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OTC 19676 Subsea, Umbilicals, Risers and Flowlines (SURF): Performance Management of Large Contracts in an Overheated Market; Risk Management and Learnings

Tony Oldfield, BP Angola BV

Copyright 2008, Offshore Technology Conference This paper was prepared for presentation at the 2008 Offshore Technology Conference held in Houston, Texas, U.S.A., 5­8 May 2008. This paper was selected for presentation by an OTC program committee following review of information contained in an abstract submitted by the author(s). Contents of the paper have not been reviewed by the Offshore Technology Conference and are subject to correction by the author(s). The material does not necessarily reflect any position of the Offshore Technology Conference, its officers, or members. Electronic reproduction, distribution, or storage of any part of this paper without the written consent of the Offshore Technology Conference is prohibited. Permission to reproduce in print is restricted to an abstract of not more than 300 words; illustrations may not be copied. The abstract must contain conspicuous acknowledgment of OTC copyright.

Abstract Greater Plutonio is BP's biggest subsea project worldwide and consists of 5 separate fields in 1500m of water, over an areal extent of 4,880km2, 150khm offshore Angola in Block 18. One of the many challenges of the development concept was to deliver the complex Subsea production system, Umbilicals, Risers and Flowlines (SURF) which will connect the 43 subsea wells to the spread moored 2 million barrel storage, new build FPSO with production capacity totaling 240,000 barrels per day, in an integrated manner over a fast track schedule to allow a safe, efficient and phased start up, with rapid production ramp up. The challenge was heightened by a commitment to deliver the highest level of local Angolan content ever achieved to date. This paper will address the challenges in project managing SURF projects of this size and highlight some of the unique aspects and challenges of this development, particularly given its Angolan content and market conditions by applying risk management principles and applying learning from previous deepwater projects in WAF, GoM and West of Shetland It is supplemented by companion papers covering specific areas of the development from sand face to facilities (OTC ­ 19673, 19674, 19675, 19676 and 19669). The key points and challenges to note about the SURF system are: · · · · · · · 43 wells with flexibility and expandability in the subsea architecture for up to 88 wells Single compliant riser tower with condition monitoring system, fabricated and assembled in Angola Highly dynamic seabed flowlines subject to high lateral buckling forces and end expansions 107km dynamic and static production control, chemical injection and data acquisition umbilicals 150km production insulated flowlines, water injection plastic lined, gas injection and service flowlines Simultaneous subsea construction, commissioning, start up, production and offtake operations Provision for a future subsea gas export offtake

The project was led by a core BP Project Leadership Team supported with directly hired contract staff co-located to major contractors' offices to work in integrated teams, through FEED, system engineering, detailed design, procurement, manufacture, fabrication, installation, commissioning, start up and production. Throughout the project functional departments provided expert technical support and integrity assurance with formal reviews and specialist advice. BP partnered with their key contractors to identify key project drivers, issues and challenges, and then mapped out a plan to systematically improve safety performance, especially in Angolan fabrication yards and for offshore simultaneous marine construction and commissioning operations. This partnering approach increased ownership and ensured that improvements were embedded in the contractor's systems and procedures, as well as enabling the contractors to take advantage of the significant safety resources/experience available within BP.

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Introduction The Angolan national oil company, Sonangol, is the concessionaire of Angola Block 18. Under a PSA (Production Sharing Agreement), BP is the operator, with 50% interest and the balance held by Sonangol Sinopec International. The Greater Plutonio development encompasses 5 fields within the Block and is currently in production having come on stream in October 2007, and is currently producing over 200,000 bpd. Greater Plutonio is a complex development with some of the largest and technically complex subsea contracts issued at the time of award. The project was executed in a hotly contested market whilst stretching the envelope in local content. The project execution plan called for a fast track development schedule to first oil and an aggressive phased ramp up from first oil with gas injection within one month of start up. A graphical overview of the system is shown in Figure 1 below. Figure 1 Field Layout

CALM Buoy

Northern System

N4

FPSO

N3 N2 N1

Riser Tower

S1

Production S4

S2 S3

Water Inj

Gas Inj

Southern System

Umbilical WI/GI

Production is segregated into the Northern System comprising Galio (N4 and N3 Manifolds), Cromio (N2 Manifold) and Paladio (N1 Manifold) and the Southern System comprising Cobalto (S4 and S3) and Plutonio (S3, S2 and S1 Manifolds). A single flowline delivers production from the Northern fields and a looped flowline delivers production from the Southern fields. Manifolds are offline, tied in with Tees along the production flowlines. The production system (flowlines, risers, manifolds and connection systems) is insulated to a level that ensures that the FPSO arrival temperature will be greater than 40°C for the vast majority of operating scenarios encountered during field life including turndown. The flowline and riser insulation also provides at least 12 hours of `cool down' time following shut in of production. Trees, manifold and connection spools are also insulated but with a shorter `cool down time' of 6 hours.

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The arrival temperatures for the Northern and Southern flowlines, for the P50 production profile, is between 47°C to 75°C, so hydrates are not possible under normal operation as the arrival temperatures are >20°C above the hydrate formation temperature and significantly above the wax appearance temperature. An uninsulated Service flowline is provided from the FPSO to the Galio N4 manifold. After a prolonged (c. 12 hours) Northern system shutdown, diesel from the FPSO will be circulated through the service line into the production line to displace production fluids back to the FPSO. This is required to prevent hydrate formation. To warm the system up before restart (to minimise methanol usage) hot diesel will be circulated though the production flowline into the service line. The Southern manifolds will be connected using a 12" insulated flowline in a loop, with S1 and part of the S2 production directed to the South Eastern section of the flowline and the remainder of the S2 production, S3 and S4 production directed towards the South Western section. During a prolonged shutdown, dead oil (from the FPSO storage tanks) will be used to displace the production fluids to the FPSO. All production flowlines have permanent facilities to inject lift gas, supplied from the FPSO, into the base of the riser. There is no requirement, even at high water cuts, for well gas lift. The gas lift rate into each riser is individually and remotely controlled through a riser base gas lift manifold and measured from the FPSO. Water Injection wells are dispersed within each field, with single duty water injection connected directly into the water injection flowlines, via Tees. The flowline system comprises separate flowlines to Cobalto and Plutonio; and a single flowline to Paladio, Galio and Cromio. Three dual service gas and water injection wells are planned for gas disposal over the initial years of field life and a gas export provision has been made via a subsea tee and flexible flowline for a future subsea Gas Export Regulating Manifold and Export Pipeline system. Subsea control of valves and the transmission of process and equipment data is by a multiplexed electro-hydraulic system, via a network of dynamic and static umbilicals and flying leads that connect to tree/manifold mounted control modules. All subsea trees are a standard 5 x 2-inch, 10,000 psi vertical design, incorporating a subsea control module (SCM); remotely actuated choke; sand detection; flow loop wall thickness monitoring point; acoustic transmission of DHPT data to surface transducer; and capable of incorporating downhole Distributed Temperature System and downhole flow control. The architecture in the fields will allow over 30 wells to be tied in and commissioned after the initial 13 well start up tranche without requiring a production shutdown. Challenges A unique set of additional challenges to those of technological complexity, deepwater remote location and fast track schedule had to be faced, namely an overheated supply market, driven by demand in a high oil and steel price environment, where only a limited number of major contractors had the capacity and capability to take on the integrated scope along with the associated risks. The success in overcoming the challenges and mitigation of risks have provided a broad and deep set of learning which will help shape the execution and delivery of future projects of this nature, as the market remains extremely challenging and complexities increase. Technology Technically, the subsea system is composed of the following key elements, · · · · · · · · 43 subsea wells; 20 water injection, 20 production, 2 dual service gas / water injection and 1 gas injection Flexibility and expandability in the subsea architecture to tie in reserves up to a total of 88 wells 25 subsea trees assembled and tested in Angola together with all Production Guide Bases (PGB's) 33 rigid composite production and control well jumpers, all fabricated in Angola 8 production manifolds, 6 of which fabricated and tested in Angola 1 water/gas switching manifold, fabricated and tested in Norway Multi phase flow metering in all production manifolds Workover control system

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· · · · · · · · · · · · · · · ·

Enhanced completion landing string assemblies Open water riser system Rigless tree intervention system Remote intervention tooling for tree operation, flowline tie-in, in-line tees and manifold intervention 1,240m Single compliant hybrid riser tower, with gas lift umbilical and manifolds and condition monitoring system, 2.2km dynamic flexible production and injection risers from riser tower to FPSO 66km dynamic production control, CI and data acquisition umbilicals to each production manifold 37km static seabed umbilicals 40km production insulated flowlines with x in line tees, FLET's and round trip pigging facilities 40km water injection plastic lined flowlines with x in line tees and FLET's 15km of gas injection and service line flowlines Rigid Oil Offloading Lines (OOL's) system with CALM buoy offtake Deepwater FPSO and Offloading Buoy Moorings Subsea gas export provision via a Gas Export Regulating Manifold (GERM) to a future regional gas export system Future provision for seabed processing for riser base production fluids pumping or produced water separation. Major offshore installation campaign with marine, commissioning and production SIMOPS

In total the above facilities amount to approximately 49,500 tonnes of hardware deployed on the seabed. From a subsea system reliability perspective the water depth, service conditions and design life requirements placed onerous supply chain product qualification testing requirements on subsystem components, especially in relation to the fatigue life of the Riser Tower, OOL's and Flex Joints, functionality of the riser buoyancy modules and flowline insulation and field joint systems, control system, manifold valving, intervention tooling, mechanical and electrical connector systems, landing string assemblies, hydrate remediation intervention assemblies, multi-phase flow meters to mention some of the key areas. Learnings from BP operations West of Shetland and the Gulf of Mexico and the subsequent compilation of reliability guidelines, allowed the embodiment of Supplier Reliability Demonstration Plans underpinned with BP's Technical Review Assurance Process (TRAP) to be built clearly into work scopes with contractors for schedule, cost and risk assessment, mitigation and control. It also allowed contractors to align in-house product development testing programmes and processes to project goals and timeframes in a transparent and robust manner for assurance purposes and for future project standardization opportunities. Hybrid Riser Tower (HRT) Of special note is the Hybrid Riser Tower, which is potentially a single point failure for the system and a critical path schedule deliverable. The tower is a compliant design, used previously in shallower water locations offshore Angola and to a lower functional specification. The Greater Plutonio design required extensive concept selection decisions and product qualification testing, coupled with Expert Review Committee steerage through the engineering to validate the concept and proceed through procurement, fabrication, assembly, tow out, upending and commissioning. The final design is summarized below, · · · · · · · · · · · · Overall length of 1240 meters from seabed to top of buoyancy tank Overall dry weight in air of 5000 tonnes Central structural core pipe of 24-ind OD seam welded tubular at the seabed tapering up to 44-inch OD at the buoyancy tank 3 off production risers, each 12-inch NB seamless grade X65 inconel clad 3 off water injection risers, 2 off 12-inch NB and 1 off 14-inch OD, all seamless grade X65 plastic lined 3 off gas lift risers, with individual retrievable subsea riser base gas lift manifolds situated at the bottom of tower 1 off gas injection riser, 12-inch NB seamless grade X65 1 off service line, 12-inch NB seamless grade X65 1 static gas lift umbilical for electro hydraulic control, power, signal and chemical injection to the riser base gas lift manifolds 1 dynamic gas lift umbilical connecting to the FPSO 11 off dynamic flexibles connecting to the FPSO port side riser balcony process pipework Condition monitoring system for fatigue life monitoring and process control

Key sub-assembled components are shown in Figures 2 to 4 below, during assembly in Sonamet Yard, Lobito, Angola.

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Figure 2 Sonamet Yard in Lobito

Sonamet Angoflex

Riser Tower

Figure 3 Riser Tower Bundle Cross Section and Bundle Launch into Lobito Bay

Figure 4 Bottom of Tower

All in all, the Riser Tower is assembled from components from over 36 vendors, ranging from line pipe, composite

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umbilicals, flexibles, manifolds, telemetry systems, buoyancy tanks, epoxy and urethane buoyancy foam systems, riser insulation, plastic linings, ROV stabs and guides, Matis connections, guide frames, subsea electrical connectors, hydroacoustic transducers. Many of the vendors involved were of a small business nature, where clear and direct engagement with the owner of business immeasurably helped the qualification, quality assurance, interface and delivery process. Final assembly of all components was designed to exacting defect free fatigue welding quality standards in a tropical, West African coastal location over a period of approximately one year, prior to tow out to location. Flowline Lateral Buckling The flowline design had to address the potential for lateral buckling and pipe-walking under the anticipated operational cycles. Lateral buckling is controlled on all flowlines using sleepers placed at regular intervals along each flowline to raise the pipe off the seabed, thereby triggering lateral buckles and minimizing buckle loads. The shorter production lines are susceptible to pipe-walking, which is controlled by attaching the flowline termination assembly (FTA) to a suction pile anchor. In all 41 sleepers and 3 flowline anchors were installed in the field. The design for lateral buckling and pipe-walking was extremely challenging and was supported by project-specific test programs including fatigue testing and detailed pipe/soil interaction testing. Following successful installation of the flowlines, detailed out-of-straightness (OOS) monitoring of the lateral buckling and pipe-walking response during hydrotest and early operation was carried out to confirm system integrity and validate the assumptions used in design, see figure 5. Figure 5 Lateral Buckling of 12-inch NB Production Flowline post start up The figure shows actual surveyed positions of the flowline, indicating the as-laid position (in grey) and the post start up position (in red), while the yellow line shows the sleeper. The shadow to the left is where the pipe initially moved to during hydrotest, before the full lateral buckle formed in operation.

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Performance Management The project execution plan recognized that delivery of BP's performance standards would require the engagement with high performing contracting organizations, experienced and capable of operating in Angola and with a capacity to develop and deliver the high levels of local Angolan content. The embedded performance criteria and key SURF related risks are tabulated below. Metric · Safety Standard Outstanding personnel safety performance record, with no lost time accidents. Deliver a high integrity facility in which all hazards have been identified and appropriate measures implemented to achieve risks that are demonstably ALARP. Deliver a quality product at the most competitive price. SURF Major Risks Inadequate integration of subsea and topsides design safety Contractor executive management alignment Inconsistent job safety risk assessments High Angolan yard manhours with many subcontractors Extensive marshalling yard/load out campaign Long offshore campaign with intense FPSO and rig SIMOPS Multi contractor vessel ownership Turnover of key personnel Malaria exposure Scope changes Subsupplier cost escalation in a tight market Delay impact of late delivery of Company supplied items Re-work from poor quality control and interface management Disruption from offshore SIMOPS Overheated market in products, services and logistics Risk of loss and damage claims Sub assembly/component delays main fabrication System stack up test delays impacts installation and testing Lack of capacity and productivity in fabrication yards Readiness of new build spoolbase at Dande Vessel availability, productivity and maintenance Underestimation of infrastructure and logistical issues Inconsistent standards and specifications Schedule pressure impacts quality Poor reporting and intervention Inadequate interface management/decision processes Certification gaps at handover Weak Management of Change (MOC) control Weak HAZID/HAZOP and action tracking Poor product qualification process Inadequate system integration testing Inadequate post installation testing Poor handovers to commissioning and operations Unclear and unrealistic targets Capacity and competency limitations Loss of containment Chemical discarges

·

Installed Cost

·

Schedule

Deliver a quality product within the required timeframe.

·

Quality

Installed facilities comply with all applicable laws, regulations, industry standards, specifications, and are designed and built in accordance with industry best practices. Installed facilities will be capable of safe, environmentally sound, and costeffective life cycle operations.

·

Operability

·

Angolan Content Environment

Effectively foster sustainable development of Angolan industries and Angolan national employees. Deliver world class environmental standards and maintain a high regard for the environment during project execution.

·

Clarity of objectives, strong performance standards articulation, engagement of contractor executive management, all led by a

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strong BP project management team accountable for interface management, integrity assurance, integrated planning, commissioning and start up, were important drivers to secure confidence in delivery. The above approach served BP well, when it transpired that though 2004 to 2008, performance issues would be influenced heavily by the market issues of steel price rises, oil price rises and the resultant activity level growth placing huge demands on the provision of goods and services as well as the availability of personnel. Contracting Strategy The contracting strategy recognized that there were limited subsea players who would be capable of taking on a large integrated EPC scope. What was also recognized from the outset was that integration and management of interfaces was the key, so retaining visibility on interfaces was the paramount objective, to allow timely intervention to take place as needed, in order to protect overall delivery. This approach was also a reaction to the market at that time (2003), where there was limited experience of successfully delivering on time, multi-billion dollar integrated subsea workscopes. After completion of the Front End Engineering Design, two major contracts were awarded in Q1 2004, namely; the Subsea Production System contract to FMC and the Umbilicals Risers, Flowlines contract to an Acergy led Consortium with Technip. The FMC contract covered detailed system engineering and hardware delivery of trees, wellheads and hangers, connector and intervention tooling, rigid well jumpers, control system, workover systems, manifold fabrication and offshore service support. The Acergy/Technip contract covered the engineering, procurement, fabrication, installation, testing and subsea commissioning support for the umbilicals, riser tower, J-lay and Reel lay of rigid flowlines, in-line tees, seabed spools, flexible tie-ins and oil offloading system including CALM Buoy, and FPSO and CALM buoy moorings. Both contracts covered international and local Angolan content commitments, which included tree assembly (FMC Luanda), PGB fabrication (Algoa Luanda), spoolbase fabrication (Technip Dande), well jumper fabrication (Petromar Soyo), infield umbilicals manufacture (Angolflex Lobito) and major fabrication works for the riser tower, CALM buoy, production manifolds and piles, in-line tees, flowline and riser base spools, FPSO and CALM buoy piles (Sonamet Lobito). Sonamet was also the offshore marshalling yard for mobilizing all major s of line pipe, chain/wire moorings and subsea structures. Major international subcontracts placed under the URF contract covered main umbilcals (DUCO Texas/AKS Alabama), line pipe insulation (Socotherm, Brazil) and CALM Buoy (SBM, Monaco). BP Project Management The BP Project Leadership Team consisted of accountable level management from the BU VP Projects, FPSO Project Director, SURF Project Director, HUC Manager, Operations Manager and Resource Development Manager, throughout the project. There was high recognition that the overall successful integration of all major contracts relied on the capability to continually intervene where necessary around a common integrated plan, which was regularly subject to probabilistic risk assessments based on a key activity set of 90 items, and calibrated with deterministic risk reviews. Equally, the interdependency on each major contract went beyond that of a normal interface level, therefore the decisions and sensitivities needed to have high visibility to enable executive action to be implemented with contractor key management. This was especially so as major equipment packages suffered delays, thereby triggering re-sequencing of operations of major activities to avoid day for day impact to the overall critical path to first oil. A good example of this was the eventual upending and installation of the riser tower after the mooring of the FPSO, as the original project execution plan was based on an unrestricted, open water access to the upending location, with all the attendant marine SIMOPS risks of working within the mooring pattern of the FPSO. Within SURF, the high interdependency between the Subsea and URF packages required a hands-on, aligned approach with the main contractors. The creation of Delivery Managers, with total accountability for the integrity, cost and schedule for the work packages challenged the more traditional organizational model where engineering, construction, installation and testing would have created the possibility for more interfaces and handover complications. The Delivery Manager then had the overview from engineering to start up, which enabled clear, crisp communication when intervention was required to address delivery threatening issues. In cooperation with the main Contractors' Executive management, the formation of Steering teams to a signed up set of

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Terms of Reference provided a formal vehicle to visibly demonstrate alignment and commitment to the project and provided a stable means to set a positive engagement tone to the team, whilst creating a powerful, small but effective decision making body. The concentration of effort at the start of the project relieved the need for the Steering team to formally engage on a regular basis throughout the project, however notwithstanding this, the commitment remained and was available whenever intervention was needed, which was the case in several specific instances at critical times.. Risk Management HSSE The primary risk areas of injury to personnel working in fabrication yards and offshore on construction vessels were managed extensively through awareness training, risk assessments and visible management commitment through yard visits, safety tours and safety recognition awards. Onshore, in conjunction with yard management a forward looking 30 day hazard identification risk matrix, with mitigation plans was used to prioritise effort and increase awareness. As engagement progressed during the course of the works, patterns became evident in both generic and task specific hazards, therefore specific training was targeted at supervisor level to mitigate awareness gaps and promote a deeper understanding of the risk assessment process and how clear, implementable mitigation measures can be generated. A typical hazard identification risk matrix is shown below in Figure 6

SURF Key HSSE Risks -90 DAY LOOK AHEADMaintaining HSSE expectations at Yard with man power increase including night shift Handling operations on FPSO Deck during mooring pull-in Hydro testing Flow Lines Driving in Angola FLT, ILT & Manifolds on shore Marshalling activities at Lobito with 20 remaining load outs Umbilical Load out Diving activity in Double Joints movement Lobito bay on Buoyancy tank Mooring of FPSO and bunkering Rigging and lifting Activities at Lobito Riser Tower Commissioning RT Security in Lobito bay

H

Risk

Pressure Testing of Manifolds Next to Pile Rack 2 RT Pressure Testing

M

RT Tow out of Lobito Bay

Confined space work in Off loading Buoy

L

L

M

H

1

Manageability

For offshore works, a 3 stage Acergy based Hazard Identification and Risk Assessment Process (HIRA), was very successfully employed, as follows, · · · Stage One was a procedural review conducted in the engineering office with BP and contractor, the output being an identification of hazards, the consequence, potential mitigation and control mechanism needed to manage the probability of occurrence. Stage Two was a review of the Stage One output, on the installation vessel with the Captain, Offshore Manager, BP and key supervisors, with the Task Plan, the output being an updated risk assessment Finally, Stage Three was the toolbox talk with all supervisory personnel within 12 hours of commencing the task., where any deviation to the Task Plan would be clearly identified as a Management of Change process, requiring a hold on activities, re-assessment of risks and control measures instigation.

For works carried out under SIMOPS conditions including FPSO 500meter zone activities, the vessels involved would work

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under a SIMPS protocol, which ensured whilst vessel operating conditions remained stable, work could continue, and in the event of any upset conditions, primacy for control reverted to the major controlling vessel to instruct other close proximity vessels to stand down. Figure 7 shows the decision flow chart for SIMOPS management.

The above process was successfully employed and in over 7 months and 1.18million vessel based manhours of continuous round the clock operations involving the FPSO, drill rig and other marine vessels; no SIMOPS related incidents were reported. Schedule Management The integrated plan was the major schedule management tool, which consolidated activities, analyzed; risk assessed and forecasted progress and delivery of first oil targets. It would incorporate activities from FPSO delivery, drilling and completion, subsea hardware deliveries, subsea construction, hook up and commissioning, start up readiness and offloading system with tanker offloading readiness. The plan was produced at the offices of the main URF contractor by BP as recognition of the critical path dependency of the subsea construction works and the need to be closely linked to any vessel changes such as unplanned dry docking. At the peak of activity the offshore construction fleet comprised 26 vessels, from major DP deepwater construction vessels to support tugs and barges, supported from four in-country mobilization locations, namely Lobito, Luanda, Dande and Soyo. The major vessels being Acergy Polaris, Eagle, Legend, Falcon, Technip Deep Blue, Constructor, Geofjord and Maersk Asserter,. Initially the plan was produced on a monthly basis, however nine months from first oil the plan was produced on a

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weekly basis which eventually became a twice weekly issue. Risk reviews of the plan were performed using in house BP Predict! software, taking a reduced subset of activities from the plan and performing a probabilistic analysis using early and late completion scenarios, to provide management with a spread of likely outcomes. In addition to this tool, a deterministic approach was taken to look at work arounds and re-sequencing opportunities to protect the critical path. This hands-on approach proved extremely successful in working with the major contractors, who themselves needed to find work around solutions to unplanned events. The ability of vessels like Polaris and Eagle to multi task and share workload proved to be extremely valuable in achieving this, and as well as delivering flexibility the plan also saw opportunities to dedicate specialist support work, such as commissioning support with the Russell Tide and out-of-straightness surveys on the flowlines to a dedicated specialist vessel, namely the Normand Tonjer. This took load off the main construction spread and allowed the quality of the specialist survey work to proceed without distraction. As a measure of success, BP and the main URF Contractor were able to create a contract close out scenario some six months prior to the physical completion of contract, based on a behavioral code of conduct aligned to a mutual understanding of the schedule drivers delivering construction completion and system handover to first oil and subsequent start up sequences to full ramp up. Quality Management In 2004, at the time of the major procurement phase, the pressure on the supply chain prompted a hands-on review of lead times and quality pressures and led to a joint BP and Contractor quality management initiative to remove unnecessary inefficiencies in the process. The result was the creation of a united Code of Conduct, based around the following principles · · · · · · · · · · · · · Strong visible leadership from Project Directors and Managers Remain fully contract compliant and work to Project procedures Have aligned organizations continually looking forward Promote crisp, clear decision making based on sound judgment Ensure clear accountabilities through project line management Have competent people in the right places Deal in facts and avoid emotive language Support speedy recognition and resolution of Technical Queries and Non Conformance Reports Identify and resolve conflict quickly by pragmatic interpretation Regularize quality management decision meetings Maintain first class records and certification paperwork Prepare early for As Built records and a smooth handover to Operations Never compromise quality and integrity for schedule gain

The success of delivering to the above code of conduct would be a major achievement and served to underpin the reliability and operability targets for the subsea system and provided an alignment mechanism for BP and its Contractors to pool resources and exert maximum influence on the supply chain. Angolan Content The project was committed to delivering a number of firsts for Angola as well as continuing to build upon the capability of the local contractors and workforce. The majority of the work was carried out in Lobito (see Figure 2) Over 3.4 million manhours were liquidated at Sonamet involving two-thirds of the yard capacity, fabricating piles, structures, subsea spools, subsea manifolds, compliant riser tower and CALM buoy, as well as marshalling FPSO and CALM buoy chain wire moorings, and load in/load out of coated line pipe. The manifolds were designed with adjustable receptacles allowing for some wider tolerances for the large bore piping, which made life easier at Sonamet in fabricating these very compact manifolds. FMC had experience exchange with the Norway based fabricator of the two production manifolds and the GI/WI Switching Manifold with personnel from Sonamet visiting the fabrication in Norway. Also in Lobito, Angoflex manufactured a number of static, seabed water injection umbilicals. At Dande, work consisted of the fabrication of plastic lined pipe stalks for water injection flowlines which were then spooled on to the Deep Blue lay vessel. The site was a newly constructed base from a green field site with a 450meter sea jetty.

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Figure 8 Dande Spoolbase and Jetty with Deep Blue at anchor and spooling pipe

In Luanda, Algoa fabricated all 43 permanent guide bases under subcontract to FMC, and FMC completed site receipt & testing of 20 Dunfermline manufactured subsea trees, and workover system, as well as starting assembly & testing of the first of 25 subsea trees to be built in Angola. FMC Luanda Base also provided drilling and completion support to the drill rig and subsea construction support to Acergy. Figure 9 Completion the First Ever Assembled and Tested Tree at FMC Luanda Base

FMC trained 18 Angolans over a six month hands on training programme, visiting fabrication at Kongsberg and Dunfermline, prior to any start-up of local assembly in Luanda. Finally, in Soyo, Petromar constructed and loaded out 12 rigid production and water injection well jumpers under subcontract to FMC. See Figure 10, below. Figure 10 Load out of Well Pu-PG to Manifold Jumper.

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Operability The first year operating efficiency target is achieve 80% of plateau production levels and to maintain production at or above plan throughout the design life of the field, requiring a very high availability from the subsea facilities, avoiding early life failures, the specifics of which are as follows, · · · · · · · · · · Use of new or emerging technology which requires qualification testing with the attendant risk to cost and schedule Qualification testing of components may not mimic the installation or in-service duty resulting in failure in service Integration testing of systems or sub-system may not reflect the in-service integrated behaviour of that system or sub-system, leading to failure in service Deepwater environment not being fully understood e.g. external cathodic protection systems over protecting components Interfaces between new down hole well control and monitoring technology, ie trees and the subsea control system may not function as expected Sand monitoring and control not functioning properly Control system failures Hydrate control and hydrate remedial measures not functioning properly, causing blockages in the production system or malfunction of components Subsea multi-phase flow meters failure to measure flow satisfactorily leading to poor reservoir management Malfunction of the WI/GI Switching manifold and associated dual service injection well

Measures taken to mitigate the occurrence and impact of the above potential problem areas involved an extensive integration of findings from the Supplier Reliability Demonstration Plan, including product Failure Modes, Effects and Criticality Analysis (FMECA), into the Reliability, Availability, and Maintainability (RAM) analysis to determine the optimum system configuration. Coupled with qualification programmes designed to give Mean Time to Failure (MTTF) and Mean Time to Repair (MTTR) provides a basis for redundancy. In support of the above work, decisions were made to provide for retrieval of key components as follows, with a suitable intervention capability and sparing philosophy. · · · · · · · · Electro-hydraulic Subsea Control Modules. Subsea Choke Inserts. Electrical, hydraulic or chemical flying leads. Tree, manifold pipework assemblies and pipeline jumpers. Electrical components of corrosion monitoring assemblies. Electrical distribution units on manifolds. Sand detectors. Production multiphase flow meters.

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To date there have been change outs of several choke modules and a planned change out of two failed multi phase flow meters, diagnostics of which are on-going at the time of writing, Cost Management Capital cost management was a major focus. Recognition of the overheated market conditions meant that despite committing to lump sum contracts, BP and is major contractors would be competing for resources in a tight market environment over the duration of the project, ie over some 4 ½ years. By comparison to direct capital costs, the balancing issue of schedule slippage had a potential to seriously erode value. Currency risk was taken by BP and relieved the Contractors of the financial risk of hedging over a period of high currency exchange rate fluctuations. Tight controls and accurate forecasting using probabilistic techniques, coupled with a cost accountable delivery organization led to accurate reporting and good control. The creation of a detailed work breakdown structure, aligned with a cost breakdown structure, together with a schedule of realistic milestones meant the cost reporting structure had a clear and aligned relationship to physical progress and expenditure profiles. When reviewed on a formal monthly basis this gave visibility to key areas of cost pressure on an ongoing basis so that specific issues could be addressed in an appropriate manner. In addition to accurate reporting of costs the use of value adding incentives was a powerful tool in aligning effort and injecting momentum into the project at key critical times, especially where re-sequencing of the offshore work programme protected a phased, sequenced start up. This also allowed delivery line managers to focus on safety, quality and schedule at a key stage in the project, when it was value protecting. The major cost challenges on the project came from several scope and interface related changes, the most significant of which was the acknowledgement of the need to investigate and mitigate risks to the flowlines from dynamic lateral buckling, due to thermal and hydraulic cycling, which was recognized as a relatively new phenomenon in 2004. The eventual solution was to provide seabed piled anchors to prevent end walking and a system of low friction sleepers to allow intermediate flowline sections to laterally expand in a controlled manner over the length of the flowline route. Ongoing out-of-straightness surveys of the lines during operation are now part of the overall subsea integrity management plan to validate the work and assure operational reliability. Lateral buckling is now the subject of a co-sponsored Joint Industry Project, named Safebuck, which BP is fully supporting Conclusions Production started from Greater Plutonio on the 1st October 2007 from the SE part of the Southern System, some 44 months after major contracts award. The sequenced start up continued with production from the SW and was completed with the Northern systems by the 28th January 2008, bringing production capacity up to 240,000 barrels per day. Major subsea construction, tie-in, testing, pre-commissioning and commissioning works remained ongoing throughout this period in a safe, efficient, and flexible manner, whilst ongoing production operations ramped up and tanker export operations continued uninterrupted. All performance metrics delivered, are summarized below, · · In Safety terms, SURF liquidated 8.65 million manhours of which 3.3 million were offshore based to first oil. TRIF was 0.55 and DAFWCF was 0.16. This compares to the overall project statistics of 21.58 million manhours with TRIF of 0.41 and DAFWCF 0.13. There were thankfully no fatalities. Environmentally, the subsea gas injection system was started up within one month of oil production commencement so major flare emissions were eliminated; there were no chemical discharges or loss of containment incidents reported from the SURF work scope, and the commitments made within Environmental Impact Assessment have all been complied with In schedule terms, 44 months from major award of contracts to first oil is a major success ranking within the top 25% mega projects executed in West Africa, In quality terms, all handovers and major punch lists resolution have been achieved without compromise to the Statement of Requirements, or applicable codes and standards. First year production efficiency, at the time of writing is meeting and exceeding the target of 80%. Angolan Content has been exceeded in terms of capital cost expenditure and volume of man-hours expended in-

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country . Major lessons learnt on the SURF delivery cover the engineering, construction, installation, commissioning and start up phases of the work as well as over the disciplines involved. The major elements to share in this paper are listed below, · · · · · · · The creation of a strong joint Subsea and URF team was important to give the contractors and market place direction and consistency in approach The reciprocity received by BP from its main and subcontractors resulted in a highly flexible offshore work campaign with a vessel capability and high crew competencies, cemented together with a strong process of hazard identification, risk assessment and management of change For a long offshore campaign of 14 months involving 1,847 construction vessel days, 7 months of intense SIMOPS activity, the detailed planning, rigor and quality of documentation and understanding of protocols avoided any major downtime clashes or close proximity incidents. The technically complex nature of the work was well supported by a Delivery Manager approach from engineering through to commissioning and start up, so that unnecessary interfaces and handovers were avoided, and ownership was deeply understood through the fabrication, installation, testing and pre-commissioning phases of the work The capacity of a small but tight overall Project Leadership Team gave an extremely large and complex project a feeling of being small and connected, which in turn allowed a huge amount of competency and flexibility of interventions to executed. The prudent use of incentives to re-align the supply chain and main contractors to schedule change and flexibility has had a very positive effect on unlocking unforeseen schedule problems and channeling energy into delivering to a tight programme. The small team mentality also created an open and transparent relationship with contractors and suppliers, which allowed an overheated market to communicate and manage its risk with BP.

Apart from being BP's first major project as an Operator in Angola, Greater Plutonio has been a learning curve in terms of delivering a project in an overheated supply market. With no obvious signs of demand easing in the short term, these learnings are being transferred to our next suite of projects, centered on Block 31, where BP is also the Operator. These learnings include managing in country logistics, supporting Angolan contractors as well as how to contract for future projects. Acknowledgements I would like to thank Sonangol, SSI, BP Management, all of the prime contractors, namely Acergy, FMC and Technip; the major Angolan based contractors, namely Sonamet, FMC Luanda, Angoflex, Petromar and Halliburton, and the many committed sub contractors & suppliers, who were involved in delivering this project. In addition, it would not be complete if I were not to recognize the efforts of the BP Project & Operations teams, with a special mention to the SURF team and the BP Wells team, who led this effort from the start of the project through ramp-up to plateau. The Author Tony Oldfield has 30 years experience in the oil and gas industry in projects delivery, production operations and business management. He has worked for oil majors and independents, and major subsea and well services contractors. He is a Registered Chartered Engineer with a B.Eng. from Liverpool University and an MBA from Aberdeen University and is a Member of the Institution of Civil and Mechanical Engineers.

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