Fotnote: Adresseavisen, 5 February 2001, “Draugen leverer olje helt til 2016”. Located at the westernmost edge of the Draugen area, Garn West was the first to be tapped with the aid of two seabed wells tied back by a 3.3-kilometre pipeline in the summer of 2001. An advantage of subsea wells was that they were quick to install and start up. And unprocessed wellstreams could be sent over ever longer distances with advanced multiphase flow technology.ĭevelopment of small satellite fields had become a profitable business, which proved a boon for oil companies around 2000 when oil prices slumped towards USD 10 per barrel. This decision built on rapid improvements during the 1990s in the methods for tying subsea wells back to fixed and floating offshore installations.ĭiscoveries too small to justify their own process platform could use relatively cheap, standardised subsea systems tied back to a fixed platform, a floater or even land. That was nine per cent of the field’s 144.2 million scm in recoverable oil. These would be tied back to the Draugen platform and increase reserves by about 81 million barrels or 13 million standard cubic metres (scm) of oil. To increase production from and producing life for the Draugen area even further, Shell now planned development of the Garn West and Rogn South subsea wells. In the longer term, the goal was to recover at least 70 per cent – assuming that the field remained commercial beyond 2016. Draugen’s producing life was extended to 2016 and the expected recovery factor increased to 67 per cent. A number of the wells were producing very well. Use of four-dimensional seismic surveys improved geological understanding of the reservoir, which was also behaving better than expected. Shell could report in 2001 that recoverable reserves in Draugen were larger than earlier thought. Reserves up, producing life and recovery factor extended Havbunnsbrønner forlenger produksjonen, kart, illustrasjon, engelsk Illustration from Draugen development status, July 1999 These forecasts have changed gradually, as technological advances in the oil industry permitted production improvements.īut the reservoir has nevertheless yielded surprises along the way. Remaining reserves are roughly 20 million barrels of oil and 9 BCM natural gas.By 2017, Draugen’s producing life had been extended to 9 March 2024 and its expected recovery factor was put at 75 per cent. The contract for upgrading Njord A, (worth NOK 5 billion) was awarded to Kværner. This aims to make the field ready to produce until 2040. Between 20, the field is being shut down to allow for upgrades to the facilities. Ownership of the field is divided between Wintershall Dea Norge AS (50%), Equinor Energy AS (27.5%) and Neptune Energy Norge AS (22.5%). Operation facilities at the field consist of Njord A, a floating steel platform unit, containing drilling and processing facilities (along with living quarters), and Njord Bravo, a storage vessel. Although the field was discovered in 1986, production did not begin until 1997. The field lies around 130 kilometres (81 mi) northwest of Kristiansund municipality, Norway. The Njord oil field ( Njord – petroleumsfelt) is an oil field 30 kilometres (19 mi) west of the Draugen field, in the Norwegian Sea. Wintershall Dea Norge AS (50%), Equinor Energy AS (27.5%) and Neptune Energy Norge AS (22.5%)
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