![]() ![]() One oe equals the amount of energy released when one cubic metre of crude oil is burnt. The latter is a measure of energy which corresponds to burning a specified amount of oil. Oil equivalent – saleable (mill scm) The annual production from Draugen measured in oil equivalent (oe). This annual output of oil, gas and condensate equalled as much as the total expected recovery from Garn West and Rogn South combined. It was at its highest-ever level of 12.87 million scm of oil equivalent (oe) per year – almost too good to be true. Production from Draugen was highly promising in 2001. Fotnote: Adresseavisen,, “Draugen større”. The Kristiansund business community also did well, with Aker Møre Montasje and Vestbase – the biggest local suppliers – securing work in the order of NOK 70-90 million.Ĭoflexip Stena Offshore won the pipelaying job, while the new water treatment system on Draugen was produced by Aker Offshore Partner at Stord. Fotnote: NTB, 6 June 2000, “Draugen utvides for 130 millioner kroner”. ![]() Among those winning contracts were Kværner Oilfield Products AS at Lysaker outside Oslo, which delivered the subsea systems. Norske Shell could report in 2001 that it was investing NOK 1.5 billion in developing Garn West and Rogn South. These satellites helped to increase and extend oil production from Draugen – which was advantageous as oil prices staged yet another recovery after 2002. Their wellstreams are routed via Garn West (see map). The Rogn South development was approved in the spring of that year, and Transocean Winner drilled and installed two subsea wells in 2002 so that they could come on stream the following January. 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. By 2017, Draugen’s producing life had been extended to 9 March 2024 and its expected recovery factor was put at 75 per cent. ![]()
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