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The Linnorm gas condensate field, located in the Norwegian Sea is technically challenging. The high pressure and high temperature reservoir contains gas with CO2, H2S and traces of mercury. Although the gas is relatively lean, the associated condensate has waxy properties. The field is located in ~ 300 m of water, ~ 5,000 m below the sea bed and 200 km from land. Although there are production facilities within 30 to 70 km, this discovery was initially seen as "stranded gas" due to the absence of an export route with available capacity. The chosen field development is in the FEED phase and comprises of subsea wells tied back to a 20 year old oil production platform, with a ~ 55 km direct electrically-heated flowline. The gas is processed on the platform for export, via a new, joint venture pipeline to an onshore terminal. This paper will discuss the key development decisions, and issues, regarding this technically and economically challenging project, from the reservoir to the export of the processed gas. Specifically it will address the reservoir development strategy considering decisions taken to exploit the different reservoir formations with individual wells, in the context of maximizing gas recovery, within the sub-surface constraints. The wells and subsea concepts are particularly challenging, pushing the limits of existing technology and requiring some world first solutions for what will be the highest temperature subsea field development on the Norwegian continental shelf with the world's longest electrically heated flowline. The surface facilities design will add significant gas processing facilities (separation, mercury removal, water and hydrocarbon dewpointing and compression) onto the platform and extend its economic life. Along with the safety, space and weight issues to be managed, there are also numerous other platform integration decisions to be made in relation to the process, flare and electrical and instrument integration. |
