Drilling slumptakes its toll
Exploratory drilling off Norway is in a trough, according to three recent forecasts. The Norwegian Petroleum Directorate anticipates 15-20 exploration and appraisal wells on the shelf this year, down more than 30% on 2002 levels, when 30 such wells were either spudded or completed. The Norwegian Oil Industry Association was less optimistic, identifying 16 potential E&A prospects for 2003. And the latest industry survey by Statistics Norway estimated a total exploration spend over the year of $782 million. This is a descent of over 20% from its previous prediction of $945 million, issued early last fall.
Depressed global markets aside, Norway's frontier status was deflated last year following dry wells on three highly rated ultra-deepwater prospects – Havsule, President, and Solsikke in the Norwegian Sea. Most of 2002's discoveries were small accumulations easily accessed from North Sea production hubs. Not all high profile drillers have been deterred. Exxon-Mobil has hired the drillship West Navion to probe the Naglfar prospect in the Voering Basin this spring, in 1,350 m of water. The location, in block 6706/6, is close to a small find recorded by Statoil in 1997. Statoil itself is thought to be lining up a well in its recently won Norwegian Sea Ellida license (PL281). Both operators are also pursuing more modest targets close to the Norne and Sleipner fields.
Ormen Lange heads for shore
Ormen Lange, the sole super-giant discovery off Mid-Norway to date, is finally on track for development. Just before Christmas, operator Norsk Hydro finally swayed its partners into accepting a subsea-shore scheme, rather than a full-scale processing platform. The agreement, following three years of technical consultations, should lead to a $7.75 billion development plan being issued this fall, with first production scheduled for 2007. The field's reserves are currently put at 375 bcm of gas and 138 MMbbl of condensate, with production, peaking at 20 bcm/yr, continuing potentially to 2050.
Production would be piped from the subsea center through a new 1,250-km pipeline to a processing plant at Nyhamma on the Mid-Norwegian coast. This might also handle gas exports from other planned developments in the area, such as BP's Skarv. The new line could also be connected via a spur to the Sleipner complex in the North Sea, for onward export to the UK. This has always been viewed as one of the main markets for Ormen Lange's gas, although competition is emerging from other regions. Gazprom recently announced plans for a $5.7-billion pipeline taking Russian gas across the Baltic Sea to Britain.
Ardmore could form the hub of a multi-field redevelopment in the central North Sea.
In the Barents Sea, Norway's first LNG project, Snohvit, continues to "bust" its budget, with a 15% upward revision to NKr 453 billion. The latest rise is attributed partly to miscalculations over capacity of the island-based LNG plant. However, Statoil says returns will still be profitable, equivalent to $14.50/bbl in 2000 dollars.
Paleocene play pays off
DONG has maintained its high strike rate in its native Danish sector with two positive appraisal wells in the Siri area. Nini-4, drilled by the jackup Ensco 70 in 59 m of water, found oil in Paleocene sandstone. A side-track was then drilled into the water leg. The partners now have four months to factor the new reserves into the current development of Nini, due onstream this August through a wellhead platform.
The other success, also in Paleocene sandstone, came from the Siri-5 well appraising the southern flank of the main Siri field, known as Stine Segment 2. These reserves will be drained through a long-reach horizontal well from the Siri platform.
New lives for old fields
Tuscan Energy, a new operator on the UK Continental Shelf, has secured funding for its oilfield development Ardmore in the central North Sea. In fact, this is a re-development of the Argyll field, a tilted fault block reservoir, which was abandoned by previous operator Hamilton in 1992 following mechanical and production problems in individual wells.
Resuscitation was sanctioned last October by Britain's Energy Ministry. Four new high-angle wells are to be drilled in sequence by the Rowan Gorilla jackup, which was designed to cope with production duties. First oil should be out this fall, with production offloaded to two dedicated shuttle tankers from a single anchor loading facility. Tuscan and its partner Acorn aim to recover 2,025 MMbbl, at a capital cost of $108 million.
As production tails off, probably in 2007, there may be scope to reactivate and tie in the abandoned satellite fields Duncan and Innes. UK analysts Wood Mackenzie claims new technologies could be applied on other North Sea fields that were prematurely shut in. This has already happened on a smaller scale with the Angus accumulation, which was redeveloped as a single-well subsea tieback to the Fife field FPSO.
DNO's work in the Heather area in the northern North Sea is arguably a redevelopment, slowly optimizing production through an ageing facility that previous owner Unocal was close to scrapping. BP's Don Area fields are also being re-worked. Don West could be developed through a subsea template tied back to the Thistle facilities. These were recently sold by BP and Conoco to DNO, which is aiming to replicate its life-extension techniques on the Thistle and Deveron fields.
Other independents are also trying their luck with steel hulks. Canadian Natural Resources has acquired operatorship of the Ninian and Murchison fields and platforms in the northern sector from Kerr-McGee. Chevron, the original developer, had previously offloaded them to Oryx. And Paladin Resources made its biggest investment to date, paying $153 million to BP and Amerada for a package that includes operatorship of Montrose, Arbroath, Carnoustie, and Arkwright, including two fixed platforms. Paladin has contracted PetroFac and Helix RDS in Aberdeen respectively to manage the facilities and to undertake further reservoir/well engineering studies.
Petro-Canada, another new entrant to the UK operator set, is to develop the Clapham oilfield in central block 21/24, at a cost of £71.4 million. Clapham was discovered in 1999, and was part of a package picked up by the company when it acquired Veba UK. This will be a subsea scheme, exporting to the Triton field FPSO via the Guillemot West/ Northwest underwater facilities.
Centrica Resources has taken outright control of BG's 1998 gas discovery Rose, in southern North Sea block 47/15b. This will be one of the few subsea tiebacks in this sector – the nearest complex is BP's Ame-thyst, 10 km to the southwest. The Amethyst A2D platform recently hosted first production from the Helvellyn gasfield, a single-well development by yet another first-time operator, ATP.