To bolster returns from marginal developments, operators are looking for ways to trim capital and operating costs.
There is a general trend away from traditional platform developments toward floating production systems and subsea and extended reach well tie-ins to existing infrastructure.
For fields still best developed by platforms, however, the trend is to simpler concepts with less requirement for maintenance.
Although current platform concepts are on a much smaller scale than the giant structures of the North Sea's glory years, they still reflect the ingenuity of the region's design engineers.
Addressing a seminar, Heinz Rothermund, managing director of Shell U.K. Exploration & Production, outlined the ideas that are determining the ways operators in the U.K. and Norway develop new fields.
Rothermund said, "Cutting operating and development costs is an imperative for Britain's offshore oil and gas industry as we strive to maximize recovery from a maturing North Sea against a background of continuing low oil prices.
"It requires the commitment and creativity of all players-operators, contractors, and suppliers-working together toward common goals. There is no room for bureaucratic barriers that inhibit this essential cooperative drive. "
Wood Mackenzie Consultants Ltd., Edinburgh, places Norwegian development projects in five categories: platform, not normally manned platform, subsea, floating, and extended reach drilling.
Within each category developments have been similar, Wood Mackenzie said, but there has been a trend toward tying in new fields to existing infrastructure.
"The rise in the number of Norwegian satellite field developments is shown by the less frequent use of stand alone platform solutions and increased use of simple wellhead platforms and extended reach drilling," Wood Mackenzie said.
"The proportion of full subsea solutions and the use of floating production systems has remained constant".
Advancements in technology, use of standard equipment, and streamlined development procedures within government have helped contain Norway's capital cost per barrel of oil equivalent.
Also, a larger number of recent developments are satellites of existing facilities. So up front capital costs are relatively low.
In 1993, average capital expenditure for probable developments was 19 kroner ($2.90)/bbl of oil equivalent, said Wood Mackenzie, while in 1994 the figure has fallen to about 16 kroner ($2.40).
However, if West Troll gas development is excluded, the figures rise to 28 kroner ($4.20) and 21 kroner ($3.20), respectively.
On the U.K. shelf, Wood Mackenzie identified 20 fields that are likely to use fixed platforms. Of those, the analyst figures there will be a 50-50 split between manned and unmanned platforms.
CRIME PROGRAM
U.K. operators have been trying to cut all costs involved in developing fields under the Cost Reduction in the New Era (Crine) program undertaken through U.K. Offshore Operators Association (Ukooa).
Ukooa's Crine group has set out to bring about a 30% reduction in U.K. off shore capital costs and a 50% reduction in operating costs, inspired by a fear that rising costs will curtail North Sea development (OGJ, Dec. 20, 1993, p. 31).
Norway's operators are pursuing their cost reduction program through the Norwegian Oil Industry Association (OLF). The OLF program promotes a philosophy similar to Crine, but it has a goal to reduce capital cost by 50%.
"While savings can be made in changing philosophies toward construction," said John Wils, chairman of Ukooa's operations committee, "it is essential that design and equipment selection are made for the life cycle of the facility if we are to achieve significant reductions in operating costs."
Wils said the chief ambition of platform designers is to run facilities unmanned.
"In this way we can reduce costs associated with maintaining life support and reduce personnel exposure to hazards."
The next target is improvement of cost effectiveness in platform utilization time: "Platform costs may be dramatically reduced when designed for 90% uptime as opposed to 99% uptime. "
To prevent costly retrofits, equipment choices should be made based on platform life cycle requirements, not on lowest price, Wils said.
BESSEMER/DAVY
Potential North Sea Fixed Platform Developments (14918 bytes)
Amoco (U.K.) Exploration Corp. last June won U.K. Department of Trade & Industry approval for a 46 million ($69 million) development program in two southern North Sea gas fields.
Development of Block 49/23 Bessemer and Block 53/5a Davy fields will involve use of two Amoco Minimum Offshore Supporting Structure (Amoss) platforms tied back to the Indefatigable field platform.
Amoss is a monotower design similar to units in use in the Gulf of Mexico, Persian Gulf, and Dutch North Sea but not used before in the U.K. North Sea.
Brown & Root Highland Fabricators Ltd., London, won a 14 million ($21 million) contract for engineering, procurement, installation, and commissioning of the two platforms. They are to be installed in March 1995.
Gas production from Bessemer and Davy is set to begin Oct. 1, 1995, at a combined maximum of 210 MMcfd.
Wood Mackenzie estimates reserves of Bessemer and nearby Beaufort reservoir, which the analyst said will be developed with a single extended reach well from the Bessemer platform, at 130 bcf of gas. Davy reserves are estimated at 150 bcf.
"The simple structures are relatively cheap to construct," said Wood Mackenzie of the Amoss concept. "Annual operating costs are lower than for subsea manifolds, since access for maintenance is more straightforward."
Total operating costs were predicted by Wood Mackenzie to be 3 million ($4.5 million/year for Bessemer/Beaufort and 4 million ($6 million)/year for Davy.
Amoco has gone so far down the cost cutting route with Bessemer and Davy that it plans to install wind turbines on the two platforms to reduce power generation costs.
Amoco figures the 200,000 ($300,000) plan to fit four wind turbines will yield an 85% cut in diesel fuel costs, a 75% drop in hydrocarbon exhausts, and a 50% saving on helicopter visits needed to maintain conventional diesel fueled generators. Helicopter visits will be required once every 90 days, Amoco said, compared with one every 2 weeks on a typical unmanned platform.
Jack Criswell, managing director of Amoco U.K., said, "Amoco's use of wind power demonstrates the kind of idea the industry can pursue to support its Crine initiative if we have the courage to try something different."
LAW PLATFORM
Shell Expro found that operating costs threatened the future viability of some of its U.K. North Sea southern gas basin fields. Lessons learned from this situation inspired Shell's version of the "no frills" platform.
Rothermund said, "In the case of the first generation southern gas fields like Leman and Indefatigable, the need to cut costs has been paramount.
"By the early 1990s, it was clear that without a significant, step-size reduction in operating costs the future of the fields was in serious doubt. The turnaround has been achieved by converting most of their platforms into unmanned satellites."
In 1992, there were 17 Shell-Esso platforms in the southern North Sea, of which 13 were manned. By the end of 1996, Shell-Esso will have 22 platforms in place, of which only three will be manned.
Rothermund said, "Over the period, offshore manpower will have been reduced by nearly 50%, while gas production will have doubled."
Shell-Esso built on the idea of unmanned platforms with the conception of the Limited Access Wellhead (LAW) platform, currently being evaluated.
"Such simple, lightweight satellite platforms contain only essential equipment and are designed for high reliability and minimum maintenance," Rothermund said.
"Existing unmanned platforms may have to be visited as much as three times a week. The target for LAW platforms is a once a year maintenance visit from a jack up or multipurpose support vessel."
Shell-Esso awarded Kvaerner H&G Offshore Ltd., Croydon, U.K., a contract to study feasibility of the LAW concept (OGJ, Oct. 11, 1993, p. 37).
The study is to evaluate hypothetical development of a field in 360 ft of water 10 km from a host platform. A Shell official said Kvaerner's work on the project is finished, and Shell is evaluating the results, Before the study, Shell said a LAW platform could be in place by 1997. The official said that after the study this statement still stands.
Shell was said to have no particular fields in mind for development with a LAW platform. Application of LAW to developments is to be decided on merit and considered case by case.
MONOTOWER
Kvaerner AS, Oslo, is targeting field development projects off Norway, the U.K., and Netherlands for use of two concepts it says can be brought from project approval to production within 1 year.
One Kvaerner design is the braced monotower for marginal field development. This has been used by Nederlandse Aardolie Mij. BY (NAM) in F/3 field off Netherlands, which began production in October 1993.
In F/3 field, the monotower is used as an offshore loading tower for export of oil previously stored in the platform's concrete base.
The braced monotower is made up of a single column on which topsides can be mounted, stayed by three symmetrically oriented braced legs angled outward and downward from the central column.
"Subsea technology on a stick," is the phrase used by Mike Smith, business development manager of consulting engineers Kvaerner Earl & Wright, to describe the braced monotower concept.
Smith said the installed cost of a braced monotower platform is about 6-10 million ($9-15 million), depending on water depth. Costs are kept down by use of standard equipment and the requirement of only a small crane vessel or jack up drilling rig for installation.
The design is suited to water depths of as much as 70 m. Smith estimated the monotower weight would work out at about 100 metric tons/10 m of water depth.
A typical wellhead platform on top of the monotower would house six wellheads and weigh about 300 metric tons, including heli-deck. Maximum topsides weight for a braced monotower would be 500 metric tons.
"The braced monotower is suited to gas fields designed to produce up to 100 MMcfd," Smith said. "A bi advantage-one that Kvaerner has patented-is that it is reusable. A braced monotower can be decommissioned and recommissioned within 48 hr.,,
MODULAR JACKET
The modular jacket, designed for water depths of 60-160 m, is made up of a base frame on which a number of jacket sections are mounted.
"For a modular jacket in 100 m of water you would need five jacket pieces in all, with weights ranging from 250 to 700 metric tons," Smith said.
This concept was inspired solely by the need to reduce installation costs in line with overall development costs.
For a conventional platform installed with one of the North Sea's giant crane barges, installation might cost 15-20 million ($22.5-30 million) out of a total project cost of 100 million ($150 million).
Because hire of a small crane barge capable of lifting only 2,000 metric tons would cost one fourth of the charter rate of one of the "big boys," Smith said, total development costs for a comparable field might be reduced to 30 million ($45 million).
"Installation of a modular jacket takes five or six days longer than a conventional jacket," he said, "but the installation cost is kept down to 5-10 million ($7.5-15 million)."
HALF PRICE
Aker AS, Oslo, has developed a new wellhead platform for marginal oil and gas fields, which the company believes can halve the development cost of traditional platform projects.
"Several operators have put satellite field developments on hold, says Aker, "because they will not be profitable with a traditional solution. This new concept could change several such developments into profitable projects."
This concept involves a light, relatively simple topsides placed on a steel jacket or concrete gravity base, with choice of substructure decided by specific project requirement and operator preference.
"Costs are slashed by means of standardizing design and fabrication and by reducing delivery time from 20 months normally to only 12-13 months," Aker said.
"In addition, major savings come from a strict priority of choosing equipment and in selecting which quality and standards the equipment should be. Only absolutely necessary facilities are included in the design.
"The equipment itself is largely based on standard vendor specifications rather than tailor-made solutions. The whole concept far the topsides is based on a building blocks principle, where complete modules of equipment can be added or exchanged, depending on what facilities are needed for each specific project."
PLATFORM IMPORTS
U.S.A. Platforms is a new U.K. group set up to offer North Sea operators a slightly modified version of a platform design which has a long track record in Gulf of Mexico development programs.
Companies involved in U.S.A. are fabricator SLP Engineering Ltd., Lowestoft U.K., which is leading the venture; installation contractor Ugland Offshore AS of Grimstad, Norway; and designer and manufacturer Atlanta Corp., Houston
U.S.A. is marketing Seahorse and Seaharvester platform concepts, first offered to Gulf of Mexico operators in 1984 by Atlantia. SLP said about 150 of these platforms have so far been installed in the Gulf of Mexico and other regions.
An SLP official said the idea of importing a concept was to be able to offer off-the-shelf platforms for which a price can be estimated "at the drop of a hat."
SLP has been in touch with certification authority Lloyd's Register, London, and the U.K.'s Health & Safety Executive and is said to have met no objection in principle to use of the design off the U.K. after minor modifications.
Seahorse is claimed to be the world's first and most widely used minimal platform jacket for marginal fields development projects. It involves two central steel support columns braced by a pyramid structure with four comer skirt piles.
Seahorse can be installed on its pyramid base in waters as deep as 30 m. For water depths to 90 m, the pyramid base is fixed on top of a box frame made up of one to six roughly cubic units.
SLP said the Seahorse can accommodate one to six wells, enough production equipment to process 70 MMcfd of gas with up to 1,200 hp compression, and emergency quarters.
SLP reckons it takes only 20-35 weeks to design, build, and install a Seahorse platform to develop a gas field with reserves of 5-50 bcf. Installed cost range is quoted as 5-10 million ($7.5-15 million).
Seaharvester is based on the Seahorse design, but it has four central steel support columns instead of two. It is designed for water depths of 90180 m.
SLP said the Seaharvester can accommodate 12 wells producing more than 100 MMcfd combined, with processing equipment and quarters to match.
Design, fabrication, and installation time is said to be 25-40 weeks, while capital cost range is quoted as 6-15 million ($9-22.5 million).
"Its low capital costs and large production capacity make it suitable for fields ranging in size from 10 to 100 bcf and from 1 to 30 million bbl of oil," SLP said.
YME FIELD
Norway's Den norske stats oljeselskap AS is putting a "no f-rills" approach into practice for development of Yme field in Block 9/2, which it sees as a pilot scheme for marginal field developments.
Yme is to be developed using a jack up rig modified to carry oil production and processing facilities. Oil will be stored in a moored tanker prior to shipment to shore by shuttle tanker.
The field, estimated to hold 36.5 million bbl of oil, is slated to go on production Oct. 15. Peak production is to be 50,000 b/d.
Rather than pay a capital cost up front, Statoil chartered the Maersk Giant jack up rig for 36 months, which can be extended as required.
The rig is due to go into a yard for conversion May 1. Modifications are expected to take 4 months.
The tankers will come from Statoil's fleet.
BRITANNIA
Joint operators Chevron U.K. Ltd. and Conoco (U.K.) Ltd. recently announced government approval for a Fl.5 billion ($2.25 billion) development of Britannia field, the U.K.'s largest undeveloped gas/condensate discovery.
Britannia, which sprawls across Blocks 15/29a, 15/30, 16/26, 16/27a, and 16/27b, holds estimated reserves of 2.6 tcf of gas and 140 million bbl of condensate (OGJ, Dec. 26, 1994, p. 30).
The field is slated to begin production on Oct. 1, 1998. Development will involve an eight leg steel platform with satellite wells tied back via a subsea manifold. Peak production is expected to be 740 MMcfd of gas and 70,000 b/d of condensate.
Although Britannia is among the U.K.'s largest current projects marked for development, the operators will use the same minimum facilities philosophy that is being applied to much smaller developments.
From an original development cost estimate of more than 2 billion ($3 billion), which earlier this year was trimmed to 421.8 billion ($2.7 billion), Chevron and Conoco now reckon the eventual capital cost could be about PI.35 billion ($2.03 billion).
The companies said development costs were cut by reducing redundant equipment on the platform, using reservoir engineering to reduce well numbers, and simplifying gas processing plant design.
Development of the project was delayed from an earlier schedule that scheduled start of gas flow in 1997. Chevron and Conoco said they used the time gained for an attack of capital spending by means of a technique they call "value engineering."
The companies said, "Project staff are encouraged to question systems and equipment items ordered and check that they meet acceptance criteria. Then, if they do meet the criteria, they question if there are even better solutions and look for synergies between components."
For example, a 25% savings in man-hours on piping engineering and stress analysis is expected as a result of this process, yielding a savings of PI.5 million ($2.25 million).
"An ideas database has been set up on the project computer network and all staff are encouraged to contribute," the companies said. "It currently contains nearly 400 ideas which, if put into practice, could save several million pounds."
"These are exciting projects and innovations," said Rothermund, reviewing ideas discussed at a Crine seminar. "But increased production has also come by improving reliability, thereby minimizing downtime, and by systematic 'barrel chasing' to squeeze as much as possible from the fields and field facilities.
"All the oil companies are exploring different ways of cutting development costs," said Robin Davies, marketing manager of Brown & Root Ltd., London. "The driver is the low oil price expected over the next few years. If operators can see a new concept working, the market will respond by leaping on the bandwagon."
Copyright 1995 Oil & Gas Journal. All Rights Reserved.
