Installation of floating production systems (FPSS) is accelerating in the Eastern Hemisphere.
As with the Western Hemisphere (OGJ, Dec. 7, p. 18), the bulk of Eastern Hemisphere FPS action has occurred in just two theaters of operations: Offshore Northwest Europe and Offshore Northwest Australia.
FPS field developments are slowly gathering momentum in the U.K. North Sea, but a number of factors are holding up progress off Norway.
In the U.K. sector, two FPS developments have recently been confirmed. Also, the completion of production from the U.K.'s first oil field has put a converted semisubmersible FPS onto the market,
Several discoveries off Norway are potential FPS developments, but there has been no permanent FPS installation there to date. The South Smorbukk field on the Haltenbanken was destined to have Norway's first FPS, until operator Den norske stats oljeselskap AS (Statoil) put the project on ice. South Smorbukk was deferred so Statoil could rethink the project to improve field economics. Other Norwegian FPS prospects have suffered the same fate.
Throughout the 1980s and into the 1990s Australia has been a leading proponent of floating, production, storage, and offloading (FPSO) systems for offshore oil development projects. It is the nature of fields discovered off Northwest Australia that makes them ideal candidates for FPSO applications.
Outside Australia and Northwest Europe, FPSs have seen limited application. Among countries where FPSs have been installed or are planned are:
- Italy, where the country's largest oil field, Vega, produces oil into a converted 250,000 dwt tanker moored off southern Sicily (OGJ, Sept. 7, 1987, p. 26). FPS systems also were installed in Mila and Nilde fields off Italy.
- Philippines, where Alcorn International Inc., Houston, is producing about 16,500 b/d of oil from West Linapacan A field with an FPSO in the South China Sea (OGJ, Sept. 21, p. 36). The converted tanker FPSO 11 that Alcorn had refurbished for Linapacan development had operated in Cadlao field off the Philippines for a decade.
- Gabon, where Amoco recently released the Ocean Producer FPSO from Gombe-Beta field (OGJ, Feb. 24, p.32).
- China, where the Agip SpA, Chevron Corp., and Texaco Inc. combine plan to develop Huizhou 32-2 and 32-2 oil fields with fixed platforms for production into an FPSO (OGJ, Sept. 28, p. 23).
Other FPS/FPSO systems in the Eastern Hemisphere have been installed or are planned off Spain, Tunisia, Egypt, Nigeria, and Indonesia.
U.K. HUDSON
Off the U.K., Amerada Hess Ltd. (AHL) decided last month to develop Hudson field, in Block 210/24a northeast of the Shetlands, using the Petrojarl 1 floating production vessel. The vessel is now located in Angus field on Blocks 31/21 and 31/26a.
While the vessel produces as much as 35,000 b/d of oil from Hudson through two subsea completions, six additional subsea wells are to be tied back 11 km to the Shell/Esso Tern platform for second phase development.
"Although unusual, we believe that the two phase development has great advantages for the Hudson owners," said Sam Laidlaw, AHL managing director and FPS advocate (OGJ, Aug. 17, p. 58).
"The use of the Petrojarl would mean that first oil could be achieved very rapidly after the approval of Annex B (development plans). Phase 2 could be developed simultaneously with this early production. Additionally, we would gain valuable knowledge of reservoir performance which would optimize Phase 2 development."
AHL's recent Fife discovery on Block 31/26a (OGJ, Nov. 2, 1992) may be the next destination for Petrojarl, according to Kate Jackson, analyst at County NatWest WoodMac, Edinburgh.
"A floater is a strong possibility for Fife," said Jackson. "And the development plan may have the right timescale to move the vessel on from Hudson."
GRYPHON
Kerr-McGee Oil (U.K.) plc decided in October to buy the production ship Tentech 850 from Ocean Producsjon AS, to develop Gryphon field on North Sea Block 9/18b.
The vessel is being built by Astano Offshore SA, Madrid, and will be completed by yearend.
Production facilities will then be installed ready for taking to the field next September, with a view to producing first oil in October. Kerr-McGee has yet to award the installation contract.
The vessel's production capacity will be 60,000 b/d of oil with a gross liquids capability of 78,000 b/d. Water injection capacity will be 79,000 b/d and gas lift capacity 21 MMcfd.
ARGYLL/DUNCAN
Production from Hamilton Oil Co. Ltd.'s Argyll and Duncan fields, on North Sea Blocks 30/24, ended last month as output declined beyond the economic limit.
The FPS Deep Sea Pioneer, a converted semisubmersible, was moved off the field to Dundee at the end of November and is being prepared for sale. Several operators are in discussion with Hamilton regarding purchase. An announcement is expected soon.
Argyll field provided the first oil to be commercially produced from the North Sea on June 11, 1975. It was originally developed using the world's first FPS, the converted semi Transworld 58. This was replaced by Deep Sea Pioneer in 1984.
U.K. PROSPECTS
Texaco Ltd. is considering an FPS development of Galley field, on North Sea Block 15/23a.
Alternatives include a subsea development tied back to Texaco's Tartan field on Block 15/16 or the Elf Enterprise Caledonia Ltd. Piper or Saltire fields on Block 15/17.
High pressure is the main obstacle to an FPS solution on Galley. One well has shut-in pressure of 8,500 psi. The field also has a high gas/oil ratio, requiring more than 40 MMcfd gas handling capacity. No current FPS can handle these requirements.
Shell U.K. Exploration & Production is considering FPS solutions for future Central North Sea production. Possible Shell[Esso developments in the area include Guillemot on Block 21/24, Heron on Block 22/30a, Puffin on Block 29/4a and Skua on Block 22/24b (OGJ, Aug. 17, p. 50).
SOUTH SMORBUKK
Statoil planned to bring South Smorbukk field on stream in 1996 as the first FPS development off Norway.
Early this year Statoil commissioned Kvaerner Engineering AS, Stavanger, to adapt the design of Kvaerner's production ship to develop the field.
A month later Statoil asked Aker Engineering AS, Oslo, to evaluate three alternative production vessel concepts with storage capacities of 378,000 bbl, 472,500 bbl, and 630,000 bbl of oil.
In June Statoil put South Smorbukk development on hold so it could perform new field development studies to include main Smorbukk field before applying for development approval. Smorbukk holds 125 million bbl of oil reserves and 2.3 tcf of recoverable gas.
No time has been set for a decision on development, but Statoil is looking to early 1994.
WEST TROLL
Norsk Hydro AS intends to use an FPS to develop Troll field's oil reservoir but was forced to invite bids for steel options to compare with the originally preferred concrete proposal.
Concrete FPS concepts were submitted separately by Kvaerner Doris Offshore Concrete and Norwegian Contractors. But market demand pushed the price for concrete high, altering the economics of what was already a marginal development.
Quotes for a concrete floater were two and a half times Hydro's estimate submitted to the Norwegian Ministry of Oil & Energy in December 1991. Then Norwegian Contractors' parent, Aker AS, pulled out, saying it was giving current projects priority and therefore could not meet the construction schedule.
During November Hydro issued bidding documents for steel semisubmersible options. Responses are expected during December, so that Hydro can choose between concrete and steel by yearend. Hydro must also choose between a tethered and a moored system.
NJORD
Norsk Hydro AS last year shelved development of Njord field on Blocks 6407/7 and 10, after receiving tenders for FPSs from Golar-Nor Offshore AS of Trondheim, Smedvig AS of Stavanger, and Kvaerner Rosenberg AS, Stavanger.
These solutions involved leasing from the owners and were ruled out because of high costs.
The operator now is considering a variety of floaters for Njord, concrete as well as steel, with an eye to starting development in 1994.
Options are open on Hydro's Visund field, too. This field is planned to begin development at about the same time as Njord and to come on stream at about the same time, in 1997-98.
BALDER
Esso Norge AS is considering an FPS development in Balder field on Norwegian Blocks 25/10 and 25/11.
Production tests were run last year using the Petrojarl 1. Results were to help form a decision on development plans this year, but this has been deferred until 1993.
Studies have been completed on ship and semisubmersible FPS options, subsea development, and a fixed platform.
A turret moored FPS similar to the Tentech 850 ship was studied 2 years ago during Exxon Corp. research into development options for use worldwide.
SNOHVIT
The Statoil operated Snohvit field in the Barents Sea is a potential candidate for an FPS, but its isolation from infrastructure and gas markets makes it a long term prospect.
Rolf Rolfsen, managing director, Total Norge AS, said it will be some time before the level of oil prices is right for development.
Total is a member of the Northern Norway LNG Venture group, along with Statoil and Norsk Hydro, set up to market jointly the gas reserves of this area.
The group is courting Ente Nazionale per d'Energia Elletrica, the Italian electric power utility, as a customer for Snohvit LNG.
They have been talking for 18 months now, and "It could easily be another 1 1/2 years before a deal is agreed," said Rolfsen.
AUSTRALIA'S FPSO PUSH
Currently there are three FPSOs working off Australia: Jabiru, Challis, and Skua, all in the Timor Sea and operated by BHP Petroleum Pty. Ltd.
A fourth, involving Griffin development on the Northwest Shelf, is under construction, while a fifth-the Wanaea/Cossack project also on the Northwest Shelf-is under consideration.
A sixth-the Marathon Oil Co. group's nearby Talisman field facility-has been dismantled following depletion of the reservoir.
It is estimated that the three Timor Sea FPSOs are contributing about 80,000 b/d to Australia's total estimated oil output of 510,000 b/d.
BHP'S VIEW
BHP engineers maintain that the combination of environmental conditions, lack of infrastructure, water depth, field size, and excellent reservoir quality off Australia's northwest coast make FPSOs a logical choice for oil developments in the region.
BHP refers to the process of determining the economics of field development as a "bottom up" exercise. In other words, reservoir characteristics are the main determinant of any development plan, and this in turn determines the recovery rate. The optimum surface facilities, then, are those that accommodate the subsurface development plan in the most cost effective manner with minimum risk, adequate environmental safeguards, and flexibility.
The company has found that flexibility is a major advantage offered by subsea developments combined with an FPSO.
JABIRU'S EXAMPLE
Jabiru-the oldest of the currently producing facilities-is a case in point.
BHP committed to a $70 million (Australian) development in the early 1980s on the basis of 11 million bbl of reserves and a development plan involving one producing well. The design incorporated the possibility of hooking up four wells.
With further appraisal drilling and a number of years of production history behind it, BHP now estimates reserves at more than 100 million bbl and has had all four production well slots occupied most of the time.
The jabiru Venture production/storage vessel has undergone two major upgrades that included increasing height of the flare stack to cope with increased gas flaring. There has also been the addition of three-stage separators and extra gas lift compressors, along with hydrocyclones to enable wells to be produced at water cuts exceeding 95%.
BHP has shown that the FPSO option has the flexibility to accommodate any changes necessary to boost the economic recovery of oil. With Jabiru the changes have been prompted by increases in reserves, but that flexibility has also worked for the reverse situation-in Skua field where reserves were downgraded. In that location, the FPSO incorporated with subsea wells has enabled the economic development of a small oil accumulation in a remote area.
BHP also points out that the initial jabiru facility involved only simple crude processing. Over the subsequent 8 years, the FPSO has been expanded to incorporate all the major facilities normally associated with the more complex oil field developments. At jabiru and Skua, for instance, the improved design incorporates a sophisticated natural gas liquids recovery plant-something seldom seen offshore until recently. There are also gas lift and water injection facilities on board.
AUSTRALIAN FPSO OUTLOOK
Looking ahead to BHP's proposed Griffin field development, the design takes this a step further and utilizes gas injection.
Griffin project features an advanced technology design that can accommodate as many as 15 wells and is believed to be the largest number of wells connected to an FPSO. And there is still flexibility for future additional wells.
There has also been a progression from one swivel per well controlled by hydraulics on the riser system to functional grouping of swivels and electrohydraulic control of the wells. For Griffin, the control umbilicals and service lines will be shared between well clusters to economize on space within the riser.
To achieve the required control, BHP engineers have adopted an electrohydraulic system with data being multiplexed across the swivel.
In short, BHP maintains that the FPSOs have evolved from fairly simple and basic development tools to facilities as sophisticated as can be found on fixed platforms anywhere in the world.
Copyright 1992 Oil & Gas Journal. All Rights Reserved.
