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14/01/2016 In 2015, four new fields started production on the Norwegian continental shelf, all in the North Sea. The authorities approved four Plans for Development and Operation (PDOs), compared to just one in 2014.
The four new producing fields are the Statoil-operated Valemon, Det norske-operated Bøyla, BG-operated Knarr and Lundin-operated Edvard Grieg.
Ten years ago, there were 51 producing fields on the shelf, while at the end of the year, 82 fields were operational: 65 in the North Sea, 16 in the Norwegian Sea and one in the Barents Sea. So far, 18 fields on the Norwegian shelf have been shut down. The latest, and only, shutdown in 2015 was the Tor field in the Ekofisk Area.
In addition to the four fields that started producing in 2015, nine fields were under development at the end of the year. Six of these are located in the North Sea, two in the Norwegian Sea and one in the Barents Sea.
On 3 January 2015, Valemon started producing. The field is located west of Kvitebjørn in the Tampen area in the North Sea. The discovery was proven in 1985 and the development plan was approved in 2011. Valemon is developed with a platform resting on the seabed, with a simplified separation process. The oil and gas are sent to Kvitebjørn and Heimdal, respectively. The facility will normally be remotely operated from shore.
On 19 January, Bøyla started producing. The discovery was proven in 2009, and the development plan was approved in 2012. The field is developed with a subsea facility that is tied in to the Alvheim FPSO, which is located 28 kilometres to the north.
On 16 March, Knarr started producing. Knarr was discovered in 2008 and the PDO was approved in 2011. The field is located approx. 120 kilometres west of Florø, and is the first major development project for BG on the Norwegian shelf. The field is developed with a floating production, storage and offloading vessel (FPSO). The oil is loaded from the Knarr FPSO onto tankers, and the gas is transported to St. Fergus in the UK via a new gas pipeline and the Far North Liquids and Associated Gas System (FLAGS).
On 28 November, the oil field Edvard Grieg started producing. The field is located on the Utsira High in the North Sea. It was proven in 2007, and the PDO was approved in 2012. Edvard Grieg will also supply Ivar Aasen with electricity. The oil from Edvard Grieg is sent by pipeline to the Grane oil pipeline, which runs to the Sture terminal in Hordaland. The gas is exported in a separate pipeline to the Scottish Area Gas Evacuation (SAGE) System in the UK.
The four development plans include three in the North Sea: the first construction stage for Johan Sverdrup, Gullfaks South (Rutil in Gullfaks Rimfaksdalen) and Gullfaks (amended PDO that includes Shetland/Lista Phase 1). The fourth development plan is for Maria in the Norwegian Sea. Statoil also submitted the PDO for Oseberg West Flank 2 just before the holidays.
Six new fields are under construction. The PDO for the largest by far, the first development stage for Johan Sverdrup, was approved on 20 August 2015. Production start-up is scheduled for late 2019. Johan Sverdrup is located 155 kilometres west of Karmøy in Rogaland. Water depth in the area is 110 – 120 metres, and the discovery covers an area of approx. 200 square kilometres. The first development stage consists of a field centre with four specialised platforms for living quarters, processing, drilling and risers.
The Statoil-operated Johan Sverdrup will be operated with power from shore from production start-up. In the first development stage, transmission capacity of 100 megawatts will be provided for the field centre, enough to cover the demand during this stage. The area solution for power from shore, which includes the Johan Sverdrup, Edvard Grieg, Ivar Aasen and Gina Krog fields, will be established no later than in 2022.
The oil from Johan Sverdrup will be exported from the riser platform to the Mongstad terminal in Hordaland through a new oil pipeline that will be connected to existing rock storage caverns. The gas will be routed from the riser platform to the Kårstø terminal in Rogaland through a new pipeline that will be connected to the existing Statpipe (rich gas pipeline) on the seabed west of Karmøy.
Martin Linge and Gina Krog were both discovered back in 1978. Technology development and new information about the subsurface led the licensees to decide to develop the fields. The PDOs were approved in 2012. Total-operated Martin Linge is located about 42 kilometres west of the Oseberg area near the border to the UK sector. A storage ship will be used for the oil that is recovered, in addition to the gas resources. Martin Linge will be operated using power from shore. Planned production start-up for Martin Linge is early 2018. Statoil-operated Gina Krog is located about 30 kilometres northwest of the Sleipner area. The gas will be transferred to Sleipner for final processing, and a storage ship will be used for the oil. Production is scheduled to start in 2017.
Det norske oljeselskap received approval for the Ivar Aasen PDO in 2013. The discovery on the Utsira High in the North Sea was proven in 2008. Production from the field will be sent to Edvard Grieg for final processing. The Edvard Grieg field will provide power to Ivar Aasen, which is scheduled to start production in late 2016.
The Hanz field – operated by Det norske oljeselskap – will be developed with seabed templates tied in to Ivar Aasen. The development and production start-up dates will be adapted to the production on Ivar Aasen.
Flyndre is a small oil field in the southern part of the North Sea, west of the Ekofisk area, which spans the border between the UK and Norway. Most of the resources are on the UK side. Maersk Oil UK is the operator, and the plan is to develop the field with a seabed template, tied in to the Clyde field in the UK sector. The development plan was approved in 2014 and production start-up is scheduled for the 2nd quarter of 2016.
Statoil-operated Aasta Hansteen is located about 320 kilometres west of Bodø in Nordland, and will be developed with the first ever Spar facility – a floating field centre – on the Norwegian shelf. Water depth in the area is 1270 metres, and new technology has been developed in order to make this field development possible. The field, which mainly contains gas, was proven in 1997 and the PDO was approved in 2013.
At the same time as the decision to develop Aasta Hansteen was made, a decision was also made to proceed with construction of a gas pipeline (Polarled) to the terminal at Nyhamna in Møre og Romsdal. Nyhamna will be upgraded so it can receive gas from Aasta Hansteen and Polarled. Aasta Hansteen and Polarled make it possible to develop other gas discoveries in the Norwegian Sea. Planned productions start-up is in late 2017.
The PDO for Wintershall-operated Maria was approved in September, and production start-up is scheduled for the 4th quarter of 2018. Maria – discovered in 2010 - is located on Haltenbanken in the Norwegian Sea, and will be a subsea development. The wellstream will be tied in to the Kristin platform for processing and metering, gas for gas lift will be collected from Åsgard B via Tyrihans and water for injection will come from the Heidrun field. The oil will be stored and offloaded on Åsgard C, while the rich gas will be transported through the Åsgard transport system (ÅTS) to Kårstø, where NGL and condensate will be extracted.
Eni-operated Goliat was discovered in 2000, and the PDO was approved in 2009. This will become the first oil field in the Norwegian sector of the Barents Sea, and will be developed with a cylindrical, floating production facility – the first Sevan type on the Norwegian shelf. Eni is planning start-up of Goliat in the near future.