Statoil assesses technology for record-long umbilical at Snøhvit; Storting greenlights project

March 12, 2002
Statoil ASA has started work to qualify technology for the record-long umbilical that will connect its Snøhvit development in the Barents Sea with land facilities in northern Norway. The announcement came a few days after Norway's Storting approved the project, which involves the first Barents Sea field development and Europe's first LNG export project.

By the OGJ Online Staff

HOUSTON, Mar. 12 -- Statoil ASA has started work to qualify technology for the record-long umbilical that will connect its Snøhvit development in the Norwegian Barents Sea with land facilities in northern Norway.

The announcement came a few days after Norway's Storting approved the project, which involves the first Barents Sea field development and Europe's first LNG export project.

"We expect to sign a contract this summer for the subsea system and umbilical," said Inge Polden, Snøhvit project engineer. "This job will be awarded to one of three suppliers we have frame agreements with."

Statoil and the subsea system suppliers are testing existing technology for the 160 km bundle of control lines and cables. Verification is expected to continue until the end of the year.

Project approval, details
The Statoil-operated Snøhvit area fields represent the first field development in the Barents Sea, and they are tied to the first LNG export project in Europe (OGJ Online, Oct. 22, 2001). In addition to Snøhvit, substantial gas reserves have also been found in nearby Albatross and Askeladd fields in Norway's Hammerfest basin in the southern Barents Sea.

While Statoil has a 22.29% interest in the fields, Petoro (formerly state holdings group SDFI) has 30%, TotalFinaElf SA 18.4%, Gaz de France 12%, Norsk Hydro ASA 10%, Amerada Hess International Ltd. 3.26%, RWE-DEA AG 2.81%, and Svenska Petroleum Exploration AB 1.24%.

On Mar. 7, Norway's Storting, or parliament, approved development of Snøhvit field, prompting protests from environmental groups. The field lies in an ecologically sensitive area north of the Arctic Circle.
Statoil and its partners will assess whether any conditions in the parliament's approval need clarification before they make a final decision on development.

The project includes a subsea development tied back by pipeline to the receiving terminal and liquefaction plant at Melkøya. LNG will be exported to terminals in the US and southern Europe.

Development costs are estimated at 40 billion kroner ($4.53 billion), excluding the LNG carriers. Statoil, Amerada Hess, Norsky Hydro, RWE-DEA, and Svenska Petroleum last December ordered the first of three LNG carriers to support export shipments from the project (OGJ Online, Dec. 12, 2001). TotalFinaElf and GdF will lift their share of the LNG with their own vessels. A total of 70 LNG cargoes/year will be shipped from the terminal near Hammerfest in northern Norway. Existing gas sale agreements involve the annual export of 2.4 billion cu m of gas to customers in the US and 1.6 billion cu m to Spain.

Plans call for work to begin soon, with production starting in 2006 and lasting until 2030.

Umbilical details
All the wells planned for Snøhvit—21 for gas and condensate and one for carbon dioxide injection—will be remotely controlled from land through the umbilical.

The distance involved requires a voltage of 3,000 v—three times the conventional level for a subsea facility. With a diameter of roughly 11 cm, the umbilical will contain high-voltage power lines, fiber-optic cables, and hydraulic piping.

The fiber-optic cables will transmit control signals to subsea valves and will return information from sensors mounted in the wells. Snøhvit will involve the world's longest distance between the control station on land and the first subsea installation.

By comparison, the maximum umbilical length on Statoil's Åsgard field in the Norwegian Sea is 50 km. Statoil's nearby Mikkel project will involve an umbilical span of 87 km.

Plans call for Snøhvit to be developed in three phases. When these have been completed in 2018, the longest distance over which remote control is exercised will be 210 km.

Development details
Edinburgh analysts Wood Mackenzie assessed the prospects for Snøhvit-sourced LNG in mid-2000.

At the time, the analysts concluded that gas discoveries in the Snøhvit area of the Barents Sea could become commercially viable if sufficient LNG markets materialize by 2006 (OGJ, Aug. 7, 2000, p. 30).

Financial feasibility of the Snøhvit project also will depend on the Norwegian government's provision of full tax advantages to the operators, WoodMac concluded, and on the operators' broad employment of the most recent advances in LNG technology.

The remoteness of the area makes exploration, production, and transportation costly. Because the distance from existing gas export infrastructure is so great, the Snøhvit partners are planning a multiple-phase LNG program with dual, phased pipelines from the fields to a proposed single-train, onshore LNG plant in Norway.

Statoil and other leaseholders in the Norwegian sector had drilled 56 wells in the area as of August 2000 and, although they have discovered no commercial oil reserves, they have found a substantial core recoverable resource of about 6.5 tcf of gas and 170 million bbl of condensate in the fields.

Current development plans for the Snøhvit LNG project will require construction of a single-train LNG terminal on the small island of Melkøya near Hammerfest. If a second train were built, WoodMac observed, it would increase output and improve project economics.

Plans call for 18 horizontal wells in the fields—5 in Snøhvit, 5 in Askeladd, and 8 in Albatross—and a 140 km, 27-in. multiphase pipeline to deliver condensate and natural gas from the fields to the plant.

Phased development, using the one-train facility, would have condensate-rich Snøhvit field production on stream first, followed by Askeladd 8 years later and Albatross 14 years after initial production begins. Gas produced early from Askeladd could be injected into Snøhvit wells to enhance liquids production.

The project will probably require compression facilities in later phases, both on a floating field platform and onshore, in order to boost recovery.

The partners expect production to reach 4.5-5.6 billion cu m/year (435-542 MMcfd) of natural gas and about 20,000 b/d of condensate.