PRT REFORMS BOLSTER BP DEVELOPMENT PLAN

Development of a group of nine Central North Sea oil and gas fields got a boost from changes in the U.K. petroleum revenue tax (PRT). Operator BP Exploration Co. Ltd. last week disclosed a green light for the l.5-2 billion ($2.25-3 billion) Eastern Trough Area Project (ETAP). BP envisages development approval early in 1993 and start of production in 1998. Meantime, BP Norway Ltd. SA carried out first field trials of a new chemical drag reducer (CDR) that yielded water injection rate increases

May 17, 1993

5 min read

Development of a group of nine Central North Sea oil and gas fields got a boost from changes in the U.K. petroleum revenue tax (PRT).

Operator BP Exploration Co. Ltd. last week disclosed a green light for the l.5-2 billion ($2.25-3 billion) Eastern Trough Area Project (ETAP). BP envisages development approval early in 1993 and start of production in 1998.

Meantime, BP Norway Ltd. SA carried out first field trials of a new chemical drag reducer (CDR) that yielded water injection rate increases of as much as 65%, with 25-50% improvement being typical.

Four water injection wells on BP's Gyda platform, in Norwegian North Sea Block 2/1a, underwent separate trials.

ETAP PLANS

A BP Exploration spokesman said some of the ETAP fields would have been liable to PRT under the old tax regime. So the reforms, which scrapped PRT on new fields, made a significant reduction in development costs.

The reforms also created a simpler tax system, making it easier to set up a commercial structure for ETAP, which has a number of partners in different license agreements.

ETAP involves a cluster of four sizable fields and five smaller fields in adjacent blocks. The four main fields are BP's Marnock, Mungo, and Machar fields, and Heron field operated by Shell U.K. Exploration & Production, the Shell/Esso U.K. plc combine.

The five small fields are the BP operated Monan and Medan fields and an unnamed discovery, along with Shell/Esso's Skua and Scoter fields. BP estimated combined ETAP reserves at 650 million bbl of oil and gas equivalent, including 1.2 tcf of gas.

BP led a feasibility study for ETAP, which came out in favor of a single processing and export platform in Marnock field, with other fields tied back as unmanned process platforms or subsea developments (OGJ, July 27, 1992, Newsletter).

ETAP partners expect to complete agreement on joint development of the fields soon. The next step is to agree on a transportation route for produced oil and gas.

Options are thought to include export of liquids via BP's Forties pipeline to Cruden Bay, England, and export of gas and condensate via Shell/Esso's Fulmar field pipeline to St. Fergus, Scotland, or via the Central Area Transmission System pipeline, operated by Amoco (U.K.) Ltd., to Teesside, England.

Marnock field lies in Blocks 22/24a and 22/24b, Machar in Block 23/26a, Mungo in Blocks 23/16a and 22/20, Monan in Block 22/20, Medan in Block 23/22a, Heron in Blocks 22/29 and 22/30, Skua in Block 22/24b, and Scoter in Block 22/30d.

BP will operate ETAP on behalf of partners Shell/Esso, Agip (U.K.) Ltd., Fina Exploration Ltd., Hamilton Oil Co. Ltd., Murphy Petroleum Ltd., Lasmo plc, and Monument Oil & Gas plc.

Chris Gibson-Smith, BP Exploration's chief executive for Europe, said the ETAP fields are early examples of BP development projects made more likely as a result of PRT reforms.

He said, "We are also looking at a number of other projects where the tax changes will encourage development through a mix of field economics and improved cash flow from our North Sea operations overall."

CDR TRIALS

The CDR BP chose for the Gyda trials is a long chain polymer developed by Conoco Specialty Products Inc. It is designed to reduce turbulence--and therefore energy loss--in drilling fluids.

Gyda field served as trial site because its water injection capacity of 150,000 b/d exceeds the maximum of about 82,000 b/d injection possible with six injection wells before the four-well trial.

The best result was an increase in injection rate to 16,000 b/d from 9,500 b/d to 16,000 b/d in one well. After the trials, this well was chosen for a long term test. With CDR in use in this well, and the other trial wells operating normally, total water injection rate increased to 89,000 b/d from about 82,000 b/d.

"The technique is not in itself entirely new, but it is the first time this new generation of chemicals has been used in this application," said Chris Kalli, head of BP Norway production facilities.

Because there is no sure way to predict whether injected chemicals will block a well completely, other companies have been reluctant to try out this new CDR, Kalli said.

However, BP research showed that contamination in injection water was not as critical as is commonly thought. Also, BP's knowledge of fracture progression and the belief that this polymer's molecules most likely would break up in the event of a blockage lessened this risk.

"Extrapolating the results, this technique should result in major revenue increases-up to about 30%, depending on facilities capacity--for fields that use waterflooding," Kalli said.

"For new fields it could reduce the number of water injection wells required by up to 30%, provide improved waterflood support in early development stages, and reduce topsides costs as a result of lower delivery pressures needed."

BP used other CDR products to perform similar trials in Magnus field in U.K. Block 211/12a at the same time. Kalli said similar results were achieved.

A permanent multiwell injection system is being planned for Gyda platform. This will go on stream in the fourth quarter.

BP expects Gyda field to show a 15-30% increase in oil revenues for 1994 as a result of the program. Current production is about 60,000 b/d.