Economic Report 2011
The UKCS: reserves, exploration, expenditure and investment, production and decommissioning
The UK’s continental shelf (UKCS) still has substantial oil and gas reserves remaining, despite having produced more than 40 billion barrels of oil equivalent (boe) over the past four decades. Based on DECC’s latest figures, Oil & Gas UK forecasts that there are somewhere between 14 and 24 billion boe1 still to be recovered. This range encompasses proven, probable and possible reserves plus a contribution from additional resources as a result of exploration activity. DECC reflects similar uncertainty in forecasting remaining recoverable reserves, with its own projections showing a maximum of around 35 billion boe against a central figure of some 20 billion boe. The remaining reserves are split roughly 2/3rds oil and 1/3rd gas and are consistent with the long term trend of reserves recovered.
Oil & Gas UK’s own figures show that currently approved investment plans (as of 1st January 2011) have the potential to deliver some 6 billion boe of reserves from existing fields. Additionally, around 3.1 billion boe from new fields and another 2.6 billion boe from brownfield developments are waiting to secure investment approval (the term “brown-field” refers to an existing oil and/or gas field; brownfield developments include several large extensions of existing fields which, because of their scale, might otherwise be considered as similar to large, new projects). In total these 5.7 billion boe cover a range of probabilities of recovery, reflecting both the underlying economics as well as the technical challenges posed by many of these fields. This could lead to the recovery of up to 11.7 billion boe during the next three decades based on the existing set of opportunities.
At the start of 2011, before the tax increase announced in the March Budget, Oil & Gas UK anticipated that proven and probable reserves (those with greater than 90% and 50% likelihood of recovery respectively) would total 10.6 billion boe, with possible reserves (less than 50% probability) adding 1.1 billion boe. However, the announcement of the increase in the supplementary charge to Corporation Tax has led to a major down-grade of investment opportunities by many companies, with initial reductions of circa 1 billion boe. This now suggests that proven and probable reserves have fallen to below 10 billion boe, again based on Oil & Gas UK’s figures.
Further new reserves are expected to come to fruition over time by:
- increasing the scope for recovery from existing fields,
- developing new discoveries which have yet to be properly appraised,
- addressing resources which are not technically or economically possible currently,
- exploring for new possibilities.
The ratio of proven reserves, in the central case, to annual production is now around 10 years, according to DECC. How successful the industry is at recovering these reserves will depend on its competitiveness.
More than ever, sustaining investment is the key to the future. Without it, the existing production base would decline at 15-20% a year. The pace of investment in exploration, new field development and increasing recovery from existing fields (brown-field investment) will shape the future of the industry. In conjunction with this, it will be essential to extend the life of the infrastructure in order to facilitate future developments, because their economics often rely on existing infrastructure, otherwise significant areas of the UKCS will become “sterilised” with little or no future production possible.
Exploration potential is highly dependent on investors’ appetite to address uncertainty. DECC carries a range of forecasts of undiscovered oil and gas resources which depend on the geological risk chosen to determine the cut-off point. With a 10% or higher geological chance of success, estimates of exploration potential range from circa 3 billion boe to circa 12 billion boe, with a central figure of 6.6 billion boe. At a 5% or more chance of success, the central forecast of exploration potential across the UKCS rises to circa 9.5 billion boe.
Almost half (45%) of current oil and gas reserves (proven, probable and possible) are located in the central North Sea, followed by 21% to the west of Shetland and 20% in the northern North Sea. The southern North Sea and the Irish Sea complete the picture with 12% and 2% of the total, respectively. The central North Sea and to a lesser extent the west of Shetland have substantial exploration potential, in addition to existing reserves, which should increase ultimate recovery.
To achieve an outcome which recovers 14 billion boe (the bottom of Oil & Gas UK’s forecast range in the first paragraph of this sub-section) will require substantial advances to be made in the more difficult geology of high pressure, high temperature (HPHT) and heavy oil reservoirs and in the deeper waters that are found to the west of Shetland, coupled with further sustained exploration activity and, of course, very substantial investment. The recent tax increase will have done little to promote such investments and it is anticipated that further changes both to the field allowance structure as well as the broader fiscal regime will be required in order to create the necessary impetus to invest in many of these risky opportunities.
To recover volumes approaching the 24 million boe (the top of Oil & Gas UK’s range) will require a radical approach to the UKCS embracing a whole range of new technical and commercial innovations to be applied to both new and existing fields. It is currently predicted that an increase in overall recovery rate for existing fields of 2.5 percentage points would cause another 1 billion barrels of reserves to be recovered. This could ultimately see new forms of technology being used offshore which have until now only been deployed onshore, such as chemical, polymer or CO2 flooding, as well as so-called “tight” gas production2. These technologies are still deemed to be uneconomic for offshore application, not least when water injection and gas injection have already been used in many fields, reducing the potential for such tertiary techniques of enhanced oil recovery (EOR). Oil and gas prices will have to increase significantly from the current outlook, combined with a radical change in the fiscal regime, if such technologies are to be applied to the UKCS.
The rate of new developments is important; unless infrastructure remains fully or substantially used, many of the existing systems will be decommissioned and removed preventing the recovery of future reserves from within their catchment area. Current analysis shows that up to half of existing fields could be decommissioned by 2020. This would lead to a rapid loss of key infrastructure and would curtail the future of the UKCS and its supply chain. However, with the necessary investment, supported by an appropriate fiscal and regulatory regime, decommissioning could be delayed by a further 10-15 years beyond current dates. Crucial to this will be the need to reduce the fiscal risk regarding access to decommissioning relief perceived by existing investors; unless investors are wholly confident that the expected tax relief will be available at the point of decommissioning, investment will tail off rapidly in many mature fields and similarly it will be much less attractive to initiate new developments. Both industry and Treasury are working together to establish how certainty on access to decommissioning relief can be achieved with the aim that initiating changes in legislation will be announced by the Budget of 2012. Success will extend the productive life of the UKCS, with lasting benefits for investment, production, employment, development of technology, taxes paid and security of supply.