COST ADVANTAGES AS WELL AS production from ever-increasing water depths make floating production installations the first choice for a variety of offshore oil field development projects.
These installation are in operation in most of the world`s offshore producing areas, providing facilities for extended field testing as well as for production of both marginal and deepwater fields. For deepwater fields that cannot be tied back to facilities in shallower water, floating systems offer the only development alternative.
In 1997, most floating production installations were in water 150-400 ft deep.
In the past, these installations were considered mainly as fast-track alternatives for producing marginal reservoirs in shallow water, far from production infrastructure.
Floating production installations include (Fig. 1):
- Semisubmersible floating production systems (FPSs), or semisubmersible floating production units (FPU).
- Monohull floating production, storage, and offloading vessels (FPSO).
- Spar buoys.
- Tension-leg platforms (TLP).
The term "mobile offshore production system (MOPS)" covers chained or wire-moored vessels, such as the FPS (FPU), FPSO, and Spar.
TLP mooring is different. These platforms are held in place with large steel tendons fastened to the sea floor.
Floating production systems can also be dynamically positioned, as in the case of BP`s Seillean FPSO. BP designed the FPSO for producing limited-size fields in the North Sea that have good productivity characteristics, such as its Cyrus field.
FPSs and FPSOs typically are connected to subsea wellheads or manifolds. Wellheads on the spar buoys and TLPs are on the deck, thereby facilitating downhole work and lowering cost. Spar buoys and TLPs may also be tied into subsea well completions.
Floating installations primarily have been designed for oil production. One advantage of the FPSO is its large storage capacity for produced oil. The other systems usually do not include any sizable storage capacity and need to be tied into floating storage vessels, shuttle-tanker terminals, or pipelines to shore.
In the past, gas was often flared from floating production systems. But now governments have started to restrict flaring, and more installations are being connected to gas pipelines.
Besides oil production, floating liquefied petroleum gas (LPG) units are in operation offshore Indonesia in the Arjuna field, and offshore Cabinda in the Takula field. The N`Kossa development, offshore Congo, also produces LPG.
Future prospects for floating systems include housing facilities for producing stranded gas. The facilities would either convert natural gas to a syncrude (gas-to-liquids, GTL) or liquefy the natural gas (LNG).
Floating facilities for converting gas to methanol were being designed in 1997.
Early floaters
Putting production facilities on a floating vessel is not new. Such installations have been in the oil field since at least the 1970s. Some barge installations in shallow inland waters might predate this.
Hamilton Brothers deployed the first semisubmersible FPS in 1975 to produce oil from four subsea-completed wells in Argyll field in the North Sea. A converted drilling rig was used for the FPS.
Another early system, 1976, was Indonesia Cities Service Inc.`s Poleng field, offshore Madura Island, Indonesia. This early-production system, in 180 ft of water, included a production barge tied to four-pile wellhead platforms. Oil from the production barge was pumped to a storage tanker yoked to a single-point mooring buoy. For export, oil was offloaded from the storage tanker to sea-going tankers.
The early FPSO mooring design was based on tanker offloading systems such as catenary anchored-leg moored buoys (CALMs) and single-point buoy moorings (SPMs).
The first ship-shape production vessel, 66,000 dwt, was installed in 1974 by Arco Indonesia Inc. in the Ardjuna field offshore the island of Java. In 1977, Shell installed a 60,000 dwt FPSO in the Castellon field offshore Spain in 377 ft of water. These system helped demonstrate the economic potential for converting tankers to floating production facilities.
The U.S. saw its first FPSO in 1981: the Exxon OST, a 55,000 dwt tanker moored in the Hondo field offshore California. The vessel processed oil from a fixed platform and offloaded the oil to dedicated shuttle tankers. It was removed in the 1990s after installation of a pipeline to shore.
The first Gulf of Mexico FPS was installed in 1989 as part of Placid Oil Co.`s deepwater Green Canyon 29 development. The converted semisubmersible proved the feasibility of FPSs for the Gulf of Mexico, although the project itself was uneconomic because the reservoir failed to meet expectations.
Enserch Exploration Inc. used much of Placid`s concept and some of Placid`s equipment in 1995 to develop its Garden Banks 388 discovery in 2,190 ft of water of the Gulf of Mexico (Fig. 2).
The first TLP was installed in 1984 by Conoco (U.K.) Ltd. in its North Sea Hutton field in 486 ft of water. This was followed by the much smaller Jolliet TLP installed by Conoco in 1989 in the Gulf of Mexico in 1,768 ft of water.
TLPs
Seven TLPs had been installed worldwide through 1997, four in the Gulf of Mexico and three in the North Sea. Statoil`s Heidrun TLP is the only one with a concrete hull. The other TLPs have steel hulls.
Shell Deepwater Development Inc. planned to install the Ursa TLP in 1999 in a record deep 3,950 ft of water. Shell had been successful in significantly reducing the cost of each of its successive TLPs in the Gulf.
Standardization and cloning are integral design features for Shell`s series of Gulf of Mexico TLPs. Its first, Auger TLP, was installed in 1993, followed by Mars in 1996, and Ram-Powell in 1997.
Although Ram-Powell is similar, it is larger, and total project cost is less. Auger and Mars cost $1.2 billion each; Ram-Powell cost $1 billion.
Based on Auger and Mars, Shell sharply cut Ram-Powell`s costs, increased unit size, and refined and enhanced design, fabrication, and construction parameters. The project benefited from an overlapping contracting, design, and fabrication/construction schedule with Mars.
Among refinements, Ram-Powell has a top-tensioned drilling riser that allows wells to be drilled with a surface blowout preventer stack. The platform drilling rig was to be removed after the wells were completed.
Catenary export risers cut costs of the TLP`s 26-mile, 12-in. oil and 25-mile, 14-in. gas pipelines and added operating efficiencies.
Ram-Powell also does not have a lateral mooring system such as was incorporated in Auger.
Ram-Powell is secured to the seafloor with 12, 28-in. diameter steel tendons, three per corner. The foundation includes 12 piles, 84 in. in diameter and 349 ft long.
As with Mars, the facilities on Ram-Powell were modularized, and include a wellbay, quarters, process, power, and drilling module. These modules were installed with a 4,000-ton capacity, twin-boom, special lifting device first used for Mars, located at a fabrication yard near Corpus Christi, Tex. (Fig. 3).
Modules were installed with the onshore booms to eliminate weather-related risks associated with offshore installation.
Ram-Powell is designed to handle 200 MMcfd of gas, 60,000 b/d of oil and condensate, and 30,000 b/d of produced water from 20 TLP wells and four subsea wells.
Another TLP having a 1999 installation date was Amoco Corp.`s Marlin TLP in 3,240 ft of water in Viosca Knoll Block 915.
A different type of TLP, Seastar designed by Atlantia Corp., was to be installed by British-Borneo Petroleum Syndicate plc for developing its Morpeth discovery in 1,500-1,700 ft of water in the Gulf of Mexico.
The minimal-sized TLP is designed for relatively small fields with few well completions. The three-leg TLP features a single column through the wave zone. Unlike the larger TLPs, the Morpeth TLP will be tied to subsea completions.
FPSOs
FPSOs comprise both barge and ship-shaped vessels. These vessels, like semisubmersibles, connect subsea wellheads to production facilities installed on the deck of the vessel. But unlike semisubmersibles, FPSOs provide a large storage capacity.
The FPSO is the only floating system that does not include drilling or workover capabilities. But this may change. Some proposeddesignsincorporatea drilling/workover rig on top of the mooring turret.
Most FPSOs installed during the 1980s were converted tankers, but newbuilds represented about half of the FPSOs planned in 1997.
FPSOs are also available for lease from third parties. In one example, Den norske stats oljeselskap AS (Statoil) planned to set up a joint venture to build and market a fleet of shuttle tanker/production ships to third parties. As a launch point for the project Statoil and China National Offshore Oil Corp. (Cnooc) leased an FPSO for 2 years to develop the Lufeng 22-1 oil field in the South China Sea.
The complex arrangement involves Statoil building and owning the vessel while the processing facilities will be leased from Advanced Production Systems (APS), Oslo, a 50-50 joint venture of Statoil and Aker AS.
The Lufeng 22-1 FPSO will incorporate Statoil`s submerged turret loading design.
FPSOs have increased in size. The 1986 Petrojarl 1 had a 637-ft length, 43-ft breadth, and 42-ft depth. The production facilities were designed to handle 40,000 b/d and store about 190,000 bbl of oil. The FPSO design for Statoil`s Aasgard field has a 905-ft length, 149-ft breadth, and a 98-ft depth. And the Aasgard FPSO is designed to process 200,000 bo/d and store about 950,000 bbl of oil. It will be installed in the field in 1999.
The purpose-built Petrojarl 1 FPSO demonstrates that such vessels can be moved from field to field. The FPSO is fitted with a turret mooring system and dynamic positioning system. It also has two riser systems, one for continuous production and the other for testing and well intervention.
Through 1997, the Petrojarl 1 had been installed in eight different North Sea fields, in water depths ranging from 230 to 1,080 ft.
By one count, 137 FPSOs were operating or in some stage of development. In 1997 about 50 were in operation. The main operating areas include the North Sea, China, and Australia.
FPSOs are moored with a buoy system or turret, or spread-moored. Buoy and turret mooring allows vessels to rotate depending on the weather. Turret-mooring is favored for FPSOs especially in harsh environments such as the North Sea and offshore Australia. But in more-tranquil environments such as offshore West Africa, spread moorings can be used. Mobil Equatorial Guinea Inc.`s FPSO in the Zafiro field is one example.
The Gulf of Mexico in 1997 was considered a possible venue for deepwater FPSOs, but questions remained about potential spill liabilities from the storage and offloading activities.
The FPSO moored in the deepest water through 1997 was in offshore Brazil. Petrobras with its FPSO II (Fig. 4) was testing a subsea well completion, MLS 3B, in the South Marlim field. The FPSO was moored in 4,659 ft of water.
FPSO II receives oil and gas from the subsea well completed in 5,4607 ft of water and houses the facilities to process the oil and gas, provide gas lift gas, and store the oil for offloading operations to a shuttle tanker. FPSO II previously was deployed as the production facilities for the West Linapacan field, offshore Philippines.
Petrobras has five FPSOs under construction, all conversions of obsolete product tankers in the Petrobras fleet. Three will be installed in Marlim field, one in Albacora field, and one in Barracuda field`s pilot production scheme. Installing FPSOs is a change for Petrobras, which previously relied on semisubmersible-based floating production systems and pipelines to produce its deepwater offshore fields.
The FPSOs will offload to a dedicated fleet of shuttle tankers, thus saving Petrobas from having to make substantial investment in pipelines.
FPSs
Semisubmersible production vessels have been primarily installed in the Campos basin offshore Brazil and the North Sea, areas with ample pipeline infrastructure. When increased drilling demand made semisubmersible drilling units scarce for conversion to production systems in 1997, newbuilds became a more likely option.
One drawback in utilizing semisubmersibles has been space and weight limitations compared to FPSOs, particularly when fluid injection/gas export is required.
Mooring arrangements for FPSs tend to have 4-12 chains emanating from the corners of the vessel. Dynamic motion analysis for expected environmental conditions will indicate the mooring forces to be expected and hence will determine the holding power in terms of number of mooring chains, their size, and the anchor requirements.
A development incorporating both an FPS and FPSO, which is also the first subsea development with electric submersible pumps for artificial lift, is Amoco Corp.`s Liuhua 11-1 oil field in the South China Sea.
At Liuhua 11-1 a converted semisubmersible, Nanhai Tiao Zhan, is installed in 1,000 ft of water. It serves for both drilling and as a surface control base for the extensive subsea production equipment. It is permanently moored and experiences only slight movement from wave action.
The other facility, a converted tanker, is an FPSO moored with a large swivel turret near the bow. Massive anchors are positioned in a large circle on the seabed and fastened to the turret.
The FPSO will weathervane, or swing on its mooring with wind and tide action, and experiences considerable pitch, roll, and heave movement from wave action. Shuttle tankers connected in tandem to the FPSO offload the oil.
Production facilities are designed to handle 65,000 b/d of oil.
For small fields, a new FPSO design is the Ramform, which was to be installed in Conoco (U.K.) Ltd.`s North Sea Banff field.
The wide-transom design offers good weathervaning characteristics, which will contribute to low overall operating costs. Its storage capacity is relatively limited, but inexpensive storage tankers can be added to the production system or more frequent offtake can be done by shuttle tankers.
Spar buoys
A relatively recent entrant in floating production facility designs is the spar buoy.
Oryx Energy Co., in September 1996, installed Neptune, the world`s first spar-based offshore oil and gas production facility, in 1,930 ft of water in Viosca Knoll Block 826. The spar has a 72-ft outside diameter hull, a 650-ft draft, a 55-ft freeboard at the cellar deck, and a 32 by 32-ft center well with room for 16 wellheads.
Oryx said it selected a spar facility because it cost less than other designs, provided direct access to wellheads, was stable, allowed phased development, and could be moved to another location.
A breakdown of the cost of the $172 million development was as follows:
- Spar hull and mooring -$53 million.
- Topside and installation-$47 million.
- Production risers-$14 million.
- Drilling and completion-$42 million.
- Engineering, project management, and permitting-$16 million.
A six-leg taut system moors the spar to 84-in. diameter piles.
The wellheads move independently of the spar; therefore, flexible lines connect the wells to the production facility. During 1997, the spar survived Hurricane Danny.
Deep Oil Technology developed the spar concept along with Spars International Inc., a joint venture between J. Ray McDermott Inc. and Aker Oil & Gas Technology AS.
The facility was designed to handle 25,000 b/d of oil, but this was to increase by several thousand barrels once the production facilities were debottlenecked.
A second and larger spar was under construction in 1997 for Chevron USA Production Co., due to be installed in 2,600 ft of water in Green Canyon Block 205. Unlike Oryx`s Neptune, Chevron`s Genesis spar was to handle both drilling and production operations.
The Genesis spar is 705 ft tall and measures 122 ft across. The unit has a 650 ft draft and was to be moored with 14 anchor lines.
A spar-like development was also set to be installed by Exxon Corp.`s Hoover/Diana project (Fig. 5). Exxon calls the facility a deep-draft caisson vessel (DDCV). Plans were to set it in 4,800 ft of water on the Hoover structure in 1999. The Diana structure will be tied in subsea to the DDCV.
Gas processing
During 1997, the world`s fourth LPG floating storage and offloading (FSO) system started up. The project involves Chevron Nigeria Ltd.`s Escravos gas field off Nigeria. The first LPG FSO began operating for ARCO Indonesia in 1978.
The Escravos FSO was the first to include tandem mooring for cargo transfer. This required development of off-loading hoses capable of operating at -43° C.
Floating barge
Elf Congo`s N`kossa development includes a 722-ft by 148-ft prestressed concrete barge. It was to be linked to two unmanned wellhead platforms andtwofloatingstorage/offloading(FSO) tankers (Fig. 6).
N`kossa production started at 30,000 b/d of oil and was expected to plateau at 120,000 b/d and 1,300 metric tons/day of liquefied petroleum gas.
The FPU accounts for half of N`kossa estimated development costs of $1.9 billion.
Elf estimates the floating barge concept saved it almost $200 million compared with a traditional production system and will also result in considerable savings on maintenance.
It hopes to apply the technology to deepwater development projects that may result from Elf`s exploration efforts in about 1,000 m of water in the Gulf of Guinea off Angola, Congo, and Nigeria.
The N`kossa barge, installed in 550 ft of water, is linked to the two drilling platforms. The FPU weighs 70,000 metric tons, including 30,000 tons for topsides. Deck surface is about 10,000 sq m.
One of the FSO tankers can store 270,000 metric tons of crude oil, the other 80,000 cu m of LPG.
The FPU contains six modules: accommodation and central control, utilities, electric power generation, gas compression for reinjection, crude oil, and gas.
Economics
In many cases floating facilities can be considerably more cost effective than fixed platforms.
There is a trade-off between capital costs and operating costs. Operating two facilities (FPU/FSO) is more expensive than one (FPSO), but capital expenditure may be less for the former. A conversion (tanker or semisubmersible drilling rig) needs less capital expenditure than a newly built vessel but may be more expensive to operate. The vessel may have to be refurbished several times over the project`s life.
One advantage of floating facilities and subsea equipment is that they can be reused. This option should be considered in the project economics.
Also, floating facilities often have very short implementation schedules, which improve a project`s rate of return.
International Maritime Associates Inc. estimates that the capital expenditures of four types of FPSO vessels are as follows:
1.Purpose-built, high-end FPSO for harsh conditions-$400 million.
2.Purpose-built FPSO for moderate conditions-$310 million.
3.Converted FPSO for moderate conditions-$240 million.
4.Converted basic FPSO with external mooring-$110 million.
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Onshore booms are placing production modules on the Mars TLP (Fig. 3).
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An FPSO yoke-moored to a single-point buoy, offshore Brazil, handles oil production from a subsea well completion in 5,607 ft of water (Fig. 4).
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