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Best Practices for the FPSO Industry Joint Industry Project [JIP] Proposal

Endeavor Management 950 Echo Lane, Suite 200 P + 713.877.8130 Houston, Texas 77024 F + 281.598.8895 www.EndeavorEAG.com

Revision 2 Submitted by Endeavor Management

October 24, 2018

FPSO Best Practices JIP

© Endeavor Management. All Rights Reserved. of 33

ProprietaryandConfidentialMaterial

The ideas, pricing, and terms of this proposal are the property of Endeavor Management. We respectfully request that the information not be disclosed or distributed to anyone outside the requesting companies or their parent companies, without the express written permission of Endeavor Management.



Background

In the late 1980s, the offshore oilfield industry was moving rapidly into deep water. Large fields had been discovered in several areas of the world in waters that presented big engineering challenges to the industry. Over the course of the next decade, these challenges were met and overcome. As the decade of the 1990s matured, the industry steadily came up with innovative ideas that transformed fundamental challenges into proven solutions.

FPSOs were originally considered an economical solution for the production of marginal fields that otherwise might not be produced. Later, FPSOs became an essential component in developing remote offshore fields as Early Production Systems (EPS) with increasing production capacity, numbers of risers, and ever‐increasing water depths, which now allow their utilization as full field production facilities.

In the past 10 years, over 100 floating production systems have been deployed worldwide. Of the choices available to Operators, FPSOs have been selected almost 80% of the time as the system of choice for developing offshore fields. Semisubmersibles come in at roughly 10% with TLPs and Spars making up the remaining 10%. Even in the US Gulf of Mexico with its established oil and gas pipeline infrastructure, two FPSOs have been introduced in recent years. This trend of FPSOs as the preferred solution is likely to continue as shown in the graph below.

In today’s current price environment, understanding the best practices for managing, designing and executing projects is essential. On FPSOs this need is even more critical due to the numerous interfaces, contractual boundaries, and challenging regulatory, flag state and class requirements. Individual companies have performed significant work in this area and the industry in general has come a long way. However, there are still major differences in capital project execution and operations. Some of this is due to the different geographic areas where FPSOs are being deployed and subsurface differences drive many of the needs of the Topsides facilities. Having said that,



there are numerous considerations that are common to many of the cases and understanding the best practices in these areas should lead to streamlined projects with a stronger chance of achieving on‐time delivery and staying within budget.

It’s not uncommon for projects to perform best practice / lessons learned assessments at the conclusion of a project. What’s different about this Joint Industry Project (JIP)? Endeavor proposes to conduct this effort with a representative cross section of the stakeholder segments typically involved in delivering an FPSO: Oil and Gas Operators, leased FPSO providers, Shipyards / Fabricators, Engineering Companies and Class Organizations over a time span of multiple projects. Ideally at least 2 to 3 players from each of these groups would become member companies and collaboration across this cross section on best practices should yield significant improvements in alignment and the opportunity to reduce costs:

Alignment: Understanding the drivers, concerns and needs in a collaborative way across the stakeholders should improve alignment on any given project, minimize misconceptions and drive down risk thereby cutting costs and improving times to project approval and subsequent delivery times.

Execution Costs: Costs should be reduced through identification of fit for purpose bare minimum solutions, where they have worked before, and why and where they can be used again. This includes consideration of higher reliance on industry standards and specifications.

Operational Safety: FPSO operational personnel can benefit from common operational procedures and sharing of best safety practices. This will benefit the industry as personnel move between vessels with common procedures and methodologies.

Situation

There is no better time than the present to understand what the best practices are in executing FPSO projects. This JIP (Joint Industry Project) proposes to utilize Endeavor’s Expert Advisory Group to gather this information from each of the participants, evaluate that information for consistency and robustness, develop and propose metrics for assessing this information, hold lessons‐learned sessions with participants to rate practices and achieve alignment on what truly are the best practices across the issues being evaluated, and then to document this effort for distribution to all participants.



TheIssues

Each of these receives further discussion within this proposal:

A. Strategic Decisions B. Project Delivery C. Mooring and Offloading D. Hull Design E. Process Module Design F. Vapor Recovery, Gas and Water Treating G. Re‐deployment H. Operational Considerations

JIPProjectObjectivesandMethodology

Endeavor Management proposes to provide leadership in identifying and developing the best practices to address these Issues. We will serve as a focal point in obtaining the best practices on each of the Issues listed herein from the participants, generate proposed metrics for evaluating the data (where appropriate), facilitate a series of workshops with the participants to achieve alignment, ranking and selection of best practices, and then generate documentation for distribution. Specific details of each Issue’s scope are shown in that section of the proposal. In general, the methodology for each Issue of the JIP is as follows:

Stage 1 Data Gathering

Proceed with Issue definition as follows:

• The Member Companies will be asked to nominate Subject Matter Experts (SMEs) to assist in the technical definition and provide comments and guidance as each Issue Team moves forward. These SMEs will serve as technical reps for the Member Companies.

• It is not mandatory for a Member Company to have SMEs but it would be beneficial. • From this point forward in this Proposal, when Member Companies are mentioned it is

presumed that the Member Companies may include their own SMEs in the transactions of the Project – or not include ‐ as they see fit.

• Endeavor will generate a proposed list of what documentation is needed for each issue to be evaluated and what metrics could be used to assess best practices.

• This summary will then be sent to the JIP Member Companies in draft form for review. • Endeavor will review this information with the Member Companies in a (Technical) Kickoff

Meeting for each Issue, solicit final comments, achieve alignment on evaluation drivers and agree on timing and data to be submitted by participants.

• Member companies will then provide the data for each of the Issues, so that this data can be assembled and initially evaluated for preparation of Stage 2 – Evaluation Results and Lesson Learned for each of the Issues.



Stage 2 Compiled Data Review / Evaluation Results and Selection of Best Practices

• Endeavor will compile the data received from the member companies and perform an initial evaluation against the metrics previously agreed to in Stage 1.

• Endeavor will hold a workshop for each issue where the compiled data will be reviewed, the results of the assessment metrics discussed and various best practices and lessons ranked.

• Endeavor will facilitate a discussion between workshop participants about each practice to ensure a common understanding and alignment between member companies.

• When all Issues have been documented, Endeavor will meet with the JIP Member Companies collectively for open discussion regarding these Issues. It is planned that these meetings will be handled on an Issue‐by‐Issue basis, similar to the Kickoff Meetings.

Stage 3 Results Review/Final Review: Report, with Deliverables

• The results of Stages 1 and 2 will be revised to reflect the comments and discussion obtained via the review meetings. The findings will be documented to the JIP Member Companies. Each Issue summary will include recommendations for follow‐on evaluation after this JIP, as appropriate.

• Publish the report to all JIP Member Companies, along with a summary presentation. • In order to stimulate industry involvement in collaboration toward FPSO Best Practices,

Endeavor will present a summary of the findings at appropriate conferences and industry gatherings and publish in industry publications.

AssumptionsandConstraints

Endeavor Management will provide professionals with appropriate backgrounds to facilitate and participate in the reporting and review process and to share their knowledge and experience. The JIP Member Companies will share sufficient information about their technical requirements, operational experience to date, future needs, service company offerings and related information, so that the Endeavor Advisors can develop informed assessments of the current status of the industry and the most attractive best practices for each Issue. Endeavor will establish guidelines with the Member Companies to outline when and how the information within the scope of this study will be discussed or disclosed (a) between JIP Member Companies, and (b) to any party outside the JIP Member Companies.



ProfessionalFeesandExpenses

This work will be performed on a lump sum basis. Endeavor has allocated a fixed number of man‐hours for each Issue and will adjust the hours between Issues; if one area needs less work and another needs more work during this JIP effort. It is presumed that each of the Member Companies will nominate a single‐point of contact to monitor progress and to coordinate with its SMEs.

Each JIP Member Company will be billed half of their total amount at project kick‐off and the other half after the draft Final Report is issued. All invoices are due in 30 days. The price per Member Company is $79,000 based on 10 Member Companies. This includes expenses such as travel to Houston for meetings for Endeavor personnel who live out of the Houston area.

The Member Companies will be notified in advance if the project requires additional hours due to significant changes in project scope. Additional work would only occur if approved by unanimous approval of the JIP Member Companies.

If more than 10 companies join this JIP, the additional funds will be used for additional study on the existing JIP Issues or for new related Issues.

The above proposed price of $79,000 per Member Company includes:

• Stage 1 summary defining each of the identified Issues and proposed metrics for evaluating the data to be received, in draft form for review by the Member Companies.

• Participation in a Kickoff Meeting where the issues and proposed metrics are discussed. • Compilation and initial evaluation of the data received from member companies. • Stage 2 Participation in each of the Issue workshops including review of the initial evaluation

results and a facilitated discussion on the best practices to achieve a ranked selection. • Completion of the overall report documenting the results of Stages 1 and 2. • Preparation of a report summary in PowerPoint format for use as:

o electronic copy to each Member Company for internal use. o Presentation of the report summary at appropriate shows, conventions, conferences, and

industry publications by Endeavor and/or the JIP Member Companies.

TimeFrame

Endeavor proposes to start the work as soon as JIP Member Company participation is confirmed. Stage 1 will be ready for review in approximately 8 weeks after the award date, subject to completing the meetings with Member Companies and receiving the Member Company data. Stage 2 will be ready for review approximately 8 weeks after the last Stage 1 review meeting is completed. The Stage 3 final report will be delivered 4 weeks after final comments are received from Stage 2.



Contact

Should you have any questions or need additional information regarding this proposal, please contact either:

Jeff Dice at 832‐465‐2879 or at [email protected] Bruce Crager at 713‐459‐1215 or at [email protected] We hope your company will choose to work with Endeavor on this challenging project. Please contact Jeff Dice or Bruce Crager to confirm interest in joining the JIP and to request the Member Company Agreement.

Sincerely,

Bruce Crager Executive Vice President – Expert Advisory Group Endeavor Management www.endeavorEAG.com

Jeff Dice, PE, PMP FPSO Best Practices JIP Project Manager Endeavor Management www.endeavorEAG.com



ISSUE A – STRATEGIC DECISIONS

Summary

The selection of the FPSO as a development solution has become more prevalent in recent years and is more established today than it was years ago. But strategic decisions made soon after FPSO concept selection can impact a range of performance parameters during both project execution and the life of the field. While many strategically important decisions are covered in subsequent sections of this JIP, two (2) are dealt with in this section. The first relates to the manner and means of defining the technical requirements, i.e. the TECHNICAL SPECIFICATION. The second relates to the asset ownership, i.e. LEASE v. OWN.

Background and Overall Methodology

Over the years more than 200 FPSOs have been installed and commissioned generating a large body of data backed experience. This experience should serve to aid in both planning and executing any new FPSO development. But not all of these experiences have been good. Few would argue that those held up as models of excellence in project execution could not be improved upon.

For years operators have tirelessly cataloged “lessons learned” for use by project planners as a means of achieving better future results. But cataloging is difficult because of the enormous array of issues involved and the even larger number of causative factors. In fact, the effort is so difficult that the utility of the end result Is often questioned. The purpose of our efforts on these two issues is to capture at a high level and summarize lessons learned across a range of good and bad experiences for the benefit of each Member Company.

That there are several different ways of paying for the assets comprising the FPSO development is obvious. At one extreme is the capital purchase or build to own option. At the other we find the long‐term lease with assorted contract options. In between are many alternatives each having its own advantages and disadvantages. But which way is best? Few will dispute that what is good for one operator may not work at all for another. In some cases, the selection will be based on the operator’s preference or past experience. In other cases, the selection will be heavily influenced by taxes or the financial condition of the operator and its partners in the venture. The purpose of looking at this issue is to summarize the perceived advantages and disadvantages of the two extremes.

Discussion: TECHNICAL SPECIFICATION

Specifications for an FPSO project have been an area of concern and debate in the industry for a number of years. The selection of a suitable and achievable specification that is right for a given project can have strong benefits in terms of cost and schedule, as well as certainty of delivery. Furthermore, sensible HSE and quality standards can result in a more practical design basis, avoid over working detailed designs and package specifications and permit easier future expansion or modification of the plant when the properties of arriving well fluids turn out to be different than forecast.



From an Operator’s perspective two important distinctions should be highlighted between FPSOs and other offshore producing platforms. The first is that the FPSO is subject to maritime standards, conventions, rules and regulations which have no application to a bottom supported platform. It can be the case that client teams with topsides experience are less familiar with the marine systems while marine personnel have limited experience with production systems. The second is that there are a number of able contractors with excellent experience building, converting, installing and operating the FPSO. These companies will build to lease or build to own. They can design, procure and install the seabed systems tied back to the FPSO. They can use their own standard specifications or the those provided by contract. The only thing they will not do is drill and complete the wells.

Like any upstream project, FPSO cost and schedule can be adversely affected by high‐end or unconventional company‐driven requirements (e.g. metallurgical composition, area/height/access requirements, equipment redundancy, accommodation standard, etc.). FPSOs do have additional exposure to these factors in way of the turret/swivel system (if required) and riser fatigue life where fixed permanently. The equipment sparing philosophy must come out of the Operator’s uptime expectations for the life of the field. The suitability of existing utilities/accommodation (especially if converted from maritime service) must also be considered. The HSE standards, quality standards and risk matrix selected all weigh on the FPSO project cost and schedule. The use of ALARP principles and setting permissible residual risk levels are important determinations which when set cannot be easily altered.

Discussion: LEASE v. OWN

For many of the early developments the lease plus contract operate option appealed to operators with offshore developments billed as “marginal” or “fast track”. As the industry matured the benefits of owning the floating assets became more appealing especially where reservoir characteristics predicted large recoverable volumes over longer periods of production. In certain cases, major oil companies have self‐performed the EPCI scope and owned the asset from the outset. In other cases, the EPCI contractor became the asset owner contractually where the developer held an option to acquire the asset for a certain period of time after the start of operations. The point here is that the developer of a new field has so many well‐ developed choices and contracting variations that the process of making a decision would seem easy. Only the shared experiences of JIP participants can confirm whether any of the considered alternatives entail potentially significant project risk.



Detailed Methodology:

For each of the two issues given above the JIP Consultant will establish and communicate to participants a set of base case Issue A deliverables.

A kickoff meeting with JIP participants will be held to review and modify as necessary the deliverables list.

The consultant will communicate to all participants the modified list of deliverables together with a request for information based on each representative’s experience. If the representative of the participant is not the company’s subject matter expert on the subject, he / she is invited to support the information submitted with published articles or other substantiation.

The JIP Consultant will receive all information submitted, capture data relevant to the agreed deliverables and tabulate it in a form which will allow the group to consider the quality and veracity of the conclusions implied by each draft deliverable.

The group of participant representatives will meet to review and discuss the draft. Where there is a consensus on each conclusion the deliverable will be considered accepted. Conclusions which are not accepted will either be changed in a way to be accepted or left as indeterminate.

Deliverables

The final draft will be incorporated in the master JIP report covering all eight issues.



ISSUE B – PROJECT DELIVERY

Summary

Project Delivery addresses three major issues associated with successful delivery of FPSO projects including: project organization, interface management, and change management.

FPSO projects have distinctive characteristics such as storage and offloading with strong marine industry links that are significantly different to other floating production systems and which require specific resources and organization to properly manage and deliver successful projects. In addition, FPSOs have unique mooring, motion, and marine challenges to be overcome. The integration of these resources into the overall project team is critical for success in terms of schedule, budget, and risk control.

Effective management of interfaces is a critical success factor for delivering any project. The effort required to do this increases exponentially with complexity. FPSOs are on the high end of the complexity spectrum due to the multiple functional requirements spread across several contractors and multiple equipment suppliers.

Change during capital projects is a given. Failure to accept, recognize, plan for, and respond to change can be attributed as one of the four greatest contributors to adverse megaproject performance. The impact of change on the business goals related to large oil and gas capital projects is significant ‐‐ and appears to be an industry given. The impacts can be very visible and predictable or hidden and show up indirectly. Most of these have a negative effect on the project cost, outcome and stakeholder relationships.

This JIP will develop ‘best practice’ measures to assure project organization, interface management, and change management are in place within owner and contractor groups that come together to build an FPSO.

FPSO project teams need to be organized to address the key technical and complex integration needs of an FPSO. Generally, small teams with broad knowledge sets are adequate to select between a Spar, a TLP, or a Semi, but the added complexity of the FPSO requires expertise in the earliest stages of project selection, when other floating production system concepts are vying for consideration. Examples of this include: overlooking details around required storage, under appreciation of being able to construct/pre‐commission at the quayside, under emphasizing issues surrounding offloading options, or over simplifying mooring selection.

The Operator and / or the FPSO Owner is responsible for setting the right framework in place for effective interface management. The Basis of Design is used to capture this information and it’s very useful to have an associated timeline of when decisions need to be made to lock in that design basis information in accordance with the overall project schedule. On FPSOs, the functional requirements and associated interfaces are impacted by contractor and vendor selection. An interface management system can be populated that includes: a description of the interface item, who owns the interface, what information is needed to define the interface by whom and when, the due date of the interface and any references to applicable drawings,



specifications, etc. The interface management system with associated responsibilities should then be reflected in the contracts and should include the need for providing adequate resources to participate actively in the interface management system and associated meetings.

FPSO developments are comprised of 5 major components (Topsides, Hull, Mooring, Risers and Subsea) that are significant projects in their own right. As a field development, these components comprise a system and are therefore highly integrated, yet primarily engineered and constructed separately. Given these complexities, project execution strategies are less than optimal with regard to minimizing potential change. On top of the decisions made, the project leaders have been conditioned to expect and live with constant changes and get rewarded for pulling it out of the fire – certainly not conducive to drive sustainable improvements.

Stage One

High level survey of the Member Companies will be done to:

• Define the current state of the art for project organization. • Each Member Company will collect or develop organizational components for FPSO projects

based on key technical, operational, and contractual factors possibly including those that differ from other floating production systems.

• Host an SME review of shared factors and staffing options, including key lessons learned (both to avoid and to implement).

• Define the current state of FPSO interface management. • Each Member Company will provide the interface management system framework used

previously. • Host a participant review of interface management options, including key lessons learned

(both to avoid and to implement) • Define the current state of factors impacting significant changes on FPSOs. • Each Member Company will collect or develop FPSO project case studies that focus on

significant changes that occurred. These may be compiled from lessons learned, formal project change instructions, outcomes of formal reviews (peer, process safety, regulator, and business gates), contractor variation logs, risk analyses, and other living documents compiled during the course of the project.

• Host an SME review of change management case studies and categorize significant common changes.

Stage Two

• Based on the results from Stage One, identify the key drivers and/or unique operating conditions the operators consider as a basis for developing the project organization, interface management, and change management.

• Project Organization will focus on Organizational Structures for various Contractual Options. • Interface Management will focus on Basis of Design Outline, Interface Management System

Description, and Contractor Matrix Description.



• Change Management will focus on developing a process to find ways to identify common sources and minimize impacts of changes using a bowtie diagram method, commonly used in hazard and safety management analyses.

Stage Three

• Collate the results of Stage Two to capture key lessons learned from the Member Companies. • Make recommendations as to best practices identified during the study and factors to be

considered for project delivery.

Deliverables

The deliverables for this section of the JIP will be a final report that includes:

• Key lessons learned as a result of the study. • Recommendations as to best practices: • Organization Chart templates for small, medium, and large FPSO projects • Interface Management Matrix template for typical project • Change Management flow chart template • Generalized data provided by the Member Companies as a result of the survey undertaken in

Stage One.



ISSUE C – MOORING AND OFFLOADING

Summary

Once an FPSO is selected as the field development option, a key decision will be related to the selection of mooring, risers and associated oil export offloading system. Important considerations associated with this decision will include the (1) type of site‐specific metocean conditions at the FPSO location, (2) need to disconnect the FPSO from the mooring system to avoid icebergs, or when hurricane conditions are anticipated, (3) field architecture requirements related to the size, number and pressure ratings for the risers/umbilicals and associated turret/fluid swivel system, and (4) type of export tankers to be deployed (i.e., Dynamically Positioned (DP) shuttle tankers, or standard trading tankers with supplemental tug support). In addition, the selection of the FPSO mooring/offloading system is impacted by the associated capital/operational costs, as well as the owner’s/operator’s perception of operational risks.

Discussion

A review of past FPSO installations indicates a wide range of mooring/offloading system options, even for FPSOs located in the same operating region. For example, while "passive" (i.e., naturally "weather‐vanning") turret‐based FPSOs with DP export shuttle tankers are dominate in the North Sea, there have been several circular FPSOs based on a spread mooring with oil offloading directly to DP shuttle tankers. In this region, there are also a number of FPSOs with “active” turret systems that require thrusters to maintain heading/position control. Another example is offshore West Africa, where there is a mix of turret‐moored and spread‐moored FPSOs employing either direct oil offloading to an export tanker, or using Catenary Anchor Leg Mooring (CALM) offloading systems located some distance away from the FPSO.

The proposed scope for this Issue has been developed to capture the various decision elements and logic associated with the owner’s/operator’s selection of the FPSO mooring/oil offloading system, with an overall goal to develop systematic guidelines for the evaluation and selection of the mooring/offloading system for FPSOs, based on past industry experience.

Stage One

Define a representative set (6‐10) of existing industry FPSO applications with the following characteristics:

• Spread‐Moored system • Turret‐Moored system (including permanent and disconnectable systems, "passive" or

"active" turret moorings) • Direct (Tandem) Tanker Offloading System or offloading via a CALM Buoy system (or

equivalent) • Various operating locations including:

o North Sea/West of Shetlands o Brazil o West Africa



o South Asia/Australia o Eastern Canada o Gulf of Mexico o North Africa/Mediterranean

• For each representative FPSO application, capture the logic/decision analysis leading to the selection of the mooring/offloading system via direct discussions with the Owner/Operator (or Contractor) of each application. Each Member Company will be asked to provide information on their respective FPSO project related to the selection of the mooring and oil offloading system.

Stage Two

Based on the results from Stage One, identify the key drivers and/or unique (environmental or other) conditions leading to the Owner’s Operator’s selection of the mooring /offloading system. It is anticipated that the types of drivers/conditions to be identified include:

• Site‐specific environmental (metocean) conditions, including the severity and directionality of wind, wave, and current

• Ability to disconnect from the mooring/riser systems to avoid icebergs/ice flows, or when extreme (e.g., hurricane or cyclone) conditions are anticipated

• Complexity of the field architecture, including number, sizes, and pressure ratings of the various risers/umbilicals to be supported by the FPSO and/or the associated turret/fluid swivel system

• Type of export tankers employed, including dedicated shuttle tankers (with or without DP systems), or standard tankers with tug assist

• Relative Capital and Operational Costs • Perceived Operational Risks, and • Design Life (early, phased or full‐field development).

Stage Three

Based on the drivers / conditions identified in Stage Two, develop a set of guidance notes defining a clear path to the selection of the type of FPSO mooring and the associated offloading system, based on key elements associated with the proposed application. Included in the guidance notes will be a detailed decision matrix that captures the key elements (i.e., drivers, conditions) identified in the study.

Deliverables

The deliverable for this portion of the JIP will be a final report that will include:

• Guidance notes and detailed decision matrix for the evaluation and selection of the FPSO mooring and offloading systems.

• Key drivers identified through review of representative industry FPSO applications. • Data captured from discussions with the owners / operators of the Member Company’s SMEs

for their respective FPSO applications.



ISSUE D – HULL DESIGN

Summary

Hull Design has an important influence on a successful FPSO project. A structured decision‐making and design process is important to ensure timely readiness of a suitable hull and marine systems, ready for topside facility integration and hookup.

A major early decision will address whether to convert or newbuild the hull. The typical basis for a conversion would be a trading tanker of sufficient size to meet storage requirements. However, other vessel types have occasionally been utilized, depending on market situation and availability of suitable hulls.

Newbuilds may be customized for the application. A hybrid approach would be to adapt a standard yard design, typically a trading tanker, with selected modifications for the FPSO application, after the original hull delivery. If the FPSO is expected to be on station for many years, the option of having no propulsion system should be considered.

Whether newbuild or conversion, a suitable hull must be configured or obtained with due consideration of required storage volume, cargo/ballast handling systems, topsides weight, weather at location, regulatory constraints, on‐station repairs and maintenance over the full operating life and tank/skin protective configuration. The latter issue encompasses the concerns of double-hull, double-side, or single-skin configuration, and/or the possible option of local protection (e.g. provision of outboard structure, cofferdams or sponsons in waterplane area).

The industry typically utilizes marine Classification Societies to provide assurance for FPSO hull and marine systems. The scope for Class will likely include moorings and may also include process facilities. Class can play an important role in conformance with regulatory and Flag State requirements for an FPSO. A strategy for Class or alternative means of marine assurance and marine regulatory approval must be in place as part of hull selection and design.

Key Tasks to be addressed in this section include:

1. Important considerations in selection of newbuild or converted hull for an FPSO 2. Optionality available for FPSO tank configuration and protective features for spill risk

mitigation 3. Strategies available and key considerations for 3rd party assurance and regulatory

compliance, considering both Coastal State and applicable International requirements. These tasks will be addressed by summarizing industry and expert views, conducting a workshop session to obtain Member Company input and consensus, compiling and reviewing consensus views with SMEs, and reporting the results.



Stage One

Develop a summary of current FPSO/Trading Tanker fleet hull/tank configuration, by region/age.

Summarize existing International/Flag State regulations for FPSO hull/tank configurations.

Summarize available concepts and tradeoffs of the various hull/tank configurations in the context of regulatory framework, Classification Society requirements, risk mitigation, fabrication/renewal, inspection/maintenance, need for propulsion and operational tradeoffs.

Survey SMEs to prepare a summary description of Classification and marine regulatory/Flag State governance of FPSO vessels, and 3rd party assurances, so that the overall roles are distinguishable.

Survey SMEs to summarize typical Classification strategies adopted for FPSOs.

Work with SMEs to identify key Classification interfaces with the Hull, including mooring/turret, risers, and process facilities (if classed).

• Host an SME workshop on the above topics and request pertinent data from the SMEs.

Stage Two

Outline the critical content of a typical FPSO hull SOR (Statement of Requirements) and discuss the needed level of definition and early-stage interface management.

Summarize best practices in conversion candidate condition assessment, use of Class Information, and important considerations in care and delivery of the candidate hull to the yard in a suitable condition.

Develop a Checklist to guide the hull conversion from the delivery voyage, cleaning, assessment, and through planning and initiation of steel replacement, systems, and plans for coating renewal or replacement, with special focus on double-hull conversions.

Develop a Strategy for long‐term (full operating life) integrity management of hull, including corrosion protection and antifouling, and all operating systems.

Summarize best practices for cargo/ballast handling including maintenance / repairs / replacement while on‐station. For conversions develop a Checklist for verifying suitability of existing marine systems.

Summarize best practices for newbuild hull design including extent of early shipyard involvement and use/suitability of marine standards and specifications.

Develop a Checklist to guide a newbuild hull project into shipyard contract award and early-stage project execution.

Compare/contrast new build and conversion considerations and outline advantages/disadvantages.

Outline options regarding classification of the hull/mooring or the entire unit.



Stage Three

Collate the results of Stage Two to capture key lessons learned from the Member Companies and Endeavor Advisors.

Make recommendations as to best practices identified during the study and factors to be considered in design of the hull.

Deliverables


Tanker and FPSO fleet databases summarizing hull/tank configuration data (spreadsheets).

Summary of existing hull tank configuration regulations for Tankers and FPSOs.

Discussion of viable hull/tank configurations for FPSOs (including tradeoffs and constraints).

FPSO SOR Requirements and checklist with discussion of best practices.

Hull design checklist of important selection factors, including summary of best practices.

Hull conversion selection and Early-execute stage Best Practices checklist. Newbuild hull design and early-execute stage Best Practices checklist. Discussion of Class, Flag, and marine regulatory roles / governance.

Overview of typical Class strategies adopted for FPSO hulls, with tradeoffs.

Discussion of class scope and associated interfaces, with tradeoffs.



ISSUE E – PROCESS MODULE DESIGN

Summary

This scope on Process Module Design addresses three major areas associated with the design, installation, and placement of the process system modules on the FPSO. These are:

• FPSO Operability • Crew Safety • Installation and interfaces considerations between the hull and the process modules, which

need to be addressed during the design of the FPSO.

Stage One

High level survey of the SMEs to:

Define the current state of the art for module design and placement.

Placement of the process modules to reduce risk to the crew on board.

Operability issues associated with the location of various pieces of equipment within the modules.

Define the current state of the art for module installation.

Build the modules piece by piece on the hull’s process deck or install the modules as larger packages placed on the hull?

Define interface issues between the process modules and the ship’s hull.

Differences in design methodologies between marine and process engineers. For example, using different FEA models makes it difficult to determine the effects of the process modules on the ship and the effects of the ship on the process modules.

Structural and piping interface issues because process modules tend to be more rigid and ship hulls tend to be more flexible.

Location of the structural elements required to attach the process modules to the ship’s deck.

Piping and electrical interfaces between the topside process system, accommodations and other systems in the hull.

Methods to allow for future expansion of the process in the field (extra deck supports, piping penetrations, cable trays, etc.)

Stage Two

Based on the results from Stage One, identify the key drivers and/or unique operating conditions the Member Companies consider as a basis for developing the process module design, including placement on the deck of the ship.

• Define the installation issues encountered during design and identify best practices for handling these installation issues.

• During design of the topsides, what other factors need to be considered? • Health, Safety and Environment considerations. • Preliminary commissioning and startup.



• Scale up to meet future requirements. • Accommodations interfaces with the process system. • Inerting system interfaces between the process system, power generation system, and the

storage tanks in the hull.

Stage Three

• Collate the results of Stage Two to capture key lessons learned from the operators. • Make recommendations as to best practices identified during the study and factors to be

considered in design of the topsides.

Deliverables


• Key lessons learned as a result of the study. • Recommendations as to best practices. • Data provided by the Member Companies as a result of the survey undertaken in Stage One.



ISSUE F – VAPOR RECOVERY, GAS, AND WATER TREATING

Summary

This Issue addresses three major areas associated with the design of the process system on the FPSO: vapor recovery, gas handling and disposal, and water treatment and water injection. Since the industry seems to have settled on a design for the separation of the oil, water, and gas with only a few modifications in the basic design to handle unique reservoir conditions, separation of the oil, water, and gas will not be considered here.

The global trend toward reducing greenhouse gas emissions has created the need for operators to develop and install methods to minimize emissions from offshore production units such as FPSOs. This Issue will focus on the three aspects of gas handling that can effect emissions from an FPSO: 1) type of vapor recovery used, 2) type of tank inerting used, and 3) disposition of the gas once it has been recovered.

In addition, Country regulations are becoming more stringent regarding the disposal of process water overboard and reducing the acceptable levels of oil in water as well as regulating other constituents in the produced water discharged to sea. Operators are looking for low cost methods to increase oil recovery. One of those methods is waterflooding which will be considered as part of this Issue.

Stage One

High level survey of the SMEs to:

Define the current state of the art for vapor recovery available to FPSO operators.

o Venting/flaring using existing tanker systems o Gathering and compressing the gas using Vapor Recovery Units (VRU) o New Technology currently in development (if any)

• Define the current methods being used for cargo tank inerting and gas freeing.

o Tanker based inert gas generators using flue gas from the boilers o Dedicated inert gas generators o Using produced gas from the process plant

• Define the method currently being used for disposal of the gas once it has been collected.

o Fuel for the FPSO o Flaring o Venting o Compression and reinjection into a reservoir o Compression and recycling through the process plant

• Define the current state of the art for water treating and disposal overboard.

o Regulatory requirements now and in the future o Best practices being used or developed



Define the current state of the art for water treating equipment and practices.

o Water quality specifications o Best practices being used, including older technologies which might be more cost

effective from a Capex/Opex standpoint

Stage Two

Based on the results from Stage One, identify the key drivers and/or unique operating conditions the Member Companies consider as a basis for developing the process design.

• The results of Stage One will also be used to identify the challenges faced by the industry as a result of their choice of technology for gas handling and water treatment.

• Any interactions between the vapor recovery, tank inerting, and gas disposition methods selected will be identified.

• Does the selection of type of gas disposal have any influence on the type of tank inerting used? For example, typical flue gas inerting systems may be too high in oxygen content to allow mixing of the gases recovered from the tanks with the process system fluids.

• What factors need to be considered when selecting the method for vapor recovery given the type of gas inerting and gas disposition?

• What flexibility, if any, should be designed into the water treatment facilities to handle future regulatory changes?

• During design of the vapor recovery, gas handling, and water handling systems, what other factors need to be considered?

o Health, Safety and Environment topics o Preliminary commissioning and startup o Gas freeing of tanks while in operation for hull inspections o Turndown and/or scale up to meet future requirements o Emergency shut downs.

Stage Three

Collate the results of Stage Two to capture key lessons learned from the Member Companies and other industry contacts.

• Make recommendations as to best practices identified during the study and factors to be considered in the design of the vapor recovery. gas handling, and water handling systems.

Deliverables


• Key lessons learned as a result of the study. • Recommendations as to best practices. • Data provided by the Member Companies as a result of the survey undertaken in Stage One.



ISSUE G – REDEPLOYMENT

Summary

Because they are highly autonomous floating systems, FPSOs offer high potential for relatively simple removal and relocation compared to most other production system alternatives. As examples, the industry’s second FPSO (FPSO II, SBM) is now on its 4th location after an initial 11‐year deployment and Petrojarl I (Teekay) commenced production in May 2018 on its 12th redeployment. Partly because of this mobility, FPSOs are often selected for new or marginal field developments where field life may be short or where produced fluid characteristics are less certain due to limited data. Shutdown / removal / relocation of an FPSO has many project delivery challenges and success factors in common with commissioning and startup.

Redeployment is viewed differently by oil company operators who have to choose between available field development options vs. FPSO providers offering new and existing vessels. Each has differing views on content of the design specifications and adoption of design codes. Understanding the future service potential from both sides early on can result in a more redeployment friendly initial design where surprises are minimized.

Any redeployment will require study and understanding of the technical issues surrounding the new location including water depth, environmental conditions, regulatory differences, production fluids, storage/offtake requirements, subsea systems interface, moorings, shore support, etc. Compromises are likely needed and a redeployment/conversion specification that provides the best balance between cost, quality and schedule is the challenge.

If a decision to redeploy is made, the overall goal is to enable a safe, successful, and on‐time shut‐down and disconnection of the FPSO facility followed by installation and start‐up at the new location. In most cases, the FPSO will be modified/repaired in some way prior to moving to the new location. Once on the new field, safety considerations arise as systems are re‐energized and SIMOPS must consider more than just physical interference. This JIP will help participants understand key elements to include in a well‐engineered redeployment execution plan.

Key Tasks to be addressed in this scope include Best Practices for: (1) inputting to the initial design FPSO specification that adequately considers removal/relocation of FPSOs, (2) preparing a redeployment/conversion specification and (3) preparing a redeployment execution plan for FPSOs. These tasks will be addressed by summarizing industry and expert views, conducting a workshop session to obtain Member Company input and consensus, compiling and reviewing consensus views with SMEs, and reporting.



Stage One

Meet with SMEs to summarize key technical, operational, and contractual factors for FPSO redeployment

Include timeline consideration from FEED through initial‐start‐up and from shut‐down to re‐energizing at the new location.

Address differences in planning for redeployment in the initial design of new build vs. conversion FPSOs.

Stage Two

• Work with SMEs to identify a representative set of industry FPSO/FSO projects, where relocation or repurposing has taken place, and then identify key drivers and issues impacting the decision.

• For each representative FPSO/FSO application, capture the logic/decision analysis leading to the relocation or repurposing decision via direct discussions with the Owner/Operator (or Contractor) of each application.

• Describe key technical, operational, and organizational success factors and lessons learned for decommissioning/relocation.

Stage Three

• Outline success factors to include in an initial FPSO design project to help maximize potential redeployment success.

• Document success factors to include in preparing a successful redeployment/conversion specification

• Outline success factors to include in a FPSO relocation execution plan including engineering activities, marine equipment requirements, marine systems readiness, risk mitigation, Class interface, and topside interfaces / coordination.

Deliverables


• Best Practices and outline checklist addressing redeployment for input to an initial FPSO design specification (before first field deployment).

• Best Practices and outline checklist for preparation of a FPSO redeployment/conversion specification

• Best Practices and guidance notes for preparation of a FPSO redeployment execution plan.



ISSUE H – OPERATIONAL CONSIDERATIONS

Summary

Operators and Contractors alike spend millions of man hours developing their own specific Operating Procedures. Such Operating Procedures are prepared by Operators and Contractors independently, and give rise to much duplication of effort. As a result, many operating procedure interfaces are necessary between the Operator and Contractor, which can be inefficient and unwieldy in practice.

Most if not all of these Operating Procedures are very similar in content and can generally be applied to the operation of FPSOs in different locations and under different jurisdictions. Since the mission of all FPSOs is the same or very similar, efficiency in operations could be obtained in the industry by developing and implementing generally acceptable standard Operating Procedures. It is suggested that considerable cost savings could be achieved by doing so.

Having industry accepted operating procedures would result in greater efficiency in operations and a reduction in uncertainty, as well as saving time, effort and man hours. As crew members transfer from one FPSO to another, they would follow the same basic procedures. Greater ease of transfer of crewmembers from one FPSO to another would occur. This would result in a reduction of operating risks – i.e. improved risk management.

This scope of work will focus on developing guidelines and checklists for the development of Operating Procedures; the JIP work on this Issue will not prepare the actual procedures.

Stage One

Research the contents of actual Operating Procedures currently in general use on FPSO units operated by the Member Companies. This would include discussions with the SMEs.

Stage Two

Establish the common content of the sample of Operating Procedures obtained in Stage One and assess the major differences between them. Meet with SMEs and agree the general structure and content of Standard Routine Operating Procedures.

Stage Three

Based on the comparative analysis of the received procedures and best practice discussions, Endeavor’s Advisors will write guidelines and content checklists for creating Standard Routine Operating Procedures for FPSO units.

Identify those operational issues that cannot be considered as standard to all locations, fields, and FPSO units.



Deliverables


• A checklist and set of guidelines for creating Operating Procedures that could be used on any FPSO.

• Identification of operational procedures that are not considered standard at all locations.



APPENDIX A

BIOGRAPHIES – ENDEAVOR PROJECT STAFF

PROJECT SPONSOR: Bruce Crager – Executive Vice President, Expert Advisory Group

Bruce Crager is Executive Vice President of Endeavor Management and leads the firm’s group of Expert Advisors, which have a focus on Offshore Oil and Gas. He has over 44 years’ experience in offshore drilling and production, primarily in management positions. This has included significant experience evaluating and providing all types of field development solutions, particularly those based on floating production systems and subsea production equipment. Bruce has worked on over 20 FPSO projects and founded Oceaneering Production Systems in 1988 which he led for 13 years. Bruce joined Endeavor in 2010 and is responsible for the development of an experienced team to support clients in the areas of strategy development, organizational change/development, decision analysis, and in technical areas such as field development planning and operational improvement. Since joining Endeavor, Bruce has consulted for many clients, including Addax Petroleum, Afren, Barra Energia, Cameron, ENI, Maersk Oil and Gas, Petrobras, Pemex, Ridgewood Energy, Shell, and VAALCO Energy. Bruce holds a BS in Ocean Engineering from Texas A&M University and was selected as a Distinguished Graduate of TAMU’s Zachry Department of Civil Engineering in 2008. He also holds an MBA from the University of Houston, has co‐authored 4 patents, written numerous technical and management articles, and is a registered Professional Engineer in Texas.

JIP PROJECT MANAGER: Jeff Dice – Project Advisor

Jeff Dice has 24 years’ experience as a structural engineer and project manager to deliver technically sound, risk managed, best value solutions. Jeff has extensive experience with fixed offshore structures, floating systems (FPSO, TLP, Spar, Semis), subsea structures, foundations, modules, pipelines, and drilling rig applications. Jeff has provided project management, design assurance, structural analysis and design, permitting, fabrication and refurbishment support, installation management, planning and scheduling, and cost estimation. Jeff spent 19 years with engineering contractors (Mustang, Atlas, Upstream, Hudson/McDermott). He then spent 6 years at BP, where he provided engineering management and discipline leadership across all project phases in concept development and brownfield topsides roles as project technical authority and engineering team lead. Jeff combines operator and contractor perspectives with decisive, analytical talents, and approachable communication skills to positively impact group culture, provide visionary leadership, and manage achievement. Jeff is an advisory board member for the Topsides, Hulls, & Platforms Conference and is active with API’s Offshore Structures Committee. He holds both a Master of Science and a Bachelor of Science in Civil Engineering from Texas A&M. Jeff is a licensed Professional Engineer in Texas and a certified Project Management Professional with PMI.



ISSUE A – Strategic Decisions

ISSUE A LEAD: Rich Keig – Advisor

Rich Keig is an Offshore Operations Consultant with solid engineering education underpinning 35 years of industry experience in vessel operations, subsea engineering, offshore construction of floating oil and gas plants including hookup, commissioning, and plant startup. His experience includes onshore supervision of the startup and producing operations of four (4) FPSOs and one (1) TLP. Rich is fluent in Portuguese, with working ability in Spanish. He holds a Master of Science in Management from Rensselaer Polytechnic Institute and an undergraduate degree in Engineering from the U.S. Coast Guard Academy.

ISSUE A CONSULTANT: David Edwards – Senior Advisor

Dave Edwards is a technical advisor and project manager with diverse global experience delivering major upstream Oil and Gas projects. Dave has extensive experience in deepwater field development and has served as the project manager on a number of $1‐5 billion+ CAPEX projects in a variety of international environments, successfully managing key internal and external stakeholders. In his 33 years at Shell, Dave developed new engineering concepts and processes that resulted in significant cost savings from improved efficiency, competition and safety. In addition, Dave successfully managed large and diverse owner teams and improved relationships with government mandated contractors, while meeting project objectives in locations that can be politically and economically challenging. He has a Ph.D. in Mechanical Engineering from Nottingham University (UK).

ISSUE A CONSULTANT: David Tuturea – Senior Consultant (Bio shown below in Issue G)

ISSUE B – Project Delivery

ISSUE B LEAD: Jeff Dice – Project Advisor (Bio shown above in JIP Project Manager)

ISSUE B CONSULTANT: Tim Swenk – Advisor

Tim Swenk has 34 years of comprehensive experience in the engineering and construction industry with many years of experience with both McDermott and Fluor. He held significant project and business leadership roles in companies leading Oil and Gas industry capital projects in a variety of international locations. As executive leader, he was instrumental in developing and implementing key business and project strategies directly contributing to margin growth. His active engagement in client and partner relationships led to successful achievement of project goals. As a member of multi‐cultural teams, Tim has a keen appreciation for development of organizations and people through active involvement in the enterprise work process implementation and talent growth globally.



ISSUE B CONSULTANT: Andy Wolford – Senior Advisor

Dr. Andrew Wolford is an accomplished risk analyst, having worked in the field of industrial risk assessment for over 29 years. He specializes in risk‐informed approaches to technology issues in the production, energy, and power industries. He has directed risk applications on a diverse range of engineered systems including offshore and onshore oil and gas installations, mobile offshore drilling units, marine and land‐ based transportation systems, chemical and nuclear fuel processing plants, nuclear power and test reactors, and the Space Shuttle. He is known for his facilitation skills and his ability to communicate risk concepts in clear and understandable terms in his consultancy with BP, Chevron, Department of Energy, and Shell International to name a few. He holds a Doctor of Science from Massachusetts Institute of Technology, a Bachelor of Nuclear Engineering from Georgia Institute of Technology, and a Bachelor of Physics from Wittenberg University.

ISSUE C – Mooring and Offloading

ISSUE C LEAD: Mark Danaczko – Senior Advisor

Mark Danaczko joined Exxon Production Research Company in 1978 and remained with Exxon and later ExxonMobil until his retirement in 2013. During this 35‐year span, Mark held key technical, management and executive‐level leadership positions in ExxonMobil’s Upstream Organizations, primarily focused on Offshore Engineering and field development projects. He was ExxonMobil’s Senior Expert in Offshore Floating and Compliant Structures, including: Tension Leg Platforms (TLPs), Semisubmersible Floating Production Units (FPUs); Deep Draft Caisson Vessels (DDCV), Classic Spars / Truss Spars; Floating Production Storage and Offloading (FPSO) vessels; Floating Storage, Regasification Units (FSRUs); and Deepwater Compliant Platforms (Guyed Towers and Compliant Piled Towers). Mr. Danaczko held key leadership positions on several high visibility offshore and shipping‐related projects, including the Lena Guyed Tower, Anasuria FPSO (Shell Exploration & Production, UK), Genesis Spar (Chevron USA), Kizomba A & B TLPs, and the Q‐Max LNG Carrier Development Project (Qatar Petroleum). Mr. Danaczko is a co‐inventor on multiple U.S. and foreign patents related to Compliant Piled Towers (CPTs), novel Floating Production Systems and several LNG‐related technologies.

ISSUE C CONSULTANT: Jens Kaalstad – Advisor

Jens Kaalstad has over 30 years’ broad experience in the Oil and Gas, Shipping and Offshore Industry. He was President of APL, Inc., the US Operation of mooring system company APL, for 12 years. He has a varied background in management, engineering, technology development, contracting, procurement, construction, and installation. He was heavily involved in the world’s first offshore LNG terminal (FSRU) and in the first FPSO in the Gulf of Mexico, BW Pioneer, for the Petrobras Cascade and Chinook development. He has been responsible for marketing, identifying, developing, negotiating and closing of EPCI contracts in excess of $100 million and involved in numerous design, fabrication and installation projects as well as development projects for various fixed and floating platform solutions. He graduated with a Master of Science in Naval Architecture from the Norwegian Institute of Technology after one year at MIT, Department of Ocean Engineering.



ISSUE C CONSULTANT: John Lovell – Senior Advisor (Bio shown below in Issue H)

ISSUE D – Hull Design

ISSUE D LEAD: Brian Gibbs – Technical Advisor

Brian Gibbs has focused on integrity management during his 40‐year international career, ranging from major life extension projects for ageing floating offshore assets to inspection and cathodic protection retrofit of fixed platforms. He has led many major projects to obtain regulatory approval for continued service of ageing assets or to rehabilitate facilities that were extensively deteriorated through corrosion and fatigue. His focus has been in corrosion management, including development, design, inspection and assessment of many corrosion protection solutions. Brian has worked in the North Sea, Asia‐Pacific, West Africa and the Gulf of Mexico. In addition to his offshore work, Brian has led onshore projects ranging from cathodic protection assessment of a critical gas pipeline to corrosion assessment of a major US bridge, and other major infrastructure. He is often called upon to prepare articles for technical journals, to speak at conferences, and to contribute to technical standards. Mr. Gibbs hold a Bachelor of Science in Civil Engineering from Polytechnic of Wales, United Kingdom.

ISSUE D CONSULTANT: David Tuturea – Senior Consultant (Bio shown below in Issue G)

ISSUE E – Process Module Design

ISSUE E LEAD: Richard Thompson – Advisor

Richard Thompson has over 30 years’ experience in both onshore and offshore management positions. These roles included a significant amount of experience in reservoir engineering, which included reserve determination and evaluation for heavy oil fields in Alberta, miscible gas flooding in Alberta and West Texas, and recoverable reserves for oil fields in Russia. He also has significant experience in production engineering that included the operation and optimization of gas plants in Alberta and West Texas. His roles also included design and construction of FPSOs as well as significant experience with the management and operation of floating production units in West Africa, Western Australia, South East Asia, and Gulf of Mexico. He also has experience with the marketing and manufacture of specialized ROV tooling and subsea equipment to support flow assurance of deepwater pipelines and facilities. He joined Endeavor in 2013 and has consulted on multiple FPSO projects for Pemex. He holds a Master of Business Administration in Finance from the University of Houston and two Bachelor degrees from the University of Saskatchewan, in Geological Engineering and Geology.

ISSUE E CONSULTANT: Wayne Huddleston – Project Advisor

Wayne Huddleston has over 39 years of experience in the upstream offshore and onshore oil and gas industry. His experience has been mainly focused in project engineering of offshore oil and gas processing facilities and predominantly in floating facilities. He was responsible for the design, procurement and installation of the process facilities for the Texaco Captain semi‐based Extended Well Test, FPSO Zafiro Producer and MOPU Ocean Legend as well as shipyard and infield facility upgrades to the FPSO Ocean Producer. For the past 6 years, he has concentrated



on project management of various offshore projects such as demobilization of the MOPU Ocean Legend, outfitting dive trolleys for BP Thunder Horse, mobilization and outfitting of an MSV with ROVs and survey equipment, and manufacturing of subsea hardware. Project experience includes work in Australia, West Africa, North Sea, SE Asia, and Colombia as well as GOM. Previous employers include Oceaneering, Shell, Tenneco Oil, Marathon Oil, and Texaco. Mr. Huddleston is a registered Professional Engineer in the state of Texas and is a Project Management Professional. He earned his Bachelors in Mechanical Engineering from the University of Texas in Austin, Texas.

ISSUE E CONSULTANT: Jeff Dice – Project Advisor (Bio shown above in JIP Project Manager)

ISSUE F – Vapor Recovery Gas and Water Treating

ISSUE F LEAD: Richard Thompson ‐ Advisor (Bio shown above in Issue E)

ISSUE F CONSULTANT: Wayne Huddleston – Project Advisor (Bio shown above in Issue E)

ISSUE G – Redeployment

ISSUE G LEAD: David Tuturea – Senior Consultant

David Tuturea has 41 years engineering and management experience related to global oil and gas. This includes lead and management positions on major offshore and onshore projects in the North Sea, Asia, US, and Canada with Brown and Root (now KBR) and ConocoPhillips. He has been involved in all phases of oil and gas developments from concept selection to start‐up and hand‐over to operations. David's experience includes frontier development concepts such as tension leg platforms, subsea storage systems, offshore Arctic production and transportation infrastructure, floating production systems, and in‐situ tar sands production.

ISSUE G CONSULTANT: John Manning – Advisor

John Manning is an experienced Naval Architect, Engineering and Project Manager with over 45 years’ experience (>24 years’ offshore oil & gas), having worked with national and independent (major and junior) oil & gas companies, major ship‐owning, shipbuilding, ship design companies and ship model test facilities in Africa, Australia, Brazil, Canada, China, Europe, India, Middle East, New Zealand, PNG, Russia, South East Asia, and USA. His qualifications include Ordinary and Higher National Certificates in Naval Architecture and Shipbuilding and a Degree in Ship Science, from the University of Southampton (UK). He is a Fellow of the Society of Naval Architects and Marine Engineers (USA), a Fellow of the Royal Institution of Naval Architects (UK), a Chartered Engineer (UK) and a European Engineer (France). He is based in Melbourne, Australia.

ISSUE G CONSULTANT: Bruce Crager – Executive Vice President (Bio shown above as JIP Sponsor)



ISSUE H – Operational Considerations

ISSUE H LEAD: John Lovell – Senior Advisor

John Lovell has over 30 years of worldwide maritime experience. He is extensively qualified in ship management, FPSO management, consulting, offshore vessel management, and vessel operations. John has utilized strategies and associations with ISO 9001 accredited service companies and international contacts to develop and implement marine service packages. He strives to improve operations, manning, insurance, safety and technical functions of FPSOs and trading vessel operations. He is experienced in worldwide and US shipping industries, including U.S. Flag and U.S.E.C. segments. John served as Deck Officer in the British Merchant Marine for 11 years. He has been Operations Manager and Director for both ship‐owning companies and ship management companies. John founded Alliance Marine Services in 1992. He holds a Bachelor of Science in Maritime Studies from London Metropolitan University and is a member of the Nautical Institute, a member of the Governing Board of the Houston Maritime Association, and a Governor of the Marine Society and Sea Cadets, London.

ISSUE H CONSULTANT: Rich Keig – Advisor (Bio shown above in Issue A)

ISSUE H CONSULTANT: W. T. (Bill) Hughes – Senior Consultant

Bill Hughes is a highly motivated and versatile Manager with 37 years in leadership positions in oil and gas industry, including 25 years international experience. He is highly skilled at leading diverse, multi‐national teams in establishing operations in international locations. He has excellent leadership, management, and partner interface skills. While Operations Manager for several international projects he was responsible for organizational development, startup and transition to normal operations with total budget responsibility to more than $300 million. He has extensive experience in all areas of oil and gas engineering and operations, to include offshore and deep water. He has demonstrated commitment to safety through development and implementation of safety systems and procedures in several locations with a multi‐national, multi‐discipline workforce. Bill holds a MBA from Michigan University and completed his undergraduate degree at West Point, New York, where he earned a Bachelor of Science from the United States Military Academy.

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