Three gas condensate fields are planned as subsea development. They will be connected to a subsea pipeline end module, PLEM, via flowlines and a 160 km multiphase pipeline from the PLEM to an onshore liquid natural gas plant. The gas has a high content of carbon dioxide and condensed water will be present, which makes the fluid corrosive to carbon steel. The temperature and pressure is moderate, the formation water contains approximate 160 g/l of salt, but the probability for production of formation water is low. Ethylene glycol will be used as hydrate inhibitor and will be injected on each wellhead and on the PLEM. The glycol will contain sodium hydroxide and when necessary corrosion inhibitor. The glycol will be regenerated onshore. Carbon dioxide will be separated and reinjected offshore. Corrosion resistant alloys will be used for well equipment, manifolds and piping and for the flowlines. Based on test programs evaluations and experience from other fields, carbon steel is selected for the main pipeline in combination with pH stabilisation and high focus on corrosion monitoring. Backup solutions if formation water should be produced, are injection of scale inhibitor or film forming corrosion inhibitor.
The Snøhvit development includes the fields Snøhvit, Albatross and Askeladd discovered in 1981 - 1984. All three fields contain mainly gas including small amount of condensate. The fields are located outside northern Norway approximately 140 km north west of Hammerfest. The first liquefied natural gas (LNG) plant in Northern Europe will be built on Melkøya to treat the gas from Snøhvit.
The owners are Statoil ASA, Petoro, TotalFinaElf AS, Gaz de France, Norsk Hydro Produksjon AS, RWE Dea Norge AS and Svenska Petroleum Exploration AS and the operator is Statoil ASA.
Snøhvit will be the first important offshore development outside Norway without installations on the surface. The production equipment will be on the sea bottom at water depths from 250 to 345 m and no platforms or production ship marking the location in the Barents see. The gas will be transported in a 160 km long multiphase pipeline to the gas terminal at Melkøya, Hammerfest. The water, the condensate and carbon dioxide, CO2 will be separated from the gas and the gas cooled to form LNG. LNG will be transported in tank ships to the customers. The CO2 will be reinjected in the formation on the field via a separate 8 pipeline.
In order to control the hydrate formation, Mono Ethylene Glycol (MEG) will be injected at each wellhead and in the main pipeline inlet, at the pipeline end module (PLEM). Chemicals to control the corrosion in the main pipeline will be injected with the MEG. The MEG will be regenerated in a MEG regeneration unit consisting of both water and salt removal units. The offshore production and transport pipeline will be operated from the control room at Melkøya. The control system will use optical fiber cables, high power electrical and hydraulic lines all located in an umbilical. In the umbilical is a line for injection of scale inhibitor to each wellhead. Offshore installation is planned in 2004 and pipe laying in 2005. The plan is to start the delivery of LNG by 01.10.2006.
A main challenge will be the control systems. The offshore production, injection and control of chemicals, MEG control, corrosion monitoring, monitoring and measuring of production and injection rates will be from the onshore control room.
Figure 1 shows a sketch of the system layout.
The material selection for the main pipeline is based on an evaluation of corrosion and the risk for carbonate scaling. The most critical input parameter is the