Norways Den norske stats oljeselskap AS (Statoil) has decided to use a production semisubmersible to develop gas reserves in the Aasgard oil and gas fields complex in the Norwegian Sea.
In other activity off Northwest Europe, Amerada Hess Ltd. (AHL) claims a first with its replacement of a subsea christmas tree in North Sea Ivanhoe field, using a multipurpose support vessel rather than a drilling rig.
Meantime, two North Sea field development projects involving jack up production platforms have run into problems and are expected to be delayed.
In addition, another floating production system development has been approved for the North Sea, and operators are starting work on two new development programs.
Aasgard development
Aasgard fields have estimated reserves of almost 7 tcf of gas and 800 million bbl of oil. Aasgard oil production is slated to begin in 1998, while gas production is expected to start in 2000.
Norwegian producers gas supply committee expects Aasgard to make a major contribution to the countrys gas exports. The complex is earmarked to supply almost 11 billion cu m/year of gas to Europe.
Statoil said the Aasgard gas semi will likely be the worlds largest floating gas production unit, with design capacities of 36 million cu m/day of gas, 11,000 cu m/day of oil, and 14,000 cu m/day of condensate.
Norways Troll A concrete gas production platform, currently being readied for first gas, is expected to be the worlds largest gas production platform, with design capacity of 100 million cu m/day. It is due on stream in April 1996.
Statoil expects to submit a development plan for the three field complex to government on Dec. 15. It estimates the cost of developing Aasgard at 26.7 billion kroner ($4.17 billion).
Aasgard project involves development of Smoerbukk, South Smoerbukk and Midgard discoveries by Statoil in conjunction with Norwegian independent Saga Petroleum AS.
Statoil and Saga earlier decided to develop Aasgard oil reservoirs using a production ship with capacity to produce and process 175,000 b/d of oil.
Development of Aasgard was recently recommended by the gas supply committee ahead of other prospects in order to meet scheduled gas supply commitments to Europe (OGJ, Nov. 27, p. 28).
Aasgard development is seen as key to development of gas resources in fields off Central Norway, where oil production is under way and being transported with shuttle tankers, but where no gas export infrastructure exists (OGJ, Oct. 9, p. 29).
Statoil said that besides having a gas production semi and an oil production ship, Aasgard also would have the worlds most extensive subsea production facilities with about 60 wells drilled through templates.
Development plans call for the production ship and topsides to be ordered early in 1996.
Long term contracts
Meantime, Statoil let contracts worth a total $65 million to Halliburton Oilfield Services Inc., Tanager, Norway, covering all the operators pipeline commissioning and well testing services for the next 5 years.
The $40 million pipeline commissioning contract covers 1996-2000 and includes work on the 12.5 km, 20 in. Sleipner West Roer pipeline and the 860 km, 42 in. Norfra trunkline, intended to take additional Norwegian gas to France.
A $25 million contract covers all Statoils well testing requirements on platforms and rigs, beginning Dec. 1 and running for 3 years with a 2 year extension option.
The work will include supply, management, and engineering of drill stem test tools and associated tubing conveyed perforating, well cleanup, and production testing services.
Among the big projects lined up for the contract period is testing of appraisal wells in the Aasgard fields, and on Norwegian Sea and North Sea blocks to be awarded around yearend under Norways 17th licensing round.
Ivanhoe work
Ivanhoe field lies on U.K. Block 15/21 and was developed by AHL along with Rob Roy and Hamish fields, using subsea manifolds tied back to a converted production semisubmersible.
Ivanhoe field was brought into production in July 1989 with original estimated reserves of 130 million bbl of oil and 70 bcf of gas. Recent production from the three fields has averaged 45,000 b/d of oil and 18 MMcfd of gas.
AHL contracted Coflexip Stena Offshore Ltd., Aberdeen, to replace a subsea christmas tree in Ivanhoe fields IK28 production well using the MSV Stena Seawell dynamically positioned monohull vessel.
Conventional intervention would involve mobilizing a diving support vessel (DSV) to disconnect the tree, bringing in a mobile drilling rig to recover and replace the tree, then bringing back the DSV to reconnect the well.
Instead AHL used Seawell, which carries a workover derrick, heavy lift cranes, and facilities to support 18 saturation divers. The vessel is certified to recover hydrocarbons to the surface.
The Seawells crew set plugs and killed the well, disconnected and recovered the tree for maintenance and refurbishment, then installed and hooked up a replacement tree. After production logging and reperforation of the well, mechanical and cement plugs were set and the well returned to production.
Tony Ward, AHL production director, said, This is a significant step forward in the servicing of subsea wells, and is of particular value to Amerada Hess, which operates a high proportion of subsea wells on its field developments.
The utilization of a dynamically positioned monohull vessel produces considerable benefits in both time and cost over more traditional methods, which require the deployment of a conventional mobile drilling rig.
A Coflexip Stena official said the main benefit to AHL was the mobility of Seawell in comparison with a rig.
There was a considerable time saving in mobilization, he said. A dynamically positioned vessel can just drive onto a location and start work, while a rig requires anchor handling operations. Also, to use a rig for a tree changeout, you would require a DSV at the front and back end of the work.
Further cost savings were achieved by using Seawell to carry out inspection and maintenance work on the fields manifolds while on location.
Yme
Statoil believes oil from Yme field will not flow until the first half of January. Yme was intended to go on stream in September.
Yme, on Block 9/2 off Norway, holds estimated reserves of 36 million bbl of oil. An 11 million bbl satellite will be tied in to the Yme platform, and three other satellite prospects have been identified.
The Maersk Giant jack up has been converted to produce Yme field, with processed oil to be stored in the Polysaga tanker ready for export by shuttle tankers.
Statoil had hoped to require only 4 weeks from departure of the rigwhich occurred early in November after delays in conversion workfrom the construction yard to first oil.
Statoil now sees it will not be able to begin production until next year because modifications were not finished at the yard.
Harding
BP Exploration Operating Co. Ltd. has been delayed by weather in completing work on Harding field development in the U.K. North Sea.
Harding development calls for use of a TGP 500 design production jack up mounted on a T-shaped concrete tank designed to store as much as 500,000 bbl of crude oil (OGJ, Aug. 15, 1994, p. 57).
The jack up is in a fjord off Stavanger awaiting a 5 day weather window in which it can be towed to the field and mated with the base that was installed last summer.
BP said Dec. 5 a suitable weather window was expected in 2 days, but there have been many false starts.
BP has written off hopes of starting production by yearend, because even after the platform is installed and its helideck fixed in place, it will take at least 45 days of drilling before oil can flow.
Harding, on U.K. Block 9/23, has estimated reserves of 185 million bbl of oil and 200 bcf of gas. The platform will be able to process 64,000 b/d of oil. Exports will be by shuttle tanker.
Banff
Conoco (U.K.) Ltd. plans to develop Banff field on Block 29/2a, using a production semisubmersible with shuttle tanker offtake during an early production phase (OGJ, Dec. 11, p. 37).
Banff field reserves are estimated at 20-110 million bbl of oil. Conoco said about 5.5 million bbl of oil will be recovered during early production, with first oil slated for August 1996.
The early production phase is expected to last 6 months, during which Conoco will charter a production unit from a combine of Sedco Forex, Schlumberger Evaluation & Production Services, and Coflexip Stena Offshore Ltd.
Two deviated wells are to be drilled for the early production period. These are expected to yield as much as a combined 35,000 b/d. The reservoir lies in Paleocene sands at 4,500-7,600 ft.
The Stena Savonita shuttle tanker will be chartered for use in early production. It can hold almost 750,000 bbl of oil and will be linked to the production rig by a 1,500 m flow line.
Banff associated gas will be flared during initial production, but options for export of the gas are to be studied as part of full field development.
Three wells drilled to date in Banff are expected to be used in the full production phase, expected to last more than 7 years, while the two early development wells also will be tied in to any new development.
Banff partners are operator Conoco 31.7%, Ranger Oil (U.K.) Ltd. 26.2%, Enterprise Oil plc 25.9%, Hardy Oil & Gas plc 12.4%, Amoco (U.K.) Exploration Co. 2%, and Santos Europe Ltd. 1.8%.
Alba
Chevron U.K. Ltd. has spudded the first of 17 development wells from a platform in northern Alba field as a means to tap reserves in the southern part of the reservoir.
Originally, Chevron expected it would need to install a second platform in Block 16/26 Alba field at a cost of 900 ($1.4 billion), but the company says advances in extended reach drilling have allowed development costs to be cut by at least two thirds.
Announcing the Alba southern development program earlier this year, Chevron said first oil from the southern wells is expected early in 1996.
Now the company has received government permission to begin production from the first southern well. This is expected to produce as much as 20,000 b/d, starting this month.
Because only 24 well slots were available on the Alba platform, Chevron modified four slots to allow drilling of two wells from each. These use larger than normal shared conductors.
Alba currently produces as much as 75,000 b/d of oil using a steel platform and oil storage tanker with offshore loading of oil into shuttle tankers for export (OGJ, Jan. 31, 1994, p. 46).
Development of the southern part of the reservoir is expected to require an expansion of platform processing capacity to 100,000 b/d. Another processing plant has been installed to handle increased capacity while water cuts remain low.
Chevron intends initially to complete subsea one production well and two water injectors. Five or six additional subsea completions are envisaged if drilling beyond an 18,500 ft target is impractical.
As water injection from the southern reservoir increases with time, Chevron anticipates addition of a further production plant on Alba platform or installation of a small bridge linked platform by about 1999.
Erskine
The Santa Fe Monitor jack up arrived in the North Sea in late November to begin a 212 year program to drill six development wells for Texaco Ltd. on U.K. Block 23/26a Erskine field.
The U.K. government approved development of Erskine last May. A 290 million ($450 million) program will involve installation of a not normally manned platform tied back to Amocos Lomond platform 19 miles north.
Erskine holds estimated reserves of 330 bcf of gas and 75 million bbl of condensate. First production is expected in late 1997 from what will be the first high temperature/high pressure gas field development in the North Sea.
Erskine gas lies in Jurassic sandstone at 15,000 ft. Bottomhole pressure is 14,000 psi, temperature 350 F.
Produced gas and liquids will move through a 16 in. multiphase line to Lomond for processing. Liquids will be exported via BPs Forties system to Cruden Bay, while gas will be sent via Amocos CATS system to Teesside, U.K.
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