BIG FUTURE REMAINS FOR NORTH SEA OIL AND GAS

The U.K. North Sea can produce more oil and gas in the next 20 years than it has in the past 20, while British production can stay at more than 2.2 million b/d of oil equivalent well into the next century. With 14,4 fields either on production or approved for development off the U.K., there have been about 500 further discoveries, giving the U.K. more than 15 billion bbl oil equivalent in undeveloped reserves. There is still another 4-25 billion bbl of oil and as much as 45 tcf of gas to be

Sept. 13, 1993

4 min read

With 14,4 fields either on production or approved for development off the U.K., there have been about 500 further discoveries, giving the U.K. more than 15 billion bbl oil equivalent in undeveloped reserves.

There is still another 4-25 billion bbl of oil and as much as 45 tcf of gas to be found, says John Browne, managing director of BP Exploration Operating Co. Ltd.

Browne gave the keynote speech at the Offshore Europe conference and exhibition in Aberdeen last week, giving three keys to unlocking U.K. potential: improved technology, partnerships, and a favorable tax regime.

But a further 30% reduction in capital costs and a 50% reduction in operating costs during the next 20 years will be needed to maintain North Sea activity as envisaged by Browne.

CAPITAL SQUEEZE

U.K. Energy Minister Tim Eggar backed up Browne's call for cost reduction with a warning of a capital shortage in the North Sea.

"Big oil companies are finding difficulty financing all the projects on their books," Eggar said.

Eggar also warned that the North Sea faces increasing competition for development investments from other oil and gas regions.

"A few years ago governments could pick and choose which oil companies were given exploration rights," Eggar said.

Increasingly it is companies that are picking and choosing, while governments are competing in offering better terms for taxes and farmouts, for example.

Regional development organization Scottish Enterprise, Aberdeen, said investment spending on existing and new field developments in the U.K. was relatively high during 1991-93.

"Our research indicates that the U.K. industry now faces a slight decrease in investment spending to 1997," said Mike Fleming, head of Scottish Enterprise's energy group.

"We expect overall expenditure to gradually reduce by less than 1 billion ($1.5 billion) from 8.5 billion ($12.75 billion) in 1993 to 7.7 billion ($11.55 billion) in 1997."

Fleming said exploration, appraisal, development, and production spending on the U.K. continental shelf is expected to total almost 40 billion ($60 billion) for 1993-97.

That compares with worldwide offshore and onshore spending estimated at a total 565 billion ($847.5 billion) for the same period.

Scottish Enterprise' forecasts of drilling and development activity show a slight recovery in exploration and appraisal drilling after a fall when subsidies were abolished in the U.K. budget, while the number of operating fields is set to increase.

ABANDONMENT

Conference delegates heard an innovative approach to abandonment of Argyll field adopted by Hamilton Oil Co. Ltd. This, said the paper by representatives of Hamilton and contractors Stena Offshore Ltd. and Camco Ltd., was the first major well abandonment project in the U.K. North Sea.

Argyll field, in Block 30/24, went on production in 1975. First flow was from two subsea wells in 260 ft of water tied back to the converted Transworld 58 semisubmersible rig, later replaced by the Deepsea Pioneer converted semi.

In 1984 the nearby Duncan and Innes fields were tied back to the Argyll infrastructure. By mid-1992, 35 wells had been drilled on the block, with 18 completed as producers. Eleven were still active and the remainder had been shut in.

Conventional abandonment involves recovering completion equipment and setting plugs through drill-pipe to abandon the well. This takes 810 days.

The authors detailed development of a new abandonment method involving squeezing of productive perforations through production tubing and cementing the completion in place.

Experience showed this method could be completed in 4 days if there were no unexpected well problems. Benefits of the system were said to be:

Reduced cost due to rapid deployment between wells and implementation of a short, simple program.
Reduced risk due to a short, simplified program with little requirement for hardware recovery.

CUTTING REINJECTION

Conoco U.K. Ltd. and Thule Rigtech presented a case history on reinjection of drilling cuttings on Conoco's southern North Sea Murdoch development project, which proved the viability of annular reinjection disposal.

About 38,000 bbl of fluids were reinjected into one well, comprising 18,000 bbl of seawater and other fluids and 20,000 bbl of slurry from drill cuttings. This prevented 2,600 bbl of oil and 6,000 bbl of cuttings from being dumped overboard during development drilling.

The authors concluded that, when government legislation limits the drilling business to zero discharge, cuttings injection will be a viable solution. In the short term, cuttings wash will be the most economical and technically feasible method to meet discharge limits.