BP Amoco development an indicator of Atlantic Margin prospectivity

Aug. 1, 2000
Eyeing tracts in far western UK, Faroese waters

British Petroleum (BP Amoco) was one of the pioneering operators who believed in the prospectivity of the West of Shetlands area, with its challenging metocean conditions and severe and complex currents. - The Petrojarl Foinaven FPSO will be situated 6.4 km west of the East Foinaven drilling center.

The producer was awarded the first license in June, 1977, and in that year, made the first discovery, undeveloped Clair. Clair's reservoir is very complex and BP (later BP Amoco) has wrestled with the problem ever since. The firm now has a development plan underway and hopes for first production in mid-2004.

Foinaven was discovered in 1992; Schiehallion in 1993. Both fields, including the Loyal accumulation, which is part of Schiehallion, are now producing an average combined total of 250,000 b/d. "We have built up an impressive business there," explained Clive Fowler, West of Shetland Business Unit leader. Now, BP Amoco is planning to embark on the following:

  • A massive infill drilling program in the two producing fields
  • Bring the third field, Clair, onstream
  • Progressively develop the 6-7 already-known satellites, which have been drilled and appraised, and which are 8-10 kms from one or the other floating production, storage, and offloading (FPSO) vessels
  • Build a 395 km, 20-in. pipeline to boost production at Magnus in the North Sea
  • Carry out further exploration in the area.

Foinaven, Schiehallion

BP Amoco discoveries either in production or about to be developed.
Click here to enlarge image

"The technical challenges are now behind us and both fields are performing well," Fowler said. "Production has on occasions, reached 270,000 b/d, but this is not quite full capacity. The aim now is to build it up to 300,000 b/d later this year."

The effort will require more infill wells. The semisubmersible Paul B Lloyd Jr has already drilled some this year on Schiehallion in a two-year program. It will have to leave for a short period this summer to drill the crucial appraisal well on Rhum, a "stranded gas asset" 90 kms from Harding in the North Sea. This well is crucial in determining whether Rhum and another gas field, Devenick, 20 kms from Harding, will be developed. The Transocean Leader, which started work on Foinaven earlier this year, will drill a further five wells in 2001.

So far, 20 producers and injectors have been drilled on Foinaven and 29 on Schiehallion. "There is the potential to drill as many as that again over the next four years," Fowler said. "There is a full range of opportunities. When we began drilling, the cost of a well was $18 million gross. We have steadily reduced that, and the best well so far came out at $14 million. The aim now is to drive that down to the $10 million mark."

BP Amoco is considering permanently installing 3D seismic recording equipment on the seabed at Foinaven, which will provide direct evidence and knowledge of the movement of fluids in the reservoir - an invaluable tool for production and for locating infill opportunities.

On top of this activity, exploration within the area will be continued. Earlier this year, the Vrackie well (204/28a-3) was drilled to the south as a very tight hole by the Stena Dee.

Looking further ahead, BP Amoco will bid aggressively in the delayed UK's 19th licensing round, which is expected to be announced later this year. It has already put in bids in the first Faroes licensing round. Awards will be made in September (the bid document was submitted on a CD-ROM, a BP Amoco first).

"The Faroes region is of immense importance to BP Amoco, not least when we consider the activity we already have on the Atlantic Margin," said Martin Miles, Project Manager of Comm-ercial Development.

The firm has set its sights on blocks to the west of Foinaven and Schiehallion, and it is confident that the source rocks extend into Faroese waters. The firm is ready to begin drilling next summer, if granted licenses.


The first Foinaven satellite to be developed - T35 - came on stream in June with well P12, tied back to the FPSO, flowing 14,500 b/d. Reserves are put at 10 million barrels on the basis of a single well development. The next development is East Foinaven, discovered in 1995, which is expected to produce 36 million bbl of oil over a field life of 14 years.

This project is planned as part of the overall phased development of the main Foinaven field, 7 kms to the northwest. First production is scheduled for September 2001 from one well and will rise to 20,000 b/d in 2002 from two wells. It will remain at that level for two years before steadily declining.

There will be four subsea wells - two horizontal producers (P41 and P42) to be drilled 6.4 kms to the southeast of the FPSO close to an existing pipeline route, and two water injectors, probably to be located at the East water injection site. West of Shetland conditions generally necessitate having a producer and injector in pairs.

A new two-well drill center will comprise the two producers and will be located 30 meters to the northwest of a production gathering manifold and 20 meters to the east of a control distribution assembly. An umbilical termination assembly for the provision of hydraulic and electrical power to the wells already exists.

Production will be manifolded and exported to the existing R6 riser flowline termination assembly under the FPSO by a single 8-in. flowline. Gas from the pipeline end manifold will be similarly imported via an 8-in. line and distributed via the manifold and 2-in. flexible jumpers to the wells for gas lift.

Formation gas will be dried and compressed by the gas handling facilities on the FPSO. After being injected into the 8-in. distribution network, it will either go to gas lift or be disposed of down the G31 well.

The drilling of the first producer is scheduled in the February-May, 2001 period, to be immediately followed by the first injector. The second producer will not be drilled until April-June 2002, coming into production in August. The wells have been phased to coincide with the beginning of the decline of the main reservoir so that sufficient capacity is available on the FPSO to process the fluids without modification to the facilities. The project schedule calls for procurement in 3Q this year and pipelay in the 2Q 2001.

Magnus EOR

The project, which has commercial value as well as environmental advantages, should get sanction this summer with startup scheduled for the 4Q of 2001. The £300 million plan, which was first mooted last summer, is to lay a 185 km, 20-in. pipeline from the Foinaven/Schiehallion area to Sullom Voe, where the gas will be enriched with LPG. From there, it will go via a 210 km, 20-in. pipeline to the Magnus platform in the North Sea for re-injection into the reservoir to increase production. BP Amoco believes this could increase recoverable reserves to approximately 50 million bbl of oil and could extend field life by several years beyond 2015. Gardline Surveys carried out a pipeline route survey last year.

A new deck will be installed on the Magnus platform on top of an existing storage area. This will support a new gas compressor, associated heat exchangers, suction drums, a new gas injection manifold, and associated pipework. Additional facilities include an import riser. The existing six water injection wells would require modification. For two wells, the production tubing will be replaced with new tubing to ensure gas tight seals. At the other four, the lower sections would be redrilled (sidetracked) into adjacent areas of the reservoir. The wellheads on all six wells would be replaced, and designed to handle the increased pressures involved in gas injection.

There will be an opportunity to provide the Sullom Voe terminal with a long-term source of fuel gas and provide the possibility for further power export to the rest of Shetland. It may also create the possibility of further reductions in the volumes of gas flared at Foinaven and Schiehallion.

At present, gas from both fields, in total around 150 MMcf/d, is either utilized, fla-red, or sent to a gas disposal well in each field. The plan will require the gas to be collected via a 10-in. line from Foinaven and a 12-in. line from Schiehallion/Loyal to enter the main line at a pipeline end manifold in 180 meters of water.

"Our plans continue and we hoped to have solved the myriad commercial and technical issues associated with the project in the next two months," Folwer says.


This oil field,discovered in 1998, located in block 204/19, is 20 km north of Foinaven and Schiehallion in 850 meters water depth. It is the most distant of the outboard prospects in block 204. No figures have been given of recoverable reserves but BP Amoco considers it too small for a stand-alone development either by floater or FPSO.

BP Amoco considered the reservoir stretched north into blocks 204/14 and 15, which were unlicensed at the time of discovery. It hoped to get them in an out-of-round award, but the DTI preferred Conoco, which has drilled two wells, Slioch and Onslow.

BP Amoco now has a 32.5% stake in these licenses through its absorption of Arco. Discussions are on-going about a unified development of the three fields, but no decision has yet been reached.


The East Foinaven development will consist of four subsea wells, two horizontal producers, P41 & P42, and two water injectors.
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For more than 20 years, this complex, highly fractured, heavy oil reservoir , with more than 5 billion bbl of oil in place and lying in 140 meters water depth some 75 km to the northeast of Schiehallion, has tantalized and tormented BP Amoco and its partners.

Now, it is on the verge of being rescued, if all goes according to plan, by the adoption of tried and proven Gulf of Mexico techniques. If UK design engineers and fabricators, allied to their US counterparts, can reshape traditional thinking and methods, the field could be producing 80,000 b/d from the southern section by 2004, with a field life of at least 20 years.

Recoverable reserves are put at 250 million bbl. Various efforts to bring development to fruition have been thwarted by technical problems, particularly getting the oil to flow at satisfactory rates. These have now been overcome. Wells on extended test have flowed at 18,000 b/d.

Two years ago the project was poised for sanction. But it fell at the last hurdle - the cost was far too high. Fowler says, "When we reached the point in 1998 of seeking sanction, the project simply did not fly; it did not have enough profit-generating ability. This was mainly because traditional UK practices pushed the costs up too high.

"So, we had to re-think the whole approach. We looked at our own Gulf of Mexico developments and decided to set Pompano as the benchmark. It has the same number of wells, same handling capacity, and the same topsides that we will require. If we could replicate Pompano , with some modification, on Clair, it would do a fine job of producing." Pompano is a steel platform in 395 meters water depth in Viosca Knoll Block 900 and came on stream in 1994.

Terry Hughes, Clair Delivery Manager, puts the engineering and construction development challenge as follows: " Clair platform - $600 million. Target - $300 million." The stripped down Pompano platform cost just $200 million.

Hughes says that the keys to Gulf of Mexico development costs are - smaller design teams, simpler and more standardized designs, standard equipment, and the will to achieve success.

Cultural differences

Proposed gas pipeline routes for the Magnus enhanced oil recovers project, north of the Shetlands.
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The UK industry is well aware that Gulf of Mexico costs are lower than the UK. The Competitiveness Work Group of the government/industry Task Force, in its final report last September, highlighted this fact, particularly for small to medium steel platforms. Savings of up to 40% could be possible, it said. It summed up: " The principal differences arose as a result of cultural, rather than technical issues and would require changes throughout the supply chain if Gulf of Mexico practices were to be replicated in the UK."

The crux of the matter is just how far UK designers and fabricators are prepared to bridge this gap. UK fabricators are desperate for orders - currently, there are only two of the major yards with work - all the others are on care and maintenance.

Fowler says that BP Amoco has had discussions with all of them on these issues. "It is our intention to work with UK industry, but there will have to be an element of US methods," he says. "The trick is to design and fabricate Clair using Gulf of Mexico applications and techniques to turn in a project, with substantial reduction in costs, and with high regard for safety and the environment."

In the event UK fabricators cannot reduce their costs, BP Amoco will look at yards in the Gulf of Mexico, in Europe, and the Far East, but this would create major political problems.

The water depth at Clair, at 140 meters, and the seabed conditions, permit a fixed platform design. Fowler says that some 30 different configurations have been considered, both in steel and concrete. Eventually a short list of three was picked for final assessment - two bridge-linked steel platforms, a single steel platform, and a single column concrete structure with storage.

The options for the export route are: a pipeline to Sullom Voe, operated by BP Amoco; to Flotta, now operated by Talisman; or by offloading to shuttle tanker, which could go to a terminal or elsewhere. The Magnus EOR gas pipeline would pass close to Clair and a Y-piece could be inserted in case it is decided production should go to Sullom Voe.

The development schedule is:

  • Concept approval - summer 2000;
  • Award of front-end engineering and design contract - summer 2000;
  • Project sanction - May 2001;
  • Construction - 2001 to mid-2004; and
  • First oil - mid-2004.