Since discussions about the UK oil production are widely available on the net, in this post I will focus on the UK gas production.
Even though the UK remains as the world’s significant oil and gas producer, the UK Continental Shelf is today a mature oil and gas province.[1] This means that the shelf has been extensively explored.[2] As a result discoveries now average at 20-30 million barrels of oil equivalent,[3] which is fifty to hundred times smaller than the fields on which the North Sea was built.[4] Moreover, the increase in drilling activity especially in the past few years has not delivered produced a better success rate, which ranges between 25% and 33%. According to UKOOA, 96% of future exploration prospects are expected to be less than 50 mboe and 88% less than 20 mboe in size.[5]
Dry gas makes up close to 40% of total proven plus probable reserves[6], as well as possible reserves.[7] According to the DTI, potential additions to reserves (which are currently technically or commercially producible) could be between 68 bcm to 282 bcm. Undiscovered gas resources are estimated to amount between 225 bcm and 1035 bcm.
All these figures indicate an ultimate recoverable resource base to be between 3000 bcm and 4500 bcm.
Up until the end of 2006 the UK cumulative gross gas production was slightly over 2200 bcm (60% of dry gas and the rest associated gas). This share structure, however, has changed. Now, associated gas production accounts for 60% of gross production. Net production amounted to about 2100 bcm.
All this means that about 75% of UK gas resource base is already depleted in the worst case, and 50% in the best case.
Note that gas production reached its maximum level in 2000 and oil in 1999. These imply that it will be the reservoir performance and future reserves that will determine the future production levels. That is why the primary challenges facing the UK oil and gas industry are increasing the resource base by finding new reserves; extending the current reserves in and around existing fields; extending the life of fields and infrastructure and maximizing the recovery, among others.
The bad news is that despite the surge in technology, sustained high investments in recent years, increasing drilling activity (in particular development drilling) as well as higher oil and gas prices, both UK oil and gas production continue to decline.
Expectations about decreasing upstream expenditures from 2007 onwards, increasing technical and operating costs and the latest tax increase in January 2006 when added to the issues raised above indicate that the UKCS oil and gas activity has already become less attractive (especially the risky development fields), less competitive, more exposed to lower energy prices, and more challenging.
Announced new projects that will come online in the next few years might slow the decline rate up to 2010 but according to our estimates the UK gas production will continue to decline.
Estimating the future production profile is an extremely difficult task. However, incorporating field production data, depletion rates and planned projects, into estimates may better represent the likely development. Otherwise one could end up with the implausible estimates such as the European Commissions’ in 2003.[8] The Commission realized that and made a correction in its new release[9] which is still implausible up to 2015. (The EC study gives estimates in 5 year intervals, so I extrapolated interim years).
Dry gas makes up close to 40% of total proven plus probable reserves[6], as well as possible reserves.[7] According to the DTI, potential additions to reserves (which are currently technically or commercially producible) could be between 68 bcm to 282 bcm. Undiscovered gas resources are estimated to amount between 225 bcm and 1035 bcm.
All these figures indicate an ultimate recoverable resource base to be between 3000 bcm and 4500 bcm.
Up until the end of 2006 the UK cumulative gross gas production was slightly over 2200 bcm (60% of dry gas and the rest associated gas). This share structure, however, has changed. Now, associated gas production accounts for 60% of gross production. Net production amounted to about 2100 bcm.
All this means that about 75% of UK gas resource base is already depleted in the worst case, and 50% in the best case.
Note that gas production reached its maximum level in 2000 and oil in 1999. These imply that it will be the reservoir performance and future reserves that will determine the future production levels. That is why the primary challenges facing the UK oil and gas industry are increasing the resource base by finding new reserves; extending the current reserves in and around existing fields; extending the life of fields and infrastructure and maximizing the recovery, among others.
The bad news is that despite the surge in technology, sustained high investments in recent years, increasing drilling activity (in particular development drilling) as well as higher oil and gas prices, both UK oil and gas production continue to decline.
Expectations about decreasing upstream expenditures from 2007 onwards, increasing technical and operating costs and the latest tax increase in January 2006 when added to the issues raised above indicate that the UKCS oil and gas activity has already become less attractive (especially the risky development fields), less competitive, more exposed to lower energy prices, and more challenging.
Announced new projects that will come online in the next few years might slow the decline rate up to 2010 but according to our estimates the UK gas production will continue to decline.
Estimating the future production profile is an extremely difficult task. However, incorporating field production data, depletion rates and planned projects, into estimates may better represent the likely development. Otherwise one could end up with the implausible estimates such as the European Commissions’ in 2003.[8] The Commission realized that and made a correction in its new release[9] which is still implausible up to 2015. (The EC study gives estimates in 5 year intervals, so I extrapolated interim years).
My estimate, however in the range of DTI’s and National Grid’s announced values, are closer to their high ends. I foresee a slower decline up to 2015 followed by a steep one, converging with the others but still remain relatively optimistic.
The implications on the other hand are enormous. After having been net oil and gas exporter many years, the UK has become a net importer of gas in 2004 and of oil in 2006. Meanwhile the retirement of nuclear power plants and decommissioning of coal fired ones, combined with environmental pressures to limit the emissions will lead gas demand to grow faster in the future. This will mean increasing imports for the UK. That is why a reliable estimate for production is a prerequisite in analyzing energy security issues, especially for the UK.
OK. I cannot make the brother of gas (oil) gelous. here is my estimate for the oil production profile. And yes, I am optimistic.
Notes:
[1] Up until 2005 about 4000 wells drilled in the UKCS.
[2] However, there are some exceptions. For example, in 2001 a Canadian company, Encana, discovered an important oil field in the UK Central North Sea, generally considered as mature. With more than 150 Mt oil, it was considered as one of the major discoveries within the last twenty five years.
[3] UK Offshore Operators Association Economic Report 2006.
[4] Exploration wells on average deliver about 10 mboe per well or about 30 mboe per discovery. The largest fields discovered in the past decade was Buzzard in 2001 (550 mboe reserves) and Lochnagar in 2004 (250 mboe reserves). Commercial discovery success rate in 2006 was 36%. The volume discovered per exploration well was 15 mboe, due mainly to a large discovery (more than 100 mboe). Note that this happens at a time when upstream capital investment was the highest in nearly a decade.
[5] UK Offshore Operators Association Activity Survey 2006, February 2007.
[6] Almost 700 bcm. Of which close to 70% is proven reserves.
[7] About 280 bcm.
[8] European Energy and Transport Trends to 2030, European Commission, 2003.
[9] European Energy and Transport Trends to 2030 – Update 2005, European Commission, 2006.
[1] Up until 2005 about 4000 wells drilled in the UKCS.
[2] However, there are some exceptions. For example, in 2001 a Canadian company, Encana, discovered an important oil field in the UK Central North Sea, generally considered as mature. With more than 150 Mt oil, it was considered as one of the major discoveries within the last twenty five years.
[3] UK Offshore Operators Association Economic Report 2006.
[4] Exploration wells on average deliver about 10 mboe per well or about 30 mboe per discovery. The largest fields discovered in the past decade was Buzzard in 2001 (550 mboe reserves) and Lochnagar in 2004 (250 mboe reserves). Commercial discovery success rate in 2006 was 36%. The volume discovered per exploration well was 15 mboe, due mainly to a large discovery (more than 100 mboe). Note that this happens at a time when upstream capital investment was the highest in nearly a decade.
[5] UK Offshore Operators Association Activity Survey 2006, February 2007.
[6] Almost 700 bcm. Of which close to 70% is proven reserves.
[7] About 280 bcm.
[8] European Energy and Transport Trends to 2030, European Commission, 2003.
[9] European Energy and Transport Trends to 2030 – Update 2005, European Commission, 2006.
No comments:
Post a Comment