FLOATING PRODUCTION, STOR-age, and offloading (FPSO) systems were born and have recently flourished in the North Sea area.
By 1997, FPSO technology was spreading worldwide as operators increasingly exploited deepwater finds.
Floaters were also finding favor where field development economics were marginal and where there was little existing export infrastructure. FPSOs also were increasingly the choice for first phase development of large finds.
John Wils, Aberdeen director of the U.K. Offshore Operators Association (Ukooa), believed FPSO technology was at the top of the industry`s agenda worldwide.
He told delegates at an Aberdeen conference in October 1997 that there were 70 floating production systems in use worldwide. The number was expected to increase to 250 by 2010.
The world`s first floater development was the U.K.`s Argyll field, developed by Hamilton Bros. in the mid-1970s with a converted semisubmersible platform.
Argyll field, no longer in production, had reserves of 100 million bbl of oil, so fixed platform development was not then viable. Wils said, "Low cost was the driver for Argyll development and is still fundamental to floating production systems today."
Wils said floaters were forecast to account for 28% of capital expenditure for offshore developments in 1997 and for 39% in 1998.
"This percentage will continue to increase as offshore production rises," said Wils. "At the moment offshore output is growing by 2%/year, and this rate is expected to continue."
Shipyards capable of FPSO projects can be found around the world, and operators have successfully brought down development and operating costs through innovative technology, contractual arrangements, and project financing.
Changing portfolios
Don Henery, deepwater development consultant, Shell International Exploration & Production BV, said the change in Shell`s undeveloped-reserves portfolio in the preceding 10 years gave an indication why FPSOs were proving popular.
In 1986, 75% of Shell`s undeveloped finds were in less than 150 m of water, 90% of discoveries were of less than 250 million bbl oil equivalent, and 30% were oil finds.
Then, said Henery, 50% of undeveloped fields were potential platform satellites, 40% could be developed with fixed platforms, and only 10% were suited to floaters. High costs of FPSOs and associated subsea developments were a major concern.
By 1994, 65% of Shell`s undeveloped portfolio was oil finds, and 40% of the total were in more than 200 m of water: "Very much an oily, deepwater portfolio, and typical of petroleum companies today."
Henery said one of the keys to the success of Shell`s deepwater program, where FPSOs play a major role, has been average initial well rates better than were ever imagined in the 1980s.
One current problem with FPSO developments is the lack of availability of drilling rigs and consequent high day rates.
"Now FPSO project economics will determine if this current situation continues," said Henery. "Contractors risk starting another boom/bust cycle if rig hire costs are not kept under control."
Meanwhile, long-reach drilling and subsea developments are direct competitors with FPSOs for deepwater projects, and tensioned compliant tower platforms are becoming increasingly viable for deepwater conditions.
"Also," said Henery, "smart wells and seabed processing could affect offshore facilities dramatically. Here there is still lots of work to be done, but they are not to be forgotten about."
While FPSOs are currently booming, said Henery, they are not an automatic choice: "It will increasingly be a case of mixing and matching technologies for field developments."
For gas developments, too, floaters were being considered: "The industry is looking to produce liquefied natural gas (LNG) or liquids from gas offshore. At the moment this may seem ambitious, but for LNG the technology is starting to look manageable."
Deepwater market
Deepwater discoveries around the world have combined estimated reserves of more than 40 billion bbl of oil. Operators in 1997 were developing ways to produce hydrocarbons in up to 2,000 m of water.
Tim Warren, director of research and technical services at Shell International Exploration & Production BV, divided the total into major deepwater plays: West Africa 18 billion bbl of oil; U.S. 10 billion bbl; Brazil 8 billion bbl; West of Shetlands 3.5 billion bbl; and Norway 2.4 billion bbl.
Yet this estimate is conservative, he said, because a number of deepwater areas were not included, while others were inaccessible but likely to open in the future.
Shell was involved in most of these areas, said Warren, and had formed a multidisciplinary deepwater division. "For Shell deep water offers the most significant conventional petroleum industry opportunity for expansion of the company."
John Westwood, director of Douglas-Westwood Associates, Canterbury, U.K., noted that the number of field developments in less than 50 m of water was declining, while the number beyond 200 m was rocketing.
Westwood said that identified future deepwater developments have reserves amounting to 65 billion bbl of oil. Deepwater projects were expected to make up 11% of expected developments.
"This is a small proportion of the total," said Westwood, "but a growing one that represents a large future market."
Westwood said 254 field developments were under consideration in more than 200 m of water, while spending on identified deepwater developments was expected to amount to more than $100 billion.
North America will account for 44% of deepwater developments, said Westwood, while Europe will have 28%, South America 11%, South East Asia and Australasia 11%, and West Africa 6%.
"The majority of future deepwater fields will use subsea wells," said Westwood. "In water depths to 200 m we are aware of plans for 421 wells, but beyond 200 m there are plans for 1,350."
Of 216 expected deepwater developments, Westwood said, development schemes had been announced for 139. Floating production systems were involved in 68% of these.
Jeffrey Davison, senior project engineer at Amerada Hess Ltd., said the company had produced more than 220 million bbl of oil from U.K. floater developments in the preceding 8 years, the most by any U.K. operator.
Amerada was said to have proved FPSOs for all aspects of field development, showing them to be operationally excellent and, in the right circumstances, the most commercially attractive solution.
"The facilities themselves have been improved since 1991," said Davison, "and over several developments so that changes are now in the realms of fine-tuning or incorporation of new technology.
"Integration of ship systems and North Sea production technology has been achieved to a point where best practices can be incorporated from each."
Davison said Amerada sees a place for a fleet of FPSO vessels that can be deployed and redeployed on a number of developments either as early production, full-field developments or as late- field-life replacements for more-expensive facilities.
"Once such a fleet becomes established, initial capital costs will become written down, allowing contractors or operators owning such vessels to make realistic returns on their investment and allowing the cost of draining marginal fields to come down significantly."
Norway`s plans
While the U.K. may have started the floater industry, Norway has been key to adapting the technology to deeper water and in 1997 was planning a large number of FPSO development.
In the period 1997-2001, new field developments offshore Norway will be dominated by subsea developments and floating production systems, according to Wood Mackenzie Consultants Ltd., Edinburgh.
The analyst identified 25 fields approved and under development or expected to gain development approval in the short to medium term.
Total capital expenditure on the 25 fields was expected to amount to 160 billion kroner ($24 billion). Most were in the Norwegian North Sea, but mid-Norway was expected to emerge as a major producing region.
In 1996 Norwegian operators began production in five offshore fields, reported Wood Mackenzie: Troll East, Sleipner West, Loke Triassic, Gungne, and Yme. Visund and Norne were brought on stream in 1997 with floaters.
A total of eight field and three pipeline developments were approved by Norway`s Ministry of Industry & Energy in 1997, said the analyst. Four further field developments-Yme Gamma SE, Oseberg South, Jotun, and Troll C-received approval in 1997.
"Several developments have, however, encountered delays and cost overruns," said Wood Mackenzie. "The Balder development, planned for start-up in first-quarter 1997, encountered considerable delays which were expected to lead to start-up being put back to second-quarter 1998."
Norne was delayed by several months. Both developments involve FPSOs, "which have also proved problematic on several developments in the U.K. sector such as Foinaven, Captain, and Durward/Dauntless."
Wood Mackenzie reckoned 12 of the fields identified were probable developments, likely to be brought on stream in 1997-2001. Among these, seven were new to the analyst`s listings: Kvitebjoern, Tyrihans, Tordis H Central, Statfjord NE, Tordis H NW, Peik, and the Southern Triangle structure (Table 1).
"In the northern North Sea," said Wood Mackenzie, "increased reserves and lower costs have made Grane, formerly known as Hermod, and Fram potentially more attractive oil developments.
"Huldra was, surprisingly, expected to receive a gas allocation in autumn 1997, and development via Oseberg D platform now seems likely. The Kvitebjoern and Tyrihans gas/condensate developments are largely dependent on them receiving gas sales allocations.
"Peik is thought likely to be developed via a U.K. platform, aided by the recently concluded framework agreement for gas exports to the U.K. A number of small satellite oil developments are also expected to be tied in to the Tordis and Statfjord areas."
New production
Meanwhile, U.K. brought on stream a number of fields in fast-track developments, while Norway completed two FPSO projects.
Shell adopted the FPSO concept for a number of U.K. Central North Sea field developments, which started with Block 21/25 Guillemot, Teal, and South Teal.
For this project Shell built the Anasuria ship, which has capacity to produce 55,000 b/d of oil and 30 MMcfd of gas, and to store 850,000 bbl of oil. First production through Anasuria was in October 1996.
In March 1997 Texaco North Sea U.K. Ltd. began oil production from U.K. North Sea Captain field, following a ú500 million ($800 million) development.
Block 13/22a Captain was developed with a wellhead protector platform and oil production and storage ship, with export by shuttle tanker.
The crude oil was delivered directly to customers or to Nigg Bay terminal in Scotland`s Cromarty Firth, following an agreement with terminal operator BP. Talisman Energy U.K. Ltd. took over BP`s interest and operatorship.
Shah Etebar, Texaco`s Captain development manager, explained that the Nigg storage facility will "give us the flexibility to deliver crude cargoes which are either larger or smaller than the shuttle tanker`s capacity, as well as enabling us to deliver to customers outside the tanker`s range."
Texaco aimed to brings Captain to peak production of 63,000 b/d of oil in mid-1997. Captain lies in 340 ft of water and has estimated reserves of 350 million bbl of 19-21° gravity oil and 53 bcf of gas.
The platform has 28 well slots and was expected to house wellhead equipment for 16 production wells, five water injectors, and one aquifer water supply well.
The wells have horizontal sections of 4,600-6,000 ft, and each producer is fitted with a 456 hp electrical submersible pump with capacity to lift 20,000 b/d of oil.
The platform comprises a 4,500 metric ton jacket and 6,200 ton topsides and carries a drilling rig and living quarters unit for up to 70 crew. It was built by UIE Scotland Ltd., Clydebank.
The production ship was built to the Tentech 700 design at Spain`s El Ferrol yard by Astilleros. It has capacity to store 550,000 bbl of oil and can house a crew of up to 50. The ship is permanently moored 1.5 km from the platform and is visited every 9 days or so by a shuttle tanker for offloading.
Texaco intended to install either another wellhead platform or a subsea manifold in the field. This will also be linked back to the ship and is likely to hold facilities for 10 production wells and three water injectors.
Texaco was operator and 100% owner of the field in 1997, but Korea Captain Co. Ltd., a joint venture of Korea Petroleum Development Corp. and Hanwha Energy, had the right to acquire a 15% interest.
On Aug. 9, 1997, Amerada Hess began production from Block 21/11 Dauntless field, and 2 days later started up Block 21/16 Durward, developed jointly with a production, storage, and offloading ship.
Durward and Dauntless, 7 km apart, were developed with subsea production units tied back to the production ship, which is moored between the two fields.
Durward was started up with two production wells and a water injector. The need for additional wells will be determined as production progresses. Dauntless was developed with one production well and a water injector.
Combined initial production was 25,000 b/d. Estimated reserves for Durward and Dauntless fields are 30 million and 13 million bbl of oil respectively.
The Glas Dowr production ship is owned and operated by Bluewater Offshore Production Systems Ltd., Essen, Belgium. The ship is a newbuild tanker converted for production duty.
Glas Dowr has capacity to handle 75,000 b/d of liquids and to produce up to 60,000 b/d of oil. It can store 657,000 bbl of crude oil and discharge to a shuttle tanker at up to 25,000 bbl/hr.
The ship also has capacity to handle up to 65,000 b/d of produced water and to produce up to 24.5 MMcfd of associated gas. Produced gas fuels onboard generators, with excess being flared. Gas lift facilities may be installed later.
Durward/Dauntless field partners are operator Amerada 28%, Saga Petroleum (U.K.) Ltd. 23.5%, DSM Energy (U.K.) Ltd. 20%, British-Borneo Petroleum Syndicate plc 18.5%, and Seafield Resources plc 10%.
On Aug. 10, 1997, Conoco (U.K.) Ltd. began oil production from MacCulloch field on Block 15/24b, using an FPSO.
MacCulloch field has estimated reserves of 58 million bbl of oil. Production is expected to peak at 60,000 b/d of oil and 12 MMcfd of associated gas.
Oil from MacCulloch is metered on the ship and transported by pipeline to Piper B platform, 30 km to the northwest, operated by Elf Exploration U.K. plc. Associated gas also is exported to Piper B by pipeline.
The field`s production ship, North Sea Producer, is a converted products tanker, formerly named Dagmar Maersk. It has capacity to store 560,000 bbl of oil in the event of the export pipeline being unavailable.
The ship is owned and operated by North Sea Production Co., a joint venture of Odebrecht-SLP Engineering Ltd., Lowestoft, U.K., and Maersk Oil & Gas AS.
MacCulloch was producing through three wells tied back to the ship by flexible flowlines and risers. Further production wells were to be drilled.
MacCulloch field interest holders are operator Conoco 60% and Lasmo North Sea plc 40%. The ship is leased to Conoco under a per barrel tariff arrangement.
Shell`s second U.K. North Sea FPSO development was Block 29/7 Curlew field, which was put on fast-track development under a $450 million program.
Curlew was to begin production late in 1997, with peak output anticipated to be 45,000 b/d of oil and 100 MMcfd of gas.
The FPSO is a converted tanker leased from Maersk Co. Ltd., London. It has capacity to store 560,000 bbl of crude oil. Curlew reserves are estimated at 71 million bbl of oil and condensate and 244 bcf of gas.
Norsk Hydro AS announced on Oct. 1, 1997, the start of oil production from Njord oil field on Blocks 6407/7 and 6407/10 in the Norwegian Sea.
Njord was developed with a production semisubmersible and storage tanker. Hydro said development cost was 5.4 billion kroner ($740 million). Early output was through a predrilled production well and a gas injector. Thirteen further wells were to be drilled from the platform.
Plateau production of 70,000 b/d of oil was anticipated in spring 1998. Estimated reserves are 200 million bbl of oil and 210-350 bcf of gas. Gas initially was to be reinjected.
Early in 1997 Statoil moored its Norne field production, storage, and offloading ship in the field to prepared it for scheduled first oil production in September 1997.
Block 6608/10 Norne field was developed under a $1.3 billion program. Shortly after the discovery was made in March 1993, Statoil said Norne was its largest find in 8 years, with estimated reserves of 440 million bbl of oil.
The Norne production ship is one of the world`s largest, with capacity to store 720,000 bbl of oil and offload into shuttle tankers at rates of up to 50,000 bbl/hr.
The field, in 380 m of water, is expected to yield up to 170,000 b/d of oil. Statoil expected Norne to reach plateau production during the first half of 1998.
Four of the planned 17 development wells were expected to be completed ahead of first oil.
The first of these wells was completed for gas injection. Drilling operations ran into some technical problems, and first oil was not achieved until November.
A further delay was caused by a helicopter crash in the field in early September, when the crew and 10 offshore workers were killed as the aircraft attempted to land on the ship.
Initial production in Norne was 22,000 b/d from one well, which was to be followed by the second of the four predrilled producers in early December. Each of these four wells was reckoned to have potential to produce 36,000 b/d of oil.
Statoil said 10 wells would be brought into production to raise Norne output to a peak of about 220,000 b/d in the summer of 1998.
West of Shetland
U.K. companies worked to develop the area west of the Shetland Islands, where BP Exploration Operating Co. Ltd. in particular had made a number of large finds.
London-based Greenpeace attempted to prevent further exploration and development work west of Shetland on the grounds that the world cannot burn more oil without increasing global warming.
While Greenpeace`s efforts disrupted work but ultimately failed to halt projects, BP suffered a number of engineering problems which delayed first production from Foinaven field.
In May 1997 this first field development west of Shetland was revealed to be facing further delays because of failure of installed subsea equipment during pressure testing.
BP initially intended to produce first oil from Block 204/24a Foinaven field in late 1995, but once more had to revise its schedule. It had to retrieve a subsea manifold and five christmas trees from the seabed.
The operator said valve seals had been damaged and would leak oil if used. The problem was spotted when BP carried out high pressure testing of subsea equipment using water and dyes.
Four out of 48 valve stems on one of two subsea manifolds leaked, plus three trees from one drilling center and two from the other.
A BP official said high differential pressure between the outside and inside of the equipment affects how the valve seals seat. Leakage suggested the seals had been damaged.
Equipment was retrieved from the Iolair construction semisubmersible, which installed it. BP did not say when it expected repair work to be completed.
This was not the first setback in Foinaven. In 1996 BP had to retrieve the first subsea manifold it installed after cracks appeared on hubs during leak testing.
But all was not bad news for BP west of Shetland. Clair oil discovery on Block 206/8 made long-awaited progress towards development.
Clair was the first discovery in the West of Shetland area, made by BP in 1977.
The find lies in 460 ft of water. While it has estimated oil in place of more than 4 billion bbl, making it U.K.`s largest undeveloped offshore accumulation, reserves are pegged at only 100-300 million bbl.
The reason for Clair`s lack of progress is complexity of the reservoir. Until 1996, all wells had flowed much below commercial levels on test.
But BP hit upon the idea of using faults in the reservoir as conduits to boost flow in wells. In late summer 1996 BP concluded a well test which yielded more than 15,000 b/d, enough to suggest development was viable.
BP gathered a project team in Aberdeen to deliver a development concept for Clair by the end of 1997, according to license partner Chevron U.K. Ltd.
Chevron said Clair was being moved onto the "fast track," with the intention of achieving U.K. Department of Trade & Industry approval by mid-1998 for first phase development.
A feasibility study showed conversion of a tanker into a production, storage, and offloading ship to be the most economic development plan for Clair.
Early oil exports would be by shuttle tanker, as with BP`s Foinaven and Schiehallion developments in deeper water nearby. One longer term prospect was construction of an oil export pipeline, with oil from several fields in the area being sent to a gathering and export platform located in Clair.
Meanwhile, three operators were evaluating systems for collection, transportation, and sale of natural gas from potential field developments west of the Shetlands. The study, called Aurora project, was funded by Conoco, Texaco, and Total Oil Marine plc.
The partners, which have exploration interests in the west of Shetland play, were to examine options for subsea pipelines, gas landfall sites, and delivery of gas to customers. Texaco has a gas discovery in the area, Victory, with estimated reserves of 300 bcf.
U.K. projects
Perhaps the most surprising FPSO development in the North Sea was the U.K.`s Banff field, expected on stream in June 1998 and operated by Conoco.
The FPSO concept chosen for Banff is unique: the hull is a delta-shaped structure adapted by PGS Exploration AS, Oslo, for a fleet of seismic survey ships.
The Ramform design was chosen for Banff because it offered greater stability than conventional hull designs. It was expected to provide greater vessel uptime in the North Sea`s severe weather conditions.
Banff lies in 100 m of water on U.K. Blocks 29/2a and 22/27a and has estimated reserves of 60 million bbl of oil and 40 bcf of associated gas.
The FPSO, expected to cost $200 million to build, will have capacity to produce 60,000 b/d of oil and 45 MMcfd of gas while storing up to 120,000 bbl of oil.
Conoco will moor a 500,000 bbl capacity storage near the FPSO to handle extra storage requirements. The Ramform FPSO hull is only 380 ft long, compared with 700 ft for a conventional FPSO ship.
In June 1997 Talisman secured U.K. Department of Trade & Industry approval to develop the Ross discovery on Blocks 13/28a and 13/29a in the U.K. North Sea.
Ross has estimated reserves of 66 million bbl of oil and 20 bcf of gas. Talisman became operator of Ross in 1996 by acquiring the interests of BP in the two blocks.
The find will be developed with a production, storage, and offloading ship. Oil will be exported by shuttle tanker, while gas will be exported by a pipeline tied in to the Frigg trunkline.
First production was expected in third quarter 1998. Ten development wells were planned, with combined oil production expected to start at around 40,000 b/d.
Talisman chartered a production ship from Bluewater, which is having the hull for the ship built in Japan. A 6,000 metric ton topsides is to be built and installed by UIE Scotland under a $75 million contract. The 240 m long, 100,000 metric ton ship, named Bleo Holm, arrived at the yard in August 1997.
The ship will have capacity to produce 40,000 b/d of crude oil and 80 MMcfd of associated gas, 20 MMcfd of which will be reinjected and 60 MMcfd of which will be exported.
Bleo Holm will have capacity to store 650,000 bbl of crude oil for delivery to shuttle tankers at rates of up to 31,500 bbl/hr. The ship will also be able to inject up to 60,000 b/d of water.
Enterprise Oil plc, London, was granted approval by U.K. Department of Trade & Industry in August 1997 to develop the Pierce discovery on U.K. North Sea Block 23/27.
The operator leased a production ship and shuttle tankers from Norway`s Statoil to develop the field, with first oil slated for August 1998.
The field has estimated reserves of 84 million bbl of oil and 202 bcf of gas. Initial production was expected to be 20,000 b/d of oil, rising to 45,000 b/d at plateau. Gas will largely be reinjected.
Development is expected to cost a total of £150 million ($240 million). Enterprise let a £25 million ($40 million) contract to Rockwater Ltd., Aberdeen, to design, build, and install subsea facilities in Pierce.
The field will be developed with six production wells and three gas injectors. Subsea development work is slated for completion in July 1998.
Texaco planned to deploy a production semisubmersible unit, formerly used to deplete U.K. North Sea Emerald field, in its development of Galley field on U.K. Block 15/23a.
For Texaco`s Galley development the Emerald Producer semi will be upgraded and have its name changed to Northern Producer. Field development cost was estimated at £140 million ($224 million).
Texaco will lease the vessel from shipping firm Seatankers, which in turn is to award a 10 year management contract to Atlantic Power & Gas Ltd., Aberdeen, to operate the unit during production.
Two development wells were to be drilled ahead of first production from Galley, anticipated in first quarter 1998. These were expected to yield a combined 35,000 b/d of oil and 50 MMcfd of gas at peak. A third production well was planned.
From the subsea wellheads, oil and gas will arrive on the Northern Producer for processing. Oil and gas will be exported in separate pipelines to Texaco`s Tartan on nearby Block 15/16a.
Galley`s oil will join the output from Tartan in a pipeline to Flotta terminal in the Orkney Islands, while gas will be added to Tartan`s flow to St. Fergus terminal, north of Aberdeen.
Galley reserves are estimated at 28 million bbl of oil and 40 bcf of gas. Early production will be from the field`s northern and southern accumulations. Texaco planned to deplete eastern and western accumulations in a second phase of development.
Amerada Hess, Shell, and Texaco planned a joint development of the Bittern and Guillemot West finds with a shared FPSO.
Bittern straddles Blocks 29/1a and 29/1b, operated by Shell and Amerada respectively. The find was known informally as Razorbill and Abbot respectively by the two firms before joint development was agreed.
Guillemot West reaches into five blocks: Texaco`s Blocks 21/24 and 21/29a and Shell`s 21/29b, 21/25, and 21/30.
Field unitization had not been agreed late in 1997. Interest owners in Bittern and Guillemot West blocks are Amerada, Shell, Esso Exploration & Production U.K. Ltd., Enterprise, Deminex U.K. Oil & Gas Ltd., Hardy Exploration & Production Ltd., Texaco, and Talisman.
Oil from Bittern and Guillemot West was intended to be exported by shuttle tankers. Gas from the fields will be exported through a pipeline link to the Fulmar trunkline to shore.
The operators said a team approach will be adopted for the development. The FPSO will be managed by a joint team, with Amerada as duty holder; Bittern subsea development will be led by Shell; and Texaco will lead the subsea development team for Guillemot West.
Norwegian projects
In March 1997 Esso Norge AS issued letters of intent for an FPSO and wellhead platform for development of Jotun discovery in Blocks 25/8 and 25/7 in the Norwegian North Sea.
Esso`s Jotun field lies in 126 m of water and comprises three separate discoveries: Elli, Tau West, and Elli South. These have estimated combined reserves of 200 million bbl of oil.
Both Jotun contracts were for engineering, procurement, construction, installation, and commissioning.
The FPSO contract went to Kvaerner AS, Oslo, which will build the ship`s hull at Kvaerner Masa yard in Finland and the topsides at its Rosenberg yard in Stavanger.
The FPSO contract is valued at 2 billion kroner ($310 million). Kvaerner immediately began early engineering and preparatory work ahead of approval of the development plan.
The ship was expected to be installed in Jotun field in spring 1999, with production start-up later that year.
The FPSO will have capacity to produce 90,000 b/d of oil and to store almost 600,000 bbl of oil. The 250 m long ship will be connected to the wellhead platform by eight flowline/umbilical risers.
The 1.5 billion kroner ($230 million) wellhead platform contract was awarded to Heerema Toensberg AS, Toensberg, Norway. The platform will be a four-legged steel structure with 24 well slots.
Topsides engineering will be carried out by ABB Offshore Technology AS, Billingstad, Norway, while topsides fabrication will be at Heerema`s Toensberg yard.
The Jotun jacket will be built by Aker at its Verdal yard, while drilling facilities will be provided by Bentec Norge AS, Stavanger.
Jotun oil will be exported by shuttle tankers. The ship`s turret and mooring system will be supplied by Bluewater and installed by Kvaerner Rosenberg.
In September 1997 Saga Petroleum AS announced a plan to develop the northern part of Snorre field, on Norwegian North Sea Block 34/4, with a production semisubmersible, subsea development, and export pipelines.
Snorre`s southern sector was brought on stream in 1992 with a TLP and subsea production unit. These export oil and gas by pipeline to Statfjord platform, operated by Statoil.
Saga said the semi will be located about 9 km north of the TLP and be used to recover about 360 million bbl of oil and some gas. Snorre 2 platform start-up was slated for summer 2000.
The new platform will have capacity to produce up to 110,000 b/d of oil. This will be processed on the semi and transported by pipeline to Statfjord B platform for storage and shipment by shuttle tanker. Produced gas will be reinjected to improve recovery of oil.
The final decision on the development plan, and submission of the plan to Norway`s Ministry of Petroleum & Energy, were expected around the end of 1997. Saga hoped the plan would be approved by Storting in spring 1998.
The operator intended to invite bids for construction of the production semi and to award the contract at the beginning of 1998. Snorre 2 development was expected to cost 10-11 billion kroner ($1.4-1.5 billion).
New technology
While North Sea operators were developing fields with a number of variants on the FPSO theme, they continued research and development work.
Norway`s Statoil expected to be involved in deepwater developments at home and abroad and had a research team looking for field developments schemes suitable for water depths of up to 1,500 m.
Though all Statoil`s deepwater solutions were based on floating production systems, the actual production technology is determined mostly by weather conditions in a particular field.
Maximum wave heights off West Africa, for example, are only 7-8 m, so ships or barges moored fore and aft could be used. Weathervaning would not be needed in these conditions.
Alternatively, developments there could involve small unmanned TLPs carrying topsides wellheads, with processing equipment on a nearby barge.
In the harsher sea conditions of Northern Europe wave heights can exceed 30 m. Weathervaning is essential so turret-moored ships are a key technology.
George Murray, adviser in Statoil`s development technology department, said: "Technology used for our Norne development provides an excellent base for further progress.
"The big difference between the Norne production ship in 380 m of water and developments in depths down to 2,500 m lies in the riser system. We believe hybrid risers could be the answer for waters down to 1,000 m."
A hybrid riser would comprise steel risers from a seabed manifold to a buoyancy can positioned about 200 m below the production ship, from which flexible risers connect to the vessel.
For deeper waters, Statoil was looking into alternative riser systems. It also intended to try anchoring a barge in 1,300 m of water with fiber rope and suction pile anchors.
Brown & Root Ltd., London, developed a novel FPSO concept known as Barbox 80, which it was marketing to operators for deepwater projects.
Development of the design was assisted by the Offshore Supplies Office (OSO) of the U.K.`s Department of Trade & Industry, which said Barbox was being promoted for developments offshore West Africa and the Far East, in the Gulf of Mexico, and offshore U.K.
The Barbox FPSO is based on a square hull of exceptional structural simplicityùin crude terms it is a tethered floating box with production topsides stuck on top.
OSO said the small surface-to-volume ratio minimizes steel weight, and the simple hull form suffers a minimal amount of global wave bending when compared with standard tanker hull forms in conventional FPSOs.
The Barbox hull was said to have been designed to comprise stiffened flat panels, which can be easily fabricated and assembled by shipyards: "The impact of a shipyard`s automated panel production line on the fabrication costs is often dramatic, and the design makes full use of this potential".
Economics of Barbox were said to be improved further by avoidance of a complex turret mooring system and expensive multi-path fluid swivels which provide flow paths from the subsea wells to the process plant on the vessel.
Barbox 80 is 65.2 m long and 65.2 m wide, with a depth of 39 m and a draft of 24 m. Crude oil cargo capacity is 80,000 cu m. The hull would be spread-moored with 16 catenary mooring lines and conventional marine mooring equipment, said OSO.
FPSO warnings
While operators saw floaters as the answer to a number of operational problems, some pundits began warning of potential issues.
Ukooa`s Wils said there had been growing concern about FPSOs from one quarter: "In spite of their excellent environmental track record, FPSOs have attracted fierce criticism from environmental groups, which see them as a cheap alternative to platforms and pipelines.
"As an industry we have failed to explain to the public why floaters are sometimes preferred to fixed platforms. We have a duty to explain the FPSO operations won`t pollute significantly or increase tanker traffic noticeably, and that they are simpler to decommission than fixed platforms."
Henery of Shell, meanwhile, warned that oil companies planning to develop offshore fields using FPSOs should not skimp on preproduction work.
Henery said that with the comparatively short lead times of FPSO developments, operators sometimes viewed field development as a race. Several had their fingers burnt when they began to produce from the field.
"Operators need to be putting more into the planning and development phase of FPSO projects," said Henery, "in order to improve performance, costs, and safety later on. It`s not a race to get production first, but to get the best returns and performance. There is a danger with FPSO developments of pressing the go-ahead button too early."
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The most unconventional FPSO concept destined for use in the North Sea in 1997 was the Ramform delta-shaped vessel being built by Conoco for Banff field. The ship was to have capacity to produce 60,000 b/d of oil and 45 MMcfd of gas. The hull is only 380 ft long compared with 700 ft for a conventional FPSO ship, which limits storage capacity to 120,000 bbl of oil. Conoco will moor a 500,000 bbl capacity storage vessel near the FPSO to handle extra storage requirements.
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Conoco`s U.K. Block 15/24b MacCulloch field was developed with North Sea Producer, a converted products tanker. Production was expected to peak at 60,000 b/d of oil and 12 MMcfd of associated gas. Oil and gas from MacCulloch move by pipeline to Piper B platform, 30 km to the northwest. The production ship has capacity to store 560,000 bbl of oil in the event of the export pipeline being unavailable.
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Shell`s second U.K. North Sea FPSO development was Block 29/7 Curlew field. The FPSO is a converted tanker leased from Maersk Co. Ltd., London. It has capacity to store 560,000 bbl of crude oil.
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In August 1997 Amerada Hess began production from Block 21/11 Dauntless field, and 2 days later started up Block 21/16 Durward, developed jointly with Glas Dowr FPSO. The ship is owned and operated by Bluewater, and has capacity to handle 75,000 b/d of liquids and to produce up to 60,000 b/d of oil. It can store 657,000 bbl of crude oil and discharge to a shuttle tanker at up to 25,000 bbl/hr.
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The Anasuria FPSO was the first of a string of floaters expected to be deployed by Shell in U.K. Central North Sea fields. In October 1996 it produced first oil and gas from Block 21/25 Guillemot, Teal, and South Teal fields. It was one of the world`s largest FPSO`s, with capacity to produce 55,000 b/d of oil and 30 MMcfd of gas, and to store 850,000 bbl of oil.
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Texaco chose a wellhead platform and FPSO development for the U.K.`s Captain field. Captain lies in 340 ft of water. The platform has 28 well slots and is expected to house wellhead equipment for 16 production wells, five water injectors, and one aquifer water supply well. The ship has capacity to store 550,000 bbl of oil.
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Uisge Gorm was one of a fleet of leased FPSOs used by Amerada Hess in the U.K. North Sea. Amerada envisaged "a fleet of FPSO vessels that can be deployed and redeployed on a number of developments either as early production, full field developments or as late field life replacements for more-expensive facilities".
