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Forties breakdown heightens doubts over North Sea's longevity


Aging infrastructure hampers exploration

Norway struggles with Barents Sea

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The shutdown of nearly half the UK's oil output due to a hairline fracture in the Forties pipeline in December has added to doubts about the long-term future of the North Sea oil industry.

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The mantra of the oil industry both in Norway and the UK is that a growing ecosystem of companies of many shapes and sizes is helping maximize output and manage long-term decline, as are successful cost-cutting efforts since 2014.

North Sea fields and pipelines

In the UK the establishment of a new regulator, the Oil and Gas Authority, has replaced laissez-faire economics with a more rigorous, joined-up approach, the thinking goes.

Meanwhile, statist Norway is benefiting from a growing number of independent companies, backed by a vogue for private equity investment.

The optimism is supported by production uptick in both countries, following decades of decline.

Download our special report: Riding the wave: The Dated Brent benchmark at 30 years old and beyond

As crude oil production in the North Sea continues to evolve, its role in an increasingly globalized market has started to shift, having an impact on Dated Brent and its position as a global oil benchmark.

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UK upstream production is widely expected to be stable until the end of the decade, with oil output of around 1 million b/d, thanks to new fields such as Catcher, Kraken and Western Isles, and BP's refurbishment of the Clair and Schiehallion fields west of the Shetland Islands.

These five fields combined are expected to produce some 380,000 b/d of crude oil at peak.

The outlook for the west of Shetland region has been lifted by the plans of private equity-backed Hurricane Energy to bring on stream the Lancaster "fractured basement" discovery, a new geological play type for the UK, in 2019.

Norway's production outlook is particularly bullish, despite a dip in the second half of 2017.

Liquids output totaled 2 million b/d in 2016, and levels should be replenished by the start of output in 2019 from the giant Johan Sverdrup field, and a string of smaller fields.

Legacy fields Yme, Njord and Snorre are also being refurbished, and first oil from the Johan Castberg project in the Barents Sea is due in 2022.

But the UK's reliance on aging infrastructure, more of which passed from BP to smaller North Sea companies in 2017, is a concern, both in terms of immediate operations and long-term exploration.

Some warn against reading too much into the December 11 shutdown of the Forties pipeline, which carries around 45% of UK liquids output and was bought by chemicals company Ineos from BP just six weeks earlier.

It is unclear whether the shutdown signals more such problems ahead. Ineos has said it is making good progress with repairs, as it sources custom-made parts for the job.


But loss of infrastructure is a worry for the exploration companies trying to prolong North Sea production.

If the future of the North Sea is largely about extracting resources from multiple small accumulations of oil and gas, the model breaks down if legacy pipelines for transporting resources are removed from service.

Currently, more than half of the 110 infrastructure hubs in the UK North Sea should still be in service in five years' time, but by 2025 the share with more than five years' life in them falls to 10%, according to consultancy Wood Mackenzie.

"The longevity of those hubs is a big concern for near field exploration continuing," Wood Mackenzie research analyst Kevin Swann told the PROSPEX conference in London on December 13.

While the problem is less acute for Norway, it is an issue in the less developed Barents Sea region, which currently has just one producing oil field, Goliat.

Expansion hopes were fueled by the delineation of Norway's sea border with Russia in 2011, but the last three years have seen a lack of Norwegian exploration success generally.

Lackluster results in the Barents have scotched hopes for new pipelines; a more modest plan for the Johan Castberg development entails loading oil directly onto shuttle tankers.

"The Barents Sea continues to frustrate... [It] lacks a big, reliable, widely distributed reservoir system," Westwood Global Energy research president Keith Myers said at the PROSPEX event.

Indeed, despite new seismic imaging, both countries are struggling to find new resources.

It is 10 years since the UK's last discovery bigger than 100 million barrels of oil equivalent, the Culzean gas and condensate find in 2008; that field is due on stream, operated by Maersk Oil, in 2019.

UK officials point to strong interest in recent licensing rounds and a sharp drop in drilling costs, but not everyone will be convinced.

While UK explorers are recording higher technical success rates, the number of exploration and appraisal wells drilled is likely to have hit a new low of 20 this year, down from 44 in 2013.

Industry body Oil and Gas UK estimates capital expenditure in 2017 will have dropped to its lowest since 2010, at under GBP7 billion ($9.4 billion).

"There's a bow-wave of activity that's going to build up so hopefully, as we get to 2019 and beyond, the number of wells will increase," the OGA's manager for exploration and new ventures, Nick Richardson, said at PROSPEX.


Optimists point to a spate of deals in which major companies BP and Shell have sold assets in their North Sea heartland to smaller, dedicated players.

The assumption is the recipients, with a narrower range of options, will be hungrier to optimize these operations.

But again there are reasons for doubt. North Sea minnow EnQuest raised its profile this year by taking over the role of operator at the Sullom Voe oil terminal in the Shetland Islands from BP, and brought on stream the Kraken ultra-heavy oil field.

But financial constraints forced it to cut spending on its existing assets, resulting in a 13% drop in its overall output in the first 10 months of 2017, to 35,000 b/d of oil equivalent.

In Norway, BP's decision to hive off its assets into a new joint venture, Aker BP, has been positively received; Aker BP is now the country's largest independent with 130,000 boe/d of production, and holds a 12% stake in Johan Sverdrup.

But the deal perhaps underlines that it is the quality of assets that really counts.

Shell's recent sale of mature UK assets to private equity-backed Chrysaor for $3 billion-$3.8 billion was widely seen as a vote of confidence in the North Sea, partly because it suggested private equity investors are ready to accept slower returns.

But skeptics were surprised at the high price Chrysaor was persuaded to pay.

The wide variety of assets, comprising stakes in 10 different field clusters, will "require an awful lot of sorting out," a senior industry figure told the World Oil & Gas Week conference in London in early December.