Petronas drilling operations guideline

© 2013 PETROLIAM NASIONAL BERHAD (PETRONAS)
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DRILLING AND WELL
OPERATIONS
VOLUME 8
PETRONAS Procedures
and Guidelines for Upstream
Activities (PPGUA 3.0)

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

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4.5 Fire Protection 25
4.5.1 Fire Fighting Equipment 25-26
4.5.2 Fire Alarm System 26
4.6 Gas Detection 26
4.7 Pollution Prevention 26
4.8 Helideck on Drilling Units 26-27
4.9 Pressure System 27
4.10 Electrical Installation 27
4.10.1 Equipment and Standards 27
4.10.2 Lighting 28
4.10.3 Emergency Electrical Power Supply 28
4.11 Forced Air System and Ventilation 28
4.11.1 Hazardous System 28
4.11.2 Ventilation 28
4.11.3 Engines and Motors 29
4.11.4 Exhaust Pipes 29
4.12 Weather Data Recording 29
4.13 Diving 29
4.14 Emergency Shutdown 29
4.15 Manning 29
4.16 Support Craft 30
Section 5: Well Design and Drilling Operations 31
5.1 Drilling Unit Moving and Positioning 31
5.1.1 General Provision 31
5.1.2 Anchor Testing for Drilling Unit 31
5.1.3 Bottom Supported Unit 31-32
5.1.4 Dynamically Positioned Units 32
5.1.5 Diving Operations 32
5.2 Casing and Cementing 32
5.2.1 Drive Pipe 33
5.2.2 Conductor Casing 33-34
5.2.3 Surface Casing 34
5.2.4 Intermediate Casing 34
5.2.5 Production Casing 34-35
5.2.6 Casing Pressure Test 35-36
5.2.7 Records 36
5.2.8 Cementation 36-37

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

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

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

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

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

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

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Executive Summary
This volume provides procedures for conducting offshore and onshore well
drilling, completion, testing, workover, intervention and servicing activities in
Malaysia. 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 Contract. In adding to or amending the
procedures, PETRONAS shall consider the incremental expenditures which may be
incurred by Contractor in complying with the amended procedures.
This document provides auditable procedures for planning, preparation and
execution phases including well design, operations, equipment specification and
requirements for inspections, testing and audits including High Pressure High
Temperature (HPHT) well design soundness verification and deepwater well
contingency plan. Contractor may request exception or exemption to these
procedures and exception or exemption may be granted when PETRONAS and
Contractor agree that prudent practice is served and Health, Safety and
Environment (HSE) risk arising from the exception or exemption remain As Low As
Reasonably Practicable (ALARP).
PETRONAS shall have the right to be actively involved in all phases of Contractor’s
well drilling, completion, testing, workover, intervention and servicing activities
planning, preparation and execution.
Contact Information
All correspondence related to this volume shall be addressed to:
General Manager
Drilling
Petroleum Operations Management
Petroleum Management Unit

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Definitions
In this procedure, terms and expressions not specifically defined below shall have
the sense and meaning commonly attributed to them in the oil and gas exploration
and production industry unless the context requires otherwise:
TERM DEFINITION
Autoshear System A safety system that is designed to automatically
shut-in the wellbore in the event of a disconnect of the
Lower Marine Riser Package (LMRP). When the autoshear is
armed, a disconnect of the LMRP closes the shear rams.
Coiled-Tubing Operations Operations using spooled non-jointed pipe through the
wellhead and well tubing.
Conductor Casing The second casing string set in the order of normal
installation based on the relevant engineering and/or
geological factors (including the presence or absence of
hydrocarbons, potential hazards and water depth). The
Conductor Casing may also be first casing string set in lieu
of Drive Pipe or Structural Casing to support unconsolidated
deposits and to provide hole stability for initial drilling operations.
Deadman System A safety system that when armed is designed to automatically
close the wellbore in the event of a simultaneous absence of
hydraulic supply and signal transmission capacity in both subsea
control pods.
Deepwater Generally described as water depth beyond 300 metres.
Diverter A device for the purpose of diverting the uncontrolled flow
of fluid from the well bore.
Drill Stem Test A test that is performed by allowing formation fluids to
flow to the surface through the drill pipe or test string. It
is normally used for determination of well productivity.
Drilling Programme The programme for the drilling of one specific well.
Drilling Sequence A programme for the drilling of one or more wells as
presented in the annual Work Programme & Budget (WPB) and
its subsequent revisions.
Drilling Unit A drill ship, submersible, semi-submersible, barge, jack-up, land
rig or other vessels used in a drilling programme and includes
a drilling rig and other related facilities installed on a vessel.

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TERM DEFINITION
Drive pipe or Structural
Casing
The first casing string set in the order of normal installation
by driving, jetting or drilling to a competent bed as means to
provide support to unconsolidated deposits and to provide
hole stability for initial drilling operation.
Emergency Disconnect
System (EDS)
A system that when activated initiates a pre-programmed
sequence of well securing Blowout Preventer (BOP) functions in
a minimum amount of time prior to disconnection of the LMRP.
External Hazard Environmental conditions occurring on the drilling unit or
drilling base which threaten the safety of the operation.
High Pressure High
Temperature (HPHT)
A well generally described as having an undisturbed
Bottom Hole Temperature (BHT) greater than 300°F (149°C) and
maximum pore pressure exceeding 0.8 psi/ft or requiring
pressure control equipment with a rated working pressure in
excess of 10,000 psi.
Intermediate Casing 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 or any other previous intermediate casing shoe and
anticipated formation pressure of the hole section to be drilled.
Kick Influx of wellbore fluid into the wellbore and possible loss
of primary control of the well which shall be controlled by
secondary control (BOP).
Liner A string of casing installed inside a casing string or
another liner and lapped back inside the previous casing or liner
for at least 30 metres. A liner may be used as a drilling liner
or production liner. A liner may also be tied back to surface if
required in which it will be regarded as a production string.
Lubricator Assembly A setup consisting of wireline BOP, a riser assembly with a bleed
valve and a wireline pack off.
Non-FDP wells Wells that are not included in the original approved Field
Development Plan (FDP) and require additional approval from
PETRONAS. A minimum of fourtteen (14) days notice shall
be given prior to spudding the well.
Offshore Well A well drilled from offshore drilling unit.

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TERM DEFINITION
Oil Spill Any unexpected loss of crude oil, condensate or hydrocarbon
containment that reaches the environment, for example,
water or land irrespective of quantity recovered.
Open Hole A well bore or portion of a wellbore that is not protected by
casing.
Production Casing A string of casing which is set for the purpose of completing the
well for production.
Shooting Nipple Assembly Wireline packoff and a riser assembly held in place by BOP.
Small-Tubing Operations Operations using jointed pipes through the wellhead and well
tubing.
Snubbing Operations Operations using jointed tubing or drill pipe and a snubbing unit
under pressure conditions, either through the wellhead valve
assembly and well tubing of a completed well or through the
BOP and wellbore of a conventional operation.
Spud The initial penetration of the ground or sea floor for the purpose
of drilling a well.
Stripping Operations Operations that require manipulation of the drill string or work
string through BOP, under low or moderate pressure, without
the use of a snubbing unit.
Surface Casing The casing string set after the Conductor Casing in the order
of normal installation in a competent bed based upon relevant
engineering and/or geological factors, including the presence
or absence of hydrocarbons, potential hazards, and water
depths. The Surface Casing shall be set in order for the next hole
section to be drilled with BOP.
Waste Material Refuse, non-biodegradable garbage or any other useless
material generated during drilling and related operations
excluding fluid and drill cuttings.
Well Intervention
Operations
Remedial operations performed with the christmas tree not
removed.
Well Material Any formation or reservoir material obtained from a well and
includes cuttings, cores or fluids.
Well Suspension The temporary cessation of drilling/completion activities
(waiting for final completion or abandonment).
Workover Operations Remedial operations performed with the christmas tree
removed and BOP installed.

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Official Correspondence
Refer to Appendix 1 of this volume.
Company Press Release
Contractor shall obtain prior written approval from PETRONAS for all press
releases issued regarding wells drilled under these procedures.

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Section 1: Drilling Programme Approval
Notice of Operations (NOOP) shall be prepared by Contractor and submitted to
PETRONAS for approval or notification (whichever is appropriate) in a timely
manner. Significant deviations to the NOOP programme with prior PETRONAS’
approval and Management of Change (MOC) process shall be managed by
Contractor with considerations on impact to health, safety, environment, project/
well costs and PETRONAS/Contractor image. Contractor is responsible to avoid
retroactive approval request by ensuring timely submission of all request to
PETRONAS.
1.1 Notification
Contractor shall notify PETRONAS in the Work Programme & Budget (WPB)
and subsequent revisions of its intention to undertake any particular
Drilling Campaign.
1.2 Wellsite Survey and Shallow Hazard Report
Contractor shall conduct high-resolution geophysical site surveys to
determine the existence of shallow gas, near-surface faulting, slumping,
unusual bottom features, and other potential shallow hazards prior to the
commencement of drilling operations. Remote sensing tools normally
utilised in conducting such surveys shall include side-scan sonar,
sea-bottom profiler and other shallow seismic instrument. Survey line
spacing shall be a maximum of 250 metres apart in a 1-square-kilometre
area centred on the wellsite. If in the opinion of the Contractor, surveys exist
for a location nearby to the proposed location which may be taken as
representative of the new location, or if extensive experience in a local
area has shown that such surveys are not required, then additional surveys
may not be required subject to PETRONAS’ approval. As and when
requested such geophysical site surveys and shallow hazards reports shall be
submitted to PETRONAS.
For deepwater operations, hazards such as shallow gas, shallow water flow,
hydrates and expulsion features should be evaluated. 3D seismic or other
imaging methods may be used in lieu of conventional shallow seismic, as
appropriate.
1.3 Well Positioning
1.3.1 Pre-survey Preparation
Contractor shall notify PETRONAS of a proposed well location prior
to any positioning work.

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1.3.2 Positioning Operations
Contractor shall ensure the safety of pipelines and cables underlying
subsea and perform pre-spud and final post-spud verifications.
1.3.3 Post-positioning Works
Contractor shall submit to PETRONAS a full operation report when
available. The report shall be in hard copy or acceptable electronic
format.
1.4 Notice of Operations (NOOP)
The NOOP for all wells shall be submitted at least forteen (14) days prior
to spud date in hard copy and acceptable electronic format. Field
Development Plan (FDP) wells’ NOOP shall be submitted for information.
All other wells’ NOOP shall be submitted for approval. The NOOP shall
contain but not limited to the following information:

a) Objectives of the well;
b) Location map;
c) Prognosis cross-section;
d) Depth of well and proposed completion target (in True Vertical Depth
(TVD) and Measured Depth (MD));
e) Directional drilling plan including anti-collision plan;
f ) Casing programme and casing design criteria;
g) Mud and cement plan;
h) Bit selection and hydraulic programme (for each hole size);
i ) Well logging, coring and other formation evaluation programme;
j ) Estimated formation pressure and fracture gradient;
k) Anticipated problems and drilling hazards;
l ) Authorisation for Expenditure (AFE) breakdown;
m) Estimated depth vs days and depth vs cost chart;
n) Name and type of drilling unit;
o) Contingency plan for operational problems. A Blowout Contingency
Plan (BOCP) shall be provided in accordance with Section 13.3 for
deepwater and HPHT wells;
p) Propose full Plug & Abandonment (P&A) with drawing for exploration,
appraisal and suspended wells;
q) Well schedule;
r ) Completion diagram (for development wells);
s ) BOP configuration diagram; and
t ) Negative or inflow test procedures and criteria for a successful test, if
applicable (refer to Section 5.2.6).
Pre-spud meeting and/or drill on paper should be conducted. During the

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execution phase, if Contractor anticipates that there will be a potential cost
overrun of 10% from the approved well cost or Non-Productive Time (NPT)
more than fifty (50) consecutive hours, Contractor shall give written notice to
PETRONAS. In addition, if the above well has been completed, Contractor
shall submit and present the case to PETRONAS.
1.5 Variations
Contractor may implement variations or deviation to the approved NOOP as
deemed operationally necessary or desirable to achieve the agreed
objectives of the well in an efficient and safe manner, however prior
PETRONAS’ approval is required for significant deviations. The request for
approval submission shall include risk assessment and/or MOC documents.
Significant deviation refers to any changes that increase health, safety,
environmental or financial risk and/or well cost.

PETRONAS may require Contractor to show that specific equipment or
procedures are consistent with the interests of safe and efficient operations.
Contractor shall modify or replace any equipment or alter any procedure
that cannot be shown to be safe. Contractor shall install new equipment or
initiate new procedures if necessary to conduct safe operations.

Notwithstanding the above, during an emergency or contingency,
procedures or equipment may be altered without prior PETRONAS’ approval
and in such cases, PETRONAS shall be notified forthwith of the alterations
and the underlying circumstances within 24 hours.

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Section 2: Recording and Reporting
Drilling and well operations carried out by Contractor in Malaysia shall be
reported to PETRONAS and relevant authorities for approval and information within
the stated timeline. The reporting and report contents requirement shall adhere to
the procedures in this section. Contractor shall also record all the important
information pertaining to the operation and this information shall be made
available to PETRONAS as and when requested.

2.1 Priority Reporting
Contractor shall inform PETRONAS immediately by the most rapid and
practical means of every significant situation, event or accident, including
but not limited to the loss of life, missing persons, serious injury, fire, loss of
well control, imminent threat to safety of drilling unit, drilling rig or
personnel, oil or toxic chemical spill, or the confirmed discovery of oil and
gas.

Contractor shall submit to PETRONAS, as soon as practicable, a
comprehensive written report of the situation, event or accident, and shall
notify relevant authorities as circumstances require. Refer to Volume 3:
Health, Safety & Environment.
2.2 Rig Arrival and Release Notice
Contractor shall inform PETRONAS within 24 hours by fax, e-mail or
equivalent means:

a) Of the date that the drilling unit arrives at the drilling location; and
b) Of the actual hour and date that the drilling rig or drilling unit is released
from the drilling location
Contractor shall also notify related government departments i.e. marine
department, port authorities, fisheries department, maritime enforcement
agency and customs department at least two (2) months prior to rig arrival
and rig departure.
2.3 Daily Drilling Report
Contractor shall submit the Daily Drilling Report (DDR) to PETRONAS
containing but not limited to the following information:

a) Well name or number;
b) Rig name and type;
c) Plan Total Depth (TD) in MD and TVD (metre);
d) Current depth;

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e) Plan cost (USD or RM);
f ) Current cost (daily and cumulative);
g) Plan and actual days;
h) Days ahead/behind;
i ) The operations for last 24 hours;
j ) NPT description and duration (daily and cumulative NPT);
k) Set casing/liner size, properties and set depth;
l ) Wellbore/directional survey for last 24 hours progress;
m) Drilling fluid properties;
n) Bottom-Hole Assembly (BHA) and drilling bit description;
o) Number of Personnel on Board (POB); and
p) HSE incidents
2.4 Final Drilling and Completion Report
Contractor shall submit to PETRONAS a Final Drilling and Completion Report
and electronic copy/soft copy on CD within sixty (60) days after a well has
been drilled and completed, suspended or abandoned. PETRONAS may also
request additional information when the need arises.

The report shall include, but not limited to the following information:

a) Well number and type;
b) Rig name and type;
c) Surface and sub-surface location grid and geographical coordinates of
the well;
d) Well depth (MD and TVD);
e) Maximum angle reached;
f ) Total days spent on the well;
g) Summary of drilling operations;
h) Basic reservoir/geological details;
i ) Final wellbore sketch or completion diagram showing all downhole
components (with their I.D., O.D., length, depth of installation) and
description of wellhead and christmas tree;
j ) Type and density of fluid left in the hole;
k) Perforated intervals;
l ) Initial production test results including registered pressure, fluid/gas flow
rates and duration of test;
m) List of wireline logs and its interpretation (cored intervals should also be
shown);
n) Casing size, type, grades, weights, depth set in MD and TVD;
o) Mud composition, amount used and average per well oil-on-cuttings
(OOC) percentage for drilling with Low Toxicity Oil Based Mud (LTOBM)
or Synthetic Based Mud (SBM);

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p) Cement density, composition, volume of cement used and their
estimated top in annulus;
q) Depth-days chart, actual cost vs proposed;
r ) Operational-time breakdown;
s ) Summary of HSE incident and scheduled waste;
t ) Summary of NPT;
u) Directional drilling results and wellbore trajectory; and
v ) Final estimated well cost
2.5 Supporting Reports
Reports obtained or compiled by the Contractor regarding applied research
work or studies, that contain information which is relevant to the safety of
drilling operations in the programme area, shall be submitted to PETRONAS
as soon as they are available. PETRONAS may request any additional
information with regards to drilling operation at any time and Contractor
shall submit the information to PETRONAS within agreed timeline.

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Section 3: Drilling Quality Assurance/Quality Control
Contractor shall have quality plans and procedures in place to ensure all drilling
and completion services and goods provided are in accordance with contractual
requirements (between Contractor and third party contractors) and able to perform
as per the stated performance.
3.1 Quality Plan
Contractor shall prepare a Quality Plan which as a minimum outline the
following:
a) Categorising of services and goods based on its criticality considering
the potential impact to health, safety, environment, well integrity, and
project cost should an incident occur;
b) Planned process controls to ensure quality is integrated from well
planning to execution;
c) Capture a process for managing non-conformance from actual event in
the workshop or field to closure;
d) Methods utilised to measure quality performance and improvement
process; and
e) Plans for periodic third party contractor assessments to ensure quality
requirements are maintained and followed
3.2 Quality Requirements
Contractor shall document all quality requirements in contract documents
and/or purchase orders executed with drilling rig and third party contractors:
a) All drilling and completion equipment shall be delivered in accordance
with the relevant industry standard(s) such as American Petroleum
Institute (API) and International Organization for Standardization (ISO);
and
b) Drill strings shall be inspected in accordance to the latest version of TH
Hill Standard DS-1 or equivalent inspection standard as applicable
3.3 Quality Implementation and Continuous Improvement
All parties involved in well drilling and completion shall be responsible for
ensuring quality from planning to execution. Contractor shall have qualified
personnel responsible to ensure equipment and goods are inspected per the
quality requirements. Processes to manage changes or deviations to
Contractor’s Quality Assurance/Quality Control (QA/QC) requirements shall
be in place.

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

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Section 4: Drilling Unit Design, Manning and Logistics
Drilling units, support craft, base office and warehouses used by Contractor
shall be ready with adequate fit-for-purpose equipment, detailed procedures,
competentpersonnelandsupportservicestoensureoperationobjectivesaremetand
carried out with adherence to HSE concerns and regulations. As and when
requested by PETRONAS, copies of approval or certificates from recognised body
shall be submitted to demonstrate equipment reliability and operation safety.
4.1 Drilling Unit Design
Contractor shall submit upon the request of PETRONAS, copies of valid
approvals or certificates from a recognised certification body to demonstrate
that the proposed drilling programme can be safely executed by the drilling
unit with a view to stability, operating limits, structural strength, fatigue, etc.,
during the course of all anticipated combinations of environmental and
functional loads.
In the event that weather forecasts indicate conditions during which normal
drilling operations could not continue, Contractor shall take necessary
actions to interrupt drilling operations in time, so that the safety of the well
and drilling unit shall not be jeopardised.

4.1.1 Drilling Unit Inspection
After obtaining PETRONAS’ approval to award, Contractor shall be
responsible for conducting full drilling unit inspection by an industry
recognised third party at an opportune time prior to contract award.
The aim of this inspection is to gain accurate assessment of the state
of maintenance and working conditions of the equipment and
systems on the drilling unit in accordance with the drilling unit’s
contractual requirements. The objectives are to limit downtime and
improve reliability and safety. All critical actions from the inspection
shall be duly closed out prior to spudding of the first well. The
inspection report shall be made available upon request by
PETRONAS.
4.1.2 General Arrangement Drawings
Upon request by PETRONAS, Contractor shall submit dimensional
layouts and drawings of the drilling rig and camp. Upon request by
PETRONAS, Contractor shall submit general arrangement drawings
for all surface and subsea equipment on the drilling unit which shall
include:
a) arrangements of drill floor, cellar deck, spider deck, moonpool

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areas and their associated equipment;
b) arrangements of mud tanks, high and low pressure mud and
cement slurry systems and bulk transfer system;
c) arrangement of all surface and subsea well control systems
including arrangement of choke manifold, testing and flaring
systems;
d) arrangement of other pressure systems; and
e) position and type of all life-saving appliances, fire extinguishing
and protection systems, fire stations and appliances,
navigational safety appliances and alarm systems
4.2 Blowout Preventer Equipment
Appropriate well control equipment shall be installed, maintained and tested
to ensure well control in the course of normal safety drilling. The working
pressure of such equipment shall exceed the maximum anticipated surface
pressure to which it may be subjected to.
4.3 Protection Against External Hazards
Contractor shall take precautions necessary to protect personnel and
equipment from the external hazards of air and marine navigation and
weather.
A red aircraft warning light of at least fifty (50) candelas shall be mounted
at the top of the derrick so as to be visible from all directions.
Drilling units and support craft shall have navigational safety and marine aids
which shall meet as a minimum, the requirements of the classification
bureau; and for aircraft, the civil aviation regulatory authority.
Drilling units shall have emergency equipment and life-saving devices
sufficient to permit the escape of all personnel under all conditions which
shall meet as a minimum, the requirements of the classification bureau.
4.4 Personnel Safety and Welfare

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

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4.4.2 Derrick Escape
When a person is required to work in the derrick as part of normal
drilling operations, an escape device acceptable by general industry
practices shall be provided from the working platform in the derrick.
Persons required to work on the derrick or at a height of 2 metres or
higher, shall wear safety belts complete with tail rope having
adequate length and strength. Contractor shall ensure that such
safety belts are provided at all times on the derrick.
4.4.3 Rotary Tongs
All make-up and breakout rotary tongs shall have suitable back-up
lines made from flexible wire rope and tied down to a post having the
rigidity to withstand maximum tong line pull.
4.4.4 Medical Facilities and Provisions
An adequately equipped and supplied first aid room shall be provided
at the rig site. A drilling unit shall have a sick bay which is easily
accessible and is equipped and supplied to handle all minor indus
trial accidents. The facilities in the sick bay shall include first aid and
resuscitation equipment and shall have at least one (1) bed for every
fiffty (50) persons or portion thereof. Detailed requirements are
as per Volume 7, Section 8: PETRONAS Guidelines for Barges
Operating Offshore Malaysia (PGBOOM).
4.5 Fire Protection
Firefighting equipment and alarm shall be provided and maintained at every
drill site to combat all classes of fires.

4.5.1 Fire Fighting Equipment
Each drilling unit shall:

a) Have appliances whereby at least two (2) jets of water, each of
53 gal/min at a minimum pressure of 40 psi can be rapidly and
simultaneously directed into any part of the unit’s substructure
at least one (1) of which shall be from a single length of hose;
such appliances shall include at least two (3) power driven pumps
located separately and at least three (3) fire hoses; in any case
at least one fire hose shall be provided for every 30 metres in
length of the unit or fraction thereof.

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b) Have readily accessible:
• at least two (2) proximity firefighting suits;
• four (4) self-contained portable breathing devices; and
• a suitable water supply source of sufficient capacity to
assure adequate water supply
Notwithstanding the above, PETRONAS may require additional
firefighting equipment to be installed if such equipment is considered
necessary.
4.5.2 Fire Alarm System
A drilling unit shall be equipped with a fire alarm system that includes
detectors located:

a) in engine rooms;
b) in the boiler rooms;
c) in paint lockers;
d) in pump and mud tank rooms; and
e) in the accommodation
and which is capable of automatically sounding an alarm and
indicating on a panel the location of the fire.

4.6 Gas Detection
A drilling unit shall be equipped with gas detection systems to monitor
continuously at locations where there may be an accumulation of
combustible vapours or gas.

4.7 Pollution Prevention
The drilling unit shall be adequately equipped with facilities to prevent,
reduce and control pollution of the surrounding environment in accordance
and in compliance with the regulations as stipulated in the applicable
Malaysian laws. All decks and/or equipment shall be equipped with curbs,
gutters, drip pans and drains which shall be installed, where possible, to
collect all discharge and piped to a collecting tank or sump, with safeguards
for overflow, to be disposed in accordance with the applicable Malaysian
Laws.

4.8 Helideck on Drilling Units
If the drilling unit is equipped or required to have a helicopter deck, it shall
be:

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a) of adequate size and structural strength to accommodate the sizes and
types of helicopters to be used;
b) located so as to provide an approach/departure sector of at least 180
degrees or higher free of obstruction;
c) equipped with operable lights commonly used on heliports;
d) equipped with a non-skid deck surface and safety nets around the
perimeter;
e) provided with access gangways;
f ) provided with a coaming which shall contain any fuel spill from a leak in
the helicopter fuel tanks if such tanks are installed above decks and with
a drainage system which shall conduct such a spill away from the drilling
unit; and
g) equipped with a helicopter crash box located at the access to the
helicopter deck
4.9 Pressure System
Steam systems, pressure vessels, hot water boilers and steam generators
shall be designed, constructed and inspected in accordance and in
compliance with widely recognised industry codes.
4.10 Electrical Installation

4.10.1 Equipment and Standards
Electrical equipment on drilling unit shall conform at least to API RP
500B ‘Recommended Practice for Classification of Areas for
Electrical Installations at Drilling Rigs and Production Facilities on
Land and on Marine Fixed and Mobile Platforms’.

All electrical systems so designed and installed shall be grounded and
shall be able to operate safely under hazardous conditions that may
occur in the vicinity of the equipment.

Electrical equipment on a drilling unit which is installed in drilling
areas defined as Division I and Division II containing atmosphere
listed under Class I, Group D, classification of the API RP 500B shall
be explosion proof.

An emergency shutdown switch, capable of shutting down all
electrical equipment and power plants shall be provided at a
minimum of two (2) control stations on the drilling unit.

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4.10.2 Lighting
Adequate lighting shall be provided in all working areas inside and
outside of the drilling rig and emergency lighting shall be provided
for the proper illumination of vital areas such as control stations, well
control equipment, stairways, exits, machinery areas, emergency
generator area; and in the case of an offshore drilling unit; boat
stations, passage ways and navigation control area.

4.10.3 Emergency Electrical Power Supply
An independent emergency electrical power supply system capable
of supplying sufficient power in the event of failure in the primary
power supply shall be available to the drilling rig:

a) to secure well; and
b) for the operation of warning, lighting (in areas identified in
Section 4.10.2), alarm, communication and fire extinguishing
systems
A drilling unit shall be equipped with an independent emergency
electrical power supply system consisting of:
a) a prime mover and generator complete with a fuel supply for a
minimum of 24 hours and capable of supplying sufficient power
for navigation lighting and warning systems; emergency lighting
in areas identified in Section 4.10.2; alarm and communication
systems; pumps that are essential for maintaining the trim of the
vessel; abandonment systems when dependent on electrical
power; and fire extinguishing systems; and
b) storage batteries capable of supplying sufficient power to
operate for 3 hours the communication system, the navigation
and obstruction lights, aircraft warning lights and emergency
lighting in areas identified in Section 4.10.2
4.11 Forced Air System and Ventilation

4.11.1 Hazardous System
The hazardous areas on the drilling unit shall be in accordance with
API RP 500B.
4.11.2 Ventilation
Enclosed areas in the vicinity of the BOP stack and mud tanks and all
enclosed working and living areas on the drilling base or drilling unit
shall be properly ventilated and pressurized.

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4.11.3 Engines and Motors
Engines, generators and motors located within any area as
designated in Section 4.11.1 shall have their air intakes located in a
non-hazardous area or the intakes shall be equipped with device to
automatically or manually shutdown the diesel engine in the event of
run away.

All fans and blowers located inside rooms containing engines,
boilers, mud pumps or mud tanks and all fans used for ventilating
such rooms shall be equipped with remote shut-off switches. Air
intakes and exhausts for machinery spaces shall be capable of being
closed.

4.11.4 Exhaust Pipes
Exhaust pipes from internal combustion engines and gas turbine
plants shall be provided with proper flame and/or spark arrestors and
shall be equipped with water cooled exhaust manifold or be insulated
to prevent ignition of combustible gases and be safely vented to the
atmosphere in a non-hazardous area.
4.12 Weather Data Recording
If a Master Weather Station is not available to support any drilling operations,
the drilling location shall have facilities, equipment or knowledgeable
personnel to observe, measure and record the weather and sea conditions
within the accuracy of the available equipment or observation techniques.
4.13 Diving
An offshore drilling unit if required shall be equipped with diving apparatus
suitable for the working depths, whenever it is anticipated that the drilling
operations shall require assistance by divers based on the rig and in
accordance with Volume 3: Health, Safety & Environment.
4.14 Emergency Shutdown
Two Emergency Shutdown (ESD) control stations are required as a minimum.
One (1) shall be located at the drillers console and another at a readily
accessible safe location during all well operations. Units without drillers
console shall have readily accessible ESD stations.
4.15 Manning
Contractor shall require that a crew of sufficient number as determined by
general industry manning levels and with adequate training is available for
the operation of all equipment prior to activation of that equipment and that
all crew members have or are receiving training relevant to their duties.

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

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Section 5: Well Design and Drilling Operations
Wells shall be designed to ensure the well and/or development objectives are met;
safely and cost effectively. Casing, primary cementing and drilling fluid programmes
shall be engineered to withstand anticipated stresses and should compensate
prediction uncertainties. Drilling operations shall be carried out to ensure the
well objectives are met with As Low As Reasonably Practicable (ALARP) risk and
project/well costs containment. Contractor shall ensure that good oil field drilling
practices and continuous improvement are implemented in well design/planning
and throughout the drilling operations. Process shall be in place to manage
deviations or changes with adequate review, risk assessment and Contractor’s
authority’s approval. All wells drilled under the provisions of these procedures
shall have been included in the original WPB or its subsequent revision.
5.1 Drilling Unit Moving and Positioning

5.1.1 General Provision
A drilling unit shall not be moved to a different well location and
anchors shall not be set or retrieved, if weather or sea conditions are
such as to threaten the safety of operations or personnel. Drill
pipe, drill collars, marine risers and other equipment stored on deck,
which may shift during a move, shall be securely tied down before
commencing the move. Anchor buoy and pennant lines shall be
securely fastened to the bulwark or deck railings.
5.1.2 Anchor Testing for Drilling Unit
When anchors are used for holding the unit on position at the
wellsite, the anchor lines and anchors shall be tested to the
maximum anticipated tension prior to drilling first hole section
requiring installation of BOP. If this tension cannot be obtained,
Contractor shall take the necessary remedial action. Mooring system
analysis, design and evaluation shall be in accordance in accordance
to API RP 2SK.
5.1.3 Bottom Supported Unit
In areas of known scouring due to bottom current or tide actions and
where the drilling unit is bottom-supported, the mat, the legs,
faulting, hull or piles, surrounding sea floor shall be inspected
regularly. If scour or fill of sea floor sediments or any other condition,
likely to threaten the stability of the drilling unit, is evident, measures
shall be taken without delay to protect the safety of the unit and the
personnel on board.

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When the drilling unit is bottom-supported, the unit shall not be
raised or lowered, if weather or sea conditions exceed those allowed
in the drilling unit’s Marine Operations Manual to prevent undue risk
to the safety of the personnel, operations and drilling unit.
5.1.4 Dynamically Positioned Units
A dynamically positioned unit (DP) means a drilling unit or a vessel
which automatically maintains its position and heading by means
of thruster force. Units and vessels using DP system shall adhere to
the latest International Maritime Organization (IMO) and International
Marine Contractors Association (IMCA) guidelines on operational
requirements, surveys and testing. IMO Equipment class shall be fit
for purpose to the operations requirement and risk. IMO Equipment
Class 2 and Class 3 or equivalent classification societies class
notations DP units and/or vessels with redundancy system based
on Failure Mode and Effect Analysis (FMEA) study and proving trials
shall undergo annual DP trials by recognised classification societies
to ensure safety and reliability of DP systems. Key DP personnel
training, competence and experience requirements shall adhere to
the latest IMCA M117 guideline. Trial reports and key DP personnel
qualifications and experience records shall be made available upon
request by PETRONAS.
5.1.5 Diving Operations
Diving operations shall be undertaken only when in the opinion of
the diving supervisor, sea and weather conditions permit these
operations to be conducted safely and while they are being
conducted, no other operations which may adversely affect the
safety of the operations shall be conducted.

Diving equipment shall be properly maintained and checked at the
surface before commencing any diving operations and each diver
shall maintain a personal log book detailing his dives and medical
history.
5.2 Casing and Cementing
For the purpose of this procedure, the casing strings in order of normal
installation are: drive pipe or structural casing, conductor, surface casing,
intermediate casing and production casing.
All casings shall be manufactured in compliance with API or ISO quality
standards. Casing programme shall be designed to withstand anticipated
stresses and should compensate for any prediction uncertainties.

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5.2.1 Drive Pipe
This casing shall be set in a competent bed, with the objective of
supporting unconsolidated formation and obtaining drilling fluid
returns to surface. Normally driven to refusal or set at depth
sufficient for its objective.
However, the presence of abnormally strong formations may permit
the setting of this casing at a depth shallower than theoretically
required.

If this portion of the hole is drilled, it shall be cemented with a
quantity of cement sufficient to fill the calculated annular space back
to the sea floor (or surface for onshore).
5.2.2 Conductor Casing
The initial conductor casing string shall be set in a competent
formation (normally between 150 metres and 300 metres TVD
below the sea floor (or surface for onshore)) and shall be based upon
relevant engineering and geologic factors including the presence or
absence of shallow gas, potential hazards and water depth. In cases
where the conductor casing is set deeper than 300 metres below sea
floor (or surface for onshore) and BOP pressure control is considered
while drilling below the conductor casing shoe, a formation pressure
integrity test shall be performed as required under Section 5.6.

Unless jetted-in, the initial casing string shall be cemented with a
quantity of cement sufficient to fill the calculated annular space back
to the sea floor (or surface for onshore). The excess volume shall be
as specified in Section 5.2.9 or based on field experience. The
cement may be washed out to a depth not exceeding the depth of
the structural casing shoe to facilitate casing removal upon well
abandonment.

Conductor casing may be eliminated at specific well locations if at
least one (1) well has been drilled adjacent to the specified well
location and well logs and mud monitoring procedures demonstrate
the absence of shallow hydrocarbons or hazards. If shallow
hydrocarbons are present and Contractor can exhibit that the well
can be safely drilled without a conductor casing being set, then
the conductor casing may be eliminated with prior approval from
PETRONAS.

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For deepwater operations, conductor casing may be eliminated if
geological factors, shallow hazards, and well structural integrity are
maintained.
5.2.3 Surface Casing
Surface casing setting depths shall be based upon relevant
engineering and geologic factors, potential hazard, presence and
absence of shallow gas (normally between 450 metres TVD and 1400
metres TVD below the sea floor (or surface for onshore)). Surface
casing may be set at a depth where the formation strength is
sufficient to support the programmed mud gradients for the next
section of the hole and where the well control integrity can be
provided until the next string of casing is set.

Surface casing shall be cemented to surface or sea floor for
subsea wells. After drilling out the surface casing shoe, a formation
pressure Integrity test shall be performed as required under Section
5.6.
5.2.4 Intermediate Casing
One or more strings of intermediate casing shall be set when
required by anticipated pressures, mud weight, sediment, and other
well conditions. The proposed setting depth for intermediate casing
shall be based on the formation strength below the surface casing
shoe or previous intermediate casing string.

Intermediate casing shall be cemented with a calculated volume of
cement sufficient to fill the annular space in the open hole to 150
metres above the highest hydrocarbon or freshwater bearing sand, or
one-third of intermediate casing length, whichever is greater.

If the intermediate casing is a liner, a minimum liner lap of 30 metres
above the previous casing string shoe shall be applied. The liner lap
shall be cemented and tested to determine whether a seal between
the liner top and the next larger string has been achieved.

For subsea wells, the top of cement may be kept below the surface
casing shoe to prevent annular pressure build-up from causing
failure to the surface or intermediate casing strings.
5.2.5 Production Casing
This string shall be set before completing the well for production.

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A calculated volume of cement sufficient to fill the annular space at
least 150 metres above the uppermost hydrocarbon zone or
one-third of production casing length, whichever is greater, shall be
used. When a liner is used as production string, it shall be lapped a
minimum of 30 metres into the previous casing string, and the seal
between the liner top and the next larger string shall be tested.
5.2.6 Casing Pressure Test
After cementing, all casing strings shall be tested to verify integrity to
withstand anticipated operating loads. As a minimum, the test
pressure shall be as the following:

Cemented Conductor - 200 psi
Surface - 1000 psi
Intermediate and Production - 0.73 psi/m TVD or 1500 psi
whichever is greater

Intermediate and Production liner (and liner-lap) shall be tested to a
minimum of 500 psi above the formation fracture pressure at the
casing shoe into which the liner is lapped, where permissible.

However, the test pressure should not exceed 85% of the internal
yield pressure of the casing. The casing shall be pressure tested for
15 minutes, and if the pressure declines more than 10%, remedial
action shall be performed prior to drilling ahead, unless prior
approval is obtained from PETRONAS.

Note: Conductor casing pressure test is waived for deepwater
operations

After cementing any casing string, pressure testing of the casing can
be conducted either upon bumping of the plug or after sufficient
waiting time has lapsed based on cement laboratory test data.
Avoidance of micro-annulus between cement and casing shall be
considered.

In case of back flow at the end of cementing operations, back
pressure shall be applied until cement has set.

Laboratory test data for the particular cement mix used in the well
shall be used to determine the setting time required. Before drilling
out of the casing shoe, sufficient time shall have elapsed to allow tail
slurry to attain a compressive strength of at least 500 psi.

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

5.2.7 Records
The result of all casing pressure tests shall be witnessed by
Contractor’s representative and recorded on the Driller’s log. This
data shall be made available upon request by PETRONAS.
5.2.8 Cementation
Cement and materials for well cementing shall conform to latest API
Specification 10A. Well cement test shall conform to API RP10B-2/
ISO 10426-2 and deepwater well cement test shall conform to API
RP 10B-3/ISO 10426-3.

The cementation of surface casing, intermediate casing, production
casing and liner shall be performed by conventional displacement
method. In addition to cement slurry, preflush and spacer design,
pipe centralisation to achieve optimum standoff and pipe movement
shall be considered to improve drilling fluid removal and cement
placement quality. A cement placement, centralizer placement,
Equivalent Circulating Density (ECD), fluid displacement and
applicable stress-analysis engineering software simulation shall be
performed to support cementing design. Cementation design
reports, post-job data and cement bond evaluation log result if any
for all individual casing primary cementing operations shall be
submitted to PETRONAS upon request.

Other industry acceptable methods may be used such as inner string
cementing or simply cementing without the use of wiper plugs where
deemed appropriate without compromising primary cementation
quality.
Cementing float equipment or other means of preventing backflow

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(U-tubing) of cement during cementing shall be incorporated into a
casing string with thread locking compound. For conventional
displacement method, a float collar shall be inserted in the casing
string above one or two joints of casing above a float shoe. The float
equipment performance criteria shall correspond to the anticipated
service requirements per latest API RP 10F.
5.2.9 Excess Cement Volume
The volume of cement slurry to be placed in the open hole annulus
interval shall be based on the calculated annular volume using an
estimated hole size plus and excess of cement slurry based on similar
field experience or best practices or the following percentages of
excess slurry:

Structural - 100% excess
Conductor - 50% excess
Surface - 30% excess
Intermediate or production - most accurate caliper available + 10%
excess
5.2.10 Inadequate Cement Job
Where indications exist that cementation quality is such that well
integrity or objectives are jeopardised, Contractor shall inform
PETRONAS and ensure that remedial action is taken without any delay.
Contractor should run cement bond evaluation log.

5.3 Well Directional Survey

5.3.1 Vertical Well
First surveys shall be taken at depth no greater than 60 metres
below surface or mudline. Subsequent surveys shall be taken at 150
metres intervals but will not exceed 300 metres.

Copies of all surveys regardless of their status shall be filed with
PETRONAS. The report shall include but not limited to all tabulation
of accumulated inclination angles, the TVD and vertical section.

5.3.2 Directional Well
For wells with inclination greater than or equal to 5 degrees, first
survey shall be taken at a depth no greater than 60 metres below
drive pipe or conductor shoe, whichever is the first string of set
casing. Subsequent surveys giving both inclination and azimuth shall
be obtained on all directional wells at intervals not exceeding 150

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metres during the normal course of drilling, i.e. tangent sections. Two
successive directional survey readings shall not exceed 30 metres in
all planned angle and/or directional change portions of the hole.
Anti-collision shall be taken into consideration. PETRONAS may
require Contractor to submit the anti-collision report upon request.

Copies of directional surveys report shall be submitted to PETRONAS.
The reports shall include but not limited to the tabulation of the
accumulative drift angles, direction, TVD, vertical section and the
rectangular coordinates of each shot point.

In calculating all surveys, a correction from true north to Universal
Transverse Mercator Grid North shall be made after making the
magnetic to true north correction.
5.4 Well Control Equipment and Testing

5.4.1 BOP System
BOP equipment shall consist of an annular preventer and
the specified number of ram-type preventers. Annular preventer
shall be able to seal around any size of pipe in use, close on open
hole and allow for drill pipe stripping. The pipe rams shall be of
proper size to fit the pipe in use. The working pressure rating of any
BOP component shall exceed the maximum anticipated surface
pressure to which it may be subjected to. Unless otherwise specified
herein, all BOP systems shall conform to API Standard 53 (latest
edition) specification.
Elastomeric components rating shall be suitable for the operating
environment and compatible with the drilling and completion fluid in
use. All spare parts shall be from Original Equipment Manufacturer
(OEM). BOP closing times shall as a minimum meet API Standard 53.
If any repair or replacement of surface or subsea BOP stack is
necessary after its installation, this work shall be performed after the
well has been secured as per Section 9.10.
5.4.2 Auxiliary Equipment
The following auxiliary equipment shall also be provided:

a) An inside BOP and a full-opening drill string safety valve in the
open position with wrenches for operating the valves shall be
maintained on the rig floor at all times while drilling operations

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are being conducted with crossovers if necessary; and
b) A safety valve and circulating head shall be available on the rig
floor, assembled with the proper connection to fit the casing
that is being run in the hole at the time
5.4.3 Diverter System
A diverter system shall be capable of diverting well flow away from
the rig to provide protection for the drilling crew and rig equipment.
It is installed to control well flows encountered at shallow depths and
when the last string of casing is set in a formation of insufficient
strength such that the well cannot be shut-in because of the danger
of the flow broaching to the surface.
The diverter system shall conform to API RP 64 (latest edition)
specification. As a minimum the system shall provide an annular
preventer, with a spool below having two diverter lines (6” minimum
I.D. for land rigs and 10” minimum I.D. for offshore rigs). The diverter
lines shall have smooth bends and shall vent in different directions to
permit downwind diversion.
In known areas, for second and subsequent wells from a platform
where electrical logs have proven no hydrocarbons and/or other risk
are present in the entire hole section drilled below the first casing
string, drilling without a diverter may be acceptable. Contractor shall
inform PETRONAS accordingly.
5.4.4 Surface BOP Stack
The minimum stack requirements for drilling below any casing strings
with surface BOP stack are described below:

Surface BOP Stack
Drive or structural - 1-Diverter
Conductor - 1-Diverter
Surface - Annular, 2-Pipe Rams and 1-Blind Shear Ram
Intermediate - 1-Annular, 2-Pipe Rams and 1-Blind Shear Ram

Blind shear ram – capable to shear and seal all grades of drill pipe
used through the stack.

When a tapered drill string is in use, the following alternatives shall
apply:
a) A set of pipe rams to fit the smaller string of drill pipe installed in

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the existing BOP stack; or
b) Variable bore rams may be fitted in place of one or both sets of
pipe rams; or
c) An additional set of BOP equipped with a set of pipe rams to fit
the smaller string of drill pipe
5.4.5 Subsea BOP Stack
The minimum stack requirements for drilling below any casing strings
with subsea BOP stack are described below:

Subsea BOP Stack
Conductor - Riserless
Surface - 1-Annular, 2-Pipe Rams and 1-Blind Shear Ram
Intermediate - 1-Annular, 2-Pipe Rams and 1-Blind Shear Ram

When a tapered drill string is in use, the following alternatives shall
apply:

a) Variable bore rams may be fitted in place of one or both sets of
pipe rams; or
b) A second annular preventer may be used in lieu of pipe rams to
seal the smaller strings; or
c) An additional set of BOP equipped with a set of pipe rams to fit
the smaller string of drill pipe

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

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a) Autoshear
b) Deadman
c) Emergency Disconnect system (EDS)
Autoshear, deadman and EDS are optional for moored drilling units.
Floating drilling units operating with Surface BOP (SBOP) system with
drilling riser designed to contain wellbore pressure shall be equipped
with a Seabed Isolation Device (SID).
Prior to the removal of marine riser, the riser shall be displaced with
sea water after successful negative test. Contractor shall ensure that
sufficient hydrostatic head exists within the well bore to compensate
for the reduction in head and maintain a safe well condition, where
possible.
5.4.5.1 Subsea BOP Diversion
Drilling units that utilise a subsea BOP stack and marine riser
shall be fitted with a diverter system to safely manage gas
in the marine riser. This shall include two (2)
diverter/overboard lines arranged to be as straight as
possible to minimise erosion. The diverter lines shall
be individually selectable,and arranged to allow
overboard discharge in a safe manner in any prevailing wind
direction. The diverter line system shall be equipped
with automatic, remotely controlled full opening valves,
which open prior to closing the diverter element.
For Managed Pressure Drilling (MPD) and other operations,
when a rotating control device is installed on the marine
riser, it is not required to simultaneously have the marine
riser diverter system available.
5.4.6 BOP Test
Every drilling unit shall have a written BOP equipment testing
procedure.
5.4.6.1 BOP Control System
A minimum of two (2) BOP control stations shall be
provided. One (1) station shall be on the drilling floor and
another stationlocated at a remote readily accessible safe
area. Accumulators or pumps shall maintain a pressure
capacity reserve at all times to provide for repeated

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operations of hydraulic BOPs. The control panel shall
be fitted with alarms for low accumulator pressure as well as
for low level in the control fluid reservoir.
5.4.6.2 Pressure Test
For initial BOP system acceptance test, each component of
the BOP stack assembly and related control equipment shall
be pressure tested to their rated working pressure.
Subsequent pressure test shall be the maximum anticipated
surface pressure (or maximum anticipated wellhead
pressure for subsea BOP) and up to 70% of rated working
pressure for annular preventer. A 200 – 300 psi low
pressure BOP test shall be conducted prior to high pressure
test to maximum anticipated surface pressure. Each test
shall hold the required pressure for 5 minutes with no
indication of leakage. All test records shall be made available
upon request by PETRONAS. The BOP equipment shall be
tested according to the following procedures:
a) When installed or stump tested prior to installation;
b) Not less than once in 14 days beyond that period
PETRONAS approval shall be obtained. However, the
blind shear ram may not be tested;
c) Before drilling out after each string of casing has been
set and cemented or relevant element and connection
to be tested provided not exceeding 14 days between
tests; and
d) Following repairs that require disconnecting a pressure
seal in the assembly
Note: 1. Ram bonnets shall be tested every time opened
2. After installation of subsea BOP stack onto the
wellhead, the BOP-to-wellhead connector pressure
test may be limited to the maximum anticipated
wellhead pressure in the next hole section
5.4.6.3 Function Test
While drill pipe is in use, the following actuation procedures
shall be performed, as a minimum, to determine proper
functioning of the BOP and control stations:
a) Pipe rams: Actuated weekly, and after nippling up;
b) Blind shear rams: Actuated whilst drill pipe is out of

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the hole, after stack is nippled up, once each trip but
not more than once each day (except for subsea BOP);
c) Tapered drill string pipe rams: Actuated weekly, and
after nippling up;
d) Annular-type preventer: Actuated on the drill pipe, in
connection with the pressure test, once each week;
e) Actuation of control station shall be alternating
between primary and remote BOP control stations;
f ) Subsea BOPs shall be actuated at least on weekly basis.
Shear rams shall be function tested prior to drilling out
each set casing; and
g) Auto shear, deadman and ROV intervention operating
systems shall be function tested during subsea BOP
stump test.

5.4.7 Inspection and Maintenance
BOP system shall undergo an assessment by an industry recognised
third party well control equipment and system authority when a
drilling unit initially comes under contract. All critical actions from the
assessment shall be closed out prior to drilling. Shearing capability of
shear rams shall be verified either by testing or review of previously
conducted test data. The report shall be made available upon request
by PETRONAS.

All BOP systems and marine risers and associated equipment shall be
inspected and maintained in accordance with the manufacturer’s
recommended maintenance procedures. Inspection of subsea
installations shall be accomplished by the use of ROV, rig camera or
divers. This requirement will be waived for a period not to exceed 4
days in the event of a ROV or rig camera breakdown.

All BOP tests, maintenance and inspection shall be recorded on the
Driller’s log.
5.4.8 Personnel Competency
All supervisory drilling personnel shall be in possession of a valid
industry recognised well control training certificate and be fully
familiar with well control procedures and BOP equipment before
starting work on a well.

Well control drills and response time shall be recorded on the Driller’s
log. Drill objectives and acceptable response shall be predefined.
Regular and realistic drills shall be conducted to train involved

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personnel to achieve the acceptable response.
5.5 Drilling Fluid Programme
The characteristics used, testing of drilling fluid and the implementation of
related drilling procedures shall be designed to prevent the loss of well
control. Quantities of drilling fluid materials sufficient to provide well control
shall be maintained readily accessible for use at all times.
5.5.1 Primary Well Control
Before starting pulling out of the hole with drill pipe, the drilling fluid
shall be properly conditioned. Proper conditioning means that:
a) There is no indication of influx of formation fluids prior to pulling
the drill pipe out of the hole;
b) The weight of the returning drilling fluid is essentially the same
as the drilling fluid entering the hole; and
c) Other drilling fluid properties recorded on the daily drilling log
are within the specified ranges required to drill the hole.
When the drilling fluid in the hole is circulated, the Driller’s log shall
be monitored. When coming out of the hole with the drill pipe, the
annulus shall be filled with drilling fluid to ensure sufficient over
balance (at least 0.3 ppg or 100 psi) whichever is less is maintained at
all time.
For operations where narrow margins prevent a 0.3 ppg or 100 psi
overbalance, other methods, such as pumping out of hole, reduced
tripping speeds and increased frequency of flow checks should be
employed to maintain well control.

A device for measuring the amount of drilling fluid to fill the hole
shall be used. If there is at any time an indication of swabbing or
influx of formation fluids, the necessary safety devices and action
shall be employed to control the well.

The drilling fluid in the hole shall be circulated or reverse circulated
prior to pulling drill-stem test tools from the hole.
The hole shall be filled by accurately measured volumes of drilling
fluid. The following information shall be posted near the driller:

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

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b) The number of barrels and pump strokes required to fill the hole
for the designated number of stands of drill pipe and drill collars;
c) For each casing string, the maximum pressure that can be
contained under the BOPs before controlled bleeding off excess
pressure through the choke. Drill pipe pressure shall be
monitored when bleeding off pressure for well control; and
d) Where continuous fill trip tank equipment is used, only the
number of barrels required to fill the hole per stand of drill pipe
or drill collars and the maximum allowable casing pressure need
be posted
An operable degasser shall be installed in the drilling fluid system
prior to commencement of drilling operations. It shall be maintained
for use throughout the drilling and completion of the well.
If any variant of MPD method is used for more precise control of well
annular pressure profile, Contractor shall ensure that MPD
procedures are in place as well as risk assessment/Hazard and
Operability (HAZOP) analysis and personnel familiarisation training
are completed. Contractor shall select the MPD method that best
addresses drilling problems cost effectively.
5.5.2 Drilling Fluid Test
Drilling fluid testing equipment shall be maintained on the drilling rig
at all times, and drilling fluid tests shall be performed once every 12
hours or more frequently as conditions warrant.

Such tests shall be conducted in accordance with procedures
outlined in API RP 13B, latest revision, or other relevant codes and the
results recorded and maintained at the drill site. The following drilling
fluid system monitoring equipment shall be installed with derrick
floor indicators and used at the point in the drilling operations when
drilling fluid returns are established and throughout subsequent
drilling operations:

a) Recording mud pit level indicator to determine mud pit volume
gains and losses. This indicator shall include a visual and audio
warning device;
b) Drilling fluid volume measuring device for accurately
determining drilling fluid volumes required to fill the hole on
trips;
c) Drilling fluid return indicator to determine that returns essentially
equal the pump discharge rate; and

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d) Gas-detecting equipment to monitor the drilling fluid returns
5.5.3 Drilling Fluid Quantity
Sufficient drilling fluid materials shall be stored on the drilling unit to
meet any normal and foreseeable emergency conditions.

Subject to the above, and taking into account the availability of the
drilling fluid storage capacity of the drilling unit, the minimum
quantities of drilling fluid materials required shall be based on the
following:

a) The quantity of the drilling fluid materials shall be based on
renewing a volume of the calculated capacity of the active
drilling fluid system; and
b) The quantity of the weighting material shall be based on the
amount required to increase the drilling fluid density of the
active drilling fluid volume to overcome the highest anticipated
formation pressure for the hole section to be drilled
When the drilling fluid quantity required exceeds the storage capacity
of the drilling unit, the Contractor shall demonstrate that the
drilling fluid inventories on hand are sufficient to maintain well
control until additional quantities can be delivered to the well site.
Drilling operations shall be suspended in the absence of minimum
quantities of drilling fluid material as specified above.
5.6 Formation Integrity Test
Before drilling to a maximum of 3 metres of new hole below the surface
casing (if set below 300 metres below seabed) and intermediate casing shoe,
a pressure test shall be performed to obtain data to be used in estimating the
formation fracture gradient. This test can be stopped when sufficient
knowledge of the field has been gathered. Pressure data shall be obtained
by either testing to formation leak-off or to a controlled formation capability
test. The results of this test shall be recorded in the Driller’s log and used
to determine the depth and maximum mud weight to be used in drilling the
next interval of open hole. If during the course of drilling the hole, the mud
weight approaches within 0.5 ppg (0.026psi/ft) of the formation fracture
gradient or the formation capability test, Contractor shall exercise prudent
drilling practice to ensure well integrity and safety of the operations.

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5.7 Lost Circulation
During all normal drilling operations below the conductor, drilling shall cease
immediately whenever the drilling fluid pumped down the drill pipe is not
returning to the surface and drilling shall not be continued until adequate
circulation has been established.

In case of known areas or zones of loss circulation, it may be permissible to
drill ahead with continuing losses guided by operational and contingency
procedures. Contractor shall exercise prudent drilling practices to ensure
well integrity and safety of the operations.
5.8 Detection of Overpressure
Characteristics of the formation lithology and the formation fluid content
shall be monitored continuously after setting structural casing during
exploration drilling to detect the transition from normally pressured
formations to abnormally high pressured formations which normally include
but not limited to monitoring of:

a) Shale gas in the drilling fluid returns;
b) The shape of shale chips in drill cuttings;
c) The normalised drillability trend of the shale and in conjunction the
plotting of ‘dc’ exponent values derived from the rate of penetration or
subsequent modification of it;
d) The change in temperature and salinity of the drilling fluid returns; and
e) Indications of hole squeezing due to bore hole instability, torque and
drag
If a transition into an over-pressured formation is indicated, Contractor
shall take steps to attempt to verify the pressure of the transition zone using
recognised techniques when prudent to do so, and to maintain primary
control of the well as drilling proceeds into the over-pressured formation,
including modifying the drilling programme and equipment as required.
5.9 Suspension of Operations
In the event of a fatal accident, those operations associated with the fatality
shall be suspended as soon as safely possible and shall not be resumed
without the approval of the Police (Royal Malaysia Police) or other relevant
authority.

An operation shall be suspended as soon as possible if the continuation of
the operation causes, or is likely to cause an oil spill; or endangers, or is likely
to endanger, the safety of personnel, the security of the well, the safety of
the drilling unit and the operation shall remain suspended until it can resume

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safely. Conditions under which drilling shall be suspended in the case of a
drilling unit:

a) Inability to maintain primary well control;
b) Problems are experienced with critical BOP system component or
control system;
c) Failure of wellhead, casing or drilling fluid system;
d) Uncontrolled fire at the drilling site;
e) Failure of a significant portion of the primary power source;
f ) Inability to maintain adequate stability and buoyancy of the drilling unit;
g) Inability to satisfactorily maintain the position of the drilling unit over the
well;
h) Excessive motions of the drilling unit caused by sea-state or weather
conditions;
i ) While diving operations are being conducted at or near any part of the
subsea drilling system
All large scale incidents or accidents causing damage to equipment shall be
immediately reported to PETRONAS in writing giving estimated cost of
damage, downtime and root cause.
5.10 Shallow Hazards and Hydrocarbons
In all areas where shallow hazards or hydrocarbons are known, seismic data
shall be obtained. An appropriate shallow hazard contingency plan shall also
be in place. All seismic data relating to shallow hazards shall be submitted to
PETRONAS. Well locations shall be selected where the risk associated with
shallow hazard is avoidable or manageable. A well location shall if possible
be moved if the potential consequences and/or possible presence of a
shallow hazard are significant (i.e. moderate or high).
For drilling operations with a bottom supported drilling unit and/or drilling
from a fixed structure where presence of shallow hazards or hydrocarbons
are possible, a small diameter initial pilot hole of 8-1/2 inch or smaller size
from the bottom of the conductor casing to the proposed surface casing
seat shall be drilled and logged to aid in determining the presence or
absence of these hazards.
For drilling operations with floating drilling unit (not from a fixed structure),
systems and procedures shall be in place to continuously monitor the
operation for indications of a shallow hazard, and to ensure the safe and
swift move of the drilling unit to a position that is sufficiently remote from
the area of possible hazard or disturbance caused by any uncontrolled flow
of formation fluids.

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5.11 Underbalanced Drilling
Underbalanced drilling is defined as deliberately drilling where the pore
pressure of the formation being drilled is greater than the hydrostatic
pressure exerted by column of drilling fluid and formation fluids are allowed
to flow into wellbore. In this respect, balanced pressure drilling is a
subcategory of underbalanced drilling because the annular pressure is
expected to fall below the formation pressure during pipe movement. In
general, underbalanced drilling is aimed at improving drilling rate, limiting
lost circulation and protecting reservoir formation.

Underbalanced drilling shall be conducted only when the requirements
below are satisfied and subject to further discussion and approval by
PETRONAS prior to execution:

a) Assessment of risk and benefit of underbalanced drilling (economic and
technical justification to change from conventional drilling);
b) Assessment of fluid type to be used (gas, mist, foam, gasified liquid
and liquid);
c) Identification and assessment of equipment to be used that covers both
surface and sub-surface (gas compression, gas generation, separation,
foam, pressure control, downhole tools, BOP stack, rotating head, etc.);
d) Preparation of detailed underbalanced design programme (fluid design,
expected Rate of Penetration (ROP), wellbore model, fluid velocity,
cutting transport, cost analysis, etc.) and contingency plans; and
e) Environmental and safety concerns associated with underbalanced
drilling shall be addressed and documented. A primary consideration of
environmental protection shall include handling of returning fluid from
wellbore.
5.12 H2S Drilling Operations
When operations are undertaken involving formations or reservoirs known or
expected to contain Hydrogen Sulphide (H2S) or, if unknown, upon
encountering H2S, the following preventive measures shall be taken to
control the effects of the toxicity, flammability and corrosive characteristics
of the H2S gas.
5.12.1 Physical Properties and Toxicity
H2S is a highly toxic gas, rapidly causing death when inhaled in high
concentration. Its toxicity is almost the same as hydrogen cyanide
and is between five and six times more toxic than carbon monoxide.
H2S is heavier than air with specific gravity of 1.189 and it is
colourless. It forms an explosive mixture with air between 4.3 and
46.0 percent by volume. The acceptable maximum concentration for

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a continuous eight hours exposure of personnel is 10 parts per
million (ppm) in air, which is 0.001% by volume.
5.12.2 Breathing Equipment
An adequate number of self-contained positive pressure breathing
equipment shall be made available at all times on the rig floor, shale
shaker, mud pit area, pump area and other areas where H2S might
accumulate in hazardous quantities. All essential personnel in drilling
operation shall be required to use this equipment when necessary.

Resuscitators with spare oxygen bottle shall be provided at each
emergency centre. A cascade air-bottle system shall be provided to
refill the self-contained breathing equipment bottles. At any time and
in the vicinity where the concentration of H2S in the atmosphere
exceeds 20 ppm, breathing equipment shall be worn.

5.12.3 H2S Gas Detection
Automatic continuous H2S sensors shall be installed, be in working
condition and routinely function tested according to API RP14C to
cover as a minimum the areas of bell nipple, flowline and shale
shakers, mud pits, sack room, motor room and living quarters.

These sensors shall activate audible and visual alarms when sensing a
minimum of 5 ppm of H2S in atmosphere.

In addition, portable hand operated type H2S gas detectors shall be
made available to all essential personnel during drilling operation in
H2S environment.
5.12.4 Wind Direction Equipment
Wind direction equipment (such as wind sock and wind streamers)
shall be installed in sufficient quantity at prominent locations to
indicate to all personnel on or in the immediate vicinity of the facility
the wind direction at all times for determining safe upwind areas in
the event that H2S is present in the atmosphere.

5.12.5 Ventilation
Ventilation devices shall be explosion proof and situated in areas
where H2S may accumulate. Movable ventilation devices shall be
provided in work areas and be multi-directional and capable of
dispersing H2S away from working personnel.

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5.12.6 Personnel Training
All personnel shall be informed as to the hazards of H2S. They shall
be trained in the use of H2S safety equipment, informed of H2S
detectors and alarms, ventilation equipment, prevailing winds,
briefing areas, warning systems and evacuation procedures.

All crew members shall be familiar with basic first-aid procedure
applicable to victims of H2S exposure. Emphasis shall be placed
upon rescue and first aid for H2S victims.
5.12.7 Contingency Plan
A contingency plan shall be developed and a copy shall be submitted
to PETRONAS prior to the commencement of drilling operation in
H2S environment.

The plan shall include but not be limited to the following:

a) Physical property, toxicity level and physical effect of H2S;
b) Safety procedures, equipment and training;
c) Operating procedures during;
• Conditions with less than 10 ppm H2S in the atmosphere.
• Conditions with more than 10 ppm but less than 20 ppm
H2S in the atmosphere (limited danger to life).
• Conditions with more than 20 ppm H2S in the atmosphere
(high danger to life).
d) Responsibility and duty of personnel for each operating
condition;
e) Evacuation plan; and
f ) Agencies to be notified during emergency
Information on emergency procedures shall be posted in Bahasa
Malaysia and English at prominent locations on the operations
facilities.
5.12.8 Drilling Unit Equipment
H2S gas is highly corrosive to steel and at high stress levels, Sulfide
Stress Cracking (SSC) may occur in a very short time. All tubulars,
wellhead equipment, and other drilling related equipment which may
be exposed to H2S conditions and susceptible to SSC shall be
selected in accordance with the guideline presented in National
Association of Corrosion Engineers (NACE) MR0175/ISO15156
considering metallurgical properties and/or environment in contact
with the tubulars and equipment in order to reduce the chances of

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failure due to SSC.
5.12.8.1 Drill Pipe
To reduce potential failure due to SSC, steel drill pipe should
have a yield strength of 95,000 psi or less, unless it is heat
treated by quenching and tempering. Alternatively control of
the environment in contact with the drill pipe shall be
considered. Assessment shall be conducted to ensure risk of
drill string failure is ALARP.

5.12.8.2 Tubulars
Tubulars including casing, tubing, coupling, flange and
related equipment shall be designed for H2S service. Field
welding on casing, except conductor and surface casing
strings is prohibited, unless the Contractor can prove it is
safe to do otherwise.
5.12.8.3 BOP and Related Equipments
BOP, choke line, choke manifold and valves shall be
designed and fabricated for H2S service utilising the most
advanced technology. Elastomer, packing and other
non-ferrous part exposed to H2S shall be resistant at the
maximum anticipated temperature of exposure.
5.12.8.4 Flare System
The flare system shall be designed to safely collect and burn
H2S gas. Flare lines shall be located as far away from the
operating facilities as feasible in the manner to compensate
for wind changes. The flare shall be equipped with a pilot
and an automatic igniter.
5.12.9 Drilling Operations

5.12.9.1 Pipe Trips and Stripping
Every effort shall be made to pull drill string dry while
maintaining well control. If it is necessary to pull the drill
string wet after penetration of H2S bearing zones,
monitoring of H2S of the working areas shall be increased.
The monitoring of H2S in the vicinity of the displaced
drilling fluid returned shall also be increased.
5.12.9.2 Well Control
If gas cutting of drilling fluids beyond 0.2 ppg is

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encountered, the BOP shall be closed while maintaining
drilling fluid circulation through the choke line to the
mud-gas separator. The mud-gas separator shall be
connected into the flare system. The degasser shall be used
until the drilling fluid is free of entrained gas.
5.12.9.3 Coring
When coming out of the hole with a core barrel under
suspected H2S condition, the drilling crew shall wear
breathing mask before pulling the last twenty stands or at
any time H2S is detected at surface. “Mask on” shall
continue while opening the core barrel and examining the
cores. Cores to be transported shall be sealed and marked
for the presence of H2S.

5.12.9.4 Drilling Fluid
Suitable water or oil base drilling fluid should be used in
drilling formations containing H2S gas. A pH of 10.0
and above shall be maintained in a water base mud to
control corrosion and prevent SSC. Consideration shall also
be given the use of H2S scavengers in both water and oil
base drilling fluid systems. Sufficient quantities of additives
shall be maintained at well site for addition to neutralise H2S
picked up by the drilling fluid system. Drilling fluid
containing H2S shall be degassed and the gases removed
shall be burned with the flare system and shall be
continuously monitored for H2S concentration.

5.12.10 Well Testing Operations
During well test, the level of H2S concentration shall be
monitored at first hydrocarbon to surface and at regular
intervals subsequent to first hydrocarbon. All produced
gases shall be burned with the flare system if the gases are
flammable.

All well test equipment, well head equipment and tubular
goods shall meet the H2S service requirement. Drill pipe
shall not be used for testing well with H2S. The water
cushion shall be inhibited in order to prevent H2S corrosion.
The test equipment shall be flushed with treated fluid for the
same purpose at the end of the test.

Petronas drilling operations guideline

Petronas drilling operations guideline

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Petronas drilling operations guideline