Energy and Climate Change CommitteeWritten evidence submitted by the British Geological Survey (ISG 17)

Summary

Estimates for the amount of shale gas are variable both for parts of Britain and for Britain as a whole. Estimates for other parts of the world also vary. This reflects the difficulties of precise resource or reserve estimation in the early days of shale gas exploration and production.

In simple terms the resource estimate is the amount of gas in the ground (some of which might never be accessible), while the reserve estimate is a more sophisticated measure which describes the amount of gas that you might be able extract given economics and other factors. The recovery factor is a measure of the proportion of the total gas resource that can be extracted and is often expressed as a percentage. The recovery factor is a function of geological, economic, cultural, logistical and other factors. The recovery factor is likely to fluctuate, with a tendency to increase with time, particularly as experience and technology improves or public acceptance increases. US recovery factors are typically around 10% but it is too early to be sure of British recovery factors.

It is possible that prospects for shale gas are better offshore than onshore in the UK. This is because the sedimentary basins and the deep structures where gas is generated are larger offshore, for example for the gas-bearing Kimmeridge Clay and Carboniferous formations.

Question 1. First Part: What are the estimates for the amount of shale gas in place in the UK, Europe, and the rest of the world?

1.1 Introduction

Variations in potential shale gas yield as implied by figures released by DECC, oil and gas companies and other organisations have caused confusion in the media and amongst the general public. Occasionally this has resulted from reserve figures being confused with resource figures (Table 1). In simple terms the resource estimate is the amount of gas in the ground (some of which might never be accessible), while the reserve estimate is a more sophisticated measure which describes the amount of gas that you might be able extract given economics and other factors. The recovery factor is a measure of the proportion of the total gas resource that can be extracted and is often expressed as a percentage. To some extent the ability to obtain reserve or resource figures is determined by the stage of exploration and degree of production uncertainty. Gas in place (GIP) or Gas Initially In Place (GIIP) figures are normally derived for an exploration licence area, perhaps even before drilling takes place, for the benefit of shareholders and investors. These values often find their way into the media. When substantive data from drilling becomes available, more reliable figures for reserves and resources can be calculated. But if few wells are drilled there is a risk that the data they reveal are considered representative of large undrilled areas. A third measure of the amount of gas is the concept of “technically recoverable resources” (Table 1) which the agency Advanced Resources (2011) has used to determine how much gas is likely to be extracted. Various recovery factors have been used and Advanced Resources (2011) lists a few of the considerations made in selecting these factors. Technically or economically recovered resources will fluctuate in time according to technological advances and prices.

Table 1

TERMS USED IN SHALE GAS ESTIMATION

Terms for resources and reserves	Term	Acronym	Summary	Excludes
Resource “How much gas is in the ground”	Original gas in place	OGIP	Total volume of gas
	Gas (initially) in place	GIIP/GIP	Total volume of gas
	Ultimately recoverable		Total recoverable volume	Gas not expected to be recovered
	Technically recoverable		Limited by technology	Ditto, as well as gas not recoverable with current technology
	Economically recoverable		Limited by economics	Ditto, as well as gas not economic to recover
Reserve “How much gas could be extracted”	Reserves		Total producible gas	Ditto
	Proved reserves	1P	Probability of reserves (proven)	Probable and possible reserves
	Median figure of reserves	2P	Proven and probable	Possible reserves
	High figure of reserves	3P	Proved, probable and possible

Note: In the US, technically and economically recoverable resources are known as “contingent resources”, contingent on for example a high gas price.

1.2 United Kingdom estimates

1.2.1 BGS estimates for DECC in 2010

(see DECC. 2010. http://og.decc.gov.uk/assets/og/bo/onshore-paper/uk-onshore-shalegas.pdf)

BGS used a comparison method to calculate potential shale gas yield in different parts of Britain. For example by comparing the shale gas production per unit area of land in the US Carboniferous Barnett Shale of the Fort Worth Basin, Texas, a figure of 4.7 trillion cubic feet (tcf—equal to 132 BCM) was suggested as an approximate reserve figure for the Upper Bowland Shale of the Carboniferous Pennine Basin (DECC 2010). Similar methods were applied to southern England basins and the Cambrian shales of central England but not Wales, Scotland or Northern Ireland. The approximate reserve figure for these shales was estimated at 5.3 tcf (150 BCM). No UK drilling had taken place at the time of this estimate, and so the BGS figures were necessarily defined as tentative. Unfortunately commentators have subsequently quoted the estimates without reference to their tentative nature.

The other widely publicised estimate for Britain’s shale gas resource is that of Advanced Resources (2011) which listed 97 tcf GIP and 20 tcf recoverable resources for the UK (using a relatively low 21% recovery factor). We are not aware of the precise method used by Advanced Resources (2011) but we assume that the lower recovery factor (in relation to other countries), was probably derived from an estimate of the influence of the UK’s high population density which would restrict exploitation.

1.2.2 Resource estimates for parts of the UK

We presume the following released figures represent Gas in Place (GIP). In most cases calculation methods used are not revealed on company websites, where figures are displayed. Understandably websites are the preferred means for informing investors and shareholders of the values of potential assets, and therefore do not attempt to give the detailed scientific derivation of the GIP figures. Note that the estimates below do not cover all of the prospective shales identified previously (see Smith et al, 2011; DECC 2010), because these areas have not been explored and licences have not been awarded.

1.2.2.1 Cuadrilla’s Lancashire licence

The UK shale gas company Cuadrilla drilled two wells in 2010–11 (Preese Hall and Grange Hill) from which (we presume) the company derived gas content values for shale and figures for the thickness of shales. We assume that they extrapolated these values over their 1200 square kilometres licence area. The resultant figure for their licence area was 200 tcf GIP (Cuadrilla 2011).

1.2.2.2 IGas licences in NW England

Before drilling in IGas acreage in the North West of England the company firstly suggested shale GIIP of c.800mmboe. The company IGas recently drilled the “Ince Marshes-1” well and changed this initial estimate to c.1,600mmboe (millions barrels of oil equivalent) (IGas 2012). The latter figure is equivalent to 9.23 tcf. The exact area of NW England that this figure applies to is not known, as this company has offshore licences also. This reason for the revision of GIIP figure relates to pre-drilling calculations and an upward revision with data from the above well (relevant also to Question 2).

1.2.2.3 Eden Energy/UK Methane

Eden Energy reported the following figures for Namurian age shales for their 7 licences in South Wales (Eden 2012): “Volume of Gas Initially in Place (GIIP)—34.198 tcf and Recoverable Volume—12.799 tcf of gas”. It is not known what data was used to produce these figures, but the expected percentage recovery (37%) is higher than predicted for all US shales.

1.2.2.4 Dart Energy

Dart Energy took over Composite Energy in 2011, which had several licences in Scotland (PEDL 133) and England (Cheshire Basin and Gainsborough Trough), previously targeted on coalbed methane. Evaluations of shale gas provided figures of Original Gas in Place (OGIP) of 65.56 tcf, including 0.7 tcf in PEDL 133. An OGIP of 12 tcf is also recorded on their website and it is not clear whether these figures might apply to European licences also (Dart Energy 2012). No new well data was available on these licences.

1.3 Europe

Technically recoverable resources for the whole of Europe were calculated at 2587 tcf GIP and 624 tcf recoverable (Advanced Resources 2011; with a 24% recovery factor).

1.3.1 Poland

Poland has been assessed as possessing 792 tcf GIP and 187 tcf recoverable (Advanced Resources 2011; 24% recovery factor), but this was revised down by the Polish Geological Institute (PGI 2012) to 346–768 billion cubic metres (BCM, 12.2–27.1 tcf). PGI (2012) also admitted that not all the relevant data were available on Polish shales and that figures derived from comparison with US shales were used.

1.3.2 Germany

In Germany the Federal Institute for Geosciences and Natural Resources (BGR) reported that between 0.7 trillion and 2.3 trillion cubic metres of gas (24.7–81 tcf) could be technically extracted across the whole country. This represents a 10% recovery factor achievable from the 6.8 -22.6 trillion cubic metres of shale gas resources (240–798 tcf). Advanced Resources (2011) previously estimated 33 tcf GIP and 8 tcf technically recoverable (24% recovery factor) for Germany.

1.3.3 Austria

In Austria oil company OMV has suggested a potential recoverable shale gas resource of 15 tcf in the Vienna Basin, from an in-place resource of 200–300 tcf. Their recovery factor is about 6%.

1.3.4 Netherlands

In the Netherlands, TNO’s (the Dutch national geological survey) estimate for producible gas in place in high potential areas is 198 tcf from an estimated gas in place resource of 3,950 tcf. Their recovery factor is about 5%.

1.4 Outside Europe and global estimates

In the first assessment Rogner (1997) estimated total global shale gas at 16,112 tcf GIP including the Middle East and former Soviet Union. Advanced Resources for the US Department of Energy (2011) made estimates for the majority of the world’s shale gas basins but excluded Russia and the Middle East because they assumed that their conventional reserves would limit their need for unconventional production in the short term. Advanced Resources (2011) found a cumulative total for 33 countries of 25300 tcf GIP with 6,622 tcf recoverable (26% recovery factor, Advanced Resources 2011).

Argentina is estimated to have 2732 tcf GIP and recoverable resources of 774 tcf (Advanced Resources 2011, 28% recovery factor). Chevron is drilling, and YPF recently stated it has made a second discovery there.

China estimated (in 2012) that its reserves were 25.08 trillion cubic metres (tcm = 886 tcf) from resources of 134.42 tcm (= 4747 tcf; Bloomberg, 2012). China’s exploration of shale gas is still at an early stage, and the 12th Five-Year Plan period (2011–2015), targets an output of 6.5 billion cubic metres per year (0.229 tcf). The recovery factor applied is 18.6%. Advanced Resources (2011) estimated 5101 tcf GIP and recoverable resources at 1275 tcf (25% recovery factor).

South Africa, which recently lifted its ban on hydraulic fracturing, has 1834 tcf GIP and reserves of 485 tcf (Advanced Resources 2011, recovery factor 26%); or 450 tcf (report for Shell, 2012, probably reserves).

Question 1. Second Part: What proportion is recoverable?

The recovery factor is a function of geological, economic, cultural, logistical and other factors associated with obtaining gas from shales. The recovery factor is likely to fluctuate, with a tendency to increase with time, particularly as experience and technology improves or public acceptance increases. It is worth noting that the USA has a long history of onshore conventional hydrocarbon exploration and production, and relatively high levels of public acceptance (due in part to landowner benefits). UK landowners do not directly benefit from onshore oil and gas and the UK public in general is less familiar with energy from this source. Often after initial hostility in the exploration phase, onshore production becomes acceptable as part of the landscape. At the Wytch Farm conventional oilfield in Dorset, for example, underground oil deposits have been accessed which extend under an Area of Outstanding Natural Beauty and sensitive wildlife reserves in Poole Harbour.

Both resource (Cuadrilla 200 tcf) and approximate reserve (DECC 4.7 tcf) figures for the Pennine Basin (see above) may turn out to be correct. But final figures of this order would suggest a recovery factor for the Upper Bowland Shale of 2.35%. US recovery factors are typically nearer 10% and higher. In the US, where horizontal drilling and hydraulic fracturing has been established for about a decade, the ultimate productivity (in other words the absolute yield of the shale) is not known (INTEK, 2011). In the USA 862 tcf of technically recoverable resources was calculated, including 35 tcf of proved reserves (INTEK, 2011). Improvements in completion and drilling will, no doubt, lead to higher recovery factors.

Question 2. Why are the estimates for shale gas so changeable (different)?

Before UK drilling results were available, figures based on comparison with US shales, where production already existed, were provided for DECC by BGS (DECC, 2010). These were approximate reserve figures, based on US shales in production. GIP or GIIP figures provided by companies during exploration phases in the UK were essentially resource figures. As discussed in Question 1 and Table 1, reserves relate to what could be produced given economic conditions whereas resources are the total amount of gas present.

US shales have very variable characteristics, and it is likely that British shales will be similarly variable. Prior to targeted drilling this variation may not be known in detail. Variations in permeability and gas content and type are likely to occur within or between basins but need to be assessed by direct measurement from inside wells and from cores of rock extracted from the shale. Even when drilling data are available, wells do not necessarily drill through the full section of prospective shales, which may vary in thickness within and between licences. Compared to conventional hydrocarbons which are found in discrete, mappable structures and discovered by a few wells, unconventional hydrocarbons extend over larger areas but may be limited by changes in characteristics that cannot be quantified by a few wells.

What this means is that it is likely that estimates for reserves and resources will likely change for many years to come.

Factors other than geology are also important: the economics of gas has been transformed and the gas price lowered in the USA, by rapid discovery success, reducing the profitability of some marginal shale prospects. This might affect how much of a shale basin is economically prospective.

Question 3. What are the prospects for offshore shale gas in the UK continental shelf?

It is possible that prospects for shale gas are better offshore than onshore in the UK. This is because the sedimentary basins and the deep structures where gas is generated are larger offshore, for example for the gas-bearing Kimmeridge Clay and Carboniferous formations. The Pennine Basin which contains shale gas-bearing Carboniferous rocks extends westwards under the east Irish Sea towards the Dublin Basin in Ireland (Figures 1 and 2). Similarly it extends eastwards beneath the Southern North Sea towards the Netherlands.

The BGS is not aware of any offshore assessment for shale gas. We believe that companies are already considering the option of shallow coal-bed methane (gas from coal seams) offshore in the UK, but only in a few licence areas. These companies may be unwilling to share their experience at this relatively early exploration stage. Advanced Resources (2011) specifically excluded offshore areas and those parts of basins which extend offshore from their global study. The US has no need to look offshore because of the plentiful production onshore. It is likely that the offshore option has been ignored because the successful US shale gas exploration model does not include the offshore and because offshore costs are considered to be higher. Even if offshore costs can be reduced by complementary drilling from existing offshore (conventional hydrocarbon) facilities or drilling deviated wells from onshore, there are a number of other logistical and operational hurdles to overcome. These include different onshore and offshore licensing regimes and issues relating to the use of seawater as hydraulic fracturing fluid. On the other hand, perceived environmental problems and land access problems will likely be less offshore compared to onshore, for example in Lancashire and Sussex.

If the offshore is economically prospective for shale we anticipate exploration in areas offshore from the Weald Basin (Kent and Sussex) and the Wessex Basin (Isle of Wight and Dorset). Other areas include the Central and Northern North Sea along the median line and west of Shetland, where Upper Jurassic source rocks are present. Carboniferous strata are present offshore in the Solway Basin (offshore Carlisle), offshore from the Midland Valley of Scotland, and in the southern North Sea and east Irish Sea Basin. BGS is considering a project to analyse the feasibility of offshore shale gas in the east Irish Sea Basin.

The east Irish Sea Basin lies off the NW coast of England between the north Wales coast and the Isle of Man (Figure 1).

Figure 1 Red indicates the outcrop of the Carboniferous (Namurian) shale onshore. The pink areas indicate Namurian shale outcrops at the seabed. Although Namurian shale outcrops only in small areas at the seabed, it is present below much of the east Irish Sea under the seabed. The green and blue rectangles are licence blocks.

A number of conventional fields (eg the Morecambe Gas Field) were discovered in the centre of the basin and have supplied gas since 1985 and are expected to be exhausted in about 40 years. More recently the company Hamilton discovered a line of fields off the North Wales coast, with production beginning in 1996 (Figure 2).

Figure 2 Morecambe and Hamilton gasfields in the East Irish Sea. Their extents indicate the absolute minimum prospective area of Namurian shale in the East Irish Sea Basin because the gas they contain is probably from shale located directly below. The green and blue rectangles are licence blocks.

The source rock for these hydrocarbons is likely to be Carboniferous shale because there are relatively small areas of Coal Measures at depth (the source rock in the southern North Sea) in the basin. The extents of the gasfields indicate the absolute minimum prospective area of Namurian shale in the East Irish Sea Basin because the gas they contain is probably from shale located directly below. The shale prospectivity of the east Irish Sea Basin, which has an area in excess of 6000 km² is not known because the geology is insufficiently mapped, but using Cuadrilla’s figures on their adjacent onshore acreage (200 tcf/1200=0.17 tcf/km²) a tentative resource of 1000 tcf is suggested.

Seawater hydraulic fracturing may be possible offshore. Although there is existing infrastructure offshore in the form of drilling platforms it is probably too early to expect these to be used, but deviated drilling from the onshore may be possible. BGS is planning an investigation of the feasibility of offshore shale gas accessed from the coast by deviated drilling from the Lancashire coast.

References

Advanced Resources International, Inc. 2011. World Shale Gas Resources: An initial assessment of 14 regions outside the United States. For US Energy Information Administration at the Department of Energy.

Bloomberg 2012. http://www.bloomberg.com/news/2012–03–01/china-estimates-exploitable-shale-gas-reserves-at-25–08-tcm-1-.html

Cuadrilla 2011.http://www.cuadrillaresources.com/what-we-do/about-natural-gas/

Dart Energy 2012. http://www.dartenergy.com.au/page/Worldwide/United_Kingdom/

DECC. 2010. http://og.decc.gov.uk/assets/og/bo/onshore-paper/uk-onshore-shalegas.pdf

Eden 2012. http://www.edenenergy.com.au/wales.html

IGas. 2012. http://www.igasplc.com/uploads/120330igasincontextfinalv32[1].pdf

INTEK. 2011. Review of emerging resources: US shale gas and shale oil resources. For US Energy Information Administration at the Department of Energy. 105pp.

Polish Geological Institute (PGI). 2012. The Assessment of Shale Gas and Shale Oil Resources of the Lower Paleozoic Baltic-Podlasie-Lublin Basin in Poland.

Rogner, H-H 1997. An Assessment of World Hydrocarbon Resources. Annu. Rev. Energy Environ. 22:217–62.

Shell 2012. http://www.bdlive.co.za/business/energy/2012/09/07/cabinet-lifts-moratorium-on-shale-gas-fracking-in-karoo

Smith, N, Turner, P & Williams, G 2011. UK data and analysis for shale gas prospectivity. In Vining, B A & Pickering, S C (Eds) Petroleum Geology: from mature basins to new frontiers—Proceedings of the 7th Petroleum Geology Conference, Geological Society, London, 1087–1098.

October 2012

Questions not Answered or Answered Fully at the Committee Meeting 271–12–012

Question not appearing in transcript:

Fracking using gas? (question from Mr Lilley)

Answer:

Yes it is possible. Fracturing in the US Appalachian shales has evolved from nitroglycerine or judamite up to the early 1970s, water fracturing (aka light sand); then to nitrogen-based foam fracturing (lower water content) and to nitrogen gas fracturing (eg. in Tennessee). Liquefied gelled petroleum is also an alternative to massive hydraulic fractures and slickwater fractures. Liquefied carbon dioxide might also be effective because it could combine sequestration of climate-changing CO2 with displacement of valuable oil in shales.

Question 52 Albert Owen: Are you happy that the people who work in the North Sea now and the companies could quite easily switch over to shale from the conventional gas that they have been experts in for many decades?

To add to ‘No’

Many of these people are still needed for work there or on conventional hydrocarbons elsewhere. The onshore has been alien territory to quite a few companies, particularly the larger ones and they also were slow to appreciate the breakthrough made in shale gas in the US, so I would say the great knowledge of shale gas has not been vested with the conventional large company explorers. They have now bought in or taken over companies with expertise and this may continue if success is forthcoming in Europe. Hydraulic fracturing whilst undertaken offshore in conventional reservoirs has not perhaps needed to be fine tuned to different and difficult formations and the geochemistry of source rocks had become a moribund discipline as the North Sea matured and everyone knew the source rocks were Kimmeridge Clay (for the oil) and coals in the Coal Measures (for the gas). Other shales were just the cap rocks to the fields. So I don’t think the expertise is necessarily appropriate to move.