Operators sift through a lot of variables before picking the right production facility.

Selecting the right production platform for an offshore field is getting more complicated for operators as lightweight materials and mooring alternatives allow tension leg platforms (TLPs) to encroach on territory formerly owned by semisubmersibles.

Spars normally fill a gap between those two types of floating platforms, and the range of services they can handle is broadening as well, according to Rajiv Aggarwal, technical advisor for Halliburton-KBR's Deepwater Technology Group. He focused on Gulf of Mexico applications moving from deepwater to ultradeep and did not include tanker-based floating production, storage and offloading (FPSO) vessels in his analysis.

TLPs, spars and semisubmersibles all are proven configurations with their own advantages and disadvantages, according to speakers at the IBC Floating Production Systems 2004 Conference in Houston.

Popularity

In a popularity contest, semisubmersibles win with more than 36 new and converted facilities installed or under construction worldwide. Until recently, none was scheduled for the Gulf of Mexico. They can range from the huge newbuilds set for Thunder Horse and Atlantis fields to conversions like the original Gulf of Mexico semisubmersible on Garden Banks 388 to the new smaller units for smaller fields. When payload is critical, semisubmersibles have the advantage.

TLPs have the dominant spot in the Gulf of Mexico with 14 installed, under construction or sanctioned since 1984. Another three are in the North Sea and two each are in West Africa and Indonesia. They are a competitive option for both dry and wet tree development in up to about 5,000 ft (1,525 m) of water, Aggarwal said.

Spars also handle dry or wet trees. They are the clear winner in the Gulf of Mexico and a clear also-ran everywhere else in the world. All operating spars are in the Gulf of Mexico.

Designs range from classic spar, including Neptune in 1,900 ft (579 m) of water, to truss spars such as Gunnison in 3,150 ft (960 m) of water to Kerr-McGee's Red Hawk cell spar, which is moored in 5,300 ft (1,616 m) of water.

Kerr-McGee found it could save a lot of transportation money by having the cell spar built on the Gulf Coast.

Variables

Payload and water depth aren't the only key factors in selecting an offshore platform, Aggarwal said. Among other criteria are:

• Well patterns - clustered or dispersed;
• Drilling, workover or production only;
• Dry tree or wet tree;
• Hub or stand-alone;
• Payload capacity;
• Flexibility for expansion;
• Mooring system performance;
• Riser system feasibility and risks;
• In-service performance (behavior in loop currents);
• Predictability of delivery on time at cost;
• Contractor capability, track record, capacity;
• Contracting flexibility;
• Integration plan;
• Installation risk and equipment; and
• In-service operational complexity (ballast requirements).

In addition, he said, hull size generally increases with water depth, and stationkeeping requirements vary from critical in the North Sea to matter-of-fact off West Africa. An operator must know how each configuration will handle a Gulf of Mexico loop current, vortex-induced vibration and vortex-induced motion.

Weight

The weight of the tendons on a TLP can add a lot of payload, but newer designs use stepped-diameter tendons to hold weight down. Mooring chain was another big weight factor for floating platforms, but polyester moorings can reduce weight significantly.

Several potential solutions are in operation or under study to lower riser weight on platforms. The obvious first, easier choice is buoyancy, but operators also are studying the use of titanium components or segments in risers. Separate riser towers also can reduce the weight penalty on floating platforms.
For smaller fields, GVA Consultants has designed an asymmetrical hull to improve riser motion in water depths from 3,000 ft to 10,000 ft (915 m to 3,050 m), Aggarwal said.

All of the above factors make contributions in the final decision for choosing a floating production platform. However, the alternative risk management approach in API RP 2FPS, to deal with varying uncertainties in key components and sub-systems of a floating production and storage (FPS) vessel unit, calls for a system review to assess and reduce risk. That will eliminate some choices. An operator should then identify hazards and analyze frequency of hazard occurrences from experience with floating platforms in the area and then assess the consequences of countering individual hazards. Following that risk evaluation, an operator should be able to determine if the risk is tolerable for each choice or establish comparative risk levels for alternative overall FPS solutions and their sub-systems.

At the same conference, Kieran Kavanaugh, president of the MCS Houston operation, said the worldwide popularity contest for floaters goes to FPSOs with an anticipated 77.66% of the market between 2003 and 2007. In the same period, TLPs will take 16.14% of the market, spars 15.11% and semisubmersibles 10.9%.

Greater Plutonio

Considering operations activity, both Brazil and West Africa will be very strong, he said, while the Asia Pacific is strong, the Gulf of Mexico is good and Europe is weak.

Scott Maclachlan, FPSO topsides engineering manager for BP's Greater Plutonio project in Block 18 offshore Angola, analyzed this project.

This is BP's first operated development off Angola, and it consists of tiebacks from six fields spread over a broad area in water depths from 3,937 ft to 4,922 ft (1,200 m to 1,500 m). That meant a large number of flowlines and the need for a large FPSO with a lot of topside capacity. The area has no offshore pipeline infrastructure.

The production unit had to handle 20 production wells and 23 injection wells running through nine manifolds. It needed a unit with the capacity to produce 220,000 b/d of liquids and store 2 million bbl of oil. The FPSO will be fed by 100 miles (160 km) of risers and flowlines and 64 miles (105 km) of umbilicals.

The production facility had to supply 103 MW of power and compress 330 MMcf/d of gas for reinjection. Those heavy requirements made the FPSO selection a natural one.

Bonga

Shell also faced challenges in getting its Bonga project up and running, said Gbola Sobande, controls manager at Shell Nigeria E&P Co.

This deepwater offshore project in OPL 212 also needed a large above-water capacity to handle 225,000 b/d of oil in 280,000 b/d of total fluids and 150 MMcf/d of gas, including 65 MMcf/d of lift gas. That project has 30 seabed well locations serving 37 subsea targets.

In other words, it was a big project with big requirements. Sobande said Bonga was one reason some contractors switched to reimbursable contracts to reduce risks. The Shell team also found that, beyond a certain critical size, there is a disproportionate escalation in complexity and risk, particularly since the industry has little experience in designing and building FPSOs three times the length of a soccer field.
One challenge at Bonga dealt with the growth in required weight from 20,000 tonnes to 22,000 tonnes. That meant a redesign of parts of the platform. Another challenge was Shell's low estimate of 200,000 man-hours for completion. The actual job took an additional 5,000 man-hours.

Shell did a lot of things right in the US $3.5 billion Bonga project, Sobande said, but it could have done a better job on parts of the project, too.

It is scheduled to flow first oil in July next year.

Design

During the Floating Production Systems 2004 Conference, Edward Huang, vice president of naval architecture for Sea Engineering Inc., which makes Modec platforms, described a floating production platform design for the Gulf of Mexico.

Semisubmersibles, he said, make the most efficient use of hull steel weight, equal to TLPs and 70% less than spars. The tradeoff is a higher hull motion. Semisubmersibles also often cost less than other designs because of savings on mooring, hull and installation.

The main driver for a semisubmersible in the Gulf of Mexico, he said, is recent discoveries in water depths greater than 7,000 ft (2,135 m) with no nearby pipeline infrastructure. "As you go deeper, TLP tendons get more and more expensive," he added.

The new design is a center-pontoon semisubmersible. Where a conventional semisubmersible has columns at all four corners of the pontoons, the center-pontoon design moves the columns outboard of the pontoons. That design places less pry-squeeze load pressure on the columns, he said. It also allows easy access for polyester mooring systems, and it reduces motion.

To further blur the lines among the deepwater options, Steve Leverette, manager of the technology and research and development department at Atlantia and SBM-Imodco, described two TLP designs for ultradeep water.

One design is a deep-draft semisubmersible-type TLP that offers better control of motions on steel catenary risers. It has gone through full model testing and front-end engineering for a 6,000-ft (1,830-m) location in the Gulf of Mexico. The other TLP is a design for water depths of 8,000 ft to 10,000 ft (2,440 m to 3,050 m) using conventional steel tendons and the capacity to handle payloads up to 30,000 tonnes.
A TLP is better for deep water, he said, because there is virtually no heave, and it provides better riser support. The small footprint minimizes interference among field activities.

The keys to ultradeep TLPs are stepped tendons for lighter weight and lower cost, oscillation suppression and less tension on tendons, which translates to lighter tendon weight.

Stepped tendons mean tendons can be neutrally buoyant to a greater depth. A new oscillation supression control systems works something like a shock absorber on a car to reduce vibration and with the ability for tuning to maximize heave and pitch damping.

John Chianis, vice president of deepwater technology and engineering for ABB Lummus Global, described his company's design for an extended TLP (ETLP) platform. With the ETLP, the company has moved the columns toward the center on the pontoons, leaving the tendon porches outboard and out of the way.

These are just a sample of designs proven and approaching that will make the jobs of operating-company analysts even tougher in the future as they try to decide on the best concepts for developments in increasingly deep water.

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