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April 8, 2013 9:07 pm
When production starts at the Johan Sverdrup oilfield in Norwegian waters later this decade, it will provide a big boost to the country’s declining oil and gas output.
The discovery made by Sweden-based Lundin Petroleum in 2010 was the world’s biggest that year and could yet emerge as one of Norway’s largest discoveries ever.
Remarkably, it was found within three metres of where the French explorer Elf Aquitaine, now part of Total, drilled but failed to find oil in 1971.
But many of the other costly developments scheduled to come on stream in the North Sea over the coming years are not new finds.
Instead, a combination of high oil prices, better technology and some generous tax breaks have made it economic to lift deposits that were previously known about, but which were deliberately left in the ground because, at the time, the cost of extraction was too high.
In February, Statoil welcomed Ed Davey, the UK energy secretary, to Oslo, where he officially endorsed its plan to lead a $7bn investment in Mariner – the largest new offshore development in Britain’s sector of the North Sea in more than a decade. The Mariner field was first discovered in 1982 but left unexploited.
The expense of developing the field, an option originally explored by the now defunct Union Oil Company of California, led to it being declared fallow by the UK ministry in 2005. But it is expected to account for 5 per cent of UK daily output when it is running at full production between 2017 and 2020.
In the coming months, Statoil also expects to make a decision on whether to develop the nearby Bressay heavy oilfield in UK waters at a cost of $5.5bn. Extraction has been considered uneconomic since it was discovered in 1976, but Statoil hopes to change that by exploiting its expertise in lifting heavy oil from Norwegian and Brazilian fields.
It is not just oil majors that are committing billions of dollars to North Sea fields previously thought to be uneconomic.
In spite of early-stage funding difficulties, Xcite Energy has now drawn and sold oil from its Bentley field, which was first discovered in 1977. The Aim-quoted company expects a total development cost of $1bn to be profitably recouped by employing the latest range of improved and enhanced oil recovery techniques.
Such techniques include injecting steam, chemicals and gas into reservoirs to reduce the viscosity – stickiness – of oil and make it easier to lift.
Rupert Cole, chief executive of Xcite, says an updated reserves assessment now suggests that the post-tax value of oil reserves for the Bentley field ranges from about $1.5bn to $2.8bn.
“We shall now continue to move the project forward with ongoing studies into the potential for enhanced oil recovery, which has yet to be factored into the reserves assessment,” he says.
Though the field enjoyed many successful years of output, depletion and the increased water content of its oil has twice led to the abandonment of production, which first began in 1975. Now the company expects up to 57,000 barrels of oil equivalent a day to be drawn from the field.
EnQuest, which has secured $500m of investment from Kuwait’s national oil company towards the $1.3bn project, is not the first group to have revived abandoned European fields in recent years.
In 1996, Royal Dutch Shell and ExxonMobil ceased production at their Schoonebeek oilfield on the Dutch-German border, after nearly 50 years in which the field produced 350m barrels of oil. Declining production of treacle-like oil meant an estimated 750m barrels were left in the ground.
But in 2011, the joint venture restarted production using steam injection techniques that thin the remaining oil so it can be extracted.
The impact of wider deployment of so-called improved oil recovery and enhanced oil recovery techniques is hard to assess accurately.
But lobby group Oil & Gas UK suggests that greater investment could add 10bn barrels of oil equivalent to UK reserves.
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