshops and trainings. PS Contractor Management shall conduct regular HSE meetings and visits to site facilities, involve in the review of annual HSE Plan, incident investigations and audit reports in order to demonstrate overall commitment and accountability. Followings are the documentations and records that shall be in placed:Minutes of Management HSE meetings Reports of Management site visits and inspections Endorsement of HSE KPI’s and targets, HSE Cases or its equivalent, and HSE Plans Minutes of Meetings with Contractors 1.2.2 Policy & Strategic Objectives PS Contractor Management shall have HSE policies defined and documented. The policies shall be initiated, developed, supported and endorsed by the highest level of the PS Contractor Management. These policies shall also satisfy all applicable HSE regulatory requirements.

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PS Contractor Management shall draw up strategic objectives to support these policies and reflect the operational and business requirements, relevant HSE hazards and effects system and the views of employees, contractors, customers and companies engaged in similar activities. PS Contractor Management shall ensure that these objectives are periodically reviewed to suit the current business needs and changes. The PS Contractor shall ensure that only recently endorsed and dated HSE policy are made publicly available and prominently displayed at work sites and office areas for the views of all employees, contractors and visitors entering their premises or facilities. The HSE policy or its reviews shall be communicated to all employees and contractors in a language and format that is easily understood. Followings are the documentations and records that shall be in placed:Endorsed HSE Policy HSE Objectives and HSE Plans Communication of HSE policy to employees and subcontractors

1.2.3 Organisational Structure, Resources & Documentation In order to effectively implement the policy and meet the strategic objectives, PS Contractor shall establish a clearly defined organisational structure with specific roles and responsibilities relating to HSE MS. PS Contractor shall make available adequate resources, including personnel, funds and hardware necessary to ensure effective implementation of HSE MS programmes. There shall be a process in place to provide assurance of competency of all relevant personnel including appointed contractors involved in the aforementioned HSE critical E&P phases. There shall be an effective communication means to disseminate and assimilate HSE information throughout the PS Contractor’s organisation. PS Contractor shall possess all relevant reference documents and standards, including HSE legislations. PS Contractor shall have a systematic control over their HSE MS documents to ensure that they can be identified, easily retrievable and available at the point of use, SUPERSEDE ISSUE:

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periodically reviewed, versions are updated and when obsolete, they are promptly removed from the system and from use and from point of use. PS Contractor shall ensure the integrity of HSE records, establishing and recording retention times according to their availability and confidentiality. Followings are the documentations and records that shall be in placed: HSE Organisation Chart Job Descriptions including HSE responsibilities (non-HSE personnel) HSE MS Documentation Register/Masterlist Procedure on HSE MS Documentation Control HSE Requirements for Contractors HSE training matrix and records

1.2.4 Evaluation and Risk Management PS Contractor shall ensure that there is a structured HSE risk management and analysis in place to systematically identify and inventorise all health, safety and environmental risks and hazards in all phases of its activities at all levels of the E&P activities as part of its HSE MS. A Hazard and Effects Management Process (HEMP) or its equivalent shall be applied as part of the component to evaluate their severity, effects and probability of occurrence. PS Contractor shall have in place a control mechanism to minimize or eliminate non-compliances. PS Contractor shall also ensure that compliance to the statutory HSE risk assessment requirements (where applicable) are listed, but not limited to the followings:Chemical Health Risk Assessment (CHRA) Control of Industrial Major Accident Hazards (CIMAH)

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Radiation Protection Relating to TENORM in Oil and Gas Facilities Environmental Impact Assessment (EIA) All HSE risks shall be managed and reduced to ALARP, taking into account amongst factors of local conditions and circumstances, the balance of cost and benefits and the current state of technology availability and knowledge. The requirement for the PS Contractor in implementing and managing HSE risk shall be guided according to the stages of E&P below: 1.2.4.1

Exploration Phase –

Prior to commencement of any exploration activities, the appropriate HSE Risk Assessment and analysis shall be carried out in order to manage the potential adverse impact in carrying out the related activity. Followings are the documentations and records that shall be in place: HSE Risk Assessment and Analysis

1.2.4.2

Development Phase Field Development Plan (FDP) –

Prior to commencement of any oil and gas field development or construction of off-shore and on-shore pipelines in excess of 50 km in length or construction of oil and gas separation, processing, handling and storage facilities, the EIA shall be submitted for approval by DOE

–

During the above phase, PS Contractor shall develop HSE Philosophy and incorporate the requirements as part of the overall field development plan. Followings are the documentations and records that shall be in place: EIA proposal HSE Philosophy as part of FDP.

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Conceptual and Detail Design -

During the commencement of the conceptual design stage, PS Contractor shall ensure that there is a systematic approach for HSE hazard identification (HAZID).

-

In the following detail design stage, PS Contractor shall ensure that the identified hazards aspects are systematically evaluated and reviewed using technique(s) such as HAZOPS and/or QRA covering health, safety and environment. All HSE risks identified shall be managed to ensure that the control measures commensurate with the levels of risks accordingly. PS Contractor shall also include hazard recovery measures and plans in the event an HSE control fails or deviation from the operating limits.

-

Prior to actual construction work, PS Contractor shall ensure matters pertaining to the approval of EIA condition resolved.

-

Where applicable, an Environmental Management Plan (EMP) shall be prepared and submitted to DOE for approval and implementation.

Followings are the documentations and records that shall be in place: HAZID Inventory/register of HSE hazards, effects and aspects Hazards and Operability Study (HAZOP) Quantitative/or Qualitative Risk Assessment (QRA) EIA Report and approval conditions EMP 1.2.4.3

Fabrication/Installation/HUC -

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Prior to commencement of fabrication, installation and hook-up and commissioning activities, the appropriate Health Risk Assessment (HRA) and analysis shall be carried out at the worksite in order to manage the potential adverse impact accordingly.


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-

All risk control and recovery measures identified shall be documented in CIMAH report (where applicable) and/ or health and safety risk assessment, to be implemented appropriately in the respective activities.

-

PS Contractor shall ensure that during this phase, all EIA and EMP conditions are addressed and adhered to accordingly. Followings are the documentations and records that shall be in place: HSE Risk Assessment and Analysis CIMAH Report EMP

1.2.4.4

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Production Phase -

During normal production and maintenance activity, PS Contractor shall also ensure that the appropriate periodic health and safety risk management are carried out.

-

Prior to simultaneous operations (SIMOP) activity, PS Contractor shall ensure that the appropriate health, safety and risk management and analysis are carried out.

-

All risk control and recovery measures identified shall be documented in a HSE Case or its equivalent and/or CIMAH report (onshore facilities), to be implemented appropriately in the respective facilities. The content of HSE Case shall be guided by PETRONAS Technical Standard PTS 60.150 (Appendix 1.1): HSE Case Guidelines for Documentation, which is based on PETRONAS Technical Standard PTS 60.150. In the context of documenting HSE Case, flexibility is given to the PS Contractor with regards to its exact structure and format as long as all the elements are sufficiently addressed and covered in logical sequence.

-

PS Contractor shall ensure that during this phase, all EIA and EMP conditions are addressed and adhered to accordingly. ISSUED BY PETROLEUM MANAGEMENT UNIT

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Following are the documentations and records that shall be in place: HSE Case CIMAH Report EMP SIMOP procedure and other related procedures such as Management of Change (MOC) 1.2.4.5

Decommissioning Phase -

Refer to of Section 16.3 of Section 16: Guidelines for Decommissioning of Upstream Installation.

1.2.5 Planning PS Contractor shall ensure that their planning are developed strategically in line with their Corporate Strategic Objectives. The use of HSE Plan is critical in improving HSE performance, is often a long term process, requiring advance budgeting and allocation of resources. PS Contractor shall develop an annual and long term plan (preferably five-year) for achieving HSE objectives which provides an overview of planned objectives and detailed activities to be implemented for the respective year. PS Contractor shall also develop a systematic tracking system in order to monitor the progress of its implementation. The requirement for a structured HSE Plan, and the integration of HSE planning into the overall business process shall apply equally for activities carried out by PS Contractor, as well as activities carried out by contractors engaged in work and associated with the company’s activities. In case where a Division and/or Department HSE Plan has not address the HSE planning associated with a specific project/ activity (e.g. in connection with a field survey operations, drilling campaign) a Project/ Activity HSE Plan shall be prepared specifically to cater for a project-type activity. The project/ activity HSE Plan is required SUPERSEDE ISSUE:

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as an HSE planning tools, to document the identified risk control and recovery measures identified for implementation as part of the project execution. The HSE plan shall be submitted to PETRONAS PMU KL and Regional Office by December of the proceeding year for reference. Followings are the documentations and records that shall be in place: HSE Plan (annual and long term) HSE Plan tracking system 1.2.5.1

Asset Integrity For assurance of technical integrity of the assets, PS Contractor shall design out the risk through the implementation of a structured systems and documentation. To ensure that the continued integrity of asset (facilities and equipments) is safeguarded, the following shall be in placed: A practical and widely understood facilities change control system (management of change) A transparent inspection and maintenance philosophy and programme A programme where PS Contractor is able to improve through crossdiscipline/ cross-facility inspections. Detail requirements and documentations required regarding the subject can be referred to Section 11: Guidelines for Facilities Reliability and Integrity Management.

1.2.5.2

Procedures and Work Instructions The requirement for written procedures and work instructions shall apply equally for all HSE critical activities carried out by PS Contractor, as well as

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by the contractors engaged in work and associated with the company’s activities. All written work procedures and work instructions shall be clear, simple and unambiguous, and shall indicate the person responsible, the methods to be used and where appropriate, the performance standards and criteria to be satisfied. These standards shall be based on PETRONAS Technical Standards (PTS) or acceptable international standard. PS Contractor shall also develop specific procedures and work instructions for all its activities. Written work procedures shall address potential adverse HSE consequences if incorrectly performed. It shall also define the manner of conducting tasks at the work-site level. Following is the documentation and record that shall be in place: Work Procedures & Instructions 1.2.5.3

Management of Change There shall be procedures for the management of change, both permanent and temporary, in people, plant or processes or deviation from the established procedures and approval shall be sought in accordance with the requirements, to avoid adverse HSE consequences. The procedures shall also describe how PS Contractor interpret and assess the implication of new or amended legislation and how revised regulatory requirements are to be incorporated in the HSE MS. PS Contractor shall ensure that changes which may be HSE -critical be reviewed prior to implementation of the activities to ensure that their introduction does not prejudice the HSE performance. Following is the documentation and record that shall be in place: Management of Change Procedures

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SECTION 1 GUIDELINES FOR HEALTH, SAFETY AND ENVIRONMENT 1.2.5.4

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Contingency and Emergency Planning PS Contractor shall develop, document and maintain appropriate Emergency Response and Oil Spill Contingency Plan, both at the company level and at the specific location. This would serve to prevent an incident from escalating to a degree where people can be harmed or asset damaged or destroyed. These emergency response procedures shall have clearly defined communication linkages to the PETRONAS Upstream Emergency Communication Procedure (ECP) and relevant government agencies as stipulated in Section 18. To assess the effectiveness of the emergency response system, PS Contractor shall test their emergency procedures by scenario drills and exercise, at appropriate intervals as stipulated in the annual HSE Plan. PS Contractor shall also revise and update the procedure as and when necessary in the light of the findings during the drill experience gained. Followings are the documentations and records that shall be in place: Emergency Response Plan Emergency Drill and Exercise Schedule

1.2.6 Implementation and Monitoring Activities and tasks shall be conducted according to procedures and work instructions developed at the planning stage or earlier, covering broad areas of activities, in accordance with HSE policy. The effective practical implementation of the planned arrangements requires that the procedures and instructions are to be followed at all levels. PS Contractor and their contractors need to be familiar with relevant procedures and instructions before commencement of any work. Monitoring facilitates control of HSE critical activities and processes, and the detail and frequency of measurement needs to reflect the nature and extent of the risks involved, and concentrate on the areas where it produces the most benefit. Thus facilities that

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involve HSE critical activities require monitoring in more detail and at greater frequency. PS Contractor shall ensure that all tasks and activities are in compliance to the HSE MS, guidelines, procedures, work instructions and legal requirements based on the standards set and adopted. PS Contractor shall have an effective performance monitoring system in place to observe the performance of relevant aspects of HSE indicators and performance, as well as for establishing and maintaining records of the results in ensuring targets are met and continuous improvement is achieved. Relevant performance indicators shall be adopted. PS Contractor’s management shall ensure, and be responsible for, the conduct and verification of activities and tasks according to the relevant procedures. This responsibility and commitment of management to the implementation of policies and plans includes, amongst other duties, ensuring that HSE objectives are met and performance criteria and control limits are not breached. Management of PSC Ma shall ensure the continuing adequacy of the HSE performance of the company through monitoring activities. PS Contractor shall maintain a system of records as required by the HSE MS, procedures and guidelines to ensure integrity, accessibility and control of such records. The retention times of records shall be established and recorded, and procedures shall be maintained regarding their availability and confidentiality. 1.2.6.1

Contractor HSE Management PS Contractors are responsible to ensure that their contractors main aspects of HSE MS are being diligently monitored and soundly managed to ensure compliance to their own HSE policy, guidelines, regulatory requirements and standards adopted. PS Contractors shall ensure that appointed contractors are capable and financially viable to undertake the work safely and in an environmentally sound manner.

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Interfacing arrangements (bridging documents) shall be made available between the PS Contractor and their appointed contractors (where applicable) to clearly define the roles and accountability of both parties. Management of PS contractor shall pay particular attention to the following, but not limited to: Selection of contractors, including specific assessment of their HSE policy, practices and performance. It shall also cover adequacy of their HSE MS and commensurate with the risks associated with the services to be provided. Effective communication of the key elements of the contractor’s HSE MS, and the standards of worker and environmental protection expected from the contractor, including agreed HSE objectives and performance criteria Sharing by company and contractor of relevant information which may impact on the HSE performance of either. The requirement that each contractor has an effective and relevant training programme which includes records and procedures for assessing the need for further training. Methods for monitoring and assessing contractor’s performance against agreed HSE objectives and performance criteria. For main contractors, an HSE MS audit shall be conducted periodically while for minor contractors, regular inspections and visits to contractor’s facilities shall be carried out. Followings are the documentations and records that shall be in place: HSE specification in Contracts Contractor HSE Plans Contractor HSE KPI Minutes of HSE Meetings Audit and Inspection Plan for Contractors Bridging documents SUPERSEDE ISSUE:

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1.2.7 Audit PS Contractor shall develop the overall HSE audit programme and establish procedures for audit to be carried out as part of business control, in order to ensure that effective implementation of HSE management system in fulfilling the HSE policy, objectives and performance criteria, compliance to statutory requirements and identification of areas for improvement in leading to progressively better HSE management. PS Contractor shall conduct HSE MS auditing at a scheduled interval (preferably three years) determined from the seriousness of the activity concerned or from the results of previous audits by independent parties, to provide assurance that its activities are adequately performed and if not, to highlight deficiencies and recommend appropriate remedial action. PS Contractor shall have comprehensive audit protocols and systematic procedure established and maintain. PS Contractor is expected to conduct site specific HSE audit programme on activities at site to further ensure excellent HSE practices on their operations. PS Contractor is also responsible for the follow-up of the recommendations made. The audit shall cover the operations of the HSE MS and the extent of its integration into line activities. PS Contractors shall also carry out regular inspection and management visits at all locations. PS Contractor shall extend invitation to PETRONAS for participation at least one month notice prior to the above HSE MS and HSE audit exercise. PS Contractor shall also provide PETRONAS PMU KL and Regional Office a copy of the final HSE MS audit report one month after completion of the audit exercise. Followings are the documentations and records that shall be in place: HSE MS & HSE Audit Plan & Procedures HSE MS & HSE Audit Final Report Audit Plan for Contractors Tracking records on audit findings closure

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1.2.8 Review PS Contractor senior and/or appointed management representative shall, at appropriate intervals (at least every five years), conduct regular reviews of the HSE MS to ensure its continuing suitability, effectiveness and performance whilst identifying gaps so that remedial actions can be undertaken. Upon review, the revised HSE MS together with the basis of the changes shall be submitted to PETRONAS one month after completion of the revision. Followings are the documentations and records that shall be in place: Revised HSE MS documents Basis of changes

1.3 PETRONAS INSPECTION & AUDIT PETRONAS reserves the rights to conduct HSE site visit, inspection or technical audit at PS Contractor’s operational locations, wherever and whenever necessary. PS Contractorsshall provide the necessary arrangements and cooperation throughout the exercise. The inspection and audit team shall consists of officials from PMU KL and / or PMU region or its appointed representative(s), and where applicable the PS Contractor shareholder/equity partners. For the purpose of paragraph 1.3 herein “Appointed representative(s)” means designated individual(s) or company(ies) that shall have the authority to act on behalf of PMU, in all matters connected with the performance of the site visit, inspection or technical audit.

1.4 REPORTING AND KEY PERFORMANCE INDICATOR (KPI) a.

HSE KPI PS Contractor shall monitor and report the Health, Safety and Environment (HSE) effectiveness using Key Performance Indicators (KPI), as stipulated in Appendix

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1.2. PS Contractor HSE performance report is to be submitted to PETRONAS PMU KL and Regional Offices on monthly basis (by the 15th of following month). b.

Documents submission Appendix 1.3 stipulates the list of documents required for submission to PETRONAS PMU KL and Regional Offices (where applicable).

1.5 INCIDENT REPORTING & INVESTIGATION PS Contractor is responsible to immediately notify PETRONAS of any incidents or accidents that are related to their operations. The detail incident notification procedures are stipulated in Guidelines for Emergency Communication Procedure, Section 18. PETRONAS reserves the right to participate in any or all investigations to be undertaken by PS Contractor. A full report of the incident pertaining to fatality, loss time incidents or that causes severe damage to asset, environment and reputation that require full investigation by the PS Contractor shall be submitted to PETRONAS within a month from the date of the incident.

1.6 SAFETY PASSPORT Any person going to offshore facilities must possess valid safety passport issued from the PS Contractor. For all employees and contractor personnel, the prerequisite trainings shall be obtained from PETRONAS accepted Training Providers, and medical examination shall be conducted by the Approved Medical Examiners or examining doctors as outlined in the Offshore Medical Guidelines. The followings are the minimum standards in BOSET (Basic Offshore Safety and Emergency Training): Basic Offshore Training Basic Sea Survival Training

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Basic Fire Fighting HUET (Helicopter Underwater Escape Training) & Emergency Breathing System (EBS) Provided the above trainings and medical requirements are met, a valid safety passport issued by one PS Contractor, shall be accepted by another PS Contractor. Where there is specific condition/risk involved and/or additional competencies required, the person is obliged to adhere to the additional trainings outlined by the PS Contractor.

1.7 PROHIBITION OF DRUG AND ALCOHOL ABUSE PETRONAS prohibits and view seriously the abuse of drug and alcohol consumption for reasons that the acute and chronic use of both affects the judgement and mental alertness of a person that are essential parameters for safe and productive work operations. It is the PS Contractor’s obligation and responsibility to have a policy and procedure which includes but not limited to systematic method of identification, screening, testing and verification process that shall be implemented throughout their organisation and followed by their employees and appointed contractors to ensure that its workplaces are alcohol and drug free at all times. Any form of possession, use and manufacture of drugs and alcohol for work related purposes particularly involving PETRONAS processes and operations are strictly prohibited and excluded.

1.8 FACILITIES GAZZETTEMENT In accordance to the Protected Areas and Protected Places Act 1959, PS Contractor shall apply to PETRONAS for gazzettement within six months after installation of the facilities by submitting the information and documentations (Refer Appendix 1.4). Further details on the application process can be referred to Appendix 1.5.

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OTHER RELATED PROCEDURES This guideline is to be read together with; Malaysian statutory requirements as prescribed under EEZ, MARPOL, LEM/TEK, OSHA, EQA, State Ordinance, Acts, etc. Decommissioning Guidelines Production and Operations Guidelines Drilling Guidelines Emergency Communication Procedures

- END OF SECTION 1 -

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SECTION 2 GUIDELINES FOR EXPLORATIONS SURVEY OPERATIONS Executive Summary This Section provides guidelines and general requirements in conducting the following operations in Accordance to the Production Sharing Contract i.e.: Fish Trap Survey Operations Marine Site Survey Operations Marine Seismic Survey Operations Land Seismic Survey Operations; and Ocean Bottom Cable and Seabed Logging Operations PS Contractor shall observe and comply with the above guidelines prior to and during undertaking the surveys. Nevertheless this guideline does not cover all aspects of the above survey operations and shall be regarded as PETRONAS'general guidelines necessary for ensuring a safe and cause minimal impact to the existing infrastructures and environment in the operating areas. In cases where either equipment or scopes of the survey operations are not listed or specified in these guidelines, PS Contractor shall derive the scope based on industry best practices, internationally acceptable codes and standards, applicable Malaysian Laws and shall implement the same accordingly.

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FISH TRAP SURVEY OPERATIONS

2.1.1 Pre-Survey PS Contractor shall notify PETRONAS and Relevant Authorities (refer to Appendix 2.1) on the necessity to conduct the Fish Trap Survey, including area of operations, timing, duration, vessel name, place of registration, call sign and specifications. Notification of Fish Trap Survey to PETRONAS and Relevant Authorities shall be submitted at least 14 days prior to the survey commencement. The planned survey area shall not be conducted beyond Malaysian waters without prior approval from the Relevant Authorities and authorities of the affected countries. In all correspondences with Relevant Authorities, all surveys to be conducted by PS Contractor shall be identified as PETRONAS’ and PS Contractor’s surveys.

2.1.2 Survey Operations PS Contractor is to ensure representatives from both fishermen and Fisheries Department are included as witnesses to the survey. These representatives are to be appointed by the Fisheries Department and preferably had undergone basic sea survival training and shall adhere to Guidelines for Health, Safety and Environment (HSE) (refer to Section 1) prior to going onboard the vessel for the Fish Trap Survey. PS Contractor is to ensure that a suitable vessel and equipment to be deployed for the Fish Trap Survey comply to the Health, Safety and Environment (HSE) requirements. PS Contractor is to include requirement of ‘HALAL’ food and ‘NO LIQUOR’ on the vessel as part of Tender Documents. PS Contractor shall prepare a list of focal point/ on duty personnel to be contacted for emergency purposes. PS Contractor and the Survey Contractor shall develop their in-house Project Safety Plan for evacuation programme and all HSE requirements shall be based on Guidelines for Health, Safety and Environment (HSE) (refer to Section 1). PS Contractor shall ensure that all offshore personnel employed onboard the vessel is to carry their personal identification. SUPERSEDE ISSUE:

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All fish traps observed within the survey area are to be identified and recorded appropriately. Logging of observed devices to include date, location, time and to be supported with photographs. It is recommended that PS Contractor engage an experienced scouting company, equipped with proper positioning system for the survey. Some of the common types of Fish Trap and Fish Aggregating Devices are shown in Appendix 2.2A to 2.2F.

2.1.3 Post-Survey All data or maps to be submitted to PETRONAS and the Relevant Authorities shall be treated and addressed as confidential matters. Total compensations to fishermen are to be agreed prior to the seismic survey. If under operational situation where negotiation may not take place prior to seismic survey, PS Contractor is to notify the Fisheries Department to proceed with the seismic survey. Representative from fishermen and Fisheries Department are both required to support the actual negotiation on the compensations to be paid to the fishermen after the seismic survey is completed. All compensation shall be made through Fisheries Department. PS Contractor shall submit close-out report to PETRONAS for any compensation made. PS Contractor shall report to Fisheries Department on all Fish Trap matters. PS Contractor shall request PETRONAS assistance should any problem arises between Fisheries Department, Fishermen, Federal Government or any other local authorities.

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MARINE SITE SURVEY OPERATIONS

2.2.1 Pre-Survey PS Contractor shall notify PETRONAS and Relevant Authorities prior to Marine Site Survey commencement, including area of operations, timing, duration, vessel name, place of registration, call sign and specifications. Notification of Marine Site Survey to PETRONAS and Relevant Authorities shall be submitted at least 14 days prior to the Marine Site Survey commencement. Subject to statutory requirement especially for coastal areas, the authority may require PS Contractor to conduct Environmental Impact Assessment (EIA) prior to Marine Site Survey. The operations of Marine Site Survey shall not be conducted beyond Malaysian waters without prior approval from the Relevant Authorities and the authorities of the affected countries. PS Contractor shall ensure that all personnel onboard the survey vessel have undergone a basic sea survival training and shall adhere to Guidelines for Health, Safety and Environment (HSE) (refer to Section 1).

2.2.2 Survey Operations PS Contractor is to ensure that a suitable vessel and equipment to be deployed for the Marine Site Survey operations comply to Health, Safety and Environment (HSE) requirements. Technical inspections to be carried out prior to mobilisation of the site survey vessel. PS Contractor is to include requirement of ‘HALAL’ food and ‘No LIQUOR’ on the vessel as part of Tender Documents. PS Contractor to prepare a list of focal point/on duty person to be contacted for emergency purposes. PS Contractor and the Survey Contractor shall develop their in-house Project Safety Plan for evacuation programme and all HSE requirements shall be based on Guidelines for Health, Safety and Environment (HSE) (refer to Section 1). SUPERSEDE ISSUE:

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PS Contractor shall ensure that all offshore personnel employed onboard the vessel is to carry their personal identification.

2.2.3 Post-Survey PS Contractor shall submit close-out report to PETRONAS. The report shall be both in hard copy and acceptable electronic format. PS Contractor shall submit all site survey data and maps to PETRONAS upon completion and prior to expiry of the block as required by the Production Sharing Contract. PS Contractor shall request PETRONAS assistance should any problem arises between Fisheries Department and Relevant Authorities.

2.3 MARINE SEISMIC SURVEY OPERATIONS 2.3.1 Pre-Survey PS Contractor shall prepare Marine Seismic Survey Proposal together with a forecasted project schedule to PETRONAS and shall get Partner’s concurrence prior to submission of technical approval to conduct Marine Seismic Survey. PS Contractor shall notify PETRONAS and Relevant Authorities to conduct Marine Seismic Survey including area of operations, timing, duration, vessel name, place of registration, call sign and specifications. Notification of Marine Seismic Survey to PETRONAS and Relevant Authorities shall be submitted at least 14 days prior to the survey commencement. Subject to statutory requirement especially for coastal areas, PS Contractor may conduct Environmental Impact Assessment (EIA) prior to seismic survey. The operations of Marine Seismic Survey shall not be conducted beyond Malaysian waters without prior approval from the Relevant Authorities and authorities of the affected countries. PS Contractor shall ensure that all personnel employed onboard Marine Seismic Survey vessel have undergone basic sea survival training and shall adhere to Guidelines for Health, Safety and Environment (HSE) (refer to Section 1). SUPERSEDE ISSUE:

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2.3.2 Survey Operations PS Contractor is to ensure that a suitable vessel and equipment to be deployed for the Marine Seismic operations comply to Health Safety and Environment (HSE) requirements. Technical inspections to be carried out prior to mobilisation of the seismic and escort vessels. PS Contractor is to include requirement of ‘HALAL’ food and ‘No LIQUOR’ on the vessel as part of Tender Documents. PS Contractor to prepare a list of focal point/on duty personnel to be contacted for emergency purposes. PS Contractor and the Survey Contractor shall develop their in-house Project Safety Plan for evacuation programme and all HSE requirements shall be based on Guidelines for Health, Safety and Environment (HSE) (refer to Section 1). PS Contractor shall ensure that all offshore personnel employed onboard the vessel is to carry their personal identification. PS Contractor shall submit a daily and weekly survey reports to PETRONAS for the whole survey duration.

2.3.3 Post-Survey PS Contractor shall submit to PETRONAS a full operation report. The report shall be both in hard copy and acceptable electronic format. PS Contractor shall also submit all seismic data and maps to PETRONAS upon completion and prior to expiry of the block as required by the Production Sharing Contract. PS Contractor shall request PETRONAS assistance should any problem arises between Fisheries Department and Relevant Authorities.

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LAND SEISMIC SURVEY OPERATIONS 2.4.1 Pre-Survey PS Contractor shall prepare Land Seismic Survey Proposal together with a forecasted project schedule to PETRONAS and shall get Partner’s concurrence prior to submission of technical approval to conduct Land Seismic Survey. PS Contractor shall notify PETRONAS and Relevant Authorities to conduct Land Seismic Survey including area of operations, timing and duration. Notification of Land Seismic Survey to the Relevant Authorities shall be submitted 30 days prior to the Land Seismic Survey commencement. Subject to statutory requirement, PS Contractor may conduct Environmental Impact Assessment (EIA) prior to survey. PS Contractor shall ensure that all personnel have undergone through appropriate HSE training and shall adhere to Guidelines for Health, Safety and Environment (HSE) (refer to Section 1).

2.4.2 Survey Operations PS Contractor is to ensure that a suitable equipment to be deployed for the Land Seismic Survey operations comply to Health Safety and Environment (HSE) requirements. Technical Audit to be carried out on seismic crew prior to commencement of Land Seismic operations. PS Contractor is to include requirement of ‘HALAL’ food and ‘No LIQUOR’ as part of Tender Documents. PS Contractor to prepare a list of focal point/ on duty personnel to be contacted for emergency purposes. PS Contractor and the Survey Contractor shall develop their in-house Project Safety Plan for evacuation programme and all HSE requirement shall be based on Guidelines for Health, Safety and Environment (HSE) (refer to Section 1).

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PS Contractor shall ensure that all personnel employed possess a valid personal identification. PS Contractor shall submit a daily and weekly survey reports to PETRONAS for the whole survey duration.

2.4.3 Post-Survey PS Contractor shall submit to PETRONAS a full operation report. The report shall be both in hard copy and acceptable electronic format. PS Contractor shall also submit all seismic data and maps to PETRONAS upon completion and prior to expiry of the block as required by Production Sharing Contract. PS Contractor shall request PETRONAS assistance should any problem arises between any Relevant Authorities.

2.5 OCEAN BOTTOM CABLE AND SEABED LOGGING 2.5.1 Pre-Survey PS Contractor shall prepare Ocean Bottom Cable and Seabed Logging Proposal together with a forecasted project schedule to PETRONAS and shall get Partner’s concurrence prior to submission of technical approval to conduct the survey. PS Contractor shall notify PETRONAS and Relevant Authorities to conduct Ocean Bottom Cable and/or Seabed Logging, including area of operations, timing, duration, vessel name, owner and specifications. Notification of Ocean Bottom Cable and Seabed Logging to the Relevant Authorities shall be submitted 30 days prior to the survey commencement. Subject to statutory requirement especially for coastal and deepwater areas, PS Contractor shall conduct Environmental Impact Assessment (EIA) prior to seismic survey. The operations of Ocean Bottom Cable and Seabed Logging Surveys shall not be conducted beyond Malaysian waters without prior approval from the Relevant Authorities and authorities of the affected countries. SUPERSEDE ISSUE:

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PS Contractor shall ensure that all personnel to be onboard Ocean Bottom Cable and Seabed Logging vessel have undergone basic sea survival training and shall adhere to Guidelines for Health, Safety and Environment (HSE) (refer to Section 1).

2.5.2 Survey Operations PS Contractor is to ensure that a suitable vessel and equipment to be deployed for the Ocean Bottom Cable and Seabed Logging operations comply to Health Safety and Environment (HSE) requirement. Technical inspection to be carried out prior to mobilisation of the seismic and escort vessels. PS Contractor is to include requirement of ‘HALAL’ food and ‘No LIQUOR’ on the vessel as part of Tender Documents. PS Contractor to prepare a list of focal point/on duty personnel to be contacted for emergency purposes. PS Contractor and the Survey Contractor shall develop their in-house Project Safety Plan for evacuation programme and all HSE requirements shall be based on Guidelines for Health, Safety and Environment (HSE) (refer to Section 1). PS Contractor shall ensure that all offshore personnel employed onboard the vessel is to carry their personal identification. PS Contractor shall submit a daily and weekly survey reports to PETRONAS for the whole survey duration.

2.5.3 Post-Survey PS Contractor shall submit to PETRONAS a full operation report. The report shall be both in hard copy and acceptable electronic format. PS Contractor shall also submit all survey data and maps to PETRONAS upon completion and prior to expiry of the block as required by the Production Sharing Contract. PS Contractor shall request PETRONAS assistance should any problem arises between Fisheries Department and Relevant Authorities. - END OF SECTION 2 SUPERSEDE ISSUE:

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SECTION 3 GUIDELINES FOR FDP REVIEW AND APPROVAL PROCESS Executive Summary This Section Provides guidelines and general requirements for Field Development Plan review and approval process for PS Contractor to comply. The approach taken by PETRONAS to the process of Field Development Plan (FDP) review and approval is to establish whether there are any aspects of the proposed development which may conflict with Government and PETRONAS'objectives and to focus attention on resolving those aspects before the formal comprehensive FDP is submitted.

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3.1 GENERAL APPROACH 3.1.1

The approach taken by PETRONAS to the process of Field Development Plan (FDP) review and approval is to establish whether there are any aspects of the proposed development which may conflict with Government and PETRONAS’ objectives and to focus attention on resolving those aspects before the formal comprehensive FDP is submitted.

3.1.2

In the event of any conflict inconsistency between this guideline and the Production Sharing Contract (PSC), the PSC shall prevail.

3.2 RESPONSIBILITY 3.2.1

The Petroleum Management Unit (PMU) will coordinate the overall field development process review involving milestone reviews, PETRONAS’ review and approval and FDP execution.

3.2.2

PMU has established a Technical Review Committee (TRC) as a technical advisory role to PMU Management in assessing field development plans proposed by PSCs, during the milestone reviews. The main objectives of the TRC are: a)

To provide consistent quality assurance on all technical deliverables conducted by PSC contractors or service providers to PMU as well as providing critical challenges and constructive feedbacks to the project team to ensure all technical objectives are being met.

b)

To enhance PMU technical processes before, during and after project being executed by capturing and disseminating lesson learnt from one project to the other.

c)

To contribute towards close co-operation and smooth execution of the project by providing prompt and practical feedback to the PSCs and service providers.

3.2.3

Depending on the circumstances of each specific project, the scope of the TRC may be a complete review of the entire program, including conforming to applicable methods, technologies, standards, the appropriateness of the assumptions and input data to support the design. Or it might just be limited to specific aspects of the design program on specific tasks.

3.2.4

Endorsement of the Technical review committee must be received for each of the 4 milestones in the FDP approval processes:

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• Planning (MR#1) • Static Model (MR#2) • Dynamic Model (MR#3) • Development Model (MR#4)

3.3

CONTENT AND SUBMISSION

3.3.1

The content of the FDP shall be as defined in the PSC. PETRONAS'requirement is that any FDP submitted should be a comprehensive stand-alone document with a complete set of information and/or references that would provide the evaluator with a better and easier understanding and rationale for the field development proposed.

3.3.2

For FDP Revisions, the update specific to the scope where changes are required will be sufficient for submission and approval by PETRONAS.

3.3.3

PS Contractor shall submit three copies of the final FDP for approval by PETRONAS (PMU). There are four categories of projects that have been identified as requiring an FDP. As a general guide, the categories of the projects are tabulated in Table 3.1A.

3.3.4

In Joint Venture PSCs, FDP can be submitted to PETRONAS prior to partner’s endorsement but PETRONAS will only provide endorsement/approval upon partner’s endorsement. PS Contractor is to ensure that endorsement from Partner(s) is timely submitted to PETRONAS to avoid delay in FDP endorsement/approval. Table 3.1A : Project Categories Milestone Reviews *

Category

Scope

Green Project

Field development in a virgin field or further development of producing field from new platforms

MR#1, MR#2, MR#3,MR#4,

Petroleum Resources Development, PMU

Brown Project

Further development of producing reservoirs or new reservoirs from an existing platform

MR#1, MR#2, MR#3,MR#4


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Category

Scope

Facilities Modification, Upgrading or Rejuvenation Project.

Project that involves modifications/upgrading to the existing surface facilities to ensure facilities integrity and sufficient capacity for continuing operations.

Milestone Reviews *

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Approval By

MR#1,MR#4,

Petroleum Operations Management, PMU

Enhanced Oil Recovery Advanced recovery techniques MR#1, MR#2, (EOR) Project going beyond what are MR#3,MR#4, considered conventional methods at a given reference point in time. Typical features of advanced recovery techniques are injection of substances other than water and/or hydrocarbon gas into the reservoir to enhance oil recovery.


*Note: Document to be submitted is Facilities Improvement Plan (FIP) / Facilities Rejuvenation Plan (FRP). Refer Section 11.

3.4

THE OVERALL PROCESS

3.4.1

The overall FDP Review, Approval and Implementation Process is illustrated in the Figure 3.1 below. There are a total of eight steps; the first four steps are the designated FDP Milestone Reviews with PS Contractor which are conducted before the FDP is submitted, the next two are the internal approval process while the last two are the FDP (project) implementation stages.

3.4.2

PS Contractors will be allowed some flexibility to decide on the number, content and timing of the Milestone Reviews, as long as it does not deviate from the principle of early PETRONAS'involvement from the planning stage of the prospective field to the completion of the project.

3.4.3

There are times when PS Contractors may want to seek early guidance from PMU with regard to specific FDP requirements and/or the Milestone Review process. In such cases, a pre-MR1 meeting with relevant PMU contact person(s) can be requested.

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The meeting can be used to clarify issues such as the types and scope of project, approval requirements, timing expectation for approval, etc.

Pre-FDP Milestone Review

PLANNING MODEL MILESTONE REVIEW

G & G MODEL MILESTONE REVIEW

RESERVOIR MODEL MILESTONE REVIEW

A

DEVELOPMENT MODEL MILESTONE REVIEW

Pre-MR MEETING (if needed) EXTERNAL INTERNAL

A

PETRONAS EVALUATION

PS CONTRACTOR SUBMITS FDP

PETRONAS APPROVAL

Y

MANAGING FDP EXECUTION BY DEVIATION

FIRST OIL/ GAS

N FDP Approval

Post FDP Implementation Stage

Figure 3.1: FDP Approval Process

3.5

KEY FEATURES OF MILESTONE REVIEWS

3.5.1

The Milestone Review process is proposed in order to maintain a continuing dialogue and technical reviews as the description of a field and options for its development emerge during the development planning studies.

3.5.2

For a typical field development, the process will be guided by four Milestone Reviews pre-FDP approval and post-FDP project implementation process. The definition and the minimum key activities expected for each Milestone and government requirements are given in Appendix 3.1 and Appendix 3.2 respectively. The Milestones are not always applied in such an orderly way to all fields. It is recognized that there will most likely be a maturation cycle before every aspects have been defined in sufficient detail to enable the preparation of a FDP to be completed.

3.5.3

Following the definitions given, the timing of the Milestone Reviews will coincide with the completion of each major engineering discipline. In general, this structured process should assist the PS Contractors and PETRONAS in having an effective process where at each milestone the agreed technical assessment will form the basis of the next milestone discussion/evaluation. With the formation of the TRC, the issue

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of discontinuity in the review team players for all milestones discussion can be avoided. This will also avoid unnecessarily revisiting items that have been discussed and agreed during the previous milestones. 3.5.4

From PETRONAS'perspective, the objective of the Milestone Reviews is not to have the detailed review of every area of the development but rather the identification and resolution of any aspects of the development which may contradict Government and PETRONAS'objectives and on which the views of PETRONAS and PS Contractor may diverge. These aspects will be examined more thoroughly with the PS Contractor with the aim of reaching mutually satisfactory conclusions.

3.5.5

To expedite FDP endorsement/approval in meeting contractual obligation of field development timing, PETRONAS may provide notification of any aspects of the development where a conflict is expected and is likely to cause delay or prevent the approval of the FDP. If substantive issues are identified, a more detailed investigation of the elements of the development essential for the resolution of these issues will be made, and PS Contractor will be expected to work and develop the necessary rationale towards justifying the plans before the FDP is submitted.

3.5.6

While PETRONAS may tentatively agree on the technical aspects of the development planning studies, this should not be construed as the final approval in the context of the PSC. PS Contractor should be aware that any agreement during the Milestone Reviews shall be without prejudice to the final decision of PETRONAS'Management or other Government bodies which may have an interest in the development plan upon submission of the final FDP.

3.5.7

The figure 3.2 below summarizes the format with respect to Milestone Reviews and approval points and the expected benefit from the new process.

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GUIDELINES FOR MILESTONE REVIEWS

3.6.1

A meeting shall be held at the completion of each Milestone. Two (2) or more Milestones may be combined depending on the size, complexity and schedule of the project. The decision to combine various Milestones for discussion shall be mutually agreed between PETRONAS and PS Contractor. This can be accomplished at the pre-MR meeting discussed earlier.

3.6.2

The Milestone Review dates or schedules shall be mutually agreed between PETRONAS and PS Contractor. With the establishment of the TRC to coordinate and streamline the Milestone Reviews in PETRONAS, PS Contractor may choose to integrate Milestone Reviews with PS Contractor specific internal reviews by inviting relevant TRC members to sit in the internal reviews, where appropriate. Similarly, as PCSB is a Joint Venture Partner in most of the PSCs, PETRONAS may elect to integrate the Milestone Review with PCSB specific internal project reviews, where appropriate.

3.6.3

Any Milestone Reviews with PETRONAS must be agreed by all its Joint Venture partner(s) involved in the field of interest in accordance with their respective Joint Operating Agreements (JOAs).

3.6.4

PETRONAS may at its discretion, call for a meeting to discuss matters of specific interest or request an update of a particular project.

3.6.5

PS Contractor shall furnish to PETRONAS the discussion materials or any supporting documentation, at least three (3) days before the proposed date of each meeting.

3.6.6

If substantive issues have been identified and cannot be resolved during the Milestone Reviews, it may be necessary to refer the issues to the respective Parties' Management for their consideration and direction. The resolution of the issues should not in any way prevent the progress of the development planning studies.

3.6.7

Minutes of Meetings shall be taken by PS Contractor and submitted to PETRONAS within one (1) week after the meeting.

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3.7

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GOVERNMENT AND PETRONAS' OBJECTIVES

3.7.1

In principle, under a PSC, while PETRONAS and PS Contractor have similar objectives i.e., the optimum development of the petroleum resources of the contract area, PETRONAS with the interest of the Nation, naturally goes beyond purely commercial considerations. As Custodian of all hydrocarbon resources in the country and resource manager, PETRONAS is also interested in making sure that a given development plan provides an optimum solution in the context of total development balanced with cost effective solutions.

3.7.2

PETRONAS as a whole has the responsibility to ensure long-term protection and development of domestic hydrocarbon resources. With this big responsibility, PETRONAS would want to be fully conversant and be made aware of the assumptions used in planning for field development process from the early stage of planning until the development stage. This could help to clarify the key issues that need to be tracked as the FDP process moves forward and potentially highlight unconventional development options that may not necessarily be considered such as to include different technology options, alternative facilities plans, and proper reservoir management plan.

3.7.3

In addition to the current Government and PETRONAS' objectives of field development objectives applicable to the majority of field developments circumstances may arise where PETRONAS may need to take into account broader issues or policies into consideration.

3.8

APPROVAL FROM PETRONAS

3.8.1

PETRONAS will endeavor to approve the FDP within two months from the official date of receipt of fully endorsed FDP by all parties, provided that there are no unresolved issues.

3.8.2

The early review of draft sections or whole FDP document as these become available will help achieve this objective. PS Contractor may choose to extend copies of the draft FDP sent to their JV Partners for parallel review by PETRONAS to help expediting the approval process.

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FDP EXECUTION PHASE

3.9.1

The scope of the subsurface and surface development plan in the FDP shall cover but not be limited to all subjects discussed in milestone reviews as per Appendix 3.3 of this guideline.

3.9.2

The subsurface plan must also address potential applicability of enhanced and/or improved recovery mechanisms including the potential for their current or future integration with any secondary recovery gas and/or water injection) operations. In particular it must address potential for improved recovery and geo-sequestration through carbon dioxide injection into fields/reservoirs located in regions where gas reservoirs with high carbon dioxide are known to occur.

3.9.3

One of the important aspects in the FDP shall be the definition of uncertainties, possible subsurface alternative scenarios and the range of possible forecast outcomes. It must address the full field life cycle and not be limited to the life of the initial PSC.

3.9.4

PS Contractor is encouraged to address reservoir uncertainties when formulating well objectives by providing contingency plans as secondary objectives, over and above the primary objectives of the well.

3.9.5

The scope of FDP approval will be extended to cover the approval to drill development wells (including contingency plans/strategy) as proposed in the approved FDP. The Notice of Operation (NOP) for each well will be submitted to PETRONAS for information only, if all drilling issues have been addressed prior to FDP approval. Refer to Section 3.10.4 and Appendix 3.4.

3.9.6

The following information should be provided in the FDP w.r.t. drilling; a)

individual well objectives post historical offset well data, if any

b)

contingency plan w.r.t. uncertainties in well location or objectives

c)

typical casing depth and completion type and design, provide explanation on concept selection and all drawing attached

d)

general description of type of fluid/mud to be used including plot of pore pressure and fracture gradient

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describe all new technology application, if applicable ISSUED BY PETROLEUM MANAGEMENT UNIT

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describe abandonment programs for proposed well completion with schematic diagrams (this will be discussed again when requesting for P&A approval as completion may change with time due to wellbore intervention)

g)

describe potential production problems

h)

estimated overall drilling cost and time

i)

type of drilling rig, schedule and implementation plan

j)

expected Non-Productive Time(NPT)

k)

drilling trajectory plan and Bottom Hole Assembly (BHA) design

l)

description of selection of open hole (OH) logging program proposed

m)

anticipated problems and drilling hazard

n)

proposed completion program including the wellhead and x-tree configuration

o)

describe bit selection and hydraulics

3.10 DIVERGENCE FROM APPROVED FDP 3.10.1 Once a comprehensive FDP has been approved, PS Contractor shall proceed to develop the field in accordance with the approved FDP. 3.10.2 As the understanding of the field develops, there may be a need to modify the FDP accordingly. PS Contractor is therefore, responsible to inform PETRONAS as soon as deviations from the approved FDP are foreseen. Milestone Reviews can be reactivated if necessary, to discuss any propose revision to the field development. Please refer to Appendix 3.4 for example of situations where FDP or/and NOP revision is required. 3.10.3 A formal revision to the approved FDP shall be required if there are significant deviations to the approved development scope. The changes could also be triggered by the Full Field Review (FFR) which is required within 3- 5 years of initial development. The deviations include; a)

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development of new reservoirs or the need to further appraise the extent of the field ISSUED BY PETROLEUM MANAGEMENT UNIT

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b)

changes to depletion strategies (introducing pressure maintenance, gas sales etc)

c)

changes to drainage plan involving number and location of platforms and wells

d)

updating notional plans incorporating drilling results from Development While Exploration (DWE) prospects

e)

changes to the selected development concept (e.g. evacuation route, integrated development, new facilities, stand-alone vs satellite etc) that has a significant impact on cost, schedule and risk to availability.

3.10.4 PS Contractor is required to submit a revised NOP for PETRONAS'review and approval if there are deviations from the individual well objectives as approved in the FDP. In general, the area of deviation herein refers to reservoir targets, significant revision in drainage location beyond initial drilling targets and well utility (e.g. producer to injector) and outside of reasonable target tolerance (i.e less than 1 km) within the same region/fault block. 3.10.5 During the development drilling phase, if there are anticipated changes to the well objectives not captured under 3.9.4, PS Contractor shall submit a FDP Revision to address specifically the required changes. If PETRONAS'approval is obtained on the FDP Revision before the start of drilling of the affected wells, PS Contractor can proceed without the need to submit individual revised NOP for the drilling of such wells. 3.10.6 PS Contractor is required to submit a revised completion plan for PETRONAS’ review and approval if there are deviations from the approved FDP/NOP well objectives upon drilling the well. A Post-Drilling Review shall be submitted to PETRONAS no later than six (6) months after the completion of the last well. The review shall incorporate all new information and address its update on the geological model, impact on volumetric and reserves, drainage plan, depletion strategies, production forecast and future plans. In addition, it should also summarize the highlights / lowlights on drilling / completion operations, key lessons learnt and recommendation for further work. SUPERSEDE ISSUE:

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3.10.7 It is envisaged that the FDP Revision in a form of an update to the specific scope that require changes would be sufficient for submission and approval by PETRONAS. Final FDP updates is required to capture all changes, however, PS Contractors shall notify PETRONAS for changes in-between for approval prior to implementation. 3.10.8 Changes affecting optimization of design concept and operating philosophy in surface facilities do not require an FDP Revision; these will be evaluated as part of the Project Implementation Management process.

-END OF SECTION 3-

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SECTION 4 GUIDELINES FOR PROJECT DEVELOPMENT MANAGEMENT Executive Summary This document provides guidelines on project management of upstream petroleum operations and activities of the Production Sharing Contract (PSC), of which PS Contractor shall refer to in carrying out the project execution activities. The guidelines have been put in-place to provide guidance to PS Contractor with regard to PETRONAS expectations on project execution activities to ensure that they are carried out prudently and effectively as per the best practices currently prevalent relating to Project Development Management. These guidelines also provide means by which PETRONAS would be able to assess and steward performance. In this respect the PS Contractor shall have their own Project Development Management system in place, to ensure that the key project parameters i.e. Health, Safety & Environment (HSE), quality, cost and schedule are better managed. To meet the above objective, PS Contractor is encouraged to adopt integrated approach as much as practicable, in implementing a project to: optimise design capitalise on economy of scale benefits, where applicable promote sharing of services adopt Engineering, Procurement & Construction (EPC) or Engineering, Procurement, Construction, Installation & Commissioning (EPCIC) or Engineering, Procurement, Construction & Commissioning (EPCC) types of contracts, where applicable fit for purpose equipment and process off-the-shelf equipment / material, where applicable use of functional specifications, where applicable use of cost effective and proven technology implement standardisation and variety control SUPERSEDE ISSUE:

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maximise local contents form integrated project team apply a new technology, where applicable balance development CAPEX versus future operability, OPEX and reservoir management requirements optimise life-cycle cost The guidelines set forward in this document are generic in nature and as such shall be applicable for all types of projects as described in Section 3 Guidelines for FDP Review and Approval Process Guidelines. The guidelines provide traditional flow processes of Project Development starting from Field Development Plan (FDP) and ending at the start-up of first oil or gas production, after which the project is handed-over to the Production Operations. The guidelines also include approval requirements at Project Implementation phases, the approval of Contracting and Procurement Strategies, Work Programme and Budget (WP&B) submission and the project development related matters. The guidelines outlined are as follows: 1.

Field Development Phases

2.

Field Development Plan (FDP) Review and Approval Process

3.

Special Considerations

4.

Project Implementation Phases and Activities

5.

Contracting and Procurement

6.

Health, Safety and Environment (HSE)

7.

Project Quality Assurance (QA)

8.

Reporting and Documentation

9.

Project Performance

10.

Work Programme and Budget (WP&B)

11.

Regulatory Requirements

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4.1 FIELD DEVELOPMENT PHASES 4.1.1

Field development is a phase of development activities, which occur before the startup, and after the exploration phase has been successfully completed and the field(s) is recommended for development. Figure 4.1 shows a generic field development phases and activities that are commonly practiced.

Figure 4.1 Generic Field Development Phases and Activities

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4.2 FIELD DEVELOPMENT PLAN (FDP) REVIEW AND APPROVAL PROCESS 4.2.1

Under the Production Sharing Contract, PS Contractor is required to submit a Field Development Plan (FDP) within reasonable cost estimate for PETRONAS review and approval before proceeding to develop a particular field.

4.2.2

PETRONAS'requirement is that any FDP submitted should be a comprehensive stand-alone document with a complete set of information and/or references that would provide the evaluator with a better and easier understanding and rationale for the field development proposed.

4.2.3

The FDP shall address at least the following subjects: exploration activities, geological studies, depletion strategies, drainage plan, facilities, drilling program, operational requirements, Health, Safety and Environment (HSE), production forecast, cost and phasing, economics, and abandonment plan.

4.2.4

Current and/or future potential for enhanced/improved recovery applications together with potential for surface facilities integration with existing and/or future potential developments in the vicinity of the proposed development must be taken into account. The latter is particularly important for small fields.

4.2.5

In reviewing the FDP, the approach taken by PETRONAS is to establish whether there are any aspects of the proposed development, which may conflict with Government and PETRONAS’ objectives, and to focus attention on resolving those aspects before the formal FDP is submitted.

4.2.6

Under this process, Milestone Reviews are proposed in order to maintain a continuing dialogue and technical reviews as the description of a field and options for its development emerge during the development planning studies, until the execution takes place.

4.2.7

The objective of the Milestone Reviews is not to have the detailed review of every area of the development but rather the identification and resolution of any aspects of the

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development which may contradict Government and PETRONAS'objectives and on which the views of PETRONAS and PS Contractors may diverge. These aspects will be examined more thoroughly with the PS Contractor with the aim of reaching mutually satisfactory conclusions. Please refer to Section 3 Guideline for FDP Review & Appraisal Process on the details of MRs. 4.2.8

As the understanding of the field develops, there may be a need to modify the FDP accordingly. PS Contractor is therefore, responsible to inform PETRONAS as soon as deviations from the approved FDP are foreseen.

4.2.9

A formal revision to the approved FDP shall be required if there are significant deviations to the approved development scope. This may include development of new reservoirs or the need to further appraise the extent of the field, changes to drainage plan involving number of platforms, wells and types of completion (conventional to non-conventional) or changes to the selected development concept (e.g. evacuation route, integrated development etc).

4.2.10 It is envisaged that the FDP Revision in the form of an update to the specific scope that require changes would be sufficient for submission and approval by PETRONAS. 4.2.11 Changes affecting design concept, operating philosophy or new technology in surface facilities that do not affect the sub-surface design, do not require an FDP Revision; these will be evaluated as part of the Project Implementation Management process.

4.3 SPECIAL CONSIDERATIONS 4.3.1

PETRONAS recognizes and acknowledges that risked economics for certain projects, i.e. small fields development, reservoirs with high CO2, EOR and deepwater development projects, can often be marginal, requiring minimization of upfront appraisal and development expenditures. PETRONAS therefore encourages PS Contractor to consider potential for integrated area exploration and development planning. Consideration of development integration with existing infrastructure, even if operated by a different PS Contractor, through subsea wells and/or Floating

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SECTION 4 GUIDELINES FOR PROJECT DEVELOPMENT MANAGEMENT Production Systems is also encouraged. between PS Contractors, if required. 4.3.2

Page 46

PETRONAS will facilitate discussions

PETRONAS recognizes that Extended Production Testing of discovery/ appraisal wells is often a valuable approach to reducing uncertainty and improving project economics through reduced cycle time. PETRONAS will entertain requests for Extended Production Testing utilizing floating production systems. Any associated gas flaring requests, if necessary, will be considered.

4.3.3

Requests for Extended Production Testing should have a similar format and content to a Field Development Plan as outlined in Section 3. In addition, it must provide technical and economic justification as well as the planned duration of the extended production test. Maximum rate and total volume of any gas proposed for flaring must also be specified.

4.3.4

PETRONAS recognizes that upfront development CAPEX can sometimes be minimized by utilizing leased floating production systems and thereby, minimizing development economic risk. However, leased floating facilities are also generally associated with high OPEX leading to lower reserves. PS Contractors are required to evaluate the balance between CAPEX, OPEX and reserves and present their analysis in the Field Development Plan for PETRONAS’ consideration.

4.4 PROJECT IMPLEMENTATION PHASES AND ACTIVITIES 4.4.1 Feasibility Study 4.4.1.1

Feasibility study is a screening process that analyses the technical (subsurface potential and surface capability) and field economics to assess the overall viability of area and field development.

4.4.1.2

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PS Contractor shall develop Pre-FDP Feasibility Study report and submit to PETRONAS upon request.


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4.4.2 Conceptual Design / Front End Engineering Design (FEED) 4.4.2.1

PS Contractor shall develop a baseline document referred as the Basis for Design (BFD) or Project Development Memorandum (PDM), which provides the functional requirements for the facilities for the chosen concept, which include but not limited to: Brief description of the facilities Definition of the boundary conditions Definition of the status of any existing facilities and the performance characteristics of processes Definition of the requirements for the new or modified facilities Comparison of potential upfront and retrofit schemes together with associated incremental costs to handle the range of possible subsurface alternative scenarios and the range of possible forecast outcomes. Definition of any other constraints References to any relevant study reports

4.4.2.2

PS Contractor shall develop Project Specification or Design Basis Memorandum (DBM) based on the above BFD or PDM, which shall be further defined for any remaining sub-options to determine the functional specifications for the required facilities. The Project Specification or Design Basis Memorandum is to provide a detailed description of the essential project hardware, together with the project technical requirement such that it can be used as part of the document for detailed engineering design.

4.4.2.3

PS Contractor shall develop Project Execution Plan (PEP) to manage the project. It provides the basic parameters of the field development, a description of the project scope and description of how the project will be executed from the end of Conceptual design until hand-over of the project to the Operations. Generally it covers the following topics:-

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Project definition Project scope Contracting and procurement plans Organisation and resource plan QA and HSE plans Cost and schedule Commissioning and hand-over strategy Project management systems and procedures 4.4.2.4

PS Contractor shall conduct a Management Review or Independent Project Review of the Conceptual Design to ensure readiness to proceed to the detailed design phase. PS Contractor shall submit the BFD or PDM, Project Specification or DBM and PEP to PETRONAS.

4.4.2.5

PS Contractor shall adhere to sub-section 4.0 of PETRONAS Tenders and Contracts Administrative Procedure Manual for Upstream Procurement Activities, when engaging Design Consultant services for the Conceptual Design. The procedure is attached in Appendix 4.1 of this section, for information only. PS Contractor shall ensure to always refer to the latest version of the procedure.

4.4.3 Detailed Design 4.4.3.1

Detailed engineering design of the facilities is produced at this phase which includes all specifications, Process & Instrumentation Diagrams (P&ID), commissioning plans, 3D models, materials take off and spare parts lists.

4.4.3.2

The scope covers but not limited to: preparing preliminary detailed design preparing data sheets, specifications and requisition packages

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analyse bids and review vendor data prepare construction tender packages prepare Approved For Construction (AFC) or Issue For Construction (IFC) documents prepare procedures and manuals for commissioning and operations handle site queries and produce as-built drawings conduct HAZOP and Risks assessments 4.4.3.3

PS Contractor shall conduct a Management Review or Independent Project Review of the Detailed Design to ensure readiness to proceed to the fabrication or construction phase.

4.4.3.4

PS Contractor shall invite PETRONAS participation in Management Review or IPR before project proceed to fabrication or construction phase.

4.4.3.5

PS Contractor shall adhere to sub-section 4.0 of PETRONAS Tenders and Contracts Administrative Procedure Manual for Upstream Procurement Activities, when engaging Design Consultant services for the Detailed Design. The procedure is attached for information only in Appendix 4.1 of this section. PS Contractor shall ensure to always refer to the latest version.

4.4.4 Fabrication and Construction 4.4.4.1

The scope of fabrication and construction varies greatly depending on whether the development is onshore, offshore or subsea and whether it is a new facility project or existing facility upgrading project.

4.4.4.2

The main activities include: manage, plan and schedule the fabrication or construction activities review design drawings and prepare shop drawings, weight control and final documentation

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site survey, clearance and preparation for onshore construction project fabricate structural components at onshore fabrication yards for offshore project pre-fabricate process system packages at the vendor's work sites install system packages at fabrication yards maximise systems and equipment pre-commissioning at the onshore fabrication yards load out and fastening of fabricated components line pipes coating at the onshore coating yards 4.4.4.3

PS Contractor shall adhere to sub-section 4.0 of PETRONAS Tenders and Contracts Administrative Procedure Manual for Upstream Procurement Activities, when engaging the fabrication or construction and pipe coating contracts. The procedure is included in Appendix 4.1 of this section, for information only. PS Contractor shall ensure to always refer to the latest version.

4.4.5 Transportation and Installation 4.4.5.1

Types of barges used depend on the weight and size of the structural components and its availability. The main activities are to transport and install the components at offshore site, and to lay offshore pipelines.

4.4.5.2

PS Contractor shall ensure that the barges used are meeting marine HSE requirements in accordance with PETRONAS Guidelines for Barges Operating Offshore Malaysia (PGBOOM). Refer to Section 7 for Barges Operations.

4.4.5.3

Types of offshore terminal and/or floating facilities to be installed depend on its capability and availability. PS Contractor shall ensure that the floating

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installation meets the relevant standards and specifications for offshore terminal and/or floating facilities installation. 4.4.5.4

PS Contractor shall adhere to sub-section 4.0 of PETRONAS Tenders and Contracts Administrative Procedure Manual for Upstream Procurement Activities, when engaging transportation and installation; or pipelaying contracts for the substructure, topsides and pipelines. The procedure is included in Appendix 4.1 of this section, for information only. PS Contractor shall ensure to always refer to the latest version.

4.4.6 Hook-up and Commissioning (HUC) 4.4.6.1

Hook-up and commissioning is the final completion of work, testing and verification of system, in preparing for the start-up.

4.4.6.2

PS Contractor shall carry out pre start-up HSE Audit and/or Independent Project Review to ensure the facilities and operations are fit for start-up.

4.4.6.3

PS Contractor shall invite PETRONAS participation in the audit and/or review exercise as a full-time member. PS Contractor shall give written invitation to PETRONAS two (2) weeks before the audit and/or review exercise.

4.4.6.4

PS Contractor shall adhere to sub-section 4.0 of PETRONAS Tenders and Contracts Administrative Procedure Manual for Upstream Procurement Activities, when engaging the HUC contract. The procedure is included in Appendix 4.1 of this section, for information only. PS Contractor shall ensure to always refer to the latest version.

4.4.7 Development Drilling 4.4.7.1

PS Contractor shall carry out the development drilling activities in accordance with the Procedures for Drilling Operations (PDO), Section 5.

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4.4.8 Facilities Decommissioning 4.4.8.1

PS Contractors shall carry out facilities decommissioning activities that include the preparation of facilities for abandonment, which typically consists of the crafting of recommendations for operational, regulatory and HSE issues.

4.4.8.2

Refer to Guidelines for Decommissioning of Upstream Installation, Section 16 for detail procedure on facilities abandonment.

4.5 CONTRACTING AND PROCUREMENT 4.5.1

PS Contractor shall adhere to the PETRONAS procedures for the contracting of services and purchasing of material and equipment packages in accordance to PETRONAS Tenders and Contracts Administrative Procedure Manual for Upstream Procurement Activities.

4.5.2

PS Contractor shall prepare and review the overall contracting strategy with PETRONAS at the earliest opportunity and submit to PETRONAS Central Tender Committee for approval, prior to executing other contracting activities.

4.6 HEALTH, SAFETY AND ENVIRONMENT (HSE) 4.6.1

HSE management system is required to ensure project activities are undertaken in a safe risk-controlled environment. This HSE management system is to complement other project management systems and to focus on key safety and project risks.

4.6.2

PS Contractor shall establish the project HSE management system in full compliance with Malaysian law and regulations as per Volume 2 and be consistent with PETRONAS’ HSE requirements.

4.6.3

In accordance to the Protected Areas and Protected Places Act 1959, PS Contractor shall apply for facilities gazzettement within six months after installation of the facilities by submitting the required information and documentations as per Appendix 1.4 of PPGUA Section 1: Guidelines for Health, Safety and Environment. This gazzettement

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also applies to floating storage facilities i.e. FSO and FPSO. Further details on the application process shall be referred to Appendix 1.4 and Appendix 1.5 of the Section 1: Guidelines for Health, Safety and Environment.

4.7 PROJECT QUALITY ASSURANCE (QA) 4.7.1

QA management system is required to achieve project quality. The system should be consistent with ISO 9000 standards or equivalent.

4.7.2

PS Contractor shall develop Project Quality Plan to drive the QA aspects for all phases of the project. As a minimum it should: identify the critical systems and activities define the standards, control, performance indicators and documentation, and schedule of audits and reviews

4.7.3

PS Contractor shall invite PETRONAS participation in the audit and/or review exercise as a full-time member. PS Contractor shall give a written notification to PETRONAS two (2) weeks before the audit and/or review exercise.

4.8 REPORTING AND DOCUMENTATION 4.8.1

PS Contractor shall submit the project progress status reports to PETRONAS on weekly or fortnightly and monthly basis with the following objectives but not limited to: identify the current status of work compare actual achievement vs. plan highlight critical issues and major areas of concern facilitate effective management control and corrective action S-curves for cost and schedule comparing actual achievement vs. plan (monthly report only)

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SECTION 4 GUIDELINES FOR PROJECT DEVELOPMENT MANAGEMENT 4.8.2

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PS Contractor shall submit the following reports and documents to PETRONAS as and when available as per Table 4.8.2 below: Table 4.8.2: Reports and Documents Submission to PETRONAS

No

Documents

Information

Review

Approval

Submitted to

1

FDP Feasibility study report (as request)

2

Field Development Plan (FDP)

3

Basis for Design (BFD) / Project Development Memorandum (PDM)

X

X

GM-PRD

4

Project Specification (Conceptual Design Report Summary) / Design Basis Memorandum (DBM)

X

X

GM-PRD

5

Project Execution Plan (PEP) (including updates)

X

X

GM-PRD

6

Management Review Report / Independent Project Review Report for Conceptual Design (executive summary only)

X

GM-PRD

7

Management Review Report / Independent Project Review Report for Detailed Design (executive summary only)

X

GM-PRD

8

Pre start-up HSE Audit / Independent Project Review Report (executive summary only)

X

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X

GM-PRD X


X

GM-PRD

GM-PRD

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Information

Review

Approval

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Submitted to

No

Documents

9

Project Close Out Reports (Final report and drilling report submission is three months after project completion and 90 days after drilling completion, respectively)

X

10

HSE / Technical Audit Reports (on request)

X

POM

11

HAZOP, Special Studies Reports (on request)

X

POM

12

As built drawing (as part of Project Close Out Report)

X

POM

GM-PRD

Note: 1) For items currently identified under review column, with exception of FDP, the works can progress unless otherwise directed by PETRONAS. 4.8.3

Refer to the PPGUA Section 17: Guidelines for Data Management and Submission Requirement for detailed documents submission requirements.

4.9 PROJECT PERFORMANCE 4.9.1

PS Contractor shall submit to PETRONAS on the relevant Key Performance Indicators (KPIs) for the development project in accordance with PETRONAS Work Procedure or Guidelines For Processing WP&B. The relevant Key Performance Indicators (KPIs) shall be submitted as part of WP&B submission.

4.9.2

PS Contractor shall present the project progress performance of the development project during the quarterly Operations Committee Meeting (OCM).

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4.10 WORK PROGRAMME AND BUDGET (WP&B) 4.10.1 PS Contractor shall submit to PETRONAS for approval of the annual Work Program & Budget (WP&B) and revisions for the development projects and upgrading projects in accordance with the PETRONAS Work Procedure or Guidelines for Processing WP&B.

4.11 REGULATORY REQUIREMENTS 4.11.1 For all development projects within the Exclusive Economic Zone (EEZ), PS Contractor shall ensure compliance with the relevant regulatory requirements as details in Appendix 4.2 of the PPGUA: List of Governmental Permits, Approvals and Notifications for Offshore Facilities for Development projects (By Phases). 4.11.2 PS Contractor shall comply with the relevant local authorities’ requirements. These regulatory requirements do not apply to cross-border pipelines. 4.11.3 PS Contractor shall adhere to all the Malaysian law and regulatory requirements that are applicable to the project development.


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SECTION 5

PROCEDURES FOR DRILLING OPERATIONS Executive Summary PS Contractor shall comply with the following procedures in conducting Drilling Operations in accordance to the Production Sharing Contract. These procedures may be added to or amended from time to time upon written notice by PETRONAS and provided such additions or amendments are consistent with the provisions of the Production Sharing Contract. In adding to or amending the procedures, PETRONAS shall consider the incremental expenditures which may be required to be incurred by PS Contractor in complying with the amended procedures PS Contractor may request exception of exemption to these procedures and exception or exemption may be granted when PETRONAS and PS Contractor agree that safety, efficiency and prudent practice are nevertheless served.

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5.1

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DEFINITIONS

5.1.1 General The terms defined in Production Sharing Contract dated shall have the same meaning in these procedures.

5.1.2 Specific In these procedures, 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:1. Conductor Casing means the first casing string set in the order of normal installation to support unconsolidated deposits and to provide hole stability for initial drilling operations which shall also include stove pipe, marine conductor and foundation pile. (Refer to 5.3.3.2 and 5.3.3.3) 2. 'Surface Casing'means casing that is installed in a well to facilitate well control during drilling of the hole. The casing string is set in the order of normal installation in a competent bed based upon engineering and geological factors, including the presence or absence of hydrocarbons, other potential hazards, and water depths. (Refer to 5.3.3.4). 3. 'Surface Casing'means casing string set in the order of normal installation in a competent bed based upon engineering and geological factors, including the presence or absence of hydrocarbons, other potential hazards, and water depths. (Refer to 5.3.3.4) 4. 'Intermediate Casing' means the string or strings of casing set after the surface casing in the order of normal installation to protect against anticipated pressures, 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. (Refer to 5.3.3.5)

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5. 'Production Casing'means a string of casing which is set for the purpose of completing the well for production. (Refer to 5.3.3.6) 6. 'Coiled-Tubing Operations'means operations using spooled non-jointed pipe through the wellhead and well tubing. 7. 'Conventional Core' means a formation core that is cut by rotary coring techniques. 8. 'Diverter'means a device for the purpose of diverting the uncontrolled flow of fluid from the well bore. 9. 'Drilling Base'means a stable foundation that may be the ground surface or an artificial island upon which the drilling rig is installed in order to conduct drilling and related operations. A fixed production platform on which there are no drilling operations shall be excluded. 10. 'Drilling Programme' means the programme for the drilling of one specific well. 11. 'Drilling Sequence'means a programme for the drilling of one or more wells as presented in the annual Work Programme and Budget and its subsequent revisions. 12. 'Drill Stem Test'means 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. 13. 'Drilling Unit'means a drill ship, submersible, semi-submersible, barge, jackup, land rig or other vessels used in a drilling programme and includes a drilling rig and other related facilities installed on a vessel. 14. 'External Hazard'means environmental conditions occuring on the drilling unit or drilling base which threaten the safety of the operation.

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15. 'Kick'means influx of wellbore fluid into the wellbore and possible loss of primary control of the well which can be controlled by secondary control (BOP's). 16. 'Liner'means 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 meters. A liner may be used as a drilling liner or production liner. A liner may also be tied back to surface if required in which it will be regarded as a production string. 17. 'Lubricator assembly' means a setup consisting of wireline BOP, a riser assembly with a bleed valve, and a wireline packoff. 18. 'Major Workover Operations'mean remedial operations performed with the X'mas Tree removed and blowout preventers installed. 19. 'Minor workover Operations'mean remedial operations performed with the wellhead valve assembly installed. 20. 'Offshore Well'means a well drilled from offshore drilling base or drilling unit. 21. 'Oil Spill'means any unexpected loss of crude oil, condensate or hydrocarbon containment that reaches the environment, i.e water or land irrespective of quantity recovered. 22. 'Open Hole'means a well bore or portion of a wellbore that is not protected by casing. 23. 'Small-Tubing Operations'means operations using jointed pipes through the wellhead and well tubing. 24. 'Snubbing Operations' mean 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 blowout preventers and wellbore of a conventional operation.

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25. 'Shooting Nipple Assembly'means wireline packoff and a riser assembly held in place by blowout preventers. 26. 'Spud-In'means the initial penetration of the ground or sea floor for the purpose of drilling a well. 27. 'Stripping Operations'mean operations which require manipulation of the drill string or workstring through blowout preventers, under low or moderate pressure, without the use of a snubbing unit. 28. 'Waste Material' means refuse, non-biodegradble garbage or any other useless material generated during drilling and related operations excluding fluid and drill cuttings. 29. 'Well Material'means any formation or reservoir material obtained from a well and includes cuttings, cores or fluids. 30. 'Well Suspension' means the temporary cessation of drilling/completion activities (waiting for final completion or abandonment). 31. ‘Non FDP’ wells are those wells which are not included in the original approved FDP and require additional approval from PETRONAS. A minimum of 14 days notice should be given prior to spudding the well.

5.1.3 Abbreviations 1. API

- American Petroleum Institute

2. BOP

- Blowout Preventer

3. ESD

- Emergency Shutdown

4. H2S

- Hydrogen Sulphide

5. PETRONAS - Petroleum Nasional Berhad 6. ppm

- part-per-million

7. RP

- Recommended Practices

8. SCSSV

- Surface Controlled Subsurface Safety Valve

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9. SSSV

- Subsurface Safety Valve

10. SSV

- Surface Safety Valve

11. FDP

- Field Development Plan

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5.1.4 Cross Reference Procedures These procedure need to be cross referenced with other relevant sections i.e. Guidelines for Health, Safety and Environment (Section 1), , Guideline for Decommissioning of Upstream Installation (Section 16) and Guideline for Data Management and Submission (Section 17)

5.1.5 Official correspondence Please refer to Appendix 5.1, 5.2 and 5.3

5.2

DRILLING PROGRAMME APPROVAL

5.2.1 Notification PS Contractor shall notify PETRONAS in the Work Programme and Budget and subsequent revisions of its intention to undertake any particular Drilling Campaign.

5.2.2 Wellsite Survey and Shallow Hazard Report PS 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 sidescan sonar, sea-bottom profiler and other shallow seismic instrument. Survey line spacings shall be a maximum of 250 meters apart in a 1-square-kilometer area centered on the wellsite. If in the opinion of the PS Contractor, surveys exist for a location nearby to the proposed location which can be taken as representative of the new location, or if extensive experience in a local area has shown that such surveys SUPERSEDE ISSUE:

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are not required, then additional surveys will not be required. 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 flows, hydrates, and expulsion features should be evaluated. 3D seismic or other imaging methods may be used in lieu of conventional shallow seismic, as appropriate.

5.2.3 Well Positioning 5.2.3.1

Pre-survey Preparation PS Contractor shall notify PETRONAS on the proposed well location as per PSC requirement.

5.2.3.2

Positioning Operations PS Contractor to ensure the safety of pipelines and cables underlying subsea and perform pre-spud and final post-spud verifications

5.2.3.3

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

5.2.4 Notice of Operations For Non FDP wells the ‘Notice of Operations'shall be submitted in advance for approval at least 14 calendar days prior to spud in date. Pre spud meeting/drill on paper shall be conducted prior to drilling execution. For FDP wells, the 'Notice of Operations'shall be submitted for information in hard copy and acceptable electronic format. The 'Notice of Operations' shall contain but not limited to the following information:-

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a)

Objectives of the well;

b)

Location map; ISSUED BY PETROLEUM MANAGEMENT UNIT

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c)

Prognosis cross-section;

d)

Depth of well and proposed completion target;

e)

Directional drilling 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)

Estimated detailed cost breakdown (refer Appendix 5.4);

m)

Estimated depth vs days and depth vs cost chart.

n)

Name and type of drilling unit

o)

Contingency plan (for operational problem)

p)

Propose full P&A with drawing for exploration, appraisal wells and suspended well

q)

Well Schedule

During the execution phase, if PS Contractor anticipates there will be a potential cost overrun of 10% from the approved cost or NPT more than 50 hours, PS Contractor shall give notice to PETRONAS. In addition, if the above well has been completed, PS Contractor shall submit and present the case to PETRONAS.

5.2.5 Variations PS Contractor may implement variations or deviation to the drilling programme as he deems operationally necessary or desirable to achieve the agreed objectives of the well in an efficient and safe manner, however prior PETRONAS approval is required. PETRONAS may require PS Contractor to show that specific equipment or procedures are consistent with the interests of safe and efficient operations. Contractor shall SUPERSEDE ISSUE:

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modify or replace any equipment or alter any procedure that cannot be shown to be safe. PS 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 consent of PETRONAS and in such cases, PETRONAS shall be notified forthwith of the alterations and of the underlying circumstances. For Emergency cases within 24 hours refer to operations (all cases, notification shall be done within the next working day).

5.2.6 Drilling Base or Drilling Unit Design PS 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, fatique, etc., during the course of all anticipated combinations of environmental and functional loading operations. In the event that weather forecasts predict conditions during which normal drilling operations could not continue, PS Contractor shall take necessary actions to interrupt drilling operations in time, so that the safety of the well and drilling unit shall not be affected.

5.2.7 Support Craft 5.2.7.1

General 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 the PS Contractor shall, upon request, demonstrate to the satisfaction of PETRONAS, that support craft are capable of safely operating in the environmental

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conditions prevailing in the area of drilling operations.(PS Contractor shall make reference to its own internal guideline wrt technical specification)

5.2.8

Equipment and Provision 5.2.8.1

General Requirements The drilling rig and support craft shall be properly equipped to safely and efficiently conduct all operations involved in carrying out the proposed drilling programme. Provision shall be made to provide adequate support for the drilling programme and such support shall include transportation facilities, supplies, accommodation for personnel, first aid facilities, storage and repair facilities and communication systems. PS Contractor shall, upon request by PETRONAS, submit sufficient information to demonstrate that the drilling rig is properly equipped and that adequate provisions have been made to assure compliance with Section 5.2.8.2.

5.2.8.2

Drilling Unit Ancillaries

5.2.8.2.1

Pollution Prevention The drilling unit shall be adequately equipped with facilities to prevent, reduce and control pollution of the marine environment in accordance and compliance with the regulations as stipulated in the applicable Malaysian laws. All decks or equipment containing contaminants which are associated with drilling operations shall be equipped with curbs, gutters, drip pans and drains which shall be installed, where possible, to collect all contaminants and piped to a collecting tank or sump, with safeguards for overflow, to be disposed of later in a manner not in contravention to the applicable Malaysian laws.

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

5.2.8.2.3

Helideck on Drilling Units If the drilling unit is equipped or required to have a helicopter deck, it shall be: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; and 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. g) Helicopter crash box shall be provided at the access to the helideck.

5.2.8.3

Drilling Rigs

5.2.8.3.1

General Arrangement Drawings Upon request by PETRONAS, PS Contractor shall submit dimensional layouts and drawings of the drilling rig and camp. Upon request by

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PETRONAS, PS Contractor 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 areas and their associated equipment; b) arrangements of drilling fluid tanks, high and low pressure drilling fluid 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) the position and type of all life-saving appliances, fire extinguishing and protection systems, fire stations and appliances, navigational safety appliances and alarm systems. 5.2.8.4

BOP 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. (refer to Sec 5.3.5.1 BOP Equipment for detail).

5.2.8.5

Weather Data Recordings 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.

5.2.8.6

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

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A red aircraft warning light of at least 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. The classification bureau shall be applied as minimum requirements. 5.2.8.7

Personnel Safety and Welfare 5.2.8.7.1

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 meter. The derrick floor shall have at least two exits and preferably one each on opposite sides of the drill floor.

5.2.8.7.2

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 meters or higher, shall wear safety belts complete with tail rope having adequate length and strength. PS Contractor shall ensure that such safety belts are provided at all times on the derrick.

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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.

5.2.8.7.4

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 industrial accidents. The facilities in the sick bay shall include first aid and resuscitation equipment and shall have at least one bed for every 50 person or portion thereof. Detailed requirements are as per PETRONAS Guidelines for Barges Operating Offshore Malaysia (Section 7)

5.2.8.8

Electrical Installation 5.2.8.8.1

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.

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An emergency shutdown switch, capable of shutting down all electrical equipment and power plants shall be provided at a minimum of two control stations on the drilling unit. 5.2.8.8.2

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, drilling rig and 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.

5.2.8.8.3

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 5.2.8.8.2), alarm, communication and fire extinguishing systems. A drilling unit shall be equipped with an independent emergency electrical power supply system consisting of:i)

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 5.2.8.8.2; alarm and communication systems; pumps that are essential for maintaining the trim of the vessel; abandonment systems

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when dependent on electrical power; and fire extinguishing systems; and ii) 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 5.2.8.8.2. 5.2.8.9

Forced Air System and Ventilation 5.2.8.9.1

Hazardous Area The hazardous areas on the drilling unit shall be in accordance with API RP 500B.

5.2.8.9.2

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 or pressurized.

5.2.8.9.3

Engines and Motors Engines, generators and motors located within any area as designated in Section 5.2.8.9.1 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.

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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.

5.2.8.10

Fire Protection 5.2.8.10.1 Fire fighting equipment Fire fighting equipment shall be provided and maintained at every drill site to combat all classes of fires. Each drilling unit shall:a) have appliances whereby at least two jets of water, each of 200 litres/minute (53 gal/min.) at a minimum pressure 275 kPa (40 psi) can be rapidly and simultaneously directed into any part of the unit's sub structure at least one of which shall be from a single length of hose; such appliances shall include at least two power driven pumps located separately and at least three fire hoses; in any case at least one fire hose shall be provided for every 30 meters in length of the unit or fraction thereof. b) be readily accessible :i) at least two proximity fire fighting suits; ii) Four self-contained portable breathing devices; a suitable water supply source of sufficient capacity to assure a supply of water adequate for a minimum of 15 minutes with two jets in operation simultaneously at the rate specified in (a) and that is connected to two fire pumps; is

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equipped with a low level alarm and an adequate and reliable means of replenishing water at a greater rate than the minimum rate of fire pumping capacity. Notwithstanding the above, PETRONAS may require additional fire fighting equipment to be installed if such equipment is considered necessary. 5.2.8.10.2 Fire Alarm Systems 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. 5.2.8.11

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 Guidelines for Health, Safety and Environment (refer to Section 1)

5.2.8.12

Gas Detection System A drilling unit shall be equipped with gas detection systems of approved type that can monitor continuously at locations where there can be an accumulation

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of combustible vapors or gas and in accordance with Section 5.11.5 of this procedure.

5.2.9 Personnel PS 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.

5.2.10 Emergency Shutdown (ESD) One ESD control station, at a minimum shall be located at the drillers console during all well operations. Units without drillers console shall have readily accessible ESD stations.

5.3 TECHNICAL REQUIREMENTS FOR DAILY OPERATION 5.3.1 General Provisions All wells drilled under the provisions of these procedures shall have been included in the Original Work Programme and Budget or its subsequent Revision. PS Contractor shall comply with the following requirements:-

5.3.2 Moving and Positioning Drilling Units 5.3.2.1

General Provisions 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.

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Anchor Testing For Drilling Units 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 out of the structural casing. If this tension cannot be obtained, PS Contractor shall take the necessary remedial action.

5.3.2.3

Bottom Supported Units 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 onboard. When the drilling unit is bottom-supported, the unit shall not be raised or lowered, if weather or sea conditions are such in the mutual opinion of the barge engineer, rig mover and insurance representative, as to cause undue risk for the safety of the personnel, operations and drilling unit.

5.3.2.4

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.

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5.3.3 Casing and Cementing For the purposes of this procedure, the casing strings in order of normal installation are: drive pipe or structural casing, stove pipe or marine conductor, foundation pile, surface casing, intermediate casing and production casing. 5.3.3.1

General Requirements All casings shall meet API or ISO quality standards.

5.3.3.2

Drive or Structural Casing This casing shall be set in a competent bed, with the objective of obtaining drilling fluid returns to surface. Normally such setting depth will be 30 meters or more below the sea floor. However, the presence of abnormally strong formations may permit the setting of the this casing at a depth shallower than theoretically required. If this portion of the hole drilled, it shall be cemented with a quantity of cement sufficient to fill the calculated annular space back to the sea floor.

5.3.3.3

Conductor Casing The initial conductor casing string shall be set in a competent formation (normally between 150 meters and 300 meters TVD below the sea floor) 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 meters below seabed 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 5.3.7, Formation Intergrity Testing.

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The initial casing string shall be cemented with a quantity of cement sufficient to fill the calculated annular space back to the sea floor. If cement returns cannot be verified or confirmed, an excess volume of cement shall be used to ensure fill to the sea floor or surface. The excess volume shall be as specified in Section 5.3.3.10 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 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 PS 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. For deepwater operations, conductor casing may be eliminated if geological factors, shallow hazards, and well structural integrity are maintained. 5.3.3.4

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 meters TVD and 1400 meters TVD below the sea floor). 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 here the well control integrity can be provided until the next string of casing is set. Surface casing shall be cemented with a calculated volume of cement sufficient to fill the annular space to 150 meters above the highest hydrocarbon sand in the open hole, or if none are present, then to at least 150

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meters above the surface casing shoe. In the absence of a conductor casing string, the surface casing shall be cemented to surface. After drilling out the surface casing shoe, a formation pressure Integrity test shall be performed as required under Section 5.3.7, Formation Pressure Testing. 5.3.3.5

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 meters above the highest hydrocarbon or freshwater bearing sand, or if no hydrocarbon are present, then to at least 100 meters above the previous casing shoe. If the intermediate casing is a liner, a minimum liner lap of 30 meters above the previous casing string shoe shall be applied. The liner lap shall be tested to determine whether a seal between the liner top and the next larger string has been achieved. This requirement may be waived if the completion interval is above top of cement (TOC). For deepwater wells where no hydrocarbon are present, the Top of Cement can be kept below the surface casing shoe to prevent excessive annular pressure (due to thermal expansion) from causing failure to the surface or intermediate casing strings.

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Production Casing This string shall be set before completing the well for production. A calculated volume of cement sufficient to fill the annular space at least 150 meters above the uppermost hydrocarbon zone shall be used. When a liner is used as production, it shall be lapped a minimum of 30 meters into the previous casing string, and the seal between the liner top and the next larger string shall be tested. A float collar or other means of preventing backflow of the cement plug during cementing shall be inserted in the casing string at a distance at least 10 meters above the float shoe. The lowest two joints of the casing shall be properly centralised and made up with thread locking compound.

5.3.3.7

Pressure - Testing of Casing After cementing, all casing strings shall be tested to the minimum pressures shown below : Cemented Conductor.................. Surface........................................ Intermediate, liner ....................... and production ............................

1400kPa(200psi) 6900kPa(1000psi) 5kPa/meter(0.73psi/m)TVD, 10300 kPa(1500 psi) whichever is greater

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

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After cementing any casing string, pressure testing of the casing can be conducted either upon bumping of the plug or one of the conditions below has been satisfied : a)

12 hours have lapsed from the time the cement slurry was in place, or

b)

the tail slurry samples obtained at surface have fully set (rock hard).

In case of back flow at the end of cementing operations, back pressure should be applied until cement has set. Before drilling out of the casing shoe, sufficient time must elapse to allow tail slurry to attain a compressive strength of at least 3450 kPa (500 psi). The typical performance data for the particular cement mix used in the well shall be used to determine the setting time required. 5.3.3.8

Records The result of all casing pressure tests shall be witnessed by Contractors Representatives and recorded on the Driller's log. This data shall be made available upon request by PETRONAS.

5.3.3.9

Cementation The cementation of surface casing, intermediate casing, production casing and liner shall be performed by displacement method. Cementation reports for all individual primary casing cementing operations shall be submitted to PETRONAS upon request. For deepwater operations, other industry acceptable cementing methods may be used such as inner string cementing or simply cementing without the use of wiper plugs where appropriate

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Page 82

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 (debate to include or not), or the following percentages of excess slurry :Structural ..................................... Conductor .................................... Surface......................................... Intermediate or production............

100% excess 50% excess 30% excess most accurate hole caliper available + 10% excess

5.3.3.11

Inadequate Cement Job Where indications exist that cementation quality is such that well safety or objectives are jeopardized, PS Contractor shall ensure that remedial action is taken without any delay.

5.3.4

Well Directional Survey

5.3.4.1

Vertical Wells (Inclination ≤ 5° ) First surveys shall be taken at depth not greater than 150 m below surface or mudline. Subsequent surveys shall be taken at 150m intervals but will not exceed 300m. 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.

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Page 83

Directional Wells (Inclination ≥ 5° ) First survey shall be taken at a depth not greater than 60 m below conductor shoe. Subsequent surveys giving both inclination and azimuth shall be obtained on all directional wells at intervals not exceeding 150 meters during the normal course of drilling, i.e tangent sections. Two successive directional survey readings shall not exceed 30 meters in all programmed angle change portions of the hole. Anti collision must be taken into consideration. PETRONAS may require PS Contractor to submit the anti collision guideline upon request. However, a survey is not required for open whole sections which shall be immediately abandoned after evaluation when collision risk does not exist. 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.

5.3.5 Blowout Prevention 5.3.5.1

BOP Equipment BOP equipment shall consist of an annular and the specified number of ramtype preventers. The pipe rams shall be of proper size to fit the pipe in use, except as provided in Section 5.3.5.4 (b).The working pressure rating of any BOP component shall exceed the maximum anticipated surface pressure to which it may be subjected. All BOP systems shall at least conform to API RP 53 (Latest Edition) specification as a minimum requirement.

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Page 84

Auxiliary Equipment The following auxiliary equipment shall also be provided :a)

A top kelly cock shall be installed below the swivel and an essentially full-opening kelly cock, of such design that it can be run through BOPs, shall be installed at the bottom of the kelly or stand of working drill pipe. For a manually operated kelly cock, a wrench to fit each valve shall be stored in a location readily accessible to the drilling crew ;

b)

An inside BOP and an essentially full-opening drill string safety valve in the open position shall be maintained on the rig floor at all times while drilling operations are being conducted ; and

c)

A safety valve (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.

5.3.5.3

Surface BOP The minimum requirements for drilling below the casing strings for conventional surface BOP stacks are tabulated below :Surface BOP Stacks Drive or structural ............................ 1 - *Diverter Conductor ............................ 1 - *Diverter Surface

............................. 1 - Annular ............................. 1 - Pipe Rams ............................. 1 - Blind or Shear Ram

Intermediate

............................. 1 – Annular …………………… 2 - **Pipe Rams ............................. 1 - Blind or Shear Rams

* SUPERSEDE ISSUE:

AUG 2000

The diverter system shall provide as a minimum, an annular preventer, ISSUED BY PETROLEUM MANAGEMENT UNIT

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with a spool below having two 8-inch or larger diameter lines equipped with full opening remote control valves in the main and diverter flowlines. Alternative design employing a single 8 - inch or larger outlet off the diverter spool may be used for development drilling on platforms. 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 hdyrocarbons are present in the hole drilled below the structural casing, drilling without a diverter may be acceptable. Similarly after logging in pilot hole has proven no hydrocarbons present, the diverter may be removed prior to opening hole. ** 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 and a set of blind shear rams in lieu of blind rams, installed in the existing BOP stack ; or b) Variable bore rams may be fitted in place of one set 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.

If repair or replacement of the BOP stack is necessary after its installation, this work shall be performed after the well has been secured as per PDO Section 5.7.6. 5.3.5.4

Subsea BOP The minimum requirements for drilling below the casing strings for subsea BOP stacks are tabulated below :Subsea BOP Stacks * Riserless Conductor* Surface

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...................... 1 - Diverter on top of riser ...................... 1 - Annular ...................... 2 - Pipe Rams


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...................... 1 - Blind Shear Rams Intermediate ...................... 1 - Annular ...................... 2 - Pipe Rams ...................... 1 - Blind Shear Rams Note: *

Riserless drilling may be considered if no known shallow oil bearing formations are present or water depth is sufficient to do so, subject to PETRONAS approval

When a tapered drill string is in use, the following alternatives shall apply:a) Variable bore rams may be fitted in place of one set 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 stacks shall be equipped with blind shear rams. 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. A fail-safe design shall be incorporated into the BOP system and shall include dual pod control systems and fail-safe valving on critical lines and outlets. Prior to the removal of the marine riser for installing casing, the riser shall be displaced with sea water. PS 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. If repair or replacement of the BOP stack is necessary after its installation, this work shall be performed after the well has been secured as per Section 5.7.6.

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Page 87

Subsea BOP Diversion When the BOP system is on the sea floor, the choke and kill lines or equivalent vent lines, equipped with necessary connections and fittings, may be used for diversion in exceptional cases if approved by PETRONAS, or an annular preventer or pressure rotating pack-off type head, equipped with suitable diversion lines shall be installed on top of the marine riser. The diverter shall be equipped with automatic, remotely controlled full opening valves which open, prior to shutting in the well. 8-inch or larger diameter lines venting in two different directions to permit downwind diversion shall be provided.

5.3.5.6

Testing of BOP

5.3.5.6.1

BOP Controls A minimum of one operable readily accessible remote BOP control station shall be provided, in addition to the primary BOP control station on the drilling floor. Accumulators or pumps shall maintain a pressure capacity reserve at all times to provide for repeated 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.

5.3.5.6.2

Pressure Tests Each component of the BOP stack assembly and related control equipment shall be initially pressure tested to 70% of their rated working pressure or at least to the maximum anticipated service pressure whichever is higher. Subsequent pressure test shall be to the maximum anticipated wellhead pressure. A 500 psi low pressure BOP test shall be conducted prior to full pressure test. The annular preventer however will be tested to 10300 kPa(1495 psi) when closed around drill pipe. All pressure test shall be conducted for at least 15 minutes. All test records shall be made available upon request by PETRONAS. The annular preventer shall be tested according to the following guidelines :-

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a)

When installed or stump tested prior to installation;

b)

Not less than once in 14 days. However, the blind shear rams may not be tested ; and

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.

d)

5.3.5.6.3

Following repairs that require disconnecting a pressure seal in the assembly.

Actuation While drill pipe is in use, the following actuation procedures shall be performed, as a minimum, to determine proper functioning of the BOPs and control stations:a)

Pipe rams: Actuated weekly, and after nippling up;

b)

Blind shear rams : Actuated whilst drill pipe is out of the hole, after stack is nippled up, once each trip but not more than once each day (except for subsea BOPs);

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;

5.3.5.6.4

e)

Actuation of control station shall be alternating between primary and remote BOP control stations; and

f)

Subsea BOPs shall be actuated at least on weekly basis.

Inspection and Maintenance All BOP systems and marine risers and associated equipment shall be inspected and maintained in accordance with the manufacturer's

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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 supervisory drilling personnel shall be fully familiar with BOP procedures and the BOP equipment before starting work on the well. All BOP tests, maintenance and inspection shall be recorded on the Driller's log. In all areas where shallow hazards or hydrocarbons are known, seismic data shall be obtained and a small diameter initial pilot hole of 12-1/4 inch or smaller size from the bottom of the conductor casing to the proposed surface casing seat shall be drilled to aid in determining the presence or absence of these hazards. All seismic data relating to shallow hazards shall be submitted to PETRONAS.

5.3.6

Mud Programme

5.3.6.1

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

5.3.6.2

Mud Control Before starting pulling out of the hole with drill pipe, the mud shall be properly conditioned. Proper conditioning means that :a)

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There is no indication of influx of formation fluids prior to pulling the drill pipe out of the hole ;


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b)

The weight of the returning mud is essentially the same as the mud entering the hole ; and

c)

Other mud properties recorded on the daily drilling log are within the specified ranges required to drill the hole.

When the mud in the hole is circulated, the Driller's log shall be so noted. When coming out of the hole with the drill pipe, the annulus shall be filled with mud to ensure sufficient over balance (at least 0.3 lbs/gal or 100 psi) which ever is less is maintained at all time. For deepwater operations where narrow margins prevent a 0.3 lb/gal 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 mud 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 mud 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 mud. following information shall be posted near the driller :-

The

d)

The number of stands of drill pipe and drill collars that may be pulled between the times of filling the hole.

e)

The number of barrels and pump strokes required to fill the hole for the designated number of stands of drill pipe and drill collars.

f)

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.

g)

SUPERSEDE ISSUE:

AUG 2000

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. ISSUED BY PETROLEUM MANAGEMENT UNIT

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An operable degasser shall be installed in the mud system prior to commencement of drilling operations. It shall be maintained for use throughout the drilling and completion of the well. 5.3.6.3

Mud Test Equipment Mud testing equipment shall be maintained on the drilling rig at all times, and mud 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 mud system monitoring equipment shall be installed with derrick floor indicators and used at the point in the drilling operations when mud 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)

Mud-volume measuring device for accurately determining mud volumes required to fill the hole on trips ;

5.3.6.4

c)

Mud-return indicator to determine that returns essentially equal the pump discharge rate; and

d)

Gas-detecting equipment to monitor the drilling mud returns.

Mud Quantities Sufficient drilling mud materials shall be stored at the drilling base or drilling unit to meet any normal and foreseeable emergency conditions. Subject to the above, and taking into account the availability of the mud storage capacity of the drilling base or drilling unit, the minimum quantities of mud materials required shall be based on the following :-

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a)

The quantity of the mud materials shall be based on renewing a volume of the calculated capacity of the active mud system.

b)

The quantity of the weighting material shall be based on the amount required to increase the mud density of the active mud volume to overcome the highest anticipated formation pressure.

When the mud quantity required exceeds the storage capacity of the drilling base or drilling unit, the Contractor must demonstrate that the mud 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 mud material as specified above.

5.3.7 Formation Integrity Testing Before drilling to a maximum of 15 meters of new hole below the surface casing (if set below 300 meters 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.

5.3.8 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

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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 and Contractor shall exercise prudent drilling practices to ensure well integrity and safety of the operations.

5.3.9 Detection of Over-Pressure 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 drill ability trend of the shale and in conjunction the plotting of 'dc'exponent values derived from the rate of penetration or subsequent modification of it on a graph paper with a suitable scale ;

d)

The change in temperature and in 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 the 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 control of the well as drilling proceeds into the over-pressured formation, including modifying the drilling programme and equipment as required.

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5.3.10 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 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 onto the environment; or endangers, or is likely to endanger, the safety of personnel, the security of the well, the safety of the drilling rig or the drilling unit and the operation shall remain suspended until it can resume safely. Conditions under which drilling shall be suspended in the case of a drilling unit :a)

Inability to maintain well control;

b)

Failure of any major component of the BOP system, casing or drilling fluid system;

c)

Uncontrolled fire at the drilling site;

d)

Failure of a significant portion of the primary power source ;

e)

Inability to maintain adequate stability and buoyancy of the drilling unit;

f)

Inability to satisfactorily maintain the position of the drilling unit over the well;

g)

Excessive motions of the drilling unit caused by sea-state or weather conditions ; and

h)

While diving operations are being conducted at or near any part of the subsea drilling system.

A written report shall be submitted to PETRONAS on all fatal accidents. This report shall include but not be limited to the following information; name, age, nationality, address, etc. It shall also include the cause of the accident and the precautions to be initiated to prevent the recurrence of the incident in the future.

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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 cause.

5.3.11 Floating Drilling Operations In drilling operations where a floating or semi-submersible type of drilling vessel is used and if formation competency at the structural casing setting depth is not adequate to permit circulation of drilling fluids to the vessel while drilling conductor hole, a programme which addresses the safety, precautions and contingency plan for the operations shall be submitted to PETRONAS for approval. This programme shall include all known pertinent and relevant information, including seismic and geological data, water depth, drilling fluid, hydrostatic pressure, schematic diagram from rotary table to proposed surface casing seat and contingency plan for moving the drilling vessel off location.

5.3.12 Shallow Hazards or 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 for deepwater operations. All seismic data relating to shallow hazards shall be submitted to PETRONAS.

5.3.13 Underbalanced Drilling 5.3.13.1

Definition: 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. 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. As a broad generalization, underbalanced drilling aimed to improve drilling rate, to limit lost circulation and to protect reservoir formation.

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Page 96

General requirements: Underbalanced drilling shall be conducted only when the minimum requirements below are followed and subject to further discussion / approve approval by PETRONAS upon execution: 1.

Risk and benefit to perform underbalanced drilling (economic and technical reason to change from conventional drilling).

2.

Evaluation criteria.

3.

Fluid type used assessment (gas, mist, foam, gasified liquid and liquid).

4.

Equipment used assessment that covers both surface and sub-surface (gas compression, gas generation, separation, foam, pressure control, downhole tools, BOP stack, rotating head etc).

5.

Underbalanced design program (fluid design, expected ROP, wellbore model, fluid velocity, cutting transport, cost analysis etc).

6.

Environmental and safety concerns associated with underbalanced drilling should be addressed such as the primary consideration of environmental protection should relate to handle returning fluid from wellbore.

5.4 MATERIAL HANDLING AND DISPOSAL All waste materials from the drilling and related operations shall be handled and disposed of in a manner that does not create a hazard to safety, health and environment and is in compliance with the applicable Malaysian laws.

5.4.1 Material Handling 5.4.1.1

Bulk Material All material handled in bulk such as barite, bentonite and cement shall be stored in properly designed containers to minimize contamination of the

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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 minimize contamination. All handling equipment and tanks shall be inspected on a regular basis for foreign substances that cause contamination. Air dryers and condensation tanks shall also be inspected on a regular basis to assure that they are functioning properly. 5.4.1.2

Other Materials Drilling fluid additives, not handled in bulk, shall be packaged in properly labelled containers and pallets and shall be water-proof 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, properly vented containers located at least 25 meters from the well for land drilling and 5 meters 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 5.9.1.7. 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.

5.4.2 Disposal of Materials Wastes generated during drilling operations including used oil based mud and chemical residues/wastes resulting from drilling must 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 must be

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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 including wastes transported to shore base must be recorded, tracked and in compliance with the requirements of the Environmental Quality (Scheduled Wastes) Regulations 2005 and Environmental Quality (Prescribed Conveyance) (Scheduled Wastes) Order 2005 P.U.(A) 293. Disposal of materials, wastes and equipments 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:Atomic Energy Licensing Act, 1984 Radiation Protection (Licensing) Regulations, 1986 Radiation Protection (Basic Safety Standards) Regulations, 1988 Radiation Protection (Transport) Regulations, 1989 LEM/TEK/30 SEM.2 , 1996- Guidelines on Radiological Monitoreing for Oil and Gas Facilities Operators Associated with TENORM. Any TENORM disposal proposal has to be submitted to the Malaysian Atomic Energy Licensing Board (AELB) for approval, before license is applied and in general, a radiological impact assessment (RIA) study needs to be performed first. 5.4.2.1

Drilling Mud Only water-based-mud/fluids and synthetic based muds/fluids of low toxicity is permitted for use of drilling. “Low Toxicity Oil-Based Mud” and “Synthetic Based Mud” shall be minimised and used only when necessary (based on geological formation). The situation under which it may be necessary to use these muds, the types and the mud specification itself shall be provided by PS

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Contractor to DOE for information prior to starting of drilling operations. The use of any other drilling mud requires prior approval from the DOE. Spent oil/synthetic based mud and other remnants toxic materials are not allowed to be dumped into the sea water. These materials shall be recovered, inventorised, properly labelled, contained and transported safely to shore or to a safe area designated for disposal in accordance to applicable Malaysian laws. Drilling muds and other hazardous/toxic remnants that are categorised as scheduled waste under First Schedule of the Environmental Quality (Scheduled Wastes Regulations) 2005, are not allowed to be dumped into the seawater due to the adverse environmental impact it creates to the marine water quality and benthic organisms. Cuttings from water base mud and from environmentally acceptable oil base mud may be disposed of into the sea. 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. 5.4.2.2

Solid Waste PS Contractor shall not, unless licensed by 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 (3) principle type, Domestic Waste, Industrial Waste and Schedule Waste, and transported to shore in appropriate containers for safe disposal at a site approved by DOE and/or the state or Local authorities.

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The disposal of solid wastes (besides drilling disposal materials) into sea water is prohibited. Solid wastes shall be disposed at a site approved by the Local Authorities. 5.4.2.3

Fluid Waste PS Contractor shall not, unless licensed by DOE, discharge or spill any oil, mixture containing oil or environmentally hazardous substances, pollutants or fluid wastes 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. 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 pretreatment for e.g. neutralization is essential prior to the disposal.

5.4.2.4

Sewage PS 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.

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5.4.3 Pollution Prevention Offshore oil and water production separation facilities shall contain safeguards to prevent discharge of pollutants into the sea. 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 is stipulated in Guidelines for Emergency Communication Procedure (Section 18). Appropriate action shall be taken immediately by the responsible party and the costs for such action shall be at its expense. Oil companies 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, organize and coordinate oil spill contingency plans which encompass all its facilities offshore. Such oil spill contingency plan or plans to be submitted to PETRONAS shall have the following objectives:a)

To design, fabricate and maintain all facilities offshore in such manner to prevent and minimize the frequency of spills, through the use of automatic controls, valves and other methods;

b)

To respond quickly, effectively and with proper knowledge to contain, clean up oil or other spills; and

c)

To evaluate the damage resulting from the spill and take steps, where necessary to assist the rehabilitation of the affected area.

5.5 WELL EVALUATION 5.5.1 General Provisions The Contractor shall obtain sufficient well information and samples during the drilling of a well to permit a geological and reservoir evaluation of the well.

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5.5.2 Drilling Cuttings 5.5.2.1

Sample Frequency The frequency of sampling drill cuttings for geological purpose shall be one sample each for every 5 meters drilled in objective zones and for every 10 meters drilled in other part of the hole in exploration and appraisal wells and one sample each for every 10 meters 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 Notice of Operations.

5.5.2.2

Sample Container Each container of drill cuttings shall be accurately and durably labelled 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.

5.5.3 Cores Proposals for coring shall be indicated in the Notice of Operations to include but not limited to the depth interval of coring, objectives and reservoirs to be cored. 5.5.3.1

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.

5.5.3.2

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

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suitable containers that are accurately and durably labelled with the name of the well and the depth of the core.

5.5.4 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 PERTRONAS. Final prints of formation evaluation log, directional and other surveys shall be submitted to PETRONAS through Well 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.

5.5.5 Oil and Gas Flow Testing Flow assurance issues, such as hydrate formation and waxing at cold temperatures should be considered & handle appropriately prior to flow testing a deepwater well Refer to Section 13 of Guidelines for Well Test, Production Measurement and Allocation.

5.6 RECORDING AND REPORTING 5.6.1 Priority Reports 5.6.1.1

General The 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.

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The Contractor shall submit to PETRONAS, as soon as practicable, a comprehensive written report of the situation, event or accident, and shall notify other persons or authorities as circumstances require. 5.6.1.2

Arrival and Rig Release Notice The 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;

b)

Of the actual hour and date that the drilling rig or drilling unit is released from the drilling location.

The contractor shall also notify Government related departments i.e. Marine Department and Custom & Immigration at least 2 months prior to rig arrival and rig departure.

5.6.2 General Provisions 5.6.2.1

Daily Drilling Report Contractor shall submit the Daily Drilling Report to PETRONAS but not limited to the following information:-

SUPERSEDE ISSUE:

AUG 2000

a)

Well number

b)

Rig name

c)

Plan TD (meter or feet)

d)

Current TD

e)

Plan Cost (USD or RM)

f)

Actual Cost

g)

Plan Days

h)

Actual Days

i)

Days ahead/behind ISSUED BY PETROLEUM MANAGEMENT UNIT

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j)

Summary of operations for last 24 hours

k)

NPT-Hour (daily and cumulative NPT)

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In addition to the above, Contractor shall submit to PETRONAS the Monthly Well Completed Report by the end of the month consisting the following information :-

5.6.2.2

a)

Well Name

b)

Well Cost (USD or RM)

c)

Number of Days

d)

Non Productive Time (NPT - hour)

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.

5.6.3 Final Drilling/Well Completion Report The Contractor shall submit to PETRONAS a final drilling/well completion report and electronic copy within 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 :-

SUPERSEDE ISSUE:

AUG 2000

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 (measured depth and TVD) ;

e)

Maximum angle reached ;

f)

Total days spent on the well ; ISSUED BY PETROLEUM MANAGEMENT UNIT

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g)

Summary of drilling operations ;

h)

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 measured depth and TVD ;

o)

Mud composition and amount used ;

p)

Cement density, composition, volume of cement used and their estimated top in annulus ;

q)

Depth-time chart, actual vs proposed ;

r)

Operational-time breakdown ;

s)

Directional drilling results and wellbore trace ;

t)

Final estimated well cost ;

u)

Detailed NPT breakdown in tabular format (data to be segregrated based on NPT due to drilling contractor, service contractor and well problem).

5.6.4 Company Press Release The Contractor shall obtain prior written approval from PETRONAS for all press releases issued regarding wells drilled under these procedures.

5.7 PLUGGING AND ABANDONMENT OF WELLS 5.7.1 Responsibility to Abandon a Well Contractor shall ensure that :a)

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AUG 2000

A well or a portion of a well that is not suspended or completed is abandoned, and ISSUED BY PETROLEUM MANAGEMENT UNIT

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b)

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Where a well is abandoned, it shall be abandoned in accordance with applicable provisions under Section 5.7.

When a well or a portion of a well has not been abandoned in accordance with applicable provisions under Section 5.7, it shall be the responsibility of the Contractor, when required by PETRONAS, to properly re-abandon the well.

5.7.2 Application to Abandon a Well The Contractor shall submit to PETRONAS a request for approval of the intent to abandon any well, together with a programme outlining the procedures of the operations and plug and abandonment schematic diagram. The notification for any producible well shall include reasons for abandonment.

5.7.3 Subsequent Report of Abandonment The Contractor shall produce a detailed report of the manner in which the abandonment or plugging work was accomplished, including the nature and quantities of materials used in the plugging and the location and extend, by depth, of casing left in the well and the volume of mud fluid used. If an attempt was made to cut and pull any casing string, a description of the methods used and results obtained must be included. This report shall be submitted to PETRONAS in accordance with Section 5.6.3.

5.7.4 Permanent Abandonment 5.7.4.1

Isolation of Zones in Open Hole In uncased portions of wells, cement plugs shall be spaced to extend 30 meters below the bottom to 30 meters above the top of any Hydrocarbon zones and fresh water zones shallower than 300m, to isolate all hydrocarbon bearing zones from one another and from water bearing formations and to prevent any fluids migrating to the surface.

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A cement plug is not supported by a plug or by the bottom of the well and that is located above or against an abnormally pressured zone or a hydrocarbon bearing zone, shall after WOC to harden be tagged with 66700 Newtons (15,000 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 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, the Contractor shall consider taking remedial action to prevent cross flow between them. Where this is not possible, a cement plug shall be positioned above the fish to isolate the fish from the open hole above the fish. In the event that any of the above wells carry a radioactive fish, Department of Environment (DOE) approval shall be sought before any decision is made to abandon the well. 5.7.4.2

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 permanenttype 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 meters above and 30 meters below the casing shoe.

b)

A permanent-type bridge plug (or equivalent) set within 45 meters above the casing shoe. This bridge plug shall be tested in accordance with Section 5.7.4.5 prior to placing subsequent plugs. Before setting the plug attempts should be made to cure losses.

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c)

5.7.4.3

Page 109

For deepwater operations, either set a mechanical plug or leave adequate mud weight (required to account for riser margin) in last casing string to surface.

Plugging or Isolation of Perforated Intervals A balanced cement plug shall be set by the displacement method opposite all open perforations (not squeezed with cement) extending a minimum of 30 meters above and 30 meters below the perforated interval or down to a casing plug, whichever is less. In lieu of setting a cement plug by the displacement method, one of the following method is acceptable. a)

A cement retainer with effective back pressure control or a permanent packer set not less than 15 meters and not more than 30 meters 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 meters above the retainer or packer.

5.7.4.4

b)

A permanent-type bridge plug set not more than 45 meters above the top of the perforated interval.

c)

Such other method as may be approved by PETRONAS for a specific situation.

Plugging of Casing Stubs 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.

5.7.4.4.1

Stub Terminating Inside Casing String A stub terminating below a conductor casing shall be plugged by one of the following methods:a)

SUPERSEDE ISSUE:

AUG 2000

A cement plug set so as to extend 30 meters above and 30 meters below the stub.


REVISION 2 AUG 2008


b)

Page 110

A cement retainer set approximately 15 meters above the stub with a volume of cement equivalent to 45 meters squeezed below the retainer and 15 meters above the retainer.

5.7.4.4.2

c)

A permanent bridge plug set approximately 15 meters above the stub.

d)

Such other method as may be approved by PETRONAS for a specific situation.

Stub Terminating Below Casing String If the stub is below the next larger string, plugging shall be accomplished in accordance with either Section 5.7.4.1 or Section 5.7.4.2.

5.7.4.4.3

Liner Top or Screen Liner or screen that is impractical to be removed shall be plugged in accordance with Section 5.7.4.4.1

5.7.4.4.4

Plugging of Annular Space Any annular space communicating with any open hole and extending to the ocean floor shall be plugged with cement. This requirement is waived for deepwater operations.

5.7.4.4.5

Surface Plug A cement plug at least 45 meters in length, with the top of the plug 45 meters or less below the sea floor, shall be placed in the smallest string of casing which extends to the sea floor.

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For Subsea wellhead, the top of the plug may be set within 100 m to the sea floor. 5.7.4.5

Testing of Plugs The setting and location of the first plug below the surface plug shall be verified by one of the following methods: a)

By placing a minimum pipe weight of 66700 Newton (15,000 psi) on the cement plug or bridge plug. The cement placed above the bridge plug need not be tested.

b)

By testing the casing against the plug with a minimum pump pressure of 6900 kPa (1000 psi) with no more than a 10 percent pressure drop during a 15-minute period.

5.7.4.6 Drilling 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 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. 5.7.4.7 Clearance of Location All casing, wellhead equipment, and piling shall be removed as deep as practically possible (minimum of 1 m.) below the sea floor. The Contractor shall provide written verification that the location has been cleared of all obstructions. The wellhead does not require removal in water depths greater than 1000 ft. Please refer to Section 16, Guidelines for Decommissioning of Upstream Installation.

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5.7.5 Well Suspension (Semi-Permanent 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 5.7.4.

5.7.6 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 5.7.4.1, 5.7.4.2 and 5.7.4.3 and shall be equipped with a 'dual safety'feature in the form of kill fluid together with one of the following:a)

Pressure tested casing or cement plug or liner lap or;

b)

Other pressure testing mechanical barrier

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

5.7.7 Suspended Well Contractor shall ensure any well that is suspended and that has not been completed within 5 (five) years from the date of suspension shall be either completed or abandoned. 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 3 (three) years from the date of suspension unless prior approval has been given by PETRONAS for the extension of the period.

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5.8 COMPLETION OPERATION 5.8.1 General Provision Well completion operations shall be conducted in safe efficient manner to protect against harm or damage to life, property, environment and natural resources including hydrocarbon resources.

5.8.2 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 unitized wellhead system is used which has a working pressure rating in excess of the maximum anticipated pressure. Wellhead valve equipment shall consist of a minimum of the crown or swab valve, one SSV, and one master valve, in the Christmas tree. The SSV shall be the second valve in the flow stream from the wellbore.

5.8.3 Tubing Requirements All tubings 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 tubings and connections that are internally coated must be suitable for the temperature and well-fluid characteristic.

5.8.4 Packer Requirements All completions open to hydrocarbon bearing zones(s) shall be completed with the tubing-casing annulus packed off above the upper-most open casing perforations SUPERSEDE ISSUE:

AUG 2000


REVISION 2 AUG 2008


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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.

5.8.5 Separation of Zones Multiple completions in the same wellbore 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.

5.8.6 Landing Nipple Tubing hanger(s) shall be equipped with landing nipples or plug bushings to receive pump-through tubing plugs or back-pressure valves.

5.8.7 Sub-surface Safety Valve All tubing installations open to a hydrocarbon bearing zone shall be equipped with a SCSSV located at least 30 meters 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 meters below the sea floor. Any other method/replacement of sub-surface safety valve need PETRONAS approval.

5.8.8 Completion Fluids The fluids used during well completion operations shall be designed to minimise adverse effects on metal surfaces and formation damage, and shall be of sufficient density to control anticipated formation pressure if direct communication exists with the formation.

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AUG 2000


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5.9 WORKOVER OPERATIONS 5.9.1 General Requirements 5.9.1.1

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.

5.9.1.1.1

Workover Rigless definition A well intervention operation 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 activities were combined with supporting vessel/boat utilization in offshore environment Rigless operation shall be conducted only when the minimum requirements below are followed: 1.

Ensuring safety concerns are being addressed properly (lifting equipment, platform integrity, well control etc)

2.

Risk and benefit to perform the operations.

3.

Cost analysis.

4.

Assess the environmental impact.

Further discussion is required for any complicated operation that was not covered in this document and subject to approval by PETRONAS. 5.9.1.1.2

Workover Rig definition A well intervention operation conducted with equipment and support facilities that include requirement for workover rig over well bore.

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Further discussions required for any complicated operations that was not covered in this document and subject to approval from PETRONAS. 5.9.1.2

Workover Structures 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.

5.9.1.3

Pump-Down Operations The flowlines from the pump manifold to the wellhead valve assembly shall have a rated working pressure equal to that of the 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.

5.9.1.4

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.

5.9.1.5

Well Control Fluids The characteristics, use, and testing of well control fluids shall be designed and maintained to minimize formation damage and assure well control. Quantities of materials sufficient to assure well control shall be maintained at the wellsite.

SUPERSEDE ISSUE:

AUG 2000


REVISION 2 AUG 2008


5.9.1.6

Page 117

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 tested if possible in each tubing string before removing BOPs 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 BOPs. 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.

5.9.1.7

Well Unloading Operations Operations which involve unloading or cleaning up a well shall use piping or equivalent armored 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).

5.9.1.8

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 maximumanticipated pressure. Appropriate high pressure shut-off, and bleed valves

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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. 5.9.1.9

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. PS Contractor shall have procedure for Simultaneous Production and Drilling Operation (SIPROD).

5.9.2 Notification and Submittal Requirements 5.9.2.1

Notice of Workover Operations Workover operations, multiple completions, and reentries to complete require prior approval from PETRONAS through the submittal of a "Notice of Workover Operation" and acceptable electronic format. The document shall be submitted 14 calendar days prior to the date when approval is required. Information including, but not limited to the following is required:-

SUPERSEDE ISSUE:

AUG 2000

a)

Objective and justification of proposed workover ;

b)

Present well status ;

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 equipment to be used;

g)

Proposed procedures outline ;

h)

Estimated duration and expenditures.

i)

Estimated reserve, incremental production including estimation methodology ISSUED BY PETROLEUM MANAGEMENT UNIT

REVISION 2 AUG 2008


j)

Risk and mitigation plan.

k)

Cost analysis and detailed breakdown.

l)

Safety and environmental assessment

Page 119

Detailed workover procedures shall be submitted to PETRONAS for information purposes upon request 5 calendar days prior to commencement of workover operations. The summary of work progress shall be submitted daily. 5.9.2.2

Workover Report After the workover operation is completed, all available information shall be submitted in a Workover Report to PETRONAS not later than 60 calendar days after the workover is completed. The report shall include but not limited to the following information:a)

History of the well;

b)

Description of work performed;

c)

Dates the work was performed;

d)

A well schematic drawing with tubing details before and after workover;

5.9.2.3

e)

Results of well test, before and after workover;

f)

Detailed expenditure summary.

Routine Operations Certain routine operations, such as, pump-down or through-tubing non-rig operations are considered maintenance operations and do not require approval by PETRONAS. The operations include the following:-

SUPERSEDE ISSUE:

AUG 2000

a)

Paraffin cutting ;

b)

Moving and setting tubing plugs, gaslift valves, and SSSVs by wireline techniques ;

c)

Opening and closing circulation ports ; ISSUED BY PETROLEUM MANAGEMENT UNIT

REVISION 2 AUG 2008


Page 120

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.)

i)

Fishing operations ;

j)

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.

5.9.3 Pressure Control Requirements BOPs and other surface pressure control equipment shall have a rated working pressure which equals or exceeds the maximum-anticipated surface pressure. 5.9.3.1

Major Workover Operations For any operation involving movement of the tubing string the minimum BOP shall be installed as defined in Section 5.3.5.3.

5.9.3.2

Minor Workover Operations (Excluding Wireline Operation) For shut-in tubing pressures in excess of 34500 kPa (5000 psi) the minimum BOPs shall consist of :a) Two sets of pipe rams and one set of blind rams, or b) Two sets of pipe rams and one set of shear rams.

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For shut-in tubing pressures of 34500 kPa (5000 psi) or less, minimum requirements are:a) One set of pipe rams and one set of blind rams, or b) One set of pipe rams and one set of shear rams. 5.9.3.3

Coiled-Tubing Operations The minimum BOPs shall consist of the following :-

5.9.3.4

a)

One set of pipe-rams, hydraulically operated ;

b)

One two-way slip assembly hydraulically operated ;

c)

One pipe cutter assembly, hydraulically operated ;

d)

One set of blind rams, hydraulically operated ;

e)

One pipe stripper assembly ; and

f)

One spool with side outlets (if no side outlets are provided in the wellhead valve assembly).

g)

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

Snubbing Operations The minimum BOPs shall consist of the following :a)

One set of pipe-rams hydraulically operated;

b)

Two sets of stripper type pipe-rams BOPs, hydraulically operated with spacer spool ;

c)

One pipe stripper assembly ; and

d)

Hydraulically operated, or in exceptional cases mechanically operated, snubber slip and seal assembly; if the surface pressure is above 34500 kPa (5000 psi), hydraulically operated blind rams shall be used.

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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. 5.9.3.5

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 maximumanticipated 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 every 14 days. The pressure test shall be recorded in the relevant field log. If necessary, a manifold and choke line shall be provide and tested with water to the rated working pressure of the BOPs or of the wellhead valve assembly, whichever is less.

5.9.4 Testing and Actuation Requirements 5.9.4.1

Pressure Test Each component of the BOP stack assembly and related control equipment shall be individually tested in accordance with Section 5.3.5.6.2.

5.9.4.2

Actuation The actuation of the BOP shall be carried out as defined in accordance with section 5.3.5.6.3.

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AUG 2000


REVISION 2 AUG 2008


5.9.4.3

Page 123

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.

5.9.5 Wireline Operations 5.9.5.1

General Requirements For the purpose of these requirements wireline operations include all casedhole or open hole operations, utilizing 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 proper lighting.

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AUG 2000


REVISION 2 AUG 2008


5.9.5.2

Page 124

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 BOPs 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.

5.9.5.3

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 BOPs. 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 utilize explosive devices or hazardous radioactive materials shall vacate the rig floor and substructure prior to device arming, entry, and retrieval from the wellbore. Knowledgeable 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 (e.g electric welding, exposed rig wiring near the cable etc). PS Contractor shall require that safe operating procedures and test are used when handling any explosive devices.

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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 meters 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 meters down the hole. 5.9.5.4

Swabbing Operations The swabbing of wells shall be performed with a lubricator assembly, whether carried out with a small slick line 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 hydrocarbons shall not be performed during hours of darkness unless approved by PETRONAS.

5.9.6 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.

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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. Closure of a SCSSV will suffice as a tubing plug.

5.10 HYDROGEN SULPHIDE (H2S) DRILLING OPERATIONS 5.10.1 General Provisions When operations are undertaken involving formations or reservoirs known or expected to contain 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.

5.10.2 Physical Properties and Toxicity of H2S 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 a continuous eight hours exposure of personnel is 10 ppm in air, which is 0.001% by volume.

5.10.3 Breathing Equipment The number of breathing masks shall cover the total number of personnel in the rig location plus an adequate amount for visitors. The masks which neutralise toxic gas do not provide the necessary protection and shall never be used in continuous drilling operation when H2S environment is encountered. 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 and all essential personnel in drilling operation shall be required to use this equipment. Resuscitators with spare oxygen bottle shall be provided at each emergency centre. SUPERSEDE ISSUE:

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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 must be worn.

5.10.4 H2S Gas Detection System A number of automatic continuous H2S sensors shall be installed, be in working condition and routinely function tested according to API RP14C to cover as minimum the areas of bell nipple, flowline and shale shaker, mud pits, sack room, motor room and living quarters. These sensors should 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.

5.10.5 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.

5.10.6 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 multidirectional and capable of dispersing H2S away from working personnel.

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5.10.7 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.

5.10.8 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,

d)

Conditions with less than, 10 ppm H2S in the atmosphere.

e)

Conditions with more than 10 ppm but less than 20 ppm H2S in the atmosphere (limited danger to life).

f)

Conditions with more than 20 ppm H2S in the atmosphere (high danger to life).

g)

Responsibility and duty of personnel for each operating condition;

h)

Evacuation plan; and

i)

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.

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5.10.9 Rig Equipment H2S gas is highly corrosive to steel and at high stress levels extreme metal embrittlement may occur in a very short time. All tubulars, wellhead equipment, and other drilling related equipment which may be exposed to H2S conditions conductive to metal embrittlement shall be selected in accordance with the guideline presented in NACE MR-01-75. (National Assc. Corrosion Engineers considering metallurgical properties and/or environment in contact with the tubulars and equipment in order to reduce the chances of failure from H2S metal embrittlement. 5.10.9.1

Drill Pipe To reduce potential H2S embrittlement steel drill pipe should have a yield strength of 655,000 kPa (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.

5.10.9.2

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.

5.10.9.3

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

5.10.9.4

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

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manner to compensate for wind changes. The flare shall be equipped with a pilot and an automatic ignitor.

5.10.10 Drilling Operations 5.10.10.1

Pipe Trips and Stripping Operations Ever 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 mud returned shall also be increased.

5.10.10.2

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

5.10.10.3

Coring Operations When coming out of the hole with a core barrel under suspected H2S condition, the drilling crew shall wear protective equipment while pulling the last twenty stands or at any time H2S reaches the 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.

5.10.10.4

Mud Programme Suitable water or oil base mud shall 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 sulphide stress cracking. Consideration shall also be given the use of H2S scavengers in both water and oil base mud

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systems. Sufficient quantities of additives shall be maintained at wellsite for addition to neutralize H2S picked up by the mud system. Drilling mud containing H2S shall be degassed and the gases removed shall be burned with the flare system and must be continuously monitored for H2S concentration.

5.10.11 Well Testing Operations During well test, the level of H2S concentration shall be monitored at first hydocarbons to surface and at regular intervals subsequent to 1st. hydrocarbons. 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.

5.11 ONSHORE DRILLING OPERATION 5.11.1 General In addition to the foregoing sections, Contractor shall comply with the following procedures in conducting onshore drilling operations.

5.11.2 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. SUPERSEDE ISSUE:

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5.11.3 Well Near Potential Hazardous Sites Any PS Contractor intending to drill a well within 3 kilometers from Potential Hazardous Sites shall obtain written approval from relevant authorities prior to carrying out site preparation work.

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

5.11.5 Fire Prevention and Safety Any rubbish or debris that might constitute a fire hazard shall be removed to a distance of at least 50 meters from the vicinity of any well and the flare pit. All waste shall be burned or disposed of in a manner to avoid creating a fire hazard. Every drilling rig together with every camp located within 50 meters of the well shall be installed with an interconnected fire alarm system that is capable of automatically sound an alarm 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.

5.11.6 Engines 5.11.6.1 Internal Combustion Engines Any fixed internal combustion engine that is located within 25 meters of a drilling well onshore shall have the exhaust pipe of the engine in accordance to MEC 1 standard:Equipped with a spark arrester. SUPERSEDE ISSUE:

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Insulated or sufficiently cooled to prevent ignition of combustible gases. Directed away from the wellbore or other sources of combustible gases and terminated at least 6 meters from the vertical centre line of the wellbore. Only diesel driven engine are allowed for onshore drilling operation. For fixed installation, it must meet MEC1 standard. 5.11.6.2

Diesel Engines Any fixed diesel engine that is located within 25 meters 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 meters from the well.

5.11.7

Plug & Abandonment Requirements All wells onshore shall be plugged and cemented for abandonment as required under Section 5.7.4. In addition, the Contractor shall ensure that:a)

All casings shall be cut at a point at least one meter below the natural ground level with a minimum of 10 meters of cement plug placed in the inner most casing and

b)

A steel plate of at least 7 mm 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.

c)

SUPERSEDE ISSUE:

AUG 2000

In the event a nuclear source equipment is left in hole after several unsuccessful attempt has been made, the abandoned well shall marked with appropriate signs as per the TENORM requirement.


REVISION 2 AUG 2008


5.11.8

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Protection of Fresh Water Sands Fresh water sands are to be protected with surface casing which has been cemented 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 3015 meters above and below the zones.

5.11.9

Restoration of the 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 rat-hole and the mousehole shall be filled up and where applicable with cement plug at the surface.

5.11.10 BOP Requirements For the purpose of determining the minimum well control system to be used, all onshore wells can be classified as follows:Class 1 : A well in which no surface casing is set. Class II

: A well in which a surface casing is set and hole

maximum anticipated shut-in well head pressure does not exceed 34500kPa (5000psi) and Class III

: A well in which a surface casing is set and the

Maximum anticipated shut-in well head pressure exceeds 34500 kPa (5000 psi). The minimum requirements for drilling below each casing string for a conventional surface BOP system for each classification of onshore well are given below :Class I Well Conductor Casing ............................................ 1*-diverter Class II Well Conductor ........................................................ 1*- diverter

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Surface & Intermediate Casing ........................ 1- annular BOP 2**-Single pipe rams BOP (with a spool in between) (one to be blind rams) Class III Well Conductor Casing ............................................ 1*-diverter Surface & Intermediate Casing ........................ 1 - annular BOP 2-** pipe rams + 1 blind or shear ram Note: *

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 meters 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).

**

A double ram type BOP provided with appropriate side outlets for connecting kill or choke lines may be used for wells that are drilled not deeper than 600 meters TVD below the ground level.

***

To comply with Section 5.3.5.3 "Surface BOP".

All ram type BOP used for onshore operations without automatic ram-lock facilities shall be installed with manual hand wheels with extension for locking the rams in closed position.

5.11.11 BOP Pressure Test Each component of the BOP stack assembly and related control equipment shall be pressure tested to their rated working pressure or to the maximum anticipated wellhead pressure whichever is lower. The BOP stack assembly shall be pressure tested for at least 15 minutes. SUPERSEDE ISSUE:

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The annular preventer may be tested to 6900 kPa (1000 psi) or 50% of the rated working pressure. All BOPs and related control equipment shall be tested:a)

When installed on a well or stump-tested prior to installation. Such stump testing shall be recorded on the respective daily drilling report submitted to PETRONAS.

b)

Before drilling out, after each string of casing has been set and cemented.

c)

Not less than once every forthnight but not exceeding (14) days between tests and;

d)

Following repairs that require disconnecting a pressure seal in the assembly.

5.11.12 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 meters away from the well, have 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 back-filled and compacted.

5.11.13 Casings Supplementary to the Casing and Cementing Requirements in the foregoing Section 5.3.3, the casings to be installed in an onshore well in the order of operations are:-

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5.11.13.1

Page 137

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.

5.11.13.2

Conductor Casing The initial conductor casing string shall be set in a competent bed or through formations determined desirable to be isolated from the well by pipe for safer operations. Such setting depth shall be sufficient to allow safe use of diverter equipment as per Section 5.11.10. Any variations to such depth or where more than one conductor casing is to be set, prior approval from PETRONAS is required as part of the Notice of Operations, so as to permit safe drilling to the next casing setting depth. In cases where the conductor casing is set deeper than 300 metres TVD, a formation integrity test shall be performed as required under Section 5.3.7 "Formation Integrity Testing". If not driven, the conductor casing shall be cemented with a sufficient amount of cement to fill the annular space from the shoe of the casing to the surface. Surface Casing The surface casing shall 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 to provide well control until the next casing is set. Such setting depth for an onshore well is normally between 150 to 1400 meters TVD below the

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ground level. Variations to such depth may be made with prior approval from PETRONAS as part of the Notice of Operations. Surface casing shall be cemented sufficiently to protect all fresh water zones with a sufficient volume of cement to fill the calculated annular space at least 15 meters inside the conductor casing or to the stove pipe/structural casing in the event that conductor casing is not set. After drilling a maximum of 15 meters of new hole below the surface casing shoe, a leak-off test shall be performed to obtain data to be used in estimating the formation fracture gradient. The leak-off test shall be performed either by testing to formation leak-off test or by testing to a pre-determined equivalent mud weight. The result of this test and any other subsequent tests shall be recorded on the driller's report and used to determine the depth and the maximum mud weight for the next portion of the hole section.

5.11.14 Drilling Liquid Waste Liquid waste comprising of waste drilling mud, oily waste or other liquid products from a well shall be contained at all times and dispose of in a manner that shall not pollute any surface water or underground source of potable water. Such liquids produced may be stored in an earthen pit at the well site, provided that such pit is excavated to a depth which shall contain all the waste fluid and be so constructed that it shall not collect natural run-off water. Where the surface topography does not allow construction of such pits, all liquid waste shall be collected in tanks and transported to an area approved for storing or disposal of liquid waste. Upon cessation operations, such pits shall be backfilled and compacted.

5.11.15 Well Near Water 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 SUPERSEDE ISSUE:

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the water, PS 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 must have a suitable collecting pit & skimmer to collect the liquid waste product and water run-off.

5.12 ONSHORE COMPLETION AND WORKOVER OPERATIONS 5.12.1 General Supplementary to the foregoing Section 5.8 and Section 5.9, Contractor shall comply with the following procedures in conducting onshore completion and workover activities.

5.12.2 Sub-surface Safety Valve Any onshore well that is located within a 5 kilometer 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 installed in the tubing at least 30 meters below the ground level and such well will have a sealed casing-tubing annulus.

5.12.3 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.

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

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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 back-filled and compacted. Discharge of oilfield brines and other mineralized 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 contains connate water compatible with the injecting fluid and that such zones are separated by impermeable beds that shall prevent polluting the fresh water sands. Oilfield brines or other mineralized water which has been treated as necessary to remove constituents which may be harmful to aquatic life may be disposed of into the Malaysian Offshore and adjacent estuarine zones with approval from relevant Department Of Environment (DOE) For any waste/hazardous material generated during operations shall be disposed in accordance to Section 5.4 - Material Handling and Disposal with reference to Section 1 Guidelines for Health, Safety and Environment.

5.12.5 Onshore Wellhead Valve Assembly (X'mas Tree) All completed wells onshore 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 20700 kPa (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, PS Contractor shall ensure that, when a well is not on pump, the wellhead valve assembly shall contain a surface safety valve (SSV) that shall automatically shut-off

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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.

5.12.6 Wells on Pump Wells which are incapable of natural flow and which require pumping by sucker rods or submersible downhole pumps or any other mechanical lifting methods to produce that well may be exempted from requirements under Section 5.9.1.5 to 5.9.1.9, Section 5.9.3 to 5.9.6 and Section 5.10.1 to 5.10.7.

5.12.7 Fencing and Well Security Where a producing well, or a tank battery or a process facility is located within 5 kilometer of an occupied dwelling, a rural school, residential area or where conditions can cause exposure to the public shall be fenced as a security measure. Such fencing shall be of adequately strong construction with a lockable gate and posted with clearly visible warning sign against unauthorized entry and tempering. When a producing well, or a tank battery or a process facility is located elsewhere, a cattle type fencing with barbed wire shall be constructed around the area.


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AUG 2000


REVISION 2 AUG 2008

SECTION SECTION 67 GUIDELINES FOR SUBSURFACE BARGES OPERATING PROCEDURES SAFETY OFFSHORE MALAYSIA DEVICES (PGBOOM)

Page 142

SECTION 6 PROCEDURES FOR SUBSURFACE SAFETY DEVICES

Executive Summary This section provides procedures and requirement of subsurface safety devices on all tubing installation with regard to flowing, shut-in wells or injection wells, the subsurface safety valve specification, testing and additional protective equipment.

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AUG 2000


REVISION 2 AUG 2008

SECTION SECTION 67 GUIDELINES FOR SUBSURFACE BARGES OPERATING PROCEDURES SAFETY OFFSHORE MALAYSIA DEVICES (PGBOOM)

6.1

Page 143

INSTALLATION All tubing installation in wells shall be equipped with surface-controlled subsurface safety devices. Notwithstanding the above, during emergency, alternative safety devices e.g sub surface control devices may be temporarily installed without prior consent of PETRONAS. PETRONAS shall be notified of the situation and circumstances.

6.2

SHUT-IN WELLS Unless a well is equipped with a functioning subsurface safety valve (SSSV) (i.e valves are able to open or close, not jammed, able to withstand holding pressure and not leak) the well has to be shut-in and a tubing plug shall be installed.

6.3

INJECTION WELLS Subsurface safety devices as described under sub-section 6.1 shall be installed at all injection wells unless it is determined that the well is incapable of naturally flowing oil or gas.

6.4

VALVE SPECIFICATIONS PS Contractor shall use subsurface safety devices that comply with the minimum standards set forth in API Specification 14A i.e "Subsurface Safety Valves equipment" for quality assurance including design, material, and functional test requirements and for verification of independent party performance testing and manufacturer functional testing of such valves.

6.5

REINSTALLATION, TESTING AND MAINTENANCE PS Contractor shall install, test and maintain the SSSV Systems based on their operating and inspection maintenance philosophy.

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SECTION SECTION 67 PROCEDURES SAFETY GUIDELINES FOR SUBSURFACE BARGES OPERATING DEVICES (PGBOOM) OFFSHORE MALAYSIA

6.6

Page 144

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 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.

6.7

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 come 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 PETRONAS approval but the request has to be submitted within thirty (30) days limit after the installation.

6.8

OTHER COMPLETION TECHNIQUES PS Contractor may apply exception for SSSV requirements for wells which have other completion technique that prevent SSSV installation e.g. Sucker Rod Pump.

6.9

RECORDS PS Contractor shall maintain records which include design specifications, verification of assembly, 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.


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AUG 2000


REVISION 2 AUG 2008

SECTION 7 GUIDELINES FOR BARGES OPERATING OFFSHORE MALAYSIA (PGBOOM)

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SECTION 7

GUIDELINES FOR BARGES OPERATING OFFSHORE MALAYSIA (PGBOOM) Executive Summary This section provides guidelines and requirements of barges operating offshore Malaysia. The guidelines shall apply to all mobile offshore installation units and surface units which can be moved from place to place without major dismantling or modification, whether or not it has its own motive power.

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7.1

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INTRODUCTION The adoption of the ‘PETRONAS GUIDELINES FOR BARGES OPERATING OFFSHORE MALAYSIA” will result in achieving the desired standardisation as well as upgrading the safety requirement of the barges.

7.1.1 Application 7.1.1.1

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

7.1.1.2

The provision of section 7.2 in the Guideline will apply to 7.1.1.1 (a) to (h) above.

7.1.1.3

The provision of Section 7.3 to 7.8 will apply to 7.1.1.1 (c) to (h) above.

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7.1.2 Requirements Specifically the requirements are as follows :7.1.2.1

Accommodation Spaces a)

All accommodation spaces shall be constructed and to comply with Section 7.2 of the Guidelines.

b)

Accommodation spaces shall be constructed of steel or other equivalent material. Applicable fire integrity standards to be applied to divisions between adjacent spaces shall be as per Table 7A and Table 7B of Appendix 7.

7.1.2.2

Automatic Fire Detection and Alarm System An automatic fire detection and alarm systems shall be provided in all accommodation and service spaces. The system shall comply with the Section 7.3 of the Guidelines.

7.1.2.3

Life Saving Appliances a)

Life Saving Appliances are to comply with Section 7.4 of the Guidelines.

b)

In addition, all barges involved with maintenance activities that are either producing hydrocarbons or are shut-in and semi-submersibles shall be provided with rigid totally enclosed motor propelled survival craft (TEMPSC) of such capacity as will accommodate all persons onboard. In lieu of non availability of TEMPSC, contractor shall demonstrate alternative to meet objective of having TEMPSC.

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SECTION 7 GUIDELINES FOR BARGES OPERATING OFFSHORE MALAYSIA (PGBOOM) 7.1.2.4

Page 148

Fire Fighting Equipment a)

Fire Fighting Equipment is to comply with Section 7.5 of the Guidelines.

b)

7.1.2.5

In addition, fixed Fire Extinguishing System (CO2 or equivalent that do not contravene with IMO requirements) shall be provided in the machinery spaces.

Provisions for Helicopter Facilities Adequate provisions for helicopter facilities when provided shall comply with Section 7.6 of the Guidelines.

7.1.2.6

Operating Requirements An Operating Manual, for safe operation of the unit shall be made available on board and shall comply with Section 7.7 of the Guidelines.

7.1.3 Definitions 7.1.3.1

‘Steel or Other Equivalent Material” Where the words “steel or other equivalent material” occur, “equivalent material” means any non-combustible material which, by itself or due to insulation provided, has structural and integrity properties equivalent to steel at the end of the applicable fire exposure to the standard fire test (e.g. Aluminum Alloy with appropriate insulation).

7.1.3.2

Non-Combustible Materials Non-combustible materials are materials which neither burn nor give off flammable vapours in sufficient quantity for self-ignition when heated to approximately 750oC.

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“A Standard Fire Test” A Standard Fire Test is one in which specimens of the relevant bulkheads or decks are exposed in a test furnace to temperature corresponding approximately to the standard time-temperature curve. The specimen shall have an exposed surface of not less than 4.65 square metres (50 square feet) and height (or length of deck) of 2.44 metres (8 feet) resembling as closely as possible the intended construction and includes where appropriate at least one joint. The standard time - temperature curve is defined by a smooth curve drawn through the following points measured above the initial furnace temperature:-

7.1.3.4

at the end of the first 5 minutes

556oC


659oC


718oC


821oC


925oC

“A” Class Divisions “A” class divisions are those divisions formed by bulkheads and decks which comply with the following :-

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a)

They shall be constructed of steel or other equivalent material;

b)

They shall be suitably stiffened;

c)

They shall be so constructed as to be capable of preventing the passage of smoke and flame to the end of the one-hour standard fire test;

d)

They shall be insulated with non-combustible materials such that the average temperature of the unexposed side will not rise more than 139oC above the original temperature, nor will the temperature, at any


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one point including any joint, rise more than 180oC above the original temperature, within the time listed below :-

7.1.3.5

Class “A - 60” Class “A - 30”

60 minutes 30 minutes

Class “A - 15” Class “A - 0”

15 minutes 0 minute

“B” Class Divisions “B” class divisions are those divisions formed by bulkheads, decks, ceilings or linings which comply with the following :a)

They shall be so constructed as to be capable of preventing the passage of flame to the end of the first half hour of the standard fire test.

b)

They shall have an insulation value such that the average temperature of the unexposed side will not rise more than 139oC above the original temperature, nor will the temperature at any one point, including any joint, rise more than 225oC above the original temperature, within the time listed below:class “B - 5” class “B - 0”

c)

7.1.3.6

15minutes 0 minute

They shall be constructed of approved non-combustible materials and all materials entering into the construction and erection of “B” class divisions shall be non-combustible

“C” Class Divisions “C” class divisions are divisions constructed of approved non-combustible materials. They need to meet neither requirements relative to the passage of smoke and flame nor limitations relative to the temperature rise.

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“Public Spaces” Public spaces are those portions of the accommodation which are used for

7.1.3.8

halls, dining rooms, lounges and similar permanently enclosed spaces. “Control Stations” Control stations are spaces containing emergency sources of power and lighting, spaces containing barge radio equipment, fire control and recording stations, spaces containing centralised fire alarm equipment, and spaces containing centralised emergency public address system stations and equipment.

7.1.3.9

“Corridors” Corridors mean corridors and lobbies.

7.1.3.10

“Accommodation Spaces” Accommodation spaces are those used for public spaces, corridors, lavatories, cabins, offices, hospitals, cinemas, games, hobbies rooms, and pantries containing non-cooking appliances or similar permanently enclosed spaces.

7.1.3.11

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

7.1.3.12

“Service Spaces (low risk)” Service spaces (low risk) are lockers and store-rooms having areas of less than 2 square metres, drying rooms and laundries.

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“Machinery Spaces of Category A” Machinery spaces of category A are all spaces which contain internal combustion type machinery used either for other purposes where such machinery has in the aggregate a total power of not less than 375 kilowatts or which contain any oil fired boiler or oil fuel unit; and trunks to such spaces.

7.1.3.14

“Other Machinery Spaces” Other machinery spaces are all machinery spaces other than machinery spaces of category A described in (7.1.3.13) above.

7.1.3.15

“Hazardous Areas” Hazardous areas are all those areas where, due to possible presence of a flammable atmosphere due to operations, the use without proper consideration of machinery or electrical equipment may lead to a fire hazard or explosion.

7.1.3.16 “Service Spaces (high risk) Service spaces (high risk) are galleys, pantries containing cooking appliances, paint rooms, lockers and store rooms having areas of 2 square metres or more and workshops other than those forming part of the machinery spaces. 7.1.3.17

“Open Decks” Open decks are open deck spaces, excluding hazardous areas.

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ACCOMMODATION SPACES

7.2.1 Restrictions 7.2.1.1

There must be no direct communication between the accommodation spaces and any chain locker, cargo stowage or machinery spaces, except through solid, close-fitted doors or hatches.

7.2.1.2

No access, vent, or sounding tube from a fuel or cargo oil tank into accommodation spaces except that access openings and sounding tubes may be located in corridors, provided they are air tight sealed closed, when not in use.

7.2.2 Construction of Accommodation Spaces 7.2.2.1

Each sleeping, mess, recreational, or hospital (sick bay) space that is adjacent to or immediately above a stowage or machinery space, paint locker, drying room, washroom, toilet space, or other odour source must be made odourproof.

7.2.2.2

Each accommodation space must be protected from the heat and noise.

7.2.2.3

Where the shell or an unsheathed weather deck forms a boundary of an accommodation space, the shell of deck must have a covering that prevents the formation of moisture.

7.2.2.4

The deck heads of each accommodation space must be of light colour.

7.2.2.5

Each accommodation space in which water may accumulate must have a drain scupper located in the lowest part of the space, considering the average trim of the unit.

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Each public toilet space must be constructed and located so that its odour do not readily enter any sleeping spaces, mess, recreational, or hospital (sick bay) space.

7.2.3 Arrangement of Sleeping Spaces 7.2.3.1

To the extent practicable, crew from the same shift should be berthed together in sleeping spaces arranged to minimise disturbance created by personnel leaving for or arriving from a working period.

7.2.4 Size of Sleeping Spaces 7.2.4.1

No sleeping space may berth more than four persons, except that a sleeping space for personnel not regularly employed on a unit may berth up to six persons if the space meets Section (7.2.3), (7.2.4.2) and (7.2.5) and berthing of six persons in that space is authorised by PETRONAS.

7.2.4.2

Without deducting any equipment used by the occupants, each sleeping space must have for each occupant :-

7.2.4.3

a)

2.8 square metres (approximately 30 square feet) of deck area; and

b)

5 cubic metres (approximately 210 cubic feet) of volume.

Each sleeping space must have at least 191 centimetres (approximately 6 feet 3 inches) of headroom over clear deck areas.

7.2.5 Berths and Lockers 7.2.5.1

Each sleeping space must have a separate berth for each occupant.

7.2.5.2

No more than one berth may be placed over another.

7.2.5.3

Each berth must have a framework of hard, smooth material that is not likely to corrode or harbour vermin.

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7.2.5.4

Each berth must be arranged to provide ample room for easy occupancy.

7.2.5.5

Each berth must be at least 76 centimetres (approximately 30 inches) wide by 193 centimetres (approximately 76 inches) long.

7.2.5.6

Adjacent berths must be separated by a partition that extends at least 46 centimetres (approximately 18 inches) above the sleeping surface.

7.2.5.7

The bottom of a lower berth must be at least 30 centimetres (approximately 12 inches) above the deck.

7.2.5.8

The bottom of an upper berth must be at least 76 centimetres (approximately 2 feet 6 inches) from the bottom of the berth below it and from the deck or any pipe, ventilating duct, or other overhead installation.

7.2.5.9

Each berth must have a berth light.

7.2.5.10

Each occupant of a sleeping space must have a readily accessible locker of hard, smooth material.

7.2.5.11

Each locker must be at least 0.194 square metres (approximately 300 square inches) in cross section and 1.53 metres (approximately 60 inches) high.

7.2.6 Wash Spaces, Toilet Spaces and Shower Spaces 7.2.6.1

For the purposes of this section :a) “Private Facility” means a toilet, washing, or shower space that is accessible only from one single or double occupancy sleeping space. b) “Semi-Private Facility” means a toilet, washing or shower space that is accessible from either of two one-to-four person occupancy sleeping spaces; and

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c) “Public Facility” means a toilet, washing or shower space that is not private or semi-private. 7.2.6.2

Each private facility must have one toilet, one shower and one wash-basin, all of which may be in a single space.

7.2.6.3

Each semi-private facility must have at least one toilet and one shower, which may be in a single space.

7.2.6.4

Each room adjoining a semi-private facility must have a wash-basin if a wash basin is not installed in a semi-private facility.

7.2.6.5

Each unit must have enough public facilities to provide at least one toilet, one shower and one wash basin for each eight persons who occupy sleeping space that do not have private or semi-private facilities.

7.2.6.6

Urinals may be installed in toilet rooms, but no toilet required in this section may be replaced by a urinal.

7.2.6.7

Each public toilet space and washing space must be convenient to the sleeping space that it serves.

7.2.6.8

No public facility may open into any sleeping space.

7.2.6.9

Each wash basin, shower and bathtub must have hot and cold running water.

7.2.6.10

Adjacent toilets must be separated by a partition that is open at the top and bottom for ventilation and cleaning.

7.2.6.11

Public toilet facilities and shower facilities must be separated.

7.2.6.12

Each public facility that is a toilet space must have at least one wash basin unless the only access to the toilet space is through a washing space.

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7.2.6.13

Each washing space and toilet space must be so constructed and arranged that it can be kept in a clean and sanitary condition and the plumbing and mechanical appliances kept in good working order.

7.2.6.14

Wash basin may be located in sleeping space.

7.2.7 Mess Rooms 7.2.7.1

Each mess room must seat the number of persons expected to eat in the mess room at one time.

7.2.7.2

There must be a mess room for serving halal food for Muslim workers.

7.2.8 Hospital (Sick Bay) Space 7.2.8.1

Each unit carrying twelve or more persons on a voyage of more than three days must have a hospital (sick bay) space.

7.2.8.2

Each hospital (sick bay) space must be suitably separated from other spaces.

7.2.8.3

No hospital (sick bay) space may be used for any other purpose, when used for care of the sick.

7.2.8.4

An entrance to each hospital (sick bay) space must be wide enough and arranged to readily admit a person on a stretcher.

7.2.8.5

Each berth in a hospital (sick bay) space must be made of metal.

7.2.8.6

Each upper berth must be hinged and arranged so that it can be secured clear of the lower berth.

7.2.8.7

Each hospital (sick bay) space must have at least one berth that is accessible from both sides.

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7.2.8.8

Each hospital (sick bay) space must have one berth for every 50 persons or portion thereof onboard, who are not berthed in single occupancy rooms, but the number of berths need not exceed 2.

7.2.8.9

Each hospital (sick bay) space must have a toilet, wash basin and bath-tub or shower accessible from the hospital (sick bay) space.

7.2.8.10

Each hospital (sick bay) space must have clothes lockers, a table and seats.

7.2.9 Hospital (Sick Bay) Space Not Required 7.2.9.1

The hospital space required under Section 7.2.8 above is not required on a unit if one single or double occupancy sleeping space, designated and equipped as a treatment or isolation room or both is available for immediate medical use, and has:a)

An entrance that is wide enough and arranged to readily admit a person on a stretcher.

b)

A single berth or examination table that is accessible from both sides; and

c)

A wash basin in or immediately adjacent to it.

7.2.10 Miscellaneous Accommodation Spaces 7.2.10.1

Each unit must have enough facilities to provide 24-hour laundry service (i.e. return clothes in 24 hours).

7.2.10.2

Each unit must have enough equipment or space to provide 24-hour clothes drying service for all personnel on board.

7.2.10.3

Each unit must have an accommodation space that can be used for recreation.

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Each unit must have an accommodation space that can be used for Muslim workers to perform their prayers.

AUTOMATIC FIRE DETECTION AND ALARM SYSTEMS

7.3.1

The system shall be capable of immediate automatic activation with no manual activation by the crew.

7.3.2

The system shall include :a)

Means for giving a visual and audible alarm signal automatically at one or more indicating units whenever any detector comes into operation.

b)

When activated, the indicating units show the location where the fire is detected in any space served by the system.

c)

indicating units shall be centralised on the navigating bridge or in the Main Fire Control station which shall be so manned or equipped as to ensure that any alarm from the system is immediately received by a responsible member of the crew.

d)

constructed so as to indicate if any fault occurs in the system.

7.3.3

The detection system shall be operated by an abnormal air temperature, by an abnormal concentration of smoke or by other factors indication of incipient fire in any of one of the spaces to be protected.

7.3.4

The detection system shall not be used for any purpose other than fire detection.

7.3.5

The detectors may be arranged to operate the alarm by the opening or closing of contacts or by other appropriate methods. Detectors operated by the closing of contact shall be of the sealed contact type and the circuit shall be continuously monitored to indicate fault conditions.

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SECTION 7 GUIDELINES FOR BARGES OPERATING OFFSHORE MALAYSIA (PGBOOM) 7.3.6

Page 160

The detectors shall be :a) Fitted in an appropriate position and suitably protected against impact and physical damage. b) Suitable for use in a marine environment. c) Placed in an open position clear of beams and other objects likely to obstruct the flow of hot gases or smoke to the sensitive element.

7.3.7

At least one detector shall be installed in each space where detection facilities are required and there shall be not less than one detector for each 37 square metres (400 square feet) of deck area or as per the approved ship’s safety plan. In large spaces the detector shall be arranged in a regular pattern so that no detector is more than 9 metres (30 feet) from another detector or more than 4.5 metres (15 feet) from a bulkhead.

7.3.8

There shall be not less than two independent sources of power supply for the electrical equipment in the operation of the fire alarm and fire detection system, one of which shall be an emergency source. The supply shall be provided by separate feeders reserved solely for that purpose. Such feeders shall run to a change-over switch situated in the control station for the fire detection system.

7.3.9

A list or plan shall be displayed adjacent to each indicating unit showing the spaces covered.

7.3.10

Provision shall be made for testing the correct operation of the detectors and the indicating units by supplying means for applying hot air or smoke at detector positions as recommended by the operation manual.

7.3.11

Adequate spare detector head shall be provided on board to replace every fifth detector.

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LIFE SAVING APPLIANCES

7.4.1

All barges shall carry :-

7.4.1.1

Life rafts of sufficient aggregate capacity to accommodate twice the total number of persons onboard.

7.4.1.2

For barges involved in maintenance activities and all semi-submersibles are to carry :a) Rigid totally enclosed motor propelled survival craft (TEMPSC) of such capacity as will accommodate all persons on board, and b) Life rafts of such capacity as will accommodate all persons on board.

7.4.2

Lifejackets of 1.5 times the complement of the barge. Each lifejacket is to be fitted with a whistle and a light powered by a water activated battery. Each person shall be provided with a lifejacket stowed in his accommodation. Additional lifejackets should be stowed at or near the normal embarkation positions, in a suitable dry stowage position unlocked and clearly marked.

7.4.3

At least eight lifebuoys, shall be stowed so that they can be quickly thrown overboard in an emergency. At least half of the lifebuoys shall have self-igniting lights attached and at least one on each side with a buoyant lifeline not less than 27.5metres in length. Also self-activating smoke signal is to be provided to at least two of the lifebuoys attached with self-igniting lights.

7.4.4

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

7.4.5

A Muster List showing special duties to be undertaken by the crew in the event of an emergency shall be allotted to each member of the crew. It shall also specify

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definite signals for calling all the crew to their survival craft, life raft and fire stations and shall give full particulars of those signals. 7.4.6

7.5

All survival craft, life rafts, lifejackets and lifebuoys are to be fitted with retroreflective material.

FIRE FIGHTING EQUIPMENT All barges shall be provided with :-

7.5.1 Fire Pump 7.5.1.1

At least two independently driven fire pumps.

7.5.1.2

If a fire in any one compartment could put all the fire pumps out of action, there must be an alternative means of providing water for fire fighting. This alternative means shall be a fixed pump independently driven which shall be capable of supplying two jets of water.

7.5.2 Fire Main 7.5.2.1

The diameter of the Fire Main pipes shall be sufficient for the effective distribution of the maximum required discharge from two fire pumps operating simultaneously.

7.5.3 Fire Hose 7.5.3.1

The number of Fire Hoses to be provided on deck each complete with couplings and nozzles shall be one for each 30 metres (100 feet) length of the ship and one spare. In no case shall the number be less than five in all on deck. Machinery spaces shall also be provided with Fire Hoses.

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7.5.4 Hydrants 7.5.4.1

The number and position of hydrants shall be such that at least two jets of water not emanating from the same hydrant, one of which shall be from a single length of hose, may reach any part of the barge normally accessible to the crew.

7.5.5 International Shore Connection 7.5.5.1

At least one international shore connection. Facilities shall be available enabling such a connection to be used on either side of the barge.

7.5.6 Portable Fire Extinguisher 7.5.6.1

Sufficient number of portable fire extinguishers to ensure that at least one such extinguisher will be readily available for use in any part of the accommodation or service spaces. The number of such extinguishers shall not be less than five.

7.5.7 Firemen’s Outfits 7.5.7.1

At least two sets, or additional, as per the approved safety plan of Firemen’s Outfits stored so as to be easily accessible and ready for use. The Firemen’s Outfit as a minimum, or as required by the approved safety plan, shall consist of:a) Protective clothing of material to protect the skin from the heat radiating from the fire and from burns and scalding by steam. The outer surface shall be water-resistant. b) Boots and gloves of rubber or other electrically non-conducting material. c) A rigid helmet providing effective protection against impact.

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d) An electrical safety lamp of an approved type with a maximum burning period of three hours. e) An axe. f) A self-contained breathing apparatus of an approved type. g) Fireproof lifeline of sufficient length and strength capable of being attached by means of a snap hook to harness of the apparatus to a separate belt in order to prevent the breathing apparatus becoming detached when the lifeline is operated. h) At least two fire control plans permanently exhibited in all barges for the guidance of the crew. It should consist of General Arrangement Plan showing clearly for each deck the Control Stations, particulars of the Fire Alarms, Detecting System, the Fire Extinguishing Appliances, means of access to different compartments, decks etc.

7.6

PROVISION FOR HELICOPTER FACILITIES

7.6.1 Helicopter Deck 7.6.1.1

In general, the helicopter deck should be designed to receive the largest helicopter intended to use the facility and be of sufficient size to contain a circle of a diameter equal to at least the rotor of such helicopter. The helicopter deck should have an approach/departure sector of at least 180 degree-free of obstructions.

7.6.1.2

The helicopter deck shall :a) Have recessed tie down points for securing a helicopter. b) Have coamings and drainage facilities to prevent the collection of liquids from spreading to or falling on other parts of the barge having regard to the use of fuel. c) Have a non-skid surface.

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d) Be protected by a safety net at least 1.5 metres wide. e) Have both a main and an emergency personnel access route located as far apart from each other as practicable.

7.6.2 Fire Extinguisher 7.6.2.1

For any helicopter deck there should be provided and stored near to the means of access to that deck:a) Dry powder extinguisher of a total capacity of not less than 45 kilograms; b) A suitable foam application system consisting of monitors or foam making branch pipes capable of delivering foam solution; c) Carbon dioxide extinguishers of a total capacity of not less than 18 kilograms or equivalent, one of these extinguishers being so equipped as to enable it to reach the engine area of any helicopter using the deck; and d) At least 2 dual-purpose nozzles and hoses sufficient to reach any part of the helicopter deck.

7.7

OPERATING REQUIREMENTS

7.7.1 Operating Manual 7.7.1.1

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

7.7.1.2

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a) A general description of the unit b) General arrangement plans showing watertight compartments, closures, vents, permanent ballast and allowable deck loadings c) Light ship data and hydrostatic curves or equivalent d) Capacity plan showing the capacity, centre of gravity and free surface correction for each tank e) Stability information setting forth the allowable maximum height of the centre of gravity in relation to draught data or other parameters f) Plans and instructions for the operation of the ballast system g) Schematic diagrams of main and emergency power supplies and electrical installations h) Fire control plan including type and location of fire fighting appliances and escape routes from all compartments i)

Safety provisions including location and operation of life saving appliances and a procedure for evacuation of personnel from the unit

j)

Procedures for anchor handling; and

k) Procedures for adverse weather conditions l)

Procedures for management of waste discharges, inclusive of hydrocarbon and effluent discharges and sewage, garbage, etc. in compliance with all relevant maritime laws and regulations.

7.8

STRUCTURAL FIRE INTEGRITY TABLES The fire integrity of bulkheads and deck should comply with the minimum fire integrity of bulkheads and decks as prescribed in Table 7A and 7B in Appendix 7.

7.8.1

The following requirements should govern application of the tables :-

7.8.1.1

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Table 7A and 7B in Appendix 7 should apply respectively to the bulkheads and decks separating adjacent spaces. ISSUED BY PETROLEUM MANAGEMENT UNIT

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For determining the appropriate fire integrity standards to be applied to divisions between adjacent spaces, such spaces are classified according to their fire risk as shown in Categories [1] to [10] below. The title of each category is intended to be typical rather than restrictive. The number in parenthesis preceding each category refers to the applicable column or row in the tables :1) ‘Control Stations’ 2) ‘Corridors’ 3) ‘Accommodation Spaces’ 4) ‘Stairways’ 5) ‘Service Spaces (low risk)’ 6) ‘Machinery Spaces of Category A’ 7) ‘Other Machinery Spaces’ 8) ‘Hazardous Areas’ 9) ‘Service Spaces (high risk)’ 10) ‘Open Decks’ * Notes :

To be applied to both Tables 7A and 7B in Appendix 7, as appropriate.

a/ Where the space contains an emergency power source or components of an emergency power source that adjoins a space containing a barge’s service generator the boundary bulkhead or deck between those spaces should be an “A-60” class divisions. b/ For clarification as to which note applies see paragraphs 7.8.5.1 and 7.8.5.3 c/ Where spaces are of the same numerical category and superscript (c) appears, a bulkhead or deck of the rating shown in the tables is only SUPERSEDE ISSUE:

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required when the adjacent spaces are for a different purpose, e.g. in category (9). A galley next to a galley does not require a bulkhead but a galley next to a paint room requires an “A-O” bulkhead. d/ Bulkheads separating the navigating bridge chartroom and radio room from each other may be “B-O” rating. *

7.8.1.3

Where an asterisk appears in the tables, the division is required to be of steel or equivalent material but is not required to be of “A” Class standard.

Windows and sidecuttles, with the exception of navigating bridge windows, should be of the non-opening type. Navigating bridge windows may be of the opening type provided the design of such windows would permit rapid closure. PETRONAS may permit windows and sidecuttles outside hazardous areas to be of the opening type.

7.8.1.4

External doors in superstructures and deckhouses shall be constructed to “A-O” Class divisions and be self-closing, where practicable.

7.8.1.5

Protection of accommodation spaces, services spaces and control stations.

7.8.1.5.1

Corridor bulkheads, including doors, should be “A” or “B” Class divisions extending from deck to deck. Where continuous “B” Class ceiling and/or linings are fitted on both sides of the bulkhead, the bulkhead may terminate at the continuous ceiling or lining. Doors of cabins and public spaces in such bulkheads may have a louvre in the lower half of the door. Such openings should not be provided in a door in an “A” or “B” Class division forming a stairway enclosure.

7.8.1.5.2

Stairs should be constructed of steel or other equivalent material.

7.8.1.5.3

Stairways which penetrate only a single deck should be protected at least at one level by “A” or “B” Class divisions and self-closing doors so as to limit the rapid spread of fire from one deck to another. Personnel lift trunks should be protected by “A” Class divisions. Stairways and lift trunks which penetrate more than a single deck should be surrounded by “A” Class

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divisions and protected by self-closing doors at all levels. Self-closing doors should not be fitted with hold-back hooks. However, hold-back arrangements incorporating remote release fittings of the fail-safe type may be utilised. 7.8.1.5.4

Air spaces enclosed behind ceilings, panellings or linings should be divided by close fitting draught stops spaced not more than 14 metres apart.

7.8.1.5.5

Ceilings, linings, bulkheads and insulation except for insulation in refrigerated compartments should be of non- combustible material. Vapour barriers and adhesives used in conjunction with insulation, as well as insulation of pipe fittings for cold service systems need not be noncombustible, but they should be kept to a minimum and their exposed surfaces should have resistance to propagation of flame.

7.8.1.5.6

The framing, including grounds and the joint pieces of bulkheads, linings, ceilings and draught stops should be of non-combustible material.

7.8.1.5.7

All exposed surfaces in corridors and stairway enclosures and surfaces in concealed or inaccessible spaces in accommodation spaces and control stations should have low flame-spread characteristics.

7.8.1.5.8

Bulkheads, linings and ceilings may have combustible veneers provided that the thickness of such veneers should not exceed 2 millimetres within any space other than corridors, stairway enclosures and control stations where the thickness of such veneers should not exceed 1.5 millimetres.

7.8.1.5.9

Primary deck coverings, if applied, should be of approved materials which will not readily ignite.

7.8.1.5.10 Paints, varnishes and other finishes used on exposed interior surfaces should not be of a nature to offer an undue fire hazard and should not be capable of producing excessive quantities of smoke or toxic fumes. 7.8.1.5.11 Ducts provided for ventilation of machinery spaces of Category A and hazardous areas should not pass through accommodation and service SUPERSEDE ISSUE:

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spaces or control stations. However, this requirement may be waived provided that :a) The ducts are constructed of steel and insulated to “A-60” standard; or b) The ducts are constructed of steel and fitted with an automatic fire damper close to the boundary penetrated and insulated to “A-60” standard from the machinery space of Category A to a point at least 5 metres beyond the fire damper. 7.8.1.5.12 Ducts provided for ventilation of accommodation and service spaces or control stations should not pass through machinery spaces of Category A or hazardous areas. However, this may be waived provided that the ducts are constructed of steel and an automatic fire damper is fitted close to the boundaries penetrated.


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SECTION 8 PROCEDURES FOR CRUDE OIL PRODUCTION ALLOWABLES

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SECTION 8

PROCEDURES FOR CRUDE OIL PRODUCTION ALLOWABLES Executive Summary This section provides procedures on long and short term crude oil production approved level process. PETRONAS shall be responsible for establishing the approved production rate of crude oil in each Petroleum Field as provided for in the Production Sharing Contract. In this respect PS Contractor is requested to provide the crude oil production forecast based on the latest reservoir engineering study and approved reservoir management policy consistent with safe operating conditions and a realistic development scheduling taking into considerations the need for efficient and economic exploitation of hydrocarbon resources.

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LONG TERM CRUDE OIL PRODUCTION SUBMISSION BY PS CONTRACTOR

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FORECAST

By October 1st of every Calendar Year, in submitting the annual Work Programme and Budget, PS Contractor shall submit the remaining life cycle of crude oil production potential and availability forecasts and condensate availability forecasts (if applicable) for each petroleum field. The potential and availability production forecasts shall be based on latest reservoir engineering study and approved reservoir management policy (refer to Sec 12), well test requirement (refer to Sec 13), established Inspection & Maintenance Philosophy (refer to Sec 11) consistent with safe operating conditions (refer to Sec 1), and a realistic development scheduling i.e. Field Development Plan or Area Oil Development Plan approval (refer to Sec 3). These production potential and availability forecasts shall be shown as follows:first Calendar Year on monthly and quarterly basis, succeeding four Calendar Years on quarterly basis, remaining Calendar Years on annual basis.

8.2 SHORT TERM APPROVED PRODUCTION LEVEL PETRONAS shall advise PS Contractor on the subsequent quarterly Crude Oil Production approved level of the year prior to the commencement of that quarter. In this respect, PS Contractor is required to submit to PETRONAS in the middle of each quarter, the following information:i.

Average expected production potential and availability by field for each month of the year plus the first quarter of the subsequent year.

ii.

Breakdown

of

expected

production

availability

i.e

base

production,

infill/sidetracking, workover, well services and debottlenecking for each month of the year plus the first quarter of the subsequent year.

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iii.

Monthly gas production, utilisation and flaring/venting for each month of the year plus the first quarter of the subsequent year.

iv.

Where applicable the average monthly condensate production for each month of the year plus the first quarter of the subsequent year.

v.

The update of the year major planned shutdowns and its barrels deferred for each month of the year plus the first quarter of the subsequent year.

For item i – iv, please refer to Appendix 8 for reference. PS Contractor shall also submit brief explanation (in presentation format), information including but not limited to the following: basis/assumption used to derive the crude production forecast. reasons for variance of actual versus production approved level. unplanned shutdown and its barrels impact. issues and mitigation/production enhancement plan. PETRONAS may request for a meeting with PS Contractor for clarification. Towards achieving the said quarterly approved production PS Contractor shall update and propose relevant monthly production levels at the monthly crude oil lifting/programming meeting. The monthly target production shall be in line with the quarterly approved production and PETRONAS will decide the monthly target which shall then be implemented by PS Contractor.

8.3

PRODUCTION VARIATION PS Contractor must first take all possible steps to comply with the quarterly and annual approved levels with minimal production fluctuation. However, to cater for unexpected operational requirements, PS Contractor must take all efforts to make-up the deferred production i.e. through production enhancement initiatives, etc. In the event that there is over or under production, PS Contractor shall then make-up the over or under production in the next succeeding quarter. The make-up or cut back

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production shall be agreed by PETRONAS. In any event, over-production or underproduction shall be minimized towards achieving the annual approved level by year end. For field that fall under the National Depletion Policy (NDP), the production shall be governed by the latest NDP guidelines. The NDP states that any major fields which are having total Oil Initially Inplace (OIIP) equal to or more than 400 MMstb, the production will be limited to a ceiling of 3.0% of OIIP in any one year.

-END OF SECTION 8-

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SECTION 9 PROCEDURES FOR GAS PRODUCTION & FLARING/VENTING LIMIT Executive Summary This section provides procedures on non-associated and associated gas disposal and approval processes on flaring/venting of the gas. PS Contractor shall seek PETRONAS'approval for flaring or venting of non-associated and associated gas from any Petroleum Field. In this respect PS Contractor is requested to provide the non-associated and associated gas forecast based on the latest reservoir engineering study and approved reservoir management policy consistent with safe operating conditions and a realistic development scheduling taking into considerations the need for efficient and economic exploitation of hydrocarbon resources.

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9.1

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LONG TERM NON-ASSOCIATED GAS PRODUCTION FORECAST SUBMISSION BY PS CONTRACTOR By October 1st of every Calendar Year, in submitting the annual Work Programme and Budget, PS Contractor shall submit the remaining life cycle of gas production and disposition forecast based on supply capacity (availability) including the condensate forecast for each non-associated gas field. These production potential and availability forecasts shall be shown as follows:first Calendar Year on monthly and quarterly basis, succeeding four Calendar Years on quarterly basis, remaining Calendar Years on annual basis. PS Contractor shall not produce non-associated gas, other than for the purpose of gas sales and gas related operational requirements, without prior approval of PETRONAS.

9.2

LONG TERM ASSOCIATED GAS PRODUCTION FORECAST SUBMISSION BY PS CONTRACTOR By October 1st of every Calendar Year, in submitting the annual Work Programme and Budget, PS Contractor shall submit the remaining life cycle of associated gas production availability forecasts for each petroleum field. Such forecast shall be consistent and in accordance with the considerations as stipulated in Section 8.1 of Procedures For Crude Oil Production Allowable.

9.3

SHORT TERM NON-ASSOCIATED AND ASSOCIATED GAS PRODUCTION PETRONAS shall advise its gas customers on the latest gas supply outlook on quarterly basis. In this respect, PS Contractor is required to submit to PETRONAS in middle quarter, following information:i.

Average expected gas supply capacity outlook by field for each month of the year plus the first quarter of the subsequent year.

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ii.

Breakdown of expected production capacity i.e base production, infill/sidetracking, workover, well services and debottlenecking for each month of the year plus the first quarter of the subsequent year.

iii.

Monthly gas production, utilisation and flaring/venting for each month of the year plus the first quarter of the subsequent year.

iv.

Where applicable the average monthly condensate production for each month of the year plus the first quarter of the subsequent year.

v.

Update of the year major planned shutdowns for each month of the year plus the first quarter of the subsequent year.

For item i – iv, please refer to Appendix 8 for reference. PS Contractor shall also submit brief explanation (in presentation format), information including but not limited to the following: basis/assumption used to derive the gas capacity forecast. reasons for variance of actual and forecast versus WP&B and/or Overall Area Development Plan (OADP) gas supply capacity forecast. unplanned shutdown and its volume impact. issues and mitigation/production enhancement plan. PETRONAS may request for a meeting with PS Contractor for clarification. PS Contractor must first take all possible steps to comply with the WP&B and/or Overall Area Development Plan (OADP) gas supply capacity forecast with minimal production fluctuation. However, to cater for unexpected operational requirements, PS Contractor must take all efforts to mitigate the shortfall i.e. through production enhancement initiatives etc.

9.4 GAS FLARING / VENTING 9.4.1 Non-associated gas Non-associated gas shall NOT be flared or vented without prior approval of PETRONAS, except as provided herein:SUPERSEDE ISSUE:

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a) when gas is released from condensate stabilization units and the utilization of such gas cannot be economically justified; b) during cleaning up of a well and well evaluation tests not exceeding a continuous testing period of 48 hours; c) when gas is released during emergencies, or as part of normal production operations; and d) during regular schedule facilities maintenance and inspection of gas related equipment not exceeding 1 week e) during commissioning of gas related equipment not exceeding 2 weeks.

9.4.2 Associated gas PS Contractor shall seek PETRONAS'approval for flaring or venting of associated gas from any Petroleum Field. In this respect, PS Contractor shall submit the corresponding associated gas production and utilisation forecast based on crude oil availability forecast and shall provide justification for the flaring or venting level. The forecast shall be submitted together during the 1st Quarter crude oil production forecast submission. PETRONAS shall convey the annual flaring/venting limit of associated gas from any Petroleum Field for PS Contractor to comply. Associated gas shall not be flared or vented without prior approval of PETRONAS, except as provided herein:a) when gas vapours are released from storage vessel including tanks, specifically surge tanks and Free Water Knock-out Vessels, and if such gas vapours cannot be economically utilised; b) during temporary equipment failure, e.g. compressor but not exceeding 72 hours; c) during cleaning up of a well, production test or any other well evaluation tests not exceeding a continuous period of 48 hours; SUPERSEDE ISSUE:

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d) when regular scheduled preventive maintenance, inspections and testing are conducted; e) when gas is released during emergencies, e.g. emergency shutdowns, blanketing or pressure relief operations, or as part of normal production operations (e.g. instrument gas); and f) during commissioning of gas related equipment not exceeding 2 weeks.

9.5 FLARING/VENTING PERMIT In the event that flaring/venting exceeds the specific period as stipulated in Sections 9.4.1 and 9.4.2, PS Contractor shall seek flaring/venting permit from PETRONAS Regional Office. PS Contractor must comply with the flaring or venting limit set for the year. In line with PETRONAS’ ‘towards zero flaring’ policy PS Contractor must take all steps to minimise the flaring or venting.


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SECTION 10 GUIDELINES FOR ONSHORE/OFFSHORE OPERATIONS Executive Summary This section provides the basic guidelines on the operations of offshore and onshore facilities, inclusive of Floating Production & Storage Offloading (FPSOs)/ Floating Storage Offloading (FSOs)/Mobile Operating Drilling Units (MODUs)/Work Barge/Platforms/onshore Crude Oil, Condensate and Gas Terminals and other locations, such as supply bases and warehouses, notwithstanding all other associated facilities and equipment therein, e.g., accommodation barge, pipelines, export facilities, pumps and compressors, etc. PS Contractor shall operate these offshore and onshore facilities, structures and pipelines safely, in accordance with best industry practices and in compliance with PETRONAS HSE and regulatory requirements as well as the applicable Malaysian laws. PS Contractor is required to develop, update and maintain the operating manuals, operating procedures, shutdown programmes, as-built drawings for all the offshore and onshore facilities. PS Contractor shall also ensure the operations and activities undertaken by its contractor(s) at all locations and work sites are in line with the PS Contractor’s operating philosophies and HSE policies.

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10.1 NOTICE OF INTENT PS Contractor shall submit a notice of intent to PETRONAS, advising at least thirty (30) days before commencement of operations for any newly constructed offshore and onshore facilities, structures and pipelines. However, PS Contractor shall advise PETRONAS should there be any changes to the commencement date immediately. The commencement of operations shall refer to the introduction of first hydrocarbon through the systems, i.e., the production phase.

10.2 OPERATIONS MANUAL PS Contractor shall prepare an operation manual consisting of starting, operating and shutdown procedures which shall outline preventive measures and systems checks required to ensure proper functioning of all shutdown, control and alarm system for production facilities. PS Contractor shall provide a copy of the operation manual to PETRONAS when requested.

10.3 SIMULTANEOUS OPERATIONS PROCEDURES PS Contractor shall prepare and update a general operating procedure for conducting activities simultaneously with production operations, which could increase the possibility of occurrence of undesirable events such as harm to personnel and / or environment or damage to properties. The general operating procedures shall include but not limited to a detailed description of operations and procedures for mitigation of potential undesirable events. Activities requiring the simultaneous operations procedures shall among others cover drilling, rig workover, diving and major construction operations and maintenance activities. PS Contractor shall prepare specific / dedicated simultaneous operations procedures for each activity and location prior to execution.

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

10.4 SHUTDOWN 10.4.1 Annual Shutdown Plan PS Contractor shall advise PETRONAS KL and PMU Regional Office of the annual shutdown plan, as per its original Work Programme & Budget submission, stating the reasons for and the duration of the shutdowns and shall update PETRONAS KL and PMU Regional Office on quarterly basis, as specified in Section 8: Procedures for Crude Oil Production Allowable.

10.4.2 Unplanned Shutdown PS Contractor shall notify PETRONAS PMU Regional Office promptly of any major unplanned crude oil production shutdown. Major unplanned crude oil production shutdown shall refer to any shutdown events which are not planned in the PS Contractor’s original Work Programme & Budget submission, and which may impact the agreed tanker lifting programme, and as well as the monthly crude oil production target for the specific PS Contract area. PS Contractor shall also notify PETRONAS PMU Regional Office promptly of any shutdown of its crude oil/condensate/gas terminals and/or export facilities, either due to weather or technical integrity concerns of its associated equipment, such as, loading hoses, SALM/SBM, export pumps, etc. which warrant the said facilities being unavailable or unsafe for any loading operations to be performed. PS Contractor shall notify PETRONAS PMU Regional Office promptly of any unplanned gas production shutdown events which are not planned in the PS Contractor’s original Work Programme & Budget submission, and which has an impact on downstream gas customers. The prompt notification of the above shall be made within 24 hours through telephone calls and to be followed in writing via e-mails or telefax, stating at least the description of failure/reason(s) of shutdown, volume shortfalls, impact on flaring or re-injection (where applicable), actions taken and estimated time for normalization. This is in SUPERSEDE ISSUE:

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addition to the normal PS Contractor’s reporting via the daily production operations report as described in sub-section 10.6.

10.5 AS-BUILT DRAWINGS PS Contractor shall revise all as-built drawings for facilities, structures and pipelines whenever significant modifications are carried out to ensure that the as-built drawings are as per current status. The said drawings shall be made available to PETRONAS when requested. PS Contractor shall make available all latest as-built drawings for hand-over to PETRONAS prior to field relinquishment as required under Production Sharing Contract. PS Contractor shall also submit to PETRONAS as-built drawings for all new projects.

10.6 DAILY PRODUCTION OPERATIONS REPORT PS Contractor shall submit or make accessible to PETRONAS PMU Regional Office the daily operations report, including crude, associated and non-associated gas production per platform and field, crude sales and stocks, flaring, gas sales and condensate production and sales, if applicable, and reasons for any abnormalities in the performance, such as, production shortfalls and/or excessive gas flaring. The submission can be made via electronic mailing system. PS Contractor shall also ensure that daily operations log is maintained and updated to record significant daily operational activities at all work locations.

10.7 QUARTERLY PRODUCTION OPERATIONS REPORT PS Contractor shall submit to PETRONAS quarterly production operations report including crude, associated and non-associated gas production per platform and field, gas flaring per platform and field, including at other facilities such as crude oil terminals, crude sales and stocks, flaring, gas sales and condensate production and sales, if applicable.

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10.8 TERMINAL OPERATIONS In addition to the above, the Terminal Operations, inclusive of both the onshore and offshore crude oil/condensate and gas terminals, i.e., receiving, processing, stabilization, storage, offloading and export/transfer facilities, shall comply with the following requirements, namely :•

PETRONAS’ Measurement & Allocation Procedures that consist of the hydrocarbon inventory, loading, metering, validation, custody transfer and accounting procedures;

•

PETRONAS’ HSE requirements;

•

PETRONAS’ Emergency Communication / Notifications Procedures; and

•

PETRONAS’ Marine Safety Practices;

•

Malaysian Statutory requirements or any international instruments to which Malaysia is a signatory and/or a party. versus upstream procedures by PETRONAS and PS Contractor’s own operations requirements).

10.9 INSPECTION & OPERATIONS AUDIT PETRONAS reserves the right to conduct any operations inspection or audit at PS Contractor’s and/or its contractor’s operational locations, whenever and wherever necessary. This may be conducted either as a separate exercise or together with the HSE, facilities and/or other activities inspection and audit.


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SECTION 11 GUIDELINES FOR FACILITIES RELIABILITY & INTEGRITY MANAGEMENT Executive Summary This section provides a structured framework for managing reliability and integrity aspects of PS Contractor’s production facilities. The objective of the document is to establish, sustain and assure the reliability and integrity of facilities throughout their lifecycle. All management systems, standards, procedures and practices developed by PS Contractor shall comply and be consistent with the requirements stipulated in this section. The requirements contained in this document shall be applicable to both PS Contractor-operated and lease facilities.

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Definitions “Facilities” is defined as infrastructures concerned with the production and processing of hydrocarbons and should be read to include wells, structures, sub-structures, pipelines and sub-sea systems.

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

“Reliability” is defined as the ability of the asset to perform the required function(s) under specified operating conditions for a stated period of time.

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11.1 INTRODUCTION Safe and efficient operations of facilities are essential to both PS Contractor’s and PETRONAS’ business and HSE performance. Apart from enabling achievement of the desired quantity (production target) and quality of produced hydrocarbon, assured facilities integrity and reliability preclude any undesirable HSE impacts resulting from functional failures of facilities. All facilities are to perform their functions as intended and when facilities performance falls below intended level, effective corrective actions need to be promptly implemented.

11.2 FULL LIFE CYCLE MANAGEMENT In managing reliability and integrity of facilities, PS Contractor shall adopt the full life cycle management concept encompassing all phases in facilities life cycle - from conceptualization to decommissioning. In the field development phase, reliability and integrity shall be incorporated into FDP and design of facilities. During construction, installation and commissioning of facilities, reliability and integrity are to be addressed as part of assurance program for development projects. Throughout the production phase, reliability and integrity shall be sustained and safeguarded through prudent operations and proper inspection and maintenance of facilities. Due considerations shall also be given to reliability and integrity of facilities prior to field relinquishment to PETRONAS. PS Contractor shall ensure that integrity of facilities is in the state that enables safe and reliable continued operations after the handover. Throughout the lifecycle of facilities, the risks associated with their operations are to be reduced based on the As Low as Reasonably Practicable (ALARP) principle.

11.3 MANAGEMENT SYSTEM Management of facilities reliability and integrity shall be strongly inter-related with HSE and quality management. To provide a structured framework for effective management of facilities, PS Contractor shall incorporate key elements of facilities reliability and integrity management into its management system(s). SUPERSEDE ISSUE:

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The elements shall include, as a minimum, the following: •

Leadership and Commitment PS Contractor’s management shall demonstrate visible leadership and commitment by placing high priority and playing active roles in activities related to facilities reliability and integrity. Apart from allocating necessary financial and human resources, the management shall put in place mechanism to measure and monitor performance related to facilities reliability and integrity. In addition, PS Contractor’s management shall inspire, motivate and empower the employees to deliver target performance relating to facilities reliability and integrity and take accountability of facilities reliability and integrity impact to business performance.

•

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

•

Organization, Roles and Responsibilities PS Contractor shall establish a functional structure and allocate resources to reflect reliability and integrity management is a line responsibility. The roles, responsibilities and accountabilities of relevant personnel shall be clearly defined. PS Contractor shall institute communication means to disseminate information on facilities reliability and integrity management across its organization,

•

Reliability and Integrity Management Processes PS Contractor shall identify and clearly define methodologies to assure reliability and integrity of facilities. As a minimum, the methodologies shall include the following: •

risk assessment to estimate the magnitude and decide the tolerability of risks

•

risk and reliability management to determine facilities maintenance requirements

•

criticality assessment to determine relative importance of equipment to overall facilities operations

•

incident investigation and failure analysis

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•

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•

bad actor management to identify and rank issues relating to facilities reliability and integrity and work towards elimination of the problems

•

remnant life assessment to ensure safe operation of critical equipment and those nearing end of design life

•

assessment of operational performance, process effectiveness and personnel competencies

Improvement Plan and Implementation PS Contractor shall review and assess its facilities reliability and integrity performance to identify areas that need improvement. Corrective or improvement efforts shall be prioritized based on criticality and risks.

•

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

•

Management Review PS Contractor’s management shall review performance and remedial plans related to facilities reliability and integrity. Improvement objectives and targets shall incorporate PETRONAS’ aspirations and requirements. Apart from assuring performance, the review shall assess to establish optimal use of resources, competency of personnel or contractor and application of appropriate existing and new technology. Following the review, appropriate improvement measures are to be implemented accordingly.

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

11.4 OPERATIONS OF FACILITIES PS Contractor shall prudently ensure safe, reliable and efficient operation of facilities. Procedures and work instructions for both routine and non-routine activities are to be developed and adhered to during operations. PS Contractor shall employ adequate number of competent personnel for its production operations. The operating procedures

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and others relevant technical instructions including drawings and equipment dossier shall be made accessible on locations and updated, when necessary. The operating limits as defined during design of facilities are to be monitored during operations so as to ensure the design intents are met. Should the operating limits deviate from the design basis, PS Contractor is to undertake necessary corrective measures to ensure safety, reliability and efficiency of facilities operations. In addition PS Contractor shall monitor the quality of produced hydrocarbon and effluent to ensure there is no presence of elements which will be detrimental to integrity and reliability of facilities.

11.5 INSPECTION AND MAINTENANCE Inspection and maintenance shall be integral and essential parts of PS Contractor’s overall production operations. The activities ensure functional fitness of all facilities. PS Contractor shall ensure that the activities are undertaken effectively to realize the desired performance of facilities. 11.5.1 Compliance to Legislative Requirements All inspection and maintenance activities undertaken by PS Contractor shall be, as a minimum, in full compliance to relevant legislations. 11.5.2 Philosophy and Related Documents PS Contractor shall develop and establish its own inspection and maintenance philosophy outlining the objectives, policies and principles governing inspection and maintenance of facilities. In addition, the document shall include strategies to address or mitigate potential threats to reliability and integrity of facilities. Cost effectiveness, as much as possible, should be a primary consideration. As deemed necessary by changes in legislations, revision in company standards, assessment of maintenance effectiveness, advances in technology or enhancement in industry best practices, PS Contractor shall review and update its system and all documents related to inspection and maintenance of facilities.

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PS Contractor shall submit one (1) copy of documents related to facilities reliability and integrity management, including those for inspection and maintenance to PETRONAS. Should there be any revision to any of the documents, PS Contractor is to provide PETRONAS with the updated revision within 6 months of such change. 11.5.3 Minimum Requirements for Inspection & Maintenance 11.5.3.1

Topsides / Onshore Terminals Mechanical Static Equipment Mechanical static equipment includes pressure vessels, piping, boilers, heat exchangers, launchers & receivers, tanks, etc. PS Contractor shall establish appropriate corrosion management program including chemical applications, microbiological monitoring and appropriate analysis to ensure sustained integrity of static equipment. A baseline survey, before equipment is put into service, shall be conducted to obtain reference which future surveys will be compared against. Periodic inspection consisting of both external visual checks for coating degradation and assessment of internal corrosion and/or erosion through wall thickness measurement shall be the basis for condition-based maintenance of the equipment. For pressure vessels that cannot be internally inspected, suitable alternative method shall be used. Appropriate technique shall be employed to perform Corrosion Under Insulation (CUI) and heat exchanger tubes inspection. PS Contractor may adopt a risk-based methodology for inspection of static equipment in lieu of the time-based approach. However, the risk-based methodology selected by PS Contractor must be able to reduce the

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associated residual risks to an acceptable level to ensure safe operations of equipment. The maintenance or replacement of the equipment shall be determined based on the inspection findings. Major Rotating Equipment Major rotating equipment includes gas turbines, internal combustion engines (gas & diesel), gas compressors (reciprocating & centrifugal) and pumps. PS Contractor, as much as possible, shall adopt risk and reliability management methodology to determine the appropriate inspection and maintenance strategies, tasks and intervals. Planned preventive maintenance shall be performed based on OEM recommendations and if applicable, improved practices acquired through PS Contractor’s operational experience. PS Contractors, whenever feasible, shall periodically or continuously conduct condition monitoring to establish basis for predictive or condition-based maintenance of equipment. The condition monitoring shall include vibration and temperature monitoring, operating parameters trending, lube oil analysis and boroscope inspection. Functional test to address dormant failures shall be conducted on a defined frequency for emergency (e.g. firewater pumps, emergency diesel generator etc.) and standby equipment as well as machinery safeguarding / protective system. Major inspection and overhaul shall be performed based on the combination of OEM recommendations and condition monitoring data taking into considerations the operating parameters and mode of operation.

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Safeguarding Devices and Systems The devices and systems are safety-critical items which detect abnormal conditions, perform logical processing and initiate necessary executive actions per defined Cause and Effect Matrix to ensure the facilities are brought to a safe state. Such devices and systems include instrumentations (sensors, transmitters, switches, pilot etc.), detectors, initiating devices (breakglasses, pushbuttons, kill knobs, fusible plugs etc.), fire and gas systems, shutdown systems, HIPPS, shutdown & blowdown valves and pressure relief devices (relief valves, rupture discs etc.). PS Contractors shall conduct periodic functional test of all safety-critical / protective devices and systems at a defined frequency to address dormant failures within devices and systems. The testing shall establish that the Cause & Effect Matrix implemented in the systems remains correct and intact / unchanged. Pressure relief devices shall be subjected to periodic nondestructive functional test. However, impact to production resulting from such testing needs to be taken into considerations and minimized. Where possible, PS Contractor shall employ technologies and practices that allow on-line testing of devices and systems. Shutdown & blowdown valves and pressure relief valves (where applicable) shall be inspected for leakage, damage and corrosion. Fire Fighting and Life Saving Equipment PS Contractors shall conduct periodic inspection and functional test of all fire fighting (fire water pumps, monitors, deluge, sprinklers, portable extinguishers

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etc.) and life saving equipment (lifeboat, life raft, escape capsule etc.) to ensure functionality during emergency situations. 11.5.3.2

Structures PS Contractor shall conduct baseline survey to include visual inspection of the entire structure (including appurtenances) and NDT on selected structural members and nodes. In addition, PS Contractor is to develop and implement a periodic survey program to cover structural members at above MSL, splash zone and below MSL area. The survey shall assess if there is any damage, anomaly, corrosion, marine growth, debris or coating deterioration. Visual inspection, NDT and CP reading shall be part of the periodic survey program. PS Contractor may adopt a risk-based methodology for inspection of structures in lieu of the time-based approach. However, the risk-based methodology selected by PS Contractor must be able to reduce the residual risks associated with the structures to an acceptable level. The maintenance requirements which may involve touch-up painting, major repainting, repair or replacement of structural members and cleaning of marine growth are to be condition-based as necessitated by findings during the survey.

11.5.3.3

Pipelines Pipelines include subsea pipelines, risers, onshore (buried & above ground) pipelines and associated facilities. PS Contractor shall develop and implement appropriate corrosion management program to sustain integrity of pipelines. Wherever applicable,

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the corrosion management program shall include chemical inhibition, dissolved gas analysis, microbiological monitoring and cathodic protection. All pipelines, except for those of maintenance-free type e.g. CRA, shall be equipped with facilities for internal cleaning through pigging. Frequency of pigging shall be determined based on both technical and operational considerations. Cleaning pigs shall be properly selected to ensure effectiveness of pigging in maintaining efficiency of fluid transport and mitigating corrosion in the pipeline. PS Contractor shall conduct baseline survey for pipeline internal and external within the first two (2) years of service. At a frequency defined by PS Contractor, pipelines, risers and appurtenances shall be externally inspected. As a minimum, all pipelines transporting process fluid from wells (FWS) and hydrocarbon export line (inter-field pipeline or trunkline to shore) transporting processed / stabilized medium for sales shall be able to be internally inspected using intelligent pigging tools with capability to detect both internal and external defects. Rectification of items identified during survey / inspection of pipelines and risers shall be promptly taken by PS Contractor to avoid failures. PS Contractor may adopt risk-based methodology for inspection of pipelines in lieu of the time-based approach. However, the RBI methodology selected by PS Contractor must be able to reduce the associated residual risks to an acceptable level to ensure safe operations of the pipeline. To mitigate environmental impacts due to pipeline failure, PS Contractors operating trunk lines, subject to feasibility, are to install early leak detection system.

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SECTION 11 GUIDELINES FOR FACILITIES RELIABILITY & INTEGRITY MANAGEMENT 11.5.3.4

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Wellhead and Downhole System PS Contractor shall establish and implement a system to comprehensively manage well integrity. The inspection program for wellheads and Christmas trees (including assemblies) shall include visual check for physical damage, corrosion and leaks. Christmas tree valves shall be subjected to leak and functional test at a frequency to be determined by PS Contractor. PS Contractor shall monitor corrosion and erosion in downhole system, particularly production tubings using appropriate means. Functionality of all SCSSSV and wellhead valves is to be assured through regular testing. To establish integrity of downhole system, PS Contractor shall also perform bleed down and monitoring of annulus pressure build up. Monitoring of sand production from wells shall also form part of inspection program for downhole system. Preventive maintenance for wellheads and Christmas tree (including assemblies) shall include regular greasing / lubricating of and injection of sealing compound into valves. Depending on functional test results, SCSSSV may need a change-out or servicing.

11.5.3.5

Subsea Systems The entire subsea production system shall be ideally designed to be maintenance-free. All valves, fitting and connectors shall be maintenance-free units for the whole design life. Based on manufacturer’s recommendations, PS Contractor shall also develop and implement inspection program for subsea systems using appropriate methods (ROV, ROT and/or diver.) Due to high cost of intervention, particularly for deepwater facilities, subsea systems shall, as much as possible, be designed for no scheduled / preventive maintenance.

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11.5.4 Planning and Implementation To ensure effectiveness in terms of both performance and cost, PS Contractor shall properly plan and schedule its inspection and maintenance program. Appropriate computerized management system is to be employed by PS Contractor for planning and scheduling of activities. All inspection and maintenance activities resulting in partial or total production impact shall be clearly stated in WP & B. Timely and consistent execution is essential in ensuring effectiveness of planned inspection and maintenance activities. PS Contractor shall endeavor to fully comply with its inspection and maintenance plan. Deviations from the plan shall be managed systematically. To minimize production impact, PS Contractor shall maximize opportunistic maintenance by capitalizing on any facilities shutdown. As in any other activities related to production operations, full compliance to HSE requirements during inspection and maintenance activities is non-negotiable and supersedes economic considerations. 11.5.5 Materials Management Whilst PS Contractor must avoid wastage due to incorrect and excessive inventory in the warehouse, it is critical that correct spare parts, tools and consumables for inspection and maintenance activities be made available in a timely manner. Stock inventory shall be determined based on criticality and failure rates of equipment and lead-time for spare parts. The materials management system should be integrated with the maintenance management system employing appropriate computer system. 11.5.6 Contracting and Contractor Management In the event of insufficient in-house resources or capability or due to specialized nature of certain works or purely for cost effectiveness reasons, PS Contractor may contract SUPERSEDE ISSUE:

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out inspection and maintenance works. However, PS Contractor shall ensure that all contractors are technically competent to perform the works. All tendering and contracting shall be undertaken in full compliance to PETRONAS procurement procedures. PS Contractor shall be responsible to manage cost, schedule and quality aspects of the works whilst ensuring strict adherence to HSE requirements by contractors employed for inspection and maintenance of facilities. 11.5.7 Reporting and Key Performance Indicator (KPI) PS Contractor shall measure and report to PETRONAS compliance and effectiveness of reliability and integrity using KPI listed in Appendix 11.

11.6 MAJOR FAILURES AND CORRECTIVE ACTIONS PS Contractor shall inform PETRONAS of any findings that could potentially lead to HSE issues, major failure of facility and production reliability. PS Contractor shall promptly report to PETRONAS all major facilities failures as described in Section 10. To minimize production impact, PS Contractor shall immediately take necessary corrective action(s) to safely resume production at desired level and work out long term measure(s) to prevent recurrence.

11.7 MANAGEMENT OF CHANGE PS contractor shall develop and maintain a system to properly manage permanent and temporary changes and deviations including those of physical or functional aspects of facilities, operating procedures and inspection and maintenance plan that may impact reliability and integrity of facilities. The principal elements of the change control system shall include, but not limited to, definition, justification, technical review, risk assessment approving authority and documentation. PS Contractor shall periodically review the list and status of changes and institute necessary measures to counteract any adverse effects. Care must be taken, SUPERSEDE ISSUE:

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however, to ensure that the system does not degenerate such that expediency takes precedence over thorough review.

11.8 INFORMATION AND KNOWLEDGE MANAGEMENT All data, information, documents and technical drawings of facilities are to be properly maintained and updated. Data on reliability and integrity of facilities are to be properly collected, validated, processed, analyzed and documented. PS Contractor shall maintain proper and auditable record of inspection and maintenance activities. History of failures, root cause(s) and remedial actions are to be properly documented. Documents containing information on reliability and integrity of facilities are to be systematically managed by having in place a document management system. For ease of storage and longevity of documents electronic copies are preferred over hard copies. Lessons learned and best practices are to be captured, documented and disseminated in a systematic manner. If deemed beneficial, PETRONAS may request PS Contractor to share lessons learned with others.

11.9 PRESERVATION In the event that any facilities need to be put out of service, partially or totally, for a period exceeding three (3) months, PS Contractor shall develop the procedure(s) to properly and cost effectively preserve the facilities or part of facilities throughout the duration in accordance with equipment manufacturer’s recommendations or good industry practices.

11.10 FACILITIES MODIFICATION, UPGRADING OR REJUVENATION Modification, upgrading or rejuvenation of facilities may be necessary due to the following reasons: To enhance processing capacity (excluding requirements for new reserve development) To sustain/improve integrity or reliability To address obsolescence of system or its component(s) To suit changed operating envelope SUPERSEDE ISSUE:

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To improve quality of processed hydrocarbon To ensure effluent meet environmental regulatory specifications If the total estimated value of the project exceeds the threshold limit of RM10 million or if the project is deemed critical by PETRONAS, PS Contractor shall submit for PETRONAS’ approval the Facilities Improvement Plan (FIP) / Facilities Rejuvenation Plan (FRP) prior to undertaking the project. The FIP/FRP approval process shall adopt the FDP review and approval processes as described in Section 3. In addition, the FIP should combine key activities as prescribed for Milestone Review 1 (MR#1) and Milestone Review 4 (MR#4). The document shall contain the following information: •

Objectives

•

Project Definition

•

Scope Of Work

•

Operations & Maintenance Philosophy

•

Cost & Economics

•

Schedule

•

Project Organization

•

Contracting Strategy

•

Technology

•

HSE

•

Quality Management

In the event of any change as described in Appendix 12, PS Contractor is to submit a revision of the FIP/FRP. During the project implementation, PS Contractor shall furnish PETRONAS with monthly progress report highlighting the progress, achievements, look ahead plan, and issues of the project.

-END OF SECTION 11-

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SECTION 12 GUIDELINES FOR RESERVOIR MANAGEMENT Executive Summary This section provides the basic framework of reservoir management guidelines for PS Contractor:a)

on continuous reservoir data acquisition, the monitoring and analysis of reservoir performance with reasonable accuracy and as appropriate through the field life cycle; and

b)

to carry out periodic Full Field Reviews and other studies for further development for ongoing reserves and production optimisation.

c)

on maintaining/keeping accurate records of all reservoir related data for submission in accordance to Section 17. An accurate welltest, other reservoir & production related data must be obtained in accordance to other relevant sections.

The objective is to promote optimum field development by economically optimizing hydrocarbon recovery and maintain optimal field performance. For the purpose of this section, “reservoir” may also include reference to compartment where the unit is being managed.

fault block or

Other sections to be referred together with this section are ; Section 4- Guidelines for Project Development Management Section 5- Procedures for Drilling Operations Section 8 - Procedures for Crude Oil Production Allowables Section 9- Procedures for Gas Production & Flaring/Venting Limit Appendix 12 - List of Well Proposal Requiring PETRONAS Approval Section 13 - Procedures for Well Test, Production Measurement & Allocation Section 14- Dynamic Liquid Hydrocarbon Measurement Section 17 - Data Submission Requirement SUPERSEDE ISSUE:

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12.1 PREAMBLE The PS contractor shall operate in a manner that is consistent with sound reservoir management principles at all stages of the reservoir’s life cycle.

12.1.1 Reservoir Management In the context of these guidelines reservoir management is defined as: An ever-changing and ongoing process which must be conducted at all stages of the life cycle of a petroleum reservoir system from discovery to abandonment to ensure optimum development and depletion of the reservoirs. It must be a multidisciplinary process aimed at cost effectively enhancing the knowledge and understanding of the reservoir system and translating the enhanced understanding into operational plans for ongoing development to optimise production and reserves. The reservoir system includes any associated aquifer, gas cap, wells and surface facilities.

12.1.2 Full Field Reviews Full Field Reviews (FFR) are a comprehensive multi-disciplinary re-evaluation of all basic reservoir characterisation data, dynamic reservoir and well performance data as well as relevant surface facilities considerations pertaining to an oil or gas field. These re-evaluations must use the most relevant current interpretation techniques to maximise knowledge distillation from the data. Such re-evaluations include (but not limited to) seismic reprocessing, sequence stratigraphic correlations, petrophysical reevaluation, re-evaluation of reservoir and fluid properties and fit for purpose 3-D static and dynamic reservoir modelling. Full Field Reviews must examine interfaces and mutual optimisation of the reservoirs, wells and the surface facilities, and seek production and reserves optimisation opportunities including (but not limited to) examining the potential for:

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1.

Workovers

2.

Infill drilling ISSUED BY PETROLEUM MANAGEMENT UNIT

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3.

Artificial lift

4.

Secondary recovery

5.

Enhanced/improved recovery

6.

Surface facilities debottlenecking and optimisation

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

12.2 EARLY DEPLETION STAGE PS Contractor shall operate in a manner that is consistent with the optimum reservoir management strategy of the field as approved in the field Field Development Plan (FDP), regarded to be pre-development FFR. PS Contractor shall ensure that prudent reservoir management policies/strategies are being implemented. The reservoir management strategy may need to be revised or modified in light of the new data being acquired during the initial development stage. Depending upon the variations of the new data from the FDP data, a revised Full Field Review may be required. During the course of production operations PS Contractor shall maintain database of production, pressure, reservoir performance and reservoir geological description data. With the new data, PS Contractor shall update models and/or performance forecast, when necessary. PS Contractor shall submit a proposal for PETRONAS review and approval if reservoir performance and other data show that a different reservoir management strategy than that approved in the FDP is required for optimum reservoir management. Prior to submitting the proposal for PETRONAS approval, PS Contractor shall have technical review upfront with PETRONAS. Due to uncertain drive mechanism any Gas-Oil-Ratio (GOR) controls, where appropriate and in accordance with prudent reservoir management practices, shall be addressed in the approved FDP. If significant uncertainty exist in the reservoir drive mechanism, the FDPs SUPERSEDE ISSUE:

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should have multiple scenarios covering the potential range of reservoir drive mechanisms and reservoir descriptions, and consequently the range of anticipated reservoir behavior. However, if no reservoir studies have been conducted, the reservoir GOR shall be limited to 1.5 x Rsi during the initial production stage. This is to ensure that there is no adverse impact to oil recovery and to allow sufficient time on data gathering to understand the reservoir behaviour. Nevertheless, PS Contractor may propose for PETRONAS approval the revision of GOR limit with technical justification and in accordance with good industry practices. The reservoir depletion shall not exceed 15% of developed EUR per year. Any depletion rate exceeding 15% need to be supported by reservoir studies and approved by PETRONAS Some fields may be subjected to National Depletion Policy (NDP) policy. Please refer to Procedures for crude oil production allowable Section 8.3 PS Contractor shall take actions to improve well deliverability/injectivity as deemed necessary. PS Contractor may carry out workovers and/or other well work activities and artificial lift programs which require submission of proposals for PETRONAS approval (refer to Appendix 12 for documentation and approval requirements). PS Contractor shall present to PETRONAS the field performance/surveillance, in the annual Field Reservoir Management Review (FRMR). The timing for the annual review and the package submission deadline will be determined by PETRONAS. PETRONAS may also request detail review by well in the Field Review Workshop (FRW) at any time required. PS Contractors shall invite PETRONAS for participation in any PS Contractors in-house detail well by well review to obtain exception for a separate FRW.

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12.3 MIDDLE AND LATE STAGE PS Contractor shall continue to gather and analyze reservoir performance data and operate in a manner that is consistent with the optimum reservoir management strategy of the field in line with sub-section 12.2. PS Contractor shall apply appropriate reservoir management tools and/or techniques for analyzing field performance. PS Contractor shall also conduct reservoir studies (i.e. full field review/depletion study) when there’s new data available (such as new or reinterpreted seismic, new well data, etc) or when performance deviate from forecast. When performance is per expectation, PS Contractors shall also nevertheless conduct the full field review/depletion study at least once every 3 to 5 years from the initial production. The results from the reservoir studies shall be submitted to PETRONAS for review. These full field review/depletion study shall cover but not limited to subsurface static and dynamic model update and further development opportunity. PS Contractor may apply for exception for the field review/depletion study with justification for PETRONAS consideration. PS Contractor shall take actions to improve well deliverability/injectivity as deemed necessary. PS Contractor may carry out workovers and/or other well work activities and artificial lift program which require submission of proposal for PETRONAS approval (refer to Appendix 12 for documentation and approval requirements). PS Contractor shall present to PETRONAS the field performance/surveillance during annual review. The timing for the annual review and the package submission deadline will be determined by PETRONAS. PETRONAS may also request detail review by well (FRW) at any time required. PS Contractor shall invite PETRONAS for participation in any PS Contractors in-house detail well by well review to obtain exception for a separate FRW.

12.4 IMPROVED AND ENHANCED RECOVERY At any stage of reservoir depletion PS Contractor shall look for opportunities to add reserves, preferably by natural means. However, artificial lift and/or improved recovery method may be required in cases where natural drive mechanisms are insufficient and it is SUPERSEDE ISSUE:

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economically justifiable to do so. PS Contractor shall submit the artificial lift and/or improved recovery program in the FDP or FDP Revision for PETRONAS technical review and approval. Examples of improved recovery method include but not limited to, water injection, and/or immiscible gas injection for pressure maintenance as well as displacement efficiency improvement. For fields with water injection or gas injection, PS Contractor shall conduct voidage replacement and volumetric sweep analysis of each reservoir and present summary of results to PETRONAS annually. For water injection, voidage replacement policy of each reservoir will be determined by the optimum reservoir management strategy of the field. For immiscible gas injection for pressure maintenance, voidage replacement policy of each reservoir will be determined by the optimum reservoir management strategy of the field, and/or a group of fields sharing the same infrastructure. At any stage of depletion, PS Contractor may seek PETRONAS approval for the application of enhanced recovery techniques. PS Contractor shall conduct screening study for enhanced recovery development opportunities during initial Field Development Plan and/or investigate these as part of Full Field Reviews. Examples of enhanced recovery techniques include, but are not limited to, immiscible or miscible gas injection, microbial enhanced recovery, surfactant flooding, steam flooding, polymer flooding and air injection. In particular, the PS Contractor must examine the potential for reserves optimization and geo-sequestration of greenhouse gas through immiscible and miscible carbon dioxide injection into fields located in regions (such as Peninsular Malaysia and Sarawak) that contain gas reservoirs with high carbon dioxide content.

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12.5 RESERVOIR MANAGEMENT PLAN PS Contractor shall submit a Reservoir Management Plan which includes the strategies and plan to PETRONAS in the initial FDP for approval. The content shall include the following but not limited to ; 12.5.1 Reservoir Management Strategy and Plan in various anticipated operational conditions. Any deviation to the plan outlined in 12.5.1 requires a revision/update to the RMP, and shall require PETRONAS approval prior to implementation. 12.5.2 An integrated sand management plan. Justification is required for not having sand management plan/provision. For existing reservoirs that are producing sand, an RMP or FDP update is required to be submitted for approval to include this new requirement. The RMP is required to be assessed and reviewed by PS Contractors annually and reviewed to PETRONAS as part of the annual performance review (FRMR or FRW reviews).

12.6 WELL ABANDONMENT PS Contractor shall submit plans for well abandonment for PETRONAS approval in accordance to section 5 of the Procedure for Drilling Operation or once the PSC or/and PETRONAS has determined that the reservoir/well can no longer produce economically and does not have the potential to do so in the future. This requirement shall be in-line with Section 16 of Guidelines for Decommissioning of Upstream Installation.


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SECTION 13 GUIDELINES FOR WELL TEST, PRODUCTION MEASUREMENT AND ALLOCATION

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SECTION 13 GUIDELINES FOR WELL TEST, PRODUCTION MEASUREMENT AND ALLOCATION Executive Summary This section provides the scopes / guidelines on the requirement for the information that is required to be submitted related to the completion and recompletion of development/ production wells on Well Test and Production Measurement and Allocation. It also provides the procedure for acquiring basic information for the purpose of reservoir management. However, the procedure written in this section does not cover all aspects of Well Testing and Production Measurement and Allocation, and shall be regarded as PETRONAS' requirements necessary while ensuring safety and integrity of production facilities based on good oilfield practices. This section shall be read together with the followings: 1. Section 3

: Guidelines for FDP Review and Approval Process

2. Section 11 : Guidelines for Facilities Reliability & Integrity Management 3. Section 12 : Guidelines for Reservoir Management. 4. Section 14 : Guidelines for Hydrocarbon Measurement 5. Section 15 : Guidelines for Gas Measurement In cases where the requirements and frequencies are not specifically stated in this Guidelines, PS Contractor shall derive the scopes and frequencies based on best oilfield practices, internationally recognised codes and standards and applicable Malaysian Laws, and shall implement the same accordingly.

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13.1 OIL PRODUCING WELL 13.1.1 Production Rate Test Upon initial completion or recompletion of oil wells, PS Contractor shall carry out the initial production rate test as soon as stable flow is established and/or subject to not more than 60 days of initial production or at the first safe opportunity available. The test shall be carried out on each separated producing interval(s) of the well whenever the interval(s) is put on production. PS Contractor shall conduct subsequent production rate test monthly for all active producers. However, if the well has established a consistent and predictable performance trend, a quarterly production test is allowed with PETRONAS approval. Production rate test shall also be conducted if the following arisen:a)

The new choke size has never been used before.

b)

The well performance is anticipated to be significantly different from prediction.

c)

Shut-in well within the last 3 years with capability of flowing.

Result of the production test shall be maintained by PS Contractor and be submitted as per Section 17, Guidelines for Data Management and Submission. The report of the above test shall include but not limited to the following information;

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a)

Choke size used for the well during the production test was conducted.

b)

Result of the production rate test (including the gas lift or other related information, where applicable).

c)

Measurement of the surface production conditions, i.e tubing and casing head pressure, pressure and temperature (where applicable) of the measuring equipment.


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13.1.2 Bottom Hole Pressure Survey 13.1.2.1

Transient Pressure Survey PS Contractor shall conduct initial flowing and build-up (FBU) or drawdown (DD), pressure survey(s) for newly completed or recompleted oil wells for each reservoir. The length of the build-up or drawdown period must be sufficient to capture well and reservoir parameters. This survey shall be conducted at the first safe opportunity available. Subsequent to the initial survey, periodical survey shall be conducted on each active producer when deemed necessary for wellbore evaluation. The exercise shall be conducted in accordance with prudent reservoir management practices.

13.1.2.2

Static Bottom Hole Pressure (SBHP)Survey This survey shall be conducted on at least 50% of the total active producers in each reservoir annually for the first two years of its producing life and on at least 25% of total active producers thereafter. The survey can be conducted on active or non-active producers.

13.1.2.3

Production Logging Tool (PLT) Survey For commingle reservoirs, PS Contractor shall conduct initial PLT Survey to define proper production allocation and/or identify well / reservoir problem. The subsequent survey shall be conducted as and when required.

13.1.2.4

Flowing Survey For oil wells with artificial lift, PS Contractors shall conduct flowing survey as required to validate well model and achieve optimum well operating condition.

13.1.2.5

Fluid Contact Logging Survey PS Contractors shall conduct fluid contact logging survey as required.

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13.2 GAS PRODUCING WELL 13.2.1 Deliverability Test Upon initial completion or recompletion of gas wells, PS Contractor shall carry out the initial deliverability test as soon as stable flow is established and/or subject to not more than 60 days of initial production or at the first safe opportunity available. The test shall be carried out on each separated producing interval of the well whenever the interval is put on production and on a minimum of three (3) rates. Subsequent to the initial deliverability test, periodical delivery test shall be performed at least once a year, if a single rate test indicates significant delivery change. This test shall be conducted for at least four (4) different flowrates on all active producers.

13.2.2 Periodic Production Rate Test PS Contractor shall conduct subsequent monthly production rate test for all active gas producers. Result of the production rate test shall be maintained by PS Contractor. The report for the above test shall include but not limited to the following information: i. Choke size used for the well during the production test was conducted. ii. Result of the production rate test. iii. Measurement of the surface production conditions, such as tubing and casing head pressure, pressure and temperature (where applicable) of the measuring equipments.

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13.2.3

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Bottom Hole Pressure Survey

13.2.3.1

Transient Pressure Survey PS Contractor shall conduct initial flowing and build-up (FBU) pressure survey(s) for newly completed or recompleted gas wells for each reservoir (refer to Section 12 for definition). The test should consist of at least 3 different rates (as per initial deliverability test) and followed by sufficient build-up period to capture well and reservoir parameters. This survey shall be conducted at the first safe opportunity available. The survey results shall be submitted within 60 days of completion of the survey. Subsequent to the initial survey, periodical survey shall be conducted on each active producer when deemed necessary for wellbore evaluation. The exercise shall be conducted in accordance with prudent reservoir management practices.

13.2.3.2

Static Bottom Hole Pressure (SBHP)Survey This survey shall be conducted on at least 50% of the total active producers in each reservoir (refer to Section 12 for definition) annually for the first two years of its producing life and on at least 25% of total active gas producers thereafter.

13.2.3.2.1

Production Logging Tool (PLT)Survey For commingle gas reservoirs, PS Contractor shall conduct PLT Survey for every 2 years to define proper production allocation and/or identify well / reservoir problem.

13.2.3.2.2

Fluid Contact Logging Survey PS Contractors shall conduct fluid contact logging survey as required.

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13.3 INJECTION WELL 13.3.1 Injection Rate Measurement Injection volume shall be measured and allocated on monthly basis.

13.3.2 Injectivity Test PS Contractor shall conduct initial injectivity test in every injection well or in any well converted to injection well for the purpose of pressure maintenance. For water injector, the test shall be done until above fracture pressure or maximum safe operating injection pressure to determine the reservoir fracture gradient and other well/reservoir information. Test shall be conducted within 90 days of injection or at the first safe practical opportunity available.

13.3.3 Injection Profiling Survey For commingle reservoirs, PS Contractor shall conduct initial Injection Profiling Survey to define proper injection allocation and/or identify well / reservoir problem. The subsequent survey shall be done as required.

13.3.4 Injection Fall Off Survey PS Contractor shall conduct initial Injection Fall Off Survey for newly completed or recompleted wells for each reservoir (refer to Section 12 for definition). The test should include sufficient shut in period to capture well and reservoir parameters. This survey shall be conducted at the first safe opportunity available. The survey results shall be submitted within 60 days of completion of the survey. Subsequent to the initial survey, periodical survey shall be conducted on each active injector when deemed necessary for wellbore evaluation. The exercise shall be conducted in accordance with prudent reservoir management practices.

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13.4 REQUIREMENT FOR WELL TESTING MEASUREMENT DEVICES. For oil / gas / injection well, the measurement devices to be used for well testing purposes shall be calibrated annually with an accuracy of +/- 10%.

13.5 EXCEPTION TO THE ABOVE REQUIREMENT PS Contractor may apply approval for exception to the above requirements with justifiable reason(s). Exception request/report shall be submitted to PETRONAS within 30 days before/after the occurrence of the exception case(s), respectively. PETRONAS may also from time to time request additional tests / surveys to be carried out within operational constraint if necessary.

13.6 RECORD KEEPING Result of the above test shall be maintained by PS Contractor and shall be submitted in accordance with Section 17.

13.7 PRODUCTION MEASUREMENT AND ALLOCATION 13.7.1 13.7.1.1

Production to each Field and Platform/Production Station. Measurement Production rates of oil, gas, condensate (if applicable) and formation water shall be determined for each platform/production station, field and terminal. Measurement for platform/production station, field and terminal which share a common facility with other station having different equity and PSC shall be agreed upon by PETRONAS. It is PSC Operator’s responsibility to ensure that the measurement system for well testing purpose is at all time comply with accuracy requirement of 10%. This can be conducted by means of onsite calibration or other methods that deem appropriate.

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SECTION 13 GUIDELINES FOR WELL TEST, PRODUCTION MEASUREMENT AND ALLOCATION 13.7.1.2

Page 215

Allocation Following the end of each calendar month, based on official measurement in the terminal either onshore or marine terminal or in other authorised place, the monthly production of oil, gas, condensate (if applicable) and formation water for each field and production platform/station shall be determined. A monthly report shall be submitted within thirty (30) days from the end of the month under review and shall include the following reconciled figures: i

petroleum and formation water;

ii

fluids injected; and

iii

petroleum/gas utilised, flared or vented, stored in and delivered from each production station/terminal.

13.8 PRODUCTION ALLOCATION TO EACH PRODUCTION STRING Following the end of each calendar month, based on the monthly production, the production rates of oil, gas, condensate (if applicable) and formation water for individual string shall be determined based on production rate test.

13.9 PRODUCTION ALLOCATION TO EACH PRODUCING INTERVAL When two or more producing intervals are being produced through a common string, the oil, gas, condensate (if applicable) and formation water production of the string shall be allocated to each producing interval according to the split ratio for the individual fluid. Determination of the split ratios shall be made before a new combination of producing intervals is placed into production or when the combination is changed or when data indicate a change is in order. Revision of the split ratios shall be made when deemed necessary based on well performance and survey and when operationally feasible.

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

-END OF SECTION 13-

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SECTION 14 GUIDELINES FOR DYNAMIC LIQUID HYDROCARBON MEASUREMENT Executive Summary These guidelines provide the minimum requirements for the establishment of a Liquid Hydrocarbon Custody Transfer and Allocation Metering Systems and also the information that are required to be submitted and shall be regarded as PETRONAS'general requirements necessary while ensuring accuracy, safety and integrity of the metering systems based on best oilfield practices, internationally recognised codes and standards and applicable Malaysian laws. In cases where the requirements and frequencies are not specifically stated in these guidelines, PS Contractor shall derive the scopes and frequencies based on best oilfield practices, internationally recognised codes and standards and applicable Malaysian Laws, and shall implement the same accordingly.

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14.1 INTRODUCTION These guidelines shall be read as part of Section 12, Guidelines for Reservoir Management and Section 13, Guidelines for Well Testing, Production Measurement and Allocation.

14.1.1 Scope These guidelines provide the minimum requirements in the design, installation, testing, commissioning, operation and maintenance of Liquid Hydrocarbon Custody Transfer and Allocation Metering Systems. Unless otherwise specified, the guidelines mentioned hereunder are applicable for both Custody Transfer and Allocation Metering Systems. The objective of these guidelines are to ensure that all Liquid Hydrocarbon Custody Transfer and Allocation Metering Systems are designed, installed, tested, commissioned, operated and maintained in accordance with the minimum requirements of PETRONAS for accurate measurements of liquid hydrocarbon. This guidelines does not cover the static measurement i.e. tank gauging, however, it is recognized that, should the dynamic measurement failed, the static measurement will be used for quantitative determination in accordance to the agreed onshore/offshore terminal procedures.

14.1.2 Distribution, Intended Use and Regulatory Considerations Unless otherwise authorized by PETRONAS, the distribution of these guidelines is confined to companies forming part of PETRONAS and PETRONAS’ Production Sharing (PS) Contractors or their nominated third party or parties for the above scope of work. These guidelines are intended for use by all involved in the design, installation, testing, commissioning, operation and maintenance of a Liquid Hydrocarbon Custody Transfer and Allocation Metering Systems in PETRONAS, its PS Contractors or their nominated third party. It is the responsibility of the respective PS Contractors or Contractor as SUPERSEDE ISSUE:

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referred to in these guidelines, to ensure that these guidelines are followed if, wholly or partly, the above scope of work are outsource or contract out to any third party or parties. In developing oil and gas fields that straddle with neighbouring countries, if the co-host country has its local regulations, the Contractor shall determine by careful scrutiny which of the requirements are more stringent and which combination of the requirements will be acceptable as regards to safety, environmental and economic aspects. In all cases the Contractor shall inform PETRONAS of any deviation from the requirements of these guidelines which are considered to be necessary in order to comply with the neighbouring countries local regulations. PETRONAS may then negotiate with the Malaysian Authorities and the respective Authorities concerned with the objective of obtaining agreement to follow these guidelines as closely as possible and also to be cost effective.

14.1.3 Definitions General definitions The Contractor refers to the Production Sharing Contractors which sign the Production Sharing Contract with PETRONAS in respect of the exploration, exploitation, winning and obtaining of petroleum resources in the Contract Area on the terms and conditions set out in the said contract. The Vendor is the party which manufactures or supplies equipment and services to perform the duties specified by the Contractor. The word Shall indicates a requirement. The word Should indicates a recommendation. Specific definitions Accuracy - The measure of the closeness of a measurement to the true value. Allocation Metering System (for liquid hydrocarbon)- A measuring system comprising mechanical, instrument and computer parts whose registered measured quantity is used for allocation between two or more Contractors which involved in SUPERSEDE ISSUE:

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sharing the same facilities for their operation . This system normally has an uncertainty of +/-1%. Automatic Sampler - A system which, when installed in a pipe and actuated by automatic control equipment, enables a representative sample to be obtained from the liquid flowing in the pipe. The system generally consists of a sampling probe, a sample extractor, an associated controller and a sample receiver. Normally it is also equipped with a sampler performance monitoring device. Computer Part – That part of the metering system that consists of digital computers and receives digital signals from A/D converters or from digital instrument loops. Control Chart - A graphical chart of the constancy of measurement used for evaluating whether meter proving operations are in or out of statistical control. On it are shown the +/- 3 sigma limits of dispersion from the average system factor, x (standard deviation), within which the measurement system considered to be in control (API Chapter 13). Custody Transfer Metering System (for liquid hydrocarbon) - A measuring system comprising mechanical, instrument and computer parts whose registered measured quantity is used for sale where there is a change in ownership. This system normally has an uncertainty of +/-0.25 % of standard volume. Density - The density of a quantity of a homogeneous substance is the ratio of its mass to its volume. The density varies as the temperature changes and is therefore generally expressed as the mass per unit of volume at a specific temperature. Displacement Prover - Provers, which operate on the principle of the repeatable displacement of known volume of liquid from a calibrated section of pipe between two detectors. These include provers that were commonly referred to as either “conventional” pipe provers or “small volume” provers. Flow Computer - is an arithmetic processing unit and associated memory device that accepts electrically converted signals representing input variables from a liquid measurement system and performs calculations for the purpose of providing flow rate and total quantity data.

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Flow meter – Flow measuring device which, indicates the measured flow rate. In some cases, it is also a device that indicates the total amount of fluid passed during a selected time interval. Instrument Loop - Includes all elements that form part of the measurement of each individual quantity from sensor to input of the A/D converter or input of digital signal to the computer part. Linearity - The deviation or spread of calibration data points from an acceptable straight line over the defined flow range. Linearity of a Meter - The ideal accuracy curve of a volume meter is a straight line denoting a constant meter factor. Meter linearity is expressed as the total range of deviation of the accuracy curve from such a straight line between the minimum and maximum recommended flow rates. Maximum Meter Flow Rate - The maximum rate of flow recommended by the meter manufacturer or authorised by a regulatory body. The maximum rate is determined by considerations of accuracy, durability, pressure drop, repeatability, and linearity. Meter Proving - An exercise carried out in accordance to the proving procedure in order to determine the relationship between the volume of liquid passing through a meter at one set of conditions and the indicated or reference volume at the same conditions. Meter run - A flow measuring device complete with associated strainers, entry/exit pipework, upstream and downstream straight lengths, flowmeter and flow straighteners. Minimum Meter Flow Rate - The minimum rate of flow recommended by the meter manufacturer or authorised by a regulatory body. The minimum rate is determined by considerations of accuracy, repeatability and linearity. Online Density Meter - A density meter also known as densitometer operating on a representative sample of the process material withdrawn continuously from the process line or vessel via a sampling system. Positive Displacement Meter - A meter in which the measuring element is the discrete volumetric segments in the meter and volume is directly measured by

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continuous separating (isolating) a flow stream into discrete volume segments and counting them. Prover Computer - is an arithmetic processing unit and associated memory device which consists only the proving function for the proving of meters and the calculation of meter factors. Pulse Interpolation - Any of the various techniques by which the whole number of meter pulses is counted between two events (such as detector switch closures) and any remaining fraction of a pulse between the two events is calculated. Repeatability - The quality which characterizes the ability of a measuring instrument to give identical indications or responses, for repeated applications of the same value of the measured quantity under stated conditions of use. Sampling - An exercise in accordance to the procedure that is carried out either automatically or manually to obtain a sample that is representative of the contents of any pipe, tank or other vessel and to replace that sample in a container from which a representative test specimen be taken for analysis. Small Volume Provers - Any pipe prover used to calibrate a meter, having a volume between detectors that does not permit a minimum accumulation of 10,000 whole (unaltered) pulses from the meter. Small volume provers require meter pulses discrimination by pulse interpolation or other technique to increase the resolution. Standard Reference Conditions - The conditions of temperature and pressure to which measured volumes are to be corrected. Standard reference conditions for pressure and temperature shall be 101.325 kPa (abs) and 15 ºC respectively, in accordance with ISO 5024. Station Computer - is an arithmetic processing unit and associated memory device which sends commands and accepts calculated data from Flow Computer and Prover Computer for Station Totalisation computation and archiving. Turbine Meter - A meter in which the measuring element is a multi-bladed rotor or impeller to which the metered stream imparts a rotational velocity that is proportional to the mean velocity of the stream. Measured volume is registered by counting rotor revolutions.

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Uncertainty - The part of the expression of the result of a measurement which states the range of values within which the true value of, if appropriate, the conventional true value is estimated to fall. Validation - The process of confirming or substantiating the accuracy of input variables to a measurement system at normal operating conditions, using reference equipment traceable to certified standards.

14.1.4

Abbreviations AC

- Alternating Current

A/D

- Analogue to Digital

AGA

- American Gas Association

API


BS

- British Standards Institution

CCR

- Central Control Room

DC

- Direct Current

DP

- Differential Pressure

FAT

- Factory Acceptance Test

GHV

- Gross Heating Value

IP

- The Institute of Petroleum

IEC

- International Electrotechnical Commission

ISA

- Instrument Society of America

ISO

- International Organization of Standardization

LCR

- Local Control Room

MPMS - Manual of Petroleum Measurement Standard

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NBS

- National Bureau of Standard

NEC

- National Electricity Code

PID

- Piping and Instrument Drawings

RTD

- Resistance Thermal Detector ISSUED BY PETROLEUM MANAGEMENT UNIT

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SECTION 14 GUIDELINES FOR DYNAMIC LIQUID HYDROCARBON MEASUREMENT SI

- International System of Unit

SIRIM

- Standard Industrial Research Institute of Malaysia

STC

- Site Testing and Commissioning

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14.2 GENERAL REQUIREMENTS 14.2.1 Units of Measurement The base (reference or standard) conditions for metering system shall be in Sl units in accordance with the ISO 5024 latest revision whose base conditions are defined as pressure of 101.325 kPa (abs) at temperature 15oC. Where an imperial unit such as barrel is required, it shall be converted from the base Sl unit and referenced to 14.696 psia and 600F. Liquid hydrocarbon measurement shall be either in volumetric, mass or energy units. The units shall be SI units.

14.2.2 Approval Requirements PETRONAS approval shall be obtained for measurement and allocation concept and metering project implementation as per section 14.2.2.1 and 14.2.2.2, respectively. Section 14.2.2.3 specifies the government approval that is required to be complied by Contractors. 14.2.2.1

Measurement and Allocation Concept Proposed Measurement and Allocation concept shall be submitted for PETRONAS evaluation and approval. The concept shall be submitted and agreed during the Field Development Plan stage. Contractor shall carry out the financial exposure and cost benefit analysis during the evaluation of the concept and to determine the location for the installation of the metering system, metering system configuration and level of accuracy required. To

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facilitate the above approval, the preliminary submission to PETRONAS shall include but not limited to the following items. 1. Measurement philosophy. 2. Product allocation principles. 3. Measurement methods and standards. 4. Proposed system accuracy. 5. Production accounting exposure analysis. 6. Metering Project cost estimates. 7. Field area and installation layout with main pipelines. 8. Proposed sizing of the metering system. 9. Preliminary system configuration. The metering system can either be used for Custody Transfer or Allocation purpose. Two categories of metering system fall under the preview of these guidelines. a.

Custody Transfer Metering System – This type of system is normally of high accuracy and designed with an uncertainty of +/0.25% of standard volume, used for custody transfer application i.e. transfer of ownership. The figure registered from this system is used for sales determination.

b.

Allocation Metering System - This type of metering system has slightly lower accuracy than Custody Transfer Metering and normally designed with an uncertainty of +/-1%. This type of system is used for allocation of liquid between fields of different ownership sharing a common facility or facilities. The allocation method normally used is by “full allocation” i.e. where metering systems are installed in all fields of different ownership involved in sharing the same facilities. However, the uncertainty of the

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metering system can also be designed to be of custody transfer quality standard e.g. +/-0.25% if “measurement by difference” allocation concept being adopted. Factors such as oil reserve, investment cost and impact to the related parties are to be considered and agreed by those involved before this allocation concept is adopted. Only upon PETRONAS agreement on the measurement and allocation concept, Contractors can proceed on procuring of the relevant metering systems in accordance to these guidelines. It is the responsibility of the Contractor to obtain agreement from their equity partner and the interested party or parties that will be affected with the metering system installation, before the concept is submitted for PETRONAS agreement. 14.2.2.2

Metering Project Implementation PETRONAS will also request the following information to be submitted for approval prior to the release of bid package:a) System specifications. b) Design formula and calculations. c) Calculation of overall accuracy and uncertainty of the system. d) Relevant drawings. e) Other relevant information. PETRONAS may also request the Project Definition Manual be submitted prior commencing fabrication of the metering system and will inform Contractor if other information is required. Prior to the official use of the metering system, Contractor shall submit an application together with all the relevant data for PETRONAS to review and PETRONAS will provide the approval after having satisfied with the system performance either from the data submitted or after visiting the installation site. Metering system installed shall be traceable to SIRIM Berhad’s standard.

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Contractor shall also submit to PETRONAS for approval the hydrocarbon allocation and accounting procedure and as well as the validation procedure. The operation procedure will be requested on the need basis. 14.2.2.3

Government Regulatory Requirement Custody Transfer Metering System which registered flow quantity that is also used to calculate the crude oil sales tax needs to be agreed by the Malaysian Authorities i.e. SIRIM Berhad and Customs and Excise Department. System to be installed shall be first agreed by the authorities and certification from them is necessary prior official use. Should other method of measurement intended to be used for the above application, agreement by Customs and Excise Department is necessary. Contractor shall also ensure that the Department of Safety and Health (DOSH) approval is obtained by their Vendors should the fabrication and testing of the metering system be carried out in Malaysia. Approval should also be obtained if the system is to be installed and operated onshore.

14.2.2.4

Deviations Any deviation from these guidelines with respect to the measurement and allocation concept, design, operation and maintenance of the metering system requires PETRONAS prior approval.

14.2.3 Documentation Contractor shall establish and maintain an up-to-date file containing all specifications, calculations and drawings (as-built). The file should also contain reports concerning verification revisions, design, fabrication, installation and commissioning including inspection and testing programs and operation manual for all fixed and temporary phases, and other relevant documentation.

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Contractor shall ensure that all documentation during the metering project implementation are timely available such as the project definition manual including the uncertainty analysis, factory and site acceptance test procedures and its result and as well as project completion report. PETRONAS may request some of these information on the need basis. The Contractor should maintain up-to-date lists of current documentation and documentation under preparation. Contractor’s internal control system including the documentation should also be made available to ensure the qualities of the metering systems are maintained.

14.3 DESIGN 14.3.1 General Requirement The metering and proving systems shall be designed, fabricated, inspected and tested in accordance with the latest agreed editions and addenda to the technical specifications, codes, standards and references mentioned in Section 14.7 References. Contractor shall request the vendor to quote for the design, manufacture, testing, calibration and documentation of a fully integrated skid and associated control panel. The metering system shall comprise the following major component parts:1. Field mounted skid and instrumentation. The minimum number of parallel meter runs required from the specified maximum and minimum flow rates at the specified accuracy with one complete spare meter run and a proving facilities. For allocation metering system where its availability is less critical, the spare run may not be required. Flow proportional automatic sampling system.

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All associated pipe-works, valves and fittings, access stairs, walkways for operation, maintenance and validation, lifting pad eyes and drip pans. All transducer and instrumentation necessary for automatic meter proving prover operation and continuous measurement of mass and volumetric quantities and flowrates of liquid together with its temperature, pressure, density and water content prior to delivery. 2. Metering control panel and computing facilities in the Control Room The computer system consisting of flow computers, prover computer, station computer and communication bus. Station computer and communication bus shall be provided with full redundancy. For the allocation metering system, this depends on the availability and criticality requirement of the system. All other items not specifically mentioned but necessary for the functioning of the systems, including equipment for testing and calibration. The control panel shall include all terminations, computing devices, indicators and controls necessary for operation from the panel location. All equipment within the skid shall be ergonomically arranged such that it is safe and easily accessible for operation, maintenance and validation. Facilities to ease the validation shall be included in the system. Platforms, gratings, stairs, etc. be provided as required for easy movement within the skid area. For metering system that required heat tracing, all equipment and components that will be accessed periodically shall be provided with removable insulating covers fitted with quick release fasteners. All equipment and material supplied shall be brand new and suitable to be used for its intended operating conditions. The system shall be designed to allow subsequent re-calibration of the displacement prover on site with a portable master pipe prover - master meter calibration equipment, tank prover-master meter or calibration can. For allocation metering system where a master meter being used, a calibration facility for proving the master meter shall be made available. Suitable process

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and electrical equipment and connections shall be provided for the above purpose. No bypassing of the metering system is allowed for normal operations after commissioning and startup. For the purpose of commissioning and start up, should a bypass line is required, it shall be provided with a blind or a positive shutoff double block and bleed valve with telltale bleed for verifying shutoff integrity. This valve shall always be sealed. Other designs can be accepted provided that the Contractor can demonstrate and document equivalent or better accuracy and integrity of the abovementioned system. A typical flow scheme is shown in Figure 1 Appendix 14. 14.3.2 Meter Run Design / Pipe Work The meter runs shall be designed in accordance to the ISO 2714, ISO 2715 and API Manual of Petroleum Measurement Standards Chapter 5-Metering and other chapters as specified in the reference list. Materials selected shall conform to applicable codes, pressures and temperature ratings, process conditions, corrosion resistance, ingress protection and electrical safety classification. Each parallel meter run shall be provided with an inlet, outlet, stream control and prover inlet valves, thermal relieve valve, flowmeter with required upstream and downstream straight length or flow straightening vane as required and a strainer with differential pressure indicator and draining facility. The strainer shall be able to handle the highest flow capacities of the meter with a minimum pressure drop. Temperature transmitter and thermowell, pressure transmitter and pressure gauge shall also be provided. The number of parallel meter runs shall be such that the metering system shall be capable of measuring all flow rates from the minimum to maximum of the metering system throughput with one meter run on standby and the remaining meters still operating within their working range. For allocation metering system that is less critical, standby meter run may not be required. However, prior approval shall be obtained from PETRONAS as per Section 14.2.2 - Approval Requirements. SUPERSEDE ISSUE:

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A full bore through conduit or ball valve should be fitted upstream, downstream and prover inlet of each meterrun. Double block and bleed valves configuration should be fitted at the following places:•

Meter run outlets to prover inlet header

•

Meter run outlets to outlet header

•

Prover outlet to outlet header

•

Prover drains line.

These valves (with the exception of the meter run inlet valve) shall have instrumentation for cavity pressure relief and shutoff integrity verification. Drain connections from double block and bleed valves configuration shall have an isolation valve and pressure gauge, for verification of tight shut-off. For offshore metering systems, suitable arrangement for the valves to meet the safety standard is to be followed. Flow control valves shall preferably be located at the following points: On each meter run outlet between the tee and the outlet double block and bleed valve. On the prover outlet between the 4-way diverter valve and the outlet double block and bleed valve. The valves shall be capable of stable control over at least the normal linear range of the meter. Valve and actuator sizing calculations shall be required as part of the documentation. Thermal relief valves shall be provided for all sections of pipework capable of isolation and possible over-pressure. All connections shall be self-draining. The total pressure drop of each meter run at the maximum linear operating conditions shall be provided.

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Flowmeter Type Turbine and positive displacement flowmeter are normally used for custody transfers of liquid hydrocarbons. In determining the type of flowmeter to be used, reference to Appendix 14.1, shall be made for flowmeter design requirements. Although factors such as pressure, temperature, viscosity, flow range and fluid contamination may influence the type of meter selected, viscosity, flow rate and fluid contamination should be considered first. Linearity of each meter shall be better than ±0.25% over a 10:1 flow range at the specific operating viscosity. The meter shall be calibrated initially, preferably on the liquid with the viscosity for which the system is designed, or if unavailable, on water by the independent authority. Viscosity performance shall be established when the meters are in operation. The repeatability of 5 consecutive proof runs under stable conditions shall be better than ±0.025 % of the average meter factor. This shall be checked at minimum and maximum flow and at evenly distributed flow rates within the specified 10:1 range, on both water and fluid of the relevant viscosity. The former checks shall be carried out at the Manufacturer's works during system test (FAT) and the latter during location tests (SAT).

14.3.2.2

Prover Design A permanent meter proving facility shall be provided and be designed as per ISO 7278 Liquid Hydrocarbons – Dynamic Measurement – Proving Systems for Volumetric Meters and API MPMS Chapter 4 – Proving Systems and Chapter 4 of API Manual. Meter proving facility can be using any of the following methods.

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

Conventional Pipe Prover The Conventional Pipe Prover shall preferably be of the bi-directional type with quick opening closure for sphere removal, sized and manufactured in accordance with ISO 7278-2 Liquid hydrocarbon – Dynamic measurement – Proving systems for volumetric meters – Part 2: Pipe provers, API MPMS, Chapter 4.2 - Manual of Petroleum Measurement Standards Chapter 4 - Proving Systems Section 2 - Displacement Provers and the following criteria :-

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a.

Number of meter pulses generated over calibrated volume to be not less than 10,000 whole pulses (unaltered) per trip i.e. 20,000 pulses (unaltered) total round trip volume.

b.

Resolution of detector/displacer system shall be compatible with requirement (1).

c.

Displacer velocity not exceeds 3 m/s.

d.

Length between detector switches to be at least 20,000 times detector repeatability.

e.

Prover connection shall be downstream of the meters.


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The prover shall be designed such that the repeatability during calibration of the volumes, where five calibration trials are performed and be within +/-0.01% of the average volume.

g.

Connections shall be provided on the prover loop to facilitate recalibration with a portable master pipe prover-master meter or tank prover-master meter. Drain at the lowest point and vent at the highest point shall also be provided. The prover system should also been equipped with the temperature and pressure measuring element.

h.

Other considerations for the design including of the followings:1. Detector switches The pipe prover shall have two detector switches at each end of the prover with preferable four independent calibrated prover volumes. The prover volumes from the cross-sectionally installed detector switches shall be very similar and these calibrated volumes are to be independent of each other where at any one time if either one of the detector switches fails, it does not invalidate the other prover volume. The detector should be designed such that the contacting head of the detector protrudes far enough into the prover pipe to ensure switching takes place at all flow rates during calibration and normal operation. Detectors and switches should be weatherproofed against corrosive marine environment and suitable for the electrical safety classification of the installation. 2. Prover Internal and Coating Internal diameter of the prover loop shall have the same diameter throughout and there shall be no tappings or

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drain points between the calibrated volumes of the prover. The internal coating of the pipe prover shall provide a continuous level, durable and smooth surface for the application. The vendor shall provide full details of the coating, surface preparation, method of surface preparation, method of application, maximum allowable fluid temperature and method of repair. Porosity and explosive decompression of the lining shall also be avoided. 3. Four-way Diverter Valve The four way diverter valve shall be motorised and provided with a local and remote actuation together with a manual override hand wheel. If remote status of valve is required, limit switches shall be provided. Necessary instrumentation to detect leakage on the valve is also to be equipped. The 4-way flow diverter valve in the bidirectional prover shall be fully seated and sealed before the displacer meets the first detector. 4. Freedom from Shock When the prover is operating at its maximum design flowrate the displacer shall come to rest safely at the end of its travel without shock. 5. Guide Bars/Tees Careful consideration shall be given to the design of guide bars or tees to avoid damage to displacers. b)

Small Volume Prover “Small Volume” is one type of prover of which the volume is insufficient to accumulate a minimum of 10,000 whole meter pulses

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between detector switches for each pass of the displacer. Small volume provers require meter pulse discrimination by pulse interpolation or another technique to increase the resolution. The performance of this type of prover is critically dependent on the mechanical precision of the tube bore and movable element position detecting system, the measurement accuracy and stability of temperature and pressure, tightness of the moving parts and the ratio between the diameter of the tube and the actual displacement of the moveable elements. Should the fiscal authorities accept the use of “small volume” provers, these may be applied. For offshore applications, where space and weight are important considerations, a “small volume” provers will provide a smaller and lighter solution for a given meter capacity. Small volume provers shall be designed and manufactured in accordance with ISO 7278-2 Liquid hydrocarbon – Dynamic measurement – Proving systems for volumetric meters – Part 3: Pulse Interpolation Technique, and API MPMS, Chapter 4.2 - Manual of Petroleum Measurement Standards Chapter 4 - Proving Systems Section 2 - Displacement Provers and also with the following criteria: Small Volume Prover inlet connection should preferably be downstream of the operation meters. Connections shall be provided at the small volume prover system to facilitate re-calibration by Water Draw Method at site. Piston seal leakage check kit shall be delivered together with the small volume prover. Water Draw Assembly or Test Measures should be delivered together with the small volume prover.

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The prover shall be designed such that the repeatability during calibration of the volumes, where five calibration trials i.e. 5 consecutive runs are performed and be within +/-0.01% of the average volume. Vertically installed. Test Measures for the calibration of the small volume provers shall comply with the requirements given in the API Manual of Petroleum Measurement Standards Chapter 4 - Proving Systems, Section 7 Field Standards Test Measures and shall be supplied by the vendor, certified with certificate issued. Prior calibration of small volume provers using the Test Measures at site, the Test Measures shall be first calibrated and certified by SIRIM. As minimum requirements, the following elements shall forms parts of the small volume prover : 1. A precision cylinder. 2. A displacer piston, spheroid, or other fluid separation device. 3. A means of positioning and launching the displacer upstream of the calibrated section. 4. A displacer detector(s) 5. A valve arrangement that allows fluid flow while the displacer is traveling from one position to the opposite position. 6. Pressure measurement and indication devices. 7. Temperature measurement and indication devices. 8. Instrumentation with timers, counters, and pulse interpolation capability During proving of Turbine and Positive Displacement meters, the displacer velocity shall not exceed 1.5 m/s. The internal diameter of the prover flow tube shall have the same diameter throughout the flow tube. The calibrated or swept volume of the prover, located between SUPERSEDE ISSUE:

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the displacer-position sensors shall be free from any tappings, vent or drain points. The small volume prover should be installed downstream of meters. The small volume prover shall allow the displaces to come to rest safety without shock at the end of its travel when operating at its maximum design flow rate. There shall no sign of cavitation in the small volume prover, the valves or any other apparatus within the specific temperatures and pressure ranges when operating at its design maximum flow rate. The internal coating of the small volume prover shall have uniform bore, durable and smooth long lasting surface. Block valve shall be installed to isolate the small volume prover from line pressure during maintenance, removal of displacer, replacement of seals, cleaning, etc. Drain at lowest point and vent at highest point shall be provided. Pressure relief valves and leak detection facilities shall be installed with discharge piping to control thermal expansion of the liquid in the small volume prover while it is being isolated from the main stream.

14.3.2.4 Master-Meter Provers A Master-meter is an indirect prover that uses the concept of transfer proving. A flow meter with exceptional linearity and repeatability is selected to serve as a master meter (Intermediate Standard) for the proving of another meter or prover operating in the field. A comparison of the two outputs is the basis of the master-meter proving method.

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The mastermeter provers shall be manufactured in accordance with ISO 7278 Liquid Hydrocarbons – Dynamic Measurement – Proving Systems for Volumetric Meters and the API Manual of Petroleum Measurement Standards Chapter 4 - Proving Systems, Section 5 - Master-Meter Provers. Master-meter proving, of which satisfactory results can be achieved, is used in situations in which proving by direct method cannot be accomplished because of logistic reasons, such as unavailability of provers. However, the Mastermeter method introduces uncertainties between the meter being proved and the prover that is used to calibrate the master meter. Master Meter Provers shall be used on a less critical metering system. The master meter should be placed downstream of the meter to be proved and shall be connected in series and close enough to minimize corrections for volume during proving. All fluid diverting valves between the meters shall provide a positive seals. If the master meter is in portable service, it should be protected against damage during transportation, installation and handling.

14.3.3 Instrument Requirement 14.3.3.1

Field Instrumentation

14.3.3.1.1 Location of Sensors Temperature and pressure shall be measured in each meter runs and at the inlet and the outlet of the pipe prover. 14.3.3.1.2 Installation of Instruments A thermowell shall be installed adjacent to every electronic temperature sensor or group of sensors for calibration. It shall be possible to connect test instruments in parallel with all pressure sensors in the metering SUPERSEDE ISSUE:

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system. Temperature, pressure and density, where specified, measuring points shall be representative of conditions at the meter and situated as follows:a. In volumetric measurement systems: as close to the meter as possible without infringing the requirements of the API Measurement manual or other standards as specified in this guideline. b. In mass measurement systems: as close to the densitometers as possible, which should also be located as near the meter as possible, without infringing the API Measurement Manuals or other standard as specified in this guideline. 14.3.3.1.3

Instrument Loops The instrument loops shall be kept separate from other types of instrumentation and power supply cabling in the area of use. Cables and junction boxes shall not be shared with instrument loops that are not part of the metering system. Cables and other part of the instrument loops shall be designed and installed so that they will not be affected by electromagnetic fields.

14.3.3.1.4

Transmission of Pulse Signal Pulse signal transmission and treatment from the turbine meter shall be designed in accordance with guidelines in IP252 or ISO 6551. A pulse comparator shall be installed which signals an alarm when a preset number of error pulses occurs on either of the transmission lines in accordance with the above code. The pre-set level should be adjustable, and when an alarm occurs it should be recorded on a non-resettable comparator register. Where the pulse error alarm is determined by an error rate, the error threshold shall be less than 1 count in 100,000.

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Pulse discrepancies that occur during the low flow rates experienced during meter starting and stopping should be inhibited. The pulse transmission to the prover counter should be from one or both of the secured lines to the pulse comparator, and precautions should be taken to avoid any signal interference in the spur from the comparator line. Internationally accepted pulse interpolation methods for the pulse signals from the turbine meters may be used if it can be proved that the accuracy of the metering system satisfies the requirement in this article and satisfactory documentation of the reliability for the interpolation is produced. 14.3.3.1.5

Conversion of Signals from Analog to Digital Form The A/D conversion shall not contribute systematic errors to the measurements. Total inaccuracy in the analog to digital conversion, including resolution, drift, linearity, repeatability and other random errors shall be less than +/- 0.025% of full scale. Where a single A/D conversion is used, back-up converter is required.

14.3.3.1.6

Temperature Measurement The temperature-measuring element shall be a platinum resistance element or temperature transmitter in accordance with guideline in IEC 751 “Tolerance class A" or equivalent. The accuracy for the complete circuit shall be better than +/-0.15o C.

14.3.3.1.7

Pressure Measurement The accuracy for the complete pressure loop shall be better than +/-0.25% of span.

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Density Measurement The density measurement where specified, shall be designed in accordance with IP Petroleum Measurement Manual Part VII Section 2 or API Manual of Petroleum Measurement Standard, Chapter 9. For mass measurement, two density transducers should be installed. The installation shall be such that the liquid passing through the density meter is representative of the line density and no gas can be trapped in the density meter that could cause the error on the density reading. They should both be installed at the inlet to the metering system, within a fast loop arrangement. Insertion type densitometers may be installed in the inlet or outlet of the metering system. The densitometers installation should be in such that one can remain online for density measurement continuously while the other one is taken out for maintenance / validation. Necessary correction to meter conditions shall be carried out. The built -in temperature sensor in the densitometer shall only be used for indication purpose. The accuracy for the complete loop shall be better than +/- 0.5 kg/m3.

14.3.3.2

Control Room Instrumentation

14.3.3.2.1

Environmental Instruments which are sensitive to temperature or other environmental factors shall be installed in locations where these factors can be controlled.

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14.3.4 Computer Based Monitoring and Control Functions Requirement 14.3.4.1 General Metering and meter proving shall be managed by a computer system. Manual proving shall also be incorporated as a backup. This system shall be installed in the CCR, LCR or local equipment room. Normally, separate computers should be dedicated to each of the metering runs, to the station and to prover control. However, the functionality of the prover and station computers may be combined into one or more computers if it can be demonstrated that the required reliability, availability and redundancy standards will be met. However, such arrangement has to be agreed by PETRONAS. The computer system is to be designed as follows:1) The computer part in the metering system shall have no functions other than those involved in the metering. The metering system shall be designed in such a way that the maximum liquid flow will be measured. 2) The computer part shall have the capability of displaying continuously the number of pulses received from the meter during proving. 3) The system should include at least two independent registers for storing accumulated fiscal quantities for each meter run and the station total. It shall not be possible to delete or change these registers by operator encroachment or power failure. 4) The computer shall also be designed to ensure that amounts generated during validation/calibration are registered separately from the measured amount. 5) Manually entered parameter shall be displayed without rounding off or truncation of digits. The display on the computer shall have sufficient resolution to enable the verification for the calculation accuracy as in Section 14.3.4.3 be carried out. 6) Computer system shall be designed such that the transfer of data to DCS / SCADA / Plant Information (PI) System is permissible and all interfacing SUPERSEDE ISSUE:

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requirement such as the handshaking and necessary software is provided. 7) The computer part shall have automatic watch over for differences between readings of measured values, for parallel meter runs. 8) For continuous monitoring of measurement data the computer shall, for each meter run, automatically log and store for at least one year the following data: At intervals of 1 hour cumulative quantities, meter factor and average values of pressure, temperature and density. At intervals of 24 hours: cumulative quantities. This information shall be accessible on printout in a clearly set out format using standard computer printer and paper. Access to the logs shall not be possible without the use of key operated switch. 9) The flow computer shall (standard feature and without further modification) be able to receive at least 2 pulse trains from a turbine meter to perform the pulse security check in accordance with the guidelines stated in the IP 252 or ISO 6551. 10) Report facility for computer constants, keypad setting should be available. 11) The computer will have the ability to perform meter curve (foot-print) interpolation for minimum of 8 calibration points. 14.3.4.2

Data Security The data transmission of the computer shall be designed in accordance with Level A of the IP Standard 252/76, Part XIII Section 1. The computer shall have a self-diagnostic capability. It shall monitor that the program loops are executed at the correct intervals by means of a watchdog function. The parts of the memory that contain permanent data shall have a periodical check sum control. The algorithms and the fixed parameters important for accurate computation of fiscal quantities shall be stored in non-alterable memory.

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Security system shall be provided for manual entering of data. The computer system shall be designed and features provided for sealing. Program version number shall be assigned to identify the current program used and this can be determined directly from Visual Display Unit (VDU) or print out. The version number can be updated every time permanent program is altered. 14.3.4.3 Calculation The computer routines for fiscal measurement calculation shall satisfy API MPMS Chapter 12- Calculation of Petroleum Quantities and IP 201 Petroleum Measurement Manual Part 1- Calculation of Oil Quantities. 1)

Update time to changes of input signals shall not be more than 2 seconds and parameters having response time such as density and temperature shall not exceed 5 seconds.

2)

The interval between each cycle for computation of instantaneous flowrate and accumulated flow shall be less than 10 seconds.

3)

The algorithms for calculation of meter factor at reference condition shall contain all correction factors given in API 2534 1st edition 1970.

4)

Algorithm and rounding off error for computation of fiscal quantities in the flow computer shall be within +/- 0.001 % for totalisation and +/0.01% for flowrate of the computed value. Rounding or truncation shall only be carried out at the end of final computation.

5)

Temperature reading in degree Fahrenheit (deg F) shall be corrected to 1 decimal point and 2 decimal points for reading of temperature in degree Celcius ( ºC).

6)

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For meter factor and volume prover computation purposes, the decimal points used shall follows: i.

Ctl, Cpl, Cts and Cps - 6 decimal points.

ii.

Prover volume calculation - 4 decimal points.


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iii.

Meter factor - 6 decimal points.

iv.

Final prover volume shall be corrected to 3 decimal points.

Any deviation from the above requirements PS Contractor is obliged to follow SIRIM requirement.

14.3.4.4 Printouts and Hardcopies The computer system shall have dedicated printers for alarms and reports. Supervisory computer should be able to electronically archive all the alarms and reports. Common printer can be used if an acceptable priority routine is established. Automatic logging on the following information is to be provided: 1) Alarms for faults detected by the computer (date, time). 2) Inserted parameters/constant, both fixed and changeable. 3) Quantity report. 4) Instantaneous values of rate and measured input parameters. Fixed values, which are used instead of live signals, shall be identified. 5) Meter proving report. All data required for manual checks of calculated correction factors and meter factor shall also be included. The Contractor, after consultation with PETRONAS, shall establish a system for reporting of agreed data. 14.3.4.5

Meter Proving Algorithm Routine During designing the computer routine for meter proving operations, the followings shall be followed:1) All meter runs outlet and prover inlet valves and status check for meter proving sequencing shall be automatic. 2) All proving calculations shall be carried out by the computer system and printed automatically. Sufficient data shall be available on the printout such that meter proving calculations can be verified externally. Repeatability limits and the required number of consecutive

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run for repeatability acceptance shall only be changeable with highest security level. (Meters repeatability shall be such that they can be calibrated against a permanent meter prover with a sequence of 5 consecutive runs, where the difference between the highest and lowest meter factor does not exceed 0.05% of the average meter factor). 3) Maximum trial runs before the computer aborts the proving operation shall also be made changeable with highest security level. (Default number of trial runs is 10). 4) Prover stabilisation period for process conditions i.e. temperature, flowrate, pressure parameters of the stability limit shall be user changeable with appropriate security level (supervisor/engineer). 5) Automatic loading of meter factor to flow computer upon confirmation from operator. Acceptable meter factor shall be within the meter factor high and low limit of the respective meter. The Contractor, after consultation with PETRONAS, shall establish a system for reporting of agreed data. 14.3.4.6

Power Supply The computer shall be equipped with an uninterruptable power supply (UPS) system for back up purposes. Normal operation of the metering system shall not be affected if there is any change from one power source to another.

14.3.5 Sampling and Analysis Requirement The metering system shall be provided with automatic flow proportional sampling system to collect representative sample for the determination of BS&W, average density and for other analysis purposes. Manual spot sampling for back-up purposes should also be made available. The sampling system shall be designed in accordance with guidelines in IP Petroleum Measurement Manual Part VI Sampling Section 2, ISO 3171 and API MPMS Chapter 8 of latest edition.

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As sampling system for the determination of water content is critical especially in upstream activities which eventually determined the net production, due attention must given to the the design and operation in ensuring a representative sampling. For Custody Transfer System, sampler controller and sample monitoring unit should be installed. Selection of sampling point shall be such that the pipeline condition at the selected point is homogeneous. Contractor need to demonstrate by calculation whether additional mixing requirement such as static or jet mixer is required to ensure homogeneity of the liquid prior sampling. Where slugs of water may be experienced, inline water detection probe shall be fitted to detect abnormal levels of water content. For sampling of pressurised liquids, the following should be observed. a. Pressurised cylinders should be lightweight. b. Prior extracting of the liquid either for further transportation or analysis, the samples shall be representative and can be achieved through internal mixing in the cylinder. Integrity of the samples are to be maintained throughout the exercise. c. For pressurized manual sampling, appropriate sample point and sampling cylinder for pressurized liquid is to be used and to ensure that no lighter components of the fluid able to be liberated out of the cylinder

14.3.6 Metering Data The metering data should be made available by PS Contractors at hourly/daily or on request basis. Please refer to Appendix 14..2.

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14.4 TESTING, CALIBRATION AND COMMISSIONING 14.4.1 General Requirement Prior to site installation, a Factory Acceptance Test (FAT) shall be conducted to check the integrity of both the computer software and the mechanical/skid instrumentation. FAT procedures shall be agreed between Contractor and the Vendor prior to the test. During FAT, the electronic and the mechanical instrumentation shall be tested together. Prover system need to be first calibrated and witness by a third party before flow integration test be carried out. It is essential that the vendor shall demonstrate that the equipment was internally tested and in good working order before the Contractor and PETRONAS representatives are invited for the FAT. All FAT results are to be fully documented. Only after successful completion of the FAT can the metering system be accepted and shipped out to the site. On site, further testing shall be carried out prior to the commissioning of the system. Calibration of all instrumentations using SIRIM Berhad’s traceable test equipment shall be carried out. It is the responsibility of the Contractor to ensure that the FAT and Site Acceptance Test (SAT) procedures be made available prior to the tests. PETRONAS may request these procedures to be submitted for review. PETRONAS shall be notified at least three weeks prior to both tests.

14.4.2 Calibration 14.4.2.1

General Liquid Hydrocarbon Custody Transfer and Allocation Metering Systems shall be calibrated with test equipment having certified traceability to international or national standards. Secondary standards or instruments used for calibration of all relevant parts of the metering system shall be calibrated and certified by SIRIM Berhad or any other independent laboratory which can prove such traceability.

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Instrument Calibration All relevant instruments used in the metering system shall be calibrated and certified by the manufacturer which can prove such traceability.

14.4.2.3

Prover Calibration The proving system shall be calibrated at the vendor’s works as part of their system checks and after installation on site, immediately prior to start up. The detail calibration method used will depend on the type of meter proving system.

14.4.2.3.1

Displacement Prover Calibration a) Conventional Pipe Prover Calibration The pipe prover shall be calibrated using water draw or mastermeter method at vendor's work place as part of their system checks. The pipe prover shall also be calibrated by using water draw or master-meter method upon installation on-site for Site Acceptance Test before it is put into service. If master meter method is used, the meter shall be calibrated at site using water draw. Similar method of calibration should be done both at the vendor’s factory and at site. Both calibrations shall be in accordance with the standards as specified in Section 14.7 - References. All pipe prover calibrations shall be witnessed by an independent certification authority and attested to in writing. Test Measures used for the pipe prover volume calibration shall be certified traceable to international or national standards.

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The pipe prover shall be calibrated with at least two separate volumes. Four volumes are preferred. The pipe prover shall be capable of producing corrected volumes for five consecutive runs in any given direction within ±0.01% of the average. The average of the five (5) consecutive round trips volumes shall be used as the base volume of the pipe prover. Pipe prover volume calibration process shall be repeated at a flow rate change of at least 25% to verify the possible leak during the base volume calibration. The corrected volumes for 3 consecutive runs at any given direction shall repeat within ±0.01% of the average. The average volume of these three (3) round trips volumes shall not deviate from newly established prover base volume by more than 0.02%. Copies of the calibration certificates for each of these and all subsequent calibrations shall be documented in the validation report and shall be made available to PETRONAS upon request. These certificates shall show the reference numbers of the sphere detectors. The calibrated volume shall be in SI Units at Standard Reference Conditions. b) Small Volume Prover Calibration The small volume prover shall be calibrated physically using water draw method at vendor's work place as part of their system checks for both the upstream and downstream volumes. The small volume prover shall also be calibrated by using the same method i.e. water draw method upon installation on-site before it is put into service. Both calibrations shall be in accordance with the standards as specified in Section 14.7 - References.

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All small volume prover calibrations shall be witnessed by an independent certification authority and attested to in writing. Test Measures used for the small volume prover calibration shall be certified traceable to international or national standards. The small volume prover shall be calibrated physically for both the upstream and downstream volume if these volumes are used for meter proving. The small volume prover shall be capable of producing corrected volumes for five (5) consecutive runs in any given direction repeatable within ±0.01% of the average. The average of the five (5) consecutive volumes shall be used as the base volume of the small volume prover. Small volume prover calibration process shall be repeated at a flow rate change of at least 25% or greater to verify the possible leak during the base volume calibration. The corrected volumes for 3 consecutive runs in any given direction shall repeat within ±0.01% of the average. The average volume of these three (3) round trips volumes shall be within 0.02% with the newly established base volume. Copies of the calibration certificates for each of these and all subsequent calibrations shall be sent to PETRONAS upon request. These certificates shall show the reference numbers of the optical detectors used in the calibration. The calibrated volume shall be in SI Units at Standard Reference Conditions. 14.4.2.3.2

Master-Meter Prover Calibration The master meter prover shall be calibrated on the same liquid or other liquid as appropriate that will be used during operation of the meter. A linearity curve of the master meter prover should be

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developed at minimum 8 points over the range of the meter to operate. The linearity limit shall be within +/- 0.25% for up to 2 inch meter and +/- 0.15% for meter size greater than 2 inch. The meter factor that is applied to the master meter should be the average value of five (5) consecutive runs repeating within +/- 0.01% of the average. 14.4.2.4 Meter Calibration The first calibration test on each meter shall be performed at Vendor's premises. For each type of meter used, the performance of the meter shall, prior to factory acceptance test, be demonstrated by the Vendor by initial calibration with a suitable medium at minimum 8 points. 5 of these points shall span the “Normal operating range” and 3 points shall span low flow to “Design Minimum”. The Vendor shall issue calibration certificates for the meter calibrated. Each point shall consist of five (5) consecutive runs, the results of which the difference between the highest and lowest meter factor does not exceed 0.025% of the average meter factor. The linearity must be within +/-0.25% over the specified "Normal operating flow range". The vendor or Contractor shall perform final test and calibration during Site Acceptance Test with hydrocarbon against meter prover.

14.4.3 Testing 14.4.3.1

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

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Factory Acceptance Test

14.4.3.2.1

General Check Prior to further test in the factory, a general check on the system is to be carried out. This includes checking of the following items. 1. Dimension check as per approved drawings and standards. 2. Instrument installation and quantity check as per approved drawings and bill of quantity respectively. 3. Availability of all documentations.

14.4.3.2.2

Metering Panel and Instrumentation Equipment Tests 1. All panel and field mounted instrumentation, cabling and the connectors shall be visually inspected for compliance with specifications with regard to segregation of cables, satisfactory access, vents, drains and general good quality of installation work. 2. Calibration checks using precision test equipment shall be performed on all transducers, transmitters, converters, indicators, recorders, gauges and switches, etc. supplied for use with the system. 3. All safety and relief valves shall be tested, set and tagged with the set pressure. 4. An insulation test shall be made on all power supply and instrument cables, and panel wiring using voltage tester. Instruments shall be disconnected during this test which may cause internal damage. All resistance thermometer elements shall be tested for insulation resistance to BS -1904.

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5. A sample of the power circuit breakers shall be tested by simulating a short circuit failure. 6. The control panel shall be fully functionally tested before connection to the skid using appropriate simulators and other test equipment. These tests shall include: b. Panel mounted receiving indicators etc. c. Outputs from panel mounted controls. d. Meter run and prover instruments. e. Computer functional test. f.

Verification of computer calculation and integration accuracy as specified in Section 14.3.4.

g. Interlocks and alarms. h. Checking of power distribution circuits and breakers for correct wiring. i.

Analogue functions shall be calibrated at a minimum of five points rising and five points falling in the range (0%, 25%, 50%, 75%, 100%).

7. All remotely operated valves shall be checked after installation on the metering skid by: a. Manual stroking of the valves to check limit switch actuation and to ensure full operating. b. Local operation to verify phase of electrically operated actuators rotation and functioning of local controls. c. Remote operation and checking of remote position indication and interlocks. d. Noting the time for each valve to fully stroke in each direction.

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8. After connection between the panel and skid, loop checks shall be made on all circuits to check correct wiring and calibration of the system. This shall include checks if all alarms, interlocks, digital and analogue inputs and outputs. 9. A check shall be made on effects of power supply variation by setting all instruments in a normal operating mode and varying the output voltage to upper and lower limits and noting the effect by repeating functional checks. 10. The panel should be heat soaked for a minimum of 100 hours. Records shall be made of temperature at selected points on the panel. Following completion of the heat soak, the loop checks as in item 8 shall be repeated at ambient temperature to ensure that none of the equipment has suffered any thermal effects. A check of microprocessor functional performance shall be made during the soak test (after internal panel temperatures have stabilized). 11. Measurement and records shall also be made on panel maximum power consumption (AC & DC). 12. Data transfer to another system shall be checked for data accuracy, data correctness and redundant switching of communication channel. 13. Spares, if possible should be tested. 14. The simulation test among other thing shall include simulating with at least five different values that cover the minimum and maximum level in the working range of the skid instrument and the computers using test simulators.

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The simulators shall simulate signals connected to the computers input or in any other way to secure a controlled, constant input to the computers. Testing or simulating the different functions of the computers shall include but not be limited to manually input data, printouts, alarms and data transmission between the computers. All calculations by the computers shall be verified by injecting known values to the computers and to compare the result using manual calculation e.g. flow calculation software.

14.4.3.2.3

Flow Testing Calibration 1. Prior to flow test at the vendor's location, all the individual equipment inclusive of mechanical, instrument and computing system has first to be tested. The system shall be connected to suitable pump and test equipment where the following tests be carried out using water or other suitable test medium. a. All meters shall be individually flow tested and proved against the prover at their rated maximum and minimum flows on five points at specified intervals between maximum and minimum. Each point shall consist of five consecutive runs, the results of which the difference between the highest and lowest meter factor does not exceed +0.025% of the average meter factor. The linearity must be within +/-0.25% over the specified "Manufacturer design flow range". b. Observations shall also be made and recorded of: i.

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Pressure drop across strainer.


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SECTION 14 GUIDELINES FOR DYNAMIC LIQUID HYDROCARBON MEASUREMENT ii.

Pressure drop across meter run.

iii.

Pressure drop across prover.

iv.

Density measurement, if applicable.

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Checks shall be made during testing for tightness of shutoff on high integrity and the four-way diverter valves. c. All meter runs shall preferably be flow tested simultaneously (i.e. one metering and one proving) and preferably up to the normal maximum linear capacity of each meter. d. Checks shall be made on the functioning of the flow control valves. e. Checks shall be made on the correctness of the meter proving algorithms. f.

Checks shall be made to ensure correct reports such as meter proving report and metering report (hourly or batch report) generated by the computing system.

g. Checks on the correct functionality of the sampling system to ensure volume collected and accuracy as per number of grabs, accuracy of sampling system, alarms and switching of sampling cylinders. 2. Following completion of the flow testing, the liquid test medium shall be drained and a thorough inspection be carried out on the condition of prover lining and other equipment where possible. 3. Computer simulations shall be carried out whereby all calculations by the computing system shall be verified.

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Site Acceptance Test The Contractor shall provide test procedures for punch list items arriving on site. Other items to be provided shall include but not limited to the following: 1.

Loop diagram and loop checkout sheets.

2.

Full print data base checking.

3.

System functional test procedure and schedule.

The onsite acceptance test shall be considered as an extension of the FAT. Prior to SAT, all wiring termination to be checked and powering of the panel should be carried out by the vendor or authorized vendor’s representative. Some tests carried out during FAT shall also be repeated during SAT. SAT on Custody Transfer Metering System that involved export tax computation should be witnessed by SIRIM. The SAT shall concentrate more specifically on the following: a. Inspection of material and equipment on arrival at site including spares and documentation. If damage occurred during transport, it is important to establish without delay, the extent of the damages and whether it is repairable onsite or necessary to order new materials. Suitable storage of material and equipment should be provided. b. Field calibration of the pipe prover shall be in accordance with API Manual of Petroleum Measurement Standard Chapter 4 - Meter Proving and the requirements stated in these guidelines. All calibration equipment used for prover and other metering equipment shall be traceable to National Standard. All prover calibration on Custody Transfer Metering System that involved export tax computation shall be witnessed by Contractor and SIRIM. PETRONAS at any time may also witness the calibration exercise. The results shall be certified by SIRIM. SUPERSEDE ISSUE:

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c. The metering panel and instrumentation equipment test shall also be repeated which also includes the computations check carried out by the computer system. The calibration exercise carried out on the instrument in this exercise is considered as Validation No. 1. d. The completed meter skid and panel shall be subjected to operational functional test during actual flow condition to demonstrate satisfactory performance at the design flowrates. e. Contractor shall submit project completion report, which should include the first official validation report to PETRONAS within 30 days after system has been commissioned. Before the system is put in operation for official use, approval from PETRONAS shall be obtained.

14.4.4 Commissioning 14.4.4.1

General The installation, commissioning and start-up of the metering system shall be carried out in accordance with the requirements in this section.

14.4.4.2

Installation Quality Assurance The Contractor shall set up an installation and commissioning plan of a system of activities, the purpose of which is to provide assurance and show evidence that the overall quality control shall be effectively maintained. The plan shall be applied systematically to all metering systems, and deviations will not be tolerated.

14.4.4.3

Commissioning Commissioning shall include running-in of all rotating equipment, checking alignment, testing control loops, stroking valves, flushing, hydrotesting, final

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testing of electrical instrumentation systems, purging, drying, inerting etc. usually carried out sequentially on a system basis. Commissioning is completed when the metering system is ready for start-up. 14.4.4.4

Start-up This begins with the introduction of process hydrocarbons not counting where these may have been used previously for pressure testing/purging.

14.5 OPERATION, VALIDATION AND ACCOUNTING 14.5.1 General Requirement Contractor shall operate and maintain the metering system to the highest degree of engineering standard in order to maintain its accuracy and integrity. As such, operating, validation and accounting procedures/manuals shall be prepared by the Contractor and approved (validation and accounting procedures) by PETRONAS before start-up. These procedures shall document all activities that influence the measurement system.

14.5.2 System Operation The Contractor is required to carry out the following essential activities:1. Metering stations shall be operated and maintained in accordance with the manufacturer’s recommendations and approved operation, validation and hydrocarbon accounting procedures. Particular attention shall be given to flow stabilization prior to meter proving, checking of block and bleed valves for leaks. a) Meter Proving Operations for Continuous Flow Measurement System For a newly commissioned metering station with a dedicated meter proving facility in a continuous production system (as distinct from tanker loading), meters shall be proved twice a week at approximately equal intervals between proving. Provided the meter factor scatter is SUPERSEDE ISSUE:

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acceptable to PETRONAS and until a meter factor control chart is established, the frequency may be reduced to once a week or monthly basis. The frequency for proving may be further reduced upon agreement between PETRONAS and Contractor. b) Meter Proving Operations for Batch Measurement System For tanker loading systems, any meter onstream shall be proved at least once regardless of the duration of loading. Additional proving is required on stream(s) where conditions have changed and a ‘prove required’ alarm is triggered. 2. Where meter types other than mentioned in this guideline, the type and frequency of meter proving by the Contractor shall be determined on an individual basis by PETRONAS after consultation with the Contractor. Account shall be taken on the meter type, process fluid and operational load cycle. Where meters employing novel technology are to be used, extra evaluation periods and tests will usually be required before a long-term operational schedule can be determined. 3. Meter factors that are acceptable for use shall be based on the repeatability acceptance criteria of not more than 0.05% of five consecutive runs. Meter factor control chart is to be developed and Meter Factor High and Low limits be established used to verify the acceptability of the meter factor. 4. Pipe provers and small volume provers shall be calibrated at least once a year. Where this is not possible for operational or whatever reasons, longer calibration interval may be considered by PETRONAS. However, those systems that are affected by taxes calculation require SIRIM Berhad’s approval. Inspection of the sphere, checking of sphere size, concentricity etc. should take place prior to calibration. After calibration, the sphere detectors and switches shall be sealed.

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Any maintenance work on the prover that could affect the swept volume e.g. changes of sphere detectors and switches should not be undertaken without prior notice to PETRONAS who will advice if a calibration is required. 14.5.2.1 Operating Manual The Operating Manual shall be prepared for the purpose of providing operational guideline for the operators in performing metering activities. It shall then describe the operation of the system which includes the computers, the skid instrumentation, sampling activities and other operation of the metering system. The manual among other things shall also include what actions to be taken in case of malfunction or alarm on the metering system. The minimum content of the manual shall consist of the following:1. Overall process description. 2. Metering system description. 3. Metering instrument specification. 4. Computer system operation (including the computer read codes) and actions taken on alarms. 5. Metering system operation. 6. Metering sealing procedure. 7. Sampling procedure.

14.5.3 System Validation In order to maintain the reliability and accuracy of the metering system, Contractor shall conduct a periodic calibration and validation of the metering system at a frequency agreed by PETRONAS. For new systems, a monthly validation shall be performed. A new validation frequency can be agreed with PETRONAS after such time the system is stable. The calibration/validation shall be performed in accordance with SUPERSEDE ISSUE:

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the system Validation Manual prepared by the Contractor and approved by PETRONAS. All validation result shall be recorded on the format agreed in the Validation report. The report shall include but not limited to the following:1. As found and as left result of the calibration exercise. 2. System error preferably in accordance with ISO 5168 latest revision. 3. Findings and recommendations. 4. Metering irregularities occurred since then and between the last validations. Validation reports shall then be prepared after each validation and submitted to PETRONAS within 1 month. Any irregularity on the figures generated, resulting from the validation shall be endorsed by PETRONAS. 14.5.3.1

Validation Manual The Validation Manual shall be prepared for the purpose of providing guideline for the verification of the metering system instrumentation. The content of the validation manual shall consist of, but not limited to the following: 1. Brief description of the metering system This shall include a concise description of the design concept of the system and its instrumentation including the computer system. Description as to the function of each individual instrument, its accuracy and location in the system layout, system capacity, flow operating condition and the schematic drawing of the system. Instrument description shall include manufacturer's name and model number, range, accuracy, input/output signal and tag number.

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2. Calibration Procedures The step-by-step calibration procedures for the instruments shall be detailed out for each individual instrument in the system. A set of validation check sheets shall also be included and all readings obtained during each calibration shall be recorded on the check sheets. Adjustment shall be made when a reading is out of tolerance. After any adjustment the complete test shall be repeated. 3. Frequency of Calibration and Inspection Contractor shall detail out the frequency of validation/calibration of each of the metering instruments. 4. Flow Calculation Calculations/formulae used to arrive at the volumetric, mass and heat throughput shall be clearly laid out. All flow constants that are to be used shall be shown in actual units they are used. Where the flow constants are fixed, the actual values and their derivations shall be shown. 5. Metering Irregularity Calculation All types of irregularities on the metering system and methods for the corrections shall be clearly stated. 6. Calibration / Validation Equipment A list of the calibration/validation equipment to be used in the validation exercise shall be provided in the validation manual. All information related to the equipment specification such as its accuracy, repeatability, serial no., and range shall also be provided. The accuracy of the calibration equipment shall be better than the accuracy of the instrument to be validated.

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The equipment shall be traceable to SIRIM or any National Bureau of Standard acceptable to SIRIM. 7. System Error Calculation System error calculation shall be listed in the validation manual and preferably will be in accordance with ISO 5168 latest revision.

14.5.4 System Maintenance The Contractor shall maintain the metering system in order to maintain its accuracy and integrity. The Contractor shall notify and seek PETRONAS approval before any change or modification is made on the metering system. Drawing(s) and sufficient data shall be submitted together with the request for approval. PETRONAS representative(s) shall be invited to witness the maintenance activities on the system modification. All results pertaining to these activities shall then be properly documented. The contractor shall also obtain the vendor's recommended comprehensive spare parts list and priced quotation for parts for commissioning and two years operation.

14.5.5 Security All software and all flow factors, status and alarm information stored in the system shall be protected to prevent loss of information by inadvertent operator action or input power failure. In order to ensure security of data in the computers and other critical instrumentation in the metering system, sealing procedures shall be adhered to. The procedure shall be prepared by the Contractor. Critical instruments such as the computers and critical valves shall be sealed where practically possible to prevent unauthorized entry or manipulation of the computer SUPERSEDE ISSUE:

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system and opening or closing of critical valves at the metering skid. The sample cans of the sampling systems shall be sealed. The seals shall have serial number for easy identification. The last valve downstream of the outlet header or offloading valve shall be sealed as per Custom requirement. The sealing of these identified critical instruments shall be carried out by Contractor’s authorized person and be recorded in a dedicated Sealing Log Book. This logbook shall be kept in the metering control room where PETRONAS will review it on the need basis.

14.5.6 Accounting / Allocation Manual The Accounting/Allocation Manual shall be prepared by Contractor and approved by PETRONAS. The purpose of this manual is to precisely define the way metered and other data are to be used for the determination of sales, allocation and production quantities. The minimum content of this manual shall consist of the following: a) Accounting and allocation concepts. b) Allocation procedure and algorithm. c) Production measurement system. d) Product sampling and analysis. e) Data requirements. f) Mass, volume and heating value calculations. g) Methods to account for irregularities in quantity.

14.5.7 Metering Station Record Keeping 14.5.7.1

Log Books/Records Contractors shall maintain electronic / manual logbook and records of prover system, metering system, meter proving and metering print - out. Records of

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parameters such as meter flow rate, liquid temperature and density shall be kept at the metering station for at least 3 months. All of the logbook / records shall be made available within reasonable time for inspection by PETRONAS. Electronic or manual logbook and records shall be maintained comprising information of the following systems: i) Prover System The Contractor shall maintain a logbook for the prover system detailing all calibrations, sphere detector serial numbers and any maintenance work done on the proving facilities loop and its associated equipment. ii) Metering System A.

Metering Log book A log book for the metering system shall be kept preferably for each meter showing details of: 1. Type, Stream and Tag No. particulars including location and production measured. 2. Totaliser reading(s) where applicable on commencement and cessation of metering. 3. All mechanical or electrical repairs or adjustments made to the meter or its read-out equipment and other parts of the metering system. 4. Metering errors due to equipment malfunction, incorrect operation, etc. including data, time and totaliser readings; both at the time or recognition of an error condition and when remedial action is completed. 5. Alarms, together with reasons and operators response. 6. Any breakdown of meter or withdrawal from normal service, including time and totaliser readings. 7. Replacement of security seals when broken.

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Metering Record A manual / automatic recording should also be kept, at intervals of not more than 1 hour, of the following parameters: •

All meter totaliser readings;

•

Meter flow rates (also relevant meter factors), pressure and temperature, and (if measured continuously) density.

One of these sets of readings should be recorded at 2400 hours, or at the agreed time for taking daily closing figure. Other parameters such as liquid density and percentage of BS & W content should be recorded at agreed interval. iii) Meter Proving Record The Contractor shall also keep a Meter Proving Record for each meter giving the details of each proof run such as prove flow rate, pressure, temperature, meter factor etc. This record shall include a running plot, or similar control chart, so that any undue change or fluctuation in meter factors may be easily detected (see API Chapter 13).

14.5.8 Direct Reporting Contractor shall notify PETRONAS regional office prior to any major maintenance, recalibration work on the metering and proving systems and also other operational related activities. PETRONAS shall also be officially notified, when any abnormal situation or error occurs which could require significant adjustment to the totalised meter throughputs. If a meter is required to be removed for maintenance work or replacement, PETRONAS shall be officially informed detailing the serial number of the meter concerned and the reasons for the action taken.

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

14.6 FINAL PROVISION i.

Final acceptance of the metering system will depend on the successful completion of site acceptance tests during actual flowing conditions at the field site.

ii. Contractor shall submit project completion report to PETRONAS at least 30 days after system has been commissioned for official approval of system usage. iii. PETRONAS reserves the right to make more detailed requirements for items mentioned in these guidelines. iv. PETRONAS may in special cases provide exemption from the requirements of these guidelines.

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14.7 REFERENCES PETRONAS Technical Standard •

PETRONAS Procedures/Guidelines for Upstream Activities, Production Operations Section 13 – Guidelines for Well Testing, Production Measurement and Allocation.

•

SIRIM’s Berhad Crirteria Circular - AFLA 1991/01 and 1991/02. API Manual of Petroleum Measurement Standards Chapter 1 – Vocabulary API Manual of Petroleum Measurement Standards Chapter 4 – Proving Systems Section 1 –Introduction API Manual of Petroleum Measurement Standards Chapter 4 – Proving Systems Section 2 – Displacement Provers API Manual of Petroleum Measurement Standards Chapter 4 – Proving Systems Section 5 – Master-Meter Provers API Manual of Petroleum Measurement Standards Chapter 4 – Proving Systems Section 6 – Pulse Interpolation API Manual of Petroleum Measurement Standards Chapter 4 – Proving Systems Section 7 Field – Standard Test Measures API Manual of Petroleum Measurement Standards Chapter 4 – Proving Systems Section 8 – Operation of Proving Systems API Manual of Petroleum Measurement Standards Chapter 5 – Metering Section 1 – General Considerations for Measurement by Meters API Manual of Petroleum Measurement Standards Chapter 5 – Metering Section 2 – Measurement of Liquid Hydrocarbon by Displacement Meters API Manual of Petroleum Measurement Standards Chapter 5 – Metering Section 3 – Measurement of Liquid Hydrocarbon by Turbine Meters API Manual of Petroleum Measurement Standards Chapter 5 – Metering Section 4 – Accessory Equipment for Liquid Meters API Manual of Petroleum Measurement Standards Chapter 5 – Metering Section 5 – Fidelity and Security of Flow Measurement Pulsed-Data Transmission Systems

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API Manual of Petroleum Measurement Standards Chapter 5 – Metering Section 6 – Measurement of Liquid Hydrocarbon by Coriolis Meters API Manual of Petroleum Measurement Standards Chapter 5 – Metering Section 8 Measurement of Liquid Hydrocarbon by Ultrasonic Flow Meters using Transit Time Technology API Manual of Petroleum Measurement Standards Chapter 6 – Metering Assemblies API Manual of Petroleum Measurement Standards Chapter 7 – Temperature Determination API Manual of Petroleum Measurement Standards Chapter 8 – Sampling API Manual of Petroleum Measurement Standards Chapter 9 – Density Determination API Manual of Petroleum Measurement Standards Chapter 10 – Sediment and Water API Manual of Petroleum Measurement Standards Chapter 11 – Physical Properties Data. API Manual of Petroleum Measurement Standard, Chapter 12 – Calculation of Petroleum Quantities. API Manual of Petroleum Measurement Standards Chapter 13 – Statistical Aspects of Measuring and Sampling API Manual of Petroleum Measurement Standard, Chapter 15 – Guidelines for the Use of the International System of Units (SI) in the Petroleum and Allied Industries API Manual of Petroleum Measurement Standards Chapter 20 – Allocation Measurement API Manual of Petroleum Measurement Standards Chapter 21 – Flow Measurement Using Electronic Metering System API Standard 2534 - Measurement of Liquid Hydrocarbon by Turbine Meter Systems. BS 5233 : -1975 'Glossary of Terms used in Metrology ',1st edition 1975. SUPERSEDE ISSUE:

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BS 1904 'Specification for Industrial Platinum Resistance Thermometer elements'. IEC 751 : 1983 'Industrial platinum resistance thermometer Sensor', 1st edition 1983. IP Petroleum Measurement Manual, Pan VI Section 2 A Guide To Automatic Sampling of liquid from pipelines July 1987. IP 252/76 Petroleum Measurement Manual, Part XIII Section 1 Fidelity and Security of measurement - Data Transmission for fluid metering system. IP Petroleum Measurement Manual, Part VII Section 2 Continuous Density Measurement tentative Sept. 1979. IP 201/64 Petroleum Measurement Manual, Part 1- Calculation of Oil Quantities. IP Petroleum Measurement Manual, Part VI1 Section 2- Guide to Automatic Sampling. ISA Standard S 5,1 1983 'Instrumentation Symbols and Identification'3rd edition. ISO 1000 : 1981 'Sl Units and recommendations for the use of their multiples and of certain other units'- 2nd edition 1981. (Latest 3rd Edition 1992-11-01 Amendment 1 1998-11-01) ISO 1998-6 Petroleum Industry – Terminology – Part 6: Measurement – First Edition ISO 2714 Liquid hydrocarbons - Volumetric measurement by displacement meter systems other than dispensing pump ISO 2715 Volumetric measurement by turbine meter systems ISO 3170 Petroleum liquids – Manual sampling ISO 3171 Petroleum liquids - Automatic pipelines sampling ISO 4124 Liquid Hydrocarbons – Dynamic measurement – Statistical control of volumetric metering systems ISO 4267-2 Petroleum and liquid petroleum products – Calculation of oil quantities – Part 2: Dynamic measurement

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ISO 5024 Petroleum liquids and liquefied petroleum gases – Measurement – Standard reference conditions ISO/TR 5168 Measurement of fluid flow – Evaluation of uncertainties ISO 6551 Petroleum liquids and gases – Fidelity and security of dynamic measurement – Cabled transmission of electric and/or electronics pulsed data ISO 7278-1 Liquid hydrocarbons – Dynamic measurement – Proving systems for volumetric meters – Part 1: General principles ISO 7278-2 Liquid hydrocarbons – Dynamic measurement – Proving systems for volumetric meters – Part 2: Pipe provers ISO 7278-3 Liquid hydrocarbons – Dynamic measurement – Proving systems for volumetric meters – Part 3: Pulse interpolation techniques ISO 7278-4 Liquid hydrocarbons – Dynamic measurement – Proving systems for volumetric meters – Part 4: Guide for operators of pipe provers ISO/TR 9494 Petroleum liquids – Automatic pipeline sampling – Statistical assessment of performance of automatic samplers determining the water content in hydrocarbon liquids ISO 10790 Measurement of fluid in closed conduits – Guidance to the selection, installation and use of Coriolis meters (mass flow, density and volume flow measurements) ISO/TR 12765 Measurement of fluid in closed conduits – Methods using transit-time ultrasonic flowmeters ISO/TC28/SC2 - 24E July 1972 - Glossary of Measurement Terminology.

- END OD SECTION 14 -

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SECTION 15 GUIDELINES FOR GAS MEASUREMENT Executive Summary These guidelines provide the minimum requirement for the establishment of a Gas Custody Transfer and Allocation Metering Systems and also the information that are required to be submitted and shall be regarded as PETRONAS'general minimum requirements necessary while ensuring accuracy, safety and integrity of the metering systems based on best oilfield practices, internationally recognised codes and standards and applicable Malaysian laws. In cases where the requirements and frequencies are not specifically stated in these guidelines, PS Contractor shall derive the scopes and frequencies based on best oilfield practices, internationally recognised codes and standards and applicable Malaysian laws, and shall implement the same accordingly.

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15.1 INTRODUCTION These guidelines shall be read as part of the Main Documents, Production Operations Section 13: Guidelines for Well Testing, Production Measurement and Allocation.

15.1.1 Scope These guidelines provide the minimum requirements in the design, installation, testing, commissioning, operation and maintenance of Gas Custody Transfer and Allocation Metering System. Unless otherwise specified, the guidelines mentioned hereunder are applicable for both Custody Transfer and Allocation Metering Systems. The objective of these guidelines are to ensure that all Gas Custody Transfer and Allocation Metering Systems are designed, installed, tested, commissioned, operated and maintained in accordance with the minimum requirements of PETRONAS for accurate measurement of gas.

15.1.2 Distribution, Intended Use and Regulatory Considerations Unless otherwise authorised by PETRONAS, the distribution of these guidelines are confined to companies forming part of PETRONAS and PETRONAS’s Production Sharing (PS) Contractors or their nominated third party for the above scope of work. These guidelines are intended for use by all involved in the design, installation, testing, commissioning, operation and maintenance of Gas Custody Transfer and Allocation Metering Systems in PETRONAS, its PS Contractors or their nominated third party. It is the responsibility of the respective PS Contractor or Contractor as referred to in this guidelines, to ensure that these guidelines are followed if, wholly or partly, the above scope of work are outsource or contract out to any third party or parties. In developing oil and gas fields that straddle with neighbouring countries, if the co host country have its local regulations, the Contractor shall determine by careful scrutiny which of the requirements are more stringent and which combination of the requirements will be acceptable as regards to safety, environmental and economic SUPERSEDE ISSUE:

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aspects. In all cases the Contractor shall inform PETRONAS of any deviation from the requirements of these guidelines which are considered to be necessary in order to comply with the neighbouring countries local regulations. PETRONAS may then negotiate with the Malaysian Authorities and the respective Authorities concerned with the objective of obtaining agreement to follow these guidelines as closely as possible and also to be cost effective.

15.1.3 Definitions 15.1.3.1

General definitions The Contractor refers to the Production Sharing Contractors which sign the Production Sharing Contract with PETRONAS in respect of the exploration, exploitation, winning and obtaining of petroleum resources in the Contract Area on the terms and conditions set out in the said contract. The Vendor is the party which manufactures or supplies equipment and services to perform the duties specified by the Contractor. The word Shall indicates a requirement. The word Should indicates a recommendation.

15.1.3.2

Specific definitions Accuracy - The measure of the closeness of a measurement to the true value. Allocation Gas Metering System - A measuring system comprising mechanical, instrument and computer parts whose registered measured quantity is used for allocation between two or more parties, which involved in sharing the same facilities for their operation. This system normally has an uncertainty of +/-2%.

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Automatic Sampler - A system which, when installed in a pipe and actuated by automatic control equipment, enables a representative sample to be obtained from the fluid/gas flowing in the pipeline. The system generally consists of a sampling probe, a sample extractor, an associated controller and a sample receiver. Normally it is also equipped with a sampler performance monitoring device. Computer Part – That part of the metering system that consists of digital computers and receives digital signals from A/D converters or from digital instrument loops. Custody Transfer Gas Metering System - A measuring system comprising mechanical, instrument and computer parts whose registered measured quantity is used for sale where there is a change in ownership. This system normally has an uncertainty of +/-1 %. Flow Coefficient - The same as flow coefficient mentioned in ISO 5167 latest edition. Flow Computer - is an arithmetic processing unit and associated memory device that accepts electrically converted signals representing input variables from a liquid measurement system and performs calculations for the purpose of providing flow rate and total quantity data. Gross Heating Value - Mass Based - The number of heat units liberated when unit mass of a product in the vapor phase at standard temperature and pressure is burned completely in air saturated with water vapor. The gaseous products of combustion are brought to the same standard conditions for temperature and pressure but the water produced is condensed to liquid in equilibrium with water vapor. Instrument Loop - Includes all elements that form part of the measurement of each individual quantity from sensor to input of the A/D converter or input of digital signal to the computer part.

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Linearity - The deviation or spread of calibration data points from an acceptable straight line over the defined flow range. Meter run - A flow measuring device complete with associated strainers, entry/exit pipework, upstream and downstream straight lengths, flowmeter and flow straighteners. Minimum Meter Flow Rate - The minimum rate of flow recommended by the meter manufacturer or authorised by a regulatory body. The minimum rate is determined by considerations of accuracy, repeatability and linearity. Maximum Meter Flow Rate - The maximum rate of flow recommended by the meter manufacturer or authorised by a regulatory body. The maximum rate is determined by considerations of accuracy, durability, pressure drop, repeatability, and linearity. Online Gas Density Meter - A density meter also known as densitometer, operating on a representative sample of the process material withdrawn continuously from the process line or vessel via a sampling system. Orifice Plate - The same "orifice plate" as mentioned in ISO 5167 latest edition. Repeatability - The quality which characterizes the ability of a measuring instrument to give identical indications or responses, for repeated applications of the same value of the measured quantity under stated conditions of use. Reynold Number - Dimensionless parameter expressing the ratio between the inertia and viscous forces (ISO 5167 - 1:2003 (E)). Sampling - An exercise in accordance to procedure that is carried out either automatic or manual to obtain a sample that is representative of the contents of any pipe, tank or other vessel and to replace that sample in a container from which a representative test specimen be taken for analysis.

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Standard Reference Conditions - Standard reference conditions for pressure and temperature shall be 101.325 kPa (abs) and 15 Degrees C respectively, in accordance with ISO 5024. Station Computer - is an arithmetic processing unit and associated memory device which sends commands and accepts calculated data from Flow Computer and Prover Computer for Station Totalisation computation and archiving. Uncertainty - The part of the expression of the result of a measurement which states the range of values within which the true value of, if appropriate, the conventional true value is estimated to fall.

15.1.4 Abbreviations AC

- Alternating Current

A/D

- Analogue to Digital

AGA

- American Gas Association

API


BS

- British Standards Institution

CCR

- Central Control Room

DC

- Direct Current

DP

- Differential Pressure

FAT

- Factory Acceptance Test

GHV

- Gross Heating Value

IP

- The Institute of Petroleum

IEC

- International Electrotechnical Commission

ISA

- Instrument Society of America

ISO

- International Organization of Standardization

LCR

- Local Control Room

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MPMS

- Manual of Petroleum Measurement Standard

NBS

- National Bureau of Standard

NEC

- National Electricity Code

PID

- Piping and Instrument Drawings

RTD

- Resistance Thermal Detector

SI

- International System of Unit

SIRIM

- Standard Industrial Research Institute of Malaysia

STC

- Site Testing and Commissioning

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15.2 GENERAL REQUIREMENTS 15.2.1 Units of Measurement The base (reference or standard) condition for metering system shall be in Sl units in accordance with the ISO 5024 latest revision whose base conditions are defined as pressure of 101.325 kPa (abs) at temperature 15oC. Where imperial unit such as barrel is required, it shall be converted from the base Sl unit and referenced to 14.696 psia and 60oF. Gas measurement shall be either in volumetric, mass or energy units. The units shall be SI units.

15.2.2 Approval Requirements PETRONAS approval shall be obtained for measurement and allocation concept and metering project implementation as per Items 5.2.2.1 and 5.2.2.2, respectively. Item 5.2.2.3 specifies the government’s approval that is required to be complied by Contractors.

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Measurement and Allocation Concept Proposed Measurement and Allocation concept shall be submitted for PETRONAS evaluation and approval. The concept shall be submitted and agreed during the Field Development Design stage. Contractor shall carry out the financial exposure and cost benefit analysis during the evaluation of the concept and to determine the location for the installation of the metering system, metering system configuration and the level of accuracy required. To facilitate the above approval, preliminary submission to PETRONAS shall include but not limited to the following items. 1. Measurement philosophy 2. Product allocation principles. 3. Measurement methods and standards. 4. Proposed system accuracy. 5. Production accounting exposure analysis. 6. Project cost estimates. 7. Field area and installation layout with main pipelines. 8. Proposed sizing of the metering system. 9. Preliminary system configuration. The metering system can either be used for Custody Transfer or Allocation purpose. Two categories of metering system fall under the purview of these guidelines. a) Custody Transfer Metering System - This type of system is normally of high accuracy and designed with an uncertainty of +/- 1%, used for custody transfer application i.e. transfer of ownership. The figure registered from this system is used for sales determination. b) Allocation Metering System - This type of metering system has slightly lower accuracy than the Custody Transfer Metering System and normally designed with an uncertainty of +/-2%. This type of system is used for

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allocation of gas between fields of different ownership sharing a common facility or facilities. Allocation method normally used is by “full allocation” i.e. where metering systems are installed in all PSC parties involved in sharing the same facilities. However, the uncertainty of the metering system can also be designed to be of custody transfer quality standard i.e. +1% if “measurement by difference” allocation concept being adopted. However, factors such as gas reserve, investment cost and impact are to be considered and agreed by all related parties before this allocation concept is adopted. Generally two main measurement concepts currently are acceptable for the above purpose namely, 1. Measurement by difference method. 2. Full allocation. Only upon PETRONAS agreement on the measurement and allocation concept, Contractors can proceed on procuring of the relevant metering systems in accordance to these guidelines. It is the responsibility of the Contractor to obtain agreement from their equity partner and the interested party or parties that will be affected with the metering system installation, before the concept is submitted for PETRONAS agreement. 15.2.2.2

Metering Project Implementation PETRONAS will also request the following information to be submitted for approval prior to the release of bid package: a) System specification. b) Design formula and calculation. c) Calculation of overall accuracy and uncertainty of the system. d) Relevant drawings. e) Other relevant information.

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PETRONAS may also request the Project Definition Manual be submitted prior to commencing the fabrication of the metering system and will inform Contractor if other information is required. Prior to the official use of the metering system, Contractors shall submit an application together with all the relevant data for PETRONAS to review and PETRONAS will provide the approval after having satisfied with the system performance either from the data submitted or after visiting the installation site. Metering system installed shall be traceable to SIRIM Berhad’s standard. Contractors shall also submit to PETRONAS for approval the hydrocarbon allocation and accounting and as well as the validation procedures. The operation procedure will be requested on the need basis. 15.2.2.3

Government regulatory requirement Contractors shall ensure that the Department of Safety and Health (DOSH) approval is obtained should the fabrication and testing of the metering system be carried out in Malaysia. Approval should also be obtained if the system is to be installed and operated onshore.

15.2.2.4

Deviations Any deviations from these guidelines with respect to the measurement and allocation concept, design, operations and maintenance of the metering system shall require PETRONAS prior approval.

15.2.3 Documentation Contractor should establish and maintain an up-to-date file containing all specifications, calculations and drawings (as-built). The file should also contain reports concerning verification revisions, design, fabrication, installation and commissioning including inspection and testing programs and operation manual for all fixed and temporary phases, and other relevant documentation.

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Contractor shall ensure that all documentation during the metering project implementation are timely available such as the project definition manual including the uncertainty analysis, factory and site acceptance test procedures and its result and as well as project completion report. PETRONAS may request some of this information on the need basis. The Contractor should maintain up-to-date lists of current documentation and documentation under preparation. Contractor’s internal control system including the documentation should also be made available to ensure the quality of the metering systems is maintained.

15.3 DESIGN 15.3.1 General Requirement The gas metering system shall be designed and constructed in accordance with the industry and international standards and shall be capable of measuring minimum and maximum flowrates (using mass based computations) at the expected system throughput with parallel meter runs and with the provision of one standby meter run. Should the system is a less critical system, standby meter run may not be necessary. However, prior approval shall be obtained from PETRONAS as per Section 15.2.2 Approval Requirements The system shall have common inlet and outlet header with system of valves to facilitate inspection and maintenance. No bypassing of the metering system is allowed for normal operations after start-up. Instrumentation to measure flow, line pressure, line temperature and density shall be provided for each meter run. Density calculation using component can be an alternative means in the event that direct measurement by the instrumentation is not possible. These instruments shall have back up facilities in case of failure. Local read out indicators, recorders or solar flow computer should also be made available on each SUPERSEDE ISSUE:

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meter run. Use of multi-stream flow computer for backup shall come with dedicated power supply from separate source. Metering stations should be designed to minimize the probability of liquid carry-over into the metering station and from any condensation or separation that would have significant effect on measurement uncertainties. Where new technology other than orifice plate or ultrasonic metering are to be deployed, details of proposed equipment, layout and verification procedures should be discussed with PETRONAS in advance. A control room should be made available to station the computational facilities to continuously compute the volume and the mass. The energy value of gas delivered shall be computed by multiplying the total mass over a period of time by the average Gross Heating Value (GHV) of the gas during the same period of time as above. The composition of the gas GHV (mass based) shall be determined by using an on-line Gas Chromatograph or through flow proportional sampling and lab analysis. The Sl unit shall be used and the heat content of the gas shall be expressed in Megajoules at Standard Reference Conditions. In addition to lifting pad eyes and drip pan, the metering system shall also be designed with access stairs and walkways for operation, maintenance and calibration. Piping shall be arranged in such a manner to avoid tripping or overhead problems. A typical flow scheme is contained in Appendix 15 of this guideline.

15.3.2 Mechanical Requirement and Primary Element 15.3.2.1

Orifice Meter Orifice meter design and installation shall be in accordance with ISO 5167 latest edition unless otherwise specified in this guideline. Proposals to

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implement new requirements contained within the latest revision of ISO 5167 for existing metering systems, either partially or in full, should be discussed with PETRONAS prior to implementation. 15.3.2.1.1

Orifice plate and fitting 1. The minimum diameter ratio (Beta Ratio) shall not be less than 0.2 and the maximum allowable shall not exceed 0.6. 2. Maximum differential pressure of 0.5 bar is preferred. Higher differential pressure may be used where it is demonstrated that the conditions of items d. and e. mentioned below are met. Deformation calculation shall be calculated for the worst case condition if the meter forms part of the blowdown system. 3. Orifice plate shall have the thickness as determined in ISO 5167 latest revision. 4. The deformation of the orifice plate at maximum differential pressure shall be less than 1% (i.e. not exceeding flatness limit). When measured on bench, the flatness shall be within 0.5%. 5. The uncertainty in flow caused by elastic deformation of the orifice plate shall be less than 0. 1%. 6. The upstream and downstream pressure tapping shall be in the same axial plane in accordance with direction stated in ISO 5167 latest edition. 7. Carrier for the Orifice Plate should be of the type so that the plate may be changed or removed for routine inspections without depressurising the line.

15.3.2.1.2

Meter Tubes Upstream and downstream pipe length from the orifice plate shall have the lengths as specified in "Zero additional uncertainty".

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The tube should be installed in a manner so that it can be disassembled for inspection and maintenance of the inner wall both upstream and downstream of the Orifice Plate. The meter-tube should be externally insulated to minimize the heat transmission or loses to or from the surroundings to ensure temperature stability. The density tapping line and other line (e.g. Temperature Transmitter), that form part of the density calculation shall be fully insulated to minimize the errors. The use of flow straightening vanes, drain and vent holes in the meter tubes shall follow the recommendations as stipulated in ISO 5167 latest edition. Upstream pipe run between primary device and first upstream fitting or disturbance may be made up of one or more sections of pipe as per ISO 5167 latest edition. It must be ensured that the diameter step between any two sections does not exceed 0.3% of the mean value of D, i.e. pipe diameter which is measured in accordance to ISO 5167 latest edition. 15.3.2.1.3

Valves and Fittings Both ends of gas meter run shall be provided with block and bleed valves for isolation and may be either through conduit gate or full bore ball valves. The gas isolation system shall be designed such that differential pressure across the orifice plate does not exceed 1 bar during pressurisation and depressurisation. Equalizing line and valves shall be provided by passing across the inlet valve for pressurising/equalising and depressurising the meter run. The gas metering station shall be provided with a vent system. Individual connections to this system shall be taken from downstream of the office meters. Each connection shall be provided with dual block valves and a pressure gauge located in between the block valves.

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Gas Ultrasonic Flow Meter (Multipath) The design of a gas metering system should follow the ISO/TR 12765 and AGA 9 and specific recommendations from the meter manufacturer. The use of this type of meter is subject to PETRONAS approval.

15.3.2.2.1

General Requirements. The ultrasonic meters to be used shall have sufficient number of sound path, which is proven to provide a representative gas velocity measurement covering the cross section of the pipe at the relevant flow conditions. Meters shall be installed in accordance with field proven installation practices. It shall also be installed such that no accumulations of liquid or particles could possibly occur in the vicinity of the transducers that could affect its performance. Piping arrangement for the meter or the construction of the meter itself shall allow inspection and necessary maintenance on the meter to be carried out. The transducer shall be retrievable and with the removal a pair of the transducer’s, the uncertainty of the meter shall be within tolerable limit. All the pair transducers shall be tagged accordingly. Facility for the detection of malfunction of the meter such as transducer failure should also be provided. Low flow alarm shall be indicated when meter starts to operate below its specified minimum flowrate. System diagnostic shall be provided for performance monitoring of the meter. Tampered free computing feature should be provided to log the required data.

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Precautionary measures should be taken if carbon dioxide (CO2) levels are expected to approach 8% or if the meter is operating near the critical gas density. The presence of high levels of some component in the gas e.g. CO2, can influence and possibly inhibit the operation of the meter. 15.3.2.2.2 Meter Tubes The number of meter tubes shall be based on a design capacity and spare run shall be provided for custody transfer metering system. As for the allocation metering, the spare run requirement is dependent upon the criticality of the system. However, a minimum set of a pair offline transducer shall be made available. The minimum upstream pipe length shall be 10D with upstream flow conditioner and the minimum downstream pipe length shall be 5D. For bidirectional applications, both ends of the meter should be considered “upstream”. It shall be further verified that the piping upstream and downstream of the meter will not resulted in the measurement uncertainty as mentioned in Section 2.2.1 is exceeded. Flow straighteners of recognised standard can be installed, if necessary. Meter manufacturer shall be consulted on the installation location such as, the meter not to be installed near a pressure reduction system (e.g. valves), and the surrounding equipment will not affect the ultrasonic signals. Proper evaluation needs to be carried out. 15.3.2.3

Other Meters Used of other types of meter than orifice plate and gas ultrasonic flowmeters shall be subjected to PETRONAS prior approval.

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15.3.3 Instrument Requirement 15.3.3.1

Field Instrumentation

15.3.3.1.1

Instrument loop The instrument loops shall be kept separate from other types of instrumentation and power supply cabling in the area of use. Cables and junction boxes shall not be shared with instrument loops that are not part of the metering system. Cables and other part of the instrument loops shall be designed and installed so that they will not be affected by electromagnetic fields.

15.3.3.1.2

Differential Pressure Measurement If the relative measuring uncertainty at the lowest operational differential pressure exceeds +/- 0.7%, each meter tube shall have more than one transmitter, each covering a part of the total differential pressure range in the system. In addition, there shall be a check differential pressure cell connected to the computer part, which shall generate an alarm if the difference in readings from pay and check cell exceeds a set limit. The signal from the Pay transmitter shall normally be used in the mass flow computation. In the event of failure on Pay transmitter, the Check transmitter will be used. The system shall also be designed in such a way that auto switching over is provided between the Low and the High DP (Differential Pressure). The impulse lines connecting the meter's static and differential pressure sensors shall be as short as possible and the upstream and downstream pressure tapping shall be in the same axial plane and shall not be below the central axis of the meter tube.

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1. Installation requirement. The differential pressure sensor transmitter shall be installed vertically upright. The impulse lines shall have a downward gradient or tilt angle and shall also be provided with a condensate trap. The DP sensor/transmitters shall be protected against weather and vibration. The manifolds valves and pipe assemblies shall be designed for isolation purposes, maintenance and shall also have the provision for on-line calibration. 2. Accuracy Requirement Differential pressure loop shall have an accuracy better than 0.25% of span. 15.3.3.1.3

Density Measurement Gas density at the meter may be determined by continuous direct measurement using a densitometer or calculation based on equation of state with the measurements of the gas temperature, pressure and composition. However, both methods can be used for the “pay” and “check” function. Minimum requirements for density measurement using both methods are as follows: 1. General Requirement Each meter run shall be provided with the facility to measure the online density. The position of the densitometer shall be such that the density of the gas is measured at line temperature and pressure. The output signal from the densitometer shall be in the form of frequency. The densitometer shall be provided with facilities for online calibration without removing the unit from its mounting.

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2. Installation Requirement The densitometers shall be installed as near as possible to the density sample probe, downstream of the orifice, in a pocket. Density samples shall be extracted at a point 8D downstream of the orifice and returned to the flange tap downstream, in accordance with the I.P. Petroleum Measurement Manual Part VII Density Section 2. The built-in RTD shall be used for indication purpose only. The complete system shall be insulated against heat loss. 3. Accuracy Requirement The accuracy for the complete density circuit using vacuum check method shall be within 80 nanoseconds. 15.3.3.1.4

Temperature Measurement 1. General Requirement The temperature measurement shall be made using a 4 wire platinum RTD in accordance to IEC 751 (1983) "Tolerance Class A" or equivalent. The temperature measuring device shall be located downstream of the orifice plate close to the densitometer. 2. Local Indicators Local Indicators for the line temperature should be provided for each meter run. 3. Installation Requirement A thermowell should be installed adjacent to every electronic temperature sensor or group of sensors for calibration.

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4. Accuracy Requirement The accuracy for the complete circuit shall be better than ±0.15oC. 15.3.3.1.5

Pressure Measurement 1. General Requirement The static pressure tapping shall be in accordance with the ISO 5167 latest edition whereby it is located in the plane of the upstream pressure tapping. It shall be preferably separated from the tapping provided to measure the differential pressure 2. Local Indicators Local Indicator for the gauge pressure should be provided for each meter run. 3. Installation Requirement The location for the local Indicator shall be close to the static pressure transmitter tapping. 4. Accuracy Requirement Better than ± 0.25% of span.

15.3.3.1.6

Local Recorders 1. General Requirement For orifice meter, local recorders shall be installed at the metering skid to give a local readout and act as a backup unit to the flow computer. It can be either a chart recorder or an independently powered flow computer (e.g. solar powered, multi-stream flow computer, etc.);

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Local recorder inputs or inputs to the independently powered flow computer for the differential pressure, line temperature as well as the line pressure shall be provided in each meter run in order to facilitate the computation of the mass and volume throughput for the particular line in case of failure of the main computer. 2. Installation Requirement The local recorders shall be located at the metering skid and shall be sheltered. 15.3.3.2 Control Room Instrumentation Instruments that are sensitive to temperature or other environmental factors should be installed where these factors can be controlled.

15.3.4 Computer Based Monitoring and Control Functions Requirements 15.3.4.1

General Gas metering computation shall be managed by a computer system. This system shall be installed in the CCR, LCR or local equipment room. Normally, separate computers should be dedicated for the metering runs, and the station control. However, the functionality of the computers may be combined if it can be demonstrated that the required reliability, availability and redundancy standards will be met. However, such arrangements have to be agreed by PETRONAS. The computer system is to be designed as follows:1.

The computer part in the metering system shall have no functions other than those involved in the metering. The metering system shall be designed in such a way that the maximum gas flow will be measured.

2.

The system should include at least two independent registers for storing accumulated fiscal quantities for each meter run and the

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station total. It shall not be possible to delete or change these registers by operator encroachment or power failure. 3.

The computer shall also be designed to ensure that cumulative quantities generated during validation/calibration are registered separately from the measured amount.

4.

Manually entered parameter shall be displayed without rounding off or truncation of digits. The display on the computer shall have sufficient resolution to enable the verification for the calculation accuracy as in Section 15.3.4.3 be carried out. Facilities shall be provided to prevent access to computer by unauthorised personnel.

5.

Computer system shall be designed such that the transfer of data to DCS /SCADA/Plant Information (PI) system is permissible and all interfacing requirement such as the handshaking and necessary software is provided.

6.

The computer part shall have and automatic watch over for differences between readings of measured values, for parallel meter runs.

7.

For continuous monitoring of measurement data the computer shall, for each meter run, automatically log and store for at least one year the following data: At intervals of 1 hours cumulative quantities, and average values of pressure, temperature and density. At intervals of 24 hours: cumulative quantities. This information shall be accessible on printout in a clearly set out format using standard computer printer and paper. Access to the logs shall not be possible without the use of key operated switch.

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8.

Gas meter proving algorithm should be available.

9.

Report facility for computer constants, keypad setting should be available.

10.

The computer will have the ability to perform meter curve (foot-print) interpolation for minimum of 8 calibration points.


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Data Security The data transmission of the computer shall be designed in accordance with Level A of the IP Standard 252/76, Part XIII Section 1. The computer shall have a self-diagnostic capability. It shall monitor that the program loops are executed at the correct intervals by means of a watchdog function. The parts of the memory that contain permanent data shall have a periodical check sum control. The algorithms and the fixed parameters important for accurate computation of fiscal quantities shall be stored in non-alterable memory. Security system shall also be provided for manual entering of data. The system shall be designed and features provided for sealing of the computer systems. Program version number be assigned to identify the current program used and this can be determined directly from Video Display Unit (VDU) or print out. The version number can be updated every time permanent program data is altered.

15.3.4.3

Calculation The computer routines for fiscal measurement calculation shall be in accordance to the requirements detailed in the applied standards. It shall also include the followings:1. Update time to changes of input signals to metering system shall not be more than 2 seconds and parameters having response time such as density and temperature shall not exceed 5 seconds.

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2. The interval between each cycle for computation of instantaneous flowrate and accumulated flow shall be less than 10 seconds. 3. Algorithm and rounding off error for computation of fiscal quantities in the flow computer shall be within +/- 0.001 % for totalisation and +/0.01% for flowrate of the computed value. Rounding or truncation shall only be carried out at the end of final computation. 15.3.4.4

Printouts and Hardcopies The computer system shall have dedicated printers for alarms and reports. Common printer can be used if an acceptable priority routine is established. Automatic logging on the following information is to be provided. a) Alarms for faults detected by the computer (date time). b) Inserted parameters/constant, both fixed and changeable. c) Quantity report. d) Instantaneous values of flow rate and measured input parameters. Fixed values which are used instead of live signals shall be identified. The Contractor, after consultation with PETRONAS, shall establish a system for reporting of agreed data.

15.3.4.5

Power Supply The computer shall be equipped with an uninterruptible power supply (UPS) system for back up purposes. Normal operation of the metering system shall not be affected if there is any change from one power source to another.

15.3.5 Sampling and Analytical Instrumentation 15.3.5.1

General Requirements – Sampling Recommendations as specified in ISO 5167 latest edition is to be followed. Delay time calculation shall be performed to ensure that delay time between

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sample point and analyser shall be kept short and at least shorter that the duration of the analytical cycle. 15.3.5.2

On-Line Gas Chromatograph The Gross Heating Value (GHV) (mass based) shall be calculated in Megajoules per kilogram (MJ/kg) at Standard Reference Conditions. Packing materials used in the chromatograph column, carrier gas, valves configuration, and pressure flow regulators shall be of industry standards. The composition shall represent the composition determine according to ISO 6974. The calibration gas composition for the Gas Chromatograph shall be as close as possible to the process gas composition. The controller shall be programmed such that computations are made based on the peak integration of individual components constituting the sample. Hydrocarbon fractions heavier than and including Hexane should be combined and treated as normal Hexane. The analysis shall be normalized to 100 percent and the result expressed in percentage mole fractions. Operating density calculation is normally performed by the computer using the percentage mole fraction from the G.C (Gas Chromatograph). The computer system shall also capable of calculating the followings based on the compositional data according to ISO 6976 latest edition: Compressibility factor at reference condition. Gross calorific value. Wobbe-index. Relative density (real / ideal). Density at reference condition.

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The sampling system shall ensure that gases to GC are representative and any liquid contamination is prevented in the sample tubing. Recommendations as specified in ISO 10715 latest edition is to be followed. The sampling route between the sampling point and the analyser shall be practically as short as possible. 15.3.5.3

Gas Sampler Systems Where no online Gas Chromatograph is installed and Gas Sampler (GS) is used, an automatic Gas Sampler shall be able to collect and store representative gas sample at line condition for transportation and analysis. The system shall be in accordance with ISO 10715. The automatic gas sampler shall be provided with the following monitoring facilities: 1.

Amount of sample collected.

2.

Health status of sampler controller/system

3. Sampler cans in use 15.3.5.4

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

15.4 TESTING, CALIBRATION AND COMMISSIONING 15.4.1 General Requirement Prior to site installation, a Factory Acceptance Test (FAT) shall be conducted to check the integrity of both the computer software and the mechanical/skid instrumentation. FAT procedures shall be agreed between Contractor and the Vendor prior to the test.

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During FAT, the electronic and the mechanical instrumentation shall be tested together. It is essential that the vendor shall demonstrate that the equipment was internally tested and in good working order before the Contractor and PETRONAS representatives are invited for the FAT. All FAT results are to be fully documented. Only after successful completion of the FAT can the metering system be accepted and shipped out to the site. On site, further testing shall be carried out prior to the commissioning of the system. Calibration of all instrumentations using SIRIM Berhad’s traceable test equipment shall be carried out. It is the responsibility of the Contractor to ensure that the FAT and Site Acceptance Test (SAT) procedures be made available prior to the tests. PETRONAS may request these procedures to be submitted for review. PETRONAS shall be notified at least three weeks prior to both tests.

15.4.2 Calibration 15.4.2.1

General Gas Custody Transfer and Allocation Metering Systems shall be calibrated with instruments having certified traceability to international or national standards. Secondary standards or instruments used for calibration of all relevant parts of the metering system shall be calibrated and certified by SIRIM Berhad or any other independent laboratory which can prove such traceability.

15.4.2.2

Meter Calibration / Inspection

15.4.2.2.1

Orifice Meter Inspection and measurement of upstream pipe section (D) adjacent to the orifice plate shall be checked for circularity and cylindricality in accordance to ISO 5167. Inspection shall be conducted by third party and traceable to applicable International standard.

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Ultrasonic Meter The ultrasonic flowmeter when intended to use for Custody Transfer and Allocation purposes shall be first calibrated at a traceable laboratory at conditions near to its operational conditions and a certificate is to be issued. The meter shall be calibrated for at least 5 points over the whole operating range of the meter after which errors curve be generated. The geometric dimensions of the ultrasonic flow meter which affect the measurement result of the gas flowrate shall be measured by traceable equipment and its result be made available on the certificate. Where system diagnostic is used to justify an extension to the interval between meter recalibrations for multi-path ultrasonic flow meters, features and data acquired should be agreed with PETRONAS in advance.

15.4.2.3

Instrument Calibration All relevant instruments used in the metering system shall be calibrated and certified by the manufacturer, which can prove such trace ability.

15.4.3 Testing 15.4.3.1

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

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Factory Acceptance Test

15.4.3.2.1

General Check Prior to further test in the factory, a general check on the system is to be carried out. This includes checking of the following items. 1. Dimension check as per approved drawings and standards. 2. Instrument installation and quantity check as per approved drawings and bill of quantity respectively. 3. Availability of all documentations.

15.4.3.2.2 Metering Panel and Instrumentation Equipment Tests 1. All panel and field mounted instrumentation, cabling and the connectors shall be visually inspected for compliance with specifications with regard to segregation of cables, satisfactory access, vents, drains and general good quality of installation work. 2. Calibration checks using precision test equipment shall be performed on all transducers, transmitters, converters, indicators, recorders, gauges and switches, etc. supplied for use with the system. 3. All safety and relief valves shall be tested, set and tagged with the set pressure. 4. An insulation test shall be made on all power supply and instrument cables, and panel wiring using voltage tester. Instruments shall be disconnected during this test which may cause internal damage. All resistance thermometer elements shall be tested for insulation resistance to BS -1904. 5. A sample of the power circuit breakers shall be tested by simulating a short circuit failure.

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6. The control panel shall be fully functionally tested before connection to the skid using appropriate simulators and other test equipment. 7. These tests shall include: a) Panel mounted receiving indicators etc. b) Outputs from panel mounted controls. c) Meter run and instruments. d) Computer functional test. e) Verification of computer calculation and integration accuracy as specified in Section 3.4. f) Interlocks and alarms. g) Checking of power distribution circuits and breakers for correct wiring. Analogues functions shall be calibrated at a minimum of five points in the range (0%, 25%, 50%, 75%, 100%). 8. All remotely operated valves shall be checked after installation on the metering skid by: - . a) Manual stroking of the valves to check limit switch actuation and to ensure full opening. b) Local operation to verify phase of electrically operated actuators rotation and functioning of local controls. c) Remote operation and checking of remote position indication and interlocks. d) Noting the time for each valve to fully stroke in each direction. 9. After connection between the panel and skid, loop checks shall be made on all circuits to check correct wiring and calibration of the system. This shall include checks if all alarms, interlocks, digital and analogue inputs and outputs.

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10. A check shall be made on effects of power supply variation by setting all instruments in a normal operating mode and varying the output voltage to upper and lower limits and noting the effect by repeating functional checks. 11. The panel should be heat soaked for a minimum of 100 hours. Records shall be made of temperature at selected points on the panel. Following completion of the heat soak, the loop checks as in No. 8 shall be repeated at ambient temperature to ensure that none of the equipment has suffered any thermal effects. A check of microprocessor functional performance shall be made during the soak test (after internal panel temperatures have stabilised). 12. Measurement and records shall also be made on panel maximum power consumption (AC & DC). 13. Data transfer to another system shall be checked for data accuracy, data correctness and redundant switching of communication channel. 14. Spares, if possible should be tested. The simulators shall simulate signals connected to the computers input or in any other way to secure a controlled, constant input to the computers. Testing or simulating the different functions of the computers shall include but not be limited to manually input data, printouts, alarms and data transmission between the computers. All calculations by the computers shall be verified by injecting known values to the computers and to compare the result using manual calculations. 15.4.3.3

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

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1. Loop diagram and loop checkout sheets. 2. Full print data base checking. 3. System functional test procedure and schedule. The onsite acceptance test shall be considered as an extension of the FAT. Prior to SAT, all wiring termination to be checked and powering of the panel should be carried out by the vendor or authorized vendor’s representative. Some tests carried out during FAT shall also be repeated during SAT. The SAT shall concentrate more specifically on the following: a) Inspection of material and equipment on arrival at site including spares and documentation. If damage occurred during transport, it is important to establish without delay, the extent of the damages and whether it is repairable onsite or necessary to order new materials. Suitable storage of material and equipment should be provided. b) The metering panel and instrumentation equipment test shall also be repeated which also includes the computations check carried out by the computer system. The calibration exercise carried out on the instrument in this exercise is considered as Validation No 1. c) The completed meter skid and panel shall be subjected to operational functional test during actual flow condition to demonstrate satisfactory performance at the design flowrates. d) Contractor shall submit project completion report, which should include the first official validation report to PETRONAS within 1 month after system has been commissioned. Before the system is put in operation for official use, approval from PETRONAS shall be obtained.

15.4.4 Commissioning 15.4.4.1

General The installation, commissioning and start-up of the metering system shall be carried out in accordance with the requirements in this section.

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Installation Quality Assurance The Contractor shall set up an installation and commissioning plan of a system of activities, the purpose of which is to provide assurance and show evidence that the overall quality control shall be effectively maintained. The plan shall be applied systematically to all metering systems, and deviations will not be tolerated.

15.4.4.3

Commissioning Commissioning shall include running-in of all rotating equipment, checking alignment, testing control loops, stroking valves, flushing, hydrotesting, final testing of electrical instrumentation systems, purging, drying, inerting etc. usually carried out sequentially on a system basis. Commissioning is completed when the metering system is ready for start-up.

15.4.4.4

Start-up This begins with the introduction of process hydrocarbons not counting where these may have been used previously for pressure testing/purging.

15.5 OPERATION, VALIDATION AND ACCOUNTING 15.5.1 General Requirement Contractor shall operate and maintain the metering system to the highest degree of engineering standard in order to maintain its accuracy and integrity. As such, operating, validation and accounting procedures/manuals shall be prepared by the Contractor and approved (validation and accounting procedures) by PETRONAS before start-up. These procedures shall document all activities, which influence the measurement system.

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15.5.2 System Operation The Contractor is required to operate and maintained the metering stations in accordance with the manufacturers’ recommendations and approved operation, validation and hydrocarbon accounting procedures. 15.5.2.1

Operating Manual The Operating Manual shall be prepared for the purpose of providing operational guideline for the operators in performing metering activities. It shall then describe the operation of the system which includes the computers, the skid instrumentation, sampling activities and other operation of the metering system. The manual among other things shall also include what actions to be taken in case of malfunction or alarm on the metering system. The minimum content of the manual shall consist of the following:1. Overall process description. 2. Metering system description. 3. Metering instrument specification. 4. Computer system operation (including the computer read codes) and actions taken on alarms. 5. Metering system operation. 6. Metering sealing procedure. 7. Sampling procedure.

15.5.3 System Validation In order to maintain the reliability and accuracy of the metering system, Contractor shall conduct a periodic calibration and validation of the metering system at a frequency agreed by PETRONAS. For new systems, a monthly validation shall be performed. A new validation frequency can be agreed with PETRONAS after such SUPERSEDE ISSUE:

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time the system is stable. The calibration/validation shall be performed in accordance with the system Validation Manual prepared by the Contractor and approved by PETRONAS. All validation result shall be recorded on the format agreed in the Validation report. The report shall include but not limited to the following:1.

As found and as left result of the calibration exercise.

2.

System error preferably in accordance with ISO 5167 latest revision.

3.

Findings and recommendations.

4.

Metering irregularities occurred since then and between the last validations.

Validation reports shall then be prepared after each validation submitted to PETRONAS within 1 month. Any irregularity on the figures generated, resulting from the validation shall be endorsed by PETRONAS. 15.5.3.1

Validation Manual The Validation Manual shall be prepared for the purpose of providing guideline for the verification of the metering system instrumentation. The content of the validation manual shall consist of, but not limited to the following: 1.

Brief description of the metering system This shall include a concise description of the design concept of the system and its instrumentation including the computer system. Description as to the function of each individual instrument, its accuracy and location in the system layout, system capacity, flow operating condition and the schematic drawing of the system. Instrument description shall include manufacturer's name and model number, range, accuracy, input/output signal and tag number.

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

3.

Frequency of Calibration and Inspection Contractor shall detail out the frequency of validation/calibration of each of the metering instruments.

4.

Flow Calculation Calculations/formulae used to arrive at the volumetric, mass and heat throughput shall be clearly laid out. All flow constants that are to be used shall be shown in actual units they are used. Where the flow constants are fixed, the actual values and their derivations shall be shown.

5.

Metering Irregularity Calculation All types of irregularities on the metering system and methods for the corrections shall be clearly stated.

6.

Calibration / Validation Equipment A list of the calibration/validation equipment to be used in the validation exercise shall be provided in the validation manual. All information related to the equipment specification such as its accuracy, repeatability, serial no., and range shall also be provided. The accuracy of the calibration equipment shall be better than the accuracy of the instrument to be validated. The equipment shall be traceable to SIRIM or any National Bureau of Standard acceptable to SIRIM.

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System Error Calculation System error calculation shall be listed in the validation manual and will be preferably in accordance with ISO 5167 latest revision.

15.5.4 System Maintenance The Contractor shall maintain the metering system in order to maintain its accuracy and integrity. The Contractor shall notify and seek PETRONAS'approval before any change or modification is made on the metering system. Drawing(s) and sufficient data shall be submitted together with the request for approval. PETRONAS representative(s) shall be invited to witness the maintenance activities on the system modification. All results pertaining to these activities shall then be properly documented. The contractor shall also obtain the Vendor's recommended comprehensive spare parts list and priced quotation for parts for commissioning and two years operation.

15.5.5 Security All software and all flow factors, status and alarm information stored in the system shall be protected to prevent loss of information by inadvertent operator action or input power failure. In order to ensure security of data in the computers and other critical instrumentation in the metering system, sealing procedures shall be adhered to. The procedure shall be prepared by the Contractor. Critical instruments such as the computers, DP transmitters, tapings and critical valves shall be sealed where practically possible to prevent unauthorized entry or manipulation of the computer system and opening or closings of critical valves at the metering skid. The sample cans of the sampling systems shall be sealed. The seals shall have serial number for easy identification.

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The last valve downstream of the outlet header or offloading valve shall be sealed as per Custom requirement. The sealing of these identified critical instruments shall be carried out by Contractor’s authorised person and be recorded in a dedicated Sealing Log Book. This log book shall be kept in the metering control room where PETRONAS will review it on the need basis.

15.5.6 Accounting / Allocation Manual The Accounting/Allocation Manual shall be prepared by Contractor and approved by PETRONAS. The purpose of this manual is to precisely define the way metered and other data are to be used for the determination of sales, allocation and production quantities. The minimum content of this manual shall consist of the following:1. Accounting and allocation concepts. 2. Mass, volume and heating value calculations. 3. Methods to account for irregularities in quantity.

15.5.7 Metering Station Record Keeping 15.5.7.1

Log Books/Records Contractors shall maintain electronic / manual logbook and records of prover system, metering system, meter proving and metering print - out. Records of parameters such as meter flow rate, gas temperature and density shall be kept at the metering station for at least 3 months. All of the logbook / records shall be made available within reasonable time for inspection by PETRONAS. Electronic or manual logbook and records shall be maintained comprising information of the following: a) Metering Log book A log book for the metering system shall be kept preferably for each meter showing details of:

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Type, Stream and Tag No. particulars including location and production measured.

ii. Totaliser reading(s) where applicable on commencement and cessation of metering. iii. All mechanical or electrical repairs or adjustments made to the meter or its read-out equipment and other parts of the metering system. iv. Metering errors due to equipment malfunction, incorrect operation, etc. including data, time and totaliser readings; both at the time or recognition of an error condition and when remedial action is completed. v. Alarms, together with reasons and operators response. vi. Any breakdown of meter or withdrawal from normal service, including time and totaliser readings. vii. Replacement of security seals when broken. b) Metering Record A manual / automatic recording should also be kept, at intervals of not more than 1 hour, of the following parameters: i.

All meter totaliser readings;

ii. Meter flow rates (also relevant meter factors), pressure and temperature, and (if measured continuously) density. One of these sets of readings should be recorded at 2400 hours, or at the agreed time for taking daily closing figure.

15.5.8

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

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If a meter is required to be removed for maintenance work or replacement, PETRONAS shall be officially informed detailing the serial number of the meter concerned and the reasons for the action taken. When correction to meter totalised figures are required due to known metering errors, a formal report shall be submitted to PETRONAS detailing the times of the occurrence, totaliser readings, and suspected causes for the errors occurring.

15.6 FINAL PROVISION 15.6.1

Final acceptance of the metering system will depend on the successful completion of site acceptance tests during actual flowing conditions at the field site.

15.6.2

Contractor shall submit project completion report to PETRONAS at least 30 days after system has been commissioned for official approval of system usage.

15.6.3

PETRONAS reserves the right to make more detailed requirements for items mentioned in these guidelines.

15.6.4

PETRONAS may in special cases provide exemption from the requirements of these guidelines.

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15.7 REFERENCE PETRONAS Procedures/Guidelines for Upstream Activities, Production Operations Section 7.2 - Well Testing, Production Measurement and Allocation. BS 1904: 'Specification for Industrial Platinum Resistance Thermometer elements' IEC 751: 1983 'Industrial platinum resistance thermometer Sensor',1st edition 1983 IP Petroleum Measurement Manual, Part VII Section 2 Continuous Density Measurement tentative Sept. 1979. ISO 1000: 1981 'Sl Units and recommendations for the use of their multiples and of certain other units'- 2nd edition 1981 ISO 5024: l979 'Standard Reference condition for volume, mass and heat’ 1st edition 1979. ISO 6551: 1982 ‘Petroleum liquids and gases - Fidelity and security of dynamic measurement - Cable transmission of electronic and/or electronics pulsed data.’ 1st edition 1982. ISO 5168: 1978 (E) ‘Measurement of fluid flow - Estimation of uncertainty of a flowrate measurement.’ ISO 5167-1: 1991 (E) ‘Measurement of fluid flow by means of pressure differential devices - Part 1: Orifice plates, nozzles and venturi tubes inserted in circular crosssection conduits running full. ISO 6976: ‘Natural Gas - calculation of calorific valves, density, relative density and Wobbe index from gas composition.’ ISO 12765/TR: 1998 ‘Measurement of fluid flow in closed conduits -Methods using transit-time ultrasonic flowmeters.’ ISO 10715: 1997 ‘Natural gas - Sampling guidelines’ AGA 9: 1998 ‘Measurement of Gas by Multipath Ultrasonic Meters.’ AGA 8: 1985 ‘Compressibility Factors for natural gas and other related hydrocarbon gas.’ ISO 12213: 1997 ‘Natural gas - calculation of compression factor.’ ISO 6974-1984(E): ‘Natural Gas - Determination of hydrocarbon, inert gases and hydrocarbons up to C8 - Gas chromatographic method.’ -END OF SECTION 15-

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SECTION 16 GUIDELINES FOR DECOMMISSIONING OF UPSTREAM INSTALLATION Executive Summary This section provides guidelines and minimum requirement for decommissioning of upstream installation.

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16.1 INTRODUCTION Since 1976, PETRONAS, the national oil corporation, had entered into several Production Sharing Contracts (PSC) with various oil companies for the exploration and exploitation of petroleum resources in Malaysia. PETRONAS as custodian and statutory manager of the national petroleum resources in Malaysia, is obligated to address the process of decommissioning of all disused upstream structures and installations that have ceased to accommodate oil and gas production or are at the end of their design life consistent with the national laws and international conventions. PS Contractors conducting platform decommissioning pursuant to their PSC shall comply with these guidelines. These guidelines may be expanded or amended from time to time upon written notice by PETRONAS. All additions or amendments are to be in consultation with the PS Contractors. When amendments are made to the guidelines, PETRONAS shall consider the incremental expenditures that may be required to comply with such amendments. PS Contractors will be granted sufficient time from the effective date to make necessary revisions to the Work Programme and Budget and to conduct the decommissioning operations in accordance with the amended guidelines. PS Contractors may request for exceptions to these guidelines in their decommissioning plans. Such exceptions may be granted at the sole discretion of PETRONAS taking into account safety of navigation, environment, efficiency and prudent practice.

16.1.1

Definitions a)

Onshore (Land and Territorial Sea) Land and inclusive of areas falling within 12 nautical miles from low later line of the official coastal line (Please refer to Appendix 16.5).

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Shallow Water Offshore areas falling beyond 12 nautical miles from low water line of the official coastal line and no greater than 200 meters in depths. (Please refer to Appendix 16.6).

c)

Deepwater Offshore areas, which are more than 200 meters in depth (Please refer to Appendix 16.7). Please refer to Appendix 16.1 for the schematic definition of the above areas.

16.2 OBJECTIVE OF THE GUIDELINES The purpose of these guidelines is to provide guidance for all PS Contractors to ensure that all activities pertaining to the decommissioning of any disused upstream structures and installations shall be consistent with the terms of the PSC, national / local laws and international conventions. The scope of these guidelines covers the abandonment of wells, and decommissioning of pipelines, and facilities.

16.3 DECOMMISSIONING PHILOSOPHY AND REQUIREMENT 16.3.1

PETRONAS’ Decommissioning Philosophy PETRONAS'decommissioning philosophy to be applied in Malaysia, based on the areas as defined in Section 16.1.1 above, is noted as follows: 1. PETRONAS, as the statutory manager for petroleum resources, shall adhere to the standards and obligations committed to by the Government of Malaysia and will adopt measures which shall be no less effective than the established international rules and standards, and consistent with the national/local laws. 2. Disused upstream structures and installations need to be decommissioned. Decommissioning is a process to put disused structures and installations out of service. The extent of such removal shall be decided on a case-by-case decommissioning assessment, taking into account all factors particularly the

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legitimate interests of other PS Contractors, users of the sea, the safety of navigation and the preservation of the marine environment. 3. It is envisaged that each case-by-case decommissioning assessment shall entail consultations involving all interested parties.

16.3.2

General Decommissioning Requirement All disused upstream structures and installations located in Malaysia are required to be fully decommissioned, except where non-removal or partial removal is consistent with the standards and requirements imposed by these guidelines. In general, decommissioning of structures and installations shall be evaluated on case-by-case basis. In line with PS Contractors’ obligation as stipulated in the PETRONAS’ FDP Guidelines Milestone Review 4, PS Contractors shall provide the decommissioning plan, which includes but not limited to schedule, method (options) and cost estimates based on end of PSC life or field’s economic life. The decommissioning work is driven by the following factor: a) Safe operations of the facilities towards integrity and Health, Safety and Environment. b) End of field economic life. c) Legislative requirements. The general approval process of structures and installations decommissioning is shown in Appendix 16.2.

16.3.2.1

Safe Operations of the Facilities towards Integrity, Health, Safety and Environment (HSE) The facilities integrity which covers pipelines, topsides, structures, wells and marine facilities shall be regularly assessed in line with Section 11 (Guidelines for Inspection and Maintenance ). In the event that the integrity assessment falls below the integrity safe limit, pose serious risk to HSE, and beyond repair, PS Contractors may consider the facilities to be decommissioned.

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Field Review The field review can be conducted through Full Field Review (FFR), Depletion Studies, Subsurface Review, etc. The field review shall be completed three (3) to five (5) years prior to the projected date by which time the field’s production level is expected to decline or drop below PS Contractors’ forecasted economic region (case-by-case basis).The decision to decommission the field would be based on the field review and on the case where the field can no longer be produced and/or redeveloped commercially using existing and new technology, including Enhanced Oil Recovery (EOR), using the current facilities. The field review shall include but not be limited to the following: 1.

Re-interpretation of the current seismic data.

2.

Study on redevelopment opportunities using the Improved Oil Recovery (IOR) techniques.

3.

Screening study for EOR opportunities and techniques.

The outcome of the field review shall be submitted to PETRONAS. Therefrom, the decision to decommission any field will be subjected to PETRONAS’ approval. 16.3.2.3

Legislative Requirement Please refer to Section 16.4 “Legal Frame Work”.

16.4 LEGAL FRAMEWORK 16.4.1

General The following legislation and standards (as amended) shall be referred to in the implementation of the various decommissioning options for disused upstream structures and installations within Malaysia. At present, the Government of Malaysia has not promulgated any specific decommissioning regulations for the oil and gas industry. There are, however, enabling provisions in several Acts which allow the

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Government of Malaysia to promulgate any decommissioning regulations as it deems fit. These are: 1) Merchant Shipping Ordinance, 1952 - Section 485A. Power to make regulations relating to offshore industry structures, etc. (1) Notwithstanding anything contained in this Act, the Minister may make regulations for the purpose of ensuring the safety of and control over offshore industry structures, off-shore industry mobile units and off-shore industry vessels. (2) Without prejudice to the generality of the powers under subsection (1), such regulations may make provisions for or in relation to any of the following matters. 2) Continental Shelf Act, 1966 (Revised 1972) - Section 16.6. Regulations. (1) The Yang di Pertuan Agong may make regulations for: (i) Providing for the removal of installations or devices constructed, erected, or placed in, on, or above the continental shelf which have been abandoned or become disused. 3) Exclusive Economic Zone Act, 1984 -

Section 21. Prohibition of construction, operation or use of artificial island, etc., except with authorization. (i) No person shall construct, operate or use any artificial island, installation or structure in the exclusive economic zone or on the continental shelf except with the authorization of the Government and subject to such conditions as it may impose.

-

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Section 22. Consent of Government necessary for delineation of course for laying of submarine cables and pipelines.


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(ii) No person shall lay submarine cables or pipelines in the exclusive economic zone or on the continental shelf without the consent of the Government as to the delineation of the course for the laying of such cables and pipelines. (iii) Without prejudice to subsection (1), the Government may impose such conditions as it may consider necessary for the laying or maintenance of such cables and pipelines in the exercise of its right to take reasonable measures for the exploration of the continental shelf, the exploitation of natural resources and the prevention, reduction and control of pollution from such cables or pipelines. -

Section 23. Duty of owner of submarine cable or pipeline. The owner of any submarine cable or pipeline which has fallen into disuse or is beyond repair shall forthwith inform the Government thereof and shall, if so directed by the Government, remove such cable or pipeline within such period of time as the Government may direct.

-

Section 41. Power to make regulations. (i) The Yang di-Pertuan Agong may make regulations for carrying out the provisions of this Act. (ii) Without prejudice to the generality of subsection (1), such regulations may provide for any of the following matters.

16.4.2

Environmental Potential environmental pollution arising from the decommissioning process has always been a critical dimension to consider. The relevant legislative acts to consider are as follows: 1.

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Exclusive Economic Zone Act 1984 a.

Section 2. Interpretation.

b.

Section 10. Offence in respect of the discharge or escape of certain substances. ISSUED BY PETROLEUM MANAGEMENT UNIT

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Environmental Quality Act, 1974 a.

Section 27. Prohibition of discharge of oil into Malaysian waters.

b.

Section 29. Prohibition of discharge of wastes into Malaysian waters.

3. Environmental Quality (Prescribed Activities) Assessment) Order 1987 - Item 12. Petroleum.

(Environmental

Impact

4. "Environmental Impact Assessment Guidelines for Petroleum Industries”: an administrative guideline issued in 1997 by Department of Environment, Ministry of Science, Technology & Environment, Malaysia.

16.4.3

International Obligations Malaysia is a party to the following international instruments and, therefore, it is obligated to uphold the decommissioning standards and requirements under those international instruments: 1. United Nations Convention on the Law of the Sea (UNCLOS), 1982 Article 60(3). 2. International Maritime Organisation (IMO) Guidelines & Standards, 1989. 3. International Convention for the Prevention of Pollution from Ships, 1973 and the modifying Protocol, 1978 (MARPOL 73/78)

16.5 ONSHORE (LAND AND TERRITORIAL SEA) Decommissioning of onshore facilities shall be conducted in consultation with and approval from the Local Authorities, as the case may be, before proceeding with the following activities.

16.5.1

Pre-Decommissioning Process A Decommissioning Options Assessment (for example, Best Practicable Environmental Option (BPEOA)) shall be conducted to evaluate potential decommissioning options, taking into consideration the strategies, environmental,

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safety and cost elements. In addition to that, the options recommended should not pose any undue risk to human life, environment, existing asset and reputation. The selection of the options above will be evaluated on a case-by-case basis. PS Contractors shall submit their Decommissioning Options Assessment to PETRONAS for review and approval. The Decommissioning Options Assessment proposal shall include but not limited to:

16.5.1.1

•

Removal options.

•

A relative ranking of the options based on its strengths and weaknesses.

•

The estimated cost and days for each option including the schedule for the recommended option. Establishment of Decommissioning Options for Onshore Facilities The main options that PS Contractors shall forward for PETRONAS’ considerations, for decommissioning onshore facilities shall include but not limited to:

16.5.1.1.1

Land Installations

16.5.1.1.1.1

Structure Mothball/Relocate/Reuse Mothballing is an option when the structure can be maintained with minimum maintenance but sufficient to ensure integrity, for future reuse at the site or at an alternative site after total removal. For PETRONAS’ consideration of this option, PS Contractors would need to:

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•

identify immediate or future developments in the area that would use a similar type of facilities;

•

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•

estimate the duration and maintenance cost of the mothball period; and

•

prepare the system for minimum maintenance and initiate mothballing; upon PETRONAS’ approval to proceed.

PETRONAS must be consulted for any reclassified use. 16.5.1.1.1.2

Total Removal and Reinstatement of Land In this option the entire structure is removed. The land reinstatement shall be subjected to Local Authorities’ requirement.

16.5.1.1.1.3

Pipeline Pipeline can be decommissioned either by leaving it in-situ or by total removal.

16.5.1.1.1.4

Well Well abandonment shall be conducted as per PETRONAS’ Procedure for Drilling Operations (refer to Section 5). The wellhead shall be totally removed and the land to be reinstated.

16.5.1.1.2 16.5.1.1.2.1

Territorial Sea Sub-Structures

16.5.1.1.2.1.1

Relocate / Reuse For PETRONAS’ consideration of this option, PS Contractors would need to: •

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•

investigate whether the existing platform is suitable for continued use; and

•

prepare the system for minimum maintenance; upon PETRONAS’ approval to proceed.

PETRONAS must be consulted for any reclassified use. Relocation of a reusable platform requires the topsides to be decommissioned and removed if necessary and the jacket structure cut at piles and relocated. 16.5.1.1.2.1.2 Artificial Reef With the partial or total removal options, the platform could be relocated and disposed off at a suitable site to create artificial reefs. There are various factors to be considered such as fisheries’ potential enhancement, usefulness of the platform, environmental impacts and effect to other users of the sea. If the platform location is an ideal condition for a reef site, the topple-in-place option can be the best removal option if the water depth at the site is sufficient to provide navigational clearance. For platform removal option, PS Contractors in consultation with PETRONAS shall liaise with Approving Authority in identifying a new reef site or to add to an existing reef location. 16.5.1.1.2.1.3 Total Removal In this option the entire structure above the seabed is removed. The structure may be disposed off by taking it onshore for recycling or emplacing it as a marine habitat (or artificial reef).

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Topsides The topsides could be disposed off by taking it onshore for recycling or reuse or emplacing it as a marine habitat (or artificial reef).

16.5.1.1.2.2.1 Mothball / Relocate / Reuse Mothballing is an option when the structure can be maintained with minimum maintenance but sufficient to ensure integrity, for future reuse at the site or at an alternative site after total removal. For PETRONAS’ consideration of this option, PS Contractors would need to: •

identify immediate or future developments in the area that would use a similar type of platform;

•

investigate whether the existing platform is suitable for continued use;

•

estimate the duration and maintenance cost of the mothball period; and

•

prepare the system for minimum maintenance and initiate mothballing; upon PETRONAS’ approval to proceed.

PETRONAS must be consulted for any reclassified use. Relocation of a reusable platform requires the topsides to be decommissioned and removed if necessary and the jacket structure cut at piles and relocated. 16.5.1.1.2.3

Pipeline Pipeline can be decommissioned either by leaving it in-situ or by total removal.

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PS Contractors in consultation with PETRONAS shall liaise with Approving Authority whether to leave the pipeline in-situ or totally removed. 16.5.1.1.2.4

Well Abandonment Well abandonment shall be conducted as per PETRONAS’ Procedure for Drilling Operations (refer to Section 7). The wellhead shall be totally removed.

16.5.1.1.2.5

Marine Facilities The decommissioning and removal of marine facilities shall be decided by PETRONAS inline with the findings of Decommissioning Options Assessment.

16.5.1.1.2.5.1 Relocate / Reuse For PETRONAS’ consideration of this option, PS Contractors would need to: •

identify immediate or future developments in the area that would use a similar type of facilities;

•

investigate whether the existing facilities are suitable for continued use; and

•


PETRONAS must be consulted for any reclassified use. 16.5.1.2

Decommissioning Plan A decommissioning plan may deal with the decommissioning of all of the facilities located on a field or part of the facilities including a single installation or pipeline. The precise content of a decommissioning plan may vary according to the circumstances. Please refer to Appendix16.3 as a minimum requirement to be included in the decommissioning plan. The decommissioning plan shall

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be submitted by the PS Contractors for PETRONAS’ approval at least 12 months prior to decommissioning activities. 16.5.1.2.1

Health, Safety and Environment (HSE) Requirement Health HSE considerations for each decommissioning option will vary consistent with Decommissioning Options Assessment taking into account human life, environment, asset and reputation. While the approved decommissioning option should not pose any adverse impact to the environment, it should properly balance the considerations of environmental protection, safety and cost. An Environmental Management Plan (EMP) together with the comparative environmental risks associated with different decommissioning alternatives will be required for submission to PETRONAS for review and subsequent submission to the Department Of Environment for approval six (6) months prior to the decommissioning of any platform. In the case where Environmental Impact Assessment (EIA) is applicable, the EMP needs to be consistent with the EIA requirements. The EMP shall cover but not limited to: •

Pre-decommissioning activities covering baseline studies, chemical and waste inventory, pollution control, etc.

•

Decommissioning activities covering environmental aspects and significant impacts of platform decommissioning and the mitigation measures to be taken during platform removal, transport and disposal to minimise health, safety and environmental impact.

•

Post-decommissioning activities covering the monitoring of the impact/effects on marine environment and ecosystem, navigation and other users of the sea, etc. The risk assessment shall be conducted to cover safety, health and social aspect of the proposed decommissioning proposal for

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submission to PETRONAS. The risk assessment shall include but not limited to: -

16.5.1.2.2

•

Identification of hazard potential issues and consequential impacts of the option selected.

•

Measures to reduce risk to As Low As Reasonably Practicable (ALARP).

Consultation and Liaison An integral part of the decommissioning plan is to demonstrate the industry’s high level of environmental awareness and proactiveness. In the event that a public consultation process becomes necessary in certain cases, the PS Contractors may be required to assist PETRONAS to initiate and manage the dialogue process to obtain the community and stakeholders’ views and concerns. PS Contractors together with PETRONAS shall liaise with various Government departments as and when required. The various departments are but not limited to: •

Department Of Environment Protection and preservation of the marine environment.

•

Federal Marine Department Safety of navigation, search and rescue and other maritime services.

•

Maritime Enforcement Co-ordination Centre Co-ordination in the enforcement of maritime activities in Malaysian waters.

•

Department Of Fisheries Fishing industry, marine parks and reserves, including coral reefs and artificial reefs, enforcement on fishing activities.

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Inland Revenue Taxation.

•

Royal Customs Excise duty.

•

Attorney General's Office Legal aspects on the maritime affairs.

•

Local Authorities Disposal and potential usage of platforms on land.

•

Department of Safety and Occupational Health

•

Ministry of Domestic, Trade and Consumer Affairs

•

Royal Malaysian Police

16.5.1.3 Incorporation in Work Programme and Budget (WP&B) As soon as PETRONAS approves the decommissioning plan, the PS Contractors shall provide budget provisions for platform decommissioning in the immediate forthcoming WP&B. Details of information required shall be consistent with pre-budget guidelines. The decommissioning activities shall commence after PETRONAS approves the decommissioning WP&B.

16.5.2 Decommissioning Execution 16.5.2.1 Project Execution Plan Each decommissioning activity requires Project Execution Plan (PEP) that needs to be submitted to PETRONAS for review at least one (1) month prior to execution. In the event of any deviation from the approved Decommissioning Plan, PS Contractors shall seek PETRONAS’ approval for execution. Refer to Appendix 16.4 for table of content.

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16.5.2.2 Land Installation Decommissioning 16.5.2.2.1

Structure The integrity of the structure needs to be revalidated by certified parties prior to decommissioning work based on latest reassessment report.

16.5.2.2.1.1

Mothball / Relocate / Reuse In general, the applicable means are total removal of structure above ground. The structure requirement for removal shall follow the Local Authority requirements.

16.5.2.2.2

Pipeline Pipelines decommissioning and disposal shall be decided by PETRONAS on a case-by-case basis. Pipelines decommissioning work involves flushing and cleaning to meet regulatory requirements. Pipelines which are to be left in-situ shall be flushed, filled with seawater, cut and plugged, with the ends buried below ground.

16.5.2.2.3

Well Abandonment Well abandonment shall be conducted as per PETRONAS’ Procedure for Drilling Operations (refer to Section 5).

16.5.2.3

Territorial Sea

16.5.2.3.1

Sub-Structure The integrity of the sub-structure needs to be revalidated by certified parties prior to decommissioning work based on latest reassessment report incorporating any underwater findings. The International Maritime Organization (IMO) Guidelines and Standards for the Removal of Offshore Installations and structures on the Continental Shelf and in the Exclusive Economic Zone, adopted by IMO (Resolution A.672 (16)), set out the minimum global standards to be applied for the removal of offshore installations and structures.

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Total Removal In general, the applicable means are total removal by lifting/floating of substructure after piles have been cut. The depth of cutting shall be a minimum of one (1) meter below the mudline subject to cutting method and seabed conditions such as siltation rate, erosion rate, type of soil, etc. The substructures requirement for removal shall follow the IMO requirement.

16.5.2.3.1.2

Relocate/Reuse For PETRONAS’ consideration of this option, PS Contractors would need to: •

identify immediate or future developments in the area that would use a similar type of platform;

•


•



Artificial Reef With the total removal options, the substructure could be relocated and disposed off at a suitable site to create artificial reefs. There are various factors to be considered such as fisheries’ potential enhancement, usefulness of the platform, environmental impacts and effect to other users of the sea. If the platform location is an ideal condition for a reef site, the topple-in-place option can be the best removal option if the water depth at the site is sufficient to provide navigational clearance.

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For structure removal option, PS Contractors in consultation with PETRONAS shall liaise with Approving Authority in identifying a new reef site or to add to an existing reef location. 16.5.2.3.2

Topside PS Contractors to comply with Section 11.4.11 of PPGUA: Preservation of Facilities, Structures and Pipelines upon cessation of production. addition, PS Contractors shall obtain PETRONAS’ prior approval for removal of any components from the said facilities until decommissioning is completed. Decommissioning activities shall only be carried out after the platform is totally shutdown, cleared of all hazardous materials and certified safe for decommissioning to proceed. The minimum scope of requirements should cover the four (4) principal categories of all production and utilities systems on a topside namely: 1. Hydrocarbon systems All separators, process vessels and piping shall be purged and flushed. Residual hydrocarbons shall be collected and dispose at certified onshore disposal site / agency. Radioactive materials shall be handled according to AELB guideline. 2. Non-hazardous systems Cooling water, firewater, utility air and instruments need to be depressurised, flushed, drained and isolated. 3. Toxic and hazardous chemical systems Toxic and hazardous materials should be removed. The system shall be purged, flushed and detoxified. Any discharge of the cleaning effluent must satisfy any applicable regulation.

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4. Electrical power systems Decommissioning of electrical systems is a planned sequenced shutdown of all motor control centers, switchgear and generators with proper safety procedures. Upon completion of all decommissioning works, the topside is to be rendered safe for hotwork via permit to work system. Issuance of safe certificate for hotwork shall be enforced. Integrity of structures has to be verified prior to any cutting, removal, lifting / floatation and transportation of any package or modules. Centers of gravity of the topsides loads have to be established. 16.5.2.3.3

Pipeline Pipelines decommissioning and disposal shall be decided by PETRONAS on a case-by-case basis. Pipelines decommissioning work involves flushing and cleaning to meet regulatory requirements. Pipelines to be left in-situ shall be flushed, filled with seawater, cut and plugged, with the ends buried below mudline. The risers, tube turns and minimum twelve (12) meters of the pipeline section from the base of the substructure shall be totally removed. The removal can be conducted together with substructure removal where applicable. Where appropriate, special measures and consideration need to be taken for ‘hot tap’ or other special pipeline-to-pipeline connections to reduce risk and exposure of the remaining section of pipeline. For total pipeline removal execution, Local Authority shall be consulted on the method and disposal options.

16.5.2.3.4

Well Abandonment Well abandonment shall be conducted as per PETRONAS’ Procedure for Drilling Operations (refer to Section 7). The wellhead shall be totally removed with cutting depth of wellhead system at a minimum of two (2)

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meters below the mudline subject to cutting method and seabed conditions such as siltation rate, erosion rate, type of soil, etc. The substructures requirement for removal shall follow the IMO requirement. 16.5.2.3.5


16.5.3

Post Decommissioning Process

16.5.3.1

Removal of Debris and Seabed Clearance On completion of all decommissioning activities, the land / seabed in the facilities vicinity shall be cleared of all debris that shall be properly disposed according to legislative requirements. Any exceptions to the requirement shall be subjected to government’s approval. For partial removal or in-situ toppling methods, the remaining structures shall be surveyed and their positions recorded. This information would then be submitted to the relevant authorities. The PS Contractors shall check the specified area and remove any debris located within its footprint and vicinity of the facilities (gazetted area). Any exceptions to the requirement shall be subjected to PETRONAS’ approval. The PS Contractors shall verify the site is clear after decommissioning by appropriate methods such as underwater diver survey, trawling in two directions across the location or any other methods subject to approval from PETRONAS. PS Contractors shall degazette the facilities and update Admiralty Charts / Malaysian Charts etc. with respective government agency.

16.5.3.2

Verification The PS Contractors shall verify that the area was cleared of all obstructions and debris. The PS Contractors shall run side-scan sonar or bottom-scan sonar or any other methods subject to approval from PETRONAS, across the location

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to ensure no debris clutters the specified area. Where practical, the PS Contractors shall also visually record the cleared site area for evidence. The PS Contractors shall conduct the survey immediately after the completion of decommissioning work. The PS Contractors shall submit in writing the detail survey report and certification to PETRONAS. This shall include a minimum, the detail of the followings:1) Extent of the area surveyed, (as per gazetted area or specified otherwise by PETRONAS) 2) Survey method used 3) Original Survey Report by the Surveyor 4) Original 3rd Party Certification PETRONAS and PS Contractors shall mutually agree on the selection of 3rd Party Certifier and Surveyor. 16.5.3.3

Post Environmental Assessment The PS Contractors shall conduct the Post Environmental Assessment within three (3) months from the date of completion of decommissioning work, to ensure that there are no adverse impacts on the surrounding marine and land environment. This assessment shall be consistent with the Post Decommissioning Environmental Assessment Plan as per the approved PEP. After completion of the Post Environmental Assessment, the findings shall then be submitted / presented to PETRONAS and the relevant authorities. Upon acceptance of Post Environmental Assessment, PS Contractors shall close out any action items if required.

16.5.3.4

Disposal PS Contractors shall comply with the approved PEP. PS Contractors shall manage disposal until the completion and submit the close out report.

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Post Decommissioning Reports Upon completion of Post Decommissioning works, the PS Contractors as a minimum shall submit the following reports to PETRONAS within one (1) month.

16.5.4

1.

Survey Verification Report

2.

Disposal Report

3.

Post Environmental Assessment Report.

4.

As Built Drawings / Documents

Report PS Contractors shall submit to PETRONAS two (2) reports (both in hard and soft copy) namely: -

16.5.5

i.

Completion report for each stage of decommissioning (well P&A, pipeline, topside and sub-structures) within one month after completion of each stage; and

ii.

Final Closeout Report (no later than six (6) months after completion of decommissioning works). The report shall cover the predecommissioning, decommissioning and post decommissioning activities. Refer to Appendix 16.8 for the Table Of Content.

Degazettement PS Contractors shall submit an application to degazette the decommissioned facilities and its relevant area within one (1) month after the submission of the Closeout Report.

16.5.6

Residual Liability Pending the issuance of a National Policy on Restoration of Oil & Gas Fields, any residual liability of all disused upstream structures and installations shall be finally decided by PETRONAS, in consultation with the relevant Government authorities.

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16.6 SHALLOW WATER 16.6.1

Pre-Decommissioning Process A Decommissioning Options Assessment (for example, BPEOA) shall be conducted to evaluate potential decommissioning options, taking into consideration the strategies, environmental, safety and cost elements. In addition to that, the options recommended should not pose any undue risk to human life, environment, existing asset and reputation. The selection of the options above will be evaluated on a case-by-case basis. PS Contractors shall submit their Decommissioning Options Assessment to PETRONAS for review and approval. The Decommissioning Options Assessment proposal shall include but not limited to: • • •

16.6.1.1

Removal options. A relative ranking of strengths and weaknesses of each option. The estimated cost for each option including the schedule for the recommended option.

Establishment of Decommissioning Options

16.6.1.1.1

Sub-structures The sub-structure covers monopods, piles, jackets, conductor, riser, etc.

16.6.1.1.1.1

Relocate / Reuse For PETRONAS’ consideration of this option, PS Contractors would need to: • identify immediate or future developments in the area that would use a similar type of platform or any new field development that may tie-back and use the facilities on the platform;

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• investigate whether the existing platform is suitable for continued use; and • prepare the system for minimum maintenance; upon PETRONAS’ approval to proceed. PETRONAS must be consulted for any reclassified use. Relocation of a reusable platform requires the topsides to be decommissioned and removed if necessary and the jacket structure cut at piles and relocated. 16.6.1.1.1.2

Artificial Reef With the partial or total removal options, the platform could be relocated and disposed off at a suitable site to create artificial reefs. There are various factors to be considered such as fisheries’ potential enhancement, usefulness of the platform, environmental impacts and effect to other users of the sea. If the platform location is an ideal condition for a reef site, the topple-in-place option can be the best removal option if the water depth at the site is sufficient to provide navigational clearance. For platform removal option, PS Contractors in consultation with PETRONAS shall liaise with Approving Authority in identifying a new reef site or to add to an existing reef location.

16.6.1.1.1.3

Total Removal In this option the entire structure above the seabed is removed. The structure may be disposed off by taking it onshore for recycling or emplacing it as a marine habitat (or artificial reef).

16.6.1.1.1.4

Partial Removal Partial removal would leave the lower part of the structure in its pile condition. The top part of the jacket may be placed besides this structure, taken onshore for recycling or emplace it as a marine habitat (or artificial reef).

SUPERSEDE ISSUE:

AUG 2000


REVISION 2 AUG 2008


Page 341

16.6.1.1.2 Topsides 16.6.1.1.2.1

Mothball / Relocate / Reuse Mothballing is an option when the topside can be maintained with minimum maintenance but sufficient to ensure integrity, for future reuse at the site or at an alternative site after total removal. For PETRONAS’ consideration of this option, PS Contractors would need to:•

identify immediate or future developments in the area that would use a similar type of processes;

•

investigate whether the existing topside is suitable for continued use;

•

estimate the duration and maintenance cost of mothball period;

•

prepare the system for minimum maintenance and initiate mothballing; and

•

investigate whether the existing topside is suitable for other non oil & gas purposes such as training centre, etc.

PETRONAS shall be consulted for any reclassified use. 16.6.1.1.3

Pipeline Pipeline can be decommissioned either by leaving it in-situ or by total removal. PS Contractors in consultation with PETRONAS shall liaise with Approving Authority whether to leave the pipeline in-situ or totally removed.

SUPERSEDE ISSUE:

AUG 2000


REVISION 2 AUG 2008

SECTION 16 GUIDELINES FOR DECOMMISSIONING OF UPSTREAM INSTALLATION 16.6.1.1.4 16.6.1.1.4.1

Page 342

Well Abandonment Dry Wellhead Well abandonment shall be conducted as per PETRONAS’ Procedure for Drilling Operations (refer to Section 5). The wellhead shall be totally removed.

16.6.1.1.4.2

Subsea Wellhead Well abandonment shall be conducted as per PETRONAS’ Procedure for Drilling Operations (refer to Section 5). Subsea well head and its associated accessories can be decommissioned either by leaving it in-site or by total removal.

16.6.1.1.5

Mobile and Floating Facilities Mobile and Floating Facilities and their ancillaries (buoys, chains, anchors, and turret/riser) can either be reused at a different location or totally disposed.

16.6.1.2

Decommissioning Plan A decommissioning plan may deal with the decommissioning of all of the facilities located on a field or part of the facilities including a single installation or pipeline. The precise content of a decommissioning plan may vary according to the circumstances. Please refer to Appendix 16.3 as a minimum requirement to be included in the decommissioning. The decommissioning plan shall be submitted by the PS Contractors for PETRONAS’ approval at least twelve (12) months prior to decommissioning activities.

16.6.1.3

Health, Safety and Environment (HSE) Requirement HSE considerations for each decommissioning option will vary consistent with Decommissioning Options Assessment taking into account human life, environment, asset and reputation. While the approved decommissioning option should not pose any adverse impact to the environment, it should

SUPERSEDE ISSUE:

AUG 2000


REVISION 2 AUG 2008


Page 343

properly balance the considerations of environmental protection, safety and cost. . An Environmental Management Plan (EMP) together with the comparative environmental risks associated with different decommissioning alternatives will be required for submission to PETRONAS for review and subsequent submission to the Department Of Environment for approval six (6) months prior to the decommissioning of any platform. In the case where Environmental Impact Assessment is applicable, the EMP needs to be consistent with the EIA requirements. The EMP shall cover but not limited to: •

Pre-decommissioning activities covering baseline studies, chemicaland waste inventory, pollution control, etc.

•


•

Post-decommissioning activities covering the monitoring of the impact/effects on marine environment and ecosystem, navigation and other users of the sea, etc.

The risk assessment shall be conducted to cover safety, health and social aspect of the proposed decommissioning proposal for submission to PETRONAS. The risk assessment shall include but not limited to: -

SUPERSEDE ISSUE:

AUG 2000

•

Identification of hazard potential issues and consequential impacts of the option selected.

•

Measures to reduce risk to As Low As Reasonably Practicable (ALARP).


REVISION 2 AUG 2008


Page 344

Consultation and Liaison An integral part of the decommissioning plan is to demonstrate the industry’s high level of environmental awareness and proactiveness. In the event that a public consultation process becomes necessary in certain cases, the PS Contractor may be required to assist PETRONAS to initiate and manage the dialogue process to obtain the community and stakeholders’ views and concerns. PS Contractors together with PETRONAS shall liaise with various Government departments as and when required. The various departments are but not limited to: •


•


•


•

Department Of Fisheries Fishing industry, marine parks and reserves, including coral reefs and artificial reefs, enforcement on fishing activities.

•


•

Royal Customs Excise duty

•


•


SUPERSEDE ISSUE:

AUG 2000


REVISION 2 AUG 2008


16.6.1.5

•


•


•


Page 345

Incorporation in Work Programme and Budget (WP&B) As soon as PETRONAS approves the decommissioning plan, the PS Contractors shall provide budget provisions for platform decommissioning in the immediate forthcoming WP&B. Details of information required shall be consistent with pre-budget guidelines. The decommissioning activities shall commence after PETRONAS approves the decommissioning WP&B.

16.6.2

Decommissioning Process

16.6.2.1

Project Execution Plan Each decommissioning activity requires Project Execution Plan (PEP) that needs to be submitted to PETRONAS for review at least one (1) month prior to execution. In the event of any deviation from the approved Decommissioning Plan, PS Contractors shall seek PETRONAS’ approval for execution. Refer to Appendix 16.4 for table of content.

16.6.2.2

Sub-structures Decommissioning The integrity of the sub-structure needs to be revalidated by certified parties prior to decommissioning work based on latest reassessment report incorporating any underwater findings. The International Maritime Organization (IMO) Guidelines and Standards for the Removal of Offshore Installations and Structures on the Continental Shelf and in the Exclusive Economic Zone, adopted by IMO (Resolution A.672 (16)), set out the minimum global standards to be applied for the removal of offshore installations and structures.

SUPERSEDE ISSUE:

AUG 2000


REVISION 2 AUG 2008

SECTION 16 GUIDELINES FOR DECOMMISSIONING OF UPSTREAM INSTALLATION 16.6.2.2.1

Page 346

Partial Removal The upper portion of the sub-structure shall be removed to an agreed cut level. The remaining sub-structure may be retained or removed completely. Partially removed structure must allow for a minimum of 55 meters of water clearance.

16.6.2.2.2

Total Removal In general, the applicable means are total removal by lifting/floating of substructure after piles have been cut. The depth of cutting shall be a minimum of one (1) meter below the mudline subject to cutting method and seabed conditions such as siltation rate, erosion rate, type of soil, etc. The substructures requirement for removal shall follow the IMO requirement.

16.6.2.2.3

Topple The substructure is toppled to the seabed at its piled location and must lie below the recommended level imposed by the regulations which is a minimum of 55 meters water clearance from the highest structure elevation.

16.6.2.3

Topside PS Contractors to comply with Section 11.4.11: Preservation of Facilities, Structures and Pipelines upon cessation of production. In addition, PS Contractors shall obtain PETRONAS’ prior approval for removal of any components from the said facilities until decommissioning is completed. Decommissioning activities shall only be carried out after the platform is totally shutdown, cleared of all hazardous materials and certified safe for decommissioning to proceed. The minimum scope of requirements should cover the four (4) principal categories of all production and utilities systems on a topside namely: -

SUPERSEDE ISSUE:

AUG 2000


REVISION 2 AUG 2008

SECTION 16 GUIDELINES FOR DECOMMISSIONING OF UPSTREAM INSTALLATION 1.

Page 347

Hydrocarbon systems All separators, process vessels and piping shall be purged and flushed. Residual hydrocarbons shall be collected and dispose at certified onshore disposal site / agency. Radioactive materials shall be handled according to AELB guideline.

2.

Non-hazardous systems Cooling water, firewater, utility air and instruments need to be depressurised, flushed, drained and isolated.

3.

Toxic and hazardous chemical systems Toxic and hazardous materials should be removed. The system shall be purged, flushed and detoxified. Any discharge of the cleaning effluent must satisfy any applicable regulation.

4.

Electrical power systems Decommissioning of electrical systems is a planned sequenced shutdown of all motor control centers, switchgear and generators with proper safety procedures. Upon completion of all decommissioning works, the topside is to be rendered safe for hotwork via permit to work system. Issuance of safe certificate for hotwork shall be enforced. Integrity of structures has to be verified prior to any cutting, removal, lifting / floatation and transportation of any package or modules. Centers of gravity of the topsides loads have to be established.

16.6.2.4

Pipeline Pipelines decommissioning and disposal shall be decided by PETRONAS on a case-by-case basis. Pipelines decommissioning work involves flushing and cleaning to meet regulatory requirements. Pipelines to be left in-situ shall be flushed, filled with seawater, cut and plugged, with the ends buried minimum one (1) meter below mudline.

SUPERSEDE ISSUE:

AUG 2000


REVISION 2 AUG 2008


Page 348

The risers, tube turns and minimum twelve (12) meters of the pipeline section from the base of the substructure shall be totally removed. The removal can be conducted together with substructure removal where applicable. Where appropriate, special measures and consideration need to be taken for ‘hot tap’ or other special pipeline-to-pipeline connections to reduce risk and exposure of the remaining section of pipeline. 16.6.2.5

Well Abandonment Well abandonment shall be conducted as per PETRONAS’ Procedure for Drilling Operations (refer to Section 5). The wellhead shall be totally removed with cutting depth of wellhead system of between zero (0) and two (2) meters below the mudline subject to cutting method and seabed conditions such as siltation rate, erosion rate, type of soil, etc. The substructures requirement for removal shall follow the IMO requirement.

16.6.2.6


16.6.3

Post Decommissioning Process

16.6.3.1

Removal of Debris and Seabed Clearance On completion of all decommissioning activities, the land / seabed in the facilities vicinity shall be cleared of all debris that shall be properly disposed according to legislative requirements. Any exceptions to the requirement shall be subjected to government’s approval. For partial removal or in-situ toppling methods, the remaining structures shall be surveyed and their positions recorded. This information would then be submitted to the relevant authorities. The PS Contractors shall check the specified area and remove any debris located within its footprint and vicinity of the facilities (gazetted area). Any exceptions to the requirement shall be subjected to PETRONAS’ approval. The PS Contractors shall verify the site is clear after decommissioning by appropriate methods such as underwater diver survey, trawling in two

SUPERSEDE ISSUE:

AUG 2000


REVISION 2 AUG 2008


Page 349

directions across the location or any other methods subject to approval from PETRONAS. PS Contractors shall degazette the facilities and update Admiralty Charts / Malaysian Charts etc. with respective government agency. 16.6.3.2

Verification The PS Contractors shall verify that the area was cleared of all obstructions and debris. The PS Contractors shall run side-scan sonar or bottom-scan sonar or any other methods subject to approval from PETRONAS, across the location to ensure no debris clutters the specified area. Where practical, the PS Contractors shall also visually record the cleared site area for evidence. The PS Contractors shall conduct the survey immediately after the completion of decommissioning work. The PS Contractors shall submit in writing the detail survey report and certification to PETRONAS. This shall include a minimum, the detail of the followings:1.

Extent of the area surveyed, (as per gazetted area or specified otherwise by PETRONAS)

2.

Survey method used

3.

Original Survey Report by the Surveyor

4.

Original 3rd Party Certification

PETRONAS and PS Contractors shall mutually agree on the selection of 3rd Party Certifier and Surveyor. 16.6.3.3

Post Environmental Assessment The PS Contractors shall conduct the Post Environmental Assessment within three (3) months from the date of completion of decommissioning work, to ensure that there are no adverse impact on the surrounding marine and land environment. This Assessment shall be consistent with the Post Decommissioning Environmental Assessment Plan as per the approved PEP.

SUPERSEDE ISSUE:

AUG 2000


REVISION 2 AUG 2008


Page 350

After completion of the Post Environmental Assessment, the findings shall then be submitted/presented to PETRONAS and the relevant authorities. Upon acceptance of Post Environmental Assessment, PS Contractors shall close out any action items if required. 16.6.3.4

Disposal PS Contractors shall comply with the approved PEP. PS Contractors shall manage disposal until the completion and submit the close out report to PETRONAS.

16.6.3.5

Post Decommissioning Reports Upon completion of Post Decommissioning works, the PS Contractors as a minimum shall submit the following reports to PETRONAS within one (1) month:-

16.6.4

i.

Survey Verification Report.

ii.

Disposal Report.

iii.

Post Environmental Assessment Report.

iv.

As Built Drawings / Documents.

Report PS Contractors shall submit to PETRONAS two (2) reports (both in hard and soft copy) namely:i.

Completion report for each stage of decommissioning (well P&A, pipeline, topside and sub-structures) within one month after completion of each stage; and

ii. Final Closeout Report (no later than six (6) months after completion of decommissioning works). The report shall cover the pre-decommissioning, decommissioning and post decommissioning activities. Refer to Appendix 16.8 for the Table Of Content.

SUPERSEDE ISSUE:

AUG 2000


REVISION 2 AUG 2008


16.6.5

Page 351


16.6.6


16.7 DEEPWATER 16.7.1

Pre-Decommissioning Process A Decommissioning Options Assessment (for example, BPEOA) shall be conducted to evaluate potential decommissioning options, taking into consideration the strategies, environmental, safety and cost elements. In addition to that, the options recommended should not pose any undue risk to human life, environment, existing asset and reputation. The selection of the options above will be evaluated on a case-by-case basis. PS Contractors shall submit their Decommissioning Options Assessment to PETRONAS for review and approval. The Decommissioning Options Assessment proposal shall include but not limited to: -

SUPERSEDE ISSUE:

AUG 2000

•

Removal options.

•

A relative ranking of strengths and weaknesses of each option.

•

The estimated cost for each option including the schedule for the recommended option.


REVISION 2 AUG 2008


Page 352

Establishment of Decommissioning Options

16.7.1.1.1

Sub-structures The sub-structure covers tension leg platform (TLP), piles, jackets, conductor, riser, gravity base structure (GBS), sub-sea production system, etc.

16.7.1.1.1.1

Relocate / Reuse For PETRONAS’ consideration of this option, PS Contractors would need to: •

identify immediate or future developments in the area that would use a similar type of platform or any new field development that may tie-back and use the facilities on the platform;

•


•



Artificial Reef With the partial or total removal options, the platform could be relocated and disposed off at a suitable site to create artificial reefs. Various factors to consider include benefits such as fisheries’ potential enhancement, usefulness of the platform, environmental impacts and effect to other users of the sea. If the platform location is an ideal condition for a reef site, the topple-in-

SUPERSEDE ISSUE:

AUG 2000


REVISION 2 AUG 2008


Page 353

place option can be the best removal option if the water depth at the site is sufficient to provide navigational clearance. PS Contractors in consultation with PETRONAS shall liaise with Approving Authority in identifying a new reef site or to add to an existing reef location for platform removal. 16.7.1.1.1.3

Total Removal In this option the entire structure above the seabed is removed. The structure may be disposed off by taking it onshore for recycling or emplacing it as a marine habitat (or artificial reef).

16.7.1.1.1.4

Partial Removal Partial removal would leave the lower part of the structure in its pile condition. The top part of the structure may be placed besides this substructure, taken onshore for recycling or emplace it as a marine habitat (or artificial reef).

16.7.1.1.2 16.7.1.1.2.1

Topsides Mothball / Relocate / Reuse Mothballing is an option when the topside can be maintained with minimum maintenance but sufficient to ensure integrity, for future reuse at the site or at an alternative site after total removal. For PETRONAS’ consideration of this option, PS Contractors would need to:-

SUPERSEDE ISSUE:

AUG 2000

•

identify immediate or future developments in the area that would use a similar type of processes;

•

investigate whether the existing topside is suitable for continued use;

•

estimate the duration and maintenance cost of mothball period;


REVISION 2 AUG 2008


Page 354

•

prepare the system for minimum maintenance and initiate mothballing; and

•

investigate whether the existing topside is suitable for other non oil & gas purposes such as training centre, etc.

PETRONAS shall be consulted for any reclassified use. 16.7.1.1.3

Pipeline Pipeline can be decommissioned either by leaving it in-situ or by total removal. PS Contractors in consultation with PETRONAS shall liaise with Approving Authority whether to leave the pipeline in-situ or totally removed.

16.7.1.1.4 16.7.1.1.4.1

Well Abandonment Dry Wellhead Well abandonment shall be conducted as per PETRONAS’ Procedure for Drilling Operations (refer to Section 5). The wellhead shall be totally removed.

16.7.1.1.4.2

Subsea Wellhead Well abandonment shall be conducted as per PETRONAS’ Procedure for Drilling Operations (refer to Section 5). Subsea well head and its associated accessories can be decommissioned either by leaving it in-situ or by total removal.

16.7.1.1.5

Mobile and Floating Facilities Mobile and Floating Facilities and their ancillaries (buoys, chains, anchors, turret/riser) can either be reused at a different location or totally disposed.

SUPERSEDE ISSUE:

AUG 2000


REVISION 2 AUG 2008


Page 355

Decommissioning Plan A decommissioning plan may deal with the decommissioning of all of the facilities located on a field or part of the facilities including a single installation or pipeline. The precise content of a decommissioning plan may vary according to the circumstances. Please refer to Appendix 16.3 as a minimum requirement to be included in the decommissioning. The decommissioning plan shall be submitted by the PS Contractors for PETRONAS approval at least twelve (12) months prior to decommissioning activities.

16.7.1.3

Health, Safety and Environment (HSE) Requirement HSE considerations for each decommissioning option will vary consistent with Decommissioning Options Assessment taking into account human life, environment, asset and reputation. While the approved decommissioning option should not pose any adverse impact to the environment, it should properly balance the considerations of environmental protection, safety and cost. An Environmental Management Plan (EMP) together with the comparative environmental risks associated with different decommissioning alternatives will be required for submission to PETRONAS for review and subsequent submission to the Department Of Environment for approval six (6) months prior to the decommissioning of any platform. In the case where Environmental Impact Assessment (EIA) is applicable, the EMP needs to be consistent with the EIA requirements. The EMP shall cover but not limited to: -

SUPERSEDE ISSUE:

AUG 2000

•

Pre-decommissioning activities covering baseline studies, chemical and waste inventory, pollution control, etc.

•



REVISION 2 AUG 2008

SECTION 16 GUIDELINES FOR DECOMMISSIONING OF UPSTREAM INSTALLATION •

Page 356

Post-decommissioning activities covering the monitoring of the impact/effects on marine environment and ecosystem, navigation and other users of the sea, etc. The risk assessment shall be conducted to cover safety, health and social aspect of the proposed decommissioning proposal for submission to PETRONAS. The risk assessment shall include but not limited to: -

• •

16.7.1.4

Identification of hazard potential issues and consequential impacts of the option selected. Measures to reduce risk to As Low As Reasonably Practicable (ALARP).

Consultation and Liaison An integral part of the decommissioning plan is to demonstrate the industry’s high level of environmental awareness and proactiveness. In the event that a public consultation process becomes necessary in certain cases, the PS Contractors may be required to assist PETRONAS to initiate and manage the dialogue process to obtain the community and stakeholders’ views and concerns. PS Contractors together with PETRONAS shall liaise with various Government departments as and when required. The various departments are but not limited to: •


•


•


• SUPERSEDE ISSUE:

AUG 2000

Department Of Fisheries ISSUED BY PETROLEUM MANAGEMENT UNIT

REVISION 2 AUG 2008


Page 357

Fishing industry, marine parks and reserves, including coral reefs and artificial reefs, enforcement on fishing activities. •


•

Royal Customs Excise duty.

•


•


16.7.1.5

•


•


•


Incorporation in Work Programme and Budget (WP&B) As soon as PETRONAS approves the decommissioning plan, the PS Contractors shall provide budget provisions for platform decommissioning in the immediate forthcoming WP&B. Details of information required shall be consistent with pre-budget guidelines. The decommissioning activities shall commence after PETRONAS approves the decommissioning WP&B.

16.7.2 16.7.2.1

Decommissioning Process Project Execution Plan Each decommissioning activity requires Project Execution Plan (PEP) that needs to be submitted to PETRONAS for review at least one (1) month prior to execution. Refer to Appendix 16.4 for table of content.

SUPERSEDE ISSUE:

AUG 2000


REVISION 2 AUG 2008


Page 358

Sub-structures Decommissioning The integrity of the sub-structure needs to be revalidated by certified parties prior to decommissioning work based on latest reassessment report incorporating any underwater findings. The International Maritime Organization (IMO) Guidelines and Standards for the Removal of Offshore Installations and Structures on the Continental Shelf and in the Exclusive Economic Zone, adopted by IMO (Resolution A.672 (16)), set out the minimum global standards to be applied for the removal of offshore installations and structures.

16.7.2.2.1

Partial Removal The upper portion of the sub-structure shall be removed to an agreed cut level. The remaining sub-structure may be retained or removed completely. Partially removed structure must allow for a minimum of 55 meters of water clearance.

16.7.2.2.2

Total Removal In general, the applicable means are total removal by lifting/floating of substructure after piles have been cut. The depth of cutting shall a minimum of one (1) meter below the mudline subject to cutting method and seabed conditions such as siltation rate, erosion rate, type of soil, etc. The substructures requirement for removal shall follow the IMO requirement.

16.7.2.2.3

Topple The substructure is toppled to the seabed at its piled location and must lie below the recommended level imposed by the regulations which is a minimum of 55 meters water clearance from the highest structure elevation.

SUPERSEDE ISSUE:

AUG 2000


REVISION 2 AUG 2008


Page 359

Topside PS Contractors to comply with Section 11.4.11 of PPGUA: Preservation of Facilities, Structures and Pipelines upon cessation of production. In addition, PS Contractors shall obtain PETRONAS’ prior approval for removal of any components from the said facilities until decommissioning is completed. Decommissioning activities shall only be carried out after the platform is totally shutdown, clear of all hazardous materials and certified safe for decommissioning to proceed. The minimum scope of requirements should cover the four (4) principal categories of all production and utilities systems on a topside namely: 1. Hydrocarbon systems All separators, process vessels and piping shall be purged and flushed. Residual hydrocarbons shall be collected and dispose at certified onshore disposal site / agency. Radioactive materials shall be handled according to AELB guideline. 2. Non-hazardous systems Cooling water, firewater, utility air and instruments need to be depressurised, flushed, drained and isolated. 3. Toxic and hazardous chemical systems Toxic and hazardous materials should be removed. The system shall be purged, flushed and detoxified. Any discharge of the cleaning effluent must satisfy any applicable regulation. 4. Electrical power systems Decommissioning of electrical systems is a planned sequenced shutdown of all motor control centers, switchgear and generators with proper safety procedures.

SUPERSEDE ISSUE:

AUG 2000


REVISION 2 AUG 2008


Page 360

Upon completion of all decommissioning works, the topside is to be rendered safe for hotwork via permit to work system. Issuance of safe certificate for hotwork shall be enforced. Integrity of structures has to be verified prior to any cutting, removal, lifting / floatation and transportation of any package or modules. Centers of gravity of the topsides loads have to be established. 16.7.2.4

Pipeline Pipelines decommissioning and disposal shall be decided by PETRONAS on a case-by-case basis. Pipelines decommissioning work involves flushing and cleaning to meet regulatory requirements. Pipelines to be left in-situ shall be flushed, filled with seawater, cut and plugged, with the ends buried minimum one (1) meter below mudline. The risers, tube turns and minimum twelve (12) meters of the pipeline section from the base of the substructure shall be totally removed. The removal can be conducted together with substructure removal where applicable. Where appropriate, special measures and consideration need to be taken for ‘hot tap’ or other special pipeline-to-pipeline connections to reduce risk and exposure of the remaining section of pipeline.

16.7.2.5

Well Abandonment Well abandonment shall be conducted as per PETRONAS’ Procedure for Drilling Operations (refer to Section 5). The wellhead shall be totally removed with cutting depth of wellhead system of between zero (0) and two (2) meters below the mudline subject to cutting method and seabed conditions such as siltation rate, erosion rate, type of soil, etc. The substructures requirement for removal shall follow the IMO requirement.

16.7.2.6


SUPERSEDE ISSUE:

AUG 2000


REVISION 2 AUG 2008


16.7.3 16.7.3.1

Page 361

Post Decommissioning Process Removal of Debris and Seabed Clearance On completion of all decommissioning activities, the land / seabed in the facilities vicinity shall be cleared of all debris that shall be properly disposed according to legislative requirements. Any exceptions to the requirement shall be subjected to government’s approval. For partial removal or in-situ toppling methods, the remaining structures shall be surveyed and their positions recorded. This information would then be submitted to the relevant authorities. The PS Contractors shall check the specified area and remove any debris located within its footprint and vicinity of the facilities (gazetted area). Any exceptions to the requirement shall be subjected to PETRONAS’ approval. The PS Contractors shall verify the site is clear after decommissioning by appropriate methods such as underwater diver survey, trawling in two directions across the location or any other methods subject to approval from PETRONAS. PS Contractors shall degazette the facilities and update Admiralty Charts / Malaysian Charts etc. with respective government agency.

16.7.3.2

Verification The PS Contractors shall verify that the area was cleared of all obstructions and debris. The PS Contractors shall run side-scan sonar or bottom-scan sonar or any other methods subject to approval from PETRONAS, across the location to ensure no debris clutters the specified area. Where practical, the PS Contractors shall also visually record the cleared site area for evidence. The PS Contractors shall conduct the survey immediately after the completion of decommissioning work. The PS Contractors shall submit in writing the detail survey report and certification to PETRONAS. This shall include a minimum, the detail of the followings:-

SUPERSEDE ISSUE:

AUG 2000


REVISION 2 AUG 2008


Page 362

1. Extent of the area surveyed, (as per gazetted area or specified otherwise by PETRONAS). 2. Survey method used 3. Original Survey Report by the Surveyor 4. Original 3rd Party Certification PETRONAS and PS Contractors shall mutually agree on the selection of 3rd Party Certifier and Surveyor. 16.7.3.3

Post Environmental Assessment The PS Contractor shall conduct the Post Environmental Assessment within three (3) months from the date of completion of decommissioning work, to ensure that there are no adverse impact on the surrounding marine and land environment. This Assessment shall be consistent with the Post Decommissioning Environmental Assessment Plan as per the approved PEP. After completion of the Post Environmental Assessment, the findings shall then be submitted / presented to PETRONAS and the relevant authorities. Upon acceptance of Post Environmental Assessment, PS Contractor shall close out any action items if required.

16.7.3.4

Disposal PS Contractors shall comply with the approved PEP. PS Contractors shall manage disposal until the completion and submit the close out report to PETRONAS.

16.7.3.5

Post Decommissioning Reports Upon completion of Post Decommissioning works, the PS Contractors as a minimum shall submit the following reports to PETRONAS within one (1) month:1. Survey Verification Report 2. Disposal Report

SUPERSEDE ISSUE:

AUG 2000


REVISION 2 AUG 2008


Page 363

3. Post Environmental Assessment Report 4. As Built Drawings / Documents

16.7.4

Report PS Contractors shall submit to PETRONAS two (2) reports (both in hard and soft copy) namely:i.

Completion report for each stage of decommissioning (well P&A, pipeline, topside and sub-structures) within one (1) month after completion of each stage; and

ii. Final Closeout Report (no later than six (6) months after completion of decommissioning works). The report shall cover the pre-decommissioning, decommissioning and post decommissioning activities. Refer to Appendix 16.8 for The Table Of Content.

16.7.5


16.7.6


16.8 PS CONTRACTORS’ OBLIGATIONS DURING HAND-OVER If the PS Contractors are to relinquish field(s) to PETRONAS, the PS Contractors shall provide the following information to the extent such information is in the PS Contractors’ possession in addition to any other information stipulated by the PSC, which is required for decommissioning planning: •

Estimated remaining field life at hand-over date

•

Operating costs for at least three (3) years preceding the hand-over date

SUPERSEDE ISSUE:

AUG 2000


REVISION 2 AUG 2008


Page 364

•

Statement on wells abandonment experience for the field

•

Recommended method for abandonment of remaining wells

•

Topside inventory and their remaining life where appropriate

•

Underwater survey/inspection data/information for the year of handover and all the previous inspection years

•

All as-built drawings, operating manuals and design documentations

•

Engineering evaluation of inspection and repair history for the substructure

•

The status and composition of the drill cutting pile where applicable

•

Report on any settlement and soil properties up to 5 meters below seabed (consistent with EIA requirements)

•

Structural integrity assessment supported by appropriate structural analyses

•

Recommendation for future use of the redundant installations

•

Estimated cost(s) for decommissioning based on recommended option(s)

•

Latest report on anomalies and shallow gas within the vicinity of the installation.


SUPERSEDE ISSUE:

AUG 2000


REVISION 2 AUG 2008


Page 365


Executive Summary PETRONAS has the entire ownership of the national petroleum resources including all data and information generated from upstream petroleum activities of the Production Sharing Contractor (PSC). A copy of the data shall be submitted to PETRONAS to be preserved for future use in the domestic E&P ventures. This section provides guidelines for Production Sharing Contractor (PSC) in managing the data internally and submitting the data to PETRONAS. In this respect, the PS Contractor shall have in place a proper data management system, documented policy and guidelines and adequate data management resources or organization to ensure data are captured, safely stored, its quality are known and standardized, integrity are protected, is easily accessible and timely submitted to PETRONAS according to the specified requirements.

SUPERSEDE ISSUE:

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17.1 PREAMBLE In accordance with the terms and conditions of the Production Sharing Contract (PSC), PETRONAS has the entire ownership of all original data and information generated from upstream petroleum activities under the applicable PSC. A copy of the original data shall be submitted to PETRONAS to be preserved for future use in the domestic E&P ventures. This section provides guidelines for Production Sharing Contractor (PS Contractor) in managing and submitting the data to PETRONAS. In this respect, the PS Contractor shall have in place a proper data management system, documented policy and guidelines and adequate data management resources or organization to ensure data are captured, safely stored, its quality are known and standardized, integrity are protected, is easily accessible and timely submitted to PETRONAS according to the specified requirements.

17.2 COMMITMENT AND ACCOUNTABILITY PS Contractor shall demonstrate strong commitment and accountability in its data management efforts, and provide necessary resources to develop and maintain an efficient data management function.

17.3 DATA SUBMISSION GUIDELINE All final and approved data for archival purposes shall be submitted directly to Data Management Section of Petroleum Management Unit (PMU) except for daily operational report or data which requires the approval from the corresponding line department in PMU. All data shall be submitted to the stipulated addresses in Appendix 17.

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17.4 DATA SUMISSION CHECKLIST PS Contractor shall submit all data to PETRONAS including but not limited to the data types, data format, media format and the timeline as stipulated in Appendix 17.

17.5 DATA FORMAT STANDARD FOR SUBMISSION PS Contractor shall be responsible to Quality Check (QC) any data generated from their activities and take necessary action to rectify any errors or discrepancies prior using, keeping and submitting to PETRONAS. For raw digital data, PS Contractor shall submit the data to PETRONAS in open industry format for easy transfer to any systems. PETRONAS reserves the right to reject any data submitted not following the standards as stipulated in Appendix 17. PS Contractor shall rectify and resubmit the data in correct data and media format. Upon request, except for raw digital data, PS Contractor shall submit data in common commercial application format, however companies’ proprietary data format is not allowed. PETRONAS reserves the rights to specify, after consultation with the PS Contractors, the medium, format and method by which original data, information, studies, reports and samples are to be stored, prepared and submitted to PETRONAS.

-END OF SECTION 17-

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Executive Summary This section provides guidelines for PS Contractor to communicate swiftly and reports effectively to PETRONAS in the event of an incident and emergency occurrence in its upstream operations. This section also provides PETRONAS and COMCEN contact lists for PS Contractor’s immediate notification.

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18.1 INTRODUCTION This Emergency Communication Procedure has been developed to ensure that the PS Contractor communicates swiftly and reports effectively to PETRONAS in the event of an incident and emergency occurrence in its upstream operations. This document is formulated and developed to meet PETRONAS requirements for PS Contractor operating in Malaysia. This procedure complements the existing Health, Safety and Environment Guideline: Section 1 of the Main PPGUA. It shall be revised from time to time as required by PETRONAS to ensure that any changes in the emergency response communication chain between the PS Contractor and PETRONAS are updated and correctly documented.

18.2 SCOPE This Emergency Communication Procedure covers all emergency situations which may be encountered by the PS Contractor during the E & P cycle. These procedures is to enable PS Contractor to contact and notify PETRONAS key personnel via Petroleum Management Unit (PMU) Regional Offices, PMU HSE Kuala Lumpur, Petroleum Operations Management, PMU Kuala Lumpur and PETRONAS COMCEN, in the event of emergencies, to keep them informed of the related incident. Those contacted will be in turn responsible for ensuring that all the relevant personnel (within PETRONAS) are informed immediately.

18.3 DEFINITION For the purpose of this Procedure, the definition of an incident and emergency is as follows:-

18.3.1

Incident Any abnormal or unplanned event or series of events that has caused or has the potential to cause adverse effects to PS Contractor’s normal operations and procedures, facilities, or personnel, which requires attention, and has the potential to precipitate to an emergency. Each incident should be mitigated by

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the PS Contractor as quickly as possible, monitored and evaluated to prevent it from escalating to an emergency situation.

18.3.2

Emergency An unexpected situation resulting in fire, explosions, oil and/or chemical spill, gas escape, serious injury or fatality, structural damage, total evacuation, severe electrical storm, aircraft or vehicle crash, vessel collision or sinking, deliberate act of arson or sabotage, or a combination of any of the foregoing incidents all of which requires PS Contractor’s in-house emergency organisation immediate response to bring it under control. These emergency situations may develop into major disasters that warrant mobilizing special resources from external parties such as Government (for anti-hijacking) and agencies/organisations (for search and rescue).

18.3.3

Disaster & Crisis An incident or emergency which has the potential to significantly impact the company’s Image, operations or entails significant economic or legal liabilities. A disaster is therefore a subset of incidents or emergencies which due to its nature or severity has crossed a threshold requiring support and intervention from PETRONAS corporate level. Characteristics associated with incidents classified as disaster include:

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Effects are not localized and may have off-site impact. Impacts may be long term based upon the incident or emergency. Normal operations or conduct of business may be interrupted. Resources required to respond may extend beyond the capabilities of the distressed site or business unit. Generate moderate to extensive media and public interest. Time frame for actions may be extremely limited. Potential to escalate into crisis. ISSUED BY PETROLEUM MANAGEMENT UNIT

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Crisis A decisive moment, a time of danger or great difficulty and within the context of this manual, which is an actual or potential threat to PETRONAS’ medium to long term ability to operate its business arising from loss of control of a disaster due to its impact on operability, image and reputation, integrity as well as viability. A corporate crisis by definition, for PETRONAS, is a disaster which has reached a threshold of failure to control requiring a full or partial mobilization of the PETRONAS Crisis Management Team (CMT). Characteristics associated with crisis include:

•

Significant issue affecting corporate reputation, credibility and integrity.

•

Significant potential impact on PSCs, business units or joint ventures with long-term consequences.

•

Extensive media and public interest generated on the incident and on the organization.

•

Require significant corporate resources including financial support, manpower, management and technical expertise to respond effectively.

•

Time management is an essence.

•

Limited and often conflicting information regarding the situation.

18.4 EMERGENCY RESPONSE PLAN PS Contractor is required to establish, develop and maintain comprehensive Emergency Response Plan (ERP), Manual and Procedure which best suits their operations needs stating the emergency organizations, responsibility, communication system and detailed procedures outlining the action to be taken by their employees in the event of any possible emergency which may endanger life, property or the environment. The ERP shall be in accordance to the statutory requirements and outlines the management of the emergency response to the incident tailored to the SUPERSEDE ISSUE:

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operational requirements of the PSC. Depending on the levels of emergency / crisis situations, PETRONAS shall be informed accordingly in the event of the emergency. Generally, the ERP shall consist of the following elements: a)

Potential hazards associated in its operations and impact to the local community

b)

Emergency response structure with roles and responsibilities of Emergency Response Team (ERT) and Emergency Management Team (EMT) based on the organisational and management principles of Incident Command System (ICS).

c)

Response strategy, tactics and emergency management structure.

d)

Communication and notification protocols (internal and external)

e)

Communication and coordination between PSC and the authorities.

f)

Information and media response including procedures and policy for managing media and image issues.

g)

Human resource policy and procedures of handling issues relating to personnel, contractors, clients and local community affected by the incident.

h)

Resource matrix.

i)

Linkages to COMCEN and PMU to assess additional support and resources.

j)

Post incident procedures.

Upon the occurrence of an emergency, the PS Contractors'Emergency Response Plan will be activated and messages will be immediately relayed to their respective Emergency Command/Coordination Centers (ECC). The ECC of the PS Contractors involved will then alert SM PMU Regional Offices, SM PMU HSE Kuala Lumpur, SGM POM-PMU Kuala Lumpur and copied the information to PETRONAS COMCEN in Kuala Lumpur. Upon receipt of the PS Contractor’s emergency notification, SGM POM-PMU will notify relevant key personnel in PETRONAS, where appropriate action plan will be activated accordingly.

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18.5 EMERGENCY CLASSIFICATION In this procedure, emergencies are categorized into 3 tiers:Tier 1 - Incident Tier 2 - Emergency Tier 3 - Disaster & Crisis Situation The detail definition of three levels of emergency / crisis situations are as follows :-

18.5.1

TIER 1 - INCIDENT (Refer Figure 1) A situation where the incident is causing no danger to life and where risk of damage to property and environment is minimal. The incident is within the control of PS Contractor with assistance from local sources, where ECC is not activated and does not classify under Tier 2 & 3. Refer to Figure 1 for the response and communications/notification for this situation. The situation includes the followings, but not limited to:

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(a)

LTI

(b)

First Aid Case

(b)

Near Misses

(c)

Restricted Work Cases (RWC)

(d)

Medical Treatment Cases (MTC)

(e)

Fire (minor non-process)

(f)

Minor Oil and Toxic/hazardous chemical spills (< 5 bbls)

(h)

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FIGURE 1: TIER 1 - INCIDENT

OFFSHORE / ONSHORE ACCIDENT / INCIDENT

PS CONTRACTOR ER TEAM AT SITE ACTIVATE ACTIONS TO BRING EMERGENCY UNDER CONTROL OR EVACUATE.

THIRD PARTIES SUPPORT VESSELS

NOTIFY ONSHORE OFFICE ON THE NATURE OF EMERGENCY, ACTION TAKEN, ETC.

BARGES

NOTIFY SUPPORT VESSELS AND NEARBY FACILITIES FOR ASSISTANCE IF NEEDED.

ETC.

RIGS (AT SITE / FIELD)

THIRD PARTIES HELI SERVICES SUPPORT VESSELS MEDICAL ADVICES CONTRACTOR SERVICES ETC.

MUTUAL SUPPORT OTHER PS CONTRACTORS

PROVIDE BACK-UP HELI & VESSELS PLANT OPERATORS ETC.

PS CONTRACTOR OFFICE ONSHORE COORDINATE OVERALL RESPONSE EFFORT INCLUDING : ACTIVATE PRE-ARRANGED THIRD PARTIES ASSISTANCE, E.G HELICOPTER, SUPPORT VESSELS, MEDICAL ARRANGEMENT, ETC. IF NECESSARY. MOBILISE INVESTIGATION TEAM. REPORTING TO PETRONAS 24 HRS OR MONTHLY (where applicable)

PS CONTRACTOR'S SCOPE

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TIER 2 - EMERGENCY (Refer Figure 2) A situation where there is, or which may deteriorate and cause danger to life, and risk of damage to property, environment, potential damage to corporate image and future operation and can be brought under control within the PSC with the implementation of special emergency response measures through initiation of the relevant emergency organisation and activation of the ECC and may require support from local authorities, mutual aid groups and neighboring plants. The situation includes the followings, but not limited to: (a)

Lost Time Injury

(b)

Fatality

(c)

Bodyvac and Medevac Body Evacuation - removal of dead body to onshore Medical Evacuation - when life is not in immediate danger

(d)

Helicopter Emergency Helicopter ditches into the sea Helicopter emergency landing Helicopter crash

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(e)

Fire (process and major non-process) where the Emergency Response Team (ERT) is mobilized.

(f)

Explosion

(g)

Well Blowouts

(h)

Structural Failures

(i)

Major Oil and Toxic/Hazardous Chemical Spills (>5 barrels)

(j)

Condensate Spills

(k)

Man Overboard

(l)

Lan and Marine Transport Incidents ISSUED BY PETROLEUM MANAGEMENT UNIT

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Page 376

Property Damage (for medium and major property damage based on the Risk Assessment Classification)

(n)

Natural Disaster :

(o) (p)

Earthquakes Tsunami Typhoons Detection of Contagious Disease(s) Man Overboard

Refer to Figure 2 for the response and communications/notification for this situation.

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FIGURE 2: TIER 2 – EMERGENCY OFFSHORE / ONSHORE ACCIDENT / INCIDENT

PS CONTRACTOR ER TEAM AT SITE THIRD PARTIES

ACTIVATE ACTIONS TO BRING EMERGENCY UNDER CONTROL OR EVACUATE.

SUPPORT VESSELS

NOTIFY ONSHORE EMERGENCY CONTROL CENTRE (ECC) ON THE NATURE OF EMERGENCY, ACTION TAKEN, ETC. AND SEEK ASSISTANCE IF NEEDED.

BARGES RIGS ETC. (AT SITE / FIELD)


THIRD PARTIES HELI SERVICES SUPPORT VESSELS MEDICAL ADVICES CONTRACTOR SERVICES ETC.

PS CONTRACTOR EMERGENCY TEAM AT EMERGENCY CONTROL CENTRE (ECC)

LOCAL AUTHORITIES

RESPONSE IMMEDIATELY TO CALL BY SITE ER TEAM.

MUTUAL SUPPORT

HOSPITAL POLICE

COORDINATE OVERALL RESPONSE EFFORT INCLUDING :ACTIVATE PRE-ARRANGED THIRD PARTIES ASSISTANCE, E.G. HELICOPTER, SUPPORT VESSELS, MEDICAL ARRANGEMENT, ETC.

OTHER PS CONTRACTORS PROVIDE BACK-UP HELI & VESSELS

NOTIFY LOCAL AUTHORITIES.

PLANT OPERATORS

PORT AUTHORITY DOE ETC.

NOTIFY / ADVISE PS CONTRACTOR TOP MANAGEMENT.

PIMMAG ETC.

NOTIFY IMMEDIATELY AND IF NEEDED REQUEST EXTERNAL ASSISTANCE FROM PETRONAS.

PS CONTRACTOR'S SCOPE CC

PETRONAS SCOPE

PETRONAS COMCEN

PMU HSE SENIOR MANAGER (KUALA LUMPUR) NOTIFY / UPDATE SGM PMU ACCESS / MONITOR SITUATION

SENIOR MANAGER PMU REGIONAL OFFICE

SENIOR GENERAL MANAGER, POM, PMU NOTIFY / ADVISE HIGHER MANAGEMENT AND UPDATE OF EMERGENCY

ASSESS / MONITOR SITUATION AT PS CONTRACTOR ECC OR SITE IF POSSIBLE

PROVIDE INPUTS FOR PRESS RELEASES (IF NECESSARY) THROUGH LEGAL & CORPORATE AFFAIRS DIVISION

UPDATE SGM POM, PMU

NOTIFY / ADVISE HRM IF EMERGENCY INVOLVED PETRONAS STAFF

SVP, E & P BUSINESS SGM, LEGAL & CORPORATE AFFAIRS DIVISION

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PRESIDENT

GM, HR DEVELOPMENT


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TIER 3- DISASTER & CRISIS SITUATION (Refer Figure 3) A situation where the incident / accident escalates and will cause grave danger to life causing multiple fatalities, severe damage to the environment involving neighboring sites and surrounding communities, or total loss of facility. The incident is clearly beyond the capacity and capabilities of PETRONAS or the PS Contractors. The situation warrants the intervention of the Malaysian Government. The situation includes the following, but not limited to : (a)

Security threat Hijacking of an installation Terrorism Kidnapping

(b)

Major oil and Toxic/Hazardous Chemical Spill (> 5 bbls)

(c)

Total loss of an installation

(d)

Multiple fatalities

(e)

Major Marine collision incidents (involving vessels)

(f)

Endemic/Pandemic Disease

(g)

Aircraft crash incidents

Refer to Figure 3 for the response and communications/notification for this situation.

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FIGURE 3: TIER 3 - DISASTER & CRISIS SITUATION OFFSHORE / ONSHORE ACCIDENT / INCIDENT PS CONTRACTOR ER TEAM AT SITE THIRD PARTIES

ACTIVATE ACTIONS TO BRING EMERGENCY UNDER CONTROL OR EVACUATE.

SUPPORT VESSELS

NOTIFY ONSHORE EMERGENCY CONTROL CENTRE (ECC) ON THE NATURE OF EMERGENCY, ACTION TAKEN, ETC. AND SEEK ASSISTANCE IF NEEDED.

BARGES RIGS ETC. (AT SITE / FIELD)


THIRD PARTIES HELI SERVICES SUPPORT VESSELS MEDICAL ADVICES

PS CONTRACTOR EMERGENCY TEAM AT EMERGENCY CONTROL CENTRE (ECC)

CONTRACTOR SERVICES ETC.

RESPONSE IMMEDIATELY TO CALL BY SITE ER TEAM.

LOCAL AUTHORITIES

COORDINATE OVERALL RESPONSE EFFORT INCLUDING :-

MUTUAL SUPPORT

HOSPITAL POLICE

ACTIVATE PRE-ARRANGED THIRD PARTIES ASSISTANCE, E.G. HELICOPTER, SUPPORT VESSELS, MEDICAL ARRANGEMENT, ETC.

OTHER PS CONTRACTORS PROVIDE BACK-UP HELI & VESSELS PLANT OPERATORS PIMMAG ETC.

PORT AUTHORITY

NOTIFY LOCAL AUTHORITIES.

DOE

NOTIFY / ADVISE PS CONTRACTOR TOP MANAGEMENT.

ETC.

NOTIFY IMMEDIATELY AND REQUEST EXTERNAL ASSISTANCE FROM PETRONAS.

PS CONTRACTOR'S SCOPE CC

PETRONAS SCOPE PMU HSE SENIOR MANAGER (KUALA LUMPUR)

PETRONAS COMCEN

SENIOR MANAGER PMU REGIONAL OFFICE ASSESS / MONITOR SITUATION AT PS CONTRACTOR ECC OR SITE IF POSSIBLE

NOTIFY / UPDATE SGM POM, PMU

FIGURE 18.2: TIER 2 - MAJOR EMERGENCY

ACCESS / MONITOR SITUATION

UPDATE SGM POM, PMU

PRESIDENT

SVP, E & P BUSINESS

SENIOR GENERAL MANAGER, POM, PMU IMMEDIATELY INFORM THE PRESIDENT AND VP (E&P BUSINESS) OF THE EMERGENCY APPRAISE THE EMERGENCY

GM, SECURITY DIV

GM, HR DEVT

SGM, LCAD

ACTIVATE COORDINATION ASSISTANCE FROM GOVERNMENT BODIES eg. MECC AND MRCC FOR THEIR ASSISTANCE UPDATE THE PRESIDENT AND VP (E&P BUSINESS) AND IF NEEDED OTHER RELEVANT AUTHORITIES INFORM AND UPDATE LEGAL & CORPORATE AFFAIRS DIVISION TO ENABLE PRESS OFFICER TO PREPARE PRESS RELEASE FOR MEDIA. NOTIFY / ADVISE HRM IF EMERGENCY INVOLVED PETRONAS STAFF. REQUEST ASSISTANCE (IF NECESSARY) FROM SECURITY DEPARTMENT FOR CROW D CONTROL AND PROVIDE DIRECTION TO CONCERNED PARTIES.

GM, GHSE

OUTSIDE EXPERT (W HERE NECESSARY)

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MARITIME RESCUE COORDINATING CENTRE (MRCC) - PORT KELANG PROVIDE BACK UP SEARCH AND RESCUE SERVICES AIRCRAFT SURFACE CRAFT MARITIME RESCUE ENFORCEMENT COORDINATING CENTRE (MECC) - LUMUT ACTIVATE NATIONAL SECURITY COUNCIL TO COMBACT HIJACKING NEGOTIATION GROUP PASKAL (OFFSHORE) MCC (ONSHORE)

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18.6 NOTIFICATION OF EMERGENCIES AND RESPONSIBILITIES 18.6.1

PS Contractor

18.6.1.1

All emergencies involving incidents and accidents shall be reported to PMU. The emergency message shall contain the required information as per Initial Incident Notification Form shown in Appendix18A.

18.6.1.2

All incident cases under Tier 1, shall be recorded and included by PS Contractor into their monthly HSE performance report submission to PMU. Refer to Figure 1 for the procedure of Tier 1- Incident

18.6.1.3

For Tier 1, LTI, RWC, MTC and Minor Oil and Toxic/Hazardous Chemical Spill (with ERT is activated), PSC is required to notify PMU within the period of 24 hours. The incident shall be notified by PS Contractors by phone to SM PMU Regional Offices and SM PMU HSE Kuala Lumpur, followed by e-mail/telefax of the Initial Incident Notification Form.

18.6.1.4

All emergency cases under Tier 2 and 3 shall be notified immediately, regardless of the time and location by phone to SM PMU Regional Offices and SM PMU HSE and followed by e-mail/telefax of the Initial Incident Notification Form addressed to SM PMU Regional Offices, SM PMU HSE Kuala Lumpur, SGM POM-PMU and copied to PETRONAS COMCEN, regardless of the time of the location. Depending on the severity of the incident, the follow-up reporting of the incident to PMU Regional Offices shall be provided at appropriate intervals and at least on a daily basis until the emergency situation/crisis has been resolved or the deactivation of the ECC, which ever is later. Refer to Figure 2 for the procedure of Tier 2Emergency.

18.6.1.5

Not withstanding to the above Tier classification, any incident which has impact on the reputation and credibility of PETRONAS, both in terms of media and public concern, shall also be notified to PETRONAS immediately as per item 18.6.1.4.

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SM PMU Regional Office, SM PMU HSE Kuala Lumpur, SGM POM-PMU and PETRONAS COMCEN can be reached via the contact numbers in Appendix 18B: Notification Contact List.

18.6.1.6

Should the emergency involved oil/chemical spill, it is the responsibility of PS Contractor to appropriately notify and request PIMMAG for their response. PIMMAG can be reached via the contact numbers in Appendix 18B: Notification Contact List.

18.6.1.7

PSC shall forthwith notify the nearest related local Authority (DOE, POLICE, DOSH, HOSPITAL, ETC) by the quickest means available for all emergency cases under Tier 2 and 3 except for Tier 1.

18.6.2

Petroleum Management Unit, PETRONAS

18.6.2.1

Upon receipt of emergency message, SM PMU Regional Offices and SM PMU HSE Kuala Lumpur shall immediately notify/update SGM POMPMU Kuala Lumpur and will continue to provide him with further information as and when received from PS Contractor.

18.6.2.2

As and when required, SGM POM-PMU, SM PMU HSE and SM PMU Regional Offices can liaise with PETRONAS COMCEN to get latest update, and vice versa.

18.6.2.3

For Tier 3, SGM of POM-PMU shall appraise the emergency status, activate coordination assistance from authorities/organisations (external), update management and impart strategic and technical input to PETRONAS Crisis Management Team at corporate level as and when appropriate.

- END OF SECTION 18-

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SECTION 19 GUIDELINES FOR OPERATING PERFORMANCE IMPROVEMENT (OPI) Executive Summary This section provides guidelines on effective tools and methodology for PS Contractor implementing improvement initiatives in closing performance gap. It is PETRONAS aspirations for PS Contractor to achieve operational excellence in conducting upstream activities. PS Contractor may at its own effort or upon instructed by PETRONAS conduct improvement initiative on specific activities (i.e. production operations or projects) or incident etc. in the event that any of the abovementioned activities performed poorer than expected. PS Contractor shall pursue their own improvement tool and methodology where applicable or may adopt the following tools and methodology developed by PETRONAS. The purpose of this guideline is to have a common understanding of terms and standardized reporting and tracking.

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19.1 OVERALL EQUIPMENT EFFICIENCY (OEE) AND DOWNTIME DATA PS Contractor is required to submit the OEE and downtime data (planned and unplanned) for oil and gas facilities to PETRONAS on monthly basis. Description OEE is a key performance indicator that measures field operational performance. Operational performance can be measured by dividing the platform’s reconciled production by the adjusted technical potential over the same period of time Rationale OEE measurement forms the foundation of cascading performance dialogues and performance management system, e.g., from hour-by-hour shift manager to operator performance dialogues to weekly platform Operations Improvement Management (OIM) performance dialogues. It also provides a standard methodology to measure platform and field performance. Instructions and Format OEE =

Actual Production Adjusted Technical Potential

Adjusted Technical Potential = Technical Potential (TP) – Indirect Losses Indirect Losses = External Deferment (planned and unplanned) + Planned Deferment External Deferment = common facilities Operated By Others (OBO) downtime, tanker delays, tank top etc Planned Deferment = DOSH, PETRONAS requirement etc. Actual Production = Adjusted Technical Potential – Direct Losses Direct Loss = Availability Loss + Productivity Loss + Quality Loss Availability Loss = Planned Maintenance (PM) other than DOSH and PETRONAS requirement + Unplanned Deferment (unplanned activities, equipment malfunction) SUPERSEDE ISSUE:

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Productivity Loss = Other losses / slowdown + losses due to well characteristics Quality Loss = Reconciliation effect Please refer to Appendix 19A, 19B for OEE oil and gas methodology respectively and Appendix 19C for deferment category.

19.2 ROOT CAUSE PROBLEM SOLVING (RCPS) Description The term ‘Five (5) WHY’ methodology has been developed to identify and analyze causes of poor performance. PS Contractor may adopt and utilize this methodology using the ‘Causal Tree’ (refer to Appendix 19D) Rationale RCPS is the central analytical tool for problem solving. The benefits are: 1. It is a systematic tool that uncovers ‘hard’ and ‘soft’ root causes of problems 2. Teaches frontline and management to be relentless, rigorous, and always fact-based in problem-solving 3. Engages the relevant personnel in problem solving as well as developing possible solutions 4. Balances comprehensiveness and prioritization in determining probable causes to a problem Instructions and Format 1. Define the problem 2. Start at an actionable lever and ask “why” to generate hypothetical answers keeping in mind both the ‘soft’ (e.g. organization, mindsets) and ‘hard’ (e.g. operational) factors 3. Gather data to turn hypotheses into clearly supported facts 4. Iterate trees until reach an answer that is either a: – Mindset

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– Leadership issue, – Capability issue, or an – Organization issue, but realize that not all issues have these root causes 5. Test probable root cause by reversing current situation: – does it solve the problem?, or – is it caused by an element raised earlier in the tree? 6. If test fails, ask ‘why’ again or go one step back up the tree and ask ‘why’ there, if it passes, go to step 7. 7. Group the root causes – what are the potential interventions that emerge?

19.3 GAP SIZING ANALYSIS Description In the event that any specific activities performed poorer than expected a gap sizing analysis shall be conducted. This gap sizing exercise will include ‘cost’ as well as ‘production’ elements. Rationale Gap analysis is a business resource assessment tool enabling a company to compare its actual performance with its potential performance. This helps provide PETRONAS and PS Contractor with insight into areas that have room for improvement. Instructions and Format A gap is measured based on actual performance versus target or plan for any specific period. The gap will further broken down into deferment category as described in Appendix C (level 1).

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19.4 STAGE GATE Background The gap sizing will enabled PETRONAS and PS Contractor to pinpoint the most critical issues to close the production gap. This document provides and overview of the initiative tracking process requirements to manage high value initiatives. PS Contractor is required to develop a comprehensive set of interventions plan to the critical issues and develop a standard methodology to track and monitor intervention progress. Rationale The stage gate tool will provide greater transparency regarding intervention tracking, and to resolve specific issues as they arise. This tool will help to better understand the situation and actions to be taken. This document serves as an introduction to a four-step ‘stage gate’ project management methodology and templates to track high value interventions. Introduction to stage gate processes Stage gating is a project management tool that breaks down a project into a series of stages (activities) and gates (decision points), please refer to Appendix 19E. It uses a four-step stage gate process to monitor interventions i.e.: Stage Gate 1: Problem definition (refer to Appendix F) Stage Gate 2: Root cause solution (refer to Appendix G) Stage Gate 3: Implementation and risk mitigation plans (refer to Appendix H) Stage Gate 4: Implementation monitoring (refer to appendix I ) Please refer to Appendix E to J for the Stage Gate templates and guidelines. PETRONAS may request PS Contractors to submit the Stage Gates template on case by case basis. - END OF SECTION 19 -

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APPENDIX 1

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APPENDIX 1.1 HSE Case Guidelines for Documentation The Case described in this guideline is constructed in 7 parts as shown below:1.

Management Summary and Introduction The Management Summary provides a brief overview of the Case findings, a summary of the objectives established by operations management (based upon HSE MS objectives), and all parties associated with its compilation, review and validation. It may also include a description of historical HSE performance in the facility or operation by way of background to the objectives and targets set, and providing a baseline for future comparison over time of how HSE MS is actually performing in the operation.

2.

Operation’s HSE Management System The Operation’s HSE MS documents the quality system used for managing HSE risk in the specific facility or operation covered. It translates the material given in the HSE MS Manual from the corporate level, to the demonstration of practice at the level applicable to the management of the specific facility or operation. This section should demonstrate the operation specific application of the systems described in the HSE MS Manual. It should also detail local interpretation of corporate policies and objectives, contact persons, relevant meetings, controls and plans, e.g. contingency plans. It should relate, and be cross referenced to, appropriate parts of the hazard analysis and installation description. Reference should be as specific as possible. Documents, standards, procedures, etc., which are referenced to the Case should be controlled documents with unambiguous titles and document numbers.

3.

Activities Catalogue The Activities Catalogue shall contain the quality requirements for activities involved in the application of the Hazards and Effects Management Process in the facility operation. The documentation requirements shall also be cascaded from the corporate level to a level applicable to the facility or operation. As a general rule, the Case analysis documented in the Case Activities Catalogue should show that controls are in place and that the working practices and procedures are both suitable and sufficient.

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To include in this section: Foreword Describe the purpose of Activities Catalogue and how it is to be used. It shall also provide documentation of controls at the appropriate level and endorsement by the custodian of the documents. The Activity Records will require review cycles and re-endorsement as and when process custodian or activity owners change. Structure of the Activity Listing In all cases, supervisory staff needs to have understanding of the tasks carried out in their area of responsibility and should be able to confirm on the standing instructions and work instructions. The hazards and effects encountered in the work situation should be cross-checked with the activities to gain assurance that all hazards and effects are being effectively managed. Catalogue of Activity Records (Specification Sheets) The Activity Records, which should be endorsed and reviewed, can be used as the information database from which information can be extracted, which is both relevant and usable at the workplace. If Task Definition specification records are produced as an additional, same level of verification or business control is not required and it shall be cross referenced in the Activity Records. However, the Case does not necessarily require such task sheets, but it needs to refer to a competent set of work instructions and procedures instead. 4.

Description of Operation This section shall describe the essential features relevant to HSE and emergency management of the facility or operation, which will enable the understanding of how the hazards and effects could affect the facility or operation and its HSE systems. The process description and the facilities management shall be supported with technical illustrations for better understanding. The section shall consist of but not limited to: Outline of Operation HSE-critical Controls Illustrations



REVISION 2 AUG 2008

APPENDIX 1

5.

Page 389

Hazards and Effects Analysis The Hazards and Effects Analysis should demonstrate that all potentially significant hazards and effects have been identified, the risks from the hazards and effects evaluated and understood, and that controls to manage risks of the hazards and effects are in place. This section shall include: Hazards and Effects Analysis It shall summarize the investigations carried out as part of the Hazards and Effects Analysis into all types of accident scenarios, hazardous conditions, and environmental effects. This section shall be regarded as evidence that a full and systematic check has been made for hazards and effects and that potentially significant hazards and effects have been analyzed in terms of associated risks. Hazards and Effects Register The purpose of this register is to present in a clear and concise form, the results of the analysis made of each hazard or effects present at, or resulting from, the facility or operation. The contents shall demonstrate that all hazards and effects have been identified, are understood and are being properly controlled. It shall also demonstrate that the facility is adequately defended and preparations are in place to handle any emergencies. HSE-critical Operations Procedures This section covers mandatory HSE-critical operational procedures. These procedures will often already exist in some form as a part of the operating procedures and simply require to be flagged and for a listing to be produced. The procedures shall also include a statement of the hazard management objectives and the design assumptions inherent in its preparations.

6.

Identified Shortfalls and Remedial Work Plan The preparation of HSE Case is a fact finding process used to determine conformity at the installation/operational level to the various elements of the company’s HSE MS and the acceptance criteria for hazard and risk management. The Case should contain a demonstration of commitment to improvement by providing a plan, known as the “Remedial Work Plan”, to resolve the shortfall findings of the assessments



REVISION 2 AUG 2008

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Page 390

thereby improving the safety of the installation / operation. The plan should show action parties, a priority rating and completion dates. 7.

Conclusions and Statement of Fitness This section presents conclusions concerning meeting the objectives of the Case as simple as possible. It should also contain a Statement of Fitness for the operation or facility. In particular it that notes those events with the potential to cause major harm to people or the environment have been identified, assessed, controlled and that plans are in place for recovery in the event that control is lost. It shall conclude that the Case demonstrates the facilities’ management system in place, adequately to enable the company to comply with all relevant statutory and company provisions and any activity in connection with it. In view of the above, the operation/installation is considered safe to operate.



REVISION 2 AUG 2008

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Page 391

APPENDIX 1.2 Data Submission Guidelines for Reporting of Health, Safety and Environment Data Submission

Frequency

Reporting Level

A

Health:

1

Total Reportable Occupational Illness (TROI: No. Of Cases)

Monthly

PMU Regional & KL Office

2

Total Reportable Occupational Illness Frequency (TROIF)

Monthly


B

Safety

1

Fatality*

Monthly


2

Lost Time Injury* (LTI)

Monthly


3

Lost Time Injury Frequency (LTIF)

Monthly


4

Total Reportable Case Frequency (TRCF)

Monthly


5

Restricted Work Cases* (RWC)

Monthly


6

Medical Treatment Cases* (MTC)

Monthly


7

First Aid Cases

Monthly


8

Fire and or Explosion Incident

Monthly


9

Nearmisses Cases

Monthly


10

Unsafe Acts/Unsafe Conditions

Monthly




REVISION 2 AUG 2008

APPENDIX 1

Page 392

Data Submission Guidelines for Reporting of Health, Safety and Environment Data Submission

Frequency

Reporting Level

C

Environment

1

No. of Major Oil Spill Incident & Volume (> 5 bbls)*

Monthly


2

No. of Major Oil Spill Incident & Volume (> 5 bbls)

Monthly


3

Oil Spill Index (Total vol. of oil Spill/Total Production (bbl))

Monthly


4

No of Condensate Spill Incident & Volume (bbl)

Monthly


5

Effluent Discharge Quality* (Oil & Grease) from Onshore Terminals (Crude & GasT)

Monthly


6

Produced Water Quality* (Oil in Water) from Offshore (including FSO/FPSO)

Monthly


7

Hydrocarbon & Toxic Gas release

Monthly


8

GHG Emission (CO2, CH4, Total CO2 in tonnes and Total CO2(tonnes)/kBOE)

Quarterly

PMU KL Office

9

Scheduled Wastes

As per DOE req

PMU KL Office

10

TENORM Wastes

As per AELB req

PMU KL Office

D

Others

1

Property Damages (all categories under RAC)

Monthly


2

Number of fines (by Authority)

Monthly


3

Total Manhours Worked

Monthly

PMU KL Office

4

Vessel Encroachment (within 500 m radius)

Monthly


*Note HSE incident reported under Fatality, LTI, RWC, MTC, Fire/Explosion, Oil Spill (>5 bbls), EDQ & PWQ of > 40 ppm and Vessel encroachment shall be supported by incident description, Initial findings and lesson learnt to be attached together with the monthly report. For LTI, the report shall include the following:a. Summary of incident b. Investigation findings c. Root cause d. Action taken e. Lesson learnt Submissions of the HSE KPI by PS Contractor to PMU shall be made in the form of softcopy, followed by a formal hardcopy issuance by the 15th. of the following month. SUPERSEDE ISSUE: AUG 2000


REVISION 2 AUG 2008

APPENDIX 1

Page 393

APPENDIX 1.3

List of Health, Safety and Environmental Documents for Submission List of Submission

Frequency

Deadline

Reporting Level

1

HSE-MS Manual

Once

Within one month after endorsement


2

HSE Cases (Production Phase)

Once

One month before commencement

PMU KL Office

3

CIMAH Report (for onshore operations)

Once


PMU KL Office

4

Health Risk Assessment

Once

One month after the assessment

PMU KL Office

5

HSE Plan

Yearly

December of the preceding year


6

Emergency Response Plan

Once


PMU KL Office

7

HSE KPI Report

Monthly

Every 15th of the following month


8

HSE-MS Audit Final Report

As per audit plan

One month after audit completion


9

HSE Audit Final Report

Upon request

-


10

Incident Investigation Report

Upon completion of the investigation

One month after the date of incident


11

EIA/EMP Report

Once

One month after DOE approval

PMU KL Office

12

EIA Approval Condition

Once

One month after DOE approval

PMU KL Office

13

Environmental Compliance Report

As per DOE/AELB requirements

-


14

GHG Emission

Quarterly

-

PMU KL Office



REVISION 2 AUG 2008

APPENDIX 1

Page 394

APPENDIX 1.4 GAZETTING CHECKLIST •

Most recent photos: - size 8” x 10” - 5 angles (north, south, east, west, aerial) - 1 copy each angle

•

Hydrographic map: - scale 1:5000 - 2 copies (one copy each for GSO and AG)

•

Contour map: - scale 1:500 000 - 2 copies (one copy each for GSO and AG)

•

Relevant information: - name of facility - type of facility - spherical coordinates - purpose of facility (oil/gas/both) - location (nm from shore) - field name that the installation is used for - oil and gas production (after installation) - value of installation (in RM million)


Not needed for resubmission


REVISION 2 AUG 2008

AUG 2000

SUPERSEDE ISSUE:

•

• •

M o nito r th e su b m issio ns P ro vide clarificatio ns to legal if requ ired A ssist in interface w ith PSC s

PM U H SE

(3 m on ths)

Jab . P egu am N eg ara (A G ’s ch am b er) - B h g G u b alan

PRO PO SE D PLA TFO R M G A ZE TTEM ENT PR O C ESS

Government

PSC & PETRONAS

• •

•

•

S ub m ission d on e by focal dept/ section A pp ly w ith in 6 m o n th s after in stallation is com pleted

N o te: * if th ere is n o issu e ** if require further actions from P S C s

V erification S ub m it app lication to C S D

V erification S ub m it app lication to G S O P utrajaya

V erification - check & record based on go vt’s requirem ents S ub m it app lication to A ttorney’s gen eral O ffice for L egal E n dorsem ent

(1 w eek * to 1 m o nth * * )

(1 w eek)

• •

•

•

P rim e M inister O ffice As M in ister H om e A ffairs (1 m o nth to 3 m on th s)


PSC

E & P L egal D ept. (H ead of L egal)

C o rp o rate S ecurity D epartm en t (C S D ) (S M , Plan nin g, D ev. & C risis M gt) cc: C O M C E N

(1 m on th )

G overn m ent S ecurity O ffice (G S O ) -U n it K w s L aran gan / T pt Larangan

(E nd orsem en t)

K em en terian K eselam atan D alam N egeri - P en. S etiau sah a

APPENDIX 1.5

APPENDIX 1

REVISION 2 AUG 2008

28

Page 395

APPENDIX 2

Page 396

APPENDIX 2.1 LIST OF LOCAL AUTHORITIES 1. Yang Berbahagia Setiausaha Kerajaan Negeri Terengganu Pejabat Setiausaha Kerajaan Tingkat 15, Wisma Darul Iman 20503 Kuala Terengganu Terengganu Darul Iman Fax : 09-6234278 Tel : 09-6231957 2. Pengarah Bahagian Perlindungan Sumber Ibu Pejabat Perikanan Malaysia Kementerian Pertanian Malaysia Aras 1-7, Menara Blok 4G2 Wisma Tani Presint 4 Pusat Pentadbiran Kerajaan Persekutuan 62628 W.P Putrajaya Fax : 03-88892786 3. Pengarah Operasi Jabatan Arah Operasi Kementerian Pertahanan (Kementah) Jalan Padang Tembak 50634 Kuala Lumpur 4. Pengarah Pusat Penyelarasan Penguatkuasaan Maritim Bahagian Keselamatan Negara Jalan Iskandar Shah Telok Muroh 32200 Lumut Perak Darul Ridzuan Tel : 05-6804111 / 6834113 / 6835291 / 6834961 5. Syahbandar Pantai Timur Pejabat Syahbandar 20000 Kuala Terengganu Terengganu Darul Iman



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APPENDIX 2

Page 397

6. Pengarah Perikanan Negeri Terengganu Wisma Perikanan Negeri Taman Perikanan Chendering 21080 Chendering Kuala Terengganu Terengganu Darul Iman Fax : 09- 6173351 Tel : 09 - 6173352 / 6173353 7. Pengarah Perikanan Negeri Kelantan Tingkat 6, Wisma Persekutuan Jalan Bayam 15628 Kota Bharu Kelantan Darul Naim Fax : 09-7483433 Tel : 09-7486606 / 7482851 8. Pengarah Laut Jabatan Laut Sarawak Lot. 683, Seksyen 66 Jalan Utama Tanah Puteh 93619 Kuching, Sarawak Fax : 082- 331778 Tel : 082- 484159 9. Pengarah Laut Jabatan Laut Malaysia Pejabat Laut Wilayah Persekutuan Labuan Peti Surat 81005 87020 Wilayah Persekutuan Labuan Tel.: 087-413511 Fax No. : 087-413515 Website: www.marine.gov.my 10. Pengarah Perikanan Laut Jabatan Perikanan Laut Sarawak Tingkat 15, Bgn Sultan Iskandar Jalan Simpang Tiga, Peti Surat 1375 93728 Kuching, Sarawak Fax : 082-415499 Email : [email protected] Tel : 082-252743 / 250357



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APPENDIX 2

Page 398

11. Pengarah Perikanan Laut, Jabatan Perikanan Sabah Aras 4, Blok B Wisma Pertanian Sabah Jalan Tasik Luyang Off Jalan Maktab Jaya 88624 Kota Kinabalu, Sabah Fax : 088- 240511 Tel : 088- 235966 / 245489 / 245484 Email : [email protected] 12. Pengarah Jabatan Perikanan Labuan Km 4, Jalan Patau-Patau Peti Surat 81411 87024 W.P Labuan Fax : 087- 412885 Tel : 087- 415881 13. Pegawai Laut Jabatan Laut Sarawak Kawasan Sarawak Timur Pejabat Bahagian Miri Jalan Kubu, Beg Berkunci No.18 98009 Miri Sarawak Tel.: 085-442121 Fax No.: 085-418608 14. Marine Manager, Bintulu Port Sdn. Bhd Km 12, Jalan Tanjung Kidurong P.O.Box 996, 97008 Bintulu, Sarawak Fax No.: 086-253597 15. Ketua Bahagian Haidrografi, Markas Tentera Laut Kementerian Pertahanan (Kementah, KL) Jalan Padang Tembak 50634 Kuala Lumpur Fax No.: 03-3685289 16. Senior Manager Petronas Maritime Services Sdn Bhd Level 16, Menara Dayabumi Jalan Sultan Hishamuddin 50050 Kuala Lumpur Tel.: 03-27836000 Fax No.: 27836966



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APPENDIX 2

Page 399

17. General Manager Petroleum Resource Exploration Petroleum Management Unit Level 22, Tower 2 PETRONAS Twin Towers Kuala Lumpur City Centre 50088 Kuala Lumpur Fax No.: 03-5813238 18. Senior Manager Sabah/Sarawak Regional Office Petroleum Management Unit Jalan Sekolah 98100 Lutong Sarawak Fax No.: 085-662623 19. Senior Manager East Cost Regional Office Petroleum Management Unit 3rd Floor, PETRONAS Office Complex 24300 Kertih, Kemaman Terengganu Fax No.: 09-8640127



REVISION 2 AUG 2008

APPENDIX 2

Page 400

APPENDIX 2.2A

Flag

Bamboo Buoy Sea Surface

Coconut leaves

Sinkers Seabed

Type : UNJANG



REVISION 2 AUG 2008

APPENDIX 2

Page 401

APPENDIX 2.2B

Floats Sea Surface

Coconut Leaves Rope

Weight

Type : UNJANG BUAI



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APPENDIX 2

Page 402

APPENDIX 2.2C

Bamboo Sea Surface

Galvanized Wire

Sinkers Seabed

Type : UNJANG IBU



REVISION 2 AUG 2008

APPENDIX 2

Page 403

APPENDIX 2.2D

Dove-eyed Wire

Valve Trap Door

Weight Base

Type : BUBU



REVISION 2 AUG 2008

APPENDIX 2

Page 404

APPENDIX 2.2E

Type : FISH TRAP



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APPENDIX 2

Page 405

APPENDIX 2.2F

Dan Buoy Sea Surface

Briddle

Dove-eyed Wire

Weighted Base

Seabed

Type : FISH TRAP



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APPENDIX 3

Page 406

APPENDIX 3.1 MILESTONES DEFINITION a)

Planning Milestone(MR#1) The Planning Milestone is reached when a feasibility study of a potential field or area development has been completed. The feasibility study provides reserves assessment, preliminary development concepts, cost and schedule and economic viability. In this phase, although uncertainties are at the highest level, broad outline of the project can be defined.

b)

Geological and Geophysical (Static) Milestone (MR#2) The Geological and Geophysical Milestone is reached when the geological description, resource size and associated uncertainties have been reasonably established and addressed. At this stage, the main deliverables are seismic related structural and attribute maps, structural and reservoir maps, crosssections, petrophysical summary and gross bulk volumes and volumetric inplace. Sufficient work would have been performed to provide a comprehensive description and interpretation of subsurface reservoirs. Upside potential and future plans to appraise such potential should be highlighted.

c)

Reservoir (Dynamic) Milestone (MR#3) The Reservoir Milestone is reached when the subsurface aspects of the field including depletion mechanism, size of recoverable reserves, expected production profile, number of platforms, numbers and types of development well have been reasonably established. At this stage an optimal sub-surface development option would have been studied to include important considerations such as well density and coverage, application of new technologies i.e., horizontal and multi-lateral wells, suitability of pressure maintenance and suitability of enhanced recovery techniques. For fields containing high carbon dioxide , this milestone must address the potential for enhanced recovery and/or geo-sequestration through immiscible or miscible carbon dioxide injection. An important aspect of this milestone is to address the uncertainties, alternative scenario outcomes and the range of possible outcomes for each scenario. The reservoir appraisal, monitoring and surveillance programmes aimed at resolving these uncertainties must also be addressed.

SUPERSEDE ISSUE:

AUG 2000


REVISION 2 AUG 2008

APPENDIX 3

Page 407

Lastly, this milestone must address the potential for cluster or phased development of other nearby discoveries or exploration prospects if they are successful. d)

Development Milestone (MR#4) The Development Milestone is reached when the preferred development concept consistent with the reservoir development scenario, well design and facilities design has been evaluated. These cover processing, gathering, gas utilization, storage and evacuation systems. At this stage a firm base case for field development outlining the preferred technical option with uncertainties would have been identified and quantified. Any potential for development integration with existing facilities (even if these are operated by another PS Contractor) must be addressed. Where it is necessary to examine potential for development integration between two or more PSCs, PETRONAS will facilitate these discussions upon request. Bases for the selected development option should be clearly defined. In addition, PS Contractors shall also briefly discuss all the shortlisted options and their evaluation results. Cost estimates should be of sufficient accuracy and breakdown for Work Program and Budget purposes.

SUPERSEDE ISSUE:

AUG 2000


REVISION 2 AUG 2008

Page 408

APPENDIX 3

APPENDIX 3.2 GOVERNMENT AND PETRONAS' OBJECTIVES

a)

comply with PSC requirements

b)

ensure application of appropriate exploration technology which reduces uncertainty and risk

c)

ensure that sufficient and accurate data is gathered

d)

ensure that development and depletion of discovered fields are at a pace consistent with national needs

e)

secure the full recovery of developable reserves and address future potential

f)

avoid waste of petroleum and reservoir energy in the recovery of reserves

g)

an infrastructure should, where feasible, aid future field developments

h)

an integrated development concept be pursued, where applicable

i)

impact of field scheduling on crude/gas quality and area development

j)

comply with local regulations and government policies

k)

adopt oilfield practices that are comparable with practice adopted in similar, successful developments

SUPERSEDE ISSUE:

AUG 2000


REVISION 2 AUG 2008

APPENDIX 3

Page 409

APPENDIX 3.3 MILESTONE REVIEWS’ KEY ACTIVITIES LIST Key Activities List – Planning Milestone #1

KEY ACTIVITY

DESCRIPTIONS

PSC compliance

•

PSC commitment to undertake area/field development from exploration, development and production within the period of PSC

Data availability & validation

• • • •

resource assessment production forecast subsurface / well planning seismic (2D, 3D, OBC & Hires seismic/reprocessing) fluid properties, appraisal geohazard, seabed / route / area survey metocean, environmental data

• • •

Resource Assessment

•

volumetrics, recoverable reserves, upside and downside potential, reserves uncertainties

Feasibility study / Conceptual Development Plan

•

surface development options comparison (type of facilities) subsurface development options (no of wells, pressure maintenance, EOR feasibility etc) capital and operating expenditures (high level estimates) project timing/preliminary milestone schedule (1st production / startup), development phases new technology application production rate evacuation route

• • • • • •

SUPERSEDE ISSUE:

AUG 2000


REVISION 2 AUG 2008

APPENDIX 3

Page 410

MILESTONE REVIEWS’ KEY ACTIVITIES LIST Key Activities List – Planning Milestone #1(cont’d..)

KEY ACTIVITY Area Development

DESCRIPTIONS • • • •

sharing of facilities, infrastructure evacuation options host facility integrity clustar development, with field unitisation (if applicable), near field

Project Risk Management

•

risk identification, assessment, mitigation plan

Economic Feasibility

• •

indicative economics including sensitivities cases early monetisation

• • • •

Maximise local content plan

SUPERSEDE ISSUE:

AUG 2000

zero flaring / venting plan decommissioning of facilities / abandonment of wells asset integrity HSE compliance (especially on EIA)

• • • •

supply/demand forecast project value ranking tariff/ullage field unitisation (if applicable)

• •

project organisation project value chain (i.e. design, fabrication etc.)


REVISION 2 AUG 2008

APPENDIX 3

Page 411

MILESTONE REVIEWS’ KEY ACTIVITIES LIST Key Activities List – G&G Milestone #2 (Geophysics) KEY ACTIVITY (geophysics)

DESCRIPTIONS •

•

site investigation for pipeline route survey, platform hazard, geohazard such as shallow gas & seabed channels, gas chimney, gas seepage, pork mark & sink holes. seismic; 2D vs 3D, wellbore data (VSP, DSI, etc) recent technology (shear wave, 4C & OBC) reprocessing and new acquisition (PSDM, PSTM, under shooting, Q-3D) seabed logging (electromenictic) & high resolution seismic

• • • • •

isochore/ net sand/ reservoir map, seismic workflow attribute analysis (spec. decomp, coherency, sweetness, etc) velocity analysis/depth conversion/synthetic seismogram structural reconstruction/modeling geo-volume interpretation (GVI)

• •

Multi-attributes, seismic facies analysis seismic/wellbore quantitative analysis (i.e. reservoir calibration and prediction) forward modeling such as AVO & seismic inversion (AI) Q migration/ Time lapse analysis

• • •

Seismic Interpretation

• • • • •

reservoir container size & shape (i.e. sheet sand or chanelise), reservoir continuity reservoir stratigraphic demarcation (channel boundaries & geobodies) fault linkages, fault compartmentalisation

Legend:

!"

!

$ %&! % &

% % &

" # #$ '!

SUPERSEDE ISSUE:

AUG 2000


REVISION 2 AUG 2008

APPENDIX 3

Page 412

MILESTONE REVIEWS’ KEY ACTIVITIES LIST Key Activities List – G&G Milestone #2 (Geology) KEY ACTIVITY (geology)

DESCRIPTIONS

Geological Database

• • •

depositional environment/hydrocarbon migration/source rock tectonic history/structural style wellbore database quality and quantity (logs, cores, RFT etc)

Stratigraphy/ Structural /Sedimentation/ Studies

• • • • • • • •

well to well correlation/cross section/sequence stratigraphy structural reconstruction/fault analysis facies analysis (log/core calibration & descriptions) reservoir characterisations i.e. architecture reservoir description (diagenesis, sedimentology, petrography, biostratigraphy & geochemistry etc) fluid analysis i.e. compositional analysis & crude properties geomechanics/rock physics. geopressure

Static Model

• • • • • •

structure, trend mapping, structural/ stratigraphic X-section 3D geologic modeling/facies modeling deterministic/stochastic modeling GBV calculation STOIIP computation STOIIP distribution (By platform, fault blocks, etc)

Resource Assessment

• •

methodology/approach (probabilistic and deterministic) classification as per PETRONAS Resources Classification and Guidelines uncertainties and risk

• Upside potential

• • •

updip/downdip potential, deeper HPHT/ untested fault block / near field potential/stratigraphic untested reservoir/fault block/new play potential future plans/propose appraisal

Legend: Sw = Water Saturation RFT = Repeat Formation Tester HPHT = High Pressure High Temperature COS = Chances of Success SR = Speculative Recovery SUPERSEDE ISSUE:

AUG 2000


REVISION 2 AUG 2008

APPENDIX 3

Page 413

MILESTONE REVIEWS’ KEY ACTIVITIES LIST Key Activities List – G&G Milestone #2 (Formation Evaluation)

KEY ACTIVITY (formation evaluation) Database

DESCRIPTIONS • • • •

Analysis

• • • • • • • • • • • • • • • • •

SUPERSEDE ISSUE:

AUG 2000

input/output logs reservoir parameters (internal averages I.e. net sands, porosity, Sw, etc.) composite logs routine and SCAL formation water analysis V-shale & V Clay analysis NMR analysis saturation determination techniques (resistivity-based & resistivity independent such as Pc) borehole image analysis LRLC (log modelling) rock mechanics log-core calibration techniques environmental corrections (log editing) pressure analysis production logging analysis permeability modelling/porosity modelling cut-offs justification geological integration log reconstruction, petrofacies uncertainty analysis comprehensive documentation


REVISION 2 AUG 2008

APPENDIX 3

Page 414

MILESTONE REVIEWS’ KEY ACTIVITIES LIST Key Activities List – Reservoir Engineering Milestone #3 KEY ACTIVITY Reservoir Model

DESCRIPTIONS • • • • • • • • • • •

,

• • • Reservoir Mgmt Plan and Operating Strategy

RSP ( refer to PPGUA Section 12 for details)

( ' * ()+

)

SUPERSEDE ISSUE:

AUG 2000

construction of the model fluid interaction and rock properties PVT reports, core analysis, DST etc reservoir geometry, aquifer size, gascap size, oil column, GOR, dip, production data fluid contact fluid properties and composition pressure data number of platforms/wells, drainage plan, oil and gas depletion plans, secondary recovery, production profile, recovery efficiencies application of horizontal or multi-lateral wells EOR (processes, performance, well spacing) etc. well test results, well deliverabilities, well flow analysis,well integrity analysis formation damage completion design, sand exclusion, artificial lift, perforation techniques production problems, stimulation techniques application of horizontal or multi-lateral wells

• • •

well and reservoir monitoring offtake rate, GOR limit, drawdown, target pressure, well intervention GIGP ratio, waterflood mgmt, EOR surv program and sensitivity analysis

• • • •

additional data acquisition, aquifer size upside potential, downside risk deliverability ullage development phasing impact

• •

•

objective well and reservoir monitoring plan (surveys- no survey & frequency, well test requirement) potential and well reservoir issues and mitigation plan (artificial lift, formation damage, sand production etc.) well intervantion plan

• •

oil>45% gas>85%

•


REVISION 2 AUG 2008

APPENDIX 3

Page 415

MILESTONE REVIEWS’ KEY ACTIVITIES LIST Key Activities List – Development Milestone #4 KEY ACTIVITY /

SHORTLISTED DESCRIPTIONS •

'

• • • • • • •

,

.

• • • •

drilling experience, drilling plans & schedule well design, rig selection, material selection, new technology, drilling risks completion design, sand exclusion, perforation techniques production problems, stimulation techniques type of drilling mud used (water / oil based mud) generate detail well package (refer to para 3.1.9.6 of this document) Describe all technology application, if applicable Describe potential production problem due to mud design,etc

• • • • •

Surface Development Concept

• • • • • • • • •

SUPERSEDE ISSUE:

AUG 2000

outline description of the field/reservoirs proposed for development reservoir depletion mechanisms Number and location of wells likely required Pressure maintenance requirement i.e gas injection and/or gas production forecasts of oil, gas, water and greenhouse gases production proposed means of disposing greenhouse gases forecast reservoir pressures and produced fluid properties appraisal opportunities through development drilling or early production

options shortlist and final selection facilities requirement, material selection corrosion Management Plan flow Assurance structural integrity and available ullage at host platform cost reduction efforts gas disposition plan zero flaring / venting commitments HSE Philosophy


REVISION 2 AUG 2008

APPENDIX 3

Page 416

MILESTONE REVIEWS’ KEY ACTIVITIES LIST Key Activities List – Development Milestone #4 (cont’d) KEY ACTIVITY

DESCRIPTIONS •

Measurement

• •

measurement concept/method (fiscal, allocation or operation) validation & certification requirement well testing requirements

New technology

•

Final Evacuation Route

• • •

evacuation route throughput capacity, pipeline material selection flow assurance

Decommissioning

•

timing / schedule, method, cost estimate for decommissioning of facilities and abandonment of wells

Project Risk Mitigation Plan

•

project risk register - surface and sub-surface

SUPERSEDE ISSUE:

AUG 2000

surface and sub-surface technology application


REVISION 2 AUG 2008

APPENDIX 3

Page 417

MILESTONE REVIEWS’ KEY ACTIVITIES LIST Key Activities List – Development Milestone #4 (Cont’d..)

KEY ACTIVITY Economic Analysis

DESCRIPTIONS • •

Project returns on the selected development concepts (Base Case vs options – IRR, NPV, assumptions) Incremental project returns for IOR/EOR projects

Final Cost Estimates

•

CAPEX & OPEX cost estimate including cost phasing (well, platform, floaters, drilling, pipeline etc)

Project Master Schedule

• •

Detail schedule activities First production/startup date

Operating Philosophy

• • • •

manning requirements shutdown & control philosophy inspection & maintenance philosophy reliability & asset integrity

HSE Requirements

• • •

compliance with local authority basic facility safety design philosophy HSE risk management

EOR Initiative / Plan

•

provision for EOR implementation: well slots, space & facilities upgrade provision

Lessons learnt

•

lessons learnt from similar past projects

Contracting Strategy

•

preliminary Overall Contracting Strategy

Design Basis Memorandum

•

preliminary design concept

SUPERSEDE ISSUE:

AUG 2000


REVISION 2 AUG 2008

Page 418

APPENDIX 3

APPENDIX 3.4 FDP/NOP REVISION MATRIX

Changes to plan in FDP

FDP Revision

NOP Revision

1

Target location changes within 1km radius of original target in the same region or fault block (including workover sidetracks to correct/optimize perforation depths). Plan not addressed in the approved FDP

2

Target location changes within 1km radius of original target but to a different fault block / region (plan not addressed in the approved FDP)

Y

Y

3

Addition and deletion of wells

Y if not addressed in FDP

Y if addressed in FDP

4

Changes to depletion strategy (if not addressed in FDP)

Y

5

Changes to well utility eg producer to injector, or vice versa

Y if not addressed in FDP

6

Addition and deletion of completions or changes to tubular sizes or casing program with no change in well utility / type eg. addition or deletion of packers, bigger or smaller tubings, conventional vs horizontal well, changes in sand control type, etc. . Plan not addressed in the approved FDP.

Y

7

Deeper TD due to G&G / Reservoir / Operational reasons

Y

8

Changes to well cost estimates

Y

9

Well sidetrack or suspension due to G&G / operational reasons (excluding sidetracks / suspensions already planned in NOP)

Y

10

Significant changes to facilities concept

SUPERSEDE ISSUE:

AUG 2000


Y (NOP revision or NOWOP approval)

Y if addressed in FDP

Y

REVISION 2 AUG 2008

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APPENDIX 4.1 SECTION 4 OF PETRONAS TENDERS & CONTRACTS ADMINISTRATIVE PROCEDURE MANUAL FOR UPSTREAM PROCUREMENT ACTIVITIES EXECUTION OF PROCUREMENT ACTIVITIES 4.1.1 SCREENING Definition: Screening of bidders is an exercise where bidders in all appropriate categories of the LLRC are asked whether they are interested to bid. Scope: This process takes place before the list of bidders to be invited in the tender exercise is finalised. Screening are generally carried out to check licensed company interest to participate in bidding exercise when there are too many companies in the LLRC Principle: All companies in the appropriate SWEC of the LLRC at the time of the screening exercise shall be invited for the exercise. PETRONAS prior approval is not required to carry out screening exercise. For above CTL, the result of the exercise together with the recommended list of bidders shall be incorporated in the Tender Plan and shall be presented to the relevant Tender Committee within one (1) month after the closing date of the screening exercise. The above principles shall apply to all value bands. Screening Process (SC)

Value Band Above CTL

CTL & Below

SUPERSEDE ISSUE:

AUG 2000

Process SCAC1

In the screening, all bidders listed in the relevant Work Category shall be invited.

SCAC2

PS Contractors shall incorporate list of invited bidders and screening results in the Tender Plan.

SCBC1

As per individual PS Contractors'in-house procurement procedures.


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4.1.2 TENDER PLAN Definition: The Tender Plan is the package that describes the scope of work, procurement strategy, evaluation criteria, etc. Scope: The Tender Plan shall contain but not limited to the following: i)

Project Background / Tender Brief.

ii)

Scope Of Work.

iii)

Procurement Strategy And Methodology.

iv)

MPP Code.

v)

Tender And Project Schedule.

vi)

Highlights of Instructions To Bid (ITB).

vii)

Bidders List/Basis Of Selection.

viii)

Bid Evaluation Process.

ix)

Technical Evaluation, Methodology, Criteria and Team Member.

x)

Commercial Evaluation, Methodology, Criteria and Team Member

xi)

Highlight of the Technical Evaluation Criteria & Specification for TCC.

xii)

Technical & Commercial evaluation criteria for procurement above RM15 Million, a separate technical and commercial evaluation criteria proposal must be submitted to TCC for approval.

Principle: For procurement above the CTL, PETRONAS prior approval of the Tender Plan is required except for the following cases: i)

Sole Source items provided such items are identified and approved by PETRONAS in the yearly consolidated Master Procurement Plan such as VDP and proprietary items.

ii)

Marine vessels under CORAL Database (less than twelve (12) months with value less than RM5 Million). Any intention to bid shall only require PETRONAS Technical Coordinator’s prior approval.

iii)

For Umbrella Contracts: a)

With Approved Contract Value (Umbrella Design Service Contract (UDSC)) - value of each work order less than the value as specified in the approval letter.

b)

Without Approved Contract Value (Umbrella Design Service Agreement (UDSA)) - value of each work order less than the value as specified in the approval letter.

SUPERSEDE ISSUE:

AUG 2000


REVISION 2 AUG 2008

APPENDIX 4

Page 421

The cut-off date for the recommended list of bidders in the Tender Plan shall be on the day of the appropriate Tender Committee meeting. The decision on the final list of bidders to be invited for bidding shall rest with the respective Approving Authority. PS Contractors shall ensure that bid validity period is kept as short as practicable and guided by the following common practices: i) ii)

Below RM15 Million - 90 days or less RM15 Million and above - 90 -120 days

In the event there is a requirement to extend the bid validity for any tender above CTL, PS Contractors shall seek PETRONAS prior approval to extend the bid validity.

SUPERSEDE ISSUE:

AUG 2000


REVISION 2 AUG 2008

APPENDIX 4

Page 422

Tender Plan Process (TP) Value Band Above

Process TPA1

RM15 Million

Two (2) sets of the draft Tender Plan shall be submitted to the Senior Manager, PSC Management Department for PETRONAS review. The Tender Plan shall be in the format given in ATTACHMENT VIII. Compliance to this format will ensure the quality of the submission and timely PETRONAS review. Non-compliance to the format will render the submission automatically rejected.

TPA2

The Tender Plan shall be reviewed and signed by the Technical Coordinator and Techno-Commercial Coordinator. The review is expected to complete within ten (10) working days.

TPA3

Seven (7) copies of the Tender Plan shall be submitted by PS Contractors to the TCC Secretary, three (3) working days before the TCC meeting.

TPA4

After Tender Committee deliberation, PS Contractors should submit the amended report incorporating all Tender Committee’s comments. The amended report must be re-signed and submitted to the TCC Secretary within 14 days. However, amended report submitted within 24 hours after deliberation need not be resigned. Failure to comply with the above, PS Contractors is required to re-present the Tender Plan in the subsequent Tender Committee meeting.

TPA5

Once endorsed by the TCC, the Tender Plan shall be signed by the TCC Chairman. Eight (8) copies shall be submitted by PS Contractors to the CTC Secretary, three (3) working days before CTC meeting. Two (2) additional copies will be provided by PS Contractors to the Technical Coordinator and Techno-Commercial Coordinator.

SUPERSEDE ISSUE:

AUG 2000


REVISION 2 AUG 2008

APPENDIX 4

Page 423

Tender Plan Process (TP) (continued) Value Band Above CTL to RM15 Million

Process TPAC1

Two (2) sets of the draft Tender Plan shall be submitted to the Senior Manager, PSC Management Department for PETRONAS review. The Tender Plan shall be in the format given in ATTACHMENT IX and ATTACHMENT X. Compliance to this format will ensure the quality of the submission and timely PETRONAS review. Non-compliance to the format will render the submission automatically rejected.

TPAC2

The Tender Plan shall be reviewed and signed by the Technical Coordinator and Techno-Commercial Coordinator. The review is expected to complete within ten (10) working days.

TPAC3

Seven (7) copies of the Tender Plan shall be submitted by PS Contractors to the relevant Tender Committee Secretary three (3) working days before the JTC meeting.

TPAC4

After Tender Committee deliberation, PS Contractors should submit the amended report incorporating all Tender Committee’s comments. The amended report must be re-signed and submitted to relevant Tender Committee Secretary within the following time frame: MJTC - 14 days JTC - 7 days RJTC - 7 days However, amended report submitted within 24 hours after deliberation need not be resigned. Failure to comply with the above, PS Contractors is required to re-present the Tender Plan in the subsequent Tender Committee meeting.

CTL & Below

SUPERSEDE ISSUE:

AUG 2000

TPAC5

Once endorsed by the relevant Tender Committee, the Chairman shall prepare the Tender Committee Meeting Summary for approval from Approving Authority.

TPBC1

As per individual PS Contractors’ in-house procurement procedures.


REVISION 2 AUG 2008

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Page 424

4.1.3 ISSUANCE OF INVITATION TO BID (ITB) DOCUMENT Definition: ITB documents comprise instructions to the bidders, technical requirements, terms and conditions for procurement and the standard format for all the bidders in submitting their bids. Scope: This covers the process of issuance of ITB to the approved bidders. Principle: ITB documents shall only be issued to the bidders as approved in the Tender Plan. The bidders must comply fully with the ITB requirements in their base bid. Qualifications and exceptions may render their bids as being non compliant and the bidders may be disqualified. Alternative proposals are generally encouraged but such alternatives shall only be considered against the base bid. ITB Process (ITB) Value Band Above CTL

Process ITBAC1

PS Contractors shall require bidders to submit at least three (3) copies of technical and two (2) copies of commercial bid proposals of which one (1) set is marked “Original” and the remaining sets are marked “Copy 1” and/or “Copy 2”. All copies of the bid proposals shall be marked “CONFIDENTIAL”.

ITBAC2

Any amendment to the ITB documents after its issuance must be approved by PETRONAS. PS Contractors shall communicate such amendments in writing to all bidders within a reasonable time prior to closing date of receipt of tenders. Any amendment thus advised, shall be deemed to constitute part of the Invitation to Bid documents. Where necessary, PS Contractors may revise the closing date for receipt of bids upon receiving PETRONAS’ approval in order for bidders to comply with the amended requirements.

SUPERSEDE ISSUE:

AUG 2000


REVISION 2 AUG 2008

APPENDIX 4

Page 425

ITB Process (ITB) (continued) Value Band

CTL & Below

Process ITBAC3

Any additional information, interpretation, or advice to the tender package given by or agreed upon by PS Contractors shall be made known to all the bidders.

ITBAC4

Any information, which may be required by the bidders in order to complete their bids or any interpretation thereof, shall be documented.

ITBBC4


4.1.4 RECEIVING BID PROPOSAL (RB) Definition: Bid proposals are the submissions made by the bidders based on the invitation solicited by PS Contractors. These consist of separate technical and commercial bid proposals. The technical bid proposals shall include the unpriced commercial proposals. Scope: This process covers the receipt of bid proposals from the bidders and includes the safe custody of the bid proposals until formally opened. Principle: Security of documents is to be strictly observed. Packages are to be in sealed envelopes clearly marked as “Commercial”, “Technical”, "Original”, “Copies”, as applicable, together with bidder's name and deposited in a designated locked tender box/room before specified bid closing time. It shall be the responsibility of all personnel involved in procurement to maintain the confidentiality of bid documents and to ensure that they are kept in a safe and secure place at all times. A Tender Register is to be maintained to record details of receipt. Non compliance to bid instructions and late bids shall be rejected after due consideration of the circumstances.

SUPERSEDE ISSUE:

AUG 2000


REVISION 2 AUG 2008

APPENDIX 4

Page 426

Receiving Bid Process (RB) Value Band Above CTL

Process RBAC1

After the bid closing time, PS Contractor should record the following: i)

Name of bidders invited / collected

ii) Number of bid received iii) Name of bidders who submitted bid Non compliance to bid instructions and late bids shall be rejected after due consideration of the circumstances. The PS Contractors shall deposit its detailed Cost Estimate (endorsed by PS Contractors’ Team Leader) in a sealed envelope into the tender box prior to opening of commercial bids. CTL & Below

RBBC1

As per individual PS Contractors in-house procurement procedures.

4.1.5 BID OPENING (BO) Definition: Bid Opening - Authorised opening of solicited bids received from bidders and detailed PS Contractors cost estimates. Basically there are two types of bid opening: i)

Technical Bid Opening - the formal opening of technical bid proposal received from bidders invited to bid for the tender.

ii)

Commercial Bid Opening - the formal opening of commercial bid proposals and cost impacts resulting from technical clarifications.

Bid Opening Committee - A committee set up by PS Contractors to administer the receipt and opening of bids from the bidders. The committee shall comprise of a minimum of two (2) persons. Scope: This covers the formal opening of bids and the control procedures required to ensure the integrity of the bids.

SUPERSEDE ISSUE:

AUG 2000


REVISION 2 AUG 2008

APPENDIX 4

Page 427

For value RM15 Million and Above: i)

The technical bid proposal shall be opened after TCC has approved the Technical Evaluation Methodology and Criteria (TEMC).

ii)

The commercial bid proposal shall be opened after CTC has approved the Technical Evaluation Report and TCC has approved the Commercial Evaluation Criteria (CEC).

For value RM15 Million and Below: i)

The technical bid proposal shall be opened immediately after the closing date.

ii)

The commercial bid proposal shall be opened only for technically acceptable bidders.

The detailed PS Contractors cost estimates shall be opened together during commercial bid opening. Principles: Two-tier Bid Opening Two-tier Bid opening shall be the norm. Technical bid proposal shall be opened first on the same day or the first working day after bid closing date. The commercial bid proposal and cost impact shall be opened only after technical clarification and evaluation report have been completed and approved by PETRONAS where applicable. Only commercial proposals of technically acceptable bidders will be opened. Single-Tier Bid Opening PETRONAS prior approval is required for single-tier bid opening by incorporating such request in the Tender Plan. The technical and commercial bid proposals shall be opened concurrently on the same day preferably on the first working day after closing time. Bid Opening Bids shall be opened immediately after the bid closing date for security reasons, as well as to ensure that the bidding process is not delayed. In the event only one (1) bidder is technically qualified from a competitive bidding exercise, PS Contractors shall present the Technical Evaluation Report to the relevant Tender Committee for PETRONAS approval before opening the commercial bid. In the event that only one (1) bidder submits the bid proposal, PS Contractors are allowed to proceed with the technical bid opening. The commercial bid proposal and cost impact shall be opened only after technical clarification and evaluation report have been completed.

SUPERSEDE ISSUE:

AUG 2000


REVISION 2 AUG 2008

APPENDIX 4

Page 428

Bid Opening Process (BO)

Value Band Above

Process BOA1

Once the ITB documents are issued, the detailed Technical Evaluation Methodology and Criteria (TEMC) must be submitted to TCC for approval.

BOA2

Two (2) sets of the draft TEMC shall be submitted to the Senior Manager, PSC Management Department for PETRONAS review.

RM15 Million

The TEMC shall be in the format given in ATTACHMENT XI. Compliance to this format will ensure the quality of the submission and timely PETRONAS review. Noncompliance to the format will render the submission automatically rejected.

Above CTL

BOA3

The TEMC shall be reviewed and signed by the Technical Coordinator. The review is expected to complete within ten (10) working days.

BOA4

Seven (7) copies of the TEMC shall be submitted by PS Contractors to the TCC Secretary, three (3) working days before the TCC meeting.

BOA5

The TEMC is to be deliberated at the TCC after the bid closing date. Subsequently, the technical bids must be opened immediately thereafter but no later than two (2) working days after the approval of the TEMC.

BOAC1

The Bid Opening Committee is required to stamp and sign the relevant pages of the original copy of technical bids only. PS Contractors shall ensure that original bid and related documents are properly kept in the designated room after duly stamped and signed by Bid Opening Committee.

BOAC2

SUPERSEDE ISSUE:

AUG 2000

The Secretary of the Bid Opening Committee shall record all attendees, date and time tenders were opened.


REVISION 2 AUG 2008

APPENDIX 4

Page 429

Bid Opening Process (BO) (continued) Value Band Above CTL

CTL & Below

SUPERSEDE ISSUE:

AUG 2000

Process BOAC3

The summary of bid response shall be included in the technical and techno-commercial reports.

BOAC4

Any alteration or correction to the commercial proposal shall be initialed and highlighted by the bidders and counter initialed by the Bid Opening Committee. If the alteration does not bear the bidders’ initials, the Bid Opening Committee shall initial the changes.

BOAC5

PS Contractors’ Bid Opening Committee is prohibited to communicate with the invited bidders after bid opening.

BOAC6

PETRONAS reserves the right to witness any bid opening as and when appropriate.

BOBC1



REVISION 2 AUG 2008

APPENDIX 4

Page 430

4.1.6 BID EVALUATION Definition: Bid Evaluation is when the technical and commercial bid proposals submitted by Bidders are assessed against the approved evaluation criteria and commercial model to determine the compliance. Evaluation exercise shall be divided into two (2) categories: i)

Technical Bid Evaluation - evaluate the technical bid proposal received from bidders to bid for the tender using the technical parity band.

ii)

Commercial Bid Evaluation - evaluate the commercial bid proposals and cost impacts if any resulting from technical clarifications.

Scope: This covers the process of technical and commercial bids evaluations. The technical bid evaluation shall include bid clarification if any. The bid clarification shall include but not be limited to the clarification of all deviations and exceptions in the technical and unpriced commercial proposals submitted by the bidders. It also includes clarification by bidders to PS Contractors on any matter in the bid proposals. Principle: Two-tier Bid Evaluation The technical and unpriced commercial bid proposal shall be evaluated based on the approved Technical Evaluation Criteria. The commercial bid proposal is only opened and evaluated after the technical clarification and evaluation exercise have been completed or upon approval of the technical evaluation report by PETRONAS. Single-Tier Evaluation Techno-Commercial evaluation shall be done simultaneously but by separate evaluation team members. The coordinator/evaluation team leader shall have access to both technical & commercial evaluation documents for purposes of merging the two (2) reports to be submitted to PETRONAS for approval. Technical Evaluation The technical evaluation criteria shall be classified into essential and general criteria, which had been approved by PETRONAS. Bidders’ technical proposal shall be evaluated based on the Technical Parity Band (TPB) system.

SUPERSEDE ISSUE:

AUG 2000


REVISION 2 AUG 2008

APPENDIX 4

Page 431

The technical parity band shall be categorised as follows: GREEN

-

Technically Acceptable.

YELLOW

-

Technically Acceptable But With Areas Of Minor Concern.

RED

-

Technically Not Acceptable.

Essential Criteria - Essential Criteria are "must" criteria. Non-compliance/deviations/ exceptions to any of these criteria after clarification will render the bid technically unacceptable. Bidders shall be requested to comply with the requirement and to submit cost impact (if any). Only GREEN and RED parity band will be used. General Criteria - General Criteria are "want" criteria. Non-compliance/deviations/ exceptions to any of these criteria, after clarifications may or may not render the bid to be technically unacceptable. Bidders shall be requested to comply with the requirements and to submit cost impact (if any). GREEN, YELLOW and RED parity band may be used. Clarifications during technical bid evaluation which allow for price changes or technical data alterations by bidder(s) shall as far as possible be avoided. Bid clarification shall mean any clarification on the part of PS Contractors during the technical evaluation stage with regards to the following: i)

Technical specification

ii)

Scope of supply

iii)

Unpriced commercial items including terms and conditions of the contract

Such clarification may or may not result in cost impact. All technical clarifications should be signed by the respective approving authority. PS Contractors shall ensure that the integrity of the bidding exercise is not jeopardised through bid clarifications. Bid clarifications shall be conducted in a fair and professional manner. PS Contractors should ensure that clarifications are minimised and questions should be clear, complete and precise. All correspondence with bidders shall be recorded. During the technical evaluation stage, contact with bidders is prohibited. Where clarifications are necessary, all such communications must be made via letter or facsimile duly approved and authorised by the relevant authority of PS Contractors. Commercial Evaluation For commercial evaluation, the following shall be taken into account to derive the Estimated Total Bid Award Price. Raw Bid Price - The original cost of the equipment or services quoted by the bidder, in the commercial proposal for the specified scope of work/supply.

SUPERSEDE ISSUE:

AUG 2000


REVISION 2 AUG 2008

APPENDIX 4

Page 432

Cost Impact - Any addition/deletion to the Raw Bid Price quoted by the bidders for compliance to requirements of the bid arising from technical and unpriced commercial clarifications. Discount - Discount shall refer to the reduction in Price quoted by the bidder. Estimated Total Bid Award Price = Raw Bid Price + Cost Impact - Discount. There shall be no clarification with the bidders after commercial bids are opened. If PS Contractors intent to apply the External Cost for the commercial evaluation, such requirement must be incorporated in the Tender Plan. PS Contractors shall proceed with the commercial evaluation for bidders whose application for renewal of licence/registration is still pending approval. Only approved Evaluation Team members of PS Contractors shall be involved in bid evaluation exercises. The evaluation team leader shall be a senior personnel of the PS Contractors. PETRONAS reserves the right to send its representative(s) to any bid evaluation exercise conducted by PS Contractors and shall have access to bid documents as and when required.

SUPERSEDE ISSUE:

AUG 2000


REVISION 2 AUG 2008

APPENDIX 4

Page 433

Technical Evaluation Process (TE)


Process TEAC1

PS Contractors shall ensure that the bid evaluation is conducted in a designated room. During the evaluation, no personnel other than those approved in the Tender Plan or TEMC or CEC as Evaluation Team members shall have access to the documents.

TEAC2

The technical evaluation criteria as approved by PETRONAS is to be adhered to strictly. PETRONAS prior approval is required for any deviation from the approved criteria.

TEAC3

Any noncompliance in the original technical and unpriced commercial proposal will not result in automatic disqualification. PS Contractors will advise the Bidders to comply with the ITB requirement through clarifications, which will be carried out in a controlled environment. The proposed clarifications must be approved by PS Contractors’ relevant Approving Authority. All clarifications shall be in writing.

TEAC4

SUPERSEDE ISSUE:

AUG 2000

The following procedures shall be observed by bidders when responding to clarifications: i)

Bidders are required to respond on or before a stipulated time, date and to a specified address.

ii)

Similar procedures in bid opening shall govern the opening of response to clarifications with cost impact.

iii)

PS Contractors shall indicate and outline all the changes to the original bid, especially if they involve changes in price.

iv)

Bidders who fail to respond to bid clarifications after two (2) reminders will be disqualified.


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Page 434

Technical Evaluation Process (TE) (continued)


Process TEAC5

Should there be a cost impact as a result of technical clarification, PS Contractors shall request bidders to submit their responses in sealed envelopes. The cost impacts shall be kept sealed until commercial bid opening. For single-tier evaluation, the cost impacts can be opened upon receipt.

TEAC6

Where Bidders cannot comply with one or more of the Essential Criteria, then no further evaluation will be carried out on the General Criteria for such Bidders.

TEAC7

If modifications of the bid package become inevitable during the bid clarification meetings, such changes shall be issued to all approved bidders, provided that such changes, in the opinion of both PETRONAS and PS Contractors, do not substantially alter the original intent of the bids and prices quoted.

TEAC8

Upon completion of the technical evaluation, the bidder will be categorised under any one of the following Technical Parity Band (TPB): Green - Technically Acceptable Yellow - Technically Acceptable with Areas of Minor Concern Red - Technically Not Acceptable

CTL & Below

SUPERSEDE ISSUE:

AUG 2000

TEAC9

Bidders Code shall be assigned to each bidder immediately after completion of technical evaluation. This bidders code shall be used for technical evaluation report, commercial evaluation and award recommendation.

TEBC1



REVISION 2 AUG 2008

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Page 435

Commercial Bid Opening & Evaluation (CE)


Process CEAC1

The commercial bid proposal is only opened and evaluated after the technical clarification and evaluation exercise have been completed or upon approval of the technical evaluation report by PETRONAS. Only bidder who is categories under “ Green “ and “ Yellow “ will be opened and commercially evaluated.

CEAC2

The Bid Opening Committee is required to open, stamp and sign the relevant pages of the original copy of commercial bids. The Secretary of the Bid Opening Committee shall record all attendees, date and time bids were opened.

CEAC3

PS Contractors shall ensure that the bid evaluation is conducted in a designated room. During the evaluation, no personnel other than those approved in the Tender Plan or TEMC or CEC as Evaluation Team members shall have access to the documents.

CEAC4

The commercial evaluation criteria as approved by PETRONAS are to be adhered to strictly. PETRONAS prior approval is required for any deviation from the approved criteria.

CEAC5

The commercial evaluation should be conducted in Ringgit Malaysia (RM). Commercial bid proposals in foreign currencies should be converted to RM equivalent. The exchange rate used should be the average of buying and selling quoted by Bank Negara on the bid closing date.

CEAC6

SUPERSEDE ISSUE:

AUG 2000

Upon completion of commercial evaluation all the technically acceptable bidders should be ranked commercially. Bidder with the lowest total bid award price shall be recommended for award.


REVISION 2 AUG 2008

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Page 436

Commercial Bid Opening & Evaluation (CE) (continued)

Value Band

Process

Above CTL

CEAC6

No clarification or communication with the bidders is allowed during the commercial evaluation.

CTL & Below

CEBC1


4.1.7 TECHNICAL AND COMMERCIAL EVALUATION REPORTS & AWARD RECOMMENDATION Definition: Technical and Commercial Evaluation Reports are the reports on findings and result of technical and commercial bids evaluations respectively. Award Recommendation is a recommendation from PS Contractors to PETRONAS based on the Technical and Commercial Evaluation results to award the tender to the successful bidder. Scope: This covers the process from preparation of report which details out the findings and result of technical and commercial evaluation from which award recommendation is developed. Principles: Technical Evaluation Report (TER) for tender value above RM15 Million requires PETRONAS approval prior to the opening and evaluation of the commercial bid. For tender value below RM15 Million, the technical and commercial evaluation results are integrated in the Techno-Commercial and Award Recommendation Report. However, when there is none or only one (1) technically acceptable bidder from a competitive bidding exercise, PS Contractors shall present the Technical Evaluation Report to the relevant Tender Committee for PETRONAS approval on the next course of action. Award Recommendation proposed by PS Contractors to PETRONAS shall be based on technically acceptable and commercially lowest bidder. The final decision on the Award Recommendation shall rest with the respective Approving Authority

SUPERSEDE ISSUE:

AUG 2000


REVISION 2 AUG 2008

APPENDIX 4

Page 437

Evaluation & Award Recommendation Process (AR)

Value Band Above

Process ARA1

RM15 Million

Two (2) sets of the draft TER shall be submitted to the Senior Manager, PSC Management Department for PETRONAS review. The TER shall be in a format given in ATTACHMENT XIII. Compliance to this format will ensure the quality of the submission and timely PETRONAS review. Noncompliance to the format will render the submission automatically rejected.

ARA2

The TER shall be reviewed and signed by the Technical Coordinator and Techno-Commercial Coordinator. The review is expected to complete within seven (7) working days.

ARA3

Seven (7) copies of the TER shall be submitted by PS Contractors to the TCC Secretary three (3) working days before the TCC meeting.

ARA4

After Tender Committee deliberation, PS Contractors should submit the amended report incorporating all Tender Committee’s comments. The amended report must be re-signed and submitted to the TCC Secretary within 14 days. Failure to comply with the above, PS Contractors is required to represent the Tender Plan in the subsequent Tender Committee meeting.

ARA5

Once endorsed by the TCC, the TER shall be signed by the TCC Chairman. Eight (8) copies shall be submitted by PS Contractors to the CTC Secretary, three (3) working days before CTC meeting. Two (2) additional copies will be provided by PS Contractors to the Technical Coordinator and Techno-Commercial Coordinator.

SUPERSEDE ISSUE:

AUG 2000


REVISION 2 AUG 2008

APPENDIX 4

Page 438

Evaluation & Award Recommendation Process (AR) (continued)

Value Band Above

Process ARA6

Upon approval of the Technical Evaluation Report by CTC, the Commercial Evaluation Methodology and Criteria shall be presented to TCC for approval. Then the commercial bids can be opened for evaluation.

ARA7

A draft of Techno-Commercial Evaluation and Award Recommendation Report shall be submitted to the Senior Manager, PSC Management Department for PETRONAS review.

RM15 Million

The Techno-Commercial and Award Recommendation Report shall be in a format as given in ATTACHMENT XV. Compliance to this format will ensure the quality of the submission and timely PETRONAS review. Noncompliance to the format will render the submission automatically rejected. ARA8

The Techno-Commercial Evaluation and Award Recommendation Report shall be reviewed and signed by the Techno-Commercial Coordinator. The review is expected to complete within seven (7) working days.

ARA9

Seven (7) copies of the Techno-Commercial Evaluation and Award Recommendation Report shall be submitted by PS Contractors to the TCC Secretary three (3) working days before the TCC meeting.

ARA10

A Bidders'Code in the format as per ATTACHMENT XIV shall be submitted in a sealed envelope to TCC Secretary on the day of the TCC meeting.

ARA11

After Tender Committee deliberation, PS Contractors should submit the amended report incorporating all Tender Committee’s comments. The amended report must be re-signed and submitted to the TCC Secretary within 14 days. Failure to comply with the above, PS Contractors is required to represent the Tender Plan in the subsequent Tender Committee meeting.

SUPERSEDE ISSUE:

AUG 2000


REVISION 2 AUG 2008

APPENDIX 4

Page 439


Value Band Above

Process ARA12

RM15 Million

Once endorsed by the TCC, the Techno-Commercial Evaluation and Award Recommendation Report shall be signed by the TCC Chairman. Eight (8) copies shall be submitted by PS Contractors to the CTC Secretary, three (3) working days before CTC meeting. Two (2) additional copies will be provided by PS Contractors to the Technical Coordinator and Techno-Commercial Coordinator.

ARA13

For tender value RM15 -100 Million, three (3) copies of the Techno-Commercial and Award Recommendation Report must be submitted by PS Contractors to the CTC Secretary, three (3) working days before the MC meeting. The Techno-Commercial and Award Recommendation Report for PETRONAS MC approval shall be in a format as given in ATTACHMENT XVIII.

ARA14

For tender value above RM100 Million, nineteen (19) copies of the Techno-Commercial and Award Recommendation Report must be submitted by PS Contractors to the CTC Secretary, three (3) working days before the Board meeting. The Techno-Commercial and Award Recommendation Report for PETRONAS Board approval shall be in a format as given in ATTACHMENT XVIII.

ARA15

After the approval of PETRONAS Board has been obtained, one (1) copy of the Techno-Commercial and Award Recommendation Report shall be submitted by PS Contractors to the CTC Secretary for onward submission to Ministry of Finance (MOF) for concurrence. The Techno-Commercial and Award Recommendation Report for MOF concurrence shall be in a format as given in ATTACHMENT XVIII.

SUPERSEDE ISSUE:

AUG 2000


REVISION 2 AUG 2008

APPENDIX 4

Page 440


Value Band Above CTL to RM15 Million

Process ARAC1

Two (2) sets of the draft Techno-Commercial Evaluation and Award Recommendation Report shall be submitted to the Senior Manager, PSC Management Department for PETRONAS review. The Techno-Commercial Evaluation and Award Recommendation Report shall be in a format given in ATTACHMENT XVI and ATTACHMENT XVII. Compliance to this format will ensure the quality of the submission and timely PETRONAS review. Noncompliance to the format will render the submission automatically rejected. However, when there is none or only one (1) technically acceptable bidder, PS Contractors shall present the Technical Evaluation Report to the relevant Tender Committee after reviewed and signed by the Technical Coordinator and TechnoCommercial Coordinator for PETRONAS approval on the next course of action. The TER shall be in a format given in ATTACHMENT XIII and ATTACHMENT XVII.

SUPERSEDE ISSUE:

AUG 2000

ARAC2

The Techno-Commercial Evaluation and Award Recommendation Report shall be reviewed and signed by the Technical Coordinator and Techno-Commercial Coordinator. The review is expected to complete within seven (7) working days.

ARAC3

Seven (7) copies of the Techno-Commercial and Award Recommendation Report shall be submitted by PS Contractors to the relevant Tender Committee Secretary three (3) working days before the JTC meeting.

ARAC4

A Bidders'Code in the format as per ATTACHMENT XIV shall be submitted in a sealed envelope to relevant Tender Committee Secretary on the day of the meeting.


REVISION 2 AUG 2008

APPENDIX 4

Page 441


Value Band

Process ARAC5

After Tender Committee deliberation, PS Contractors should submit the amended report incorporating all Tender Committee’s comments. The amended report must be re-signed and submitted to relevant Tender Committee within the following time frame: i)

MJTC - 14 days

ii)

JTC - 7 days

iii)

RJTC - 7 days

However, amended report submitted within 24 hours after deliberation need not be resigned. Failure to comply with the above, PS Contractors is required to re-present the Tender Plan in the subsequent Tender Committee meeting.

CTL & Below

ARAC6

Once endorsed by the relevant Tender Committee, the Chairman shall prepare the tender committee summary for approval from Approving Authority.

ARBC1


4.1.8 CONTRACT AWARD Definition: Contract award is when PS Contractors award the contract to the successful bidder upon receiving PETRONAS approval. Scope: This covers the period from PETRONAS approval of the Techno-Commercial and Award Recommendation Report until the successful bidder is notified of the award and finalised contract documents are with the various parties for execution.

SUPERSEDE ISSUE:

AUG 2000


REVISION 2 AUG 2008

APPENDIX 4

Page 442

Principle: PETRONAS will issue an approval letter for the Techno-Commercial and Award Recommendation Report to PS Contractors upon obtaining approval from Approving Authority. The approval letter should include name of successful bidder, Approved Contract Value (ACV), contract duration and the approval condition(s). The ACV is known as Original ACV and this information shall not be revealed to the successful bidder. PS Contractors shall issue a Letter Of Intent to Award or Letter Of Award to the successful bidder within fourteen (14) days after receipt of PETRONAS approval. PS Contractors shall ensure the approval condition(s) are incorporated into the contract documents.

Contract Award Approval Process (CA) Value Band Above CTL

CTL & Below

SUPERSEDE ISSUE:

AUG 2000

Process CAAC1

PETRONAS to notify PS Contractors of the award approval via fax and/or letter.

CAAC2

PS Contractors shall issue a letter of Award/Intent to the successful bidder.

CAAC3

A copy of award notification shall be submitted to PETRONAS.

CAAC4

PS Contractors shall prepare final contract document, which incorporates all conditions imposed by PETRONAS.

CABC1



REVISION 2 AUG 2008

APPENDIX 4

Page 443

4.1.9 ABORTING TENDER Definition: Aborting Tender is when PS Contractors recommend to abort the tendering exercise or when PETRONAS direct PS Contractors to abort the tender. Scope: This covers the process of aborting tender resulting from, but not limited to the following situations: i)

A major change in work scope and technical specification.

ii)

The goods or services are no longer required after further study of the requirement.

iii)

Unreasonable bid price i.e. too high compared to the prevailing market price.

iv)

Deferment or cancellation of projects.

v)

The only technically acceptable bidder withdrew from tendering exercise.

vi)

Non-compliance to the tendering process.

Principle: PS Contractors shall notify PETRONAS in writing of their intention to abort the specific tender with justifications. Subsequently, PS Contractors are required to present the proposal to abort the tender exercise to the relevant Tender Committee for PETRONAS approval within 30 days. The proposal shall contain, but not limited to the following elements: i)

Objective.

ii)

Tender Background - original tender requirement, work scope and tender approval process.

iii)

Justification.

iv)

Recommendation.

SUPERSEDE ISSUE:

AUG 2000


REVISION 2 AUG 2008

APPENDIX 4

Page 444

Tender Abortion Process (TA) Value Band Above CTL

CTL & Below

SUPERSEDE ISSUE:

AUG 2000

Process TAAC1

PS Contractors shall notify PETRONAS in writing on their intention to abort the tender.

TAAC2

Two (2) sets of the draft proposal to abort the tender shall be submitted to the Senior Manager, PSC Management Department for PETRONAS review.

TAAC3

The proposal to abort the tender shall be reviewed and signed by the Technical Coordinator and Techno-Commercial Coordinator. The review is expected to complete within seven (7) working days.

TAAC4

Seven (7) copies of the proposal to abort the tender shall be submitted by PS Contractors to the relevant Tender Committee Secretary three (3) working days before the meeting.

TABC1



REVISION 2 AUG 2008

APPENDIX 4

Page 445

APPENDIX 4.2 LIST OF GOVERNMENTAL PERMIT, APPROVALS AND NOTIFICATIONS FOR OFFSHORE FACILITIES OF DEVELOPMENT PROJECT (BY PHASES) Permit, Approval or Notice A.

C.

D.

Applicable Law

DOE

EQA

MDTCA

EEZA

Screening, Conceptual Design, Concept Selection and DBM Preparation. 1)

B.

Government Agency

Approval of Environmental Impact Assessment (EIA) Report for Offshore Facilities.

Preliminary and Detailed Design 1)

Approval to Install and Operate Platforms, Pipelines, Submarine Cables in the EEZ .

2)

Approval for Direct Importation of Procured Materials and Equipment for the Project.

CED

CEO

3)

Exemption from Customs Duties and Tax for Project Purchased Non-BEL Items.

Treasury

CA

4)

Communications Equipment Import Permit for Platforms.

TD

TA

5)

Approval to Install Subsea Trunk Pipelines and Onshore Pipelines (PTI)

DOSH

PSMA

6)

Notification of Intent to Cross Telecommunications Cable.

JTM

-

7)

Approval for OSC (Onshore Slug Catcher) Pipeline Shore Crossing.

Port Authority

-

DOSH

FMA

Treasury

CEO

Fabrication 1)

DOSH Approval of Cranes/Pressure Vessels/Machineries on Platforms.

2)

Approval to Dispose of Project Purchased BEL Items.

Offshore Transportation and Installation 1)

Approval to Designate Platforms as Legal Landing Places. (Construction to make request thru Tax Dept.)

CED

CA

2)

Maritime Notification for Temporary Offshore Marine Vessel Operations Related to Offshore Construction Activities.

MD

MSO

3)

Notification of Permanent Offshore Installation of Platforms, Pipelines and Submarine Cables.

MD

MSO

SUPERSEDE ISSUE:

AUG 2000


REVISION 2 AUG 2008

APPENDIX 4

E.

F.

Page 446

Permit, Approval or Notice

Government Agency

Applicable Law

4)

Approval for Direct Importation/Relocation of Fabricated Components.

CED

CEO

5)

Notification to DOE of Commencement of Offshore Construction Work.

DOE

EQA

6)

Notification to DOE for Completion of Offshore Construction Work.

DOE

EQA

7)

Notification to DOSH for Subsea Trunk/Onshore Pipelines.

DOSH

PSMA

8)

Approval from DOE Director General to Discharge Effluent into Malaysia Waters for Pipeline Flushing, Pigging and Hydrotesting.

DOE

EEZA

9)

Notification of Platforms and Pipelines Installation for Fishermen’s Compensation.

FD

MOU

10)

Notification of Pipeline Installation Landing Onshore.

DC

-

MHA

PAPPA

TD

TA

DOSH

PSMA

DOSH

PSMA

Startup And Operations 1)

Gazetting the Offshore Installation as a Protected Place.

2)

Communications Equipment Operating License and Assignment of Operating Frequencies.

3)

Approval to Operate Subsea Pipelines to shore.

Notifications to DOSH for Emergency Pipeline Works (If necessary)

SUPERSEDE ISSUE:

AUG 2000


REVISION 2 AUG 2008

APPENDIX 5

Page 447

P M U C O R R E SP O N D E N C E L IST

E X P L O R A T IO N S T A G E

E X E C U T IO N

P L A N N IN G

W e ll P r o p o s a l

O p e r a t io n

A pproval (S G M P R E X ) E n d o r s e m e n tD r illi n g P r o p o s a l (G M D R IL L IN G )

P lu g & A b a n d o n ( P & A )

G & G I s s u e s & O v e r a ll A p proval

A p p r o v a l (P R E X )

N O O P p er P ro p o sa l

D r il lin g R e la t e d I s s u e s

E n d o r sem e n t (P O M )

In fo (S G M P R E X ) In fo (G M D R IL L IN G )

N o te: 1.

PREX – PETR OLEUM R ESO URCE E X P L O R A T IO N

2.

P O M – P E T R O L E U M O P E R A T IO N S M AN AGEM ENT PR D – PE TR O LE U M R E SO U R C E D EV ELO PM ENT

3. 4. 5.

D a ily D r ill in g R e p o r t ( D D R ) & E n d W e ll R e p o r t M a n d a t o r y to P R E X & P O M

G & G Issu es

A pproval (P R E X )

D r ill in g /O t h e r I s s u e s A p p r o v a l (P R E X ) E n d o r s e m e n t (P O M )

N O O P – N O T IC E O F O P E R A T IO N G & G – G E O L O G IS T A N D G E O P H Y S IS T

* P le a s e n o t e d th a t a ll a p p r o v a l r e q u e s t a n d in fo n e e d to b e s u b m it to P S C E x p lo r a tio n M a n a g e m e n t g r o u p SUPERSEDE ISSUE:

AUG 2000


REVISION 2 AUG 2008

D a ily D r illin g R e p o r t (D D R ) M a n d a t o r y se n t t o GM PRD & GM D r illin g

In fo (G M P R D ) In fo (G M D R IL L I N G )

N O O P p er F D P

D r illin g /O th e r I ss u e s A p p ro v a l (G M D r illin g ) In fo (G M P R D )

O p e r a t io n

E x e c u t io n

PREX – PETR O LEU M R ESO U RC E E X P L O R A T IO N P O M – P E T R O L E U M O P E R A T IO N S M ANAGEM ENT PRD – PETR O LEU M R ESO U R CE DEVELOPM ENT N O O P – N O T IC E O F O P E R A T IO N G & G – G E O L O G IS T A N D G E O P H Y S IS T

1. 2. 3. 4. 5.

G & G Issu es A p p ro va l (G M PRD) I n f o ( G M D r illin g )

E n d o r s e m e n t ( G M D r illin g )

D r illin g R e la te d I s s u e s

A p p ro v a l (G M P R D )

G & G I s s u e s & O v e r a ll A p p roval

P lu g & A b a n d o n (P & A ) D u r in g D r illin g

N o te :

Page 448

AUG 2000

SUPERSEDE ISSUE:


REVISION 2 AUG 2008

* P le a s e n o te th a t p r o d u c in g o il fie ld s (r e v isit, in f ill e tc ) is u n d e r th e P e tr o le u m O p e r a tio n s M a n a g e m e n t ( P O M ) D e p a rtm e n t w h ile o il & g a s f ie ld s a r e u n d e r P e tr o le u m R e s o u r c e D e v e lo p m e n t ( P R D ) D e p a r tm e n t.

A p p ro v a l (S G M PRD) In fo (G M D R IL L IN G )

D e v p r o p o s a l (n o t as p er ap p roved F D P i.e . c h a n g e r e s e r v o ir ta r g e t)

A p p ro v a l (S G M P R D ) E n d o r s e m e n t- D r illin g P r o p o s a l (P O M )

FD P

P la n n in g

DEVELO PM ENT STAG E

P M U C O R R E S P O N D E N C E L IS T

APPENDIX 5

AUG 2000

SUPERSEDE ISSUE:

Note:

1. 2. 3. 4. 5.

Well Abandonment Approval (POM) Info (PRD)

Plug & Abandon (P&A) Existing Well Approval (POM) Info (PRD)


PREX – PETROLEUM RESOURCE EXPLORATION POM – PETROLEUM OPERATIONS MANAGEMENT PRD – PETROLEUM RESOURCE DEVELOPMENT NOOP – NOTICE OF OPERATION G&G – GEOLOGIST AND GEOPHYSIST

DECOMMISIONING STAGE

PRODUCTION STAGE

PMU CORRESPONDENCE LIST

APPENDIX 5

REVISION 2 AUG 2008

Page 449

APPENDIX 5

Page 450

Detail Cost Breakdown LINE A

DETAILS OF COSTS TANGIBLE COSTS CASING AND ACCESSORIES TUBING WELL EQUIPMENT - SURFACE WELL EQUIPMENT - SUBSURFACE OTHERS TANGIBLE COST

TOTAL (USD) DRILLING

COMPLETION

TOTAL

DRILLING

COMPLETION

TOTAL

TOTAL TANGIBLE COST B INTANGIBLE COSTS 1 PREPARATION AND TERMINATION - RIG UP / RIG DOWN - SURVEY -LOCATION STAKING / POSITIONING 2 DRILLING AND WORKOVER OPERATION -CONTRACT RIG -MUD CHEMICAL AND ENGINEERING SERVICES - WATER -BIT, REAMERS AND CORE HEAD -DIRECTIONAL DRILLING AND SURVEY -CASING INSTALLATION -CEMENT, CEMENTING AND PUMP FEES -EQUIPMENT RENTAL -DIVING SERVICES 3 FORMATIONAL EVALUATION -CORING AND SIDEWALL CORE -MUD LOGGING SURFACE -DRILLING STEM TEST, RFT -OPEN HOLE ELECTRICAL LOGGING SERVICES 4 COMPLETION -CASING LINER AND TUBING INSTALLATION -CEMENT, CEMENTING AND PUMP FEES -CASED HOLE ELECTRICAL LOGGING SERVICES -PERFORATION AND WIRELINE SERVICES -STIMULATION TREATMENT 5 GENERAL -SUPERVISION -INSURANCE -MARINE RENTAL AND CHARTERS -HELICOPTER AND AVIATION CHARGERS -OTHER TRANSPORTATION -ALLOCATION OVERHEAD -FUEL & LUBRICANT -ENVIRONMENTAL COST TOTAL INTANGIBLE COST TOTAL COST

SUPERSEDE ISSUE:

AUG 2000


REVISION 2 AUG 2008

APPENDIX 6

Page 451

INTENTIONALLY LEAVE AS BLANK PAGE

SUPERSEDE ISSUE:

AUG 2000


REVISION 2 AUG 2008

Page 452

APPENDIX 7

TABLE A ~ FIRE INTEGRITY OF BULKHEADS SEPARATING ADJACENT SPACES ~

Space Below \ Space Above Control Stations

[1]

Corridors

[2]

Accommodation Spaces

[3]

Stairways

[4]

Services Spaces (low risk)

[5]

Machinery Spaces of Category A

[6]

Other Machinery Spaces

[7]

Hazardous Areas

[8]

Service Spaces (high risk)

Open Deck

SUPERSEDE ISSUE:

AUG 2000

-

-

[9]

[10]


-

REVISION 2 AUG 2008

Page 453

APPENDIX 7

TABLE B ~ FIRE INTEGRITY OF DECKS SEPARATING ADJACENT SPACES ~

Space Below \ Space Above Control Stations

[1]

Corridors

[2]

Accommodation Spaces

[3]

Stairways

[4]

Services Spaces (low risk)

[5]

Machinery Spaces of Category A

[6]

Other Machinery Spaces

[7]

Hazardous Areas

[8]

Service Spaces (high risk)

[9]

Open Deck

SUPERSEDE ISSUE:

AUG 2000

[10]


-

-

-

-

REVISION 2 AUG 2008


TOTAL OPERATOR

TOTAL PSC B

Field 4

Field 3

Field 2

Field 1

PSC B

TOTAL PSC A

Field 4

Field 3

Field 2

Field 1

PSC A

FIELD (OIL - KBD)

JAN

FEB

MAR

Q1 AVG

APR

MAY

JUN

JUL

AUG

SEP

Q3 AVG

OCT

NOV


Q2 AVG

1)YEAR 200X FIELD TECHNICAL POTENTIAL (FULL WELL STREAM)

APPENDIX 8A

APPENDIX 8

DEC

Q4 AVG

2006 AVG

JAN

FEB

Q1 AVG

REVISION 2 AUG 2008

MAR

200X

Page 454


TOTAL OPERATOR

TOTAL PSC B

Field 4

Field 3

Field 2

Field 1

PSC B

TOTAL PSC A

Field 4

Field 3

Field 2

Field 1

PSC A

FIELD (OIL-KBD or GAS MMSCF/D)

JAN

FEB

MAR

Q1 AVG

APR

MAY

JUN

Q2 AVG

JUL

AUG

SEP

Q3 AVG

OCT


2)YEAR 200X BASE PRODUCTION (AVAILABILITY)

APPENDIX 8B

APPENDIX 8

NOV

DEC

Q4 AVG

2006 AVG

dd-mm-yy JAN

FEB

Q1 AVG

REVISION 2 AUG 2008

MAR

200X

Page 455


TOTAL OPERATOR

TOTAL PSC B

Field 4

Field 3

Field 2

Field 1

PSC B

TOTAL PSC A

Field 4

Field 3

Field 2

Field 1

PSC A


JAN

FEB

MAR

Q1 AVG

APR

JUN

Q2 AVG

JUL

AUG

SEP

Q3 AVG

OCT


MAY

NOV

3) YEAR 200X BUILD UP FROM INFILL /SIDETRACK DRILLING PROJECTS (AVAILABILITY)

APPENDIX 8C

APPENDIX 8

DEC

Q4 AVG

2006 AVG

dd-mm-yy JAN

FEB

Q1 AVG

REVISION 2 AUG 2008

MAR

200X

Page 456


TOTAL OPERATOR

TOTAL PSC B

Field 4

Field 3

Field 2

Field 1

PSC B

TOTAL PSC A

Field 4

Field 3

Field 2

Field 1

PSC A

Q3 AVG

OCT


(please specify type of work i.e. mechanical repair, acidizing, add perforation, decommingle, water shutoff etc) FIELD (OIL-KBD or GAS JAN FEB MAR Q1 AVG APR MAY JUN Q2 AVG JUL AUG SEP MMSCF/D)

4) YEAR 200X BUILD UP FROM WORKOVER ACTIVITIES (RIG/WIRELINE )

APPENDIX 8D

APPENDIX 8

NOV

DEC

Q4 AVG

2006 AVG

dd-mm-yy JAN

FEB

Q1 AVG

REVISION 2 AUG 2008

MAR

200X

Page 457


TOTAL OPERATOR

TOTAL PSC B

Field 4

Field 3

Field 2

Field 1

PSC B

TOTAL PSC A

Field 4

Field 3

Field 2

Field 1

PSC A

JUL

AUG

SEP

Q3 AVG

OCT


(please specify type of work i.e. insert string, gaslift optimization, zone change, etc) FIELD (OIL-KBD or GAS JAN FEB MAR Q1 AVG APR MAY JUN Q2 AVG MMSCF/D)

5) YEAR 200X BUILD UP FROM WELL SERVICING

APPENDIX 8E

APPENDIX 8

NOV

DEC

Q4 AVG

2006 AVG

dd-mm-yy JAN

FEB

Q1 AVG

REVISION 2 AUG 2008

MAR

200X

Page 458


TOTAL OPERATOR

TOTAL PSC B

Field 4

Field 3

Field 2

Field 1

PSC B

TOTAL PSC A

Field 4

Field 3

Field 2

Field 1

PSC A

JUN

Q2 AVG

JUL

AUG

SEP

Q3 AVG


(please specify type of work i.e. separator, compressor, pump, pipeline etc.) FIELD (OIL-KBD or GAS JAN FEB MAR Q1 AVG APR MAY MMSCF/D)

6) YEAR 200X BUILD UP FROM DEBOTTLENECKING ACTIVITIES

APPENDIX 8F

APPENDIX 8

OCT

NOV

DEC

Q4 AVG

2006 AVG

JAN

MAR

Q1 AVG

REVISION 2 AUG 2008

FEB

200X

Page 459


TOTAL OPERATOR

TOTAL PSC B

Field 4

Field 3

Field 2

Field 1

PSC B

TOTAL PSC A

Field 4

Field 3

Field 2

Field 1

PSC A


JAN

FEB

MAR

Q1 AVG

APR

JUN

Q2 AVG

JUL

AUG

SEP

Q3 AVG

OCT


MAY

7) YEAR 200X TOTAL AVAILABILITY (APPENDIX 8B+8C+8D+8E+8F))

APPENDIX 8G

APPENDIX 8

NOV

DEC

Q4 AVG

2006 AVG

JAN

MAR

Q1 AVG

REVISION 2 AUG 2008

FEB

200X

Page 460


TOTAL OPERATOR

TOTAL PSC B

Field 4

Field 3

Field 2

Field 1

PSC B

TOTAL PSC A

Field 4

Field 3

Field 2

Field 1

PSC A


JAN

FEB

MAR

Q1 AVG

APR

MAY

Q2 AVG

JUL

AUG

SEP

Q3 AVG

OCT


JUN

8) 200X TOTAL CONDENSATE FORECAST (FROM OIL AND GAS FIELDS)

APPENDIX 8H

APPENDIX 8

NOV

DEC

Q4 AVG

2006 AVG

JAN

FEB

Q1 AVG

REVISION 2 AUG 2008

MAR

200X

Page 461


TOTAL OPERATOR

Field 1 Field 2 Field 3 Field 4 TOTAL FLARING

GAS FLARING

Field 1 Field 2 Field 3 Field 4 TOTAL FUEL/GAS LIFT

GAS FOR FUEL/GASLIFT

Field 1 Field 2 Field 3 Field 4 TOTAL SALES

GAS SALES

Field 1 Field 2 Field 3 Field 4 TOTAL INJECTION

GAS INJECTION

Field 1 Field 2 Field 3 Field 4 TOTAL PRODUCTION

GAS PRODUCTION

PSC

FIELD (MMSCF/D) JAN

FEB

MAR

APR

MAY

JUN

Q2 AVG

JUL

AUG

SEP


Q1 AVG

8) YEAR 200X GAS UTILIZATION AND FLARING FORECAST

APPENDIX 8I

APPENDIX 8

Q3 AVG

OCT NOV DEC

Q4 AVG

REVISION 2 AUG 2008

Q1 AVG

200X

dd-mm-yy 2006 AVG JAN FEB MAR

Page 462


LEGEND :

JAN

APR

M AY JU N

7 D (2 -3 K b /d )

7 D (1 0 K b /d )

8 D (0 .5 K b /d )

3 D (1 .4 K b /d )

3 D (3 .0 K b / d )

4 D (1 .2 K b /d )

M AR JUL

OCT

21D

5D

}

NOV DEC

EXAMPLE

7 D (1 6 K b /d )

( 2 0 .7 K b /d )

4 D (3 .1 K b /d )

3 D (0 .4 K b /d )

SEP

7 + 2 D (1 6 K b /d )

AU G


FEB

Q 1 C R S u b m is s io n

F ie ld G G C a rg o Ta n k In s p e c tio n & M a in te n a n c e .

F ie ld E E G a s C o m p re s s o r L P C T ra in 1 o v e rh a u l.

D ie ld D D V e s s e l C le a n in g & M a in te n a n c e .

F ie ld B B & C C R is e r In s ta lla tio n .

F ie ld A A D e b o ttle n e c t P ro je c t.

PSC B

F ie ld K V e s s e l C le a n in g .

F ie ld H - F ie ld J h o s t tie -in s .

F ie ld G m o d ific a tio n fo r c o m p re s s o r re s ta g in g .

F ie ld E C o m p re s s io n P ro je c t tie - in s .

F ie ld C - F ie ld D h o s t tie -in s .

F ie ld A & B - F ie ld F tie -in s .

PSC A

A C T IV IT IE S

A P P E N D IX X I 20XX M AJO R SHU TDO W N PLAN

APPENDIX 8J

APPENDIX 8

REVISION 2 AUG 2008

Page 463

APPENDIX 9

Page 464




REVISION 2 AUG 2008

APPENDIX 10

Page 465




REVISION 2 AUG 2008

APPENDIX 11

Page 466

List of KPIs for Facilities Reliability and Integrity

KPI Element

Compliance to overall planned maintenance.

Definition

Unit of Measure

Number of PMs completed x 100% Number of PMs planed

%

Compliance of critical safety devices and systems preventive maintenance.

Number of PMs completed x 100% Number of PMs planed

Loss of Containment (LOC) incident related to technical integrity.

Number of reportable Loss of Containment (LOC) incident related to technical integrity of facilities.

Overall Equipment Efficiency, OEE-(Oil)

OEE =

Actual Production x100 Adjusted Technical Potential

%

Overall Equipment Efficiency, OEE-(Gas)

OEE =

Net Production x100 Adjusted Technical Potential

%

SUPERSEDE ISSUE:

AUG 2000

%


No.

REVISION 2 AUG 2008

APPENDIX 12

Page 467

TECHNICAL PROPOSAL REQUIRES PETRONAS APPROVAL NO. 1 2

TECHNICAL PROPOSAL Any new wells not included in the approved FDP Any workover wells of the following objectives:• Recomplete/deepen to new zone not develop/address in the FDP,

DOCUMENT • FDP revision or

PETRONAS APPROVAL TIMING 1 Month

• Notice of Operations • FDP Revision

1 Month

• Technical Proposal

• Sidetrack new zone not develop/address in the FDP 3

Any workover wells of the following objectives:• Recompletion • Reperforation • Sidetrack exciting zones • Squeeze/plug job

• Technical proposal

2 weeks

• Gravelpack installation • Mechanical repair • Acid stimulation/fracturing • Change in well utility 4

FDP revision:• Development of new reservoirs, wells, platform. • Appraisal of new area • Changes to drainage plan i.e:• FDP Revision

Platforms

1 Month

Wells Type of completions •

Changes to development concept e.g. Evacuation route, integrated development, FPSO. Etc.

SUPERSEDE ISSUE:

AUG 2000


REVISION 2 AUG 2008

APPENDIX 12

NO. 5

TECHNICAL PROPOSAL

DOCUMENT

Page 468

PETRONAS APPROVAL TIMING

Reservoir Management Plan revisions:• GOR Limit revision/relaxation • Gas/Water Injection revision • Production Policy i.e:Offtake by well/reservoir Commingle/decommingle zone

•

Technical proposal

2 weeks

•

FIP Revision

1 Month

• Change in depletion strategy and well utility i.e.:Oil producer to gas/water injection Gas injection to gas sale 6

Facilities Improvement Plan (FIP) Revision / Facilities Rejuvenation Plan (FRP):Any changes of : • Objective • Concept/Scheme • Technology • Operations & Maintenance Philosophy

Note: 1) Other activities not listed above do not require PETRONAS technical approval. 2) Contractor may apply for exception to the above approval timing i.e. when good opportunity arises with justification for PETRONAS approval. 3) The PETRONAS approval timing is based on best endeavour basis and subject to issues being resolved.

SUPERSEDE ISSUE:

AUG 2000


REVISION 2 AUG 2008

APPENDIX 13

Page 469


SUPERSEDE ISSUE:

AUG 2000


REVISION 2 AUG 2008

APPENDIX 14

Page 470

14.0 TYPICAL LIQUID METERING SYSTEM

Figure 1: Liquid Metering System (Custody Transfer) typical schematic diagram.

SUPERSEDE ISSUE:

AUG 2000


REVISION 2 AUG 2008

APPENDIX 14

14.1

Page 471

FLOWMETER TYPES For each flowmeters that is to be/currently used, Contractors shall comply with the following requirements: 14.1.1 Turbine Meters Turbine meters shall be equipped with two pick-up coils each of which shall be fitted with a preamplifier and is independent of each other. The turbine meter shall be installed and provided with meter tubes and flow straighteners as necessary, in accordance with the ISO 2715 Liquid Hydrocarbons – Volumetric measurement by turbine meter systems and API MPMS Chapter 5 – Metering Section 3 – Measurement of Liquid Hydrocarbons by Turbine Meters The linearity of each meter shall be within +/- 0.25% of the average meter factor over the designed flow range and for the full range of viscosities specified, i.e. the complete family of calibration curves for all viscosities within the specified "Normal operating flow range", shall lie within the envelope of +/- 0.25% of the average between the highest and lowest meter factor at the specified viscosity. The vendor shall provide, in its proposal, typical meter test reports for the type and size of meter offered over the specified viscosity range. 14.1.2 Positive Displacement Meters Positive displacement (PD) meters are to be used when the turbine meters can not meet the conditions of the medium such as too high a viscosity for it to operate. Double casing type of PD meter should be used for high-pressure application to minimize the effect of pressure in volume of the measuring chamber of the meter. The required repeatability and linearity for the meter is similar to that of a turbine meter. The proving requirement for the PD meter is also similar to that of the turbine meter. The pulse generator selected must be capable to provide sufficient pulses required i.e 10,000 whole pulses (unaltered) for a single trip when proving using conventional pipe prover.

SUPERSEDE ISSUE:

AUG 2000


REVISION 2 AUG 2008

APPENDIX 14

Page 472

14.1.3 Other Meters Use of other types of flowmeter other than turbine and positive displacement meters shall be subjected to PETRONAS approval. 14.2

METERING DATA The following metering data, including but not limited to, shall be made available and printed automatically or on demand: 14.2.1 Batch Measurement The metering data for batch measurement i.e tanker loading, should consist of Batch Start Report, Batch Hourly Report, Batch End Report and Meter Proving Record. A.

Batch Start Report

i. ii. iii. iv. v. vi. vii. viii. ix. x. B.

Batch Hourly Report

i. ii. iii. iv. v. vi. vii. viii. ix. SUPERSEDE ISSUE:

AUG 2000

Batch Number Batch Start Date/Time Gross Volume Start (Cumulative) Gross Volume Finish (Cumulative) Gross Volume (Gross Volume Start – Gross Volume Finish) Flow Rate Meter Factor Temperature Pressure Prover and Meter Runs Settings and Constants Log

Batch Number Report Date/Hour Gross Volume Start (Cumulative) Gross Volume Finish (Cumulative) Gross Volume (Gross Volume Start – Gross Volume Finish) Flow Rate Meter Factor Temperature Pressure ISSUED BY PETROLEUM MANAGEMENT UNIT

REVISION 2 AUG 2008

APPENDIX 14

C.

Page 473

Batch End Report

i. ii. iii. iv. v. vi. vii. viii. ix. x. xi. xii.

Batch Number Batch Start Date/Time Batch End Date/Time Gross Volume Start (Cumulative) Gross Volume Finish (Cumulative) Gross Volume (Gross Volume Start – Gross Volume Finish) FWAT - Flow Weighted Average Temperature FWAP - Flow Weighted Average Pressure Meter Factor Calculated CTL Calculated CPL Standard Volume

D. Meter Proving Report

i. ii. iii. iv. v. vi.

Batch Number Prover Volume Identification/Volume Meter Tag No. Proving Start Date/Time Proving End Date/Time Trial Run Number For Each Trial Run:

vii. viii. ix. x. xi. xii. xiii. xiv. xv. xvi.

SUPERSEDE ISSUE:

AUG 2000

Volume Flow Rate Pulse Count Flight Time Density Line Temperature Line Pressure Prover Temperature Prover Pressure CTLm, CPLm, CTLp, CPLp, CTSp, CPSp Meter Factor


REVISION 2 AUG 2008

APPENDIX 14

Page 474

Every final average of the 5 consecutive trial runs resulting the successful meter proving: xvii. xviii. xix. xx. xxi. xxii. xxiii. xxiv. xxv. xxvi. xxvii. xxviii. xxix. 14.2.2

Volume Flow Rate Pulse Count Flight Time Density Line Temperature Line Pressure Prover Temperature Prover Pressure CTLm, CPLm, CTLp, CPLp, CTSp, CPSp Meter Factor Meter Factor Repeatability % Previous in Use Meter Factor Difference between the New and Previous in Use Meter Factor

Continuous Flow Measurement The metering data for continuous flow measurement should consist of Hourly Report, Sale Report and Production Report. A. Hourly Report

i. ii. iii. iv. v. vi. vii. viii. ix. x.

SUPERSEDE ISSUE:

AUG 2000

Date/Time of Report Gross/Standard/Net Volume and Mass (if applicable) Start (Cumulative) Gross/Standard/Net Volume and Mass (if applicable) Finish (Cumulative) Gross/Std/Net Volume and Mass (if applicable) (Gross Volume Start – Gross Volume Finish) Flow Rate FWAT FWAP Density Calculated CTL Calculated CPL


REVISION 2 AUG 2008

APPENDIX 14

xi. xii.

Page 475

Base Oil and Water Density Settings Calculated Water-Cut

B. Sale Report (e.g. 00:00 – 00:00) C. Production Report (e.g. 06:00 – 06:00)

SUPERSEDE ISSUE:

AUG 2000


REVISION 2 AUG 2008

APPENDIX 15

Page 476

TYPICAL GAS METERING SYSTEM

Figure 1: Gas Metering System (Custody Transfer) typical schematic diagram. 15.1

METERING DATA The following metering data, including but not limited to, shall be made available and printed automatically or on demand:

15.1.1

SUPERSEDE ISSUE:

AUG 2000

Continuous Flow Measurement The metering data for continuous flow measurement should consist of Hourly Report, Sale Report and Production Report.


REVISION 2 AUG 2008

APPENDIX 15

A.

Hourly Report

2. 3. 4. 5. 6. 7. 8. 9. 10. 11. 12. 13.

SUPERSEDE ISSUE:

AUG 2000

Page 477

Date/Time of Report Gross/Standard/Net Volume, GHV and Mass (if applicable) Start (Cumulative) Gross/Standard/Net Volume, GHV and Mass (if applicable) Finish (Cumulative) Gross/Std/Net Volume, GHV and Mass (if applicable) (Gross Volume Start – Gross Volume Finish) Flow Rate FWAT FWAP Density Calculated CTL Calculated CPL Base Oil and Water Density Settings Calculated Water-Cut

B.

Sale Report (e.g. 00:00 – 00:00)

C.

Production Report (e.g. 06:00 – 06:00)


REVISION 2 AUG 2008

APPENDIX 16

Page 478

Appendix 16.1

SUPERSEDE ISSUE:

AUG 2000


REVISION 2 AUG 2008

APPENDIX 16

Page 479

Appendix 16.2

SUPERSEDE ISSUE:

AUG 2000


REVISION 2 AUG 2008

APPENDIX 16

Page 480

Appendix 16.3

SUPERSEDE ISSUE:

AUG 2000


REVISION 2 AUG 2008

APPENDIX 16

Page 481

Appendix 16.4

SUPERSEDE ISSUE:

AUG 2000


REVISION 2 AUG 2008

APPENDIX 16

Page 482

Appendix 16.5

Appendix 16.6

SUPERSEDE ISSUE:

AUG 2000


REVISION 2 AUG 2008

APPENDIX 16

Page 483

Appendix 16.7

SUPERSEDE ISSUE:

AUG 2000


REVISION 2 AUG 2008

APPENDIX 16

Page 484

Appendix 16.8

SUPERSEDE ISSUE:

AUG 2000


REVISION 2 AUG 2008

Raw navigation 2D

Final navigation 2D

Raw navigation 3D

Final navigation 3D

Bin Center 3D

1.2

1.3

1.4

1.5

1.6


Seismic Seismic Coverage Map

DATA CLASS

1 1.1

NO.

Paper

FORMAT

3 weeks before survey

SUBMISSION PERIOD Future Data

Within 2 months after survey completed

P1/90 or P6/98

Within 2 months after processing completed

UKOOAP6/98 / Within 2 months after UKUOOAP1/90 survey completed

UKOOAP2/90 OR UKOOAP 2/86

UKOOAP2/92 / Within 2 months after UKOOAP 2/86 / survey completed UKOOAP 2/90 UKOOAP1/90 Within 2 months after survey completed

1:100,000 Acrobat PDF

SCALE


CDR/DVD/IBM 3590

CDR/DVD/IBM 3590

CDR/DVD/IBM 3590

CDR/DVD/IBM 3590

CDR/DVD/IBM 3590

CDR/DVD

MEDIA Hardcopy *Electronics

DATA SUBMISSION REQUIREMENT CHECKLIST

APPENDIX 17

Inclusive of water depth




REVISION 2 AUG 2008

Inclusive of geological play and pre existing seismic lines with full fold coverage. Also for reprocessing work.

REMARKS

Page 485

DATA CLASS

SCALE SEG-Y

FORMAT

Page 486

REVISION 2 AUG 2008

Information on Trace Header should contain the following: 2D Survey 1. Shot Point at byte location 17 (4 byte integer) 2. CDP at byte location 21 (4 byte integer) 3. X coordinate at byte location 73-76 4. Y coordinate at byte

SUBMISSION PERIOD REMARKS Future Data Within 2 months of the EBCDIC Information should survey contain: 1. Line/Survey name, Area (Block/Prospect name), Processing Company, Client, Date 2. Acquisition Information required for processing also include date and name of company acquiring the survey 3. Projection System (preferably UTM) and XY reference definition (preferably 2d=CDP, 3D=bin center) 4. Brief Processing History


MEDIA Hardcopy *Electronics Post Stack Trace for 2D & IBM 3590 (10 3D should contain: or 20 1. Raw Stack (where Gigabyte) / available) and DVD (for 2D or Migration (32 bit) Site Survey 2. Final Zero phase only) Migration for Interpretation (32 or 16 bit) 3. Final Sub-Stack data (32 Bit) such as full, near, mid and far offset stack. 4. Special Processing output for aiding final interpretation such as Instantaneous Phase, Acoustic Impedance, AVO Cubes and Optical Stacking


1.7

NO.

APPENDIX 17

Field trace/pre-stack trace 2D/3D

1.8


DATA CLASS

NO.

SCALE


Field trace: SEG- Within 2 months of the D survey Pre-stack trace: SEG-Y

FORMAT


IBM 3590 (10 N/a or 20 Gigabyte)


APPENDIX 17

REVISION 2 AUG 2008

3D Survey 1. Inline at byte location 189-192 and also byte location 9-12 (4 byte integer) 2. Cross line at byte location 193196 and also at byte location 21-24 (4 byte Integer) 3. X coordinate at byte location 73-76 4. Y coordinate at byte location 77-80 The other parameters as per defined by SEG None

location 77-80

REMARKS

Page 487


N/a

CDR/DVD

Acrobat PDF

Acrobat PDF

ASCII

FORMAT

Page 488

REVISION 2 AUG 2008

2 months after processing Both hardcopy and soft copy are completed required

(Upon request if available)

Information Header Format: (should contain) Survey/Line name, Area (Block, prospect name), Velocity type, Processing Date, Processing Company, Client name, Brief Processing History, Datum, Outline velocity pick frequency Velocity Format 1. 2D: Should contain: Shot Point, CDP, X & Y, Time/Velocity (all type) 2. 3D: Should contain: Inline, Cross line, X & Y, Time/Velocity (Depth) Paper section is optional

SUBMISSION PERIOD REMARKS Future Data Within 2 months of the ASCII Format should contain the survey following:


N/a

CDR/DVD

MEDIA SCALE Hardcopy *Electronics IBM 3590 (10 N/a or 20 Gigabyte)

Paper (If available) 1.11 Processing/Reprocessing Paper report

Velocity: (units in meter) 1. For Normal Processing: Final Stacking and Migration velocity 2. Advance processing (such as PSI, PSTM): Stacking velocity, Interval Velocity, Time/Depth Velocity and velocity contributing to final stacking output (if any).

1.9

1.10 Velocity maps

DATA CLASS

NO.

APPENDIX 17

DATA CLASS

CDR/DVD CDR/DVD

CDR/DVD

1.17 Field supporting Paper documents (observer log)

1.18 Interpreted seismic horizons (Final study)

1.19 Interpretation report

Acrobat PDF

Acrobat PDF

Acrobat PDF

N/a

Acrobat PDF

ASCII / CGM

1:25000 Acrobat PDF 1: 50,000 1:100,000 1:250,000 N/a Acrobat PDF

N/a

N/a

N/a

Acrobat PDF

FORMAT

Page 489

None

3 months after the work completion

3mths after the work completion

REVISION 2 AUG 2008

Submitted together with the final study report None

Not limited to seismic sections, time slice, and datum time slice. Seismic and velocity modeling.

2 months after the survey None

2 months after survey completed

3 months of the None completion of the survey 3 months of the None completion of the survey 2 months after the survey Inclusive of seismic lines numbers and shot point ranges

SUBMISSION PERIOD REMARKS Future Data 1 month after survey To include Far field signature completed (ASCII)


CDR/DVD

1.16 Final and composite shot- Paper point location map


CDR/DVD

1.15 Inventories of field tapes Paper

Paper

CDR/DVD

Paper

1.14 Consultant QC reports

CDR/DVD

Paper

MEDIA SCALE Hardcopy *Electronics Paper CDR/DVD N/a

1.13 Navigation report

1.12 Acquisition report Daily and Weekly acquisition reports;

NO.

APPENDIX 17

DATA CLASS

Water depth data

Site Survey Processed digital data

Interpretation report

2.2

3 3.1

3.2


Bathymetry Water depth map

2 2.1

1.21 Specialized seismic processing and reprocessing reports

1.20 Specialized seismic processing and reprocessing data

NO.

Paper

Paper

Paper

Paper

Acrobat PDF

SEG-Y

FORMAT

N/a

N/a

Acrobat PDF

SEG-Y

Page 490

Within 1 month after the report is completed

1 month after survey None completed 3 months after Inclusive of analog data interpretation completed

None

None

REVISION 2 AUG 2008

Not limited to DHI, AVO, synthetic seismogram

SUBMISSION PERIOD REMARKS Future Data Within 3 weeks after the Not limited to DHI, AVO, synthetic report is completed seismogram

1:25,000 Acrobat PDF 1 month after survey 1:50,000 completed 1:100,000 N/a ASCII 1 month after survey Shape file format completed (ESRI)

N/a

SCALE


CDR/DVD

CDR/DVD

CDR/DVD

CDR/DVD

CDR/DVD

MEDIA Hardcopy *Electronics IBM 3590

APPENDIX 17

Gravity Survey (if available) Gravity and accelerometer records/profiles or spot reading Traverse line maps

4

Navigational records Paper required for correction to observations Processed gravity Paper anomaly maps

4.4


4.5

Meter calibration and drift Paper base station reports

Paper

Paper

N/a

1:25,000 Acrobat PDF 1:50,000 1:100,000

N/a

1 month after survey completed





REMARKS

Page 491

REVISION 2 AUG 2008

Method of anomalies calculation should be explained

None

None

None

None

SUBMISSION PERIOD Future Data Acrobat PDF 1 month after survey None Shape file format completed (ESRI)

FORMAT

1:25,000 ASCII 1:50,000 1:100,000 N/a ASCII

N/a

SCALE


CDR/DVD

CDR/DVD/ IBM 3590

CDR/DVD

CDR/DVD

CDR / DVD / IBM 3590

MEDIA Hardcopy *Electronics CDR/DVD

4.3

4.2

4.1

Site Survey Map

DATA CLASS

3.3

NO.

APPENDIX 17

Magnetometer records/profiles

Altimeter records, storm monitor records and navigational record Traverse line maps

Magnetometer operator Paper log or other means of relating magnetic observation to local time reports

5.1

5.2

5.4


5.3

Magnetic Survey (if available)

5

Paper

Paper

Paper

Listing of absolute measured gravity values, theoretical gravity values and corrected free-air gravity anomaly values

4.6

1:25,000 Acrobat PDF OR 1:50,000 OR 1:100,000 Acrobat PDF

N/a

N/a

ASCII

FORMAT




1 month after survey complete

None

None

None

None

SUBMISSION PERIOD Future Data 1 month after survey None completed


CDR/DVD/ IBM 3590

CDR/DVD

CDR/DVD/IBM N/a 3590

CDR/DVD/IBM N/a 3590


DATA CLASS

NO.

APPENDIX 17

REMARKS

REVISION 2 AUG 2008

Page 492

Processed Data

6.1

6.2


PMU Data N/a Manageme nt

PMU Data N/a Manageme nt


CDR/DVD/ N/a 3590

FORMAT

Page 493

REVISION 2 AUG 2008

3 month after processing completed


SUBMISSION PERIOD REMARKS Future Data N/a 1 month after survey None completed Acrobat PDF for 3 months after completion Report per project report ASCII for data

CDR/DVD/ N/a 3590

Seabed Logging Survey (if Available) Raw Data (EM data)

CDR/DVD

6

Paper

METOCEAN (Meteorology and Oceanography) data : 1) Wave 2) Wind 3) Current 4) Tide 5) Temperature 6) Salinity

5.6

5.5

MEDIA SCALE Hardcopy *Electronics Diurnal variation records Paper CDR/DVD N/a

DATA CLASS

NO.

APPENDIX 17

Pipeline route hydrographic survey (before and after installation) report including the location point Rig or platform positioning report

7.3


7.4

Paper

Paper (report)

Paper

Well or Platform site survey reports

CDR

N/a

N/a

N/a

3 months after Profiles, processed data, maps studies/survey completed and reports SEG-D for field data and SEGY for processed data 3 months after Profiles, processed data, maps studies/survey completed and reports

Acrobat PDF

1 week after spud date

REVISION 2 AUG 2008

Final spud location must be transmitted immediately within 24 hrs

Report-Acrobat 3 months after Profiles, processed data, maps PDF studies/survey completed and reports DigitalCAD/Shape file

Acrobat PDF

Page 494

SUBMISSION PERIOD REMARKS Future Data PDF 1 Month after completion of Acquisition 3 Months after completion of Processing


CDR/DVD

CDR/DVD

SEG-D/SEGY

7.2

IBM 3590 (10 N/a or 20Gb)

Other Survey and Studies Well or Platform site survey digital

7 7.1

6.3

MEDIA SCALE FORMAT Hardcopy *Electronics Acquisition & Processing PMU Data Paper CDR/DVD N/a (Final) Reports Manageme (If Available) nt

DATA CLASS

NO.

APPENDIX 17

Soil or foundation investigation report

Platform Outline

7.8

7.9


7.10 Field Outline

Paper

Well velocity survey and Paper velocity seismic profiling (VSP) Piston and gravity coring Paper investigation

7.6

7.7

Environmental or oceanographic data

7.5

N/a

N/a

N/a

N/a

N/a

Page 495

REVISION 2 AUG 2008

Part of Final study report. To be updated during ARPR submission. Must be inclusive of 1) Depth structure map 2) Min of 2 reference seismic cross line and inline across the field 3) Interpreted well logs 4) Pressure plot 5) Geological cross section across the field

3 months after Profiles, processed data, maps studies/survey completed and reports



SUBMISSION PERIOD REMARKS Future Data 3 months after Profiles, processed data, maps studies/survey completed and reports As and when available

CAD / Shape file Within 3 months after map / Auto cad installation CAD / Shape file Within 3 months after installation

Acrobat PDF

Acrobat PDF

Acrobat PDF

Acrobat PDF

FORMAT


CDR/DVD

CDR/DVD

CDR/DVD

CDR/DVD

CDR/DVD


DATA CLASS

NO.

APPENDIX 17

DATA CLASS

CDR/DVD

CDR/DVD

8.1.4 Migrated TVS sections Paper with at least one (1) key seismic line passing through the location of the proposed well

8.1.5 Assessment of hydrocarbon volume-inplace and estimated reservoir parameters

N/a

N/a

1:12,500 OR 1:25,000 OR 1:50,000

N/a

N/a

SCALE

Acrobat PDF

Acrobat PDF/CGM

Acrobat PDF/CGM

Acrobat PDF

Acrobat PDF

FORMAT

REMARKS

Page 496

REVISION 2 AUG 2008

Detailed by category of proved, probable and possible and expected value (EV) and assigned to each reservoir and fault block of such Field;

None

None

2 weeks before spud date None

2 weeks before spud date None



CDR/DVD

8.1.3 Depth and time structure Paper maps and velocity maps used of prospective horizons


CDR/DVD

8.1.2 Recommendation to Drill Paper or Well Proposals

Paper

CDR/DVD


Paper

Geological & Petrophysical data 8.1 Well Reports 8.1.1 Well proposals

8

NO.

APPENDIX 17


Geological Completion Reports 8.3.1 Geological Completion Reports

8.3

Paper

8.2.2 Abandonment Programs Paper 8.2.3 Drilling Completion Paper Reports

Paper

N/a

N/a

N/a


Acrobat PDF

REMARKS

Page 497

Within three (3) months of None completion of the well

REVISION 2 AUG 2008

Including detailed well cost estimate;

None

None

Acrobat Daily or weekly None PDF/Spreadshee t file Acrobat PDF 2 weeks before spud date None Acrobat PDF Within three (3) months of None completion of the well

Acrobat PDF

Acrobat PDF

Acrobat PDF

FORMAT


CDR/DVD

Electronic N/a File/Digital/CD R/DVD CDR/DVD N/a CDR/DVD N/a

CDR/DVD

8.1.8 Proposed drilling and Paper formation evaluation programs to be submitted

8.2 Exploration Drilling 8.2.1 Daily or Weekly drilling reports

CDR/DVD

8.1.7 Costs and technical Paper details relating to prospect or field and new projects

DATA CLASS

MEDIA SCALE Hardcopy *Electronics 8.1.6 Structural or stratigraphic Paper CDR/DVD N/a cross-section

NO.

APPENDIX 17

DATA CLASS

Paper

Digital

Paper

8.3.4 Well completion logs in paper prints (see 8.4.1)

8.3.5 Geological well or composite log in digital (see 8.4.1)

8.3.6 Geological well or composite log in paper print (see 8.4.1)


Digital

1:200 1:500

1:500

1:500

1:500

SUBMISSION PERIOD Future Data Within three (3) months of None completion of the well

REMARKS

Page 498

REVISION 2 AUG 2008

LIS / LAS/ DLIS / Within three (3) months of Showing formation test PDS, CGM, PDF completion of the well depths/results, cores or sidewall cores depth, hydrocarbon shows, preliminary log analyses and stratigraphy PDS/CGM/TIFF Within three (3) months of Showing formation test completion of the well depths/results, cores or sidewall cores depth, hydrocarbon shows, preliminary log analyses and stratigraphy; LIS/LAS/DLIS Within three (3) months of Showing detailed lithology completion of the well description and percentages, penetration rates, basic drilling data (ROP, WOB, Mud weight, etc.), gas readings and composition PDS/CGM/TIFF Within three (3) months of Showing detailed lithology completion of the well description and percentages, penetration rates, basic drilling data (ROP, WOB, Mudweight, etc.), gas readings and composition

Acrobat PDF

FORMAT


CDR/DVD

CDR/DVD

CDR/DVD

CDR/DVD


8.3.3 Well completion logs in digital tape (see 8.4.1)

8.3.2 Geological and operations summaries

NO.

APPENDIX 17

DATA CLASS


8.3.9 Pressure analysis Paper including pressure versus depth plot and fluid contact estimation. 8.3.10 Post-drill Well Evaluation Paper or Well Summary Reports 8.3.11 Service company reports Paper covering mudlogging, wireline testing, production testing, wireline/LWD/MWD etc. N/a N/a

CDR/DVD CDR/DVD

Acrobat PDF

Acrobat PDF

Acrobat PDF

1:200 1:500 1:1000

Acrobat PDF

FORMAT

Page 499

Final approved version of digital data including special study conducted by third parties

9 months after end of None campaign/FRR 3 months after completion None of the well

REVISION 2 AUG 2008

3 months after completion None of the well To be included in well completion report

PDS/CGM/TIFF for DLIS/LIS and LAS

SUBMISSION PERIOD REMARKS Future Data 6 months after completion Final approved version of log analysis, processing and interpretation reports with a summary of the net zones, porosity and water saturation and permeability cutoffs used and other assumptions used or made in deriving the results.


N/a

CDR/DVD

CDR / DVD


well log analysis, Digital processing and interpretation reports.

8.3.8 Final

8.3.7 Final well log analysis and interpretation

NO.

APPENDIX 17

DATA CLASS

CDR/DVD

8.3.17 Core analysis reports Paper inclusive of daylight or UV photographs and any other analysis carried out 8.3.18 Fluid analysis reports Paper PVT analysis


Paper

CDR/DVD

Paper

8.3.16 Petrographic studies

8.3.19 Directional survey reports.

CDR/DVD

Paper

N/a

N/a

N/a

N/a

N/a

Acrobat PDF, Spreadsheet file, ASCII Acrobat PDF, Spreadsheet file, ASCII

Acrobat PDF

Acrobat PDF

Acrobat PDF

Acrobat PDF

Acrobat PDF

Acrobat PDF

FORMAT

Page 500

3 months after completion None of the well

3 months after completion None of the well

REVISION 2 AUG 2008

SUBMISSION PERIOD REMARKS Future Data As and when available None within 3 months after completion of the surveys With a summary of the net zones, porosity and water saturation and permeability cutoffs used and other assumptions used or made in deriving the results; 3 months after completion None of the well 3 months after completion None of the well 3 months after completion None of the well 3 months after completion None of the well


Electronic N/a File/Digital/CD R/DVD Electronic N/a File/Digital/CD R/DVD

CDR/DVD

Paper

8.3.14 Paleontological and palynological reports 8.3.15 Geochemical reports

CDR/DVD


8.3.12 Subsurface pressure or temperature survey reports 8.3.13 Computer processed log Paper interpretation

NO.

APPENDIX 17

DATA CLASS


8.4 Well Logs 8.4.1 Well Logs - all wireline logging & Logging while drilling data (including composite log). Types of logs but not limited to the followings, and may vary between logging contractors: 1. Gamma Ray and Gamma Ray Spectroscopy Logging 2. Acoustic Sonic and Seismic Logging 3. Resistivity Logging:(i.e. Laterolog, Induction) 4. Nuclear Logging: (i.e. Neutron and Density) 5. Electromagnetic and Nuclear Magnetic Resonance Logging 6. Formation Pressure & Sampling Logging

NO. N/a

SCALE DLIS/LIS and LAS

FORMAT

REMARKS

Page 501

REVISION 2 AUG 2008

Data deliverable is in Measured Depth (MD). True Vertical Depth (TVD) if available)

Composite log, process and interpreted results data are final approved versions.

3 months after completion Raw digital data acquired as per of the well. actual logging program for exploration and development wells, for open hole and cased hole logging.



CDR / DVD


APPENDIX 17

DATA CLASS


8.5 Samples 8.5.1 Drill cuttings; 8.5.2 A representative portion of sidewall cores 8.5.3 Drill cores 8.5.4 Fluid - oil, gas, condensate, water 8.5.5 Any other types of samples n/a n/a n/a n/a n/a

n/a n/a

n/a n/a

n/a

n/a

n/a n/a

n/a n/a

1/200, 1/500

SCALE

n/a

n/a n/a

n/a n/a

PDS / CGM /TIFF

FORMAT

As when available

As when available As when available

As when available As when available

Within 3 months after completion of the well




7. Geological Logging 8. Auxiliary Logging, Geochemical Logging 9. Cased Hole Logging 8.4.2 Field and final prints, Paper (colored and in all available scales)

NO.

APPENDIX 17

None

None None

None None

REVISION 2 AUG 2008

Scales may vary depending on the requirement of the logs run (i.e. FMS/FMI 1/40).

Scales In measured depth (MD). In true vertical depth (TVD) available.

REMARKS

Page 502

DATA CLASS

N/a

N/a

N/a

SCALE

Acrobat PDF

Acrobat PDF

Acrobat PDF

FORMAT

As when available

As when available

As when available



CDR/DVD

CDR/DVD

CDR/DVD


Interpretative Material Reports Progress reports on Paper geophysical and drilling operation An annual general review Paper of the interpretation of the subsurface structure in any area over which geological, geophysical, drilling or other operations have been conducted Reserve Calculation Paper Reports. All reports inclusive of any subsequent revisions with respect to the amount of


9.3

9.2

9.1

9

8.6.2 Detailed production tests reports

8.6

Production Well Test Data 8.6.1 Production testing procedures

NO.

APPENDIX 17

REVISION 2 AUG 2008

In respect of contract area the reports shall include 1. the location, size, extend, structural and stratigraphic cross-sections of the

(Inclusive of any subsequent revisions thereof)

(Inclusive of any subsequent revisions thereof)

Requirement for submission is as per stated in Section 11 of PPGUA (11.5 Record Keeping) Requirement for submission is as per stated in Section 11 of PPGUA (11.5 Record Keeping)

REMARKS

Page 503

DATA CLASS

Platform conformable proven and expected estimated recoverable petroleum reserves

Petroleum in a petroleum reservoir classified as – 1. Proven petroleum originally-in-place 2. Expected and maximum possible petroleum originally-inplace 3. Proven estimated ultimate recoverable petroleum reserves 4. Expected estimated ultimate recoverable petroleum reserves


NO.

SCALE

FORMAT




APPENDIX 17

REVISION 2 AUG 2008

petroleum reservoirs 2. the amount of Petroleum estimated to be in reservoir 3. the method and calculation of the estimates in item (ii) above; 4. all the data upon which the above estimates were based which includes but not limited to maps of scale 1:12,500, 1:25,00, whichever is applicable at each reservoir level for the following: a. Structure depth map at top of reservoir quality rocks b. Reservoir facies to reflect the porosity and permeability distribution vertically or laterally c. Net hydrocarbon d. Definition of the various petroleum in place and reserves category.

REMARKS

Page 504

DATA CLASS

FORMAT

CDR/DVD

10.4 No of wells which were Paper shut-in 10.5 No of wells into which Paper fluids or gas were injected 10.6 Total quantity of un Paper reconciled Petroleum & water produced

Monthly Monthly

Acrobat PDF Acrobat PDF, ASCII


Monthly

Monthly

As and when available

Monthly


Acrobat PDF

Not Acrobat PDF applicable

Not applicable CDR/DVD Not applicable CDR/DVD/Ele Not ctronic applicable File/Digital & Online Submission

CDR/DVD

Paper

10.3 No of wells which produced Petroleum or water

Electronic Not Acrobat PDF, File/Digital/CD applicable Application R/DVD project format (e.g. OFM) , Spreadsheet

Paper

10.2 All available data, information, studies and reports inclusive of any subsequent revision thereof relating to production operations


SCALE

Electronic Not Acrobat PDF File/Digital/CD applicable R/DVD


10 Production Operations 10.1 Monthly Production report Paper including all PDF format

NO.

APPENDIX 17

REVISION 2 AUG 2008

As per stated in Item 9.7, Section 9 – Procedures for Onshore/Offshore Operations of PPGUA document.

REMARKS

Page 505

DATA CLASS

FORMAT

Not Acrobat PDF, applicable ASCII





SCALE

Monthly

Monthly

Monthly

SUBMISSION PERIOD Future Data Monthly


MEDIA Hardcopy *Electronics Total quantity of fluids Paper CDR/DVD/Ele and gas injected ctronic File/Digital & Online Submission Qty of Petroleum utilized, Paper CDR/DVD/Ele flared or vented, stored in ctronic and delivered from each File/Digital & production station; Online Submission Reconciled production of Paper CDR/DVD/Ele Petroleum ctronic File/Digital & Online Submission Petroleum flow, pressure Paper CDR/DVD/Ele and temperature readings ctronic at each production station File/Digital & Online Submission Monthly production Paper CDR/DVD/Ele allocation data ctronic File/Digital & Online Submission


10.11

10.10

10.9

10.8

10.7

NO.

APPENDIX 17

REVISION 2 AUG 2008

For Digital data and On-line submission, Volume or Quantity is by String, Completion, Well, Zone, Reservoir & Field.

REMARKS

Page 506

DATA CLASS

FORMAT






SCALE

Page 507

Monthly

Monthly

Monthly

Monthly

REVISION 2 AUG 2008



SUBMISSION PERIOD REMARKS Future Data Monthly For Digital data and On-line submission, Volume or Quantity is by String, Completion, Well, Zone, Reservoir & Field.


MEDIA Hardcopy *Electronics Daily gas injection data Paper CDR/DVD/Ele ctronic File/Digital & Online Submission Daily water injection data Paper CDR/DVD/Ele ctronic File/Digital & Online Submission Gas lift gas data Paper CDR/DVD/Ele ctronic File/Digital & Online Submission Daily well status data Paper CDR/DVD/Ele ctronic File/Digital & Online Submission Well test data Paper CDR/DVD/Ele ctronic File/Digital & Online Submission


10.16

10.15

10.14

10.13

10.12

NO.

APPENDIX 17

DATA CLASS


None

REMARKS

Page 508

REVISION 2 AUG 2008

Inclusive of progress and evaluations and preliminary well log results whenever available;

3 months after completion None of well

1 week before commencement of work

Acrobat PDF, Daily or weekly Spreadsheet file

Acrobat PDF

Acrobat PDF

SUBMISSION PERIOD Future Data Annually


CDR/DVD/Ele N/a ctronic File/Digital & Online Submission

Paper

11.3 Daily or weekly drilling reports

N/a

CDR/DVD

N/a

11.2 Standard drilling program Paper from each platform

CDR/DVD

MEDIA SCALE FORMAT Hardcopy *Electronics Paper CDR/DVD/Ele Not Acrobat PDF, ctronic applicable ASCII File/Digital & Online Submission

11 Development drilling 11.1 Notice of Operation for Paper well drilling and work over

10.18 Quarterly Crude Oil Production Capacity Review 10.19 Quarterly Gas Production Capacity Review

10.17 Pressure survey data

NO.

APPENDIX 17


N/a

N/a

N/a

N/a

Acrobat PDF

Acrobat PDF

Acrobat PDF

Acrobat PDF

Acrobat PDF

As when available & finalized



3 months after abandoned

None

3 months after completion None of well

SUBMISSION PERIOD Future Data Acrobat PDF, 3 months after completion None Spreadsheet file of well

FORMAT


CDR/DVD

12.3 Basis for Design (BFD) / Paper Project Development Memorandum (PDM)

CDR/DVD

CDR/DVD

CDR/DVD

Paper

Paper

Paper

12.2 Field Development Plan (FDP)

12 Project Management 12.1 FDP Feasibility study report (as request)

11.6 Well abandonment reports;

DATA CLASS

MEDIA SCALE Hardcopy *Electronics 11.4 Well completion reports; Paper CDR/DVD/Ele N/a ctronic File/Digital & Online Submission 11.5 Final completion reports Paper CDR/DVD N/a (for work over operations)

NO.

APPENDIX 17

REMARKS

REVISION 2 AUG 2008

Page 509

DATA CLASS

CDR/DVD

CDR/DVD

12.7 Pre start-up HSE Audit / Paper Independent Project Review Report (executive summary only)

12.8 Project Close Out Paper Reports (Final report and drilling report submission is three months after project completion and 90 days after drilling completion, respectively)

N/a

N/a

N/a

N/a

Acrobat PDF

Acrobat PDF

Acrobat PDF

Acrobat PDF

Acrobat PDF

FORMAT

Final Drilling Report – 90 days after drilling

Final Project Close Out – 3 months after project completion.




SUBMISSION PERIOD Future Data As when available & finalized


CDR/DVD

12.6 Management Review Paper Report / Independent Project Review Report for Detailed Design (executive summary only)


CDR/DVD


12.5 Project Execution Plan Paper (PEP) (including updates)

12.4 Project Specification (Conceptual Design Report Summary) / Design Basis Memorandum (DBM)

NO.

APPENDIX 17

REMARKS

REVISION 2 AUG 2008

Page 510

DATA CLASS

N/a

CDR/DVD

CDR/DVD

12.13 Transportation and Paper installation procedures for major facilities when available 12.14 Factory acceptance test Paper procedure completion reports where applicable


N/a

CDR/DVD

12.12 Major fabrication planning Paper package and execution plan

Acrobat PDF

Acrobat PDF

Acrobat PDF

Acrobat PDF

Acrobat PDF

Acrobat PDF

FORMAT

Page 511



As and when required


REVISION 2 AUG 2008

SUBMISSION PERIOD REMARKS Future Data As and when available Inclusive of conceptual studies, conceptual or preliminary or frontend design and amendments thereto As and when available


N/a

N/a

CDR/DVD

Paper

N/a

12.11 Special Engineering studies

CDR/DVD

Paper


12.10 Project assessment report; if any

12.9 Platform facility design basis or philosophy

NO.

APPENDIX 17

DATA CLASS


12.18 Operating and start-up manual 12.19 Overall long-term maintenance program for facilities and pipelines 12.20 Weekly and monthly operation and maintenance reports 12.21 Facility modification and upgrading reports (including as built drawing update)

12.16 Main sub-contractor performance appraisal reports 12.17 As built drawings

12.15 Weekly and monthly engineering reports and main subcontractor progress reports (where applicable)

NO.

CDR/DVD/Ele N/a ctronic File CDR/DVD/Ele N/a ctronic File

Paper

Paper

Acrobat PDF, Electronic CAD

Acrobat PDF

Acrobat PDF

Acrobat PDF

Acrobat PDF, Electronic CAD

Acrobat PDF

Acrobat PDF

FORMAT

REMARKS

Page 512



As when available

Upon request

REVISION 2 AUG 2008

As when available ( after Inclusive of vendor catalogue and contractor to updates for as built drawings operator/owner handover) whenever available.




N/a

CDR/DVD

Paper

N/a

CDR/DVD

CDR/DVD/Ele N/a ctronic File

N/a

Paper

Paper

CDR/DVD


APPENDIX 17

DATA CLASS


13.4 Production, stock, sales or exports and losses figures.

13.2 Report of Result of the validation exercise performed 13.3 Detailed Petroleum accounting procedures;

Paper

Paper

Paper

N/a

N/a

Acrobat PDF

Acrobat PDF

CDR/DVD

FORMAT

As when available

In the month after the calibration/validation has been done As when available

As and when required



CDR/DVD

CDR/DVD

MEDIA SCALE Hardcopy *Electronics CDR/DVD N/a Acrobat PDF

Measurement for custody transfer and entitlement determination purposes, 13.1 Detailed measurement Paper procedures, design and operation of measurement systems;

13

12.22 Risk assessment, environmental impact assessment, technical or safety audit and HAZOP study reports, if any;

NO.

APPENDIX 17

REMARKS

REVISION 2 AUG 2008

Page 513

DATA CLASS

CDR CDR CDR CDR CDR CDR

Paper

Paper Paper

Paper Paper

Paper

14.6 Emergency Response Plan 14.7 HSE KPI Report 14.8 HSE-MS Audit Final Report 14.9 HSE Audit Final Report 14.10 Incident Investigation Report 14.11 EIA Report


CDR

CDR

Paper

14.5 HSE Plan

Paper

N/a

CDR

14.12 EIA and EMP Approval Condition

N/a

CDR

Acrobat PDF

Acrobat PDF

Acrobat PDF Acrobat PDF

Acrobat PDF Acrobat PDF

Acrobat PDF

Acrobat PDF

Acrobat PDF

Acrobat PDF

Acrobat PDF

Acrobat PDF

FORMAT

One month after the date of incident One month after DOE approval One month after DOE approval

Within one month after endorsement One month before commencement One month before commencement One month after commencement December of the preceding year One month before commencement th Every 15 One month after commencement



N/a

N/a

N/a N/a

N/a N/a

N/a

N/a

N/a

CDR

14.2 HSE Cases (Production Paper Phase) 14.3 CIMAH Report (for Paper onshore operations) 14.4 Health Risk Assessment Paper

N/a

SCALE

CDR


Paper

Health, Safety and Environment 14.1 HSE-MS Manual

14

NO.

APPENDIX 17

REMARKS

REVISION 2 AUG 2008

Page 514

DATA CLASS

Onshore / Offshore Operations Notice of Intent Annual Shutdown Plan Major Unplanned Crude Oil Production Interruption Major Unplanned Gas Supply Interruption As-built Drawings of Completed Projects Daily Production Operations Report Quarterly Production Operations Report


15.7

15.6

15.5

15.4

15.1 15.2 15.3

15

CDR

Acrobat PDF

Acrobat PDF

FORMAT

Early April of the succeeding year



N/a

MEDIA SCALE Hardcopy *Electronics Paper CDR N/a

14.13 Environmental Compliance Report (Scheduled Waste, TENORM, Effluent Quality and Emission) 14.14 PETRONAS Group GHG Paper Report

NO.

APPENDIX 17

REMARKS

REVISION 2 AUG 2008

Page 515

DATA CLASS

Reserve status

Latest as-built drawing

16.5

16.6


ARPR report (Annual Review of Petroleum Resource)

Paper

16.7 Inspection records

17

Paper

16.7 Major maintenance, improvement and modification records

Paper

Paper

N/a

N/a

N/a

N/a

Acrobat PDF

Acrobat PDF

Acrobat PDF

Acrobat PDF

Acrobat PDF

Acrobat PDF

Acrobat PDF

Acrobat PDF

Acrobat PDF

FORMAT

annually

Within 3 months after relinquished

SUBMISSION PERIOD Future Data Within 3 months after relinquished Within 3 months after relinquished Within 3 months after relinquished Within 3 months after relinquished Within 3 months after relinquished Within 3 months after relinquished Within 3 months after relinquished Within 3 months after relinquished


CDR/DVD

CDR/DVD

CDR/DVD

CDR/DVD

CDR/DVD

Well status

16.4

N/a

N/a

CDR/DVD

Paper

N/a

CDR/DVD

N/a

Well, reservoir and field Paper performance history 16.3 Reservoir and well data Paper

16.2

CDR/DVD


Relinquishment status report 16.1 Complete report listings Paper

16

NO.

APPENDIX 17

None

None

None

None

None

None

None

None

None

REMARKS

REVISION 2 AUG 2008

Page 516

Page 517

Manager, Data Management Section, Technology, Capability & Data Management, Petroleum Management Unit, PETRONAS

Any query regarding the guidelines and procedures stated in Section 17: Data Management and Submission Guidelines can be directed to:

QUERIES REGARDING THE GUIDELINE

17.1.2.1


PSC Data Management Section, Technology, Capability & Data Management, Petroleum Management Unit, PETRONAS Level 23, Tower 2 PETRONAS Twin Towers 50888 Kuala Lumpur REVISION 2 AUG 2008

Submission of Post Stack Seismic data plus Bin Center, Observers Log, Velocity in tapes, Well logs data packages and Technical reports in a set of digital copy and hardcopy by the PS Contractor shall be made to:

17.1.2 THE SUBMISSION ADDRESSES

17.1.1

DATA SUBMISSION ADDRESSES


17.1

APPENDIX 17

Page 518

PETRONAS Geological Samples Warehouse LOT 6744, Jalan Tekali 1 Kawasan Perindustrian Tekali 11/2 Miles, Sungai Tekali 43100 Ulu Langat

For Geological samples such as core, cuttings, fluids etc, the submission should be sent to:



REVISION 2 AUG 2008

Note: PETRONAS will inform PS Contractors on the details of the contact person from time to time or in the event that the addresses have changed or been revised

17.1.2.3

Record Centre Operation (RCO), PETRONAS Management Training Centre (PERMATA), Lot 1413, C. T. 3457, Off Jalan Air Hitam, 43000 Kajang, Selangor Darul Ehsan.

17 .1. 2.2 For submission of Pre-Stack data such as Field and gathers, navigation and observers log the submission should be addressed to:

APPENDIX 17

APPENDIX 18

Page 519

APPENDIX 18A

SUPERSEDE ISSUE:

AUG 2000


REVISION 2 AUG 2008

APPENDIX 18

Page 520

APPENDIX 18B NOTIFICATION CONTACT LIST : PMU, PETRONAS REGIONAL OFFICE, KERTE H

POSITION

:

MANAGER, EAST COAST REGIONAL OFFICE

TELEPHONE HANDPHONE FAX

: : :

09-864-0688(DL) 019-9153340 (PMU KERTEH, REGIONAL MANAGER) 09-8640127

PMU, PETRONAS REGIONAL OFFICE, SABAH / SARAWAK:

POSITION

:

MANAGER, SABAH/SARAWAK REGIONAL OFFICE

TELEPHONE HANDPHONE FAX

: : :

085-662425 / 085-474030 (D/L) 019-2749268 (PMU MIRI, REGIONAL MANAGER) 085-662623

PETROLEUM OPERATION MANAGEMENT (POM), PMU, KUALA LUMPUR: 1.

POSITION TELEPHONE HANDPHONE FAX ALTERNATE TELEPHONE HANDPHONE FAX

: : : : : : : :

SENIOR MANAGER, HSE 03-2331-3279 (DL) 012-3289341 (PMU HSE KL OFFICE) 03-2331-3168 / 3169 GENERAL MANAGER, PRODUCTION OPERATIONS 03-2331-2599 019-8215492 03-2331-3168 / 3169

2.

POSITION TELEPHONE HANDPHONE FAX

: : : :

SENIOR GENERAL MANAGER, POM 03-2331-4108 (DL) 019-9830392 03-2331-3168 / 3169

SUPERSEDE ISSUE:

AUG 2000


REVISION 2 AUG 2008

Page 521

APPENDIX 18

PETRONAS COMCEN, KUALA LUMPUR (24 HOURS MANNED STATION) TELEPHONE FAX ATTENTION

: : :

03-21611703 (D/L), 03-23312141 / 2142 / 2143 / 2144 03-21611696 COMCEN MANAGER H/P : 019-2266699 03-2331 6250 (D/L)

DESIGNATION

NAME

GM PIMMAG

Capt. Amir Murad

Manager, Operations And Training

SUPERSEDE ISSUE:

AUG 2000

- Alternate Capt. Chin Kon Wing

OFFICE

HOME

03-2783-6993 (D/L) H/P 019-3500197 03-2783-6997 (G/L) 03-2783-6992 (Fax) 03-2783-6998 (D/L) H/P 019-3131631 03-2783-6992 (Fax)


REVISION 2 AUG 2008

Page 522

APPENDIX 18

APPENDIX 18B

PETRONAS : EMERGENCY CONTACT LIST DESIGNATI ON

NAME

OFFICE

HP/EMAIL

President

Y.Bhg. Tan Sri Dato' Mohd Hassan 03-2331 4802 Marican 03-2331 4401

03-42532590

Vice President (E&P Business)

Ramlan Abdul Malek

03-2331 3362 03-2331 1301

H/P: 012-8388387 ramlanm@petrona s.com.my

PETROLEUM MANAGEMENT UNIT Senior General Manager Petroleum Operations Management

Mohd Tarmizi Munir

03-2331 4108 03-2331 3364

H/P: 019-9830392 tarmizm@petrona s.com.my

Senior General Manager Petroleum Resource Exploration

Effendy Cheng Abdullah

03-2331 4678 03-2331 2116

H/P: 012-2771245 effendy@petronas .com.my

Mohd Jukris Abd Wahab Senior General Manager Petroleum Resource Development

03-2331 9393 03-2331 9339

General Manager Strategic Planning

03-23314432 03-23312717

H/P: 017-6307220 jukrisw@petronas. com.my H/P: 012-3731013 [email protected] om.my

M arina Bt M d taib

Dr Jaizan Hardi Jais General Manager Technology, Capability & Data Mgt

03-2331 3115 03-2331 5170

H/P: 019-3180920 jaizan@petronas. com.my

General Manager Production Operations

Joseph Podtung

03-2331 2599 03-2331 3675

HP: 019-8215492 josephp@ petronas.com.my

General Manager Drilling

Ahmad Nahrawi

03-23313171

Manager HRM & Administrative Services

Norzeta Binti Ismail

03-23313515

Senior Manager Health, Safety & Evironment

Amer Othman

03-2331 3279 03-2331 3314

HP: 012-3257165 ahmadnahrawi_moh [email protected] HP: 019-3527779 [email protected] m.my H/P: 012-3289341 [email protected] m.my

Azlan Mohd Said

03-2331 2372 03-2331 2336

COM CEN / M anager

03-23312141 / 2142 / 2143 / 2144 03-21611703

CORPORATE SECURITY General Manager, Security Planning Development & Crisis Management

H/P: 012-2012942 azlan_msaid@petr onas. com.my

COMCEN PETRONAS Twin Towers

SUPERSEDE ISSUE:

AUG 2000


REVISION 2 AUG 2008

Page 523

APPENDIX 18

DESIGNATION

NAME

OFFICE

HP/EMAIL

Group HRM General Manager

Zaharan B. Ma t Alipiah

03-2331 2014 03-2331 2367

H/P: 019-2335411 zaharan@petrona s.com.my

Iqbal Abdullah

03-2331 4955

H/P: 012-3937690 iqbal@petronas. com.my

03-2331 1354 03-2331 4736

H/P: 013-3501531 roslirh@petronas. com.my

H/P: 019-2136737

Group HS E Senior General Manager

LEGAL & CORPORATE AFFAIR DIVISION Rosli bin Abdul Rahim General Manager Stakeholders Management (Group Corporate Affair) PETRONAS - EAST COAST REGIONAL OFFICE General Manager

Zulkifly B. Mohd Ismail

09-8655517 09-8655574

Senior Manager PMU Kerteh

Hamadi Tani

09-8640688 03-2331 9269

PETRONAS - SABAH/SARAWAK REGIONAL OFFICE General Manager Sabah

Burhan Rasit

088-296900 (D/L) H/P: 012-2993700 088-296901

General Manager Sarawak

Mosir B Hamid

082-419601(G/L) 082419604(G/L)

Senior Manager PMU Sabah/Sarawak

Dzulkafli B Mansor

085-662425 (D/L) H/P: 019-6554512 085-474030 (D/L)

SUPERSEDE ISSUE:

AUG 2000


H/P: 019-9534006

REVISION 2 AUG 2008

SUPERSEDE ISSUE:

AUG 2000

APPENDIX 18

Page 524


REVISION 2 AUG 2008

SUPERSEDE ISSUE:

AUG 2000

APPENDIX 18

Page 525


REVISION 2 AUG 2008

SUPERSEDE ISSUE:

AUG 2000

APPENDIX 18

Page 526


REVISION 2 AUG 2008

SUPERSEDE ISSUE:

AUG 2000

APPENDIX 18

Page 527


REVISION 2 AUG 2008

SUPERSEDE ISSUE:

AUG 2000

APPENDIX 18

Page 528


REVISION 2 AUG 2008

SUPERSEDE ISSUE:

AUG 2000

APPENDIX 18

Page 529


REVISION 2 AUG 2008

APPENDIX 18

Page 530

APPENDIX 18D

SUPERSEDE ISSUE:

AUG 2000


REVISION 2 AUG 2008

SUPERSEDE ISSUE:

AUG 2000

APPENDIX 18

Page 531


REVISION 2 AUG 2008

SUPERSEDE ISSUE:

AUG 2000

APPENDIX 18

Page 532


REVISION 2 AUG 2008

SUPERSEDE ISSUE:

AUG 2000

APPENDIX 18

Page 533


REVISION 2 AUG 2008

SUPERSEDE ISSUE:

AUG 2000

APPENDIX 18

Page 534


REVISION 2 AUG 2008

Reconciled Well Technical Potential R

P O

R

P

A v a i la b il it y L o s s e s

P la n n e d U n p la n n e d M a in te n a n c e o th e r D eferm e n t t h a n D O S H , P M U E q u i p m e n t f a i lu r e

W

P r o d u c tiv ity L o s s e s

S lo w d o w n / L o w

Q u a l it y L o s s e s

Page 535

R e c o n c ile d

x100

REVISION 2 AUG 2008

R e c o n c i li a t i o n e ff e c t S h r i n k a g e lo s s e s

A c t u a l P r o d u c ti o n A d ju s te d T e c h n ic a l P o te n tia l


P la n n e d D e fe rm e n t DO SH, PMU re q u irem e n t

O

E x te rn a l L o s s e s

W

Adjusted Technical Potential


EUP

OEE =

Availability

E x t e r n a l D e fe rm e n t C o m m o n F a c i lit i e s O B O d o w n t im e T a n k e r d e la y

EP

O il - O E E

APPENDIX 19A

APPENDIX 19

Actual Production

Metered Production

E xte rn a l D e fe rm e n t

Reconciled Well Technical Potential O p e r a ti o n a l U sage

C o n d e n s a t io n

O p e r a ti o n a l fl a r in g F uel G a s r e - i n j e c ti o n G a s lif t B la n k e t g a s U t il it y / In s tr u m e n t gas

In d ire c t L o s s e s

P la n n e d D e fe rm e n t (D O S H /P M U )

1. 2. 3. 4. 5. 6.

Adjusted Technical Potential


Page 536

U n p la n n e d D e fe rm e n t ( Q u a lit y * * )

1 . C o m p re s s o r s h u td o w n 2 . H u m a n e rro r

T r a n s m is s i o n / R e c o n c i li a t i o n lo s s e s

Leakage/ R e c o n c i li a t i o n


1

REVISION 2 AUG 2008

R e c e iv e d b y T e rm in a l

R e c o n c ile d P r o d u c tio n x100 A d ju ste d T e c h n ic a l P o te n tia l *

P la n n e d U n p la n n e d D e fe rm e n t D e fe rm e n t NON ( U n r e li a b i li ty ) D O S H /P M U

1 . E q u ip m e n t m a in te n a n c e 2 . P r o j e c ts

OEE =

Metered Production

* A d j u s t e d T e c h n i c a l P o t e n ti a l = R e c o n c il e d P r o d u c t i o n + t r a n s m i s s i o n / r e c o n c il i a t io n l o s s e s + u n p l a n n e d d e f e r m e n t ( U n r e l ia b il it y & Q u a li t y ) + p la n n e d d e fe rm e n t (n o n D O S H /P M U ) * * W h e n o p e r a t o r i s a s k e d t o s h u t d o w n b e c a u s e o f g a s q u a l it y / c o m p o s it i o n i s s u e . * * * E x c e s s c a p a c it y i s a r e c o n c i le d n u m b e r t h a t c a n o n l y b e c a l c u l a t e d a f te r a l l o t h e r d e f e r m e n t /l o s s e s a r e a c c o u n t e d f o r * * * * C u s t o m e r i s d e f i n e d b a s e d o n th e b o u n d a r y o f t h e s p e c if i c s y s t e m b e i n g m e a s u r e d

E xces s c a p a c ity * **

1 . C u s t o m e r ’s u n a v a i l a b ili t y 2 . P ip e lin e o v erp res s u re

G as - O EE

APPENDIX 19B

APPENDIX 19

Reconciled Production

Page 537

APPENDIX 19

APPENDIX 19C

"

!

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APPENDIX 19

APPENDIX 19D

Page 543

A p p e n d ix E

R C P S C a u s a l T re e L e a d e r s h ip

A s k w h y 5 t im e s t o g e t t o t h e r o o t c a u s e

G ro u p th e ro o t c a u s e s

C a p a b i l it y M in d s e t s & B e h a v io r O r g a n iz a t io n

Is t h e p r o b le m s ta te m e n t c le a r ?

If I s o l v e t h i s i s s u e , d o e s it s o lv e t h e p r e v io u s i s s u e ? W h a t a r e t h e im m e d ia t e c a u s e s ? A re th e y c o m p re h e n s iv e a n d in d e p e n d e n t o f e a c h o t h e r ? 4



REVISION 2 AUG 2008

A p p r o v e t a r g e t s a n d m e t r ic s


S o u rc e : P M U

A p p ro v e te a m m e m b e rs a n d a l lo c a t e r e s o u r c e s

D e v e lo p s o lu tio n s

•

A p p r o v e m o n it o r i n g p la n

A p p r o v e im p le m e n t a t io n p la n

A p p r o v e a l lo c a t io n o f r e q u ir e d r e s o u r c e s ( b u d g e t a nd m a np o w e r)

G a te 3

ta rg e t s

G a te

Page 544

REVISION 2 AUG 2008

C o n f i r m im p a c t o f p r o j e c t a g a in s t t a r g e t s

C o n f i r m p r o j e c t c o m p le t io n

G a te 4

a g a in s t d e a d lin e s

• M e a s u r e p r o j e c t r e s u lt s a g a i n s t

p la n C o m p le t e r i s k a n d im p a c t m o n it o r i n g p la n

• T r a c k im p le m e n t a t io n p r o g r e s s

te a m

M eas ure p r o je c t r e s u lts

• D e v e lo p im p le m e n t a t io n

T ra ck im p le m e n ta tio n

S ta g e 4 (~ 1 2 -2 4 m o n th s )

• F o r m im p le m e n t a t io n

P la n im p le m e n ta tio n

S ta g e 3 (~ 2 w e e k s )


A p p ro v e b u d g e t r e c o m m e n d a t io n s

R e v ie w m a n p o w e r r e q u ir e m e n t s

V a l id a t e p r o p o s e d s o l u t io n s

R e v ie w r o o t c a u s e a n a l y s i s

G a te 2

D e te r m in e r o o t c a u s e • B u i ld f a c t - b a s e • P e r f o r m r o o t c a u s e p r o b le m s o l v i n g • P r io r it iz e r o o t c a u s e s D e v e lo p s o lu tio n s • D e v e lo p p o t e n t ia l s o l u t io n s a n d e s t im a t e im p a c t • D e t a i l r e s o u r c e s r e q u ir e d ( e . g . , m a n p o w e r, b u d g e t) • E s t im a t e c o m p le t io n d a t e s • L a u n c h q u ic k - w i n s a c t io n ( if a n y )

D e te r m in e r o o t ca use

S ta g e 2 (8 w e e k s )

A p p r o v e p r o j e c t o b j e c t iv e , s c o p e a n d s c h e d u le

G a te 1

S ta g e g a te d e c is io n s

•

– P r o b le m – O b j e c t iv e – S cope – S u c c e s s c r it e r ia – R e s o u rc e s – C o n s t r a in t s D e te r m in e p r o j e c t t im e l i n e a n d m i le s t o n e s

• D e f in e

D e fin e th e p r o b le m

S ta g e 1 (~ 2 w e e k s )

S ta g e g a te a c tiv i tie s

S t a g e g a t in g is a p r o je c t m a n a g e m e n t t o o l t h a t b r e a k s a p r o je c t d o w n b y a c t iv it y (s ta g e s ) a n d c r itic a l d e c is io n s (g a te s )

A P P E N D IX 1 9 E

APPENDIX 19


S o u rc e : P M U

E x c lu d e d f r o m s c o p e :

In c lu d e d in s c o p e :

5. Scope:

3 . P r o b le m d e fi n i tio n : -

-

1 . In itia ti v e ti tle :

N am e: P o s iti o n : C o n ta c t p h o n e : C o n t a c t e m a il:

2 . P r o je c t te a m le a d e r :

S t a r t le v e l -

KPI -

6 . C r ite r ia fo r s u c c e s s :


-

4 . O b je c ti v e :

S ta g e G a te 1 : P r o b le m d e fin itio n te m p la te (p g 1 /2 )

A P P E N D IX 1 9 F

APPENDIX 19

REVISION 2 AUG 2008

-

T a r g e t le v e l

Page 545

P r o f ile

8 . P o t e n t ia l b a r r ie r s :


S o u rc e : P M U

-

D ept

7 . T e a m m em b e rs C o m m it m e n t


S e n io r m a n a g e m e n t r e s p o n s ib le :

C I m a nager

T e a m le a d e r :

1 0 . V a lid a t io n :

G ate 2

G a te 3

9 . T a r g e t c o m p le t io n d a t e s f o r r e m a in in g G a t e s

-

Nam es

S ta g e G a te 1 : P r o b le m d e fin itio n te m p la te (p g 2 /2 )

A P P E N D IX 1 9 F

APPENDIX 19

REVISION 2 AUG 2008

G a te 4

Page 546

Page 547



REVISION 2 AUG 2008

1 ) In itia tiv e title : C h o o s e a s h o r t n a m e th a t b e s t d e s c r ib e s th e in iti a tiv e . T h e titl e w ill a c t a s th e id e n tif ie r to d is ti n g u is h t h is in iti a tiv e f r o m th e o th e r s 2 ) In itia tiv e te a m l e a d e r : T h is is t h e n a m e o f th e p e r s o n r e s p o n s ib le f o r th e e n d - to - e n d c o m p e titio n o f th e in iti a tiv e a t th e w o r k in g le v e l. 3 ) P r o b l e m d e fi n itio n : D e t a ile d d e s c r ip tio n o f th e p r o b le m in c lu d in g th e f o llo w in g e le m e n ts : W h a t: W h a t is th e n a t u r e o f th e p r o b le m W h e r e : W h e r e it o c c u r s ( e .g ., o n w h a t f ie ld , p la tf o r m , w e ll, e q u ip m e n t) W h e n : W h e n d id t h e p r o b le m f ir s t o c c u r a n d h o w o f te n it h a s o c c u r r e d i n t h e p a s t 1 2 m o n t h s . Im p a c t: W h a t h a s b e e n t h e im p a c t to p r o d u c tio n ( K b /d ) 4 ) O b je c tiv e : A d e t a ile d d e s c r ip tio n o f th e o b je c tiv e o f th e in iti a tiv e th a t is S p e c if ic : O u tlin e s t h e o b je c tiv e – w h a t y o u w a n t to a c h ie v e M e a s u r a b le : I n tr o d u c e s a m e a s u r a b le o u tc o m e ( e .g ., r e d u c e d o w n tim e b y x % , in c r e a s e w e ll u p tim e b y y % ) A c ti o n a b le : D e s c r ib e s h o w y o u w ill a c h ie v e y o u r o b je c tiv e R e le v a n t: L in k s t h e o b je c tiv e a n d a c ti o n s t o th e p r o b le m a t h a n d T im e b o u n d : S p e c if ie s w h e n y o u p la n to a c h i e v e th e o b je c tiv e 5 ) S c o p e : S t a t e t h e f o c u s a n d b o u n d a r i e s o f t h e a c t i v i t i e s . W h e r e a p p l i c a b l e , c l a r if y w h a t i s n o t i n c l u d e d i n t h e s c o p e t o e n s u r e t h e te a m is f o c u s e d o n l y o n w h a t is d ir e c tl y r e l a te d to t h e is s u e a t h a n d . 6 ) S u c c e s s c r ite r ia : L is t d o w n th e 2 - 4 K P Is t h a t a r e d ir e c tly li n k e d to t h e is s u e t h a t c a n b e m e a s u r e d to d e te r m in e w h e th e r o r n o t th e i n itia tiv e w a s s u c c e s s f u l. In d ic a t e b o th c u r r e n t le v e ls a n d t h e d e s ir e d ta r g e ts p o s t im p le m e n ta tio n . 7 ) T e a m m e m b e r s : I n t h i s s e c t i o n n o t e t h e c o m p o s i t i o n o f t h e ‘ p r o b l e m s o lv i n g ’ t e a m m e m b e r s . T h i s i s l i k e l y t o b e d i f f e r e n t t h a n t h e i m p l e m e n t a t i o n t e a m . L i s t t h e d e p a r t m e n t ( t o p s id e m a i n t e n a n c e ) , p r o f i l e ( e . g . , s p e c i a l i s t i n r o t a t i n g e q u i p m e n t ) a n d n a m e s o f in d iv id u a l t e a m m e m b e r s . A ls o lis t t h e a g r e e d - t o t im e c o m m itm e n t o f e a c h in d iv id u a l. 8 ) P o t e n ti a l b a r r ie r s : L is t d o w n th e p o te n tia l b a r r ie r s to s u c c e s s f u lly r e s o lv in g th e is s u e s . T y p ic a l b a r r ie r s in c lu d e l a c k o f c o m m itm e n t , a lig n m e n t o f t o p m a n a g e m e n t , in a d e q u a t e r e s o u r c e s ( m a n p o w e r , f in a n c ia l, a n d c a p a b ilit ie s ) 9 ) T i m e t o g a te c o m p le ti o n : T h e s u g g e s te d tim e lin e f o r g a te c o m p le tio n is a s f o llo w s G a te 2 : 8 w e e k s a f te r G a te 1 G a te 3 : 4 w e e k s a f te r G a te 2 G a te 4 : W ith in 6 m o n th s o f G a te 3 1 0 ) V a lid a tio n : E a c h g a t e m u s t b e s ig n e d o f f b y b o th th e te a m m e m b e r , th e c o n ti n u o u s im p r o v e m e n t ( C I) m a n a g e r a n d a s e n i o r m a n a g e r r e s p o n s ib le f o r a d d r e s s in g th e is s u e . V a li d a ti o n b y th e s e t h r e e p a r tie s is r e q u ir e d f o r e a c h g a t e s u b m is s io n .

T h e r e a r e 1 0 s u b - s te p s in th is s t a g e w h ic h m u s t b e fu lf ille d p r io r m o v in g to S ta g e G a te 2 :

S ta g e G a te 1 : P r o b le m d e fin itio n g u id e lin e

A P P E N D IX 1 9 F ( C O N T . )

APPENDIX 19

Page 548

APPENDIX 19

A P P E N D IX 1 9 G

S ta g e G a t e 2 : R o o t c a u s e s o lu t io n te m p la t e M a jo r c a u s e s

P r o p o s e d s o lu t io n a n d a c t io n s

E x p e c te d im p a c t

E s t im a t e d cost

E x te rn a l re s o u rce s r e q u ir e d

T im e to c o m p le t e

V a lid a t io n : T e a m le a d e r

C o n t in u o u s im p r o v e m e n t m a n a g e r

S e n io r m a n a g e r r e s p o n s ib le

S o u rc e : P M U



REVISION 2 AUG 2008

APPENDIX 19

Page 549

A P P E N D IX 1 9 G ( C O N T . )

S ta g e G a te 2 : R o o t c a u s e s o lu tio n g u id e lin e T h e S t a g e G a t e 2 t e m p la t e c a n o n ly b e f ille d i n o n c e t h e R C P S a n a ly s i s ( A p p e n d i x E ) c o m p le t e d . T h e r e a r e 6 s u b - s t e p s t o t e m p la t e c o m p le t i o n : 1 ) M a jo r c a u s e s :

2 ) P r o p o s e d s o lu t io n : 3 ) E x p e c t e d im p a c t :

4 ) E s t im a t e d c o s t : 5 ) E x te rn a l re s o u rc e s r e q u ir e d : 6 ) E s t im a t e d t im in g :


L i s t o u t t h e m a j o r c a u s e s / s p e c if i c f i n d i n g s o f t h e r o o t c a u s e i n v e s t i g a t i o n . F o r e x a m p le , i f y o u u s e d t h e 5 - w h y m e t h o d o lo g y , t h i s w o u ld c o r r e s p o n d t o t h e la s t b ra n c h (e s ) o f th e 5 -w h y tre e . L i s t p r o p o s e d s o lu t i o n a n d h i g h - le v e l a c t i o n s t o a d d r e s s t h e m a j o r c a u s e . L i s t t h e b e n e f it t h a t y o u w i ll a c h i e v e t h r o u g h i m p le m e n t i n g t h e a c t i o n s . T h i s s h o u ld b e li n k e d d i r e c t ly o r i n d ir e c t ly w i t h t h e K P I s li s t e d i n t h e s t a g e o n e t e m p la t e E s t i m a t e t h e c o s t t o im p le m e n t t h e a c t i o n . P r o v i d e d e t a i le d b a c k u p f o r b u d g e t a p p ro v a l I n d i c a t e if y o u w i ll r e q u i r e a d d i t i o n a l v e n d o r o r s e r v i c e p r o v i d e r s u p p o r t t o i m p le m e n t t h e a c t i o n . W h e r e a p p li c a b le , P E T R O N A S m a y b e a b le t o le v e r a g e i t s o w n n e t w o r k a n d a lli a n c e s t o a s s i s t if n e e d e d . E s t i m a t e t h e t i m i n g t o c o m p le t e t h e a c t i o n . A lt h o u g h t h e d e t a i le d i m p le m e n t a t i o n p la n w i ll b e d e v e lo p e d i n t h e n e x t s t a g e , p r o v i d e a n i n d i c a t i o n o f h o w lo n g y o u b e li e v e i t w i ll t a k e t o i m p le m e n t .


REVISION 2 AUG 2008

Page 550

APPENDIX 19

A P P E N D IX 1 9 H

S t a g e G a t e 3 : I m p l e m e n t a t io n a n d r i s k m i t i g a t io n p l a n s t e m p la t e ( p g 1 / 2 ) T e a m m e m b e rs D e p a rtm e n t

P r o file

Nam e

C o m m itm e n t

P o t e n t ia l is s u e s / r is k s a n d m it ig a t io n : R is k

A c tio n

V a lid a t io n : T e a m le a d e r

C o n t i n u o u s im p r o v e m e n t m a n a g e r

S e n io r m a n a g e r r e s p o n s ib le

S o u rc e : P M U



REVISION 2 AUG 2008

Page 551

APPENDIX 19

A P P E N D IX 1 9 H ( C O N T .)

S ta g e G a te 3 : Im p le m e n ta tio n a n d r is k m itig a t io n p la n s te m p la te (p g 2 /2 ) M a in C a u s e

M i le s t o n e t a s k

S ta rt d a te ( y y /m m /d d )

E n d d a te ( y y /m m /d d )

P e rs o n r e s p o n s ib le

S o u rc e : P M U



REVISION 2 AUG 2008

Page 552


p e rs o n .

s t a r t d a t e , e n d d a t e a n d r e s p o n s ib le


REVISION 2 AUG 2008

3 ) I m p l e m e n t a t io n p la n : P r o v id e t h e k e y m i le s t o n e a c t iv it ie s f o r e a c h m a jo r c a u s e f r o m s t a g e 2 t e m p la t e in c lu d in g t h e

t o t a k e t o m it ig a t e t h e m

2 ) R is k a s s e s s m e n t : In t h is s e c t io n , l is t d o w n t h e s p e c if ic r is k s t o a s u c c e s s f u l im p le m e n t a t io n a n d t h e a c t io n s y o u p la n

n a m e s a n d t im e c o m m it m e n t e x p e c t e d

1 ) I m p l e m e n t a t io n t e a m : S im ila r t o s t e p 7 in t h e s t a g e o n e p r o c e s s , lis t d o w n t h e d e p a r t m e n t , p r o f ile , t e a m m e m b e r

T h e r e a r e 3 m a in s t e p s t o c o m p le t in g s t a g e t h r e e – f o r m in g t h e im p le m e n t a t io n t e a m , a s s e s s in g t h e r is k s a n d d e v e lo p in g t h e p la n .

S ta g e G a te 3 : Im p le m e n ta tio n a n d r is k m itig a tio n p la n s g u id e lin e

A P P E N D IX 1 9 H ( C O N T . )

APPENDIX 19

APPENDIX 19

Page 553

A P P E N D IX 1 9 I

S ta g e G a te 4 : Im p le m e n t a t io n m o n it o r in g te m p la t e A c tio n ite m s c lo s u r e

A c tio n ite m

A c tio n s f o r s u s ta i n a b ility :

A c tu a l c lo s u r e

E x p e c te d c lo s u r e

… .

…

…

… .

…

…

… .

…

…

…

…

… .

P e r s o n n e l t r a in e d o n p r o b le m / n e w s o l u t io n s

D o c u m e n t a t io n g e n e ra te d / u p d a te d

O th e r

V a lid a t io n : T e a m le a d e r C I m a nager S e n io r m a n a g e r r e s p o n s ib le S o u rc e : P M U



REVISION 2 AUG 2008

APPENDIX 19

Page 554

A P P E N D IX 1 9 I ( C O N T . )

S ta g e G a te 4 : Im p le m e n ta tio n m o n ito r in g g u id e lin e

S t a g e G a t e 4 c o v e r s a c t io n it e m c lo s e o u t a n d s u s t a in a b ilit y s t e p s : 1 ) A c t io n i t e m c l o s e o u t : T h e a c t io n i t e m s h e r e s h o u ld d ir e c t ly c o r r e la t e t o m a jo r c a u s e f r o m t h e S t a g e G a t e 2 t e m p la t e a n d t h e im p le m e n t a t io n p la n . L is t t h e a c t io n it e m , t h e p la n n e d c lo s e d d a t e ( f r o m S t a g e G a t e 3 ) a n d a c t u a l c lo s e d d a t e . 2 ) S u s t a in a b il it y p l a n : S t e p s t a k e n t o e n s u r e s u s t a in a b ilit y o f t h e in it ia t iv e im p r o v e m e n t s . E x a m p le s in c lu d e , b u t a r e n o t lim it e d t o , t r a in in g , d o c u m e n t a t io n a n d p r o c e s s r e d e s ig n .



REVISION 2 AUG 2008

DEFINITION

Page 555

DEFINITIONS Actual Production Average production rate actually realised over a specified period.

Approved Production Average production rate over a specified period that is established and issued by PETRONAS from time to time to be complied by PS Contractor.

Facilities, structures and pipelines All topside facilities, offshore structures, pipelines, safety devices and system, storage tanks, wellhead stack-ups including sub-sea completions system, export & loading facilities, electrical installations and telecommunications facilities that related to production of oil, gas and condensate either installed onshore or offshore except for subsurface safety devices.

Gas Oil Ratio (GOR) Limits GOR limits established and issued by PETRONAS to be complied by PS Contractor.

Gas Utilisation The gas uses for petroleum operations and gas lift.

Guideline The official document outlining main PETRONAS’ requirements on specific activities to be undertaken by PS Contractor to ensure safe and cost effective operations in upstream activities.

HALAL Food Food contain no pork or meat without proper Islamic preparation. It shall be certified by Local Islamic Authorities.

SUPERSEDE ISSUE:

AUG 2000


REVISION 2 AUG 2008

Page 556

DEFINITION

Major Repairs Any repair work which cost RM 500 K and above for each particular unplanned works related to crude, gas and condensate production.

National Depletion Policy (NDP) Major fields having total Oil Initially Inplace (OIIP) equal to or more than 400 MMstb. The production from major fields will be limited to a ceiling of 3.0% of OIIP in any one year.

Oil Production Availability The Oil Production Potential after taking into account the planned shutdown schedule.

Oil Production Potential The forecast of oil production deliverability at full wellstream or at system capacity.

Operational Integrity Operational Integrity of a facility is achieved when it is being operated as intended, such that it can achieve production targets without attracting undue risks to personnel, environment or assets.

Over-Production The differential by which the Actual Production exceeds the Approved Production Levels.

PETRONAS Regional Office PETRONAS Petroleum Management Unit (PMU) regional offices located at Kerteh and Miri.

Procedure The official document outlining detail PETRONAS’ requirements on specific tasks in upstream operations to be undertaken by PS Contractor to ensure quality, reliability and standardized output

SUPERSEDE ISSUE:

AUG 2000


REVISION 2 AUG 2008

DEFINITION

Page 557

Tanker Lifting / Programming Meeting The monthly meeting between Crude Oil Group, Petroleum Management Unit and PS Contractor to forecast and target the subsequent month production level.

Technical Standard Standard set by PETRONAS in meeting certain technical specifications and requirements.

Technical Integrity Absence during specified operation of a facility foreseeable risk of failure endangering safety of personnel, environment or asset value. (Acceptable technical integrity refer to audit team recommendation prior to the field handover/relinquishment process).

Under-Production The differential by which the Actual Production falls short of the Approved Production levels.

Upstream Operations All activities involved in the oil, gas and condensate production.

SUPERSEDE ISSUE:

AUG 2000


REVISION 2 AUG 2008

PETRONAS PROCEDURES AND GUIDELINES FOR UPSTREAM ACTIVITIES

ACKNOWLEDGEMENT These procedures and guidelines review update for the Upstream Activities have been undertaken by Petroleum Management Unit in association with the established PETRONAS’ Production Sharing Contractors namely, PETRONAS Carigali Sdn.Bhd.(PCSB), ESSO Production Malaysia Limited (EMEPMI), Sarawak Shell Berhad (SSB), PETROFAC (Malaysia) Limited (PETROFAC), Amerada Hess (Malaysia) Limited (AMERADA HESS),Talisman Malaysia Limited (TML) Nippon Oil Limited (NIPPON), Newfield Sarawak Malaysia Inc (NEWFIELD) and Murphy Sarawak Oil Ltd & Sabah Oil Ltd (MURPHY OIL). The PMU Management would like to express special thanks and appreciation to the following key personnel for their perseverance and endless commitment in making these procedures and guidelines possible:

1. Guidelines for Health Safety & Environment i.

Azlan Subari (PMU)

ii.

Rozita Musib (PMU)

iii.

Bolhi Maskawi (PMU)

iv.

Razali Ibrahim (PMU)

v.

Nur Atikah Abu Bakar (PMU)

vi.

Enteli (PCSB)

vii.

Roziah Noordin (EMEPMI)

viii.

Andrew Collin (SHELL)

ix.

Mahathir Malim (PETROFAC)

x.

Saabi Wahab (TML)

xi.

Marina Jamil (MURPHY)

2. Guidelines for Explorations Survey Operations i.

M Zaki Othman (PMU)

ii.

Kevin Robinson (NEWFIELD)

iii.

M Yashkor Yunus (MURPHY)

iv.

W Hasan W Zakaria (PCSB) ISSUED BY PETROLEUM MANAGEMENT UNIT


v.

Anyi Ngau (SHELL)

vi.

Abd Razak Nurin (EMEPMI)

vii.

Anwar Khan (TML)

viii.

Yoshinori Lino (NIPPON)

ix.

Wee Eng Swee (AMERADA HESS)

3. Guidelines for FDP Review & Approval Process i.

Norhayati Hashim (PMU)

ii.

Chen Kah Seong (PMU)

iii.

Aidil Shabudin (PMU)

iv.

Zulkifli Abd Rani (PMU)

v.

Boo Kean Soon (PMU)

vi.

M Farizan Ahmad (PMU)

vii.

Jimmy Wee (SHELL)

viii.

Anthony Yeo (SHELL)

ix.

Abdul Rahman Abd Rahim (EMEPMI)

x.

Tn Syed Mohammad Syed Ismail (PCSB)

xi.

Ku Azhar Ku Akhil (MURPHY)

xii.

Quentin Goodbody (TML)

xiii.

Yoshinori Lino (NIPPON)

xiv.

Nor Azila Mohd Salleh (AMERADA HESS)

xv.

Barry Dawe (NEWFIELD)

xvi.

Cy. MC Cants (PETROFAC)

4. Guidelines for Project Development Management i.

Norhayati Hashim (PMU)

ii.

Mazuin Ismail (PMU)

iii.

Lau Nai Tung (SHELL)

iv.

Hafidzah Abdul Rahman (EMEPMI) ISSUED BY PETROLEUM MANAGEMENT UNIT


v.

Noriyani Osman (EMEPMI)

vi.

Syed Mohammad Syed Ismail (PCSB)

vii.

Ahmad Kamal Razak (PCSB)

viii.

Zahimi Osman (MURPHY)

ix.

Geoff Bell (TML)

x.

Kentaro Mochizuki (NIPPON)

xi.

Nor Azila Mohd Salleh (AMERADA HESS)

xii.

Patrick Simpson (NEWFIELD)

5. Guidelines for Drilling Operations i.

Iskandar Riza (PMU)

ii.

Alfian Iqbal (PMU)

iii.


iv.

Mariam A Aziz (PMU)

v.

Bambang Iriyanto (PMU)

vi.

Khairul Anuar Mahadi (PMU)

vii.

Neil Hudson (PCSB)

viii.

Kamarulzaman Jaafar (PCSB)

ix.

Kayode Olaikan (SHELL)

x.

Azmeer Ahmad (EMEPMI)

xi.

Azman (EMEPMI)

xii.

Fauzi Abbas (TML)

xiii.

Lee Chih Chiang (TML)

xiv.

Alan Ferguson (PETROFAC)

xv.

Chris Fannery (MURPHY)

xvi.

Kasim Selamat (MURPHY)

xvii.

Mike Wylie (NEWFIELD)

xviii.

Harun Embong (NIPPON) ISSUED BY PETROLEUM MANAGEMENT UNIT


6. Guidelines for Sub Surface Safety Devices i.

Mariam A Aziz (PMU)

ii.

Alfian Iqbal (PMU)

iii.

Iskandar Riza (PMU)

iv.


v.


vi.


vii.

Neil Hudson (PCSB)

viii.


ix.

Kayode Olaikan (SHELL)

x.

Azmeer Ahmad (EMEPMI)

xi.

Azman (EMEPMI)

xii.

Fauzi Abbas (TML)

xiii.

Lee Chih Chiang (TML)

xiv.

Alan Ferguson (PETROFAC)

xv.

Chris Fannery (MURPHY)

xvi.

Kasim Selamat (MURPHY)

xvii.

Mike Wylie (NEWFIELD)

xviii.

Harun Embong (NIPPON)

7. Guidelines for Barges Operating Offshore Malaysia i.

Zaidi Zulkifli (PMU)

ii.

Yogarajan Egamabran (PMU)

iii.

Ismail Sulaiman (PCSB)

iv.

Syed Hairil Hafez (PCSB)

v.

Chin Chun Fatt (SHELL)

vi.

Azman Johari Skymmar (EMEPMI)



vii.

Manjit Singh (TML)

viii.

Sh Hassan Omar (NIPPON)

ix.

Rob Deane (NEWFIELD)

8. Guidelines for Crude Oil Production Allowables i.


ii.

Zaidi Zulkipli (PMU)

iii.

Yogarajan Egambaran (PMU)

iv.

Mohd Irwan Mohd Saari (PMU)

v.

Mohd Anwar Mohd Latif (PMU)

vi.

Azizul Atemin (PMU)

vii.

Albert Terry (MURPHY)

viii.

Mustafa Adenan (PCSB)

ix.

Joseph Liew (SHELL)

x.

Syed Helmi Syed Mohsin (EMEPMI)

xi.

Dave Spence (PETROFAC)

xii.

Kim Hansen (AMERADA HESS)

xiii.

Abdullah Zulkarnain Abu Bakar (TML)

xiv.

Shahril Adha Zamhury (TML)

9. Guidelines for Gas Production and Flaring / Venting Limit i.


ii.


iii.


iv.


v.

Mohd Anwar Mohd Latif (PMU)

vi.

Azizul Atemin (PMU)

vii.

Albert Terry (MURPHY)

viii.

Mustafa Adenan (PCSB) ISSUED BY PETROLEUM MANAGEMENT UNIT


ix.

Joseph Liew (SHELL)

x.

Syed Helmi Sye Mohsin (EMEPMI)

xi.

Dave Spence (PETROFAC)

xii.

Kim Hansen (AMERADA HESS)

xiii.

Abdullah Zulkarnain Abu Bakar (TML)

xiv.

Shahril Adha Zamhury (TML)

10. Guidelines for On-Shore and Off-Shore Operations i.

Bolhi Maskawi (PMU)

ii.

Lionel Tan (PCSB)

iii.

Alan Tan (SHELL)

iv.

Norman Anjek (SHELL)

v.


vi.

Ahmad Ghani (MURPHY)

vii.

Shahril Adha (TML)

viii.

Greg Youd (NEWFIELD)

11. Guidelines for Facilities & Integrity Management i.

Norazman Mohd Isa (PMU)

ii.

Marcella Abdul Karim (PMU)

iii.

Safree Zainudin (SHELL)

iv.

Husni Ishak (EMEPMI)

v.

M Sarifuddin B Othman (PCSB)

vi.

Fadzal Ahmad (MURPHY)

vii.

Ronizain Ismail (TML)

viii.

Azuzani Haslinda Abdul Halim (AMERADA HESS)

ix.

David Balusek (NEWFIELD)

x.

Hisham Ibrahim (PETROFAC) ISSUED BY PETROLEUM MANAGEMENT UNIT


12. Guidelines for Reservoir Management i.

Mariam A Aziz (PMU)

ii.


iii.

Amir Yusof (PMU)

iv.


v.

Azizul Atemin (PMU)

vi.


vii.

Ronny Gunarto (PMU)

viii.


ix.

Tg Ahmad Tarmizi (PMU)

x.

Mohd Izat Ali (PCSB)

xi.

Ooi Kiam Chai (NIPPON)

xii.

Azlan Anuar (NEWFIELD)

xiii.

Patrick Simpson (NEWFIELD)

xiv.

James Lim (SHELL)

xv.

Jeremy Wong (SHELL)

xvi.

Bay Chung Yong (TML)

xvii.

Chua Hwa Tian (TML)

xviii.

Siti Sabrina Sutu (AMERADA HESS)

xix.

Kamarul A. Buang (EMEPMI)

xx.

Henrikus Amperanto (MURPHY)

13. Guidelines for Well Test, Production Measurement & Allocation i.

Zainal Din (PMU)

ii.

Norasmarina Masrom (PMU)

iii.

Zakiah Zakaria (PMU)

iv.

M Kamarulanuar A Kadir (PMU)

v.

Mohd Azri Abdul Aziz (PMU) ISSUED BY PETROLEUM MANAGEMENT UNIT

PETRONAS PROCEDURES AND GUIDELINES FOR UPSTREAM ACTIVITIES vi.


vii.

Raja Sharifuddin Ahmad (PMU)

viii.

Rick Chan (MURPHY)

ix.

Ismi Mohd Nasir (MURPHY)

x.

Syahzad Samad (MURPHY)

xi.

Fadzal Ahmad (MURPHY)

xii.

Shahril Adha (TML)

xiii.

Abdullah Zulkarnain (TML)

xiv.

Azhar Omar (PCSB)

xv.

Mohd Azhar Mazlan (PCSB)

xvi.

D. Vijay Kumar (PCSB)

xvii.

Barry Goodin (NEWFIELD)

xviii.

Jaz Marshall (SHELL)

xix.

Chew Boon Fei (SHELL)

xx.

Nasreen Khalid (EMEPMI)

14. Guidelines for Dynamic Liquid Hydrocarbon Measurement i.

Zainal Din (PMU)

ii.


iii.


iv.


v.

Mohd Azri Abdul Aziz (PMU)

vi.


vii.


viii.

Rick Chan (MURPHY)

ix.


x.


xi.

Fadzal Ahmad (MURPHY)]

xii.

Shahril Adha (TML) ISSUED BY PETROLEUM MANAGEMENT UNIT


xiii.


xiv.

Azhar Omar (PCSB)

xv.


xvi.

D Vijay Kumar (PCSB)

xvii.


xviii.


xix.


xx.


15. Guidelines for Gas Measurement i.

Zainal Din (PMU)

ii.


iii.


iv.


v.

Mohd Azri Abdul Aziz (PMU)

vi.


vii.


viii.

Rick Chan (MURPHY)

ix.


x.


xi.

Fadzal Ahmad (MURPHY)]

xii.

Shahril Adha (TML)

xiii.


xiv.

Azhar Omar (PCSB)

xv.


xvi.

D Vijay Kumar (PCSB)

xvii.




xviii.


xix.


xx.


16. Guidelines for Decommissioning of Upstream Installation i.

M Nasir Yunus (PMU)

ii.

Sameerah M Nawi (PMU)

iii.

M Nazori Janor (PMU)

iv.

Azlan Subari (PMU)

v.


vi.

Emry Hisham Yusoff (PMU)

vii.

M Azrunizam Yaacob (PMU)

viii.

Desline Sinta (SHELL)

ix.

Jerry Siran Langan (SHELL)

x.

Ahmad Mazlan Osman (NEWFIELD)

xi.

Greg Youd (NEWFIELD)

xii.

Akihiko Miyahara (NIPPON OIL)

xiii.

Mohamad Azahar (NIPPON OIL)

xiv.

Muzakir Zainal Abidin (EMEPMI)

xv.

Agustinus Hadi (MURPHY OIL)

xvi.

Tay Kim Chee (MURPHY OIL)

xvii.

A Khalid B Jaafar (PCSB)

xviii.

Azizul Azhar (PCSB)

xix.

Ronizain Ismail (TALISMAN)

xx.

Shahril Adha Zamhuri (TALISMAN)



17. Guidelines for Data Management and Submission i.

Norzilah Jaafar (PMU)

ii.

Azlan Subari (PMU)

iii.

Idrus M Shuhud (PMU)

iv.

Robert Siahaan (PMU)

v.

M Kasim M som (PMU)

vi.

Anthony Yeo (SHELL)

vii.


viii.

Mat Zakir Darus (TML)

ix.

Hassan Mohd Ali (TML)

x.

Wan Aswandi (PETROFAC)

xi.

Chandramoorthy (PCSB)

xii.

Henrikus Amperanto (MURPHY)

xiii.

Mohd Azlan Anuar (NEWFIELD)

xiv.

Kentaro Mochizuki (NIPPON)

xv.

Mokhzani Ariffin (AMERADA HESS)

xvi.

Fadzillah Abdullah (EMEPMI)

xvii.

Clarence Samuel (EMEPMI)

xviii.

Ghazali Noordin (EMEPMI)

xix.

Yap Siew Chee (EMEPMI)

18. Guidelines for Emergency Response and Communication Procedure i.

Rozita Musib (PMU)

ii.

Azlan Subari (PMU)

iii.

Bolhi Maskawi (PMU)

iv.


v.

Rozita Musib (PMU)

vi.

Nur Atikah Abu Bakar (PMU) ISSUED BY PETROLEUM MANAGEMENT UNIT

PETRONAS PROCEDURES AND GUIDELINES FOR UPSTREAM ACTIVITIES vii.

Enteli (PCSB)

viii.


ix.

Andrew Collin (SHELL)

x.

Mahathir Malim (PETROFAC)

xi.

Saabi Wahab (TML)

xii.

Marina Jamil (MURPHY)

19. Guidelines for Operating Performance Improvement i.


ii.

M Ali M Shamsuddin (PMU)

iii.

Danial Khan Abdul Rashid Khan (PMU)

iv.

Rahul Mehrota (GTS)

v.

Wira Yusof (GTS)

vi.

Noor Azlan M Harif (PCSB)

vii.

Syed Helmi (EMEPMI)

viii.

Jonny Labo (SHELL)

ix.

Gerard Liang (NIPPON OIL)

x.

Shahril Adha (TML)

xi.

Ahmad Ghani (MURPHY OIL)


Ppgua Aug 2008 as Rolled Out Feb 2009

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