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Up and running: inside INEOS’s decision to keep the Forties pipeline flowing
The Forties pipeline system exports around 40% of the UK’s oil and gas, and links up more than 80 North Sea assets. Julian Turner assesses how INEOS' decision to postpone taking the pipeline offline this June, due to the Covid-19 pandemic, will impact UK and world markets.
Credit: Henning Flusund
In 1975, BP transported the first oil ashore from the Forties field in the North Sea along the Forties pipeline system (FPS) to Cruden Bay.
Production from the field officially began two months later at a rate of 10,000 barrels per day (b/d). Once all four drilling platforms were operational, the 130-well system had an estimated production capacity of 500,000 b/d; by 2015, four decades later, Forties had delivered more than 2.6 billion barrels.
Today, the 310-mile pipeline remains a vital piece of energy infrastructure. Serving the central area of the North Sea in both the UK and Norway, it has nominal capacity of over 600,000 b/d; delivers around 40% of the UK’s oil and gas; and connects more than 80 oil and gas assets to the mainland.
Shutting it down can therefore have a serious impact on oil and gas prices, as well as jeopardising revenue and security of supply. In December 2017, INEOS – which had acquired the FPS and Kinneil terminal from BP just two months earlier – announced it was shutting the pipeline for a period of weeks while a hairline crack and subsequent leak near Netherley in Aberdeenshire was repaired.
As a result, the price of Brent briefly rose to a two-year high of above $65 (£47) a barrel, while wholesale natural gas prices for UK same-day delivery surged by nearly 30% to a four-year high.
"The shutting down of the Forties pipeline does cause significant issues for our industry, financially, operationally and commercially,” commented Deirdre Michie, chief executive of trade body Oil & Gas UK. “40% of oil production is now shut-in and the resulting lost production is worth around £20m per day at current oil prices to industry.”
Covid-19 and INEOS’s decision to postpone FPS shutdown
In July 2019, INEOS announced it had started progressively reducing the throughput of the FPS to roughly half normal levels to fix an operational issue with the main heater on train three at Kinneil.
As a result, FPS flows decreased to around 180,000 b/d, while gas streams from the Elgin-Franklin fields, a significant supply source for the UK, were restricted to an estimated three million cubic metres a day.
The previous February, INEOS underlined the importance of the asset to the UK in general – and the company’s bottom line in particular – by unveiling an ambitious $626m (£500m) investment package in the pipeline system, aimed at modernising environmental systems and upgrading technology.
INEOS said it will prolong the life of the pipeline by “at least” 20 years, and gave notice of a three-week "system shutdown" as part of the investment package, scheduled to take place in June 2020.
INEOS said it will prolong the life of the pipeline by “at least” 20 years
Then came Covid-19. As the world struggled to get to grips with the pandemic, INEOS announced in late March that it would delay the planned shutdown until August at the earliest due to concerns around bringing workers together, and that it was also “responding to requests from customers”.
On 4 April, INEOS said the postponement of the FPS downtime would be extended further to 2021.
“The decision has been taken in the face of the ongoing government restrictions due to the coronavirus pandemic, and in the interests of providing clarity to its customers and the UK oil and gas industry,” the company said in a statement.
“We found that there was a desire to delay the shutdown to 2021 by the majority of our customers.
“In making this announcement it is hoped that customers (and the supply chain) will now be able to plan with greater certainty.”
Flood warning: the FPS and global production increase
One of the immediate effects of the initial postponement was a projected increase in North Sea oil production. According to research firm Rystad Energy, the decision to delay the shutdown to August 2020 could add several hundred thousands of extra barrels to the market every day over summer.
Rystad forecasts a rise of 330,000 bpd to 2.96 million bpd for June 2020, and of 190,000 bpd to 3.04 million bpd for July; presciently, it also said “we see a case for delaying the turnaround to 2021”.
“This just adds another ripple to the growing oversupply pool of global liquids – an overhang for 2Q20 that is already so incomprehensibly massive that it will eventually force shut-ins as oil prices fall below short-run marginal costs and logistical challenges arise,“ said Rystad Energy oil market analyst Milan Rudel, referring to the decision by OPEC+ countries to start flooding the world’s total oil production with an estimated extra 2.5 million bpd amid the Covid-19 crisis.
This just adds another ripple to the growing oversupply pool of global liquids
At the time of writing, OPEC producers and allies have agreed to cut output in May and June by 10 million barrels (around 10%) to counter the slump in demand caused by Covid-19 lockdowns. The cuts will then be eased gradually until April 2022.
Rystad also noted that E&P companies are trying to keep oil flowing during the current crisis, while cutting back on all other activities. Turnarounds increase human-to-human contact; for example, adding maintenance crews typically results in more people on the platform, and more rotation.
“Given the current struggle, E&Ps are understandably trying to mitigate the coronavirus risk by implementing their version of social distancing,” added Rudel.
Less is more: downtime trends in the North Sea
In a wider context, there is evidence that North Sea production downtime as a whole is decreasing.
According to the second edition of the Glacier Production Index – which tracks the frequency of uptime and downtime in offshore UK oilfields on a quarterly basis using Oil & Gas Authority data – North Sea operators reduced the frequency of downtime by 19.2% in the year to September 2019.
Published in February, the latest figures reveal a successful year-on-year reduction in downtime in the year to September. Offshore rigs exported an estimated $11.1bn (£8.5bn) worth of oil from the North Sea in the first nine months of 2018, when the average level of uptime was 80; this has since risen to 83% in 2019, potentially resulting in millions of dollars of additional revenue for producers.
Many North Sea assets will have to survive without the most important pipeline system in the basin
“Planned shutdowns are still the largest source of downtime in the North Sea,” commented Scott Martin, executive chairman of oilfield services firm Glacier Energy Services. “Broadly speaking, the less frequently downtime occurs, the more efficient production is likely to be.
“Increasing efficiency has attracted fresh investment in the North Sea, as the industry looks to continually reduce its cost base while extending the lifecycle of its assets. Downtime frequency is just one barometer of how successfully this is being achieved.”
The Glacier Production Index was published before the decision to postpone the planned shutdown of the FPS in June 2020. Glacier Energy Services warns the downward downtime trend could end when the FPS was due to close, confirming the pipeline’s economic and strategic importance.
“The industry is consistently reducing downtime but in modest degrees,” said Martin. “That consistent, moderate progress could face a major challenge this summer, as many North Sea assets will have to survive without the most important pipeline system in the basin.”