Snøhvit development brings budget, schedule changes

Offshore activities are well under way on Statoil’s Snøhvit project, which involves the production of gas through subsea facilities tied back 143 km to an onshore liquefied natural gas (LNG) plant. Drilling started in late 2004 and will continue until spring 2006. Part of the pipelay started last year, and the remainder is scheduled for spring and summer 2005.

While the offshore work is going according to plan, Statoil has had to give way in its struggle to maintain the overall schedule and budget and recently announced adjustments on both fronts. Newly installed Chief Executive Helge Lund is involved in the project, an indication of the importance it has for the company’s reputation.

Statoil’s latest cost estimate is NKr51.3 billion, up a hefty 30% on the original budget of NKr39.5 billion. Meanwhile, Statoil expects regular exports of LNG to begin in 1Q 2007, several months after the contract date of Oct. 1, 2006. First gas will flow in March 2006, opening the way for a run-in period at the LNG plant.

As has happened in the past, Statoil has become a victim of its own willingness to take on technically demanding projects involving new technology that would have benefited from more extensive groundwork and early engineering. In the case of Snøhvit, these drawbacks center on the LNG plant, which involves the first use of a new liquefaction technology Statoil developed and which the company claims to be the most efficient.

The current budget figure does not include the four newbuild carriers of 145,000-cu-m capacity, which will transport LNG to customers in the US and Spain. All four are under construction in Japan.

Snøhvit firsts

Like the onshore plant, the offshore development involves a number of firsts. It represents the first offshore production in the Barents Sea, which lies within the Arctic Circle, and the most northerly offshore production in the world. It also involves the longest tieback of a multiphase wellstream to shore. This was originally set at 167 km, but changes in the pipeline route have shortened it to 143 km.

Gas will come not only from Snøhvit, but also from the nearby Albatross and Askeladd fields. Statoil estimates combined gas reserves at 200 bcm. The annual production rate is set at 20.8 MMcm/d. Statoil expects production to continue for about 30 years, although there is a good chance that this period will be extended as there are both other additional reserves in the area and plans for further exploration.

Environmental considerations largely drove Statoil’s choice of a subsea development. The authorities set standards even higher than elsewhere on the Norwegian continental shelf due to the extremely sensitive ecology of the Barents Sea. A subsea solution represents a closed system with no emissions to sea or air, as would be the case with a surface installation. It is also seen as one that interferes least with other users of the sea, notably fishermen. There is no exclusion zone, as there would be with a surface installation, and the trawl board-friendly protection structures placed on the seabed equipment should ensure that fishing can proceed without interference.

Another environmentally driven decision was the re-injection of carbon dioxide into the subsoil. The gas from the Snøhvit fields has a CO2 content of 5-8%. Statoil has to separate this out before liquefying the gas and returning it through a separate pipeline to the field where it will collect down a dedicated disposal well. It was Statoil that pioneered CO2 injection beneath the seabed on the Sleipner field in the 1990s. Snøhvit represents the first use of a subsea well for this purpose.

20 subsea producers

In addition to theCO2well, Statoil has planned 20 subsea production wells - eight on Snøhvit, four on Albatross, and eight on Askeladd. In the first phase, Statoil will drill six production wells on Snøhvit and three on Albatross.

A second phase is scheduled for 2011, when Statoil will drill the remaining two Snøhvit producers. The final phase will take place in 2014-15, when Statoil will add the fourth Albatross well, along with the eight Askeladd wells.

Transocean’s semisubmersiblePolar Pioneer, which, as its name suggests, was built in 1986 for duty in the Arctic environment, will drill the first-phase wells. The rig, which had previously worked in the Norwegian sector of the North Sea, underwent upgrading before heading north. In addition to operating in a harsh climate, it meets the required standard of no harmful emissions.

Drilling, which was originally scheduled to begin in September 2004, was delayed by an offshore strike, which continued for several weeks in late summer. As a result the first well - 7121/4-A99, theCO2injection well - spudded on Dec. 9, 2004. The water depth on the three fields varies from 250 m to 345 m.

Subsea equipment

Vetco Gray, which at the time of contract award was operating as ABB Offshore Services, is supplying the subsea trees. The contractor is also responsible supplying other subsea equipment, including templates, manifolds, and control systems.

The wells will be housed on four-slot templates held in place by suction piles. Statoil installed four such templates last year to accommodate the Snøhvit and Albatross wells. Each weighs 260 tonnes, measures 26 m x 16 m, and stands 14 m high. Each also contains a 60-tonne manifold through which production will be gathered and passed into a flowline.

The flowlines from each template run to a pipeline end manifold (PLEM) through which the combined wellstream accesses the export pipeline. The PLEM consists of a manifold weighing 210 tonnes housed in a template weighing 235 tonnes and measuring 32 m x 17 m x 14 m.