Jeremy Beckman • London
BP has won UK government approval for the $7-billion second-phase development of the Clair field west of Shetland. The Clair Ridge project will target 640 MMboe of reserves in an area north of the Clair Phase 1 facilities, which came onstream in February 2005. The field, discovered in 1977, is one of the UK's largest, but technology limitations caused development of the complex reservoirs to be postponed for more than two decades.
Clair Ridge calls for construction of two new bridge-linked platforms, both to be installed in 2015 with oil production starting the following year and peaking at 120,000 b/d. The new facilities are designed to extend production from the greater Clair area through 2050, and they will also serve as a hub for future expansion, depending on the results of appraisal drilling. There is potential, as a new well this year has confirmed an oil extension to the southwest of Clair.
Various new techniques will be applied for Clair Ridge, including what BP claims will be the world's first full-field deployment offshore of LoSal equipment designed to modify the salinity of water injected into the reservoir to increase oil recovery. And vapor recovery will be implemented to capture and recycle produced low-pressure gas for fuel or for exports to Scotland.
BP Group's chief executive said this and the company's other new UK projects, including the Schiehallion/Loyal field redevelopments west of Shetland and the Devenick, Kinnoul, and Andrew area schemes, should allow it to maintain production from the North Sea at 200,000 – 250,000 boe/d until 2030.
So, not all the majors are scaling back in the UK North Sea, although ExxonMobil has agreed to divest its interests in the giant Beryl complex and other fields to Apache, under a transaction valued at $1.75 billion. Apache will look to repeat the turnaround it achieved on the declining Forties field facilities which it acquired from BP in the previous decade. Here the company has drilled a further 100 development wells, produced 161 MMboe and added around 171 MMboe in fresh reserves.
RWE Dea has taken delivery from Heerema of the Breagh Alpha platform for the Breagh gas field in the UK southern North Sea. Pictured are the topsides during load-out onto the seagoing barge at Heerema Zwijndrecht, near Rotterdam.
Ministry presses co-development of Luno, Draupne
Norway's Ministry of Petroleum and Energy is insisting on a joint development solution for the Luno and Draupne fields in the North Sea, which hold combined reserves of over 330 MMboe. The two fields are only 8 km (4.9 mi) apart – both sets of licensees had discussed a unitized scheme, but this appeared to have fallen by the wayside for cost/scheduling reasons. However, the Ministry is adamant that only a cooperative arrangement will be approved, which it views as of greater benefit to the area and Norwegian society as a whole.
Lundin Petroleum had just completed the front-end engineering design for its 188 MMboe Greater Luno Area, which would take in the recent Tellus basement discovery to the north. Lundin claimed it had proposed a joint scheme to the Draupne licensees prior to receipt of the Ministry's letter, and provisions for this arrangement are included in its draft plan. It also has just secured a rig for development drilling, with a target of first oil late in 2015. Det norske oljeselskap, operator of Draupne, had been evaluating an alternative joint scenario grouping together its Hanz and West Cable discoveries.
Both operators may have had other matters on their minds; both are partners in Statoil's potentially giant Aldous Major oil discovery in North Sea license PL265, and Luno operating the connected Avaldsnes find in PL501. Following a new audit of Avaldsnes by Gaffney, Cline & Associates, Lundin has upped its estimate of recoverable sources to 800 MMbbl to 1.8 Bbbl. Prior to its latest appraisal well, Statoil had postulated 400 to 800 MMbbl recoverable for Aldous Major, suggesting 1.2-2.6 Bbbl under a combined scheme.
Analysts Wood Mackenzie believe the value of these discoveries could hit $13 billion, and assuming development over the next few years, the potential to provide 20% of Norway's total oil output from 2020 and over half by 2027.
Bids close for Norway round
Avaldsnes and other recent finds in mature parts of the Norwegian Sea were on acreage issued under Norway's Awards in Predefined Areas licensing scheme. So claimed Johannes Kjode, deputy director general of the Norwegian Petroleum Directorate in his comments on APA 2011, which has drawn applications from 41 companies. The Norwegian Ministry of Petroleum and Energy expects to issue licenses for this round either by year-end or early in 2012.
APA 2011 offered 377 blocks across a total area of 108,430 sq km (41,865 sq mi). The pre-defined area in the Norwegian Sea was expanded by more than 20,900 sq km (8,069 sq mi) compared with what was offered under APA 2010.
Dutch appraisal plans
The Dutch government has extended the terms for the M10/M11 shallow water block licenses through June 30, 2013, according to operator Ascent Resources. The blocks are off the north coast of the Netherlands, and include three structures with gas discoveries, all from the Slochteren unit of the Rotliegendes sandstones. The partners plan to drill a final appraisal well in the second half of next year on the Terschelling Noord discovery to confirm reservoir parameters for detail design for a development.
Also in the Dutch sector, Australian-owned Petro Ventures Netherlands has agreed to farm into five shallow water blocks operated by Sterling Resources in the F and L quadrants. The blocks contain four oil finds, and an appraisal well was due to be drilled this fall in F17.
Another company, Oranje Nassau Energie (ONE), has completed acquisition of a stake in the offshore Q16a license from NAM, and operatorship of the Q16/FA gas field. Earlier this year ONE acquired the Dutch production and exploration interests built up by Canadian company Cirrus Energy.
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