Shale gas extraction in the UK: a review of hydraulic fracturing
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Shale gas extraction in the UK: a review of hydraulic fracturing



A 76-page report issued by the UK Royal Academy of Engineering and the UK Royal Society. The report encourages the UK to expand fracking in that country and says when regulated propertly, fracking is ...

A 76-page report issued by the UK Royal Academy of Engineering and the UK Royal Society. The report encourages the UK to expand fracking in that country and says when regulated propertly, fracking is safe.



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    Shale gas extraction in the UK: a review of hydraulic fracturing Shale gas extraction in the UK: a review of hydraulic fracturing Document Transcript

    • Shale gasextractionin the UK:a review ofhydraulicfracturingJune 2012
    • Shale gas extraction in the UK: a review of hydraulic fracturing Issued: June 2012 DES2597 © The Royal Society and The Royal Academy of Engineering 2012 The text of this work is licensed under Creative Commons Attribution-NonCommercial-ShareAlike CC BY-NC-SA. The license is available at: Images are not covered by this license and requests to use them should be submitted to: Requests to reproduce all or part of this document should be submitted to: The Royal Society The Royal Academy of Engineering Science Policy Centre 3 Carlton House Terrace 6 – 9 Carlton House Terrace London SW1Y 5DG London SW1Y 5AG T +44 20 7766 0600 T +44 20 7451 2500 W E W This document can be viewed online at: and Shale gas extraction in the UK: a review of hydraulic fracturing
    • ContentsSummary ........................................................4 Chapter 6 – Risk management ....................48 6.1 The UK’s goal based approach toRecommendations ..........................................6 regulation ......................................................48 6.2 Collecting data to improve riskTerms of reference .........................................8 assessments ................................................. 49 6.3 Environmental risk assessments ................... 51Chapter 1 – Introduction.................................91.1 Hydraulic fracturing.........................................9 Chapter 7 – Regulating shale gas .................531.2 Stages of shale gas extraction ...................... 10 7.1 Conditions of Petroleum Exploration and1.3 The global policy context .............................. 10 Development Licences..................................531.4 Environmental concerns in the USA ............. 11 7.2 Conditions of local planning permission.......541.5 Environmental concerns in Europe ............... 14 7.3 Notification of well construction and the1.6 Moratoria ...................................................... 15 well examination scheme..............................541.7 Concerns about seismicity ............................ 15 7.4 Conditions of environmental permits............551.8 The UK policy context ................................... 17 7.5 Regulating production activities on a nationwide scale ...........................................55Chapter 2 – Surface operations .................... 192.1 Fracturing fluid .............................................. 19 Chapter 8 – Research on shale gas ..............572.2 Water requirements .....................................20 8.1 Uncertainties affecting small scale2.3 Managing wastewaters .................................20 exploratory activities .....................................572.4 Disposal of wastewaters ...............................21 8.2 Uncertainties affecting large scale2.5 Disposal of solid wastes ...............................22 production activities ......................................572.6 Managing methane and other emissions ....22 8.3 Funding research on shale gas .....................58Chapter 3 – Well integrity ............................243.1 Preventing well failure ...................................25 References ....................................................603.2 Improving the well examination scheme .....263.3 Detecting well failure ....................................27 Acronyms .....................................................66Chapter 4 – Fracture propagation ................. 31 Glossary ........................................................684.1 Monitoring fractures .....................................314.2 Constraining fracture growth ........................32 Appendix 1 – Working Group .......................704.3 Hydraulic fracturing below aquifers ..............34 Appendix 2 – Evidence gathering .................72Chapter 5 – Induced seismicity ....................405.1 Natural seismicity ..........................................40 Appendix 3 – Review Panel ..........................755.2 Seismicity induced by coal mining ...............405.3 Seismicity induced by hydraulic fracturing... 415.4 Factors affecting seismicity induced by hydraulic fracturing .......................................425.5 Mitigating induced seismicity .......................435.6 Damage to well integrity ...............................455.7 Seismicity induced by disposal.....................455.8 Regulating induced seismicity ......................46 Shale gas extraction in the UK: a review of hydraulic fracturing 3
    • SUMMARY Summary The health, safety and environmental risks associated Concerns have also been raised about seismicity with hydraulic fracturing (often termed ‘fracking’) induced by hydraulic fracturing. Natural seismicity as a means to extract shale gas can be managed in the UK is low by world standards. On average, effectively in the UK as long as operational best the UK experiences seismicity of magnitude 5 ML practices are implemented and enforced through (felt by everyone nearby) every twenty years, and regulation. Hydraulic fracturing is an established of magnitude 4 ML (felt by many people) every technology that has been used in the oil and gas three to four years. The UK has lived with seismicity industries for many decades. The UK has 60 years’ induced by coal mining activities or the settlement of experience of regulating onshore and offshore oil abandoned mines for a long time. British Geological and gas industries. Survey records indicate that coal mining-related seismicity is generally of smaller magnitude than Concerns have been raised about the risk of fractures natural seismicity and no larger than 4 ML. Seismicity propagating from shale formations to reach overlying induced by hydraulic fracturing is likely to be of even aquifers. The available evidence indicates that this smaller magnitude. There is an emerging consensus risk is very low provided that shale gas extraction that the magnitude of seismicity induced by hydraulic takes place at depths of many hundreds of metres or fracturing would be no greater than 3 ML (felt by several kilometres. Geological mechanisms constrain few people and resulting in negligible, if any, surface the distances that fractures may propagate vertically. impacts). Recent seismicity induced by hydraulic Even if communication with overlying aquifers were fracturing in the UK was of magnitude 2.3 ML and possible, suitable pressure conditions would still be 1.5 ML (unlikely to be felt by anyone). The risk of PGEGUUCT[ HQT EQPVCOKPCPVU VQ ƃQY VJTQWIJ HTCEVWTGU seismicity induced by hydraulic fracturing can be More likely causes of possible environmental TGFWEGF D[ VTCHƂE NKIJV OQPKVQTKPI U[UVGOU VJCV WUG contamination include faulty wells, and leaks and real-time seismic monitoring so that operators can spills associated with surface operations. Neither respond promptly. cause is unique to shale gas. Both are common to all oil and gas wells and extractive activities. Monitoring should be carried out before, during and after shale gas operations to inform risk assessments. Ensuring well integrity must remain the highest Methane and other contaminants in groundwater priority to prevent contamination. The probability of should be monitored, as well as potential leakages of well failure is low for a single well if it is designed, methane and other gases into the atmosphere. The constructed and abandoned according to best geology of sites should be characterised and faults practice. The UK’s well examination scheme was KFGPVKƂGF /QPKVQTKPI FCVC UJQWNF DG UWDOKVVGF VQ set up so that the design of offshore wells could be the UK’s regulators to manage potential hazards, reviewed by independent, specialist experts. This inform local planning processes and address wider UEJGOG OWUV DG OCFG ƂV HQT RWTRQUG HQT QPUJQTG concerns. Monitoring of any potential leaks of activities. Effects of unforeseen leaks or spills methane would provide data to assess the carbon can be mitigated by proper site construction and footprint of shale gas extraction. impermeable lining. Disclosure of the constituents QH HTCEVWTKPI ƃWKF KU CNTGCF[ OCPFCVQT[ KP VJG 7- Ensuring, where possible, that chemical additives are non-hazardous would help to mitigate the impact of any leak or spill.4 Shale gas extraction in the UK: a review of hydraulic fracturing
    • SUMMARYThe UK’s goal based approach to regulation is to more concentrated during waste commended, requiring operators to identify and NORM management is not unique to shale gasassess risks in a way that fosters innovation and GZVTCEVKQP 014/ KU RTGUGPV KP YCUVG ƃWKFU HTQOcontinuous improvement in risk management. The the conventional oil and gas industries, as wellUK’s health and safety regulators and environmental as in mining industries, such as coal and potash.regulators should work together to develop Much work has been carried out globally onIWKFGNKPGU URGEKƂE VQ UJCNG ICU GZVTCEVKQP VQ JGNR monitoring levels of radioactivity and handlingoperators carry out goal based risk assessments NORMs in these industries.according to the principle of reducing risks to AsLow As Reasonably Practicable (ALARP). Risk Shale gas extraction in the UK is presently at a veryassessments should be submitted to the regulators small scale, involving only exploratory activities.for scrutiny and then enforced through monitoring Uncertainties can be addressed through robustactivities and inspections. It is mandatory for OQPKVQTKPI U[UVGOU CPF TGUGCTEJ CEVKXKVKGU KFGPVKƂGFoperators to report well failures, as well as other in this report. There is greater uncertainty aboutaccidents and incidents to the UK’s regulators. the scale of production activities should a futureMechanisms should be put in place so that reports shale gas industry develop nationwide. Attentioncan also be shared between operators to improve must be paid to the way in which risks scale up.risk assessments and promote best practices across Co-ordination of the numerous bodies withthe industry. regulatory responsibilities for shale gas extraction must be maintained. Regulatory capacity mayAn Environmental Risk Assessment (ERA) should need to be mandatory for all shale gas operations. Risksshould be assessed across the entire lifecycle of Decisions are soon to be made about shale gasshale gas extraction, including risks associated with extraction continuing in the UK. The next round ofthe disposal of wastes and abandonment of wells. issuing Petroleum Exploration and DevelopmentSeismic risks should also feature as part of the ERA. Licences is also pending. This report has not attempted to determine whether shale gas extractionWater requirements can be managed through should go ahead. This remains the responsibilityintegrated operational practices, such as recycling of the Government. This report has analysed theand reusing wastewaters where possible. Options technical aspects of the environmental, health andfor disposing of wastes should be planned from safety risks associated with shale gas extraction tothe outset. Should any onshore disposal wells be inform decision making. Neither risks associated withnecessary in the UK, their construction, regulation the subsequent use of shale gas nor climate risksand siting would need further consideration. JCXG DGGP CPCN[UGF &GEKUKQP OCMKPI YQWNF DGPGƂV from research into the climate risks associated withWastewaters may contain Naturally Occurring both the extraction and use of shale gas. FurtherRadioactive Material (NORM) that are present in DGPGƂV YQWNF CNUQ DG FGTKXGF HTQO TGUGCTEJ KPVQ VJGUJCNGU CV NGXGNU UKIPKƂECPVN[ NQYGT VJCP UCHG NKOKVU public acceptability of all these risks in the contextof exposure. These wastewaters are in need of of the UK’s energy, climate and economic policies.careful management should NORM become Shale gas extraction in the UK: a review of hydraulic fracturing 5
    • SUMMARY Recommendations Recommendation 1 Recommendation 3 To detect groundwater contamination: To mitigate induced seismicity: r The UK’s environmental regulators should work r BGS or other appropriate bodies should carry with the British Geological Survey (BGS) to carry out national surveys to characterise stresses and out comprehensive national baseline surveys of identify faults in UK shales. Operators should carry methane and other contaminants in groundwater. out site-specific surveys to characterise and identify local stresses and faults. r Operators should carry out site-specific monitoring of methane and other contaminants r Seismicity should be monitored before, during in groundwater before, during and after shale gas and after hydraulic fracturing. operations. r Traffic light monitoring systems should be r Arrangements for monitoring abandoned wells implemented and data fed back to well injection need to be developed. Funding of this monitoring operations so that action can be taken to mitigate and any remediation work needs further any induced seismicity. consideration. r DECC should consider how induced seismicity is r The data collected by operators should be to be regulated. Operators should share data with submitted to the appropriate regulator. DECC and BGS to establish a national database of shale stress and fault properties so that suitable Recommendation 2 well locations can be identified. To ensure well integrity: Recommendation 4 r Guidelines should be clarified to ensure the To detect potential leakages of gas: independence of the well examiner from the operator. r Operators should monitor potential leakages of methane or other emissions to the atmosphere r Well designs should be reviewed by the before, during and after shale gas operations. well examiner from both a health and safety perspective and an environmental perspective. r The data collected by operators should be submitted to the appropriate regulator. These r The well examiner should carry out onsite data could inform wider assessments, such as inspections as appropriate to ensure that wells the carbon footprint of shale gas extraction. are constructed according to the agreed design. Recommendation 5 r Operators should ensure that well integrity tests Water should be managed in an integrated way: are carried out as appropriate, such as pressure r Techniques and operational practices should be tests and cement bond logs. implemented to minimise water use and avoid abstracting water from supplies that may be r The results of well tests and the reports of under stress. well examinations should be submitted to the Department of Energy and Climate r Wastewater should be recycled and reused Change (DECC). where possible. r Options for treating and disposing of wastes should be planned from the outset. The construction, regulation and siting of any future onshore disposal wells need further investigation.6 Shale gas extraction in the UK: a review of hydraulic fracturing
    • SUMMARYRecommendation 6 Recommendation 9To manage environmental risks: Co-ordination of the numerous bodies with regulatory responsibilities for shale gas extraction should ber An Environmental Risk Assessment (ERA) should maintained. A single body should take the lead. be mandatory for all shale gas operations, Consideration should be given to: involving the participation of local communities at the earliest possible opportunity. r Clarity on roles and responsibilities.r The ERA should assess risks across the entire r Mechanisms to support integrated ways of lifecycle of shale gas extraction, including the working. disposal of wastes and well abandonment. Seismic risks should also feature as part of r More formal mechanisms to share information. the ERA. r Joined-up engagement of local communities.Recommendation 7Best practice for risk management should be r Mechanisms to learn from operational andimplemented: regulatory best practice internationally.r Operators should carry out goal based risk Recommendation 10 assessments according to the principle of The Research Councils, especially the Natural reducing risks to As Low As Reasonably Environment Research Council, the Engineering Practicable (ALARP). The UK’s health and safety and Physical Sciences Research Council and the regulators and environmental regulators should Economic and Social Research Council, should work together to develop guidelines specific to consider including shale gas extraction in their shale gas extraction to help operators do so. research programmes, and possibly a cross-Research Council programme. Priorities should includer Operators should ensure mechanisms are put in research into the public acceptability of the extraction place to audit their risk management processes. and use of shale gas in the context of UK policies on climate change, energy and the wider economy.r Risk assessments should be submitted to the regulators for scrutiny and then enforced through monitoring activities and inspections.r Mechanisms should be put in place to allow the reporting of well failures, as well as other accidents and incidents, between operators. The information collected should then be shared to improve risk assessments and promote best practices across the industry.Recommendation 8The UK’s regulators should determine theirrequirements to regulate a shale gas industry shouldit develop nationwide in the future. Skills gaps andrelevant training should be identified. Additionalresources may be necessary. Shale gas extraction in the UK: a review of hydraulic fracturing 7
    • SUMMARY Terms of reference 6JG 7- )QXGTPOGPVoU %JKGH 5EKGPVKƂE #FXKUGT 5KT Methodology John Beddington FRS, asked the Royal Society and A Working Group was set up to oversee this project the Royal Academy of Engineering to carry out an (see Appendix 1). The Working Group met on six KPFGRGPFGPV TGXKGY QH VJG UEKGPVKƂE CPF GPIKPGGTKPI occasions when it was briefed by other experts. evidence relating to the technical aspects of the Consultations with other experts and stakeholders risks associated with hydraulic fracturing to inform were held between meetings. Submissions were government policymaking about shale gas extraction received from a number of individuals and learned in the UK. societies (see Appendix 2). This report has been reviewed by an expert Review Panel (see Appendix 3) The terms of reference of this review were: and approved by the Engineering Policy Committee of the Royal Academy of Engineering and the Council r What are the major risks associated with hydraulic of the Royal Society. fracturing as a means to extract shale gas in the UK, including geological risks, such as seismicity, The Royal Academy of Engineering and The Royal and environmental risks, such as groundwater 5QEKGV[ CTG ITCVGHWN VQ VJG )QXGTPOGPV 1HƂEG HQT contamination? 5EKGPEG HQT KVU ƂPCPEKCN UWRRQTV HQT VJKU TGXKGY r Can these risks be effectively managed? If so, how? This report has analysed environmental and health and safety risks. Climate risks have not been analysed. The risks addressed in this report are restricted to those associated with the onshore extraction of shale gas. The subsequent use of shale gas has not been addressed.8 Shale gas extraction in the UK: a review of hydraulic fracturing
    • CHAPTER 1Introduction1.1 Hydraulic fracturing pumped into the well to maintain the pressure in theShale is a common type of sedimentary rock formed well so that fracture development can continue andfrom deposits of mud, silt, clay and organic matter. proppant can be carried deeper into the formationShale gas mainly consists of methane, although (API 2009). A well may be too long to maintainother gases may also be present, trapped in shale sufficient pressure to stimulate fractures across itswith very low permeability. Shale gas does not entire length. Plugs may be inserted to divide the wellreadily flow into a well (‘produce’). Additional into smaller sections (‘stages’). Stages are fracturedstimulation by hydraulic fracturing (often termed sequentially, beginning with the stage furthest away‘fracking’) is required to increase permeability (see and moving towards the start of the well. AfterFigure 1). Once a well has been drilled and cased fracturing, the plugs are drilled through and the well(‘completed’), explosive charges fired by an electric is depressurised. This creates a pressure gradientcurrent perforate holes along selected intervals so that gas flows out of the shale into the well.of the well within the shale formation from which Fracturing fluid flows back to the surface (‘flowbackshale gas is produced (‘production zone’). Pumps water’) but it now also contains saline waterare used to inject fracturing fluids, consisting of with dissolved minerals from the shale formationwater, sand (‘proppant’) and chemicals, under (’formation water’). Fracturing fluid and formationhigh pressure into the well. The injection pressure water returns to the surface over the lifetime of thegenerates stresses in the shale that exceed its well as it continues to produce shale gas (‘producedstrength, opening up existing fractures or creating water’). Although definitions vary, flowbacknew ones. The fractures extend a few hundred water and produced water collectively constitutemetres into the rock and the newly created fractures ‘wastewaters’ (EPA 2011).are propped open by the sand. Additional fluids are Shale gas extraction in the UK: a review of hydraulic fracturing 9
    • CHAP TER 1 Figure 1 An illustration of hydraulic fracturing (Al Granberg/ProPublica) Fracturing fluids are injected under pressure to stimulate fractures in the shale. The fractures are propped open by sand contained in the fracturing fluid so that shale gas can flow out of the shale into the well. Well Sand keeps fractures open Shale gas Fracture flows from fractures into well Mixture of Well water, sand and chemical additives Fractures Shale 1.2 Stages of shale gas extraction through them and access only a small volume of Shale gas extraction consists of three stages: the shale. Horizontal wells are likely to be drilled and fractured. Once a shale formation is reached r Exploration. A small number of vertical wells by vertical drilling, the drill bit can be deviated to (perhaps only two or three) are drilled and run horizontally or at any angle. fractured to determine if shale gas is present and can be extracted. This exploration stage may r Abandonment. Like any other well, a shale gas include an appraisal phase where more wells well is abandoned once it reaches the end of (perhaps 10 to 15) are drilled and fractured to its producing life when extraction is no longer characterise the shale; examine how fractures will economic. Sections of the well are filled with tend to propagate; and establish if the shale could cement to prevent gas flowing into water-bearing produce gas economically. Further wells may be zones or up to the surface. A cap is welded into drilled (perhaps reaching a total of 30) to ascertain place and then buried. the long-term economic viability of the shale. 1.3 The global policy context r Production. The production stage involves the commercial production of shale gas. Shales 1.3.1 Potential global shale gas resources with commercial reserves of gas will typically ‘Gas in place’ refers to the entire volume of gas be greater than a hundred metres thick and contained in a rock formation regardless of the will persist laterally over hundreds of square ability to produce it. ‘Technically recoverable kilometres. These shales will normally have resources’ refers to the volume of gas considered shallow dips, meaning they are almost horizontal. to be recoverable with available technology. ‘Proved Vertical drilling would tend to pass straight reserves’ refers to that volume of technically10 Shale gas extraction in the UK: a review of hydraulic fracturing
    • CHAPTER 1recoverable resources demonstrated to be estimates the total volume of technically recoverableeconomically and legally producible under existing shale gas worldwide to be 6,622 tcf. The USA haseconomic and operating conditions. approximately 862 tcf, and China 1,275 tcf (see Figure 2). In Europe, Poland and France are two ofShale gas could increase global natural gas the most promising shale gas countries with 187resources by approximately 40%. The US Energy tcf and 180 tcf of technically recoverable resources,Information Administration (EIA) estimates the global respectively. Norway, Ukraine and Sweden may alsotechnically recoverable resources of natural gas possess large technically recoverable resources.(largely excluding shale gas) to be approximately The EIA estimates the UK’s technically recoverable16,000 trillion cubic feet (tcf) (EIA 2011). The EIA resources to be 20 tcf (EIA 2011) Figure 2 Estimates of technically recoverable shale gas resources (trillion cubic feet, tcf) based on 48 major shale formations in 32 countries (EIA 2011) Russia, Central Asia, Middle East, South East Asia and central Africa were not addressed in the Energy Information Administration report from which this data was taken. 83 Norway 388 Canada UK 20 187 Poland France 180 862 USA 1275 China Algeria 231 Pakistan 51 290 Libya 681 Mexico India 63 226 Brazil 62 Paraguay Australia 396 64 Chile 485 South Africa 774 Argentina1.3.2 Global climate change and energy security molecule of methane is greater than that of carbonShale gas is championed by some commentators as dioxide, but its lifetime in the atmosphere is shorter.a ‘transition fuel’ in the move towards a low carbon On a 20-year timescale, the global warming potentialeconomy, helping to displace higher-emitting fuels, of methane is 72 times greater than that of carbonsuch as coal (Brinded 2011). Others argue that shale dioxide. On a century timescale, it is 25 times greatergas could supplement rather than displace coal use, (IPCC 2007).further locking in countries to a fossil fuel economy(Broderick et al 2011). The development of shale gas 1.4 Environmental concerns in the USAcould also reduce and/or delay the incentive to invest Hydraulic fracturing was pioneered in the 1930s andin zero- and low-carbon technologies and renewable ƂTUV WUGF CHVGT VJG 5GEQPF 9QTNF 9CT KP VJG 75# VQenergy (Broderick et al 2011, Stevens 2010). exploit the relatively shallow Devonian Shale in the GCUVGTP 75 CPF #PVTKO 5JCNG KP VJG /KFYGUV 6JG ƂTUVThere are concerns that even small leakages of well to be hydraulically fractured was in 1949. Onlymethane during shale gas extraction may offset the a modest volume of gas was recovered. Advanceseffects of lower carbon dioxide emissions (Howarth in technology in the late 1980s and early 1990s ledet al 2011). The global warming potential of a to directional drilling and hydraulic fracturing in the Shale gas extraction in the UK: a review of hydraulic fracturing 11
    • CHAP TER 1 Barnett Shale in Texas (Selley 2012). An important 1.4.1 Improper operational practices turning point came in the 1990s. Geochemical There has been widespread concern in the USA studies of the Antrim Shale of the Michigan Basin about the environmental impact of hydraulic revealed that the gas being released was not fracturing. One cause for concern has been improper thermogenic (produced by the alteration of organic operational practices. A US Environmental Protection matter under high temperatures and pressures over Agency (EPA) study reported that hydraulic fracturing long time periods) but was biogenic (produced had contaminated groundwater and drinking by bacteria) (Martini et al 1998). This discovery water supplies in Pavillion, Wyoming (DiGiulio et opened up new areas for exploration where the al 2011). The well casing was poorly constructed, shale had previously been deemed either immature and the shale formations that were fractured were or over-mature for thermogenic gas generation. as shallow as 372m. Many claims of contaminated At the same time, progress was being made in water wells due to shale gas extraction have been methods of drilling, such as directional drilling that made. None has shown evidence of chemicals could steer the drill bit to exploit regions with high HQWPF KP J[FTCWNKE HTCEVWTKPI ƃWKFU 9CVGT YGNNU KP concentrations of carbon and where the shale is areas of shale gas extraction have historically shown most amenable to being fractured. By 2002-03, the high levels of naturally occurring methane before combination of hydraulic fracturing and directional operations began. Methane detected in water wells drilling made shale gas commercially viable. with the onset of drilling may also be mobilised by vibrations and pressure pulses associated with the Shale gas production has been enhanced by US lease drilling (Groat and Grimshaw 2012). In 2011, the EPA regulations that require a leaseholder to commence was directed by Congress to undertake a study to operations within a primary term period (normally better understand the potential impacts of hydraulic ƂXG [GCTU QT NQUG VJG NGCUG TGICTFNGUU QH RTKEG 5JCNG fracturing on drinking water resources. This EPA gas production in the USA has caused gas prices to study is examining impacts from the acquisition of fall as supply has outstripped demand. Shale gas has water and its mixing with chemicals to create fracture FKXGTUKƂGF FQOGUVKE GPGTI[ UWRRNKGU CPF TGFWEGF ƃWKF VJTQWIJ VQ VJG OCPCIGOGPV QH ƃQYDCEM CPF 75 FGRGPFGPEG QP KORQTVU QH NKSWGƂGF PCVWTCN ICU RTQFWEGF YCVGT KPENWFKPI FKURQUCN # ƂTUV TGRQTV Shale gas rose from 2% of US gas production in KU GZRGEVGF CV VJG GPF QH  6JG ƂPCN TGUWNVU 2000 to 14% in 2009, and is projected to rise to are due in 2014. In 2011, the Secretary of Energy more than 30% by 2020 (EIA 2011). Advisory Board Natural Gas Subcommittee submitted its recommendations to improve the safety and environmental performance of shale gas extraction (see Textbox 1).12 Shale gas extraction in the UK: a review of hydraulic fracturing
    • CHAPTER 1Textbox 1 Recommendations of the US Secretary of Energy Advisory Board Natural GasSubcommittee (DoE 2011a, DoE 2011b)Recommendations ready for implementation Recommendations ready for implementationprimarily by federal agencies primarily by state agenciesr Communication among federal and state r Measurements of groundwater should be regulators should be improved. Federal funds made prior to any shale gas operations to should be provided to support the non- provide a baseline to assess any claims of profit State Review of Oil and Natural Gas water contamination. Environmental Regulations (STRONGER) and Ground Water Protection Council (GWPC). r Microseismic monitoring should be carried STRONGER began as a voluntary programme out to assure that fracture growth is developed to improve state regulations and constrained to producing formations. has since emerged as a partnership between industry, non-profit groups and regulators that r Best practice for well construction should develops best practice, including through new be developed and implemented, including guidelines. pressure testing and cement bond logs, to verify rock formations have been properlyr Incentives should be provided for states to isolated. offer their regulation framework to peer review under STRONGER. Extra funding would r Inspections should be carried out to confirm allow GWPC to expand its Risk Based Data that operators have remediated any defective Management System that helps states collect well cementation effectively. Inspections and publicly share data, such as environmental should also be carried out at safety-critical monitoring of shale gas operations. stages of well construction and hydraulic fracturing.r Operators should disclose all chemicals used in fracturing fluid and not just those r The composition of water should be that appear on Material Safety Data Sheets. monitored and publicly reported at each Disclosure should be reported on a well-by- stage of shale gas extraction, including the well basis and made publicly available. Extra transport of water and waste fluids to, and funding would support GWPC’s fracturing fluid from, well sites. chemical disclosure registry, Frac Focus, so that information can be accessed, according to chemical, well, company and geography. Recommendations whose implementation require new partnershipsr Operators and regulators should be r A systems approach to water management encouraged to reduce air emissions using should be adopted, requiring more effective proven technologies and practices. Systems sharing of federal and state responsibilities. should be implemented to monitor air emissions from shale gas operations, the r Mechanisms should be established to engage results of which should be made publicly regulators, operators and local communities available. The data collected should be used to discuss measures to minimise operational to assess the carbon footprint of shale gas impacts, including scientific studies to assess extraction compared to other fuels. impacts on local water resources, land use, wildlife and ecology. Shale gas extraction in the UK: a review of hydraulic fracturing 13
    • CHAP TER 1 1.4.2 Exemptions from regulation and Awareness of Chemicals Act (FRAC ACT) bills Another cause for concern was a number of were introduced in the House of Representatives exemptions granted to shale gas extraction from and Senate. The FRAC ACT would have required federal regulations. The 2005 Energy Act exempted companies to disclose such details, although not the hydraulic fracturing from being considered an proprietary formula. These bills had been proposed ‘underground injection’ under the Safe Drinking in the previous session of Congress but never Water Act. Compliance with various federal became law. requirements to prevent water contamination was not necessary. Fracturing wastes are exempt Environmental protection remains mainly a state from disposal restrictions under the Resource responsibility. In some states, requirements Conservation and Recovery Act. Operators are exempted from federal regulation are still imposed exempt from certain liabilities and reporting through state regulation. Some states are revising requirements relating to waste disposal under their regulations with a particular focus on three the Comprehensive Environmental Responsibility, areas of concern: water abstraction and disclosure Compensation, and Liability Act. Exemption from QH HTCEVWTKPI ƃWKF EQORQUKVKQP YGNN EQPUVTWEVKQP the Emergency Planning and Community Right to and wastewater management (Groat and Grimshaw Know Act means the type and quantity of chemicals 2012). Some states may have more capacity and to be used in fracturing do not need to be disclosed experience to regulate shale gas operations than to the EPA. In 2010, the Fracturing Responsibility other states (see Textbox 2). Textbox 2 Complications of US state and federal regulation A study by the University of Texas at Austin r Well construction. Some states are updating reviewed state regulations and enforcement provisions for well construction, according capabilities in 16 US states where shale gas to site-specific operational and geological extraction is currently underway, or is anticipated conditions. (Groat and Grimshaw 2012). This study concluded that variation exists among states in r Wastewater management. Some states are the regulation of: requiring operators to formulate disposal plans. In some states, disposal is primarily by r Water abstraction and disclosure of underground injection. In others with less fracturing fluid composition. In some states, suitable subsurface conditions disposal is via groundwater is privately owned and subject discharge into publicly owned treatment works. to different requirements than in other states The latter method has been prohibited by some where groundwater is owned by the state and states. Other states require pre-treatment before subject to state abstraction permits. More discharge. In some shale gas areas, wastes from uniform disclosure of the composition multiple well sites are managed at a centralised of fracturing fluids may be needed among disposal site. state regulators. 1.5 Environmental concerns in Europe potential to extract and use unconventional fossil Shale gas extraction in Europe is at the exploration fuel resources, including shale gas, should be stage. It is many years away from US levels of assessed (European Council 2011). In 2012, the commercial production, especially in the light European Commission (EC) judged that its existing of differences in geology, public acceptability, legal framework was adequate to address shale gas population density, tax breaks and environmental extraction (Vopel 2012). Shale gas could reduce some regulation (Stevens 2010). In 2011, European European countries’ dependence on natural gas Union (EU) Heads of State concluded that Europe’s imports (European Parliament 2012b).14 Shale gas extraction in the UK: a review of hydraulic fracturing
    • CHAPTER 1The EC Directorate-General for the Environment 1.7 Concerns about seismicityis conducting a desk study on environmental and Concerns in the UK have focused on seismicityhealth risks associated with hydraulic fracturing induced by hydraulic fracturing. ‘Seismicity’ orto identify knowledge gaps. The EC Directorate- ‘seismic events’ refer to sudden phenomena thatGeneral for Climate Action is carrying out a similar release energy in the form of vibrations that travelstudy focused on gas emissions associated with through the Earth as sound (seismic) waves. Energyshale gas extraction, including potential leakages of may be released when rocks break and slide pastmethane. The EC Directorate-General for Energy has each other on surfaces or cracks (‘faults’). Energycarried out a project on licensing, authorising and may also be released when rocks break in tension,the issuing of operational permits for shale gas. The opening up cracks or fractures. The passage andJoint Research Centre (JRC) is examining whether TGƃGEVKQP QH UGKUOKE YCXGU ECP DG OQPKVQTGF D[the exposure scenarios of Chemical Safety Reports seismometers at seismic stations. Geophones areunder Registration, Evaluation, Authorisation and used along regular lines (‘seismic lines’) or gridsRestriction of Chemicals regulation are adequate VQ QDVCKP VYQ QT VJTGG FKOGPUKQPCN RTQƂNGU QH VJGfor shale gas extraction. The JRC is also assessing CTVJoU UWDUWTHCEG UVTWEVWTG nUGKUOKE TGƃGEVKQPthe potential impacts on water and land use under surveys’). Seismicity is measured according tovarious national and EU-wide scenarios. Results of the amount of energy released (magnitude) or thethese studies should be available by the end of 2012. effect that energy release has at the Earth’s surface (intensity) (see Textbox 3).All EU member states are members of an AdHoc Technical Working Group on Environmental On 1st April 2011, the Blackpool area in northAspects of Unconventional Fossil Fuels, In Particular England experienced seismicity of magnitudeShale Gas. The Working Group seeks to exchange 2.3 ML shortly after Cuadrilla Resources (‘Cuadrilla’,information; identify best practice; assess the hereafter) hydraulically fractured a well at its Preeseadequacy of regulation and legislation; and provide Hall site. Seismicity of magnitude 1.5 ML occurredENCTKV[ VQ QRGTCVQTU +V OGV HQT VJG ƂTUV VKOG KP on 27th May 2011 following renewed fracturing ofJanuary 2012 and was attended by representatives the same well. Hydraulic fracturing was suspended.of approximately two thirds of member states. The Cuadrilla commissioned a set of reports to investigateWorking Group may meet again in summer 2012 the cause of seismicity (de Pater and Baisch 2011).when the results of some of the aforementioned The Department of Energy and Climate ChangeEC research are published. It is unclear whether the (DECC) also commissioned an independentWorking Group will continue to meet thereafter. report that was published for public comment (Green et al 2012).1.6 MoratoriaEnvironmental concerns have led to moratoria onhydraulic fracturing for shale gas extraction in partsof the USA and in other countries. In May 2010, theMarcellus Shale Bill was passed in Pennsylvania,enforcing a three-year moratorium while acomprehensive environmental impact assessmentis carried out. In August 2010, New York Stateimposed a temporary moratorium, pending furtherresearch into environmental impacts. Moratoriahave also been imposed elsewhere, including in theprovince of Quebec, Canada (March 2011), France(July 2011), South Africa (August 2011) and Bulgaria(January 2012). Shale gas extraction in the UK: a review of hydraulic fracturing 15
    • CHAP TER 1 Textbox 3 Measuring seismic magnitude and intensity Magnitude scales are calibrated to Richter’s The frequency of the radiated seismic waves is magnitude scale. The scale is logarithmic so the proportional to the size of the fracture. Since smallest events can have negative magnitudes. engineered hydraulic fractures are typically small, Each unit step in the scale indicates a 32-fold seismic events induced by hydraulic fracturing increase in the energy released. Seismic intensity only produce high frequency radiated seismic is an indication of how much a seismic event waves, and so do not produce ground shaking affects structures, people and landscapes at the that will damage buildings. The number of people Earth’s surface. Surface effects are compared who feel small seismic events is dependent on the to a scale originally developed by Mercalli background noise. that considers who can feel an event along with visual and structural effects. The Mercalli The British Geological Survey (BGS) runs a network scale has been superseded by the European of approximately 100 stations to monitor seismicity Macroseismic Scale that incorporates new in the UK. The Atomic Weapons Establishment knowledge about how buildings behave during also has a limited number of stations to monitor seismic events. international compliance with the Comprehensive Nuclear Test Ban Treaty. Other seismic stations The effect a given seismic event will have at include those maintained for research by the earth’s surface depends on several factors. universities. The detection limit of this national The deeper a seismic event occurs the more its network is a function of background noise that radiated energy is attenuated. A deeper seismic OC[ KPENWFG VTCHƂE VTCKPU CPF QVJGT KPFWUVTKCN event will have a lower intensity than a shallower noise, as well as natural noise, such as wind. Given event of the same magnitude. Different average background noise conditions in mainland materials attenuate seismic waves to different UK, a realistic detection limit of BGS’ network is degrees. Soft rocks, such as shale, attenuate magnitude 1.5 ML. For regions with seismic waves more than hard rocks, such more background noise, the detection limit may as granite. Different buildings and structures be closer to magnitude 2-2.5 ML. Vibrations from respond differently depending on how they are a seismic event of magnitude 2.5 ML are broadly constructed. The response of a building to a GSWKXCNGPV VQ VJG IGPGTCN VTCHƂE KPFWUVTKCN CPF seismic event also depends on the frequency other noise experienced daily (see Table 1). of the ground shaking. High frequencies (above 20-30 Hz) will do relatively little damage.16 Shale gas extraction in the UK: a review of hydraulic fracturing
    • CHAPTER 1Table 1 The average annual frequency of seismic events in the UK Magnitude (ML) Frequency in the UK Felt effects at the surface -3.0 Not detected by BGS’ network Not felt -2.0 Not detected by BGS’ network Not felt -1.0 Not detected by BGS’ network Not felt 0.0 Not detected by BGS’ network Not felt 1.0 100s each year Not felt, except by a very few under especially favourable conditions. 2.0 25 each year Not felt, except by a very few under especially favourable conditions. 3.0 3 each year (GNV D[ HGY RGQRNG CV TGUV QT KP VJG WRRGT ƃQQTU QH buildings; similar to the passing of a truck. 4.0 1 every 3-4 years Felt by many people, often up to tens of kilometres away; some dishes broken; pendulum clocks may stop. 5. 0 1 every 20 years Felt by all people nearby; damage negligible in buildings of good design and construction; few instances of fallen plaster; some chimneys broken.1.8 The UK policy context 6JG ƂTUV 7- YGNN VQ GPEQWPVGT UJCNG ICU YCU FTKNNGFThe UK has experience of hydraulic fracturing and KP  +VU UKIPKƂECPEG CV VJG VKOG YGPV WPPQVKEGFdirectional drilling for non-shale gas applications. as abundant conventional reservoirs made shaleOver the last 30 years, more than 2,000 wells have gas extraction uneconomic. It was not until thebeen drilled onshore in the UK, approximately 200 mid-1980s that research began into the potential(10%) of which have been hydraulically fractured for gas production from UK shales. In 2003, theto enhance recovery. The combination of hydraulic Petroleum Revenue Act was repealed, exemptingfracturing and directional drilling allowed the shale gas production from the Petroleum RevenueFGXGNQROGPV QH 9[VEJ (CTO ƂGNF KP &QTUGV KP Tax (Selley 2012). In 2008, 97 Petroleum Exploration1979. Discovered by British Gas in the 1970s and and Development Licences were awarded for shaleQRGTCVGF D[ $TKVKUJ 2GVTQNGWO UKPEG  VJG ƂGNF gas exploration in the UK during the 13th Round ofis responsible for the majority of UK onshore oil Onshore Licensing (see chapter 7). A 14th licensingRTQFWEVKQP CPF KU WTQRGoU NCTIGUV QPUJQTG QKN ƂGNF round is pending.Over 200 wells have been drilled. Drilling verticallyonshore then horizontally out to sea has proved Industry interest in shale gas extraction in themore cost-effective than building offshore platforms, UK includes:allowing oil to be produced beneath the Sandbanksestate, Bournemouth, from oil reservoirs 10km away. r England. Five potential shale gas explorationIn 1996, British Gas hydraulically fractured a well well sites have been identified by Cuadrilla inKP VJG NUYKEM )CU ƂGNF KP .CPECUJKTG MO HTQO Lancashire. The first test well was drilled in AugustCuadrilla’s Preese Hall well). Gas has been produced 2010 at Preese Hall; a second at Grange Hill Farmfrom it ever since. In the 1990s, several wells were later that year; and a third near the village ofalso fractured in the UK to extract coal bed methane. Banks in August 2011. Hydraulic fracturing has Shale gas extraction in the UK: a review of hydraulic fracturing 17
    • CHAP TER 1 been undertaken at only one site. DECC has also 1.8.1 UK climate change and energy security granted a license for a site in Balcombe, West The UK government has agreed to meet a number of Sussex identified by Cuadrilla. Three possible sites domestic and European targets to decarbonise the have been identified in the Mendip Hills by UK UK economy (Moore 2012). The Climate Change Act Methane and Eden Energy. Planning permission 2008 calls for an 80% reduction in greenhouse gas has been sought for boreholes for geological emissions by 2050. This includes an interim target samples. UK Methane has stated it has no interest of a 34% reduction in emissions by 2020 and a 50% in hydraulic fracturing at this stage. One site has reduction in emissions by the 2023–2027 budget been identified in Woodnesborough, Kent, by (all from a baseline of 1990). The EU has a target to Coastal Oil and Gas Ltd. Planning permission reduce EU-wide greenhouse gas emissions by 20% has been granted. Neither Cuadrilla’s West between 1990 and 2020. It has also agreed that 20% Sussex nor Coastal Oil and Gas Ltd’s Kent sites of total energy production across the EU should be have yet been granted permission for drilling or generated by renewable sources, and so the UK hydraulic fracturing. has committed to sourcing 15% of its energy from renewables. r Wales. Three sites have been identified by Coastal Oil and Gas Ltd. DECC has given permission for The House of Commons Energy and Climate Change drilling at two of these sites, but not hydraulic Committee carried out an inquiry into shale gas fracturing. Planning permission has been granted in 2011. The inquiry considered the prospects for for the sites at Neath and Maesteg where wells shale gas in the UK; risks and hazards involved; will be deepened to obtain geological samples. potential carbon footprint of large-scale shale gas Planning permission was refused at Llandow, Vale extraction; and implications for the UK of large- of Glamorgan. The decision is being appealed with scale shale gas production around the world (HoC a public inquiry.   6JG %QOOKVVGG EQPENWFGF VJCV KH C UKIPKƂECPV amount of shale gas enters the UK market (whether r Scotland. Although potential shale formations from domestic or foreign sources), it will probably do exist in Scotland, to date there has been discourage investment in more expensive, lower no interest in shale gas extraction. Consent for carbon emission renewables (HoC 2011). hydraulic fracturing has been provided to one operator with an interest in extracting coal bed Over the last decade, the UK has experienced methane. reduced domestic production from the North Sea and an increased reliance on natural gas imports. r Northern Ireland. Tamboran Resources has New pipelines from Norway and the Netherlands an interest to extract shale gas in an area that CPF NKSWGƂGF PCVWTCN ICU OCMG WR VJG FKHHGTGPEG extends across the border between Northern The House of Commons Energy and Climate Change Ireland and the Republic of Ireland. Committee also concluded that domestic resources could reduce the UK’s dependence on imports, but The Environment Agency (EA), serving England and the effect on energy security may be ‘unlikely to be Wales, has been reviewing the adequacy of existing enormous’ (HoC 2011). The UK has an open gas regulation. In 2011, the Scottish Environmental market with large new import infrastructure and a Protection Agency (SEPA) published a position diversity of potential gas suppliers (Moore 2012). statement based on its preliminary views of shale gas extraction (SEPA 2011). The Northern Ireland 1.8.2 Joint academies review Environment Agency is working with the Irish 6JG 7- )QXGTPOGPVoU %JKGH 5EKGPVKƂE #FXKUGT 5KT environmental regulator to develop a regulatory John Beddington FRS, asked the Royal Society and framework suitable for transboundary activities. the Royal Academy of Engineering to carry out an KPFGRGPFGPV TGXKGY QH VJG UEKGPVKƂE CPF GPIKPGGTKPI evidence to inform government policymaking about shale gas extraction in the UK. The following chapters analyse environmental and health and safety risks associated with the onshore extraction of shale gas.18 Shale gas extraction in the UK: a review of hydraulic fracturing
    • CHAPTER 2Surface operations (TCEVWTKPI ƃWKF allowing each stage to address local conditions,6JG ƃWKFU OQUV EQOOQPN[ WUGF HQT J[FTCWNKE such as shale thickness; presence of natural faults;fracturing are water-based. The water can be and proximity to other well systems (API 2009).abstracted from surfacewater bodies, such as rivers Operations require specialised equipment, includingand lakes, or from groundwater bodies, such as ƃWKF UVQTCIG VCPMU RTQRRCPV VTCPURQTV GSWKROGPVaquifers or public and private water sources. Sand and blending and pumping equipment. Theseis added as a proppant to keep fractures open. components are assembled and linked to monitoringVarious chemicals are also added (see Figure 3). U[UVGOU UQ VJCV CFLWUVOGPVU ECP DG OCFG VQ ƃWKFDuring multistage fracturing, a series of different XQNWOG CPF EQORQUKVKQP ƃWKF KPLGEVKQP TCVG CPFXQNWOGU QH HTCEVWTKPI ƃWKFU KU KPLGEVGF YKVJ URGEKƂE pressure.concentrations of proppant and other additives, (KIWTG  6[RKECN EQORQUKVKQP QH HTCEVWTKPI ƃWKF D[ XQNWOG UQWTEG $TKVKUJ )GQNQIKECN 5WTXG[ The 0.17% of chemical additives may include scale inhibitor to prevent the build up of scale on the walls of the well; acid to help initiate fractures; biocide to kill bacteria that can produce hydrogen sulphide CPF NGCF VQ EQTTQUKQP HTKEVKQP TGFWEGT VQ TGFWEG HTKEVKQP DGVYGGP VJG YGNN CPF ƃWKF KPLGEVGF KPVQ KV CPF UWTHCEVCPV VQ TGFWEG VJG XKUEQUKV[ QH VJG HTCEVWTKPI ƃWKF Additives 0.17% e Sand Water 5.23% d 94.60% a c b a. Scale inhibitor b. Acid c. Biocide d. Friction reducer e. Surfacant2.1.1 Disclosing the composition of QH HTCEVWTKPI ƃWKF QT YCUVGYCVGTU QPUKVG ECP DG fracturing fluid mitigated using established best practices. In theIn the USA, there are calls for operators to disclose UK, installing impermeable site lining (‘bunding’) isHWNN[ VJG EQORQUKVKQP QH HTCEVWTKPI ƃWKF CFFKVKXGU UGG typically a condition of local planning permission.section 1.4.2). This is already required in the UK. In 6JG KORCEV QH HTCEVWTKPI ƃWKF URKNNU ECP DG HWTVJGTthe UK, the environmental regulator has the power mitigated by using non-hazardous chemicalsunder the Water Resources Act 1991 to demand the where possible. In the UK, there is no generic listFKUENQUWTG QH VJG EQORQUKVKQP QH HTCEVWTKPI ƃWKFU QH CRRTQXGF EJGOKECNU HQT WUG KP HTCEVWTKPI ƃWKF The environmental regulators use a methodology2.1.2 Spills of fracturing fluid developed by the Joint Agencies Groundwater5WTHCEG URKNNU QH HTCEVWTKPI ƃWKF OC[ RQUG C ITGCVGT Directive Advisory Group to assess the hazardcontamination risk than hydraulic fracturing itself potential of any chemical to be used, according to(Groat and Grimshaw 2012). The impact of any spills VJG URGEKƂE UKVG CPF NQECN J[FTQIGQNQIKECN EQPFKVKQPU Shale gas extraction in the UK: a review of hydraulic fracturing 19
    • CHAP TER 2 2.2 Water requirements 2.2.2 Alternatives to water There are concerns that hydraulic fracturing could Another option would be to use waterless fracturing TGSWKTG XQNWOGU QH YCVGT VJCV YQWNF UKIPKƂECPVN[ ƃWKFU 6JGUG KPENWFG IGNU CPF ECTDQP FKQZKFG CPF deplete local water resources (Entrekin et al 2011). nitrogen gas foams (King 2010). These techniques are Reported estimates for the volumes of water required important where shales are susceptible to damage for shale gas extraction vary according to local from water-based fracturing (King 2010). Gelled liquid geology, well depth and length and the number of RGVTQNGWO ICU .2) HTCEVWTKPI ƃWKFU EQWNF DQQUV hydraulic fracturing stages. In the UK, under the initial production rates and allow near full recovery Water Resources Act 1991, an operator is required QH VJG HTCEVWTKPI ƃWKFU YKVJKP FC[U QH UVKOWNCVKQP to seek an abstraction permit from the environmental 6JG WUG QH VJGUG ƃWKFU RCTVKEWNCTN[ RTQRCPGDCUGF regulator if more than 20m3 of water is to be LPG, could reduce the toxicity of wastewaters since abstracted per day from surface or groundwater they do not dissolve salts, heavy metals or Naturally bodies. If water is instead sourced from a mains Occurring Radioactive Material (NORM) in shales to supply, the water company will need to ensure it can the extent that water does. still meet the conditions of the abstraction permit that it will already be operating under. 2.3 Managing wastewaters Approximately 25% to 75% of the injected fracturing Overall water use is important. Estimates indicate ƃWKF ƃQYU DCEM VQ VJG UWTHCEG YJGP VJG YGNN KU that the amount needed to operate a hydraulically FGRTGUUWTKUGF 6JKU ƃWKF KU OKZGF YKVJ OGVJCPG fractured shale gas well for a decade may be and saline water containing minerals from the shale equivalent to the amount needed to water a golf HQTOCVKQP 6JG XQNWOG QH ƃQYDCEM YCVGT FGRGPFU course for a month; the amount needed to run a on the properties of the shale, the fracturing design  /9 EQCNƂTGF RQYGT RNCPV HQT  JQWTU CPF CPF VJG V[RG QH HTCEVWTKPI ƃWKF WUGF -KPI   the amount lost to leaks in United Utilities’ region Produced water will continue to return to the in north west England every hour (Moore 2012). surface over the well’s lifetime. These wastewaters The rate of abstraction is also important. Hydraulic typically contain salt, natural organic and inorganic fracturing is not a continuous process. Water is compounds, chemical additives used in fracturing required periodically during drilling and then at each ƃWKF CPF 014/ 02%   8GT[ NKVVNG KU EWTTGPVN[ fracturing stage. Operators could consult water known about the properties of UK shales to explain utilities companies to schedule operations to avoid YJCV HTCEVKQP QH HTCEVWTG ƃWKF YKNN TGVWTP CU ƃQYDCEM periods when water supplies are more likely to be water, as well as the composition of formation under stress (Moore 2012). waters and produced water.1 2.2.1 Alternative sources of water 2.3.1 Storing wastewaters Water stress can be avoided by using alternative In the USA, wastewaters have historically been sources of water. Freshwater was necessary early stored onsite in open pits, such as excavated and in the development of certain US shales when lined containment ponds (API 2009). The possible friction reducers, scale inhibitors, and particularly leakage of liners has led to calls to avoid the use of UWTHCEVCPVU UJQYGF RGTHQTOCPEG FKHƂEWNVKGU YJGP pits in favour of closed loop steel tanks and piping mixed in saline water (King 2010). Technologies systems (Groat and Grimshaw 2012). Open storage developed to overcome these problems in offshore ponds are not permitted in the UK. Wastewaters hydraulic fracturing (where the use of seawater is are instead stored in closed metal tanks before more prevalent) are now being applied to onshore being treated. Leaks or spills of wastewaters can operations (Harris and van Batenburg 1999). The be managed in the same way as spills of fracturing use of saline water from deep aquifers is being ƃWKF UGG UGEVKQP   6JKU JCCTF KU PQV WPKSWG considered in some US shales (Yost 2011). to shale gas extraction but common to many industrial processes. 1 Contribution from Professor Richard Davies, Director of Energy Institute, University of Durham (private correspondence)20 Shale gas extraction in the UK: a review of hydraulic fracturing
    • CHAPTER 22.3.2 Reuse of wastewaters 2.3.4 Transporting wastewatersIntegrated operational practices should be adopted The transport of wastewaters offsite is carried out byto minimise water use and avoid abstracting water road haulage companies licensed by the UK’s healthfrom supplies that may be under stress. Recycling and safety regulators with experience of transportingwastewater where possible would reduce the hazardous substances. The UK’s environmentalvolumes of wastewater in need of disposal, although TGIWNCVQTU KUUWG ECTTKGT TGIKUVTCVKQP EGTVKƂECVGUit could concentrate contaminants and thereby and the Department of Transport and Vehicle andcomplicate disposal. Operator Services Agency are responsible for vehicle licensing and testing.Wastewaters can be diluted with freshwater andthen reused in subsequent fracturing operations. 2.4 Disposal of wastewatersPre-treatment may be necessary. The composition Disposal wells may be necessary if wastewaterof wastewaters changes over the lifetime of a volumes exceed the capabilities of onsite, closed-well. The most appropriate treatment will depend NQQR UVQTCIG VCPM U[UVGOU +PLGEVKQP QH YCUVG ƃWKFUon the waters’ degree of salinity (King 2010). The into porous and permeable rock formations has beenenvironment in which some shales were initially VJG RTKOCT[ FKURQUCN QRVKQP HQT YCUVG ƃWKFU HTQO VJGdeposited was marine (King 2012). Produced US oil and gas industry (DoE 2009). Disposal wellswater in the latter stages of shale gas extraction are often depleted oil and gas wells, but wells can beis more saline owing to the increased amount of FTKNNGF URGEKƂECNN[ HQT FKURQUCN KH KV KU GEQPQOKE VQ FQsaline formation water that it contains. Desalination so. The site of disposal wells depends on geologicaltechnologies are being developed to control conditions and regulation. In the USA, some wastessalinity and support reuse of wastewaters. These are transported to disposal sites by truck or pipelinetechnologies concentrate salt and recover water (DoE 2009).through evaporation, distillation, electric separationor chemical treatment. The most common treatment 2.4.1 Disposing of fluidsWUGU UGNGEVKXG OGODTCPGU VJCV ƂNVGT QWV UCNV KQPU Wastewaters are considered to be an ‘extractivewhen high pressure is applied across them. As waste’, and so are regulated under the Mining Wastewell as producing pure water, these desalination Directive. Operators are required to formulate wastetechnologies typically produce a small amount of management plans that identify how wastes are tobrine slurry that may be converted to solid waste in minimised, treated, recovered and disposed of. Thisa crystalliser before disposal (ALL Consulting 2005). includes identifying environmental and health impactsMicroorganisms, such as bacteria, can exist even and measures to address them, including control andin deep shale formations, and so may be present monitoring activities. Disposal would be regulatedin the formation water within wastewaters. These in the UK under the Mining Waste Directive andmicroorganisms need to be removed for health Water Framework Directive. An environmental permitand safety and commercial reasons. Bacterial can would be necessary, as well as pre-treatment, beforeproduce hydrogen sulphide and acids that corrode discharge into a disposal well. If wastewaters containwell casings, and so potentially contribute to well 014/ CDQXG URGEKƂGF NKOKVU C HWTVJGT RGTOKV YQWNFHCKNWTG &KUKPHGEVKQP VGEJPKSWGU KPENWFG ƂNVTCVKQP be required. The Radioactive Substances Regulationtechniques, as well as ultraviolet light, chlorine, would also apply. Currently, a disposal well would beiodine, ozone and acid treatments (ALL Consulting constructed in the UK according to the Borehole Sites2005). and Operations Regulations 1995 if the disposal well was in a mining area and to a depth of 30m or greater.Pre-treatment could take place onsite, although this Offshore disposal would involve extra environmentalis currently expensive. Technologies could build on regulations, such as those under the ConventionVJQUG CNTGCF[ WUGF VQ VTGCV YCUVG ƃWKF HTQO QHHUJQTG for the Protection of the Marine Environment of theoil and gas extraction. Alternatively, wastewaters North-East Atlantic (the OSPAR Convention).could be transported to a treatment facility offsite.Numerous facilities exist in the UK with extensiveexperience of treating similar wastes from a rangeof industrial sectors. Shale gas extraction in the UK: a review of hydraulic fracturing 21
    • CHAP TER 2 2.5 Disposal of solid wastes Shale tends to contain more uranium than other RECOMMENDATION types of rocks. The radioactive decay of uranium-238 Water should be managed in an produces radium-226 that decays to radon-222 KPVGITCVGF YC[ gas. Other NORM found in shales includes thorium and lead-210, concentrations of which vary from r Techniques and operational practices formation to formation. NORM in shales is usually at should be implemented to minimise NGXGNU UKIPKƂECPVN[ NQYGT VJCP UCHG NKOKVU QH GZRQUWTG water use and avoid abstracting water NORM dissolves in formation water, so wastewaters from supplies that may be under stress. need careful management should NORM become r Wastewater should be recycled and more concentrated during treatment (King 2012). reused where possible. Dissolved NORM may settle out to form solid wastes, such as mineral scale on the inside of wells r Options for treating and disposing of and pipes or sludge that accumulates in storage wastes should be planned from the or treatment tanks. Scale is composed primarily of outset. The construction, regulation and insoluble barium, calcium and strontium compounds siting of any future onshore disposal that precipitate out of wastewaters due to changes wells need further investigation. in temperature and pressure. Radium is chemically similar to these elements, and so is incorporated into the scales. Sludge settles out of wastewaters 2.6 Managing methane and other emissions and consists of oily solids often containing silica 8GPVKPI CPF ƃCTKPI QH OGVJCPG CPF QVJGT GOKUUKQPU compounds and barium. are controlled through conditions of Petroleum Exploration and Development Licences. The health NORM management is not unique to shale gas and safety regulator places similar controls under GZVTCEVKQP 014/ KU RTGUGPV KP YCUVG ƃWKFU HTQO VJG the Borehole Sites and Operations Regulations 1995 conventional oil and gas industries, as well as and and Offshore Installations and Wells (Design and mining industries, such as coal and potash. Much Construction) Regulations 1996. Local authorities are work has been carried out globally on monitoring responsible under the Environmental Protection Act levels of radioactivity and handling NORMs in the 1990 to inspect sites for odour and noise associated oil and gas industries. For example, it is standard YKVJ VJG XGPVKPI QT ƃCTKPI QH ICU .QECN CWVJQTKVKGU practice to sandblast pipes to remove scale or to use also have a statutory duty under the Air Quality a rotating drill bit. The removed scale is then placed in Standards Regulations 2007 to monitor emissions to sealed containers for later disposal. Scale can also be ensure they do not breach local air quality standards. removed by dissolving NORM in an aqueous solvent Methane contained in wastewater can be regulated before re-injecting the NORM-containing solution into by the environmental regulator placing controls a disposal well (ALL Consulting 2005). on operators’ waste management plans (see section 2.4.1). In the UK, solid NORM wastes fall into one of three categories: very low concentration (‘out of scope’); low The Industrial Emissions Directive would apply if concentration; medium or high concentration (requires shale gas is processed before injection into the gas an EPR permit). An environmental permit is required pipeline or combusted to generate electricity and/ for disposing of NORM wastes that exceed ‘out of or heat onsite. A permit would then be needed, UEQRGo EQPEGPVTCVKQPU &KURQUCN KP NCPFƂNN KU V[RKECN HQT requiring the operator to monitor emissions of solid wastes of low and medium concentrations. Some methane (and other air pollutants). Shale gas in offshore oil production facilities have permits allowing the UK is expected to be of high quality, so large some NORM wastes to be discharged directly to sea. scale processing may not be necessary. Operators22 Shale gas extraction in the UK: a review of hydraulic fracturing
    • CHAPTER 2should still monitor potential leakages of methaneand other emissions before, during and after shale RECOMMENDATIONgas operations. Monitoring before operations would 6Q FGVGEV RQVGPVKCN NGCMCIGU QH ICUindicate the effects of methane due to non-shale gasoperations in the area or natural seepage (methane r Operators should monitor potentialKU TGNGCUGF PCVWTCNN[ HTQO CNNWXKWO UQKNU NCPFƂNN UKVGU leakages of methane or other emissionsand peat deposits). One option would be to construct to the atmosphere before, during andsemi-permanent monitoring stations around the after shale gas operations.perimeter of a drilling site. Alternatively, emissions r The data collected by operators shouldcould be monitored near to the well. Both options be submitted to the appropriateface complications. Gas emissions would be diluted regulator. These data could informin the atmosphere before reaching monitoring wider assessments, such as the carbonstations, limiting their detection accuracy. Monitoring footprint of shale gas near to the well could be disturbed due tosurface equipment being changed at different stagesof operations. Monitoring data should be submittedto the appropriate regulator. Reliable data would beavailable to inform assessments of health impactson local populations (McKenzie et al 2012). Thesedata could also inform assessments of the carbonfootprint of shale gas extraction (see section 8.2.2).‘Green completion technologies’ are used in the USAVQ ECRVWTG CPF VJGP UGNN TCVJGT VJCP XGPV QT ƃCTG CP[ OGVJCPG CPF QVJGT ICUGU GOKVVGF HTQO ƃQYDCEMwater (DoE 2011b). These technologies separateQWV ICU YCVGT CPF UCPF KP ƃQYDCEM ƃWKF DGHQTGdirecting the recovered gas into pipelines. Methaneand carbon dioxide emissions are reduced comparedVQ XGPVKPI CPF ƃCTKPI OGVJCPG TGURGEVKXGN[ )TGGPcompletion technologies could allow emissionslevels similar to those associated with natural gasextraction (Broderick et al 2011). The EPA hasissued federal regulations making green completiontechnologies mandatory for hydraulic fracturing of allgas wells in the USA from 2015 onwards. No suchrequirements exist in the UK for exploratory activities.Consideration should be given the possible use ofgreen completion technologies, especially for anyfuture production activities in the UK, based on bestavailable technologies and operational best practices. Shale gas extraction in the UK: a review of hydraulic fracturing 23
    • CHAP TER 3 Well integrity ‘Well integrity’ refers to preventing shale gas from Well failure may arise from poor well integrity leaking out of the well by isolating it from other resulting from: subsurface formations (API 2009). The isolation is provided according to how the well is constructed. r Blowout. A blowout is any sudden and A series of holes (‘wellbores’) of decreasing diameter uncontrolled escape of fluids from a well and increasing depth are drilled and lined with steel to the surface. casing joined together to form continuous ‘strings’ of casing (see Figure 4): r Annular leak. Poor cementation allows contaminants to move vertically through the r Conductor casing. Set into the ground to a well either between casings or between casings depth of approximately 30 metres, the conductor and rock formations. casing serves as a foundation for the well and prevents caving in of surface soils. r Radial leak. Casing failures allow fluid to move horizontally out of the well and migrate into the r Surface casing. The next wellbore is drilled and surrounding rock formations. sealed with a casing that runs past the bottom of any freshwater bearing zones (including but not Figure 4 An example of a shale gas limited to drinking water aquifers) and extends all well design (DoE 2009) the way back to the surface. Cement is pumped down the wellbore and up between the casing and the rock until it reaches the surface. Conductor casing r Intermediate casing. Another wellbore is drilled and lined by an intermediate casing to isolate the Aquifer well from non-freshwater zones that may cause instability or be abnormally pressurised. The Cement casing may be sealed with cement typically either Surface casing up to the base of the surface casing or all the way to the surface. Salt water zone r Production casing. A final wellbore is drilled into the target rock formation or zone containing shale gas. Once fractured, the shale gas produces into Intermediate casing the well. This wellbore is lined with a production Cement casing that may be sealed with cement either to a safe height above the target formation up to the base of the intermediate casing; or all the way to the surface, depending on well depths and local geological conditions. Cement Production casing Production Zone24 Shale gas extraction in the UK: a review of hydraulic fracturing
    • CHAPTER 33.1 Preventing well failure 3.1.2 Preventing casing failures Once drilled, but before casings are installed and3.1.1 Preventing blowout cemented, instruments can be run down the wellboreBlowouts are rare. Blowouts can occur when drilling to detect naturally occurring (gamma) radiation andencounters an over-pressurised, highly permeable measure the density and porosity of the formationformation. Some shales can be over-pressurised, (API 2009). The diameter of the wellbore can bebut even then blowout is unlikely because shale measured using callipers so that casings are installedhas very low permeability. A recent blowout from a accurately. Once installed and prior to further drilling,Chesapeake well in Wyoming, USA, resulted from ECUKPIU CTG RTGUUWTG VGUVGF VQ GPUWTG UWHƂEKGPVgas that had leaked up from the Niobrara Shale into a mechanical integrity and strength so that they canshallower, more permeable formation. withstand pressures exerted at different phases of the well’s life, such as those exerted during the fracturingBlowouts are a major safety hazard to workers. They process (API 2009). Immediately after drilling out ofOC[ CNUQ TGUWNV KP GUECRGU QH ƃWKF KPVQ PGCTD[ UWTHCEG each casing, a formation pressure test (‘leak off test’)water. The environmental impacts of blowout depend is carried out.on (Groat and Grimshaw 2012): 3.1.3 Preventing poor cementationr timing relative to well activities (determining Cementation provides structural support, as well whether pressurised fracturing fluid or shale as isolation of different rock formations. Cements gas is released); may be tested in advance to ensure their properties meet the requirements of particular well designs (APIr whether escape is through the surface casing 2009). Cement needs to completely surround casings or deeper in the well; to provide a continuous annular seal between casings and the rock formation, as well as between casings.r the nature of the risk receptor (whether A cement bond log (CBL) is an acoustic device run freshwater aquifer or water well). inside casings to detect the presence of cement CEEQTFKPI VQ VJG CDUQTRVKQPTGƃGEVKQP QH VTCPUOKVVGFA blowout preventer (BOP) is placed at the top of a sound signals. CBL tests the quality of cementYGNN FWTKPI FTKNNKPI VQ CWVQOCVKECNN[ UJWV FQYP ƃWKF bond between casings and formation and indicatesƃQY KP VJG YGNNDQTG UJQWNF VJGTG DG CP[ UWFFGP QT KH EGOGPV JCU TGCEJGF VJG URGEKƂGF JGKIJV +H CP[WPEQPVTQNNGF GUECRG QH ƃWKFU &WTKPI RTQFWEVKQP VJG UGEVKQP QH VJG YGNN FQGU PQV OGGV KFGCN URGEKƂECVKQPUBOP is replaced with a series of valves to connect the a remedial cement job can be completed beforeYGNN VQ VJG ICU GZRQTV RKRGNKPG 6JG $12 KU VJG ƂPCN subsequent sections are drilled. Casings can beresort when a blowout occurs. When the BOP closes, similarly tested and repaired following each fracturingvulnerabilities in casing and cement below could fail, stage. Well integrity is inferred during operations byCNNQYKPI ƃWKF VQ GUECRG KPVQ UWTTQWPFKPI UWDUWTHCEG RTGUUWTG VGUVKPI 6JKU KU EQPƂTOGF D[ OQPKVQTKPIformations (an underground blowout). Proper design annular pressures, as well as testing seals and valvesto maintain subsurface well integrity remains vital. at casing joints (API 2009). Despite the quality of the initial cementation (indicated by an adequate CBL test), some wells can still leak over time. One possible explanation is the tendency of cement to shrink (Dusseault et al 2000). Cement shrinkage may be caused by one (or a combination) of several distinct mechanisms associated with drying, cooling and autogenous (sealed system) effects. A cement formulation that is resistant to one mechanism will not necessarily be resistant to another (The Concrete Society 2010). Shrinkage can reduce radial stresses, weakening cement bonds with the surrounding rock and Shale gas extraction in the UK: a review of hydraulic fracturing 25
    • CHAP TER 3 leading to circumferential cracks. These cracks In the USA, the American Petroleum Institute and can grow vertically due to resulting changes in American National Standards Institute accredited horizontal stresses and pressure gradients. Gas guidance documents exist for shale gas extraction. and other contaminants may accumulate slowly In the UK, guidelines exist for certain aspects in these cracks, enter shallow strata or even leak of hydraulic fracturing, such as proppant use, at the surface many years after production or well and guidance for directional drilling is under abandonment. Even the presence of surface casing development. Guidelines across the lifecycle provides no assurance against gas leakage at the of shale gas extraction may be required surface from the surrounding ground. The problems (Pereira 2011). of cement shrinkage and cracking over time have led to the development of new resistant cement 3.2 Improving the well examination scheme formulations (Bentz and Jensen 2004). The UK’s well examination scheme is highly valuable, allowing well designs to be reviewed by 3.1.4 Best practice for well construction specialised experts that may not be directly available Studies in North America have used well data to to the health and safety regulator. The Offshore identify key factors affecting leakage, especially the Installations and Wells (Design and Construction, number of casings and the extent to which these etc.) Regulations 1996 requires the design and casings were cemented. Some of the leaky wells In construction of offshore and onshore wells to a Canadian study had only a single casing or were be examined by an ‘independent and competent left uncased except in the section from the surface person‘(‘well examiner’). The examiner can ask for casing down to just below the aquifer (Watson and results of well integrity tests, such Bachu 2009). Others had not been cemented at all or as pressure tests and CBLs, and can raise any health the cementation had not reached the required height and safety concerns with the operator. (Watson and Bachu 2009). Several percent of older The examiner does not have the power to give oil and gas wells leaked, while fewer than 0.5% of consent to, or prohibit, activities. The examiner those constructed since 2000 according to stricter can inform the health and safety regulator if he standards were found to be leaky (Watson and KU WPUCVKUƂGF VJCV VJG QRGTCVQT JCU CFFTGUUGF Bacchu 2009). his concerns. In the USA, it is common to have two strings of The operator commissions and pays for the services casings. When intermediate casing is not installed, of the well examiner. The Offshore Installations and cementing the production casing to the surface Wells (Design and Construction, etc.) Regulations should be considered (API 2009). Intermediate 1996 states that the well examiner should be casing is not always cemented all the way back nUWHƂEKGPVN[ MPQYNGFIGCDNG CPF UGRCTCVG HTQO VJG to the surface. At a minimum, the cement should immediate line management of the well operations extend above any exposed water or hydrocarbon involved ... This might be someone employed by the bearing zones (API 2009). In some states, such as well operator’s organisation. It is important that those Pennsylvania and Texas, there is a requirement to carrying out examination work have appropriate cement casing to approximately 75 ft below any levels of impartiality and independence from aquifers. Failure to do this can lead to groundwater RTGUUWTGU GURGEKCNN[ QH C ƂPCPEKCN PCVWTG 2TQOQVKQP contamination as occurred in Pavillion, Wyoming pay and reward systems should not compromise (DiGiulio et al 2011). In the UK, standard practice professional judgement’. The guidelines should be is to have three strings of casing with at least ENCTKƂGF VQ GPUWTG VJG YGNN GZCOKPGT KU CP GORNQ[GG two (intermediate and production casing) passing of a separate company. The independence of the through and thereby isolating any freshwater zones. scheme must not be compromised. Best practice is to cement casings all the way back to the surface, depending on local geology and hydrogeology conditions.26 Shale gas extraction in the UK: a review of hydraulic fracturing
    • CHAPTER 3The Offshore Installations and Wells (Design andConstruction, etc) Regulations 1996 state that wells RECOMMENDATIONshould be designed and constructed so that ‘as 6Q GPUWTG YGNN KPVGITKV[far as is reasonably practicable, there can be noWPRNCPPGF GUECRG QH ƃWKFU HTQO VJG YGNN CPF TKUMU VQ r Guidelines should be clarified to ensurethe health and safety of persons from it or anything the independence of the well examinerin it, or in strata to which it is connected, are as low from the is reasonably practicable’. The scheme should be r Well designs should be reviewed by thewidened so that well integrity is also considered from well examiner from both a health andan environmental perspective. Wider expertise within safety perspective and an environmentalor outside of the oil and gas sector may need to be perspective.drawn on. r The well examiner should carry outDuring operations, the well examiner will receive onsite inspections as appropriate toreports for review to ensure the well is constructed ensure that wells are constructedaccording to the agreed design. Examination by according to the agreed design.paper trail is standard practice since the scheme hasits origin in reviewing offshore wells. Inspections r Operators should ensure that wellshould be made onsite as appropriate to review integrity tests are carried out asthat onshore wells are constructed according to appropriate, such as pressure tests andthe agreed design. There is currently no legislative cement bond logs.requirement for pressure tests or CBLs to be carriedout. Operators should carry out such tests as r The results of well tests and theappropriate to ensure well integrity. reports of well examinations should be submitted to the Department of EnergyThe operator keeps the reports of the well and Climate Change (DECC).examination scheme for a minimum of six monthsafter a well has been abandoned so that they areavailable for health and safety regulator to consideron request. The Department of Energy and Climate 3.3 Detecting well failureChange (DECC) already has a database that Once a well has been constructed, operators candocuments the location of wells. The results of well continue to carry out appropriate tests, such astests and the reports of well examinations should be pressure tests and CBLs, to verify well integrity duringsubmitted to DECC so that this database includes operations. Continuous monitoring of ground gasinformation about the history of every well’s integrity. emissions can also be implemented using monitoringThis would be important when addressing any wells around the well pad to detect any gas migratingpossible well failures, especially post-abandonment. outside the surface casing and into the surrounding ground. This scenario could arise from cement failure between casings, or between casings and the shale formation. Regular sampling of near surface aquifers could also detect well failure of this sort. Shale gas extraction in the UK: a review of hydraulic fracturing 27
    • CHAP TER 3 3.3.1 Methods to distinguish sources of methane 3.3.2 Adding tracers to fracture fluid Methane in shale gas is derived by two distinct Tracers can assist understanding of fracture processes that leave characteristic chemical and propagation (see section 4.1). They also provide isotopic signatures. Biogenic methane is generated evidence for determining whether hydraulic fracturing by bacteria typically in shallow anaerobic locations, has led to groundwater contamination. The distinct UWEJ CU YGVNCPFU CPF NCPFƂNN UKVGU 6JGTOQIGPKE elemental composition and isotopic signatures of methane is generated by organic matter changing ƃQYDCEM YCVGT RTQXKFG QRRQTVWPKVKGU HQT VTCEGT UVWFKGU under high temperatures and pressures over long that could indicate contamination of groundwater or time periods. Thermogenic methane can be found surface waters (Entrekin et al 2011). in both shallow and deep formations. 3.3.3 Baseline surveys of UK groundwater Biogenic shale gas consists mostly of methane, while One US study by Duke University sought to thermogenic shale gas consists of methane and other evaluate the impact of shale gas extraction on gases. The detection of higher chain hydrocarbons groundwater by analysing samples from active and (owing to the presence of other gases) can be used non-active areas of shale gas extraction (Osborn et to distinguish between biogenic and thermogenic al 2011). Methane in samples from active areas was methane (Révész et al 2010). Isotope analyses can determined to be from deep, thermogenic sources provide additional evidence. Biogenic methane has compared to methane in samples from non-active low values of the isotopes Ɂ13C and Ɂ2H. Thermogenic areas determined to be of biogenic origin. The methane has higher Ɂ13C and Ɂ2H values (Révész et al study concluded there was evidence of methane 2010). Detecting radioactive 14C can also be used as a contamination of certain aquifers overlying the distinguishing tool. Unlike biogenic gas, thermogenic Marcellus and Utica shale formations in north eastern gas does not contain 14C due to its generation from Pennsylvania and upstate New York associated deeply buried older organic material over thousands with hydraulic fracturing (Osborn et al 2011). This of years (allowing time for the radioactive carbon conclusion has been contested. An alternative isotope to decay). The isotopic values of thermogenic topographical and geological explanation has been and biogenic shale gas can be altered if they come provided (Molofsky et al 2011). The analysis of the into contact with water. Combined gas and water samples could be consistent with thermogenic analyses can be carried out to understand the origin methane from the formations overlying the Marcellus of gases in aquifers. This involves analysing both the Shale rather than from hydraulic fracturing within isotopes of carbon in the water, and the isotopes the Marcellus shale itself (Molofsky et al 2011). of hydrogen and oxygen constituting the water This highlights the importance of baseline surveys (Osborn and McIntosh 2010). Since shale gas can of naturally occurring methane and underlying be formed by both thermogenic and biogenic geological topography. In the absence of such processes, distinguishing between these two types baselines, the conclusion of the Duke University of gas is not in itself conclusive. To determine the UVWF[ KU WPXGTKƂCDNG 6JG CXCKNCDKNKV[ QH OGCUWTGOGPVU origin of methane in groundwater, its chemical and in advance of fracturing would have provided an isotopic compositions need to be compared to those objective baseline for determining whether shale of the gas extracted from nearby shale formations. gas extraction had been the source of contamination (Williams 2010). No evidence of contamination with FGGR UCNKPG DTKPGU QT HTCEVWTKPI ƃWKFU YCU HQWPF KP any of the groundwater sampling in the study.28 Shale gas extraction in the UK: a review of hydraulic fracturing
    • CHAPTER 3The British Geological Survey (BGS) has carried out samples will be taken to measure stable isotopesome work on background levels of methane in ratios to distinguish between thermogenic andUK groundwaters unrelated to shale gas extraction biogenic sources of methane (see section 3.3.1).(Goody and Darling 2005). In late 2011, BGS carried Other chemical and biological signatures useful forout a limited review of the potential impact of shale attribution purposes will also be monitored (seegas extraction on UK groundwater (Stuart 2011). BGS section 3.3.2). Groundwater residence time will beis now establishing a more comprehensive baseline measured to improve understanding of the age ofsurvey of methane in groundwater in areas likely to groundwater. Approximately 200-250 samples atbe investigated for shale gas extraction in the UK. existing boreholes are planned to be taken over6JG ƂTUV RJCUG KPXQNXGU UCORNKPI ITQWPFYCVGT CV the course of FY2012-2013 (see Figure 5). Thevarious locations in the UK, monitoring dissolved results are expected to be available before theconcentrations of methane and carbon dioxide. end of March 2013.If elevated concentrations are detected, repeat Figure 5 British Geological Survey baseline survey of UK groundwater The red circles represent locations of existing groundwater methane analyses. The grey areas highlight current onshore UK Petroleum Exploration and Development Licences. The green lines highlights areas of shale gas interest. The numbered areas are those prioritised by the British Geological Survey (BGS) where baseline surveys of UK groundwater should be carried out, according to the possible order in which shale gas activities may take place while also considering logistics and BGS’s own operational practices. 7 Areas prioritised for baseline groundwater methane survey 2 3 1 West Lancashire and Cheshire Basins 2 Northern Ireland 3 Stainmore Trough and Cleveland Basin 6 1 4 Wessex and Weald Basins 5 South Wales Coast 6 Midlands (Edale and Widmerpool Gulf; Gainsborough Trough 7 Northumberland Trough 5 4 Shale gas extraction in the UK: a review of hydraulic fracturing 29
    • CHAP TER 3 3.3.4 Detecting well failure post-abandonment DECC requires operators to submit an abandonment RECOMMENDATION plan and obtain consent before operations to 6Q FGVGEV ITQWPFYCVGT EQPVCOKPCVKQP abandon a well are commenced. Abandonment requirements are considered in the initial design of r The UK’s environmental regulators the well to ensure the well is left in a satisfactory should work with the British Geological condition to prevent future leakage. Operators are Survey (BGS) to carry out comprehensive required to design, construct and operate wells so national baseline surveys of methane that they can be suspended or abandoned in a safe and other contaminants in groundwater. manner, after which there can be no unplanned r Operators should carry out site-specific GUECRGU QH ƃWKFU 5EJQGPOCMGTU et al 2009). HSE monitoring of methane and other YQWNF DG PQVKƂGF QH VJG CDCPFQPOGPV CPF TGEGKXG contaminants in groundwater before, weekly reports of the abandonment process. The during and after shale gas operations. abandonment would also be reviewed under the well examination scheme (see section 3.2). Unless r Arrangements for monitoring abandoned there is unusual or adverse development during the wells need to be developed. Funding abandonment process, no subsequent monitoring is of this monitoring and any remediation currently required. work needs further consideration. Monitoring arrangements should be developed r The data collected by operators should to detect possible well failure post abandonment. be submitted to the appropriate Continuous ground gas monitoring and aquifer regulator. sampling could be similar to that carried out before and during fracturing operations. Temporary monitoring equipment could be used, such as that WUGF VQ OQPKVQT GOKUUKQPU HTQO NCPFƂNN UKVGU QT even semi-permanent monitoring stations could be installed. Monitoring would be at a reduced frequency, perhaps every few years. This requires techniques that can reliably distinguish between methane from non-shale operations in the areas of abandoned wells. Operators are responsible for wells once abandoned. Operators have an open-ended liability to remediate any ineffective abandonment operations. Consideration should be given to establishing mechanisms, such as a common liability fund, to ensure funds are available to respond to well failure post-abandonment in the ECUG VJCV VJG QRGTCVQT ECP PQ NQPIGT DG KFGPVKƂGF30 Shale gas extraction in the UK: a review of hydraulic fracturing
    • CHAPTER 4Fracture propagation4.1 Monitoring fractures CV JKIJGT VGORGTCVWTG VJCP HTCEVWTKPI ƃWKF CV VJGOperators have an incentive to carefully monitor and UWTHCEG  %QQNKPI FWG VQ VJG KPLGEVGF ƃWKFU ECP DGensure fractures propagate in a controlled manner detected to provide extra data about the fracturingand remain within the target shale formation (see RGTHQTOCPEG (NWKF ƃQY CPF FGPUKV[ ECP CNUQ DGFigure 6). Excessive, uncontrolled fracture growth measured to identify perforation intervals thatis uneconomic, wasting resources on the extra EQPVTKDWVG VQ ƃQYDCEMchemicals, pumping equipment and manpowerneeded. Various methods are available to monitor The most successful monitoring techniques havefracture growth before, during and after operations been tiltmeters and microseismic monitoring.(Bennett et al 2006). Chemical tracers can be added Tiltmeters detect microdeformation in surroundingVQ HTCEVWTKPI ƃWKF 6JG RGTHQTOCPEG QH VJG HTCEVWTKPI rock that radiates outwards as fractures open.process stage by stage can be inferred from the Tiltmeters can be placed in an array of shallowEQPEGPVTCVKQP QH URGEKƂE VTCEGTU EQODKPGF YKVJ VJG boreholes or in monitoring wells at depths toTGEQXGT[ VKOG CPF XQNWOGU QH ƃQYDCEM YCVGT 6JG estimate fracture geometry. Seismometers candilution of the tracers can improve understanding of DG RNCEGF KP UKOKNCT EQPƂIWTCVKQPU VQ FGVGEVHTCEVWTG ƃWKF NQUU CPF ƃQYDCEM GHƂEKGPE[ 2TQRRCPV microseismic events created as energy is releasedcan be tagged with a radioactive tracer. Detection of when each fracture opens. These events typicallyVJG VTCEGTU ECP EQPƂTO YJGVJGT RTQRRCPV YCU RNCEGF have a magnitude less than -1.5 ML (see Figure 6, C).as intended and identify leakage points (King 2010). Advances in tiltmeter and microseismic sensitivityAn alternative is to rely on naturally occurring isotopic and computer processing allow fracturing to besignatures. Many shale formations contain elevated monitored in three dimensions and in real time (APIlevels of naturally occurring radioactive materials 2009). These data allow fracturing models to be(NORMs), such as isotopes of radon and radium TGƂPGF CPF HWVWTG VTGCVOGPVU VQ DG QRVKOKUGF(Genereux and Hemond 1990). Shale formations are Figure 6 Microseismic monitoring of a typical hydraulic fracturing operation in the Barnett Shale, Texas, USA (Zoback et al 2010). ‘A’ displays a horizontal view of microseismic events along the horizontal well. The thick black line represents the horizontal well. Note that the vertical axis does not begin at the surface but at depth (5120 feet). Each dot represents a separate microseismic event. Each colour represents a distinct fracturing event. ‘B’ displays a cross sectional view of the microseismic events. ‘C’ displays the distribution of these microseismic events by magnitude. A Horizontal distance (feet) 0 500 1000 1500 2000 2500 3000 3500 4000 4500 5000 5120 5320 Depth below surface (feet) 5520 5720 Barnett Shale 5920 6120 Shale gas extraction in the UK: a review of hydraulic fracturing 31
    • CHAP TER 4 B Horizontal distance (feet) -1000 800 600 400 200 0 200 400 600 800 1000 5120 5320 Depth below surface (feet) 5520 5720 Barnett Shale 5920 6120 C Cumulative number of microseismic events (log sscale) 1000 100 10 1 -3.1 -3 -2.9 -2.8 -2.7 -2.6 -2.5 -2.4 -2.3 -2.2 -2.1 -2 -1.9 -1.8 -1.7 -1.6 -1.5 -1.4 Magnitude (ML) 4.2 Constraining fracture growth maximum principal stress, and hence the direction of fracture propagation, tends to be vertical. At 4.2.1 Geological stresses shallower depths, where the direction of maximum )GQNQIKECN UVTGUUGU CTG VJG OQUV UKIPKƂECPV UQWTEG QH principal stress tends to be horizontal, fractures will constraint on fracture growth (Fisher and Warpinski tend to propagate more horizontally (see Figure 7). 2012). Fractures propagate perpendicularly to the The directions of maximum and minimum stress direction of least principal stress, following the vary across the UK (Baptie 2010). Characterising the direction of maximum principal stress (API 2009). stresses at a prospective site for shale gas extraction The weight of the overlying rock formations is one is an important mseans of determining the direction component of the total geological stress. This weight in which fractures will tend to propagate. increases with depth, meaning that the direction of32 Shale gas extraction in the UK: a review of hydraulic fracturing
    • CHAPTER 4 Figure 7 The relationship between depth and orientation of fracture growth in sedimentary formations (Fisher and Warpinski 2012) CEJ RQKPV QP VJG ƂIWTG TGRTGUGPVU C UGRCTCVG HTCEVWTG treatment from more than 10,000 fractures mapped using tiltmeters throughout the past decade in numerous sedimentary formations (including shale) across North America. Each point is plotted against depth and percentage of horizontal component. The red line shows the average of all fractures. 0% horizontal component represents a purely vertical fracture. 100% would be a purely horizontal fracture. 0 2000 4000 6000 Depth (feet) 8000 10000 12000 14000 16000 0 10 20 30 40 50 60 70 80 90 100 Percentage horizontal component4.2.2 Well pressure induced fracture network is desirable to maximise theIt may be theoretically possible to create a pressure fracture surface area so that as much gas as possiblethat could overcome geological stresses so that a YKNN ƃQY QWV QH VJG UJCNG KPVQ VJG YGNN %QORNGZKV[fracture could grow vertically to shallow depths or KU KPƃWGPEGF VJTQWIJ QRGTCVKQPCN OGCPU UWEJ CUeven the surface. Practically, this is not feasible. The UNQYN[ KPETGCUKPI VJG TCVG QH ƃWKF KPLGEVKQP YJKEJXQNWOG QH ƃWKF KPLGEVGF FWTKPI QRGTCVKQPU KU UKORN[ also helps to keep fractures within the formation zoneKPUWHƂEKGPV D[ QTFGTU QH OCIPKVWFG VQ ETGCVG VJGUG -KPI   %QORNGZKV[ KU CNUQ KPƃWGPEGF VJTQWIJpressures. Even then, such an enormous pressure natural mechanisms. Intersection with local structuralEQWNF PQV DG UWUVCKPGF .GCM QHH QH ƃWKF YQWNF UQQP features can be a strong determinant of fracturereach a point where the leak off rate would equal the growth (King 2010). Layers with different materialinjection rate. The fracture simply could not grow any properties, such as strength and shear modulusfurther (King 2010, Fisher and Warpinski 2012). (elastic stiffness), support complex growth. Weak interfaces and discontinuities between layers or even4.2.3 Geological structure slippage along the layers can blunt, kink, bifurcateModels of fracture propagation often assume and terminate growth. Should fractures enter higherthat the geological layers through which fractures RGTOGCDKNKV[ NC[GTU ƃWKF OC[ NGCM QHH KPVQ VJGpropagate are homogenous, depicting fractures as formation, stunting fracture growth further.single linear or planar cracks. However, the structureof overlying geology is heterogeneous, giving riseto fractures of a more complex, branching nature(Fisher and Warpinski 2012). Complexity in the Shale gas extraction in the UK: a review of hydraulic fracturing 33
    • CHAP TER 4 4.3 Hydraulic fracturing below aquifers 4.3.2 Evidence of fracture height growth US microseismic data shows that fractures created 4.3.1 Groundwater permits by hydraulic fracturing are very unlikely to propagate 6JG KPLGEVKQP QH HTCEVWTKPI ƃWKFU KPVQ UJCNGU KU vertically more than one kilometre (see Figure 8). One regulated in the UK under the Water Framework recent UK study examined vertical fracture growth Directive and Environmental Permitting Regulations DCUGF QP FCVCUGVU QH TGEQTFGF PCVWTCN CPF CTVKƂEKCNN[ (EPR) 2010. The environmental regulator is created fracture growth from the USA, Europe and responsible for deciding whether this activity Africa (Davies et al 2012). The maximum vertical poses a contamination risk to groundwater and if JGKIJV QH CTVKƂEKCNN[ ETGCVGF HTCEVWTGU GZCOKPGF KP VJKU an environmental permit is necessary to set limits study was less than 600m. The height of only 1% of on the activity to manage the risk to an acceptable these fractures was greater than 350m (see Figure level. If an activity poses an unacceptable risk, the 9). The vertical height of most of natural fractures activity would be prohibited. Cuadrilla’s fracturing examined in this study was between 200-400m. Very at the Preese Hall site was deemed to pose no risk, few natural fractures extended beyond 700m, and it so an environmental permit was not deemed to be was extremely rare that any extended beyond 1000m. necessary. The nearby Sherwood aquifer is saline and It is not clear that these natural fractures propagate not connected to, or used for, public water supplies. by the same mechanisms as engineered hydraulic The nearest sensitive groundwater is many kilometres fractures, although there may be similarities. away. Should Cuadrilla’s operations change, the environmental regulator would reassess whether the The largest vertical growth may arise when fractures new activities posed a risk and if an environmental intercept faults. Even then, faults do not assist permit would be required. propagation in an unconstrained way. Some conclude that rather than being ‘open’ and providing a pathway At present, the environmental regulator does not permit towards the surface, faults in shales must be closed. fracturing below freshwater aquifers. If this policy Were faults ‘open’, any gas present would have were to change, consideration should be given to: escaped over geological time, leaving no resource to exploit (Fisher and Warpinski 2012). This explanation r composition of the fracturing fluids may hold for conventional hydrocarbons where (see section 2.1); faults have been found to cut through ‘sealing units’ (assemblages of low permeability rock that halt or r well design (see Chapter 3); TGVCTF VJG ƃQY QH J[FTQECTDQPU  VJGTGD[ EQPFWEVKPI ƃQY QXGT IGQNQIKECN VKOGUECNGU %CTVYTKIJV et al r evidence of fracture height growth; 2007). This explanation does not necessarily apply r hydrogeological conditions for fluid flow; to shale gas. The low permeability of shale means VJCV ICU FQGU PQV ƃQY YKVJQWV UWKVCDNG RTGUUWTG r site specific geology of UK shales; conditions even in the presence of an ‘open’ fault. This is why shale needs to be hydraulically fractured r better understanding of UK shales and to stimulate gas production. overlying geology;34 Shale gas extraction in the UK: a review of hydraulic fracturing
    • CHAPTER 4Figure 8 Comparisons of fracture growth and depth of overlying water sources (aquifers orwater wells) (Fisher and Warpinski 2012) CEJ QH VJG HQWT ƂIWTGU KNNWUVTCVGU HTCEVWTG JGKIJV HQTfracture treatments performed in four major US shale formations between 2001 and 2010. The depthof each fracture treatment is illustrated by the yellow line and sorted by depth. The red spikes representVJG GZVGPV QH WRYCTF CPF FQYPYCTF HTCEVWTG ITQYVJ 6JG FCTM DNWG DCTU CV VJG VQR QH GCEJ ƂIWTGillustrate the depth of overlying water sources. Barnett Shale 0 2000 4000 Depths (ft) 6000 8000 1000 Fracture stages Woodford Shale 0 2000 4000 6000 Depths (ft) 8000 1000 12000 14000 Fracture stages Shale gas extraction in the UK: a review of hydraulic fracturing 35
    • CHAP TER 4 Marcellus Shale 0 2000 Depths (ft) 4000 6000 8000 Fracture stages Eagle Ford Shale 0 2000 4000 Depths (ft) 6000 8000 1000 12000 14000 Fracture stages36 Shale gas extraction in the UK: a review of hydraulic fracturing
    • CHAPTER 4 Figure 9 Frequency of fracture height for artificial and natural fractures (A) and probability of fracture height not being exceeded (non-exceedance) for artificial (stimulated) and natural fractures (B) (Davies et al 2012) A B 1 Probability of non exceedance 0.8 Stimulated Stimulated Frequency (upward vertical growth) 0.6 (upward vertical growth) Stimulated Stimulated 0.4 (downward vertical growth) (downward vertical growth) Natural Natural 0.2 0 0 200 400 600 800 0 200 400 600 800 1000 Fracture height (metres) Fracture height (metres)4.3.3 Hydrogeological conditions for fluid flow oil). These zones may be drilled into and fractured,The very unlikely event of fractures propagating leaving overlying thicknesses of impermeable,all the way to overlying aquifers would provide a un-fractured shale undisturbed.RQUUKDNG TQWVG HQT HTCEVWTG ƃWKFU VQ ƃQY *QYGXGTsuitable pressure and permeability conditions would There are approximately nine Lower CarboniferousCNUQ DG PGEGUUCT[ HQT ƃWKFU VQ ƃQY ;QWPIGT   shale basins of particular interest to shale gas5WHƂEKGPVN[ JKIJ WRYCTF RTGUUWTGU YQWNF DG TGSWKTGF extraction in northern England, including theduring the fracturing process and then sustained Bowland, Edale, Widmerpool and Gainsboroughafterwards over the long term once the fracturing troughs, as well as the Liassic (Lower Jurassic) andRTQEGUU JCF EGCUGF +V KU XGT[ FKHƂEWNV VQ EQPEGKXG Kimmeridge Clay (Upper Jurassic) of the Wessexof how this might occur given the UK’s shale gas and Weald Basins in southern England.2 Thehydrogeological environments. Even if this were the Lower Carboniferous Shale in the Bowland basin iscase, the permeability of the fractures would still approximately 800m thick, although the organic richneed to be similar to that of the overlying aquifer potential source rock is probably 250m thick (seeHQT CP[ UKIPKƂECPV SWCPVKV[ QH ƃWKF VQ ƃQY +P TGCNKV[ Table 2). It is overlain by a formation of siltstones andthe permeability of the aquifer is likely to be several mudstones (the Manchester Marl) between 180morders of magnitude greater than the permeability of and 300m thick that acts as an impermeable seal.VJG HTCEVWTGU 7RYCTF ƃQY QH ƃWKFU HTQO VJG QPG QH Above the Manchester Marl lie sandstone formations.shale gas extraction to overlying aquifers via fractures Although they contain water, these formations arein the intervening strata is highly unlikely. located beneath another impermeable formation (the Mercia Mudstone) that is between 100m and4.3.4 Site-specific geology of UK shales 500m thick. Thickness of UK shales Depth of UK shalesIn a typical situation, a shale formation may have a Shale gas is likely to be extracted at depths of manygross thickness of several hundred metres within hundreds of metres or even several kilometres towhich there may be a net interval of one or more GPUWTG TGUGTXQKT RTGUUWTGU UWHƂEKGPVN[ JKIJ VQ CNNQYorganic-rich zones that may generate shale gas (or ICU VQ ƃQY VQ VJG UWTHCEG (TCEVWTKPI QH VJG $QYNCPF Shale (Cuadrilla’s target for shale gas extraction2 Contribution from Professor Al Fraser, Chair in Petroleum Geosciences, Imperial College London Shale gas extraction in the UK: a review of hydraulic fracturing 37
    • CHAP TER 4 in Lancashire) took place at depths of 1700m and and Formby, and gas seeps at Stoureton, Wigan and 3100m. Extracting shale gas from much shallower Abbeystead. Apart from Abbeystead, these seeps shales is unlikely since reservoir pressures would be have been geochemically matched with the Bowland VQQ NQY HQT ICU VQ ƃQY CV EQOOGTEKCN TCVGU 5JCNGU Shale (Harriman and Miles 1995). Gas seeping at containing gas are exposed at the surface in places. locations (other than Abbeystead) is thermogenic Some 200 natural oil and gas seeps are known across rather than biogenic (HMSO 1985). the UK (Selley 1992). There are oil seeps in Liverpool Table 2 Thickness and depth of UK shales of interest to shale gas extraction (Harvey and Gray 2010) (QTOCVKQP VJKEMPGUUGU CPF FGRVJ XCT[ YKFGN[ CETQUU DCUKPU UQ CNN VJKEMPGUU CPF FGRVJ ƂIWTGU CTG generalised values. In A, ‘gross thickness’ refers to the entire shale and ‘net thickness’ refers to that part of the shale of particular interest for shale gas extraction (where known). In B, ‘gross thickness’ includes impermeable and permeable strata. ‘Net thickness’ refers to impermeable strata. A Shales of interest in the UK B Strata overlying these shales Depths at Shale Depths at Thickness of which these thickness which these strata shales are these strata located are located JURASSIC Upper Jurassic, 400 - 75m 600m gross Weald Clay Surface - 1000m 900m gross Kimmeridge 150m net 600m net Clay of the Weald basin Lower Jurassic Surface - 2000m 150m gross Oxford Clay and Surface - 2000m 660m gross Lias of the Kimmeridge 600m net Wessex basin Clay (where preserved) CARBONIFEROUS Bowland 1700 - 3100m 800 gross Bowland Shale 3500m - surface 700m trough 250m net and Manchester (MM only) (MM only) Marl (MM) Edale trough Surface - 5000m 2000m gross Edale (Bowland 5000m - surface >2000m gross equivalent) and 1500m net Namurian shales Widmerpool 1000 - 4000m 3000 gross Bowland 4000m - 500m >3000m gross trough equivalent and 2500m net Namurian shales Gainsborough 200 - 4500m 2000 gross Bowland 2000m 1000m gross trough equivalent and 500m net Namurian shales38 Shale gas extraction in the UK: a review of hydraulic fracturing
    • CHAPTER 44.3.5 Better understanding of UK shales and has produced an extensive literature on their overlying geology geomechanical and transport properties. In Europe, the waste management organisations Andra (France),6JGTG KU C NCEM QH FCVC QP VJG OGEJCPKECN CPF ƃQY Nagra (Switzerland) and Ondraf Niras (Belgium)properties of shales, such as permeability and gas have active research programmes examining themigration potential. The majority of data has been Callovo-Oxfordian Claystone, Opallinus Clay andcollected during hydraulic fracturing operations (King Boom Clay, respectively, as candidate geologies for2010). Relatively little research has been undertaken the disposal of radioactive waste. These organisationson how hydraulic fracturing could affect the rate at have extensive databases covering permeability,which contaminants migrate vertically from shale strength and rock deformation properties. Theseformations (Myers 2012). Characterising shale to target formations are generally claystones withbetter understand its behaviour before, during no silt or sandstone component, and so are notCPF CHVGT J[FTCWNKE HTCEVWTKPI TGOCKPU FKHƂEWNV direct analogues of the target formations for shaleWhen measuring the mechanical properties of gas extraction.shale, experimental measurements need to takeinto account the elevated pressure and change The British Geological Survey is developing ain temperature at depth. The low permeability of hydrogeological model to gain a better understandingshale means that coupled mechanical and hydraulic of the depth of potential shale gas reservoirs andexperiments tend to take a long time to complete. location of any overlying aquifers. BGS is also investigating the properties of the intervening rockResearch into the properties of clay-rich rocks that will control the movement of water, such asas potential sites for radioactive waste disposal permeability, porosity and fracture density. Shale gas extraction in the UK: a review of hydraulic fracturing 39
    • CHAP TER 5 Induced seismicity 5.1 Natural seismicity 5.2 Seismicity induced by coal mining UK seismicity is low by world standards. Historical A subset of seismic events in the UK is related to records suggest that the largest seismic events in the coal mining activities or the settlement of abandoned UK are likely to be less than magnitude 5 ML, causing mine workings. Seismicity induced by coal mining limited damage at the surface (see Table 1). On average, is generally smaller than naturally occurring the UK experiences seismicity of magnitude 5 ML every seismicity, perhaps no greater than magnitude twenty years, and of magnitude 4 ML every three to 4ML (see Figure 10). four years (Green 2012). Most seismic events in the UK occur at depths of over 10km, limiting the extent to which they are felt at the surface. No onshore seismicity in the UK is known to have produced a surface rupture. Figure 10 Natural seismicity (red) and coal mining-induced seismicity (green) in the 7- HTQO  VQ  5QWTEG $TKVKUJ )GQNQIKECN 5WTXG[ Magnitude > 5.0 ML 4.0 – 4.9 ML 3.0 – 3.9 ML 2.0 – 2.9 ML < 2.0 ML 1 640 Shale gas extraction in the UK: a review of hydraulic fracturing
    • CHAPTER 55.3 Seismicity induced by hydraulic fracturing Cuadrilla suspended its hydraulic fracturingThere are two types of seismicity associated with operations at the Preese Hall well and commissionedhydraulic fracturing. Microseismic events are a a set of reports to investigate the cause of theroutine feature of hydraulic fracturing and are due to seismic events (de Pater and Baisch 2011). DECCthe propagation of engineered fractures (see Chapter also commissioned an independent report into the4). Larger seismic events are generally rare but can events (Green et al 2012). Both reports attributebe induced by hydraulic fracturing in the presence of the two seismic events to Cuadrilla’s fracturinga pre-stressed fault. operations. The most likely cause of the events was VJG VTCPUOKUUKQP QH KPLGEVGF ƃWKF VQ C PGCTD[ DWVThe energy released during hydraulic fracturing is RTGXKQWUN[ WPKFGPVKƂGF RTGUVTGUUGF HCWNV TGFWEKPIless than the energy released by the collapse of the effective stress to the point where the faultopen voids in rock formations, as occurs during slipped and released its stored energy (de Patercoal mining. The intensity of seismicity induced by and Baisch 2011; Green et al 2012). The energyhydraulic fracturing is likely to be smaller due to released was several orders of magnitude greaterthe greater depth at which shale gas is extracted than the microseismic energy associated withcompared to the shallower depth of coal mining. routine hydraulic fracturing.Magnitude 3 ML may be a realistic upper limit forseismicity induced by hydraulic fracturing (Green Analysis of the seismic data suggests that the twoet al 2012). If a seismic event of magnitude 3 ML events were due to the reactivation of a pre-stressedoccurs at depths of 2-3km, structural damage at HCWNV +P VJG CDUGPEG QH HWTVJGT FCVC KV KU FKHƂEWNV VQthe surface is unlikely. determine whether the fault was directly intersected by the well, or whether hydraulic fracturing led toOn 1st April 2011, the Blackpool area experienced pressure changes that induced a distant fault toa seismic event of magnitude 2.3 ML shortly after slip. Subsequent geomechanical tests suggest thatCuadrilla’s Preese Hall well in the Bowland Shale bedding planes in the Bowland Shale are weakwas hydraulically fractured. Another seismic event enough to have slipped and provided a conduit forof magnitude 1.5 ML occurred on 27th May 2011 ƃWKF VQ ƃQY QWV QH VJG YGNN CPF KPVQ VJG HCWNV QPGfollowing renewed hydraulic fracturing of the same (de Pater and Baisch 2011).well. These events were detected by the BritishGeological Survey’s national seismic network (seeTextbox 3). The Blackpool region is an area of lownatural seismicity even by UK standards. In 1970, aseismic event of magnitude 2.5 ML occurred 5 kmsouthwest of Blackpool. The 3.7 ML Ulverston seismicevent on 28th April 2009 was also felt in the region.Historically, the largest seismic event in the regionwas of magnitude 4.4 ML near Lancaster in 1835with a maximum intensity of 6 EMS. Shale gas extraction in the UK: a review of hydraulic fracturing 41
    • CHAP TER 5 5.4 Factors affecting seismicity induced by The pressure in the well is also a key determinant of hydraulic fracturing induced seismicity, and is affected by: 5.4.1 Fault and shale properties r The volume of injected fluid. Larger volumes The properties of shale provide natural constraints generate higher pressures. on the magnitude of seismicity induced by hydraulic fracturing. Different materials require different r The volume of flowback fluid. Larger flowback amounts of energy to break. Shale is relatively weak. volumes reduce the pressure. Stronger rocks will generally allow more energy to build up before they break, generating seismic events r The injection rate. More rapid injection of larger magnitude. generates higher pressures. The magnitude of induced seismicity is also r The flowback rate. More rapid flowback reduces determined by the properties of the fault, namely: the pressure. r The surface area. The larger the fault, the greater Although six fracturing stages were planned at the seismicity. 2TGGUG *CNN %WCFTKNNC QPN[ EQORNGVGF ƂXG DGHQTG ceasing its operations. Seismicity was only induced r The degree to which the fault is pre-stressed. following hydraulic fracturing stages where larger The more pre-stressed the fault, the greater the XQNWOGU QH ƃWKF YGTG KPLGEVGF CPFQT YJGTG VJGTG seismicity. YCU NKVVNG QT PQ ƃQYDCEM QH ƃWKFU FG 2CVGT CPF Baisch 2011). Stages 2 and 4 were associated with 5.4.2 Pressure constraints the 2.3 ML and 1.5 ML seismic events, respectively. The magnitude of seismicity induced by hydraulic 6JG[ KPXQNXGF TGNCVKXGN[ NCTIG XQNWOGU QH KPLGEVGF ƃWKF fracturing is affected by pressure changes in the CPF NKVVNG KH CP[ ƃQYDCEM 5VCIG  KPXQNXGF C UOCNNGT shale formation near to the well. The hydraulic XQNWOG QH KPLGEVGF ƃWKF CPF CP KPETGCUGF ƃQYDCEM fracturing process fundamentally constrains these TCVG 5VCIG  KPXQNXGF JKIJ XQNWOGU QH KPLGEVGF ƃWKF pressure changes (Zoback 2012): DWV KPXQNXGF ƃQYDCEM TCVGU VJCV NKOKVGF VJG UGKUOKEKV[ induced (see Figure 11). Controlling the pressure in r Pressurisation takes place across a limited volume the well is an important measure to mitigate induced of rock, typically only a few hundred metres in any seismicity. Feeding seismic monitoring data back to direction. operations allows the injection volume and rate to be TGFWEGF CPF VJG ƃQYDCEM XQNWOG CPF TCVG KPETGCUGF r Pressurisation only takes place over a limited timescale, typically only a few hours. r Pressure dissipates into the surrounding geology as more fractures are created, limiting the pressure that can build up.42 Shale gas extraction in the UK: a review of hydraulic fracturing
    • CHAPTER 5 Figure 11 The relationship between injection volume (yellow line), flowback volume (red line) and magnitude of induced seismicity (circles) (de Pater and Baisch 2011). 6JG ƂIWTG UJQYU CNN ƂXG HTCEVWTKPI UVCIGU CV 2TGGUG *CNN /QTG UOCNN GXGPVU YGTG TGEQTFGF KP May because the monitoring system was improved with local stations. 60000 3 50000 2 40000 1 Volume (bbl) Magnitude 30000 0 of induced seismicity (ML) 20000 -1 10000 -2 0 -3 25/03/11 01/04/11 08/04/11 15/04/11 22/04/11 29/04/11 06/05/11 13/05/11 20/05/11 27/05/11 03/06/11 Date & time5.5 Mitigating induced seismicity faults. Site characterisations could include desk- based studies of existing geological maps, seismic5.5.1 Geological surveys to characterise TGƃGEVKQP FCVC DCEMITQWPF UGKUOKEKV[ FCVC HTQO VJG stresses and identify faults BGS. Stress data are relatively complicated to collectFaults are ubiquitous in the Earth’s crust. In many and many techniques require a borehole to be drilled.areas of the UK, only the largest faults have been Operators are likely to collect stress data as a mattermapped, and then only at the surface. Predicting of course. Stresses are a strong determinant of wellthe presence of subsurface faults requires detailed design and fracturing strategy.surface mapping, development of validatedgeological models, and if available, the data from Operators should not overlook the potential presenceUGKUOKE TGƃGEVKQP UWTXG[U *GPPKPIU et al 2012). of faults that cannot be detected given the limits of6JGTG CTG KPUWHƂEKGPV FCVC QP HCWNVU KP VJG $QYNCPF UGKUOKE TGƃGEVKQP UWTXG[ 6JGUG UOCNN HCWNVU YKNN JCXG5JCNG VQ UWRRQTV C FGƂPKVKXG EQPENWUKQP CDQWV caused geological strata to slip less than 10m relativewhether seismic events similar to those at Preese to one another. There is no reliable way of detectingHall might occur in the future (Green et al 2012). them but it may be possible to statistically predict theExtensive areas of the Bowland Shale have not been presence of such faults (Rotevatn and Fossen 2011).OCRRGF D[ UGKUOKE TGƃGEVKQP UWTXG[U 6JG UGKUOKE These faults tend to have relatively small surfaceTGƃGEVKQP UWTXG[ NKPG PGCTGUV VQ 2TGGUG *CNN KU C HGY areas so are less likely to lead to seismic events thatkilometres away. For those faults already mapped by can be felt at the surface.UGKUOKE TGƃGEVKQP UWTXG[U OQTG FCVC CTG PGGFGF QPtheir mechanical properties and permeabilities. Data 1PEG HCWNVU JCXG DGGP KFGPVKƂGF CPF IGQNQIKECNare also needed in other prospective areas where no stresses characterised, operators can draw on well-UGKUOKE TGƃGEVKQP FCVC EWTTGPVN[ GZKUV understood tools used in the oil and gas and mining industries to assess the orientation and slip tendencyThe BGS or other appropriate bodies should carry out of faults and bedding planes (Hennings et al 2012,national surveys to characterise stresses and identify Lisle and Srivastava 2004, Morris et al 1996, Rutqvistfaults in UK shales. Operators should also carry out et al 2007). Hydraulic fracturing near a fault with aUKVGURGEKƂE UWTXG[U RTKQT VQ J[FTCWNKE HTCEVWTKPI high slip tendency should be characterise local stresses and identify nearby Shale gas extraction in the UK: a review of hydraulic fracturing 43
    • CHAP TER 5 5.5.2 Pre-fracturing injection test 6TCHƂE NKIJV OQPKVQTKPI U[UVGOU UJQWNF DG +V KU FKHƂEWNV VQ RTGFKEV GZCEVN[ YJCV YKNN JCRRGP KP C implemented in the UK for shale gas extraction. particular shale formation once hydraulic fracturing The Cuadrilla-commissioned report into the seismic commences. The fracture behaviour of a particular events at Preese Hall suggested the following formation is commonly characterised using small thresholds (de Pater and Baisch 2011): pre-fracturing injection tests with microseismic monitoring. Subsequent operations can then be r Magnitude smaller than 0 ML. OQFKƂGF CEEQTFKPIN[ #2+   # TGCUQPCDNG RGTKQF Regular operations. of time should be allowed to elapse following a pre- fracturing injection test to ensure no seismic activity r Magnitude between 0 and 1.7 ML. QEEWTU CU VJG KPLGEVGF ƃWKF FKHHWUGU CYC[ HTQO VJG Continue monitoring after injection for at least well and pressure changes in surrounding rock two days until the seismicity rate falls below formations are redistributed (Green et al 2012). one event per day. 5.5.3 Traffic light monitoring systems r Magnitude greater than 1.7 ML. Enhanced Geothermal Systems (EGS) use methods, Stop injection and employ flowback, while such as hydraulic fracturing, to enhance the recovery continuing monitoring. of heat by increasing the permeability of rock that is hot but has low permeability (Majer et al 2007). Had the above thresholds been in place for Cuadrilla’s 6JG KPLGEVKQP QT UWDUGSWGPV EKTEWNCVKQP QH ƃWKFU operations, no mitigating action would have been can change stress patterns in the rock, inducing taken preceding the 2.3 ML event on 1st April 2011 seismicity. EGS in Basel, Switzerland has been (Green et al 2012). The report commissioned by the associated with induced seismicity as large as Department of Energy and Climate Change (DECC) magnitude 3.5 ML (Bachmann et al 2011). into the seismic events at Preese Hall proposed a more precautionary set of lower magnitude 6TCHƂE NKIJV OQPKVQTKPI U[UVGOU CTG KORNGOGPVGF CU thresholds (Green et al 2012). best practice in EGS. Data are fed back to operations so that action can be taken to mitigate induced seismicity (Majer et al 2007): r Green. Injection proceeds as planned. r Amber. Injection proceeds with caution, possibly at reduced rates. Monitoring is intensified. r Red. Injection is suspended immediately.44 Shale gas extraction in the UK: a review of hydraulic fracturing
    • CHAPTER 56JG VJTGUJQNFU QH VTCHƂE NKIJV OQPKVQTKPI U[UVGOU 5.6 Damage to well integrityPGGF PQV DG OCIPKVWFGDCUGF 04%   6TCHƂE Discussions about the magnitude of seismicitylight monitoring system thresholds used in EGS induced by hydraulic fracturing often focus on theare based on ground motions, focusing on peak limited (if any) damage at the surface. Attentionground acceleration and velocity in conjunction with should also be given to any damage to well integrity.frequency (Majer et al 2007). Other industries that Tests carried out after Cuadrilla’s second fracturinggive rise to ground motion, such as construction, stage and 2.3 ML seismic event revealed deformationquarrying and mining, are regulated by maximum of the Preese Hall well casing. The extent of the wellvibration levels rather than maximum magnitude casing deformation at Preese Hall was greater thanlevels. A small event close to a structure can be just 0.5 inches over a depth range between 8480 andas disruptive in terms of vibration as a large event 8640 feet (de Pater and Basich 2011). Because offurther away (Majer et al 2008). Ground motion its location deep in the well and within the alreadysystems have been developed by the Dutch oil and heavily perforated section of casing, this deformationgas industry, government and research communities was considered to pose no more risk to the integrityto mitigate induced seismicity (van Eck et al 2006). of higher sections of the well than the perforations themselves (Green et al 2012).6TCHƂE NKIJV OQPKVQTKPI U[UVGOU CTG NKOKVGF D[the need for, and expense of, real-time seismic DECC should consider the conditions under whichmonitoring. These systems also rely on the repeat pressure tests and/or cement bond logsextrapolation of statistical relationships observed (CBLs) would be required to provide evidence aboutin natural seismicity that may not necessarily apply whether well integrity had been compromisedto induced seismicity. More research is needed to following unexpected levels of induced seismicity.better understand the precise relationship between A repeat pressure test and/or CBL be should beYGNN RTGUUWTG CPF UGKUOKEKV[ KPFWEGF KP UJCNGU 6TCHƂE reviewed by an independent well examiner and thelight monitoring systems are also affected by natural results submitted to DECC.delays within geological systems, such as the slowOQXGOGPV QH ƃWKFU VJTQWIJ HCWNVU $CEJOCPP et al 5.7 Seismicity induced by disposal2010). The two seismic events at Preese Hall both 9CUVG ƃWKFU RTQFWEGF FWTKPI UJCNG ICU GZVTCEVKQPQEEWTTGF VGP JQWTU CHVGT VJG KPLGEVKQP QH ƃWKF 1PG may be disposed of through injection into disposalsolution may be to continue monitoring of the site wells (see section 2.4). Pressure in disposal wells canafter operations have ceased (DoE 2012). Another build up over time, inducing seismicity. Between 20thapproach would be to use more advanced statistical November and 1st December 2008, 11 small seismicmodels to forecast future seismicity rates based on events were detected near Dallas-Fort Worth Airport,historic rates (Bachmann et al 2010). Further research Texas. They were attributed to the same focus pointis required but these models could be used in at an estimated depth of 4.4 km and less than 0.5kmEQPLWPEVKQP YKVJ VTCHƂE NKIJV OQPKVQTKPI U[UVGOU3 from a well drilled a few months previously at a depth QH  MO VQ FKURQUG QH YCUVG ƃWKFU HTQO UJCNG ICU operations (Frohlich et al 2011).3 Contribution from Mark Naylor, University of Edinburgh (private correspondence) Shale gas extraction in the UK: a review of hydraulic fracturing 45
    • CHAP TER 5 The magnitude of seismicity induced by disposal risk assessments for each new exploitation licence tends to be greater than that induced by hydraulic before operations can begin. These assessments fracturing (Zoback 2012). Disposal involves a longer set out both the expected maximum magnitude NGPIVJ QH VKOG QXGT YJKEJ NCTIGT XQNWOGU QH ƃWKF ECP of potential seismic events and the anticipated allow greater pressures to build up. The magnitude mitigation measures. A monitoring plan has to be of seismicity induced by disposal does not typically submitted and approved by the authorities. If seismic exceed magnitude 5 ML (Majer et al 2007, Nicholson events occur with magnitudes or impacts exceeding and Wesson 1990, Suckale 2010). Induced seismicity what is described or approved by the plans, the could be mitigated using similar practices as those authorities can intervene (Eck et al 2006). outlined above (Zoback 2012): Operators should carry out a seismic risk assessment r Avoid injection into active faults and faults (see Textbox 4) as part of their Environmental in brittle rock. Seismic imaging methods can Risk Assessments (see section 6.3). Measures identify faults and characterise local stresses to mitigate induced seismicity would therefore (see section 5.5.1). be scrutinised when the ERA is submitted to the regulators and enforced through monitoring activities r Minimise pressure changes at depth. The and inspections (see section 6.3). In the UK, the volumes of fluid to be disposed could be reduced, protection of groundwater and the underground and/or more wells constructed into which KPLGEVKQP QH ƃWKFU KU TGIWNCVGF WPFGT VJG 9CVGT smaller volumes of fluid could be injected. Highly Framework Directive and Environmental Permitting permeable rock formations could be used that Regulations (see section 4.3.1). DECC should consult can accommodate large volumes of fluid without with the UK’s environmental regulators and Mineral experiencing significant pressure changes. Highly Planning Authorities to consider the adequacy of permeable rock formations could be used that these regulations to address induced seismicity, deform plastically and so do not store large and how requirements for measures to mitigate amounts of energy. induced seismicity could feature in the conditions of environmental permits or local planning permission r Establish modification protocols in advance. (see section Traffic light monitoring systems can be deployed to respond to seismicity (see section 5.5.3). The US National Research Council (NRC) calls for operators to publicly disclose and discuss with local r Be prepared to alter plans. Injection rates may communities how measures to mitigate induced need to be reduced or wells may even need to seismicity are to be implemented (NRC 2012). In the be abandoned should the seismicity induced be UK, this would be addressed by ensuring that the too great. ERA involves the participation of local communities at the earliest possible opportunity (see section A recent study by the US National Research   6JG VJTGUJQNFU QH VTCHƂE NKIJV U[UVGOU UJQWNF Council outlines protocols for mitigating seismicity be updated in the light of operational experience. induced by disposal, as well as a range of energy 6JTGUJQNFU OC[ PGGF VQ DG UKVG URGEKƂE FGRGPFKPI technologies. These protocols require operators to on local geology, local population density, past check their plans against a comprehensive list of seismicity and the scale of operations in the area. criteria (including historical seismicity, local geology, # VTCHƂE NKIJV OQPKVQTKPI U[UVGO HQT C RCTVKEWNCT YGNN regional stress, and the nature of the proposed may be limited by other operations nearby should injection) to determine whether injection could ƃWKF NGCM HTQO OWNVKRNG YGNNU KPVQ VJG UCOG HCWNV induce seismicity (NRC 2012). Operators should share data with DECC and BGS to 5.8 Regulating induced seismicity establish a national database of shale stress and fault DECC should consider how induced seismicity is to properties so that suitable well locations can be regulated. Since 2003, Dutch mining legislation DG KFGPVKƂGF 5VTGUU FCVC EQWNF CNUQ DG UJCTGF YKVJ has required onshore operators to carry out seismic the World Stress Map Project that compiles global stress data.46 Shale gas extraction in the UK: a review of hydraulic fracturing
    • CHAPTER 5Textbox 4 Elements of a risk assessment for seismicity induced byEnhanced Geothermal Systems (DoE 2012)1. Carry out a preliminary screening 4. Establish local seismic monitoring to evaluation. Screen out sites with low RTQXKFG UKVG URGEKƂE DCUGNKPG FCVC measures of acceptability through Background seismicity should be characterised consultation with local communities and in advance of operations (perhaps even one to reviews of relevant regulations. Impacts and two years beforehand) to increase understanding VJG CTGC VQ DG CHHGEVGF UJQWNF DG KFGPVKƂGF of mechanisms of stress build up and release and to identify faults.2. Implement an outreach and communications programme. 5. Assess the ground shaking hazards at Transparency and participation of local the site. Use data from step 4 to carry out a communities should be maintained quantitative assessment using probabilistic seismic hazard analysis.3. Identify criteria for ground vibration and noise risk assessment. Operators 6. Carry out induced seismicity risk should review ground-borne noise and assessment. Update step 1 in the light of vibration impact assessments and monitoring data collected in steps 2-5. A probabilistic risk systems used in relevant industries, such as analysis could be carried out. The vulnerability construction, quarrying, and mining. Building of risk receptors should also be considered, damage criteria, structural damage criteria such as the robustness of the structures in the and human exposure to vibration should be area to be impacted. reviewed to determine ground motion and vibration limits. A baseline of ground vibration 7. Develop a mitigation plan. # VTCHƂE NKIJV and noise should also be established. monitoring system could be implemented based on a plot of ground motion as a function of injection rates and time. If any damage is caused by induced seismicity, then compensation may be required. Operators should review legislation relevant to other sectors to consider whether they are liable and if insurance is required due to any damage or nuisance.RECOMMENDATION6Q OKVKICVG KPFWEGF UGKUOKEKV[r BGS or other appropriate bodies r Traffic light monitoring systems should should carry out national surveys to be implemented and data fed back to well characterise stresses and identify faults injection operations so that action can be in UK shales. Operators should carry taken to mitigate any induced seismicity. out site-specific surveys to characterise and identify local stresses and faults. r DECC should consider how induced seismicity is to be regulated. Operatorsr Seismicity should be monitored before, should share data with DECC and BGS to during and after hydraulic fracturing. establish a national database of shale stress and fault properties so that suitable well locations can be identified. Shale gas extraction in the UK: a review of hydraulic fracturing 47
    • CHAP TER 6 Risk management 6.1 The UK’s goal based approach to regulation a goal based approach for offshore activities under The UK’s approach to managing health and safety the Convention for the Protection of the Marine risks is goal based. Regulators set out goals but Environment of the North East Atlantic (OSPAR). operators are responsible for considering the OSPAR recommends setting environmental goals means to achieve them according to the following to be met by operators through internationally framework (HoL 2006): recognised and independently audited Environmental Management Systems (OSPAR 2003). r A lower bound below which risks are considered CEEGRVCDNG CPF PQ HWTVJGT UKIPKƂECPV CEVKQP KU A goal based approach to offshore and onshore required. regulation is to be commended. Operators are forced to identify and assess risks in a way that fosters r An upper bound above which risks are deemed innovation and continuous improvements in risk unacceptable, requiring that the activity giving rise management. Some argue that this approach is to the risk should be discontinued or action taken limited to the extent that ‘reasonably practicable’ is to reduce the risk. QPN[ FGƂPGF KP VJG 7- D[ ECUG NCY #P CNVGTPCVKXG VQ a goal based approach would be a more prescriptive r An intermediate range where risks are regarded as one adopted in other countries, such as the USA, acceptable provided they are reduced to As Low UGVVKPI QWV URGEKƂE WPKXGTUCN UVCPFCTFU VQ DG As Reasonably Practicable (ALARP). met. This approach has its limitations. It tends to support routine practices and limit innovation in risk The Offshore Installations and Wells (Design and management. A prescriptive approach may also be Construction, etc) Regulations 1996 state that wells NGUU RTQRQTVKQPCVG CPF ƃGZKDNG VJCP C IQCNDCUGF should be designed and constructed so that ‘as CRRTQCEJ VQ NQECN UKVG URGEKƂE TKUMU CU YGNN CU far as is reasonably practicable, there can be no changing circumstances, such as the introduction WPRNCPPGF GUECRG QH ƃWKFU HTQO VJG YGNN CPF TKUMU VQ of new technologies or best practices. Another the health and safety of persons from it or anything QRVKQP KU VQ FGXGNQR UGEVQT URGEKƂE IWKFGNKPGU in it, or in strata to which it is connected, are as (HoL 2006). Given common sources of health, safety low as is reasonably practicable’. The well should and environmental risk, the UK’s health and safety also be designed and constructed so that as ‘far as regulators and environmental regulators should is reasonably practicable, it can be suspended or work together to develop guidelines that help shale abandoned in a safe manner; and after its suspension gas operators carry out risk assessments based on or abandonment there can be no unplanned escape the ALARP principle. These guidelines could help QH ƃWKFU HTQO KV QT HTQO VJG TGUGTXQKT VQ YJKEJ KV NGFo familiarise foreign operators with the UK’s goal based approach to risk management.4 Operators should A recent review of the Macondo (Deepwater Horizon) put in place internal processes to explain how risks incident recommended that the Department of can be managed according to the ALARP principle Energy and Climate Change and the UK’s offshore oil so that contracted service companies carry out and gas industry should develop a more goal-based consistent risk assessments. Operators should also approach to environmental regulation (Maitland ensure mechanisms are put in place to audit their et al 2011). Oil & Gas UK (which represents the risk management processes (see Textbox 5). Risk offshore industry) is developing the concept of an assessments should be submitted to the regulators Environmental Assurance Plan that could identify for scrutiny and then enforced through monitoring baseline performance standards and targets, leaving activities and inspections. operators responsible for the means to achieve them (Maitland et al 2011). The UK already adopts 4 Contribution from Professor Ragnar Lofstedt, Director, Centre for Risk Management, Kings College London48 Shale gas extraction in the UK: a review of hydraulic fracturing
    • CHAPTER 6 Textbox 5 An example of industry best practice for risk management The International Safety Rating System (ISRS) r The Risk Evaluation audit section reviews how marketed by Det Norse Veritas (DnV) was health, safety and environmental risks are developed in partnership with the nuclear, identified and assessed. chemical, petrochemical and other industries (ISRS 2012). ISRS provides tools to audit r The Risk Control audit section reviews the risk management processes in a variety of measures put in place to manage these risks. organisations across sectors. Having initially focused on occupational health and safety, r The Emergency Preparedness audit section ISRS now also addresses environmental risks. reviews the comprehensiveness and In 2009, ISRS’ scope was expanded to address categorisation of emergency scenarios, testing major accidents, such as fire, explosion or the quality of on- and offsite emergency plans. release of flammable or toxic materials. Auditors trained to score the ISRS system have enabled r The Learning from Events audit section reviews benchmarking of risk management processes the reporting and investigation of events, between companies and between groups allocation of corrective actions and follow up. within the same company: r The Risk Monitoring audit section reviews the robustness of monitoring systems to ensure the management system in place remains fit for purpose.6.2 Collecting data to improve risk assessments Historically, major accidents in other sectors haveIt is mandatory for operators to submit reports about led to subsequent operational and regulatoryaccidents and incidents to the UK’s regulators (see improvements. Any UK shale gas industry must notTextbox 6). Reports should also be shared between wait for an incident or accident but should seek tooperators. Reliable data on failures of well integrity, identify and share best practice from the well as failures or shortcomings in procedures The importance of an open sharing and learningcarried out during well construction, operation and culture is clear from investigations into past oil andabandonment, are not readily available. These data gas incidents, such as the Macondo (Deepwatershould not be proprietary to any one company. Horizon) accident in the Gulf of Mexico (Maitland et%QOOGTEKCN EQPƂFGPVKCNKV[ QT VJG RTQURGEV QH CFXGTUG al 2011). Systems should be in place so that whenpublicity should not become barriers to sharing data incidents happen with the potential to becomeand learning from incident experience (Maitland major accidents, they are promptly investigated byet al 2011). Mechanisms should be established so operating companies. Regulators should scrutiniseVJCV YQTMGTU ECP EQPƂFGPVKCNN[ TGRQTV CEEKFGPVU CPF the effectiveness with which companies monitor,incidents, especially well and operational failures investigate and learn from events and sharebefore, during and after operations. Once collected, information within and across companiesthe information should be shared anonymously to (Maitland et al 2011).improve risk assessments and promote best practicesacross the industry. Precedents for such mechanismsexist in other sectors (see Textbox 7). Shale gas extraction in the UK: a review of hydraulic fracturing 49
    • CHAP TER 6 Textbox 6 Accident and incident reports submitted to the UK’s regulators The Reporting of Injuries Diseases and Dangerous reported under RIDDOR. Jointly funded by the UK’s Occurrences Regulations 1995 (RIDDOR) health and safety regulators and the UK Offshore requires employers to report workplace incidents Operators Association, the HCR system allows and accidents (unintentional events leading users to submit incident reports online. Outputs to health and safety concerns), including near based on data in the HCR database are generic misses, to local authorities and the health and and non-attributable. safety regulators. Regulation 3 of RIDDOR has a URGEKƂE UGV QH &CPIGTQWU 1EEWTTGPEGU HQT YGNNU The Environment Agency collects information on (Schedule 2, Part I) that the well operator must reported incidents, including incidents self reported report, including: blowouts; unplanned uses by operators, using a National Incident Reporting of blowout prevention equipment; unexpected System (NIRS). A record starts when the Incident detection of hydrogen sulphide; failure to maintain Communication Service or Regional minimum separation distance between wells; and Communications Centre Wales receives a report of mechanical failure of safety critical elements of a a potential incident. The report is then passed to well. The UK’s health and safety regulators publish VJG CRRTQRTKCVG EQORGVGPV QHƂEGT KP VJG NQECNKV[ VQ annual statistics so that the industry and others assess the incident response based on a Common can consider trends in the information reported +PEKFGPV %NCUUKƂECVKQP 5EJGOG 6JG CUUGUUOGPV under RIDDOR. Operators can voluntarily provide along with details of the incident response and information about offshore hydrocarbon release post incident activities, such as legal action and incidents to the hydrocarbon releases (HCR) cost recovery, is recorded on NIRS. system to supplement the information 6GZVDQZ  %QPƂFGPVKCN TGRQTVKPI QH CEEKFGPVU HTQO VJG CXKCVKQP CPF OCTKVKOG UGEVQTU 6JG CXKCVKQP %QPƂFGPVKCN *WOCP (CEVQTU +PEKFGPV 4GRQTVGTU CTG KFGPVKƂGF UQ VJCV TGRQTVU ECP DG Reporting Programme (CHIRP) has been running validated and action taken. Reporters’ identities since 1982 (CHIRP 2012). In 1996, it was are not revealed outside CHIRP without their restructured into a charitable company limited consent, allowing key information to be circulated by guarantee to ensure its independence so that anonymously. The Mariners’ Alerting and Reporting OCPCIGOGPV CPF ƂUECN TGURQPUKDKNKVKGU CTG JGNF 5EJGOG /#45 KU C EQPƂFGPVKCN TGRQTVKPI U[UVGO by an independent Board of Trustees. CHIRP run by the Nautical Institute to allow full reporting complements other formal reporting systems of accidents (and near misses) without fear of operated by other UK organisations, such as the KFGPVKƂECVKQP QT NKVKICVKQP 0CWVKECN +PUVKVWVG   Civil Aviation Authority Mandatory Occurrence MARS reports are held in a publicly-accessible Reporting, by providing a means through which database. MARS reports regularly comprise alerts individuals can report concerns without being so that actions from recent incidents can be KFGPVKƂGF VQ VJGKT RGGT ITQWR OCPCIGOGPV QT relayed to the mariner on board a vessel. the regulators at all levels of seniority across the aviation sector.50 Shale gas extraction in the UK: a review of hydraulic fracturing
    • CHAPTER 6 RECOMMENDATION Best practice for risk management should DG KORNGOGPVGF r Operators should carry out goal based risk r Risk assessments should be submitted assessments according to the principle of to the regulators for scrutiny and then reducing risks to As Low As Reasonably enforced through monitoring activities Practicable (ALARP). The UK’s health and inspections. and safety regulators and environmental regulators should work together to r Mechanisms should be put in place to FGXGNQR IWKFGNKPGU URGEKƂE VQ UJCNG ICU allow the reporting of well failures, as well extraction to help operators do so. as other accidents and incidents, between operators. The information collected r Operators should ensure mechanisms should then be shared to improve risk are put in place to audit their risk assessments and promote best practices management processes. across the industry.6.3 Environmental Risk Assessments radioactive waste management under the RadioactiveCurrently, an operator may need to carry out an Substances Act 1993. ERAs draw on a ‘source-Environmental Impact Assessment when seeking pathway-receptor’ model that has proved to belocal planning permission. The Schedules attached to ƃGZKDNG CETQUU C TCPIG QH GPXKTQPOGPVCN TKUMUTown and Country Planning (Environmental Impact (Gormley et al 2011). This model forces operatorsAssessment) England and Wales Regulations 1999 to consider carefully the relationships between thesuggest an Environmental Impact Assessment source of an environmental hazard; the pathwaysis required if the area of operations exceeds one through which it can impact the environment; andhectare. Environmental Risk Assessment (ERA) has those objects within the environment that could bebecome best practice in non-shale gas industries harmed (‘receptors’). Guidelines developed by theCUUKUVGF D[ UGEVQTURGEKƂE IWKFGNKPGU5 An ERA UK’s regulators should help shale gas operators carryshould be mandatory for all shale gas operations out ERAs according to the ALARP principle (seeCUUKUVGF D[ IWKFGNKPGU URGEKƂE VQ UJCNG ICU GZVTCEVKQP section 6.1).developed by the UK’s regulators (see section 6.1).Unlike an Environmental Impact Assessment, an ERA Late involvement of public consultation inwould assess not just the impacts of hazards but environmental decision-making process has oftenalso their likelihood. This would help to prioritise risks led to public frustration and demands for earlierand support more proportional risk management. engagement. Participatory risk assessments areThe ERA should assess risks across the entire best practice (Stern and Fineberg 1996). An ERA forlifecycle of shale gas extraction, including disposal, shale gas operations should allow stakeholders tothe abandonment process and the monitoring of participate in the framing of environmental problems;abandoned wells. Seismic risks should also feature identifying and assessing risks; and evaluatingas part of the ERA (see section 5.8). different means of managing them (Gormley et al 2011). This would complement the new NationalALARP does not formally apply to ERAs. A principle Planning Policy Framework that encouragesof reducing risks to As Low As Reasonably early engagement between operators and localAchievable (ALARA) is formally applied to the communities even pre-application (DCLG 2012).5 Contribution from Professor Simon Pollard, Head of Department, Environmental Science and Technology, Cranfield University Shale gas extraction in the UK: a review of hydraulic fracturing 51
    • CHAP TER 6 RECOMMENDATION 6Q OCPCIG GPXKTQPOGPVCN TKUMU r An Environmental Risk Assessment (ERA) should be mandatory for all shale gas operations, involving the participation of local communities at the earliest possible opportunity. r The ERA should assess risks across the entire lifecycle of shale gas extraction, including the disposal of wastes and well abandonment. Seismic risks should also feature as part of the ERA.52 Shale gas extraction in the UK: a review of hydraulic fracturing
    • CHAPTER 4 7Regulating shale gasThe regulation of shale gas extraction in the UK r Conditions of Petroleum Exploration anddraws on the experience of onshore and offshore oil Development Licences;and gas industries over the last 60 years. Currently,VJGTG CTG  7- QPUJQTG QKN ƂGNFU CPF  QPUJQTG r Conditions of local planning permission;ICU ƂGNFU KP RTQFWEVKQP RTQFWEKPI  DCTTGNU RGTday of oil and 250,000m3/d of gas or approximately r Notification of well construction and the well1500 barrels per day oil equivalent (see Figure 12). examination scheme;Risks posed by exploratory activities are managed atvarious stages of the UK’s regulatory system: r Conditions of environmental permits. Figure 12 Existing onshore conventional oil and gas wells in the UK (Harvey and Gray 2010) The red circles represent conventional wells that have been drilled. The yellow circles represent EQPXGPVKQPCN YGNNU VJCV JCXG DGGP FTKNNGF CPF HTQO YJKEJ ICU JCU ƃQYGF 67.1 Conditions of Petroleum Exploration and Division of the Department of Enterprise, Trade and Development Licences Investment. Shale gas extraction was not consideredIn some countries, such as the USA, landowners when regulations for conventional gas extractionown the hydrocarbons under their land and thereby YGTG HQTOWNCVGF KP VJG U 6JGTG KU PQ URGEKƂEhold the rights to exploit them. In the UK, ownership mention of shale gas in UK legislation. Licencesis conferred on the state. In England, Scotland URGEKƂE VQ J[FTCWNKE HTCEVWTKPI QT FKTGEVKQPCN FTKNNKPIand Wales, licences to exploit hydrocarbons are are not awarded per se. Rather, PEDL licenses areissued by the Department of Energy and Climate issued along with consents for particular activitiesChange (DECC) through Petroleum Exploration and and controls can be imposed accordingly (forDevelopment Licences (PEDL) rounds. In Northern example, see section 2.6).Ireland, onshore licenses are granted by the Energy Shale gas extraction in the UK: a review of hydraulic fracturing 53
    • CHAP TER 4 7 7.2 Conditions of local planning permission local planning permissions. The Environment Agency PEDL licences grant exclusivity to operators in the (EA) serves England and Wales, although a single licence area. They do not give immediate consent for environmental body for Wales is due to become drilling an exploration well or any other operation. operational in 2013. The Scottish Environmental An operator must negotiate access with landowners; Protection Agency (SEPA) serves Scotland, and the seek permission from the Coal Authority if operations Northern Ireland Environment Agency (NIEA) serves will penetrate coal seams; and be granted local Northern Ireland. The EA has a statutory requirement planning permission from the Minerals Planning to safeguard public health, so seeks expert advice Authority (MPA). In England, Wales and Scotland, from health professionals, such as the Health the MPA involves local authorities, including Protection Agency (HPA). The EA has an agreement representatives from districts and county councils. with the HPA about when and how the HPA is In Northern Ireland, the Planning and Local consulted when permitting an activity. Government Group (within the Department of Environment) is responsible for shale gas planning. Under current planning arrangements, it is the decision of the local planning authority to decide who Proposals will be screened by MPAs to identify to consult. Health professionals should be consulted whether an Environmental Impact Assessment is to advise on local health impacts whether directly or required (see section 6.3). Even if an Environmental indirectly through the EA. The HPA has established a Impact Assessment is not required, environmental Working Group of chemical and radiation specialists and health impacts can be addressed through to collate and review literature, including national the conditions of planning permission. MPAs are and international studies, about the potential health responsible for ensuring operators comply with impacts of shale gas extraction. Its terms of reference these conditions. are yet to be established. The results of this HPA review should inform local planning processes. Local planning conditions can also address aesthetic KORCEVU CU YGNN CU EQPVTKDWVKQPU VQ NQECN PQKUG VTCHƂE Induced seismicity and air pollution. The UK has the experience of best MPAs should consult the British Geological Survey RTCEVKEG VQ FTCY QP 9[VEJ (CTO QKN ƂGNF KU NQECVGF KP (BGS) to advise on induced seismicity and help to one of the world’s most famous regions of outstanding identify suitable locations for wells, drawing on a PCVWTCN DGCWV[ CPF QH URGEKCN UEKGPVKƂE KPVGTGUV 6JKU PCVKQPCN CPF UKVGURGEKƂE WPFGTUVCPFKPI QH IGQNQI[ includes the Jurassic Coast and World Heritage sites; BGS has provided MPAs with technical documents designated wetlands of international importance; and to provide guidance on certain issues, such as national nature reserves. Post-operations site restitution safeguarding mineral resources (Wrighton et al may also be included as a condition of the planning 2011). BGS could provide similar technical assistance permission. to help operators carry out consistent seismic risk assessments and to help MPAs oversee the The density of local population areas may also be KORNGOGPVCVKQP QH VTCHƂE NKIJV OQPKVQTKPI U[UVGOU considered in the local planning permission process, and other mitigation measures. although many operations are likely to be located on farmland where population density is low. Drilling  0QVKƂECVKQP QH YGNN EQPUVTWEVKQP CPF VJG well examination scheme multiple wells can be useful where there is limited The Borehole Sites and Operations Regulations surface area for operation. Up to 20 wells or more 1995 require an operator to notify the UK’s health can be drilled from a single pad, reducing the and safety regulators at least 21 days in advance size of the surface footprint and requiring less of any drilling operations: the Health and Safety surface equipment. Executive (HSE) in England, Wales and Scotland, 7.2.1 Informing local planning processes with and Health and Safety Executive for Northern scientific advice Ireland (HSENI) in Northern Ireland. This provides an opportunity to review the operator’s plans for Health effects on local populations the design, construction and operation of the well, The UK’s environmental regulators are statutory as well as ensuring a suitable well examination consultees to the local planning process, and so can scheme is in place (see section 3.2). As the well is advise on the environmental conditions of being constructed, the health and safety regulators54 Shale gas extraction in the UK: a review of hydraulic fracturing
    • CHAPTER 4 7inspect the weekly operations reports submitted hundreds of wells were to be drilled in the UK. Theby the operator. During operations, the UK’s health UKIPKƂECPV XQNWOGU QH ƃQYDCEM YCVGT IGPGTCVGF OC[and safety regulators receive no information from exceed the capabilities of onsite, closed-loop storagethe operator unless an event is reported according tank systems, in which case, disposal wells may beto Reporting of Injuries Diseases and Dangerous necessary (see section 2.4). Other impacts, includingOccurrences Regulations 1995 (see Textbox 6). transportation, loss of biodiversity (due to habitatOnsite inspections may be carried out as required. loss and fragmentation), visual impacts, effects on airUnder the Water Resources Act 1991, the operator quality, would warrant more required to notify the Environment Agencyabout the intention to drill a well along with details 7.5.1 Maintaining co-ordinationof its construction. A single body should take leadership to ensure co-ordination of the numerous central and devolved7.4 Conditions of environmental permits bodies with responsibilities for regulating shaleOnce the MPA has granted planning permission, gas extraction in the UK. Consideration should beDECC will check with the relevant health and safety given to:and environmental regulators before giving consentto the drilling of an exploration well. An operator r Clarity on roles and responsibilities. Localmust also seek a set of environmental permits before planning permissions tend to focus on impactsoperations can begin under the Environmental on the local environment. Environmental permitsPermitting (England and Wales) Regulations 2010 tend to focus on the processes giving rise to these(for example, see section 4.3.1). The conditions to impacts. Clarity would help to ensure efforts arebe placed on operations as part of the granting of a not duplicated and to avoid the managementRGTOKV CTG KPHQTOGF D[ C URGEKƂE TKUM RTQƂNG HQT GCEJ of any risk falling between responsibilities. Forsite based on an Operational Risk Assessment (OPRA) example, more consideration needs to be givenmethodology developed by the UK’s environmental to how exactly measures to mitigate inducedregulators. The OPRA methodology considers the type seismicity are to be regulated (see section 5.8).of facility; type and quantity of wastes involved; typeand levels of emissions released; risk receptors in the r Mechanisms to support integrated ways ofarea; and the environmental management system to working. Under the Control of Major Accidentbe implemented. Once a site is awarded a permit, the Hazards (COMAH) regulations, the ‘competentenvironmental regulators continue to use the OPRA authority’ that enforces the regulations is themethodology and rating system to monitor a site’s joint responsibility of the HSE and EA. Operatorsperformance and compliance with permit conditions. of onshore installations that fall under COMAH’s remit effectively interface with a unified regulatory7.5 Regulating production activities on a authority. This mechanism could be useful for nationwide scale the UK’s environmental regulators to tap intoAn operator can seek permission for a production the specialist expertise of the well examinationwell, according to a similar process for an exploration scheme (see section 3.2). Wider application of thiswell, although a new PEDL licence is not required. The and other mechanisms could to help streamlineoperator would need to submit a Field Development activities, minimise bureaucracy and reducePlan for DECC’s consent. DECC would check with pressures on limited resources.the regulators before issuing a Field DevelopmentConsent, setting limits on the quantities of gas to be r More formal mechanisms to shareRTQFWEGF XGPVGF QT ƃCTGF .QECN RNCPPKPI RGTOKUUKQP information. Operators provide data to the UK’smay need to be sought again, possibly placing new regulators (see Textbox 6). Different regulatorsconditions on production activities. may not have direct access to each other’s databases beyond informal relationships. EA andExisting UK regulation contains the necessary DECC co-convene a joint regulators forum onelements to manage the risks associated with small- shale gas to exchange information and share bestscale activities. Attention must be paid to the way in practice. It has been meeting regularly since earlywhich risks scale up if a shale gas industry develops 2011, consisting of officials from governmentnationwide (IEA 2012). For example, the probability departments (DECC; Departmentof an instance of a failed well would increase if Shale gas extraction in the UK: a review of hydraulic fracturing 55
    • CHAP TER 4 7 for Environment, Food and Rural Affairs; 7.5.2 Increasing capacity Department of Communities and Local The UK’s regulators should now begin to determine Government; Welsh Government; Scottish their requirements to regulate a shale gas industry Executive; Department of the Environment should it develop in the UK. Skills gaps and relevant NI; and Department of Enterprise, Trade and training should be identified. Some local authorities Investment NI) and regulatory agencies (EA, have in-house expertise while others need to reach SEPA, NIEA, HSE and HSENI). This forum could out to external expertise. Training events with other become more a formal body. Information could regulators could at the same time help to clarify also be shared through participation at relevant roles and responsibilities. Extra resources may Advisory Groups of the Planning Officers Society. also be necessary to support BGS’ activities that regulators may need to draw on (see sections r Joined-up engagement of local communities. 3.3.3, 5.5 and MPAs have to write a Statement of Community Involvement to explain how local communities will The EA uses the risk rating provided by its OPRA be engaged. Co-ordinated approaches would help methodology to determine the charge for a site’s to ensure that consultation by different bodies at permit. An operator with a higher risk is charged a various stages does not confuse the purpose of higher fee to cover the resources needed to assess consultation to local communities. the site’s proposed risk. The EA then works on a receipt-based funding model. If an operator is r Learning from operational and regulatory successful in gaining permission for exploration or best practice internationally. The USA is production, the operator is charged to cover the a priority partner. Lessons should be learned costs of the EA’s activities. If unsuccessful, the costs from the USA and taken into account in the can be recovered through alternative mechanisms, development of UK regulations (see section 1.4). UWEJ CU RWDNKE HWPFU 9JGP CP QRGTCVQT PQVKƂGU The EU is another priority (European Parliament HSE about an intention to construct and operate a 2012a). The UK should ensure any changes at the YGNN *5 CUUGUUGU VJG FGUKIP CPF XGTKƂGU VJG YGNN EU level do not dilute the strengths of the UK’s is operated safely through inspections (see section approach to regulation or frustrate the activities of 7.3). HSE currently carries out these activities without the UK’s regulators (Maitland et al 2011). recovering the costs involved. Under proposed legislative changes, HSE is looking to introduce a Fee RECOMMENDATION For Intervention Model so that HSE could recover Co-ordination of the numerous bodies with these costs (HSE 2011). This mechanism provides an regulatory responsibilities for shale gas incentive for operators to meet their obligations. This extraction should be maintained. A single mechanism could be applied more widely so that the body should take the lead. Consideration 7-oU TGIWNCVQTU TGOCKP UWHƂEKGPVN[ TGUQWTEGF UJQWNF DG IKXGP VQ RECOMMENDATION r Clarity on roles and responsibilities. The UK’s regulators should determine r Mechanisms to support integrated their requirements to regulate a shale gas ways of working. industry should it develop nationwide in the future. Skills gaps should and relevant r More formal mechanisms to share VTCKPKPI UJQWNF DG KFGPVKƂGF #FFKVKQPCN information. resources may be necessary. r Joined-up engagement of local communities. r Mechanisms to learn from operational and regulatory best practice internationally.56 Shale gas extraction in the UK: a review of hydraulic fracturing
    • CHAPTER 8Research on shale gas8.1 Uncertainties affecting small scale 8.2 Uncertainties affecting large scale exploratory activities production activitiesUncertainties affecting the small scale exploratory /QTG UKIPKƂECPV WPEGTVCKPVKGU EQPEGTP VJG UECNG QHactivities in the UK can be addressed through effective production activities should a shale gas industrymonitoring systems and research programmes before develop nationwide. The potential scale will beUJCNG ICU GZVTCEVKQP EQOOGPEGU QP CP[ UKIPKƂECPV dictated by the UK’s potential shale gas resources,scale. Research priorities include: as well as government policy making. This report has addressed environmental, health and safety risksr technologies to reduce water requirements for associated with shale gas extraction. Policymaking hydraulic fracturing (see section 2.2.2); YQWNF DGPGƂV HTQO TGUGCTEJ KPVQ VJG ENKOCVG TKUMU associated with the extraction and subsequentr improving understanding of UK shales and the use of shale gas. This report has focused on the composition of wastewaters (see section 2.3); technical aspects of the risks associated with J[FTCWNKE HTCEVWTKPI 2QNKE[ OCMKPI YQWNF CNUQ DGPGƂVr technologies to treat wastewaters (see from research into the public acceptability of shale section 2.4); gas extraction and use in the context of wider UK policies, including:r methods to determine sources of methane (see section 3.3.1); r climate change policy, especially the impact of shale gas extraction on the UK meeting itsr monitoring the long term behaviour of wells, emissions targets (see section 1.8.1); including after abandonment (see section 3.3.4); r energy policy, especially the impact of shale gasr improving understanding of mechanical and development on investment in renewable energy flow properties of shale (see section 4.3.5); (see section 1.8.1);r improving the effectiveness of traffic light r economic policy, including socioeconomic monitoring systems and statistical models to benefits from employment to tax revenue and forecast induced seismicity (see section 5.5.3). from shale gas use. 8.2.1 The UK’s proven reserves of shale gas Various estimates of the extent of certain areas in the UK with shale gas resources have been provided (see Textbox 8). It will be some years before shale gas production data and the impact of regulatory and economic conditions allow a rigorous estimate of the UK’s proven reserves of shale gas. Shale gas extraction in the UK: a review of hydraulic fracturing 57
    • CHAP TER 8 Textbox 8 Estimates of shale gas resources in the Bowland Shale In a 2010 report commissioned by the measured data from two wells for permeability, Department of Energy and Climate Change gas content and other key parameters (Broderick (DECC), the British Geological Survey (BGS) et al 2011). Other operators, including Island estimated that the Bowland Shale could Gas Ltd, Eden Energy, Greenpark Energy and potentially yield up to 4.7 trillion cubic feet Composite Energy, have estimated the size of (tcf) of technically recoverable gas (Harvey shale gas resources within their respective licence and Gray 2010). This is equivalent to roughly areas (Broderick et al 2011). Only the estimate by 1.5 years of UK gas consumption (HoC 2011). Cuadrilla has been informed by measured data (in This recoverable gas estimate was an area Cuadrilla’s case, from two wells). A new DECC- based assessment, drawing upon comparisons commissioned BGS study will estimate the gas-in- between the Bowland basin and Barnett Shale in place estimate related to the area where Cuadrilla Texas, USA, given similarities in age and palaeo- has exploration rights and for the greater Bowland environmental character. Cuadrilla has published Shale prospective area by the end of 2012. BGS is a gas-in-place estimate of approximately 200 using 3D modelling to estimate the UK’s total shale tcf for its Bowland Shale license area. From gas resource. This is likely to help identify potential the US experience, and based on current sweet spots where there are high concentrations technological capability, it is expected that of carbon and where the rock’s mineralogy and only 10% of this value (20 tcf) is likely to be existing fractures make it most amenable to technically recoverable. Cuadrilla’s estimate was hydraulic fracturing. a volumetric based assessment. It drew on 8.2.2 The carbon footprint of shale gas extraction Different perspectives on hydraulic fracturing do not There are few reliable estimates of the carbon neatly divide into views held by experts and those footprint of shale gas extraction and use in the peer held by ‘the public’. ‘The public at large’, civil society reviewed literature. One US study from Cornell organisations, those who adopt more sceptical University concluded that the carbon footprint of perspectives on technological developments, as UJCNG ICU GZVTCEVKQP KU UKIPKƂECPVN[ NCTIGT VJCP HTQO well as protest groups should all be involved in conventional gas extraction owing to potential this research. This will help ensure the government leakages of methane (Howarth et al 2011). The same addresses issues of actual, rather than assumed, study recognised the large uncertainty in quantifying public concern. This research should also investigate these methane leakages, highlighting that further what makes a regulator trustworthy. Concerns tend research is needed. Data collected from methane to focus less on a particular technology per se and monitoring submitted to the UK’s regulators could more on how the technology is governed in real be used to inform assessments to reduce this world circumstances. This is problematic in the uncertainty (see section 2.6). light of a lack of trust in the government to act in the public interest and ensure adequate regulatory 8.2.3 The public acceptability of shale gas oversight (Chilvers and Macnaghten 2011). extraction The Economic and Social Research Council has 8.3 Funding research on shale gas funded extensive research to better understand the The majority of shale gas research is carried out public views of low carbon fuels, such as nuclear by the industry where most expertise is located. power (Whitmarsh et al 2011). Government decision Publicly funded research may be necessary to OCMKPI YQWNF DGPGƂV HTQO UKOKNCT TGUGCTEJ KPVQ GPUWTG EQPƂFGPEG VJCV FGEKUKQP OCMKPI KU KPHQTOGF the public acceptability of shale gas extraction by independent, evidence-based research. There is within the context of wider government policies. currently no cross-Research Council or Technology Opportunities should be created to allow expert 5VTCVGI[ $QCTF 65$ RTQITCOOG URGEKƂECNN[ understanding about risks to be challenged and addressing shale gas extraction. Such a programme ‘blind spots’ to be explored (Whitmarsh et al 2011). could provide an integrated and interdisciplinary58 Shale gas extraction in the UK: a review of hydraulic fracturing
    • CHAPTER 8assessment of the risks and opportunities associated LWEC fosters collaboration between projects thatwith shale gas extraction and use in the UK. It could ECP FGNKXGT DGPGƂVU VQ OWNVKRNG RCTVPGTU /GODGThelp to focus efforts and ensure that national needs organisations with their own budgets can pay anare met while drawing on research efforts elsewhere, annual subscription, contribute staff resources to runespecially in the USA and in Europe (see Textbox 9). a small directorate or contribute to common needs.A cross-Research Council programme could be The Geological Society of London has established abased on existing precedents. Involving 15 UK Geosciences Skills Forum (GSF) in partnership withhigher education partners and institutes, the UK the Petroleum Exploration Society of Great Britain,Carbon Capture and Storage Consortium was British Geological Survey and other partners. GSFset up in 2005 to rapidly expand a UK research could broker a dialogue between the Researchcapacity for carbon capture and storage, involving Councils, TSB, DECC, Department for Communitiesengineers, natural and social scientists. Launched and Local Government, Department for Environment,in 2008 as a 10-year partnership, the Living With Food and Rural Affairs and Environment Agency andEnvironmental Change (LWEC) partnership includes the wider geosciences community about researchresearch councils, government departments, priorities and capacity needs.devolved administrations and government agencies. Textbox 9 Emerging European research efforts into shale gas extraction )CU 5JCNGU QH WTQRG )#5* KU WTQRGoU ƂTUV Initiative for Unconventional Resources is interdisciplinary shale gas research initiative managed by the German Research Centre for sponsored by a number of industrial companies. Geosciences at the Helmholtz Centre Potsdam. Established in 2009, GASH is developing a GIS 512 EQODKPGU WTQRGURGEKƂE TGUGCTEJ database of European black shales, including with relevant US experience to develop best their location, as well as biological, chemical and practice for shale gas extraction to address physical properties. This also includes identifying environmental impacts and public concerns. sweet spots and predicting the formation 512 YKNN GUVCDNKUJ C nƂGNF NCDQTCVQT[o VQ VGUV of shales. GASH has a particular focus on and demonstrate best practices independently Denmark and Germany. Under the initiative, 12 funded by entities not actively involved in oil research projects are being undertaken, drawing and gas extraction. The Shale Gas Information on research institutions, national geological Platform (SHIP) does not carry out its own surveys, including the British Geological Survey, research. SHIP is a public platform for sharing universities and industry experts. The European information on shale gas. Sustainable Operating Practices (E-SOP) RECOMMENDATION The Research Councils, especially the research programmes, and possibly a Natural Environment Research Council, the cross-Research Council programme. Priorities Engineering and Physical Sciences Research should include research into the public Council and the Economic and Social acceptability of the extraction and use of shale Research Council, should consider gas in the context of UK policies on climate including shale gas extraction in their change, energy and the wider economy. Shale gas extraction in the UK: a review of hydraulic fracturing 59
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    • ACRO N Y MS Acronyms ALARA As Low As Reasonably Achievable ALARP As Low As Reasonably Practicable ANSI American National Standards Institute API American Petroleum Institute BGS British Geological Survey BOP Blowout preventer CBL Cement Bond Log CHIRP Confidential Human Factors Incident Reporting Programme COMAH Control of Major Accident Hazards DCLG Department for Communities and Local Government DECC Department of Energy and Climate Change DEFRA The Department for Environment, Food and Rural Affairs EA Environment Agency EIA Energy Information Administration (US) EGS Enhanced Geothermal Systems EMS European Macroseismic Scale EPA US Environmental Protection Agency EPR Environmental Permitting Regulations ERA Environmental Risk Assessment E-SOP European Sustainable Operating Practices EU European Union ft feet GASH Gas Shales of Europe GIS Geographical Information System GSF Geosciences Skills Forum GWPC Ground Water Protection Council HPA Health Protection Agency HSE Health and Safety Executive HSENI The Health and Safety Executive for Northern Ireland ISRS International Safety Rating System JRC Joint Research Centre LPG Liquid Petroleum Gas LWEC Living With Environmental Change ML Local Magnitude scale MARS Mariners Alerting and Reporting Scheme Ml Megalitres (1x106 litres) MPA Mineral Planning Authority NIEA Northern Ireland Environment Agency NORM Naturally Occurring Radioactive Material NPPF National Planning Policy Framework OPRA Operational Risk Assessment OSPAR The Convention for the Protection of the Marine Environment of the North-East Atlantic PEDL Petroleum Exploration and Development Licence REACH Registration, Evaluation, Authorisation and Restriction of Chemicals RIDDOR Reporting of Injuries, Diseases and Dangerous Occurrences Regulations 1995 SEAB US Secretary of Energy Advisory Board66 Shale gas extraction in the UK: a review of hydraulic fracturing
    • ACRONYMSAcronymsSEPA Scottish Environment Protection AgencySHIP Shale Gas Information PlatformSTRONGER State Review of Oil and Natural Gas Environmental RegulationsTSB Technology Strategy Boardtcf Trillion cubic feetUKCCSC UK Carbon Capture and Storage Consortium Shale gas extraction in the UK: a review of hydraulic fracturing 67
    • GLOSS ARY Glossary Term Definition Baseline survey A survey carried out prior to any operations to determine the natural background levels of cer- tain substances. Biocide An additive that kills bacteria. Biogenic Produced by bacteria. Blowout A sudden and uncontrolled escape of fluids from a well up to the surface. Blowout preventer High pressure wellhead valves, designed to shut off the uncontrolled flow of hydrocarbons. Borehole See ‘wellbore’. Bunding A secondary enclosure to contain leaks and spills. Cap rock A layer of relatively impermeable rock overlying an oil- or gas-bearing rock. Carbon footprint A measurement of the impact of activities on the environment by the amount of greenhouse gases they produce. It is measured in units of carbon dioxide equivalent. Casing Metal pipe inserted into a wellbore and cemented in place to protect both subsurface formations and the wellbore. Cement bond log A method of testing the integrity of cement used in the construction of the well, especially whether the cement is adhering effectively to both sides of the annulus between casings or between the outer casing and the rock sides. Coal bed methane A form of natural gas found along with coal seams underground. Directional drilling The intentional deviation of a wellbore from the path it would naturally take. Disposal well A well, sometimes a depleted oil or gas well, into which waste fluids can be injected for safe disposal. Enhanced Geothermal Systems A geothermal system that uses heat from deep in the ground to generate energy. An enhanced geothermal system is one where the natural connectivity does not permit sufficient flow and additional stimulation is required. Flowback water The fluid that flows back to surface following a fracturing treatment. It is a mixture of the original fracturing fluid and saline water containing dissolved minerals from the shale formation. Gas in place The entire volume of gas contained in a formation regardless of the ability to produce it. Global Warming Potential A measure of how much a given mass of a greenhouse gas is estimated to contribute to global warming relative to carbon dioxide. Groundwater Water found beneath the earth’s surface. Hazard A hazard is something (e.g. an object, a property of a substance, a phenomenon or an activity) that can cause adverse effects. Horizontal drilling A special case of directional drilling where the well is deviated onto a horizontal plane. Hydraulic fracturing A means of increasing the flow of oil or gas from a rock formation by pumping fluid at high pressure into the well, causing fractures to open in the formation and increase its permeability. Hydrogeology The geology of groundwater, especially concerning the physical, biological and chemical properties of its occurrence and movement. Leakoff test A test used to determine the pressure required to initiate fracturing of the rock formation. Microseismic Very small seismic events, normally below -1.5 ML. Naturally Occurring Radioactive Radioactive elements and their decay products found in the environment that have been Material generated from natural processes. Permeability A measure of the ability of a rock to transmit fluid through pore spaces. Porosity A ratio between the volume of the pore space in reservoir rock and the total bulk volume of the rock. The pore space determines the amount of space available for fluids. Pressure test A method of testing well integrity by raising the internal pressure of the well up to maximum expected design parameters. Produced water The fluid that returns to the surface during the production phase of a well that contains both fracturing fluid and saline water from the rock formation. Proppant Particles (normally sand) mixed with fracturing fluid to hold fractures open after a hydraulic fracturing treatment. Proved reserves The volume of technically recoverable resources demonstrated to be economically and legally producible.68 Shale gas extraction in the UK: a review of hydraulic fracturing
    • GLOSSARYReservoir A subsurface body of rock that acts as a store for hydrocarbons.Risk A risk is the likelihood that a hazard will actually cause its adverse effects, together with a measure of the effect.Scale inhibitor A chemical treatment used to control or prevent deposits building up in the well.Seismicity Sudden geological phenomena that release energy in the form of vibrations that travel through the earth as compression (primary) or shear (secondary) waves.Seismic reflection surveys A technique that uses reflected seismic waves to map the structure of rock layers in two- or three-dimensions.Surfactant A chemical that lowers the surface tension or interfacial tension between fluids or between a fluid and a solid.Sweet spot Regions in oil and gas reservoirs with high concentrations of carbon that are most amenable to production.Technically recoverable resource The volume of gas within a formation considered to be recoverable with existing technology.Thermogenic methane Methane produced by the alteration of organic matter under high temperatures and pressures over long time periods.Tiltmeter An instrument used to detect microdeformations in surrounding rock.Tracer A chemical additive that can be used to identify the presence of the fracturing fluid by subsequent monitoring.Traffic light system An early warning monitoring system with thresholds to indicate when operations should proceed with caution or halt.Unconventional gas Gas found in a reservoir of low or zero permeability.Wellbore The hole created by drilling operations, also known as the ‘borehole’.Well integrity The ability of the well to prevent hydrocarbons or operational fluids leaking into the surrounding environment.Well pad The surface infrastructure of the drilling operations. Shale gas extraction in the UK: a review of hydraulic fracturing 69
    • APPENDIX 1 Appendix 1: Working Group The following Working Group was set up to oversee this project. Members of the Working Group acted in an individual and not a representative capacity, and declared any potential conflicts of interest. The Working Group Members contributed to the project on the basis of their own expertise and good judgement. Professor Michael Bickle FRS Dr John Roberts CBE FREng Mike Bickle is based in the Department of Earth John Roberts has been the Chairman of the Royal Sciences at Cambridge University. His research Bank of Canada (Europe) Limited since 2009. He focuses on tectonics and geochemistry, with his most is also currently Chairman of Halite Energy Group recent work examining fluid-mineral reaction kinetics Limited, which champions underground gas storage, associated with geological carbon sequestration. as well as Bluebay Asset Management Limited, He is Director of the Cambridge Centre for Carbon which specialises in fixed income and alternative Capture and Storage and is also the NERC Chair of investment products, and Blackrock New Energy the UK Integrated Ocean Drilling Programme (IODP) Investment Trust. He is an advisor to Fortis European advisory committee. Clean Energy Fund, Trustee of Ecofin Research Foundation, and Deputy Lieutenant of the County of Dr Dougal Goodman OBE FREng Merseyside. Dougal Goodman is Chief Executive of The Foundation for Science and Technology. He is Professor Richard Selley also non-executive Chairman of the Lighthill Risk Dick Selley is Emeritus Professor of Petroleum Network, a consortium of insurance companies Geology and a Senior Research Fellow at Imperial working to bridge the gap between the insurance College London. He has researched, taught and market and the research community. He was formerly practiced petroleum exploration for fifty years, and Deputy Director of the British Antarctic Survey and in the mid 1980s he identified the scale and location a General Manager at BP during which time he was of the UK’s shale gas resources. He has spent most Head of Safety. He holds visiting chairs at University of his career at Imperial College, with the exception College London and Cranfield University. of several years working for oil companies in Libya, Greenland and the North Sea. He was a member Professor Robert Mair CBE FREng FRS (Chair) of Conoco’s exploration team that found the Lyell, Robert Mair is the Sir Kirby Laing Professor of Civil Murchison and Hutton fields. He has provided Engineering at Cambridge University and was Master consultancy services across the world, and is of Jesus College 2001-11. He was Senior Vice- currently a consultant on shale gas to the Crown President of the Royal Academy of Engineering 2008- Estate Commissioners via the Energy Contract 11, and is a founding Director of the Geotechnical Company Limited. Consulting Group, an international consulting company based in London. He has specialised Professor Zoe Shipton throughout his career in underground construction, Zoe Shipton is a Professor within the Department including soft ground tunnelling, retaining structures, of Civil Engineering at the University of Strathclyde, deep excavations and foundations and has advised with previous lectureships at the University of on many projects worldwide. In the UK he has been Glasgow and Trinity College Dublin. Her current closely involved with the design and construction of research focuses on the 3D structure and the Jubilee Line Extension for London Underground, permeability architecture of faults, with the aim of and with the Channel Tunnel Rail Link (now HS1) and better understanding the evolution of fault zone Crossrail projects. He is Chief Engineering Adviser to structures and the migration of fluids through the the Laing O’Rourke Group. Earth’s crust. She has carried out consultancy work for Cluff Geothermal Limited, BHP Billiton and StatoilHydro.70 Shale gas extraction in the UK: a review of hydraulic fracturing
    • APPENDIX 1Professor Hywel Thomas FREng FRS Professor Paul Younger FREngHywel Thomas is a Professor within the Institute Paul Younger is a Professor at the Institute forof Environment and Sustainability at Cardiff Research on Sustainability at Newcastle University.University, where he is also Pro-Vice Chancellor for He is a hydrogeologist and environmental engineer,Engagement, and Director of the Geoenvironmental and is renowned for his pioneering researchResearch Centre. His research focuses on generating and outreach programme in community basedan improved understanding of the engineering ecologically integrated remediation techniquesbehaviour of unsaturated soil, with the application of for water pollution and abandoned mines. He is aresearch to industry being one of his main priorities. Director at Cluff Geothermal Limited, which focusesHe is currently Principal Investigator for a Welsh on geothermal energy, and Five-Quarter EnergyEuropean Funding Office project on Earth energy Limited, which champions the extraction of coalrelated problems, including underground gas flows. gas in the UK.He has experience working with consulting engineersScott Wilson Kirkpatrick and Partners.Project management and research teamThe Royal Academy of Engineering and the Royal Society acknowledge the contributions of the followingmembers of staff in managing this project, carrying out research and analysis, and drafting the report:r Ben Koppelman, Senior Policy Adviser, Contact The Royal Society r Ben Koppelmanr Dr Alan Walker, Senior Policy Adviser, 0044 (0)207 451 2532 The Royal Academy of Engineering ben.koppelman@royalsociety.orgr Emma Woods, Policy Adviser, r Dr Alan Walker The Royal Society 0044 (0)207 766 0678 Shale gas extraction in the UK: a review of hydraulic fracturing 71
    • APPENDIX 2 Appendix 2: Evidence gathering 1 Evidence sessions Evidence session 1 – UK regulation and licensing Evidence session 6 – Environmental risks process r Stuart Rolley, Head of Environment, Coal Authority r Simon Toole, Director, Licensing, Exploration and Development, Department of Energy and Climate r David Allan, Chair of Safety, Environment and Change Technical Committee, British Drilling Association r Tony Grayling, Head of Climate Change and r Ian Davey, Senior Advisor in Environment and Communities, Environment Agency Business, Environment Agency r Allan Green, Well Operations Inspector, Health and XKFGPEG DTKGƂPI  s 5GKUOKE TKUMU Safety Executive r Dr Brian Baptie, Head of Seismology, BGS Evidence session 2 – British Geological Survey (BGS) project on shale gas r Professor Mike Kendal, Head, Department of Earth Sciences, Bristol University r Dr Rob Ward, Head of Groundwater Science, BGS r Professor Philip Meredith, Department of Earth r Professor Mike Stephenson, Head of Energy Sciences, University College London Science, BGS r Martin Rylance, Engineering Manager for Fracking Evidence session 3 – Industry perspectives and Stimulation, BP r Dr Graeme Smith, Vice President for Unconventional Evidence session 8 – Risk management Gas and Oil, Shell r Judy Knights, Marine and Energy Class of Business r Martin Cox, Aberdeen Drilling Management Ltd Executive, Performance Management Directorate, Lloyd’s r Nick Hooper, Head of Science and Innovation, British Consulate General, Boston (via r Richard Palengat, Senior Underwriter, Head of teleconference) Marine and Energy, AEGIS London Evidence session 4 – NGO perspectives r Andrew Kibble, Head of Unit, Chemical Hazards and Poisons Division, Health Protection Agency r Dr Doug Parr, Chief Scientist, Greenpeace r Martyn Evans, Climate Change and Energy Advisor, r Tony Bosworth, Senior Climate Change Campaigner, Environment Agency (via teleconference) Friends of the Earth (via teleconference) r Jeanne Briskin, Office of Science Policy, Evidence session 5 – Operational risks US Environmental Protection Agency (via teleconference) r Eric Vaughan, Chief Technology Officer, Cuadrilla Resources r Adrian Topham, Baker Hughes r Peter Robinson, NRG Well Examination Ltd r Professor Ray Orbach, Energy Institute, University of Texas at Austin, USA72 Shale gas extraction in the UK: a review of hydraulic fracturing
    • APPENDIX 22 Other consultationsWe are grateful for opportunities to consult with the following individuals:r John Arnott, Head of Policy, Department of Energy r Mark Livingstone, Head of Water Regulation Group, and Climate Change Northern Ireland Environment Agencyr Tristan Asprey, Exploration Operations Manager for r Professor Ragnar Lofstedt, Director, Centre for Risk Europe and Greenland, Exxon Mobil Management, Kings College Londonr Jenny Banks, Energy and Climate Change Policy r Ken Lowe, Water Management, Cuadrilla Resources Officer, WWF-UK r Professor Philip Macnaghten, Professor ofr Roy Baria, Technical Director, EGS Energy Geography, Durham Universityr Professor Richard Davies, Director of Energy r Charles McConnell, Chief Operating Officer in the Institute, University of Durham Office of Fossil Energy, US Department of Energyr Martin Diaper, Climate Change Advisor, r Bryan Monson, Deputy Chief Executive, Health and Environment Agency Safety Executive Northern Irelandr Melvyn Giles, Global Leader for Unconventional r Jim Neilson, Head of Offshore, Pipelines and Diving Gas, Shell Policy, Health and Safety Executiver David Gladwell, Managing Director, Aurora r David Palk, Development Management, Suffolk County Councilr Dr Silke Hartmann, Northern Ireland Environment Agency r Professor John Perkins FREng, Chief Scientific Adviser, Department for Business, Innovation andr Lillian Harrison, Minerals and Waste Planning Policy Skills Manager, Kent County Council r Professor Nick Pidgeon, Director of ther Toni Harvey, Senior Geoscientist, Department of Understanding Risk Research Group, Cardiff Energy and Climate Change Universityr Sir Brian Hoskins FRS, Director of Grantham Institute r Professor Simon Pollard, Dean, Faculty of for Climate Change, Imperial College London Environment and Science, Cranfield Universityr Chris Ingham, Bioprocessing Manager, r Malcolm Roberts, Senior Policy Officer, Scottish United Utilities Environmental Protection Agencyr Sally Kornfeld, Team Leader, International Oil r Professor John Shepherd FRS, Professorial Research and Gas Activities, US Department of Energy Fellow in Earth System Science, University of Southamptonr Professor David Mackay FRS, Chief Scientific Adviser, Department of Energy and Climate Change Shale gas extraction in the UK: a review of hydraulic fracturing 73
    • APPENDIX 2 r Simon Talbot, Managing Director, Ground-Gas Solutions Ltd r John Thorogood, Senior Technical Advisor, Drilling Global Consultant LLP r Mihai Tomescu, Chief Economist, instruments and impact assessment, Directorate General Environment, European Commission r Sir Bob Watson FRS, Chief Scientific Adviser, Department for Environment, Food and Rural Affairs r Professor Mark Zoback, Professor of Geophysics, Stanford University, USA 3 Written submissions We are grateful for receiving written submissions from: r Professor Al Fraser, Chair in Petroleum Geoscience, r Professor Ragnar Lofstedt, Director, Centre for Risk Imperial College London Management, Kings College London r The Geological Society of London r Petroleum Exploration Society of Great Britain r Mike Hill, Director, Gemini Control and r Professor Simon Pollard, Dean, Faculty of Automation Ltd Environment and Science, Cranfield University r Daniel Lawrence, Counsel (Environment, Planning r Halliburton and Regulatory Practice Group), Freshfields Bruckhaus Deringer LLP74 Shale gas extraction in the UK: a review of hydraulic fracturing
    • APPENDIX 3Appendix 3: Review PanelThis report has been reviewed by an independent panel of experts. Members of the Review Panel werenot asked to endorse the report’s conclusions and recommendations. They acted in a personal andnot an organisational capacity and were asked to declare any potential conflicts of interest. The RoyalAcademy of Engineering and the Royal Society gratefully acknowledge their contribution.The report has been approved by The Royal Academy of Engineering’s Engineering Policy Committeeand the Royal Society’s Council. Members of both bodies were asked to declare any potential conflictsof interest. Like many UK companies and charities, the Royal Society and the Royal Academy ofEngineering invest their portfolios in a range of companies and funds, including equity holdings in oiland gas companies.r Paul Golby FREng The Royal Academy of Engineering and the Royal Chairman, Engineering and Physical Sciences Society would also like to thank the following Research Council individuals for providing comments on sections of previous drafts:r Professor James Jackson FRS Head, Department of Earth Sciences, r Christopher Ingham, Bioprocessing Manager, University of Cambridge United Utilities Water Plc.r Professor Susan Owens OBE FBA r Phil Keeble, Well examiner, BP Exploration UK Head, Department of Geography, (retired) University of Cambridge r Daniel Lawrence, Counsel (Environment, Planningr Professor Anthony Pearson FRS and Regulatory Practice Group), Freshfields Schlumberger Cambridge Research Centre Bruckhaus Deringer LLPr Professor John Pethica FRS (Chair) r Professor John Sheppard FRS, School of Ocean Vice President, the Royal Society and Earth Science, National Oceanography Centre, University of Southamptonr Professor John Tellam School of Geography, Earth and Environmental Sciences, University of Birminghamr Professor Martyn Thomas FREng Director, Martyn Thomas Associates Ltd.r Professor John Woodhouse FRS Department of Earth Sciences, Oxford University Shale gas extraction in the UK: a review of hydraulic fracturing 75
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