North Sea Development Action Brisk; Plays Expand Elsewhere Off Europe

Troll A is the world's largest production platform yet little more than a giant wellhead platform. It has throughput capacity of 100 million cu m/day of gas, with output sent to an onshore terminal for treatment.

The North Sea may be a mature play, but operators are continually searching for new ways to develop small finds near existing infrastructure and to develop discoveries in new areas at low cost.

As they fill in gaps in the North Sea oil and gas infrastructure, companies are also exploring and planning developments in new plays such as the U.K.'s West of Shetlands area, the Irish Sea, and the Atlantic Margin from off western Ireland to northern Norway.

Floating production systems and subsea technology are vital parts of many of Northwest Europe's recently sanctioned field developments, for both large and small reservoirs.

Richard Shepherd, managing director of Petrodata Ltd., Aberdeen, told a recent conference that changing attitudes worldwide towards field developments mean that projects undertaken from now to 2005 will be radically different from those of the last 20 years.

"If there is one single factor which is forcing more change more quickly than at any time in the last 20 years of offshore contracting," said Shepherd, "it is the oil industry's huge and very rapid achievement in squeezing much more oil out of every dollar spent during the last 5 years or so."

In the 1970s and '80s oil companies spent their money on fixed platforms and topsides and their associated installation and hook-up techniques and equipment.

"The profile for the next 10 years is different," said Shepherd. "There is a much wider spread of field development categories. There are many more projects, mostly much smaller in size, shorter in lead time and delivery, and with a much larger share of costs in 'wet' business such as marine and subsea, rather than 'dry' business like shore-based services and assets."

Floaters dominant

Floating production units are set to dominate Northwest Europe's future field developments, according to Smith Rea Energy Analysts Ltd., Canterbury, U.K.

Smith Rea said 77% of oil output capacity of new fields brought on stream last year in Northwest Europe relied on mobile production units, while demand for floaters is growing worldwide, particularly floating production, storage, and offtake units (FPSOs).

In 5 years Smith Rea expects 76 floaters to be in use around the world; this time last year the analyst could foresee only 48. The number of contractors capable of building floaters was also said to have doubled in 12 months.

"Thanks to continued technical progress and changing commercial attitudes," said Smith Rea, "the mobile production unit is no longer seen simply in terms of marginal field development but can be the preferred option for fields of widely differing sizes and characteristics."

But while floaters are one of a number of concepts increasingly used by North Sea operators to reduce development costs, Smith Rea has said that recent advances in drilling technology, including horizontal and extended-reach drilling and multilateral completions, may have had more effect on industry economics in the 1990s than industry cost-cutting initiatives.

"Capital and savings of £1 billion-plus can be attributed to these technologies over the period 1990 to 1995," said Smith Rea, "but cost reduction is only a minor part of their economic impact on the industry.

"Far more important over the same period was their enabling role in increasing commercially recoverable reserves within existing fields by more than 2.2 billion bbl and in permitting development of fields with reserves of 2.5 billion bbl, which without them would have remained unexploited.

"The gross production value of these 4.8 billion bbl at current prices is a staggering £54 billion ($81 billion), much of which is likely to accrue before the turn of the century."

Troll's gas treatment plant at Kollsnes, north of Bergen, is the world's largest such unit. It has capacity to process 89 million cu m/day of gas but can be expanded as Statoil concludes further gas sales contracts with buyers in continental Europe.

Subsea niche

Shepherd reckons that outside the shallow area of the Gulf of Mexico, subsea developments will capture more than a quarter of the rest of the world's 750 or so new offshore developments expected between 1995 and the end of the decade. Many other developments will involve floating production systems or floater-subsea hybrid technology.

"Deeper water projects account for almost 60% of the new field potential outside the shallow Gulf of Mexico," said Shepherd. "The subsea share then rises closer to 40% in water depths of more than 70 m.

"The North Sea has led the large scale subsea revolution after the dramatic and pioneering work in Brazil. For the next 5 years, almost half of all the world's deeper water field development projects are in the North Sea, and more than half of these will be exclusively subsea."

Shepherd said the swing from dry to wet production systems has been rapid: A quarter of all producing deeper water North Sea fields are subsea, he said, while 44% of those out for tender will be subsea, and two thirds of those at the planning stage are expected to be subsea.

"So-called frontier oil is likely to be produced within the limits of conventional fields at perhaps $12/bbl," said Shepherd. "Costs are expected to fall much further so that the costs of today's highest cost new fields would be halved.

"The technologies now being applied in the North Sea in particular, both in conventional water depths and perhaps before 2000 in the deep waters West of Shetland, may mean that North Sea oil production holds up far longer and far higher than any forecasts have dared to suggest."

New production

North Sea operators have completed some large and some small developments in the first half of this year, and in almost every one an innovative approach has had to be taken to make it viable.

Den norske stats oljeselskap AS (Statoil) has taken over operatorship of the giant Troll gas field development in Norway from development operator Norske Shell AS.

The field is producing small amounts of gas for commissioning of onshore and offshore plants. In October Troll gas will begin to supply up to 24 billion cu m/year of gas to European customers.

Troll field has estimated reserves of more than 1 billion bbl of oil and 1.3 trillion cu m of gas, but development was viable only because of new technologies.

Troll's western oil province contains the bulk of the field's liquids in a large but thin reservoir. Without horizontal drilling, recovery of oil and commerciality of the field would have been impossible.

Troll West was brought on stream last year with a production semisubmersible by Norsk Hydro AS. Troll East gas was developed with the world's tallest and heaviest platform, at 430 m tall and 1.05 million metric tons in weight the largest man-made object ever to be moved.

Although large, it is little more than a giant wellhead platform. While it would have just about been possible to build the enormous gas treatment plant required for Troll on a platform, Shell decided an onshore terminal gave more room for expansion.

The platform will produce from 39 wells, each capable of yielding up to 3.4 million cu m/day of gas though normally restricted to 2.8 million cu m/day. Production capacity of the platform is 100 million cu m/day of gas.

The terminal capacity is 89 million cu m/day, but this can be expanded as further gas sales agreements with Europe are clinched. Gas is piped ashore to a terminal at Kollsnes for treatment prior to export via pipeline to Europe (OGJ, July 1, p. 40).

BP Exploration Operating Co. Ltd. began oil production from Andrew field in U.K. North Sea Block 16/28 on June 26 at an initial rate of 3,500 b/d. First oil was achieved only 6 weeks after platform deck installation.

Further predrilled wells will be brought on stream over the next 2 months, and the Cyrus subsea satellite will be started up in July. Combined production is expected to reach 60,000 b/d by yearend.

Andrew has estimated reserves of 119 million bbl of oil and condensate and 134 bcf of associated gas. The field was discovered in 1974 in 116 m of water.

Here the technology is conventional: a steel platform with pipeline exports, with four wells predrilled. Nearby Cyrus field, which had earlier produced through a production ship, was tied in as a two well subsea satellite of the platform.

Innovation in Andrew came in the contracts, which gave the companies that designed, built, and installed the platform a share in any cost savings made during construction.

BP and the contractors came up with a development cost of £373 million ($560 million) for Andrew. This compared with an estimate of £450 million ($675 million) made by BP without the input of contractors.

By the time Andrew began production, BP reckoned its total development cost was £290 million ($435 million).

Harding

In April BP began oil production from the U.K. North Sea's Harding field, using a platform comprising a jack-up production unit mounted on a concrete storage base.

Harding lies in 110 m of water on Block 9/23b and has estimated reserves of 185 million bbl of oil and 200 bcf of gas. Development cost was £430 million ($650 million).

BP said oil flow began on Apr. 23 at 5,000 b/d. This was expected to rise to 25,000 b/d from the first well and to be increased with other wells to 60,000 b/d by yearend.

The base was installed in June 1995. The jack-up was scheduled to be installed in September 1995, but bad weather delayed this until January as the operation required 5 days of relative calm.

The 23,000 metric ton heavy-duty jack-up has capacity to produce 64,000 b/d of oil. It is based on the proprietary TPG 500 design by Technip Geoproduction SA, Paris (OGJ, Aug. 15, 1994, p. 56).

The jack-up sits on a T-shaped concrete gravity base, which weighs 90,000 metric tons. The base has capacity to store more than 500,000 bbl of oil, which is pumped for export to a shuttle tanker moored 2 km away.

BP said Harding's Central and South reservoirs have been developed, while a further 15-40 million bbl of oil lies in satellite development prospects on the same block.

Harding's produced gas is being reinjected into the reservoir and will be exploited as oil output wanes.

Field partner Ranger Oil Ltd. said the development cost of $3.50/bbl makes Harding one of the most economical fields in the U.K. North Sea. Ranger said operating costs are expected to be less than $3/bbl once full production is achieved.

In April Amoco (U.K.) Exploration Co. began production from Beaufort gas field, which lies on Blocks 49/23 and 49/28 of the southern North Sea.

The field was developed with a single extended-reach well drilled from nearby Bessemer platform by the Cecil Provine jack-up rig. Development cost was £6 million ($9 million).

Beaufort is expected to produce up to 30 MMcfd of gas over a 4 year field life. Gas moves via Bessemer by pipeline to Amoco's Indefatigable 49/23AT platform and on to Bacton terminal.

Kent Davis, Amoco's southern North Sea asset manager, said: "Advanced drilling technology is enhancing our capability to develop small but important North Sea gas fields.

"This is in line with our strategy of maximizing use of existing North Sea infrastructure and developing satellite fields around our core area of operations."

Last year Amoco brought on stream Davy and Bessemer fields as satellites of Indefatigable. Davy and Bessemer platforms were the first monotowers installed in the U.K. North Sea.

Mobil North Sea Ltd. used the design to develop Galahad field. Amoco is considering development of other finds near Indefatigable with the same concept (OGJ, Oct. 23, 1995).

BP has also begun production from South Magnus field in the northern U.K. North Sea area. The field, on Block 211/12a, was developed with a subsea well tied back to Magnus platform 7 km to the north.

Production started on May 25 at a rate of 17,000 b/d of oil. South Magnus has estimated reserves of 20 million bbl of oil and gas equivalent to 6 million bbl of oil. Production is expected to settle to around 14,000 b/d and to last 10 years.

BP's Andrew field development involved use of conventional technology but unconventional gain-sharing relationships with contractors. BP originally estimated Andrew costs at £450 million ($675 million) but with the help of contractors brought it on stream for an estimated £290 million ($435 million).

Schiehallion

While BP has been completing the Andrew, Harding, and South Magnus projects, it has also been pushing new field developments west of the Shetland Islands.

In March the U.K. Department of Trade & Industry (DTI) approved a plan by BP to develop the Schiehallion and Loyal discoveries.

Schiehallion and Loyal lie in 375 m of water on U.K. Block 204/20 and have estimated reserves of 340 million bbl and 85 million bbl of oil respectively.

The company plans a £900 million ($1.35 billion) development, involving a production, storage, and offtake ship producing from 29 seabed wells completed in four clusters.

As is increasingly common with the current trend for fast track developments, BP let contract more than 9 months before DTI's approval of the project.

Last June the operator let contract to Atlantic Frontier Alliance, comprising Brown & Root Ltd. of Aberdeen, Single Buoy Moorings Inc. of Marly in Switzerland, and Harland & Wolff Ltd. of Belfast, to design and build the ship.

"Schiehallion is a large and highly significant development in every sense," said Eggar. "It is one of the biggest oil fields to be announced in the last decade, and I am quite convinced it will play a major part in establishing the waters to the west of Shetland as a major new oil province.

"Not only will the vessel have a storage capacity of nearly a million bbl of oil, and the ability to process around 140,000 b/d of oil, it will have been constructed in the shortest ever time for such a vessel."

DTI said Schiehallion is the second largest U.K. oil find, after Scott field, to be approved for development in the last decade. It was discovered in late 1993 and is expected to begin production in early 1998.

BP expects to bring the first West of Shetland field into production later this year. This will be Foinaven, another FPSO development. Also, the company plans an extended well test this summer in Clair field, discovered in 1977.

Clair

Though Clair is the U.K.'s largest undeveloped oil find in terms of oil in place-the reservoir is thought to hold more than 4 billion bbl-drilling and testing to date have shown it be a complex structure, and flow rates have been inconsistent. Hence BP estimates oil reserves at only 100-300 million bbl.

In May BP Exploration Operating Co. Ltd. began an extended well test in Clair in a bid to prove it commercially viable.

Clair lies on Blocks 206/7a, 206/8, 206/9, 206/12, and 206/13, where water depth is up to 150 m. Since its discovery in 1977, 10 appraisal wells have been drilled, but none has flowed sufficiently to deem Clair viable.

The Sedco Explorer semisubmersible rig anchored in the field in May and reentered an earlier well this week for an ambitious test.

If the test is successful, BP expects to look at development options for Clair, particularly at a floater as in the Foinaven and Schiehallion developments, and perhaps a platform long term.

The well to be reentered is 206/8-10, a high angle well drilled into the core of the reservoir in 1995. Extended well testing was planned to take place last year, but the well was suspended without testing due to delays and weather. The current test was expected to last 45 days.

"The objective of this test," said BP, "will be to try and produce some 15,000 b/d and maintain this over an extended period.

"If such production can be maintained, the partners may decide to extend the test beyond 45 days and attempt to produce up to 2 million bbl from the reservoir, equivalent to three tanker cargoes."

The best flow rate from Clair to date was 7,300 b/d with the 206/8-9z well drilled in 1992. A second well that year, aimed at demonstrating repeatability, flowed at only 2,545 b/d maximum.

A BP official said that, since these tests, analysis of 3D seismic data from Clair has enabled geologists to map fractures in the reservoir.

They have worked out which fractures can act as conduits to boost oil flow and which can restrict flow. This information was used to plot the course of the 206/8-10 well.

"If the 1996 work program is a success," said BP, "the partners may decide to bring forward some form of early production scheme before the end of the century.

"Although no decisions have been taken, an early production system would help to ensure that all the commercial and geological risks are fully understood before plans for more permanent development are considered."

Norway's plans

Norway has its own giant floater project under way. Statoil's Aasgard fields in the Norwegian Sea will be developed with an oil production ship and a gas production semisubmersible (see p. 50).

Norway too is working to open new areas in the midst of mature North Sea areas. Esso Norge AS plans two nearby developments as separate projects in a North Sea area so far without transport infrastructure.

In May Esso let contract to Aker AS, Oslo, for a conceptual development study for its Elli, Elli South, and Tau discoveries in the Norwegian North Sea.

The three finds have total estimated reserves of 200 million bbl of oil. An Esso official believes it will be possible to produce the three from one installation.

Three main options are being studied: a production, storage, and offloading ship with subsea wellheads; a production, storage, and offloading ship linked to a wellhead platform; and a wellhead platform in the field tied back to a new platform in Heimdal field, where Elf Petroleum Norge AS is operator.

First oil production from the finds is scheduled for late 1998 or early 1999. The official said the names Elli and Tau are only in-house references; the company has applied for a formal name now development is being studied.

Esso has proposed the name Jotun for the entire project. Elli would then be referred to as Jotun, Tau as Jotun East, and Elli South as Jotun South.

Earlier this year Esso announced a plan to develop the Balder discovery, 25 km south of Jotun. Balder will be developed with 15 subsea wellheads tied back to a production, storage, and offloading ship (OGJ, Feb. 19, p. 58).

Norsk Hydro has submitted to Norway's Ministry of Industry & Energy a plan for development and operation of the Oseberg East discovery in the Norwegian North Sea.

The find lies 27 km northeast of Oseberg field center and has estimated reserves of 145 million bbl of oil. License partner Saga Petroleum AS said Oseberg East will be developed with a steel platform with first-stage processing, drilling, and accommodation facilities.

A 3.3 billion kroner ($500 million) development is expected to lead to first oil in October 1998. Production will be piped to Oseberg center for final processing and transport to the Sture terminal near Bergen.

Elgin/Franklin

As BP cranks up Harding output, Elf Exploration U.K. plc has let contracts for front-end engineering design of a platform for its planned Elgin/Franklin development, incorporating the same jack-up concept.

Elf let contract to McDermott Marine Construction Ltd., London, and Technip to study feasibility of using a TPG 500 design jack-up as part of a central processing platform in the Elgin/Franklin development.

McDermott and Technip have formed a joint venture to market the TPG 500 concept and have been given until November by Elf to complete the Elgin/Franklin study.

McDermott said: "The unique aspects of the TPG 500 design concept offer substantial savings over conventional platform installations. Key to its success is the extensive use of low-cost fabrication techniques, capability for full onshore commissioning, and onboard installation facilities which allow the platform to 'self install' without the need for heavy-lift crane barges."

Elgin and Franklin gas/condensate discoveries lie on Blocks 22/30c and 29/5b respectively. Elf plans to begin production in 2000, using a central processing complex in Elgin and a smaller platform in Franklin.

Wood Mackenzie Consultants Ltd., Edinburgh, estimates Elgin reserves at 125 million bbl of condensate and 550 bcf of gas, and those in Franklin at 75 million bbl of condensate and 700 bcf of gas.

Elf originally planned to begin production from Elgin and Franklin in 1998. However, Britain's low gas prices following gas market liberalization have meant development must wait until the planned Interconnector pipeline from the U.K. to Belgium gives access to a more profitable market (OGJ, Dec. 4, 1995, p. 44).

Elf also let contract for an undisclosed sum to Santa Fe Drilling Co. (North Sea) Ltd., Aberdeen, for drilling of further wells during development of Elgin and Franklin.

Santa Fe has a contract to begin Elgin development drilling at the end of this year with the Galaxy 1 heavy-duty jack-up. The new contract covers up to eight production wells in Elgin and six in Franklin and is due to begin in fourth quarter 1997.

Small fields

The imagination of Northwest Europe's operators is shown on a grand scale by projects like Aasgard and Schiehallion and on a small scale with a flurry of small field developments.

Saga Petroleum received approval from Norway's Ministry of Industry & Energy for 6 months of test production from H Central reservoir near Tordis East, which is currently under development.

Saga plans to produce 3.1 million bbl of oil from H Central through a subsea template being installed this summer in Tordis East field on Block 34/7. Saga hopes to determine the extent of oil-bearing sands and communication within H Central in a bid to estimate reserves. The test could begin this autumn but may be deferred to next year if priority is given to a production well in Tordis East.

Amerada Hess AS has told Danish Energy Agency that its South Arne oil discovery is commercially viable. South Arne, in Danish North Sea Blocks 5604/29 & 30, flowed almost 2,500 b/d of oil on test in February 1995.

Soeren Holm, managing director of Amerada's Danish unit, said it is too early to give an estimate of South Arne reserves.

He said the company is studying two main options for development: a platform with oil storage and processing facilities and a gas pipeline to shore; and a floating production, storage, and offloading unit with a gas pipeline to shore.

Amerada said the development choice will depend on access to appropriate oil and gas export facilities. Feasibility studies are under way, with a target to achieve first production in 1998.

Phillips Petroleum Co. U.K. Ltd. announced in April it has proved additional reserves in North Sea Judy field, currently under development, with its 30/7a P-12 well.

Phillips said the well cut 540 ft of gross hydrocarbon pay and was tested over an interval of 110 ft in Triassic sandstones. The well flowed 3,800 b/d of condensate and 20 MMcfd of gas on a 36/64 in. choke.

Phillips has delayed Judy production because of a dispute over gas supply with Enron Europe Ltd. and is currently installing a gas injection module on the platform to enable reinjection of associated gas (OGJ, Sept. 25, 1995, p. 38).

In May Kerr-McGee Oil (U.K.) plc commissioned McDermott to carry out a preliminary engineering study for development of the Janice discovery in U.K. North Sea Block 30/17a.

A number of alternatives are under study, but a production, storage, and offloading ship is thought to be the favored option. Janice lies in 80 m of water and has estimated reserves of 20 million bbl of oil.

Marathon Oil U.K. Ltd. has let contract to McDermott to carry out preliminary engineering of development of the West Brae discovery.

West Brae will be developed as a subsea satellite of Brae A platform, maybe in conjunction with the nearby Sedgwick discovery operated by Enterprise Oil plc, London.

Marathon hopes to receive development approval for West Brae in August, after which McDermott's work will form the basis of an engineering, procurement, construction, and installation contract.

Frontier work

As the West of Shetland area approaches the start of production, other offshore areas on the western side of the British Isles are being probed.

Operators have raised concerns that the U.K. Department of Transport (DOT) is putting a hold on their plans to drill wildcat wells in the U.K. Irish Sea following the grounding of the Sea Empress tanker in February.

An industry source said the department's reluctance to approve drilling plans has caused problems for Elf Exploration U.K. plc, which had intended to drill on U.K. Block 108, and British Gas plc.

A DOT official denied the department was holding back drilling because of any links with pollution fears following the Sea Empress spill.

In a bungled salvage attempt, the tanker spilled some 70,000 metric tons of oil, which came ashore along the South Wales coast (OGJ, Mar. 4, p. 41).

"An application to drill on U.K. Block 108 was refused recently," said the official, "but this was because the company planned to drill in a busy shipping lane. Our sole criterion for judging drilling plans is navigational."

In late May Marathon Oil Manx Ltd. plugged and abandoned its 112/29-1 wildcat as a tight hole. This was the first well to be drilled in the offshore area licensed last year by the Isle of Man government.

A Marathon official said only that the company is studying data from the well to determine further exploration plans in the area.

Marathon is also operator of Block 112/24, where the license obligation is to conduct a seismic survey contingent on success of the 112/29 well.

The official said the company is leaning towards the cautious in its estimation of the well results. Marathon struck gas off Southwest Wales in 1994 with a Block 103/1 find later named Dragon (OGJ, Nov. 7, 1994, p. 35).

The official said Marathon is keen to appraise the Dragon prospect but has met with difficulties getting approval from DOT for an appraisal well.

Meanwhile, the company planned to acquire 2D seismic data on Blocks 103/6 and 106/27 near the Dragon discovery, beginning in July.

Marathon has drawn up plans to drill two wells next year on different prospects near Dragon, one on Block 103/6 and one on Block 106/19.

Further north on Block 112/15, Esso spudded a wildcat on May 28 in 150 ft of water using the Glomar Adriatic XI jack-up rig.

Esso said the rig will drill for 50-60 days and may remain on site for a further 2-3 weeks to test any discovery. The company said a dedicated counter-pollution vessel will be on location during the drilling operation.

Esso has gone to unprecedented lengths to make the public aware of its drilling plans here due to the rig's proximity to the shore and the fact that blocks north of the Isle of Man are virgin territory (OGJ, May 6, p. 46).

In April Enterprise Oil plc, London, spudded a wildcat on Block 27/5 in the Slyne Trough off western Ireland, using the Petrolia semisubmersible drilling rig.

Ireland's Department of Transport, Energy & Communications said the well is part of a work program under a license awarded in 1993. The rig is expected to stay on location for about 40 days, after which it will move northwards to Quadrant 18 to drill a well on a license issued in 1994.

Also in April Geoteam AS of Oslo completed speculative acquisition of seismic and gravity data over the northern sector of disputed offshore territory between the U.K. and the Faroes Islands.

Geoteam said the new data forms an extension of its 1995 North Shetland basin survey. The survey was carried out by the Geolog Dm. Nalivkin research vessel, which has since moved to the Rockall Trough area west of Ireland for a speculative survey of U.K. and Irish frontier acreage.

Statoil U.K. Ltd. intends this summer to acquire 3D seismic data on Block 26/28a off western Ireland in the area of the Connemara discovery, Ireland's only oil strike to date.

The survey will be used to determine the best site for an appraisal well in Connemara, which will be drilled in 1997. Statoil said results from the well will be crucial for a development decision on Connemara.

Connemara was first deemed noncommercial but is looking increasingly viable as a floater development (OGJ, June 5, p. 17). Statoil acquired Connemara in its takeover of Dublin's Aran Energy plc last year.

Statoil has also issued a letter of intent to Reading & Bates (U.K.) Ltd., Aberdeen, to charter the J.W. McLean semisubmersible for drilling off western Ireland.

The $60 million deal secures the rig for up to 19 months beginning March 1997, with one project being appraisal of the Connemara discovery. The rig will also drill two wildcats on other nearby licenses.

A concrete monotower for southern North Sea field developments has been developed by AMEC-LOG of Aberdeen, a unit of fabricator AMEC plc.

Gashopper, as it is called, is said to be suitable for gas and oil field developments in water up to 60 m deep. A base caisson enables seawater ballasting for stability when installed and buoyancy for towing.

The platform is designed to have topsides fitted either in drydock or offshore through use of a jack-up rig or light crane barge. It can handle up to 16 well risers, compared with 6 for a steel monotower.

Imad Younes, principal structural engineer at AMEC-LOG, said a Gashopper designed for drydock completion could take topsides of 500 metric tons maximum.

Alternatively, installing topsides offshore, while being much more expensive, would allow up to about 3,000 metric tons of topsides to be fitted.

AMEC sees this concept as suitable for use as a central processing facility in a shallow-water development, where the trend is for normally unmanned installations.

"We have proposed this concept for a number of gas projects in the last year," said Younes, "but the problem has been declining gas prices in the U.K."

Younes said Gashopper was first proposed to BP in a feasibility study for development of the North Cleeton satellite gas discovery.

"The reservoir was found not to be promising," said Younes, "so BP did not go ahead with the project, though BP liked the design. Now we are making proposals to use it for BP's Hoton field development."

Gashopper was also proposed for the Belvedere development planned by Mobil North Sea Ltd., said Younes. Here the design qualified as one out of three options, but Mobil has put Belvedere on ice because of low gas prices.

A typical Southern Gas basin installation, said Younes, in 35 m of water would require a 6,000-7,000 metric ton base if topsides were installed offshore, or about 11,000 metric tons if topsides were fitted onshore.

Subsea control

Ocean Technical Systems Ltd. of Cheam, U.K., has been working to develop a remotely operated, low-cost subsea control system, which will enable a subsea wellhead to be controlled from a host platform via radio telemetry through a unique, tethered-buoy design.

Phil Hands, business development manager of Oceantech, said the Wellbuoy system would enable offshore operators to optimize subsea developments, particularly where a new development can be tied back to an existing facility.

"Using proven methodology," said Hands, "it is possible to eliminate the conventional seabed umbilical and provide an inherently safe and redeployable system whilst saving approximately 50% on capital expenditure.

"As an unmanned facility, it requires far less equipment than traditional solutions and offers the great advantage of modular repair. It will be offered to industry as an 'off-the-shelf' design, configurable to specific development requirements."

There is a range of differently sized buoys to cope with varying water depths, wave conditions, and number of subsea wells to be monitored and controlled.

The buoy informs the host platform of status of all buoy and wellhead systems and communicates instructions from the platform to change mode of operation of the wellhead and transmission of emergency shutdown instructions.

"It is expected that the buoy will be serviced every 6 months," said Hands. "Although the facilities on board only require an annual inspection, current U.K. legislation for subsea wellheads requires that the umbilical and the operation of the subsea valves, particularly the downhole safety valve, must be checked every 6 months.

"It is proposed that the buoy is given a major overhaul every 5 years by removing it from its station and taking it ashore. The cost of such an exercise is less than the regular inspection over 5 years of a conventional seabed laid umbilical system."

Hands said applicability of Wellbuoy is chiefly dependent on step-out distance, but also on number of wellheads to be controlled and water depth.

A single wellhead, for example, would not be economical unless it was more than 5 km from a host platform, he said.

Funded by Shell Expro, Oceantech has completed a feasibility study for development of the Mallard prospect in the central North Sea with Wellbuoy.

This design involves two production wells and two water injectors controlled by Wellbuoy from a host platform 17 km away, said Hands, and offering a £6-8 million ($9-12 million) saving over a conventional subsea development.

The highest number of wellheads studied so far for a Wellbuoy application is six. Beyond 200 m water depth the weight of required mooring chains is thought to put a limit on use of Wellbuoy, though Hands said buoyancy can be increased simply by increasing the size of the buoy.

The communication method can also limit applicability. For line of sight telemetry systems, the theoretical limit will be the horizon line at about 22 miles, but for a satellite link there would be no upper limit.

BHR Group Ltd., Bedford, U.K., has developed the Wellcom pressure booster, which is intended to use energy from high-pressure wells to drive production from nearby low-pressure wells.

The research group said that, traditionally, high-pressure wells are choked back to match the pressure of the export pipeline, which wastes energy. Wellcom takes this 'free' energy to increase production from lower-pressure wells.

The Wellcom system comprises an in-line separator, a jet pump, and a commingler. There are no moving parts, and it requires no active control, which BHR said suits it to subsea and deepwater applications.

A version for oil fields is designed to separate out gas from the high-pressure stream before utilizing the liquid as the driving force, passing through a jet pump which boosts production of the low-pressure stream.

• The Aasgard Development Scheme [121095 bytes]

THE WORLD'S LARGEST production ship and gas production semisubmersible are slated for use in development by Den norske stats oljeselskap AS (Statoil) of the Aasgard discoveries in the Norwegian Sea.

The Aasgard project involves development of the Smoerbukk, South Smoerbukk, and Midgard discoveries, with estimated reserves amounting to 800 million bbl of oil and 7 tcf of gas.

The production ship will have capacity to produce 200,000 b/d of oil, to process 15-16 million cu m/day of gas, and to store 150,000 cu m of oil. It will be 276 m long and 45.4 m wide and have a draft of 26.6 m.

The oil production ship is to leave Aker's Stord yard at the end of May 1998 and be ready for oil production in early August 1998.

Statoil has said the production semisubmersible will have capacity to produce 36 million cu m/day of gas, 11,000 cu m/day of oil, and 14,000 cu m/day of condensate.

Design work on the semisubmersible will continue until April 1997. The production semisubmersible is scheduled to be ready for production in October 2000.

Besides two innovative production vessels, Statoil has also decided to build a unique vessel for well completion and intervention services because of the high number of subsea wellheads planned for Aasgard.

Statoil plans construction of a small waterplane area twin-hull (Swath) vessel, an innovative alternative to semisubmersible rigs for many well operations.

Smedvig AS of Stavanger will own and operate the Swath vessel, which is said to have stability and seakeeping and load-handling capabilities similar to those of a semisubmersible rig but to be more mobile.

The Swath concept is the result of Statoil's efforts to develop a cost-effective technique for deepwater workovers and completions. The company has recently sanctioned field developments involving a total of about 100 subsea wellheads, including 60 for Aasgard.

Statoil's idea to cut well workover and completion costs in Aasgard is to build a relatively fast, dynamically positioned vessel specifically designed for the job. The main savings will come through the shorter time required to move and position the rig between operations.

The company estimates that the Swath vessel will be able to perform well completions 36% cheaper and workovers 50% cheaper than those done from an anchored semisubmersible.

Swath model testing was completed in January at the Danish Marine Institute in Copenhagen. A full-size, 10,000 dwt unit would be 122 m long with a 2,600 sq m deck space. Sailing speed would be 13-14 knots.

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