Oda is the first Spirit Energy-operated project in Norway, demonstrating the in-country capacity and capability of our business. Oda is developed with a subsea facility including two production wells tied-back to the Ula field (13 km) and one water injection well for pressure support. Oil is exported to Ekofisk and then onward in Norpipe to the Teesside terminal in the UK. The Oda gas in sold on the Ula platform.
Production commenced on 16 March 2019, five months ahead of schedule, and Oda has an expected field life of 2030+. The project also came in under budget, with development costs reduced by around 15% from when the plan for development and operation (PDO) was submitted to the authorities in November 2016.
Vale is located in the Central North Sea, 16 kilometres north of the Heimdal field. Discovered in 1991, the plan for development and operation (PDO) was approved in 2001. The field is developed with a subsea template including one horizontal production well with a single side track, tied-back to the Heimdal facility. Production started in 2002 and Vale, which produces both gas and condensate, has an expected field life of 2021/22.
The well stream from Vale is routed to Heimdal for processing and export. Gas is transported via Vesterled to St Fergus in the UK. Condensate is transported by pipeline to the Brae field in the UK sector and further to Cruden Bay.
Barnacle is located in the North Sea in UK blocks 211/29F and 211/30C – southwest of the Statfjord Main Field. It was discovered in 1992 (211/29-10Z), by Shell, and the licence was awarded during the 30th UK licensing round in October 2018. First oil was achieved in December 2019.
The Barnacle Field has been developed with a single extended reach well (6.7 km) from the Statfjord B platform. Existing Norwegian North Sea infrastructure has been used, with no subsea equipment installed in the UK Continental Shelf (UKCS).
Heimdal is located in the Central North Sea. Discovered in 1972, the plan for development and operation (PDO) was approved in 1981, with the field developed using an integrated drilling, production and accommodation facility with a steel jacket (HMP1).
Production started in 1985 and the PDO for Heimdal Jurassic was approved in 1992. The PDO for the Heimdal Gas Centre was approved in 1999, and included a new riser facility, connected by a bridge to HMP1.
Heimdal has an expected field life of 2021+ and is now mainly a processing centre for other fields; presently Atla, Skirne, Vale and Valemon, and for Huldra until production ceased in 2014. The Huldra pipeline to Heimdal is now used for transport of rich gas from Valemon. Heimdal also serves as a hub for rich gas transported from Oseberg to continental Europe via the Draupner platforms.
Ivar Aasen is a field in the northern part of the North Sea, 30 kilometres south of the Grane and Balder fields. Discovered in 2008, the plan for development and operation (PDO) was approved in 2013, and production started in 2016. The development comprises a production, drilling and quarters (PDQ) platform with a steel jacket and a separate jack-up rig for drilling and completion.
The platform is equipped for the tie-in of a subsea template planned for the development of the Hanz field, and for possible development of other nearby discoveries. First stage processing is carried out on the Ivar Aasen platform, and the partly processed fluids are transported to the Edvard Grieg platform for final processing and export.
Kvitebjørn is located in the Northern North Sea, 15 kilometres southeast of the Gullfaks field. Discovered in 1994, the plan for development and operation (PDO) was approved in 2000. The field is developed with an integrated accommodation, drilling and processing facility with a steel jacket. Production started in 2004 and, as well as gas, it also produces condensate.
Maria is located on Haltenbanken in the Norwegian North Sea, where water depth in the area is 300 metres. It was discovered in 2010, and the plan for development and production (PDO) was approved in 2015. The field is developed as a subsea tieback with two templates - there are five producers and two water injectors on the field.
Gas for gas lift is supplied from the Åsgard B facility via the Tyrihans D template. Sulphate-reduced water for injection is supplied from Heidrun. Production started in 2017, nine months earlier than estimated in the PDO, and water injection started one month after production start-up.
Statfjord is located in the Northern North Sea, on the border between the Norwegian and UK sectors. It was discovered in 1974, and the plan for development and operation (PDO) was approved in 1976. The field has been developed with three fully-integrated concrete facilities: Statfjord A, Statfjord B and Statfjord C.
Statfjord A, centrally located in the field, came on stream in 1979. Statfjord B, in the southern part of the field, in 1982, and Statfjord C, in the northern part, in 1985. The satellite fields Statfjord Øst, Statfjord Nord and Sygna have a dedicated inlet separator on Statfjord C.
A plan for development and operation (PDO) for the Statfjord Late Life project was approved in 2005, and has prolonged the field’s lifetime as well as increasing oil and gas recovery. It is now focused on identifying and drilling remaining oil targets. Statfjord, including the Statfjord satellites, has an expected field life of 2025+.
Trym, which was discovered in 1990, is located in the southern part of the Norwegian North Sea, three kilometres from the border of the Danish sector, in an area with a water depth of 65 metres.
The plan for development and operation (PDO) was approved in 2010 and the field was developed with a subsea template, including two horizontal production wells, tied to the Harald facility in the Danish sector. Production started in 2011, with Trym producing both gas and condensate. The field is temporarily shut-in until Q2 2022 while the Tyra re-development is ongoing.
Vega was discovered in 1981 and is located in the Northern North Sea, 28 kilometres west of the Gjøa field, where water depth in the area is 370 metres. The field consists of three separate deposits: Vega Nord, Vega Sentral and Vega Sør, producing oil, gas and condensate.
The plan for development and operation (PDO) for Vega Nord and Vega Sentral was approved in 2007. The field has been developed with three subsea templates with four slots, tied to the processing facility on the Gjøa field. A total of six production wells have been drilled, with production starting in 2010.