drilling and completions

North America Shale Drilling and Completions WWD000L PoliciesValid through September 2014

Petroleum

ii | North America Shale Drilling and Completions

Foreword

My Expectations:

We will work together as one team, have a passion for keeping our crews safe and be good citizens wherever we work.

We must not be afraid of change and will offer up solutions, not excuses.

We will set our goals high and continually challenge ourselves, and our service providers, to improve our performance. We will benchmark as the best, hold ourselves accountable for, and achieve, high performance through good planning, adopting high standards and excelling in our control of implementation.

Detailed planning, review and investigation must be a way of life in the office and in the field. To drive this, we need to have transparency in our reporting and investigating of all failures and incidents and hold honest, open and effective after-action reviews.

Chris Nelson, Vice President North America Shale Drilling and Completions

These Policies are mandatory for all operations managed by BHP Billiton Petroleum North America Shale Drilling and Completions. Any deviations from these Policies require appropriate risk assessment, completion of the Policy Exemption Control Form and approval from the responsible field Drilling and Completions Manager.

These Policies are intended to provide clear direction on equipment, processes and procedures that are critical to the safe and efficient conduct of BHP Billiton Petroleum Drilling-managed operations. They are not intended to replace the Drilling Management System (DMS), which provides broader and more detailed guidance on how Drilling and Completions conducts its operations.

Where conflict exists between these Policies and the DMS Standards and Guidelines, the Policies shall take precedence. Constructive challenge and debate to improve the Policies are encouraged and should be directed to the Vice President North America Shale Drilling and Completions.

Derek Cardno, Vice President Drilling and Completions

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What We Will Do and How We Will Do It What we will do: •Always put the safety of our people first •Maintain control of our wells at all times •Deliver wells with full integrity •Lead the industry in performance and cost •Deliver results that create opportunities for the Corporation •Develop our people to be more capable than we are •Be the drilling team that people want to work for

How we will do it: •Stop the job if it cannot be done safely •Have a well thought out plan, consistent with our standards •Communicate simply, openly and honestly •Work closely with our customers and contractors •Use correctly rated, tested and unaltered equipment •Critically review our performance •Ruthlessly seek root cause for safety incidents and equipment failures •Train and develop our people •Provide a challenging and fun place to work

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WWD000L Policies – Valid through September 2014 | v

Foreword iiWhat we will do and How we will do it iv

Organization 11.1 Roles and Accountabilities 11.2 Competency, Behavior and Awareness 11.3 Hazard Management 11.4 Communication, Consultation and Participation 21.5 Contractor Management 21.6 Document Control 3

Planning 52.1 Health, Safety, Environmental and Community Planning 52.2 Well Planning and Programming 52.3 Directional Planning and Programming 52.4 Well Control Planning 52.5 Well Test Planning 6

Design Policies 93.2 Directional Well Design Policies 93.3 Cementation Design 93.4 Wellheads and Xmas Tree Design 103.5 Oil Country Tubular Goods (OCTG) Design 113.6 Drillstring Design 113.7 Well Control Systems and Equipment Design 113.9 Surface Equipment Design 133.10 Well Integrity – Barriers Design 14

General Operations Policies – Drilling and Completions 154.1 Operational Preparation 154.2 Management Of Change (MOC) 164.3 Hazardous Areas 164.4 Pressure and Function Testing 164.5 Safe Work Procedures 184.6 Working Equipment 214.7 Incident and Failures Reviews and Reporting 21

Operations Policies – Drilling 235.1Operations♀ 235.2 Well Control – Drilling 245.3 Cementing Operations 255.4 Barriers Policies 26

Operations Policies – Completions 296.1 Well Site Area Classification (Red Zone) 296.3 Treating / Well Testing Iron 296.4 Pressure Testing 296.5 Well Control 296.6 Drills 306.7 Well Monitoring 306.8 Work over 306.9 Snubbing 316.10 Coiled Tubing 316.11 Hydraulic Fracturing Operations 316.12 Wireline 316.13 Perforating and Explosive Devices 326.14 Well Testing Operations 33

Lifting and Handling 357.1 Lifting Equipment Inspection and Certification 357.2 Lifting Operations 357.3 Crane Hooks, Shackles, Slings and Chains 36

Well Design and Operations Well Control Equipment Policies 388.1 ‘Low’ H2S Concentrations 388.2 ‘High’ H2S Concentrations 39

Language 40

Contents

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WWD000L Policies – Valid through September 2014 | 1

1.2.2 Behavior The following actions must not be taken by any person involved in Drilling and Completions operations. Failure to comply with these rules will result in disciplinary action, up to and including dismissal:•Failure to report incidents immediately.• Instruction to deliberately breach BHP Billiton Petroleum

Policies.•Serious breach of BHP Billiton Petroleum Business Conduct

Guidelines.•Breach of BHP Billiton Petroleum Substance Abuse Policies.•Denial of time to conduct job safety analysis (JSA) or job risk

analysis (JRA).•Denying a STOP work request.• Intentional closing out of actions with the intent to mislead.• Intentional cover-up of relevant facts in incident investigations.•Knowingly failing to follow BHP Billiton Petroleum corporate

policies or NAS Policies.•Knowingly failing to follow the BHP Billiton Petroleum Fatal Risk

Controls requirements.•Tolerance of unsafe acts or conditions.•Smoking in areas other than those designated for smoking.•Possession of firearms, ammunition or other deadly weapons;

exceptions to this shall only be permitted when authorized by BHP Billiton Petroleum for security purposes and to ensure the protection of personnel and property.

•Failure to wear PPE where specified.•Use of emergency equipment other than for emergencies or

authorized testing and drills.•Unauthorized operation of equipment.•Disposal of waste in an unauthorized manner.•Horseplay, practical jokes, fighting, theft, personal violence or

abuse (verbal, written, photographic or physical based on race, gender, age, religion or culture).

Conventional blade knives and firearms are prohibited on BHP Billiton Petroleum operations and vehicles.

1.3 Hazard ManagementWWD004 Drilling Risk Management Guidelines WWD015 Drilling Safety Guidelines

1.3.1 Hazard Identifications, Risk Assessment and Risk ManagementFatal Risk Controls shall be implemented as provided for in BHP Billiton Petroleum Health, Safety, Environment and Community Controls (validity June 2014).

Planning for drilling, completions and well interventions campaigns in every basin shall include fit for purpose:•Campaign / Field Risk Assessment.•Pad Hazard Review.•Well Risk Assessment for specific well types.

1.1 Roles and Accountabilities All Drilling and Completions personnel shall be provided with their position description.

Position descriptions, including Health, Safety, Environment and Community (HSEC) responsibilities, are set out in WWD012.

Competency of staff personnel and contractors filling staff positions shall be assessed either through qualified referee, probationary assignment or other formal assessment means.

New staff and contractor personnel coming into the Drilling organization shall be thoroughly inducted into these Policies, relevant Drilling Management System standards and guidelines, field-specific well design, completions and field operations documents relevant to their jobs and individual campaigns.

1.2 Competency, Behavior and Awareness1.2.1 Competency Assurance and TrainingWWD012 Drilling Human Resources Guidelines

Induction training shall be conducted for all rig crews and service company personnel to explain operating plans, to ensure that safety systems are in place and to advise all participants of their operational and emergency roles and responsibilities.

The BHP Billiton Petroleum drilling, completions and contractor personnel listed below shall be trained in well control procedures by an accredited International Well Control Forum (IWCF) or Well Control Accreditation Program (WellCAP) institution or Well Control Certificate for Surface Stack and Workover/ Well Servicing – Supervisor Level and shall have a valid Well Control Certificate.

Well Control Certificates shall be renewed at least every two (2) years, unless otherwise specified below.

The following specific positions shall hold valid Well Control Certificates:•Drilling / Completions Managers and Superintendents.•Drilling / Completions Supervisors.•Operations Engineers.•Drilling and Completion contractors supervisors, including

Toolpushers, Drillers, Frac-, Coiled Tubing and Snubbing Supervisors.

No one shall relieve the Driller / Operator unless that person has appropriate Well Control Certification.

The following positions are required to complete Well Control School every four years, but are not required to maintain regulatory certification:

•Senior Drilling/Completions Engineers. •Drilling/Completions Engineers.

HSEC and other appropriate competency training, satisfying the mandatory HSEC training requirements of WWD012 and addressing specific campaign risks shall be provided to all BHP Billiton Petroleum personnel.

Organization

Section 1

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Section 1

Organization continued

contractors and major service contractors.

During all office safety meetings, minutes shall be taken and the minutes distributed throughout D&C.

1.4.2 Instructions to Contractors, Technical and Safety AlertsAll instruction to the Drilling Contractor and Service Contractors, including drillers instructions, casing and cement job instructions, completions and well services supervisors instructions, shall be communicated in writing to the Contractor’s supervisors, signed off by the Drilling / Completions Supervisor and Contractor’s supervisors and transmitted on a daily basis to the responsible Drilling / Completions Engineer for retention in well files.

Technical bulletins shall be used as a means of disseminating technical information between the Drilling departments whenever problems occur that could have worldwide implications.

Safety Alerts (“one pagers”) shall be issued to the D&C teams, appropriate PUs and contractors, as necessary. These alerts shall be reviewed and actioned, as appropriate, by all well site personnel, including personnel when they return to work from days off.

1.5 Contractor ManagementWWD016 Drilling Contracts Management Guidelines

Contractor HSEC management shall be an integral part of the general management of contractors throughout the contract life cycle, from contractor pre-qualification, through tender preparation, contractor and tender evaluation and selection, contract award, contract execution and post-campaign review.

Contractors supplying rig and other safety-critical services shall meet the performance standards specified in BHP Billiton Petroleum Drilling Standards and Guidelines. Safety-critical

• Operational Risk Assessments, as required (e.g. shallow hazard analysis).

Additional Campaign Risk Assessments should be conducted whenever significant changes are anticipated.

Inspections and audits of drilling and workover rigs and safety-critical services shall be conducted and completed prior to contract award or, if not practical, as early in the campaign as possible and shall address:•Safety critical systems and controls.•Safety management systems.•Mechanical reliability.• Drilling and hazardous fluids (including fuel) containment integrity.•Well control systems, procedures and training.

Journey management plans shall be developed in conjunction with the PU for all well sites and used for all journeys. These shall include Rig Move Plans and service contractor mobilization.

1.3.2 Risk Recording and ReviewD&C Managers are responsible for maintaining a Risk Register for their fields.

1.4 Communication, Consultation and Participation1.4.1 Stakeholder Consultation and ParticipationA general safety meeting, with mandatory participation by crews and third parties coming on tour, shall be held weekly.

A pre-tour safety meeting, with participation by a Drilling or Completions Supervisor, crews and third parties coming on tour, shall be held twice daily.

Office safety meetings shall be held quarterly, with mandatory participation by all D&C personnel and appropriate BHP Billiton Petroleum line management, HSEC personnel, drilling/workover

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A bridging document shall be produced, between the drilling contractor, workover contractor and completions/well service contractors and BHP Billiton Petroleum well control policies and procedures, which shall highlight any differences and clearly state the agreed procedures. As an alternative, NAS-specific well control manuals that include equipment requirements, policies and procedures for drilling, completions and well services activities may be produced.

1.6 Document ControlA document control system, including revision history, shall be used to manage the approval process for technical or operational documents that are subject to formal management approval.

services are defined as the provision by a contractor of any equipment or conducting of any operation that penetrates or extends the pressure-containing envelope of the well or has a specific life-saving or life support function.

1.5.1 Bridging of Contractor to D&CPrior to the start-up of operations using rig contractors, completions and well services contractors, a bridging document shall be prepared which interfaces between D&C and the contractor’s Management Systems.

1.5.2 Bridging of Well Control PoliciesPrior to operations commencing on a newly contracted rig or other pressure control equipment, the contractor’s well control policies and procedures shall be reviewed to ensure compatibility with the BHP Billiton Petroleum Well Control Standard (WWD005).

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Section 2

Planning

abnormal pressure zone, whichever is the deeper, to a maximum of 164 feet.

The drilling program for directional wells shall include as a minimum:•A spider plot (if other wells are expected to interfere with the

planned well).•A vertical section and plan view.•A well path interference summary.•The survey program.• Lease boundaries.

Surface and target coordinates shall be verified in accordance with WWD010 Directional Drilling and Surveying Guidelines.

The Senior Drilling Engineer and Subsurface Geologist shall approve the directional plan.

2.3.1 Tool CalibrationAll survey tools shall be inspected and calibrated prior to use in any well.

2.3.2 Position ReferencesThe PU shall provide final surveyed surface and bottom hole location coordinates for each well.

All surveys measuring inclination and direction, including directional surveys at multi-well pad locations, shall be referenced to Grid North.

At multi-well pad locations, all surveys shall reference a single fixed point in space (the survey reference point) as the origin of the local coordinate grid.

Each rig’s rotary table (RT) elevation shall be referenced to the adopted vertical datum, following local convention, and surveys shall reference the RT as the vertical reference.

2.4 Well Control PlanningWWD005 Well Control Standard WWD007 Well Integrity Standard

2.4.1 Well Control Planning – DrillingThe pre-service inspections audit, which is carried out on all rigs prior to them being put into service, shall specifically assess the condition of the drilling contractor’s blowout preventers and other well control equipment.

Kick tolerance shall be calculated in advance of drilling hole sections with the BOP stack installed.

Drilling operations with a calculated kick tolerance less than the design approved in the Drilling Program, requires approval by the Drilling Manager.

2.4.2 Well Control Planning – Well Completions and Re-entriesShut-in procedures shall be posted at the control consoles of all units and shall address:•normal operations.

2.1 Health, Safety, Environmental and Community PlanningWWD015 Drilling Safety Guidelines WWD018 Drilling Environmental Guidelines WWD020 Drilling Health and Hygiene Guidelines

Annual HSEC Plans shall be prepared and shall be approved by Drilling and Completions Managers.

Emergency response plans, including Medevac plans, shall be integrated into BHP Billiton Petroleum emergency management plans and coordinated and aligned with local emergency response authorities.

Drills and exercises shall be held periodically in accordance with the PU schedule, to confirm the effectiveness of emergency response plans.

Contingency plans shall be prepared and documented for any potential hazard that cannot be eliminated or mitigated by equipment selection, procedures or design features.

Where H2S gas is expected to be encountered in a well, an H2S contingency procedure shall be prepared.

2.2 Well Planning and ProgrammingWWD006 Well Design Standard

All available relevant offset well data shall be gathered and analyzed during the planning of the well.

A Basis of Design (BOD) agreed by the PU/Exploration and the local drilling and completions department shall be developed for each well, or group of similar wells, drilled, completed or re-entered.

Equipment and materials used in wells shall be designed, manufactured, inspected, installed and tested in accordance with industry-accepted standards as specified in relevant BHP Billiton Petroleum standards.

Well-cost estimates used for preparation of AFE, shall be prepared for all wells, completions or re-entries and shall be approved by the PU prior to any financial commitment.

Well-cost estimates shall:•Be based on most likely well time estimates.•Take into consideration the purpose of the estimate and

required accuracy. •Address the sensitivity of the estimate to major identified risks.

The cost estimating procedures used shall follow the Drilling standards provided in WWD014 Drilling Engineering Planning and Guidelines and WWD100L NAS D&C Management System.

2.3 Directional Planning and ProgrammingWWD010 Directional Drilling and Surveying Guidelines

Survey programs shall be designed to limit the positional uncertainty at the deepest planned objective or possible

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Section 2

Planning continued

2.5 Well Test PlanningWWD017 Well Test Guidelines

2.5.1 Well Test Risk AssessmentThe well testing contractor shall provide piping and instrumentation diagrams (PandIDs), process flow diagrams (PFDs), equipment diagrams, specifications and certification for all equipment.

Hazard and Operability Analysis (HAZOPs) involving relevant service contractor personnel shall be conducted:•On all well test spreads when first put into service and

thereafter when any changes are made to spread configuration.•Where a Hazard Analysis identifies particular conditions that

may arise due to well condition, external factors (weather/atmospheric conditions), equipment constraints, local constraints or environmental concerns.

The HAZOP for well test equipment shall include all safety-critical equipment and all ancillary equipment containing hydrocarbon or well fluids interfaced into the well test package.

Representatives from each service contractor supplying equipment shall participate in HAZOPs for well test equipment.

• tripping operations.• tubulars or tools that cannot be shut-in on.

On live well interventions, a hazard assessment and JRA shall be conducted for all penetrations of the well pressure envelope.

Where possible, the kill wing valve installed on the Xmas tree shall be used for well kill.

Prior to any well intervention, all Xmas tree valves, frac valves and wireline lubricator valves shall be inflow tested.

Hydrate suppression capability shall be available for all intervention operations where hydrate formation is a possibility.

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Section 3

Design Policies

3.2 Directional Well Design PoliciesWWD010 Directional Drilling and Surveying Guidelines

3.2.1 Collision Avoidance PoliciesWells in which the well centerlines are closer than 20 feet per 1,000 feet of drilled depth or, if less than this limit, closer than a maximum potential uncertainty of 2 feet between the ellipses of uncertainty of the two wells (when calculated at 95 percent confidence level or 2-sigma), shall be isolated by plugging them below the depth of potential interference prior to drilling ahead.

Nearby wells that are expected to interfere with the trajectory of the planned well shall be plugged in accordance with WWD010.

Confirmation that the nearby well has been plugged shall be obtained in writing prior to drilling ahead as per WWD010.

The minimum radius of curvature method shall be used to calculate bottom hole location from survey data.

A mathematical model shall be used to ensure that sufficient separation is maintained between wells.

3.3 Cementation DesignWWD024 Cementing Standard WWD007 Well Integrity Standard

3.3.1 Cementation PreparationAll oilfield cements shall undergo quality control analysis in accordance with American Petroleum Institute API Specification 10A, Specification for Cements and Materials for Well Cementing (ISO 10426-1:2009).

All slurry additives, both dry and liquid, shall undergo a quality control regimen to ensure uniformity and desired performance in accordance with supplier specifications.

3.3.2 Cement Slurry DesignA pre-drill temperature model shall be developed, based upon accurate static temperature measurements from offset wells.

The cement slurry design should be based upon accurately measured bottom hole static temperature (BHST) and bottom hole circulating temperature (BHCT).

All zones requiring isolation shall meet the barriers standards defined in WWD007 Well Integrity Standard.

Cement slurries shall be designed to ensure pressure is maintained on the formation as the slurry sets up through its critical transition period.

3.3.3 Cement Slurry TestingSlurry design and pilot testing shall be completed during the planning phase for any well type.

The cement slurry design determined from pilot testing shall be retested using the field blend prior to the job.

Field blend testing shall be conducted, where practical and where time allows, with samples taken of each material on the rig

3.1 Well DesignWWD006 Well Design Standard WWD007 Well Integrity Standard WWD008 OCTG Standard WWD009 Wellhead Standard WWD021 Completions and Well Services Guidelines

3.1.1 Critical Program ElementsCementing calculations shall be independently completed by the Cementer, Drilling Engineer and Drilling Supervisor.

3.1.2 Well ProgramsDrilling, Completion and Well Testing Programs shall be signed by the responsible Engineer and approved by the Senior Drilling Engineer or Senior Completions Engineer.

The eQIP Management of Change Form shall be completed and approved for all significant program changes.

3.1.3 Casing and Tubing DesignMinimum assumed kick volumes for well design shall be:

Hole Size ( in) Kick Volume (bbl)

17 or larger 75

12 to 17 40

8 to 12 25

Less than 8 15

These shall be calculated for a swabbed kick as defined in WWD006.

Casing and tubing designs shall consider the full well life cycle as specified in the BoWD for burst, collapse and tri-axial loads as per WWD006.

Casing and tubing strings shall be designed with the following minimum design factors:

Loading Minimum Design Factor

Burst 1.101

Collapse 1.00

Axial 1.302

1.203

Tri-axial 1.25

1 Based on 87.5% wall thickness for burst loads only 2 Normal operating conditions (production, shut-in, etc.)3 Infrequent / low-probability loads (i.e. frac screen-out, etc.)

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Section 3

Design Policies continued

allow for well intervention and repair of surface valves or other downstream pressure-controlling equipment.

All Xmas trees installed on any land well capable of flowing naturally to surface (i.e., with any positive shut-in wellhead pressure) shall have at least one valve in the flow stream on the Xmas tree fitted with a fail-safe closed actuator.

During well interventions, only the Xmas tree flow-stream valve fitted with the fail-safe closed actuator may be fitted with a fusible lockout cap or other mechanical isolation device.

All Xmas trees should be fitted with a separate kill inlet not forming part of the well flow stream pipe work.

3.4.2 Wellheads Barriers DesignSurface wellhead side-outlets shall be configured as follows:

A-Annulus (Tubing Head Housing): All API studded side outlets. Both outlets with VR plug profile. Side 1 = VR plug fitted, companion flange with test port/check valve to confirm no trapped pressure. Side 2 = dual full-opening gate valves, API companion flange, drilled and tapped 2 inch LP, fitted with 2 inch LP XXH bull plug, drilled and tapped ¾ inch NPT and fitted with a fully rated needle valve for pressure gauge and transducer.

B-Annulus (Casing Head Housing): All API studded side outlets. Both outlets with VR plug profile. Side 1 = VR plug fitted, companion flange with test port/check valve to confirm no trapped pressure. Side 2 = single full-opening gate, API companion flange, drilled and tapped 2 inch LP, fitted with 2 inch LP XXH threaded “Ell”, 2 inch LP XXH threaded riser to above ground, 2 inch threaded fully-rated ball valve, 2 inch LP XXH bull plug, drilled and tapped ¾ inch NPT and fitted with a fully rated needle valve for a pressure gauge.

Note that B-annulus:

• the ‘L’ may be 45 or 90 degrees, and:• if the cellar is not intended to be filled, the “L” and riser may be

omitted but the configuration shall otherwise remain the same as above.

3.4.3 Wellhead Quality Assurance (QA)/Quality Control (QC) and AcceptanceWWD022 QA-QC Guidelines

All wellhead and Xmas tree components shall be manufactured to a Quality Plan, which shall be reviewed and agreed prior to placing an equipment order.

Formal records shall be kept of all witnessing of factory acceptance testing, whether by BHP Billiton Petroleum in-house Quality Engineers or third parties acting on their behalf.

A stack-up test with casing/tubing hanger stack-up measurement and fit tests, drift testing of body and hangers, wear bushings and test tools shall be performed on all newly designed wellheads, Xmas trees, and frac trees prior to first-time use.

(including mix-water) that will be used for the job.

The BHST used in the final cementing design shall be reviewed and approved by the Senior Drilling Engineer (SDE) and cementing service company.

All slurry properties shall be tested in accordance with the methods described in API RP10B-2.

The following tests shall be run on all slurries:•Surface rheology.•Downhole rheology.•Downhole gel strengths (10 sec./10 min.).•Free Fluid.•Fluid Loss (on Fluid Loss Control slurries only).•Thickening Time (the tailored method is preferred where

possible, since it simulates down-hole/actual placement parameters).

•Compressive Strength Analysis (either “Crush” or “Non-Destructive” method).

•Static Gel Strength Analysis (Transition Time) shall be run on all slurries that may be exposed to flow zones to analyze their static gel strength development.

•Sedimentation Testing.

The cement service company representative shall send an email with all laboratory testing reports (both cement service company and third party), along with a plot of compressive strength development, to the Drilling Engineer and Superintendent responsible for the well.

3.4 Wellheads and Xmas Tree DesignWWD009 Wellhead Standard WWD021 Completions and Well Services Guidelines WWD022 QA-QC Guidelines

3.4.1 Specifications and StandardsWellhead equipment shall be designed and constructed in accordance with the relevant API specifications and the relevant sections of WWD009 Wellhead Standard.

Wellhead and Xmas tree equipment shall have a rated working pressure in excess of the maximum anticipated wellhead pressure. This shall include any kill loads or stimulation loads unless a Xmas tree saver device is used.

Where hydrogen sulfide may be encountered, or when well fluid composition is unknown (e.g., exploration wells), then sour service wellhead equipment shall be specified.

On conventional Xmas trees, all valves shall be rated to a minimum of the same API pressure rating as the Xmas tree body unless the body is de-rated to match the valve rating.

Side outlet valves shall be rated to the same pressure as the wellhead unit to which they are attached.

All wellhead tubing hangers shall be provided with means of isolating the tree (e.g., nipple or back pressure valve profile) to

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•Drill pipe shall be hard-faced with wear-resistant alloy material, preferably applied approximately 3/32 inch proud of tool joint surface.

•Acceptable hard-facing materials include: Armacor M, Arnco 200XT, Pinnchrome and similar products.

•Where only tungsten carbide hard facing is available, hard facing on drill pipe tool joints shall not be either raised or rough finished.

•All drill-collars, stabilizers and any other in-hole equipment may be hard-faced with tungsten carbide, which shall be flush with the body and shall be ground to a smooth finish.

3.7 Well Control Systems and Equipment Design WWD005 Well Control Standard

3.7.1 Well Control Equipment DesignAll pressure control equipment shall:•Have a unique identification number.•Be provided with details of its design basis, construction,

testing and intended operating envelope.•Be accompanied by current certificates evidencing its

maintenance, inspection and condition. The BOP and associated equipment shall be rated to exceed the maximum anticipated surface pressure. All wetted surface components shall compatible with the anticipated well fluids.

Pipe rams shall be installed that fit all sizes of drill pipe used.

BOP shear rams, where installed, shall be able to shear and seal the pipe body of all drillstring tubulars planned for use.

Steel ring gaskets shall be installed between the wellhead and the BOP and the wellhead to Xmas tree connector.

The BOP accumulator volume shall comply with API Standard 53.

The BOP stack configuration shall comply with the relevant API standards and WWD005 Well Control Manual stack-up configuration standards.

The inlet below the lowest ram shall not be used as a choke line during well control operations.

BOP closing times shall, at a minimum, meet API RP16E.

Diverter closing times shall, at a minimum, meet API RP 64.

The diverter vent line shall be designed to have sufficient liquid and gas-handling capacity for the well(s) being drilled and valve sizes selected to minimize pressure drops and risk of plugging.

Mud Gas Separators (MGS), where employed, shall have sufficient gas-handling capacity for the well(s) being drilled.

Remote BOP control panels shall be fitted with an uninterruptible power supply (UPS) and/or air supply, as appropriate. The panels shall be positioned adjacent to the main rig floor egress.

All vent lines, blooie lines, flare lines and relief lines, shall be designed with appropriately fixed and engineered clamps, brackets or tie-down cables.

3.5 Oil Country Tubular Goods (OCTG) DesignWWD008 Oil Country Tubular Good Standard

3.5.1 Tubular SelectionAll casing, liner and tubing pipe bodies shall be manufactured to API Spec 5CT.

Large-diameter tubulars (16 inch and larger) shall be manufactured to API 5L or 5CT.

Electrical resistance weld (ERW) pipe shall only be used for surface casing and conductor strings.

All casing and tubing connections shall be manufactured to API Spec 5CT, other than where non-API metal-to-metal gas-tight production casing and tubing are required in Section 8 below.

Premium-threaded gas-tight production casing and tubing connections shall be qualified to ISO 13679 (minimum category 3).

Short Threaded Connections (STC) shall not be used.

Where H2S is expected, tubulars shall be designed to National Association of Corrosion Engineers (NACE) MR0175.

Torque-turn equipment shall be used when running all premium-threaded production casing and tubing; all torque-turn charts shall be included in the well files.

3.5.2 Tubulars QA and QCWWD022 QA/QC Standard

All tubulars shall be manufactured to a Quality Plan, which shall document the process of manufacture, testing, third party witnessing and inspection.

Casing to drillpipe crossovers shall be manufactured to a Drilling-approved Quality Plan.

3.6 Drillstring DesignWWD011 Drillstring Standard

3.6.1 Drillstring Design and ManufactureNew drillstring components must be manufactured and inspected to API Specifications 5 and 7.

Used drillstring components shall be inspected to Standard DS-1, against the appropriate Service Category.

Pin connections shall have stress-relief grooves and box connections shall have a DRILCO or equivalent bore-back feature.

Any tools that do not have bore-backs or do not meet the requirements listed on the previous page, require exemption by the BHP Billiton Petroleum Drilling Manager. Exemption may be given to rental and other short-term usage tools which do not require bore-backs or stress-relief groove features, including some fishing tools and wellhead running tools.

All newly manufactured or recut connections shall be cold-rolled and chemplated or cold-rolled and high grain phosphated.

Hard Facing:

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Section 3


Quick-connectors with resilient seals may be used on the bottom connection of wireline BOPs rated at less than API 10M, subject to risk assessment.

Wireline BOPs with a quick-connector bottom outlet relying on a resilient seal, may only be used when there is at least one valve below the quick-connector that has wireline shear capability and cannot be locked out, and subject to a risk assessment prior to operations commencing.

BOPs with threaded top and bottom connections made up into drilled and tapped flanges, and similar back-welded connections, shall not be used.

During wireline and coiled tubing activities, there shall be at least two BOP rams positioned above the kill inlet.

The kill inlet shall be fitted with a minimum of two fully rated flanged- or integral full bore isolation valves and shall be positioned below the lower-most ram.

All emergency shutdown device (ESD) valves in the flow stream shall be capable of being operated from a remote location.

Lubricator assemblies (including the lubricator, stuffing box and other connections above the BOPs) shall be constructed using full-penetration welded components.

3.7.6 Subsurface Safety ValvesSurface-controlled subsurface safety valves (SCSSV) shall be installed in those wells described in the well design flow-chart in Section 8.

All SCSSV used shall have pump-through capability.

The depth at which a SCSSV should be fitted may be determined by local legislation, but in any case shall meet the following criteria:• It shall be fitted at a fail-safe setting depth (i.e., if control line

fails, it shall fail-safe close in all normally anticipated well and annulus operating conditions).

• It shall be fitted at, or deeper than, the shallowest competent formation and in any case no shallower than 100 feet below surface.

3.7.2 Well Control Equipment VerificationShop proof tests on new or refurbished pressure control equipment should be held for a minimum of 15 minutes (low pressure) and 60 minutes (high pressure).

BOP shear rams, if fitted, shall be verified for shear capability by either a test of the shear rams or a review of actual data from shear testing carried out previously.

Where confirmation of the shearing capability is not verified by actual test data, a statement from the original equipment manufacturer (OEM) with a calculation provided by the OEM using their own algorithm may be accepted, with Drilling Manager approval.

3.7.3 Air-Drilling Well Control Equipment DesignRotating BOPs and associated equipment shall be rated API 2M minimum static and manufactured to API Specification 16RCD as a minimum standard.

Air drilling operations shall be performed only on wells designed as follows:•Designed in accordance with the requirements of API RP 92U

Underbalanced Drilling Operations•Rotating head rated to at least the MASP of the well.•Surface conductor shoe sufficiently competent to withstand a

shut-in.•BOP system meeting the requirements of WWD005 Well Control

Standard that will allow well shut-in in the event of excessive gas-flow from a formation.

•A blooie line of sufficient diameter to handle the expected flow rate, routed with minimum bends and fitted with ignition equipment or a pilot light

3.7.4 Mud System Requirements for Well ControlAll rigs with active mud/completion fluid tanks shall be fitted with independent level indicators, and a fluid volume totalizer readout and trip alarm located at the Driller’s console.

3.7.5 Completions and Interventions Well Control EquipmentAll well servicing BOPs shall:•Be manufactured from forgings.•Have a flanged bottom connection.•Have a minimum of two sets of rams.•Shall not be considered as additional valves.•Be fully rated to a minimum of the nominal working pressure of

the Xmas tree.•Be hydraulically operated (with manual backup) with the

operating controls remote from the well.• Include a device capable of cutting wire or coiled tubing and

subsequently seal off the wellbore.

Wireline BOPs rated API 10M or greater shall have flanged bottom connections, unless the well is incapable of flowing naturally to surface.

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Line pipe connections larger than two (2) inch nominal diameter shall be of welded or flanged construction – no threaded line pipe over two (2) inch diameter with the following exceptions (allowed only when used for service duty at 5,000 psi or less):•BOP control system piping.•Tank suction hoses.•Water lines rated at American National Standards Institute

(ANSI) Class 150 or less.

Back welded threaded connections are not acceptable on pipe of any diameter.

Any flow wetted surface piping systems shall be designed, constructed and certified, at minimum, in accordance with ASME B31.3 and in accordance with NACE MR.01.75 for sour service conditions.

All gas, oil and water flow lines, including vent lines and flare lines, shall be properly secured with appropriately fixed and engineered clamps, brackets or tie-down cables.

Flow lines shall not run through rig work areas.

3.9 Surface Equipment Design3.9.1 High Pressure Piping and Flexible HosesWWD002 Drilling Audit and Inspection Guidelines WWD025 Drilling and Completions Piping Standard

Surface piping systems shall contain the appropriately-sized relief valves for the anticipated pump rate and relief valve discharge piping shall be in accordance with the manufacturer’s specification.

All high pressure flexible hoses shall comply with the design, selection and operations standards provided in WWD025 Drilling and Completions Piping Standards.

All high-pressure hoses shall be provided with identification banding and certificates and shall be inspected and retested each

3.8 Well Test DesignWWD017 Well Testing Standard

3.8.1 Well Test String DesignWell testing strings shall have metal-to-metal seal connections if the expected maximum SIWHP is greater than 3,000 psi and/or the well fluids may, or will, contain H2S.

Permanent packers shall be used for wells with pore pressures greater than 10,000 psi.

3.8.2 Specifications and CertificationAll pressure-containing test equipment shall have valid third-party certification.

The entire well test package, including ancillary equipment handling hydrocarbon or well fluids, shall be subjected to a design and certification validation by an independent, competent third-party inspector.

The flow line from the surface tree to the testing choke manifold, and the choke manifold, shall be rated and tested to the maximum expected surface pressure, as calculated from reservoir pressure less the hydrostatic of a gas column to surface, plus any kill or stimulation pressure.

Natural gas shall not be used as a substitute for compressed air for any well testing equipment instrumentation, or controls.

3.8.3 Well Test ESD System DesignA well test ESD system shall be provided and shall function closed in less than ten (10) seconds.

As a minimum, ESD stations shall be provided on the drill floor, at the well test area and at the entrance to the well location. For rigless well tests, the ESD station shall be remote from the well.

3.8.4 Well Testing Flowline and Piping SpecificationsAll high pressure lines, including instrumentation lines, shall have double isolation.

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Section 3

All naturally flowing land wells completed with a packer shall be provided with the means to set a fully rated mechanical isolation plug at, or below, the packer.

All wells that are capable of flowing naturally to surface shall be completed with a down hole packer capable of withstanding full reservoir pressure, irrespective of the annulus fluid used in the well.

3.10.2 Barrier Hazards Assessment and RequirementsA barrier hazard assessment shall be conducted for all stages of every well type. An assessment shall also be conducted whenever a Critical Element is not met.

For simultaneous operations (SIMOPs), the requirements to make adjacent wells safe shall be considered in a risk assessment, which shall consider dropped objects, vehicles colliding with a well, well path collisions, etc., as detailed in WWD007 Well Integrity Standard.

A cemented shoe track qualifies as a temporary barrier, once it has been pressure tested as per program and successfully negative tested to simulate the reduction of mud weight.

3.10.3 Well Kill System SpecificationsIrrespective of pressure rating, all kill line isolation valves shall be API or ANSI flanged (i.e., with metal ring-type joints or gaskets) or solid welded.

Valves with flanged outlets using spiral-wound metal gaskets or fiber-type gaskets and valves with threaded outlets, are not allowed on the kill line between the kill line isolation valves and the kill inlet point below the BOPs.

Flexible steel hoses (e.g., Chiksan lines, Coflexip hoses, etc.) that rely on a resilient seal for pressure integrity may only be used on the kill pump side of the kill line isolation valves.

3.10.4 Instrument ConnectionsAll small diameter (¾ inch and less) threaded pressure and instrument tappings shall be protected with double block-and-bleed stainless steel high-pressure valves; this requirement includes tappings for pressure sensors fitted to lubricators.

six months. Hoses shall also be banded with the validity termination date in accordance with industry standards. Copies of certification for all hose components shall be available at the well site.

All Chiksans and flexible high pressure (HP) hoses shall have adequate safety restraints installed to protect personnel in the event of failure in accordance with WWD025 Drilling and Completions Piping Standard.

Service contractors shall provide inspection and rejection standards for all hammer-unions on such high pressure hoses.

3.9.2 Equipment LayoutsWell site equipment layouts, including frac unit layouts, shall be verified by the Drilling / Completions Supervisor as complying with process flow diagrams (PFDs) and layout diagrams approved by BHP Billiton Petroleum.

3.9.3 Travelling Block Control System (TBCS)A TBCS shall be fitted on all D&C-contracted drilling and workover rigs, to reduce the potential for the travelling assembly to contact the crown or rig floor.

3.10 Well Integrity – Barriers DesignWWD007 Well Integrity Standard

Permanent barriers are barriers that will not be lost or degraded with time (cement is commonly used to construct a permanent barrier).

Temporary barriers are tested mechanical devices that should contain pressure to allow BOP removal (for example) but which might eventually fail if left in place for a considerable period of time.

Barrier controls apply equally to casing and to annuli. Refer to WWD007 for definitions of permanent and temporary barriers and the verification of their integrity.

3.10.1 Flow Stream and Annulus BarriersAll completed wells shall be provided with a minimum of two independent mechanical barriers.

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Section 4

General Operations Policies – Drilling and Completions

operations. The meeting or teleconference call shall be attended by the responsible Drilling/Completions Supervisor, Drilling/Field Superintendent, Drilling/Completions Engineer, Directional Driller, Mud Engineer, and the drilling/service contractors Driller, Toolpusher, Superintendent or Supervisor, as appropriate, and recorded on the daily drilling/completions report.

4.1.4 Mobilization and Rig MovesThe Drilling / Completions Supervisor shall ensure that all vendors have verified that all loads to be moved meet payload, height and weight restrictions and that the relevant contractors have conducted dropped objects reviews prior to commencing moving to any well sites.

All rig moves must be conducted following an approved rig-move plan, which shall itemize the number and sequence of lifts, load move-off and move-on sequences.

A pre-move meeting must be help prior to all rig moves: the meeting must be attended by:•Drilling Supervisor.•Rig contractor’s Toolpusher and/or Rig Manager.•Trucking / rig-moving contractor’s truck-pusher or supervisor.

4.1.5 Safety CommunicationThe Drilling/Completions Supervisor shall conduct Pre-Tour Operations Meetings to outline the work objectives and operations, both programmed and contingent.

The meeting should review the previous day’s operations and the upcoming operations to be performed.

4.1 Operational Preparation4.1.1 Campaign InductionsCampaign inductions shall be performed at the start of a new campaign and annually thereafter.

All BHP Billiton Drilling/Completions Supervisors shall be inducted in the following:•BHP Billiton reporting requirements.•Well control policies.•Bridging documents.•HSEC requirements.•Permit to Work.

4.1.2 Well Site InductionsAll personnel arriving at a well site shall receive a site-specific induction, which shall include the following:•emergency procedures.•muster area locations.• restricted areas.•authority to stop the job.•performing a job risk assessment (JRA) prior to starting any

task.• incident reporting.•overview of current site operations.

4.1.3 Pre-Spud / Pre-Completions MeetingsA pre-spud meeting shall be held prior to the spudding or re-entry of all wells and prior to the commencement of completions

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General Operations Policies – Drilling and Completions continued

Section 4

•Significant change in program activities (e.g. fishing operation).•Significant change in formation pressure or fluid properties (i.e.

outside the parameters defined in the program).•Unable to achieve required well integrity.•Changes to Field Basis of Well Design requirements.•Changes to test pressures.

Operations with degraded well or equipment conditions shall be risk assessed, including barrier analysis, prior to operations proceeding.

Minor procedural variations required to enhance safety of the operation, or to streamline activities, may be initiated at the well site. Such variations should be discussed with the Drilling Superintendent or Completion Superintendent, as appropriate, and the responsible Engineer.

4.3 Hazardous AreasWWD005 Well Control Standard

API RP 500 Recommended Practices for Classification of Locations for Electrical Installations at Petroleum Facilities Classified as Class I, Division 1 and Division 2

API RP 505 Recommended Practice for Classification of Locations for Electrical Installations at Petroleum Facilities Classified as Class I, Zone O, Zone 1, and Zone 2

For operations where no drilling or workover rig is used, the Hazardous Area Zone 1 shall be deemed to extend 5 feet from the well centre-line and the Zone 2 an additional 5 feet from the outer edge of the Zone1 area.

When pressure control equipment is connected to a well, this extends the Zone 2 area to a ten (10) feet three-dimensional envelope around such equipment. In practice this means that the Zone 2 area will extend ten (10) feet above a coil tubing unit injector or above the top of a Grease Injector Head.

All internal combustion engines, their exhausts, air-intakes, fuel lines, electrical equipment and controls shall be positioned a minimum of fifty (50) feet from the well centre-line.

4.4 Pressure and Function Testing4.4.1 ProceduresDuring pressure testing operations, all non-essential personnel shall be cleared from the test area and the test area cordoned off with clearly marked barriers including signs and colored chain or tape.

The Drilling / Completions Supervisor shall confirm that all flanged connections have been fitted with the correct gaskets and bolts, made up to the correct torque and in the correct sequence prior to commencing hydro-testing.

All BOP and pressure control equipment shall be function tested every seven (7) days and pressure tested:•Prior to spud or upon installation.

The issues mentioned below should be covered in the agenda; they are intended as a guide, but discussions should not be limited to just these topics:•Current and forecasted weather conditions.•Safety incidents.• Lessons learned.•Planned daily operations. •PTW requirements.•Equipment and personnel movements.•Muster stations.•Search plans.•Emergency alarms and lights, where fitted.

4.1.7 Personnel HandoversThere shall be an effective, documented crew change and shift change hand-over in place for all site-based personnel, drilling contractors’ and major service contractors’ supervisory personnel.

4.1.8 Drilling/Completion ProgramsNo operation shall be conducted unless it follows an approved Drilling Program or Completions Program.

4.1.9 Bridging DocumentsAll BHP Billiton Petroleum and contractor Supervisors and Superintendents involved in drilling and completions operations shall be familiar with relevant approved bridging documents.

4.2 Management Of Change (MOC)4.2.1 Policy ExemptionsAll BHP Billiton and contractor employees shall comply with the policies in this document. However, there may be circumstances when some policies cannot be complied with; under these circumstances, a policy exemption is required. The policy exemption shall follow the electronic MOC process (eQIP) and shall be approved by the responsible Senior Drilling and Completions Manager.

4.2.2 Procedural ChangesSignificant change to the Drilling Program or Completion Procedure shall be detailed on the Management of Change form in eQIP and subsequently approved by the original approval authority.

The electronic MOC (eQIP) process is required for any change to an approved well design, completion or programs.

Significant program changes include, but are not limited to, modification or alteration of the following aspects of any operation:•Changes to programmed Critical Elements, e.g. critical pressure

tests, LOT/FIT, casing setting depths, etc.•Equipment change from that defined in the program.•Remedial action for equipment failure that is not covered in the

program.

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4.4.2 Recording and ReportingAll pressure tests shall be recorded on a Martin-Decker chart recorder (or equivalent).

Chart recorders used shall have a measuring range such that the intended test pressure falls within 60% of the full scale reading.

All successful and unsuccessful tests shall be charted and recorded as they may have future value.

All pressure tests shall be clearly recorded in the Daily Report as having been carried out.

All electronic test charts shall be downloaded and printed.

All test charts shall be dated and clearly marked with the well number, test name, test number and time it was performed.

All test charts shall be signed off by the pump operator and the Drilling / Completion Supervisor.

All BOP and casing test charts shall be reviewed by the responsible Drilling / Field Superintendent as soon as possible after the tests are completed.

If there is doubt on the acceptance of the pressure test, the Drilling / Completions Supervisor must send a copy of the chart to the Drilling / Completions Manager for review.

All BOP and casing test charts shall be reviewed by the responsible Drilling / Field Superintendent as soon as possible after the tests are completed.

The pressure recorder charts, electronic data files and hard copy reports (all of which shall be scanned) for all successful and unsuccessful tests, shall be retained and forwarded at the end of the well to the responsible Drilling / Completions Engineer for inclusion in the well file. The pressure and function tests shall be recorded (date, duration and psi) in the daily report.

•At an interval not exceeding twenty-one (21) days.•After disconnecting or repairing any pressure control

equipment; the disconnected components shall be re-tested before being put back in service.

•After disconnecting or repairing any control system component; the entire system shall be function and pressure tested before being put back in service.

Blind and/or blind-shear rams (where fitted) shall be tested to the casing test pressure, as a minimum.

For the initial BOP test (upon installation), the annular and, where fitted, the variable-bore rams (VBR) shall be pressure tested on the largest and smallest OD drill pipe or casing to be used in the well program.

Subsequent pressure tests of the annular and VBR(s) shall be performed on the smallest size pipe to be used in the well and retested if smaller OD pipe is picked up.

An accumulator drawdown test shall be performed after:• Initial nipple up of BOPs upon contract commencement.•Any repairs that required isolation/partial isolation of the

system, or:•Every six (6) months from previous test.

Pressure test operational acceptance criteria shall be as follows:• Large volume tests (casing, tubing, etc.): 30 minutes (high

pressure).•Wellheads and trees; BOPs, lubricators and other pressure

control equipment; casing/tubing hanger seals; surface lines and treating iron – 5 minutes (low pressure) and 5 minutes (high pressure).

All pressure tests shall be held for:•The minimum times specified above.•A final flat line pressure (i.e. no bleed off) within 98 percent of

the specified test pressure.

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Section 4


•Danger tape placed below areas where working at height is being conducted (including scaffolding).

•Danger tape placed below areas where identified yet unresolved DROPS potential exists.

•Danger tape placed around the chemical- and mixing areas for pressure pumping operations.

4.5.2 Stopping the JobWe expect and authorize anyone working on BHP Billiton worksite to:•Stop to plan.•Stop if in doubt. •Stop if the plan changes.•Stop to investigate if the job goes wrong.

Everyone has the responsibility and authority to stop any job if they believe there is a danger of injury to personnel, damage to equipment or the environment.

Remember, no one has to prove it is unsafe to stop a job, but we SHALL prove it is safe before we start a job.

4.5.3 Fitness to Work and FatigueEveryone shall be fit-for-work when their work shift begins. If you feel you are unfit in any way to perform your job including being affected by fatigue or illness, you shall report this to your supervisor immediately.

Normal work durations shall be limited to twelve (12) hours.

Maximum work hours shall be limited to sixteen (16) hours,

4.5 Safe Work ProceduresBHP Billiton Petroleum Health, Safety, Environment and Community Controls (valid until June 2014)

BHP Billiton Petroleum PHSE-14-C03 Fatal Risk Controls

BHP Billiton Petroleum PHSE-13-P12 Personal Protective Equipment Procedure

4.5.1 Work Areas and AccessAll gratings, handrails and other removable equipment that could potentially become dropped objects shall be identified and included in the Dropped Object Management System on the drilling- or workover rig, coiled tubing unit or crane.

Hazardous areas shall be clearly identified with signs and/or barriers. Escape paths shall be kept clear at all times.

Barriers should be erected prior to the start of hazardous operations and removed as soon as possible after hazardous operations are completed.

Work areas in which access shall be restricted shall be identified by the use of barriers in accordance with the table below:

Exceptions: The use of danger tape is allowed without a PTW to demarcate the work area for the following tasks, for circumstances in which:•Danger tape placed around areas where lifting operations are

being conducted.

Type Purpose Requirements for use Installed by Authority for entry

Caution Tape/Chain Yellow

• To indicate that a hazardous condition or task is underway within the area.

• To restrict entry

• No PTW required.• Information tag on tape to

describe purpose.

• Any person • Persons entering shall be able to identify the hazards listed on the caution tag and abide by the conditions.

Danger Tape/Chain Red

• To indicate that a high-risk condition or task is underway within the area.

• To prohibit entry without authority.

• All tasks requiring a PTW (see exceptions below).

• Information tag on tape to describe purpose.

• PTW holder or person in charge of the work area.

• Persons entering shall: • Be directly involved in task and

obtain approval from the PTW holder or person in charge of the work.

• Be familiar with the area hazards and controls by reviewing the written risk assessment / JSA.

Structural Barriersi.e. use of scaffold tube or concrete barriers

• To prevent access into an area where a physical structure is absent i.e., removed grating, missing handrail, etc.

• To prohibited entry without authority

• To prevent damage to equipment, e.g. wellheads / Xmas trees

• PTW may or may not be required.

• Information tag on barrier to describe purpose.

• Scaffolder/ competent person where scaffold tubing used.

• Welder where welding conducted.

• Crane for heavy lifting

• Additional PTW required for access beyond barrier

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4.5.6 Working at HeightFall protection equipment and practices shall be used when:•Working in temporary access platforms/man-lifts using the

manufacturer’s approved anchor point.•Performing work on elevated (more than 4ft) surfaces without

handrails or toe boards.•Fixed ladders without fall restraint systems. Personnel shall not perform work at heights alone.

4.5.7 Weather ConstraintsNAS Severe Weather Procedure NAS Emergency Response Procedure IADC Tropical Rotating Storms General Guidelines for Land Rig Operations

Accurate weather forecasts are essential and shall be routinely monitored, with consideration to the operational aspects of the work program. Weather conditions shall be considered and a suitable weather window identified before starting any operation.

Tropical rotating storms (tornados) shall be monitored by the D&C Managers whenever they are within 1,000 miles of an operating site within their PU.

Fit-for-purpose storm shelters designed and built to ICC/NSSA Standards shall be made available on all well sites in those areas identified by Field risk assessments.

The decision to suspend operations due to adverse weather shall be made by the Drilling/Completions Supervisor in accordance with NAS Severe Weather Procedure, including the requirement that operations shall be suspended for:• severe thunderstorms, winds greater than 58 mph, tornados

and hurricanes forecast within seventy (70) miles or expected to occur within the next three (3) hours.

• lightning within a six (6) mile radius of the work place and for 30 minutes after the detected lightning strikes.

Where winds greater than 58 mph, tornados and hurricanes are forecast to occur within the next thirty (30) minutes, all site personnel must be mustered and must take shelter in the onsite storm shelter or, if such a fit-for-purpose storm shelter is not available on site, inside the heaviest steel building(s) available at the well site.

Extra precaution shall be taken during extreme heat conditions greater than 85°F and 30% humidity (refer to the Heat Stress Management Plan).

4.5.8 Hydrogen Sulphide (H2S)The Drilling/Completions Supervisor shall confirm the correct well control equipment material, elastomers and design (e.g. BOP equipped with blind shear rams) with the approved Drilling or Completion Program, as appropriate.

The Drilling/Completions Supervisor shall confirm all well control equipment certification for the proposed well work.

including travel time; this shall be followed by an uninterrupted break of at least (8) hours; this is the exception and not the rule and approval is required from Drilling Manager or Completions Manager, as appropriate, to work more than twelve (12) hours per shift.

An exception is a Drilling Supervisor or Completion Supervisor, who is considered a “day/night worker”: Night-time working hours for non-routine events and supervision of critical operations (for example cementing, well control events, etc.) are permitted. In the event operations are likely to continue, relief shall be provided.

4.5.4 Personal Protective Equipment (PPE)As a minimum, all personnel on BHP Billiton Petroleum-controlled sites shall wear:•Hard hat to recognized industry standards.•Safety glasses (clear lenses at night or in low-light areas).• Impact resistant gloves.•Safety boots (lace-up or slip-on type).•Fire Resistant Clothing (FRC – NFPA2112 compliant) coveralls or

long sleeve shirts and long trousers•Hearing protection in high noise areas, as defined by noise

surveys.•PPE requirements for eye protection forbid the wearing of

metal-framed safety glasses by electricians and electronic technicians.

Additional PPE may be required for specific tasks; always refer to Material Safety Data Sheets (MSDS), Job Risk Assessment (JRA) and Power Tool Manufacturer’s Recommendation. The following is a list of example PPE requirements:

•Face shields required for the following activities: - striking metal to metal/hammer union make-ups. - handling chemicals (i.e. including goggles): note that mesh type shields shall not be used.

- grinders (i.e. including goggles). - power washing. - disconnecting Cam-Lok connections. - disassembling spent gun connections. - venting trapped pressure, e.g. from a plug-setting tool.

•dust masks for sand/proppant handling (comply with OSHA regulations, for example when handling silica).

•Rubber boots, slicker suits, rubber gloves, goggles and face shield for tank cleaning.

4.5.5 The Buddy SystemAt no time may any individual be alone on any well site. A minimum of two (2) persons shall remain in visual contact with each other at all times while on the well site.

If two (2) persons are the sole occupants of a well site and one has to leave the well site, then both persons shall leave the well site.

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Section 4

Specific types of task that require a PTW include:•Hot work.• Isolations.•Working at height.•Confined space entry.•Complex lifts (e.g. dual crane, blind lifts).•Soft slings.•HazMat handling (e.g. acids, caustic chemicals, silica transfer).•Hydrocarbon transfers, including OBM.•Use of manual torque multipliers (e.g. pry-bars).•Explosives.•Radioactive sources.•Man riding (e.g. man-lift, cranes).•Working with pressure.•Removal of handrails, grating or permanent barriers.

After the PTW is signed by all participating personnel, the permit shall be displayed in the Toolpushers office along with the JRA. Permit posted area shall clearly define Open or Suspended Permits.

Permits shall not extend across tour changes.

Permits are no longer valid when:•The employee(s) listed on the PTW changes.•The working conditions change.•The status of the PTW changes (Permit has been marked

Completed, Suspended or Cancelled).

The Drilling / Completions Supervisor and Toolpusher / Service Supervisor(s) shall monitor, audit and review the PTWs.

4.5.12 Lock-out and Tag-out Any device that may have any energy source shall be locked-out and tagged-out prior to working on that device. Only the person(s) directly involved in the locked out device may hold the key(s) – multiple keys must be issued to a lock box if more than one individual is involved in the task.

4.5.13 Job Risk Assessment (JRA) A risk assessment shall be carried out prior to all tasks in order to plan the job, identify and eliminate or mitigate the risk from hazards associated with the task and recorded on the daily report. The JRA should include, but not be limited to, the following typical operations: rigging up and down of equipment, pressure testing, lifting, fracturing, pumping, cementing, snubbing, workover rig, slickline, electric wireline, coil tubing, swabbing, hot oiling, chemical treatments, flow back operations, chemical transfers, spill clean-up and maintenance of equipment etc.

All individuals involved in the job must participate in the JRA.

The Job Risk Assessment is a living document and should be revised prior to the introduction of any new procedure / change of procedure.

All workstrings/tubing require a DS-1 Service Category 4 inspection when working with H2S.

The Drilling / Completions Supervisor shall confirm that all systems and piping that contain H2S are properly labelled.

The Drilling / Completions Supervisor shall confirm that potential exposure points are secured from public access by the use of fences, locked gates and warning signs.

Emergency Response equipment associated with H2S operations shall be identified and provided at the well site: such H2S Emergency Response equipment shall be readily available and positioned remote from the well and any flow back equipment being used.

Visitors shall have adequate H2S training and be briefed on site, to ensure safe operations.

Personnel involved in H2S operations shall be clean-shaven, to minimize exposure to H2S while carrying out their duties; additionally they shall be subject to face-fit testing for breathing air apparatus.

Prepare Wellsite Search Plan: All personnel shall be aware of the correct search pattern if an H2S event should occur.

Wind Sock(s) shall be erected on site in clear view for all personnel to observe wind direction.

Site Medical professionals supporting operations shall know the physiological effects of H2S toxicity and its treatment.

4.5.9 Confined Space EntryEntry into confined spaces shall be subject to BHP Billiton Petroleum Fatal Risk Controls.

In addition to the requirements of the Fatal Risk Controls, when any confined space is opened (e.g., storage tanks, frac tanks, pits, void spaces, etc.), immediate and regular testing of both the confined space and adjacent spaces shall be conducted.

4.5.10 Fire Watch and Fire PreventionAll rigs and well services contracted to BHP Billiton Petroleum shall have appropriate training for fire watch personnel for all welding operations conducted at well sites. Firewatchers shall be trained to check adjacent areas and utilize a fire-watch checklist.

All fuel tanks on rigs shall be adequately identified both on the rig drawings and visually with appropriate markings to identify the hazards associated with any welding or other hot work.

4.5.11 Permit To Work (PTW)PTW is a formal written authorization used to control specific types of work activity that are identified as safety critical.

The Drilling / Completions Supervisor is responsible to approve, obtain, close, suspend and audit PTWs.

The rig Toolpusher/Service Supervisor, as appropriate, is responsible for opening PTWs and obtaining PTW approval from the Drilling/Completions Supervisor.

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4.6.2 Manual Torque MultipliersManual torque multipliers shall not be used.

The unavoidable use of manual torque multipliers shall be conducted under a PTW and be in compliance with the following:•The manual torque multiplier shall have a safe means of

releasing the stored potential energy once the work is completed.

•A provision of a secure reaction point to prevent inadvertent release of stored energy.

•A JRA shall be conducted which will consider the possibility of the unexpected release of the stored potential energy.

4.6.3 Electrical Hand Tools and Portable Electrical EquipmentAll tools, instruments, equipment and PPE employed by electricians and electronic technicians on all rigs shall be insulated and properly maintained and in good order.

4.7 Incident and Failures Reviews and Reporting 4.7.1 Incident ReportingAll incidents including injuries, near misses, spills or equipment damage shall be reported immediately to your supervisor and to the Drilling / Completions Supervisor, as appropriate, no matter how minor it may seem.

4.7.2 Failure Investigation Reports (FIRs)Failures causing NPT in excess of eight (8) hours, due either to equipment function, serviceability, procedures or supply, shall be reported, recorded and tracked through the electronic FIR (eQIP).

Failures causing NPT of less than eight (8) hours due to either equipment function, serviceability, process or supply, shall be reported and recorded through the electronic FIR (eQIP), but need not be tracked.

Entries to this system shall include a brief description of the defect and the areas shall be investigated.

All FIRs must be assigned to a Quality Assurance Engineer and the relevant Service Company, so that a thorough investigation and resolution will be assured.

The contractor controlling the work should retain the Job Risk Assessments in a searchable and retrievable format for future reference.

JRAs should always be conducted at the worksite where practical.

4.5.14 After Action Reviews (AARs)After-action reviews shall be performed on all JRAs to capture learning from tasks and to improve safe and efficient operations. AARs are used to (1) identify what went right, (2) identify opportunities for improvement and (3) edit the JRA task steps, in order to implement changes.

After-action reviews shall also be performed after every hole section and distinct operation (?).

Actions raised shall be forwarded to the responsible Engineer, who should action and produce feedback, and copied to the Superintendent.

4.4.15 Well HandoverA well hand-over form shall be completed whenever a well site, and/or a well, is handed back and forth between Construction, Drilling, Completions, Facilities, or the Production Unit; the well hand-over document shall be completed on the transfer of control of the well.

Prior to initiating well re-entry, Xmas tree valve controls and the ESD system for that well shall be formally handed over to Completions and shall remain under the sole control of Completions at all times, until the well is handed back to Production.

4.6 Working Equipment4.6.1 Welding Machines Permanent, semi-permanent and transportable welders (except MIG welders) shall be fitted with voltage reduction devices.

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22 | North America Shale Drilling and Completions Table of contents


Section 5

Operations Policies – Drilling

inspection is required.

All down hole tools shall be inspected to DS-1 Standard Service Category 3 to 5.

The Drilling Supervisor shall verify that drillstring components have been inspected at the frequencies listed below:•All drill string components shall be inspected prior to contract

commencement.•All drill pipe and HWDP shall be inspected every four (4) wells or

at the completion of a multi-well pad, whichever is greater. •All BHA components (drill collars, drilling tools, cross-overs,

non-magnetic drill collars, lift subs, etc.) shall be inspected prior to first use on each well.

The Drilling Supervisor shall witness the make-up of all BHA components assembled at the rig.

The Drilling Supervisor shall verify and record all critical dimensions (length, OD, ID, fishing neck, tool joint length and internal taper, etc.) of all equipment run or installed in the well and shall confirm that all BHA components comply with the Drilling Program.

All tubulars and BHA equipment shall be internally drifted prior to running in the hole.

A float sub with a solid float shall be run in all BHAs. Tripping and snubbing operations during managed pressure drilling, shall require two float subs with solid floats.

All drill bits, reamers, stabilizers and mills shall be gauged and calipered in and out of the hole.

5.1.5 Wireline OperationsWWD021 Completions and Well Services Guidelines

All slickline work inside the drill string shall be conducted with a full opening safety valve (FOSV) installed.

All E-line and braided line work inside the drill string shall be conducted with pressure control equipment installed to:•maintain a double barrier.•allow pack-off on the wire.•allow shut-in and removal of the wireline tools.•allow circulation of the drillstring.•enable cutting of the wire.

There shall be a kill inlet below the lower-most E-line BOP ram.

During all wireline operations, a remote operated intrinsically-safe wireline cutting device shall be available on the rig floor.

When a lubricator is used, the first pressure test shall test the entire lubricator system with E-line across the pressure control equipment. Subsequent pressure tests shall verify the integrity of the broken lubricator connection.

E-line perforating operations shall use radio-safe detonating systems.

Surface operations for the arming and disarming of guns shall not

This section shall be read in conjunction with Section 4, General Operations Policies and Section 7, Lifting and Handling

5.1 Operations♀5.1.1 PlanningInstructions to Contractors (ITC) for all drilling operations shall be issued each tour and shall include:•Detailed step by step instructions for the planned operations.•Signed approval by the Toolpusher and Drilling Supervisor prior

to operations commencing.

Calculations required for critical operations (cement volumes, displacement volumes, bottoms up volumes, FIT/LOT, etc.) shall be performed by the Drilling Supervisor and independently checked by the Toolpusher, Drilling Engineer and relevant service company operator.

5.1.2 CasingAll casing shall be tallied prior to running and counted afterwards to ensure that an accurate count of pipe in the well, and remaining on location, is maintained.

Casing tallies shall be prepared by the Drilling Supervisor or Operations Engineer and independently checked by the Toolpusher and relevant service company operator (i.e. wellhead or liner hanger operator).

Auto-fill float equipment shall not be run on any casing string that has hydrocarbons in the section being cased-off.

Instructions to contractor shall clearly state that the casing shall be filled a minimum of every thirty (30) joints (every fifteen (15) joints for 13-3/8” casing) when using conventional float equipment. When filling light pipe on starting to run casing, casing must be filled more frequently to prevent it from floating.

The Drilling Supervisor shall verify that the torque turn equipment is calibrated and that the correct torque values are being used when running premium-threaded casing.

Casing shall be pressure tested prior to drilling out the shoe track.

5.1.3 Running CasingCasing stabbing boards shall not be used unless subject to the Management of Change process and approved by the responsible DM/CM.

Circulating swages and/or casing circulating tools shall be available for use on all casing jobs.

Fit-test of circulating swages and casing circulating tools shall be performed prior to all casing running operations. The swages and circulating tools shall be pressure-rated to at least the MASP of the hole section being cased-off.

5.1.4 Drill Strings / BHAsWWD011 Drillstring Standard

All drill pipe shall be inspected to DS-1 Standard Category 3. If H2S is encountered or expected, a DS-1 Service Category 4

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Section 5

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•normal drilling operations.•air drilling, where applicable.• surface hole drilling with a diverter.• tripping operations.• casing across the BOP.•BHA across the BOP.• specific shut-in situations.

A hard shut-in procedure shall be used on all kicks. This entails closing the annular preventer (the HCR valve will already be in the closed position. Following a shut-in, pipe rams shall be closed if pressure exceeds 1,500 psi on the BOP stack. These requirements do not apply to under-balanced or managed-pressure drilling, which require field specific procedure for well control.

5.2.4 Operational ControlsA diverter shall be installed while drilling the surface hole section and shall not be removed until casing has been run and cemented; all subsequent hole sections shall be drilled with a conventional BOP installed.

The minimum distance from the wellbore to the end of the diverter vent line shall be seventy-five (75) feet.

The diverter vent line shall be securely anchored to withstand high volume fluid flow.

The diverter vent line shall have two independent and different methods of ignition.

The diverter system shall include an hydraulic actuated valve on the diverter vent line. The diverter annular and hydraulic actuated valve on the vent line shall be function tested upon installation, recorded on the DDR, and meet the following requirements:•Diverter packing element ≤ 20in: The diverter control system

shall be capable of opening the vent line valve and closing the diverter element within thirty (30) seconds.

•Diverter packing element > 20in: The diverter control system shall be capable of opening the vent line valve and closing the diverter element within forty-five (45) seconds.

The diverter annular shall be shell tested a minimum of every six (6) months.

A FOSV with appropriate crossovers shall be:•available on the rig floor at all times.• in the open position.• rigged up on a tugger line ready to install.

A fully-rated FOSV (e.g. TIW) shall be installed any time a trip is interrupted.

An inside BOP (i.e. Gray valve) with appropriate cross-overs shall be available on the rig floor at all times.

Standing orders shall be posted requiring the Driller, and mud loggers if present, to advise the Drilling Supervisor when pre-agreed hole fill discrepancies, drilling breaks, gas levels, abnormal cuttings or junk are observed.

be conducted when there is an electrical storm within ten (10) miles of the well site and for thirty (30) minutes after the detected lightning strikes.

5.2 Well Control – DrillingOperations shall stop whenever problems are experienced with any of the BOP components or the BOP control system. Operations shall not resume until the problem has been rectified unless a hazard assessment has been conducted and approved by the Drilling Manager.

5.2.1 DrillsKick, choke, and pit drills shall be conducted a minimum of every week with each crew.

Trip drills shall be conducted every trip until the Drilling Supervisor is satisfied with the response and weekly thereafter with each crew.

Stripping drills shall be carried out at campaign commencement and thereafter at three-month intervals. Each Driller shall be experienced in stripping operations.

Drills shall be designed to test the Driller’s ability to quickly detect an influx and also to quickly shut the well in.

The Drilling Supervisor shall be present for all drills and record response times on the daily drilling report.

5.2.2 BOP and Choke Manifold Line-upThe Driller shall check the status of the Driller’s BOP panel to ensure local control and verify control system pressures at the start of each tour.

The well control valve line-up shall be confirmed by the Driller and verified by the Toolpusher and Drilling Supervisor at the start of each tour. The line-up for drilling operations shall be: •Manual inner gate valve - open.•Outer HCR valve - closed.•All valves between the HCR valve and primary well control

choke (including valve to pressure sensor) – open.•Auto-choke – closed.•Manual valve downstream of primary well control choke

– closed.•Valve on line from the choke manifold to the trip tank – closed. •Valve on line from the choke manifold to the shakers – closed.•Valve on the line from the choke manifold to the Mud Gas

Separator (MGS) – open.•All other valves – closed.

Any changes to BOP/choke valve line up must be approved by the Drilling Manager.

A BOP hand wheel shall be readily accessible on location but does not need to be rigged up.

5.2.3 Well Shut-inShut-in procedures shall be posted on the rig floor and shall address:

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circulating on the trip tank.

The Driller shall set alarms for pit gain and flow show as agreed with the Drilling Supervisor; the Drilling Supervisor shall verify at the start of each tour that agreed alarms have been correctly set and are functional.

A trip tank with continuous fill shall be used to monitor the well while:•out of hole.•during all trips in and out of the hole with drill pipe, casing,

and wireline.

A trip sheet shall be completed for each trip in or out of the hole, additionally: •both calculated displacement/fill volumes and actual

displacement/fill volumes shall be recorded by the Driller on the trip sheet, to within a maximum of 0.25 bbl increments.

• final total actual displacement/fill volumes and calculated volumes shall be recorded on the daily drilling report for each trip.

• trip sheets shall be sent to the responsible Drilling Engineer daily.

If a slug is pumped, the Drilling Supervisor shall verify that the volume of fluid displacement by the slug is correct prior to tripping out of the hole.

The Drilling Supervisor and Toolpusher shall be on the floor for following operations:• start of tripping-out operations for a minimum of the first 1,000

feet and until hole fill-up is confirmed correct.•when circulating through the choke.•upon entering open hole from any casing shoe.•prior to getting back to bottom for at least the last 1,000 feet.•When back-reaming or pumping out of the hole.

For all operations, wells shall be circulated using a closed system with accurate volume (bbl-in / bbl-out) and gas monitoring. This shall include:•displacing a well to a lighter fluid.• cementing operations.•diverter drilling.

5.2.6 Air DrillingAir drilling shall use rotating well control equipment and shall be used in conjunction with a conventional BOP when drilling below the surface casing.

5.3 Cementing OperationsWWD024 Cementing Standard

Where loaded in the field, the Drilling Supervisor shall witness the loading of all cement plugs or drill pipe plugs into the cementing head and shall verify that the correct plugs are used.

For production casing strings, a fully-rated FOSV, with premium connections, shall be installed below the cement head, to allow the cement head to be removed and rigged up for wireline

Once BOPs have been installed on any well, an FIT or LOT shall be conducted upon drilling out of each casing string, other than conductor pipe.

The Driller shall flush out the trip tank at the start of each tour.

Choke and kill lines shall be circulated weekly as a minimum, and daily when mud weight exceeds 15.0 ppg.

Slow circulating rates (SCR) shall be taken with at least one pump daily and after:•BHA changes.•mud weight changes exceeding 0.2 ppg.•every 1,000ft of drilled interval.

The Driller shall complete kill sheets for all hole sections after BOPs are installed and shall update it at the start of every tour and when BHA changes are made. Updated kill sheets shall be kept on the rig floor and in the Toolpusher and Drilling Supervisor offices. The Toolpusher and Drilling Supervisor shall verify all kill sheets.

BOP space-out and tool joint space-out diagrams shall be posted on the rig floor at all times and verified by the Drilling Supervisor. The length of the tool joint internal upset shall be considered in the space-out calculation for rigs with blind-shear rams, as blind/shear rams will not shear pipe thicker than the tube.

Blind-shear and blind rams shall not be:• closed routinely when out of the hole.• tagged with the drillstring.

Tripping out of the hole with losses requires the approval of the Drilling Manager. The drillstring shall not be tripped-out if the well is not static unless:• losses are low enough to be controlled with mud on location,

or: • the gain has been measured to be declining and confirmed

as ballooning.

Bottoms up shall be circulated through the choke and Mud Gas Separator (MGS) on all trips in the hole before drilling resumes or casing cementing operations commence.

Drillstrings shall not be reciprocated through the BOP stack during well kill operations unless risk assessed and approved by the Drilling Manager (requires a MOC).

Wireline retrievable survey tools shall not be run inside the drillstring unless the well is static, unless approved by the Drilling Manager.

5.2.5 Well MonitoringFlow checks shall be conducted:•after a drilling break.•prior to tripping (including after pumping out of the hole).•prior to pulling the BHA through the BOP stack.•anytime when anomalous pit volume readings are observed.

Minimum flow check duration shall be 15 minutes with the well

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Section 5

Operations Policies – Drilling continued

operations.

The Drilling Supervisor and Drilling Engineer shall confirm that all field blend testing is complete and meets cement program specifications, before pumping cement.

Rig-specific volume controls for mud pits, water tanks, frac tanks and cement displacement shall be in place prior to every cement job. All volumes pumped into and returned from the well shall be monitored and recorded during all cementing operations.

If the plug does not bump at the calculated displacement volume, do not over-displace by more than 50% of the shoe track volume (100% of the shoe track volume in the case of horizontal production casing strings), prior to shutting down pumps to wait on cement.

After cement is in place, if it is determined that the floats are not holding, do not pump back any cement.

The shoe track shall not be drilled out until the cement has developed a minimum of 500 psi compressive strength.

Nitrified cement slurries shall not be used for any cement job once the BOP is installed..

5.4 Barriers PoliciesWWD007 Well Integrity Standard

5.4.1 Barrier Requirements - Well SuspensionWhen suspending a well, all hydrocarbon-bearing and/or permeable zones shall be isolated from surface by two (2) independent mechanical barriers including, but not limited to:•Casing.•Cement.•Mechanical plugs (bridge plugs, back-pressure valves).•Wellhead cap.•Casing hanger and seal assembly.

All mechanical barriers shall be pressure tested in order to verify their integrity.

Removal of BOPs with only one mechanical barrier in place after running and cementing casing is allowed provided all the following conditions are met:•Casing and annulus flow paths are observed and verified for no

flow for a minimum of 60 minutes.•Calculated time to achieve 500 psi cement compressive

strength has been reached for cement covering hydrocarbon bearing zones and any over-pressured zone.

•Casing hanger has been installed and the seals successfully pressure tested.

The BOP shall be replaced with the secondary mechanical barrier as soon as practical. The secondary barrier shall be capable of monitoring pressure and allowing pumping into the wellbore (kill operations).

5.4.2 Barriers Requirements – Well AbandonmentWWD007 Well Integrity Standard

All discrete permeable zones penetrated by a well shall be isolated from each other by a minimum of one cement barrier.

All hydrocarbon-bearing zones and over-pressured water zones penetrated by a well shall be isolated from the surface by a minimum of two cement independent barriers.

All normally or sub-normally pressured water-bearing permeable zones penetrated by a well shall be isolated from the surface by a minimum of one cement barrier.

Where a well is side-tracked, discrete permeable zones penetrated by the abandoned hole section shall be isolated from each other by a minimum of one cement barrier.

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Section 6

Operations Policies – Completions

absence of flow, the BOP stack acting as the secondary temporary barrier may be removed. The BOP shall be immediately replaced with a full-diameter fully rated valve and with a means of observing well pressure and pumping into the well. Where a BPV is fitted in the tubing hanger, this may be substituted by a blind flange also fitted with means of observing well pressure.

6.3 Treating / Well Testing IronAll surface treating lines shall be pressure tested prior to the start of operations. Pressure testing shall be conducted with the PRV in place, but isolated to avoid activating it. The Completions Supervisor shall verify that the PRV is placed back in service before treating operations commence.

The inspection bands on all fracture stimulation treating iron shall be visually inspected while the equipment is being hooked up. Any iron exceeding six (6) months inspection period shall not be used.

All temporary piping shall have an effective restraining system applied.

6.4 Pressure TestingThere shall be NO simultaneous operation(s) undertaken in the vicinity of pressure testing operations. In addition, treating iron shall not be connected to adjacent wells from the same pressure source.

The Completions Supervisor shall:•Ensure the pump operator knows volume(s) being tested, the

test pressures to be applied, the hold durations of the tests and the number of pressure tests to be performed.

•Ensure that a line pressure test is carried out and all gauges are checked for calibration before pressure testing.

•For any in-flow tests, ensure that both the applied pressures and bled off pressures are recorded, then monitor for pressure build up.

•Ensure that all test pressures are bled off slowly.•Ensure that any annular pressure is not vented-off without

utilizing lubricate and bleed techniques, to ensure that annuli are kept fluid filled. A low-pressure reference pressure shall be left on the annulus for verification purposes.

6.5 Well ControlThe Completion and Well Servicing Supervisors are responsible for ensuring that correct well control practices and the implementation of well control procedures are applied.

6.5.1 Pressure Control Equipment (PCE)Pressure control equipment (PCE), e.g. BOP stack, full opening safety valves, etc, shall be installed for all well work and rigged up in accordance with the Completions Program or WWD005 Well Control Standard. A pressure and function test shall be performed prior to commencement of operations.

Any connection of the PCE that has been broken shall be re-tested

This section shall be read in conjunction with Section 4, General Operations Policies and Section 7, Lifting and Handling

WWD021 Completions and Well Services Guidelines

6.1 Well Site Area Classification (Red Zone)In addition to the industry-standard hazardous area zoning shown in Section 4.3, for all high pressure fracturing or pumping operations, a designated Red Zone shall be established around high pressure fracturing / pumping equipment and lines.

At no time shall personnel be allowed in this Red Zone while equipment is under pressure test, or while pumping operations are being conducted using temporary pipework.

Hydraulically operated valves should be used whenever possible, to minimize personnel exposure to high-pressure areas.

Entry for legitimate equipment manipulation/inspection operations shall be allowed only after de-pressurizing.

6.2 BarriersWhen only a single primary barrier is in place (i.e. no secondary barrier is available), a Risk Assessment shall be conducted and the Completions Manager’s approval obtained prior to operations proceeding.

A hydrostatic overbalance shall never be considered as a permanent independent barrier.

Barriers testing and verification requirements prior to well suspensions shall be included in the drilling/ completions program.

All permanent or temporary barriers shall be verified as per WWD007 Well Integrity Standard.

All mechanical barriers shall be tested in the direction in which pressure shall be held, in order to verify their integrity.

6.2.1 Xmas and Frac Stack TreesWhere Xmas tree valves require repair or removal, a minimum of two tested mechanical barriers shall be placed upstream of the valve being repaired. The valve being repaired shall also be isolated from downstream pressure by a double block-and-bleed system.

6.2.2 Well SuspensionSuspended wells shall be left with two independent, tested temporary barriers.

BOPs, Xmas trees, frac stacks and pressure control equipment shall not be nippled down until at least two temporary barriers have been installed and tested in the flow stream and annulus.

When suspending a well, permeable zones penetrated shall be isolated from surface by two independent temporary barriers.

In the case of highly impermeable zones that require hydraulic fracturing in order to flow, properly tested and cemented un-perforated casing may be considered as the primary temporary barrier. If the well is filled with fluid and the fluid level is monitored for flow for a sufficient period of time to confirm the

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Sectioni 6

Operations Policies – Completions continued

floor at all times, with closing key and appropriate crossovers.

When running completion hardware a suitable kill joint shall be used for proper BOP space-out. In addition:•FOSVs shall be left ready in the OPEN position for installation.•The FOSV shall be stabbed and made up onto the work string

every time a trip is interrupted.

Run a float in all work strings unless the procedure requires to reverse circulate or tool string function will not allow.

All equipment run into a well shall be measured (length, OD, ID, fishing neck, shear pins ), drifted and/or gauged and its position in the string noted in the completion well file.

All tubulars shall be tallied and their positions in the string recorded while being run.

The Completions Supervisor (CSV) shall verify all tubular tallies and operational calculations (displacement volumes, bottoms-up volumes, etc).

When a packer or shear set device is included in the completion, the value and number of shear devices shall be recorded on the completions report.

Flow checks shall be conducted:•Prior to tripping (including after pumping out of the hole).•Prior to pulling the BHA through the BOP stack.•Anytime when anomalous pit volume readings are observed.

Minimum flow check duration shall be 15 minutes with the well circulating on the trip tank.

The Driller shall set alarms for pit gain and flow show as agreed with the Completion Supervisor.

A trip tank with continuous fill shall be used to monitor the well while:•Out of hole.•During all trips in and out of the hole with drill pipe, casing, and

wireline.

A trip sheet shall be completed for each trip into or out of the hole, additionally:

•Both estimated displacement/fill volumes and actual displacement / fill volumes shall be recorded by the Driller on the trip sheet to within a maximum of 0.25 bbl increments.

•Final actual displacement/fill volumes and calculated volumes shall be recorded on the Daily Report for each trip.

•Trip sheets shall be sent to the office daily.

If a slug is pumped, the Completion Supervisor shall verify that the fluid volume displaced is correct prior to tripping out of the hole.

The Completion Supervisor and Toolpusher shall be on the floor for following operations:•Start of tripping operations for a minimum of the first 1,000

feet and until hole fill-up is confirmed correct.•When circulating through the choke.

prior to exposing it to operating pressure.

All PCE components shall have minimum IDs measured and compared against maximum ODs of tools being run, by being drifted with an appropriately-sized API drift.

During all workover and snubbing operations, wells shall be shut in on a ram preventer when surface pressure exceeds, or may exceed, 1,500 psi.

When displacing a well to a lighter fluid, wells shall always be displaced using a closed system and with accurate volume monitoring, i.e. barrels in- and out or PVT monitoring.

6.6 Drills Drills and exercises shall be held to confirm the effectiveness of emergency response plans. Refer to WWD005 Well Control Standards for all activities. (i.e. Coiled Tubing, Fracturing, Snubbing, and Wire line)

Drills should only be conducted when well / hole conditions are safe and there is no conflict with other operations.

6.7 Well MonitoringPrior to commencement of operations, a trip sheet shall be filled out with hole volumes, displacement volumes, pipe and annular capacities, fluid weights, measured and true vertical depths. The trip sheet shall be verified by Completion or Well Servicing Supervisor.

Shut-in tubing, casing annuli and surface casing pressures shall be recorded every tour and included on the Daily Report.

Monitor surface casing throughout all well operations (i.e. all surface casing valves are in the OPEN position and pressure gauge installed, relief valve installed dependent on the operation – fracture stimulation). Surface casing pressure shall not exceed design limits. If pressure is recorded on surface casing, stop and report findings to Completion Superintendent for guidance on path forward.

Wellbore conditions (i.e. fluid level, pressure, flow check, etc) shall be monitored at all times during well work operations.

A fluid weight should provide the appropriate overbalance (pressure gradient) to control formation pressure, unless otherwise dictated in the well procedure.

When top filling a tubing string, maintain 75 psi maximum differential at current depth.

When well operations are temporary suspended (e.g. driller leaves the rig floor, shut down for night, etc), the well shall be shut in such that primary and secondary barriers are in place in all potential flow paths.

A calibrated portable gas tester / monitor (e.g. Crowcron Triple or similar) shall be available on location at all times.

6.8 Work overTwo full-opening safety valves (FOSV) shall be available on the rig

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in CT unit. These procedures should at least discuss pressure testing, hole fill discrepancies (bbl in/bbl out), run speed, chain traction, PVT alarms and variances, gas levels and junk observed in the well.

Emergency shut in procedures shall be posted in the CT unit ( i.e. pinhole leak at surface, collapsed CT string or leak at stripper).

Both the Completions Supervisor and the CT service contractor shall review the service history of the coil prior to CT operations commencing.

CT Life Cycle shall be monitored throughout the CT operation. All CT runs shall be modelled prior to operations.

The Completions Supervisor shall verify that the Nitrogen has been checked for purification.

Where eCoil is used, a logging head with dual check valves and two stage release method (pump pressure and tension) shall be used. The Completion Supervisor shall ensure that the weak point calculations for eCoil have been performed prior to running in the well.

6.11 Hydraulic Fracturing OperationsAll Frac stacks shall be equipped with a minimum of:•Crown valve.•Goat Head with either a 3 inch 1502 or 4 inch 1002 WECO

hammer union.•Swab valve.•Flow Cross with choke and kill flanged inlets.•Additional valve.

All the above valves shall have wireline shearing capability and the upper-most shall be remotely-operated.

Any operation beyond single well requires a manifold (i.e. zipper) of the same pressure rating as the piping system.

The integrity of the night-cap connection shall be pressure tested and verified prior to frac operations commencing.

All surface lines and frac equipment should be rigged up in accordance with the approved lay-out and PandIDs.

The electric line BOP and night-cap should be rated for the maximum anticipated pressure during fracture operations.

The fluids and material (e.g. frac fluids, frac sand, etc) quality control tests should be verified by the Completions Supervisor and Frac Service Supervisor prior to pumping into the well.

6.12 WirelineElectric-line, slick-line, braided and swab wireline PCE shall be equipped to provide a primary and secondary barrier as a minimum:•Tool trap.•Flanged pump-in sub equipped with 2 inch 1502 hammer union.• Two wire rams with grease injection between rams (braided line only).•Blind ram.• A remote operated valve capable of cutting wire and acting as a barrier.

All wells shall be circulated using a closed system with accurate volume monitoring, including when displacing a well to a lighter fluid.

6.9 SnubbingAll Workover policies shall apply equally to snubbing operations.

All snubbing BOP stacks shall be equipped with a minimum of:•Stripper rubber.•Annular preventer.•Pipe ram.•Pipe ram.•Blind ram.•Shear ram (i.e. capable of shearing pipe).

Written instructions and specific work duties and tasks shall be assigned to personnel.

The secondary BOP control panel shall be positioned at least 75 ft from the wellhead in clear view of the work basket.

All pipe snubbed into the wellbore should have at least a BHA consisting of a check valve, landing nipple one joint above the check valve or a standing valve as a contingent isolating device.

The accumulator controls require mechanical guards to prevent accidental operation. These controls should be clearly labelled.

Drift the BOP before installing the jacking unit.

An individual escape line should be rigged and available for each person working atop hydraulic snubbing equipment

Volumes of all fluids being pumped into or bled from well during snubbing or stripping operations shall be measured and recorded.

All personnel shall be aware of the established maximum pressure limit under which safe stripping procedures are permissible.

The work string / tubing should be top-filled every 5 joints.

6.10 Coiled TubingAll coil tubing stacks shall be equipped with a minimum of:•Stripper rubber.•Blind ram.•Shear ram.•Slip ram.•Pipe ram.

Where the SITP is above 5,000 psi, additional Pipe / Slip rams and stripper shall be installed on the CTU BOP and flanged directly onto the tree or wellhead.

All coil tubing bottom hole assemblies shall be equipped with dual back pressure valves and hydraulic release sub.

The CT Service supervisor shall complete a trip sheet record for each trip RIH/POOH.

Completions Supervisor Instructions to Contractor shall be posted

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Sectioni 6

Operations Policies – Completions continued

Clear the line of fire of all unnecessary personnel prior to arming, disarming or in the presence of an explosive device.

The person arming or disarming an explosive device shall keep the Safety Key in his possession.

The Safety Key shall remain outside the wireline unit until the explosive device has been introduced into the well and has reached a minimum depth of 200 feet below ground level.

Detonators shall be inserted into a Blasting Cap Safety Tube and the top of the tube closed prior to electrically arming a perforating gun by connecting the detonator wires to the gun wires.

6.13.2 Running / Pulling Explosive DevicesWhen running explosive devices in the well, wait until a minimum depth of 200 feet below ground level before turning on the safety switch, restoring AC Power and turning on essential RF transmitters.

When pulling explosive devices from the well, stop at a minimum depth of 200 feet below ground level prior to re-establishing RF silence and preparing the instrument cab for explosives operations. Remove the Safety Key and verify that the Casing-to-Rig voltage is less than 0.25V (AC and/or DC).

If a lightning storm arrives when pulling explosive devices from a well and before being able to complete the disarming operation, the explosive device shall be kept in the well at a minimum depth of 200 feet below ground level.

•Flanged directly to the wellhead or tree.

The first lubricator pressure test shall test the entire lubricator system with wire across the lubricator pack-off device; subsequent tests shall verify the integrity of the re-made lubricator connection.

When a fully-rated nightcap is installed for any pump-down operation, the nightcap shall include a needle valve.

6.13 Perforating and Explosive Devices6.13.1 Handling, Arming and DisarmingAll handling, arming, disarming and running/pulling operations shall be conducted strictly in conformance with the service contractor’s standard operating procedures.

Consult local weather forecast services for potential lightning storms and severe weather prior to initiating any perforating or explosive operations.

Surface operations for the arming/disarming of guns shall not be conducted when there is an electrical storm within 10 miles of the well site and for 30 minutes after the detected lightning strikes.

A sign reading “Danger Explosives – Turn off Radio Transmitters” shall be placed at the entrance to location.

Only remove the explosives required for immediate use from the storage magazine.

Power shall NOT be applied through an explosive device, whether ARMED OR UNARMED, at any time while on the surface.

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6.14 Well Testing OperationsWWD017 Well Test Guidelines

The Completions Supervisor shall verify that all well test equipment and piping is within the validity of its current certification and that it will remain so for the intended duration of the well test.

Well testing procedures shall include approved hydrate mitigation and contingency management plans for all wells where potential for hydrate formation exists.

The well stream shall be monitored for H2S and other potentially hazardous components.

All well testing pipe work shall be thickness checked prior to testing operations to confirm no metal erosion.

If H2S has not been anticipated and in excess of ten (10) ppm is detected, the well test shall be suspended, a HAZOP shall be conducted and appropriate controls and mitigations implemented prior to continuing operations.

Equipment layout diagrams and piping and instrumentation drawing (PandID) shall be available on site.

The Completions Supervisor and well test supervisor shall verify line-up and correct functioning of all ESD systems from a remote location.

An ESD system shall be installed and shall function closed in less than ten (10) seconds.

6.13.3 Misfired Perforating Gun(s)Never troubleshoot an armed explosive device.

Once safe to do so, prepare to disarm the perforating gun(s): •While wearing a face shield, safely relieve all perforating guns

of any trapped pressure immediately upon removal from the well. All pressure relief parts shall be positioned facing away from personnel.

•Disarm the perforating gun(s) ballistically (by cutting the detonating cord below the detonator) and then electrically (by cutting the detonator wires).

Misfired detonators shall be packed in the detonator carrying case after shunting their leads.

All explosive remnants shall be packed in explosives remnants boxes and returned to the explosives magazine for storage and proper disposal.

6.13.4 Misfired TCP Gun(s)In the event that TCP gun(s) do not fire, the following additional conditions shall apply:•Never pull out of hole with a drop bar in the TCP string.•Never apply pressure to the tubing or the annulus and always

avoid shocks to the TCP string while pulling out of the hole.

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Section 7

Lifting and Handling

completed at the start of every tour or if there is a change of operator. This checklist shall be provided to the Drilling / Completions Supervisor upon completion.

Man-riding tugger wires shall replaced every 6 months with new wire.

Utility tugger wires shall replaced every 12 months with new wire.

Tugger (winch) wires shall not be re-terminated on-site. All re-terminated tugger wires shall be load tested by a qualified inspector.

7.2 Lifting OperationsHands-free lifting devices shall be used on all lifting operations. Personnel must maintain a minimum of 4 feet distance between themselves and the load.

If hands-free lifting cannot be performed safely, then the lift shall be conducted under a Permit to Work.

If after a risk assessment (JSA/JRA), it is determined that tag lines are necessary to assist in the control of a load during lifting operations, the tag line used shall be constructed as follows: • coated with a non-slip material for ease of grip and to prevent

slipping through gloves.• semi-rigid (coil resistant) to prevent snagging and looping

around fixtures and fittings.

All tag lines shall be fitted with a large karabiner, or safety hook, to allow attachment to the load.

Third-party lifting equipment shall not be lifted, moved, operated or repaired unless the appropriate third-party personnel are supervising the task. The only exception is when the equipment is to be lifted and the item has been pre-slung by the third-party and meets BHP Billiton Petroleum lifting requirements.

Man-riding baskets shall be designed with a solid floor, kick plates, internal handrails, a harness anchor point, positive locking inward opening gate and fitted with primary and secondary slinging.

Personnel working inside a man-riding basket shall be tied-off to the basket.

Operators of mobile lifting machines shall be trained and certified to nationally-approved standards, i.e. NCCCO (Cranes); OSHA (Forklifts, Telescopic Forklifts and Man lifts).

Where it is necessary to use a crane to give access to rig personnel for work in inaccessible locations, such operations shall be subject to issue of a Permit to Work. These operations shall be allowed only when no other practicable means of accessing the work location are available.

All lifts over process/hydrocarbon-containing systems should be avoided wherever possible, but in all cases shall be fully risk assessed, have a detailed lift plan approved by the Drilling / Completions Manager and be subject to Permit to Work (PTW).

7.1 Lifting Equipment Inspection and CertificationBHP Billiton Petroleum HSEC Controls (valid to June 2014), Fatal Risk Controls, Control 8 Lifting Operations

BHP Billiton Petroleum PHSE-14-P01 Lifting Operations Procedure

BHP Billiton Petroleum PHSE-14-P02 Lifting Equipment Control and Operations

The owners of lifting equipment used in BHP Billiton Petroleum operations worldwide shall be able to show documentary evidence that the equipment was designed, manufactured, tested, inspected and maintained to the relevant standards and specifications referred to in BHP Billiton Petroleum PHSE-14-P02 Lifting Equipment Control and Operations.

A pre-start-up audit of lifting equipment shall be conducted by an independent competent specialist. This audit should include all rig and service contractor operations.

All lifting equipment and accessories, including lifting-eyes, shall be inventoried and entered into a lifting register owned and maintained by the rig contractor. The lifting register shall be maintained during the entire contract period.

All lifting equipment shall be inspected and certified by a qualified inspector. The equipment shall be clearly marked with a unique identification number, rated capacity (or safe working load) and color-coded for the validity of the certification period. The certification period shall be renewed and color-coding changed every 6 months.

The inspection frequency for lifting equipment shall be as follows:•Cranes shall be inspected annually.•Cranes and hoists used for lifting personnel shall be inspected

every 6 months

•All other lifting equipment shall be inspected every 6 months

All lifting eyes shall be load tested and NDT’d when initially put into service and re-certified every 6 months by a qualified inspector. Design documentation and certification for lifting eyes shall be available on-site.

Lifting eyes installed without evidence of design documentation, approved welding standards, material composition and other certification and test documentation shall be removed from service and destroyed.

Working-at-height harnesses and lanyards shall be inspected prior to each use and removed from the rig if damaged. The date of first use shall be recorded for each working-at-height harness and lanyard in service.

All working-at-height harnesses and lanyards shall be inspected monthly by an OEM-approved inspector and replaced after no longer than 12 months after manufacture or 6 months in service, whichever occurs first.

All mobile lifting machines shall have an inspection checklist

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Section 7

Lifting and Handling continued

Chains shall not be used for lifting but may be used for:• load binders / tying down loads on vehicles.• removing or replacing rotary table bushings from a rotary table.•pulling and handling loads, as long as the load is not suspended

by the chains and does not pose a “dropped object” hazard in the event the chain should fail while under tension.

•Tail chains on winch-trucks and haul-trucks are allowed provided they are secured to the wire rope using a swaged or machine fitted termination.

7.3 Crane Hooks, Shackles, Slings and ChainsCrane hooks shall be of a positive locking design. If a crane hook is fitted with an operating trigger, the trigger shall be flush or recessed within the body of the hook.

Four-part shackles are the only type shackles approved for use.

All lifting slings shall be made from wire rope; an exception is the use of synthetic slings under a Permit to Work for handling of chrome tubulars or other delicate cargoes that could be severely damaged by wire rope slings.

All synthetic slings shall be scrapped after the earlier of six (6) months in service or twelve (12) months from the date of manufacture.

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Section 8

Well Design and Operations Well Control Equipment Policies

Well designs shall be based upon the following flow-charts:

8.1 ‘Low’ H2S Concentrations

Well Type III

• Premium Production Casing and Tubing

• 2 tree master valves (UMV fail-safe closed)

• Packer and SCSSV required• Platform wells

(gas-lifted) – risk assess for annulus safety valve

Well Type II



• Packer required

• No SCSSV required

Start hereOffshore

Well?

Will the well flow naturally to

surface?

Is the well within 500ft

of a public place or an environmentally

sensitive area?

Yes

Yes

Yes

Is the well AOFP

(MMSCFD x PPM) more than 0.03

MMSCFD of H2S?

No

YesGo to

next page

Well Type I

• API Production Casing and Tubing

• No packer required


Drilling Rig

Blind Rams Only (No Shears)

Workover Rig


Snubbing Unit

Shear Rams Required

Drilling Rig


Workover Rig


Snubbing Unit

Shear Rams Required

Drilling Rig

Shear Rams Required

Workover Rig

Shear Rams Required

Snubbing Unit

Shear Rams Required

No

No

No

NOTE: “Premium” means metal-to-metal seal, gas tight under all expected load conditions for life-of-well, qualified to ISO 13679.

“Public place” includes: public road; railroad; navigable waters; permanent habitation.

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8.2 ‘High’ H2S Concentrations

Yes

Is the well within 3 miles of a

public place or environmentally

sensitive area?

Is the well AOFP

(MMSCFD x PPM) more than 0.3 MMSCFD of

H2S?

No

Yes

Well Type II



• Packer required


Drilling Rig


Workover Rig


Snubbing Unit

Shear Rams Required

Well AOFP (MMSCFD x PPM) is more than 0.03 MMSCFD of H2S

Is the well within 2,600ft

of a public place or an environmentally

sensitive area?

No

No

Is the well AOFP


H2S?

No

No

Well Type III



• Packer and SCSSV required

• Platform wells (gas-lifted) – risk assess for annulus safety valve

Drilling Rig

Shear Rams Required

Workover Rig

Shear Rams Required

Snubbing Unit

Shear Rams Required

No

Is the well AOFP


H2S?

Is the well within 5,000ft of a

public place or an environmentally

sensitive area?

Yes

Yes

Yes

Yes

NOTE: “Premium” means metal-to-metal seal, gas tight under all expected load conditions for life-of-well, qualified to ISO 13679.

“Public place” includes: public road; railroad; navigable waters; permanent habitation.

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Section 9

Language

Acronym Definition

MASP maximum allowed surface pressure

MGS mud gas separator

MOC Management of Change

NACE National Association of Corrosion Engineers

NAS North America Shale

NDT non-destructive testing

NMDC non-magnetic drill collar

OCTG oil country tubular goods

OEM original equipment manufacturer

PandID piping and instrumentation diagram

PBR polished bore receptacle

PCE pressure control equipment

PFD processflowdiagram

PPE personal protective equipment

PRV pressure relief valve

PTW permit to work

PU Production Unit

QA quality assurance

QC quality control

RT rotary table

RTTS retrievable, treating, testing and squeezing

SCR slow circulating rates

SCSSV surface-controlled subsurface safety valve

SDE Senior Drilling Engineer

SIMOPs simultaneous operations

SV swab valve

SWL safe working load

SWP safe working pressure

TBCS travelling block control system

UBD under-balanced drilling

UMV upper master valve

UPS uninterrupted power supply

WellCAP Well Control Accreditation Program

WOC waiting on cement

WWD World Wide Drilling

Acronym Definition

AD Assistant Driller

AFE Authority for Expenditure

ANSI American National Standards Institute

API American Petroleum Institute

ASNT American Society of Non-destructive Testing

BHA bottom hole assembly

BHCT bottom hole circulating temperature

BHST bottom hole static temperature

BOP blowout preventer

BOWD basis of well design

CCE Cement Company Engineer

CCU cargo carrying unit

CSG Customer Sector Group

CSV Completions Supervisor

CT coiled tubing

D&C Drilling and Completions (department)

DE Drilling Engineer

DM/CM Drilling Manager/Completion Manager

DMS Drilling Management System

DS Drilling Superintendent

DSV Drilling Supervisor

ERW electrical resistance weld

ESD emergency shutdown device

FOSV full opening safety valve

GOR gas oil ratio

H2S hydrogensulfide

HAZOP Hazard and Operability Analysis

HP high pressure

HPHT high pressure, high temperature

HSEC Health, Safety, Environment and Community

HWDP heavy-weight drill pipe

IADC International Association of Drilling Contractors

IWCF International Well Control Forum

JRA job risk analysis

JSA job safety analysis

LMV lower master valve

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Table of contents

10185_NASDC-WWD000LPolicies - Valid through September 2014

BHP Billiton Petroleum1360 Post Oak Boulevard Houston Texas 77056 3020 USATelephone 1 713 961 8500 Drilling Fax 1 713 961 8465

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