OFFSHORE EUROPE
Jeremy Beckman • London
UK looks to harness brownfield potential
Average production from UK fields fell by 9% last year to 2.4 MMboe/d, according to Oil & Gas UK’s latest Economic Report. Overall output is set to dip by a further 6-8% to 2.2-2.3 MMboe/d this year, the association adds.
The rate of decline is linked directly to the rate of investment in new and existing fields, and spending has diminished steadily since 2007. However, if levels could be sustained at £5 billion/yr ($7.6 billion) or above in today’s money, UK fields could still deliver around 1.5 MMboe/d in 2020, the report claims. That would still be sufficient to satisfy half Britain’s oil and gas demand.
The report identifies 73 potential new UK field developments, ranging in size mainly from 5 to 100 MMboe. These, alongside brownfield expansion programs, could lead over time to recovery of 1.5 Bboe at a capital cost of £16 billion ($24.4 billion). Of that total, around 80% would most likely head to projects in the central North Sea and west of Shetland.
As for existing fields, the report estimates that a 2.5% increase in the overall recovery rate could unlock a further 1 Bboe of reserves. However, this may depend on deployment of new forms of technology which have so far featured only onshore, such as chemical, polymer or CO2 flooding, and “tight gas” production.
Exploration on upward curve
Drilling confidence appears to be picking up throughout northwest Europe. Deloitte’s latest activity review lists 28 exploration and appraisal (E&A) wells across the UK shelf in the second quarter of this year, a jump of 86% on the same period in 2009. The southern gas basin led the way, accounting for 38% of the latest wells. Seven of those completed encountered oil, with one gas discovery.
Offshore Norway, 19 E&A wells spudded during the second quarter of this year, up 58% on the first quarter, with seven of the completed wells finding hydrocarbons. Two-thirds of the activity was in the Norwegian North Sea, the remainder further north in the Norwegian Sea. And off the Netherlands, there were six new E&A wells, up 66% on 2Q 2009.
Among the successes was EnCore’s Catcher oil discovery in UK central block 28/9, which the company rates as a 300-MMbbl prospect, following appraisal drilling southwest of the main structure. GDF Suez is also upbeat on Cygnus in the southern sector, after completing its sixth appraisal well. It now estimates reserves at 500 bcf – 1 tcf recoverable, and is working on an expanded two-phase development involving facilities on Cygnus’ eastern and western fronts.
Pipeline changes under way
DONG has won approval for its Trym development in the far south of the Norwegian sector, although construction has been under way since 2009. This will be the first Norwegian field to export production to a Danish field center, in this case Maersk’s Harald platform via a 5-km (3.1-mi), 8-in. (20.3-cm) subsea multi-phase pipeline.
This spring, Denmark’s energy ministry proposed an amendment to its Pipeline Act regulating use of the Gorm field pipeline, which transports the bulk of Danish offshore oil production to a terminal at Fredericia. The amendment is driven by DONG’s plan to develop the high--pressure/high-temperature Hejre field via the Gorm pipeline.
Hejre’s input would introduce a higher content of light hydrocarbons into the line, which would have to be separated on exit to allow separate shipment of crude oil and condensate products (butane and propane). The amendment will provide for the establishment of separation facilities.
Aker Solutions built the manifold for DONG’s Trym, the first subsea tieback from Norway to Denmark.
In another development, the Danish Energy Agency is considering alternative uses for Danish platforms facing decommissioning. Some are connected to Dutch infrastructure via the gas pipeline extending from Tyra West to the NOGAT trunkline system, which terminates in Den Helder. Although the pipeline serves to export Danish gas to The Netherlands, flow could be reversed to allow for imports to Denmark, which might justify keeping otherwise redundant production facilities in business.
Frontier plays dominate
Ireland and Norway have opened up wide swathes of frontier acreage for their latest offshore licensing rounds.
The Irish energy ministry is making available Ireland’s entire sector of the Atlantic Margin for exploration – previous offerings off the western coast have focussed on individual basins. The opened area comprises 996 full blocks and 58 part-blocks, 30-380 km (18-236 mi) offshore, in water depths from 200 m to over 3,000 m (656-9,842 ft).
Investment terms have also eased, with the government now offering two-year licensing options to allow companies to assess an area’s exploration potential, without a large, up-front cash commitment. After submitting a work program, partnerships can then opt for a conventional 15-year license.
As a further stimulus, research institutes in Ireland and Newfoundland-Labrador are collaborating to devise plate reconstruction models. The aim is to show Ireland and eastern Canada’s sedimentary basins in their original positions when the two countries were virtually joined together, helping geoscientists to determine prospective areas offshore Ireland with similar geology.
Norway’s Petroleum and Energy Ministry has offered 51 blocks in the Barents Sea and 43 in the Norwegian Sea, under the country’s 21st Licensing Round.
Suncor accepts bid
Dana Petroleum has agreed on a $393-million offer for Petro Canada Netherlands. The latter has been one of the busier players on the Dutch shelf in recent years, bringing onstream the De Ruyter oil and gas field, and expanding production from other wide-ranging offshore interests acquired from German company Veba. However, Suncor Energy, Petro Canada’s new owner, had priorities elsewhere.
The package brings Dana 51 MMboe of proven, probable and possible reserves and up to 67 MMboe of un-risked prospective resources. Aside from De Ruyter, there are numerous other discoveries in the area, notably Van Nes and Van Ghent, which will be tied into the De Ruyter platform under the Medway Development Project.
Dana has further plans to use the Hanze platform in Quadrant F – which like De Ruyter’s, features a gravity-based structure for oil storage – as a central processing hub for nearby shallow gas prospects in Jurassic and Chalk reservoirs.
Premier makes pitch
Premier Oil is negotiating a farm-in to Chrysaor’s Solan field development in shallow water west of Shetland. The project, which first has to be sanctioned by both Chrysaor and the UK government, involves installation of an unmanned, articulated tower with oil processing and storage facilities. Solan has reserves estimated at 4% MMboe.
Also in this area, BP has issued another major contract for its Clair Ridge project, with Aker Verdal awarded the 22,300-metric ton (24,581-ton) drilling and production platform jacket. Among other UK programs, Apache North Sea has started work on its Bacchus subsea development, which will export production to the Forties Alpha platform via a 7-km (4.3-mi) pipeline bundle, to be supplied and installed by Subsea 7.
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