In Norway, DEA has a solid and promising licence portfolio with assets in all major phases in every region of the Norwegian Continental Shelf (NCS).
DEA has been present on the NCS for more than 40 years now. At the end of 2015, as part of an acquisition, DEA took over shares in more than 40 licences as well as significant production volumes from producing oil and gas fields in Norway.
DEA has ownership interests in several producing fields, such as Gjøa, Snorre, Snøhvit, Knarr, Skarv, Njord and Hyme. The company also participated in some of the
most important recent discoveries on the NCS, like Skarfjell and Alta.
DEA is operator of PL 435 (Dvalin), where the company made discoveries in 2010 and 2012.
Selection of DEA Norge licences
One of the largest industrial projects in Norway
The Skarv field was discovered in 1998 and is located just south of the Polar Circle, 210 kilometres off the coast of Sandnessjøen. Four discoveries were made in the unit Skarv & Gråsel (1998), Idun (1999) and Snadd (2000).
The field development includes a 295-metre-FPSO with a production capacity of 85,000 barrels a day which makes it DEA’s most important producing field in Norway.
Production started in December 2012 and is expected to last for 25 years. Since then, the field has produced around 55 million barrels of oil and exported approximately 11.5 billion sm3 gas liquids at the end of 2015. The transportation of the gas takes place via the 80 km long Åsgard Transport System.
- DEA Norge AS: 28.08 %
- BP Norge AS (operator): 23.84 %
- Statoil ASA: 36.16 %
- PGNiG Norge AS: 11.92 %
The PL 435 production licence is located 15 kilometres northwest of the Heidrun field and 35 kilometres south of the Skarv field in the Norwegian Sea. The nearest town is Namsos on Norway's west coast.
Major gas discovery thanks to innovative ideas
In the 1980s, the Dvalin field was initially deemed to not hold much in the way of promise for the oil industry, due to a lack of success in exploration by other companies. As time passed, however, innovative ideas and approaches revealed new findings, and in 2007 a consortium with DEA as the operator company was granted the PL 435 licence.
The first major gas discovery was reported in September 2010, when the first exploration well was drilled on the Dvalin field. A gas-bearing reservoir with a thickness of 150 metres was encountered in the Fangst formation (Dvalin East). A second gas-bearing reservoir with a thickness of 140 metres was discovered in 2012 with a second exploration well (Dvalin West).
The estimated reserves of the Dvalin field amount to 18.2 billion standard cubic metres of gas.
The field development is based on a proven technical concept with four subsea wells tied back to the existing Heidrun host platform with a 14.9-kilometre pipeline. The water depth is close to 400 metres. Water and condensate will be separated from the gas on a new gas processing module which will be installed on the Heidrun topside. Rich gas redelivered from Heidrun will be transported via the Polarled trunk line to the Nyhamna onshore gas terminal for further processing. Finally, the gas will be transported via Gassled to the market.
The Plan for Development and Operation (PDO) will be submitted to the Authorities in October 2016. First gas is expected in 2020.
- DEA Norge AS (operator): 55%
- Petoro AS: 35%
- Edison Norge AS: 10%
The Knarr field is located in the northern North Sea, 112 kilometres off the Norwegian coast. The licence was awarded in 2005 as part of the APA awarding round.
Fast-tracking of procedure ensures rapid field development
The main discovery in the Knarr licence region from 2008 was processed in a fast-track procedure. This enabled a field development and operating concept to be presented to the Norwegian authorities just two years later, and this in turn was approved in June 2011. In the meantime, a Lease & Operation agreement was signed with TeeKay, on whose behalf Samsung built a floating, production, storage and offloading vessel (FPSO).
Oil was discovered in the Knarr west region at the end of 2011. Production commenced in 2015 and is currently producing around 50,000 barrels oil per day. The gas will be transported via a dedicated pipeline in the FLAGS system (Far North Liquids and Associated Gas system), into which natural gas from the Gjøa is also fed. Oil is exported via shuttle tankers.
- DEA Norge AS: 10%
- BG Group (operator): 45%
- Idemitsu Petroleum Norway: 25%
- Wintershall Norge ASA: 20%
The Gjøa field is located 45 kilometres off the Norwegian west coast in the northern North Sea. Production started in November 2010. The oil is exported by pipeline to the Norwegian mainland via the Troll Oljerør II platform to Mongstad. Gas is fed into the FLAGS system (Far North Liquids and Associated Gas system) via a pipeline on the UK Continental Shelf, and from there it is transported on to St. Fergus in Scotland.
The semi-submersible platform is supplied with power from the mainland.
It’s the only one of its kind to be supplied with power from the mainland, thereby emitting less CO2. This platform is currently producing from the Gjøa field and the third-party operated Vega field. At present, around 3000 to 4000 standard cubic metres of oil and 12 million standard cubic meters of gas are produced each day.
- DEA Norge AS: 8%
- ENGIE E&P Norge (operator): 30%
- Petoro: 30%
- Wintershall: 20%
- Shell: 12%
Snøhvit is a natural gas field in the Barents Sea and is located 140 kilometres to the northwest of the town of Hammerfest. It is the first offshore development project in the Barents Sea, and has no surface installations on the field itself.
Up to 550 tons of gas are processed per hour
The subsea gas wells are connected via pipelines to the LNG plant on the island of Melkøya, just off Hammerfest. The depth of the water there is between 310 and 340 metres. In addition to Snøhvit, the field also includes several discoveries and reservoirs in the Askeladd and Albatross structures.
The natural gas is shipped out from the plant as LNG on LNG tankers. Potential expansion of the processing capacity of the LNG plant on Melkøya is currently being examined. The current processing capacity of the plant is between 530 and 550 tons per hour.
- DEA Norge AS: 2.81%
- Statoil (operator): 36.79%
- Petoro: 30%
- Total E&P Norge: 18.4%
- ENGIE E&P Norge: 12%
Snorre is an oil field in the Tampen region of the northern North Sea. DEA has an 8.57 per cent stake in the field, which contains a large share of DEA Norge's oil reserves. Around 110,000 barrels of oil are produced from the Snorre field each day.
Production at a depth of 2,000 metres
The Snorre field consists of several large fault blocks. The reservoir consists of sandstone from the Statfjord and Lunde formations in the Early Jurassic stratum and the Triassic strata. It is at a depth of between 2,000 and 2,700 metres. The southern part of the field has been developed with a TLP (a platform moored with a tension leg to the bottom of the sea) and a subsea production system (Snorre A). The northern part of the field is developed from a semi-submersible drilling and production platform (Snorre B).
Production life to be extended at the Snorre field
Oil and gas are separated in a two-stage process on the Snorre A platform, and from there they are transported by pipeline for final processing and export to the Statfjord A platform. From the Statfjord platform, the oil is transported on shuttle tankers, while excess gas is sent via the Statpipe pipeline to Kårstø. Processed oil from the Snorre B platform is transported to the Statfjord B platform by pipeline for temporary storage and loading onto shuttle tanks.
The licence partners have been working on plans for a number of years on how the field will be developed in the future and long term (Project Snorre 2040). The aim of the project is to extend the production life of the Snorre field on the basis of its significant potential.
- DEA Norge AS: 8.57%
- Statoil (operator): 33.28%
- Petoro: 30%
- ExxonMobil Norge: 17.45%
- Idemitsu Petroleum: 9.6%
- Core Energye: 1.1%
Statfjord Øst is an offshore oil field located around 7 kilometres to the northeast of the Statfjord field in the Tampen region of the North Sea. The depth of the waterdepth is between 150 and 190 metres.
The field has been developed with two production templates and one water injection template on the sea bed, connected via pipelines to the Statfjord C platform. In addition, one production well has been drilled from Statfjord C.
In addition to us, Petoro, ExxonMobil, Centrica Resources and Idemitsu Petroleum also have stakes in the field which is operated by Statoil.
DEA has a 1.4% share in the field.
This licence covers the two producing subsea fields Tordis and Vigdis and the Vigdis North East development project. The licence is situated 210 kilometres to the northwest of Bergen, in the Tampen area of the North Sea. We have a 2.8% share in the licence. Statoil is the operator, with the other partners being Petoro, Exxon Mobil and Idemitsu.
Discovery over 25 years ago
The Tordis field was discovered in 1987 by well 34/7-12, and the field development and operating plan was approved in May 1991. Several wells were drilled in the first development phase. Four more production wells and three injection wells were added to this later on; these were completed using a four-slot injection template. The field is tied in to the Gullfaks C platform, which processes the wellstream and provides water for injection. The water depth is between 150 and 220 meters.
The Vigdis field was discovered in 1988 by well 34/7-13, and the first field development and operating plan was approved in December 1994. The field was initially developed by using two four-slot production- and one four-slot injection-template. The field is tied in to the Snorre A platform, which processes the wellstream and provides water for injection before export of the oil to the Gullfaks A platform for storage and offloading. The water depth is around 280 meters.
Expansion of the Vigdis Field
In 2002, further investment in the Vigdis region (Vigdis Extension) was decided. In 2003, two new four-slot templates were installed (one for production and one for injection). Two additional sub-sea satellite wells were set up, connected via pipelines with the templates for the production and injection wells.
Vigdis North East was discovered in 2009 by well 34/7-34. A fast-track development was initiated, and on 16 September 2011 the field development and operating concept was approved. Vigdis North East has recoverable reserves of around 33 million barrel of oil equivalents. The field is developed using a subsea production system connected via the Vigdis infrastructure to the Snorre A platform.