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Well Construction Project Execution Plan Golfinho-Atum Development

Well Construction Project Execution Plan

Golfihno-Atum Development Document No. GF-090-AM1-CP-PEP-00001

Rev. 0 Rev Date: 5-30-18

G-A Development Well Project Execution Plan - Submitted - CONFIDENTIAL

Table of Contents 1 PROJECT OVERVIEW ....................................................................................................................... 8

1.1 INTRODUCTION ......................................................................................................................... 8 1.2 ACRONYMS AND DEFINITIONS ..................................................................................................... 8 1.3 OVERALL PROJECT SCOPE .......................................................................................................... 10 1.4 PROJECT DESCRIPTION ............................................................................................................. 10 1.5 PROJECT OBJECTIVES AND GOALS .............................................................................................. 12 1.6 PEP UPDATE PROCESS ............................................................................................................... 12

2 WELL CONSTRUCTION STRATEGY ................................................................................................... 13

2.1 CORE VALUES .......................................................................................................................... 13 2.2 MANAGEMENT SYSTEM ............................................................................................................ 13 2.3 WELL CONSTRUCTION PROCESS ................................................................................................. 14 2.4 EXECUTION FRAMEWORK ......................................................................................................... 15

3 WELL CONSTRUCTION PLAN .......................................................................................................... 17

3.1 WELLBORE CONFIGURATION ..................................................................................................... 17 3.2 OPERATIONAL SEQUENCE ......................................................................................................... 18 3.3 CAMPAIGN SCHEDULE .............................................................................................................. 19

4 PERSONNEL AND ORGANIZATION ................................................................................................... 22

4.1 RESOURCE ALLOCATION ........................................................................................................... 22 4.2 POSITION DESCRIPTIONS & COMPETENCY ................................................................................... 22 4.3 ORGANIZATION STRUCTURE ...................................................................................................... 22 4.4 JOB POSITIONS ........................................................................................................................ 23 4.5 JOB DESCRIPTION ..................................................................................................................... 25 4.6 LOCAL WORKFORCE DEVELOPMENT .................................................................................................. 27 4.7 RESOURCE TEAMS .................................................................................................................... 28

5 HEALTH, SAFETY AND ENVIRONMENT ............................................................................................. 29

5.1 INTRODUCTION ....................................................................................................................... 29 5.2 REGULATORY COMPLIANCE ...................................................................................................... 30 5.3 ENVIRONMENTAL MANAGEMENT PLAN ..................................................................................... 31 5.4 CONTRACTOR HSE MANAGEMENT ............................................................................................. 31 5.5 SECURITY ................................................................................................................................ 31 5.6 EMERGENCY PREPAREDNESS AND RESPONSE .............................................................................. 32 5.7 INCIDENT REPORTING AND INVESTIGATION ................................................................................ 32

6 OPERATION SUPERVISION ............................................................................................................. 34





6.1 HSE CRITICAL AND NON ROUTINE OPERATIONS ........................................................................... 34 6.2 HSE AND OPERATIONALLY CRITICAL EQUIPMENT ......................................................................... 34 6.3 UNPLANNED EVENT NOTIFICATION ............................................................................................ 35 6.4 MANAGEMENT OF CHANGE ...................................................................................................... 35 6.5 CONSENTS ................................................................................................................................. 37

7 RISK MANAGEMENT ..................................................................................................................... 38

7.1 HAZARD ANALYSIS PROCESS ...................................................................................................... 38 7.2 CAMPAIGN RISK ASSESSMENT ................................................................................................... 39 7.3 WELL RISK ASSESSMENT............................................................................................................ 39 7.4 OPERATIONS RISK ASSESSMENT ................................................................................................. 40 7.5 RISK MANAGEMENT DURING OPERATIONS ................................................................................. 41 7.6 POST CAMPAIGN REVIEW ......................................................................................................... 41

8 CONTRACTS & PROCUREMENT ...................................................................................................... 43

8.1 INTRODUCTION ....................................................................................................................... 43 8.2 CONTRACTING PROCESS ........................................................................................................... 43 8.3 RIG SPECIFICATION AND CONTRACTING STRATEGY ...................................................................... 44 8.4 MAJOR SERVICES CONTRACTING STRATEGY ................................................................................ 44 8.5 CONTRACT BUNDLING AND PRIORITIZATION ............................................................................... 45 8.6 CONTRACTOR MANAGEMENT ................................................................................................... 45 8.7 CONTRACTOR HSE MANAGEMENT ............................................................................................. 47

9 QUALITY ASSURANCE .................................................................................................................... 49

9.1 PROCESS DESCRIPTION ............................................................................................................. 49 9.2 PROCESS OUTLINE .................................................................................................................... 50

10 LOGISTICS ................................................................................................................................... 53

10.1 INTRODUCTION ....................................................................................................................... 53 10.2 LOGISTICS BASE ....................................................................................................................... 53 10.3 PORT FACILITY OPTIONS ............................................................................................................ 54 10.4 TRANSPORTATION ................................................................................................................... 56 10.5 PROJECT SUPPORT PLAN ........................................................................................................... 56

11 INFORMATION & DOCUMENTATION MANAGEMENT ........................................................................ 58

11.1 DOCUMENT CONTROL .............................................................................................................. 58 11.2 CAMPAIGN PLANNING REPORT .................................................................................................. 58 11.3 DAILY RIG REPORT .................................................................................................................... 59 11.4 STATUTORY, MANAGEMENT AND PARTNER REPORTING .............................................................. 59 11.5 WELL PERFORMANCE SUMMARY ............................................................................................... 59





11.6 END OF WELL REPORT .............................................................................................................. 60 11.7 TECHNICAL BULLETIN AND AUDIT FINDINGS ................................................................................ 60

12 PERFORMANCE MONITORING ....................................................................................................... 62

12.1 KEY PERFORMANCE INDICATORS ............................................................................................... 62 12.2 HSE & TECHNICAL PERFORMANCE INDICATORS ........................................................................... 62 12.3 COMMUNICATION AND DATA ANALYSIS ..................................................................................... 64 12.4 DRILLING CURVES AND OTHER MEASUREMENTS ......................................................................... 65 12.5 COST REDUCTION ..................................................................................................................... 65 12.6 BENCHMARKING ...................................................................................................................... 65

13 REVIEW & AUDIT .......................................................................................................................... 67

13.1 CAMPAIGN PLANNING REVIEW (DWOP/CWOP) ........................................................................... 67 13.2 POST WELL REVIEW AND CAMPAIGN WRAP UP ........................................................................... 67 13.3 AMS REVIEW ........................................................................................................................... 67 13.4 TECHNICAL AUDIT .................................................................................................................... 67

APPENDIX I: NOTIONAL RIG SPEC ............................................................................................................... 69

APPENDIX II: AMA1 DRAFT RIG CONTRACTING STRATEGY ............................................................................. 73

APPENDIX IIIA: AMA1 DRAFT SUPPORT SERVICES CONTRACTING STRATEGY .................................................... 78

APPENDIX IIIB: CONTRACTS LIST & PRIORITIZATION ...................................................................................... 89

APPENDIX IV: LOGISTICS REQUIREMENT ..................................................................................................... 91

APPENDIX V: PROJECT LEVEL RISK MATRIX .................................................................................................. 93

APPENDIX VI: CAMPAIGN LEVEL TOP RISK ................................................................................................... 95





List of Figures Figure 1-1: Golfinho-Atum Field Location Map ......................................................................................... 11 Figure 2-1: Well Delivery Process .............................................................................................................. 15 Figure 2-2: Execution Framework .............................................................................................................. 16 Figure 3-1: Wellbore Configuration ........................................................................................................... 18 Figure 3-2: Notional Well Construction Schedule ..................................................................................... 21 Figure 4-1: Well Construction Org Chart ................................................................................................... 24 Figure 7-1: Risk Assessment Levels ............................................................................................................ 39 Figure 7-2: Risk Assessment Matrix ........................................................................................................... 42 Figure 9-1: Campaign Quality Plan ............................................................................................................. 52 Figure 10-1: Satellite Image of Pemba Port Facility .................................................................................. 54





List of Tables Table 8-1: Contract Responsibility Matrix ................................................................................................. 43 Table 12-1: Technical Performance KPIs ................................................................................................... 64





1 PROJECT OVERVIEW

1.1 INTRODUCTION

This document is the Project Execution Plan (PEP) for well construction of the Golfinho-Atum Field. This PEP outlines key strategies, procedures and processes that will be used to successfully execute the Well Construction Plan (GF-090-AM1-CP-BOD-00001). In addition, this document provides details of the campaign objectives and technical scope.

The scope of this PEP covers the well construction process. The well construction team will use this PEP to ensure alignment with the project’s business objectives and as a road map for detailed planning. The document will also serve as a medium to communicate the execution plan to broader GA upstream teams (Subsurface and Subsea Functions), service support teams (C&P, Logistics, HSE, Aviation, ITS, Security), Contractors, management, partners (via DSPs) and other stakeholders.

In addition, this PEP will be used to,

• Document campaign objectives with respect to HSE obligations, requirements, standards and initiatives.

• Clarify roles and responsibilities within the team with respect to core management processes. • Define interfaces, responsibilities and communication internal and external to the well construction

team. • Define broad execution strategies that will be adopted for the phases of the campaign • Outline contracting strategies and processes to effectively provide all major equipment and services. • Describe campaign controls with respect to cost, schedule, MOC and reporting. • Outline transition strategies for final ownership handover to the Production Operations team

1.2 ACRONYMS AND DEFINITIONS

AMA1 Anadarko Moçambique Área 1 Limitada APC Anadarko Petroleum Corporation API American Petroleum Institute BML Below Mud Line BOP Blow Out Preventer Bscfd Billion standard cubic feet per day CMP Contractor Management Plan C&P Contracts and Procurement CXT Christmas Tree CWOP Complete Well on Paper Sessions CWOR Completions & Workover Riser DOA Delegation of Authority DUAT Direito de Use e Aproveitamento da Terra (State granted land right to use and profit) DSP Decision Support Package





DWOP Drill Well on Paper sessions EIA Environmental Impact Assessment EMP Environmental Management Plan ENH Empresa Nacional de Hidrocarbonetos (National Oil Company) ENI Area 4 Operator EPC Engineering, Procurement, and Construction EPCC Exploration and Production Concession Contract EPCI Engineering, Procurement, Construction, and Installation ERP Emergency Response Plan FID Final Investment Decision (FID) GA Golfinho-Atum Field GoM Government of Mozambique HPWHH High Pressure Well Head Housing HR Human Resources HAZOP Hazard and Operability Study HAZID Hazard Identification HSE Health, Safety, and Environment INP Instituto Nacional de Petróleos (Oil & Gas Regulatory) ISO International Organization for Standardization ITP Inspection and Testing Plan ITT Invitation to Tender IWOCS Installation and Workover Control System KPI Key Performance Indicators LNG Liquefied Natural Gas LPWHH Low Pressure Well Head Housing MARPOL International Convention for the Prevention of Pollution from Ships MOC Management of Change MOF Material Offloading Facility MRF Material Release Form MTPA Million Tonnes per Annum PEP Project Execution Plan PIC Person in charge POD Plan of Development QA Quality Assurance QASSP Quality Assurance and Service Supply Plan QC Quality Control RBLL Rovuma Basin LNG Land, Lda SAP Systems Application Products (business application software) SOP Standard Operating Procedures THS Tubing Head Spool. TPI Third Party Inspection UWA Ultimate Work Authority WCP Well Construction Plan





1.3 OVERALL PROJECT SCOPE

AMA1 made significant gas discoveries off the northern coast of Mozambique. Development of these resources requires design and construction of subsea production facilities, producer wells and related subsea gathering systems, a two train onshore LNG facility for liquefying, storing, and exporting natural gas and associated liquids such as condensate. The construction and development will take place in a remote, environmentally-sensitive location lacking any existing infrastructure.

The plan requires the construction of 18 wells (including re-entry and completion of 3 maturation wells drilled in 2015) in the first phase of field development. Future expansion and development plans include additional wells to be delivered to supply gas to more onshore LNG trains.

Development of these facilities will occur in a safe, timely and cost-effective manner in order to meet the economic goals set in the POD approved by APC, partners and GoM.

1.4 PROJECT DESCRIPTION

Mozambique is located in southeast Africa. AMA1’s offshore gas discoveries are in the Golfinho-Atum and Prosperidade fields in Area 1 of the Rovuma Basin. The Golfinho-Atum Development is a deep water discovery located approximately 50 km offshore Mozambique. It will be developed as a subsea system tied back to an onshore LNG facility on the Afungi Peninsula located 10 km southeast of Palma. The onshore facilities will be constructed within the Project DUAT.

The following map shows the location of the project.





Figure 1-1: Golfinho-Atum Field Location Map

AMA1 is the operating company for the Area 1 development. The Golfinho-Atum field is entirely located within Area 1; therefore, it will be operated exclusively by AMA1. There have been additional gas discoveries offshore Mozambique in Area 4 of the Rovuma Basin. Area 4 is located adjacent to Area 1 to the east and is operated by ENI and its partners. This PEP is specific to the Golfinho-Atum field development of Area 1. AMA1 will be developing Area 1 with several Partners. The participants in the Area 1 EPCC are as follows,

• Empresa Nacional de Hidrocarbonetos, E.P. (“ENH”) – 15%. • Anadarko Mozambique Area 1 Limited (AMA1) – 26.5%. • Mitsui E&P Mozambique Area 1 Limited (“Mitsui”) – 20%. • BPRL Ventures Mozambique B. V. (“BPRL”) – 10%. • Beas Rovuma Energy Mozambique Limited (“BREML”) – 10%.





• ONGC Videsh Limited (“ONGC Videsh”) – 10%. • PTTEP Mozambique Area 1 Limited (“PTTEP MZA1”) – 8.5%

The project is a Greenfield development and consists of the following elements,

• Wells and infrastructure to deliver gas from the offshore fields. • Offshore facilities to collect and transport gas to the onshore facility. • Onshore facilities to receive and treat raw gas liquefy and store LNG and condensate. • Marine facilities to enable export of LNG and condensate. • Infrastructure and utilities to support construction, plant operations and workforce. • Resettlement of existing Mozambique residents within the DUAT.

1.5 PROJECT OBJECTIVES AND GOALS

The objective of the Project is to safely deliver an offshore gas field development by constructing offshore wells, pipelines and an onshore LNG facility consisting of two initial onshore LNG trains while planning for future expansion. Project success is defined as safe execution, minimal detrimental impact on the local population and environment, delivery on budget, delivery on schedule, quality that meets or exceeds project specifications, meeting stakeholder expectations and being in compliance with applicable current environmental and regulatory requirements. The key goals are summarized as follows,

• Develop a culture that emphasizes the importance of the involvement of all parties in the development and maintenance of a safe and incident free environment.

• Compliance with all environmental regulations and commitments, and alignment with industry best practices, minimizing impacts to people and the surroundings.

• Control of capital costs within agreed project objectives. • Construct wells and facilities with minimal detrimental impact to local inhabitants and the

environment. • Enhance the facilities, opportunities and prospects for the local community on the Afungi peninsula

and surrounding area

1.6 PEP UPDATE PROCESS

This PEP is a working, controlled document that is updated when necessary to reflect current campaign plans. Changes will be managed via the MOC process as outlined in Section 6.4. Every member of the team is expected to be familiar with this document. The Well Construction Manager is the document owner and will be responsible for keeping it live and updated as required. Feedback relative to improving this document shall be routed through the above mentioned. If an item in this PEP is unclear or not in alignment with actual practices of the campaign, it should be discussed with the relevant personnel in the team.





2 WELL CONSTRUCTION STRATEGY

2.1 CORE VALUES

The campaign will be executed in line with Anadarko’s core values. These values include Integrity and Trust, Servant Leadership, People and Passion, Commercial Focus, and Open Communication. The Well Construction Team will understand and execute AMA1’s strategy, safeguard the long-term interests of APC, AMA1 partners and other stakeholders, maintain high standards for health, safety and the environment and act responsibly with company assets. The team will not sacrifice long-term value for short-term gain and also not use the excuse, “we’ve always done it that way”.

2.2 MANAGEMENT SYSTEM

In addition to embracing APCs core value, a well construction management system will be developed and used for managing risks in order to protect people and the environment, as well as for standardizing how plans and procedures are to be developed. The management system will provide the framework, tools and direction to meet the key strategies outlined below.

HSE: Enable AMA1 to manage well construction in a healthy, safe and environmentally responsible manner. Assist in the growth of a culture that shows care and concern for individuals by developing procedures based on appropriate and relevant practices and safety standards and leveraging “Lessons Learned” from within the global industry and previous well construction campaigns.

Standards and Work Processes: Identify and implement appropriate industry practices. Establish and communicate a common set of objectives and expectations for use in managing well construction operations. Apply standards and procedures to meet or exceed requirements of the well construction management system. Provide a structure to organize processes, programs and procedures in order to deliver well delivery expectations and objectives. Apply consistent standards in HSE management, well integrity and risk assessment, campaign planning, well design, operations supervision, reporting and communications, Setting targets and monitoring performance, and contracting strategy.

Risk Management: Identify, evaluate and control risks to prevent or mitigate incidents that could impact people, the environment, and/or assets. Identify and mitigate significant risks as early as possible.

Rules, Regulations and Business Ethics: Comply with applicable laws and regulations and adhere to the highest business ethics standards. Promote open and honest communication, eliminate barriers and develop mutual trust among an integrated multi-functional team. Seek early input from key stakeholders and maintain active communication to ensure alignment.

Organization and Resources: Organize personnel with the skills, capabilities and experience to produce the strongest possible well construction team by maintaining appropriate staff personnel levels to provide expertise and continuity. Preserve area specific knowledge and expertise. Employ expert consultant staff when required. Follow a “plan for success” staffing strategy to ensure the right people (employees and consultant) are available at the right time, leveraging both AMA1’s and the industry’s experience.





New Technology and Continuous Improvement: Establish, maintain and enhance a communications network with other APC well construction teams to facilitate the transfer of technology, safety alerts, problem bulletins, performance improvement initiatives and results. Establish a process of planning and execution reviews with efficient feedback times to drive continuous improvement. Celebrate successes such as significant milestone achievements on a regular basis

Contracts and Procurement: Work with C&P to plan, develop and execute an effective contracting strategy, utilizing competent and motivated contractors while leveraging AMA1’s experience.

2.3 WELL CONSTRUCTION PROCESS

The core process for well construction involves the design, planning, execution, analysis and continuous improvement of drilling and completions activities. This process also includes sub-processes such as rig scheduling, well planning, well operations, well performance reviews and campaign performance reviews and support processes such as development of equipment specifications, procurement and tendering, contract administration, cost reporting, logistics and transportation. HSE leadership and management of asset integrity provide key controls that underpin all well construction processes.

As part of AMA1’s strategy, a well construction process has been mapped out to show key deliverables from the FEED stage at project concept to the Campaign Review stage at project closeout. Details of the well construction process and the deliverables at each stage gate or milestone can be found in The Mozambique Well Construction Process (MS Section 6.4)

The well delivery process is as shown in Figure 2-1





Figure 2-1: Well Delivery Process

2.4 EXECUTION FRAMEWORK

The different technical standards developed for the core well construction process and non-core processes from support teams will be developed and maintained according to the requirements of the relevant sections of the Well Construction Management System. These standards, which are referenced in the WCP and PEP documents, the major well construction-overarching documents, will be applied in the design and program of each well in the campaign. The framework is depicted in Figure 2-2.





Figure 2-2: Execution Framework





3 WELL CONSTRUCTION PLAN

3.1 WELLBORE CONFIGURATION

The well construction plan as per The Design, Fabrication and Testing of Well Construction Asset (MS Section 4.1) has been designed to deliver an average 150MMscf/d gas production rate for a 30-year life. The general casing program for the construction of the wellbore includes a jetted 36” conductor string set at 72m below mud line, a 20” surface casing string set through the fragile upper interval, then cemented to the mudline, and a 13 ⅝” intermediate / production casing string set below an Oligocene aged marker. A 10-3/4” production liner will be set just above the designated zone of interest before drilling a 9 ½” open hole through the reservoir. Based on strategies identified in section 2.2.6 of this PEP, a technology improvement opportunity is being researched where the reservoir is top set with a 13-5/8 x 10-3/4” tapered string, eliminating the need to make a separate run for the 10-3/4” liner. This could improve the well construction timeline and cost effectiveness. The base case design will be reflected in project economics until the tapered string design is finalized and validated.

In the keeper maturation wells drilled in 2015, the reservoir will be top set with a 10 ¾” liner upon well bore re-entry prior to under reaming the production interval.

The completion is designed with an open hole gravel pack system. The gravel pack packer is planned to be set inside the 10 ¾” liner with an isolation valve incorporated within the gravel pack assembly. Based on results from NODAL analysis, a 7” tubing string will be utilized to ensure the well is capable of delivering maximum rates through its lifetime with no limitations. The production string will have a 13 ⅝” x 7” production packer installed, to provide a pressure barrier from the reservoir to the surface and to serve as an anchor for the production tubing. The production packer will be set deep and above the liner lap. A telescoping space out joint assembly will also be installed in the production string. It will be used to land out the subsea tubing head when the tubing bottoms out in the gravel pack packer. A perforated sub in the tubing string will prevent trapped annulus pressure between the gravel pack packer and production packer. Figure 3-1 shows the planned completion for Golfinho-Atum.

The first of the subsea equipment packages to be deployed will consist of a wellhead system (LPWHH & HPWHH). This system will support the rig’s BOPs and provide the profile for landing the 13-5/8” casing hanger. The second package is the THS, which will be installed on the HPWHH prior to drilling the reservoir section. This provides a profile for landing the tubing head and an interface with the flow line jumper. The last subsea package that will be deployed is the CXT. The CXT is run on the CWOR package and it is landed and locked on the THS mandrel.

The following documents can be referenced for additional details’

• Golfinho-Atum Phase 1 Casing Stress Analysis document (GF-090-AM1-DR-BOD-0000X) • Golfinho-Atum Phase-1 Production Tubing Stress Analysis document (GF-090-AM1-CP-ANA-00002) • Golfinho-Atum Well Construction Plan document (GF-090-AM1-CP-BOD-00001)





Figure 3-1: Wellbore Configuration

3.2 OPERATIONAL SEQUENCE

Three of the six keeper maturation wells drilled in 2015 will be re-entered, cleaned out and under reamed to the top of the reservoir before a 10-3/4” liner is run and cemented. Generally, there are three distinct rig operations for the construction of each new wellbore. These are drilling, completions and flow back operations. In addition, each operation is separated into component phases. These phases are as described in Sections 3.2.1, 3.2.2 and 3.2.3. There are work steps associated within each phase described in more details in the Well Construction Plan document (GF-090-AM1-CP-BOD-00001).





3.2.1 Drilling Operations Phases

In fulfilment of Operations Excellence (MS Section 6.1), a drilling program will be prepared to cover procedures for all operations to be performed on each well bore including,

• Moving the rig to the well location • Running and jetting 36” conductor to 72 m bml • Drilling 26” hole sections to 1000 m bml. Running and setting 20” casing • Installing and testing BOPs • *Drilling 16” hole to Oligocene Marker. Running and setting 13-5/8” casing. • *Drilling 12-1/4” hole to top reservoir. Running and setting 10-3/4” liner. • Installing barriers. Unlatching BOPs. • Installing THS. Re-latching and testing BOPs. Recover barriers • Drilling 9-1/2” hole

*Note: For efficiency and cost effectiveness, 16” hole may be drilled to top of reservoir and a tapered 13-5/8” x 10-3/4” casing string run to top of reservoir. Feasibility of that design and its risk assessment is currently ongoing

3.2.2 Completions Operations Phases

As in section 3.2.1, a completions program will be prepared to cover procedures for all operations related to the completions designs for all wells including,

• Preparing wellbore for Completion • Running lower completion • Gravel Packing Open Hole • Running Upper Completion • Installing barriers. Unlatching BOPs

3.2.3 Reservoir Clean-up Operations Phases

• Run Subsea Tree on CWOR. Recover barriers • Flow well for clean up • Rig Down. Pull CWOR • Handover well to Production. Move Rig Off

3.3 CAMPAIGN SCHEDULE

As discussed, up to 18 wells are planned to be available for production upon startup of the LNG Facility. The strategy for the initial well count is to balance the objectives of supply assurance (high confidence that production will be sufficient to meet plant capacity for a pre-determined period) and capital efficiency (avoiding excess drilling to reduce initial capex, as well as to gather additional reservoir data, which will





be used to improve placement of subsequent wells). Additional analysis will be completed prior to the start of the campaign to further optimize that balance, and the well count may be adjusted accordingly

The well construction schedule for Phase-1 wells will be planned to assess critical geological uncertainties with the early wells, thereby facilitating optimization of the remaining program. As the project timeline calls for all wells to be available for production startup, the sequence is irrelevant to productive capacity. Drilling of wells in addition to the first 18 will be required to supplement the raw gas supply to the LNG Facility during the Development and Production Period. Data collected during the drilling of the initial wells, as well as production performance, will reveal an enormous quantity of information to improve the characterization of the reservoirs. Therefore, the number and location of future development wells is currently subject to a high degree of uncertainty.

The first well spud is anticipated 24 months after FID and a total campaign duration of 30 months is estimated for a planned one rig schedule. The first 2 wells and one re-entry in the schedule will be drilled, completed and cleaned up to test the lower completions performance. In addition, these wells will ensure delivery of fuel gas to the LNG plant prior to commissioning. A notional schedule is shown in Figure 3-2. This schedule will be optimized and drawn up to perform similar operations in batches for overall efficiency gains.





Figure 3-2: Notional Well Construction Schedule

Y6Q1 Q2 Q3 Q4 Q5 Q6 Q7 Q8 Q9 Q10 Q11 Q12 Q13 Q14 Q15 Q16 Q17 Q18 Q19 Q203 6 9 12 15 18 21 24 27 30 33 36 39 42 45 48 51 54 57 60

Group 1: 2 x new wells plus 1 x Re-entry Group 2: 5 x new wells Group 3: 4 x new wells plus 1 x Re-entry Group 4: 4 x new wells plus 1 x Re-entry

Y1 Y2 Y3 Y4 Y5

FID rig mob LNG fuel gas T1 SC

Group 1 Group 2 Group 3 Group 4

Drill

Complete

Re-entry

well construction planning work

rig de-mob





4 PERSONNEL AND ORGANIZATION

4.1 RESOURCE ALLOCATION

The team will be staffed according to the current and future well campaign needs for AMA1. It will have a staffing plan finalized before FID showing the mobilization and demobilization of team members. Skilled and qualified AMA1 personnel will be assigned to the project as required to support the Staffing Plan. Once a staffing need is identified, HR will work with the team to hire potential candidates by submitting an internal APC job posting or by working with a manpower consulting agency. The team leads with a subsequent decision from the Well Construction Manager to approve or reject will interview suitable candidates. New AMA1 personnel will go through the onboarding process as shown in the AMA1 Onboarding Orientation, EA-MZ-AD0000-APC-A01-00001-00. Depending on work location, Human Resources will engage the new personnel to determine visa requirements, work permits, vaccination and other requirements. If offshore travel is necessary, the Offshore Personnel Transfer document, EA-MZ-AD0000-APC-C17-00001-00, will be in effect. Personnel will need to go through the Demobilization process once their job assignment is completed

4.2 POSITION DESCRIPTIONS & COMPETENCY

Position descriptions for the team will be developed and maintained by the Well Construction Manager. The Position Descriptions contained in the staffing plan will be discussed and clearly explained to the team. Updates and improvements will be incorporated into Position Descriptions and communicated to everyone in positions where there is a job requirement change. The Well Construction Manager will assess competency of personnel and of contractors filling staff positions. Key elements of competency assessment will include,

• Pre-employment review of resumes, education and employment history. • Verification of skills, character and past performance through reference to past employers. • An interview process focused on the specific job requirements. • Confirmation the candidate satisfies a training needs assessment for the position, or that gaps in

training can be addressed. • Periodic (normally annually) documented reviews of performance in the role. • Assessment of training requirements and maintenance of training records

The team’s Competency Check List and Training Matrix Document (MS Section 2.2), currently being developed, will describe additional details for key job positions

4.3 ORGANIZATION STRUCTURE

The organization is designed to ensure continuity in key positions. As needs change, team personnel may change roles, responsibilities, or time dedication to the project. Staffing transitions will be planned to allow the team to expand and contract as warranted by the campaign requirements. Personnel from AMA1 and contractor groups will be employed on a full-time and on a part-time basis to fill management, interface, technical, field-work and specialist support needs. Organization planning will be reviewed





regularly to ensure the campaign is resourced appropriately and revised as necessary to meet the evolving needs of the project.

The team will be based in The Woodlands office in Texas during the design and initial planning phase pre-FID. It will transition to the Maputo office in Mozambique 9-12 months before spud. The Well Construction Manager will oversee the project from The Woodlands office with frequent visits to Maputo. The Organization Chart planned for execution is shown in Figure 4-1. Resource from support teams such as ITS, Security, C&P are currently not shown. Also not shown are coordinators from contractor organizations that will provide services and will be dedicated to the campaign. These positions include the Rig Manager, Directional Drilling and Surveying, Fluids, Tubular Running and others.

The team structure will be confirmed prior to the time of project execution.

4.4 JOB POSITIONS

The positions for which job descriptions, experience level, training and responsibilities have been identified are detailed in the Well Construction Organization, Roles and Responsibilities Document (MS Section 2.1). The job positions includes,

• Well Construction Manager • Engineering Manager • Operations Manager • Drilling Engineer • Completions Engineer • Performance Engineer • Subsea Engineer • Planning Engineer • Operations Coordinator • Rig Supervisor • Completions Specialist • Subsea Specialist • Rig Clerk • Fluid Consultant • HSE Advisor • Logistics Coordinator





Figure 4-1: Well Construction Org Chart





4.5 JOB DESCRIPTION

4.5.1 Management

In order to effectively execute well construction activities, the project is led by a Well Construction Manager serving as the team’s Delivery Manager. The team is primarily organized along engineering and operations lines with a team lead responsible for each. A well performance role is added to the well construction organization to foster the culture of continuous improvement through data analytics and application of new technology.

The Well Construction Manager provides overall leadership, makes high-level decisions and sets the strategic direction consistent with the project goals. A core function of the well construction manager is the development and management of the organization. He is responsible for the operational, technical, safety, environmental, financial, quality assurance and administrative aspects of the well construction campaign. He overviews the well delivery process to ensure compliance with APC policies and statutory regulations.

The Operations Manager reports directly to The Well Construction Manager and has overall responsibility for all aspects of the entire operation i.e. HSE, operational, technical, financial and administrative. He is the official line of communication between the Office (Maputo/The Woodlands) and The Field (rig). During drilling, completions and well clean-up activities, The Engineering Manager will play an active part in assessing any problems and proposing solutions and changes to the program or procedure. Any program changes requested or required will be routed through the Operations Manager and not sent directly to the rig. He is the focal point of contact with resource teams such as HSE, C&P, Logistics and external agencies e.g. INP

The Engineering Manager also reports directly to the Well Construction Manager and leads a group of Planning, Drilling and Completions Engineers. He is responsible for the provision of all engineering technical support for the well construction campaign. Also, included in the group is a Subsea Engineer’s position with responsibilities for full subsea system integration to well construction. Some of the subsea systems include CXT, THS and CWOR. The Engineering Manager supervises engineering support to the operation and has overall responsibility for optimizing well planning, costing for the drilling / completions operation.

4.5.2 Office Personnel

The Drilling Engineer will provide technical engineering support to the drilling operation and is responsible for delegated aspects of Drilling Program and end of well reporting. The Completions Engineer will also provide technical engineering support like the Drilling Engineer but for completions, well test and well clean-up operations. He will work with other members of the team to execute the completions program and the end of well report for the completions phase. In addition, both The Drilling Engineer and The Completion Engineer will monitor and ensure cost accuracy and spend during completions program execution. They will work with the rig consultants and the accountants to ensure costs are allocated correctly to the right codes in ‘openwells’ (field cost reporting) and SAP (invoiced cost reporting) applications. Both roles (Drilling/Completions) will ensure that the activities of the service companies





(tools, equipment and specialists) are well coordinated and aligned with the drilling/completions programs. The Completions Engineer will be supported by an Operations Coordinator and two Completions specialists (during the drilling phase) to supervise completions tools/equipment preparations and QA/QC efforts at the various contractors facilities in the region.

Three office based roles (Performance, Planning and Subsea) have been added to the org chart in order to fulfil some aspects of the well construction objectives. The Performance Engineer will provide the necessary interface for continuous improvement by monitoring well construction technical performance and comparing with benchmarked KPIs. The Engineer, whose work will be tied with the Real Time Solution Center in Houston, will provide regular feedback to the team on cost and performance issues. Part of the Performance Engineer’s role will also include monitoring the application of technology and advising the team on how such technologies can be adapted to create step changes in AMA1’s well construction performance.

The other key role is that of the Planning Engineer who will look after all of the design and planning work for upcoming wells on the rig schedule for drilling and completions. The Planning Engineer makes sure that the drilling and completions programs are ready before execution and ensures that risk assessments for each well are performed, organizes peer reviews, DWOP and CWOPs before programs are signed off. As part of the role, the Planning Engineer will prepare the AFE for each program and will work with the Drilling and Completions Engineers to ensure that the service companies are coordinated with details of the programs, close out any NPT events appropriately and reflect lessons learnt from previous operations in the programs being prepared.

The Subsea Engineer as previously described will provide all interface work required to install the THS CXT and CWOR successfully. He will work with the Planning Engineer to ensure that operational steps for installing the above equipment are captured in the completions program. He will oversee the handover and supervise all interface issues of the subsea equipment between The Subsea Team and The Well Construction Team. Part of his work will involve working with the suppliers in performing all necessary QA/QCs such as SITs, dock test and others to ensure the equipment will function as specified. He will advise the team on maintenance issues, equipment installation options and rig requirements for running and installing equipment. He will be assisted by two Subsea Specialists to cover night/day subsea operations on the rig and contractor’s facilities in Mozambique

4.5.3 Rig Personnel

The rig, which may likely be a dual derrick rig, will primarily have a Rig Supervisor acting as AMA1’s senior representative and focal point on the rig for all activities and operations. He will report directly to the Operations Manager. He is ultimately accountable for all operations on the rig and will be the primary contact for all phases of the operation from the rig to the office via the Operations Manager, regardless of operations in progress e.g. completions, testing, drilling. The Contractor’s PIC/UWA will have ultimate responsibility for the safety of all personnel onboard the rig and the safety of the installation. The Rig Supervisor liaises closely with the Contractor’s PIC or Rig Superintendent to ensure the approved Drilling, Completions, or other programs are correctly implemented and complied with. The Rig Supervisor will be responsible for preparing clear job instructions (POA) for driller / service companies for all operations and communicating to the office in clear, accurate and concise manner in both verbal and written terms. The





Rig Supervisor takes complete ownership of the daily drilling reports (DDR) and will ensure their completeness and accuracy.

Assisting the Rig Supervisor are two Assistant Rig Supervisors providing 24 hour coverage for rig operations. They help, in their respective day/night shifts, in carrying out duties and responsibilities as listed above, promoting good safety practices and behaviors and ensuring cost and cost effectiveness.

During completions and well clean-up/testing activities there will be two Completions Specialists on board the rig for round the clock coverage. They will work with the Assistant Rig Supervisors and report directly to the Rig Supervisor. They are responsible for supervising all completions operations, supervise service companies involved with completions and well testing/clean-up. Their functional reporting line is to the office based Completions Engineer who provides them with technical and functional support. Since the project is planning to have two completions specialist on the rig during completions operations, the day specialist will be designated the Senior Completions Specialist. All critical communications including any changes to program must be routed throughout the Senior Completions Specialist. As previously mentioned, during the drilling phase, the Completions Specialist will assist the Operations Coordinator (role described below) with QA/QC work for completions equipment, tool make tests and other work at the various contractor facilities in the region.

Some of the other players who are not office based or rig based but work to support the project from other locations (mostly contractor facilities) include The Operations Coordinator and The Fluids Consultant. The Operations Coordinator’s role is to ensure that completions tools and equipment are prepared and made up by the contractors to the correct standards before mobilization to the rig. He provides the contractors with the crucial details of well functionality, timing, verifies specification and certification and witnesses various QA/QC tests. He is a vital interface between the Completions Engineer, the Contractors, the Logistics team and Completions Specialists.

The Fluids Consultant helps to maintain fluids at their desired properties. They will assist in fluid volumetric and maintaining the right inventory of chemicals. As such, he will work closely with the fluids contractor to ensure the mud/brine plants and, the bulk storage units are operated effectively to supply the rig with drilling and completions fluids when required. Tank cleanliness at the mud plant supply base, the supply vessels and the rigs will be one of his areas of responsibilities. He will be required to visit the rig, the mud plant and the supply base frequently.

4.6 Local Workforce Development

In support of AMA1s national content development strategy, the well construction team will continue to promote opportunities for Mozambicans to participate in the project by implementing plans that respectively target employment, training and development. The Well Construction Team will encourage knowledge transfer between expats and locals at all levels. Office and rig based positions will be identified early in the program and a plan to nurture locals into these positions will be developed. Also, rig and service companies will participate in AMA1’s local work force development strategy.





4.7 RESOURCE TEAMS

Support processes would preferably be executed by competent experts from other AMA1 Resource Teams or other APC Corporate resources. The principle non-core areas where support will be required are

• HSE, where additional support would be sought for local legislative requirements related to health, safety, environmental and community issues and for assistance with HSE audits, incident investigation and training.

• Procurement, tendering and contracting, which may be supported by appropriate personnel under the direction of the well construction team.

• Logistics and supply, where support would be sought through the Logistics or Supply Chain for materials handling, supply vessels, aviation, customs and immigration clearances.

• Aviation Services, for assistance with chartering aircraft, setting up fixed-wing or helicopter operations and technical / safety audits of aircraft and operators.

• Human Resources of assistance with recruiting, performance improvement, transfers, salary administration and career development.

• Finance and administration, support for SAP, cost control and reporting, invoice processing, reconciliation and the budget process.

• Legal, for contract vetting, FCPA issues, background check, advice and assistance with local legislative requirements as they affect operations

• Security • Information Technology and Systems





5 HEALTH, SAFETY AND ENVIRONMENT

5.1 INTRODUCTION

The Well Construction Team will design, construct, and repair wells throughout their lifespan in a manner that protects employees, contractors, communities and the environment. The campaign will be implemented in compliance with APC and applicable international and Mozambique laws and regulations. Well operations will be aligned with best industry practices to the extent practicable. The well construction execution framework described in Section 2.4 will be utilized to manage the team’s plans and procedures in furtherance of these objectives. In case of conflict, the more stringent requirement will apply. During all phases of the well campaign, the team will,

• Manage assets in a safe and environmentally responsible manner. • Ensure the health and safety of all personnel under AMA1 control • Design and execute operations based on best industry practice and technical considerations. • Minimize environmental impact as per commitments made in the EIA. • Conduct operations, including flaring, in a manner that minimizes risks to people and environment. • Closely manage contractor and vendor selection. • Motivate personnel at all levels on HSE issues. • Assess ongoing contractor performance with agreed KPIs and document performance reviews • Motivate and hold accountable all personnel at all levels on HSE issues • Using both leading and lagging indicators, seek to continuously improve HSE metrics and processes.

Key HSE goals are summarized as follows,

• To maintain an incident free workplace. • Ensure that safety has a visibly high priority in decisions involving design options, construction

procedures and cost/schedule trade-offs. • Develop a positive culture emphasizing the importance of the involvement of all parties and personnel

in developing, maintaining and enhancing a safe environment, which embraces the aspiration that all HSE incidents and injuries are preventable.

• Celebrate performance and ensure that everyone is recognized and rewarded for success • Secure and protect all personnel, facilities, assets, and operations. • Ensure that all observations, both positive and negative are recorded, assessed and tracked with

effective initiatives developed to address identified trends. • Investigate Incidents and Near Misses according to APC standards and ensure that key lessons are

learnt, documented and that actions are tracked until satisfactory closure.

Work will be performed in a manner that meets AMA1’s performance requirements in compliance with applicable environmental commitments, laws and regulations. Where specific national laws and regulations do not exist, compliance with international and APC standards will be required.





Wastes (hazardous and non-hazardous) generated during well construction activities will be managed in consideration of applicable legislation, project commitments, AMA1’s procedures and international standards. Waste management options will utilize the following hierarchy,

• Eliminate waste. • Reduce the amount of waste produced. • Reuse materials where possible. • Recycle waste where feasible. • Treat and dispose of residual wastes responsibly. • Avoid or reduce potential impacts on biodiversity and ecosystem services.

The primary project HSE document, the AMA1 HSE Plan, will be complied with through a well construction HSE document. It will define policies, procedures and guidelines for safety and environmental matters related to all activities conducted during the well construction process. Compliance with the policies and are is mandatory and shall be monitored and enforced. In preparing this document, current practices and procedures within APCs well construction groups and the industry at large may also be assimilated, according to the priorities defined in the well construction management system. The management system requires that all activities be planned, executed and analyzed to ensure the safety of personnel and equipment. The document will include requirements for,

• General safety rules, behaviors and responsibilities including STOP work authority • An effective, proactive safety observation program • A permit to work system • Induction, training and competency assessments • Hazardous material management • Job safety analysis • Safety alert procedures • Emergency response • Environmental guidelines • Drug and alcohol policies • Immunization and travel requirements

5.2 REGULATORY COMPLIANCE

Regulatory Compliance Plans are defined for land use issues, legal aspects, permits, and understanding of the expectations for compliance with all local and national regulations required in the country of Mozambique. All permits required for the campaign and operation with definition of responsibility for acquisition and schedule will be identified and requested through the work process identified in the Permit Request Procedure, EA-MZPM0000-APC-P33-00004-00. Permit acquisition will require alignment between AMA1 well construction and service providers/contractors to ensure engineering deliverables are issued in a timely manner.





5.3 ENVIRONMENTAL MANAGEMENT PLAN

The campaign execution will entail management of environmental and social impacts and risk. The Environmental Management Plan developed for the project seeks to,

• Ensure the Environmental Impact Assessment approval conditions, Mozambique laws and regulations, lender commitments and industry good practices are addressed under the AMS.

• Define measures required to implement construction and operations-related management and mitigation requirements.

• Communicate environmental goals throughout the campaign and strive towards continuous improvement.

The AMA1 HSE team will monitor and report on Contractor environmental performance to verify that the measures in AMA1 Environmental Management Plan, EA-MZ-SR0000APC-C01-00009-00, are being complied with.

5.4 CONTRACTOR HSE MANAGEMENT

Contractors will be required to comply with national laws and conform to applicable AMS requirements, codes and international standards. Contractors will be required to develop, implement and maintain an HSE Plan and the associated procedures in compliance with AMA1 requirements and necessary to perform work safely and in a manner that avoids, minimizes and mitigates impacts to the environment and local communities. The HSE Plan requirements of contractors will be based on the risk associated with the services being contracted. The HSE contractor engagement process is likely to include prequalification, tendering, selection, bridging (verification of alignment between contractor and company HSE programs), and the need for continuous improvement.

5.5 SECURITY

The Project Security Plan will guide the campaign’s security objective. The objective of the security program is to protect personnel, assets, and operations, in a manner that is consistent with the applicable laws and standards, Company core values, and the furtherance of the project’s social license to operate in Mozambique.

The process for developing and delivering the security program is as follows; initial and continual assessment of the related security threat and risk factors serves to identify the corresponding security countermeasures. These measures are consolidated into an activity specific security support program, which is documented and detailed in the form of a security plan. The implementation of the security plan includes a documented quality assurance mechanism to ensure optimal standards, and that the security program remains adapted to a potentially evolving security environment

The plan includes measures to protect and separate campaign personnel and facilities from potential threats including malevolent actions from groups or individuals (criminal or terrorist), civil unrest (social)





and any potential security risk resulting from accidents or acts of nature. The Security strategy consists of a multi-layered solution based on the development of the following capacities:

• Detect: Independent and interoperable human and technical surveillance and monitoring capabilities designed to identify any unauthorized or suspect presence, as well as any security breaches.

• Deter: A measured security profile designed to inform and dissuade all but the most determined hostile action.

• Delay: Physical and technical barriers and obstacles which would require time, effort, and exposure to engage or penetrate.

• Respond: The capacity to intervene, in accordance with established procedures, against any suspect presence or hostile action.

• Recovery: The capacity to resume operational activities following an incident or crisis. • Reassessment: Routine and specific security assessments and evaluations to ensure the required

levels of protection are maintained

5.6 EMERGENCY PREPAREDNESS AND RESPONSE

AMA1 has developed an ERP specific to operations in Mozambique. The ERP is designed to help AMA1 respond appropriately to incidents. The ERP’s primary goal is to help AMA1 mitigate any injury, loss of life, damage to property or harm to the environment.

The purpose of the ERP is to, • Serve as the basis for an organized action plan for dealing with an emergency. • Define responsibility, priority, and importance in countering an emergency. • Provide information regarding proper handling of serious incidents and identifying the organizations

involved. • Define the protocol for communicating with personnel and agencies during an emergency.

The ERP operates within a tiered response framework where the response level is determined by the complexity of the incident, the risk to personnel, and the impact to the environment. The ERP utilizes the Incident Command System, which provides a systematic and proactive management approach to guide departments to work seamlessly in order to reduce the loss of life and property as well as to reduce harm to the environment. Reference the Emergency Preparedness and Response Plan, EA-MZ-SR0000-APC-P18-00001-00, for further information.

5.7 INCIDENT REPORTING AND INVESTIGATION

AMA1 is responsible for reporting incidents involving employee occupational injury or illness, vehicle accidents, property loss, third-party injury or illness, third-party property damage, spills, and air releases. Procedures for incident reporting to Regulatory Authorities have been established to comply with Mozambique Legal Requirements. A uniform method has been established for the investigation of incidents, identification of incident cause(s), and implementation of corrective actions in order to prevent or reduce the likelihood of recurrence of similar incidents. Incident Levels between 0 and 3 are assigned





based on severity of the incident and an investigation is required for Incident Levels between 1 and 3. Investigation findings and corrective actions are documented and communicated as applicable.





6 OPERATION SUPERVISION

6.1 HSE CRITICAL AND NON ROUTINE OPERATIONS

Prior to commencing any operations, a detailed project risk assessment will be carried out to identify procedures required to prevent failure or loss of control, or to mitigate the consequences of such a failure or loss of control. All risks will be defined and ranked at both initial (raw) and residual (mitigated) levels. An HSE critical operation is any operation where the consequence of equipment failure or loss of control could result in a major accident, significant material or equipment damage, serious personal injury, fatality or significant harm to the environment. Operations such as well testing, heavy lifts, drilling close to the cones of uncertainty of producing wells would be considered HSE critical. Controlled written procedures based on the risk assessment will be in place prior to commencing the HSE critical or non-routine operation. While standard procedures may be appropriate, HSE-critical and non-routine operations will usually require the development of job-specific procedures. Medium/High risk operations on the rig will be required to be conducted under a Permit to Work (PTW) system (e.g. for vessel entry, work on safety systems, working overboard or in the moon pool area, etc.).

6.2 HSE AND OPERATIONALLY CRITICAL EQUIPMENT

Equipment inspection and audit procedures will be developed to ensure the proper maintenance and function of critical equipment. HSE critical equipment is any item of equipment, or systems, whose failure could cause, or contribute substantially to, a major accident, significant material or equipment damage, serious injury, fatality or significant harm to the environment. It also includes those items of equipment, or systems, intended to prevent or limit the effect of a major accident. HSE critical equipment provided by service contractors and suppliers for use on the rig will be subject to verification by an independent, competent person. Prior to being put in service on the rig, the UWA (person in charge) for the rig shall ensure to his own satisfaction that the HSE critical equipment supplied have been designed, constructed, maintained, tested, commissioned and installed on the rig such that they will operate as per requirement. Operators of the HSE critical equipment shall be confirmed as appropriately trained, qualified and verified competent.

Routine testing of HSE critical equipment and systems will be implemented where necessary to ensure that such equipment or systems are maintained in good operating conditions. Such tests will be conducted by competent persons and shall be witnessed by, or on behalf of AMA1. The results of such tests will be recorded in the relevant well files. Testing of HSE critical equipment and systems should include the following:

• Emergency power supply systems • Emergency well kill pumps and their fluid supply systems • Casing pressure tests. • LOTs and FITs • Well Control Equipment testing. • Well completion pressure tests.





• Well tests on clean up or flow back packages • Test string and surface equipment pressure tests. • Load tests and other non-destructive tests on cranes, lifting appliances and lifting gear

6.3 UNPLANNED EVENT NOTIFICATION

The well construction manager will be notified within an hour of any significant incident or unplanned event including:

• All LTIs and Reportable Spills. • Serious incident or near-misses involving rig stability, aviation, supply vessels, security, criminal act or

equipment damage, where the potential for fatality exists. • Well control incidents where non-routine well-kill procedures may be required. • Stuck pipe incidents where sidetrack or extended duration fishing operations may be required.

6.4 MANAGEMENT OF CHANGE

The AMA1 MOC document procedures will be implemented to ensure that changes to policies, equipment, personnel, procedures and approved programs are properly assessed, managed, authorized and communicated to relevant parties.

6.4.1 Changes to policies

Compliance with policies as contained in various well construction management systems is mandatory for all operations. Any deviations from policy will require appropriate risk assessment and the approval of the Well Construction Manager. This approval must be documented in a manner that leaves an acceptable audit trail.

6.4.2 Contractor’s Equipment Change Management

Audits of contractor’s HSE systems will include the contractor’s procedures for changes to equipment and system design, lay-out, arrangement and use (including equipment replacement), so as to ensure that unauthorized changes are not made and to ensure that changes are properly engineered and prevent hazardous situations arising. It must be ensured that Rig Contractor and Services Contractors have procedures in place for bringing equipment changes to the attention of the Rig Supervisor and for seeking his approval prior to the changes being implemented.

6.4.3 Program Change Management

Changes which may compromise program objectives would be discussed with the Subsurface Team prior to initiating the change. Unauthorized changes to the program will only be made at the well site in





emergency situations. As soon as is practicable, the nature and reason for the change shall be communicated to the Ops Manager and his authorization obtained to proceed with the program.

The required level of authorization for a particular change to a program will depend on the magnitude or significance of the change. This may range from verbal confirmation by the Ops Manager to written authorization by all original well program signatories.

The Ops Manager shall ensure that changes from procedures specified in the drilling, completion or testing program are made in writing and communicated to the Rig Supervisor and as appropriate the Engineering Manager. The Ops Manager shall also ensure that barrier analysis is conducted if the integrity of the well, drill string or well control equipment is affected. The required level of authorization for a program change will be determined by the Ops Manager.

6.4.4 Personnel Changes

Detailed handover notes will be written and kept as a record in the rig handover book. When possible, crew changes shall be scheduled to allow for a reasonable handover period between both AMA1 and Rig Contractor supervisors. AMA1 and Rig Contractor supervisors shall stagger their respective crew changes to ensure they do not all change out at the same time. AMA1 Supervisors and Engineers should be thoroughly briefed by the Ops Manager or Engineering Manager prior to going to the rig site. The briefing would include, as a minimum:

• AMA1 expectations. • Regulatory requirements for the operations area. • Well specific details. • Reporting relationships. • Emergency Response arrangements. • Change Management procedures.

Staff and contract personnel working in the AMA1 Well Construction organization for the first time must be formally inducted. Similar handover briefing procedures should also be in place for the Rig Contractor and major Service Contractors at tour and hitch handovers. A MoC-Personnel Request process will be triggered for personnel changes for personnel in the following positions

• AMA1 Drilling and Completion Engineers • AMA1 Consultant Drilling, Subsea and Completion Engineers • AMA1 Operations Manager, Engineering Manager • AMA1 Rig Supervisors/Completion Specialists/Subsea Specialists • Exempt are Contractor and 3rd Party personnel not related to the operation of Critical Equipment

In addition, the MoC-Personnel Request process would be dated and numbered. The following information should be completed in the MoC-Personnel Request process:

• Impacted Party and proposed timeframe





• Affected Role / Position / Personnel • Requested Personnel Change • Justification for the requested personnel change • Training required prior to making the personnel change • Handover or Other requirements that should be addressed prior to making the personnel change

approvals

6.5 Consents

The Well Construction Manager in coordination with appropriate support resources must determine the extent to which partner and government agencies consents are required for specific operations. He will establish and maintain a checklist of those operations (for example completion interval, well-testing, suspension, abandonment) for which either partner or government prior consent is required. In addition, he would ensure that requests for consent are made to partners and government agencies in a timely manner and are properly documented.





7 RISK MANAGEMENT

7.1 HAZARD ANALYSIS PROCESS

The Well Construction Team will actively seek to identify all significant risks to the campaign. The key strategy is to address risk as a whole, including risk to the contractors and external parties contributing to the project. Risk is defined as any activity or situation that threatens to significantly undermine the safety, environmental, schedule, cost, or other performance objective for the project. Process Safety and Environmental Risk identification and mitigation is addressed through HSE procedures.

A risk management process Well Construction Hazard Analysis Process (MS 3.1) is currently being worked on and expected to be finished by FID. It will be developed to cover the scheduling, methodology and documentation of all the different stages of risk assessment conducted during the well construction process. Risk assessment would be an integral part of the overall well planning process. It will be conducted in all of the major phases of the campaign life cycle, each of which is discussed separately and in further detail below. Emphasis would be placed on joint risk assessment with the rig contractor and service companies, particularly for identification of operational risks. Based upon the detailed risk assessments conducted at each stage of the campaign life cycle, the well construction team would be able to focus in good time on major risk and HSE-critical operations.

Risk assessments will be conducted at the three different stages shown in figure 7-1 and results will be captured in a well construction risk register. An overall project level risk assessment was performed using the G-A development project risk matrix as per Appendix V. The project matrix puts well construction in same context as the onshore LNG plant and Subsea.

The risks identified are in the project risk register, the top 20 risks are listed in Appendix VI.





Figure 7-1: Risk Assessment Levels

7.2 CAMPAIGN RISK ASSESSMENT

The ‘Campaign Risk Assessment’ will be updated as soon as a tentative well construction schedule is compiled and prior to issuing scouting enquiries (rig pre-qualification) for the hire of a rig. The objective of front-end campaign planning and campaign risk management is to identify all of the potential risk arising from the planned operations at the specific well location. The particular hazards, which are identified, will normally arise from the particular constraints (geographical, logistical, environmental, legislative, etc.) or peculiarities of the well area of operations and the specific well location. The risk assessment process would commence with the team identifying all of the potential hazards arising from the intended well locations, then consider the proposed well schedule, the optimum rig-type identified, tentative rig availability and associated equipment specifications and logistical support requirements. A brief “brainstorming” review session would then be held, to identify the potential risks for each well proposed for the GA campaign on the well construction schedule. As part of the Campaign Risk Assessment the Risk identified will be risk ranked according to The Well Construction Team’s Risk Assessment Matrix provided in Figure 7-2

7.3 WELL RISK ASSESSMENT

A ‘Well Risk Assessment’ will be conducted once a definitive well proposal is received and either a rig has been identified or contracted. The Well Hazard assessment will be conducted as part of the well design exercise and it should seek to identify specific hazards arising from peculiarities of the well design, for example abnormal pressure, fluid composition, shallow gas and any environmental issues specific to the





well design. The Well Hazard Assessment would consider those hazards, which have been identified during the development of the well design, in addition to studying in greater detail those, which

may have been identified during the earlier Campaign Risk Assessment. Hazards identified will be ‘major’ hazards and should not include ‘normal’ well construction occurrences as ‘hazards’ or ‘risks’, for example minor lost circulation, sticky hole conditions or expectations of over-pull. Risks will be restricted to unusual activities that could adversely affect the well duration or costs, which may have a safety or environmental impact or which might impact equipment specifications or selection.

The Well Hazard Assessment will be documented in a report, detailing the major risks identified, their consequences, their controlling factors, the recommended and agreed mitigating actions and agreed action parties. All risks identified will be entered into the Risk Register for future tracking.

The results of the Well Hazard Assessment will provide inputs to the following,

• Final well design. • Final drilling/completions program. • Confirmation of equipment needs / selection prior to rig- or service-contract award. • Development of drilling/completions or other operations procedures (rig-move, environmental etc.). • Operations Risk Assessment (see Section 6.3 below). • Additional engineering or further technical studies required

7.4 OPERATIONS RISK ASSESSMENT

An ‘Operations Risk Assessment’ will be conducted prior to operations commencing and would include representatives from the drilling contractor, supply vessel contractors and other service contractors. Since the ‘Well Risk Assessment’ considered hazards arising mainly from the characteristics of the well design, the ‘Operations Risk Assessment’ would aim to identify hazards which are particular to the rig general arrangement, the operational interfaces between the rig equipment and the well, and the rig, service contractors equipment or drilling equipment limitations. The deliverables include,

• Identification of additional rig-specific and interface hazards, the estimated frequency and possible consequences of those risks

• Agreement on mitigating actions and controls required, the assignment of future deliverables or agreed actions to specific action parties, and agreement on deadlines.

• Preparation of contingency plans, where mitigating actions are not possible. • Confirmation that the rig contractor’s and service contractors HSE Management Systems interface

effectively with AMA1 HSE system and AMS. • Development of an action plan for hazard/risk monitoring and assessment during the operational

implementation phase.

The Operations Hazard Assessment would be properly documented and formalized in a report, with the results used as inputs to the following campaign documents,





• Risk Register. • HSE Plan • Bridging Documents • Emergency Response Plans • Drilling/Completions Program (or supplemental).

The Operations Hazard Assessment would also identify those areas where uncertainties remain and for which further information or additional studies may be required. Specific hazards or problem areas, which arise, may be considered for further studies, which may include, JSA’s, HAZOP’s or Quantitative Risk Assessments (QRA’s).

7.5 RISK MANAGEMENT DURING OPERATIONS

The following elements of operations risk management will be discussed and sorted out among all parties prior to rig mobilization,

• Obtain the prior agreement of the rig contractor and service contractors for the continuation of a ‘risk based’ approach to HSE throughout the operations phase.

• Agree with the rig contractor prior to operations commencing, on whether the contractor will implement AMA1’s Incident Reporting and Investigation system.

• Hazards will be discussed prior to all jobs and for all major changes to the program, either through pre-tour safety meetings, pre-job safety meetings or JSA’s. These should be used as operations safety awareness and planning tools.

• Any major risks and agreed controls identified at the rig must be documented and entered into the Risk Register.

• Consideration must be given to assessing the risk rating of each hazard identified. A method of assessing such risk rating must be agreed upon.

• Maintain a current Risk Register or other recording system, with frequent updating as a result of incident investigations, STOP, hazard reports, etc.

• Ensure that the rig contractor and service contractors continuously review and identify hazards and controls in their work practices and procedures and that documented procedures are always followed.

• Conduct periodic audits of all contractor’s HSE Management Systems, to ensure that they effectively control risks during operations.

7.6 POST CAMPAIGN REVIEW

A post-campaign risk review would be conducted as part of the post-well / post-campaign operations review, during which the effectiveness of overall campaign hazard management would be reviewed. The review should serve to confirm that the ‘hazard tracking’ system was effective and that all mitigating actions were properly closed-out.





Figure 7-2: Risk Assessment Matrix





8 CONTRACTS & PROCUREMENT

8.1 INTRODUCTION

This section applies to the management of contracting and procurement activities by AMA1 with its selected contractors, vendors and suppliers. It does not apply to contracting and procurement activities between the selected Contractors and their subcontractors, vendors or suppliers. Various contracts will exist on the project, including service contracts with contractors and purchase orders with suppliers. The Contracts and Procurement team is responsible for managing these contracts. Members of the C&P team report to the C&P Manager. The C&P team personnel will ensure proper documentation is drafted and agreed between the Well Construction Team and external contracting parties to efficiently execute contracts. Below is a table describing the responsibilities of various AMA1 and external teams regarding contract activities.

Table 8-1: Contract Responsibility Matrix

AMA1 Well Construction Mgr (or as

appropriate in accordance with

G9 DOA

AMA1 C&P Manager

(or as appropriate in accordance

with G9 DOA

AMA1 C&P Team

Requestor (or as

appropriate in accordance with

G9 DOA

AMA1 Partners

GoM (INP)

Requisition Review/Approve Review Review Draft/Approve Commitments<$25MM Approve Approve Draft Review/Approve Commitments>$25MM Approve Approve Draft Review/Approve Approve

In addition, the guidelines in the management system, Contractor Management (MS Section 5.1), will be used for (a) the management of the rig contractor and service providers and (b) the contracting of rigs and well bore construction services, and the supply of equipment and materials for GA campaign. The guideline provides recommendations and guidance on,

• Contractor management, including HSE • Safety critical elements verification • Contractor HSE pre-qualification • Contractor technical and commercial prequalification and evaluation • Contents of tender document

8.2 CONTRACTING PROCESS

Rig and major services contracts will be established through competitive tendering. A formal Contractor prequalification exercise will be carried out for rigs and some major services in order to identify those potential providers of services or goods who should be capable of fulfilling AMA1’s basic safety, technical and commercial requirements. This strategy is considered appropriate due to,

• The high number of wells and the long duration of the well construction phase of the project





• The current slump in the industry which presents several technical and commercial options • Statutory requirements by GoM, which require a formal tendering process for services above the

contract value threshold stated in Table 7-1. The rig and most major well construction services will be above this contract value threshold.

The contracting process will include the following,

• Prequalification of potential contractors for HSE, technical and commercial capability • Preparation of tendering document and issuance to bidders • Receipt and evaluation of bids • Award Recommendation and approval • Letter of Intent and contract preparation • Contractor Mobilization

8.3 RIG SPECIFICATION AND CONTRACTING STRATEGY

One rig will be required to execute the well construction campaign. The rig will have a similar spec as shown in Appendix I. A preliminary contracting strategy is currently being prepared for the rig. A draft of the rig contracting strategy is described in Appendix II of this PEP. The rig will be pre-qualified based on the following criteria,

• Availability • Deck space and hull storage • Dual derrick capabilities • Rig past performance and safety records • Contractor management and organization • Credit worthiness • Tree and tubing spool handling • Maintenance culture and inventory level

8.4 MAJOR SERVICES CONTRACTING STRATEGY

Several service will be required to support well construction. A draft of the contracting strategies for the major support services are described in Appendix IIIa.

The major support services include,

• Supply of large OD pipe and OCTG Casing and Tubing plus associated services • Provision of drilling fluid, reservoir Drill-in fluid, gravel pack and completion fluids services • Provision of Directional Drilling, MWD/LWD, Mud logging and Downhole tools services • Supply of Wellhead Equipment and provision of wellhead services • Provision of wireline logging and pipe recovery services





• Provision of Completions Services and Supply of Completions Equipment (Screens, gauges, packers, safety valves, fluid loss device)

• Provision of Well test and Clean up Services • Provision of Casing and Tubing Running Services • Provision of Solids Control and Waste Management Services • Provision of ROV Services • Provision of Pumping and Cementation Services • Provision of Shorebase and logistics Services • Provision of Supply Vessels and support services • Provision of Fixed and Rotary wings Aircraft Services

8.5 CONTRACT BUNDLING AND PRIORITIZATION

Appropriate bundling of well construction goods and services will effectively reduce technical risk, interface issues and costs. Examples of where this can be applied include,

• Main fluids: drilling mud, reservoir drill-in fluid, brine • Fluids & sand control: muds, brines, gravel pack carrier fluids, and pumping services • Sand control: lower completion hardware and gravel pack pumping services • Full completion: upper and lower completion hardware and gravel pack pumping services • Drilling services: Directional drilling & formation evaluation (mud logging if required) • Completion services: coiled tubing, slickline, electric wireline

A list showing required well construction contracts and the priority for establishing these contracts are as shown in Appendix IIIb

8.6 CONTRACTOR MANAGEMENT

A contract management plan will be developed prior to initiating tenders. The plan will cover management of contractors (rig and services) from the start of campaign planning, through contract award to contract termination. It will cover both performance and HSE management from the initial campaign planning stage through the operational phase until the end of the campaign.

8.6.1 Contract Preparation Work

Some of the critical contract preparation tasks that will be accomplished in preparing for the campaign include,

• Preparation of an audit list of safety critical contractors - the rig, helicopters, supply vessels and others. The audit list will include a planning chart showing anticipated timing of each inspection / audit and the intended scope of work.

• Compiling a training requirement list. This will include personnel from AMA1, rig contractor and service contractors. While most contractors will have competent, properly technically qualified





personnel, there may be issues associated with HSE that will require them to undertake further training. The specific training needs will be organized as a front-end issue, to allow completion of training well in advance of operations commencement.

• Reviewing the safety management systems of the rig contractor, supply vessel contractor and several other major services providers so their systems are properly bridged with AMA1’s HSE management system.

• Planning for the appropriate ‘moduspec’ rig, and supply vessel inspections. Review detailed requirements for supply vessel safety and equipment surveys and condition surveys.

• Reviewing the supply base safety management system for safe operational procedures, maintenance, inspection, testing and modification, subcontractors and support services, design and construction, emergency response.

8.6.2 Contract Execution

Plans will be developed to keep the rig and service contractors engaged to the well construction objectives and AMA1 overall goals during the execution phase. The following measures have been very effective in prior projects in ensuring contractor alignment,

• Organize a kick off meeting with all personnel (AMA1 and contractors) prior to well spud to review AMA1 HSE requirements and expectations. Discuss and clarify any issues arising from the bridging document, inspection/audit reports, SOPs, training requirements, manning level, communication protocol, policies and procedures and any other issues.

• Encourage initiatives to improve contractor performance. Initiatives that have been successful in the past include routine rig visits by team leads (AMA1, rig and service company managers) for audits and investigation, hazard hunts, HSE culture surveys, pre-spud meetings, performance recognitions and others. Have periodic meetings with contractors in town to maintain a focus on both technical and HSE performance. Regularly scheduled meetings such as monthly HSE meeting, end of well reviews, DWOPs, rig schedule and other have been used to provide feedback to the contractors on performance.

• Replicate models where key contractor personnel are embedded with the well construction team in same office. Also, have contractors supervisors schedule routine visits to the well construction team offices to meet with AMA1 well construction team.

8.6.3 Post Contract Reviews

At the end of the campaign, a wrap up session will be held with all contractors and AMA1 well construction team. This meeting will be used to assess, summarize and report on contractor performance, lessons learnt and improvement opportunities. As part of the review, major contractors would be required to analyze their performance and identify improvement opportunities.





8.7 CONTRACTOR HSE MANAGEMENT

The Well Construction Team is specifically accountable for HSE performance in its campaign, but the nature of its business means that the accountability is actually executed through its rig and service contractors. Even though AMA1 coordinates the delivery of that performance, it is the contractors that actually deliver it. Both the rig and services contracts bind contractors to deliver HSE performance, but the contractors themselves have to ‘own’ the HSE performance and be accountable for it. AMA1 has a leadership role and must seek to enforce the contractor’s HSE performance contractually.

Management of HSE on the rig is complicated by AMA1 contracting third party and support services direct, rather than the more usual practice elsewhere in other industries where a prime contractor contracts directly with its subcontractors. In this latter model, control of subcontractors HSE is the responsibility of the prime contractor. The ‘drilling’ model is more complex, there are very few rig contractors worldwide with the management skills, capability and willingness to coordinate both their own HSE, and Drilling’s service contractors HSE, on behalf of Drilling. The well construction team must therefore accept the need to take the leadership role in managing and coordinating both the rig contractor and service contractors HSE.

In order to ensure that HSE performance is maintained at the highest level, the well construction team would ensure that the following HSE issues are addressed,

8.7.1 Planning

• In pre-qualifying rig contractors, take into account their HSE management skills and capabilities, giving weighting to those that are capable of managing service contractor’s HSE performance. Recognize the additional costs that AMA1 will incur in contracting a rig contractor that lacks such skills and capabilities

• Ensure that contractual arrangements for both rig and service contractors clearly identify, where possible, required HSE performance objectives and criteria, back-up with reward/penalty provisions.

• Ensure that all contracts, whether for rig or third party services, clearly identify the HSE resources required by both contractor and AMA1.

8.7.1 Leadership and Coordination

• Make a fundamental decision for the campaign on whether AMA1 or the rig contractor should perform the role of HSE leader and coordinator. Where prequalification audits and assessment indicate that the rig contractor has the skills and resources, as a preference, ensure that the rig contractor has contractual responsibility for coordinating and leading overall work-place HSE leadership and performance.

• Recognize the additional HSE and resources that will be required in any campaign where AMA1 takes the HSE leadership and coordinating role, and plan budget resources and costs accordingly. Also, recognize that this will require both front-end loading of HSE supervision and management workload and that this additional effort will likely continue throughout the campaign.





• Recognize, and ensure that all contractors similarly recognize, the contractual implications of poor HSE performance by rig and service contractors.

8.7.2 Performance Monitoring

• The role of AMA1 should be to monitor, measure and audit HSE performance achieved by contractors and to provide the leadership, drive, coordination and contractual enforcement necessary to ensure that contractors meet contractual HSE performance requirements.

• Set the goal of having each contractor take ownership of, and accountability for achieving, HSE performance objectives set for the campaign





9 QUALITY ASSURANCE

9.1 PROCESS DESCRIPTION

Quality management is one of the key components necessary to meeting the objective of conducting safe and efficient operations. All materials, equipment and services to be procured for and used in the campaign that includes drilling, completion, well test and subsea activities will comply with the QA/QC requirements set out in the Quality Assurance Guideline Document (MS Section 4.0). The document, upon completion prior to tendering, will contain generic quality control requirements (or Inspection Test Plans) for,

• Drilling Tools and 3rd party services • Completions Tools and 3rd party services • Drilling Tangible purchases • Completions tangible purchases • OCTG

The Quality Assurance Guidelines will define AMA1’s minimum inspection requirements for commonly required purchase and rental equipment, and equipment used by specialist service providers. The inspection requirements address all phases of the equipment procurement process, from initial tendering through to receipt of goods or provision of the service to include post job reporting and lessons learned

The Quality Assurance Guidelines will include comprehensive review acceptance criteria for asset equipment and service related products. A detailed review of each supplier’s QMS and QC processes will be conducted prior to commencement of a contract, for manufactured items or for the provision of specialist services with specialist equipment, to ensure that no misunderstanding remains as to levels of quality demanded by AMA1.

All ITT packages for equipment or services will include

• A Quality Management Schedule (Manufacturing, inspection and test plans) in the proposed Contract. • The generic QC Spec sheets (MTR, certifications, bill of materials, critical dimensions) for individual

items of equipment, or service, shall be included within this Quality Management Schedule when tendering.

• For new manufactured equipment (i.e., wellheads, liners, OCTG), a manufacturing Quality Plan (ITP) shall be requested from the Contractor by Supply Chain which shall detail how the Contractor intends to manage, control, and perform the manufacturing, testing, and certification of the equipment ordered.

• The Quality Plan (QP/ITP) defines the procedures, codes and standards being used for QA/QC activities and should include as a minimum:

− Ensure equipment design is approved, and validated (new technology); − Material traceability checks; − Identification; − Key manufacturing processes;





− Gas, hydrostatic pressure and significant other compliance tests; − Calibration requirements; − NDT, dimensional and visual inspections; − Final function testing and stack up testing and pre-Operations testing; − Requirements for Contractor Data Book and Certification documentation. − Special Processes - The Contractor’s QP/ITP is also to identify all critical activities or special

processes (example: NDE, weld cladding, gas testing, coating, threading) that are to be sub-contracted and describe the Contractor’s method of ensuring the Sub-Contractor is compliant with Contractor policy and relevant specifications to the good or service supplied.

− Sub-Contractor Control – Critical sub-contractor must be a part of a contractor Approved Vendor List (AVL) and must have been previously audited or qualified by the contractor.

• For Services and Rentals (Service Related Product), Contractor shall provide Quality Plans for all service equipment, including rental equipment destined for the well site. QP/ITP’s may also be in the form of checklists and maintenance programs so long as they have the ability to demonstrate service equipment meets design and regulatory compliance for both the Contractor and Anadarko. A job history (or record) of all previous inspection and maintenance records must be readily available by contractor for review by the Anadarko Project Team or representatives acting on Anadarko’s behalf.

The Quality Assurance Guidelines or ITP QC Spec sheets contained in the Campaign-Specific QASSP shall be used in the inspection process of the goods prior to their release for use by AMA1. Confirmation that all goods have been subjected to the required level of inspection shall be required before they are deemed suitable for use at the rig site. An AMA1 TPI shall ensure that the necessary checks have been performed and shall confirm by signature on the relevant QC Spec sheet and the MRF which shall accompany the goods at all times and shall be confirmed at the supply base prior to onward transport to the rig site. The Rig Supervisor shall check the goods, MRF and QC Spec sheet (Release Note) again prior to its use at the rig site.

Use of the ITP QC Spec sheet does not relieve the supplier of the goods from the responsibility for ensuring the goods are supplied to the required quality. The AMA1 QA/QC Release Note, which states this responsibility, shall also accompany the goods.

The Drilling Engineer/Completions Engineer and Tools & Equipment Specialist shall be responsible for ensuring that they are fully aware of planned equipment movements on an ongoing basis, and that relevant TPIs are mobilized to perform inspections as required to allow release of such equipment. Shorebase Logistics personnel must ensure that an appropriate, signed-off QC Spec sheet accompanies all equipment. As with lifting certification, if the document is not present, the equipment will not be shipped. Any deviation from this procedure requires a waiver from the Ops Manager.

9.2 PROCESS OUTLINE

To ensure correct use of the process at all times and correct inspection and release of goods, the Drilling Engineer / Completions Engineer and Tools & Equipment Specialist must meet regularly (daily during well operations) to develop the forward plans. During well operations, this shall be based on a 7-day look ahead.





The DE and/or CE responsible for planning of a well, or campaign, shall review the design of each item of equipment required for the well/campaign with the Tools & Equipment Specialist. Between them, they will ensure that the Campaign-Specific QASSP sensibly addresses critical functions, or integrity elements, in the equipment design, to facilitate correct and focused inspections by TPIs. Effective Communications between QA, Managers, Engineers, Rig, S&L, Geological Ops, Shorebase personnel, Suppliers and TPIs are critical to eliminate poor quality equipment.

The process outlined herein shall be followed for all items procured for the well/campaign construction process. This includes, but is not limited to, the following:

• Major well asset equipment − Wellheads, Xmas Trees and Tubing Hangers − Liner Hangers − Upper & Lower Completion Equipment (Packers, SSSV, FLDs, etc.) − Miscellaneous Completion Equipment (Control Line, Control Line Protectors, Sand Face

Equipment, Screens, Shunt tubes etc.) − Coil Tubing and Well Intervention / Workover Equipment

• Tubulars − Conductors − OCTG – Casing and Tubing − Drill String components (new and used)

• Services − Coil Tubing and Well Intervention / Workover Equipment − Running Tools for any item of equipment − Mechanical Services (Casing make-up and running equipment, cementing tools) − MWD/LWD/Directional Drilling/ RSS / Motors − Other Services (Cementing, Drilling & Completion Fluids, etc) − Wireline − Testing

• Drilling Consumables (Including drill bits) • Drilling/Completion Sub Assembly Make-Up • Lifting Equipment and Containers associated with any item of equipment

The QA/QC of rig contractor supplied equipment (e.g. BOPs, Derrick Equipment, permanent on-site rig equipment) is administered by the contractor and audited by the Ops Manager and will not normally be covered under this guideline unless specifically requested by the Ops Manager. The campaign quality plan is as depicted in Figure





Figure 9-1: Campaign Quality Plan





10 LOGISTICS

10.1 INTRODUCTION

The success of the campaign depends upon effectively managing the transport, transfer, storage, and disposition of materials, equipment, and people from global locations by land, sea, and air. Logistics infrastructure to support these operations is critical to the Project.

Access to an integrated logistics base in the region will be required to support the efficient and effective supply of materials and services for the development program. A fully functional logistics base should include marine quays, a pipe yard, warehouses, offices, an open storage area, a mud plant, fuel and lubricants storage, chemicals storage, a workshop, and customs and immigration offices.

Ideally, these facilities should be co-located on one site to provide for the coordinated loading of drilling rig supply vessels, however the shore base (including warehouse, pipe yard, and offices) may be separate from the port if transportation between the two is reliable. The port area should include marine quays capable of handling high frequency (multiple visits per week) loading/offloading of platform supply vessels up to approximately 90 m in length, and periodic (several visits per year) offloading of break bulk charters up to approximately 150 m in length. A designated area of roughly 200-500 m2 is also required at or near the port to accommodate the contractor mud/brine plant and bulk system. A total area of roughly 3-5 hectares is required for the shore base, which will comprise a pipe yard of 5,000-15,000 m2, covered warehouse space of 2,000-6,000 m2 , a covered work area of 1,000-3,000 m2 , and office and accommodation space including support infrastructure for catering, security, recreation, etc. (see Appendix IV for requirements). It is expected that the port and shore base facilities will be contracted temporarily for the duration of the first campaign phase, and will be released between campaigns. Plans for the logistics shore base and dimensions of the facilities are initial estimates and may be adjusted through the detailed planning and optimization process after FID.

10.2 LOGISTICS BASE

AMA1 committed to facilities in Pemba to support the exploration/appraisal program from 2009 to 2015. Some of these facilities include a company owned supply base of 50,000 m2 that has a lay down yard for tubulars, three warehouses for drilling with the biggest one measuring at 3000 m2 and a camp accommodation for 35 personnel. In addition, the supply base has transportation, waste disposal facility, fuel station, power generation plant, recreation, security, communications, parking, catering and offices for 50 personnel.

AMA1 is aware that Government has awarded a concession in Pemba for the development of an oil and gas logistical facility, and will take this into account when considering any tender process for the well construction logistics base. The final selection of a facility will be based on AMA1’s tendering evaluation and procurement criteria, which will incorporate technical capabilities, safety assessments, commercial terms, contractor due diligence, risk analysis, and logistical considerations of the potential locations. AMA1 will select the facility that optimizes the expected value for the Project, with due regard for procurement requirements of the Decree-Law and other applicable Mozambican legislation





10.3 PORT FACILITY OPTIONS

10.3.1 Pemba Port

Pemba’s port facility is located in a large natural bay approximately 1600 km north of Maputo at latitude 12º 57” south and longitude 40º 30” east. A single dock 180 m long x 16 m wide is present, connected to shore by a 100 m long causeway. Draft at low tide is reported to be in excess of 8 m. The port is commercially active at present, although handling only four to six vessels per month, consisting primarily of container vessels carrying various goods and foodstuffs for the local market and a biweekly ship load of fuel.

A satellite photo of the port facility is provided here as Figure 7-1. Figure 7-2 offers an overview from an adjacent hillside. Although electricity and lighting are available at the dock, AMA1 had to arrange for cranes, fuel, water and bulks to support exploration drilling operations. Based on consultations with the port authorities, AMA1 contracted a portion of its stevedoring services through the port, train a cadre of ten to fifteen men to safely load and unload the work boats under supervision of qualified crane operators and Anadarko supervisors. The dock itself was in good repair and the port’s 40 ton forklifts routinely moved 40’ sea containers along it. AMA1 conducted a civil engineering analysis of the structure to confirm that the dock is suitable for installation of bulk barite and cement facilities.

Figure 10-1: Satellite Image of Pemba Port Facility

There was a sharp increase in the number of Cargo vessel visits to the dock from 2011 onwards creating extreme port congestion and necessitating AMA1 to approve the development of a temporary floating quay solution. The floating quay was designed out of a converted barge towed in from the North Sea. It





was installed and commissioned in 2013 to provide two dedicated berths for PSV dock operations by SDV/Bollore Africa Logistics. This solution sorted the port congestion issues and lasted till the end of the exploration and appraisal phase in 2015.

For the development of the Rovuma Basin and based on the operational needs of AMA1 and eni , GoM initiated a plan to develop a Pemba Oilfield Terminal through an alliance fostered by ENHILS (ENH Integrated Logistics Service SA) to support offshore drilling campaigns and subsea construction activities. A site to the west of the existing port has been allocated for the proposed ENHILS facility, but little construction activity has occurred to date.

AMA1 may have to oversee the improvement of existing roads. This road network may include pedestrian and community roads, vehicle traffic roads, and heavy haul roads if the Pemba Commercial Port facilities and the PTS dock are to be used. The main heavy haul roads through Parquetete village is busy with pedestrians and often washed out during the rainy seasons. It represents a critical safety issue that discourages the use of the port. This will not be an issue if the ENHILS port and road networks are constructed.

10.3.2 Afungi MOF

A Material Offloading Facility (MOF) will be constructed as part of the LNG near shore marine terminal at the Afungi peninsula, 500 km North of Pemba. The MOF will be developed as a multi-purpose dock with facilities to receive all equipment and materials required to construct the onshore LNG Facility and supporting infrastructure, to support Subsea System construction activities, and to accommodate marine services such as escort tugs and pilot boats. There will be dedicated warehousing, storage and laydown areas near the MOF and distributed elsewhere throughout the Project Site to facilitate the construction of the Project and reliable operations. These facilities will provide secure storage for materials related to all onshore and offshore components of the Project. Due to its remote location, the permanent operations camp will be self-sufficient with a stand-alone configuration. This camp will be built to accommodate AMA1’s and selected Contractor’s personnel involved in G-A development. The camp will include staff accommodations, kitchen, dining, outdoor and indoor recreational areas in addition to other utilities and support buildings including a medical clinic and laundry. Potential issues associated with using this MOF for well construction include

• Congestion with ongoing LNG plant construction • Reliance on LNG EPC contractor (CCSJV) for logistics support • Lack of proximity to Pemba where the well construction contractors are currently based. • Expense to set up and operate dedicated service contractor facilities

10.3.3 Mtwara Port

Mtwara port in Tanzania is across the border from Mozambique. It is a deep water port with the quay dredged to 9.8m. There are no tidal restrictions for vessels entering and leaving the harbor, but there is an enforcement length restriction of 175 meters due to the shape of the channel. The port has a quay wall of 385 meters that can accommodate two ships and one coastal vessel at a time. With the





introduction of new solar powered navigational aids in 2012, the port is accessible to ships 24 hours a day. Cargo handling equipment include 3 mobile cranes of 25 tons, 15 tons and 4 tons; 4 tractors, 18 trailers, 8 forklifts and 1 front loader of 7.5 tons. The port does not have specialized equipment for handling container traffic. There are four (4) transit sheds with a total storage capacity of about 15,000 tons. The idea of using Mtwara Port as an access point will be dependent on relaxing the tight tonnage restriction to cross the Unity Bridge and mitigating the cost and potential logistical/regulatory obstacles associated with going through customs twice (Tanzania and Mozambique). It is to be expected that GoM will not be supportive of this idea. The port was used extensively by other operators to drill in Tanzania deep water economic zone. It has major services facilities already established.

10.3.4 Nacala Port

Nacala Port: Nacala port is in Mozambique. It is the deepest port in Southern Africa and serves as landlocked Malawi with a 578 m railway. It has no restrictions on ship movement or size and serves as the main port terminal for export of coal. The port has four general cargo berths and one for containers. Bunkering is available by road tanker with a pipeline at the general cargo berths. Port Congestion, lack of established drilling services facilities and lack of proximity to Golfinho-Atum location are drawbacks as it takes more than 60 hrs. by boat from Nacala port to location.

10.4 TRANSPORTATION

Air transportation of goods, services and personnel (rig crew and support personnel) will mostly be done out of the Pemba Airport. The airport has direct air link to the main airport in Johannesburg, Dar Es Salam and Kenya. It is also connected directly to the capital city of Maputo where a majority of the project personnel will be based. Furthermore, AMA1 intends to construct an airstrip and associated infrastructure on the Afungi Peninsula. The airstrip will have a paved design capable of handling a regional jet such as the Boeing 737 (or equivalent), and will be constructed to appropriate international standards (consistent with Mozambique Civil Aviation Regulation 139 and International Civil Aviation Organization Annex 14).

It is currently intended to locate the helicopter base at the Pemba airport for crew change and medivac operations. A second option is to have the base at Afungi with a supporting chartered flight service to move the rig crew and service company personnel from Pemba

10.5 PROJECT SUPPORT PLAN

Prior to initiating the execution phase of the Project, AMA1 will conclude agreements with GoM detailing Project-specific procedures and mechanisms that will be employed in the administration of certain Governmental functions including customs clearance, issuance of visas and work permits, and Project permitting. Such customized procedures and mechanisms are required to support the scale and pace of material and personnel movements associated with the Project, the magnitude of which is without precedent in Mozambique. The Project Support Plan agreed between GoM and AMA1 will define, procedures and mechanisms to enable the uninterrupted, timely flow of imported goods and personnel to the Project, including:





• Confirmation that all the items on the Importation List are exempt from duties, imposts, taxes, and other charges pursuant to the EPCC (or other regime), subject to proper application of procurement procedures with respect to local goods and services.

• Inclusion of all items on the Importation List in the Mozambique customs database, to minimize confusion or misinterpretation during the Project execution phase

• Agreement on critical details of procedures to be employed by the Mozambican authorities for customs clearance of Project materials to avoid Project schedule delays, including the location for customs clearance activities on or near the Project Site, relevant work processes, etc. In addition to the Project Site, such procedures may apply to other ports of entry by sea and air such as Maputo, Pemba, and Nacala

• Establishment of coordination mechanisms for the implementation of visa and work permit processes and procedures to be followed by GoM, AMA1, and other Project stakeholders.

• Identification of specific Government entities who are accountable for visa and work permit administration at both a central and provincial level, and the establishment of coordination mechanisms among them and with the Project





11 INFORMATION & DOCUMENTATION MANAGEMENT

11.1 DOCUMENT CONTROL

AMA1 Project Information Management Plan and Document Management Plan will be used to control the documentation needed to meet the requirements of the project and the well delivery process, and to manage the approval process for all technical or operational documents that are subject to formal management approval. Controlled HSE guidelines, standards and procedures will be regularly reviewed and updated to take account of lessons learned and changes to requirements or practices. Responsibility for review and update will be clear and would consider, where practical, employee involvement in the review process. Controlled HSE documents will be identified by revision status and/ or issue date. The controlled copies reside in the AMA1 electronic (Intranet) system. Where printed copies are used for any purpose, they must be checked against the controlled version before use. The Well Construction Manager will establish and maintain a register of controlled documents, which identifies responsibility for checking and approval, and the legal and commercial requirements for storage and retention.

Records will be stored and maintained so that they are retrievable and protected against damage, destruction or loss. There must be a method of distribution, to ensure that appropriate personnel receive current revisions and obsolete revisions are returned or destroyed, as necessary. Approval must be obtained at an appropriate level for all revisions to technical or operational documents that were subject to formal management approval on first being issued.

The Operations Manager is responsible for ensuring mandatory documents are provided to the Rig Supervisor and Rig Contractor, as appropriate, and that they are kept current. The latest revisions of the following documents must be kept on the rig,

• Bridging document • Emergency response plan • Waste management plan • Rig Safety Case • AMA1 HSE documents, policies and protocols • The drilling, completion, testing or workover program. • Rig and service contracts. • AMA1 Guidelines and Standards relevant to the planned rig operations • Records and forms relevant to the planned rig operations

11.2 CAMPAIGN PLANNING REPORT

Periodic campaign planning reports should be prepared by the Ops Manager to chart progress against agreed key dates and milestones. A bullet point campaign planning status report should be prepared to update the Subsurface Team customer weekly or at appropriate intervals agreed between Well Construction and the Subsurface Team. A project schedule bar chart showing all significant tasks with planned and actual progress relative to the Campaign Plan should be maintained by the Ops Manager.





An action tracking and closeout list should be maintained to capture all actions resulting from planning activities such as hazard assessment, peer reviews, planning meetings and ad hoc discussions.

11.3 DAILY RIG REPORT

Daily progress on all well operations must be reported by the Rig Supervisor to the well construction team. A Daily Rig Report in standard Landmark’s OPENWELLS format must be prepared on the rig by the Rig Supervisor. The report distribution should be determined by the Well Construction Manager in accordance with the requirements of the well construction team, subsurface team customers and resource Teams. The Well Construction Manager should establish the authority level for approval of the distribution list prior to release.

Distribution should be controlled by E-mail distribution list or AMA1 intranet posting. Security of access should be controlled by LAN login and access security features, allowing access only to those with approved database storage server drive access. Daily Rig Reports should be transmitted daily from the rig site to the shore base (and to the local well construction database) after information in the report has been verified to be correct. Information contained in the report should be confined to facts and using configurations or acronyms common to the industry.

11.4 STATUTORY, MANAGEMENT AND PARTNER REPORTING

The well construction team will comply with the reporting requirements of the subsurface team, AMA1 management, joint venture partners and relevant government authorities. It shall be the responsibility of the Well Construction Manager to comply with commitments agreed with the assets regarding reporting to joint venture partners (JOA) and government authorities (license terms). If required a summary daily report should be prepared to satisfy internal (AMA1 management) and external (statutory and partner) reporting requirements. Where possible, the standard “Daily Management Summary” report (a default report generated by Landmark’s Openwell reporting software) should be used for statutory, management and partner reports and may be distributed by e-mail or in hard-copy form.

11.5 WELL PERFORMANCE SUMMARY

A Well Performance Summary must be prepared and be presented to the subsurface team customer as soon as practicable after the well is complete. The Well Performance Summary should be generated soon after the end of the well and should normally be presented to the customer within seven days after the end of the well. The Well Performance Summary should include:

• AFE/Actual time versus Depth. • A basic well bore configuration schematic. • Time breakdown pie-chart. • Graph of Non-Productive Time (NPT) elements and percentage contributions. • KPI's Targets/Actuals for: Depth, ROP, Cost, NPT (%), Safety.

Well Performance parameters must be based upon ‘Rushmore’ definitions.





11.6 END OF WELL REPORT

An “End of Well Report” (sometimes referred to as a ‘Final Well Report’) should be prepared for all wells. The Drilling and Completions Engineers for the well shall be responsible for preparation and distribution of the EOWRs that should be issued in a timely manner, normally within thirty days after the end of the well. The distribution of the EOWR should be determined by the Well Construction Manager in accordance with the requirements of the Well Construction, the Subsurface and Resource Teams. The EOWR should use consistent standard format and should contain:

• Well information summary: location; rig; contractor; operator; timing; basic well bore configuration schematic.

• Time versus depth curves. • Operational description. • Time analysis. • Final cost breakdown. • Performance summary. • Casing, cement, mud, bit records. • Detailed/dimensioned wellhead/guidance structure drawing for suspended wells. • Records for surveys, pressure testing, coring, logging, testing and completions (from service

contractor reports). • Detailed well status diagram (completion / abandonment). • NPT and summaries of time analyses performed by the Drilling and Completions Engineer should be

added as an appendix to the EOWR. • Analyses of downtime, lost time, etc., required for the EOWR should be the responsibility of the

Drilling Engineer and Completions Engineers for the well. • Suggestions for future improvements and initiatives may be based upon summary reports and

‘Hotnotes’ written by the Rig Supervisor and should be incorporated into the EOWR.

11.7 TECHNICAL BULLETIN AND AUDIT FINDINGS

Technical bulletins and audit findings must be used as a means of disseminating technical information between the APCs well construction teams whenever problems occur which could have worldwide implications. Technical bulletins must be prepared in the first instance by the well construction team when:

• An initiative is tried, whether successfully or unsuccessfully. • When a solution is required for an existing or upcoming problem. • There is an equipment or procedural failure.

The Engineering Manager must forward copies of all technical bulletins to the other APC well construction teams Worldwide as a matter of routine. The Engr. Manager should maintain a register of technical bulletins for review by the assigned Drilling and/or Completions Engineer during the planning phase for each well. Failure investigation reports and Non-Conformance reports shall be used in a similar fashion.





Audit findings which could have an application in other areas must be distributed to all other APC well construction teams.





12 PERFORMANCE MONITORING

12.1 KEY PERFORMANCE INDICATORS

Key Performance Indicators (KPI's) will be developed before rig mobilization to measure and track HSE and other key areas of technical performance, to ensure continuous improvements and to ensure that Well Construction and other Resource Teams provide a ‘Best in Class’ level of service to the Subsurface Team. KPIs (including HSE KPI’s) will be defined during the Annual Performance Review process and are the main Technical and HSE Management System performance improvement tools. The objective of these KPIs will be:

• To measure and track technical and HSE performance, set targets, and ensure continuous improvement,

• To enable reporting of technical and HSE performance against agreed targets and frequencies, and • To support annual evaluation and review of technical and HSE performance.

HSE KPIs may vary from year-to-year, but will likely be associated with:

• Leadership and Behaviours, • Injuries, • Near miss and hazard reporting, • HSE management audits, • Emissions and discharges, • Improvement activities, • Legal requirements and • Significant HSE risks.

Participative KPIs will also be set for management through individuals’ Personal Development Programs. These KPIs contribute towards achieving the targets identified in the Annual HSE Action Plan and should include Improvement initiatives, Participation in HSE audits and incident investigations, and Close-out of actions arising from Audit Investigations, etc.

In order to ensure continual improvement, KPIs will be established based on the previous year’s technical and HSE performance, coupled with knowledge of AMA1 HSE requirements and upcoming programs in the well construction schedule. The annual HSE Action Plan must outline clear, specific, measurable, time-bound actions. Actions within the annual HSE Action Plans will be tracked at regular monthly review meetings, and should contribute towards the planning of the audit program.

12.2 HSE & TECHNICAL PERFORMANCE INDICATORS

The team’s performance will be measured against agreed KPI targets on an annual or more frequent basis. Targets for all KPI's must be set for the campaign and each well, the nature of HSE KPIs will vary from year-to-year, depending on various factors including, AMA1 overall HSE KPIs, campaign specific operations, GoM regulatory and reporting requirements, HSE Management System requirements. The following types





of HSE performance indicators may be established and reported each month in order to support the continuous improvement process,

• Lost Time Injury Frequency Rate (Number of Lost Time Injuries per million man hours worked) • Number of near-misses / incidents by category (including loss-of-containment and fires) • Volumes of discharged drilling fluids and cuttings; • Any additional environmental reporting requirements, as defined by local laws • Fuel usage and associated emissions; • Volumes of flared and vented gases • Behavioural safety observations; • Medical treatment cases: • Occupational illnesses • Number of health risk assessments conducted

In addition to the above, the following information may also be reported on a monthly basis,

• Progress with action close-out • Attendance at Safety Meetings • Behavioural-based Safety Program Observations/Initiatives.

These monitoring and reporting items above will be updated from time to time. Additional measurement parameters (i.e. JSA’s, sickness related absenteeism, HSE audits, etc) could be included within the HSE performance monitoring programmes.

Technical Performance KPI's, examples of which are described in Table 12-2, will be continuously reviewed and improved upon to ensure that they present the clearest and most accurate indicators of performance in all key areas of the drilling and completions process. In addition, the KPIs will be aligned with AMA1’s Business Plans and be based upon ‘Rushmore’ or other industry-wide definitions so that the KPI’s used allow proper comparison with other local and international Operators.





Table 12-1: Technical Performance KPIs

KPI Measure Units

Definition

ROP mtr/d Spud to TD including logs but excluding testing and completions

NPT lost time, (lost time vs total time)

days, (%) All non-productive time including rig and services, split into periods (i) from spud to TD and (ii) move-on, rig-up, rig-down and move off.

NPT down time, (lost time vs total time) days, (%) All non-productive time with delays due to weather, equipment/tools/material delivery, waiting on decision from town etc.

Drilling Time, (plan vs actual) days, (%) Total time for the drilling phase of the well

Completions Time, (plan vs actual) days, (%) Total time for the completions phase of the well including well test

Drilling Cost, (plan vs actual) US$, (%) Total cost for the drilling phase of the well

Completions Cost, (plan vs actual) US$, (%) Total cost for the completions phase of the well including well test

12.3 COMMUNICATION AND DATA ANALYSIS

Once each level of HSE and technical performance data has been calculated, it would be communicated to the workforce. This may be achieved by being discussed at weekly rig site safety meetings, displayed on safety noticeboards and/or discussed at AMA1/contractor progress meetings.

Additionally, workforce involvement in the maintenance of good HSE performance may be further encouraged by initiating incentive programs, rewarding and recognising high standards of HSE performance achievement.

Each party receiving HSE performance data will review the data, discuss HSE performance with the interested parties and identify any trends. Contractors would review the HSE performance of their subcontractors and consult with them on any conclusions drawn or actions necessary. The Operations Manager will review the HSE performance of contractors and compare the actual HSE performance with the objectives given in the campaign HSE plan. The Well Construction Manager will review the performance as a whole in consultation with the Operations Manager and compare the actual HSE performance with the annual HSE plan.





Incident data will be analysed periodically for the emergence of trends. Breakdown of injury statistics into crew, area of rig and body part will assist in forming conclusions, as to focus areas. Breakdown of equipment damage incidents and spills can be similarly analysed and used to direct effort more effectively.

12.4 DRILLING CURVES AND OTHER MEASUREMENTS

Target drilling curves will be developed for every well and be presented as time versus depth graphs. Target drilling curves will be based on offset well data from AMA1 OPENWELL database. A ‘pacesetter curve’ would be developed using a composite of the best problem-free hole sections from offset wells and the best performance flat line time for the rig being used. A preliminary ‘AFE curve’ or ‘well cost estimate curve’ will also be developed using the expected problem free time from offset wells plus the AMA1’s current year non-productive time target.

An operational measurement program will be developed and implemented. The operational measurement program will include Tripping rate, BOP stack and riser running and pulling, Casing and tubing running, Picking up GP equipment and completion tools and others.

The results of operational measurement will be analysed, reported back to service contractors and crews and used to set targets for continuous improvements. Crews will be involved as much as possible in the measurement system and be encouraged to suggest methods for improving performance

12.5 COST REDUCTION

Key cost drivers will be identified to ensure all drilling personnel are aware of the cost drivers involved in operations. Where key cost drivers are high, re-tendering, negotiating or other innovative contract strategies may be considered in an attempt to reduce costs. Time related costs (day rates) are generally the largest component of total well costs, while general and administrative costs are normally a small component of the total cost. Potential time related cost reductions achieved by introducing technical innovations through additional engineering manpower or the use of technical assistants, etc., may be considered. Internal costs such as shore base, flights, security, HSE and time writing will be properly understood to ensure that the correct costs are allocated. Cost allocations raised externally will be challenged when appropriate.

12.6 BENCHMARKING

Routine benchmarking of other Operators performance will be conducted, to ensure that achievable ‘Best in Class’ performance targets can be set and met. AMA1 will participate in performance benchmarking of other relevant Operators in the Sub Sahara/East Africa Region. AMA1 may also perform process and technology benchmarking on Operators in the Region who are best in specific areas of operations. Benchmarking will be carried out either through joint industry studies, commercial benchmarking studies (Rushmore) or by direct approach to other Operators to exchange performance data. The Performance Engineer will coordinate the benchmarking of International Operators for both performance and process information. The Subsurface Team and management will be provided with periodic performance





benchmarking summaries, showing AMA1’s performance compared to major competitors in that basin or region.





13 REVIEW & AUDIT

13.1 CAMPAIGN PLANNING REVIEW (DWOP/CWOP)

A review process for well and campaign planning at an appropriate stage in the planning stage will be established. The timing of the planning review will consider the completeness of the planning work and the time required to implement the changes brought about as a result of the review. Since several of the wells in the campaign are similar in design, they may be covered as one generic campaign well type. Reviews will include all personnel involved in the well or campaign plus drilling and completions personnel from the other well construction teams in APC (GOM and International). In addition, resource team personnel from HSE, Logistics, C&P, Aviation and others including subsurface team, subsea and contractor personnel, if appropriate. The results of the review will be documented and action items agreed. Action items should be carried in a tracking and closeout system.

From time to time, peer reviews involving competent persons outside AMA1 will be held. Such reviews will be formally minuted and actions closed out.

13.2 POST WELL REVIEW AND CAMPAIGN WRAP UP

A review process for well or campaign performance will be established following completion of operations. The review will include participants in the campaign in addition to contractor personnel. It will be an open and honest analysis of well performance. Candid assessment from all parties will be encouraged. Focus on performance, problems, initiatives that worked effectively and areas for improvement. The results of the review will be fed back to the current or next well or campaign planning. Action items will be carried in a tracking and closeout system

Significant technical findings including problems, solutions or initiatives that worked and may be applicable to other APC regions, may be sent out via technical bulletin.

13.3 AMS REVIEW

A formal review will be undertaken as an impartial assessment by the well construction management of the status and adequacy of AMS, including Technical and HSE elements. The objective of the management review is to ensure that the AMS (Technical and HSE) is at all times suitable, adequate and effective. The review will also include assessing opportunities for improvement and any need for change to the AMS including the Technical, Health, Safety and Environmental Policies.

13.4 TECHNICAL AUDIT

Technical audits of the rig, supply vessels, helicopters and other service contractor equipment, as appropriate, will be conducted and completed prior to contract award or, if not practical, as early in the campaign as possible. Technical audits will be conducted by AMA1 or qualified third parties under the





direction of the Operations Manager or Rig Supervisor. Such audits will include rig / vessel mechanical condition, lifting gear, etc, and safety systems, as appropriate. The scope and inspection criteria for technical audits will be reviewed and approved by the Operations Manager and must meet relevant AMS Standards and Guidelines. An audit of helicopter and fixed wing aircraft operations, organized by the Corporate Aviation Manager must be conducted prior to the commencement of the campaign. Follow up audits will be scheduled as appropriate





APPENDIX I: Notional Rig Spec





APPENDIX II: AMA1 Draft Rig Contracting Strategy A deep-water rig will be required to execute drilling and completions operations in the Golfinho-Atum discovery area. Rig market for deep water environment is currently at 50% rig utilization with most recently awarded contracts for a limited term (less than 6 months) with day rates of $185 – $265 k. There are rates indications from some published accounts (see Figure below) on some longer term contracts such as

1. BHPs 2-year contract with Transocean for the Deepwater Invictus drillship at $145,000 day rate, starting Q2, 2018 in the Gulf of Mexico

2. ONGCs 3-year contract with Vantage Drilling for the Platinum Explorer drillship at $108,000 day rate starting in Q4, 2017 in India.

3. Indicative rates for the lowest bid from a recent RFI issued by Tullow for a 4-contract in West Africa showed the lowest bid at $137,000/d for first year and a 2nd year rate at $157,000/d with rates for years 3 and 4 floating in accordance with oil pricing.

Ultra-deepwater dayrates (Source: HIS-Petrodata)

Based on Phase-1 well count of 15 grass root wells and 3 re-entries, a rig will be required for a period of 30 months including mob/demob, assuming a duration of 50 d to drill and complete each well and 32 days for the re-entries (drill and complete). For bid attractiveness, a 2 year fixed contract term plus 2 x 6 months extensions will provide greater flexibility. A better alternative that will minimize excess contract term exposure is to tie the rig contract to the full development of phase-1 wells with a floating time period. This way, there won’t be any obligation to keep the rig if the well construction performance exceed expectation.

Rig selection will depend on

• Rig Availability: Selection criteria will provide greater scoring weights to rigs that could be made available within a reasonable window of expected spud date in order to deliver expected number of wells before project 1st gas date.





• Deck Space & Hull Storage: Due to lack of local oilfield infrastructure, the remote area of operation and the fast pace/short duration nature of these wells, a rig with large deck space and maximum storage would be vital. Rig selection would be based on a worst case scenario of drilling and completing one well at a time. Due to long rig up times (efficiency/logistics), drilling/completions equipment such as the ones listed below may be required to be kept on the rig at all times.

o IWOCS o Brine filtration units o Gravel pack skids o Flowback/clean up package o Directional and mud logging units o Cement unit o ROV o Vacuum unit o Dryer/Centrifuge

In addition, it’s of vital importance that the selected rig has an adequate pit capacity to handle multiple fluid systems and utilizes an active pit management system to avoid fluid contamination issues.

• Dual Derrick Design: It is essential that the selected rig has dual derrick capability in order to enhance performance efficiencies, safety and cost effectiveness. Dual derrick rigs have been shown to improve performance by at least 15% as compared to single derrick rigs. This is one reason a lot of the latest rig design are dual derricked. The 20” casing could be made up, run to the mud line in the aft derrick and be ready to be stabbed in/RIH after jetting the 36” pipe via main rotary. In addition, all the BHAs, drill pipes/completions workstring/workover riser, casing/tubing can be racked back off critical path using the aft rotary. The efficiency of VIV riser suppression modules will be investigated to see if there is value in having such devices as part of the rig’s equipment package in the tender.

• Rig Performance & Safety Culture: Rig operations data, as captured, in openwells (for rigs that have worked under APC contract in the past), RigLogix, Rushmore, IHS and other sources will be analyzed to determine level of rig performance and safety culture.

• Contractor Management/Organization: Support and engagement of rig owner’s management is crucial to the success of the campaign. Anadarko’s previous experience with rig owners will be tapped into as a key indication. Also, of interest is the contractor’s organization and support structure for previous and current remote ops.

• Credit worthiness: The rig contractor’s financial health and solvency will be scrutinized to ensure that contractual obligation are able to be fulfilled during the period of the contract. This is especially important due to recent bankruptcies in the sector.

• Tree & Tubing Head Spool Handling: Rig will be capable of handling and running the SSTs off line (compensated crane, bridge crane and handling equipment). This will save the cost of contracting a dedicated vessel. This assumes that a support vessel from the subsea pipeline contractor will not be available at all times to install trees and/or tubing spool.





• Maintenance Culture & Inventory level: maintaining inventory level is currently an issue due to the prevailing tight budget. As a result, parts are being sourced from nearby cold stack rigs to maintain rigs in service. The ‘time based maintenance’ strategy where parts are replaced after cumulative hours of use is being replaced with a different strategy of repairing equipment after they are broken

Selection process will start with pre-qualifying rigs owned by established deep water rig contractors. They will be invited for a presentation on AMA1 drilling/completions plan and thereafter requested to provide a list of fit ‘for purpose rigs’ and potential modifications that will enhance the criteria identified above. The proposals will be analyzed with the objective of high-grading and selecting the top rigs. Note, these rigs will be selected from different contractors in order to increase bid competitiveness.

An invitation to tender document will be sent out (only for the pre-qualified rigs) for technical and commercial bids. The bids will be evaluated for an award recommendation. Approvals will be sought from management, partners and INP at each tendering milestones (tendering strategy, bid evaluation results and award recommendation). Details at each stage of the process include,

1. Pre-qualification Stage: a. Rig availability during the expected time of drilling Golfinho-Atum development wells. b. Provide a fit for purpose rig as per AMA1’s minimum technical spec requirement. Rig must

have adequate capacities to meet drilling, completions and subsea requirements. c. Demonstrated evidence of rig performance for rigs that are not newly built, including

personnel experience level. d. Support for new ideas, innovation and optimization to improve drilling/completion efficiency.

Ideas such as hopping with BOP stack in water, making BHAs, completions equipment off critical path must be embraced.

e. Provide strong evidence of rig crew safety culture working in remote environments, rig management systems

f. Ability to set up in country facilities to support rig ops (yard, warehouse, rig spares, riser storage, staff housing and office)

g. Ability for in country business registration within the 6 months govt stipulated period. h. Have a reliable logistics set up to independently manage shipment of spares, equipment and

services from within and outside of Mozambique without relying on AMA1’s set up. i. Have an audit verifiable system that ensures customs clearance, visa, immigration, work

permits, rig licensing and other govt required permits are not violated. j. Show strong evidence of management support of HSE, FCPA, UK anti-bribery act, local laws

and respect for local culture. k. Show desire to incorporate AMA1’s local content, training and Moz workforce plan l. Explore new ideas such as integrating Cmt unit, ROV, dryer/centrifuge combo, vacuum unit,

shaker screens, rig positioning (Fugro/UWS) and other rig dependent services to rig contract as per applicable specs





m. Minimize rig equipment failure allowance time for both subsea and surface equipment in any given month (cannot be banked). Keep regular maintenance (oil change out, slip/cut drill line, saver sub replacement, and black out tests) on AMA1’s time.

2. Invitation to Tender Stage: a. Prepare invitation to tender document for prequalified bids. The document will include

technical and commercial bid packages. Bid validity should be minimum 12 months from the day of bid submission deadline. This will allow sufficient time to analyze bids, seek 3rd party verification of rig equipment reliability/performance and work the award recommendation through management, partners and INP.

b. Prepare draft AMA1 rig contract with terms and conditions. Vet draft contract with legal. c. Send out tender package and draft rig contract to contractors. Provide sufficient time (90 –

120 d) for contractors to submit bid. d. Prepare detailed bid analysis strategy. Ranking matrix will include local content, workforce

plan and training. A technical/commercial bid evaluation strategy will be agreed upfront and documented before tendering

3. Bid Analysis Stage: a. Bids will be submitted in 2 parts (technical and commercial). The commercial bids for only the

technically approved bids will be opened for evaluation. Bid evaluation will be clear and auditable.

b. A day rate compensation and pricing model is still apt. Additional cost for extra personnel, tools, equipment and local set ups (staff housing, vehicles, warehouse and others) could be broken out from base rate and clearly marked.

c. Award recommendation will be based on technically qualified lowest commercial bid. 4. Award Recommendation Stage:

a. Present bid evaluation and award recommendation to mgt, partnership and INP. b. Secure mgt, partnership and INP approval on award recommendation c. Send letter of intent (LOI) to winning bid. d. Work with legal and contractor to finalize contract and letter agreement.

APCs experience in rig tendering is limited since all rigs were contracted through single source negotiations. However, from past experience in tendering for a rig with stage gate approval process through management, partnership and government entities, it should be expected that AMA1 process will take 15 months to finalize. Major work to be done and time breakdown are highlighted below;

o Tendering Strategy Approval: To kick off the process, it’s critical that the objectives and all

underlining processes are clearly defined and approved by management, partners and INP. A tendering strategy document is required to achieve these, it will highlight prequalification requirements, tendering process, contract value, and expected start date, contract duration, bid evaluation, award recommendation and other key information. This could be finalized within 6 weeks with key support from the contract/procurement team.





o Prequalification: A 6 months’ work will be required to narrow down and filter through a list of available rig options, contractor organization and performance records to high grade and select the top rigs and rig owners. Visits and travel may be required to contractor work bases and rig locations within and outside the US. Auditing available and public records for any indication of contractors’ FCPA violations, financial records, HSE compliance, drilling/completions performance and rig modification requirements would require some time. Deliverable includes a list of five pre-qualified rig owners and best ‘fit for purpose’ rigs that will be invited to tender. Key support will be expected from legal (FCPA/Credit worth), accounting (financial disclosures), HSE, contracts/procurement/business services, drilling/completions/subsea ops.

o Prepare Invitation to Tender Document: Time will be required to prepare a tender document and a draft rig contract needed to invite bids from the pre-qualified contractors. It is anticipated that the above can be accomplished in 3 months. Also, tenderers will be given 3 months to prepare bids for submission. This period will include various bid clarifications meeting and communications to tenderers. Support will be required from legal (vet draft contract), contracts/procurement, HSE, drilling/completions/subsea ops.. Deliverable includes an invitation to tender document, draft contract, bid evaluation matrix.

o Bid Evaluation & Award Recommendation: This is expected to take 6 weeks to prepare but additional time of 6 weeks will be required for mgt, partners and INP approval of the results.

o Letter of Intent & Rig Mobilization: Once approval is granted, a letter of intent (LOI) will be drafted by legal and sent out to the winning bid. The language in the LOI will commit the rig owner to start preparation towards mobilizing rig while the final rig contract and letter agreement are still being vetted. Preparation to mobilize rig may include any rig modification work, SPS work (it’s vital that rig is not taken out of service until all wells are delivered) and setting up local registration and presence (contractor yard, housing, transportation). It’s advisable to allot a 6 months’ allowance for this in the project schedule under a worst case scenario.





APPENDIX IIIa: AMA1 Draft Support Services Contracting Strategy The table below shows the various considerations for contracting services to support the well construction campaign. Note that the process to establish a service contract will be similar to the above process of hiring a rig. The Major Services contract will include; • Supply of large OD pipe and OCTG Casing and Tubing plus associated services • Provision of drilling fluid, reservoir Drill-in fluid, gravel pack and completion fluids services • Provision of Directional Drilling, MWD/LWD, Mud logging and Downhole tools services • Supply of Wellhead Equipment and provision of wellhead services • Provision of wireline logging and pipe recovery services • Provision of Completions Services and Supply of Completions Equipment (Screens, gauges, packers, safety

valves, fluid loss device) • Provision of Well test and Clean up Services • Provision of Casing and Tubing Running Services • Provision of Solids Control and Waste Management Services • Provision of ROV Services • Provision of Pumping and Cementation Services • Provision of Shorebase and logistics Services • Provision of Supply Vessels and support services • Provision of Fixed and Rotary wings Services





Major Services

Potential Tenderers

Pre-qualification Contract Strategy

1 Supply of OCTG large OD pipe, casing, and tubing plus associated services

TENARIS/Hydril, V&M, Mitsui, Nippon/Sumitomo Other suppliers

• All contractors require full vetting to determine readiness to provide services independently without heavy reliance on AMA1 infrastructure and personnel for logistics, immigration, visa and customs issues.

• Demonstrate strong evidence of QA/QC management system for remote ops environment.

• Ability to set up in country facilities to support rig ops (yard, warehouse, maintenance facilities, storage, staff housing and office)

• In country business registration within the 6 months govt stipulated period.

• Have a reliable logistics set up to independently manage shipment of spares, equipment and services from within and outside of Mozambique without relying on AMA1’s set up.

• Have an audit verifiable system that ensures customs clearance, visa, immigration, work permits and other govt required permits are not violated.

• Show strong evidence of management support of HSE, FCPA, UK anti-bribery act, local laws and respect for local culture.

• Show desire to incorporate AMA1’s local content, training and Moz workforce plan.

• Check if contractors are willing to provide full cycle services including pipe running, pipe inspection, storage and fabrication of extension joints to the WH housings through 3rd party arrangements.

• Estimated contract value for development work is $100 mm

• Tendering will offer the most cost effective option for pipe supply and provision of services.

• Send out tender document early to prequalified vendors to allow sufficient time for Selected contractor to be registered in country (process has been known to take more than 12 months) and also set up support infrastructure.

• Supply agreement and contract duration should be tied to the construction of the 18 development wells

• Bid validity should be minimum 12 months from the day of bid submission deadline. This will allow sufficient time to analyze bids and work the award recommendation through management, partners and INP. .

• Bids will be submitted in 2 parts (technical and commercial). The commercial bids for only the technically approved bids will be opened for evaluation. Ranking matrix will include local content, workforce plan and training. A technical/commercial bid evaluation strategy will be agreed upfront and documented before tendering.

• Ideas on pricing/compensation model still needs to be explored and discussed broadly. One idea suggests an all in rolled up cost per joint successfully installed. Pricing could be broken





Major Services

Potential Tenderers


into supply ($/ft of joint supplied) and service elements ($/day)

3 Provision of drilling fluid, reservoir Drill-in fluid, gravel pack and completion fluids services

Baroid, Baker, MI

• Contractors are required to provide drilling fluids services to drill wells to top reservoir, change fluids system to drill through reservoir and provide compatible fluid system for sand face and upper completion.

• As part of the services, contractors will provide gravel pack services (proppant/gravel, carrier/breaker fluids) including equipment (pumps, mixers, silos and others) and filtration units

• Readiness to pre-invest in onshore liquid mud plant and brine mixing/storage facilities should be verified. This may be crucial if the PLB is not ready by spud. Rig and supply vessels may not provide sufficient storage to minimize risk of fluid contamination.

• Contractors in country inventory will include all chemicals, additives and materials required for the drilling, completions and flowback phases of the well construction process. Also, contractor must have adequate spares in country for all service tools and equipment.




• Tendering will offer the most cost effective option for provision of services.

• Send out tender to pre-qualified contractors early to allow sufficient time for selected contractor to set up support infrastructure.

• Contract duration should be tied to the construction of the 20 development wells



• Ideas on pricing/compensation model still needs to be explored and discussed broadly.





Major Services

Potential Tenderers






4 Provision of

Directional Drilling, MWD/LWD and Downhole tools services

Schlumberger, Halliburton, Baker

Weatherford

• All contractors require full vetting to determine readiness to provide services independently without heavy reliance on AMA1 infrastructure and personnel for logistics, immigration, visa and customs issues. Schlumberger and Halliburton/Baker have reasonable presence in Mozambique and are fully registered to provide services. Weatherford has no visible presence yet. Sperry’s status will be ascertained before tendering.

• DD/LWD/MWD tools availability by the time of spudding 1st Golfinho-Atum development well. Also explore availability of special tools such as @bit gamma, rotary steerable (highly deviated wells)



• All potential tenderers are already registered in Moz.

• Contract duration should be tied to the construction of the development wells

• May need to pre-qualify Baker due to its association with GE and GE’s plan to spin its oil and gas division.

• WFT has been known to provide services in selected deep water location including Brazil but will need to be fully vetted during the prequalification stage.





Major Services

Potential Tenderers


• Capabilities to offer reliable tools as per attached DD/MWD/LWD tools requirements.


• Support for new ideas, innovation and optimization to improve drilling efficiency. Tools upload/download off critical path, minimizing tool downlink time and others.

• Crew should be able to communicate effectively and work well with AMA1 and rig crews









• Ideas on pricing/compensation model still needs to be explored and discussed broadly. Current wellbore construction timeline suggests breaks in the drilling sequence necessitating significant standby costs to keep basket of tools in country. If timeline does not change a footage pricing formulae may be more cost effective.





Major Services

Potential Tenderers


• Ascertain if contractors can effectively integrate other services such as fishing (cased and open hole), provision of down hole tools such as jars, X/Os, subs, PBLs, ASTs and service tools such as RTTS, circulation sub, storm valves.

• AMA1 wishes to eliminate day rates on provision of multiple backups for each hole section. Check contractors’ readiness to provide services without AMA1 specifying back up requirements. Can we push the burden on contractors without significant lost time on the rig.

5 Supply of Wellhead Equipment and provision of wellhead services

Drillquip, FMC GE One Subsea, Aker


• DQ running tools are robust and reliable, were used for 10-12 wells before complete strip down is required, engineering support weak. FMC tools not as robust as DQs, strong engr. support. AMA1 has no experience with GE, Aker and Cameron

• DQ provides an integrated service that includes large OD pipe/connector supply, supply and fabrication of wellhead equipment and extension joints (HP/LP WH housing and csg hangers). FMC supplies wellhead equipment, AMA1 had to contract Franks for supply of large OD pipes and fabrication to extension joints.

• Estimated contract value for development work is above $30 mm

• Explore possibility of a single source negotiation with the CPI winning bid. This will provide a seamless integration with subsea systems (CVT, THS, jumpers etc)


• Send out tender to pre-qualified contractors early to allow sufficient time for Selected contractor to be registered in country (process has been known to take more than 12 months) and also set up support infrastructure..


• Bid validity should be minimum 12 months from the day of bid submission deadline. This will allow sufficient time to analyze bids and work





Major Services

Potential Tenderers


• Supply of large OD pipes can be excluded from this service if results from item 1 above is positive (i.e any of the casing suppliers is able to supply large OD pipes in country).

• It may be more cost effective and efficient to lump wellhead service with the winner of the subsea CPI contract since the latter is expected to have an in country base.








the award recommendation through management, partners and INP. .






Major Services

Potential Tenderers


6 Well clean up and well test Services

Schlumberger Halliburton, Baker









• Estimated contract value for development work will be over $50 mm


• All potential tenderers are already registered in country.




7 Provision of Completions Services and

Schlumberger Halliburton, Baker,

• Services may include all running tools, equipment and materials to run screens, perform gravel pack






Major Services

Potential Tenderers


Supply of Completions Equipment (Screens, gauges, packers, safety valves, fluid loss device)

Superior operations, run upper completions, control systems and others









• Explore possibility of a single source negotiation with the CPI winning bid. This will provide a seamless integration with subsea systems (CVT, THS, jumpers etc)


• Schlumberger, Halliburton and Baker are registered to provide services in Moz.








Major Services

Potential Tenderers


8 Provision of wireline logging services

Schlumberger Halliburton, Baker










• Schlumberger performed work during the exploration and appraisal phase.

• All tenderers are registered in Moz but winning bid will need time to set up support infrastructure..




9 Logistics Base and support services

ENHILS, AMA1

• The creation of ENHILS and the likely construction of a Shorebase/port facility at Afungi by AMAI turnkey contractor has provided logistics services






Major Services

Potential Tenderers


options to AMA1 Well Construction for Phase-1 development.

• Rates from ENHILS for a yet to be constructed logistics base at Pemba will be compared with EPC contractor’s rate for the Afungi base.









APPENDIX IIIb: Contracts List & Prioritization

Contract Priority Comment

Rig 1* When is best time to secure rig to take advantage of soft rig market? Do we contract for time or wells?

Lower Completion Hardware & Services 1 Screens, packers, service tools, wash pipe, &

handling tools

Upper Completion Hardware & Services 1 Production Packer, SCSSV, DHPTG, Space-out

joint, control lines, clamps, spooling

Wellheads 1 Consider executing tender earlier than FID to mitigate interface issue with subsea tree vendor

Casing & Tubing 1 Include crossovers and burst disc subs, or tender separately

Fluids 2*

Drilling mud, completion brine, reservoir drill-in fluid, and filtration; Additional testing required before executing tender (need to begin before FID?); Mud plant build lead time to be considered

Gravel Pack Pumping 2 Proppant, gravel pack carrier fluid, skid pumping services; additional testing required before executing tenders

Directional Drilling Tools 2 Potential bundle with formation evaluation

Formation Evaluation 2 Require cooperation with Operations Geology to define work scope

Well Test Services 2 Includes fire control equipment

Cementing & Services 2 Bulk cement, chemicals, & pumping service

Solids Control Equipment 2 Cuttings dryer, any other kit beyond rig scope of supply

ROV 2 May be done in conjunction with rig tender





Helicopters 2 Potential joint service with Eni

Supply Vessels 2

Tubing & Casing Running Services 3 Bundle services for drilling & completion

Slickline Services 3

Electric Wireline Services 3 Cased hole, through tubing, pipe recovery

Coiled Tubing Services 3

Cementing Equipment 3 Float equipment, retainers, etc.

Shore Base Services 3 Trucking / cranes at port / yard facility

Fishing Tools 3

Wellbore Cleanout Tools 3

Drilling Rentals 3 Drilling jars, under reamers, etc.

Completion Rentals 3 Retrievable bridge plugs, service packers, etc.

Drill Bits 3 Primary and secondary provider required

Fuel 3

Mud Logging 3 Uncertain if required; bundle with other service





APPENDIX IV: Logistics Requirement

1. PSV Operations at dock a. Work one supply vessels at the dock to support one deepwater rig. Assume a 4-8 hrs spread

covering night and day dock operation for the duration of the drilling campaign (start in Q4, 2021 for 30 months)

b. Work one an additional boat at the dock to support well construction material/equipment transfer from Pemba. Assumption: boat will make at least 2 runs to Pemba every week

c. Make allowance to provision three support security vessels at the dock with fuel/water (one will maintain a 5km security ring around the rig and will only berth once every month at the dock. The other two will escort the 3 PSVs and berth with the PSVs)

d. Most loads will be under 45 t but expect occasional loads of 100 t. (160t crane will be adequate)

e. PSVs measures 240’ in length, 55’ in beam and 22’ in depth. Max draft 18’. One security boat is same size as PSV, the other two are 1/3 size.

f. Assume total no of port calls for PSVs and Security vessels to be 200 per year during the drilling campaign

g. Adequately sized cranes/handling equipment, Trucks/trailers, Forklifts, vehicles and other ancillary equipment will be required to manage load lifts and transfers between the dock and the well construction pipe lay down/staging area

h. Boats will be expected to be supplied with fuel and water at the dock. The fuel/water will be for the uninterrupted running of the boats and the rig. Boats/Rig fuel consumption is 1400 bbls/d; fresh water 500 bbls/d

2. Ocean Cargo Vessels

a. Assume 1 AMA1 chartered cargo vessel berthing at the dock once every quarter b. Expect to offload 30,000 mt of well construction equipment/materials (mostly OCTG

pipes/tubulars, chemicals) c. Customs clearance of vessel d. Adequately sized cranes/handling equipment, Trucks/trailers, Forklifts, vehicles and other

ancillary equipment will be required to manage load lifts and transfers between the dock and the well construction pipe lay down/staging area

3. Open Land Space a. Require ½ ha of land for well construction service provider to install the ff

i. Fluids test lab container ii. 500 bbls mud treatment and brine plants

iii. 12000 bbl mud and brine storage units iv. 10000 bbl base oil storage v. Bulk storage systems for the ff

1. Oilfield cement 2. Barites 3. Bentonite





b. If deck space is sufficient and deck rating is good, would prefer item (a) on the MOF dock. Deck rating should be greater than 50 tons/sq mtr

c. Pipe lines from the discharge end of the storage units and bulk plants will be required to be run to the dock (for boat transfers)

d. 2-1/2 ha of land for pipe laydown yard and well construction staging area e. 3000 sq mtr warehouse for storage of mud/completions chemicals

4. Waste disposal facilities a. Rig waste streams (slops, waste oil, wooden pallet, household and general waste) b. Waste will be segregated before arrival at facility c. Expect 60,000 bbls of slops (oily water) if rig is unable to separate out water for disposal

offshore as per environmental standard d. As an option if existing legislation changes to zero cuttings discharge before rig mobilization:

will need a drill cuttings treatment plant to treat 4000 bbls of cuttings per well for an approx total of 18 wells. Cuttings will be transported in 25 bbl boxes to plant with the PSVs. Each box will contain avg of 6.9% oil on cuttings by weight. The oil will have to be extracted and disposed of the cuttings in an environmentally acceptable way. An additional PSV will need to be worked at the dock in addition to the three regular under item 1 above.

5. Office Space a. One office space for one well construction logistics coordinator b. One office space for two materials men c. One office space for 2 pipe specialists d. One office space for one HSE e. Office spaces for 3 mud treatment and bulk plant operators





APPENDIX V: Project Level Risk Matrix

Health/Safety Environmental Community Project ScheduleProject Cost orAsset Loss Reputation

5

CATA

STRO

PHIC

Multiple FatalitiesSevere disabilities

Extended durationFull-Scale ResponseRequires corporate assistance and reported by international media.

Extensive community impact on a large scale and communicated by national/international media.

Extensive delay> 6 Months

Extensive cost impact>$500MM

Catastrophic impact on reputation. Loss of Operating or Development License.

4

SEVE

RE Single or few fatalitiesMultiple disabling injuries

Extended durationIn-country responseRequires in-country assistance and reported by national media.

Major communitySignificant delay3 - 6 Months

Significant cost impact<$500MM>$250MM

Significant impact on reputation and ability to operate. Large amount of resources required to rectify

3

MAJ

OR Serious Injury to Personnel

Severe but non-fatal

Local resource CommitmentOil spill response, communicated by media.

Impact on a large scale and communicated by national/international media.

Medium delay1 - 3 Months

Major cost impact<$250MM>$100MM

Significant impact on reputation and ability to operate. Some resources required to rectify

2

MO

DERA

TE Medical Treatment for Personnel/No Impact on PublicLost Time Incident (LTI)

Moderate/Limited Response of Short DurationOil spill response, communicated by media.

Moderate impact on local Community

Moderate delay1 Week - 1 Month

Moderate Cost Impact<$100MM>$5MM

Moderate impact on reputation and ability to operate. Some resources required to rectify

1

MIN

OR Minor Impact on Personnel

First aid onlyMinor/Little or No Response Needed

Little or no impact on public Limited or no media coverage

Minor delay< 1 week

Minor cost impact<$5MM Little or no reputation impact.

Risk Severity Evaluation Criteria





5 DES-13, EXT-2, LOG-2,RSC-3

CON-4, DES-5, EXC-2, EXC-7, EXC-8, EXT-4HSE-1, HSE-2, HSE-4

4 SEC-1, HSE-3 DES-7, LOG-9

COM-5, CON-1, DES-12, EXC-1, EXT-3, EXT-5, LIC-2, LIC-7, LOG-8,

RSC-1, RSC-4

DES-8, DES-10, EXC-3LOG-7

3 CON-2, DES-2, EXT-6, LIC-1

COM-1, CON-3, DES-6, EXC-5, EXC-6, LOG-11,RSC-2, RSC-5, HSE-5

COM-2, COM-3, COM-4, EXT-1, LIC-6, LOG-3

2 EXC-4, LOG-6, LOG-10SEC-2

DES-1, DES-3, DES-4, DES-9, LIC-3, LIC-4,LIC-5, LOG-4, LOG-5

DES-11

1 LOG-1 RSC-6

Risk Matrix Pre-Mitigation

Impa

ct





APPENDIX VI: Campaign Level Top Risk