Opinion: Future potential of the UK North Sea

The UKCS Workforce Dynamics Review has been produced by OPITO and RGU.
Iona Energy had a number of projects in the North Sea before it went under.

Professor Alex Kemp and Linda Stephen of Aberdeen University review future long-term prospects for the UK Continental Shelf

The current political debate has generated much heat surrounding the future of the North Sea oil and gas industry. Here we attempt to shed light on the subject.

The long-term future of the sector depends on a combination of:

o The volume of the ultimate resources, including future discoveries

o The costs of exploiting these resources

o Government policies (which can incentivise or retard exploration and developments)

An understanding of all of these is necessary to come to informed judgements about the long-term potential.

The Department of Energy and Climate Change (DECC) has recently stated that its best estimate of the remaining recoverable potential is in the range 11-21billion barrels oil equivalent.

DECC also sees a considerable upside potential, but with much higher associated risks. Another reputable source, Oil and Gas UK, estimates the ultimate recoverable potential within the range 15-24billion boe.

It is important to note that these estimates have no associated time scale indicating when the resources could be exploited. Nor has detailed economic modelling been conducted to assess whether the fields associated with these resources will be commercially viable.

Here at Aberdeen University, we have conducted detailed financial modelling of the prospects in the period to 2050. This involves calculations of the pre-tax and post-tax returns to all the sanctioned fields, incremental projects, probable and possible fields, discoveries not yet being assessed, and the fruits of further exploration.

Reflecting the current practice of licensees, a conservative oil price of $90 in constant real terms was employed to screen all field developments.

For those discoveries not currently being assessed an average development cost premium of $5 per barrel above those pertaining to current new developments was imposed.

Key results are that cumulative production over the period 2014-2050 could be in the 14-15billion boe range, depending on the extent of success in implementing Wood Review recommendations regarding production efficiency and access to infrastructure.

Further financial modelling has also been undertaken on the possible effects of tax reliefs following the current review. These could incentivise further field developments resulting in a total plausible range of 15-16.5billion boe over the period to 2050.

The year 2050 is a convenient date at which to stop detailed modelling. But the industry will continue beyond that date. Some existing fields such as Clair can confidently be expected to remain viable beyond 2050.

Further, in our comprehensive database, no fewer than 125 known existing discoveries remain undeveloped at 2050 because they are not commercially viable at the $90 (real) oil price.

In aggregate they contain total potential recoverable reserves in the range 2.5-3billion boe.

Some have extremely high costs per barrel and may never be commercially viable.

But, even the most bearish commentators on the oil market would agree that, by 2050, real oil prices are likely to be much higher. Thus more developments should be triggered by that time, even with the expected reduction in infrastructure availability.

At the year 2050 in our model there are also 58 new discoveries made between 2014 and 2045 which contain over 1billion boe but are uneconomic. Again, it can be expected that, with higher oil prices, some will become economic.

Over the longer term, technological advances can also be expected which will result in rates of oil recovery higher than the present average of around 45%.

At the moment there are only a very few active tertiary recovery schemes.

Others are certainly possible, and, with sympathetic encouragement from Government, many more could be implemented, relating to schemes such as low salinity water-flood, polymer flood, miscible gas injection and CO2 injection.

Recovery factors in the 60%-70% range would make a substantial extra contribution to aggregate production both before and after 2050.

Technological advances have already led to decommissioned fields being reopened. It can confidently be predicted that there will be more of these. Some will utilise producing systems with tanker loading for exporting oil and so reliance on existing infrastructure is reduced.

As an example of what could be achieved with new technology the decommissioned Miller field could be reopened, perhaps with a CO2 EOR scheme.

It will be recalled that the scheme which was aborted some years ago envisaged extra oil production of around 40million barrels.

Currently there is a somewhat downbeat sentiment in the UKCS with falling output, exploration at very low levels, and many assets being offered for sale.

Historically, there have been waves of pessimism and optimism. It is also tempting to extrapolate historic trends.

In the later 1980’s, the general view was that the fall in oil production from its peak in 1984 would continue unabated, given the reduced prospectivity and high unit costs.

The Department of Energy “Brown Book” published in 1988 foresaw a continued production decline into the 1990’s. In the event, technological advances, such as long reach horizontal drilling and 3D (and later 4D) seismic, plus cost reductions and favourable tax treatment for new developments, reversed the decline in a fairly spectacular fashion.

In sum, it is quite conceivable that the industry can be prolonged well beyond 2050 at activity levels which, while small by today’s standards, contribute significantly to the national economy.

No-one can say with any assurance whether or not the long run upper potential of 24billion boe foreseen by OGUK will be achieved. But policies consistent with this should be put in place.