A yearend deadline for installing emergency shutdown valves (ESVs) on most platform risers in the U.K. North Sea has turned the normal summer maintenance period into one of the most active ever in British waters.
The ESVs are required by legislation introduced after the July 1988 Piper Alpha explosion and fire. They will be installed in addition to the normal weather window inspection and maintenance work. A number of operators have started to install subsea isolation valves.
U.K. Offshore Operators Association estimates companies will spend 360 million ($650 million) on valve installation.
Production normally drops during the summer maintenance shutdown, but the 1990 reduction will be deeper and longer than usual. Where fields are connected to pipeline systems, detailed coordination between operators has been needed.
Shell U.K. Exploration & Production, operator of the Brent pipeline system, said the line will be shutdown 4 weeks in the final quarter of this year because of the ESV work. Throughput will also be restricted during the 2 weeks after the shutdown.
Shell closed the Flags gas gathering system in the East Shetlands basin in July and planned to keep it closed until September. Gas demand in the summer is light, and the effect of the closure is negligible.
Work on the ESVs ranges from lightweight 3 in. valves to valves on 36 in. risers as heavy as 40 metric tons. The installation work is disruptive because the valves need to be as close to the splash zones as possible and must be protected against fire and blast.
BP Exploration has been forced to delay its gas lift project in Forties field to give priority to the ESV work.
NEW FIELDS
Six oil fields and two gas fields have come on stream during the past 12 months. Seven more are to be commissioned during the next few months.
Between them the new developments demonstrate the diverse range of technology in use in the U.K. North Sea.
None of the fields already on stream were developed with conventional drilling and production platforms.
Linnhe, Don, Blair, Hamish, and Della are subsea satellites tied back to existing production facilities. Arbroath and Ravenspurn South are satellite platforms. The dynamically positioned Seillean production ship is stationed on Cyrus.
Of the fields still to come on stream, Shell/Esso's Kittiwake is most like a conventional unit. It is a drilling and production platform but has a low-cost, lightweight design with all topsides installed in three lifts. Shell/Esso also is using conventional Southern basin gas platform technology for Barque and Clipper fields. Emerald will have a floating production unit. Ravenspurn North is a shallow water concrete unit, Moira a subsea completion, and Audrey an unmanned satellite. Amethyst has two unmanned platforms controlled from shore, where the gas is processed.
ACTIVITY TO CONTINUE
Prospects for a continued high level of activity in U.K. waters look good.
A recent study by County Natwest Woodmac, Edinburgh, identifies 57 oil and gas developments that might gain government approval in the next 2-3 years.
BP Exploration, one of the major operators in the U.K. sector, also takes an optimistic view of the future.
David Harding, BP Exploration's chief executive, said BP estimates that reserves discovered but not yet produced total 10 billion bbl, the equivalent to cumulative production to the end of 1989.
Gas reserves on the same basis would be 40 tcf, compared with cumulative production through 1989 of 25 tcf.
The County Natwest Woodmac study also emphasizes the trend toward development of gas/condensate fields in U.K. waters. It says 52% of the projects will involve recovery of liquids and gas, many in the central North Sea.
Of the remaining fields 26% are oil projects, and 22% are pure gas.
Recovery from the fields will be 3.8 billion bbl of liquids, equivalent to 58% of remaining recoverable reserves from fields on stream or under development.
Gas reserves recovered from the new fields will be 14.4 tcf of sales gas. The study says 47% of these reserves will come from the central North Sea and 32% from waters farther north.
The Southern basin and Irish Sea together will be less important than in the past, accounting for only 21% of reserves.
Combined liquids production from probable developments will peak in 1996 at an average rate of 1.2 million b/d, about 49% of total U.K. production expected in that year.
Gas production will not peak until 1999 at 3.1 bcfd, slightly more than the output expected in that year from fields now with development approval.
Capital spending on the probable new fields is projected at 13.7 billion ($24.66 billion) at 1990 prices. The analysts calculate the average cost at 2.18/bbl ($3.92/bbl).
According to the survey, 61% of the fields will be developed with conventional technology, 26% will use subsea systems, and 13% will use floating production units. Capital costs for conventional technology average 2.13/bbl ($3.83/bbl), for subsea technology 2.32/bbl ($4.17/bbl), and for floaters 2.53/bbl ($4.55/bbl).
FABRICATION CAPACITY SHORTAGE
The high level of activity in U.K. waters is putting pressure on British fabrication capacity.
Jacket and topsides fabricators have little short term space in yards, and a number of operators have considered placing major projects in foreign yards.
AGIP U.K., which is developing Tiffany field in the T-block it purchased from Phillips Petroleum, awarded the U.K.'s largest turnkey contract for the project. The work also includes development of Toni field with a subsea system tied back to Tiffany.
As part of the 450 million ($810 million) contract, the 16,000 metric ton steel jacket will be built in Sicily by Consorzio Italoffshore. Drilling components will also be designed in Italy.
Amerada Hess Ltd. placed major fabrication contracts for Scott field development with McDermott Scotland before receiving formal Annex B approval from the Department of Energy.
Scott, on Blocks 15/21a and 15/22, has reserves of 450 million bbl of oil, 290 bcf of gas, and 40 million bbl of gas liquids. It is the biggest offshore development in progress in U.K. waters.
McDermott received a contract for design, procurement, fabrication, and installation of twin steel jackets to be installed in 1992 and 1993, in preparation for first oil at the end of 1993.
The contractor will start work immediately using the design services of Earl & Wright, which has begun extensive conceptual work for Amerada Hess.
Other operators are seeking early slots for new projects. Occidental Petroleum (Caledonia) placed contracts for the jackets, topsides, and platform installation work before winning Annex B approval for its 30,000 b/d Saltire project (formerly East Piper), scheduled to start up in 1992.
And Marathon Oil U.K. Ltd. sent telexes of intent to three companies for the jacket, topsides, and drilling template and piles for Central Brae field, which the company wants to bring on stream in 1993. It estimates reserves at 300 million bbl of oil and 1.3 tcf of gas.
SOUTHERN GAS ACTIVITY
Activity remains high in the southern gas producing area. Development is following exploration north from the traditional Rotliegendes plays into the Carboniferous areas of the southern North Sea.
The transition coincides with ending of the British Gas plc role as monopoly buyer of new offshore gas supplies.
British Gas is negotiating to buy 90% of the supplies from a number of potential new developments. Meanwhile, the first projects are coming forward in which all output will be sold to non-British Gas customers.
A group led by ARCO British sold production of Pickerill field in the Southern basin for power generation fuel. Pickerill's 850 bcf of reserves will be developed with two unmanned platforms linked to the Conoco gas reception terminal at Theddlethorpe.
The project, costing 200 million ($360 million), will start production in 1992 and reach a plateau of 210 MMcfd the following year.
Ranger Oil, operator of small Anglia field, is taking the process one step further by becoming an equity holder in the power station project at Great Yarmouth that will purchase the Anglia gas.
The end of the British Gas monopoly is also generating competition between operators. Total Oil Marine and a majority of the partners in Caister field, a Carboniferous prospect in Quadrant 44 near the Dutch border, has sold 89% of the gas for electricity generation.
Conoco preferred a joint development for its Murdoch area structures, where a number of wells have found 300 bcf of reserves.
If it develops Caister alone, Conoco could feed its 11% of reserves into the Murdoch development, which has the option of moving its supplies through lengthy connections to the Conoco-operated Loggs systems to the southwest or through Hamilton Bros.'s Esmond/Forbes/Gordon complex to the northwest.
Hamilton Bros. has installed the first shallow water concrete platform in U.K. waters in Ravenspurn North field and expects to start production in the fall.
Hamilton Bros. has also discovered a small accumulation on Block 43/27 about 4 miles east of the field. The well flowed 37.6 MMcfd and is a candidate for a subsea tie-back to the new facilities.
Throughput of the Loggs pipeline system will be increased this fall when Phillips Petroleum brings on stream the second unmanned satellite platform in Audrey field. The second six-slot platform will increase contractual gas delivery capacity to British Gas to 450 MMcfd from 327 MMcfd.
BP Exploration is ready to begin gas production from 850 bcf Amethyst field in October. The 260 million ($468 million) project ran a 2 day production test from two unmanned platforms in May.
The two platforms are controlled from an onshore station using line of sight electronic transmission. All processing is undertaken at the British Gas Rough terminal at Easington. Even daily pigging of the 30 in. line is remotely controlled.
Production from the first two platforms will be 150 MMcfd. Two further platforms are scheduled to be installed in May 1991.
In the same area, BP is looking to complete the original concept of the Villages development by phasing the Hyde and Hoton prospects into the processing and pipeline system at Ravenspurn South field.
BP said it has as many as 20 southern North Sea gas discoveries targeted for future development.
SATELLITE DEVELOPMENTS
In the central part of the North Sea, development of satellite fields with subsea completions is proving fast and profitable.
Mobil North Sea's Ness subsea satellite linked to Beryl facilities has the lowest production cost in the U.K. at 51/bbl.
Operators have received approvals for a series of small satellite fields developed with subsea completion and tied back to existing facilities.
North Sea Sun received U.K. government approval to develop the 4 million bbl Blair field with a single subsea well tied back to the Balmoral floating production system. The well has been under extended test since summer 1989 and is producing about 2,000 b/d.
Amerada Hess Ltd. also received permission to tie back its 1.5 million bbl Hamish field to the floating production system serving Ivanhoe/Rob Roy fields. The field is producing 3,000 b/d.
The 10 million bbl Linnhe field came on stream last November-2 months after Annex B approval was received. The single producing well and a water injector are tied back to Beryl field 4 miles away.
Phillips has approval for the 6 million bbl Moira field as a subsea satellite to its Maureen field about 6 miles away. The field soon will start production from a single well expected to produce 5,600 b/d.
SOPHISTICATED FLOATER
The most sophisticated piece of equipment installed in the North Sea this year is BP Exploration's Seillean offshore production vessel.
It began oil production from Cyrus field in April. The custom built vessel holds station during production with dynamic positioning, then disconnects from the wellhead and delivers its 310,000 bbl cargo. It then steams back to the field and repeats the cycle.
Cyrus has only 13 million bbl of reserves. BP will seek permission from the Department of Energy to use Seillean to produce the 20 million bbl of reserves in Donan field. BP has spudded two appraisal wells in Donan, on Block 15/20.
Amoco U.K. Exploration started production from Arbroath field this summer through an unmanned satellite wellhead platform tied back to its Montrose field.
Arbroath output was expected to peak at 35,000 b/d, but flow already has reached 44,000 b/d, mainly due to debottlenecking processing capacity at Montrose.
Production wells in the field are being drilled by the Mr. Mac heavy duty jack up. The drilling rig has been skidded onto the platform, and the jack up is acting as drilling tender.
Earlier this year Amoco discovered a 25 million bbl reservoir close to the Abroath platform that could be tied into the new production unit with a subsea completion.
Sovereign Oil & Gas plc expects to bring 43 million bbl Emerald field on stream toward the end of the year using a floating production vessel.
The semisubmersible Emerald Producer is in final stages of conversion and should be floated out to the field in late summer. A storage tanker is under conversion at a yard in Spain and is scheduled for installation about the same time.
A BUSY PROGRAM
Shell U.K. Exploration & Production, operator of the Shell/Esso group, has one of its busiest summer work programs on record.
It will start up three fields this year in addition to installing platform and subsea ESVS.
In May the company completed installation of the 7,500 metric ton integrated deck structure for Kittiwake field.
Kittiwake is one of the new generation of slim-line platforms requiring only three module lifts to complete topsides installation. The 350 million ($630 million) project is to produce first oil in the fall and build to a plateau of 36,000 b/d.
The small Osprey field will be developed with a subsea production complex tied back to Dunlin field. Shell Expro has completed the first two wells and expects to bring the field on stream in November. Production will reach 24,000 b/d in 1992.
In the Southern basin, Shell is in final stages of developing Clipper and Barque fields in the Sole Pit area. The fields have combined reserves of 875 bcf and are scheduled to produce first gas by Oct. 1. Production will plateau at 200 MMcfd in 1992.
Shell Expro also completed its first two horizontal wells in U.K. waters this year. The first was a gas producer in Barque field with a horizontal section of 2,500 ft.
The second, with a horizontal section of 2,010 ft, was in mature Dunlin oil field in the East Shetlands area. Shell said the well cost 70% more than a conventional well, but the output of 5,000 b/d was three times that of a conventional well.
Shell said the success not only raised the possibility of using horizontal wells to enhance recovery from the field but also opened the door to opportunities in other reservoirs.
In addition to the offshore work, Shell Expro will spend 700 million ($1.26 billion) on development of the four fields in the Gannet complex.
A drilling and production complex will be installed in Gannet field, and three other fields will be developed with subsea production systems tied back to the Gannet A platform.
The four fields have combined reserves of 170 million bbl of oil and condensate and 700 bcf of gas.
Shell said it will use tender assisted drilling for the Gannet A program and will use the Sedco Sedco 704 semi for tender assist duties, starting in October 1992.
BRUCE FLOW TO START
A group led by BP will begin gas deliveries from Bruce gas/condensate field in 1993. British Gas signed a purchase contract covering 90% of the 2.6 tcf of reserves. The remaining 10% has been sold for power generation.
Two-stage Bruce development will cost 1.5 billion ($2.7 billion). Contracts have been placed for the drilling platform and the separate processing and quarters platform.
Output from the 210 million bbl of condensate reserves will be transported through a 150 mile, 24 in. pipeline into the Forties system. Gas will be exported through a 3 mile tie-in to the Frigg pipeline.
Occidental Petroleum has started redevelopment of Piper field using an integrated drilling and production platform.
The eight-leg, 46,000 metric ton steel jacket will support topside designed to handle as much as 140,000 b/d of oil and accommodate 24 wells. Piper Bravo will cost 580 million ($1.04 billion).
A 200 metric ton subsea drilling template was installed at the new Piper location. Occidental plans to drill as many as six production wells before installing the jacket.
Piper Bravo is designed to handle crude from other fields. Output from Saltire field 4 miles away will be transported through Piper into the existing pipeline system to the Occidental consortium's terminal at Flotta in the Orkney Islands.
Occidental is seeking Annex B approval for 100 million bbl Saltire field. It wants to build a 24 well, integrated steel drilling and production platform to produce 35,000 b/d of oil and 53 MMcfd of gas through pipeline links into Piper Bravo.
NELSON MOVES AHEAD
Development of Nelson field is moving ahead following agreement on operatorship between Enterprise Oil plc, which found the field, and Shell Expro, operator of the field extension.
Shell will be responsible for design and construction; Enterprise will take over during the operational phase.
Nelson has estimated reserves of 350 million bbl and 100 bcf of gas. Annex B approval for an integrated drilling and production platform is expected shortly, which would enable Shell to start output in 1993, rising to 125,000 b/d and 35 MMcfd of gas in 1995.
Total Oil Marine completed a well on Block 22/7, indicating a small westerly extension of the field.
Chevron is pushing ahead with its plans for two stage development of Alba field on Block 16/26.
In the first phase, an eight-leg steel drilling and production platform will be installed on the northern part of the 300 million bbl field.
The unit will come on stream in 1993, with output peaking at 60,000-70,000 b/d. A second platform is scheduled for the southern end of the field, starting up in 1999.
Underlying Alba is one of the biggest undeveloped gas/condensate accumulations in U.K. waters-Kilda field, which extends into adjoining Block 15/30 operated by Conoco U.K. Ltd.
Chevron said Kilda was discovered in the mid-1970s, but its commercial prospects were not realized until the 16/26-9 well was drilled in 1987. It said further appraisal work could show that it extends into three more blocks.
Chevron said the scale of Kilda has not been determined. Production is unlikely before 1998.
Copyright 1990 Oil & Gas Journal. All Rights Reserved.