Another oil and gas reservoir has joined the growing list of producing fields in the U.K. North Sea.
More field development projects are on tap in the U.K. and Norwegian sectors of the sea. But a production schedule has been sidetracked off the U.K. Here are the latest reports:
- Lasmo North Sea plc, London, placed its U.K. North Sea Birch field on stream Sept. 15 ahead of schedule and under budget. The field, in Block 16/12a, is a subsea satellite of South Brae field.
- Subsea development programs are in store for one field off Norway and one off the U.K. Norwegian independent Saga Petroleum AS submitted a plan to Norway's Ministry of Industry & Energy for development of East Tordis field on Block 34/7. Mobil North Sea Ltd. disclosed plans to develop Nevis field, which lies in U.K. Blocks 9/12 and 9/13, at a cost of 66 million ($99 million).
- Phillips Petroleum Co. U.K. Ltd. may have to defer start-up of oil and gas production from Judy/Joanne fields development after Enron Europe Ltd. decided to take no gas for the first year of its purchase contract.
Birch production
Lasmo's Birch field, with estimated reserves of 47 million bbl of oil equivalent, will produce 23,000 b/d of oil and 60 MMcfd of gas.Birch fluids move via pipeline 14 km to Brae platform, operated by Marathon Oil U.K. Ltd., for processing. Crude oil and natural gas liquids are then sent through via the Brae and Forties pipelines to Kinneil terminal.
Gas sold to the Brae license group enters the Scottish Area Gas Evacuation (SAGE) export pipeline from Brae to St. Fergus.
Lasmo said it placed Birch on stream 2 weeks ahead of schedule and at least 20 million ($30 million) below the original development budget of 140 million ($210 million). Early flow is from two production wells connected via a subsea manifold to Brae A platform. One water injection well is in use.
Lasmo plans to drill two more wells next year to boost Birch production. One will be a producer, the other a water injector.
David Thomas, Lasmo production operations manager, said his company intends to study development plans for small discoveries -- Larch, Pine, and Elm -- in the Birch area's Block 16/12a.
"These are not as good as Birch," Thomas said. "If they are developed, they are likely also to be subsea tiebacks. There is a chance license partners will agree to drill further wells here next year."
Lasmo has installed a Y-piece in the export pipeline from Birch to Brae to enable future tie-in of possible development in the Larch prospect.
Block 16/12a partners are operator Lasmo 46.8%, Deminex U.K. Oil & Gas Ltd. 35.5%, Hardy Oil & Gas (U.K.) Ltd. 14.9%, and Hardy North Sea Ltd. 2.8%.
Subsea developments
Total expected outlay for Saga's East Tordis field development program is 500 million kroner ($78 million). First oil is slated for summer 1997, with flow expected to rise quickly to about 25,000 b/d of oil.East Tordis holds estimated reserves of 34 million bbl of oil. Saga said the breakeven development cost would work out to $7.7/bbl.
Saga plans to develop East Tordis with a four slot subsea template linked to existing subsea infrastructure in nearby Tordis field.
One production well will be used for East Tordis and possibly a water injection well. This leaves two well slots free to tap other reserves in the area.
East Tordis oil will join production from Tordis to be piped to Statoil C platform, operated by Norway's Den norske stats oljeselskap AS, for processing, storage, and export. Of the U.K. subsea project, Mobil North Sea Chairman Lance Johnson said, "Nevis has been on the drawing board a long time. It is only recently that improved technology and lower development costs have combined to enable the project to go ahead."
Nevis holds estimated reserves of 50 million bbl of oil, 1.8 million bbl of condensate, and 175 bcf of gas in two reservoirs.
The field will be developed in two phases. South Nevis will be a two well subsea development tied back to Mobil's Beryl Alpha platform, 7 km east.
Mobil has slated first oil from South Nevis for October 1996 and expects production to reach 13,500 b/d of oil.
Reservoir performance will be monitored as a guide for future development work. Mobil anticipates an eight-well subsea cluster will be needed to boost oil production to 23,000 b/d in 1999 and gas production to a peak of 53 MMcfd in 2003.
Subsea wells will be maintained using an intervention system deployed by a remotely operated vehicle. This was developed in conjunction with Kvaerner FSSL Ltd., Aberdeen.
Phillips delay
Phillips is pursuing two alternatives to place Judy/Joanne fields on stream without gas sales to Enron. One option could lead to start-up on time but at reduced volumes. The other could cause a year's delay.Judy/Joanne is to produce associated gas. So liquids production is affected by lack of gas delivery because Judy platform has no facilities to inject gas. production.
Phillips is developing Block 30/7a Judy and Joanne fields with a platform in Judy with a link to a subsea manifold in Joanne. Production start was slated for early 1996 (OGJ, June 12, p. 38).
Enron announced Sept. 14 it will take no gas during Oct. 1, 1996-Sept. 30, 1997. The company made no estimate of its gas nomination under the second year of the contract, to end Sept. 30, 1998.
Enron declined to say why it had chosen not to take delivery of Judy/Joanne gas. However, the announcement came after a plunge in U.K. spot market gas prices because of a glut of gas (OGJ, July 24, p. 16).
A spokeswoman for Enron Europe said negotiations are under way with Phillips over the issue. No claim for compensation can be made by Phillips, she said, because Enron acted "within the letter of the contract."
Meanwhile, Phillips said Judy and Joanne start-up volumes may be delayed or lower than planned. Oil flow was expected to surge to 95,000 b/d, then fall to average 65,000 b/d in the first year.
Enron was to have taken as much as 260 MMcfd of gas.
Phillips has two alternatives to place Judy/Joanne on production.
The first option revolves around the fact that the Block 30/7a gas reservoir spills over into adjoining Block 30/6b. The latter block is owned by the same Phillips group, but its gas is not dedicated to Enron.
"So even if Enron chooses to pay and not take gas from Block 30/7a," said a Phillips spokesman, "Phillips is free to produce gas from Block 30/6b. And if we produce gas from 30/6b, we will therefore be able to produce liquids from 30/7a."
Phillips was said to be talking to the Central Area Transmission System (CATS) pipeline partners and a number of potential purchasers about Block 30/6b gas sales. Enron also has been approached as a potential processor of this gas because of its terminal on CATS.
The Phillips spokesman said production of liquids with Block 30/6b gas would enable Judy/Joanne to start up according to schedule.
Early production volumes would be lower than planned, though, at an estimated 35,000-40,000 b/d of oil and with targeted sales of 100-150 MMcfd of gas.
A second alternative is injection of Block 30/7a gas earmarked for use by Enron, which would allow production of Judy/Joanne liquids even if gas production were deferred.
The spokesman said installation of gas injection facilities on Judy platform likely would cost about 50 million ($75-80 million). Under this option, Judy/Joanne start-up would be de- layed until 1997.
"In the absence of any production," said the spokesman, "Phillips will be receiving payments under the gas sales agreement annually, in arrears, each fall." License interests in Blocks 30/7a and 30/6b are operator Phillips 36.5%, Agip (U.K.) Ltd. 33%, and British Gas Exploration & Production Ltd. 30.5%. Copyright 1995 Oil & Gas Journal. All Rights Reserved.