Oil and gas fields are steadily coming on stream in the U.K. North Sea.
During the past 12 months, three new oil developments and four gas fields were commissioned.
This high level of offshore activity will continue. During 1990, the U.K. Department of Energy gave approval for 18 new offshore projects, which will cost operators 5.2 billion to complete. So far this year, the department has approved eight new offshore projects.
As many as 50 other fields could be brought forward for development during the next 5 years.
Fabrication yards are seeing a return to the boom activity of the early 1980s. Some facilities mothballed after the 1986 oil price collapse have been restarted. The lack of construction capacity in the U.K. has forced some operators to place orders with continental European suppliers. Some have gone further afield; for example, the jacket for the new British Petroleum Co. plc Forties riser platform will be built in Korea. Net result has been a big increase in fabrication costs.
A survey by analysts County Natwest Woodmac showed that fabrication costs have risen by 20-30% in the past year, while development drilling costs have risen on the tide of a doubling in rig rates during the same period.
U.K. production costs are also rising. A County Natwest Woodmac survey showed that the 1987 average production cost of 92.50/bbl (in 1991 money) has risen to 23.25/bbl in 1990.
As production increases the overall average should decline to 22.80/bbl by 1995, but the increased maturity of the major fields and higher supply service costs will ensure that overall costs remain about 10% above 1987 levels.
The unavoidable increases in production and development costs have triggered efforts by operators to contain overall expenditures. The search for greater technical efficiency is running alongside renewed pressure on manpower and administrative costs.
BP OPTIMISTIC
BP Exploration takes an optimistic view of North Sea prospects. Chief Executive John Browne recently said BP production would rise from its present level of about 530,000 b/d of oil equivalent and would remain above 500,000 b/d for the rest of the century.
He said the decline of large, old fields like Magnus and Forties was inevitable, although tax changes to encourage incremental investment could prolong their lives.
BP will offset this decline with output from new, smaller fields, which are likely to be just as profitable as the big fields.
Browne said the company needs to develop simpler designs and novel production methods that will reduce the need for new infrastructure and give fields of 30,000-40,000 b/d output the same rate of return as fields producing 100,000 b/d or more.
Browne said if Forties was developed today it would require two platforms instead of five.
BP, he said, expects to bring 13 development projects on stream in the North Sea within the next 5 years and more in the second half of the decade. The first will be Miller and Bruce fields.
Miller oil field moves into the crucial offshore installation phase this summer and is scheduled to be on stream next year.
The field, adjoining Brae field in Block 16/8b, has reserves of 240 million bbl and will have a peak production rate of 113,000 b/d through a link into the Forties pipeline. Sour gas from the field has been sold as power station fuel and will be transported in a dedicated line.
Follow-up to Miller is Bruce gas-condensate field,
which extends across Blocks 9/8a, 9/9a, and 9/9b.
Engineering has started on the bridge-linked drilling and production platforms. The 2.6 tcf, 220 million bbl reservoir is on schedule to produce first gas in October 1993. Gas production, expected to peak at about 530 MMcfd, will be delivered through a spur line to the Frigg pipeline.
Liquids, building to about 80,000 b/d, will be exported through a 150 mile, 24 in. line into the Forties system, where BP is building a riser platform to handle the increase in third party business.
BP also has installed the second pair of unmanned platforms in Amethyst field in the Southern basin, raising annual average peak production capacity to 180,000 b/d.
LARGEST DEVELOPMENT
Amerada Hess Ltd. is responsible for the largest development under way in the U.K. North Sea. When development of Scoff oil field started in 1990, reserves were estimated at 450 million bbl of oil, 290 bcf of gas, and 40 million bbl of gas liquids.
Since then, a southerly extension has added significantly to the field's oil reserves and will be integrated into the development.
Amerada said it will develop the field with a drilling and process platform bridge-linked to a quarters unit. There will also be an extensive subsea operation with three manifold clusters of water injection wells and seven production wells tied back to the process and drilling platform.
The field will require a total of 18 production wells and 15 water injectors. Water injection capacity will be 310,000 b/d.
The main contracts have been awarded, and the project is on schedule to produce first oil at the end of 1993. Production from the 1.1 billion ($1.78 billion) project will build to a peak of 180,000 b/d.
Oil will be carried through a 50 mile, 24 in. export line to the Forties system. The gas has been sold to Mobil Gas Marketing Ltd. and will be exported through an 8 mile, 10 in. line to the Mobil North Sea-operated Scottish Area Gas Evacuation (SAGE) pipeline system.
SHELL PLANS
Shell U.K. Exploration & Production, operator of the Shell/Esso group, is considering eight development projects for the next few years.
Five are gas fields in the Southern basin, mostly around the existing Barque and Clipper developments. These will include an extension of Barque in Block 48/14 and Ensign field, southeast of Barque. In the Clipper area, Shell is looking at Schooner and Ketch fields.
The fifth field is Mobil North Sea's Gawain field, which extends into Shell's 49/24 acreage.
The three prospective oil developments are north of the gas fields. East of the Shetlands, Shell is looking at Brent South field and Pelican field, south of Cormorant field. In the central North Sea, Heron field is a candidate for development.
During the past 12 months, Shell Expro brought on stream Kittiwake and Osprey oil fields in the oil province and Barque and Clipper gas fields in the Southern basin.
The biggest development in the Shell portfolio is currently Nelson field, with 450 million bbl of oil reserves and 1.85 tcf of gas.
The project, for which Shell is operator only for the development phase, requires an integrated drilling and production platform that is to produce first oil in 1993. Enterprise Oil will take over as operator for the production phase, when output will rise to a peak of 160,000 b/d of oil and 65 MMcfd of gas.
Oil will be carried through a link to the Forties system, gas through the Fulmar gas pipeline.
Shell Expro is also pushing ahead with development of the Gannet complex, consisting of a drilling and production center on the main Gannet field with flow lines to three subsea satellites.
Total reserves for the four fields are 170 million bbl of liquids and 700 bcf of gas. Gannet will cost about 700 million ($1.13 billion).
ALBA DEVELOPMENT
Chevron U.K. Ltd.'s Alba field under development in Block 16/26 will have the first custom-built floating storage unit (FSU) in the North Sea.
The turret-mounted FSU will provide 775,000 bbl of storage for the integrated drilling and production platform, which is due on stream in 1994. Peak production from the $1.1 billion project will be 60,000-70,000 b/d, reached in 1995.
Alba is an Eocene discovery with reserves of about 390 million bbl. The first platform will be installed in the northern part of the field, followed by a second platform in the southern part once Chevron has operating experience with the reservoir from the first unit. Peak output from the two platforms will be about 100,000 b/d of 20 gravity oil.
Alba is the first heavy oil reservoir to be developed in U.K. waters.
Beneath Alba lies one of the largest undeveloped gas-condensate reservoirs in the U.K. North Sea.
The Kilda/Lapworth structure is a Lower Cretaceous reservoir that extends from Blocks 16/27a and b in the east through 16/26 and 15/30 to 15/29a.
In Blocks 16/26 and 16/27b, where Chevron is operator, the field is known as Kilda. Reserves are unofficially estimated at 1.5 tcf of gas and 200 million bbl of liquids.
Conoco, operator of Block 15/30, calls the structure Lapworth.
This year, Texaco North Sea U.K. Co. announced a potential western extension of the field with its 15/29a-5 well, which tested 19.5 MMcfd of gas and 2,300 b/d of condensate. Reserves in this sector are put at 1 tcf of gas and 200 million bbl of liquids.
Appraisal work is in progress. Companies, notably Conoco, have strengthened their equity holdings through a series of equity swaps and purchases.
Last month Chevron began a 540 sq km 3D survey across five blocks for a 12 company group. It is the largest single 3D operation in the North Sea and will cost 3.5 million ($5.74 million). Chevron will use preliminary results to determine sites for further appraisal wells. The final survey will help equity owners to locate development wells.
EAST BRAE WORK
Marathon Oil U.K. has started work on its fourth consecutive development in the Brae area in Quadrant 16.
After bringing on stream the South, North, and Central Brae reservoirs in Block 16/7, the company has turned its attention to East Brae gas-condensate field in Block 16/3.
It has received approval for a drilling and production platform to house a gas recycling project. Liquids production will begin in 1993 and build to a peak of 115,000 b/d. Gas production of about 600 MMcfd will be reinjected to maintain pressure.
Liquids from East Brae will be piped into the main Brae production complex in 16/7, where there is a pipeline link into the Forties system to the Scottish mainland.
Gas production from the first three Brae fields is to start in 1993 through a spur line into Mobil's SAGE system, in which partners in the Marathon development have a 50% holding.
Mobil has completed the 210 mile, 30 in. line from the Beryl area to the St. Fergus terminal in Scotland and has started the link into Brae. Start-up is expected next year.
CATS PROJECT
Gas development in the southern part of the central North Sea will benefit from the Central Area Transmission System (CATS), which is being laid by Amoco (U.K.) Exploration Co. from Everest and Lomond. gas fields to Teesside in northeastern England.
The 250 mile, 36 in. line will start up in 1993 to move gas from Everest and Lomond to a 1,725 mw cogeneration power station being built by Enron Corp. and ICI in Teesside.
The power station will require about 270 MMcfd of gas. Everest will contribute 150 MMcfd with the balance coming from Lomond,
However, capacity of the CATS line is 1.4 bcfd. At least six other potential developments in the area could make use of the line during the next decade.
Amoco will develop Everest with two steel platforms-a 10-12 well drilling and production unit and a riser platform. A single steel platform on Lomond will be linked to Everest by a 20 in. gas line and an 8 in. condensate line.
Liquids from the two fields will travel through a 14 in. line to BP Exploration's Forties pipeline system to the mainland.
QUADRANT 9 STRUCTURES
Development plans are starting to come forward for the complex Eocene structures in Quadrant 9.
Gryphon field in Block 9/18b looks like becoming the production center for the whole area. The operator, Kerr-McGee (U.K.) plc, plans a concrete gravity based platform that would start up in 1995.
Production is expected to average 45,000-50,000 b/d. The concrete structure, the first in the U.K. North Sea since the 1970s, will have storage capacity of about 500,000 bbl to service a tanker loading export system.
One of the first third party users of the Gryphon facilities could be BP Exploration, which is studying plans for Forth field development based on horizontal wells.
The future of the project will largely depend on the outcome of a horizontal well being drilled this summer by BP into the main part of the reservoir. If the well is successful, a development plan could be in place by the end of next year.
Forth is in Block 9/23b, immediately south of Gryphon. It is due north of Hamilton Bros.' Crawford field, the first oil reservoir in U.K. waters to be abandoned.
Crawford produced through a floating production vessel, which was withdrawn. The subsea wellhead equipment has been removed and will be reused off Ghana.
AGIP DEBUTS
Italian-owned Agip U.K. made its debut as a development operator in the North Sea when it acquired government approval for Tiffany field last year.
Later in the year it received the go-ahead for a subsea development of Toni field, also in Block 16/17.
Agip has let contracts for the drilling and production platform to service the 125 million bbl of oil in Tiffany field.
Start-up is scheduled for 1993 with production rising to 65,000 b/d.
The subsea field is expected to come on stream about 6 months later at about 20,000 b/d. Production will be carried through the Forties system.
Lasmo also made its debut as an operator with the subsea development of the Staffa satellite to Ninian field. First production, through Ninian facilities, is expected toward the end of this year.
Peak production will be about 8,000 b/d.
Another project by a new British sector operator, Sovereign Oil & Gas' marginal Emerald field, has run into problems.
An innovative financing deal and an advantageous turnkey contract for conversion of a semisubmersible into a floating production system were negated by Davy Offshore's problems in undertaking the work.
All the field facilities are ready, including a converted storage and offloading tanker. However, the semisubmersible production vessel is more than a year late.
Another new operator, Ranger Oil, has approval to develop the 240 bcf Anglia gas field in Block 48/18b of the Southern basin. The jacket and topsides for the unmanned platform are in place. First gas is expected in December.
Immediately west of Anglia in Blocks 48/17a and b and 48/18a and b, Mobil North Sea is working on a single platform project for Lancelot field.
Mobil said the project is on schedule to start up next year. The company is also working on a subsea system to link the Guinivere satellite in 48/17b into this system.
ARCO British Ltd. is developing Pickerill field in Blocks 48/11a and b, 48/12b, and 48/17b.
The first of two steel jackets has been installed, and development drilling has started. A second platform will be installed next year. Production, building to about 170 MMcfd, will begin later in the year.
A dedicated pipeline will be laid to Conoco's Theddlethorpe terminal. Most of the field's gas will be sold for power generation.
Total Oil Marine has sold all the output of Caister field in Block 44/23a for power generation. Conoco declined to sell its share of the gas and eventually sold its equity stake to the other Caister partners.
Conoco is operator for the substantial reserves that have been found in and around nearby Murdoch field. A joint development covering the Caister and Murdoch areas cannot be ruled out.
Southeast of Caister and Murdoch, Ultramar is developing the first Anglo-Dutch gas field. The Markham reservoir extends from U.K. territory into Dutch waters.
The 675 bcf reservoir will be developed with a small platform complex. A spur line will carry the gas into the Dutch pipeline infrastructure.
ALWYN, LYELL
In the northern North Sea, Total Oil Marine has installed a three well subsea system to tap an extension of its Alwyn North field in Block 3/9. The project will cost about 60 million ($98.4 million).
Start-up of the 22 million bbl, 158 bcf reservoir is expected toward the end of the year.
Production will build to 16,000 b/d of oil and 88 MMcfd of gas.
The company is working on basic engineering studies for the 120 million bbl, 494 bcf Dunbar field, formerly Alwyn South, about 15 miles south of the Alwyn North complex. It is seeking government approval for a satellite wellhead platform tied back to Alwyn North, with start-up by the end of 1994.
The Alwyn Southeast area consists of three structures with 15 million bbl of liquids and 423 bcf of gas. They will be developed later as subsea satellites of Dunbar.
Oil production will peak at about 50,000 b/d with a maximum gas delivery of 317 MMcfd after decline of Alwyn North gas production.
At the beginning of this year Conoco received approval to develop Lyell field in Block 3/2 using a subsea system tied back to Ninian facilities at a cost of 160 million ($262 million).
It will be one of the largest subsea systems in the U.K. North Sea, with 10 producers and 8 injectors to produce about 19,000 b/d from the 40 million bbl reservoir. First oil is expected in 1993.
Copyright 1991 Oil & Gas Journal. All Rights Reserved.