New technology, concepts aim at lower costs
Guntis MoritisNew technologies both at the application stage and at the concept stage aim at reducing costs for producing and developing offshore fields.
Production Editor
At the center of many of these new technologies are floating production, storage, offloading, and drilling vessels. These vessels are tied to subsea completions that take advantage of smaller and lighter wellheads, and such emerging technologies as subsea multiphase meters and pumps, and subsea separators and boosters.
Operators now also can define and reach new producing horizons more accurately with new seismic techniques and by drilling complex extended reach and horizontal wells.
One estimate is that offshore Norway, alone, will realize from fields currently producing and fields approved for development an additional 3.1 billion bbl of oil by implementing improved oil recovery methods such as new drilling techniques and more extensive gas and water injection projects.
According to the Norwegian Petroleum Directorate, the aim in Norway for its offshore fields is to increase the average recovery factor from 39% to 47%. Fig. 1 shows the rapid rise, during the last few years, in oil recovery factors for some of Norway's main producing fields.
Floating production
Forecasts indicate that the number of floating units involved in offshore production will rapidly increase. A report, recently published by the International Maritime Association, lists 62 floating production systems currently in place in the world: 6 tension-leg platforms (TLPs), 25 semisubmersibles, and 31 floating production, storage, and offloading vessels (FPSOs).
IMA estimates that 130 new floating production systems are at various stages of planning and development. At mid-1996, 30 of these systems were on order, representing a capital investment of $8-10 billion. IMA estimates that over the next 3-5 years another $10-15 billion will be spent on floating production systems.
Floating production systems are a boon for both developing marginal fields and deepwater fields in which it is not cost effective or possible to set traditional steel or concrete platform structures. These systems represent both new builds and conversion of existing vessels for production.
New builds are primarily for long-lived fields such as in the case of Den norske stats oljeselskap a.s.'s (Statoil's) Aasgard project for developing three separate 1980 Norwegian Sea discoveries. The Aasgard FPSO has a 25-year design life and Statoil estimates that the facilities may be used for as long as 50 years.
The Equatorial Guinea Zafiro field (operated by Mobil Corp.), on the other hand, will need an FPSO only for the first phase of the project. Mobil obtained an FPSO that was converted from a tanker on a 3-year contract with options for 2 additional years (OGJ, June 10, 1996, p. 28).
Lower cost well work
One concept becoming more practical as drilling rig day rates escalate, and because of the recent failure of Statoil's twin-hull (Swath) vessel to pass a tank test, is to include a drilling/workover rig on the turret of a ship-shaped FPSO. Fig. 2 -- the Concept of drilling rig on FPSO turret [79453 bytes] illustrates the Maritime Hydraulics a.s. concept for its hydraulic powered rig on the turret of a TenTech FPSO design.
Statoil had planned for the dynamically positioned Swath vessel to significantly reduce well completion and workover costs compared to anchored semisubmersible rigs.
Another concept for a vessel that may also be in the running for both production and well work is the Ramform design that Petroleum Geo-Services AS (PGS) has successfully used to speed 3D seismic surveys.
According to PGS, the vessel is very stable and capable of topsides of up to 14,000 tons compared to semisubmerible capacities of 4,000 ton loads.
PGS envisions that these vessels could serve as shuttle tankers with oil being stored above the sea level. Also, larger versions could act as production facilities, drilling vessels, or cable laying vessels. It estimates that a vessel with production facilities would be about 165 3 330 ft. Its current seismic vessels are about 130 3 270 ft.
Smaller turret
Large, heavy, expensive turrets are the norm for most new build FPSOs but there are other concepts that may cost less and offer more flexibility. One such concept is the Statoil, Advanced Production Loading (APL), and Framo Engineering A.S. multipath, disconnectable fluid swivel (Fig. 3 [117431 bytes]). The submerged turret loading system has been used in several North Sea projects, and it also has been modified for production.
The first application may be Statoil's Lufeng 22-1 development, offshore China.
Subsea systems
An area where subsea systems are changing is in the reduction of the size and weight of equipment. This allows installation and servicing of subsea equipment with a drilling rig or from a smaller, less specialized vessel.
Well heads
Subsea trees are more compact and lighter, especially the horizontal tree design compared to the standard subsea tree design.
Horizontal trees have valves on the side to permit fullbore entry through the tree. This eliminates the need to pull the tree for well workover or recompletion work.
In Kvaerner Oilfield Products a.s.'s version of the horizontal tree, scheduled to be installed in Norsk Hydro a.s.'s Njord field, the production guidebase has been eliminated and flow lines are tied directly into the tree.
New remote-operated vehicle tie-in equipment for connecting flow lines to the subsea trees can work in much more restricted areas. Kvaerner says the porch size on its equipment is about 1.5 ft instead of the 13 ft or more previously required. This allows subsea equipment to be placed much closer together.
Other subsea equipment
Other subsea equipment such as multiphase meters, multiphase pumps, and subsea boosters aim to reduce flow line costs and permit production of more remote satellite fields.
Subsea boosters have been proposed for Statoil's Lufeng 22-1 development (Fig. 4 [121916 bytes]). These boosters would eliminate the need to run submersible pumps in the wells. The first subsea booster was installed in the A/S Norske Shell's operated Rogen South satellite of the Draugen field in 1993.
New principles
A number of different concepts are being developed for subsea multiphase meters that rely on considerably different principles. The Kongsberg Offshore a.s. meter is based on measuring the dialectric constant of the flow.
Multi-Fluid International A/S uses microwave technology to determine flow and Framo first homogenizes the flow before measuring it with a venturi meter (Fig. 5 [48384 bytes]).
Framo has orders to install its subsea meters in the East Spar development in Australia, Statoil's Aasgard South field in Norway, and BP's Eastern Trough Area Project (ETAP) field in the U.K. The Statoil Aasgard order is for qualification testing.
Various concepts for subsea separation and subsea multiphase pumping are being developed. Fig. 6 shows Kvaerner's version of a subsea separator. One objective of some subsea separators is to reduce the amount of water flowing from the well to the processing facility. Less water in the flow line reduces back pressure on the well, allowing it to flow longer and at greater rates.
![Fig. 2 -- the Concept of drilling rig on FPSO turret [79453 bytes]](http://images.pennwellnet.com/ogj/images/ogj/9441jmo02ac.gif){kind=link}
![Fig. 3 [117431 bytes]](http://images.pennwellnet.com/ogj/images/ogj/94415002.gif){kind=link}
![Fig. 4 [121916 bytes]](http://images.pennwellnet.com/ogj/images/ogj/94415101.gif){kind=link}
![Fig. 5 [48384 bytes]](http://images.pennwellnet.com/ogj/images/ogj/94415102.gif){kind=link}
Kvaerner's subsea separator is one version that is undergoing testing (Fig. 6).
Composites
Composite materials are one solution for reducing overall weight of topsides for floating vessels and subsea completions. Although initially still more costly than steel, composites in corrosive environments can mean lower costs over the life of a facility.
The Composite Engineering & Application Center (CEAC), a consortium of the industry, government, and University of Houston, has been active in determining the benefits of composites for oil and gas production facilities.
CEAC member organizations include: Amoco Corp., BP Exploration Inc., Conoco Inc., Phillips Petroleum Co., Shell Development Co., Ameron Fiberglass Pipe System, McDermott International, Smith Fiberglass Products Inc., U.S. Department of Energy (DOE), and the U.S. Minerals Management Services (MMS).
CEAC recently completed an initial study to assess the economics and benefits of composite materials in deepwater developments in the Gulf of Mexico. A second phase of the study is in the planning stages. Results will be discussed in a conference planned for fall 1997.
Composite materials have the potential for reducing hydrocarbon finding and producing costs, especially in deepwater. CEAC says the benefits of composite materials are their light weight, corrosion resistance, and high strength/stiffness-to-weight ratio.
CEAC estimates that the weight saved with composite components (vessels, piping, secondary structures, etc.) in the topsides, risers, and moorings should be translated into reduced structural weight and buoyancy required to support the topsides equipment, risers, and moorings.
But CEAC says very little is gained if lightweight components are used, but the deck structure and hull are still designed to support the original 100% steel topsides and risers.
Composites are made from high-strength fibers in a polymer matrix. The three main fibers are glass, carbon, and aramid (Kevlar). Polymers can be epoxy, vinylester, and phenolic. Each of these composites has different strengths and weaknesses. The lowest cost are the glass reinforced epoxy (GRE) pipe and tubulars.
Glass-reinforced polyester (GRP) has been used for overtrawlable subsea structures. Seanor Engineering A.S. provided these structures for the Draugen field.
The Troll onshore facility at Kollsnes, Norway, also extensively includes GRP composites. The building of the facility onshore eliminated the need to install extensive processing facilities on the offshore Troll platform.
For Troll onshore, protruded GRP from Norwegian Applied Technology A.S. (NAT) was installed for gratings, stairs, ladders, and handrails. Although more expensive than steel initially, NAT says GPR was justified based on the life-cycle cost over the 50-year design life of the facility. The GRP should stand-up to the very corrosive seashore environment at Kollsnes, which because of the seashore environment is said to be more corrosive than if the facility were offshore.
NAT estimates that the ratio of initial and life time costs of GRP to steels is as follows:
- Gratings, length 3,000 m - initial 1.2, life 0.8
- Stairs, length 100 m - initial 2.13, life 1.48
- Ladders, length 2,500 m - initial 1.04, life 0.7
- Handrails, length 15,000 m - initial 1.03, life 0.63
Composites also have been extensively used on the Shell Offshore Inc. Mars TLP in the Gulf of Mexico and are scheduled to be included in Shell's other upcoming TLPs and subsea developments.
The Dupont Group and Kvaerner plan to test a prototype composite drilling riser on the Heidrun TLP in 1998. Composites could also be used to lower the weight of TLP tendons.
Coiled composite pipe is also under development by such companies as Compipe AS. Its version aims at reducing costs for subsea service, water injection, and flow lines. The pipe Compipe is developing has a fiber glass epoxy outer layer and a thermoplastic inner liner.
About this report
The Journal's exclusive Production Report, written and edited by Production Editor Guntis Moritis, examines the industry's move to develop deepwater and marginal fields with floating production systems combined with sophisticated subsea and well completion technology. Onshore, we look at more-efficient sucker rod-pumping designs and discuss power costs as they relate to the pending U.S. electric utility deregulation.
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