North Sea under pressure
The industry still thinks the mature province offers opportunities, but the good times may not have long to roll
While the short-term outlook for the North Sea is bright, it's still hard to see how the sector can maintain momentum beyond the early 2020s without more big finds—and they have largely proved elusive in recent years.
The oil and gas production outlook for Norway, the UK and the Netherlands is largely flat or one of gentle decline up to 2025, with a handful of sizeable discoveries now coming into production helping to ameliorate the impact of output declines in existing fields.
Rystad Energy, a consultancy, forecasts that West European operators—mainly active in those three countries—will produce just over 7m barrels of oil equivalent in 2017, falling to around 6.2m boe/d in 2025. Production due on stream in the next five years is being underpinned by some recent discoveries.
In Norway, Statoil and Lundin's Johan Svedrup project in the Utsira Height region of the North Sea, based on estimated resources of 1.9bn-3bn boe, should start producing oil in late 2019. Offering 440,000 b/d to start with and peaking at 0.66m b/d, Statoil estimates this will account for 25% of total Norwegian oil production at the time, illustrating the project's importance.
Meanwhile, Statoil is expected to take a final investment decision on the $6bn Johan Castberg development in the Barents Sea by the end of 2017, which could start producing in 2022 from proven reserves estimated at 450m-0.65bn barrels.
In the UK, Hurricane Energy's major discovery in the Greater Lancaster area, west of the Shetland Islands, could prove to be the largest in UK waters for more than 15 years. The company talks of 1bn barrels of recoverable resources. Hurricane wants to start production in 2019.
Total brought its 90,000-boe/d Laggan Tomore development in the West of Shetland area on stream last year. It has just announced the start of production from the nearby Edradour and Glenlivet gas and condensate fields, which could add as much as 56,000 boe/d to UK output.
But prospects become murkier further ahead. The latest crop of new output stems largely from exploration efforts in the years around 2010, when the Johan Svedrup find was discovered, and when both oil prices and capital spending were high.
Since 2014, against the background of lower oil prices, the number of North Sea discoveries has tailed off. That means there simply won't be the same amount of hydrocarbons to convert into new projects by the 2020s.
"If you make a find of a couple of hundred million barrels, then it's a good find, but when you are trying to combat declines from multi-billion barrel fields you need bigger discoveries to make an impact on overall production," says Simon Sjøthun, a consultant at Rystad.
A lot of money, incentives and energy have been thrown into tracking down those new mega-finds. The quest has taken drillers in the UK North Sea into deeper, stormier waters and high-pressure, high-temperature wells. For drillers in Norway, it's taken them into the Arctic. But success has been limited, with several prospects flattering to deceive in recent years.
The latest disappointment was Statoil's announcement in late August that drilling on its Korpfjell prospect in an area of the Barents Sea, close to the Russian border, had found non-commercial quantities of gas and no oil. The test well did at least establish the existence of a petroleum system and more wells will be drilled, but earlier estimates by Statoil and its partner Lundin, which had speculated about oil reserves of greater than 1bn barrels, look over-optimistic.
Dry wells have been commonplace in the Barents Sea in recent months. The largest discovery has been Lundin's Filicudi oil find in the Loppa High area in February, estimated to hold a gross resource of 35m-100m boe of both oil and gas. Statoil has also made an oil discovery, estimated to hold 50m boe in the Kayak area of the Barents, which could be tied back to Johan Castberg, and another oil and gas discovery in the Norwegian Sea—Cape Vulture—for which resources are estimated at 20m-80m boe.
These all have commercial potential, but they aren't going to be transformational for the region unless they prove to be part of much larger reservoirs.
Significant efficiency gains and enhanced oil recovery techniques are at least helping to ameliorate the decline rate. Money has also been pumped into renovating and extending the life of established fields. BP has done this with the Schiehallion redevelopment West of Shetland, an area where the production heyday was in the 1990s, but which could now keep producing until 2035 and beyond.
You need bigger discoveries to make an impact on overall production
Governments are also doing their bit, pushing new licensing rounds in both Norway and the UK, while easing the fiscal load and providing tax breaks for operators. In Late August, the UK's new energy minister Richard Harrington pledged the government's "full support" for the industry, claiming that the authorities were working to provide £2.3bn ($2.96bn) worth of government support through its Industrial Strategy.
A Wood Mackenzie report, published in September, highlights the upside of further exploration in the UK North Sea. The consultancy estimates that around half of the UK's 3bn boe of technically recoverable stranded oil and gas resources is potentially economic, which, while costing $18bn to develop, it could still generate $10bn in value to project partners.
Wood Mackenzie reckons it would take 14 years and 500 wells to discover fresh volumes of a similar size, so it could be a prize worth the investment in such a mature province. But it also notes that the challenges would be substantial, given that the individual projects would be small and that it would require a group of peers to exploit them effectively—something which could be difficult to form.
External factors are also likely to play a role in how the North Sea develops. The majors, at least publicly, seem sanguine about the future of the global oil industry, with most of the biggest players saying they don't expect oil demand to peak until the 2040s or beyond. But any signs that the peak could be nearer, or simply the addition in coming years of tougher environmental regulations, would weigh on investment decisions in mature provinces such as the North Sea. This is especially true if cheaper supplies can be found elsewhere to meet global demand.
Green issues are already moving closer to centre stage. September's Norwegian elections featured debate over whether the country should stop oil drilling altogether, or at least curtail it in sensitive areas of the Arctic.
Still, despite the chaos threatened by Brexit in the UK, the North Sea has the advantage of being surrounded by politically stable, affluent countries with long experience of the hydrocarbons sector and an infrastructure to match. Provided the oil price doesn't slump again soon, that should be enough to delay the inevitable.