Shale Gas - Energy and Climate Change Committee Contents

5  Environmental Risks of Shale Gas

DECC's 14th Onshore Oil and Gas Licensing Round

96.  In July 2010 DECC published a Strategic Environmental Assessment (SEA) for the draft plans of their forthcoming 14th round of onshore oil and gas licensing.[200] Tony Grayling—Head of Climate Change and Sustainable Development at the Environment Agency—told us that, as at March 2011, the final version of DECC's SEA has not yet been published.[201] SEA's are required under European Directive 2001/42/EC and implemented through the UK's Environmental Assessment of Plans and Programmes Regulations 2004.[202] Individual projects can also require an Environmental Impact Assessment (EIA) under the 1985 EIA Directive.[203] DECC's SEA on onshore oil and gas licensing states that:

Besides the use of larger quantities of water than other methods of extraction, the production and environmental management methods required to provide suitable environmental protection with regard to this activity are well established (i.e. are techniques already used to stimulate production in conventional gas development).[204]

97.  As at April 2011, DECC was still considering responses to a consultation on this SEA.[205] They intended to issue a Government response as soon as was "practical", and would then be in a position to "invite applications" for licences.205 The licensing round would cover:

  • onshore oil and gas exploration and production (which included shale gas);
  • virgin coal-bed methane exploration and production; and
  • natural gas storage in hydrocarbon reservoirs.200

The SEA of DECC's draft plans for the 14th onshore licensing round assessed the potential impacts of onshore licences on: geology and soils; landscape; water environment; air quality; climatic factors (long term weather patterns); and health.[206] We were told that DECC had sufficient expertise to perform a thorough SEA for the 14th Onshore Round. DECC's Director of Oil and Gas Licensing, Exploration and Development did not consider that "there is any particular technical or environmental impact of shale gas that we are not capable of understanding".[207] The Minister added that DECC is "one organisation among a number that are involved in the environmental and safety monitoring of these issues [...] the environment agencies involve the HSE and the local planning authority, whereas with the coal-bed methane it is the Coal Authority".[208]

Environmental Permitting

98.  The Environment Agency's principal aims are to "protect and improve the environment, and to promote sustainable development.[209] The Environment Agency (EA) is responsible for issuing the environmental permits currently necessary to undertake shale gas exploration and production. Professor Anderson of the Tyndall Centre told us: "I trust the relevant authorities and scientists and the Environment Agency to come up with the appropriate legislative framework, but they need to be given the time to think through these sets of issues, to look at what happened in the US, to learn from their experience there".[210] The EA believed that "there is a robust regulatory regime in place to ensure any environmental impacts from unconventional gas [...] are minimised" and that "the regulatory regime in the UK will continue to be sufficiently robust as it is to manage and minimise the environmental risks from [unconventional gas] […] we will, of course, keep that under review".[211] WWF on the other hand told us that "A spokesperson from the Environment Agency told WWF that 'the Environment Agency is currently developing policy at the national level on shale gas permitting' and that 'fracking' will probably not be able to go ahead without a permit".[212]

99.  The EA addressed environmental concerns on a site-by-site basis as they "assess the need for, and respond to, applications for environmental permits […] we apply a proportionate risk-based approach to preventing pollution and protecting the environment".[213] Local EA staff have assessed the potential impact of Cuadrilla's operations (in the north west of England) on the water environment and have "decided that, at present, it does not require permitting under the EPR [Environmental Permitting Regulations 2010]".[214] A permit under the EPR was required "where fluids containing pollutants [...] are injected into rock formations that contain groundwater" and a permit may also be needed if the activity posed a risk of "mobilising natural substances that could then cause pollution".[215] The permit would specify limits on the activity and any requirements for monitoring. If it was decided that "the activity cannot affect groundwater" a permit would not be necessary.[216] It would be the EA's decision as to whether groundwater was present or not.

100.  The Environment Agency noted that if shale gas took off on large scale, and in the "majority of cases we don't deem that an environmental permit is required", it would mean that the Environment Agency "will not be getting any […] income that will cover the costs of […] site-by-site assessments".[217] Tony Grayling added that in such a scenario, the Environment Agency would have to have a discussion with DEFRA and DECC on "having a proper assessment of what our resource needs will be going forward".[218]

101.  We recommend that the Government consider the future funding for the Environment Agency should the shale gas industry expand in the UK. As the situation stands, shale gas operators are unlikely to explore in areas where the Environment Agency will determine there is a risk to groundwater, so an Environmental Permit will not be necessary. However, the Environment Agency will still be expected to monitor for contamination and pollution, without being able to recover costs through the issuance of a permit.

Hydraulic Fracturing

102.  The successful injection of hydraulic fracturing fluid to release shale gas should result in natural gas production without the contamination of underground sources of drinking water, but this relies upon the integrity of the well and the correct fluid design. However, as Professor Richard Selley of Imperial College London told us, "there are different types of shale gas formations that respond differently to different type of fracturing".[219] The fluid design is determined by the often-unique geology of the particular shale gas formation.

103.  There are many naturally occurring substances in the shale formation, and the process of hydraulic fracturing can affect their "mobility", which means their ability to move around and potentially enter a water source. These substances can include: naturally occurring "formation" fluid (such as brine) found in the shale rock; gases, such as the target natural gas (mostly methane), carbon dioxide, hydrogen sulphide, nitrogen and helium; trace elements of substances such as mercury, arsenic and lead; naturally occurring radioactive material (radium, thorium, uranium); and "volatile organic compounds" (VOCs) that easily vaporise into the air, such as benzene.[220]

104.  Hydraulic fracturing can be repeated as necessary to maintain the flow of gas to the well, but there are concerns about the cumulative effects of such repeated fracturing. For example, the effects of repeated high-pressures on the well components, such as the casing and the cement.[221] Nigel Smith, of the British Geological Survey, told us "they are going to fracture probably every three or four years […] They will do their best to keep it going as long as they can".[222]

Possible Contamination of Drinking Water

105.  We heard during our visit to the US, that the US Environmental Protection Agency (EPA) believed that—from evidence it had gathered so far—that "if hydraulic fractures combine with pre-existing faults of fractures that lead to [drinking water] aquifers or directly extend into aquifers, injection could lead to the contamination of drinking water supplies by fracturing fluid, natural gas, and/or natural occurring substances".[223]

106.  During the fracturing process, some of the hydraulic fracturing fluid may flow through the artificially created fractures to other areas within the shale gas formation, in a phenomenon known as "fluid leakoff". Fluid leakoff during hydraulic fracturing "can exceed 70 percent of the injected volume if not controlled properly", which could result in fluid migrating into drinking water aquifers.[224] In comparison, coal-bed methane formations are mostly shallow, so where hydraulic fracturing is used there is a risk that it could be happening in—or very near to—shallow drinking water supplies.[225]

107.  The US EPA has stated that proper well construction is "essential for isolating the production zone from USDWs [underground sources of drinking water], and includes drilling a hole, installing a steel pipe [casing] and cementing the pipe in place".[226] There is therefore a risk of groundwater pollution from improperly constructed wells.[227]

108.  DECC thas stated that while there might have been cases of well integrity failure on some US shale wells, they "do not believe that such a situation would occur in the UK".[228] They added that the operator was obliged to ensure that the well design is "safe and fit for purpose", and that this obligation was "checked very carefully by the Health and Safety Executive".

109.  Professor Selley of Imperial College London observed that the process of artificial fracturing was as "old as Moses, [it] has been used in the petroleum industry for decades".[229] In contrast, the Tyndall Centre referred to "the 'novel' risks associated with hydraulic fracturing", namely contamination of water supplies by the hydraulic fracturing fluid or methane—the latter was associated with (in-)famous images of people in the US setting their tap-water alight. [230]

110.  The moratorium on hydraulic fracturing in New York State was a result of concerns surrounding environmental risks, in particular the potential contamination of water supplies. DECC believed that cases of contamination in the US have been the result of "some incompetent operators [who] have allowed gas to contaminate shallow [water] aquifers, which should not be possible with proper well casing design".[231] The Geological Society has stated that there "is no recorded evidence of this [contamination], and [they have] good reason to think it untrue, since the process takes place at depths of many hundreds of metres below the [water] aquifer".[232] With regard to the issues of fugitive methane emissions during shale gas exploration and production, the Geological Society believed that this "is very unlikely to be due to hydraulic fracturing, since this occurs at depths of several thousand metres beneath the surface".[233]

111.  During our visit to the US, we heard little concern from environmental groups, state or federal regulators, or academics on the environmental impacts of the hydraulic fracturing process itself. Any instances of methane contamination of groundwater were either blamed on poor well construction (an issue that applies to conventional as well as unconventional hydrocarbons) or were thought to pre-date any hydrofracing activity.

112.  In Washington DC we met the US Department of Energy's (DoE)Deputy Assistant Secretary for Oil and Gas, Christopher Smith, who presented us with their 2009 publication "Modern Shale Gas Development in the United States: A Primer". This report discussed naturally occurring radioactive material (NORM), which some soils and geologic formations contain in low levels. The report described "when NORM is brought to the surface during shale gas drilling and production operations, it remains in the rock pieces of the drill cuttings, remains in solution with produced water [which flows out of the formation during production], or, under certain conditions, precipitates out in scales or sludges".[234] However, the DoE concluded that because the public did not come into contact with shale gas field equipment for extended periods of time "there is very little [radiation] exposure risk from gas field NORM". [235]

113.  We conclude that hydraulic fracturing itself does not pose a direct risk to water aquifers, provided that the well-casing is intact before this commences. Rather, any risks that do arise are related to the integrity of the well, and are no different to issues encountered when exploring for hydrocarbons in conventional geological formations. We recommend that the Health and Safety Executive test the integrity of wells before allowing the licensing of drilling activity.

114.  We recommend that the Environment Agency should insist that all companies involved in hydraulic fracturing should declare the type, concentration and volume of all chemicals they are using.

115.  We recommend that before the Environment Agency permits any chemicals to be used in hydraulic fracturing fluid, they must ensure that they have the capabilities to monitor for, and potentially detect, these chemicals in local water supplies.

Volume of Water Required

116.  The Tyndall Centre estimated that "a six well [shale gas exploration] pad takes between 54-174 million litres of water" which is "equivalent to 22-69 Olympic size swimming pools", or between 9-29 million litres per well.[236] In comparison, according to the American Petroleum Institute (API) the water usage in shale gas plays ranges in the US from 7.5-15 million litres of water.[237] Figure 6 gives flow chart of water use during hydraulic fracturing, and at each stage identifies the potential risks to drinking water as seen by the US Environmental Protection Agency.

Figure 6—Water Use in Hydraulic Fracturing Operations

Source: US EPA, Draft to Study the Potential Impacts of Hydraulic Fracturing on Drinking Water, February 2011, p 14

117.  During peak shale gas production in the Barnett Shale, Texas, the total amount of water required represented 1.7% of the estimated total freshwater demanded by all users (domestic and commercial) within the Barnett Shale area.[238] Whether the withdrawal of this much water from local surface (reservoirs or rivers) or ground water sources (aquifers) has a significant impact will vary depending on the location and the time of year. It is possible to offset the large water requirements for hydraulic fracturing by recycling the fluid that flows back up from the well (known as "flowback" fluid).[239] It is estimated that between 10-40% of the original fluid injected is recoverable.[240] By adding additional chemicals and more freshwater this can be reused. However, high levels of total dissolved solids (TDS) and other dissolved constituents can present challenges to recycling.

118.  The removal of such large volumes of water could put stress on drinking water supplies, especially as it is not possible to recycle the majority of it.239 The Campaign to Protect Rural England (CPRE) believed that "fostering a water intensive industry [in the UK] which is likely to increase demand for a scarce resource is highly questionable".[241] Professor Anderson of the Tyndall Centre explained that "even in wet parts of the world, which is where some of these shales are, there are often issues of water supply throughout the year, and this [hydraulic fracturing] will be another pressure on that water supply system".[242]

119.  In their 2006 report "Underground, Under Threat - The State of Ground Water in England and Wales" the Environment Agency stated that in the north west of England—where Cuadrilla are exploring for shale gas—11% of water is supplied by groundwater (which represents 5% of all the groundwater abstracted in the UK).[243] Data for the rest of the UK is shown in Figure 7.

120.  During its shale gas exploration in the US, Shell stated that it had "reduced its use of freshwater by about 50% by reusing treated fracturing water".[244] WWF believed that it was "possible to recycle wastewater and should shale gas production take place in the UK this should be mandatory".[245] Asked whether the Environment Agency should be regulating the amount of water that is recycled, Mr Marsland, Groundwater Manager for the Environment Agency, told us that they "would certainly encourage them to recycle […] [but] [there could be complexities in recycling in terms of the [increasing] concentration of pollutants".[246]

121.  However, the potential abstraction of such large volumes of water needed for fracking, and the subsequent lowering of the water table, could also affect water quality by: exposing naturally occurring minerals in the aquifer to an oxygen-rich environment—the resulting chemical changes could alter their solubility, causing chemical contamination of the water; stimulating bacterial growth, which could cause taste and odour problems; causing an upwelling of lower quality water from deeper within an aquifer.239 The US EPA believed that "large volume water withdrawals from ground water can also lead to subsidence and/or destabilization of the geology".[247] Additionally, large water abstractions may lead to an increase in the concentration of contaminants in surface water resources.[248]

Figure 7—Chart showing percentage of total groundwater abstracted in 2003, and a map showing percentage of water in each region supplied by groundwater

Source: Environment Agency, "Underground, Under Threat—The State of Ground Water in England and Wales", 2006, p 11

122.  Mark Miller estimated that Cuadrilla would probably use "about 1,000 cubic metres total for our drilling process and probably another 12,000 [cubic] metres for the fracturing process […] 13,000 cubic metres [in total] […] about five Olympic swimming pools".[249] Mr Miller added that in a year they might use 20 Olympic swimming pools-worth of water in their future operations.[250] Cuadrilla bought their water from the mains (through United Utilities) and "as often as we can, we will", Mr Miller told us.[251] He also said that United Utilities "know their availability of water and they [would] curtail us if they feel we would be taking too much […] we are just an industrial customer like anybody else".[252]

123.  Asked about the volume of water required for hydraulic fracturing operations, Jonathan Craig of the Geological Society told us that "only 30%, of the fractures that we make are contributing gas to the well. We need to either use less fluid, so that we only frac the 30% that we need to frac, or get much more efficient about the fracing so that we create more fractures that are contributing".[253] Nick Grealy made the comment to us that while "3 million gallons sounds alarming […] four million gallons is the irrigation for a golf course for 28 days".[254] Jonathan Craig added that "a typical shale gas field in the US might have 850 wells in it […] this is different from conventional exploration […] it is basically 100,000 barrels of water per well".[255]

124.  Tony Grayling of the Environment Agency told us that "in terms of large scale usage of water from the environment, an abstraction licence is required from the Environment Agency and we wouldn't license unsustainable abstraction".[256] The Environment Agency told us that the water required for hydraulic fracturing is considered in the same way as any other industrial process.[257] Mr Grayling added, "I don't think you can single out this activity among all the other water-use activities for special treatment".[258]

125.  We conclude that there is only a small risk that the large volumes of water required for hydraulic fracturing will place undue stress on the water supply, though this could be more significant at times of drought in low rainfall areas. We recommend that the Environment Agency should have the power to prescribe the minimum amount of water recycling that takes place during unconventional gas exploration, on a site-by-site basis that takes into account the water stresses particular to the region.

Waste Water Treatment and Disposal

126.  After the high-pressure injection of the hydraulic fracturing fluid has induced fractures in the shale formation, the pressure is decreased and the direction of fluid flow is reversed, "allowing fracturing fluid and naturally occurring substances to flow out of the wellbore to the surface [over a period of several weeks for shale formations, and potentially longer for coal-bed methane]; this mixture is called 'flowback'".[259]

127.  The toxicity of these substances varies considerably, with the naturally occurring metals exerting various forms of toxicity at low concentrations (even though they are essential nutrients).[260] Flowback and produced water from hydraulic fracturing operations are held in storage tanks and waste impoundment pits prior to or during treatment, recycling and disposal.

128.  Flowback liquid (from the fracturing process) and "produced" water (which comes from the shale formation during gas production) can be managed through disposal or treatment, which may then be followed by discharge to surface water bodies or reuse.[261] The primary options for dealing with this wastewater are:

  • inject underground through a disposal well (onsite of offsite);
  • discharge to a nearby surface water body;
  • transport to a municipal wastewater treatment plant;
  • transport to a commercial industrial wastewater treatment facility; or
  • reuse for a future fracturing procedure either with or without treatment.[262]

129.  Tony Marsland of the Environment Agency told us that the wastewater from Cuadrilla's operations near Blackpool would be "going to a specialist waste treatment plant in East Yorkshire—a specialist water and gas plant—for specific treatment and disposal".[263] Asked whether the Environment Agency was confident that current waste treatment plants were capable of detecting and dealing with the chemicals and contaminants found in flowback water, he added that it "is up to the waste treatment facility to determine whether it has the capacity and can treat that particular waste stream […] they have to make sure they can meet their own [obligations under their] permits before they can discharge [it]".[264]

130.  Chair of Blackpool Green Party, Philip Mitchell (who submitted evidence on his own behalf) highlighted the risk of "inadequate numbers of treatment centres to process this waste [and] the risk to locally produced food [from contamination]".[265] SSE believed that while there were hazards connected with the management of the large amounts of chemically contaminated waste water used in the hydraulic fracturing process, "closed loop water systems are being developed by industry to reduce water" required.[266] Regarding the availability of waste treatment centres should shale gas exploration expand in the UK, Mr Miller told us that the existing waste facilities, have really been established to handle some of the fluids coming from offshore [oil and gas exploration], and that is a pretty big industry […] even if shale gas got pretty active […] [it wouldn't] exceed the capacity that was set up to service the North Sea.[267] Dennis Carlton of Cuadrilla added that that shale gas exploration companies could always "drill a disposal well" if expansion of the industry became inhibited by the capacity of waste treatment facilities.[268]

131.  Regarding the disposal of flowback and produced water from hydraulic fracturing operations, the Environment Agency's Head of Groundwater, Tony Marsland, told us: "We certainly don't need any more regulation. The Environmental Permitting Regulations would cope with this".[269] As to the environmental impacts of shale gas production, particularly in terms of the management and disposal of the large quantities of water involved, the Minister of State for Energy, Charles Hendry MP, told us that, "the Environment Agency should lead on these matters, as they have an absolute responsibility for environmental protection".[270]

132.  We recommend that DECC and DEFRA ensure that the Environment Agency monitors randomly the flowback and produced water from unconventional gas operations for potentially hazardous material that has been released from the shale formation. In order to maintain public confidence in the regulators—and in the shale gas industry—we recommend that both water and air be checked for contamination both before and during shale gas operations.

133.  We encourage the Government to insist that as the shale gas industry develops, companies are required to work together in order to optimize the use of waste water treatment plants, to minimise both the number of plants and the distance waste water has to be transported.

Air Pollution

134.  DECC's Strategic Environmental Assessment for their forthcoming 14th Onshore Oil and Gas Licensing Round states that the:

existing [air quality] regulatory controls on transport, power generation and gas flaring are regarded as adequate […] EIA [Environmental Impact Assessment] to support planning and other consents would be expected to give due consideration to the potential implications of the planned activity on attainment of local and regional air quality plans.[271]

135.  During our visit to the US, the Department of Energy provided us with a report that described how "some air emissions commonly occur during [shale gas] exploration and production activities [...] NOx, volatile organic compounds [VOCs, such as benzene], particulate matter, SO2, and methane".[272] NOx gases are responsible for the brown haze around areas of industry, and contribute to: acid rain; the destruction of lake ecosystems; and the formation of ozone smog, which has been linked to illness and death. In Texas, the US Environmental Defense Fund (an environmental organisation) expressed concern that "regulatory agencies were inadequately monitoring air quality, we analyzed the state's data and found that air pollutants including benzene […] were being emitted from the wells".[273]

136.  A study prepared for the US Environmental Defense Fund, stated that "[shale] gas production [...] can impact local air quality and release greenhouse gases into the atmosphere".[274] The Fund identified various methods to capture methane and other gases that were released during well completions (when the well is made ready for production)—the use of these methods was known as a "green completion". Such completions not only reduced emissions of methane (if the methane was to be vented to the atmosphere), carbon dioxide (if the methane was to be flared) and other compounds (such as benzene, that can cause localised pollution and health problems), but they also captured products that could be sold by the operator. These green completions included methods to capture methane and VOC compounds during well completions, and the control of VOC from gas "condensate" tanks through the use of vapour recovery units.[275] The Environment Agency is not yet familiar with "green completion" technology, but should there be any commercial development of shale gas in the UK they would "require operators to use Best Available Techniques for the management of shale gas emissions".[276]

137.  The US EPA told us that about half of shale gas wells in the US generated liquid hydrocarbons (not oil) known as "wet gas". This contained molecules that were heavier than methane, collectively known as "condensates". The Environment Agency told us that they were not concerned by condensates as they expected "most shale wells [in the UK] to produce a high quality gas that will not need refining so there will be no gas condensates".[277]

138.  Tony Grayling told us that the Environment Agency was "not expecting big air quality implications […] the Government have oversight of the implementation of the Air Quality Directive […] the Environment Agency has to have regard to the National Air Quality strategy".[278] The Environment Agency "would prefer that if methane is being discharged that it was flared, because obviously that converts it to carbon dioxide, which is a much less potent greenhouse gas […] but we would respect the Health and Safety Executive's judgment about what is safe".[279]

139.  The Environment Agency told us that they would only monitor the emissions from shale gas operations if the activities involved "the refining or large scale combustion of gas [flaring]".[280] The Agency only expected flaring to be done on a small scale, so an environmental permit would not be necessary. If the shale gas operator were to flare gas on a large scale, they would be required to monitor for oxides of nitrogen, volatile organic compounds, sulphur dioxide and methane.[281]

140.  We recommend that the Environment Agency should have the powers to insist that—in collaboration with the Health and Safety Executive—planned onshore venting and flaring of natural gas for extended periods are not permitted.

Shale Gas and Local Communities

141.  The Tyndall Centre also described more "run of the mill" impacts of shale gas exploration and production such as "vehicle movements, landscape, noise and water consumption".[282] The Campaign to Protect Rural England (CPRE) raised these issues and stated they were: "concerned to ensure that any shale gas extraction in England does not cause unacceptable damage to the countryside".[283] The CPRE made the point that "onshore shale gas production […] [is] likely to be visually and ecologically intrusive" and would face "significant opposition on the grounds of landscape and wildlife conservation and rural character and amenity"[284].

142.  Another barrier to shale gas development in the UK is the population density. For example, England has a population density of 383 per km2, whereas the US has a population density of 27 per km2.[285] SSE) believed that this was particularly relevant as "shale gas resources are spread more thinly over much wider areas" and so would require more drilling activity. The Geological Society stated that the "physical footprint[s] associated with onshore [shale gas] exploitation, are very large compared to conventional hydrocarbons".[286] However, Cuadrilla argued that drilling many shale gas wells (up to 16) from the same "pad" increased the efficiency of gas gathering and production facilities, and that this method "also significantly reduces the visual impact of shale gas production at the surface".[287] Shell agreed, saying that "advances made in drilling horizontal wells […] mean that horizontal wells can replace many vertical wells", reducing the landscape footprint of shale gas exploration.[288]

143.  The British Geological Society pointed out that "lack of benefit to locals (in contrast to the US) and […] the relatively densely populated state of the UK is also a hindrance to development". In the US, landowners owned the oil and gas under their land, while in the UK "the Crown controls the right to produce hydrocarbons".[289] Professor Paul Stevens of Chatham House noted that in "Europe […] the state will reap the financial rewards of the resource and provide no financial incentive for the local community".[290] The Oxford Institute for Energy Studies agreed that "land access will remain challenging as long as there are no financial incentives for landowners".[291] The Dutch Energy Council has officially advised the Dutch government that "landowners and tenants [must] benefit financially from unconventional gas development on their land" if there was to be public support for shale gas exploration.[292]

144.  Comparing the development of shale gas in the UK and the US, the Minister told us the "issue of land ownership is a very critical one".[293] He added that in the UK, individual landowners have to give their consent to those who have been granted exploration licences, which is not always the case in the US. DECC explained that a recent case before the Supreme Court had ruled that where a landowner "unreasonably refuses to agree access, where he demands unreasonable terms, or where the fragmentation of land ownership means a licensee cannot agree terms with everyone" then the Mines (Working Facilities and Support) Act 1996, as modified by the Petroleum Act 1998, provided a method by which a licensee could seek "ancillary rights [of access] through the courts".[294] DECC pointed out that this was a far from common procedure.

145.  The Geological Society also explained that "social and psychological barrier[s] to the development of shale gas" were likely to be greater than physical (land) restrictions: "Open spaces may be more highly valued in light of their relative scarcity [in the UK]".[295] However, they cited the example of BP's Wytch Farm in Dorset, "the largest onshore oil field in Western Europe", as a demonstration that the industry can "successfully exploit resources […] while meeting the highest environmental and social standards". They also added that "if shale gas were to be used to supply local energy needs […] such developments might be regarded more positively".[296]

146.  The Minister thought it "quite challenging to see how" shale gas operations might encroach upon densely populated urban areas, as we witnessed in Fort Worth, Texas.[297]

147.  We conclude that the development of the UK shale gas industry will be different from the US—greater population density and stricter environmental legislation in Europe will give a greater incentive to drill fewer, better wells that take advantage of multiwell pad technology and horizontal drilling to minimise the impact on the landscape.

148.  We recommend that the Environment Agency and the Department of Energy and Climate Change take lessons from unconventional gas exploration in the US, especially at the state-level where much of the expertise lies. The US has a great deal of regulatory experience of dealing with the issues of water contamination, the volume of water required, waste water treatment and disposal, air pollution, and infrastructure challenges. The UK Government must use this experience to ensure the lowest achievable environmental impacts from unconventional gas exploitation here.

200   DECC, SEA for a 14th and Subsequent Onshore Oil & Gas Licensing Rounds-Environmental Report, July 2010 Back

201   Q 229  Back

202   The Environmental Assessment of Plans and Programmes Regulations 2004 (SI 2004/1663) Back

203   Environmental Impact Assessment Directive (85/337/EEC) Back

204   DECC, SEA for a 14th and Subsequent Onshore Oil & Gas Licensing Rounds-Environmental Report, July 2010 p 2 Back

205   "14th Onshore Licensing Round", DECC Oil and Gas, Back

206   DECC, SEA for a 14th and Subsequent Onshore Oil & Gas Licensing Rounds-Environmental Report, July 2010 p28 Back

207   Q 285  Back

208   Q 285 Back

209   "About Us", information on the Environment Agency website, Back

210   Q 86 Back

211   Ev 106 (EA), Q 207  Back

212   Ev 100 (WWF) Back

213   Ev 106 (EA) Back

214   Ev 106 (EA) Back

215   Ev 106 (EA) Back

216   Ev 106 (EA) Back

217   Q 211  Back

218   Q 211 Back

219   Q 6 Back

220   US EPA, Draft to Study the Potential Impacts of Hydraulic Fracturing on Drinking Water, February 2011, p 30 Back

221   US EPA, Draft to Study the Potential Impacts of Hydraulic Fracturing on Drinking Water, February 2011, p 30 Back

222   Q 33 Back

223   US EPA, Draft to Study the Potential Impacts of Hydraulic Fracturing on Drinking Water, February 2011, p 31 Back

224   P.S. Glenn, "Control and Modeling of Fluid Leakoff during Hydraulic Fracturing", Journal of Petroleum Tech 37(6), June 1985, p 1071 Back

225   J.C. Pashin, "Hydrodynamics of CBM Reservoirs in the Black Warrior Basin", Applied Geochemistry 22(10), October 2007, p 2257-2272 Back

226   US EPA, Draft to Study the Potential Impacts of Hydraulic Fracturing on Drinking Water, February 2011, p 27 Back

227   Ev w32 (Co-op) and Osborn et al, "Methane Contamination of drinking water accompanying gas-well drilling and hydraulic fracturing", Proceedings of the National Academy of Sciences, 9 May 2011  Back

228   Ev 66 (DECC) Back

229   Ev 74 (Selley) Back

230   Ev 86 (Tyndall) Back

231   Ev 57 (DECC) Back

232   Ev 92 (GSoL) Back

233   Ev 92 (GSoL) Back

234   US Department of Energy, Modern Shale Gas Development in the United States: A Primer, April 2009, Back

235   US Department of Energy, Modern Shale Gas Development in the United States: A Primer, April 2009,  Back

236   Ev 86 (Tyndall) Back

237   American Petroleum Institute, Water Management Associated with Hydraulic Fracturing, Guidance HF2, June 2010  Back

238   L.P. Galusky, "Fort Worth Basin Natural Gas Play", Barnett Shale Water Conservation and Management, April 2007 Back

239   US EPA, Draft to Study the Potential Impacts of Hydraulic Fracturing on Drinking Water, February 2011, p 20-21 Back

240   R.D. Vidic, "Sustainable Water Management for Marcellus Shale", Temple University (Philadelphia), March 2010 Back

241   Ev w8 (CPRE) Back

242   Q 113 Back

243   Environment Agency, Underground, Under Threat-The State of Ground Water in England and Wales, 2006, p 11 Back

244   Ev w19 (Shell) Back

245   Ev 100 (WWF) Back

246   Q 255 Back

247   US EPA, Draft to Study the Potential Impacts of Hydraulic Fracturing on Drinking Water, February 2011, p 21 Back

248   "Water Withdrawals for Development of Marcellus Shale Gas in Pennsylvania", Pennsylvania State University, October 2010, p 8 Back

249   Q 125  Back

250   Q 125  Back

251   Q 126 Back

252   Qq 125-126 Back

253   Q 201  Back

254   Q 202  Back

255   Qq 203,207 Back

256   Q 229  Back

257   Q 232 Back

258   Q 234 Back

259   US EPA, Draft to Study the Potential Impacts of Hydraulic Fracturing on Drinking Water, February 2011, p 35 Back

260   US EPA, Draft to Study the Potential Impacts of Hydraulic Fracturing on Drinking Water, February 2011, p 32 Back

261   US EPA, Draft to Study the Potential Impacts of Hydraulic Fracturing on Drinking Water, February 2011, p 40 Back

262   J.A. Veil, "Water Management Technologies used by Marcellus Shale Gas Producers", Argonne Nat'l Lab, July 2010 Back

263   Q 242  Back

264   Q 246 Back

265   Ev w36 (Mitchell) Back

266   Ev w9 (SSE) Back

267   Q 157  Back

268   Q 157 Back

269   Q 261  Back

270   Q 336 Back

271   DECC, SEA for a 14th and Subsequent Onshore Oil & Gas Licensing Rounds - Environmental Report, July 2010, p82 Back

272   US Department of Energy, Modern Shale Gas Development in the United States: A Primer, April 2009, Back

273   "Can we tap shale gas safely", Environmental Defense Fund, 7 December 2010, Back

274   Al Armendariz,"Emissions from Natural Gas Production in the Barnett Shale Area and Opportunities for Cost-Effective Improvements", Environmental Defense Fund, Back

275   Al Armendariz,"Emissions from Natural Gas Production in the Barnett Shale Area and Opportunities for Cost-Effective Improvements", Environmental Defense Fund, Back

276   Ev 107 (EA) Back

277   Ev 107 (EA) Back

278   Q 263 Back

279   Q 265 Back

280   Ev 107 (EA) Back

281   Ev 107 (EA) Back

282   Ev 86 (Tyndall) Back

283   Ev w8 (CPRE) Back

284   Ev w8 (CPRE) Back

285   Paul Stevens, "The 'Shale Gas Revolution': Hype and Reality", Chatham House, September 2010 Back

286   Ev 92 (GSoL) Back

287   Ev 78 (Cuadrilla) Back

288   Ev w19 (Shell) Back

289   Ev 57 (DECC) Back

290   Paul Stevens, "The 'Shale Gas Revolution': Hype and Reality", Chatham House, September 2010 Back

291   Florence Gény, "Can Unconventional Gas be a Game Changer in European Gas Markets?", OIES, December 2010, p100 Back

292   "Dutch Energy Council embraces unconventional gas", European Energy Review, 9 February 2011 Back

293   Q 280 Back

294   Ev 66 (DECC) Back

295   SG15a Back

296   SG15a Back

297   Q 218 Back

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© Parliamentary copyright 2011
Prepared 23 May 2011