Shale Gas

Memorandum submitted by the Department of Energy and Climate Change (SG 1)


UK Onshore Oil & Gas Activity in General

1. The onshore oil and gas industry has been operating in the UK for well over 60 years and production, although currently only 1.5% of overall UK oil & gas total, nevertheless contributes usefully to UK security of supply and to the UK economy.

2. Close cooperation between the industry and the planning authorities has allowed the industry to develop with minimal environmental impact. Alongside DECC licences and consents, all exploration and development activities also need to be authorised by the Health & Safety Executive .

3. Recent years have seen continued interest in onshore oil and gas activity as the response to the 13th Round in 2008 proved. That Round saw a good outcome with 97 licences awarded in total confirming the continuing commercial attractiveness of onshore oil and gas exploration opportunities in the UK, and there was renewed interest in coal bed methane.

4. Current estimates suggest that overall onshore potential proven and probable reserves equate to around 1.5% - 2% of the UK's overall reserves. Government wants to ensure that operators get the opportunity to explore and develop onshore - and licensing is the first part of this process.

5. There are currently some 28 UK onshore oil fields and 10 onshore gas fields in production. Overall UK onshore oil production is around 24,000 barrels per day (2009). BP's Wytch Farm field (Dorset) is the largest onshore oil field in Europe, and, although production peaked over a decade ago, the field still produces around 20,000 barrels a day ( around 83% of UK onshore oil production) .


6. In the UK, as elsewhere, gas (and oil) is predominantly produced from permeable rock formations such as sandstones. But there have been many attempts over the years to develop other kinds of petroleum resources. The commercial development of "unconventional" gas resources has been limited until the last decade, when new production techniques have enabled a rapid development of shale gas.

7. Natural gas can also be extracted from coal deposits by drilling ("coal bed methane" or CBM – also known as "coal seam gas"). The energy of coal can also be exploited by gasifying the coal in the ground ("underground coal gasification" or UCG), though the gas produced is not "natural gas" (i.e., predominantly methane), but a mixture of combustible gases.

Conventional versus unconventional shale gas, tight gas and coal bed methane (CBM)

UK Potential & Licence Rounds

8. Although there may be significant resources of unconventional gas in the UK, this has not so far been demonstrated. It should not be assumed that the commercial success of shale gas and CBM in the US will be transferable to the different geological and other conditions of the UK. We are however encouraging exploration and appraisal actively for both shale gas and coal bed methane. The Coal Authority is similarly encouraging exploration and appraisal for underground coal gasification actively.

9. DECC aims to launch a new (14th) onshore round this year, and expects a fair amount of interest from the industry, for both conventional and unconventional prospects.

10. The map below shows the location of CBM wells drilled, the three approved CBM developments, the Underground Coal Gasification licences awarded by the Coal Authority, the current onshore licences and the area under consultation which may be offered in the 14th licence round.

Map showing onshore licences, coal bed methane activity, and potential 14 th Round licence acreage.


11. The Technology - Shale gas is natural gas produced from shale. Shale has low permeability, so gas production in commercial quantities requires fractures to provide permeability. Although a small amount of shale gas has been produced for years from shales with natural fractures, the shale gas boom in recent years has been due to modern technology in hydraulic fracturing where fluid is pumped into the ground to create fractures to make the reservoir more permeable, then the fractures are propped open by small particles, and can enable the released gas to flow at commercial rates. Horizontal drilling is often used with shale gas wells, with lateral lengths up to 10,000 feet within the shale, to create maximum borehole surface area in contact with the shale. The US experience suggests that successful production techniques are quite specific to particular formations.

Ranges of Total Organic Carbon in typical tight gas sand, shale gas, and coal bed methane prospects

12. As the diagram above shows, there is a continuum of unconventional gas prospectivity from tight gas sands, gas shales to coal bed methane (CBM).

13. Some conventional sandstone wells that failed to flow gas are being re-examined in light of American tight gas successes and 56 billion cubic metres (bcm) of tight gas potential reserves have been identified in the sandstone reservoirs of the Southern North Sea.

14. Gas can be found in the pores and fractures of rocks but also bound to the matrix, by a process known as adsorption, where the gas molecules adhere to the surfaces within a shale or a coal.

15. UK Potential - While there is growing interest in European potential for shale gas, the UK potential is as yet untested. The UK shale gas industry is in its infancy, and ahead of drilling with fracture stimulation and testing, there are no reliable indicators of potential productivity. There is variable data available on the geology, depending on whether oil and gas exploration has been undertaken and the extent of existing seismic data available.

16. A DECC commissioned British Geological Survey (BGS) study has recently concluded that, with the present state of knowledge about relevant UK geology, the only means of estimating the resource is by analogy with similar shales which have been successfully exploited in America. The study has been placed on DECC’s Oil and Gas website and can be found via the following weblink:

It is also attached to this report for ease of reference.

17. If the prospective shale area of UK shale gas potential did prove to be as prolific as the analogous basins in the US, it could be of the order of 150 bcm of gas (900 million barrels of oil equivalent). To put this in context, this compares with the UK’s overall remaining conventional oil and gas reserves of some 20 billion barrels (including offshore).

18. However it is not yet clear whether there is any economic shale gas resource in the UK, as testing of our shales may show them to be less productive that those in the US. In addition, bearing in mind planning and environmental issues, it would be unrealistic to assume that the drilling density achieved in the US (thousands of wells) could be replicated in the UK. So this figure may be more representative of the theoretical top end reserves, rather than what it might be ultimately recoverable through practical development.


19. The Technology - In addition to exploiting methane from abandoned and existing coal mining operations, the opportunity also exists to exploit methane which is still locked into the reserves of coal and coal measures strata that remain unworked.  This concept is referred to as Coal Bed Methane since it involves directly drilling into unworked coal and coal measures strata to release methane held (or adsorbed)within the coal. CBM offers a method of extracting methane without detrimentally affecting the physical properties of the coal.

20. UK Potential - In the last 5 years over 40 CBM exploration and appraisal wells and 12 pilot production development wells have been drilled. IGAS and Nexen are generating electricity from CBM production, a first for the UK, at their Doe Green development, near Warrington and are currently flow testing in Staffordshire at Keele Park as part of the Potteries CBM development. In Scotland, Composite Energy drilled 18 multi-lateral wells in their Airth CBM development, which is currently suspended, but produced water and gas in 2008 and 2009.

21. The theoretical CBM resource in the UK is estimated to be 2900 billion cubic metres (bcm) using only coals with the right depth, thickness, gas content, and separation from underground mine workings. Given that the 2009 annual UK natural gas consumption was approximately 86 bcm this corresponds to about 33 years consumption. However, the part of this CBM resource that is economically viable to produce is likely to be very much smaller, possibly around 10% or less. This is largely due to perceived widespread low seam permeability, low gas content, resource density and planning constraints. More drilling and testing is necessary to refine the estimate. At the moment only modest amounts of CBM gas has been shown to be economic and realistic estimates of the size of the resource are not possible until drilling and production demonstrates more generally the economics of production in UK conditions. A BGS study on UK CBM potential is available on DECC’s Oil & Gas website at:


22. The Technology: UCG is the partial in-situ combustion of a deep underground coal seam to produce a gas for use as an energy source.  It is achieved by drilling two boreholes from the surface, one to supply oxygen and water/steam, the other to bring the product gas to the surface.  This combustible gas can be used for industrial heating, power generation or the manufacture of hydrogen, synthetic natural gas or other chemicals.  The technique has not yet been demonstrated to be commercial anywhere in the world, though there is one long-running project in Uzbekistan.

23. UK Potential: Although trials were conducted in the UK as long ago as the 50s, the technical and economic viability of underground coal gasification (UCG) has not to date been demonstrated. It is too early to judge, therefore, what contribution this fledgling technology might make to future UK energy needs. Notwithstanding, there is active interest in the sector’s potential. The licensing body, the Coal Authority, has over the last year or so granted 14 Conditional Licences for UCG (all in relation to undersea reserves). DECC is monitoring progress with interest and continues to work with other parties (the Coal Authority, Environment Agency) to help ensure clarity around the regulatory aspects of the process.


24. The Namurian Bowland Shales in the Lancashire basin (which are the source rock for the Irish Sea fields) are the most prospective, but also the Jurassic Kimmeridge and Lias shales (source rocks for the North Sea and English Channel fields) are being considered in the Weald basin in southern England. Indications of gas have often been encountered while drilling through these shales for conventional exploration of sandstone and limestone.

25. The first UK exploration well designed to evaluate shale gas potential, using state-of-the-art fracture stimulation and testing procedures, is currently drilling west of Blackpool (Cuadrilla’s Preese Hall 1 well), shown on the far right (North end) of the diagram below.

Cross section from England’s south coast to the Lancashire basin near Blackpool

26. Reserves can be estimated for conventional oil and gas prospects by applying a recovery factor to the hydrocarbons in place, but for shale gas, the reserves are dependent upon the number of wells drilled, the success of the fracture stimulation, and the use of horizontal drilling to increasing the area that can be drained around each borehole.

27. Shale gas success can only be measured after a number of wells are drilled and tested. The initial production rates and ultimate recovery of gas for each well then are averaged to estimate the reserves in the various parts of a large shale gas play.

28. An estimate of UK potential can only be made by analogy to productive areas. On an area basis, comparing the size of the prospective UK Namurian Carboniferous (Upper Bowland Shale) shale to the Barnett Shale play in Texas, the Lancashire basin could potentially yield up to 133 bcm of shale gas. If the onshore UK Jurassic shale gas play is analogous to the Antrim Shale in Michigan, the Weald/Wessex basin could potentially yield 6 bcm recoverable shale gas. There is higher risk potential in older shales, and some offshore potential too.

29. However, as noted above, it is difficult to imagine that a US model for shale gas development, with thousands of wells in each trend, can be replicated in the UK. Planning and environmental considerations are likely to limit the number of surface locations from which wells can be drilled, but there is hope that a smaller scale development with numerous horizontal wells from central sites could be economically viable. But it is too early in UK shale gas exploration to know if commercial development can be established.

30. Unlike some other countries where landowners own the oil and gas under their land, in the UK the Crown controls the right to produce hydrocarbons. DECC licenses these rights to exploit oil and gas resources; and, together with the environmental control through the planning system (by Local Authority supported by the Environmental Agency and other consultees), and safety regulation (by the Health and Safety Executive), this should result in a well ordered development of the resource. This has already been achieved with the UK’s long experience of development of its more conventional onshore oil and gas resources.

Risks of Rapid Depletion of Shale Gas Resources?

31. While there has been debate in the industry regarding the forecasting of future shale gas production profiles, it is too early to know what decline rates we might experience. We don’t yet have UK data to estimate the initial production rate, the initial rate of production decline, and the degree to which that initial decline rate flattens out over time. We have significant potential reserves – but no proved prospectivity for shale gas, and only pilot production data for CBM.


Prospects for further production in the US

32. Production of unconventional gas in the US is expected to increase with the growth in unconventional gas production being driven largely by shale gas production rising from 14% of total consumption (around 3 trillion cubic feet) in 2009 to 45% (around 12 tcf) in 2035, according to the EIA (US Energy Information Administration) chart below [1] .

U.S. Dry Gas Production (trillion cubic feet a year) by source: 1990 – 2035.

Source: US Energy Information Administration

33. This growth is expected to help put downward pressure on the US’s demand for imports. The US’s net imports peaked in 2007 at around 3.5 trillion cubic feet of gas, most of which was imported from Canada. The US’s net imports are projected to fall from 2.6 tcf in 2009 to 1.3 tcf in 2025 and 0.3 tcf in 2035. The EIA are expecting imports of gas from Canada and from LNG to fall over the next two decades.

34. The EIA has continued to revise up its expectations for shale gas production and the impacts this will have on the US market. For example in contrast to the Annual Energy Outlook 2010 reference case, the EIA now:

· Has doubled the technically recoverable unproved reserves of shale gas;

· Projects higher shale gas production;

· Projects lower US prices;

· Projects lower total U.S. net imports of LNG (due in part to less world liquefaction capacity and greater world regasification capacity, as well as increased use of LNG in markets outside North America); and

· Assumes the Alaska pipeline will not be constructed as projected due to both the projected lower US prices and higher capital costs which makes this unattractive.

It should be noted that such projections are sensitive to a number of assumptions, relating for example to the pace of technological innovation and economic growth.

35. The impact of further growth in gas production in the US on global markets will depend on a number of factors:

· The extent to which the increase in production is offset by increases in US demand for gas;

· The extent to which it exceeds, or falls below, market expectations and therefore helps push the global market into over- or under-capacity; and

· Whether the US will be able, and the extent to which it will be able to export natural gas in other markets.

Prospects for unconventional gas production in the rest of the world

Global Unconventional Natural Gas Resources in place (trillion cubic metres)





Middle East and North Africa





Sub-Sahara Africa





Former Soviet Union










Central Asia and China





OECD Pacific





South Asia





Other Asia





North America















Central and Eastern Europe





Western Europe










Source: Rogner (1996), Kawata and Fujita (2001), Holditch (2006). Taken from World

Energy Outlook 2009 table 11.3, International Energy Agency.

36. While North American production is expected to continue to increase, there are significant uncertainties over the extent, the timing and the location of production elsewhere in the world. This is due to a number of factors including:

· the limited understanding of reserves : The table above shows estimates for the unconventional gas reserves thought to be in place in various regions across the world. On these estimates, the resource could be very large. For comparison, global consumption of gas is around 3 tcm per annum [2] . However, comprehensive assessments are few and far between. And there is a lack of production experience outside the US, which leaves substantial uncertainty about how much of the resource might ultimately be producible. Nonetheless, the current IEA estimate is that around 380 tcm could be recoverable based on current data. This compares to an estimated 404 tcm of recoverable conventional reserves and 184tcm of proven gas reserves;

· prices: the price required to incentivise investment will depend on a number of factors, such as the productivity and cost of the well, access to transport infrastructure etc. The IEA has estimated recoverable unconventional resources can be produced at prices between $2.7/MBtu [3] and $9/MBtu in the US.

· environmental controls and population density: unconventional production is more land intensive than traditional methods. Either factor could restrict development, particularly in Europe which has high population density and a well developed regulatory framework;

· land ownership: US legislation differs from most, including that in Europe, in that it grants landowners rights over hydrocarbon resources rather than conferring ownership on the state. This has provided a huge incentive for landowners to agree to invasive drilling on their property. The lack of such an incentive could be particularly significant in parts of Europe with strict planning laws;

· availability of infrastructure: the US and Canada have highly developed gas grids, something that is lacking in China, India and some other potential sources of unconventional gas; and

· access to technology and expertise: the technology required to exploit unconventional resources is highly specialised and has been largely, though not entirely, confined to the US.

37. Notwithstanding the uncertainty it is clear that there is potential for additional gas to be brought to market in large volumes. Should this be the case, there could be significant impacts on global energy markets and climate change.

38. Price implications –The unexpected growth in unconventional gas production in the US has already, in conjunction with other factors, helped to depress UK and global spot wholesale gas prices over the course of 2009 by reducing the US need for LNG imports, although recently UK wholesale prices have rebounded strongly. Over the medium and long-term, the impact of new sources of unconventional gas on prices is uncertain. Increased supply of gas via increased production of unconventional is likely to reduce gas prices going forward. However, instead there might be upwards pressure on gas prices if expectations of unconventional gas being brought to market leads to under-investment in conventional gas or other energy sources. The EIA expects unconventional gas to exert downward pressure on natural gas price. Natural gas wellhead prices in AEO2011 (in 2009 dollars) only reach $6.53 per thousand cubic feet in 2035, compared with $8.06 in AEO2010 due in part to increased estimates on recoverable shale gas resources.

39. Security of supply – there is potential for security of supply to be improved due to the opportunities for consuming countries to diversity across a wider range of sources of supply.

40. Climate implications –increased unconventional production would result in lower emissions if it displaces fuels such as coal that are associated with higher emissions. However, the potential downside from reduced emissions in the short- to medium-term is that this reduces the incentive to invest in developing and deploying the low-carbon alternatives required to meet longer-term emission goals. If gas was to play a major longer-term role, this would suggest a greater need for effective CCS technology for gas plants. Tighter national emission targets and policies to support innovation and deployment of low-carbon technologies could be used to reduce these risks. With such measures, the increased use of gas could be an effective bridge to help deliver greater near-term reductions.

41. To reduce the uncertainty posed by these issues, the Department intends to closely monitor developments and will consider the need for additional research to improve our understanding of the implications for policy. In the meantime, DECC is continuing to liaise with the energy industry and academia as knowledge and experience develops.


42. The safety risks and hazards associated with drilling for shale gas should be no more onerous than those associated with drilling for any other hydrocarbons by a borehole (for instance, the worse case being a blow out leading to the release and possible ignition of gas).

43. The process of extending the borehole to the shale formations of interest, will follow those used for conventional drilling of oil and gas wells, with a number of casings of reducing diameter being run and cemented to form a conduit to surface. The principle of dual barriers to any potential flow of fluid will be maintained and equivalent safety features for the production phase of shale gas will be in place i.e. sub surface safety valves.


44. The risks to people from drilling a borehole for hydrocarbons under a production, or exploration and appraisal, license will be regulated by the Health and Safety Executive (HSE).

45. UK legislation requires the operator to assess not only the risks and hazards above ground but also those associated with the sub surface aspects of the operations. The operator must notify HSE of any proposed drilling operations which will allow a dialogue to start on the management of the risks that have been identified.

46. More generally environmental risks of shale gas development have received some media attention in the US and have even resulted in a hydrofrac drilling ban in the state of New York which flanks the successful Marcellus shale trend.  It is claimed that some incompetent operators have allowed gas to contaminate shallow aquifers, which should not be possible with proper well casing design.

47. The use of large quantities of water for fracture stimulation in areas with limited water supply and the safe disposal of the recovered fluids have also been reported as contentious in the US. Public health concerns there have resulted in a demand for greater transparency regarding the chemical composition of the fracture stimulation fluid and the US Environmental Protection Agency have recently changed their requirements. In the US, where the landowner owns the mineral rights, directly benefiting from drilling, consent to dense drilling has been allowed with reported possible negative effects on local communities.



48. The carbon intensity of natural gas from shale formations varies between various shales and depends on the extraction process and emission management. Both the greater number of bore holes required to be drilled for shale gas in relation to field gas and the process of hydraulic fracturing of the rock add to the energy and carbon footprint of the extraction process. This carbon footprint can be increased further by fugitive emissions of methane released directly to the atmosphere as a result of the fracturing process.

49. Little investigation has been undertaken into the size and variability of greenhouse gas emissions from the extraction process and even less has been conducted on the potential impact of fugitive methane emissions. Estimates of the carbon intensity of shale gas should therefore be treated with caution until peer-reviewed work is available. However, providing that fugitive emissions of methane can be managed adequately, shale gas can be expected to have a carbon intensity greater than that of natural gas from conventional fields, but significantly lower than that of coal.

January 2011

[1] NB: 1 tcf is equal to around 28.3 bcm.

[2] WEO 2010, Table 5.1, Primary natural gas demand by region and scenario (bcm), page 181.

[3] Millions of British thermal units.