An uncertain outlook

Production is increasing in the UK North Sea as investments made up to 2014 come onstream. But what’s next? Elaine Maslin takes a look.

The Culzean development jacket was installed in July. Image from Maersk Oil.

Investment made in the boom years leading up to 2014 has been playing out in the UK North Sea this year, resulting in increased production in the basin.

BP’s huge Quad 204 floating production, storage and offloading (FPSO) redevelopment project, West of Shetland, came onstream in May, closely followed by EnQuest’s Kraken heavy field development – another FPSO project – in June. Premier Oil’s Catcher FPSO development and the Western Isles FPSO, operated by Dana Petroleum, are expected to follow suit.

More will follow, with Statoil’s Mariner heavy oil development, as well as Maersk Oil’s high-pressure, high-temperature Culzean development taking shape– both fixed facility developments due onstream in 2018 and 2019, respectively. The result is increasing UK Continental Shelf (UKCS) production. Yet, all but one of these projects (Culzean) were sanctioned in 2012-2014. Since then, fewer projects have been sanctioned.

In 2012, not including field addenda, there were 21 offshore field consents, but that tapered off to 10 in 2013, and seven in 2014. In 2015, it only just five: EnQuest’s Scolty and Crathes oilfield tiebacks, Total’s Glenlivet and Edradour condensate subsea tiebacks, and Culzean. In 2016, just one project was sanctioned (a historic low): BP’s Arundel tieback. Similarly, so far, only one project has been sanctioned in 2017, Statoil’s Utgard development, a tieback, which straddles the border with Norway.

A modest hopper

BP Glen Lyon FPSO, which came onstream earlier this year. Image from BP.

“The first half of this year hasn’t been as good as you would expect,” says Theo Bull, UK upstream oil and gas analyst at Wood Mackenzie. But, there is some light at the end of the tunnel. Three more projects are expected to reach final investment decision this year, Bull says, on a base case estimate. He expects those fields to be Hurricane Energy’s Lancaster early production system (OE: September 2015), West of Shetland, Independent Oil & Gas’ Vulcan Satellites project (OE: August 2017), in the southern North Sea, and Alpha Petroleum’s Cheviot development. Shell’s Penguins redevelopment (OE: April 2017) and Zennor Petroleum’s Finlaggan discovery development are possible “wild cards” for 2017.

If you include Norway, which has had three project sanctions in the year to date, one brownfield and two subsea, there’s a modest number of projects, Bull says. “By the end of this year, we expect seven projects to be sanctioned (three in the UK, three in Norway and one in the Netherlands), amounting to 670 MMbo or US$8 billion in capex. That’s a reasonably positive story,” Bull says. In comparison, there were 2400 MMboe sanctioned in 2015 (515 MMboe not including Johan Sverdrup) across five fields, totaling $21 billion capex, and 560 MMboe sanctioned in 2016, across 11 fields, totaling $5.5 billion capex.

“Looking further ahead, we expect up to six greenfield FIDs in the UK in 2018, with Premier Oil’s Tolmount the most significant. However, the majority of the remaining projects expected to reach sanction are reasonably small scale,” Bull adds.

BP is still assessing further phases of its Clair field, West of Shetland, while Chevron is still crunching the numbers on what would be a large FPSO development at Rosebank, but Wood Mackenzie doesn’t expect this to reach FID until 2019.

Chevron said that it expects to issue invitations to bid for the Rosebank FPSO later this year –having cancelled a previous contract.

Recently, commentary by Westwood Global Energy Group suggests that, even with OPEC cuts being held, the pain could continue beyond 2018, as increased supply – the result of the record spending levels in up to 2014 – brings more oil to market.

Silver linings

However, speak with the UK Oil & Gas Authority (OGA) and it seems there’s more about which to be positive.

“We are currently looking at about 16 field development plans including addenda during 2017, with currently an additional 10 in 2018,” says Gunther Newcombe, the OGA’s director of operations. “Not all of them are big, but they are incremental and will potentially add an additional 250,000 b/d to future production, as well as some much-needed contracts for the supply chain.”

Indeed, a recent report by the International Energy Agency said conventional producers are globally now focusing on smaller, more near-term investments, and it has been suggested that this could also mean the industry is more able to hold back from going into another cost escalation cycle.

Following the OGA’s 2017 report on North Sea projects, which highlighted budget and schedule overruns, and lessons learned, huge strides have been made in project delivery, Newcombe says. “This year, EnQuest’s Kraken development came onstream significantly under budget [$2.5 billion vs $3.2 billion at the time it was sanctioned] and Maersk Oil’s Culzean project is currently on time and budget.”

Exploration is how the hopper is filled and UKCS exploration drilling remains low. But, there have been high success rates among the wells that have been drilled, Newcombe says. “Last year, 26 exploration and appraisal wells were drilled (13 each), with 460 MMboe delineated, at $0.87/bbl, with a high, one in two success rate, Newcombe says. This year, approximately 28 wells are expected with the key aspect being quality not quantity.”

There is some interesting exploration in the North Sea coming up, Bull says, including the highly anticipated Korpfjell prospect (in the Barents Sea) and the Verbier prospect in the Moray Firth of the UK North Sea.

The hope is that there’s more to come, following some £40 million government funding spent on broadband seismic over underexplored areas of the UKCS. This has been made available to industry, alongside a host of existing well and other data.

Known, but untapped, discoveries are also under focus. Some 150 data bases, and other data, were made available ahead of the 30th licensing round, which looks to relicense these fields. Projects like the Vulcan Satellites show these fields do offer opportunities, Bull says. The 30th round is anticipated to be the largest round ever, according Paul Warwick, an industry veteran, who was speaking in Aberdeen last month.

Another possible resource is tight gas, which the OGA recently launched a study into, focusing on the southern North Sea.

“The Southern North Sea tight gas play holds over 2 Tcf in discovered, but undeveloped accumulations,” says Dave Moseley, manager - Reports, NW Europe at research group, Westwood Global Energy Group. And there is further potential in undrilled exploration prospects and infill drilling opportunities, which could increase estimates to 3.8 Tcf, according to the OGA. But, Moseley warns, most developments are reliant on current infrastructure remaining open for business.

Some are already active. BP, which retained interests in the Carboniferous play when it sold out of the southern gas basin in 2012, is now drilling an exploration program south of the Ravenspurn field, targeting a new tight gas play in the Namurian.

“This was encouragingly sidetracked with a development leg in June,” Moseley says. “If the several-hundred Bcf pre-drill potential can be realized this may help extend the life of Ravenspurn, which is currently expected to reach cessation of production in around 2021. However, even in the event of success, discoveries like this remain the exception rather than the norm in a basin of this maturity.”

Another initiative, to encourage more collaboration, through area plans, could also reap more production, Newcombe says. “The area planning approach is really critical. In the central Graben, we can see, value can be improved by up to 50% if we can get more collaboration and optimize the use of current infrastructure,” he says. Similarly, there’s a significant volume of gas West of Shetland that is currently stranded and could be unlocked if companies worked together.

Last but not least, technology also has a role to play, Newcombe says, both deploying it faster but also more broadly across the basin.

The OGA has been gathering technology plans from the operators and it is looking where technology could be used more broadly than it currently is, from geosteering to using flexibles instead of rigid pipes. Pilot projects, such as testing a thermite plug, for well barrier placement, are being encouraged. The thermite plug concept is due to be tested onshore in the UK this October, under a project with the Oil & Gas Technology Centre. But, it’s also been looking at research and development, an area which has suffered from low investment, says Newcombe, who suggests tax breaks might be able to help encourage activity in this space.

Ultimately, however, he says the basin needs transformational change: “There’s a lot of good stuff happening, but it’s too slow. Collaboration will make the big difference.”