Jeremy Beckman • London
Norway's leaders look ahead
For Norway's big two, launching the Ormen Lange project was the main event of 2003, so said leading spokesmen for Statoil and Norsk Hydro during recent financial presentations in London. From Hydro's standpoint as development operator, the field's gas will provide a 216% replacement of its global reserves.
According to Statoil's acting CEO Inge Hansen, the Langeled subsea line exporting the gas to Easington, UK will add 25 bcm/year to Norwegian shelf trunkline capacity.
Of the two spokesmen, Statoil's was by far the more forthcoming concerning plans for exploration and development in the sector as a whole. Hydro has one commitment explor-atory well to come this year in the Norwegian Sea. Otherwise, it will mostly be targeting structures close to its North Sea platform complexes. These include Oseberg, where it was recently cleared by the government to develop the western flank. Hydro has also won extensions from the Petroleum Ministry to three production licenses in this area through 2031.
Elsewhere in the North Sea, Hydro has completed the transfer of its 30% stake in the Gjoa discovery to Gaz de France Norge. The field extends over two blocks situated 70 km north of the Troll field. Recoverable reserves are put at 50 MMbbl of oil and 25 bcm of gas. Statoil will operate the development, which at this stage appears to be a two-pronged affair involving a production ship for the oil, and a subsea template tying gas wells back to a platform in the Tampen region. On start-up – probably in 2008 – control would pass to Gaz de France.
Alba inching farther south
ChevronTexaco has secured approval from its partners for AXS-2, the £48 million second phase of its Alba Extreme South development in the UK North Sea. The project entails installing a four-well manifold, the first three of which are currently being drilled, by the semi Stena Spey. Subsea 7, which supplied the bundled pipeline and end manifold for AXS's first-phase wells in 2002, is also responsible for the new hardware and associated tie-ins. First oil is due out in November, climbing to a peak of 40,000 b/d. As before, production will be sent through flowlines to ChevronTexaco's Alba Northern platform for processing.
Chevron's Alba Northern platform will process oil from the AXS-2 subsea development.
Outside its UK strongholds of Alba, Britan-nia, Captain, and Erskine, the company looks to have been in retreat. Recently, it ceded control of the Galley field and associated production semi to Talisman and simultaneously sold stakes in the Statfjord UK and Orwell fields to Centrica for $108 million. Headquarters in Aberdeen has identified 12 undeveloped assets across the shelf, however, warranting further attention. These include the heavy oil giant Bressay, east of the Shetlands, and Torridon to the west. Contractors have been asked to submit development proposals combining new technologies with innovative commercial arrangements. So far, over 30 suggestions have been evaluated, and follow-up talks are under way concerning at least three fields.
Kristin schedule under pressure
Hydro would not comment on its bidding plans for acreage under Norway's current 18th licensing round. Inge Hansen viewed the re-opening of the Norwegian Barents Sea for exploration as very positive for Statoil.
Statoil is developing the Snøhvit gasfield in this sector, and Hansen was confident that the barge for the associated liquefaction plant would sail in on time from Spain this summer. Dragados, the topsides outfitter, had fallen behind schedule on another Statoil-led project, Kristin, where it is supplying the riser balcony and flare tower. This delay caused some of the work to be transferred in February to the Aker Stord yard in western Norway, where the modules will eventually be hooked up to Kristin's semisubmersible production platform. Both the hull and topsides are reportedly being strengthened, as the living quarters module had exceeded its weight specification.
On top of this, the project's costs may escalate 10% to NKr19 billion, if the partners decide on a late change to the drilling plan. This involves adding more, and lengthier, horizontal wells to boost condensate recovery. Due to the complexities of the high-pressure, high-temperature reservoir, all production wells must be completed prior to start-up in October 2005. If the scheme is expanded, a third may have to be brought in aside the two semis currently on station.
Fewer tribulations at Åasgard, also in the Norwegian Sea, where the Mikkel subsea development has come on line, on time, and 30% within budget. The field's 28 bcm of gas and 40 MMbbl of condensate are being piped to subsea facilities on the Midgard field, then heading onwards to the Åasgard B platform for separation.
Drilling was due to start this month on another subsea development, Åasgard Q, aimed at improving drainage of the Smorbukk South reservoir. The Transocean Searcher is putting in two wells that will be connected to the Åasgard A FPSO via a new template, which will also accommodate the last of Åasgard's 52 development wells. Technip/Subsea 7 and Stolt Offshore have been booked for the installations this summer. In a later phase, two further Q wells and a gas injector may be added.
Another FPSO-driven Statoil field, Glitne, is to stay in production for a further three years. This follows strong returns from a fifth producer well drilled in 2003, two years after the field was brought onstream via PGS' Petrojarl 1 on what was expected to be a short-term charter. However, ongoing reviews of the reservoir have more than doubled the recoverable estimate to 50 MMbbl-plus.
This year Statoil has one new development, Kvitebjorn, approaching start-up (in October). According to Hansen, Statoil may also sanction major life extension/expansion projects for Statfjord and Troll, and a couple of smaller new schemes such as Volve and the Norne satellites. He also mentioned that the company's production costs on the Norwegian shelf had never been lower, dipping to NKr22.3/boe in 2003.