SHELL/ESSO EYE BRENT REDEVELOPMENT

Shell U.K. Ltd. and Esso U.K. plc will spend El.3 billion ($1.95 billion) to redevelop Brent, the U. K.'s biggest oil field.

The project will entail a major refurbishment of the giant field's four large platform topsides.

Shell U.K. Exploration & Production, operator for the Shell/Esso combine, will begin a unique 5 year engineering program that will transform Brent into a gas field and extend field life at least 10 years.

"The Brent redevelopment is a landmark in world oil history," said Chris Fay, managing director of Shell Expro, sole developer of Brent field. "It is a daunting task, far more difficult than developing a new field. This pioneering project will rejuvenate a field that will now remain a major national asset for longer than was originally expected. "

Shell/Esso said there is no precedent in the oil industry for a scheme to unlock substantial new reserves of oil and gas from a major offshore oil field by lowering reservoir pressure and rebuilding facilities on a massive scale while production continues.

OTHER NW EUROPE OFFSHORE

Meantime, North Sea oil output has rebounded sharply from a troubled start to the year. North Sea oil production rose to an average 4.369 million b/d in February from 4.096 million b/d in January, when bad weather halted production from fields dependent on tanker offloading (OGJ, Jan. 25, p. 44).

In other activity off Northwest Europe:

Elf Enterprise Caledonia Ltd. was forced to stop production from its North Sea Claymore and Scapa fields when a standby vessel lost power and collided with an accommodation vessel.
BP Exploration Operating Co. Ltd. gave the green light Apr. 2 for development of Forth oil field on North Sea Block 9/23b at a cost of 400 million ($600 million).
Conoco (U.K.) Ltd. on Mar. 25 brought on stream the second of three fields to be developed via Ninian field facilities on North Sea Block 3/3.
Texaco North Sea U.K. Co. marked a milestone en route to 1993 start-up of Strathspey oil field in the U.K. North Sea.
BP claimed the U.K. record for horizontal well displacement with its North Sea Hyde 48/6-36Z development well.
AS Norske Shell contractor Aker AS mated Norway's Draugen field platform topsides and concrete gravity base structure (GBS) in the deepwater Vats fjord site of Norwegian Contractors AS on Mar. 27-28. Draugen is in the Haltenbanken area of the Norwegian North Sea.

PRODUCTION

Brent field, which lies in 460 ft of water on North Sea Block 211/29, provides 13% of U.K. oil and 10% of U.K. gas. In 1993, oil production will average 219,000 b/d. Output peaked in 1985-86 at 416,000 b/d. When redevelopment ends in 1998, oil production will be down to 165,000 b/d.

Gas production reached its British Gas plc contract level of 500 MMcfd in 1986. Brent produces more gas than any other U.K. oil field. Among U.K. gas fields only British Gas' Morecambe and Shell/Esso's Leman produced more last year.

Brent produces from two reservoirs at respective depths of 8,700 ft and 9,400 ft that extend north-south for 10.5 miles and are 3.1 miles across at their widest point.

The field's four platforms have slots for 154 wells, of which 138 have been drilled. Waterflooding is currently under way, although this will become noncommercial in 1998.

The Brent System oil pipeline transports about 630,000 b/d of oil from 10 fields with 13 platforms, of which six fields and nine platforms are operated by Shell/Esso. It moves the crude 92 miles via Shell/Esso Cormorant A platform to Sullom Voe terminal in the Shetland Islands.

Gas is collected from 11 fields, four operated by Shell/Expro, and fed into the Far North Liquids and Associated Gas System (Flags) at Brent A platform. It is then sent 278 miles to St. Fergus processing plant, north of Aberdeen.

DEPRESSURIZATION

Because of Brent's high gas to oil ratio, Shell/Esso plans to lower pressure in the reservoirs beginning in 1997, from 5,500 psi to 1,000 psi by 2010.

That will in effect take Brent gas out of solution, enabling recovery of oil and gas reserves that were otherwise unrecoverable. Shell/Esso estimated the added reserves at 34 million bbl of oil and 1.5 tcf of gas, equivalent to a small oil field and a sizable gas field. These boost Brent's ultimate recoverable reserves to 1.976 billion bbl of oil, 5.523 tcf of gas, and 620 million bbl of NGL. About 73% of recoverable oil and about 45% of recoverable gas have been produced.

When production began in 1976, it was thought production would end in 1998. By the time the field is abandoned sometime during 2008-2015, about 55% of reserves in place will have been recovered and 80% of gas.

Depressurization will begin in 1997, when two platforms will have been converted to low pressure facilities. Water injection will be stopped and reservoir pressures allowed to fall, freeing increasing volumes of solution gas from remaining oil.

The rate at which this will happen is uncertain, said Shell/Esso. Because reservoir pressure will have dropped, however, producing oil wells will be used for injection of gas to raise fluids to the platforms for separation.

Controlling water flow from the reservoirs' aquifer is crucial to maintaining the best pressure depletion rate. Water be will removed through wells previously used for injection with the aid of submersible pumps.

Shell/Esso said one of the most sophisticated reservoir modeling computer programs in the oil industry has been devised to guide depressurization.

PLATFORMS

Brent has four platforms in a line running south to north. Brent Alpha is the furthest south, smallest, and lightest-a steel structure weighing 30,000 metric tons. Production capacity is 100,000 b/d. First production was June 1978.

Next in line is Brent Bravo, a 195,000 ton concrete Condeep platform, which began production in November 1976. Production capacity is 180,000 b/d and storage capacity 1.1 million bbl of oil.

Further north is Brent Charlie, a 320,000 ton concrete platform that began production in June 1981. Capacity is 240,000 b/d production and 600,000 bbl storage.

Northernmost Brent Delta is a twin of Bravo, beginning production in November 1977. Weight is 207,000 tons, production capacity 150,000 b/d, and storage capacity 1.1 million bbl of oil.

A storage and loading buoy, Brent Spar, enabled offshore loading from 1976 until opening of the oil pipeline in November 1979. It lies 1.8 miles from Alpha and 1.5 miles from Bravo. Weight is 65,000 tons and storage capacity 300,000 bbl of oil.

A gas flare structure serves Alpha and Bravo platforms. It lies 1.9 miles from Alpha and 1.6 miles from Bravo and weighs 1,250 metric tons.

REFURBISHMENT

Depressurization requires major replacement of equipment on three Brent platforms, while all four need upgrading in line with current North Sea safety requirements and replacement of aging topsides.

Shell/Esso said there were no problems with platform substructures, which were designed to outlive anticipated field life.

Besides installation of low pressure production equipment, greater gas handling capacity is required as the pressure drops. The gas contract level will be increased to 600 MMcfd.

Gas is currently produced on all four platforms. After depressurization, only three platforms will be needed for gas production. There will be a dramatic reduction in complexity of processing, said Shell/Esso, bringing considerable cuts in running costs.

Bravo, Charlie, and Delta platforms will be refurbished for low pressure gas production. Each will undergo a year of preparatory work prior to shutdown for a year.

Only one platform will be out of commission at the outset. Bravo will close first in mid-1994, followed by Charlie, then Delta. Bravo and Charlie will be ready for low pressure production by the end of 1996, with Delta ready by the end of 1997. Any two platforms will be able to meet the winter maximum gas demand.

Alpha platform will be upgraded, but not converted to low pressure gas production. It will continue to drain the southern section of the reservoir at high pressure and to produce from a southern extension of the Brent reservoir. It will also remain as the gathering point for the gas pipeline network.

Early next century, as depressurization continues, production from Alpha will cease to be viable and production will be ended.

New process modules for oil and gas separation and gas compression and treatment will be installed on the southern sides of Bravo, Charlie, and Delta platforms. Living quarters will be sited at the north side, in line with current safety thinking (OGJ, Dec. 14, 1992, p. 25).

Decks on these three platforms will be strengthened to accommodate 3,500 ton process modules, each 1,300 tons heavier than existing equipment.

"Almost half of Britain's oil and a third of its gas comes from fields that started production in the 1970s," Fay said. "Output from them is falling, and increased maintenance for aging facilities means higher running costs.

"At a time when oil prices are static, innovative methods are needed to ensure that producing extra resources from declining fields will be economically justified."

NORTH SEA PRODUCTION

Total Norwegian production of crude oil and condensate production averaged 2.21 million b/d in February, said Wood Mackenzie Consultants Ltd., Edinburgh, up 107,000 b/d from January's level. This was due largely to the return of Statfjord, Snorre, and Oseberg fields to normal production levels.

U.K. offshore production in February was 1.975 million b/d, up from 1.806 million b/d in January. Piper field returned to production, averaging 20,700 b/d in February, according to Royal Bank of Scotland plc (OGJ, Feb. 8, p. 31).

Danish oil production was down to 160,000 b/d from January's average 162,000 b/d, while Netherlands output fell 1,000 b/d to 26,000 b/d.

Norwegian gas production fell 14 MMcfd from January's average to 2.916 bcfd in February, said Wood Mackenzie. Month to month gas production declines also occurred in the U.K., from 8.688 bcfd to 8.5 bcfd, and in the Netherlands, from 1.989 bcfd to 1.906 bcfd. Meantime, Danish gas production rose from 316 to 484 MMcfd. Production of gas off Ireland rose from 235 MMcfd to 272 MMcfd.

CLAYMORE/SCAPA PROBLEMS

The Cam Sentinel standby ship began to drift at 6:40 p.m. Mar. 28 and collided with MSV Tharos accommodation vessel, which was standing off Claymore platform on Block 14/19. Waves were more than 20 ft high and wind speed was 30-40 knots.

No one was injured, said Elf Enterprise, although both vessels sustained damage. AR 135 nonessential crew members were flown ashore by helicopter, leaving 67 on board Tharos.

Production from Claymore and its satellite Scapa field was halted. Output had been 53,000 b/d and 36,000 b/d of oil, respectively. Production from Scapa was resumed at 10:40 a.m. Mar. 29 and from Claymore 20 min later.

Tharos received a 3 in. gash above the waterline on one of its eight columns. Temporary repairs were completed within 1 hr of collision. Sentinel regained power but was towed to Invergordon for repairs to steering gear.

Elf Enterprise said an investigation is under way to establish the cause of the accident.

FORTH DEVELOPMENT APPROVED

A heavy duty steel jack up production unit, designed by Technip Geoproduction SA, Paris, will be used to develop Forth field. This will be mounted on a 500,000 bbl capacity concrete gravity storage tank.

Most output will be transported via a submerged turret offshore loading system, although field partners are considering a 10 in. diameter pipeline fink to Forties system 7.5 miles away. Two 97,000 dwt shuttle tankers will remove stored oil.

Forth was at first considered noncommercial after discovery in 1988, but BP said innovative development and project management along with horizontal drilling helped reduce development costs to among the lowest in the North Sea (OGJ, Mar. 22, p. 27).

Production is scheduled to begin in early 1996, peaking at 60,000 b/d of oil within 6 months. Eight horizontal production wells and five water injectors will be used to recover 187 million bbl of oil from two reservoirs in the first phase of development.

Gas reserves of 200 bcf will be developed once the oil is gone. Field life is estimated at 20 years. BP said another 15-40 million bbl of oil lies in satellite formations on the same block.

Forth field partners are: operator BP Exploration 70%, Repsol SA 25%, and Ranger Oil (U.K.) Ltd. 5%.

FOURTH CONTRACTS

For the Forth project, BP let a 25 million ($37 million) contract for detailed design and procurement work on the proprietary TGP 500 production unit to Technip and McDermott Engineering (Europe) Ltd., London.

The 50 million ($75 million) concrete base will be built at Hunterston, Scotland, by Costain Engineering Ltd. and Taylor Woodrow Ltd. Delivery will be in summer 1995.

A 70 million ($105 million) steel superstructure will be built by Hyundai Heavy Industries Co. Ltd. Smedvig Ltd., Aberdeen, won the 16 million contract for design and operation of the drilling package.

Other contracts related to the Forth project are: Cooper Rolls of Bootle, U.K., an 11 million ($16.5 million) contract to supply the power generation plant; ABB Process Automation Ltd. Stevenage, U.K., to supply a 5 million ($7.5 million) platform control system; Weir Pumps Ltd., Glasgow, to supply pumps worth L2 million ($3 million); and Det norske Veritas, to provide the 1 million ($1.5 million) certification contract.

CONOCO DEVELOPMENT

Conoco (U.K.) Ltd. disclosed first production from Lyell field in Block 3/2.

The field has an estimated 400 million bbl of oil in place, but only 40 million bbl is recoverable because of heavy faulting and poor permeability.

Output from Lyell reached 10,000 b/d through one well. Further wells will be drilled and tied in to achieve 18,000 b/d peak production in the fourth quarter. The Neddrill 6 semisubmersible rig is drilling development well 3/2-A02.

Conoco plans to recover about 30 million bbl through this first phase of production while assessing viability of other parts of the reservoir, which is split into five main sections. Water depth is 480 ft.

Lyell's subsea facilities allow for 15 production and water injection wells. These are connected to a manifold from which three flowlines, a methanol line, and a control system umbilical extend to South Ninian platform 9 miles away.

Chevron U.K. Ltd. is operator of Ninian, a giant field developed in the late 1970s using one concrete and two steel platforms. Peak production was 316,000 b/d of oil in 1982, while gas peaked at 13 MMcfd in 1983.

Third party subsea developments enabled Chevron to extend the lifetime of Ninian, which currently produces about 65,000 b/d of oil and natural gas liquids. Chevron receives a tariff of $3.50-4.50/bbl for production through Ninian.

After processing at South Ninian, Lyell's oil is sent via the Ninian pipeline system, along with recovered NGL, to Sullom Voe. Associated gas production, to peak at 10 MMcfd, is used for fuel at South Ninian.

Lyell field interests are operator Conoco 33.34%, Chevron 33.33%, and Oryx U.K. Energy Co. 33.33%. Ninian field interests are operator Chevron 17.1%, Enterprise Oil plc 18.52%, Lasmo plc 17.26%, Murphy Petroleum Ltd. 10%, Neste North Sea Ltd. 4.25%, Oryx 21.37%, and Ranger Oil (U.K.) Ltd. 11.5%.

STRATHSPEY

Four subsea structures for development of Strathspey field, which lies in 450 ft of water on Block 3/4a, left the Nigg, Aberdeen, yard of Highland Fabricators Ltd. Mar. 25. They will be installed in May.

Strathspey has reserves of 80 million bbl of oil, 10 million bbl of NGL, and 334 bcf of gas. First production is scheduled for the fourth quarter.

Peak oil production of 45,000 b/d is expected in 1994, while gas output will peak at 114 MMcfd in 1997. Water injection will take place at 88,000 b/d, supplied from South Ninian platform.

Strathspey contains an oil reservoir and a gas/condensate reservoir, both Jurassic. The Brent oil reservoir will be produced from eight wells with three water injectors. The Statfjord gas reservoir will be produced from six wells, including two extended reach wells to drain the 85 ft thick condensate rim. The long reach wells will have horizontal sections of as much as 2,500 ft.

Subsea production will be controlled from the Central Ninian platform. Wells will be clustered around a central manifold. Oil will be sent to Central Ninian for export to Sullom Voe by an existing pipeline. Gas will enter the Flags system at Brent A platform 16 miles away via a new 16 in. pipeline.

Strathspey field interests are operator Texaco 67%, Shell U.K. Ltd. 13.25%, Esso Exploration & Production Ltd. 13.25%, and Oryx 6.5%.

STAFFA

Another satellite to Ninian, Staffa field on Block 3/8b, began production in March 1992 and averages about 6,000 b/d. Reserves are 8 million bbl of oil and 10 bcf of gas. Water depth is 460 ft.

Lasmo developed Staffa using a subsea system tied back to South Ninian, with a multiphase pipeline sending oil and gas to the platform. Oil is. processed and exported via the Ninian line to Sullom Voe. Gas is used as fuel on Central Ninian.

Staffa field partners are Lasmo 60% and Ranger 40%.

HORIZONAL RECORD

The BP record well had a 7,116 ft horizontal section and reached total measured depth of 17,618 ft.

The well was spudded by Glomar Baltic 1 jack up on Nov. 16, 1992 and completed Mar. 16. Tests indicated a 57 MMcfd gas flow at a wellhead pressure of 600 psi.

BP said this well, along with a first development well completed last year, should be enough for initial production requirements from Hyde. The company, is considering drilling a third development well.

Gas sales are to begin October 1993 to Alliance Gas, the U.K. gas supply joint venture formed by BP, Den norske stats oljeselskap AS and Norsk Hydro AS.

Hyde field production will be via a platform, not normally manned, to the West Sole pipeline for export to Easington terminal. Hyde field reserves are estimated at 135 bcf of gas.

DRAUGEN

The 950 ft tall Draugen GBS, the largest concrete base in the world, was ballasted before the 20,000 metric ton topsides was fitted. Now only 110 ft of GBS is above water.

Operator AS Norske Shell and contractor Aker AS intend to commission and hook up the platform ready for towout May 3. The structure will be towed for 10-12 days to Block 6407/9, for installation during June in 820 ft of water.

Shell said Mar. 31 that the Dyvi Stena semisubmersible rig was moving to the field to begin predrilling production wells (OGJ, Aug. 17, 1992, p. 63). Oil production is to start this fall.

It is believed Shell intends to upgrade Draugen reserves by 30%, taking estimated recoverable oil to 560 million bbl. Shell would not confirm this, saying only that a study is under way and would take several months.

Norwegian Contractors said the new GBS for Sleipner East would be ready in time for mating Apr. 26, a week ahead of schedule (OGJ, Aug. 17, 1992, p. 60).