David Knott
Senior Editor
Floating production system (FPS) technology has come of age in the North Sea.
That's apparent in plans to use FPSs to tap two of Northwest Europe's largest offshore oil discoveries in the last 10 years. First North Sea oil production with a floater involved a converted semisubmersible drilling rig. Floaters have been in use for small field development projects ever since.
Now, industry's rising interest in FPSs reflects two trends:
- As the North Sea matures, discoveries are likely to be in deeper, more remote locations.
- Operators increasingly are under pressure to slash costs.
Mike Pink, director of production and development for Shell Internationale Petroleum Mij. BV, said that with about 50 FPSs in use around the world, technical and commercial confidence in them seems assured.
"Floating production systems, which in many ways are independent of water depth, are now proving to be increasingly reliable in shallower waters," Pink said.
"They are generally less capital intensive and have shorter lead times than other options, and they are more flexible. They enable phased development. Their potential for deepwater developments is considerable, especially for small to moderate oil and gas accumulations."
Rex Gaisford, director of development for Amerada Hess Ltd., stressed the economic benefits of floaters during a conference at London's Institute of Marine Engineers.
"For the last 25 years in the North Sea we have built and then believed in and defended a high cost culture," he said.
"We believed we were inevitably a high cost oil province. Nothing could have been further from the truth. We can now start to believe in and build a low cost structure for the second half of the North Sea story. It has already started to happen."
U.K. TREND
Central to recent debate among North Sea operators has been the Cost Reduction Initiative for the New Era (Crine).
This is a drive by U.K. offshore operators to cut development costs by 30% and operating costs by as much as 50% (OGJ, Dec. 20, 1993, p. 31).
Gaisford cited Amerada's Hudson field development, which benefitted from early Crine thinking and so was a low cost project from the start.
"Since its inception we have reduced its development cost by a further 20%," Gaisford said. "Hudson field will be a survivor in the future climate of low prices."
Wood Mackenzie Consultants Ltd., Edinburgh, called the increasing use of floaters the most significant trend in today's U.K. North Sea developments.
The analyst identifies 62 U.K. fields that could be developed in the short to medium term. Nine U.K. fields are expected to be developed using floaters, along with four off Norway (see table).
The producing Donan field was the only other field lined up for development by floater when the Angus field development plan was approved in 1990. Of the nine current U.K. floater prospects, six are expected to use ships.
The increase in popularity of floaters can be traced to Angus field, now abandoned, Angus was developed using the Petrojarl 1 production ship, starting production very late in 1991. The field produced about 11 million bbl of oil through 1992 and half of 1993.
Wood Mackenzie said, "Although the value of the project can only be measured in tens of millions of pounds, the internal rate of return achieved was over 200%, and payback was achieved rapidly."
Last year, Kerr McGee Oil (U.K.) plc placed the U.K.'s first purpose built, permanently moored production vessel on production. Use of a floater enabled oil to be produced 2 years ahead of Kerr McGee's original platform plan.
Kerr McGee's 265 million Gryphon field development was brought on stream last October, only 10 months after development was approved by the Department of Trade & Industry (OGJ, Nov. 1, 1993, p. 23).
NORWAY'S NEEDS
Den norske stats oljeselskap AS developed Veslefrikk field in Norwegian North Sea Block 30/3a using Norway's first permanently moored floater. It started production in 1989.
Although Veslefrikk remains Norway's only permanent FPS, Petrojarl 1 was used by Esso Norge AS for extended production testing of the Balder reservoir and by Norsk Hydro AS for trials in West Troll oil field.
Just as Norway followed U.K. into the oil industry and created platform designs that were unique, it appears Norway will adopt floaters and give them a creative twist.
Statoil has committed to develop Norne oil field using Norway's first permanently moored production ship. Statoil engineers have also designed a flexible production ship that can double as a shuttle tanker (see story, p. 26).
Arild Nystad, resource management director for the Norwegian Petroleum Directorate, said one of Norway's big priorities is to develop technical solutions for profitable depletion of small fields.
For this Norway would be looking to the U.K. for models, Nystad said, and in particular the Crine initiative and floaters.
Nystad reckons Norway has 10 billion metric tons of oil equivalent (TOE) in potential reserves. Reserves in 105 planned developments and discoveries amount to 1.85 billion metric TOE.
This gives an average field size for potential developments of less than 20 million TOE, compared with an average 100 million metric TOE for reserves in fields under development.
"Our big challenge is to use our infrastructure to harvest further discoveries," Nystad said. About 75% of future production is expected to come from fields within 50 km of current installations.
Away from existing infrastructure, Nystad said, floaters are the likely production method for many smaller fields, with production vessels moving from one field to another like Petrojarl 1.
NORNE FIELD
When discovery of Norne field was announced by Statoil in March 1993, the company said the 440 million bbl field was its largest strike in 8 years. Norne was later chosen as a pilot scheme for rapid development (OGJ, Oct. 25, 1993, p. 99).
Norne, on Block 6608/10 where water depth is 380 m, is Norway's northernmost field under development. Statoil opted for a production vessel connected to subsea wells by flexible risers.
"The concept choice was obvious in the circumstances," said John Adlam, Norne project director. "There is no infrastructure nearby, while the Norwegian Sea is an environmentally sensitive area."
Statoil decided to use a 260 m long by 41 m wide vessel with onboard oil storage to develop the field. This is claimed to be the world's largest production ship. The vessel's storage capacity will be 720,000 bbl of oil, while its offloading rate will be a maximum 50,000 bbl/hr to a shuttle tanker.
"The process module is key to the success of Norne," Adlam said. "We want to have the ship built using normal shipbuilding techniques and the process module to be built according to onshore practices."
Adlam pointed out that onshore process modules are typically cheaper than offshore process equipment.
"For years contractors have been telling us that, if they are given only a basic specification, process modules can be built more cheaply," he said. "Now is their chance to prove it, We are expecting a 15 20% cost reduction, and we have given the contractor functional specifications rather than detailed designs."
NORNE CONTRACTS
In early April, Statoil let a 100 million kroner ($14 million) contract to Kvaerner AS, Oslo, for preengineering of the process plant for the Norne production ship. Plant capacity will be 160,000 b/d of oil and 210 MMcfd of gas, with a water injection module of 250,000 b/d capacity.
"Main engineering work on the process module will be carried out by suppliers," said Adlam, "cutting the need for the work to be done by Kvaerner. Using the normal approach, detailed engineering would have been done twice."
Also in April, Statoil let an 860 million kroner ($120 million) contract to Kongsberg AS, Kongsberg, Norway, for design and fabrication of subsea installations for Norne field.
The subsea equipment will consist of five templates with slots for 20 wells: 11 oil producers, seven water injectors, and two gas injectors.
"Development win involve reinjection of gas plus water injection," Adlam said, "although we could change over to water drive only, if Norne gas is sold, and still get the same results."
Twelve risers will be used, but as many as 24 can be accommodated, allowing for tie in of future discoveries.
Statoil hopes to receive approval of the Norne development plan from Oslo by December. This will allow first oil to be produced by the end of 1997, a period of only 3 years from approval to production.
Adlam said development of Norne using a platform would have cost about $1.6 billion. By using a floater and cutting out duplication of work, Statoil aims to develop the field for about $1.3 billion.
"We are at the limit for monohull production with Norne," Adlam said. "Any higher production capacity would require more storage. For fields of Norne's size and smaller fields in deep water, the monohull is the most attractive solution."
WEST OF SHETLAND
BP last March disclosed discovery of a 250 500 million bbl oil field in 480 m of water on Block 204/24a, west of the Shetland Islands. This was later named Foinaven and declared to be BP's largest U.K. discovery in 5 years.
Almost a year later BP announced another 250 500 million bbl oil strike in nearby Block 204/20, where water depth is 375 m. This field was named Schiehallion.
BP last March asked for tenders from three contractors for engineering studies leading to fast track development of Foinaven field using a floater.
BP chose Brown & Root Ltd. of London, Single Buoy Moorings Inc. of Marly, Switzerland, and FMC Corp. (U.K.) Ltd. of Dunfermline to bid and expects to award a contract to one of the companies next month.
Although BP has not disclosed details of briefings to the contractors, plans are believed to be concentrating on use of a semisubmersible FPS with a storage tanker moored alongside and offloading into a shuttle tanker.
BP also has approached a number of engineering contractors for ideas on a wider development of the area west of the Shetlands. This will involve Schiehallion field and Block 206/8 Clair field, discovered in 1972.
Wood Mackenzie says development of Clair field has been delayed by a hostile environment, the field's heavy oil, and low reservoir permeability.
The analyst expects BP to run a pilot production test on Clair in the mid-1990s, after which full production is thought likely using a converted semisubmersible rig or floating production vessel and offshore tanker loading.
SHELL ESSO PLANS
Shell U.K. Exploration & Production plans to use a floater to develop a group of small to medium Central North Sea fields. This will be the first use of a floating production, storage, and offtake (FPSO) unit by the Shell U.K. Ltd. Esso Exploration & Production U.K. Ltd. combine.
In February Shell Expro let a 12 million ($18 million) contract to Single Buoy Moorings for detailed design of an FPSO unit. The contract can be extended to include construction, procurement and installation, valued at 230 million ($345 million).
The FPSO will be a 140,000 dwt monohull vessel with 55,000 b/d of oil processing capacity. Design is expected to be completed late this month or early in July.
Expro plans to use the FPSO to develop a group of Central North Sea fields with combined reserves estimated at 230 million bbl of oil. An exact schedule of development for the fields has not been decided.
Initial development will involve Block 21/25 Teal field and one other from possible choices of Block 21/25 South Teal field, Block 21/29 Mallard field, and Block 21/24 Guillemot complex fields. The first dual development is expected to cost 500 million ($750 million).
A year ago the company said changes to U.K. oil industry taxation had brought forward a number of developments previously thought marginal. First oil from Teal and most likely Mallard is now slated for 1995, having been previously penciled in for 1997 by Wood Mackenzie (OGJ, May 10, 1993, p. 27).
"The decision to pursue FPSO technology follows an extensive review of alternative strategies for producing reserves in Central North Sea fields," said Brian Ward, Shell Expro production director.
"Benefits include no repeated capital expenditure for conventional fixed platform facilities, shorter lead times for future fields through relocating the FPSO, and, by allowing smaller fields to be developed economically, reduced appraisal drilling requirements."
MACHAR TRIAL
BP Exploration Operating Co. Ltd. has chosen a production semisubmersible and storage tanker for early production from Machar field in U.K. North Sea Block 23/26a.
BP plans to start Machar production in May or June for a period of 10 months.
This will enable BP to study Machar reservoir performance while deciding on long term development as part of the Eastern Trough Area Project (ETAP), which will most likely involve further development of Machar with a platform.
First full scale ETAP production is scheduled for 1998 from a group of four sizable fields and five small fields, all operated by BP and Shell-Esso (OGJ, May 17, 1993, p. 18).
Total ETAP reserves are estimated at 380 million bbl of oil and 1.6 tcf of gas equivalent. Wood Mackenzie pegs Machar field reserves at 60 million bbl of oil and 160 bcf of gas.
Macher's early production will involve a subsea completion tied back to the converted semisubmersible, which will produce oil directly into a shuttle tanker. Production will be shut in while the tanker is on delivery to an onshore terminal.
The Sedco 707 semisubmersible drilling rig was converted for production at Invergordon, Scotland. The rig left the yard at the end of February, after which a 20,000 b/d processing module was installed offshore by Schlumberger Evaluation & Production Services (U.K.) Ltd., Aberdeen.
The Machar production system will be operated on behalf of BP by an alliance of Stena, Schlumberger, and subsea hardware supplier ABB Vetco Gray U.K. Ltd., Aberdeen.
The U.K. Department of Trade & Industry gave approval early this month for Machar test production. DTI said BP will produce as much as 7 million bbl of oil at a maximum 30,000 b/d during the Machar test.
BP let contract to Stena Offshore Ltd., Aberdeen, for supply and installation of a Machar loading tanker. The contractor has chartered the 108,000 dwt Savonita from Andreas Ugland Bulk AS, Oslo, for the job.
The vessel is being converted at Blohm & Voss AG's Hamburg yard to hold 750,000 bbl of oil. Conversion is to be complete by June 22.
FIFE FIELD
Early last February Amerada Hess asked Bluewater Terminals SA, Villans sur Glane, Switzerland, to begin preliminary engineering on conversion of a tanker to an FPSO for development of Fife field on U.K. Block 39/1.
The vessel will be chartered to Amerada by Bluewater for 4 years, with first production scheduled for third quarter 1995. Average production will be about 40,000 b/d of oil during the field's 4 year life. Reserves are estimated at 34 million bbl of oil.
Amerada received DTI approval for its Fife field plan in March and immediately asked Bluewater to secure a vessel for conversion.
Amerada also let a 4.5 million ($6.75 million) contract to ABB Vetco Gray, for seven subsea trees to be installed in Fife field. Delivery is scheduled for early 1995.
Five trees win be installed by mid-1995 with two more to be in place by 1996. First oil is expected in third quarter 1995.
NEW LIFE
Last year saw abandonment of two U.K. floater developments. Hamilton Oil Co. Ltd., London, ceased production from Argyll field in Block 30/24, while Amerada halted production from Angus field in Block 31/26.
Argyll, which went on stream in June 1975, was the world's first floating production system development project. It used a converted semisubmersible rig, later replaced by a newer converted rig.
Argyll's Deepsea Pioneer production vessel was sold to Hamilton parent BHP Petroleum Pty. Ltd. and sent to Southeast Asia for refurbishment. The vessel is due in Dai Hung field off Viet Nam to start production in October (OGJ, Feb. 21, p. 32).
Amerada used the Petrojarl 1 ship for production from Angus. Once production ceased, the company sailed the vessel north to Block 210/24a to begin production from Hudson field,
Amerada expects to cease Hudson production through Petrojarl 1 in November. By then the company will have completed a subsea development for Hudson, made up of six wells tied back to Shell Expro's Tern platform 7 miles away.
Once first phase production on Hudson has finished, the Petrojarl 1 will transfer to ARCO British Ltd. for development of Blenheim field in Block 16/21b. ARCO chartered the vessel from owner Golar Nor Offshore AS, Trondheim, Norway, to start production in early 1995 for an expected 3 4 years.
PROSPECTS
Among other potential floater developments, Wood Mackenzie said Conoco (U.K.) Ltd. has appraised the complex Galley field, a 1974 discovery in Block 15/23a.
Development of two of four identified fault traps is expected by the analyst in the late 1990s, using a floating production system. Oil is thought likely, to be loaded offshore with gas exports via the Miller or SAGE pipelines to St. Fergus, Scotland.
In addition, Norsk Hydro is at the conceptual engineering stage with development of Njord field off Central Norway. A newbuild semisubmersible with concrete hull is one of the designs under consideration.
Norsk Hydro also is considering a floater for development of Visund field. The company, is believed to be aiming to submit development plans for Njord and Visund later this year to Norway's Ministry of Industry & Energy.
Offshore engineering contractor Aker AS, Oslo, said the availability of suitable second hand semisubmersible rigs has made converted semis the most common form of floater to date.
However, there are only a few rigs that can provide the required load capacity, Aker said. The company estimates there are only 15 such rigs in the Gulf of Mexico and fewer than that in the North Sea.
Aker says monohull newbuildings are currently in favor: "Most inquiries at the moment tend to be for tanker type installations. U.K. Gryphon field development has helped heighten interest in that direction."
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