Large offshore reservoirs continue to attract floating production units, but gas will push into this oil-dominated territory.

Mild operating environments, remote locations and deepwater fields make floating production, storage and offloading (FPSO) systems the development tool of choice for many field applications. Operators often choose this solution to tap big reserves, particularly off West Africa and Brazil, where highly productive wells are common.
But as the world becomes more concerned about carbon dioxide emissions and gas flaring, alongside tighter regulatory control, solutions soon will have to be found for the large volumes of stranded gas that until now simply had been wasted via an FPSO flare stack.
Contractors are starting to suggest new floating production ships can not only process oil and offload it to shuttle tankers, but also can provide an economic way of delivering associated gas to a market where it can be monetized.
Next generation
The Fluor Offshore Services division in Houston, Texas, outlined what it calls a next-generation combined FPSO, which although focused primarily on oil production, also will offer liquefied natural gas (LNG), compressed natural gas (CNG) and gas-to-liquids (GTL) options. It also can use gas for offshore power generation, or gas to wire (GTW). Another possibility is converting gas onboard from methane to methanol by altering its molecular structure. These alternatives could overcome gas transport limitations in remote operating regions where flaring is restricted, gas reinjection is less desirable or the tax regime encourages gas utilization.
Some of the technologies already are available to make combined FPSOs a reality, particularly with CNG. Skip Alvarado of Fluor Offshore Services said, "We believe that the first combined FPSOs are not too far down the road."
Such a unit probably would have to be bigger and heavier than a conventional FPSO, and would require a more complex interface of production systems onboard.
Multiple construction sites would be required to turn Fluor's concept into reality, for both topsides and hull fabrication. The installation, hookup and commissioning phases of a combined FPSO project would be a major challenge, particularly if conversion of an existing ship is involved.
"A purpose-built vessel, on the other hand, could significantly extend the project schedule," an Offshore Technology Conference paper on the proposal suggested.
"The increased topsides weight and complexity will stretch the module construction and installation capabilities of most present day offshore construction yards, as well," Alvarado said. "The size and scope of these larger FPSOs may result in the need to fabricate topside modules in more than one location."
When asked where these giant units could be built, Alvarado said it could be just about anywhere worldwide, including the United Kingdom, where several North Sea FPSOs have been outfitted. Alvarado also identified Asia, particularly Singapore, as another location that could accommodate Fluor's concept.
Depending on the size of the throughput required, Fluor's combined FPSO could be anything between 85,000 dwt for a CNG system on a unit capable of processing 50,000 b/d of oil, up to a colossal 453,000 dwt for a GTL-equipped FPSO capable of processing 150,000 b/d of oil.
While the technical and economic parameters will dictate which, if any, of these gas-handling technologies is chosen, Fluor said it offers operators a range of options for stranded gas (Table 1).
Fluor said most FPSOs are focused on producing oil, and associated gas handling is seen as a secondary issue. Gas reinjection into the producing reservoir or a storage reservoir usually is done to satisfy regulatory requirements since flaring is allowed only in emergencies and for short periods.
For GTL to be economic, Fluor suggests a throughput of between 5,000 b/d to 10,000 b/d. CNG is said to be the cheapest option requiring the shortest lead time - since gas dehydration and compression equipment commonly is available on FPSOs. GTW is regarded as feasible too, since offshore power generation is common in the North Sea. Installations offshore Norway gradually are moving toward onshore power generation, proving that long-distance power cabling to production platforms is becoming readily accepted. GTW involves using produced gas for offshore power generation and then sending the generated electricity back to the beach.
"Compared to a pipeline, subsea cable transmission is less sensitive to water depth and is believed to be commercially justifiable for distances to shore between 150 km and 400 km (94 miles and 250 miles). Deepsea high-voltage cable can be safely made and laid for capacities up to 500 MW," Alvarado said.
Perhaps anticipating this trend toward gas utilization, Norwegian ship and FPSO owner Bergesen plans to convert the 20-year-old LPG tanker Berge Arrow into an LPG FPSO. It is marketing the unit for West Africa. This combined concept, which will have ABB as operator and development partner, is nearing "a concrete state," according to a Bergesen spokesman. "The conversion will most likely be done at a yard in Singapore, possibly the Jurong shipyard," he added.
Off Western Australia, Shell Exploration & Production and partner and operator Woodside Petroleum plan to install the world's first floating LNG plant over Greater Sunrise field.
Risers
Elsewhere, a different FPSO concept evolution is under way with a joint industry project (JIP) involving Japan National Oil Corp., Japan Drilling Co. and Mitsubishi Heavy Industries. Since the JIP started, it has expanded to include Inpex Co., Japan Petroleum Exploration, Mitsui Oil Exploration, Rig Engineering Consultants and RTI International. This proposal features compliant vertical access risers (CVARs).
The group is working on two variants. The CVAR FPSO I is for Brazilian and Indonesia, while the CVAR FPSO II is designed for West Africa. These units would be cheaper than a conventional FPSO, offering dry trees in ultradeep water. Both feature a workover rig mounted over the risers, allowing direct well intervention via dry trees.
JIP members introduced the CVAR concept at OTC in 2001, and they have enhanced the concept with a version suited for West Africa that uses a spread mooring system to avoid the need for a turret and fluid transfer system, the most expensive components on a weathervaning FPSO.
Proponents of this concept argue turret weathervaning capability in Indonesia and Brazilian applications, and weathervaning without a turret in West Africa, would be cheaper and more practical as it would allow a rig to operate on workovers and permit well intervention from the FPSO.
Because traditional FPSOs use subsea completions, they have an inherent disadvantage, the Japanese group said. "Subsea completions are more complex and expensive than surface completions, with well-known reliability issues," a paper on the proposal argued. "These complexities, in terms of the necessary sophisticated completion design, the control system and related umbilicals, and the large number of independent lines to the surface for production, control, gas lift and injection, while not prohibitive by any means, have to be shown consideration."
Japan's JIP pointed out the usual methods for connecting FPSOs to the subsea wellheads commonly involve either catenary, flexible or rigid freestanding risers, all of which make it impossible for well intervention to be carried out directly through the riser. Also, flow assurance issues revolving around wax and hydrate formation must be addressed during the design and operation of the FPSO.
Designing an FPSO that can give access through the riser can enable big economies, the JIP group said.
Modeling of the cost-savings offered by this type of unit suggest capital expenditure for a CVAR FPSO I could be US $223 million, while a CVAR FPSO II could cost $255 million, compared to $284 million for a conventional FPSO.
Tension-leg platforms
Moving away from FPSOs, one of the main rival floating platform designs is the tension-leg platform (TLP). Work in this area has focused on extending water depth and payload capacity.
One engineering company is developing a drilling and tender vessel design intended to complement enhanced TLPs.
Atlantia Offshore, a part of the IHC Caland group, which also owns FPSO specialist Single Buoy Moorings, has been working on the new drilling tender in a broader study with sister company Marine Structure Consultants (MSC). Together the companies are looking to provide deepwater development tools to extend the capability of a TLP.
Already tender-assisted drilling units with self-erecting capabilities are in wide use in the Far East and West Africa in shallow water. "This cost-effective method can also be extended to deepwater applications," Atlantia said in an OTC paper.
MSC carried out design engineering for this new drilling tender semisubmersible, designated TSS-33, and the design matches Atlantia's own SeaStar TLP design.
This new MSC tender rig would allow the payload of a dry-tree TLP to be increased because some of the drilling and completion payload could be put on the tender vessel, Atlantia said.
"The tender vessel will be moored by means of a taut-leg prelaid mooring spread near the wellhead platform. Typical displacements of these semisubmersible tender vessels are approximately 25,000 metric tonnes," Atlantia said.
Morpeth, Allegheny and Typhoon are Atlantia SeaStars with 58-ft (17.6-m) -diameter monohulls. TotalFinaElf will operate Matterhorn, an enhanced SeaStar with an 84-ft (25.6-m) -diameter monohull that provides a dry tree and drilling completion platform. Atlantia won a fixed-price contract to supply the hull in August 2001, and the new Matterhorn platform is due for installation in the US Gulf this summer for first oil in August.
Based on its experience, Atlantia sees no reason why the TLP design cannot be taken to greater depths. Model tests carried out by the company indicate a TLP could be taken to 6,500 ft (1,981 m) in the Gulf of Mexico and 9,000 ft (2,744 m) in West Africa.
ABB has some designs for TLPs in progress, too. Among them are three- and four-leg TLPs and a monocolumn TLP for deepwater development with dry trees.
Sometimes size matters, and when BP decided to build the largest floating production platform in the world, it turned to the GVA Consultants' 40000 semisubmersible design.
BP will pull reserves from its 1 billion-bbl Thunder Horse and 500,000-bbl Thunder Horse North fields from its station in 6,040-ft (1,840-m) waters in the Gulf of Mexico.
The system can produce 250,000 b/d of oil and 200 MMcf/d of gas while injecting up to 300,000 b/d of water.
Deck capacity on the floater is 40,000 metric tons, and it is capable of displacing 130,000 metric tons of water.

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