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The Greater Plutonio accumulation lies in 1,200m to 1,500m of water, 160km northwest of Luanda in the Block 18 concession. It consists of five distinct fields; Galio, Cromio, Paladio, Plutonio and Cobalto. It was discovered in 1999-2001 and is the first BP-operated asset in Angola. It has total estimated reserves of about 750 million barrels, making it one of the biggest off Angola’s coast.
In 1999, BP drilled the Platina (in the west of the block) and Plutonio wells using the deepwater drillship Pride Angola, and followed these in 2000 with Galio, Paladio, Cromio and Cobalto. They are all located within 20km of each other.
Later discoveries included the Cesio and Chumbo fields, slightly further to the south and west. It is likely that Cesio and Chimba will be developed with Platina. These fields hold up to 300 million barrels of recoverable oil between them and are due to come on stream between 2008 and 2010.
The Greater Plutonio development was approved in early 2004. Originally, BP Angola and Shell Exploration and Production Angola BV hold Block 18’s exploration permit under a production-sharing contract with Angola’s state-owned oil company, Sociedade Nacional de Combustveis de Angola (Sonangol). Now, while BP still has a 50% interest in the block, which was acquired by Amoco in 1996 prior to its merger with BP, the other 50% is held by Sonangol Sinopec International, a joint venture between the Chinese and the Angolan state oil companies, which bought out Shell’s interest.
The focus for the exploration campaign has been the northern part of the block, adjacent to neighbouring Block 17. It resulted in eight successes from eight exploration wells drilled.
Development of Greater Plutonio, which has cost an estimated $1,000m, presented a number of challenges. The fields are spread over a wide area (35km from Platina to Cobalto) with water depth varying from 1,200m to 1,500m. In addition, the group of fields involves reservoirs at different stratigraphic levels.
The joint development uses 43 subsea wells – 20 producers, 20 water injectors and three gas injectors – tied back to a single spread moored FPSO facility to process produced fluids and export crude.
The heart of the subsea system is the longest single riser tower system of its kind in the world. At about 1,250m, it connects the FPSO to a network of subsea flowline and control systems that include 150km of flowlines, nine manifolds and 110km of instrument and control umbilicals.
The 310m-long, "all-electric" FPSO has an oil storage capacity of 1.77 million barrels, oil processing capacity of up to 240,000 barrels of oil per day, produced and treated water injection rate of 450,000 barrels per day, and gas handling capacity of up to 400 million standard cubic feet per day. It is held in position by 12 mooring lines connected to anchor piles on the seabed.
With a 3½-year development timeline, production started on 1 October 2007 and is expected to reach 250,000 barrels of low-sulphur medium gravity crude per day. Capital expenditure for the development has been estimated at $4 billion over the life of the fields.
The project features some innovative and novel technologies being applied such as a distributed temperature sensing system linked to downhole flow control of water injection, subsea multiphase metering and running trees on wires.
BP awarded FMC Kongsberg Subsea a $270 million contract to supply subsea systems and related services. The FMC unit’s scope of supply for the entire project included 45 subsea trees and associated structures, manifolds and production control systems, as well as connection systems for flowlines and umbilicals.
In 2005, BP signed a further $80 million contract with FMC Kongsberg for the supply of subsea systems covering installation services and local Angolan supply. FMC Technologies also supplied technical services related to installation and start-up.
BP also awarded a $730 million field development contract to a consortium of Stolt Offshore and Technip. The contract covered engineering, procurement, fabrication and installation of risers, umbilicals and flowlines to serve all the fields. Stolt Offshore led the consortium, installing 75km of 12in insulated production, gas injection, and service flowlines and 103km of umbilicals. The consortium also installed 12 FPSO mooring lines, the production manifolds and a single riser tower to hook up the FPSO.
Kellogg Brown & Root oversaw the engineering, procurement, construction and management, and Hyundai Heavy Industries fabricated the FPSO hull and topside equipment, at an estimated cost of $650m. Emerson was awarded $9 million for automation of offshore oil production.
WellDynamics and BP signed a multi-well contract for the provision of SmartWell downhole flow control and ancillary completion equipment to manage water injection. The project required equal numbers of oil production wells and water injection wells. The water injection wells provide reservoir pressure support and sweep efficiency to ensure optimal reserve recovery. An additional three gas injection wells are used for reservoir pressure support and to dispose of associated gas production.
Other contracts for the development included Transocean for drilling contract services.
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