Gas developments highlight NW Europe action

Magellan jack up rig and Safe Lancia accommodation semisubmersible are stationed alongside Armada platform for development drilling and crew quartering, respectively, during platform commissioning. First gas and condensate from Armada's Fleming, Drake, and Hawkins fields were produced Oct. 1. Photo courtesy of BG Exploration & Production.

Development action continues apace off Northwest Europe,

Off the U.K., BG Exploration & Production Ltd. began gas production on Oct. 1 from Armada development centered on North Sea Block 22/5b.

Work under redevelopment of Brent field was completed late last month, as Shell U.K. Exploration & Production restarted production from Brent D platform.

In action off Norway, Saga Petroleum AS announced a plan to extend development of Snorre field. And Statoil and Saga plan to merge four Norwegian Sea gas/condensate discoveries to develop them more quickly as one project.

Armada

Development of Armada cost £430 million ($690 million). The original budget was £537 million ($860 million), but this was cut through incentive deals with contractors.

The operating cost for Armada is also expected to be among the lowest in the North Sea at less than $3/bbl. Much of this is attributed to low personnel costs: the platform has a crew of only 29 (OGJ, Nov. 18, 1996, p. 30).

Armada development involves one steel platform depleting three fields-Fleming, Drake, and Hawkins-with combined reserves estimated at 1.2 tcf of gas and 70 million bbl of condensate. As much as 450 MMcfd of gas will be produced and exported via Everest field riser platform through the Central Area Transmission System pipeline to Teesside, U.K. (see map, this page). Condensate and natural gas liquids will be separated on Armada platform and exported at rates of as much as 26,000 b/d via Everest and the Forties oil pipeline system to Cruden Bay, Scotland. Armada interests are operator BG 45.27%, Amoco (U.K.) Exploration Co. 18.2%, Fina Exploration Ltd. 12.53%, Phillips 11.45%, Yorkshire Electricity Ltd. 6.97%, and Agip (U.K.) Ltd. 5.58%.

Brent return

Shell Expro, operating joint venture of Shell U.K. Ltd. and Esso Exploration & Production U.K. Ltd., resumed production from Brent D platform on Sept. 21.

Delta platform was the last of three platforms in the field to be shut down for extensive upgrading under a £1.2 billion ($2 billion) redevelopment program begun in 1993 (OGJ, Apr. 12, 1993, p. 28).

Redevelopment has involved replacing much of the process equipment on three platforms to operate at lower gas pressures and renovating Brent A platform to act as a gas gathering platform. Shell/Esso's aim is to reduce pressure in the Brent reservoir, to help in exploiting remaining oil pockets and transforming the field into one of Europe's largest gas producers.

Brent D output is expected to build gradually in coming months, to plateau at about 50,000 b/d of oil and 220 MMcfd of gas. With Delta back on line, Brent is expected to produce an average 160,000 b/d of oil and more than 600 MMcfd of gas the next 12 months.

Jorn Berget, Brent field general manager, said: "Although the main engineering work is almost complete, there is still a lot to be done. We are still a few weeks away from resuming gas export, and there will be an ongoing well engineering program, including a £100 million ($160 million) project to pump water from the reservoir, to ensure we achieve maximum recovery of oil and gas."

Snorre plan

Saga plans 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 tension-leg platform (TLP) and subsea production unit. These export oil and gas by pipeline to Statfjord platform, operated by Statoil. Saga says the semi will be located about 9 km north of the TLP and will be used to recover about 360 million bbl of oil and some gas. Snorre 2 platform start-up is slated for summer 2000.

The new platform will have capacity to produce 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 and Energy are expected by yearend. Saga hopes the plan will be approved by Storting in spring 1998.

The operator intends to invite bids for construction of the production semi shortly and expects to award the contract early in 1998. Snorre 2 development is expected to cost 10-11 billion kroner ($1.4-1.5 billion).

Haltenbank South

Only a week after Saga decided to develop its Kristin and Lavrans gas and condensate finds with a shared TLP, the company agreed to expand the project to include Statoil's Trestakk, Tyrihans North, and Tyrihans South finds. Saga chose a TLP in preference to a floating production, storage, and off- loading vessel after "an overall consideration of economy, safety, resource utilization, operation, flexibility for tie-in of additional reserves, and schedule" (OGJ, Oct. 6, 1997, p. 38).

The two companies have agreed to combine Kristin, Lavrans, Trestakk, and Tyrihans for development as Haltenbank South project. Saga will be operator of field developments, and Stat- oil will operate gas and condensate export pipelines and terminals. Statoil will begin work with a study of transport prospects from the fields. The companies plan to submit a development plan next June. They envision a TLP in Kristin, with satellite subsea developments in Lavrans, Trestakk, and Tyrihans (see map, this page).

First production is slated for 2001. Combined reserves for the discoveries are estimated at 200 billion cu m of gas and 100 million cu m of oil and condensate.