Whichever way you slice it, the giant Johan Sverdrup field in the Norwegian North Sea is proving a major success for its operator, state-controlled Statoil.
The firm now expects the project’s 440,000 b/d first phase to cost 28pc less than it estimated when phase 1 was approved in 2015. The field’s recoverable resources are now pegged at 2.1bn-3.1bn bl of oil equivalent (boe), up from previous guidance of 2bn-3bn boe and initial guidance of 1.7bn-3bn boe.
And best of all, the costs are down. Capital efficiency and cost-cutting have helped push the breakeven oil price for phase 1 to below $15/bl. The breakeven price for the whole field is pegged at under $20/bl.
Not bad at all for a field located in 120m of rough water between the Norwegian mainland and the Shetlands. But while the wait for Johan Sverdrup is almost over, the need for another big find is pressing.
Norway’s production is on an inexorable downward slope and Sverdrup will provide only a temporary salve. The Norwegian Petroleum Directorate (NPD) expects crude production to decline by 2pc in 2018 and fall further in 2019. Sverdrup then will provide a 15pc boost in 2020 and output could hit a record in 2023. Based on current assumptions, that year will also mark the peak, NPD said.
“It is absolutely essential that additional profitable resources are proven, also larger discoveries,” the NPD said last month. The recent uptick in global crude prices may encourage more exploration in a region with a forecast abundance of untapped resources and a benign investment environment. As BP’s upstream head Bernard Looney said last month, technological leaps forward are helping companies pinpoint oil and gas that was previously hidden.
This could be the key. Johan Sverdrup was discovered in the area in which the very first licence was awarded on the Norwegian shelf — an area that had come up dry in the 1960s and 1970s and was thought to have no potential.