The storm nears in the North Sea
UK and Norwegian oil output has defied gravity for the past year, but the slowdown will become plain in 2016
OIL OUTPUT from the UK and Norway has been hanging on in recent months, in spite of the seeming incompatibility of high costs and low oil prices. Both countries actually managed modest rises last year, as projects sanctioned before the slump in crude prices began to deliver oil. But a repeat of that levitation trick in 2016 seems unlikely, for now.
Hydrocarbons output from the UK Continental Shelf (UKCS) last year managed its first increase for more than 15 years, as spending on new-field development converted reserves into produced barrels. According to government field-by-field data, offshore oil production reached 0.934m barrels a day in the fourth quarter of 2015, an increase of over 11% from December 2014 and an average of around 0.89m b/d during the first 10 months of 2015.
This year, though, oil production should weaken slightly, as a result of natural declines in productivity, some field closures and a slow-down in new-field start-ups. By the summer, average UKCS production could be down by 20,000-30,000 b/d – roughly 2-3% – although a slight uptick in output towards the end of the year, as more new projects start up, might stabilise the full-year average at around that level. Gas production, meanwhile, may actually rise, with flows from Total’s 0.5bn cubic feet a day Laggan Tormore gasfield starting in the first quarter of 2016.
The situation in Norway is similar. Oil output amounted to 1.57m b/d in 2016. That constituted a 3% rise from 1.51m b/d in 2015, as the pace of drilling and output from existing operations exceeded expectations, says the Norwegian Petroleum Directorate (NPD). But although several significant discoveries are in development, a slow-down in infill drilling in response to weak oil prices is likely to push output back to around the 2015 level by the middle of the year, stabilising at that level over the full year. NPD forecasts average oil production of 1.53m b/d in 2016.
New to the scene
Recent UK start-ups influencing last year’s production rise include the 70,000 barrels of oil equivalent a day Golden Eagle field and the 50,000-boe/d Kinnoull field. Smaller contributions came from Gannets F and A, and Peregrine. Towards the end of the year, oil flows at EnQuest’s 20,000-b/d Alma/Galia field and Taqa’s 10,000-b/d Cladhan tie-back commenced, and will make small but growing contributions to 2016 output.
Further substantial additions to UK production in the near future are limited, with important projects slipping behind schedule. Premier Oil’s 20,000-25,000-b/d Solan field should enter service imminently, following bad-weather delays. But the start date of Ithaca Energy’s 30,000 boe/d Greater Stella Area development has been pushed back from the first to the third quarter. Dana Petroleum’s 40,000 b/d Western Isles Development Project (WIDP), previously due on stream this year, is now not expected to start commercial flows until late 2017.
Meanwhile, BP’s 50,000 boe/d Quad204 redevelopment of the Schiehallion and Loyal fields is not expected to yield first oil until late this year. Repsol’s 25,000-boe/d Montrose Area Redevelopment may start producing in 2016 – although 2017 is more likely – but won’t reach peak production until 2018. And uncertainty surrounds the future of the 11,000 b/d Orlando subsea tie-back, after developer Iona Energy went into administration late last year.
Several other projects are approaching start-up – including Chevron’s Alder field, Statoil’s Mariner field, EnQuest’s Kraken field, BP’s Clair Ridge expansion, and Premier Oil’s Catcher Area development. But these won’t be commercially active until 2017 at the earliest. Beyond 2020, the prospects for the UKCS look grim, with exploration and development drilling at a virtual standstill and hefty job losses threatening operational continuity.
Norway’s remaining oil resources, meanwhile, are larger than the UK’s, but it shares the problems of high costs and a preponderance of mature, declining fields. So far, though – like the UK – it seems to have escaped reasonably unscathed, with big investors broadly staying put despite low oil prices, and helping achieve last year’s rise in output. Recent start-ups include BG Group’s 63,000 boe/d Knarr field, which came on stream a year ago and produced an average of 12,000 boe/d in 2015. The ConocoPhillips-operated Eldfisk II project started producing in early 2015 and should continue to add to production in 2016 as it ramps up towards its 70,000 boe/d target.
Lundin Petroleum’s Edvard Grieg field, in the Norwegian North Sea, brought on stream in late 2015, should reach plateau production of around 100,000 boe/d in the second half of 2016. Eni’s 70,000-b/d Goliat field, in the Barents Sea, is expected to start producing in the imminent future. And Det Norske’s 16,000-b/d Ivar Aasen field is scheduled for start-up in the fourth quarter.
Prospects for 2017 and beyond include Gina Krog, Aasta Hansteen and Njord Future – all Statoil-operated fields – and Total’s Martin Linge field. But by far the best prospect for growth in Norwegian oil output – the Statoil-operated Johan Sverdrup field – won’t start to have a significant effect on production until after 2020. Among the Norwegian Continental Shelf’s largest ever oil discoveries, the field should produce 0.55m-0.65m b/d at peak.
This article is part of an in-depth series on regional production forecasts. Click here for our extensive global coverage.