Like any offshore region, it has been a trying few years for the UK North Sea since the devastating oil price downturn that kicked off in mid-2014 and saw Brent crude prices plummet from more than $100 a barrel to around $35 as the price finally bottomed out in January 2016. Since then, oil and gas operators on the UK Continental Shelf (UKCS) have tightened their belts considerably, cutting production costs and collectively laying off tens of thousands of workers.
Now, North Sea observers are optimistic that the pain is beginning to pay off. Average development costs across the UKCS have fallen from $23.80 per barrel of oil equivalent (boe) in 2014 to an estimated $13-$15 in 2018, with operating costs also falling to less than half of what they were before the oil price crash.
Production efficiency has also been boosted significantly, rising from 61% in 2012 to 74% last year, according to data from the Oil & Gas Authority (OGA), the regulator and industry champion created as an independent agency by the UK Government in April 2015 in response to Sir Ian Wood’s famous 2014 review of the UKCS.
As a highly mature offshore province, the UKCS is now being geared towards the ‘Maximising Economic Recovery’ theme set out by the Wood Review, with emphasis placed on securing the investment and development necessary to make the most of the region’s remaining reserves in the coming decades.
Vision 2035: long-term outlook looks bright on paper
‘Vision 2035’ sets out the OGA’s long-term strategy for optimising hydrocarbon recovery in the UK North Sea, with a headline goal of reaching 14.9bn boe in cumulative production by 2050. Going by the latest analyses, it’s a goal that appears to be within the reach of the UK’s offshore industry, at least in theory.
The most recent numbers come from the University of Aberdeen’s Centre for Research in Energy Economics and Finance (ACREEF). In October, ACREEF director and professor of petroleum economics Alexander G. Kemp and research fellow Linda Stephen published a new assessment of long-term prospects for the UKCS. The researchers took into account the operational cost reductions of the last three years, carrying out financial simulation modelling using a base scenario of $60 per boe and 55 pence per thermal unit for gas in real terms.
The study’s topline results seem to confirm the productivity gains made by the industry on the UKCS, and show a path forward that would see the region come within a whisker of the OGA’s ambitious production goals by 2050.
“What we are finding is that if the cost reductions painfully achieved over the last few years can be maintained, then between 2018 and 2050, we could have, on one view of what the required investment hurdle of investors could be, a total cumulative production of 14.8bn boe, which would actually be in line what the OGA’s Vision 2035,” says Kemp.
“That’s quite encouraging, and what it means is that the rather sharp decline in production between 1999 and 2014 has been substantially moderated. Over the last couple of years, despite the pains, the industry has had a reasonable increase in production. We’re saying that might continue for a few years. We’re also saying that the dramatic decrease in field investment could be stabilised, and there could be some increase over the next number of years.”
The road to 2050: risks abound for future UKCS production
The numbers paint a promising picture, but as Kemp acknowledges, there are a host of caveats that could throw off these optimistic projections. The most obvious is the oil price, which has recovered since the doldrums of 2016 but still looks a long way from the heady days of $100-plus that were seen before the 2014 crash, and significant volatility this year is keeping investors guessing.
“The price has been extremely volatile this year, and has gone up to about $85 and later dropped to below $60,” says Kemp. “There’s no doubt about it, the investment screening price is very important. We found a big difference according to the price you pick.”
Oil and gas developers can offset price risk to some degree with hedging, allowing them to fix a price for future hydrocarbon production. But with a similar volatility in futures prices, getting the hedge right is no easy feat.
Central to the OGA’s strategy for maximising economic recovery, as well as the encouraging modelling in Kemp’s report, is the ability for the industry to develop and commercialise marginal fields that are classified as technical reserves. These fields are generally small, with high potential unit costs and significant gaps in reliable data. Given that new exploration projects are thin on the ground and set to stay that way – “by 2045 there are very few exploration wells,” says Kemp – the industry’s willingness to invest in developing these wells and collaborate through clustering to make them viable is a make-or-break factor for the region’s future.
“As the currently sanctioned fields are reaching the end of their lives, we depend more and more on these not-yet-sanctioned fields, where there’s a lot of uncertainty about them,” Kemp says. “That’s where the ifs and buts come in. There is a rather optimistic view taken on the ability of the industry to successfully develop a lot of these small pools.”
A rosy future for the UK North Sea also depends on maintaining the cost reductions and efficiency gains made during the last few years. “We’re assuming that all the cost reductions will be kept under control,” says Kemp. “We only have overall costs increasing at 2% per year, the general inflation rate, which is very modest. If the costs go out of control, as they did between 2009 and 2013, then that would spoil the whole thing.”
Bringing the industry together to maximise economic recovery
So Vision 2035’s goal of 14.9bn boe cumulatively produced by 2050, and the predictive studies that show this is possible, might be fairly accurately described as a best-case scenario, and one that could easily be knocked off-course if a few key variables trend lower than expected.
With the future shrouded in mystery, it’s more important than ever that supporting bodies such as the OGA are facilitating investment today. Part of that will be fundamental research on commercialising small pools, one of five key research areas at the Oil & Gas Technology Centre, established in Aberdeen in October 2016.
“Quite a few technical advances are currently being researched, and we are in effect assuming that these will bear fruit,” says Kemp.
Beyond the technical aspects of marginal field development, the Wood Review calls for massively increased cross-sector collaboration to form cluster developments around small pools, allowing multiple fields to share infrastructure, which will be vital to control costs when developing harder-to-reach reserves. Kemp says recent studies have demonstrated that the returns from cluster developments in the southern North Sea far outstrip what would be possible with standalone projects, but fostering the level of collaboration between rival firms will be one of the OGA’s trickiest challenges.
As the OGA and the UK Government continue to market North Sea opportunities to the global oil and gas industry, any provision of raw data improves companies’ ability to make investment decisions set against an uncertain future.
“Since the Oil & Gas Authority was formed, it has put out a yearly estimate of oil and gas reserves,” Kemp says. “The last one came out very recently, just a few weeks ago [at the time of writing]. Since it took over that responsibility, its coverage of the subject has increased year by year. And of course, now it provides seismic data to operators. Data provision by them can help quite a lot, especially at the exploration stage.
“So yes, the Oil & Gas Authority is now providing not only information on reserves, but information on a wide range of topics. Going back ten years, there was no such provision.”