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May 2006 Maritime Technology Reporter
Growing Requirement for Floating Production Systems
James R. McCaul, President
International Maritime Associates, Inc.
Floating production has evolved over the past 30 years in response to the need to produce in water depth beyond the reach of fixed platforms. There are now 179 floating production systems in operation and another 46 on order. They are routinely producing on fields in the North Sea, Gulf of Mexico and offshore Brazil, West Africa, Southeast Asia, China, other locations. Thirty are producing on fields in water depth exceeding 1 kilometer. The 2 kilometer mark will be passed within the next two years, when the Independence Gas Hub and Blind Faith production semis start producing in the Gulf of Mexico. By any measure, this is a remarkable achievement for a technology that dates only from the mid-1970s.
Growth of floating production — Floating production can be traced to 1974, when Hamilton Brothers converted the semisubmersible drill rig Transworld 58 to a floating production unit for use on the Argyll field in the North Sea. The unit was placed in 79 meters water depth and operated for 16 years. The first ship shape floating production unit is traced to 1977, when Shell converted a 60,000 dwt tanker to an FPSO vessel with 20,000 b/d processing capacity for use on the Castellon field offshore Spain. It operated in 115 meters water depth.
But the commercializing and early expansion of floating production technology can be attributed to Petrobras. The operator saw floating production as an excellent, relatively low cost solution for producing crude in the deepwater fields of Campos Basin. Petrobras began using converted rigs as production semisubmersibles in 1977 --- and within ten years had 11 floating production units operating offshore Brazil.
Interest in floating production spread to other operators in the 1980s. Driving this was the successful demonstration of floating system technology on offshore fields between 1984 and 1986. Most notable were Conoco's Hutton tension leg platform, the Golar Nor Petrojarl 1 early production system and BP's Seillean SWOPS vessel. These systems clearly showed floating production to be a practical and economical solution for certain offshore applications. By the end of the 1980s, there were 31 floating production systems in operation.
The tempo of installations continued to build over the first half of the 1990s. More than a dozen FPSOs were installed in the five year period, the bulk of which were placed offshore China, Southeast Asia, Australia or in the North Sea. They included Woodside's Cossack Pioneer, a large FPSO able to process 140,000 b/d oil that was placed on the Wanaea/Cossack field offshore Australia. Seven production semis were installed, including Norsk Hydro's Troll B production semi in the North Sea, which is capable of producing 270,000 b/d oil and 282 MMcf/d gas. The early 1990s saw the take-off of TLPs, with three units being installed, Snorre and Heidrun in the North Sea and Auger in the Gulf of Mexico. By end 1995 there were 57 floaters in operation.
Things really took off in the second half of the 1990s. In the five year period there were orders for almost three dozen FPSOs, including 14 harsh environment units for use in the North Sea and East of Shetlands. They included the sophisticated and expensive Asgard FPSO, capable of processing 200,000 b/d oil and 600 MMcf/d gas, and the Schiehallion FPSO, capable of processing 155,000 b/d oil and 140 MMcf/d gas. During this period a dozen production semis were installed, five of which were placed in the North Sea, five offshore Brazil. The North Sea units included the purpose-built Visund, with processing capacity for 113,000 b/d oil and 350 MMcf/d gas, and the Troll C, with capability to process 190,000 b/d oil and 320 MMcf/d gas. TLP installations grew significantly, with six new TLPs being installed in the Gulf of Mexico. They included Shell's large deck TLPs Mars, Ram Powell and Ursa and the mini-TLPs Morpeth and Allegheny. This period also saw the first spar installations, when Kerr McGee installed the Neptune spar in 1997, followed a year later by Chevron's Genesis spar. By the end of the decade, there were 112 floating production systems of all types in operation.
Growth has continued unabated during the first half of this decade. Almost 60 FPSOs have been installed, including 20 units off West Africa. Among these have been some huge purpose-built units for multi-billion dollar deepwater developments. They include ExxonMobil's Kizomba A and B, each having 250,000 b/d oil and 400 MMcf/d gas processing capability, Total's Girassol with processing capability of 200,000 b/d oil and 105 MMcf/d gas and Shell's recently installed Bonga with 225,000 b/d oil and 150 MMcf/d gas processing capacity. The past five years have seen seven production semis placed in service, including two large gas condensate production semis, Asgard B and Kristin for the North Sea, and the NaKika production semi in the Gulf of Mexico, which at 1920 meters holds the current water depth record for floating production systems. Nine TLPs have been installed since the beginning of the decade, including two wellhead units off West Africa and a unit in Southeast Asia. There also has been significant growth in use of production spars during the first half of the decade. Twelve units have been delivered since 2000, all for placement in the Gulf of Mexico. By end 2006, counting the units to be installed during this year, there will be 194 floating production systems of all types in operation.
30 Year Trend in Growth of Production Floaters
Advantages/disadvantages of various floating systems — FPSOs are the most common type of floating production system. They represent 61 percent of the production units now in operation and 70 percent of the production units on order. They are located in all major offshore areas, except the Gulf of Mexico. FPSOs have the advantage of providing field storage, which enables them to be utilized independent of pipeline infrastructure. They are also less weight sensitive than other types of floating production systems and the extensive deck area of a large tanker provides flexibility in process plant layout. Another advantage is the ability to utilize surplus or aging tanker hulls for conversion to an FSPO vessel, a solution which can be relatively inexpensive compared to building a new hull. The disadvantage is that the subsea tiebacks associated with FPSOs generally bring higher well maintenance costs.
Production semis comprise the second largest segment of floating production systems. They represent 21 percent of all production floaters in operation and 13 percent of the current floater order backlog. This type production system was a popular solution during the early years of floating production. A large number of surplus drill rig hulls were available that could be fitted with process plants and converted relatively cheaply into production units. But when the availability of surplus hulls dried up in the 1990s, the semi as a production facility became less attractive than FPSOs. However, their popularity has rebounded over the past several years as development has moved to ultra-deepwater, dispersed fields. Production semis have the advantage of being able to operate on complex deepwater fields involving a large number of wells over a dispersed area. Recent orders have included very expensive purpose-built units such as Thunder Horse, P51, Kristin and Atlantis. But a new range of significantly less expensive light deckload production semis capable of operating in ultra-deepwater are attracting considerable industry interest. There has also been a recent project, Gomez, where the operator converted an old drill semi hull to a small production semi.
TLPs are the third most common type of production system. The 18 TLPs now in operation represent 10 percent of all floating production units and the 3 TLPs on order account for 7 percent of the order backlog. All TLPs have been purpose-built for the field on which they operate. Full size TLPs had been a popular production option in the Gulf of Mexico and North Sea. But Shell's Brutus in the Gulf of Mexico marked the end of the full size TLP period. These types of production floaters are not suited for use on ultra-deepwater fields. Tendon weight grows exponentially with increasingly deeper water and the potential use of full size TLPs is generally considered to be no more than 1800 meters. Mini-TLPs however remain very popular in the Gulf of Mexico. Like full size TLPs, minis have the ability to support dry trees, which is a particularly desirable feature in the Gulf of Mexico. The disadvantage is they lack storage and though they can operate in deeper water than the full size unit, they still appear to have depth limitations. The deepest to date is the Moses TLP now on Marco Polo, which is in water depth of 1310 meters. Conceptually, there are designs for mini-TLPs to operate in water depth to 2700 meters, but no unit has yet been ordered for such an application. Wellhead TLPs work in conjunction with an FPSO or production barge. They are positioned directly over the well and enable the trees to be at the surface. Production facilities are on an accompanying FPSO, barge or platform. They range significantly in size, complexity and cost.
Spars are relative newcomers to floating production. Production spars have the ability to accommodate dry trees, a feature liked by operators in the Gulf of Mexico where well maintenance is a particularly important issue. Water depth does not seem to be a limitation. Spars have been utilized in water depth to 1710 meters (Devil's Tower) and theoretically can be employed in water depths to 3000 meters and beyond. A spar is currently earmarked for the Great White field, which at 2260 meters would be the deepest application yet for this type production system. The original classic spar design based on a full length cylinder has been superseded by the truss spar, comprised of an upper hard tank and lower truss structure. Hoover/Diana, the largest classic spar, supports a 26,500 ton payload. Holstein, the largest truss spar, is able to support almost the same payload on a hull that is half the weight of Hoover/Diana. Payload up to 40,000 tons can theoretically be provided on a spar, but only with substantial increase in hull diameter. Spars can provide storage but to date no spar has been used in this capacity. A smaller version known as a cell spar has been used as a production system on gas fields. The Red Hawk cell spar in the Gulf of Mexico has a bundled hull with an overall diameter of 19.5 meters and is able to support 4,700 tons topsides payload. A spar design was recently selected as a floating wellhead facility for offshore Malaysia. It will work with an accompanying FPSO. This is the first application of a spar as a wellhead facility and the first contract for a spar outside the Gulf of Mexico.
Outlook for floating production — Underlying market drivers for floating production are very strong. World energy demand is growing at a rate of 1.6 percent annually, driving the need to find and develop new oil and gas sources. Deepwater fields are one of the few remaining untapped sources for new production. The futures market is forecasting crude prices in the $60+/bbl area and natural gas in the $8-9/MMbtu range at the end of the decade, providing incentive for undertaking new capital expenditures. It's not surprising that most oil companies are planning to significantly increase capex budgets for E&P activity over the next several years. Further evidence of the strong underlying market is provided by drill rig demand. Rig utilization is extremely high, pushing 100 percent in some areas, and rig rates are going through the roof as field operators try to secure equipment for exploration and development drilling.
We believe this market has a long way to run before losing steam. In our recent study of the floating production market, we forecast orders for 103 to 130 production floaters over the next five years. This figure includes 75 to 95 additional units that will be purpose-built or converted from existing hulls and 28 to 35 redeployments of existing units. These orders are expected to generate capital expenditures of $35 to 44 billion over the five year period. In addition, orders for 25 to 35 floating storage units will generate another $1.5 billion in capital expenditures for conversion or construction.