Deepwater production adds challenge after challenge to the operators that pit experience, innovation, technology and optimism against the forces of nature to produce projects on time, on budget and within an acceptable profit bracket.

"In deep water, there are severe economic penalties for getting it wrong. There are higher risks in deeper water and longer distances," said Thomas A. Choate, systems engineering manager for Intec Engineering, during a press conference at the Offshore Technology Conference.

Coulomb field produces in the Gulf of Mexico from 7,200 ft (2,196 m). Chevron drilled its Toledo prospect to 10,011 ft (3,053 m). The well turned up dry, but the next one beyond 10,000 ft (3,050 m) may not. Anadarko Petroleum will station its Independence Hub semisubmersible production platform in 8,000 ft (2,440 m) of water and collect production from subsea wells as deep as 9,000 ft (2,745 m), added David Hartell, project manager with Marathon Oil Co., deepwater Gulf of Mexico.

Operators continue to look for ways to handle the greater depths with enough efficiency to produce deepwater fields at a reasonable profit. It's working.

Deepwater model

At least in the Gulf of Mexico, the deepwater model was first set by the majors as they used tension-leg-platform hubs to produce batches of fields that would have been uneconomic as standalone projects. Na Kika was a cooperative effort between Shell and BP.

Pioneer Natural Resources, the Canyon Express group and now Anadarko made the concept palatable for independents by getting someone else to pay for the platform; in these cases, Enterprise Product Partners LP and its predecessor company. Operators continue to operate the fields and the platform, but the service company handles platform processing and production pipelines.

That satellite model has been in place in the North Sea for years. Offshore west Africa and offshore Brazil, the satellite concept still is a single-operator operation for Total, ExxonMobil, Shell and Chevron. ExxonMobil and Chevron will combine production facilities for the Gorgon group of fields and the deeper-water Io/Jansz complex offshore Western Australia.

Selection

Operators take a variety of factors into consideration in deepwater platforms. A central production and drilling platform offers a single drill center, lower operating expenses and life-cycle costs, simpler well hardware, minimized well intervention cost and downtime, fewer flow assurance problems and potentially higher recoveries, according to Pieter Wybro at Sea Engineering Inc. in last year's Floating Production Systems USA conference in Houston. Subsea wells minimize drilling cost and risk in reservoirs that cover a wide area or in satellite fields. Subsea wells also provide the model to date for ultradeepwater production, often with innovative flow-assurance techniques.

Petro-Canada looked at the lack of infrastructure offshore Newfoundland and decided a submerged riser base manifold producing to North America's only active floating production, storage and offloading (FPSO) vessel was the answer at its Terra Nova field.

Instead of reaching for a one-size-fits all solution, operators are tailoring their offshore platforms and facilities. Offshore west Africa, where there is little infrastructure moving production to shore may represent a security risk, FPSOs fit the task. Offshore Kalimantan, Indonesia, Unocal prefers tension-leg platforms (TLPs) tied to FPSOs or to shore.

In the Gulf of Mexico, BP uses the world's largest and second largest semisubmersibles for its Thunder Horse and Atlantis fields, but it uses the world's largest and second largest spars at Holstein and Mad Dog.

Brazil's Petrobras relies on semisubmersibles such as the P-40 and ship-shaped FPSOs.

More than 70% of the country's proved reserves are in deep and ultradeep water, and to reach those reserves more efficiently, the Brazilian operator's Procap 3000 program has come up with some specialized production concepts custom-suited to Brazil.

New ideas

One concept is the Big Buoy, a subsea riser buoy for use with steel catenary risers (SCRs) from the subsea wells to the buoy. From the buoy, flexible risers relay oil to the production vessel. It can work in 426 ft (130 m) of water with no internal pressure boost, and the company can submerge it either by flooding or with attached weights.

The subsea positioning insulates it from surface wind, waves and currents. The first unit was installed in May in 1,640 ft (500 m) of water, and the company will observe its performance for 3 months to gain confidence for a working installation, Formigli said.

Another new-build concept is the FPSOBR. This is not a conventional ship or a conversion from a tanker, and it's not shaped like a conventional ship. The flat bottom and sides lower construction costs by allowing use of ordinary naval construction steel fabricated in a shipyard or construction site. They help increase fatigue life to 100 years for a minimum of intervention. The sides are double sided to protect against leakage in case of a collision, and the righting-arm curve is "many times greater than rules recommend."

The company designed the vessel to work in water depths to 9,843 ft (3,000 m) using flexible risers to bring the oil from deepwater subsea wells.

Formigli calls the third concept the MonoBR. It looks like a short, stubby spar, but it's not really a spar, he said. It's a short, cylindrical hull with a draft of only 131 ft (40 m) and total displacement of some 135,000 tonnes.

Formigli said this should be the first of a family of mon-column hulls in which hull diameters and cylinder depths change mass and inertia. The moonpool, which has a smaller diameter outlet at the bottom than the topside, adds out-of-phase forces that compensate for vertical and angular motions on the hull.

Petrobras isn't the only company with plans for the future of deepwater floating production systems. ExxonMobil has its own ideas on the subject. Those ideas rely heavily on the use of heavy up-front planning, modeling and analysis to avoid costly back-end remedial expenses.

Preplanning

In a talk titled "Component-based Engineering and the Need for Full-scale Performance Measurement," Robert E. Sundstrom, supervisor, ExxonMobil Upstream Research Co., said the keys are computation, models and full tests to monitor the effects of events such as vortex-induced vibration. Those tests affect not only the financial aspects of a deepwater design but the safety and operating convenience of the crew, as well.

"Offshore, we don't know all the rules. For the others (rules), we must try to improve designs and reduce uncertainty," he said.

Ideally, operators could use a full-scale model for tests, but that's not a financial option. Hydro-dynamic elements of a model in a tank don't scale up from model to full size. In deepwater systems, reasonable models would be too large for the test tanks. "We have to truncate the model and account for the trucations," Sundstrom said.

ExxonMobil reduces uncertainty as much as possible in the model and goes to the full working version. It then gets feedback from the working version to polish the software and make it more accurate for the next modeling task.

Hank van den Boom, with the Maritime Research Institute in The Netherlands, uses a slightly different approach. He monitors full-scale operations. "Monitoring is accelerating experience without having to make mistakes," he said.

For example, his organization studies FPSO roll by recording hull motions on three FPSOs in relation to wave conditions. One unit was Girassol of Angola, another was the P-35 off Brazil and the third was the Glas Dowr off South Africa.

Results of those studies and others will help designers and operators of offshore production platforms get ready for events such as Ivan the Terrible, the hurricane that tore floating drilling rigs loose from their moorings, disjointed pipelines and damaged and destroyed platforms in the east-central Gulf of Mexico.

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